Buying a wind farm
Anyone buying a wind farm should be aware of a number of issues that can affect the value or even viability of the project.
Offtake and Interconnection
Most wind projects derive much of their value from a power contract.
Terms like the electricity price, the remaining contract term, security that must be posted to secure performance, the deadline to start electricity deliveries for any project that is still under development, and the minimum number of turbines that must be operating to avoid a de-rating are obviously important.
It will be an uphill battle to finance a project with an unrated offtaker. Financeability analyses are becoming more complicated as more projects rely on corporate offtakers. Power purchase agreements with corporations are evolving. They are becoming shorter in term with longer "merchant tails" where the owner must rely on uncontracted revenue. Recent corporate PPAs sometimes have tracking accounts to track the extent to which the contract price for electricity exceeds the current market prices during the contract term, and the overage must be paid to the customer. (For more on these challenges, see "Financing PPAs With Shorter Terms" in this issue.)
Many power contracts contain change-of-control provisions. Determining whether the potential acquirer fits into an exception, if there are any exceptions, and whether the transaction requires the consent of the electricity purchaser are gating issues. Consents can take time to obtain.
The project location is important in an era of grid congestion. Some wind projects have been "curtailed," meaning ordered by the grid to scale back output, by up to 97% at times. This obviously affects revenue. A technical consultant should be brought in to analyze curtailment risk.
A project in an organized market where a regional transmission organization and independent system operator has been put in charge of the grid has more options for where to sell its power unlike a project in Florida or Idaho, for example, where there is no spot market. Regulated utilities in areas without alternative outlets for power are required by law to buy the output at their "avoided cost," or the amount they would spend to generate the electricity themselves. However, this purchase obligation, while a matter of federal law, is administered by state public utility commissions. Enforcement varies by state. (See, for example, "PURPA and Solar" in the April 2017 NewsWire and "New Technologies and Old Issues Under PURPA" in the February 2018 NewsWire.) There may be restrictions in some states on direct sales to end users of the electricity; the local utility may have a monopoly on electricity supply.
Numerous wind projects, particularly in ERCOT, lack a traditional power contract. They sell into the local grid and rely on hedges or swaps to put a floor under the electricity price so that the projects can be financed. Three types of hedges are commonly used: fixed-volume price hedges (where a fixed amount of output each period is hedged), virtual PPAs with corporate offtakers (which are power contracts that are financially settled, so that they act as hedges and the volume matches the actual output) and proxy revenue swaps (which hedge both price and weather risk).
Hedges require careful analysis. Key factors on which to focus are whether the hedge is physically or financially settled and what liens and other credit support the hedge counterparty requires.
In most projects with hedges, basis risk is the central concern. In a hedged project, the electricity is sold to the grid at a floating market price determined at a "node" on the grid. The project then pays a floating amount to a hedge counterparty in exchange for a fixed price in return. The two amounts are netted, and one party pays the net amount to the other. The payment by the project under the hedge is a floating price determined at a "hub," which is not the same as the node. The price gap has reached as much as $12 to $14 per megawatt hour in the Texas panhandle. The potential for a gap in price is called basis risk.
New projects usually have to pay the cost of "network upgrades" to the grid to accommodate the additional electricity. Payments may also have to be made to upgrade neighboring grids to relieve congestion. The payments can run into the millions of dollars.
Production tax credits can be claimed on the electricity output from wind farms in the United States. The credits may be claimed only on electricity generated and sold to unrelated persons for the first 10 years after a facility is originally placed in service. The credit is currently 2.5¢ a kilowatt hour. The amount is adjusted annually for inflation.
A facility only qualifies for credits if it is under construction by the end of 2019, and it only qualifies for credits at full value if it was under construction by the end of 2016. Facilities on which construction begins in 2017, 2018 and 2019 qualify for credits at reduced levels of 80%, 60% and 40% of the full rate.
Anyone buying the development rights to a project that has not been built yet should determine when the project started construction, if in fact it is under construction. A weak start-of-construction fact pattern may limit the ability to finance the project. If a project has already been financed, then be sure to check the start-of-construction representations made to investors and assess how much risk the buyer will take if it steps into such a representation.
There are two ways to start construction. They are by starting "physical work of a significant nature" at a factory on equipment for the project or at the project site, or by "incurring" at least 5% of the project cost.
Turning first to off-site physical work, some wind companies had work start at the factory on a transformer for the project.
The manufacturer should do as much work on the transformer as possible before the construction-start deadline and deliver the transformer before the deadline or as soon after as possible. Many transformer manufacturers are not in a position to do any manufacturing themselves, so they order components from suppliers to put in a basket with the name of the project on it for use later in manufacturing the transformer. Some tax counsel want to see work by the manufacturer itself. The more that was done before the construction-start deadline, the better. Many tax counsel like to see such work cost at least $250,000 and take at least 250 man hours to complete. Non-physical work, like design or engineering, does not count as part of the man hours. The focus is on physical work.
