20160812Gilchrist Direct.pdf

Ronald L. Williams, ISB No. 3034
Williams Bradbury, P.C.
1015 W. Hays St.
Boise, ID 83702
Telephone: [phone]
Email: [e-mail]

Attorneys for Intermountain Gas Company

BEFORE THE IDAHO PUBLIC UTILITES COMMISSION

IN THE MATTER OF THE APPLICATION OF
INTERMOUNTAIN GAS COMPANY FOR
THE AUTHORITY TO CHANGE ITS RATES
AND CHARGES FOR NATURAL GAS
SERVICE TO NATURAL GAS CUSTOMERS
IN THE STATE OF IDAHO

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Case No. INT-G-16-02

DIRECT TESTIMONY OF HART GILCHRIST

FOR INTERMONTAIN GAS COMPANY

August 12, 2016

Gilchrist, Di 1
Intermountain Gas Company
I. INTRODUCTION 1
Q. Please state your name, title and business address. 2
A. My name is Hart Gilchrist. I am Vice President, Operations, for Intermountain
Gas Company. My business address is 555 South Cole Road, Boise, Idaho
83709.
Q. Mr. Gilchrist, would you please summarize your educational and professional 6
experience. 7
A. I have been working in the natural gas industry and at Intermountain Gas for 22
years, where I started as an Engineering Technician in the Boise District office. I
was named Vice President, Operations in July 2015. Prior to this role I have held
numerous positions in the operations department. In my current assignment, I am
responsible for corporate and field operations and engineering functions for the
Company. These activities include transmission and distribution integrity
management, corrosion, leak survey, damage prevention, gas measurement,
public awareness and installation and maintenance of natural gas facilities in our
distribution system.
I have bachelor’s degrees in finance and marketing from the University of 17
Idaho and an MBA from Boise State University. I serve on the United Way of
Treasure Valley board of directors, Boise State University College of Business
and Economics Advisory Board, College of Western Idaho Foundation Board,
American Gas Association Managing Committee, Northwest Gas Association
Board and Boise Chamber of Commerce Advisory Board.
Q. What is the purpose of your testimony in this docket? 23
Gilchrist, Di 2
Intermountain Gas Company
A. My testimony will cover several areas.
First, I will discuss the delivery chain involved in bringing natural gas from the
well-head to the consumer, and the role Intermountain plays in the last part, or
local distribution, of that delivery chain. Second, I will provide some detail on
certain operations and maintenance expenses of the Company operating as a local
gas distribution company (“LDC”). Third, I will explain the Company’s focus on 6
building and maintaining a safe and reliable natural gas distribution system and
the costs incurred in that endeavor. Fourth, I will explain Intermountain’s 8
infrastructure replacement program and spending and lay out a proposal for a
future program and regulatory case that would allow the Company to identify
parts of its distribution system that has aged or has been identified as needing
replacement per federal pipeline safety programs to the point where it needs to be
replaced in the near-term, and how Intermountain can recover our replacement
costs more quickly for a portion of this pipeline replacement.
II. GAS SUPPLY CHAIN 15
Q. Please describe Intermountain’s delivery chain. Where does Intermountain 16
acquire its natural gas and how is the cost of that wholesale commodity 17
passed through to customers of the Company?
A. First, it is important to distinguish the role Intermountain plays as an LDC, and
that it is not a vertically integrated utility. By that, I mean it does not own any
producing gas wells that are ultimately used to supply its retail customers in
Idaho. Instead, the Company contracts with a wholesale supplier to acquire the
gas needed to meet its regulatory obligation to provide service to its Idaho
Gilchrist, Di 3
Intermountain Gas Company
Customers. Currently, Intermountain has contracted with IGI Resources, Inc., a
wholly owned subsidiary of BP Energy (“IGI/BP”) to acquire wholesale gas on 2
behalf of Intermountain, and arrange, or contract, for transportation of that gas to
the Company’s various distribution systems in southern Idaho. That contacted-for
delivery occurs over an interstate pipeline system that is not owned by
Intermountain, but in the Company’s case, is owned by Williams-Northwest
Pipeline Company (“NW Pipeline”). Prices for wholesale gas acquired by IGI/BP
on behalf of Intermountain are market driven, while transportation costs paid to
NW Pipeline are at rate-of-return regulated prices set by FERC. Both gas
commodity costs and transportation costs are then passed through, dollar for
dollar, to Intermountain’s customers pursuant to the Company’s annual Purchased 11
Gas Adjustment (PGA) cost recovery filing.
