BCPSO et al. IR No. 1 2012 Resource Plan for PNG(NE) Pipeline Systems Pacific Northern Gas (N.E.) Ltd. Page 1 December 5, 2012 REQUESTOR NAME: BCPSO et al. INFORMATION REQUEST ROUND NO: #1 TO: Pacific Northern Gas (N.E.) Ltd. (PNG) DATE: November 2, 2012 PROJECT NO: 3698690 APPLICATION NAME: 2012 Resource Plan Pipeline Systems for the Fort St. John/Dawson Creek and Tumbler Ridge Distribution Systems 1.0 Reference: Exhibit B-1, page 6, Resource Plan Objectives – Provision of Reliable, Secure, and Safe Service 1.1 Is it PNG’s view that DSM programs or peaking arrangements would increase the utility risk profile over time? Please explain. Response: The Fort St. John/Dawson Creek system is not in a supply constraint situation as this service area is located in a region of multiple sources of supply and plentiful reserves. This is a very different situation from that of other utilities in the British Columbia which are constrained by the capacity of pipelines running from the source of supply to the area of demand. The location of Tumbler Ridge is such that it is supply constrained, with only a single source of supply serving the region. In addition, this service area has a very small customer base (~1,400 customers), including 3 large commercial customers, therefore the impact on demand of implementing DSM programs is expected to be negligible. However, PNG(N.E.) notes that there may be an adverse impact if the DSM programs are not cost-effective. Further, PNG(N.E.) is presently unable to provide commercial customers with firm supply for annual demand in excess of 20,000 GJ per year due to the terms of the service agreement with its supplier, therefore it is unlikely peaking arrangements would be effective. Based on the foregoing, PNG(N.E.) is of the view that neither DSM programs nor peaking arrangements would be expected to have a material impact on the utility risk profile. B-5
Transcript
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 1
December 5, 2012
REQUESTOR NAME: BCPSO et al.
INFORMATION REQUEST ROUND NO: #1
TO: TO: Pacific Northern Gas (N.E.) Ltd. (PNG)
DATE: November 2, 2012
PROJECT NO: 3698690
APPLICATION NAME: 2012 Resource Plan Pipeline Systems for the Fort St. John/Dawson Creek and Tumbler Ridge Distribution Systems
1.0 Reference: Exhibit B-1, page 6, Resource Plan Objectives – Provision of Reliable, Secure, and Safe Service
1.1 Is it PNG’s view that DSM programs or peaking arrangements would increase the
utility risk profile over time? Please explain.
Response:
The Fort St. John/Dawson Creek system is not in a supply constraint situation as this service area is
located in a region of multiple sources of supply and plentiful reserves. This is a very different situation
from that of other utilities in the British Columbia which are constrained by the capacity of pipelines
running from the source of supply to the area of demand.
The location of Tumbler Ridge is such that it is supply constrained, with only a single source of supply
serving the region. In addition, this service area has a very small customer base (~1,400 customers),
including 3 large commercial customers, therefore the impact on demand of implementing DSM
programs is expected to be negligible. However, PNG(N.E.) notes that there may be an adverse impact if
the DSM programs are not cost-effective.
Further, PNG(N.E.) is presently unable to provide commercial customers with firm supply for annual
demand in excess of 20,000 GJ per year due to the terms of the service agreement with its supplier,
therefore it is unlikely peaking arrangements would be effective.
Based on the foregoing, PNG(N.E.) is of the view that neither DSM programs nor peaking arrangements
would be expected to have a material impact on the utility risk profile.
B-5
markhuds
PNGNE 2012 RESOURCE PLAN PIPELINE SYSTEMS
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 2
December 5, 2012
1.2 In considering capacity additions in the near and medium terms, does PNG compare the capital expenditure involved with the cost of a peaking arrangement that would obviate the need for a capacity addition in the short or medium term?
Response:
PNG(N.E.) capacity additions anticipated in the near or medium term are generally for improvements to
distribution systems that are serving mostly residential and commercial customers. Capacity additions
generally arise due to the addition or expansion of industrial sales or transportation customers. Under
PNG(N.E.)’s main extension policy, industrial or transportation customers responsible for incremental
demand must fund capacity additions to meet this demand. Peaking arrangements may be considered at
the time of negotiating new service arrangements, if appropriate, however they are unlikely to obviate the
need for capital additions related to a specific customer.
