Wind project financings in the US now rely on the production tax credit (PTC) to monetise tax benefits, especially since the US Department of Treasury’s cash grant programme ended on 31 December 2011. Some projects were grandfathered into the cash grant programme, but the number of eligible projects is dwindling. So, the wind sector was especially nervous during 2012, as the PTC neared its own expiry at year-end. The PTC paid $0.022 per kWh in 2012. Congress ultimately extended the grant – but on 1 January 2013, hours after the subsidy had formally expired.

Preserving the PTC was not, however, the only goal for renewables developers, lenders and investors in 2012. Industry groups lobbied Congress and the Internal Revenue Service (IRS) to help them attract retail investors into renewables – efforts that have continued into 2013. To unlock retail interest, the renewables industry is urging Congress to allow master limited partnerships (MLPs) to invest in renewables assets, while real estate investment trusts (REITs) are leaning on the IRS to allow them to own wind or solar capacity. At least one vehicle exists that does not require legislative or regulatory involvement. KeyBanc Capital Markets is promoting C corporations as listed vehicles that could draw in retail investors.

Project Finance decided to examine market sentiment in US renewables in light of the PTC’s extension, the efforts to expand the investor base and potential innovations to the basis of wind project financing. Project Finance contacted four leading players in the US wind sector:

• Jim Murphy, Invenergy’s chief financial officer and chief operating officer
• Sean Finnerty, senior vice-president at Competitive Power Ventures
• Daniel Brown, vice-president in KeyBanc Capital Markets’ utilities, power & renewable energy group; and
• Keith Martin, partner at Chadbourne & Parke.

Brian Eckhouse, Project Finance (BE): Let’s start by discussing the state of the tax equity market. It seemed that investors had growing appetites for solar in 2012. Are there indications that this will hurt the wind sector in 2013?

Keith Martin, Chadbourne & Parke (KM): There are roughly 20 active tax equity investors. The cost of tax equity has remained fairly stable the last two-and-a-half years. If anything, it has been trending down slightly. If solar demand picks up this year, then that could cause the cost of tax equity to increase. The cost is strictly a function of demand and supply. It does not move directly with interest rates. However, we have not seen any evidence of an increase. As I said, if anything, the cost has been trending down slightly.

BE: What types of unlevered and levered yields do tax equity investors expect for wind deals?

KM: Unlevered yields are in the 7.5% to 9% range, depending on the developer and the project. If there is debt at the partnership or project level, then the tax equity investor will require a 500bp to 800bp yield premium.

BE: Two common financing structures in the US wind sector are the partnership flip and the sale-leaseback. Has one won more favour than the other in the recent months and, if so, why?

KM: We are still seeing a lot of partnership flips. There has been a move lately toward fixed-flip structures, where the tax equity investor’s interest in the project flips down after five or six years, regardless of yield, and to pay-go structures, where the amount the tax equity investor invests is tied in part to output and, therefore, indirectly to tax credits. Sale-leasebacks work in the wind sector only for projects on which a Treasury cash grant or investment credit will be claimed. 55% of wind farm tax equity deals involved production tax credits in 2011, and 75% involved production tax credits in 2012. You can’t do a sale-leaseback of a wind farm and claim production tax credits. The US tax code does not allow it. Thus, if anything, trend in the wind market is to greater use of flip structures or, perhaps more accurately, that market is not abandoning flip structures.

Sale-leasebacks should become more common in the solar market. There is a disagreement among some law firms about whether there is a heightened risk of recapture of investment credits in partnership flip deals. The IRS is also raising questions about whether the tax equity investor in a flip deal is truly a partner if he gets back his investment fully in year one through the investment credit, utility rebates and a depreciation bonus. These issues may drive more companies to sale-leasebacks.

BE: Daniel, we’re seeing tax equity investors sell their stakes in wind projects to other investors. What is driving this?

Daniel Brown, KeyBanc (DB): Sales of tax equity stakes became more common beginning in mid-2012. The first driver is that mature tax equity positions are increasingly looking like cash equity positions, because most, if not all, of the tax benefits have expired, but the projects have not flipped, as projects have not performed up to expectations. This may be due to flawed wind studies, maintenance issues or curtailment. The second driver is that there are increasing pools of yield-oriented investors who are willing to invest in renewable energy transactions, and see these tax equity stakes as desirable investments. As more tax equity positions approach their flip dates, I expect to see more of these sales occur.

BE: Some wind proponents say the prolonged uncertainty over the PTC last year will curtail deal flow in 2013. Do you agree?

DB: Certainly there were many developers who put capital expenditures on hold due to uncertainty related to the PTC. So, from a financing perspective I expect there to be a lower level of deal flow in 2013 versus 2012, as many of these newly qualified projects may not require construction financing until 2014.

Sean Finnerty, CPV (SF): Deal flow in 2013 will be impacted by the PTC but it will also be impacted due to many utilities responding to the looming PTC expiration and buying a lot of wind in 2011 and 2012. We expect that only 1GW to 2GW will reach commercial operation in the US and, depending on how the PTC rules ultimately get defined, another few GW may enter construction for a 2014 commercial operation date.