Another common form of physical work is to dig a percentage of the turbine foundations — at least 10% would be ideal — and to have put in at least a mile of turbine string roads. Access roads to the highway generally do not count. The turbine foundations must be used in the project. They cannot have washed away. The road should be finished to the permanent surface.
The contract for the work had to be binding on the parties before the work started. If there was a right to cancel the contract, the contract should have required payment of a termination fee of at least 5% of the remaining contract price, plus payment for work completed. A contract with a termination for convenience is not binding if no damages have to be paid. Any subcontracts also must be binding to count physical work done under them.
The second way to start construction is to "incur" at least 5% of the project costs. Costs are not incurred merely by spending money, with one exception. Equipment or services must normally be delivered to count the costs. The exception is a payment before the deadline counts if there was delivery within 3 1/2 months after the payment.
Title transfer may have been enough technically, but it is best if there was actual delivery of the equipment. In order to count a payment for services, then all services must have been completed within the 3 1/2 months.
It is fine if delivery occurred at the factory. However, there should have been formal acceptance. The developer should have had a representative inspect the equipment and formally accept the equipment by signing an acceptance certificate with serial numbers of the equipment and other basic information. Any sales, use or value added taxes triggered by delivery should have been paid. Title and risk of loss should have passed to the developer on or before delivery.
If the equipment was stored by the manufacturer, the developer should have paid for storage and insured the equipment against loss after it was considered delivered.
If payment was made at year end with delivery within 3 1/2 months, make sure that the contract was binding and identified the specific equipment being purchased. There should not have been a right to unwind the transaction and get a refund of the purchase price.
A common problem is a down payment or deposit made when the contract was signed. Equipment delivery is rarely within 3 1/2 months after such a deposit.
It was not enough merely to have started construction in time, there must also be continuous work after the year construction started. Starting construction starts a four-year clock to run on finishing the project. Under US tax rules, a project must be completed within four years after the year construction started or the developer must prove continuous work. This may be difficult to do. Any project that started work under the physical work test must prove "continuous construction." One that started based on incurring at least 5% of the project cost must prove "continuous efforts."
Be sure to investigate whether physical work was done or costs were incurred in an earlier year than the developer said construction first started.
Some developers have tried to buy more time to complete projects on which physical work started by discarding the physical work and starting over under either the physical work or 5% test. There must have been a clear business reason why the earlier work was not used: for example, the project had to be moved to a different site.
Contractors who build wind farms or supply equipment are already short of capacity in 2020 to take on more orders. A glut of wind farms that started construction in 2016 must be on line by the end of 2020.
Even in cases where contractors have been lined up by the seller of a project, look for a duty for the contractor to pay liquidated damages as a stick to get the work done by the deadline. A project that slips past the deadline and cannot prove continuous work will be out of luck. Tax credits may only be claimed on the electricity output from the share of the project that is put in service by the deadline.
Finger-pointing risk is inherent in all projects with more than one construction contract where the contracts are not fully wrapped. With a wind project, the turbine supplier is responsible for the turbines. A balance-of-plant contractor may erect them and build the substation and the remaining parts of the project. A prospective purchaser of development-stage projects should ensure that there are no "seams" in the contract arrangements with the turbine supplier and balance-of-plant construction contractor so that at least one of them will be responsible to fix any issue or to pay compensation.
The contracts should fit together. For example, the point of delivery under both the turbine supply agreement and BoP construction contract should be the same location, and the BoP contractor should be prepared to receive deliveries on the same schedule (and at the same rate) as the turbine supplier will deliver turbines under the turbine supply agreement.
The turbine supplier often acts as the contact operator to maintain the turbines for the period the turbines remain under warranty. The operation and maintenance agreement will typically have a performance guarantee of at least 95% to 97% availability. The liquidated damage and bonus amounts are often tied to the contracted electricity prices for the project, but a potential purchaser should ensure that the liquidated damages are adequate compensation for lost performance and there will be enough operating cash flow to pay any bonus that has been promised to the operator for exceptional output.
Force majeure events that excuse the operator should also excuse performance under the offtake contract.
A prospective purchaser may not have much say about maintenance agreements already in place, but it should understand the risks created by them. Does the contract operator have a good reputation in the market? This may be important if the project will be resold or have to be financed or refinanced.
Take note of any caps in indemnities or liquidated damages and whether there have already been payments that reduce the remaining caps.
Most wind projects have tax equity financing and some also have debt in place.
An important issue when reviewing the financing arrangements is whether there is any change-of-control restriction that would prevent the project sale.
