20060829Comments.pdf

CECELIA A. GASSNER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. 6977
RECEIVED
200& ~IUG 29 Pi"1 2:
IDAHO PU?'IQ", NI
UTILITiES CGrJ'dvllcdvh
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF INTERMOUNTAIN GAS
COMPANY'S 2007-2011 INTEGRATED RESOURCE PLAN. CASE NO. INT -06-
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, by and through its Attorney of
record, Cecelia A. Gassner, Deputy Attorney General, in response to the Notice of Filing and
Notice of Modified Procedure in Order No. 30090 issued on June 30, 2006, submits the
following comments.
BACKGROUND
On May 1 , 2006, Intermountain Gas Company ("Intermountain" or "Company ) filed its
2006 Integrated Resource Plan (IRP) for the years 2007-2011 with the Commission. In the
Executive Summary ofthe Company s IRP, the Company states that the IRP is meant to describe
the currently anticipated conditions from 2007-2011. It further states that the document is meant
to present strong guidelines rather than be "a prescription for all future energy resources." IRP at
1. The Company is the sole distributor of natural gas in southern Idaho, serving 275 800
customers in 74 communities during the first half of fiscal year 2006. Its system contains over
000 miles of transmission, distribution and service lines. Id. In fiscal year 2005, over 446
STAFF COMMENTS AUGUST 29, 2006
miles of distribution and service lines were added in response to new customer additions and to
maintain service for the growing customer base. Id.
Intermountain s two major markets are the residential/commercial market (the "core
market") and the industrial market. !d.Intermountain saw an increase of 5% in average
residential and commercial customers during the first half of fiscal year 2006. Id. Forty-four
percent (44%) of the throughput on Intermountain s system during fiscal year 2005 was
attributable to industrial sales and transportation. Id.
According to the IRP, the peak day send-out studies and load duration curves were
developed under design weather conditions to determine the magnitude and timing of future
deficiencies in firm peak day delivery capability. Residential, commercial and industrial peak
day load growth on the Company s system is forecast to grow at an annual average rate of 4%
over the next five years. The Company calculated the growth for the system as a whole as well
as for the separate regions in which the Company operates. When forecasted peak day send-out
is matched against existing resources, a peak day delivery deficit occurs during January 2007.
According to the Company, that peak day deficit increases at a rate of 38% per year for the
planning period if no action is taken. According to the Company s calculations, a deficit of firm
capacity begins to occur near the peak day beginning in the winter of 2009. IRP at 4. The IRP
sets forth the following abbreviated analysis ofthe Company s main service regions:
Idaho Falls Lateral Region
The Idaho Falls Lateral (IFL) region serves many cities between Pocatello to the south
and St. Anthony to the north. The residential, commercial and industrial load served off the IFL
represents approximately 15% of the total Company customers and 18% of the Company s total
winter send-out during December of2005. Id. When forecasted peak day send-out on the IFL is
matched against the existing peak day distribution capacity, a peak day delivery deficit occurs
during 2007 and increases thereafter. Id. Intermountain believes that small, short direction peak
day distribution delivery deficits in the future can be mitigated by working with customers who
have the potential to cut their peak day consumption by switching to fuel oil during extreme cold
temperatures. IRP at 5. However, the Company states that the projected delivery deficits are of
such magnitude that "looping" of the existing system is warranted to add necessary firm delivery
capability to the area.
STAFF COMMENTS AUGUST 29, 2006
Sun Vallev Lateral Region
The Company s residential, commercial and industrial customers in the Sun Valley
Lateral (SVL) region account for 4% of the total customer base and 4% of the Company s total
winter send-out during December of 2005. Id. When forecasted peak day send-out on the SVL
is matched against the existing peak day distribution capacity, a peak day delivery deficit occurs
during 2009 and increases thereafter. The tourism industry-related industrial load on the SVL is
limited in size and does not currently have the capability to switch to alternative fuels in order to
mitigate peak day send-out. IRP at 6. The Company believes that the growth in the SVL will
warrant future upgrades to the existing pipeline system, and the Company plans to increase the
delivery capability and capacity on the SVL through a series of cost-effective system upgrades.
