Smartening Up the Grid

The smart grid has meant a lot of things to a lot of people: a system that would be more efficient, robust, flexible, and—not least—green friendly. More than half the U.S. states have adopted so-called renewable portfolio standards requiring so-and-so much electricity to be green by such-and-such times. On June 26, the U.S. House of Representatives passed the American Clean Energy and Security Act, which mandates renewable energy standards for most of the country’s largest electric utilities. The act also includes a provision for a carbon cap-and-trade system that will make fossil fuels at least somewhat more expensive and low-carbon fuels more competitive.

But connecting new wind farms to the existing U.S. grid has already required entrepreneurs, operators, and regulators to bend and stretch rules almost to the breaking point.  As pressure grows to integrate still more wind, as well as solar concentrators, biomass combustion, and perhaps even tidal generators, rules will have to change.

How much pressure are we talking about? A lot. One survey of 11 major U.S. transmission regions found last year that applications to connect new wind and solar generators came in aggregate to 250 gigawatts—that’s the equivalent of roughly 250 standard atomic power plants—while combined natural gas, coal, and nuclear applications came to just 180 GW, according to Peter Mark Jansson and Richard A. Michelfelder, writing in the July 2008 issue of Electricity Journal. When New Jersey offered unusually generous rebates to solar installation companies at the beginning of this decade, more than 100 installation companies cropped up in just a few years, and at the end of 2007 the state had to stop accepting additional applications for solar interconnections.

Wind and photovoltaic farms may be small and beautiful when contemplated one at a time, but when considered altogether they add up to a big, ugly regulatory headache. The queuing system widely used in the United States to determine who gets to build new generation and connect with the grid works like this: Regional transmission organizations (RTOs) and independent system operators (ISOs) are charged by the Federal Energy Regulatory Commission (FERC) with overseeing the operation of the nation’s grid. Among their duties is to conduct feasibility studies when generators make interconnection requests. Under current FERC rules, these requests are managed by means of ”queues,” on a first come, first served basis. This system has worked well enough for large fossil-fuel-based generators. But these days the typical queue is jammed with hundreds of requests for interconnection from small generators of renewable power.

FERC has recently approved a number of creative proposals for queue reform. For example, during the past 10 years the Bonneville Power Administration (BPA),  headquartered in Portland, Ore., has had great difficulty making any major upgrades to its transmission system, while at the same time it has been struggling with a growing list of transmission service requests, many from wind power developers in the lower Columbia River area. (BPA is a federal entity that predates the RTO structure and operates a transmission system and wholesale electric market in the Pacific Northwest.) Bonneville Power adopted an innovative approach that changed the way customers requested transmission service and thus was able to achieve the critical mass of service contracts needed to get that transmission authorized. Because of its rich hydropower resources, of the 2000 MW of wind power currently generated in the BPA footprint, the vast majority serves the demand of other Northwest utilities.

In June 2008, with FERC approval, the BPA was able to radically reform its queuing process. It began clustering service requests rather than studying each individually. This gave the BPA a better idea of what impact the requests would have collectively on the network. It also launched a ”network open season” during which all current applicants looking for long-term transmission were required either to sign service contracts or drop their applications. The BPA and its customers also agreed to substantially increase the financial commitment required to secure a position in the queue to an amount equal to the cost of a full year of transmission service. This immediately yielded 160 long-term transmission service contracts, the majority for wind power. The open season also helped clear the queue of nonviable projects. ”We immediately got 6000 MW of signed contracts, and the other 8000 MW of pending projects dropped out of the queue,” says Elliot Mainzer, the BPA’s executive vice president for corporate strategy.

The combined clustering and open season exercise allowed the BPA to free up 1700 MW in available capacity on the network. Primarily to meet the additional needs for wind power service, the BPA announced in May that it will add four new high-voltage transmission lines to its network.

If anyone knows the fatal flaws of transmission planning for renewables in the United States, it’s Dariush Shirmohammadi. In early 2006, as director of transmission for the southern region of the California ISO (CAISO), Shirmohammadi was given the task of producing a transmission service plan for moving wind power from rural Tehachapi—a mountain pass in Southern California between Bakersfield and the Mojave Desert—to consumers in greater Los Angeles, some 120 miles to the south. This was a project of some urgency. The state of California had recently revised its ambitious renewable portfolio standard upward, mandating that 20 percent of its electricity come from renewable sources by 2010. It was nowhere near reaching that target.