1.3 Do any of the current transportation arrangements with any of the large industrial transporters involve interruptible service? If so, please provide the interruptible capacities involved.
Response:
None of the current transportation arrangements involve interruptible service.
1.4 Has PNG ever undertaken a peaking arrangement with any of its transportation customers? If so, please provide details including the time period, cost, capacity involved, and the reason for entering into the arrangement for each case.
Response:
No.
1.5 Does PNG expect that a peaking arrangement might be a reasonable short or
medium term option in the future? If so, has PNG investigated what the cost would be to secure a peaking arrangement for the short or medium term in order to estimate the cost of an alternative to any planned short or medium term capacity additions?
Response:
No.
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 3
December 5, 2012
2.0 Reference: Exhibit B-1, page 7, Resource Plan Objectives – Stability of Rates 2.1 Does PNG expect to make any large capital expenditures to increase system
capacity that are expected to materially increase rates in the (i) short, (ii) medium, or (iii) long term?
Response:
As noted in section 4.1.2 of the 2012 Resource Plan, PNG(N.E.) is undertaking capital expenditures to
continue safe, reliable service to customers and increase capacity to meet forecast demand in the Dawson
Creek service area under all scenarios, including connecting Pouce Coupe to the Tomslake system and
replacement of the Pouce Coupe lateral. These expenditures are not expected to have a material impact
on rates in the short, medium or long term.
3.0 Reference: Exhibit B-1, pages 5-8, Resource Plan Objectives
3.1 Does PNG consider “better utilization of existing pipelines” a resource plan objective?
Response:
Pipeline efficiency has been identified as a planning objective in the PNG(N.E.) resource planning,
however, given the location of the PNG(N.E.) system, pipeline costs do not generally comprise a very
large component of the rates for customers. This applies to both pipelines owned by PNG(N.E.) and
capacity contracted by PNG(N.E.) on other pipeline systems. As a result, efficiency gains in the
utilization of existing pipelines do not translate into significant savings for customers and therefore
PNG(N.E.) does not believe there are cost effective programs and services that could be implemented to
increase pipeline utilization.
3.2 Has PNG ever looped a pipeline in order to increase capacity?
Response:
Yes. The pipelines serving Taylor and Fort St. John were looped to increase capacity. This was
undertaken at a time before PNG acquired the PNG(N.E.) assets.
4.1 Please explain why the Fort St. John residential customer additions are forecasted to decline significantly in the years 2016-2019 inclusive.
Response:
Please see the response to BCUC IR No. 1 Question 10.1.
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 4
December 5, 2012
5.0 Reference: Exhibit B-1, pages 15 and 17, Tables 2 and 3, Residential and Small Commercial Customer Forecasts
5.1 The referenced tables show “Year End Customers.” Does PNG use year-end
customers to forecast demand for the years in question ? If so please explain why year-end customers is useful for this purpose; if not, please provide tables showing the “average” or “effective” customer numbers, for each of the years shown in these tables, that underpin the forecasted demands.
Response:
PNG(N.E.) uses the number of customers forecast at year end to forecast demand. The number of
customers in all of PNG(N.E)’s systems is forecast to increase each year. The number of customers is
therefore greatest at the end of the year when the colder temperatures drive the peak demand on the
system. A peak demand calculated based on year-end customer counts is therefore more representative of
the peak demand that can be expected to occur in that year.
6.0 Reference: Exhibit B-1, pages 14 -17, Figures 6-11, Residential and Small
Commercial Customer Additions
6.1 Please confirm that the referenced figures show net annual additions for each year; if unable to so confirm, please explain fully.
Response:
Confirmed.
6.2 Please provide the information shown in each of the referenced figures numerically, in tabular form.
Response:
Please see the table that follows. In preparing this data, PNG(N.E.) became aware that Figure 11
(Tumbler Ridge Small Commercial customer additions) did not correctly present the data used in the
Resource Plan forecasting models. The version of Figure 11 on page 17 of the Resource Plan incorrectly
presented small commercial customer additions totalled over both Dawson Creek and Tumbler Ridge.
PNG(N.E.) has include a revised Figure 11 in its response to this question. The error is one of
presentation only and does not affect the remainder of the data and calculations presented in the Resource
Plan.
