20130225Lobb DI in Support.pdf

BEFORE THE
23 F
IDAHO PUBLIC UTILITIES COMMISStON
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION DBA AVISTA
UTILITIES FOR AUTHORITY TO INCREASE
ITS RATES AND CHARGES FOR
ELECTRIC AND NATURAL GAS SERVICE
IN IDAHO.
CASE NO. AVU-E-1 2-08/
AVU-G-1 2-07
DIRECT TESTIMONY OF RANDY LOBB
IN SUPPORT OF THE STIPULATION
AND SETTLEMENT
IDAHO PUBLIC UTILITIES COMMISSION
FEBRUARY 25, 2013
1
Q. Please state your name and business address for the
2 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 Utilities 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 1980
12 and worked for the Idaho Department of Water Resources from
13 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. I have analyzed utility rate applications,
17 rate design, tariff analysis and customer petitions. I have
18 testified in numerous proceedings before the Commission
19 including cases dealing with rate structure, cost of service,
20 power supply, line extensions, regulatory policy and facility
21 acquisitions. My duties at the Commission include case
22 management and oversight of all technical Staff assigned to
23 Commission filings.
24 Q. What is the purpose of your testimony in this case?
25 A. The purpose of my testimony is to describe the
CASE NOS. AVU-E--12--08/AVU-G-12-07 LOBE, R. (Stip) 1
02/25/13 STAFF
1 parties' comprehensive settlement in the case and explain
2 Staff's support.
3
Q. Please summarize your testimony.
4 A. After thorough review of the Company's application,
5 detailed identification of adjustments, two settlement
6 workshops and thoughtful assessment of settlement
7 alternatives, Staff believes that the proposed multi-phase,
8 two-year Settlement is in the public interest, is fair, just
9 and reasonable and should be approved by the Commission.
10
Q. How is your testimony organized?
11 A. My testimony is subdivided under the following
12 headings:
13 Stipulation Overview Page 2
14
Staff Investigation Page 4
The Settlement Process Page 8
15
Settlement Evaluation Page 9
16 Cost of Service/Rate Design Page 14
17 Stipulation Overview
18
Q. Please summarize the Stipulation and Settlement.
19 A. The Stipulation filed with the Commission provides
20 for a two-phase rate plan for both electric and natural gas
21 service, with a further base rate increase stay-out provision
22 through January 1, 2015. The first phase of the plan would
23 take effect on April 1, 2013 and provide for no increase in
24 electric base revenue and an annual increase in natural gas
25 revenue of $3.12 million or 4.92%. The second phase of the
CASE NOS. AVU-E-12-08/AVU--G-12-07 LOBB, R. (Stip) 2
02/25/13 STAFF
1 plan, proposed to take effect on October 1, 2013, specifies
2 an annual electric base revenue increase of $7.825 million or
3 3.2%. Annual natural gas revenues would increase by $1.33
4 million or 2.0%. There would be no base rate increase in
5 2014.
6 When these proposed base rate increases are
7 combined with Bonneville Power Administration transmission
8 revenue credits and Purchased Gas Adjustment credits, the net
9 increase over two years is about $4.77 million (1.9%) for
10 electric and $3.31 million (5.2%) for natural gas service,
11 respectively.
12 The Stipulation specifies a 9.8% return on equity
13 and a 7.91% overall rate of return, annual power supply cost
14 levels, non executive salary levels, end of period rate base
15 levels and treatment of Palouse Wind expenses and benefits.
16 The Stipulation also specifies a cost of service based
17 revenue spread to the various customer classes with a uniform
18 increase in the energy portion of the rate. The Stipulation
19 was signed by all parties to the case expect the Consumer
20 Action Partnership of Idaho (CAPAI). The Settlement document
21 is attached as Staff Exhibit No. 101.
22
Q. How does the stipulated annual revenue requirement
23 increase for electric and natural gas service compare to the
24 increases originally requested by Avista?
25 A. Avista originally proposed to increase annual
CASE NOS. AVU-E-12-08/AVU-G--12-07 LOBB, R. (Stip) 3
02/25/13 STAFF
1 electric revenue by $11.393 million (or 4.6%) and annual
2 natural gas revenue by $4.561 million (or 7.2%) effective
3 April 1, 2013. The Company requested a 10.9% return on
4 equity with an 8.46% overall rate of return.
5 The Stipulation provides for no increase in
6 electrical rates on April 1, 2013 and a $7.825 million, 3.2%
7 annual revenue increase October 1, 2013. Annual natural gas
8 revenues would increase by $3.12 million or 4.92% on April 1,
9 2013 and $1.33 million or 2.0% on October 1, 2013. A key
10 difference between the Company's original proposal in this
11 case and the Stipulation is the prohibition on any additional
12 base rate increases through January 1, 2015.
13 The stipulated electric increase is about 68% of
14 the Company's original proposal and delays implementation of
15 the rate increase for six months. The proposed increase in
16 natural gas revenue on April 1, 2013 is also about 68 9o- of the
17 Company's original proposal. However, combined with the
18 second phase of the natural gas increase on October 1, 2013,
19 the Settlement represents about 98% of the Company's original
20 application for natural gas. Under the Company's original
21 proposal, the rate increases would have all taken effect on
22 April 1, 2013 and the Company could have realistically filed
23 three more general rate cases before the January 1, 2015
24 stay-out date stipulated in the Settlement.
25 Staff Investigation
CASE NOS. AVU-E-12-08/AVU-G-12-07 LOBB, R. (Stip) 4
02/25/13 STAFF
1 Q. What type of investigation did Staff conduct to
2 evaluate the Company's rate increase request?
3 A. Staff began analyzing the Company's filing on
4 August 29, 2012, with 21 Commission Staff members assigned to
S the case. Staff submitted 199 formal production requests to
6 the Company and numerous formal and informal audit requests.
7 Staff also reviewed the latest Avista electric and natural
8 gas rate case filings in the State of Washington, including
9 over 300 data requests and responses. Three Staff
10 accountants each conducted a week long on-site audit of
11 Company books and reviewed external auditor workpapers.
12 Q. What areas and issues were specifically identified
13 and assigned for review?
14 A. Capital expenditures and plant investment in
15 generation, transmission, distribution and information
16 technology were specifically identified for both gas and
17 electric service and were separately evaluated. Return on
18 equity, capital structure and cost of debt were evaluated and
19 determined. Staff examined and verified operation and
20 maintenance expenses including electric power supply costs,
21 natural gas purchase costs, taxes, depreciation, salaries,
22 level of workforce, consultant costs, incentive pay and
23 vegetation management costs.
24 Staff also evaluated the Company's proposed Energy
25 Efficiency Load Growth Adjustment, Jurisdictional allocation
CASE NOS. AVIJ-E-12-08/AvU-G-12-07 LOBB, R. (Stip) 5
02/25/13 STAFF
1 methodology, class cost of service methodology and rate
2 design options.
3 Q. What type of adjustments to the Company's proposed
4 electric revenue requirement did Staff identify?
5 A. Staff particularly focused on possible adjustments
6 in five primary areas: 1) rate of return, 2) power supply
7 expenses, 3) 2012/2013 capital investment and O&M expenses,
8 4) salaries, and 5) miscellaneous test year expenses. Staff
9 developed positions on individual adjustments in each of
10 these five categories then refined and quantified the revenue
11 requirement impact of each in preparation for pre-filed
12 direct testimony.
13 With respect to rate of return, Staff believed that
14 9.8% return on equity was reasonable, calculated a debt cost
15 of 5.98% and identified a capital structure of 53% debt and
16 47% equity. The resulting overall return of 7.84% reduced
17 the Company's proposed annual revenue requirement by an
18 estimated $6 million.
19 Power supply adjustments included removing expenses
20 and benefits associated with the Company's Palouse Wind power
21 purchase agreement, reducing forced outage rates for the
22 Company's coal fired power plants and modifying load
23 forecasts by improving weather normalization methodology and
24 removing the proposed Energy Efficiency Load Adjustment.
25 Eliminating the effect of Palouse Wind from power supply
CASE NOS. AVU-E-12-08/AVU-G-12-07 LOBB, R. (Stip) 6
02/25/13 STAFF
1 reduced annual expenses by an estimated $2.9 million on a
2 normalized basis.
3 Staff proposed to remove 2013 Capital additions,
4 O&M expenses and Information Technology (IT) investments to
5 limit test year proforma through December 31, 2012. In
6 addition to adjustment for 2013 salary increases, Staff
7 identified adjustments for prior year salary increases for
8 nonexecutive labor starting in 2011. Staff also identified
9 adjustments for executive officer incentives and the effects
10 of the Company's announced workforce reduction.
11 Finally, Staff identified 10 other individual
12 miscellaneous annual adjustments ranging from $400,000 for
13 unspent vegetation management to $1,000 for transmission
14 training and travel. The combined impact of this category of
15 adjustments was estimated at approximately $1 million.
16 Q. What type of adjustments did Staff identify for
17 natural gas revenue requirement and what was the impact?
18 A. Most of the adjustments identified by Staff on the
19 electric side were applied to the natural gas revenue
20 requirement as well. These adjustments included rate of
21 return, 2013 capital additions and O&M, salary/workforce
22 expenses and many of the miscellaneous items. These
23 adjustments totaled approximately $1.6 million on an annual
24 basis.
25 Staff's investigation of the Company's application
CASE NOS. AVtJ-E-12-08/AVU-G-12-07 LOBB, R. (Stip) 7
02/25/13 STAFF
1 was essentially complete and all of the adjustments were
2 identified prior to settlement discussions. Staff was in the
3 process of refining its position on the various issues in
4 preparation for presentation at hearing.
5 The Settlement Process
6 Q. Would you please describe the process leading to
7 the Stipulated Settlement?
8 A. Yes. The Company filed its rate application with
9 the Commission on August 29, 2012 and Staff immediately began
10 its investigation. The first settlement conference was held
11 on January 17, 2012 in the Commission hearing room with all
12 parties of record in the case invited to participate.
