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?
Jacobs and MPS also began to focus on the reality that Mars Hill would be exporting out of the MPS footprint while MPS’s emergency reliability margins were required only for flows into its footprint. ”Our contract with MPS was to export out,” reports Jacobs. ”So if they had a loss of generation, physics would actually redirect our generation to supply it. Our electrons would not have to go out and then be reassigned to come back in, which would appear to create a double burden on the transmission line.”
In the end, MPS became comfortable enough with this complex situation to provide nonfirm transmission service to Mars Hill—no small accomplishment, considering that MPS answers to multiple regulators despite its tiny size. (It is part of the Northern Maritime Control Area operated by the New Brunswick System Operator, which in turn answers to the Northern Maine Independent System Administration, a FERC-approved entity.)
In another instance, First Wind worked with the New York Independent System Operator (NYISO) to update rules on transmission cost sharing to reflect the realities of the rural grid. In this case a First Wind farm required an upgrade not to a transmission line but to antiquated substation protection equipment located in a rural area of upstate New York in the Finger Lakes region that had not seen new transmission investment in 34 years.
”It amounted to $3 million in charges that we were expected to pay, and we were flabbergasted,” says Jacobs.
Although the NYISO had reformed its cost-sharing rule years ago to require all generators who use a new line to pay their share of transmission costs, the rule did not anticipate a situation in which not the actual lines but their controls needed to be upgraded. ”The ISO legal staff realized this was a shortcoming in the rules and extended them to cover electronic protection systems as well,” Jacobs says. The fortunate outcome allowed First Wind to share the cost of the upgrade with two other wind farms that were seeking interconnection.
MPS, First Wind, and the NYISO are not the only entities that have found ways to massage rules and modify practice to make new things happen.
Joe Green, a project manager with Iberdrola Renewables , a subsidiary of a large Spanish power company, knew that his business unit was in for a long wait in the Pennsylvania-New Jersey-Maryland Interconnection (PJM) queue when it submitted its interconnection request for the 102-MW Locust Ridge 2 wind farm in Schuylkill County, Pa., in the summer of 2006.
PJM is a regional transmission organization long known for its exceptional competence in grid management. Despite that reputation, there was seemingly little to do about the long line of companies and entrepreneurs that had been queuing up with new generation projects.
But Green was a man with a personal mission. He and his wife had invested a good portion of their personal savings in a 26-MW wind farm (later acquired by Iberdrola Renewables) along Locust Ridge the previous year. Now, as project manager for Iberdrola, he was charged with getting a second farm up and running along the same ridge. Green had grown up in Schuylkill County and had seen the environmental damage that coal mining had inflicted on the region. ”It spurred me to build something clean in the heart of anthracite coal country,” he says.
Green’s personal knowledge of the available land, the landowners, and the permitting process along the ridge gave Iberdrola a leg up in the development of Locust Ridge 2. The project had a couple of other things going for it. Iberdrola wanted to bring it on line as close to the end of 2008 as possible to meet its strategic planning goals and was willing to back up that commitment with financial muscle.
In September 2006, after PJM had produced its initial feasibility study for Locust Ridge 2, Iberdrola decided to commit $300 000 up front to obtain an interim connection agreement. This, in turn, effectively made the project ”live,” allowing PJM and the local utility, PPL Corp., of Allentown, Pa., to dedicate full-time engineering resources to it.
Under normal circumstances, PJM’s feasibility study would have been followed by a systems impact study and then by a facility study. But waiting for PJM to produce each of those studies would have delayed the project for over a year, Green estimates. ”Ultimately, it was about the strength of our balance sheet and the confidence on the part of management to take on the risk before having all the studies completed that allowed us to pull ourselves out of the queue,” says Green. ”So instead of having 50 projects ahead of us, this financial commitment made us a dedicated, funded project.”
Green also credits PPL for Iberdrola’s positive experience with Locust Ridge 2. PPL did the extra analysis required to determine that the wind farm could connect with an existing nearby 69-kV transmission line, after some conductor upgrades; it found that it could do so much more cheaply than if Locust Ridge had connected with a more distant one that was about to be upgraded from 230 to 500 kV. Even more critical to the timely completion of the project, says Green, was PPL’s offer to tie Locust Ridge 2 into a second, adjacent 69-kV line to provide a temporary test outlet while the first 69-kV line was being upgraded. As a result, Locust Ridge 2 became operational early this year, very close to its original target deadline.
Green’s experience with PPL, PJM, and Iberdrola shows that a willingness to cut through red tape and push some limits--besides exhibiting a ready command of acronyms—is essential to getting green generation up and running. Mike Jacobs’s dealings with MPS, First Wind, and the NYISO have much the same import: Some imaginative interpretations had to be put on terms like ”firm,” ”nonfirm,” and ”capacity limits.”
Current rules are being stretched hard, maybe too hard in some instances. In any event, more accommodating rules are urgently required.
About the Author
Susan Arterian-Change writes frequently about electricity, business, and regulation, and she blogs for IEEE Spectrum Online about community impacts of alternative energy futures.
To Probe Further
IEEE’s Power & Energy magazine devoted its March–April 2009 issue to smart transmission and distribution: ” Making the Connections: Next-Generation Grid,” and included an article taking a regulatory look.
The vision of a self-healing grid is nicely described in ”Preventing Blackouts: A Smarter Grid That Automatically Responds to Problems Could Reduce the Rising Number of Debilitating Blackouts,” [PDF] by Massoud Amin and Phillip F. Schewe, Scientific American , May 2007.
The technical features of a green-friendly grid get a qualitative account in David Talbot’s ”Lifeline for Renewable Power,” Technology Review , January;–February 2009.
An article by Susan Arterian Chang emphasizing the regulatory preconditions for a green-friendly grid appeared in the November 2008 issue of EnergyRisk : ” Renewables Call for Transmission Build”.