King & Spalding’s renewable energy practice group described the bright future of solar power in its April 2015 Energy Newsletter. Ongoing photovoltaic (PV) projects in Latin America, Africa and the Middle East, certainly supports the view that solar power will play an increasing role in the power generation mix for both developing and developed countries.
Of course, enthusiasm alone will not get the solar power industry to that point. Like any power project developer, developers of large-scale solar projects need, as a first principle, a secure revenue stream from their projects to repay construction costs and reward investors. Without this security, a project simply won’t get going.
Prudent solar project developers therefore take the time needed to lock in their revenue stream through a long-term contract (usually, a “power purchase agreement” or “PPA”) and/or feed-in-tariff (FiT) program, although such steps are easier said than done. Local regulations change, and utilities, particularly in emerging markets with little solar power experience, commonly assume that they can apply a PPA developed for their thermal power generation to a solar project without material changes. However, developing a PPA for a large-scale solar project requires careful analysis and drafting of several key concepts. This article will focus on three of those.
Unlike certain other forms of power generation, large solar PV power project cannot, given current technology, effectively store energy or otherwise influence its supply of fuel (i.e. sunlight) over any specific time period after initial site selection and development. Solar projects resemble run-of-river hydro or wind projects in this regard. Not only will solar projects face seasonal and night/day differences in solar irradiation, but variations in cloud cover, haze or other factors could reduce the energy output of the solar project at any hour of any day. As a result, the generator performance obligations in a solar PV PPA should not require the supply of a definite power generation capacity, or volume of energy, over a given time period, as PPAs for less intermittent resources often require.
Rather, generators should seek a risk-sharing approach that focuses on (i) making available whatever energy the project can generate at a given time, based on the in situ conditions at such time, which can vary on a daily or even hourly basis as with run-of-river and wind generation, and/or (ii) converting sunlight to AC energy output at an agreed performance ratio when compared with peak nominal rated capacity of the PV panel modules. These calculations typically involve consideration of solar specific issues, such as solar irradiation and PV panel degradation (at a minimum), as well as spectrum, temperature and (possibly for the conversion of sunlight to AC energy), the effects of seasonal weather variability on testing.
The tariff structure for solar PPAs will also differ from PPAs for other forms of generation. In place of the standard availability or take-or-pay volume structures used for other forms of generation, we commonly see the tariff structure for solar PV PPAs, at least as proposed by the emerging market utility off-takers, drafted in terms of (i) energy output alone (i.e., the off-taker must pay for all energy generated by the facility), or (ii) a combination of energy output and deemed energy (i.e., if the off-taker does not take all energy generated by the facility, then it pays for a theoretical energy volume).
While common, these approaches may create unexpected issues. They can, for instance, embed within the tariff structure assumptions that the project will always receive “must run” status under the local regulation/dispatch regime, and that metered volume will therefore always correspond to the full availability of the solar project. Developers have accepted this at times on the belief that, since solar PV projects cannot technically respond to short term dispatch requests, they will always receive the highest priority in the local dispatch regime.
Yet this assumption may not always be accurate. Some emerging market utilities with dispatch regimes explicitly favour some forms of power generation over solar (e.g., hydropower projects owned by the same utility). Demand and transmission constraint issues, in certain circumstances, could also result an inability to dispatch the full energy available from the project, without fault or breach by the off-taker. Also, given the potential for a rapid rise of solar or other renewable projects, it does not seem out of the question for regulations or dispatch regimes eventually to change to the detriment of those projects, notwithstanding their technical classification as non-dispatchable. A solar project in any of the above situations, without a PPA that adequately addresses these risks, could face significant revenue issues.
In addition, both of the approaches mentioned above tend to place the generator on a back foot in payment disputes insofar as they put the burden of proof on the generator to show why payment of metered volume alone does not suffice. A generator-friendly PPA would switch this burden around so that the off-taker has to establish when the fixed payments under its PPA did not apply.
One mechanism to address these issues includes redrafting the tariff structure of the solar PV PPA to require payment for the greater of metered volume or the energy volume theoretically available, with exceptions only if certain specified mechanical interruptions of the PV project (e.g., planned maintenance or forced outage) occur. Solar power producers may also wish to place a floor (e.g., a P10+ energy volume) on the energy theoretically available, thereby pushing to the off-taker some of the resource risk that the revenue stream faces. These extra steps would materially increase the revenue security of a solar PV project over the long term.
Also, it is not uncommon for solar project tariffs to be fixed over the life of the PPA as opposed to tariffs in conventional energy PPAs that typically have an escalation clause built in. The element of the revenue stream should always be considered in determining the financial feasibility of any particular project as well as the term of the PPA being negotiated.
FiT or other regulated incentive regimes provide a final example of factors that might affect a solar PV PPA differently from a PPA for coal or gas-fired thermal generation. These regulatory regimes vary country by country, but a solar power project developer will always need to understand the eligibility, approval process and criteria for the FiT; rate duration, structure, pricing and currency issues; cost control mechanisms or other ongoing requirements; the FiT funding mechanism (i.e., where the utility receives funds to pay the FiT); contract terms (i.e., whether the FiT term forms an enforceable element in the PPA); review period for the program; and impact of the FiT regime, and the role of any regulatory body linked to that regime on the ability of the project to pass through cost increases resulting from changes in law and other political events. A coherent interface between the PPA and any FiT regime would play an important role in protecting the long-term revenue security of a solar project.
While addressing each of these issues takes time and an understanding of risks specific to solar projects, we have seen that solutions do exist and the future of the solar power industry looks very promising.