20070124final_order_no_30229.pdf

Office ofthe Secretary
Service Date
January 24, 2007
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION'
CONSIDERATION OF THE FIVE
AMENDMENTS TO SECTION 111 OF THE
PUBLIC UTILITY REGULATORY
POLICIES ACT OF 1978 (PURP
CONTAINED IN THE ENERGY POLICY
ACT OF 2005
ORDER NO. 30229
CASE NO. GNR-06-
On July 28, 2006, the Commission issued a Notice of Inquiry to consider the five
new" PURP A standards contained in the Energy Policy Act of 2005 (the "Act"). The Act
amended Section III of the Public Utility Regulatory Policies Act of 1978 (PURP A) by adding
five new federal ratemaking standards for electric utilities. The Act also amended PURP A
Sections 112 and 115 to require that state regulatory commissions determine whether they should
adopt the five PURPA standards as requirements for regulated electric utilities. 16 US.C. ~
2621(a). The five new PURPA standards are: Net metering; fuel source diversity; fossil fuel
generation efficiency; time-based metering and communications ("Smart Metering ); and
interconnection services to customers with on-site generating facilities. After examining the two
sets of written comments and public workshop comments, we issue this Order.
BACKGROUND
This is not the first time that Congress has required state commissions to examine
national regulatory standards. In 1978 Congress enacted PURP A to encourage: (1) the
conservation of energy supplied by electric utilities; (2) the optimum efficiency of utility
resources; and (3) equitable rates for electric customers. PURPA ~ 101; 16 U.C. ~ 2611. In
response to both PURP A and the Energy Policy Act of 1992, this Commission initiated
proceedings to review the prior federal standards. See Order Nos. 17586, 16611 , 24729. The
five new standards that are the subject of this review generally address energy efficiency,
advanced metering, and customer generation.
A. The Commission s Responsibilities
Although the Act requires the Commission to undertake a review of the five new
federal standards, the Act does not compel the Commission to adopt the standards. PURP
recognizes that nothing "prohibits any State regulatory authority . from making a
ORDER NO. 30229
determination that it is not appropriate to implement any such standard. . . ." Order No. 30108 at
citing 16 U.C. ~ 2621(a) (emphasis original). The Act also recognizes that a state regulatory
commission already may have implemented the new federal standards or comparable standards
in prior proceedings. 16 U.C. ~ 2622(d)-(f). If a State commission has already "reviewed" a
new standard - by implementing the standardla comparable standard or has considered the
standard but declined implementation - then no further action is necessary. Id.; 16 U.C. ~
2621(c)(l).
In undertaking the reVIew of the five federal standards PURP A outlines the
procedural requirements that the Commission must follow. The Commission shall issue a public
notice of its review proceeding and make its determination regarding each of the five standards
for each regulated utility: (1) in writing; (2) based upon findings and evidence presented in the
proceeding; and (3) make its findings available to the public. 16 US.c. ~ 2621(b).
B. Procedural History
In its initial Notice of Inquiry the Commission directed the three largest electric
utilities (Avista Utilities, Idaho Power Company, and PacifiCorp dba Rocky Mountain Power)!
to answer a series of questions about each new standard. The Commission s questions are
contained in prior Order Nos. 30108 and 30146. Besides inviting public participation, the Notice
required that the utilities serve their comments on a service list of interested persons.
1. The Public Workshop. The Commission s initial Notice also scheduled a public
workshop that was convened on September 13 , 2006. The purpose of the workshop was to
review the utilities' responses to the Commission s questions set out in its initial Notice. The
Commission also sought to determine whether there was consensus among the participants about
whether the Commission: (1) had already adopted the standards; (2) should adopt the federal
standards or comparable standards, if not already adopted; or (3) should not implement the
federal standards.
The following parties attended and participated in the public workshop: A vista
Idaho Power, Rocky Mountain Power, Hunt Technologies, the Industrial Customers of Idaho
Power, Distribution Control Systems, John Weber, Jay Blackhurst, and the Commission Staff.
The participants reviewed each of the five federal standards and the utilities' responses to the
1 Atlanta Power does not meet PURPA's threshold requirement of retail sales of 500 million kilowatt hours in a
calendar year. 16 U.C. ~ 2612(a).
