20100910final_order_no_32064.pdf

Office ofthe Secretary
Service Date
September 10, 2010
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE FILING BY
VISTA CORPORATION DBA A VISTA
UTILITIES OF ITS 2009 NATURAL GAS
INTEGRATED RESOURCE PLAN (IRP)ORDER NO. 32064
CASE NO. AVU-09-
On December 30, 2009, Avista Corporation dba Avista Utilities filed its 2009 natural
gas Integrated Resource Plan (IRP) with the Commission. Since 1989, the Commission has
required electric and natural gas utilities to file a biennial IRP describing the utility s plans to
meet the future energy needs of its customers. Order No. 22299. An IRP generally describes a
utility's growing customer base, load growth, supply-side resources, demand-side management
and risk analysis.
On January 28, 2010, the Commission issued Order No. 30990 seeking public
comment on Avista s gas IRP. The Commission s Order requested comments be filed no later
than March 23 2010. The only comments were filed by the Commission Staff.
In the IRP, A vista anticipates average growth in its daily demand for natural gas of
1.1% during the period 2010 to 2028-29 (net of projected conservation from DSM savings
programs). During the same time frame, the Company estimates that its peak-day demand will
increase by a compound rate of 1.3%. The Company forecasts that its Idaho/Washington service
territory would experience a supply deficiency in 2023. Given the estimated deficiency, the
Company plans to meet the projected shortages through DSM, conservation, and incremental
transport resources from existing pipelines and supply basins.
Based upon our review of Avista s IRP and Staff comments, we accept Avista
natural gas IRP for filing.
AVISTA'S IRP
Avista s 2009 IRP was developed with the participation of its Technical Advisory
Committee (T AC). Members of the T AC included customers, consumer advocates, academics
utility peers, Commission Staff, governmental agencies, and other interested parties. A vista
sponsored four T AC meetings to assist in the preparation of the IRP. The Company noted that
this IRP was developed during the two-year period (2007-2008) when the United States and
ORDER NO. 32064
other global economIes were experIencIng a financial and credit CrISIS.These financial
uncertainties prompted the Company to consider "a wider range of scenarios to evaluate and
prepare for a broad spectrum of potential outcomes" in this IRP. IRP at p. 1.
Avista s IRP has five parts: demand forecast; natural gas price forecast; supply
resources; demand-side management (DSM) programs; resource needs; and the 2010-11 near-
term action plan.
1. Demand Forecasting. The Company s approach to demand forecasting centers on
customer growth and consumption per customer as the basic components of demand. The
Company considers various factors that influence these components including: population
employment trends, age and income demographics construction trends conservation
technologies, new uses, and consumption per customer.In the demand forecast, A vista
constructed six different scenarios including its "Expected Case" scenario. In the Expected
Case, A vista anticipates an average growth in daily demand of 1.1 % during the period 2010
through 2028-29 (net of projected conservation savings from DSM programs). IRP at p. 1.3.
During the same time frame, the Company estimates that its peak-day demand will increase by a
compound rate of 1.3%. Id.
Price Forecasting The Company maintains that natural gas prIces are a
fundamental component of integrated resource planning. Although A vista does not believe that
it can accurately predict future prices during the 20-year horizon, it has developed high-
medium- and low-price forecasts for natural gas prices. A vista submits that issues of economic
recovery, expectations of new shale gas production, and increased natural gas-fired power
generation make long-term pricing forecasts difficult. IRP at p. 1.4. The Company used low-
price elasticity response factors in its Expected Case.
3. Natural Gas Supply. Avista has a diverse portfolio of natural gas supply resources
including owned and contract storage, firm capacity rights on six pipelines and commodity
purchase contracts from several different supply basins. The Company also evaluated resource
additions from incremental pipeline transportation, storage options, distribution enhancements
and various forms of liquefied natural gas storage or service. Id. at p. 1.5. Matching its resource
supply scenario with its expected case demand scenario, the Company forecasts that its
Idaho/Washington service territory will not experience a supply deficiency until the year 2023.
