20100805Lobb Direct in Support of Stipulation and Settlement.pdf

BEFORE THE RECEIVED
2010 AUG -5AHIO:i.a
IDAHO PUBLIC UTILITIES COMMISSION IDAHO PUBLIC
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IN THE MATTER OF THE APPLICATION OF )
AVISTA CORPORATION DBA AVISTA ) CASE NO. AVU-E-10..1/
UTILITIES FOR AUTHORITY TO IN:REASE ) AVU-G-10-1
ITS RATES AND CHARGES FOR )
ELECTRIC AND NATURAL GAS SERVICE )IN IDAHO. )
)
)
)
DIRECT TESTIMONY OF RANDY LOBB
IN SUPPORT OF THE STIPULATION
AND SETTLEMENT
IDAHO PUBLIC UTILITIES COMMISSION
AUGUST 5, 2010
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public Utilities
7 Commission as Utili ties Division Administrator.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science Degree in
11 Agricultural Engineering from the University of Idaho in
12 1980 and worked for the Idaho Department of Water Resources
13 from June of 1980 to November of 1987. I received my Idaho
14 license as a registered professional Civil Engineer in 1985
15 and began work at the Idaho Public Utilities Commission in
16 December of 1987. My duties at the Commission currently
17 include case management and oversight of all technical
18 Staff assigned to Commission filings. I have conducted
19 analysis of utility rate applications, rate design,
20 proposed tariffs and customer petitions. I have testified
21 in numerous proceedings before the Commission including
22 cases dealing with rate structure, cost of service, power
23 supply, line extensions, regulatory policy and facility
24 acquisi tions .
25 Q.What is the purpose of your testimony in this
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1 case?
2 A.The purpose of my testimony is to describe the
3 Stipulation (the Proposed Settlement) filed in this case
4 and to explain the rationale for Staff's support.
5 Q.Please summarize your testimony.
6 A.Staff believes that the comprehensive Proposed
7 Settlement resolving all issues in the general rate case
S and agreed to by all parties participating in the
9 settlement process1 is in the public interest, is just and
10 reasonable and should be approved by the Commission.
11 Q.How is your testimony organized?
12 A.My testimony is subdivided under the following
13 headings:
16
Stipulation Overview Page 2
The Settlement Process Page 5
Revenue Increase and DSIT Page 7
Class Cost of Service Page 14
Rate Design Page 17
DSM Prudency page 19
Consumer Issues Page 22
14
15
17
1S
19
20 Stipulation Overview
21 Q.Please provide an overview of the Stipulation and
22 Settlement.
23 A.The Stipulation filed with the Commission
24 1 The Idaho Community Action Network and North Idaho Energy
25 Logs, Inc., as intervenors, were provided notice of the
settlement discussions, but did not participate.
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1 provides for an annual overall increase in electric base
2 revenue of $21.25 million or 9.25%. This increase is
3 partially mitigated for the first two years by using $17
4 million in Deferred State Income Tax (DSIT) credits to
5 offset a portion of the increase.
6 With the credit offset, the first year average
7 net increase for electric service will be $8.25 million or
8 3.59% effective October 1, 2010. The second year increase
9 will be an additional $9 million or 3.92% and the third
10 year increase when all credits are exhausted will be an
11 additional $4 million or 1.74%.
12 The Stipulation provides for an overall increase
13 in natural gas revenue of $1.85 million or 2.62%. This
14 increase is mitigated in the first year by using $500,000
15 in DSIT credits to offset a portion of the increase. With
16 the credit, the first year revenue increase will be $1.35
17 million or 1.9% effective October 1, 2010. The remaining
18 increase of 0.72% will occur in the second year when the
19 credit expires.
20 The Stipulation and Settlement specifically
21 identifies annual power supply cost levels for the Power
22 Cost Adjustment (PCA) mechanism, supports a prudency
23 finding for 2008 and 2009 Demand Side Management (DSM)
24 expendi tures, specifies rate spread to the individual
25 classes and supports increased funding for low income DSM
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1 programs. The Stipulation also addresses accounting
2 treatment for the Coeur d' Alene Tribe Settlement costs,
3 Spokane River Relicensing costs, Colstrip lawsuit costs and
4 Jackson Prairie Storage costs.
5 Finally, the Stipulation provides for workshops
6 and discussion among the parties and the Company on a
7 variety of issues including class cost of service, first
S block residential rate levels, and a variety of other
9 consumer issues.
10 Although the Stipulation represents a
11 comprehensive settlement of all revenue requirement issues
12 in the case, it does not specifically identify revenue
13 adjustments to the Company's case or specify an authorized
14 return on equity (ROE).
15 Q.How does the annual revenue requirement increase
16 for electric and gas service proposed in the Stipulation
17 compare to the increase originally proposed by Avista?
1S A.Avista originally proposed to increase annual
19 electric revenue by $32.114 million or 13. 9S% and increase
20 annual natural gas revenue by $2.575 million or 3.6%. The
21 Stipulated Settlement provides for an increase in annual
22 electric revenue of $21.25 million or approximately 66% of
23 the original request. That increase is further reduced by
24 $13 million for one year and then by $4 million in the
25 second year using the DSIT credits. Instead of paying an
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1 additional $32.114 million from October 1, 2010 to
2 October 1, 2011, electric customers will only pay an
3 additional $8.25 million or 26% of the original request.
4 Through September 30, 2012, customers will pay a total of
5 $25.5 million in additional electric costs or 40% of the
6 $64.228 million that would have been required under the
7 Company's original proposal.
8 The Stipulated Settlement provides for an
9 increase in annual natural gas revenue of $1.85 million or
10 70% of the Company's original request. With the DSIT
11 credit, the first year increase is $1.35 million or 52% of
12 the Company's original request. The Stipulation and
13 Settlement is attached as Staff Exhibit No. 101.
14 The Settlement Process
15 Q.Would you please describe the process leading to
16 the Stipulated Settlement?
17 A.Yes. The Company contacted Staff the week of
18 June 14, 2010 to discuss the possibility of scheduling a
19 settlement workshop. Staff was scheduled to complete its
20 company audit the same week and needed time to review its
21 findings and develop its revenue requirement
22 recommendations for hearing. Staff positions on cost of
23 service, rate design and consumer issues were already well
24 developed.
25 All parties were invited to attend or participate
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1 by phone in the settlement workshops on July 6 and July S
2 in the Commission hearing room. Parties participating in
3 both workshops included Commission Staff, Avista,
4 Clearwater Paper Company, the Community Action Partnership
5 Association of Idaho (CAPAI), the Idaho Conservation League
6 and the Snake River Alliance. Idaho Forest Group only
7 participated in the second workshop.
S Settlement discussions were dominated by revenue
9 requirement issues with additional discussions on other
10 issues such as cost of service, rate design, low income
11 weatherization funding and other customer service
12 commitments. Revenue requirement discussion was framed by
13 the electric and natural gas service increases proposed by
14 the Company and the preliminary increase recommendation of
15 Staff for electric service of approximately $16.4 million
16 or 51% of the Company's proposal and for natural gas
17 service of $792,000 or 31% of the Company's original
1S proposal.
19 At the July 6, 2010 workshop the Company first
20 proposed using $17.5 million in DSIT credits to mitigate
21 the electric and gas service increases. Based on these
22 revenue requirement positions and the positions of the
23 parties on various other issues, negotiations ensued and
24 the Stipulated Settlement was reached.
25 Q.How did the Commission Staff evaluate the
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1 Stipulated Settlement to determine that it was reasonable?
2 A.In this case as in other past general rate cases,
3 Staff evaluated the merits of the Stipulated Settlement by
4 comparing it to the expected outcome if the case proceeded
5 to hearing. In other words, Staff had to determine which
6 process would result in the best deal for customers. In
7 Staff's view, the best deal for customers is the lowest
S justifiable annual revenue requirement.
9 While the Commissioners make the ultimate
10 decision on Company revenue requirement based on the record
11 at hearing, it is the parties to the case that make revenue
12 requirement adjustment recommendations on the record for
13 the Commission to decide. The outcome at hearing in terms
14 of revenue requirement must therefore be evaluated based on
15 both the adjustments to the Company's revenue request that
16 are presented on the record and how the Commission might
17 decide each adjustment.
1S Revenue Increase and DSIT
19 Q.What type of adjustments to the Company's
20 proposed revenue requirement had Staff identified and what
21 was the dollar value of those adjustments?
22 A.As previously indicated, Staff's preliminary
23 estimate of downward adjustments to the Company's proposed
24 electric revenue increase of $32.114 million totaled
25 approximateiy $15.7 million (a $16.4 million, 7.1%
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1 increase) and approximately $1.78 million (a $792,000,
2 1.12% increase) on the natural gas service side. The big
3 ticket issues identified by Staff for electric service
4 included: an annual reduction in power supply costs of $6.8
5 million; a reduction in Return On Equity (ROE) to 10% for
6 an annual revenue reduction of $4.3 million; elimination of
7 all salary increases back to January 1, 2009 for a revenue
8 reduction of $1.35 million, elimination of Lancaster
9 transmission wheeling expense of $1.6 million; and
10 elimination of working capital of $1.26 million. The
11 remaining identified reduction of $550,000 in annual
12 revenue consisted of 10 other individual adjustments.
13 On the natural gas side, Staff adjustments for
14 ROE, salaries and removal of Jackson Prairie storage costs
15 represented $1.5 million of the total identified revenue
16 requirement reduction of $1.78 million.
17 Q.How confident was Staff that its adjustments
18 could be justified on the record and accepted by the
19 Commission upon hearing?
20 A.Staff took a very aggressive approach to
21 developing its revenue requirement adjustments in
22 preparation for testimony and in preparing for settlement
23 negotiations. It is unlikely that all of the preliminary
24 adjustments presented by Staff in negotiations would have
25 survived ongoing review to be presented at hearing and it
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STAFF
1 is unlikely that all of the adjustments presented at
2 hearing would have been accepted by the Commission.
3 For example, Staff proposed eliminating 90% of
4 the wheeling costs associated with the Lancaster power
5 plant. These costs are actually incurred by Avista to
6 wheel Lancaster power through Bonneville Power
7 Administration's (BPA) system to Avista's service
S terri tory. While a reasonable argument could have been
9 made to reduce the costs, it is questionable whether all of
10 the recommended reduction would have been accepted.
11 In addition, Staff had to further develop
12 justification to support the level of proposed reductions
13 in salaries, ROE and working capital before it was
14 presented in testimony. Company rebuttal at hearing could
15 have presented arguments that some or all of the reductions
16 were unjustified. On the gas service side, Staff would
17 have had to offset the proposed revenue requirement
1S reduction for removal of Jackson Prairie storage with
19 benefits included in the Company's case that resulted from
20 the addition of low cost natural gas storage.
21 Finally, Staff could not ignore the $17.5 million
22 in DSIT benefits offered by the Company as part of the
23 settlement. Given the complicated nature of the accrual
24 and the difficulty in identifying the level of tax benefits
25 already returned to customers, Staff was not confident that
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1 it could justify this level of credit to customers at
2 hearing.
