Two things the solar industry seems to never stop doing is setting growth records and finding new markets.
The sector added a record 7.3 GW of new capacity in 2015, with over 4 GW of that coming from the utility-scale solar segment. Just-released industry numbers foresee it more than doubling last year’s installed capacity in 2016 — increasing to 16 GW of installations, including almost 12 GW of utility-scale solar.
In addition, new Energy Department numbers foresee utility-scale solar becoming, for the first time, the biggest source of new U.S. generation for the year.
True to form, the industry will expand into new markets to get to these numbers, according to a new report, “The Next Wave of U.S. Utility Solar,” from GTM Research.
“To date, roughly 80% of utility-scale solar has been driven by state renewable portfolio standards (RPSs),” said GTM Solar Analyst and report lead author Colin Smith. “But now we are seeing the next wave of utility scale solar in a new landscape. The present utility-scale solar pipeline is more than 50% non-RPS driven.”
Before 2015, utility-scale solar not driven by an RPS was only 16% of new installed capacity. In 2015, 39% of capacity brought on-line came from non-mandate-driven demand. In 2016, over half of new utility-scale solar installed capacity will, for the first time, be not driven by renewables mandates.
This activity is dominated by solar-friendly states. Texas, North Carolina, Georgia, California, and Utah currently have almost two-thirds (64%) of the non-mandate-driven projects in development.
“As more utility-scale solar is developed outside of RPS obligations and non-RPS drivers become more common, more states will have a diverse mix of drivers,” the study reports.
As demand for solar expands beyond RPS programs, three factors are expected to drive growth in the utility-scale segment of the market, the study reports.
The biggest will be voluntary utility procurements as power companies are attracted by solar’s low price.
The second will be must-take procurement from qualifying facilities (QFs) under the dictates of the 1978 Public Utility Regulatory Policy Act (PURPA).
The third will be corporate procurement of power from utility-scale solar systems. While this area is smallest of the three at present, analysts expect it to be among the most interesting markets in coming years.
Can’t beat those prices
The installed cost for utility-scale solar has dropped over 50% since 2007, according to Lawrence Berkeley National Laboratory.
Estimates vary, but the trend observed by GTM Research remains unchanged: The $5.25/Watt utility-scale PV price in 2007 fell to $1.45/Watt in 2015, taking the 2007 utility-scale solar contract price of $200/MWh to as low as $25/MWh in 2015.
With the five year extension and phase out of solar’s 30% investment tax credit (ITC), the National Renewable Energy Laboratory (NREL) projects the installed cost for solar could drop 43% further by 2020.
The solar bargain is attracting voluntary procurement at unprecedented levels as utilities buy and own solar outside the requirements of renewable energy standards.
There are at least 4.1 GW of voluntary procurement in the pipeline, Smith said.
Utility-scale solar investment is especially appealing to utilities because it offers 20-year price contracts with no fuel costs.
“It serves as a fixed price hedge against natural-gas price uncertainty,” the paper reports.
With the tax credit extensions in place, wind and utility-scale solar are typically the least-cost options for utilities looking for a compliance path for the Obama administration's Clean Power Plan through the early 2020s, according to analysis from the Rhodium Group.
Wind and solar installed costs falling at the rate projected by the NREL Annual Technology Baseline (ATB) would result in a 250% increase in renewable generation by 2022, Rhodium reported.
Utilities take advantage
Utilities have increasingly been taking advantage of falling solar prices, observed Mark Bolinger, researcher at the Lawrence Berkeley National Laboratory (LBNL) and co-author of the lab's most recent utility-scale solar report.
NV Energy recently reported signing a PPA for the 100 MW output of First Solar’s Playa Solar 2 installation at $0.0387/kWh after paying only $0.046/kWh for the output of SunPower’s 100 MW Boulder Solar installation last year, he noted. The utility bought utility-scale solar power for an average of $0.1377/kWh for solar generation over the course of 2014.