ORDER NO. 30229
questions. As set out in greater detail below, the participants generally reached consensus that
the Commission had already implemented the federal standards except for Smart Metering.
2. Further Comments.On October 6, 2006, the Commission issued another Notice
of Modified Procedure inviting a second round of public comments regarding the five PURP
standards. The Notice required that comments be filed with the Commission no later than
October 27, 2006 and permitted the three utilities opportunity to file reply comments, if
necessary, no later than November 10 , 2006. In response to the Commission s second Notice
comments were filed by the Commission Staff, a member of the public, and the Network for
New Energy Choices. Rocky Mountain Power filed timely reply comments.
THE FIVE FEDERAL STANDARDS
AND THE COMMENTS
The Commission observed in its initial Notice that many of the basic concepts
embodied in the five "new" federal standards are not new to this Commission. Order No. 30108
at 3. The Commission, the three electric regulated utilities and other interested parties have
previously addressed the efficiency and energy resource enhancements encompassed in the new
standards. Indeed, the utilities and the workshop participants agreed that the Commission has
already adopted four of the new PURP A standards. The five federal standards and the comments
for each standard are discussed below.
A. Net Metering
Net metering generally refers to customers generating their own electricity with any
excess generation being delivered to the utility s distribution system. In essence, the customer
utility meter records the flow of electricity to and from the customer. The Commission approved
its first net metering tariff in 1997. Order No. 26750 (approving Idaho Power s Schedule 84).
The federal standard provides:
(11) Net Metering. Each electric utility shall make available upon request net
metering service to any electric consumer that the electric utility serves. For
purposes of this paragraph, the term "net metering service" means service to
an electric consumer under which electric energy generated by that electric
consumer from an eligible on-site generating facility and delivered to the
local distribution facilities may be used to offset electric energy provided by
the electric utility to the electric consumer during the applicable billing
period.
ORDER NO. 30229
1. Utilities' Responses . The three utilities responded that they each have a net
metering program in place that is available to all customers. The framework of each utility s net
metering program is similar in that they: (1) offer net metering to customers using solar, wind
hydropower, biomass or fuel cells to generate energy; (2) limit the program to 0.10% of their
retail peak generation; (3) limit residential customers to facilities no greater than 25 kW; and (4)
restrict anyone customer from generating more than 20% of such generation limit. A vista
reported that it had four residential net metering customers in Idaho that produced 16 000 kW
during 2005. The Company s net metering Schedule 63 was most recently approved August 1
2006.
Rocky Mountain Power currently has one residential net metering customer but has
several potential projects pending. The Company s net metering schedule is 135 and its net
metering generation limit is 714 kW.
Idaho Power has 20 residential customers, 4 small business customers, and 2 large
business customers engaged in net metering. The 24 smaller customers generated 397 255 kW in
2005. Idaho Power s net metering Schedule 84 is currently under review in Case No. IPC-06-
17.
2. Workshop Comments. The utilities and the participants generally agreed that the
utilities' net metering programs meet the federal net metering standard. One participant did
express a concern that existing net metering customers may be detrimentally affected if they
installed generating facilities based upon existing net metering rate structures, and the utility
subsequently changes the program.
3. Second Round Comments. Staff commented that this standard has already been
implemented by the Commission. Staff also noted that net metering customers with significant
and excess generation could participate as PURP A "Qualifying Facilities" and would be entitled
to published avoided cost rates. Staff Comments at 4-
John Weber recognized that all the utilities have net metering programs but he
suggested that a state net metering law is needed to ensure uniformity. He stated that a state law
makes it easier for utilities, business, and people to plan for the future.
The Network for New Energy Choices (NNEC) also submitted general comments
regarding net metering. NNEC did not specifically address any Idaho net metering programs but
submitted a report rating 34 states (not including Idaho) with existing net metering programs.
ORDER NO. 30229
NNEC asserted that New Jersey has an outstanding net metering program that is supported in
part by a variety of rebates and tax reimbursements to reduce capital costs. NNEC Comments at
6. Among the program elements that made New Jersey s net metering program successful were:
allowing renewable energy facilities up to 2 MW; allowing commercial customers to participate
in net metering; calculating excess generation on an annual basis based upon established avoided
cost rates; removing any limit on the total amount of electricity that can be generated in the
program; and prohibiting unnecessary safety requirements to be imposed on the net metering
customers. Id. at 9-14.