IRP at p. 1.6. The graph of forecast shortages is almost flat which leads the Company to
ORDER NO. 32064
conclude that its existing resources will be sufficient to meet demand for quite some time.
However, if demand growth accelerates, the steep demand curve could quickly accelerate
resource shortages by several years.Id. at 1.8. Given the estimated deficiency in 2023, the
Company plans to monitor the forecasts underlying the projected shortages to address the future
shortages in a timely manner.
4. DSM Programs. Demand-side management (DSM) programs are intended to
encourage customers to reduce their energy consumption. Cost-effective DSM measures may
include incentives for the purchase of high efficiency appliances (water heaters, clothes dryers
furnaces), insulation, weather-stripping, insulated windows, ductwork, and heat recovery
systems. The Company considered a total of 155 residential and 147 non-residential DSM
measures in this IRP. Id. at p. 4.4. The Company s IRP then analyzed various DSM and other
conservation measures and calculates that these measures may save approximately 3.12 million
therms in the Company s north division in 2010. Id. at p. 4.
5. 2010-11 Action Plan. The Company s IRP identifies and establishes a near-term
action plan that will steer the Company toward the risk-adjusted, least-cost method of providing
service to its natural gas customers. Included in this action plan are efforts to improve computer
modeling, evaluate planning standards, and apply various risk analyses. Key components of the
action plan include:
Monitoring actual demand and responding aggressively when growth
exceeds the Company s forecast demand.
Researching and refining the evaluation of resource alternatives including:
The implementation of risk factors and timelines; updated cost estimates;
feasibility assessments; and targeting options of the service territory with
near-term unserved demand exposure.
Analyzing per-customer data and DSM program results for indications of
price elasticity response trends that may be influenced by evolving
economic conditions. Determining if the American Gas Association will
update its analytical work or consider hiring outside experts in price
elasticity on a regional basis.
Continuing pursuit of cost-effective demand-side solutions to reduce
demand. In Washington and Idaho, conservation measures are targeted to
reduce demand by 2.193 million therms in 2010. This goal represents an
increase of25% in Washington/Idaho from the 2007 IRP.
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Performing an updated assessment of technical and achievable potential
for conservation in the Company s service territory prior to the 2011 IRP.
Continuing to monitor issues of diminishing Canadian natural gas
importing and looking for signals that indicate increased risk of disrupted
or dwindling supply from Canada.
Exploring and evaluating alternatives and additional forecasting
methodologies for potential inclusion in the next IRP.
Id. atpp. 1.11-12.
The Company identified three general risk areas that require future monitoring. First
the Company will continue to monitor economic conditions and financial markets associated
with natural gas demand, infrastructure development, credit availability, and commodity prices.
Second, the Company will continue to monitor federal climate change legislation and its
projected effects upon emission levels, phase-in time frames, allocation of allowances
availability of offsets, cost mitigation to customers, and a host of related least-cost service
challenges. Third, an increasing supply of natural gas in North America is forecasted to come
from "unconventional" gas, especially shale gas. In addition, international liquefied natural gas
(LNG) projects are in the permitting stage and may become a reality in the future.The
availability of LNG combined with the projected increase in supply of unconventional gas may
mean lower prices in the future. "Although beneficial to end users in the near term, this dramatic
volatility and uncertainty could cause long-term disruption in production, pipeline and storage
capital investment, exacerbating boom/bust cycles in the long term." IRP at 1.14.
STAFF COMMENTS
The Supply-Side Resources
Avista has a diversified portfolio of natural gas supply resources. The Company
philosophy is to reliably provide natural gas to customers with an appropriate balance of price
stability and prudent cost while building a diversified portfolio to manage risk in continuously
changing market conditions.
Staff reported that A vista benefits from its close proximity to the two largest natural
gas producing regions in North America: the Western Canadian Sedimentary Basin (WCSB) and
the Rocky Mountain natural gas basins. Historically, these basins have supplied Avista with
natural gas supplies that were discounted to other regions in the country, due to the limited
ORDER NO. 32064
pipeline export potential. However, recent large pipeline projects now connect these basins to
large population centers in the Southwest, Midwest, and Northeast, which have diminished the
discounted price advantage that A vista has historically enjoyed. Future projects to relieve the
bottlenecks and pipeline congestion out of the basins enabling gas to flow to higher-priced
markets along with increased gas production (from shale) in the East could further erode or
eliminate altogether the price advantage. Staff Comments at 5.
