20040209Lafferty Exhibits Part I.pdf

DAVID J. MEYER
SENIOR VICE PRESIDENT AND GENERAL COUNSEL
A VISTA CORPORATION
O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC AND
NATURAL GAS CUSTOMERS IN THE STATEOF IDAHO
CASE NO. A VU-04-
EXHIBIT NO.
ROBERT 1. LAFFERTY
FOR A VISTA CORPORTATION
(ELECTRIC ONLY)
(SCHEDULES 4 11,14 & 15 OF THIS EXHIBIT ARE CONFIDENTIAL)
CASE NO. A VU-04-
EXHIBIT NO.
TABLE OF CONTENTS
SCHEDULE NO DESCRIPTION PAGE
SCHEDULE 2000 Resource Selection Process Report
SCHEDULE 2 1997 IRP Update (filed in July 2000)1- 84
SCHEDULE 3 Evaluation Process Flow Chart and Evaluation Guidance
for RFP 1- 6
SCHEDULE 4 Resource Selection Process - 2nd Round Screening
(Confidential)
SCHEDULE 5 2000 Request For Proposals
SCHEDULE 6 R W Beck - RFP Bid Analysis Review
SCHEDULE 7 Resource Selection Process - 3rd Round Screening
(Confidential)
SCHEDULE 8 Resource Selection Process - Additional Explanation 1- 5
SCHEDULE 9 Resource Planning & Acquisition Documentation Index
(Confidential)1- 8
SCHEDULE 10 Revenue Requirement AnalysIs - Top Projects
(Confidential)1- 5
SCHEDULE Coyote Springs 2 - Re-evaluation (Confidential)1- 6
SCHEDULE 12 CS2 GSU Failure - Steps Taken By The CS2 Partners
(Confidential)1- 6
SCHEDULE 13 GSU Transformer Data
SCHEDULE 14 Coyote Springs 2 GSU Alternatives (Confidential)1 - 15
SCHEDULE 15 Coyote Springs 2 - Budget to Actual Cost Comparison 1- 3
(Confidential)
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6
VISTA CORP
2000 RESOURCE SELECTION PROCESS REPORT
February 14 2001
The following report outlines the resource planning, data gathering, evaluation and
selection process that has been a focus of a concentrated work effort by A vista Corp staff
and others outside of the Company. The intent of the report is to provide an overview of
the entire selection process. A vista has extensive documentation records that were kept
throughout the work effort. Those records are available to provide the details supporting
the decisions that were made by the Company. Many of those records contain
confidential bids and proprietary analysis done by third parties. Certain information is
therefore intentionally kept general in this report to avoid inappropriate disclosure.
Plannin2 & Determination of Resource Need
Fall 1998
Through
Spring 2000
Fall 1999
Fall 1999
Through
Spring 2000
Centralia Sale
. On October 30, 1998, the Centralia owners approved moving forward
with a plan to put the entire generating plant and mine up for sale.
In November 1998, the Centralia plant was put up for formal bidding.
. On May 7, 1999, the Centralia TECW A was selected as the winning
bidder. The mine owners executed a sale agreement with TECW
dependant on obtaining board and regulatory approvals and upon
resolution of several other plant and mine related issues.
. On May 5, 2000, the Centralia power plant was sold to TECW A by
the joint owners.
Medium-Term Power Purchase
In October 1999, the Company contracted with TECW A for 200MW
of capacity and energy for Ql , Q2, and Q4 contingent on the sale of
the plant and continuing through 12/31/03. A contingent purchase
was most beneficial due to the real uncertainty as to whether all of
the sale contingencies could be worked through satisfactorily.
Resource Site Option Investigation
The Company began meetings in August to discuss resource projects
in the Pacific Northwest region that were felt to be possible long-term
resource candidates. A list of likely sites in the region was made.
All of the projects were combined cycle natural gas combustion
turbine sites.
From September through November, a total of 32 project sites were
visited. Information was collected regarding permitting status
construction schedules, potential costs, unique issues, etc. Air permit
issues, water source issues, water discharge issues, community
support issues, electric transmission, natural gas transmission, etc.
were part of the data gathered from the different meetings and visits.
The company considered the prospect of a project consisting of either
Resource Selection Report
February 14 2001 Exh. 6 / Schedule 1
R. Lafferty
A vista Corporation
Page 2 of 16
Avista CCCT
Initial Siting Study
I CCCT Turbine
Site Study
Book #2)
..
Pacific Northwest
Combined Cycle
Combustion Turbine
Generation Facility
Siting Study
ICCCTTurbine Site
Study Book #2)
Spring 2000
one or two combined cycle combustion turbines. The assumption
was that a two-unit project would be a partnership arrangement
where a third-party would take on the obligations of the second unit.
Both parties would share in the economies of scale that occur when
two units are managed together at one location. Alternatively, the
second unit could still be built at a later date.
November through December, company staff processed through
information gathered on different sites in a series of meetings. Sites
with significant roadblocks were eliminated through a group review
process. Five sites were selected for further evaluation and study.
Those sites were: Rathdrum, Idaho (at the current simple cycle
project location); Kaiser Mead; Hermiston, Oregon; Starbuck,
Washington; Vana1co (near Vancouver, W A).
In January 2000, the company contracted with Dames & Moore to
perform a more thorough site evaluation on those project sites
identified. Some of the evaluation areas were air permit issues, water
source issues, water discharge issues, noise issues , etc. The
consultant was asked to consider issues and suitability of the site
relative to place either one 250MW combined cycle turbine or two
250MW combined cycle turbines (500MW total) at each of the sites.
The relative benefits of one project site over another can change
depending on whether one or two combined cycle turbines are
planned. The company wanted these differences identified.
April 2000 saw the completion of the Dames & Moore project site
study. Rathdrum was the top ranked project site for a single
combined cycle turbine. Kaiser-Mead ranked as a top project site for
a two unit project.
The Dames & Moore study was reviewed with the IRP T AC group
on 6/22/00.
Updated Resource Plan/Criteria
The company reviewed various planning issues along with updating
the company s Load & Resource tabulation showing the removal of
its share of the output from Centralia in mid-year 2000. One
planning factor that was changed was the degree to which the
company would plan to rely on the short-term market to meet load
obligations. However, as prices continued to rise in the late spring of
2000, the company concluded that it should reduce its reliance on the
short-term market to meet planned resource requirements. The L&R
showed over 300aMW of need in 2004. A similar amount of annual
capacity need was also shown.
In addition to looking at annual capacity and energy L&R positions,
the company also looked at the month by month L&R position during
on-peak and off-peak times. The company reviewed its position
monthly over several years. Again, 2004 showed significant deficits
and therefore would be the focus of future discussions regarding the
Exh. 6/ Schedule 1
R. Lafferty
A vista Corporation
Resource Selection Report
February 14 2001
Page 3 of 16
WUTC IPUC
staff meetings.
I Planning-Need
Book #3)
Spring 2000
company s resource need.
The company met with the WUTC staff on 5/23/00 and the IPUC
staff and commissioners on 6/2/00. The purpose of those meetings
was to review the company s Load & Resource tabulation, the size
and timing of resource need, the types of resource options, and the
process or steps that the company should take to select resources for
filling the identified needs. The company laid out some general
concepts for the all-resource RFP. The company also developed and
presented "deficiency duration curves" showing the percent of time
that the company would be deficient a certain amount of power using
the Prosym hourly dispatch model and 60 years of hydro data. The
area under the curve gives a good general indication of the amount of
energy needed to meet resource requirements. (Peaking plants were
removed from the resource stack in this presentation of data, and then
they were shown added back to show how they fit peak needs.) A
base load resource, such as a combined cycle combustion turbine,
was shown to fit the deficiency gap.
The company began work on a 1997 Integrated Resource Plan
Update at the suggestion of the WUTC staff. We discussed that it
was most expedient to file an update of an already filed and accepted
plan in order to get an official acceptance of resource need from the
commission. The other alternative would have been to file the IRP
that was in progress. This would have taken much longer to get
commission review and acceptance. The company proceeded to
address key areas of the plan, identified by WUTC staff, that would
require updating.
Updated 1997 IRP
The IRP is a long-term planning tool used to determine Avista
energy and capacity balance for a ten-year period. The IRP itemizes
Avista s peak and average loads firm contract resources and
obligations, and power plant energy production and capacity (under
critical water conditions) on an annual basis. Netting these numbers
illustrates Avista s annual surplus or deficit energy and capacity
position to serve native load.
Due to changes in the native load forecast, changes in power plant
ownership, and changes in long-term firm contract resources and
obligations it was necessary to revise the 1997 IRP to show the most
current load and resource position. The IRP was revised and
submitted to the WUTC on July 12 2000. The IRP shows Avista
deficit in load and resource balance through 2003 under critical water
conditions. In 2004 and beyond, the IRP shows A vista requiring up
to 300 MW of energy and capacity to meet native load requirements.
. A vista used the 2000 Gas IRP as a starting point for the 1997 IRP
Update electric price forecast. It is reasonable to assume that a new
generation combined cycle combustion turbine is the likely marginal
Exh. 6 / Schedule 1
R. Lafferty
A vista Corporation
Page 4 of 16Resource Selection Report
February 14,2001
June/July
2000
lRP Technical
Advisory Team
Meeting
I Planning-
Need Book #3)
resource of the future. Applying historical spark spreads to quantify
a possible electric forecast is a reasonable method to show how a new
resource may fair under different market conditions.
IRPIRFP Review
Because of the need for substantial long-term resources, the company
developed drafts of an all-resource request for proposals (RFP). The
company developed a draft RFP during May and June 2000.
. On 6-22-00, company staff reviewed the basic components of the
1997 IRP Update with the IRP Technical Advisory Committee
(T AC) in Spokane. WUTC staff, IPUC staff, Northwest Energy
Coalition, and Northwest Energy Services were in attendance at the
meeting and provided some comments. Company staff reviewed the
Prosym hourly dispatch model that was being used to evaluate
resource options. The Company s natural gas and electric price
forecasts were discussed. The company also shared draft copies of
the proposed all-resource RFP. The RFP would assess options
available in the market to compare to its own company sponsored
projects. Company staff also made a presentation regarding the
company s new resource site investigation process including the
Dames & Moore site investigation study.
The company followed up with WUTC staff, IPUC staff, Washington
State Public Council, Industrial Customers of Northwest Utilities,
Washington Dept. of Community, Trade and Economic
Development, and Northwest Energy Coalition to get comments on
both the 1997 IRP Update and the proposed RFP. Various comments
were received and worked through. The company shared ProSym
model run data showing how the A vista resources would be modeled
with commission staff.
July/August IRPIRFP Approvals
2000
lRP and RFP
Filed With
WUTC IPUC
I Planning-Need
Book #3)
. On July 12 2000, the 1997 IRP Update (IRP) was filed with both
commissions to supplement the Company s previous plan filed
pursuant to WAC 480-100-251 in Washington and by Idaho Order
No. 22299. The RFP filings were based on the Company s IRP. As
described in the preceding sections, Avista s revised loads and
resources demonstrated a need for power.
. A vista Corp filed its Request For Proposals (RFP) with the WUTC
on July 13, 2000 and with the IPUC on July 12, 2000. The RFP
indicated that the company was seeking proposals for approximately
300 MW of capacity and energy and that flexibility/dispatchability
of a resource was a preference. Proposals were sought on all
resource types. Renewable resources were given a 10% price credit.
The RFP was filed pursuant to the WUTC's rule requiring
solicitation of competitive bids under WAC 480-107. The Company
Exh. 6 / Schedule 1
R. Lafferty
Avista Corporation
Page 5 of 16Resource Selection Report
February 14 2001
RFP Approved
by WUTC and
recognized by
IPUc.
f Planning-Need
Book#4J
opted to file identical copies with IPUC for purposes of keeping the
Idaho Commission abreast of resource procurement issues on the
same timeline.
The Company met with Commission Staffs prior to each filing as
described in preceding sections. These meetings, in combination
with Avista June IRP Technical Advisory Committee meeting,
allowed the Company to gain stakeholder input prior to the release
of the RFP.
. On July 12, 2000, the company mailed copies of the filed RFP to
potential bidders or interested parties for their review and comment.
. On July 18 2000, the WUTC formally noticed the filing of Avista
RFP and requested comments by August 8, 2000.
. On July 21 , 2000, the IPUC formally noticed Avista s RFP and
requested comments by August 11 , 2000.
. On August 2, 2000, company representatives met with IPUC staff
and Commissioners in Boise to review the 1997 IRP Update and the
RFP and to respond to questions.
. On August 9, 2000, the WUTC heard commission staff, intervenor
and company comments on Avista s all-resource RFP. The WUTC
Commission Staff developed a memorandum supporting both the
need for resources identified in the 1997 IRP Update and the RFP.
The WUTC approved the RFP in Docket NO. UE-001O81.
IPUC staff issued their recommendations on August 11th noting that
issuance of the RFP was an appropriate action. On October 10th, the
IPUC issued Order No. 28542 regarding the RFP, in Case NO.
A VU-08 noting that approval is not necessary. The IPUC stated
the Company is commended for soliciting public input into its RFP
process.
As an ongoing process, the Company agreed, as part of the
Commission approvals, to provide the Staffs access to all materials
needed to review the final evaluation system before the bids were
opened. Further, the Company committed to sharing all modeling
and analysis with the Staffs for the purpose of verifying the final
selections.
The RFP was released to the public on August 14, 2000. The RFP
and the 1997 IRP Update were published on A vista s web-site. An
announcement was posted in newspapers in Spokane, Seattle and
Portland. Media was contacted and interviews were conducted
regarding the Company s need for resources and the RFP. The
company asked for bids to be returned by September 18,2000.
