BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MONTANA DOCKET NO. D2016.9.68 Application for Authority to Change and Establish Natural Gas Delivery Service and Production Rates Revenue Requirement (Phase One) Allocated Cost of Service and Rate Design (Phase Two) TESTIMONY AND EXHIBITS STATEMENTS & WORKPAPERS (PHASE TWO) May 31, 2017
164
Embed
DOCKET NO. D2016.9 - NorthWestern Energy...Docket No. 02016.9.68 Phase Two Transmittal Letter May31, 2017 Page 3 of 3 NorthWestern's attorneys in this matter are: Mr. Al Brogan NorthWestern
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
BEFORE THE PUBLIC SERVICE COMMISSION OF THE STATE OF MONTANA
DOCKET NO. D2016.9.68
Application for Authority to Change and Establish Natural Gas Delivery Service and Production Rates
Revenue Requirement (Phase One)
Allocated Cost of Service and Rate Design (Phase Two)
TESTIMONY AND EXHIBITS STATEMENTS & WORKPAPERS
(PHASE TWO)
May 31, 2017
r NorthWestern Energy
Delivering a Bright Future
Mr. Will Rosquist Administrator, Regulatory Division Montana Public Service Commission 1701 Prospect Avenue PO Box 202601 Helena, MT 59620-2601
May 31, 2017
RE: Docket No. 02016.9.68 - In the Matter of NorthWestern Energy's Application for Approval to Change and Establish Natural Gas Delivery Service and Production Rates - Phase Two - Allocated Cost of Service and Rate Design
Dear Mr. Rosquist:
NorthWestern Corporation, d/b/a NorthWestern Energy ("NorthWestern"), submits its Application for Phase Two - Allocated Cost of Service and Rate Design in Docket No. D2016.9.68. An original and ten copies are enclosed.
On September 2, 2016, NorthWestern filed its Motion to Bifurcate this Rate Case. The Commission granted NorthWestern's Motion. Ultimately, the Commission approved NorthWestern's request that the Phase Two portion of this docket be filed no later than May 31 , 2017.
NorthWestern retained Management Applications Consulting, Inc. ("MAC") to · complete the required allocated cost of service studies:
• embedded cost of service - transmission , distribution , storage, and production; and
• marginal cost of service - production.
As described in testimony, the embedded cost of service studies performed by MAC are well-developed , thorough analyses that provide a sound basis for rate development.
MAC also developed the rate design proposals in this filing with certain guidance from NorthWestern as described in the testimony.
11 EParkSt I Butte, MT59701-1711 I 0 406-497-1000 I F 406-497-2535 NorthWestern Energy.com
Docket No. 02016.9.68 Phase Two Transm ittal Letter May31 , 2017 Page 2 of 3
NorthWestern has also proposed a revision to its Natural Gas Tariff, Rule 6 -Line Extensions.
NorthWestern formed a stakeholder group that included NorthWestern employees, a representative of the Montana Consumer Counsel ("MCC"), two Commission staff members, and other interested parties to explore the rationale for, and the presentation and design of, a potential natural gas utility decoupling mechanism proposal. Four meetings were held. NorthWestern ultimately determined that it would not make a proposal for a natural gas decoupling mechanism at this time.
Documents submitted with this filing are:
1. Application ;
2. Marked-Up Tariffs;
3. Prefiled Direct Testimony and Exhibits of Joe Schwartzenberger;
4. Prefiled Direct Testimony and Exhibits of Paul M. Normand of MAC;
5. Statement L -Allocated Cost of Service; and
6. Statement M - Rate Design.
Three copies of this letter and documents submitted herewith are being delivered to the MCC. One copy of this filing is being served on the parties of record in Phase One of this docket.
The NorthWestern employee responsible for answering questions concerning this rate change request or for inquiries to the appropriate members of the Utility Staff is:
Joe Schwartzenberger Regulatory Affairs Department NorthWestern Energy 11 East Park St. Butte, MT 59701 (406) 497-3362 joe.schwartzenberger@northwestern .com
Docket No. 02016.9.68 Phase Two Transm ittal Letter May31, 2017 Page 3 of 3
NorthWestern's attorneys in this matter are:
Mr. Al Brogan NorthWestern Energy 208 N. Montana, Suite 205 Helena, Montana 59601 Tel. (406) 443-8903 al.brogan@northwestern .com
Ms. Ann Hill NorthWestern Energy 208 N. Montana Ave., Suite 205 Helena, Montana 59601 Tel. (406) 444-8110 ann [email protected]
Along with Joe Schwartzenberger, Al Brogan , and Ann Hill, please add Connie Moran to the official service list in this docket to receive copies of all documents. NorthWestern also requests that all electronic correspondence related to this filing be sent to [email protected].
If there are any questions in this regard , I can be reached at (406) 497-3362.
aoe Schwartzenberger Director of Regulatory Affairs
1
AL BROGAN NorthWestern Energy 208 N. Montana, Suite 205 Helena, Montana 59601 Tel. (406) 443-8903 [email protected] ANN HILL NorthWestern Energy 208 N. Montana, Suite 205 Helena, MT 59601 Tel. (406) 444-8110 [email protected] Attorneys for NorthWestern Energy
DEPARTMENT OF PUBLIC SERVICE REGULATION BEFORE THE PUBLIC SERVICE COMMISSION
OF THE STATE OF MONTANA IN THE MATTER OF NorthWestern’s ) REGULATORY DIVISION Request for Authority to Change and ) DOCKET NO. D2016.9.98 Establish Natural Gas Delivery Service and ) Production Rates – Phase Two Allocated ) Cost of Service and Rate Design
NorthWestern Energy’s Application for Phase Two
of this Docket
NorthWestern Corporation d/b/a NorthWestern Energy (“NorthWestern”) respectfully
submits this Application for Phase Two – Allocated Cost of Service and Rate Design
(“Application – Phase Two”) in this Docket to the Montana Public Service Commission
(“Commission”). In support thereof, NorthWestern states as follows:
2
I. Applicant's full name and Post Office address are:
North Western Energy 11 East Park Butte, MT 59701
II. Applicant is NorthWestern Corporation doing business as NorthWestern Energy in the States
of Montana, South Dakota and Nebraska as a public utility.
III.
The following described tariff sheets are the natural gas sheets impacted by the proposals in
this submittal that are presently in effect in the State of Montana and on file with the
Commission. All other natural gas sheets remain as previously approved by the Commission:
Natural Gas Rates:
Schedule Description Sheet No.
D-RG-1 Residential Natural Gas Service 10.1 D-RGCA-1 Residential Gas Core Aggregation Service 11.1 D-GSG-1 General Natural Gas Service 20.1 D-GSGCA-1 General Service Gas Core Aggregation 21.1 D-FTG-1 Firm Transportation Natural Gas Service 25.1 D-ITG-1 Interruptible Transportation Natural Gas Service 27.1 T-FUGC-1 Firm Utility Gas Contract Service 30.1 T-FTG-1 Firm Transportation Natural Gas Service 80.1 T-ITG-1 Interruptible Transportation Natural Gas Service 85.1 T-FSG-1 Firm Storage Natural Gas Service 90.1 Rule No. 6 Line Extensions R-6.1
3
IV.
Applicant will submit new tariff sheets for natural gas service to customers served by
Applicant in the State of Montana upon approval of the changes proposed in this filing. The
proposed new sheets will replace the present tariff sheets as follows:
Natural Gas Rates:
Schedule Description Sheet No.
D-RG-1 Residential Natural Gas Service 10.1 D-RGCA-1 Residential Gas Core Aggregation Service 11.1 D-GSG-1 General Natural Gas Service 20.1 D-GSGCA-1 General Service Gas Core Aggregation 21.1 D-FTG-1 Firm Transportation Natural Gas Service 25.1 D-ITG-1 Interruptible Transportation Natural Gas Service 27.1 T-FUGC-1 Firm Utility Gas Contract Service 30.1 T-FTG-1 Firm Transportation Natural Gas Service 80.1 T-ITG-1 Interruptible Transportation Natural Gas Service 85.1 T-FSG-1 Firm Storage Natural Gas Service 90.1 Rule No. 6 Line Extensions R-6.1
V. North Western has prepared, and files concurrently with this Application, its allocated cost of
service and rate design information, including Testimony and Exhibits and Statements L and
M prepared in accordance with the information required in Commission rules Allocated Cost
of Service (ARM 38.5.176) and Rate Design (ARM 38.5.177).
VI.
Attached in support of this filing are the following documents that are by this reference made
a part hereof:
1. Marked-Up Tariffs;
2. Prefiled Direct Testimony and Exhibits of Joe Schwartzenberger;
3. Prefiled Direct Testimony and Exhibits of Paul M. Normand;
4. Statement L - Allocated Cost of Service; and
5. Statement M - Rate Design.
Wherefore, NorthWestern respectfully requests that the Commission:
1. Approve the Natural Gas Supply Rate Design proposals
as presented in this filing;
2. Approve the Natural Gas Line Extension Tariff revisions
as presented in this filing;
Respectfully submitted this 31 st day of May 2017.
NORTHWESTERN ENERGY
4
CERTIFICATE OF SERVICE
I hereby certify that the original and eleven copies of NorthWestern Energy’s Allocated Cost of Service and Rate Design (Phase Two) in Docket No. D2016.9.68, the Natural Gas General Rate Filing, has been hand delivered to the Montana Public Service Commission with three copies to the Montana Consumer Counsel this date. It has also been e-filed with the Montana Public Service Commission and emailed to counsel of record and to those requesting electronic service only. It has also been served upon the following persons by postage prepaid via first class mail as follows: Robert Nelson Montana Consumer Counsel PO Box 201703 Helena, MT 59620-1703 Pat Corcoran NorthWestern Energy 11 East Park Butte MT 59701 Joe Schwartzenberger NorthWestern Energy 11 East Park Butte MT 59701 Thorvald A. Nelson Holland & Hart 6380 S. Fiddlers Green Circle Suite 500 Greenwood Village CO 80111 Ann Hill NorthWestern Energy 208 N Montana Ave Suite 205 Helena MT 59601
George Donkin J W Wilson & Associates Rosslyn Plaza E - Suite 602 1621 North Kent Street Arlington VA 22209 Kevin Degenstein Chief Operating Officer Gas Natural Inc. PO Box 2229 Great Falls MT 59403 Dr. John W. Wilson J W Wilson & Associates Rosslyn Plaza E - Suite 602 1621 North Kent Street Arlington VA 22209 Will Rosquist Administrator, Regulatory Div. Public Service Commission 1701 Prospect Ave PO Box 202601 Helena, MT 59620-2601
Connie Moran NorthWestern Energy 11 East Park Butte MT 59701 Al Brogan NorthWestern Energy 208 N Montana Ave Suite 205 Helena MT 59601 Al Clark 142 Buccaneer Drive Leesburg FL 34788 Nikolas S Stoffel Holland & Hart 6380 S. Fiddlers Green Circle Suite 500 Greenwood Village CO 80111 Jed Henthorne President and General Manager Energy West Montana Inc. PO Box 2229 Great Falls MT 59403
DATED this 31st day of May 2017.
Connie Moran Administrative Assistant
NorthWestern Energy
NATURAL GAS TARIFF
Revised Canceling Revised
Schedule No. D-RG-1
DISTRIBUTION BUSINESS UNIT RESIDENTIAL NATURAL GAS SERVICE
Sheet No. Sheet No.
APPLICABILITY: Applicable to residential service, including single family dwellings and single family living units which are individually metered, in all territory served by the Utility Distribution Business Unit (Utility).
RATES: Net Monthly Bill: Monthly Service Charge per Meter:
Commodity Charges (Monthly $/Therm)
Total Rate
~ $ 8.25
Distribution Charge $ 0.2451485
Transmission Charge
Storage Charge
Gas Supply Charge
Def erred Gas Cost Amortization DBU GT AC Amortization TBU GT AC Amortization Storage GT AC Amortization
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer' s bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
LOW INCOME DISCOUNT: Customers of the Utility shall obtain a thirty percent (30%) discount during November 1st to April 30th from the above Regular Customer Rate(s) for residential usage, if they have satisfied the requirements for and are receiving energy assistance through the LIEAP program administered by the State of Montana Department of Public Health and Human Services.
(continued)
NATURAL GAS TARIFF
NorthWesterti Energy Canceling
44111 Revised 43rct Revised
Schedule No. D-RGCA-1
Sheet No. Sheet No.
11.1 11.1
DISTRIBUTION BUSINESS UNIT RESIDENTIAL GAS CORE AGGREGATION SERVICE
APPLICABILITY: Applicable to residential service, including single family dwellings and single family living units which are individually metered, being served under the Core Aggregation Gas Transportation Program (Program) in all territory served by the Utility Distribution Business Unit (Utility).
AVAILABILITY: Available to residential service customer loads, aggregated in accordance with Rate Schedule No. AGCT-1 and as is administratively feasible for the Utility.
RATES: Net Monthly Bill:
PLUS :
Monthly Service Charge per Meter:
Commodity Charges (Monthly $/Therm Distribution Charge
Transmission Charge
Storage Charge
DBU GT AC Amortization TBU GT AC Amortization Storage GTAC Amortization
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
LOW INCOME DISCOUNT: Customers of the Utility shall obtain a thirty percent (30%) discount during November 1st to April 30tl1 from the above Regular Customer Rate(s) for residential usage, if they have satisfied the requirements for and are receiving energy assistance through the LIEAP program administered by the State of Montana Department of Public Health and Human Services.
DEFERRED GAS COST: Pursuant to MPSC Order the above Deferred Gas Cost Amortization shall be in effect until the balance is extinguished.
GAS TRANSPORTATION ADWSTMENT CLAUSE: Pursuant to MPSC Order the above GTAC Amortization shall be in effect until the balance is extinguished.
(continued)
NorthWestenf Energy
NATURAL GAS TARIFF
Revised Canceling Revised
Schedule No. D-GSG-1
DISTRIBUTION BUSINESS UNIT GENERAL NATURAL GAS SERVICE
Sheet No. Sheet No.
APPLICABILITY: Applicable to commercial, industrial, multiple apartment buildings containing two or more dwelling units served through one meter, and other nonresidential core service in all territory served by the Utility Distribution Business Unit (Utility).
RATES: Net Monthly Bill: Monthly Servie Charge per Meter: Meters Rated @ Cu. Ft. per hour
0 to 300 301 to 1,000
1,001 to 2,000 2,001 to 5,000 5,001 to 10,000
10,001 to 30,000 >30,000
PLUS: Commodity Charges (Monthly $/Therm)
Distribution Charge
Transmission Charge
Storage Charge
Gas Supply Charge
Deferred Gas Cost Amortization DBU GT AC Amortization TBU GT AC Amortization Storage GT AC Amortization
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
DEFERRED GAS COST: Pursuant to MPSC Order the above Deferred Gas Cost Amortization shall be in effect until the balance is extinguished.
(continued)
NorthWestern Energy
NATURAL GAS TARIFF
41 st Revised Canceling 4ot1i Revised
Schedule No. D-GSGCA-1
DISTRIBUTION BUSINESS UNIT GENERAL SERVICE GAS CORE AGGREGATION
Sheet No. Sheet No.
21.1 21.1
APPLICABILITY: Applicable to commercial, industrial, multiple apartment buildings containing two or more dwelling units served through one meter, and other nonresidential core service, being served under the Core Aggregation Gas Transportation Program (Program) in all territory served by the Utility Distribution Business Unit (Utility) .
AVAILABILITY: Available to general service customer loads, aggregated in accordance with Rate Schedule No. AGCT-1 and as is administratively feasible for the Utility.
RATES: Net Monthly Bill: Monthly Servie Charge per Meter: Meters Rated @ Cu. Ft. per hour
0 to 300 301 to 1,000
1,001 to 2,000 2,001 to 5,000 5,001 to 10,000
10,001 to 30,000 >30,000
PLUS : Commodity Charges (Monthly $/Therm)
Distribution Charge
Transmission Charge
Storage Charge
DBU GT AC Amortization TBU GT AC Amortization Storage GT AC Amortization
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
(continued)
NATURAL GAS TARIFF
NorthWestern Energy Canceling
41 st Revised 40111 Revised
Sheet No. Sheet No.
Schedule No. D-FTG-1
DISTRIBUTION BUSINESS UNIT FIRM TRANSPORTATION NATURAL GAS SERVICE
APPLICABILITY: Applicable to Shippers for finn transportation service on the Utility Distribution System under the tenns of a Gas Transportation Service Agreement (Agreement) between the Utility Distribution Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).
RATES: Net Monthly Bill:
Monthly Service Charge per Meter:
Meters Rated @ Cu. Ft. per hour
2,000 to 5,000 5,000 to 10,000
10,001 to 30,000 >30,000
PLUS: Distribution Charge: ($/MDDQ)
Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)
MINIMUM BILL: Per respective contracts. $ 0.0017935 $ 0.0017935 TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PAYMENT: Billed amounts shall be considered past due if not paid by the due date shown on the bill. Past due bills are subject to a late payment charge in accordance with the provisions of Rate Schedule No. SGS-1 .
