b-3 i,ar/; - bcuc.com … · vancouver, bc v6c 3k4 tel: (604) 691-5680 fax: (604) 697-6210 email:...

Verlon G. Otto Director, Regulatory Affairs

Pacific Northern Gas (N.E.) Ltd. 750 – 888 Dunsmuir Street Vancouver, BC V6C 3K4 Tel: (604) 691-5680 Fax: (604) 697-6210 Email: [email protected]

Via E-File May 21, 2020 B.C. Utilities Commission File No.: 4.2(2020) Suite 410, 900 Howe Street Vancouver, BC V6Z 2N3 Attention: Patrick Wruck Commission Secretary and Manager, Regulatory Services Dear Mr. Wruck: Re: Pacific Northern Gas (N.E.) Ltd.

Application for a Certificate of Public Convenience and Necessity to Implement Automated Meter Reading (AMR) Infrastructure Response to BCUC Information Request No. 1

Accompanying, please find the response of Pacific Northern Gas (N.E.) Ltd. to the referenced information request. Please direct any questions regarding the application to my attention.

Yours truly,

Verlon G. Otto Enclosure

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Yvonne.Lapierre

PNG NE CPCN AMR Infrastructure

PNG(NE) AMR CPCN Application Response to BCUC IR No. 1 May 21, 2020 Page 1 of 55

Pacific Northern Gas (N.E.) Ltd. Application for a Certificate of Public Convenience and Necessity to Implement Automated

Meter Reading Infrastructure

INFORMATION REQUEST NO. 1 TO PACIFIC NORTHERN GAS (N.E.) LTD.

Table of Contents Page no. A. Project Background..................................................................................................................... 2

B. Project Need ............................................................................................................................... 4

C. Project Alternatives .................................................................................................................... 8

D. Project Description ................................................................................................................... 27

E. Financial .................................................................................................................................... 43

F. Public Consultation ................................................................................................................... 51


A. PROJECT BACKGROUND

Reference: APPLICATION OVERVIEW Exhibit B-1, Section 1.2.1, p. 6; PNG Code of Conduct and Transfer Pricing Policy Application, Exhibit B-3, Attachment BCUC Panel IR No. 1 – PNG Proposed 2019 Code of Conduct – Amended Draft, Section 3.2.3 Financial Capability

On page 6 of the Application, Pacific Northern Gas (N.E.) Ltd. (PNG(NE)) states it “is capable of financing the implementation and operation of the AMR [Automated Meter Reading] Project either directly, or indirectly through its association with PNG [Pacific Northern Gas] and the ACI [AltaGas Canada Inc.] group of companies.”

Section 3.2.3 of the PNG Code of Conduct and Transfer Pricing Policy (COC/TPP), approved by the British Columbia Utilities Commission Order G-270-19, states:

PNG shall ensure that any loan, investment, or other financial support provided to an Affiliate is provided on terms no more favorable than what that Affiliate would be able to obtain as a stand-alone entity from the capital markets, and in all cases at no more favorable terms than PNG could obtain directly for itself in capital markets.

Any loan, investment, or other financial support provided to, or received from, an Affiliate must be approved by the BCUC.

1.1 Please provide the terms and conditions of the proposed related-party financing (e.g. interest rate, repayment terms, covenants, security) and discuss how the terms and conditions compare to the terms and conditions if PNG(NE) were to access capital markets on its own.

Response: The information presented on page 6 of the Application under Section 1.2.1, Financial Capability, is to establish that PNG(NE) has the financial capability to fund the proposed AMR Project, either on its own, or by virtue of the relationship with its parent company. PNG(NE) would finance this project in the normal course of business of funding its annual capital expenditures. PNG(NE) has adequate facilities available, and would draw on its Revolving Credit Facility approved under BCUC Order G-185-17 or on its Committed Operating Line approved under BCUC Order G-285-19 to finance the AMR Project.

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1.1.1 Please provide reference to where (e.g. Excel row number or cell reference) the terms and conditions are reflected in the Excel versions of Appendix B and C, respectively (Exhibit B-2).

Response: Not applicable. Due to the short-term implementation period for undertaking this capital project, PNG(NE) has not made provision for an allocation of financing costs in the financial analysis presented.

1.2 Please discuss the impact, if any, of the proposed related-party financing on PNG(NE)’s current approved debt-equity ratio.

Response: Not applicable. Please see the response to Question 1.1.

1.3 Given current capital market conditions and rates, please discuss whether PNG(NE) considered obtaining financing as a stand-alone entity from the capital markets. If yes, what were the pros and cons of this alternative and why was it rejected.



B. PROJECT NEED

Reference: PROJECT NEED AND JUSTIFICATION Exhibit B-1, Section 2.1.3, p. 10 Existing Manual Meter Reading Processes

On page 10 of the Application, PNG(NE) states that residential meters are read on a bi-monthly basis and commercial meters are read monthly. In addition, PNG(NE) states that meter reading is performed over a series of eight cycles, with each cycle taking approximately three days.

PNG(NE) further states:

PNG(NE)’s meter reading workforce is comprised of two area managers and five full-time equivalent (FTE) meter readers… In addition to the regular meter reading cycles, manual meter reads are also required each time a customer requests a move in / move out from a premise or makes a special request for an actual read. Meter re-reads may also be required to verify or correct previous reads when an error has been identified.

2.1 Please explain what a meter reading “cycle” is, including what work is currently performed during a “cycle.”

Response: A reading “cycle” is a time frame in which the meter is read for the billing period, and in the current state this is done every second month. Meters are currently read manually by a meter reader who takes a physical read of each meter by visually capturing the meter reads and entering it into a handheld device. This requires a meter reader to enter each customer premise.

2.2 Please explain how the meter reading cycle is expected to change following the

implementation of the AMR project. Please comment on whether meter reading will continue to be performed bi-monthly for residential customers, and whether the series of eight cycles of three days each will be maintained.

Response: In the future, meter reads would be captured by AMR radio signals which can gather meter data in the geographical area without attending each property, and eliminates the need for a physical manual read which requires putting eyes on each meter. This in turn would enable PNG(NE) to increase the frequency of the reading “cycle” to a monthly cycle from the current bi-monthly cycle. Reading meters remotely by AMR will reduce the cost of the meter read and provide improved accuracy of reads. A monthly reading cycle will also address a 40-day limitation on the history of consumption that can be retained by the ERT device on the meter.

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2.3 Please explain how many off-cycle manual meter reads (move in/move out, special

request and meter re-reads) PNG(NE) currently conducts annually.

Response: Currently PNG(NE) has approximately 1,700 off-cycle manual reads annually. These off-cycle reads primarily pertain to move in/move out, special requests and meter re-reads. Moving to a monthly read cycle will provide accurate daily consumption information and thereby is expected to eliminate the need for off-cycle reads for these items.

2.4 Please confirm whether the five FTE meter readers are also responsible for the

manual meter reads arising from customer requests and meter re-reads, as described in the preamble above.

Response: The majority of off-cycle reads are performed by meter readers. However, if a Customer Service Technician (CST) has been dispatched to an area for preventative maintenance work and there was a required off-cycle read then the CST may be given the responsibility for a nearby off-cycle read.

2.4.1 If confirmed, please discuss how many FTEs (or portions of an FTE) out of the

existing five FTE meter readers are required to conduct manual meter reads arising from customer requests and meter re-reads in the existing manual meter reading process.

Response: On a day to day basis at least one meter reader would be tasked with the off-cycle reads with any overload being assigned to CSTs.


2.5 Please explain whether off-cycle manual meter reads will be required after the

proposed AMR Project is implemented.

Response: Following implementation of AMR, off-cycle manual reads would only be required to verify stopped meters - all other requests for off-cycle read would be captured via the AMR monthly read cycle. As discussed in the response to Question 2.2, in order for PNG(NE) to capture daily read data to facilitate meeting the requirements of off-cycle reads, it is necessary to move to a monthly billing cycle. Since PNG(NE)’s AMR solution would be implemented in stages, for logistical purposes, each cycle would be sequenced and dropped into a monthly reading book. Eventually all bi-monthly cycles would be moved to monthly and captured data could be chained together for continuous daily volumes. If PNG(NE) continued bi-monthly reading, an average of 20 daily data reads would be lost leaving a gap in the data required to meet the needs of off-cycle reads.

2.5.1 If not, please explain why not.

Response: Please see the response to Question 2.5.

2.5.2 If yes, please explain how these meter reads will be performed, the costs

involved and where those costs are identified in the Application.

Response: Currently, approximately 95% of off-cycle reads pertain to move in/move out read requests, and most of the others relate to customer requests for rereads due to suspected read errors. As noted in response to Question 2.5, post-implementation of AMR off-cycle manual reads are expected only in instances to verify stopped meters. Consequently, PNG(NE) anticipates the volume and cost of manual reads on a go-forward basis to be very low and that these verification reads would be undertaken by CSTs as part of their routine duties. On this basis, PNG(NE) has not made provision for what is expected to be a nominal cost in its financial evaluation of the AMR Project.


