20061027Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
RECEIVED
2006 OCT 27 Pt1 I: 39
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Street Address for Express Mail:
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Attorney for the Commission Staff
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 (PURPA) CONTAINED IN THE
ENERGY POLICY ACT OF 2005.
CASE NO. GNR-06-
STAFF COMMENTS
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
attorney of record, Donald L. Howell, II, Deputy Attorney General, and submits the following
comments in response to Order No. 30146 issued on October 6 2006.
BACKGROUND
On July 28 2006, the Commission issued a Notice oflnquiry to consider the five "new
PURP A standards contained in the Energy Policy Act of 2005. More specifically, the Energy Policy
Act (EP A) amended Section 111 of the Public Utility Regulatory Policies Act of 1978 (PURP A) by
adding five new federal ratemaking standards for electric utilities. The five new PURP A standards
are: net metering; fuel source diversity; fossil fuel generation efficiency; time-based metering and
communications ("Smart Metering ); and interconnection services to customers with onsite
generating facilities. The Commission directed the three largest electric utilities (Avista, Idaho Power
and Rocky Mountain Power) to answer a series of questions set out in the initial Notice.l The Notice
Atlanta Power is not subject to the PURPA standards. Order No. 30108 at n.
STAFF COMMENTS OCTOBER 27 2006
required that the utilities serve their comments on a service list of interested persons. Order No.
30108 at 10.
A. The Public Workshop
The Commission s Notice also scheduled a public workshop on September 13 2006, for the
purpose of reviewing the utilities ' written comments. Participants at the public workshop included
the three utilities, Hunt Technologies, the Industrial Customers ofldaho Power, Distribution Control
Systems, the Commission Staff, and customers John Weber and Jay Blackhurst. The participants
reviewed each of the five federal standards and the utilities' responses to the questions set out in the
Commission s Notice oflnquiry. In Order No. 30146 the participants and other interested persons
were invited to comment on the five federal standards. These Staff Comments are submitted pursuant
to Order No. 30146.
B. The Commission s Responsibilities on Review
Although the EP A requires the Commission to undertake a review of the new federal
standards, the Act does not compel the Commission to adopt the standards. PURP A recognizes that
nothing "prohibits any State regulatory authority. . . from making any determination that it is not
appropriate to implement any such standard. . . ." Order No. 30108 at citing 16 U.C. ~ 2621(a)
(emphasis original). The EP A also recognizes that a state regulatory commission may have already
implemented the new federal standards or comparable standards in prior proceedings. 16 US.
~ 2622( d)-Ct). If a State has already reviewed a new standard - by implementing the
standard/comparable standard or has considered the standard but declined implementation - then no
further action is necessary. !d.16 US.C. ~ 2621(c)(I).
In undertaking our 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 U.C. ~ 2621(b).
In reviewing the five standards, the Act requires that the Commission consider the three goals
of PURP A. The goals of PURP A are: (1) conservation of energy supplied by electric utilities;
STAFF COMMENTS OCTOBER 27 2006
(2) optimal efficiency of electric utility facilities and resources; and (3) equitable rates for electric
consumers.
C. Timelines and Deadlines
The timeline for each standard as set by the Act are listed below. If the Commission has not
completed its review of each standard by the respective deadline, then the review shall occur in the
first applicable proceeding that follows the deadline, but no later than three years after the deadline.
Net Metering
Commission Begins or Schedules Consideration
Commission Makes a Determination
August 8, 2007
August 8 , 2008
Fuel Sources (diversity)
Commission Begins or Schedules Consideration
Commission Makes a Determination
August 8, 2007
August 8, 2008
Fossil Fuel Generation (increased efficiency)
Commission Begins or Schedules Consideration
Commission Makes a Determination
August 8, 2007
August 8, 2008
Smart Metering
Commission Begins or Schedules Consideration
Commission Makes a Determination
February 8, 2007
August 8, 2007
Interconnection (for customer on-site generation)
Commission Begins or Schedules Consideration
Commission Makes a Determination
August 8, 2006
August 8 , 2007
THE FIVE STANDARDS
Net Metering
Section 1251 of the Act states that net metering should be made available to any electric
consumer that the utility serves. It also defines "net metering" clearly so that any net offset has to
apply "during the applicable billing period" in which the consumer s generation is delivered to the
local grid.
The 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
STAFF COMMENTS OCTOBER 27, 2006
net metering to customers generating electricity using solar, wind, hydropower, biomass or fuel cells;
(2) limit the program to 0.10% of their retail peak generation; and (3) limit residential customers to
facilities no greater than 25 kW.