APPLICATION OF RATES :
Monthly Bill Components: Each month, Shipper' s bill shall consist of a Monthly Service Charge and a Reservation Charge.
1. Monthly Service Charge: The Monthly Service Charge shall be the product of the number of delivery meters at Shipper' s facility times the applicable Meter Charge(s) set forth above under RATES. If Shipper receives service under more than one rate schedule through a single meter, only one Service Charge per meter per month shall apply.
(continued)
NATURAL GAS TARIFF
NorthWesterii Energy
27th Revised Canceling 26th Revised
Sheet No. Sheet No.
27.1 27.1
Schedule No. D-ITG-1
DISTRIBUTION BUSINESS UNIT INTERRUPTIBLE TRANSPORTATION NATURAL GAS SERVICE
APPLICABILITY: Applicable to Shippers for interruptible transportation service on the Utility Distribution System under the terms of an Interruptible Gas Transportation Service Agreement (Agreement) between the Utility Distribution Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).
RATES: Net Monthly Bill:
Monthly Service Charge per Meter:
Meters Rated @ Cu. Ft. per hour
2,000 to 5,000 5,000 to 10,000
10,001 to 30,000 >30,000
PLUS: Distribution Charge: (Monthly Rate per Therm)
TAX PORTION OF RA TE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PAYMENT: Billed amounts shall be considered past due if not paid by the due date shown on the bill. Past due bills are subject to a late payment charge in accordance with the provisions of Rate Schedule No. SGS-1.
APPLICATION OF RATES: Monthly Bill Components: Each month, Shipper's bill shall include a Monthly Service Charge and an Interruptible Distribution Commodity Charge for the actual quantities of natural gas delivered for Shipper.
1. Monthly Service Charge: The Monthly Service Charge shall be the product of the number of delivery meters at Shipper 's facility times the applicable Meter Charge(s) set forth above. If Shipper receives service under more than one rate schedule through a single meter, only one service charge per meter per month shall apply.
2. Commodity Charge: The Monthly Commodity Charge shall be the produce of the actual monthly quantities of gas delivered to Shipper at Shipper ' s Point(s) of Delivery times the Maximum Distribution Commodity Rate set forth above, unless otherwise negotiated between the Utility and Shipper.
(continued)
NorthWestern Energy
NATURAL GAS TARIFF
Revised Canceling Revised
Schedule No. T-FUGC-1
TRANSPORTATION BUSINESS UNIT FIRM UTILITY GAS CONTRACT SERVICE
Sheet No. Sheet No.
APPLICABILITY: Applicable to natural gas utilities receiving service as of November 1, 1991 for Firm Utility Gas Contract Sales Service provided under terms and conditions of contracts with the Utility Transportation Business Unit (Utility) as approved by the Montana Public Service Commission.
RATES: Net Monthly Bill Monthly Service Charge per Meter:
Meters Rated @ Cu. Ft. per hour
10,001 to 30,000 >30,000
PLUS: Transmission Charges: Maximum Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)
Transmission Commodity Rate (Therm)
GT AC Amortization (Therm) PLUS : Storage Charges: Maximum Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)
Storage Commodity Rate (Therm)
Storage GT AC Amortization (MDDQ) PLUS: Gas Supply Charges (Therm)
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
(continued)
NorthWestern Energy
NATURAL GAS TARIFF
41 st Revised Canceling 40t11 Revised
Schedule No. T-FTG-1
TRANSPORTATION BUSINESS UNIT FIRM TRANSPORTATION NATURAL GAS SERVICE
Sheet No. Sheet No.
80.1 80.1
APPLICABILITY: Applicable to Shippers for firm transportation service on the Utility Transmission System under the terms of a Firm Gas Transportation Service Agreement (Agreement) between the Utility Transportation Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).
Maximum Monthly Reservation Rate for Maximum Daily Delivery Quantity (MDDQ)
Transmission Commodity Rate (Therm):
Maximum
Minimum
GT AC Amortization
Balancing Penalty Rate
Total Rate
$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70
$ 1.0323733 $ 1.0462758
$ 0.0079951 $ 0.0079285 $ 0.0017935
$ (0.0007528)
Tax Portion of Rate
$ 0.2538910 $ 0.3010417
$ 0.0020959 $ 0.0022812
Higher of $25 .001 Dekatherm Or 150% of Market Price
Rate Without Tax
$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70
$ 0.7784823 $ 0.7452341
$ 0.0058992 $ 0.0056473 $ 0.0017935
$ (0.0007528)
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
GAS TRANSPORTATION ADJUSTMENT CLAUSE: Pursuant to MPSC Order the above GTAC Amortization shall be in effect until the balance is extinguished.
MINIMUM BILL: Per respective contracts.
(continued)
NorthWesteni Energy
NATURAL GAS TARIFF
41 st Revised Canceling 40111 Revised
Schedule No. T-ITG-1
Sheet No. Sheet No.
TRANSPORTATION BUSINESS UNIT INTERRUPTIBLE TRANSPORTATION NATURAL GAS SERVICE
APPLICABILITY: Applicable to Shippers for interruptible transportation service on the Utility Transmission System under the terms of an Interruptible Gas Transportation Service Agreement (Agreement) between the Utility Transportation Business Unit (Utility) and Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).
RATES: Net Monthly Bill:
Monthly Service Charge per Meter:
Meters Rated @ Cu. Ft. per hour
5,000 to 10,000 10,001 to 30,000
>30,000 PLUS: Transmission Charge (Therm):
Maximum: Transmission Commodity Rate
Minimum: Transmission Commodity Rate
Balancing Penalty Rate
Unauthorized System Use Rate
Total Rate
$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70
$ 0.0411794 $ 0.0424136
$ 0.0017935
Tax Portion of Rate
$ 0.0104419 $ 0.0086686
Higher of $25 .00/ Dekatherm Or 150% of Market Price
$ 25.00
MINIMUM BILL: Per respective contracts.
Rate Without Tax
$ 95.25 $125.65 $136.90 $180.60 $303.75 $400.70
$ 0.0307375 $ 0.0337450
$ 0.0017935
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer' s bill.
PLUS: OTHER APPLICABLE CHARGES: All charges contained on other applicable rate schedules approved by the Public Service Commission of Montana.
PAYMENT: Billed amounts shall be considered past due if not paid by the due date shown on the bill. Past due bills are subject to a late payment charge in accordance with the provisions of Rate Schedule No. SGS-1 .
(continued)
NorthWestern Energy
NATURAL GAS TARIFF
Canceling 40th Revised 39t1i Revised
Schedule No. T-FSG-1
TRANSPORTATION BUSINESS UNIT FIRM STORAGE NATURAL GAS SERVICE
Sheet No. Sheet No.
APPLICABILITY: Applicable to Shippers for Firm Storage Service under the terms of a Firm Gas Storage Service Agreement (Agreement) between the Utility Transportation Business Unit (Utility) and the Shipper and as subject to Rate Schedule General Terms and Operating Conditions (Rate Schedule GTC-1).
RATES: Tax Portion of Rate Without Total Rate Rate Tax
TAX PORTION OF RATE: This rate represents the amount charged to customers for state and local taxes and fees and is separately disclosed on customer's bill.
APPLICATION OF RATES:
Monthly Bill Components: Each month, Shipper's bill shall include a Withdrawal Reservation Charge and, if applicable, an Injection Commodity Charge for the quantities of natural gas nominated by Shipper and received by Utility for injection into storage, a Withdrawal Commodity Charge for the quantities of natural gas nominated by Shipper and delivered by Utility from storage for Shipper's account and a Storage Capacity Charge.
1. Withdrawal Reservation Charge: The Monthly Withdrawal Reservation Charge shall be the product of the Shipper's Storage Maximum Daily Delivery Quantity (MDDQ) as set forth in the Agreement times the applicable rate set forth above.
2. Injection Commodity Charge: The Monthly Injection Commodity Charge shall be the product of the Shipper's nominated quantities of natural gas received by the Utility for injection into storage times the applicable rate set forth above.
3. Withdrawal Commodity Charge: The Monthly Withdrawal Commodity Charge shall be the produce of the Shipper's nominated quantities of natural gas delivered by the Utility from storage times the applicable rate set forth above.
4. Storage Capacity Charge: The Monthly Storage Capacity Charge shall be the product of the Shipper's storage balance at the end of the month times the applicable rate set forth above.
5. Discounting Rates: The Utility shall have the ability to discount the Monthly Withdrawal Reservation Rate set forth above if the Shipper can demonstrate that, as a direct result of the
(continued)
N ~-4-L""W"Z: .... N NATURAL GAS TARIFF oru1-weSLCTil
Energy Canceling
Rule No. 6
LINE EXTENSIONS
Revised Revised
Sheet No. Sheet No.
6-1 Free Main Line Extension Allowance - Upon application for natural gas Core service, the Utility shall make an extension of the distribution main pipeline free of charge to the Applicant for Service up to the level of cost shown below, but no greater than the entire actual cost of such line extension:
Residential Service Customer
All other Core Customers ($/Therm)
$ 900.00 $ 850.00 ~ $0.391
times the Utility ' s estimate of the annual Therm consumption of the Customer.
Non-Core Transportation Customers: Determined on an individual basis .
A. Applicant requesting installation of a gas service will receive a meter and regulator free of charge, but will be responsible for the cost of the service pipeline connecting the meter to the distribution main. Customer contributions toward the cost of the gas service are nonrefundable.
B. The Applicant for service shall furnish all necessary rights-of-way.
6-2 Extension Beyond Free Limit (See Rule No. 6-11)
A. Where a main extension cost exceeds the free limit specified above in Rule No. 6-1 , the Utility will require the Applicant for Service to pay the difference between the cost of the project and the main extension allowance. Whenever this customer cost is collected as an advance, if additional requests for service (new line taps) from this protected extension are received within 60 months from the date the extension is completed, the Utility will:
1. Collect from the new line tap an advance or contribution representing an amount equal to the average advance for all line taps on the main line extension, in addition to the new line tap.
2. Refund to previously connected line taps of the existing line, their successors or assignees, or the current owner(s) of the property such an amount as is required to reduce the average cost of the line tap to the average advance with all connected line taps sharing equally in the cost of the original protected line.
The Customer(s) of each line tap, as a group, will share any required advance for their line tap extension, equitably, in addition to the cost of their individual line extension. Additional advances and refunds associated with such line taps will be treated as specified in Rule No. 6-2 A above.
(continued)
JS-1
Department of Public Service Regulation 1 Montana Public Service Commission 2
Docket No. D2016.9.68 3 Natural Gas General Filing - Phase Two 4
NorthWestern Energy 5 6
7 8
PREFILED DIRECT TESTIMONY 9
OF JOE SCHWARTZENBERGER 10
ON BEHALF OF NORTHWESTERN ENERGY 11
12
Table of Contents 13
Description Starting Page No. 14
Witness Information 2 15
Purpose of Testimony 4 16
Ratemaking Elements 5 17
Overview of NorthWestern’s Allocated Cost of Service and RD Proposals 7 18
Embedded Cost of Service Study and Revenue Moderation 8 19
Natural Gas Supply Marginal Cost of Service Study 13 20
Rate Design Proposals 15 21
Bill Impacts 18 22
Natural Gas Tariff Changes 21 23
Revised ECOS 22 24
Future Use of the ECOS Method for Production and Delivery Services 23 25 26
Exhibits 27
Natural Gas Revenue Moderation Exhibit__(JS-1) 28
Bill Impacts Exhibit__(JS-2) 29
Computation of Free Primary Line Extension Allowances Exhibit__(JS-3) 30
31
JS-2
Witness Information 1
Q. Please state your name and business address. 2
A. My name is Joe Schwartzenberger. My business address is 11 East Park 3
Street, Butte, Montana 59701. 4
5
Q. By whom are you employed and in what capacity? 6
A. I am NorthWestern Energy’s (“NorthWestern” or “Company”) Director of 7
Regulatory Affairs. 8
9
Q. Please summarize your education and employment experience. 10
A. I attended Montana State University (“MSU”), receiving a Bachelor of Science 11
degree in Mechanical Engineering Technology in 1982. I also received a 12
Master of Business Administration degree from the University of Montana in 13
2000. During my career, I have attended various seminars and sessions 14
regarding engineering, business, utility, and regulatory subjects including the 15
University of Idaho Utility Executive Course and the American Gas 16
Association Executive Leadership Program for Energy Professionals. I am a 17
registered Professional Engineer in Montana. 18
19
After graduating MSU, I was employed by Bechtel Power Corporation as a 20
field engineer in Colstrip, Montana and began my career with the Montana 21
Power Company (“MPC”) in 1986 as a Plant Engineer in Colstrip. I relocated 22
to Butte, Montana with MPC and progressed through a number of 23
JS-3
engineering positions becoming Manager of Technical Services in 1993 with 1
responsibility for providing technical support for MPC’s Demand-Side 2
Management (“DSM”) programs. In 1997, I was promoted to Director of 3
Operations with responsibility for managing an unregulated energy services 4
subsidiary of MPC. In 2002, I transferred to MPC’s Government and 5
Regulatory Affairs Department as Manager of Regulatory Support Services 6
with primary responsibility for NorthWestern’s Universal System Benefits 7
(“USB”) and DSM programs. I was promoted to my current position in 2004. 8
9
Q. What are your responsibilities as Director of Regulatory Affairs? 10
A. In my capacity as director I am responsible for state and federal regulatory 11
activities, DSM and USB programs, and electric load research – collecting, 12
analyzing and managing electric load data to meet various internal and 13
external needs in Montana. 14
15
I regularly participate in the preparation and/or consideration of the testimony, 16
exhibits, and workpapers in NorthWestern’s proceedings before the Montana 17
Public Service Commission (“MPSC” or “Commission”) and the Federal 18
Energy Regulatory Commission (“FERC”). As relates specifically to this 19
testimony, I sponsored allocated cost of service and rate design (“RD”) 20
testimony in Docket No. D2012.12.94, NorthWestern’s last natural gas utility 21
general rate filing. 22
23
JS-4
Purpose of Testimony 1
Q. What is the purpose of your testimony in this proceeding? 2
A. I am NorthWestern’s policy witness for the natural gas allocated cost of 3
service and RD proposals in this filing which are based on the natural gas 4
transmission, distribution, and storage (“Delivery Services”) and natural gas 5
production (“Production Services”) revenue requirements presented in 6
NorthWestern’s rebuttal filing in Phase One of this docket (“Rebuttal Revenue 7
Requirement”) 1. My testimony: 8
1. Describes how the Rebuttal Revenue Requirement and the allocated 9
cost of service and RD elements contained in this filing are related; 10
2. Provides an overview of the allocated cost of service and RD 11
components included in this filing; 12
3. Introduces NorthWestern’s embedded cost of service (“ECOS”) 13
proposal including Delivery and Production Services; 14
4. Presents NorthWestern’s proposed revenue moderation of the ECOS 15
results; 16
5. Briefly discusses NorthWestern’s natural gas supply marginal cost of 17
service (“MCOS”) study and provides recommendations for use of the 18
results; 19
6. Introduces NorthWestern’s RD proposals; 20
1 The revenues reflecting NorthWestern’s Delivery Services rebuttal revenue requirement are included on Exhibit__(PJD-41), page 1, column P, lines 7-48, included with the Phase One Prefiled Rebuttal Testimony of Patrick J. DiFronzo. The revenues reflecting NorthWestern’s natural gas Production Services rebuttal revenue requirement are included on Exhibit__(PJD-42), page 1, column R, lines12-34, included with the Phase One Prefiled Rebuttal Testimony of Patrick J. DiFronzo.
