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200 1 Electric Integrated
Resource Plan
COYOTE SPRINGS II SITE
A VISTA's 2001 Electric Integrated Resource Plan
TABLE OF CONTENTS
Page
PLAN SUMMARY
Appendix A 1997 Action Plan...........................................
Resource Update
Appendix B Load Forecast...
........ "" '" """ .,. ... """" ...... ....
Appendix C Resource Planning....
........ """'" '" ... ........... ....
Prosym/Risk Management/Reserves
Electric and Natural Gas ~rice Forecasts
Appendix D Resource Alternatives...
............ ".....,. .......... ....
Distributed Generation
Appendix E RFP Process-2000...........................................
Appendix F 2001 Action Plan............................................
Preferred Resource Strategy
Appendix G Resource and Contract Information......
""""" .....
Existing Resources
Resource Need
Generation Performance Data
Appendix H Other Items.................................................
Distribution Planning
Transmission Planning
Public Involvement
Hydro Relicensing
A voided Cost
Appendix I Glossary of Terms, Abbreviations & Acronyms..... ..
Appendix J Avista s Energy Efficiency Resources..................
Triple-E Report
Appendix K Updated Loads and Resources... ... ...
....... ... "" ...
PLAN SUMMARY
Introduction
July 12
2000
A vista
filed an
updated
1997
IRP
A vista Corp.' s last Integrated Resource Plan (IRP) was filed with theCommission on August 25, 1997. Since then many things have changed
in the electric utility industry and for A vista Utilities, the regulateddivision of Avista Corp.
On July 12 2000 Avista prepared an update to its 1997 IRP to include
those significant changes. This updated IRP also served as the
basis for aRequest-For-Proposals (RFP), which was issued on August 14, 2000.
Since then, there have been other updates including the final results of
the RFP process. These updates show significant peak and energy
deficits for the company starting in the year 2004, without additionalresources.
Resource Update
. -
1. On February 12, 1999 A vista sold Meyers Falls, a small hydroelectric project to
Hydro Technology Systems.
2. In 1999, the company completed the program to replace all four runners at Long Lake
hydro facility, which increased the capability from 72.8 MW to 88 MW.
3. On February 23 , 2000 the Federal Energy Regulatory Commission issued to Avista a
new 45-year operating license for the two hydroelectric projects on the Clark Fork
Ri ver.
4. On May 5, 2000 the sale of Centralia, a coal-fired generating facility, to TransAltawas completed. A vista owned 15% of the generating plant. Generation was replacedwith a purchase through 2003.
5. Cabinet Gorge upgrades are in progress for a total increase of 52 MW with 9aMW ofenergy.
6. A vista has selected the 280 MW Coyote Springs II project and three DSM resources
for a total of 13aMW to meet a large portion of its resource needs.
For further information, please see Appendix A.
Electric Sales Forecast
The forecast of firm sales to the core-market is one of the most critical forecast elements.
Customers in the core-market segment include residential, commercial and industrial.
The requirements of the core-market segments place demand on the delivery system
(both distribution and transmission) for which generation capacity is acquired, either byownership or purchase contracts.
A vista utilizes econometric models to produce sales and customer forecasts. Peak load
and energy forecasts are derived from the sales forecasts. The total sales forecast in kWhreflects a compound growth rate of 1.9%. The forecasted peak load for the year 2000 is
1557 MW and for the year 2009 is 1851 MW. The energy forecast for the year 2000 is
1008 aMW and for the year 2009 is 1159 aMW.
For further information, please refer to Appendix B.
Resource Planning
A vista is projecting a modest but increasing load growth of 1.9 percent over the next tenyears. These load increases over the planning period result in the need for additional
resources. In addition the company s power purchase of 200 MW, which replacedCentralia generation, expires at the end of 2003. Also the company has recentlyexperienced dramatic increases in market price and volatility, which has caused the
company to move away from reliance on the short-term market for a portion of its baseresources. These changes have caused the company to implement a resource acquisitionstrategy to serve its needs.
August
2000
Avista
issued
an RFP
Based on Avista s current load projections and resource requirements,
the company is facing significant energy and peak deficits. By the year
2009 the peak deficit is 402 MW and the energy deficit is 301 aMW.
New resource(s) will have an impact on the resource dispatch sequence
because of the fuel supply, marginal costs, and other operating
characteristics. A vista is using PROSYM to model its resources to meetits system requirements on an hourly basis, and to assess the dispatch
requirements and compatibility of new resource need in conjunction with
existing resources, both hydro and thermal.
A vista issued an RFP in August 2000 to identify low cost and environmentally sound
resource options that would best satisfy the company s resource needs. The biddingprocess supports the companies on going assessment of the cost and availability of new
resources and provides input to this IRP.
For additional information, please see Appendix C and G.
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 willbe evaluated including energy efficiency measures.
Some of the options that have been discussed and are under consideration are:
1. Build a generating resource.
2. Purchase existing or new generation assets.
3. Complete system upgrades at generating facilities.
4. Negotiate a long-term power purchase agreement.
5. Buy in the short-term wholesale market.
6. Purchase the output of a generating or cogeneration facility.
7. Develop additional energy efficiency and DSM programs.
8. Buy energy efficiency through third party developers.
For further information refer to Appendix D.
Preferred Resource Strategy and 2001 Near-Term Action Plan
From the
RFP
process
A vista
selected a
CCCT
and 3
DSM
bids
Avista was pleased with the number and variety of bids received in
the RFP process. The quality of the proposals provided a good
reflection of the market. A vista selected the 280 MW Coyote Springs
II resource as a self-build project and three demand-side resource bids
for a total of 13aMW.
Avista s preferred resource plan will be a combination of low-cost
resource acquisitions. A vista expects to do the following:
1. Acquire supply and demand-side resources through the recently
completed RFP process.
2. Continue or increase the level of energy efficiency programs
under the tariff rider.
3. Re-negotiation of mid-Columbia power purchase contracts.
4. Acquire hydro or thermal unit upgrades when cost-effective.
5. Purchase and sell on the short-term markets to match resource
needs.
6. Evaluate and acquire, if cost-effective, additional supply and
generation units to handle variability.
2001 Near-Term Action Plan:
Public Process
1. Continue free flowing exchange of information with T AC members.
2. Propose changes to the IRP process that will be useful in the competitive market era.
Demand-Side Management
1. Pursue energy savings for the next three years with funding from the tariff rider.
2. Consider the development of programs that will allow peak shaving.
3. Determine the potential for Time-Of-Use (TOU) rates.
4. Execute and implement DSM contracts that were selected under the 2000 RFP.
..... '
Supply-Side Resource Options
1. Pursue the base plan for Spokane River Hydro relicensing.
2. Upgrade at least two units at Cabinet Gorge hydro facility.
3. Evaluate the effects of a micro turbine on the system.
4. Installed inlet coolers at Rathdrum combustion turbines for additional summer
peaking output (completed July, 2000).
5. Evaluated RFP bids, compared to company options, and selected options that werecost effective and that best met company s long-term resource need (completed
December 2000). Complete transfer agreements for selected suppl y-side resource.
6. Pursue re-negotiation efforts with mid-Columbia PUDs.
7. Evaluate the need for additional supply or generation units to handle variability in
hydro , retail loads, and potential generation outages under projected market
conditions.
Resource Management Issues
1. Implement relicensing programs on the Clark Fork River hydro projects, as part of theLiving License" commitment.
2. Continue to examine and pursue cost-effective efficiency improvements at generation
facilities.
For further information. please see Appendix E and F.
For more information about A vista Corp. or its affiliate businesses, visit the corporatewebsite at www.avistacorp.com.
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SUMMARY REPORT FOR 1997 ACTION PLAN
In the 1997 Electric IRP, Avista listed specific action plan activities, which were to beaccomplished during the past two-year planning cycle, This appendix summarizes the company
progress on these individual action items. More detailed reports on many of these activities can
be found in the other appendices. The 1997 Action Items appear on the left-hand column in italicsfollowed with a summary of the company s response in the right column,
Reduce Company Costs
Evaluate the benefits of selling off
high cost generating resources
by August 1997.
Cost effective analysis was done on all of
the company s generating resources, Meyers
Falls, a small hydro facility, was sold in 1999 and
Avista s share of Centralia, a coal-fired plant in
western Washington, was sold in 2000,
When feasible, buyout high cost
energy purchase contracts.Avista contacted all high cost purchase
contract owners (PURPA facilities) to see if
they would be interested in a buyout. The
company was not able to finalize any buyout.
Reduce operating costs
existing generating plants.Avista is constantly striving to come up with
ways to drive the average cost of production
down. Automation is currently being placed in
some of the hydro projects.
Develop strategies to renew low
cost energy purchase contracts Several discussions and agencies rulings on this
item have decreased Avista s expectations but
the company is continuing to work toward a
favorable outcome.
Increase Company Revenues
Expand Avista s energy services
and Avista Advantage into additional
retail markets,
Avista Corp.'s subsidiaries have expanded into
into new markets, with Avista Advantage
conducting business in all 50 states.
Increase wholesale sales through
Avista s wholesale section and
Avista Energy.
Avista Utilities has exceeded its goals in
wholesale markets. But Avista Corp, has
refocused to concentrate on the western part of
the U,S. with the closing of Avista Energy
offices in Boston and Houston,
'-- .
Increase customers through
expansion of system infrastructure
and acquisition as opportunities
become available.
Although the company has pursued some
opportunities, none have been successful so
far.
/',
Identify and pursue those opportunities
that add value to the existing system
and provide positive resource benefit.
Public Process
Continue to be involved with the public
outreach programs through 1998
and beyond.
Continue free flowing exchange
of information with TAC members,
Propose changes to the lAP process
that will be useful in the competitive
market era,
Demand-Side Management
Continue to pursue energy savings
through the DSM filing for the next
three years (1997-1999) with funding
from the tariff rider,
Evaluate options to participate
In regional, market transformation
DSM programs.
Supply-Side Resource Options
Continue to pursue the most cost
effective options in the hydro
relicensing process.
Negotiate favorable long-term
Extension of the Wanapum and
Priest rapids power sales contracts
by December 1997,
Develop joint ventures with other
Avista has added 4 to 5 aMW of DSM and
conservation measures to its system each year.
The company has reconstructed the intake at
Monroe Street and can now realize full capacity
output. We have also replaced the runners on
all four units at Long Lake which provides a
greater efficiency. With recent improvements to
Kettle Falls we are now able to get a higher
capacity rating, compared to one year ago,
Avista has been very successful in involving
the public in its business decisions. Two
examples of this is the Steam Plant oil cleanup
in downtown Spokane and the collaborative
relicensing process for the Noxon Rapids and
Cabinet Gorge hydro facilities,
The company feels that this has been
accomplished through mailings and the holding
of TAC meetings.
Suggestions to improve thelRP process has
been submitted both verbally and written that
should be useful in this era of competition.
The DSM tariff rider has been granted an
extension for the foreseeable future by both
states , although in Idaho the funding has been
reduced,
Avista is committed financially to support the
region s market transformation programs.
Avista was successful in preserving its
hydro flexibility at Noxon and Cabinet
Hydro facilities with a granting by FERC of a new
45 year operating license.
The company has not been successful to date in
this action plan item, We still hope that some
type of agreement can be reached with Grant
PUD.
Avista Labs is developing partnerships with
companies to market fuel cell
technology,
Resource Management Issues
Evaluate all resource options
against wholesale market price
of power.
Continue to evaluate the effects
to hydroelectric system operation
resulting from efforts to protect fish
stocks listed under the ESA.
Implement the best compliance
strategy for the Centralia coa/-
fired plant.
Implement FERC Orders 888 and
889 during 1997.
Finalize the discussions on
Canadian Entitlements and
PNCA by year end 1997,
Continue to utilize and incorporate
Prosym, an hourly production cost
model, into the data/resource analysis
used by the company
Use Wholesale Marketing activities
to maintain short-term and long-
term resource balance.
Identify through suNeys customers
acceptance of green power tariff
and if feasible implement by
June 1998.
others that can contribute to the product
development and sales, such as Black & Veatch.
Avista uses market prices as a major input
in its least-cost analysis as well as other
considerations such as dispatchability,
compatibility with existing resources and
reliability. The company purchased third-partyprice forecasts for its RFP resource evaluations.
The company is involved in helping the
region mitigate effects from fish protection
but the main concern is bull trout
mitigation on the Clark Fork river. Avista
through its new license has committed to funding
mitigation efforts at Noxon and. Cabinet hydro
facilities. The "living" license concept allows
changes in the approach to these mitigation
efforts as future conditions dictate,
The company along with the other owners
purchased scrubbers to bring ~he plant
into compliance , prior to selling the plant.
The company has separated its marketing
and transmission functions and has complied
with all the details of the FERC orders,
Canadian Entitlements have been agreed to
and returned to Canada, and the new PNCA
has been signed.
The use and refinement of this model
continues at Avista, This hourly model is
being used in planning and optimization
functions.
Avista uses the markets to buy and sell both
short-term and long-term to assure that
the resource supply is sufficient for both
the retail and wholesale customers, and to
optimize the use of resources to meet system
requirements.
Although the focus groups indicate a small
number would be interested in a green tariff
the majority of the customers view us as
being green through its hydro generation. Ifcustomer choice is implemented, Avista will
probably offer a full menu of choices to its
customers, including green power.
RESOURCE UPDATE
Resources
. Avista s hydroelectric plant availability rate, an enviable 97 percent, enabled thecompany to achieve a 1997 cost of production that ranked among the very lowest in
the nation. Both access to Canadian and domestic natural gas sources gives abundant
reliable supplies that can be delivered at equally competitive market rates.
In early 1999, the company submitted its application for relicensing two hydroelectric
projects on the Clark Fork River, the final step in the largest collaborative relicensingeffort in u.S. history. Avista worked with Native American tribes, conservationassociations, property owners, non-governmental organizations, and local, state , andfederal agencies- 39 stakeholder groups in all, to create a "Living License Allparties agree to work together over the 40 or 50 year life of the license to addressissues as they arise. This revolutionary concept quickly emerged as an industrymodel, and the company received the National Hydropower Association s 1999Hydro Achievement Award for Stewarding Water Resources as a result of thiscollaborative approach. On February 23, 2000 the Federal Energy RegulatoryCommission issued to A vista a new 45-year operating license, This relicensingrepresents the first time that a large hydroelectric project has successfully received a
new license on time.
In 1999, the company completed the program to replace all four runners at Long Lake
hydro facility, which increased the capability from 72.8 MW to 88MW.
On February 12, 1999 at 6:00 p.m., after receiving all regulatory approvals, Avistaturned the Meyers Falls Hydroelectric Plant over to Hydro Technology Systems, Inc.The sale of Meyers Falls was in the best interest of Avista s customers andshareholders. The purchaser has elected to sell power from the plant to the company
for a period of up to eight years at a price of 21.85 mills per kilowatt-hour. Theselling price of the hydro facility was $316 000.
The 1 340 MW coal-fired Centralia generating facility in southwest Washington was
sold on May 10, 1999 to TransAlta for $554 million. The selling price was for both
the thermal generating station and the adjacent coal mine. The generating plant wassold for $400 million, of which A vista would receive its ownership share of 15percent. The sale was subject to a number of state and federal regulatory reviews. On
May 5 , 2000 the sale was completed.
The Colstrip fuel agreements were mediated in 1998, effectively reducing the costs ofcoal commodity beginning 7/1/00 and the coal transportation costs beginning on
711/01 and eliminated further contract reopeners that were to begin on successivefive-year anniversary dates, respectively. The parties also agreed that the Buyers(other than Puget Sound Energy, Inc.) had met their Final Reclamation obligationsand were indemnified against any future costs of final reclamation, The mediationalso established a governance body to provide the Buyers with approval rights for
capital spending and approval of annual and long-term mine plans and budgets, TheColstrip Project began combining workforces in 1998 between employeemaintenance crews for Units 1 and 2 and Units 3 and 4 and reduced the workforce
necessary to operate and maintain the plant.
On August 14, 2000 A vista issued a Request for Proposals (RFP) for both supply-side
and demand-side resources. On September 18 , 2000 A vista opened the bid proposals,
The company received 32 bid proposals from 23 parties, for a total of over 4,400
MWs. There were 8 energy efficiency bids, 6 renewable bids , and 18 supply or unit
contingent bids. A vista has selected the 280 MW gas-fired Coyote Springs IIgeneration project and three DSM resources for a total of 13 aMW.
~::rV'ST
Corp.
APPENDIX B
LOAD FORECAST
..-.,
ELECTRIC SALES FORECAST
INTRODUCTION
The 2000 electric sales forecast was prepared during the summer of 1999, It is the firststep in the IRP process, namely the assessment of electric power demand so thatstudies for optimal supplies can be performed.
The forecast of firm sales to the core-market is the most critical forecast element.Customers in the core-market segment include residential (both single and multi-familyhouseholds), ,small, medium, and large-sized commercial customers (stores, officeshospitals, schools, and warehouses), and small, medium, and large-sized industrialcustomers (involved in product manufacturing). A small irrigation load is distributedbetween commercial and industrial market segments, while street lighting loads arecounted in commercial, industrial , and as a separate segment. The requirements of thecore-market segments place demands on the delivery system (both distribution andtransmission) for which generation capacity is acquired, either by ownership or purchasecontract.
Requirements for other load obligations , either through direct delivery or by contract, toboth end-use customers and other utility companies, is discussed elsewhere in thisdocument.
Service Area Economic Forecasts
In a change from past practice, Avista purchases County-level forecasts for eightprincipal customer concentrations company wide. For Oregon , the five countiesrepresent only a natural gas service area as presently constituted. For Washington and
Idaho, where Avista Utilities provides both electricity and natural gas energy services
the three counties of data contain in excess of ninety percent of economic activity in the
entire electric service area. Each county model produces separate detailed forecasts foremployment, income, and population. The income and population forecasts should beconsidered as results of the economic forecasts, since the cause and effect relationshipmodeled treats employment as the principal independent variable. Avista Utilities treats
its service area as a whole, differentiated by retail product, namely electricity and naturalgas. Avista Utilities is providing electric services in a portion of its territory, but the entire
territory is exhibiting the same levels of economic growth.
Population
The eight counties show increases from 1 000 550 in 2000 to 1 093 550 in 2010,representing a cumulative increase of 9., or a compound rate of 0., which is about
5 times the national rate of growth expected for the same period. Washington andIdaho growth is proportionate, shown in the accompanying charts with cross-hatch. ThePopulation shares by county in 2010 are shown below:
Fig.
Uniononner
/0
Jackson
18%
Employment
Non-agricultural employment is the sum of the components of manufacturing and non-manufacturing employment. Agricultural employment is small. Each of the availablecomponents of employment are forecasted separately. Components include:construction; finance, insurance, and real estate; federal government; state and localgovernment; durable manufacturing; non-durable manufacturing; transportation andutilities; services; and trade. The eight county employment grows from 414,400 in 2000
to 465,800 in 2010 , and Washington and Idaho are again exhibiting proportionategrowth, This job growth is 12.4% cumulatively over the ten years, and averages 1.compounded. This rate is slightly faster than the 1.1 % U.S. growth expected over thesame period,
Two factors explain the slow employment growth relative to the population growth: First
the economies of each county are significantly dependent on resource-based industrieslike mining, forest products, and farming, which are slow-growth performers nationwide;
B-3
....
and , second , each of these counties has an above average number of retirees, which isexpected to trend upward. These retirees represent a non-employed sector of theeconomy that adds to population and provides a multiplier into the local areas throughspending of respective retirement income from public and private sources. Therefore
the services and trade employment growth is offsetting the declines in the extractivesectors of the economy. In fact, services employment is growing at double the rate ofoverall employment, slightly faster than the U.S. growth.
The employment shares by county are shown below:Fig.B-2
Bonner Union3% Klamath
Josephine
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Personal Income & Inflation
Nominal personal income (before taking inflation out) is expected to grow in the service
area by 4.6 percent per year, compounded. The increase from $22,92 billion in 2000 to$35.77 billion in 2010 defines the footprint for utility service areas of Avista Utilities,Over the same period, the chain-weighted personal consumption deflator averages 2,
percent.
Price
Electric price forecasts are based on a no-deregulation scenario. The price forecastscenario assumes retail rates increase 1.5 percent per year. This increase averages
only two-thirds the overall rate of inflation. This price forecast indicates that priceelasticity will not play an important role in electrical consumption trends.
The forecasts of natural gas prices are incorporated in the use per customereconometric equations. Retail prices of natural gas are expected to average 2.increases over the forecast period, before taking inflation out. After taking out inflationprices are expected to be only four percent higher in inflation adjusted terms in 2010than in 2000. The elasticity impact of this anticipated price change is negligible. Priceincreases at the retail level of five to seven percent every two to three years are built into
the base case forecast.
The commodity cost of gas represents approximately half of the delivered cost of gas to
firm residential, commercial, and industrial customers. ORI's forecast at the nationallevel for 2000-2010 has commodity prices escalating at 5.7 percent average over theperiod. Over the same period, utility natural gas costs are expected to increase only 5.percent. Forecasts of natural gas costs are notoriously volatile, and depend for the mostpart on the assumptions related to oil prices. As described above , oiI prices areexpected to increase 5.0 percent on average. DRI continues to correctly treat naturalgas as a superior quality fuel, as compared to oil, which is the principal explanation forthe positive difference.
FORECAST METHODOLOGY
Avista Utilities utilizes econometric models to produce sales and customer forecasts.Econometric models are systems of algebraic equations which relate past economicgrowth and development in the geographic communities served electricity with pastcustomer growth and consumption. The previous discussion of economic forecastsprovides the basis for the input variables of the cause and effect relationship modeledover the past.
.---"
Typically, a minimum of ten years of historical relationships are modeled to provide acertain level of confidence that we have the relationship correctly identified, The datautilized is separated by state, by rate schedule, and by customer class. The dominantimpact in the equations for firm sales is the variable which measures cold weather. We
use heating degree days for the appropriate geographical area in the model. The 30year National Weather Service average is used to project the future. Hot weather is
becoming more important. Incorporating Cooling-degree days into the econometricrelationship is underway, the results of which will be reported in the next IRP,
FORECAST RESULTS
The results of the forecasting process produce forecasts of the number of customers in
each customer group being served each month, and the average electricity use by eachgroup, For example, the residential class in Washington has four main groupscommonly referred to as schedules. The small residential user is on schedule 1. Thenumber of customers in schedule 1 is forecast for ten years, and the use per customer is
forecast for ten years, and the sales forecast for each month of the next ten years is the
product of these two series. We have summarized the ten year forecasts into annualfigures, and have collapsed the groups into recognized classes of customers:residential, commercial, industrial, and street lights. Results will be presented for eachclass, and for each state. A PURPA cogeneration contract expires during the forecast
period. We expect this customer to continue using its own generation to supply a portionof it's own load. It is important to recognize that the supply modeling proceduresdescribed elsewhere in this document use the monthly information.
. Peak load and energy forecasts are derived from the sales forecasts, as reported on thefollowing page.
Residential Customers 2000 2010 Compound GrowthWashington186,407 224,264Idaho130121 ,980Total275,537 346,244Residential kWh (million)
Washington 322 787Idaho0721,463Total399250Commercial Customers
Washington 071 26,184Idaho64818,512Total719696Commercial kWh (million)
Washington 113 578Idaho946891Total0594,469Industrial Customers
Washington 672 743Idaho507637Total179380Industrial kWh (million)
Washington 819 876Idaho315761Total134637Street Lighting kWh (million)
Washington
Idaho
Total
Total kWh (million)
Total 617 382Reflects the expiration of a cogeneration contract with one customer.
Annual Actual from 1997 to mid-1999, forecast mid-1999 thereafter:
Total Electric Sales (million kWh)
000
12,000
000
0 :
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
8 Total 10 056 094 212 340 411 801 931 073 224 383 551 730 920 1218 Total WA 771 913 049 277 303 402 503 605 709 815 923 033 145 260
Avista Corp. Energy and Peak Forecast
1900
.. ...... .......
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. +.
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1500
1300
----------...........
1100
~..
-on
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1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010-+-ENERGYOO 968 953 1089 1031 1008 1013 971 982 1007 1033 1059 1091 1124 1159 1196----ENERGY97 941 952 967 991 1007 1021 1033 1044 1055 1066 1077 1089 1101 1113 1124
.--
..nENERGY9593894695496397097898799410031011 1020 1029 1039 1046
-..
PEAI500 1796 1517 1683 1521 1557 1594 1557 1~0~164 692 1743 1796 1851
....