Jim Murphy, Invenergy (JM): As far as preserving deal flow for 2013, it depends on the exact circumstances of a particular project. Some power purchasers were willing to execute PTC-contingent agreements in 2012. In these cases, proceeding with project financing in early 2013 became feasible following the PTC extension. Other power purchasers preferred to wait for the extension. Some of these parties are uncertain that a subsequent extension will occur, and are keen to sign PPAs in 2013. Those projects, of course, will have to start construction before 1 January 2014, and so financing likely would be completed in the third and fourth quarters of 2013.

SF: Businesses need a level of certainty in order to invest and the short-term extension of the PTC, with now unclear rules, does not provide the level of certainty needed to make long-term investment decisions. As a result of this uncertainty and lack of a long-term resolution there has been a pull-back of investment across the wind industry, from the turbine supply chain to operations and maintenance service providers to developers. With the short-term PTC extension, some of these businesses are working to get on track to respond to the market – but the willingness to make long term investment decisions with such policy uncertainty is still difficult.

KM: The PTC extension that Congress passed could carry the industry into 2015. Depending on what happens to natural gas prices, the industry could be within reach of being able to stand on its own.

BE: With the grant-centric deals largely done, how common is it to finance a project without the PTC?

JM: It’s not common at all – which is not to say it would be difficult. Quite to the contrary, it would be much more straightforward than a project financing that requires tax credit monetisation. But it is difficult to envision a project that would have acceptable returns absent a PTC or ITC.

KM: Smaller to medium-sized developers have a hard time today raising tax equity. The tax equity players all want to deal with the same handful of large balance-sheet players. It is challenging to finance a wind farm without using the tax benefits or getting value for them, but it has been done. A contracted project where the electricity price is high enough to satisfy debt-service coverage ratios would have the easiest time.

BE: As utilities begin to hit their renewable energy portfolio standard (RPS) targets, new power purchase agreements have become scarcer. Is the paucity of wind PPAs a bigger hindrance to deal flow than the existence of the PTC?

JM: It depends. Some projects have been viable without PPAs because, in certain markets, they can be hedged long-term via financial players, and/or they have other revenue streams such as renewable energy credits (RECs). But both PPAs and PTCs remain critical to achieving a robust deal flow.

SF: PPAs are scarce because utilities bought a lot of wind the past couple of years. Nonetheless, PPAs are still out there and being competed for. The challenge for developers will be managing to ride through the next few years as demand returns and state-level renewables portfolio standards catch up with existing supply. Whether or not securing a PPA or the uncertainty around the PTC is a bigger hindrance to new projects depends on a company’s risk appetite. For developers that have the risk appetite and the capital to build these projects on a merchant basis, the PTC risk becomes the larger hindrance. Uncertainty lies in how many merchant wind projects get built in the next few years.

BE: How would a developer go about financing a wind farm in the US without the PTC?

SF: Without the PTC, financing a wind farm would be similar to financing a natural gas fuel generating project or any other conventional generator. Like with those traditional generation projects, the wind farm sponsor would approach the debt markets and work to secure financing based on the profitability of the specific project. This has been the case for a number of wind farms in the US in recent years as developers were able to take advantage of the Treasury’s cash grant programme.

DB: The lack of a future PTC extension will signal the end of tax equity as we know it. Monetising depreciation in the absence of a PTC, ITC or cash grant is extremely inefficient. Consequently, for developers without tax appetite, developing projects with acceptable rates of return will become even more challenging. The easiest solution to this problem would be to develop projects, and then sell them prior to COD [commercial operations] to entities with taxable income (such as utilities), but the universe of logical buyers who have material taxable income is decreasing. Recognising this reality, developers will likely focus their efforts on states with robust renewables portfolio standards, where REC prices may compensate for the loss of PTC economics.

JM: If modified accelerated cost recovery system (MACRS) benefits remain available, but there is no PTC or ITC, I doubt it would be worthwhile to structure a tax-oriented deal to capture that value. Rather, the developer likely would retain the MACRS benefit to shelter its other income. Project debt financing could come from banks and/or institutional lenders, and equity could come from sponsors, infrastructure funds, and potentially publicly-traded vehicles.

DB: REITs and MLPs are commonly discussed vehicles through which renewable energy projects can unlock the public equity markets. But to be most effective, both require significant legislative changes. An attractive alternative which is available today is to form a dividend paying C corporation containing primarily operating assets – called a YieldCo – and access equity priced similarly to REITs and MLPs. We believe you will see multiple YieldCos launch initial public offerings in 2013.

KM: Wind companies raise capital from up to six tiers of capital. Working from cheapest to most expensive money, they are Treasury cash grants, government-guaranteed or enhanced debt, straight debt, tax equity, back-levered debt and true equity. The two cheapest tiers of capital are largely disappearing. If tax equity also disappears, then the cost of capital will increase.

The industry has been looking for ways to bring down that cost, focusing primarily on how to reduce the cost of true equity. Various wind companies are looking at moving their operating assets into publicly-traded vehicles and then raising equity by selling interests. The equity can be raised at higher multiples to earnings because the projects will have been “de-risked.” They produce predictable cash flow. The fact that the ownership interests can be sold in a liquid market also makes them more valuable. These YieldCos take several different forms, including Canadian income trusts, REITs and synthetic MLPs.

