20230609Application_Exhibits.pdf

June 9, 2023 Ms. Jan Noriyuki Commission Secretary
Idaho Public Utilities Commission P.O. Box 83720 Boise, ID 83720-0074
RE: Case No. INT-G-23-03 Dear Ms. Noriyuki: Attached for consideration by this Commission is an electronic submission of Intermountain Gas
Company’s Application for Authority to Update the Renewable Natural Gas Facilitation Plan. If you should have any questions regarding the attached, please don’t hesitate to contact me at [phone].
Sincerely,

Lori A. Blattner Director, Regulatory Affairs Intermountain Gas Company
Enclosure
cc: Mark Chiles Preston Carter

RECEIVED
2023 JUNE 9, 2023 10:44AM
IDAHO PUBLIC
UTILITIES COMMISSION

INTERMOUNTAIN GAS COMPANY
CASE NO. INT-G-23-03

APPLICATION
AND
EXHIBITS

In the Matter of the Application of INTERMOUNTAIN GAS COMPANY
for Authority to Update the Renewable Natural Gas Facilitation Plan

INTERMOUNTAIN GAS COMPANY’S APPLICATION - 2

Preston N. Carter, ISB No. 8462
Morgan D. Goodin, ISB No. 11184
Givens Pursley LLP
601 W. Bannock St.
Boise, Idaho 83702
Telephone: [phone]
Attorneys for Intermountain Gas Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

In the Matter of the Application of
INTERMOUNTAIN GAS COMPANY
for Authority to Update the Renewable
Natural Gas Facilitation Plan

Case No. INT-G-23-03

APPLICATION

Intermountain Gas Company (“Intermountain” or “Company”), a subsidiary of MDU
Resources Group, Inc. with general offices located at 555 South Cole Road, Boise, Idaho, pursuant
to the Rules of Procedure of the Idaho Public Utilities Commission (“Commission”), requests
authority, pursuant to Idaho Code Sections 61-307 and 61-622, to update its Renewable Natural Gas
(“RNG”) Facilitation Plan with the following three changes: 1) introduce a Maintenance Fee for
RNG producers that require use of export facilities to physically move natural gas onto an interstate
pipeline; 2) establish a calculation methodology for the monthly Access Fee; and 3) make clear that
the Company’s Tariff Rate Schedule T-3 Interruptible Distribution Transportation Service
(“Schedule T-3”) will be applicable to the transportation of RNG on Intermountain's distribution
system to a point of interconnection with Northwest Pipeline LLC (“Northwest Pipeline”).
Please address communications regarding this Application to:
Lori A. Blattner
Director – Regulatory Affairs
Intermountain Gas Company
Post Office Box 7608
Boise, Idaho 83707
[e-mail]
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 3

and
Preston N. Carter
Morgan D. Goodin
Givens Pursley LLP
601 W. Bannock St.
Boise, Idaho 83702
[e-mail]
[e-mail]
[e-mail]

In support of this Application, Intermountain alleges and states as follows:
I. INTRODUCTION
Intermountain is a gas utility, subject to the jurisdiction of the Commission, engaged in the
sale of and distribution of natural gas within the State of Idaho under authority of Commission
Certificate No. 219, issued December 2, 1955, as amended and supplemented by Order No. 6564,
dated October 3, 1962.
Intermountain provides natural gas service to the following Idaho communities and counties
and adjoining areas:
Ada County - Boise, Eagle, Garden City, Kuna, Meridian, and Star;
Bannock County - Arimo, Chubbuck, Inkom, Lava Hot Springs, McCammon, and Pocatello;
Bear Lake County - Georgetown, and Montpelier;
Bingham County - Aberdeen, Basalt, Blackfoot, Firth, Fort Hall, Moreland/Riverside, and Shelley;
Blaine County - Bellevue, Hailey, Ketchum, and Sun Valley;
Bonneville County - Ammon, Idaho Falls, Iona, and Ucon;
Canyon County - Caldwell, Greenleaf, Middleton, Nampa, Parma, and Wilder;
Caribou County - Bancroft, Grace, and Soda Springs;
Cassia County - Burley, Declo, Malta, and Raft River;
Elmore County - Glenns Ferry, Hammett, and Mountain Home;
Fremont County - Parker, and St. Anthony;
Gem County - Emmett;
Gooding County - Bliss, Gooding, and Wendell;
Jefferson County - Lewisville, Menan, Rigby, and Ririe;
Jerome County - Jerome;
Lincoln County - Shoshone;
Madison County - Rexburg, and Sugar City;
Minidoka County - Heyburn, Paul, and Rupert;
Owyhee County - Bruneau, Marsing, and Homedale;
Payette County - Fruitland, New Plymouth, and Payette;
Power County - American Falls;
Twin Falls County - Buhl, Filer, Hansen, Kimberly, Murtaugh, and Twin Falls;
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 4

Washington County - Weiser.
Intermountain's properties in these locations include transmission pipelines, liquefied
natural gas storage facilities, compressor stations, distribution mains, services, meters and
regulators, and general plant and equipment. Intermountain is a wholly-owned subsidiary of MDU
Resources Group, Inc. (“MDU”).
II. BACKGROUND
Renewable Natural Gas is the term used to describe pipeline-quality biomethane produced
from biomass. Common sources of biomass used in the production of RNG are livestock operations,
landfills, and wastewater treatment facilities. It is interchangeable with natural gas, carbon neutral,
and fully compatible with the U.S. pipeline infrastructure. It can be used in homes and businesses, in
manufacturing and heavy industries, for electricity production, and as an alternative fuel for
transportation.
From a greenhouse gas emissions perspective, RNG has the potential to provide significant
benefits. RNG production captures methane from animal waste and other biomass sources that
otherwise would directly enter Earth’s atmosphere. When it is eventually combusted, the RNG
releases significantly fewer greenhouse gas emissions than if the methane had been released directly
into the atmosphere.
RNG also has the potential to provide a valuable new revenue stream for Idaho farmers. It
may allow livestock operations to convert waste into a beneficial supplementary revenue source.
The Idaho Department of Agriculture reports that Idaho is the fourth largest milk producing state in
the nation. With the large number of dairies, the state has seen increased activity around dairy RNG
projects over the past year. As neighboring states implement or look to implement policies that
encourage or mandate the use of renewable sources of energy, including RNG, Idaho is in a prime
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 5

location with the necessary biomass to produce and transport a significant amount of RNG to these
markets.
On May 4, 2020, the Company filed an application requesting authority to facilitate
renewable natural gas access in Case No. INT-G-20-03. In its application, the Company proposed
an RNG Facilitation Plan that would guide all future distribution system access by RNG producers.
The Facilitation Plan incorporated a monthly fee for access to Intermountain’s distribution system.
The monthly fee included a Maintenance Fee and an Access Fee. The Maintenance Fee covered the
Operation and Maintenance (“O&M”) expenses required to operate and maintain the facilities that
connect the RNG plant to the Intermountain distribution system. This fee would be updated
annually. The proposed Access Fee provided a return to the Company for granting access to its
distribution system and would be recorded as non-utility revenue. Among other things, the intent of
Case No. INT-G-20-03 was to establish fees and procedures to ensure utility customers were
completely insulated from all impacts of RNG production. The Commission approved
Intermountain’s RNG Facilitation Plan in Order No. 34693.
After the RNG Facilitation Plan was approved and implemented, Intermountain received
requests from potential RNG producers to access interstate markets though Northwest Pipeline, the
only interstate pipeline connected to Intermountain's distribution system. A new compressor station
and other related facilities (“Export Facilities”) will need to be installed to accommodate the
transportation of excess RNG to Northwest Pipeline. In addition, Northwest Pipeline may need to
construct a new interconnection with Intermountain's distribution system. This filing seeks to
expand upon the current RNG Facilitation Plan to allow for the transportation of RNG onto the
interstate pipeline, while continuing to ensure that utility customers are insulated from all impacts of
RNG production.

INTERMOUNTAIN GAS COMPANY’S APPLICATION - 6

III. TRADITIONAL NATURAL GAS SERVICE
Under the updated RNG Facilitation Plan proposed in this Application, gas delivered to an
RNG producer to operate its facilities will continue to be billed at Intermountain’s standard tariffed
rates. A standard customer agreement will be executed with the RNG producer. The monthly billing
for an RNG facility will be the same as any other Intermountain customer based upon the tariff
selected.
IV. FEDERAL ENERGY REGULATORY COMMISSION
Currently, when new RNG facilities connect to Intermountain’s system, the RNG is
delivered to a point on the distribution system and consumed in Idaho. However, Intermountain
has received requests from potential RNG producers that would result in the RNG being
transported to a new point of interconnection with Northwest Pipeline. In order to provide this
service, Intermountain will file an application with the Federal Energy Regulatory Commission
(“FERC”) to authorize the transportation of RNG in interstate commerce. The filing with FERC
would occur subsequent to a final Order being issued in this case. The FERC filing will be
limited to transportation of RNG and will not subject the entirety of Intermountain’s facilities to
FERC jurisdiction.
V. RNG FACILITATION MAINTENANCE FEES
Intermountain proposes to maintain the existing monthly Maintenance Fee that covers
expenses incurred by Intermountain to provide service to RNG producers. In addition, the Company
proposes a new Export Facility Maintenance Fee (“EFMF”). The EFMF would apply only to
producers located in areas within Intermountain's distribution system where retail load is not large
enough to absorb the produced RNG; without the export facilities, Intermountain would not be able
to accept excess RNG because it would not have the capacity to transport it. The RNG agreements
will continue to include a clause to cover Startup and Extraordinary O&M expenses.
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 7

Maintenance Fees. The Maintenance Fee covers the expenses incurred by Intermountain to
provide service to RNG producers on a monthly basis. The current monthly Maintenance Fee is
$2,300 based on the average of monthly costs incurred to serve all RNG producers from October 1,
2022, through September 30, 2023.1 The current Maintenance Fee does not include O&M costs
related to Export Facilities.
Export Facility Maintenance Fee. The Company proposes the addition of a separate Export
Facility Maintenance Fee for RNG facilities whose RNG cannot be consumed by Intermountain’s
existing customers and therefore must be injected into the interstate pipeline system. The EFMF
would cover expenses incurred by Intermountain to operate and maintain the compressor station(s)
and any other facilities required to inject produced RNG into Northwest Pipeline. At this time,
Intermountain estimates the monthly EFMF will be approximately $5,400 based on the Company’s
experience in operating compressor stations.
Startup and Extraordinary O&M Expenses. In the event of startup O&M expenses or other
out of the ordinary O&M expense at an RNG production facility, the producer is billed for the
actual additional expenses incurred by Intermountain. This protects other RNG producers from
being required to share in higher startup costs or other extraordinary expenses incurred by a specific
producer. The Company is proposing no change to this provision.
VI. ANNUAL MAINTENANCE FEE UPDATE
The monthly Maintenance Fee is updated on an annual basis by Intermountain. The expense
incurred to provide RNG access to the Company’s system changes over time. Adjusting the
monthly fee annually ensures it accurately reflects the true cost of providing service to RNG
producers. Intermountain calculates the new fee each September based on actual expenses for the

1 See the Company’s Annual Maintenance Fee Update for Case No. INT-G-20-03 submitted September 23, 2022.
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 8

September 1st through August 31st time-period. The new fee takes effect October 1st of each year to
align with Intermountain’s Purchase Gas Adjustment mechanism price changes.
The annual update consists of two parts: 1) an update to the monthly Maintenance Fee, and
2) a Maintenance Fee Adjustment.
Maintenance Fee Update. Actual RNG expenses are separately tracked and booked as a
non-utility expense into an RNG business unit. The actual RNG expenses for the previous 12-month
period are used to compute a new monthly fee that reflects the actual expenses incurred over the
previous year. Intermountain sums all the actual expenses from September 1st through August 31st
and divides the total by 12. The resulting Maintenance Fee for the new year is effective on October
1st.
Maintenance Fee Adjustment. Intermountain also reviews the actual expenses incurred to
serve RNG producers compared with the revenue generated by the monthly Maintenance Fee for
the same 12-month period. The difference between revenue and expenses, if any, is the Adjustment
Balance. The Adjustment Balance is divided by 12 to arrive at the Maintenance Fee Adjustment.
The monthly Maintenance Fee Adjustment will be added to or subtracted from the new
monthly Maintenance Fee to arrive at the Maintenance Fee to be charged to each RNG producer for
the 12-months starting on October 1st each year.
Export Facility Maintenance Fee Update and Adjustment. Consistent with the current
treatment of the Maintenance Fee update, Intermountain proposes to update the EFMF each year
using actual compressor station O&M expenses for the previous 12-month period.
Intermountain also proposes to align with the current treatment of the Maintenance Fee
Adjustment and update the EFMF each year using actual compressor station expenses for the
previous 12-month period. The Company proposes to review the actual expenses incurred to operate
Export Facilities compared with the revenue generated by the monthly EFMF for the same 12-
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 9

month period to derive the difference between the revenue and the expenses. Any applicable
balance would be divided by 12 to arrive at the EFMF Adjustment.
The monthly EFMF Adjustment will be added to or subtracted from the new monthly
EFMF to arrive at the EFMF to be charged to applicable RNG producers for the 12-months starting
on October 1st each year.
VII. ACCESS FEE
Case No. INT-G-20-03 established that the monthly fee for RNG would include an Access
Fee component. However, the case did not establish a methodology or clearly state the Access Fee.
In this Application, the Company proposes to establish a methodology to determine the Access Fee
amount.
The intent of the Access Fee is to provide Intermountain a return for providing RNG
producers access to Intermountain's distribution system. The Company proposes the calculation of a
risk premium using a methodology focused on Return on Equity (“ROE”) values as the basis for the
Access Fee. FERC released new policies for determining an ROE in 2020.2 FERC’s revised policy
for natural gas pipelines utilizes the Discounted Cash Flow and Capital Asset Pricing Model
methodologies to calculate the ROE, which is a disparate approach from the utility ROE method.
The Company’s proposed methodology for determining the Access Fee is to compare the difference
between the ROE per the FERC methodology and the ROE from a utility ROE method. The
difference is the Risk Premium percentage. The Risk Premium is then multiplied by the average
cost of an RNG facility to determine the Risk Factor amount. The Risk Factor amount is then
grossed-up for any applicable charges, if any, to determine the Access Charge. As shown in Exhibit
1, the method generates a proposed Access Charge of $8,000 per month, which is the same amount

