S&P Global Market Intelligence




        



Watershed February freeze upends booming ERCOT wind hedge market

By: Adam Wilson | March 11, 2021

Bank hedges have emerged as the preferred contract structure in Texas as the supply of traditional power purchase agreements, or PPAs, could not keep up with the development interest for wind in the state. These hedges were believed to be a reasonably safe alternative to traditional physical PPAs in the Electric Reliability Council Of Texas Inc. region. Owners and banks are now rethinking the contract structure after the February freeze and ensuing energy crisis in ERCOT wiped out a years' worth of revenue in a matter of days and put owners on the hook for billions of dollars in losses.

The ERCOT market and hedges

Bank hedges, also known as fixed-volume price swaps, have been an increasingly popular alternative to traditional PPAs for many years now. In ERCOT particularly, most wind projects over the past 15 years have entered into a hedge contract — an estimated two-thirds of the installed capacity currently in the state utilizes this option in some form compared to a PPA.

Unlike a physical PPA where a project sells any power generated to a utility at a fixed price, a hedge is an agreement between the power plant owner and another counterparty, typically a bank. The project owner sells a fixed volume of power at a fixed price, known as the strike price, to the hedge provider who purchases it at an agreed-upon trading hub. The power generated by the project is sold in a separate merchant transaction directly to the wholesale market via the nearest grid node. If the strike price is higher than the purchase price at the hub, the hedge provider pays the difference to the project owner. Conversely, if the hub price is higher than the strike price, the project owner pays the difference to the hedge provider. The project owner receives the revenue from the power sold at the node plus or minus the difference between the hub price and strike price.





For example, a wind project has agreed to a strike price with a hedge provider of $40/MWh. If the power the project owner buys at the hub is priced at $20/MWh, the hedge provider pays the project owner the difference of $20/MWh. If the project sells its power generated to the nearest grid node at $10/MWh, that project has netted $30/MWh for these two transactions combined. Where the risk comes in for project owners is when the hub price is different, e.g., higher, than the nodal price. This is known as basis risk.

Additionally, in fixed-volume hedge agreements, the project owner faces the risk of not generating sufficient power to meet the obligations under the hedge agreement. This is known as volumetric risk. Typically, the project must buy and resell power to the hedge provider to match the amount of generation expected to be produced by the project either 95% or 99% of the time on an hourly or daily basis, known as P95 or P99 scenarios, respectively. When a project owner simultaneously faces basis risk and volumetric risk, i.e., if the hub price is higher than the strike price and the project is not able to generate sufficient power to offset those losses, the owner is subject to a financial loss.

Historically, hedge agreements have been a reasonably safe option for both project owners and the hedge counterparty. A traditional PPA is the least risky and most reliable revenue stream for project owners. In ERCOT, however, wind development has significantly outpaced the volume of PPAs utilities were willing to enter into with non-dispatchable generation sources. Selling power directly on the wholesale market as a pure merchant project is often viewed as too risky of a revenue stream to secure financing for these intermittent resources. Consequently, the bank hedge framework emerged as the solution for wind developers that were looking to capitalize on the production tax credit and desirable wind resources in Texas but could not secure a PPA. Driven, in part, by this contract mechanism, wind development in ERCOT grew at a blistering pace.

From 2014 through 2020, wind capacity in ERCOT nearly tripled from roughly 11,000 MW to over 30,000 MW. In this period, bank hedges along with the emergence of virtual PPAs with corporate off-takers were the primary contract structures driving development, with physical PPAs a distant third.

Learn how we can help you identify renewable power generation opportunities.

Request a demo



The February freeze

On Feb. 9, many energy officials including those at ERCOT, the Public Utility Commission of Texas, or PUCT, and energy providers in the state were preparing for a potentially severe winter weather event. In the following days, a polar vortex brought in historically cold temperatures, ice storms that downed power lines and caused massive traffic pileups, damaging winds, and unprecedented snowfall. The ERCOT energy grid, as a result, grew increasingly stresse. Energy demand skyrocketed while generators struggled to keep up. Fuel supply chains were disrupted, and power plants not adequately winterized to maintain operations in such extreme conditions were forced to shut down. To prevent a catastrophic blackout that potentially could have lasted months according to officials, ERCOT initiated rolling outages that left millions across the state without power.

To convince more generators to come online and ease the stress on the grid, the PUCT issued an emergency order to shed certain nonessential electrical load and also called for electric energy prices to be raised to the market cap of $9,000/MWh. This proved ineffective, as there was no power available to come online at the time. Several coal, gas and nuclear plants were temporarily forced offline due to the harsh conditions. The massive fleet of wind power across the state also was not immune to the weather as turbines froze, halting generation. While frozen turbines were hardly to blame for the energy crisis in Texas, the event left many wind project owners reeling. In total, roughly 18,000 MW of wind generation were shut down during the freeze, representing 57% of the state's wind fleet.

Project owners under fixed-volume hedge agreements were forced to purchase power at sky-high prices in the thousands of dollars per megawatt-hour to meet their contracted power obligations, while their turbines were not able to supply nearly enough power to the grid to offset these losses. As a result, multiple owners have reported substantial debts, which could potentially result in bankruptcy and/or forfeiture of their wind assets. "For some projects, four years' worth of revenue was lost in a matter of days" noted Brian Kelly, Energy Team Leader at McGuireWoods LLP. "To say the market dynamics changed 180 degrees [during the event] isn't close to sufficient. The market disruption caused by the weather event and the PUCT's subsequent response was unprecedented."

