20011221Starrs Direct Testimony.pdf

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ORIGINAL
William M. Eddie ISB#5800
Land and Water Fund of the Rockies
P.O. Box l612
Boise,ID 83701
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Express mail address:
1320 W. Franklin St.
Boise, lD 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY TO
AMEND SCHEDULE 72 _ INTERCONNECTIONS
TO NON.UTILITY GENERATION
IPC-E-01-38
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
APPROVAL OF A NEW SCHEDULE 84 _
NET METERING
rPC-E-01-39
TN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY TO
AMEND SCHEDULE 86 _ COGENERATION
AND SMALL POWER PRODUCTION _ NON-FIRM
ENERGY
IPC-E-01-40
DIRECT TESTIMONY OF THOMAS STARRS
A. PLEASE STATE YOUR NAME, ADDRESS, AND EMPLOYMENT.
A. My name is Thomas J. Starrs. My address is 14502 SW Reddings Beach Road,
Vashon WA 98070-6814. I am a principal in the energy and environmental consulting firm of
Kelso Starrs & Associates LLC.
A. PLEASE OUTLINE YOUR EDUCATIONAL BACKGROUND AND
PROFESSIONAL EXPERIENCE.
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Starrs, Thomas
Renewable Northwest Project, et al.
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A. I hold a Ph.D. from U.C. Berkeley's Energy & Resources Group, and a law
degree from U.C. Berkeley's Boalt Hall School of Law. I spent three years as an attorney in the
Environmental and Natural Resources Group of Perkins Coie, a Seattle-based law firm, before
returning to graduate school to earn my Ph.D. My consulting practice focuses on the design,
analysis and implementation of legal and regulatory incentives for the development of renewable
energy technologies, with a focus on solar and wind energy. I am the author of over thirty
publications regarding renewable and distributed energy policy. In addition, I have made invited
presentations on energy policy to the U.S. Congress, to numerous national organizations. and to
legislative committees, public utility commissions, and state energy offices in over a dozen
states.
A. ON WHOSE BEHALF ARE YOU TESTIFYING?
A. I am testifuing on behalf of the Renewable Northwest Project, Northwest Energy
Coalition, Northwest Sustainable Energy for Economic Development, Idaho Rivers United,
Climate Solutions, and the American Wind Energy Association.
A. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?
A. The purpose of my testimony is to address certain procedural, technical, and
regulatory issues regarding the interconnection of, and eligibility for, net metering under Idaho
Power Company's proposed Schedules 72,84 and 86.
A. WHAT MATERIALS HAVE YOU REVIEWED IN PREPARATION FOR THIS
TESTIMONY?
A. I reviewed Idaho Power's applications to amend Schedules 72 and 86, and to add
Schedule 84.
a. wtTH RESPECT TO IDAHO pOWER',S APPLICATION TO AMEND
SCHEDULE 72, ARE THERE ANY INTERCONNECTION REQUIREMENTS THAT YOU
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SEE AS CREATING UNNECESSARY OR INAPPROPRIATE BARzuERS TO NET
METERING?
A. Yes. Schedde 72 requires the net metering customer to "pay all costs of
interconnecting a Generation Facility to the Company's system." See First Revised Sheet No.
72-3. Although I do not object in principle to a requirement that net metering facility owners be
required to cover the reasonable cost of any modifications to the utility system necessary to
accommodate the net metering facility, this requirement imposes an open-ended and unbounded
obligation that creates economic uncertainty for a potential net metering customer. This is
unnecessary and easily avoided through a simple tiered review process that determines whether
any such modifications are necessary.
For instance, California has adopted a three-tiered review process for distributed
generation facilities that analyzes (1) whether the generating facility is of a size and type that an
automatic determination can be made that the facility may be safely interconnected without any
modifications to the utility system, and therefore without any additional cost to the customer; and
if not then (2) whether the generating facility is of a size and type that a simple and quick review
of the distribution system at the point of interconnection will indicate that the facility can be
interconnected without any modifications to the utility system, and therefore without any cost to
the customer; and if not then (3) that a more elaborate interconnection study is necessary in order
to determine whether. and if so what, modifications to the distribution system will be necessary
in order to accommodate the generating facility. This review process is detailed in the California
Public Utility Commission's Decision Adopting Interconnection Standards, Decision 00-12-037 ,
Rulemaking99-10-025, Appendix A, page 2 (lssued December 21,2000), available on the
internet at : http :i/www.cpuc.ca. goviwordjdf/FINAL_DECI S ION//4 1 I 7.pdf.
