RULES AND REGULATIONS
PENNSYLVANIA PUBLIC UTILITY COMMISSION
[52 PA. CODE CH. 75]
[36 Pa.B. 7574]
[Saturday, December 16, 2006][L-00050275]
Alternative Energy Portfolio Standards The Pennsylvania Public Utility Commission (Commission) on June 22, 2006, adopted a final rulemaking order which promotes onsite generation by customer-generators using renewable resources and eliminates barriers which may have previously existed regarding net metering.
Executive Summary
Pursuant to 73 P. S. § 1648.5, the Public Utility Commission is required to develop regulations governing interconnection standards within the Commonwealth through a stakeholder process. This rulemaking is the final regulation resulting from the stakeholder process. The regulation governs the process by which a customer-generator, as defined by the Alternative Energy Portfolio Standards Act (73 P. S. §§ 1648.1--1648.8), may interconnect onsite generation equipment to an electric utility's distribution lines. The regulations set forth specific levels of review and review criteria depending on the rated generation capacity of the generation equipment. The regulations also provide for a dispute resolution process to manage disputes which may arise during the interconnection process.
Regulatory Review
Under section 5(a) of the Regulatory Review Act (71 P. S. § 745.5(a)), on October 15, 2004, the Commission submitted a copy of the notice of proposed rulemaking, published at 36 Pa.B. 942 (February 25, 2006) to the Independent Regulatory Review Commission (IRRC) and the Chairpersons of the House Committee on Consumer Affairs and the Senate Committee on Consumer Protection and Professional Licensure for review and comment.
Under section 5(c) of the Regulatory Review Act, IRRC and the Committees were provided with copies of the comments received during the public comment period, as well as other documents when requested. In preparing the final-form rulemaking, the Department has considered all comments from IRRC, the House and Senate Committees and the public.
Under section 5.1(j.2) of the Regulatory Review Act (71 P. S. § 745.5a(j.2)), on November 1, 2006, the final-form rulemaking was deemed approved by the House and Senate Committees. Under section 5.1(e) of the Regulatory Review Act, IRRC met on November 2, 2006, and approved the final-form rulemaking.
Public Meeting Held
August 17, 2006Commissioners Present: Wendell F. Holland, Chairperson; James H. Cawley, Vice Chairperson; Bill Shane; Kim Pizzingrilli; Terrance J. Fitzpatrick
Final Rulemaking Re Interconnection Standards for Customer-generators pursuant to Section 5 of the Alternative Energy Portfolio Standards Act, 73 P. S. § 1648.5; L-00050175
Implementation of the Alternative Energy Portfolio Standards Act of 2004: Interconnection Standards; M-00051865
Final Rulemaking Order By the Commission:
The Alternative Energy Portfolio Standards Act of 2004 (the Act), includes directives that the Commission develop regulations setting forth interconnection standards for customer-generators. In accordance with Section 5 of the Act, 73 P. S. § 1648.5, this constitutes the Commission's Final Rulemaking which establishes regulations governing interconnection for customer-generators as set forth in the Act.
BACKGROUND Section 5 of the Act provides as follows:
The commission shall develop technical and net metering interconnection rules for customer-generators intending to operate renewable onsite generators in parallel with the electric utility grid, consistent with rules developed in other states within the service region of the regional transmission organization that manages the transmission system in any part of this Commonwealth. The commission shall convene a stakeholder process to develop Statewide technical and net metering rules for customer-generators. The commission shall develop these rules within nine months of the effective date of this act.73 P. S. § 1648.5.
On March 3, 2005, the Commission convened an Alternative Energy Portfolio Standards Working Group (AEPS WG). The AEPS WG was established in order to provide a forum for considering the technical standards, business rules and regulatory framework necessary for the Act's implementation. The Net Metering sub-group was formed out of the AEPS WG and was specifically tasked with developing proposed regulations governing net metering and interconnection standards.
The Net Metering sub-group has met on several occasions since March 3 to discuss and develop a set of proposed regulations in two parts. First, the Net Metering sub-group focused on net metering. Second, the Net Metering sub-group focused on interconnection standards, which is the subject of this rulemaking proceeding.
Participants in the Net Metering sub-group have included representatives from Commission Staff, the Department of Environmental Protection (DEP), the Energy Association of Pennsylvania (EAPA) and several of its member companies, the Pennsylvania Farm Bureau, the Office of Consumer Advocate (OCA), the Office of Small Business Advocate (OSBA), Citizens for Pennsylvania's Future (Penn Future), the Small Generator Coalition (SGC) with the Solar Energy Industries Association and several similar entities.
At the initial meeting, participants were requested to discuss various issues which any rulemaking involving interconnection standards would need to address. As the Net Metering sub-group moved forward with the interconnection standards stakeholder process, the Commission determined that the Mid-Atlantic Distributed Resource Initiative (MADRI) was also moving forward with a stakeholder process to develop model interconnection standards for small generators in the PJM Interconnection L.L.C. (PJM) footprint. MADRI is comprised of the public utility commissions of Pennsylvania, Delaware, the District of Columbia, New Jersey and Maryland, along with the United States' Department of Energy and PJM. Similar to the Pennsylvania process, stakeholders from the utility industry, consumer organizations, distributed generation interest groups and vendors along with the MADRI members were invited to participate in developing model interconnection standards.
On May 15, 2005, the Commission notified the Net Metering sub-group that it would hold the Pennsylvania interconnection standards process in abeyance, pending the development of a uniform model by the MADRI stakeholder process. Participants in Pennsylvania's Net Metering sub-group were strongly encouraged to participate in the MADRI interconnection process. Participants were advised that the Commission Staff would use the MADRI model as the basis for the Staff proposal which would lead to an Order proposing the interconnection standards rulemaking.
Following several meetings held in June, July and August of 2005, the MADRI stakeholder group advised Commission Staff that a draft model addressing interconnection standards was in sufficient form to merit consideration in the Pennsylvania process. Commission Staff received the MADRI model on or about August 19, 2005. On August 29, 2005, Staff issued its initial proposal (initial Staff proposal) to the Pennsylvania Net Metering sub-group and requested comments on or before September 19, 2005. The initial Staff proposal was based upon the MADRI model interconnection standards. In the notice for comments, Staff identified those areas where the initial Staff proposal modified the MADRI model and invited comments specifically directed to those modifications as well as any other areas participants wished to address.