Reference: PROJECT NEED AND JUSTIFICATION Exhibit B-1, Section 2.2.6, p. 12 Benefits of Automated Meter Reading – Revenue Protection

On page 12 of the Application, PNG(NE) states that, currently, gas theft is identified by a drastic decrease in customer consumption, a chance sighting of illegal activity, or meter reader identification of signs of meter tampering.

3.1 Please quantify the historical cost of identified gas theft in the most recent five-year time period.

Response: As noted in Section 2.2.6, Revenue Protection, of the Application, PNG(NE) does not have a formal gas detection program. PNG(NE) has invstigated suspicious information when it has been reported to PNG(NE) or visualized by PNG(NE) technicians. However, PNG(NE) is unable to quantify the impact of gas theft as an element of unaccounted for gas. PNG(NE) has noted the matter of gas theft in the context of the opportunity to analyze timely and accurate meter read data for anomalies that may be indicative of gas theft.

3.2 Please clarify whether savings from reduced gas theft are considered as a qualitative

or quantitative benefit of the proposed AMR Project.

Response: Opportunities to identify gas theft are considered a qualitative benefit of the proposed AMR Project. Please also see the response to Question 3.1.

3.2.1 If it is a quantitative benefit, please provide reference to where (e.g. Excel row number or cell reference) the expected savings are reflected in the Excel versions of Appendix B and C, respectively, (Exhibit B-2), and provide PNG(NE)’s assumptions and supporting calculations for the expected savings.

Response: Not applicable. Please see the responses to Question 3.1 and 3.2.

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C. PROJECT ALTERNATIVES

Reference: PROJECT ALTERNATIVES CONSIDERED Exhibit B-1, Section 2.3.1, pp. 12-13 Automated Meter Reading

On pages 12-13 of the Application, PNG(NE) states:

Various levels of AMR technology exists – from basic handheld units to fixed networks with data collection infrastructure tied to power poles and repeater units.

The AMR infrastructure considered by PNG(NE) involves equipping existing meters with ERT [Encoder Receiver Transmitter] modules that transmit meter read data via a RF [Radio Frequency] signal to a vehicle-mounted radio transceiver….

The implementation of mobile collection technology will allow for the remote reading of meter data communicated by RF from the ERTs simply by driving the service vehicle equipped with the mobile collection unit in the general vicinity of customer meters without having to follow existing meter reading routes and without having to access customer premises.

4.1 Please provide an assessment of the cost‐effectiveness for the proposed AMR system (vehicle-mounted collection unit) compared to a fixed network option.

Response: The cost-effectiveness of AMR compared to a fixed network option is clear. An in-depth analysis of both options was conducted which evaluated the potential benefits to PNG(NE) associated with AMI utilizing a fixed network system compared to the costs to achieve those benefits (e.g., new ultrasonic meter fleet, network infrastructure, meter data management software, etc.), and this evaluation illustrated that AMI based on a fixed network system did not make financial sense. PNG(NE) notes that based on the quotes received for the fixed network option the net present value of customer costs over a 20-year period was $32,656,477. This was due to the high initial capital costs of $23,101,603, primarily related to fixed network infrastructure, and ongoing operational costs which averaged over $1.4 million annually, primarily for the smart meter network infrastructure and meter data management system. By comparison, the financial analysis conducted on the mobile AMR alternative demonstrated a net present value of customer benefits of almost $2.1 million. Given the economics of AMR vastly outweigh those of AMI and PNG feels strongly that AMI is not a prudent choice for PNG(NE) customers. Further, given the compelling economics of AMR, PNG does not believe it is losing any optionality by selecting the AMR solution.

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4.2 Please explain whether AMR technology allows for a combination of mobile and

fixed network-type data collection and entry methods.

Response: Depending upon the technology vendor and the specifications of the ERT, some ERTs used in AMR implementations can be read via both mobile and fixed network receivers. PNG(NE) had given consideration to Itron’s 500G ERT which would enable the ability to move from a mobile to fixed network system at some point in the future. However, PNG(NE)’s proposal to proceed with AMR is as a cost-effective and efficient replacement to the current manual meter reading process. Installation of the 500G ERT would come at a higher capital cost of approximately $85,000 with no certain financial benefit. On this basis, PNG(NE) is proceeding with the Vendor A Itron 100G ERT, and though it does not have the noted capability, this capability was never a consideration in PNG(NE)’s business case..

4.2.1 If not, why not?


4.3 Please compare the quality and quantity of information available to either PNG(NE) or its customers from fixed network-type data collection and the proposed AMR system.

Response: AMR provides basic consumption reading at regular utility-scheduled intervals. Should a utility want a greater level of information in an AMR scenario they can read meters on a more frequent basis. Itron AMR gas ERTs do provide datalogging capability that give a utility the option to individually interrogate an ERT to download hourly interval data stored within the device that is not transmitted during the standard reading cycle. With AMI, meters are read on hourly intervals and those intervals are transmitted 4-6 times per day to the AMI head-end system. In addition, if so configured, events and alarms may be captured by AMI endpoints that provide additional information to the utility to potentially identify operational or customer service improvements. In short, one consumption read per billing cycle is provided by AMR vs twenty-four (24) hourly intervals daily with an AMI system.


4.4 Please explain further the meter data transmission capability of the proposed AMR

system, including the distance over which the data can be transmitted and whether the mobile collection vehicle is required to drive by each customer property.

Response: The distance over which data can be transmitted is dependent upon the radio frequency (RF) environment at each meter. Typically, given the outdoor location of natural gas meters, RF propagation is much better and typically means that there are instances where the utility vehicle does not need to pass by each customer property. The Vendor A Itron ERTs proposed for the AMR Project have been known to transmit over distances up to 5 km. However, in practice there are factors such as foliage and other obstructions that can impact the transmittal distance, so unless all of the meters on a particular street are picked up, the vehicle would still need to pass by the other previously read meters to pick up the one that did not read from another street.

4.5 Please explain whether the proposed AMR system can be upgraded to enhance mobile collection distance and efficiency in the future, if warranted.

Response: The output/transmit power of the AMR modules typically remains the same, however vendors occasionally make improvements to the sensitivity and functionality of their reading technology which can have the impact of increased collection distances and meter reading efficiency.

4.5.1 If yes, please explain what the cost would be.

Response: The cost of such improvements are unknown as the improvement could be as simple as a software update or it may require the purchase of a new piece of reading equipment to take advantage of the update.


4.6 Please discuss any system redundancies in the proposed AMR data collection system,

including whether the data collection unit is portable to a back-up PNG(NE) vehicle.

Response: System redundancy can be found in the ability to easily move the data collection unit between vehicles if required. Additional redundancy is found in the fact that PNG(NE) has planned to purchase two mobile data collection units as part of the AMR Project. In the event that the vehicle unit or one of the collection components were to go down, PNG(NE) would readily be able to continue with planned meter reading activities while vehicle repairs are undertaken or while a new collection component is shipped by the vendor. PNG(NE) further notes that handheld units with RF-read capability are a part of the proposed AMR solution that these could be used in the event of a mobile data collection unit breakdown.

4.6.1 Please identify where the costs associated with this system redundancy are included in the Application.

Response: These cost of the data collection units are captured in the proposed capital expenditures. As noted in response to Question 4.6, the proposed capital for the AMR Project includes two mobile collection units (MC3) and these are noted as the second item on the pricing summary provided as confidential Appendix E to the Application.


Reference: PROJECT ALTERNATIVES CONSIDERED Exhibit B-1, Section 2.3.3.1, p. 15; Section 2.3.4, p.17; Assessment of AMR Alternatives

On page 15 of the Application, PNG(NE) states:

The products of two industry leaders in the field of meter reading technologies were considered for PNG(NE)’s evaluation: Itron and Sensus Flexnet (Sensus). Both product lines offer AMR and AMI [Advanced Metering Infrastructure] solutions for the natural gas market, with the respective technologies of each having comparable functionality.

On page 17 of the Application, PNG(NE) summarizes its assessment of AMR alternatives:

“Based on the lower capital and incremental costs, greater anticipated financial benefits for customers, and prior established working relationships, PNG(NE) proposes proceeding with implementation of Itron AMR infrastructure.”

5.1 Notwithstanding the difference in cost and PNG(NE)’s previous experience with Itron products, please explain whether PNG(NE) considers the Itron and Sensus AMR technologies to be equivalent in terms of functionality. Please explain any differences identified.

Response: PNG(NE) considers the AMR technologies of the two vendors to be equivalent in terms of general functionality.

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Reference: PROJECT ALTERNATIVES CONSIDERED Exhibit B-1, Section 2.3.2, pp. 14-15 Advanced Metering Infrastructure (AMI)

On pages 14-15 of the Application, PNG(NE) states:

Gas and water utilities would have to either develop agreements with other utility companies with existing towers or build their own network infrastructure which may come at considerable cost.

Based on the foregoing, gas utilities have generally chosen to invest in AMR with a focus on the benefit of automating the meter reading process, rather than AMI. Where gas utilities have implemented AMI, they have generally done so where they are part of a corporate entity that provides both electric and natural gas service and where AMI infrastructure has been implemented concurrently for both areas of the business. PNG(NE) notes that at this time, no Canadian Gas Association member natural gas utility has implemented AMI.

