20111205Comments.pdf

KARL KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
472 W. WASHINGTON STREET (83702)
PO BOX 83720
BOISE, IDAHO 83720-0074
Tel: [phone]
Fax: [phone]
Idaho Bar No. 5156
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2011 DEC -S PM 3: l 5
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF AVISTACORPORATION )
DBA AVISTA UTILITIES' FILING OF ITS 2011 )
INTEGRA TED RESOURCE PLAN (lRP). )
)
)
)
CASE NO. A VU-E-11-04
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilties Commission comments as follows on Avista
Utilties' 2011 Electric Integrated Resource Plan (IRP).
BACKGROUND
Avista filed its IRP with the Commission on August 25,2011. The IRP is a biennial
planing document that sets forth how the Company intends to serve its customers' anticipated
electric requirements. See Commission Order Nos. 22299 and 24729.
The 2011 IRP is the Company's 12th plan. It contains sections describing Avista's
process for involving stakeholders, curent and forecasted loads and resources, energy efficiency
programs, environmental policy considerations, transmission and distribution systems,
generation resource options, market analysis, preferred resource strategies and a sumar of
actions to be taken by the Company in accordance with its 2011 IRP Action Plan.
STAFF COMMENTS 1 DECEMBER 5, 2011
STAFF REVIEW
Overview
The main purose of Avista's IRP process is to develop a Preferred Resource Strategy
(PRS). The PRS describes a future resource plan needed to meet forecasted load growth while
simultaneously considering cost and varous risk factors. However, the Company clarifies that
the PRS is only one of many potential resource portfolios that optimize the tradeoff between cost
and risk and that the IRP and resulting PRS is used more as a guide in the Company's resource
acquisition efforts. As evidence, the IRP process also produced 22 action items (Avista, 2011
IRP, section 9) to continually monitor or obtain better information to improve futue IRP and
business planing efforts.
The Company developed the PRS primarily using two analytical models: AURORAxmp
and PRiSM. AURORAxmp is a resource dispatch model that can predict resource dispatch
costs, greenhouse gas emissions, and more importtly, wholesale market prices at key hubs
throughout the Western Interconnect. These outputs are used as inputs into the PRiSM modeL.
A vista uses PRiSM to select portfolios of resources from a menu of potential resources that
simultaneously optimize cost and risk while satisfying energy, capacity, and renewable portfolio
standard (RPS) requirements. Having several portfolios that fall along a risk/cost continuum of
"optimal" solutions allows Avista to select a PRS that, in the Company's judgment, wil meet the
needs of shareholders, ratepayers, and the general public. By utilzing this method, the Company
selected a portfolio that is needed to meet anual energy deficits that begin to occur in year 2020,
and sumer and winter capacity deficits in years 2019 and 2020, respectively. The PRS is
primarly composed of 323 aMW of "cost-effective DSM" (netted against the load forecast), 70
aMW of wind generation, and 669 aMW of both simple-cycle and combined-cycle natural gas
generation.
Staff has reviewed Avista's 2011 IRP. Based on this review, Staff believes that Avista
generally has demonstrated a rigorous approach in developing its IRP and has reasonably met
requirements set forth by the Commission. Further details of the PRS and Staffs analysis are
outlined below. In sumar, however, Staff believes the 2011 IRP raises three important issues:
1. The early acquisition of wind resources to meet Washington State Energy
Independence Act requirements (page 9).
STAFF COMMENTS 2 DECEMBER 5, 2011
2. Using two different assumptions for carbon credit allocations, which could
understate the sales forecast (p.6).
3. Transmission in-service dates not synchronized between different utilty IRP's
(p.11).
Public Involvement
Avista utilzed a Technical Advisory Committee (T AC) comprised of a variety of
staeholders to gather input and to help develop the 2011 IRP. There were 75 people on the
T AC list representing customers, academia, governent, consultants, other utilties, and other
interested paries that were either invited or who asked to paricipate.
Commission Staff actively paricipated by attending all six T AC meetings and providing
input outside of meetings throughout the process. This includes thoroughly reviewing drafts of
the IRP and providing comments back to the Company. Staff believes the Company made
considerable effort to increase public participation in developing the 2011 IRP; however,
achieving significant participation across the spectrum of stakeholders continues to be difficult.