Following the receipt of comments to the initial Staff proposal, the Commission issued its Notice of Proposed Rulemaking on November 16, 2005 (November NOPR). The November NOPR was developed based upon the MADRI model interconnection standards as of August 19, 2005, the initial Staff proposal which modified that model, and comments submitted through the Net Metering sub-group process. The foregoing is consistent with the Act's mandate that these regulations be developed through a stakeholder process.
Similar to the initial Staff proposal, the November NOPR sought comments on specific issues and invited comments on any other issues which interested persons wished to raise. The November NOPR was published at 36 Pa.B. 942 (February 25, 2006). Comments were due to be filed on or before April 26, 2006.
Comments to the November NOPR were filed by: the Independent Regulatory Review Commission (IRRC); the DEP; the Department of Agriculture; the Pennsylvania Farm Bureau; the Pennsylvania Environmental Council; the OCA; the OSBA; the EAPA; PECO Energy Company (PECO); Citizens' Electric Company of Lewisburg, PA, and Wellsboro Electric Company (collectively, ''Citizens''); the Industrial Energy Consumers of Pennsylvania, Met-Ed Industrial Users Group, the Penelec Industrial Customer Alliance, the Philadelphia Area Industrial Users Group, the PP&L Industrial Customer Alliance and the West Penn Power Industrial Interveners (collectively, ''IECPA''); Penn Future; Native Energy, LLC (Native Energy); and, Pennsylvania Small Generator Coalition (SGC).
DISCUSSION The Commission has reviewed each of the comments filed in this proceeding. We will address those comments as we go through the regulations, seriatim.
A. § 75.21. Scope
This section endeavors to set forth the scope of the interconnection standards adopted under the Act. In the initial Staff proposal, the Scope of the regulations was described as applying to residential and small commercial customers. In the Net Metering rulemaking, several participants commented that use of the phrase ''residential and small commercial customers'' had the potential of excluding some agricultural customers who otherwise would be considered ''customer-generators'' under the Act.
We have modified the initial Staff proposal to be consistent with the scope provided in the Net Metering rulemaking. As we stated there, paraphrasing the Act is the best method of setting forth the scope of the regulations. The Act expressly provides that the net metering and interconnection regulations are to be developed for ''customer-generators.'' That term is defined in the Act and has specific capacity limits in place. Accordingly, the scope of the regulations provides that they apply to EDCs which have customer-generators who intend to pursue net metering and interconnection opportunities in accordance with the Act.
IECPA commented that it supported the revised scope language. However, IECPA wanted to clarify that nothing in this rulemaking would serve to modify or invalidate agreements governing interconnections for systems with nameplate capacity greater than 2 MW. We agree with IECPA that this rulemaking is not intended to alter transactions involving generation systems with nameplate capacities of greater than 2 MW.
B. § 75.22. Definitions
In its comments, the IRRC suggested that the Commission define five technical terms that are used in making pivotal determinations during the screening process for interconnection requests. The first term, ''Radial Distribution Circuit,'' appears four times in the proposed regulations in the following sections: § 75.34(iv), Review Procedures; § 75.37(b)(1), Level 1 Interconnection Review; § 75.38(b)(1), Level 2 Interconnection Review and § 75.40(d)(4), Level 4 Interconnection Review. In the proposed regulation a radial distribution circuit is presented as the segment of the EDC's system to which a small generation facility will interconnect. This term is defined in IEEE Standard 1547 (2003) as a system in which independent feeders branch out radially from a common source of supply. From the standpoint of a utility system, the area described is between the generating source or intervening substations and the customer's entrance equipment. A radial distribution system is the most common type of connection between a utility and load in which power flows in one direction, from the utility to the customer. (Presentation by Thomas Basso, IEEE Secretary, Standards Coordinating Committee 21, June 9, 2004).
We shall include this term and the following definition in the final regulation.
Radial Distribution Circuit--a system in which independent feeders branch out radially from a common source of supply. From the standpoint of a utility system, the area described is between the generating source or intervening substations and the customer's entrance equipment. A radial distribution system is the most common type of connection between a utility and load in which power flows in one direction, from the utility to the load.The second term to be defined is ''Draw-out Type Circuit Breaker,'' which appears at Section 75.36 of the proposed regulation, regarding additional general requirements. The National Electrical Safety Code (NESC) defines circuit breaker as a switching device capable of making, carrying and breaking currents under normal circuit conditions and also, making and carrying for a specified time and breaking currents under specified abnormal circuit conditions, such as those of a short circuit. A draw-out circuit breaker has two parts, the base, which is bolted and wired to the frame and the actual breaker, which slides into and electrically mates with the base. Thus, a draw-out circuit breaker can be physically removed from its enclosure thereby creating a visible break in the circuit.
Based upon the NCSC language, we shall include the following definition in the final rulemaking.
Draw-out Type Circuit Breaker--a switching device capable of making, carrying and breaking currents under normal circuit conditions and also, making and carrying for a specified time and breaking currents under specified abnormal circuit conditions, such as those of a short circuit. A draw-out circuit breaker has two parts, the base, which is bolted and wired to the frame and the actual breaker, which slides into and electrically mates with the base. A draw-out circuit breaker can be physically removed from its enclosure thereby creating a visible break in the circuit.The third technical term which needs to be defined is ''Secondary,'' which is used at Sections 75.37(b)(3) and 75.38(b)(9) regarding Level 1 and Level 2 Interconnection Reviews. The specific language within these two sections of the regulation is as follows:
When the proposed small generator facility is to be interconnected on a single-phase shared secondary line, the aggregate generation capacity on the shared secondary line . . .The term ''Secondary,'' refers to a service line subsequent to the utility's primary distribution line, and is also referred to as the customer's service line. For clarity we shall incorporate the definition of ''Secondary,'' describing its intended meaning within the final rulemaking as follows.
Secondary line--a service line subsequent to the utility's primary distribution line, and is also referred to as the customer's service line.The fourth technical term cited by the IRRC is ''Center Tap Neutral,'' which is used at Sections 75.37(b)(4) and 75.38(b)(10) regarding Level 1 and Level 2 Interconnection Reviews. The following is an explanation of how and why a center tap neutral approach is applied when installing electrical service.
A center tapped transformer has a tap in the middle of the secondary winding, usually used as a grounded neutral connection. This provides an option of using the full available voltage output or just half of it according to need. This type of transformer is used to bring the distribution system voltage down from three-phase to a safer level to be used for household purposes.
We shall include the following definition in the regulation regarding a center tap neutral transformer.