Id.
Canvon County Region
Fourteen percent (14%) of the Company s residential, commercial and industrial load is
served off the Canyon County Lateral (CCL) region, and it accounted for 13% of the Company
total winter send-out during December of 2005. Id. When forecasted peak day send-out on the
CCL is matched against the existing peak day distribution capacity, a peak day delivery deficit
occurs during 2007 and increases thereafter. Id. The industrial customer base in the CCL region
does not currently have the capability to switch to alternative fuels as a means of mitigating peak
day send-out and the Company states that it is currently exploring optional means of enhancing
the distribution capability in this region. IRP at 7.
STAFF ANALYSIS
PURP A Requirements
In accordance with the Public Utilities Regulatory Policy Act of 1978 (PURPA) (as
amended by the 1992 Energy Policy Act), Commission Orders No. 25342, 27024 and 27098
require that the Company submit an Integrated Resource Plan (IRP) to the Commission every
two years, addressing the following elements:
Demand Forecasting
Assessment of Efficiency Improvements (DSM Actions) & Avoided Costs
Natural Gas Supply Options
Natural Gas Purchasing Options and Cost effectiveness
Integration of Demand and Resources
. Two-Year Action Plan
Relationship Between Consecutive Plans (2004 Plan to 2006 Plan)
Public Participation
STAFF COMMENTS AUGUST 29, 2006
The Company s 2006 IRP addressed each of these elements to various degrees, as described in
more detail below.
Demand Forecasting
In June 1997 the Commission granted the Company s request to change the planning
horizon for the Company s IRP process from twenty years to five years. See Order No. 27024.
The planning period of 2007-2011 used for this IRP meets that requirement. The Company
forecast, which is the basis for the 5-year planning period, provides daily, monthly and peak
demands and predicts significant growth of peak demand in the core sectors of residential and
commercial customers and stable peak demand in the industrial sector over the planning period.
The forecast is based on: 1) growth in the number of households in the service territory
commensurate with growth of the population and the economy, 2) corresponding growth in the
number of small commercial customers, and 3) conversion to natural gas use by residences that
presently do not use natural gas.
It is the Staff's opinion that , in general, the forecasting inputs and methodologies used by
the Company are neither as comprehensive nor as robust as they could be. Although Staff
concurs that some of the aspects of the modeling may be adequate, there are other factors that
should undergo a wider range of analysis than the Company performed here. The IRP should be
considered a comprehensive planning document performed for the benefit of the utility
customers. As such, and as noted in comments below, the Company should not shy away from
addressing multiple scenarios and sensitivity analyses for such items as natural gas pricing or
factors effecting demand when performing the analysis necessary for the IRP.
The Company relies on the May 2005 economic forecast for the State of Idaho issued by
John S. Church (the "Church forecast") for both the population and economic growth inputs to
its forecasts. The Church forecast uses household, employment and wage data to set a baseline
forecast and high and low growth forecasts. Although it would be better to use a more recent
forecast, Staff realizes that the 2005 forecast was the latest available when the IRP was prepared.
The Staff deems this forecast to be satisfactory when considered with the conservatism of the
heating-degree design year.
In its forecast model, Intermountain uses a Design Heating Degree Year based on the
coldest 12-month period of the preceding 30 years with some modification (October 1984
through September 1985). The modifications are: 1) that the coldest month of the 30-year record
STAFF COMMENTS AUGUST 29 , 2006
period replaces the coldest month for the design year (in this case, December 1985 replaced
January 1984), 2) the coldest day of the record period is used to set the peak demand day, and 3)
the heating degree-days in the remaining winter and shoulder months were increased by one
percent in recognition of the potential for colder weather in any month. The resulting heating
design year is compared to the coldest year (1985) and to the 30-year weighted normalized
average of the period of record in Graph 1. IRP at 30. Staff agrees with use of this conservative
design year data that provides a capacity to deliver commodity on the peak day that is more than
one-third greater than that needed to deliver the average peak of the period of record.
