20170824AVU to Staff 54-73.pdf

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/23/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff 054 TELEPHONE: [phone]
REQUEST:

Please explain how the Company recovers dig-in expenses. Morris Exhibit No. 1, Schedule 2, at 37. Please include all supporting workpapers and analysis. RESPONSE: Avista actively seeks the recovery of all costs associated with repairing the damage to its service facilities and equipment caused by the actions of others, including, but not limited to, underground natural gas service facilities damaged by third-party excavators. Recovery of these costs is managed by the Avista Claims Department, which is tasked with identifying the responsible party
and gathering all pertinent costs and supporting documentation for the incident, including (a) labor, materials and equipment costs; (b) physical asset costs; and (c) estimates of natural gas loss. Once this information is compiled, the Claims Department issues an invoice to the responsible party, which may, depending on the circumstances, be either the excavator or, in the case of an
inaccurate locate, the company responsible for locating Avista’s underground facilities.
In those instances where the responsible party fails to acknowledge and/or remit payment on the invoice issued by Avista, the Claims Department will follow up with 30-day, 60-day and 90-day letters and/or telephone calls. If the responsible party refuses to take responsibility for the costs
associated with the damage to Avista’s service facilities and/or equipment, or otherwise fails to
respond to communications from Avista, the matter will, depending on the circumstances, be referred either to in-house legal counsel or an outside agency to pursue recovery.
The expenses associated with dig-in events are generally O&M expenses. Specific to natural gas
investments, the referenced Morris Exhibit No. 1, Schedule 2, page 37 refers to the Gas Non-Revenue Program within the “Failed Plant & Operations Investments” capital investment driver. This program includes additional capital investment not related to dig-in events. The business case for this Gas Non-Revenue Program includes additional discussion of investment
under this program and can be found at Rosentrater Exhibit No. 8, Schedule 5, page 177.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01 / AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC - Keyt RESPONDER: D. Machado / J. Miller
TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-055 TELEPHONE: [phone]
REQUEST: Please describe how the Gas Telemetry Program costs are allocated to individual customers and customer classes. Rosentrater Direct at 56. If costs are not allocated, please explain why not.

RESPONSE: Investment under the gas telemetry program is placed in service in the jurisdiction in which the assets are located—that is, telemetry equipment installed at a gate station in Idaho is assigned to
the Idaho jurisdiction. On a prospective basis, the program costs, on a system basis, are allocated
among jurisdictions on the basis of the three year average (2013-2015) of transfers to plant in each respective jurisdiction. The respective allocation used in Avista’s pro forma adjustments in this case was 28.173 percent for Idaho.
With regard to the allocation among rate schedules, the telemetry investment costs are allocated in
the Company’s natural gas cost of service study dependent upon which FERC account the costs are booked to. Depending upon the use of the equipment, telemetry costs are typically recorded to FERC accounts 379, 385, 395, and 397. Please refer to Company witness Mr. Miller’s Exhibit No. 15, Schedule 1, page 7, for a FERC account level description of how costs are allocated to
individual rate schedules.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: Regulatory REQUEST NO.: Staff-056 TELEPHONE: [phone]
REQUEST:

Please explain how the Company determined that a 45-percent reduction in the Overbuild Pipe Replacement Program achieves an acceptable level of risk. Rosentrater Direct at 58. Additionally, please provide the Company’s definition of acceptable risk. RESPONSE: As noted in the testimony of Mr. Morris, one of the Company’s key objectives related to our capital investments is to be mindful of the overall cost impacts to our customers over time. In recent years Avista has chosen to not fund all of the capital investment projects requested by the
various departments in the Company, driven in large part by the Company’s desire to mitigate the retail rate impacts to customers. The decision to delay funding on certain projects is made only in cases where the Company believes the amount of risk associated with the delay is reasonable and prudent.