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As a practical matter, actual utility experience with net metering facilities across the
country has demonstrated that in the vast majority of cases, the customer's equipment provides
the necessary safety and power quality protection and the distribution system can accommodate
the facility without any modification. Under these circumstances, the proposed language is
overbroad and does nothing more than create uncertainty for the customer regarding the total
cost of the net metering facility. To illustrate this point, imagine a customer receiving a bid for a
10 kW wind energy system that reads, in effect, "Total Installed Cost: $30,000 plus the actual
cost of the equipment that the utility determines is necessary." The customer's response,
naturally enough, will be to conclude that the bid is meaningless and the total project cost is
unbounded.
The proposed language provides a mechanism for receiving an initial cost estimate, but
the language also clearly provides that actual costs may vary without limitation from the
estimated costs -- and furthermore, that the utility reserves the right to collect any additional
costs that the utility later concludes may be necessary to maintain the distribution system.
A better solution would be to shift the burden of presumption by specifying that a net
metering facility that complies with applicable codes and standards can be interconnected
without any additional cost to the customer, unless the utility makes an affirmative finding
following the submission of a completed net metering application that the proposed facility will
require modifications to the utility system in order to be safely and reliably interconnected. The
utility shall inform the customer of such finding within a reasonable period following the
submission of the application (i.e. 30 days), and the customer shall have the opportunity to
appeal the finding to the Commission.
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A. ARE THERE ANY OTHER INTERCONNECTION REQUIREMENTS THAT YOU
SEE AS CREATING LNNECESSARY OR INAPPROPRIATE BARzuERS TO NET
METERING?
A. Yes. Schedt:Je 72 also contains language requiring net metering customers to submit to
Idaho Power an initial certification and a recurring annual certification. These certification
requirements are not necessary to ensure compliance with appropriate safety and power quality
requirements, will provide little if any incremental protection for the customer or the utility, and
will be prohibitively expensive for customers to comply with. The specific language to which I
refer is on Original Sheet 72-6,which states in relevant part:
Seller Generation Facilities that qualify for net metering under Schedule
84 are required to submit to the Company certification from an independent
qualified party licensed in the State of Idaho that the design and equipment in the
Generation Facility and Seller Furnished Facilities (1) comply with the standards
of this schedule and applicable electric and building codes and (2) will operate to
safely deliver Energy to the Interconnection Point. The Seller shall provide the
credentials and licenses of the certifying party to the Company for review and
acceptance of the certification.
The Seller will obtain an annual certification from an independent
qualified party licensed in the State of Idaho, certifuing the Generation Facility
and Seller Furnished Facilities and equipment are in compliance with all current
applicable electrical and safety codes and are able to safely and reliably continue
to operate. The Seller will provide the credentials and licenses of the certifying
party to the Company for review and acceptance of the certification. A copy of
this certification must be forwarded to the Company by May lst of every calendar
year in which the Seller's facility is interconnected to the Company's system.
Within the first calendar year of operation, the Seller will be required to supply
only the certifications required at the time of the initial interconnection. In the
event the Company does not accept the annual certification within sixty days of
its receipt, the Generation Facility will be disconnected from the Company's
system until such time as the certification is completed and accepted by the
Company.
A. COULD YOU EXPLAIN WHY YOU BELIEVE THESE CERTIFICATION
REQUIREMENTS ARE LTNREASONABLE?
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A. Yes. Utilities have legitimate concems about the safety and performance
characteristics of non-utility owned generation. However, there are well-established methods for
addressing these concerns that are much less intrusive and burdensome than the requirements
Idaho Power has proposed. Specifically, the utility's concerns can be addressed by ensuring that
net metering facilities are installed in accordance with the requirements of local and national
electrical codes, and use equipment that has been tested and approved as complying with
appropriate standards for interconnection to utility systems.
The responsibility for ensuring compliance with electrical codes rests with the "Authority
Having Jurisdiction" or AHJ, who is usually a local or state electrical inspector. Virtually every
net metering facility will require that the customer pull an electrical permit. triggering the
process by which the facility will be inspected and approved. Idaho Power effectively
recognizes the importance of the permitting and inspection process elsewhere in the proposed
Schedule 72, where it requires net metering customers to submit proof that "all licenses. permits,
inspections and approvals necessary . . . have been obtained from applicable Federal, state or
local authorities." See First Revised Sheet No. 72-3. There is no legitimate reason to require the
customer to obtain duplicative and redundant certification of compliance from an "independent
party licensed in the State of Idaho."