2 See FERC Docket No. PL19-4-000, issued May 21, 2020.
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 10

as the current Access Charge being assessed to existing RNG facilities. Intermountain utilized the
9.5 percent ROE from the Stipulation and Settlement of its current general rate case3 for the utility
ROE method and an ROE from a recent FERC Staff testimony on March 3, 2023, for the FERC
methodology ROE.4 The Company has included the FERC Staff testimony as Exhibit 2.
VIII. BIOGAS STANDARDS
The renewable natural gas delivered to Intermountain’s system must meet the Company’s
biogas standards outlined in Exhibit 3. The biogas standards ensure the renewable natural gas
delivered to the Company’s system achieves the same quality as the traditional natural gas
provided by Intermountain.
IX. COMMISSION FEES
For the purposes of computing Intermountain’s proportionate assessment of Commission
Fees, all revenues resulting from the RNG Facilitation Plan are included in Intermountain’s gross
operating revenues.
X. RATE SCHEDULE T-3 RATES
As mentioned in Section II, the Company has received requests from potential RNG
producers that would result in some or all of the produced RNG being transported to a new point
of interconnection with Northwest Pipeline. The RNG utilizes the Company’s distribution
facilities until it interconnects with Northwest Pipeline. A tariffed distribution rate is paid by the
end use customer for any RNG that is consumed on Intermountain’s system. However, the
existing RNG Facilitation Plan does not include provisions that allow Intermountain to charge
RNG producers a tariffed rate for the use of the Company’s system to transport RNG to a point
of interconnection with Northwest Pipeline.

3 See Stipulation and Settlement submitted May 4, 2023, Case No. INT-G-22-07.
4 See FERC Docket No. RP22-1033-000, FERC Staff Witness Alexander Gill, page 7.
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 11

To hold utility customers financially harmless, Intermountain proposes updating its Rate
Schedule T-3 to be applicable to RNG producers. Gas produced by the RNG facility that is
exported to Northwest Pipeline will be assessed Rate Schedule T-3 Monthly Rates. Revenue
recovered from RNG producers specific to Schedule T-3 rates will be treated as an offsetting
revenue credit in the Company’s next general rate case. The Rate Schedule T-3 included with
this filing is provided as an example for reference purposes. The Company concurrently has
submitted updated tariff schedules as a result of a settlement agreement in its general rate case.5
The Company proposes to update Rate Schedule T-3 with the changes proposed in this case after
a final order is received in the general rate case.
XI. UTILITY CUSTOMER FINANCIAL IMPACT PROTECTION
The Company’s intent is for utility customers to be insulated from the service extended to
RNG producers. RNG producers will continue to pay for all startup costs associated with RNG
projects including but not limited to permitting, engineering drawings, specifications, surveying,
and property research. The producer will also continue to pay for the cost of all access related
infrastructure and facilities upfront. The capital costs related to an RNG production project are
included in rate base, which is then equally offset with a Contribution In Aid of Construction
(“CIAC”) payment from the RNG producer. The additional monthly expenses incurred by
Intermountain to provide on-going service to RNG producers are recovered in the monthly
Maintenance Fees described above. Intermountain’s shareholders assume all financial risks of
providing access to the Company’s system for RNG producers.

5 See Case No. INT-G-22-07.
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 12

XII. INCOME TAX GROSS UP
In Case No. INT-G-23-03, the Commission issued a limited waiver to Order No. 21933,
which prohibits Intermountain from grossing up CIACs to cover the additional income tax
generated by the CIAC payment.6 To ensure there is no financial impact to utility customers
from the RNG projects, Intermountain grosses up the RNG projects to account for the additional
income tax the CIAC revenue from RNG projects incurs. The income tax gross up is booked as
utility revenue to offset the additional income taxes and ensure there is no financial impact on
utility customers. Intermountain proposes that this treatment be continued and that it extend to
export facilities required for the injection of RNG into Northwest Pipeline.
XIII. SYSTEM SAFETY PROTECTION
All RNG agreements include safety provisions to protect the safety and reliability of service
for utility customers. Safety requirements include: a) minimum/maximum daily and hourly flow,
b) minimum/maximum delivery pressure, operating pressure, and maximum allowable operating
pressure, c) required installation of regulation, odorization, pressure relief, control valve equipment,
and a gas chromatography system, d) biomethane quality specifications, e) required gas quality
testing and monitoring, f) any other provisions Intermountain may deem necessary to protect the
safety and reliability of its system. A clause is also incorporated in the agreements to specify that
Intermountain will not be under any obligation to take the gas produced by an RNG facility if the
Company’s distribution system is at maximum capacity.
XIV. EXISTING PRODUCERS
The proposed changes will not impact existing RNG producers. Letters outlining the
proposed changes to the Company’s RNG Facilitation Plan will be sent to all RNG Producers

6 See Order No. 34693. The Commission authorized Intermountain to gross up each CIAC payment from RNG
producers to cover the income tax generated by the CIAC payment.
INTERMOUNTAIN GAS COMPANY’S APPLICATION - 13

currently contracting for the service. The proposal will also not impact existing T-3 Transportation
customers. With the proposed changes to the T-3 tariff, however, Intermountain will send a letter to
all T-3 Transportation customers explaining the proposed tariff revisions. Finally, a press release
has been sent to daily and weekly newspapers, and major radio and television stations in
Intermountain’s service area. The customer letters and press release are included as attachments.
XV. MODIFIED PROCEDURE
Intermountain requests that this matter be handled under modified procedure pursuant to
Rules 201-204 of the Commission’s Rules of Procedure. Intermountain stands ready for immediate
consideration of this matter.
XVI. REQUEST FOR RELIEF
Intermountain respectfully petitions the Idaho Public Utilities Commission as follows:
a. That the proposed changes to the Company’s Renewable Natural Gas Facilitation Plan
as described herein be approved without suspension and made effective no later than
July 1, 2023,
b. That this Application be heard and acted upon without hearing under modified procedure,
and
c. For such other relief as this Commission may determine proper.
DATED: June 9, 2023.
INTERMOUNTAIN GAS COMPANY GIVENS PURSLEY LLP

By By
Lori A. Blattner Preston N. Carter
Director Regulatory Affairs Attorney for Intermountain Gas Company

EXHIBIT NO. 1

CASE NO. INT-G-23-03

INTERMOUNTAIN GAS COMPANY

Access Charge Calculation
(1 page)
Line 
No.Description Amount
(a)(b)
1 Base Return on Equity 9.50%(1)
2 Return on Equity per FERC 10.01%(2)
3 Risk Premium % 0.50% Rounded
4 Average Cost of RNG Facility 1,600,000$        
5 Risk Factor $ 8,000$                
6 Gross Up Factor 1
7 Access Charge 8,000$                Rounded
Notes
(2)See Exhibit No. 2
Intermountain Gas Company
Access Charge Calculation
(1)See Stipulation and Settlement submitted May 4, 2023, Case No.
INT‐G‐22‐07
Exhibit No. 1 Case No. INT-G-23-03 Intermountain Gas Company Page 1 of 1

EXHIBIT NO. 2

CASE NO. INT-G-23-03

INTERMOUNTAIN GAS COMPANY

FERC Staff Testimony
(51 pages)
EXHIBIT S-0037
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 1 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page i of i

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Northern Natural Gas Company ) Docket No. RP22-1033-000

Summary of the
Prepared Answering Testimony of
Alexander Gill
Witness for the Trial Staff of the
Federal Energy Regulatory Commission

Dr. Gill is an Economist in the Federal Energy Regulatory Commission’s
(Commission) Office of Administrative Litigation. The purpose of Dr. Gill’s prepared
answering testimony is to establish the appropriate return on equity, capital structure, and
cost of debt for ratemaking purposes for Northern Natural Gas Company (Northern). Dr.
Gill recommends a return on equity of 10.01 percent, a capital structure consisting of
64.21 percent equity and 35.79 percent debt, and a cost of debt of 4.15 percent. The
recommended rate of return on equity is based on Dr. Gill’s conclusion that Northern
faces lower risk than the member of the proxy group and other natural gas pipelines.

In Section II of his testimony, Dr. Gill provides an overview of the proceeding and
Northern’s pipeline system. In Section III, Dr. Gill details his return on equity
calculations completed in adherence to current Commission policy. In Section IV, Dr.
Gill explains his reasoning for concluding that Northern is lower-than-average risk.
Sections V and VI present Northern’s capital structure and cost of debt, respectively,
which are eligible under Commission policy to use for ratemaking purposes. Section VII
combines the return on equity, cost of debt, and capital structure recommendations in an
overall after-tax weighted average cost of capital of 7.91 percent. In Section VIII, Dr.
Gill responds to Northern witnesses’ testimony regarding return on equity and Northern’s
risk. Section IX concludes.

Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 2 of 51
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 3 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037

TABLE OF CONTENTS
I. INTRODUCTION .......................................................................................................... 1
II. OVERVIEW ................................................................................................................... 4
III. ROE .............................................................................................................................. 7
A. SUMMARY AND RECOMMENDED ROE ............................................................... 7
B. PROXY GROUP SELECTION ..................................................................................... 7
C. APPLICATION OF THE COMMISSION’S TWO-STEP DCF MODEL .................. 12
D. APPLICATION OF THE COMMISSION’S CAPM APPROACH ............................ 16
E. CAPM ANALYSIS USING BLOOMBERG BETAS ................................................. 18
F. CAPM ANALYSIS USING VALUE LINE GROWTH RATES IN THE ONE-STEP
DCF MODEL .................................................................................................................... 19
G. INDICATED ZONE OF REASONABLENESS FOR NORTHERN’S ROE ............. 20
IV. NORTHERN’S RELATIVE RISK ............................................................................ 21
V. CAPITAL STRUCTURE ............................................................................................ 36
VI. COST OF LONG-TERM DEBT ................................................................................ 39
VII. AFTER-TAX WEIGHTED AVERAGE COST OF CAPITAL ............................... 40
VIII. RESPONSES TO NORTHERN’S TESTIMONY ................................................... 41
A. ROE CALCULATIONS ......................................................................................... 41
B. RISK ........................................................................................................................ 43
IX. CONCLUSION ........................................................................................................... 44
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 4 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Northern Natural Gas Company ) Docket No. RP22-1033-000

Prepared Answering Testimony of
Alexander J. Gill
Witness for the Trial Staff of the
Federal Energy Regulatory Commission
I. INTRODUCTION

Q. Please state your name and business address. 1
A. My name is Alexander Gill. My business address is 888 First Street, NE, 2
Washington, D.C. 20426. 3
Q. By whom are you employed and in what capacity? 4
A. I am employed by the Federal Energy Regulatory Commission (FERC or 5
Commission) as an Economist in the Office of Administrative Litigation (OAL). 6
Q. Please describe your educational background and experience. 7
A. In May 2005, I received a Bachelor of Science degree summa cum laude in 8
Economics and Political Economy from Tulane University in New Orleans, LA. 9
From 2005 to 2008, I was employed by JP Morgan Chase Bank, N.A. as a 10
commercial mortgage credit analyst. From 2008 to 2009, I was employed by 11
Trimont Real Estate Advisors, LLC as a special servicer of commercial 12
mortgages. Both positions were based in Atlanta, GA. In December 2012, I 13
received a master’s degree in Economics from North Carolina State University in 14
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 5 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 2 of 45

Raleigh, NC. From 2014 to 2015, I was a fellow at George Mason University in 1
Fairfax, VA and an adjunct instructor at American University in Washington, 2
D.C., where I taught a graduate course in economics. From 2015 to 2019, I taught 3
finance and economics at St. Lawrence University in Canton, NY. In August 4
2019, I received a PhD in Economics from North Carolina State University. In 5
March 2020, I began employment at the Commission as an Economist in OAL, 6
where I have analyzed cost of capital issues, including determining the appropriate 7
rate of return on equity for natural gas and electricity transmission providers, as 8
well as oil pipeline market power issues. 9
Q. Have you previously testified before the Commission? 10
A. Yes, I have provided testimony to the Commission in the following proceedings: 11
ƒ Constellation Mystic Power, LLC, Docket No. ER18-1639 12
ƒ West Texas Gulf Pipe Line Company, LLC (Docket No. OR19-22-13
000) and Permian Express Partners, LLC (Docket No. OR19-32-14
000) (consolidated) 15
ƒ Midwestern Gas Transmission Company (Docket No. RP21-525-16
000) 17
Q. What is the purpose of your testimony in this proceeding? 18
A. The purpose of my testimony is to determine the appropriate ratemaking rate of 19
return for Northern Natural Gas Company (Northern) under the Commission’s 20
current policy and guidelines. The three components of Northern’s rate of return 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 6 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 3 of 45