Market penetration rates for new households and customer conversion rates from other
energy sources for each service region during the planning period are presented in tabular
format. IRP at 21-22. The market penetration numbers presented in the IRP are more realistic
than those presented in the 2004 IRP. However, the increasing market penetration going forward
seems contradictory to market conditions and requires more explanation. For example, the
efficiency, availability and application methods of heat pumps make them competitive with
central natural gas heat at today s prices and it might be expected that electric heat will gain
market share. In such a case, the market penetration numbers would at least stay steady or
perhaps slightly decrease over time.
The conversion rates for existing homes are less optimistic than in the previous IRP
however, those conversion rates are presented as generally increasing over the planning period.
This seems counterintuitive since conversion reduces the size of the non-natural gas users
market. Given the large increase in retail natural gas prices in the past few years, while electric
prices have been relatively stable, the decrease in conversion rates is logical but the forecast
increase in conversion is not. The Company should address market penetration and conversion
rates in more detail in future IRPs to expand upon the reasoning behind the Company s analysis
that gas use will increase despite market forces that would otherwise lead economic forecasters
to conclude that gas use would decrease.
In the Company s forecast, total daily usage during the peak months of November
through February for residential and small commercial customers is determined through multiple
linear regression analysis and summed for monthly and annual demand. Each of the peak
months is individually modeled to establish customer usage through heating degree-days. Non-
peak weather sensitive usage is derived by subtracting non-heating base usage (defined as use
STAFF COMMENTS AUGUST 29, 2006
during July and August) from the remaInIng months and applying a separate weather
normalization analysis to the individual month on a daily basis.
Staff believes this to be an overly simplistic forecasting method that ignores other factors
driving demand, such as prices of natural gas and electricity, seasonality, and timed heating
systems among other factors. Use of one or more of these other factors could be included to
improve the model with little computational cost. Forecasts can and should be improved
whenever cost effective with the intent of solidifying the Company s prescribed action plan.
Staff recommends that in future IRPs, models that were tested but subsequently rejected in favor
of the documented models be reported. Finally, the Company may wish to consider modeling
the RS-, RS-1 and small commercial classes separately. It is reasonable to expect a different
response to weather patterns for the three groups of customers based on their characteristics.
In its forecasts, the Company uses a set of three price curves, one each for pricing at
Sumas, AECO and the Rockies for the IRP Planning Period (Exhibit No., Appendix A, Chart
4.2). This set of prices is used in the computer model to determine costs associated with
resource selection and to calculate the final costs resulting from the model selections. The
Company does not state in the IRP the source of the pricing nor does it make use of a range of
pricing that might correspond to the different economic cases used for the IRP.
Separately from the IRP, in a response to a production request, the Company states that it
used a single source for the natural gas pricing used in the IRP, the NYMEX market close data
plus basin differential pricing provided by IGI Resources, a BP Energy Company. No effective
date or dates for the price data was stated. The Company also stated in its response to a
production request that an additional pricing data point from November 6, 2005 was used in the
model to check for the impacts of differing pricing and that the results did not materially effect
the model's optimization. The Company goes on to state that inclusion of other forecast data
would result in as many as nine scenarios (low, medium and high customer growth for each
pricing scenario) without improving the IRP. These scenarios or sensitivity analyses are exactly
the product that Staff believes should be published in the IRP in order to show that the IRP has
resulted in selection of the best plan going forward. Otherwise, the reader has no basis for
believing that the Company has used anything other than intuition and reliance on a unique
1 RS-1 and RS-2 refer to the Company s two residential rate classes. RS-1 includes customers who do not have both
a gas furnace and gas water heater, regardless of other appliances. RS-2 customers have at least a gas furnace and a
gas water heater. IRP at 10.