Because electrical inspectors are concerned primarily with building safety (e.g. fire
protection) rather than with utility safety and power quality, utilities cannot necessarily rely on a
routine electrical inspection to address their concerns. However, national standard-setting
authorities such as the Institute of Electrical and Electronics Engineers (IEEE) and Underwriters
Laboratories (UL) have spent years designing and adopting appropriate standards for the
interconnection of so-called "distributed generation" to utility systems. For instance, the IEEE
recently approved a standard for utility interconnection of solar photovoltaic systems, entitled
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IEEE 929-2000 "Recommended Practice for Utility Interface of Photovoltaic (PV) Systems."
Similarly, UL has approved UL 1741, entitled "Standard for Inverters, Converters and
Controllers for Use in Independent Power Systems." These standards have been widely adopted
across the country, and in fact the states of California, Montana, Oregon, and Washington all
specify that compliance with these standards precludes the imposition of additional requirements
by utilities, absent explicit regulatory approval following a determination that additional
requirements are necessary to address legitimate safety concerns. Thus, a product that is "listed"
by UL has been tested and approved as being in compliance with relevant UL standards.
As a practical matter, the vast majority of net metering applications Idaho Power is likely
to receive will be for inverter-based systems, including solar photovoltaic and small wind electri
systems. For these facilities, Idaho Power's review should be limited to ensuring that the
being used is listed to UL 1741. No further review is necessary, and no further review should be
required.
Comparable standards for non-inverter based systems using synchronous or induction
generators, such as some small hydroelectric facilities and some larger wind turbines, are under
development. The IEEE is finalizing a draft standard for a wide range of distributed power
technologies, entitled IEEE P1547/D08 Draft Standardfor Interconnecting Distributed
Resources With Electric Power Systems (Draft Date: August 29, 2001). The UL is certain to
develop a corresponding testing standard, as it did for inverter-based systems. This will create a
effective national standard for all distributed technologies, which can then be readily adopted
across the country. Until such time, it is reasonable for Idaho Power to require additional
project-specific review, but only for these non-inverter based systems.
To put Idaho Power's proposed certification requirements in context, it is important to
realize that many net metering facilities will be very small-scale generating facilities producing
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modest amounts of electricity. A two-kilowatt (2 kW) solar photovoltaic system, for example,
will produce perhaps 300 kilowatt-hours (kwh) of electricity per month. Assuming the retail
price of power is $0.06/kwh, the value of the energy produced is $18 per month, or
approximately $216 per year. Yet Idaho Power is proposing that the customer hire an
"independent qualified party licensed in the State of Idaho" to conduct an initial inspection. and a
recurring annual inspection. It seems possible -- if not likely -- that the cost of hiring someone to
perform this inspection and provide the required documentation to Idaho Power could easily
exceed the annual energy savings from the net metering facility. Thus, the proposed requirement
is an obvious economic barrier to the development of such facilities.
A. ARE YOU AWARE OF ANY OTHER UTILITIES OR JURISDICTIONS THAT
REQUIRE ANNUAL CERTIFICATIONS OF SYSTEM SAFETY AND RELIABILITY?
A. No. To my knowledge, no other utilities or states require annual certifications of
system safety or reliability for net metering facilities.
A. PLEASE DISCUSS HOW IDAHO POWER COULD MEET ITS NEEDS OF
GRID SAFETY AND RELIABILITY WITH RESPECT TO NET-METERING, WHILE
ELIMINATING EXPENS IVE AND UNNECE S SARY INTERCONNECTION
REQUIREMENTS.
A. Idaho Power should rely on initial inspection and testing to ensure compliance
with local and national electrical codes and with national standards for utility interconnection of ]
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distributed generating facilities, as described above. There is an emerging national consensus i
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around the adoption and use of these standards, and there is no legitimate reason for Idaho Powerl
Ito impose additional requirements that serve little or no purpose other than to unnecessarily I
Iinflate the cost of installing and operating a net metering facility
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a. WITH RESPECT TO IDAHO POWER',S APPLICATION FOR APPROVAL OF
SCHEDULE 84 _ NET METERING, IS IT REASONABLE TO RESTICT NET METERING
ELIGIBILITY TO ONLY RESIDENTIAL AND SMALL COMMERCIAL CUSTOMERS?