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 5
December 5, 2012
Table BCPSO 6.2 - Net Customer Additions
Fort St John Dawson Creek Tumbler Ridge
Residential
Small
Commercial Residential
Small
Commercial Residential
Small
Commercial
2012 176 35 92 23 9 3
2013 196 39 101 26 10 3
2014 203 40 103 27 10 3
2015 208 41 104 28 10 3
2016 103 21 61 12 6 2
2017 138 20 67 12 6 1
2018 134 19 51 11 5 1
2019 136 22 59 14 5 2
2020 181 26 56 15 5 2
2021 181 27 52 15 5 2
2022 185 27 58 14 5 2
2023 199 27 62 13 6 2
2024 183 26 54 12 5 2
2025 201 27 53 12 5 1
2026 192 26 48 11 4 1
2027 216 27 55 11 5 1
2028 210 26 46 12 4 1
2029 209 26 46 11 4 1
2030 205 26 46 12 4 1
2031 203 26 47 11 4 1
2032 204 26 46 11 4 1
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 6
December 5, 2012
Figure 11 (Revised) – Tumbler Ridge Small Commercial Customer Additions
7.1 Please explain how PNG calculated the average residential customer additions of 1.6%, 1.0%, and 0.5% for Fort St. John, Dawson Creek, and Tumbler Ridge, respectively.
Response:
Please see the response to BCUC IR No. 1 Question 10.1.
7.2 For any residential customer additions forecasts that were developed using regression or other statistical techniques, please provide (i) the equations estimated, (ii) the input data used, (iii) the sources of all input data used, and (iv) the summary statistical outputs of the regression or statistical exercises used to prepare the forecasts.
Response:
Customer additions forecast were not developed using regression.
-10
-5
0
5
10
15
20
Tumbler Ridge (Revised) Small Commercial Customer Additions
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 7
December 5, 2012
7.3 For any residential customer additions forecasts that were not developed using regression or other statistical techniques, please describe fully the forecasting methodology used and provide the input data underpinning the forecast.
Response:
Please see the response to BCUC IR No. 1 Question 10.1.
8.1 Please provide the information shown in Figures 12-17 numerically, in tabular form.
Response:
Please see the response to BCUC IR No. 1 Question 13.1.
8.2 Please explain why the Residential UPA in Tumbler Ridge, as shown in Figure
14, monotonically increases from 2012-2017 inclusive and decreases thereafter.
Response:
Please see the response to BCUC IR No. 1 Question 13.2 and 13.3.
For any UPA forecasts that were developed using regression or other statistical technique, please provide (i) the equations estimated, (ii) the input data used, (iii) the sources of all input data used, and (iv) the summary statistical outputs of the regression or statistical exercises used to prepare the forecasts.
Response:
The UPA forecasts were not developed using regression.
8.3 For any UPA forecasts that were not developed using regression or other
statistical technique, please describe fully the forecasting methodology used and provide the input data underpinning the forecast.
Response:
Please see the response to BCUC IR No. 1 Question 13.2 and 13.3.
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 9
December 5, 2012
8.4 Please provide the data underpinning the 10-year normalization described on page 20.
Response:
Please see the following tables.
Table BCPSO 8.4a – Fort St. John – Degree Day Summary
PNG NE - FORT ST JOHN - DEGREE DAY & NORM
JAN FEB MAR APR MAY JUNE JULY AUG SEPT OCT NOV DEC TOTAL
8.5 Did PNG assume that the average normalized temperature for the period 2002-2011 would be maintained throughout the forecast period? If so, please explain why; if not, please provide the assumptions and calculations that underpin the weather forecasted over the forecasted period.
Response:
Yes. While climate change may have an effect on the annual number of heating degree days experienced
in PNG(N.E.)’s service areas over the 20 year period of the Resource Plan, PNG(N.E.) is unable to
forecast with a reasonable level of confidence what that effect may be. Commonly accepted predictions
are for a warming of the average global temperature by two degrees Celsius by 2050. Assuming that this
warming trend is linear over time, a one degree increase in the average annual temperature in Fort St.