Q. Please describe Intermountain’s gas supply chain.
A. Page 1 of Exhibit 3 is a simplified diagram of the gas supply chain from the gas
wellhead to the end consumer. As shown on this diagram, gas comes out of the
ground at the gas wellhead, which is independently owned, with the various wells
connected via a gathering system to a gas compressor station and gas processing
station. IGI/BP will acquire a gas supply on behalf of Intermountain from
producers/wholesalers who represent a wellhead owner. It does not matter to
Intermountain where the gas originates; it’s just a commodity to us. IGI then
contracts with one or more interstate pipeline owners to move the contracted-for
gas to a city gate or a farm tap, where Intermountain takes delivery of the
wholesale gas and distributes it to our customers.
Gilchrist, Di 4
Intermountain Gas Company
Q. Please describe what happens once Intermountain takes delivery of the 1
wholesale gas. 2
A. The Company takes delivery of gas at a variety of points on the NW Pipeline
system that roughly correspond with the various Idaho cities, towns and farms
served by Intermountain. Those multiple delivery points are the “Gas Station” box 5
as shown on Exhibit 3, Page 1. Downstream from the “Gas Station” box on Page
1 of Exhibit 3 is the portion of the diagram showing storage facilities, compressor
stations, distribution pipelines, and industrial, commercial and residential
consumers. All of these facilities and infrastructure are designed and built to
deliver gas supply to core market and non-interruptible industrial customers on
the coldest peak-day period. The storage facilities, or liquid natural gas (LNG)
facilities are an additional failsafe necessary to provide deliverability and
reliability on the coldest peak-day period. Peak-day is defined as the maximum
daily quantity of gas distributed through the Company’s system. In order to meet 14
peak-day demand, the Company has to design and build the distribution system
with enough capacity (or using correct pipe size and pressure blends) to meet this
demand, regardless of what the demand is on non-peak days. The Company
receives the gas at pressures between 500-800 psig and through a series of
pressure cuts (via regulators at city gates, district regulator stations and domestic
regulators) delivers gas to our customers between 20 psig and 4 oz.
Q. Where does Intermountain provide retail gas service in Idaho, and what is 21
the Company’s customer base. 22
Gilchrist, Di 5
Intermountain Gas Company
A Page 2 of Exhibit 3 shows a map of the Company’s service area in southern 1
Idaho. The Company’s current customer base consists of 302,790 residential
customers and 31,860 commercial customers.
III. OPERATIONS AND MAIINTENANCE OF PLANT AND 4
FACILITIES 5
Q. Please describe the Company’s operation centers in Idaho and elsewhere that 6
support customers in Idaho. 7
A. The Company has a general office, five (5) major operations centers with two (2)
satellite service centers serving Intermountain customers, as well as a customer
service center in Meridian. The general office, located in Boise, is made up of
Intermountain’s administrative staff. This staff includes Intermountain’s 11
executive team and employees that lead Intermountain’s safety, training, 12
operations, engineering, accounting, regulatory, human resources, cash
processing, marketing/public relations, information technology and geographic
information systems. Each of the five operations centers is made up of our
operations and service groups. These groups provide all field service activities,
operations and maintenance (pipeline safety compliance) activities, customer
acquisition activities and emergency response activities. These five operations
centers are located in Nampa, Boise, Twin Falls, Pocatello and Idaho Falls. The
two satellite service centers, located in Hailey and Soda Springs, respectively,
provide field service activities and emergency response activities in our more
remote areas. The MDU Resources’ customer service center, located in Meridian, 22
serves over a million customers in eight (8) states across 4 brands: Intermountain,
Gilchrist, Di 6
Intermountain Gas Company
Cascade Natural Gas, Montana-Dakota Utilities and Great Plains Natural Gas.