3 Q.How were the DSIT benefits derived and why are
4 they now available to offset the present rate increase?
5 A.The deferred state income taxes are booked when
6 there is a difference between the state income taxes paid
7 and the amount reflected on the Company's books. When
S taxes and benefits are flowed through to customers, no DSIT
9 is booked. When taxes and benefits are normalized, DSIT is
10 booked.
11 Under normalization, the differential is then
12 distributed to customers over the life of the assets.
13 Federal and State tax laws usually dictate when
14 normalization must occur. There are other accounting areas
15 where the Company may elect to use either the flow-through
16 method or the normalization method. This election once
17 made is followed unless properly changed. The DSIT amounts
1S discussed here are a result of Idaho taxes. No Federal or
19 Washington State amounts are at issue.
20 Avista originally flowed these items through but
21 changed to normalization when deregulation was being
22 explored by many entities, both companies and commissions.
23 Due to the timing of rate cases, not all DSIT reflecting
24 the normalization methodology was included in rates. In
25 the last general rate cases, Case Nos. AVU-E-09-1 and
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1 AVU-G-09-1, the Company used the flow-through method for
2 state income tax. With that change in accounting
3 treatment, deferrals would not be booked. That left the
4 DSIT balance of approximately $11 million on the books with
5 a portion of those benefits belonging to customers. Avista
6 offered the full amount of $17.5 million ($11 million
7 grossed-up for taxes) as rate mitigation in the Settlement.
S Q.Would all of the DSIT benefits used to mitigate
9 the rate increase in settlement have been available to
10 customers if this case had gone to hearing?
11 A.No. Staff believes that for a period of time
12 DSIT was booked at a different level than was reflected in
13 rates. In other words, customers actually received more
14 tax benefits during the period than are reflected in the
15 booked DSIT. Therefore, it could be demonstrated that the
16 Company rather than customers is entitled to a larger
17 portion of the $17.5 million DSIT.
1S Unfortunately, the mismatch in booked tax versus
19 the ratemaking treatment over time makes it nearly
20 impossible to accurately determine the exact allocation
21 between customers and shareholders of the $11 Million
22 ($17.5 million after tax gross-up) total DSIT booked during
23 the period. It would require extensive study to track the
24 actual amounts normalized in each case especially when
25 there was a settlement or the amount is not shown in the
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1 rate casé orders. Not only would it be time consuming and
2 costly but the result could be subj ect to dispute. The
3 Stipulated Settlement credits all of the DSIT to customers
4 for maximum benefit .
5 Q.Did any other party to the case indicate intent
6 to address the Company proposed revenue requirement in the
7 rate case?
S A.One party indicated that it might address
9 appropriate ROE for the Company. Other than that, no
10 parties planned to address revenue requirement issues.
11 Q.Why are a new return on equity and other specific
12 revenue requirement adjustments not specified in the
13 Stipulation?
14 A.Specific adjustments and ROE were not specified
15 in the Stipulation to facilitate agreement on the overall
16 revenue requirement. While the settlement parties
17 generally agreed on a reasonable level of revenue, there
1S was stark disagreement on the individual adjustments
19 proposed to reach that revenue level. This was
20 particularly true with respect to ROE. Rather than specify
21 an ROE that all parties could not support, the Stipulation
22 simply specified an overall revenue requirement that could
23 be fully supported.
24 Q.Is the Company precluded from filing general rate
25 cases over the next three years?
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1 A.No. However, the issue of a rate case moratorium
2 was discussed during negotiations. While Staff was
3 concerned over the potential for multiple base rate
4 increases in a single year and requested a moratorium as
5 part of the Settlement package, it was not included in the
6 final Stipulation. In exchange for the moratorium, the
7 Company required an additional increase in revenue
S requirement that Staff and other parties were unable to
9 support. The moratorium condition was therefore dropped in
10 lieu of a lower overall revenue increase in this case.
11 Q.Could you please summarize why Staff supports the
12 revenue requirement portion of the Stipulation?
13 A.Yes. Staff maintains that the combination of
14 reduced base rate revenue requirement and the use of DSIT
15 benefits to mitigate the increases as specified in the
16 Stipulation is a better deal for customers than could have
17 been achievable through hearings. Staff's best case
1S scenario would have resulted in additional revenue of
19 approximately $32.7 million over two years ($16.34 million
20 each year), if all Staff adjustments proposed at settlement
21 were accepted by the Commission. The Stipulated Settlement
22 specifies additional electric revenue of $25.5 million over
23 the two year period ($S. 25 million in year one and 17.25
24 million in year two) .
25 Given that neither Staff nor any other party had
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1 identified any DSIT benefits available to customers prior
2 to settlement discussions, it is unclear how thoroughly
3 this information could have been reviewed before prefiled
4 direct testimony was due. Based on a preliminary review by
5 Staff, it appears that over half of the $17.5 million DSIT
6 might not have been normalized in rates so effectively may
7 have already been flowed through to customers in past
S electric and natural gas rates. In any case, the amount of
9 the DSIT available to customers would be subj ect to dispute
10 at hearing. However, with the Stipulated Settlement
11 customers receive the full $17.5 million of the DSIT
12 benefit.
13 Class Cost of Service
14 Q.Please describe the Stipulated Settlement with
15 respect to electric customer class cost of service and
16 revenue spread among classes.
17 A.The Stipulation does not accept the Company's
1S originally proposed class cost of service study but uses a
19 less modified version of the cost of service study last
20 approved by the Commission. The parties then agreed to
21 move all classes one quarter of the way to "full" cost of
22 service as proposed in the Company's original application.
23 Q.What was the cost of service modification and
24 what was its impact?
25 A.The cost of service study originally submitted by
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1 the Company in this case showed that several customer
2 classes were below cost of service including the
3 residential class and several classes were above cost of
4 service. The Company then proposed that all customer
5 classes be moved one quarter of the way to "Full" cost of
6 service. This means that once the overall revenue
7 requirement increase is determined, those classes below
S cost of service would receive a larger portion of the
9 increase and those above cost of service would receive a
10 smaller portion of the increase.
11 The cost of service methodology initially
12 proposed by the Company deviated from previously accepted
13 cost of service methodology in three significant ways. It
14 proposed a unique approach to the peak credit
15 classification of production costs as energy or demand
16 related; it classified all transmission costs as demand
17 related instead of a split between demand and energy; and
1S it used seven coincident peaks instead of all twelve
19 monthly coincident peaks in formulating the major demand
20 allocator. All of these proposed changes benefitted large,
21 high load factor customers or customer groups.
22 The Company proposed the cost of service changes
23 to benefit these customers because the Company observed
24 that they were struggling in today's economy. Several
25 large customers had down-sized and at least one had gone
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1 out of business. Staff observed that when costs are
2 shifted away from large customers they are shifted to the
3 other customer classes including the residential class, all
4 of whom are also experiencing the downturn in the economy.
5 In settlement, Staff accepted the classification that all
6 transmission costs be demand related only because it is a
7 more common cost of service practice.
S The overall effect of settlement on cost of
9 service is an increase in the cost responsibility of the
10 residential class over what would have been allocated under
11 previously approved cost of service methodology, but a
12 lower allocation than that originally proposed by the
13 Company.
14 All parties agreed that the one quarter move to
15 full cost of service as originally proposed by the Company
16 was reasonable. Staff recognizes that this relatively
17 small move leaves some substantial room for movement in
1S future cases.
19 Q.Did the parties agree to evaluate electric cost
20 of service prior to the next Avista general rate case?
21 A.Yes. The parties agreed as part of the
22 Stipulation to convene a public workshop to discuss the
23 possibility of revising the peak credit method of
24 classifying production costs. Possible revisions include
25 the monthly production cost weightings (12cp vs. 7cp) and
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1 allocation of transmission costs.
2 Q.What did the parties agree to with respect to
3 natural gas cost of service?
4 A.The parties agreed to accept the Company's
5 proposed cost of service methodology and move all classes
6 60% toward full cost of service except for transportation
7 service which will be moved fully to cost of service.
S Staff supported this position because the methodology was
9 previously approved by the Commission and class increases
10 required to achieve 60% of full cost of service were all
11 within a reasonable range. Staff also supported a full
12 decrease in transportation rates to provide a more accurate
13 price signal reflecting cost of service for that class.
14 Ra te Design
15 Q.The Stipulation provides for an increase in the
16 monthly electric residential customer charge. Why does
17 Staff support the increase?
1S A.The Company originally proposed to increase the
19 monthly electric and natural gas customer charges from the
20 current $4. 60/month to $6. 75/month and from $4. OO/month to
21 $6.75/ month, respectively. The Stipulation limits the
22 increase in the electric customer charge to $0. 40/month
23 from the current $4.60/month to $5.00/month. No change in
24 the monthly natural gas customer charge is proposed in the
25 Stipulation.
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1 Staff supported the limited customer charge
2 increase as part of a negotiated settlement and to
3 recognize the increased investment made by the Company to
4 install more sophisticated automated meters.
5 Q.Are there any other rate design changes specified
6 in the Stipulation?
7 A.No. The residential energy rate differential for
8 electric energy consumption between the first and second
9 block will not change from the differential that currently
10 exists. This is consistent with the Company's original
11 proposal and provides a reasonable spread between the first
12 and second blocks in Staff's opinion. The Stipulation does
13 include a provision to convene a public workshop prior to
14 the Company's next general rate case to discuss the
15 appropriate threshold between the size of the first tier
16 and second tier energy blocks for residential electric
17 service. Staff welcomes such a discussion.
18 Q. What are the new first year residential energy
19 rates and what is the impact on customer bills?
20 A.The base residential energy rates will increase
21 from $0. 0695/kWh to $0. 07775/kWh for the first 600 kWh per
22 month and from $0. 07867/kWh to $0. 08691/kWh for energy use
23 above 600 kWh per month. The differential between the
24 first and second block rate is maintained at $0. 0092/kWh.
25 The first year base energy rates with the DSIT credit is
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1 $0. 0735/kWh for the first 600 kWh per month and $0. OSlS/kWh
2 for energy use above 600 kWh per month. The residential
3 rate impact of the proposed Stipulation and Settlement is
4 shown on Staff Exhibit No. 102.
5 Natural gas rate changes for all customer classes
6 are shown on page 7 of Attachment B to the Stipulation and
7 Set tlement .
S DSM Prudency
9 Q.The Stipulation in this case includes an
10 agreement that Avista' s demand side management (DSM)
11 expenses in 200S and 2009 were prudently incurred for the
12 benefit of its Idaho customers. What are the costs
13 associated with DSM for those two years?