Some change-of-control provisions only reach up to a certain corporate level, such as the first entity in the ownership chain that has substantial assets other than the project. Others go much higher, such as to a private equity owner.
Some change-of-control restrictions do not apply if the buyer meets certain pre-determined criteria, such as a financial test and an experience or ownership test.
At a minimum, notice will have to be sent to the financiers.
If consent will be needed from the financing parties for the sale, leave plenty of time.
Many financing documents require credit support from an upper-tier sponsor entity. For debt, this may take the form of a cash sweep guarantee where a sponsor parent promises a lender that it will contribute cash to pay debt service if cash from electricity sales is diverted to pay an indemnity to the tax equity investors. For tax equity, there is always a sponsor guarantee that ensures payment to the tax equity investor of indemnity claims. There may be other required guarantees or credit support.
A buyer will usually have to provide substitute security. However, in a "platform sale" of the developer together with all of its projects, it is possible that all entities providing credit support are being acquired, so the existing credit support can remain in place.
Many wind farms are financed in the tax equity market using partnership flip structures. (For more on how such transactions work, see "Partnership Flips" in the April 2017 NewsWire.) What happens in partnerships is more complicated than what the documents say. Complicated partnership accounting rules limit the economic benefits that a partner can pull out of the partnership. A buyer should have someone experienced at looking at partnership models review the updated tracking model used by the partnership to track how close the tax equity investor is to reaching its target yield. There may also be cash sweeps that divert cash to the tax equity investor. An example is where the investor is late reaching the target yield from what was expected when the deal closed. The investor may also have a right to adjustments if there is a tax law change.
Most partnership flip transactions allow the tax equity investor to sweep between 50% and 100% of cash flow to pay any unpaid indemnity claims: for example, for disallowance of tax benefits on which the investor was counting. This means what cash is distributed to the sponsor may be too little to pay debt service on any back-levered debt at the sponsor level.
The buyer should be sure to have recourse against the seller under the purchase agreement for any indemnities that must be paid to the tax equity investor because of something that happened in the past.
If there is also debt on the project or at the level of the sponsor partner, there are conditions that must be satisfied in order for the sponsor to take cash distributions. These conditions may include maintaining a minimum debt service coverage ratio. Check past performance for how close to the line the project has been performing.
Real estate can be the most expensive part of diligence. The project needs not only the right to be on the site, but also easements for rights of way for things like power lines and the project substation to move the electricity to market.
Common problems are where a developer failed to spot protected wetlands or where someone else holds rights to subsurface minerals and the exercise of those rights might disturb use of the surface for a wind farm. Title insurance should be in place with a "non-imputation endorsement" covering all of the land rights.
A non-imputation endorsement allows a buyer of the project to receive the full benefit of the title insurance policy by denying the title company the ability to reject coverage by imputing knowledge to the buyer that only the former owner (seller) had. Without such an endorsement, the insurer could reject a claim if the title defect was created or known by the prior owner.
The title company will require a non-imputation affidavit from the seller. Each title company has its own form. The form should be included as an exhibit to the purchase agreement or the buyer should make it a condition to closing that the seller sign an affidavit sufficient for the title company to issue a non-imputation endorsement satisfactory to the buyer.
Be on the lookout for severed wind rights. In some projects, landowners may have severed their wind rights from ownership of the underlying site. Someone other than the site owner may own the wind lease. State law is unsettled on whether wind rights can be severed. To address this, the purchase agreement should include a condition that the seller secure estoppels from any third party owner of wind rights confirming that it does not have a claim against the site owner, for example, for back payments.
Environmental and Permitting
Make sure the project site is not contaminated because anyone using the site could have to contribute to the cleanup cost. A buyer may qualify for certain defenses against liability under federal law if it did not cause the contamination or make it worse. One requirement to qualify is to have done "all appropriate inquiry" before buying the wind farm. This is usually begun by conducting a phase I environmental site assessment and, sometimes, a phase II investigation. The results of the assessments may suggest rethinking the purchase price, protections in the purchase agreement, environmental insurance or even the purchase itself.
The project must be in compliance with federal and state species and habitat protection laws, such as the Endangered Species Act, the Migratory Bird Treaty Act and the Golden Eagle Protection Act. Failure to comply with these laws can lead to significant fines, curtailment or even criminal sanction.
Other environmental statutes come into play if the project has a federal connection, such as it is on land leased from the federal government. In that case, a more involved environmental impact statement may be required under the National Environmental Policy Act. The National Historic Preservation Act requires federal agencies to "take into account the effect of the undertaking on any district, site, building structure or object that is included in or eligible for inclusion in the National Register" and consult with the state historic preservation officer. A federal permit will be required under the Clean Air Act if there will be storm water runoff during construction into US rivers or lakes.