Procurement of natural gas is done via contracts. For the IRP, the SENDOUT(ID
model assumes the natural gas is purchased as a firm, physical, fixed-price contract regardless of
when the contract is executed and what type of contract it is. However, in reality, Avista pursues
a variety of contractual terms and conditions in order to capture the most value from each
transaction. Id.
The Company s procurement plan addressed in the IRP is a diversified and structured
plan for natural gas purchases that does not attempt to predict market outcomes. The plan seeks
to competitively acquire natural gas supplies while reducing exposure to short-term price
volatility. The procurement strategy includes hedging, storage utilization, and index purchases.
Although the specific provisions for the plan will change as a result of ongoing analysis and
experience, the plan calls for disciplined but flexible hedging approaches over periods of time
with windows and targets used to initiate transactions. The Company also uses spot market
acquisitions and short-term index purchases for both the summer filling of storage and during the
heating season. In recognition of the volatility present in the markets, the Company is
continually working to add longer-term purchases and other measures to diversify its
procurement portfolio with the aim of reducing that volatility while also securing low-cost
supplies. Id. at 5-
The Company has several gas purchasing methods available. These include daily and
monthly spot market indices, short- and long-term purchases, fixed-price vs. indexed pricing,
price floors, ceiling and other collars, physical price hedging, and financial price hedging. The
Company recognized that a diverse portfolio of supply options will reduce price and volatility
risk and utilize most of these purchasing tools.
Staff commented that natural gas prices are estimated at Stanfield, Malin, Sumas
Rockies, and AECO hubs. However, of the basins that more directly impact Idaho in the 2028-
29 Expected Case, the average basin real prices at Sumas, Rockies and AECO are expected to be
ORDER NO. 32064
$7., $6., and $7.25 per dekatherm, respectively. Avista maintains that issues of economic
recovery, expectations of new shale gas production, and increased natural gas-fired power
generation make long-term pricing forecasts difficult. The Expected Case: (1) estimates a carbon
adder of $5-$67 per ton; (2) estimates a coal-to-gas adder of $.50-$1.00 Dth; (3) assumes no
drilling constraints; and (4) assumes a steady supply of gas from Canada. Staff believes it is
reasonable to take multiple price factors into consideration; however, as legislation for federally
mandated Renewable Portfolio Standards (RPS) and Renewable Energy Credits (RECs)
develops, Staff would like to see the Company narrow the range of prices for modeling the
carbon and coal-to-gas adders. In addition, Staff would like the Company to closely monitor its
assumption that gas supply from Canada will remain steady to allow time for additional
resources when necessary.
In the Expected Case for Washington and Idaho, A vista has the existing resource
supply to meet the forecasted peak-day demand until 2023. Given this timing, the Company
contends that it has sufficient time to carefully monitor, plan and take action on potential
resource additions. The Company also plans to define and analyze sub-regions within this broad
region for potential resource needs that may materialize earlier than 2023.
Storage Resources
Natural Gas storage is a valuable strategic resource that enables improved
management of a highly seasonal and varied demand profile. The numerous benefits of storage
include:
Invaluable peaking capability;
Access to typically lower-cost off-peak supplies;
Reduced need for higher-cost annual firm transportation;
Storage injections that increase the load factor of the existing firm
transportation, and;
Additional supply point diversity.
Avista s existing storage resources consist of ownership and leasehold rights in two in-ground
regional storage facilities: Jackson Prairie located near Chehalis, Washington and Mist located
approximately 60 miles northwest of Portland, Oregon. Mist storage is utilized mostly for the
benefit of Avista s Oregon customers.