When the Capital Planning Group meets to discuss how to best accommodate the Company’s combined requests for capital investment within the approved spending limit, they make an iterative and comparative assessment of the benefits and avoided consequences associated with funding or deferring projects or programs. In this process the team adjusts the list of projects to be
funded, as well as the amounts to be funded, to arrive at the best-balanced allocation of capital
among priority needs across the business. This allocation balances benefits and risks in a manner that Avista deems reasonable. For example, Avista’s Gas Facility Replacement Program (Aldyl A pipe replacement) has been funded year-to-year at a level needed to complete the work within the
established 20-year horizon. This program has been fully funded because Avista has determined
the risk associated with potential increases in leaks in this piping, which would result from less funding and a slower pace in replacements, to be unreasonable. Replacing the Aldyl A pipe has priority because of the characteristics of the pipe itself and its proven tendency to fail at increasing rates with age. By comparison, the Overbuild Pipe Replacement Program does not address assets
that are at increased risk of failing, but rather, remedies circumstances where customers have
created code violations by locating structures over our piping. While the ‘overbuilding’ does increase the risk in the event there was a leak under one of these structures, the likelihood of leaks occurring in these situations is less than situations involving Aldyl A pipe.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/18/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Jeff Webb TYPE: Production Request DEPARTMENT: Gas Engineering REQUEST NO.: Staff-057 TELEPHONE: [phone]
REQUEST:
Please quantify the annual and per unit reduction of O&M costs due to reducing farm taps referred to in Rosentrater Exhibit 8. Please include all supporting workpapers and analysis.
RESPONSE: Annual numbers of Farm Tap retirements specific to this reason are not tracked. Regulator Station
retirements in general are tracked, but they are not broken out as to why they are retired, so
extrapolating an annual number is not possible. Additionally, single service farm taps are not distinguished from regulator stations in the accounting system. It costs approximately $55 per year to maintain one farm tap. On average: approximately 8 Farm
Taps can be inspected in one eight hour day by one individual (1.0 hrs each), $24 worth of
maintenance parts and supplies are used at each inspection, and the maintenance cycle is once every three years. See Staff_PR_057 Attachment A, which is also shown below shows the calculation of the $55 per year cost to maintain one farm tap:
FARM TAP MAINTENANCE
Key maintenance items include regulators and relief valves. On
average, one of these are replaced on 1 out of every 20

$ 55 Divide by 3 to get an annual cost per station
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/21/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-058 TELEPHONE: [phone]
REQUEST:

Please provide the business case for the Meter Data Management System. Rosentrater Direct at
64. Please include all supporting workpapers and documentation. a.) Please explain why the Meter Data Management System business case was changed from the Enterprise Technology functional group in 2016 to the General Plant functional group
in 2017. b.) Please include all benefit-cost analysis conducted showing the value of the Meter Data Management System before and after AMI is implemented in both Washington and Idaho. Please include all supporting workpapers and documentation, including jurisdictional
allocations and costs.
RESPONSE: a.) Avista understands this question to reference the table header under which the project was
included in this case (i.e., “General Plant Capital Projects” at page 61 of Ms. Rosentrater’s testimony in this case—Docket No. AVU-E-17-01/AVU-G-17-01) as compared to the table header under which the project was included in the previous case (i.e., “Enterprise Technology Capital Projects” in Docket No. AVU-E-16-03, Kensok, Di, page 7). This
change results from the decision to include this project in the testimony of Ms.
Rosentrater, as she is the Company vice president who is the primary sponsor of the project. The project was included in Ms. Rosentrater’s testimony within the “General Plant Capital Projects” for simplicity’s sake, rather than including a separate Enterprise Technology table with one item. This does not, however, change the nature of the project.
In fact, in Company witness Ms. Schuh’s workpapers (page 14 of 95) the pro forma
adjustment associated with the Meter Data Management Hardware and Software components is clearly illustrated using the depreciation rate for hardware and the 12.5-year depreciable life (8% annual depreciation expense) proposed by the Company in
Docket No. AVU-E-17-03.
b.) Meter data management systems (MDM) are emerging as a metering standard across the industry, enough so that Avista contemplated installing such an application to be its enterprise system for storage and management of metering data as a part of installing its new customer care and billing system (2012-2015). The Company elected to temporarily
defer the implementation until the present time, allowing us to further evaluate the technical specifications that would be optimal for Avista. Ultimately, the Company chose to assess the specifications for its meter data management system as part of its selection of an advanced metering infrastructure (AMI) system. Avista developed a cost-benefit
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analysis for its Meter Data Management (“MDM”) system as part of its AMI business
case. The Company’s decision to establish the meter data management system as the single system of record for all meter usage data was based on the principle of avoiding the
increased complexity, cost and technical risk associated with the alternative of implementing and maintaining two or more separate meter data systems of record. As an example of the complexity, our customer care and billing system is configured to receive billable usage from a single source of record. The integration of more than one source of record would require modifications to this and our other application systems adding costs,
complexity and risks. Operating multiple meter data management systems would also require different meter ‘head end’ solutions. Storing customer’s usage data in multiple different systems would also complicate the tasks of Avista’s Customer Service Representatives, requiring them to access different storage systems to access customers’ usage data, depending on the location of each customer. Adopting one meter data
management system as the Company’s system of record for customer usage and billing data, as Avista has chosen, is prudent because it avoids the technical complexity and risks, and the greater capital and O&M costs that would be required to implement and maintain separate meter data management systems for each of its jurisdictions.

