Phil Davies - Senior Writer
Published July 1, 2007 | July 2007 issue
In February the Minnesota Legislature adopted the most ambitious renewable-energy mandate in the country. By requiring most utilities serving Minnesota customers to derive 25 percent of their retail electricity sales from renewable sources by 2025, the mandate commits electricity producers to a rapid ramp-up in generation from wind power, solar power, wood burning and other renewable technologies. To satisfy the mandate, an additional 5,000 to 6,000 megawatts (Mw) of renewable generating capacity—seven times Minnesota's current capacity—must flow onto the state's grid over the next 18 years. Expensive transmission upgrades are needed to carry that power to residential and business users, who could end up paying more for electricity.
Yet barely a whimper was heard from power companies, business interests and consumer advocates when the measure passed. Those most affected by the mandate—utilities that must abide by it and heavy electricity users that have no choice but to buy their power—seemed resigned to the inevitable.
The Minnesota Chamber of Commerce, which over the years has opposed renewable-energy mandates, struck a neutral stance on the law, officially called a renewable portfolio standard, or RPS. Missouri River Energy Services, an electricity wholesaler based in Sioux Falls, S.D., that serves 24 municipal utilities in Minnesota, voiced disappointment over the legislation's failure to push for transmission improvements, but didn't object publicly to its main thrust. In a telephone interview, spokesman Bill Radio said that MRES is also concerned that the law will raise electricity rates for its members and their customers.
"But this is the way that everybody is going," he said, "and we certainly don't feel that others should do things that are environmentally responsible, and we shouldn't. So we're going at it just as everybody else will."
Mandating power production from renewable resources does appear to be the way everybody is going, in the Ninth District and across the country. Montana and Wisconsin are among 22 other states (plus the District of Columbia) that have enacted similar but less stringent RPSs with various minimum percentages, eligible technologies, and intermediate and final target dates. Montana's standard, adopted in 2005, requires investor-owned utilities to obtain 5 percent of their electricity from new renewable-energy facilities by 2008 and 15 percent by 2015. Wisconsin upped its modest RPS last year, setting a statewide renewable-energy goal of 10 percent by 2015. To get there, each utility must increase its renewable-energy percentage by at least six points above average 2001-03 levels. (See table for a comparison of state RPSs.)
Proponents of renewable-energy mandates cite their environmental benefits and the economic promise they hold for rural areas. Commenting on Minnesota's tough standard, Mike Bull, assistant commissioner for renewable energy in the state Department of Commerce, said that the measure helps the state utilize its "indigenous resources" for generating electricity rather than import coal and natural gas from other states. "There's an environmental benefit to that, and there's an economic development benefit to that," he said. "Since we have the resource, we also want to attract the manufacturing facilities that go along with creating the infrastructure to utilize the resource."
Opponents of RPSs are mostly silent. Amid growing evidence of, and public anxiety over, global warming, the idea of displacing fossil fuels with renewable energy has garnered considerable political and popular support in the past few years.
But as states across the country jump on the RPS bandwagon, it's fair to ask if mandates are the right mechanism to encourage greater use of renewable energy. State mandates raise a lot of questions for utilities, regulators and electricity consumers: Will mandates drive up electricity rates, and if so, by how much? Are energy portfolios imbued with green capable of reliably delivering electricity to where it's needed? If government deems greater generation and consumption of renewable energy important enough to justify intervention in electricity markets, are mandates the right public policy tool?
The available evidence suggests that district RPSs at current levels won't short-circuit electricity supplies or send rates soaring, although some increases are likely. But nor are they the ideal way to stimulate renewable-energy development.
Government edicts have a way of getting things moving. Renewable-energy mandates have effectively fostered renewable-energy development in the district because utilities have no choice in the matter; they must buy green power from somewhere. A 1994 Minnesota law requiring Xcel Energy to purchase a minimum amount of renewable power as a condition for storing radioactive waste at its Prairie Island nuclear plant is credited with jump-starting large-scale wind power development in the state. Since the mid-1990s utilities and private developers have erected more than 40 utility-grade wind farms in the windswept southwestern corner of the state.
Portfolio standards contribute to sustained industry growth by giving renewables a fighting chance against entrenched conventional fuels, advocates say. By guaranteeing customers for renewable energy, mandates help nascent renewable technologies and industries achieve economies of scale. Widespread development of large commercial wind farms, combined with refinements in turbine technology, has helped lower the price utilities pay for wind power to about six cents per kilowatt hour (kWh), roughly half of what it was 20 years ago.
"Without mandates, the utilities would have simply dabbled in wind," said Michael Vickerman, executive director of Renew Wisconsin, a nonprofit organization that supports renewable-energy development. "With mandates, utilities are forced to integrate wind into their core energy plan. What we've seen over the past 25 years is the mainstreaming of wind."
