20100323Comments.pdf

DONALD L. HOWELL, II
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 3366
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LIJ¡ U 2~"ì P~ "1 2: 5ì
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE FILING BY A VISTA )
CORPORATION DBA A VISTA UTILITIES OF )
ITS 2009 NATURAL GAS INTEGRATED )RESOURCE PLAN (IRP). )
)
)
CASE NO. AVU-G-09-6
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilties Commission, by and through its Attorney of
Record, Donald L. Howell II, Deputy Attorney General, submits the following comments in
response to Order No. 30990 issued on January 28,2010.
BACKGROUND
On December 30,2009, Avista Corporation dba Avista Utilties fied its 2009 natural gas
Integrated Resource Plan (IRP) with the Commission. In Order No. 22290 issued in January
1989, the Commission required electric and natural gas utilities to fie a biennial IRP describing
the utility's plans to meet the future energy needs of its customers. The IRP is a comprehensive
long-range planing tool designed to identify and evaluate forecasted natural gas requirements.
The purpose of the IRP is to plan for the acquisition of the most cost-effective, risk-adjusted
portfolio of existing and future resources, and to meet the daily and peak-day demand and
delivery requirements over the next 20-year period. IRP at p. 2.4. Avista's IRP includes:
STAFF COMMENTS 1 MARCH 23, 2010
Demand forecasts; natural gas price forecasts; supply resources; demand-side management
(DSM) programs; resource needs; and the 2010-2011 near-term action plan. The Company
states that this IRP was developed during the last two years when the United States and other
countries 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 outcome" in this IRP. IRP at p. 1.1.
A vista serves approximately 315,000 natural gas customers in three states including
about 73,000 natural gas customers in northern Idaho. In Avista's northern operating division
(eastern Washington and northern Idaho), it serves roughly 218,000 natural gas customers. The
Company's customer base is generally comprised of 94% residential customers, 5% commercial
customers, and 1 % industrial customers. IRP at p. 2.3.
1. The IRP
The Company's approach to demand forecasting focuses 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 (e.g., natual gas
vehicles), and consumption per customer. In the demand forecast, Avista lays out six different
scenarios including its "Expected Case"i scenario. System wide in the Expected Case, Avista
anticipates a compounded average growth in daily demand of 1.1 % during the period 2010 to
2028-2029 (net of projected conservation savings from DSM programs). During the same time
frame, the Company estimates that its peak-day demand wil increase by a compound rate of
1.3%. ¡d.
The Company maintains that natural gas prices are a fudamental component of
integrated resource planning. Although A vista does not believe that it can accurately predict
future prices over the 20-year horizon, it has developed high, medium and low-price forecasts for
the price of natural gas.
A vista 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
i The "Expected Case" is the Company's estimate of the most likely outcome given its experience, industr
knowledge and understanding of future natural gas markets.
STAFF COMMENTS 2 MARCH 23, 2010
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. ¡d. at p. 1.5. Matching its resource supply
scenario with its Expected Case demand scenaro, the Company forecasts that its
Idaho/Washington service territory wil not experience a supply deficiency until the year 2023.
IRP at p. 1.6. The graph of the forecast shortages is almost flat, which leads the Company to
conclude that its existing resources wil be sufficient for quite some time to meet demand.
2. IRP 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
planing 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; feasibilty 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 wil
update its analytical work or consider hiring outside experts in price
elàsticity 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 milion therms in 2010. This goal represents an
increase of25% in Washington/Idaho from the 2007 IRP.
· 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.
¡d. at pp. 1.11-l2.
STAFF COMMENTS 3 MARCH 23, 2010
3. Risk Issues
The Company has identified three general issues that require monitoring and may
increase risk. First, the Company wil continue to monitor economic conditions and financial
markets on natural gas demand, infrastructue development, credit availabilty, and commodity
prices. Second, the Company wil continue to monitor federal climate change legislation and its
projected effects upon emission target levels, phase-in time frames, allocation of allowances,
availability of offsets, cost mitigation to customers, and a host of implementation 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, which have been at least a half decade in the making, are beginning to come
online. The near-term excessive LNG supply, combined with the projected increase in supply of
unconventional gas, and a lingering global recession may mean lower prices in the future.
"Although beneficial to end users in the near term, this dramatic volatilty and uncertinty could
cause long-term disruption in production, pipeline and storage capital investment, exacerbating
boom/bust cycles in the long term." IRP at 1.14.
