Renewable portfolio standards (RPS) have become the norm rather than the exception in the United States.
By the end of 2007, 46 percent of nationwide retail electricity sales were covered by mandatory state RPS requirements, according to research conducted by the Lawrence Berkeley National Laboratory.1 In other words, renewable generation under a state RPS mandate served some portion of 46 percent of retail power sold last year.
As of mid-2008, 26 states and the District of Columbia enacted mandatory RPS policies. Four additional states have non-binding goals. While these standards have posed little problem for many utilities, they are causing headaches for some. And as RPS requirements become more ambitious—and the most cost-effective project opportunities get developed—those headaches will grow into migraines.
“Some utilities have struggled to meet requirements,” says Ryan H. Wiser, a scientist in Lawrence Berkeley’s environmental energy technologies division. “Utilities in Nevada, for example, have signed a large number of renewable energy contracts, but many of the projects that have been contracted for have failed to meet their deadlines. Some have even been cancelled.”
In the majority of states with RPS programs, compliance to date has been complete or almost complete, certainly well above 97 percent. In California, for example, investor- owned utilities achieved 100 percent compliance in 2004 and 2005, and 98 percent compliance in 2006. Such success, however, won’t be so easy in the future. “They are not on track to achieve full compliance (with California’s 20 percent RPS mandate) by 2010,” Wiser says. “No one expects them to be able to achieve this.”
Mark Sinclair, executive director of the Clean Energy States Alliance (CESA) in Montpelier, Vermont, and vice president of the Clean Energy Group, agrees with Wiser’s assessment. “It’s important to remember that most RPS laws ramp up requirements over time,” he says. During the first few years, targets are relatively modest, so it is easy for most utilities to meet them. “The challenge will come as the increasing targets kick in over the next five to ten years,” Sinclair says.
To achieve full compliance with existing state RPS requirements, utilities must add 61 GW of new renewable capacity by 2025, equivalent to 4.7 percent of projected 2025 electricity generation in the United States, and 15 percent of projected electricity demand growth.
Five states will require more than 5,000 MW of new renewable capacity between now and 2025: California (almost 10,000 MW); Illinois (about 7,000); Minnesota (almost 6,000); Texas (between 5,000 and 6,000); and New Jersey (about 5,000).
But even in states with less ambitious goals, hitting RPS targets won’t necessarily be easy. In North Carolina, for example, the legislature recently enacted an RPS of 12.5 percent, which utilities must meet by 2025—equating to less than 2,000 MW. “We intend to meet that legislative standard,” said Progress Energy CEO Bill Johnson in an interview earlier this year. “But it’s a little too soon to give a definitive answer on the ultimate role of renewables. Our first solicitation in the Carolinas got a little more than 700 MW, a lot of intermittent, with the exception of some biomass—and some of the biomass projects are counting on the same fuel source. So there isn’t 700 MW of dependable capacity in that solicitation.”
Besides having to deal with requirements that some utilities consider unreachable, project developers must deal with a policy landscape that continues changing. In 2007, for example, four states established new RPS policies, 11 states significantly revised pre-existing RPS programs (mostly to strengthen them), and three states created non-binding renewable energy goals.
Additionally, renewable developments face challenges at every turn, including issues with siting, transmission, funding, and solar set-asides.
• Siting: According to Lawrence Berkeley’s Wiser, the primary barrier in New England has been difficulty in siting, permitting, and building projects, not to mention the high costs. “For example, if wind companies can site and permit 400-MW projects in Texas in a couple of months, but it requires ten years to do so in Massachusetts, they are going to focus their efforts where it is easiest to site and permit,” he explains.
• Transmission: In some states, inadequate transmission is a constraint. “For example, the Great Plains are capable of generating large amounts of wind,” says Steve Weisman, a vice president with consulting firm Peregrine Energy Group. However, moving that power to population centers is costly and difficult. “Some of the problem relates to transmission-siting challenges,” he says. “Some has to do with the power loss over long distances.”
According to Lawrence Berkeley’s Wiser, the main reason California utilities won’t achieve the state’s 20 percent requirement by 2010 largely can be ascribed to the lack of progress in building new transmission. “In fact, while transmission challenges exist in a number of states, California is probably the only state where this is the primary barrier to achieving full compliance,” he says. In fact, the California Energy Commission has indicated it does not expect California IOUs to meet the state’s 20 percent RPS requirement by 2010, in part because of insufficient transmission.
Similar problems exist in other states. Nevada Power officials have said that, in the long term, the utility will not be able to meet Nevada’s RPS without a transmission line connecting Nevada Power to Sierra Pacific Power.
“In the next few years, transmission will become an even greater challenge,” says CESA’s Sinclair. “In light of this, a number of states are working together to determine where transmission should go and, more critically, how to allocate payment.” That is, states increasingly recognize the need to deal with the lack of transmission investment as a major barrier to achieving RPS targets. In 2007, at least five states (Texas, Colorado, California, Minnesota, and New Mexico) took important steps to try to mitigate this barrier.
• Financing: Inadequate funding can be another challenge for utilities, according to Karlynn S. Cory, with the Strategic Energy Analysis and Applications Center at the National Renewable Energy Laboratory (NREL) in Golden, Colorado, and co-author of Renewable Portfolio Standards in the States: Balancing Goals and Implementation Strategies. Market structure can be important in this regard, particularly whether the market is regulated with a single electricity provider, or restructured for market competition. “Regulated utilities with a captive customer base and cost-recovery guarantees are better positioned to make investments in new generation or execute long-term power-purchase contracts with renewable energy project developers,” Cory says. In restructured markets, however, electricity generation and distribution responsibilities often are separated. In states with retail competition, and where distribution utilities are precluded from making generation investments, long-term investment planning becomes difficult and risky for suppliers.