6.1 Please describe any potential cost differences, relative to the proposed AMR project, if PNG(NE) were able to develop agreements with other companies with existing towers or existing network infrastructure.

Response: Towers or network infrastructure are required to mount collection devices with an AMI system and may be also be used for an AMR system. The availability of locations for mounting collection devices can be difficult for utilities that don’t have field infrastructure upon which to mount the devices (i.e. natural gas utilities vs electric utilities). Joint Use Agreements (JUA) would increase the cost of the project to PNG(NE), as would the requirement to purchase the collectors to be mounted as part of a fixed network.

6.2 Please discuss any barriers to AMI installation on existing towers or on existing network infrastructure.

Response: In order for PNG(NE) to take advantage of existing network infrastructure from another utility, they would have to be on the same vendor’s system, the locations would have to be suitable for PNG(NE), and PNG(NE) would be subject to terms and conditions and costs of JUAs to utilize that utility’s collection infrastructure or shared towers. In general, except in certain unique circumstances, the sharing of existing network collection infrastructure is not practical.

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6.3 Please discuss any efforts undertaken by PNG(NE) to develop agreements with other

companies with existing towers or existing network infrastructure.

Response: PNG(NE) has not made any effort in regard to pursing fixed-network infrastructure for its AMR Project due to the challenges outlined in response to Question 6.2. Further, PNG(NE)’s proposal to implement AMR technology in its service area has been presented as a cost-effective improvement to its current manual meter reading process that also provides a number of qualitative benefits as detailed in the Application. The incremental financial benefits of PNG(NE)’s proposal exceed the incremental costs and provide a tangible benefit to ratepayers. The mobile solution proposed by PNG(NE) is considered cost-effective, and incremental costs associated with joint use agreements and/or fixed network infrastructure make PNG(NE)’s proposition uneconomic.

6.3.1 If undertaken, please discuss the expected costs. Were these costs considered in the financial analysis presented on page 16 of the Application?


6.4 Please explain whether PNG(NE) is aware of any natural gas utility in Canada planning to implement AMI.

Response: Through PNG’s discussions with its vendors, consultants and other companies in the Canadian Gas Association, AMI does not appear to be actively planned by many gas utilities. PNG understands that some gas installations across North America have effectively “piggy-backed” on electric AMI installations, but it is extremely rare to have a “standalone” application for natural gas due to the appreciable cost difference. PNG understands that FortisBC is considering an AMI project for natural gas meter reading across their service territory. PNG is cognizant that PNG(NE) has some unique differences from FortisBC, and therefore may not have the same drivers and economics in justifing the underlying business case. For example, PNG(NE) operates in a less urban area and therefore it is more difficult to justify the implementation of a network, and PNG(NE) does not serve large metroplotion areas that could require sectionalization to avoid a large-scale outage from an upstream leak or emergency.


6.4.1 If so, please provide the name of the utility and where it plans to implement AMI.




An AMI endpoint may also have the ability to record a variety of other physical data (i.e. pressure, flowrate, temperature, corrosion data and methane detection) and the ability to virtually and remotely shut off the gas supply, offering the potential for further operational efficiencies for system safety and integrity. PNG(NE) notes that the configuration of its gas distribution networks/systems is such that there is reduced potential for benefits to be realized from virtual/remote shut-off capability. PNG(NE)’s systems are relatively small with taps from upstream gas suppliers and, as such, line pack is not significant. Further, PNG(NE)’s systems do not serve large urban centres where the supply/demand balance can be managed through load shedding in the event of an upstream upset.

A second key feature of AMI referred to previously is the ability to provide real time consumption data. Real time data has other benefits, including the ability to provide customers with greater details on their consumption and the potential to allow for flexible billing dates.

6.5 Please explain further the opportunity for operational efficiencies of system safety and integrity attributed to remote shut-off capability of an AMI system.

Response: Remote shut-off capability with respect to gas meters is primarily available in new solid-state, ultrasonic meters, though external to the meter shut-off solutions are available. Assuming a shut-off valve is available and paired with a seismic sensor in a solid-state meter, a seismic event of a certain size can trigger the valve and potentially avert any damage that could be caused by the event. Operationally this is an efficiency as it is able to be actuated as the event is occurring and does not require a truck to be rolled throughout the service territory to achieve this same result. Also, from an operational standpoint, remote shut-off capability assists in the utility’s ability to remotely cut service, for example, following standard notifications and communication, to a non-paying customer. Thus, AMI, in combination with ultrasonic meters, may provide an ability to more precisely curtail individual customers at the meter set, in the event of a leak or an emergency. While this is innovative technology, PNG(NE)’s current means of using an upstream valve, pipe squeeze or station adjustment continues to be effective for the scale of utilty of PNG(NE). For a large urban system, with a single pipeline feed, this feature may be more beneficial when compared to PNG(NE)’s dispersed and less-urbanized system with multiple upstream gas supply taps.


6.5.1 Please explain whether PNG(NE) quantified any cost benefits from these operational efficiencies related to AMI in the Application.

Response: PNG(NE) did not quantify cost benefits related to these operational efficiencies. PNG(NE) further notes that, unlike electricity meters, the operational benefit of the remote disconnection capability is one-sided as a physical presence is required on the reconnection side for appliance re-lights.


Response: As noted in response to Question 4.1, PNG(NE) conducted a financial analysis of the AMI alternative which led to a net present value of incremental customer costs in excess of $32 million. Given the sheer magnitude of additional costs that would be borne by ratepayers under the AMI alternative, PNG(NE) determined that the cost benefits associated with operational efficiencies would be minor relative to the total costs and did not further attempt to quantify such efficiencies.

6.5.3 If yes, please identify where in the Application the cost benefits can be found.

Response: Not applicable. Please see the response to Question 6.5.2.

6.6 Please discuss how customer access to personal real-time usage data is different between AMR and AMI technology.

Response: Real-time usage data is not available with either AMI or AMR. AMR data is available following the regular reading schedule. AMI data can be made available the day following or in some cases, with proper integration, every four to six hours. Further, access to this data in an AMI scenario requires some form of web presentment/customer engagement tool to manage the data presentment to customers.


6.6.1 Please discuss any information PNG(NE) has gathered regarding customer interest in real time consumption data.

Response: PNG(NE) has not engaged customers regarding interest in access to real time consumption data. PNG(NE) further notes that none of the customers in the PNG-West Thornhill AMR Pilot, nor any participants in the public consultations expressed interest in terms of this type of data access. PNG(NE) submits that as real or near real time data is not as valuable for gas customers as it may be for electric customers, PNG(NE) did not consider customer interest in real time data in its assessment.

6.6.2 Please explain whether customer interest in real time consumption data was considered in PNG(NE)’s assessment of project alternatives.

Response: Please see the response to Question 6.6.1.


Reference: PROJECT RISKS Exhibit B-1, Section 2.5, pp. 22-23 COVID-19

7.1 Please comment on how the evolving COVID-19 situation has impacted the likelihood of PNG(NE) experiencing any of its other risk scenarios. Please provide an update to Exhibit 2-9 on page 23 of the Application, if necessary.

Response: PNG has added a column to Exhibit 2-8 that identifies if any updates to the control/mitigation of the identified risks are required as a result of the COVID-19 pandemic. Exhibit 2-8 Overview of Risks and Mitigation Strategies

Key Risk Control / Mitigation Update related to COVID-19

1 Project Management

Upon BCUC approval, a Project Execution Plan will be finalized, outlining budget, schedule, and scope baselines, resource requirements, breakdown of deliverables, acceptance criteria and quality control requirements. PNG has experienced personnel and contractors, including recent experience with a pilot project in PNG-West.

The project execution plan will consider and incorporate measures and changes to planned activities as a result of adhering to COVID-19 safety measures.

2 Communication The Communication and Stakeholder Management Plan will be finalized as part of Project Execution Plan and will ensure regular collaborative communications are provided to all internal and external stakeholders throughout the duration of the project.

Communication activities will consider COVID-19 safety measures such as physical distancing and not having large gatherings of people.

3 Installation Schedule and Sequence

Field installation of ERTs will start in Spring 2020 when site conditions are favorable. ERT installation route sequencing will be included as part of project planning. Route sequencing will be reviewed and accepted by PNG(NE) prior to installation.

No expected change to this risk or related control/mitigation. However, PNG expects to commence field installations in the Summer of 2020, given the expected timing of BCUC approval.

4 Resource Requirements

PNG internal resources who have skills and experience in AMR technology will be utilized during project execution and will train new resources on the procedures in place.

No expected change to this risk or related control/mitigation.

5 Foreign Exchange $0.05 reduction in C$ vs US$ = $~7k reduction in project NPV.

15% contingency is included in financial analysis.


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Key Risk Control / Mitigation Update related to COVID-19

6 Failure Rate of Modules

Financial analysis modelled an average 0.5% annual failure rate although the Itron product claims failure rate is much lower. Average 0.5% annual increase in failure rate leads to ~$100k reduction to project NPV.


7 Resource Calendar

Financial analysis modelled labour headcount reductions to occur 3 months after project fully implemented. 6-month delay in headcount reduction leads to ~$200k reduction to project NPV. PNG(NE)’s project management approach will reduce this risk.