PEAK97 1546 1559 1583 1623 1651 1677 1700 1719 1738 1756 1777 1799 1823 1844 1865
\--.
PEAK95 1529 1538 1552 1566 1579 1590 1602 1615 1628 1642 1655 1669 1684 1698 1729
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Corp.
APPENDIX C
RESOURCE PLANNING
RESOURCE PLANNING
At the present time there is a period of uncertainty for the electric utility industry,Wholesale competition is now market based. High power prices and volatility haveresulted from a combination of tightening supply-demand balance , low hydro, and adysfunctionional California market. The region and the industry are expeIiencing aculture shift from cooperation and coordination to competition and confidentiality,
Long-term utility resource planning will be impacted by market conditions and furtherrestructuring, The concerns of confidentiality, market positioning and sensitiveinformation needs to be addressed as it relates to the IRPs. The company believes that the
role of IRPs is still important but the process and requirements will have to change to
accommodate the changes in the new utility environment. The importance of IRPs is that
they facilitate better communications between the company and public (outside entities
Commission, etc.
Avista is
deficit
and
needs to
get into
a load-
resource
balance
A vista s energy needs and the energy market place have both changed
considerably since the last IRP report, The company is deficit and
needs to get into a load-resource balance. A vista is planning to meet itscustomers' needs in the least-cost manner. This IRP report describes
the mix of energy efficiency and generating resources that can meet
future needs at the lowest cost to the company and its customers.
Projections indicate that the majority of significant new generationadditions in the United States will be natural gas fired plants. Gasdemand for electricity generation is rising as gas is currently the fuel of
choice. Gas is expected to maintain this role as a result of technologyimprovements, the low cost of gas turbines, and the growing influence
of environmental concerns , as gas burns much cleaner than coal or oil.
Avista issued a Request-For-Proposals (RFP) to identify low cost and environmentallysound resource options that would best satisfy the company s resource needs. Thebidding process supports the company s ongoing assessment of the cost and availability
of new resources and provides input to this IRP. The resources bid to the compan y inresponse to the RFP must be competitive with other resource options available to Avista
including resources available at cost from affiJiates , in order to be considered forpurchase, The resources bid under this RFP are proposals for energy efficiency and
power supply resources. The company received 32 bid proposals from 23 parties , for atotal of over 4,400 megawatts. There were 8 energy efficiency bids, 6 renewable bidsand 18 supply or unit contingent bids. Avista is using PROSYM and its revenuerequirements model to evaluate the benefit and value of these resource bids and other
company projects to the company and its customers. Avista has selected the 280 MWgas-fired Coyote Springs II project and three DSM resources for 13 aMW to meet a large
portion of its resource needs.
PROSYM
Chronological Production Modeling System
Prosym is a chronological modeling tool used for the purpose of producing near andlong-term forecasts of electric system operation. Prosym is the Fortran-
based simulationengine that applies intricate algorithms to process electrical industry data into usefulresults,
Prosym is a complete electric utility/regional pool analysis and accounting system, It
designed for performing planning and operational studies, and as a result of itschronological structure, accommodates detailed hour by hour investigation of theoperations of electric utilities and pools. Because of its ability to handle detailedinformation in a chronological fashion, planning studies performed with Prosym closely
reflect actual operations. Prosym was the first second-generation chronological modelwith new technology that vastly speedup the simulation process that used open standards
for both input and reporting to link up with the latest software tools. Now, it is the firstthird-generation model, capable of analysis not only in the traditional cost-based worldbut also in the rapidly evolving pools and free markets for power worldwide,
Prosym uses a powerful data input method capable of handling the large volume ofinformation required to perform highly detailed studies of electric generation and pooloperation.
Electric utilities, and generation pools, operate generation resources, energy storagedevices, and load control systems to match generation and load on an instantaneous basis.
This real-time operation entails using highly sophisticated control systems, which matchgeneration levels with load virtually instantaneously. It is not analytically necessary torepresent this level of time detail in performing planning studies, which have a timehorizon of weeks to years. What is necessary, is a level of time detail that allows the
planning study to obtain a reasonable approximation of actual system operation. Hourly
time steps can accommodate the modeling of virtually any utility or pool situation, so thebasic time unit used in Prosym is one hour. In each hour of a study period, Prosymconsiders a complex set of operating constraints to simulate the least-cost operation of the
utility. This hour-by hour simulation , respecting chronological, operational, and other
constraints in the case of cost-based dispatch, and relevant pool or independent systemoperator rules in the case of bid-based dispatch, is the essence of the model.
Prosym simulations consist of a two step process: (1) projection of the load data over the
study period and (2) simulation of utility or regional operation. As the companycontemplates 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 potential fuel supply and marginal costs.A vista uses Prosym to model its resources, to meet its load requirements on an hourlybasis, and to assess the dispatch requirements and compatibility of new resources used in
conjunction with existing resources, both hydro and thermal.
RISK MANAGEMENT
Renewed Focus on Risk related to Energy Resources
A vista Utilities has recently updated its Energy Resources Risk Policy. The recentdramatic increases in volatility to prices in the West have dictated a reduction in
Volumetric Limits, The company experiences fluctuations in customer loads and ingeneration capability and is continually optimizing on an hourly, daily, monthly, ycarlyand for several years into the future, while insuring that it meets firm powercommitments. This process requires projections of the many variables that impactbalancing loads and resources. These projections provide an estimate of any gapsbetween loads and resources. The above mentioned Volumetric Limits govern maximum
exposure to pricing fluctuations.
The following excerpt from A vista Utilities Energy Resources Risk Policy providesinsight on the management of risk related to energy products.
Company Philosophy toward Risk
A vista Corp. will honor its commitments to provide reliable energy services at areasonable cost for its utility customers. A vista Corp: recognizes that there are inherent
risks to income from Energy Resources operations in its electric and natural gas utility.
Risks are driven by uncertain load obligations, by the nature of energy resources, by the
energy marketplace, and by the manner that various regulatory constraints affect thebusiness. It is A vista Corp.' s intention that income risk be moderated to maintainfinancial health of the company.
Avista Corp.'s Energy Resources operations are intended to fulfill the utility s obligation
to meet its firm power commitments and dispatch company-owned and company-controlled resources and manage contracts efficiently, while minimizing costs. AvistaCorp.' s Energy Resources operation is not intended to add risk by taking positions in the
market beyond what is prudent to manage imbalances between committed utility loads
and the power resources under Avista Corp.'s control.
A vista recognizes the variability of its power load requirements and the variability ofcertain generating resources output capacity because of weather and streamflow
conditions, A vista also recognizes the risks of operational and delivery of power that are
inherent with such resources, including unplanned outages with varying durations. Since
there are inherent differences between forward estimates and actual energy loads orresources, it is necessary to both buy and sell energy in hourly, daily, monthly and longer
increments to match actual resources to actual energy requirements, A vistaacknowledges there are risks of counterparty non-performance and variability in pricesfor power and fuel for generation.
C-4
RESER YES
A reasonable level of planning reserves helps the company ensure adequate generatingcapacity during periods of extreme weather or unexpected plant outages, Avistaplanning reserves are not based on the size or types of its resources, Avista s capacityreserves include components for cold weather, generator-forced outages andcontingencies such as river freeze-up at hydroelectric plants. Although they vary by yearcapacity reserves for planning purposes are approximately 12 percent of the companytotal resources or 15 percent of the forecasted peak system load.
The capacity planning reserves that the company has used for the past few years areshown below (figures in megawatts):
Table C-
Year 1995 1996 1997 1998 1999 2000 20011991 Least Cost Plan 263 265 266 2681993 Integrated Resource Plan 247 248 250 2511995 Integrated Resource Plan 245 246 247 248 250 251 2521997 Integrated Resource Plan 243 246 250 253 2552001 Integrated Resource Plan 246 249
These planning reserves are based on 10 percent increase in peak loads which isequivalent to one day in twenty years with an additional 90 MW to account for riverfreeze ups and a portion of the forced outage reserves. This provides A vista with about
15 percent reserves based on forecasted peak loads. The forecasted peak loads are based
on the average expected cold day. For example, the peak for January 2000 was estimatedat 1557 MW (at 8 degrees F) but Avista would expect the peak to be 1713 MW on theextreme day (-10 degrees F).
The company and the Pacific Northwest region does plan for energy contingencies
through planning criteria. Energy contingency for planning purposes comes from aportion of thermal plant's plant factor that is below 100 percent , which would result in anincrease of purchased fuel. Another portion of the energy contingency is covered by the
draw down of reservoir water that is allowed to flow through unused hydro generatingunits. Energy reserves have not been a factor in the Northwest region because regionalplanning is done under critical water conditions.
Operating reserves are considered a portion of the planning reserves and are based on 5
percent of hydro generation and 7 percent of thermal. They are those reserves that autility is required to carry under the Coordination Agreement for that particular operating
year. If an unpredictable event was to occur, such as a forced outage on a generatingunit, the utility would use its operating reserves to cover the event. If the reserves beingcarried by the utility were not sufficient then the utility could ask for and receive reserves
from other parties to the Coordination Agreement.
ELECTRIC AND NATURAL GAS PRICE FORECASTS
Electric
and
Natural
gas pnce
volatility
has
increased
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 goalto provide and use a forecast that is reasonable in its start point and
reflects a longer-term expectation for price increases, A vista knows
there 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.
Natural Gas and Electricity Price Forecasts
Key to any comparative resource decision is an understanding of the future prices for
electricity. 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. There is no sure means to accurately predict prices for even the next few
days, let alone many years into the future. A vista therefore relies on a set of forward
predictions it believes account for the range of possible future outcomes.
The Natural Gas Price Forecast
The price forecasts developed for this update build on the wholesale natural gas forecast
contained in Avista s July, 2000 natural gas integrated resource plan (Gas IRP).
Contained in the Gas IRP is a base forecast of northwest natural gas prices, as detailed inthe base case forecast shown below.
Figure C-
Northwest Natural Gas Price Forecasts
2001-2033 nominal dollars
(')
I/)
As detailed in the graph, wholesale natural gas prices rise from an average annual value
of $2,52 in 2001 to $6.35 per decatherm 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 caseescalation 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. In the low case, the cost per decatherm rises only to $7,12,In the high case , the price increases to $12.88. This compares to a base forecast in 2033of $9.60 per decatherm.
For the RFP evaluation, A vista utilized base case , high natural gas price, low natural gasprice, and high load growth scenarios provided by a third party. These price studies areconsidered proprietary and therefore are not included with this report.
The Electricity Price Forecast
With the scenarios for future natural gas prices established, electricity price forecasts wasestimated using a "sparks spread." Spark spreads identify the heat rate expressed in
BtuJkWh that, when applied to a natural gas price, equate an equivalent price ofelectricity. For example, on 6/812000 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 July equated to 26 635 Btu/kWh.
The average spark spread through calendar year 2000, again using quotes obtained on
6/8/2000, is 21 920 BtuJkWh. Looking forward, the calendar year 2001 spark spread is
approximately 17,300 BtuJkWh. To convert the natural gas price forecasts into electricity
forecasts, varying spark spread values were considered. The short-term spark spreadsinherent 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 often, thirteen, and fifteen thousand Btu/kWh applied to the three natural gas price
forecasts. At the ten thousand level with base gas , electricity prices rise from
approximately $24 per MWh in 2004 to $38 per MWh in 2013, to $96 per MWh in 2033.
The average annual nominal price increase equals 4.8 percent. In real terms, theequivalent values are $22, $27, and $31 , equal to a 1.1 percent annual increase.
Where the spark spread is assumed to be fifteen thousand Btu/kWh, our high caseestimate, 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 terms, prices rise from $36 in 2004 to $49 in 2033, for an annual average real
escalation of approximately 1.1 percent.
A vista s base case spark spread forecast is thirteen thousand Btu/kWh. At this leveLelectricity 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 tenns, theequivalent values are $29 , $35 , and $40 per MWh in 2004 , 2013 , and 2033, respectively,The average nominal increase equals 4,8 percent. In real terns, the forecast rises 1,percent annually.
Using the low natural gas price forecast and the base case spark spread, electricity pricesrise 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 percentnominal and 2.0 percent real. Forecasted prices increase from $32 per MWh in 2004 to
$167 per MWh in 2033.
The folJowing table describes the three electricity price forecasts, including forwardmarket prices prior to August 2003.
170
Figure C-
Northwest Electricity Price Forecasts
Jul 2000-2033 nominal dollars
!.. 150
' ::: "....
:~::w...~".,-
ElECtric
F orw:rds90
Extrq:o-1'1 70 Ided
i8 6/8/00~ J.L~ ... 50 1i. -., Forw:rds
"")"")"")......"")
o:t
..."")
0;-
CIO
..."")
iE!
"")"")"")
Again, for the RFP evaluation , A vista used third-party proprietary forecasts for base case
and various scenarios, for use in comparative dispatch and economic evaluations of
resource alternatives, Because these forecasts are proprietary, they are not made part of
this report,
..-. ,
(~-
"'i8.r...
.....~~, ~ ..
Corp.
APPENDIX D
RESOURCE
ALTERNATIVES
RESOURCE AL TERNA TIVES
There are multitudes of resource options available to the company. Some are moresuitable than others depending on capital cost, dispatch ability, accessibility, operating
experience, environmental considerations, and other impacts, All resource options willbe evaluated including energy efficiency measures. Probably the preferred resourcescenario will be a combination of resource options.
combination
of resource
options is the
preferred
resource
scenan 0
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-term power purchase agreement
. Buy in the short-term 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, or through a third party.
The initial screening of resource costs uses data from the Power Council , actual sitesbeing constructed or just recently constructed, and information received from nationalpublications, Much of this information is shown in Table D-1. The mill per kilowatthour figures are nominallevelized costs, in 1999 dollars.
Nuclear plant costs are not on the list, although it is known (from previous Power Council
studies) that nuclear total cost is about 100 mills/kWh or ranked on the high end of the
Power Council's geothermal projects.
Biomass plants are also not on the list except for land fill gas and biogasification plant.The analysis show that biomass plants have total costs in the range of the low geothermal
costs or about 70 to 80 miJIs/kWh.
Many of these resources have costs that are very site specific. especiaIJy 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.
A vista 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 tothe uncertainty in the markets. At this time other utilities in the Northwest findthemselves in the same situation as Avista so a long-term commitment from them for a
power supply would not be very likely. Avista has included in the 2000 RFP a provisionto bid to the company a long-term power supply contract.
A vista s energy efficiency programs are evaluated in detail on a trimesterly basis andsubmitted 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 meaningfuloversight by the Triple-E Board. The company has also assessed the potential forenhancements to specific programs to meet utility resource needs and will be assessingthe potential for capacity and peak-energy targeted programs in the near future. Pleasesee Appendix J for further information.
A vista has historically planned and developed various resource types. The company hasexperience with hydro, coal, natural gas, and biomass generating plants and demand-sideresources. This operating experience gives the company valuable information that can beused in its resource evaluations.
A vista needs a resource that can provide additional benefits in support of the existinggeneration system. What is needed is a resource that can be dispatched, follow load, andprovide a capacity component. In other words, as an entity with a control area, thecompany needs resources that are dispatchable and meets energy and capacityrequirements 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 withrelatively low capital costs and discharge less pollutants into the air than other fossil fuel
plants.
At this point in time the following resources would not pass the initial screening. Thefollowing costs are nominal life-cycle, levelized costs.
Nuclear: Costs are over the 100 mills per kilowatt-hour range. The total cost and thelack of public acceptance make this resource option unacceptable.
Coal: Costs are 80 to 90 mills. The total cost and cost uncertainty in air qualityissues make this resource option unacceptable.
Wind: Costs are 60 to 80 mills. There are indications that costs are declining but ourstudies show there are not favorable sites in our service territory so transmission costs
would have to be added. Because wind is intermittent the resource would have to bediscounted for lack of capacity component. This would make this resource optionunacceptable.
Geothermal: 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 solicitedresource bids from the market in a Request-for-Proposals (RFP). The company hoped for
innovative bids from project developers. The RFP bids were evaluated against theinformation that had been gathered both internally and externally,
Table D-
Alternative Resource Options
Source: NWPPC (6/00)
Nominal Life-Cycle Levelized
Cost (1999$)
Project Type Fuel Type Total Capital O&M Fuel250 MW CC - West & A2-14 Block 2 Base Gas 41.13,24,2x160 SCCT Low Gas 41.1.78 34.250 MW CC - Eastside Block 2 Base Gas 42.14,24,2x160 SCCT Base Gas 42.47 34.2x160 SCCT High Gas 43.34,High Plains Wind (AB , MT, Wy, CO, NM)Wind 60.47.13.High Plains Wind ((Q) Main Grid)Wind 69.53.16.Landfill Gas Recovery Landfill Gas 69.28.32.Pacific Coast Wind (BC, OR, W A, CA)Wind 78.61.55 17.Advanced Coal (fluidized bed)Coal 79.37.33.Geothermal 4th Plan Group 1- Opt.Geothermal 79.59.19.Geothermal 4th Plan Group 1- Base Geothermal 79.59.19.Cascades Geothermal - Optimistic Geothermal 81,61.20.Geothermal 4th Plan Group 1- Pessimistic Geothermal 81.60.20,Cascades Geothermal - Base Geothermal 81,61.20.Cascades Geothermal - Pessimistic Geothermal 82.61.20.Conventional Coal (300 MW)Coal 88.41.37.80MW SCCT, 4/29 Pessimistic Gas 92.38,43.Basin & Range Geothermal- Optimistic Geothermal 103.78.25,Basin & Range Geothermal - Base Geothermal 103.78.25.Basin & Range Geothermal - Pessimistic Geothermal 105.47 79.26.25 MW Bio-Gasification CC (4'" Plan)Biomass 122.45 52,33.37.Basin & Range 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 CW Grid (50 miles)Solar 242.237.Whitehorse PV ~ Grid _(50 miles)Solar 284.278.Whitehorse PV (fb Grid Solar 291.280.10.PV Shingles Solar 558.549.Roof Rack PV Solar 611.602.Aurora Fuel Cell (Peaking)Gas 823.674.99.48.
,"-.
,t'
DISTRIBUTED GENERATION TECHNOLOGIES
Distributed Generation can be used as an alternative and/or suplement to utility resource
additions.
Technology Overview
The definition of Distributed Generation is- generation, storage , or DSM devicesmeasures and/or technologies that are connected to or injected into the distribution level
of the power delivery grid. The Distributed Generation (DO) can be located atcustomers premises on either side of meter or at other points in the distribution system,
These technologies are installed by customers, energy service providers or a utilitydistribution company at or near a load for an economic advantage over the distribution
grid-based system.
DG can potentially have a greater value than grid power due to:
1. enhanced customer value2. distribution system benefits
3. back-up or emergency power4. social or environmental value
These values are the result of DG being able to augment central station plants and
optimize transmission and distribution asset utilization, facilitate competition and expand
consumer choice, and provide services in an unbundled electric service.
By dispersing generation resources , and siting them closer to loads, the potential exists
for utilities and other energy service providers to:
1, Provide peak shaving in high load growth areas.
2. A void difficulties in pennitting or gaining approval for transmission line
rights-of-way.
3. Reduce transmission line costs and associated electrical losses.
4. Provide inside the fence cogeneration at customers' industrial or commercial
sites.
There seems to be at least two distinct DG markets. One market is for generation in thekilowatt range , represented by devices such as the new microturbines or small fuel cells.
The other market, also called DG, but resembling a wholesale market more than a retail
one, is for multi-megawatt units that may be on-site at a large commercial or industrialfacility. These units are most likely large, aeroderivative turbines, reciprocating engines
or large fuel cell plants. The small units can be handled by the existing distribution
system, while the larger units would require distribution enhancements and special
contracts.
DG is composed of a variety of technologies, some of which are old, and most wouldhave a different niche and would be deployed differently. These technologies include:
Internal combustion engines Gas turbinesFuel cells Batteries
Micro-hydro
Photovoltaic
Micro-turbines
Magnetic energy storage
Diesel engines
Wind systems
Flywheels
Stirling engines
Solar-dish stirling
Aeroderi vati ve turbi nes
Common traits in DG technologies are the following:
1. Mass produced
2. Modular
3. Small (.:::20 MW)
4. Support system reliability
5. Provide economic advantage to end-user
6. Provide customer and utilities an alternative to standard generation options
--'
Fol1owing is a list of distributed generation sources and their efticiencies. Allefficiencies mentioned are generating efficiency only, excluding recoverable thermalenergy.
Diesel engines in sizes from 50 kW to 6 MW provide standby power forcommercial and small industrial customers and provide transmission and distributionsupport. Their efficiency is 33% to 35%.
Internal combustion engines in sizes from 5 kW to 2 MW, provide primarypower and commercial co-generation. Efficiencies: 33% to 35%.
Combustion turbines in sizes 1 MW to 100 MW provide industrial co-generation and transmission and distribution support. Their efficiency ranges from 33%
to 45%.
Microturbines in sizes from 25 kW to 100 kW provide standby power, remotepower and commercial co-generation. Their efficiency ranges from 26% to 30%.Phosphoric acid fuel cells in sizes from 200 kW to 1 MW, are a potential sourceof premium power and can provide commercial co-generation at an efficiency of 40%.Solid oxide fuel cells in 25 kW to 3 MW sizes, provide commercial co-generation and primary power with efficiencies of 45% to 65%.
Polymer electrolyte membrane fuel cells from less than 1 kW to 250 kWshould be ideal for residential customers, premium power and remote power withefficiencies of up to 40%.
Battery storage systems, from 500 kWh to 5000 kWh, provide power quality,voltage regulation and premium power with efficiencies of 70% to 75%.
Photovaltaic arrays are available in sizes from less than 1 watt and up to 1000kW. Their efficiency depends upon the relationship of sunlight to ac power, typically
10% to 20%. They are used for remote power, peak shaving and power quality.
Wind Power. American Wind Energy Association, Washington, D., estimatesthat wind power capacity on line in the United States will grow to 2000 MW by the year
2000,
Each DG technology shares a common need to interface with the grid. The number onebarrier to distributed resources is lack of simplified, low cost interconnection capability.Some utility concerns are safety and reliability issues. Several organizations are
beginning to deal with these issues. The National Association of Regulatory Utility
Commissioners has issued a Request for Proposals on generic guidelines for handling DG
interconnections with the distribution grid, and the Institute of Electrical and Electronics
Engineers has 23 Standards Subcommittees working on interconnection standards for DG
installations.
Other technical issues include net metering, parallel operating agreements, standby
charges, and the effect on gas supply. These and other issues will need to be evaluated
and resolved in order to encourage the application of DG resources.
Market Analysis
Economic impacts from DG systems may include one or more of the following:
Load management
Reliability
Power quality
Fuel flexibility
Cogeneration
Deferred or reduced T &D investment or charge
Increased distribution grid reliability/stability
Potential for increased natural gas infrastructure to support DO application
Potential benefits of renewable based DO:
No/low noise or air pollution
Independent of fossil fuel price changes
Good for very small, modular applications
Could be used on either side of a meter
Coincident with peak summer demand when solar resource is used
Deployment issues of renewable based DG:
Intermittent availability (unless used with storage)
Islanding
Less than 2 MW
Interconnection standards and cost
Will need grid support
. New industry, lacks public exposure
Characteristics of storage technology as a DG resource:
Provide auxiliary services on either side of the meter
Used by utilities; energy service provider and end-user
Wide range of size and storage duration
Costs will come down faster as core technologies are used for transportation
Batteries and SMES available now
MOST LIKELY USERS OF DG IN NEXT FIVE YEARS
Industry
Commercial
Residential
Utili ties
lC Small &
Engine Micro
Turbines
Storage Fuel Small Large
Cell Wind Wind
Advantages of Distributed Resources over Central Station Generation and T &D
Typically can install in a few days to a few weeks for systems less than 100kW.
Easier to locate due to small footprint of fuel cells and microturbines.Photovoltaics may be an exception (land versus rooftop); few permits and
approvals needed.
Can be tailored to meet the needs of the customer (isolated with reservemargin, or with utility standby; parallel operating with backup.
For isolated operation, power quality is a function of inverter harmonics orother customer load.
Microturbines have a lower (US$500/kW) investment cost; fuel cells and PV
systems are significantly higher.
Microturbines operating isolated without T&D costs have competitive energy
prices of 8 to 10 cents/kWh (low investment and high fuel cost); fuel cells are
typically 15-17 cents/kWh. Could be 7-9 cents /kWh for high volume,
Microturbines and fuel cells can be relocated with relative ease. Photovoltaics
may require moving massive structures. If a customer opts for anothersupplier, the generation equipment is easily relocated.