STAFF COMMENTS AUGUST 29 , 2006
forecast to prepare the plan. Staff believes the number of scenarios that are necessary or the
computer sensitivity runs necessary to develop those scenarios is not an undue burden. Many
other utilities perform literally hundreds of runs for many scenarios to arrive at their planning
results.
Given that the IRP is written evidence that the utility has conducted a comprehensive
analysis of possible demand and supply scenarios, Staff believes it to be appropriate to use a
range of natural gas pricing forecasts applied to the economic bases of the IRP and to consider
the quality of multiple sources for those price forecasts. Also, Staff believes it is appropriate to
address the range of expected pricing in terms of any impacts on planning that expected or
possible price changes may have, such as changes in supply, a move to use more or less storage
more or less use of hedging, or a change in consumption due to price change (e.g. price
elasticity, which is addressed below).Staff recommends that the Commission require the
Company to use a range of natural gas price forecasts that consider multiple sources and
inclusion of sensitivity analysis with regard to economic issues in future IRPs. At least a half-
dozen other natural gas price forecasts exist that could be used for comparison, to ensure that too
much weight is placed in merely a single forecasted price set.
As mentioned, the demand forecast appears to lack certain considerations, including the
price elasticity of demand. In the past, this factor has often been thought of as not significant
within the retail price levels of natural gas. However, the large price increases of 2005 have
resulted in estimates of price elasticity in the range of 0.10-15 applying to the present range of
natural gas prices. This means that a 1 % increase in price results in a 0.10-15% decrease in
demand. With a 25% price increase (in 2005 the Company s retail price increased 27%), the
resulting expected change in demand would be 2.50-75 %. Staff considers this to be a
significant change. In its response to a production request on this topic, the Company states that
it has considered addressing price elasticity of demand but believes it is not appropriate
primarily due to its belief that price elasticity of demand will not effect the design weather
assumptions for the coldest day to be served. Staff understands that the Company may logically
come to that conclusion in its analysis, but would prefer to see the analysis conducted and
presented rather than have a simple assumption drive the IRP. The Company also states that it
does not wish to include price elasticity of demand because it would add additional possible
scenarios to be included in the IRP. As Staff has noted, that is precisely what is needed here - an
examination of all likely scenarios in order to derive the plan that will best meet customer
STAFF COMMENTS AUGUST 29, 2006
demands. Staff recommends that the Commission require price elasticity of demand to be
addressed in future IRPs to capture the effect the change in the price of the commodity may have
on consumer demand.
Assessment of Efficiency Improvements (DSM Resource Options)
In response to an April 27 , 1997 filing by the Company (Case No. INT-97-2), the
Commission issued Order No. 27098 allowing the Company, in its biennial IRP , to address
efficiency measures with a "general explanation with each IRP filing of whether there are cost
effective (demand-side management (DSM)) opportunities." Order No. 27098 at 2. Prior to that
time the Commission required that the IRP address ... a full spectrum of opportunities available
to the Company, including conservation and efficiency measures... ." Order No. 25342.
In addressing efficiency, the IRP provides an overview of growth of the North American
natural gas markets. and makes its case for natural gas being the most efficient energy source
available. IRP at 58-63. The Company goes further by addressing, among other things, its
support and promotion of:
Building codes requiring increased use of energy efficient equipment and
materials;
The Company s participation in the Gas Technology Institute s research and
development of higher efficiency applications for natural gas;
The Company s customer education practices that address efficiency;
Its participation in the Parade of Homes where they sponsored use of high
efficiency furnaces;
Sponsorship of a half day Energy Resources Symposium;
Outreach to educate senior citizens about conservation tips and payment options;
and
Past offering of rebates for customers that convert to high efficiency furnaces and
several other educational activities.
Beyond a very general statement of support for these and similar activities, there is no mention in
the IRP of any efficiency or DSM programs or evaluations of those programs being performed or
reviewed by the Company. Also lacking is any analysis to identify whether there are other cost-
effective DSM opportunities available.