ST AFF REVIEW
In accordance with the Public Utilties Regulatory Policy Act of 1978 (PURP A) (as
amended by the 1992 Energy Policy Act), Commission Order Nos. 25342, 27024 and 27098
require that the Company submit an Integrated Resource Plan (IRP) every two years, addressing
the following elements:
. Demand Forecasting
· Assessment of Effciency Improvements (DSM Actions) & Avoided Costs
· Natural Gas Supply Options
· Natural Gas Purchasing Options and Cost Effectiveness
. Integration of Demand and Resources
· Short-Term Action Plan
· Relationship Between Consecutive Plans (2007 Plan to 2009 Plan)
. Public Participation
STAFF COMMENTS 4 MARCH 23,2010
The Company's 2009 IRP addressed each of these elements to various degrees. The Company's
Submittal complies with the requirements of the Commission Order No. 25342 as described in
more detail below.
The Supply-Side Resources
A vista has a diversified portfolio of natural gas supply resources, including owned and
contracted storage, firm capacity rights on six pipelines, and commodity purchase contracts from
several different supply basins. The Company's philosophy is to reliably provide natural gas to
customers with an appropriate balance of price stabilty and prudent cost while building a
diversified portfolio to manage risk in continuously changing market conditions.
A vista benefits from its close proximity to the two largest natural gas producing regions
in North America; the Western Canadian Sedimentar 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 pipeline export potentiaL.
However, recent large pipeline projects now connect these basins to large population bases in the
Southwest, Midwest, and Northeast, which have diminished the discounted price advantage that
Avista has 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 furher erode or eliminate altogether the price advantage.
Procurement of natural gas is done via contracts. For the IRP, the SENDOUT(ß 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.
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 utilzation and index purchases.
Although the specific provisions for the plan wil 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 summer fillng of storage and durng the
heating season. In recognition of the volatilty present in the markets, the Company is
STAFF COMMENTS 5 MARCH 23, 2010
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.
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, ceilng and other collars, physical price hedging and financial price hedging. The
Company recognized that a diverse portfolio of supply options wil reduce price and volatilty
risk and utilzes most of these purchasing tools.
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 $7.39, $6.85, 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 diffcult. 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 drillng 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 (REC's) develops, Staff
would like to see the Company narow 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 wil remain steady, to allow time for additional resources when necessary.
In the Expected Case for Washington and Idaho, Avista 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 profie. The numerous benefits of storage include:
. Invaluable peaking capability;
. Access to typically lower cost off-peak supplies;
STAFF COMMENTS 6 MARCH 23, 2010
· Reduces the need for higher cost anual firm transportation;
· Storage injections increase the load factor of the existing firm transportation, and;
· Additional supply point diversity.
A vista'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 utilzed mostly for the
benefit of Avista's Oregon customers.
The Company is one-third owner, with 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 facilty with a total working gas capacity of
approximately 25 Bcf. Avista's current share of this capacity for core customers is
approximately 5.2 Bcf and includes 266,667 Dth of daily deliverabilty rights.
In 1999, and again in 2002, A vista paricipated in capacity expansions of the project with
NWP and PSW. It was determined that the additional capacity for core utilty customers was not
needed at that time, and the expansion went under the management of Avista Energy, Avista's
former non-regulated energy marketing and trading affliate. In June 2007, Avista Energy sold
substantially all of its energy contracts and ongoing operations to Shell Energy North America,
L.P. (Shell). Concurrent with the sales transaction, Avista reacquired the rights to the 2002
expansion 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 deliverabilty. After April 30, 2011, Avista plans on recallng
these rights for availabilty in their utilty operations, and have included it in the SENDOUT(ß
model as an incremental available storage resource at that time.
Other regional storage facilities exist and may be cost effective. Additional capacity at
the Mist facility, capacity at one of the Alberta area storage facilities, Clay Basin in northeast
Utah, and northern California storage are all possibilties. However, transportation to and from
these facilties to Avista's service territory continues to be the largest impediment to contracting
these storage options.
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 satellte LNG plant where LNG is trucked to the
STAFF COMMENTS 7 MARCH 23, 2010
facility in liquid form rather than liquefying on site, and a Company-owned liquefaction LNG
facility have all been evaluated and considered.
All of the elements of the Company's supply portfolio, procurement options and
planing, taken together, satisfy the requirements ofPURPA and provide cost effective supply
for all classes of customers.
Distribution Planning
Avista's integrated resource planing encompasses evaluation of safe, economical and
reliable full-path delivery of natural gas from basin to burner tip. Securng adequate natural gas
supply and ensuring sufficient pipeline transportation capacity to its local service areas become
secondar issues if the local distribution areas are not adequately planed and become severely
constrained. The IRP addresses future local demand growth, determines potential areas of
distribution system constraints, analyzes possible solutions and estimates costs for eliminating
constraints.
Avista'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.
Demand Forecasting
The integrated resource plan (IRP) begins with the development of a demand forecast.
Avista uses a Dynamic Demand Methodology, 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.
STAFF COMMENTS 8 MARCH 23, 2010
A vista defines three different geographic demand classifications: Demand Area, Service
Territory, and Division. The demand areas are used for SENDOUT(ß 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.