ORDER NO. 32064
The Company is one-third owner, with Northwest Pipeline (NWP) and Puget Sound
Energy (PSE), in the Jackson Prairie Storage Project, which benefits Avista s customers in all
three states. Jackson Prairie Storage is an underground reservoir facility with a total working gas
capacity of approximately 25 billion cubic feet (Bet). Avista s current share of this capacity for
core customers is approximately 5.2 Bcf and includes 266 667 Dth of daily deliverability rights.
In 1999, and again in 2002, A vista participated in capacity expansions of the project
with NWP and PSE. It was determined that the additional capacity for core utility customers
was not needed at that time, and the expansion was undertaken by A vista Energy, A vista
former non-regulated energy marketing and trading affiliate. In June 2007, Avista Energy sold
substantially all of its energy contracts and ongoing operations to Shell Energy North America
LP. (Shell). Concurrent with the sales transaction, A vista reacquired the rights to the 2002
expansion from A vista Energy while the 1999 expansion rights were temporarily included in the
sale. Shell retains these rights through April 30, 2011. These rights represent approximately 3
Bcf of storage capacity and 100 000 Dth of daily deliverability. After April 30, 2011 , Avista
plans on recalling these rights for availability in its utility operations and has included it in the
SENDOUT(ID model as an incremental available storage resource at that time. Id. at 7.
Liquefied natural gas (LNG) continues to be evaluated as a supply-side resource to
meet peak-day demand or cold weather events. Contracting for existing capacity with Plymouth
LNG (owned and operated by NWP), building a satellite LNG plant where LNG is trucked to the
facility in liquid form rather than liquefying on-site, and a Company-owned liquefaction LNG
facility have all been evaluated and considered. Id. at 7-
After reviewing all of the elements of the Company s supply portfolio, procurement
options and planning, taken together, Staff believes they satisfy the requirements of PURP A and
provide cost-effective supply for all classes of customers. Id. at 8.
Distribution Planning
Staff noted that A vista s integrated resource planning encompasses evaluation of safe
economical and reliable full-path delivery of natural gas from basin to burner tip. Securing
adequate natural gas supply and ensuring sufficient pipeline transportation capacity to its local
service areas become secondary issues if the local distribution areas are not adequately planned
and become severely constrained. The IRP addresses future local demand growth, determines
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potential areas of distribution system constraints, analyzes possible solutions and estimates costs
for eliminating constraints. Id.
A vista s natural gas distribution system consists of approximately 1 900 miles of
distribution main pipelines in Idaho with another 3,400 miles in Washington and 2 300 miles in
Oregon, along with numerous regulator stations, service distribution lines, monitoring and
metering devices, and other equipment. System pressure is maintained by pressure regulating
stations that utilize pipeline pressures from the interstate transportation pipelines before natural
gas enters the distribution networks.
The IRP lists several areas for distribution system enhancements; however, most of
the projects are in the Company s Oregon service territory where the system is much older than
the Idaho/Washington contiguous system. The few areas designated for enhancement in the
Idaho/Washington service territory are mostly around the Spokane area, with some minor capital
projects in northern Idaho. Id.
Demand Forecasting
A vista uses a Dynamic Demand Methodology to develop its demand forecast - where
key demand drivers behind consumption are identified, the sensitivity of key demand drivers are
analyzed, and combinations of the demand drivers are developed under different scenarios.
After testing various sensitivities, these are combined into different demand drivers to form six
scenarios, they are: (1) High Growth, Low Price; (2) Low Growth, High Price; (3) Green Future;
(4) Alternate Weather Standard; (5) Supply Constraints; and (6) the Expected Case.
Avista defines three different geographic demand classifications: demand area
service territory, and division. The demand areas are used for SENDOUT(ID modeling and are
structured around the pipeline resources that serve them. These are then aggregated into the
service territories and divisions for presentation throughout the IRP. See Staff Comments at
Geographic Demand Classification
Demand Area Service Territory Division
Spokane NWP Washington/Idaho North
Spokane GTN Washington/Idaho North
Spokane Both Washington/Idaho North
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Each modeled scenario has two types of demand forecasts, annual demand, and peak-
day demand. Peak-day demand is for determining the adequacy of existing resources or the
timing of acquiring new resources under extreme weather conditions. In order to estimate both
forecasts for each scenario over the planning period, the Company must estimate the number of
customers, use-per-customer, normalized vs. extreme weather, natural gas prices, and price
elasticity for each geographic area. These results, when combined with one another, are used to
develop the IRP demand forecast.