Exh. 6/ Schedule 1
R. Lafferty
A vista Corporation
Page 6 of 16
Resource Selection Report
February 14 2001
Evaluation and Decision-Supply Side
Sept.- 2000
Review RFP
Evaluation
Process with
WUTCI/PUC
staff
(Planning-
Need
Book #4)
Supply-Side Evaluation Matrix Development
. A vista determined that a first screening would ensure that bid
proposals met required criteria as stated in the RFP. Bidders were to
provide general qualifications as outlined in the RFP plus the project
specific information requested for each proposal submitted.
The RFP document laid out the three principle areas that would be
the focus of further evaluation: Electric power characteristics;
finance/price characteristics; and social/environmental
characteristics. The company had committed to commission staff to
develop a more detailed evaluation matrix based on the principle
areas prior to the opening of RFP bid proposals.
The company developed a set of financial/price and non-price factors
with associated weightings. This evaluation matrix and write-up
describing the various weightings and the ranking process was
reviewed with WUTC and IPUC staff members on September 13,
2000.
FinanciallPrice Factors
. To provide a consistent evaluation framework, the Screening Work
Group developed a matrix to evaluate all supply-side proposals
against. The matrix contained the categories of FinanciallPrice
Evaluation Factors, and Non-Price Evaluation Factors.
FinanciallPrice factors received a 65% total weighting. Within this
category, three sub-categories, and their weightings, were assigned.
The FinanciallPrice Factors were: economic benefits (35%);
financial performance capability (15%); and fuel price risk (15%).
Economic benefits assessed the net savings, on a per-MWh basis, that
each proposal brought to the Company s resource portfolio.
Financial Performance Capability assessed the likelihood that the
bidder had the financial ability to complete the proposed project.
Fuel Price Risk quantified the potential for the price of the proposal'
fuel source to change significantly. For example, flat purchase
contracts that were not tied to the price of an underlying fuel source
rated highly. Projects consuming natural gas received a lower rating.
Non-Price Evaluation Factors
. Non-Price Evaluation Factors received a 35% total weighting. In
each category, sub-categories and weightings were assigned. Within
the Non-Price Evaluation Factors were: fuel availability risk (5%);
Electric Factors (20%); and Environmental Factors (10%).
Fuel Availability Risk assessed the availability of supply and any
risks associated with delivery of the fuel.
Electric Factors provided an area to evaluate such characteristics as
ramping rates, dispatchability, reactive supply, the supply source, and
system integration.
Resource Selection Report
February 14,2001
Exh. 6 / Schedule 1
R. Lafferty
Avista Corporation
Page 7 of 16
September
2000
Henwood
Pricing
Forecast
lEva/.-
Decision
Book #2)
Environmental Factors were designed to ensure adequate pennits
were available, that environmental laws and regulations were adhered
to, and proven technology was used to meet such laws and
regulations.
Pricine Study - Henwood Ener2V Services. Inc
Under contract with A vista, Henwood Energy Services, Inc. (RESI)
delivered a WSCC Regional Market Price Forecast study on
September 22, 2000. The price forecast included monthly heavy and
light load electricity prices and annual gas prices (later updated to
monthly gas prices) for the years 2001 - 2022. The wholesale
electric and natural fi.as price forecast was derived from HESI's
proprietary Prosym
M and Electric Market Simulation System
software. (ProsymTM performs detailed fundamental simulation of
the electric wholesale market on an hour-to-hour basis. Electric
production is modeled at the generation unit level while system loads
and transmission constraints are modeled on an hourly basis.
ProsymTM computes market clearing prices and generation production
for user-defined transmission zones.
As a third party source with recognized expertise in electric and
natural gas forecasting, A vista used HESI's electric and natural gas
forecast as the source for the second screen RFP economic evaluation
process.
The base electric price forecast was subject to many market variables.
Plant availability, plant additions, gas prices, hydro conditions, load
growth, and transmission constraints could all affect the future price
of wholesale electricity. HESI provided a report (dated September
2000) and a supplemental report (dated December 21 2000)
detailing assumptions made in the electric and natural gas price
forecast.
Development Of High and Low Electric Price Scenarios:
. To illustrate the impact of different levels of new capacity additions
in the WSCC on wholesale electricity prices HESI performed an
electric price scenario analysis for the period 2001 through 2005.
the underbuild scenario, 9 000 MW of new generation (only capacity
that was under construction as of August 2000) comes on line in the
WSCC during the 2001-2005 period. The overbuild scenario was
simulated by including 23,000 MW of new generation in the WSCC
with announced commercial operation dates before 2005. This
represents roughly 44 percent of known announced generation in the
WSCc. Natural gas prices were assumed to be the same as the base
case.
Exh. 6 / Schedule 1
R. Lafferty
A vista Corporation
Page 8 of 16
Resource Selection Report
February 14 2001
September
2000
September
2000
. To quantify a reasonable spread of potential longer term high and low
electric price scenarios, Avista used HESI's scenario analysis as a
starting point. A paper by Professor Andrew Ford of Washington
State University discusses cycles in the electric industry due to
overbuilding and underbuilding electric plant. A vista used the
frequency interval (7 years) between periods of peak over or under
building from Dr. Ford combined with the amplitude of the electric
price from the HESI over or under build scenarios to extrapolate a
high and a low price forecast through the year 2025. . After
discussion with Commission staff, A vista finalized the high/low
electric price forecast scenarios by smoothing the over/underbuild
data to represent a high and low price forecast.
The Company extended the price forecasts through 2025 using the
growth rate between 2021 and 2022 to meet the need for a forecast of
25-year duration.
Prosym Analysis Methodology
Prosym is commercially available production cost modeling tool that
optimizes hourly dispatch of company owned or contract generation
resources against load requirements, gas and electric price
infonnation, and supply or requirements contracts. A vista used
Prosym
1M to estimate costs and benefits to
A vista s utility system of
the RFP bids and the self-build option.
The resulting model output quantifies how each RFP bid or self-build
resource option meets the hourly requirements of Avista s electric
system with the least production cost.
Models of Avista s system included on-peak and off-peak loads
hydroelectric and thennal generating resources, contractual sales and
purchases, and spot-market sales and purchases
The model was run without proposed resource options and then with
each resource proposal individually to determine the net benefit of
each resource option to the company.
Economic AnalysislRevenue Requirements Modeling
All proposals entering at least the second screening were to be
evaluated with an economic spreadsheet model developed by the
company. The spreadsheet calculated project benefits/costs by year
for the 2001-2025 period, including rate-of-retum loadings.
The economic analysis spreadsheet obtained four columns of annual
data for each proposal directly from Prosym: generation, fuel costs
variable O&M and start-up costs, and operating margin net of variable
costs. The economic analysis went further to include in its
Resource Selection Report
February 14,2001
Exh. 6/ Schedule 1
R. Lafferty
Avista Corporation
Page 9 of 16
September
2000
October
2000
calculations of margin each proposals fixed costs, including debt
service, rate of return, taxes, and transportation.
Each proposal's final economic analysis value was determined using
the operating margin net of all fixed and variable costs on a per-MWh
basis.
Initial Screening Process
. On September 18, 2000 Avista received 32 proposals for 2,700
megawatts from 23 parties in response to its RFP. Of the 32
proposals, 8 were energy efficiency bids, 6 were for renewable
resources, and 18 were supply or unit-contingent offers. Bid proposals
were opened in the presence of supply and demand-side company
personnel as well as a representative of the WUTC.
Energy efficiency bids were provided to the DSM workgroup for a
parallel analysis and evaluation process.
Copies of the 24 remaining proposals were distributed to the supply-
side Screening Work Group for evaluation. The supply-side
Screening Work Group was made up of 12 senior-level Avista
employees from varying areas of expertise, including engineering,
regulatory affairs, wholesale marketing, resource optimization
finance, transmission, environmental, and natural gas.
The supply-side Screening Work Group applied their expertise to
determine the completeness of each proposal against the requirements
of the RFP. Based on its completeness, it was decided by the work
group whether a bid proposal should move forward to the next screen.
Where applicable, certain parties were contacted by telephone to
clarify the details of their proposals and in some instances to remove
deficiencies in them.
. On September 21 the Screening Work Group gathered to share their
findings and screen out those proposals that didn t significantly meet
the general requirements set forth in the RFP.
Letter notifications were sent to three parties on September 22, 2000
stating that their proposals did not significantly meet the general
requirements set forth in the evaluated. A verbal review of the process
to date was conducted with both WUTC and IPUC staffs.
2nd Screening Process
All supply-side proposals that passed through the Initial Screening
Process were evaluated in a 2nd Screening Process that included the
price and non-price evaluation factors described above.
Several parties with proposals in the 2nd screening were contacted by
various Screening Work Group individuals to clarify certain proposal
details.
Prosym models were run based on Henwood natural gas and
electricity base case forecasts , as well as low and high market electric
price scenario forecasts.
Exh. 6/ Schedule 1
R. Lafferty
Avista Corporation
Page 10 of 16
Resource Selection Report
February 14 2001
Screened to Short
List of Seven
Projects
(Eval. Decision
Book #1)
November
2000
RW BeckRFP
Bid Analysis
Review
(Eval. -Decision
Book#3j
Economic analysis/revenue requirements spreadsheets were generated
using all available information.
The supply-side Screening Work Group convened October 11,2000 to
assign values to the second round screening matrix.
. A short list of five proposals resulted from this screening process step,
including market purchases, small hydro, and one utility natural gas-
fired turbine option.
Analysis and results of this screening ste~ were reviewed with IPUC
and WUTC staff on October 18th and 20 respectively. WUTC and
IPUC requested two additional natural gas-fired turbine proposals be
included on the short-list, bringing the total up to seven.
RW Beck - Resource Analysis Process Review
RW Beck Consultants were retained to assess Avista s proposal
evaluation process.
RW Beck reviewed the anal~is of a representative sample of bid
proposals including Prosym inputs and assumptions, the WSCC
Regional Electricity Market Price Forecast Study prepared by lIESI
the high and low case electric price scenarios and economic models
and analyses used to calculate the expected net benefit of each
proposal to Avista s system.
R. W. Beck recommended additional fine tuning of the analysis
including: Resource dispatching against forecasted hourly market
energy prices, separate energy and capacity prices used in the analysis
use of monthly gas prices, and modification of price sensitivity cases.
RW Beck's review of Avista s analysis is summarized below:
1. Avista s approach provides a reasonable way to determine which
option is most viable
2. Approach taken by A vista provides for a fair comparison of the
resource options and does not inherently disadvantage any of the
reviewed RFP bids
3. Avista has included the necessary parameters in both the Prosym
modeling and in the economic analyses
4. R. W. Beck did not find any material deficiencies (including
miscalculation of formulas or omission of essential data) in the
analyses reviewed
Exh. 6/ Schedule 1
R. Lafferty
A vista Corporation
Page 11 of 16
Resource Selection Report
February 14 2001
November
2000
RW Beck
Market Price
Forecast
Assumptions
and
Methodology
fEval.Decision
Book #3)
RW Beck Enerl!V and Capacity Price Forecast
RW Beck Forecast
As suggested in the process review Avista contracted with RW Beck
to provide a more detailed energy and capacity electric and gas
forecast that included hourly electric prices and monthly gas prices.
This granular forecast more closely represents market conditions on an
intra-day basis when generation capacity approaches load
requirements. As seen recently in the western power market, as load
requirements approaches supply limits, dramatic price spikes can and
will occur. While it was not the intent of this long-term analysis to
estimate short-term price spikes, the purpose of the more granular
analysis was to better represent the volatility in the market. RW
Beck's hourly forecast captures price spikes, in a long-term sense, by
assuming that the generator on the margin must receive adequate
compensation to pay for all fixed and variable costs plus a profit. In a
mature electric market, demand is much less than supply during most
periods within a year. Occasionally, when load increases dramatically
due to weather, machines trip off-line, transmission lines fail, or hydro
conditions are poor, demand will approach or exceed supply. Under
these circumstances generators must recover all expenses to maintain
economic viability in the long-term.
Differences between RW Beck and HESI Forecasts
A vista contracted with lIESI to provide a long-term electric price
forecast. This forecast was used during the first two screening
processes of the RFP review. After retaining RW Beck to review
Avista s analysis process, RW Beck suggested using a refined electric
and natural gas forecast that included the following:
Resource dispatching against forecasted hourly market energy
pnces
Separate energy and capacity prices in analysis
Use of monthly gas prices
Modification of price sensitivity cases
The resulting differences between HESI's forecast and RW Beck'
forecast were within a reasonable range of one another on an average
basis. However, the granularity of RW Beck's forecast enabled the
flexible resources to capture the value of the market on an hourly basis
resulting in greater benefits to Avista s system.
Resource Selection Report
February 14 2001
Exh. 6/ Schedule 1
R. Lafferty
A vista Corporation
Page 12 of 16
Oct,/Nov. -
2000
Dec, -2000
jrd Screening
Results
f Eval. -Decision
Book #1)
Sensitivity Analysis
In addition to the basecase forecast, RW Beck provided three
sensitivity cases in the hourly price forecast. These were:
1. High Fuel Price Case with natural gas prices 25% higher than the
Base Case
2. Low Fuel Price Case with natural gas prices 25% lower than the
Base Case
3. High Load Case with WSCC loads 1.5% higher than the Base
Case
Third Screening Process
. Short-listed proposals were subject to greater scrutiny in the 3rd
screen. Electric and natural gas transportation pricing and availability
were verified. Where applicable, project heat rates and generating
capacity were adjusted to account for seasonal variances and losses.
The Company s Rathdrum project was refined to include two potential
configurations.
. Two short-listed parties were removed from further consideration due
to transmission and financial performance capability issues.
. RW. Beck price forecasts for natural gas and electricity replaced the
earlier Henwood pricing values. The biggest change was a shift to
hourly electricity pricing and loads in Prosym.
The economic analysis/revenue requirement spreadsheets were
updated with all newly available information.
Coyote Springs 2 became available as a resource option.
