The role of financing and tax considerations in reducing cost

Until now, most utility-scale solar projects have been built under power purchase agreements (PPAs). Under a PPA, a utility agrees to buy electricity from an independent site developer, who bears virtually all of the risks associated with the project. The developer typically must acquire the land, buy the solar panels, buy and install all necessary wiring, and arrange interconnection to the grid before it can begin to realize any revenue under the PPA. As part of shouldering these risks, the developer owns the solar farm and also benefits from any available tax credits associated with it, such as the federal investment tax credit (ITC). Depending on the facility’s tax environment, the developer may or may not be in a position to exploit these credits.

The nature of PPAs makes reliable execution inherently difficult for developers. To win a PPA contract with a utility, site developers generally must offer their electricity at the lowest possible price. Meanwhile, the cost of such installations may be impacted by financing challenges and also is prone to unpredictable increases for reasons that may be outside the developer’s control.

In many cases the site developer, often relying on venture funding, is focused on a handful of relatively small projects, with little or no expectation of revenue until those projects are completed and connected to the grid. Without a steady revenue stream, developers may not be able to attract reasonably-priced financing for longer term multi-megawatt projects. Because their future project plans are uncertain, they may have difficulty obtaining favorable forward pricing for either solar modules or other balance of system components. Delays in grid connection can impose severe additional costs on developers who may already be in precarious financial situations.

The trend to PPAs was due in part to regulations that prohibited utilities from using renewable energy investment tax credits.Therefore, utilities did not have this incentive to directly own solar facilities. And ITCs usually expired after a year or two, with eligibility requirements shifting with the political winds, dampening developers’ desirability to undertake larger projects.

In October 2008, however, two important changes reshaped the landscape for utility-scale solar energy. The federal Emergency Economic Stabilization Act of 2008 (EESA) extended the 30% renewable energy ITC for eight years¹, enabling better visibility and predictability -- two fundamental requirements for long term planning. Significantly, the EESA also lifted the prohibition against utilities’ use of the ITC. As a result, while PPAs may still provide a favorable financial structure, alternative approaches have become more feasible than ever before.

Under one of these alternatives, a manufacturer of solar modules would enter into an off-take agreement with a utility – under which the utility agrees to buy a certain number of modules (measured in megawatts of generating capacity) over the course of five years or more – which are installed on a solar farm owned by the utility. Under this structure, the module maker may be able to obtain favorable financing for plant construction, and can standardize wiring, electrical inverters, mounting hardware, and other module components. Similarly, with a predictable supply of modules from a single source, the utility is able to plan its investments in land and transmission capacity, placing solar generation near current or anticipated demand centers. High volumes allow both the utility and the module manufacturer to lock in favorable forward component pricing to achieve the lowest cost per installed watt.

The impact of efficient financing on the cost of a solar installation can be substantial. For example, with a five-year off-take agreement, covering 400MWp of solar modules, the installed price could approach $3/Wp. Once installed, the modules can be expected to produce approximately 500 GW hours of energy annually (assuming 1,750 hours of sunshine, typical for the south-central US), at an annualized cost of about US$65 million over their 25-year operating life. A comparable natural gas-fired peak generation plant would incur between US$33 and $56 million in annual fuel costs. Thus, the net ratepayer impact for a typical 10 TWh operator could be as low as $0.001 per KWh.²

¹More details on this credit can be found here.
²Applied Materials data, fab2farm presentation

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