8 Resource and Material Requirements – Labour and Truck

Financial analysis assumes elimination of 5 FTE and 5 trucks. Existing non-meter reading FTE with existing truck will assume the responsibility of meter reading after AMR implementation. The need for one additional FT employee and truck = ~$1.3M reduction to customer savings NPV.


10 Data Transfer PNG resources are trained and experienced to validate that all ERTs data is properly transferred the BBS. Quality control procedures will be developed to ensure ERT serial numbers are entered into / properly synchronized with the BBS.


11 Material Cost Certainty / Delivery Timeline

The structure of the contract that PNG(NE) has negotiated favourably with Vendor A provides cost certainty on major project elements.

Agreement in place with Vendor A to hold agreed price quote until end of Q3 2020.


12 Meters for Recall Meters for recall will be replaced prior to installing ERTs. Project schedule will include the timing of meter replacement for meters due for recalls. A post-deployment plan will be developed to recall meters and attach the ERT post implementation.

Meter recall activities have experienced some delay as a result of COVID-19 due to the fact that PNG needs to enter a customer premise is required for relights. If the delay of meter recalls continues this item could be impacted.

13 Quality Control Develop a Project Control Manual with input from core project team that outlines the acceptance criteria of each deliverable.


14 Concurrent Projects

Incorporate in project planning the risk and impact of other concurrent projects on the resource, schedule, and scope of the AMR Project.



Reference: PROJECT NEED AND JUSTIFICATION Exhibit B-1, Section 2.3.3, p. 16 Capital Cost Estimate of Alternatives


…[It] obtained cost estimates for each of the AMR and AMI solutions offered by each of the vendors, with the Itron product estimate coming from Vendor A and the estimate for the Sensus product coming from Vendor B. Parameters specified in PNG(NE)’s request for vendor proposals for upgrading 22,887 services (active and inventoried meters) included the capital cost of metering, collection and support systems to allow for automated meter reading, the cost of installation, and the cost of project management [Emphasis added].

8.1 Please clarify whether the request for vendor proposals for AMR and AMI solutions was open to parties other than Vendor A and B.

Response: PNG(NE) requested proposals only from the two vendors noted.

8.1.1 If yes, please provide the total number of bids received for each solution (e.g. AMR, AMI) and the proponent selection criteria for the top AMI and AMR solutions described in the Application.


8.1.2 If no, please explain why not.

Response: Vendors A and B were selected as they are considered industry leaders in the field of meter reading automation and as they have the technology and experience to provide an appropriate solution to PNG(NE) and to support the implementation of this solution.

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Reference: IMPLEMENTATION OF AMI Exhibit B-1, Section 2.3.3, p. 16 Capital Cost Estimate of AMI Alternative


Initial cost estimates for AMI infrastructure provided to PNG(NE) were in the range of $7 million to $11 million with system functionality limited to the automation of the meter reading function. With the assistance of industry consultants, PNG(NE) subsequently conducted a more thorough analysis and determined that significant additional up-front and ongoing capital costs would be required in the area of system integration and for added human resources to operate and support a complete fully functioning AMI system. Provision for these additional elements has the effect of pushing the estimated initial capital costs for an AMI solution to exceed $20 million, well beyond a level that supports a cost-effective solution for PNG(NE).

9.1 Please explain further the difference in the scope of work and final system functionality included in the AMI infrastructure estimated to cost $7-11 million and the AMI infrastructure estimated to cost greater than $20 million.

Response: The cost difference between the AMI and AMR solutions is due to the capital and operating and maintenance costs associated with the field infrastructure, head-end and meter data management system, additional professional services and the personnel required to maintain and operate an AMI system. These costs are unique and typical in an AMI system and are required in order to capture, process and automate the meter reads.

9.2 Please provide a detailed breakdown of the cost estimate for AMI infrastructure implementation and the anticipated cost savings.

Response: Please see the attached Excel file: ”Attachment BCUC 9.2 – PNGNE AMR CPCN – AMI Evaluation” for information on the AMI infrastuture evaluation, including underlying costs. A working copy of this Excel model has concurrently been filed with PNG(NE)’s responses to BCUC Confidential IR No. 1 the BCUC’s reference.

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9.3 Can AMI infrastructure with system functionality, which is initially limited to the

automation of meter reading, be expanded to a fully functional AMI system in the future?

Response: Yes, assuming that a more expensive gas ERT module purchased initially has AMI functionality (i.e. Itron 500G ERT), an AMI system could be implemented in a staged approach. However, as noted in response to Question 4.1, the incremental customer costs for a fixed network AMI option had a net present value over a 20-year period of $32,656,477. This was due to the high initial capital costs of $23,101,603, primarily related to fixed network infrastructure, and ongoing operational costs which averaged over $1.4 million annually, primarily for the smart meter network infrastructure and meter data management system. In PNG(NE)’s view, even though the cost of an AMI-capable ERT is not significantly greater than the AMR-enabled ERT PNG(NE) has proposed in its AMR project, the significant incremental costs to move to a full AMI system, even in a staged manner, would not be an economic proposition for PNG(NE).

9.3.1 If yes, what is the incremental cost of adding this functionality later?



Response: Not Applicable. Please see the response to Question 9.3.

9.4 Please explain whether AMR infrastructure deployed through this Project could be upgraded to AMI technology in the future.

Response: As envisioned and recommended, no, the AMR infrastructure proposed for deployment in PNG(NE)’s AMR Project can not be upgraded to AMI technology in the future. Due to the negative economics for AMI, selecting Vendor A’s AMI gas module that could be read as an AMR module was not considered. Conversely, as established in PNG(NE)’s Application, the case for AMR was positive with a payback available and positive financial benefits to customers, which led PNG(NE) to the recommendation to implement AMR.


Reference: PROJECT NEED AND JUSTIFICATION Exhibit B-1, Section 2.3.4, p. 17 Assessment of AMR Alternatives

10.1 Please provide the Association of Cost Engineering Guidelines 17R-97 and 18R-97 (Cost Estimating Classification System – revision November 2011) (AACE Guidelines) estimate class and level of accuracy for the Vendor B capital cost estimate.

Response: PNG(NE) considers the capital cost estimates of both Vendor A and Vendor B to be at a Class 2 level of certainty, as they are vendor bids that are based on substantive definition of the AMR Project. Upon approval of the AMR Project, negotiation of final contractual terms will be completed and result in a Class 1, definitive cost estimate.

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Reference: PROJECT NEED AND JUSTIFICATION Exhibit B-1, Section 2.4, pp. 17-21 Project Justification and Benefits

11.1 Please discuss whether PNG(NE) intends to track the realization of financial and qualitative AMR Project benefits. Please explain why or why not.

Response: PNG(NE) submits that the two key components contributing to quantifiable financial benefits from the proposed AMR Project are a reduction in the number of meter reading staff and a reduction in the number of vehicles required for the meter reading function. Directly associated with these quantifiable benefits are the qualitative benefits of improved workforce safety associated with reduced staff and reduced GHG emissions associated with reduced vehicle usage. Further, the remaining identified qualitative benefits of the AMR Project (i.e. timely/accurate meter reads, increased customer satisfaction and revenue protection opportunities are inherent in the rollout of AMR technology. To this end, PNG(NE) had not planned a formal tracking and reporting on the realization of these benefits, as if these objectives were not met, they would be clearly evident from an operational standpoint and action would be undertaken to rectify any identified issues.

11.1.1 Would PNG(NE) be amenable to providing AMR Project benefits realization reporting to the BCUC? Please explain why or why not.

Response: As noted in response to Question 11.1, PNG(NE) had not planned a formal tracking and reporting on the realization of anticipated benefits to the Commission. However, should the BCUC request reporting on quantifiable metrics, PNG(NE) is amendable to this request. Based on the benefits put forth in the Application, PNG(NE) envisions that such a report might be filed annually and would focus on PNG(NE) resources dedicated to the meter reading function (i.e. staffing and vehicles) compared to the current state with manual meter reading processes.

11.1.1.1 If yes, please provide the proposed content and timing of such reporting.

Response: Please see the response to Question 11.1.1.

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Reference: PROJECT NEED AND JUSTIFICATION Exhibit B-1, Section 2.5, p. 22 Resource Calendar

On page 22 of the Application, PNG(NE) states that the financial analysis modelled labour headcount reductions to occur three months after the project is fully implemented.

12.1 Please explain why the financial analysis modelled labour headcount reductions to occur three months after the project is fully implemented. Does PNG(NE) expect to recover the cost of three months of labour headcount through rates after AMR is fully implemented? Please explain.

Response: In its Application, PNG(NE) has identified delayed implementation as a project risk, and that this risk has the potential to negatively impact the financial evaluation of the AMR Project due to incremental labour costs. Further, implementation of the AMR Project will not be instantaneous – it will be implemented in phases on a community-by-community basis. As a prudent and conservative measure in the financial evaluation, PNG(NE) has included labour costs for a transitional period that also provides accommodation for costs arising from potential delays in implementation.