. On November 21,2000 the Screening Work Group re-convened to
develop a new matrix for the short-listed proposals and a
recommendation for presentation to Company officers.
Since Rathdrum continued to be a highly ranked project, community
meetings were held in the Rathdrum area to discuss the potential of an
expansion and accept public comments. A number of interested
parties were contacted, including the Kootenai Environmental
Alliance, the Pan Handle Health District, the City of Rathdrum, and
various other community and neighborhood groups.
Decision
Following the conclusion of the 3rd screen, a meeting was convened
with the Company officers to discuss the results of the RFP process.
Results of the supply- and demand-side efforts were shared.
. On November 28-29 met with IPUC and WUTC staff in Spokane to
discuss the results of the 3rd screening. Staff was informed of the
expectation that Coyote Springs 2 would be the Company s choice on
the supply side. RW. Beck made a presentation on its new market
price forecasts and its review of the Company s RFP process. The
Exh. 6/ Schedule 1
R. Lafferty
A vista Corporation
Page 13 of 16Resource Selection Report
February 14 2001
Demand Side
Spring 2000
September
2000
consultant found the Company s process was sufficiently
comprehensive and did not bias the results.
On December 1 a final meeting with Company officers confirmed the
recommendation of Coyote Springs IT, and that their proposals would
not be Springs 2 as the supply-side resource selection, and 3 DSM
bids.
Updated Resource Plan I Criteria
The development of the demand-side portion of the RFP and the
process screening, evaluating and selecting proposals benefited from
the contributions of several organizations. Substantial input was
received from the staffs of the IPUC and the WUTC as well as
representatives of the Northwest Energy Coalition, Washington
Committee on Trade and Economic Development, Northwest Energy
Efficiency Coalition and Northwest Energy Services.
Modifications to early drafts of the DSM RFP were made to
accommodate an expedited timeline without placing an undue burden
on potential bidders. Several criteria that were considered
unnecessary for the evaluation process were deferred until after the
successful proposals were selected. These criteria, including proof of
insurance, permitting and licensing and similar requirements, were
moved to the due diligence and contracting phase to make the bid
development process less onerous.
Demand-Side Evaluation Matrix Development
The DSM RFP team acted in concert with the supply-side evaluators
to develop a clear and consistent means of evaluating all proposals
received under the RFP. Six criteria were identified and weights for
the point scores of each characteristic were agreed upon. Both supply
and demand-side proposals were to have the same weights applied to
price and non-price components of the proposals.
The criteria arrived at by the DSM RFP team consisted of price (with
a weight of 50 out of 100 points), resource dispatchability (15 points),
ramping, measure life and persistence (10 points), customer
economics and customer service (10 points), bidder credibility (10
points) and portfolio value (5 points).
. A six-stage process for evaluating demand-side proposals was also
established at this time. This process was separate from that of the
evaluation of supply-side proposals, but the presence of key personnel
in both the supply and demand-side teams, the use of the same
timeline and the continual feedback regarding revealed avoided costs
was established to ensure that an integrated supply and demand-side
resource decision would be reached.
Exh. 6/ Schedule 1
R. Lafferty
Avista Corporation
Page 14 of 16
Resource Selection Report
February 14,2001
October -
November
2000
The six-stage process established called was (1) screening of the
proposals for completeness, (2) preliminary evaluation of each
proposal by a seven-person team selected based upon the nature of the
bid as well as establishing sufficient common personnel on each team
to ensure consistency, (3) final evaluation side-by-side evaluation of
all proposals by a team composed of all of the members of the
preliminary evaluation teams, (4) negotiation of short-listed proposals
completed by a single team, (5) the completion of due diligence on
those proposals selected from the negotiation process and (6)
establishing contracts with the selected proposals.
At the bid opening it was determined at this time that, in addition to
the seven demand-side proposals, one proposal submitted under the
supply-side portion of the RFP would be evaluated by the DSM team.
This supply-side proposal involved the acquisition to capacity from
customer-owned generation more appropriately evaluated by those
familiar with operations on the customer-side of the meter.
The eight DSM proposals received were advanced to a three-person
DSM screening team. Minor clarifications were required on three
proposals, one proposal required the provision of a missing page and
one proposal was deemed wholly deficient in substance. Fourteen
questions which, if answered completely, would meet the minimum
requirements upon which to base a preliminary evaluation was
submitted to WSU. Five days later representatives of WSU indicated
that they would not be phase.
DSM Proposal Evaluation and Selection
Seven preliminary evaluation teams were formed to study and
evaluate the remaining proposals. Four of the seven members of each
evaluation team were included on all evaluation teams, the other three
members were selected to provide expertise specific to the individual
proposal. Three of the four common members of all evaluation teams
were also included on the supply-side evaluation team.
During the preliminary evaluation each proposer was contacted by
conference call at least once, and usually several times, to clarify the
content of the proposal. Preliminary scoring of all proposals were
completed at the end of this phase.
All members of the preliminary evaluation teams staffed the final
evaluation process. Initial meetings were convened to discuss
capacity and energy proposals, followed by a final meeting of both
categories of proposal.
The final evaluation expanded on the characteristics of the proposals
identified in the preliminary evaluation process. Based upon a
discussion and ranking of each project for each of the six criteria a
final overall scoring and ranking of proposals emerged.
The last duty of the evaluation team was to determine which of the
seven ranked proposals had the potential to be developed into
Exh. 6/ Schedule 1
R. Lafferty
Avista Corporation
Page 15 of 16Resource Selection Report
February 14,2001
December-
February
2000 2001
successful ventures. In this final analysis the lowest ranking two
proposals were deemed to be fatally flawed in one or more categories
and were consequently eliminated from consideration.
The five short-listed proposals were forwarded to a negotiation team.
The composition of the negotiation team was such that all individuals
were familiar with the proposal characteristics by virtue of their
involvement in the evaluation process. Two of the members of the
negotiation team were also involved in the supply-side evaluation and
negotiation of proposals.
Each bidder was contacted, usually on several occasions, by the
negotiation team as a whole. Bidders were again given the
opportunity to explain the characteristics of their proposal, respond to
questions and to make voluntary modifications to their proposal.
Upon the conclusion of the negotiations each modified proposal
received a final evaluation and scoring by the negotiation team. Three
of the five proposals under negotiation were selected as successful
proposals responding to these questions. The proposal was
consequently eliminated in the screening.
Proposal Contracting and Implementation
Those proposals that had been selected were advanced to due
diligence. The due diligence team was originally composed of three
and later (due to changes in job responsibilities) four individuals.
During due diligence the bidder in being required to complete those
portions of the RFP that were deferred in order to facilitate a
streamlined bidding process (proof of insurance, permitting, licenses
etc.). References, financial and other characteristics deemed critical to
the proposal success will also be verified.
Presuming that selected proposals are satisfactorily completed and
critical characteristics verified in due diligence, the contracting phase
will complete the RFP. During this phase the bidder and company
will commit to contractual form the understandings made during the
negotiation process.
Implementation of the contracted proposals is expected to begin
immediately upon the completion of the contract.
Overall RFP Evaluation & ReDortin2
February
2001
RFP Evaluation
The Company s documentation of its resource selection process has
been compiled for future filing with the Washington and Idaho
Commissions. The purpose of the evaluation is to chronicle the
circumstances, events and the steps taken in conjunction with the
Company s resource decision in 2000.
Resource Selection Report
February 14 2001
Exh. 6/ Schedule 1
R. Lafferty
Avista Corporation
Page 16 of 16
July 12, 2000
A VISTA CORPORATION
1997 Integrated Resource Plan Update
I, Introduction:
Avista s last Integrated Resource Plan (IRP) was filed with the Commission on August 25, 1997.
That plan showed that the company was surplus for many years into the future. Since then many
things have changed in the electric utility industry and for A vista. Therefore, the company has
prepared this updated IRP to include those significant changes. As discussed later, this updated
IRP will also serve as the basis for a Request- for-Proposal (RFP) that Avista plans to issue.
The following infonnation has been presented at various T AC meetings and will become a
integral part of the next IRP.
ll. 1997 IRP Update
.....
1. Load Forecast
The 2000 electric sales forecast was prepared during the summer of 1999. The forecast of finn
sales to the core-market is one of the most critical elements and was presented and discussed at
the T AC meeting. A vista Utilities utilizes econometric models to produce sales and customer
forecasts. Econometric models are systems of algebraic equations which relate past economic
growth and development in the geographic communities served electricity with past customer
growth and consumption.
The electrical energy forecast shows an annual average load of 1013 aMW in 2001 increasing to
1159 aMW in 2009. The peak forecast shows 1594 MW in 2001 with 1851 MW in the year
2009. The ten-year compound growth rate for residential usage is 2.3 percent, commercial is 3.
percent and industrial is 1.6 percent. The overall total energy forecast has a compound growth
rate of 1.9 percent.
The annual load forecast numbers, for both peak and energy, through the year 2009 can be found
on the Requirements and Resources tabulation sheet.
2, Resource Assessment
Centralia
The sale of the Centralia coal-fired plant resulted in the loss of 201 MW of capacity and 177
aMW of annual energy from Avista s resource portfolio. The company entered into a short-tenn
contract with TransAlta, the new owners of Centralia, to replace a majority of the generation lost
with the sale of the plant. The tenn of this contract starts in July 2000 and extends through
December 2003.
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 1 of 84
Hydro Relicensing
Avista Corp. was granted by the FERC on Feb. 23 , 2000, a new 45-year license to operate the
Noxon Rapids and Cabinet Gorge hydroelectric projects on the lower Clark Fork River. Thelicensing effort culminates seven years of planning and consultation, utilizing a unique
collaborative approach that produced one of the most successful ever hydro relicensing efforts.
The application to relicense was submitted by Avista Corp., Feb. 18, 1999, and contained a
comprehensive settlement agreement with 27 signatories.
This landmark agreement ensured the continued economical operation of the two plants while
providing a variety of enhancements to natural resources of the project area. A vista retainsnearly all the valuable load following and peaking capability of the two projects while providing
early implementation of protection, mitigation, and enhancement measures to benefit native fish
species, recreation opportunities, continued protection of cultural resources, wildlife populations
and water quality. Avista will spend approximately $4.7 million annually with a significant
expenditure eannarked for enhancing bull trout populations.
Contract Sales and Purchases
While there has been a lot of wholesale contract activity since the last report, the terms of the
more recent contracts have tended to be relatively short. It is interesting to note that most of the
purchase and sale agreements tenninate by the year 2003 , except some of the contracts with BPA
and exchanges. There are only three sale contracts that extend beyond the year 2003. Those are
the PacifiCorp, PGE and Snohomish PUD contracts.
*PacifiCorp and the company entered into a ten year summer capacity sale for the period
June 16, 1994 through September 15 2003 (with PacifiCorp option to extend for up to
five years). The company delivers 150 MW of summer capacity with energy purchased
at 25 percent load factor based on variable prices.
*Portland General Electric is purchasing from the company 150 MW of capacity through
December 31 2016. The energy associated with the capacity deliveries has to be
returned within 168 hours.
*Snohomish PUD purchases 100 MW of firm capacity with a minimum amount of finD
energy at 50 percent load factor from the company. The contract ends September 2006.
Avista also has. a large cogeneration facility (potlatch Forest Industry) in its service territory that
entered into a ten-year contract with the company which tenninates at the end of 2001. The
power received from Potlatch has a maximum capacity of 59 MW and average energy of 55
aMW.
Hydro Upgrades
In 1999, the company completed the program to replace all four runners at Long Lake, which
increased the capability from 72.8 MW to 88 MW. In the planning stages are turbine runner
replacements and generator rewinds for three units at Cabinet Gorge and two units at Noxon
Rapids. There is also a possibility of an Upper Falls turbine runner replacement and generator
rewinds for three units at Little Falls.
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 2 of 84
3, Reserves Analysis
A reasonable level of planning reserves helps the company ensure adequate generating capacity
during periods of extreme weather or unexpected plant outages. Avista s planning reserves are
not based on the size or types of its resources. Avista s capacity reserves include components for
cold weather, generator-forced outages and contingencies such as river freeze-up at hydroelectric
plants.
The company s planning reserves are based on 10 percent increase in peak loads or one day in
twenty years and an additional 90 MW to account for river freeze ups and a portion of the forced
outage reserves. This provides Avista with about 15 percent reserves based on forecasted peak
loads. The forecasted peak loads are based on the average expected cold day. For example, thepeak for January 2000 was estimated at 1557 MW (at 8 degrees F) but we would expect the peak
to be 1713 MW on the extreme day (-10 degrees F).
Avista s operating reserves are considered a pan of the company s planning reserve numbers.
The operating reserves are 5 percent of hydro generation and 7 percent of thennal and are what
we are legally required to carry under regional criteria.
4, Re-dispatch Study
As the company contemplates the addition of one or more resources to its portfolio it will be
faced with a different resource stack and fuel mix. The new resources will have an impact on the
resource dispatch sequence because of the fuel supply and marginal costs. The company is using
PROSYM to model its resources, to meet its load requirements on an hourly basis, and to assess
the dispatch requirements and compatibility of new resources used in conjunction with existing
resources, both hydro and thermal.
PROSYM is a commercially available production cost model used to perform electric planning
and operational studies. Due to its hourly chronological design and its capability to accurately
dispatch the company s flexible hydro system, we use PROSYM to perform dispatch analyses of
various generation sources. A key point to remember is that PROSYM is a production cost
model. The resource inputs include machine characteristics, fuel costs, and variable operation
and maintenance costs. The model does not calculate the total cost of the resource. After the
dispatch information is obtained from PROSYM, traditional economic analyses of each resource
option must be performed.
An example of a PROSYM run with a new combined cycle combustion turbine modeled into the
company s system is shown in Appendix A.