The Company addresses the value of natural gas in replacing electricity for heat as a
more efficient use of heat than the generation of electricity through combustion of natural gas or
any other fossil fuel. In its assessment the Company calculates that without the natural gas heat
used in 2004 .. .Idaho Power s winter peak load could reach 4 259 megawatts, a 94%
STAFF COMMENTS AUGUST 29, 2006
increase!" IRP at 62. This section seems to justify greater gas consumption rather than promote
more efficient use of existing supply.
In response to a production request asking the Company, "What efficiency measures did
the Company review and consider in the 2006 IRP process and what were the results of those
reviews?" the Company responded as follows:
All of Intermountain Gas Company s Integrated Resource Plans that were filed
subsequent to the above referenced Order Number, including the 2006 IRP , included a
listing of "cost effective DSM opportunities." These measures are more fully explained in
the Company s filed IRP as contained in the section "The Efficient and Direct Use of
Natural Gas.
As previously noted, the Company actively promotes the wise and efficient use of natural
gas. The aforementioned media campaigns, conservation information and education on
the Company s website, and conservation minded bill stuffers all focus on cost effective
energy efficiency measures. The Company credits these efforts with a measurable
decline in weather adjusted baseload consumption.
Response of Company to First Set of Production Requests at 6.
Evaluation and use of cost-effective demand-side resources in a utility s resource mix is
the purpose of an integrated plan. Staff believes that education and information are an important
part of DSM, however, providing information and education are not DSM measures in that they
do not directly create alternative resources that can be quantified and substituted for supply side
resources.
Given the recent history of extreme upward price pressure and volatility in the natural gas
markets, the impact of those prices on consumers, and the fact that there are few, if any,
expectations of substantial decreases in natural gas prices, Staff considers the IRP's analysis of
cost-effective DSM measures to be inadequate, and believes that the Company has failed in this
IRP to satisfy the requirements of Commission Order No. 27098. It is more important than ever
that the Company help customers manage their consumption of natural gas. Conservation of this
resource is good for customers, the economy and business.Staff recommends that the
Commission direct the Company to address the "full spectrum of opportunities available to the
Company, including conservation and efficiency measures" that was part of the IRP process
prior to Order No. 27098. Staff believes that the IRP process should be expanded to require
cost/benefit evaluation of all feasible DSM programs and adoption of a mechanism that will
result in cost-effective DSM measures being implemented.
STAFF COMMENTS AUGUST 29, 2006
Natural Gas Supply Options
The Company addresses commodity supply in two sections of the IRP
, "
Traditional
Supply and Deliverability Resources" and "Non-Traditional Supply Resources." IRP at 45-
and 54-, respectively. Intermountain currently accesses natural gas from two supply basins
the Rocky Mountain Region and the Western Canadian Sedimentary Basin (British Columbia
and Alberta) through three pipeline systems, all of which reach the Company s service area via
the Northwest Pipeline System. The basins currently supplying natural gas to the Company are
quite large and have significant reserves. These same pipeline systems could be used in the
future to access additional sources of natural gas.
The Company s extensive use of natural gas storage to assure the ability to meet winter
demands (especially winter peak demands) provides the added benefit of significantly mitigating
high winter natural gas prices. The Company utilizes both underground and liquefied storage.
The Company owns underground storage in three different and geographically diverse locations.
The Company s underground storage is located to the west at Jackson Prairie in Washington
State, to the north at AECO in Alberta and to the southeast at Clay Basin in Utah. Intermountain
owns liquefied storage in two locations, Northwest Pipelines liquefaction facility in Washington
and a Company-owned liquefaction/gasification facility within the Company s service territory
west of Boise. All of the Company s out-of-service-territory storage is either bundled with
transportation to the service territory or is combined with Company-contracted transportation to
the service territory.