14 A.The testimony filed by Avista does not state
15 Idaho-specific DSM costs, but the Company's 200S and 2009
16 DSM annual reports contain this information. Table 14 (EG)
17 in the 200S report indicates that $4,079,015 was spent for
lS DSM funded by Idaho electricity customers and that
19 $2,143, 3S0 was spent for DSM funded by Idaho natural gas
20 customers. Similarly, Tables 11 and 12 in the 2009 report
21 show Idaho electricity-funded DSM costs of $5,335,909 and
22 $2, 46S, 52S of costs funded by Idaho natural gas customers.
23 Total DSM expenditures in Idaho for 200S and 2009
24 were $9,414,924 funded by electricity customers and
25 $4,611, 90S funded by natural gas customers.
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1 Q.How will the approximate $14 million spent by
2 Avista for DSM programs affect electric and natural gas
3 rates?
4 A.DSM costs will have no direct effect on tariffed
5 energy rates because Avista's electricity and natural gas
6 DSM programs are funded through energy efficiency tariff
7 riders, Schedules 91 and 191 , respectively. Indirectly,
8 however, prudent and cost-effective DSM programs, by
9 definition, reduce the total of all bills paid by Avista's
10 customers. In short, while customers do pay for Avista' s
11 DSM programs through the energy efficiency tariff riders, a
12 prudency finding for past expenses will not affect the base
13 rates under consideration in this case.
14 Q.Why does Staff support a prudency finding for
15 200S/2009 DSM expenditures as part of the settlement in
16 this case?
17 A.Staff believes that Avista's DSM efforts in 200S
18 and 2009 were generally reasonable and cost-effective and
19 that sufficient progress is being made toward improving the
20 processes and transparency of its program evaluations.
21 In last year's rate case (AVU-E-09-01 and AVU-G-
22 09-01), the Staff recommended that Avista's request for a
23 prudency finding of its January through November 200S DSM
24 costs be deferred "... until such time that the Company is
25 able to provide more comprehensive evaluations of its DSM
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1 programs and efforts." After the conclusion of that case,
2 the Staff convened a DSM evaluation workshop with Avista
3 Utilities, Idaho Power Company and Rocky Mountain Power.
4 The outcome of the workshop was a Memorandum of
5 Understanding (MOU) signed in December 2009 by Staff and a
6 representative of each of the three utilities. The MOU
7 included evaluation and reporting prerequisites that will
8 allow Staff to evaluate DSM prudency requests by the
9 utilities. Because the MOU agreement was not reached until
10 the end of 2009, it contained language indicating Staff
11 would allow reasonable leniency for reporting DSM program
12 evaluations through 2009. The MOU also contained specific
13 language allowing Avista Utilities to re-file its 2008 DSM
14 prudency request without Staff opposition.
15 Q.Please describe Avista' s progress in its DSM
16 evaluation and reporting since the MOU was signed.
17 A.As a result of the Commission deferring Avista's
lS request for a DSM prudency finding in Case Nos. AVU-E-09-01
19 and AVU-G-09-01, the aforementioned MOU, and similar DSM
20 evaluation questions being raised in a Washington Utilities
21 and Transportation Commission docket, Avista formed a
22 collaborative process to examine DSM evaluation and low-
23 income program issues. As part of this effort, the Company
24 has been diligently working on a comprehensive DSM
25 Evaluation, Measurement and Verification (EM&V) Framework
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1 for review by collaborative members, including the IPUC
2 Staff. The Company has contracted with nationally-
3 respected DSM evaluation experts to improve its own
4 understanding as well as the collaborative's understanding
5 of evaluation best practices. The Company recently
6 reorganized its DSM group to further separate DSM
7 evaluation, policy and planning from DSM implementation.
S Finally, the Company's Energy Efficiency Annual Report
9 filed on April 1, 2010, which shows 2009 DSM performance,
10 is much more detailed than its former "Triple-E" reports.
11 In short, although Avista's DSM evaluation and reporting
12 are not yet at the level anticipated by the MOU, and Staff
13 has suggested further refinements as part of its comments
14 in Case No. AVU-G-10-02, the Company appears to be making
15 reasonable progress toward addressing remaining
16 insufficiencies. Thus Staff is exercising the "reasonable
17 and necessary leeway" during transition years as
lS contemplated by the MOU. The MOU is attached as Staff
19 Exhibit No. 103.
20 Consumer Issues
21 Q.Could you please describe the basis of Staff's
22 support for the Service Commitments described in Section 16
23 (c) of the Stipulation?
24 A.Yes. The Company has agreed to address several
25 areas of concern to Staff. Perhaps most important with
CASE NOS. AVU-E-10-1/AVU-G-10-1
OS/05/10 LOBB, R. (Di) 22
STAFF
1 respect to rate impact, the Company has committed to review
2 its policies and address in its next general rate case the
3 appropriateness of charging for services it now provides
4 wi thout charge to customers or other parties, e. g. ,
5 establishing new accounts or managing tenant/landlord
6 accounts. The Company also will re-examine its existing
7 non-recurring charges to determine whether those amounts
S cover a reasonable portion of the Company's current cost to
9 provide those services. Staff believes it is prudent to
10 re-examine the cost of providing non-recurring or on-going
11 services, particularly where those services are
12 discretionary and are clearly linked to a particular
13 customer or third-party rather than customers in general.
14 Appropriately pricing such services more closely aligns
15 costs with benefits and reduces the upward pressure on
16 rates.
17 The Company has agreed to use its best efforts to
18 meet or exceed its current service level standard (the
19 percentage of calls answered within a defined number of
20 seconds) as established by the Company. Utili ties must be
21 accessible to customers, and an important measure of that
22 accessibility is how promptly calls from customers are
23 answered. Staff has expressed concerns in the past about
24 both the Company's service level standard (SO% of calls
25 answered within 60 seconds) and the Company's performance
CASE NOS. AVU-E-10-1/AVU-G-10-1
OS/05/10 LOBB, R . (D i) 23
STAFF
1 in reaching the goals it has set for itself. Given
2 Avista's target, which should be readily achievable, Staff
3 believes it is necessary that the Company focus its
4 attention on improving its performance in this area.
5 Avista has agreed to hold at least five energy
6 conservation workshops for senior citizens in different
7 Idaho communities prior to December 31, 2011. This program
8 is targeted to seniors who might find themselves in tight
9 financial situations that cause them to reduce their use of
10 space heating in order to cut monthly bills. The primary
11 goal of the workshops is to provide education on how to
12 conserve energy without compromising comfort, health, and
13 safety. This program has been offered in Washington, but
14 not in Idaho. The Company previously indicated to Staff
15 that it would implement the program in Idaho in 2009, but
16 that did not occur.
17 The Company has agreed to begin tracking and
lS reporting to the Commission monthly data regarding customer
19 credit activity. Staff is in the process of developing a
20 database to track residential customer arrearages, service
21 disconnections, and reconnections. The data will enhance
22 Staff's ability to more promptly identify and respond to
23 credit-related issues and more fully inform the Commission
24 on issues related to future policy development.
25 The Company has also agreed to actively manage
CASE NOS. AVU-E-10-1/AVU-G-10-1
OS/05/10 LOBB, R. (Di) 24
STAFF
1 the Low Income Weatherization and Low Income Energy
2 Conservation Education Programs to assure that the stated
3 goals and obj ecti ves of these programs are achieved and
4 that costs associated with these programs are prudently
5 incurred. Consistent with the terms of the DSM prudency
6 MOU mentioned above, Staff believes these customer-funded
7 programs need to be actively managed, not merely
8 underwritten.
9 Q.Would you please explain Staff's support for
10 additional funding for low income weatherization and low
11 income DSM education?
12 A.Yes. Staff agreed to an increase in low income
13 weatherization funding and additional funding for low
14 income education programs in an effort to continue
15 improvement in energy affordability. The increase in low
16 income weatherization and education funding helps fill a
17 growing need for programs that assist customers in reducing
18 their monthly bills. They also save energy and help to
19 reduce Company uncollectible billings to the benefit of all
20 customers. With the Company's improved commitment to
21 program oversight, Staff anticipates that the cost
22 effectiveness of these programs will improve.
23 Q.Has the Company agreed to work with Staff to
24 address some of the other concerns it has raised?
25 A.Yes. In coordination with Staff, Avista will
CASE NOS. AVU-E-10-1/AVU-G-10-108/05/10 LOBB , R . (D i ) 2 5
STAFF
1 develop and conduct a study on its deposit policy and
2 practices with respect to residential customers. Among the
3 obj ecti ves of the study would be to determine if current
4 deposit policy correctly identifies customers who pose a
5 credit risk to the Company, encourages customers who pose a
6 credit risk to improve payment habits, and reduces the
7 amount of credit and collection acti vi ty as well as bad
S debt associated with those customer accounts. An earlier
9 deposit study independently conducted by Avista fell short
10 of Staff's expectations and the hope is that a more
11 collaborative approach will answer key questions about the
12 efficacy of collecting deposits, particularly with respect
13 to influencing individual customers' payment behavior.
14 The Company also will work with Commission Staff
15 to address Staff's concerns about Avista's policies and
16 practices with respect to:(a) opening and closing
17 customer accounts and (b) offering term payment
18 arrangements to customers. Staff has identified several
19 issues that fall under these two topics that require
20 further discussion in order to more fully resolve. Given
21 its positive working relationship with Avista and the
22 Company's commitment in this case, Staff expects to be able
23 to reach resolution on these issues.
24 Q.Does this conclude your direct testimony in this
25 proceeding?
CASE NOS. AVU-E-10-1/AVU-G-10-1
OS/05/10 LOBB, R. (Di) 26
STAFF
1 A.Yes,it does.
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CASE NOS. AVU-E-10-1/AVU-G-10-1
OS/05/10
LOBB , R . (D i) 27
STAFF
David J. Meyer, Esq.
Vice President and Chief Counsel of
Reguatory and Governental Affairs
A vista Corporation
1411 E. Mission Avenue
P.O. Box 3727
Spokane, Washington 99220
Phone: [phone], Fax: [phone]
.. \ ,.-..RC"';.' ,i""';,..L-e-\ .. ,,"
inin JUl21 l\~ iO:32
Donald L. Howell, II
Krstine Sasser
Deputy Attorneys General
Idaho Public Utilities Commssion Staff
P.O. Box 83720
Boise, ID 83720-0074
Phone: [phone], Fax: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
IN TH æR OF TH APPLICATION
OF A,VISTA ORPORATION FOR TH
AUTO TO INCREASE ITS RATES
AN CHA ES FOR ELECTRC AN
NATU ÒAS SERVICE TO ELECTRC
AN NATU GAS CUSTOMERS IN
TH STATE OF IDAHO
)
) CASE NOS. AVU-E-10-0l
) AVU-G-1O-01
)
)
) STIPULATION AN SETTLEMENT
)
)
This Stipulation is entered into by and among A vista Corporation, doing business as A vista
Utilities ("Avista" or "Company"), the Staff of the Idaho Public Utilties Commission ("Staff),
Clearater Paper Corporation ("Clearater"), Idaho Forest Group, LLC ("Idaho Forest"), the
Communty Action Parership Association of Idaho ("CAP AI"), the Snake River Alliance ("Snake
River"), and the Idaho Conseration League ("Conservation League"). These entities are
collectively refered to as the "Paries," and represent all pares in the above-referenced cases that
Exhibit No. 101
Case Nos. A VU-E-1 0-0 l/AVU-G-lO-O 1
R. Lobb, Staff
8/05/1 0 Page 1 of 31
STIPULATION AN SETTLEMENT - A VU-E/G-10-01 Page 1
paricipated in settlement discussions. i The Paries understand this Stipulation is subject to approval
by the Idaho Public Utilties Commission ("IPUC" or the "Commission").