JS-5
7. Presents the billing impacts of NorthWestern’s RD proposals that 1
reflect NorthWestern’s Rebuttal Revenue Requirement and revenue 2
moderation; 3
8. Proposes an update to the residential and general service Free Main 4
Line Extension Allowances in NorthWestern’s Natural Gas Line 5
Extension Policy to reflect the related RD proposals; and 6
9. Proposes the use of the ECOS allocation method for Production and 7
Delivery Services in future proceedings before the Commission. 8
9
Ratemaking Elements 10
Q. Please describe how the Rebuttal Revenue Requirement and the 11
allocated cost of service and RD proposals contained in this filing are 12
related. 13
A. Four specific ratemaking steps are incorporated in this proceeding, all of 14
which are regular components of general rate filings. These steps and the 15
resulting breakout of costs by non-interruptible customer rate class for 16
combined Delivery and Production Services are illustrated on page 1 of 17
Exhibit__(JS-1). A general description of each step follows: 18
Revenue Requirement – This step determines the test year natural gas 19
system revenue requirement based on operating expenses, taxes, 20
interest paid on debts owed, depreciation expense, and return on rate 21
base. Historic actual information is adjusted for known and 22
measurable changes occurring 12 months beyond the actual year. 23
JS-6
The Rebuttal Revenue Requirement presented in Phase One of this 1
docket is the basis for NorthWestern’s ECOS and RD proposals in this 2
filing. 3
4
Allocated Cost of Service – This step allocates the respective costs of 5
providing utility services that make up the total revenue requirement to 6
the various utility customer classes (e.g., Residential and General 7
Service) based on their use of Natural Gas Delivery Services and 8
Production Services. NorthWestern’s ECOS presented in this filing 9
reflects the use of embedded (accounting) cost allocation techniques, 10
and its MCOS for natural gas supply reflects the use of marginal cost 11
allocation techniques. These cost allocation methods are discussed in 12
the testimony of Paul M. Normand (“Normand Direct Testimony – 13
Phase Two”) of Management Applications Consulting. 14
15
Customer Class Revenue Moderation – This step adjusts the ECOS 16
class revenue requirements at equalized rate of return revenue levels 17
to mitigate the impacts some customer classes would experience if 18
rates were designed to collect the ECOS class revenue requirements. 19
Moderation can be thought of as the initial step in RD as it establishes 20
class revenue targets to be recovered via the proposed rates. 21
22
JS-7
Rate Design – This final step establishes the individual rates that are 1
ultimately used to bill customers. Rates are designed to collect the 2
moderated revenues on a class-by-class basis. The Delivery and 3
Production Services RD proposals included in this filing were guided 4
by the results of the ECOS studies. 5
6
Overview of NorthWestern’s Allocated Cost of Service and RD Proposals 7
Q. Please provide a brief overview of NorthWestern’s allocated cost of 8
service and RD proposals in this filing. 9
A. The allocated cost of service and RD proposals are presented in my 10
testimony and exhibits and in the Normand Direct Testimony – Phase Two, 11
along with Statement L and supporting workpapers, and Statement M and 12
supporting workpapers. This material is comprised of ECOS and MCOS/RD 13
analyses, results, and proposals for Delivery and Production Services. 14
15
Q. What are NorthWestern’s primary objectives for the Allocated Cost of 16
Service and RD portion of this filing? 17
A. NorthWestern’s primary objectives are the proper allocation of the costs of 18
providing Delivery and Production Services among the various customer 19
classes based on cost causation and the development of rate design 20
structures that recover these costs on that basis to the extent reasonable. As 21
a practical matter, costs should be allocated between classes of customers, 22
and rates should be designed to assure that customers make appropriate 23
JS-8
contributions to the costs they cause, while being mindful of other factors 1
important to sound rate design including bill impacts, for example. 2
3
Embedded Cost of Service Study and Revenue Moderation 4
Q. How generally was the ECOS study included in this filing developed? 5
A. Mr. Normand developed the ECOS study for purposes of determining 6
revenue requirement responsibility and the costs of the various components 7
of the services NorthWestern provides at equalized rate of return. His 8
testimony presents the methodologies used, the analyses he conducted, and 9
the associated results. 10
11
Q. Did NorthWestern use the ECOS results as the basis for class revenue 12
moderation and RD for this filing? 13
A. Yes. The Normand Direct Testimony – Phase Two discusses the application 14
of the ECOS model and changes/improvements that have been made to it for 15
purposes of this filing including incorporation of NorthWestern’s natural gas 16
production assets: Battle Creek, Bear Paw (NFR), and South Bear Paw 17
(Devon). 18
19
The ECOS moderation analysis is presented on page 2 of Exhibit__(JS-1) 20
and discussed further below. The ECOS study allocates the requested 21
Rebuttal Revenue Requirement among the customer classes based on costs 22
such that the sum of all of the revenue requirement responsibilities by 23
JS-9
customer class is equal to the Rebuttal Revenue Requirement. The ECOS 1
class revenue requirement responsibilities are then moderated to establish 2
revenue targets for each rate class. Because the moderated class revenues 3
are different than the ECOS class revenues, they result in revenue subsidies 4
for certain customer classes. The sum of the moderated class revenue 5
responsibilities also equals the Rebuttal Revenue Requirement. 6
7
Q. What is meant by moderation and why is it necessary? 8
A. NorthWestern’s moderation proposal simply modifies Mr. Normand’s full 9
ECOS class revenue requirement results to mitigate customer bill impacts. A 10
comparison of the revenue requirement responsibilities by customer class 11
resulting from the ECOS study to current rate revenues revealed some large 12
disparities and that some classes are being subsidized by other classes. 13
Revenue moderation gives consideration to the overall billing impact of 14
establishing class revenue targets for rate design which will, in total, equal the 15
full ECOS results. Consistent with prior practice, NorthWestern moderated 16
the ECOS study results to mitigate significant bill impacts by class. 17
18
Cost of service allocation studies embody a process aimed at assigning costs 19
to customers based on the services they receive. If one believes that rates 20
should be based solely on the concept that the “cost causer pays,” it would be 21
appropriate to use the ECOS study results at equalized rate of return to 22
establish rates in one step in this filing. Most, including NorthWestern, agree 23
JS-10
that while assigning costs to the cost causer is an important consideration in 1
setting rates, there are other considerations, such as bill impacts, that are 2
also important. The ECOS results suggest that significant changes in 3
revenue responsibilities for certain classes are in order. Over time, 4
NorthWestern believes it is important and proper to work toward achieving 5
rates that reflect costs in order to reduce inter-class subsidies. However, 6
given the large rate adjustments that would be required to achieve this 7
objective in a single rate case, NorthWestern recommends taking incremental 8
steps toward this objective and moderated the ECOS study results to that 9
end. 10
11
For example, the Distribution Business Unit (“DBU”) Firm Transportation 12
Service customer class would experience an increase of approximately 30% 13
over current rates if the results from the ECOS study were used. With 14
moderation, NorthWestern proposes that this customer class instead receive 15
a 9.81% increase, as shown on page 2 of Exhibit__(JS-1). I describe 16
NorthWestern’s overall approach to moderation below. 17
18
Q. Have you prepared an exhibit that reflects the combined effect by 19
customer rate class of the Rebuttal Revenue Requirement and the ECOS 20
and moderation proposals contained in this filing? 21
JS-11
A. Yes, page 2 of Exhibit__(JS-1) presents the proposed by-class cost 1
allocations before and after moderation. The following table can be used as a 2
guide to review this page: 3
Natural Gas Production and Delivery Services ECOS Revenue Moderation
Current Rate Revenues by class compared
to Proposed Rebuttal Revenue
Requirement Revenues by class resulting
from a uniform percent increase, including
dollar and percent differences.
Columns E, G, I, and J; Lines 7
to 21
Proposed ECOS Revenues compared to
Current Rate Revenues with related dollar
and percent differences. Columns N and O
present the combined impact of the
Rebuttal Revenue Requirement increase
and ECOS reallocations by class before
any moderation.
Columns E, L, N, and O; Lines
7 to 21
Proposed ECOS impacts only, including
dollar and percent differences.
Columns G, L, Q, and R; Lines
7 to 21
Proposed Embedded Moderated Revenues
compared to Current Rate Revenues with
related dollar and percent differences.
Columns E, N, O, and Q; Lines
23 to 38
Q. What general guidelines did NorthWestern use in establishing the 4
proposed moderated revenues? 5
A. As discussed above, the primary goal of moderation is to mitigate the billing 6
impacts that would otherwise result from implementation of the ECOS study 7
JS-12
results. The general guidelines NorthWestern used for moderation in this 1
filing were: 2
1. Consideration of bill impacts from the collective effects of the Rebuttal 3
Revenue Requirement, moderation, and RD proposals as described 4
below; 5
2. Consistent with Item 1 above, capping the maximum increase for any 6
class at 1.4 times the 7.01% overall system increase in revenue 7
requirement, or 9.81%; and 8
3. Providing no class a rate decrease even if the ECOS study showed a 9
decrease was necessary to achieve the cost of service. 10
11
Collectively, these guidelines move toward cost of service while maintaining 12
the basic goal of mitigating customer bill impacts. 13
14
Q. How did you perform moderation based on these guidelines? 15
A. Current rate revenues for the DBU Firm Transportation Service class are 16
about 30% less than its ECOS revenues at equalized rate of return. I applied 17
a 9.81% revenue increase to this class because, of all classes, it is farthest 18
from its cost of service. Refer to column G, line 29 on page 2 of Exhibit__(JS-19
1). I then distributed the resulting revenue deficiency of approximately $9 20
million to the remaining classes based on the shape of the ECOS revenues 21
for those classes. Refer to columns I, J, and L, lines 24 through 33, and 22
column L, lines 8 through 16. The resulting moderated class revenues and 23
JS-13
dollar and percent changes as compared to current rate revenues are 1
included in columns N, O, and Q, lines 23 through 32. 2
3
Current rate revenues for Firm Storage Natural Gas Service are above its 4
costs by about 10%. Consistent with the guidelines, this customer class did 5
not receive a decrease. 6
7
Natural Gas Supply Marginal Cost of Service Study 8
Q. Has NorthWestern included a MCOS study for Delivery Services? 9
A. No. Order No. 7249e in Docket No. D2012.9.94, at ¶ 61 “authorizes 10
NorthWestern to use its ECOS model for Delivery Services in its next cost of 11
service case.” This is that filing for the natural gas utility. 12
13
Q. Why did NorthWestern conduct a separate MCOS study for natural gas 14
supply? 15
A. NorthWestern conducted a MCOS study based on its interpretation of 16
Administrative Rule of Montana 38.5.176. While the Commission authorized 17
NorthWestern to use its ECOS model for Delivery Services in this filing, it did 18
not waive the requirement for a natural gas supply MCOS study. The MCOS 19
study is presented in the Normand Direct Testimony – Phase Two, which 20
discusses the methodologies Mr. Normand used and the analyses he 21
conducted. 22
23
JS-14
Q. Are NorthWestern’s RD proposals for Production Services based on the 1
MCOS study? 2
A. No. Mr. Normand discusses the results of the MCOS study and his 3
recommendation regarding use of them for RD. NorthWestern notes that the 4
differences between classes in natural gas supply winter marginal unit prices, 5
as adjusted to NorthWestern’s rebuttal revenue levels, are very small, about a 6
1% difference between the lowest and highest prices. The MCOS results do 7
indicate that winter marginal unit prices with demand and supply components 8
combined are about 55% higher than summer marginal unit prices (an 9
average of $0.312 per therm in the winter vs. $0.202 per therm in the 10
summer) as a result of estimated marginal demand costs in the winter only. 11
12
However, the winter unit prices are only about 12% higher than the proposed 13
all-in natural gas supply rate of $0.278 per therm (rounded to three decimals). 14
This all-in rate is the sum of the proposed Production Services with and 15
without property tax rate components in this filing and the April 1, 2017 16
purchase gas supply (natural gas tracker) rate component. NorthWestern 17
does not believe that this relatively small difference indicates the need to 18
increase the price customers pay for natural gas in the winter when, by virtue 19
of increased consumption for space heat and a tendency toward higher 20
purchase gas supply costs in the winter in normal years, natural gas bills for 21
most customers already rise dramatically. 22
23
JS-15
Rate Design Proposals 1
Q. How were rates developed in this filing? 2
A. Mr. Normand developed the rate designs based on his ECOS results and 3
NorthWestern’s revenue moderation. His testimony presents the criteria that 4
guided his general approach to rate design, the methodologies he used to 5
develop the rates, and the rates themselves. In particular, the proposed 6
rates, in combination with NorthWestern’s moderated class revenue targets, 7
result in improved price signals to customers while maintaining reasonable bill 8
impacts. 9
10
Q. Did NorthWestern make any specific requests of Mr. Normand regarding 11
rate design? 12
A. Yes. We specifically requested that the property tax components of 13
Production and Delivery Services rates be designed to collect the total 14
property taxes that are included in the Rebuttal Revenue Requirement less 15
any property taxes that are not addressed in the property tax tracker (e.g. 16
tribal taxes). NorthWestern also requested that the property tax rate 17
components be designed to collect the by-class property taxes determined by 18
the ECOS to the maximum extent practical. In Order No. 7501 entered in 19
Docket No. D2016.1.9, the Commission affirmed the benefits of transparent 20
rates that create a visible, calculable cost associated with property taxes for 21
customers. ¶ 6. The proposed RD furthers transparency relative to these 22
costs. 23
JS-16
NorthWestern also requested that Mr. Normand design one Production 1
Services rate (including with and without property tax components) for all core 2
classes. This is consistent with the Stipulation2 regarding future ratemaking 3
treatment for the production assets, and customers are familiar with a single 4
natural gas supply rate, which is easier to understand and administer. 5
6
Finally, NorthWestern requested that the increases in rates for DBU 7
Interruptible Transportation and Transmission Business Unit (“TBU”) 8
Interruptible Transportation services be the same as the increases to their 9
firm service class counterparts. This approach to rate design for the 10
interruptible transportation classes is consistent with the approach approved 11
in Docket No. D2012.9.94 and in Consolidated Docket Nos. D2007.7.82 and 12
D2009.9.129. 13
14
Q. Mr. Normand’s proposed customer service charges represent a 15
significant increase for some customer classes. Do you agree with his 16
recommendations? 17
A. Yes. As Mr. Normand explains, the ECOS results indicate the need to 18
increase customer service charges for all classes, and the increases reduce 19
intra-class subsidies. To put the proposed increases in perspective, it is 20
worth noting that in accordance with Order No. 7501, on January 1, 2017, 21
NorthWestern implemented a new rate design that, among other changes, 22
2 Stipulation and Settlement Agreement of NorthWestern Energy and the Montana Consumer Counsel presented to the MPSC in Phase One of this docket.