The 2010 addition of the customer service center has been an asset to Idaho’s 2
economy and Intermountain is fortunate that MDU Resources selected Idaho and
Meridian in particular to make this significant capital investment for its customer
service center.
Q. Could you please describe the effort and investment the Company has made 6
in information and technology systems? 7
A. Yes, but first let me set the stage for you. In 1985, Intermountain served less
than 100,000 customers with approximately 425 employees, compared to serving
approximately 330,000 customers today with 241 employees, plus shared services
employees. We have been able to achieve this significant reduction in customer-
to-employee ratio through several avenues: transformation of the personal
computer; operations mobile field solutions, including electronic field order
completion and leak survey; implementation of encoder receiver transmitters
(ERT’s) on customer meters; integrated geographic information system (GIS); 15
electronic pipeline safety compliance system that interfaces with GIS and;
electronic work management system. Each of these technology implementations
has allowed Intermountain to streamline work processes, reduce paperwork and
back-office activities and continue to maintain a safe, reliable distribution system.
Q. How have O&M costs historically been maintained, reduced or deferred in 20
the past? 21
A. One example, as referenced above related to ERT’s, pertains to the 2001-2002
implementation of the company’s automated meter reading (AMR) system. The
Gilchrist, Di 7
Intermountain Gas Company
AMR system included the installation of approximately 280,000 ERT’s on 1
customer meters and the implementation of three mobile collectors installed in
vehicles to capture monthly meter reads. Prior to the implementation of the AMR
system, Intermountain collected monthly customer meter reads manually, on foot,
using 27 meter reader staff. Upon completion of the AMR implementation, the
company is able to read the same amount of customer meters with 7
employees. Intermountain continues to read 330,000 customer meters today with
the same number of employees, thus deferring additional O&M costs of additional
employees since 2001.
IV. SAFETY 10
Q. Many of Intermountain’s operating expenses relate to the Company’s 11
commitment to both customer safety and employee safety. Please give us an 12
idea of the safety systems the Company has in place regarding customer 13
safety, and how that impact’s system operations. 14
A. Intermountain is committed to customer safety. As part of this commitment,
Intermountain has an extensive pipeline safety program, which will be discussed
later in this testimony as well as a dedicated staff of employees to address
customer needs and concerns as well as natural gas emergencies. The company’s 18
first responders are trained to assess, make safe and repair any abnormal operating
conditions on the distribution system. This group of employees is made up of
service technicians and construction crews. The company keeps employees in
these positions on stand-by 24 hours per day, seven days per week to allow for
quick response to customer needs, facility damages and outages. This is
Gilchrist, Di 8
Intermountain Gas Company
accomplished by investing in safety and ensuring a qualified workforce. All of
our operations employees go through a series of training modules covering all
aspects of their jobs and have to display competency through testing and hands-on
evaluations. This program is called Operator Qualification. Additionally, our
service technicians go through an extensive service technician apprentice program
which consists of classroom training as well as ride-a long’s with seasoned
employees. Service technicians cannot be on-call or respond to emergencies on
their own until the successful completion of the apprentice program which takes
one full year. All of these programs help ensure that the company provides a
qualified workforce that prudently operates the distribution system and provides a
safe system for our customers.
Q. You also mentioned employee safety as the second part of Intermountain’s 12
safety commitment. Please elaborate? 13
A. Intermountain’s employee safety goal is “Commitment to Zero”, evidencing a 14
drive towards zero vehicle accidents and zero employee injuries. As such, the
Company views safety as in investment, although in reality it is an operating
expense. As part of Intermountain’s Commitment to Zero the Company provides
all necessary Personal Protective Equipment (PPE) to its employees. This
includes the likes of hard hats, safety glasses, high visibility clothing, gloves,
safety toe footwear, etc. The Company also provides its employees with regular
safety training as well as defensive driving training specifically geared toward
zero accidents. Intermountain’s belief is that a serious commitment to and 22
Gilchrist, Di 9
Intermountain Gas Company
investment in safety will help to ensure that Intermountain’s employees go home 1
in the same condition they came to work in.