Beyond these considerations, the new meter data management system will also help Avista provide improved service to our Idaho customers even before a new AMI system is installed. Some of these service improvements include the following:
1. Reduced call time for customers who are either starting or stopping service with
Avista. 2. Improved process for estimating bills for customers. 3. More efficient management of “billing exceptions” since all billing data will reside on a common head end platform.
4. Automated billing for our MV 90 industrial and large commercial customers. 5. Reduced time in the billing cycle between the when the meter is “read” and when the customer receives the bill. 6. Meter readings taken during field activities by Avista personnel will be validated in the meter data management system, ensuring the accuracy of the field read.

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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/21/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-059 TELEPHONE: [phone]
REQUEST:
Please provide all workpapers and documentation for Idaho AMI business case.
RESPONSE: The installation of automated meter reading (AMR) in Idaho was completed in 2006 and the assets
were assumed to have a fifteen-year life before the system would have to be replaced. The effects of age and deterioration of elements of the system are becoming evident. In addition to the aging of the natural gas meter modules and electric meters, the field network equipment and back office software is already obsolete. As an example, the Itron network equipment will no longer be supported after year 2021. Avista and its associated technology vendors are developing
alternatives to help support these systems until the entire system is replaced, but none of these solutions will meet the requirements of our next generation replacement metering system (whether AMR or AMI).
As Avista began its initial planning to replace the existing AMR system in Idaho, we considered
whether to replace it with current-generation AMR technology or to upgrade the metering system to AMI as the preferred alternative. The existing AMR system would essentially have to be replaced, including new meters, field network devices, and head end hardware and software. There are no new types of benefits for customers with a new AMR system, and the principal benefit
would continue to be O&M savings associated with the elimination of manual meter reading. In
addition to not capturing additional areas of benefit, AMR is quickly becoming obsolete as a metering standard in the industry; by the time the AMI deployment commences in Idaho, more than 70% of all households in the U.S. are expected to be equipped with AMI.
Advanced metering in Idaho will allow Avista to better meet our customers’ current and long-term service expectations, save energy through conservation voltage reduction, reduce customer costs by reducing outage duration, reduce storm restoration costs, thwart energy theft, and enable future options such as time-of-use or demand-based rates. Finally, the initial deployment of AMI in Washington has been demonstrated to be cost effective, and the same will hold true for the Idaho
deployment. This is because the costs for new meters, communications systems and hardware, and the head-end applications and hardware and other systems, etc., would not be included in the business case analysis, since they are already required to replace the existing AMR system.
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/22/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: Regulatory REQUEST NO.: Staff 060 TELEPHONE: [phone]
REQUEST: Please describe how Avista calculates the cost effectiveness of replacing overhead feeders with underground lines. Rosentrater Direct at 9.
RESPONSE: The vast majority of electric distribution facilities are maintained and / or replaced ‘in-kind,’
aligned with Avista’s current construction and material standards, in compliance with the National
Electric Safety Code (NESC) and other applicable rules. However, programs for converting overhead facilities with underground lines are gaining traction across the electric industry and Avista participates in a number of peer-utility forums including the Western Energy Institute to maintain awareness and alignment on a variety of issues including electric distribution asset
replacement.
In 2012, Avista initiated an asset condition program titled Grid Modernization. The program embodies a collaborative effort between various departments including Engineering, Asset Management, Asset Maintenance, and Electric Operations. This program is a long-term strategic
effort that reconstructs electric distribution facilities that are approaching the end of their useful life. The program was planned for a 60-year cycle (i.e. would rebuild every feeder over 60 years) and feeders are selected based on the best opportunities to improve facility health and performance. In specific situations, the project designs created by Grid Modernization include converting portions of overhead facilities to underground. In those instances, a variety of factors
influence the decision including the following:
• When the costs and risks associated with reconstruction of the overhead feeder and equipment, while the line continues to serve customers (energized), are balanced with the costs and safety advantages of installing new underground lines (de-energized), junctions,
and padmounted transformers. This treatment is typically only cost effective where the new electric cable can be “plowed” in rural areas versus the more expensive “trenching” installation required in urban, hard-scape areas.
• In inaccessible and heavily forested areas where relocating the feeder to a road right-of-way reduces exposure to tree related outages, improves reliability, help reduce
costs for vegetation management, and improves accessibility if problems arise.
• When the feeder is located in public road rights-of-way where clear zone requirements make it impractical to maintain overhead facilities.
• When Avista’s facilities are being installed along with the infrastructure of other utilities
(e.g. cable, phone, sewer, and water), which provides opportunities to use a joint trench to
replace or relocate facilities.
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• In areas where conflicts exist between threatened and endangered bird species and the
location overhead facilities (e.g. eagles, ospreys, and hawks).
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-061 TELEPHONE: [phone]
REQUEST:
Regarding Distribution Wood Pole Management, please provide the location and number of
affected poles in Idaho and Washington. Rosentrater Direct at 20.
RESPONSE:
Please see Staff_PR_061 Attachment A, an Excel file listing each of the Company’s overhead feeders, including the state and general location of the feeder by operations office, the feeder name, the attached substation, and the number of poles in each feeder line.
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/22/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: Regulatory REQUEST NO.: Staff 062 TELEPHONE: [phone]
REQUEST:
Please provide all studies conducted that compare the overhead and underground options for the
URD replacement projects in Idaho. Rosentrater Direct at 21.
RESPONSE:
Avista’s decisions to place electric feeder and service lines underground instead of building overhead facilities are based on a range of factors. For example, land developers often decide they want underground facilities (and they pay for that) when they have the Company install electric service in residential subdivisions or commercial / industrial developments. When underground residential district (URD) cable is in need of replacement it is replaced in kind because the
circumstances that supported the initial decision to underground the line most likely still apply. Further, the reliability issues related to early generation electric cables have been satisfactorily addressed, and URD cable is widely used across the industry. Consequently, the Company does not evaluate the alternative of replacing underground cable with overhead distribution facilities.
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/22/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Larry La Bolle TYPE: Production Request DEPARTMENT: Regulatory REQUEST NO.: Staff 063 TELEPHONE: [phone]
REQUEST: Please provide the locations and workpapers associated with Idaho URD replacement projects. Please include accelerated replacement schedules and calculations for avoided outage estimations. Rosentrater Direct at 22.

