Federal Interconnection Standards: Putting DG in a Box

Is FERC overstepping its jurisdiction and attempting to force a standard into a one-size-fits-all category?
Fortnightly Magazine - April 1 2003

Is FERC overstepping its jurisdiction and attempting to force a standard into a one-size-fits-all category?

Few industry stakeholders would argue the benefits of clear, concise universal standards for interconnecting distributed generation (DG) to electric utility grids. In fact, since PURPA (the Public Utility Regulatory Policy Act) was adopted in 1978 to promote alternative energy sources and diversify the electric power industry, numerous qualifying facilities (QFs) have been successfully integrated into utility grids by adhering to rules mandated by FERC and state commissions. Many of these QFs are interconnected directly to transmission grids, where FERC's jurisdiction falls squarely within Order 888. However, FERC has raised its jurisdictional bar to establish rules for interconnecting small DG facilities of 20 MW or less-including distribution previously in the domain of state regulators.

Despite the benefits of uniformity and consistency that a national standard for DG interconnections would provide, FERC's approach may have several potential shortcomings:

  • Little federal applicability. The vast majority of small DG facilities will interconnect at distribution voltages serving on-site customer loads for which states clearly have jurisdiction.
  • Duplication of efforts. A universal DG standard applied by the federal government will duplicate and potentially undermine successful efforts already undertaken in states such as Texas, New York, and California, irritate state regulators, and cause confusion among DG providers and utilities alike. These efforts took months, and FERC has learned the difficulty of reaching consensus on interconnection standards. Too many players with divergent goals can cause the process to bog down into a hopeless myriad of details.
  • Difficulty in implementation. States have greater flexibility than FERC to ensure that standards are consistent with state policy and utility regulations, and they also are in a better position to address any disputes that require interpretation and implementation of interconnection rules.

When FERC issued its April 2002 notice of proposed rulemaking (NOPR) on standardized interconnection agreements (IA) for generators of all sizes, DG suppliers immediately understood its significance. They seized the opportunity to capitalize on FERC's support of small DG as an economically competitive alternative to traditional central supply and delivery options.1 However, DG supporters want a simplified, expedited application review and approval process for generators under 20 MW, for all but the most complex interconnections. DG supporters argue-with apparent justification in some cases-that utilities will stifle integration of small, low-cost generators into their grid. Sympathetic to DG concerns, FERC agreed to address rules for DG by opening a small generator interconnection advanced NOPR (ANOPR) (August 2002) and establishing a coalition composed of utilities, a Small Generator Coalition (SGC), and NARUC to streamline application processes and procedures for DG less than 2 MW and for DG between 2 MW and 20 MW via consensus agreement.

At first, it appeared that FERC might quickly develop simplified and universal interconnection standards that would address SGC and utility concerns alike. FERC pointed to recent agreements crafted by PJM and ERCOT as models that DG advocates, utilities, and many states supported to justify that such an approach could be applied universally. FERC brushed aside jurisdictional objections by reminding commenting parties that it "has jurisdiction over generator interconnections when a generator interconnects to a transmission provider's transmission system or makes wholesale sales in interstate commerce at either the transmission or distribution voltage level." Interestingly, the ANOPR is silent about DG interconnections at the distribution level that exclude exports or wholesale sales-potentially, a large segment of the DG market that, by default, would be left to states to handle.

Elements of a Comprehensive Standard

In a typical DG facility operating in parallel with an electric utility grid, the DG output may be fully consumed by the adjacent load (non-export) or injected into the grid if output exceeds load (export). While numerous configurations and DG sizes are possible, comprehensive interconnection standards share the following elements:

  • clear and concise application requirements and cost, including filing deadlines;
  • processes for evaluating DG grid impacts, including screening criteria for system impact and facilities studies;
  • simplified or expedited approval process for low-impact or pre-certified DG;
  • minimum technical requirements, including DG performance criteria (e.g., voltage, frequency, power quality);
  • safety and reliability requirements, including protective relaying according to DG size and type; and
  • a dispute resolution procedure including mediation, arbitration, and commission filing. DG technologies generally fall under two categories: rotating machines such as induction and synchronous generators, and latent devices, such as photovoltaic (PV) systems or fuel cells that involve few moving parts. The latter category typically employs inverter-based technologies to convert direct current output to alternating current to synchronize to the utility grid.