Center tapped neutral transformer--a transformer with a tap in the middle of the secondary winding, usually used as a grounded neutral connection, intended to provide an option for the secondary side to use the full available voltage output or just half of it according to need.The last term the IRRC requested the Commission to provide a definition for is ''Anti-Islanding Function,'' which is used in the regulation at Sections 75.38(b)(8) and 75.40(e)(4), regarding Level 2 and Level 4 Interconnection Reviews. As described in IEEE 1547, islanding is the situation during which the customer's generator facility energizes a portion of the spot or area network (distribution system) through the point of common coupling for more than five seconds. To prevent this event, the customer's interconnection system must detect the island and cease to energize the spot or area network within two seconds of the formation of an island. Islanding may also be described as occurring when a distributed generation source continues to provide electricity to a portion of the utility grid after the utility experiences a disruption in service. Since the utility no longer controls this part of the distribution system, islanding can pose problems for utility personnel safety, power quality, equipment damage and restoration of service. (National Renewable Energy Laboratory, Study and Development of Anti-Islanding Control for Grid-Connected Inverters, May 2004). Accordingly, the anti-islanding capability acts to automatically isolate the generating unit from the distribution circuit within a specified period of time when a potential islanding situation develops.
Anti-islanding capability is built into inverter based systems certified to IEEE 1574 standards and tested in accordance with UL 1741. Acknowledging the IRRC's request, we shall include the following definition of anti-islanding in our final regulation.
Anti-islanding--the protective function which prevents electrical generating equipment from exporting electrical energy when connected to a de-energized electrical system.The IRRC also noted that several definitions contain substantive provisions which cannot be enforced unless those provisions are placed in the body of the regulation. The IRRC pointed to the definitions for: ''Certificate of completion,'' ''Interconnection system impact study'' and ''Queue position.'' We will modify those definitions and ensure that substantive provisions are placed in the appropriate places in the regulations. In addition, the IRRC suggested adding a definition of ''Equipment package'' to this regulation. We have done so.
The IRRC also notes that at certain places in the Definitions section, we reference ''the most current official published version'' of technical references (IEEE standard 1547.1 and UL standard 1741) while in other places we reference the standards ''as amended and supplemented.'' The IRRC suggests that we revise the definitions to provide for a consistent phrase regarding the updated versions of the technical standards. The EAPA also comments that the regulations should recognize that the technical standards are ''living'' documents that will be amended and supplemented over time. We will make the modification recommended by the IRRC which also addresses the EAPA's concerns.
Proposed ''Affected System'' Definition
The proposed regulations do not incorporate a definition of ''Affected System.'' The term refers to an Electric Distribution System, other than the Electric Distribution System owned or operated by the EDC to which the customer-generator is interconnected, that may be affected by the proposed interconnection.
Positions of the Parties
The EAPA argues that there will be situations where the installation of a customer-generator may have an impact on a neighboring EDC, particularly for Level 2 and 3 installations. Of particular concern to the EAPA are interconnections with other utility systems at the distribution level such as with Rural Electric Co-ops and Municipal Utilities. The EAPA, therefore, supports inclusion of a mechanism to deal with such situations both for purposes of system study and accounting/cost allocation. The IRRC agrees that any system which may be affected by the generator, including neighboring EDCs, should be party to the consideration of the impact of that generator on their systems.
The OCA and SGC, however, do not believe that the definition proposed by the EAPA is necessary. The OCA is not aware of substantial interconnections below the sub-transmission level where impacts identified by the EAPA can be reasonably expected to occur. In addition, the OCA notes that the Commission's proposed regulations govern small generators of less than 2 MW. Larger units will be required to interconnect directly under PJM small generation interconnection rules. As a result, for those larger systems, regional impacts will be analyzed and generators will be required to comply with PJM rules.
Likewise, SGC believes that a definition for this term is functionally irrelevant under state jurisdiction in the presence of a functional Regional Transmission Organization (RTO). SGC notes that in cases where a generator interconnection may affect another utility's system, it can only do so through the transmission grid. That type of request would be processed under PJM Interconnection rules for proper impact analysis on the transmission grid.
Disposition
The OCA and SGC have made valid arguments against the inclusion of a definition of ''Affected System.'' The Commission therefore declines to incorporate that definition since it is highly unlikely that the impacts cited by EAPA are likely to occur with systems contemplated by this regulation. Larger units over 2 MW would be required to interconnect directly under PJM small generation interconnection rules. If an interconnection governed by this regulation does present a problem of this nature, that can be reviewed by the Commission on a case-by-case basis.
Designated Address
The EAPA proposes a specific definition for ''designated address'' in addition to providing that EDCs establish a designated address for receipt of interconnection applications and materials. The IRRC also comments that a designated address should be used to provide certainty for the delivery of interconnection materials to EDCs. We will decline to adopt a definition for designated address, but we will provide the requirement that each EDC provide information regarding its designated address in interconnection materials, its tariff and on its website.
Proposed ''Electric nameplate capacity'' Definition
The proposed regulation defines ''Electric nameplate capacity'' as the ''net maximum or net instantaneous peak electric output capability measured in volt-amps of a small generator facility as designated by the manufacturer.''
Positions of the Parties
The EAPA comments that use of the word ''net'' is inappropriate in the definition. According to the EAPA, if ''net'' is contained in the definition, it is theoretically possible for a 100 MW generator with 99 MW of load to be reviewed under the Level 2 screening criteria. The EAPA comments that the effect of the generator on the EDC's system needs to be based on the rating of the generator and not on the net output capability. The EAPA suggests deletion of the word ''net'' from the definition. The IRRC comments that the Commission should explain why net output is the correct measure.
Disposition
We will decline to adopt the EAPA suggestion. In doing so, we note that the EAPA's ''theoretical'' example is not particularly useful in the analysis of this issue. Simply put, the screens and studies provided for in this regulation are designed to ensure that the net output capability of any particular generator facility will not adversely affect the distribution circuit to which interconnection is sought. Thus, the generating output which is of concern is that output net only of the generation plant use. It is that net output capability which will impact the distribution circuit. Systems which carry output potentials of sufficient size to warrant the EAPA's concern are necessarily processed under higher level screens with greater scrutiny. This, in turn, will provide the certainty that the EAPA suggests is at the root of its concern. Conversely, adoption of the EAPA's suggestion may force lower rated systems into more complex screens without any concomitant benefit to circuit reliability.
Proposed ''Minor Equipment Modification'' Definition
The proposed definition of Minor Equipment Modification provides that: ''Changes to the proposed small generator facility that do not have a material impact on safety or reliability of the electric distribution system.'' The purpose of the definition is to clarify that in those circumstances when a minor equipment modification is made, a new interconnection application will not be required. (See, e.g., § 75.23(f)(6)).
