[Editor's note: Shortly after this focus went to press, the US senate passed tax legislation that included an extension to the cash grant for renewables projects. For more details of the programme, see below]

Wind power generation in the US has been the domain of small and mid-scale developers for much of the past decade. It has evolved into a neatly-executed model of construction-to-tax-equity financing. The partnership flip structure, the centre of this model, is based on two tiers of equity, and allows sponsors to maximise their tax benefits and reap the rewards for assuming development and construction risk.

However, the credit crunch and policymakers’ responses to it have created opportunities for new ownership struc­tures, and may hasten consolidation, or at least some equity recycling, in US wind. Waqar Zaidi, who leads renewable energy for Enbridge, notes that, “The market was built through entrepreneurship supported by tax incentives from the 1990s until around 2000. By selling on the assets post-construction, there was a greater added value.”

Despite the increases in debt costs, which are only starting to abate, the utilities that buy power are looking to drive down costs. Says Zaidi “in 2008 and 2009, investors hold­ing assets were making a good return on the PPAs, but there has been a downward pressure on the PPA rate and the market wants to see less arbitrage and to eliminate the middle man.”

Challenges in the market

The number of PPAs to come to market in the US post-Lehman era has dropped significantly; by as much as 50% according to an adviser with experience in the US wind power market since its inception. The way offtakers procure their wind power has also become more competitive. Requests for proposals seek the lowest cost of power per megawatt hour and one sponsor notes, “There were about 50 bidders for a recent Midwest project with only 200MW of capacity. It is becoming fierce.”

According to Richard Ashby, former CFO of Renewable Energy Systems’ Americas subsidiary, “there is far less value placed by acquirers on development portfolios without off-take. Not so long ago, buyers were ascribing significant value to early and mid-stage projects, this however is no longer the case. I think the market has accepted that in a highly competitive and challenging environment, development assets don’t necessarily and seamlessly translate into contracted, operational projects.”

Capacity constraints have also become more commonplace as the US wind power market has matured, with transmission operating at capacity in some regions, which has in some cases devalued generation assets.

The impact of constricted credit markets has inevitably taken its toll on developers and sponsors. The demise of Babcock & Brown, which pioneered the partnership flip model on its North America wind assets, shook the market considerably. A high-profile casualty of the credit crisis, its legacy has proved damaging for some developers which had adopted its strategies for making high and speedy returns on both regular and tax equity investment. Babcock & Brown Wind’s successor entity, Infigen, has struggled to sell its US portfolio at an attractive price.

Utility appetite and demand

According to Ashby, “Utilities are becoming increasingly sensitive to developers flipping projects with the power purchase agreements included, and extracting a premium which the utilities believe should be passed on to the rate-payer.” This disquiet echoes the argument that has carried on in PPP circles as to how public and private sectors should share the gains of project refinancings. The cost of power to end-users during a recession has become an issue, and regulators and politicians have not hesitated to make their views known to utilities.

Some utilities are beginning to seek out ownership of assets, as evidenced by the recent acquisition of John Deere Renewables, a 735MW wind portfolio, by Midwest utility Exelon Corporation. Exelon financed the $860 million ac­quisition with a $900 million corporate bond issue. Around 75% of the capacity is contracted through long-term PPAs. Exelon was able to achieve low pricing on the bonds by financing them at the same level as its existing unregulated, predominantly baseload conventional power assets, which would have been impossible for a pure-play independent renewables generator. The issue comprised $550 million in ten-year notes carrying a 4% coupon and $350 million in 31-year notes with a coupon of 5.75%.

But while they may boast a low cost of capital, not all utilities are in a position to own and operate wind power assets outright. “There is a need to create efficiencies in the supply chain. Utilities awarding PPAs are increasingly trying to build relationships with whoever is likely to be the last or long-term holder of the asset,” says Zaidi. “It’s more efficient for them. It reduces their cost of capital and mitigates some of the risk as there is greater certainty in knowing who will hold and operate the asset for the foreseeable future.”

Enbridge, notes Zaidi, has a $30 billion balance sheet and has acquired around C$1 billion of contracted wind assets in Canada over an 18-month period. “There are very few developers who have the balance-sheet flexibility to choose between corporate finance or project finance,” he says. Enbridge’s wind power purchases to date have been funded with corporate financing, which Zaidi believes has been the most cost effective way in recent months.

“We wouldn’t rule out project financing if the rates were appealing and the risk was manageable,” he says.”But it’s a question of comparing A-rated corporate debt with the cost of project loans. Risk spreads have increased over the last three years.”