Fuel cells have very low emissions of less than 1 parts-per-million (ppm),
although safeguards for hydrogen are necessary. Photovoltaics have noemissions. Microturbines are generally less than 9 ppm for CO and less than
9 ppm for NOx.
Microturbines and fuel ceIl infrastructure needs are very low if isolatedoperation. Can be applied in areas where line extensions and new
construction are impractical or uneconomic (customers in remote areas orislands). This is a significant advantage for third world countries where only afuel source is needed.
. On site heat recovery and hot water are available. Fuel cells and airconditioning/chiller systems can be added to reduce the cost to between 6 and
7 cents/kWh.
Energy losses are in the range of 1 % to 2%.
The low voltage secondary feeds from distributed generation are generally not
a hazard to the public.
. );
Along with the increased demand for electricity comes the need for efficiency andeconomy in generation. DO applications will fill some of that need, Bechtel Powerestimates that the annual world wide demand for DG wil1 be on the order of 30 to 40
gigawatts over the next 5 years. Westinghouse estimates that 40 percent of all worldwide
capacity addition from 1998 to 2008 will be DG of some form. EPRI estimates apotential market of 2.5 gigawatts per year of DG by the year 2010, U.S. Department ofEnergy forecasts explosive growth in DG, accounting for as much as 20 percent of all
new domestic power generation capacity additions through 2010.
Major companies are investing in facilities to produce DG devices. Allied Signal Power
Systems began pilot production of its 75 kW TurboGenerator units in late 1998. ONSl, aUnited Technologies company, has already produced more than 160 of its 200 kW PC25
phosphoric acid fuel cell power plants. Ballard Generation Systems broke ground in1998 for its first commercial manufacturing facility, which will soon start producingBallard's PEM fuel cells. Energy Research has constructed a plant to manufacture up to
17 MW per year of its molten carbonate fuel cells, and Siemens Westinghouse brought
on-line a pilot manufacturing facility that can produce up to 4 MW per year of its solid
oxide fuel cells.
Companies that are commercializing emerging distributed generation technologies arefacing huge challenges. In the bulk power market, distributed energy technologies willfind it difficult to compete with the nearly 60 percent efficient combined-cycle gasturbines as the design of choice for a power generator, at least in the near or mediumterm. Nor will they easily displace reciprocating engine gensets as the tried-and-truetechnology for emergency or backup generation for most end users who currently have
them. DO will first have to find high:-value niche applications.
BP A is projecting that DG will turn the energy grid into a two-way web that has thepotential to disrupt business unless the grid itself changes to accommodate these newtechnologies. DG could create chaos on the transmission system through the shear
numbers of transactions and interconnections caused by small generators that go on and
off line. But if its coordinated in a market-based system, that could reduce costs and
increase reliability to all parts of the electric system, creating the new 'energy web'These small, local power sources installed at substations or on the customer s side of the
meter could reduce transmission congestion, support voltage, shave peaks and improvethe use of distribution assets.
Most if not all the DG technologies have to overcome concerns regarding reliability,
capital cost, emissions, fuel delivery and nonfuel O&M expenses. For wind generationthe concern is reliability. Fuel cells strong point is environmental performance whilecapital cost is a concern. PV systems need to reduce their capital cost. Reciprocatingengines have proven performance and installed costs lower than costs of virtually allcompetitors. Micro turbines, firing natural gas, can deliver single digit emissions of NOx
and CO , but the problem is fuel delivery at needed pressures (250 to 500 psi
g).
Economics
The following DG economics were developed from available trade information,
It isgenerally recognized that costs will decrease over time through new product development
and consumer experience. The cost-effective threshold for customers and utilities willcontinue to be driven by avoided generation costs, which vary considerably though outthe United States.
COMMERCIAL STATUS OF DISTRIBUTED GENERATION
Commercial
Availability
Size
Installed
Cost ($/k W)
O&M Costs
(cents/kWh)
Fuel Type
Typical Duty
Cycles
lC Engines Small Micro-
Turbines , Turbines
Well Well New
established established industry
3 kW-IMW-25 kW-
5MW 50MW 200 kW
$350-$500-$300-
$1500 $900 $1000
7- 1.5 2- 0.2- 1.0
Fuel Cell
Well
established
1 kW-
200 kW
$3000-
$4500
0.3- 1.5
Diesel Propane Propane HydrogenPropanebiogas &, oil &distillate oil distillate &propanebiogas& biogas biogas
Baseload Baseload Peaking Baseload
Intermed.Intermed.
peaking baseload
Photovoltaic Dish-Small Large
Stirling Wind Wind
Commercial Well Year Well WellAvailabilityestablished2000?established established
Size 30 kW-30 kW and 600 watts-40 kW-2MW larger 40kW 5MW
.~,
Installed 000-$10 000/500-$700-Cost ($/kW)$10 000 kW (now)000 100
$400/kW
(later)
~\\'V'ST II~
Corp.
APPENDIX
RFP PROCESS - 2000
A VISTA'S RFP PROCESS-2000
A vista Corp.' s projections of its requirements and resources showed significant deficits in
both peak and energy. The company discussed the significance of those changes with
Commission staff and also with other parties including a presentation and discussion at
the June 22, 2000 TAC meeting. On July 12 2000 Avista filed an update to its 1997 IRP
for Commission acceptance. This updated IRP served as a basis for a Request-For-
Proposals (RFP), which was filed for Commission approval on July 13,2000 and then
issued to potential bidders on August 14, 2000.
In addition the company placed an advertisement in the regional newspapers announcing
the company s need for long-term firm power, both supply and energy efficiency
resources. The advertisement was placed in the newspapers of Seattle, Portland and
Spokane.
Avista s RFP is an "all-source" competitive bid RFP based on the company s identified
need for 300 MW of electric capacity and energy starting in 2004. The company
considered any offer of resources including, but not limited to, market energy and
capacity, energy efficiency, renewable resources, turnkey plants, and construction by a
bidder on a site furnished by Avista. A resource with operational flexibility capable of
meeting changing needs and load conditions was identified as a preference.
The 2000
RFP goal
was to
identify low
cost and
en Vlfon-
mentally
sound
resource
options
The goal of the 2000 RFP was to identify low cost and
environmentally sound resource options that best satisfy Avista
resource needs. This process supported the company s ongoing
assessment of the cost and availability of new resources, and
provided input for Avista s 2001 IRP. As stated in the RFP
resources bid to the company in response to this RFP had to be
competitive with other resource options available to Avista
including resources available at cost from affiliates, in order to be
considered for purchase.
The RFP was written so that proposals from energy efficiency
measures competed against each other and power supply resources
competed against other power supply resources. Then the most
favorable resources bid to the company would be compared with
Avista s own potential or existing resource acquisition programs
for either energy efficiency or power supply resources respectively.
A vista developed an evaluation matrix for both supply-side and demand-side bid
proposals. The power supply resource bids that passed the initial screening
(completeness of bid information) would go through a production modeling process and
an economic modeling analysis, The evaluation matrix then would screen those
successful bids. The evaluation matrix ranked the resource bids as to their relative value
provided to the company and its customers. The Commission staffs reviewed this
information and their input was incorporated into the analyses, The evaluation matrix
had two main categories. The first category was Financial/Price Factors, with a
weighting percentage of 65%, The second category was Electric Power and
SociallEnvironmental Factors, with a weighting percentage of 35%. Each of these factors
had subcategories that were weighted.
The demand-side proposals were to be evaluated based upon an evaluation matrix of six
characteristics. These characteristics incorporated proposal price (at a 50% weighting),
dispatchability (15%), customer economics and service (10%), ramping, measure life and
persistence (10%), bidder credibility (10%) and portfolio value (5%). A screening team
was selected to review the completeness of each proposal as it was received and to assign
it to an interdisciplinary preliminary evaluation team composed of analysts, engineers and
program implementation specialists knowledgeable of the energy efficiency measures
and customer segments being addressed.
On September 18,2000 Avista opened the bid proposals. The company received 32 bid
proposals from 23 parties, for a total of over 4,400 MW s. There were 8 energy efficiency
bids, 6 renewable bids, and 18 supply or unit contingent bids. Avista was pleased with
the response received from its 2000 RFP. Some bid proposals were not complete and didnot pass the initial screening. Three supply-side bid proposals did not pass the initial
screen and the bid sponsors were notified on September 22, 2000,
Supply-side bids:For the supply-side bids Avista used PROSYM dispatch model, an
economic model and third-party price forecast scenarios to perform analyses of the
resource bid proposals received under the RFP. Those bids that scored the best where
then screened through the evaluation matrix by an RFP work group consisting of
employees from different departments within the company. The weighted percentages
used in the company s matrix evaluation were based on each factor s contribution toward
meeting company s least cost planning goals. The weighted factors were economic
benefit (35%), financial capability (15%), fuel price risk (15%), fuel availability risk
(5%), electric factors (20%) and environmental (10%).
On October 17 , 2000 A vista completed its second screening using the modeling and
evaluation matrix tools and developed its preliminary short list of the bid proposals.
Comments from Commission staff asked for additional review of two bids, which were
then included. Seven bid proposals made the short list from the second screen. Bidders
were notified.
After gathering additional infonnation and discussions with project sponsors, A vista
evaluated the preliminary short list bid proposals against one another and against
company projects. The result of this third screen was that many supply-side proposalswere eliminated from the short-list for negotiation. The company met with IPUC and
WUTC staff on November 28-2000 to discuss results of the third screen. On
December 11 , 2000 the bid sponsors were so notified.
Demand-side bids:The eight energy efficiency proposals received were screened for
completeness. Those proposals that contained inadequate information upon which to
base an evaluation were given the opportunity to correct their deficiencies. One proposal
was eliminated at this stage for incompleteness. The remaining seven proposals were
assigned to their respective preliminary evaluation teams for in-depth review.
The preliminary evaluation teams discussed with the bidders the nature of their proposal
and, based upon the proposal and these clarifications, a summary of the relevant
characteristics of each proposal was completed. The preliminary evaluation team also
completed an initial scoring of the proposal using the evaluation matrix specified in the
RFP.
A final evaluation team, composed of all of the members of the seven preliminary
evaluation teams, convened to further discuss the characteristics of the proposals and to
complete a consensus final scoring and ranking of the proposals. Using this ranking it
was determined that five of the seven projects had the potential to be developed into
proposals which were cost-effective in comparison to either the lRP avoided cost or those
supply-side proposals that were in contention for short-listing.
A single negotiation team was selected to work with the short-listed bidders. Based upon
these negotiation sessions the bidders were given the opportunity to modify their proposal
to improve the proposals score and likelihood of final selection. Several of the bidders
took this opportunity to modify their pricing structure, target markets and energy
efficiency measures. Three of these five proposals were ultimately successful in being
selected for contracting. These selected proposals were then advance to a due diligence
and contracting team to execute the negotiated settlement for implementation.
Coyote
Springs II
gas fired
project
was
selected
On December 12, 2000 A vista made public its resource evaluation
decision. A vista Utilities announced the selection of the Coyote
Springs II site near Boardman, Oregon as the preferred supply-side
resource option and three demand-side management bids (13 MW in
energy savings acquired over a three-year period) to meet the utility
growing resource needs.
The Coyote Springs II project is a combined-cycle natural gas-fired
combustion turbine with generation output of about 280 MWs. Besides the overall cost
effectiveness of the project, a key factor in selecting this resource was its fully licensed
status. The construction of this plant is scheduled to begin in January 2001. Completion
of the project is expected by June 1 2002.
Under the terms of the project agreements, ownership of Coyote Springs II will be
transferred at cost to A vista Utilities from A vista Corp. subsidiary A vista Power LLC
which acquired Coyote Springs II in July 2000 from Enron North America and Portland
General Electric.
Also
selected
were three
DSM bids
The three demand-side bids selected included measures varying
from compressed air systems equipment and evaluation software to
a broad variety of energy efficiency measures. One bid targeted
offices , retail facilities and food service customers while another bid focused primarily on
state and local governments, higher education and public hospitals,
With these supply and demand-side resources added to A vista s resource stack, they
should provide a significant portion of the needed power supply to meet the electrical
requirements of the company for the next several years,
n'ii.
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....
Corp.
APPENDIX
2001 ACTION PLAN
2001 NEAR-TERM ACTION PLAN
Avista s preferred energy strategy provides direction for the company s long-term
activities, The company s new near-term action plan outlines activities that will support
this strategy and improve the planning process. This appendix describes action items
planned for 2001 through 2002. Progress on these activities will be monitored over the
two-year planning cycle and reported in the company s next Integrated Resource Plan.
Public Process
1. Continue free flowing exchange of information with T AC members,
2. Propose changes to the IRP process that will be useful in the competitive market era,
Demand-Side Mana2ement
1. Pursue energy savings for the next three years with funding from the tariff rider.
2. Consider the .development of programs that will allow peak shaving.
3. Determine the potential for Time-Of-Use (TOU) rates.
4. Execute and implement DSM contracts that were selected under the 2000 RFP.
Supply-Side Resource Options
1. Pursue the base plan for Spokane River hydro relicensing.
2. Upgrade at least two units at Cabinet Gorge hydro facility.
3. Evaluate the effects of a micro turbine on the system.4. Installed inlet coolers at Rathdrum combustion turbines for additional summer
peaking output (completed July, 2000),
5. Evaluated RFP bids, compared to company options, and selected options that were
cost effective and that best met company s long-term resource need (completed
December 2000). Complete transfer agreements for selected supply-side resource.
6. Pursue fe-negotiation efforts with Mid-Columbia PUDs.
7. Evaluate the need for additional supply or generation units to handle variability in
hydro, retail loads , and potential generation outages under projected market
conditions.
Resource Mana2ement Issues
1. Implement relicensing programs on the Clark Fork River hydro projects, as part of the
Living License" commitment.
2. Continue to examine and pursue cost-effective efficiency improvements at generation
facilities.
A VISTA's PREFERRED RESOURCE STRATEGY
Avista s Requirements and Resources show some significant deficits both in peak and
annual energy for the next ten years. For the short-term, the company is also facing short
falls in both capacity and energy. The company will probably receive some energy
resources from the 2000 RFP to help meet these earlier needs, Short-term purchases
energy efficiency measures and hydro upgrades will meet these short-term deficits.
In the year 2004 the company shows significant deficits in both energy and capacity. The
deficits of about 300 MW in both energy and capacity fluctuate through the years
depending on contract terminations. By the year 2009 the energy deficit is still about 300
aMW while the peak deficit has increased to 400 MW. Future years will show increasing
deficits as the company experiences increasing load growth.
Strategy is to
acqlure
supply-side
and demand-
side
resources
and cost-
effective unit
upgrades
One of the decisions of the 2000 RFP process was the selection of
Coyote Springs IT, a gas-fired combined cycle combustion turbine.
With the 280 MW Coyote Springs II addition to our resource stack
in 2002, it will provide a significant portion of the needed power
supply to meet the electrical requirements for the following ten
years. Even with this addition, the company will experience
surpluses and deficits on a monthly, weekly, daily and hourly basis
depending on weather and hydro conditions. These swings in the
power supply will need to be handled daily through short-term
purchases and sales in the market place, and/or the acquisition of
other power suppl y options.
Avista currently has long-term purchase rights to power output
from four mid-Columbia River hydrolectric plants owned by three
Public Utility Districts. Each of the mid-Columbia contract purchases represents a very
low cost and a flexible resource for the company. Contracts with Grant County PUD are
the first to expire, with Priest Rapids terminating in 2005. The company is involved in
re-negotiating these contracts. A vista relies on mid-Columbia plants to handle a certain
amount of company need for flexibility. Therefore the company expressed a preference
for flexible resources in the 2000 RFP.
Resource additions will need to be flexible enough to handle the loads being ramped up
and down under a variety of seasonal and load conditions. A vista experiences load
changes of 100 MW or more during several hours of each day. Flexibility will allow the
resources to be dispatched. Purchases from the market will not handle this need. The
market tends to offer standard heavy load hour and light load hour products that do not
meet load shaping or following needs.
-,-
Avista was pleased with the number and variety of bids received in the RFP process. The
quality of the proposals provided a good reflection of the market. The RFP proposals will
also be used to compare other company options. Avista chose the least-cost option
between RFP bid proposals and various build/implementation resource opportunities.The supply-side resource chosen was a natural gas-fired electric generation plant.
Natural gas plants can be built relatively quickly with relatively low capital costs and
discharge less pollutants into the air than other fossil fuel plants, The company would
like to maintain a degree of diversity in the type of resources added. Diversity in
resource types and fuel supply can be beneficial in the long-term. The gas-fired Coyote
Springs II generating plant meets these criteria,
Under the 2000 RFP A vista also selected three energy efficiency proposals that were cost
effective and would provide benefits to the company. Avista is committed to maintaining
a DSM presence in its service territory for the foreseeable future. During the past few
years the company has used a tariff rider to finance its energy efficiency measures. The
tariff rider provides a way to expense the cost of the programs so that a regulatory asset is
not kept on the books. A vista collects between $4 and 5 mil1ion that is used to fund
energy savings of 4 to 5 aMW per year plus market transformation programs.
The preferred case also assumes that there wil1 be no significant degradation of
generation on the Spokane River system due to hydro-relicensing. The company will use
a collaborative relicensing process, similar to that successfully used to relicense the Clark
Fork hydro facilities. Avista expects that the new Spokane River FERC license will be
more restricti ve than in the past. Annual energy production could be shaped into
different periods thereby modifying annual production.
As maintenance and replacement conditions dictate, there will be opportunities for cost-
effective hydro and thermal upgrades. Some of the opportunities include 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. Other opportunities include the
addition of a small natural gas-fired combustion turbine at Kettle Falls, with the exhaust
heat being used to increase the efficiency of the wood-fired plant. Ways to decrease the
discharge pollutants at our combustion turbine facilities and thereby increase the annual
allowable operating hours are also being studied and evaluated; as well as the addition of
supply or generating units to handle variability in hydro, loads and outages.
A vista wil1 also continue to work on reducing resource costs so that the resources remain
price competitive. The preferred resource strategy should provide, at this time, what is
needed to prepare the company for the competitive future. In addition it will be least
cost, flexible, and provide value to the company and its customers.
SUMMARY:
Avista s preferred resource plan wil1 be a combination of low-cost resource acquisitions.
A vista expects to do the following:
Acquire supply and demand-side resources through the recently completed
RFP process.
Continue or increase the level of energy efficiency programs, under the tariff
rider.
Re-negotiation of mid-Columbia power purchase contracts.
Acquire hydro or thermal unit upgrades, when cost-effective.
Purchase and sell on the short-term markets to match resource needs.
Evaluate and acquire, if cost-effective, addition supply and generation units to
handle variability.
11'
ii il,
... .- ...,.
ur.j
...
Corp.
APPENDIX G
RESOURCE AND
CONTRACT
INFORM A TION
-.'
G-1
EXISTING A VISTA GENERATING CAP ABilITY
The following is a tabulation of the maximum generating capability (the amount of energy the
plant is capable of producing during peak conditions) and the nameplate capability (the amount of
energy the equipment within the plant was designed to produce) for each of Avista s generatingplants. Avista has no resource scheduled for retirement in the next 10 years.
Table G-
Maximum NameplateYearPlantCapability (kW)Capability (kW)
1890 Monroe Streee 800 8001906Post Falls 18,000 7501908Nine Mile 500 26,4001910Little Falls 36,000 0001915Long Lake 000 70,0001922Upper Falls 200 0001952Cabinet Gorge 236,000 231 3001959Noxon Rapids 528 000 466,2001978Northeast (gas/oil)000 2001983Kettle Falls (wood waste)000 50,7001984Colstrip 1 (15% ownership coal-fired)222 000 233,400
1995 Rathdrum2 (gas)176,000 166,500
The Colstrip coal-fired plant has test capability of 1,400 MW (total for units No.3 and No.4). At 15%, Avista s shareof the project is 210 MW. The plant operator (Montana Power) operated the units in an over pressure mode that
results in the plant exceeding its tested capability. Recent history indicates the plant operates consistently above
1 ,400 MW and for load and resource tabulations is shown as 222 MW.
The Rathdrum gas-fired, simple-cycle combustion turbines (two units) were declared available for commercial
operation on January 1 , 1995. The January rating capability for these units was 176 MW.
3. Monroe Street's intake initiation was resolved and its capability was increased from 13 MW to 14.8 MW. Nine Milepeak capability was decreased from 29 MW to 24.5 MW. In 1999, Avis!a completed the program to install all four
units at Long Lake with new runners, which increased the capability from 72.8 MW to 88 MW. Noxon Rapids totalpeak capability has been decreased from 554 MW to 528 MW.
RESOURCE AND CONTRACT INFORMATION
The primary objective of the IRP is to deyelop a long-term plan for meeting Avista
energy requirements. For this 2001 IRP Avista has looked at the situation for the next ten
years but has extended the economic analysis for the life of potential resources.
The resource of choice among utility planners is the combined cycle combustion turbine
(CCCT) using natural gas as the fuel. These types of generating resources provide low
capital costs , use fuel that is in abundance, and have minimal environmental problems
compared to other types of thermal generation. In addition, these CCCT units can be
sited and constructed in four to five years.
This appendix discusses the resources and contracts that are coordinated to achieve the
IRP objective. Specifically, A vista s current need for resources is described. This is then
followed by an outline of the power sales agreements A vista holds with utilities and
power producers throughout the region.
RESOURCE NEED
Based on Avista s current resource requirements, the company has a significant need for
new firm electric resources. A vista determined the best options for future resource
additions , which included issuing a Request for Proposals (RFP) that was all-inclusive.
The RFP asked for energy efficiency measures and power supply options, including
power plant site and turnkey power plant. A vista completed its RFP process and selected
supply-side and demand-side resources to fill a significant portion of its resource need.
Without resource additions, the company is facing significant energy and peak deficits.
By the year 2009 the peak deficit is 402 MW and the energy deficit is 301 aMW. After
2006-, all wholesale sales have terminated except the capacity sale to Portland General
Electric. Planning reserves are still included as a requirement.
Table G-
Avista Utilities
2000 Existing Resources
for Retail
(Under Critical Water Conditions)
ResolJrce Energy Capability
(In Average MWs)
-------- ------ -------- -----------
AVISTA RESOURCES
Hydroelectric
Thermal
Conservation
313aMW
303aMW
43aMW
CONTRACT RESOURCESHydroelectric 87 aMWCogeneration 55aMWUtility Purchases 250aMW
-- -------------------------- -----
Total Resources 1051 aMW
A vista continues to assess resource opportunities---focusing on those that provide the
most benefits to the company and its customers. This continual assessment of available
resource alternatives helps Avista respond to constantly changing conditions.
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-term market contract with TransAlta, the new owners of Centralia, to replace a
majority of the generation lost with the sale of the plant. The term of this contract starts
in July 2000 and extends through December, 2003.
In 1999, the company completed the program to replace al) four runners at Long Lake
which increased the compatibility 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 Fal)s.
0-4
TABULA TION OF FIRM REQUIREMENTS AND RESOURCES
A vista s 10-year tabulation of firm requirements and resources shows the company s load
and resource position on an annual basis for the next ten years. The line items are the
various loads, resources and contracts the company holds by year. The peak column
shows the expected maximum capability and requirements of the company during theyear-this peak normally occurs in January. The average column shows the expected 12-
month annual average energy numbers for each year. The hydro numbers are based on a
one-year critical period (1936-37 water year) from the Final Regulation done by the
Northwest Power Pool, and reflects the reservoir levels in January per the hydro
regulation study.
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 Appendix B).
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 (under critical water conditions). The mid-Columbia numbers decrease due to
the Priest Rapids Contract ending in 2005 and the Wanapum contract ending in 2009.
A vista is hopeful that a contract extension can be negotiated with Grant County PUD in
the near future. Lines 24 and 25 are the company s existing single-cycle combustion
turbines, and lines 33 and 34 are the expected thermal generation output from Kettle Fans
and Colstrip.
Line 23 shows a cogeneration contract terminating at the ends of 2001. This is a lO-year
contract with an industrial customer to buy 55 aMW of cogeneration and continue serving
their 90 MW load. A vista expects the customer to use its own generation to supply a
portion of its own load and the company would serve the remainder of the load.
Line 29 shows the BPA residential exchange contract with the 47 MW flat delivery of
power to the company from BPA. There is no dispatchability or flexibility with this
contract. Although this contract has not been signed, the company feels it is firm enough
to be included. And finally, 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.
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1
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. An example of a PROSYM run with a new combined cycle
combustion turbine modeled into the company s system is shown in the following charts.