Staff encourages the Company to continue its efforts to improve public paricipation to as wide
of constituency as possible in future IRPs.
Load and Resource Balance
Avista's IRP shows that the Company will have surplus capacity and energy to meet load
for several years. The Company should be able to supply customer requirements until at least
2020 from an anual average energy perspective. The size of the shortage is relatively small at
49 aMW for three consecutive years and then gradually increases to 475 aMW in 2031. The
Company uses a 90 percent monthly confidence interval on load hydroelectricity variabilty as a
contingency margin. Planing for this contingency means there is a 10% probabilty that the
Company will need to go to market during any given month. Staff believes this is a reasonable
assumption given that the Company has sufficient transmission to access surplus generation
through the Mid-Columbia energy market.
Except for a 54 MW summer peak deficit that occurs in 2016, summer and winter peak
capacity shortages begin to regularly occur in 2019 and 2020, respectively. The Company
predicts sumer deficits to occur staing in 2019 at 98 MW rising to 774 MW in 2031. Winter
deficits begin to occur in 2020 staring at 42 MW rising to 883 MW by the end of the IRP
STAFF COMMENTS 3 DECEMBER 5, 2011
planing horizon. For capacity planing purposes, Avista uses an 18-hour 3-day peak event
standard which effectively smoothes large peak hour events. The Company then adds operating
reserve requirements and a 15 percent summer peak and 14 percent winter peak planing margin
approximating the Northwest Power and Conservation Council's planing targets. Staff believes
these are reasonable assumptions especially given Avista's access to and availabilty of market
resources if predicted deficits are understated. The table below provides a summar of energy
and capacity balances reflected in the 2011 IRP.
Net Load Resource Balance
Year ~I ~ ~ ~ ~I ~i... ~I ~I ~i. ~i..... ~
Winter Peak IMWI 654 635 567 373 254 31 199 152 -42 .125 .216 .259 .296 .342 .401 .704 .746 .796 .835 .883
Summer Peak IMWI 251 1 91 9 .54 36 2 .98 .140 .152 .21 .234 .249 .316 .352 .599 .660 .689 .708 .774
Average Energ laMWI 116 69 108 89 82 54 11 13 -49 .67 -46 .103 .126 .11 .218 .408 .405 .456 -42 -475
Load Forecast
An environment of uncertainty has remained throughout the development of the 2011
IRP. The average energy load forecast is expected to grow 1.7 percent anually, which is
approximately 390 aMW over the 20-year planing horizon. This is approximately the same
growth rate forecasted in the 2009 IRP; however, the actual measured load for 2010 was lower
than was forecasted in the 2009 IRP, resulting in a 2011 IRP load forecast that is lower year-to-
year. Staffs comments on the 2009 IRP reflect concern that the Company's 2009 load forecast
did not adequately account for the recession's effects. Staff believes the Company has addressed
this issue by reducing the overall 2011 load forecast compared to the 2009 forecast.
The Company created three separate cases for the average energy load forecast to test the
risk sensitivity of the Company's PRS using a 0.5 and 1.5 multiplier relative to the expected case
forecast for the low and high case scenarios, respectively. Staff agrees with the use of
multipliers because they provide insight into the effects of load growth variation so that planing
contingencies can be developed.
The Company predicts peak demand wil grow 1.5 percent anually totaling 571 MWof
incremental load through 2030. The peak demand forecast utilizes 11 years of historical net
native load and actual peak demand to develop its peak demand forecast; however, it is smoothed
so that extreme weather events do not overwhelm it. The Company produced both winter and
STAFF COMMENTS 4 DECEMBER 5, 2011
sumer peak demand forecasts with winter peaks being consistently higher than summer peaks.
The Company notes that the spread between winter and summer is narowing due to higher
sumer air conditioning penetration.
A vista uses a retail sales forecast to develop the net native load projections used in its
IRP. The sales forecast is a sumation of electricity demand across all customer classes. The
major factors driving increases in the sales forecast by customer class are: (l) housing stars for
residential class demand; (2) residential growth on the growth for commercial class customers;
(3) employment growt for the industrial sector; and (4) population growth for street lighting.