Commission Findings: We find that the federal net metering standard has already
been adopted. A vista, Idaho Power, and Rocky Mountain all have net metering programs that
comply with the federal standard. For the most part, net metering customers that produce excess
energy receive credits or payments not at avoided cost rates but at their tariffed service rates.
This provides a greater incentive than net metering programs that use avoided cost rates.
B. Diversity of Fuel Sources
(12) Fuel Sources. Each electric utility shall develop a plan to minimize
dependence on 1 fuel source and to ensure that the electric energy it sells to
consumers is generated using a diverse range of fuels and technologies
including renewable technologies.
In the initial Notice the Commission asked whether diversifyi~g generating fuel
sources has already been implemented in Idaho. The utilities and the workshop participants
agreed that this standard has already been implemented as a part of each utility s Integrated
Resource Plan (IRP) process. Mr. Weber suggested that the utilities should add more renewables
to their generating resources. The Staff also commented that the Commission has already
implemented this federal standard as evident from each utility s IRP resource stack. Staff
Comments at 5.
Commission Findings: We agree with the workshop participants that the diversity
of fuel sources standard has already been adopted by this Commission. In January 1989 , the
Commission issued Order No. 22299 requiring Avista, Idaho Power, and Rocky Mountain (or
their predecessors) to biennially prepare and file an Integrated Resource Plan (IRP). The
2 If customer-generated energy exceeds the amount supplied by A vista, the "net billing credit" is applied to the
following month. Any accumulated billing credits after 12 months are eliminated and the billing cycle starts again.
Avista Schedule 63 , ~ 5. See also Rocky Mountain Schedule 135 (residential customer credited at retail rate).
ORDER NO. 30229
Commission required that each IRP describe the utility s expectation for load growth and
provide an overview of available resource options, including "conservation resources, demand-
side resources and other potentially low, life-cycle cost resources." Order No. 22299. We find
that the IRP process minimized dependence on a single fuel source and demonstrates that our
utilities employ a diverse array of generating resources.
C. Fossil Fuel Generation Efficiency
This standard promotes the efficiency of fossil fuel generating facilities.
particular, this standard provides:
(13) Fossil Fuel Generation Efficiency. Each electric utility shall develop
and implement a 10-year plan to increase the efficiency of its fossil fuel
generation.
1. Utilities ' Responses . Idaho s three electric utilities all have fossil fueled facilities.
They asserted that fossil fuel efficiency is already a part of their 10-year IRPs. For example
A vista noted that examining fossil fuel efficiency is a part of the ongoing review process
performed by the Colstrip owners committee. Idaho Power noted that since 1995 it has obtained
18 MW of generation efficiency upgrades at its thermal plants.
2. Workshop Comments . The workshop participants did not disagree with the
utilities ' assessment that generation efficiency is part of their respective IRPs. The Industrial
Customers of Idaho Power did note that the Commission may want to require future IRPs to
explicitly address this issue instead of being subsumed in the IRP process.
3. Staff Comments. Staff agrees with the utilities that generation efficiency is part of
the IRP process. To make generation efficiency more transparent, Staff recommended that the
Commission direct that future IRPs explicitly address this issue as part of each utility s IRP.
Staff Comments at 6.
Commission Findings: As was the case with fuel source diversity, we find that this
standard addressing fossil fuel efficiency is already a part of our IRP process. However, we do
agree with the comments of the Industrial Customers that an analysis of fossil fuel efficiency
should specifically be addressed in each IRP. Consequently, the Commission directs that each
utility specifically include in its IRP a section that addresses increasing the efficiency of its fossil
fuel generation. This will make the concept of fossil fuel efficiency more transparent in future
IRPs.
ORDER NO. 30229
D. "Smart Metering
This standard requires that each utility make available to each customer class time-
based rate schedules and, upon request, offer each customer a time-based rate schedule. More
specifically, this standard states:
(14) Time-based metering and communications.
(A) Not later than 18 months after the date of enactment of this
paragraph, (3) each electric utility shall offer each of its customer
classes, and provide individual customers upon customer request, a
time-based rate schedule under which the rate charged by the electric
utility varies during different time periods and reflects the variance, if
any, in the utility s cost of generating and purchasing electricity at the
wholesale level. The time-based rate schedule shall enable the
electric consumer to manage electric use and cost through advanced
metering and communications technology.