Austin Energy also recently received record low bids below $0.04/kWh in response to its 2015 request for proposals (RFP). Those bids were 20% lower than the contract it signed with Recurrent Energy in 2014 for $0.045/kWh and only 25% of the $0.16/kWh it paid its first large installation in 2012.
Those prices, Bolinger said, were indicative, not exceptional.
“The responses to utility solicitations show quite a bit of capacity priced very similarly to the winning bids in the RFPs, and that confirms this pricing is real," he said.
The Austin Energy RFP for 600 MW of solar received 149 unique proposals representing 7,976 MW from 33 different bidders. “Almost 1,300 MW were reportedly bid at levelized prices of $45/MWh or less,” LBNL reports.
A Southwestern Public Service 2014 RFP for 200 MW of utility-scale PV received 112 project bids representing 5,250 MW. Some 2,958 MW were bid at levelized prices ranging from $40/MWh to $50/MWh, and 1,782 were bid at levelized prices ranging from $50/MWh to $60/MWh.
Of the 2,537 MW of renewable resources bid into the 2015 NV Energy RFP, more than 90% were solar. LBNL did not get pricing information for the non-winning bids, but several hundred MW of shortlisted capacity were reportedly bid at prices very similar to the winning bids. In addition, the solar bids were priced lower than wind or geothermal bids, according to the utility.
Florida Power and Light and Xcel Energy have also made non-mandate-driven utility-scale solar buys more recently, Smith added.
The PURPA projects
Beyond utility voluntary procurement, the next biggest category of non-mandate-driven utility-scale solar growth is through PURPA contracts. They make up 16% of the current pipeline and are likely to become an increasingly important factor in states where regulators protect competitive contract standards.
The Public Utility Regulatory Policy Act, better known as PURPA, was passed in 1978 to ensure utilities had diverse resource mixes at a time when policymakers were concerned about over-reliance on foreign oil for electricity generation. The law, in short, requires that utilities contract with certain qualifying facilities (QFs) to supply power at or below its avoided cost for other generation.
Though once almost unthinkable, the utility-scale solar value proposition now pushes out other generators vying for PURPA contracts. Utilities across the country have begun expressing concern about development pipelines over-filled with solar QFs.
“The price of solar is so low that developers are able to profitably offer generation at the utilities’ avoided costs,” Smith said. “There isn’t a lot utilities can do about their PURPA obligations if regulators sustain the contract standards.”
Out West, PacifiCorp has been leading an effort in its six-state territory to raise awareness of the volume of utility-scale solar in the pipeline. The Warren Buffett-owned utilities argue they have plenty of solar capacity coming online and say they concerned the new PURPA contracts may reduce the resource diversity the law was designed to create.
“The standard contract length has been 15 or 20 years and the standard project size has been 5 MW or 10 MW,” Smith said. "PacifiCorp is asking state regulators to reduce the contract length and system size. The new numbers would likely make it substantially more difficult for the developer to get a solar project to pencil.”
Just last week, regulators in Oregon rejected PacifiCorp's proposal to trim PURPA contracts, but Buffett's utility business had better luck Utah earlier this year when the PSC shortened contracts from 20 to three years. Idaho regulators also cut contracts to two years in summer 2015.
PURPA contention is not limited to Western states. In North Carolina, regulators turned away a proposal from Duke Energy to shorten contract lengths and limit project size last year.
“A lot of PURPA projects have come online, especially in North Carolina, where Strata Solar has led the trend,” Smith said.
“Strata has many, many 5 MW projects working through the PURPA mechanism in North Carolina. And I think we will also see even smaller developers, like Cypress Creek Renewables in South Carolina, grow considerable pipelines in their niche areas,” he said.
Growth of the PURPA pipeline will remain uncertain where challenges keep its viability in limbo, GTM reports.
“It is a federal law interpreted on the state level so the effectiveness of challenges will vary state to state,” Smith said.
In some states, PURPA will become an inconsequential factor as policy changes make QF status unappealing for developers. But for others it will be a major driver.
“There is a lot of solar in the pipeline driven by it," Smith said.