Load and Resource Monthly and Hourly Analysis
Resource Flexibility
Flexible generation resources are a key component to meet the requirements of Avista
customers. As depicted in the charts , 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. The market today tends to offer only standard heavy load hour and light load hour
products that do not meet load shaping or following needs. In the past it was possible to
purchase more flexible power at reasonable prices. Physical resources have become more
important to shape resources to load and to follow either planned or unplanned load changes.
2004 Study
A detailed tabulation of the load and resource requirements study of the year 2004 is shown in
the following pages. A vista chose the year 2004 for an in-depth study because, as mentioned
before, 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 normal hydro conditions. The second study goes into
even further detail. Avista created an hourly Surplus-Deficiency duration Curve for the year
2004 using PROSYM to gain the following information. 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 information 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
performed after dispatch information is gained from PROSYM modeling.
2004 - 2020 Study:
Hourly system load and resource evaluations for the years 2004, 2010, 2015, and 2020 are also
shown. The method used to calculate the surplus and deficiencies for each of these time periods
is similar to the method used above. Instead of using 60 years of actual flows A vista inputs the
average of 60 years along with the hourly requirement of forecast net system loads, known
contracts (both supply and requirements), and existing resources. The result shows the percent
of time and magnitude of surplus and deficiency for each year studied.
Load growth expectations based on the forecasted methodologies are explained in Appendix B.
Avista doesn t expect drastic changes in our load beyond the normal load growth that has been
experienced. But the future is uncertain and A vista 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 could decide to serve all their own load
from existing generating facilities. Or if partial deregulation was to come to our region, A vista
could pick up some industrial loads thereby increasing the load requirement.
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CONTRACT INFORMATION
There have been some significant changes in the electric utility industry during the past
three years. These changes are a result of competition due to increasing natural gas
supplies, technology, open access, retail wheeling opportunities, and customer demands
for more energy service options. Within the United States , 24 states have some form of
retail open access that covers 60 percent of the nation s population. These changes have
affected both the retail side of the business and the wholesale side.
While there has been a lot of wholesale contract activity since the last report, the terms ofthe more recent contracts have tended to be relatively short. It is interesting to note that
most of the purchase and sale agreements terminate by the year 2003, except some of the
contracts with BP A and exchanges. There are only three sale contracts that extend
beyond the year 2003. These 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 lead factor based on variable
prices.
Portland General Electric is purchasing from the company 150 MW of
capacity through December 21 , 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 firm energy at 50 percent load factor from the company. The
contract ends September 2006.
With retail needs being met by the lowest cost resources, the result will be a continuation
of low rates for A vista s customers. A vista will also continue to offer some energy
efficiency programs to its customers in order to maintain the DSM infrastructure already
in place. A vista provides energy services to customers as a part of the continuing
commitment to customers to be a total seryice company responsive to their needs.
CONTRACTS WITH UTILITIES
.-,.
Bonneville Power Administration/ WWP Exchange
The company and BPA entered into an exchange agreement for the term July 6, 1994
through June 30, 2000. The company will deliver to BPA capacity and energy each
month July 6, 1994 through June 30 1996 and BPA will deliver to the company an
equivalent amount of power July 1 , 1996 through June 30, 2000.
Bonneville Power Administration Residential Exchange
BPA has proposed a settlement of power delivery and dollars to cover the Residential
Exchange with the investor owned utilities. The initial period of delivery is the BP A five
year rate period, October 2001 through September 2006. The proposed settlement
amounts for Avista are currently 47 aMW of power delivered flat for five years and an
equivalent amount of cash equal to 43 aMW. For the subsequent five year period
(starting in October 2006) the total amount proposed to be made available to A vista is
149 aMW.
Bonneville Power Administration- WNP No.3 Settlement
On September 17 , 1985, the company signed settlement agreements with BPA and the
WPPSS in which the company agreed not to proceed further on the construction delay
claims. In addition to settling the construction delay litigation, the BP A Settlement
includes agreements for an exchange of energy, an agreement to reimburse the company
for certain WNP No.3 preservation costs and an irrevocable offer of WNP No.
capability for acquisition under the Regional Power Act.
Under the energy exchange portion of the BPA Settlement, the company expects to
receive from BPA approximately 41 average megawatts for a period of up to 32.5 years
subject to a contract minimum of 5.8 million MWh. The company is obligated to pay
BP A operating and maintenance costs associated with the energy exchange, determined
by a formula in an amount not less than 1.6 cents per kWh nor more than 2.9 cents per
kWh expressed in 1987 dollars, unless WNP No.3 is completed in which case, under
certain circumstances, the operating and maintenance costs may be measured by actual
WNPNo. 3 costs. The company began receiving power from BPA on January 1 , 1987.
With the BP A Settlement, the company continues as an owner of WNP No.3 under the
Ownership Agreement and will continue to pay its ownership share of preservation costs.
BP A is required to reimburse the company for the preservation costs and other costs of
WNP No.3 paid on or after February 1 , 1985 through the date that WNP No.3 is
restarted or terminated. The reimbursement will be applied against the operating and
maintenance costs, which the company will pay BP A under the energy exchange portion
of the BP A Settlement.
Bonneville Power Administration 5-Year Purchase
Avista purchases 115 MW of annual firm energy delivered at a flat rate of delivery
during all hours. This agreement began October 1996 and continues until September 30
2001. The rate is flat for the contract term.
Columbia Storage Power Exchange (CSPE)
In 1968 , the company was entitled to receive power from the Columbia Storage Power
Exchange, a nonprofit Washington corporation, which purchased Canada s share of the
downstream benefits resulting from the Columbia River Treaty. The company s share of
the power is five percent. This contract will be in effect until the year 2003.
In conjunction with CSPE arrangements, the company has purchased Entitlement and
Supplemental Capacity commencing April 1977. This is strictly a capacity purchase with
the amount decreasing until 2003 when the Agreement terminates.
Cogentrix 57 Month
A 5 year interruptible sale commenced October 1, 1995 and terminates September 30,2000. Cogentrix shall purchase from 46 to 50 MW of capacity between 98% - 100%monthly load factor.
The interruptible product was replaced with firm energy and capacity. This contract hasbeen restructured to a 57-month sale. Starting January 1997 through August the capacitysale is 47 MW between 98% to 100% load factor, on September 1997 the capacityincreased to 162 MW through March 1998, on April it decreased to 137 MW anddecreased again on October 1998 to 100 MW where it remains through the end of the
contract, September 30, 2001.
Clark PUD
This sale commenced October 1996 and continues through July 2001. On or beforeJanuary 1 of each year of the term, Clark will provide to Avista the monthly contractdemands it will purchase for that Operating Year. The nomination shall not be greaterthan 250 MW in any month, or less than 100 MW in any month. The average annualcontract demand shall not be less than 175 MW. The total amount of firm energyscheduled by Clark shall equate to a weekly load factor of between 50% and 65%.
City of Cheney
This sale is a five year firm sale of 2 MW of capacity at 100% load factor, commencingOctober 1996 through September 2001 , to the City of Cheney.
Cinergy Services
A vista is purchasing from Cinergy Seryices a three year on peak purchase (Monday
through Saturday) of 25 MW, starting January 1999.
Duke Purchase and Sale
Avista is purchasing at Colstrip 100 MW of firm energy from Duke and selling to Duke
at Centralia 100 MW of firm energy. The terms of the agreement is for 100 MW of firmenergy at 100% load factor starting January 1 , 1999 through July 31 , 2001.
Eugene Water and Electric Board
Eugene shal1 purchase 10 MW of capacity with a minimum load factor of 70% up to a
maximum of 100%. This is a 5-year agreement, which commenced October 1 , 1995 andcontinues through September 30, 2000. Rates are fixed by contract.
Energy Services
This is a four year purchase from Energy Services , Inc. that started July 1 , 1997 and goesthrough June 30, 2001. The energy delivered is 50 MW of firm energy at 100% loadfactor.
-_.
Enron
Avista purchased from Enron two years of 50 MW of firm energy for the period July 1,
1999 to June 30 2001.
Idaho
A vista is purchasing from Idaho Power 100 MW at 100% load factor for the period
August 1 , 1998 through July 31 , 2001.
Mid-Columbia Purchases
Chelan County PUD:
Rocky Reach Plant
The company has been receiving 3.9% or 32 MW of capacity from Rocky Reach Hydro
Plant since 1961, but the debt interest and repayment charges were not a cost factor until
1963. The contract is in effect until November 1 , 2011, and Avista s participation was
reduced to 2.9% (23 MW) on July 1 1977, for the remainder of the contract.
The company signed an amendment to the Rocky Reach Power Sales contract June 1
1968, which provides for company participation in the power output of four additionalunits in the fall of 1971. The company s percentage share in these additional units will
be the same as the initial seven units and currently is 2.9% or 14 MW.
Douglas County PUD:
Wells Plant
The company has a 50-year contract for 5.6% of the Wells Hydro plant power. The
power became available in 1967; however, it was assigned to other utilities until
September 1 , 1972, at which time the company started receiving this power. The PUD
may withdraw , within certain limits , a portion of the plant output but cannot reduce the
company s share below 3.5%. Avista s participation reduced to 3.5% (29 MW) on
September 1, 1997, for the remainder of the contract. The contract is in effect until
August 31 , 2018.
Grant County PUD:
Priest Rapids Plant
The company first received power from Priest Rapids Hydro Plant in 1959, but debt
interest and repayment charges didn t become a factor until 1961. The company s shareof this plant's power was initially 11 %. Reductions in the company s share were made
by the PUD in predetermined maximum amounts on five years ' notice. The company
share was reduced to 6.1 % on September 1 , 1983 and will remain 6.1 % (55 MW) until
the end of the contract. The contract is in effect until October 31 2005.
Wanapum Plant
The compan y recei ved 13.1 % of capacity commencing in 1964 but pai doni y its share of
the operating charges. However, debt interest and repayment charges commenced
January 1 , 1965. Similar to the Priest Rapids contract, the company s share was reduced
to 8.2% (75 MW) on September 1 , 1983 until the end of the contract. The contract is in
effect until October 31 2009.
MIECO
The MEICO purchase is for 25MW of firm energy at 100% load factor. It is a two year
agreement starting January 1 2000 through December 31 2001.
Montana Power
Avista is selling to Montana 100 MW at Colstrip at 100% load factor for the period
August 1 1998 through July 31 2001.
Nichols Pumping
A vista provides energy at Colstrip for Nichols pumping with the other plant owners
providing reimbursement plus an adder with PGE returning the energy at mid-Columbia.
PacifiCorp 1994
The company and PacifiCorp 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). Delivery to PacifiCorp is June 16 through September 15 , with PacificCorp
option to change the term to June 1 through September 30 by giving prior notice. The
company will deliver 100 MW in 1994 and 1995 and 150 MW in 1996 and thereafter.
Energy will be purchased at 25 percent load factor based on variable prices.
PacifiCoI'? Exchange
The company and PacifiCorp entered into a 15 year, 50 MW exchange, from June 16
1994 through March 31 , 2009. Delivery season is June 16 through September 15 in the
summer to PacifiCorp and December 1 through February 28 in the winter to WWP. The
energy exchanged is 27 600 MWh per season and the monthly load factor can vary
between 0 to 50 percent. Either party may terminate the exchange with three years
notice, after March 31, 2004.
Pend Oreille PUD
Avista is selling to Pend Greille for the term January 1, 1998 to July 31 , 2000 6 MW firm energy at 100% load factor.
Portland General Electric
The company is selling to PGE 100 MW of capacity, ten hours per day, fifty heavyload
hours per week for the term March 1 , 1992 through October 31, 1994. Within 168 hours
the energy associated with the capacity deliveries shall be returned. In June 1992 the
company signed a long-term capacity sale with PGE for an additional 50 MW beginning
November 1992 through October 1994, and 150 MW for the period starting November 1
1994 through December 31,2016.
Portland General Electric
A vista is selling to PGE two separate one year deals with different terms of 25 MW
energy at 100% load factor for the period January 1 2000 through December 31 2001.
Puget Sound Energy
The company, on January 1 , 1988, entered into an agreement with PSE to sel1 a block of
power for 15 years. The contract demand is 100 MW for contract years 1988 through
2000 and 67 MW for 2001 and 33 MW for contract year 2002, unless the contract is
extended for two years. The two-year extension is dependent on whether the company
has minimal load growth. Energy will be delivered to PSE based on 75 percent annual
load factor. Energy shall not be scheduled for any hour at a rate higher then 100 MW or
less than 30 MW. The price for energy is the company s average power cost, but not to
exceed BP A's new resource rate.
SEMPRA
A vista is purchasing from SEMPRA for five years firm energy of 50 MW for enumerated
period of delivery, The term is August 1 , 1997 through March 31 , 2002 for a delivery
period of August 1 through March 31 of each year.
Snohomish PUD
The contract begins October 1996 and ends September 2006. The agreement provides for
the long-term sale of firm capacity and energy at fixed rates. In every month, Snohomish
has the obligation to purchase the maximum amount of firm capacity (100 MW) and a
minimum amount of firm energy at 50% load factor. Snohomish has the right to
purchase a maximum amount of firm energy at 100% load factor.
TransAlta
Avista is purchasing power from TransAlta, the new owners of the coal-fired Centralia
plant. It is a flat delivery over all hours excluding April 1 through June 30 for the year
2000 through 2003. The contract starts July 1, 2000 and the delivery rate is 200 MWh
per hour.
West Kootenay
Sale of winter capacity shall be provided beginning November 1 , 1995 and ending
February 29, 2000. West Kootenay has the option to increase the capacity purchase
amounts and to add purchase amounts for the months of October and March. West
Kootenay may either purchase energy associated with the capacity or may elect to return
the energy.
GENERA TION PERFORMANCE DATA
This section includes five years of historical data relating to WWP's generation and
power purchased from independent developers under PURP regulations. It also
includes a monthly summary of economy exchanges, purchases and sales. Resources are
identified within one of the following categories:
1. Hydroelectric
Noxon Rapids
Cabinet Gorge
Post Falls
Upper Falls
Monroe Street
Nine Mile
Long Lake
Little Falls
2. Coal-Fired
Colstrip No.
Colstrip No.
3. Other
Kettle Falls
4. PURP A - Hydroelectric
Upri vel' Power Project
Big Sheep Creek
Jim Ford Creek
John Day Creek
Meyers Falls
5. PURPA - Thermal
Minnesota Methane
6. Economy Purchases/Sales
Based on hydro and load conditions at time of purchase or sale.
NOTE: PURPA facilities that produce less than 1500 Mwh/year are not listed.
Table G-
Hydro Plants
Noxon Ra ids
FERC License Expiration Date: 03/01/2046
Rated Capacity:Total No.No.No.No.No.
(Peak in MW)528 102 102 102 130
Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor
1995 Jan 100.1998 Jan 99.40
Feb 100.Feb 100.
Mar 92.Mar 1.08 97.
Apr 80.Apr 99.
May 97.May 98.
Jun 100.Jun 100.
Jul 100.Jul 99.
Aug 100.Aug 96.
Sep 100.Sep 92.
Oct 91.47 Oct 90.
Nov 99.Nov 98.
Dec 99.Dec 99.
1996 Jan 99.1999 Jan 99.
Feb 100.Feb 95.
Mar 89.44 Mar 93.
Apr 100.Apr 99.
May 99.May 100.
Jun 100.Jun 99.
Jul 100.Jul 99.
Aug 98.Aug 100.
Sep 100.Sep N/A N/A
Oct 99.Oct 75.
Nov 100.Nov 80.
Dec 99.Dec 91.
1997 Jan 99.48
Feb 99.
Mar 88.
Apr 99.
May 99.
Jun 100.
Jul 99.
Aug 100.
Sep 98.
Oct 28.82.
Nov 100.
Dec 100.
Equivalent Availability Factor = Availability Factor = (Available Unit Days/Period Unit Days) . 100.
Forced Outage Rate = (Forced Outage Unit Days/(Service Unit Days + Forced Outage Unit Days)) .100.
Table G-
Hydro Plants
Cabinet Gorae
FERC License Expiration Date:03/01/2046
Rated Capactiy:Total No.No.No.No.
(Peak in MW)236 63.57.57.57.
Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor
1995 Jan 99.1998 Jan 97.
Feb 97.40 Feb 99.
Mar 75.Mar 99.
Apr 95.Apr 100.
May 99.May 99.
Jun 100.Jun 99.
Jul 99.Jul 100.
Aug 99.Aug 100.
Sep 100.Sep 99.
Oct 99.Oct 91.
Nov 99.Nov 99.
Dec 100.Dec 99.
1996 Jan 99.1999 Jan 100.
Feb 99.Feb 95.
Mar 100.Mar 100.
Apr 100.Apr 100.
May 99.May 99.
Jun 100.Jun 100.
Jul 100.Jul 99.
Aug 99.Aug 99.
Sep 82.Sep 100.
Oct 91.00 Oct 98.
Nov 99.Nov 100.
Dec 99.Dec 100.
1997 Jan 100.
Feb 100.
Mar 99.
Apr 100.
May 100.
Jun 100.
Jul 100.
Aug 99.
Sep 87.
Oct 80.
Nov 99.
Dec 100.
Equivalent Availability Factor = Availability Factor = (Available Unit Days/Period Unit Days) . 100.
Forced Outage Rate = (Forced Outage Unit Days/(Service Unit Days + Forced Outage Unit Days))' 100,
Table G-
Hydro Plants
Post Falls
FERC License Expiration Date: 7/31/2007
Rated Capactiy:
(Peak in MW)
Total No.
18.0 2.No.No.
Upper Falls
FERC License Expiration Date: 7/31/2007
Rated Capactiy:
(Peak in MW)
Total No.
10.2 10.
Monroe Street
FERC License Expiration Date: 7/31/2007
Rated Capactiy:
(Peak in MW)
Total No.
14.8 14.
Nine Mile
FERC License Expiration Date: 7/31/2007
Rated Capactiy:
(Peak in MW)
Total No.
24.5 4.No.No.
Long Lake
FERC License Expiration Date: 7/31/2007
Rated Capactiy:
(Peak in MW)
Total No.
88.0 22.
No.
22.
No.
22.
No.
No.
No.
22.
Little Falls
FERC License Expiration Date: NA (License not required)
Rated Capactiy:
(Peak in MW)
Total No.
36.0 9.No.No.No.
Maintenance and outage records for the above plants are not computerized and exist in log style
handwritten form. It would take many man-hours to obtain the necessary data to determine accurate
forced outage and availability data. Because of this, five years of data is not included. The data is
available for inspection or recording at any time.
No.No.
Table G-9 Coal~Fired Plants
Colstrip No.
Rated Capacity =700 MW
Service Date = 1/10/1984
Design Plant Life = 35 years
WWP's Share = 15%
Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor
1995 Jan 87.1998 Jan 84.
Feb 1.57 97.Feb 15.85.
Mar 95.Mar 91.
Apr 99.Apr 86.
May 58.May 100.
Jun 19.Jun 100.
Jul 10.77,Jul 99.
Aug 94.Aug 13.87.
Sep 99.Sep 97.
Oct 91.Oct 27.71,
Nov 94.Nov 99,
Dee 100.Dee 99.
1996 Jan 99.1999 Jan 14.82.
Feb 99.Feb 27.72.
Mar 100,Mar 11.86.
Apr 99.Apr 98.
May 99.May 69.
Jun 16.41 83.Jun 99.
Jul 99.Jul 17.81.
Aug 92.Aug 92,
Sep 90.Sep 90.
Oct 98.Oct 95,
Nov 91.Nov 18.79.
Dee 90.Dee 98.
1997 Jan 10.67.
Feb 99.44
Mar 95.
Apr
May 58.
Jun 98.
Jul 1.95 97.
Aug 91.
Sep 13.86.
Oct 99.
Nov 38.61,
Dee 99.
Note: WWP uses 111 MW/unit based on an over pressure mode of operation.
Forced Outage Rate:
Forced Outage Hours/(Service hours + Forced Outage Hours) , 100 (%).
Equivalent Availability Factor:
Available Hours - feDerated Hours ' Size of Reduction )/Maximum Capacity!' 100 l%).
Period Hours
Table G-
Coal-Fired Plants
Coistrip No.
Rated Capacity =700 MW
Service Date = 4/6/1986
Design Plant Life = 35 years
WWP's Share = 15%
Forced Equivalent Forced Equivalent
Outage Availability Outage Availability
Year Month Rate Factor Year Month Rate Factor
1995 Jan 98.1998 Jan 98.
Feb 99.Feb 99.
Mar 99.Mar 95.
Apr 33.23.Apr 91.
May 34.64.May 47.40
Jun 92.Jun 22.77.
Jul 95.Jul 93.
Aug 97.Aug 85.
Sep 15.69.Sep 90.
Oet 90.Oet 99.
Nov 95.Nov 25.74.
Dee 100.Dec 93.
1996 Jan 99.1999 Jan 93.
Feb 99.Feb 98.
Mar 31.43 79.Mar 89.
Apr 100.Apr 0.40 98.
May 100.77.May 97.
Jun Jun 59.
Jul 32.52.Jul 72.
Aug 97.Aug 94.
Sep 16.83.Sep 98.
Oct 99.Oct 98.
Nov 73.Nov 99.
Dee 92.Dec 92.
1997 Jan 98.42
Feb 99.
Mar 100.
Apr 48.
May 93.
Jun 96.
Jul 21.78.
Aug 14.84.
Sep 92.
Oct 89.
Nov 99.
Dee 99.
Note: WWP uses 111 MW/unit based on an over pressure mode of operation.
Table G-
Forced
Outage
Year Month Rate
1995 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
1996 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
1997 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
12.
36.
11.
25.
Other Resources
Kettle Falls
Rated Capacity =47 MW
Service Date = 12/1/1983
Design Plant Life = 35 years
Availability
Factor
100,
100.
90.
100.
29.
100.
100.
99.
97.
97.
97.
100.
100.
100.
100.
100.
100.
60.
99.44
96.
100.
100.
99.
99.
99.
99.
100.
86.
88.
17.
95.
88.
92.
96.
74.46
97.
Year Month
1998 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
1999 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Availability Factor: (Available Hours/Period Hours) . 100 (%).
Forced
Outage
Rate
4.40
1.40
30.
24.
Availability
Factor
100,
95.
96.47
100.
100.
95.
99.
99.40
99,
100.
97.
99.
99.
99.
99.
100.
62.
99,
97.
98.
69.
99.41
75.
Table G-
Year Month
1995 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dee
1996 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dee
1997 Jan
Feb
Mar
Apr
May
Jun
Jut
Aug
Sep
Oct
Nov
Dec
PURPA Hydroelectric Plants
John Day Creek Hydroelectric ProiecVDavid Cere!=lhino
Rated Capacity = 900 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 9/21/2022
Generation - MWh Year Month Generation - MWh
1998 . Jan 156
Feb 142
Mar 110
Apr 141
May 150
Jun 428
Jul 425
Aug 430
Sep 401
Oct 307
Nov 292
Dee 268
1999 Jan 246
Feb 206
Mar 148
Apr 268
May 286
Jun 423
Jul 395
Aug 438
Sep 354
Oct 273
Nov 202
Dec 166
154
129
367
427
440
417
245
246
209
295
240
273
327
407
419
429
426
394
296
224
195
184
183
202
140
230
302
430
429
435
419
314
252
226
Scheduled energy not metered energy,
Table G-
PURPA Hydroelectric Plants
Jim Ford Creek Power Project/Ford Hydro Limited Partnership
Rated Capacity = 1 ,500 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 4/14/2023
Year Month Generation - MWh Year Month Generation - MWh
1995 Jan 702 1998 Jan 730
Feb 826 Feb 639
Mar 950 Mar 894
Apr 679 Apr 774
May 429 May 516Jun227Jun554
Jul Jul 433
Aug Aug 254SapSep
Oct 147 Oct
Nov 591 Nov
Dee 613 Dee 360
1996 Jan 857 1999 Jan 587
Feb 690 Feb 040
Mar 696 Mar 665
Apr 041 Apr 973
May 881 May 942
Jun 109 Jun 463
Jul Jul
Aug Aug
Sap Sap
Oct Oct
Nov Nov
Dec 464 Dee
1997 Jan 464
Feb 858
Mar 870
Apr 018
May 983
Jun 553
Jul 183
Aug 254
Sep
Oct
Nov
-,-
Dec
Table
PURPA Hydroelectric Plants
Biq Sheep Hydroelectric Project/Sheep Creek Hydro. Inc.
