Thanks to the Doe for funding this study and making it public. Electricity for the masses.
interconnection procedures contained in the IREC
model are divided into four areas:Level 1: 10 kilowatts (kW) and smaller for certifiedinverters (residential-sized systems)
2: 2 MW and smaller, certified (commercial net metering and other systems)mLevel 3: 10 MW and smaller, certified, non-exporting (designed for combined-heat-and-power facilities) Level 4: All others up to 10 MW, including generators that
attempt but do not qualify for other, more expedited standards The concept behind the rules is to categorize the possible generator interconnections from least complex to most complex. Under such segregation, the fees and time to process an interconnection application can be minimized for each grouping while simultaneously maintaining the highest
level of safety and reliability. IREC’s approach has been to design a rule that eliminates as many barriers as possible in
order to provide a model that truly allows small renewable generation to flourish. Compromises that some state rules
have included that are not consistent with the concept of promoting DG have been excluded.
The IREC model uses as its core the recent IEEE 1547 standard (and associated UL 1741 testing standard) which
allows a utility to expedite the review of many generator protective functions since these have already been reviewed
and approved by UL or another equivalent testing laboratory. Each of the first three levels relies on some prereview
by an independent third-party testing laboratory. The fourth and final category is the catch-all for generators
tat either require complete review of their custom protection equipment or do not meet any of the more
stringent criteria for the other levels. This category also includes generators that are initially processed for
interconnection under any of the three more expedited versions, but fail to qualify because of a technical issue.
While the IREC model is not incompatible with either the requirements under the Energy Policy Act of 2005 Section
align=”LEFT”>1254 or FERC Order 2006, the rules are more comprehensive. Where there are departures from Order
align=”LEFT”>2006, the departures are those that are supported by a certain state rule – a rule that is less cumbersome to the generator.
Procedures for the simplest class – the 10-kW residentialsized generator – are almost identical to those rules
contained in FERC Order 2006, in Massachusetts and in New Jersey. Among the federal and state interconnection
rules already in place, there appears to be the most consistency among this category. While some have debated
the need or ability to raise the threshold of this category to a number greater than 10 kW (state rules range from 10 kW to
80 kW in this category), because of the general consistency, IREC chose to remain with the 10 kW limit. Future
revisions of the model may revisit this issue particularly as technologies are developed that target larger generators for
the residential class. The 2-MW procedures provide for a more intensive review
of the proposed generator but still are structured such that a qualified utility engineer should be able to complete the
review in about three hours. Because all generators under this category must be listed by UL (or another laboratory) to
the UL 1741 standard, all review of generator protection has been eliminated as redundant. Instead, the procedures
employ a group of screening criteria designed to demonstrate that the generator is sufficiently small in
comparison to the grid at the proposed point of interconnection, so that no in-depth study of the
interconnection is warranted. The key screen ensures the generator size (in aggregate with
other DG) is small in comparison to the grid – less than 15 % of the peak load. The second most important screen
checks to ensure the contribution from the generator to utility circuit fault current (which makes utility protective
devices fail under excessive current) is less than 10% of that available. A secondary check on fault current ensures that where
circuits are already near their design limit and are presumably slated for upgrade, DG is not added that will
exacerbate the problem. Whereas FERC has included a screen disallowing processing under the 2-MW procedures
where circuit loading is at or above 87.5%, the IREC rule uses a limit of 90%. Since FERC’s rule was the result of a
compromise among the parties and is not technically based, IREC chose the more defensible 90% as the number most
utilities use (although many are as high as 100%) for planning system upgrades based on fault current. A
percentage lower than a particular utility’s planning threshold can exclude generators from simple
interconnection based on the invalid assumption that the gnerator should wait until the circuit is upgraded prior to
interconnecting. To be most accurate, the percentage in a rule would be that same percentage that a utility uses for
distribution upgrades. IREC also chose to include a very conservative set of
screens that allow simple interconnection to distribution networks, both spot and area. While IEEE is, at the time of
this writing, considering additional elements to the 1547 standard to address networks, IREC did not believe there
should be an absolute bar to simplified interconnection while those rules are being developed. Instead, the IREC
rule allows for very small and inverter-based interconnections to allow a few small pilot installations to
proceed. In fact, these pilots may provide valuable information on the interaction and safety of generators on
networks. IREC also felt it would be unwise to exclude fom an interconnection model those urban areas (typically
served by networks) that are likely to be the most valuab elocations for DG.