Staff observed that A vista forecasts its core customer growth at the town code level
for residential, commercial, and industrial customers. There are 56 town codes in Washington
26 in Idaho, and 37 in Oregon. These 119 town code forecasts are used for optimizing decisions
within these geographic sub-areas. The Company utilizes Global Insights, a third-party data
provider, for its 20-year growth forecasts. This data is combined with local knowledge about
sub-regional construction activity, age, and other demographic trends and historical data to
determine the long-term forecasts. By 2028-, the number of Washington/Idaho customers is
projected to increase at an average annual rate of 2.2%. In Idaho customer growth is expected to
be 3.0% for residential, 2.5% for commercial and 0.6% for industrial. Id. at 9.
In Washington and Idaho use-per-customer is expected to be flat, with demand
growing at a compounded average annual rate of 1.0%. The Company modeled several price
elasticity factors , but used low-price elasticity response factors in its Expected Case. Unless
there is an annual real price increase exceeding 30%, elasticity will remain unchanged.
However, with annual real price increases over 30%, the Company s estimated elasticity factor is
negative ., meaning that as natural gas prices increase by 10% there will be a 0.6% decrease in
usage. In the Company s Expected Case, there are two modeled price increases over 30%, one
in 2010 as a result of the recession s very low gas prices and another in 2015 due to carbon
adders. Staff asserts that the Company should continue to estimate several price elasticity
factors, especially given prices are expected to begin increasing rapidly in 2015. However, Staff
encourages the Company to do more detailed research on tariff rate price elasticity, especially
base usage price elasticity. Staff sees tariff rate price elasticity as a reasonable place for research
given that it has been difficult to accurately predict, the usage is not completely understood, and
it is where behavioral changes in usage can occur. Id. at 10.
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Weather is modeled differently when predicting annual demand vs. peak-day demand.
Annual demand is modeled based on the National Oceanic Atmospheric Administration
(NOAA) 30-year average, whereas peak-day demand adjusts the 30-year average to reflect a
five-day cold weather event (W A/ID- 82 HDD
, -
17 degrees Fahrenheit). Staff agrees with the
way the annual demand and peak-day demand weather scenarios are modeled. However, Staff
encourages A vista to continue evaluating the correlation between weather trends at various
stations within Washington and Idaho, to make sure it is not necessary to use a larger number of
weather stations to estimate demand, similar to the demand analysis conducted in Oregon. Id.
Avista projected a Washington/Idaho peak-day demand shortage in the 2007 IRP to
occur in 2014-2015 , driven primarily by average compounded demand growth of 2% per year
and average natural gas customer growth of 2.4% in the residential sector. However, in the
Expected Case of the 2009 IRP, the Company is less optimistic about future growth, primarily
because of the economic slowdown experienced nationwide. Therefore, A vista does not project
a peak-day demand shortage until 2022-2023 in its Washington/Idaho region. However, the
Company states that if demand growth accelerates, a steeper demand curve could quickly
accelerate resource shortages by several years. Therefore, the Company plans to monitor the
Expected Case assumptions and forecasts underlying its projections to address future shortages
in a timely manner. Given the Company s estimated time frame for resource shortages has been
pushed out eight years between IRP', Staff encourages the Company to closely monitor the "flat
demand risk" I associated with accelerating demand so that it has an adequate lead time to
acqUIre resources.
I A resource risk that should demand growth accelerate, the steepening of the demand curve could quickly
accelerate resource shortages by several years, possibly leaving the utility without sufficient supplies.
ORDER NO. 32064
Figure 1.5 WAllO Existing Resources YS. Peak Day Demand
ExpectedCase (Net of DSM Savings) November to October
400,000 .
