From the beginning of this century, the U.S. utility industry has been developing the conceptual framework for a smarter electricity grid that would be self-healing, interactive, and interoperable, open and communicative in real time, and green friendly. Now, nearly 10 years later, a dozen or two buzzwords more, and after a great deal of serious technical study, suddenly it’s real. The U.S. stimulus legislation adopted earlier this year allocates US $4.5 billion in grants for smart grid projects, $6 billion to support loan guarantees of $50-60 billion for renewable energy and transmission, and $6.5 billion in loan guarantees for the Bonneville Power Administration (BPA) and the Western Area Power Administration (WAPA) to expand transmission to accommodate renewably generated energy--a lot of money in all.
On 18 June, the National Institute of Standards and Technology (NIST) received a detailed account of issues and priorities that smart grid standards will need to address having been handed the job of devising an overall architecture. NIST is to issue a draft Smart Grid Interoperability Standards Framework document in September.
It’s a good start, but frankly, all will be for naught if the process of technical innovation and investment is not accompanied by a far-reaching reform of the ways the nation’s regional transmission and local distribution systems are regulated. ”We have entities, both public- and investor-owned, willing to invest in and build transmission,” says Michael Heyeck, senior vice president of transmission for American Electric Power in Columbus, Ohio, the country’s largest transmission operator. ”We just need uniform, guiding principles from somewhere to tell us what the projects are, who will pay for them, and in whose backyard they can be built.”
If the billions spent on green energy and green-friendly transmission are to mesh with the billions spent on smart grid technology, the rather convoluted way the grid has been regulated and managed will have to be rethought from the ground up. ”Everyone has their eye on the stimulus package, and there is at the same time an important impetus for transmission in the desire for clean energy,” observes James Hoecker, of WIRES, a business group that encourages investment in transmission. ”The problem is that the solution to transmission involves not just public monies but a more rational regulatory regime.”
A rosy glow is cast on First Wind's Mars Hill turbines, with the sun low in the sky
Hoecker, a former chairman of the Federal Energy Regulatory Commission (FERC), knows that deterioration of the grid infrastructure and sharply increasing long-distance traffic on the grid are major problems in their own right, independent of green energy concerns. Since the beginning of the decade, such traffic has increased four- or fivefold. But if a rebuild of the grid makes the transmission system better only for large bulk carriers, the end effect could be a repeat of what we saw with the interstate highways. That system proved marvelously friendly to heavy trucking, but it often drained the life out of the communities it was meant to nourish.
What follow are some stories from the trenches, where utilities, transmission operators, and entrepreneurs have been improvising frantically to make renewables projects go, working within outmoded and obsolete regulatory frameworks. With these examples and more to follow, we hope to illuminate the challenges facing policymakers and rule makers. For starters, a case study from Maine shows how one utility, under unusually awkward circumstances, has managed to keep wind-generated electricity flowing.
Last December, Mike Jacobs , vice president of transmission for Newton, Mass.-based First Wind, learned from the Maine Public Service Company (MPS) that it could no longer accommodate all the generation from First Wind’s Mars Hill wind farm in Aroostook County. Consisting largely of wilderness, Aroostook is Maine’s northernmost and largest county and borders Canada’s province of New Brunswick on two sides. These geographic oddities partly explain MPS’s unique distinction of having no direct connection as yet to the U.S. grid, although its system receives and exports power from and to Canada through three 69 or 138-kilovolt lines that terminate at substations across the border with New Brunswick.
From those peculiarities has followed a further eccentricity: Electricity generated at First Wind’s 42-megawatt Mars Hill farm, besides serving MPS’s 37 000 retail customers, is sometimes exported to Canada on the three MPS lines, only to be imported back on other lines to power other parts of New England.
”The utility never had enough generation in its area before to cause it to run into physical limits for exporting,” says Jacobs. ”Now they were telling us that they would have to cap how much energy we could produce. We previously had firm reservations to export for most hours, and the new conditions caused a cut in our nonfirm transmission.”
Nonfirm service means that the generator has the right to use the transmission only if conditions allow and only for a short period. If the utility experiences some limiting factor, it has the right to immediately require the generator that has reserved nonfirm capacity to power down. But even though MPS had had a nonfirm contract with First Wind for a portion of its generation since 2006, MPS never had much reason to exercise its privilege before.
Jacobs decided to take a closer look at how MPS was applying the regulatory rules for determining its ”reliability” or safety margin for dealing with an unanticipated loss of generation or transmission capacity. In MPS’s case, if one of its generators suddenly shut down, it would need to rely on imports from over the border. So it had been maintaining unused capacity along its incoming lines for just such a contingency. But now Jacobs thought that perhaps MPS, pressed up closer against capacity limits, was giving that contingency greater weight than the rules strictly required.
So he sat down with the operators of the utility for a brainstorming session. The first question they addressed was, ”Should we be counting that reserve margin as if it was really filled or as filled only in the event of a contingency?” Jacobs recalls. And if it was counted only in a contingency, couldn’t MPS then offer Mars Hill nonfirm service equal to that reserve?