13 Workshop participants included Commission Staff, Avista,
14 Clearwater Paper Company, Idaho Forest Group, the Community
15 Action Partnership of Idaho (CAPAI) and the Idaho
16 Conservation League. The Snake River Alliance (SPA) was a
17 party to the case but did not participate in the Conference.
18 Settlement discussions focused on revenue
19 requirement issues such as capital budget requirements,
20 appropriate return on equity, Capital Structure, Company
21 salaries, O&M expenses, load adjustments, acceptable test
22 period and the acquisition costs associated with the Palouse
23 Wind project. Given the wide disparity in the revenue
24 requirement position of the various parties, the possibility
25 of a multi-year rate agreement was also discussed as an
CASE NOS. AVU-E-12-08/AVtJ--G-12-07 LOBB, R. (Stip) 8
02/25/13 STAFF
1 avenue to settlement.
2 Q. Was settlement reached at that time?
3 A. No. The parties could not reach agreement and
4 convened a second settlement conference on January 24, 2013.
5 Again, all parties participated except the SPA. The second
6 conference focused primarily on needed capital additions over
7 the next two years, the costs and benefits of the Palouse
8 Wind project and how a two-year rate plan might be
9 structured. After numerous proposals and counter proposals,
10 with give and take by all parties, a two-year rate agreement
11 was ultimately reached. The Stipulation and Settlement was
12 filed with the Commission on February 6, 2013.
13 Settlement Evaluation
14 Q. How did Commission Staff evaluate the Stipulated
15 Settlement to determine that it was reasonable?
16 A. Staff evaluated the merits of the Settlement in
17 this case for both electric and gas service by looking
18 closely at each of the Staff identified revenue requirement
19 adjustments to assess how they might hold up at hearing.
20 Staff also evaluated the potential for and the
21 likely impact of additional Avista general rate case filings
22 during the proposed Settlement stay-out period. The overall
23 objective of Staff's assessment was to achieve the best
24 outcome for customers with respect to base rates in this case
25 and with respect to base rate increases that might otherwise
CASE NOS. AVU-E-12-08/AVU-G-12-07 LOBB, R. (Stip) 9
02/25/13 STAFF
1 occur due to additional general rate filings during the
2 Settlement stay-out period.
3
Q. Why did Staff conclude that the Settlement was
4 better than the alternative?
5 A. Although Staff identified significant adjustments
6 to propose at hearing it is unlikely Staff would have
7 prevailed on all or most of them. Many proposed adjustments
8 were to costs and expenses the Company already incurred or
9 will incur in 2013. For example, Staff proposed to eliminate
10 recovery of worker salary increases starting in 2011, but
11 Avista certainly could make a case at hearing that these wage
12 increases were fair and prudent, and they were actually paid
13 by the Company. Some of Staff's proposed adjustments were to
14 capital costs in 2012 and 2013. Staff did not conclude from
15 its investigation that these costs were imprudent, so even if
16 Staff had prevailed on these adjustments in this case, it
17 would only delay Avista's recovery until the next rate case.
18 This would likely make certain that Avista would immediately
19 file another case and perhaps another after that.
20 Q. Could you please describe Staff's position
21 regarding other issues specified in the Settlement?
22 A. Yes. The Settlement specifies a 9.8% return on
23 equity, a 6.1% cost of debt and a capital structure of 50%
24 equity and 50% debt for an overall 7.91% rate of return.
25 Staff believes the resulting overall rate of return is
CASE NOS. AVU-E-12-08/AVU--G-12-07 LOBE, R. (Stip) 10
02/25/13 STAFF
1 justified and a reasonable compromise in this case. It
2 reflects the same return on equity recently approved for
3 Avista by the Washington Commission. It also reflects a
4 current actual cost of debt that is slightly higher than
5 previously calculated by Staff and an imputed rather than
6 actual capital structure. The imputed Capital Structure is
7 consistent with past cases and representative of the
8 estimated December 2013 Capital Structure.
9 The Settlement also specifies annual power supply
10 expenses for use in the Power Cost Adjustment mechanism.
11 Staff adjustments reflecting forced outage rates, weather
12 normalization and the energy efficiency load adjustment are
13 not captured in stipulated power supply expenses. Staff,
14 recognizes that actual expenses associated with these
15 adjustments will effectively flow through the Power Cost
16 Adjustment mechanism whether they are included in base rates
17 or not.
18 Staff will further evaluate the Company's weather
19 normalization methodology and the affects of energy
20 efficiency programs on load forecasts in subsequent rate
21 cases.
22 Q. How did Staff incorporate reduction in expenses
23 associated with the Company's announced voluntary reduction
24 in workforce?
25 A. Staff originally identified the test year costs and
CASE NOS. AVU-E-12--08/AVtJ-G-12-07 LOBB, R. (Stip) 11
02/25/13 STAFF
1 benefits of the workforce reduction program to determine the
2 net effect on annual revenue requirement. The workforce
3 reduction benefits or costs were not included in the
4 Company's Application. Staff analysis showed that actual
5 test year expenses to implement the program exceeded test
6 year benefits (due to expensing in a single year). However,
7 in subsequent years, benefits of the program will continue
8 while program expense will not. Staff therefore, amortized
9 the expense over several years to assure a test year benefit.
10 Staff ultimately determined that if reasonable
11 settlement on revenue requirement is achieved in this case,
12 the full benefit of workforce reduction can still be captured
13 in future test years without any expense offset. Staff
14 therefore, conceded the issue as part of the Settlement.
15 Q. Could you please address Staff's position regarding
16 the Settlement's treatment of Palouse Wind project costs?
17 A. Yes. For purpose of settlement in this case, the
18 costs and benefits associated with the Palouse Wind power
19 purchase agreement are not included as normal power supply
20 expenses in base rates. Rather, the net costs/benefits are
21 tracked and recovered through the Power Cost Adjustment
22 mechanism at 90%. This represents a compromise from Staff's
23 original position that would have excluded Palouse project
24 costs from any rate recovery until it was shown to be needed
25 to serve Idaho load.
CASE NOS. AVU-E-12-08/AVtJ-G-12-07 LOBB, R. (Stip) 12
02/25/13 STAFF
1 Staff objected to the project because the Company
2 acquired it to satisfy a Washington State Renewable Portfolio
3 Standard without any immediate need to serve load. Moreover,
4 Staff determined that the project power supply expenses would
5 exceed project benefits under near term normalized load and
6 power supply conditions.
7 However, Staff recognized that the project will
8 likely be economical for Idaho customers over the 20-year
9 contract life and could be economical over the next two years
10 under a variety of load and resource conditions. Staff also
11 recognized that the project could provide additional value
12 through the sale of renewable energy credits and could likely
13 be justified to meet load by 2015. Consequently, Staff
14 deemed that treatment through the Power Cost Adjustment
15 mechanism, with partial contribution of net project expense
16 by the Company, reasonably resolved this issue.
17 Q. What types of capital costs are included in this
18 case and how are they treated in the two-year Settlement?
19 A. Capital investment included in this case makes up
20 about 70 9. of the Company's electric revenue increase request
21 and 48% of the natural gas increase request. Staff's
22 investigation shows that 94% of the 2012 investments were to
23 replace aging infrastructure or upgrade existing plant. In
24 2013, over 96% of the capital investment was to replace or
25 upgrade existing plant. Staff identified reasonable
CASE NOS. AVU-E-12-08/AVU-G-12-07 LOBE, R. (Stip) 13
02/25/13 STAFF
1 expenditures for distribution plant replacement on the gas
2 and electric side as well as radio and customer service
3 software used to serve all utility customers.
4 While Staff supports maintaining service quality
5 and assuring safety by replacing aging infrastructure such as
6 distribution poles and conductors and Adyl-A natural gas
7 pipeline, Staff questions the timing for inclusion in rates.
8 Staff limited proforma test year plant additions to December
9 31, 2012. Consequently, 2012 investment was included for
10 base rate recovery on April 1, 2013. But 2013 investment was
11 not allowed in base rates until October 1, 2013. The
12 attached Settlement shows how 2013 capital additions were
13 removed from the April increase and added back for the
14 October increase.
15 With respect to vegetative management expenses,
16 Staff originally proposed an adjustment to reduce the amount
17 requested in the Application to reflect expenses actually
18 incurred. As part of the Settlement, Staff agreed that
19 customers would be better served if the requested vegetative
20 management expenses were maintained and actually put toward
21 the intended purpose.
22 Cost of Service/Rate Design
23
Q. Please describe the Stipulated Settlement with
24 respect to customer class cost of service and rate design.
25 A. The Settlement spreads the Idaho jurisdictionally
CASE NOS. AVU-E-12-08/AvU-G-1207 LOBE, R. (Stip) 14
02/25/13 STAFF
1 allocated revenue requirement to customer classes based on
2 the Company's proposed gas and electric cost of service
3 studies. The studies showed that residential customers were
4 paying a smaller than necessary part of the cost while larger
5 customers were paying more than necessary.
6 Staff evaluated the results of the cost of service
7 studies by first ensuring that the underlying jurisdictional
8 allocation methodology assigned a reasonable portion of
9 electric and natural gas system costs to Idaho. Staff then
10 evaluated various cost of service methodologies on the
11 electric side to determine how customer classes were affected
12 by the differences. While not adopting a specific
13 methodology, Staff agrees that the cost of service move for
14 the various gas and electric customer classes as proposed by
15 the Company is reasonable in this case (25 5.1, move toward cost
16 of service for gas customer classes and 15 move for electric
17 customer classes) . Consequently, Staff supports the prorated
18 application of the Company's cost of service studies based on
19 the stipulated gas and electric revenue requirement
20 increases.
21
Q. Does the Settlement provide for changes in rate
22 design?
23 A. No. Existing rate design will not change for
24 either electric or gas customers, and the monthly residential
25 customer charges will not increase. All of the proposed
CASE NOS. AVtJ-E-12-08/AVtJ-G-12-07 LOBB, R. (Stip) 15
02/25/13 STAFF
1 revenue increase will be applied uniformly to the energy
2 component of rates. Staff maintains that these rate changes
3 are reasonable given the limited change in overall revenue
4 requirement.