Inverter-based generators tend to have less impact on utility grids because they automatically shut down if the grid experiences an outage or abnormal condition. Smaller DG-10 kW is often a rule of thumb-and those that are inverter-based typically are candidates for simplified interconnection. Most states employ screening criteria based on DG size relative to utility circuit loadings. For example, a DG applicant may pass a screen for expedited processing if DG output is less than 10 percent of the feeder peak.

FERC's ANOPR Quickly Bogs Down

The pitfall of false expectations soon reared its head as the SGC, represented by an impressive array of suppliers and industry experts, fought to a stalemate with utilities and NARUC on specific provisions of proposed small generator interconnection applications and procedures. The consensus agreement submitted by the joint coalition in November 2002 now resembles a patchwork quilt of annotations and exceptions highlighting as many differences as areas of agreement among the SGC, NARUC, and utilities.

Comments submitted to FERC by the SGC portray utilities and NARUC as inhibiting the evolution of a robust DG market, and characterize prior utility interconnection standards as "inconsistent, overly burdensome, unreasonably expensive, and often deliberately obstructive," noting that current "interconnection procedures constitute one of the most significant barriers to the widespread use of small resources in U.S. electricity markets."2 The SGC points out that the utilities' proposal could lead to unacceptably long application and study timeframes (over one year for complicated applications) as a major deficiency of the consensus agreement.

Perhaps the most fundamental, yet vexing issue in this debate is who bears the burden of proof of judging how and when DG interconnection will negatively impact utility grids. The DG coalition argued that FERC and state PUCs typically "assume the worst" when evaluating DG, leaving open the possibility of long application reviews or onerous interconnection requirements, including utility system upgrades that would dwarf the thin profit margins offered by smaller DG facilities. DG providers have pressed for fast-track approvals of smaller DG facilities using straightforward screening mechanisms, which utilities appear to support. The devil is in the details as to what constitutes reasonable application timeframes and screening criterion. Jim Watts, director of marketing for Ingersoll-Rand Energy Systems and a veteran of interconnection standard development, says, "We did have success and achieved consensus on some of the fundamental assumptions, for example certification and the use of screens. We basically just ran out of time to complete issues like network interconnection, applications, and agreements and didn't reach consensus on many issues concerning secondary network interconnection."

Utilities bristle at the notion that DG might be given favorable treatment over its own customers, and they suggest suppliers have overstated the problem as prior interconnection requests have gone smoothly-a point that some DG supporters concede. Utilities worry that if they encounter many competing DG interconnection applications, they don't want to be bound by unachievable tight deadlines mandated by interconnection agreements. In addition, utilities loathe the idea of cross-subsidies or cost shifting caused by DG integration and are therefore cautious not to overlook less obvious system impacts. In its comments to the FERC ANOPR, the Edison Electric Institute recommends the commission should "reject ratepayer or shareholder subsidies to small generators." It further states, "In obtaining interconnection, small generators must pay the full cost of studying the interconnection, and must make the same contribution for upgrades as generators would. Otherwise the utilities' other customers or shareholders will be unfairly and inappropriately subsidizing small generators. Moreover, this will not allow price signals for locating generation at the most efficient and economic place, as indicated by locational marginal prices."

Although many of the differences in the consensus agreement appear trivial-such as number of days to process an application-the large number of areas of disagreement suggests that a quick resolution of these issues is overly optimistic. Some participants lamented that far too many stakeholders, often without expertise in DG or power systems, doomed the process from the start. Now FERC has the unenviable task of weighing the divergent views rendered by the joint coalition into a standard without alienating ANOPR participants and DG stakeholders. As Commissioner Pat Wood stated at a Department of Energy event in January, "We got a different result and level of consensus than we had hoped for. Our staff is working on the rule, but it is not easy. This falls right in the middle of jurisdictional issues."

