20180223final_order_no_33997.pdf

Office of the Secretary
Service Date
February 23,2018
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE INTEGRATED )CASE NO.INT-G-17-04
RESOURCE PLAN FILING OF )
INTERMOUNTAIN GAS COMPANY )
)ORDER NO.33997
On August 4,2017,Intermountain Gas Company (Company)filed its Integrated
Resource Plan (IRP)for the years 2017-2021.The Company files an IRP every two years to
describe the Company's plans to meet its customers'future natural gas needs.The IRP must
discuss the subjects required by Commission Order Nos.25342,27024 and 27098,and section
303(b)(3)of the Public Utility Regulatory Policies Act (PURPA),15 U.S.C.§3202.The
Commission reviews the IRP to ensure that it discusses these subjects and represents a diligent
effort by the Company to plan for the anticipated supply and demand for natural gas.
The Commission issued a Notice of Filing that provided notice of the IRP and set a
deadline for submitting Petitions to Intervene.Order No.33870.No Petitions to Intervene were
received.The Commission then issued a Notice of Modified Procedure setting deadlines for
comments and reply comments.Order No.33922.Commission Staff timely submitted the only
comments filed in the case.The Commission now issues this Order acknowledging the IRP.
BACKGROUND
A natural gas IRP describes a company's plans to meet its customers'future natural
gas needs.In Order No.25342,the Commission adopted IRP requirements for local gas
distribution companies in response to amended Section 303 of the Public Utility Regulatory
Policies Act of 1978 (PURPA).In Order No.27024,the Commission shortened the required
planning horizon from 20 years to at least 5 years.Order No.27098 removed any requirement
that IRPs formally evaluate potential demand-side management (DSM)programs,and instead
directed the companies to explain whether cost-effective DSM opportunities exist.In summary,
these three orders direct gas utilities to file an IRP every two years that includes:
1.A forecast of future gas demand for each customer class,which includes the
number,type,and efficiency of gas end-users as well as effects from
economic forces on gas consumption;
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2.An analysis of gas supply options for each customer class,which includes
a projection of spot market versus long-term purchases for both firm and
interruptible markets,an evaluation of the opportunities for using company-
owned or contracted storage or production,an analysis of prospects for
company participation in a gas futures market,and an assessment of
opportunities for access to multiplepipeline suppliers or direct purchases
from producers;
3.A comparative analysis of gas purchasing options,and an explanation of
whether there are cost-effective DSM opportunities;
4.The integration of the demand forecast and resource evaluations into a long
range (at least a five-year)plan describing the strategies designed to meet
current and future needs at the lowest cost to the utility and its ratepayers;
5.A short-term (e.g.,two-year)plan outlining the specific actions to be taken
by the utility in implementing the IRP;
6.A progress report that relates the new plan to the previously filed plan;and
7.Public participation.
Additionally,in its order on the Company's 2013 IRP,the Commission allowed the
Company to stop filing semi-annual lost and unaccounted for gas (LAUF Gas)reports.'Instead,
the Company was to discuss LAUF Gas in the Company's future Purchased Gas Cost Adjustment
(PGA)caseS2 and IRPs.The IRP's LAUF Gas section must explain the Company's (a)framework
for how it has tested for,identified,and remediated equipment measurement errors or leaks,and
(b)business process for alleviating measurement errors through its financial accounting of
nominations,scheduling,measurements,flow volume allocation,and billing.See Order No.
32855.Finally,in its order on the Company's 2015 IRP,the Commission directed the Company
to include more detail in its future IRPs about how the Company calculates avoided costs and uses
those calculations to determine whether natural gas DSM opportunities are or are not cost-
effective.See Order No.33314.
'LAUF Gas is the difference between the amount of natural gas delivered to the Company's distribution system at
the city gate and amount of natural gas ultimately recorded at the customers'meters.
2 The Company files a PGA each year to adjust rates to reflect changes in the Company's costs to buy natural gas fromsuppliers-including transportation,storage,and other related costs.