5, Long Term Natural Gas and Electric Price Forecasts
There is much uncertainty in the natural gas and electric price forecasts. Price volatility has
increased recently given extremely high prices in the daily and forward markets. The company
knows that there will be periods of high prices and periods of low prices as the price curves
fluctuate based on demand and supply criteria. It is the company s goal to provide and use a
forecast that is reasonable in its start point and escalation for the long tenn. A vista knnw~ there
A vista Corp - 1997 IRP Update
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 3 of 84
will be variations both high and low in the future as the company forecasts theSe energy prices.The forecasts reflect the best information that is available at the time the forecast is made.
Key to any "buy or build" decision is an understanding of the future prices for electricity and
natural gas. Because natural gas generation is a significant contributor to the cost of operating
such a facility, the future prices for this underlying commodity cannot be overlooked.
discussed above, there is uncertainty in both the near-term and long-tenn natural gas price
forecasts. A vista therefore relies on a set of forward. predictions it believes account for a range
of possible future outcomes.
The Natural Gas Price Forecast
The price forecasts developed for this update build on the natural gas forecast contained in
Avista s forthcoming July, 2000 Natural Gas Integrated Resource Plan (Gas IRP). Contained inthe Gas IRP is a base forecast of northwest natural gas prices, as detailed in the median or base
case forecast shown below.
Northwest Natural Gas Price Forecasts
2001-2033 nominal dollars
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As detailed in the graph in the base case, natural gas prices rise from an average annual value of
$2.52 in 2001 to $6.35 per decathenn in 2025, the end of the Gas IRP forecast. On average, this
equates to a 4.1 percent annual change.
The Gas IRP does not analyze natural gas price sensitivity at the wholesale level and ends its
forecast in 2025. Therefore to represent low and high forecasts, the base case escalation rate was
adjusted downward and upward by 1 percent annually, respectively. Additionally, to provide a
30-year forecast beginning in 2004, the rate of change in 2025 was continued through 2033.
the low case, the cost per decathenn rises only to $7.12. In the high case, the price increases to
$12.88. This compares to a base forecast in 2033 of $9.60 per decatherm.
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 4 of 84
The Electricity Price Forecast
With the scenarios for future natural gas prices established, electricity price forecasts was
estimated using a "spark spread." Spark spreads identify the heat rate expressed in Btu/kWh
that, when applied to a natural gas price, equate an equivalent price of electricity. For example
on June 8, 2000 the forward price for July 2000 natural gas was $4.13 per decatherm. The July
2000 Mid-C forward price was approximately $110 per MWh. The spark spread for Julyequated to 26,635 Btu/kWh.
The average spark spread through calendar year 2000, again using quotes obtained on June 8
2000, is 21 920 Btu/kWh. Looking forward, the calendar year 2001 spark spread is
approximately 17 300 Btu/kWh. To convert the natural gas price forecasts into electricity
forecasts, varying spark spread values were considered. The short-term spark spreads inherent in
today s forward markets appear high given historical levels. Between 1997 and 1999, the spark
spread varied from a low of 7,800 to nearly 17,000 Btu/kWh.
To represent the varying spark spread levels A vista considered three spark spreads of ten
thirteen, and fifteen thousand Btu/kWh applied to the three natural gas price forecasts. At tenthousand BtulkWh with base case gas prices, electricity prices rise from approximately $24 per
MWh in 2004, to $38 pet MWh in 2013, to $96 per MWh in 2033. The average annual nominal
price increase equals 4.8 percent. In real terms, the equivalent values are $22, $27, and $31,
equal to a 1.1 percent annual increase.
Where the spark spread is assumed to be fifteen thousand BtulkWh, our high case estimate
electricity prices equal $39 per MWh in 2004. Prices rise to $61 in 2013 and then to $153 in
2033. The average annual price escalation again is 4.8 percent nominal. In real tenns, prices
rise from $36 in 2004 to $49 in 2033, for an annual average real escalation of approximately 1.1percent.
Avista s base case spark spread forecast is thirteen thousand Btu/kWh. At this level, electricity
prices rise from approximately $32 per MWh in 2004 to $50 per MWh in 2013, to $125 per
MWh in 2033 using the base case gas forecast. In real terms, the equivalent values are $29, $35
and $40 per MWh in 2004 2013, and 2033, respectively. The average nominal increase equals8 percent. In real terms, the forecast rises 1.1 percent annually.
Using the low natural gas price forecast and the base case spark spread, electricity prices rise
more slowly at 3.8 percent annually, or 0.1 percent real. In 2004 the annual average electricity
price equals $31 per MWh. By 2033 the price equals $93 per MWh. With the high natural gas
forecast, electricity prices rise at an average annual rate of 5.8 percent nominal and 2.0 percent
real. Forecasted prices increase from $32 per MWh in 2004 to $167 per MWh in 2033.
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 5 of 84
The following table describes the three electricity price forecasts, including forward market
prices prior to August 2003.
Northwest Electricity Price Forecasts
July 2000-2033 nominal dollars
170
150
13.000 Blu/kWh Spark Spread
110 O/S,uO
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6. Resource Alternatives
There are multitudes of resource options available to the company. Some are more suitable than
others depending on capital cost, dispatchability, accessibility, operating experience
environmental considerations, and other impacts. All resource options will be evaluated
including energy efficiency measures. Probably the preferred resource scenario will be a
combination of resource options.
Some of the options that have been discussed and are under consideration are:
Build a generating resource
Purchase existing or new generation assets
Complete system upgrades at generating facilities
Negotiate a long-tenD power purchase agreement
Buy in the short-tenD wholesale market
Purchase the output of a generating or cogeneration facility
Develop additional energy efficiency and DSM programs
. Buy energy efficiency through third party developers
Customer load dropping is also being considered although it is not generally considered a
resource. Retail load that can be interrupted or curtailed under specific circumstances can free-
up temporary capacity and energy. And as such, the company plans to explore those possibilities
through contract negotiations with large customers.
The initial screening of resource costs uses data from the Power Council, actual sites being
. constructed or just recently constructed, and infonnation received from national publications.
Avista Corp - 1997 IRP Update
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 6 of 84
Attached are the nominallevelized costs in 1999 dollars of many supply-side resource types
made available by the Power Council (see Appendix B).
Nuclear plant costs are not on the list, although we know (from previous Power Council studies)
that nuclear total cost is above 100 mills/kWh or ranked on the high end of the Power Council'
geothermal projects.
Biomass plants are also not on the list except for land fill gas and biogasification plants. Theanalysis show that biomass plants have total costs in the range of the low geothennal costs orabout 70 to 80 mills /kWh.
Many of these resources have costs that are very site specific, especially the renewables like
wind and geothermal. Avista would need to do a very detailed cost analysis based on a particular
site location in order to assess ultimate viability of these options.
Avista is constantly assessing the markets in order to buy and sell power on an hourly and daily
basis. Most utilities and marketers don t want to commit to long-term sales due to theuncertainty in the markets. At this time other utilities in the Northwest find themselves in the
same situation as A vista so a long-term commitment from them for a power supply would not be
very likely. We have included in the proposed RFP a provision to bid to Avista a long-term
power supply contract.
Avista s energy efficiency programs are evaluated in detail on a trimesterly basis and submitted
to the company s External Energy Efficiency (Triple-E) Board for review. These reports cover
the full menu of standard practice tests and descriptive statistics and are disaggregated by
customer segment and technology. These reports are the basis for company program
management efforts as well as providing a foundation for meaningful oversight by the Triple-
Board. The company has also assessed the potential for enhancements to specific programs to
meet utility resource needs and will be assessing the potential for capacity and peak-energy
targeted programs in the near future. Please see Appendix C for further information.
7, Screening Results
Avista has historically planned and developed various resource types. The company hasexperience with hydro, coal, natural gas, and biomass generating plants and demand-side
resources. This operating experience gives the company valuable information that can be used in
its resource evaluations.
A vista needs a resource that can provide additional benefits in support of the existing generation
system. What is needed is a resource that can be dispatched, follow load, and provide a capacitycomponent. In other words, as an entity with a control area, the company needs resources that
are dispatchable and meets energy and capacity requirements under a variety of conditions.
A natural gas fired electric generation plant is one example of a resource that could meet those
needs stated above. Natural gas plants can be built relatIvely quickly with relatively low capital
Exh. 6 Schedule 2
R. Lafferty
A vista Corporation
Page 7 of 84
costs and discharge less pollutants into the air than other fossil fuel plants. As shown in
Appendix B , the Northwest Power Planning Council costs for natural gas fired generation
projects range from approximately 41 mills to 43 mills.
At this point in time the following resources would not pass the initial screening. The following
costs are nominallife-cyc1e, levelized costs.
Nuclear: Costs are over the 100 mills per kilowatt-hour range. The total cost and the
lack of public acceptance make this resource option unacceptable.
Coal: Costs are 80 to 90 mills. The total cost and cost uncertainty in air quality issues
make this resource option unacceptable.
Wind: Costs are 60 to 80 mills. There are indications that costs are declining but our
studies show there are not favorable sites in our service tenitory so transmission costs
would have to be added. Because wind is intermittent the resource would have to be
discounted for lack of capacity component. This would make this resource option
unacceptable.
Geothennal: Costs are 80 to 100 mills making this resource option unacceptable.
Solar: Costs are over 240 mills making this resource option unacceptable.
These costs are presented for general comparison purposes. The company will solicit resource
bids from the market in an upcoming Request-for-Proposals (RFP). The company is hoping for
innovative bids from project developers. The RFP bids will be evaluated against the infonnation
that has been gathered both internally and externally.
8. Load and Resource Summary
General
Included is Avista s annual Requirements and Resources (Load and Resource Summary) that
shows the company s load and resource position on an annual basis for the next ten years (see
Appendix D). It is dated June 1,2000 and will be the same one used in the 2000 IRP. The peak
column is the January peak (the highest forecasted peak for the year) and the average column is
the annual 12-month average for the year. The resource peak numbers are what could be
expected as maximum capacity outputs during January. The hydro peak and energy numbers are
from the final regulation done by the Northwest Power Pool and reflect the reservoir levels in
January per the hydro regulation study (one-year critical period, 1936-37 water). The average
energy numbers are the expected 12-month averages for the loads, resources and contracts.
All the requirements are shown at the top of the page. Most of the purchases and sales contracts
end by the year 2004. The peak and average forecasted loads are shown on line 1 labeled
System Load. Line 17 Reserves are A vista s planning reserves and are part of the total
Requirements (as described in Section 3).
The Resource section is comprised of the resources and purchase contracts. Line 19 shows the
system hydro and line 20 is the contract hydro from the mid-Columbia PUD projects (with
critical water conditions). The mid-Columbia numbers decrease due to the Priest Rapids contract
ending in 2005 and the Wanapum contract ending in 2009. Avista is hopeful that a contract
extension can be negotiated with Grant County PUD. Lines 24 and 25 are the company s existing
Avista Corp - 1997 IRP Update
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 8 of 84
simple-cycle combustion turbines, and lines 33 and 34 are the expected thennal generation
output from Kettle Falls and Colstrip.
Line 29 shows the BP A residential exchange contract and the 47 MW flat delivery of power to
the company from BP A. There is no dispatchability or flexibility with this contract. Although
this contract has not been signed~ A vista feels it is finD enough to be included.
Line 44 is the Surplus (Deficit) numbers calculated by subtracting the Total Requirements from
the Total Resource numbers. In the year 2004 Avista is 287 MW deficit on peak and 318 aMW
deficit on energy under critical water planning criteria.
Resource Flexibility
Flexible generation resources are a key component to meet the requirements of Avista
customers. As depicted in the charts on pages 8 and 9 in Appendix E, A vista experiences load
changes of 100 MW or more during several hours of each day. Loads must be ramped up and
down under a variety of seasonal and load conditions. In order to meet the load, flexible
resources (Cabinet Gorge, Noxon Rapids, Long Lake, Mid Columbia contract hydro, and the
Rathdrum Combustion turbines) are dispatched. Even with these resources, A vista still must
purchase peak energy products to meet customer demand during different times. The market
today tends to offer standard heavy load hour and light load hour products that do not meet load
shaping or following needs.
2004 Study
A detailed tabulation of the load and resource requirements study of the year 2004 is also
attached (see Appendix E). We chose the year 2004 for an in-depth study because, as mentioned
above, many of the larger supply and requirements contracts have ended and future requirements
change (for the most part) due to load growth.
This study is shown in two parts. The first study shows on and off peak loads and resource
requirements monthly under critical and nonna! hydro conditions. The second study goes into
even further detail. We created an hourly Surplus-Deficiency duration Curve for the year 2004
using PROSYM to gain the following infonnation. By using the Northwest Power Pool's sixty
year hydro generation study for our system, PROSYM runs 720 (sixty years X 12 months/year)
hydro scenarios into the forecast net system load, all known contracts, and existing resources.
The infonnation gained from this model output shows the company s resource requirements to
meet load under many different hydro conditions. This duration curve will be used to analyze
how new resource additions will "fit" into the company s requirements without any affect from
market conditions. As stated before, standard economic modeling must be penonned afterdispatch infonnation is gained from PROSYM modeling.
Load growth expectations based on the forecasted methodologies are explained under Section 1.
Avista doesn t expect drastic changes in our load beyond the nonnalload growth that has been
experienced. But the future is uncertain and Avista needs to be flexible enough to handle
unforeseen changes. For example, the company could lose load by having Avista s larger retail
customers install cogeneration, like WSU or Potlatch deciding to serve their own load from
existing generating facili ties. Or if partial deregulation was to come to our region, A vista could
pick up some industrial loads thereby increasir g the load requirements.
Avista Corp -1997 IR.P Update
Exh. 6 / Schedule 2
R. Lafferty
Avista Corporation
Page 9 of 84
APPEND IX A
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 10 of 84
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....
J.I
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 13 of 84
11/
011
...
J.J
Exh. 6 / Schedule 2
R. Lafferty
A vista Corporation
Page 14 of 84
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......