Two types of non-traditional resources are available to the Company: 1) the
encouragement customers (who have the capability to do so) to switch fuels from fuel oil to coal
and 2) the Company s use of alternative commodities, such as propane and transportable
liquefied natural gas. The Company s physical supply of natural gas is diversified by
geographical source and deliverability. In Staff's opinion the Company has adequately
addressed supply-side options in the IRP.
Natural Gas Purchasing Options and Cost Effectiveness
Intermountain s purchasing strategies for natural gas make it the lowest cost provider of
the two natural gas companies providing retail service in Idaho. This is due in large part to the
substantial use of storage gas purchased at summer prices. This year most of the summer gas
purchased for storage injections and free-flowing gas was hedged at prices well below the
existing weighted average cost of gas (W ACOG). This type of hedging, relative to the current
STAFF COMMENTS AUGUST 29, 2006
W ACOG, is consistent with the "Gas Supply Risk Management Program.z The Company and
Staff continue to evaluate the risk management guidelines within this program to manage the risk
and price volatility to customers.
The Company s documentation of its market evaluations and market fundamentals
continues to improve. The market expertise and experience of the Company and its purchasing
agent are extensive and will provide the background to evaluate the current guidelines and
expand the Gas Supply Risk Management Program as the Company and Staff continue to meet
on this topic.
Integration of Demand and Resources
The IRP section entitled "Load Duration Curves" identifies certain delivery constraints.
IRP at 42. These constraints fall into two categories: 1) deficits in delivery to the Company
system from the interstate pipeline, and 2) deficits in the Company s distribution system capacity
for delivery to its customers. Deficits of delivery into the system are shown in the following
table:
INTO SYSTEM PEAK DAY DELIVERY DEFICITS (mmbtu) from Ex. 3
FISCAL 2007 2008 2009 2010 2011
YEAR
Total High Growth 743 High Growth 898 High Growth 406 High Growth 954 High Growth 115 545
Company Base Case 316 Base Case 342 Base Case 950 Base Case 605 Base Case 85,070
Deliverability Low Growth 886 Low Growth 561 Low Growth 914 Low Growth 894 Low Growth 469
In addition, for distribution system delivery needs, the Idaho Falls Lateral, Sun Valley
Lateral, and Canyon County service areas are the only areas forecasted to have deficits for the
planning period. Those forecast deficits are shown below:
2 The objectives ofIntermountain Gas Company s Gas Supply Risk Management Program are to (a) help ensure
adequate gas supplies, transportation and storage are available for its customers; (b) mitigate the adverse impact that
significant price movements in the natural gas commodity can have on the Company s supplies, customers and other
operations; and (c) minimize the credit risk inherent in the implementation of certain price risk reducing strategies.3 Table created by Commission Staff using data provided by the Company in its IRP.
STAFF COMMENTS AUGUST 29, 2006
INTRA-SYSTEM DELIVERY DEFICITS (mmbtu) from Ex. 3
FISCAL 2007 2008 2009 2010 2011
YEAR
Idaho Fall High Growth 994 High Growth 513 High Growth 971 High Growth 037 High Growth 891
Lateral Base Case 045 Base Case 765 Base Case 686 Base Case 11,446 Base Case 108
Low Growth 946 Low Growth 830 Low Growth 725 Low Growth 321 Low Growth 069
Sun Valley High Growth High Growth High Growth 711 High Growth 789 High Growth 848
Lateral Base Case Base Case Base Case Base Case 929 Base Case 852
Low Growth Low Growth Low Growth Low Growth Low Growth
Canyon High Growth 861 High Growth 675 High Growth 013 High Growth 979 High Growth 057
County Base Case 374 Base Case 984 Base Case 860 Base Case 362 Base Case 15,897
Low Growth Low Growth 862 Low Growth 640 Low Growth 931 Low Growth 237
These deficits are addressed in the IRP section entitled "Resource Optimization." IRP at
64. For the system as whole the Company forecasts, in the year 1 base case, a peak day deficit in
delivery into the system of 23 316 mmbtu/day in 2007 growing to 85 070 in 2011. The IRP
states that this deficit will be met by acquiring an incremental 25 000 mmbtu of interstate
delivery on Northwest Pipeline in Year 1 of the plan (2007) along with unspecified contracts for
matching commodity. In the IRP the Company also addresses the need for 36 900 mmbtu in
year 5, but is less specific about how that deficit will be satisfied. The intervening years are not
addressed. The Company s modeling results designate "fill" for the needed commodity for this
deficit. "Fill" is the model's name for a generic acquisition. Although the data is available in
tables found in the exhibits, in the IRP the Company makes no statement about what specific
purchases or storage plans exist to satisfy this "fill" requirement. An improvement to this part of
the IRP would be for the Company to define the linkage between identifying the necessary
resources and performance under its natural gas acquisition policies and the Risk Management
Pro gram.