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INTERMOUNTAIN'S IRP FILING
The Company regularly forecasts the demand of its growing customer base and
determines how to best meet that demand.The Company's IRP represents a snapshot in time of
the Company's ongoing planning process;it describes the anticipated conditions over a five-year
planning horizon,the anticipated resource selections,and the process for making resource
decisions.See IRP at 2.The Company sells natural gas to two major markets:the
residential/commercial market and the industrial market.In 2016,the Company served an average
of 313,000 residential customers and 32,000 commercial customers,which is a 2.2%increase in
average residential and commercial customers from 2011.Residential and commercial customers
use natural gas primarily for space and water heating.Industrial customers use natural gas for
boiler and manufacturing applications.The agricultural economy and the price of alternative fuels
strongly influence industrial demand for natural gas.In 2016,industrial sales and transportation
accounted for 52%of the throughputon Intermountain's system.Id.at 2-3.
In this IRP,the Company forecasted changes to its peak-day loads due to customer
growth under base case,and high-and low-growtheconomic scenarios.The Company forecasted
a base case growth scenario in which its total residential,commercial,and industrial peak-day
loads increase each year for five years by an average of 2.68%.According to the Company,this
increase in peak-day loads corresponds to expected growth in the Company's markets for
residential and small commercial customers.The Company saw no peak-day deliverydeficits over
the next five years when it matches its forecasted peak-day deliveryagainst its existing resources.
Id.at 3-4.
The Company also analyzed different geographic areas so it can plan to meet any
projected deficits in those areas.In this IRP,the Company analyzed the Idaho Falls Lateral,the
Sun Valley Lateral,the Canyon County Region,the State Street Lateral,and the Central Ada Area.
Id.at 5-10.
The Idaho Falls Lateral is 104 miles long and serves cities between Pocatello and St.
Anthony in eastern Idaho.It served about 15%of the Company's customers and 14%of the
Company's projected peak-day delivery for January 2017.The Company stated that matching the
Idaho Falls Lateral's forecasted peak-day delivery against its existing peak-day capacity showed
that the Company can meet this area's peak-day demands for the five-year IRP period.The
Company also noted that the Company can use its portable liquefied natural gas (LNG)facility in
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Rexburg to reduce system peak loads and meet customer demand by supplementing firm capacity
on the lateral during peak-day events.The Company planned to use the Rexburg LNG facility's
additional capacity in 2021.Id at 5-6.
The Sun Valley Lateral served about 3%of the Company's total customers and 3%of
the Company's projected peak-day delivery for January 2017.The Company stated that matching
the Sun Valley Lateral's forecasted peak-day delivery against its existing peak-day distribution
capacity (199,500 therms)showed that the Company can meet this area's peak-day demands for
the five-year IRP period.Id at 6-7.
The Canyon County Lateral served about 14%of the Company's total customers and
19%of the Company's projected peak-day deliveryfor January 2017.The Company stated that
matching the Canyon County Lateral's forecasted peak-day delivery against its existing peak-day
distribution capacity (860,000 therms in 2019 and 930,000 therms in 2020)showed that the
Company can meet this area's peak-day demands during the five-year IRP period.The IRP noted
this region's diverse industrial customer base currentlyhas limited ability to mitigate peak-day
deliveryby switching to alternative fuels.The Company is thus exploring other ways to enhance
this area's distribution capability,mainly regarding potential biogas production.Id.at 7-8.
The State Street Lateral in northwest Boise is 16.2 miles long.It primarily serves
residential and commercial customers that comprised about 14%of the Company's total customers
and 15%of the Company's projected peak-day delivery for January 2017.The Company stated
that matching the State Street Lateral's forecasted peak-daydelivery against its existing peak-day
distribution capacity (670,000 therms in 2019 and 765,000 therms in 2020)showed that the
Company can meet this area's peak-day demands for the five-year IRP period.Id.at 9.
The Central Ada Area in the Boise area consists of multiplehigh-pressure pipeline
systems.It serves a diverse base of residential and commercial customers that comprised about
15%of the Company's total customers and 12%of the Company's projected peak-day delivery
for January 2017.The Company stated that matching the Central Ada Area's forecasted peak-day
delivery against its existing peak-day distribution capacity (710,000 therms)showed that the
Company can meet this area's peak-day demands during the five-year IRP period.Id.at 10.
In summary,the IRP analyzed residential,commercial,and industrial customer growth
and its impact on the Company's distribution system using design weather conditions under
various scenarios for Idaho's economy.The Company measured peak-day delivery under each
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customer growth scenario against the available natural gas delivery systems to project the
magnitude and timing of delivery deficits on a total Company and regional perspective.The
Company analyzed the resources needed to meet any projected deficits within a framework of
options to help determine the most cost-effective means to manage the deficits.The Company
explained that these options allow its core market and firm transportation customers to rely on
uninterrupted service now and for years to come.Id at 11.