Position of the Parties
The EAPA suggests adding the phrase ''power quality'' to the above definition (and to other portions of the regulation). The purpose of the EAPA suggestion is to ensure that ''the maintenance of power quality be incorporated into several locations throughout the rulemaking.''
Disposition
We will decline to adopt the EAPA's suggestion. The issue of power quality is managed by the regulation's use of IEEE 1547 and UL Standard 1741 requirements as well as the more complex and advanced reviews required for generator facilities which are not readily certified under the less complex screens. Adoption of the EAPA's suggestion here (and at other locations in the regulation) simply adds additional, unnecessary complexity.
C. General Issues
Initially, we note that the EAPA provided an extensive red-lined version of the proposed regulation. Most of the suggested modifications did not have accompanying comments or other justification for their implementation. Where the suggestions result in greater clarity without modifying substance or a participant's obligations, we have generally adopted them. In many cases, we have declined to modify the regulation without further comment. Where comments have been provided by the EAPA, we have addressed them. However, we emphasize that all of EAPA's suggestions have been carefully considered.
A brief description of the substantive provisions of the regulation is in order at this point. The regulation provides interconnection procedures for small generators with a nameplate capacity of up to two megawatts who wish to interconnect to an EDC's electric distribution system. The procedures divide the process into four distinct review screens, Levels 1, 2, 3, and 4, depending on the size and nature of the interconnection equipment involved.
Level 1 projects are those which: a) have a nameplate capacity of 10 kW or less; and, b) are inverter based using customer interconnection equipment that is certified.
Level 2 projects are those which: a) have a nameplate capacity rating which is 2 MW or less; b) are inverter based; c) have received certification of the customer's interconnection equipment or review of the generator facility under Level 1 was not approved.
Level 3 projects are those which: a) have a nameplate capacity of 2 MW or less; b) do not qualify for either Level 1 or Level 2 review procedures or have been reviewed under Level 1 or Level 2 process but have not been approved for interconnection.
Interconnection customers who do not qualify for Level 1 or Level 2 review and do not export power to the grid may request to be evaluated under Level 4, which is an expedited review process.
The IRRC's General Comments
Screening criteria vs. alternative energy source availability
The IRRC presented several general comments which are best addressed at this time. First, the IRRC expressed concern that some of the screening criteria could serve as barriers to the development of alternative energy. Accordingly, the IRRC suggested that the Commission explain how a necessary balance is stricken between the adopted screening criteria and allowing alternative energy sources to be reasonably available in the marketplace.
This regulation concerns itself with providing technical standards and processes by and through which customer-generators may interconnect to an EDC's distribution system. The alternative energy sources enabled by these interconnections will be a very small part of the over-all alternative energy development envisioned by the Act. In addition, it is anticipated that the technical expertise of the customer-generators covered by the regulation will vary widely. Accordingly, the screening criteria have been developed to ensure that the interconnection process is relatively quick and inexpensive, while still providing for reliability of the electric distribution system. To the extent that criteria serve to screen out a particular generator facility, the screens provide the ability for customer-generators to make necessary modifications and eventually obtain interconnection.
There should be only two instances when a generator facility fails the screens regardless of efforts at modification. The first is when a particular distribution circuit has reached its maximum capacity and is physically incapable of receiving any additional generation. The second instance is when the generator facility simply cannot match the screens' technical requirements regardless of modification. In either case, reliability demands that the interconnection fail. It is anticipated that the number of these types of failures will be few and will not significantly decrease the amount of alternative energy which would normally be produced by the types of interconnected generation contemplated by this regulation.
Cost Recovery
The IRRC suggests that the Commission address cost recovery in the context of certain regulations which provide for EDC actions. We will address the issue of cost responsibility in the context of those specific regulations. However, cost recovery by an EDC is an issue that is not readily resolved in the context of this regulation. The Act provides for the recovery of certain specific and indirect costs relating to implementation of the Act at Section 3, 73 P. S. § 1648.3. Whether costs incurred in implementing this regulation are covered under that section, or whether they are allowable as an EDC expense for recovery through rates are issues to be decided in the context of the Commission's over-all implementation of the Act or, possibly, in an individual EDC's applicable rate case.
Insurance and Indemnification
In our November NOPR, we did not mandate indemnification or liability insurance requirements having determined that the appropriate vehicle for indemnification, and insurance requirements, if any, would be the interconnection agreement form. We invited comments on the issue of requiring customer-generators to provide general liability insurance as a prerequisite for interconnection and asked the Parties to discuss how such a requirement would apply to each customer-generator class.
Positions of the Parties
The IRRC queried how interconnections with alternative energy suppliers could be done without insurance protection but went on to state that because the Commission did not provide language regarding insurance requirements, any language added to the regulation would have to be done in another rulemaking. IRRC pointed to the §§ 75.37(a) and 75.38(a) of the proposed regulation which provide that an ''EDC may not impose additional requirements . . . not specifically authorized under this subchapter.''
Citizens state that customer-generators should be required to provide general liability insurance because the malfunction of a parallel generating unit of any size might negatively affect the EDC's distribution system and service to other customers. The EAPA supports an insurance requirement with policy limits commensurate with the industry norm for equipment of the size being utilized.
DEP, SGC, and the OCA support following the MADRI model which does not require customer-generators to provide general liability insurance; but, does provide a recommendation in the interconnection agreement that the customer-generator obtain liability insurance to cover any potential risk. Native Energy, the Department of Agriculture, Pa Farm Bureau, and SGC state that many rural landowners and farmers do not have the capital necessary to invest in additional forms of insurance and that such a requirement would act as an obstacle to their investment in clean energy projects. Various Parties opposing an insurance regulation point to our neighboring states, New Jersey and New York, which do not permit the EDCs to require insurance of the customer-generators.
Disposition
We have received no comments that have provided even anecdotal information regarding instances where the lack of an insurance requirement for a customer-generator has negatively affected the EDC's system or other customers. We anticipate that most customer-generators will voluntarily obtain some form of liability protection. Additionally, we note that our net metering regulations do not require insurance. We will follow the MADRI model on this issue. We expect that the standard interconnection agreement will not require customer-generators to provide proof of general liability insurance; however, it will recommend that every customer-generator protect itself with insurance due to the risk of incurring damages. We believe that this approach will permit the customer-generator to determine the appropriate amount and type of insurance that best suits their facility without creating further barriers to those wishing to interconnect. If experience with implementation suggests otherwise, we will revisit this issue in another rulemaking.
