Us utilities are ramping up their solar energy sources and committing to aggressive clean energy targets. But will the current purchase power agreement route be the best way for utilities when it comes to their return on investment and factoring in for failed projects?
Utilities in the United States are embracing solar power and other forms of renewable energy in an effort to meet aggressive state mandates that call for certain amounts of energy to be produced from renewable sources.
California, for example, has the strictest renewable portfolio standard (RPS) in the U.S., requiring that 33 percent of the energy produced from public utilities be from renewable sources by 2020. Nevada also has a challenging RPS, calling for 25 percent of that state’s energy to come from renewable sources by 2025.
PPA all the way?
With the clock ticking, utilities are ramping up their efforts to incorporate solar energy into their energy mix. While some are investing directly in solar projects, the primary method utilities are taking is to commit to purchase power agreements (PPA) to buy energy from solar projects that are then farmed out to developers who find financing to build the projects.
Utility-scale PV development in the U.S. is becoming a central focus for domestic and global players. The current market, valued at $1 billion per year, is scaling rapidly, according to GTM Research, with business opportunity emerging across the market’s value and supply chains. GTM predicts that utility demand will double this year, and says that the total market value will reach $8 billion by 2015.
California’s three public utilities all have major PPAs in place with numerous solar developers. Pacific Gas & Electric has been the most active, with contracts signed to deliver about 3MW of energy from the sun.
Southern California Edison is next, followed by San Diego Gas & Electric, with agreements totaling 1,100MW. PG&E recently entered into a 25-year contract with Sempra Energy for 150 MW of renewable power from an expansion of Sempra’s Copper Mountain Solar complex in Boulder City, Nevada.
The first 92 MW of solar panels at Copper Mountain are expected to be installed by January 2013, with the remaining 58 MW slated for completion by 2015. Under the terms of the contract, PG&E has the option to accelerate the operation date of the second phase.
"Copper Mountain Solar 2 is a great opportunity for PG&E to continue down the path toward a clean energy future - a vision we share with our customers,” says Fong Wan, senior vice president for procurement for PG&E. "We are delighted to be part of this partnership that will allow us to deliver more green power to meet our customers' long-term electricity needs."
Building in flexibility
The fact that PG&E built in flexibility for the second phase of the project is important. Utilities that fail to meet their state’s RPS requirements can face fines, so being able to move up the operation date is key.
Likewise, utilities need to walk a fine line when it comes to producing too much renewable energy. Because the cost of solar is still not at grid parity, it is more expensive for ratepayers than traditional electricity. State regulators, therefore, must carefully monitor utilities as they pursue renewable portfolio standards.
“Utilities generally need to over-procure,” says Mike Taylor, Research Director at the Solar Electric Power Association. “If they need 500 megawatts by 2015, they are not going out and getting exactly 500. They have to assume a certain amount of failure and delay on these projects because there is some amount of risk involved.”
Factoring in failure
Taylor says that some utilities are procuring as much as 50 percent more renewable energy than needed, and many are negotiating with state regulators when it comes to an agreeable failure rate to assume.
“If utilities assume the wrong failure rate and don’t get enough solar, they face fines,” says Taylor. “But if they over-estimate and get more solar than needed, then regulators say this will cost rate payers more than we anticipated.
" The utilities are trying to make a good faith effort to balance this in the right way and regulators are still trying to understand how to best manage that.”
Those potential project failures have led some utilities like PG&E to own their own solar development projects. However, that is not the most common route to to take, since most utilities do not want to act as banks.
“Most of the activity is still occurring with the model where the utility signs a PPA and acts as the electricity buyer, and it’s up to the developer to find parties to invest and finance the project,” says Brett Brett Prior, a Senior Analyst at GTM Research in Boston. “That represents the majority of the utility solar projects in the US.”
According to GTM’s database, there are more than 700 solar utility projects either in operation or in some stage of development, with a total of more than 50 gigawatts of generation. However, that number drops to 13 gigawatts when you exclude the projects that are without signed PPAs.
“There is a huge pipeline for the vast majority of these projects,” says Prior. “This will allow utilities to meet their RPS requirements when these projects come online.”
The government of Jordan executed the power purchase agreements (PPA) related to the first phase of its direct proposal program involving 200MW of solar power.
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