STAFF COMMENTS
Commission Staff believed the Company's IRP is reasonable and should be
acknowledged,but also identifies areas for improvement in future IRPs.Staff Comments at 3.
Staff believed the Company's demand forecast methodology is generally reasonable,
and appreciated the Company's detailed explanation of its customer growth and peak weather
forecastingmethodologies.Id at 3,4.However,Staff recommended the Company further explain
its models for estimating usage-per-customer and the time series models it applies,and how it uses
its customer growth forecasts and weather models to determine a system growth rate.Id at 4.
Staff identified two areas of the Company's system,the Canyon County Lateral and
the State Street Lateral,where the Company indicated that no capacity deficit occurs during the
IRP period (when forecasted demand is matched against existing peak-day distribution capacity),
but where the Company also projected that an enhancement is needed within the IRP period.Id
at 5-7.In both cases,the Company's deficit analysis assumed distribution capacity increases in
2020,and Staff understood the increase is due to the enhancement project.Id at 6,7.Staff
believed this practice-includingfuture enhancements as existing delivery capability in the
analysis of demand and resources-"obscures the magnitude and timing of potential capacity
deficits and does not provide a transparent and robust method for comparing alternatives."Id at
6 (see also 7).Staff recommended that in future IRPs,"the Company identify potential deficits
by comparing expected demand to existing capability without planned enhancements."Id
(emphasis in original).Once deficits have been established,the Company should conduct a
transparent and robust analysis of supply-and demand-side alternativesto resolve the deficits.Id
Staff also recommended the Company provide information regarding analysis of alternatives and
an explanation of why a specific solution was selected.Id at 7.Staff believed the Company's
analysis of demand and available resources for the areas of its system was otherwise reasonable.
Id at 5.
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Staff believed most of the Company's analysis of its supply options was reasonable,
but identified concerns with its analysis of the Nampa LNG facility and DSM resources.Id at 7.
Specifically regarding the Nampa LNG facility,Staff asserted the Company did not provide
sufficient information for Staff to assess the operation and cost-effectiveness of the facility,
compared to other options.Id.at 8.Staff asserted such information is critical to developing a
least-cost,least-risk plan,and recommended the next IRP include such operational and cost
information.Id
Regarding DSM resources,Staff acknowledged and supported many of the
Company's efforts.Id at 8-9.Staff also identified certain concerns and recommendations.First,
Staff discussed a research and development project described in the 2017 IRP,and noted that it
appears to be the same project discussed in the 2015 IRP.Id at 9.Staff recommended the
Company use the results of the research project to "develop or enhance programs in its service
territory."Id
Second,Staff had concerns with how the Company approaches DSM in its IRP.The
IRP listed several DSM objectives,but omitted what Staff characterized as the "primary goal of
DSM":to acquire cost-effective resources.Id at 9.Staff also did not agree that the Company
should focus solely on "the most"cost-effective DSM measures.Id at 9-10.Rather,the Company
should pursue alll cost-effective DSM to ensure customers are provided all the available cost-
effective resources.Id at 10 (emphasis in original).Finally,Staff believed the IRP did not
adequatelymodel DSM as a resource.Id Staff explained the Company selected certain DSM
measures and included only the resulting therms savings.Id Staff believed the Company should
have modeled other DSM resources to determine which are cost-effective and therefore should be
pursued.Id Staff also indicated the IRP did not discuss how DSM could impact the Company's
need for future and planned capacity upgrades or how DSM acquisition will impact its load
forecast.Id The Company also did not discuss how DSM avoided costs will be updated because
of this IRP.Id
Staff recognized that the Company's DSM program is new and that it will take time
to implement and model a fully developedDSM portfolio.Id Staff recommended the Company
convene an energy efficiency advisory group to assist with the effort.Id Staff believed the next
IRP should include "a more robust analysis of DSM resources,including a modeling process by
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which DSM measures are selected based on cost-effectiveness,an explanation and update of
avoided costs,and an explanation of the impact of DSM on supply and capacity needs."Id
Finally,Staff discussed whether and how the Company had addressed certain items
discussed by the Commission in its order on the Company's last IRP,Order No.33314.Id Staff
believed that the Company had addressed some items but,as noted above,did not sufficiently
explain enhancement projects,the calculation of DSM avoided costs,or how those costs are used
to determine the cost-effectiveness of DSM resources.Id.at 10-11.Staff also indicated that public
participation in the Company's development of its IRP remains a concern.Id at 11.Staff
acknowledgedthe Company increased the number of public IRP presentations (from three to four)
and encouraged public feedback and input.Id However,Staff emphasized "the Company should
provide an opportunityfor public involvement as the IRP is being developed-notsimply after-
the-fact."Id (emphasis in original).Staff encouraged the Company to convene an IRP advisory
group to improve public participation in developing future IRPs.Id.Finally,Staff acknowledged
the Company's improvement in its LAUF Gas rate of 0.31%,which the Company reports as being
one of the best in the industry.Id.