Rated Capacity = 1 ,500 kW
Hours Connected to System = Not Available
Level of Dispatehability = none
Expiration Date = 6/4/2021
Year Month Generation-MWh Year Month
1995 Jan 174 1998 Jan
Feb 526 Feb
Mar 173 Mar
Apr 071 Apr
May 265 May
Jun 157 Jun
Jul 841 Jul
Aug 293 Aug
Sap 134 Sep
Oet 199 Oet
Nov 374 Nov
Dee 912 Dee
1996 Jan 913 1999 Jan
Feb 674 Feb
Mar 053 Mar
Apr 139 Apr
May 182 May
Jun 045 Jun
Jul 090 Jul
Aug 406 Aug
Sep 157 Sep
Oet 139 Oet
Nov 150 Nov
Dee 104 Dee
1997 Jan 104
Feb 232
Mar 352
Apr 754
May 170
Jun 927
Jul 185
Aug 990
Sep 676
Oet 717
Nov 126
Dee 985
Generation-MWh
898
469
830
218
988
066
221
575
458
139
176
317
695
748
695
142
029
121
150
076
703
254
161
654
Table G-15
PURP A Hydroelectric Plants
Upriver Power Project/City of Spokane
Rated Capacity = 15,700 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 7/1/2004
Year Month Generation - MWh Year Month Generation - MWh
1995 Jan 860 1998 Jan 090
Feb 391 Feb 035
Mar 565 Mar 9,495
Apr 10,280 Apr 867
May 371 May 908
Jun 801 Jun 178
Jul 803 Jul 527
Aug 2,449 Aug 1.423
Sap 2.498 Sep 178
Oct 004 Oct 678
Nov 342 Nov 232
Dee 645 Dee 602
1996 Jan 915 1999 Jan 10,724
Feb 138 Feb 703
Mar 755 Mar 10,238
Apr 8.498 Apr 255
May 159 May 349
Jun 199 Jun 383
Jul 945 Jul 266
Aug 757 Aug 520
Sep 727 Sep 2,417
Oct 656 Oct 3,467
Nov 955 Nov 844
Dee 307 Dee 988
1997 Jan 902
Feb 10,019
Mar 721
Apr 634
May 825
Jun 995
Jul 819
Aug 667
Sap 072
Oct 067
Nov 704
Dee 560
Table G-
Year Month
1998 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dee
1999 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
---
PURPA Thermal Plants
Minnesota Methane/MM Spokane EnerQY LLL
Rated Capacity = 900 kW
Hours Connected to System = Not Available
Level of Dispatehability = none
Expiration Date = 4/03/2016
Generation - MWh
228
454
417
420
417
529
496
Purchased the output 5/25/98
379
256
418
411
515
433
482
456
472
473
457
473
Table G-
PURPA Hydroelectric Plants
Meyers Falls! HYdroTechnoloQY Systems
Rated Capacity = 1300 kW
Hours Connected to System = Not Available
Level of Dispatchability = none
Expiration Date = 12/31/2006
Year Month Generation - MWh
1999 Jan Feb Mar 439Apr 829May 825Jun 871Jul 834Aug 877Sep 826Oct 757Nov 819Dec 877
Scheduled energy not metered energy
Sold the plant 2/12/99
Economy Purchases and Sales
Table G-
Total Average Total Average
Short-term Cost Short-term Cost
Year Month Sales - MWh Mills/kWh Purchases - MWh Mills/kWh
1995 Jan 792 18.156 753 14,
Feb 100,739 12.075 10.
Mar 745 12.170 578 11.
Apr 44,842 12,147,880 12.
May 63,761 130 030 9.40Jun222,951 115 289
Jul 146 089 10.154,864 12.
Aug 137,075 15.169 536 16.Sep 202 050 16.216 556 16,
Oct 248,201 14.316 343 11.
Nav 266,197 14.338 703 11.Dee 386,710 12.438 626
1996 Jan 454,848 14.506 752 10.
Feb 393,833 13.366 217 10.
Mar 472,178 11.444,631
Apr 465,784 406 995
May 505,355 449 308
Jun 694,408 664 722
Jul 903,221 11.024,820 10.
Aug 616,967 14.768 015 13.Sep 715,523 15.811 316 14,
Oct 597,694 16.795 513 15.
Nav 681 ,831 18.187 814 20.
Dee 875,158 19.1,496 247 20.
1997 Jan 785,455 15.957,485 15.
Feb 766,226 14.937,534 12.
Mar 957,637 11.994,721 10.
Apr 829,468 11.828 168 10.
May 053,496 11.937 016 11.73Jun289,979 11.226 763 12.46
Jul 560,227 15.41 1 ,427,275 15,
Aug 103,824 18.199 566 17.
Sep 949,004 21.132,663 19.
Oct 965,159 18.812,509 17.
Nav 931,711 21.933 751 20.
Dec 910 810 20.894 638 19,
G-40
Economy Purchases and Sales (continued)
1998 Jan 883,456 19.914,422 20.
Feb 979,108 17.068 522 17.48
Mar 185,458 16.1 ,224 978 15.
Apr 394 605 17.356,928 16.
May 137 592 14.975,395 13.
Jun 367,472 14.211 155 14.
Jul 1 ,521 ,454 22.45 1,418,320 22.
Aug 542,756 30.560,756 30.Sep 134 907 31.158,504 32.Oct 941 013 26.962,296 27.
Nov 165,315 27.122 001 27.
Dec 284 335 27.336,667 28.
1999 Jan 286 835 22.1 ,428,764 24.Feb 933,631 19.031 218 21.
Mar 690 097 20.841 704 20.Apr 800,384 19.768,516 19.
May 203,987 19.090,078 20.Jun 1 ,191 973 18.108,388 19.
JuJ 668 614 27.688 631 29.
Aug 1 ,527,405 33.604 909 34.Sep 689 791 33.41 685,617 34.Oct 050,743 37.007 130 36.
Nov 024 158 30.865,599 32.Dec 372,407 28.219,047 29.
~::'V'ST
Corp.
APPENDIX H
OTHER ITEMS
DISTRIBUTION SYSTEM AND PRACTICES
Scope of the Distribution system
The Distribution system starts at the substation fence and ends at the customer s meter.
Between these two points distribution feeders consisting of poles, conductor
transformers and associated devices provide the interface between the substation and the
customer. An equivalent underground system exists as well. At Avista Utilities, the
primary voltage levels range from 34 500 volts to 2 300 volts.
Distribution Planning
Distribution feeders are designed, built and upgraded based on Reliability and Planning
criterion. Planning is the task of identifying when new substations and distribution
feeders are to be built or when the current carrying capability of the conductors need to
be increased. Planning can also be called Distribution Load Forecasting. A long range
plan is prepared through the use of a load-forecasting program. Ten-year distribution
forecasts are performed for both summer and winter peak loads. A vista uses a PC based
program to forecast loads. The program uses five years of load history along with a
growth rate to predict what future loads will be. The analysis then flags capacity
problems on substation transformers and feeders based upon loading criteria specific to
urban and rural areas. There are two main components used in the Joad-forecasting
program: capacity data and load data. Capacity data is gathered annually by studying
substation and distribution equipment load data. Feeder load readings are examined
monthly. At the completion of a Distribution Load Forecast, the distribution system
upgrades for the next ten years will have been identified.
Reliability criterion insures that the A vista Utility distribution system is operated to
assure continuity of service consistent with sound economical planning principles. The
intent is to limit the number of customers affected by an outage and the duration of the
outage. National and state standards are used to establish normal and emergency levels
for customer voltage, distribution equipment loading and distribution short circuit levels.
Distribution Construction Budget
The Distribution Construction Budget consists of:
Growth items driven by a load growth forecast. This includes all projects providing
additional capacity to serve projected future load.
Maintenance items submitted by operating areas. These are primarily increasing the
current carrying capacity of the feeders.
Distribution Practices
Substation site selection. loss reduction and asset management are items under this topic
The selection of a substation is an economical analysis including cost of present and
future system losses, cost of additional transmission and cost of land, Surrounding
geography and availability of suitable land factor into the selection. Transmission routing
has a major impact on the selection process and can be the overriding consideration.
Distribution loss reduction is an attempt to run the system as efficiently as possible.
In the early eighties, Avista started using economic conductor analysis for all new
construction. Economic conductor sizing includes the cost of distribution conductorlosses when selecting the conductor size.
About the same time, a system-wide capacitor replacement program was initiated. This
was an opportunity to optimize the number and location of capacitors for line lossreduction. When distribution feeders are modified, capacitor banks are reviewed forproper location and size.
When transformers are purchased, the associated core and winding losses are evaluated
as part of the bid. The total ownership cost of the transformer, (purchase price and losses
over the life of the transformer) is examined.
The distribution feeders are reviewed for load imbalance. Reducing load imbalance is a
cost-effective means of lowering system losses.
A vista has been converting older 2 300 and 4 000 volt distribution systems to higheroperating voltages and in doing so, the feeder amps and corresponding losses are
decreased. There are two of these systems to be converted.
Asset management is a process to control costs.
Through a comprehensive integrated set of Material , Design and Construction standards
unifonn construction practices are attempted. This is an attempt to avoid the aquisition of
non-standard items. When purchasing materials for line construction , the lowest purchaseprice does not necessarily mean the least installed-cost; the big picture must be kept in
VIew.
Avista has an active pole inspection, stubbing and replacement program. Throughprograms such as this, the useful life of the installed plant is extended. Prior to any
distribution rebuild or voltage conversion, an inspection is completed to assess the
condition of the poles.
Avista utilizes computer modeling extensively
The distribution system is modeled for voltage , overloaded equipment, short circuit
cun'ent and voltage flicker. These models will predict the improvements that can be
achieved when a feeder is reconfigured or upgraded. The software, which is used to build
the models, was purchased from an external vendor.
The implementation of GIS (graphical information system) is underway. In addition to a
mapping system, this tool allows access to the distribution system data-base for data
aquisition, system analysis and design.
To gain more experience in the area of Distributed Generation, a Micro-turbine has been
placed on the A vista system and operational data is being acquired. In addition, a Fuel
Cell has been in operation for several years and operational experience is being
accumulated with it. Computer modeling is being conducted to determine the affects of
Distributed Generation on the Distribution system.
Conclusion
A vista is actively engaged in exploring cost effective and efficient ways to distribute
energy to our electrical customers. New products are being tried to make our distribution
systems more efficient with out sacrificing safety.
SYSTEM PLANNING (TRANSMISSION)
Relationship to Resource Planning
Avjsta (Transmission) System Planning and Operations continues to respond to the
requests from Resource Planning for integration of resources to serve retail load. As
Resource Planning analysis installation of additional generation on the system, it willmake requests for studies from System Planning. System Planning will investigate theimpacts and provide information as requested to Resource Planning for use in evaluation
of the cost-effectiveness of various resource options. System Planning s goal is toprovide reliability and maximize the efficient use of the transmission system.
Current Issues
A vista System Planning and Transmission Operations faces an uncertain future as a resultof the current restructuring of the Electric Transmission Businesses as the industry moves
toward a more deregulated market. This turmoil includes several activities:
1. An increased emphasis on reliability. Both the North American Electric Reliability
Council (NERC) and the Western Systems Coordination Council (WSCC) have
instigated a move toward mandatory compliance with reliability and operatingcriteria.
2. An increased emphasis on operational studies to detennine the simultaneous
capability of transfer paths. This has resulted in the formation of four regional study
groups that determine simultaneous and non-simultaneous capabilities of all impacted
transfer paths. Included in this is the Northwest Operational Planning Study Group in
which A vista participates. The rule for operation states simply: if the flow pattern
hasn t been studied to assure system integrity, then the system cannot be operated in
that way.
3. A move toward consolidation of transmission resources into larger organization sothat it will be more completely separate from any merchant entities. On December
, 1999 the Federal Energy Regulatory Commission (FERC) issued its final rule
(Order No. 2000) regarding the development of Regional Transmission
Organizations (RTOs). The Order requires that all public utilities that own , operateor control interstate transmission facilities file by October 15, 2000, either a proposalto participant in an RTO or an alternative filing describing efforts and plans to
participate in an RTO. Avista with other utilities filed a phase one RTO West.
The big impact of #1 above js that previous to this move toward mandatory compliance
utilities could occasionally violate WSCC reliability criteria (usually unintentional) aslong as there were no detrimental effects on neighboring systems. MandatoryCompliance states that utilities must now meet all criteria within their own boundaries as
well as not affecting others. On June 18 , 1999 the majority of the members of the WSCC
signed agreements to participate in the WSCC's Reliability Management System (RMS).
This system tracks violations of operating and planning criteria with consequencesranging from letters to management and State Utility Commissions to monetary penalties.
The initial RMS implementation included only critical operating criteria. A pilot NERC
~ .
compliance program is under way that will eventually blend with RMS. Ultimately there
will be a complete Mandatory Compliance system that will require utilities to get a long
list of important operating and planning criteria. The consequences for non-compliance
may be severe and include monetary penalties. The full implementation of Mandatory
Compliance will require national legislation to be effective and binding.
The increased emphasis on operational studies is a result of de-regulation and other
factors that put the transmission system of the Westelll Interconnection at a potentially
higher operational risk. The two large widespread outages in 1996 contributed to the
urgency of making sure the transmission system can handle transfer needs in each
upcoming operating season. Abnormally large amounts of new generation are planned
for installation in the Westelll Interconnection in the next 3-years. While local
interconnection studies are being pelformed, it is nearly impossible to do long range
system wide planning because no one knows what new plants will come to fruition and
what the actual generation patterns will be. Other factors, such as changes in generation
patterns on the Columbia river to help mitigate fish depletion have added complexity to
planning studies. As a result of all of this, more emphasis is being put on the near term
operational" studies rather than longer term "planning" studies. Each sub-region will
analyze the allowable transfer levels for recognized transfer paths. Avista is an active
participant in the Northwest Operational Planning Study Group.
Order No. 2000 requires A vista and other interstate transmission owners to work together
to determine possible configurations for a Regional Transmission Organization (RTO) and to file a plan with the FERC on or before October 15 , 2000. Avista and other
transmission owners have proposed formation of an Independent Transmission Company
(ITC), and will file for its formation with the FERC by this deadline. Work on the RTO
and ITC proposals have been a monumental task because of differences in transmission
rates between the differing utilities, and the fact that the FERC would like whatever
transmission organization ultimately forms (whether just the ITC or a combination of an(ITC with an RTO) to levelize the cost of transmission to encourage open access.
Implementation of an ITC or RTO could cause cost shifts for the participants that are
beneficial to some and unacceptable to others. Avista expects the discussionssurrounding and ITC and/or RTO to continue to develop over the next year to eighteen
months.
Expansion Possibilities & System Reconfiguration
The impact of expansion on the Avista transmission system is largely dependent upon the
location of the proposed, expansion. Some of the possible solutions to various systemconstraints may. have the added benefit of making load and generation additions more
easy to integrate. These solutions include possible conversions of parts of the 115 kV
system to a radial rather than looped system and a significant amount of additional or
reconductored 230 kV transmission lines. Any new load or generation integration will
continue to be handled on a case by case basis.
Reliability
A vista s transmission system is planned, designed, constructed and operated to meet peak
load demands and peak load transfers while assuring continuity of service during system
disturbances and to be consistent with sound economic planning principles. FERC Form
715 includes the planning limits of both the transmission lines and transformer
capabili ties for the A vista system. A vista Planning uses the Western Systems
Coordinating Council's "Reliability Criteria for System Design" as a benchmark
determine the performance of Avista s system in relation to interconnections with other
Northwest regions and utilities.
PUBLIC INVOLVEMENT
Avista serves at the consent of its publics. The company believes the most effective way
to reach balanced business decisions is by working with the public , utility commission
staffs and other key audiences. An effective public involvement process creates the
opportunity to build credibility and trust for the company. A vista realizes public
participation will continue to be an important consideration in resource planning as well
as all other business decisions.
Public meetings, open houses, facility tours, customer surveys and advisory groups are all
being used today to help others understand the company s situation, receive input from
constituency groups, gauge public concerns and accommodate group needs. A vista is
firmly committed to the education of all its stakeholders. Communication, education and
inyolvement are the foundation of Avista s internal and external relations.
There are dozens of utility company projects going on each day through out the service
territory. Most of this work is low-impact, routine maintenance completed on existing
facilities. Occasionally a more significant project with noticeable effects is required in
order for the company to continue to provide safe and reliable service.
It is these more complex projects with more community impact that an exchange of
information between all parties is essential. A vista uses public meetings to educate the
public about the need for the project and to solicit input and, when possible, obtain
consensus on the preferred alternatives from the standpoint of impacts to the communities
affected. A vista holds public meetings on an issue-specific basis throughout the year.
Meetings are formatted to allow citizens to take in valuable information as well as ask
questions of accountable Avista employees and provide input on preferred alternatives or
community impacts that need to be taken into account.
A good example of this public involvement was the company s huge effort in getting the
relicensing completed for the Noxon Rapids and Cabinet Gorge hydro facilities. This
public involvement resulted in a comprehensive settlement agreement with 27 parties.
The company utilized a unique collaborative approach that produced one of the most
successful ever-hydro relicensing efforts.
Technical Advisory Committee (T AC):
The T AC is comprised of representatives from customer groups, government agencies
and environmental organizations, which reviews all of A vista s resource planning
activities. Avista sponsored three TAC meetings during this latest planning cycle. The
three dates and information discussed were:
August 19, 1999
IRP Plan and Future Activities
Energy (electric and natural gas) Forecast
Fuel Cells
Energy Efficiency Programs
November 18, 1999
Future Gas Supply and Prices
Wholesale Markets and Prices
Relicensing of Noxon and Cabinet
Distribution Planning
Bull Trout Impact on System Hydro
Transmission Planning
Centralia Sale
Level of Risk in Marketing Activities
Identification of Stranded Costs
June 22 , 2000
Need for Additional Resources
Resource Analysis
Avista s Models and Model Outputs
Forward Pricing Curves (electric and gas)
RFP Purpose and Status
New Resource Site Investigation
IRP Partial Draft
Survey Results:
The company handed out a survey at the last T AC meeting to try and get feed back from
the participants as to the effectiveness of the meetings and their needs. The six questions
and a summary of responses received are:
1. Are we providing enough information to meet your needs?
Answers- Yes (at this time), might help to have pre-meeting information.
2. What about the quality (verbal and written) of the information?
Answers- Great.
3. How can we improve the feed back from you to us?
Answers- Ask for it, more contact outside the scheduled meetings.
4. Is the number of T AC meetings okay?
Answers- Yes.
5. If there were additional information you need, what would it be?
Answers- None, information ahead of time, comparison of resource alternatives.
-.,
6. Do the presenters at the meetings provide enough information?
Answers- Yes.
HYDRO PROJECT RELIC~
Avista Corp. was granted by the Federal Energy Regulatory Commission on February 23,
2000, a new 45-year license to operate the Noxon Rapids and Cabinet Gorge
hydroelectric projects on the lower Clark Fork River. The license order was received a
year before the existing licenses e~pired and 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., February 18 , 1999, and contained a comprehensive settlement agreement
with 27 signatories.
A vista was
granted a
new 45-year
license for
Noxon
Rapids and
Cabinet
Gorge
The 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
Corp. retains nearly all the valuable load following and peaking
capability of the two projects while providing earlyimplementation of protection , mitigation , and enhancement
measures to benefit native fish species, recreation opportunities,
continued protection of cultural resources, wildlife populations,
and water quality. Avista Corp. will spend approximately $4.
million annually with a significant expenditure earmarked for
enhancing bull trout populations. Bull trout are presently listed as
threatened under the Endangered Species Act.
The highly successful outcome of the relicensing process has received national mediaattention and awards. Avista Corp. received in 1999 the National HydropowerAssociationprestigious Hydro Achievement Award for Stewardship of Water
Resources. The award was given to A vista Corp. for exemplary stewardship of the
nation s rivers, resourcefulness, and creativity in meeting challenges associated with
hydroelectric development; and an uncompromising commitment to championing hydro
power as a vital component of the country s energy future.
The FERC license order and settlement agreement is in many ways the first of its kind,
and represents a cost to the company well below the outcomes of other hydro relicensing
proceedings where issues were often contested. The following summarizes the highlights
of the Clark Fork hydro relicensing program:
At nearly 800 MW of generating capacity, this is the largest collaborative
relicensing effort ever undertaken in the United States.
The Clark Fork process is considered the template for FERC's newcollaborative alternative relicensing approach and is the first-ever on time
relicensing for a major project.
The Clark Fork Settlement Agreement comprises 27 participants and is the
first of its kind in the nation for a large project. Signatories include Native
American Tribes (5), federal agencies (2), state agencies (8), nongovermental
organizations (10), and local authorities (2).
partnership with Trout Unlimited represents a first of its kind with a
national river organization.
The Living License , created in the Avista Corp. process is a first of its kind.
Based on the principles of adaptive management and flexible funding, this
innovative approach has created among the participants unprecedented local
ownership and joint management of new license conditions.
Precedent setting acceleration of Noxon Rapids license term by four years
(2005 to 2001 to coincide with Cabinet Gorge license) facilitates simultaneous
relicensing of both projects.
Other precedents in the relicensing process include early FERC involvement
early EIS scoping, and neutral facilitation of consultation process.
The first Programmatic Agreement for a project of this size, signed by five
tribes, two states, and the federal government that resolves cultural resource
Issues.
Successfully incorporated agency mandatory conditioning authorities with
local , consensus-based, decision making.
The first collaboratively prepared environmental assessment and license
application for a large project.
First relicensing process resulting in early implementation (two years prior to
license expiration) of new license terms and funding of natural resource
protection and enhancement measures.
A VOIDED COST
A voided costs are costs determined by a public utihty commission process that is
intended to represent the costs a utility would otherwise incur to generate or purchase
power if not acquired from another source. These costs would apply to customer owned
resources made available to A vista.
In general , avoided cost is meant to represent the incremental cost of new electric
resources available to a utility. Avoided cost rates reflect the price of power from
avoided resource or resource mix. These rates are often applied to the purchase of energy
from PURP A quaHfying faciHties (QF). In some cases, the avoided cost is used to
determine the cost-effectiveness of potential resource alternatives.
Presently, the avoided cost methodology used in the filed tariff for the purchase of QF'
output of less than one megawatt in size is the same in both Washington and Idaho. The
avoided costs are based on a gas-fired combined cycle combustion turbine, used as the
surrogate firm resource to determine costs of future power during the projected time
period of resource need. Based on the 2000 RFP , Avista has good data on the capital and
siting costs of a CCCT. The big question in these calculations is the future cost of natural
gas. Gas price assumptions can vary the project economics substantially. The company
has, from third parties , scenarios of natural gas prices into the future. A vista will use all
of this information to derive the avoided cost figures which will be representative of the
costs that the company might expect associated with the construction and operation of aCCCT.
The avoided costs shown in the 2000 RFP are based on figures from the NWPPC and
natural gas prices from the company s natural gas 2000 IRP. Based on the current
situation these gas prices are probably on the low side. These inputs resulted in the
calculated avoided cost in the RFP to rise from $38 per MWh in 2004 to $58 in 2020.
With the publication of the 2001 IRP, A vista will file revised avoided costs to match the
parameters in the IRP, including information received from the 2000 RFP. Avistahas 90
days after the IRP filing to file revised numbers in Washington. The company will also
file at about the same time updated avoided cost numbers in Idaho. This will allow the
company to remain in compliance with the state s requirements in their management of
the PURP Alegislation.
~\\'iI'ST
Corp.
APPENDIX
GLOSSARY OF TERMS
ABBREVIATIONS &
ACRONYMS
Aggregators
Average Megawatt (aMW)
Avista Corp.
Avoided Costs
B. C. Hydro
Base Loaded
Bilateral Contracts
BPA
Capacity
Capacity Constrained
Capitol Costs
CF (Capacity Factor)
Cogeneration
CO2 (Carbon Dioxide)
Competition Transition Charge (CTC)
Conservation
Brokers who seek to bring together customers
or generators to buy or sell power in bulk
making a profit on the sale.
A measure of the average rate of energy
delivered. One aMW equals 8,760 000 kWh
per year.
Formerly the Washington Water Power
Company and the parent company for Avista
Utilities.
Costs determined by a public utility commission
process that are intended to represent the cost
a utility would otherwise incur to generate or
purchase power if not acquired from another
source.
British Columbia Hydro and Power Authority.
A resource which operates more efficiently
without being cycled to meet daily load
changes.
Contract between a generator and consumer
which may involve aggregation.
Bonneville Power Administration, the federal
power marketing agency for the Pacific
Northwest.
The maximum load a generator, power plant, or
power system can produce or carry under
specified conditions.
A condition where a system adds resources for
capacity needs rather than energy needs.
Cost of investment in a new resource, installed
$ per kW.
The percentage of a resource s maximum
generation capacity that is actually used.