Section 1648.5 of the Act; Consistency with rules in other states
IRRC noted that the Act requires that the Commission adopt rules which are consistent with rules developed in other states located in Pennsylvania's region. The IRRC comments that several interested parties have commented that the regulation differs from certain regulations in New Jersey in several respects, with the commenting party usually favoring the New Jersey rules. The IRRC requests that the Commission explain how the final form regulation is consistent with Section 1648.5 of the Act.
The requirement of the Act is that the Commission adopt regulations that are ''consistent'' with rules developed in neighboring states. The Act does not require that our processes be identical. In most instances, the regulation is very close if not identical to the processes established in New Jersey. Some examples include the lack of an insurance requirement, a multi-level screening process based upon the complexity, output and certification level of the generation facility and the effort to standardize the interconnection process across the Commonwealth. Differences include specific timelines for the individual screens, the requirement for a lock-box device to permit access to generator facilities and the limitation that non-inverter based equipment be processed under a Level 3 screen rather than a Level 2 screen.
From the foregoing, the Commission believes that the final-form regulation is ''consistent'' with the regulations in neighboring states, albeit not identical. It is important to note that the final-form regulation was developed, in part, using the MADRI process which included input from almost all of the neighboring state public utility commissions. In addition, not all of the neighboring states have finalized their interconnection standards while some (such as New Jersey and New York) have finalized standards which are not identical. Accordingly, we interpret the Act's requirement to adopt an approach which serves Pennsylvania while being consistent, but not necessarily identical, with neighboring states. To that end, we have adopted a multi-level screening process with specific timelines and specific technical requirements. That type of system is, in general, consistent with New Jersey and other surrounding states that have standards in place.
Review Timelines
Positions of Parties
IRRC noted that several comments argued that the timelines for review provided in the various screens were too long. As noted, Penn Future, the Pennsylvania Environmental Council, and SGC think the review process is too long. Those Parties would like to see the review periods mirror those used in the New Jersey interconnection standards. DEP proposed that the Level 1 review period should be shorter. SGC suggested that the Level 1 review should not exceed 20 business days, Level 2- 25 business days, Level 3-180 business days, and Level 4-30 business days. Citizens Electric and Wellsboro Electric noted the potential review burden on a small utility. They noted their limited financial and personnel resources available to conduct review of customer-generator applications, and proposed that the regulations provide for flexibility to accommodate small EDCs. The EAPA supported most of the proposed review timelines for Level 1 through Level 4.
Citizens, DEP, PECO and SGC offered comments about how the timelines should be handled during an EDC's emergency situation. Citizens propose that the commission adopt regulations concerning an extension of the Level 1 through Level 4 timelines in such situations. All the other commentators suggest that the Commission should consider extensions of the timelines on a case-by-case basis.
Disposition
We have analyzed the proper balance between an expedited review process and providing the EDC with adequate time to properly review a customer-generator's interconnection application without compromising safety, reliability, and creating additional personnel costs for the EDC. As part of our drafting of the timelines, we have participated in the MADRI Interconnection Working Group and reviewed interconnection guidelines of other states including New Jersey.
Based on our analysis and the comments that we have received, we believe the timelines in the regulations offer the proper balance between an expedited review process for the customer-generator and adequate time for the EDC to review the potential project for safety and reliability. A customer-generator that is proposing a project with a 15 to 20 year life will not be deterred with a review time slightly longer than the review time in another state. The payback to the customer over the fifteen to twenty years will be about the same regardless of whether the project takes a slightly longer review period to approve. A shorter review process could require the EDC hiring more staff to make certain the shorter review period is met, which will result in additional personnel costs to the ratepayer.
We hasten to add that the timelines set forth in the regulation are maximum timelines. Depending on the number of pending interconnections, the actual review time could be much less. We also expect that as the EDCs and equipment vendors become more experienced with the review processes, the actual time for review will be reduced. Therefore, we will maintain the review timelines from the proposed regulations.
We acknowledge that during an emergency situation an EDC may need to re-direct personnel to assist in addressing the emergency situation. However, the Commission does not believe that a regulation is required to address this issue. It is possible that an EDC could work informally with interconnection applicants to obtain extensions in emergency situations. Failing that, an affected EDC could seek a waiver of specific timelines from the Commission.
Inverter/noninverter distinctions for interconnection
IRRC commented that several sections of the regulation distinguish between inverter and non-inverter based equipment. IRRC noted that the Act contains no mention of whether an alternative energy source requires inverter based equipment or not. IRRC requested that we explain why there should be a distinction between inverter and non-inverter based equipment in the regulation.
The regulation governs the physical interconnection of generation facilities to distribution circuits. Different types of generation facilities (i.e., inverter and non-inverter based equipment) have different engineering aspects and potentially different impacts on the circuits involved. Generally speaking, inverter based equipment that has been certified requires a much less complex review process than a rotary based system that has not been certified. Accordingly, it is appropriate for the review screens to provide different approaches to the different types of equipment. Because this issue deals with physical interconnection, it is the type of equipment that is important, not necessarily the type of alternative energy source used.
Advanced Notice of Final Rulemaking
IRRC noted that several issues remain in contention at this stage of the rulemaking process. IRRC suggested that the Commission continue the stakeholder process and publish an Advanced Notice of Final Rulemaking in an effort to resolve any remaining controversy.
As we discussed above, this process began in the early spring of 2005. The issues have been discussed several times in the Pennsylvania stakeholder process and at length during the summer of 2005 during the MADRI process. Participants were given the opportunity to comment on a staff initiated straw man proposal and then given an additional opportunity to comment on the November NOPR. At this point in time, the Commission understands the positions of those commenting on the issues and has received sufficient information to enable us to balance the relative interests involved and achieve the best results for Pennsylvania, consistent with the requirements of the Act. Accordingly, we believe that the additional time spent in further review will only delay implementation of the regulation without providing consensus on any of the issues which remain in controversy.
D. § 75.33. Fees and Forms
Positions of the Parties
The IRRC commented that fees and forms are not specified in this section other than the notation that the Commission will develop the fees. IRRC requested that the Commission provide detailed information on the fees and forms required in this regulation. DEP expressed the concern that failure to provide specific fees and forms in this regulation will further delay implementation of the interconnection standards and requests that any proceedings to develop fees and forms be initiated as soon as possible.