The Company filed amended pages 43 and 44 to specifically identify the deficits for the
planning period; however, the IRP does not match those deficits with planned resources. Staff
believes that the IRP is intended to be a plan of how the Company will fulfill its obligations to
supply its customers, but that piece is lacking in the IRP itself.
4 Table created by Commission Staff using data provided by the Company in its IRP.
STAFF COMMENTS AUGUST 29, 2006
Outside of the IRP, in its response to a production request, the Company stated it was
originally planned that specific lateral deficits will be met with specific resources as follows:
Canyon County -
a. 2007 - the relatively small deficit of 3 740 therms is eliminated
by utilizing mobile LNG. From a real-world standpoint, it is
possible that a deficit this small occurring on only one day may be
also resolved from short-term operational efficiencies.
b. 2008-11 - distribution main looping and pressure upgrades that
add 170 000 therms of additional delivery capacity resolves all
deficits thru 2011.
Idaho Falls Lateral -
c. 2007 - the 30,450 therm deficit is filled by using mobile LNG
d. 2008 -09 - the deficits are almost entirely filled by adding
000 therms of capacity to the distribution facilities via the Phase
V looping proj ect.
e. 2010-2011 these deficits are entirely filled by utilizing the Phase
XI looping project that adds another 90 000 therms of capacity.
Sun Valley Lateral -
f. 2009 - the 370-therm deficit is filled via mobile LNG.
g. 2010-2011 - the deficits for these years are entirely filled via a
looping project that increases capacity by 40 000 therms.
Response by Company to First Set of Production Requests at 5.
Additionally, the Company states that further study has resulted in delaying the need for
the above-mentioned resources as follows:
Notwithstanding the above, subsequent to completing and filing the
2007 -11 IRP with the Commission, the Company has further refined
its plans to eliminate the projected distribution deficits in a more
cost efficient manner. Interestingly enough, some of the early
research conducted for this IRP led to discovering some technology
enhancements that will allow the Company to forestall some very
expensive pipeline upgrades in two areas of the system. These
refinements are explained below:
Canyon County -
a. 2007-08 - further study of historical pressures from Northwest
Pipeline and the ability to use the Company s system linepack for
temporary" storage indicate that in the near-term, the peak day
deficits will lag prior estimates and the deficits will occur a later
year and at a lesser magnitude. Consequently, the looping project
that was to occur in 2007 can now be delayed until 2008.
STAFF COMMENTS AUGUST 29, 2006
b. 2008-11 - the looping project now planned for 2008 will
continue to eliminate all remaining deficits proj ected thru 2011.
Idaho Falls Lateral -
c. 2007-08 - updated analysis forecast that, due to higher Northwest
Pipeline pressure and temporary use of lateral "line pack", any
deficits would occur later and would be smaller than earlier
projected. Additionally, the Company has continued to research the
mobile LNG technology and found that it can be employed on a
larger scale over a longer period of time than was assumed in the
IRP. Consequently, the looping projects previously projected for
2007 and 2009 may now be delayed until after 2011 saving the
Company approximately $7.5 million.