Geographic Demand Classification
Demand Area Service Territory Division
Spokane NWP Washington/Idaho North
Spokane GTN Washington/Idaho North
Spokane Both Washington/Idaho North
Medford NWP Medford/Roseburg South
Medford GTN Medford/Roseburg South
Roseburg Medford/Roseburg South
Klamath Falls Klamath Falls South
La Grande La Grande South
Each modeled scenario has two types of demand forecasts, anual 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. Annual demand is useful for
preparing revenue budgets, procurement plans, and preparing purchased gas adjustment (PGA)
filings. In order to estimate both forecasts for each scenario over the planing 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.
Core customer growth is forecasted 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 utilzes Global Insights, a third-pary 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 2028-29, the number of Washington/Idaho customers is projected to
increase at an average anual rate of2.2%. In Idaho customer growth is expected to be 3.0% for
residential, 2.5% for Commercial, and 0.6% for IndustriaL.
STAFF COMMENTS 9 MARCH 23, 2010
In Washington and Idaho use-per-customer is expected to be flat, with demand growing
at a compounded average anual 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
anual real price increase exceeding 30%, elasticity wil remain unchanged. However, with
annual real price increases over 30%, the Company's estimated elasticity factor is negative .06,
meaning that as natural gas prices increase by 10% there wil 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
believes 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.
Weather is modeled differently when predicting annual demand vs. peak day demand.
Annual demand is modeled based on the National Oceanic Atmospheric Administration's
(NOAA) 30-year average, whereas peak day demand adjusts the 30-year average to reflect a
five-day cold weather event (W AlID- 82 HDD, -17 degrees Fahenheit). Staff agrees with the
way the anual demand and peak day demand weather scenarios are modeled. However, Staff
encourages the Company to continue evaluating the correlation between weather trends at
various stations within Washington and Idaho, to make sure it's not necessar to use a larger
number of weather stations to estimate demand, similar to the demand analysis conducted in
Oregon.
As shown below, A vista projected a Washingtonldaho peak day demand shortage in the
2007 IRP to occur in 2014-2015, driven primarly 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,
Avista doesn't 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
STAFF COMMENTS 10 MARCH 23, 2010
shortages in a timely manner. Given the Company's estimated time frame for resource shortges
has been pushed out 8 years between IRP's, 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.
Figure 1.5 WAllO Existing Resources vs. Peak Day Demand
Expected Case (Net of DSM Savings) November to October
400,000
Prior Short
350.000 :...."...."
300.000
250,000
g 200,000
150,000
100.000
50.000
o ~~ ~~~~~~ ~~ ~ ~ #~~ø#~ ~ #~~~~~¥K¥~KK ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ #~~#~##~~_Existing GTN _ Existing TF.1 bywlExistíng TF-2
lii'Spokane Supply __ Peak Day Demand -l Prior IRP Peak Day Demand
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. This includes marketing campaigns and financial
incentives to persuade customers to adopt conservation measures. Cost-effective DSM measures
may include incentives for the purchase of high efficiency appliances (water heaters, clothes
dryers, furnaces), insulation, weather-stripping, insulated windows and duct work, and heat
recovery systems. The Company considered a total of 155 residential and 147 non-residential
DSM measures in this IRP. In the 2007 IRP, for the North Division in the Expected Case, the
2 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 utilty without suffcient supplies.
STAFF COMMENTS 11 MARCH 23, 2010
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 wil begin to have higher
paricipation rates as recessionar natural gas prices recover due to increased demand, and in
anticipation of natural gas price increases from carbon legislation.
In order to influence customers to implement natural gas effciency 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 13 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. Some examples of weather sensitive measures
include: high efficiency furnaces, ceilng/walllfoor insulation, weather stripping, insulated
windows, duct work improvements, and ventilation heat recovery systems. In order to prepare
customers for significant price increases modeled to take effect in 2015, Staff encourages the
Company to closely evaluate program paricipation levels, and market saturation to make sure its
marketing efforts are effective.
When evaluating measures for cost effectiveness, A vista uses a multi phase approach by:
1) Identifying the Technical Potential; 2) Assessing the Achievable Potential; 3) Test modeling
in SENDOUT(ß3; 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 bariers 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
3 Linear programming model widely used to solve natural gas supply and transportation optimization questions.
STAFF COMMENTS 12 MARCH 23, 2010
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 test
modeling in SENDOUT(ß. This involves entering each individual conservation measure to
enable more granular and accurate measure selection for DSM resource acquisition. Once
measures are selected, the Company develops its final conservation goals by augmenting the
measure results of SENDOUT(ß with estimates from the commercial and industrial site specific
programs. This eliminates the site-specific program savings already captured in the
SENDOUTtI model, and prevents the double counting of measure savings. When developing
the 2007 IRP conservations goals, the Company simply grouped measures in to bundles to
faciltate easier data input and faster SENDOUT(ß system processing. However, in this IRP, the
Company has made an extra effort to test each individual conservation measure in SENDOUT(ß.