350.000 .
Prior Short
50 000 .
0 J
~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~
~~ Q
& # # ~ ##~~~~~~~~~~~~ ~~ ~~#~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~##~ #~~ ~ #
_ExistingGTN _ExistingTF.
""., "
ExislingTF-IiiiiiiSSpokane Supply
-+-
Peak Day Demand """""Prior IRP Peak Day Demand
........
Current
300,000
250,000
! 200,000.
150,000 .;
100.000 )
The Demand-Side Resources
Demand-side management (DSM) is the activity pursued by an energy utility to
influence its customers to reduce their energy consumption or change their patterns of energy use
away from peak consumption periods. In the 2007 IRP, for the north division in the Expected
Case, the Company s 2010 DSM savings goal was 1 755 829 therms. By comparison, in the
2009 IRP, the Company s 2010 DSM savings goal is 2 193 338 therms, or nearly 25% more
savings in this IRP. The Company says the potential increase in the target is the result of a steep
carbon mitigation cost adder anticipated to take effect in 2015. Although not mentioned in the
IRP, Staff believes the Company s existing and future DSM programs will begin to have higher
participation rates as recessionary natural gas prices recover due to increased demand, and in
anticipation of natural gas price increases from carbon legislation. Id. at 12.
In order to influence customers to implement natural gas efficiency upgrades now
based on a price increase modeled to take effect in 2015, the Company has several programs
targeting conservation measures. These measures are divided into two types: base load
measures; and weather sensitive measures. Base load measures save energy independently of
weather, while weather sensitive measures are influenced by temperature.A vista has
ORDER NO. 32064
residential base load measures and 39 non-residential base load measures. Some examples of
base load measures include: high-efficiency water heaters, dishwashers, and front-load clothes
washers. Avista has 21 residential weather sensitive measures and 15 non-residential weather
sensitive measures. Weather sensitive measures save the most energy during the coldest periods
and therefore have a higher avoided cost than base load measures. In order to prepare customers
for significant price increases modeled to take effect in 2015 , Staff encourages the Company to
closely evaluate program participation levels and market saturation to make sure its marketing
efforts are effective. Id.
When evaluating measures for cost-effectiveness, Staff reports that Avista uses a
multi-phase approach by: (1) identifying the Technical Potential; (2) assessing the Achievable
Potential; (3) test modeling in SENDOUT(ID ; and (4) developing Conservation Goals. The
Technical Potential estimates all energy savings that can theoretically be accomplished if every
customer that could potentially install a conservation measure did so without consideration of
market barriers such as cost and customer awareness. The Achievable Potential is a more
realistic assessment of expected energy savings. It recognizes and accounts for economic and
other constraints that preclude full installation of every identified conservation measure.
Although Staff sees the Technical Potential as being somewhat general, it is understandable that
the base level market potential must be established for estimating the impact of the constraints
precluding full installation. Therefore, Staff believes it is reasonable to continue offering both
estimates within the IRP. Once the technical and achievable potential have been identified, the
Company begins SENDOUT(ID test modeling. When developing the 2007 IRP conservation
goals, the Company simply grouped measures into bundles to facilitate easier data input and
faster SENDOUT(ID system processing. However, in this IRP, the Company has made an extra
effort to test each individual conservation measures using the SENDOUT(ID model. Staff
believes this level of testing helps guarantee that the savings associated with specific measures
are not incorrectly estimated, overstated, or deemed cost-effective when they are not. Staff
further believes that the IRP meets the requirements for evaluation of efficiency improvements
(demand-side management or DSM) and avoided costs. Id. at 12-13.
