This article, from law firm Chadbourne & Parke LLP, was authored by Paul Kaufman, and provides a look at the financials and costs of owning a wind farm.
Private equity funds and pension trusts that are unable to use the large tax subsidies on U.S. wind farms may have an opportunity shortly to acquire operating projects.
A significant number of U.S. wind farms will have been in operation for at least 10 years by the end of 2013. These wind farms qualified for 10 years of production tax credits on their electricity output. The credits are 2.2¢ a kilowatt hour. The fact that the United States subsidizes construction of new renewable energy facilities through tax subsidies has made it difficult for one without a U.S. tax base to invest in such projects. Most projects have been financed to date in the tax-equity market. There are roughly 20 active tax equity investors.
The United States had an installed wind capacity of 6,350 MW at the end of 2003, according to data collected by the us Deparent of Energy. Those projects will be at least 10 years old by the end of 2013.
Will the developers who still own them be interested in selling?
Developers sell projects for various reasons. A developer may need to rebalance its balance sheet or generate cash to develop other projects. Exhaustion of production tax credits may be an opportunity for the developer to exit as the value of the project at that point will be limited to the project’s cash flow. The developer may have an added interest in selling if the project has underperformed, because the cash needs of the project for maintenance may be a strain for the developer or the project may need additional capital improvements.
Reliable revenue stream?
Purchasing a project that has been in operation for 10 years raises a number of due diligence questions. Knowing where to probe will save time.
One of the first places to focus is the status of the power purchase agreement under which electricity, renewable energy credits and other attributes from the project are being sold.
The first step in evaluating the power contract is to gather all of the documents that govern performance by the parties. Many utilities buying electricity from independent generators under long-term contracts use “administrative guides” or “operating committees” to administer such contracts. A review of the administrative guide or the minutes or records of the operating committee is advisable.
If the electricity is being sold to a regulated utility, another key document is the order by the state public utility commission authorizing the utility to pass through the electricity price under the contract to its ratepayers. Be sure to check whether the public utility commission imposed conditions. Some state commissions require periodic review of the rate order.
Check whether the offtaker, or agency that regulates its rates, has developed buyer’s remorse. While someone buying a wind farm may see it as a plus that the power contract requires the local utility to pay above-market prices for the electricity from the project, the utility and its regulators may not see it the same way. How great a risk is there that the utility will want at some point to try to get out of the contract? Will it be encouraged to do so by its regulators? Check whether the utility’s consent is required to a sale of the project company, as that may give the utility leverage to insist on lower electricity prices.
More recent power purchase agreements or PPAs demand a higher level of performance from wind developers and give the utility greater operational flexibility than what was found in older PPAs. Older PPAs may have had a mechanical availability guarantee, but were unlikely to include performance guarantees. An availability guarantee requires the project to be available a minimum percentage of the time to generate energy. A performance guarantee requires the project not only to be available, but also requires the wind to blow.
Older PPAs usually made the utility responsible for curtailments beyond the point of delivery (which was generally the project busbar). The utility had to keep paying for the electricity that was curtailed. Newer PPAs generally require the project to shoulder some portion of the risk of curtailment beyond the busbar.
Be sure to check how the project has performed. Did it breach availability or performance guarantees? Has the project paid liquidated damages to the utility or received notices of noncompliance or default? Have disputes, formal or informal, been initiated by either party? Has the project company met all of its reporting obligations under the PPA?
Have there been uncompensated curtailments or have all curtailments been compensated by the utility? If the project went uncompensated, has the cause for the curtailment been mitigated or eliminated?
Finally, focus on the market in which the utility is located. What other options are there for selling electricity if the utility defaults? Evaluating the financial strength of the utility is a critical issue. Has the utility maintained its credit rating? Has there been a substantial change in the utility’s load or customer base?
Fully derisked project?
There are other due diligence issues to consider. On the positive side, the performance of the project will be well understood. Wind projections will have been verified or vilified.
Further, to some extent, major equipment problems are likely to have surfaced after 10 years of operation. The break-in period for the project will have been enjoyed or suffered by the original owner. Nevertheless, the buyer should determine whether the project is “broken” or just “broken in.”
For example, due diligence should include a review of the project’s past operating history, project availability, outages and maintenance records, and a review of the turbine manufacturer’s performance across other operating projects. A careful review of the owner’s capital invesents and expenses for operation and maintenance will be helpful to determine whether maintenance or repairs were deferred.
If possible, the buyer should consider whether the type of equipment in use at the project has met performance expectations at other projects. For example, has the turbine manufacturer been subject to serial defect claims that might affect the project’s turbines?
While warranty periods in turbine supply agreements of the 2002 and 2003 vintage generally lapsed after two years, a purchaser should nonetheless be concerned with the turbine supplier’s ability to continue to provide spare parts or be sure that substitutable parts are available from other suppliers. Review how well outside contractor to whom the project has hired out operation and maintenance has performed.