I. INTRODUCTION
1. The terms and conditions of ths Stipulation are set fort herein. The Pares agree
that ths Stipulation represents a fair, just and reasonable compromise of all the issues raised in the
proceeding and that this Stipulation and its acceptance by the Commission represent a reasonable
resolution of the multiple issues identified in this Stipulation. The Paries, therefore, recommend
that the Commission, in accordance with RP 274, approve the Stipulation and all of its ters and
conditions without materal change or condition.
II. BACKGROUN
2. On March 23, 2010, Avista fied an Application with the Commission for authority
to increase revenue from electrc and natual gas serce in Idaho by 14% and 3.6%, respectively. If
approved, the Company's revenues for electrc base retal rates would have increased by $32.1
milion anually; Company revenues for natual gas service would have increased by $2.6 milion
anually. The Company requested an effective date of Apri123, 2010 for its proposed
electrc/natual gas rate increase. By Order No. 31038, dated April 9, 2010, the Commission
suspended the proposed schedules of rates and charges for electrc and natural gas serce for a
period of thirty (30) days plus five (5) months, from April 23, 2010, until such time as the
Commssion enters an Order accepting, rejecting or modifyg the Application in ths matter.
3. Petitions to interene in ths proceeding were filed by Clearater, Idaho Forest,
CAP AI, the Idaho Conseration League, the Idaho Communty Action Network ("ICAN"), Snake
River, and Nort Idaho Energy Logs. By varous order, the Commssion granted these
interentions. See, IPUC Order Nos. 31041, 31052, 31054, 31058, 31068, 31069 and 31070.
i The Idaho Communty Action Network and Nort Idao Energy Logs, Inc., as intervenors, were provided notice of the
settement discussions, but did not parcipate.
STIPULATION AN SETTLEMENT-AVU-E/G-10-01 Exhibit No. 101 ,Page 2
Case Nos. A VU-E-1 0-0 l/A VU-G-10-01,
R. Lobb, Staff
8/05/1 0 Page 2 of 31
4. Public workshops for Avista customers were held on June 28, 2010, in Lewiston,
Idaho, and on June 29, 2010, in Coeur d'Alene, Idaho, for the purose of explainng the Company's
Application, and in order to provide an opportty for customers to ask questions of Staff. No
customers attended the workshop in Lewiston, and approximately five customers attended in Coeur
d' Alene. Settlement conferences were subsequently noticed and held in the Commission offces on
July 6 and 8, 201 0, and were attended by signatories to this Stipulation. Furher public customer
hearngs have yet to be scheduled. The techncal hearng was previously scheduled to begi on
September 22, 2010. The Paries' request to modify the procedural schedule will be the subject of a
separate Motion.
5. Based upon the settlement discussions among the Paries, as a compromise of
positions in ths case, and for other consideration as set fort below, the Pares agree to the
following terms:
III. TERMS OF THE STIPULATION AND SETTLEMENT
6. Overiew of Settlement and Revenue Requirement. The Pares engaged in
productive settlement discussions in the conferences on July 6 and 8, 2010. The Paries agree that
A vista should be allowed to implement revised taff schedules designed to recover $21.25 milion
in additional anual electrc revenue and $1.85 milion in additional anual natual gas revenue,
which represent a 9.25% and 2.62% increase in electrc and natual gas anual base tarff revenues,
respectively. However, these increases are offset by a rate impact mitigation plan discussed below
resulting in a 3.59% increase in electrc and a 1.9% increase in gas revenues.' New electric and
natual gas rates would become effective October 1,2010.
The Paries agree that ths settlement is not contingent upon any specific
methodology for individual components of the revenue requirement deterination, but all Pares
support the overall increase to the Company's revenue requirement, and agree that the overall
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101 Page 3
Case Nos. A VU-E-10-0l/A VU-G-10-01
R. Lobb, Staff
8/0~/1 0 Page 3 of 31
increase represents a fair, just and reasonable compromise of the issues in this proceeding and that
this Stipulation is in the public interest.
7. Rate Impact Mitigation Plan. The electrc rate impact to customers wil be phased-in,
beginning on October 1, 2010, over thee years, resulting in a 3.59% increase October 1, 2010, a
3.92% increase on October 1,2011, and a 1.74% increase on October 1,2012, after givig effect to
a two-year amortization of$17 milion of Deferred State Income Tax (DSIT) refud which is being
credited to electrc ratepayers to mitigate the rate impact. The table below ilustrates ths rate
mitigation plan in more detaiL.
ELECTRC RATE IMPACT MITIGATION PLAN
Revenue Increase of $21.25 millon or 9.25%, partially offset by the amortiation of DSIT over 2 years.
Year 1
(October 1,2010)
Year 2
(October 1,2011)
Year 3
(October 1,2012)
Less - Prior Increase
$21.25 mion,9.25%$21.25 nullon 9.25%$21.25 mion 9.25%
$13.00 miion 5.66%$4.00 nullon 1.74%$0.00 mion 0.00/0
$0.00 mion i 0.00/0 ;$8.25 mion!3.59%,$17.25 mion:7.51%
,,;,~.,-._~." 'o~ ,,.,,__,,...~,,_'"'~ -_."-" ,-"~,,,,~'--.-+r""""'-'-""
Total Increase
Less - DSIT Credit
"",._n'" .~.~_~~ ,w_""",,,~.,,,,,,._,~",~._._.,...,,.... ;..,.."."~,.,."..,._ ,.__,,,.. .,"L..., "",_,,'m~,"'___ --"~"
Net Increase to
Customers $8.25 millonl 3.59% $9.00 millon; 3.92% $4.00 millon¡ 1.74%
The DSIT reflected on the Company's balance sheet totals approximately $11.1
milion, and when adjusted for the effect of the revenue converion factor of 0.63676, totals
approximately $ i 7.5 milion, representing normalization of state income taxes for a period of years.
As par of ths mitigation plan, the Paries agree to credit $ i 7 milion of the DSIT to electrc
customers over two years to help offset the rate impact, and $0.5 milion for one year to help offset
a portion of the first year natual gas rate increase (thereby reducing the first year impact from 2.6%
to 1.9%). The Company wil record regulatory liabilties in Account 254 to account for the $17
milion electrc and $0.5 milion gas DSIT refuds, and wil record deferrals for the associated
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101 Page
4
Case Nos. A VU-E-10-01/A VU-G-10-01
R. Lobb, Staff
8/05/10 Page 4 of31
revenue related expenses and defered federal income ta. The deferral amounts will be amortzed
as the refuds are passed on to customers. The Company will fie, with its compliance filing, tarff
schedules 099 (electrc) and 199 (natual gas) which wil be used to pass the DSIT credit back to
customers.
8. Recovery of Lancaster Costs. In Case No. A VU-E-09-01, a settlement was reached
in which the purchase of the output from the Lancaster combined-cycle generating plant was found
to be reasonable with the recovery of the fixed and varable costs though the PCA. Those costs
have now been incorporated into the base revenue requirement in this case.2
9. PCA Authorized Level of Expense. The new level of power supply expense, retail
load and Clearater Paper generation, and retail revenue credit rate resulting from the settlement
revenue requirement for puroses of the monthly PCA mechansm calculations, are detaled in
Attachment A.
10. Prudence of Energy Effciency Expenditues. The Pares agree that Avista's
expenditures for electrc and natual gas energy effciency programs from Januar 1, 2008 though
November 30, 2008, and from December 1, 2008 through December 31, 2009 are prudent and
recoverable.
11. Cost of Service. As par of this rate case, the Company prepared an analysis of using
a peak credit method of classifyng production costs, allocating 100% of transmission costs to
demand, and allocating transmission costs to reflect any peak and off-peak seasonal cost differences
over seven months, rather than assuming an equal weighting over twelve months. The Paries agree
to take into account, for puroses of rate spread in ths proceeding, the allocation of 100% of
transmission costs to demand. The Paries have otherise agreed to exchange information and
convene a public workshop, prior to the Company's next general rate case, with respect to the
2 The Lacaster power plant is a 275 MW gas-fied combined cycle combustion tubine located in Rathdr, Idao.
Avista Utilities will purchase all of the output of the plant though 2026.
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101 Page 5
Case Nos. A VU-E-1 0-0 l/AVU-G-1 0-0 1
R. Lobb, Staff
8/05/1 0 Pa~e~ of31
possible use of a revised peak credit method for classifyng production costs, as well as
consideration of the use of a 12 CP (whether "weighted" or not) versus a 7 CP or other method for
allocating transmission costs.
The Paries have also agreed to move all electrc rate schedules approximately 25%
toward unity (except for the Street and Area Lighting Schedules, which wil receive a percentage
increase equal to the overall increase in revenue requirement). The following table shows the
relative rates of retu after giving effect to the foregoing adjustments.
3
ELECTRC PRESENT & PROPOSED RELATIVE RATES OF RETUR
Residential Schedule 1
General Servce Schedule 1 i
Large General Servce Schedule 21
Ex Lage General Servce Schedule 25
Clearater Paper Schedule 25P
Pumping Service Schedule 3 i
Street & Area Lighting Schedules
Overall
Present Relative
ROR
0.85
1.56
1.8
0.61
0.85
0.79
1.03
1.00
Settement Relative
ROR
0.89
1.42
1.4
0.70
0.88
0.85
0.95
1.00
The Paries agreed to move all natual gas rate schedules approximately 60% toward
unity (except for Transportation Servce Schedule 146, which will receive a full decrease to unty),
as shown below:
3 The followig assumptions were used to incorporate the settement into the cost of servce model for rate spread
puroses: (I) Begin with the filed pro form results of operation; (2) input the agreed-upon revised power supply
adjustment; (3) reflect power supply changes in production proper adjustment; (4) reflect cost of debt from AVU-
E-09-01 in restated debt adjustment; (5) determe remaig adjustment necessar to achieve revenue requirement
given rate of retu from A VU-E-09-01; (6) ru cost of servce model on these results using the prior method,
except transmission costs are 100% demand (allocated by 12 CP); (7) adjustment amount included as common cost
allocated by four-factor allocator; (8) use results to determne rate spread with 25% movement toward unty.