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 25 of 84
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6
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APPEND IX B
Exh. 6 / Schedule 2
R. Lafferty
A vista Corporation
Page 32 of 84
Exhibit 1
Alternative Resource Options
Source: NWPPC (6/00)
Nominal Life-Cycle Levelized
Cost(1999$)
Project Type Fuel Type Total Capital O&M Fuel
250 MW CC - West & A2-14 Block 2 Base Gas 41.18 13.24.
2x160 SCCT Low Gas 41.34.
250 MW CC - Eastside Block 2 Base Gas 42.14.24.
2x160 SCCT Base Gas 42.34.
2x160 SCCT Hioh Gas 43.34.
Hioh Plains Wind (AB, MT, WY, CO, NM)Wind 60.47.13.
Hioh Plains Wind
((g
Main Grid)Wind 69.48 53.16.
Landfill Gas Recovery Landfill Gas 69.28.32.
Pacific Coast Wind (BC, OR, W A, CA)Wind 78.61.55 17.
Adv. Coal (PFBC)Coal 79.37.33.
Geothermal 4th Plan Group 1- Oct.Geothermal 79.59.19.
Geothermal 4th Plan Group 1- Base Geothermal 79.59.19.
Cascades Geothermal - Optimistic Geothermal 81.61.09 20.
Geothermal 4th Plan Group 1- Pessimistic Geothermal 81.60.20.
Cascades Geothermal - Base Geothermal 81.61.41 20.
Cascades Geothermal - Pessimistic Geothermal 82.61.72 20.
Conventional Coal (300 MW)Coal 88.41.37.
80MW SCCT, 4/29 Pessimistic Gas 92.38.43.
Basin & Ranoe Geothermal - Optimistic Geothermal 103.78.25.
Basin & Ranoe Geothermal -. Base Geothermal 103.78.25.
Basin & Ranoe Geothermal - Pessimistic Geothermal 105.47 79.26.45
25 MW Bio-Gasification CC (4tn Plarl)Biomass 122.45 52.33.37.
Basin & Ranoe Wind (10, AZ, UT, NV)Wind 135.44 104.30.
80MW SCCT, 4/29 Optimistic Gas 144.69.19.55.
80MW SCCT, 4/29 Base Gas 148.45 73.19.55.
Aurora Fuel Cell (Distribution CG).Gas 172.125.25.22.
Eli PV ~ Grid (50 miles)Solar 242.237.
Whitehorse PV ~ Grid (50 miles)Solar 284.278.
Whitehorse PV ~ Grid Solar 291.280.10.
PV Shinoles Solar 558.549.
Roof Rack PV Solar 611.602.
Aurora Fuel Cell (Peakino)Gas 823.674.99.48.49
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 33 of 84
APPEND IX C
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 34 of 84
Triple-E Report
December 1 , 1999 to March 31 , 2000
Avista Utilities Controllers Dept.
Resource Analysis Team
Jason Fletcher
Steve Negretti
Jon Powell
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 35 of 84
Table of Contents
Introduction.........
'..""".'. .'.. ........ ......... .."..." ...... ... ......".... ... .... .................... .'.'..".... ... ................
General Analytical Notes """
............. .............. ................... ..... '.". ."...'."."'" ."""'. ...... ............... .....
Database and Non-Database Projects.
.""." ... ... .............., "".".""""'.".'" ." ."'" .............................
Non-Quantifiable Non-Energy Impacts... ... .....,
'.."""'" ... ...... .'.'" ............ """".."'" ... .."'.""" ...........
Quantitative Results...... ...
'.""""'. ... ",.""",.", ........: .::...... ... ........................... """"""'."'. ... "'." .""
Allocation of Utility Costs... ......
""""'." "'."'" ""'.""'.." .............................. ...... ......... ................ ....
Table Utility Costs Aggregated by Programs and Customer Segments............................................
Table Assignment of Utility Costs to Customer Segments.............................................................
Table 3, Allocation of Utility Costs Across Customer Segments and Technologies.................................
Table Allocation of Direct Incentives Across Customer Segments and Technologies..........................
Treatment of -De-Rated" Project Results....... ........
""",." ......... .............................. """ """""'.""'"
Energy Savings... ....., ......
...... ... "'."""" ...................,.... ...... ...... ......... ......... """'" ... ... ... ... """ .....
Table 5, Allocation of Electric Savings Across Customer Segments and Technologies...........................
Table 6, Allocation of Natural Gas Savings Across Customer Segments and Technologies.....................
Customer Costs and Non-Energy Benefits............
""""""'" ................................. """"'.""""'" """
Table Allocation of Non-Energy Benefits Across Customer Segments and Technologies
.....................
Table 8, Allocation of Customer Costs Across Customer Segments and Technologies...........................
Cost-Effectiveness and Descriptive Statistics........................... .................. -..
""""..'."'.'" ................
Table Cost-Effectiveness Statistics by Customer Segment
""""""'" """"'.'.""" ."""" """""" ".".
Table 0, Cost-Effectiveness Statistics by Technology........................................
.............................
Table Net Benefits by Customer Segment.........
""""""'."'..""""""". ............................... ......
Table 12. Net Benefits by Technology.................................................................
...................-..-..
Table 13, Summary of Cost-Effectiveness Tests and Descriptive Statistics..................._.....................
Energy Efficiency Tariff Rider Balance Calculations..................................................................
"""'"
Table 14, Calculation of Energy Efficiency Tariff Rider Balance and Interest........................................
Analysis Measurement and Evaluation Summary............................._.................................................
Program Updates
".""" """""" """"""""" ...............,.. ....,....... ... .-. .-. ... """'" """."""'." .........."
Individual Project Reviews...................... .....
...............". ......................................... ..-...................
Notable Projects, Disclosures, and Policy Updates
.............". ......." ......... """"""'" ...... """"""".' """"
Database Change.....................
-"""""""""'."""""""""""" .................................... ............ ""
Technology Revision........................ ...............
""""'."""."""'."""""""'" ..... ....................".. .....
Treatment of Direct Incentives and Non-Energy Benefits....................................................................
Supermarket Refrigeration Case Retrofit Project....................................................
.""'."""""""""'.
Appendix A, Additional Descriptive Statistics......
"""""""""'" ..............-.............................................
Table A 1, Breakdown of Database Projects by Type.......................................................................
Table A2, Breakdown of All Projects by Type....................................
.....................-......................
Table A3, Breakdown of Database Projects by State......................................................................
Table A4, Breakdown of All Projects by State................................................................................
Table AS, Breakdown of Database Projects by Electric Rate Schedule.................._..................._........
Table A6, Breakdown of All Projects by Electric Rate Schedule.........................................................
Table Al, Breakdown of Database Projects by Natural Gas Rate Schedule.........................................
Table A8, Breakdown of All Projects by Natural Gas Rate Schedule...................................................
Appendix B , Summary of Results the August 1 to November 30,1999 Report...........................................
Table B1, Utility Costs Aggregated by Programs and Customer Segments..........................................
Table B 2, Assignment of Utility Costs to Customer Segments.......
...... """""" ..... .......... ... .. . . ..... ... ....
Table B3, Allocation of Utility Costs Across Customer Segments and Technologies
............".................
Table B4, Allocation of Direct Incentives Across Customer Segments and Technologies
""""""""""""
Table B5, Allocation of Electric Savings Across Customer Segments and Technologies.........................
Table B6, Allocation of Natural Gas Savings Across Customer Sf!gments and Technologies...................
Table B7, Cost-Effectiveness Statistics by Customer Segment
............ ...... ........................................
Table B8, Cost-Effectiveness Statistics by Technology.........
""""""'" ..... """""'" .............. """""'"
Table B9, Summary of Cost-Effectiveness Tests and Descriptive Statistics..........................................
Table B10, Calculation of Energy Efficiency Tariff Rider Balance and Interest........................._............
Exh. 6/ Schedule 2
R. Lafferty
A vista C'.ornorJltion
Page 36 of 84
Avista Utilities Triple-E Report March 2000
Introduction
This is the second Triple-E Report produced in fulfillment of Avista Corporation s commitment at the time
of the most recent Schedule 90 Tariff approval. This report covers quantitative results for the December
, .
1999 to March 31 , 2000 trimester. It includes costs, energy savings, cost-effectiveness and descriptive
statistics, Energy Efficiency Tariff Rider balances, measurement and evaluation (M&E) activities, policyupdates, and large project disclosures.
Given that much of the basic methodology was covered in the prior report, we have excluded that
discussion from this report. We are distributing an electronic version of the previous report for the
reader's reference.
In place of the methodology discussion, this report includes approximately three times as many tables
than were present in the last report. This is partially to facilitate comparison against the previous August
1 to November 30, 1999 trimester report. but this report also contains a more detailed disaggregation of
our impact by jurisdiction and rateclass. Unless otherwise noted, the analytical methodology employed is
unchanged from the prior report.
This is the first report where the SaJesLogix database has been used. Data quality has improved in
several areas of this process , including the incorporation of additional information fields and custom
reports.
Although the format of the June 2000 Triple-E Board meeting does not include discussion of this report,
we would appreciate the opportunity to meet with any Triple-E Board member interested in the full detail
of these calculations, either individually or in small groups.
Page 1
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 37 of 84
Avista Utilities Triple-E Report March 2000
General Analytical Notes
This section has been included to provide insight into analytical details that affect the results of this report.
This includes relevant information regarding the treatment of raw data that influences the analysis.
Database and Non-Database Projects
All Avista Corporation energy efficiency projects can be roughly divided into two categories; those that are
tracked on a project-by-project basis through the Sa/esLogix database and those that are handled outside
the database.
Non-database projects include the Resource Management Partnership Program (RMPP), the Limited
Income program and the Natural Gas Awareness Campaign. The analyses of these programs are
brought into the report only after a custom evaluation of their costs and benefits are completed.
Database projects are tracked individually through the Sa/esLogix database. Each of the characteristics
relevant to the analysis, such as energy savings, non-energy benefits, utility revenue impact and
customer cost, are specified based upon each project's unique characteristics.
Database Project Details
Projects tracked through the database include all projects that are individually reviewed. as well as three
measures that are analyzed in mass (due to the similarity of many of the project characteristics). Projectsreviewed in mass are comprised of the following measures:
1) VendinaM/$EFfM
VendingM/$ER is a control mechanism used to reduce the energy usage of cold drink vending
machines. A prescriptive analysis of non-energy benefits resulting from VendingM/$ER installations
revealed that a significant portion (20%) of the participant benefit from this measure accrue in the
form of non-energy (maintenance) savings. These results have been incorporated into the analysis.
Since this is a control device, benefits and costs accumulated through VendingM/$ER are allocated to
the Controls technology.
2) lED Exit Sians
A detailed analysis of lED exit sign annual energy savings was conducted in 1999, with the result
being a revision from 240 kWh per sign to 200 kWh per sign. This was primarily based upon a higherinventory of compact fluorescents in the existing inventory than was anticipated. The analysis team
has also completed a prescriptive analysis of non-energy benefits resulting from the installation of
lED exit signs. The results of this analysis indicate that most (83%) of the participant benefit from
this measure accrue in the form of non-energy (maintenance) savings. These results have been
incorporated into the analysis. lED exit sign projects were incentivized as New Technologies.
such. benefits and costs accumulated through this program are allocated to the New Technologies
measure.
3) lED Traffic Siona's
The energy savings from LED traffic signals are tracked by jurisdiction and are incorporated into the
analysis. This measure has also been the subject of a non-energy benefit analysis by the analysis
Page 2 Exh. 6 / Schedule 2
R. Lafferty
Avista Corporation
Page 38 of 84
Avista Utilities Triple-E Report March 2000
team. The results of this analysis indicate that a significant portion (42%) of the participant benefit
from this measure accrue in the form of non-energy (maintenance) savings. These results have been
incorporated into the analysis. LED traffic signal projects were incentivized as New Technologies.
such, benefits and casts accumulated through this program are allocated to the New Technologies
measure.
All Other Proiects
All projects tracked within SaJesLogix aside from those fitting the categories above, are individuallyanalyzed for their impacts. All characteristics relevant to cost-effectiveness calculations and descriptive
statistics are based upon project specific circumstances.
Non-Database Project Details
Resource Manaaement Partnershio Proaram (RMPP)
This program derives resource savings by placing resource managers in individual school districts. Theresources affected include electric, natural gas (and other energy), water, sewer and solid waste. For themast part, the nan-energy resource impacts occur early during the resource manager's work with the
school district. During this particular trimester there were not any significant non-energy resource
savings. Energy savings, however, do require the ongoing presence of a district resource manager and
do not degrade as much as non-energy resource savings during the period of time that the resource
manager is present.
The billing analysis captures the electric and natural gas savings. Non-utility energy impacts are captured
on a site-specific basis. The billing analysis for the RMPP program has, over time, resulted in severalpolicies dealing with such contingencies as new construction at an existing school site, the treatment of
portable buildings, the aggregation or disaggregation of loads across multiple meters, and so on.
Projects for which the customer receives a direct incentive at a school site where a resource manager is
present are removed from the metered savings calculation and credited to the technology that the direct
incentive applies toward. For example. the savings from lighting projects at schools are removed from thebilled energy savings and credited as an impact of the lighting technology. All billed energy savings
remaining after these specific projects have been removed are attributed to resource management
activities.
The resource management energy savings can then be characterized by three components; (1)
behavioral, such as tuming off the lights as necessary, (2) operational, such as utilizing existing controls
or modifying the dispatch of end-uses and (3) hardwired measures that, for one reason or another, did not
receive a direct incentive. In recognition of the short life of the behavioral and operational measures, incalculating the energy savings for any particular period of time it is assumed that 50% of the energy
savings in the prior year and 25% of the energy savings two years preceding were readapted. This effect
substantially increases the number of first-year kWh claimed by the program, but it also results in a
weighted average life of only four years for these billed energy savings.