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.
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 anual
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 availabilty and pricing;
5) Cost of new assets (revenue requirements); and 6) Demand-side management. These factors
are incorporated into SENDOUTtI, and then several scenarios are evaluated to form an
assessment of how the supply of existing resources wil 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 uncertinties. After evaluating the resources
based on avoided cost and the criteria above, the least-cost approach is selected to meet resource
deficiencies.
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
STAFF COMMENTS 13 MARCH 23, 2010
the deficiency is identified, the model shows a general preference for incremental transporttion
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
subsidiar of TransCanada Pipeline, which owns and operates a natural gas pipeline that rus
from the Canada/SA border to the Oregon/California border. This pipeline runs directly
through or lies in close proximity to Avista's service terrtories. The GTN system currently has
ample unsubscribed capacity. Mileage based rates and backhaul potential are options for
securing incremental resource needs, therefore A vista wil 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.
The Alternate Scenarios, Portfolios, Stochastic Analysis
Avista 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 go into effect. In its
"High Growth, Low Price" scenario, which is the most rapid demand growth, the Washington
and Idaho terrtory goes unserved February 2016. The Company contends that with the potential
for accelerated unserved dates, it wil closely monitor demand trends and resource lead times.
Since exchange agreements and LNG prices are difficult to predict, A vista 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 not capacity available. Both alternate supply scenarios resulted in satellte 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(ß and the
STAFF COMMENTS 14 MARCH 23, 2010
Expected Case becomes the lowest Net Present Value Revenue Requirement (NPVRR)4
portfolio given expected demand, existing supply and anticipated availabilty.
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 certin degree
of randomness or unpredictabilty. By estimating the probabilty 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 reoccurrng 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
CarloS simulations with varing prices. A vista 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 planing. 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 utilze 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 twenty-year simulations (i.e. - 4000
years), Medford's peak day occurence is expected to occur once every 31 years. In Washington
and Idaho, peak day occurrence is only expected to occur once every 571 years. Based on the
frequency of the peak day occurence, the Company maintains that peak day occurs with enough
frequency to keep its stadard for IRP planing the same. In this IRP Staff accepts the
Company's conclusion, but believes the reserve margin for peak day planning warants
continued analysis, especially given the prudency of additional capacity costs are evaluated in
rate cases. Staff wants to be sure customers are not caring the additional cost for overbuilt
resources because the reserve margin for peak day occurences is too high.
Additional Comments
According to Commission Order No. 25342, the Company is required to provide a two-
year plan, a progress report that relates the new plan to the previously filed plan (2007 Plan to
2009 Plan), and allow public paricipation and comment while formulating its plan. As
4 NPVRR- Provides a means of equilbration between a dollar spent today and a dollar spent in the future.
S A statistical modeling technique employed in SENDOUT for evaluating risk and uncertainty given the possibilties
that exist with a real-life system.
STAFF COMMENTS 15 MARCH 23, 2010
mentioned in the introduction, the Company clearly identifies and establishes a near-term action
plan that wil steer the Company toward the risk-adjusted, least-cost method of providing service
to its natural gas customers. Throughout the IRP, the Company relates the new plan by
referencing the previously fied plan. The action items from the prior fiing are identified, and
the corresponding results of its interim evaluations are discussed. The Company has allowed an
opportunity for public participation and comment through regularly held meetings with the
Technical Advisory Committee (T AC) consisting of staff from the three states' Commissions,
several Non-governent Organizations (NGOs) and members of the public. While developing
the plan, the Company solicited feedback on several of its IRP inputs, and frequently
communicated its modifications through e-mail, conference calls, and individual meetings.
STAFF RECOMMENDATION
Staff believes that Avista's 2009 Natural Gas IRP satisfies the requirements of
Commission Order No. 25342. Staff recommends that the Company's fiing of its 2009 IRP be
acknowledged and accepted. This recommendation should not be interpreted as approval or as a
judgment of prudence that mayor may not have been demonstrated by the Company in preparing
the IRP or the prudence of not following the plan.
Respectfully submitted this 23 J day of March 2010.
Donald L. H ell, II
Deputy Attorney General
Technical Staff: Matt Elam
Donn English
i: umisc/commentslavug09.6dhmedetc
STAFF COMMENTS 16 MARCH 23, 2010
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 23RD DAY OF MARCH 2010,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. A VU-G-09-06, BY MAILING A COPY THEREOF, POSTAGE PREPAID AND VIA
E-MAIL, TO THE FOLLOWING:
GREGRAHN
A VISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-MAIL: greg.rahCfavistacorp.com
CERTIFICATE OF SERVICE