1. A vista. A vista has four residential net metering customers in Idaho that produced
000 kWh during 2005. The Company s net metering tariff (Schedule 63) was most recently
approved August 1 , 2006. Schedule 63 credits excess generation at full retail rates on the customer
next monthly billing.
2. Rocky Mountain Power.Rocky Mountain currently has one residential net metering
customer but has several projects pending. The Company s net metering generation ceiling is
714 kW. The Company s net metering schedule is 135.
3. Idaho Power.Idaho Power has 20 residential customers, 4 small business customers
and 2 large business customers. The 24 smaller customers generated 397 255 kWh in 2005.
The Company has an Application pending to modify its net metering Schedule 84. In Case No.
IPC-06-17 Idaho Power proposes to change the net credit for net metering generation to 85% of the
avoided cost contained in Schedule 84.
Staff Recommendation: The parties generally agree that the utilities' net metering programs
meet the net metering standard. One concern expressed at the workshop was 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. While this
may occur, Staff believes that net metering customers with significant and excess generation have
other rate structures available. For example, Idaho Power customers have the option of participating
under Schedule 86 (Co-generation and Small Power Production Non-Firm Energy). In addition, firm
energy generation customers with qualifying facilities are entitled to published avoided cost rates
under PURP A.
It is also important to note that the three utilities all offer net metering programs under tariffs
not contracts. The Commission is well aware that there is no guarantee that tariff rates will remain
STAFF COMMENTS OCTOBER 27, 2006
unchanged. As Staff noted in its comments in Idaho Power s net metering Case No. IPC-06-, net
metering customers who desire certain fixed rates and terms may wish to consider a QF contract.
In summary, Staff believes that the Commission has already adopted the federal net metering
standard by implementing net metering schedules for the three utilities. The Staff further recognizes
that Idaho Power s proposed changes to its net metering Schedule 84 is currently before the
Commission.
Diversity of Fuel Sources
This standard requires that each utility prepare a plan to minimize dependence on any single
fuel for its generation resources. It also requires that utilities take steps to assure that a diverse range
of fuels and technologies are included in the resource mix, including renewable resources.
Staff asserts that this standard is presently the practice for the applicable electric utilities
serving customers in Idaho. In Order No. 22299, the Commission required Avista, Idaho Power, and
Rocky Mountain Power (or their predecessors) to biennially prepare and file an integrated resource
plan (IRP). Each IRP describes the Company s expectation for load growth and provides an
overview of available resource options, including "conservation resources, demand-side resources
and other potentially low life-cycle-cost resources." Order No. 22299.
A review of the current IRPs reveals that each utility employs a diverse range of generating
resources including renewables. For example, Rocky Mountain s current 2004 IRP reflects the
addition of demand side management (DSM) resources, coal and natural gas thermal generation
combined heat and power generation, wind, geothermal, distributed generation, etc. Notice of Filing,
Case No. P AC-05-2 (June 30, 2005); see also Order Nos. 29614 (Idaho Power) and 29887 (A vista).
The IRP process allows the Commission to review the utilities' planned generation every two years
and thereby be assured that the companies minimize dependence on any single fuel source and that
they employ a diverse array of fuels and technologies, including renewables.
Staff Recommendation: The workshop participants agreed that diversification of generating
fuel sources was evident from review of each utility's resource stack as presented in their IRPs.
Consequently, the Staff believes that the Commission has already implemented this federal standard.
Further action is not necessary.
STAFF COMMENTS OCTOBER 27, 2006
Fossil Fuel Generation Efficiency
The fossil fuel generation efficiency standard relates almost exclusively to the second PURP
goal of "optimal efficiency." Fossil fuel generated electricity used in Idaho is sourced from either
coal or natural gas. All three utilities have fossil fuel (coal and natural gas) generation facilities.
Planning for and increasing the efficiency of existing generating resources is most commonly a part
of general utility practices and a part of the IRP process.
The three utilities assert that addressing expansion and improvements involving fossil fuel
efficiency is already a part of their IRPs. For example, Avista 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 implemented 18 MW of generation efficiency upgrades.
The utilities maintain that the Commission need not take further action on this standard because it has
already been implemented.
Staff Recommendation: Staff agrees with the utilities' assessment that generation efficiency
is part of their respective IRPs. To make generation efficiency more transparent, however, Staff
recommends that the Commission direct that future IRPs explicitly address this issue as part of the
IRP Process.