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D. PROJECT DESCRIPTION

Reference: PROJECT DESCRIPTION Exhibit B-1, Section 2.5, p. 23, Appendix D, p. 3 Replacement of Meters


Meters for recall will be replaced prior to installing ERTs. Project schedule will include the timing of meter replacement for meters due for recalls. A post-deployment plan will be developed to recall meters and attach the ERT post implementation.

On page 3 of Appendix D, PNG(NE) states a key learning of the PNG-West 2018 AMR Pilot was that expired meters had to be recalled prior to marrying the meter with an ERT. This activity was not initially considered a risk in the AMR Pilot project schedule.

13.1 Please explain further the rationale and plan for replacing meters prior to installing ERTs.

Response: Meter recalls are mandated by Measurement Canada and require timely removal and replacement of meters for testing and certification. PNG(NE) plans to remove meters identified for replacement in 2020 early in the year, prior to implementation of the AMR Project. This will facilitate the vendor marrying ERTs to the meters as part of the project installation and implementation. PNG(NE) notes that the vendor has Measurement Canada certification to undertake this activity, whereas PNG(NE) presently does not. Once the AMR Project has been approved, PNG(NE) will undertake to have its employees accredited to perform this activity such that ERTs will be installed on stock meters prior to being installed in the field.

13.2 Please explain how PNG(NE) determines which meters and how many meters are required for replacement prior to installing ERTs.

Response: The meter recall process is a separate activity, completely independent of the AMR Project. As required and as defined by Measurement Canada, each year PNG(NE) must remove meters for testing and verification, with the number of meters subject to recall varying from year to year depending on the specific meter groups subject to sampling or recall. The meter groups are determined based on prior sample results for a particular meter group and meter seal expiry dates, therefore, the requirements for the current period are unknown until testing and variance results have been completed for the previous period.

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13.3 Please clarify how many of the existing gas meters to be fitted with ERTs would need

to be replaced prior to the project implementation. In your explanation, please provide the average age of PNG(NE) meters.

Response: The current meter recall plan for 2020 requires the recall of approximately 920 meters for PNG(NE) (FSJ/DC and TR). Approximately 510 of these will be retired due to their being at the end of their useful life.

13.3.1 Is this a similar proportion of gas meters requiring replacement compared to

the PNG-West 2018 AMR Pilot? If not, please explain why not.

Response: As noted in response to Question 13.2, the meter recall process is a separate activity, completely independent of the AMR Project. As further noted, the number of meter recalls varies by area and year based on group types and sizes selected by Measurement Canada. As such, there is no identifiable correlation to the PNG(NE) meter recalls for 2020 and those that may have occurred in 2018 for the community of Thornhill.

13.4 Please describe the resources, including equipment and staff, required to implement these meter replacements.

Response: The meter recall process is conducted using internal staff and further supplemented by the use of external contract resources as required. Tools required are standard Customer Service Technician tools as well as vehicles for transport of manpower, meters, and tools/materials. Please also see the response to Question 13.2.


13.5 Are the costs of the resources required to support these meter replacements and the

meter replacements included in the PNG(NE) AMR project estimate? Please explain.

Response: Please see the response to Question 13.2. The meter recall and replacement activities are an annual activity independent of the AMR Project. Meter recall costs are an element of PNG(NE)’s cost of service as an operating expense (BCUC Account 673). Consequently, these costs are not an element of the AMR Project financial evaluation. The sequencing of performing meter recalls and replacements prior to implementation of the AMR Project is for improved efficiency, as identified in the PNG-West 2018 AMR Pilot lessons learned.

13.6 If a meter, with an ERT attached, is to be replaced in the future, please explain

whether the ERT will be transferred to the replacement meter.

Response: A previously installed ERT on a meter that has been identified for recall and replacement will be transferred/reused on a new or a recertified and sealed meter to be redeployed. This activity will be performed at a Measurement Canada approved inspection and testing facility.


Reference: PROJECT DESCRIPTION Exhibit B-1, Section 3.3, p. 26, Sections 3.4.2, p. 28, Appendix D, p. 2 Field Installation of ERTs


Vendor A has provided PNG(NE) with a quotation for materials and services whereby it will undertake the installation and implementation of a fully functioning AMR system for all residential and small commercial customers in PNG(NE) service areas.

Page 28 of the Application shows that field installation of ERTs is scheduled for October and November of 2020.

On page 2 of Appendix D, PNG(NE) observed that in the PNG-West 2018 AMR Pilot “weather conditions had a significant impact on the project schedule when installing ERTs. Sales & Service was working during weekends during winter season, which caused delay in the installation and meter reading.” Further, PNG(NE) identified weather conditions as a risk in the project schedule and recommended installation during non-winter months as a risk mitigation strategy in the future.

14.1 Please explain if there is an increased risk to the project from installing ERTs in October and November 2020 and, if so, what mitigation measures PNG(NE) and Vendor A proposes to employ while performing the installation.

Response: PNG believes the AMR Project can still effectively be completed if there are delays into the fourth quarter of 2020. However, weather may play a role in the installation phase if the project encounters extreme weather condtions. Snow level and temperatures cannot be anticipated at this time. An assessment of conditions will be made at the time of installation and concerns will be addressed and resources tasked accordingly to support an effective implementation process.

14.2 Is the cost for any additional resources required to support installation in

unfavorable weather conditions included in the AMR project estimate? Please explain.

Response: PNG(NE) has not made any provision for this circumstance in its AMR Project cost estimates. However, PNG(NE) notes that the cost estimate includes a 15% contingency to accommodate uncertain or unknown items of this nature.

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14.2.1 If not, please provide an estimate of any additional cost.

Response: PNG(NE) is unable to estimate the impact of this factor given the significant uncertainty around what weather conditions may be at such a future date. If PNG(NE) receives approval fromt the BCUC on the anticipated timeline, this risk of unfavourable weather conditions is lower. However, PNG(NE) considers it equally likely that the weather will be favourable as unfavourable at that time. Please see the response to Question 14.2 which discusses the contingency provision included in the AMR Project cost estimate.


Reference: PROJECT DESCRIPTION Exhibit B-1, Section 3.6.2, pp. 29-30; Order G-127-11, Appendix A, p. 4; Application by PNG for Approval of its Consolidated Gas Sales Tariff proceeding, Exhibit B-7, BCUC IR 14.21 Radio-off Option for Customers

On page 29 of the Application, PNG(NE) states,

customers requesting radio-off will be levied a service charge to cover the cost of setting up their account as having opted out of AMR. Such a customer would also be levied a service charge should they subsequently request a move to AMR. PNG(NE) proposes that a fee of $60 would be levied…

PNG(NE) further states the proposed fee is consistent with the service Reconnection Fee under the Standard Fees and Charges Schedule of PNG’s Consolidated Gas Sales General Terms and Conditions (Appendix F).

On page 4 of Appendix A to BCUC Order G-127-11, the BCUC states:

With respect to the $60 reconnection fee, PNG notes there is a significant difference between connecting a customer and reconnecting a customer. When a customer disconnects and reconnects two service calls are required. In the case of a new account only one service call is required. Thus, PNG submits that charging $30 would not be comparatively reasonable. Further, PNG notes that the average cost incurred for reconnection is $60.20 which is in line with the current reconnection charge and therefore fair from a cost recovery point of view.

15.1 Please explain the proposed business process and the amount of time required for: a) setting up customer’s account as having opted out of AMR; and b) setting up a customer’s account if the customer subsequently requests to move to AMR.

Response: For scenario a) PNG(NE) envisions two instances in which a customer could opt out of AMR: 1) before the initial deployment of the AMR and installation of ERTs; and 2) after the deployment and an ERT is already installed at the customer premise. The following provides a brief overview of the process under each instance by which a customer would request to opt out, as well as the anticipated time required by PNG personnel and the associated cost.

1 Retrieved from: https://www.bcuc.com/Documents/Proceedings/2011/DOC_27094_B-7_PNG-Resp-BCUC-IR-No1.pdf

1S.O

https://www.bcuc.com/Documents/Proceedings/2011/DOC_27094_B-7_PNG-Resp-BCUC-IR-No1.pdf

https://www.bcuc.com/Documents/Proceedings/2011/DOC_27094_B-7_PNG-Resp-BCUC-IR-No1.pdf


Set Up Account as AMR Opt Out Prior to AMR Deployment:

1) Customer calls Customer Care to make request.

2) Customer Care Representative (CSR) creates a Service Order for the installer to bypass installation of ERT (5 min).

3) Service Order is given to the installer to bypass the installation of ERT during AMR Project field deployment.

4) Service Order is finished off and sent back to Customer Care center.

5) CSR enters finished Service Order and updates billing system (5 min). Total CSR time/cost: 10 min x $48.51/hr = $8.09 Total cost = $8.09

Set up AMR Opt Out After AMR Deployment:


2) Customer Care Representative (CSR) creates a Service Order for the installer to omit Transmitter (5 min).

3) Service Order is generated and assigned to a Customer Service Technician (CST).

4) The CST travels to/from customer premise to fulfill Service Order (travel time is a variable, assumed 20 min average).

5) CST removes the ERT or exchanges the meter set (35 min).

6) CST faxes completed Service Order to Customer Care (5 min).

7) Customer Care Closes the Service Order and updates billing system (5 min).

