It’s a complaint heard in as many as 90% of DE projects, according to one study; namely, the sometimes ridiculously tough, seemingly arbitrary, prohibitively expensive, and overly finicky requirements to be met for parallel grid interconnection. After years of DE firms simply enduring the situation, recent developments suggest that matters may be moving in the right direction. Just this May, the Federal Energy Regulatory Commission (FERC) issued its new Rule 2006, which should prove a major step forward in defining, streamlining, and standardizing small generator interconnection procedures (SGIP) and standardizing small generator interconnection agreements (SGIA). Issued mid-May and becoming effective in August 2005, the rule directs public utilities that do interstate electrical transmission to amend the open-access transmission tariffs (OATT) and offer non-discriminatory, standardized interconnection service. Observing that, historically, “Public utilities had … the incentive to engage in, and had engaged in, unduly discriminatory transmission practices,” FERC’s standard will perhaps correct that situation, starting fairly soon. The hope and goal is to see interconnect barriers lowered to the practical minimal-point needed to assure system safety and reliability. (For Rule 2006 summary provisions, see sidebar.)

Why, you may wonder, has interconnection required a federal ruling? Historically, although the Public Utility Regulatory Policies Act of 1978 (PURPA) was aimed at opening the nation’s grids to customer-owned interconnected generation, the reality has proven tougher than was envisioned. Electric utilities—having almost no incentive to make the process easy, and several reasons to thwart it—have typically forced developers to run a gauntlet of expenses and vexing hurdles. Over the years, such anticompetitive conduct has been investigated academically a few times, perhaps most notably by the National Renewable Energy Laboratory (NREL) in 2000, under the DOE. This resulted in a lengthy report, Case Studies of Interconnection Barriers and their Impact on Distributed Power Projects. NREL completely confirmed the scope and severity of DG developers’ difficulties. More positively, the report also presented a 10-point action plan for correction. Over the ensuing years all 10 points have been incorporated, to varying degrees, in several new industry standards and model interconnection agreements.

Greatly complicating the reparative challenge is the fact that FERC oversight and rulemaking overlap and compete with that of 50 state regulatory bodies. FERC governs interstate electrical commerce, of course, while each state regulates business within its own borders. Scores of utilities and transmission organizations are governed both ways.

The difficulties notwithstanding—and with growing awareness of the nation’s need for more diversified and renewable power generation—the DE industry has been witnessing a steady succession of important breakthroughs.

Examples include:

• Beginning in 1999, aggressively favorable state regulatory commissions in New York, Texas, California, and Ohio have issued rulings to lower interconnection barriers and standby rate charges.
• October 2001: FERC initiated its first major distributed-generation rulemaking, which culminated in 2003 with Rule 2003(c) standardizing the interconnection procedures and business terms for “large generators,” i.e, those yielding 20-plus megawatts. Like the new Rule 2006 for small generators, the earlier prototype applies to the approximately 176 regulated utilities and transmission providers engaged in interstate wholesale transmission and distribution.
• February 2002: The National Association of Regulatory Utility Commissioners (NARUC), seeking to foster state-level electrical tariffs and policies on DE-grid interconnections, passed a resolution supporting the development of two model DE interconnection procedures and business agreements. By October 2003, NARUC had issued its Model Interconnection Procedures and Agreement for Small Distributed Generation Resources.
• 2002–2005: In a survey of initiatives underway in the 50 states conducted by the National Regulatory Research Institute (NRRI), five states—Delaware, Florida, Idaho, New Hampshire, and Virginia—have now approved DG-favorable documents, while a half-dozen others—Arizona, Michigan, Minnesota, Missouri, New Mexico, and Wisconsin—are entertaining drafts, proposals, discussion papers, or interim procedures. Sixteen member-states of the Southern States Energy Board have endorsed Texas’s model DG interconnection standard as a prelude to regulatory “ratification.”
• January 2004: The New York State Public Service Commission ordered a waiver of standby charges for new DG resources of less than 1 MW meeting certain cogeneration efficiencies.
• July 2004: The IEEE issued its critically important “Standard for Interconnecting Distributed Resources with Electric Power Systems,” designated IEEE 1547. This addresses the performance, operation, testing, product quality, and safety of interconnection of hardware and software for DG—with additional subset standards and related issues still being ironed-out to cover DG control, communication, interoperability, design, engineering, installation, and certification, according to IEEE’s Web site. Based on input from several hundred organizations, the 1547 series should completely encompass all technical and engineering standardization related to DG, greatly enhancing progress and efficiency.
• Feb 2005: The California Energy Commission completed a revision of its five-year-old Rule 21 interconnection procedures, with the effect of boosting DG-favorable treatment even further.