RESPONSE:
The total number of line segments and feet of underground URD cable installed in Avista’s Idaho
service territory by operating division, and the total segments and feet of cable replaced are provided in the table below.
Operating Division Total Segments
Installed
Total Length
Installed (ft)
Total Segments
Replaced
Total Length
Replaced (ft)
Coeur d'Alene 17,540 5,033,886 934 279,774
Grangeville 1,998 1,372,622 692 544,168
Kellogg 1,661 1,040,320 412 373,817
Lewiston (Clarkston) 3,103 849,685 624 179,385
Palouse ID (Pullman) 2,785 858,433 914 279,208
Sandpoint 4,964 1,508,125 1,467 500,737
St. Maries 1,525 1,123,912 337 240,001

Calculation of the costs and benefits associated with the accelerated replacement schedule, which are excerpted from pages 8 and 9 of the Company’s asset management report for 2007, are provided below.
Electric Underground Replacement
This ER addresses programmed replacement of aging underground primary distribution cable, commonly referred to as URD. Over 6,000,000 feet of original vintage cable were installed. Approximately 1,000,000 feet of the original cable remains in service. There are over 200 faults
on the cable annually. Analysis indicates accelerated program to replace the remainder of the cable in four years is a fiscally sound decision. The computed IRR values between a 7 year program and a 4 year program are within .07% of each other. However, the overall number of faults with a 7 year
program vs. a 4 year program is estimated to be 30% higher over a 10 year timeframe. Estimated
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faults double between a 4 year program and the current replacement pace of about 100,000 ft per
year during the next 10 years. The results are in Table 6 "Underground Cable Replacement Financial Results.” IRR of 4 year program compared to 10 year program basis is 10.15%.
Table 6. Underground Cable Replacement Financial Results
10 Year Results
Capital, O&M, Consequences, Installation, O&M
Response
For Outage Response Over 10
Years
3.5% inflation per year applied
Budget during replacement timeframe
Replacement Pace, 10 years to replace
all original cable
Replacement Pace,
4 years to replace all
Note (a) Cost to respond to outages has been decreased as number of outages decreases with the quantity of cable replaced.

Table 1. Underground Cable Replacement Reliability Results.
10 Year Results Primary Voltage Note (a) Note (b)
Replacement Pace, 10 years to replace all original cable
Replacement Pace, 4 years to replace all
Note (a) CAIDI is predicted as flat value due to estimated time to repair fault remaining constant. Multiple simultaneous outages would result in larger CAIDI value Note (b) SAIFI value is calculated from the number of faults times average number of customers
per fault (13) divided by number of years (10) divided total number of customers (rounded to 340,000).
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01 / AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Landen Grant TYPE: Production Request DEPARTMENT: Operations REQUEST NO.: Staff-064 TELEPHONE: [phone]
REQUEST NO.: Regarding the LED Change Out Program, please provide the locations and associated expense for all Idaho projects. Rosentrater Direct at 28.
RESPONSE: See Staff_DR_064 Attachment A.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/18/2017 CASE NO: AVU-E-17-01 / AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Erin McClatchey TYPE: Production Request DEPARTMENT: Compliance REQUEST NO.: Staff-065 TELEPHONE: [phone]
REQUEST: Please provide information about all penalties, monetary and otherwise, that have occurred because of non-compliance with NERC standards. Rosentrater Direct at 32.