According to some estimates, Tehachapi has the potential to accommodate between 4500 and 6000 MW of wind power annually, roughly the equivalent of between four and six nuclear power plants. The intense heat of the Mojave Desert whips air eastward from California’s Central Valley, often creating gale-force winds. But the history of Tehachapi transmission planning and building is a tortured one. In the late 1980s, Sagebrush Partners, a consortium of wind farm developers, approached Rosemead-based Southern California Edison (SCE) with an interconnection request to build a line from Tehachapi to a substation some 50 miles to the south, in Palmdale.

Under the federal Public Utility Regulatory Policies Act of 1978 (PURPA), which in effect broke up the monopolistic hold traditional utilities had on power generation, utilities were required to buy power from renewable power generators like Sagebrush at rates established by state utility commissions. The California Public Utilities Commission (CPUC) had set those rates at very generous levels, and utilities were not always happy to pay them. After considering the price SCE quoted for building the line, Sagebrush decided that it would be cheaper to construct it itself and proceeded to do so, reportedly at a significantly lower cost than SCE’s estimate. In 2006, however, with the tables turned, the owners of Sagebrush did not consent to allow another independent wind generator, Aero Energy, in Tehachapi, to tap into the line. Aero Energy appealed to FERC, which eventually ruled in its favor in 2007. But by then Aero Energy’s plans had apparently changed, and the company did not pursue the connection to the Sagebrush line.

Meanwhile, starting in the mid-1990s, the CPUC had patched together a succession of loosely organized working committees and task forces to produce plans to build transmission for renewables in Tehachapi. But more than a decade later none of those plans had come to fruition. The reason, according to Shirmohammadi, gets to the heart of what’s wrong with transmission planning across the United States and why so little new transmission has been built for the last 30 years. ”No one party can say, ’Go ahead and build a line,’ ” he maintains, ”but any one party can kill a transmission project. You have so many parties that have a say in the discussion about transmission that the whole process, more often than not, turns into a long-term melee.”

In the case of Tehachapi, the CPUC had in fact approved parts of the transmission project before the final report of the last task force and had ordered SCE to build it in 2003. SCE took the CPUC to court to get the order blocked. In 2004, the court found in SCE’s favor.

Inheriting this dysfunctional planning process, Shirmohammadi knew he had to come up with something transformational. Since he also had two other large regional transmission projects for review on his plate, he seized the opportunity to create a broader and more rigorous planning template. He developed the CAISO South Regional Transmission Plan for 2006 (CSRTP-2006), involving a multidisciplinary team of stakeholders, including representatives of utilities, renewables developers, public interest groups, and regulators. The group was given a clear mission: to formulate a plan for the southern portion of the CAISO grid by the end of 2006, focusing on regional needs and benefits rather than individual projects. One of CSRTP-2006’s main goals was to ”stop conflicting interests from damaging the chances of developing a regional plan for Southern California and the needed transmission infrastructure.”

”We were also not supposed to be arguing about whether transmission is good or bad or whether renewables were good or bad,” says Shirmohammadi. ”Those issues were to be resolved elsewhere.”

The result of this deliberately nurtured consensus-building effort was a transmission-planning solution for the Tehachapi area, reached on deadline in September 2006, that was acceptable to all parties and represented a major planning breakthrough for renewables transmission. The plan would require SCE to undertake a US $1.8 billion project to build roughly 200 miles of 220- and 500-kilovolt lines and upgrades by 2013 to integrate approximately 4500 MW of wind energy into the CAISO-controlled grid and ensure that this energy reached the Los Angeles area. It had another key element: The plan was flexible enough to anticipate new demand for electricity in the Antelope Valley and was capable of integrating generation from future geothermal, solar, and wind projects in Tehachapi and surrounding areas. The CAISO board of governors approved the plan in January 2007. But the plan still requires the CPUC’s stamp of approval, expected at the end of 2009. Meanwhile, of the 11 transmission line segments approved, none has yet been built.