A. No. Although it is reasonable for utilities to seek different approaches for limiting
the scale and scope of net metering programs in order to avoid significant cost-shifting between
customers, Idaho Power is also proposing to limit the cumulative nameplate generating capacity
of generating facilities to approximately 2.9 megawatts (MW). See Schedule 84 Application, at
4. This limitation is more than sufficient to ensure that any potential revenue losses attributable
to net metering are inconsequential and result in no significant cost-shifting. Accordingly, there
is no justification for the additional limitation on eligible customer classes. As a practical matter,
experience in other states has demonstrated that commercial customers -- including irrigation
customers and other agricultural customers -- are among the most interested in net metering.
A. WHY DO YOU BELIEVE IT IS IMPORTANT THAT IRRIGATION
CUSTOMERS BE ELIGIBLE FOR NET METERING?
A. Rural landowners -- including ranchers, farmers, and other irrigators -- are most
likely to benefit from an abundance of sun, wind, and other resources that can be hamessed and
converted to clean, renewable electricity.
A. FOR CUSTOMERS UTILIZING THREE-PHASE POWER AND DEMAND
METERS, ARE THERE ANY TECHNICAL BARRIERS TO INTERCONNECTING NET-
METERED GENERATION SYSTEMS, WHICH MIGHT JUSTTFY MAKING SUCH
CUSTOMERS INELIGIBLE FOR NET METERING?
A. No.
A PLEASE EXPLAIN.
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A. Many net metering facilities are three-phase systems, including most solar and
wind systems larger than l0 kW. The interconnection of these facilities is not significantly more
complicated than single-phase systems. In fact, three-phase systems may be preferable because
they minimize the potential for phase imbalance that may arise from larger single-phase
facilities.
Although the metering required to provide net metering for three-phase and demand-
metered customers are somewhat more complicated than for the simplest single-phase
metering requirements do not justiff precluding any class or category of customers from availing
themselves of net metering. Advances in new electronic metering technologies ensure that bi-
directional power flows can be measured accurately and inexpensively. For instance, there are
meters currently available that can track bi-directional power flows on a time-of-use basis while
also measuring peak demand. To provide just one example, the ABB Alpha Plus series of
provide high-accuracy, revenue-quality electronic metering with multi-rate tracking. real/reactive
power tracking, service connection validation, power quality monitoring, and load profiling with
remote communications capability. Although the cost of these advanced meters -- which range
from $200 to $2,000 -- might be prohibitive for the smallest-scale facilities. this cost is likely to
be acceptable for a larger-scale facility owner seeking to capture some of the benefits of net
metering in a time-of-use or demand-metered application. In fact, utilities in other states --
California and New York are two of which I am aware -- already are offering net metering
combined with time-of-use pricing.
Moreover, there is nothing to prevent a utility from installing separate meters for the
customer's generation and the customer's loads, and 'netting' generation against consumption in
the billing process rather than in the metering process. In this case, the cost of additional
metering will be very modest.
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A DO YOU HAVE ANY ADDITIONAL COMMENTS?
A. Yes. With the exception of the concems previously identified in this testimony,
and some concerns raised in other comments submitted by the parties on whose behalf I am
submitting this testimony, I believe Idaho Power deserves to be commended for its efforts to
craft a simple, understandable, and workable net metering option for its customers. The
proposed Schedule 84 represents a significant improvement over Idaho Power's existing net
metering option, which was unnecessarily complicated and imposed interconnection and service
charges that rendered the option largely meaningless as a mechanism for encouraging customers
to invest in small-scale renewable generation.
If the concerns raised by the parties are addressed by the Commission, Idaho Power will
be able to claim credit to a net metering policy that is what it should be: a simple, inexpensive,
and easily-administered mechanism for streamlining the process by which customers interested
in generating some of their own electricity using clean, renewable, and locally-available
resources can do so.
A. DOES THAT CONCLUDE YOUR TESTIMONY?
A. Yes, it does. I thank the Commission for the opportunity to submit this testimony
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Renewable Northwest Project, et al
Dated this 20th day of December, 2001
Thomas J. Starrs
Starrs,