The 10-MW rule completes an omission in FERC Order2006 and provides for the simplified interconnection of
larger generators, provided there is no export to the grid.This would accommodate both combined-heat-and-power
(CHP) generators as well as large photovoltaic (PV)systems, especially where the 2-MW rule – which is an
aggregate – has already been fully subscribed. Because thereis no export to the grid (and reverse power relays or other
devices will so ensure) a utility need only be concerned withfault current contribution. According to experts at PJM
Interconnection (the independent regional transmissionoperator in the Mid-Atlantic states), every distribution
circuit is sufficiently robust that any generator powerfluctuations should not adversely affect the circuit. In other
words, a generator could go from full power to no power,resulting in large power swings on a circuit, and there would
be no adverse result. Because on-site generators are the onlyorm of DG eligible under this category, the maximum
power fluctuation is limited to a customer’s load.The final and most intensive category simply codifies what
is a typical utility interconnection study process. The IRECrule does encourage the review to be expedited where
possible, but leaves open the possibility of a full-blowninterconnection study that may include massive upgrades to
the utility grid. For most DG systems, such costly upgradeswould make a project financially infeasible. Nonetheless,
the model rule is designed to accommodate even these most
complex interconnections.An intentional cut-off at 10 MW was incorporated as a
reflection of what appears to be a growing state/federaljurisdictional line. Because most (if not all) 10-MW and
larger generators will impact the transmission grid, FERC’sjurisdiction may be implied for this larger size class. While
there may be some argument on a firm jurisdictional split,such a bright line would help small-generator developers
know which interconnection rules would apply to theirproposed system.
IREC’s updated model also includes standard applicationforms for the initiation of an interconnection review. These
are nearly identical to those included in FERC Order 2006,
with modified language for states. The application forms
were universally supported by all stakeholders in the FERC
process. Standard form interconnection agreements are also
included. The simplified version draws heavily on the
National Association of Regulatory Utility Commissioners
(NARUC) model interconnection agreement
.
IREC’s model is superior to the NARUC interconnection
model because the NARUC model does not include the
more recent developments from the FERC Order 2006 or
state rulemakings on interconnection. While the Mid-
Atlantic Distributed Resources Initiative (MADRI)
interconnection model includes the 10-MW non-export
standard, there are so many other departures harmful to
small generators that this model should be rejected. (The
opening comments included in the MADRI model indicate
support from the utility community and strong objections
from the small-generator community). The Environmental
Law and Policy Center (ELPC) has recently released an
interconnection model that has not been fully reviewed at
the time of this writing. The ELPC model appears to support
many of the propositions in the IREC model and hence may
be a suitable alternative.
While there are no other complete model interconnection
rules that provide an expedited process to remove barriers to
the use of DG, FERC has indicated its rule could be used as
a model. Colorado’s recent promulgation of interconnection
rules seems to have taken FERC up on its offer and is now a
state rule that nearly identically tracks FERC Order 2006.
3. NEW STATE INTERCONNECTION RULES
Some states have adopted interconnection rules that apply
only to DG systems that are not net-metered. Other states
have adopted rules only for net-metered systems; these rules
apply specifically to renewable-energy systems, for the most
part. Several states have adopted rules for both types of
systems.
In 2005 and early 2006, new interconnection rules were
adopted by Colorado, Indiana, Louisiana and North
Carolina. Significantly, Colorado is the first state to adopt
interconnection rules that essentially mirror FERC’s rules
for small generators. Colorado’s rules address three levels of
interconnection: (1) certified, inverter-based systems up to
10 kW, (2) certified systems up to 2 MW, and (3) systems
up to 10 MW that do not qualify for either of the first two
levels. Colorado’s rules include a standard interconnection
agreement, a screening process for interconnection studies,
and guidance for dispute resolution. Furthermore, utilities
may not require customers to install an external disconnect
switch, and network interconnection is generally permitted.
The primary difference between Colorado’s DG
interconnection rules and FERC’s rules is the maximum
system size. Indiana’s rules are also similar to FERC’s
rules. These rules include three levels of interconnection;
the first two levels – for inverter-based systems up to 10 kW
other systems up to 2 MW – apply to systems that comply
with IEEE 1547.
