By: Richard A. Kessler |
Texas ERCOT continues to add wind power capacity faster than any electricity market in the US but for project developers, finding and making solid returns is a growing challenge in a changing and competitive environment as buyers become more risk-adverse and savvy.
“The standard 20-year power purchase agreement (PPA) that this industry is built on is readily fading away. The market is shifting. There are far fewer of those opportunities than we have ever had,” says Thanasis Latrou, chief executive of Caprock Renewables.
Those PPAs that exist mainly involve vertically-integrated municipal utilities and co-ops, about 16% of the huge ERCOT market, and they have become more educated consumers.
Earlier this decade, several larger progressive ‘munis’ locked themselves into renewables off-take deals that were politically defensible at the time.
Subsequently, wind and solar prices plunged, leaving their rate bases paying for expensive albeit cleaner power – prompting criticism and questioning from city councils, consumer groups, competing traditional generators and their supporters in conservative think tanks and the Legislature.
More recent muni PPAs have involved some of the country’s lowest renewable energy prices, an indication of plentiful supply in a buyer’s market. For project owners there is often a trade-off: thinner margins but less risk than alternative off-take structures.
ERCOT has peak electric load of more than 72GW, the most of any state grid, and 21.1GW of installed wind capacity.
The balance of ERCOT – an independent system operator (ISO) which serves 90% of the state’s electric load and is located entirely within Texas – was deregulated two decades ago when monopoly public utilities were each “unbundled” and broken into three companies: generation, retail (customer service and billing) and transmission.
Competition was allowed in generation and retail, while transmission was limited to one operator per district in most cases to prevent wires from being strung indiscriminately. Owners must provide access to all qualified retail electric suppliers. Long-haul transmission was allocated separately under a streamlined interconnection process.
What has emerged is a highly competitive and liquid electricity market with a different dynamic than found elsewhere in the US. Ideas and new product offerings are tested faster, and more rapidly adopted and challenged, in ERCOT.
Nowhere is that more evident than with alternative off-take structures including those for corporate and industrial (C&I) – the fastest growth consumer segment there for wind energy within a vibrant state economy.
In first quarter this year, Texas’ economy grew 2.9%, trailing only Washington, Utah, Colorado and South Dakota among states, according to the US Bureau of Economic Analysis, a federal agency. Those four state economies totaled a combined $1.06trn in size versus a much larger $1.7trn for Texas.
Wind project hedges
Within ERCOT, three types of hedges have developed in varying and innovative degrees that can allow developers to finance their wind projects: fixed-volume price swaps, corporate PPAs and so-called proxy revenue swaps.
The fixed-volume price swap, or bank hedge, is the most widespread, although corporate PPAs are mushrooming in number and could prevail in the next several years. “A hedge is not as straightforward as a PPA. It’s more of an esoteric instrument,” Latrou told a recent industry conference organised by Infocast.
A fixed-volume price swap in ERCOT is a type of physical hedge, as the hedge provider – it can also be a non-bank financial institution or strategic investor – buys electricity as part of the transaction, which occurs at trading hubs.
At the hub, the project owner buys electricity in fixed volumes for the prevailing price and then resells that power to the hedge provider for an earlier agreed set price per MWh. Electricity generated by the wind farm is sold separately at the closest busbar, or locational marginal pricing node. There are more than 4,000 in ERCOT.
Hubs are not physical locations but instead, an arithmetic average of bulk electricity prices, determined at a liquid pricing point. Usage determines pricing with contract terms, location and time of use key influences in shaping final costs.
While a typical 10-12-year hedge arrangement provides a set volume of power at a fixed price, which gives a long-life asset with some level of revenue certainty, the owner must manage basis risk – the difference in market pricing between the busbar and hub.
This differential can be problematic – hub prices are often higher – particularly where there is curtailment and/or wind energy oversupply, a load mismatch known as covariance.
ERCOT power prices can also spike during cold winter and hot summer months. That’s good if projects have merchant capacity to sell and can get it to load, but owners can also see their margins evaporate if they have a hedge.
As well, most hedges do not excuse the delivery obligation of power from the wind farm if curtailment events such as transmission congestion occur, a growing problem in some areas of ERCOT. If a project doesn’t generate or can’t deliver to meet a fixed obligation, the project owner must find the electricity elsewhere at prevailing prices. That’s volume risk.
Project owners don’t have many options to mitigate basis risk, in part because financial institutions usually won’t provide financial hedges that avoid basis risk through settlement at a project node. So-called tracking accounts are employed to delay the impact of basis risk but don’t eliminate it.
All this can have project owners sometimes feeling as if they are captive to fluctuating electricity prices which in ERCOT follow those of natural gas, the volatile majority fuel for power generation on the grid.