At this point we don t have enough data an school districts that have discontinued their resource manager
program to verify the accuracy of the measure persistence figures being used.
Limited Income
The Limited Income program obtains energy savings- through weatherization improvements and electric to
gas conversions (space heat and domestic hot water) for qualified electric utility customers. These
Page ~Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 39 of 84
Avista Utilities Triple-E Report March 2000
savings enter the analysis by applying the results of a detailed billing analysis study completed in 1999 to
the water heat and space heat conversions claimed through the program. The weatherization savings
are based upon engineering estimates specific to the dwelling. Since the vast majority (99%) of the
energy savings in this segment is from fuel-conversions. this has been the focus of the measurement and
evaluation efforts to date.
The Limited Income program also funds structural and mechanical repairs to qualified homes, subject to a
cap. if they are necessary to ensure the persistence of the energy measures installed, or if they are
necessary on a health and human safety basis. It is assumed the benefits derived from these repairs
have a non-energy benefit commensurate with their costs.
In this particular trimester no costs associated with these repairs were reported to the analysis team.
will be following up on these impacts in more detail in the next trimester to determine if expenses had
been incurred that were not captured as non-energy benefits.
Since these programs are operated in conjunction with community action program (CAP) agencies as
part of their overall offerings to this customer segment. the utility costs of the programs are fairly minimal.
This leveraging strategy has substantially contributed to a cost-effectiveness higher than would be
expected out of this segment.
To clarify the meaning of the various tables reporting on this program, the customer cost is equal to the
utility incentive for the limited income programs because aU costs associated with energy savings are paid
for through the incentive.
Natural Gas Awareness Camcaian (NGAC)
The effects of the NGAC are incorporated into the analysis based upon the most recent information on
actual residential conversions of space heating, water heating, clothes dryers, ovens and ranges. The
first 1 000 space heating conversions are excluded on the basis that these customers are part of the
natural adoption in our service territory. This is the only program that excludes the energy savings of
free-riders (or natural adopters).
The savings for this program will be adjusted when recently completed survey information is subjected to
our energy savings analysis and verification.
Non-Quantifiable Non-Energy Impacts
The analytical group has been working to further develop means of quantifying, where possible, and
identifying, where quantification is unreasonable, the non-energy impacts of our projects. The reason for
this is twofold; (1) to more accurately represent the cost-effectiveness of the projects and (2) to provide
management information about the overall benefits of our programs. This information will be used to
refine the marketing of energy efficiency technologies.
At present our quantification of non-energy effects has been limited to two primary components; (1)
modifying the capital cost of projects to reflect differences in end-use equipment life and (2) incorporating
the maintenance savings. The quantified maintenance savings is almost exclusively related to lighting
projects. The non-quantifiable value of these non-energy benefits must be taken into consideration when
interpreting much of this analysis. and in particular the TRC test results.
We are endeavoring to improve our ability to identify and quantify these non-energy benefits in the future.
One of the changes implemented to address this issue is detailed under the Notable Projects. Disclosures
and Policy Update section of this report.
Page 4 Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 40 of 84
Avista Utilities Triple-E Report March 2000
Quantitative Results
The following contains descriptions of the methodologies used for completion of the cost-effectiveness
analysis and descriptive statistics for the December 1 , 1999 to March 31 , 2000 trimester. Observations
noted in the course of performing this analysis have been noted as well.
Allocation of Utility Costs
This allocation methodology is essentially unchanged from our previous report.
The raw data for utility non-incentive costs comes in the form of actual expenses and journal entries
incurred by Tariff Rider accounts. The raw data for direct incentive costs comes in the form of accrual-
based expenses, drawn from the SalesLogixdatabase. While non-incentive costs represent real
expenditures, incentives are de-rated in the same manner as kWh, therms, etc. As such, incentivesapplied to projects in the Contracted phase are accounted for at 75%, those applied to projects in the
Construction phase are accounted for at 95%, and those applied to Completed projects are accounted for
at 100%. This methodology was adopted this trimester in an effort to more closely align expenditures
with committed funds.
Each expenditure is incurred through an account number specific to the appropriate customer segment
to an "old" program (prior to our shift to the customer segment model), or to general implementation or
M&E. In order to attribute all costs to customer segments and technologies , three allocations must be
made. The first allocation assigns the expenses associated with the old programs to customer segments.
Next, the general implementation and general M&E expense are allocated to customer segments. Last
the utility non-incentive expenses associated with, or allocated to, each customer segment are allocated
to individual technologies within that segment.
The overall allocation process is heavily dependent upon the judgement of the individuals performing the
allocation. The meaningfulness of these allocations is handicapped by the joint cost nature of many
expenditures. An audit, site visit, or marketing effort is generally targeted towards multiple technologies.
Consequently there is the potential for technologies which are cost-effective contributors to the overall
portfolio to be cost-ineffective as a result of being burdened with a disproportionate amount of allocated
general costs. This should be considered when reviewing both cost-effectiveness ratios and net cost-
effectiveness results.
In our previous Triple-E Report we noted that the proportion of utility costs allocated to one of the general
categories seemed excessive. The general implementation and general M&E categories were only to be
used if a cost could not be reasonably allocated to one or more individual customer segments. We
reiterated the need for accurate reporting of these costs to the staff on several occasions after that point.
The net result was an insignificant reduction in the proportion of costs charged to general (27.7% to
27.5%). We will continue to follow up on this task, but our tentative interpretation is that the allocation to
general costs is appropriate in spite of the initial appearances.
Refer to Tables 1-4 for utility costs allocated across programs, customer segments, and technologies.
Page 5
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 41 of 84
Avista Utilities Triple-E Report March 2000
Table 1 Utili Costs A ated b Pro rams and ~ustomer Se ments
Implementation Incentives M&E TOTAL
SEGMENTS
Agriculture 756 756
Education 120,099 208,958 912 331,969
Food Service 947 16,200 396 30,543
Health Care 486 22,715 34,279
Hospitality 784 25,240 241 51,265
Limited Inccme 12.960 414 492 427 452
Manufacturing 104,638 127 739 941 233,318
Office 709 30,441 004 60,154
Residenliar 689 319 78,007
Retail 789 657 620 30,066
GENERAL
General (Implementation)624.456 624.456
Genero!I (M&E)87,813 813
OTHER EXPENDmJRES
flEEA3 $232 442,005 445,237
Leases 867 44,798 50,665
OLD PROGRAMS
LED Traffic Signals 112 105 31,217
New Technologies 698 28,548 30,246
Prescriptive HV AC
Presaiptive Ughting 319 157 360 836
RfvFP 475 475
Site Specific 25,186 020 110 28,316
SS-VFD . $344 344
Trade Ally 719 293 110 182
TOTAL 086,523 407 504 98,585 592 611
BROKEN OUT BY CATEGORY
Total assigned to segments 421,857 853,761 10,192 285,809
Total assigned to general 624,456 813 712,269
Total assigned to other 099 486.803 495,902
Total assigned to old programs 31.111 66,940 580 98,631
TOTAL 086,523 407,504 98,585 592,611
CATEGORY AS A PERCENT
Total assigned to segment 16,32.0.4%49.
Total assigned to general 24.27.
Total assigned to other 18.19.
Total assigned to old programs 1.2%
TOTAL 41.98/.54.38/.8"10 100.08/.
NOTES:
1) Incentives are accounted for on an accrual basis, and are therefore de-rated (in the same way as kWh, therms, etc.)
2) Costs for this trimester's portion (1/3) of the Natural Gas Awareness Campaign are included in Residential.
3) Costs associated with membership in NEEA are included in this table, but are excluded from all other tables.
4) Costs associated with outstanding leases are included in this table, but ore excluded from all other tables.
Page 6
Exh. 6 / Schedule 2
R. Lafferty
A vista Corporation
Page 42 of 84
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9
Avista Utilities Triple-E Report March 2000
Treatment of De-Rated Project Results
As previously mentioned, projects in the Contracted and Construction phases are credited with 75% and
95% of the engineering estimates. This applies to kWh savings, therm savings, direct incentives , non-energy benefits, and customer costs.
Energy Savings
During this trimester Avista participated in over 12.3 million kWh of energy savings, which resulted in an
increase of approximately 137 000 therms of natural gas usage. This represents the progress of projects
within the .pipeline" of the five sequential phases during the trimester.
As always, the net therm savings incorporate the additional therm usage of electric to natural gas
conversions. The largest therm contributors this trimester were the Natural Gas Awareness Campaign
and the conversion component of the Limited Income program.
Avista Corporation s participation in the Northwest Energy Efficiency Alliance is within this report for
purposes of calculating utility costs, but has been excluded for cost-effectiveness purposes. This is due
to the lack of definable energy savings at this point in time. During this trimester, NEEA accounted for
17.2% of our utility costs.
These calculations of energy savings do not include any estimates of free-riders, free-drivers , or anymarket transformation effects. At this point it is unclear how these effects will influence the total energy
savings of the portfolio. We will be investigating this question in the near future in compliance with our
Idaho general ratecase order.
Refer to Tables and 6 for the allocations of electric and therm savings (increases) across customer
segments and technologies.
Page 10
Exh. 6 / Schedule 2
R. Lafferty
A vista Corporation
Page 46 of 84
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1
Avista Utilities Triple-E Report March 2000
Customer Costs and Non-Energy Benefits
A summary of customer costs incurred to achieve the energy savings portion of the projects captured in
this report has been included. The raw customer costs have been modified to exclude non-electric
components of customer projects, arid to appropriately match the measure life of base-case and high-
efficiency altematives. Customer cost figures listed are also not adjusted for direct incentives granted by
Avista Corporation.
These customer costs substantially affect the total resource cost test and the participant test. Customer
costs amount to approximately two-thirds of the total resource and participant costs.
The non-energy benefit data reflects the quantifiable non-energy benefits accruing to the energy
efficiency projects. To date these quantifiable non-energy benefits are limited to maintenance savings
inherent in lED exit sign, lED traffic signal VendingM/$ER, and non-residential lighting projects.
We are continuing our research to quantify other non-energy benefits such as productivity, safety, retail
sales and so forth. To date we have not found a sufficient body of research that would reasonably
substantiate the numerical claims that have been made in these areas. These as yet non-quantifiable
non-energy benefits are clearly major influences on the adoption of energy efficiency measures and on
the cost-effectiveness of our portfolio, and they are actively used in marketing these measures to our
customers.
We are reviewing the database projects in greater depth to obtain information about increased production
and other relatively easily quantifiable values. We will also be working to better identify what non-energy
benefits accrue to what measures, even if those benefits are non-quantifiable.
Refer to Tab/es and B for the allocations of customer costs and non-energy benefits across customer
segments and technologies.
Page 12
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 48 of 84
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Avista Utilities Triple-E Report March 2000
Cost-Effectiveness and Descriptive Statistics
The following tables contain cost-effectiveness statistics for this trimester for all four standard
practice tests. Also included are net benefits for each test by customer segment and technology.
Net benefits have been included to give additional insight into the significance of each segment
and technology.
The Total Resource Cost (TRC) ratio is essentially unchanged from the previous trimester" (1.
to 1.11). It is too early to ascertain if we were correct in our expectation that TRC cost-
effectiveness would increase as the one-time costs incurred in the August 1 to November 30
1999 trimester were completed. As of yet, we do not have enough history of calculating cost-
effectiveness on a trimesterly basis to determine if the normal variation could conceal a
meaningful increase in cost-effectiveness.
The Utility Cost Test (UCT) ratio has fallen significantly from the previous trimester (2.11 to 1.11).
As mentioned previously, we are uncertain as to the normal variation that we should expect when
cost-effectiveness is calculated on a trimesterly basis, but it seems unlikely that a change of this
magnitude is within normal variation. It is more likely that it is the result of the imposition of the
new Schedule 90 Tariff and the higher incentives contained therein. Supporting this hypothesis is
the fact that the proportion of .old programs. (those projects being completed under the old tariff)
has fallen significantly from the previous trimester.
It is possible that the decline in the UCT ratio will continue into the next trimester, as the last of
the .old programs. reach completion and the project pipeline is composed completely of the
higher incentive projects being completed under the new tariff. If this is the case, a management
review of the portfolio would be warranted to address the issue of identifying what the minimum
acceptable UCT ratio is and how the portfolio can be managed to achieve it.
The participant test ratio has moved from 2.98 to 4.46 in the last trimester. This increase lends a
certain amount of corroboration to the theory that the UCT ratio is falling as a result of increased
utility direct incentives. It may also imply that the freEHidership ratio has improved as a result of
offering enhanced in~entives (the larger the incentive and the higher the participant ratio the more
likely it is that the program made the difference in adoption of the measure). The tiering of the
incentives based upon simple payback may further enhance that effect.
These interpretations will be incorporated into the free-ridership analysis that the Company was
requested to perform under the recently completed Idaho ratecase order. This may impact the
timing of the study. Having established the hypothesis that the new programs appear to be
impacting the free-ridership ratio. it would be necessary to segment .old. programs from .new
programs to develop an accurate view of free-ridership.
The non-participant test ratio (also called the rate impact measure) experienced a slight decline
from 0.44 to 0.33. As had been previously indicated, Avista is mathematically guaranteed to fail
this test (have a ratio below 1.0) as long as our rates are above our avoided costs. The Avista
response has been to offer a broad enough program portfolio to provide every customer the
opportunity to directly or indirectly benefit from our portfolio. The meaning of a non-participant
test is diminished as these program benefits become more widely distributed.
Comparison to the previous trimester indicates a slight increase in the customer cost per kWh (18
cents/kWh to 20 cents/kWh). A change of this magnitude is likely to be within the normal
variation of a trimesterly report.
The utility implementation cost also increased from 7 cents/kWh to 10 cents/kWh. This is
attributable to the reduction in energy savings from 14.2 million kWh to 12.3 million kWh. The
utility implementation costs actually fell from the previous trimester.