— rate of return on equity (ROE), capital structure, and cost of debt — are 1
addressed below. My testimony also responds to the arguments and conclusions 2
regarding Northern’s rate of return and risk profile provided by Laura Demman 3
(Ex. NNG-00001), Joseph Lillo (Ex. NNG-00039), and Anne Bulkley (Exs. NNG-4
00056 through NNG-00065). 5
Q. Are you sponsoring any exhibits in addition to your prepared Answering 6
Testimony? 7
A. Yes, I sponsor Exhibits S-0038, S-0039, and S-0040, described in the Table of 8
Exhibits above. 9
Q. What data period do you rely on for your analysis? 10
A. I rely on the most recent data available based on Commission precedent and 11
because it is the best indication of expected future market conditions. See 12
Coakley, et al. v. Bangor Hydro-Electric Company, et al., 147 FERC ¶ 61,234, at 13
P 64 (2014) (Opinion No. 531); Bangor Hydro-Electric Company, 117 FERC ¶ 14
61,129, at P 28 (2006) (Opinion No. 489); Portland Natural Gas Transmission 15
System, 134 FERC ¶ 61,129, at P 242 (2011) (Opinion No. 510.); and SFPP, L.P., 16
134 FERC ¶ 61,121, at P 208 (2011) (Opinion No. 511). For determining 17
Northern’s ROE, I rely on data from the six-month period ending January 31, 18
2023, which I will refer to as the “Study Period.” The Study Period is distinct 19
from the “Test Period” as used in Trial Staff’s testimony in this proceeding, which 20
is the 21-month period ending December 31, 2022. For determining Northern’s 21
capital structure and cost of debt, the last twelve months of the Test Period is the 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 7 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 4 of 45

relevant data period. Opinion No. 510, 134 FERC ¶ 61,129 at P 242; Opinion No. 1
511, 134 FERC ¶ 61,121 at P 208. Whenever particular data is referenced in my 2
testimony, I specify the period from which it is drawn. 3
Q. Does your testimony offer any legal opinions? 4
A. No. Although I cite to various Commission opinions and orders, I do so only to 5
inform the reader of the specific guidance I am following in developing my 6
recommendations and conclusions. My testimony is intended to present my 7
understanding of the Commission’s policies and does not reflect any legal 8
opinions. 9
II. OVERVIEW 10
Q. Please provide the background of this proceeding. 11

A. On July 1, 2022, Northern filed revised tariffs with the Commission seeking, 12
among other things, an ROE of 14.05 percent, a capital structure comprised of 13
63.61 percent equity and 36.39 percent debt, and a cost of debt of 4.15 percent, 14
which, collectively, would result in an overall rate of return of 10.45 percent. Ex. 15
NNG-00039 at 3:2-10 and 5:9-15. Twelve protests were filed in response, ten of 16
which raised Northern’s rate of return as a particular concern. Northern answered 17
the protestors on July 15, 2022, and July 20, 2022, and the Northern States Power 18
Companies and Southwestern Public Service Company filed an answer on July 20, 19
2022. All three answers were rejected by the Commission, and on July 29, 2022, 20
the Commission set “the justness and reasonableness of Northern’s proposed tariff 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 8 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 5 of 45

records” for hearing. Northern Natural Gas Company, 180 FERC ¶ 61,066, at P 1
9, Ordering Paragraph (C) (2022). 2
Q. What facilities are at issue in this proceeding? 3

A. Northern is an extraordinarily large and complex system consisting of 14,287 4
miles of natural gas pipeline, 75 billion cubic feet (Bcf) of storage capacity, and 5
two liquefied natural gas storage facilities with 4.3 Bcf of capacity. Ex. NNG-6
00026 at 3:3-7. The system stretches from southwest Texas to northern Minnesota 7
and Michigan. A map of the system is provided in Ex. S-0026. Northern has 8
1,700 delivery and receipt points and has historically transported natural gas from 9
what it calls the Field Area (generally the Permian Basin supply area and 10
specifically the Northern system south of Clifton, KS) to utilities and other 11
consumers in the Market Area (the Northern system north of Clifton, KS). Exs. 12
NNG-00026 at 3:8-10 and S-0039 at 1. The Market Area includes delivery points 13
to municipalities in Nebraska, South Dakota, Iowa, Wisconsin, Minnesota, and 14
Michigan. Northern was originally constructed in 1930 and has been expanding 15
since, including six expansion projects since 2019, all in Minnesota. Ex. S-0039 16
at 1 and 250-256. It connects to “virtually all major interstate and intrastate 17
pipelines in the Field Area” and many in the Market Area. Id. at 1; Ex. NNG-18
00026 at 4:1-14. 19
Northern describes itself as a “reticulated” system because it is nonlinear 20
and provides service across many delivery-receipt point combinations or paths. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 9 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 6 of 45

Ex. NNG-00026 at 6:3-19. It also now supplies most of the Market Area demand 1
from Market Area supply and uses pressure displacement to transport gas over 2
large portions of its system and to inject or extract gas from storage, making the 3
system largely reversible and gas largely fungible on the system. Id. at 5:7-6:2. 4
As Northern witness Royce Ramsey explains: “Northern uses its line pack and 5
operational storage to allow Northern’s customers to schedule simultaneous 6
receipt and delivery of gas, even though the actual travel time from the Field Area 7
to the Market Area could take nearly three days.” Id. at 3:17-20. 8
The system’s complexity is such that Northern itself has difficulty 9
quantifying its operational transportation capacity, though it is listed as 6.3 Bcf per 10
day in the Market Area and 1.7 Bcf per day in the Field Area in Mr. Ramsey’s 11
testimony (Ex. NNG-00026 at 3:4-5) and on Northern’s website (Ex. S-0039 at 1-12
2). In its peak day capacity report to the Commission (provided in Exhibit S-0039 13
at 3-4), Northern explains: 14
Due to the physical and design complexity of Northern’s pipeline 15
system, it is not possible to define capacity with a single numerical 16
value. Instead, Northern believes that a clearer and more complete 17
perspective can be obtained by setting forth capacity at ten (10) key 18
points along its system. 19

At the ten key points Northern lists, capacity is approximately 94 percent 20
committed to shippers, and the Clifton, KS demarcation point between the Field 21
and Market areas is fully committed. Id. and Ex. S-0039 at 67. This is consistent 22
with representations made by Northern’s parent, Berkshire Hathaway Energy 23
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 10 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 7 of 45

Company (BHE), to investors that 94 percent of transportation and storage 1
revenues are from demand charges “that are not dependent on the volumes 2
transported.” Ex. S-0039 at 12. According to Northern witness Demman, 3
“Northern’s firm storage capacity is fully subscribed under long-term 4
agreements.” Ex. NNG-00001 at 36:13-14. 5
Northern is owned by NNGC Acquisition, LLC, which is wholly owned by 6
BHE Pipeline Group, LLC, which is wholly owned by BHE. Ex. S-0023 at 3. 7
BHE is 91 percent owned by Berkshire Hathaway, Inc. Id. 8
III. ROE 9
A. SUMMARY AND RECOMMENDED ROE 10
Q. What ROE are you recommending for Northern? 11
A. I am recommending an ROE of 10.01 percent, which is the average of the medians 12
of the lower halves of the ranges produced by the discounted cash flow (DCF) 13
model and the capital asset pricing model (CAPM), each executed in accordance 14
with Commission policy and precedent as explained below. 15
B. PROXY GROUP SELECTION 16
Q. What is the Commission’s policy regarding the formation of a proxy group 17
for a natural gas pipeline? 18
A. Natural gas or oil pipeline proxy group companies must satisfy three criteria: “(1) 19
the company’s stock must be publicly traded; (2) the company must be recognized 20
as a natural gas or oil pipeline company and its stock must be recognized and 21
tracked by an investment information service such as Value Line; and (3) pipeline 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 11 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 8 of 45

operations must constitute a high proportion of the company’s business.” Inquiry 1
Regarding the Commission’s Policy for Determining Return on Equity, 171 FERC 2
¶ 61,155, at P 58 (2020) (ROE Policy Statement); see also Composition of Proxy 3
Groups for Determining Gas & Oil Pipeline Return on Equity, 123 FERC ¶ 4
61,048, at P 8 (2008) (Proxy Group Policy Statement). A “high proportion” of 5
pipeline operations under the third criterion historically meant at least 50 percent 6
of assets devoted to or operating income derived from pipeline operations, but the 7
Commission began relaxing this standard in 2003 to obtain proxy groups of “at 8
least four, and preferably at least five members” when necessary. ROE Policy 9
Statement at PP 59-61, 64-65; see also Proxy Group Policy Statement at P 8 10
(citing Williston Basin Interstate Pipeline Company, 104 FERC ¶ 61,036, at P 35 11
n.46 (2003)); Kern River Gas Transmission Company, 126 FERC ¶ 61,034, at P 12
104 (2009) (Opinion No. 486-B). The Commission also allows the consideration 13
of Canadian firms as proxy group candidates if necessary to form a proxy group of 14
sufficient size. ROE Policy Statement at P 66. 15
Q. Did you apply any additional screening criteria to develop the gas pipeline 16
proxy group? 17
A. Yes. First, to be included in the DCF model, a proxy group member must have a 18
positive Institutional Brokers’ Estimate System (IBES) growth rate (Seaway 19
Crude Pipeline Company LLC, 154 FERC ¶ 61,070, at P 196 (2016) (Opinion No. 20
546)) and must pay non-decreasing dividends during the Study Period. Opinion 21
No. 531, 147 FERC ¶ 61,234 at P 112; see also Opinion No. 510, 134 FERC ¶ 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 12 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 9 of 45

61,129 at P 186. Second, a proxy group member must have investment-grade 1
credit ratings. Opinion No. 510, 134 FERC ¶ 61,129 at P 222, n.301; Opinion No. 2
486-B, 126 FERC ¶ 61,034 at PP 80-81. Third, a proxy group member cannot be 3
engaged in significant merger or acquisition activities during the Study Period. 4
See Association of Business Advocating Tariff Equity, et al. v. Midcontinent 5
Independent System Operator, Inc. et al., 169 FERC ¶ 61,129, at P 365 (2019) 6
(Opinion No. 569) (citing Opinion No. 531 at P 114 and Association of Business 7
Advocating Tariff Equity, 156 FERC ¶ 61,234, PP 37-43 (2016) (Opinion No. 8
551)); see also Panhandle Eastern Pipe Line Company, 181 FERC ¶ 61,211, at P 9
144 (2022) (Opinion No. 885). 10
Q. What potential proxy group members did you consider in your analysis? 11
A. The most restrictive of the Commission’s proxy group membership requirements 12
is that a company must have at least 50 percent of assets devoted to or income 13
derived from natural gas pipelines, and this condition must be relaxed in this case 14
to obtain a proxy group of four or five members. I therefore began by considering 15
the following five companies as candidates for the proxy group because they have 16
the highest percentages of natural gas pipeline operations among publicly traded 17
companies followed by Value Line: 18
1) Enbridge Inc. (Enbridge); 19
2) Kinder Morgan, Inc. (Kinder Morgan); 20
3) National Fuel Gas Company (National Fuel); 21
4) TC Energy Corp. (TC Energy); and 22
5) The Williams Companies, Inc. (Williams). 23
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 13 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 10 of 45

