The numbers game

Shopping for project pipelines has been a keen pursuit for solar companies eager to gain a foothold in the relatively young American market. Only in late April, First Solar announced a plan to buy San Francisco-based NextLight Renewable Power for about 285 million U.S. dollars; a move that First Solar said would net it 1.1 gigawatts of projects under development. “There is opportunity to capture more value for our customers and enable growth in a more rapid way by having the captive pipeline,” said CEO Rob Gillette during a conference call with financial analysts.
Touting a growing list of projects – along with their sizes – seems an easy way to neatly summarize a company’s strength, impress the public and perhaps inject some fears into its competitors. But what does the term “project pipeline” really entail? The term generally refers to a list of planned power plants for the utility market in which the customers could be either the utilities, or companies that supply power to utilities. Without some way of defining the term, it’s difficult for supplier and customers, as well as investors, to draw comparisons or gauge whether these proposed projects will progress from ideas to reality.
“The reason for creating stages in a pipeline is to assess the risks and apply values to it,” says Sheldon Kimber, Senior Vice President of Recurrent Energy, an independent power producer in California. “That’s true across wind, gas, solar and other energy markets.”
Ty Jagerson, President of California-based Helio Micro Utility, which develops commercial projects but provides engineering and construction service in the utility market, points out that the description of a pipeline could change depending on intended goals.
“If it’s a pricing discussion, and someone says I’m going to pay you every dollar for every megawatt in your pipeline, then it matters. Then it really makes a difference,” Jagerson said.
While developers don’t use the same metrics for defining the size and maturity of their project pipelines, they do share similar perspectives on determining where along the development timeline to slot their projects. Without getting into those details, however, tossing out the size of project pipelines in press releases or public discussions could invite skepticism.
“The size of pipelines is in large part a public relations tool. It’ll be hard to agree to one definition,” says Shayle Kann, a senior analyst at GTM Research in Massachusetts. “A lot of developers out there would say they have five gigawatts of pipelines, but all that means is that they are looking at leasing land for a potential five-gigawatts.”
There has certainly been no shortage of project announcements in the U.S. Developers and solar panel manufacturers from Europe and Asia have flocked there in the last few years, after seeing a growing number of states requiring its utilities to supply renewable electricity. A national mandate, which is under consideration, could give the market a further boost.
Well over ten gigawatts of utility-scale photovoltaics projects have been announced within the last four years, Kann says. But the complexity of completing them – from lining up financing to obtaining regulatory permits – will whittle the list down considerably. In fact, by Kann’s calculations, about three gigawatts of those are likely to be built in the next four years.
Some utilities have signed deals for more power than they need to meet regulatory requirements, because they can’t be certain that all of the projects would be built. Meanwhile, project developers say tough competition – and tales of those who floundered because they couldn’t get the financing to deliver on the contracts – has weeded out those among them lacking development expertise.