A series of special permits may be required. These include permits where federal or state waters or wetlands may be affected, county or municipal land use permits, permits to deal with state or local noise limits, possible regulation of "shadow flicker" under state or local law, and demonstration that there are no hazards to aviation if turbines or other equipment exceed certain height limits by obtaining a "determination of no hazard to air navigation" from the Federal Aviation Administration.
The purchase agreement should have indemnities, insurance or purchase price holdbacks to address any issues.
Representations and warranty insurance is becoming more common in acquisitions.
Sellers are suggesting that buyers rely solely on it rather than make claims against the seller or require a cash escrow or holdback to cover potential claims. This is particularly common where the seller is a private equity fund that will want to distribute the full sales proceeds immediately to its investors.
R&W insurance does not cover breaches of covenants by the seller.
Offering to purchase R&W insurance could enhance a bidder's position in a competitive auction. R&W insurance could also help in the future when some of the sellers will remain part of the management team by reducing internal friction if there ultimately ends up being a claim for a breach of a representation.
The cost of such insurance may be below 3% of coverage limits with deductibles of 1% of deal value or less, depending on the size of the transaction. The buyer often pays the insurance premium because it is purchasing the policy, but sometimes the buyer and seller split the cost.
An R&W policy can be bound in as little as a week. Two to three weeks is more typical, but it is not uncommon for it to take longer when there is a large portfolio requiring a significant amount of diligence. During the underwriting phase, the underwriter will review the purchase agreement and due diligence reports or memos. The underwriter will usually want a call with the buyer and its advisers to go over the diligence in detail. The buyer and its advisers should spend time preparing for the call.
The seller usually wants to sell a legal entity.
The buyer would prefer to buy assets so that its purchase price can be reflected in the tax basis in the assets and can be recovered through depreciation. Another reason to buy assets is to avoid inheriting any legal liabilities at the entity level.
Buying assets may not be possible where it would require transferring permits and contracts. The buyer should also be able to have its purchase price be reflected in asset basis by buying an entity that is fiscally transparent for tax purposes.
In a "platform sale," where an existing wind development company, including employees and management, is being purchased, the transaction may take the form of a merger in order to force all the owners to sell. With a merger, as long as equity owners that hold at least 51% of the equity approve the merger, then the transaction will close even if some equity owners are opposed, the target will merge with an acquiring company, with one of the entities remaining and the other ceasing to exist. The merger will be called a reverse or forward subsidiary merger, depending on which of the merged companies survives.
The buyer may have to make various government filings.
Foreign buyers must consider whether to make a filing with a US government committee that reviews inbound investments in US companies or projects that may have national security implications. Most filings are voluntary, but the danger of not filing is the government can force the investment to be unwound later. The committee — called CFIUS for Committee on Foreign Investment in the United States — historically has reviewed transactions in which a foreign person gains control over a US trade or business. However, Congress expanded its authority in 2018 to cover acquisitions of certain non-controlling interests and to make filings mandatory for certain types of transactions. Deals involving critical technology and critical infrastructure are subject to heightened scrutiny and may be subject to a mandatory filing. (For more information, see "US to Review More Inbound Investments" in the August 2018 NewsWire and "CFIUS and China" in the February 2018 NewsWire.)
A filing may also be required with the US Department of Agriculture if the project is on farmland. The Agricultural Foreign Investment Disclosure Act, or AFIDA, requires foreign companies, and US companies in which a foreigner has a significant interest or substantial control, to report transfers of interests, including leases, in US farmland. There are significant fines for failure to comply. Several US states also have limits on the amount of land a foreign entity can own, while others ban foreign ownership of agricultural land completely.
A section 203 filing may be required with the Federal Energy Regulatory Commission. Such filings are required before any operating wind farm that is 30 megawatts or larger in size can be transferred. A transfer of 10% or more of the direct or indirect equity interests triggers an obligation to file. Jurisdictional facilities requiring such filings include physical assets such as the interconnection facilities associated with a wind project and "paper facilities" such as a project company's FERC-approved tariff. Federal filings are not required for assets in most of Texas. FERC usually clears the transaction within 30 and 60 days where a transfer is uncontested.
Finally, the Hart-Scott-Rodino Act requires parties to a transaction that is larger than a certain size to notify both the Federal Trade Commission and the US Department of Justice and to wait out a statutory waiting period (usually 30 calendar days) before closing on the transaction. The size thresholds are adjusted annually based on changes in the gross national product. The filing obligation is triggered currently if the transaction value is more than $90 million, either the acquiring or the acquired party has annual sales or total assets of at least $180 million, and the other party to the transaction has annual sales or total assets of at least $18 million. There are various exemptions that may apply. An exemption that commonly applies to wind farms that are under development and have not generated any revenue is the exemption for "unproductive real property." This exemption would not apply to an acquisition of an operating wind farm or one that is on the verge of beginning operations.