STIPULATION AN SETTLEMENT-AVU-E/G-10-01 Exhibit No. 101 P~ge6
Case Nos. A VU-E-10-01/A VU-G-10-01
R. Lobb, Staff
8/05/1 0, Page60f31
NATUR GAS PRESENT & PROPOSED RELATIVE RATES OF RETUR
General Servce Sch. 101
Lage Genera Servce Sch. 111
Interrptible Sales Servce Sch. 131
Tranporttion Servce Sch. 146
Overal
Present
Relative
ROR
0.95
1.24
1.0
1.33
1.00
Settement
Relative ROR
0.98
1.0
1.03
1.00
1.00
12. Rate Spreadate Design.
(a) As indicated above, the Pares agree that the increase in base revenue would
be spread to move all electrc rate schedules approximately 25% toward unity (excet for the
Street and Area Lighting Schedules, which wil receive a percentage increase equal to the
overall increase in revenue requirement) and all natual gas rate schedules approximately
60% toward unty (except for Transportation Serice Schedule 146, which wil receive a full
decrease to unty).
(b) The Pares agree that there will be an increase in the basic charges, monthly
minimum charges, and demand charges in Schedules 11, 21 and 25, as shown in
Attachment B.
(c) Otherwise, a unform percentage increase will be applied to each energy rate
within each electrc serice schedule excluding Schedule 1, residential serce where the
block differential remains constant.
(d) The Paries agree that the curent residential electrc basic charge of $4.60 per
month wil be increased to $5.00, and the residential natual gas basic charge of $4.00 per
month wil remain the same.
( e) Attachment B provides a summar of the curent and revised rates and
charges (as per the settlement) for electrc and natual gas serce.
STIPULATION AN SETTLEMENT - A VU-E/G-1 0-01 Exhibit No. 101 Page 7
Case Nos. A VU-E-10-0l/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 7 of 31
13. Resulting Percentage Increase by Schedule. The following tables reflect the agreed-
upon percentage increase by schedule for electric and natual gas serce, along with the first-year
net rate impact resulting from the rate impact mitigation plan set forth in Section 7:
Electric Increase Percentage by Schedule:
General Fit Year Net
Rate Schedule Increase with Credit
Residenl Schedule 1 11.0%4.3%
General Serce Schedul 11 6.6%2.6%
Lage Gene Serce Schedule 21 8.7%3.4%
Ex Lage General Serce Schedule 25 9.8%3.8%
Clearater Paper Schedul 25P 7.2%2.8%
Pmiin Sere Scheul 31 13.5%5.2%
Stret & Area Lig Scheules 9.2%3.6%
Overall 9.3%3.60;0
Natural Gas Increase Percentage by Schedule4:
General Fit Year Net
Rate Schedule Increase with Credit
Generl Serce Scheule 101 3.4%2.6%
Lage General Servce Schedule 111 0.2%-0.3%
Intetile Sales Sere Schedule 131 1.0%0.6%
Traorttion Sere Schedul 146 -6.9%-8.6%
Overall 2.6%1.9%
14. Residential First Tier Energy Blocks. The Pares wil exchange information and
convene a public workshop, prior to the Company's next general rate filing, with respect to the
appropriate size of the fist tier energy block for Residential Electrc Serce Schedule 1 (curently
at 600 Kwhs).
4 As par of ths case, the Pares agreed, for puroses of clarty and tranparency, to move all natual gas commodity
and demad costs from base rates to Schedule 150 (Purchased Gas Cost Adjustment); the retail rate schedules will now
only reflect the non-commodity distrbution rates. The application of the DSIT to natual gas customers would be spread
based on each schedule's contrbution to base revenues including the general increase in this case.
STIPULATION AN SETTLEMENT-AVU-E/G-10-01 Exhibit No. 101_ Page 8
Case Nos. AVU-E-10-01/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 8 of 31
15. Effective Date for New Rates. The Paries agree, as an integral par of the
Settlement, that the effective date for new electrc and natual gas rates should be October 1, 2010.
16. Customer Serce-Related Issues.
(a) Low-Income Weatherization Funding. The Paries agree that the anual
level
of fuding of $465,000 to the Communty Action Parership (CAP) agencies for fuding of
weatherzation (which includes adinistrative overhead) should be increased to $700,000.
The continuation and level of such fuding wil be revisited in the Company's next general
rate :fling, or other appropriate proceeding. Ths total amount wil be fuded though the
Energy Effciency Tarff Rider (Schedules 91 and 191).
(b) Funding for Outreach for Low-Income Conseration. The Paries agree to
anual fuding of $40,000 to Idaho CAP for purposes of providing low-income outreach
and education concerg conseration. Ths amount wil be fuded though the Energy
Effciency Tarff Rider (Schedules 91 and 191), and wil be in addition to the $700,000 of
Low-Income Weatherization Funding. The continuation and level of such fuding will be
revisited in the Company's next general rate fiing or other appropriate proceedings.
(c) Other Serce Commitments.
(i) The Company wil review its policies and address in its next general
rate case the appropriateness of charging for serices it now provides without charge
to customers or other paries, ~, establishing new accounts or managing
tenant/andlord accounts. The Company wil also reexamine its existing non-
recurrng charges to determine whether those amounts cover a reasonable portion of
the Company's curent cost to provide those serces.
(ii) The Company wil use its best effort to meet or exceed its curent
contact center servce level standards.
STIPULATION AN SETTLEMENT - A VU-E/G-1 0-01 Exhibit No. 101 Page 9
Case Nos. AVU-E-1O-01/AVU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 9 of 31
(iii) In coordination with Staff, the Company wil develop and conduct a
study on Avista's deposit policy and practices with respect to residential customers.
Among the objectives of the study would be to determine if the current deposit
policy correctly identifies customers who pose a credit risk to the Company, whether
it encourages customers who pose a credit risk to improve payment habits, and
whether it reduces the amount of credit and collection activity as well as bad debt
associated with those customer accounts.
(iv) The Company wil hold at least five Senior Energy Conservation
workshops in different Idaho communties prior to December 31, 2011.
(v) The Company wil begin tracking and reporting to the Commission
monthy data regarding customer credit activity.
(vi) The Company will actively monitor the Low Income Weatherzation
and Low Income Energy Conseration Education Programs to assure that the stated
goals and objectives of these programs are achieved and that costs associated with
these programs are prudently incured.
(vii) The Company will work with Commission Staff to address Staffs
concers about Avista's policies and practices with respect to: (a) openng and
closing customer accounts, and (b) offering ter payment arangements to
customers.
i 7. Other Accounting Treatments. The Paries agree to the accounting treatment for the
following items:
(a) Coeur d'Alene Tribe Settlement and Spokane River Relicensing
Deferrals - The Paries agree to a ten-year amortzation of the remaining balances
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101llige 10
Case Nos. A VU-E-10-01/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 10 of31
beginning October 1, 2010 of the CDA Settlement Deferral, the Spokane River Deferral, and
the Spokane River PM&E DeferraL.
(b) Colstrip Lawsuit Settement - The Paries agree to eliminate the
amortzation of the deferred costs, due to insurance proceeds received subsequent to the
original filing of the case.
(c) Jackson Prairie (JP) Storage - The parties agree to the revised accounting
treatment proposed by the Company for its existing cushion gas using the net book value of
the utility assets at Febru 2010 to record the transfer of the cushion gas from non-
recoverable (pERC Account No. 352.3), which is a depreciable asset, to recoverable (FERC
Account No. 117.1), which is a non-depreciable asset. The JP assets that wil transfer from
Avista Energy on May 1, 2011, wil include plant assets, operations and maintenance
expenses, as well as cushion gas that wil be recorded in both recoverable and non-
recoverable FERC accounts using a similar allocation method.
IV. OTHER GENERA PROVISIONS
18. The Paries agree that ths Stipulation represents a compromise of the positions of the
Paries in this case. As provided in RP 272, other than any testimony filed in support of the approval
of this Stipulation, and except to the extent necessar for a Pary to explain before the Commission
its own statements and positions with respect to the Stipulation, all statements made and positions
taken in negotiations relating to ths Stipulation shall be confidential and will not be admssible in
evidence in this or any other proceeding.
19. The Paries submit ths Stipulation to the Commssion and recommend approval in
its entirety pursuant to RP 274. Paries shall support this Stipulation before the Commission, and no
Par shall appeal a Commission Order approving the Stipulation or an issue resolved by the
Stipulation. If ths Stipulation is challenged by any person not a pary to the Stipulation, the Paries
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101 Page 11
Case Nos. A VU-E-10-01/A VU-G-10-01
R. Lobb, Staff
8/05/10 ta.ge 11 of 31
to this Stipulation reserve the right to file testimony, cross-examine witnesses and put on such case
as they deem appropriate to respond fully to the issues presented, including the right to raise issues
that are incorporated in the settlement ters embodied in ths Stipulation. Notwthstanding ths
reseration of rights, the Pares to this Stipulation agree that they wil continue to support the
Commission's adoption of the terms of ths Stipulation.
20. If the Commission rejects any par or all of this Stipulation or imposes any additional
material conditions on approval of ths Stipulation, each Par reseres the right, upon wrtten
notice to the Commission and the other Paries to ths proceeding, withn 14 days of the date of such
action by the Commission, to withdraw from this Stipulation. In such case, no Pary shall be bound
or prejudiced by the terms of ths Stipulation, and each Pary shall be entitled to seek
reconsideration of the Commission's order, file testimony as it chooses, cross-examne witnesses,
and do all other thngs necessar to put on such case as it deems appropriate. In such case, the
Paries immediately wil request the prompt reconveng of a prehearng conference for puroses of
establishing a procedural schedule for the completion of the case. The Paries agree to cooperate in
development of a schedule that concludes the proceeding on the earliest possible date, taking into
account the needs of the Pares in paricipatig in hearngs and preparng testimony and briefs.
21. The Paries agree that ths Stipulation is in the public interest and that all of its terms
and conditions are fair, just and reasonable.
22. No Pary shall be bound, benefited or prejudiced by any position asserted in the
negotiation of ths Stipulation, except to the extent expressly stated herein, nor shall ths Stipulation
be constred as a waiver of the rights of any Pary uness such rights are expressly waived herein.
Execution of ths Stipulation shall not be deemed to constitute an acknowledgment by any Par of
the validity or invalidity of any paricular method, theory or principle of regulation or cost recovery.
No Pary shall be deemed to have agreed that any method, theory or principle of regulation or cost
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101 Page 12
Case Nos. A VU-E-10-01/A Vù-G':rO-Ol
R. Lobb, Staff
8/0S/1 0 Page i:Lof3 1
recovery employed in arving at ths Stipulation is appropriate for resolving any issues in any other
proceeding in the futue. No findings of fact or conclusions of law other than those stated herein
shall be deemed to be implicit in ths Stipulation.
23. The obligations of the Paries under this Stipulation are subject to the Commission's
approval of ths Stipulation in accordance with its ters and conditions and upon such approval
being upheld on appeal, if any, by a cour of competent jursdiction.
24. Ths Stipulation may be executed in counterar and each signed counterpar shall
constitute an original document.