Q. What are some of the federal safety requirements that are driving the 3
Company’s maintenance costs? 4
A. Intermountain has several processes or systems in place that help ensure the safe
operation of our distribution system. Most of these are derived from federal
pipeline safety requirements that can be found in the Code of Federal Regulations,
Title 49, Part 192. Specifically, I will discuss the following areas: Leak Survey,
Corrosion, Atmospheric Corrosion, Public Awareness, Damage Prevention,
Regulator Station inspection and testing, Valve maintenance, Transmission
Integrity Management and Distribution Integrity Management. Intermountain
applies these processes to approximately 6,216 miles (32 million feet) of gas
mainline and approximately 350,000 service lines.
Q. Please explain the federal Leak Survey, Corrosion and Atmospheric 14
Corrosion requirements? 15
A. Leak Survey: Intermountain is required to leak survey all natural gas
distribution pipelines of its non-business districts every four (4) years and those in
business districts annually. The Company is required to survey all natural gas
transmission lines annually and if they fall in a Class 3 location (46 or more
buildings intended for human occupancy within 220 yards of the pipeline of any
continuous mile) have to be surveyed twice annually.
Corrosion: For all steel natural gas pipelines, Intermountain must protect
them against external corrosion using the following means: (1) install pipelines
Gilchrist, Di 10
Intermountain Gas Company
with an external protective coating; (2) have a cathodic protection system
installed which is designed to protect the pipe; typically this “system” is a 2
combination of anodes and rectifiers. These systems have to be annually
inspected to insure they are functioning properly to protect the steel pipelines
against external corrosion. This is done by measuring the “pipe-to-soil” interface
of cathodically protected and isolated pipe districts, regardless of the use of
anodes or rectifiers. In addition, rectifiers are inspected every two (2) months to
ensure they are properly protecting the steel pipe.
Atmospheric Corrosion: All pipe and components related to the natural
gas pipeline system that are above ground and exposed to the atmosphere are
inspected every three (3) years to ensure the atmosphere is not causing any
deterioration to our system.
Q. Please explain the federal Public Awareness, Damage Prevention, Regulator 13
Station inspection and testing requirements. 14
A. Public Awareness: Intermountain follows the American Petroleum
Institute (API) Recommended Practice (RP) 1162 which is incorporated by
reference into Part 192. Activities surrounding public awareness include
educating the public, appropriate government organizations and persons engaged
in excavation activities on the following: (1) use of the Idaho one call (Digline)
system prior to excavation; (2) possible hazards associated with unintended
releases from a gas pipeline facility; (3) physical indications that such a release
may have occurred; (4) steps that should be taken for public safety in the event of
a gas pipeline release; and (5) procedures for reporting such an event.
Gilchrist, Di 11
Intermountain Gas Company
Damage Prevention: The Company engages in location of gas facilities
prior to excavation work (when notified by the excavator) through its contractual
relationship with Digline of Idaho. Excavators can call Digline at no charge to
the excavator. Digline then contacts a Company representative who locates
Intermountain gas facilities within 48 hours of the request. Additionally,
Company representatives regularly meet with excavators to educate them about
the importance of safe excavation.
Regulator Station inspection and testing: The Company inspects each
regulator station and its equipment on an annual basis to ensure it is in good
mechanical condition, has adequate capacity and reliability, is set to control,
increase or relieve pressure, and is properly installed and protected from dirt,
liquids, and other conditions that could prevent proper operations. Across
Intermountain’s distribution system, the Company has 664 regulator stations that
receive this annual maintenance.
Valve Maintenance: Each Company valve that is either on a transmission
class pipeline or which may be used for the safe isolation of Intermountain’s 16
system is required to be and is inspected annually. For transmission class valves
this includes partially operating the valve; for the remaining valves this includes
checking and servicing the valves. The Company has 5,115 valves that receive
this annual maintenance.