2 Linear programming model widely used to solve natural gas supply and transportation optimization questions.
ORDER NO. 32064
The Integrated Resource Portfolio
The Integrated Resource Portfolio is the Company s comprehensive analysis of
bringing a risk-adjusted, least-cost plan together based on daily, monthly, seasonal and annual
assumptions. The assumptions in this analysis relate to: (1) demand data (customer count and
usage); (2) weather; (3) transportation and storage; (4) natural gas supply availability and
pricing; (5) cost of new assets (revenue requirements); and (6) demand-side management. These
factors are incorporated into SENDOUT(ID, and then several scenarios are evaluated to form an
assessment of how the supply of existing resources will meet demand. The resource options are
evaluated based on the cost, lead time requirements demand period (peak vs. base load),
usefulness, timing of various quantities, risks and uncertainties. After evaluating the resources
based on avoided cost and the criteria above, the least-cost approach is selected to meet resource
deficiencies. Id. at 13.
Staff believes the Company does an adequate job of reviewing several different
scenarios, and in determining the likelihood of these occurring. As mentioned previously, in the
Expected Case for Washington and Idaho, a resource deficiency does not occur until 2023. Once
the deficiency is identified, the model shows a general preference for incremental transportation
resources from existing pipelines and supply basins to resolve the capacity deficiencies. In
Washington and Idaho, the Company has determined the lowest-cost resource to meet this
deficiency is additional TransCanada Gas Transmission Northwest (GTN) capacity. GTN is a
subsidiary of TransCanada Pipeline, which owns and operates a natural gas pipeline that runs
from the Canada/USA border to the Oregon/California border. This pipeline runs directly
through or lies in close proximity to Avista s service territories. The GTN system currently has
ample unsubscribed capacity. Mileage-based rates and backhaul potential are options for
securing incremental resource needs; therefore, A vista will use this to meet the 2023 resource
deficiency. In the case where upstream pipeline GTN capacity is fully subscribed and capacity is
not available, Avista would rely on satellite LNG for Washington and Idaho. Staff encourages
the Company to closely evaluate the level of unsubscribed capacity on GTN as the system
becomes more fully subscribed, primarily to make sure it's not forced to rely on more expensive
LNG. Id. at 14.
ORDER NO. 32064
The Alternate Scenarios, Portfolios, Stochastic Analysis
Staff noted that A vista uses a deterministic modeling approach where several
alternate demand and supply scenarios are applied to develop a broad diversity of possible
alternate portfolios. As mentioned in the demand forecasting section, the Company lays out six
different scenarios including its Expected Case. Within these scenarios, the Company models
two distinct price increases: one occurs almost immediately as the recession ebbs and the second
occurs in 2015 as a result of significant carbon cost adders for when climate change policy goes
into effect. In its "High Growth, Low Price" scenario, which is the most rapid demand growth
the Washington and Idaho territory goes unserved February 2016. The Company contends that
with the potential for accelerated unserved dates, it will closely monitor demand trends and
resource lead times. Id.
Because exchange agreements and LNG prices are difficult to predict, Avista runs
several supply scenarios. For Washington and Idaho, two additional supply-side scenarios with
changed assumptions on GTN capacity were run. One scenario assumed significantly higher
rates, because of fewer contracts. The other scenario assumed GTN capacity becomes fully
subscribed and there is no capacity available. Both alternate supply scenarios resulted in satellite
LNG as the preferred backup resource portfolio. Once alternate demand and supply scenarios
are matched together to form portfolios, the resources are run through SENDOUT(ID and the
Expected Case becomes the lowest Net Present Value Revenue Requirement (NPVRR)
portfolio given expected demand, existing supply and anticipated availability.
Once the Expected Case is determined, the Company also tests its portfolio using
stochastic modeling, a technique of predicting outcomes that take into account a certain degree
of randomness or unpredictability. By estimating the probability distributions associated with
the unpredictability of potential outcomes, the Company can determine how random historical
variation in natural gas prices and weather might impact portfolios. This allows the Company to
plan for more realistic cost comparisons, aside from re-occurring design conditions which can
overstate total system costs. To investigate whether the total Expected Case portfolio cost is
within an acceptable range given 200 unique pricing scenarios, the Company conducts Monte
3 NPVRR - provides a means of equilibration between a dollar spent today and a dollar spent in the future.
ORDER NO. 32064
Carl04 simulations with varying prices. Avista derived over 200 Monte Carlo weather
simulations in order to stress test the deterministic analysis for weather variability and to test its
parameters for design weather planning. In the simulations, random monthly HDD values are
distributed on a daily basis for a month in history with similar HDD totals. This simulation
provides robust weather patterns that the Company can utilize for further testing its portfolio, and
provides an estimate on how frequently a design day could potentially occur.