Does a project stay “developed” once it is fully developed? If a project has been operating for 10 years, is it reasonable to assume that site control (land and title), permitting and community support are free from issues?
While the project may have been scrubbed for development flaws when it was financed, and development flaws will tend to reveal themselves with the passage of time, it is best not to assume that the project is free of development issues. The passage of time is not always kind to developed projects. The buyer should consider whether the owner has maintained site control as well as the priority of its claim over the site in the chain of title. A new phase I environmental assessment should be ordered to ensure that the site remains in an acceptable environmental condition. Consider asking for a new survey to check for new crossings, easements or other uses of the land, such as mining or gas drilling, since the project was originally financed.
Wind farms operate under permits that may have conditions on continued operation. Check that the project has complied with all permitting conditions, including requirement for post-operation reports and studies. Check whether endangered or threatened species have moved closer to the site since the project was built. Did the project take on study or reporting requirements with respect to flora or fauna and, if so, are there open-ended mitigation obligations that spring from the reports?
Unfortunately, regulatory requirements are not frozen in time once a project has been built. Check for new compliance obligations. For example, in 2002 wind projects were not regulated by the National Electricity Reliability Council and its regional reliability councils (such as the Western Electricity Coordinating Council). However, it is now clear that wind projects are subject to reliability regulation and, accordingly, every project needs a compliance plan.
Joint venture owner?
If the project is owned in a joint venture and less than all the joint venture interests are being purchased, be sure to understand the rights and obligations of the joint venture partners by reading the operating agreement. Most joint ventures are limited liability companies. There are a number of issues to consider.
For example, the other joint venture partners may have a right of first offer or an option over the interests being sold on the same terms as the proposed sale. There may be a waiting period before the sale can close. Even if there is no right by the other members to buy, their consent may be required to a sale. Joint venture agreements vary on how far up the ownership chain the restrictions on sale apply.
In joint ventures between a developer and a financial party, the developer usually has day-to-day control over operation of the project. A list of major decisions requires consent by the financial investor. If buying out the financial investor’s position, be sure to check, if possible, whether the parties had a good working relationship.
A buyer should understand the status of each party’s capital accounts. Each partner in a joint venture has a capital account that is his claim on the project assets if the joint venture liquidates. If there is still outstanding debt at the project or joint venture level and the person selling claimed tax depreciation on the project, then there may be “phantom” income that the owner of that position will have to report in the future as the remaining debt principal is repaid. The project will have income from future electricity sales on which taxes will have to be paid by the partners, but the cash will go to pay debt service. The “phantom” income tied to principal repayment must be allocated to partners in the same ratio they claimed tax depreciation on the project.
Check how the joint venture agreement addresses deadlocks between the partners. Is there is a fair and manageable process for dispute resolution? Some operating agreements provide for a “shotgun” resolution of disputes. Under this mechanism, a partner disputing the decision of another partner offers a price at which he must either sell his interest or buy the other partner’s interest.
Check the mechanisms for budgeting and calls for additional capital. Many operating agreements provide for dilution of a non-contributing partner’s interest in the event of an unfulfilled capital call.
While uncommon, projects that reached commercial operation in 2003 may be owned by a “flip” partnership. A flip partnership is a joint venture between a developer and a tax equity investor.
In a partnership flip, the joint venture usually allocates 99% of income, tax losses and tax credits, and distributes 99% of cash, to the tax equity investor until it reaches a target yield, after which the interest of the tax equity investor drops to 5% and the developer has an option to buy the tax equity investor’s interest.
If buying the tax equity investor’s interest, be sure to check whether the tax equity investor has a negative capital account. Some tax equity investors agreed to “deficit restoration obligations” to absorb more tax benefits. The holder of the interest would have to contribute capital to the joint venture upon liquidation in the amount of capital account deficit.
Most operating agreements also bar a transfer of a joint venture interest if the transfer would cause the joint venture to “terminate” for tax purposes. It terminates if 50% or more of the profits and capital interests in the joint venture are transferred within a 12-month period. Termination could have an economic cost, although it is not likely to have much of one for a 10-year-old project. Federal Energy Regulatory Commission approval will also be required to transfer an interest in the project. Such approvals usually take 45 days. State approval may also be required.
Improving the value proposition
Are there ways for a buyer to squeeze more value out of the project?
For example, is it possible to add or improve turbines under the existing PPA and the permit and land rights for the site? Wind technology has improved substantially since the turbines were installed at 2003 and earlier projects. Are these improvements substantial enough to justify the capital invesent required to install additional turbines or retrofit existing turbines?
Can the purchaser capture other intrinsic or extrinsic value? For example, is there spare capacity under the interconnection agreement and interconnection facilities that would allow a thermal or solar resource to be added to the existing wind resource?
Another factor that will improve the value proposition is the resetting of depreciation. The purchase price can be recovered through depreciation. A carefully planned due diligence effort is required before buying operating plant. That is the only way to prove the value proposition with certainty.