STIPULATION AN SETTLEMENT-AVU-E/G-1O-01 Exhibit No. 101 Page 13
Case Nos. AVU-E-10-0l/AVU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 13 of 31
-"'\"2 r.JDATE ths '- dã of July 2010.
A vista CorporationB~ZJ¡
avid J. Meyer
=:ttmey for A vista Corraon
Idao Public Utilities Commssion Staff
By:
Donald L. Howell, n
Krstine A. Sasser
Deputy Attorneys General
Clearater Paper Corporation Idaho Forest Group
By:By:
Dean J. Miller
Attorney for Idaho Forest Group LLC
Peter Richardson
Attorney for Clearater Paper
Community Action Parership Association Idaho Conservation League
By:By:
Brad M. Pudy
Attorney for CAP AI
Benjamn J. Otto
Snake River Alliance
By:
Ken Miller
STIPULATION AN SETTMENT - A VU-E/G-lO-Ol ExhibiiNo. 101 _~~ge 14
Case Nos. A VU-E-1 0-0 l/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 14 of31
DATED thisi3~day of July 2010.
David J. Meyer
Attorney for A vista Corporation
A vista Corporation
By:By:
Donald L. well, II
Krstne A. Sasser
Deputy Attorneys Genera
Clearater Paper Corporation Idaho Forest Group
By:By:
Peter Richardson
Attorney for Clearater Paper
Dea J. Miler
Attorney for Idaho Forest Group LLC
Community Action Parership Association Idaho Conservation League
By:By:
Benjamin J. OtoBrad M. Purdy
Attorney for CAPAI
Snake River Allance
By:
Ken Miler
STIPULATION AND SETTLEMET-AVU-E/GM10-01 ExhibitNo.i01 Pag~i4
Case Nos. AVU-E-10-01/AVU-G-10-01
R. Lobb, Staff
8/05/10 Page 15 of31
~
DATED this2?day of July 2010.
AvitaCorpration
By:
David J. Meyer
Attrney forAvista Coiptaon
By:
Communty.Aeton.Parermp.AssocÍaton
By;
BraM. Pudy
Attorney fofCAPAI
SnaeRiver Alliance
By:
knMíler
Idao Public UtiUtiesComnÍssioiiSta
By:
DonadLHowellt II
KineA. Sasser
DepUt AttoreysGener
Idao .ForetØrup
By:
Dea J..MiUer
Attorney for. Idaho Fo;tst 6rupLLC
Idao Constvatioii Leagu
By:BeJanJ.Ot.
S'lULA1'ON ANSETtLEME - A\T..ElG"¡O~Ol Page 14
Exhibit No. 101 "
Case Nos. AVU-E-10-0l/A VU-G-10-01
R. Lobb, Staff
8/05UO Page 16 of 31
DATED this ~ day of July 2010.
A vista Goiporation
By:
David J. Meyer
Attorney for A vistaCorporatioh
Glearater Paper Corporaton
By:
Peterltchardson
Attorney forC1eaa.ter Paper
GommulÛty Actiöll parerhip. Associatioll
By:
Brad M.Purdy
AttorneyforCAPAI
Snake River Alliance
By:
Ken Miller
Idaho Public Utilities Commission Staf
By:
Donald L. Howell, II
KrstineA. Sasser
Deputy Attorneys Generl
~,.ean J. Miler
Attorney for IdahoForetGroupLLC
Idaho Conservation League
By:
'Benjamin ¡, Otto
STIPULATIONAND SETTLEMENT - AVU-E/G-IO';01 Page 14
Exhibit No. 101
Case Nos. AVU-E-10-0l/A VU-G-10-01
R. Lobb, Staff
8/05/10 Page 17 of31
. Jul2510 06:47p Brad Purdy 208-384-8511 p.2
~
DATED th ~ day of July 2010.
A vista Corpration Idaho Public Utilities Commsion Sta
By:By:
Donald L. Howell,. II
Krstine A. Sasser
Deputy Attorneys General
David J. Meyer
Attorney for A vist Corporation
Clearater Paper Corporaon Idao Forest Group
By:By:
Dean J. Miler
Attorney for Idao Forest Grup LLC
Peter Richardson
Attorney for Clearer Paper
Communty Action Parership AsciationBd3gJ~Bra M. Purdy~
Attorney for CAP AI
Idaho Conservation League
By:
Benjam J. Oto
Snae River Allance
By:
Ken Miler
STIPULATION AND SETTLEMENT-AVU-E/G-Io-Ol Exhibit No. 101 Page 14
Case Nos. A VU-E-10-0l/AVU-G-1O-01
R. Lobb, Staff
8/05/1 0 Pa~e 18 of31
07/25/2010 SUN 16: 52 (TX/RX NO 5678) ~002
~A1'ED ths 1. J day of July 2010.
Avista Corporation
By:
David J.-Meyer.
Attorney for Avista Corporation
Clearater Paper Corporation
By:
Peter Richadson
Attorney for Clearter Paper
Community Action Parership Association
By:
Brad lv. Purdy
Attorney for CAPAI
Snae River Allance
By:
Ken Miler
Idaho Public Utiities Commission Stff
By:
DOIli:1d L. Howell; II
Krtie A. Sasser
Deputy Attorneys General
Idaho Forest Group
By:
DeanJ. Miler
Attoniey for Idao Forest Group LLC
Idaho Conservaton League
By: -& --.
Bei;ai J. Otto
l l¡"I"~'I ,ç,. T, c: l. .
STIPULATION AN SETTEMENT - AVU-E/G-IO..01 Exhibit No. 101 Page 14
Case Nos. AVU-E-10-01lAVU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 19 of31
DATED this _day of July 2010.
Avista Corporation
By:
David J. Meyer
Attorney for Avista Corporation
Clearwater 'fperCorp'oratiol1
By:
Peter Richardson
Attoiuey for Cleaiwater Paper
Comitity ActionPartnershipAssociatioli
By:
BtfM.:purdy
Attorney forCAPAI
Snake RìverAUiance
¡By: ~ --d4~
KenMìller
Idaho Pl.blic Utilities Com.issIól1 Staff
By:
Donald.;r. Howell, II
KristiieA.Sasser
Deputy Attorneys General
Idaho Forest QroiJp
By:
By:
Dei I. Miler
Attorney for IdahoForest Group LLC
Idaho ConserVation Leågue
Benjamin J. QUo
E hOb' N 101 Page 14x 1 it o. . "
Case Noso A VU-E-lO-O 1/ A VU-G-lO-O 1
R. Lobb, Staff
8/05/1 0 Page 20 of 31
STIPULATION AND SETtLEMENT~ AVU-B/G-IO-Ol
20fO JUl 27 AI1 10: 32
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-10-Ol & AVU-G-10-Ol
ATTACHMENT A
Electric PCA Authorized Expense and
Retail Sales
Exhibit No. 101
Case Nos. A VU-E-lO-Ol/A VU-G-1O-01
R. Lobb, Staff
8/05/1 0 Page 21 of31
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STIPULATION AND SETTLEMENT
Case Nos. AVU-E-10-Ol & AVU-G-10-Ol
ATTACHMENT B
Electric and Natural Gas Rate Design
Exhibit No. 101
Case Nos. A VU-E-10-01/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 23 of 31
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B
AVISTA UTILITES
IDAHO ELECTRIC, CASE NO. AVU-E.1Ð-1
PRESENT & PROPOSED RATES OF RETURN BY RATE SCHEDULE
12 MONTHS ENDED DECEMBER 31, 2009
Present Rates Base Propod Rates
Present Present Tari Proposed Propod
Line Type of Sch.Rate of Relative Proposed Rate of Relativ
No.Service Number Return BQ Increase Return BQ
(a)(b)(c)(d)(e)(f)(9)
Residential 5.40%0.85 11.0%7.64%0.89
2 General Service 11,12 9.86%1.56 6.6%12.14%1.42
3 Large General Service 21,22 7.48%1.18 8.7%9.75%1.14
4 Extra Large General Svc.25 3.86%0.61 9.8%5.99%0.70
5 Clearwater 25P 5.35%0.85 7.2%7.52%0.88
6 Pumping Service 31,32 5.01%0.79 13.5%7.27%0.85
7 Strt & Area Lights 41-49 6.53%1.03 9.2%8.09%0.95
8 Total 6.32%1.00 9.3%8.55%1.00
Attchment B
Stipulation and Settlement
Case No. AVU-E-10-01 & AVU-G-10-01
AvistaExhibit No. 101 Page 2 of 8
Case Nos. AVU-E-10-0l/AVU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 25 of 31
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU.E.10-o1
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
Present General Proposed Proposed
Base Tariff ERM&Present Rate Biling Base Tariff
Sch. Rate Oter Adj.1) Billng Rate Increase Rate B!
(a)(b)(c)(d)(e)(f)(g)
Residential Service. Schedule 1
Basic Charge $4.60 $4.60 $0.40 $5.00 $5.00
Energy Charge:
First 600 kWhs $0.06950 $0.00313 $0.07263 $0.00825 $0.07573 $0.07775
All over 600 kWhs $0.07867 $0.00313 $0.08180 $0.00824 $0.0849 $0.08691
General Services. Schedule 11
Basic Charge $6.50 $6.50 $3.00 $9.50 $9.50
Energy Charge:
First 3,650 kWhs $0.08715 $0.00647 $0.09362 $0.00348 $0.09351 $0.09063
All over 3,650 kWhs $0.07433 $0.00647 $0.08080 $0.00298 $0.08019 $0.On31
Demand Charge:
20 kW or less no charge no charge no charge no charge
Over 20 kW $4.00/kW $4.00/kW $0.75/kW $4.75/kW $4. 75/kW
Large General Service. Schedule 21
Energy Charge:
First 250,000 kWhs $0.05765 $0.00576 $0.06341 $0.00344 $0.06314 $0.06109
All over 250,000 kWhs $0.04919 $0.00576 $0.05495 $0.00295 $0.05419 $0.05214
Demand Charge:
50 kW or less $275.00 $275.00 $50.00 $325.00 $325.00
Over 50 kW $3.50/kW $3.50/kW $0.75/kW $4.25/kW $4.25/kW
Primary Voltage Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Extra Large General Service. Schedule 25
Energy Charge:
First 500,000 kWhs $0.04709 $0.00510 $0.05219 $0.00356 $0.05324 $0.05065
All over 500,000 kWhs $0.03988 $0.00510 $0.04498 $0.00302 $0.0454 $0.04290
Demand Charge:
3,000 kva or less $10,000 $10,000 $2,000 $12,000 $12,000
Over 3,000 kva $3.25/kva $3.25/kva $0.75/kva $4.00/kva $4.00/kva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Annual Minimum Present:$601,940 $662,400
Clearwter. Schedule 25P
Energy Charge:
all kWhs $0.03960 $0.00490 $0.04450 $0.00206 $0.0443 $0.04166
Demand Charge:
3,000 kva or less $10,000 $10,000 $2,000 $12,000 $12,000
Over 3,000 kva $3.25/kva $3.25/kva $0.75/kva $4.00/kva $4.00/kva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Annual Minimum Present:$555,600 $602,260
Pumping Service. Schedule 31
Basic Charge $6.50 $6.50 $1.00 $7.50 $7.50
Energy Charge:
First 165 kW/kWh $0.07800 $0.00586 $0.08386 $0.01052 $0.08891 $0.08852
All additional kWhs $0.06649 $0.00586 $0.07235 $0.00897 $0.07585 $0.0754
(1) Includes all present rate adjustments: Schedule 66- Temporary PCA Adj., Schedule 91-Energy Effciency Rider Adj.,
and Schedule 59-Residential & Farm Energy Rate Adj. (Sch. 1 only).