Are State Interconnection Standards the Answer?

FERC's dilemma underscores the difficulty in having so many parties with divergent interests develop prescriptive interconnection standards on a national basis. Indeed, NARUC's Model DG Interconnection Procedures and Agreement issued in July 2002 offers a broad template of terms and procedures- "fill in the blank" is an apt description of NARUC's model. This contrasts markedly with the highly detailed and prescriptive standard molded by the joint coalition in the FERC process. Not surprisingly, the NARUC model implies that states are in the best position to address interconnection standards and could easily tailor the NARUC model based on local needs and preferences. NARUC continues to urge FERC not to disregard the NARUC model, stating in its comments to the ANOPR, "Any NOPR that FERC develops based on this ANOPR process should allow states to implement the NARUC model." NARUC further states, "The NARUC Model was compiled from the 'best practices' of States that have previously held fully open, inclusive and fair proceedings to address interconnections of distributed energy resources."

California, Texas, and New York have issued interconnection standards, and several other states plan to do so as well. In California, Southern California Edison has processed approximately 1,400 interconnection applications. However, the presence of interconnection standards alone may not be the catalyst to prompt widespread DG development. In Texas, only about 40 DG units have been installed over two years using the new Texas interconnection requirements. Moreover, the absence of before-and-after data makes such a comparison difficult. Industry experts suggest electric rates and DG costs are more compelling reasons for less-than-robust levels of DG penetration in some states than the absence of interconnection standards.

Richard Brent, director of government affairs at Solar Turbines, has been actively involved in DG regulatory issues for almost a decade. He stated, "Technical interconnection standards are important so as to capture the latent value of DG, but so are the commercial and economic elements that are embodied in rate design. Fair, reasonable, and nondiscriminatory rate design that recognizes the value of DG is the next great challenge, and arguably just as important."

Other states are beginning to build up steam in developing interconnection standards. The Massachusetts Technology Collaborative (MTC), the state's development agency for renewable energy and administrator of the Renewable Energy Trust, is supporting the Massachusetts DG Interconnection Collaborative. The recent successful collaborative efforts in Massachusetts to develop an interconnection standard illustrate how states may be in a better position to develop interconnection standards. Massachusetts achieved consensus in just four months, versus a year or longer in other states and by FERC. Arguably, the Massachusetts standard is as comprehensive as the ANOPR and agreements issued thus far. Ironically, the MTC DG collaborative includes many of the same stakeholders (albeit far fewer participants) that participated in the FERC process.

Though states can quickly develop standards geared to state policy goals and utility-specific factors, DG providers recoil at the idea of having to master a haphazard array of standards promulgated in different states. In fact, differences in screening criteria, DG rating thresholds, and dispute resolution procedures found in states with formal standards, offer merit to the idea of a national standard. Partly offsetting this concern is the flexibility that states have to later modify their own standards to respond to DG concerns.

What National Standards Are in Place?

The Massachusetts Technology Collaborative benefited from the efforts already undertaken in other states as well as national groups responsible for creating industry standards. The Institute of Electric and Electronic Engineers (IEEE) and the Underwriters Laboratories (UL) recently developed standards for DG interconnections. The UL standard (UL 1741) offers certified design standards for inverter-based DGs under 10 kW, common ratings for commercially available PV systems. The IEEE standard (P1547) establishes minimum technical and performance standards for interconnecting DG up to 10 MW.

Developing these standards takes time and money. The IEEE standard P1547 crosses a major threshold, since it took just three years for approval versus five to10 years for many IEEE standards. Undoubtedly this accelerated timeline would not have been possible without the support from the Department of Energy's Distributed Energy and Electricity Reliability (DEER) Program, which in addition to IEEE 1547, also helped NARUC develop its interconnection model and the Public Utility Commission of Texas write its Interconnection Guidebook. Patricia Hoffman, the DEER acting program manager, says, "We recognized early on that if these technologies, which are so critical to the future of our energy infrastructure, were going to survive we needed to have national interconnection standards."