Renewables advocates’ are increasingly excited over the role being played by corporate procurement. What started as selling Renewable Energy Certificates (RECs) to customers willing to pay a premium for renewables has transformed into a blooming solar market sector.
When large corporate buyers showed interest in RECs, utilities expanded their offerings. When renewables’ installed costs plunged, the corporate buyers saw an opportunity have a degree of energy independence by becoming off-takers or project owners.
In 2015, corporate off-takers accounted for over 3 GWs of new capacity, according to World Resources Institute Director of Utility Innovation Letha Tawney.
“We are seeing large corporations, either through direct access or green tariffs, start doing one-to-one sourcing to power data centers and other large operations,” GTM's Smith said.
For instance, Apple is buying power through NV Energy and Salt River Project from projects being developed by First Solar, Smith said. Amazon Web Services is buying power from a project owned and developed by Dominion Virginia, Equininix is buying power from a Southern California Edison project, and Google has worked out an arrangement for solar-generated electricity from Duke Energy in North Carolina.
Utilities are evolving green tariffs to make it possible to meet the demands of these key customers without shifting any cost burden to other ratepayers. NV Energy’s Green Energy Rider, Duke Energy’s Green Source Rider, and Solar*Connect offerings from Xcel Energy in Colorado and Minnesota are a few examples.
Utilities and regulators have realized green tariffs are “the path of least resistance,” Smith said. “Providing them will prevent corporations from bypassing utilities and buying directly from developers.”
With a green tariff, the price to the corporate off-taker is higher than if the company had contracted directly with the project developer, Smith said. But the price is lower price than the corporate off-taker could get in a wholesale electricity market.
The price is high enough so the utility does not have to pass costs to other ratepayers, but still allows for the corporate buyer to get a reduced rate while paying integration, maintenance and transmission costs.
The deal worked out between NV Energy, Switch, and Nevada regulators could be the best example of what to expect going forward, Smith said.
Under the deal, the utility agreed to supply the technology company with 100% renewable energy through contracts the utility makes to buy solar and wind energy from developers.
Nevada’s regulators approved this arrangement because the utility might otherwise have lost 2% of its revenue, which would have further increased burdens on NV Energy’s customers, Smith added. “Many utilities could face this situation.”
The Switch-NV Energy deal is “an important first step,” WRI's Tawney agreed. It proves regulated utilities can work with their customers to deliver new renewable energy.
“But it is a first generation product,” she added. “It doesn’t yet offer the package large buyers need. Utilities, including NV Energy, are working with their customers to create the second generation of green tariffs, like Xcel’s Renew*Connect.”
The next wave of utility-scale solar
An emerging utility-scale market driver is solar built as merchant generation to sell directly into wholesale markets. While not as significant of a force today, the GTM team expects it to increase in significance in the future.
“It is several years away because it will take time for people who finance solar development to be willing to take that kind of risk instead of finding a long term off-taker,” he said.
There are less than 500 MW of utility-scale solar projects being built without contracts, the study reports.
A project is “full merchant” if its power is sold at real-time spot market prices, the study explains. For a “partial merchant” project, the power is sold based on a spot market price “supported by a variable or fixed price floor set by a short-term hedge contract.”
Though spot markets in moments of peak demand offer huge upside potential, the overall competitiveness of merchant projects is uncertain and few are willing to “play the market” as many fossil fuel plants do today.
But with today's low financing costs and the declining cost of solar installations, more developers may choose to move ahead on construction without a specific off-taker in mind. They would have the option of selling into wholesale markets if the project is completed and a contract is not secured.
The 8minutenergy/SunEdison Mount Signal II project, the study notes, will be online this year even though its power purchase agreement (PPA) with Southern California Edison does not start until 2020. Because the merchant option existed, it moved ahead with development, though the project owners ultimately signed a 5-year PPA with Equinix rather than risk the California wholesale market.
Beyond growth in the merchant market, the GTM team notes that legal happenings around the Obama administration's carbon regulation plan could also affect the utility-scale solar market.
“The other driver that is even more up in the air is the Clean Power Plan,” Smith said. “It is not yet clear what that will mean for the growth of solar or when.”