Economies of scale

Small developers, chasing a number of uncertain prospects, need to reap sttractive returns from flipping assets at completion. “Smaller developers tradi­tionally deployed a small amount of capital, seeking a rela­tively large re­turn,” says Zaidi. “Bigger companies such as Enbridge can make a bigger, long-term capital deployment with a similar risk and return profile as the traditional builders, but for long term growth, which provides greater value for money to the utility and to the rate-payer. The development market has provided the opportunities for companies such as Enbridge to enter this market."

According to Zaidi, cutting out the debt service requirements of more tradi­tional project finance and accept­ing a more moderate rate of return on its investments, Enbridge can make the case for efficiency while still making a substantial profit. “Participants need access to larger sums of capital and credit support in the US, and securing off-take agree­ments has become intensely competitive,” says Ashby. “The requests for proposals from utilities are rigorous, seeking advanced developed projects with the lowest cost over a 20-year period. Recently, in some instances there have been scores of bidders for small contracts. This kind of market places a premium on scale bidders that can access the capital markets efficiently and opportunistically and can procure equipment and services at a material cost advantage.”

“Utilities are looking at balance sheet risk in the long term, and the efficiencies larger companies have in raising corporate debt with a lower yield,” notes one investor. “Even a difference of 50bp to 100bp is considered an advantage.” There are a number of wind industry players that are of a sufficient size to participate at this level: Iberdrola, BP, EDP’s Horizon, EDF-EN/enXco, AES, and NRG, for example, are all active in the US market. The larger players, however, have very different levels of experience in developing and acquiring wind farms.

Local expertise

Though Zaidi and other new, big entrants to the wind market believe that there are a number of financial inefficiencies in existing practices, the experience that these developers have acquired over the past decade and more is useful. “Wind was formerly a relatively small industry,” says Ashby. “The industry has grown significantly in the past five years or so and market interest, capital and experienced industry veterans has transitioned from coal and gas-fired IPP and utility sectors to the wind market.  The growth has provided potential for investment, and opportunities to deploy capital. The US market has learned a lot from Europe in terms of commercialisation and is showing signs of leveraging knowledge from other regions and sectors and applying it to the wind market.

“The wind market has also become increasingly stratified. Smaller developers typically excel at outreach to the land owners and building the relationships necessary at the in the early stages of project development. However, development has become more expensive in general due to enhanced permitting and environmental requirements and higher land lease and option payments.

“The trend for consolidation is accelerating, similar to what has already occurred in the gas-fired IPP sector over the last 10 years. Smaller, mid-size and a handful of large developers have been and will continue to be consolidated into an industry dominated by large, well-capitalised play­ers looking to have a long-term relationships with the utilities.”

Though smaller developers will see smaller returns than those to which they have become ac­customed, their chances of being awarded a PPA may increase. For de­velopers that have suffered from con­strained capa­city, a reduced return percentage could prove more appealing than sitting on a dormant asset.

Large asset buyers can enjoy a natur­al hedge from dealing with a variety of smaller regional developers, because the US wind market is geo­graphically diverse. “Look at Texas,” says one de­veloper, “It’s a very welcoming state for us because wind farms can be installed away from population density. Con­versely, there are massive permitting problems in the north-eastern states because though people are theor­etically in favour of renewable energy, there is a not-in-my-back-yard mentality, as there is with UK onshore wind development.”

Consolidation and utility involvement

As the market reaches maturity, it has become an appealing opportunity for pure equity players, as several infrastructure and power funds have begun to realise. For as long as developers could claim an upfront cash grant from the US treasury instead of production tax credits, the complex tax structuring needed to allow non-US taxpayers, including funds’ limited partners and foreign utilities, to use them became much less important. But whether the two-year-old grant, or even the investment tax credit, the slightly more digestible tax credit that the cash grant monetises, survives the winter is uncertain.

Whether the smaller but more venerable developers will continue to provide large buyers with access to their pipe­lines remains to be seen. Many will be reluctant to merge with larger investors or divest assets wholesale. The number of responses to RFPs in, for example, Wyoming, Indiana and across the Midwest indicates that there are still scores of bidders resisting consolidation. But with a failed bid costing each developer upwards of $3 million, repeatedly losing out on PPAs could take a considerable toll on smaller balance sheets.

However, both government and utilities are growing weary with the complex tax structuring that accompanies new wind development, especially where their incentives are captured by tax equity investors rather than passed on to rate payers. The practice has continued thus far because, says one developer, “The tax credit mechanisms are complicated, convoluted and inefficient.” Though utilities may eventually follow the Exelon lead towards direct ownership, a market shift of such proportions will not happen quickly and many utilities have neither the means nor the inclination to become quite so directly involved. n