The price of electricity and customers' sensitivity to it is an importnt factor driving the
overall sales forecast. A vista predicts electricity prices wil rise on average eight percent
anually from 2010 to 2018 followed by the general rate of inflation for subsequent years. The
Company accounts for 25 percent of the rise in electricity prices based on carbon and renewable
portfolio standard (RPS) legislation. Using the Company's price elasticity estimates, this equates
to an overall 1.2 and 0.8 percent reduction in electricity sales annually (until 2018) for residential
and commercial customers, respectively, due to growth in electricity prices.
The Company also considers customers' income elasticity and the cross-price elasticity of
natual gas on electricity demand. Because of the Company's unique perspective as provider of
both electricity and natural gas, the Company takes into account how much electricity demand is
affected by customers who switch to natural gas as a substitute. Staff believes that these insights
lead to a better forecast overalL. For the expected case, the Company assumes that rising
incomes offset the effects of rising electricity and natural gas prices.
New to Avista's IRP is a projection of electrc vehicle consumption using data from the
Northwest Power and Conservation Council's Sixth Power Plan. Although the amount is
relatively small, Staff supports including it in the forecast so that futue IRPs can account for the
effects of this likely growing market.
The Company also included additional sales for very large customers. The only additions
included were publicly announced long-lead time buildings that occur through year 2015. Staff
supports this methodology because it provides a non-arbitrary basis to quantify load, and by
using a 3-year time frame it allows sufficient lead time for the Company to react while
identifying additional loads to be included in the next IRP planing cycle.
STAFF COMMENTS 5 DECEMBER 5, 2011
The only remaining factors that affect the sales forecast are weather effects and the
amount of conservation that customers adopt. The combination of all these effects results in a
sales forecast that grows at a 1.6 percent anually compounded rate through 2035.
Staff notes that A vista uses two sets of assumptions regarding the issuance of credits for
greenhouse gas (GHG) legislation. The expected case sales forecast assumes there will be no
free allocation of credits, while the rest of the IRP analysis assumes otherwise. If GHG
legislation does allow free allocation of credits, the electricity price forecast could be overstated
resulting in an underestimated sales forecast. Staff agrees with the Company that this difference
in assumptions should not significantly affect the IRP results, given that the Company models
load as a risk variable and understands its sensitivity on resource selection. Overall, Staff
believes the Company's sales forecast appears reasonable and has taken into account all the
major factors that affect it.
Supply-side Resources
A vista's current portfolio of supply-side resources used to determine load resource
balance deficits includes Company-owned assets totaling 1802 MW in nameplate capacity and
approximately 438 aMW in power purchase agreements (PPA) and contracts. The IRP analysis
assumes that all thermal resources will operate throughout the 20-year planning time horizon.
Staff believes a legislated cost of carbon or additional emission abatement requirements could
affect this assumption.
Demand-side Resources
A vista netted curent and forecasted energy efficiency from the load forecast prior to
determining load resource balance deficits. To determine the energy effciency and demand
response potential for its Washington and Idaho service terrtories, the Company hired Global
Energy Parners to conduct a Conservation Potential Assessment (CPA). The study looked at
"existing programs, naturally occurring energy savings, the impacts of known building codes and
standards as of2010, technology developments and innovations, changes to the economy, and
energy prices." (Avista, 2011 IRP, p. 3-3). The consultat estimated what the Company could
realistically achieve by taking into account cost effectiveness, industr stadard incentive rates,
expected paricipation rates, customer preferences, and budget constraints. Forecasted savings
are ilustrated in the table below. It shows that energy savings are projected to offset roughly 50
percent of load growth through 2022.
STAFF COMMENTS 6 DECEMBER 5, 2011
Year
2012 2017 2022 2027 2031
Baseline Forecast (MWh)8,799,039 9,463,880 10,417,347 11,536,869 12,574,182
Achievable Energy Savings (MWh)49,804 395,397 940,578 1,538,868 2,025,679
Achievable forecast (MWh)8,749,236 9,068,483 9,476,769 9,998,002 10,548,503
Energy Savings (% of baseline)0.6%4.2%9.0%13.3%16.1%
Load Growth %8%18%31%43%
Besides energy efficiency programs, the Company evaluated several standard demand
response programs. Because Washington State's Energy Independence Act (I-937) requires
energy effciency resources to be acquired first, need for additional capacity to meet peaks were
not required until the 2020 time frame making demand response currently not cost effective.