John by 2032 would result in a decrease in the number of heating degree days by approximately 365. The
resulting impact in 2032 on the annual residential UPA is estimated to be a reduction by approximately
five percent. The UPA in 2032 adjusted in this manner lies within the range of UPA’s forecast in the
Low and Reference Scenarios.
8.6 Please provide the historical data and PNG’s analysis of the historical UPA
trends referred to on page 20.
Response:
The data has been provided in response to BCUC IR No. 1 Question 13.1. PNG(N.E.)’s analysis has been
described in response to BCUC IR No. 1 Question 13.2 and 13.3.
8.7 Please provide support for PNG’s assumptions – as described on page 20 –
regarding the rates of decline in residential and small commercial UPAs for the forecast period (i) from 2012-2020 and (ii) from 2021-2030.
Response:
Please see the response to BCUC IR No. 1 Question 13.2 and 13.3, as well as to BCUC IR No. 1
9.1 Please provide the temperature that PNG assumes would prevail on a design day.
Response:
Please see the table, below.
Table BCPSO 9.1 – Design Day Temperatures
Design Day Temperature
Celsius Heating Degree
Fort St. John -41.8 59.8
Dawson Creek -45.0 63.0
Tumbler Ridge -40.0 58.0
9.2 Please explain fully how PNG has determined “the coldest day that may
realistically be experienced (the “design day”)” and provide the data and calculations that underpin the design day.
Response:
The specific design day temperatures presented in the response to Question 9.1 have been used by
PNG(N.E.)’s system planners when determining the available capacity on each of the delivery systems.
The temperatures are the coldest that can be expected once every 25 years. PNG(N.E.) has not retained
any calculations supporting these numbers.
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 13
December 5, 2012
9.3 For the daily demand calculations for the residential markets that use regression analysis, please provide (i) the equations estimated, (ii) the input data used, (iii) the sources of all input data used, and (iv) the summary statistical outputs of the regression exercises.
Response:
Please see the response to BCUC IR No. 1 Question 23.1. For the demand day forecast presented in its
2008 Resource Plan, PNG(N.E.) calculated separate heat and baseload factors for its residential, small
commercial and large commercial customers. The heat and baseload factors were calculated for each year
over the period January 2001 to 2007 using a linear regression on monthly billed consumption and
heating degree days. R2 values were greater than 0.95 in most of the regressions of residential and small
commercial data. R2 values for regression of large commercial data were lower, ranging from 0.6 to 0.95.
The trend in heat and baseload factors was then projected out to 2008 and adjusted slightly so as to match
the annual UPA’s reported in PNG(N.E.)’s 2008 Revenue Requirements Application. All of the data and
analyses have been provided in electronic format in Excel-based working papers (Attachment BCPSO IR
No. 1 Question 9 (NE Weather Normalized Use per Account.xls)).
The 2008 heat and baseload factors were scaled in proportion to the reduction in annual UPA between
2008 and 2011 before being applied in the design day demand forecast presented in the 2012 Resource
Plan.
9.4 For the daily demand calculations for the small commercial markets that use
regression analysis, please provide (i) the equations estimated, (ii) the input data used, (iii) the sources of all input data used, and (iv) the summary statistical outputs of the regression exercises.
Response:
Please see the response to Question 9.3.
BCPSO et al. IR No. 1
2012 Resource Plan for
PNG(NE) Pipeline Systems
Pacific Northern Gas (N.E.) Ltd.
Page 14
December 5, 2012
10.0 Reference: Exhibit B-1, page 33, Tumbler Ridge Gas Supply 10.1 When does the current supply agreement with CNRL expire?
Response:
The current service agreement between PNG(N.E.) and CNRL had an initial term from January 1, 2007
through to January 1, 2010. The agreement has continued on an evergreen two contract year term
extension basis and may be terminated by either party giving the other at least one contract year’s written
notice of termination. Based on these terms, the agreement will continue to apply until at least January 1,
2014.
11.0 Reference: Exhibit B-1, pages 34-35, Demand Side Management (“DSM”) 11.1 Does PNG have any objections to considering “small” residential and small
commercial DSM initiatives such as encouraging or providing low-flow showerheads and pipe-wrap to customers?
Response:
PNG(N.E.) would consider DSM initiatives of this nature as part of the development of a corporate-wide
DSM strategy. Please see the response to BCUC IR No. 1 Question 5.1.
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