PV's Promise

Fortnightly Magazine - May 2009

Chris O’Brien is no starry-eyed idealist. An engineer with an MBA, he began his career developing fossil-fired power plants for the AES Corp. But in the 1990s his career took a different turn, when he launched the Energy Star program for the U.S. Environmental Protection Agency. After that, he went into the solar energy business, and never has looked back.

Before joining Oerlikon Solar, O’Brien developed markets for photovoltaic (PV) modules in positions at BP and Sharp. From 2003 through 2008, he chaired the Solar Energy Industries Association (SEIA), the national trade group for solar equipment manufacturers. Now he’s working to build a network of PV-module manufacturers using Oerlikon’s cell-production lines.

To discuss the outlook for utility solar investments, Fortnightly met with O’Brien in his Washington, D.C., offices early this year, and followed up by telephone in March.

 

Fortnightly: What does Oerlikon do?

O’Brien: We’re a leading global supplier of thin-film PV technology. We’re headquartered in Switzerland, but we have customers around the world. We don’t produce PV modules, but we supply turnkey manufacturing plants to customers that produce modules. In contrast to more vertically integrated PV suppliers, our approach is different. We have 10 customers who are now in production or construction, representing nearly 600 MW of cumulative PV manufacturing capacity.

 

Fortnightly: Where do you place PV in its evolution as a power source? Is it still a niche solution or is it entering the mainstream?

O’Brien: Solar has a long history of promise, for some good reasons. It’s environmentally benign, and the resource is abundant, dwarfing other energy resources. The challenge has been that it was significantly more expensive than other technologies.

There’s been a significant reduction in cost for PV technology since the 1970s. The economics are beginning to converge. With some of the incentives currently in place in the United States today, solar projects deliver a reasonable return on investment for private investors.

SEIA has set a very ambitious goal for solar to deliver up to 12 percent of U.S. energy demand by 2020. Whether we achieve that or not, I expect the amount of solar generation will increase several-fold over the next decade. There are some challenges in the short- and mid-term. It will require some well-designed policies that both provide some incentive to end-use customers and also provide a level playing field between solar and conventional energy sources, in terms of their environmental impact and the time of day when they deliver energy.

 

Fortnightly: I know PV technologies have improved, in terms of efficiency and cost. Where do they stand today?

O’Brien: We guarantee to our customers that their plants will produce modules with an average efficiency exceeding 9 percent, which is a 50 percent improvement on typical thin-film PV modules.

We’re aggressively pursuing a plan to reduce costs from about $1,500 per kilowatt DC in 2008 to $700 in 2011 or 2012. For large-scale PV projects in sunny sites in the United States, that will allow modules to produce electricity at peak demand for about $130 per megawatt-hour.

 

Fortnightly: With changes to the federal investment tax credit (ITC) and solar requirements in state renewable energy standards, many utilities are spending money on solar roofs and solar central stations. Do you think this kind of investment is sustainable?

O’Brien: A couple of key catalysts have accelerated utilities’ interest in owning and operating renewable energy projects in general, and solar projects in particular. The first catalyst has been the drop in the expected price for installed PV systems, and consequently the cost of energy from those systems. Some companies, like FirstSolar, Sun Power and others, have significantly shifted expectations and provided some eye-opening improvements in the value of PV energy as delivered to utility customers.

A second important catalyst is the sudden introduction of new policies that are providing an unprecedented opportunity for utilities to capture tax credits directly and potentially access loan guarantees from the government to support investments in renewable energy projects. And policies are evolving at the state level, in such states as California, regarding the regulatory treatment of investments in PV.

These policies provide an opportunity for utilities to kick the tires of the technology in a much more meaningful way and test alternative business models. There’s good reason to think this is a long-term trend. We know the ITC will be in place until 2016, and there’s no expectation that utilities would lose the ability to use that directly. That’s a significant long-term window. And the cost trends are sustainable, particularly with regard to thin-film technologies. Collectively they comprise only 10 percent of the market today, but I’ve seen estimates that they could be 25 to 50 percent of the market by 2012. That’s driven by economies of scale and continued advances in the performance of the technology itself.