Total CSR time/cost: 10 min x $48.51/hr = $8.09 Total CST time/cost: 60 min x $55.24/hr = $55.24 Total cost = $63.33

For scenario b) PNG(NE) anticipates the following process to occur when a customer requests to move back to AMR, as well as the anticipated time required by PNG personnel and the associated cost. Reinstate Account to AMR:


2) Customer Care Representative (CSR) creates Service Order for installation of an ERT (5 min).


4) The CST travels to customer premise to fulfill Service Order (travel time is a variable, assumed 20 min average).

5) The CST installs and configures the ERT or exchanges the meter set (35 min).



7) Customer Care closes the Service Order and updates billing system (5 min).


15.2 Please confirm, or explain otherwise, that the proposed $60 fee will be charged once when the customer opts out of AMR and again when, or if, the customer subsequently requests to move to AMR (e.g. the total fee levied will be $60+$60=$120 for a customer choosing to switch out of and back to AMR).

Response: The primary cost driver to address a customer’s request to opt out of AMR or back on to AMR is the requirement for a CST to physically attend to the customer premise to manually remove/add the ERT or alternatively install a meter set without a ERT in the case of an opt out or install a meter set with an ERT in the case of an opt back in. PNG(NE) submits that if a customer opts out prior to the deployment of AMR there would be no service charge on opt out as there would be negligible cost incurred (i.e. $8.09 per the response to Question 15.1). However, if a customer requests to opt out after AMR is deployed, they will be charged the $60 fee in order for PNG(NE) to recover the associated cost of this action (i.e. $63.33 per the response to Question 15.1). Further, customers requesting to opt back on to AMR will be charged the $60 fee in order for PNG(NE) to recover the associated cost of this action (i.e. $63.33 per the response to Question 15.1).

15.2.1 Please explain whether it would be appropriate to levy a $30 fee when

setting up a customer’s account as having opted out of AMR and again when subsequently requesting to move to AMR (e.g. the total fee levied will be $30+$30=$60 for a customer choosing to switch back to AMR). Please explain why or why not.

Response: It is not clear to PNG(NE) what the basis for the $30 fee proposed in this question is. In PNG(NE)’s Application a fee of $60 was proposed for opting out of and opting back on to AMR, and a fee of $30 was proposed for each required manual meter read. Please also see the response to Question 15.2.


15.3 Please provide the current average cost incurred for reconnection and compare that

to the expected average cost for:

i. setting up a customer’s account to opt out of AMR; ii. setting up a customer’s account if the customer subsequently requests to switch

to AMR; and iii. both i) and ii)

If possible, please provide cost breakdowns by action required (e.g. customer contact, travel time to customer), including the hourly rate(s) and estimated amount of time that will be spent. Please state the assumptions (if any) for all amounts.

Response: The following provides a brief overview of the process undertaken for service reconnection at a customer premises, as well as the anticipated time required by PNG personnel and the associated cost. Reconnection of Service:


2) Customer Care Representative (CSR) creates a Service Order to reconnect service, (5 min).



5) CST reconnects service (25 min).


7) Customer Care closes the Service Order and updates the billing system (5 min).


As illutstrated in the reponse to Question 15.1, the cost to set up a customer requesting to opt out of AMR or to opt back in to AMR is $63.33. The primary difference between the cost associated with a reconnection and the cost of opting out or opting back on to AMR is the time on site (25 minutes for a reconnect and 35 minutes for AMR opt out or opt back on)


15.4 Please clarify whether the proposed $60 fee assumes that the configuration of the

radio-off meter within the AMR system will take place at the same time as the initial installation of the AMR meter at the customer’s property. Please discuss why or why not and explain who will perform the configuration (e.g. PNG(NE) employee or Vendor A employee).

Response: As described in the response to Question 15.1, a customer could opt out of AMR in two instances: 1) before the initial deployment of AMR and installation of ERTs; and 2) after the deployment and an ERT has already been installed at the customer premise. PNG notes that the ERTs to be installed as part of the AMR Project can not be programmed to be on or off but rather must be physically removed to facilitate a customer’s request to have a radio-off configuration. Also as described in response to Question 15.1, customers opting out of AMR prior to deployment would not be charged a fee as in this scenario all that is required is the issuance of a Service Order to effect the bypass of installation of an ERT at the customer premises and this would have a nominal cost. Under the scenario whereby the opt-out takes place after the AMR deployment, a Customer Service Technician must be dispatched to the property to remove the ERT or to swap the meter set with one that does not have an ERT. Consequently customers opting out after AMR has been implemented would be charged the $60 fee to recover the cost of this service request.



Customers selecting the radio-off option would also be charged a fee to cover the cost of manually reading their meter, currently on a bi-monthly basis. PNG(NE) proposes that a fee of $30 would be levied for the required manual meter read. This proposed fee is considered reasonable and is consistent with the Customer Requested Meter Reading Fee under the Standard Fees and Charges Schedule of PNG’s Consolidated Gas Sale General Terms and Conditions.

On page 10 of the Application, PNG(NE) states that residential meters are read on a bi-monthly basis and commercial meters are read monthly.

15.5 Please explain whether the proposed $30 fee for radio-off customers will be a one-time fee or if it will be charged bi-monthly for residential customers and monthly for commercial customers.

Response: The proposed $30 fee is a per meter read fee to be charged based on bi-monthly readings for residential customers and monthly readings for commercial customers.


In the Application by PNG for Approval of its Consolidated Gas Sales Tariff proceeding, PNG stated in response to BCUC IR 14.2:

The estimated cost of reading a meter at the customer’s request depends on the location of the customer. PNG receives very few requests from customers to perform a special meter reading. A rough estimate, which takes into account labour for the Customer Service Technician to perform the read, administration costs associated with creating and closing the Service Order, automotive costs, and overheads, is approximately $40…

15.6 Please provide an update to the response provided to BCUC IR 14.2 above. What is the current business process and associated cost of performing a manual meter read at the customer’s request? If possible, please provide a cost breakdown by action and state the assumptions (if any).

Response: The following provides a brief overview of the process undertaken for a manual meter read at the request of a customer, as well as the anticipated time required by PNG personnel and the associated cost. Manual Meter Read (Current State):

1) Customer Care Representative (CSR) creates a Service Order for manual meter read, (5 min).



4) CST reads meter and and records read on the Service Order (5 min).


6) Customer Care enters read and closes the Service Order (5 min).



15.6.1 Please compare and contrast the current business process to perform a manual meter read at the customer’s request and the proposed business process for a manual meter read after AMR implementation.

Response: PNG(NE)’s process for a manual meter read In the current state has been detailed in response to Question 15.6. In a post-AMR deployment state there are two manners in which a customer can get a consumption read for a specific date:

1. Electronically – whereby a Customer Care Representative (CSR) creates a Service Order for a read file for a specific date. This request is placed in the queue to be held for read file. The read file is filtered by account and date after the monthly reads are uploaded and the daily value is entered into the billing system and the Service Order is closed.

2. Manually – which would generally follow the same process as the pre-AMR deployment

manual read process (as per response to Question 15.6). PNG(NE) anticipates that the vast majority of the customer driven manual reads will be able to be completed electronically for AMR customers once the AMR infrastructure has been deployed.


15.6.2 If the proposed business process differs, please provide a breakdown of the estimated cost of the proposed process by action, including the hourly rate(s) and estimated amount of time that will be spent. Please state the assumptions (if any) and compare that to the proposed $30 fee.

Response: PNG(NE)’s process for a manual meter read In the current state has been detailed in response to Question 15.6 and is reproduced below: Manual Meter Read (Current State):

1) Customer Care Representative (CSR) creates a Service Order for manual meter read, (5 min).



4) CST reads meter and and records read on the Service Order (5 min).




The following provides a brief overview of the anticipated process to be undertaken for a manual meter read after AMR deployment, as well as the anticipated time required by PNG personnel and the associated cost. Manual Meter Read (Post AMR deployment – electronic; requires customer to have AMR)

1) Customer Care Representative (CSR) creates a Service Order for a read file for a specific date. Request is placed in the queue to be held for read file. (5 min)

2) CSR filters the read file by account and date after the monthly reads are uploaded and the daily value is entered into the billing system and the service order is closed. (10 min)

Total CSR time/cost: 15 min x $48.51/hr = $12.13 Total cost = $12.13


15.7 Please provide the maximum cost to perform a manual meter read for PNG(NE)’s

most remotely located customer, and the minimum cost to perform a manual meter read for PNG(NE)’s closest customer.

Response: Please see the analysis that follows. Closest Customer: Customer located next door to PNG(NE)’s regional offices.

1) Customer Care Representative (CSR) creates a Service Order for manual meter read (5 min).


3) CST travel time (assumed 5 min).

4) CST reads meter and records read on the Service Order (5 min).




Furthest Customer: Customer located the furthest distance from PNG(NE)’s regional officed (190 km away or 380 km return trip; assumes no PNG employee in area to read the meter)

1) Customer Care Representative (CSR) creates a Service Order for manual meter read (5 min).


3) CST travel time (assumed 285 min).

4) CST reads meter and records read on the Service Order (5 min).

5) CST faxes Completed Service Order to Customer Care (5 min).