(B) The type of time-based rate schedules that may be offered
under the schedule referred to in subparagraph (A) include, among
others -
(i) time-of-use pricing. . .
(ii) critical peak pricing. . .
(iii) real-time pricing. . . and
(iv) credits for consumers with large (load reductions).
The Commission s initial Notice observed that Avista began installing advanced
meter reading (AMR) devices on all of its Idaho electric and gas meters in 2005. Avista is now
in the third year of a four-year deployment of AMR meters for its Idaho customers. Rocky
Mountain has offered its residential customers time-of-day service (Schedule 36) for many years.
For its part, Idaho Power has implemented an AMR pilot program for more than 23 000
residential customers that provides two optional services: Time-variant pricing and air
conditioner cycling programs.When authorizing these Smart Metering programs, the
Commission stated that the implementation of the programs should be prudent and cost-
3 The participants agree that the implementation date for this standard is August 8, 2007. Order No. 30146 at note
4 The A/C Cycling program uses radio-controlled technology to reduce residential A/C load during the summer
peaking period.
ORDER NO. 30229
effective. Order No. 30146 at 7. The Notice also observed that a recent FERC Staff Report
indicated that Idaho ranked fifth (at 16.2%) in the percentage of customers with "advanced
metering.Id.
1. Utilities ' Responses . All three utilities recommended the Commission not adopt
this standard. A vista indicated that it would not finish installing all of its meters by August 2007
(the PURP implementation date for this standard). A vista also insisted it did not have
implementing tariffs, data storage, and necessary billing changes to support time-based rates.
The Company estimated that the billing and data storage costs alone would be approximately $22
million. Finally, Avista asserted it was not cost effective to offer time-based rates to all classes
of customers, but that it might be effective for larger customers. Order No. 30146 at 8.
Rocky Mountain declared that it currently offers optional time-of-day service to all
residential and distribution voltage customers. Although 31 % of its residential customers and
two general service customers are served under Rocky Mountain s time-of-use tariff, the
Company stated it was neither achievable nor reasonable to adopt the federal standard. Rocky
Mountain supported the Commission s statement that all Smart Metering programs should "
prudent and cost effective." Rocky Mountain Comments at 7 citing Order No. 30108 at 7.
Idaho Power commented that it is deploying smart meters so that the costs of
deployment are commensurate with the benefits. The Company reported that it has 123
industrial customers (Schedule 19) on time-of-use; 130 large business customers (Schedule 9) on
time-of-use; and 117 irrigation customers on time-of-use (but not ARM equipped meters). In
summary, all three utilities indicated that adoption of Smart Metering policies should be based
upon a company-by-company analysis and implemented in situations where the cost and benefits
are reasonable.
2. Staff Comments. Staff also recommended the Commission not adopt this federal
standard at this time for several reasons. First, Staff agreed with the three utilities that they
would be unable to implement across-the-board Smart Metering within the time period
contemplated by the federal standard. Second, Staff argued that AMR technology has not fully
developed or reached a state of trouble-free deployment. In particular, Staff pointed to the
Commission s recent review of Idaho Power s ARM pilot where the Commission recognized
that "ARM technology is relatively new and is evolving." Order No. 30102 at 6. Idaho Power is
5 Slide 7 at http://www.ferc.gov/whats-new/headlines/2006/2006-3/07-20-06-demand-response.pdf
ORDER NO. 30229
still attempting to resolve interface issues in its AMR pilot. Third, Staff expressed concern that
Smart Metering programs ought to be cost effective and tailored to the circumstances of each
utility. Staff Comments at 8-
Staff maintained that utilities should continue to take measured, pro-active steps to
implement cost-effective AMR programs. Staff recommended that the Commission not adopt
the federal standard, but instead, continue to work with utilities to establish AMR systems and
rate structures on a schedule that benefits both the utilities and their customers. Consequently,
Staff recommended that A vista and Rocky Mountain each address Smart Metering deployment
in their next general rate cases. Id.