In sum,Staff's primary concern with the IRP was that it does not transparently or
robustly analyze the supply and demand-side options for meeting capacity deficits.Id.Staff also
believed the Company should provide more information about how it models its storage facilities
and DSM resources,and that it should increase public involvement in developing the IRP.Id.
Staff made the followingrecommendations for future IRPs:
1)Convene an IRP advisory group (made up of key stakeholders and open to the
public).
2)Work with the IRP advisory group to develop an IRP that (a)identifies the
magnitude and timing of potential deficits with existing resources,and (b)includes
a transparent analysis of supply-and demand-side resource options to determine
the most cost-effective solution to all identified deficits.
3)Include a more thorough explanation of per-customer consumption models and the
time series models appliedto them.Explain in more detail how the Company uses
its customer growth forecasts and weather models to determine a system growth
rate.
4)Describe how DSM avoided costs change because of the IRP.
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In summary,Staff believed the IRP analyzed residential,commercial,and industrial
customer growth and its impact on the Company's system under various scenarios.Peak-day
demand under each scenario was measured against the Company's available natural gas delivery
systems,includingplanned enhancements,to project deficits for each of several regions.The IRP
determined there are no peak-day delivery deficits for the 2017-2021 IRP period.Staff believed
the 2017 IRP is reasonable and recommended the Commission acknowledge it.
COMMISSION FINDINGS AND DECISION
Intermountain Gas Company is a natural gas corporation and public utility.See Idaho
Code §§61-116,-117,and -129.The Commission has jurisdiction over the Company and the
issues in this case under Title 61 of the Idaho Code,includingIdaho Code §61-501.
We have reviewed the record,including the Company's IRP and the Staff's comments.
Based on our review,we find that the Company's IRP substantially complies with the
Commission's prior orders.We thus acknowledge that the Company has filed its IRP.In doing
so,we reiterate that an IRP is a working document that incorporates many assumptions and
projections at a specific point in time.It is a plan,not a blueprint,and by issuing this Order we
merely acknowledge the Company 's ongoing planning process,not the conclusions or results
reached through that process.With this Order,we do not approve of the IRP or any resource
acquisitions referenced in it,or endorse any particular element in it,and we offer no opinion on
the prudency of the Company's election of its preferred resource portfolio.The appropriateplace
to determine the prudence of the IRP or the Company's decision to follow or not follow it,and the
validation of predicted performance under the IRP,will be a general rate case or other proceeding
in which the issue is noticed.See Order Nos.24981 and 25342.
The Commission also acknowledges the Staff's comments.In particular,we find it
reasonable that the Company should convene an IRP advisory group and work with the group to
develop future IRPs that comprehensively and transparently consider demand,existing resources,
and potential supply-and demand-side options for meeting any deficits.Such advisory groups
have proven informative and helpful to other utilities in developing their IRPs.We strongly
encourage the Company to also consider Staff's other comments and recommendations as it
develops its future IRPs.
ORDER NO.33997 8
O RD ER
IT IS HEREBY ORDERED that the filing of the Company's 2017-2021 IRP is
acknowledged.
THIS IS A FINAL ORDER.Any person interested in this Order 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.Within seven (7)days after any person has petitioned for
reconsideration,any other person may cross-petition for reconsideration.See Idaho Code §61-
626.
DONE by Order of the Idaho Public Utilities Commission at Boise,Idaho this
day of February 2018.
PAUI KJELLÀÑDER,PRESIDENT
KRI INE RAPER,CØMMISSIONER
ERIC ANDERSON,COMMISSIONER
ATTEST:
Diane M.Hanian
Commission Secretary
I:\Legal\LORDERS\INTGl704cc finalorderdoex
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