Disposition
In the November NOPR, we stated that standard forms and fees would be developed through an iterative process involving Commission tentative and final Orders. We expect to use the stakeholder approach in the development of both fees and forms to a greater extent than the November NOPR may have suggested. The nature of the Commission action which follows the stakeholder process will be determined later. As we move through that process, we will bear in mind the concerns expressed regarding improper subsidies and the need for prompt implementation. As suggested by the IRRC, the fees developed in that process will be placed in EDC tariffs. It has been the Commission's experience that fees and forms of the nature at issue here are not readily addressed in rulemakings, particularly if changes are warranted as all participants gain experience during implementation.
E. § 75.34(2). Limitation of Level 2 Reviews to Inverter Based Equipment; § 75.34(4). Use of Level 4 Reviews for Interconnection to Area Networks
Under § 75.34 (2), an EDC uses Level 2 for evaluating interconnection requests for inverter based systems that have a nameplate capacity rating of 2 MW or less, the equipment is certified, and the proposed interconnection is to a radial distribution circuit, or spot network limited to serving one customer. Section 75.34(4) provides for an expedited review process for those customers not qualifying under Level 1 or Level 2 and that do not export power beyond the point of common coupling.
Positions of Parties
Penn Future, SGC, Pennsylvania Energy Council, Farm Bureau, Pa. Department of Agriculture, DEP, Pennsylvania Environmental Council, and Native Energy support allowing non-inverter systems to be reviewed under Level 2. They note that many bio-digesters and low-impact hydro projects rely on rotating equipment and would not be eligible for the more expedited Level 2 review. Because of the greater cost of a Level 3 review, they suggest this regulation could cause a barrier to entry. They further mention that FERC Order 2006 allows Level 2 reviews of generators similar to those discussed here, but require additional information from the generator.
The EAPA and PECO support the retention of Level 2 reviews limited to inverter based systems. They note that the use of inverter technology eliminates or greatly reduces the impact the facility will have on the Area Electric Power System. However, they suggest that non-inverter based generation has the potential to deliver five to seven times the fault current an inverter based generator of equal size can deliver. This can significantly impact the ability of the distribution system's protective equipment to adequately detect a fault condition within an acceptable time period and lead to equipment damage and outage conditions.
The EAPA and PECO support the permissive use of a Level 4 review. The EAPA notes that the intent of the Level 4 review was to work with the alternative energy community to provide an accommodation while simultaneously maintaining safety and reliability. Therefore, they emphasize that it is imperative that the EDCs maintain the authority over the level of review required for interconnection to an area network. SGC supports the Level 4 review process for larger generators, but suggests all language be eliminated that does not deal with the larger non-exporting generators.
Disposition
The EAPA makes a strong argument why Level 2 reviews should apply only to inverter based generators. The potential impact on system reliability and safety must be an over-riding consideration. A non-inverter system that could potentially deliver five to seven times the fault current of an inverter system is a concern and requires the level of analysis offered in a Level 3 review.
Other comments noted that a Level 3 review will add to the cost of a bio-digester project and could cause a barrier to entry. We agree that the project cost for bio-digesters will increase under a Level 3 review. However, the incremental cost will not be so large as to inhibit entry into the market for a project that could cost $700,000 to $800,000. It is our expectation that the actual incremental cost for a Level 3 review could be less than 1% to 2% of the total project cost. Accordingly, we will decline to modify the Level 2 prerequisites.
In the MADRI Interconnection Working Group, the EDCs agreed to include a Level 4 review of an interconnection to an area network in limited circumstances and only at their discretion. The Level 4 review is predicated on the EDC possessing enough data to accurately assess the impact of the generator on the system. SGC supports the Level 4 review process for smaller generators. We agree that the EDC must make the determination whether enough information exists under a Level 4 review to allow them to accurately assess system reliability and safety, or whether the project should be reviewed under Level 3.
F. § 75.36(2) Total Nameplate vs. Incremental Evaluation
Section 75.36(2) of the proposed regulations provides that when an interconnection request is for an increase in capacity for an existing small generator facility, the interconnection request shall be evaluated on the basis of the new total electric nameplate capacity of the small generator facility.
Position of the Parties
PECO, Citizen's Electric and the EAPA agree with the proposed regulations as written. In order to ensure system reliability, the interconnection review must be based on the total nameplate capacity of the interconnection facility. The parties contend that the total evaluation is vital to an EDC when determining the relaying necessary to properly protect the distribution system. Further, what must be considered when reviewing an interconnection request is the aggregate generation connection to a line or line segment, not only the nameplate capacity of a single interconnection facility. Evaluating the aggregate generation is the only way to ensure that safety and quality of service of the line is not jeopardized and system reliability is maintained.
SGC, the OCA and Penn Future recommend that the level of review assigned to new interconnection applications be based on the proposed new incremental capacity. The parties contend that the aggregate impact of existing distribution generation capacity on a circuit is addressed by each Level of the screening criteria. The OCA urges the Commission to follow the model outlined in PJM Manual 14A and 14B.
Disposition
Safety and quality of service remain paramount to any cost savings that may occur in developing these standards. We simply cannot ignore design and service conditions that afford reliable service and a continuous supply of electricity. SGC commented that the Commission may be attempting to prevent sequential incremental additions to a single installation as a means of circumventing the application of a more intensive interconnection review. This is not the case. As stated by Citizens, the appropriate engineering and safety design for a facility must consider the maximum potential adverse impact of the facility on the distribution system. This will occur only if the review is based on the total nameplate capacity. The entire nameplate electric capacity should be examined at the time of application.
With regard to the use of the PJM approach, this regulation deals with interconnection at the distribution level, not the higher transmission level. The PJM Manuals address interconnection procedures for high voltage and extra high voltage transmission lines that possess a higher design and service condition for new loads. This is not the case with smaller distribution service systems that require more scrutiny when incremental load is added. Based on the comments presented on this issue, we will maintain the language presented in the proposed rulemaking and favor on the side of caution when dealing with operational issues.
G. § 75.36(3). EDC Records
IRRC suggests several modifications to this provision to provide consistency and greater clarity. We have modified § 75.36(3)(ii) to require reporting on the number of days to complete interconnection requests rather than the ''times'' required for completion. The IRRC suggests greater specificity in § 75.36(3)(v) which required the reporting of the number of requests that were not processed within ''established timelines.'' The regulation provides timelines in several areas. Accordingly, we have modified the subsection to provide that reporting will be required for the number of requests which were not processed in accordance with the timelines established in this subchapter. We believe that will provide sufficient direction to the EDCs to produce the information the Commission seeks.
H. § 75.36(6). Interconnection Request
IRRC suggested modifying this provision to provide greater clarity. We agree. The modified provision will simply provide that when an interconnection request is deemed complete, any modification other than a minor equipment modification shall require the submission of a new interconnection request, unless otherwise approved by the EDC.