BE: Renewables groups have lobbied for MLPs to be available to their sector. But will the Congressional push for tax reform preserve the status quo?

KM: Master limited partnerships are picking up support on Capitol Hill. Senator Chris Coons (D-Delaware) has done an excellent job of drawing attention to them. Senator Lisa Murkowski (R-Alaska), the senior Republican on the Senate Energy Committee, said in February that she also supports allowing their use by renewable energy companies. It will still be an uphill battle to get this through Congress, but the issue is in play. There is no current legislative vehicle to consider them. The most likely place to consider them is if and when Congress ever takes up corporate tax reform. Congress will have to consider then what types of companies and industries it is willing to let operate without having to pay corporate income taxes. Minerals and natural resources companies have a pass on corporate income taxes today. The question is whether Congress will expand that category. Other industries besides renewables are also vying for the same treatment. The renewables companies say they need parity with fossil fuels.

BE: What type of private placement appetite exists for greenfield wind farms?

DB: At KeyBanc, we get increasing number of calls from insurance companies looking for renewable projects to invest in. Clearly, the market exists for operating projects, and increasingly, investors are willing to look at greenfield assets as well. From a developer perspective, the appeal of using bank financing during construction is that there is more flexibility in when construction funds are drawn. An insurance company will look to have a defined draw schedule at financing close, and if funds are not needed in line with that schedule a developer will have to bear the funded cost of debt as opposed to a commitment fee. When this occurs, it is adverse to equity returns.

BE: What are the advantages of a financing structure mixing bank debt and an institutional tranche?

JM: For large transactions, like the one Invenergy completed in 2012, access to both capital markets was important in order to fully subscribe the debt requirement. The institutional tranche provides extended tenor – versus the bank market, which is constrained to shorter-term or mini-perm deals due to rising funding costs. The bank tranche reduces the amount of principal subject to make-whole premiums in the event of a refinancing. These hybrid financings usually are marketed with significant anchored amounts identified for each tranche – which reduces subscription risk – and with pre-negotiated inter-creditor arrangements, which reduces transaction costs.

SF: Pairing commercial banks with institutional lenders may allow the borrower to optimise the financing structure. First, on an aggregate basis, it can provide the borrower with the tenor it is seeking. Second, it can provide the borrower with some optionality with regards to fixed- and floating-rate debt, thereby minimising potential pre-payment penalties and make-whole liabilities traditionally associated with institutional loans. Third, it may result in a blended lower cost of debt, assuming the bank tranche amortises completely over the shorter-term, thereby not attracting the otherwise higher reserve requirement and associated increased cost of funding, while the institutional tranche extends over the longer term. And fourth, it allows the banks to more efficiently provide the credit support and working capital facilities alongside longer-term institutional debt.

DB: There are multiple factors encouraging these transactions, including minimising execution risk. First, while 18-year fully amortising financing was readily available for strong projects two years ago, there are now few lenders in the market willing to provide that long of a tenor as a result of the European financial crisis. In many ways, 10 years has become the new 18 years, and mini-perms are the preferred structure for the majority of lenders. The second factor is that there are an increasing number of insurance companies active in the wind and solar financing space. Finally, current all-in rates for debt financing are extremely attractive by historical measures, and developers are keen to lock these rates in for the life of their projects.

BE: We’ve seen hedged deals for gas-fired projects clear the term loan B market recently. Now, there’s talk of financings for wind farms that rely on hedges in lieu of power purchase agreements, which Jim referred to. Is there a sense that financing markets would be willing to accept hedged wind deals that feature revenue floors?

SF: Hedges will continue to be a vehicle that developers use to secure project financing in liquid markets, such as in the PJM and ERCOT interconnections, and lenders will continue to look at how to supply financing to projects with hedges.

DB: There are more wind deals with hedges that are coming to the market in 2013. While these can be financeable if structured properly, there are certain issues developers must consider. Financial hedges are generally executed at liquid electricity hubs which may not be close to project’s point of physical interconnection. Basis risk may exist between these two locations may exist which can be difficult to quantify.

BE: For all the talk about the retreat of European lenders and, accordingly, depleted liquidity, some large deals closed in the US in 2012, including the $3.6 billion bank deal for the Sabine Pass liquefaction project. Does this portend a strong market reception for offshore wind projects in the US?

DB: The Cheniere transaction was evidence that rumours of the demise of the bank market have been greatly exaggerated, and that sponsors with strong relationships are likely to have successful transactions. Generally the bank market is open for creditworthy onshore wind projects, and I believe the same to be true of offshore wind.

SF: The market reception for offshore wind will depend on the number and size of other opportunities in the market. Offshore wind needs to become a bit more cost competitive relative to onshore wind projects and other generation.

BE: Will tax equity investors be drawn to offshore wind?

KM: We are about to find out. The Cape Wind project will be sounding out the tax equity market shortly. The project will need a two-year forward commitment from tax equity investors; it has a long construction period. The same structures used for projects on land also work in theory for offshore projects.