The sequential production of electricity and
useful thermal energy.
An emission from fossil fuel burning.
Nonbypassable charge to customers to recover
utility stranded costs.
Reducing electrical consumption with measures
that increase the energy efficiency of
appliances , motors, building shells , etc.
Cost Shifting Shifting cost from one group of customers to
another-from industrial to residential or
commercial to residential-or from one utility to
another.
CPUC California Public Utilities Commission.
Critical Period The historical period of water conditions during
which the region s hydro power system would
generate the least amount of energy while
drafting shortage resevoirs from full to empty.
Customer Groups Industrial, residential, commercial and
agricultural.
Data Resources Inc. (DRI)WWP's national economic forecasting
contractor.
Demand The instantaneous rate at which electric energy
is delivered to or used by a system.
Demand-Side Management (DSM)The activity of acquiring demand-side
resources.
Demand-Side Resources Resources that can be added to a utility system
to reduce customer electric usage, or control
the timing or shaping of such usage.
DIG Demand Side Issues Group
Direct Access Ability of a power producer to sell directly to a
retail customer.
Dispatchability The ability to operate or not operate a resource
for economic reasons.
Distribution Function of distributing power to retail
customers.
Distributed Generation Generation, storage or DSM devices, measures
and/or technologies that are connected to or
injected into the distribution level of the power
delivery grid.
DSI Direct Service Industries (certain industrial
customers of BP
Electrical Energy The amount of electrical usage or output
average over a specified period, e.g. kWh.
Energy Policy Act (EPAct)House Referendum #776 passed in 1992,
encouraged competition among bulk power
producers.
EMF Invisible lines of electric and magnetic fields
surrounding an electric conductor, commonly
referred to as Electro-Magnetic Fields.
End-Use The final use of electricity by customers (e.
lighting, cooking, etc.
Environmental Externalities Environmental effects, including environmental
benefits, that are not directly reflected in the
cost of electricity.
EWG Exempt Wholesale Generator (of electricity).
They are exempt from certain regulations which
traditional utilities must follow.
Existing Resources Those resources that are currently in use, or
being developed under contract but not yet in
operation.
Federal Energy Regulatory Commission.FERC
Firm Load Customer load served by a utility without a
contractual provision for curtailment.
Fixed Costs Costs that do not vary in relation to change in
plant output.
Fossil Fuels Coal, oil, natural gas and other fuels deriving
from fossilized geologic deposits.
Framework CPUC's new market structure for generation
transmission and distribution among investor-
owned utilities.
Fuel Cells Fuel cells convert hydrogen gas to electricity
through an electrochemical process with no
combustion.
Fuel Efficiency Utilizing fuels in applications that produce the
greatest end-use efficiency (e.g. conversion of
electric space and water heating to natural
gas).
Fuel Mix The make-up of resources used to serve load
by fuel type.
Generation Producing electricity.
Generation Costs Costs associated with producing electricity or
acquiring it through contracts.
Grid Large electric system linking transmission lines
both regionally and locally.
GWh 1 gigawatt-hour = 1 million kilowatt hours.
Independent System Operator (ISO)Independent operator of transmission lines to
assure reliable and fair transfers of electricity
from generators to distribution companies.
Inland Northwest The area of eastern Washington, northern
Idaho and western Montana.
Integrated Utility Utility that provides generation , transmission
and distribution services for its customers.
IOU Investor-Owned Utility.
IPP'Independent Power Producers.
IPUC Idaho Public Utilities Commission.
IRP Integrated Resource Plan or integrated
resource planning.
1 kilowatt = 1000 watts
kWh 1 kilowatt-hour = 1000 watt-hours
Levelized Cost The present value of a cost stream converted
into a stream of equal annual payments.
Load Amount of electricity being used at any given
time.
Load Forecast The predicted demand for electric power for
planning purposes.
Lost Opportunities Resources, which if not acquired or developed
within a certain time, could be lost.
Market Forces Competition for sales, new alliances, innovative
pricing structures, customer demand, choice
and various kinds of services.
Market Power Domination of the new marketplace by
electricity suppliers that own a high percentage
of generation.
MCS Model Conservation Standards.
Mill/kWh One mill equals one tenth of a cent.
Frequently used as a monetary measure when
referring to the cost of producing or conserving
electricity.
Monte Carlo Simulation Monte Carlo refers to the traditional method of
sampling random variables in simulation
modeling. Samples are chosen randomly
across the range of the distribution.
Muni Municipal- or publicly owned utility.
megawatt = 1000 kilowatts
MWh
Net System Load
Nominal
Nonfirm Interruptible Load
Nonfirm/Secondary Energy
Nonutility Generation
NWPP
NW PPC
O&M
Obligation to Serve
Pacific Northwest Coordination Agreement
(PNCA)
Peak
Performance-Based Ratemaking (PBR)
Power Brokers and Marketers
Power Exchange (PX)
Present Value
PUHCA
1 megawatt-hour =1000 kilowatt-hours
The total load of a system , including both firm
and interruptible, within a utilities service area.
Rates or costs that include the effects of
inflation.
Load which can be curtailed in response to a
system emergency.
Electric energy having limited or no assured
availability.
Generation by producers other than electric
utilities.
Northwest Power Pool, an organization of
electrical utilities.
Northwest Power Planning Council. A federally
chartered council comprising Idaho, Oregon,
Montana and Washington that establishes
policy on Northwest electrical energy, fish and
wildlife issues.
Operation and Maintenance Costs.
Regulatory obligation of a utility to provide
electric planning services for all customers and
to assure an adequate supply of electricity now
and in the future.
An agreement signed in 1964 by the federal
government and Northwest utilities to agree to
operate generating projects as a single entity to
make the optimum use of the water and
storage resources in the region.
The greatest amount of demand occurring
during a specific period of time.
Regulated rates based on performance
objectives, not on actual costs.
Companies seeking to sell generation to large
industrial customers or to an aggregate of
smaller customers.
Spot" price market where electricity is bought
and sold much like a stock exchange.
The worth of future returns of costs in terms of
their value now.
Public Utilities Holding Company Act.
PURPA
QFs
Rate Regulation
Real
Redesign or Reengineering
Regional Transmission Group (RTG)
Regulatory Compact
Reliability
Renewable Resource
Resource Clearinghouse
Restructuring
Retail Wheeling
Seasonal Output
Stranded Costs
Supply-Side Resources
TAC
Tariff
Public Utility Regulatory Policies Act.
Qualifying Facilities under PURPA
(cogeneration and small power production
facilities).
Supervision over rates and major decisions by
elected officials and their appointees.
Costs or rates that are corrected for the effects
of inflation.
Process corporations utilize to eliminate non-
value added work and handoffs.
New forum for energy service providers within a
specific geographic area to agree on operating
parameters and resolve issues.
. Long-term agreements between regulatory
agencies and utilities, which are usually
embodied in regulatory decisions.
A measurement of the availability over a
defined period regarding the delivery of power
to a customer.
Resources such as wind, solar, hydro, etc., in
which their availability is not limited by use.
WWP's internal employee group responsible
for overall integration of resource acquisition
activities.
Reconfiguring the market structure by opening
the generation of electricity and retail services.
to competition.
An alternative to ~raditional energy service
where customers are able to choose any
electric provider they want.
EleCtrical output from a resource which varies
in amount according to the season.
Costs associated with providing electricity that
are above market prices.
Resources that generate an electrical output in
the utility system.
Technical Advisory Committee.
A schedule filed by a utility with a regulatory
agency describing transactions between the
utility and customers in terms of type of service,
rates changed and means of payment.
Tariff Rider A separate Schedule of rates, in addition to
general tariff, intended to collect payment for
specific programs or services such as DSM.
Traditional Ratemaking Regulated rates based on costs expanded, not
on meeting performance objectives.
Transition Period for Direct Access 1998-2005, as defined by the CPUC.
Transmission Lines over which electricity from generators is
sent to distribution companies.
Transmission Availability A separate schedule of rates, in addition to
general tariff, intended to collect payment for
specific programs or services such as DSM.
Unbundled Rates Separate line-item charges for generation
transmission, distribution and other services
and programs.
Unbundled Services Functional separation of generation,
transmission and distribution services.
Customers can select generation services from
competing suppliers (direct access).
Utility Distribution Company (UDC)The regulated utility that serves as the
intermediary between the generator and the
consumer by supplying distribution services.
Variable Costs Costs that vary in direct proportion with plant
output.
Watt A basic unit of electric power equal to 0.00134
horsepower.
Weatherization A process of making buildings more energy
efficient such as the Home Insulation Program.
Wheeling The use of one utility system s transmission
facilities to transmit power of and for another
system.
Wholesale Wheeling Selling electricity to wholesale buyers to resell
to retail customers.
WNP Washington Public Power Supply System
Nuclear Project.
-.'
WSCC
WUTC
Western System Coordinating Council.
Washington Utilities and Transportation
Commission.
n'ii.
'"
Hf
...
Corp.
APPENDIX J
AVISTA'S ENERGY
EFFICI ENCY
RESOURCES
. .
A VISTA CORPORATION ENERGY EFFICIENCY RESOURCES
Summary
A vista Corporation has been operating demand-side management (DSM) programs, inone form or another, for over ten years. These programs are funded by the Energy
Efficiency Tariff Rider, a surcharge on Washington and Idaho retail electric rates, thathas been in place for over five years. Currant DSM activities are conducted by theEnergy Services Department funded by the Tariff Rider at a level of 1.0% in Idaho and
1.5% in Washington.
History
Pre-1990
1991
1992
1993-1994
1995
1996
1998
1999
1999
Energy efficiency activities conducted by A vista was limited to small
scale capitalized programs.
A vista introduced the first significant non-residential energy efficiency
programs.
A vista introduced the first significant residential energy efficiency
programs. Included was a pilot for the Switch-Saver program, whichfunded conversions of residential space heating and domestic hot water
from A vista electric to natural gas.
Based on the success of the Switch-Saver program, Energy Exchanger was
Initiated, which funded fuel conversions for all A vista Utilities residential
electric customers.
The Washington Utilities and Transportation Commission (WUTC) and
Idaho Public Commission (IPUC) approved the implementation of North
America first non-bypassable distribution charge to fund the
conservation activities of Avista Corporation. Called the DSM, or Energy
Efficiency, Tariff Rider, it was funded by electric and natural gas
surcharges (1.5% and 0.5% respectively) and administered on a two year
pilot basis.
The Tariff Rider was extended for the three-year period through 1999. The
natural gas surcharge was adjusted to 0.0% as a result of the substantial
reduction in the cost of natural gas. The stipulation was made that the
natural gas surcharge would be reestablished at a level above 0% if gas
efficiency programs could be cost-effectively offered to a broad customer
base.
The fixed sunset date for Tariff Rider funding was lifted. The only
remaining condition for termination is based upon the imposition of public
purpose legislation in Washington and Idaho.
The WUTC and IPUC approved revision to the Tariff Rider, allowing
DSM program administration to be aligned more closely with customerneeds.
The Idaho general ratecase filed by A vista Corporation resulted in the
reduction of funding through the electric surcharge collected in Idaho from
5% to 1.
The Tariff Rider
The Tariff Rider has funded the energy efficiency activities of Avista in Washington and
Idaho since 1995. In 1998 the sunset date for funding of the Tariff Rider was lifted
allowing us to administer DSM without the looming prospect of funding termination.
Recently, the Idaho general ratecase filed by Avista Corporation resulted in the reduction
of funding to the Tariff Rider in Idaho from 1.5% to 1.0%. This was mandated as a result
of a persistently positive Tariff Rider balance within Idaho.
The purpose of the Tariff Rider is to allow continued energy efficiency funding
irrespective of increased competition in the electric industry. By shifting revenue
collection from generation to distribution, several problems with historical energy
efficiency accounting are alleviated. The Tariff Rider provides a stable, predictable
source of conservation funding while eliminating concerns about capital budgeting,
accumulation of increased regulatory assets , uncertain future regulatory treatment of
capitalized investment, and future competitiveness.
The Tariff Rider mechanism maintains continuity in the promotion and support of energy
efficiency, provides for long-term resource diversity, recognizes the timing of resource
needs, promotes the transformation of consumer markets to energy efficient choices, and
provides a valuable customer service.
A vista Corporation s Tariff Rider currently collects approximately $4.5 million per year.
Local and Regional Benefits
In 1999 Avista fundamentally altered the approach to DSM from a regulatoriJy inspired
traditional utility program approach to a market segmentation approach. The marketsegmentation approach focuses on customer needs of segments (i.e. retail , office , etc.rather than on rate schedules and similar regulatory distinctions. A vista expects this
approach to allow the company to be more responsive to customer need.
In recognition of the unique needs of the limited income and physically challenged
customers, Avista has established this as its own customer segment within the strategy.The focus of this segment has been electric to natural gas conversions, enhancing energy
efficiency measure persistence by treating the heaJth and human safety issues for the
structure and the implementation of assistive technologies to improve the safety and
quality of life for the physically challenged customers.
In addition to ten customer segments, A vista has also identified fifteen technologies thatare individually managed to ensure that Avista is at the forefront of the industry in
knowledge. The technology managers have the resources and knowledge to assess the
applicability of their technology and work with individual customer segment managers to
bring it to the customer site.
In addition to local energy efficiency programs, A vista is a funding participant in the
Northwest Energy Efficiency Alliance (NEEA). NEEA is a non-profit organization
funded by the seven investor-own utilities and the Bonneville Power Administration to
pursue market transformation opportunities on a regional basis. Avista has contractually
agreed to fund NEEA for an additional five years (2000 to 2004 inclusive) with programs
operating over the next seven years (to 2006). Avista dues represent 4.0% of NEEA'
$100 million in funding authorizations over the five year funding period.
External Energy Efficiency Board
With the removal of a sunset date, continued oversight of the Tariff Rider was needed.As a result of a non-binding oversight committee consisting of regulators , public
stakeholders, environmentalists and customers was put into place in the form of the
External Energy Efficiency (Triple-E) Board. The Triple-E Board currently convenes
annually to review program design, results , and future programs. These reviews provide
an accounting of our activity, including disclosures of large projects and policy decisions
as well as expenditures, energy savings, Tariff Rider revenue and cost-effectiveness.
The meetings of the Triple-E Board supplement a trimesterly (three-times per year)
reporting process that A vista has committed to.
The Triple-E Board essentially formalizes the stakeholder involvement process that
A vista Corporation has undertaken throughout the 1990s.
Measurement and Evaluation
A vista Corporation carries out an on-going measurement and evaluation (M&E) process
for all energy efficiency programs. The objective of this process covers not only the
traditional measurement of energy savings achieved, but also extends to physical
verification of installation, preexistence, implementation process evaluations, and
accounting reviews.
Organizationally the M&E analysis is performed independent of the DSM
implementation group (i., the Energy Services Department) by the Avista Utilities
Controllers Department. This independent review has been effective at proactively
addressing issues regarding the implementation of energy efficiency programs and
projects. This extends not only to the measurement of energy savings, but also to
implementation process, regulatory compliance, strategic direction, accounting, and other
Issues.
Cost-Effectiveness Analysis
Cost-effectiveness of the energy efficiency programs is a major criteria for performance
under the Tariff Rider. Avista is currently undertaking significant new efforts to more
accurately quantify, or at least identify, the non-energy savings and customer costs of
energy efficiency measures. This is part of an effort to not only more accurately assess
the cost-effectiveness of the programs, but also to identify non-energy benefits that are of
value in marketing the programs. Organizationally, the cost-effectiveness data is through
the end of calendar year 1998. An evaluation of cost-effectiveness for calendar year
1999 is currently underway.
It is also worth noting that A vista periodically reviews the potential for providing natural
gas efficiency services to our retail natural gas customers. The initial Tariff Rider and
program filing in 1995 included a natural gas surcharge of approximately 0.5% and
corresponding program offerings. The natural gas surcharge was reduced to 0.
beginning in 1997 as a result of the lack of cost-effective program opportunities at thetime of its approval.
Avista continually monitors the weighted average cost of gas (as a proxy for the gas
avoided cost) and will reevaluate the cost-effective of natural gas programs should it
increase significantly. Avista will re-evaluate the potential for gas efficiency programs if
changes in the weighted average cost of gas, gas end-use technologies, or methods of
program delivery warrant the effort.
Since the implementation of the customer segment approach to delivering energy
efficiency programs, A vista has committed to providing the Triple-Board with
trimesterly reports detailing significant projects, implementation changes M&E activities
and cost-effectiveness studies. The most recent report is included in this appendix.
Triple-E Report
April 1 2000 to July 31 , 2000
A vista Utilities
Customer Solutions Department
Renee Coelho
John Dunlap
Jason Fletcher
. Jon Powell
Table of Contents
Introduction....... ........
""""""" ........ ..... .................. ........... .......................... ......... ..... "'"
Quantitative Calculations........ .......... ......
........ """"" ....,... ..... ... ........ ..... ........ '........., ... ......
Cost Allocation..................................................
.......................................................... 2Incentive Calculation, Capture of Analytical Data................................................................. 2
Allocation of Utility Costs to Segments and Technologies...................................................... 2
Table 1: Utility Costs Aggregated by Programs and Customer Segments...............
........ """"
Table 2: Assignment of Utility Costs to Customer Segments................................................
Table 3: Allocation of Customer Costs Across Segments and Technologies...........................
Table 4: Allocation of Direct Incentives Across Customer Segments and Technologies.............
Table 5: Allocation of Electric Savings Across Customer Segments and Technologies......
........ 8
Table 6: Allocation of Natural Gas Savings Across Customer Segments and Technologies........
Table 7: Allocation of Non-Energy Benefits Across Customer Segments and Technologies........
Table 8: Allocation of Customer Costs Across Customer Segments and Technologies.............. Cost-Effectiveness Calculations. ...... .....
"""""" """"" ... """""" .............. ...... """"'" .......
Table 9: Cost-Effectiveness Statistics by Customer Segment........................................ ...... 11Table 10: Cost-Effectiveness Statistics by Technology.................. ..................................... 11
Table 11: Net Benefits by Customer Segment.............
......... ........ ...................... """ """"
Table 12: Net Benefits by Technology.........................................................
""""""""'"
Table 13: Summary of Cost-Effectiveness Tests and Descriptive Statistics............................. Energy-Efficiency Rider Balances............................................................"""""""""""'" 14
Table 14: Calculation of Energy-Efficiency Tariff Rider Balance and Interest..........................
Measurement and Evaluation Results....
.................... ............ """"" """" .... "" ..... """"""'"
Resource Mana~ement Partnership Program............................................................,........
VendingMI$ERT . ........ ......... ..........
............... """'" ...... """ ............... """'" ... ...... ..... .....
City of Coeur d'Alene LED Traffic Lights Measurement and Evaluation Report........................... 17GlobaITech
........ ............. ..... ... """"'" """"'" ""'" ............... .............................. ........
Notable Projects, Disclosures and Policy Updates.........................
.................................. ""'"
New Technology Policy Statement............................................................"""""""""""" 19
Simple Payback Policy Statement..........................................................."""""""""""'" 22
Appendix A: Summarization of the Last Twelve Months of Activity.
............................................
Table A 1: Avista Electric Efficiency Program Twelve Month Summary...
...... ..... ........ ............,
Chart A2: Standard Cost-Effectiveness Ratios by Trimester.....
.......... ...................... ...........
TRC Costs, TRC Benefits, and Utility Costs................................. ................ """"""""""'" 28Chart A3: TRC Costs.................................................................."""""""""""""""'" 29Chart A4: TRC Benefits..........................................................
.....................................
Chart A5: Utility Costs.............................................................
....................................
Energy Savings Details................ """'"
"""""" ........ ...... .......... """""""""'" ...... .,. ........
Chart A6: Electric Savings by Trimester......................................................
""""""""""
Chart A7: Electric Savings by Segment.................................................................,......... 31Chart A8: Electric Savings by Technolo
py. ........... .......,....... ............. ...... ..... """"" """""
Chart A9: Project Breakout by kWh
(~
and 3'd Reports)........................................
............
Utility Expenditures and Tariff Rider Balances.....................................................................
Chart 10: Utility Costs (cash basis vs. cost-effectiveness basis)...........................
..............
Chart A 11: Energy-Efficiency Tariff Rider Balances...........................................................
Appendix B: Additional Descriptive Statistics....................................................."""""""""'" 35
Table B1: Breakdown of Database Projects by Type..........................................................
Table B2: Breakdown of All Projects by Type.....................
""""'" ...................................
Table B3: Breakdown of Database Projects by State.........................................................
Table B4: Breakdown of All Projects by State....
...... ....,..... ........... """'" ..... ""'" ..... ..........
Table B5: Breakdown of Database Projects by Rate Schedule............................................. Table B6: Breakdown of All Projects by Electric Rate Schedule....................................... ..... 37
Table B7: Breakdown of Database Projects by Natural Gas Rate Schedule...... """"""""""" 37Table B8: Breakdown of All Projects by Natural Gas Rate Schedule.....................................
_..
vista Utilities Triple-E Report July 2000
Introduction
This is the third Triple-E Report produced in fulfillment of Avista Corporation s commitment to
enhanced analysis and reporting made at the time of the August 1999 Schedule 90 revision.
This report covers the four-month period from April 1, 2000 to July 31 , 2000. Inasmuch as this is
the third trimesterly report, we now have one full year of data produced using the same
methodology, Consequently we have included as Appendix A several twelve-month summaries
and graphs.
Except where noted, the methodology applied in developing these numbers is unchanged from
that elaborated upon in previous Triple-E Reports. As a consequence you will find more
numerical and less written content in this report.
Future Triple-E Reports may require significant modifications to incorporate the effects of the
proposed natural gas efficiency portfolio, the implementation of proposals selected under the
Avista Request for Proposals process and other changes as they become necessary.
Page 1
Avista Utilities Triple-E Report July 2000
Quantitative Calculations
Cost Allocation
Avista uses two approaches for compiling the costs attributable to energy-efficiency activities.
1. A cash basis is employed for use in determining utility expenditures for calculation of the
Energy-Efficiency Tariff Rider balance. Both incentive and non-incentive utility expenditures
are tracked in this way.
2. An accrual method is used for purposes of determining the utility incentive costs for
calculation of cost-effectiveness. This accrual method realizes utility incentive costs for
incomplete projects at the same rate at which energy savings from those incomplete projects
are realized. For example, the methodology realizes 75% of the anticipated incentive cost
when the project is contracted to match the 75% of the expected energy savings claimed
upon contracting. This approach is intended to match the drop-out rate of projects as they
progress through "the pipeline" as well as the utility resources invested in the project at each
stage.
Incentive Calculation. Capture of Analvtical Data
The calculation of site-specific customer incentives was being centralized during this trimester
with the calculations performed by the Analysis Team. This change was made in order to ensure
consistency in the calculation of incentives and to provide the opportunity for the Team to capture
non-energy benefits and identify measurement and evaluation (M&E) opportunities.
A user-friendly incentive calculation model has been created to capture project-specific data. At
the moment it is too early to determine if this will result in improved identification quantification of
non-energy benefits, but we are certain that this approach will virtually guarantee that all
incentives are calculated in compliance with Schedule 90 and the policy manual that has been
developed to guide implementation.
It is hoped that this calculation can be transitioned back to those responsible for program
implementation once the model has proven itself and a sufficient body of precedence on policy
issues has been compiled.
Allocation of Utilitv Costs to Seaments and Technoloaies
Whenever possible , utility non-incentive costs are directly assigned to the customer segments
identified in this report. However, a sizable proportion of implementation activity covers multiple
segments. These costs are allocated to either a general implementation or a general M&E
account number.
At the close of the trimester the lead coordinator for Energy-Efficiency Tariff Rider opportunities
allocates the general implementation costs to each individual segment. Similarly, the Analysis
Team allocates general M&E costs to each individual customer segment.
Once these general costs have been allocated to customer segments, the customer segment
managers allocate all costs assigned to their segment (both those assigned to that segment as
well as those allocated from the general implementation account) to the various technologies.
Page 2
Avista Utilities Triple-E Report July 2000
The final result is an allocation of all utility non-incentive costs across the segment ( technology
matrix.
Incentive costs are all directly assigned to the segment/technology matrix based upon the nature
of the project and customer.
Refer to Tables 4 for utility cost allocations across programs, customer segments, and
technologies
Refer to Tables 6 for the allocations of electric and therm savings across customer segments
and technologies.
Refer to Tables 8 for the allocations of customer costs and non-energy benefits across
customer segments and technologies.