None of this represents what might be considered perfect, universal standardization, but the net, cumulative effect should eventually enable DG developers to see significantly lower interconnection costs; a smoother, streamlined application process; quicker and more predictable project completion timetables; and less ‘reinventing of the wheel’ or redundancy. FERC’s recent ruling amplifies: “Equipment manufacturers will have compatible technical specifications to meet. New generation will be located on the basis of what works best for the Interconnection Customer and the Transmission Provider, not jurisdictional differences in interconnection rules.” FERC also anticipates that Rule 2006 will, as the commission’s accompanying statement says, “facilitate the introduction of new technologies … limit the opportunities for transmission providers to favor their own generation, preserve reliability and safety of the transmission provider’s transmission system …” Other benefits include lower costs for DG developers; enhanced grid reliability; increased energy supply; lower wholesale electric costs due to increased supply; and more non-polluting “alternative energy resources,” FERC notes.

FERC versus NARUC
If there’s any shortcoming to FERC’s new rule, it would appear to be the federal agency’s limited jurisdiction, which encompasses only OATT utilities. The majority of small generators interconnect with utilities that aren’t subject to OATT, and hence they’re not subject to rule 2006; rather, they fall under state commission rules. Here, NARUC’s two-year-old model interconnection standard—which closely parallel’s FERC’s and provided much of its inspiration—must undergo state-by-state implementation. As previously noted, FERC and NARUC both claim jurisdiction and have engaged in an ongoing turf battle, which appears to be going NARUC’s way. Although strongly supportive of DG in principle, NARUC wants the 50 states to retain local jurisdiction. For its part, FERC points out that Rule 2006 largely “harmonizes … many of the best practices interconnection rules recommended by NARUC” anyway.

Richard Brent, who is government affairs director for Solar Turbines and was active on a team of small-generation advocates negotiating with FERC, notes that the federal-state jurisdictional issue has been a recurring complication. In discussing DE lobbying efforts in 2004, he recalls, “We got into very complex discussions” concerning both local and interstate transmission, “because most all DG is not technically wired to run at transmission-level voltages—and yet,” he says, “here we were negotiating about getting interconnected to the transmission system.” Thus, at some points during industry strategizing, the question was raised about why the DE industry should worry about such interconnections, i.e., “Why are we here at FERC,” he says, “as opposed to working at the state level?” Defining the breakpoint between transmission and distribution is a regulatory can of worms to be avoided, he adds, but the DE contingency decided, “the reason why we wanted to be connected to the grid is because we believe we can be part of a demand-response initiative,” he says. “We can be part of a capacity market” in key places “like California, PJM [Pennsylvania, New Jersey, and Maryland regional transmission], and New England.” In such locales, DE has a role to play in easing bottlenecks, and a federal interconnection rule would give the industry access to a wholesale market enabling “credit for customer-owned capacity, and customer oriented demand-response,” says Brent, who is also a former chairman of the US Combined Heating and Power Association (USCHPA).

At one point Brent’s industry colleagues found themselves in three-way negotiations with FERC and NARUC. He recalls, “In an odd way, while FERC gave a commendable effort to interconnect small DG 20 MW and under—what it may have done was to tighten up the NARUC standards so that we can start to look for a uniform national standard for interconnection that can at least be a guideline and could be adapted, as appropriate, and adopted by a given state.” With the issuance of NARUC’s interconnection model in 2003, he says, “I think we’re 85% of the way there. … So that’s kind of a nice side benefit of our negotiations for the year-and-a-half-plus” with FERC.

DG Lighting Up ISOs and RTOs?
What’s the real impact, then, of FERC 2006 on typical transmission organizations? Eric Laverty, an engineer with the Midwest ISO or MISO—a nonprofit independent transmission operators group covering 14 states and adjacent Canadian provinces—participated in multiple FERC stakeholders meetings in drafting both the large- and small-generator interconnection procedures. From a transmission standpoint, he says, “The FERC order covers a whole lot of ground. There aren’t too many people at any utility or ISO who know all of it,” he adds, referring to Rule 2003 covering 20-MW-plus generators. FERC is thus allowing ISOs and RTOs an additional 30 days to implement Rule 2006 and granting greater flexibility than it grants to utilities.

Regarding the interconnection rules themselves, Laverty explains, the preliminary study processes required under the new regime “are very similar, really” to what has always been done. The chief gain of standardization appears to be that the DE applicant can now deploy the same generating equipment anywhere that FERC has jurisdiction. Hence, “If you’ve got developerd who’br been working out in California and they want to come here to the Midwest and locate a project, the rules are now the same in both places,” he says, “so we don’t have to go over every nuance of the procedures.” Technical dissimilarities from project to project will remain significant, however, because transmission systems vary considerably depending on, say, a rural versus urban locale.