RESPONSE: Since January 1, 2016, Avista has not incurred any penalties, monetary and otherwise, due to
non-compliance with NERC Reliability Standards.
As stated in Ms. Rosentrater’s testimony, compliance with NERC standards is mandatory under federal law and “The standards require utilities to plan and operate their systems to avoid customer outages and to prevent adverse impacts to neighboring utility systems arising from the loss of transmission service. Specifically, the transmission system must be designed so that the simultaneous
loss of up to two facilities will not impact the interconnected transmission system. Further, the loss of any single facility must not cause any other facility in service to exceed its System Operating Limit (voltage or capacity ratings) or cause the interconnected transmission grid to operate outside specified reliability limits (voltage and stability limits).”1 Whether non-compliance with NERC standards has occurred in the past or not does not change the fact that continued investment is required to maintain
compliance with NERC Reliability Standards. We do not want to become out-of-compliance and incur penalties before investing in maintaining our level of compliance. Avista performs an annual Transmission System Planning Assessment to evaluate system performance with respect to NERC Reliability Standards and this assessment helps provide guidance as to the capital investments the Company prioritizes over its 5year capital investment plan.
1 Rosentrater, Direct, page 32, line 17 through page 33, line 5.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/18/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Ken Sweigart TYPE: Production Request DEPARTMENT: Substation Design REQUEST NO.: Staff-066 TELEPHONE: [phone]
REQUEST: Please list and provide the associated expense for all proposed Idaho distribution substation projects, including rebuild projects and new distribution substations.
RESPONSE: Staff_PR_066 Attachment A includes Avista’s five year plan (2017-2021) for substation and
transmission projects, as of June 2017.
Staff_PR_066 Attachment B includes the year-to-date project expenditures for Avista’s substation projects through July 2017.
Staff_PR_066 Attachment C and D include the requests submitted to the Capital Planning Group
(“CPG”) for the New Distribution Substations and Distribution Substation Rebuilds business cases, respectively, for the 2018 to 2022 capital planning process, which is currently underway. These attachments include enumeration of the planned substation work under each business case.
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/21/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Jeff Schlect TYPE: Production Request DEPARTMENT: Transmission Services REQUEST NO.: Staff-067 TELEPHONE: [phone]
REQUEST: Please describe how the Hallett and White substation interconnection investment for an existing large retail customer is a prudent expense for Idaho customers. Rosentrater Direct at 41.
RESPONSE: Local substation project costs are commonly split into three primary components: distribution,
transmission and communications. All distribution and communication costs for a local substation
project are allocated to the jurisdiction in which the substation providing service resides. The transmission portion of a substation project is treated the same as all other transmission investment and is split between jurisdictions based upon the Company’s Production/Transmission (P/T) Ratio allocation. Accordingly, for the Hallett and White substation upgrade project, all distribution and
communications costs will be attributable to the Company’s Washington jurisdiction while the
transmission portion of the project will be allocated between the Company’s Washington and Idaho jurisdictions, just as with any other transmission investment. This allocation of transmission investment between jurisdictions is consistent with all substation integration projects. For example, recent substation projects in the Company’s Idaho jurisdiction include Blue Creek,
Lucky Friday, and Lewiston Mill Road. While these substations provide service to Idaho jurisdiction loads, all transmission costs associated with these projects have been allocated to both the Company’s Idaho and Washington jurisdictions. As outlined in the Company’s response to Staff 69, it is understood that components of the
interconnected transmission grid accrue benefits to all customers. This includes transmission investment associated with a local substation integration project. For example, transmission sectionalizing switches associated with a substation integration project also benefit other customers served by the transmission line to which the new or rebuilt station is connected. In the
case of a forced outage, sectionalizing switches may be operated, either by automatic or manual
operation, to quickly reconfigure the system to isolate the problem area and restore service to most or all customers impacted by the transmission problem. Additionally, as referenced in the Company’s response to Staff 68, FERC policy rejects the direct
assignment of integrated grid facilities even if those facilities would not have been installed but for
a particular request for service [see Consumers Energy Company, 96 FERC PP 61,132 (2001)] (emphasis added).
Accordingly, since all distribution and communication costs associated with the Hallett and White
Substation upgrade project will be allocated to Washington customers, and all transmission costs associated with this project will be allocated to both Washington and Idaho customers pursuant to