Staff agrees with the Company that futue demand response should be considered in the future,
especially when capacity deficits exist and there is a lack of need for resources to meet average
energy requirements.
Staff notes that the Company only uses its conservation program IRP analysis to establish
baseline goals and to determine budgets and human resource operational needs (Avista 2011
IRP, p. 3-18). A vista makes actual resource acquisition decisions through its ongoing business
and operations planing processes. This allows the Company to react to changing conditions by
continually evaluating existing and potentially new programs to adjust its DSM resource
portfolio.
Staff calls attention to concerns made in comments for the 2009 IRP about the exclusive
use of the Total Resource Cost (TRC) test to evaluate programs in the IRP and its continued
exclusive use in the 2011 IRP. Although the TRC is an important perspective, it is but one of
four other cost-effectiveness tests including paricipant, utilty, and ratepayer perspectives. Since
the TRC is typically more restrictive than the paricipant and utility cost tests and the Company
is only using the IRP for overall program direction setting, Staff agrees with using the TRC as a
screen in its CPA as long as the other tests continue to be conducted for resource acquisition
decisions.
Environmental Policy Considerations
A vista's IRP analysis takes into account several curent and potential future
environmental regulations. Primarly, this includes state and federal rules and regulations of
greenhouse gas emissions (GHG), mandatory renewable energy standards, mandated investments
in energy efficiency, and various renewable energy credits and incentives. The main importce
STAFF COMMENTS 7 DECEMBER 5, 2011
in considering future potential policies is the amount of risk due to uncertainty they create for
planing large capital investments. The risk is a fuction of the nature of utilty investments that
require long lead times for construction compounded by large capital costs with economic lives
that lock utilties into an investment for decades.
Federal Policy
From a national perspective, the 2011 IRP has accounted for future greenhouse gas
legislation by predicting a carbon price that ranges from approximately $15 per short ton in 2015
to $80 per short ton in 2031. Instead of picking one specific model legislation, the Company
chose to do a weighted average of four potential outcomes with 30 percent allocated to a regional
GHG policy, 30 percent to a national climate policy, 30 percent to a national carbon tax, and 10
percent to the curent status quo. Staff believes that the Company's approach is reasonable for
determining an estimated cost of carbon.
Curently, the federal governent offers Production Tax Credits (PTC), Investment Tax
Credits (ITC), and Treasur grants to incentivize renewable energy. Because the PTC and ITC
are scheduled to expire in 2012 and 2013, respectively, the Company chose not to assume
extension of any tax benefits beyond their expiration dates. Staff agrees with the Company that
the continuation of these credits is uncertain and highly unlikely given the curent budget setting
environment and debt crisis in Washington, D.C.
State Policy
From a state perspective, resource plans included in the IRP had to comply with
Washington's Senate Bil 6001 prohibiting Avista from expanding or developing any new coal-
fired generation capability without sequestering carbon. As a result, no additional coal-fired
generation was included in the Company's PRS.
Second and more importantly, Washington State voters passed the Energy Independence
Act (I-937) in 2006. This Act required Avista to serve three, nine, and 15 percent of retail load
by 2012, 2015, and 2020, respectively, with qualified renewable energy or renewable energy
credits while acquiring all cost effective conservation and energy efficiency measures. To fulfill
this Renewable Portfolio Standard (RPS) through 2019, Avista recently signed a contract for the
Palouse Wind project, even though it is not needed to meet forecasted energy loads until 2020
(Avista, 2011 IRP, p. 2-24). Although the power purchase agreement is not needed to meet
Washington RPS requirements until 2015, the Company has acquired the resource to tae
STAFF COMMENTS 8 DECEMBER 5, 2011
advantage of federal ta benefits mentioned earlier and the current low prices for wind energy.
To meet the RPS requirements for year 2020, the Company will need an additional 42 aMWof
wind or qualified renewable energy credits.
Staff notes that the need for the first increment of wind to meet load has shifted from
2018 in the 2009 IRP to 2020 in the 2011 IRP. This is likely due to a reduction in the load
forecast. Additionally, Staff takes no position at this time on the prudence of Avista's renewable
resource acquisition decisions, but mentions it because renewables acquisition is one of the most
significant outcomes of the 2011 IRP. The choice of the specific selected resources, the decision
to acquire resources early, and the allocation of costs amongst state jurisdictions will all be
addressed later when A vista seeks to recover costs through rates.