Smart Metering
This standard requires each utility to make available to each customer class time-based rate
schedules and, upon request, offer each customer a time-based rate schedule. The intent is to
conserve energy and reduce load by providing the tools for the utilities and customers to manage their
energy use and costs through advanced metering, communications technology and sophisticated rate
structures. The standard recognizes that a wide variety of rate structures may be used, including:
Time-of-Use Pricing
Critical-Peak Pricing
Real- Time Pricing
Credits for Load Reduction
As the Commission noted in its Order No. 30146, the utilities have already initiated various
Smart Metering (time-based metering and communications) programs. For example, Avista began
installing Advanced Meter Reading (AMR) devices on all of its Idaho electric and gas meters in 2005
STAFF COMMENTS OCTOBER 27 2006
and expects to complete the change by 2009. Order No. 24602 at 51. 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. Order No. 29959. When
authorizing these Smart Metering programs, the Commission stated that the implementation of the
programs should be prudent and cost effective. A recent Federal Energy Regulatory Commission
(FERC) Staff Report indicated that Idaho ranks fifth (at 16.2%) in the percentage of customers with
advanced metering.
1. Avista. Avista noted that it is in the second year of a four-year deployment of AMR
meters for all of their Idaho customers. The equipment being deployed is AMR capable and was
selected by Avista so that the Company would have options in implementing time-of-use and demand
response practices. The Company has pointed out that, once the AMR installation at the customer
meter is complete, the additions necessary for a "fully" advanced system will all be at the Company
end in the form of software and communications systems. The Company also calculated that adding
the necessary data storage and billing system software would cost approximately $22 million. Id.
Avista indicated in its comments that time-of-use pricing may not be cost-effective for all
customer classes and all customers. In particular, the Company stated that the potential "savings
created by customers shifting their day time demand into the night does not outweigh the cost of
meter installation, software upgrades, and associated operational costs." Avista Comments at 7.
However, Avista did see some advantages by offering time-of-use rate structures to its large industrial
customers.
2. Rocky Mountain Power. Rocky Mountain declared that it currently offers optional time-
of-day service to all residential and distribution voltage customers. The Company has more than
400 residential customers (31 %) and 2 general service customers on time-of-use schedules. It
maintained that its time-of-day service complies with the spirit of the standard. The Company
indicated it was neither achievable nor reasonable to adopt the new standard by February 2007.
Rocky Mountain did agree with the Commission s statement that all Smart Metering programs should
be prudent and cost effective.
STAFF COMMENTS OCTOBER 27 2006
3. Idaho Power.The Company commented that it is steadily deploying Smart Meters so that
the costs of deployment are commensurate with the benefits. The Company reported 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 meters). The Company has
approximately 25 500 AMR meters currently installed. It too noted that it would not be able
implement this standard for all customers by February 2007. The Company s next AMR report on its
pilot is due May 1 , 2007. Order No. 30102.
The Company also offers an Air Conditioner Cycling program (Schedule 81) as an optional
service for eligible residential customers in Ada, Canyon and Gem Counties. By controlling the
residential air conditioners of 40 000 participants, the Company plans to reduce its summer peak
loads by more than 40 MW. The air conditioners are directly controlled by Idaho Power by radio
communications. Order No. 29702.
4. Workshop . In the workshops, representatives of Hunt Technology agreed with the utilities
that there should be specific Smart Metering policies for each utility based upon their distinct
territories and customer base. The participants recognized that Idaho ranks fifth nationally in the
percentage of customers with "advanced meters." If the Commission were to consider greater
deployments of Smart Meters, Hunt suggested that the policy should be guided by consideration of
three issues: (1) what is in the best operational interest of the utility; (2) what is in the best interest of
ratepayers; and (3) what functionalities work for each utility.
Staff Recommendation: As the Commission noted in Order No. 30146, and as set out above
the utilities are in various stages of AMR deployment. The opportunities to conserve energy, reduce
peak demand, and provide customers with the ability to manage their energy use are intrinsic in both
Smart Metering and the use of more sophisticated rate structures suggested by this federal standard.
While the Commission has authorized various Smart Metering programs, Staff does not believe the
Commission should adopt the federal standard at this time for several reasons.