That said, bank hedges work well enough in ERCOT and gigawatts more will get done in the future. The question is how much risk tolerance project owners are willing to stomach with those hedges out there, much less others in development that will require them to invest even more in analytics, consultants and specialized data to stay in the wind game.
Financial institutions have a strong incentive to make these product offerings attractive enough in the marketplace, in part because they can also benefit by providing tax equity and debt capital for projects.
Equally so, banks must also contend with exposure to market variability. They are fully aware that many of their best and most experienced project sponsor customers are also employing sophisticated risk management tools, as well as energy management desks in ERCOT.
The rub is that there is not an endless supply of hedge counterparties in ERCOT and banks have plenty of projects from which to pick and choose. Citigroup Energy, for example, in May did a 15-year bank hedge with Boston-based Longroad Energy for its 237MW Rio Bravo project in ERCOT. The weaker ones won’t make the cut particularly as the value of federal tax credits diminish.
“Good projects are going to get built. They will have good sponsors, technology and transmission story, and be contracted or partially contracted,” said George Hardie, vice president of development, North America, at Pattern Development. “They are going to have some competitive advantage.”
Corporate or virtual PPAs are all the rage in ERCOT and some of the largest globally for wind have been done there involving tech giants Amazon and Facebook and industrial firms Dow Chemical and General Motors, among many others.
This sector should remain vibrant given robust demand for readily available cheap, clean renewables. More companies are transitioning toward cleaner energy sources for economic, environmental and social reasons, with pressure to do so coming from communities, customers and shareholders.
With virtual PPAs, companies provide the financial hedges but unlike fixed-volume price swaps, no electricity sales occur with the wind farm. In its simplest form, the project pays the per MWh floating price for a set percentage of electricity generated, and the hedge provider pays for the same amount of power per MWh at a price agreed earlier.
Also, unlike price swaps, there are often excused hours that may include transmission curtailment or force majeure, although often require wind farm minimum availability requirements.
Wind farm owners benefit as the hedge provides unit price protection for electricity generated. Companies also benefit financially and usually obtain the environmental attributes, often renewable energy credits.
As is usually the case in ERCOT, the company will try to reap public relations gains from the hedge by asserting that the revenue stream from the PPA directly allowed the wind farm to be built and operated.
As the emerging corporate market matures, wind farm developers are finding it is becoming more complicated and costly at times to participate.
Some of their actual and potential customers have become more astute and knowledgeable about how locational, execution and project operational risks in PPAs must be managed – and much less willing to assume them.
“Every new RFP for a corporate PPA seems to involve a new idea for how to push risk back on the developer,” Dennis Meany, president of Lincoln Clean Energy, told a Norton Rose Fulbright conference earlier this year.
He and other developers said that some large corporates such as Microsoft want to move from “as generated” contracts toward firm volumes that better fit the shape of their energy requirements.
Meany noted that if corporates fix the quantity and shape, then they are involved with hedge accounting, which they want to avoid. They are trying to ascertain how to take a shaped product without the accounting hassle.
This presents a challenge for wind asset owners but one that could pay them dividends in ERCOT and elsewhere, if they can find solutions for this problem.
“We need to put on our creative hats to find different products that can provide value to the market,” Caroline Mead, associate director of origination at EDF Renewables, said at Infocast, even as the industry takes on more risk. She said she welcomes corporate buyers with a “different view or different angle” for long-term hedges.
“In ERCOT, it’s really about the economics. Pricing for wind is so incredibly compelling for regulated utilities or corporate PPAs. That’s the major driver,” she said.
That will drive aggregation of corporate customers in ERCOT, something that developers expect will add momentum to and broaden the market next decade.
Proxy revenue swaps
This is a relatively new hedge up to 10 years whose providers are weather-risk investors such as reinsurers that pay the project a pre-agreed fixed price for a period of settlement that is either a quarter or annum, not per MWh produced or sold.
The project owner pays the swap provider a set percentage of “proxy revenue” equal to the designated hub market price multiplied by the facility’s “proxy generation.” This is equal to the project’s output of electricity that would have been generated based on its capabilities and measured wind speeds.
The owner must deal with basis risk, but the swap does provide a hedge against volume risk and hub energy price variations. Sale of RECs to the counterparty are allowed.
The weather-risk investor is hedging the hub price per unit and the project’s volume of power over a time period.
In ERCOT, which can experience some of the most pronounced weather variations in the country, these instruments won’t be for the faint of heart in the wind development community.
Still, some project sponsors are getting comfortable with them and looking for projects in which the swaps make economic sense as they can be expensive and complicated. They expect deals involving proxy revenue swaps soon.