State renewable energy standards (RPSs) may be threatened by the expiration of federal tax credits, according to research from the Lawrence Berkeley National Lab (LBL).
Lab scientist Galen Barbose, speaking at the annual meeting of the National Association of Regulatory Commissioners (NARUC) in San Francisco, presented the results of a joint study between LBL and the National Renewable Energy Lab, assessing the costs and benefits of state renewable portfolio standards.
More than half of U.S. states have RPS laws in place and have collectively deployed about 46 GW of new renewable capacity through the end of 2012.
So far, most states are well ahead of their RPS goals and have seen very small price impacts, ranging from 1% to 3%.
“Costs are increasing as targets ramp up,” however, said Barbose, “so there is some concern about where they may be headed.”
There are external factors that may increase cost impacts—like the expiration of federal tax credit—or reduce them, like higher gas prices, technology improvements, or EPA’s Clean Power Plan.
The big risk, as Barbose sees it, is that most states have a cost cap in their RPS to limit ratepayer exposure to higher prices. These “safety valves” are pretty low, he says. With the expiration of federal tax credits, “we may see an increasing number of states bumping against cost caps, making them unable to achieve the targets.”
The federal production tax credit (PTC), currently worth $23/MWh for the first 10 years of operation, expired at the end of 2013. Congress is considering extending a package of tax incentives, including the PTC, in the current lame duck session. A number of conservative and fossil-fuel groups have come out in opposition to extending the PTC.
The states most at risk of hitting price caps are Illinois and Delaware, which have caps of 2% and 3%, respectively. Twelve states have cost caps of less than 5%. Colorado has in theory has surpassed its rate cap, but has put excess costs into a balancing account to be settled later rather than pass them on to ratepayers now.
Measuring the incremental cost of renewables is not an exact science. A key question is what the “avoided cost” is, whether it is based on average or marginal costs, a typical power plant, spot market prices, or other options.
A case in point is California, which uses two competing methods to estimate costs. One approach, comparing renewables to the all-in cost of a combined cycle gas turbine with a hedged gas contract, found renewables were 3.6% lower. Using California Independent System Operator energy and capacity market prices instead, renewable prices were 6.5% higher.
“This makes California either the least expensive or the most expensive state,” said Barbose.
While some states may be close to hitting their caps, overall national renewables development is far outpacing RPS requirements.
Xcel Energy in Colorado, for example, has a 30% by 2020 goal, and is already at 20% (once bonus credits for in-state development are accounted for). Xcel has been able to buy wind power at prices competitive to what it sees for natural gas. Two recent wind contracts were signed for $27.50/MWh, with a 25-year levelized cost of $35/MWh.
Texas, which has a nominal target of 5,880 MW by 2015, has over 13,000 MW of wind in the ground, with another 7,600 MW under construction, as of third quarter 2014.
Likewise, the Midwest as a whole has much more wind than is required under RPS goals. While Iowa was the first state to mandate renewable energy, back in 1983, it has not updated those goals, even as wind has grown to 27% of state demand.
By 2020, state RPS laws will require a total of 98 GW of renewable capacity, rising to 123 GW by 2035. This will require between 3 GW and 7 GW of new build per year through 2020 and 1 GW to 2 GW per year thereafter. By comparison, RPS-driven additions averaged about 6 GW per year since 2008. Non-RPS projects added another 4 GW per year.
—Bentham Paulos is a freelance writer and consultant specializing in energy issues.