JS-17
removed all property taxes from customer service charges. The Commission 1
noted in ¶ 8 of Order No. 7501: 2
“…that by removing taxes from the monthly service fee that all 3
customers pay and calculating this amount as part of a volumetric rate 4
for taxes, that some customers within a particular class will pay less, 5
and some will pay more, as a result of adopting Option (a). However, 6
based on the evidence submitted by Mr. DiFronzo, the Commission 7
finds that the revenue shifting caused by the transfer of cost recovery 8
from monthly fixed charges to volumetric rates will have a minor impact 9
relative to the total bill amounts. Test. DiFronzo at Exh. PJD-2 & PJD-10
5. This effect may be addressed in future general natural gas and 11
electric rate cases.” 12
13
For example, the January 2017 change in rate design for the residential class 14
reduced the customer service charge from $7.35 per month to the current 15
charge of $5.80 per month, a 21% decrease. As detailed in his testimony, Mr. 16
Normand proposes a residential customer service charge of $8.25 per month. 17
The majority of the increase associated with Mr. Normand’s proposed 18
monthly service charge basically reverses the intra-class subsidies resulting 19
from the January 2017 decrease and the associated bill impacts. 20
21
22
23
JS-18
Bill Impacts 1
Q. Have you prepared monthly customer billing impacts resulting from 2
NorthWestern’s proposals in this filing? 3
A. Yes. As described above, NorthWestern believes rates should move toward 4
costs, but it is also sensitive to maintaining reasonable billing impacts. A 5
billing impact analysis is necessary to determine if the combined impacts of 6
the Rebuttal Revenue Requirement, moderation, and RD are reasonable 7
across the spectrum of usage levels. Because RD can impact customers 8
within the same class differently depending on their usage levels, it is 9
important that such an analysis consider a broad range of usage levels within 10
each class. 11
12
Q. What were NorthWestern’s objectives regarding overall bill impacts? 13
A. NorthWestern’s objectives were: 1) to limit bill impacts to less than a 10% 14
increase for the majority of customers most of the time, and 2) for customers 15
who will experience an impact of greater than 10%, to limit the actual dollar 16
impact to a reasonable amount. These objectives were achieved. 17
18
Regarding the second objective, low-use residential customers, those 19
customers who use up to 20 therms per month for example, experience bill 20
impacts that are greater than 10%, but the associated actual dollar impacts 21
range from $2.40 to $2.42 per month. As Mr. Normand explains, these 22
increases are primarily the result of partially moving the recovery of the fixed 23
JS-19
cost of meters and services into the customer service charge. In this context, 1
“low use” is largely a function of season because the large majority of 2
NorthWestern’s residential natural gas customers consume natural gas for 3
their space heating needs. Refer to page 1 of Exhibit__(JS-2), columns E, G, 4
and H, lines 34 through 51. In August 2016, 76% of customers consumed 20 5
therms or less while in February 2017, owing primarily to space heating 6
needs, only 3% of customers consumed 20 therms or less. The average 7
natural gas water heater on NorthWestern’s system consumes approximately 8
17 therms per month. 9
10
Q. Please describe the bill impact sheets included In Exhibit__(JS-2). 11
A. Exhibit__(JS-2) presents the bill impacts for each rate class that result from 12
the proposed rates in this filing. This exhibit computes the billed amount 13
using current rates to the billed amount using proposed rates for each rate 14
class and computes dollar and percentage differences. For comparison 15
purposes, the proposed natural gas supply rates include the purchase gas 16
supply rate component from the April 1, 2017 natural gas supply tracker. 17
18
Refer to the table starting on line 7 of page 1 of Exhibit__(JS-2) showing the 19
billing impacts for a Natural Gas Residential Customer using 100 therms per 20
month. Columns G and H present current rate information; columns J and K 21
present proposed rate information, and columns M and N present the dollar 22
JS-20
and percent differences between current and proposed rates by rate 1
component and for the entire bill. 2
3
Below these computations, starting on line 34, are tables of billing impacts for 4
selected monthly natural gas usages. The Total Bill Impact and Percent 5
Change in columns K and M are calculated for each usage value in column J. 6
The detailed bill amounts by rate component (shown in columns H and K, 7
lines 7 through 27) are based on 100 therms by using the usage value in 8
column B, line 10. To illustrate both a summer and a winter month, the 9
number of customers for August 2016 and February 2017 are provided for 10
each usage range shown in column H. August 2016 customers are shown in 11
column E and February 2017 customers are in column G. 12
13
While not identical, the bill impact analyses for the other customer classes 14
include similar layouts and computations. 15
16
Q. Please summarize the bill impacts resulting from the revenue 17
requirement, moderation, and RD proposals in this filing. 18
A. Following are a few key statistics: 19
1. Residential customers using 10 therms per month will receive an increase 20
on their total bill of 19.35% or $2.42, and customers using 20 therms per 21
month will receive an increase on their total bill of 12.50% or $2.40. 22
JS-21
2. Residential customers using 100 therms per month will receive an 1
increase of 2.98% on their total bill or $2.17. 2
3. Residential customers using 200 therms per month will receive an 3
increase of 1.35% on their total bill or $1.88. 4
4. Bill increases for General Service customers range from approximately 5
3.6% to 8.9% on their total bill. A separate bill impact analysis sheet is 6
included for each of the seven different monthly service charges for this 7
customer class. 8
5. Bill increases for Firm Utility Gas Contract Service customers range from 9
approximately 2.7% to 9.5% on their total bill. 10
6. TBU Firm Transportation Service customers receive a total bill increase 11
ranging from approximately 3.8% to 6.4%. 12
7. DBU Firm Transportation Service customers receive a total bill increase 13
ranging from approximately 4.4% to 8.1%. 14
15
Natural Gas Tariff Changes 16
Q. Is a marked-up copy of the tariffs that NorthWestern proposes to 17
implement included in this filing? 18
A. Yes. Each sheet of each natural gas tariff with proposed revisions is provided 19
behind the tab labeled “Marked-Up Tariffs” included with this filing. The 20
specific information that NorthWestern proposes to change is red-lined. 21
22
Q. Please describe the nature of the proposed changes. 23
JS-22
A. On each tariff sheet behind the Marked-Up Tariffs tab, the current rates have 1
been crossed out. Next to, or under, each of the current rates, the 2
corresponding proposed rate has been inserted. Rates that are not impacted 3
by this filing remain unchanged. 4
5
Note that NorthWestern is proposing to update the free main line extension 6
allowances for core customers in Rule 6, Line Extensions, to reflect the RD 7
proposals in this filing. The proposed allowance for residential customers is 8
$850, and the proposed rate to determine the allowance for all other core 9
customers is $0.391 per therm. Refer to Exhibit__(JS-3) for supporting 10
computations. The changes are reflected on the affected marked up Rule 6 11
tariff sheet. 12
13
Revised ECOS 14
Q. Did NorthWestern provide an ECOS in this filing that reflects the 15
Stipulation? 16
A. There was inadequate time to develop an ECOS that reflects the entirety of 17
the Stipulation prior to this filing nor has the Commission issued a Phase One 18
order. However, Mr. Normand did develop an ECOS that is based on 19
NorthWestern’s Phase One Rebuttal Filing, but reallocates the Administrative 20
and General and Common Plant Costs from the natural gas production 21
function to the delivery services functions by customer class. Mr. Normand 22
JS-23
discusses the revised ECOS and presents the summary results including a 1
comparison to his ECOS study included in Statement L. 2
3
Q. Has NorthWestern included moderation and RD proposals based on the 4
revised ECOS? 5
A. No. As I noted above, the revised ECOS does not reflect the Stipulation in its 6
entirety, and the Commission has not yet ruled on it. NorthWestern expects 7
to update its ECOS, moderation, and rate design proposals as necessary 8
after the Commission issues an order. 9
10
Future Use of the ECOS Method for Production and Delivery Services 11
Q. Do you have any other requests of the Commission? 12
A. Yes. NorthWestern believes the ECOS model included in this filing produces 13
reasonable results for both Delivery and Production Services and that a 14
natural gas supply MCOS provides comparative information for natural gas 15
1 Source for Core and Firm Transportation and Storage Services: Statement L, Part 1, Page 1, Table 1.
2
3 Source for Core and Firm Transportation and Storage Services: Statement L, Part 1, Page 1, Table 2
4
5 Includes Natural Gas Production and Delivery Services Revenues for Core Services.
NorthWestern Energy - Natural Gas Utility
Proposed Embedded Cost of Service Moderation Based on NorthWestern's Rebuttal FilingProduction and Delivery Services
Source for Core and Firm Transportation and Storage Services: Exhbits_(PJD-41) and (PJD-42) included with the Phase 1 Prefiled Rebuttal Testimony of Patrick J. DiFronzo.
Source for DBU and TBU Interruptible Transportation current rate revenues: Exhibit_(PJD-41) included with the Phase 1 Prefiled Rebuttal Testimony of Patrick J. DiFronzo
Docket No. D2016.9.68
Exhibit_(JS-2)
Page 1 of 11
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
A B C D E F G H I J K L M N
Residential Services - Bill Amount
Usage in therms 100 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Bill PercentageRate Amount Rate Amount Rate Amount Change Change
Monthly Service Charge per Meter 5.80$ 5.80$ 5.80$ 5.80$ $8.25 8.25$ 2.45$ 42.24%
Current Rates Approved Including Deferred Tax Portion in Rates
Current Rates Approved Excluding Deferred Tax Portion in Rates
Proposed RatesRate Moderation
General Service Meters > 30,000 cuft/hr
J:\Bill Impact All Customers rebuttal final
Docket No. D2016.9.68
Exhibit_(JS-2)
Page 9 of 11
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
A B C D E F G H I J K L
CustomerD
Transmission MDDQ 450Storage MDDQ 260
Total Usage in Therms 9,014 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Incr/(Decr) Total BillMeter 2 Rate Amount Rate Amount Rate Amount Bill Impact Percent
Monthly Service Charge per Meter 262.10$ 262.10$ 262.10$ 262.10$ 384.40$ 384.40$ 122.30$
Meters Rated @ Cu. Ft. per hour Meter 2 2 1 21 = 10001 - 300002 = > 30000 Bill Impact -$ -$ -$ 292.53$
Bill Percent 0.00% 0.00% 0.00% 9.54%
Bill Impact 2,327.34$ 495.98$ 70.67$ 292.53$ Bill Percent 3.79% 6.09% 2.72% 9.54%
Firm Utility Gas Contract Service
Range of Impact
Customers
Firm Utility - Bill Amount Proposed RatesRate Moderation
Current Rates Approved Including Deferred Tax Portion in Rates
Current Rates Approved Excluding Deferred Tax Portion in Rates
J:\Bill Impact All Customers rebuttal final
Docket No. D2016.9.68
Exhibit_(JS-2)
Page 10 of 11
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
A B C D E F G H I J K L
Customer Size SmallReservation MDDQ 1,150
Storage MDDQ 0Firm Usage in Therms 20,450
Storage Injection 0Storage Withdrawal 0
Storage Capacity 0Interruptible Usage in Therms 0 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Incr/(Decr) Total Bill
Meter 2 Rate Amount Rate Amount Proposed Amount Bill Impact PercentMonthly Service Charge per Meter 136.90$ 136.90$ 136.90$ 136.90$ 180.60$ 180.60$ 43.70$
Total Reservation 1.5258253$ 1,187.23$ 1.4785055$ 1,150.47$ 1.541295$ 1,203.22$ 52.75$
Total Bill (Price Incl. Service Charge) 1,608.05$ 1,566.18$ 1,666.38$ 100.20$ 6.40%
1Rates exclude the tax tracker deferred balance from Docket No. D2016.12.97 Tax Tracker approved by law.
Small Medium LargeReservation MDDQ 1,150 20,000 110,000
Storage MDDQ 40,000Firm Usage in Therms 20,450 620,000 3,299,740
Storage Injection 80,000Storage Withdrawal
Storage Capacity 640,000Interruptible Usage in Therms 1,690 114,540
Meters Rated @ Cu. Ft. per hour Meter 2 2 31 = 5000 - 100002 = 10001 - 30000 Bill Impact 100.20$ -$ -$ 3 = > 30000 Bill Percent 6.40% 0.00% 0.00%
Bill Impact 100.20$ 1,079.06$ 6,774.87$ Bill Percent 6.40% 3.76% 3.73%
Non-Core TBU Transportation Service
Range of Impact
TBU Transportation - Bill Amount
Rate ModerationCurrent Rates Approved Including
Deferred Tax Portion in RatesCurrent Rates Approved Excluding
Deferred Tax Portion in RatesProposed Rates
J:\Bill Impact All Customers rebuttal final
Docket No. D2016.9.68
Exhibit_(JS-2)
Page 11 of 11
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
A B C D E F G H I J K L
Customer Size LargeReservation MDDQ 5,000
Storage MDDQ 0Firm Usage in Therms 284,300
Storage Injection 0Storage Withdrawal 0
Storage Capacity 0Interruptible Usage in Therms 57,080 1-Apr-17 Total Bill 1-Apr-17 Total Bill Total Bill Incr/(Decr) Total Bill
Meter 4 Rate Amount Rate Amount Proposed Amount Bill Impact PercentMonthly Service Charge per Meter 177.55$ 177.55$ 177.55$ 177.55$ 229.10$ 229.10$ 51.55$
excluding A&G and Common Plant costs and reallocating to Delivery Service. 18
19
PMN-3
II. EMBEDDED COST OF SERVICE STUDY 1
GENERAL DESCRIPTION OF ECOS STUDY 2
Q. Has NorthWestern prepared an ECOS study for use in developing natural gas 3
utility rates? 4
A. Yes. The ECOS study is included in Statement L. The ECOS study relies upon the 2015 5
test year as set forth in Exhibit__(PJD-41) and Exhibit__(PJD-42) attached to the 6
Prefiled Rebuttal Testimony of Patrick J. DiFronzo in Phase One of this filing. The costs 7
employed by this study match NorthWestern’s natural gas utility’s total test period 8
rebuttal revenue requirement. 9
10
Q. Why has NorthWestern filed an ECOS study in this rate increase application? 11
A. In Order No. 7249e in Docket No. D2012.9.94, NorthWestern’s previous general rate 12
case, the Montana Public Service Commission (“Commission”) authorized the use of 13
NorthWestern’s ECOS model for natural gas delivery services in its next cost of service 14
case. ¶ 61. This filing is that case for the Company’s natural gas utility. Accordingly, 15
NorthWestern has prepared and filed an ECOS study as the underlying cost basis upon 16
which to assess its proposed revenue distribution. The ECOS study will provide the 17
allocated costs and related revenue requirements by function and rate class at a uniform 18
Rate of Return (“ROR”). The ECOS plant results in this study are also used to derive the 19
allocated property taxes by rate class. As I describe in more detail below, in addition to 20
natural gas delivery services, and consistent with NorthWestern’s Phase One filing in this 21
docket, the ECOS study incorporates NorthWestern’s three natural gas production assets. 22
23
Q. Do you believe that an ECOS study is appropriate for use in allocating costs? 24
PMN-4
A. Yes, I believe that embedded costs of service provide a fair, transparent, and reasonable 1
basis for allocating costs including natural gas production costs. In fact, the use of ECOS 2
studies for allocating costs to customer classes and deriving revenue targets by cost 3
function and class of service on a uniform equalized basis is common in the utility 4
industry. These final class revenue requirements for rate design are often moderated to 5
address customer bill impact concerns as discussed in the Prefiled Direct Testimony of 6
Joe Schwartzenberger (“Schwartzenberger Direct Testimony”). 7
8
Q. Are the methodologies employed in performing the ECOS study you sponsor in this 9
filing the same as the methodologies used to conduct the ECOS study submitted in 10
NorthWestern’s filing in Docket No. D2012.9.94? 11
A. Yes. The methodologies are generally the same as previously used in Docket No. 12
D2012.9.94, NorthWestern’s most recent natural gas general rate case. However, as 13
described below, I made several modifications to the study to provide more summary 14
information, to improve the accuracy of the allocations, to incorporate NorthWestern’s 15
recently acquired gas production assets, and to improve the transparency of the study and 16
its results. These modifications include: 17
(a) Addition of functional allocations to NorthWestern’s three natural gas production 18
assets; and 19
(b) Detailed allocation of property taxes that supports the development of separate rate 20
components designed to collect property taxes from each customer class based on 21
plant allocations. All of the proposed volumetric transmission, distribution, storage, 22
and production rates include two parts: a property tax component and a component 23
PMN-5
without property taxes, and all monthly service charges exclude any recovery of 1
property taxes. 2
3
Q. Do the steps you employed in conducting the ECOS study follow the marginal cost 4
requirements that are set forth in ARM 38.5.176(2) through (5)? 5
A. Yes, they do. Even though the rules’ requirements specifically relate to marginal costs, 6
the steps I took in this ECOS study follow these requirements as well. The 7
NorthWestern ECOS model functionalizes costs as required by ARM 38.5.176(2). The 8
NorthWestern model classifies and allocates costs as required by ARM 38.5.176(3). The 9
model employs loss factors, allocates Operation and Maintenance (“O&M”) costs, and 10
employs Administrative and General (“A&G”) expense as well as general and common 11
plant allocation factors as required by ARM 38.5.176(4). The ECOS model employs the 12
time frames (i.e., design day demands, annual sales volumes, and winter sales volumes), 13
carrying charge calculations (i.e., NorthWestern’s proposed rate of return and taxes), and 14
proxy class cost estimates (i.e., meter and services investments based on the Company’s 15
data) as required by ARM 38.5.176(5). ARM 38.5.176(6) is not applicable to the ECOS, 16
since it addresses the use of a future time frame for a marginal cost study. 17
18
Q. Is NorthWestern required to follow the marginal cost requirements that are set 19
forth in ARM 38.5.176(2) through (5) in this filing? 20
A. No, as explained above, these requirements do not apply to delivery services costs, but I 21
employed them in my ECOS study. The Commission previously authorized an ECOS 22
study for natural gas delivery services in this case. However, NorthWestern is requesting 23
rate treatment for its natural gas production assets, and a marginal cost study for natural 24
PMN-6
gas supply is therefore required. To that end, NorthWestern has performed a marginal 1
cost study for natural gas supply. I discuss the marginal cost study and the results below; 2
the results are included in Statement L. 3
4
In Order No. 7046i issued in June 2011 in Docket No. D2009.9.129, the Commission 5
also authorized NorthWestern to file an ECOS analysis for delivery services in its next 6
rate case. In that order, it cautioned NorthWestern to “not neglect economic theories and 7
analysis” ¶ 234. I believe that the ECOS study’s adherence to the requirements of ARM 8
38.5.176(2) through (5) demonstrate that NorthWestern is continuing to consider 9
economic theories and analysis and is also promoting economically efficient 10
consumption decisions. 11
12
Q. Generally describe the process of conducting an ECOS study. 13
A. An ECOS study is usually performed in three steps – functionalization, classification, and 14
allocation. Functionalization identifies the operations level where the costs are incurred, 15
either directly or indirectly, with respect to the physical process of providing service. For 16
example, cost associated with distribution mains (distribution function) are segregated from 17
costs associated with transmission mains (transmission function). Similarly, storage 18
investment and costs are segregated from the costs of transmission mains, although a 19
portion of storage is used for transmission balancing and therefore is functionalized as 20
transmission-related. Classification separates costs according to the product characteristics 21
of service as denoted by the primary cost driver – i.e., capacity, commodity, and customer-22
related costs. Allocation uses this information, along with the knowledge that certain costs 23
are incurred exclusively for the benefit of certain customers (direct assignments), to 24
PMN-7
allocate or assign the specific cost components that have been functionalized and classified 1
to specific classes. To the extent practical, costs are allocated based on factors that reflect 2
the manner in which the costs arise. 3
4
Q. Please describe the process of cost functionalization. 5
A. After all of the individual cost components representing the total revenue requirement have 6
been gathered for the cost study, the various cost components are separated according to 7
the function they perform. These functions are: 8
• Production - costs associated with NorthWestern’s Battle Creek, Bear Paw (NFR), and 9
South Bear Paw (Devon) gas production plant. They have been separated into baseload 10
and peaking components, reflecting the manner in which the production facilities are 11
operated. NorthWestern injects a limited amount (9.8%) of natural gas into storage 12
during off-peak periods and uses storage gas as well as flow gas to meet its natural gas 13
demands during winter peak periods; 14
• Storage – costs associated with storing large quantities of natural gas for use during 15
periods of high winter demand. Normally, NorthWestern injects natural gas into 16
storage facilities during periods of low demand and withdraws from storage during 17
periods of high winter demand levels. As indicated below NorthWestern uses a portion 18
(13.2%) of its storage deliverability (25,000 Dekatherms (“Dkt”)) for balancing load 19
and supplies on the transmission system; 20
• Transmission – costs associated with large, high pressure mains that transport large 21
volumes of natural gas to load centers and natural gas storage facilities; 22
• Distribution – costs associated with distributing the natural gas from the transmission 23
system to the end users’ points of delivery; and 24
PMN-8
• Customer – costs associated with providing service to the customer, i.e., services, 1
regulators, metering, billing, etc. 2
3
For the most part, the unbundled costs of a utility such as NorthWestern are already 4
somewhat functionalized based on recorded data. In fact, the Federal Energy Regulatory 5
Commission (“FERC”) Uniform System of Accounts (“USOC”), which the Commission 6
requires NorthWestern to follow, provides for the recording of a major portion of costs by 7
accounts defined and arranged by functional level. 8
9
Q. Please describe the process of cost classification. 10
A. Cost classification is the process of further categorizing the functionalized costs according 11
to the cost-causing characteristic of the utility service provided. The three principal cost 12
classifications are capacity-related (demand) costs, commodity-related (volumetric) costs, 13
and customer-related costs. 14
15
Capacity-related costs (also referred to as demand-related costs) are those fixed costs 16
related to the maximum Dkt demand upon the system, normally the design day (88 Heating 17
Degree Days (“HDD”)) Dkt capacity requirements imposed by a natural gas customer on 18
the Company’s delivery network. Commodity-related costs are those costs related to the 19
therms1 the customer utilizes over a specified period, such as a month or year. Customer-20
related costs are those costs incurred due to the number of customers on the system. These 21
1 NorthWestern undertakes its analysis and reporting in dekatherms, but bills customers in therms. Consequently, the consumption data employed in the cost of service study is expressed in dekatherms and the consumption data employed in rate design is expressed in therms.