The stochastic analysis shows that with over 200 20-year simulations (i., 4 000
years), the Washington/Idaho peak-day occurrence is expected to occur only once every 571
years. Based on the frequency of the peak-day occurrence, the Company maintains that peak-
day occurs with enough frequency to keep its standard for IRP planning the same. In this IRP
Staff accepts the Company s conclusion, but believes the reserve margin for peak-day planning
warrants continued analysis, especially given that the prudency of additional capacity costs are
evaluated in rate cases. Staff wants to be sure customers are not carrying the additional cost for
overbuilt resources because the reserve margin for peak-day occurrences is too high.
DISCUSSION
The Commission has reviewed Avista s 2009 natural gas Integrated Resource Plan
(IRP) and Staffs detailed comments. We find that the Company s IRP contains the necessary
information and is in the appropriate format as directed by our Order No. 22999. We further find
that Staffs comments have been very helpful and informative in reviewing the IRP.
We appreciate Avista s efforts in refining and improving its IRP. The Company has
done a good job with its risk analysis. We encourage the Company to closely monitor economic
conditions and financial markets regarding natural gas demands, credit availability, and
commodity prices. We further encourage the Company to closely monitor its assumptions
concerning gas supply from Canada so that if changes occur, the Company will have sufficient
time to obtain the necessary resources.
We do adopt several of the Staffs recommendations. First, we direct Avista to do
more detailed research on the price elasticity of natural gas. Additional research on customer
usage may yield useful data. Second, given the Company s estimated time frame for resource
shortages, we encourage the Company to closely monitor the flat demand risk. In the event that
4 A statistical modeling technique employed in SENDOUT for evaluating risk and uncertainty given the possibilities
that exist with a real-life system.
ORDER NO. 32064
demand growth accelerates, then it could result in a shorter period in which the Company must
acquire resources to meet the shortage.
Third, A vista should closely evaluate the level of unsubscribed capacity on the
TransCanada gas pipeline as that system becomes more fully subscribed. If this system capacity
becomes fully subscribed, then A vista may have to rely on satellite LNG for both its
Washington/Idaho customers. Finally, we find that the Company s reserve margin for peak-day
planning warrants continued analysis. This is especially true given that the prudency of
additional capacity costs are evaluated in general rate cases. The point here is that customers
should not be responsible for the additional cost of overbuilt resources because the reserve
margin for peak-day occurrences is too high.
ACCEPTANCE OF FILING
Based upon our review, we accept for filing the Company s 2009 natural gas
Integrated Resource Plan. Our acceptance of the IRP should not be interpreted as an
endorsement of any particular element of the plan, nor does it constitute approval of any resource
acquisition or proposed action contained in the plan.
ORDER
IT IS THEREFORE ORDERED that Avista s 2009 natural gas Integrated Resource
Plan is accepted for filing.
IT IS FURTHER ORDERED that Avista s 2011 IRP address those four
recommendations set out in the "Discussion" section above.
THIS IS A FINAL ORDER. Any person interested in this Order (or in issues finally
decided by this Order) or in interlocutory Orders previously issued in this Case No. A VU-09-
06 may petition for reconsideration within twenty-one (21) days of the service date of this Order
with regard to any matter decided in this Order or in interlocutory Orders previously issued in
this Case No. A VU-09-06.Within seven (7) days after any person has petitioned for
reconsideration, any other person may cross-petition for reconsideration. See Idaho Code ~ 61-
626.
ORDER NO. 32064
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this /0
day of September 2010.
ff. (
. KE PTO , PRE DENT
6~ ti~
MARSHA H. SMITH, COMMISSIONER
ATTEST:
~fJ
D. Jewell
Commission Secretary
bls/O:A VU-O9-06 dh2
ORDER NO. 32064