Page 14 Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 50 of 84
Avista Utilities Triple-E Report March 2000
We have added a measure of incentive cost per kWh to assist in diagnosing the UCT ratio issue.
as previously discussed. The increase in incentive cost per kWh from five cents to seven cents
reflects the most recent change to the Schedule 90 Tariff.
Refer to Tables and 10 for summaries of cost-effectiveness for all four standard practice tests
by customer segments and technologies.
Refer to Tables 11 and 12 for summaries of net benefits for all four standard practice tests by
customer segments and technologies.
Refer to Table 13 for further details on the calculation of the cost-effectiveness rations. as well as
some useful descriptive statistics.
Page 15
Exh. 6 Schedule 2
R. Lafferty
Avista Corporation
Page 51 of 84
Avista Utilities Triple-E Report March 2000
Table 9 Cost-Effectiveness Statistics b Customer Se ment
Total Non-
Resource Utility Cost Partidpant Partidpant
Cost Tes!Test Test Test
Agriculture NlA
Education
Food Service
Health Care 10.
Hospitality 16.0.22
Limited Inccme NlA 0.29
Manufacturing
Office 0.49
Residential
Retail 1.46 127.
PORTFOUO
Table 10 Cost-Effectiveness Statistics b Technolo
Total Non-
Resource Utility Cost Partidpant Partidpant
Cost Test Test Test Test
Appliances
Assistive Technologies NlA
Compressed Air 33'
Controls
HVAC 1.20
Industrial Precess (8.01)
Ughting
Monitoring NlA
Motors NlA
New Tech
Renewables NlA NlA NlA NlA
Resource Management 1.29 NlA
SheD (0.31)(1.11)(0.77)(0.12)
Sustainable Building NlA
PORTFOUO
NOTES:
Costs for this trimester's portion (113) of the Natural Gas Awareness Campaign are induded in Residential.
Costs assodated with membership in NEEA are exduded from all cost-effectiveness calQJlations.
Costs assodated with outstanding leases are exduded from all cost-effectiveness calQJlations.
N/A' is listed for segments and technologies with benefits, but no costs.
Page 16 Exh. 6 / Schedule 2
R. Lafferty
Avista Corporation
Page 52 of 84
A vista Utilities Triple-E Report March 2000
Table 11 Net Benefits b Customer Se ment
Total Non-
Resource Utility Cost Partidpant Partidpant
Cost Test Test Test Test
Agriculture (30.784) $(30,784)(30.784)
Education 958 778 347 818 417 921 (1,448,409)
Food Service (32,371) $(20.798) $98.941 (130.319)
Health Care 97.913 (67 544) $236,051 (138 138)
Hospitality 879 (92 295) $219,638 (210.100)
Urriled Income (46,251) $(46.251) $276,036 (1,445,800)
Manufacturing (634,407) $(99,250) $(52.563) $(581,963)
Office 81.059 (67 195) $320,826 (274,598)
Residential (40,061) $340,559 827.902 (1,103,064)
Retail 38,408 (40,457) $177 215 (140,418)
PORTFOUO 402 162 223 803 521,968 503 595)
Table 12 Net Benefits by Technology
Total Non-
Resource Utility Cost Partidpant Partidpant
Cost Test Test :w!Test
Appliances (39.944) $105.571 444 788 (583.667)
Assistive Technologies (104.694)(104 694)(104 694)
Compressed Air (k5,586)(7,881) $25,756 (42,341)
Controls (39,177) $781 333,908 (365,394)
HVAC (146,462) $113,941 689,879 (2,093.761)
Industrial Process (29,492)(30,249) $817 (36.309)
Lighting 612.692 236 186 941 179 (1,342,545)
Monitoring (24.023)(24,023)(24 023)
Motors (59 413)(59,413)(59,413)
NewTech 394 861 45,380 969,313 (574,515)
Renewables
Resource Management 28,527 28,527 270.812 (229,678)
Shell (165,112)(74,309)(160,482)(38,240)
Sustainable Building (9,015)(9,015)(9,015)
PORTFOUO 402, 162 223 803 521,968 503,595)
NOTES:
Net benefits are calculated by subtracting costs from benefits.
Costs and benefits induded in each cost-effectiveness test are detailed in Table 13.
Costs for this trimester's portion (113) of the Natural Gas Awareness Campaign are induded in Residential.
Costs associated with membership in NEEA are exduded from all cost-effectiveness calculations.
Costs assodated with outstanding leases are excluded from all cost-effectiveness calculations.
Page 17 Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 53 of 84
Avista Utilities Triple-E Report March 2000
Table 13 Summary of Cost-Effectiveness Tests and Descriptive Statistics
Regular Income Umited Income Overall Regular Income Umited Income Q:!m!LTotal Resource Cast Test I1.2!1!!ili2 Utility Cast Test aortlolio Dortlolio DortlolioElectric avoided cost 066,877 599,880 666,757 Electric avoided cost 066.877 599,880 666,757Non-Energy benefits 775,461 775,461 Natural Gas avoided cost (209 832)(136,413)(346 244)
Natural Gas avoided cost (209.832)(136 413)(346.244)UCT benefits 857 045 463,467 320 512
TRC benefits 632,506 463,467 095,973
Non-incentive utility cost 080,782 95,227 176,009Non.incentive utility cost 080.782 95.227 176.009 Incentive cost 506.209 414 492 920,701
Customer cost 103.311 414 492 517 802 UCT costs 586.991 509,718 096,709
TRC costs 184,093 509,718 693,811
UCT ratio
TRC ratio Net UCT benefits 270 054 (46 251)223 803Net TRC benefits 441,413 (46,251)402,162
Regular Income Umited Income Overall Regular Income limited IncomePartlcioant Test aortfolio aortlolio Dortfolio Non.Partlcioant Test aortlo/io Dortlolio Dortlolio
Bm Reduction 067 573 276 036 343,609 Electric avoided cost savin9s 066,877 599.880 666 757
Non-Ener9Y benefits 775,461 775 461 Nan-Part benefits 066,877 599,880 666,757
Participant benefits 843,033 1,276,036 119.070
Revenue loss 537,681 535.961 073,642Customer project cost 103,311 414 492 517,802 Non-incentive utility cost 080.782 95,227 176 009Incenlive received 506,209 414 492 920,701 Customer incentives 506,209 414 492 920 701
Participant CO&ts 597,101 597,101 Non-Part costs 124 672 045 679 170 351
Participant Test ratio N/A Nan-Part. ratio
Net Participant benefits 245,932 1,276,036 521,968 Net Non.Part. benefits 057,795)445 800)(5,503 595)
Descrlotlve Statistics
Annual kWh savings
Customer CO&IIkWh S
Non-incentive utility cosllkWh $
E/ectric avoided castllcWh $
Incentive costllcWh $
Regutar Incame
Dortfolio
10,363.237
20 S
10 $
20 S
05 .
limited Income
aortlolio
957.034
21 S
05 $
31 S
0.21 S
Overall
DOrtlaiio
12,320.271
0.20
0.22
NOTES:
Costs lor this trimeste"s portion (113) 01 the Natural Gas Awareness Campaign are included in Resmential.
Costs associated with membership in NEEA are excluded from aU cost-effectiveness calculations.
Costs associated with outstanding leases are excluded from all cost-effectiveness calculations.
N/A" is listed lor segments and technologies with benefits. but no costs.
Page
Exh. 6/ Schedule 2
R, Lafferty
A vista Corporation
Page 54 of 84
Avista Utilities Triple-E Report March 2000
Energy Efficiency Tariff Rider Balance Calculations
The methodology of this calculation has not changed since the previous Triple-E Report. Oneerror, the omission of the effect of the one-month lag specified in the 1994 Accounting Guidelines
amounting to $10 949, has been corrected.
In the last twelve months Avista has:
spent $2.2 million more than it has collected as Tariff Rider revenues ($1.4 million in
Washington, $0.8 million in Idaho)
incurred expenditures in excess of rider revenues by 47% (41% in Washington, 64% inIdaho)
reduced the Tariff Rider balance by $1.9 million ($1.2 million in Washington, $0.7 million in
Idaho)
cut the balance by 45% (41% in Washington, 53% in Idaho) and
incorporated within the balance $318 000 of interest assessments ($215 000 Washington$103,000 Idaho).
This progress towards Avista Corporation s objective of reducing the balance through funding
cost-effective energy efficiency may somewhat overstate the progress to date due to a
disproportionate amount of NEEA invoices paid during this moving average; However, eventaking this into consideration, it does represent a significant increase in energy efficiency activity
on the part of the Company.
The TRC cost-effectiveness during this trimester indicates that it is not only an increase in
expenditures, but that the incremental expenditures do have energy savings commensurate with
their costs.
Refer to Table 14 for the most recent update to our tariff rider balance calculation.
Page 19 Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 55 of 84
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Avista Utilities Triple-E Report March 2000
Analysis Measurement and Evaluation Summary
For this reporting period, seven projects and programs were selected for in-depth review. Thefollowing summaries highlight the findings of each review.
For confidentiality reasons, customer names have been omitted except in the case of
governmental organizations. More detailed reports are available upon request.
The analysis team continually endeavors to present to the Triple-E Board an accurate portrayal of
Avista Utilities' energy efficiency activities. Comments and suggestions regarding both the
content and format of this report are always welcome.
Program Updates
Resource Management Partnership Program (RMPP)
The billing analysis of all school districts participating in RMPP were reviewed and revised to
meet the most recent policy decisions on these calculations.
It was notable that no non-energy benefits have been identified during the trimester. Follow-up
indicated that this was an accurate reflection of the programs current activity. Most of the
participating school districts have already realized the majority of the cost-effective non-energy
resource savings.
One meter located at Mead High School is currently under investigation. The usage on the meter
has dramatically increased to a level far beyond that which is reasonable for the tennis court
application that it was intended for. We are almost certain that the nearby construction of a major
addition to the school is the cause of the aberration. If we can positively identify construction as
the source of the usage we will revise the billed savings calculation upward by that amo~nt.
VendingMI$ERTM Program
In the November 1999 Triple-E Report, it was reported that Avista was embarking on an
aggressive project to install VendingM/$ER control units on hundreds of cold drink vending
machines within the service territory. As of March 31 , 2000, over 300 individual VendingM/$ERunits were installed, or in the process of being installed, on vending machines throughout Avista
Utilities' service territory.
The VendingM/$ER control unit is manufactured by Bayview Technology Group, Inc. It is
designed to operate as an intelligent power controller for cold product vending machines. It is not
recommended for use with vending machines containing perishable products. The
VendingM/$ER uses a passive infrared sensor to shut down the controlled vending machine
when the area surrounding the machine has been vacant for 15 minutes. The VendingM/$ER will
periodically re-power the vending machine to ensure the product stays cold.
Preliminary monitoring conducted by Avista has shown an estimated annual energy savings of
500 kWh per unit. These results closely match studies performed by Bayview and other
analysis, including a study performed by Rutgers University. These preliminary studies form the
basis for the annual savings claim of 1 500 kWh per VendingM/$ERinstallation. Avista has
adopted this figure for a prescriptive program, with the understanding that further data collection
would occur and savings claims would be adjusted accordingly.
Page 21
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
Page 57 of 84
Avista Utilities Triple-E Report March 2000
The VendingM/$ER is appropriately considered a new technology since a microprocessor based
control of vending machines is new and such a technology was non-existent in the Avista service
territory prior to the launch of this program. Under the existing tariff, any new technology project
producing 1 500 kWh in annual savings would be eligible for an incentive of $150.00 to
$210.depending on the project simple payback. For this program Avista has chosen to
purchase VendingM/$ER units on behalf of customers, in lieu of direct financial incentives. The
cost per VendingM/$ERunit is $135.
Avista Utilities is currently in the midst of axtensive monitoring of the VendingM/$ERcontrol unit.
Data acquisition began in December of 1999. Monitoring is currently being performed on dozens
of cold drink vending machines at customer locations throughout the service territory.
Oatalogging of vending machines without control units installed, as well as those under
VendingM/$E:Rcontrol. are underway. Data acquisition will continue until a large enough
population has been observed to provide us with adequate data for calculation of average annual
kWh savings. Oatalogging results will be used to adjust annual energy savings claimed by Energy
Services if necessary.
The results of datalogging efforts for the VendingM/$E:R program thus far have indicated that the
savings may average closer to 800 kWh per installation. However, given the substantial variance
of savings across projects we have decided to delay any adjustment until we can expand the
sample size. We will revisit this topic in the next Triple-E Report, with the benefits of a larger
sample size.
The analysis team intends to capture data on individual electricity consumption for as long as a
year, both pre and post installation. We are also striving to capture energy consumption on a
variety of vending machine makes and models, dispensing cold products of various sizes and in a
variety of locations.
Individual Project Reviews
Project Status:
Program/Segment:
Technology:
Site:
Location:
Completed August of 1999
Trade Ally and New Technology Programs
Canopy Lighting and LED Strip Lighting
Service Station and Convenience Store
Colville, Washington
Study Summarv
This study resulted in no impact on energy savings estimates.
This project was randomly selected from a list of projects completed between January 1,
1999 and February 15, 2000.
The project involved the lighting retrofits incorporated in the replacement of canopies over
gas pump islands. High wattage metal halide lights were replaced with lower wattage metal
halide light fixtures with some de-ramping. High wattage fluorescent lights were replaced with
new technology light emitting diode (LED) strips.
After some investigation, the LED strip lighting was found to be appropriately incentivized as
a New Technology measure. It has been recommended that Energy Services attached
Page 22
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 58 of 84
Avista Utilities Triple-E Report March 2000
documentation to New Technology projects to explain the rationale used to determine New
Technology status.
A process error was uncovered as the LED canopy strip lighting was mistakenly entered into
the project tracking database as "LED Exit Signs.