My calculations of the trailing three-year average (see Proxy Group Policy 1
Statement, 123 FERC ¶ 61,048 at P8) assets devoted to and income derived from 2
gas pipeline operations for these companies is provided in Exhibit S-0038 at pages 3
34-38. 4
Q. Which companies satisfy all your criteria? 5
A. Only TC Energy satisfies all the criteria discussed above. Kinder Morgan has a 6
negative growth rate and therefore cannot be included in the DCF model discussed 7
below, but Kinder Morgan does satisfy all the remaining proxy group eligibility 8
criteria and can be used in the CAPM. Williams, National Fuel, and Enbridge all 9
report assets devoted to and income derived from natural gas pipelines below 50 10
percent. None of the five proxy group candidates above participated in significant 11
merger or acquisition activity during the Study Period, have below-investment-12
grade credit ratings, or decreased dividend payments during the Study Period. 13
Q. Why is Kinder Morgan eligible for use in the CAPM while it has a negative 14
growth rate? 15
16
A. In Opinion No. 885, the Commission stated that the Initial Decision “found that it 17
is illogical to include companies with negative rates in a CAPM analysis,” and 18
thus excluded TC Pipelines from both the DCF model and the CAPM on the basis 19
of TC Pipelines’ negative growth rate. 181 FERC ¶ 61,211 at PP 146, 149 (citing 20
Panhandle Eastern Pipe Line Company, 174 FERC ¶ 63,026, at P 210 (2021)). 21
The Panhandle Initial Decision at paragraph 210 cited paragraph 77 of Opinion 22
No. 569-A. However, Opinion No. 569-A at paragraph 77 simply explains that 23
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 14 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 11 of 45

companies with negative growth rates are excluded from the one-step DCF model 1
that is used to calculate the risk premium used in the CAPM itself. Association of 2
Business Advocating Tariff Equity Coalition of MISO Transmission Customers, 3
171 FERC ¶ 61,154, at P 77 (2020) (Opinion No. 569-A)). Opinion No. 569-A 4
does not state that companies with negative growth rates are to be excluded from 5
the CAPM itself, and actually includes First Energy Corp. and Entergy Corp. in 6
the CAPM proxy group despite their negative growth rates. See Opinion No. 569-7
A, 171 FERC ¶ 61,154 at P 216 n.360 (citing Appendix III to Opinion No. 569-A 8
which adopts Trial Staff’s presentation of the CAPM on brief that does not 9
exclude companies with negative growth rates from the CAPM itself). The 10
Commission has similarly included companies with negative growth rates in the 11
CAPM. Entergy Arkansas, Inc., et al., 175 FERC ¶ 61,136, at Appendices II-III 12
(2021) (Opinion No. 575) (FirstEnergy Corp.); DATC Path 15, LLC, 177 FERC 13
61,115, at PP 207, 211 (2021) (Opinion No. 879) (OGE Energy Corporation); 14
Constellation Mystic Power, LLC, 176 FERC ¶ 61,019, at P 170, Appendix C 15
(2021) (Constellation) (FirstEnergy Corp. and Entergy Corp.). In summary, 16
Commission policy is to exclude companies with negative or very high (greater 17
than 20%) growth rates from the one-step DCF model used to determine the risk 18
premium in the CAPM, but it does not exclude companies from the CAPM itself 19
based on negative or very high growth rates, notwithstanding the exclusion of TC 20
Pipelines from the CAPM in Opinion No. 885, 181 FERC ¶ 61,211 at P 149. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 15 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 12 of 45

Q. What is the minimum percentage of assets devoted to, or operating income 1
derived from, natural gas pipelines that allows a proxy group of at least four 2
members? 3
A. Approximately 25 percent. Lowering the threshold to at least 25 percent of 4
income derived from or assets devoted to natural gas pipeline operations allows 5
the inclusion of Enbridge, National Fuel, and Williams in the proxy group. Ex. S-6
0038 at 34-38. 7
Q. Does Northern agree that the 50 percent requirement must be relaxed to form 8
a proxy group with four or five members? 9
A. Yes. See Ex. NNG-00056 at 27:2-10. 10
Q. Considering Commission policy and the present composition of the natural 11
gas pipeline industry in the U.S., what is the appropriate proxy group for 12
Northern? 13
A. The appropriate proxy group for Northern consists of Enbridge, Kinder Morgan 14
(for the CAPM only), National Fuel, TC Energy, and Williams. 15
C. APPLICATION OF THE COMMISSION’S TWO-STEP DCF MODEL 16
Q. How did you apply the Commission’s DCF model approach to the proxy 17
group? 18
A. The DCF methodology I applied is the two-step DCF methodology (two-step 19
DCF) that the Commission has used for natural gas pipelines since 1998. 20
Transcontinental Gas Pipe Line Corporation, 84 FERC ¶ 61,084 (1998) (Opinion 21
No. 414-A). Specifically, I used the following formula to calculate the DCF 22
model results: 23
Implied cost of equity = (D/P)*(1+.5(GIBES)) + GComp 24
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 16 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 13 of 45

D is the firm’s annual dividend, P is the average price of the firm’s stock over the 1
Study Period, and D/P is the firm’s dividend yield during the Study Period. GIBES 2
is the firm’s short-term (3-5 year) projected growth rate of earnings per share at 3
the end of the Study Period, and GComp is the firm’s composite growth rate. GComp 4
is equal to (2/3)*GIBES + (1/3)*GGDP, where GGDP is the expected long-term growth 5
rate in U.S. Gross Domestic Product (GDP). ROE Policy Statement, 171 FERC ¶ 6
61,155 at PP 29, 31-34; Opinion No. 569, 169 FERC ¶ 61,129 at P 134. 7
I calculated the dividend yield for each member of the proxy group 8
according to the Commission’s methodology: 9
That methodology derives a single dividend yield for each 10
proxy group company, using a three step process: (1) 11
averaging the high and low stock prices as reported by the 12
New York Stock Exchange or NASDAQ for each of the six 13
months in the study period; (2) dividing the company’s 14
indicated annual dividend for each of those months by its 15
average stock price for each month (resulting in a monthly 16
dividend yield for each month of the study period); and (3) 17
averaging those monthly dividend yields. 18

Opinion No. 531, 147 FERC ¶ 61,234 at P 77; see also Opinion No. 510, 134 19
FERC ¶ 61,129 at PP 232-234; El Paso Natural Gas Company, 145 FERC ¶ 20
61,040, at P 658 (2013) (Opinion No. 528). The dividend yield calculations are 21
detailed in Exhibit S-0038 at pages 3-9. Enbridge and TC Energy are 22
headquartered in Canada and declare and pay dividends in Canadian dollars 23
(CAD). Both firms are dual listed on the Toronto and New York Stock 24
Exchanges. U.S. stockholders receive dividend distributions in U.S. dollars 25
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 17 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 14 of 45

(USD) on the record date (Enbridge) or payment date (TC Energy) at the 1
prevailing Canadian/U.S. dollar exchange rate on that day. Therefore, U.S. 2
investors’ expected and realized dividend yields during the Study Period partly 3
depended on the Canadian/U.S. dollar exchange rate. U.S. investors in Enbridge 4
and TC Energy do not know exactly what dividend they will receive until the 5
record or payment date arrives. To account for this complication while 6
maintaining the logic of the Commission’s approach to calculating dividend 7
yields, I average the CAD/USD exchange rate over the Study Period and used that 8
average to convert dividends declared and paid in CAD to USD for Enbridge and 9
TC Energy. I also calculated dividend yields in CAD using Enbridge’s and TC 10
Energy’s Toronto Stock Exchange prices in CAD as a check on the reasonableness 11
of my approach to calculating dividend yields for U.S. equity investors in 12
Enbridge and TC Energy. For Enbridge (U.S.), I calculate a dividend yield of 6.43 13
percent, while for Enbridge (Canada), I calculate a dividend yield of 6.42 percent. 14
Ex. S-0038 at 3-4. For TC Energy (U.S.), I calculate a dividend yield of 6.20 15
percent, while for TC Energy (Canada), I calculate a dividend yield of 6.23 16
percent. Ex. S-0038 at 7-8. 17
I obtained GIBES for each member of the proxy group from Yahoo! Finance 18
on the last trading day of the Study Period, January 31, 2023. These growth rates 19
are shown in screenshots produced in Exhibit S-0039 at pages 21-34. 20
The Commission’s method of calculating GGDP is to average long-run GDP 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 18 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 15 of 45

growth estimates from the Energy Information Administration, the Social Security 1
Administration, and IHS Markit. ROE Policy Statement, 171 FERC ¶ 61,155 at P 2
5 n.11; Proxy Group Policy Statement, 123 FERC ¶ 61,048 at P 6 n.7; Opinion 3
No. 531, 147 FERC ¶ 61,234 at P 39 n.67, aff’d, 149 FERC ¶ 61,032, at PP 6, 10 4
(2014) (Opinion No. 531-A). My calculation of a GGDP of 4.17 percent is shown 5
in Exhibit S-0038 at page 31. 6
Q. What are the results of the DCF model? 7
A. The results of the DCF model range from 8.62 percent to 13.68 percent. The 8
median result is 10.68 percent. The median of the lower half of the range is 9.40 9
percent. Ex. S-0038 at 2. 10
Q. Did you exclude any results as outliers? 11

A. No. The Commission does not apply a specific outlier test in natural gas and oil 12
pipeline cases but will consider outliers on a case-by-case basis. ROE Policy 13
Statement, 171 FERC ¶ 61,155 at P 87. The outlier tests applied in electric cases 14
(see Opinion No. 569-A, 171 FERC ¶ 61,154 at PP 154, 156, 161), if applied here, 15
would not result in the exclusion of any DCF model results. Ex. S-0038 at 2. 16
Finally, using a standard statistical heuristic of considering results outside of two 17
standard deviations from the mean as outliers does not indicate that any of the 18
DCF results should be excluded. Id. This method, it should be noted, assumes 19
that DCF results are normally distributed. 20
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 19 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 16 of 45

D. APPLICATION OF THE COMMISSION’S CAPM APPROACH 1

Q. How did you apply the Commission’s CAPM approach to the proxy group? 2

A. The specific CAPM approach I applied follows the Commission’s guidance in the 3
ROE Policy Statement, 171 FERC ¶ 61,155 at PP 39-42,46-47. To calculate 4
CAPM results, I used the following formula: 5
Implied cost of equity = rf + β*(rm-rf) + s 6
where: 7
rf is the risk-free rate of return. 8
rm is the overall market (usually an exchange or index) rate of return. 9
Beta (β) is the relationship between a firm’s returns and market returns. Note that, 10
in the equation above, the change in the cost of equity for a given change in rm 11
(Δrm) is (β* Δrm). 12
s is a size adjustment, where size is measured by market capitalization. 13
Id. P 8. 14
Q. How is the risk-free rate of return determined? 15

A. Following the Commission’s policy, id. P 39, I calculated the average monthly 16
yield on 30-year Treasuries over the Study Period, which is 3.68 percent. Ex. S-17
0038 at 43. 18
Q. How is the market rate of return determined? 19

A. In the ROE Policy Statement, the Commission states that it will “estimate the 20
expected market return using a forward-looking approach based on a one-step 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 20 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 17 of 45

DCF analysis of all dividend paying companies in the S&P 500 . . . exclud[ing] 1
S&P 500 companies with growth rates that are negative or in excess of 20%.” 171 2
FERC ¶ 61,155 at P 39. The Commission’s preferred source for the short-term 3
growth projections used in the one-step DCF is IBES, though it currently will 4
“allow participants to propose using Value Line growth projections…” Id. P 55. I 5
performed a one-step DCF analysis consistent with Commission policy using 6
IBES growth projections which resulted in a market return (rm) of 11.16 percent. 7
Ex. S-0038 at 10-11 and 14-21. Using Value Line growth rates rather than IBES 8
growth rates results in a market return of 12.40 percent. Ex. S-0038 at 12-13 and 9
22-29. 10
Q. How are the betas used in the CAPM analysis determined? 11

A. Betas for each of the members of the proxy group were obtained from Value Line. 12
ROE Policy Statement, 171 FERC ¶ 61,155 at P 46. 13
Q. How are the size adjustments determined? 14

A. The size adjustments are based on the most recent available (December 31, 2022) 15
Kroll Cost of Capital Navigator size premia. Id. PP 44, 47. Ex. S-0038 at 44 and 16
Ex. S-0039 at 35. 17
Q. What are the results of your CAPM analysis? 18

A. CAPM results for the proxy group range from 9.78 percent to 12.03 percent. The 19
median result is 11.28 percent. The median of the lower half of the range is 10.62 20
percent. Ex. S-0038 at 10. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 21 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 18 of 45

Q. Did you exclude any CAPM results as outliers? 1

A. No. As I previously discussed, the Commission does not apply a specific outlier 2
test in natural gas and oil pipeline cases, but will consider outliers on a case-by-3
case basis. ROE Policy Statement, 171 FERC ¶ 61,155 at P 87. The outlier tests 4
adopted for electric cases (Opinion No. 569-A, 171 FERC ¶ 61,154 at PP 154, 5
156, 161), if applied here, would not result in the exclusion of any results. Ex. S-6
0038 at 10. Finally, using a standard statistical heuristic of considering results 7
outside of two standard deviations from the mean results as outliers does not 8
indicate that any of the CAPM results should be excluded. Id. Again, this method 9
assumes the CAPM results are normally distributed. 10
E. CAPM ANALYSIS USING BLOOMBERG BETAS 11
Q. Why do you present CAPM results using Bloomberg betas, rather than Value 12
Line betas? 13

A. The market rate of return used to calculate the market risk premium in the CAPM 14
is based on the S&P 500 index. Value Line betas are derived from the New York 15
Stock Exchange (NYSE). There is thus an internal inconsistency in the 16
Commission’s standard approach, which the Commission has recognized in the 17
context of setting ROEs for electric utilities. Opinion No. 569-A, 171 FERC ¶ 18
61,154 at P 76; Constellation, 176 FERC ¶ 61,019 at PP 77, 85. Betas derived 19
from the S&P 500 can be obtained from Bloomberg for use in the CAPM to rectify 20
the inconsistency. Furthermore, Value Line covers Enbridge as a Canadian 21
company and therefore provides a beta for Enbridge’s listing on the Toronto Stock 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 22 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 19 of 45

Exchange (ENB.TO) rather than Enbridge’s listing on the NYSE (ENB). Use of 1
Bloomberg betas avoids this inconsistency. I obtained adjusted betas based on 2
weekly price data and S&P 500 returns for the five years ended January 31, 2023. 3
See Ex. S-0038 at 32. 4
Q. What are the results of the alternative CAPM analysis? 5
A. Using Bloomberg betas, the CAPM results for the proxy group range from 9.73 6
percent to 11.14 percent. The median result is 9.92 percent. Ex. S-0038 at 11. 7
F. CAPM ANALYSIS USING VALUE LINE GROWTH RATES IN THE ONE-8
STEP DCF MODEL 9
Q. Why do you present one-step DCF model results using Value Line growth 10
rates, rather than IBES growth rates? 11