Wind's relatively low cost has made it the go-to renewable-energy source for district utilities trying to satisfy RPSs. With assistance from a federal production tax credit for wind farms that reduces the cost of their electricity by roughly one-third, wind power has become roughly competitive with new coal generation and natural gas firing, spurring wind power development across the country.
Montana's first utility-grade wind farm, the 135 Mw Judith Gap facility, began operating in early 2006, supplying power to NorthWestern Energy under a 20-year contract. By year's end Montana-Dakota Utilities, the state's other investor-owned utility, plans to generate its own wind power from a 20 Mw wind farm to be built near the town of Baker. Several wind farms are being built in southern and eastern Wisconsin outside the district, and in Minnesota wind power expansion continues apace: Over 900 Mw of additional wind power is slated to come online in the state by the end of next year.
Wind farms are going up even in states such as Oregon and Oklahoma that have not enacted RPSs, posing the question of whether mandates are still necessary to drive development in states where wind power has a firm foothold. "The irony of [the Minnesota RPS] coming at this time is that with the production tax credit, wind is becoming a competitive alternative to other resources on its own," said Mike Franklin, director of energy policy for the Minnesota Chamber of Commerce.
In contrast with wind, district mandates appear to have done little to stimulate development of other types of renewable generation such as biomass, small hydro and photo voltaics. Eight years after Wisconsin adopted its first RPS, requiring utilities to obtain 2.2 percent of their electricity from renewable sources by 2012, only 60 Mw of new biomass and a single new hydroelectric plant have been developed, according to the Public Service Commission (PSC). In Minnesota, where Xcel was required by the 1994 mandate to invest in biomass as well as wind, biomass projects account for less than 1 percent of retail electricity sales. Most new biomass generation has come from burning waste wood or poultry manure, at a much higher cost than producing power from conventional fuels.
Because of either a lack of suitable sites for new projects or technical drawbacks that elevate costs, private investors and utility resource managers in the district have shown little interest in nonwind technologies.
Historically, utilities have relied on energy sources that deliver the most reliable power for the lowest price—coal (which accounts for more than half of the power produced in every district state except South Dakota), nuclear, large hydro plants and natural gas. Utilities and their customers worry that compulsory use of increasing amounts of renewable energy will drive up rates and compromise reliability, if not immediately then several years from now when RPS numerical targets peak.
Minnesota's "25 by 25" goal is the strongest in the nation in terms of the percentage of renewables that must be added to the state's energy portfolio. Xcel must clear an even higher bar under the mandate, relying on renewables for 30 percent of its electricity sales by 2020. Today, renewable sources account for only 3.5 percent of statewide retail electricity sales. Because most of the additional renewable energy is expected to come from wind, an estimated 3,000 new wind turbines would have to be erected in the state by 2025. Wisconsin's modified RPS also represents a significant ratcheting up from the original 1999 mandate, which has been met, according to the PSC.
Market mechanisms and regulatory oversight built into district RPSs are meant to offset the loss of utilities' purchasing freedom. Renewable-energy credit (REC) programs give utilities the option of declining to generate or purchase renewable power; instead they can satisfy an RPS by buying RECs from other utilities with a surplus of renewable power in their energy portfolios. The Wisconsin PSC has administered such a program since 2001, and REC trading systems are being developed in Minnesota and Montana.
In all three district states with RPSs, utilities and ratepayers can also appeal for relief from state regulators. "Off ramps" written into Minnesota's RPS allow the Public Utilities Commission (PUC) to temporarily relax its provisions if commissioners become concerned about higher rates, reliability, transmission restraints or other issues. "The commission has the authority to essentially shape the standard to fit each utility's circumstances so they're not forced to do dumb things," Bull said.
But these safety valves have not allayed fears that forcing utilities to add thousands of megawatts of renewable power to the grid will prove too much, too soon.
The most worrisome aspect of RPSs, especially for power-hungry businesses, is the possibility of big rate increases. Electricity rates in Minnesota, Wisconsin and Montana are below the national average; power in Minnesota costs less than half what it does in Massachusetts, according to government figures. Escalating renewable-energy targets could change that, imposing a financial burden on businesses and consumers.
Electricity produced from every renewable source except large, preexisting hydro facilities (which don't qualify as renewable under any district RPS) costs more today than power generated from conventional fuels. As noted, wind is competitive with coal and often cheaper than natural gas—generally used to meet peak demand—only because of the federal production tax credit, which has been extended through 2008. If Congress lets the 1.9 cents per kWh credit expire in 2009, wind would lose that competitive edge. Utilities required by RPSs to purchase unsubsidized wind—or even more expensive biomass or solar power—would respond by passing along those higher costs to ratepayers.