I. § 75.36(8) Single Point of Interconnection
Under § 75.36(8), regarding additional general requirements, the proposed regulation states that ''an EDC may propose to interconnect more than one small generator facility at a single point of interconnection.'' This may be done to minimize the cost of the interconnection project to the customer-generator. Additionally, if the customer-generator requests to have more than one generator facility interconnected at a single point on the EDC's system, the EDC may not unreasonably refuse the customer-generator's request. Finally, this section provides that if an EDC proposes a single point of interconnection for more than one generation facility of a single customer-generator, that customer-generator may elect to pay the entire cost of separate interconnection points.
Positions of the Parties
First, we will address the four areas of concern presented by the IRRC on this portion of the proposed regulations. The IRRC expressed concern that the first sentence of the proposed regulation is not clear and suggested that it be redrafted. Second, the IRRC questioned whether minimization of the EDC's costs would be considered or if only the customer-generator's costs were subject to such analysis. Additionally, should EDC costs to enhance system reliability and safety be part of this analysis? The IRRC's third comment suggests that the regulation provide clear guidance on what is ''unreasonable'' regarding refusal of a joint facility, single point interconnection. Lastly, the IRRC suggested that we reconcile the language in this section--''May not unreasonably refuse to do so,'' with the language at § 75.37(a)(5) which states ''construction of facilities by the EDC on its own system is not required to accommodate the small generator facility.''
We agree with the IRRC regarding the clarity of the first sentence of § 75.36(8), and shall redraft that language for inclusion in the final regulation. Regarding the IRRC's second comment, the EDC is required to provide to the customer-generator a description and non-binding estimated cost of facilities required to interconnect the project in a safe and reliable manner. The EDC will not be responsible for any costs incurred to install a customer-generator interconnection. All of the interconnection's associated costs will be the responsibility of the customer-generator. Additionally, since all costs of physical interconnection are the responsibility of the customer-generator, there is no reason to perform an analysis of how to minimize the EDC's costs.
The term ''unreasonable'' is used in this regulation to remind the EDCs that the purpose of the Act is to encourage the development of alternate sources of energy and to deny such a request without good reason would be violative of the Act. It is simply an affirmative statement of the underlying principle that all parties to an interconnection transaction are expected to act in good faith. This is very similar to the ''arbitrary and capricious'' standard which governs certain Commission actions. The term is not so vague as to preclude an EDC from conforming its actions to its intent. In addition, any EDC that has reservations is free to seek an opinion of counsel or petition the Commission for a Declaratory Order.
We believe the language in § 75.37(5) which states that an EDC is not required to construct facilities on its system to accommodate a small generation facility, is not in conflict with § 75.36(8). The meaning of § 75.37(5) is that an EDC is not required, for example, to extend its distribution system or install additional line poles or transformers to accommodate the installation of a customer-generator interconnection. Even though pursuant to § 75.36(8), an EDC may not unreasonably refuse a customer-generator's request for a single point interconnection of multiple generation facilities, no cost of the interconnection will be the responsibility of the EDC.
Parties commenting on the proposed regulations had varying positions on this section. The EAPA does not oppose the concept but, points to cost recovery as a subordinate issue. The OSBA stated that the language implies that the EDC is to pay the cost if the customer-generator chooses to use a single point of interconnection for multiple generation facilities. Additionally, the OSBA asserted that to avoid subsidization, this cost should be paid by the customer-generator. As explained above, we shall clarify the language in the proposed regulation to remove any ambiguity as interpreted by the OSBA.
Penn Future and PEC stated that if the EDC requests a single point of interconnection for multiple generator facilities, then the EDC must be responsible for the costs, otherwise these costs would be a significant barrier to the customer-generator. Conversely, PECO stated that the customer-generator is the party responsible for the costs of interconnection at any point on the EDC's system. Whether or not the interconnection is located on the same point as other interconnections should not shift the cost responsibility to the EDC. We do not agree with the interpretation of Penn Future and PEC wherein the EDC would 'request' a single point of interconnection for multiple generator facilities. The proposed regulation states that an EDC may 'propose' a single point of interconnection. Additionally, regardless of the fashion in which the EDC communicates to the customer-generator the benefits of, or the engineering constraints involved in, utilizing a single point of interconnection, the customer-generator remains responsible for the costs associated with the project.
Finally, SGC believes the costs should be shared proportionally among the customer-generators interconnected at any single point, pursuant to PJM's model. The SGC comment has merit and should be considered when and if two customer-generators facilities may be interconnected to an EDC's system at the same point, thereby providing a cost savings to each customer-generator. However, we believe that matter is more appropriately resolved in the interconnection agreements rather than through regulation.
Disposition
Based upon the foregoing comments provided by the IRRC as well as the Parties as described above, we shall redraft the language for this section, as follows:
(8) To minimize the costs to customer-generators, An an EDC may propose to interconnect more than one small generator facility at a single point of interconnection. to minimize costs to the customer generator, and When a customer-generator requests a single point of interconnection for multiple generation facilities, the EDC may not unreasonably refuse a request to do so. When an EDC proposes a single interconnection point for multiple generation facilities of a customer-generator, and the customer-generator elects not to accept the EDC's proposal, An the interconnection customer customer-generator may elect to shall pay the entire cost of a separate point of interconnection facilities for each generation facility.J. § 75.36(9) and (10) Additional General Requirements (Lockbox)
Section 75.36 (9) and Section 75.36 (10) address the need to isolate the small generator facility from the distribution system by means of an isolation device accessible by the EDC. The device is necessary to ensure system reliability and safety, and the safety of EDC lineworkers. In lieu of an external disconnect switch, the Commission finds that a balanced and measured approach is the allowance of a readily accessible lock box.
Positions of Parties
The various commentors disagreed about the need for a disconnect device and the cost for such a device. Penn Future and SGC strongly oppose the requirement for an external disconnect switch or a lockbox to allow access to the disconnect switch by way of a lockbox. They note that an external disconnect switch can be costly and unnecessary when the inverter meets the IEEE 1547 standard for disconnecting from the grid. They encourage the Commission to adopt regulations similar to New Jersey that do not require either a disconnect switch or a lock box.