Page 3
Avista Utilities Triple-E Report July 2000
Table 1 Utilit Costs A ated b Pro rams and Customer Se ment~
Implementation Incentives M&E TOTAL
SEGMENTS
Agricultural 219 32,470 193 882
Government 103,711 217,232 790 324 732
Food Service 305 164 945 29,413
Heallh Care 16.028 10,203 945 175
Hospitality 41,295 112,654 193 157,142
Limited Income 11,328 365,504 376,832
Manufacturing 109 579 121,501 8,488 239 568
Office 29,621 27,155 269 044
Residential2 $56,721 105,580 883 163,184
Retail 504 12,686 986 27,177
GENERAL
General (Implementation)624,022 624 022
General (M&E)56,669 669
OTHER EXPENDITURES
t\EEA 3 793 375,577 378 370
Leases4 $26,249 249
OLD PROGRAMS
LED Traffic Signals 120 120
New Technologies 373 27,169 27,543
Prescriptive HVAC
Prescriptive Lighting 1 ,440 440
RMPF'
Site Specific 053 112,622 115 675
SS-VFD 35.577 35,577
Trade Ally 345 930 585
TOTAL 066,145 562,724 92,361 721,230
BROKEN OUT BY CATEGORY
Total assigned to segments 409 310 012,148 692 1,457 151
Total assigned to general 624 022 56,669 680,691
Total assigned to other 29,042 375,577 404 619
Total assigned to old programs 771 174,998 178 770
TOTAL 066 145 562,724 92,361 721,230
CATEGORY ASA PERCENT
Total assigned to segment 15.37.53.
Total assigned to general 22.25.
Total assigned to other 13.14.
Total assigned to old programs 6.4%
TOTAL 39.57.o/~1 100.
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 trimesters 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 are excluded from all other tables.
5) The Government segment includes educational institutions as well as federal, state and local governments.
Page 4
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A vista Utilities Triple-E Report July 2000
Cost-Effectiveness Calculations
The cost-effectiveness calculations are completed based upon the industry-standard California
Standard Practice Manual for each of the four tests.
Quantifiable non-energy benefits are included in these calculations. Avista has been aggressive
in identifying these non-energy benefits where they are quantifiable.
The largest non-energy benefit has usually taken the form of quantifiable deferred capital
expenditures on the part of the customer (resulting from replacing an existing end-use with a
limited life remaining with a high-efficiency alternative with a substantially longer life). A
methodology for quantifying this substantial benefit for inclusion in cost-effectiveness calculations
was under development during this trimester but was not applied to the calculations for this
report.
Maintenance savings, particularly for lighting end-uses , have also been significant.
To date Avista has not found a sufficiently rigorous calculation of other non-energy benefits
(productivity, security etc.) to include them in the calculation of cost-effectiveness. To the extent
that these benefits are non-quantifiable the resulting cost-effectiveness calculations are
conservative.
Refer to Tables and 10for summaries of cost-effectiveness results by customer segment and
technology.
Refer to Tables 11 and 12 for summaries of net benefits by customer segments and technologies.
Refer to Table 13 for further details on the calculation of the cost-effectiveness ratios and related
descriptive statistics.
Page 10
Avista Utilities Triple-E Report July 2000
Table 9 Cost-Effectiveness Statistics by Customer Segment
Total Non-Resource Utility Cost Participant Participant
Cost Test Test Test Test
Agricultural
Government
Food Service 1.43 15.0.43Health Care
Hospitality 0.45
Limited Inoome 0.44 N/A
Manufacturing 19.0.44Office594.(4.31)
Residential 0.49 1.43
Retail 0.41
PORTFOLIO
Table 10 Cost-Effectiveness Statistics by Technology
Total Non-Resource Utility Cost Participant Participant
Cost Test Test Test Test
Appliances 1.42 0.44Assistive Technologies N/A N/A N/A N/A
Compressed Air 0.43
Controls 0.46
HVAC
Industrial Process 11.0.46
Lighting
Monitoring N/A
Motors
New Tech
Renewables NlA N/A N/A N/AResource Management (0.70)(0.70)N/A
Shell 4.44
Sustainable Building N/A
PORTFOLIO
NOTES:
Costs for this trimester's portion (1/3) of the Natural Gas Awareness Campaign are included in Residential.Costs associated with membership in NEEA are excluded from all cost-effectiveness calculations.
Costs associated with outstanding leases are excluded from all cost-effectiveness calculations.
N/A" is listed for segments and technologies with benefits, but no costs.
Page 11
vista Utilities Triple-E Report July 2000
Table 11 Net Benefits b Customer Se ment
Total Non-
Resource Utility Cost Participant Participant
Cost Test Test Test Test
Agricultural 197 96,727 421,213 (383,016)Govemment (87 935) $407,609 027 946 100,751)Food Service 513 700 225,517 (183,855)Health Care (104.491) $(66,998) $751 (131,341)Hospitality 298 136 717 532,149 (453,098)Limited Income (231 855) $(231 855) $858,269 213,556)Manufacturing 1,413,317 380 186 2.435,154 021 750)
Office 449,408 (15 655) $624,141 (153,705)Residential (444 004) $126 848 562.438 (1,212,046)
Retail (58,361) $(49 711) $169 (127 922)
PORTFOLIO 092 087 838,567 791,747 981,040)
Table 12 Net Benefits b Technolo
Total Non-
Resource Utility Cost Participant Participant
CostTest Test Test ill!Appliances (68,577) $590 313 567 (500,858)Assistive Technologies
Compressed Air 58,924 92,257 244,619 (185,696)
Controls 281 161 553,028 339,189 029,915)
HVAC (376,727)110,948 807 980 396 107)Industrial Process 201,158 216,612 688,834 (487 547)
Lighting (143,521)(77 588)620 079 (757 825)
Monitoring (32,129)(32,129)(32,129)Motors (37 984)(165)155 (62 139)New Tech 831 105)461.446 (374,614)Renewables
Resource Management (126,953)(126,953)(45,545)(85,724)
Shell 254.418 586 337.423 (63,971)Sustainable Building 514)514)514)
PORTFOLIO 092,087 838 567 791 747 981 040)
NOTES:
Net benefits are calculated by subtracting costs from benefits.
Costs and benefits included in each cost-effectiveness test are detailed in Table 13.
Costs for this trimesters portion (1/3) of the Natural Gas Awareness Campaign are included in Residential.Costs associated with membership in NEEA are excluded from all cost-effectiveness calculations.
Costs associated with outstanding leases are excluded from all cost-effectiveness calculations.
Page 12
Avista Utilities Triple-E Report July 2000
Table 13 Summary of Cost-Effectiveness Tests and Descriptive Statistics
Regular Income Limited Income Overall Regular Income Limited IncomeTotal Resource Cost Test QQ!1fQ!iQ.portfolio portfolio Utllltv Cost Test portfolio portfolio Il2tl.!2lli!.Electric avoided cost 266.327 532.751 799.079 Electric avoided cost 266,327 532 751 799.079Non-Energy benefits 001 662 001.662 Natural Gas avoided cost (288,016)(353 470)(641 486)Natural Gas avoided cost (288,016)(353.470)(641.486)UCT benefits 978,312 179.281 157 593TRC benefits 979 974 179.281 159.255
Non-incentive utility cost 083 832 45.632 129.464Non-incentive utility cost 083.832 632 129.464 Incentive cost 824 057 365,504 189.562Customer cost 572 199 365 504 937.703 UCT costs 907 890 411 136 319 026TRC costs 656.031 411 136 067.167
UCT ratio
TRC ratio Net UCT benefits 070 422 (231,855)838 567Net TRC benefits 323,943 (231,855)092,087
Regular Income Limited Income Regular Income Limited Income OverallParticipant Test portfolio portfolio portfolio Non-Participant Test portfolio portfolio portfolioBill Reduction 679 957 858,269 538.227 Electric avoided cost savings 266 327 532.751 799 079Non-Energy benefits 001 662 001.662 Non-Part benefits 266.327 532 751 799.079Participant benefits 681.619 858.269 539,889
Revenue loss 125 922 335 171 7,461 092Customer project cost 572,199 365 504 937,703 Non-incentive utility cost 083,832 45,632 129,464Incentive received 824 057 365.504 189,562 Customer incentives 824 057 365.504 189.562Participant costs 748.141 748,141 Non-Part costs 033 811 746.307 780 118
. Participant Test ratio N/A Non-Part. ratioNet Participant benefits 933 478 858,269 791.747 Net Non-Part. benefits 767 484)213,556)981 040)
Descriptive Statistics
Annual kWh savings
Customer cost/kWh $
Non-incentive utility cost/kWh $
Electric avoided cost/kWh $
Incentive cost/kWh $
Regular Income
portfOlio
214,161
17 $
07 $
21 $
05 $
Limited Income
portfolio
738.035
21 $
03 $
31 $
21 $
Overall
portfolio
16.952,196
NOTES:
Costs for this trimester s portion (1/3) of the Natural Gas Awareness Campaign are included in Residential.Costs associated with membership in NEEA are excluded from all cost-effectiveness calculations.
Costs associated with outstanding leases are excluded from all cost-effectiveness calculations.
N/A" is listed for segments and technologies with benefits. but no costs.
Page 13
Avista Utilities Triple-E Report July 2000
Energy-Efficiency Tariff Rider Balance Calculations
The Energy-Efficiency Tariff Rider balance has been reduced by over 50% during the course of
this trimester. Within Washington the ending balance fell by 45%, as opposed to Idaho (where
the Rider was reduced to 1.0% in August, 1999) where the balance fell by 77%.
It is anticipated that the Idaho Energy-Efficiency Tariff Rider balance will reach zero by the end of
September, 2000. To date, there has been no change in the level of program delivery to Idaho in
spite of the reduced Rider level.
The Washington balance is projected to reach zero by the Spring 2001.
Refer to Table 14 for the most recent update to our Tariff Rider balance calculation.
Page 14
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5
Avista Utilities Triple-E Report July 2000
Measurement and Evaluation Results
Attached are brief descriptions of measurement and evaluation (M&E) efforts that have occurred
during the course of the trimester, Additional work has been done within this area, the results ofwhich will be presented at the Spring / Summer 2001 Triple-E meeting.
It should be noted that Avista is reducing the M&E resources that will be devoted to providing
independent testing of unproven energy efficiency devices, Based upon our experience it is more
appropriate to rely on other independent third-party laboratories to provide this type of testing.This change in emphasis does not extend to measuring the energy impact of commercially
available and proven energy efficiency devices claimed as part of our program portfolio,
Resource Manaaement Partnershio Proaram (RMP
Resource managers assigned to participating school districts initiate and maintain behavioral
operational and hardwired energy efficiency measures at facilities throughout the school district.
Energy savings claims from the RMPP program are based upon comparisons of actual
comprehensive meter reads from all meters of each participating school district. Provisions have
been made to appropriately measure and claim re-adoption of the short lifespan behavioral and
operational measures. The methodology adopted for the measurement of re-adoption isconsistent with the calculation of the weighted average lifespan of the energy savings claimed
from this program. (The weighted average energy savings in this category is only four years).
Hardwired measures that are installed in facilities participating in the RMPP program are claimed
in the specific technology category involved rather than as part of the resource management
technology.
Energy savings from this program have been gradually declining over time as the most cost-
effective measures are acquired. During this trimester only 62 007 annual kWh were claimed in
the Government segment under the resource management technology. As previously mentioned
this does not include the acquisition of substantial hardwired lighting efficiency measures, as
those savings accrue to the lighting technology.
Vendin.QM1$ER
As indicated in the last trimester report, Avista is continuing a long-term evaluation of theVendingMI$ERTM vending machine control device. At present Avista is claiming 1500 annual
kWh per device, This amount was based upon manufacturer data, independent tests and furthertests completed by Avista.
Based upon M&E completed to date it appears that the actual savings of devices installed by
Avista is closer to the range of 1 000 to 1 200 kWh per year.
Due to the substantial variance in the savings from device to device this M&E project will continue
into at least the next trimester before the past and future energy savings claims are corrected.
Additionally, Avista has expanded the M&E effort to attempt to identify other potential factors in
determining the energy savings on installed devices, Specifically, we are interested in
determining if the newer machines achieve greater energy savings as a result of their larger
physical size and increased panel illumination. Past measurements by Avista have not
consistently recorded machine size, type or vintage.
Page 16
Avista Utilities Triple-E Report July 2000
Individual Droiect reviews
Citv of Coeur d'Alene LED Traffic Liqhts Measurement & Evaluation ReDort
Methodology:
A complete intersection-by-intersection inspection to verify what was actually installed.
Savings were determined utilizing readings from the existing kWh meter before and afterinstallation, Calculated estimates were used for one new intersection, Hanley and Ramsey.
Findings:
Light Count Error: The initial report shows 16 through lanes at Government and Ironwood, butthere are only 13 through lanes. This error is relatively insignificant, resulting in an
overstatement of savings projections by 1 700 kWh (about 1 %,
Run Time Assumptions: Conservative run times were used for the original estimates. As a
result, savings projections in the Avista Service Territory were 15% below actual results
(28 000 kWh).
Exclusion of Kootenai Electric Intersections: No savings were ever claimed for the three
intersections in Kootenai Electric Service Territory. The savings for the three Kootenai
Electric Intersections is 50 000 kWh.
Winter Peaking Phenomenon: Five downtown intersections exhibited an unexpected "winterpeaking" phenomenon. Results are shown below:
Intersection
SecondfThird and Sherman
Fourth/Fifth and Sherman
Seventh and Sherman
Typical Summer Usage
800 kWh
400 kWh
760 kwh
Winter Peak
5000 kWh
3600 kWh
2400 kWh
Initial assumptions were that the increased usage was the result of (possibly unnecessary)
cabinet heaters. Upon further investigation with the City s Signal Supervisor it wasdetermined that these cabinet heaters have not been in use, The City Signal Supervisor is
well aware that cabinet heaters are not needed with modern controls. As a result, heatershave not been used for many years.
The City was also surprised by the winter peaking phenomenon , and decided to investigate.It was learned that the winter peak is the result of extensive use of Christmas lighting in the
downtown area. The Coeur d 'Alene City Accounting Department is aware of the increased
winter usage, and budgets accordingly.
Conclusion: The savings should be adjusted upward from 144,000 kWh to 222,000 kWh.This adjustment will be made in the 811100 to 12131/00 report.
GlobalTech 1M
GlobalTech 1M is a device permitting the reduction in energy use of lighting systems at specific
times of the day, Avista has worked with two outdoor area lighting demonstration projects
within the service territory. Data is being collected regarding reductions in energy use
reductions in light output and overall effect upon the end-use,
Page 17
vista Utilities Triple-E Report July 2000
The technology employed in the GlobalTechTM device will transition from being incentivized
under the New Technology incentive tier to the standard high-efficiency incentive tier in
January of 2001. This transition to standard efficiency incentives is based upon the amount
of time that has elapsed since the project became commercially available in our area,
Page 18
A vista Utilities
ChartA10
Triple-E Report July 2000
Utility Cost (Cash Basis vs. Cost-Effectiveness Basis)
500 000
$2,000 000
500 000
000 000
$500 000
ChartA11
IccaSh I8CE
1 sl Report 2nd Report 3rd Report
500,000
Energy-Efficiency Tariff Rider Balances
000 000
500 000
000,000
500 000
000,000
500 000
000 000
$500 000
$(500 000)
:...
6..
:...
6..(II rn CO
...,
u..:2;:2;
...,...,...,
u..:2;:2;
...,...,
I-+-Washinglon -Idaho -'-Syslem I
Page 34
vista Utilities Triple-E Report July 2000
The cost-effectiveness measurement of expenditures is persistently above the cash basis due to
the increase in energy savings during this time period. More projects are coming into the pipeline
(and being partially realized on an accrual basis for cost-effectiveness purposes) than are being
completed (and being paid on a cash basis),
Refer to Chart A 10 for utility expenditures, calculated based upon both the cash basis and the
cost-effectiveness basis.
The Energy-Efficiency Tariff Rider balance has also been captured for the entire system , as wellas Washington and Idaho individual/yo Clearly the Idaho balance is very near zero and the
Washington balance is falling dramatically. This tends to indicate that a change in the level of
activity may be necessary in the summer of 2001 , as well as the consideration of an increase
both Tariff Riders.
Refer to Chart A 11 for the Energy-Efficiency Tariff Rider balance in Washington, Idaho and
system-wide.
Page 33
Avista Utilities Triple-E Report July 2000
Chart A9 Project Breakdown by kWh (2nd and 3rd Reports)
Lighting
24%
LED Exit & Traffic
VendingMiser
Page 32
15,ci.II)::i II)t.)0:((ij II)a::c::a::!II ill u..
::2 a::::i
Chart AS Electric Savings by Technology
000 000
000 000
000,000
12,000,000
000 000
000 000
000 000
.r:.
...
II)
(,)
II)I!?.r:.t.)t.)
:.:(
11) t.)c::Q) C) .r:.ii3!!1 t.) c::
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(,)
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Avista Utilities
Chart A6
000 000
15,000 000
000 000
000 000
000 000
000 000
Chart A7
000 000
000 000
000 000
000 000
Triple-E Report July 2000
Electric Savings by Trimester
1 5t Report 2nd Report 3rd Report
Electric Savings by Customer Segment
Page 31
Avista Utilities Triple-E Report July 2000
The energy-efficiency programs have saved over 43 million 1s1 year kWh's (nearly 5 amW's) inthe last twelve months.
The most recent trimester has been the highest energy savings period to date. However, givenonly three trimesters it is difficult to call this an identifiable trend,
The energy savings are most concentrated in the Government segment. This is undoubtedly
attributable to Avista s highly successful Resource Management Partnership Program (RMPP).
The savings from that program are generally declining as the most cost-effective measures are
gradually being adopted within the participating school districts.
To put the success of the Government segment into perspective, the energy savings within thissegment during this twelve-month period exceed the savings achieved in the Regular-Income andLimited-Income residential segments combined. This is not an indication of a lack of residential
energy savings (these two segments are the fourth and fifth-ranking segments in terms of
acquired energy). It is instead a measure of substantial first year kWh energy savings comingfrom RMPP.
The Office, Manufacturing and Residential segments are the next largest beneficiaries of energy
savings. These savings are primarily attributable to lighting and HVAC savings in the medium tolarge office segment.
When energy savings are broken out by technology the HVAC segment is the largest contributor,
This is somewhat misleading, given that much of these electrical savings come from electric to
natural gas conversions, The calculation of electrical savings fails to fully realize the energy
consumed on the natural gas portion of the conversion.
Lighting and controls are the next largest energy saving technologies, This can also be
misleading since a significant proportion of the controls savings are attributable to lighting
controls.
In the period of time covered by the second trimesterly report, there was some concern internally
that there was too great of a reliance on "mass" projects (projects generally implementing
measures with individually small savings but a large market). These include LED exit signs, LEDtraffic lights and VendingMI$ERTM. Additionally, fighting is a fairly routine measure that is often
implemented in small quantities.
Analysis of the second and third trimester energy savings has indicated that 62% of savings are
attributable to site-specific type projects. Most of the remainder (24%) comes from lightingprojects. The LED exit sign and LED traffic light program savings have fallen substantially as
those measures complete their aggressive marketing campaign under the enhanced New
Technologies incentive structure. Future follow-ups to these measures are expected todemonstrate that these technologies have become much more accepted and perhaps even
industry standard" inCY 2001 and beyond.
While we have no particular baseline upon which to measure this program mix, it seems to be areasonable diversification of the overall energy-efficiency portfolio.
Refer to Charts A6 - A8 for electric savings broken down by trimester, segment, and technology.
Refer to Chart A9 for the kWh breakdown by project type.
Page 30
Avista Utilities
Chart A3
Chart A4
Chart AS
Triple-E Report
Incentive
48%Non-Incentive
52%
Page 29
July 2000
TRC Costs
TRC Benefits
Utility Costs
vista Utilities Triple-E Report July 2000
Notably, at this point, 29% of the TRC benefits are derived from quantifiable non-energy benefits.
If our ability to quantify those benefits increases we should see significant movement in this
relationship, as well as an increase in the TRC ratio,
The results of the TRC test are, to a significant degree, not immediately within the control of the
utility. 71 % of the TRC costs are customer costs, with the remaining 29% being non-incentiveutility costs.
The utility costs are fairly evenly split between incentive and non-incentive costs. The proportion
of utility costs going towards incentives has increased with the adoption of the generally higher
tiered incentives in the most recent revision of Schedule 90.
Refer to Charts A3 - A5 for TRC Test benefits and costs , and Utility Cost Test costs.
Page 28
Avista Utilities Triple-E Report July 2000
Table A1 Avlsta Electric-Efficiency Program Twelve-Month Summary
Aug. 1 '99 to Nov. 30 '99 (4 months)Dec. 1 '99 to Mar. 30 00 (4 months)Apr. 1 00 to Jul. 31 00 ( 4 monlhs)Aug. 1 '99 to Jul. 31 '00 (12 months)Tolal Rosource Cost Test Reo. Inc.Um, Inc.f2!tI2II2 !JmJn&.f!!!:I!2U2 Llm.lnc.Portfolio Llm.lnc.Elect"c Avoided Cost $303.697 457.790 761.487 066,877 599,880 666.757 266,327 532,751 799,078 636,901 590.421 $ 11,227,322Non.energy benefits $76.850 76.850 775 461 $775,461 001,662 001 662 $ 3,853.973 S S 3,853,973Gas Avoided Cost $1859.4241 S 163,443\ $1922.867 i209.8321 $1136.4131 /346,245 1288.016) $1353.470) $(641,486 S /1357.2721 S 1553,3261 $ 11910.598)
TOTAL TRC BENEFITS $521,123 394,347 915.470 632.506 463,467 095,973 979,973 179,281 159.254 S 12,133.602 037,095 $ 13.110.697
Non.lncenlive Utilily Cost $905,457 29,569 935.026 080.782 95.227 H6.009 083,832 45,632 129.464 070,071 HO.428 240.499Customer Cost S 273,339 291,377 564,716 103,311 414.492 517.803 572,199 365.504 937,703 948.849 071 373 020.222TOTAL TRC COSTS 178,796 320,946 3.499,742 184,093 509,719 693,812 656,031 411,136 067,167 S 10,018,920 241.801 11,260,721
TRC BIC Ratio 0.44NetTRC benefits S 342,327 73,401 415,728 448,413 (46,252) $402,161 323,942 (231,855) S 092.087 114.682 (204.706)909,976
Ulility Cosl Te.t
Electric Avoided Cost S 303,697 $457.790 761 487 066,877 S 599,880 $666 757 266,327 532,751 799,078 $ 9,636.901 S 590,421 S 11 227 322Gas Avoldod CoSI S 1859.424) 163,443) 1922,8671 1209,832\ S 1136.413) $i346,245 /288.016\ $/353,4701 $1641.486 357,272' 1553.326\ S 11 910.5981
TOTAL UTC BENEFITS $444 273 394 347 838.620 857 045 463,467 320,512 978.31 I 179.281 157 592 279,629 037 095 316,724
Non.lncenlivo Utilily Cost $905.457 29.569 935 026 080.782 95,227 H6.009 1.083,832 45,632 129,464 070 071 170.428 240.499Incenllve Utllily Cost $595.293 291.377 886,670 506.209 414 492 920.701 824,057 365.504 189.561 925,559 071.373 996,932TOTALUTCCOSTS $500,750 320.946 821,696 586 991 509,719 096,710 907,889 41\,136 319,025 995,630 241 80\237.431
UCT BIC Rallo
Net UCT benefits $943.523 73,401 016,924 270,054 (46.252) S 223,802 070.422 (231 855) S 838,567 283 999 (204.706) S 079.293
Partlclosnl To.t
BillsV9S $4.471 020 456.505 927,525 067.573 276,036 343609 679,957 858.269 538.226 $ 14218.550 590,810 S 16,809,360Non.energy benefits S 76,850 76.850 775,461 775,461 001,662 001 662 853,973 853,973
TOTAL PART. BENEFITS $547.870 456,505 5.004375 843,034 276,036 119.070 681,619 858,269 539 888 S 18,072.523 590.810 S 20,663,333
Cuslomer Cost $273,339 $291,377 564716 ;:03,311 S 414,492 S 517.803 572,199 365.504 937,703 $ 6,948.849 $ 1,071 373 S 8,020,222Incentive Utllily Cost S (595.293) $1291.377) 1886,670 508.209\ S /414.492\ S i920,701 1824,057! /365,504\ $ /1.189,561)$ 11.925.5591 $ 11,071,373) S 12.996,9321TOTAL PART. COSTS S 678.046 678046 597 102 597 102 748,142 748.142 023.290 023.290
Participant BIC Ratio #DlVIOI #DIVIOI #DIVIOI #DIV/OI
Partlclpanl nol benefits $869.824 456,505 326,329 245,932 276,036 521,968 933,477 858,269 791,746 $ 13,049,233 590,810 S 15,640,043
Non.Partlclpanlloloctrlc! To.'