5
Q. What rate offsets are available to mitigate the
6 base rate increases?
7 A. The parties have agreed to use $3.865 million in
8 Bonneville Power Administration Settlement Revenue beginning
9 October 1, 2013 to partially offset the electric base rate
10 increase. The revenue represents Idaho's share of money that
11 the Bonneville Power Administration must pay Avista for
12 having used Avista's transmission system. It will be used to
13 reduce the billed energy rate over the period of October 1,
14 2013 through December 31, 2014.
15 The natural gas base rate increase will be
16 partially offset by a $1.55 million un-refunded credit
17 balance held back by the Commission in the most recent
18 purchased gas adjustment case, Case No. AVU-G-12-05. The
19 Commission held the credit refund plus interest in
20 anticipation of Avista filing a natural gas general rate
21 case. The Parties agreed to refund the credit balance over
22 the period October 1, 2013 through December 31, 2014. Staff
23 believes returning the credit during the 15-month period
24 beginning in October provides the greatest benefit to
25 residential gas and electric customers.
CASE NOS. AVU-E-12-08/AVU-G-12-07 LOBB, R. (Stip) 16
02/25/13 STAFF
1
Q. How does the proposed base rate Settlement impact
residential customer bills?
3 A. The net effect of the electric base rate increase
4 and partially offsetting credit is about a $2.21 per month
5
increase for a residential customer using 1000 kWh. This
6
increase will not take effect until October 1, 2013 with the
7 credit lasting through December of 2014.
8 The net effect of the gas base rate increase
9
beginning April 1, 2013 will be $4.69 per month for a
10 residential customer using 100 therms. The net effect of the
11 gas base rate change and partially offsetting credit on
12 October 1, 2013 will be $0.51 per month increase for a
13 residential customer using 100 therms.
14
Q. Does this conclude your testimony in this case?
15 A. Yes, it does.
16
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18
19
20
21
22
23
24
25
CASE NOS. AVU-E-12-08/AVU-G-12-07 LOBE, R. (Stip) 17
02/25/13 STAFF
David J. Meyer, Esq.
Vice President and Chief Counsel of
Regulatory and Governmental Affairs
Avista Corporation
1411 E. Mission Avenue
P.O. Box 3727
Spokane, Washington 99220
Phone: [phone], Fax: [phone]
REC El yE.
103FE87 P11 2::i
IDAHO PiF3uc
UT1LI1S COiM1SS1ON,
Karl Klein
Weldon Stutzman
Deputy Attorneys General
Idaho Public Utilities Commission Staff
P.O. Box 83720
Boise, ID 83720-0074
Phone: [phone], Fax: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF AVISTA CORPORATION DBA AVISTA ) CASE NOS. AVU-E-12-08
UTILITIES FOR AUTHORITY TO ) AVU-G-12-07
INCREASE ITS RATES AND CHARGES )
FOR ELECTRIC AND NATURAL GAS )
SERVICE IN IDAHO ) STIPULATION AND SETTLEMENT
This Stipulation is entered into by and among Avista Corporation, doing business as
Avista Utilities ("Avista" or "Company"), the Staff of the Idaho Public Utilities Commission
("Staff), Clearwater Paper Corporation ("Clearwater"), Idaho Forest Group, LLC ("Idaho
Forest") and the Idaho Conservation League ("Conservation League")'. These entities are
collectively referred to as the 'Parties," and represent several parties in the above-referenced
cases that participated in settlement discussions. The Parties understand this Stipulation is
subject to approval by the Idaho Public Utilities Commission ("IPUC" or the "Commission").
The Community Action Partnership Association of Idaho ("CAPAI") participated in settlement discussions and is
continuing to review its position with regard to the Settlement, as proposed, and will be filing separate comments
and/or testimony in that regard. The Snake River Alliance, as an intervenor, was provided notice of the settlement
discussions, but did not participate.
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page I
Exhibit No. 101
Case Nos. AVU-E-12-08I
AVU-G-12-07
R. Lobb, Staff
02/25L13 Page 1 of 39
I.INTRODUCTION
I. The terms and conditions of this Stipulation are set forth herein. The Parties agree
that this 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 represents a
reasonable resolution of the multiple issues identified in these cases. The Parties, therefore,
recommend that the Commission, in accordance with RI 274, approve the Stipulation and all of
its terms and conditions without material change or condition.
II.BACKGROUND
2.On October 11, 2012, Avista filed an Application with the Commission for
authority to increase revenue from electric and natural gas service in Idaho by 4.6% and 7.2%,
respectively. If approved, the Company's revenues for electric base retail rates would have
increased by $11.4 million annually; Company revenues for natural gas service would have
increased by $4.6 million annually. The Company requested an effective date of April 1, 2013
for its proposed electric and natural gas rate increases. By Order No. 32689, dated December 4,
2012, the Commission suspended the proposed schedules of rates and charges for electric and
natural gas service.
3.Petitions to intervene in this proceeding were filed by Clearwater, Idaho Forest,
CAPAI, the Idaho Conservation League, and the Snake River Alliance. By various orders, the
Commission granted these interventions. See, IPUC Order Nos. 32678, 32680 and 32687.
4.Settlement conferences were noticed and held in the Commission offices on
January 17 and 24, 2013, and were attended by signatories to this Stipulation; further discussions
ensued. Based upon the settlement discussions among the Parties, as a compromise of positions
STIPULATION AND SETTLEMENT AVU-E-12-08 &AVU-G-12-07 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 2of39
in this case, and for other consideration as set forth below, the Parties agree to the following
terms:
III. TERMS OF THE STIPULATION AND SETTLEMENT
5. Overview of Settlement and Revenue Requirement. The Parties agree that Avista
should be allowed to implement revised tariff schedules designed to recover the following
revenue requirement in two steps, as summarized in Attachment A, and below:
Electric
Step 1: April 1, 2013
a. No electric base rate change effective April 1, 2013, instead of the proposed
4.6%, or $11.393 million.
Step 2: October 1, 2013
a.Overall electric base rate increase of 3.1% (3.2% in billed rates) or $7.825 million
effective October 1, 2013.
b.Offsets - Apply $3.865 million for rate mitigation purposes (the BPA Parallel
Operation Settlement 2), and amortize that offset over 15 months, from October 1,
2013 to December 31, 2014.
C. Net overall bill increase to customers of 1.9% effective October 1, 2013.
Summary of Electric Rate Changes
Billing Rate Net Billing
Change Offset Rate Change
April 1, 2013 0.0% 0.0% 0.0%
October 1, 2013 3.2% -1.3% 1.9%
2 The BPA Settlement Revenue of $3.865 million represents the Idaho customers share of $12,224 million (system)
for the past use of Avista's transmission system for the period January 2005 through February 2013. In December
2012, Avista and Bonneville reached a settlement that pertains to the use of Avista's transmission system by
Bonneville. Avista and Bonneville each own and operate transmission systems that are interconnected at various
points, Between June 1998 and December 2009, Bonneville integrated four generation projects onto its 115 kV
transmission system in the Walla Walla, Washington area. Bonneville sold transmission capacity to wind projects
totaling 336 MW. The transmission path for these four projects follows a single Bonneville line that has a rated
capacity of only 203 MW. Upon Avista's discovery of this situation, Avista asserted that Bonneville requires the
use of up to 133 MW of parallel capacity support through the Avista system in order to fulfill Bonneville's
transmission service obligations for these wind projects. The Settlement Agreement was intended to resolve the
issue of compensation to Avista for the prior use of its transmission system, as well as provide Bonneville with
continuing cost-effective parallel capacity support in lieu of constructing additional transmission facilities at this
point in time. Avista anticipates FERC approval of the Settlement in February 2013, after which Avista will bill
Bonneville.
STIPULATION AND SETTLEMENT—AVU-E-12-08 & AVU-G-12-07 Exhibit No. 10 1
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 3 of 39
Natural Gas
Step 1: Apri 11, 2013
a. Overall natural gas base rate increase of 4.9% (5.0% in billed rates) or $3.115
million, instead of the proposed 7.2%, or $4.561 million, effective April 1, 2011
Step 2: October 1. 2013
a.Overall natural gas base rate increase of 2.0% (2.0% in billed rates) or $1.330
million effective October 1, 2013.
b.Offsets - Apply $ 1.550 million PGA deferral credit balance from 2012 PGA 3 to
partially offset the base rate increase, amortized over 15 months, October 1, 2013
to December 31, 2014.
C. Net overall kilt impact to customers of 0.3% effective October 1, 2013.
Summary of Natural Gas Rate Changes
Billing Rate Net Bililig
Change Oflet Rate Change
April 1, 2013 5.0% 0.0% 5.0%
October 1, 2013 2.0% -1.7% 0.3%
6. Cost of Capital. The Settling Parties agree to a 9.8 percent return on equity, with
a 50.0 percent common equity ratio, and adopt the capital structure and resulting rate of return as
set forth below:
Capital ProForma ProForma
Component i Structure Cost Weighted Cost
Total Debt i
Common Equity
50.000/0
50.00%
6.01% j
9.80%
3.01%
4.90%
7.91% Total 100.00%
In Docket AVU-G-12-05, the Commission approved Staff's proposal that approximately $1.55 million in un-
refunded credit balances be held back due to the Company's filing of a "Notice of Intent to File a General Rate
Case." The Commission stated in Order 32651, on page 6, that "the resulting $1.55 million un-refunded credit
balance will help mitigate potential rate increases and provide rate stability for customers."
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 pA..................