IEEE 1547 has not yet addressed the thorny problem of integrating DG into low voltage (secondary) grid network systems used in downtown districts in most major cities. Utilities have been exceedingly cautious on DG network integration so as not to jeopardize reliability or power quality on these highly complex grids. IEEE is now developing application guidelines that eventually may address network systems (the IEEE standard includes less complex spot networks). However, compliance is voluntary under either standard and IEEE 1547's broad language requires interpretation if it is to be used as a comprehensive interconnection standard. IEEE 1547 also does not include process or commercial issues such as applications, timelines and agreements. Scott A. Castelaz, vice president for corporate development and external affairs at ENCORP (a leading provider of DG solutions), says, "The recently passed IEEE standards are an important step in the right direction. However, the adoption of these standards should be viewed as a journey and not so much as a destination. In many important aspects the non-technical factors are in much need of improvement relating to tariffs, contracts, and the general process to obtain a safe, reliable interconnection. This will not only improve the existing market base for interconnection but will also spur new demand for the DG market itself."

Is a Hybrid Arrangement the Answer?

Questions arise on two fronts regarding interconnection standards for small DG (less than 20 MW): Should states be solely responsible for interconnection standards for small DG? And, are FERC's proposed standards relevant for the majority of small DG interconnecting at distribution voltages?

DG installations that include third-party export sales presumably would fall under FERC's jurisdiction, regardless of voltage. Notably, the majority of applications for interconnection in California are small without exports to the grid, thereby avoiding the regulatory burden associated with third-party sales. As demonstrated in Figure 1, which is based on a hypothetical population of 1,000 applications, all but a handful of DG applications for interconnection will be for smaller devices that fall under streamlined review procedures for non-export, low-impact interconnection.

The non-export exception is streamlined in states that adopted net metering rules.3 For example, Massachusetts allows retail customers to export up to 60 kW on a simplified basis. However, states may not readily cede jurisdiction on net metering to FERC, which further narrows the population of DG that might fall under FERC's jurisdiction.

Order 888 has made the question of "what constitutes a transmission interconnection" a bit fuzzier. FERC's seven-step test for classifying distribution has decreased, jurisdictionally (if not functionally), the number of lines utilities now classify as transmission. It's not unusual for distribution assets to include lines up to or exceeding 69,000 volts.4 Few facilities that are rated at 20 MW or below the ANOPR's upper limit will ever be connected at higher voltages. Absent third-party exports, FERC's consensus agreement may not be applicable for the vast majority of small DG that retail customers are likely to install.

In the ANOPR, FERC makes no effort to address the jurisdictional question, perhaps adding fuel to fire on the question of state versus federal rights. One might expect the DG coalition to prefer a federal standard. DG supporters also like the idea of having a consistent set of standards versus the range of standards that invariably will appear at the state level. States and utilities might suggest that lessons learned on DG integration could cause state standards to become more consistent over time.

A FERC standard fills the gap for states that do not plan to develop their own standard, because of DG activity (incentives to build DG dwindles for states with low electric rates) or reliance on a federal standard. Its actions also may act as a catalyst for states that have not yet developed interconnection standards. The NRECA too has developed an interconnection standard that could be used as a proxy in states without interconnection standards.

Unless FERC and states reach an understanding, or courts rule otherwise, DG developers and utilities may have to contend with competing standards with applicability that is less than certain for the range of interconnection applications that inevitably will arise. These concerns, however, may pale to the battles likely to arise as states wrestle with the question of back-up rates, credits for DG system benefits, and a host of institutional, legal, and regulatory issues that surely will accompany the maturity of the DG market.

  1. The DG suppliers and participants cited in this article include photovoltaic, wind, fuel cell, induction and synchronous generators, combined heat and power, and micro-turbine systems.
  2. Joint Comments of the Small Generator Coalition on Small Generator Interconnection ANOPR Consensus Documents and Annotations, .
  3. Utilities buy back power at the same retail rate they sell power to customers using a single meter that records net kilowatt-hour flows.
  4. 35,000-volt to 69,000-volt lines often are classified as subtransmission, which can be assigned to distribution or transmission.

Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.