As for small generator connections to MISO, Rule 2006 will impact “a large number of our projects,” he suggests—perhaps “half of the wind generation applications” alone, not to mention other DG technologies, all of which would be classified as small generators. MISO ISO receives interconnection requests “daily,” he adds.

State Interconnection Rules: Easy to Dodge?
Although this spate of regulatory intervention appears to be an improvement, recent reports in California and New York illustrate how far short rulemaking can fall if the regulated utility is bound and determined to thwart DG, come what may.

A case in point: In 2004–2005 the California Energy Commission undertook an extensive review of Rule 21 with the aim of resolving several shortcomings. Submitting testimony concerning the proposed revision, Tecogen, a national DG developer, reported a quite less-than-satisfactory experience in that state, lasting several years. For example, despite their having met all requirements of Rule 21 in order to qualify for “simplified interconnection without additional requirements,” Tecogen’s local utility “partner,” Pacific Gas & Electric (PG&E), somehow managed to reject all of Tecogen’s interconnection applications, comprising 24 cogen units for 15 projects, according to Tecogen’s public-record statements to the commission. PG&E also insisted that Tecogen apply “extremely expensive” redundant safety systems based on PG&E designs. Moreover, several Tecogen projects were halted mid-construction, “and stranded in the field or at the factory,” the company claimed. Ultimately, a compromise ensued, but Tecogen’s experience under Rule 21 “was “financially devastating to all parties.”

Another unhappy California energy businessman—Mark A. Moser of RCM Digesters Inc., Berkeley, CA—attempted to develop four projects in the state, connecting digester-fueled generators to PG&E, Southern California Edison, and San Diego Gas & Electric. A big loophole in Rule 21 allowed the utilities a “supplemental review,” effectively negating Rule 21 access rights. Moser’s four projects became seriously delayed and, once they entered the process, Moser received no timetables for work completion. The projects, he said, received “no outside review, and no referee” (i.e., the dispute resolution process failed each time). Moser reported being invoiced exorbitant sums for connection services (one bill came to $30,000 and another utility’s statement was “1-inch thick,” he wrote). When the utilities performed identical equipment tests, resulting charges inexplicably ranged from a low of $500 in one case, up to $7,000 in another. After Moser called a community newspaper to publicize the alleged mistreatment, his expense tab was revised downward $40,000.

Proposed Changes
Taking such testimony into account, California’s energy commission devised several proposed changes in Rule 21, which were forwarded to the California Public Utility Commission (CPUC) earlier this year. Four key areas covered in the revised rule follow:

• Net metering projects will “lose” the meter. The CEC prefers that utility payouts to DG owners be based on estimated power output rather than on actual meter measurements. This would eliminate the significant cost of metering (which can be expensive and is borne by the DG owner). California’s innovative concept may need to be revisited, however, if billing disputes proliferate. Meters would still be required if the DG project receives public funding incentives or tariff exemptions.
• Utilities can’t thwart net metering for “combined” DG (i.e., a system incorporating both net-metering output and non-metered output). Compensation is to be given for both kinds of DG. Interconnection rules for networked DG will be incorporated into a revised Rule 21 (with a draft proposal due in December 2005).
• Dispute resolution will be fine-tuned. Mediation by the CPUC; tighter timelines for resolution; and clearer identification of decision-makers will be incorporated. Utilities will be required to provide more detailed technical justification to the DG owner, rather than simply asserting a need “to protect safety and ensure reliability,” as utilities like to say. For educational purposes and to assist other DG owners, dispute case information will be made public, subject to appropriate confidentiality safeguards.
• Cost-tracking of utility expenses will give CPUC regulators better data on what utilities’ DG-related costs are, to assist in future evaluations.
• Grid-interconnection application fees and grid-infrastructure improvements should be paid for by the utility, with the cost recovered through the distribution component of utility rates.

On a final note, New York State also boasts pro-DG regulatory policies, but again, utility practices can continue to make interconnecting tough. As Solar Turbines product manager Chris Lyons noted last year, “Each utility has a number of ‘outs’ that they use as excuses not to conform to that FERC standard.” Example: in dealing with Con Edison in New York City, Lyons recalls, “We were having to look at whole new turbine-generator package designs to accommodate what they define as their ‘short-circuit study requirements,’” thereby rendering the interconnects “totally different than what we’ve been traditionally used to.”

Thus, again, despite the Public Service Commission’s best efforts at standardization, New York’s interconnection rules somehow remain “specific to their utility,” Lyons says.

Will FERC 2006 help? Perhaps so, he speculates. Since Con Ed imports power across state lines, the utility should fall under federal jurisdiction. Or then again, Lyons wonders, “Maybe they’ll get around it; I don’t know...”

DAVID ENGLE, a writer based in La Mesa, CA, specializes in construction-related topics.

DE - November/December 2005