The OCA, DEP, and EAPA agree that an accessible lock box is a reasonable compromise that mitigates the safety concern and also limits the cost. DEP questions the need to require an isolation devise on a small generator project, but believes that the external lockbox offers an acceptable compromise. The OCA strongly supports the lockbox approach. They endorse an approach that ensures that consumers, utility employees and others are not endangered by unanticipated power flows into the distribution network, and feel the lockbox concept offers the proper balance between safety and cost. The OCA appears to support the position of allowing the EDC to install the lockbox. The EAPA also agrees that the lockbox proposal offers a reasonable alternative to mandating an accessible disconnect device. They suggest that the lockbox alternative was proposed to benefit the customer-generator and the lockbox and installation should be paid by the customer. They also propose that the customer-generator should be responsible for the acquisition and installation of the lockbox.
Disposition
We agree with Penn Future and SGC that a certified inverter system that meets IEEE 1547 standards offers only a small chance of a safety problem to workers, customers, or other customers, but we agree also with OCA, DEP, and EAPA that the access to a disconnect switch with the lockbox system offers a low-cost solution and provides an extra level of safety. We will maintain the provision that a customer who does not wish to provide an accessible external disconnect switch, must provide access to a disconnect switch through the lockbox system. We believe a lockbox alternative benefits both the customer-generator and the EDC, therefore, we are requiring the EDC to provide lockboxes to the customer-generator at a price to cover the EDC's cost of the lockbox. The customer-generator will be responsible for paying the cost of the lockbox and is responsible for the installation of the lockbox.
K. §§ 75.37(b)(2), 75.38(b)(2), 75.40(c)(1)(iv) and 75.40(c)(5)(iv) Interconnection to Spot and Area Networks
In the November NOPR, we addressed the issue of an acceptable limitation on the amount of the aggregate capacity which would be permitted to interconnect to the load side of spot networks and area networks. For each type of network, we expressed the maximum limit as 5% of the network's maximum load. We requested detailed technical information from any party which desired a modification to that limitation.
Positions of the Parties
The EAPA states that for spot networks, the addition of a 50kW cap to the 5% of maximum load is ''important from a safety and reliability perspective.'' The EAPA was more specific when it addressed area networks. It commented that a 50kW cap was even more important in those instances because the load on those networks is usually much greater that spot networks. Accordingly, a 5% limitation would provide for much greater capacity additions and provide for greater risks that network protectors would operate incorrectly.
The Pennsylvania Environmental Council questions the need for a 50kW cap in addition to the 5% percentage cap. The SCG also questions the addition of a 50kW cap. The SGC notes that for spot networks, the number of customers is very small so that interconnection standards for these networks can be somewhat relaxed provided the proper studies are done. The SCG observes that both Colorado and New Jersey permit interconnections to networks and that Colorado provides for a 300kW cap, not a 50kW cap. For area networks, New Jersey permits inverter-based generators up to the smaller of 10% of the network minimum load or 500kW. Non-inverter based interconnections are permitted provided there is appropriate assurance that no power will leave the generation site. Penn Future also questions the need for a 50kW cap in addition to the 5% limitation in spot and area network interconnections. Penn Future advises that it is aware of no reason why a 50kW cap would be required for safety or reliability.
Disposition
We will decline to adopt the EAPA's requested modification. In doing so, we note that the interconnection to spot networks are processed under Level 1 and Level 2 reviews which provide for interconnection of certified inverter-based equipment that is equipped with redundant protective devices which presents extremely low risk factors. Interconnection to area networks is processed under a Level 4 review. An EDC will conduct an area network impact study to determine if any adverse impacts will result from the interconnection. Depending on the results of that study, the EDC may refuse the interconnection even if the generation facility is within the 5% cap. Based upon the foregoing, including the comments regarding the New Jersey and Colorado approaches, we will retain the 5% cap without an additional 50kW cap for spot and area network interconnections.
L. § 75.37(c). Level 1 Review
IRRC suggested a minor modification to paragraph (4) to provide that an EDC shall approve the interconnection request rather than sign it so as to be consistent with paragraph (5). We will adopt this suggestion.
M. § 75.38(b)(4) Level 2 Interconnection Review--Fault Current Limits
The Level 2 screen provides that the proposed small generator facility, in aggregate with other generation on the distribution circuit, may not cause any distribution protective devices and equipment, or other customer equipment on the electric distribution system to be exposed to fault currents exceeding 85% of the short circuit interrupting capability, nor may an interconnection request be made on a circuit that already exceeds 85% of the short circuit interrupting capability.
Positions of Parties
The EAPA maintains that the 80% fault current limitation should be adopted. They note that they do not have a record of the ratings of customer owned equipment which require a more conservative fault current limitation. Penn Future, the Pa. Environmental Council, and SGC argue for at least a 90% level. They note that FERC Order 2006 calls for an 87.5% level, and the MADRI model adopted a 90% level. The Pa. Environmental Council felt that that 85% fault current level standard could cause de-facto barriers to entry for customer-generators.
Penn Future and SGC asked the Commission to conduct additional research on such items as the percent of distribution circuits that would be disqualified under the 85% limit and the number of circuits that are being affected. SGC suggests that customer-generators are being held to a higher margin of safety than normal utility practice.
Disposition
The Commission has examined this issue in more detail. We have requested additional information from the EDCs on the limits of their circuits. In response to the suggestion that the Commission should adopt either the FERC Order 2006 87.5% or the MADRI 90% level, we researched the derivation for these levels and found each number was adopted without specific technical analysis to support the level. The FERC Order 2006 adopted 87.5% as an average between the 90% level proposed by the solar lobby and others, and the 80% to 85% proposed by the EDCs. The MADRI level of 90% was never agreed to by the EDCs and some other participants to the MADRI process, but was adopted by the moderator of the MADRI working group with the support of the solar lobby and some others.
SGC states in their comments, ''There appears to be no technical basis for the new lower level,'' referring to our adoption of the 85% fault current level. This statement is completely inaccurate. We asked for technical and quantitative analysis of this issue and received only one quantitative analysis. PPL offered a reasoned technical analysis of why a level of 80% to 85% was appropriate. SGC's only response to PPL's analysis was, ''. . . this analysis is misinforming.'' Neither SGC nor anyone else offered a written, technical critique of PPL's conclusion. Those parties supporting the 90% level offer no analysis and assert only that we should adopt a compromise that was reached in the FERC Order 2006, a number was unilaterally adopted by MADRI, or the limitation that was adopted in the New Jersey interconnection regulations.
The best information that the Commission has received to date strongly supports the position that an 85% limit will not impact the vast majority of circuits. Accordingly, the 85% limit will not serve as a de facto barrier as suggested by the SGC. Conversely, the 85% limit willprovide protection that avoids potential fault current problems. Based on the quantitative analysis that we reviewed and the additional research conducted by the Commission, we will retain the 85% fault current level.
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