Transmission and Distribution Planning
Avista is putting significant effort into addressing supply-side energy efficiency by
finding cost-effective investments in its distribution system to minimize costs related to line loss
and other sources of operational cost. For the first time, the Company has included cost-
effective distribution system feeder upgrades as a resource in the PRS. The Company predicts
6.1 aMW of losses may be avoided by the end of the IRP planing horizon. A vista is also
forecasting an additional 6.6 aMW of savings due to Smart Grid investments and has sought
outside grant fuding to investigate various projects. Staff is encouraged by the Company's
efforts in finding effciency opportnities that can potentially reduce customer rates.
Staff also supports the Company's paricipation in several regional groups including,
ColumbiaGrid, and Northern Tier Transmission Group. Its active paricipation ensures
operational coordination of the transmission system for reliabilty purposes as well as Avista's
interests in evaluating future transmission plans.
Future Resource Options
A vista determined a levelized cost based on yearly maximum energy availability for
resources considered for inclusion in its PRS. These costs also include any curent state and
federal incentives for qualifying resources up to the time they expire. The main options considered
for the PRS include: (a) gas-fired combined cycle combustion turbine (CCCT), (b) gas-fired
combustion tubine and reciprocating engines (SCCT), (c) wind turbines, (d) photovoltaic (PV)
and thermal solar generation, (e) coal-fired thermal generation, and (f) upgrades to existing thermal
and hydroelectricity facilties.
STAFF COMMENTS 9 DECEMBER 5,2011
A vista considered two main types of natural gas fueled generation resources in its IRP.
Both combined cycle (CCCT) and simple cycle (SCCT) technologies have relatively inexpensive
capital cost but are disadvantaged by risk associated with fuel cost volatilty. The Company
estimated levelized cost for CCCT at $99.07/MWh and $110 to $ 123/MWh for SCCT
technology.
Wind and solar technology are mainly considered because they lack carbon emissions,
qualify as renewable resources to meet RPS requirements, and are eligible for different kinds of
renewable energy credits and incentives. Capital costs on a per-MWh basis are significantly
higher than natural gas, but wind and solar do not have any fuel cost. A vista estimated levelized
cost of wind to be between $100 and $1 09/MWh, while solar ranges from $202/MWh for
concentrating solar to $325/MWh for PV technology.
A vista did not consider coal-fired generation as an incremental resource mainly because
it is prohibited without carbon capture and sequestration through Washington's Senate bil 6001
and because of future carbon cost risk. For comparison puroses with other technologies, A vista
estimated coal's levelized cost to be $140 to $156/MWh.
A vista curently has significant hydroelectricity and thermal resources. By upgrading
existing facilities, the Company can obtain small amounts of capacity and energy at relatively
low cost. Included in curent resources is nine MW of capacity from upgrades to Noxon Rapids
slated to be completed in 2012. In total, the Company estimates a total of 40 aMW of additional
energy due to potential hydro upgrades. In addition, there is the potential for 167 MW of
capacity from upgrades to Avista's Rathdrum and Coyote Springs natural gas plants.
Market Analysis
The Company conducted a market analysis to determine greenhouse gas emissions,
dispatch percentages and costs, and prices of electricity at key hubs throughout the Western
Interconnect. Avista used the output of this analysis as input in selecting the PRS. The analysis
took into account several risk factors by using Monte Carlo sampling methods for each of the
independent variables under consideration. Risk factors included: greenhouse gas prices, natural
gas prices, load variabilty, hydroelectric availabilty, wind volatilty, forced plant outages, and
several smaller factors.
The Company's analysis predicts that greenhouse gas levels will be reduced 11.2 percent,
while market prices wil increase approximately 168 percent over the 20-year time period
STAFF COMMENTS 10 DECEMBER 5,2011
primarily due to carbon and RPS policies included in the modeL. Staff agrees with the Company,
that current and future greenhouse gas legislation and RPS requirements are changing the
electricity marketplace in the West. Replacing coal-fired generation results in higher penetration
levels of renewable generation increasing from five to 13 percent. Penetration of lower carbon-
emitting natural gas generation is predicted to increase from 23 to 41 percent as well. This wil
inevitably lead to higher rates and increased price volatility in the future in order to maintain
similar reliabilty levels.