PMN-9
are costs closest to the customer premises (meters and services) which generally are not 1
available for use by anyone else and have no causal relationship to consumption volumes. 2
3
Q. Please describe the process of cost allocation. 4
A. Cost allocation is the assignment of functionalized and classified costs to customer classes. 5
Allocation factors reflecting capacity requirements, commodity volumes, and customer 6
costs rely on operating and accounting data to produce representative allocation factors in 7
the form of percentages that add up to 100 percent. These allocation factors applied to 8
specific plant, rate base items, and various expenses derive the total costs of providing 9
service for each class of customers. For example, NorthWestern designs its natural gas 10
mains to maintain natural gas deliverability during the very coldest days. As a result, it is 11
reasonable to assign the costs of natural gas mains on design day (88 HDD) demands by 12
class, as I have done in this case. In turn, it is possible to develop allocation factors for 13
each detailed cost item such that costs are allocated on the metric that best embodies the 14
manner in which costs arise. For example, actual meter costs are allocated according to the 15
number of customers by class weighted by their relative costs of meters. 16
17
NATURAL GAS DELIVERY SERVICES ECOS STUDY 18
Q. Please describe the natural gas delivery services ECOS study detail provided in 19
Statement L. 20
A. The Natural Gas Delivery Services ECOS study (first part of Statement L) consists of 16 21
pages. Pages 1 and 2 of the study provide tables that summarize the results of the cost 22
study. Page 1 compares current rate revenues to proposed revenue levels at Equalized 23
ROR with property taxes included in all functions (Columns B through G), and page 2 24
PMN-10
compares current rate revenues to proposed rate revenue levels based on the Rate Design 1
which includes the property taxes redistributed to all functions except the Customer 2
Function in column (G). These summary tables show the relationship between functional 3
revenues by class at both present and proposed rate levels (Equalized ROR and Rate 4
Design) with a percentage change for all functions and classes. Page 3 of the study lists the 5
functionalization factors. Page 4 shows the class allocation factors employed by 6
NorthWestern in Statement L. Pages 5 and 6 set forth the functionalization of the natural 7
gas revenue requirement components such as plant in service, accumulated depreciation, 8
and cash working capital to develop Rate Base for all functions. Pages 7 and 8 develop the 9
functionalization of O&M expense, revenue, and taxes to achieve an initial functional 10
revenue requirement. Pages 9 through 15 provide the detailed allocations of these 11
functionalized costs to customer classes, which result in an achieved class ROR level as 12
shown at the bottom of page 15. Column A of these pages of the cost study provides a 13
description of the costs allocated, column B shows total system costs, and columns C 14
through K include customer class descriptions. Column L details the allocation factors 15
used to allocate the total costs to classes; as discussed above, page 4 includes these factors. 16
Page 16 shows the detail functional allocator factor development for Labor-Related O&M 17
expenses used in the study. 18
19
Q. Please describe how you functionalized costs in the ECOS model. 20
A. First, I defined 11 cost functions: 21
1. Production - Battle Creek 22
2. Production - Bear Paw (NFR) 23
3. Production - South Bear Paw (Devon) 24
PMN-11
4. Transmission 1
5. Distribution - Other 2
6. Distribution - Customer Meters 3
7. Distribution - Customer Services 4
8. Storage 5
9. Customer Meter Reading 6
10. Customer Records 7
11. Customer Other 8
I either allocated or directly assigned each major item of revenue requirement to functions 9
as shown in column N on pages 5 through 8 of the study. Also shown in this column are 15 10
functionalization factors that I used when I could not directly assign costs to functions. 11
These indirect, or composite, functionalization factors include the following: 12
1. Functional Revenue 13
2. Functional Revenue excluding Production 14
3. Functional Plant Investment 15
4. Functional Plant Investment excluding Production 16
5. Functional Labor Expense 17
6. Functional Labor Expense excluding Production 18
7. Functional Expenses 19
8. Functional Expenses excluding Production 20
9. Meters and Services Expenses 21
10. Distribution Operations Labor Expense 22
11. Distribution Maintenance Labor Expense 23
12. Storage 24
PMN-12
13. Production - Battle Creek 1
14. Production - Bear Paw (NFR) 2
15. Production - South Bear Paw (Devon) 3
4
A list of all functional and class allocation factors is also provided on pages 3 and 4 of the 5
study as I previously discussed. At the completion of the functionalization effort, all costs 6
that comprise NorthWestern’s revenue requirement, including common costs, are assigned 7
to cost functions. 8
9
A detailed Functional Labor Expense allocator (page 16) was developed to more accurately 10
functionalize labor-related costs. This allocator was developed by functionalizing all labor-11
related O&M expenses by each account excluding Production and summing these allocated 12
amounts to create the labor expense allocation factor excluding Production which is 13
represented by the acronym FuncLaborXP. 14
15
Q. How did you use this FuncLaborXP allocator? 16
A. I used the FuncLaborXP allocator to spread Intangible, General, and Common plant to 17
functions as shown on page 5. 18
19
Q. Please describe the functionalization of storage plant that you incorporated into the 20
current ECOS study. 21
A. I functionalized storage plant investment into two components to recognize that a portion 22
of storage plant deliverability is reserved for balancing of the loads on NorthWestern’s 23
natural gas transmission lines. The ECOS study recognizes that NorthWestern reserves 24
PMN-13
25,000 Dkt per day of deliverability from the storage facilities for transmission load 1
balancing. This amounts to 13.6% of the deliverability of total storage facilities. 2
Consequently, I functionalized 13.6% of all storage plant investment to the transmission 3
function. 4
5
Q. Please describe how costs were classified in the ECOS study. 6
A. The classification of costs as capacity-, commodity-, and customer-related takes place 7
within the development of allocators used to assign costs to customer classes. Please refer 8
to pages 9 through 15 of the ECOS study, which show the classification and allocation 9
steps. On these pages, the costs included in the Production – Battle Creek, Production – 10
Bear Paw (NFR), Production – South Bear Paw (Devon), Storage, Transmission, and 11
Distribution Other functions are allocated to classes using the capacity-related allocation 12
factors (which are referred to in the ECOS study by the acronyms BattleCreekAlloc, 13
BearPawAlloc, DevonAlloc, StorageAlloc, TranDD, and DistDD), thus effectively 14
classifying these functionalized costs as capacity-related costs. Similarly, the costs 15
included in the Meters, Services, Meter Reading, Customer Records, and Customer Other 16
functions are allocated to customer classes using the MeterCost, Services, MeterRdg, 17
CustRecords, and Customer allocation factors, thereby producing costs that are classified as 18
customer-related costs. 19
20
Q. Please describe how you allocated costs in the ECOS study. 21
A. Once costs were functionalized and classified, I allocated costs to customer rate classes, as 22
shown on pages 9 through 15 of the study. The allocators used to allocate costs are shown 23
on pages 3 and 4 of the study. The 11 allocators listed on page 4 in column B are used to 24
PMN-14
allocate the majority of costs and rely on external information. These are the underlying 1
foundation to the cost of service study results and are described in more detail below. 2
1. BattleCreekAlloc, BearPawAlloc, and DevonAlloc – Each production plant 3
allocation factor reflects the operation of NorthWestern’s Battle Creek, Bear Paw 4
(NFR), and South Bear Paw (Devon) natural gas production facilities. The 5
production plants operate at full or near-full capacity throughout the year. In the 6
off-peak periods, the capacity delivered to the system exceeds the sales 7
requirements, with the excess delivered to storage. It is estimated that 9.8% of the 8
capacity is delivered to storage. To reflect the production capacity deliveries to 9
storage, a weighted allocation factor was developed. This allocator was weighted 10
90.2% based on July and August average volumes and 9.8% on winter volumes. 11
These two allocators were used for each of the production plants. 12
2. StorageAlloc – Storage plant was and is used to supplement flowing gas to serve 13
core customers. NorthWestern storage is also marketed directly to third-party 14
suppliers. NorthWestern contracts with core customers and third parties to provide 15
varying amounts of deliverability and capacity. Deliverability is the maximum 16
daily rate of withdrawal and is measured in Dkt per day. Capacity is the measure of 17
total volume that can be stored for later withdrawal and is measured in total Dkt. 18
NorthWestern has invested in three storage plants of varying deliverability, 19
capacity, and cost. The storage allocator reflects the operational characteristics of 20
NorthWestern’s Dry Creek, Box Elder, and Cobb storage fields for the last three 21
years. The storage allocator is based on a three-year average dispatch. Individual 22
plant investments were allocated in two steps: first to the months in which they 23
were dispatched on an average historical basis, and second to classes based on their 24
PMN-15
sales in those months adjusted to reflect only sales made from storage withdrawals. 1
These allocation factors reflect the historical storage and deliverability attributes of 2
NorthWestern’s storage plant. 3
3. TranDD – For transmission, the Transmission Design Day allocator is based on the 4
estimated design day demands imposed on the transmission system by each rate 5
class. The design day demands were computed through regression analyses of 6
monthly sales and heating degree data by establishing a base-use- and heating-use-7
per-degree-day factor and then extrapolating to the 88 heating degree days used for 8
the design day. This allocation methodology remains unchanged from 9
NorthWestern’s ECOS study submitted in Docket No. D2012.9.94. 10
4. DistDD – For distribution, the Distribution Design Day allocator is based on the 11
estimated design day demands imposed on the distribution system for each rate 12
class. The distribution allocation factor was developed from the TranDD allocator, 13
which zeroes out classes that are not served by the distribution system. This 14
allocation methodology remains unchanged from NorthWestern’s ECOS study 15
submitted in Docket No. D2012.9.94. 16
5. MeterCost – The meter allocator is based on typical metering cost per customer 17
including installation for each rate class. This is the most accurate approach to 18
developing meter costs for each rate class as the costs can vary somewhat between 19
service classes based on Company data. These estimated costs are then multiplied 20
by the number of customers in each class, which results in a total cost estimate by 21
customer class that is employed as the meter cost allocator to assign actual meter 22
costs in the ECOS study. The methodology for allocating meter costs to classes is 23
the same as employed in NorthWestern’s previous ECOS study. 24
PMN-16
6. Services – Similar to the MeterCost allocator, the services allocator is based on an 1
estimate of service cost per customer multiplied by the number of customers. The 2
actual calculation begins with the number of customers which is then slightly 3
reduced to reflect the number of services, which is typically less. Based on 4
Company records, certain locations have more than one customer but only one 5
service. Like meter costs, discussed above, this approach recognizes the varying 6
costs by customer classes and is the most representative of cost assignment. As in 7
the case of meters, the services allocation factor in this study is calculated in the 8
same manner as in NorthWestern’s previous ECOS study. 9
7. MeterRdg – The meter reading allocator was developed in a two-step process using 10
detailed cost accounting data. Meter reading costs were separately identified for 11
automated meter reading, manual meter reading, and readings taken from the gas 12
measurement system. The count for each type of meter reading was then identified 13
by rate class to develop the meter reading allocator. This allocation methodology 14
remains unchanged from NorthWestern’s previous filing. 15
8. CustRecords – Customer records expense is assigned to rate classes based on the 16
number of customers. The costs of the computerized customer records system are 17
similar for each customer and do not differ significantly by rate class, making 18
customer count the proper allocator. This allocation methodology remains 19
unchanged from NorthWestern’s previous filing. 20
9. Customer – The allocator for other customer costs is identical to the CustRecords 21
allocator, i.e. based on the number of customers. As is the case with the other 22
customer-related allocation factors, this allocation methodology remains unchanged 23
from NorthWestern’s previous filing. 24
PMN-17
Q. Please describe the resulting assignment of costs to customer classes in the ECOS 1
study. 2
A. As stated above, summary results of the ECOS study are shown on pages 1 and 2 of the 3
study with four separate tables on each page providing the following information: 4
• Table 1 – Total Actual Natural Gas Revenue for the Test Year at Current Rates 5
shows the revenues produced by rate class and function at current rates. Note that 6
revenues at current rates are presented for the Production, Storage, Transmission, 7
Distribution, and Customer functions and in total for each rate class. Table 1 is 8
identical on pages 1 and 2. I also show the customer-related revenues with and 9
without property taxes in columns (G) and (H), respectively. 10
• Table 2 on page 1, – Total Natural Gas Revenue at Equalized ROR, shows the 11
revenues that would be produced if all inter-class and inter-function subsidies were 12
eliminated, i.e. if all rates and classes produced the proposed system rate of return 13
on their allocated functional rate base. These revenues are the level of revenues that 14
would be produced by a fully cost-based rate. Table 2 on page 2, Total Proposed 15
Natural Gas Revenue from Rate Design, sets forth the revenues by function for each 16
class that would be produced by NorthWestern’s proposed rates in this filing, after 17
customer class revenue moderation as explained in the Schwartzenberger Direct 18
Testimony. 19
• Table 3 – shows the dollar difference between Table 1 and Table 2 on each page. 20
Table 3 on page 1, Natural Gas Revenue Change to Achieve Equalized ROR, shows 21
the changes in revenue that would result from moving all classes to a revenue level 22
equal to their respective allocated costs of service. On a class-by-class basis, 23
General Service and Firm Storage rates should be reduced and other firm service 24
PMN-18
rates should be increased in order to achieve cost-based rates. On a function-by-1
function basis, storage and distribution charges for most classes should be reduced 2
while production, transmission, and customer charges should be increased in order 3
to achieve cost-based rates. Table 3 on page 2, Natural Gas Revenue Change Rate 4
Design, sets forth the Company’s proposed changes in revenue by class and 5
function. This table reflects the effects of rate moderation upon proposed class 6
revenue and upon the functional rate components for each class of service. 7
• Table 4 – provides the percent difference between Table 1 and Table 3 for both 8
Pages 1 and 2. Table 4 on Page 1 provides the percent change from present revenue 9
that would be necessary for current rates to collect allocated costs of service at 10
equalized ROR. Table 4 on Page 2 provides the percent change in revenues by 11
class and by function proposed by NorthWestern. The proposed class revenues set 12
forth on this table reflect the increases proposed by NorthWestern as set forth on 13
Page 1 of Statement M, column (I). 14
15
Table A below summarizes the class-by-class results of the ECOS study at present and at 16
equalized ROR revenue levels (see also Statement M, page 1, column (F)) and the increase 17
that would be required. 18
PMN-19
Table A Equalized Class Revenue Requirement Comparison
Revenue at
Present Rates Revenue at
Equalized ROR Increase to
Equalized ROR Percent Increases
from Current Residential 74,315,199 80,963,615 6,648,415 8.95 General Service 38,719,759 39,600,473 880,714 2.27
Firm Utilities 581,773 694,857 113,084 19.44
DBU Transport Firm 2,408,640 3,138,126 729,485 30.29
DBU Transport Interruptible 0 0 0 0.00
TBU Transport Firm 13,006,109 14,272,008 1,265,900 9.73
4 Development of A&G Loading Factors – Develops A&G Loading Factors related to new plant and plant-related factors.
Develops Common and General Plant Loading Factors and Loss Factors applied to unit capacity assets.
6
5 Development of Levelized Fixed Charge Rates – Develops Levelized Fixed Charge Rates to be applied to the capacity costs calculated on Table 1.