3. Other Public Comments.Mr. Weber urged the Commission to implement Smart
Metering progr~s. He indicated that Smart Metering "will reduce demand during the peak
hours because people seem to react to what hits their pocketbooks more than anything else. It
also more closely reflects the true cost of power at any given time.
4. Rocky Mountain Reply Comments. In its reply comments, Rocky Mountain
agreed with the Staffs comments that the Commission has already implemented the four federal
standards except for Smart Metering. With regards to Smart Metering, Rocky Mountain did not
object to Staffs recommendation that "the status of (Rocky Mountain s) time-of-use programs
and "plans to change or upgrades for advanced metering" should be addressed in the Company
next general rate case. The Company did note that implementation of Smart Metering programs
should be in conjunction with a proceeding to address the cost recovery of any advanced
metering programs. Reply Comments at 2.
Commission Findings: After reviewing the comments, we find it is not appropriate
to adopt this federal standard. While we concur with the intent of the standard, its ubiquitous
scope and implementation timeline are unrealistic. In particular, the federal standard requires
that a utility make available time-based rates to each and every customer no later than 18 months
after the effective date of this standard. We find that requiring smart meters across the board for
each utility has not been demonstrated to be cost effective.
Although we decline to adopt this federal standard, we find that the Commission
embraces the spirit of the standard. In particular, we have implemented Smart Metering
communication programs for all three utilities. For example, nearly a third of Rocky Mountain
residential customers are subscribers of time-of-day service; Idaho Power has installed power
ORDER NO. 30229
line carrier AMR meters for more than 25 000 customers; and Avista is installing AMR devices
on all of its Idaho meters by 2009. In addition, Idaho Power also offers an Irrigation Peak
Reduction program for its large irrigation customers (Schedule 23) and the A/C Cool Credit
program for residential (Schedule 1) customers. The Commission remains committed to
implementing smart meter programs that are cost effective and that offer benefits to both the
utilities and their customers.
We do adopt Staff s recommendation that A vista and Rocky Mountain address the
status of their smart meter programs in their next general rate cases. In particular, A vista shall
address the status of its current AMR program, its cost recovery proposal, and its plans for
implementing time-of-use rates, demand responses, or other appropriate rate structures. For its
part, Rocky Mountain shall address the status of its time-of-day program, provide justifications
for the existing rate differentials, and advise the Commission of any appropriate changes to its
rate structures for its customers or classes of customers.
E. Interconnection
This last federal standard encourages state commissions to adopt "best practices" to
promote the interconnection of distributed generation facilities. Distributed generation generally
refers to a customer s on-site generating facility that may provide generation (i., interconnects)
to the local distribution system as opposed to connecting to the utility s transmission system.
This federal standard adopts interconnection standard No. 1547 published by the Institute of
Electrical and Electronics Engineers (IEEE) and references other model codes adopted by state
regulatory agencies, such as NARUC's "Model Interconnection Procedures and Agreement" (the
NARUC Model"
EPAct Section 1254(a) states:
(15) Interconnection. Each electric utility shall make available, upon request
interconnection service to any electric consumer that the electric utility
serves. For purposes of this paragraph, the term "interconnection service
means service to an electric consumer under which an on-site generating
facility on the consumer s premises shall be connected to the local
distribution facilities. Interconnection services shall be offered based upon
the standards developed by the Institute Of Electrical And Electronics
Engineers: IEEE Standard 1547 for Interconnecting Distributed Resources
with Electric Power Systems, as they may be amended from time to time. In
addition, agreements and procedures shall be established whereby the
services offered shall promote current best practices of interconnection for
distributed generation, including but not limited to practices stipulated in
ORDER NO. 30229
model codes adopted by associations of state regulatory agencies. All such
agreements and procedures shall be just and reasonable, and not unduly
discriminatory or preferential.
1. Utilities ' Responses . The utilities indicated that they have already implemented
this federal standard for the most part. A vista stated that its interconnection requirements are
contained in its Schedule 70, Part 28 and on its website. The Company recently amended its
Schedule 70 to include the adoption of IEEE Standard 1547 in Case No. A VU-06-4. Avista
suggested the Commission might adopt the NARUC Model as a "guideline" recognizing that
utilities may have particular concerns with certain elements of the Model Agreement. For
example, A vista said that it may have difficulty providing notice of interruptions seven days in
advance.