The market analysis also took into consideration various regional transmission projects.
Staff notes that Avista assumed a 2016 in-service date for Gateway West and a 2019 date for
Boardman-to-Hemingway transmission projects. However, Idaho Power's 2011 IRP assumes a
2016 in-service date for Boardman-to-Hemingway and a 2022 date for Gateway West.
Differences in in-service date assumptions could affect market prices used in the Company's IRP
analysis, especially since both transmission projects wil open market access for several utilities
in corrdors that are currently highly constrained.
Preferred Resource Strategy
The PRiSM tool used to identify the PRS can simultaneously optimize cost and risk by
selecting from a menu of potential resources while satisfying a set of constraints. Constraints
used in the model include capacity, energy, RPS, and greenhouse gas emission requirements
while using electricity prices generated from the market analysis. A vista believes it has selected
a PRS that appropriately weighs cost and risk among several different resource portfolios fallng
along the risk/cost continuum of "optimal" solutions that balances the future needs of
shareholders, ratepayers, and the general public.
The resulting PRS is primarily a combination of both simple-cycle and combined-cycle
natural gas plants, wind generation, and energy efficiency, which makes up 97 percent of the
total portfolio. The Company estimates the present value of the PRS investment at $0.84 bilion
requiring approximately $1.7 bilion in capital expense. In addition, A vista estimates a total of
$1.4 bilion (nominal) over 20 years wil be needed to obtain 310 aMW in energy efficiency
resources. The preferred resource strategy is ilustrated in the table below.
STAFF COMMENTS 11 DECEMBER 5,2011
2011 Preferred Resource Strategy
NWWind 2012 120 35
seeT 2018 83 75
Existing Thermal Upgrades 2019 4 3
NWWind 2019-2020 120 35
seeT 2020 83 75
eeeT 2023 270 237
eeeT 2026 270 237
seeT 2029 46 42
Distribution Efficiency All Years 28 13
Energy Efficiency All Years 419 310
Total 1443 1062
Comparison with 2009 IRP
The 2011 PRS is similar in comparson to the 2009 PRS except for a few noted changes.
Most significantly, the 2011 PRS replaces approximately 30% of total natural gas generation
with simple-cycle technology (SCCT) that was exclusively combined-cycle technology (CCCT)
in the 2009 PRS. The 2011 PRS also increases the amount of distribution and energy efficiency
resources by seven percent while decreasing reliance on wind by about three percent of total
energy for the portfolio.
Staff supports the increase in energy effciency. Staff also encourages the Company to
explore cost-effective demand response to meet peak demand requirements especially during
periods when peak demand is driving resource acquisition decisions.
Risk Analysis
In addition to developing resource portfolios that fell along the risk/cost continuum of
"optimal" solutions, the Company also performed a tipping point analysis to determine the
sensitivity of certain factors to shift the PRS to a different resource mix.
The first analysis was done on solar capital cost. It showed that the capital cost of solar
generation would need to decrease 53 percent to make it competitive with wind generation. The
Company also looked at CCCT capital cost sensitivity to determine why the PRS shifted from
using CCCT exclusively in 2009 to a combination of CCCT and SCCT in 2011. The analysis
showed that the capital cost of CCCT would need to be 22 percent lower to replace SCCT in the
PRS. Finally, Avista analyzed the PRS's sensitivity to load growth. Using a lower load growth
STAFF COMMENTS 12 DECEMBER 5, 2011
scenario than the expected case, the Company determined that the PRS would not change in the
near term, but would require less wind and natural gas generation capacity in the long term.
Using a higher growth scenario, additional wind would be required to meet RPS requirements
and peaking resources would be needed to meet peak load growth.
Staff believes the Company's tipping point analysis is an important tool for testing the
robustness of the PRS. Identifying which variables make the PRS sensitive to changes can help
the Company and the Commission know which factors to monitor on an ongoing basis so that
resource acquisition decisions can be made in a timely fashion to meet ratepayer needs.