A. The Commission has indicated that it will consider the use of Value Line growth 12
rates, instead of IBES growth rates, in the one-step DCF model. ROE Policy 13
Statement, 171 FERC ¶ 61,155 at P 55. I therefore present the results of such an 14
analysis for illustrative purposes. 15
Q. What are the results of using Value Line growth rates in your CAPM 16
analysis? 17

A. Use of Value Line growth rates in the one-step DCF model results in a market rate 18
of return of 12.40 percent. Ex. S-0038 at 12-13 and 22-29. Combined with Value 19
Line betas, this gives CAPM results ranging from 10.83 percent to 13.45 percent 20
with a median of 12.57 percent and a median of the lower half of 11.67 percent. 21
Id. at 12. Combined with Bloomberg betas, this gives CAPM results ranging from 22
10.68 percent to 12.37 percent with a median of 10.95 percent and a median of the 23
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 23 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 20 of 45

lower half of 10.72 percent. Id. at 13. 1
G. INDICATED ZONE OF REASONABLENESS FOR NORTHERN’S ROE 2
Q. How does the Commission determine the zone of reasonable ROEs from the 3
results of its two-step DCF analysis and CAPM analysis? 4

A. The Commission gives equal weight to the DCF and CAPM analyses by averaging 5
their results. ROE Policy Statement, 171 FERC ¶ 61,155 at PP 48, 50 (citing 6
Opinion No. 569, 169 FERC ¶ 61,129 at PP 425, 427). The zone of 7
reasonableness ranges from the average of the minimums of the DCF model and 8
CAPM results to the average of the maximums of the DCF model and CAPM 9
results. 10
Q. What is the zone of reasonableness indicated by your analysis? 11

A. The zone of reasonableness is 9.20 percent to 12.85 percent. The average of the 12
median DCF model result (10.68 percent) and median CAPM result (11.28 13
percent) is equal to 10.98 percent. Ex. S-0038 at 1. 14
Q. What is the indicated range from using CAPM results based on Bloomberg 15
betas? 16

A. The zone of reasonableness indicated from using Bloomberg betas in the CAPM is 17
9.16 percent to 12.39 percent. The average of the median DCF model (10.68 18
percent) result and the median CAPM result (9.92 percent) is equal to 10.30 19
percent. Ex. S-0038 at 1. 20
Q. What are the ranges indicated by using Value Line growth rates in the one-21
step DCF model used in the CAPM? 22

A. Using Value Line betas, the indicated zone of reasonableness is 9.73 percent to 23
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 24 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 21 of 45

13.56 percent. The average of the median DCF model result (10.68 percent) and 1
the median CAPM result (12.57 percent) is equal to 11.63 percent. Id. Using 2
Bloomberg betas, the zone of reasonableness is 9.65 percent to 13.02 percent. The 3
average of the median DCF model result (10.68 percent) and the median CAPM 4
result (10.95 percent) is equal to 10.82 percent. Id. 5
In this case, Bloomberg betas are lower than Value Line betas for the proxy 6
group, and IBES growth rates are generally lower than Value Line growth rates for 7
dividend-paying members of the S&P 500. Therefore, using IBES growth rates or 8
Bloomberg betas produces lower CAPM results, and using both IBES growth rates 9
and Bloomberg betas results in the lowest indicated median ROE and zone of 10
reasonableness. 11
IV. NORTHERN’S RELATIVE RISK 12
Q. How does the Commission account for risk faced by a company relative to the 13
risk of the proxy group companies? 14
A. Unless a subject natural gas pipeline faces anomalous risk relative to the proxy 15
group, other pipelines, or both, the Commission’s policy is to set the pipeline an 16
ROE equal to the median of the zone of reasonableness. ROE Policy Statement, 17
171 FERC ¶ 61,155 at P 6. In Portland Natural Gas Transmission System, the 18
Commission stated: 19
The Commission’s traditional assumption with regard to 20
relative risk is that natural gas pipelines generally fall into a 21
broad range of average risk absent highly unusual 22
circumstances that indicate an anomalously high or low risk 23
as compared to other pipelines. Thus, unless a pipeline 24
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 25 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 22 of 45

makes a very persuasive case in support of the need for an 1
adjustment and the level of the adjustment proposed, the 2
Commission will set the pipeline’s return at the median of the 3
range of reasonable returns. However, the Commission 4
permits parties to present evidence to support any return on 5
equity that is within the zone of reasonableness, and the 6
Commission has recognized that an examination of the risk 7
factors specific to a particular pipeline may warrant setting its 8
ROE either higher or lower than the middle of the zone of 9
reasonableness established by the proxy group. 10

142 FERC ¶ 61,197, at P 382 (2013) (Opinion No. 524) (footnotes omitted); see 11
also Opinion No. 510, 134 FERC ¶ 61,129 at P 265; Proxy Group Policy 12
Statement, 123 FERC ¶ 61,048 at P 7. In Opinion No. 528, the Commission made 13
clear that it “places a heavy burden on those attempting to justify a deviation from 14
the median ROE” and that 15
any analysis attempting to demonstrate that a deviation from 16
the median ROE is justified must present a comparison 17
between the risk level of the subject company and the risk 18
level of each of the proxy group companies. This is the crux 19
of the analysis, and if it is lacking, the analysis is incomplete. 20

145 FERC ¶ 61,040 at PP 688, 698. 21
Q. What is the Commission’s definition of risk? 22
A. In Generic Determination of Rate of Return on Common Equity for Electric 23
Utilities, Notice of Proposed Regulations, the Commission explained that: 24
Risk is typically defined as the inability to predict the 25
outcome of future events with certainty. In an investment 26
context, it may be viewed simply as the chance that expected 27
returns will not be realized or, alternatively, as the chance of 28
realizing returns less than expected. The traditional approach 29
to the evaluation of investment risk focuses on the two major 30
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 26 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 23 of 45

sources of uncertainty to a company: business risk and 1
financial risk. Business risk relates to the uncertainty of 2
expected income flows to the company. This uncertainty may 3
be viewed as a function of the variability in a company’s 4
operating income over time, and such statistical techniques as 5
standard deviation and standard error can be used to measure 6
this variability for some defined period. 7
Financial risk is the uncertainty introduced by the method of 8
financing an investment. It represents that portion of total 9
company risk, over and above business risk, which results 10
from using debt. Financial risk arises because the use of debt 11
requires a company to pay fixed interest charges prior to 12
paying dividends to common stockholders. The fixed and 13
senior nature of interest charges increases the risk of equity in 14
two ways. First, the greater the debt burden, the greater the 15
risk that the company will default on its interest payments and 16
be forced into bankruptcy. Second, the greater the percentage 17
of debt in a company’s capital structure, the more uncertain 18
are common stockholder’s expected returns, because of the 19
increased volatility of the residual earnings available to them 20
with any given change in operating income. 21
47 Fed. Reg. 38,332, at 38,338-39 (1982), order adopting final rule, Order No. 22
389, 49 Fed. Reg. 29,946 (1984), reh’g denied, Order No. 389-A, 49 Fed. Reg. 23
46,351 (1984) (noting that the Commission did not reject this background 24
language in the final rule). 25
Q. How is a subject pipeline’s relative risk evaluated by the Commission? 26
A. A firm’s cost of equity depends on investors’ risk perceptions, so the investor’s 27
perspective is the appropriate one to consider. Opinion No. 528, 145 FERC ¶ 28
61,040 at PP 693-694. The Commission has referenced credit ratings to determine 29
a subject company’s relative risk. See e.g., Opinion No. 486-B, 126 FERC ¶ 30
61,034 at P 137; Opinion No. 528 at P 631. Credit ratings and company 31
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 27 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 24 of 45

evaluations are available from S&P and Moody’s for the proxy group companies, 1
Northern, and BHE. Ex. S-0039 at 46-209. Fitch does not presently have a rating 2
for Northern or BHE. Nor does Value Line cover Northern or BHE. The credit 3
ratings of the proxy group, Northern, and BHE are summarized in Exhibit S-0038 4
at page 33. Additionally, the Commission has referenced the degree of 5
competition and earnings stability when discussing pipeline risk. Opinion 414-A, 6
84 FERC ¶ 61,084 at 61,427; Opinion No. 486-B at P 75. 7
Q. Does Northern face lower risk than the proxy group? 8
A. Yes. Northern has a higher credit rating than any member of the proxy group. 9
Exs. S-0038 at 33; NNG-00061 at 4. The proxy group’s credit ratings range from 10
Baa3 to Baa1 according to Moody’s and from BBB- to BBB+ according to S&P. 11
All of these ratings are below Northern’s ratings (A by S&P and A2 by Moody’s). 12
S&P’s most recent issuer ranking of midstream energy companies rates Northern 13
as the second-lowest risk issuer in North America, behind Colonial Enterprises, 14
Inc. (Colonial). Ex. S-0039 at 36-45. Colonial is a 5,500 mile pipeline that 15
transports refined products from the Texas Gulf Coast to metropolitan areas in the 16
Southeast and along the East Coast to Lindon, NJ. Like Northern, it benefits from 17
low business risk, because the transportation it provides is from a reliable supply 18
area to reliable demand areas. Id. at 119-125. 19
Both Moody’s and S&P give Northern the highest issuer rating of any 20
natural gas pipeline in North America. Exs. S-0038 at 46-52; S-0039 at 36-45. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 28 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 25 of 45

Moody’s gives Northern a higher rating than any other natural gas pipeline, oil 1
pipeline, or midstream company in the world. Ex. S-0038 at 53-66. By these 2
metrics, if Northern is not a lower-than-average risk pipeline, then no natural gas 3
pipeline is. 4
Northern has a higher equity ratio (equity/total capitalization) of 64.12, 5
compared to an average of 44.12 percent and high 50.35 percent of among the 6
proxy group. Exs. S-0038 at 41; S-0040 at 4. The members of the proxy group 7
are also engaged in a wider array of businesses than Northern, and these other 8
businesses are generally riskier than natural gas pipelines and storage. Enbridge 9
and TC Energy both have liquids transportation businesses, which are considered 10
riskier by the Commission. Opinion No. 486-B, 126 FERC ¶ 61,034 at PP 73, 75. 11
Kinder Morgan also owns and operates refined product pipelines and crude oil 12
pipelines, which are considered riskier than natural gas pipelines by the 13
Commission. Id. P 71; Kern River Gas Transmission Company, 117 FERC ¶ 14
61,077, at P 152 n.248 (2006) (Opinion No. 486). National Fuel is significantly 15
engaged in risky natural gas exploration and production activities. Williams is 16
engaged in gathering and processing natural gas. Northern is not exposed to the 17
riskier lines of business the proxy members engage in. 18
Q. Are Northern and Moody’s related entities? 19

A. Yes. Berkshire Hathaway, Inc. owns 91.14 percent of BHE, which in turn owns 20
100 percent of Northern. Northern’s 2021 FERC Form No. 2, p. 102. Berkshire 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 29 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 26 of 45

Hathaway, Inc. is also the largest shareholder in Moody’s, holding approximately 1
13.47 percent of outstanding shares. Ex. S-0039 at 248-249. Based on my review 2
of Moody’s rating of Northern in conjunction with the other facts and risk 3
analyses described herein, I do not believe that the relationship between Northern 4
and Moody’s creates a conflict of interest in Moody’s assessments of Northern. 5
Q. What is your conclusion regarding Northern’s risk relative to the proxy 6
group? 7
A. Northern bears less business and financial risk than the proxy group. 8
Q. Does Northern face lower risk than other gas pipeline and storage systems? 9
A. Yes. Natural gas pipelines typically operate in a lower risk environment than most 10
other businesses because they are shielded from competition and have customers 11
with inelastic demand and good credit. Northern stands out among this group for 12
numerous reasons. It is large, perhaps the largest natural gas pipeline in the world, 13
and links prominent supply basins and other interstate pipelines to demand centers 14
in the Midwest U.S. The Northern system is adaptable to changes in market 15
dynamics over time (see e.g., Ex. NNG-00026 at 5:7-6:19), as its longevity 16
reflects. 17
According to BHE, Northern is “economically unfeasible to replicate.” Ex. 18
S-0039 at 11. Northern’s location, scope, and flexibility are immutable to the 19
extent that such characteristics of the system are beyond the control of 20
management. That is not to say that good management is not essential to the 21
success of the system, and that Commission policy is not to penalize good 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 30 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 27 of 45

management. Opinion No. 414-A, 84 FERC ¶ 61,084 at 61,427. There is 1
consistent demand for Northern’s transportation and storage services from 2
creditworthy customers. Ex. S-0039 at 13. Potential competitors face substantial 3
barriers to entry. Overall, Northern faces little prospect of a decline in demand for 4
transportation and storage, a decline in natural gas supply to its system, or an 5
increase in competition such that Northern becomes unprofitable or unable to earn 6
its allowed ROE consistently. 7
Q. Did you evaluate Northern’s earnings history? 8
A. Yes. To evaluate Northern’s variability of returns, I reviewed Northern’s FERC 9
Form No. 2 filings dating back to the year 2000 (which contain data starting at 10
year end 1999). Northern’s rate of return on book equity is consistent across the 11
past 12 years, as can be seen on the chart below, produced with data shown in 12
Exhibit S-0038 at pages 39-40. Northern’s only loss since 1999 was recorded in 13
2001, when Northern wrote off monies owed to it by Enron Corporation, its parent 14
company prior to BHE’s acquisition. The write-off of $132.4MM in accounts 15
receivable and $112.5MM in notes receivable from Enron Corporation resulted in 16
a net loss that year of $52.1MM. 17
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 31 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 28 of 45