Rocky Mountain asserted it did not need to adopt IEEE Standard 1547 because the
Company already uses the standard and further noted that it is not applicable to every situation.
The Company s interconnection standards are set out in its net metering Schedule 135 and its
Open Access Transmission Tariff (OA TT) posted on its website.Rocky Mountain also
recommended the Commission consider not adopting the NARUC Model because: Its timelines
are too restrictive, it may inadvertently limit due diligence for each plant, and Idaho is only one
of six states where PacifiCorp operates.
Idaho Power indicated that it is generally in compliance with the federal
interconnection standard and has proposed to adopt the IEEE Standard 1547. Idaho Power
interconnection policies and practices are contained in its Schedules 72 and 84; in its Best
Practices (website); and in its OA TT. Rather than adopting standards for certain sized facilities
Idaho Power currently divides facilities into small, medium, and large interconnecting facilities.
Idaho Power also noted that the IEEE standard is not applicable to all situations because it
applies to facilities of 10 MV A or less. Turning to the NARUC Model, Idaho Power supported
the model in principle but recognizes that "one size does not fit all.It filed a new Uniform
Interconnection Agreement Schedule 72 (and Schedule 84 for QFs) in response to FERC'
Standards of Conduct. In Order No. 30179 issued November 17, 2006, the Commission found
that the new Interconnection Agreement was reasonable and adopted IEEE Standard 1547.
2. Staff Comments Staff asserted that the utilities generally meet the spirit and
intent of this standard by their inclusion of IEEE 1547. Staff recommended that the Commission
ORDER NO. 30229
find that it has already implemented this recommendation. Staff further suggested that the
NARUC Model be used as a "guideline" for interconnection agreements thereby maintaining
flexibility in schedule and technical application for the utilities to work with special or unique
projects and conditions. Staff Comments at 11-12.
3. Rocky Mountain Reply Comments. In its reply comments, Rocky Mountain
questioned the Staffs recommendation to use the NARUC Model as a guideline for
interconnection. While PacifiCorp agrees that the NARUC Model can serve as a tool or
reference, the Company urged that the NARUC Model should not be applied as a rule to the
Company s interconnection agreements. Reply Comments at 3.
Commission Findings: We concur with the parties' comments that the Commission
has already implemented this federal standard. The three utilities all have interconnection
services and have adopted the IEEE standard 1547 (in those cases where the standard is
applicable). More specifically, the Commission has recently approved new interconnection
schedules for Avista and Idaho Power. Order Nos. 30111 and 30179, respectively.
In our Notices, we also asked for comment regarding whether the Commission
should specifically adopt the NARUC Model. Order No. 30146 at 10. After reviewing the
comments, we agree with Staff, Idaho Power and Rocky Mountain that the NARUC Model be
used as a "guideline" for interconnection agreements rather than mandated as a rule. As such
we recognize that the NARUC Model can serve as a tool or reference but is not specifically
applicable to all interconnection situations.
ORDER
IT IS HEREBY ORDERED that the Commission has previously adopted the net
metering, diversity of fuel sources, fossil fuel generation efficiency, and interconnection
standards contained in Section III ofPURPA as amended by the Energy Policy Act of2005.
this time the Commission declines to adopt the "Smart Metering" standard but will continue to
implement cost-effective smart metering programs for each utility on a case-by-case basis.
IT IS FURTHER ORDERED that Avista Utilities, Idaho Power Company and
PacifiCorp dba Rocky Mountain Power include fossil fuel generation efficiency as part of their
future Integrated Resource Plans.
ORDER NO. 30229
IT IS FURTHER ORDERED that Avista and Rocky Mountain address the status of
their smart metering deployments and programs as set out in the body of this Order in their next
general rate cases.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) or in interlocutory Orders previously issued in this Case No. GNR-06-
02 may petition for reconsideration within twenty-one (21) days of the service date of this Order
with regard to any matter decided in this Order or in interlocutory Orders previously issued in
this case. Within seven (7) days after any person has petitioned for reconsideration, any other
person may cross-petition for reconsideration. See Idaho Code ~ 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this J.. if tI..
day of January 2007.
,J~
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~~l
Commission Secretary
bls/GNR-O6-02 dh3
ORDER NO. 30229