Stipulation and Settlement
Case No. AVU-E-10-01 & AVU-G-10-o1
Exhibit No. 101 Avista
Attchment B Case Nos. A VU-E-1 0-0 l/AVU-G-1 0-01 Page 3 of 8
R. Lobb, Staff
8/05/10 Page 26 of31
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8
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU.G.10.01
PRESENT & PROPOSED RATES OF RETURN BY RATE SCHEDULE
12 MONTHS ENDED DECEMBER 31, 2009
Present Rates Base Proposed Rates
Present Present Tariff Proposed Proposed
Line Type of Sch.Rate of Relative Proposed Rate of Relative
No.Service Number Retum BQ Increase (1)Retum BQ
(a)(b)(c)(d)(e)(f)(g)
1 General Service 101 7.00%0.95 8.3%8.38% .0.98
2 large General Service 111 9.20%1.24 0.6%9.40%1.10
3 Interrptible Servce 131 8.09%1.10 4.2%8.81%1.03
4 Transportation Service 146 9.81%1.33 (6.9%)8.55%1.00
5 Total 7.39%1.00 6.8%8.55%1.00
(1) Natural Gas Commodity Costs moved from base Sales Schedules to Schedule 150 as part of the stipulation.
Stipulation and Settlement
Case No. AVU-E.10-Q1 & AVU-G-10-01
AvistaAttachment B Exhibit No. 101 Page 6 of 8
Case Nos. AVU-E-1O-01/A VU-G-10-0f
R. Lobb, Staff
8/05/lO jlage 29 of31
AVISTA UTLITES
IDAHO GAS. CASE NO. AVU-G.10-01
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
Current Gas Cost New General DSIT (Sch.199)Proposed Proposed
Base Moving to Base Present Presenl Rate Rate Billing Base
Rate Schedule 150 Rate 111 Rate Adj. 121 Billng Rate ~Decrease (31 ß!ß!
(a)(b)(c)(d)(e)(f)(g)(h)(i)Ol
Generl Service. Schedule 101
Basic Charge $4.00 $4.00 $0.00 $4.00 $4.00
Usage Charge:
Alltherms $0.87815 ($0.53674)$0.34141 $0.482 $0.82593 $0.03374 ($0.00729)$0.8523 $0.37515
Large General Servce - Schedule 111
Usage Charge:
Firs 200 therms $0.86316 ($0.48520)$0.37796 $0.0172 $0.39516 ($0.00361)$0.3155 $0.39516
200 . 1,000 therm $0.79944 ($0.53674)$0.26270 $0.489 $0.7439 $0.00008 ($0.00361)$0.739 $0.26278
1.00 . 10.000 therms $0.72485 ($0,53674)$0.18811 $0.48039 $0.66850 $0.00006 ($0.00361)$0.6645 $0.18817
Allover 10.000 therms $0.6841 ($0.53674)$0.14727 $0.4839 $0.62766 ($0.00826)($0.0361)$0.61579 $0.13901
Minimum Charge:
per month $75.59 $75.59 $3.44 $79.3 $79.3
pertherm $0.0000 $0.0000 $0.4839 $0.4839 ($0.0361)$0.47678 $0.00000
Interrptble Service. Schedule 131
Usage Charge:
All Therms $0.61264 ($0.45293)$0.15971 $0.40349 $0.56320 $0.0676 ($0.00286)$0.56710 $0.1667
Transportion Servce. Schedule 146
Basic Charge $200.00 $200.00 $0.00 $200.00 $200.00
Usage Charge:
All Therms $0.11385 $0.11385 $0.11385 ($0.0826)($0.00159)$0.10400 $0.10559
(1) The New Base Rate is derived from the Currnt Base Rate, less the Natural Gas Commodity Costs moved to Schedule 150, prior to th General Rale Increase.
(2) Includes Schedule 150- Purchase Gas Cost Adj.. Schedule 155 - Gas Rate Adj.. Schedule 191 . Energy Efficiency Rider Adj.
(3) See Page 8 of Attchment A
Attchment B
Stipulation and Settlement
Case No. AVU-E-1()01 & AVU.G-1()01
Avista
Exhibit No. 101 ., Page70f8
Case Nos. AVU-E-10-0l/AVU-G-10-01
R. Lobb, Staff
8/05/10 Page 30 of 31
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Exhibit No. 102
Case Nos. A VU-E-10-0l/A VU-G-10-01
R. Lobb, Staff
8/05/10
MEMORANDUM OF UNDERSTANDING
FOR PRUDENCY DETERMINATION OF DSM EXPENDITURES
This Memorandum of Understanding ("MOU") is entered into on this 21st day of
December 2009 between Idaho Power Company ("Idaho Powet'), Avista Utilties,
PacifiCorp(d/b/a Rocky Mountain Power) (collectvely ''the Utilties" and individually as
"the utility"), and the Staff of the Idaho Public Utilties Commission ("Staff). All of the
above-named entiies are hereinafter sometimes referred to collectively as "Parties" or
individually as "Part."
WITNESSETH:
A. The Parties agree that there exists a need for the Utilities andStàff to
develop a common understanding of the basis upon which prudency of demand-side
management ("DSM") expenditures can be determined for purposes of cost recovery.
B. The Parties attended a workshop on October 5, 2009, to discuss the
contents of a more comprehensive utilty annual DSM report that would demonstrate a
commitment to, and accomplishment of, objective and transparent evaluation of DSM
efforts. The agreed"-upon principles ("guidelines") stemming from that workshop are set
out below.
C. A copy of Staffs expectations for DSM prudency review is ,included as
Attachment NO.1. Although Utilties wil make a good faith effort to address Staffs
expectations in following these guidelines, Staff expectations are informational and the
Utilities wil not be bound by them in the context of this Memorandum of Understanding.
D. The Parties recognize that implementation of the DSM prudency
guidelines and evaluation framework described below wil not automatically result in
MEMORANDUM OF UNDERSTANDING - 1 Exhibit No. 103
Case Nos. A VU-E-1O-01/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 1 of 10
DSM prudency findings. Instead, even with their implementation, future DSM prudency
findings wil require the preparation of a formal filing with the Commission.
Utilty DSM Annual Report Requirements
1. Template. Idaho Powets 2008 Demand-Side Management Annual
Report wil be used as a starting point template for enhanced reports beginning with
reports for 2009 DSM operations and results. Elements like those found in Idaho
Powets 2008 report wil be included in each Utilit's annual report for Idaho programs
that reporting year, clearly identifing Idaho-specific data and narratives. The DSM
annual reports may be filed as stand-alone documents or as a combination of
documents (e.g., combined with a DSM business plan) that together fulfll the
agreements in this MOU.
2. Table of Contents. Each annual DSM report wil contain a table of
contents that references all items specifed below, including the appendix where the
Cost-Effectiveness and Evaluation Table can be found.
3. Highlights or Introduction Section. Each annual DSM Report wil include
an initial overview of:
a. Process evaluations begun or completed during the previous year,
modifications to DSM processes that resulted from those evaluations, and planned
process evaluations and modifications for the coming year.
b. Impact evaluations begun or completed during the previous year,
modifications to DSM programs that resulted from those evaluations, and pianned
MEMORANDUM OF UNDERSTANDING - 2
Exhibít No. 103
Case Nos. A VU-E-10-01lA VU-G-1O-01
R. Lobb, Staff
8/05/10 Page 2 of 10
impact evaluations for the coming year. This section wil also highlight updates of
assumptions or reference reports used in assessing cost-effectiveness during the past
year and those expected to be reviewed in the coming year.
4. Cost-Effectveness Section. Each DSM annual report wil include a Cost-
Effectiveness section and table listing individual programs/measures and the basis for
estimates of their cost-effectiveness, i.e., formulas, data inputs and assumptions, and
sourcelrationale for each datum and assumption, including the date of the source.
5. Evaluation Section. Each DSM annual report wil include an Evaluation
section and table showing the schedule for evaluations, including impact assessment,
assumptions, source review, the schedule for field impact 'measurement, and
completion date. If this schedule is not included, a reasonable explanation for why such
a schedule, in whole or in part, is not necessary wil be included.
a. It is anticipated that over a reasonable frequency cycle (e.g., 2 t03
years), all substantial programs wil have undergone process and impact evaluations.
However, Staff agrees that the initial evaluation cycles may be longer for 2008 and 2009
programs unti these guidelines are fully implemented.
b. A copy of each DSM evaluation completed since filing the previous
DSM annual report wil be included as an appendix to the annual DSM report as well as
any confidential cost information that are not included. The utilty wil supplement it
DSM report with any confidential cost information once the Staff has signed a protective
agreement with the utility.
6. Program Specific Section. Program-specifc sections of the annual DSM
Report wil be reported by sector or by customer class, with a description of each
MEMORANDUM OF UNDERSTANDING - 3
Exhibit No. 103
Case Nos. A VU-E-1 0-0 l/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 3 of 10
individual program offered in the sector or customer class, and wil include a list of
measures within each program.
a. Process Evaluation. Each program-specific section wil have a
process evaluation description that includes:
i. Program implementation modifications undertaken during
the course ofthe year and the rationale behind the change(s).
ii. Other process issues identifed during the course of the year.
iii. Any formal process evaluation undertken during the year.
iv . Total process evaluation cost, inclusive of both utilit-
provided and contract-provided services, and names of primary outside evaluators
conducting process evaluations and titles of intemal evaluators. The DSM Report will
indicate which cost information is considered confidential; each utilty wil supplement its
DSM report with any program evaluations containing confidential proprietary information
once the Staff has signed a protective agreement with the utilty.
v. Process changes completed or planned during the upcoming
year, if any.
b. Impact and Cost-effectiveness Evaluation. Each program-specifc
section wil include an impact and cost-effectiveness evaluation description including:
i. Primary assumptions and source (with year source was
produced) used in the initial determination of cost-effectiveness.
ii. Primary assumptions and source (with year source was
produced) used to determine post implementation impact and cost-effectiveness.