Business Card Services, a commercial printing company in Burnsville, Minn., spends over $7,000 per month on electricity needed to run printing presses and lights around the clock. CEO Jim Marchessault worries that the state's RPS will increase his power bill, eliminating a key advantage of operating in Minnesota. "I'm not against renewables, by any stretch of the imagination, as long as it makes good economic sense," he said. "But if [the mandate] forces rates up, it would make us as a Minnesota manufacturer less competitive in the marketplace."
The Wisconsin Industrial Energy Group, a trade association of large energy users, publicly supported Wisconsin's revised RPS. But "some of my members are primarily energy-driven companies," said Executive Director Todd Stuart, "and it could impact them negatively. We are very concerned about this issue and what it's going to cost."
Stuart worries about the considerable capital cost—roughly $3.2 billion through 2015, WIEG estimates—of building renewable-energy facilities to satisfy Wisconsin's RPS. He notes that heightened demand for turbines, towers and other wind farm equipment in the past two years has already inflated wind development costs that consumers must ultimately bear. "There are lines out the door," he said. "We may be in the queue, but so is everybody else, and the costs keep going up and up."
For the record, studies that looked at the projected rate impact of RPSs in various states forecast only incremental increases in electricity prices. But these studies were by no means conclusive; energy markets are complex, and certainty about future market conditions and energy policies is hard to come by (see "Watt if: Estimating the rate impact of RPSs").
The prospect of a power supply increasingly dependent on power from renewable sources also raises nagging reliability issues. Can utilities long accustomed to the steady output of nuclear, coal and big hydro plants incorporate hundreds of megawatts of weather-dependent wind power into their energy portfolios without risking California-style brownouts? And will there be sufficient transmission capacity to transport bumper crops of rural juice generated from wind, biomass and other sources to cities where it's needed?
Recent research on the operational effects of RPS targets indicates that power producers can indeed absorb a heavy infusion of renewables—specifically wind—without risking brownouts and other system breakdowns. The 2006 Minnesota Wind Integration Study, commissioned by the state PUC, examined the impact of generating 20 percent of electricity statewide from wind by 2020, as called for by the state RPS. The study found that the 20 percent target would not reduce reliability, as long as sufficient backup generation (from coal and natural gas) and transmission capacity were in place. Great River Energy, Minnesota's second-largest power supplier, conducted its own wind integration study last year and came to the same conclusion.
But there's no assurance that the new transmission lines assumed in the Minnesota Wind Integration Study—and needed to transport renewable power in other areas of the district—will exist when RPS target dates roll around. Transmission bottlenecks already restrict the flow of wind power off the Buffalo Ridge in southwestern Minnesota; without massive upgrades, the anticipated construction of thousands of new wind turbines would overwhelm the area's electricity grid. A scarcity of high voltage lines in the eastern Dakotas could also restrict the eastward movement of electricity from additional wind farms developed in central Montana to fulfill that state's mandate.
The transmission issue is at the heart of MRES's objections to Minnesota's mandate. Radio, the company spokesman, said he wonders whether the PUC will step in if transmission improvements fail to keep pace with renewable-energy development. "We're concerned that the off ramps will not be granted, the mandates will stay in place and the transmission will not be adequate for the power that's supposed to get on the grid," he said.
Current and proposed projects aimed at beefing up transmission to accommodate increased wind power development in the district include $160 million in line upgrades by Xcel Energy in southwestern Minnesota; a 200-mile transmission line running from Brookings, S.D., to the Twin Cities planned by a utility consortium; and a high-voltage link between Great Falls, Mont., and Lethbridge, Alberta.
The worst-case scenario for district RPSs is that they distort prices and undercut market efficiencies to such a degree that they become a crutch for overpriced, dead-end technologies. "What we risk doing ... is we mandate the consumption of energy that is so expensive that it wouldn't be bought absent the mandate," said Jerry Taylor, a senior fellow with the Cato Institute, a public policy think tank in Washington, D.C.
Like "carrot" approaches to renewable-energy development such as the wind production tax credit, Wisconsin's property tax exemption for photo voltaics and other government incentives, holding a "stick" over utilities' heads risks misallocating resources to economic activities that at the end of the day produce little value. A mandated or subsidized renewable-energy industry may generate employment in rural areas (although there's considerable debate over just how many jobs are created by wind farms and other renewable-power facilities), but ratepayers and the overall economy pay dearly for those jobs if workers are engaged in inefficient power production.