6
6 Summary of Marginal Capacity Costs – Develops the capacity costs per design day Dkt from the results of Tables 1 through 5.
8
7 Marginal Commodity Costs – Presents the calculated seasonal commodity costs previously developed from Table 2 and adjusts for losses and uncollectibles.
8
8 Summary of Marginal Cost Estimates – Presents the calculated marginal costs from Tables 6 and 7 and applies these costs to the billing determinants to derive full annual marginal costs.
9
9 Marginal Commodity Costs – Marginal unit cost per Dkt – Develops full marginal unit cost on a seasonal and annual basis for core rates.
10
10 Derivation of Marginal Prices – Equi-Proportionally Adjusted Costs – Presents Marginal Cost prices adjusted to revenue constraints from embedded cost of service seasonally and annually for core rates.
Final Results per Dkt
PMN-25
Q. Do you recommend that the Company utilize the marginal costs results that you 1
have calculated in your study and summarized on Exhibit ___(PMN-3)? 2
A. No. Based on my costs results, I do not recommend that the prices be applied to any 3
proposed rates for two primary reasons: First, the class price differentials are small with 4
seasonal costs being reasonably close to current prices, and second, the prices have all 5
been adjusted (reduced) to the Company’s total Rebuttal revenue levels. 6
7
IV. NATURAL GAS DELIVERY SERVICE RATE DESIGN 8
GENERAL OVERVIEW OF PROCESS 9
Q. Generally describe the rate design process. 10
A. Rate design generally relies upon a balancing of often-conflicting concerns and interests. 11
Customer impact considerations are very important in recognizing social concerns and 12
promoting consumer confidence in making informed, long-run choices. Revenue stability 13
considerations are also important in ensuring that a utility has an opportunity to earn a fair 14
and reasonable return on its investment. Ease of administration and understanding is 15
necessary to allow consistent, fair, and transparent application of rates. Because these 16
concerns and interests often conflict with one another, it is necessary to balance the relative 17
importance of one concern (or set of concerns) against other concerns. For example, cost-18
based rates may lead to undue customer impact as a result of large rate increases required 19
to set rates at a level that recover the costs of providing service. While some concerns are 20
more subjective than others, the difficulty of quantifying a concern makes it no less 21
important. 22
23
PMN-26
The objective of cost-based rates tends to drive the rate design process with consideration 1
given to notions of fairness, objectivity, and economic efficiency. In this case, 2
NorthWestern chose to adopt a rate-making process that I believe closely mirrors the 3
process typically employed within the utility industry. In this process, a cost-based 4
standard is established and present rates are compared to that standard. Next, criteria 5
limiting the relative rate adjustment impact upon consumers are established. Finally, rates 6
are moved toward full cost recovery subject to the constraints of the rate impact criteria. 7
The overall objective is to move rates for each class within a zone of reasonableness to the 8
overall Company ROR. 9
10
NorthWestern’s development of class revenue levels for natural gas consumers balances 11
movement toward cost-based rates with the recognition that large increases result in rate 12
impacts that may be considered unduly burdensome. However, rate design is a zero-sum 13
process because a reduction in the revenues recovered from one class results in an increase 14
to the rates of one or more other classes, given a specific revenue requirement level. The 15
process of rate moderation and the specific class revenue targets for rate design are 16
discussed more thoroughly in the Schwartzenberger Direct Testimony. 17
18
Once the revenue requirement targets for each rate class are determined, the next step in 19
the rate design process is an assessment and development of the overall structure and 20
price levels for a given class. The ECOS study, submitted in Statement L, provides costs 21
by function and classes, which allows the specific components of each rate to be 22
compared to the associated costs. Again, consideration of customer impact, revenue 23
stability, ease of application and understanding, as well as other practical concerns, may 24
PMN-27
temper the extent to which individual rate elements (i.e., customer, demand, and energy 1
charges) reflect their respective costs of service. Finally, once an initial draft set of rates 2
is established, customer bill impact analyses are undertaken to ascertain whether further 3
rate moderation is necessary. The Schwartzenberger Direct Testimony includes a 4
discussion of these analyses relating to customer bill impacts for the Company’s 5
proposed rates. 6
7
DESCRIPTION OF NORTHWESTERN’S PROPOSED RATE DESIGN 8
Q. Have you prepared schedules that support NorthWestern’s proposed natural gas 9
delivery service rates? 10
A. Yes, these workpapers are provided in Statement M of this filing. Page 1 of Statement M 11
sets forth (1) the normalized billing determinants used to develop the Natural Gas Delivery 12
rates (i.e., average number of customers, Maximum Daily Delivery Quantity (“MDDQ”), 13
and therm sales volumes); (2) the revenues produced by applying present rates to the 14
normalized test year billing determinants; (3) the class revenue requirements determined by 15
the ECOS study submitted in Statement L at an equalized class basis; (4) the moderated 16
revenue levels proposed by NorthWestern as provided in the Schwartzenberger Direct 17
Testimony; (5) the revenues produced by the proposed rates; and (6) the percentage 18
increases resulting from the proposed rates. 19
20
Page 2 of Statement M provides a single page summary of the proposed rates for each class 21
of service. Page 3 presents the same row-by-row details as page 2 except at present 22
approved pricing levels effective January 2017. Please note that the property tax recovery 23
has been shown separately for each rate, and there is no property tax recovery in any of the 24
PMN-28
service charge prices shown on pages 2 and 3. Page 4 details the overall increase in 1
Production which was applied uniformly to all core rates. Page 5 details the property tax 2
rates by class with the targeted revenue amounts by rate class in column (H). The 3
remaining pages 6 through 19 provide the detailed calculations of the proposed delivery 4
service rates for each of the individual rate classes. 5
6
Q. Please describe your general approach to the design of natural gas delivery service 7
rates. 8
A. My general approach to rate design was guided by several criteria that I believe are 9
consistent with Mr. Schwartzenberger’s rate moderation recommendations: 10
1. that individual rates should move toward their unit costs of service, as provided by 11
the ECOS study; 12
2. that rates by class should increase on a percentage basis to the Company’s overall 13
increase in a measured way; 14
3. that the magnitude of the change in individual rates should be capped or limited to 15
ensure reasonable customer impacts; 16
4. that property tax expenses be recovered in a separate proposed volumetric rate for 17
each customer class; 18
5. that emphasis should be placed on the recovery of the fixed costs as it relates to 19
customer-related costs for meters and services; 20
6. that to the maximum extent practical, the same design process should be used for all 21
proposed rates; and 22
7. that the rates should consider reasonable simplification where possible for 23
administrative ease and customer understanding. 24
PMN-29
The unit costs from the ECOS study provide the starting point for individual class rate 1
designs. In the process of designing individual rate components, separate changes to 2
service charge, commodity, and MDDQ rates will have varying impacts on the individual 3
members of the rate class. Thus, the movement of the individual rate components was 4
moderated to avoid undue impacts to individual customers within a given rate class similar 5
to the moderation of the overall increase among customer classes. 6
7
Q. Please summarize the fixed customer costs relating to proposed monthly customer 8
service charges for each class. 9
A. Table D below summarizes the customer-related cost recovery at existing rates (January 10
2017) after removing the property tax amount, at full-equalized cost of service, and at 11
proposed rate levels. The proposed pricing levels for the service charges were set at 50% 12
of the difference between the claimed (full cost of service) and the existing rates. Please 13
note that these monthly charges, which we have identified separately for each rate class, do 14
not include any recovery of property taxes as required by the Commission’s directive. The 15
monthly charges have been rounded to the nearest nickel. 16
17
PMN-30
Table D Comparison of Monthly Service Charges
(excludes property taxes)
Rate Existing Claimed Proposed Residential 5.80 10.66 8.25 Employee 4.35 8.00 6.15 General Services: 0 to 300 * 15.05 18.12 16.60 301 to 1 k 19.85 23.90 21.90 1 k to 2 k 32.00 38.52 35.25 2 k to 5 k 53.75 64.71 59.25 5 k to 10 k 66.00 79.47 72.75 10 k to 30 k 104.35 125.64 115.00 > 30 k 126.80 152.67 139.75 Utilities < 30 k 101.65 196.49 149.05 > 30 k * 262.10 506.66 384.40 DBU < 5 k 97.35 153.88 125.60 < 10 k 111.25 175.86 143.55 < 30 k * 152.90 241.68 197.30 > 30 k 177.55 280.65 229.10 TBU < 10 k 95.25 156.04 125.65 < 30 k 136.90 224.29 180.60 > 30 k * 303.75 497.63 400.70
* The level of average use associated with the calculated service charge. All other service charges 1 were derived based on the existing pricing levels to this level to determine the proposed charges. 2 Note: All data taken from Statement M. Existing service charges reflect a lower level charge after 3 removing the property tax component as of January 2017. 4
5
Q. Why have you set the proposed customer service charges at a more cost-based price 6
level in your rate design in this case? 7
A. In my opinion, the proposed service charges are both reasonable and certainly well below 8
cost. The proposed pricing rationale is threefold. First, the proposed pricing recovers these 9
fixed costs more equitably amongst customers. Volumetric use does not drive these costs; 10
therefore, the current recovery of these costs through volumetric charges is inappropriate. 11
Collection through the monthly service charge more properly recovers these costs from the 12
users of meters and services. Second, these proposed fixed monthly service charges go a 13
PMN-31
long way toward reducing the current high level of intra-class subsidy that exists in the 1
current volumetric recovery. Finally, the increase to the service charges helps to mitigate a 2
new layer of subsidy within each class introduced in January 2017. Removing the property 3
taxes from the approved monthly service charges that existed at that time means that 4
revenues collected to recover property tax expense are now recovered on a volumetric 5
basis. This shifts the recovery towards the higher volume users in each class and into the 6
winter period. 7
8
Q. Please describe the rate design process for the proposed natural gas delivery service 9
and production rates. 10
A. The proposed rates rely upon the results of the ECOS study in Statement L as moderated in 11
the Schwartzenberger Direct Testimony to establish class revenue objectives which also 12
embody class bill impact considerations as discussed in his testimony. 13
14
Prior to deriving final proposed volumetric pricing levels for each rate class, several steps 15
were initially undertaken to establish certain price levels and associated revenue recovery 16
for the following revenue segments: 17
18
PMN-32
STEP ACTIVITY
Class Revenue Targets Establish a moderated target revenue level to be recovered from each class through rate design.
Customer Monthly Service Charge Establish service charges at a 50% increase between existing levels to full cost of service level (Table D) exclusive of property taxes.
Production Costs Remaining Establish recovery of production-related costs from core classes using uniform factors for each class for both the property tax and remaining Production revenue requirement components. This approach to introducing uniformity for these two production cost components simplifies the recovery process and customer understanding for rate design purposes.
Property Tax Recovery Establish a property tax revenue amount to be recovered from core rates (Statement M, page 5, column (H)) based on cost of service results. The final level of property tax recovery from each rate class is the target revenue level less the recovery from the uniform Production component.
Residual Revenue Requirement Once the proposed Customer Service charge, the Production Cost Recovery (for core classes), and the Property Tax revenues are determined, these total dollars are then summed and subtracted from each core class’s moderated revenue targets (as determined in the Schwartzenberger Direct Testimony) to determine the remaining (residual) revenues to be recovered. These remaining revenues are then recovered by increasing all remaining functions of core rate structure prices by the same percent based on the equalized ROR levels from the cost study.
PMN-33
CORE RATES 1
RESIDENTIAL – Pages 6 and 7 of Statement M provide the development of proposed 2
rates for Residential customers and Residential employees (a small group of Company 3
retirees who receive a 25% discount from the Residential rate). Lines 38 through 49 of 4
page 6 provide the component costs from the ECOS study. Based on this study, the unit 5
cost for the monthly service charge was almost twice ($10.66 vs. $5.80) the current 6
Residential service charge. The proposed service charge was set at 50% of this difference, 7
or $8.25. The rate design steps started with the class revenue targets less the recovery of 8
service charge, property tax, and production revenues to determine a residual amount of 9
revenues to be recovered from the functional unit pricing levels. Using the billing statistics 10
for each function, the unit pricing levels were adjusted to achieve the desired remaining 11
revenues. These results are presented in detail on Page 7 of Statement M, lines 78 through 12
98. Finally, the customer service charge was rounded to the nearest nickel and the 13
remaining charges to seven decimal places. These increases produce a Residential rate 14
structure that moves toward cost-based rates while maintaining the moderated Delivery 15
Service rate increase target of $79,597,459, or 7.11% for the Residential class. 16
17
GENERAL SERVICE (“GS”) – Pages 8 through 10 of Statement M provide the 18
development of proposed rates for GS customers. Because the ECOS study showed that 19
current GS rates exceed the costs to provide service to GS customers, a slightly lower-than-20
system average increase is proposed for this rate. As with the design of all classes, the 21
existing monthly Service (i.e., customer) charges are much less than costs. The proposed 22
service charges were increased in the same manner as the Residential rate described above 23
and rounded to the nearest five cents. Since there are several block usage pricing levels, 24
PMN-34
the service charge for the average use level was initially set based on the average use (< 1
300) with all other charges derived based on the existing level ratios to this block. The 2
component costs are set forth on Lines 37 through 39. The transmission cost is 132% of 3
the present transmission charge, while the present distribution and storage charges are 4
much higher than their respective costs of providing service. Since the rate design 5
procedure produces proposed rates that adjust each functional component charge in 6
proportion to the variance with embedded cost, the transmission charge was increased by a 7
large percentage and the distribution and storage charges were reduced. These price 8
comparisons are made with all property taxes removed. As a result of the moderated 9
revenue targets, the GS rate level is increased to $41,303,388, or a 6.67% increase, while 10
the equalized ROR costs are $39,600,473 (Schedule M, pages 1 and 8 to 10). 11
12
FIRM UTILITY GAS CONTRACT SERVICE – Pages 11 through 13 of Statement M 13
provide the development of proposed rates for Firm Utility Gas Contract Service. As with 14
all other rates, the Monthly Service Charges per meter were found to be below the 15
respective costs to serve and were increased in the same manner as residential and general 16
service at 50% of the difference between existing levels and full cost of service. Because 17
the present transmission charges are lower than the costs to provide transmission service 18
and the present storage charges are greater than the costs of providing service, the proposed 19
storage charges were modestly increased and the proposed transmission charges were 20
increased by a proportionately greater percentage. 21
22
23
PMN-35
NON-CORE RATES 1
DBU FIRM TRANSPORTATION – Pages 14 and 15 of Statement M provide the 2
development of rates for Non-Core Distribution Firm Transportation service using the 3
results of the ECOS study as moderated pursuant to Mr. Schwartzenberger’s 4
recommendations. Similar to the rates for other customer classes, the Monthly Service 5
Charges per meter were increased to 50% of the difference between the current level and 6
full cost of service and then rounded to the nearest five cents. The distribution charges 7
were substantially below costs to serve, so these rates were increased to $2,644,856 FIRM 8
(Statement M, page 14, line 1, and page 15, line 67). The Reservation rate was increased 9
6.70% resulting in a total proposed moderated increase of 9.81% for this class, or a 10
moderated increase of $236,216. 11
12
TBU FIRM TRANSPORTATION – Pages 16 through 18 of Statement M provide the 13
development of rates for Non-Core Transmission Firm Transportation service. The 14
Monthly Service Charges per meter were increased similar to all other service charges by 15
increasing to a level at 50% of the difference between current and full cost of service and 16
rounded to the nearest five cents in the same manner as the charges for the Non-Core 17
Distribution Firm Transportation service. Both the present Reservation rate and the 18
Commodity base rates were increased by 6.72%, which is the proposed moderated revenue 19
for this class excluding property taxes and increased 7.16% with property taxes included. 20
21
STORAGE SERVICE – Page 19 of Statement M provides the development of proposed 22
Storage service rates. Because the current rates charged for Storage are significantly higher 23
PMN-36
than the costs to provide this service, the rates for this class were increased by less than the 1
system average increase, or by 5.87%. 2
3
NON-CORE INTERRUPTIBLE SERVICE – Finally, as indicated on lines 28 through 31 4
of page 1 of Statement M, the proposed DBU Interruptible Transportation and the TBU 5
Interruptible Transportation rates are proposed to increase by the same percent as the 6
corresponding firm classes. 7
8
Q. How do the proposed rate components compare to the unit costs derived from 9
NorthWestern’s ECOS study? 10
A. While the movement toward cost-based rates was tempered by concerns of customer 11
impact, as described in the Schwartzenberger Direct Testimony, the proposed rate 12
structures and revenue recovery compare favorably to their related cost components 13
(Statement M, pages 6 and 7). Exhibit__(PMN-1) provides a comparison of the existing 14
unit pricing by rate class with the proposed unit charges for each class (Statement M, pages 15
1 and 2). 16
17
Q. Has NorthWestern calculated bill impacts associated with natural gas rate designs? 18
A. Yes. Natural gas bill impacts are discussed in the Schwartzenberger Direct Testimony. 19
20
Q. In your opinion, are the proposed natural gas production and delivery service rates 21
fair and reasonable? 22
A. Yes. Based on the analyses I have performed and on my experience, I believe that the 23
proposed production and natural gas delivery service rates described above and developed 24
PMN-37
and presented in Statement M reasonably recover the embedded costs of providing service; 1
that these rates do not impose any undue customer impact or hardship; and that these rates 2
reflect a consistent application of recognized ratemaking standards. Consequently, I 3
believe that the proposed natural gas rates are fair and reasonable and that the Commission 4
should approve these proposed rates. 5
6
V. SUMMARY – ECOS STUDY AND RATE DESIGN 7
Q. Please summarize your recommendations regarding the embedded costs of service 8
information and study submitted in Statement L of this rate filing. 9
A. NorthWestern engaged MAC to prepare an ECOS study for this filing and to assist in rate 10
design efforts. The cost allocation methodologies employed in the ECOS study in 11
Statement L closely follow the methodologies employed in NorthWestern’s most recent 12
rate filing in Docket No. D2012.9.94 including certain improvements as described above. I 13
believe that the procedures employed in conducting the ECOS study comport with standard 14
industry practices, reflect the operations and characteristics of NorthWestern and its 15
customer classes, and provide fair and reasonable estimates of the costs of providing 16
service to the various customer classes. In my opinion, this study is a reliable and useful 17
document for determining class costs of service as an important foundation in the design of 18
class revenue targets and proposed rates. I recommend that this study be used to establish 19
natural gas rates in this proceeding. 20
21
Q. Please summarize your recommendations regarding NorthWestern’s proposed rates. 22
A. NorthWestern has proposed rates that balance the results of the ECOS study with a 23
number of often competing pricing considerations. The proposed rates represent a 24
PMN-38
movement toward cost-based rates while simultaneously giving due consideration to 1
consumer impact. Mr. Schwartzenberger recommended a well-reasoned and balanced 2
approach to developing class revenue objectives with the rate moderation proposal made 3
in his testimony. Within the guidelines of Mr. Schwartzenberger’s rate moderation 4
proposal, I designed rates that take into account the information provided by the ECOS 5
study. As I have testified above, I believe that the rates proposed by NorthWestern are 6
fair and reasonable and are neither overly burdensome nor unduly discriminatory. I 7
recommend that this Commission approve the natural gas rates proposed by 8
NorthWestern. 9
10
VI. SUMMARY – MARGINAL COST STUDY – GAS SUPPLY 11
Q. Please summarize your recommendations regarding the marginal costs of service 12
information and study submitted in Statement L of this rate filing. 13
A. NorthWestern engaged MAC to prepare a marginal cost study for Gas Supply for this 14
filing. The marginal cost methodology employed ten separate tables that arrive at pricing 15
levels presented in Table 10 by season and customer class. I believe that the procedures 16
employed in preparing the marginal gas supply study reflect our best estimate of future 17
costs, the operations and characteristics of the Company and its core customer classes, and 18
provide a reasonable estimate of the costs of providing gas supply on a seasonal and annual 19
basis. In my opinion, this study is a reliable and useful document for comparing existing 20
pricing levels for the Company. 21
22
PMN-39
VII. REVISED ECOS FOR PROPOSED STIPULATION ADJUSTMENT 1
Q. Have you prepared an ECOS analysis which reflects the removal of Administrative 2
and General (A&G) expenses and Common Plant from the Production functional 3
costs? 4
A. Yes, I have. After modifying the specific allocation factors for A&G and Common plant to 5
exclude any assignment to the Production function, I reran the ECOS and recalculated the 6
resulting cost and revenue requirements at an equalized ROR basis which I have attached 7
as Exhibit__(PMN-4). 8
9
Q. Could you please briefly discuss your revised ECOS results presented in 10
Exhibit__(PMN-4)? 11
A. Certainly. Table 1 of this exhibit shows the class and functional revenue requirements at 12
the Company’s equalized ROR level which can be compared to and is the same as Table 1 13
of the filed Statement L Part 1, page 1. The revised ECOS results are shown in Table 2 for 14
all classes and functions with A&G and Common excluded from any allocation to 15
Production. The revenue requirements for these re-allocated costs have now been shifted 16
by functions and customer classes through the allocation process with the same overall 17
revenue requirement being achieved as shown in Table 2. All of the revenue differences 18
from the re-allocation process are presented in Table 3 by functions and classes. 19
20
Q. Does this complete your Phase Two direct testimony? 21
A. Yes, it does. 22
NorthWestern EnergyNatural Gas Utility Rate DesignSummary of Proposed Rates
Excl Prop Tax Line Description Service Charge Distribution Transmission Storage Production Total 1 Residential:
Uniform System of Accounts ("USOC") ‐ a prescribed set of accounts established by the Federal Energy
Regulatory Commission uniformly applied to investor‐owned utilities for the purpose of
standardizing the recording of costs.