MEMORANDUM OF UNDERSTANDING - 4
Exhibit No. 103
Case Nos. A VU-E-10-0l/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 4 of 10
iii. Any changes from initial determination (or last evaluation)
used for current cost-effectiveness evaluation and the reason for the change (such as
updated assumptions, sources or field measurement).
iv. Planned cycle for reassessment of cost-effectiveness
assumptions or measurement.
v. Total impact evaluation cost, inclusive of both utilty-provided
and contract-provided services, and names of primary outside evaluators and titles of
inside evaluators. The DSM Report wil indicate which cost information is considered
confidential; each utilty wil supplement its DSM report with any program evaluations
containing confidential proprietary information once the Staff has signed a protective
agreement with the utilty.
vi. Changes in program due to evaluation results.
c. Market Effects Evaluations. Each program-specifc section wil
describe any market effects evaluations that have been planned or completed by or for
the utility, including those planned or completed by the Northwest Energy Effciency
Allance that are pertinent to any programs for which the utilty is claiming electricit ,
savings or other impacts.
7. Expenses Without Direct Energy Savings. As discussed in the October 5
workshop, the Utilties have expenses associated with DSM-related activities for which
they do not claim energy savings. Expenses associated with non-quantifiable energy
saving programs and initiatives, including but not limited to, infrastructure, education,
outreach, and research, wil be identifed in the DSM annual reports and may be
considered reasonable and necessary expenses for a broad based DSM portolio.
MEMORANDUM OF UNDERSTANDING - 5
Exhibit No. 103
Case Nos. A VU-E-1 0-0 l/A VU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 5 of 10
Reasonable evaluations of such programs and efforts, commensurate with their 'costs,
will be accomplished and reported. The Utilties wil include these expenses in the
calculations which determine a cost-effective DSM portolio.
Prudency Determination
8. A utility may request a DSM prudency review at any time.
9. The Parties recognize that planning, implementing, and evaluating DSM
programs are not a precise science; they require the application of judgment and
experience. Utilities are encouraged to continually review these programs and make
appropriate program improvements.
10. Witin that context, review of utilty demand-side management expense
for prudency shall take into consideration utilty compliance with the planning,
evaluation, and reporting guidelines listed above. A showing by the utility that it made a
good faith effort to reasonably perform within these guidelines wil constitute prima facie
evidence that the utility's DSM expenses were prudently incurred for cost recovery
purposes. By its performing witin these guidelines, assuming there is no evidence of
imprudent actions or expenses, the utilty can reasonably expect that in the ordinary
course of business Staff wil support full cost recovery of its DSM program expenses.
Treatment of 2008 and 2009 Expenditures
11. Recognizing that their 2008 DSM reports have already been filed, the
Utilties need not amend those reports, but instead wil combine evaluation reporting for
2008 with 2009 in their 2009 reports to be filed in 2010. Because it is not possible to
comply exactly with the requirements listed above for the historical expenses of 2008
and 2009, Parties agree to include as many components as possible in the 2010 Annual
MEMORANDUM OF UNDERSTANDING - 6
Exhibit No. 103
Case Nos. A VU-E-1O-01/A VU-G-10-01
R. Lobb, Staff
8/05/10 Page 6 of 10
QSM Repn, Staffagr'ê tOPlCVlê!"SOnablêand' neCè$$ry~way forthä
implêmentatioo oftñeguidêlífï$$d:-"beg 'irithsMOU 'fOttle2010 DeM retrtl.
12.Staagreesthat AvJstutllesmaYf&fllê: ils20fl OSMprtnc
tèueSlstbatweYe deferr in A\lU-~9..1 anAVU-~1a$ "mll-Yéátpniønøy
røque$lstlWiJ nofbeo,~et,bYSta.
p!tnmlsslOßBøtSoundlWJblsMemoranduM of Qnginillnding
1'3;' The panles'ttithiS Meniøraâ1JmofÜOdersaridi.,~QWe*thlt'th
COl'mlS$km Staft bil's''Ørifv itelf and hâsoo 'épllcit Otimpllcit äutrito ,blrid'thf¡
IdahQ'PubUO UtiUties OOmm¡Nion.
IN 'WITNESS''NEREOF. thPaites herethavecaused'thls MeI'~lnto
bêê)tel:fKln thelrrøsPebt'_lt01dth'ê datlss,tfattJ)dW.
Dated tJ~s"(S-daY()f ae~","r3Qg¡
'" cr~::ID
IP..()I:..El~Je U1'S
CQMMl$SJONstAF
"ti
Dated this ii..Y:of December 2009.
.~~.
, '. Ral'diL3i ..".,'. '" "" ".
Repreenthgthe ,ldaliPUbllc'
UtIJité$:.Cømr;i$sIQSta
IOAllO.'POVVRCOMPAN
~l
Dated.thf$g~YOfO~~200,AVlSlAUTIUTIES
er.rI"~
. epreseningAvi$laUtilJté$
MEMORAUMOFUNOER$TANDINGw 7 Exhibit No. T03
Case Nos. AVU-E-1O-0l/AVU-G-1O-01
R. Lobb, Staff
8/05/1 0 Page 7 of 10
Dated thiS;J day of December 2009.
MEMORANDUM OF UNDERSTANDING - 8
ROCKY MOUNTAIN POWER
Exhibit No. 103
Case Nos. A VU-E-1O-0l/AVU-G-IO-01
R. Lobb, Staff
8/05/10 Page 8 of 10
ATTACHMENT NO.1
Staff Expectations for Cost-Effectiveness Tests, Methods and Evaluations
1. Cost Effectiveness Measurements. As stated at the October 5, 2009,
DSM evaluation workshop, Staff believes that prudent DSM management requires that
cost-effectiveness be analyzed from a wide variety of perspectives, including the
ratepayer impact perspective, and that all programs and individual measures should
have the goal of cost-effectiveness from the total resource, utility, and participant
perspectives. (See IPUC Order No. 22299 issued January 27, 1989, and Order No.
28894 issued November 21, 2001.) If a particular measure or program is pursued in
spite of the expectation that it wil not, itself, be cost-effective from each of those three
perspectives, then the'annual DSM report should explain why the measure or program
was implemented or continued.
2. Net-to-Gross Adjustments. The net-ta-gross issue was also discussed at
the evaluation workshop. Some of the references that the utilties assert that they use,
such as the California Standard Practice Manual, actually require that all tests be done
on a net savings basis. Staff continues to assert that most programs and measures
have a significant number of participants who would have installed the measure or
changed their behavior in the absence of the utilit program. Absent new evaluation
research to provide a basis for the net-to-ross adjustments used by each utilty, the
utilty has the burden of explaining the source of its net savings adjustments or lack
thereof. Staff wil continue to assess whether utilty cost-effectiveness estimates
suffciently and prudently include net-to-gross adjustments.
3. Third-Part Evaluators. Independence of evaluators from program and
portolio management is another important issue that was discussed at the evaluation
workshop. While it was generally agreed that not all evaluations need to be performed
by third-part evaluators, Staff believes such evaluations tend to be perceivèd as being
more objective and transparent, and thus more credible, than evaluations performed by
utilty staff, all other factors being equal. While Staff wil review all evaluations and may
MEMORANDUM OF UNDERSTANDING - 9
Exhibit No. 103
Case Nos. A VU-E-1O-01/AVU-G-10-01
R. Lobb, Staff
8/05/1 0 Page 9 of 10
review any evaluation in depth, utilties should expect that their self-evaluations may be
scrutinized more closely than third-part evaluations, as may the programs themselves.
4. Estimating Non-Energv Benefis. Non-energy benefits are important and
prudent factors to assess in analyzing cost-effectiveness and determining incentive
levels, but Staff cautions against cre~ting . confusion by subtracting the estimated value
of non-energy benefits from program and measure costs when reporting DSM costs on
a cents per kWh basis.
5. Contractor Costs. After DSM reports are filed in 2010, Staff may
reconsider whether to require inclusion of specific contract amounts paid to contractors
in subsequent DSM reports.
6. Suggested Resources. In addition to the several evaluation,
measurement, and cost-effectiveness manuals that were discussed at the workshop,
Staff suggests it may be useful for utilties to generally follow the guidelines in the
National Action Plan for Energy Effciency's Model Energy Effciency Program Impact
Evaluation Guide, released November 2007. Another of NAPEE's reports titld
Understanding Cost-Effectiveness of Energy Effciency Prorams: Best Practices,
Technical Methods, and Emerging Issues for Policy-Makers may also be usefuL.
MEMORANDUM OF UNDERSTANDING -10
ExhibitNo. roT
Case Nos. AVU-E-1O-01/AVU-G-1O-01
R. Lobb, Staff
8/05/1 0 Page 10 of i 0
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 5TH DAY OF AUGUST 2010,
SERVED THE FOREGOING DIRECT TESTIMONY OF RANDY LOBB IN SUPPORT
OF THE STIPULATION AND SETTLEMENT, IN CASE NOS. AVU-E-lO-OI_AVU-G-
10-01, BY E-MAILINGANDMAILINGACOPYTHEREOF.POSTAGEPREPAID.TO
THE FOLLOWING:
DAVID J MEYER
VP & CHIEF COUNSEL
A VIST A CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-MAIL: david.meyer(favistacorp.com
PETER J RICHARDSON
GREG M ADAMS
RICHARDSON & O'LEARY
515 N 27TH ST
BOISE ID 83702
E-MAIL: peter(frichardsonandolear.com
greg(frichardsonandoleary. com
DEAN J MILLER
MCDEVITT & MILLER LLP
PO BOX 2564
BOISE ID 83701
E-MAIL: joe(imcdevitt-miler.com
ROWENA PINEDA
ID COMMUNITY ACTION
NETWORK
3450 HILL ROAD
BOISE ID 83703
E-MAIL: Rowena(fidahocan.org
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH ST
BOISE ID 83702
E-MAIL: bmpurdy(ihotmail.com
KELL YO NORWOOD
VP STATE & FED REG
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-MAIL: kelly.norwood(iavistacorp.com
HOWARD RAY
CLEARWATER PAPER CORP
803 MILL ROAD
PO BOX 1126
LEWISTON ID 83501-1126
E-MAIL: howard.ray(ic1earwaterpaper.com
LARRY CROWLEY
ENERGY STRATEGIES INSTITUTE
5549 S CLIFFS EDGE AVE
BOISE ID 83716
E-MAIL: crowleyla(faol.com
LEEANNHALL
3518 S EDMUNDS ST
SEATTLE WA 98118
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
POBOX 844
BOISE ID 83701
E-MAIL: botto(fidahoconservation.org
KEN MILLER
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
E-MAIL: kmiler§snakeriverallance.org
CLARK FAIRCHILD
VICE PRESIDENT
NORTH IDAHO ENERGY LOGS
PO BOX 571
MOYIE SPRINGS ID 83845
E-MAIL: energylogs§gmai1.com
ROB PLUID
PRESIDENT
NORTH IDAHO ENERGY LOGS
PO BOX 571
MOYIE SPRINGS ID 83845
E-MAIL: robpluid§gmai1.com
TOM OXFORD
SECRETARY TREASURER
NORTH IDAHO ENERGY LOGS
E-MAIL: oxford§meadowcrk.com
(ELECTRONIC SERVICE ONLY)
~.\(~