A case in point is a new plant in Benson, Minn., that burns turkey manure to generate electricity. The $225 million Fibrominn plant, contracted to Xcel Energy to satisfy the biomass portion of its 1994 mandate, is expected to employ 30 to 35 full-time workers and support another 175 jobs in related industries such as trucking. But even after factoring in federal tax breaks for biomass generation, Xcel is reportedly paying twice as much for the plant's 55 Mw output as it would for an equivalent amount of wind power.
Advocates of RPSs counter that focusing on the market price of renewable energy ignores the bigger picture. Supporting renewables by government fiat is justified because electricity markets fail to fully account for their public benefits—in particular, environmental pluses such as less pollution and lower emissions of gases implicated in global warming. When these societal benefits are added to the cost-benefit equation, the true cost of continuing to rely on fossil fuel generation becomes clear, said Vickerman of Renew Wisconsin.
Many economists agree that electricity markets consistently underprice conventional fuels such as coal and natural gas because no one pays for the consequences of fouled air and water, or an apparently warming planet. In economic terms, pollution and greenhouse-gas emissions are "negative externalities" that may cause market failure—and call for government intervention to set things right. Correctly priced to recognize their public benefits, renewable-energy technologies may indeed provide greater value to society than conventional means of generation.
However, mandates do nothing to correct renewable-energy pricing; they simply render it irrelevant, negating the mechanism that makes markets efficient providers of goods and services. If utilities must buy power from renewable sources regardless of the price, producers have no incentive—other than limited competition among themselves—to operate efficiently, delivering power for the least cost in labor and materials.
Government has other means of influencing electricity markets that minimize the chances of unforeseen economic fallout. It can, for example, use its taxing and regulatory authority to impose penalties on utilities for polluting the air and water, effectively making cleaner alternatives a more economical choice. A number of economists, including William Nordhaus of Yale University, have recommended taxing greenhouse-gas emissions to encourage reductions and spark development of renewable-energy technologies. Another market-based approach to the problem of climate change would cap emissions of carbon dioxide and other heat-trapping gases and allow utilities that achieve reductions to sell credits to those that don't. An effective national cap-and-trade system already exists for sulfur dioxide, an industrial pollutant that causes acid rain.
The problem with these options is they're difficult to implement politically, said Steven Taff, an economist at the University of Minnesota, who has done research on renewable energy. Taxes of any kind are unpopular, he notes, and U.S. industry has only recently warmed to the notion of cap and trade. There are no federal taxes or caps on carbon emissions, although California, four other western states and a Canadian province have signed a compact to establish a cross-border cap-and-trade system for greenhouse-gas emissions.
"So we fall back on mandates," Taff said. "We say, 'You shall do this,' because we seem to be quite willing to just tell people to do it, as opposed to providing the proper economic incentives for them to do it, and for them to do it perhaps cheaper."
Renewable-energy mandates in the district are likely to remain the law of the land, part of a patchwork of state RPSs that has spread across the country in the absence of a federal portfolio standard. The impact of RPSs on electricity markets years from now may be negligible, dwarfed by other factors such as rising capital costs for all forms of generation and the aging of the national transmission grid. Or their effect could be significant, squeezing household budgets and weighing on the location decisions of businesses.
It remains to be seen how state utility regulators interpret RPS off-ramp provisions such as Minnesota's caveats about reliability and transmission constraints, or "cost caps" in the Montana mandate that let utilities off the hook if the market price of renewable-energy sources exceeds benchmarks set by the state PSC. So far, no utility or ratepayer group in the district has formally petitioned for relief from RPS requirements.
And a big question for power producers is how soon—or if ever—a regional or national market develops for RECs. Renewable-energy credit programs are designed to work like sulfur dioxide emissions credits; instead of paying a premium for, say, locally produced biomass, a district utility could meet all or part of its RPS obligation by buying credits from areas of the country best suited to renewable-energy generation—hydro from Maine or solar from Arizona. In this way, RECs help drive down the cost of compliance with mandates. "Certainly, a well-designed system will help the market reach a lower-cost portfolio," Taff said.
But today scant opportunity exists for interstate trading of RECs. Trading of "renewable resource credits" among Wisconsin utilities has been minimal and confined to the state. One potential sticking point in developing a broader trading network is gradations in perceived greenness among different types of renewables—waste-wood burning versus wind power, for example.
The Minnesota PUC, which must establish a state REC program by the beginning of next year, has been working with utility regulators in neighboring states, including Wisconsin and Montana, to develop a regional monitoring system to track and verify RECs traded across state borders.
Stuart of WIEG believes that even if wider markets do develop for RECs, utilities will still have to buckle down and produce or buy increasing amounts of actual green megawatts. After all, the goal of state RPSs is to promote increased production of renewable energy from local sources, not to support such development in other parts of the country. "You can't trade your way out of the mandate," he said. "You could, but it would be cost-prohibitive."