“In addition, states’ RPS policies are usually subject to legislative and regulatory changes,” Cory says. “The financial community, which provides the funding for renewable projects, tries to avoid the risks that legislative and regulatory uncertainty can cause.”
• Solar Set-Asides: Wind’s dominance of RPS markets arises from its relatively low cost, compared to other non-hydro renewable energy sources. “Solar, biomass, and distributed generation are not being advanced significantly by RPS laws at this point because of their higher costs and, for biomass, because of air-quality issues,” says CESA’s Sinclair.
To encourage diversity of renewable energy sources, about a dozen states either have designed or revised their RPS laws to require set-asides for solar, or even distributed generation. “Because of the increased costs, it’s unclear how easy it will be for utilities in these states to meet these solar set-asides,” Sinclair says.
Most states with RPS mandates allow utilities to meet their requirements by acquiring renewable energy credits or certificates (RECs). An REC is a tradable environmental commodity representing proof that one megawatt-hour of electricity was generated from an eligible renewable energy resource.
RECs can reduce the cost of RPS compliance by reducing T&D costs, while also providing access to a larger quantity of resource options. RECs have become the prominent mechanism for addressing geographical limitations and cost issues, and they likely will become more important as RPS requirements ramp up and developers exploit the most cost-effective project options, no matter where they’re located. Using RECs, however, presents a number of challenges.
“Concerns have been expressed that REC price variability and uncertainty might limit the ability of RPS policies to support renewables investment decisions,” says NREL’s Cory. REC markets are based on short-term purchases, but short-term markets don’t help developers obtain project financing. “The best way to get assurances is through long-term contracts,” she says. Some states are attempting to address this weakness by requiring long-term contracts. Utilities in Colorado, for example, are required to sign minimum 20-year contracts to meet the state’s RPS standard. California, Connecticut, Nevada, and Montana have 10 year minimums, and Maryland requires 15 years for solar contracts. “These requirements help to solidify their value to financiers,” she says.
Another challenge, according to Lawrence Berkeley’s Wiser, is that some states don’t allow RECs to meet RPS requirements. “California, Arizona, and Iowa do not currently allow unbundled RECs to qualify,” he says. (This isn’t an issue in Iowa, though, because that state achieved its standard in 1999.)
The use of RECs also depends on the utility regulatory structure in a given state. “Where retail choice is allowed, unbundled REC trade has been a fairly common form of compliance,” Wiser says. In states where utilities still are regulated by their utility commissions, most of the compliance has occurred through long-term bundled renewable electricity contracts, but RECs are used on occasion.
CESA’s Sinclair sees additional challenges. “It’s not clear what the future value of RECs will be, because of political issues in various states related to how strongly their RPS laws will be enforced,” he states. “In addition, RECs differ in each of the 26 states, which prevents a liquid market and makes it more difficult to finance around RECs.”
There are efforts underway to address some of these challenges. For example, the Clean Energy States Alliance is collaborating with several states in a DOE-funded program to harmonize and coordinate RPS programs, toward the goal of creating a national, or at least regional, REC market.
“Some parts of the country are better suited for certain kinds of renewables than others,” says Karen Hyde, vice president of resource planning and acquisition for Xcel Energy. “Over the long term, a vibrant REC market will help the United States meet renewable energy standards, because there are parts of the country that are better suited for certain kinds of renewables than others.”
But political challenges likely will persist, because many states have tied economic development goals to their RPS programs, and aren’t eager to have their ratepayers finance development in other states. “They would rather see their RPS requirements met through generation in their own back yards,” Sinclair says.
Would a Federal RPS solve all, most, or even some of the challenges utilities face meeting state-mandated RPS requirements?
Federal RPS legislation has passed the U.S. Senate on three occasions since 2002. In August 2007, the House passed a federal RPS for the first time, as an amendment to a larger energy bill. The Senate, however, was unable to break a filibuster to include the RPS in the final energy bill.
According to Lawrence Berkeley’s Wiser, lawmakers have proposed seven different options for a federal RPS. However, most discussions these days revolve around two. The first is to establish a federal RPS that simultaneously pre-empts state RPS policies. The second—generally considered more politically viable—is to establish a federal RPS that also allows states to develop and maintain different and more stringent requirements.
Whether either of these will come to fruition remains uncertain, and depends on the future direction of national politics. Competing priorities might push federal RPS legislation to the back burner. “The prospect for a federal RPS may dim if legislators focus more attention on the overarching carbon problem,” Wiser says.
However, because states have proven that RPS are significant drivers of new renewable energy, Sinclair says Congress eventually will enact a federal RPS. “A federal RPS could go a long way to creating a national renewable energy market and a national REC market, which would provide a lot more stability for financing renewable projects,” he says. “This would help utilities meet RPS goals in a cost-effective manner.”
Additionally, Sinclair says renewable generation would expand if the executive branch—DOE and FERC—would work more closely together on comprehensive transmission planning, establishing renewable energy zones, and offering clear cost-allocation rules for transmission. “This could be huge in helping states with RPS success,” he says.
In sum, a federal RPS would make it easier for utilities to meet renewable energy goals than the current state patchwork. Perhaps more important, however, would be a greater federal commitment to renewable energy in general. “What’s really needed is for the federal government to help states build markets and create the infrastructure to meet state RPS goals,” Sinclair says.
1. Wiser, Ryan and Galen Barbose, Renewable Portfolio Standards in the United States: A Status Report with Data Through 2007, Lawrence Berkeley National Laboratory, April 2008, available at: http://eetd.lbl.gov/ea/ems/re-pubs.html.