North Carolina adopted DG interconnection rules in 2005
for residential systems 20 kW and under, and for
commercial systems 100 kW and under. Louisiana’s
interconnection rules apply only to net-metered systems and
generally are not favorable for customer-generators. The
rules apply to residential systems up to 25 kW and
nonresidential systems up to 100 kW. It deserves mention
that Louisiana’s relatively simple interconnection and netmetering
rules were adopted 29 months after legislation
requiring their creation was enacted.
At the time of this writing, new interconnection rules for
DG are under development in several states, including
Arizona, Pennsylvania, Vermont and Washington.
Arizona’s proposed rules resemble FERC’s rules, and
Pennsylvania’s proposed rules are based on the MADRI
model, which is less favorable for customer-generators than
the FERC model. Proceedings already initiated to develop
DG interconnection rules in Hawaii, Illinois, Iowa and
Kansas are stagnant, and the Minnesota Public Utilities
Commission (PUC) still has not approved Xcel Energy’s
interconnection tariff.
4. STATE INTERCONNECTION RULES REVISED
Several states revised existing interconnection rules in 2005
and early 2006. California’s Rule 21 Working Group, which
consists of parties interested in the ongoing development of
the state’s interconnection standard, meets periodically to
create consensus among stakeholders to address revisions
required by regulatory order. Among other issues, the
Working Group is addressing dispute resolution and
network interconnection. Hawaii enacted legislation in 2005
requiring the state PUC to develop interconnection rules for
net-metered systems greater than 10 kW. In December
2005, the Massachusetts Distributed Generation
Collaborative made several modifications to its model DG
interconnection tariff, originally adopted in February 2004.
Generally, these revisions are related to the interconnection
process, meter ownership, network interconnection and the
role of DG in distribution planning.
In early 2005, the New York Public Service Commission
(PSC) approved utility tariffs that comply with a 2004
commission order requiring utilities to increase the
maximum capacity of an individual interconnected system
to 2 MW, and to include provisions for network
interconnection. Later in 2005, the PSC modified its rules
by extending interconnection to net-metered wind-energy
systems up to 25 kW for residential turbines and 125 kW for
farm-based turbines.
Increasingly, when developing new interconnection
standards and when revising existing standards, states are
considering including provisions for network
interconnection, dispute resolution and standard agreements.
Until recently, these issues received little attention.
5. NEW STATE NET-METERING RULES
In 2005 and early 2006, the public utilities commissions of
Colorado, Louisiana, Michigan, North Carolina and the
District of Columbia adopted new net-metering rules for
renewable-energy systems. Colorado’s new rules, which
apply to systems up to 2 MW, rival New Jersey’s rules as
the best in the country. Significantly, utility support for netmetered
systems up to 2 MW in capacity was largely driven
by the solar carve-out provision in the state’s renewable
portfolio standard (RPS), enacted in November 2004. Net
excess generation (NEG) is credited at the utility’s retail rate
to the customer’s next bill. There is no limit on the total
capacity of all net-metered systems in a utility’s service
territory.
Michigan’s unique net-metering program was created after
several failed attempts to enact net-metering legislation. In
May 2005, the PSC approved a consensus agreement among
several stakeholders (including 11 utilities) implementing a
voluntary net-metering program that applies to systems up
to 30 kW. NEG is credited at the utility’s retail rate and
carried over to the following month for one year. Customergenerators
retain ownership of renewable-energy credits
(RECs). New rules adopted by the District of Columbia PSC
apply to renewable-energy systems, CHP systems,
microturbines and fuels cells up to 100 kW.
Louisiana’s net-metering rules, modeled on Arkansas’s
rules, apply to nonresidential systems up to 100 kW and
residential systems up to 25 kW. Although there is no
aggregate limit on net-metered systems and NEG may be
carried over to the next month indefinitely, Louisiana’s
interconnection rules for net metering generally are not
favorable to customer-generators. Similarly, North
Carolina’s net-metering rules, which apply to nonresidential
systems up to 100 kW and residential systems up to 20 kW,
contain several unappetizing provisions. Specifically, NEG
is granted to the utility twice annually with no compensation
for the customer, and customers may not use battery storage.
At the time of this writing, the Pennsylvania PUC is
developing net-metering rules for systems up to 2 MW, as
required by statute. Pennsylvania will become the third state
to support 2-MW net metering.
6. STATE NET-METERING RULES REVISED
As technologies evolve, as markets for renewable energy
and DG take form, as costs of fossil fuels vacillate, and as
state energy policies begin to play out, some states have
amended their net-metering laws accordingly. Several states
took action in 2005 to modify their existing rules. In most
cases, rules were expanded to accommodate additional
technologies or larger systems.