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13Page 4 of 39
A. ELECTRIC
7. Overview of Electric Revenue Requirement (April 1. 2013). Below is a summary
table and descriptions of the electric revenue requirement components agreed to by the Parties
for April 1, 2013:
SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
Amount as Filed:
Adjustments:
a.) Cost of Capital
b.) Remove 2013 Capital Additions (Delay to October 1, 2013)
c.) Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
I. Major Generation O&M
ii.Information Services & Technology
iii.CS2 Levelized Return
iv.Non-Exec Labor
d.) Remove 2013 Property Tax Expense
e.) Remove Officer Incentive and CPI escalation
C) Two-Year Amortization of Reardan
g.)Include Palouse Wind in PCA until in base rates in 2015 (900/o/100/o sharing)
h.)Misceilaneouse Adjustments: Two-Year Amortization of Booz Consulting
costs, Oasis Training, Abandoned Projects & Depreciation Study expense
Adjusted Amounts Effective April 1, 2013
Revenue
Requirement Rate Base
$ 11,393 $ 639,030
$ (5,517)
$ (1,117) $ (
$ (926)
$ (318)
$ (38)
$ (426)
$ (428)
$ (187)
$ 878
$ (3,139)
$ (175) ______
$ - $637
a.Cost of CaDital. As previously described (see Paragraph 6 above).
b.Remove 2013 Capital Additions. Reflects total depreciation expense and rate
base, net of accumulated depreciation and accumulated deferred income tax,
as of year-end December 31, 2012. Moves 2013 capital additions to October
1, 2013 rate change.
c.Remove 2013 Expenses: Delay Recovery to October 1. 2013 Rate Change.
i. Major Generation O&M. Removes the 2013 incremental non-
labor generation plant operation and maintenance (O&M) expense
related to the Company's thermal generation plant at Kettle Falls,
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 PawS ---- - Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 5 of 39
and its hydro generation plants, to be included in the October 1,
2013 rate change.
ii.Information Services & Technology. Removes the 2013
incremental information service and technology expenses, related
mainly to the Company's replacement of the Company's Customer
Service Information System, and increased costs to support various
business processes, application support, additional security
requirements, annual contractual agreements and maintenance and
license fees, to be included in the October 1, 2013 rate change.
iii.CS2 Levelized Return. Removes the 2013 incremental
amortization of the deferred levelized return related to the 10-year
deferral of return on the Coyote Springs 2 (CS2) investment, to be
included in the October 1, 2013 rate change.
iv.Non-Exec Labor. Removes the 2013 incremental non-executive
labor increases, to be included in the October 1, 2013 rate change.
d.2013 Property Tax. Removes the 2013 incremental property tax expense,
adjusting property tax expense to December 31, 2012 levels.
e.Remove Officer Incentive and CPI Escalation. Removes officer portion of
incentives and removes the Consumer Price Index adjustment on incentives
included in the Company's original filing.
f.Two-Year Amortization of Reardan. See Paragraph 10 below for further
information.
g.Include Palouse Wind in PCA until Reflected in Base Rates in 2015. See
Paragraph 9 below for further information.
STIPULATION AND SETTLEMENT—AVU-E-12-08 & AVU-G-12-07 - Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 6 of 39
h. Miscellaneous Adjustments. Includes a two-year amortization of Booz & Co.
consulting fees, thereby reducing test period expenses, and removes certain
other amounts related to OASIS training, abandoned projects and depreciation
study expenses.
8. Overview of Electric Revenue Requirement (October 1, 2013). Below is a
summary table and descriptions of the Electric revenue requirement components agreed to by the
Parties for October 1, 2013:
SUMMARY TABLE OF ELECTRIC REVENUE REQUIREMENT
EFFECTIVE OCTOBER 1, 2013
000s of Dollars
Revenue
Requirement Rate Base
Amounts Effective April 1, 2013
Adjustments to October 1, 2013 Rate Change:
a.)2013 Capital Additions
b.)2014 Capital Additions
c.)Add 203 Expenses
L Major Generation O&M
II. Information Services & Technology
lii. CS2 Levehzed Return
iv. Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
$ 5,488 $ 20,705
$ 629 $ 888
$ 926
$ 318
$ 38
$ 426
$ 7,825
a.2013 Capital Additions. Includes 2013 capital additions, reflecting total
depreciation expense and rate base, net of accumulated depreciation and
accumulated deferred income tax, as of year-end December 31, 2013.
b.2014 Capital Additions. Includes certain 2014 capital additions, including
depreciation expense and rate base, net of accumulated depreciation and
accumulated deferred income tax, to represent an agreed-upon level of rate
base.
c.2013 Expenses:
STIPULATION AND SETTLEMENT - AVU-E- 12-08 & AVU-G- 12-07 Page 7
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 7 of 39
i.Major Generation O&M. Includes the 2013 incremental non-labor
generation plant O&M expense discussed above in Paragraph
7(c)(i).
ii.Information Services & Technology. Includes the 2013
incremental information service and technology expenses
discussed above in Paragraph 7(c)(ii).
iii.CS2 Levelized Return. Includes the 2013 incremental
amortization of the deferred CS2 levelized return discussed above
in Paragraph 7(c)(iii).
iv.Non-Exec Labor. Includes the 2013 incremental non-executive
labor increases discussed above in Paragraph 7(c)(iv).
9.Palouse Wind. The Parties agree that recovery of costs related to the Palouse
Wind Power Purchase Agreement ("PPA") will be included in the PCA, subject to the current
sharing (90% customer, 10% Company) until it is included in base rates as part of the
implementation of new rates from the Company's next general rate case anticipated in 2015.
10.Reardan Wind Site Deferral. The Parties agree to amortize the Reardan Wind
Project deferred balance of $1.747 million over a two-year period beginning April 1, 2013.
11.Amortization of 2013 Coyote Springs 2/Colstrip Maintenance Deferral. The
Parties agree that the amount deferred in 2013 related to the Company's O&M costs of its
Coyote Springs 2 (CS2) natural gas-fired generating plant and its fifteen (15) percent ownership
In May 2008, Avista purchased the Reardan Wind Project Site from Energy Northwest, the then-current developer,
after it was demonstrated as the Company's least-cost option for securing a renewable resource for its customers,
consistent with its 2007 Integrated Resource Plan. Avista later chose to delay the construction of the Reardan
project and take advantage of much-lower costs for wind projects that emerged in 2011 (Palouse Wind). Avista
recorded $4.0 million of site acquisition and preparation costs, of which approximately $1.7 million is Idaho's share.
This includes approx. $0.37 million in AFUDC in accordance with Order No. 30611 (Case No. AVU-E-08-04)
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-0-12-07 Page 8 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 8 of 39
share of the Colstrip 3 & 4 coal-fired generating plants will be amortized over three years,
beginning with the implementation of new base rates resulting from the Company's next general
rate case filing.5
B. NATURAL GAS
12. Overview of Natural Gas Revenue Requirement (April 1. 2013). Below is a
summary table and descriptions of the Natural Gas revenue requirement components agreed to
by the Parties:
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
Revenue
Requirement Rate Base
Amount as Filed: $ 4,561 S 110,930
Adjustments:
a.) Cost of Capital $ (957)
b) Remove 2013 Capital Additions (Delay to October 1, 2013) $ (22) $ 1,309
c.) Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
I. Information Services & Technology $ (42)
ii. Non-Exec Labor $ (215)
d.) Remove 2013 Property Tax Expense $ (84)
e.) Remove Officer Incentive and CPI escalation $ (50)
E) MisceUaneouse Adjustments: Two-Year Amortization of Booz Consulting $ (76)
costs, Injuries & Damages, Abandoned Projects & Depreciation Study
expense
Adjusted Amounts Effective April 1, 2013 $ 3,115 $ 112,239
a.Cost of Capital. As previously described (see Paragraph 6 above).
b.Remove 2013 Capital Additions. Reflects total depreciation expense and rate
base, net of accumulated depreciation and accumulated deferred income tax,
Per Order No. 32371 in Case No. AVU-E- 11-01, in order to address the large variability in year-to-year O&M
costs, beginning in 2011, the Company was allowed to defer changes in O&M costs related to its Coyote Springs 2
(CS2) natural gas-fired generating plant located near Boardman, Oregon, and its fifteen (15) percent ownership
share of the Colstrip 3 & 4 coal-fired generating plants located in southeastern Montana. The Company compares
actual, non-fuel, O&M expenses for the Coyote Springs 2 and Colstrip 3 & 4 plants with the amount of expenses
authorized for recovery in base rates in the applicable deferral year, and defers the difference from that currently
authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized over a three-
year period, beginning in January of the year following the period costs are deferred.
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 9of39
as of year-end December 31, 2012. Moves certain 2013 capital additions to
the October 1, 2013 rate change.6
c. Remove 2013 Expenses: Delay Recovery to October 1. 2013 Rate Change.
i.Information Services & Technology. Removes the 2013
incremental information service and technology expenses as
discussed above, to be included in the October 1, 2013 rate change.
ii.Non-Exec Labor. Removes the 2013 incremental non-executive
labor increases as discussed above, to be included in the October 1,
2013 rate change.
d. 2013 Property Tax. Removes the 2013 incremental property tax expense,
adjusting property tax expense to December 31, 2012 levels.
e. Remove Officer Incentive and CPI Escalation. Removes officer portion of
incentives and removes the Consumer Price Index adjustment on incentives
included in the Company's original tiling.
f. Miscellaneous Adjustments. Includes a two-year amortization of Booz & Co.
consulting fees, thereby reducing test period expenses, and removes certain
other amounts related to injuries and damages, abandoned projects and
depreciation study expenses.
6 In the Company's filed case, inclusion of total net plant, including accumulated depreciation and accumulated
deferred income tax on an average-of-monthly-average basis for 2013, had the effect of reducing rate base by $1.309
million and increasing revenue requirement associated with a net increase in depreciation expense by $22,000. This
is due to the original filed adjustment that depreciated all plant, including the plant in service balance at December
31, 2012, to the AMA balance at December 31, 2013. The additional accumulated depreciation on plant in service
at December 31, 2012 was greater than the net plant additions in 2013 on an AMA basis, which had an overall
impact of reducing net rate base.
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Pau i0 - Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 10 of 39
13. Overview of Natural Gas Revenue Requirement (October 1. 2013). Below is a
summary table and descriptions of the Natural Gas revenue requirement components agreed to
by the Parties:
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE OCTOBER 1, 2013
000s of Dollars
Amounts Effective April 1, 2013
Adjustments to October 1, 2013 Rate Change:
a.)2013 Capital Additions
b.)Add 2013 Expenses
i.Information Services & Technology
ii.Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
Revenue
Requirement Rate Base
$ - $ 112,239
$ 1,073 $ 3,8311
$ 42
$ 215
$ 1,330 1 11
a.2013 Capital Additions. includes certain 2013 capital additions, including
depreciation expense and rate base, net of accumulated depreciation and
accumulated deferred income tax, to represent an agreed-upon level of rate
base
b.2013 Expenses:
i.Information Services & Technology. Includes the 2013
incremental information service and technology expenses
discussed above in Paragraph I 2(c)(i).
ii.Non-Exec Labor. Includes the 2013 incremental non-executive
labor increases discussed above in Paragraph 1 2(c)(ii).
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Exhibit No. 101
Case Nos, AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page ilof 39
C. OTHER SETTLEMENT COMPONENTS
14.PCA Authorized Level of Expense. The new level of power supply expense, retail
load and Clearwater Paper generation, and the April 1, 2013 and October 1, 2013 Load Change
Adjustment Rates resulting from the April 1, 2013 and October 1, 2013 settlement revenue
requirements for purposes of the monthly PCA mechanism calculations, are detailed in
Attachment B. The parties agree for the purpose of Settlement in this case to accept the
Company's normalized load forecast without specifically accepting the weather normalization
methodology or the proposed Energy Efficiency Load Adjustment.
15.Depreciation Rates. The Parties have agreed to the updated electric and natural
gas depreciation rates as filed by the Company, with all common/allocated plant depreciation
rates, including the new depreciation rates for transportation equipment, effective January 1,
2013 to coincide with the Company's Washington and Oregon jurisdictions, with the remaining
direct Idaho plant depreciation rate changes effective April 1, 2013.
16.Earnings Test. The Company agrees to an after-the-fact earnings test, where it
would refund to customers one-half of any earnings in excess of the 9.8% ROE for each of the
years 2013 and 2014, to allay any concerns that the base rate relief in April 1, 2013 and October
1, 2013 may allow the Company to exceed its authorized return. The earnings test would be
based on actual, consolidated results for Idaho electric and natural gas operations.
17.Rate Freeze/Stay Out. The Parties agree that, in recognition of the two-year rate
plan covered by this Stipulation, Avista will not file another electric or natural gas general rate
case before May 31, 2014, and while it may request an effective date earlier than January 1,
2015, final approved new rates will not go into effect prior to January 1, 2015. This does not
apply to tariff filings authorized by or contemplated by the terms of the Power Cost Adjustment
(PCA), or the Purchased Gas Adjustment tariff (PGA), or other miscellaneous filings.
12 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 12 of 39
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07
D. COST OF SERVICE/RATE SPREAD/RATE DESIGN
18. Cost of Service. For electric operations, the Company prepared an analysis using
a peak credit method of classifying production costs, allocating 100% of transmission costs to
demand, and allocating transmission costs on a twelve-month basis. For settlement purposes, the
Parties agreed to use a pro-rata allocation based on the Company's proposed 15% move towards
unity for purposes of spreading the revised electric revenue requirement, while not agreeing on
any particular cost of service methodology.
For natural gas operations, the Company proposed that all rate schedules be moved
approximately 25% towards unity. For settlement purposes, the Parties agreed to use a pro-rata
allocation of the Company's natural gas rate spread percentages from its original filing for
purposes of spreading the revised revenue requirement.

19. Rate Spread/Rate Design (Base Rate Changes).
(a)As indicated above, the Parties agreed that the increase in base revenues
would be spread to all electric and natural gas rate schedules on a pro-rata allocation of
the Company's rate spread percentages from its original filing.
(b)The Parties agree that the revenue requirement for each electric and natural
gas service schedule will be applied as a uniform percentage increase to each volumetric
energy rate as shown in Attachment C. The Parties agree that there will be no change to
Schedule 1 and Schedule 101 basic charges.
(c)Attachment C provides a summary of the current and revised rates and
charges (as per the Settlement) for electric and natural gas service.

20. Rate Spread/Rate Design (Offsets).
STIPULATION AND SETTLEMENT - AVU-E- 12-08 & AVU-G-1 2-07 Page i3 --
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 13 of 39
(a)The Parties have agreed that the electric base rate offset related to the BPA
Settlement Revenues will be spread to electric rate schedules on a uniform cents per kWh
basis.
(b)The Parties have agreed that the natural gas base rate offset related to the
2012 PGA deferral credit balance of $1.55 million will be spread to natural gas rate
schedules on a uniform cents per therm basis
(c)Attachment D contains the form of tariff related to the electric and natural gas
offsets agreed to by the Parties. A new electric rate schedule, Schedule 97, will be used
for purposes of passing through to customers the electric offset. A new natural gas rate
schedule, Schedule 197, will be used for purposes of passing through to customers the
natural gas offset. Both tariffs would expire on December 31, 2014.
(d)Any under- or over-refunded amounts relating to the Electric or Natural: Gas
offsets will be trued up in the following year's Power Cost Adjustment (electric) or
Purchased Gas Cost Adjustment (natural gas).
21. Resulting Percentage Increase by Electric Service Schedule. The following tables
reflect the agreed-upon percentage increase by schedule for electric service 7:
Electric Increase Percentage by Schedule - A pol 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates
Residential Schedule 1 0.0% 0.0%
General Service Schedule 11/12 0.0% 0.0%
Large General Service Schedule 21/22 0.0% 0.0%
Extra Large General Service Schedule 25 0.0% 0.0%
Clearwater Paper Schedule 25P 0.0% 0.0%
Pumping Service Schedule 31/32 0.0% 0.0%
Street & Area Lights Schedules 0.0% 0.0%
Overall 0.0% 0.0%
' Avista will file both electric and natural gas conforming tariffs related to the October 1, 2013 rate changes with the
Commission on or before August 30, 2013 for the Commission's review and approval.
STIPULATION AND SETTLEMENT— AVU-E-12-08 & AVU-G-12-07 PageJ& - Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 14 of 39
Electric Increase Percentage by Schedule - October 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates*
Residential Schedule 1 3.5% 2.6%
General Service Schedule 11/12 2.8% 1.90/0
Large General Service Schedule- 2lt22 3.3% 2.1%
Extra Large General Service Schedule 25 2.7% 1.0%
Clearwater Paper Schedule 25P 2.3% 0.4%
Puning Service Schedule 31/32 3.9% 2.9%
Street & Area Lights Schedules 3.1% 2.7%
Overall 3.1% 1.9%
* Net Increase includes the effects of the proposed changes in Schedule 97 (BPA
Adjustment) and the General Rate Increase, all effective on October 1, 2013.
22. Resulting Percentage Increase by Natural Gas Service Schedule. The following
tables reflect the agreed-upon percentage increase by schedule for natural gas service:
Natural Gas Increase Percentage by Schedule - April 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates
General Service Schedule 101 5.3% 5.4%
Large General Service Schedule 111/112 3.8% 3.9%
Interruptible Sales Service Schedule 131/132 4.0% 4.0%
Transportation Service Schedule 146 8.7% 8.7%
Overall 4.9% 5.0%
Natural Gas Increase Percentage by Schedule - October 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates **
General Service Schedule 101 2.1% 06%
Large General Service Schedule 111/112 1.6% -0.5%
Interruptible Sales Service Schedule 131/132 1.4% -1.4%
Transportation Service Schedule 146 3.5% 3.5%
Overall 2.0% 0.3%
** Net Increase includes the effects of the proposed changes in Schedule 197 (PGA) and
the General Rate Increase, all effective on October 1, 2013.
STIPULATION AND SETTLEMENT-AVU-E-12-08 & AVU-G-12-07 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 15 of 39
IV. OTHER GENERAL PROVISIONS
23.The Parties agree that this Stipulation represents a compromise of the positions of
the Parties 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 necessary for a Party 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 this Stipulation shall be confidential and will not
be admissible in evidence in this or any other proceeding.
24.The Parties submit this Stipulation to the Commission and recommend approval
in its entirety pursuant to RP 274. Parties shall support this Stipulation before the Commission,
and no Party shall appeal a Commission Order approving the Stipulation or an issue resolved by
the Stipulation. If this Stipulation is challenged by any person not a party to the Stipulation, the
Parties 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 terms embodied in this Stipulation.
Notwithstanding this reservation of rights, the Parties to this Stipulation agree that they will
continue to support the Commission's adoption of the terms of this Stipulation.
25.If the Commission rejects any part or all of this Stipulation or imposes any
additional material conditions on approval of this Stipulation, each Party reserves the right, upon
written notice to the Commission and the other Parties to this proceeding, within 14 days of the
date of such action by the Commission, to withdraw from this Stipulation. In such case, no Party
shall be bound or prejudiced by the terms of this Stipulation, and each Party shall be entitled to
seek reconsideration of the Commission's order, file testimony as it chooses, cross-examine
witnesses, and do all other things necessary to put on such case as it deems appropriate. In such
case, the Parties immediately will request the prompt reconvening of a prehearing conference for
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Pan i6 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 16 of 39
purposes of establishing a procedural schedule for the completion of the case. The Parties agree
to cooperate in development of a schedule that concludes the proceeding on the earliest possible
date, taking into account the needs of the Parties in participating in hearings and preparing
testimony and briefs.
26.The Parties agree that this Stipulation is in the public interest and that all of its
terms and conditions are fair, just and reasonable.
27.No Party shall be bound, benefited or prejudiced by any position asserted in the
negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this
Stipulation be construed as a waiver of the rights of any Party unless such rights are expressly
waived herein. Execution of this Stipulation shall not be deemed to constitute an
acknowledgment by any Party of the validity or invalidity of any particular method, theory or
principle of regulation or cost recovery. No Party shall be deemed to have agreed that any
method, theory or principle of regulation or cost recovery employed in arriving at this Stipulation
is appropriate for resolving any issues in any other proceeding in the future. No findings of fact
or conclusions of law other than those stated herein shalt be deemed to be implicit in this
Stipulation.
28.The obligations of the Parties under this Stipulation are subject to the
Commission's approval of this Stipulation in accordance with its terms and conditions and upon
such approval being upheld on appeal, if any, by a court of competent jurisdiction.
29.This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Pam 17
Exhibit No. 101
Case Nos. AVU-E-1248/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 17 of 39
DATED this . day of February, 203.
Av'staCorpo.tion.
By: ,17 / ' David J. Weyer
Attorney for Avista Co ration
Idaho Public Utilities .Commission Staff
By:.
Karl Klein
Weldon $.tut. man
Deputy Attorneys General
.iear...tec PCôipc.ration
By:....
Peter Richardson
Attorney for C:Iearwate.r Paper
Idaho Forest-Group
By: . . .. ...
Dean J Miller
AttOflIeY for idäho PorestGroup aC
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 18 of 39
STIPULATION AND SE1TLEME4T - AVU-E-12-08 &..'v.0-12-07 .
p - (r
-p
p
DATED tius day of February, 2013
Avisti C on Idaho Pub1ic11lihi(
By:_____
Corporation to
Em
Clearwater Paper Corporation Idaho Forest (I4I
By:
'Peter Rtthardson Dean J. MI
DATED this - day of February, 2013.
Avista Corporation Idaho Public Utilities .Co ission Staff
By: By:
David J. Meyer Karl Klein
Attorney for Avista corporation Weidon. Stutzman
Deputy Attorneys General
Clearwater Idaho Forest Group

Peter Ri ardson

By: Dean J. Millet
Attorney for Clearwater Paper Attorney for Idaho Forest Group LLC
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
STIPULATION AND SETTLEMENT AVU-E-12-08 & AVU-042-07 'Page 18
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 20 of 39
DATED this dayof February, 2013.
Avista Corporation Idaho Public Utilities Commission Staff
By: By:
David L Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutznian
Deputy Attorneys General
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
;
40eany
pp
By
. Miller
Attorney for Idaho Forest Group LLC
Idaho Conservation League
Benjamin J. Otto
Attorney for ICL
Exhibit No. 101
Case Nos. A\'U-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 21 of 39
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU04207
DATED this7day of February, 2013.
Avista Corporation Idaho Public Utilities Commission Stall
By:__ By:_______________________________
David J. Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzman
Deputy Attorneys General
:Clearwater Paper Corporation Idaho Forest Group
By:
Peter Richardson Dean 3. Miller
Attorney for Clearwater Paper Attorney for Idaho Forest Group LW
Idaho Conservation League
By: 4
Benjamin J. Otto
Attorney for ICL
STIPULATION AND SETTLEMENT —AVEJ-E-12-08 &AVI$.G-12-07
is
PM i&:±
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- I 2M7
R. Lobb, Staff
02/25/13 Page 22 of 39
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT A
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 23of39
Avista Utilities:
Idaho Rate Adjustments Electric
RESIDENTIAL GENERAL SVC. 16. GEN. SVC. EX LG GEN SVC CLEAR WATER PUMPING ST & AREA 116
Effective April 1. 2013 TOTAL SCHEDULE 1 SCH. 11,12 SCH. 21,22 SCHEDULE 25 SCHEDULE 25P SCH. 31,32 SCH. 41-49
1 Total Billed Revenue $ 245,924,000 $ 96,390,000 $ 32,597,000 $ 51,597,000 $ 16,024,000 $ 41,005,000 $ 4,867,000 $ 3,444,000
2 Revenue Chanees
3GRCIncrease 1$ -1$ - $ - $ - $ - $ - $ - $ -
4 Total Revenue Change $ - $ - $ $ - $ - $ - $ - $ -
5
6 Percentaes Chanees
7 GRC Increase 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
8 Total Billed Percentage Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
9
10
11
12
13
14
15
16 Effective October 1. 2013
17 Total Billed Revenue $ 245,924.000 $ 96,390,000 $ 32,597,000 $ 51,597,000 $ 16,024,000 $ 41,005,000 $ 4,867,000 $ 3,444,000
18 Revenue aaes
19 GRC Increase * $ 7,825,0001 $ 3,532,000 $ 920,000 $ 1,714,000 $ 434,000 $ 928,000 $ 190,000 $ 107,000
20 SPA Reduction (15 Month Amortization) ** $ (3,058,000)1 $ (1,024,000) $ (301,000) $ (614,000) $ (273,000) $ (782,000) $ (51,000) $ (13,000)
21 Total Revenue Change $ 4,767,000 $ 2,508,000 $ 619,000 $ 11100,000 $ 161,000 $ 146,000 $ 139,000 $ 94,000
22
23 Percentaee Changes
24 GRC Increase 3.2% 3.7% 2.8% 3.3% 2.7% 2.3% 3.9% 3.1%
25 SPA Reduction -1.3% -1.1% -0.9% -1.2% -1.7% -1.9% -1.0% -0.4%
26 Total Billed Percentage Change 1.9% 2.6% 1.9% 2.1% 1.0% 0.4% 2.9% 2.7%
27
28
29 * Utilizes a pro-rata allocation of the Company's electric rate spread percentage from its original filing for purposes of spreading the revised revenue requirement.
30 ** The SPA settlement benefit of $3.865 million amortized over 15 months is equal to $3.058 million annually. It will expire @ 12/31/14.
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4 00
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment A Page 1 of 2
Avista Utilities Natural Gas
Idaho Rate Adjustments
GEN SERVICE LRG GEN SVC INTERRUPTIBLE TRANSPORT SPECIAL
Effective April 1. 2013 TOTAL SCHEDULE 101 SCH. 111&112 SCH. 131&132 SCHEDULE 146 CONTRACTS
1 Total Billed Revenue $ 62,090,000 $46,896,000 $14,607,000 $201,000 $289,000 $97,000
2 Revenue Chanees
3 GRC Increase * 1$ 3,114,7ZI $ 2,512,740 $ 569,000 $ 81000 $ 25,000 $ -
4 Total Revenue Change $ 3,114,740 $ 2,512,740 $ 569,000 $ 81000 $ 25,000 $ -
5
6 Percentage Changes
7 GRC Increase 5.0% 5.4% 3.9% 4.0% 8.7% 0.0%
8 Total Billed Percentage Change 5.0% 5.4% 3.9% 4.0% 8.7% 0.0%
9
10
11
12
13
14 Effective October 1, 2013
15 Total Billed Revenue $ 65,204,740 $ 49,408,740 $ 15,176,000 $ 209,000 $ 314,000 $ 97,000
16 Revenue Changes
17 GRC Increase * $ 1,330,000 $ 1,073,000 $ 243,000 $ 3,000 $ 11,000 $ -
18 PGA Reduction (15 Month Amortization) ** $ (1,131,000 ) $ (799,000) $ (326,000) $ (61000) $ - $ -
19 Total Revenue Change $ 1991000 $ 274,000 $ (83,000) $ (3,000) $ 11,000 $ -
20
21 Percentage Changes
22 GRC Increase 2.0% 2.2% 1.6% 1.4% 3.5% 0.0%
23 PGA Reduction -1.7% -1.6% -2.1% -2.9% 0.0% 0.0%
24 Total Billed Percentage Change 0.3% 0.6% -0.5% -1.4% 3.5% 0.0%
25
26 * Utilizes a pro-rata allocation of the Company's natural gas rate spread percentages from its original filing for purposes of spreading the revised
27 revenue requirement.
28 ** The PGA deferral of $1.55 million amortized over 15 months is equal to $131 million annually. It will expire @ 12/31/14.
(D J,o -,
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Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
AttachmentA.- Page 2 o 2
n
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT B
REVISED - March 1, 2013
Exhibit No. 101
Case Nos. AVU-E-12-08/AVU-C}-12-07
R. Lobb, Staff
03/01/13 Page 26 of 39
Avista Corp
Pro forma January - December
PCA Authorized Expense and Retail Sales
PCA Authorized Power Supply Expense - System Numbers (ii
Iia! Januan February March Agril Mav June JUN Auoust Seotember Q(QL November December
Account 555- Purchased Power (2) $88,182,972 $10,717,432 $9,359,487 $8,546,885 $6,841,564 $5,337,699 $5,287,042 $5,648,618 $7,939,502 $5,551,282 $5,789,904 $8,437,276 $8,726,282
Account 501 -Thermal Fuel $30,916,732 $2,789,917 $2,632,215 $2,785,057 $2,031,330 $1,718,372 $1,405,767 $2,715,972 $2,948,383 $2,925,528 $3,051,784 $2,909,636 $3,002,771
Account 547-Natural Gas Fuel $88,631,151 $8,264,229 $7,537,533 $7,376,233 $4,927,841 $2,851,219 $2,201,285 $8,893,937 $8,303,984 $8,561,441 $9,099,171 $9,713,701 $10,900,577
Account 447- Sale for Resale $57,620,639 $4,641,568 $4,386,361 $4,792,538 $5,372,207 $5,022,215 $3,271,701 $6,033,100 $3,115,032 $4,649,875 $4,672,288 $5,573,841 $6,089,913
Power Supply Expense $148,110,215 $17,130,010 $15,142,875 $13,915,637 $8,428,528 $4,885,076 $5,622,392 $9,225,427 $16,076,838 $12,388,375 $13,288,571 $15,486,772 $16,539,716
Transmission Expense $17,970,479 $1,495,284 $1,530,877 $1,480,538 $1,427,248 $1,371,518 $1,420,882 $1,432,251 $1,480,124 $1,483,239 $1,547,809 $1,665,262 $1635447
Transmission Revenue $15,910,828 $1,324,260 $1,118,308 $1,231,356 $1,159,556 $1,231,179 $1,409,821 $1,563,830 $1,439,516 $1,361,638 $1,498,288 $1,294,553 $1,278,524
PCA Authorized Idaho Retail Sales 13)
19181 Janua Febnjaiv March 6pfd &A. June JUIV Auou Seotember Octob November December
Total Retail Sales, MWtI 2,920,315 288,554 259,942 251.709 220,890 215,126 211,354 242,247 239,641 218,705 210,034 262,809 299,304
Clearwater Paper Retail Load = Generation, MWh 444,563 39,257 35,848 26,604 38.658 38.512 33,557 38,814 38,992 35,735 38,447 38,899 41,240
April 1, 2013 Approved Rates
Load Change Adjustment Rate $26.63 /MWh
October 1, 2013 Approved Rates
Load Change Adjustment Rate $26.97 iMVVti
PCA Authorized Clearwater Paper Directly Assianed Values
Total Janua Februa March Agril
P 0 ru
May June JUIV Aucu ( September QçjgDI November December
Purchased Power $19,080,644 $1,684,910 $1,538,596 $1,141,844 $1,659,201 $1,652,935 $1,440,266 $1,665,897 $1,673,537 $1,533,746 $1,650,145 $1,669,545 $1,770,021
April 1, 2013 Approved Rates
Z Retail Revenue from Load = Generation (4) $21,043,428 $1,854,485 $1,707,734 $1,256,966 $1,833,636 $1,819,288 $1,591,683 $1,833,565 $1,841,967 $1,694,991 $1,816,219 $1,844,742 $1,948,159
r.. ' October 1, 2013 Approved Rates
9 Retail Revenue from Load = Generation (4) $21,523,556 $1,896,882 $1,746,450 $1,285,700 $1,875,387 $1,860,881 $1,627,925 $1,875,474 $1,884,078 $1,733,585 $1,857,742 $1,886,753 $1,992,699
61 1)Multiply system numbers by 34.76% to determine Idaho share.