Sun Valley Lateral -
a. Through the use of mobile LNG, the pipeline looping that was
previously projected to occur in 2007 is now likely to be postponed
until after 2011 saving the Company over $2.5 million.
Response of Company to First Set of Production Requests at 5-
After reviewing this response, Staff recommends that the Company publish an
addendum to the Resource Optimization section of the IRP. The addendum should identify the
individual deficits, each resource addition or change originally planned to satisfy those deficits
the changed situation and the resulting postponement of or newly planned resource that will be
implemented to eliminate the deficit situations. Staff recommends that the Commission require
the Company to specifically describe and evaluate the additional resources that will be acquired
developed or constructed to eliminate demand deficits in commodity and transportation in all
future IRPs.
Two-Year Plan
Order No. 25342 mandated that each IRP include a two-year plan "outlining the specific
actions to be taken by the utility in implementing" the IRP. Order No. 25342. Order No. 27024
granted the Company s request to submit a five-year IRP rather than a twenty-year IRP. Order
No. 27024. In light of the Staffs experience in evaluating the Company s IRPs submitted since
the issuance of Order No. 27024, the Staff respectfully recommends that if the Commission
desires for the Company to continue submitting IRPs with a five-year forecast window, the
Commission may wish to consider striking the requirement for the Company to submit a two-
year plan within the IRP. The information presented in the five-year plan should provide
information that would adequately fulfill the two-year plan s purpose, and the inclusion of the
STAFF COMMENTS AUGUST 29, 2006
two-year plan within the Company s five-year IRP usually results in duplicative information that
does not further illuminate the overall plan.
Relationship Between the Plans (2006 IRP vs. 2004 IRP)
Staff believes that the IRP satisfies this requirement. In the comparative analysis section
of the IRP, the Company addresses the differences between the 2004 IRP and the present IRP.
Each major section of the IRP is addressed and the significant differences between the two plans
discussed.
Public Participation
The Company met the requirement for public participation in the IRP process. Public
involvement in the IRP process consisted of a Yz-day session wherein the Company met with
customers, concerned consumer groups and Commission Staff to discuss the inputs to the IRP.
Questions and comments were solicited from all present.
STAFF RECOMMENDATION
After a complete evaluation of the Company s IRP, its methodology and conclusions, the
Staff recommends that the Commission direct the Company as follows:
1) That in future IRPs, models that were tested but subsequently rejected in favor of
the documented models be reported (along with a summary of why the
alternatives were rejected), including customer usage over seasonal and annual
time periods, a range of natural gas price forecasts from multiple sources, and
price elasticity of demand.
2) That in future IRPs, the Company address the "full spectrum of DSM
opportunities available to the Company, including conservation and efficiency
measures" that were part of the IRP process prior to Order No. 27098 and that the
IRP process be modified to require that a cost/benefit evaluation of all feasible
DSM measures be performed and that the Commission consider actions aimed at
creating a mechanism that will result in all cost-effective DSM measures being
implemented.
3) To specifically describe and evaluate the additional resources that will be
acquired, developed or constructed to eliminate demand deficits in commodity
supply and transportation in all future IRPs.
STAFF COMMENTS AUGUST 29, 2006
4) That the Company publish an addendum to the Resource Optimization section of
the IRP addressing the changed lateral transportation capacity deficit positions
stated in the Company s response to production request.
Respectfully submitted this day of August 2006.
Cecelia assner
Deputy Attorney General
Technical Staff: Harry Hall
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STAFF COMMENTS AUGUST 29, 2006
CERTIFICATE OF SERVICE
HEREBY CERTIFY THAT I HAVE THIS 29TH DAY OF AUGUST 2006
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-06-, BY MAILING A COpy THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
MICHAEL P. McGRATH, DIRECTOR
GAS SUPPLY & REG. AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE, ID 83707
MORGAN W. RICHARDS, JR.
ATTORNEY AT LAW
804 E PENNSYLVANIA LANE
BOISE, ID 83706
SEC T AR
CERTIFICATE OF SERVICE