Legal & Regulatory

Beyond the Renewable Portfolio Standard

Renewable portfolio standards (RPSs) have been remarkably successful in boosting renewable generation, especially in the western U.S., where most states enjoy large areas of prime wind and solar potential (and, to a lesser extent, geothermal). Of the 11 western states, eight (Arizona, California, Colorado, Nevada, New Mexico, Oregon, Montana, and Washington) have RPS mandates. Utah has a voluntary standard, while Idaho and Wyoming have no RPS. The mandates range from 15% (Arizona and Montana) up to 33% (California). Most have deadlines of either 2020 or 2025 (Montana’s is in 2015).

Most discussion surrounding RPSs in the U.S. has focused on the resources and regulations that are necessary to meet them. Some experts, however, have begun thinking about what happens after these standards are met and the deadlines have passed.

There are good reasons to look beyond the current RPS approach. In several western states, such as Arizona, momentum for boosting RPSs beyond their current levels has stalled, and pressure has even begun in some quarters for reversal (see “The Lurking Threat to State RPSs” in the August issue of POWER).

But there is another reason to think that the future of RPSs in the western U.S. is likely not to be continued ratcheting up of state-level mandates but rather a broader regional solution. The problem is that meeting the current RPSs in several states, most notably California, will require developing most or all of the easily exploited solar and wind resources in those areas, and going beyond existing mandates will require developing more expensive, less-efficient resources, or facilitating large-scale imports from elsewhere in the West.

This dilemma is the subject of a report from the National Renewable Energy Laboratory (NREL), “Beyond Renewable Portfolio Standards: An Assessment of Regional Supply and Demand Conditions Affecting the Future of Renewable Energy in the West,” published in August. NREL began by assuming that all RPSs in the western U.S. would be met by 2025 and calculated what prime renewable potential was likely to be unexploited after that. (It defined “prime-quality” resources as wind with annual capacity factors of at least 40%, solar with direct normal insolation of at least 7.5 kWh/m2/day, and all geothermal.)

The study had several notable findings:

■ Western states will collectively need 127 TWh to 149 TWh of renewable generation annually to meet current RPSs; California accounts for nearly 60% of this.

■ Colorado, Montana, Nevada, and New Mexico will have surpluses of prime renewable resources after meeting their RPSs. Wyoming and Idaho will also have large undeveloped prime resources.

■ California, Oregon, Utah, and Washington have already developed most or all of their prime in-state resources and will need all of it and more to meet RPS-related demand.

What this suggests, the study says, is that future renewable development in the West is likely to involve transmission corridors from prime resource areas inland to demand centers on the West Coast. The authors then worked from current cost projections for generation and transmission to determine how competitive this imported power would be compared to new combined cycle gas turbine generation after 2025. Notably, the study assumed that the production tax credit and investment tax credit would not be extended beyond their current expiration dates. It also based competitiveness on a hypothetical doubling of current transmission costs in order to maintain a conservative approach.

While geothermal was not competitive with gas under any of the transmission scenarios, the results were different for wind and some solar. Wind from Wyoming and New Mexico to California and Arizona—and from Montana and Wyoming to Oregon, Washington, and California—was competitive with gas, again, without any assumed subsidies. The same was true for solar from Nevada to Arizona and California. Though transmission from Wyoming to coastal demand centers would be expensive given the long distances, the state’s wind potential is high enough to keep it competitive. Indeed, the report found that Wyoming wind could generate 37.3 TWh annually at a delivered cost of $69/MWh to $81/MWh purely by building out those areas with a 40% capacity factor or better.

The figures for New Mexico were not quite as good, but the higher generation cost was offset by lower transmission costs due to closer proximity to Southern California. (The picture was not so rosy for Colorado; its large wind surplus would be handicapped by prohibitively high transmission costs over the Rockies.)

What this study suggests is that future renewable resource planning may need to focus less on fixed generation numbers and more on how to get the generation where it needs to go. That will also require a move beyond state-level planning to regional and federal cooperation in facilitating large-scale interstate transmission—always a complicated prospect.

How all this transmission would be paid for is not clear, especially given that the large majority of renewable generation in the West operates on a merchant basis, with costs being recovered via power purchase agreement rather than a rate base. That suggests that transmission would not be built without market signals favoring renewable generation over other sources. That may come from clear cost competitiveness, if the NREL study is accurate, but history suggests that regulatory incentives may be necessary along the way. ■

Thomas W. Overton, JD is POWER’s gas technology editor. Follow him on Twitter @thomas_overton and @POWERmagazine.

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