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the Company’s standard P/T Ratio allocation, the Company respectfully asserts that its investment
in this project is a prudent expense for its Idaho customers.
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/20/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Jeff Schlect TYPE: Production Request DEPARTMENT: Transmission Services REQUEST NO.: Staff-068 TELEPHONE: [phone]
REQUEST: Regarding OATT, please cite the federal rules which require the Company to construct transmission facilities at the request of transmission customers. Please list proposed projects and associated expense related to customer requests for new transmission facilities. Rosentrater Direct
at 43. RESPONSE:
Federal Rules
Federal rules regarding the Company’s obligation to construct transmission facilities at the request of transmission customers are outlined in a number of documents and proceedings and are continually subject to adjustment and refinement through applicable rulings or orders promulgated
by the Federal Energy Regulatory Commission (FERC). The basic obligations by which the
Company must comply include the following sections of the Company’s Open Access Transmission Tariff (OATT): For Point-to-Point Transmission Service, Section 13.5, Section 15.4 and Section 27; for Network Integration Transmission Service, Section 28.2, Section 28.3, Section 30.8 and Section 32; for Interconnection Service, Attachment M – Section 3.2.2.
Related to Point-to-Point Transmission Service, Section 13.5 states:
In cases where the Transmission Provider determines that the Transmission System is not capable of providing Firm Point-to-Point Transmission Service… the Transmission Provider will be obligated to expand or upgrade its Transmission System…
This obligation to construct is subject to the provisions of Section 15.4, which are further clarified by the provisions of Section 27. Section 27 requires that certain costs may be attributable to a Transmission Customer “to the extent consistent with Commission [FERC] policy.”
Similarly, for Network Integration Transmission Service, Section 28.2 includes an obligation on
the part of the Transmission Provider to “plan, construct, operate and maintain” its Transmission System “…in order to provide Network Integration Transmission Service…” And shall
endeavor to construct and place into service sufficient transfer capability to deliver the Network Customer's Network Resources to serve its Network Load on a basis
comparable to the Transmission Provider's delivery of its own generating and
purchased resources to its Native Load Customers.
Sections 28.3 and 30.8 further affirm this “comparability” obligation and ensure that Transmission Customers have an equal, if not greater, right to the use of interface capability with other systems. Section 32 outlines the study processes required to assess what new construction might be needed
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to provide Network Integration Transmission Service and Section 32.4 specifically references the
costs that may be attributable to the customer, namely Direct Assignment Facilities and an “appropriate share of the cost of any required Network Upgrades.” A Transmission Provider is also obligated to construct facilities to provide interconnection to a
Large Generating Facility per Attachment M – Section 3.2.2.1:
Transmission Provider must conduct the necessary studies and construct the Network Upgrades needed to integrate the Large Generating Facility in a manner comparable to that in which Transmission Provider integrates its generating facilities to serve native load customers.
These provisions underscore the Company’s obligation to construct transmission facilities to meet a Transmission Customer’s or Interconnection Customer’s needs. With respect to the allocation of costs associated with these projects, FERC policy stipulates that only Direct Assignment Facilities may be directly allocated to a customer, while all Network Upgrades are the responsibility of the
Transmission Provider. As outlined in the Company’s response to Staff 69, the interconnected transmission network provides benefits to all customers. FERC policy on the determination of which facilities are Network Upgrades, and which may be directly assigned to a customer, asserts a consistent view. Network Upgrades are defined in the OATT for both Transmission Service and
Interconnection Service.
For Transmission Service (Section 1.29):
Modifications or additions to transmission-related facilities that are integrated with and support the Transmission Provider’s overall Transmission System for the general
benefit of all users of such Transmission System.
For Interconnection Service (Attachment M – Section 1):
Network Upgrades shall mean the additions, modifications, and upgrades to the Transmission Provider’s Transmission System required at or beyond the point at which
the Interconnection Facilities connect to the Transmission Provider’s Transmission System to accommodate the interconnection of the Large Generating Facility to the Transmission Provider’s Transmission System. Examples of FERC policy on determining what facilities must be deemed Network Upgrades
include: From Order No. 807-A at P 241:
Direct assigned facilities “are sole-use, limited and discrete, radial in nature, and not
part of an integrated transmission network... (emphasis added)
And from Florida Power & Light, 98 FERC ¶ 61,276 (2002):
In Consumers Energy Company, 96 FERC ¶ 61,132 (2001) (Consumers), the Commission rejected the direct assignment of integrated grid facilities even if those
facilities would not have been installed but for a particular request for service
(See Consumers at 61,561). (emphasis added)