1
Based on all the years shown, Northern’s coefficient of variation (standard 2
deviation divided by mean) of rate of return on book equity is 0.41. Ex. S-0038 at 3
39. Excluding the year 2001, Northern’s coefficient of variation is 0.31. Id. 4
Since 2010, Northern’s returns have stabilized, averaging 11.53 percent with a 5
standard deviation of 1.03 percent (giving a coefficient of variation of 0.09). Id. 6
Northern’s earnings have been highly predictable over the past decade. 7
Q. Did you evaluate Northern’s competition? 8
A. Yes. Northern witness Demman states that Northern faces competition from 9
other pipelines in both the Market and Field Areas. Ex. NNG-00001 at 23:17-10
24:6, 25:5-14, 31:1-14. Although Northern intersects with many other pipelines, it 11
is not clear that Northern’s relationship with other pipelines is purely or even 12
primarily competitive. Northern receives gas from and delivers gas to other 13
pipelines to allow its customers more options of source and delivery locations. 14
-5.00%
0.00%
5.00%
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
RoR on Book Equity, Northern, 1999-2021
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 32 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 29 of 45

Ex. NNG-00026 at 5:7-6:19. Northern’s history of discounting and constructing 1
incremental expansions to avoid “bypass” (i.e., customers using another pipeline) 2
implies that, when competition or the threat of competition exists, Northern is 3
well-positioned to beat the competition by providing new or existing services at a 4
price below what other pipelines can or could provide. Ex. NNG-00001 at 28:5-5
29:2. Northern’s parent, BHE, summed up Northern’s competitive position in its 6
November 2022 presentation to investors as follows: “Prices are competitive with 7
other pipelines which minimizes the level of discounting needed in competitive 8
markets[.] Competitive rates have been increasing in major markets[.]” In the 9
Field Area, Northern has a “tremendous advantage for customers and pipeline[s] 10
to capture opportunities,” and its Field Area footprint provides “opportunity to 11
capture increased volumes.” Ex. S-0039 at 11. 12
S&P notes that Northern “faces intense competition and revenue volatility” 13
in the Field Area but still rates its competitive position as “strong” and notes that 14
the Market Area accounts for 70 to 80 percent of Northern’s revenue. Ex. S-0039 15
at 97-106. Similarly, Moody’s finds that, “While Northern’s field area is subject 16
to competition and more sensitive to variable market conditions, its majority 17
market area business is stable and continues to underpin the company’s strong 18
credit metrics.” Moody’s also notes that Northern’s storage customers are 19
typically utilities in the Market Area who “are physically integrated with Northern, 20
setting a high barrier to entry to competition from other pipelines.” Id. at 185-192. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 33 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 30 of 45

Witness Demman also claims that capacity release (customers with excess 1
committed capacity that market unused capacity to other customers) and peak 2
shaving (customers storing propane or liquefied natural gas to mitigate their 3
demand for natural gas transportation at times of high demand) constitute 4
competition for Northern. Ex. NNG-00001 at 29:10-30:20. These practices affect 5
the timing of demand and willingness to pay for natural gas transportation and also 6
decrease Northern’s revenue compared to scenarios where such practices are 7
absent, but do not affect the total quantity of natural gas shipped on Northern 8
during any given year. Thus, capacity release and peak shaving are examples of 9
Northern’s customers organizing their operations to minimize the costs of natural 10
gas transportation but do not represent competition to Northern. 11
Q. Does Northern face less risk than the average gas pipeline? 12
A. In my opinion, yes, although it is impossible to measure or quantify risk, which is 13
subjectively perceived. Northern has a consistent supply of natural gas from the 14
Field Area and from other pipelines and consistent demand from the Market Area 15
(which is demonstrated by Northern’s continued expansion). Ex. S-0004 at 44. 16
Northern has completed or started five expansion projects since 2019, all in 17
Minnesota. Ex. S-0039 at 250-256. As described above, Northern is highly 18
subscribed and receives 94 percent of its revenues from firm capacity and storage 19
contracts, meaning revenues are guaranteed even if gas is not transported. Its 20
customers rely on its services and pose little counterparty risk. According to BHE, 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 34 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 31 of 45

Northern’s “top 10 customer groups (64% of 2021 revenue) have a weighted 1
average credit rating of BBB+/Baa1.” Ex. S-0039 at 13. Northern consistently 2
earns profits, is largely insulated from commodity price risk and counterparty risk, 3
and Northern can benefit from arbitrage opportunities across its system through 4
gas purchases and sales during extreme weather. Ex. S-0004 at 42-44, 118, 133 . 5
Q. Please summarize your view of Northern’s risk. 6
A. Northern has a stable, reliable, and captive customer base and is shielded from 7
competition by substantial barriers to entry facing new entrants to the natural gas 8
transmission industry. Northern has a strong balance sheet and consistent 9
earnings. Northern’s business risk and financial risk are low, and its overall risk is 10
lower than the members of the proxy group and most, if not all, other natural gas 11
pipelines. 12
Q. Having concluded that Northern faces low risk, relative to the proxy group 13
and other pipelines, how did you determine the appropriate placement of 14
Northern’s ROE within the zone of reasonableness? 15
A. As I discussed above, the Commission has stated that parties can advocate for an 16
ROE placement at the median or anywhere else within the zone of reasonableness, 17
but they must justify any placement of the ROE that deviates from the median. 18
Opinion No. 524, 142 FERC ¶ 61,197 at P 382. But the Commission to date has 19
provided no guidance as to specific placement away from the median or what is 20
needed to adequately support such placement of the ROE in the lower or upper 21
half of the zone of reasonableness for a below or above-average risk pipeline, 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 35 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 32 of 45

respectively. Rather than assigning the median to a “broad range of average risk 1
pipeline,” the Commission in this case must choose from a broad range of ROEs 2
to apply to a single category of risk, low. In Opinion No. 524, the Commission 3
concluded that the subject pipeline faced above-average risk and placed the ROE 4
at the very top of the range. 142 FERC ¶ 61,197 at P 395. It did so based on the 5
following two facts: Portland had a below-investment grade rating and was unable 6
to recover a portion of its costs due to customer bankruptcies. Id. at PP 382, 395. 7
In a previous case, Transcontinental Gas Pipe Line Corporation, the Commission 8
also set a pipeline’s ROE at the top of the range because it had a below-9
investment-grade credit rating and was evaluated by a witness to be “riskier than 10
all other pipelines” except one. 60 FERC ¶ 61,826 (1992). In Opinion No. 486, 11
the Commission assigned the subject pipeline the median ROE plus 50 basis 12
points because it found the pipeline to be higher-than-average risk. 117 FERC ¶ 13
61,077 at PP 175, 177. 14
In this case, Northern has a credit rating above every member of the proxy 15
group according to Moody’s and above all other pipelines save one (Colonial) 16
according to S&P. Northern also has a geographic span and a diverse and 17
creditworthy customer base rivaled by few other systems, if any. Applying the 18
reasoning in Opinion No. 524 and Transcontinental Gas Pipe Line Corporation to 19
Northern, one may reasonably conclude that Northern should be assigned the 20
minimum value in the zone of reasonableness if Northern’s low-risk position were 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 36 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 33 of 45

independent of its management. 1
In Opinion No. 414-A, the Commission stated that it does not want to 2
penalize good management by decreasing the ROE for pipelines with low risk due 3
to its own decisions: “[T]he Commission will not lower a pipeline’s ROE if its 4
lower risk is the result of the pipeline’s own efficiency. Instead, the Commission 5
will focus on risks faced by the pipeline that are attributable to circumstances 6
outside the control of the pipeline’s management . . .” 84 FERC ¶ 61,084 at 7
61,247. In Opinion No. 510, the Commission found the subject pipeline to be high 8
risk due to its own decision-making and declined to assign an ROE above the 9
median of the zone of reasonableness. 134 FERC ¶ 61,129 at PP 269-270. 10
Q. Is Northern’s low risk the result of good management? 11
A. On balance, Northern’s low-risk position is likely due in part to management and 12
in part to circumstances beyond management’s control. According to Moody’s 13
and S&P, Northern’s management is not a factor influencing its best-in-class 14
ratings. S&P’s rating analysis lists “management and governance” as 15
“Satisfactory (no impact).” Ex. S-0039 at 100. Moody’s rating analysis equalizes 16
its rating for Northern with its forward-looking “scorecard-indicated outcome,” 17
and management is a supplementary consideration in Moody’s methodology that 18
does not directly impact a natural gas pipeline’s ratings scorecard. Ex. S-0039 at 19
191 and 210-229. In other words, Moody’s does not adjust Northern’s rating, 20
either upward or downward, due to its evaluation of Northern’s management. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 37 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 34 of 45

Northern itself cites its historical ability to fend off competition (Ex. NNG-1
00001 at 28:5-29:2), strong customer service, and reliability as factors in its 2
sustained success. Id. at 22:10-23. Mastio and Company surveys Northern’s 3
customer base and ranks it first among mega-pipelines and second among U.S. 4
interstate pipelines. Id. and Ex. S-0039 at 12. Furthermore, whatever decreased 5
risk Northern faces due to its strong balance sheet (i.e. low leverage) is a direct 6
result of management decisions. 7
Q. Are you aware of any cases in which the Commission has found a natural gas 8
pipeline to face low risk and assigned an ROE below the median result? 9
A. No. 10
Q. Does Northern believe that it should be awarded a lower-than-median ROE 11
because of its low risk? 12
A. No. Ex. NNG-00056 at 57:3-58:2. 13
Q. What is your opinion on Northern’s appropriate ROE? 14
A. In my opinion, Northern faces lower risk than the proxy group and other pipelines. 15
Northern’s risk-reducing characteristics constitute “highly unusual circumstances 16
that indicate an anomalously. . . low risk,” Opinion No. 524, 142 FERC ¶ 61,197 17
at P 382, and set it clearly outside “a broad range of average risk. . .” Id. Northern 18
should therefore be treated as low risk and awarded an ROE below my calculated 19
median of 10.98 percent and greater than or equal to the minimum of my 20
calculated zone of reasonableness (9.20 percent). I recommend 10.01 percent for 21
the reasons summarized below, but any ROE within that range for Northern would 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 38 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 35 of 45

be consistent with Commission precedent. 1
Q. Why is 10.01 percent the appropriate ROE for Northern? 2
A. Northern is a lower-than-average risk natural gas pipeline and should be awarded 3
an ROE below the median (10.98 percent) under Commission precedent. The 4
minimum ROE of my calculated zone of reasonable ROEs under the 5
Commission’s current methodology is 9.20 percent. No explicit methodology for 6
deriving and placing an ROE within the lower half of the zone indicated by the 7
minimum ROE of the zone and the median presently exists in Commission 8
precedent. In prior cases where a pipeline was judged to be above-average risk for 9
reasons beyond the control of management, the Commission set the subject 10
pipeline’s a ROE at the maximum of the relevant zone, implying that here 11
Northern should be assigned an ROE at the low end of the zone if its low-risk 12
position is not the result of good management. In a case where the Commission 13
agreed that a pipeline was low risk as the result of good management, the 14
Commission still placed the ROE at the median of the range (i.e. it declined to 15
lower the assigned ROE from the average-risk level). Transcontinental Gas Pipe 16
Line Corporation, 85 FERC ¶ 61,323 at 62,271-274 (1998) (Opinion No. 414-B). 17
Finally, in my opinion, Northern’s low risk position is due partly to good 18
management and partly due to its size, scope, geographic position, and other 19
factors discussed above that are generally beyond management’s control. 20
There is no obvious adjustment to Northern’s ROE that would equalize its 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 39 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 36 of 45

non-management-related risk-adjusted ROE with that of an average-risk pipeline. 1
Risk is subjective and unquantifiable. Since the Commission assigns the median 2
ROE to a broad range of average risk pipelines, however, and Northern, in my 3
opinion falls outside of this broad range, an ROE below the median result is 4
appropriate for Northern. 5
Therefore, Northern’s ROE should be placed above 9.20 percent and below 6
10.98 percent. To choose a value within this truncated range, I calculated the 7
median of the lower half of the range, which is simply the first quartile of the 8
range (a value that is above 25 percent and below 75 percent of the data in the 9
range). This approach recognizes the Commission’s preference to use the median 10
as the measure of central tendency of the ROE range in pipeline proceedings. 11
Opinion No. 486, 117 FERC ¶ 61,077 at P 175. The average of the median of the 12
lower half of the DCF model results and median of the lower half of the CAPM 13
results is 10.01 percent, my recommended ROE for Northern. The midpoint of the 14
lower half of the zone of reasonableness (i.e., the average of the minimum, 9.20 15
percent, and median, 10.98 percent) is 10.09 percent, eight basis points higher than 16
the result of averaging the medians of the lower halves of the range. 17
V. CAPITAL STRUCTURE 18