Study Detail
This project was initiated after an energy audit .ofthe customer s facility. The energy audit was
completed in September of 1998. The customer was in the process of replacing canopies over
three gasoline and diesel pump islands and chose to install lower wattage metal halide fixtures.
The manufacturer of the new fixtures claims several design improvements allow the use of a
lower wattage lamps. The new fixture positions the metal halide lamp vertically rather than
horizontally, and uses an improved reflector and prismatic lens to direct light out of the fixture in a
uniform manner.
Lighting improvements were incentivized under the Trade Ally program in effect at the time.
the project neared completion, the Energy Se/Vices project lead separated the Light Emitting
Diode strip lighting savings from the remainder of the project. This allowed the LED portion of the
project to be incentivized as a New Technology.
After a review of the project file and discussion with the Energy Se/Vices project technical lead, it
was determined that New Technologies incentives were appropriately applied toward the LED
strip lighting as this was a relatively new product and this was the first application with Avista
involvement. Initially the project file lacked documentation, which would explain the rationale
behind assigning New Technology status to the LED strip lighting. This deficiency was brought to
the attention of Energy Se/Vices and additional notes were added to the project file. Analysis
staff recommended Energy Se/Vices incorporate such documentation with all New Technology
projects. As a result, a policy change has been incorporated.
A review of the accounting transactions revealed an error in data entry. The LED canopy strip
lighting was mistakenly entered into the Energy Se/Vices database as an LED exit sign project.
The error caused incentive payments to be charged to the LED exit sign program account.
Annual kWh savings were also erroneously credited to the LED exit sign program. Energy
Se/Vices was informed of the error and appropriate account corrections were made.
A post-verification of the installation was performed by Energy Se/Vices and photographs of the
equipment were included in the project file- The analysis team also performed an independent
verification of this project. The engineering calculations were reviewed and found to be accurate.
Energy savings for this project totaled 12.800 kWh per year for the metal halide canopy lighting
improvements and 8 340 kWh per year for the LED strip lighting. The customer received an
incentive of $1 084.00.
Project Status:
P rogram/Segment:
Technology:
Site:
Location
Completed January of 1999
Site Specific Program
Irrigation Pumping Efficiency Improvements
Farm
Kahlotus, Washington
Studv Summarv
This study resulted in no impact on energy savings estimates.
Page 23 Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 59 of 84
Avista Utilities Triple-E Report March 2000
This project was randomly selected from a list of projects completed between January 1
1999 and February 15, 2000.
The project involved the installation of a variable frequency drive on a irrigation pump motor
and a retrofit from standard impact sprinkler heads to low pressure pivot rotator sprinkler
heads. The project was completed under a performance-based agreement.
Data was collected for over a year from water flow meters and Avista Utilities electric meters
on irrigation pumps serving seven pivot irrigation systems. The results of the data collection
analyses were used to establish energy and water savings, and the incentive amount.
Several non-energy benefits were documented by the owners of the farm; including improved
cold weather irrigation to provide a measure of frost protection, a large reduction in water
usage, and reduced equipment failure caused by high water pressure stress.
Study Detail
In the summer of 1997 , a study was begun at a family owned farm near Kahlotus, Washington.
The farmers of this land were seeking assistance to reduce both electric power consumption and
water usage.
The customer and the Energy Services technica/lead chose to replace standard impact sprinkler
heads with a low-pressure pivot rotator sprinkler heads. To allow proper operation and control of
the new sprinklers, water pressure control was required. The pressure control was obtained by
installing a variable frequency drive on a 100 horsepower pump serving the seven irrigated crop
circles.
The sprinkler heads provided several benefits: including reduced water run off, greater uniformity
in water application, reduced wind drift, and reduced water loss caused by evaporation. The new
sprinkler heads also allowed the farmer to vary the water droplet size, allowing improved
precision in water' application.
The operators of the farm closely monitored water usage over several years. Electric usage
history was available from Avista Utilities customer records. With this information, a performance-
based energy efficiency agreement was executed. Avista and the farm operators collected water
flow data and electric usage data for over one year following the installation of the low-pressure
pivot rotator sprinkler heads and the variable frequency drive. The data collection was completed
in December of 1998.
Several non-energy benefits were documented. Water savings totaled 554 acre-feet per year
(180,521,454 gallons). Superior water distribution capabilities allowed the farm to provide a
measure of frost protection. The customer anticipates significant maintenance cost savings from
reduced equipment failure caused by high water pressure. The customer also expressed
satisfaction with the improved water distribution on his crops, noting that "The crop under the
rotator equipped center pivots was always in at least as good, or in better condition, than the
crops grown under impact sprinkler equipped machines.
A review of the incentive formula in the energy efficiency agreement found that the incentive
calculation was appropriately applied. A review of the accounting transactions found costs and
incentives were appropriately charged to the Site Specific program.
The savings for this project totaled 51,326 kWh per year. The CL:stomer received an incentive of
$2,566.00.
Page 24 Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 60 of 84
A vista Utilities Triple-E Report March 2000
Project Status:
Program/Segment:
Technology:
Site:
Location:
Completed May of 1999
Trade Ally and Site Specific Programs
Cooling and Ventilation Improvements
Mine
Wallace, Idaho
Studv Summary
This study resulted in no impact on energy savings estimates.
This project was randomly selected from a list of projects completed between January 1
1999 and February 15, 2000.
The project was completed using both the Trade Ally program and the Site Specific program.
The Trade Ally portion allowed for expenditures to study and implement the replacement of
Whizbang units with portable fans. The Site Specific program provided incentives for the
conversion of an adjacent mineshaft into an exhaust shaft.
The large scale and unique nature of these projects warrant an ongoing persistence study.
The large annual energy savings could be reduced should the mine scale back its operations
in the future.
Studv Detail
Heat and humidity levels in the mineshafts are very high. The miners in the shafts developed a
device called a Whizbang to provide cooling. A Whizbang is essentially a pipe, drilled with
approximately a dozen 1/8" holes. The pipe is connected to a compressed air system and is
turned on and off by the miners as needed. The study performed by Energy Services in
coordination with the customer s own engineering staff indicated the mines had fifty Whizbangs
operating up to 5,408 hours per year. While these devices worked well and were compatible with
the extreme conditions found in the mines, they were created without regard to energy efficiency.
Energy Services proposed replacing the Whizbang units with individual portable 2 horsepower
cooling fans. The customer replaced the Whizbangs on a limited basis, removing eighteen units
and replacing them with two horsepower cooling fans.
The engineering estimates for the Whizbang replacements were reviewed and found to be
appropriate. However, the customer is under no obligation to continue the use of the individual
fans, nor does there appear to be a tracking mechanism in place to ensure that the air
compressor loads are reduced. Analysis staff recommended Energy Services coordinate a
follow-up study within the next six months to measure the persistence of this measure.
The ventilation project required that the mine open a connection to an adjacent shaft and use it
for exhaust ventilation. By making the connection to the adjacent shaft. ventilation to the mine
was increased and fan horsepower requirements were reduced.
klformation included in the project file indicates a significant engineering effort was made to
ensure this operational change 'Nould greatly improve the ventilation in the mine and reduce the
required horsepower. Engineering calculations are detailed in an initial project memo from the
Avista project engineer, however the project changed over time and subsequent calculations
were absent in the project file. Final savings figures were presented only in a summary
spreadsheet and to recreate the final energy savings figures was difficult.
Analysis staff recommended Energy Services review project files upon project completion and
establish a procedure to ensure final energy savings calculations are clearty documented and
reflect all changes between initial study and project completion.
Page 25
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 61 of 84
Avista Utilities Triple-E Report March 2000
As with the Whizbang project, any change in the mine s operation could dramatically alter the
energy savings provided by the ventilation project. A follow-up study of both of these projects, by
the analysis team in coordination with Energy Services, is to be initiated within the next six
months.
The savings for the Whizbang cooling replacement project totaled 2,091 300 kWh per year andsavings for the ventilation efficiency improvements totaled 1 942,100 kWh per year. The customer
received an incentive (capped at 50% of the project cost) of $62 500.00.
Project Status:
Program/Segment:
Technology:
Site:
Location
Contracted as of March 31 2000
Site Specific Program / Manufacturing Segment
Process Fuel Conversion
Specialty Metals Manufacturer
Spokane, Washington
Studv SummarY
This study resulted in no impact on energy savings estimates.
This project was randomly selected from a list of projects which were in progress as of March
2000.
This project was listed as Contracted as of March 31 , 2000 and involves a process fuel
switch. An electric oven is to be replaced with a natural gas oven.
The project file contained a detailed engineering calculation to estimate potential electricitysavings.
A significant non-energy benefit was identified e.arly in the study. The customer is nearing the
maximum capacity of existing transformers. The process fuel switch will allow the customer to
defer the installation of a new transformer and additional electrical circuit breakers and will
free up approximately 40 kW of capacity to be used for future production expansion.
. The process requires precise temperature control and requires specialized ovens.
Study Detail
The manufacturing process, which is the subject of this project, involves the bonding of dissimilar
metals. In this case, steel is bonded to aluminum using a molecular bonding material. The bond
occurs as the steel and aluminum are heated in an oven with precise temperature control. The
customer's process allows bonding to occur without reduction or oxidation, which often occur
when dissimilar metals are in close proximity.
For this energy efficiency project, the customer will be replacing an existing radiant electric oven
with a new radiant natural gas oven. The customer also needed to increase processing capacity
and was considering several options including the installation of additional electric or gas fired
ovens. The new gas oven chosen by the customer will provide this increase in the production
capacity.
Energy Services personnel documented the operation of the existing electric oven and detailed
the operation of up to two additional electric ovens under considercltion to meet the increased
process capacity. Using production information provided by the customer, it was calculated that
the heeding elements in the original oven consumed 166,400 kWh per year. Adding two similar
Page 26
Exh. 6/ Schedule 2
R. Lafferty
A vista Corporation
Page 62 of 84
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A vista Utilities Triple-E Report
Table 87 Cost-Effectiveness Statistics by Customer Segment
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
NEEA
Agriculture
Manufacturing 1.05 0.40
Health Care
Hospitality
Office 2.27 10.
Food Service
Retail
Residential 78.
limited Income (electric)0.42
RMPP Education 16.
PORTFOLIO 0.43
PORTFOLIO wID NEEA 2.98
REFERENCE: Comparable to Table 9 of March 2000 Report.
Table 88 Cost-Effectiveness Statistics by Technology
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Appliance
Assislive Tech
Controls 0.43
Motors
HVAC 0.47
Industrial
Ughting
Maintenance
Monitoring
New Tech
Regional
Renewable
Resource Mgmt 10.10.0.47
Shell
Sustainable Building
PORTFOLIO 2.98 0.43
PORTFOLIO wID NEEA 2.11 2.98
REFERENCE: Comparable to Table 10 of March 2000 Report
Page
Exh. 6/ Schedule 2
R. Lafferty
Avista Corporation
March 2000
Page 67 of 84
Avista Utilities
Table 89
Triple-E Report March
Summary of Cost-Effectiveness Tests and Descriptive Statistics
Total Resource Cost Test
Electric avoided cost S
Non-Energy benefits S
NaNral Gas avoided cast S
TRC benefits S
Implemenlalion cost S
Customer cost S
TRC casts S
TRC I3tio
Utility Cost Test
Electric avoided cast S
NalUl3l Gas avoided cost S
UCT benefils S
Regular Income
portfolio wilhout
303.697 S
76.850 S
(859.424) S
521.122 S
Urniled Incerne
457.790
Overall portfolio
without NEEA
S 4 761 487S 76 850
(63,443) S (922.867)
394.347 S 3.915,469
905.457 29.569 935.026
2.273.339 291.377 564 716
178,795 320.946 499.742
Regular InallTle
portfolio wilhoul
303,697 $
(859.424) $
444.273 $
Umited Income
2S!!!!!1!!2
457.790
(63.443)
394,347
Overan portIoio
witllout NEEA
S 4 761,487S (922.867)S 3.838.620
Regular Income
portfolio without
NEEA
471,020 $
76.850 S
547 869 $
273.339 S
(595 293) $
678,046 S
71 NA
Regular Income
portfolio wilhoul
444 273 $
444.273 $
Regutar' Income
portfoflO wilhout
13,049.400
174 $
069 $
330 $
046 $
REFERENCE: Comparable 10 Table 13 of March 2000 Report.
Implementation cast $905.457 29.569 935,026
Incentive cast S 595.293 291 377 886.670
UCT costs S 500.749 320.946 821,696
UCT 13~0 2.30 2.11
PartleiDant Test
Bil Recluclion S
Non-Energy benefits S
Participant bellefits $
Customer project cast S
Incentive received $
Participant casts $
Participant Test I3Iio
Non-PartleIDan! Test
Avoided cost savings $
Non-Part benefits S
Urniled Income
456,505
Overan portfolio
without NEEA
S 4 927,525S 76.850
S 5.004,374456.505
291,377 $
(291.377) S
564,716
(886.670)
678,046
Limited Inccme OYeraU portIoio
.I!!i!:!!2!!2 without NEEA
394.347 S 3.838,620
394,347 S 3.838,620
R8\'8Rue IDs.s S 6.274,491 819.887 894.378
Implementation S 905.457 29,569 935,026
Customer Incentives S 595.293 291 377 886.670
Non-Pat! costs $775.240 940,833 716,073
Non-Part. 13~0
DeserfDtive Statistics
Annual kWh:!
Cust costlkWh $
Impl costIkWh S
EI AC $/kWh $
Inc costlkWh $
Page 41
OveraU portIDio
wiIhouI NEEA
14.201 764
181
066
335
062
Urnited Income
152.364
D.253 $
026 S
397 S
0.253 $
Exh. 6 / Schedule 2
R. Lafferty
Avista Corporation
2.98
Page 68 of 84
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MODEL CONTRACTS
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c: h~ c!.~ J )
Exh. 6 / Schedule 2
R. Lafferty
Avista Corporation
Page 84 of 84