1 Open Access and Priority Rights on Interconnection Customer’s Interconnection Facilities, 150 FERC ¶ 61,211 (2015 (“Order No. 807”), order on reh’g and clarification, 153 FERC ¶ 61,047 (2015) (“Order No. 807-A”).
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Network facilities include all facilities at or beyond the point where the customer or
generator connects to the grid. See Entergy Gulf States, Inc., 98 FERC ¶ 61,014 at 61,023 (2002). This policy is without regard to the purpose of the upgrade (e.g., to relieve overloads, to remedy stability and short circuit problems, to maintain reliability, or to provide protection and service restoration).
In summary, the Company is obligated by federal rule to construct transmission facilities for transmission customers and interconnection customers, and the rules by which the Company may allocate the costs of these facilities is dictated by FERC policy regarding what may and may not be deemed to be Network Upgrades.

Proposed Transmission Projects Related to Customer Requests
Of those transmission projects identified in Rosentrater Direct (pp. 38-47), no projects are driven by a Transmission Customer request for Transmission Service or Interconnection Service. As noted for the Saddle Mountain 230/115kV Station Integration project (Rosentrater Direct at 43),
the 230kV portion of the project is also required to integrate a proposed 126MW wind generation project. Of the overall costs of this project, Direct Assignment Facilities costs to be allocated to the Interconnection Customer are estimated to be $1,412,500.
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AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/20/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Heather Rosentrater
REQUESTER: IPUC RESPONDER: Jeff Schlect TYPE: Production Request DEPARTMENT: Transmission Services REQUEST NO.: Staff-069 TELEPHONE: [phone]
REQUEST: Please include the details and map of the proposed Saddle Mountain 230/115kV station integration project and demonstrate how this transmission investment will benefit Idaho rate payers. Rosentrater Direct at 43.
RESPONSE:
Details regarding this project are included in Staff_PR_069 Attachment A - Saddle Mountain
230/115kV Station Integration Project business case justification narrative. A site map diagram and local area map for the Saddle Mountain project are provided below. With respect to this project’s benefit to specific customers, the Saddle Mountain project is
necessary to ensure the Company’s transmission system and the regional interconnected
transmission system meet applicable mandatory reliability standards and continue to provide the overall benefits of an interconnected transmission grid to all customers, including the Company’s Idaho customers. The regional transmission grid, while owned and operated by different entities, is a single, interconnected machine wherein all components provide a measure of support and
increased reliability to the system as a whole. For example, just as the Company’s recent construction of its Noxon 230kV shunt reactor station in North Idaho may be viewed as supporting the overall regional transmission grid, so may the Saddle Mountain 230/115kV station. Accordingly, the primary benefits to the Company’s Idaho customers from the Saddle Mountain project derive from the overall benefits to all customers from interconnected transmission system
operations. However, the Company’s Idaho customers also benefit from the Saddle Mountain project even if it is viewed, albeit improperly, in the context of only its impact upon the local transmission system.
Benefits Attributable to Interconnected Transmission System Operation
To the extent any transmission project enhances the reliability of a local area within the transmission grid or provides support to interconnected transmission system operations, all customers derive benefit from such investment. The benefits that accrue to all of the Company’s customers from its interconnections with the Bonneville Power Administration (“BPA”), Idaho
Power, NorthWestern Energy and PacifiCorp in the states of Idaho and Montana are the same
benefits that accrue to all of the Company’s customers from its interconnections with BPA, Chelan County PUD, Grant County PUD (“Grant PUD”), PacifiCorp and others in the state of Washington, and these same benefits are attained from the interconnections that each of the Company’s interconnected neighbors have with other transmission systems. These interconnected
transmission system benefits include reliability and diversity of power supply, reductions in
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generation capacity margins, economic operation of resources, and reductions in frequency
response requirements.
(i) All customers benefit from the generation diversity provided by interconnected transmission system operation. Absent interconnected operation, all generation needed to serve local customers would have to be constructed within or near the demand center, therefore limiting
the type of resources available. Interconnected transmission systems enable the procurement of remote resources with varying fuel supply options, the opportunity to share risk through joint projects, and introduces possible economies in transportation.
(ii) Interconnected transmission system operation provides the economic benefit of reducing necessary generation capacity margins. Absent interconnected operation, sufficient
generation capacity must be constructed in all areas not only to meet peak load demand, but also to provide backup generation capability in the event a resource was not available, either due to routine maintenance or breakdown, during peak demand conditions. The ability to draw upon mutual backup assistance in power supply reduces the overall amount of generation capacity needed to ensure reliability of supply, thereby providing economic
benefits to all customers.
(iii) An interconnected transmission system provides the opportunity for load-serving entities to pursue the most economic supply options to meet electric load requirements, ranging from long-term supply to hourly operation.
(iv) All customers benefit from the overall reduction in frequency response capability enabled by
interconnected transmission system operation. Absent interconnected operations, each separate system would need to carry its own frequency response capability to protect against widespread outages due to large deviations in frequency. If demand is greater than generation, frequency falls. If generation is greater than demand, frequency rises. To
reliably maintain system frequency, sufficient generation capacity must be online and
available to respond in a moment’s notice. Interconnected transmission system operation allows all customers to benefit from shared frequency response capability throughout the interconnected grid.
Benefits Attributable to Support for Local Transmission System
While the primary benefits of the Saddle Mountain project to the Company’s Idaho customers derive from the project’s coordinated integration into the overall regional transmission grid, upgrades to the western portion of the Company’s transmission system also provide support for activities from which the Company’s Idaho customers have, and will continue to, directly benefit.
When considering the Saddle Mountain project only in the context of its integration into the local transmission system to support the Company’s Othello area load and its interconnections with Grant PUD, the Company’s Idaho customers also benefit from the following:
(i) The Company’s interconnections with Grant PUD are imperative to integrate the Company’s
long-term Mid-Columbia resources as well as the ability to facilitate short-term power
transactions at the Mid-Columbia. The Company’s Idaho customers have long benefitted from electric energy and capacity purchased from Grant PUD and from other entities at the Mid-Columbia, which power was scheduled through the Company’s interconnections with Grant PUD.
(ii) Since 1983 the Company has provided long-term transmission service to the City of Seattle
and Tacoma Power to transfer the output of the Summer Falls and Main Canal hydroelectric generation projects that are integrated into the Avista system in the Stratford area, which lies north of Avista’s Othello service territory and adjacent to the Grant PUD 115kV transmission system. The Company has required the collaboration of Grant PUD in
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providing this service, either through procuring transmission capacity through the Grant
PUD system or by Grant PUD agreeing to be the recipient of power scheduled from the Summer Falls and Main Canal resources. The Company’s Idaho customers have long benefitted from the transmission service revenues received by the Company in providing this service.
(iii) Under the Avista-BPA West-of-Hatwai Capacity Allocation Agreement and its predecessors, the Company must operate its Big Bend area 115kV transmission system in an open, or segmented fashion. This segmented operation severs the contiguous operation of the Company’s transmission system serving the Othello and Stratford areas from the Company’s transmission facilities serving the Spokane, North Idaho, Palouse and Lewiston-Clarkston
areas. The Saddle Mountain project enhances the Company’s ability to reliably serve its Othello area load, which facilitates the Company’s continued segmentation of its Big Ben area 115kV system, which facilitates the Company’s performance under the West-of-Hatwai Capacity Allocation Agreement, which provides for the Company’s 600MW of bi-directional West-of-Hatwai transmission capacity to and from the Mid-Columbia area.
This transmission capacity directly benefits the Company’s Idaho customers because it facilitates the Company’s power resource acquisitions, purchases and sales in the Mid-Columbia area, and enables transmission service revenues generated by this transmission capacity.