California enacted three bills in 2005 related to net
metering. These new laws extended the pilot program for
net-metered biogas-energy systems and allowed as many as
three biogas-energy systems up to 10 MW to net meter;
extended a provision that allows net metering for fuel cells;
and raised the aggregate capacity limit of net-metered
systems in SDG&E’s service territory to 50 MW.
Maryland altered its net-metering statute by adding biomass
as an eligible resource and increasing the maximum
individual system capacity from 80 kW to 200 kW.
Furthermore, customer-generators may now petition the
PSC to allow net metering for systems up to 500 kW.
Similarly, Oregon enacted legislation in 2005 extending net
metering to biomass systems and allowing the PUC to
increase the capacity limit of a net-metered system above
the current limit of 25 kW.
Legislation enacted in Nevada in 2005 imposed an
aggregate capacity limit of 1% for net-metered systems in
each utility’s service territory. This law also increased the
maximum capacity of a net-metered renewable-energy
system from 30 kW to 150 kW, although some unfavorable
conditions apply to “net-metered” systems greater than 30
kW. Likewise, the Virginia Corporation Commission raised
the capacity of eligible non-residential net-metered systems
from 25 kW to 500 kW in 2005.
7. FEDERAL DEVELOPMENTS
Section 1251 of the Energy Policy Act of 2005 (EPAct
2005) implements a national net-metering scheme, and
Section 1254 requires interconnection based on the IEEE
1547 standard. While these sections do not
mandate federal
interconnection or net metering, they do direct states to
undertake consideration and make a determination with
respect to each standard. Where states regulate electric
utilities, those regulatory bodies will be required to
“consider” implementation of interconnection and net
metering. Unregulated utilities that qualify under PURPA
(there are some unregulated municipal and cooperative
electric utilities that do not qualify) also must “consider” net
metering and interconnection rules.
The essence of Section 1254 is to promote the
standardization of interconnection procedures based on
IEEE 1547. Whether fortuitous or by design, Congress’s
articulation on interconnection happens to fit nicely with the
FERC’s rules for small generators, issued in Orders 2006
and 2006-A. For generators that comply with IEEE 1547,
FERC’s rules allow the expedited interconnection of
systems up to 10 kW and interconnection for systems up to
2 MW. The FERC rules apply only to transmission owners
and those engaged in interstate commerce. The rules will
require any utility that owns or operates transmission lines
to include the new standard in their open access
transmission tariffs (OATT). By that mechanism, small
generators subject to FERC jurisdiction will have a federal
interconnection standard based in part on IEEE 1547.
One (aggressive) interpretation of Section 1254 is that
Congress sought to extend the FERC rules to all small
generators and create the seamless standard FERC desires.
Under this interpretation, there is little action required by
states other than to adopt the FERC rules for state
jurisdictional generators, perhaps with minor modifications.
For states and utilities that do not adopt FERC’s rules,
FERC theoretically has the authority to apply the federal
rule where state rules are found deficient. It is likely that a
state or non-regulated utility that adopts an interconnection
rule loosely based on IEEE 1547 (even if it differs from
FERC Orders 2006 and 2006A) will survive a legal
challenge.
Based on the general alignment between the consensus
filing of the stakeholder parties in the FERC rulemaking
process and FERC Order 2006, it is fair to assume that the
Small Generator Coalition (SGC) would support a national
scheme based on this order. Section 1254 promotes this goal
by allowing DG advocates to argue, in proceedings states
must undertake, that the state should adopt rules that parallel
Order 2006. In fact, many of the utilities involved in state
proceedings will already have filed a tariff (in compliance
with Order 2006 and 2006-A) that includes FERC’s
interconnection rules.
Existing state standards that closely resemble the FERC rule
and incorporate the IEEE standard are undoubtedly safe
under Section 1254. These include rules in place in New
Jersey, Colorado and Indiana. Other states (such as
Massachusetts) that have rules resembling FERC’s rules but
that deviate in a significant way (e.g., the peak load limit in
Massachusetts is almost half that of the FERC rule) may be
challenged if the state decides not to adjust the rules.
California is the only state that could reject adoption of
Order 2006 and still maintain its existing rule. Although
California’s interconnection rule (Rule 21) is different from
FERC’s model, the state could argue that its rule effectuates
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