 

Fortnightly: In the current financial crisis, companies are having trouble financing almost any kind of investment. How is that affecting utility investment in PV projects?

O’Brien: Compared to conventional fossil technologies, solar and other renewable technologies are characterized by comparatively higher initial cost, and little to no O&M costs over the 20- to 30-year life of the asset. That highlights the sensitivity of those investments to financing terms. To the extent utilities invest directly in PV projects and even potentially in PV manufacturing, it would reduce the portion of the energy cost associated with financing.

One thing that makes utility-owned PV attractive is that by integrating it into the rate base, utilities have an opportunity to earn a return on those investments, in the same way conventional assets are treated. It needs to meet regulatory tests for a least-cost resource, compared to a third-party owned scenario. Utilities and PUCs are testing both models. We’re in a period of transition.

 

Fortnightly: You mentioned the prospect of utilities investing in PV manufacturing facilities. Why would they want to do that?

O’Brien: The utility might have an advantage in terms of financing costs, and this, combined with getting thin-film silicon modules effectively at wholesale instead of retail, would provide significant cost advantages for utilities that are committed to large-scale deployment of PV for their future generation portfolios.

In the short term it’s important for utilities to simplify procurement, minimize the risk of supply interruptions, and gain the flexibility to source the technology from a number of potential vendors. But in the long term, potential cost savings from investing directly in manufacturing would allow utilities to capture more of the margin and achieve lower costs for solar energy.

 

Fortnightly: Earlier, you said PV costs might drop by about half in the next few years. If that’s the case, shouldn’t utilities avoid tying themselves to a specific technology or manufacturing plant?

O’Brien: The question is whether the known investment represents a positive value for ratepayers, compared to other known options today. Utilities are in the business of providing reliable electric supplies. They’re not competing against advancements that might be in hand five years or 10 years from now. They have to choose technology that makes good economic sense today, with the policies that are in place today and also weighing the credible pathway toward even more cost-advantageous options in the future.

One way of look at it is this: Investing in PV is like investing in a natural gas-fired power plant with a locked-in fuel supply contract for 20 years. You’re hedging the fuel price risk for that portion of the portfolio. I’d argue there’s more predictability in the future costs of PV than there is in the future costs of natural gas.

A second point is that Oerlikon offers the option of a services agreement that ensures the customer would have access to process improvements and changes on a going-forward basis. Most of the improvements achieved through our centralized R&D and product-development process can be retrofitted to existing lines. By investing directly in the plant, the utility customer would have more direct access to technology improvements that would be achieved over time. In the case of buying modules from third-party suppliers under long-term contracts, there might be some future performance improvements built into the pricing, but access to those price improvements wouldn’t be quite as direct.

 

Fortnightly: Is there any precedent for utilities investing in manufacturing capacity like this? Could they put it into rate base?

O’Brien: I’m not aware of any precedent for utilities investing in plants producing conventional energy technology or even something like wind turbine blades. [Editor’s note: Sometimes utility holding companies invest in advanced technologies. For example, Alliant Energy invested in Capstone Microturbine, and DTE Energy Ventures owns part of fuel-cell developer PlugPower and flywheel storage manufacturer Pentadyne. But in each case, these are unregulated assets, not included in the utility rate base.] This is somewhat new territory for utility commissions. The door is potentially open to the approach, but it would require utilities to demonstrate a clear and significant cost advantage for the ratepayer, compared to third-party procurement approaches.

We think that with the advances we expect to demonstrate in our plants over the next couple of years, there will be a good case to be made. But the onus is on Oerlikon at the moment to demonstrate the advantages that utilities might gain by investing in plants. In the short term the more likely scenario is that utilities will pursue large-scale procurement of modules based on Oerlikon technology, because of its competitiveness and its wide availability across several suppliers.