Eioclric Avoided Cost 5 3.444.273 394.347 838,620 066.877 599.880 666,757 266.327 532.751 799.078 777.477 526.978 $ 10,304.455rOTAL NON.PART BENEFITS $444,273 394,347 838,620 066 877 599,880 666,757 266,327 532.751 799,078 777.477 526,978 5 10,304 455
Rovenue Loss $274.491 619.887 894378 537 681 535.961 073,642 125,922 335,171 461 093 $ 16,938,094 491,019 $ 20.429,113Non.lncont;ve Ulilily Cost $905.457 29,569 935,026 080,782 95.227 H6,O09 083,832 45,632 129.484 070,071 170,426 240.499Incentive Ulilily CoSI $595,293 291 377 886.670 506.209 414 492 920,701 624,057 365.504 189,561 925.559 071.373 996,932
TOTAL NON-PART COSTS $775.241 940,833 716,074 124 672 045,680 170,352 033,811 746 307 780.118 $ 21,933,724 732.820 $ 26 666,544
Non.Particlpant BIC ratio 0.44 0.40Non-PaniClpan! net benefits $330.968) $(546,486)$ (4,877,454)$ (4.057,795) S (1,445.800) 5 (5.503,595)$ (4,767.484) S 213.556) $(5,981,040)$(13 156 247) $(3,205.842)$ (16.362.089)
Chart A2 Standard Cost-Effectiveness Ratios by Trimester
- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -
00
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00 - - - - - - - - - - - - - ..
.. - - - .---------------
00 . - - - - - - - - - - - - - - .. -
-------------------------------
TRC UCT Part Non.Part
Page 27
Avista Utilities Triple-E Report July 2000
Appendix A
Summarization of the Last Twelve Months of Activity
Detail Summary of Cost-Effectiveness Results
Overall the programs are cost-effective per the following:
TRC Test (1.17 benefiUcost (B/C) ratio, $1.9 million of net societal benefits)
UC Test (1.49 BIC ratio, $3.1 million of net utility benefits)
Participant Test (4.11 B/C ratio, $15.6 million in net benefits)
In summary, the program portfolio is a cost-effective resource, both societally and to the utility,
and the programs have very strongly benefited participating customers.
This analysis has been completed using the avoided costs identified in the Company s mostrecent electric and gas Integrated Resource Plans, Since those avoided costs are below the
Company s rates (the difference being the non-commodity cost), it is mathematically impossible
for the portfolio to pass the Non-Participant Test. This test has resulted in a 0,39 Non-participanttest B/C ratio and a negative $16.4 million in net non-participant benefits.
The interpretation of the Non-Participant Test (also known as the Rate Impact Measure) is to
determine the upward pressure on rates imposed by the energy-efficiency programs. It is notable
that upward rate pressure does not necessarily result in increased energy bills (even including
participant costs) due to the decreased consumption resulting from these programs.
Having a full three trimesters of data, we can now begin to tentatively determine some trends in
the cost-effectiveness results. The TRC Test results seem to be fairly stable, probably because itis a fairly broadly-based test. There is a slight but persistent upward trend in the cost-
effectiveness.
The Utility Cost Test and the Participant Test seem substantially more variable. The decreasedUCT ratio and increased Participant Cost Test ratio in the 2nd trimester is notable. Investigationindicates that this is attributable to unusually high investments in durable equipment and
infrastructure made during this time period,
The Participant Test is well below one, for the reasons previously explained, and fairly stable at
that level.
Refer to Table A 1 for the results of each of the last three trimesters followed by the overall cost-
effectiveness of the entire year. The trimester results are also graphically represented in ChartA2.
Page 26
Avista Utilities Triple-E Report July 2000
Energy savings will be calculated based upon the same definition of the baseline and
high-efficiency project.
The customer cost will be adjusted as necessary to compensate for significant
differences in the physical life of the basecase and the high-efficiency scenarios.
The customer costs will not include adjustments for non-energy benefits , although
non-energy benefits are to be tracked for inclusion in cost-effectiveness calculations.
The customer costs included in cost-effectiveness calculations will not include
adjustments for customer direct or indirect incentives.
QualifyinQ Projects
Projects that are characterized by having a significant degradation of end-use quality
do not qualify for either customer incentives or for credit toward energy savings
calculations. Degradation of savings is defined as a significant reduction to thevalue, comfort, convenience or other attributes of an end-use. Any non-trivial
reduction in the safety of any end-use will disqualify the project. This will apply to
both residential and non-residential projects.
For example, degradation of end-use would disqualify projects such as:
A lighting retrofit that reduces the lighting level below industry standards.
Changes in HV AC temperature settings which are not associated with any
other efficiency project.
Reductions in lighting levels which are deemed to adversely effect safety.
The closure or destruction of a facility.
Examples of projects which are not disqualified due to degradation of end-use
include:
Reductions in lighting levels which do not adversely effect comfort, safety or
any other end-use attribute.
Changes in HV AC temperatures when facilities are unoccupied or changes in
a manner which do not adversely effect comfort or any other end-useattribute.
Changes in an industrial process which reduces the energy use without
effecting the quantity or quality of the product.
Changes in facility operating hours which do not materially effect the
business value of the facility.
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Avista Utilities Triple-E Report July 2000
Simole Pavback (used for Direct Incentives)
Simple payback is the customer cost, as defined within this policy, divided by the first
year electric bill savings accruing to the customer. The incentive level will then bedetermined by applying that simple payback to the tier structure defined in Schedule
90,
Data collection will be the joint responsibility of the technical lead and the account
executive, Coordination and entry of the data into SalesLogix will be the account
executive s responsibility.
The account executive is responsible for submitting the data to Partnership Solutions
for calculation of simple payback before the evaluation is submitted to the customer.
Partnership Solutions will return to the account executive the final results of theincentive calculation.
Capital cost estimates can be arrived at in many ways (e.g. Means Mechanical
Estimating, contractor bids, industry standards, and in-house analysis).Simple payback calculations are not to include the values of non-energy benefits.
The simple payback calculation will not include adjustments for interactive non-
electric energy effects (e.g. the impact of a lighting retrofit on natural gas HVAC
systems).
The calculation will include adjustments for interactive electric energy effects (e.g. theimpact of a lighting retrofit on electric HVAC systems).
The calculation will include those non-electric effects that are a direct consequence of
the project (e.g. the increase in therms as a result of an electric to natural gas
conversion).
Calculation is to include all values for electric energy savings, kWh, kW, kVAR.The calculation will include the bill savings resulting from kWh, kWand kVAR impactsof the project, plus any associated electric bill tax or fee impacts.
Similar measures (e., lighting and lighting controls or HVAC and HVAC controls)
can be bundled for calculations, but dissimilar measures (e,, lighting and VFDs)must be treated as separate projects.
Sales tax paid by the customer and associated with the energy efficiency portion of
the will be included as a cost for the simple payback calculation.
_..
Calculation of Customer Cost (used for Direct Incentives)
The customer costs to be included in the simple payback calculation will be only
those associated with the energy-efficiency portion of the project relative to a defined
baseline. Energy savings will be calculated based upon the same definition of the
baseline and high-efficiency project.
The calculation of customer costs will not include any deductions for non-energy
benefits, but the baseline and high-efficiency projects will be defined to exclude these
costs and benefits to the extent possible.
Any direct or indirect incentive received by the customer will not be used to reduce
the customer cost for purposes of the calculation of simple payback.
The installation of used equipment does qualify for direct incentives, assuming that
the equipment meets all other standards,
The appropriate basecase for projects where existing equipment is in imminent
failure is the equivalent code minimum or industry standard , whichever is moreenergy efficient. Imminent failure is defined as equipment that is likely to fail within
the next year and is likely to be replaced with new equipment.
The appropriate basecase for new construction or substantial renovation is also the
code minimum or industry standard, whichever is more energy efficient.
Calculation of Customer Costs (used for Cost-Effectiveness)
The calculation of customer cost for inclusion in cost-effectiveness calculations will
include only those costs associated with the energy-efficiency portion of the project.
Page 24
Avista Utilities Triple-E Report July 2000
8 cents per first-year kWh for projects with simple paybacks in excess of 72 months
6 cents per first-year kWh for projects with simple paybacks between 48 and 72
months
4 cents per first-year kWh for projects with simple paybacks between 18 and 48
months
No customer direct monetary incentives are granted for projects with paybacks under
18 months
New Technoloav : These are projects granted new technology status per the standards
outlined in the preceding New Technology policy. Incentives for the savings directly
attributable to the project (excluding any market transformation effect) are:
14 cents per first-year kWh for projects with simple paybacks in excess of 72 months
12 cents per first-year kWh for projects with simple paybacks between 48 and 72
months
10 cents per first-year kWh for projects with simple paybacks less than 48 months
Fuel-Conversion: Projects involving the conversion of an end-use from electric to natural gas.
Projects must be served by Avista electricity, but need not be served by Avista natural
gas, The entire reduction in electric kWh load is applied to the incentives below:
3 cents per first-year kWh for projects with simple paybacks in excess of 72 months
2 cents per first-year kWh for projects with simple paybacks between 48 and 72
months
1 cents per first-year kWh for projects with simple paybacks between 24 and 48
months
No customer direct monetary incentives are granted for projects with paybacks under
24 months
Because the tiered structure of each of these three categories is based upon the projects simple
payback, it was necessary to develop a written standard for the calculation of simple payback.
The standardization of the calculation promotes consistent calculations in full compliance with
Schedule 90. In addition to the written policy, a spreadsheet model was developed to perform the
calculations.
The process of incentive calculation also incorporates the collection of additional project data for
use in cost-effectiveness calculations.
The most current written policy on simple-payback calculations is attached below.
Standards for the Calculation of Customer Simple
Pay backs for Application to Schedule 90 Incentives
Non-Enerav Benefits
Data regarding non-energy benefits is to be collected by the technical project lead
and by the account executive with the entry into SalesLogix being the. account
executive s responsibility.
Non-energy benefit data will be incorporated into cost-effectiveness calculations by
Partnership Solutions,
Non-energy benefits are not to be included in the calculation of simple payback for
purposes of determining the customer s incentive.
Page 23
Avista Utilities Triple-E Report July 2000
The life of the units are unknown and potentially variable (due to UV degradation).
Red-light runtime is unknown.
Capital cost of yellow and green lights are significantly above red lights (but red-light
only installations are available).
Sufficient number of manufacturers, but none within our service territory.
Appropriateness
Due to the slow degradation instead of catastrophic failure, there is a non-energy
safety benefit.
There are also reduced costs (and increased safety) due to the reduction in the
number of incandescent lamp changes required.
Cost-effectiveness
. Red-lights are cost-effective (reference attached cost-effectiveness analysis).
Green lights and yellow lights are not cost-effective at this time,
Timeline
New technology incentives guaranteed for one year and reevaluated at that point.
Taraetin
Target the larger traffic entities within our service territory on the belief that smaller
entities will follow-suit. Target customers are City of Spokane , County of Spokane
and City of Coeur d'Alene.
Include substantial M&E (runtime, degradation of light) in the early period in order to
represent these figures to other entities.
Summary
Use enhanced incentives and limited-time-offer to obtain significant penetration of the
early adopter segment.
Discontinue incentive with appropriate (e.g. 3 month) notice once we have the
following:
1) A solid adoption (e.g. two of the three identified) in the early adopter segment.
2) A significant start in the smaller segment (e.g. 3 entities)
3) At least one manufacturer marketing the product to customers within our
service territory,
Additionallv
Coordinate implementation with any developing RCM program in the governmental
segment.
. Long-term bonus: Challenge the industry standard of three to four lights per
intersection. Can this be reduced by one light (down to a minimum of two) as a result
of the lack of catastrophic failure in LEDs? This would substantially reduce the
capital cost of converting over to LEDs,
Coordinate with WA General Administration or our own internal financing leasingprogram.
Simple Pavback Policv Statement
Schedule 90 prescribes three separate incentive approaches to electric efficiency projects; (1)
electric efficiency, (2) new technology and (3) fuel-conversion. The definitions and tier structures
of each of these three categories are as follows:
Electric efficiency: These are projects which exceed code-minimum or industry standard but
are not electric to gas conversions or granted new technology status. Incentives are:
Page 22
Avista Utilities Triple-E Report July 2000
Enhanced incentives will only be applied as part of a business plan for addressing
the market barrier. The business plan selected must be the best available for
addressing that technology application, The field of "best available" is not confined tooptions that are available through Schedule 90 or 190 only. Other options may
include multi-utility approaches, regional or national approaches or other options that
mayor may not include utilities at all.
Whenever applicable, the new technology approach must coordinate with other utility
or non-utility initiatives in the same field.
Procedure
Adherence to quality business planning and decision-making is of great importance in the
proper application of the new technology incentive alternative. Strict adherence to a
particular procedure is much less important.
It is well recognized that concepts for new technology applications will be, and should be
discussed widely and informally. This is to be encouraged as a means of both generatingand improving successful new technology applications.
As the concept becomes increasingly firm, it is necessary to work closely with all DSM
portfolio managers to ensure that the application is coordinated with their offerings. At
this stage mutually exclusive concepts and concepts that for any reason do not fit within
the portfolio should be identified. The discussion of timing of the launch and coordination
would also be initially discussed with the portfolio manager.
When the concept becomes reasonably firm the Partnership Solutions Team would
become involved. At this later stage the business plan concept would be trued up to the
new technologies policy. Upon conclusion a brief business plan and future checkpoints
would be established for each new technology. Those responsible for following -through
with the implementation and the checkpoints would also be clearly identified.
Summary
This approach is intended to provide a basis for systematically evaluating new technology
concepts. The process will be periodically reevaluated to determine if it meets the needs
of the Company s energy-efficiency effort. The best expected measure of success would
be to:
improve the quality of concepts that are launched either through the new
technologies option or through alternative approaches to the market issue(s).
eliminate or suspend those concepts that are, for any reason, inappropriate for the
new technologies treatment.
provide a basis for continuous improvement of our process through learning about
how to better approach these identified market opportunities,
Samole New Technoloaies Business Plan
LED Traffic Lights
Market Barrie
An emerging technology,
There are bureaucratic and legal issues with being the first adopted, particularly
among smaller traffic entities.
Page 21
Avista Utilities Triple-E Report July 2000
The intent of the enhanced new technology incentive structure is to provide the flexibility
for Avista to overcome known and identifiable market barriers for appropriate and cost-effective applications of energy-efficiency with a temporary and tarQeted application ofpremium customer incentives on either a case-by-case or on a prescriptive basis. The
end result must be the acquisition of long-term energy savings either from increased
penetration of an energy-efficiency measure or through the accelerated adoption of the
measure. It is well known that not all market barriers can be addressed by an enhanced
incentive, and the enhanced incentive structure is not intended to be the sole mechanism
for addressing all market barriers.
The reference to "known and identifiable market barriers" requires that the request for
new technology status be accompanied by a satisfactory identification of this market
barrier. This may include, but is not necessarily limited to:
. A lack of confidence on the part of the customer as to how it will effect their
operation. This is only a market barrier if there are significant energy savings
achievable within the Avista service territory that would benefit from such a
demonstration project. The wholesale and/or retail infrastructure is undeveloped or
underdeveloped in a way that reduces or delays the penetration of the energy-
efficiency measure.
. A degree of saturation required to promote the incorporation of a particular measure
into an energy code or the promotion of the measure as the industry standard.
. A lack of confidence regarding the energy efficiency or the non-energy impact of the
measure.
The application must also be "appropriate . This means that:
The measure may not have non-energy disbenefits that are so substantial as to make
the measure non-viable from the standpoint of an informed and rational consumer.
This is particularly true in a case where the non-energy disbenefits are related to
safety.
The measure must be the best-available energy practice available regardless of fuel.
Under no circumstances will Avista provide enhanced new technology incentives for
measures that are not the best available option for the customer.
Measures incentivized under the new technology structure must also be "cost-effective
Cost-effective will be defined as:
Having a cost-effectiveness substantially above 1.0 using the Total Resource Cost
test as calculated in Avista s periodic reporting methodology.
This calculation does include quantifiable non-energy benefits. The decision on the
inclusion of non-quantifiable non-energy benefits will be made on a case-by-casebasis,
The enhanced incentives must be "temporary . This means that:
There must be a well-established and sound business plan indicating that the market
barrier identified will be addressed by the enhanced incentives within a finite period
of time. This period of time should not exceed two years in most cases, with shorter
periods preferred to longer periods due to the inherent risk in the longer term.
Quantifiable market indicators must be identified that will track the success, or lack
thereof, of the enhanced incentives in addressing the market barrier. Non-
quantifiable indicators are acceptable, but a clear definition is an absolute
requirement.
The term over which new technology incentives are granted must be consistent with
the business plan for overcoming the market barrier as well as ensuring equitable
treatment to customers.
The application of the new technology incentive must be "targeted"
Page 20
vista Utilities Triple-E Report July 2000
Notable Projects, Disclosures , and Policy Updates
Avista is presenting to the Triple-E Board written revisions of two major implementation policy
areas. The first of these , the New Technology Policy Statement, is a material revision to our past
approach in this area. The second policy statement, regarding the calculation of customer simple
paybacks, is a collection of minor revisions to a previous written policy.
It is our intent to commit other policies to writing over the remainder of 2000 and the early portion
of 2001. Each of these will be revised as necessary and appropriate, and significant revisions will
become part of future Triple-E Reports.
New Technology Policy Statement
Avista has committed to writing policies regarding the granting and management of projects
receiving enhanced incentives under the New Technology portion ofthe Schedule 90 incentive
structure.
The policy is subject to revision on an as-necessary basis. Interpretation of the policy andmanagement of the projects fall primarily to the Program Manager for that particular Customer
Segment.
The most current policy statement is included below in its entirety:
Avista Utilities Customer Solutions Department
Policy on the Granting of New Technology Incentive Status
Overview
The Avista Utilities Schedule 90 identifies three tiered categories of incentives available
to customers for energy-efficiency projects. These tiers are (1) high-efficiency incentives
(2) new technology incentives and (3) fuel-efficiency (electric to natural gas conversion)
incentives. While the third category, fuel-efficiency incentives, is very distinct from the
other two categories, there is much more opportunity for confusion regarding the
applicability of the high-efficiency and new technology incentive levels.
Similarly Avista is proposing a Schedule 190 natural gas efficiency tariff with both high-
efficiency and new technology incentives, These two incentive structures share the same
indistinct relationship as has been found in the electric Schedule 90 tariff.
In both the electric and gas efficiency tariffs the new technology incentives exceed the
high-efficiency incentive levels by a substantial 50% to 100%.
This general policy statement is being created in order to ensure that these enhanced
incentives are applied in a non-discriminatory manner and to increase their effectiveness
by targeting them for the appropriate technology applications.
Policy Statement
Page 19
Avista Utilities Triple-E Report July 2000
Appendix B
Additional Descriptive Statistics
This Appendix updates the descriptive statistics contained in the previous Triple-E Report.
Refer to Tables B1 and B2 for the quantity, energy savings and non-energy benefits of projects
broken out by type.
Refer to Tables 83 and B4 for a jurisdictional breakdown.
Refer to Tables 85 and B6 for a breakdown of the number and energy savings of projects by
electric rate schedule.
Refer to Tables B7 and B8 for the same breakdown of therm savings by natural gas rate
schedule.
Page 35
Avista Utilities Triple-E Report July 2000
Table B1 Breakdown of Database Projects b:
Project Type Project Count % of Projects kWh Savings % of kWh NEB $fYr % of NEB $/Lighting 21.736 208 13.5% $690.LED Exit Signs & Traffic Signals 205 576 6% $916.41VendingMI$ER 189 50.750 750 9% $020.Other 21.129,704 79.0% $(0.00)All 372 100.12,822 238 100.0% $627.
Table B2 Breakdown of All Projects b:
Project Type Project Count % of Projects kWh Savings % of kWh NEB $fYr % of NEB $/Lighting 12.736 208 10.2% $690.LED Exit Signs & Traffic Signals 205,576 2% $916.41VendingMI$ER 189 29.750 750 4.4% $020.Limited Income 114 17.738,035 10.3% $Natural Gas Awareness 141 22.251 028 13.3% $RMPP 007 4% $Other 12.208 591 60.2% $(0.00)All 638 100.952,196 100.0% $627.
Table B3 Breakdown of Database Projects b:
State Project Count % of Projects kWh Savings % of kWh
173 46.942 328 61.
199 53.879 911 38.All 372 100.822,238 100.
Table B4 Breakdown of All Projects b
State Project Count % of Projects kWh Savings %ofkWh
363 56.796 679 64.
276 43.076,629 36.All 638 100.16,873 309 100.
Page 36
A vista Utilities Triple~E Report July 2000
Table B5 Breakdown of Database Projects by Electric Rate Schedule
Rate Schedule Project Count % of Projects kWh Savings % of kWh
375
14.224,254
283 76.933,467 54.
265,770 41.
Unknown 396,372
All 372 100.822 238 100.
Table B6 Breakdown of All Projects by Electric Rate Schedule
Rate Schedule Project Count % of Projects kWh Savings % of kWh
258 40.991,438 23.
224 254
294 46,995,474 41.
265,770 31.
Unknown 396 372
All 638 100.16,873 309 100.
Table B7
Rate Schedule
101
111
121
NonelUnknown
All
Project Count
133
149
372
Table B8
Breakdown of Database Projects by Natural Gas Rate Schedule
% of Projects Therm Savings
20.2% 19 507
35.8% 28 6170% 1,275
40.1% (4 021)
100.0% 45,378
% of Therms
43.
63.
100.
Breakdown of All Projects by Natural Gas Rate Schedule
Rate Schedule
101
111
121
None/Unknown
All
Project Count
330
133
149
638
% of Projects Therm Savings % of Therms
51.7% (150,654) 90,
20.8% 28,617 -17.1% (39,763) 24.23.4% (4,021) 2.4%
100.0% (165 821) 100.
Page 37
~\'
rV'ST
Corp.
APPENDIX K
UPDATED LOADS AND
RESOURCES
UPDA TED LOADS AND RESOURCES
A vista is continuously updating its position in regards to the balance between
requirements (loads and sales) and its resources (generation and purchases). This is done
on a day to day, month to month basis in order to assure sufficient power supply to meet
the needs of its customers. The annual requirements and resource tabulation is also
updated when significant changes are known,
Avista updated its annual requirements and resources tabulation in January 2001 when
there was an adjustmentto loads and changes in contracts with BP A and Snohomish
PUD. These changes and other minor adjustments are explained below.
The system load update, done in the summer of 2000, incorporated known and
measurable changes in customer facilities and equipment. For example, changes
included shopping malls, big~box retail chains, universities and hospitals that have
completed or begun major expansions.
. The PacifiCorp Exchange contract is assumed to tenninate after March 2004, The other
contract that A vista has with PacifiCorp, which is a summer sale, is assumed to end
September 30 2003 by PacifiCorp not exercising their option to extend for five years.
The ten year sale agreement (beginning October 1996) that the company has with
Snohomish PUD is now scheduled to tenninate starting October 2001.
The planning reserves were adjusted to reflect the changes in the forecasted peak loads.
Company s system hydro and contract hydro was adjusted slightly to reflect the latest
final hydro regulation done by the NWPP. The energy output from system hydro was
increased 3 aMW and the contract hydro was decreased 2 aMW.
The other contract that was changed on the tabulation was the BPA-WNP #3. This
contract with BP A under the WNP #3 Settlement has agreements for an exchange of
energy. BPA has the option to request a major portion of the energy back if it is needed
by their system. In December 2000 BP A requested the energy back from A vista. And
since the requirements and resources tabulation is based on critical water conditions it
will be assumed that under those conditions BPA will ask for the energy. BPA's energy
to A vista is approximately 43 aMW and based on availability factors of nuclear suITogate
units the energy from Avista to BPA is about 33 aMW. The result to Avista is a net
delivery on an annual basis of 10 aMW.
The capability of Kettle Falls was increased one MW to a total of 49 MW.
The surplus (deficit) figures were adjusted to reflect these changes. The magnitude of
these changes varied depending on the year. For the year 2004 (the year Avista requested
resources under the 2000 RFP) the peak deficit went from 287 MW to 235 MW, Theenergy deficit went from 318 aMW to 287 aMW. These analyses show a continuing need
for electrical resources to meet the company s customer requirements.
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