2011 Action Items
The 2011 IRP includes a summary status report on 2009 IRP action items and a list of
action items generated from the curent IRP. Action items fall into five different categories:
(1) resource additions and analysis, (2) energy efficiency, (3) environmental policy, (4) modeling
and forecasting enhancements, (5) transmission and distribution planing. A summar of new
action items included in the 2011 IRP are listed below.
Resource Additions and Analysis
. Continue to explore and follow potential new resources opportunities.
. Continue studies on the costs, energy, capacity and environmental benefits of hydro
upgrades at both Spokane and Clark Fork River projects.
. Study potential locations for the natural gas-fired resource identified to be online by the
end of2018.
· Continue participation in regional IRP processes and, where agreeable, find opportunities
to meet resource requirements on a collaborative basis with other utilties.
. Provide an update on the Little Falls and Nine Mile hydroelectric project upgrades.
. Study potential for demand response projects with industrial customers.
· Continue to monitor regional surlus capacity and Avista's reliance on this surlus for
near- and medium-term needs.
Energy Effciency
· Study and quatify transmission and distribution efficiency projects as they apply to
Washington RPS goals.
STAFF COMMENTS 13 DECEMBER 5, 2011
. Update processes and protocols for conservation measurement, evaluation and
verification.
· Continue to determine the potential impacts and costs of load management options.
Environmental Policy
· Continue studies of state and federal climate change policies.
· Continue and report on the work of Avista's Climate Change CounciL.
Modeling and Forecasting Enhancements
· Continue following regional reliabilty processes and develop A vista-centric modeling
for possible inclusion in the 2013 IRP.
· Continue studying the impacts of climate change on retail loads.
. Refine the stochastic model for cost driver relationships, including fuher analyzing
year-to-year hydro correlation and the correlation between wind, load, and hydro.
Transmission and Distribution Planning
· Work to maintain the Company's existing transmission rights, under applicable FERC
policies, for transmission service to bundled retail native load.
. Continue to paricipate in BP A transmission processes and rate proceedings to minimize
costs of integrating existing resources outside of A vista's service area.
· Continue to paricipate in regional and sub-regional efforts to establish new regional
transmission structures to facilitate long-term expansion of the regional transmission
system.
· Evaluate the costs to integrate new resources across Avista's service territory and from
regions outside of the Northwest.
· Study and implement distribution feeder rebuilds to reduce system losses.
· Continue to study other potential areas to implement Smar Grid projects to other areas of
the service territory.
· Study transmission reconfigurations that economically reduce system losses.
STAFF COMMENTS 14 DECEMBER 5, 2011
Staff believes that the Company has made satisfactory progress on action items from the
2009 IRP. In addition, Staff believes the new action items generated in the 2011 IRP will allow
A vista to improve upon the information the Company needs to make better resource acquisition
decisions in the future and continue to cost-effectively and reliably meet its obligation to serve
load.
STAFF RECOMMENDATION
A vista's new resource needs over the next ten years are primarily driven by RPS
requirements in the State of Washington and not to meet load. The Company's requirement for
120 MW of wind in 2012 outlined in the Company's PRS is not needed to meet RPS
requirements until 2015 or energy load requirements until 2020. The Company has recently
fulfilled this requirement by acquiring a 30-year power purchase agreement for 105 MW of wind
from the Palouse Wind project. The early acquisition of this resource to meet a 2015 RPS
requirement allows the Company to take advantage of federal tax incentives and current low
wind energy costs. This early acquisition decision wil be thoroughly scrutinized once the
project is complete and A vista seeks to recover costs from ratepayers.
Overall, Staff believes that A vista performed extensive analyses, gave reasonably equal
consideration of supply- and demand-side resources, and provided acceptable opportunities for
public input, resulting in an integrated resource plan that satisfies the requirements set forth in
Commission Order Nos. 24729 and 22299. Staff recommends that Avista's 2011 IRP be
acknowledged.
Respectfully submitted this ~ day of December 2011.
¿ll¿/-
Karl Klein
Deputy Attorney General
Technical Staff: Mike Louis
i:umisc:commentsavue 11.4kkl.doc
STAFF COMMENTS 15 DECEMBER 5, 2011
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 5TH DAY OF DECEMBER 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. AVU-E-11-04, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
LINDA GERVAIS MGR
REGULATORY POLICY
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
Linda. Gevaiscmavistacorp.com
CERTIFICATE OF SERVICE
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