First, Staff agrees with the three utilities that they would be unable to implement AMR within
the time period contemplated by the standard. Even though the FERC staff reported that Idaho ranks
fifth in the percentage of customers with "advanced metering," this statistic may overstate the reality
of the situation. It is unrealistic to assume that the utilities could make time-based metering available
STAFF COMMENTS OCTOBER 27 2006
to all requesting customers by 2007. Second, AMR technology has not fully developed or reached a
state of trouble-free deployment. In the Commission s recent review ofldaho Power s AMR pilot
program, it recognized that "AMR technology is relatively new and is evolving." Order No. 30102 at
6. For example, Idaho Power is still attempting to resolve interface issues in its AMR pilot. Idaho
Power Comments at 12. Given Idaho Power s difficulties in integrating the AMR metering and
communication technologies, the Commission continued the pilot and ordered Idaho Power to submit
another report no later than May 1 , 2007.
Third, Staff agrees with the comments offered by Hunt Technology that AMR deployment
will be different for each utility based upon the characteristics of its loads and customers. As evident
above, each of the three utilities has implemented various AMR programs and is at various stages of
implementation. What works for one utility may not necessarily work for the other electric utilities.
Finally, there is the economy of scale to consider. Staff agrees with A vista that offering every
customer in every customer class time-based rates may not be cost-effective. However, Staff
continues to believe that AMR can offer cost-effective benefits for both the utilities and consumers
alike; the Staff recommends that the Commission continue its measured implementation of AMR.
Staff s comments should not be viewed as opposing AMR deployment. Staff recognizes that
the potential benefits of advanced metering available to ratepayers and the Company are too great to
delay AMR implementation indefinitely." Order No. 29362. Rather, Staff believes that the utilities
should continue to take measured, pro-active steps to implement cost-effective AMR programs.
Therefore, Staff recommends that the Commission should not adopt the federal standard, but instead
continue to work with the utilities in establishing AMR systems and rate structures on a schedule that
benefits both utilities and customers.
In the interest of continued progress in pursuit of cost effective AMR, Staff recommends that
A vista and Rocky Mountain each address Smart Metering deployment in the context of their next
general rate cases.
1) A vista should address the status of its AMR installation program, its cost recovery
proposal and its plans for development of the infrastructure necessary to implement time-
of-use rates, demand response or other appropriate rate structures for its customers or
classes of customers.
STAFF COMMENTS OCTOBER 27 2006
2) Rocky Mountain should address the status of its time-of-use programs, justification for
existing rate differentials and plans for changes or upgrades to advanced metering
including infrastructure necessary to implement time-of-use rates, demand response or
other appropriate rate structures for its customers or classes of customers.
Interconnection
The interconnection standard in Section 1254 of the Act adopts the IEEE Standard 1547 for
interconnecting electric consumers who self-generate and supply their excess energy to the grid. The
standard also proposes to establish standard agreements and procedures for interconnecting to utility
systems using best practices with procedures that are just, reasonable and non-discriminatory. The
federal standard also urges adoption of other model codes issued by state regulatory agencies such as
NARUC's Model Interconnection Procedures and Agreement (the "Model"
In this case, distributed generation refers to a customer s on-site generating facility that may
provide a generation resource (i., interconnects) to the local distribution system as opposed to
connection to the utility transmission system. See Order No. 29260 at 6-7 (comparing net metering
and distributed generation); 42 US.C. ~ 16197(g)(3).
IEEE Standard 1547-2003 (July 2003) is intended to provide uniform standards for
interconnecting a customer s on-site "distribution resource" with the local electric power system. It
provides requirements for the performance, operation, testing, maintenance and safety considerations
of the interconnection. The IEEE standard is further intended to apply to all distributed generation
technologies with aggregate capacity of 1 MW or less at interconnection. The standard does not
define the maximum distributed generation capacity for a particular installation and in fact many
systems of less than 1 MW may require interconnection different than that suggested by IEEE 1547
to assure safety of the system and of other customers. The utilities indicated that they generally have
already implemented this federal standard.
1. A vista. A vista stated that its interconnection requirements are contained in its Schedule
, Part 28 and on its web site. Avista recently amended its tariff to include the adoption oflEEE
Standard 1547. See Order No. 30111 , Case No. A VU-06-4. The Company also suggested the
Commission adopt the NARUC Model as a guideline recognizing that utilities may have particular
STAFF COMMENTS OCTOBER 27 2006
problems with certain elements of the Model. In particular, A vista may have difficulty providing
notice of interruptions seven days in advance.
2. Rocky Mountain Power.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 (OATT) posted on its website. If the Commission
wishes to adopt thresholds for interconnection, then a reasonable breaking point would be 100 kW
and less for net metering. Generators of 100 kW and larger may need additional protections. 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.