Q. Finally, what are the federal safety requirements related to Transmission 21
Integrity Management and Distribution Integrity Management? 22
Gilchrist, Di 12
Intermountain Gas Company
A. Transmission Integrity Management Plan (TIMP): The Company
implements the TIMP on any segment of transmission pipeline that falls in a High
Consequence Area (HCA). An HCA is an area or circle along the transmission
pipeline containing either 20 or more buildings intended for human occupancy, or
an otherwise identified site. The company has 290 miles of transmission pipeline
and 14 of those miles are in an HCA. There are 42 specific pipe segments that fall
under the TIMP. Federal TIMP requirements subjects covered pipelines in TIMP
areas to a process of threat identification, risk assessment, baseline assessment,
repair/maintenance, preventative and mitigative measures, quality control,
performance management and management of change, followed by reassessment
of each segment of covered pipeline every seven years.
Distribution Integrity Management Plan (DIMP): The federal DIMP
safety requirements consists of seven elements: 1) Demonstrate knowledge of
distribution system; 2) Identify threats; 3) Evaluate and prioritize risk; 4) Identify
and implement measures to address risk; 5) Measure performance, monitor results
and evaluate effectiveness; 6) Perform periodic evaluation and improvement; and
7) Report results. The Company implements the DIMP on any segment of
distribution line in the company territory; in other words, the entire distribution
system that is within the company’s jurisdiction.
Q. Please describe the O&M costs related to these safety processes and 20
programs in 2015, as well as how they have trended historically and how the 21
company expects them to trend in the future. 22
Gilchrist, Di 13
Intermountain Gas Company
A. Intermountain’s O&M costs related to District Operations each year can be 1
attributed to the safety and maintenance of our pipeline system. These are costs
associated with our field employees, tools and equipment, which are responsible
for carrying out the safety programs and processes previously discussed. In 2015,
the District Operations O&M cost were $17.825 million. While these costs have
certainly increased over the last 30 years due to salary increases, cost of living
increases, etc., the company has been able to control these costs remarkably
well. For example, in 2011, these same O&M costs were$16.333 million. In the
future, the expectation is that O&M costs will continue to rise, but at a more
accelerated rate due to recent and upcoming pipeline safety regulations, notably
DIMP and associated aging infrastructure replacements as referenced above, as
well as pending transmission pipeline regulation, quality assurance regulation and
pipeline safety management system regulation, to name a few.
V. PIPELINE REPLACEMENT 14
Q. The fourth point you wished to discuss was the Company’s investment in gas 15
pipeline infrastructure. Could you give an overview of the Company’s 16
commitment to and spending on infrastructure replacement?
A. Intermountain’s annual capital requirements has steadily increased from 18
approximately $ 17 million in 2008, to approximately $42 million in 2015.
Capital spending of $43.5 million and $42 million is planned for the years 2016
and 2017 respectively. A significant portion of this capital spending relates to
infrastructure replacement
Gilchrist, Di 14
Intermountain Gas Company
Q Please describe Intermountain’s ongoing program for managing and 1
replacing its natural gas pipe? 2
A. The Company is continuing its pipeline integrity management program to
systematically replace select portions of pipe in its natural gas distribution system
in Idaho. The pipeline integrity management program is a risk based replacement
program that assesses risk based on a pipe segments age, material, operating
pressure, leak history, damage history, etc. Intermountain began replacing
infrastructure in 2015 under the Distribution Pipeline Integrity rule that became
effective in 2013. Since 2005, Intermountain has been conducting pipeline
assessments on our transmission pipelines, but have only had to make minor
repairs. In 2015 under the company’s DIMP, approximately 30,000 feet of plastic 11
pipe was removed and replaced. The company plans to remove another 22,000 in
2016 and 25,000 in 2017. The company will continue to model the distribution
system and schedule replacement of pipe as determined by the risk model and
available monetary resources.
Q. Please describe Intermountain’s protocol for pipeline replacement? 16
A. Intermountain uses its TIMP and DIMP as drivers for pipeline replacement.
These two plans both use a risk-based approach to assessing pipelines and
determining which segments of pipe need repair or replacement. Once pipe
segments have been identified for replacement, the company assesses the capital
requirements for replacement compared to capital available in a given year. This
then determines how much replacement can be achieved in a given year.
