With a national RPS likely, utilities must adapt

Debate continues on whether a national RPS would result in potentially detrimental conflict with state-level mandates.

The implementation of a national renewable portfolio standard (RPS) appears to be moving from possibility to probability in the U.S., as President-elect Barack Obama has indicated not only that he supports such a measure, but also that his administration will make tackling energy policy an immediate item of business.

Consequently, even as pressing questions persist regarding the viability of a national RPS and its cost implications for utilities, many electric utilities and their partners are now incorporating substantial consideration of mandated renewable energy inclusion in their power portfolio planning strategies.

Based on early signs from the incoming president, “Energy and the environment are going to be high on the priority list, and it’s probably worth paying attention to,” says Elliott Mainzer, executive vice president of corporate strategy at Bonneville Power Administration (BPA).

For wind energy and other renewable technologies, a national RPS would, of course, help stabilize a favorable policy climate that has often been rendered precarious in recent years by the ongoing uncertainties of the production tax credit.

According to Randall Swisher, former executive director of the American Wind Energy Association (AWEA), a national RPS would significantly enhance the existing momentum that wind power — helped by state-level mandates — has enjoyed in the U.S.

“A federal renewable portfolio standard — which the Obama campaign embraced — of 10 percent by 2012 and 25 percent by 2025 would replicate the effectiveness of what we’ve already seen put into place in [individual] states,” he stated during a recent teleconference on energy policy. “But doing it on a national basis would be the most effective way of focusing this nation on moving in a renewable energy direction.”

Swisher further pointed out that billions of dollars’ worth of future potential investment in renewable energy will be ultimately released only if continued support on a national policy level is assured — and pre–national RPS, this guarantee has appeared less than ironclad in the minds of many would-be investors.

To many utilities, however, a national RPS still represents an unwelcome measure that could undo — rather than complement — the renewable energy progress made possible by individual states’ existing standards.

“Our view has been that the states are positioned the best to tackle renewable energy standards — simply because they have the best answers as to what energy resources are available in the states and the regions,” explains Dan Riedinger, a spokesman for the Edison Electric Institute.

Under state-level programs, the rules vary widely as to which specific energy resources can be counted toward mandates, and each state’s
expected year of RPS attainment and renewable energy percentage whether a requirement or a goal also takes into account local needs and practicality considerations.

According to Riedinger, every potential version of a national RPS released thus far contains language that would eliminate the RPS eligibility of at least one resource designated as acceptable for a given state.

“Congress’s job — if they decide to pursue this — will be to develop some type of program that takes into account the different resources available in each of the states,” he says, explaining that a uniform program would likely result in disproportionately high costs for utilities in regions featuring comparatively poor availability of leading renewable resources such as wind and solar.

Indeterminate costs

Despite the completion of numerous studies intended to crystallize issues of cost allocation and state-to-state fairness, RPS proponents and opponents alike agree that pinpointing the utilities’ and ratepayers’ costs for complying with a national standard has proven to be difficult.

Post-investigation cost projections often emerge as mere reflections of the particular assumptions that were used in the research. Moreover, the volatility of fossil fuel prices ensures at least one unknown variable — no matter the apparent certainty of any other numbers used in the calculations.

“It’s very hard to put a price tag on a federal program of this magnitude,” says Riedinger. He adds, however, that because individual companies tend to work “closer to the ground,” their cost analyses may be considered more valuable than studies conducted by the Department of Energy or large-scale organizations.

Transmission costs will inevitably factor heavily into the price equation. “There’s no doubt that to continue to meet renewable portfolio standards, we’re going to have to build transmission, and it’s going to cost money,” says Mainzer.

But with or without any mandates requiring the addition of renewable energy to the grid, utilities and other involved parties have recognized that overall grid infrastructure must be updated to simply keep up with demand.

Riedinger cites a recent Brattle Group report stating that even with energy-efficiency improvements, the electricity industry would need to invest about $1.5 trillion to $2 trillion to make the existing grid sufficiently robust to meet the demand growth expected between now and 2030. Utilities have begun to gradually respond to these projections, ramping up their infrastructure investments in recent years.

“We make money by building things like power plants and transmission lines — and then getting a return on those capital investments and by selling the electricity that we generate,” Riedinger points out.

This basic profit-generation structure will naturally conflict with energy- efficiency measures and the resultant drop in electricity purchased — a thorny issue that Riedinger believes merits major discussion as increasingly stringent requirements for utilities are put into place.

Decoupling mechanisms that allow utilities to recover the capital costs of efficiency investments so that net profits do not suffer have been successfully implemented in the Pacific Northwest, reports Mainzer. Other potential work-arounds to the long-standing efficiency vs. profitability problem may also bring relief to utilities.

Maintaining reliability

Utilities must weigh a wide range of both overt and hidden financial considerations when deciding on the optimal blend of energy resources to meet both local consumption needs and all applicable federal and state requirements. “The capital cost is only one issue for any type of generation,” Riedinger says. “Then you’ve got the fuel costs — which, for wind, are nil. Then you have the operations and maintenance costs.”

Other, less immediately obvious costs for certain generation sources — particularly renewables — will include the compensation measures necessary to overcome any intermittency issues. The inclusion of wind power in a utility’s portfolio requires especially careful examination of the source’s abilities to work effectively in conjunction with other resources during peak usage times and periods of low production.

“The problem with [wind energy] is that the capacity factor is about 25 percent — simply because wind is such an intermittent resource,” Riedinger notes. Thus, regulators often require backup generation in the form of natural gas turbines, which are more expensive to run than a coal plant or a combined-cycle natural gas plant.

“Protecting reliability is absolutely essential,” stresses Mainzer. “We, like other utilities, are making sure that we have the tools in our toolbox to protect the reliability of the system.”

BPA currently has 1,500 MW of wind energy installed and plans to double that total in 2009. Mainzer warns that this rapid influx of such a variable resource has begun to tax the integration capabilities of the hydroelectric systems typically used in the region as rapidly dispatchable backup generation.

“As you put more and more wind on the system, you are undeniably going to need more flexibility to ramp other resources up and down to deal with the fluctuations in the wind,” he says. For now, BPA will likely bring gas plants and other additional sources to market to cope with these demands, but energy storage may play an important role in future years.

Alternatively, an emerging renewable energy credit (REC) market presents another much-discussed path to RPS compliance for utilities.

“Renewable energy credits recognize the fact that not every state is blessed with enough renewable energy to meet federal requirements,” acknowledges Riedinger. Ultimately, however, a cost-layering effect may burden certain utilities or certain regions. For instance, he explains, a utility serving a high volume of consumers could financially struggle to both provide enough generation to meet its own customers’ needs and buy sufficient credits to meet standards.

RECs “can definitely produce some efficiencies and help leverage the resource availability in certain areas, but there are some pretty important implications as well,” agrees Mainzer.

Under the REC system, regions that produce generous amounts of renewable energy may develop worrisome flexibility issues stemming from partnerships with REC buyers. For instance, Mainzer says, California utilities’ practice of buying the Northwest’s wind projects with the intent of selling the physical energy in the Northwest — and also using RECs to meet obligations — has created cost-allocation concerns among utilities and other stakeholders operating in the wind projects’ local areas.

Regardless of the specifics of the expected national RPS legislation, the market signals encouraging utilities to incorporate additional wind power to their portfolios are nearly universally expected to grow increasingly strong.

“[Wind] is no longer just a marginal resource, but clearly in the sweet spot of electric utility planning for new generating capacity for the future,” AWEA’s Swisher stated.

By Jessica Lillian

North American Windpower
January 2009

Tags: Wind power, Wind energy

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