The yardstick

“Developers who promise to build with ten cents per kilowatt aren’t being taken seriously today. A solar Darwinism has taken its place,” says Tom Doyle, President of NRG Solar.
Sunpower, for one, considers five factors in defining its projects – land, contracts with utilities, transmission, government permits and financing – says Tom Werner, CEO of the Californian company. From these criteria, the company calculates the likelihood that a project could move from conception to revenue generation and uses the probability to determine the size of its project pipeline.
“Typically you would assign a zero probability if all you have is land. You need to have at least land, and you need to be short-listed with utilities, so you have an indication of getting a contract,” Werner says. “Utility short listing is a requisite to being on the list. The difficulties of any of other four factors vary depending on where you are.”
Indeed, having a contract in hand – whether it’s to sell power or to provide engineering and construction services to an electricity wholesaler – is a key to accelerating the pace of a project. It creates a desired domino effect. Lining up customers is critical for developers to borrow money or line up other types of financing for their projects. And getting those investments, in turn, will help developers clear major hurdles along the path, from going through a lengthy permitting process to winning approval for connecting their power plants to the electric grid.
Getting transmission access isn’t cheap. For a project of more than 20 megawatts in California, for example, a developer must submit an application along with 100,000 U.S. dollars in deposit, an amount that can vary depending on several factors. Along the process, the developer would be required to fork over another deposit – which could be as much as the first one – in order to keep his place in the queue, says Gregg Fishman, a Spokesman for the California Independent System Operator, which oversees the state’s wholesale electric grid and approves interconnection requests.
Although clinching that contract is crucial no matter where in the world you build a power plant, many developers will tell you that it could be more difficult to come by in the U.S. market than in Europe, where feed-in tariffs not only compel utilities to buy all available renewable power, but also set the electricity’s pricing. The United States has no feed-in tariffs, and developers typically go through lengthy negotiations with each utility or power wholesaler. In more regulated local markets, the contracts will be subject to approval by states or other governmental authorities.
When First Solar said it would buy NextLight, it defined NextLight’s projects in terms of those with power sales agreements and those who don’t. Of the 1.1 gigawatts (AC) under development by NextLight, 570 megawatts are under contracts. After buying NextLight, First Solar will have amassed 2.2 gigawatts of contracted pipeline, says the company, which manufactures cadmium-telluride thin film panels and is using the project development business to gain market dominance in the United States. Beefing up the project pipeline “gives us greater visibility into module demand through 2015 and provides a significant buffer against demand uncertainty,” says First Solar’s Spokesman Alan Bernheimer.

Doing the spadework

A lot of work has to happen before the winning of any contract. NRG considers a project to be in an advanced stage when it has secured a power sales agreement along with a site and requests for transmission, Doyle says. NRG Solar, part of NRG Energy that operates gas-and coal-fired power plants worldwide, jumped into the solar business in the past year. Its first solar power plant in operation is the 21-megawatt project it bought from First Solar for an undisclosed price last year.
Securing land is often one of the early pursuits by developers. Figuring out an optimal place to build a power plant is a decision that could have great impact on the difficulty and costs of getting interconnections and the license to build. Putting a project on public land tends to require a more lengthy environmental review, one which could take a few years for large-scale projects.
During site selection, gaining community support – and endorsements of environmental groups – can be tricky. Solar thermal power plant developers have run into strong resistance for proposed projects in the Mojave Desert in eastern California. First Solar decided to buy an option for a property next to the original location for a 550-megawatt project in central California so that it would have room to create wildlife corridors, preserve agricultural land and win support from local residents.
April Sall, conservation director of the Wildlands Conservancy, says many developers don’t do enough to seek community support. The conservancy has become a leading opponent of solar projects proposed on pristine land – properties, particularly public ones, that haven’t been used for agriculture or other commercial activities. At its urging, U.S. Sen. Dianne Feinstein has introduced a bill to set aside about a million acres for two national monuments, a special designation that would prevent solar project development. The proposed monuments include land previously donated by the conservancy to the federal government.
“Ideally, developers should meet with stakeholders in the area, including major landowners and environmental groups, to get feedback” on their projects, Sall said. “It would save a lot of people trouble, energy and money.”
Once a developer locks down a site and has a good grasp of the interconnection and permitting requirements, then he can be a lot more persuasive when he bids for contracts, Kimber of Recurrent Energy says. This early-stage development also requires some hefty investments. Recurrent, which is largely backed by private equity firm Hudson Clean Energy Partners in New Jersey, could spend hundreds of thousands of dollars for this pre-contract negotiation stage, he added.
“You can’t go to PG&E and say, ‘Give me a contract and then I’ll figure out where to put my project,’” Kimber says. “There are a lot of poorly capitalized developers and equipment manufacturers who think they don’t have to spend money to make money.” Recurrent focuses on projects that are up to 20 megawatts in capacity and serves commercial and utility customers. It has announced 250 MW (AC) of contracts for North America, including 154.5 MW (AC) in Canada. Its global pipeline, including those without contracts, has reached more than one gigawatt.