Docket No. D2016.9.68-Phase TwoExhibit__(PMN-3)
Page 1 of 1
Table - 10NorthWestern EnergyMarginal Cost Study - Gas SupplyDerivation of Marginal Prices Equi-Proportionately Constrained by Embedded Costs - Supply Service
Line Supply TotalNo. Description Residential Employee General Service Firm Utilities Company
Notes:1 Production Revenues are at 2015 Proposed Rates Excluding Gas Costs and Other Operating Revenues2 Commodity Revenues source Docket No. D2015.7.53, Exhibit_(JMS-2), Page 2 of 3, Line 273 Source: Table 8, page 1 of 14 Source: Table 9, page 1 * (1 + line 6). Design Day costs converted to Dkt based on 2015 volumes.
Total -131,917 -4,387,010 133,756 1,245,200 856,836 2,019,301 2,019,301Note: Difference of -$131,917 is due to two items. Rounding in the stipulation revenue requirements accounts of -$36,000 and the assignment of additional costs to Interruptible customers of -$96,000.
Revenue W/O TaxCustomer Class By Class Production Storage Transmission Distribution Customer Customer
Revenue Production Storage Transmission Distribution Customer Cust W/OCustomer Class By Class As Billed As Billed As Billed As Billed As Billed Tax Billed
Revenue Production Storage Transmission Distribution Customer Cust W/OCustomer Class By Class As Billed As Billed As Billed As Billed As Billed Tax Billed
Embedded Natural Gas Allocations by Utility Function
12
A B C D E F G H I J K L M N
Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator495051525354555657585960616263646566676869707172737475767778798081828384858687888990919293949596979899
100101102
Cust Contributed Capital - TDSAccum Deferred Inc Taxes
Embedded Natural Gas Allocations by Utility Function
12
A B C D E F G H I J K L M N
Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator103104105106107108109110111112113114115116117118119120121122123124125126127128129130131132133134135136137138139140141142143144145146147148149150151152153154155
O & M Expenses Prod Battle Creek 554,465$ 554,465 - - - - - - - - - - BattleCreek Prod Bear Paw 2,148,613$ - 2,148,613 - - - - - - - - - BearPaw Prod Devon 6,535,979$ - - 6,535,979 - - - - - - - - Devon Gas Supply Admin 503,955$ - - - 166,072 212,211 34,975 26,533 48,820 2,647 6,304 6,394 FuncRevXP Storage Operation 1,055,284$ - - - 143,069 - - - 912,215 - - - Storage Storage Maintenance 359,422$ - - - 48,728 - - - 310,694 - - - Storage Transmission Operation 7,766,588$ 7,766,588 Direct Transmission Maintenance 2,356,899$ 2,356,899 Direct Distribution Op - Supervision 2,181,949$ - - - - 859,881 908,368 413,700 - - - - DistOpLab Distribution Op - Meters 1,545,290$ 1,545,290 Direct Distribution Op - Cust Install 2,195,229$ - - - - - 1,040,613 1,154,615 - - - - MeterServices Dist Op - Cust Install - Battle Creek 71$ 71 - - - - - - - - - - BattleCreek Dist Op - Cust Install - Bear Paw 109$ - 109 - - - - - - - - - BearPaw Dist Op - Cust Install - Devon 205$ - - 205 - - - - - - - - Devon Distribution Op - Other 5,073,680$ 5,073,680 Direct Dist Op - Other - Battle Creek 9,396$ 9,396 - - - - - - - - - - BattleCreek Dist Op - Other - Bear Paw 14,560$ - 14,560 - - - - - - - - - BearPaw Dist Op - Other - Devon 27,220$ - - 27,220 - - - - - - - - Devon Distribution Mnt - Supervision 1,070,039$ - - - - 376,063 468,897 225,079 - - - - DistMnLab Distribution Mnt - Services 581,196$ 581,196 Direct Distribution Mnt - Meters 1,177,743$ 1,177,743 Direct Distribution Mnt - Other 679,753$ 679,753 Direct Customer Meter Reading 682,347 682,347 Direct Customer Records 2,360,682$ 33,772 52,333 97,836 2,176,741 Direct Customer Accounts 519,936$ 5,921 9,175 17,153 487,687 Direct Customer Service 1,588,712$ 39,857 61,764 115,466 1,371,625 Direct Sales Expense -$ - Direct A & G Expense - TDS Labor 14,911,685$ - - - 4,779,709 2,976,565 3,159,236 1,468,418 433,359 468,109 666,807 959,483 FuncLaborXP A & G Expense - TDS Revenue 62,468$ - - - 20,586 26,305 4,335 3,289 6,051 328 781 793 FuncRevXP A & G Expense - TDS Plant 1,360,874$ - - - 620,300 352,683 144,428 160,251 83,211 - - - FuncPlantXP A & G Expense - Battle Creek 485,261$ 485,261 - - - - - - - - - - BattleCreek A & G Expense - Bear Paw 766,161$ - 766,161 - - - - - - - - - BearPaw A & G Expense - Devon 1,473,723$ - - 1,473,723 - - - - - - - - DevonTotal O & M Expenses 60,049,492$ 1,128,742 3,052,716 8,267,582 15,901,951 10,557,139 8,483,887 4,033,081 1,794,351 1,153,430 2,850,633 2,825,980
Docket No. D2016.9.68 Statement L - Part 1
Page 7 of 16
Embedded Natural Gas Allocations by Utility Function
12
A B C D E F G H I J K L M N
Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator156157158159160161162163164165166167168169170171172173174175176177178179180181182183184185186187188189190191192193194195196197198199200201202203204205206
Total Prod Battle Creek Prod Bear Paw Prod Devon Transmission Distri Other Cust Meters Cust Services Storage Cust Mtr Read Cust Records Cust Other Allocator
Labor O & M Expenses Prod Battle Creek 105,419$ 105,419 - - - - - - - - - - BattleCreek - Prod Bear Paw 431,064$ - 431,064 - - - - - - - - - BearPaw - Prod Devon 1,099,229$ - - 1,099,229 - - - - - - - - Devon - Gas Supply Admin 369,690$ - - - 121,827 155,673 25,657 19,464 35,813 1,941 4,624 4,690 FuncRevXP - Storage Operation 377,311$ - - - 51,153 - - - 326,158 - - - Storage - Storage Maintenance 136,076$ - - - 18,448 - - - 117,628 - - - Storage - Transmission Operation 4,290,372$ 4,290,372 Direct - Transmission Maintenance 807,903$ 807,903 Direct - Distribution Op - Supervision 1,484,575$ - - - - 585,053 618,044 281,477 - - - - DistOpLab - Distribution Op - Meters 1,082,758$ 1,082,758 Direct - Distribution Op - Cust Install 1,590,331$ - - - - - 753,871 836,460 - - - - MeterServices - Distribution Op - Other 1,738,592$ 1,738,592 Direct - Distribution Mnt - Supervision 745,025$ - - - - 261,837 326,474 156,714 - - - - DistMnLab - Distribution Mnt - Services 330,983$ 330,983 Direct - Distribution Mnt - Meters 689,522$ 689,522 Direct - Distribution Mnt - Other 553,007$ 553,007 Direct - Customer Meter Reading 516,114$ 516,114.24 Direct - Customer Records 733,330$ 733,330$ Direct - Customer Accounts -$ - Direct - Customer Service 1,057,169$ 1,057,169 Direct - Sales Expense -$ - Direct - A & G Expense - Labor 5,476,904$ - - - 1,755,536 1,093,261 1,160,354 539,334 159,168 171,931 244,911 352,408 FuncLaborXP - A & G Expense - Prod Labor 202,763$ 13,068 53,435 136,260 A & G Expense - Gen Plant 1,292,055$ - - - 414,148 257,911 273,739 127,234 37,549 40,560 57,777 83,136 FuncLaborXP - Total Expenses 25,110,192$ 118,486$ 484,499$ 1,235,489$ 7,459,388$ 4,645,335$ 4,930,419$ 2,291,666$ 676,316$ 730,547$ 1,040,643$ 1,497,404$ -
Docket No. D2016.9.68 Statement L - Part 1
Page 16 of 16
STATEMENT L – PART 2
MARGINAL COST STUDY – GAS SUPPLY
Table - 1Page 1 of 1
Table - 1NorthWestern EnergyMarginal Cost Study - Gas SupplyProduction Investment
Line CompanyNo. Description Total
(1) (2) (3) (4) (5) (6)
New LNG Plant Using Trucked LNG for Liquid Supply
1 Plant Construction Costs {1} 63,554,000$ 2 Owner's Costs (1 year) {1} 10%3 6,355,400$ 4 Land {2} 70 Acres5 {3} 4,234$ per Acre6 296,3677 Total Investment 6,651,767$ 8 Deliverability, MSCFD {1} 50,0009 Dkt Conversion 1.08
10 Dkt/Day 54,000
11 Investment/Dkt/D 123.18$
Notes:1 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 7 of 11.2 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 3 of 11, paragraph 3.3 Real estate estimate provided by the Company.
Docket No. D2016.9.68 Statement L - Part 2
Page 1 of 22
Table - 2Page 1 of 6
Table - 2NorthWestern EnergyMarginal Cost Study - Gas Supply
Estimated Marginal Commodity Costs, $/Dkt
SupplyLine Residential Employee General Service Firm UtilitiesNo. Description D-RG-1 D-RG-2 D-GSG-1 D-FUGC-1
Notes:1 AECO strip price for 2018 as of 4/7/17.2 Based on TransCanada/Nova transportation rates. 3 Company estimates4 Under normal weather conditions, the daily marginal source of supply in the test year would be Off-system purchases from AECO delivered through the Nova system.
The hypothetical LNG facility would not be dispatched under normal weather conditions, only under extreme conditions
Docket No. D2016.9.68 Statement L - Part 2
Page 3 of 22
Table - 2Page 3 of 6
Table - 2NorthWestern EnergyMarginal Cost Study - Gas Supply
Average Marginal Commodity Cost, $/Dkt
Line DescriptionNo. Days in Month
(1)
1 OFF SYSTEM2 AECO Strip {1}
3 AECO Transportation {2}
4 Delivered Prices for Off-System Purchases {3}
56 Monthly Marginal Cost, $/Dkt
Notes:1 AECO strip price for 2018 as of 4/7/17.2 Based on TransCanada/Nova transportation rates. 3 Company estimates4 Under normal weather conditions, the daily marginal so
The hypothetical LNG facility would not be dispatched u
September October November December Total/Average30 31 30 31
Notes:1 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 8 of 11
Truckload system for the trucking option has been selected as opposed to the liquefaction option since it is more economical.2 Source is NWE Peak Shaving Facility Study - Phase II Cardwell West Site, page 7 of 11
Notes:1 Total O&M less Gas Raw Materials Expense and Other Gas Supply Expense2 Average of years after implementation
of new accounting system.3 Source for Expenses is the Annual Reports
Docket No. D2016.9.68 Statement L - Part 2
Page 9 of 22
Table - 4Page 2 of 4
Table - 4NorthWestern EnergyMarginal Cost Study - Gas SupplyDevelopment of A & G Loading Factors
LineNo. Description
(1) (2)
1 Nonplant Related Expenses2 920- Administrative & General Salaries3 921- Office Supplies & Expenses4 922- Administrative Exp. Transferred-Cr.5 923- Outside Services Employed6 925- Legal & Claim Department7 926- Employee Pensions & Benefits8 930- Miscellaneous General Expenses910 408-Payroll Taxes (Schedule 11)11 Total Non-Plant121314 Plant Related Expenses6 924- Property Insurance16 928- Regulatory Commission Expenses17 931- Rents18 935- General Plant Maintenance19 Total Plant Related Expenses202122 Total Allocable O&M {1}
2324 A & G Loading Factor Nonplant Related Exp25 line 11 / line 2226 Average 2002 - 2016 {2} = 24.05%272829 Total Gross Gas Plant $303132 A & G Loading Factor Plant Related Exp33 line 19 / line 2934 Average 2002 - 2016 {2} = 0.38%
Notes:1 Total O&M less Gas Raw Materials Expense and Other Gas Sup2 Average of years after implementation
of new accounting system.3 Source for Expenses is the Annual Reports
1 Common & General Plant Loading Factor2 General Plant 16,248,186$ 16,256,615$ 16,211,644$ 16,090,516$ 14,316,057$ 13,993,685$ 14,281,276$ 11,532,635$ 12,821,131$ 3 Common Plant Assigned to Gas 14,134,647$ 13,447,245$ 14,012,437$ 26,963,375$ 26,165,336$ 27,218,466$ 27,975,885$ 28,682,658$ 29,507,288$ 4 Total General and Common 30,382,833$ 29,703,860$ 30,224,081$ 43,053,891$ 40,481,393$ 41,212,151$ 42,257,162$ 40,215,293$ 42,328,419$ 5 Total Gas Utility Plant 378,790,041$ 393,024,764$ 411,212,400$ 416,333,506$ 438,067,538$ 464,510,969$ 489,072,577$ 507,294,984$ 542,836,569$ 67 Gen Plant Factor line 4 / (line 5 - line 4) 8.72% 8.18% 7.93% 11.53% 10.18% 9.74% 9.46% 8.61% 8.46%8 Average 2002 - 2016 {2} = 8.75%91011 Loss Factor Calculation12 Total Sendout 35,854,801 32,975,423 34,826,477 35,365,202 36,276,641 35,868,783 40,030,783 39,495,030 37,746,90713 Total Sales 35,473,532 32,650,343 34,444,541 34,709,757 35,644,281 36,042,271 39,194,217 38,491,313 36,924,8391415 Loss Factor line 13 / line 12 98.94% 99.01% 98.90% 98.15% 98.26% 100.48% 97.91% 97.46% 97.82%16 Average 2002 - 2016 {2} = 98.51%
Notes:1 Source: Annual Reports2 Average of years after implementation
of new accounting system.