Q. What is your recommended capital structure for Northern? 19

A. I recommend a capital structure for Northern of 64.21 percent equity, 35.79 20
percent debt based on Northern’s capital structure as of December 31, 2022. Ex. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 40 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 37 of 45

S-0040 at 4. In November of 2022, Northern’s parent BHE informed investors of 1
its intent for Northern to issue an additional $400 million in debt in the first half of 2
2023 in order to “[m]anage capital structure.” Ex. S-0039 at 19. At the time of 3
this writing, this planned additional debt is not a known and measurable change to 4
Northern’s capital structure during the Test Period. 5
Q. What is Northern’s requested capital structure? 6

A. Northern’s as-filed capital structure consists of 63.61 percent equity and 36.39 7
percent debt, based on Northern’s projected year-end 2022 capital structure as of 8
March 31, 2022. Exs. NNG-00039 at 3:2-10 and NNG-00082. 9
Q. What does Commission policy prescribe for the determination of the capital 10
structure of a natural gas pipeline? 11

A. The Commission has a three-pronged test which uses a pipeline’s own capital 12
structure if the pipeline issues its own debt (not guaranteed by its parent 13
company), has its own credit rating, and does not feature an excessive equity ratio 14
relative to members of the proxy group and to other recent Commission-approved 15
capital structures. Transcontinental Gas Pipe Line Corporation, 80 FERC ¶ 16
61,157, at 61,667 (1997) (Opinion No. 414), as later modified by the Commission 17
on rehearing in Opinion No. 414-A, 84 FERC ¶ 61,084 at 61,415. 18
Q. Does Northern meet the Commission’s three-prong test for use of its own 19
capital structure? 20

A. Yes. Northern has “its own bond rating separate from that of its parent,” (Opinion 21
No. 414-A, 84 FERC ¶ 61,084 at 61,415; Exs. S-0038 at 33 and S-0039 at 97-106, 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 41 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 38 of 45

185-192), issues its own non-guaranteed debt to third parties (Ex. NNG-00039 at 1
4:18-5:8), and has a capital structure reasonably consistent with the proxy group 2
and Commission precedent. 3
Q. Why is Northern’s capital structure not excessive relative to the proxy group 4
and prior Commission determinations? 5

A. Northern’s 64.21 percent equity-to-capitalization ratio is higher than the proxy 6
group members’, which range from 38.17 percent to 50.35 percent and average 7
44.12 percent. Ex. S-0038 at 41. In Opinion No. 414-A, the Commission stated 8
that it will not “require that a pipeline’s equity ratio be within the range 9
established by the proxy companies . . . .” 84 FERC ¶ 61,084 at 61,419. In my 10
opinion, Northern’s equity ratio is not “so far outside the range of other equity 11
ratios approved by the Commission and the range of proxy company equity ratios 12
that it is unreasonable.” Id. at 61,413. 13
The Commission has approved equity ratios of 68.86 percent, 64.29 14
percent, 61.79 percent, and 59.97 percent. See Pacific Gas Transmission 15
Company, 62 FERC ¶ 61,109 at 61,778-79 (1993); Williams Natural Gas 16
Company, 84 FERC ¶ 61,080, at 61,355-56 (1998); Panhandle Eastern Pipe Line 17
Company, 71 FERC ¶ 61,228 at 61,827-28 (1995) (Panhandle I); and Panhandle 18
Eastern Pipe Line Company, 74 FERC ¶ 61,109, at 61,359-61 (1996) (Panhandle 19
II). In the Panhandle I and Panhandle II cases, the Commission approved the 20
subject pipeline’s equity ratios of 61.79 percent and 59.97 percent despite being 21
outside the range of equity ratios for the proxy group. 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 42 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 39 of 45

In the most recent Commission decision in a natural gas pipeline 1
proceeding, Opinion No. 885, the Commission agreed that the Initial Decision 2
“appropriately adopted [the pipeline’s] actual capital structure” of 62.94 percent 3
equity and 37.06 percent debt, though the Commission reversed the Initial 4
Decision in requiring the pipeline, because of its status as a master limited 5
partnership, to deduct accumulated deferred income taxes from its equity. 181 6
FERC ¶ 61,211 at PP 97-98. The Commission also found that an equity ratio for a 7
natural gas pipeline of 60 percent was not anomalous in 2015. El Paso Natural 8
Gas Company, L.L.C., 152 FERC ¶ 61,039, at P 137 (2015) (Opinion No. 517-A). 9
Q. Are you aware of any pipeline case in which the Commission rejected use of 10
an equity ratio of 64.21 percent or lower because it was considered excessive? 11

A. No. 12
Q. What is Northern’s capital structure? 13
A. 64.21 percent equity and 35.79 percent debt. Ex. S-0040 at 4. 14
Q. Are any adjustments to Northern’s capital structure needed? 15
A. No. 16
VI. COST OF LONG-TERM DEBT 17
Q. What is Northern’s as-filed cost of debt? 18

A. As shown on Northern’s Statement F-3, shown in Exhibit NNG-00083, its as-filed 19
cost of debt is 4.15 percent, based on Northern’s projected cost of debt as of 20
December 31, 2022. Exs. NNG-00039 at 4:18-5:8 and NNG-00083. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 43 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 40 of 45

Q. Are any adjustments to Northern’s cost of debt calculations needed? 1

A. No. 2
Q. Is Northern’s cost of debt the appropriate ratemaking cost of debt to assign to 3
Northern? 4

A. Yes. The cost of long-term debt must be consistent with the capital structure used. 5
See BP Pipelines (Alaska) Inc., et al., 119 FERC ¶ 63,007, at P 224 (2007), aff’d 6
on this issue, 123 FERC ¶ 61,287 at PP 197-198 (Opinion No. 502); Enbridge 7
Pipelines (KPC), 100 FERC ¶ 61,260, at P 97 (2002); Michigan Gas Storage 8
Company, 87 FERC ¶ 61,038, at 61,166 (1999). Since the appropriate capital 9
structure for Northern is its own, the appropriate cost of debt is Northern’s cost of 10
debt as of December 31, 2022, the end of the Test Period. 11
Q. What is Northern’s cost of debt as of December 31, 2022? 12

A. 4.15 percent. Ex. S-0040 at 5. 13
VII. AFTER-TAX WEIGHTED AVERAGE COST OF CAPITAL 14

Q. What is your recommended After-Tax, Weighted Average Cost of Capital for 15
Northern in this proceeding? 16

A. My recommended capital structure, cost of debt, and ROE result in an After-Tax 17
Weighted Average Cost of Capital for Northern of 7.91 percent. Ex. S-0038 at 45. 18
Q. How does your recommended cost of capital compare to Northern’s as-filed 19
cost of capital? 20

A. Northern’s as-filed cost of capital is 10.45 percent. Ex. NNG-00039 at 5:9-15. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 44 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 41 of 45

VIII. RESPONSES TO NORTHERN’S TESTIMONY 1
A. ROE CALCULATIONS 2
Q. What is Northern’s as-filed ROE, and how was it calculated? 3
A. 14.05 percent, which is the average of the median results of Northern witness 4
Bulkley’s DCF model and CAPM results. Ex. NNG-00056 at 4:2. See also Ex. 5
NNG-00059 at 1. 6
Q. Is Northern’s filed ROE calculated in accordance with Commission policy? 7
A. No. I disagree with Northern’s choice of a proxy group, as I further discuss below. 8
Q. How does your proxy group compare to Northern’s? 9
A. Northern includes, and I exclude, ONEOK, Inc. (ONEOK) and Enterprise 10
Products Partners, LP (Enterprise) in the proxy group. Northern excludes, and I 11
include, National Fuel and Kinder Morgan (in the CAPM, as discussed above) in 12
the proxy group. Both Northern and I include Enbridge, TC Energy, and Williams 13
in the proxy group. Ex. NNG-00056 at 27:2-40:11. 14
Q. Why is ONEOK ineligible for the proxy group? 15
A. Northern witness Bulkley’s calculations (Exhibit No. NNG-00056 at 36:3-4) 16
demonstrate that ONEOK has insufficient assets devoted to and income derived 17
from natural gas pipeline operations. Natural gas liquids and natural gas gathering 18
and processing are generally riskier than natural gas pipeline operations, (Opinion 19
No. 486-B, 126 FERC ¶ 61,034 at P 86), and not regulated under the Natural Gas 20
Act. In Opinion No. 486-B, the Commission allowed a combined oil and gas 21
transportation company into the proxy group partly on the basis that its non-22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 45 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 42 of 45

natural gas transportation businesses did not predominate or outweigh natural gas 1
transportation. Id. P 75. ONEOK’s natural gas liquids business substantially 2
outweighs its natural gas transportation business and is ineligible for the proxy 3
group under Commission precedent. 4
Q. Why is Enterprise ineligible for the proxy group? 5
A. Witness Bulkley’s calculations demonstrate that Enterprise has insufficient assets 6
devoted to and income derived from natural gas pipeline operations. Ex. NNG-7
00056 at 32:8-9. Natural gas liquid and crude oil pipelines are generally riskier 8
and are regulated under the Interstate Commerce Act, not the Natural Gas Act. 9
Enterprise’s natural gas liquids, crude oil, and refined products operations 10
predominate its natural gas transportation business and are ineligible for the proxy 11
group under Commission precedent. 12
Q. Why does Northern exclude National Fuel from its proxy group? 13
A. Witness Bulkley screened companies for inclusion in the proxy group by limiting 14
her search to companies classified by Value Line as “Oil/Gas Distribution” or 15
“Pipeline MLP,” while National Fuel is classified as “Natural Gas (Diversified).” 16
Ex. NNG-00056 at 26:4-5. 17
Q. Are Northern’s ROE calculations reliable indicia of an appropriate ROE for 18
Northern in this proceeding? 19
A. For the reasons described above, no. Northern faces lower-than-average risk, and 20
Northern’s proxy group is incorrectly constructed under Commission precedent. 21
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 46 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 43 of 45

B. RISK 1
Q. What is Northern’s view of its relative risk? 2
A. By requesting the median of its calculated zone of reasonableness for its ROE, 3
Northern takes the position that it faces average risk. Northern witness Bulkley 4
states, “Northern is generally comparable to the proxy group companies, in terms 5
of market area access, access to production regions and competitive market 6
conditions for the pipeline delivery service. Therefore an ROE set at the median 7
result of that methodology is reasonable.” Ex. NNG-00056 at 57:11-14. 8
Q. Do you agree with Northern’s view of its risk? 9
A. No. As discussed above, there is overwhelming information that supports 10
Northern faces low business and financial risk relative to the proxy group and 11
other natural gas pipelines. 12
Q. What arguments regarding risk does Northern witness Demman put 13
forward? 14
A. Witness Demman discusses the nature and sources of risks that demand for 15
Northern’s services will decline but does not take a position on Northern’s risk 16
relative to the proxy group or other natural gas pipelines. The risks witness 17
Demman identifies apply similarly to other natural gas pipelines and do not 18
meaningfully inform an assessment of Northern’s appropriate placement within 19
the zone of reasonableness, which is based on Northern’s risk relative to the proxy 20
group and other natural gas pipelines. See generally Ex. NNG-00001 at 11:8-21
38:10. 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 47 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 44 of 45

Q. Do you believe that witness Demman’s testimony identifies unusual or 1
anomalous risks facing Northern? 2
A. No. While Northern undoubtedly faces some risk, like all businesses, witness 3
Demman does not identify risks facing Northern that set it apart from other natural 4
gas pipelines. The Commission’s standard for selecting an ROE within the zone 5
of reasonableness is not based on whether a company faces any risk at all, but 6
rather on whether a company faces anomalous risks relative to the proxy group 7
and other natural gas pipelines. Available data indicates that all proxy group 8
members confront greater business and financial risks than Northern. 9
Q. What arguments regarding risk does Northern witness Bulkley put forward? 10
A. Witness Bulkley discusses the interrelated impacts of monetary policy, inflation, 11
and capital market conditions but does not distinguish the effects of these 12
macroeconomic dynamics on Northern relative to their effects on other natural gas 13
pipelines or the members of the proxy group. Ex. NNG-00056 at 7:17-19:3. 14
Overall, Northern has not articulated factors unique to it that distinguish it from 15
other interstate natural gas pipelines or the proxy group and, importantly, has not 16
addressed the extensive information that demonstrates it is low risk. 17
IX. CONCLUSION 18
Q. Please summarize your testimony. 19
A. Northern should be assigned an ROE of 10.01 percent, a capital structure of 64.21 20
percent equity and 35.79 percent debt, and a cost of debt of 4.15 percent. The 21
appropriate ROE is the average of the medians of the lower half of results of the 22
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 48 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037
Page 45 of 45

DCF model and the CAPM. Northern faces lower risk than the proxy group and 1
other natural gas pipelines, and therefore it should be assigned an ROE below the 2
median. Northern meets the Commission’s requirements for use of its own capital 3
structure and cost of debt. 4
Q. Does this conclude your testimony? 5
A. Yes. 6
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 49 of 51
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 50 of 51
Northern Natural Gas Company
Docket No. RP22-1033-000
Exhibit S-0037

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

Northern Natural Gas Company ) Docket No. RP22-1033-000

CERTIFICATE OF Alexander Gill

I, Alexander Gill, declare under penalty of perjury that I am the author of the foregoing
testimony, that the facts set forth herein are true and correct to the best of my knowledge,
and that if asked the same questions contained in the text, I would give the answers
contained in the testimony.