Does size matter?

Acquisition has always been a strategy for companies to break into a new business or build up its competitive armor in an existing field. But accruing a fat pipeline doesn’t mean its owner could complete the projects.
“What impresses us is what they have done, not what they have in the pipelines,” says Hal La Flash, Director of Emerging Clean Technologies at PG&E, which has signed gigawatts of contracts for solar power in order to meet California’s goals of having 20 percent of the electricity coming from renewable sources by 2010 and 33 percent by 2020.
Still, the American market, being relatively young, hasn’t seen many utility-scale photovoltaics operations coming online. So it’s not surprising that developers do use the scope of their pipelines to convey their ability to execute plans.
Utility-scale generation capacity increased from 22 megawatts in 2008 grew to 88 megawatts in 2009 in the country, according to the Solar Energy Industries Association, which counts power plants as small as one megawatt and doesn’t include concentrating photovoltaics projects. By its latest count published in mid-May, the generation capacity had since grown to 107 megawatts, while the amount under construction reached 63 megawatts. An additional 12 gigawatts were under development.
Last year, Sunpower completed the largest PV project in the United States, a 25-megawatt (AC) power plant for Florida Power & Light. Sunpower, which also makes solar panels, has about four gigawatts of utility and commercial project pipelines worldwide, including 429 megawatts (AC) under contract for three utilities in the United States.
For investors who want to back a project, the size of the developer’s pipeline is unlikely to persuade them to fork over money, Kann of GTM Research says. But utilities could be impressed with the number of power purchase agreements that the developer already possess, given the difficulty of inking them. “Utilities might be more willing to issue PPAs to companies that already have signed PPAs. There is a success-breeds-success element,” says Kann.
The solar market has witnessed some high-profiled acquisitions over the last 18 months. MEMC Electronic Materials, a silicon wafer maker in Missouri, bought Maryland-based Sunedison for about 200 million U.S. dollars. Fotowatio, a Spanish developer, bought most of the power plant assets of MMA Renewable Ventures for 19.7 million U.S. dollars in 2009.
Then there is First Solar, which snapped up Optisolar’s 1.8-gigawatt project pipeline for 400 million dollars last year. Optisolar, which once aimed to be both a solar panel manufacturer and project developer, couldn’t get enough capital to do both. Company executives characterized the failing as a result of the credit crunch while others blamed it on the company’s unrealistic ambition and a lack of the expertise to achieve it.
First Solar also bought projects from Edison Mission Group for an undisclosed sum. First Solar didn’t specify the size of the projects when it announced the purchase in January this year, except to say that the projects ranged from 20 megawatts to 150 megawatts and weren’t under contracts.
First Solar, the largest solar panel maker in the world, already has the largest contracted project pipeline in the United States (see chart). After it buys NextLight, which happens to have the second largest contracted pipeline, First Solar will become a giant in a land of, mainly, munchkins.
That dominance, even on paper, should make its competitors pause. It has certainly raised questions about whether the company could serve its customers as a panel supplier when it also could be competing against customers for development contracts.
First Solar executives say they don’t see it that way. Chief Financial Officer Jens Meyerhoff told analysts in April that First Solar’s customers either need solar panels or both the equipment and engineering and construction services, so First Solar has simply expanded its offerings.
The reality isn’t so clear-cut. Companies that want First Solar’s panels could end up bidding for the same contracts as First Solar goes after power sales agreements with utilities, even if it’s looking forward to selling the projects later.
Some power producers believe they can get better returns by doing their own development work rather than buying finished power plants. “We like to negotiate our off-take agreements instead of taking in some else’s,” says Doyle of NRG Solar. “We have a team looking into opportunities and taking projects forward.”
There certainly seem to be plenty of opportunities. PV power would become an even more attractive form of renewable electricity as prices for equipment and construction fall. Whether these hefty project pipelines will become clean power generators or simply pipe dreams remains to be seen. SunPower’s factors in defining projects: land, utility contracts, transmission, permits and financing.