3. Idaho Power.Idaho Power indicated that it is in compliance with the federal
interconnection standard except it has not explicitly adopted IEEE Standard 1547. However, it has
proposed to incorporate this standard in Case No. IPC-06-18. Idaho Power s interconnection
policies and practices are contained in its Schedules 72 and 84; in its Best Practices (website), and in
its OATT. Rather than adopting standards for certain sized facilities, Idaho Power currently divides
facilities into small, medium and large interconnecting facilities. Idaho Power supported the NARUC
Model in principle but recognizes that "one size does not fit all." It indicated it will file a new
Schedule 72 (and Schedule 84 for QF) as part of a proposed uniform interconnection agreement this
month in response to FERC's Standards of Conduct.
Staff Recommendation: Staff believes that the utilities generally meet the spirit and intent of
the standard by their inclusion of IEEE 1547 and recommends that the Commission not adopt the
standard. Finally, Staff recommends that the NARUC Model Agreement 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 proj ects and conditions.
STAFF COMMENTS OCTOBER 27, 2006
SUMMARY
1. Staff recommends that the Commission require future IRPs to explicitly address the
issues of fossil fuel efficiency.
2. Staff recommends that the Commission find that it has already implemented the four
standards other than Smart Metering and that further action regarding those four standards is not
required.
Staff recommends that the Commission find that adoption of the Smart Metering standard
is not appropriate at this time, but that the Commission require:
a) Avista to address its AMR installation program and its plans for development of the
infrastructure necessary to implement time-of-use rates, demand response or other
appropriate rate structures for each of its customer classes in its next general rate case.
b) Rocky Mountain to address the status of its time-of-use programs, justification for
existing rate differentials and plans for changes or upgrades to advanced metering.
4. Staff recommends that the NARUC Model Agreement 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.
5. Finally, Staff recommends that the Commission find that the utilities' prior submittals
tariffs, prior Orders and this decision have satisfied all requirements of the Act for current action by
the utilities.
Respectfully submitted this 27
-fJ-.
day of October 2006.
Donald L. Ho 11, II
Deputy Attorney General
Technical Staff: Harry Hall
i: :umisc/comments/gnrtO6,2dhhh
STAFF COMMENTS OCTOBER 27 2006
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 27TH DAY OF OCTOBER 2006
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. GNR-06-, BY E-MAILING A COpy THEREOF TO THE FOLLOWING:
DAVID 1. MEYER
SR VP AND GENERAL COUNSEL
A VISTA CORPORATION
1411 EMISSION AVE, MSC-
SPOKANE W A 99220
KELLY NORWOOD
VICE PRESIDENT - STATE & FED. REG.
A VISTA UTILITIES
1411 EMISSION AVE, MSC-
SPOKANE W A 99220
BARTON L KLINE
MONICA B MOEN
LISA NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
JOHN R GALE
MAGGIE BRILZ
GREG SAID
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
DEAN BROCKBANK
P ACIFICORP
DBA ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2200
SALT LAKE CITY UT 84111
BRIAN DICKMAN
P ACIFICORP
DBA ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
TED S SORENSON
SORENSON ENGINEERING
5203 SOUTH 11 TH EAST
IDAHO FALLS ID 83404
PAM CONLEY
PO BOX 2526
BOISE ID 83701
SCOTT H. DeBROFF
SMIGEL ANDERSON & SACKS
4431 N FRONT ST
HARRISBURG P A 17110
KEN MILLER
ID ENERGY ADVOCATE
NW ENERGY COALTION
5400 W FRANKLIN SUITE G
BOISE ID 83705
DAVID HAWK
DIR. ENERGY NATURAL RES
JR SIMPLOT COMPANY
PO BOX 27
BOISE ID 83702
DAN PFEIFFER
REG. AFFAIRS MANAGER
ITRON
2111 NMOLTERRD
LIBERTY LAKE WA 99019
CERTIFICATE OF SERVICE
PETER J. RICHARDSON
RICHARDSON & O'LEARY
515 N 27TH STREET
BOISE ID 83702
JOHN WEBER
9535 W CORY LANE
BOISE ID 83704
BEN BOYD
VP REGULATORY AFFAIRS
DIST. CONTROL SYSTEMS INC
5430 HICKORY VILLAGE DR.
KINGWOOD TX 77345
J.M -;:u G&..
SECRETARY
CERTIFICATE OF SERVICE