/s/ Alexander Gill March 3, 2023
Alexander Gill
Exhibit No. 2 Case No. INT-G-23-03 Intermountain Gas Company Page 51 of 51

EXHIBIT NO. 3

CASE NO. INT-G-23-03

INTERMOUNTAIN GAS COMPANY

Intermountain Gas Company Biogas Standards
(6 pages)
Exhibit No. 3 Case No. INT-G-23-03 Intermountain Gas Company Page 1 of 6
Exhibit No. 3 Case No. INT-G-23-03 Intermountain Gas Company Page 2 of 6
Exhibit No. 3 Case No. INT-G-23-03 Intermountain Gas Company Page 3 of 6
Exhibit No. 3 Case No. INT-G-23-03 Intermountain Gas Company Page 4 of 6
Exhibit No. 3 Case No. INT-G-23-03 Intermountain Gas Company Page 5 of 6
Exhibit No. 3 Case No. INT-G-23-03 Intermountain Gas Company Page 6 of 6

EXHIBIT NO. 4

CASE NO. INT-G-23-03

INTERMOUNTAIN GAS COMPANY

Current T-3 Tariff Showing Proposed Changes
(1 page)
I.P.U.C. Gas Tariff
Rate Schedules
Twenty-Second Third Revised Sheet No. 8 (Page 1
of 1)
Name of Utility Intermountain Gas Company
Issued by: Intermountain Gas Company
By: Lori A. Blattner Title: Director – Regulatory Affairs
Effective: October July 1, 20232
Rate Schedule T-3 INTERRUPTIBLE DISTRIBUTION TRANSPORTATION SERVICE
AVAILABILITY:
Available at any mutually agreeable delivery point on the Company's distribution system to any customer
upon execution of a one -year minimum written service contract for interruptible transportation service.
MONTHLY RATE:
Per Therm Charge: Block One: First 100,000 therms transported @ $0.03771*
Block Two: Next 50,000 therms transported @ $0.01487*
Block Three: Over 150,000 therms transported @ $0.00496*
*Includes temporary purchased gas cost adjustment of ($0.00082)
ANNUAL MINIMUM BILL:
The customer shall be subject to the payment of an annual minimum bill based on annual usage of 200,000
therms. The deficit usage below 200,000 therms shall be billed at the T-3 Block 1 rate. An annual minimum
bill may not apply if the customer is a renewable natural gas production facility with annual net production
less than 200,000 therms and the customer is transporting renewable natural gas to a delivery point that is
utilized for off-system injection.
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for the cost of purchased gas as provided for in Rate Schedule PGA.
This adjustment is incorporated into the calculation of the Cost of Gas stated on customer bills.
SERVICE CONDITIONS:
1.All natural gas service hereunder is subject to the General Service Provisions of the Company's
Tariff, of which this Rate Schedule is a part.
2.This service does not include the cost of the customer's gas supply or the interstate pipeline capacity.
The customer is responsible for procuring its own supply of natural gas and transportation to
Intermountain's distribution system under this Rate Schedule.
3.The customer understands and agrees that the Company is not responsible to deliver gas supplies
to the customer which have not been nominated, scheduled, and delivered by the interstate pipeline
to the designated city gate.
4.The Company, in its sole discretion, shall determine whether or not it has adequate capacity to
accommodate transportation of the customer's gas supply on the Company's distribution system.
5.If requested by the Company, the customer expressly agrees to immediately curtail or interrupt its
operations during periods of capacity constraints on the Company’s distribution system.
Exhibit No. 4 Case No. INT-G-23-03 Intermountain Gas Company Page 1 of 1

EXHIBIT NO. 5

CASE NO. INT-G-23-03

INTERMOUNTAIN GAS COMPANY

Proposed T-3 Tariff
(1 page)
I.P.U.C. Gas Tariff
Rate Schedules
Twenty-Third Revised Sheet No. 8 (Page 1 of 1)
Name
of Utility Intermountain Gas Company
Issued by: Intermountain Gas Company
By: Lori A. Blattner Title: Director – Regulatory Affairs
Effective: July 1, 2023
Rate Schedule T-3 INTERRUPTIBLE DISTRIBUTION TRANSPORTATION SERVICE
AVAILABILITY:
Available at any mutually agreeable delivery point on the Company's distribution system to any customer
upon execution of a one-year minimum written service contract for interruptible transportation service.
MONTHLY RATE:
Per Therm Charge: Block One: First 100,000 therms transported @ $0.03771*
Block Two: Next 50,000 therms transported @ $0.01487*
Block Three: Over 150,000 therms transported @ $0.00496*
*Includes temporary purchased gas cost adjustment of ($0.00082)
ANNUAL MINIMUM BILL:
The customer shall be subject to the payment of an annual minimum bill based on annual usage of 200,000
therms. The deficit usage below 200,000 therms shall be billed at the T-3 Block 1 rate. An annual minimum
bill may not apply if the customer is a renewable natural gas production facility with annual net production
less than 200,000 therms and the customer is transporting renewable natural gas to a delivery point that is
utilized for off-system injection.
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for the cost of purchased gas as provided for in Rate Schedule PGA.
This adjustment is incorporated into the calculation of the Cost of Gas stated on customer bills.
SERVICE CONDITIONS:
1.All natural gas service hereunder is subject to the General Service Provisions of the Company's
Tariff, of which this Rate Schedule is a part.
2.This service does not include the cost of the customer's gas supply or the interstate pipeline capacity.
The customer is responsible for procuring its own supply of natural gas and transportation to
Intermountain's distribution system under this Rate Schedule.
3.The customer understands and agrees that the Company is not responsible to deliver gas supplies
to the customer which have not been nominated, scheduled, and delivered by the interstate pipeline
to the designated city gate.
4.The Company, in its sole discretion, shall determine whether or not it has adequate capacity to
accommodate transportation of the customer's gas supply on the Company's distribution system.
5.If requested by the Company, the customer expressly agrees to immediately curtail or interrupt its
operations during periods of capacity constraints on the Company’s distribution system.
Exhibit No. 5 Case No. INT-G-23-03 Intermountain Gas Company Page 1 of 1

RNG PRODUCER LETTER,

T-3 CUSTOMER NOTICE,

and

NEWS RELEASE

CASE NO. INT-G-23-03

INTERMOUNTAIN GAS COMPANY

(4 pages)

June 9, 2023 
RE: Case INT‐G‐23‐03 
Dear RNG Producer: 
Intermountain Gas Company (Intermountain) appreciates the opportunity to work with [Producer] as 
together our companies provide renewable natural gas (RNG) to customers in the western U.S market. 
This letter is to inform you that on June 9, 2023, Intermountain filed the above referenced Case 
regarding a change in Intermountain’s RNG operations with the Idaho Public Utilities Commission 
(Commission). 

This Case will serve to standardize service terms and conditions for all RNG producers that will utilize 
an Intermountain‐owned and operated compressor and related facilities (Export Facility) to inject RNG 
into Williams Northwest Pipeline (Northwest). To recover costs associated with operating the Export 
Facility, Intermountain proposes a new Export Facility Maintenance Fee (EFMF) that will be charged 
monthly to all RNG producers whose RNG would be injected into Northwest. In addition, Intermountain 
has proposed to establish a calculation methodology for the existing access fee. The access fee amount 
will not change, but the methodology to determine the existing amount is being formalized. Because 
the two RNG facilities [Producer] currently operates are located in areas that will not require use of the 
Export Facilities, your facilities will not be subject to the EFMF. This filing does not propose to change 
any other operating provisions pursuant to previous Commission Orders. Further, this Case does not 
propose to arbitrarily change terms or conditions of any executed contract or agreement between 
[Producer] and Intermountain. If the Commission approves this proposal and the resultant Commission 
Order conflicts with any existing contract term or condition, we hope to find mutually agreeable 
common ground to resolve any such difference.  

As with all Commission filings, Intermountain’s application is a proposal and is subject to public review 
and comment and to Commission jurisdiction. A copy of this application is available for public review 
on the Commission’s website (puc.idaho.gov) or at Intermountain’s website (www.intgas.com/rates‐
services/comission‐filings/). You can follow this Case, review all relevant subsequently filed documents 
or submit comments on the Commission website. 

If you have any questions, please call or email me. 

Regards, 

David Swenson 
Manager, Industrial Services 
[e-mail] 
(208) 377‐6118 

June 9, 2023

RE: INT-G-23-03

Dear Schedule T-3 Customer:

As your facility is a current Intermountain Gas Company (Intermountain) T-3 customer, this letter is to
inform you that on Friday, June 9, 2023, Intermountain filed a case with the Idaho Public Utilities
Commission (Commission) to update the previously approved RNG Facilitation Plan relative to
accounting for Renewable Natural Gas (RNG) injections into Intermountain’s system. The RNG
Facilitation Plan needs to be updated because to date, all RNG injected into Intermountain’s system has
been consumed on Intermountain’s distribution system. However, several new RNG projects propose
to inject RNG into areas of Intermountain’s system where there are few gas customers and overall
demand for gas is low. Because Intermountain’s system does not have the capacity to absorb all of the
RNG from these producers, some or all of it must be transported to a gate station with Northwest
Pipeline and injected “off-system” into the interstate pipeline system.

Specific to T-3 service, this Case requests authority for Intermountain to adjust the currently effective
T-3 Tariff to allow these affected RNG producers to elect T-3 service to transport their RNG volumes to
a new connection with Williams Northwest Pipeline. The current T-3 Tariff does not specify that the
delivery point for T-3 service could be a meter providing off-system injection and this Case seeks to
specify that authority.

The Company’s filings are subject to both public review and to approval by the Commission. A copy of
the Application is available at the Commission offices, on the Commission’s website
(www.puc.idaho.gov) and on Intermountain’s website (www.intgas.com).

If you have questions about this filing, please contact Nicole Gyllenskog or David Swenson via the
contact information below.

Sincerely,

Nicole Gyllenskog David Swenson
Mgr, Industrial Services Mgr, Industrial Services
Intermountain Gas Company Intermountain Gas Company
Office: [phone] Office: [phone]
Cell: [phone] Cell: [phone]
[e-mail] [e-mail]

Intermountain Gas files request to update Renewable Natural Gas Facilitation Plan

BOISE, ID – June 9, 2023 – Intermountain Gas Company on Friday filed a request with the Idaho Public
Utilities Commission to update its Renewable Natural Gas (RNG) Facilitation Plan. The request is to make
three changes to the plan:

1. Introduce a Maintenance Fee for RNG producers that require the use of Intermountain-owned export
facilities. The fee will be called the EFMF and will only apply to RNG producers needing a compressor
station to export gas to Northwest Pipeline.

2. Establish a calculation methodology for the existing access fee. The access fee amount will not change,
but the methodology to determine the existing amount is being established.

3. Clarify that Intermountain’s Tariff Schedule T-3 Interruptible Distribution Transportation Service will
be applicable to the transportation of RNG to points on Intermountain’s distribution system that
interconnect with Northwest Pipeline.

Transporting RNG for producers will have no impact to Intermountain Gas customers. RNG producers will
continue to pay for all startup costs associated with RNG projects, as well the cost of all access related
infrastructure and facilities, and monthly expenses incurred by on-going service to RNG producers.

Renewable Natural Gas is the term used to describe pipeline-quality biomethane produced from biomass.
Common sources of biomass used in the production of RNG are livestock operations, landfills, and wastewater
treatment facilities. It is interchangeable with natural gas, carbon neutral, and fully compatible with the U.S.
pipeline infrastructure. It can be used in homes and businesses, in manufacturing and heavy industries, for
electricity production, and as an alternative fuel for transportation.

From a greenhouse gas emissions perspective, RNG has the potential to provide benefits. RNG production
captures methane from animal waste and other biomass sources that otherwise would have directly entered the
atmosphere. When it is eventually combusted, the RNG releases significantly fewer greenhouse gas
emissions.

RNG also has the potential to provide a valuable new revenue stream for Idaho farmers. It may allow livestock
operations to convert waste into a beneficial supplementary revenue source. The Idaho Department of
Agriculture reports that Idaho is the fourth largest milk producing state in the nation. With the large number of
dairies, the state has seen increased activity around dairy RNG projects over the past year. As neighboring states
implement or look to implement policies that encourage or mandate the use of renewable sources of energy,
including RNG, Idaho is in a prime location with the necessary biomass to produce and transport a significant
amount of RNG to these markets.

Intermountain Gas Company is a natural gas distribution company serving approximately 412,500 residential,
commercial and industrial customers in 74 communities in southern Idaho. Intermountain is a subsidiary of
MDU Resources Group, Inc., a member of the S&P MidCap 400 and the S&P High-Yield Dividend Aristocrats
indices that provides essential products and services through its regulated energy delivery and construction
NEWS RELEASE
services businesses. For more information about MDU Resources, see the company’s website at www.mdu.com.
For more information about Intermountain, visit www.intgas.com.

Media Contact: Mark Hanson at 701-530-1093 or [e-mail].