On page 30 of the Application, PNG(NE) states, “Since customers would be charged a fee per meter read, PNG(NE) submits that the cost of these additional procedures would have a negligible effect on the financial analysis presented in support of this Application.”

15.8 Please discuss if PNG(NE) will track the incremental costs associated with the radio-off option separately from all other Operation & Maintenance expenses. Please explain why or why not.

Response: While PNG(NE) could implement processes to track incremental activities and costs related to the radio off option, PNG(NE) had not considered there to be significant value in tracking these incremental costs separately for all other Operation and Maintenance costs. However, as noted previously, the take-up of the radio-off option is expected to be low and the revenue collected from radio-off customers is expected to offset the associated costs of administering the radio-off option.


E. FINANCIAL

Reference: PROJECT COST ESTIMATES Exhibit B-1, Section 4.1, p. 31 Capital Cost Estimates – Vendor A (Itron)

On page 31 of the Application, PNG(NE) states the Vendor A cost estimate is “considered to be definitive” and at a Class 1 to Class 2 level of accuracy as per AACE Guidelines.

Exhibit 4-1, on page 31 of the Application, shows PNG(NE) applied a provision of 10 percent for overhead and 15 percent for contingency to the Vendor A cost estimate.

16.1 Please explain why a provision of 10 percent for overhead is appropriate.

Response: In forecasting capital projects, PNG(NE) typically includes a provision for overhead for internal resources that may be incidental to the base cost components of a project. For a project such as the AMR Project which will be executed primarily by a third-party, the 10% provision for internal overhead might be considered very conservative, however, PNG(NE) is comfortable with this provision and notes that the financial evaluation of the proposed project remains strong despite the conservative amount allowed for in the cost estimate.

16.2 Please explain why a 15 percent provision for contingency is appropriate for the Vendor A cost estimate.

Response: The quotes provided by Vendor A were considered to be Class I to Class 2 level of accuracy as per AACE guidelines. With respect to the magnitude of possible cost escalations, a Class 2 estimate has an expected accuracy range of +5% to + 20% at an 80% confidence interval and a Class 1 estimate has an expected accuracy range of +3% to + 15% at an 80% confidence interval. This implies that quoted capital costs have the statistical potential to increase by up to 15% - 20%. PNG(NE) believed it appropriate to add the high end of the Class 1 range of accuracy as a conservative contingency provision for its expected capital costs. In addition, PNG also recognizes that there are risks, albeit managed and mitigated, that are outlined in the risk assessment that could materialize during the installation. Some of these risks may be attributable to the vendor, some attributable to PNG(NE), and others a combination of shared risk between both PNG(NE) and the Vendor. The allocation of risk will be more specifically detailed in the final contract. For these aforementioned reasons, PNG believes the 15% continues to be appropriate.

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Reference: PROJECT COST ESTIMATES Exhibit B-2, Excel version of Appendices B, C; Exhibit B-1, Section 2.5, p. 22 Cost of Service Forecast – Vendor A (Itron) and Vendor B (Sensus)

Excel rows 23-25 in the Excel version of Appendices B and C, provided in Exhibit B-2, show the forecast annual vehicle operating (capital, fuel and maintenance) cost savings associated with the elimination of five trucks dedicated to meter reading.

17.1 Please explain what the forecast annual vehicle operating cost savings for each type of operating costs (capital, fuel and maintenance) is based on (e.g. certain number of years of historical average cost?)

Response: PNG(NE) made use of historical average costs when forecasting annual vehicle operational cost savings. The average fuel and maintenance costs are based on 2017 average costs of $6,000 and $4,000, respectively, escalated to 2020 at 2% annual inflation. The vehicle capital cost is was based on a 2017 average cost of $55,000 escalated to 2020 by 2% annually for inflation. This amount was divided by the estimated useful life of 7 years to arrive at the annual provision for depreciation expense.

On page 22 of the Application, PNG(NE) states the financial analysis assumes the elimination of 5 FTEs and 5 trucks because “existing non-meter reader FTE with existing truck will assume the responsibility of meter reading after AMR implementation.”

17.2 Please confirm, or explain otherwise, that the financial analysis in Appendices B and C, respectively, do not include any incremental annual labour or vehicle operating cost associated with employing an existing non-meter reader FTE with existing truck to assume meter reading responsibility.

Response: PNG(NE) confirms that the financial analysis provided in Appendices B and C, respectively, do not include any incremental annual labour associated with employing an existing non-meter reader FTE to assume meter reading responsibility. However, PNG(NE) notes that it has included in its financial analysis vehicle fuel and maintenance costs equivalent to 40% of the vehicle fuel and maintenance associated with a meter reader FTE (as per Row 28 of Exhibits B-2 and B-2-1, Excel versions of Appendices B and C to the Application).

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17.2.1 If confirmed, please explain why not. Given that AMR technology requires the existing truck be driven in the general vicinity of all customer meters, would there be additional mileage undertaken resulting in capital, fuel and maintenance costs that do not currently exist? Could there be additional salary expenses assuming meter reading responsibility cannot be performed within the existing non-meter reader FTE’s current work hours or salary? Please discuss.

Response: PNG(NE) is proposing to utilize an existing FTE to assume the meter reading responsibility. The existing FTE already operates a truck and PNG(NE) believes that there will be no additional capital costs associated with the new responsibility. In addition, PNG(NE) does not expect additional salary expenses to be assumed by this FTE. PNG(NE) does recognize that there may be some additional fuel costs and maintenance costs and PNG(NE) has reflected these costs in its financial analysis (as per Row 28 of Exhibits B-2 and B-2-1, Excel versions of Appendices B and C to the Application) and they are considered to be modest.


Reference: PROJECT COST ESTIMATES Exhibit B-1, Section 4, p. 32; Exhibit B-2, Excel version of Appendices B, C Cost of Service Forecast – Vendor A (Itron) Only

On page 32 of the Application, PNG(NE) states it has included a nominal average annual provision of $6,500 for maintenance costs for the mobile collection system in the forecast for AMR Project operating costs.

Row 32 in the Excel version of Appendix B, provided in Exhibit B-2, shows that the forecast for new handheld maintenance costs is as follows for the Itron product:

2020E – $2,987

2021E – $12,189

2022E – $10,232

2023E – 2040E – increases from $3,702 to $5,183 based on an assumed rate of inflation of 2 percent2

18.1 Please provide the calculation of the nominal average annual provision of $6,500 for maintenance costs using the forecast for new handheld maintenance costs for 2020E through 2040E, as provided in Excel row 32 in the Excel version of Appendix B.

Response: PNG(NE) submits that the $6,500 figure referred to in the preamble was a rounded number and that the exact average annual provision is $6,542 for the mobile collection system maintenance cost. This amount represents PNG(NE)’s best estimate of average annual maintenance cost over the full financial analysis period. PNG(NE) notes that this annual provision also includes the annual subscription costs (approximately $1,600 in 2020 dollars).

2 e.g. 2024E = 20203E x 1.02 (inflation rate per Excel row 63), 2025E = 20204E x 1.02 (inflation rate per Excel row 63), etc.

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18.2 Please explain how PNG(NE) forecasted the new handheld maintenance costs for the

Itron product for each of the years: 2020E; 2021E; 2022E; and 2023E.

Response: The vendor has indicated that the Itron Mobile Radios (IMRs) will not be supported after a two year

period and PNG(NE) would be encouraged to use only the Mobile Collector 3 Lite (MC3 Lite). In

addition, the IMRs were to be used as a tool to transition to the AMR infrastructure. PNG(NE) was

provided with an annual maintenance cost of $2,635 ($235.04 per month including 7% PST) for each

IMR and was also provided an annual maintenance cost (item # 20 of the AMR Implementation Pricing

Summary) of $1,744.12 ($145.34 per month) for each MC3 Lite.

The maintenance cost for 2020 assumes 3 months of use of each of the IMRs and MC3 Lites:

3 months x (3 IMRs x $235 + 2 MC3 Lites x $145.34/month) = $2,987.

The maintenance cost for 2021 assumes 12 months of use of each of the IMRs and MC3 Lites:

12 months x 3 IMRs x $235/month x 1.02 (inflation)

+ 12 months x 2 MC3 Lites x $145.34 x 1.02 (inflation)

= $12,198

The maintenance cost for 2022 assumes 9 months of use of the IMRs and 12 months use of the MC3

Lites:

9 months x 3 IMRs x $235/month x 1.02^2 (inflation)

+ 12 months x 2 MC3 Lites x $145.34/month x 1.02^2 (inflation)

= $10,232

The maintenance cost for 2023 assumes 12 months of use of the MC3 Lites and no use of the IMRs:

12 months x 2 MC3 Lites x $145.34/month x 1.02^3 (inflation) = $3,693

18.2.1 Please explain the annual variances in forecast new handheld maintenance

costs from 2020E through 2023E.



18.2.2 Please explain why forecast new handheld maintenance costs are expected to stabilize (but for inflation) after 2023E.

Response: In 2023 and beyond, only the maintenance costs associated with the MC3 Lite are included in the

analysis as the use of the IMRs are expected to be phased out. Please see the response to Question

18.2.