Shirmohammadi left CAISO in 2007 to take a consulting position, but the ISO had learned some hard lessons about transmission building from what initially went wrong and what ultimately went right with the Tehachapi planning process.

”Tehachapi was not a regulatorily sound process, because we didn’t have the rules lined up properly at the time,” says Robin Smutny-Jones, director of regulatory affairs for CAISO. ”So going forward, we came up with the Renewable Energy Transmission Initiative to create a new framework for renewables transmission approval.”

The RETI is now completing the mapping of so-called competitive renewable energy zones (CREZs) throughout the state of California. ”It’s a ground-up assessment of where we get the biggest bang for our buck from renewables,” says Smutny-Jones. ”We determined that the richest area for wind is Tehachapi; for solar it is the Mojave Desert, and for geothermal it is the Imperial Valley of Southern California. We then looked at where in those areas it would be cheapest to build transmission—where it would be easiest to site, from both an economic and environmental perspective.”

Smutny-Jones reports that by 2010, California anticipates it will have a group of solid transmission projects to go into the hopper. ”We are about halfway through the process—tinkering with the zones,” she says. California’s RETI process is now being replicated on a region-wide basis in the western states through an initiative of the Western Governors’ Association. ”We hope it will spur some broad, westwide regional transmission planning that will lead to interstate lines to move power around,” says Smutny-Jones.

Once the California CREZs have been formally approved by the CPUC, transmission built to serve them will be eligible for a new financing mechanism approved by FERC at CAISO’s urging. The new scheme will solve the chicken-and-egg conundrum that has been plaguing transmission financing for remotely sited renewable generation for years. Under the old FERC rules, a generator that required a new high-voltage line to connect with the grid carried the full cost burden. This has created an insuperable barrier to entry for smaller renewable generators located far from population centers and has stalled new transmission projects.

Under the new rule, transmission owners will be able to finance new transmission for renewables in designated CREZ zones through a transaction access charge assessed to all the existing ratepayers they serve. As each new power generator comes on line, the generating company begins paying only its share of the costs of construction based on line use, up until the time that the line is fully subscribed and all the costs have been recovered. This initiative allows for transmission to be built to meet not only current but also anticipated future generation requests.

Another regulatory reform that CAISO has added to its toolbox to accommodate variable renewable generation is the Participating Intermittent Resource Program (PIRP). Under the old rules, renewables generators often paid hefty penalties for failure to meet day-ahead scheduled output—failure that in many cases was beyond their control. Under PIRP, the schedule for individual wind-farm power has been shortened to an hour ahead, with that forecast output used for CAISO’s hour-ahead scheduling. Individual farms are also permitted to net out their deviations from schedule over a month instead of every 10 minutes, as was the case under the old regulations. This results in a smoothing out of the deviations from schedule, which translates into lower penalty costs for the generators.

Piecemeal or ad hoc approaches for reforming transmission planning to accommodate renewables, such as those implemented by the BPA and CAISO, while creative and often heroic, represent suboptimal solutions. Many renewables industry experts believe that the entire regulatory process needs to be revamped and rationalized from top to bottom, with much stronger guidance and backstop authority from the federal level, if state—and in the future, national—renewable standards for electricity generation are to be met. ”This is an interstate network, and I think that should be the animating principle we follow in trying to reform the way we regulate it,” says former FERC chairman James Hoecker.

The energy bill now before the U.S. Senate addresses some of the regulatory reform issues that are virtually ignored by the bill recently passed by the House: FERC would get more authority to regulate interstate transmission planning and to formulate a methodology for allocating new transmission costs. Renewables industry experts have pinned their hopes on those key provisions being further strengthened in the final legislation.

”There are many processes under way in regulatory communities, including federal, state, and reliability authorities, as well as in legislative bodies, to change the rules and regulations around infrastructure and grid operations,” says Rob Gramlich, senior vice president for policy with the American Wind Energy Association. ”Generally, I would characterize them as the types of changes and scope of changes that were required in the booms of nuclear and of coal-fired generation. If you are experiencing a major boom of any one generation source, you have to plan the regulatory system to accommodate it.”