Among those affected was Quebec-based Innergex Renewable Energy Inc. The company estimated the financial impact of the freeze to be C$80 million. The company was forced to shut down its 200-MW FTWIND (Flat Top Wind I) wind project, while two other wind farms and a solar plant also experienced disruptions. Algonquin Power & Utilities Corp. expects a hit of up to $55 million on its 2021 adjusted EBITDA due to losses sustained from hedges and other financial obligations resulting from the storm.

Similarly, RWE AG, which owns roughly 3,000 MW of mostly wind power in Texas, reported that it expects the adjusted EBITDA of its onshore wind/solar segment in 2021 to be negatively impacted in the low-to-mid three-digit million euro range. EDP - Energias de Portugal SA took a comparatively modest hit in the low tens of millions of dollars, according to an interview with CEO Miguel Stilwell Andrade. At least nine different renewable owners and investors sent filings to the PUCT, requesting that the commission require ERCOT to reprise power transactions that occurred between Feb. 15 and Feb. 19. These requests were subsequently rejected.


Even so, not all wind owners were affected by the price spikes. Iberdrola SA subsidiary Avangrid Inc., which owns 1,316 MW of wind capacity in ERCOT, does not expect material financial impacts as obligations across the region were very limited. Additionally, Ørsted A/S, which owns 1,325 MW of wind capacity in the state, reported that most of its wind projects do not have firm delivery obligations. According to a company spokesperson, the company "unwound the majority of our short positions before the power market was impacted by the extreme weather" and does not expect a material EBITDA impact as a result.

The aftermath

The dust has yet to settle after the February energy crisis in ERCOT, and it will likely be several months, if not longer, before final decisions are made. The PUCT has opened a formal investigation examining actions taken by ERCOT to handle the crisis. Recently, Texas Lt. Gov. Dan Patrick called for ERCOT and the PUCT to address "the $16 billion mistake" in power pricing during the extreme winter event. The outcome is yet to be determined, but utilities and power generators are demanding some sort of relief from pricing they feel was incorrectly imposed on the market.

It is likely that any pending litigation and potential resettlement of energy transactions during this period will center around this order that many in the industry have questioned. "The PUC intervened and arbitrarily ordered ERCOT to set prices at $9,000/MWh throughout the entire market in a misguided attempt to induce additional supply. The result was a dysfunctional market where non-existent power was being 'bought' and 'sold' at fantasy prices no longer set by supply and demand. Although the PUCT order had no impact whatsoever in creating additional supply it did lead to lottery-style jackpot winnings for a few traders while causing widespread financial ruin" asserted Jeffrey Chester, global head of energy project finance at Greenberg Traurig. Further calls to reform the ERCOT grid model completely remain, and the state legislature has now become embroiled in the debate, but such sweeping policy changes are often difficult to accomplish. Recent personnel shake-ups on the ERCOT board and the PUCT complicate the situation, creating greater uncertainty in the near-term.

Several wind owners have announced their intentions to activate force majeure clauses contained in their contracts in the state given the widespread failure of the market as a whole and the unprecedented extreme winter weather event. Whether or not these declarations will be successful remains to be seen. Companies are exploring other mitigation options as well.

The other question that remains is how will project developers and hedge providers adjust following the energy crisis. While winter storms like the one that caused the outage are rare, owners may be hesitant to enter into fixed-volume agreements, at least not without an insurance policy or some other form of protection in place. One such mechanism is what is called a tracking account, where a project owner facing losses due to hub-settled transactions that exceed the revenue the project earned selling into the grid node can repay this debt over a period of time through a negotiated load agreement. These loans, however, are capped and would not protect the amount of losses this event caused.

Additionally, project owners may insist that force majeure clauses explicitly cover grid failures like the one in February. Further, winterization packages are expected to become more common for new wind farms, and many developers such as Clearway Energy Inc. have already announced intentions to winterize existing projects to help prevent future weather-related outages. Such action may even be required via legislative mandate or as part of contract renegotiations, which would be yet another cost to stomach for an industry already dealing with significant financial fallout due to the freeze.

Whatever the outcome, the February grid failure will likely be a pivotal moment in the brief history of wind and renewable development in Texas. The hedge agreements that helped guide the market to where it is today will almost certainly be altered or even completely reimagined to better protect developers.

The pipeline of renewable projects in Texas continues to be impressive with just over 49,000 MW of wind and solar projects under development according to S&P Global Market Intelligence. Solar has surpassed wind in interest with roughly 33,000 MW in development — more than double that of wind — though solar projects have not traditionally engaged in the type of bank hedges that exposed wind project owners during the grid outages in February. Regardless of technology, this event will almost certainly play a key role in financing discussions during the development of these projects for the foreseeable future.

Regulatory Research Associates is a group within S&P Global Market Intelligence.

For wholesale prices and supply and demand projections, see the S&P Global Market Intelligence Power Forecast.


This article was published by S&P Global Market Intelligence and not by S&P Global Ratings, which is a separately managed division of S&P Global.
Facebook   Twitter   LinkedIn   YouTube
©  S&P Global Market Intelligence. All rights reserved.  Unsubscribe   Update your Preferences   Privacy Policy   Cookie Notice   Terms of Use   Do Not Sell My Personal Information