2)Purchased Power Expense includes reduction for Pro Forma Billing Determinants at system cost.
'0 , 3)12 months ended June 2012 weather normalized Idaho retail sales (utilizes Company's Pm Forma Billing Determinants).
4) Calculated at approved marginal Schedule 25P rates assuming 100% load factor for demand charge.
te Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Revised Attachment B March 1 2013 Page 1 of I
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT C
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 28of39
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-12-08
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000s of Dollars)
lEffective October 1st, 2013 I
Base Tariff Base Tariff Base Total Billed Total Billed Gen. Incr.
Revenue Proposed Revenue Tariff Revenue Total Total Revenue as a %
Line Type of Schedule Under Present General Under Proposed Percent at Present General Sch. 97- BPA at Proposed of Billed
No. Service Number Rates(1) Increase Rates (1) Increase Rates(2) Increase Decrease Rates(2) Revenue
(a) (b) (c) (d) (e) (U (g) (h) (I) 0) (k)
I Residential 1 $99,497 $3,532 $103,029 3.59/9 $96,390 $3,532 ($1,024) $98,898 2.6%
2 General Service 11,12 $32,432 $920 $33,352 2.8% $32,597 $920 ($301) $33,218 1.9%
3 Large General Service 21,22 $51,400 $1,714 $53,114 3.3% $51,597 $1714 ($614) $52,698 2.1%
4 Extra Large General Service 25 $16,036 $434 $16,470 2.7% $16,024 $434 ($273) $16,185 1.0%
5 Clearwater 25P $41,091 $928 $42,019 2.3% $41,005 $928 ($782) $41,151 0.4%
6 Pumping Service 31,32 $4,859 $190 $5,049 3.9% $4,867 $190 ($51) $5,006 2.9%
7 Street & Area Lights 41-49 $3,405 $3512 3.1% $3,444 $3,539 2.7%
8 Total $248,720 $7,825 $256,545 3.1% $245,924 $7,825 ($3,058) $250,691 1.90/4
(1)Excludes all present rate adjustments (see below).
(2)Includes all present rate adjustments: Schedule 59- Residential & Farm Energy Rate Adjustment. Schedule 66-Temporary
Power Cost Adjustment, Schedule 91 - Energy Efficiency Rider Adjustment, and Schedule 97- BPA Rate Adjustment.
9' 0 En Z

r!ri Attachment
C •.LL
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
AVISta
Page lof6
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-12-08
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
lEffective October 1st, 2013 I
General Proposed
Base Tariff Present Present Rate Sch. 97-BPA Billing
Scti. Rate Other Adi.0 Billing Rate lncliDecr) Decrease E91s
(a)
Residential Service Schedule
(b)
I
(C) (d) (e) (f) (9)
-
Basic Charge $5.25 $5.25 $0.00 $5.25
Energy Charge:
First 800 lcWhs 80.07848 (80.00276) 80.07572 80.00298 ($0.00091) $007779
All over 600 kWhs $008764 (80.00276) 80.08488 80.00332 (80.00091) 80.08729
General Services -Schedule 11
Basic Charge $10.00 $10.00 $0.00 $10.00
Energy Charge:
First 3,650 kWhs 80.09338 80.00072 80.09410 80.00296 (80.00091) 80.09615
All over 3,650 kWhs 80.06958 80.00072 $007030 $0.00220 ($0.00091) 80.07159
Demand Charge:
20 kW or less no charge no charge no charge
Over 20 kW $5.25/kW $5.25/kW $5.25/kW
Proposed
BaseTariff
(h)
$5.25
80.08146
80.09096
$10.00
80.09634
$0.07178
no charge
$5.25/kW
Large General Service - Schedule
Energy Chargé:
21
First 250,000 kWhs $006039 $000035 $0.06074
All over 2(2) includes all preser 80.05154 80.00035 $0.05189
Demand Charge:
50 kW or less $350.00 $350.00
Over 50 kW 84.75/kW 84.75/kW
Primary Voltage Discount $0.20/kW $0.20/kW
Extra Lame General Service - Schedule 25
Energy Charge:
First 500,000 kWhs 80.05047 ($0.00004) 80.05043
All over 500,000 kWhs $0.04275 (80.00004) $004271
Demand Charge:
3,000 kva or less $12500 $12,500
Over 3,000 kva $4.50/kva $4.50Ikva
Primary Volt. Discount $0.20/kW $0.201kW
Annual Minimum Present: $666,570
Clearwater - Schedule 25P
Energy Charge:
all kWhs $004146 ($0.00010) $004136
Demand Charge:
3,000 kva or less $12,500 $12,500
Over 3,000 kva $4.50/kva $4.50/kva
Primary Volt. Discount $0.20/kW $0.20IkW
Annual Minimum Present: $606,060

$0.00258 (80.00091) $006241

80.00219 (80.00091) 80.05317

$0.00 $350.00
$4.75/kW
80.201kW
80.06297
80.06373
$350.00
$4.75/kW
$0.20/kW
80.00165 (80.00091) 80.05117 80.05212
$0.00139 (80.00091) 80.04319 80.04414
$12,500 $12,500
$4.50Ikva $4.50/kva
$0.20/kW $0.20/kW
Proposed: $683,420
80.00108 (80.00091) 80.04153
$12,500
$4.5OIkva
80.20/kW
Proposed: $617,940
$0.04254
$12,500
$4.S0lkva
$0.20/kW
PumDlna Service - Schedule 31
Basic Charge $8.00 $8.00 $0.00 $8.00
Energy Charge:
First 165 kW/kWh 80.08939 80.00052 $0.08991 80.00360 ($0.00091) $0.09260
All additional kWhs 80.07620 $0.00052 $007672 $0.00307 (80.00091) 80.01888
$8.00
$0.09299
$0.07927
(1) Includes all present rate adjustments: Schedule 59- Residential & Farm Energy Rate Adjustment, Schedule 66-Temporary
Power Cost Adjustment, and Schedule 91 - Energy Efficiency Rider Adjustment. Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 30 0139
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment C Page 2 of 6
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000$ of Dollars)
lEffectiveApril 1st, 2013
Base Tariff Base Tariff Base Total Billed Total Billed Percent
Revenue Proposed Revenue Tariff Revenue Total Revenue Increase
Line Type of Schedule Under Present General Under Proposed Percent at Present General at Proposed on Billed
Service Number Rates (1) Increase Rates (1) Increase Rates (2) Increase Rates (2) Revenue
(a) (b) (C) (d) (e) (0 (g) (h) (i) U)
1 General Service 101 $47,852 $2,513 $50,365 5.3% $46,896 $2,513 $49,409 5.4%
2 Large General Service 111/112 $14,997 $569 $15,566 3.8% $14,607 $569 $15,175 3.9%
3 Interruptible Service 131/132 $201 $8 $209 4.09A $201 $8 $209 4.0%
4 Transportation Service 146 $289 $25 $314 8.7% $289 $25 $315 8.7%
5 Special Contracts 148 0.0% 0.0%
6 Total $63,436 $3,115 $66,551 4.9% $62,090 $3,115 $65,205 5.00/0
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155- Gas Rate Adjustment
CD
C
tt)
a 00
Stipulation and Settlement
Case No. AW-E-1208 and AVU-G-12-07
Avista
Attachment C Page 3 of 6
$0.02074 $0.52985 $0.52985
$0.00 $225.00 $226.00
$0.00978 $011649 $0.11649
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
lEffective April 1st, 2013 1
Base Present Present
Rate (1) Rate Adi.(2) Billing Rate
(a) (b) (c) (d)
General Service - Schedule 101
Basic Charge $4.25 $4.25
Usage Charge:
All therms $0.62291 ($0.01785) $0.80506
Large General Service - Schedule 111
Usage Charge:
First 200 therms $0.84418 ($0.01785) $082633
200- 1,000 therms $0.71203 ($0.01785) $0.69418
1,000- 10,000 therms $0.63624 ($0.01785) $061839
All over 10,000 therms $0.58630 ($0.01785) $0.56845
Minimum Charge:
per month $81.61 $81.61
per therm $0.43612 ($0.01785) $0.41827
interruptible Service - Schedule 132
Usage Charge:
All Therms $0.50911 $0.50911
Transportation Service - Schedule 146
Basic Charge $225.00 $225.00
Usage Charge:
All Therms $0.10671 $0.10671
General Proposed Proposed
Rate Billing Base
Increase Rate Rate (1)
(e) (f) (g)
$0.00 $4.25 $4.25
$0.04690 $0.85196 $0.86981
$0.04689 $0.87322 $0.89107
$0.02413 $031831 $0.73616
$0.02156 $0.63995 $0.65780
$0.01987 $0.58832 $0.60617
$9.38 $90.99 $90.99
$0.41827 $0.43612
(1)Includes Schedule 150 - Purchased Gas Cost Adjustment
(2)Includes Schedule 155 - Gas Rate Adjustment
Attachment C
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 32 of 39
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Page 4 of 6
AVISTA UTiLITIES
IDAHO GAS, CASE NO. AVU-G-1 2.07
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000$ of Dollars)
JEffective October 1st, 2013
Base Tariff Base Tariff Base Total Billed Total Billed Percent
Revenue Proposed Revenue Tariff Revenue Total Total Revenue Increase
Line Type of Schedule Under Present General Under Proposed Percent at Present General Sch 197 - PGA at Proposed on Billed