Gilchrist, Di 15
Intermountain Gas Company
Q. Do you believe the current pace for pipeline replacement and the system for 1
rate basing that investment is adequate, or is there a potentially better 2
regulatory model for more expeditiously replacing pipe that is at or near the 3
end of its useful life?
A. I believe a better way to more quickly fund and replace pipeline infrastructure
would be through a pipeline infrastructure cost recovery mechanism (ICRM) that
would allow Intermountain to accelerate its spending in this area, and to more
timely recover those costs that are incurred to promote the safety and reliability of
Intermountain’s distribution system.
Q. Is Intermountain proposing a pipeline ICRM in this case? 10
A. No. However, the Company intends to follow this case with an ICRM case filing.
Q. Why is the eventual establishment of a pipeline ICRM important to 12
Intermountain? 13
A. There are many portions of Intermountain’s system that need to considered for
replacement based on material, age, leak history, excavation activity, etc.
Intermountain is obligated to provide safe, reliable service to its customers, and to
that end, Intermountain is using a systematic approach to identify the elevated risk
pipe segments and replace those segments first. A potential problem for the
Company is that the costs incurred for replacing pipe has no new revenue
associated with those costs. In other words, performing these system
improvements increases costs and reduces earnings.
Q. How has Intermountain been able to incur these costs without rate recovery 22
to date? 23
Gilchrist, Di 16
Intermountain Gas Company
A. Over the past few years Intermountain has primarily funded its pipeline
improvement program through operating efficiency improvements, many of them
resulting from the MDU Resources’ acquisition of Intermountain. However, rate
base and other cost increases have reached the point that Intermountain can no
longer fund this large a capital investment from additional operating efficiencies.
Q. What are the benefits to customers and the Company if a pipeline cost 6
recovery mechanism were established and approved by the Commission? 7
A. In addition to updating the pipeline system to continue operating a safe and
reliable system, the mechanism will potentially reduce the need for future rate
cases. Without an ICRM, Intermountain will likely be in a position where it will
need to file subsequent rate cases for cost recovery of this single and significant
capital spending program, until such time as the Company’s modeling indicates 12
an acceptable level of risk profile is attained. An ICRM will provide an incentive
for the Company to control other costs between rate cases and reduce the need for
incurring additional rate case costs.
Q. Can you please describe how such a mechanism would work? 16
A. Yes. Intermountain would annually file for recovery of pipeline replacement
investment incurred over a set period of time, likely a 12 month period. It would
also seem that the timing of the filing might best coincide with Intermountain’s 19
annual PGA filings in August, with an effective date of October 1. The period of
recovery for the prior year’s investment would be a matter for determination by 21
the Commission.
Gilchrist, Di 17
Intermountain Gas Company
Q. Do other MDU Resources’ Companies and other gas utilities in the northwest 1
currently have a similar mechanism in place in other states? 2
A. Yes. Cascade Natural Gas is operating under similar programs in both Oregon
and Washington where it files for recovery of pipeline replacement costs under a
pipeline CRM. In addition, Northwest Natural Gas currently has a System
Integrity Program, which was adopted to encourage Northwest Natural to replace
bare steel and cast iron pipe. Cascade’s Washington cost recovery mechanism was
based on Northwest Natural mechanism in place in Oregon.
Q. Do you anticipate that there would be O&M savings associated with the 9
replacement of some of the aging infrastructure? 10
A. As a general rule, there will be less O&M costs associated with new
infrastructure, as opposed to aging or obsolete pipelines. On a net basis however,
Intermountain will continue to see overall increased O&M costs to maintain a
system, some of which is now approaching 60 years in age. It is important for the
Company to systematically reinvest and upgrade a portion of its pipeline system
every year, in addition to making the investments needed or required to meet
reliability requirements. While such systematic reinvestment works to slow the
growth of annual O&M costs, it does not result in a year to year reduction in
overall O&M costs.
Q. Does this conclude your direct testimony? 20
A. Yes. Thank you.