Reference: PROJECT COST ESTIMATES Exhibit B-2, Excel version of Appendix C Cost of Service Forecast – Vendor B (Sensus) Only

Row 33 in the Excel version of Appendix C, provided in Exhibit B-2, shows that the forecast for new handheld maintenance costs is as follows for the Sensus product:

2020E – $2,679

2021E – $10,929

2022E – 2040E – increases from $9,214 to $13,160 based on an assumed rate of inflation of 2 percent3

19.1 Please explain how PNG(NE) forecasted the new handheld maintenance costs for the Sensus product for each of the years: 2020E; 2021E; and 2022E.

Response: PNG(NE) acknowledges that line 33 was mislabeled and should have read “Maintenance costs for Vehicle Gateway Basestation” as the Sensus product does not include handheld devices. In addition, PNG(NE) recognizes that it had an error in line 33 for 2020 and 2021, and the corrected maintenance costs for these years are:

o 2020E – $2,214 compared to $2,679 originally reported

o 2021E – $9,033 compared to $10,929 originally reported

PNG apologises for these errors and submits that the impact on the financial evaluation is negligible. PNG(NE) has estimated a portion of the original costs of the Vehicle Gateway Basestation (VGB) as ongoing maintenance expense and has used a percentage of original costs as the annual maintenance expense translating to $369 per month per unit. The financial model assumes 3 months of use in 2020 and 12 months of use thereafter and applying an annual inflation rate. The maintenance cost for 2020 assumes 3 months of use of both VGB units:

3 months x 2 VGBs x $369 = $2,214 The maintenance cost for 2021 assumes 12 months of use of each of the VGBs:

12 months x 2 VGBs x $369/month x 1.02 (inflation) = $9,033

The maintenance cost for 2022 assumes 12 months of use of each of the VGBs:

12 months x 2 VGBs x $369/month x 1.02^2 (inflation) = $9,214

3 e.g. 2023E = 20202E x 1.02 (inflation rate per Excel row 60), 2024E = 20203E x 1.02 (inflation rate per Excel row 60), etc.

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19.1.1 Please explain the annual variances in forecast new handheld maintenance costs from 2020E through 2022E.


19.1.2 Please explain why forecast new handheld maintenance costs are expected to stabilize (but for inflation) after 2022E.



F. PUBLIC CONSULTATION

Reference: PUBLIC CONSULTATION Exhibit B-1, Section 5, pp. 33-34; Order G-20-15, Appendix A4 General Consultation

Appendix A to Order G-20-15 includes the 2015 Certificate of Public Convenience and Necessity Application Guidelines (CPCN Guidelines). Section 3 of the CPCN Guidelines outlines the requirements regarding public consultation.

In section 5.1 of the Application, PNG(NE) provides a description of the consultation conducted prior to filing the Application.

20.1 Pursuant to section 3(v) of the CPCN Guidelines regarding public consultation, please provide PNG(NE)’s overall assessment of the sufficiency of the public co10nsultation process with respect to the Project.

Response: The AMR Project’s public consultation process has been sufficient and appropriate to the nature and scope of the project. PNG(NE) advertised and conducted public information sessions in the areas affected by the AMR Project. Local municipality leaders were also contacted and presented with the current project plan. While attendance at the public sessions was less than anticipated, general questions on the AMR Project were typical of questions raised during the PNG-West 2018 AMR Pilot Project. A social media awareness campaign was also undertaken which communicated avenues available for further information and for any questions or comments. PNG(NE) observes that section 3(v) of the CPCN Guidelines refers to “Identification of specific issues or concerns raised by the First Nation.” PNG(NE) has not identified, nor does it anticipate, any issues or concerns specifically related to First Nations that would not apply to the general public. No First Nation has raised specific issues or concerns with the AMR Project to PNG(NE). PNG(NE) notes that the matter of impacted First Nations and the duty to consult have been examined in the BCUC regulatory proceeding on PNG(NE)’s 2013 Application For a CPCN to Acquire, Construct, Own and Operate a Compressed Natural Gas Virtual Pipeline between the Communities of Dawson Creek and Tumbler Ridge.[2] Specifically in regard to First Nations, PNG(NE) has identified Treaty 8 First Nations (those located in northeastern British Columbia from Fort Nelson in the north to McLeod Lake in the south)[3] as the First Nations potentially impacted by activities in its service area (Fort St. John, Dawson Creek and Tumbler Ridge). PNG(NE) believes that lands within municipal boundaries in Treaty 8 taken up for municipal

4 https://www.bcuc.com/Documents/Guidelines/2015/DOC_25326_G-20-15_BCUC-2015-CPCN-Guidelines.pdf [2] BCUC Project No. 3698725; https://www.bcuc.com/ApplicationView.aspx?ApplicationId=406; Exhibit B-4, IR Series 54 to 58 and Exhibit B-8, IR Series 53 to 55. [3] Mikisew Cree First Nation v. Canada (Minister of Canadian Heritage), 2005 SCC 69, [2005] 3 S.C.R. 388

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https://www.bcuc.com/ApplicationView.aspx?ApplicationId=406


purposes are no longer available for the exercise of treaty rights. Since the incorporation of the municipalities of Fort St. John, Dawson Creek and Tumbler Ridge, other steps have also been taken that confirm this intention, such as the prohibition of hunting within each of the municipal boundaries. PNG(NE) reiterates that the proposed activity for the AMR Project consists of installation of ERT devices on existing metering infrastructure which is generally located within the boundaries of the noted established municipalities. It is PNG(NE)’s opinion that no duty to consult arises from this circumstance. For the duty to consult to arise, PNG(NE) understands that there must be a potential adverse impact on an Aboriginal or Treaty right from the contemplated conduct – this potential adverse impact cannot be merely speculative – to trigger the duty requires “demonstration of a causal connection”[4] between the proposed conduct and the potential adverse impact. PNG(NE) submits that the CPCN sought does not have potential adverse impacts on an Aboriginal or Treaty right. Even if a potential adverse impact were to be asserted, there would be no causal connection between approval of the CPCN and a potential adverse effect on Aboriginal or Treaty rights such as the Treaty 8 rights to hunt, fish and trap.

On page 34 of the Application, PNG(NE) states “[community information sessions] [a]ttendees had questions on matters related to device safety, the cost to consumers, the loss of meter reading jobs and project timelines. Attendees were pleased to obtain a better understanding of the AMR technology and of the project goals.” Also, on page 34 of the Application, PNG(NE) states it met “with representatives of the municipalities for which the AMR Project will be implemented… Questions included the matter of displacement of meter readers, the cost to consumers, and confirmation of the technology to be used.”

20.2 Please describe the measures taken, or planned, to address issues or concerns raised by attendees and representatives of the municipalities for which the AMR Project will be implemented.

Response: Issues raised by the public at the public information and municipal leader sessions were addressed directly at that time with project details and technology facts. Further documentation in the form of a FAQ document will be distributed to the public prior to project implementation to further enhance the understanding of the AMR Project.

[4] Rio Tinto Alcan Inc. v. Carrier Sekani Tribal Council, 2010 SCC 43, para. 51


20.2.1 If no further action is required to address issues or concerns raised by attendees and municipality representatives, please explain why not.

Response: Please see the response to Question 20.2. PNG(NE) is committed to continue to engage stakeholders as the AMR Project advances.


Reference: PUBLIC CONSULTATION Exhibit B-1, Section 5, p. 33 Future Consultation and Communication

On page 33 of the Application, PNG(NE) includes an External Consultation and Communication Plan Milestones as Exhibit 5-1.

21.1 Please explain whether PNG(NE) sought input at the community information sessions and at its meetings with municipality representatives regarding future consultation and communication, as proposed in PNG(NE)’s External Consultation and Communication Plan Milestones.

Response: As noted in response to Question 20.2, the input of parties at the community information sessions and municipal meetings was sought. Issues raised by the public at the public information and municipal leader sessions primarily related to project timing and the technology being deployed. Municipal representatives expressed an interest in sharing of information with other members of local governments. To this end, PNG(NE) is continuing to engage local area stakeholders. The occurrence of the COVID-19 pandemic has required PNG(NE) to limit face-to-face interaction with the public. However, PNG(NE) is proceeding with the coordination of virtual meetings with local district representatives and municipalities to further communicate information regarding the AMR Project.

21.1.1 If yes, please provide a summary of the input received from stakeholders.

Response: Local municipalities expressed familiarity with the proposed AMR technology as similar systems have been installed for the water utilities in both Fort St. John and Dawson Creek. PNG(NE) is currently organizing web conference meetings to distribute information with local municipal leaders and council members and to provide an opportunity for feedback. Further, direct communications with customers will occur upon the successful approval of the proposed project to ensure there is widespread awareness of PNG(NE)’s planned activities. This direct communication is anticipated to include direct mailings and the provision of social media informational updates.

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21.1.1.1 Please explain whether PNG(NE) modified its External Consultation and Communication Plan Milestones based on the input received.

Response: No modification to the External Consultation and Communication Plan milestones was considered necessary as a result of the input received.

21.1.2 If PNG(NE) did not seek input on its proposed future consultation and communication with stakeholders, please explain why not.