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Saddle Mountain Substation – Site Map

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Saddle Mountain Substation – Area Map

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Patrick Ehrbar
REQUESTER: IPUC RESPONDER: Joe Miller TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-070 TELEPHONE: [phone]
REQUEST: For Electric Rate Schedule 21/22 – Extra Large General Service - Idaho, with approximately 1,125 Idaho customers, please provide – by customer - monthly energy (kWh) and monthly demand (maximum 15 minute demand in a month, kW) for each month of the test year. Please provide in
Excel format, with one record (customer) per row. RESPONSE:
See the Company’s response labeled “Staff_PR_070 Attachment A”.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Patrick Ehrbar
REQUESTER: IPUC RESPONDER: Joe Miller TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-071 TELEPHONE: [phone]
REQUEST: For each month of the test year - for each electric Extra Large General Service (Schedule 25) customer and for Clearwater Paper (Schedule 25-A) – on a confidential basis, please provide: a. kWh:
b. kW (actual): c. kW (billed) - if different from actual kW due to contract minimums, ratchets, etc.: and d. billed revenue

RESPONSE: Please see Avista's response 071C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the Protective Agreement. a.-d.
Please see the attachment labeled “Staff_PR_071C Confidential Attachment A” which contains
2016 proforma test year kWh’s and kVA usage by month. Per discussion with Commission Staff the Company has included base revenue in the response to subpart d.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/16/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Patrick Ehrbar
REQUESTER: IPUC RESPONDER: Joe Miller TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-072 TELEPHONE: [phone]
REQUEST: For Gas Rate Schedule 111/112 – Large General Service - Idaho, with approximately 1,408 Idaho customers, please provide – by customer - monthly gas usage (therms) for each month of the test year. Please provide in Excel format, with one record (customer) per row.
RESPONSE: See the Company’s response labeled “Staff_PR_072 Attachment A”.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION JURISDICTION: IDAHO DATE PREPARED: 08/11/2017 CASE NO: AVU-E-17-01/AVU-G-17-01 WITNESS: Patrick Ehrbar
REQUESTER: IPUC RESPONDER: Joe Miller TYPE: Production Request DEPARTMENT: State & Federal Regulation REQUEST NO.: Staff-073 TELEPHONE: [phone]
REQUEST: Page 26, line 22 of Mr. Ehrbar’s testimony shows that currently there are no Interruptible gas customers (Schedules 131/132). Has the Company ever provided service to a customer under this gas rate schedule? Please provide the name(s) of any customer(s) and when service was provided.
RESPONSE: Please see Avista's response 073C, which contains TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and exempt from public view and is separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the Protective Agreement.