Service Number Rates (1) Increase Rates (1) Increase Rates (2) Increase Increase Rates (3) Revenue
(a) (b) (c) (d) (e) (f) (g) (h) (I) (j) (k)
I General Service 101 $50,365 $1,073 $51,438 2.1% $49,408 $1,073 -$799 $49,682 0.6%
2 Large General Service 111/112 $15,566 $243 $15,809 1.6% $15,175 $243 -$326 $15,092 -0.5%
3 Interruptible Service 131/132 $209 $3 $212 1.4% $209 $3 46 $206 -1.4%
4 Transportation Service 146 $314 $11 $325 3.5% $315 $11 $0 $326 3.5%
5 Special Contracts 148 0.06/0 0.0%
6 Total $66,551 $1,330 $67,881 2.0% $65,204 $1,330 -$1,131 $65,403 0.3%
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155- Gas Rate Adjustment
(3)Includes Schedule 155- Gas Rate Adjustment and Schedule 197- PGA Rate Adjustment
uo
iir
Stipulation and Settlement
Case No. AVU-E-12-08 and AVIJ-G-12-07
Avista
Attachment C Page 501 6
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-1 207
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
lEffective October 1st, 2013 I
Base Present Present
Rate (1) Rate Ad112) Billing Rate
(a) (b) (c) (d)
General Service - Schedule 101
Basic Charge $4.25 $425
Usage Charge:
All therms $0.86981 ($001785) $0.85196
Lame General Service - Schedule Ill
Usage Charge:
First 200 therms $0.89107 ($0,01785) $0.87322
200-1,000 therms $0.73616 ($0.01785) $0.71831
1,000- 10,000 therms $0.65780 ($0.01785) $0.63995
All over 10,000 therms $0.60617 ($0.01785) $0.58832
Minimum Charge:
per month $90.99 $90.99
per therm $043612 ($001785) $0.41827
Interruotible Service - Schedule 132
Usage Charge:
All Therms $0.52985 $052985
Transoortation Service - Schedule 146
Basic Charge $225.00 $225.00
Usage Charge:
All Therms $011649 $0.11649
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155- Gas Rate Adjustment
General Proposed Proposed Proposed
Rate Sch. 197 PGA Billing Base
Increase Adl. Rate Rate (1
(e) (f) (g) (h)
$0.00 $4.25 $4.25
$0.02003 ($0.01489), $0.85710 $0.88984
$0.02005 ($0.01489) $0.87838 $0.91112
$0.01026 ($0.01489) $0.71368 $0.74642
$0.00927 ($0.01489) $0.63433 $0.66707
$0.00845 ($0.01489) $0.58188 $0.61462
$4.01 $95.00 $95;00
($001489) $0.40338 $0.43612
$0.00759 ($0.01489) $0.52255 $0.53744
$0.00 $225.00 $225.00
$0.00428 $012075 $0.12075
Attachment C
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 34of39
Stipulation and Settlement
Case No. AW-E-12-08 and AVU-G-1 2-07
Avista
Page 6 of 6
STIPULATION AND SETTLEMENT
Case Nos. AVU-E42-08 & AVU-G-12-07
ATTACHMENT D
Exhibit No. 101
Case Nos. AVU-E-12-08!
AVUG- 12M7
R. Lobb, Staff
02/25/13 Page 35 of 39
Avista Corporation
State of Idaho
BPA Rate Adjustment Offset
• ID portion of BPA Settlement -$3,846,000
Conversion Factor 0.995010
Revenue Requirement -$3,865,288
15 Month Amortization Rate Pro Forma BPA
kWh Reduction
1 1,454,376,696 ($1,320,981)
11&12 418,029,209 ($379,688)
21&22 847,204,858 ($769,499)
25 373,474,024 ($339,219)
25P 1,079,930,838 ($980,879)
31&32 65,224,871 ($58,242).
41-49 17,372,742 ($15,779)
Total 4,255,613,238 ($3,865,288)
Uniform cents reduction ($0.00091)
* Effective October 1st, 2013 through December 31st, 2014
Any residual balance will be trued up in a future PCA filed by the Company.
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 36of39
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Page lof4
Attachment D
I.P.U.C. No.28 Original Sheet 97 97
AVISTA CORPORATION
dlbla Avista Utilities
SCHEDULE 97
• BONNEVILLE POWER ADMINISTRATION SETTLEMENT - IDAHO
AVAILABLE:
To Customers in the State of Idaho where Company has electric service
available.
PURPOSE:
To adjust electric rates for revenues related to the Bonneville Power
Administration settlement.
MONTHLY RATE:
The energy charges of electric Schedules 1, 11, 12, 21, 22, 25, 25P, 31,
32 and 41.49 are to be decreased by 0.0910 per kilowatt-hour in all blocks of
these rate schedules.
TERM:
• The energy charges will be reduced for a fifteen month period, from
October 1, 2013 through December 31, 2014. Any residual balance will be trued
up in a future PCA filed by the Company.
SPECIAL TERMS AND CONDITIONS:
Service under this schedule is subject to the Rules and Regulations
•

contained in this tariff. The above Rate is subject to increases as set forth In Tax
Adjustment Schedule 56.
By Kelly Norwood, Vice President, State S Federal Regulation
Attachment 0 StIpulation and Settlement
Case 'No. AVU-E-t2-O8 and AVU12O7
Avista Exhibit No. 101
Pa9e2 of Case Nos. AVUE12M8/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 37 of 39
Avista Corporation
State of Idaho
PGA Rate Adjustment C
Refund of Deferred Gas Costs -$1,542,264
Conversion Factor 0.995009
Revenue Requirement -$1,550,000
• 15 Month Amortization Rate Pro Forma PGA
8th Therms Reduction
101 74,508,535 ($1,109,559)
111&112 29,081,957 ($433,080)
131&132 494,346 ($7,382)
Total 104,084,838 ($1,550,000)
Uniform cents reduction ($0.01489)
Effective October 1st, 2013 through December 31st, 2014
Any residual balance will be trued up in a future PGA filed by the Company.
Exhibit No. 101 --
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 38of39
Stipulation and Settlement
Case No. AVU.-E-12-08 and AVUG-12-07
Avista
Attachment 0 Page 3 of 4
LP.U.C. N0.27 Original Sheet 197 197
AVISTA CORPORATION
cl/b/a Avista Utilities
SCHEDULE 197
REFUND OF DEFERRED GAS COSTS - IDAHO
AVAILABLE:
To Customers in the State of Idaho where Company has natural gas
service available.
PURPOSE:
To adjust natural gas rates for the refund of prior deferred gas costs
MONTHLY RATE:
The energy charges of natural gas Schedules 101,111, 112,131, and 132
are to be decreased by 1.4890 per therm in all blocks of these rate schedules.
TERM:
The energy charges will be reduced for a fifteen month period, from
October 1, 2013 through December 31, 2014. Any residual balance will be trued
up in a future PGA filed by the Company.
SPECIAL TERMS AND CONDITIONS:
• Service under this schedule is subject to the Rules and Regulations
contained in this tariff. The above Rate is subject to Increases as set forth in Tax
Adjustment Schedule 158,
By Kelly Norwood, Vice President, State & Federal Regulation
Attachment 0 Sttpulation #M Setflernent
Case No AW E-12-08.ndAVU-G-12-O7
Aista Exhibit No. 101
Page 4 of 4 Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 39 of 39
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 25TH DAY OF FEBRUARY 2013,
SERVED THE FOREGOING DIRECT TESTIMONY OF RANDY LOBB IN
SUPPORT OF THE STIPULATION AND SETTLEMENT, IN CASE NOS.
AVU-E-12-08 & AVU-G-12-07, BY B-MAILING, MAILING VIA FED EX OR HAND
CARRY A COPY THEREOF, POSTAGE PREPAID, TO THE FOLLOWING:
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
P0 BOX 3727
SPOKANE WA 99220-3727
E-MAIL: [e-mail]
KELLY 0 NOR WOOD
VP STATE & FED REG
AVISTA CORPORATION
P0 BOX 3727
SPOKANE WA 99220-3727
E-MAIL: [e-mail]
ELECTRONIC SERVICE ONLY: DEAN J MILLER
PAUL KIMBALL McDEVITT & MILLER LLP
AVISTA CORPORATION P0 BOX 2564
E-MAIL: [e-mail] BOISE ID 83702
E-MAIL: j [e-mail]
LARRY A CR0 WLEY
THE ENERGY STRATEGIES
INSTITUTE INC
5549 S CLIFFSEDGE AVE
BOISE ID 83716
E-MAIL: [e-mail]
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON & O'LEARY
515 N 27TH STREET
BOISE ID 83702
E-MAIL: Deter(richardsonando1earv.com
gregrichardsonando1eary.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreading(Zimindspring.com
BENJAMIN J OTTO
IDAHO CONSERVATION LEAGUE
710 N. 6TH ST
BOISE ID 83702
E-MAIL: [e-mail]
KEN MILLER
SNAKE RIVER ALLIANCE
BOX 1731
BOISE ID 83701
E-MAIL: [e-mail]
ELECTRONIC SERVICE ONLY:
HOWARD RAY
CLEAR WATER PAPER CORPORATION
E-MAIL: [e-mail]
BRAD M PURDY
ATTORNEY AT LAW
2019N 17TH ST.
BOISE ID 83702
E-MAIL: [e-mail]
SECRETAR7
CERTIFICATE OF SERVICE