Docket No. D2016.9.68 Statement L - Part 2
Page 11 of 22
Table - 4Page 4 of 4
Table - 4NorthWestern EnergyMarginal Cost Study - Gas SupplyDevelopment of Miscellaneous Loading Factors
LineNo. Description
(1) (2)
1 Common & General Plant Loading Factor2 General Plant3 Common Plant Assigned to Gas4 Total General and Common5 Total Gas Utility Plant67 Gen Plant Factor line 4 / (line 5 - line 4)8 Average 2002 - 2016 {2} = 8.75%91011 Loss Factor Calculation12 Total Sendout13 Total Sales1415 Loss Factor line 13 / line 1216 Average 2002 - 2016 {2} = 98.51%
Notes:1 Source: Annual Reports2 Average of years after implementation
1 Levelized Cost for: Book Life2 Production Plant {1} 11.46% 9.48%34 INCREMENTAL COST OF CAPITAL {2}
5 Debt 4.67% 53.21%6 Preferred 0.00% 0.00%7 Common 10.01% 46.79%8 Other 0.00% 0.00%9 Weighted Cost of Incremental Capital 7.17%
101112 After Tax Cost of New Capital {3} 6.19%13 Incremental Tax Rate {4} 39.39%14 Tax Effected Cost of Capital {5} 10.24%15 Property Tax Rate {6} 3.19%16 MPSC & MCC Tax Rate {7} 0.30%17 Inflation Rate {8} 1.60%18 Property Tax Escalation Rate {8} 2.10%19 Commodity Escalation Rate {9} 2.10%20 Deferred Tax Rate 35.00%
Notes:1 Source: Table - 5, page 2.2 Weighted average current cost of raising capital in 2015.3 Wtd Cost of Capital (9) less tax savings on debt interest.4 Incremental tax rate assumed to be 35% Federal and 7% State tax which
results in a combined effective rate of 39.39%.5 Tax effected cost of capital plus tax component on return6 Current composite average tax rate.7 The state's 1.01% franchise tax is excluded since it is surcharged.8 Annual Energy Outlook 20179 Commodity price escalation factor assumed by MAC.
Docket No. D2016.9.68 Statement L - Part 2
Page 13 of 22
Table - 5Page 2 of 4
Table - 5NorthWestern EnergyMarginal Cost Study - Gas SupplyLevelized Fixed Charge Analysis - Input Data
LNGLINE ProductionNO. VARIABLE Plant
(1) (2)
1 Plant Data2 PLANT BALANCE 6,651,767 3 CAPITALIZED COST $1,0004 BOOK LIFE 355 SALVAGE VALUE 5%6 MACRS LIFE 20789 Capital Structure
10 DEBT RATIO 53.21%11 PREFERRED RATIO 0.00%12 COMMON RATIO 46.79%13 OTHER _____________ 0.00%141516 Cost of Capital17 DEBT COST 4.67%18 PREFERRED COST 0.00%19 COMMON COST 10.01%20 OTHER 0.00%21 WTD COST OF CAPITAL 7.17%22 AFTER TAX COST / CAP 6.19%232425 Tax Data26 TAX RATE 39.39%27 ITC RATE 0.00%28 REVENUE TAX RATE 0.30%29 PROPERTY TAX RATE 3.19%30 PROPERTY INSURANCE 0.00%31 DEFERRED TAX RATE 35.00%32 PROPERTY TAX BASIS 233 1 = Original Cost34 2 = Depreciated Bal3536 Misc. Data37 INFLATION RATE 1.60%38 PROP TAX ESC RATE 2.10%39 RETURN BASIS 240 1 = Begin of Year41 2 = Avg Begin & End42 3 = End of Year
Notes:1 Source: Workpapers
Docket No. D2016.9.68 Statement L - Part 2
Page 14 of 22
Table - 5Page 3 of 4
Table - 5NorthWestern EnergyMarginal Cost Study - Gas SupplyLevelized Fixed Charge Analysis - Production Plant
CURRENT PERCENT OF CONSTANT PERCENT OF
LINE LEVELIZED CAPITAL LEVELIZED CAPITAL
NO. ITEM DOLLARS INVESTMENT DOLLARS INVESTMENT
(1) (2) (3) (4) (5) (6)
1 INTEREST ON DEBT $14.99 1.50% $12.40 1.24%2 RETURN ON PREF $0.00 0.00% $0.00 0.00%3 RETURN ON COMMON $28.25 2.82% $23.38 2.34%45 RETURN lines 1 thru 3 $43.23 4.32% $35.78 3.58%6789 DEPRECIATION $27.14 2.71% $22.46 2.25%
Table - 5NorthWestern EnergyDevelopment of Revenue Requirements StreamProduction Plant
ANNUAL % of PresentYear Rate Interest Return On Return On Tax Book Deferred Taxable Inc Tax Revenue Property Property Revenue Original Worth Of No. Base On Debt Preferred Common Deprec'N Deprec'N Tax Income Payable Tax Tax Insurance Reqm'Ts Investm'T Rev Req'Mt
Table - 6NorthWestern EnergyMarginal Cost Study - Gas SupplySummary of Marginal Capacity Costs
LineNo. Description Production Capacity
(1) (2) (3) (4)
1 PLANT INVESTMENT2 Long-Run Unit Costs - $/Design Day Dkt {1} 123.18$ 3 Common & General Plant Loading Factor {2} 8.75%4 Unit Costs + Loading Factor line 2 + (line 2 * line 3) 133.96$ 56 Fixed Charge Rate {3} 9.48%7 A&G Exp Plant-Related Loading Factor {4} 0.38%8 Total Rate line 6 + line 7 9.86%910 Annualized Cost line 4 * line 8 13.20$ 1112 OPERATING EXPENSES13 Production capacity costs {5} 12.55$ 14 A&G Exp Non-Plant Loading Factor {4} 24.05%15 Total O&M Expense line 13 * [1+ line 14] 15.57$ 1617 WORKING CAPITAL18 Materials & Supplies + Prepayments Rate {5} 0.35%19 M&S Cost line 4 * line 21 0.47$ 20 Working Cash O&M Allowance {6} [line 10 + line 15] * -18% (5.14)$
21 Total Working Capital line 19 + line 20 (4.67)$ 2223 Working Capital Rev. Req'd (23)*10.24% {7} (0.48)$ 2425 System Seasonal Capacity Related Cost26 $/Design Day Dkt line 10 + line 15 + line 23 28.29$ 2728 Loss Factor {4} 0.98529 Inflation Adjustment {8} 3.19%3031 Plant-related Costs [(10)+(23)]*[1+(29)]/(28) 13.33$ 32 O&M-related Costs (15)*[1+(29)]/(28) 16.31$ 33 Seasonal Capacity Cost, $ Design Day Dkt (26)*[1+(29)]/(28) 29.64$
Notes:1 Source: Table - 1, page 1.2 Source: Table - 4, page 2.3 Source: Table - 5, page 1.4 Source: Table - 4, page 1.5 Source: Table - 2, page 2.6 Working cash computed on the basis of -65.21 days net lag.7 Revenue requirement for working cash computed as the after tax cost of capital, i.e.
debt costs plus equity costs increased by taxes equals 10.24%.8 Inflation adjustment to restate marginal costs to 2018 dollars.
Docket No. D2016.9.68 Statement L - Part 2
Page 17 of 22
Table - 6Page 2 of 2
Marginal Cost Study - Gas SupplySummary of Marginal Capacity Costs Adjusted for Uncollectibles
Line SupplyNo. Description Residential Employee General Service Firm Utilities
Table - 10NorthWestern EnergyMarginal Cost Study - Gas SupplyDerivation of Marginal Prices Equi-Proportionately Constrained by Embedded Costs - Supply Service
Line Supply TotalNo. Description Residential Employee General Service Firm Utilities Company
Notes:1 Production Revenues are at 2015 Proposed Rates Excluding Gas Costs and Other Operating Revenues2 Commodity Revenues source Docket No. D2015.7.53, Exhibit_(JMS-2), Page 2 of 3, Line 273 Source: Table 8, page 1 of 14 Source: Table 9, page 1 * (1 + line 6). Design Day costs converted to Dkt based on 2015 volumes.
Docket No. D2016.9.68 Statement L - Part 2
Page 22 of 22
5/25/2017 8:12 AM 1 of 19 NG Stmt M 2015 Rev rebuttal final Statement M
(A) (B) (C) (D) (E) (F) (H) (I) (J)
ACOSAverage Monthly Market Present Results Moderated Proposed Class
1 GS Total $38,719,759 $39,600,473 $880,715 2.27% $41,303,388 $2,583,629 6.67% $41,303,388 $2,583,629 6.67%234 Present Rates: Average Service Sales Monthly5 Customers Charge (Therms) Distribution Transmission Storage Total Service Charge Distribution Transmission Storage
Revenue
6 GS Total 67,919,333 $0.225274 $0.120118 $0.036475 $0.381868 $15,300,470 $8,158,355 $2,477,364 $25,936,1897 0 to 300 * 15,114 $15.05 $2,729,041 2,729,0418 301 to 1,000 3,343 $19.85 796,400 796,4009 1,001 to 2,000 3,337 $32.00 1,281,114 1,281,114
10 2,001 to 5,000 1,243 $53.75 801,515 801,51511 5,001 to 10,000 286 $66.00 226,650 226,65012 10,001 to 30,000 32 $104.35 40,277 40,27713 > 30,000 4 $126.80 6,594 6,59414 Total 23,359 $5,881,590 $15,300,470 $8,158,355 $2,477,364 $31,817,77915 Average Production 6,901,97916 Total $38,719,75917 Product Rate $0.1016201819 Present Rates without Property Taxes: Average Service Sales Monthly
20 Customers Charge (Therms) Distribution Transmission Storage Total Service Charge Distribution Transmission Storage Total
Revenue 21 GS Total 67,919,333 $0.161289 $0.095472 $0.028991 $0.285752 $10,954,635 $6,484,401 $1,969,043 $19,408,07822 0 to 300 * 15,114 $15.05 $2,729,041 2,729,04123 301 to 1,000 3,343 $19.85 796,400 796,40024 1,001 to 2,000 3,337 $32.00 1,281,114 1,281,11425 2,001 to 5,000 1,243 $53.75 801,515 801,51526 5,001 to 10,000 286 $66.00 226,650 226,65027 10,001 to 30,000 32 $104.35 40,277 40,27728 > 30,000 4 $126.80 6,594 6,59429 Total 23,359 $5,881,590 $10,954,635 $6,484,401 $1,969,043 $25,289,66930 Average Production 6,784,29631 Total $32,073,96532 Product Rate $0.0998883334 Present Rates Property Taxes: Sales Monthly35 (Therms) Distribution Transmission Storage Total Service Charge Distribution Transmission Storage
Revenue
36 GS Total 67,919,333 $0.063985 $0.024646 $0.007484 $0.096116 $4,345,835 $1,673,953 $508,322 $6,528,11037 0 to 300 *38 301 to 1,00039 1,001 to 2,00040 2,001 to 5,00041 5,001 to 10,00042 10,001 to 30,00043 > 30,00044 Total $4,345,835 $1,673,953 $508,322 $6,528,11045 Average Production 117,68346 Total $6,645,79347 Product Rate $0.001733
89 Property Taxes per COS, Production per Rev Requirement, Service Charge COS Moderated Property Taxes per COS, Production per Statement H, Service Charge COS Moderated90 Moderated Revenues ---------------------------------------Calculated Unit Prices ---------------------------------------- ----------------------------------------- Calculated Unit Revenue ------------------------------------------91 Unit Costs and Revenue Service Charge Distribution Transmission Storage Production Total Service Charge Distribution Transmission Storage Production Total92 Unit Costs ($/Therm)93 Base Charge w/o Property Tax See detail below $0.109680 $0.130774 $0.017828 0.126569 $0.384851 $8,159,691 $7,449,410 $8,882,104 $1,210,847 $8,118,731 $25,661,09394 Property Tax $0.000000 $0.057744 $0.045258 $0.004999 0.002296 $0.110297 0 3,921,910 3,073,882 339,529 147,282 7,482,60395 Total Commodity Charge $0.167424 $0.176032 $0.022827 $0.128865 $0.49514896 Monthly Service Charge97 0 to 300 * $20.88 $3,786,07398 301 to 1,000 $27.54 1,104,86899 1,001 to 2,000 $44.39 1,777,325
100 2,001 to 5,000 $74.56 1,111,963101 5,001 to 10,000 $91.57 314,437102 10,001 to 30,000 $144.76 55,878103 > 30,000 $175.91 9,147104 Average $29.11 Prop. Revenue $8,159,691 $11,371,321 $11,955,986 $1,550,376 $8,266,013 $41,303,388105 Present Revenue $5,881,590 $15,300,470 $8,158,355 $2,477,364 $6,901,979 $38,719,759106 Revenue Change $2,278,101 -$3,929,149 $3,797,631 -$926,988 $1,364,034 $2,583,629107 % Change 38.7% -25.7% 46.5% -37.4% 19.8% 6.67%108109110 ---------------------------------------Proposed Rates ---------------------------------------- ----------------------------------------- Proposed Revenue ------------------------------------------111 Unit Costs Proposed Rates and Revenue Service Charge Distribution Transmission Storage Production Total Service Charge Distribution Transmission Storage Production Total112 Rate ($/Therm)113 Base Charge w/o Property Tax See detail below $0.120828 $0.144066 $0.019640 $0.126569 $0.411103 $6,485,639 $8,206,558 $9,784,869 $1,333,916 $8,118,731 $27,444,075114 Property Tax $0.000000 $0.056886 $0.044586 $0.004925 $0.002296 $0.108693 $3,863,670 $3,028,235 $334,487 $147,282 7,373,674115 Total Commodity Charge $0.177714 $0.188652 $0.024564 $0.128865 $0.519795116 Monthly Service Charge117 0 to 300 * $16.60 $3,010,626118 301 to 1,000 $21.90 878,562119 1,001 to 2,000 $35.25 1,411,375120 2,001 to 5,000 $59.25 883,595121 5,001 to 10,000 $72.75 249,824122 10,001 to 30,000 $115.00 44,390123 > 30,000 $139.75 7,267124 Average $23.14 Prop. Revenue $6,485,639 $12,070,229 $12,813,104 $1,668,403 $8,266,013 $41,303,388125 Present Revenue $5,881,590 $15,300,470 $8,158,355 $2,477,364 $6,901,979 $38,719,759126 Revenue Change $604,048 -$3,230,241 $4,654,749 -$808,961 $1,364,034 $2,583,629127 % Change 10.3% -21.1% 57.1% -32.7% 19.8% 6.67%
Docket No. D2016.9.68 Statement M
Page 10 of 19
5/25/2017 8:12 AM 11 of 19 NG Stmt M 2015 Rev rebuttal final Utilities
Therms Therms Therms Allocated Allocated Moderated ModeratedLine Function MDDQ Capacity Injection Withdrawal Base Property Tax Total Base Property Tax Total $ Increase % Increase Costs % Increase
1 Revenue and Billing Information:2 Storage $2,798,334 $722,085 $3,520,419 $2,394,458 $773,635 $3,168,093 -$352,326 -10.01% $3,727,113 5.87%3 Reservation 548,885 347,748,510 32,006,830 32,459,880 45 Property Taxes per COS67 Rate Development: Base Property Tax Base Property Tax Total Base Property Tax Total Base Property Tax Total Base Property Tax Base Property Tax89 Reservation Charges: