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Document Document

Direct Testimony and Schedules Ian R. Benson
Before the Minnesota Public Utilities Commission State of Minnesota
In the Matter of the Application of Northern States Power Company for Authority to Increase Rates for Electric Service in Minnesota
Docket No. E002/GR-20-723 Exhibit___(IRB-1)
Transmission
November 2, 2020

Table of Contents

I. Introduction

1

II. Transmission System Business Unit

8

III. Capital Investments

13

A. Overview

13

B. Transmission Capital Budget Development and Management 19

C. Capital Investment Trends for 2017 to 2020

30

D. Overview of Capital Investments for 2021 to 2023

38

E. Major Planned Investments for 2021 to 2023

47

F. Key Capital Additions for 2021 to 2023

49

1. Asset Renewal Projects

49

2. Reliability Requirement Projects

69

3. Interconnection Projects

74

4. Physical Security and Resiliency Projects

78

5. Regional Expansion Projects

82

6. Communication Infrastructure Projects

85

IV. O&M Budget

89

A. O&M Overview and Trends

89

B. O&M Budgeting Process

97

C. O&M Budget Detail

100

1. Internal Labor

100

2. Contract Labor and Consulting

101

3. Employee Expenses

102

4. Fees

103

5. Materials

104

6. Miscellaneous

105

i

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V. Third-Party Transmission Expenses and Wholesale Transmission 106 Revenues
A. Overview of the Transmission System in Minnesota and the 106 Upper Midwest

B. Third-Party Transmission Expenses and Revenues

108

C. Pending FERC ROE Proceedings

116

IV. Transmission System Line Loss Analysis

122

VII. Conclusion

126

Schedules Statement of Qualifications Transmission's Capital Additions: 2021-2023 Transmission's O&M Costs by Category: 2017-2023 Third-Party Transmission Expenses Third-Party Transmission Revenues Joint Zonal Revenue and Expenses

Schedule 1 Schedule 2 Schedule 3 Schedule 4 Schedule 5 Schedule 6

ii

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1

I. INTRODUCTION

2

3 Q. PLEASE STATE YOUR NAME AND OCCUPATION.

4 A. My name is Ian Benson. I am the Area Vice President for Transmission Strategy

5

and Planning for Xcel Energy Services Inc. (XES), the service company affiliate

6

of Northern States Power Company ­ Minnesota (NSPM or the Company) and

7

an operating company of Xcel Energy Inc. (Xcel Energy).

8

9 Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE.

10 A. I have more than 29 years of experience in the utility industry and have served

11

in positions in nuclear generation, retail electric marketing, wholesale power

12

purchases and sales, and transmission. In my current position as the Area Vice

13

President for Transmission Strategy and Planning, my responsibilities include

14

supervising department engineers in planning electric transmission system

15

expansions, recommending specific construction projects to Xcel Energy

16

management and the Midcontinent Independent System Operator, Inc.

17

(MISO), overseeing transmission-related agreements with MISO and other

18

counterparties, and resolving wholesale customer transmission service

19

concerns. My resume is attached as Exhibit___(IRB-1), Schedule 1.

20

21 Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING?

22 A. I present and support the Company's capital forecasts and operation and

23

maintenance (O&M) expense requests for the Transmission organization for

24

purposes of determining electric revenue requirements and final rates in this

25

proceeding. I also provide information related to third-party transmission

26

expenses and wholesale transmission revenues and their impact on the

27

Company's revenue requirements. Further, I discuss a pending Federal Energy

1

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1

Regulatory Commission (FERC) complaint against the MISO transmission

2

owners related to the return on equity (ROE) and its potential impact on our

3

third-party transmission expenses and wholesale revenues. Finally, I report on

4

methods for calculating transmission system line losses as required by the

5

Commission's order in the Company's 2015 electric rate case (Docket No.

6

E002/GR-15-826).

7

8 Q. WHAT ARE THE KEY RESPONSIBILITIES AND OBJECTIVES OF THE TRANSMISSION

9

ORGANIZATION?

10 A. The NSP Companies, NSPM and Northern States Power Company ­

11

Wisconsin (NSPW), own, operate, and maintain an integrated transmission

12

system that has facilities in portions of Minnesota, North Dakota, South

13

Dakota, Wisconsin, and the upper peninsula of Michigan (NSP Transmission

14

System).

15

16

The Transmission organization is responsible for the planning, construction,

17

operation, and maintenance of these transmission facilities that allow energy to

18

be safely and reliably transported from generating resources (both Company-

19

owned and third-party owned) to the distribution systems that serve customers.

20

The Transmission organization is focused on ensuring that the NSP

21

Transmission System is reliable, resilient, and able to efficiently accommodate

22

an increasingly diverse and dispersed number of generators.

23

24 Q. WHAT WORK DOES THE TRANSMISSION ORGANIZATION UNDERTAKE TO

25

ENSURE RELIABILITY OF THE TRANSMISSION GRID?

26 A. The Transmission organization makes investments that maintain and improve

27

the reliability of the transmission system. An important component of

2

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maintaining the reliability of the transmission system is replacing or refurbishing

2

facilities that are in poor condition or have reached the end of their life. Many

3

of our transmission facilities were placed in-service more than 50 years ago and,

4

in some cases, these facilities are 70 years old or older. For instance, on the

5

NSP Transmission System, we have more than 500 miles of line that is 70 years

6

old or older. The Company continually assesses the age and condition of

7

transmission facilities. While age is not dispositive of the condition of an asset,

8

it is often used to identify assets for which condition may be a concern.

9

Likewise, while it is not necessarily the case that every asset should be replaced

10

at the end of its service life, in some cases, the age of the Company's facilities

11

increases the likelihood that an element will fail when stressed.

12

13

Additionally, recent severe weather incidents, including the derecho storm that

14

hit parts of the Midwest on August 10, 2020 and the California wildfires, have

15

underscored the importance of addressing the condition of aging transmission

16

infrastructure. The Transmission organization has several programs, including

17

its Major Line Rebuild program, that are focused on examining and evaluating

18

the condition and performance of each component of the transmission system.

19

We then prioritize new investments based on this evaluation and make the

20

necessary repairs and upgrades to maintain the reliability of the system.

21

22 Q. ARE THERE OTHER FACTORS AND INVESTMENTS THAT IMPACT TRANSMISSION

23

SYSTEM RELIABILITY?

24 A. Yes. Another part of maintaining the reliability of the system involves making

25

investments to maintain compliance with the mandatory standards set by the

26

North American Electric Reliability Corporation (NERC) and FERC. We are

27

constantly studying our system to determine what additional infrastructure

3

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1

investments are needed as these standards are updated and as customer loads

2

and generation mixes change.

3

4

Further, the reliability of our transmission system also depends on the physical

5

security and resiliency of the system. Thus, in addition to reliability standards,

6

NERC has also issued physical security standards, or Critical Infrastructure

7

Protection (CIP) standards, to protect the transmission system's key physical

8

assets from potential threats and attacks. Transmission also makes investments

9

to improve the physical security of our substations to comply with these CIP

10

standards. These investments include improving the perimeter fencing,

11

installing additional cameras and other monitoring devices, and replacing

12

substation gates.

13

14 Q. WHAT WORK DOES THE TRANSMISSION ORGANIZATION UNDERTAKE TO

15

SUPPORT INCREASINGLY DIVERSE AND DISPERSED GENERATION RESOURCES?

16 A. The Transmission organization makes investments to reliably and cost-

17

effectively accommodate new generation. In recent years, we have witnessed

18

unprecedented amounts of renewable energy seeking to interconnect to the

19

grid. As of September 1, 2020, there was 107.6 gigawatts of new capacity in the

20

MISO queue associated with 717 individual projects, the vast majority of which

21

were new wind and solar projects. To accommodate some of these new

22

generators, who are seeking to interconnect their projects with the Company's

23

transmission system, the Company will be making increasing investments to

24

facilitate their interconnection over the course of the multi-year rate plan.

25

26

Concurrent with this growth in renewable generation, Xcel Energy and other

27

utilities are in the process of retiring large fossil fuel generation plants. This

4

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1

shifting generation mix has required, and will continue to require, more than

2

just individual interconnection projects. This shift will require large regional

3

expansion investments similar to the CapX2020 projects and the MISO's Multi-

4

Value Projects (MVPs) to integrate the large quantities of low-cost renewable

5

energy currently pending in the MISO queue.

6

7 Q. HOW WILL THE COMPANY IDENTIFY NEW TRANSMISSION PROJECTS THAT WILL

8

BE REQUIRED TO ACCOMMODATE NEW GENERATION?

9 A. To develop this next set of transmission projects, Xcel Energy, along with its

10

other CapX2020 partners, published the CapX2050 Transmission Vision

11

Report (Vision Report) in March 2020.1 The purpose of this report was to

12

provide stakeholders with a basic understanding of the potential operational and

13

planning issues that need to be considered and addressed to facilitate the

14

transition from traditional dispatchable generation resources (coal, natural gas,

15

and nuclear) to a fleet with more non-dispatchable, weather-dependent

16

resources (wind and solar). This Vision Report will lay the foundation for future

17

studies by the CapX2050 partners and MISO that will result in a long-term

18

transmission plan to facilitate greater reliance on renewable, non-dispatchable

19

resources. While we do not plan to in-service any new regional expansion

20

projects during the term of this multi-year rate plan, this Vision Report, along

21

with MISO's annual transmission report, will help guide our future transmission

22

investments in this area.

23

1 A copy of this report is publicly available at: http://www.capx2020.com/documents/CapX2050_TransmissionVisionReport_FINAL.pdf

5

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1 Q. PLEASE PROVIDE A SUMMARY OF YOUR TESTIMONY.

2 A. In my Direct Testimony, I will discuss the Transmission organization and the

3

NSP Transmission System. I will also describe the various entities, in addition

4

to the Minnesota Public Utilities Commission (Commission), that regulate the

5

transmission system.

6

7

I will explain that the Transmission organization is proposing capital additions

8

of approximately $354.0 million for 2021, $340.0 million for 2022, and $316.7

9

million for 2023 to support the objectives I discussed above. These capital

10

additions include the Huntley­Wilmarth 345 kV Project for which the

11

Company will continue to seek recovery of through the Transmission Cost

12

Recovery (TCR) Rider. The Huntley­Wilmarth 345 kV Project has capital

13

additions of $73.2 million in 2021 and $4.3 million in 2022. Company witness

14

Mr. Benjamin C. Halama will discuss the TCR Rider cost recovery in greater

15

detail. I will describe Transmission's six capital budget groupings and the

16

importance of these investments in maintaining a safe, reliable, and robust

17

transmission system. I will provide details about the major planned investments

18

and key capital projects that the Transmission organization will place in service

19

during the term of this multi-year rate plan.

20

21

I will also discuss the Transmission O&M budgets for 2021 to 2023, which are

22

driven by internal labor, contract labor and consulting, fees, and materials. The

23

Transmission O&M budget for 2021 is $38.2 million, $38.7 million in 2022, and

24

$40.4 million in 2023. The average O&M expense budgeted for these three

25

years ($39.1 million) is below the most recent three-year historical average (2017

26

to 2019) of $39.20 million. I will provide further explanation as to why our

6

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1

O&M budget for each year is reasonable and allows us the ability to perform

2

the work necessary to construct and maintain the transmission system.

3

4

Additionally, I will discuss the MISO third-party transmission expenses and

5

wholesale transmission revenues that are budgeted for 2021 to 2023. The third-

6

party transmission expense for 2021 is $93.2 million, 2022 is $96.2 million, and

7

2023 is $98.0 million. These costs are the result of the NSP Companies serving

8

their native load customers in five other MISO pricing zones and a small load

9

outside of MISO. The wholesale transmission revenues are $92.8 million for

10

2021, $97.4 million for 2022, and $99.9 million for 2023. This revenue is the

11

result of transmission services and ancillary services provided to other utilities

12

with load in pricing zones where NSP owns transmission assets.

13

14

Finally, I report on methods to calculate line losses on the transmission system

15

as required by the Commission's Order in the Company's 2015 electric rate case.

16

17 Q. HOW IS THE REST OF YOUR TESTIMONY ORGANIZED?

18 A. My testimony is organized as follows:

19

· Section II ­ Transmission System Business Unit

20

· Section III ­ Capital Investments

21

· Section IV ­ O&M Budget

22

· Section V ­ Third-Party Transmission Expenses and Wholesale

23

Transmission Revenues

24

· Section VI ­ Transmission System Line Loss Analysis

25

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1

II. TRANSMISSION SYSTEM BUSINESS UNIT

2

3 Q. PLEASE PROVIDE AN OVERVIEW OF THE COMPANY'S TRANSMISSION SYSTEM.

4 A. The NSP Companies (NSPM and NSPW) are vertically integrated electric

5

utilities that own and operate electric transmission facilities in portions of

6

Minnesota, North Dakota, South Dakota, Wisconsin, and the upper peninsula

7

of Michigan. Together, the NSP Companies own an integrated transmission

8

system comprising approximately 8,400 miles of transmission facilities

9

operating at voltages between 34.5 kV and 500 kV, and approximately 548

10

transmission and distribution substations. The NSP Companies are

11

transmission owning members of MISO. The NSP Transmission System is

12

planned and operated on an integrated basis and has been under the functional

13

control of MISO since it began operations in February 2002. Transmission

14

service over the NSP Transmission System is open access, and transmission

15

service reservations can be requested and approved under the terms of the

16

MISO Tariff.

17

18 Q. CAN YOU DESCRIBE THE CUSTOMERS SERVED BY THE NSP TRANSMISSION

19

SYSTEM?

20 A. The NSP Transmission System serves the following two customer groups: (1)

21

retail native loads in Minnesota, North Dakota, South Dakota, Wisconsin, and

22

Michigan; and (2) the loads of other investor-owned utilities, cooperatives, and

23

municipal load serving entities (LSEs), and wholesale customers. The wholesale

24

customers comprise approximately 20 percent of the total demand on the NSP

25

Transmission System, with the remaining demand composed of retail native

26

load customers. From a transmission planning and transmission service

27

perspective, our retail customers and the wholesale customers require the same

8

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1

level of service, and as a result, the system is planned to serve the needs of each

2

type of customer equally.

3

4 Q. OTHER THAN STATE REGULATORY COMMISSIONS, SUCH AS THE MINNESOTA

5

PUBLIC UTILITIES COMMISSION, WHAT OTHER ENTITIES REGULATE THE NSP

6

TRANSMISSION SYSTEM?

7 A. The NSP Transmission System is regulated primarily by three entities other than

8

state regulatory commissions. The first is FERC. FERC is a federal

9

independent agency that regulates the interstate transmission of electricity,

10

natural gas, and oil. The Energy Policy Act of 2005 gave FERC additional

11

responsibilities. As part of that responsibility related to electric transmission,

12

FERC:

13

· Regulates the transmission and wholesale sales of electricity in interstate

14

commerce;

15

· Reviews the siting applications for electric transmission projects under

16

limited circumstances;

17

· Protects the reliability of the high voltage interstate transmission system

18

through mandatory reliability standards;

19

· Enforces FERC regulatory requirements through imposition of civil

20

penalties and other means; and

21

· Administers accounting and financial reporting regulations and conduct

22

of regulated companies.

23

24

The second is NERC. NERC is a not-for-profit international regulatory

25

authority whose primary role is to assure the reliability and security of the

26

country's Bulk Electric System (BES). NERC does this by issuing and enforcing

27

reliability standards, which transmission operators, including the Company, are

9

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1

required to comply with; annually assessing seasonal and long-term reliability;

2

monitoring the BES through system awareness; and educating, training, and

3

certifying industry personnel. As the certified Electric Reliability Organization

4

(ERO), NERC is subject to oversight by FERC.

5

6

Third is the Midwest Reliability Organization (MRO). MRO is a non-profit

7

organization dedicated to ensuring the reliability and security of the bulk power

8

system in the north-central region of North America, including parts of both

9

the United States and Canada. MRO is one of six regional entities in North

10

America operating under authority from regulators in the United States through

11

a delegation agreement with NERC, and in Canada through arrangements with

12

provincial regulators. The primary purpose of MRO is to ensure compliance

13

with reliability standards and perform regional assessments of the grid's ability

14

to meet the demands for electricity. MRO audits the NSP Companies for

15

compliance with NERC's reliability standards.

16

17 Q. PLEASE DESCRIBE MISO AND ITS ROLE WITH RESPECT TO THE NSP

18

TRANSMISSION SYSTEM.

19 A. MISO is an independent system operator and regional transmission

20

organization providing open-access transmission service, monitoring the high-

21

voltage transmission system, and operating one of the world's largest real-time

22

energy markets. NSPM and NSPW are transmission-owning members of

23

MISO. This means that, although the NSP Companies own and maintain their

24

transmission assets, MISO operates the NSP Transmission System, in

25

conjunction with the transmission systems of the other 52 transmission owners.

26

Furthermore, MISO establishes: (1) the process and rules for wholesale

27

customers to access the NSP Transmission System on a non-discriminatory

10

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1

basis; (2) the annual transmission planning process for expanding or upgrading

2

the regional transmission system, which includes the NSP Transmission System

3

(i.e., MISO Transmission Expansion Plan (MTEP)); and (3) the policies and

4

procedures that provide for the allocation of costs incurred to construct certain

5

transmission upgrades and the distribution of revenues associated with those

6

costs.

7

8 Q. PLEASE DESCRIBE THE DEPARTMENTS WITHIN THE TRANSMISSION

9

ORGANIZATION AND THEIR KEY FUNCTIONS.

10 A. There are six departments within the Transmission organization. The key

11

functions of these departments are as follows:

12

· Asset management is responsible for substation field engineering, which

13

includes routine and emergency maintenance and operational activities

14

for all Xcel Energy substations. The organization also provides field

15

implementation of certain NERC and CIP compliance activities, and

16

"commissioning" new substation facilities. Commissioning of Xcel

17

Energy substation facilities involves ensuring that our substation facilities

18

meet the operational and reliability requirements of FERC and NERC as

19

well as Xcel Energy. The Quality Assurance/Quality Control (QA/QC)

20

process performed by Xcel Energy commissioning engineers and

21

technicians thoroughly tests the equipment and control systems of our

22

electric substations prior to energizing. This organization is also

23

responsible for system sustainability. System sustainability provides,

24

among other things, electric material and design standards for the design,

25

construction, and maintenance of our transmission assets by interpreting

26

industry standards such as the American National Standards Institute

27

(ANSI). System sustainability is also responsible for developing Xcel

11

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1

Energy's reliability-centered maintenance programs that ensure the

2

health and reliability of existing assets. These processes establish the

3

baseline performance expected by our operations and maintenance

4

organizations and confirm the performance for compliance standards.

5

· Transmission strategy and planning is responsible for: (1) life cycle planning,

6

transmission system planning, and associated capital budgeting; (2)

7

negotiating transmission-service-related contracts with generators,

8

transmission owners, and distribution utilities; and (3) resolving

9

wholesale customer transmissions service concerns. In addition, this

10

organization manages Xcel Energy's participation in key regional projects

11

throughout its service territory, as well as other regional projects on and

12

adjacent to Xcel Energy's transmission systems, including the NSP

13

Transmission System. This group is also responsible for Xcel Energy's

14

policies and procedures in the competitive transmission acquisition

15

processes pursuant to various requirements of FERC Order 1000. I

16

serve as the Area Vice President for this organizational area.

17

· Field operations provides field services for construction, maintenance, and

18

emergency repairs for transmission assets.

19

· Transmission portfolio delivery is responsible for managing capital projects,

20

programs, and portfolios, including designing and engineering

21

transmission assets, managing third-party contractors, and securing and

22

managing transmission land rights.

23

· System operations is primarily responsible for the NERC Balancing

24

Authority and Transmission Operations function for all Xcel Energy

25

transmission systems, including the NSP Transmission System.

12

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1

· Transmission business operations directs the Transmission business unit's

2

efforts pertaining to compliance with NERC requirements and directs

3

business performance achievement efforts.

4

5

III. CAPITAL INVESTMENTS

6

7

A. Overview

8 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

9 A. In this section, I discuss capital budget trends for Transmission from 2017 to

10

2020 and discuss major planned investments and key capital projects for 2021,

11

2022, and 2023. I will also provide details regarding how the Transmission

12

business unit develops its annual capital budget and correspondingly identifies

13

and prioritizes capital projects within the confines of the capital budget.

14

Furthermore, I will discuss how Transmission monitors and controls spending

15

on capital projects as they move from approval through construction.

16

17 Q. PLEASE MAKE THE OVERALL BUSINESS CASE FOR TRANSMISSION'S CAPITAL

18

PROGRAM.

19 A. Reliable and efficient electric service for our customers depends on a strong

20

transmission system composed of facilities that are in good working order and

21

that are able accommodate a diverse mix of generators. The capital investments

22

made by the Transmission business unit are necessary to allow the electricity

23

generated by Company-owned and third-party generators to reach our

24

customers. To maintain the health and reliability of the transmission system,

25

the Transmission organization has made and continues to make reasonable

26

investments in maintaining existing facilities and building new transmission

27

infrastructure to replace facilities in poor condition or to meet NERC

13

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1

requirements or to accommodate new generators. These investments ensure

2

the reliable electric service that residential customers and businesses expect,

3

while also supporting a competitive wholesale electricity market that allows

4

access to low-cost generation across the MISO system.

5

6

Absent ongoing investments in our transmission system, the reliability and

7

efficiency of this important system would be at risk. The Transmission

8

organization recognizes that the Company's overall budget is limited, and we

9

seek to prioritize projects in a manner that achieves an appropriate balance in

10

maintaining the health and reliability of our transmission system while also

11

making long-term, cost-effective investments for our customers.

12

13 Q. GENERALLY SPEAKING, WHAT TYPE OF CAPITAL INVESTMENTS ARE MADE BY

14

THE TRANSMISSION ORGANIZATION?

15 A. Our capital projects require investments in transmission line components, such

16

as poles, conductors, gang-operated switches, and land rights for transmission

17

line easements. They also include investments in substation components such

18

as transformers, capacitor banks, reactors, circuit breakers, relay and

19

communication equipment, remote terminals, and real property.

20

21

Our capital projects fall into two main categories. The first consists of large

22

capital projects that are often multi-year projects. These projects are capital

23

intensive and are aimed at improving the transmission system; upgrading

24

existing facilities to meet NERC compliance requirements and to accommodate

25

new generation; replacing aging facilities; and making improvements to

26

communication infrastructure and physical security.

27

14

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1

In addition to these larger capital projects, Transmission also completes many

2

smaller capital projects each year. These smaller projects comprise a majority

3

of the total number of projects that we complete each year, but make up only a

4

minor part of our overall capital budget. Some examples of these smaller

5

projects include replacement of one to two structures or cross-arms due to

6

condition, storm damage, or age. Figure 1 and Figure 2 below depict this

7

breakdown for 2021-2023 for NSPM and NSPW. As shown in these figures,

8

our capital projects with greater than $10.0 million each in capital additions

9

make up 83 percent of our total capital additions budget each year for NSPM

10

and NSPW, but comprise only 24 percent of our total number of projects.

11

12

Figure 1

13

2021-2023 Total Number of Transmission Capital Projects

14

15

16

17

18

19

20

21

22

23

24

15

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1

Figure 2

2

2021-2023 Total Transmission Capital Budget

3

(Dollars in Millions)

4

5

6

7

8

9

10

11

12

13

14

15 Q. ARE THERE ANY OTHER UNIQUE FEATURES OF TRANSMISSION'S CAPITAL

16

INVESTMENTS?

17 A. Yes. Transmission's capital projects often require several years of development

18

and construction before they are placed in-service as capital additions. This is

19

because many of our capital projects require multiple steps, such as transmission

20

study work and planning, route selection, initial design, permitting, final design,

21

land acquisition, site preparation, and then construction. As a result, the

22

Company may have capital expenditures for a particular project that span

23

multiple years, with an in-service date several years after the first expenses are

24

incurred.

25

16

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1 Q. HOW DOES TRANSMISSION CATEGORIZE ITS CAPITAL ADDITIONS?

2 A. Our capital projects fall into six capital budget groupings based on the main

3

purpose of the project. These grouping are:

4

· Asset Renewal: This category is primarily for managing the health and

5

performance of transmission assets. The main goal is to ensure that

6

critical assets including transmission lines, substations, and other related

7

assets meet reliability and capacity requirements, while minimizing life-

8

cycle costs. This includes planned replacement of aging transmission

9

lines and substation equipment; unplanned replacement of lines or

10

equipment damaged by storms; additions to, or replacement of, aging

11

fleet vehicles and tools that support capital additions; and line relocations

12

due to road projects.

13

· Reliability Requirement: Reliability projects are constructed to ensure

14

that the transmission system is complaint with all NERC reliability

15

standards. Compliance with NERC reliability standards is mandatory for

16

all users, owners, and operators of the BES. FERC, NERC, and regional

17

reliability entities monitor and enforce compliance. Any entity found

18

non-compliant may be subject to fines of up to $1.2 million per day per

19

violation. The Transmission organization is continually studying the

20

transmission system to assess compliance with NERC standards. These

21

studies analyze the impacts of forecasted load growth, existing and

22

anticipated generation needs, and new generation interconnections to

23

determine whether transmission upgrades are necessary.

24

· Interconnection: This category includes projects that the Company is

25

required to construct under the FERC Open Access Transmission Tariff

26

(OATT) to accommodate interconnection requests from generators,

27

transmission lines, and new load.

17

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1

· Physical Security and Resiliency: There are two critical aspects to this

2

grouping of projects: physical security and grid resiliency. Physical

3

security addresses physical threats to utility infrastructure, such as

4

transmission lines and substation equipment. Grid resiliency addresses

5

the Company's ability to monitor and recover from incidents occurring

6

on our system to limit disturbances that may leave our service territory

7

exposed to prolonged outages, oftentimes by adding redundancy to our

8

transmission system. This category also includes projects intended to

9

address NERC standards related to security and grid resiliency.

10

· Regional Expansion: This category includes major high voltage

11

transmission line projects that are developed through the regional

12

planning process and serve multiple needs including regional and local

13

reliability and renewable energy outlet. Generally, these are multi-year

14

initiatives and the types of projects for which the Company seeks a

15

Certificate of Need and/or Route Permit from the Commission. This

16

category also includes projects necessary to support economic

17

development.

18

· Communication Infrastructure: This category includes the fiber optic

19

and communication network infrastructure build-out on the existing

20

transmission system to improve communication connectivity for all

21

business units. This infrastructure allows the digital transfer of

22

Supervisory Control and Data Acquisition (SCADA) data and

23

teleprotection services. As telecommunication service providers are

24

retiring the existing obsolete analog connections, Xcel Energy will be

25

continuing our efforts to privatize our communication network

26

infrastructure across the NSPM and NSPW service territories. By

27

reducing dependencies on third-party telecommunications and building

18

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1

our own, the transmission system communication infrastructure

2

improves the transmission and distribution system reliability,

3

performance, and cyber security.

4

5

Many of our capital additions serve multiple purposes, but for budgeting

6

purposes, we classify the capital project according to its primary purpose.

7

8

B. Transmission Capital Budget Development and Management

9 Q. HOW DOES TRANSMISSION ESTABLISH A REASONABLE CAPITAL BUDGET FOR A

10

GIVEN YEAR?

11 A. The annual capital budget for Transmission is based on collaboration between

12

corporate management of the overall Company finances and the business needs

13

that are identified by Transmission. Company witness Ms. Melissa L. Ostrom

14

explains how the Company establishes overall business unit capital spending

15

guidelines and budgets based on financing availability, specific needs of business

16

units, and the overall needs of the Company.

17

18 Q. CAN YOU PROVIDE A SUMMARY OF TRANSMISSION'S CAPITAL BUDGETING

19

PROCESS?

20 A. Transmission employs a "bottom-up" budgeting process to identify the capital

21

projects that we need to complete within a specific year for our business unit.

22

All of our capital projects are executed under our Capital Project Governance

23

Process. This governance process has policies and procedures in place that

24

enable Transmission to prioritize and balance our budget such that we

25

appropriately allocate funds. Our capital budgeting process includes four main

26

steps:

27

1. Identification of potential projects,

19

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1

2. Vetting of potential projects,

2

3. Prioritization of potential projects, and

3

4. Rebalancing and reprioritization of projects based on corporate budget

4

requirements.

5

6 Q. WHAT IS THE FIRST STEP IN YOUR BUDGETING PROCESS?

7 A. We begin our budgeting process by identifying and assessing the potential work

8

that is proposed for integration into the current five-year budget period. New

9

projects must satisfy a clearly defined purpose and need. The criteria used to

10

identify and assess projects are based on the six capital budget groupings I

11

discussed earlier. The budgeting process also takes into account existing

12

projects that were previously approved based on the corporate governance

13

approval requirements that Ms. Ostrom describes. The annual budget is a very

14

dynamic process where new project needs and financial requirements are

15

prioritized against existing projects that most often take multiple years from

16

initial budget approval to construction completion and close out.

17

18 Q. HOW DO YOU IDENTIFY ASSET RENEWAL PROJECTS?

19 A. Our system sustainability group identifies facilities in need of replacement or

20

refurbishment based on a variety of factors. For transmission lines, these

21

factors include: (1) the importance of a particular line to being able to reliably

22

serve customers; (2) the line's age and condition; and (3) the line's reliability

23

history. These factors receive different weights to determine which lines are in

24

the greatest need of replacement. Generally speaking, those lines that will

25

negatively affect the most customers if they fail are placed higher on the list for

26

replacement. For substation assets, a similar matrix is used. The system

20

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1

sustainability group then uses these lists to determine the urgency of each

2

replacement and identifies specific projects for possible inclusion in the budget.

3

4

Asset Renewal projects also include relocations required by road construction

5

projects. We work with federal, state, and local highway road departments to

6

identify needed relocations.

7

8 Q. HOW ARE RELIABILITY REQUIREMENT PROJECTS IDENTIFIED?

9 A. Our Reliability Requirement projects are identified based on MISO's annual

10

MTEP studies, which are an RTO lead reliability study effort. NERC requires

11

utilities to perform annual assessments of their transmission system. The

12

Company performs this annual assessment by participating in the MISO MTEP

13

process. The MISO MTEP studies the performance of the system using 1-year,

14

5-year, and 10-year future models. MISO typically finalizes its annual MTEP

15

study in December of each year.

16

17 Q. HOW DO YOU DEVELOP AN INITIAL LIST OF INTERCONNECTION PROJECTS FOR

18

THE BUDGETING PROCESS?

19 A. Our Transmission planning department gathers all available information from

20

interconnection requests submitted to the Company, either internally, from

21

other utilities, or from MISO, who administers generation interconnections.

22

23 Q. DO YOU DEVELOP A BUDGET TO ACCOUNT FOR PREVIOUSLY UNIDENTIFIED

24

INTERCONNECTION REQUESTS?

25 A. Yes. The Company typically receives interconnection requests year-round,

26

some of which will require specific funding in years that were not previously

27

planned for in our typical budget cycle. For the projects not accounted for in

21

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1

our typical budget cycle, the Company holds funding in a program called

2

Interconnection Agreement (IA) Tariff Fund. The amount budgeted for this

3

program is based on historical averages and known demand of Interconnection

4

project requests. As the Company receives these previously unplanned

5

requests, funding is made available from the IA Tariff Fund to a specific

6

interconnection project as appropriate.

7

8 Q. HOW ARE PHYSICAL SECURITY AND RESILIENCY PROJECTS IDENTIFIED?

9 A. Physical security projects are identified based on the NERC CIP-014-2

10

standard. In 2018, the Company performed a vulnerability analysis of our BES

11

(100 kV and above) substations within the NSP System. The analysis identified

12

critical facilities and physical security improvements at multiple BES substations

13

throughout the NSP system and was validated by third-party review as is

14

required by the NERC standard. After validation, each identified site is

15

prioritized for possible inclusion in the budget. CIP-014-2 requires that the

16

Company reevaluate our system every two years, so we anticipate that this

17

biennial study will continue to identify these capital projects as our transmission

18

system evolves.

19

20

Grid resiliency projects address the Company's ability to monitor and recover

21

from incidents occurring on our system to limit disturbances that may leave our

22

service territory exposed to prolonged outages. For example, based on FERC

23

Order 754, non-redundant equipment required to facilitate breaker operation

24

was added, as a contingency event, to the NERC TPL-001-4 standard. System

25

planning identifies projects annually as part of their TPL-001-4 study to

26

remediate reliability impacts caused by contingencies for possible inclusion into

27

the Transmission budget.

22

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1

2 Q. HOW ARE REGIONAL EXPANSION PROJECTS IDENTIFIED?

3 A. As I mentioned earlier, the Company takes part in regional transmission

4

planning efforts to identify needed Regional Expansion projects. The Company

5

is involved with the CapX2020 initiative, which identified and constructed the

6

CapX2020 group of projects. As I also mentioned above, this same group of

7

utilities recently completed the CapX2050 Transmission Vision Report to

8

understand the potential operational and planning issues associated with the

9

transition to more renewable, non-dispatchable generation resources.

10

11

The Company also takes part in MISO's yearly MTEP process, which works

12

with all MISO transmission owners and stakeholders to identify Regional

13

Expansion projects. The MTEP process identifies regional system needs and

14

develops and vets possible solutions. The solutions that best meet the long-

15

term needs of the regional transmission system are then approved by the MISO

16

Board of Directors in the annual MTEP process.

17

18 Q. HOW ARE COMMUNICATION INFRASTRUCTURE PROJECTS FIRST IDENTIFIED?

19 A. Our substation communication engineering group identifies and assesses

20

projects based on a specific set of criteria that considers issues like BES

21

criticality, past performance of systems currently in-service, O&M costs

22

associated with existing leased connections, telecommunication companies

23

phasing out certain technology, benefit to other business units, and integration

24

into existing Company-owned infrastructure. Based on this analysis, the

25

substation communication engineering group identifies projects for

26

consideration in the Transmission capital budget.

27

23

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1 Q. AFTER THE LIST OF POSSIBLE CAPITAL PROJECTS IS DEVELOPED, WHAT IS THE

2

NEXT STEP IN THE BUDGETING PROCESS?

3 A. The project originator develops a proposed statement of work for each project,

4

normally consisting of the proposed preliminary scope, project description,

5

need and benefits description, alternatives and proposed option, desired

6

completion date, consequences of not doing the project, and a basic electric

7

circuit diagram.

8

9

Multi-disciplinary project teams are then assembled. These project teams have

10

a diverse set of functional skills including financial management, project

11

management, design and engineering, system operations, construction, siting

12

and land rights, scheduling, vegetation management, and planning. The project

13

teams develop a detailed preliminary scope and schedule for the project with

14

supporting documentation. The project team may also prepare high-level cost

15

estimates to assess alternatives and weigh proposed solutions against other

16

alternatives. These estimates help determine the most reasonable electrical and

17

financial solution to meet the identified transmission needs. The preliminary

18

project scope for the preferred solution is entered into Transmission's

19

budgeting and forecast software tool, called TamCasting.

20

21 Q. WHAT HAPPENS AFTER THE PRELIMINARY SCOPE IS DEVELOPED?

22 A. The proposed project is presented for preliminary scope approval at the regular

23

occurring Constructability (C1) meeting. All projects must pass through this C1

24

gate before proceeding to the next project phase. At this C1 meeting, the

25

project's preliminary scope is peer reviewed by employees from relevant

26

functional areas of the Transmission organization (including project

27

management, engineering design, Transmission planning, siting and land rights,

24

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1

construction, and operations). The objective of this meeting is to review and

2

challenge the project need and the proposed preliminary scope while looking

3

for fatal flaws or better solutions. Project alternatives are reviewed to determine

4

whether the proposed solution is the most cost-effective and provides the most

5

long-term value for our customers.

6

7

Approval at the C1 meeting allows the project to pass through the C1 gate to

8

the next step in the process. Projects not approved at the C1 meeting are either

9

cancelled or returned to the project origination phase for further need and

10

preliminary scope development based on peer review feedback at the C1

11

meeting. The project may be re-presented at a future C1 meeting for approval.

12

13 Q. IF A PROJECT IS APPROVED AT A C1 MEETING, WHAT IS THE NEXT STEP?

14 A. The project proceeds to the budget estimate package phase. Based on the C1

15

approved preliminary scope, the project manager coordinates the development

16

of a budget estimate by reviewing the project deliverables with the project team,

17

identifying and documenting routing and design assumptions, conducting field

18

visits, and collecting estimates generated by engineering, siting and land rights,

19

construction, and vegetation management. In special circumstances, pre-

20

construction work orders are generated for planning and development costs--

21

such orders require immediate, out-of-cycle budget approval. The project

22

group also begins to develop an outage plan, a project-specific safety plan and

23

site security plan, and prepares a preliminary risk register. The project team

24

then assembles the budget estimate package and presents it for approval as part

25

of the annual budget process. This is referred to as the "Budget Approval"

26

phase.

27

25

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1 Q. WHAT ACTIVITIES TAKE PLACE IN THE BUDGET APPROVAL PHASE?

2 A. The Budget Approval phase involves the creation of Transmission's annual

3

budget and schedule for capital projects. This annual budget aligns with the

4

budgeting and budget governance process that Ms. Ostrom addresses in her

5

testimony. Each business unit, including Transmission, works closely with

6

corporate financial performance and reporting to develop capital budgets.

7

8 Q. WHAT IS THE FIRST STEP IN THE BUDGET APPROVAL PHASE?

9 A. The first activity for Transmission in the Budget Approval phase involves the

10

project managers refreshing the cost estimates for previously approved projects.

11

Project managers then enter new proposed project attributes, proposed

12

monthly cash flows, and in-service dates into TamCasting.

13

14 Q. AFTER ALL POSSIBLE CAPITAL PROJECTS ARE PLACED IN TAMCASTING, WHAT IS

15

THE NEXT STEP?

16 A. Our directors and managers, along with other key employees review all possible

17

projects that are entered into TamCasting and represent our proposed budget

18

to determine which should be implemented and included in the Transmission

19

budget.

20

21

As many of our Reliability Requirement and Regional Expansion projects are

22

multi-year projects, once these projects have commenced, it is difficult to halt

23

or defund these projects in subsequent budget years. We do, however, examine

24

all capital expenditures for a given year to determine whether they are necessary

25

to carry out the final execution of those projects. As a result, these projects

26

often receive higher priority in our budgeting process as they move forward

27

toward completion. Similarly, given our MISO Tariff obligations, we have little

26

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1

latitude to deny specific Interconnection projects from being included in our

2

budget.

3

4

After we determine the portion of our budget that is committed to these

5

projects, we examine our remaining budget and determine how to prioritize the

6

remaining proposed projects and previously planned projects. We prioritize

7

those projects based on the risk and urgency of a particular project.

8

9

After a series of meetings to discuss all of the potential projects and the

10

appropriate prioritization given funding availability, the result is an initial capital

11

budget for Transmission.

12

13 Q. AFTER THE INITIAL BUDGET IS DETERMINED, WHAT IS THE NEXT STEP?

14 A. Transmission's proposed capital budget then moves through the corporate

15

budgeting process discussed by Ms. Ostrom. Based on the corporate budgeting

16

process, a higher or lower percentage of the Company's overall budget may be

17

allocated to Transmission depending on the priority of needs at the Company

18

level. Once the corporate budgeting process is complete, Transmission may be

19

able to maintain its capital budget as proposed or it may need to adjust based

20

on the thresholds established at a corporate level.

21

22 Q. WHAT HAPPENS IF TRANSMISSION DOES NOT RECEIVE ALL OF ITS REQUESTED

23

FUNDING?

24 A. The capital projects that Transmission identifies as necessary in a particular year

25

often exceed the budget thresholds established at a corporate level. When this

26

occurs, our directors and managers reexamine our budget and reprioritize our

27

capital projects based on the new thresholds. During the reprioritization

27

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1

process, we carefully evaluate all of the system risks associated with each of

2

these budget reduction scenarios and reevaluate all mitigation plans that may

3

mean a suboptimal operation of the transmission system but ensure our

4

compliance with all mandated system reliability standards.

5

6 Q. CAN YOU PROVIDE AN EXAMPLE OF A PROJECT THAT WAS ELIMINATED FROM

7

TRANSMISSION'S CAPITAL BUDGET BASED ON THIS REPRIORITIZATION?

8 A. Yes, a project called "Larimore Substation Conversion" was proposed for

9

inclusion in our 2023 capital budget but was deferred until 2024 due to budget

10

reprioritization between both the Transmission organization and Distribution

11

organization.

12

13 Q. IF YOU ARE ABLE TO DEFER THIS PROJECT, IS IT EVEN NECESSARY?

14 A. The Larimore Substation Conversion project is needed but we determined that

15

it can be delayed one year. The project involves replacing a transformer in the

16

existing substation in Larimore, North Dakota with a higher capacity

17

transformer. The project also includes converting several distribution feeders

18

from 4 kV to 12.5 kV to better serve the existing area distribution load. While

19

the project is needed, system conditions allow the project to be deferred for a

20

year to allow more pressing need in the transmission system to be addressed.

21

22 Q. DOES THIS BUDGETING PROCESS THAT YOU HAVE DESCRIBED ENSURE THAT

23

TRANSMISSION'S CAPITAL ADDITIONS ARE REASONABLE AND NECESSARY IN

24

EACH YEAR OF THIS MULTI-YEAR RATE PLAN?

25 A. Yes. This budgeting process results in a reasonable budget that is representative

26

of the capital investments needed to maintain the reliability of the transmission

27

system used to provide electric service to our customers, provide necessary

28

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1

upgrades to the regional transmission system, comply with NERC reliability

2

requirements and other policy drivers, meet system capacity needs, and ensure

3

the health of existing assets.

4

5 Q. PLEASE EXPLAIN THE PROCESS YOU FOLLOW TO MANAGE CAPITAL

6

EXPENDITURES AFTER BUDGET APPROVAL.

7 A. From a financial perspective, capital projects are reviewed on a monthly basis

8

after approval to compare the monthly budget to actual funds spent. We

9

perform a monthly project forecasting exercise to ensure we have a steady and

10

dependable flow of financial information regarding capital expenditures.

11

Through this process, the entire transmission project portfolio is reviewed and

12

consolidated each month. Any variances are immediately addressed. All

13

projects that indicate they may be outside of allowed variances are reevaluated

14

and assessed internally by the Transmission business unit and may be escalated

15

to the corporate level. For larger projects, greater than or equal to $10 million,

16

we adhere to the corporate guidelines to seek "re-approval" of projects outside

17

allowed variances.

18

19

Review is also performed to compare year-to-date actual performance with year-

20

to-date and year-end forecasts. Deviations are identified, and recommendations

21

to meet financial targets are reviewed and approved. Changes are reported to

22

the financial performance and planning group, which monitors capital spending.

23

The Transmission business unit is expected to manage its capital additions to

24

its capital budget once that budget has been developed, fully-vetted, and

25

approved. The budgeting process and accountability tools allow us to do so.

26

29

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1

C. Capital Investment Trends for 2017 to 2020

2 Q. FOR 2017 TO 2019, WHAT WERE THE PRIMARY DRIVERS FOR TRANSMISSION'S

3

CAPITAL ADDITIONS?

4 A. From 2017 to 2019, our capital investments were focused on in-servicing several

5

large Regional Expansion projects. This included the remaining CapX2020

6

projects, which were completed in 2017, as well as the Badger Coulee Project,

7

a MISO designated MVP, that was completed in 2018 (also referred to as the

8

La Crosse­Madison Project).

9

10

In 2019, our capital investments in Regional Expansion declined as our

11

investments in Asset Renewal projects grew. This greater focus on Asset

12

Renewal projects was due to interrelated factors including a reassessment of our

13

transmission line inspection practices and the age and condition of our

14

transmission facilities.

15

16 Q. WHY DID THE COMPANY REASSESS THE TRANSMISSION LINE INSPECTION

17

PROGRAMS?

18 A. We reassessed our inspection programs due to the occurrence of California

19

wildfires in 2018 and 2019 that were caused by Pacific Gas & Electric Co.

20

(PG&E) transmission lines. In particular, the 2018 Camp Fire, caused by sparks

21

from faulty utility equipment, was one of the deadliest and most destructive

22

wildfires in California history. While wildfires are not a high risk in the Midwest,

23

they did propel us to examine our system, our inspection practices, and our

24

Asset Renewal programs to ensure that we are making the necessary

25

investments to address the risks we face here, such as high winds or ice storms.

26

As a result of this review, we determined a need to increase the frequency of

30

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1

our transmission line inspections to ensure that faulty equipment is identified

2

and addressed in a timely manner.

3

4 Q. PLEASE DESCRIBE THESE CHANGES TO THE TRANSMISSION LINE INSPECTIONS.

5 A. Beginning in 2018, we increased our foot patrols from every six years to every

6

four years, and increased ground line inspections which are completed for each

7

part of our system on a 12-year cycle. The frequency of these inspections was

8

benchmarked against industry practices. In 2019, we also started using

9

Unmanned Aerial Vehicles (drones) to inspect our transmission facilities. In

10

2020, we inspected over 1,000 miles of line on the NSP Transmission System.

11

12 Q. WHAT WAS THE IMPACT OF THESE INCREASED INSPECTIONS?

13 A. This increase in inspections has resulted in more defects being identified that

14

require repair or replacement. For instance, in 2019, a much higher percentage

15

of poles were ranked as Priority 2 and required immediate replacement as

16

compared to the previous two years. Specifically, in 2017 and 2018, the

17

percentage of poles ranked as Priority 2 were 1.9 percent and 2.2 percent,

18

respectively, of the total number of poles tested. In, 2019 the percentage of

19

poles ranked as Priority 2 rose to 5.0 percent of the total poles tested.

20

21

Given the condition and age of certain of our facilities, this increase in identified

22

defects due to increased inspections is consistent with our expectations. Our

23

wood and steel structures have an expected useful life of 70 years. While steel

24

structures tend to have slightly longer useful lives as compared to wood

25

structures, we utilize 70 years as a guideline for the useful life of both our wood

26

and steel structures. Currently, there are over 500 miles of transmission line

27

that are supported by structures that are 70 years old or older on the NSP

31

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1

Transmission System. While the age of a structure is not necessarily indicative

2

of its condition, older assets are most often the assets where condition may be

3

an issue given the length of time that they have been exposed to the elements.

4

5 Q. HOW DID THE COMPANY MAINTAIN THESE TRANSMISSION FACILITIES ABSENT

6

HIGHER CAPITAL INVESTMENT IN PRIOR YEARS?

7 A. Prior to 2019, we were able to keep these aging transmission assets in working

8

order through general maintenance (O&M costs) and either refurbishment or

9

replacement of specific components when they reached the end of their service

10

life. As part of these refurbishment projects, we replaced only specific

11

components that were in poor condition, like cross-arms, insulators, and some

12

poles, with the existing conductor remaining in-place. Through these

13

refurbishments, we were able to extend the life of these assets by 10 to 20 years

14

depending on asset condition and the scope of the refurbishment.

15

16 Q. DO THE CHANGES YOU DISCUSS ABOVE IMPACT TRANSMISSION'S ASSET

17

RENEWAL CAPITAL BUDGET FOR THE MULTI-YEAR RATE PLAN (MYRP) PERIOD?

18 A. Yes. Over the last five years, we have started to see that assets that were

19

previously refurbished need wholesale replacement. This can either be because

20

of the aggregate condition of all of the components of a circuit (poles, cross-

21

arms, insulators, and conductor) or where the existing design, such as the

22

current pole size, limit our ability to refurbish other components. An example

23

of this would be our lines with copper conductors. When this conductor ages,

24

it becomes brittle. Ideally, we want to replace the conductor and insulators;

25

however, if the existing poles are not able to accommodate the weight of the

26

new conductor and insulator, we need to rebuild the entire line rather than

27

simply replacing the conductor and insulators. As a result, in 2019, we began

32

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1

to identify more lines that required a complete rebuild due to the fact that

2

refurbishment was no longer an option. Given that rebuilds often require more

3

lead time to plan and implement, many of these rebuild projects were set in

4

motion to be placed in service as part of our capital budgets for 2021 through

5

2023.

6

7 Q. DID TRANSMISSION INCREASE ITS CAPITAL INVESTMENTS IN OTHER BUDGET

8

CATEGORIES DURING THIS PERIOD?

9 A. Yes. During 2017 to 2019, Transmission also completed work on several

10

smaller Reliability Requirement projects with several of these projects going in

11

service in 2018. These projects included the Pomerleau Lake Substation and

12

the Gleason Lake Substation projects in Minnesota in 2018 and the Minot Load

13

Serving Project in North Dakota in 2018 and the Maple River Red River 115

14

kV Project in North Dakota in 2019.

15

16

From 2017 to 2019, we also made increasing expenditures in the Physical

17

Security and Resiliency category to make necessary physical security upgrades at

18

eighteen of the Company's substations in Minnesota and installed additional

19

security measures such as cameras, lighting, and controlled access points at 41

20

of the Company substations in Minnesota, North Dakota, and Wisconsin.

21

22 Q. FOR 2017 TO 2020, HOW DID YOUR CAPITAL INVESTMENTS BREAK INTO THE

23

CAPITAL BUDGET GROUPINGS?

24 A. Table 1 below shows the breakdown of capital expenditures by each capital

25

budget grouping for 2017 to 2020. (I note that 2020 is a forecast based on six

26

months of actuals and six months of forecast.)

27

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1

Table 1

2

2017-2020 Capital Expenditures

3

(Excludes AFUDC) (Dollars in Millions)

4

NSPM and NSPW

2017

2018

2019

2020

(both Total Company)

5

Asset Renewal

Actual $68.8

Actual $69.5

Actual Forecast $104.4 $116.2

6

Reliability Requirement

$52.9

$75.1

$47.5

$34.0

7

Interconnection

$1.9

$10.8

$6.8

$20.2

8

Physical Security and Resiliency

$17.6

$16.5

$19.0

$12.9

9

Regional Expansion

$76.9

$60.1

$14.6

$40.7

10

Communication Infrastructure

11

Totals

$3.3 $221.4

$1.9 $233.8

$0.9 $193.2

$0.7 $224.7

12

13

Table 2 below shows the breakdown of capital additions by each of the six

14

capital budget groupings for 2017 to 2020. The amounts presented in my

15

testimony include costs recovered or intended to be recovered through the TCR

16

Rider. Mr. Halama will discuss the TCR Rider in greater detail. I am including

17

these amounts here as these projects are part of our overall Transmission capital

18

budget.

19

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1 Table 2

2 2017-2020 Capital Plant Additions

3

(Includes AFUDC)

4
NSPM and NSPW

(Dollars in Millions)

2017

2018

2019

2020

5

(both Total Company)

Actual Actual Actual Forecast

6

Asset Renewal

$57.4

$72.3

$77.6 $106.7

Reliability Requirement
7
Interconnection

$55.9 $7.6

$96.2 $9.8

$39.1 $6.7

$43.2 $21.9

8
Physical Security and Resiliency

$16.9

$14.4

$15.8

$18.1

9

Regional Expansion

$74.0 $183.5 $22.3

$3.9

10

Communication Infrastructure

$8.7

$4.5

$0.3

$1.3

11

Totals

$220.5 $380.7 $161.8 $195.1

12

13 Q. CAN YOU EXPLAIN THE SIGNIFICANT INCREASE IN CAPITAL ADDITIONS IN 2018

14

AS COMPARED TO 2017 AND 2019?

15 A. Yes. This is primarily due to the in-servicing of a large Regional Expansion

16

project, Badger Coulee, with $170.2 million in capital additions in 2018.

17

Additionally, in 2018, we also placed in service several larger value Reliability

18

Requirement projects as compared to 2017 and 2019. The Reliability

19

Requirement projects completed in 2018 include the Gleason Lake Substation

20

and Pomerleau Lake Substation projects in Minnesota and the Minot Load

21

Serving Project in North Dakota. Finally, from 2017 to 2018, our investments

22

in Asset Renewal projects increased due to the need to replace a greater number

23

of aging transmission assets in poor condition. For example, in 2018 the

24

Company completed 36 discrete End-of-Life Relay projects as opposed to

25

completing only eight of these replacements in 2017. Similarly, in our Major

26

Line Rebuild and Major Line Refurbishment programs, we saw a limited

27

number of projects completed and total dollars in-serviced in 2017 (four

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projects totaling $18,101) as compared to the completion of eight projects in

2

these same programs in 2018 for a total plant addition of $11.1 million.

3

4 Q. PLEASE EXPLAIN THE DECREASE IN CAPITAL ADDITIONS IN 2019 AS COMPARED

5

TO 2018?

6 A. This decrease is due to reduced investments in Regional Expansion projects and

7

Reliability Requirement projects in 2019 as compared to 2018. With regard to

8

Regional Expansion projects, there are limited investments in this category in

9

2019 as the remaining CapX2020 projects were completed in 2017, and Badger

10

Coulee was completed in 2018. Also, due to the timing of in-service dates, there

11

was only one material Reliability Requirement project that went into service in

12

2019 ­ the Maple River to Red River project that had capital additions of $20.7

13

million. This is a significant decrease as compared to 2018.

14

15

Further, our investments in Communication Infrastructure projects was

16

reduced in 2019 due to the Frame Relay program coming to an end. The Frame

17

Relay program replaced antiquated analog communication equipment in

18

substations with new equipment more suitable to function with modern

19

telecommunications circuits, whether owned and operated by the Company or

20

by third-party telecommunications providers.

21

22 Q. WHAT ARE THE COMPANY'S FORECASTED CAPITAL ADDITIONS FOR 2020?

23 A. In 2020, we are forecasting approximately $195.1 million in capital additions,

24

which is an increase from our 2019 actuals of $161.8 million. Capital projects

25

that will be completed in 2020 include the Wilson Substation Conversion

26

Project, which is a Reliability Requirement Project, nine specific transmission

27

line rebuild projects as part of the Major Line Rebuild program, and fourteen

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Physical Security projects from the Physical Security and Resiliency category.

2

These Physical Security projects improve the security measures at our

3

substations to protect against potential physical threats. For instance, in 2020,

4

the Company installed the following security improvements at a substation in

5

central Minnesota: a new 10 foot tall expanded metal ballistic rated security

6

fencing, a 20 foot long M40 crash rated security arm at the main gate, and

7

upgraded the substation electrical service from 100 kVA to 250 kVA.

8

9 Q. WHY ARE TRANSMISSION'S CAPITAL ADDITIONS FOR 2020 HIGHER THAN 2019?

10 A. In 2020, we saw an increase in Asset Renewal projects including nine

11

transmission line rebuild projects. In 2020, we also increased investments in

12

Interconnection projects like the Jamaica Substation that was constructed to

13

increase load serving capacity in the southeastern metro area due to a large

14

industrial customer's expansion. Transmission's other investments in

15

Interconnection projects in 2020 will include retroactive self-funded network

16

upgrade payments to generation developers for Interconnection projects that

17

were completed prior to 2020. I discuss self-funded network upgrade projects

18

in greater detail later in my testimony.

19

20 Q. HAS THE CURRENT GLOBAL PANDEMIC AFFECTED TRANSMISSION'S CAPITAL

21

FORECAST FOR 2020?

22 A. The pandemic has had a minor impact on our 2020 capital forecast presented

23

here, which was established in the summer of 2020. In certain cases, we have

24

seen minor schedule delays, but all projects that were scheduled to be placed in

25

service in 2020 will be placed in service before year-end. Transmission has

26

updated our financial budgets for 2020 to reflect our best estimate of these

27

financial impacts, and we will continue to adjust as more information related to

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COVID-19 pandemic impacts is available. This is consistent with the approach

2

we would take related to any of the various ways our business may evolve during

3

a given period.

4

5 Q. ARE THESE IMPACTS FACTORED INTO TRANSMISSION'S FORWARD-LOOKING

6

CAPITAL BUDGETS AS WELL?

7 A. Yes. At this time, we do not anticipate a major change to the capital work we

8

have planned for 2021 to 2023. We continue to monitor the work and our

9

budgets in light of the pandemic, as we do under all circumstances.

10

11

D. Overview of Capital Investments for 2021 to 2023

12 Q. WHAT ARE TRANSMISSION'S CAPITAL BUDGETS FOR 2021 TO 2023 BY CAPITAL

13

BUDGET CATEGORY?

14 A. Table 3 and Table 4 (and Figures 3 and 4) below provide both planned capital

15

expenditures and additions for 2021 to 2023.

16

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Table 3

2

2021-2023 Forecasted Capital Expenditures

3

(Includes AFUDC)

4

NSPM and NSPW

(Dollars in Millions)

2021

2022

2023

5

(both Total Company)

Budget

Budget

Budget

Asset Renewal

$150.6

$215.5

$171.3

6

Reliability Requirement

$90.3

$76.2

$62.7

7

Interconnection

$46.0

$46.2

$47.5

8

Physical Security and Resiliency

Regional Expansion
9
Communication Infrastructure

10

Totals

$41.1 $41.3 $10.5 $379.8

$34.7 $52.1 $21.8 $446.5

$30.3 $95.4 $36.1 $443.3

11

12

Table 4

13

2021-2023 Forecasted Capital Plant Additions

14

(Dollars in Millions)

NSPM and NSPW

2021

2022

2023

15

(both Total Company)

Budget

Budget Budget

16

Asset Renewal

$132.2

$148.4

$182.3

17

Reliability Requirement

$62.9

$73.9

$27.9

18

Interconnection

19

Physical Security and Resiliency

20

Regional Expansion

Communication Infrastructure

21

Totals

22

$41.0 $33.9 $74.7 $9.3 $354.0

$33.3 $43.4 $18.1 $22.9 $340.0

$40.3 $30.4 $0.0 $35.8 $316.7

23

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Figure 3

2

3

4

5

6

7

8

9

10

11

12

13

14

15

Figure 4

16

17

2021-2023 Forecasted Capital Additions

Security\Resilianc

18

y

11%

19

Regional

20

Interconnection

11%

21

Expansion 9%
Reliability Requirement

16%

22

Comm

Infrastructure

23

7%

24

Asset Renewal 46%

25

26

27

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2 Q. HOW DO TRANSMISSION CAPITAL INVESTMENTS IN 2021 TO 2023 COMPARE TO

3

HISTORICAL TRENDS?

4 A. Our 2017 through 2023 capital expenditures and capital additions are set forth

5

in Table 5 and Table 6 below. As these tables illustrate, our capital additions

6

for the MYRP period for nearly every capital budget category, with the

7

exception of Regional Expansion, are substantially higher than our historical

8

investment trends. I discuss the reasons for these increasing investments below.

9

10

Table 5

11

2017-2023 Actual and Forecasted Capital Expenditures

12

(Excludes AFUDC) (Dollars in Millions)

13 NSPM and NSPW

2017 2018 2019 2020 2021 2022 2023

(both Total Company) Actual Actual Actual Forecast Budget Budget Budget

14

Asset Renewal

$68.8 $69.5 $104.4 $116.2 $150.6 $215.5 $171.3

15

Reliability Requirement $52.9 $75.1 $47.5 $34.0 $90.3 $76.2

62.7

16 Interconnection

$1.9 $10.8 $6.8 $20.2 $46.0 $46.2 $47.5

17 Physical Security and
Resiliency

18 Regional Expansion

Communication

19

Infrastructure

$17.6 $76.9 $3.3

$16.5 $60.1 $1.9

$19.0 $14.6 $0.9

$12.9 $40.7 $0.7

$41.1 $41.3 $10.5

$34.7 $52.1 $21.8

$30.3 $95.4 $36.2

20 Totals

$221.4 $233.8 $193.2 $224.7 $379.8 $446.5 $443.4

21

22

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Table 6

2

2017-2023 Actual and Forecasted Capital Plant Additions

3

(Includes AFUDC)

(Dollars in Millions)

4 5

NSPM and NSPW (both Total Company)

2017 Actual

2018 Actual

2019 Actual

2020 Forecast

2021 Budget

2022 Budget

2023 Budget

6

Asset Renewal

$57.4 $72.3 $77.6 $106.7 $132.2 $148.4 $182.3

7

Reliability Requirement

8

Interconnection

$55.9 $7.6

$96.2 $9.8

$39.1 $6.7

$43.2 $21.9

$62.9 $41.1

$73.9 $33.3

$27.9 $40.3

9

Physical Security and Resiliency

$16.9 $14.4 $15.8 $18.1 $33.8 $43.4 $30.4

10

Regional Expansion $74.0 $183.5 $22.3 $3.9

$74.7 $18.1

$0.0

11

Communication Infrastructure

$8.7 $4.5 $0.3 $1.3

$9.3

$22.9 $35.8

12

Totals

$220.5 $380.7 $161.8 $195.1 $354.0 $340.0 $316.7

13

14 Q. WHAT IS DRIVING THE INCREASED INVESTMENT IN ASSET RENEWAL FOR 2021

15

TO 2023 AS COMPARED TO HISTORICAL TRENDS?

16 A. During the term of this multi-year rate plan, Transmission will be making

17

increasing investments in Asset Renewal projects to address the condition of

18

our aging transmission line facilities. As I noted earlier, our increased

19

investment in Asset Renewal started in 2018, and that trend continues through

20

the MYRP period. These investments arose, in part, from the review of our

21

system, our inspection practices, and our Asset Renewal programs that was

22

spurred by the devastating wildfires in California in 2018. While wildfires are

23

not a high risk in the Midwest, they are representative of other risks that our

24

system must be equipped to handle to ensure reliable and safe service. These

25

risks include ice storms or windstorms, such as the derecho that hit the Midwest

26

in August 2020.

27

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As I noted earlier, this review resulted in Xcel Energy increasing the frequency

2

of inspections and, in 2019, utilizing drones to help with these more frequent

3

and more extensive inspections. Transmission uses a defect priority rating

4

system to identify which assets require immediate action (Priority 1 or Priority

5

2) as well as those that require near-term action (Priority 3 or Priority 4), and

6

those that require monitoring (Priority 5).

7

8

These increased and more comprehensive inspections in turn identified a

9

number of defects on our facilities, as we expected given the age of our system.

10

The average life expectancy for wood and steel transmission lines is

11

approximately 70 years. Table 7 below provides a summary of the approximate

12

age of our steel and wood transmission facilities for both NSPM and NSPW.

13

14

Table 7

15

NSPM and NSPW Transmission Facilities

16

Circuits approximately Circuits approximately Circuits approximately

70 years old or older 60 years old or older 50 years old or older

17

by mileage

by mileage

by mileage

18

518 miles

1,325 miles

2,854 miles

19

20

Over the last five years, we found that assets that we previously repaired or

21

refurbished are now requiring more extensive repairs such as a wholesale rebuild

22

or a more extensive refurbishment. Given that these larger Asset Renewal

23

projects often require more lead time to plan and implement, these projects

24

were set in motion to be placed in service as part of our budgets for 2021

25

through 2023. As a result, our capital additions in our Major Line Rebuild and

26

Major Line Refurbishment programs are forecasted to be higher than in 2017

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to 2019. This increase in investment over prior years is due to both the number

2

of facilities requiring work as well as the extent of the work that will be done.

3

4 Q. CAN YOU PROVIDE AN EXAMPLE OF A MAJOR LINE REBUILD PROJECT THAT IS

5

PLANNED TO BE COMPLETED DURING THE MYRP PERIOD?

6 A. Yes, one of the specific Major Line Rebuild projects that will be completed

7

during this MYRP period is the rebuild of the approximately 16-mile Belgrade

8

to Paynesville 69 kV line. This line was originally constructed in 1940 and

9

contains approximately 328 structures. Of these 328 structures, 192 contain

10

defects, with some structures containing multiple defects, for a total of 314

11

defects on this line. In the past five years, there have been more than 20 line

12

outages on this line. Due to the fact that there are known defects on more than

13

half of the structures of the line, rather than simply replace one or two

14

structures, we must rebuild the entire line.

15

16 Q. WHAT IS DRIVING THE INCREASED INVESTMENT IN RELIABILITY REQUIREMENT

17

PROJECTS FROM 2021 TO 2023 AS COMPARED TO HISTORICAL TRENDS?

18 A. We will also be making steady increases in our Reliability Requirement category

19

through specific projects such as the Bayfield Loop Project in Wisconsin that

20

will go in service in 2022, our TACT program that has multiple projects that go

21

in service throughout the period of the multi-year rate plan necessary to comply

22

with NERC Standard TPL-001-4, and the HibTac 500 kV project that is

23

planned to go in-service in 2021; these projects are described in more detail later

24

in my testimony. In addition, capital expenditure for Reliability Requirement

25

projects are also increasing starting in 2021 due to a number of planned projects

26

that will increase reliability to the system but do not go in service until after

27

2023.

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2 Q. WHAT IS DRIVING THE INCREASE IN INTERCONNECTION PROJECTS FROM 2021

3

TO 2023 AS COMPARED TO 2017 TO 2019?

4 A. As I noted above, as of September 1, 2020, there are 107.6 gigawatts of

5

generation in the MISO queue. Of this total, 24.6 gigawatts are located in the

6

MISO West region that includes Minnesota. To accommodate these new

7

generators, the vast majority of which are wind and solar, the Company will

8

need to make increasing investments in Interconnection projects over the term

9

of the multi-year rate plan. I note that these Interconnection projects generally

10

are paid for by the interconnection customer, but in certain circumstances, Xcel

11

Energy may, pursuant to the MISO Tariff, decide to self-fund these network

12

upgrades and then receive payments over a 20-year term from the

13

interconnection customer. As such, these Interconnection projects essentially

14

pay for themselves although the timing of these reimbursements may differ

15

depending on the project.

16

17 Q. IS TRANSMISSION INCREASING ITS INVESTMENTS IN OTHER CAPITAL BUDGET

18

CATEGORIES DURING THE TERM OF THE MULTI-YEAR RATE PLAN?

19 A. Yes. We will also be doubling our efforts related to Physical Security projects

20

in the Physical Security and Resiliency category to improve and enhance the

21

physical security at our critical substation assets in compliance with NERC's

22

CIP-014 standard. As I noted earlier, the CIP-014 standard is relatively new

23

(adopted in 2014 and modified in 2015), and we spent several years assessing

24

our system. As a result of those assessments, we are now planning to implement

25

several security-upgrade projects at key substations.

26

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We will also be making increasing investments in our Communication

2

Infrastructure category between 2021 to 2023 as we continue our efforts to

3

privatize Xcel Energy's communication network infrastructure across the

4

NSPM and NSPW service territories to improve SCADA, teleprotection, and

5

remote engineering access, in addition to corporate services. This privatization

6

will also decrease response time for restoring network outages and reduce our

7

exposure to cybersecurity threats through the publicly accessible network

8

provided by third-party telecommunication companies.

9

10 Q. ARE ANY CAPITAL BUDGET CATEGORIES WITH DECLINING CAPITAL ADDITIONS

11

DURING THE MYRP PERIOD?

12 A. Yes. The Regional Expansion capital budget is currently forecasted to decline

13

over the MYRP term. The capital additions in 2021 are higher than prior years

14

due to the bulk of the Huntley­Wilmarth Project being placed in service, but

15

the capital additions then decline for 2022 and 2023. I note that towards the

16

end of the MYRP, we will be making capital expenditures to support new

17

Regional Expansion projects that we expect will arise from MISO's MTEP21

18

that will be finalized in December 2021. We anticipate that these projects will

19

not be placed in service during the term of this MYRP.

20

21 Q. WHAT KINDS OF CHANGES COULD OCCUR THAT MAY LEAD TO A RE-

22

PRIORITIZATION OF YOUR INVESTMENTS AND CHANGE THE PERCENTAGES

23

THAT YOU INVEST IN EACH CAPITAL BUDGET GROUPING DURING THE TERM OF

24

THE MULTI-YEAR RATE PLAN?

25 A. There are several reasons we may need to reprioritize capital investments in a

26

particular year or over several years. For example, a new NERC requirement

27

could require Transmission to make investments to comply with the

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requirement in a particular year. As a result, Transmission may need to increase

2

its investments in the Reliability Requirement category while at the same time

3

reducing investments in another budget category.

4

5 Q. WHY IS THE ABILITY TO CHANGE THESE INVESTMENT PERCENTAGES

6

IMPORTANT TO THE COMPANY AND YOUR CUSTOMERS?

7 A. When we make adjustments to our capital investment plans, we do so to better

8

serve our customers' and our Company's most urgent needs in the most cost-

9

effective way. When the need arises to accelerate a project or develop a new

10

project, we assess the situation to make sure we are doing so for the right

11

reasons and in a prudent way. Similarly, we assess potential project delays or

12

cancellations to make sure we are still meeting business and customer needs in

13

a reasonable way.

14

15 Q. EVEN IF YOUR INVESTMENT PERCENTAGES CHANGE FROM THE CURRENT

16

FORECAST, WILL TRANSMISSION STILL WORK TO MANAGE ITS OVERALL CAPITAL

17

INVESTMENTS WITHIN ITS OVERALL BUDGET?

18 A. Yes. While our investments in particular capital budget groupings may change

19

to address unanticipated issues, ultimately, we will invest as necessary to meet

20

our overall goals of safe and reliable transmission of energy for our customers.

21

22

E. Major Planned Investments for 2021 to 2023

23 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

24 A. The multiyear rate plan statute, Minn. Stat. § 216B.16, subd. 19, requires that a

25

utility provide "a general description of the utility's major planned investments

26

over the plan period." This section of my testimony discusses the major

27

planned investments Transmission anticipates in 2021 through 2023. The State

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of Minnesota jurisdictional amounts for each capital addition are included as

2

Exhibit___(IRB-1), Schedule 2.

3

4 Q. HOW DID TRANSMISSION IDENTIFY ITS MAJOR PLANNED INVESTMENTS OVER

5

THE PLAN PERIOD?

6 A. To identify these investments, we looked for those unique projects that require

7

a greater than normal quantity of Transmission resources to complete and that

8

contribute a significant amount to our budgeted capital additions.

9

10 Q. WHAT MAJOR PLANNED INVESTMENTS DOES TRANSMISSION ANTICIPATE

11

COMPLETING OVER THE MULTI-YEAR RATE PLAN PERIOD?

12 A. As depicted in Table 8, we anticipate undertaking three major planned

13

investments between 2021 and 2023. These investments include two Asset

14

Health programs ­ NSPW Major Line Rebuild and NSPM Major Line Rebuild

15

­ and one Regional Expansion project, the Huntley­Wilmarth Project.

16

17

Table 8

18

Transmission Major Planned Investment Projects

19

Capital Additions

20

(Includes AFUDC) (Dollars in Millions)

21

2021

2022

2023

22

NSPM Major Line Rebuild

$11.2

NSPW Major Line Rebuild

$13.5

23

Huntley­Wilmarth 345 kV Project

$73.2

$21.3 $15.1 $4.3

$63.9 $11.6 $0.0

24

25

These major planned investments, as well as the additional key capital projects

26

we anticipate completing in 2021, 2022, and 2023 are discussed in more detail

27

below.

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2 Q. DOES THE COMPANY PLAN TO RECOVER ANY OF THESE PROJECTS THROUGH

3

THE TCR RIDER?

4 A. Yes. The Huntley­Wilmarth 345 kV Project will continue to be recovered

5

through the TCR Rider. I am including this project here as it also qualifies as a

6

major planned investment during the plan period. Mr. Halama will provide

7

additional information on TCR Rider recovery of this project.

8

9

F. Key Capital Additions for 2021 to 2023

10 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

11 A. In this section, I describe the main projects under each of the capital budget

12

groupings I identified earlier. Unless otherwise stated, all dollar figures are at

13

the NSPM and NSPW Total Company level. These capital additions are

14

presented in State of Minnesota Electric Jurisdiction form in Exhibit___(IRB-

15

1) Schedule 2.

16

17

1. Asset Renewal Projects

18 Q. WHAT IS THE PRIMARY CHALLENGE FACING TRANSMISSION RELATED TO ASSET

19

RENEWAL?

20 A. The primary challenge that Transmission faces related to Asset Renewal

21

projects is the number of facilities that will require investment in the coming

22

years to maintain the reliability and safety of our transmission system. Our

23

organization is charged with maintaining a large and aging transmission

24

infrastructure. While transmission facilities generally have long lifespans, these

25

facilities do not last forever. Generally speaking, transmission structures have

26

an average useful lifespan of approximately 70 years. On the NSP Transmission

27

System, there are more than 500 miles of transmission line that are over 70 years

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old and another 1,300 miles of transmission line that are between 60-70 years

2

old. Likewise, substation transformers have an expected life of between 50 to

3

65 years and 217 of NSPM's 675 substation transformers are 50 years old or

4

older.

5

6

We do not simply replace a transmission asset due to its age, however. Instead,

7

the Company examines both the condition and performance of our aging

8

facilities to determine which facilities are in greatest need of replacement. We

9

also prioritize replacement of aging facilities based on which facilities are most

10

likely to fail and then which equipment will have the biggest impact on the

11

transmission system when it does fail.

12

13 Q. WHY ARE INVESTMENTS IN ASSET RENEWAL PROJECTS INCREASING OVER THE

14

TERM OF THIS MULTI-YEAR RATE PLAN?

15 A. Over the term of this multi-year rate plan, we will be making greater investment

16

in Asset Renewal programs and projects to address the declining condition of

17

our aging transmission facilities. This increase in investments in this area is the

18

result of interrelated factors. As I discussed earlier, one of the key events that

19

eventually led to greater investment in this category was the California wildfires

20

in 2018. While wildfires are not a big risk in the Midwest, they highlighted for

21

our Company and the industry the need to ensure that transmission assets are

22

safe, reliable, and able to withstand extreme events.

23

24

In response, we examined our Asset Renewal programs, our inspection

25

frequency, and our investment strategy. One outcome of this examination was

26

more frequent and more comprehensive inspections of our facilities that

27

resulted in identification of more deficiencies. This in turn lead to a need to

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increase our budgets to make these necessary repairs, refurbishments, or

2

rebuilds. Moreover, while we have been making steady investments in the

3

maintenance and repair of our transmission assets, many of our assets are at the

4

point where they require wholesale replacement or rebuild rather than less costly

5

repairs or refurbishments.

6

7 Q. PLEASE EXPLAIN HOW INSPECTIONS ARE USED TO IDENTIFY ASSET RENEWAL

8

PROJECTS.

9 A. The Company performs various types of assessments on the transmission line

10

facilities at different points in time. Beginning in 2018, we began increasing our

11

foot patrols from every six years to every four years and increased ground line

12

inspections which are completed on all structures on a 12-year cycle. In 2019,

13

we also started using Unmanned Aerial Vehicles (drones) to inspect all of our

14

all FAC-003 (200 kV and above) transmission facilities on an annual basis.

15

16 Q. HOW DOES TRANSMISSION EVALUATE THE CONDITION OF ITS FACILITIES?

17 A. Transmission utilizes a defect priority rating system to rank the condition of our

18

transmission facilities. This rating system utilizes a ranking from Priority 1 to

19

Priority 5, with Priority 1 ranking indicating that a component requires

20

immediate action. I summarize this ranking system in the table below.

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2

Table 9

3

Defect Priority Rankings

4

Priority

Maintenance Priority and Asset Management Implication

Ranking

Maintenance Action

5 6

Priority 1

Emergency; Immediate Action Failed Component with or

Required

without service interruption

Failure imminent-component

7 8

Priority 2

Emergency; Urgent Action Required

damaged or no longer suitable for intended use. Service not yet interrupted but failure or service

interruption is imminent.

9

Asset renewal required-significant

10

Priority 3

High Priority

wear, corrosion or damage to warrant action plan.

11

Asset renewal recommended-

12

Priority 4

Medium Priority

moderate to minimal wear, corrosion, or damage to warrant

action plans.

13

Minimal maintenance-minor wear,

14

Priority 5

Low Priority

corrosion, etc. but still functional condition for the intended

15

purpose.

16

17

The components that are designated as Priority 1 or Priority 2 require urgent

18

action and therefore are typically funded out of our Storm and Emergencies

19

programs. Those assets labeled Priority 3 to Priority 5 require action but not

20

immediately, so the replacement and repair of these components is typically

21

funded through our other Asset Renewal programs such as our Major Line

22

Rebuild or End-of-Life programs.

23

24 Q. WHAT IS THE NEXT STEP AFTER AN ASSET IS CATEGORIZED BY PRIORITY?

25 A. In these assessments, the Company identifies those transmission lines that

26

require rebuilding, and specific projects are subsequently developed and

27

prioritized using the Company's Line Prioritization Matrix, which is a tool

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1

developed by the transmission line performance group that uses internal and

2

external information to quantitatively rank each transmission circuit. Each line

3

is scored and ranked against each other incorporating the following drivers:

4

· Importance

5

o What happens if the circuit has an outage

6

o Operational concerns

7

o Design concerns

8

· Reliability

9

o Frequency of outages

10

o Duration of outages

11

o Benchmarking rating

12

· Condition Assessment

13

o Incorporates two scoring groups

14

 Field Engineer's Field Assessment

15

 Transmission Asset Management System (TAMS) Identified

16

Defects

17

· Defect count and severity

18

· Repair cost estimates

19

20

Through the assessment process, the Company may identify defective line

21

circuits requiring a full rebuild as early as five years before the rebuild is needed.

22

However, we typically budget lines for this program only two to three years in

23

advance because upgrades in the system area, storms and emergencies, and

24

changing system needs may alter the overall asset health score for identified

25

lines beyond the two- to three-year window. The Company identifies, budgets

26

for, and develops specific projects during our annual budget process and on the

27

basis of the total asset health score of the line as determined by the Line

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Prioritization Matrix. These individual projects are then prioritized against the

2

rest of the planned Transmission capital portfolio. Lastly, the Company budgets

3

for projects in the three- to five-year range based on the remaining projects that

4

are in the top quartile of the Line Prioritization Matrix following the historical

5

trends of this program.

6

7 Q. WHAT ARE THE KEY ASSET RENEWAL PROGRAMS AND PROJECTS THAT

8

TRANSMISSION ANTICIPATES PLACING IN-SERVICE DURING THE MULTI-YEAR

9

RATE PLAN PERIOD?

10 A. There are eight key Asset Renewal programs that have assets that will be placed

11

in service between 2021 and 2023:

12

1. NSPM and NSPW Major Line Rebuild program;

13

2. NSPM and NSPW Major Line Refurbishment program;

14

3. NSPM and NSPW Storms & Emergencies (S&E) Line program;

15

4. NSPM and NSPW Relay End-of-Life (ELR) program;

16

5. NSPM and NSPW Substation Breaker ELR program;

17

6. NSPM and NSPW Transformers ELR program;

18

7. NSPM Nuclear Substation ELR program; and

19

8. NSPM and NSPW Line ELR program.

20

21

There are also two key Asset Renewal projects that will be placed in service

22

during the term of the multi-year rate plan:

23

· W3203 Briggs-La Crosse Line Upgrade Project; and

24

· NSPM and NSPW Group 1 Switch Replacements Project.

25

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a. Asset Health Programs

2 Q. PLEASE DESCRIBE THE NSPM/NSPW MAJOR LINE REBUILD PROGRAM.

3 A. The Major Line Rebuild program for NSPM and NSPW represents projects

4

that rebuild large segments of transmission lines on the NSP Transmission

5

System that have a concentrated number of defects that contribute to poor line

6

performance. These projects are typically required either because the existing

7

line circuits are at risk for increased outage frequency or because the number of

8

structural defects on the circuit makes it unreasonable to refurbish only the

9

defective portions. A rebuild project scope requires complete

10

wreck-out/removal of the physical line assets, which are then replaced with new

11

line assets (e.g., structures, conductor, switches) either within the existing right-

12

of-way (ROW) or with minor, targeted right-of-way expansion to accommodate

13

outage constraints and safe construction practices.

14

15 Q. WHAT PLANT ADDITIONS ARE BUDGETED FOR 2021 TO 2023 AS PART OF THE

16

MAJOR LINE REBUILD PROGRAM?

17 A. The Company has budgeted $96.3 million for the NSPM Major Line Rebuild

18

program ($11.2 million in 2021; $21.2 million in 2022; and $63.9 million in

19

2023). The Company has budgeted $40.2 million for the NSPW Major Line

20

Rebuild program ($13.5 million in 2021; $15.1 million in 2022; and $11.6 million

21

in 2023).

22

23 Q. WHAT IS DRIVING THE INCREASED INVESTMENT IN MAJOR LINE REBUILDS

24

OVER THE TERM OF THE MULTI-YEAR RATE PLAN?

25 A. These increased investments are driven by both the condition and age of our

26

transmission assets. As I discussed earlier, until recently we have been able to

27

maintain the majority of our assets through either O&M repairs, replacement

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1

of specific components when they are at the end of their service life, or

2

refurbishment projects that extend the life of our assets by 10 to 20 years

3

depending on asset condition and the scope of the refurbishment. Recently,

4

our inspections are revealing that lines that were previously refurbished are in

5

need of replacement due to the cumulative condition of the asset (poles, cross-

6

arms, insulators, and conductor), as well as lines where their general

7

composition, like conductor type, framing, and pole sizes would not safely allow

8

for refurbishment. As a result, we need to increase our investments in our Major

9

Line Rebuild programs to rebuild these lines.

10

11 Q. CAN YOU PROVIDE INFORMATION ABOUT A SPECIFIC REBUILD PROJECT THAT

12

HAS BEEN IDENTIFIED FOR 2021 TO 2023?

13 A. Yes. The Avon­Albany project involves rebuilding an approximately seven-

14

mile segment of this 69 kV transmission line (also known as Line 0795), which

15

is over 60 years old. This transmission line originates at Great River Energy's

16

(GRE) West St. Cloud Substation in St. Joseph, Minnesota and runs westerly

17

approximately 25 miles to the Millwood Tap Switch in Freeport, Minnesota.

18

This line is critical to the reliability of this area because it serves the Company's

19

as well as other utilities' distribution loads in the area.

20

21

Through the Company's Line Prioritization Matrix, the Company identified

22

Line 0795 as being a poor performer due to its age and condition. The 1953

23

vintage line consists of direct embedded cedar wood poles. Many of the poles

24

are past their useful life and over the years, many have been replaced through

25

the Storm and Emergencies program due to their poor condition. Due to the

26

number of structures and other associated equipment (cross-arms and

27

conductors) requiring replacement, it is now more cost-effective to do an entire

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1

rebuild of this line rather than replace individual components. This project will

2

be placed in service in 2022 and has a total plant addition of $5.4 million.

3

4 Q. PLEASE DESCRIBE THE NSPM/NSPW MAJOR LINE REFURBISHMENT

5

PROGRAM.

6 A. The Major Line Refurbishment program for NSPM and NSPW encompasses a

7

group of targeted projects to replace specific transmission line components,

8

such as defective cross-arms, poles, and other line appurtenance components.

9

This program differs from the Major Line Rebuild program in that the Major

10

Line Rebuild program involves the complete removal and replacement of

11

existing assets; whereas the Refurbishment program addresses specific defects

12

on an entire line segment (breaker to breaker), replacing all like property units

13

on the line segment.

14

15

The Company identifies these defective components as at or near failure by

16

means of routine foot patrols, aerial patrols, or Field Engineer's Field

17

Assessment (which occurs only as required by damage reports-an estimated two

18

percent of all lines annually). By refurbishing specific components of a line

19

segment, and rather than rebuilding an entire line, the Company's intent is to

20

increase circuit reliability and performance and extend the residual circuit life by

21

between 10 to 20 years, at a lower cost than a full line replacement.

22

23

Similar to our Major Line Rebuild program, the Company utilizes its assessment

24

of the transmission system to help identify specific projects, which are then

25

developed and prioritized in accordance with the Company's line prioritization

26

matrix. As with the Major Line Rebuild program, each transmission line is

27

scored and ranked against each other based on the drivers noted above.

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1

2

As with the Major Line Rebuild program assessment process, the Company may

3

identify defective line circuits requiring refurbishment as early as five years

4

before repairs are necessary. However, we typically budget lines for this

5

program only two to three years in advance because upgrades in the system area,

6

storms and emergencies, and changing system needs may alter the overall asset

7

health score for identified lines beyond the two- to three-year window. The

8

Company identifies, budgets for, and develops specific projects during our

9

annual budget process and on the basis of the total asset health score of the line

10

as determined by the Line Prioritization Matrix. These individual projects are

11

then prioritized against the rest of the planned Transmission capital portfolio.

12

Lastly, the Company budgets for projects in the three- to five-year range based

13

on the remaining projects that are in the top quartile of the Line Prioritization

14

Matrix following the historical trends of this program.

15

16 Q. WHAT PLANT ADDITIONS WILL OCCUR FROM 2021 TO 2023 AS PART OF THE

17

MAJOR LINE REFURBISHMENT PROGRAM?

18 A. The Company has budgeted $34.5 million for the NSPM Major Line

19

Refurbishment program ($11.8 million in 2021; $12.9 million in 2022; and $9.8

20

million in 2023). The Company has budgeted $27.1 million for the NSPW

21

Major Line Refurbishment program ($9.5 million in 2021; $12.6 million in 2022;

22

and $5.0 million in 2023).

23

24 Q. CAN YOU PROVIDE INFORMATION ABOUT A SPECIFIC REFURBISHMENT PROJECT

25

THAT WILL BE COMPLETED BETWEEN 2021 AND 2023?

26 A. Yes, included in this program is a refurbishment of the Company's 69 kV

27

transmission line between the Company's Westgate Substation, in Eden Prairie,

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1

Minnesota and the Company's Excelsior Substation in the western Minneapolis

2

suburbs. This refurbishment project encompasses the entire length of the line,

3

which is approximately 11 miles. The scope of the project includes the removal

4

of all existing wood cross-arms. The wood cross-arms have decayed over time

5

and are beyond their useful life. These assets will be replaced with new

6

horizontal post insulators. In addition, the project includes the complete

7

removal and replacement of 32 poles that have been identified as defective

8

though our comprehensive inspection program. In total, approximately 185

9

structures will be modified, and 32 wood poles will be replaced.

10

11 Q. PLEASE DESCRIBE THE NSPM/NSPW STORMS AND EMERGENCIES (S&E) LINE

12

PROGRAM.

13 A. The S&E Line program replaces and repairs equipment that has failed due to a

14

storm event or that is identified through condition assessment as having a high

15

probability of failure and cannot wait for the next normal budget cycle for

16

replacement (i.e., either Priority 1 or Priority 2). This work is typically

17

performed in response to weather events, unforeseen events, and other

18

unscheduled maintenance work that, if not completed, puts the equipment at

19

imminent risk of failure. The work typically includes the replacement of arms,

20

poles, conductor, insulators, and other line appurtenances.

21

22 Q. WHAT RECENT TRENDS HAVE YOU SEEN IN THE S&E LINE PROGRAM?

23 A. We have recently seen more poles classified as Priority 2 (i.e., requiring

24

immediate replacement through our S&E program) than in prior years.

25

Specifically, in 2017 and 2018, the percentages of poles categorized as Priority

26

2 were 1.9 percent and 2.2 percent respectively of the total number of poles

27

tested. In 2019, the number of poles classified as Priority 2 rose to 5 percent of

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1

the total poles tested. While it is too early to tell if this is a trend or if 2019 is

2

an anomaly, it does underscore the importance of continued inspections and

3

continued funding for this program to address these urgently needed

4

replacements.

5

6 Q. HOW DOES TRANSMISSION DETERMINE THE BUDGET FOR THE S&E LINE

7

PROGRAM?

8 A. The Company sets its budget for this program based on a historical annual

9

average because the nature of the work to be performed is not known until the

10

time of an incident. The forecast is then adjusted throughout the year based on

11

actual incidents, while factoring in the probability of storm or emergency events

12

for the remainder of the calendar year.

13

14

Based on historical average budgeting for this program, Transmission's plant

15

additions for any given year range between $10.0 million and $14.0 million per

16

year. One of the reasons for this budget range is because the Company

17

occasionally experiences late season storms or emergencies for which the

18

physical work and capital expenditure must carry over from one budget year to

19

the next, causing the plant addition to be carried over from one year to the next.

20

21 Q. WHAT PLANT ADDITIONS ARE BUDGETED FOR 2021 TO 2023 FOR THE

22

NSPM/NSPW S&E LINE PROGRAM?

23 A. The Company has budgeted $25.5 million for the NSPM S&E Line program

24

($8.7 million in 2021; $8.4 million in 2022; and $8.4 million in 2023). The

25

Company has budgeted $12.3 million for the NSPW S&E Line program ($4.0

26

million in 2021; $5.3 million in 2022; and $3.0 million in 2023).

27

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1 Q. PLEASE DESCRIBE THE NSPM/NSPW ELR ­ RELAY PROGRAM.

2 A. Protective relays monitor power system quantities, typically voltages and

3

currents, and open and close circuits to remove short circuits from the power

4

system.

5

6

The ELR ­ Relay program encompasses projects that target relays for

7

replacement that exhibit poor performance and lack available replacement parts.

8

As transmission infrastructure continues to age or nears or is at its end of life,

9

these components must be changed before failures occur. As the structural

10

integrity of aging assets diminishes, outages will increase in frequency and

11

duration.

12

13

While we may identify a number of relays that require replacement as early as

14

five years in advance of the asset's end of life, we typically budget for this

15

program only two to three years in advance. During our annual budget process,

16

the poorest performing relays are added to the budget. These projects are then

17

prioritized against the rest of the planned Transmission portfolio. Budgets for

18

projects in the three- to five-year range are then planned for transmission's

19

remaining relay infrastructure based on age and asset health. The pace of this

20

replacement program may vary because many aging relays may still be functional

21

but do not offer optimal operational performance. As such, the replacement of

22

components identified in this project can be accelerated or decelerated

23

dependent on other Transmission portfolio needs.

24

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1 Q. WHAT PLANT ADDITIONS WILL OCCUR IN 2021 TO 2023 FOR THE ELR ­ RELAY

2

PROGRAM?

3 A. The Company has budgeted a total of $28.9 million for the ELR ­ Relay

4

program: $11.0 million for the NSPM ELR ­ Relay program ($4.8 million in

5

2021; $1.7 million in 2022; and $4.4 million in 2023) and $17.9 million for

6

NSPW ELR ­ Relay program ($9.6 million in 2021; $4.3 million in 2022; and

7

$4.1 million in 2023).

8

9 Q. CAN YOU PROVIDE AN EXAMPLE OF AN ELR-RELAY PROJECT THAT WILL BE

10

COMPLETED DURING THE TERM OF THIS MULTI-YEAR RATE PLAN?

11 A. Yes, an example of one of these projects is the replacement and upgrading of

12

the relaying at the Riverside Substation. This project is part of a larger effort to

13

phase out older technology relaying systems on the transmission system. The

14

relays at the Riverside Substation include older electro-mechanical relays as well

15

as first generation microprocessor relays. These types of relays have been

16

targeted for replacement primarily due to poor performance and lack of

17

replacement parts. We have budgeted $1.0 million in capital additions to

18

complete this project in 2021.

19

20 Q. PLEASE DESCRIBE THE NSPM/NSPW SUBSTATION BREAKER ELR PROGRAM.

21 A. The NSPM/NSPW Substation Breaker ELR program targets substation circuit

22

breakers for replacement that have been identified due to poor performance or

23

lack of available replacement parts for repair. As transmission infrastructure

24

ages or nears its expected end of life, components must be changed before

25

failures occur. As the structural integrity of these aging assets diminishes,

26

outages will increase in frequency and duration.

27

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As with the ELR ­ Relay program, while we may identify a number of circuit

2

breakers through the Substation Breaker ELR program that require replacement

3

as early as five years in advance, typically we budget lines for this program only

4

two to three years in advance. During our annual budget process, the poorest

5

performing circuit breaker projects are included in the budget. These projects

6

are then prioritized against the rest of the planned Transmission portfolio.

7

Budgets for projects in the three- to five-year- range are then planned for based

8

on the age and asset health of these circuit breakers. The pace of this

9

replacement program may vary because many aging breakers may still be

10

functional but do not offer optimal operational performance. As such, the

11

replacement of components identified in this program can be accelerated or

12

decelerated dependent on other Transmission portfolio needs.

13

14 Q. WHAT PLANT ADDITIONS WILL OCCUR IN 2021 TO 2023 FOR THE NSPM/NSPW

15

SUBSTATION BREAKER ELR PROGRAM?

16 A. The Company has budgeted $10.6 million for the NSPM Substation Breaker

17

ELR program ($5.0 million in 2021; $2.1 million in 2022; and $3.4 million in

18

2023). The Company has budgeted $13.5 million for the NSPW Substation

19

Breaker ELR program ($5.1 million in 2021; $3.8 million in 2022; and $4.6

20

million in 2023).

21

22 Q. CAN YOU PROVIDE AN EXAMPLE OF A SUBSTATION BREAKER ELR PROJECT?

23 A. Yes, one of the projects that we plan to complete during the term of this multi-

24

year rate plan is the replacement of all three of the 115 kV circuit breakers at

25

the Fifth Street Substation that serves downtown Minneapolis. The age of these

26

circuit breakers range from 53 to 56 years old. The average service life of a

27

circuit breaker is approximately 50 years. Given the importance of these circuit

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1

breakers in serving the large downtown load, a failure of any one of these

2

breakers could result in a large number of customers being without service. As

3

a result, it is important to replace these three circuit breakers at this time given

4

that they are already past their expected service life. We have budgeted $1.3

5

million in capital additions to complete this project in 2021.

6

7 Q. PLEASE DESCRIBE THE NSPM/NSPW TRANSFORMERS ELR PROGRAM.

8 A. The NSPM/NSPW Transformers ELR program targets transformers for

9

replacement that have been identified due to poor performance or lack of

10

available replacement parts for repair. As transmission infrastructure ages or

11

nears or is at its expected end of life, components must be changed before

12

failures occur. As the structural integrity of these aging transformer assets

13

diminishes, outages will increase in frequency and duration.

14

15

As with the other ELR programs (Relays and Circuit Breakers), we may identify

16

a number of transformers through the Transformer ELR program that require

17

replacement as early as five years in advance but, typically we budget lines for

18

this program only two to three years in advance. During our annual budget

19

process, the poorest performing transformers are included in the budget for

20

replacement. These projects are then prioritized against the rest of the planned

21

Transmission portfolio. Budgets for projects in the three- to five-year range are

22

then planned for based on the age and asset health of these assets. The pace of

23

this replacement program may vary because many aging transformers may still

24

be functional but do not offer optimal operational performance. As such, the

25

replacement of components identified in this program can be accelerated or

26

decelerated dependent on other Transmission portfolio needs.

27

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1 Q. WHAT PLANT ADDITIONS WILL OCCUR IN 2021 TO 2023 FOR THE NSPM/NSPW

2

TRANSFORMERS ELR PROGRAM?

3 A. The Company has budgeted $9.1 million in capital additions for the NSPM

4

Transformers ELR program ($0.3 million in 2021; $5.8 million in 2022; and $3.0

5

million in 2023). The Company has budgeted $13.9 million in capital additions

6

for the NSPW Transformers ELR program ($0.1 million in 2021; $9.4 million

7

in 2022; and $4.4 million in 2023).

8

9 Q. PLEASE PROVIDE AN EXAMPLE OF A TRANSFORMER ELR PROJECTS THAT WILL

10

BE COMPLETED DURING THE TERM OF THIS MULTI-YEAR RATE PLAN.

11 A. One of these projects involves the replacement and upgrade of the 300 MVA

12

Eau Claire Substation transformer and both sets of the tertiary reactors for this

13

transformer. Further, as part of this project, substation grounding and the AC

14

auxiliary system will be brought into alignment with current standards. This

15

project was initiated as part of an ELR review of system transformers. During

16

initial scoping, it was determined that the tertiary reactors for this transformer

17

needed to be replaced since they are in need of significant maintenance and are

18

reaching the end of their life. After identifying the replacement of these

19

reactors, we also examined the transformer and determined that it needed

20

replacement due to detection of degradation of transformer gasses. We further

21

determined that this transformer needed to be upgraded to 448 MVA to allow

22

for future load growth in this area. We have budgeted $6.4 million in capital

23

additions to complete this project in 2022.

24

25 Q. PLEASE DESCRIBE THE NSPM NUCLEAR SUBSTATION ELR PROGRAM.

26 A. This program has been separated from the Company's other ELR programs so

27

that it can more easily be completed in coordination with our Nuclear business

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1

unit's compliance needs. The Nuclear Substation ELR program addresses the

2

programmatic replacement of substation equipment at the substations that

3

serve the Monticello and Prairie Island nuclear generating plants. The timing

4

of these replacements is designed to align Transmission's substation

5

replacement activities with power plant refueling and maintenance activities at

6

these two nuclear facilities. The equipment identified for replacement consists

7

largely of circuit breakers, switches, relays, and power transformers. While the

8

program can be flexible from year to year, replacement of these facilities is

9

necessary to maintain the ability of the transmission system to transport the

10

energy generated by these plants to customers.

11

12 Q. WHAT PLANT ADDITIONS WILL OCCUR FROM 2021 TO 2023 FOR THE NSPM ELR

13

NUCLEAR PROGRAM?

14 A. The Company has budgeted $20.2 million in capital additions for the NSPM

15

ELR Nuclear program ($3.6 million in 2021; $7.3 million in 2022; and $9.3

16

million in 2023).

17

18 Q. PLEASE DESCRIBE THE NSPM/NSPW LINE ELR PROGRAM.

19 A. The Line ELR program for NSPM and NSPW encompasses projects that target

20

the replacement of defective cross arms, poles, and other line appurtenance

21

components on the NSP Transmission System that have been reported as

22

defective by routine foot and aerial patrols and are nearing their end of life.

23

Overall, the Line ELR program extends the life of NSP transmission line assets

24

when full line replacement is not necessary. Line ELR is utilized primarily when

25

the individual defect has occurred, but the overall line segment is otherwise in

26

sound condition with many years of additional life remaining.

27

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1 Q. HOW DOES THE LINE ELR PROGRAM DIFFER FROM THE MAJOR LINE

2

REFURBISHMENT PROGRAM DISCUSSED ABOVE?

3 A. The Major Line Refurbishment program replaces specifically identified

4

defective transmission line property units (cross-arms or poles or other line

5

appurtenances) when the majority of similar property units of the same vintage

6

and design have been identified as defective on a line circuit. Any property units

7

found to be in good operational condition are left in place.

8

9

In contrast, the Line ELR program replaces only individual transmission line

10

property units that are defective, but not similar property units of the same

11

vintage and design that are generally in good operating condition.

12

13

When defects are identified through patrols, typically one to three years in

14

advance, they are classified as either Major Line Refurbishment or Line ELR,

15

and they are budgeted and executed. These two programs are managed

16

separately because the severity of the identified defects on a circuit, along with

17

the frequency of the defects, determines which program's budget will be

18

utilized.

19

20 Q. WHAT PLANT ADDITIONS WILL OCCUR FROM 2021 TO 2023 FOR THE LINE ELR

21

PROGRAM?

22 A. The Company has budgeted $11.9 million for the NSPM Line ELR program

23

($3.6 million in 2021; $3.7 million in 2022; and $4.5 million in 2023). The

24

Company has budgeted $7.7 million for the NSPW Line ELR program ($2.9

25

million in 2021; $2.3 million in 2022; and $2.5 million in 2023).

26

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1 Q. PLEASE DESCRIBE THE GROUP 1 SWITCH REPLACEMENTS PROJECT.

2 A. The Group 1 Switch Replacements project is similar to many of our End-of-

3

Life projects. The difference is that this project specifically targets transmission

4

line switches that no longer function as originally designed or have reached the

5

end of their useful life. A Group 1 Switch Replacement project is utilized

6

primarily when an individual switch on a transmission line is found to be

7

defective, but the transmission line segment is otherwise in sound condition

8

with many years of additional life remaining.

9

10 Q. WHAT PLANT ADDITIONS WILL OCCUR IN 2021 TO 2023 AS PART OF THE GROUP

11

1 SWITCH REPLACEMENTS PROJECT?

12 A. The Company has budgeted $7.1 million for the NSPM Group 1 Switch

13

Replacements ($2.4 million in 2021; $2.2 million in 2022; and $2.5 million in

14

2023). The Company has budgeted $3.6 million for the NSPW Group 1 Switch

15

Replacements ($1.5 million in 2021; $1.1 million in 2022; and $1.1 million in

16

2023).

17

18 Q. DESCRIBE THE W3203 BRIGGS-LA CROSSE LINE UPGRADE PROJECT.

19 A. This project involves rebuilding the W3203 Briggs ­ La Crosse line. This is a

20

10-mile, 161 kV transmission line located between the Company's Briggs Road

21

Substation located near Holmen, Wisconsin and La Crosse Substation in La

22

Crosse, Wisconsin. In 2016, this project was first identified as Major Line

23

Refurbishment project due to the age and condition of certain elements of the

24

line. However, during the 2019 annual transmission planning analysis, this line

25

was identified as being close to the thermal limits under contingency conditions.

26

As a result, it was recommended that the conductor of the line be upgraded. In

27

the 2020 annual transmission planning analysis, this line was identified as

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exceeding thermal limits in the 2024 Summer peak and light load cases under

2

multiple contingencies in the area and as requiring mitigation under NERC's

3

TPL-001-4 requirements. As a result, the scope of the project was expanded to

4

include upgrading the conductor size and all terminal end switches to meet

5

NERC's TPL-001-4 requirements. Upgrading the conductor will also require

6

all of the existing poles to be replaced in order to accommodate the new

7

conductor. This project is in the preliminary design and engineering phase with

8

construction scheduled to begin in 2022. This project is currently scheduled to

9

be placed in service in 2023 and has total plant additions of approximately $11.2

10

million.

11

12

2. Reliability Requirement Projects

13 Q. WHAT IS DRIVING THE COMPANY'S INVESTMENTS IN RELIABILITY

14

REQUIREMENT PROJECTS?

15 A. NERC develops and enforces reliability standards on all transmission owners,

16

operators, and users. The Company performs transmission planning studies to

17

identify necessary upgrades to the system to ensure compliance with NERC

18

standards. Through these studies, transmission planners evaluate all various

19

alternatives to meet the identified electrical needs for the system and select the

20

option that considers the incremental impact of the project for future needs in

21

the area and best meets the long-term electrical needs of the area in a cost

22

effective- manner. This category of projects also includes transmission

23

improvements that are needed to improve the reliability in our system where

24

the operating voltage of the system being improved is below NERC regulation;

25

these projects would typically be adding operational redundancy to our 34.5 kV,

26

69 kV and 88 kV transmission systems.

27

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1 Q. WHAT WOULD BE THE IMPACT OF EITHER FORGOING OR DEFERRING A

2

RELIABILITY REQUIREMENT PROJECT?

3 A. Deferring or forgoing a necessary Reliability Requirement project could impact

4

system reliability. Further, if the project is needed to meet a NERC reliability

5

standard, the Company could be found to be in violation of NERC reliability

6

standards.

7

8 Q. WHAT ARE THE KEY RELIABILITY REQUIREMENT PROJECTS THAT

9

TRANSMISSION WILL PLACE IN-SERVICE DURING THE MULTI-YEAR RATE PLAN

10

PERIOD?

11 A. There are three key Reliability Requirement projects and programs that will be

12

placed in-service between 2021 and 2023:

13

· Bayfield Loop Project;

14

· TACT program; and

15

· Hibbing Taconite 500 kV Project.

16

17 Q. PLEASE DESCRIBE THE BAYFIELD LOOP PROJECT.

18 A. The Bayfield Loop Project, which is also referred to as the Bayfield Second

19

Circuit Transmission Project, is needed to improve system reliability by adding

20

redundancy to the system by constructing a second 34.5 kV transmission line

21

and two new substations in the Bayfield Peninsula area of Wisconsin. The

22

proposed new transmission line would extend approximately 19 miles, and

23

would connect the two new substations: the Fish Creek Substation, located

24

approximately four miles west of Ashland, Wisconsin, and Pikes Creek

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Substation, located approximately two miles west of Bayfield, Wisconsin.2 The

2

project will increase electric reliability and reduce power outages across the

3

Bayfield Peninsula by providing voltage support and a second source of power

4

to the east side of the Bayfield Peninsula. The proposed 34.5 kV transmission

5

line is called the "second circuit" or "second source" because there is an existing

6

34.5 kV line extending to Bayfield. The Public Service Commission of

7

Wisconsin granted a Certificate of Authority for the Bayfield Loop Project on

8

February 7, 2020.3

9

10

Grading for the new Fish Creek Substation will begin in 2020 and construction

11

of the Pikes Creek Substation and the transmission line are planned to

12

commence in 2021. This project is currently scheduled to be placed in service

13

in 2022. The project1 has total plant additions of approximately $43.7 million

14

($0.2 million in 2021; $41.1 million in 2022; and $2.4 million in 2023).

15

16 Q. PLEASE DESCRIBE THE TACT PROGRAM.

17 A. NERC requires utilities to perform annual assessments of their transmission

18

system and to demonstrate plans to keep the transmission system within

19

specified voltage, thermal, and stability limits throughout the 10-year planning

20

period. The Company performs this annual assessment by participating in the

21

MISO MTEP process, which is an RTO lead reliability study effort. MISO

22

MTEP participants work together to analyze the transmission system for

23

deficiencies (high voltage, low voltage, lines or transformers beyond their rated

24

capability, etc.) and to ensure compliance with NERC Standard TPL-001-4.

2 Application of N. States Power Co.-Wisc. for a Certificate of Auth. to Construct the Bayfield Second Circuit Transmission Project, to be Located in Bayfield Cnty., Wisc., PSCW Docket No. 4220-CE-182, APPLICATION FOR A CERTIFICATE OF AUTHORITY (Mar. 8, 2019). 3 Application of N. States Power Co.-Wisc. for a Certificate of Auth. to Construct the Bayfield Second Circuit Transmission Project, to be Located in Bayfield Cnty., Wisc., PSCW Docket No. 4220-CE-182, FINAL DECISION (Feb. 7, 2020).

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Generally speaking, NERC Standard TPL-001-4 requires that transmission

2

system be designed and constructed to operate reliably over a broad spectrum

3

of system conditions and following a wide range of probable contingencies such

4

as loss of one or more elements of the system. The MISO MTEP studies the

5

performance of the system using 1-year, 5-year, and 10-year future models.

6

When deficiencies are identified, MISO transmission owners create a plan to

7

manage the transmission system to stay within the specified limits. The MISO

8

MTEP typically finalizes its annual study in December of each year.

9

10

The Company established the TACT program to allocate resources necessary

11

to address reliability issues on the NSP Transmission System that are identified

12

in the annual MISO MTEP studies.

13

14

For both NSPM and NSPW the TACT program has total plant additions of

15

approximately $19.2 million ($5.9 million in 2021; $8.2 million in 2022; $5.1

16

million in 2023).

17

18 Q. CAN YOU PROVIDE ADDITIONAL DETAILS ABOUT PROJECTS THAT WILL

19

COMPRISE THE TACT PROGRAM BUDGET DURING THE MULTI-YEAR RATE PLAN?

20 A. A discrete project in this program budget includes replacing both circuit

21

breakers and upgrading three switches at the Company's West Coon Creek

22

Substation. The West Coon Substation is connected to the Company's Coon

23

Creek Substation via a 115 kV transmission line. The two circuit breakers at

24

the West Coon Substation need to be rated for 3000 amps rather than their

25

current rating of 2000 amps. This is due to the fact that, if one of those circuit

26

breakers opens, the other breaker would not be able operate because of its lower

27

capacity rating (2000 amps) compared to the 3000 amps capability that would

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be coming from the 115 kV transmission line. The scope of work includes

2

replacing both circuit breakers and upgrading three switches at the West Coon

3

Creek Substation.

4

5 Q. PLEASE DESCRIBE THE HIBBING TACONITE (HIBTAC) 500 KV PROJECT.

6 A. The HibTac 500 kV Project is located southwest of the City of Chisholm,

7

Minnesota. This project includes the removal, replacement, and relocation of

8

an approximately 3.0-mile segment of an existing 500 kV line that is located on

9

Cleveland-Cliffs, Inc.'s land where HibTac has mining operations. The existing

10

transmission line was built on right-of-way authorized by a license agreement

11

rather than an easement. The license agreement includes provisions that the

12

Company would move the transmission line if requested by licensor. On

13

January 15, 2017, HibTac formally requested that the Company remove the line

14

from six parcels to allow expansion of the HibTac mine.

15

16

The Commission granted the Company a minor alteration approving

17

construction of the HibTac 500 kV Project on March 2, 2020.4 Foundation

18

work commenced in October 2020 and construction will be complete in 2021.

19

This project has total plant additions of $15.5 million in 2021.

20

21 Q. WHY IS THE COMPANY REQUIRED TO PAY FOR THIS PROJECT INSTEAD OF THE

22

CUSTOMER?

23 A. The license agreement for this portion of the 500 kV line included a condition

24

that stated that after the first 15 years of the license agreement the costs for

25

relocating the 500 kV line would be borne by the Company rather than HibTac.

4 In the Matter of the Application for a Minor Alteration of Xcel Energy's 500 kV Transmission Line 5702, Docket No. E002/MC-19-758, ORDER (Mar. 2, 2020).

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2

3. Interconnection Projects

3 Q. WHAT IS DRIVING TRANSMISSION'S INTERCONNECTION INVESTMENTS?

4 A. Under our tariff, we are required to make the necessary transmission upgrades

5

to accommodate interconnection requests. There are three general types of

6

Interconnection projects that drive our interconnection investments:

7

transmission interconnections, load interconnections, and generation

8

interconnections. Transmission interconnections are where one utility is

9

requesting to interconnect a transmission line to our transmission system. Load

10

interconnections are where a new substation serving electric load is needed and

11

is requesting to interconnect to our transmission system, or an existing load

12

serving substation is being modified. Generation interconnections are where a

13

new generator is requesting to interconnect to our transmission system.

14

15 Q. WHAT IS DRIVING THE INCREASE IN INTERCONNECTION PROJECTS BETWEEN

16

2021 TO 2023?

17 A. The increase in Interconnection projects is driven primarily by the number of

18

interconnection requests currently pending in the MISO queue. These new

19

generation facilities require certain transmission upgrades in order to

20

interconnect to the transmission system as a result, the Company is making

21

increasing investments to complete these necessary upgrades.

22

23 Q. WHAT ARE THE KEY INTERCONNECTION PROJECTS THAT TRANSMISSION

24

ANTICIPATES PLACING IN-SERVICE DURING THE MULTI-YEAR RATE PLAN

25

PERIOD?

26 A. During 2021 to 2023, the key Interconnection programs/projects are: (1)

27

NSPM/NSPW self-funded network upgrade (SFNU) projects; (2)

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J512/J569/J587/J590 HNA-SCO interconnection; and (3) IA Tariff Fund

2

Program.

3

4 Q. PLEASE DESCRIBE THE NSPM/NSPW SFNU PROJECT.

5 A. The SFNU are a group of projects to support network upgrades necessary to

6

accommodate generation interconnections. Specifically, network upgrades are

7

defined as the additions, modifications, and upgrades to the transmission system

8

that are required at or beyond the point at which the generation interconnection

9

facilities connect to the transmission system. Generally, these network upgrades

10

are either new facilities, such as transmission lines or substations, or occasionally

11

modifications and/or additions to existing transmission substations or to

12

transmission lines connecting to an existing substation.

13

14 Q. WHY ARE THE COSTS FOR THESE SFNU PROJECTS INCLUDED IN THIS RATE CASE

15

RATHER THAN BEING RECOVERED FROM THE INTERCONNECTION CUSTOMERS?

16 A. The MISO tariff allows transmission owners like Xcel Energy the option to

17

unilaterally choose to self-fund network upgrades without requiring

18

interconnection customers to make upfront payments for these upgrades. Prior

19

to the in-service date of the network upgrades, Xcel Energy will enter into a

20

Facilities Service Agreement (FSA) with the interconnection customer to repay

21

the actual cost for the network upgrade that allows Xcel Energy to earn a return,

22

typically over a period of twenty (20) years, with payments beginning the month

23

after the network upgrades are place into service. Xcel Energy has decided to

24

exercise the self-funding option for all network upgrades associated with MISO

25

generation interconnection projects. The payments that will be made by

26

generators in accord with these FSAs over the term of the multi-year rate plan

27

are included in the transmission revenues budget in this case, which reduce the

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retail revenue requirement and keep retail customers whole. As such, these

2

Interconnection projects essentially pay for themselves, although the timing of

3

these reimbursements may differ depending on the project.

4

5 Q. WHAT IS THE BUDGET FOR SFNU PROJECTS OVER THE TERM OF THE MULTI-

6

YEAR RATE PLAN?

7 A. The Company has budgeted $46.3 million for the NSPM SFNU Project ($0.5

8

million in 2021; $16.5 million in 2022; and $29.2 million in 2023). The Company

9

has budgeted $6.0 million for the NSPW SFNU Project ($0.1 million in 2021;

10

$1.9 million in 2022; and $4.0 million in 2023).

11

12 Q. HOW DID THE COMPANY DEVELOP THE BUDGET FOR THE NSPM/NSPW

13

SFNU PROJECTS?

14 A. Currently, there are approximately 14 renewable generation interconnection

15

projects in the MISO queue that will require network upgrades to accommodate

16

their interconnection to the MISO transmission system. The budget for these

17

potential projects is developed by a facilities study performed by Xcel Energy

18

engineers at the request of MISO. These facilities studies include high-level

19

cost estimates of the potential network upgrades required based on general

20

location of the renewable generation source and proposed output of the

21

renewable generation. We relied on the cost estimates from these facilities

22

studies to develop the budget for the NSPM/NSPW SFNU projects.

23

24 Q. DESCRIBE THE HELENA­SCOTT 345 KV REBUILD PROJECT

25

(J512/J569/J587/J590 HNA-SCO INTERCONNECT PROJECT).

26 A. The Helena­Scott 345 kV Rebuild Project is an example of an SFNU project

27

but this project has its own budget apart from the overall SFNU project budget

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due to the fact that it is in the final design phase. This project involves the

2

rebuilding the existing 17-mile Helena­Scott 345 kV transmission line in Scott

3

and Carver counties to increase the capacity of the line to accommodate the

4

interconnection of several new renewable generators. Specifically, MISO

5

generation interconnection studies determined that this line needed to be rebuilt

6

to increase the capacity of the conductor to accommodate the interconnection

7

of four new wind farms in the area: the Blazing Star 2 Wind Project, the Nobles

8

2 Power Partners Projects, the Walleye Wind Project, and the Invenergy Wind

9

Development Project. To support this higher capacity conductor, the existing

10

lattice and wood H-frame structures will be replaced with new steel H-frame

11

structures. Xcel Energy as the transmission owner of this line is using the self-

12

funding option of the MISO tariff for these network upgrades. At the

13

completion of this rebuild, Xcel Energy will enter into an FSA with each

14

generator to refund their respective costs for these network upgrades. The

15

payments that will be made by these four generators in accord with these FSAs

16

over the term of the multi-year rate plan are included in the transmission

17

revenues budget in this case, which reduce the retail revenue requirement and

18

keep retail customers whole.

19

20

This project is currently in the final design phase and construction is expected

21

to commence and be completed in 2021. The Helena ­ Scott County Rebuild

22

Project (J512/J569/J587/J590 HNA-SCO interconnect project) has total plant

23

additions of approximately $35.8 million in 2021.

24

25 Q. PLEASE DESCRIBE THE IA TARIFF FUND PROGRAM.

26 A. This program is used to fund generation interconnection related transmission

27

capital investments. The specific transmission upgrades in this program have

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not yet reached the level of specificity to be defined as specific capital projects

2

but nonetheless are expected based on generator's announced plans or

3

interconnection requests in the MISO queue. The Company has budgeted

4

$12.5 million for the NSPM IA Tariff Fund ($0.0 million in 2021; $8.5 million

5

in 2022; and $4.0 million in 2023). The Company has budgeted $9.1 million for

6

the NSPW IA Tariff Fund ($0.0 million in 2021; $6.1 million in 2022; and $3.0

7

million in 2023).

8

9 Q. CAN YOU PROVIDE AN EXAMPLE OF A PROJECT WITHIN THE IA TARIFF FUND

10

PROGRAM?

11 A. One example is our J569 Rock County Substation project to interconnect a wind

12

generator into the Company's Rock County Substation that will be placed in

13

service in 2021. Another example is the Lismore project to interconnect Nobles

14

Power Cooperative (a GRE cooperative) to Xcel Energy's transmission system

15

to allow for customer load growth by Nobles Power Cooperative. This project

16

will be placed in service in 2021 and has plant additions of $1.4 million.

17

18 Q. HOW DID THE COMPANY DEVELOP THE BUDGET FOR THE IA TARIFF FUND

19

PROGRAM?

20 A. As noted above, the budget for this program is based on historical averages and

21

known Interconnection project requests.

22

23

4. Physical Security and Resiliency Projects

24 Q. WHAT ARE THE MAJOR ISSUES FACING TRANSMISSION WITH REGARD TO

25

PHYSICAL SECURITY AND RESILIENCY?

26 A. Transmission is focused on maintaining the security of our assets. High voltage

27

transformers comprise less than three percent of transformers in U.S. electric

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power substations, but they carry 60 to 70 percent of the nation's electric load.

2

Since they serve as vital nodes and carry bulk volumes of electricity, these

3

transformers are critical elements of the nation's electric power grid. They are

4

also the most vulnerable to intentional damage from malicious acts. In April

5

2013, for example, a substation in California was subject to a coordinated

6

military-type sniper attack that disabled 17 high voltage transformers, rendering

7

this substation useless.

8

9

Federal regulatory agencies have since responded to these growing threats by

10

adopting physical security standards for transmission facilities. On March 7,

11

2014, FERC issued an Order on Reliability Standards for Physical Security

12

Measures, which ultimately led to NERC standard CIP-014 addressing risks due

13

to physical security threats and vulnerabilities. To address these threats and

14

meet this new NERC standard, we are making necessary investments to make

15

our grid more resilient so that we can respond quickly to physical security

16

threats.

17

18 Q. WHAT ARE THE KEY PHYSICAL SECURITY AND RESILIENCY PROJECTS THAT

19

TRANSMISSION ANTICIPATES PLACING IN-SERVICE DURING THE MULTI-YEAR

20

RATE PLAN PERIOD?

21 A. The Physical Security and Resiliency projects that will be placed in-service

22

between 2021 and 2023 will arise out of two programs: (1) NSPM/NSPW

23

Physical Security program and (2) the NERC Circuit Protection program.

24

25 Q. PLEASE DESCRIBE THE NSPM/NSPW PHYSICAL SECURITY PROGRAM.

26 A. The NSPM/NSPW Physical Security program was developed to ensure the

27

Company's compliance with the NERC CIP-014 Physical Security Standard.

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Additionally, the program aims to improve substation site security where the

2

Company's Protection Services department has identified ongoing theft issues.

3

The purpose of this program is to improve the physical security of the

4

Company's substations. The Company is developing site-specific security plans

5

for specific substations and is obtaining third-party verification of the

6

effectiveness of these plans. These site-specific security plans may include the

7

following security measures: cameras, fencing/barrier improvements, ballistic

8

shielding of identified key substation equipment, site access controls, ground

9

sensory monitoring, and radar technology. This program is planned for 15

10

discrete substation sites in 2021; additional sites will be identified and evaluated

11

against the most current NERC security standards for inclusion in this program

12

as those standards are updated every two years.

13

14

The Company has budgeted $72.0 million for the Physical Security program

15

over the term of the multi-year rate plan ($31.3 million in 2021; $20.3 million in

16

2022; and $20.4 million in 2023).

17

18 Q. HOW DID THE COMPANY DEVELOP THE BUDGET FOR THE PHYSICAL SECURITY

19

PROGRAM?

20 A. Our Substation Compliance team and our Protection Services department have

21

identified sites that are highly likely to either a) need to be brought up to the

22

NERC CIP-014 Physical Security Standard or b) have been targets of ongoing

23

theft. As changes to the transmission system regularly occur, those changes

24

may impact a substation location that was not previously required to have the

25

physical security controls as defined under CIP-014. This is because whether

26

or not security controls are required under CIP-014 is dependent on the impact

27

the loss of that substation may have on the bulk electric system. As new

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transmission projects come forward, Xcel Energy reviews the associated

2

impacted substations to determine whether these locations must now meet the

3

heightened physical security requirements outlined in the NERC CIP-014

4

standard. A similar reevaluation is performed for sites that have been a target

5

of theft.

6

7

The budget for each of the identified sites are estimated at a high level based on

8

existing as-built and record drawings. Each site is then prioritized within the

9

program based on the level of protection required to bring it up to the NERC

10

standard or discourage theft. Each site requires an on-site evaluation by the

11

project team to validate the existing conditions, determine if there are other site

12

conditions that were not identified in the record drawings and update/validate

13

the estimate. This site evaluation is typically done in the year prior to the specific

14

site's in-service date.

15

16 Q. PLEASE DESCRIBE THE NERC CIRCUIT PROTECTION PROGRAM.

17 A. The NERC Circuit Protection program was initiated to comply with FERC

18

Order 754. Under FERC Order 754, the Company must identify single point

19

failures at critical substations with voltages of 200 kV or above and report the

20

results to NERC. The Company has studied the relevant substations and

21

identified certain required modifications to eliminate these single point failures.

22

This program includes capital projects related to separating primary and

23

secondary relaying and adding redundant direct current circuits at several

24

Company-owned substation facilities. This separation allows a back-up battery

25

to continue to provide protection services in the case the primary battery at the

26

substation fails.

27

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The Company has budgeted $17.3 million for the NERC Circuit Protection

2

program ($2.5 million in 2021; $10.6 million in 2022; and $4.3 million in 2023).

3

Under NERC Order 754, substation owners must identify and address

4

deficiencies in their protection and control systems that could pose a risk to the

5

backup response in case a failure occurs. This includes eliminating

6

opportunities for a single point of failure across multiple breakers. NERC

7

Order 754 requires compliance by 2024 so Transmission started this work in

8

2017 and will ramp up this work in 2022 and 2023 is to ensure that we complete

9

all required work prior to 2024.

10

11 Q. CAN YOU PROVIDE AN EXAMPLE OF A PROJECT WITHIN THE NERC CIRCUIT

12

PROTECTION PROGRAM?

13 A. One of the projects that the Company will be completing to comply with NERC

14

Order 754 is at the Prairie Island Substation where the Company will be adding

15

auxiliary relays to trip the breakers of other transformers in the event that a

16

failure occurs on another substation breaker. This improvement will ensure

17

compliance with NERC Order 754 and improve the reliability of the Prairie

18

Island Substation. This project will be in service in 2021 and has associated

19

plant additions of $1.1 million.

20

21

5. Regional Expansion Projects

22 Q. WHAT ARE THE KEY REGIONAL EXPANSION PROJECTS THAT TRANSMISSION

23

ANTICIPATES PLACING IN SERVICE DURING THE MULTI-YEAR RATE PLAN

24

PERIOD?

25 A. There are two key Regional Expansion projects that will be placed in-service

26

between 2021 and 2023: (1) the Huntley­Wilmarth 345 kV Project and (2) the

27

Google Data Center Project.

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2 Q. DESCRIBE THE HUNTLEY­WILMARTH 345 KV PROJECT.

3 A. The Huntley­Wilmarth 345 kV Project is a joint project between Xcel Energy

4

and ITC Midwest and involves the construction of an approximately 50-mile,

5

345 kV transmission line in southern Minnesota and associated substation

6

modifications. The transmission line will connect Xcel Energy's Wilmarth

7

Substation, located north of Mankato, and ITC's Huntley Substation, located

8

south of Winnebago. The project will also include modifications at both the

9

Huntley and Wilmarth substations to accommodate the new 345 kV

10

transmission line.

11

12

The Huntley­Wilmarth Project is needed to reduce congestion on the

13

transmission grid in southern Minnesota and northern Iowa to deliver low-cost

14

electricity to consumers from generation facilities in the area, including wind

15

farms. The project was studied, reviewed, and approved by MISO as a Market

16

Efficiency Project (MEP) in December 2016 as MISO found that the project

17

will reduce congestion on the transmission system, which will improve the

18

efficiency of MISO's energy markets resulting in lower wholesale energy costs.

19

The Commission granted a Certificate of Need and Route Permit for the

20

Huntley­Wilmarth Project on August 5, 2019.5

21

22

The project is currently under construction and will be placed in service in

23

December 2021, which is the project's MISO designated in-service date. The

5 In the Matter of the Application of Xcel Energy and ITC Midwest LLC for a Certificate of Need and for a Route Permit for the Huntley­Wilmarth 345-kV Transmission Line Project, ORDER FINDING ENVIRONMENTAL IMPACT STATEMENT ADEQUATE, GRANTING CERTIFICATE OF NEED, ISSUING ROUTE PERMIT, AND REQUIRING ADDITIONAL ANALYSIS, Docket Nos. E002, ET-6675/CN-17-184, TL-17-185 (Aug. 5, 2019).

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project has total plant additions of approximately $79.8 million ($2.3 million in

2

2020; $73.2 million in 2021; and $4.3 million in 2022).

3

4 Q. DESCRIBE THE GOOGLE DATA CENTER PROJECT.

5 A. The Company has negotiated several agreements with Honeycrisp, LLC, an

6

affiliate of Google LLC, that are intended to help bring a new data center to the

7

City of Becker, Minnesota. If the project moves forward, it could generate $600

8

million in capital investment and presents an opportunity to be one of the

9

largest private economic development endeavors in central Minnesota. To

10

facilitate the development of the possible new data center, the Company sought

11

and received approval from the Commission for several agreements, associated

12

cost recovery, and certain tariff amendments and waivers that would enable the

13

Company to provide retail electric service at transmission voltage to the possible

14

new data center.6

15

16

Among the several agreements, the Company executed an IA for Retail Electric

17

Service at Transmission Voltage, which provides the terms and conditions for

18

the Company's build-out of certain transmission voltage facilities to support

19

interconnection of the data center. The IA provides different transmission

20

voltage configurations to support varying amounts of data center load in line

21

with the customer's issuance to the Company of a "Notice to Proceed," after

22

which the Company is obligated to construct the necessary facilities at its cost.

23

Should the IA be terminated prior to the conclusion of the 10-year IA period,

24

Honeycrisp, LLC would make a termination payment to the Company

6 In the Matter of the Pet. by N. States Power Co. d/b/a Xcel Energy for Approval of Contracts and Ratemaking Treatment for Provision of Elec. Serv. to Google's Data Center Project, Docket Nos. E002/M-19-39 and E002/M-19-60, ORDER APPROVING PETITION WITH CONDITIONS (July 15, 2019).

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equivalent to the net book value of the transmission facilities as of the date of

2

termination.

3

4

The Company also requested and received approval of a one-time waiver from

5

the Company's General Time-of-Day Service Tariff requiring that a customer

6

bear the cost of interconnection upgrades required to serve the customer.

7

Rather than recover these costs directly from Honeycrisp, LLC via a

8

contribution in aid of construction (CIAC), the Company requested ­ and the

9

Commission granted ­ authorization to seek recovery of these costs in a future

10

rate case.7

11

12

The project has forecasted total plant additions from 2021 to 2023 of

13

approximately $15.2 million ($1.4 million in 2021 and $13.8 million in 2022).

14

15 Q. WHY IS THE DATA CENTER PROJECT CLASSIFIED AS A REGIONAL EXPANSION

16

PROJECT?

17 A. In addition to large regional infrastructure, our Regional Expansion Projects

18

also include those projects driven by economic development needs, which is

19

the primary driver for the Data Center project.

20

21

6. Communication Infrastructure Projects

22 Q. WHY ARE INVESTMENTS IN COMMUNICATION INFRASTRUCTURE NECESSARY?

23 A. Communication circuits are required at substations for SCADA, remote

24

engineering access, and teleprotection. In the past, the Company has relied on

25

third-party telecommunication providers for the infrastructure necessary for

26

our SCADA and teleprotection circuits (i.e., communication circuits between

7 Id. at 23.

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our substations and between our substations and our control center). However,

2

many of the telecommunication companies are phasing out their dedicated

3

analog wide area network (WAN) technology and replacing it with Ethernet

4

over fiber optics or other broadband services. These new services, while

5

capable of carrying large volumes of data, are not able to carry the data that we

6

transmit within acceptable performance requirements for the teleprotection of

7

our transmission system. As a result, we need to invest in Company-owned and

8

controlled communication infrastructure using fiber optic cable that will serve

9

our operational and system protection needs without the reliance on and

10

vulnerability to exposure from a publicly available third-party network.

11

12

Similarly, cyberattacks pose a credible threat to the reliability of our transmission

13

system as hackers could cause system outages by disabling telecommunications

14

or key pieces of equipment. Every day there are coordinated attempts to

15

infiltrate communication systems and disrupt the transmission grid. Federal

16

regulatory agencies have responded to these growing threats by adopting

17

cybersecurity standards for transmission facilities. The Company-owned

18

telecommunications network we are investing in enables the Company to

19

reduce our exposure to cybersecurity threats from the publicly available service

20

provided by third-party telecommunication providers.

21

22 Q. DO THESE INVESTMENTS PROVIDE ANY OTHER BENEFITS?

23 A. Yes, an additional benefit of these investments is that they will also support the

24

advanced grid and information system (AGIS) initiative and enterprise-wide

25

initiatives by enabling connectivity between all of our substations and corporate

26

offices.

27

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1 Q. WHAT ARE THE KEY COMMUNICATION INFRASTRUCTURE PROJECTS THAT

2

TRANSMISSION ANTICIPATES PLACING IN-SERVICE DURING THE MULTI-YEAR

3

RATE PLAN PERIOD?

4 A. The key Communication Infrastructure projects that will be placed in service

5

between 2021 and 2023 will arise out of the Communication Network program.

6

7 Q. DESCRIBE THE COMMUNICATIONS NETWORK PROGRAM.

8 A. The Communication Network program aims to privatize Xcel Energy's

9

communication network infrastructure across the NSPM and NSPW service

10

territories, wherever possible, at all transmission and distribution substations

11

for SCADA, teleprotection, and remote engineering access. Specifically, the

12

program addresses aging analog circuit technology and other technology that is

13

anticipated to become obsolete within five years. The Company will then build

14

secure communication architecture for physically isolated operational

15

technology (OT) and information technology (IT) networks from each other to

16

support islanding of the energy management system (EMS) for further cyber

17

security resilience. The program will enable the Company to reduce dependency

18

on third-party circuit providers, which will improve the Company's

19

troubleshooting response time and reduce circuit down time.

20

21

The Company has budgeted $46.7 million for the NSPM Communication

22

Network program ($3.9 million in 2021; $17.3 million in 2022; and $25.5 million

23

in 2023). The Company has budgeted $20.0 million for the NSPW

24

Communication Network program ($5.0 million in 2021; $5.0 million in 2022;

25

and $9.9 million in 2023).

26

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1 Q. CAN YOU PROVIDE AN EXAMPLE OF ONE OF THESE COMMUNICATION

2

NETWORK PROJECTS?

3 A. Yes, one example is at the Company's Rosemount Substation in Rosemount,

4

Minnesota where we will be installing upgraded telecommunication equipment

5

and installing a private communication network path (fiber optic cable) from

6

the substation to a leased fiber optic cable located outside the substation that

7

will only be utilized by the Company for communication within our network.

8

9 Q. HOW DID THE COMPANY DEVELOP THE BUDGETS FOR THE COMMUNICATIONS

10

NETWORK PROGRAM?

11 A. The budget is based on Communication Network infrastructure projects

12

identified and prioritized by our substation communication engineering group

13

for consideration in the capital budget. Communication projects are prioritized

14

based on technical need and proximity to exiting private network infrastructure

15

that is deliberately built out from a reliable core network. These projects are

16

vetted and prioritized against all Transmission projects; and rebalanced and

17

reprioritized across the entire portfolio of projects based on corporate budget

18

requirements. Project costs are estimated using historic costs from prior

19

projects.

20

21 Q. WHAT DO YOU CONCLUDE WITH RESPECT TO THE OVERALL LEVEL OF

22

TRANSMISSION CAPITAL COSTS THE COMPANY IS SEEKING TO RECOVER IN THIS

23

RATE CASE?

24 A. I conclude that our capital forecasts represent an accurate and reasonable

25

projection of our investments over these years and, as shown by the above

26

discussion, are necessary to provide reliable and resilient transmission service

27

for our customers. Finally, the costs included in our 2021 through 2023 capital

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budgets are representative of the types of work we must and will do year over

2

year. Therefore, these capital forecasts can be relied on to set just and

3

reasonable rates for our customers.

4

5

IV. O&M BUDGET

6

7

A. O&M Overview and Trends

8 Q. WHAT IS INCLUDED IN THE TRANSMISSION O&M BUDGET?

9 A. The Transmission O&M budget includes costs associated with the operation

10

and maintenance of our transmission system. This includes internal and

11

contract labor, employee expenses, fees, and materials. The majority of

12

Transmission's O&M budget is related to internal labor costs as these

13

employees are necessary to plan, construct, operate, and maintain the

14

transmission system on a daily basis.

15

16 Q. WHAT ARE THE TRANSMISSION O&M BUDGET CATEGORIES?

17 A. The Transmission business unit O&M budget consists of six main cost

18

categories: (1) internal labor; (2) contract labor and consulting; (3) employee

19

expenses; (4) fees; (5) materials; and (6) other. I describe these categories in

20

detail later in my testimony.

21

22 Q. HOW ARE THE TRANSMISSION BUSINESS UNIT LONG-TERM O&M COSTS

23

TRENDING?

24 A. From 2017 to 2019, the Transmission business unit has engaged in productivity

25

improvement initiatives, which have resulted in a declining O&M expenses over

26

these years. These efforts have driven improved scheduling and field

27

productivity, resulting in more efficient and effective ways for transmission

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crews to schedule and complete their work, thus reducing O&M expenditures.

2

Additionally, an industry benchmarking analysis resulted in changes to the

3

Company's repair versus replacement policies to promote replacement over

4

repair for assets that required repeated costly repairs. These initiatives, and the

5

resulting reductions in O&M expense, have been executed to offset ongoing

6

inflationary pressures, as well as pressures resulting from the Company's asset

7

growth. For example, scheduling efficiencies have driven the organization from

8

a 41 percent to a 90 percent average scheduling efficiency. This allows work to

9

be planned and executed in a more efficient manner reducing the overall O&M

10

cost of the work. Some examples of the efforts that led to the increased

11

efficiency include locking in the schedules a week prior, more detailed

12

scheduling, formalized job readiness checklists, minimization of schedule

13

changes, and daily huddles with leadership and crews to discuss daily work

14

plans.

15

16

Transmission's forecasted O&M for 2020 is lower than the three-year average

17

of 2017 to 2019. During 2020 our operations were impacted by the COVID-

18

19 public health emergency. In response to the impact that COVID-19 had on

19

our communities, customers, and operations in 2020, Transmission adjusted

20

our operations to keep employees and communities safe as well as to maintain

21

financial flexibility as the Company faced uncertainties about the depth and

22

duration of the impacts of COVID-19. Specifically, Transmission temporarily

23

reduced O&M expenses in 2020 by reducing contractor hours, reduced

24

employee travel, delaying hiring open positions, and scaling back on overtime,

25

where possible without impacting safety and reliability.

26

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1 Q. WHAT ARE THE TRANSMISSION O&M BUDGETS FOR 2021 TO 2023?

2 A. As shown in Table 10, we have budgeted $38.2 million for Transmission O&M

3

in 2021, $38.7 million in 2022, and $40.4 million in 2023.

4

5

Table 10 also provides our actual O&M costs for 2017 to 2019 and the 2020

6

forecast for O&M spend (half year actuals and half year forecast). Table 11

7

provides this same information but allocated to the State of Minnesota Electric

8

Jurisdiction. Exhibit___(IRB), Schedule 3 also provides the Transmission

9

O&M costs by cost category for 2017 to 2019.

10

11

Table 10

12

Transmission O&M Budget by Cost Category

13

NSPM-Electric ($000,000)

14

Cost

2017

2018

2019 2017 ­ 2019 2020

2021

2022

2023

Category

Actual Actual Actual Average Forecast Budget Budget Budget

15

Internal Labor $21.40 $22.00 $20.40

$21.30

$20.00 $21.50 $22.10 $22.80

16 17

Contract Labor and Consulting

$4.70

$4.50

$4.50

$4.60

$3.90 $4.50 $4.50 $4.40

Employee

18

Expenses

$2.70

$2.90

$2.70

$2.80

$2.30 $3.10 $3.10 $3.10

Fees*

19

Materials

$3.50 $3.60

$3.50 $3.30

$3.40 $2.50

$3.50 $3.10

$3.50 $1.70

$3.70 $2.50

$3.90 $2.40

$4.20 $2.30

20

Other

$5.10

$4.10

$2.60

$3.90

$2.60 $2.90 $2.70 $3.60

21

Total

$41.00 $40.30 $36.10

$39.20

$34.0 $38.20 $38.70 $40.40

* The "Fees" cost category includes Dues, Fees, and Licenses, which includes professional & utility

22

association dues, land and railroad permits, license fees, as well as NERC and FERC assessments.

23

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Table 11

2

Transmission O&M Budget by Cost Category

3

State of Minnesota Electric Jurisdiction

(Net of Interchange Billings to NSPW)

4

($000,000)

5

Cost

Category

2017

2018

2019 2017 ­ 2019 2020

2021

2022

2023

Actual Actual Actual Average Forecast Budget Budget Budget

6

Internal Labor $15.8 $16.2 $14.9

$15.6

$14.6 $15.7 $16.1 $16.6

7

Contract Labor and Consulting

$3.5

$3.3

$3.3

$3.4

$2.8

$3.3

$3.3

$3.2

8

Employee

Expenses

$2.0

$2.2

$2.0

$2.0

$1.7

$2.2

$2.2

$2.2

9

Fees*

$2.6

$2.6

$2.5

$2.5

$2.5

$2.7

$2.8

$3.1

10

Materials

Other

11

Total

$2.7 $3.7 $30.3

$2.5 $3.1 $29.9

$1.8 $1.9 $26.4

$2.3 $3.0 $28.8

$1.2 $1.9 $24.7

$1.8 $2.2 $27.9

$1.8 $2.0 $28.2

$1.7 $2.6 $29.4

12

* The "Fees" cost category includes Dues, Fees, and Licenses, which includes professional & utility association dues, land and railroad permits, license fees, as well as NERC and FERC assessments.

13

14

15 Q. DO TRANSMISSION'S O&M EXPENSES FOR 2021 TO 2023 CONTINUE THIS

16

DECLINING TREND FROM 2017 TO 2019?

17 A. Generally, yes. The Transmission O&M budget for 2021 to 2022 trends lower

18

than 2017 to 2019 actuals, with a slight increase in 2023 as compared to 2017

19

to 2019 actuals. Overall, the three-year average for these years ($39.1 million)

20

is below the most recent three-year historical average (2017 to 2019) of $39.20

21

million. This continued decrease is primarily driven by productivity

22

improvement initiatives that have been implemented by Transmission that I

23

discussed earlier.

24

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1 Q. HOW DOES THE TRANSMISSION O&M BUDGET FOR 2021 TO 2023 COMPARE TO

2

2019 ACTUALS?

3 A. Transmission's O&M budget for each of these three years is higher than 2019

4

actuals by an average of eight percent. The overall increase from 2019 actuals

5

to the 2021 to 2023 O&M budget is driven by increases in: 1) base pay; 2) non-

6

labor inflation; 3) fees; and 4) asset growth and compliance.

7

8 Q. WHAT IS DRIVING THE INCREASE IN BASE PAY DURING THE TERM OF THE MULTI-

9

YEAR RATE PLAN?

10 A. Transmission has budgeted a three percent annual increase in base pay for non-

11

bargaining employees and two and a half percent annual increase in base pay

12

for bargaining employees. Annual base pay increases are discussed in greater

13

detail by Company witness Ms. Ruth K. Lowenthal.

14

15 Q. WHAT IS NON-LABOR INFLATION AND HOW DOES IT IMPACT TRANSMISSION

16

O&M EXPENSES?

17 A. This represents inflation for all non-labor (excluding fees) portions of our O&M

18

budget. Transmission has budgeted a one percent increase in non-labor O&M

19

costs to account for inflation.

20

21 Q. WHAT IS DRIVING THE INCREASE IN FEES?

22 A. Transmission's budget for regulatory fees is based on guidance received from

23

regulatory agencies as to the expected increase in these fees each year. Guidance

24

from NERC and MRO suggested a per year increase of five percent for both

25

organizations. Consistent with this guidance, the Company has budgeted an

26

average increase of 11 percent for 2021 to 2023 as compared to the 2017 to

27

2019 actuals.

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2 Q. HOW DOES ASSET GROWTH AND COMPLIANCE RESULT IN INCREASED O&M

3

EXPENSES?

4 A. The Company's asset base is growing by approximately five percent annually as

5

the Company constructs additional miles of transmission line and as the number

6

of substations increases. This asset growth results in increased O&M expenses

7

for both transmission lines and substations. Examples of transmission O&M

8

work that increases as the asset base increases are substation inspections,

9

transmission line inspections, administration and supervision, administrative

10

and general maintenance, battery maintenance, relays, and corrective

11

maintenance.

12

13 Q. ARE THERE ANY OTHER REASONS WHY THE TRANSMISSION O&M BUDGET FOR

14

2021-2023 IS HIGHER THAN 2019 ACTUAL O&M EXPENSES?

15 A. Yes, 2019 O&M expense is an outlier in that it is $4.6 million below the 2017-

16

2018 historical average. This is the result of the acceleration of certain O&M

17

expenses into late 2018, which then reduced 2019 O&M expenses. The O&M

18

activities and expenditures that were accelerated into 2018 include capacitor

19

bank purchases, oil leak repairs, and addressing outstanding corrective

20

maintenance. Transmission's 2019 O&M spend is also lower due to a backlog

21

of maintenance projects driven by the prioritization of other types of work

22

during 2019. This backlog of maintenance work will be addressed in 2021

23

through 2023, thus increasing the 2021-2023 O&M budgets as compared to

24

2019. A portion of these increases have been offset by productivity

25

improvement initiatives, which have been implemented by Transmission. Table

26

12 summarizes the impacts of these items on the O&M budget.

27

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2

Table 12

3

Transmission 2021-2023 Budget vs. 2019 Actual O&M Expenditures

4

NSPM-Electric

(Dollars in Millions)

5

Amount of

Cost Drivers

6

2019 Actual

Increase/Decrease

Total $36.10

7

Base Pay

Non-labor Inflation

8

Fees: NERC, Professional and Association Dues, and License Fees

$1.20 $0.20 $0.40

9

2019 Normalization

Fund Substations Maintenance Backlog

10

Asset Growth and Compliance

$1.00 $1.70 $0.30

11

Productivity Improvement Initiatives

Miscellaneous Other

12

2021 Budget

($2.80) $0.10

$38.20

13

Base Pay

Non-labor Inflation

14

Fees: NERC, Professional and Association Dues, and License Fees

$0.70 $0.10 $0.20

15

Asset Growth and Compliance

Productivity Improvement Initiatives

16

Miscellaneous Other

$0.30 ($1.00)
$0.20

17

2022 Budget

18

Base Pay Non-labor Inflation

$0.70 $0.10

$38.70

19

Fees: NERC, Professional and Association Dues, and License Fees

Asset Growth and Compliance

20

Miscellaneous Other

$0.30 $0.30 $0.30

21

2023 Budget

$40.40

22

23 Q. HOW DO THE 2021 TO 2023 O&M BUDGETS COMPARE WITH THE 2020

24

FORECAST?

25 A. Transmission's O&M budget for each of these three years is higher than the

26

2020 forecast by an average of 15 percent. The overall increase from the 2020

27

forecast to the 2021 to 2023 O&M budget is driven by increases in: 1) base pay;

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2) non-labor inflation; 3) fees; and 4) asset growth and compliance. In addition,

2

as noted above, our 2020 O&M expenses are lower due to several reductions

3

made in response to COVID-19.

4

5 Q. HOW DOES THE 2022 O&M BUDGET COMPARE TO THE 2021 BUDGET?

6 A. The 2022 O&M budget is one percent higher than the 2021 budget. This is due

7

to slight increases in: 1) base pay; 2) non-labor inflation; 3) fees; and 4) asset

8

growth. These increases are partially offset by the realization of additional

9

productivity improvement initiatives implemented by Transmission, resulting in

10

reduced O&M expenditures.

11

12 Q. HOW DOES THE 2023 O&M BUDGET COMPARE TO THE 2022 BUDGET?

13 A. The 2023 O&M budget is four percent higher than the 2022 budget. This is

14

driven by increases in: 1) base pay; 2) non-labor inflation; 3) fees; and 4) asset

15

growth.

16

17 Q. HOW HAS THE COVID-19 PANDEMIC AFFECTED TRANSMISSION'S O&M

18

FORECASTS FOR 2021 AND BEYOND?

19 A. The COVID-19 pandemic has not materially changed Transmission's O&M

20

forecasted costs for 2021 through 2023. Our 2020 O&M budget reflects one-

21

time reductions discussed above but these reductions are not sustainable as the

22

core work of Transmission, operating and maintaining our transmission system,

23

must continue in spite of the pandemic.

24

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B. O&M Budgeting Process

2 Q. HOW DOES THE COMPANY SET THE O&M BUDGET FOR THE TRANSMISSION

3

BUSINESS UNIT?

4 A. As with our capital budget, the O&M budget for the Transmission business unit

5

is built using a bottom-up approach. Each budget manager reviews their needs,

6

factoring in work plans as well as any anticipated efficiency gains for the coming

7

years, and develops budgets in accordance with those needs and anticipated

8

efficiency improvements. As part of this bottom-up process, the field

9

operations and construction units review those facilities that need repairs to

10

extend their asset life, addressing issues like broken insulators, loose hardware,

11

woodpecker damage, broken or damaged guy wires, etc. In this way, Asset

12

Renewal projects are a driver of the O&M budgeting process. The individual

13

manager budgets are then consolidated for a total Transmission O&M budget

14

and analyzed for reasonableness and accuracy as compared to recent actual

15

trends. This process includes normalizing the actual spend for those expenses

16

that are not expected to continue into the budget year due to changes in business

17

conditions or one-time events. The total Transmission business unit budget is

18

compared to the overall Company targets, which are discussed further in Ms.

19

Ostrom's Direct Testimony. If the budget is greater than the overall Company

20

targets provided to Transmission, the needs are prioritized with the most critical

21

needs funded first and the least critical needs funded last.

22

23 Q. DOES TRANSMISSION EVER NEED TO CHANGE THE ALLOCATION OF O&M

24

FUNDS DURING THE FINANCIAL YEAR?

25 A. Yes, the Transmission business unit has had to change the allocation of O&M

26

funds during the financial year. Unexpected operational or regulatory events,

27

such as additional NERC compliance requirements, during the year can cause

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additional unplanned transmission O&M costs. When this occurs, we make

2

every effort to re-evaluate activities within the Transmission business unit to

3

absorb the unexpected costs.

4

5 Q. HOW OFTEN DOES TRANSMISSION RE-EVALUATE ITS O&M BUDGET?

6 A. The Transmission business unit re-evaluates the business needs annually in

7

development of the O&M budget. As needs change, the budget is prioritized

8

to fund the most critical needs first. If the funding required for critical needs is

9

greater than the Company target provided to the Transmission business unit,

10

the critical needs that are not funded within the targets provided are brought to

11

the Company to be prioritized along with the needs of the other business units.

12

For example, if a new NERC compliance requirement is implemented that will

13

cause a substantial change in O&M expenditures and was not contemplated in

14

the targets provided by the Company, additional funding may be requested by

15

the Transmission business unit to cover that need.

16

17

Also, during any given year, we are routinely monitoring our O&M actual

18

expenditures versus their associated budgets and identifying any variances of

19

significance as they materialize. As budget pressures are identified in certain

20

areas or programs, options are reviewed to mitigate those pressures. One

21

mitigation option would be the reallocation of funds from other areas, where

22

budgeted work of a lower priority or more discretionary nature in the short-

23

term may be reallocated to cover the programs experiencing the budget

24

pressures. If the amount needing funding cannot be funded prudently within

25

the overall Transmission business unit O&M budget, the issue is brought

26

forward to the Company as a request to increase the overall O&M target for the

27

Transmission business unit.

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2 Q. PLEASE EXPLAIN HOW TRANSMISSION MONITORS ITS O&M EXPENDITURES.

3 A. The Transmission business unit is supported by a dedicated finance team. The

4

finance team prepares monthly reporting for the Transmission business unit

5

that includes reviews of the current month actual versus budget, year-to-date

6

actual versus budget, and year-end forecast versus target. This reporting is

7

reviewed on a monthly basis with the Transmission leadership team, where

8

concerns or issues are also discussed.

9

10 Q. HOW DOES THE TRANSMISSION BUSINESS UNIT O&M BUDGET PROCESS AND

11

GOVERNANCE COMPARE TO INDUSTRY PRACTICE?

12 A. The process the Transmission business unit uses in the development of the

13

O&M budget is consistent with the practices used in the other business units

14

across the Company. As discussed above, the budget development is

15

accomplished through a bottom-up approach where each budget manager

16

develops their budget based on identified work plans and efficiency gains for

17

the budget year and prioritized based on the most critical activities to ensure the

18

Company targets are met. During the year, governance is accomplished

19

through the monthly reporting and monitoring of performance as well as formal

20

tracking of changes to the year-end targets by director within an operating

21

company, as discussed above. Any changes to the year-end targets within the

22

Transmission business unit are approved by the Senior Vice President of

23

Transmission. Any changes to the overall Transmission business unit targets is

24

brought forward to the Company for consideration. Further discussion of the

25

overall Company budget process and governance is discussed in the Direct

26

Testimony of Ms. Ostrom.

27

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C. O&M Budget Detail

2

1. Internal Labor

3 Q. WHAT INTERNAL LABOR COSTS ARE INCLUDED IN THE TRANSMISSION BUSINESS

4

UNIT O&M BUDGET?

5 A. This category represents the O&M portion of salaries, straight time labor,

6

overtime, and premium time for internal employees. An attrition factor of four

7

percent is also applied, which reduces labor costs to account for retirements,

8

hiring delays, and other employee transfers. These amounts include costs for

9

both NSPM employees and the appropriate allocation of Xcel Energy Services

10

employees. For capital construction-focused positions, the vast majority of the

11

labor costs are allocated to capital; however, some labor costs are charged to

12

O&M activities like employee meetings, training, and administrative functions.

13

14 Q. WHAT CHANGES IN INTERNAL LABOR COSTS DO YOU ANTICIPATE FOR 2021 TO

15

2023?

16 A. We are expecting an average annual increase of two percent in internal labor

17

costs from 2021 to 2023.

18

19 Q. WHAT ARE THE MAJOR DRIVERS BEHIND THE INCREASE IN INTERNAL LABOR

20

COSTS FROM 2021 TO 2023?

21 A. The increase in internal labor costs from 2021 to 2023 budgets is primarily due

22

to annual base pay increases for both bargaining and non-bargaining employees.

23

These annual base pay increases and the historical trends for base pay increases

24

are discussed more fully in the Direct Testimony of Ms. Lowenthal.

25

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1 Q. PLEASE DISCUSS EFFORTS TO MINIMIZE INCREASES IN INTERNAL LABOR COSTS.

2 A. The Transmission business unit closely monitors our overall headcount

3

numbers, ensuring that any increases in headcount above the budgeted levels

4

are prudent and fully reviewed. In addition, we closely monitor the amount of

5

time spent on capital activities on a monthly basis as part of the overall monthly

6

reporting to manage the amount of internal labor being charged to O&M.

7

8

2. Contract Labor and Consulting

9 Q. WHAT COSTS ARE INCLUDED IN THE TRANSMISSION O&M BUDGET FOR

10

CONTRACT LABOR AND CONSULTING?

11 A. This category represents our use of contract labor and consultants, which allows

12

the Company to increase and decrease its staffing levels as workloads require

13

rather than bringing on more full-time staff. Using contract labor also allows

14

use the ability to retain the services of experts, as needed, for specific tasks or

15

project efforts. We believe utilizing contractors and consultants in this way is

16

an efficient and cost-effective way to complete required work while ensuring

17

the cost for the resources is only incurred during time it is needed.

18

19 Q. WHAT CHANGES IN CONTRACT LABOR AND CONSULTING COSTS DO YOU

20

ANTICIPATE FOR 2021 TO 2023?

21 A. We are expecting an average decrease of three percent in contract labor and

22

consulting costs for 2021 to 2023, as compared to the average of the 2017 to

23

2019 actual costs.

24

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1 Q. WHAT ARE THE MAJOR DRIVERS BEHIND THIS DECREASE IN CONTRACT LABOR

2

AND CONSULTING COSTS?

3 A. The decrease in contract labor and consulting costs is driven by productivity

4

improvement initiatives, which have been implemented by the business. These

5

efforts have resulted in improved scheduling and field productivity, resulting in

6

more efficient and effective ways for transmission crews to spend their time,

7

thus reducing the need for contractor support and the outsourcing of certain

8

O&M activities.

9

10 Q. WHAT STEPS HAS TRANSMISSION TAKEN TO MINIMIZE CONTRACT LABOR COSTS?

11 A. While utilizing contractors and consultants can be a cost-effective method of

12

managing labor costs on projects with variable workloads, the Transmission

13

business unit continues to take steps to minimize the cost of contract labor and

14

consulting costs. This includes increasing the reliance on workload planning to

15

ensure the staffing levels, including both internal and external resources, are at

16

the minimum required levels. Furthermore, the Transmission business unit

17

utilizes strategic sourcing and the competitively bid Master Service Agreement

18

program to obtain qualified and cost-effective contract labor. The Master

19

Service Agreement program creates supply agreements with several preferred

20

vendors to obtain bulk discounts and better service.

21

22

3. Employee Expenses

23 Q. WHAT COSTS ARE INCLUDED IN THE O&M BUDGET FOR EMPLOYEE EXPENSES?

24 A. This category represents expenses incurred by employees when traveling to

25

remote locations to perform field work or traveling to required trainings,

26

personal communication device expenses, and necessary (non-capital) safety

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1

equipment. Travel expenses incurred include per diem, mileage, hotel and

2

airfare, travel meals, and other travel-related expenditures.

3

4 Q. WHAT CHANGES IN EMPLOYEE EXPENSE COSTS DO YOU ANTICIPATE FOR 2021

5

TO 2023?

6 A. We are expecting an average increase of 11 percent in employee expenses for

7

2021 to 2023, as compared to the average of the 2017 to 2019 actual costs. As

8

discussed above, Transmission is planning to utilize more internal labor versus

9

contract labor over the term of the multi-year rate plan. This increased use of

10

internal labor means that there will also be an increase in associated employee

11

expenses.

12

13

4. Fees

14 Q. WHAT FEES ARE INCLUDED IN THE TRANSMISSION BUSINESS UNIT BUDGET?

15 A. This category consists of fees we are required to pay to the NERC and MRO

16

for the operation of the transmission system. As a regulated utility, the

17

Company is required to pay fees for each of those organization's operating

18

costs. It also includes professional and utility association dues, as well as land

19

and railroad permits and license fees, and other similar fees necessary for the

20

operation of our business.

21

22 Q. WHAT ARE THE MAJOR DRIVERS BEHIND THE INCREASE IN FEES FROM 2021

23

THROUGH 2023?

24 A. The increase in the fees cost category for 2021 through 2023 is primarily

25

attributable to increases in regulatory fees. The Company forecasts its

26

regulatory fees based on guidance from the regulatory bodies. Guidance from

27

NERC and MRO suggested a per year increase of five percent for both

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1

organizations. Consistent with this guidance, the Company has budgeted an

2

average increase of 11 percent for 2021 to 2023 as compared to the 2017 to

3

2019 actuals.

4

5

5. Materials

6 Q. WHAT MATERIALS ARE INCLUDED IN THE TRANSMISSION BUSINESS UNIT

7

BUDGET?

8 A. This category consists primarily of consumables, hardware, and refurbished

9

materials used in substation maintenance and repair operations. Additionally,

10

tools, small equipment, and supporting supplies are included.

11

12 Q. WHAT CHANGES IN MATERIALS COSTS DO YOU ANTICIPATE FOR 2021 TO 2023

13

AS COMPARED TO 2019 ACTUALS?

14 A. We are expecting an average decrease of 23 percent in material costs for 2021

15

to 2023, as compared to the average of the 2017 to 2019 actual material costs.

16

17 Q. WHAT ARE THE MAJOR DRIVERS BEHIND THIS DECREASE IN MATERIAL COSTS?

18 A. This decrease in material costs is driven by policy reviews conducted by the

19

Company that resulted in, among other things, changes in how the Company

20

determined whether to repair versus replace certain assets. Specifically, this

21

resulted in more replacement of assets as opposed to repairs, that then led to

22

reductions in O&M expenditures for materials. In addition, the Transmission

23

business unit continues to take advantage of the Master Service Agreement

24

program, utilizing negotiated supply agreements with several preferred vendors

25

to obtain bulk discounts and better service. We are also continuing to look for

26

opportunities to optimize the sourcing for materials through efficiencies gained

27

within the supply chain organization.

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2

6. Miscellaneous

3 Q. WHAT COSTS ARE INCLUDED IN THE MISCELLANEOUS CATEGORY?

4 A. The miscellaneous category is primarily fleet costs. This category consists of

5

costs for the internal fleet assets as directed to O&M accounts on an hourly

6

basis by Transmission operations. This is an aggregate cost of all fleet

7

equipment charged to Transmission O&M, including cars, trucks, construction

8

equipment and trailers. In addition to fleet costs, the miscellaneous budget for

9

2021 to 2023 includes anticipated reductions in O&M as a result of productivity

10

enhancements expected to be implemented by the Company.

11

12 Q. WHAT CHANGES IN MISCELLANEOUS COSTS DO YOU ANTICIPATE FOR 2021 TO

13

2023 AS COMPARED TO 2019 ACTUALS?

14 A. We are expecting an average decrease of 21 percent in miscellaneous costs for

15

2021 to 2023, as compared to the 2017 to 2019 average. Efforts to reduce per

16

unit expense for transportation costs have resulted in decreased total fleet

17

expenditures. Additionally, improvements in vehicle utilization tracking have

18

resulted in fleet time and dollars being more accurately assigned to capital versus

19

O&M projects, resulting in reduced O&M spend. Lastly, certain anticipated

20

O&M reductions resulting from efficiency efforts initiated by the Company are

21

captured in the miscellaneous cost category for the 2021 to 2023 budget.

22

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1 V. THIRD-PARTY TRANSMISSION EXPENSES AND WHOLESALE

2

TRANSMISSION REVENUES

3

4

A. Overview of the Transmission System in Minnesota and the

5

Upper Midwest

6 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

7 A. In this section of my testimony, I discuss the Company's third-party

8

transmission revenues and expenses and the impact that pending FERC

9

proceedings have on those revenues and expenses.

10

11 Q. GENERALLY SPEAKING, WHAT ARE THIRD-PARTY TRANSMISSION EXPENSES?

12 A. While NSP Transmission System loads and transmission facilities are primarily

13

located within the NSP pricing zone, the NSP Companies serve loads in five

14

other MISO pricing zones and a small load outside MISO. The NSP

15

Companies also collect revenue for transmission facilities located in the GRE

16

pricing zone, and several other utilities collect revenue for transmission facilities

17

located in the NSP pricing zone.

18

19

As a result, the NSP Companies incur third-party transmission expenses to

20

serve their native load customers, either in other zones or under Joint Pricing

21

Zone (JPZ) arrangements developed to compensate other utilities for their

22

facilities in the NSP pricing zone consistent with the MISO Transmission

23

Owners Agreement. The NSP Companies also receive revenues for

24

transmission and ancillary services provided to other utilities with load in pricing

25

zones where NSP owns transmission assets or as otherwise provided under the

26

MISO Tariff.

27

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1 Q. WHAT IS THE RELATIONSHIP OF THIRD-PARTY TRANSMISSION EXPENSES AND

2

WHOLESALE TRANSMISSION REVENUES TO THE COMPANY'S COST OF SERVICE?

3 A. Third-party transmission expenses and wholesale transmission revenues can

4

either serve as a credit or debit to the Transmission business unit's O&M costs.

5

6 Q. PLEASE DESCRIBE THE HISTORICAL DEVELOPMENT OF THE TRANSMISSION

7

FACILITIES IN MINNESOTA AND THE UPPER MIDWEST.

8 A. Electric utilities in Minnesota serve retail service areas that are spread

9

throughout the state, sometimes non-contiguous to other parts of their retail

10

service areas. The Company serves the Twin Cities, several major cities

11

including St. Cloud, Mankato, and Winona, and about 400 other communities

12

in Minnesota, while other utilities serve areas between the Company's

13

territories. This is because electric utilities in Minnesota and the upper Midwest

14

(investor-owned, cooperatives, and municipal utilities) have worked together

15

for many years to develop a transmission network that will serve our respective

16

native load customers. As a result, electric utilities in Minnesota and the region

17

have highly interconnected transmission facilities that do not necessarily follow

18

the patchwork of retail service area boundaries. This cooperation benefits our

19

customers by providing the transmission infrastructure needed to serve our

20

loads at a lower cost than if the Company and neighboring utilities each

21

independently constructed facilities to reach their respective service area loads.

22

23 Q. HOW DOES THE HISTORY OF COOPERATION AFFECT THE COSTS TO MINNESOTA

24

CUSTOMERS?

25 A. As designed and implemented, the jointly developed multi-owner transmission

26

grid in Minnesota has resulted in less duplication of facilities and increased

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system efficiency. This has resulted in lower costs to customers throughout

2

Minnesota.

3

4

Today, access to that multi-owner transmission grid is available under the MISO

5

Tariff. Essentially, the Company receives revenue from other entities that use

6

our transmission system and incurs an expense for using the transmission

7

systems of other entities.

8

9

B. Third-Party Transmission Expenses and Revenues

10 Q. PLEASE EXPLAIN HOW THE WHOLESALE REVENUES AND THIRD-PARTY

11

EXPENSES ARE RECOVERED.

12 A. The MISO Tariff recovers the costs of transmission facilities through rates

13

established and billed by "pricing zones," which roughly match the boundaries

14

of the local balancing authority areas operated by individual MISO member

15

utilities. The local balancing authority areas closely resemble the control areas

16

from the pre-MISO operational days. Control areas were used to designate

17

transaction schedules and system dispatch responsibilities to specific utilities.

18

When the transmission owners first began interconnecting, control area

19

boundaries were established to roughly encompass a utility's transmission and

20

generation assets. The concept of control areas (now local balancing authority

21

areas) is still used for utility energy accounting purposes.

22

23

The concept of a pricing zone is that the "network loads" within the pricing

24

zone, including a utility's retail native load customers, will bear the Annual

25

Transmission Revenue Requirement (ATRR) associated with the transmission

26

facilities in the zone on a load ratio share basis. The ATRR is calculated using

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the transmission cost of service rate formula set forth in the MISO Tariff for

2

each transmission owner.

3

4 Q. HOW DOES THE BILLING WORK?

5 A. The Company is party to JPZ agreements for both the NSP pricing zone and

6

the GRE pricing zone. Under these agreements, the transmission owning

7

utilities are compensated for their facilities in the zone, and the load serving

8

utilities are billed for their loads in the zone. Since the NSP Companies are

9

both transmission owners and load serving entities in both pricing zones, the

10

NSP Transmission System (1) receives revenues for its facilities in the NSP and

11

GRE pricing zone and (2) incurs expenses for its loads in the NSP and GRE

12

pricing zones.

13

14

Furthermore, as a MISO transmission owner, the NSP Companies collect third-

15

party wholesale transmission service revenues for others' use of the NSP

16

Transmission System under both the MISO Tariff and other wholesale

17

transmission agreements. The NSP Transmission System also incurs

18

transmission and/or ancillary expenses for its loads in other MISO pricing

19

zones.

20

21 Q. PLEASE DESCRIBE THE TRANSMISSION THIRD-PARTY EXPENSES AND

22

WHOLESALE REVENUES FOR 2021 TO 2023.

23 A. The NSP Transmission System (NSPM and NSPW combined) is operated as

24

an integrated system and is treated as one under the relevant provisions of the

25

MISO Tariff. Using third-party transmission is necessary to serve NSP

26

Transmission System loads, including NSPM retail native loads in Minnesota,

27

and thus the costs should be included in rates. However, those costs are offset

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1

by various transmission service revenues, thereby reducing total costs to NSPM

2

customers in Minnesota. Table 13 summarizes the 2021 to 2023 budgets for

3

MISO third-party transmission revenues and expenses and administrative

4

charges for the total NSP Transmission System, compared to 2019 actual and

5

2020 forecast amounts.

6

7

Table 13

8

NSP System Third Party Transmission Expenses and Revenues ($000)

9

Description

10

Third Party Transmission Expenses

JPZ Payments (NSP and GRE Zones)

2019

2020

2021

2022

2023

Actual Forecast

Budget

Budget

Budget

$ 60,404 $ 48,985 $ 58,414 $ 60,066 $ 61,236

11

MISO Network Service, Point to Point, and Ancillary $ 17,732 $ 22,421 $ 23,639 $ 24,335 $ 24,695

Services

12

MISO Admin Charges (Sch 10)

$ 11,138 $ 10,802 $ 10,914 $ 11,601 $ 11,851

Other (Transmission Facilites/Other Native Load

$ 239 $

63 $

210 $

214 $

218

13

Deliveries, etc)

TOTAL Third Party Expenses

$ 89,513 $ 82,272 $ 93,176 $ 96,215 $ 98,001

14

2019

2020

2021

2022

2023

15

Wholesale Transmission Revenues

JPZ Revenues (NSP and GRE Zones)

Actual Forecast

Budget

Budget

Budget

$ 56,936 $ 48,047 $ 52,066 $ 55,598 $ 57,185

16

MISO Network Service

MISO Point to Point

$ 25,163 $ $ 7,923 $

30,291 $ 6,957 $

30,595 $ 6,353 $

28,755 $ 6,199 $

29,618 6,205

17

GFAs Self-Funded Network Upgrades

$ 418 $ $ -$

423 $ -$

423 $ 1,610 $

426 $ 4,710 $

427 4,710

18

Other (Ancillary Services/LBA Services, etc) TOTAL Third Party Revenues

$ 1,596 $ $ 92,036 $

1,766 $ 87,484 $

1,713 $ 92,760 $

1,731 $ 97,420 $

1,767 99,913

19

Net Expense (Revenue)

$ (2,523) $ (5,213) $

385 $ (1,236) $ (1,944)

20

21

22

Since NSPM and NSPW operate the NSP Transmission System as an integrated

23

system, the table above reflects NSP Transmission System revenues and

24

expenses. The third-party transmission expenses and revenues are described in

25

more detail later in my testimony and in Exhibit___(IRB-1), Schedules 4 and 5.

26

The 2021 budget shows net expense which serves to increase to the Company's

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overall retail cost of service. Likewise, the 2022 and 2023 budget shows net

2

revenues which serve to decrease the Company's overall retail cost of service.

3

4 Q. DO THE TRANSMISSION EXPENSES YOU DESCRIBE INCLUDE CHARGES UNDER

5

MISO SCHEDULES 26 AND 26A TO RECOVER THE COSTS OF INVESTMENTS BY

6

MISO MEMBERS RECOVERED THROUGH THE REGIONAL EXPANSION CRITERIA

7

AND BENEFITS (RECB) TARIFF MECHANISM?

8 A. No. Schedules 26 and 26A provide for cost recovery of certain transmission

9

projects. Schedule 26 recovers from MISO loads the costs of projects

10

determined to be eligible for partial regional cost recovery as a "reliability" or

11

"economic" project under the RECB mechanisms. Schedule 26A recovers

12

from MISO loads the costs of projects determined to be eligible for full regional

13

cost recovery as an MVP. The Company includes MISO Schedule 26 and 26A

14

charges, as well as an offset for Schedule 26 and 26A revenues, in the TCR

15

Rider.

16

17 Q. PLEASE DESCRIBE THE 2021, 2022, AND 2023 NSP TRANSMISSION SYSTEM

18

THIRD-PARTY TRANSMISSION EXPENSES.

19 A. There are several types of third-party costs, which are summarized in Exhibit

20

___(IRB-1), Schedule 4. These are NSP Transmission System transmission

21

costs necessary to serve NSP Transmission System loads, including NSP retail

22

native loads in Minnesota, pursuant to rate schedules accepted for filing by

23

FERC. My testimony provides the NSP Transmission System costs; Mr.

24

Halama's cost of service reflects the portion allocated to the Minnesota

25

jurisdiction.

26

· JPZ Costs ­ As I previously discussed, the NSP Transmission System

27

incurs costs for serving its native loads within the NSP Joint Pricing Zone

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and in the GRE Joint Pricing Zone. The Company, GRE, Southern

2

Minnesota Municipal Power Agency, Central Minnesota Municipal

3

Power Agency, Northwestern Wisconsin Electric Company, Minnesota

4

Municipal Power Agency, Missouri River Energy Services, East River

5

Electric Power Cooperative and Rochester Public Utilities (collectively

6

the "NSP Zone Transmission Owners") each own transmission facilities

7

and serve loads in the NSP pricing zone. The 2021 to 2023 expense is

8

for our use of the NSP Transmission Owners transmission facilities to

9

serve the NSP Transmission System loads in the NSP pricing zone. The

10

revenue reflects use of the NSP Transmission System facilities by other

11

utilities to serve their respective loads in the NSP zone. The NSP

12

Transmission System 2021, 2022, and 2023 net payment under the NSP-

13

JPZ arrangement is forecast to be $7.6 million, $5.7 million, and $5.3

14

million, respectively, based on the JPZ expense and JPZ revenue

15

summarized in Table 14 below.

16

17

Table 14

18

Joint Pricing Zone ­ NSP Zone

19

(Dollars in Millions)

20

Revenue Expense Net Payment

21

2021

$47.1

$54.7

$7.6

22

2022

$50.5

$56.2

$5.7

2023

$52.0

$57.3

$5.3

23

24

25

Similarly, the NSP Transmission System has both native load and transmission

26

facilities located in the GRE pricing zone, which is also a multi-utility zone. The

27

Company pays GRE a net payment consisting of expense and revenue

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components: the expense of using other parties' facilities to serve the

2

Company's native load, and the revenue paid by other parties for their use of

3

NSP's facilities in the GRE zone. The NSP Transmission System 2021, 2022,

4

and 2023 net receipt for the GRE JPZ is forecast to be $1.2 million, $1.3 million,

5

and $1.3 million, respectively, based on the JPZ expense and JPZ revenue

6

summarized in Table 15 below.

7

8

Table 15

9

Joint Pricing Zone - GRE Zone

10

(Dollars in Millions)

11

Revenue Expense Net Receipt

12

2021

$4.9

$3.7

$1.2

13

2022

$5.1

$3.8

$1.3

2023

$5.2

$3.9

$1.3

14

15

16

Thus, the combined 2021, 2022, and 2023 impact of both the NSP JPZ and

17

GRE JPZ is a net payment of $6.3 million, $4.5 million, and $4.0 million based

18

on total expense and revenue summarized in Table 16 below and in Exhibit

19

___(IRB-1), Schedule 6.

20

21

Table 16

22

Joint Pricing Zone - NSP and GRE Zones

23

(Dollars in Millions)

24

Revenue Expense Net Payment

25

2021

$52.1

$58.4

$6.3

26

2022

$55.6

$60.1

$4.5

2023

$57.2

$61.2

$4.0

27

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1

2

· Network Integration Transmission Service (NITS), Point to Point, and Ancillary

3

Service Costs ­ All NSP Transmission System native loads located within

4

MISO are required to pay either a JPZ charge, as described above, or to

5

purchase NITS under Schedule 9 of the MISO Tariff. Accordingly, the

6

NSP Companies incur such charges with respect to their native loads in

7

the Dairyland Power Cooperative, ITC Midwest, and Minnesota Power

8

pricing zones. The NSP Companies' load in the Otter Tail Power pricing

9

zone is treated as being in the NSP pricing zone for JPZ/NITS purposes.

10

In addition to the base transmission (JPZ/NITS) charge, each load is also

11

ascribed charges, as applicable, under the MISO Tariff for ancillary

12

services, such as Schedule 1 ­ Scheduling, System Control and Dispatch

13

Services, Schedule 2 ­ Reactive Supply and Voltage Control From

14

Generation or Other Sources Service, and Schedule 33 ­ Blackstart

15

Service. Finally, the Company serves a small native load in Berthold,

16

North Dakota, that is connected to the Southwest Power Pool (SPP)

17

system outside the MISO region. Under the MISO Tariff, the Company

18

is required to purchase point-to-point (PTP) transmission service and

19

associated ancillary services to export power supply resources from the

20

MISO region. The NSP Transmission System 2021, 2022, and 2023

21

payments to MISO for these services are forecasted to be $23.6 million,

22

$24.3 million, and $24.7 million, respectively.

23

· MISO Administrative Charges ­ MISO charges its transmission service

24

customers, such as the Company, its Schedule 10 administrative charges

25

to recover the costs of administering its Tariff and providing other

26

transmission functions. The 2021, 2022, and 2023 charges of $10.9

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million, $11.6 million, and $11.9 million, respectively, are based on

2

MISO's forecast of its Schedule 10 rates.

3

· Other Transmission Expense/Facility Charges. The NSP Companies incur

4

these costs to secure delivery rights for the integration of NSP

5

Transmission System loads. This cost consists of payments to Dairyland

6

Power Cooperative, Minnkota Power Cooperative, McLeod Cooperative

7

Power Association, Redwood Electric Cooperative, Southwest Power

8

Pool, and Stearns Electric Association for use of their respective facilities

9

to enable the Company to serve certain native loads. The NSP

10

Transmission System 2021, 2022, and 2023 payments to these entities are

11

forecast to be $178,000; $183,000; and $186,000, respectively.

12

13 Q. WHAT ARE THE 2021, 2022, AND 2023 WHOLESALE TRANSMISSION REVENUES?

14 A. As shown in Table 13, the total NSP Transmission System 2021 test year

15

wholesale revenues are estimated to be $92.7 million. The NSP Transmission

16

System wholesale revenues for the 2022 and 2023 plan years are estimated to be

17

$97.4 million and $99.9 million, respectively. Exhibit___(IRB-1), Schedule 5

18

provides more detailed information on the various transmission service

19

revenues by type of service for 2019 and 2021, 2022, and 2023. The revenues

20

from these wholesale services are reflected as revenue credits in the cost of

21

service supported by Mr. Halama, thereby offsetting some of the third-party

22

transmission expenses and reducing total costs to our Minnesota customers.

23

24 Q. HOW ARE THE WHOLESALE TRANSMISSION REVENUES KEPT ACCURATE AND

25

CURRENT?

26 A. The NSP Companies update their MISO Attachment O ATRR every year. This

27

update is required by the MISO Tariff and coordinated with MISO Tariff

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Administration staff to reflect current year projected costs and the true-up of

2

prior period costs and loads.

3

4

C. Pending FERC ROE Proceedings

5 Q. PLEASE EXPLAIN THE BACKGROUND OF THE PENDING FERC ROE

6

PROCEEDINGS IN FERC DOCKET NOS. EL14-12 AND EL15-45.

7 A. On November 12, 2013, a group of industrial customers in the MISO region

8

filed a complaint (FERC Docket No. EL14-12, or the "First Complaint") asking

9

FERC to reduce the base rate of ROE used in the transmission formula rates

10

of jurisdictional MISO transmission owners, including the NSP Companies,

11

from 12.38 percent to 9.15 percent. On September 28, 2016, FERC issued

12

Opinion 551, granting a 10.32 percent base rate ROE, effective November 12,

13

2013 to February 10, 2015 and prospectively from the date of the Order. Per

14

Opinion 551, refunds were issued during the first half of 2017; however,

15

multiple parties requested rehearing of Opinion 551, as discussed further below.

16

17

In February 2015, due to the impending expiration of the 15-month statutory

18

limit on refund periods for complaints under section 206 of the Federal Power

19

Act, a second Complaint (FERC Docket No. EL15-45, the "Second

20

Complaint", or, together with the First Complaint, the "MISO ROE

21

Complaints") was filed proposing to reduce the base ROE from 12.38 percent

22

to 8.67 percent. The Second Complaint created a period of potential refunds

23

from February 12, 2015 to May 11, 2016. In June 2016, based on the Opinion

24

531 methodology, an ALJ recommended a base ROE of 9.70 percent ("Second

25

Complaint Initial Decision").8 However, multiple parties filed exceptions to

8 155 FERC ¶ 63,030 (2016).

116

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1

the Second Complaint Initial Decision, and the complaint continues to be

2

subject to ongoing litigation, as discussed further below.

3

4

On April 14, 2017, the United States Court of Appeals, D.C. Circuit (D.C.

5

Circuit Court) vacated and remanded Opinion 531, finding that FERC had not

6

properly established that the existing ROE was unjust and unreasonable and

7

also failed to adequately support the newly approved base ROE.9 As Opinion

8

551 and the Second Complaint Initial Decision both cited Opinion 531 as the

9

basis for the respective decisions, Opinion 531's vacatur also invalidated those

10

decisions.

11

12

On November 21, 2019, FERC issued Opinion 569, an order on rehearing of

13

Opinion 551 and FERC's initial order on the Second Complaint. Opinion 569

14

adopted a new ROE methodology and set a new base ROE of 9.88 percent,

15

effective for the 15-month refund period from November 12, 2013, to February

16

11, 2015, and prospectively from September 28, 2016. Opinion 569 also

17

dismissed the Second Complaint on the basis that the "existing rate" to be

18

evaluated in that complaint was the 9.88 percent base ROE ordered in the First

19

Complaint, which continued to be just and reasonable through the Second

20

Complaint period. This dismissal drew a strongly-worded dissent from

21

Commissioner Richard Glick, who, like the Complainant-Aligned Parties

22

(CAPs), contended FERC should evaluate the Second Complaint not against

23

the outcome of the First Complaint, but against the 12.38 percent base ROE

24

inherent in rates paid by customers during the Second Complaint's refund

25

period. Various parties requested rehearing of Opinion 569 on multiple

26

grounds, including which models should be used to evaluate and set a new base

9 Emera Maine, 854 F.3d at 22-23.

117

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1

ROE, how the models should be applied, FERC's use of judgment, and the

2

dismissal of the Second Complaint.

3

4

On May 21, 2020, FERC issued Opinion 569-A, which granted rehearing in part

5

of Opinion 569, adopting a new ROE methodology which includes the risk

6

premium model in addition to the DCF and CAPM, and established yet another

7

new base ROE of 10.02 percent, effective for the First Complaint refund period

8

(November 12, 2013 to February 11, 2015), and prospectively beginning

9

September 28, 2016. The MISO TOs did not request rehearing but did appeal

10

the decision to the D.C. Circuit Court, as discussed below.

11

12

On June 30, 2020, the D.C. Circuit Court issued an opinion in an unrelated case,

13

Allegheny Defense Project v. FERC, finding FERC's practice of issuing "tolling

14

orders," which previously had the effect of allowing FERC unlimited time to

15

act on requests for rehearing, to be unlawful, and requiring FERC to act on

16

requests for rehearing within 30 days.10 On July 22, 2020, in response to the

17

Allegheny decision, FERC issued an order denying the requests for rehearing as

18

a matter of law, though FERC also indicated its intention to set aside its

19

previous decision and issue a new order on rehearing at a future date.

20

21

Between June 1, 2020, and July 20, 2020, seven different groups, including the

22

MISO TOs, filed petitions for review of Opinions 551, 569, and 569-A with the

23

D.C. Circuit Court. On August 5, 2020, FERC filed a motion to hold the

24

appeals in abeyance pending FERC's intended action on rehearing. Although

25

it is uncertain what path this litigation will follow as it continues on rehearing at

10 Allegheny Defense Project v. Federal Energy Regulatory Commission, 964 F.3d 1, 18-19 (D.C. Cir. 2020).

118

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1

FERC and through the appeals process in the courts, the one thing that seems

2

certain is that it is far from over.

3

4 Q. WHAT IS THE NSP COMPANIES' MOST RECENT FERC-APPROVED ROE AT THIS

5

TIME?

6 A. The most recent FERC order establishing a new base ROE for the NSP

7

Companies is FERC Opinion 569-A, which set the base ROE at 10.02 percent.

8

Although that Order remains subject to change from ongoing litigation, billed

9

rates are currently based on that order and use a total ROE of 10.52 percent

10

(10.02 percent base ROE, plus a 50 basis point incentive adder for RTO

11

participation).

12

13 Q. DOES THE COMPANY HAVE CERTAINTY AT THIS POINT AS TO THE FINAL MISO

14

ROE THAT WILL BE ADOPTED BY FERC?

15 A. Not at this time. As evidenced by the multiple requests for rehearing at FERC

16

and appeals at the D.C. Circuit Court that are currently pending, there is still

17

quite a bit of uncertainty as to the final ROE that will be adopted.

18

19 Q. WHAT HAS BEEN THE IMPACT OF THE MISO ROE COMPLAINTS ON NSPM'S

20

FINANCIAL RESULTS FOR ITS MINNESOTA ELECTRIC JURISDICTION?

21 A. In previous Minnesota rate cases, the transmission revenue credit, which

22

represents the pass-through to retail customers of revenues received for

23

providing transmission service to other utilities, resulting in a reduction to the

24

cost of service, has been calculated using the previously-effective MISO ROE

25

of 12.38 percent. The Company has issued initial refunds for Opinion 569 for

26

the time period from November 2013 through February 2015 and November

27

2019 through June 2020. As a result, the transmission revenues actually earned

119

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1

have fallen short of the level credited to Minnesota retail customers, causing

2

financial loss to the Company that I discuss in more detail below.

3

4 Q. IS THERE A TRUE-UP MECHANISM TO PROTECT THE COMPANY AND RETAIL

5

CUSTOMERS FROM THE FINANCIAL IMPACTS RESULTING FROM CHANGES TO THE

6

MISO ROE DUE TO THE MULTIPLE PENDING FERC PROCEEDINGS?

7 A. No, at least not for transmission revenues credited to customers through base

8

rates. Certain types of transmission revenue are credited to customers through

9

the TCR Rider, which includes a true-up to ensure customers are credited with

10

the actual amount, no more and no less, of the revenues received. However,

11

for items included in base rates, there has been no true-up mechanism in place.

12

13 Q. CAN YOU QUANTIFY THE AMOUNT OF LOSSES EXPERIENCED BY THE COMPANY

14

AS A RESULT OF THE DIFFERENCE BETWEEN THE ULTIMATE FERC ROE AND

15

THE ROE USED TO CALCULATE THE MINNESOTA REVENUE CREDIT?

16 A. As I discussed previously, the ultimate outcome of the MISO ROE Complaints,

17

including refunds for the time period since November 2013, is uncertain at this

18

time. However, Table 17 below estimates the difference, on a Minnesota

19

jurisdictional basis, between the level of the Company's transmission revenues

20

included as a revenue credit in its previous rate cases, based on the 12.38 percent

21

previously-effective base ROE and what that revenue credit would have been

22

had the 10.02 percent base ROE from Opinion 569-A been known at the time

23

those cases were filed.11

24

11 An incentive adder of 50 basis points for RTO participation is applicable to periods on or after January 6, 2016; thus, for those periods, the 12.38 percent previous ROE is compared against a new ROE of 10.52 percent.

120

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1

Table 17

2

Estimated Impact of ROE on Transmission Revenues

3

(State of MN Electric Jurisdiction)

4

12.38% vs.

5

Year

10.02% base ROE

($000s)

6

2013

$323

7

2014

$5,210

2015

$4,547

8

2016

$2,998

9

2017

$4,738

2018

$4,064

10

2019

$4,218

11

2020

$4,267

Total

$30,365

12

13

14

Thus, the Minnesota jurisdiction has received excess revenue credits of

15

approximately $30.4 million from 2013 to 2020.

16

17 Q. WHAT DOES THE COMPANY RECOMMEND WITH RESPECT TO THE TRANSMISSION

18

REVENUE CREDIT IN THIS CASE?

19 A. As discussed by Mr. Halama, the Company believes a determination at FERC

20

on this matter should not impact the retail jurisdiction, and the cost of capital

21

should be treated consistently across our rate base. Therefore, the transmission

22

revenue credit has been calculated using the Company's most recently approved

23

ROE of 9.06 percent as approved by the Commission in the Company's latest

24

TCR Rider proceeding.12 The Company further proposes to make an

12 In the Matter of the Petition of Northern States Power Company for Approval of the Transmission Cost Recovery Rider Revenue Requirements for 2017 and 2018, and Revised Adjustment Factor, Docket No. E002/M-17-797, ORDER AUTHORIZING RIDER RECOVERY, SETTING RETURN ON EQUITY, AND SETTING FILING REQUIREMENTS (Sept. 27, 2019).

121

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1

adjustment as part of its compliance filings to reflect the final authorized ROE

2

in this case.

3

4 Q. WHAT IS THE IMPACT OF A LOWER FERC AUTHORIZED ROE?

5 A. For the 2021 test year, a 10 basis point (0.1 percentage point) reduction in the

6

FERC authorized ROE is estimated to result in a reduction in wholesale

7

transmission revenues, net of third-party transmission expenses, of

8

approximately $0.4 million. This amount excludes revenues and expenses under

9

MISO Schedules 26 and 26A, which are excluded from base rates and instead

10

included in the TCR Rider.

11

12

VI. TRANSMISSION SYSTEM LINE LOSS ANALYSIS

13

14 Q. WHAT IS THE PURPOSE OF THIS SECTION OF YOUR TESTIMONY?

15 A. In its June 12, 2017 Order in our 2015 electric rate case, the Commission

16

determined that the consideration of line losses--the amount of energy that is

17

lost through the process of transmission and distribution--may further enhance

18

the accuracy of the Class Cost of Service Study.13 As a result, the Commission

19

directed the Company in its next rate case to report on methods to conduct loss

20

studies to measure line losses. The two general categories of losses on the Xcel

21

Energy system are transmission losses and distribution losses. I will discuss the

22

methods for measuring transmission losses, while Company witness Ms. Kelly

23

A. Bloch discusses the methods for measuring distribution losses in her Direct

24

Testimony.

25

13 In the Matter of the Application of Northern States Power Company for Authority to Increase Rates for Electric Service in the State of Minnesota, Docket No. E002/GR-15-826, FINDINGS OF FACT, CONCLUSIONS, AND ORDER, at 49 (June 12, 2017).

122

Docket No. E002/GR-20-723

Benson Direct

1 Q. WHAT ARE ELECTRIC LOSSES?

2 A. The Edison Electric Institute (EEI) defines electric losses as the general term

3

applied to energy (kilowatt-hours) and power (kilowatts) lost in the operation

4

of an electric system. Losses occur when energy is converted into waste heat in

5

conductors and apparatus. Demand loss is power loss and is the normal

6

quantity that is conveniently calculated because of the availability of equations

7

and data. Demand loss is coincident when occurring at the time of system peak,

8

and non-coincident when occurring at the time of equipment or subsystem

9

peak. Class peak demand occurs at the time when that class's total peak is

10

reached.

11

12 Q. HOW DOES THE COMPANY CALCULATE LOSSES ON THE TRANSMISSION SYSTEM?

13 A. The Company uses NSP hourly State Estimator data to calculate both the

14

demand and energy losses on the NSP Transmission System.

15

16 Q. WHAT IS THE STATE ESTIMATOR?

17 A. The State Estimator is basically an on-line power flow program that creates a

18

complete complex voltage solution for the network model. The State Estimator

19

solution is based on real-time measurements, scheduled load and generation,

20

and dispatcher/operator entries. The State Estimator is performed several

21

times per hour and provides a continuous snapshot of the transmission

22

network.

23 Q. HOW DOES THE STATE ESTIMATOR OBTAIN THE REAL-TIME MEASUREMENTS

24

FROM THE TRANSMISSION SYSTEM?

25 A. The State Estimator uses real-time data from the Company's Energy

26

Management System (EMS). The EMS is an integrated set of computer

27

hardware, software, and computer programs which aid Company transmission

123

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1

system operators in viewing, monitoring, and operating the transmission

2

system. EMS receives real-time measurements from the field through telemetry.

3

These real-time measurements are imperfect but redundant. This redundancy

4

permits the State Estimator to determine an estimate for the voltage magnitude

5

and angles for the observable portion of the network model which best matches

6

the information given by the unfiltered measurements.

7

8 Q. ARE REAL-TIME MEASUREMENTS AVAILABLE FOR ALL OF PORTIONS OF THE

9

TRANSMISSION SYSTEM?

10 A. No. Portions of the network that are not observable with real-time

11

measurements. For those portions of the system, the State Estimator uses data

12

from key nodal points on the system from which we have telemetry data from

13

to determine the overall system status. That system status which includes load

14

and generation values along with voltages and amperage, also reflects the overall

15

losses on the system.

16

17 Q. HOW DOES THE STATE ESTIMATOR UTILIZE ALL OF THIS NETWORK DATA?

18 A. The State Estimator utilizes all of the collected data to create a real-time

19

snapshot of the transmission network. This solved real-time network snapshot

20

can be used for several applications including calculating transmission system

21

losses.

22

23 Q. HOW CAN THIS REAL-TIME NETWORK BE USED TO CALCULATE TRANSMISSION

24

SYSTEM LOSSES?

25 A. The State Estimator has the ability to provide over 8,000 states of data for

26

calculating losses. The demand losses are the losses that occur on the NSP

124

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1

Transmission System during the monthly peak hourly load. Energy losses will

2

be the summation of all hourly losses in each month.

3

4

To calculate the required percentages, these losses will then be divided by NSP's

5

local balancing authority (LBA) load. In the case of demand losses, the load

6

will be the peak hour load while the energy loss will be the summation of MWh

7

loads in the given month.

8

9

Not all the loads in NSP's LBA are NSP's native load. Loads from GRE and

10

Dairyland Power Cooperative are within NSP's LBA. GRE is an electric

11

cooperative based in Minnesota while Dairyland Power Cooperative is an

12

electric cooperative based in Wisconsin. These loads also create losses on the

13

transmission system and need to be added to NSP's load to obtain the correct

14

loss percentages.

15

16 Q. WHAT ARE THE LIMITATIONS OF USING THE STATE ESTIMATOR CALCULATIONS

17

OF TRANSMISSION SYSTEM LOSSES?

18 A. At the end of the day, any transmission system losses calculated by the State

19

Estimator is an estimate based on collected data and may not necessarily reflect

20

actual line losses at any given point in time. This is because the loss calculations

21

created by the State Estimator rely on estimates for the portions of the system

22

where we do not have real-time telemetry and are averaged into hourly time

23

intervals.

24

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1

VII. CONCLUSION

2

3 Q. PLEASE SUMMARIZE YOUR TESTIMONY.

4 A. The Transmission organization constructs and maintains the transmission

5

components for the NSP Transmission System that are necessary to enable the

6

safe, reliable, and efficient delivery of energy from generating resources to

7

customers. We anticipate completing $354.0 million of capital additions in

8

2021, $340.0 million in 2022, and $316.7 million in 2023. These capital additions

9

include transmission projects for which we will seek rate recovery through the

10

TCR Rider. These capital projects are needed to maintain the health of

11

transmission facilities, meet reliability requirements, add capacity to support

12

increasing amounts of new generation, interconnect new generators, and enable

13

communication between our facilities.

14

15

We have budgeted $38.2 million for Transmission O&M in 2021, $38.7 million

16

in 2022, and $40.4 million in 2023. The three-year average for these years ($39.1

17

million) is below the most recent three-year historical average (2017 to 2019) of

18

$39.20 million.

19

20

These capital and O&M budgets are a reasonable representation of the work

21

that Transmission will complete during the term of this MYRP and I

22

recommend that the Commission approve Transmission's capital and O&M

23

budget as presented in this rate case.

24

25 Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?

26 A. Yes, it does.

126

Docket No. E002/GR-20-723

Benson Direct

Northern States Power Company

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 1
Page 1 of 1

Statement of Qualifications Ian R. Benson

Current Responsibilities My responsibilities include: supervising engineers in planning the electric transmission systems for the four Xcel Energy Inc. operating companies, NSPM, Northern States Power Company, a Wisconsin corporation (together the NSP Companies), Public Service Company of Colorado (PSCo), and Southwestern Public Service Company (SPS); overseeing the development of local and regional transmission system plans, including coordinated joint planning with the Midcontinent Independent Transmission System Operator, Inc. (MISO), and other utilities to ensure reliable transmission service; recommending the construction of such plans to Xcel Energy Inc. management and MISO; participating in and supporting MISO sponsored transmission service studies, generation interconnection studies, long range regional plan development, load service planning and other transmission planning activities required by MISO to perform its obligations under the MISO Tariff and the MISO Transmission Owner's Agreement; and providing technical support for regulatory aspects of transmission system planning activities and contract development for the NSP Companies, PSCo, and SPS.

Education: Bachelor of Geological Engineering - 1984 University of Minnesota

Bachelor of Science, Mathematics ­ 1991 University of Minnesota

Master of Business Administration ­ 2010 University of St Thomas

Previous Employment (1991 to 2010): Senior Engineer - Northern States Power Company (1991 ­ 1994) Lead Sales Representative - Northern States Power Company (1994 ­ 1998) Mid-Term Marketing Representative - Northern States Power Company (1998 ­ 1999) Manager, Mid-Term Markets - Northern States Power Company (1999 ­ 2000) Director, Origination - Xcel Energy Services Inc. (XES) (2000 ­ 2004) Director, Transmission Access - XES (2004 ­ 2009) Director, Transmission Investment Development - XES (2009 ­ 2010) Director, Transmission Business Relations and Asset Management - XES (2010 ­ 2013) Director, Transmission Planning and Business Relations - XES (2013 ­ 2016) Area Vice President, Transmission Strategy and Planning ­ XES (2016 ­ present)

U.S. Navy Active Duty: 1984 to 1989 Naval Reserve: 1989 to 2006

Northern States Power Company
Transmission's Capital Additions: 2021-2023
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPM Additions Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal

Project Name
Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment S&E - Line S&E - Line S&E - Line S&E - Line ELR Nuclear NSPM Line ELR Line ELR Line ELR ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay

WBS Level 2 #

Description

A.0000351.004 A.0000351.022 A.0000351.026 A.0000351.030 A.0000351.033 A.0000351.034 A.0000351.035 A.0000351.036 A.0000351.037 A.0000351.038 A.0000351.039 A.0000351.040 A.0000498.004 A.0000498.022 A.0000498.024 A.0000498.025 A.0000498.028 A.0000498.031 A.0000498.037 A.0000498.038 A.0000498.039 A.0000498.040 A.0000498.041 A.0000498.046 A.0000498.048 A.0000498.049 A.0000177.043 A.0000177.050 A.0000177.055 A.0000177.056 A.0001014.001 A.0000504.025 A.0000504.039 A.0000504.043 A.0000395.016 A.0000395.029 A.0000395.061 A.0000395.062 A.0000395.064 A.0000395.065 A.0000395.066 A.0000395.067 A.0000395.068 A.0000395.069 A.0000395.071 A.0000395.072 A.0000395.073 A.0000395.074 A.0000395.075 A.0000395.076 A.0000395.077

NSPM Major Line Rebuild,Line NSM0808 AIR RLK Rebuild Line NSM0730 - West Sioux Falls - Line 729 NSM0752 Belgrade - Paynesville Rebuild NSPM 0795 Avon - Albany NSM0730 SOS - WSF Rebuild NSM0779 - Canisota Juntion - Salem,Line NSM0794 BLD DGC Rebuild NSM0703 FRM PKN Rebuild NSM0703 FRM NOF Rebuild NSM5401 MLK WAK Rebuild NSM0752 Belgrade - Paynesville PH2 NSPM Major Line Refurbishment NSPM0815 BDS -WIL 115kV Refurb NSM0752 Brooten Paynesville Refurb Line NSM0734 West gate Excelsor Line NSPM0857 BDS -NMC 115kV Refurb NSM0746 Prairie Minnkota Refurb NSM0735 CAR STB Refurb NSM0735 CAR YAM Refurb NSM0735 DLO STB Refurb NSM0701 CRO to GFD Refurb NSM5400 ALB-PAT-WAK Refurb NSM0761 LAK ZUM Refurb NSM0772 Prairie IC-Emerado Refurb 786 - Minnkota - Larimore, Line NSPM S&E 69kV, Line ND S&E B 69kV, Line SD S&E B 69kV, Line NSPM Priority Defects 69kV Line NSPM - ELR - Nuclear NSPM T-Line ELR 2016 69kV, Line ND 69kV T-line ELR, Line SD 69kV T-line ELR, Line NSPM - 2016 - ELR - Relays NSPM - 2018 - ELR - Relays Airport Relaying - RLK Black Dog Relaying-BLL,BRV,CDV Elliot Park Relaying-MST,RIV Fifth St Relaying - RIV Ft Ridgely Relaying - WLM Koch Relaying - JNC Lincoln Co Relaying - CHC,CEN Main St Relaying - ELP,RIV Moore Lake Relaying - RIV Osseo Relaying - Bus1 TT Paynesville Relaying - WAK Prairie Relaying - NOR1,NOR2 Riverside Relaying - MOL,TWL Riverside Relaying-ELP,FST,MST Rogers Lake Relaying-AIR

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 1 of 8

Addition Amount ($000s)

2021

2022

2023

NSPM (Total State of MN NSPM (Total State of MN NSPM (Total State of MN

Company) Elec. JUR Company) Elec. JUR Company) Elec. JUR

In-Service Date

0 4,208
0 5,162
0 0 1,866 0 0 0 0 0 0 2,666 1,599 3,135 2,689 482 0 0 0 0 0 0 475 793 7,512 100 100 1,001 3,561 3,417 100 100 0 182 269 0 699 354 0 0 539 800 0 0 0 0 0 1,028 256

0 0 0 0 0 0 0 0 0 0 0 0 0 1,944 1,166 2,286 1,961 351 0 0 0 0 0 0 346 578 5,478 73 73 730 2,597 2,492 73 73 0 132 196 0 510 258 0 0 393 583 0 0 0 0 0 749 187

0 0 1,427 0 5,352 1,399 0 2,780 884 2,957 3,826 2,624 3,261 0 0 0 0 0 180 155 530 3,624 3,452 1,659 0 0 7,209 100 100 1,001 7,277 3,519 100 100 0 0 0 0 0 0 0 0 0 0 357 0 0 0 701 0 0

0 0 1,041 0 3,902 1,020 0 2,027 645 2,156 2,790 1,913 2,378 0 0 0 0 0 131 113 387 2,643 2,517 1,210 0 0 5,257 73 73 730 5,307 2,566 73 73 0 0 0 0 0 0 0 0 0 0 260 0 0 0 511 0 0

63,858 0 0 0 0 0 0 0 0 0 0 0
9,848 0 0 0 0 0 0 0 0 0 0 0 0 0
7,209 100 100
1,001 9,321 4,320
100 100 1,478
0 0 765 0 0 353 352 0 0 0 20 20 820 0 0 0

46,567 0 0 0 0 0 0 0 0 0 0 0
7,181 0 0 0 0 0 0 0 0 0 0 0 0 0
5,257 73 73 730
6,797 3,150
73 73 1,078
0 0 558 0 0 257 256 0 0 0 14 14 598 0 0 0

12/31/2025 12/15/2021 12/15/2022 3/31/2021
1/15/2022 12/15/2022 12/15/2021 12/15/2022 12/15/2022 12/15/2022 12/15/2022 12/15/2022 12/31/2025
6/30/2021 6/15/2021 12/15/2021 6/30/2021 6/15/2021 12/15/2022 12/15/2022 12/15/2022 12/15/2022 12/15/2022 3/15/2022 12/15/2021 12/15/2021 12/31/2025 12/31/2025 12/15/2025 12/30/2025 12/30/2024 12/15/2025 12/31/2025 12/31/2025 12/31/2025 11/15/2021 5/31/2021 5/15/2023 12/15/2021 12/15/2021 12/15/2023 12/31/2023 12/15/2021 12/15/2021 12/15/2022 12/15/2023 11/15/2023 12/15/2023 12/15/2022 12/15/2021 2/15/2021

Northern States Power Company
Transmission's Capital Additions: 2021-2023
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPM Additions Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal

Project Name
ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers W St Cloud - Black Oak 0953 Replace OPGW ELR - Transformers Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements Transmission UAV Flights Tools Line Field Ops Tools Line Field Ops Tools Line Field Ops Tools Line Field Ops Tools Line Field Ops S&E - Sub S&E - Sub S&E - Sub NSP Reloc B NSP Reloc B NSP Reloc B NSPM Metro Steel pole Rplmnt

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 2 of 8

WBS Level 2 #

Description

A.0000395.080 A.0000395.081 A.0000395.082 A.0000395.083 A.0000395.084 A.0000395.090 A.0000395.096 A.0000394.009 A.0000394.016 A.0000394.026 A.0000394.027 A.0000394.028 A.0000394.029 A.0000394.030 A.0000394.031 A.0000394.032 A.0000394.033 A.0000394.034 A.0000394.035 A.0000394.036 A.0000394.037 A.0000351.013 A.0001299.002 A.0000506.002 A.0000705.006 A.0000705.019 A.0000705.020 A.0000705.021 A.0000705.022 A.0000705.031 A.0000705.035 A.0000705.037 A.0000705.041 A.0000705.048 A.0000705.056 A.0000705.059 A.0000705.060 A.0000705.062 A.0000855.001 A.0006059.085 A.0006059.445 A.0006059.452 A.0006059.453 A.0006059.496 A.0000585.008 A.0000585.009 A.0000585.013 A.0000276.026 A.0000276.035 A.0000276.056 A.0000743.004

Tanners Lake Relaying - WDY Twin Lakes Relaying - RIV Wakefield Relaying - PAT West Coon Rapids Relaying-ECK Wilmarth Relaying - FTR Cedarvale Replace Relaying to BDS Red Rock Relaying NSPM ELR Breakers Souris - Repalce Breaker 5T70 Fifth St-Replace Bkrs 5M760,5M765,5M770 Hugo-Replace Bkrs 5P196 & 5P197 Inver Grove-Replace 4P8,4P9,4P10 Minnesota Valley-Replace 69 kV & 115 kV Prairie-Replace Bkrs 4G8 & 4G9 Arlington-Replace Bkrs 4S191,4S192,4S199 Rogers Lake-Replace Bkr 5P69 Rose Place-Replace Bkr 5P50 Wakefield-Replace Bkr 5N28 Winthrop-Replace Brk 4S54 Wilmarth-Replace Bkr 5S19 Westgate-Replace Bkrs 4M3 & 4M5 NSM0795 West St Cloud Millwood Tap NSM0953 NOB SPK REPL OPGW MN NSPM ELR Transformers NSPM Switch Replacements, Line NSM0737 Gleason Lake 4M58 NSM0782 Gleason Lake 4M17 NSM0721 Fairfax Muni Tap 450, 453 NSM0755 Bush Park Muni 4N41, 4N42, & 4N4 NSM0789 Wells Ck 4H21, 4H22, 4H23, Line NSM0733 Reynolds Rpl SW 130 131 0733 Thonpson Rpl SW 120 121 NSPM GRE Switch Replacements 69kV, Line NSM0719 Sleepy Eye City switch #290,291& NSM0793 Villard 4N33 4N34 NSM0760 Frontenac SW 541 & 542 NSM0752 Brooten SW 686 687 Line Averill Tap SW NSPM Transmission UAV Tools MN Sub Tool Blanket MN, Line Survey Group Tool B Line Civil Dept Tool B Line EPZ Mats MN ND S&E, Sub NSPM S&E, Sub SD S&E, Sub NSPM Reloc B 69kV, Line ND Reloc B 69kV Line SD Reloc B 69kV, Line NSPM Triple Ckt Pole Repl 2016

Addition Amount ($000s)

2021

2022

2023

NSPM (Total State of MN NSPM (Total State of MN NSPM (Total State of MN

Company) Elec. JUR Company) Elec. JUR Company) Elec. JUR

In-Service Date

395 0 0 0 0 0
328 0 0
1,307 0 0 0 0
985 558 539
0 1,636
0 0 0 0 301 0 0 0 0 0 0 380 388 98 0 0 570 920 20 6,210 300 147 60 300 50 64 1,472 64 1,477 50 50 347

288 0 0 0 0 0
239 0 0
953 0 0 0 0
719 407 393
0 1,193
0 0 0 0 219 0 0 0 0 0 0 277 283 72 0 0 416 671 15 4,529 219 107 44 219 36 47 1,073 47 1,077 37 37 253

0 326
0 0 0 355 0 0 346 0 871 875 0 0 0 0 0 0 0 0 0 0 9,073 5,756 491 0 0 452 417 439 0 0 98 347 0 0 0 0 0 300 154 50 2,000 250 64 1,472 64 1,477 50 50 2,367

0 238
0 0 0 259 0 0 252 0 635 638 0 0 0 0 0 0 0 0 0 0 6,616 4,197 358 0 0 330 304 320 0 0 72 253 0 0 0 0 0 219 113 36 1,458 182 47 1,073 47 1,077 37 37 1,726

0 0 20 20 536 0 0 1,478 0 0 0 0 881 631 0 0 0 20 0 411 20 10,447 0 3,004 1,576 228 228 0 0 0 0 0 98 0 355 0 0 0 0 300 162 50 2,000 50 64 1,472 64 1,477 50 50 1,970

0 0 14 14 391 0 0 1,078 0 0 0 0 643 460 0 0 0 14 0 300 14 7,618 0 2,191 1,149 167 167 0 0 0 0 0 72 0 259 0 0 0 0 219 118 36 1,458 36 47 1,073 47 1,077 37 37 1,436

12/15/2021 12/15/2022 11/30/2023 11/30/2023 12/15/2023 12/15/2022
5/15/2021 12/31/2025 10/31/2022 12/15/2021 12/15/2022 12/15/2022 12/15/2023 12/15/2023 4/15/2021 4/30/2021 4/10/2021 12/15/2023 5/30/2021 12/15/2023 12/15/2023 12/15/2023 7/15/2022 12/15/2025 12/31/2025 12/15/2023 12/15/2023 12/15/2022 12/15/2022 12/15/2022 5/14/2021 6/14/2021 12/15/2025 12/15/2022 12/15/2023
6/1/2021 6/1/2021 4/15/2021 10/30/2021 12/31/2025 12/31/2025 12/31/2025 10/30/2025 12/31/2025 12/31/2024 12/31/2025 12/31/2024 12/21/2025 12/15/2025 12/15/2025 12/31/2025

Northern States Power Company
Transmission's Capital Additions: 2021-2023
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPM Additions Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Total
Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement

Project Name
NSPM Metro Steel pole Rplmnt Tools COM Substation Tools COM Substation RTU - EMS Upgrade - NSPM RTU - EMS Upgrade - NSPM Unserviceable Brkr Rplmt Program Fault Recorders - NSPM Fault Recorders - NSPM Fault Recorders - NSPM Fault Recorders - NSPM Unserviceable - Relays - NSPM Hiawatha West Tools, Training Center Tools System Protection Comm Eng Tools - Engineering Tools STAC Tools STAC NSP Line Capacity
TACT TACT TACT TACT TACT TACT TACT TACT TACT TACT TACT TACT HIBTAC 500kV NSPM Galloping Conductors NSPM Galloping Conductors NSPM Galloping Conductors NSPM Galloping Conductors NSPM Galloping Conductors NSPM Galloping Conductors NSPM Galloping Conductors DCP Great Plains DCP Great Plains Black Dog-Wilson 115kV uprates Long Lake-Baytown Ln #0801 Uprate Wilmarth-TC Thru Flow Mitigation Magic City Extension Hollydale Dist.115 kV Hollydale Dist.115 kV Raptor Distribution Substation Raptor Distribution Substation Falls Capacitor Bank

WBS Level 2 #

Description

A.0000743.009 A.0006059.449 A.0006059.451 A.0000657.005 A.0000657.025 A.0000287.018 A.0000393.006 A.0000393.007 A.0000393.008 A.0000393.009 A.0000751.003 A.0001413.001 A.0006059.447 A.0006059.087 A.0006059.450 A.0001019.001 A.0001019.003 A.0000233.005

NSM0870 FST RIV Triple CKT Pole Rplmt NSP COM Tool Sub NSPM COM Tools (BU 8640) NSPM ELR - RTU,Comm AS King RTU Comm MN Unserviceable Breaker Replacement, Su Eden Prairie Fault Recorder Comm Kohlman Lake Fault Recorder Comm Elm Creek - Install Fault Recorder Comm Inver Hills - Install Fault Recorder Com MN Unserviceable Relay Hiawatha West TR2 Install NSPM Training Center Tools NSPM Sys Protect Comm Eng Testing Eq NSP Ops Engineering Tools NSPM Tools STAC NSPM STAC Tools Line Capacity-MN, Line

A.0000943.007 A.0000943.008 A.0000943.010 A.0000943.011 A.0000943.013 A.0000943.014 A.0000943.016 A.0000943.017 A.0000943.018 A.0000943.019 A.0000943.020 A.0000943.021 A.0000901.001 A.0000714.016 A.0000714.017 A.0000714.018 A.0000714.019 A.0000714.020 A.0000714.022 A.0000714.024 A.0010174.004 A.0010174.005 A.0000155.002 A.0001438.001 A.0000385.001 A.0001450.003 A.0000226.013 A.0000226.021 A.0010148.007 A.0010148.008 A.0001185.001

2020 NSPM NERC TPL(MN-TACT) 2021 NSPM NERC TPL (MN-TACT) Red Rock Bkr Replacement Riverside Bkr Replacement St Louis Park Bkr Replacement West Coon Rapids Bkr Replacement AS King Bkr Replacement Black Dog Bkr Replacement Chisago Bkr Replacement Coon Creek Bkr Replacement Jim Falls Bkr Replacement Sheyenne Bkr Replacement HIBTAC 500kV Relocation Line NSM5538 Galloping Mitigation Line NSM5545 Galloping Mitigation Line NSM5547 Galloping Mitigation Line MN NSM5547 Galloping Mitigation Line SD NSM5538 Galloping Mitigation Line SD NSM5531 Galloping Mitigation Line NSM 5537 Galloping Mitigation Line Great Plains 5503 Line Great Plains Sub TAM Black Dog Wilson 115kV Uprates Sub LN #0801 Baytown - Long Lake Reconductor Line 0717 GRI to CAR Rbld, Line Line 0860 ROW Holydale TR Expansion TAM Line5409 In/Out at HOL South Washington Sub In Out South Washington Sub TAM Falls 40MVAR Cap Bank Sub

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 3 of 8

Addition Amount ($000s)

2021

2022

2023

NSPM (Total State of MN NSPM (Total State of MN NSPM (Total State of MN

Company) Elec. JUR Company) Elec. JUR Company) Elec. JUR

In-Service Date

1 340 135 99 52 559 393 462 420 348 492 1,397 592 100
60 12 12 10 67,593

1 248
98 72 38 407 286 337 306 254 359 1,019 432 73 44
9 9 7 41,096

0 1,000
135 986
0 566
0 0 0 0 491 0 75 100 60 12 12 0 86,158

0 729 98 719
0 413
0 0 0 0 358 0 55 73 44 9 9 0 62,828

0 1,000
140 990
0 567
0 0 0 0 493 0 75 100 60 12 12 0 130,874

0 729 102 722
0 413
0 0 0 0 359 0 55 73 44 9 9 0 95,436

12/15/2021 12/31/2025 12/31/2023 12/31/2024 5/15/2021 12/31/2024 12/20/2021 12/20/2021 11/30/2021 11/30/2021 12/31/2024 1/15/2021 12/31/2025 12/31/2025 12/31/2025 12/31/2025 12/31/2025 12/1/2021

4 1 35 35 1,952 755 585 83 200 1,987 11 10 15,469 2,196 1,525 1,059 329 65 3,216 2,237 0 0 5,308 0 0 0 1,656 435 642 1,418 0

3 1 26 25 1,424 551 426 60 146 1,449 8 7 11,280 1,601 1,112 772 240 47 2,345 1,631 0 0 3,870 0 0 0 1,207 317 468 1,034 0

4 8,179
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 4,959 4,040 0 22 0 0 0 1,941

3 5,964
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3,616 2,946 0 16 0 0 0 1,415

4 5,092
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 3,160 3,293 0 0 0 3,000 0 0 0 0 0

3 3,713
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2,304 2,401 0 0 0 2,188 0 0 0 0 0

12/31/2024 12/31/2023 5/15/2021 5/15/2021 5/31/2021 5/15/2021 5/15/2021 5/15/2021 5/15/2021 5/15/2021 3/15/2021 3/15/2021 12/15/2021 9/15/2021 9/15/2021 8/15/2021 9/15/2021 9/15/2021 9/15/2021 9/15/2021 12/15/2023 12/15/2023
3/1/2021 6/1/2022 3/1/2022 12/1/2023 12/31/2021 12/1/2021 5/15/2021 5/15/2021 6/1/2022

Northern States Power Company
Transmission's Capital Additions: 2021-2023
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPM Additions Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Total
Interconnection Interconnection Interconnection Interconnection Interconnection Interconnection Interconnection Interconnection Total
Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency

Project Name
Lincoln County Capacitor Bank Wilmarth/Mankato Energy Center Trans. Pr Wilmarth/Mankato Energy Center Trans. Pr 0714:MDE(ITC)MDL(City)Tap Rbld Stockyards Sub Stockyards Sub Aldrich DCP Forbes Substation SVC Retire Prairie Substation Capbank Remove Fair Park Fair Park Wilson Substation Conversion Wilson Substation Conversion PRC-002-2 NERC Compliance PRC-002-2 NERC Compliance PRC-002-2 NERC Compliance PRC-002-2 NERC Compliance PRC-002-2 NERC Compliance Cannon Falls Retaining Wall Hatton Sub Forbes Communication Rosemount Sub Rosemount Sub
SFNU MTEP18 NSPM J512/J569/J587/J590 HNA-SCO IA Tariff Fund J569 Rock County Sub East River Wellington G621 Wind Int. G621 Wind Int.
Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security NERC Order 754 NSPM NERC Order 754 NSPM NERC Order 754 NSPM NERC Order 754 NSPM

WBS Level 2 #

Description

A.0001184.001 A.0000660.001 A.0000660.003 A.0000727.001 A.0000718.001 A.0000718.002 A.0000986.001 A.0001179.001 A.0001178.001 A.0001424.001 A.0001424.002 A.0000390.001 A.0000390.013 A.0001157.001 A.0001157.002 A.0001157.003 A.0001157.004 A.0001157.005 A.0000725.001 A.0000744.001 A.0001179.003 A.0000715.001 A.0000715.002

Lincoln Co 30MVAR Cap Bank Sub ARL Main Bus Reconfig(USE), Sub GRI Trans DE Switches Sub Line 714 rebuild, Line Stockyards DCP TR3, Sub 0818/5529 Tap Relo, Line Aldrich DCP Upgrade Feeders, Sub FBS Retire Forbes SVC Prairie Sub Remove 40 MVAR Capbank Fair Park TR1 Feeder Fair Park RTU Comm Wilson Breaker and 1/2 WilSub Breaker and Half Comm ASK-Repl/Add DFR shelves BLL-Repl/Add DFR shelves RRK-Repl/Add DFR shelves TER-Repl/Add DFR shelves WLM-Repl/Add DFR shelves (TBD)Cannon Falls Site Imprvmnt,Sub DCP - Hatton TR, Line Forbes Comm Rosemount TR2, Sub Rosemount TR2 Sub Comm

A.0001378.002 A.0001412.001 A.0000076.002 A.0001460.001 A.0001387.001 A.0000898.001 A.0000898.002

SNFU Development Pre Con J512/J569/J587/J590 Line0982 HNA-SCO IA Tariff Fund NSP J569 RCY SUB - NU SELF FUND East River Wellington Interconnection G621 Chanarambie Wind Interc Sub Direct G621 Chanarambie Wind Interc Sub Network

A.0000710.004 A.0000710.010 A.0000710.011 A.0000710.017 A.0000710.019 A.0000710.020 A.0000710.021 A.0000710.026 A.0000710.030 A.0000710.031 A.0000710.033 A.0000710.044 A.0000710.045 A.0000738.001 A.0000738.003 A.0000738.004 A.0000738.008

NSPM Physical Security Sub Infrstruc NSPM Physical Security Comm NSPM ND Physical Security Comm Arden Physical Security Comm Fieldon Physical Security Comm Merriam Park Physical Security Comm Moore lake Physical Security Comm Rose Place Physical Security Infrastr Arden Hills Physical Security Infrastr Fieldon Physical Security Infrastr Moore Lake Physical Security Infrastr Wilmarth Physical Security Infrasr Crandall Physical Security Infrastr NERC 754 Protection Sys MN,Sub Prairie Island NERC Order 754 Upgrade Monticello NERC Order 754 Upgrade Forbes 500kV NERC Order 754

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 4 of 8

Addition Amount ($000s)

2021

2022

2023

NSPM (Total State of MN NSPM (Total State of MN NSPM (Total State of MN

Company) Elec. JUR Company) Elec. JUR Company) Elec. JUR

In-Service Date

1,649 0
380 0 0 0 0
980 850 752 42 470 249 194 193 102 102 99 328
0 107
59 12 47,780

1,202 0
277 0 0 0 0
715 620 548 31 343 181 141 141 75 75 72 239
0 78 43 9 34,842

0 1,263
0 1,606 1,314
139 1,015
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 24,481

0 921
0 1,171
958 101 740
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 17,852

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 153 0 0 0 14,701

0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 111 0 0 0 10,720

6/1/2021 5/31/2022 4/1/2021 12/1/2022 10/15/2022 10/15/2022
6/1/2022 12/15/2020
4/15/2021 4/15/2021 4/15/2021 12/28/2020 6/15/2021 6/15/2021 6/15/2021 6/15/2021 6/15/2021 6/15/2021 12/15/2021 10/31/2023 5/15/2021 12/15/2020 12/15/2020

493 35,769
0 1,378 1,229
125 -2
38,992

360 26,083
0 1,005
896 91 -1 28,434

16,533 0
8,512 0 0 0 0
25,045

12,056 0
6,207 0 0 0 0
18,263

29,233 0
4,005 0 0 0 0
33,237

21,317 0
2,920 0 0 0 0
24,237

1/1/2026 12/15/2021 12/31/2025
9/1/2021 6/30/2021 10/15/2021 10/15/2021

12,551 5,547 65 439 1 0 0 0 1,401 0 0 1,346 932 0 1,097 418 190

9,153 4,045
48 320
0 0 0 0 1,022 0 0 981 0 0 800 304 138

14,899 3,670 453 0 0 0 0 0 0 0 0 0 0
10,608 0 0 0

10,865 2,677 330 0 0 0 0 0 0 0 0 0 0 7,736 0 0 0

15,232 4,525 0 0 0 0 0 0 0 0 0 0 0 4,253 0 0 0

11,107 3,300 0 0 0 0 0 0 0 0 0 0 0 3,101 0 0 0

12/31/2025 12/30/2025 9/30/2022 12/15/2021 12/15/2021 12/15/2021 12/15/2021 12/15/2021 12/15/2021 12/15/2021 12/15/2021 12/15/2021 12/15/2021 10/30/2024 9/15/2021 3/30/2021 12/15/2021

Northern States Power Company
Transmission's Capital Additions: 2021-2023
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings

Project Name

NSPM Additions

Physical Security and Resiliency NERC Order 754 NSPM

Physical Security and Resiliency NERC Order 754 NSPM

Physical Security and Resiliency NERC Order 754 NSPM

Physical Security and Resiliency OT Cyber Security NSPM

Physical Security and Resiliency OT Cyber Security NSPM

Physical Security and Resiliency NSPM Physical Security

Physical Security and Resiliency NSPM Physical Security

Physical Security and Resiliency Geo Mag Dist (GMD)

Physical Security and Resiliency NSPM Electro Mag Pulse (EMP)

Physical Security and Resiliency Total

WBS Level 2 #

Description

A.0000738.010 A.0000738.011 A.0000738.016 A.0001456.001 A.0001456.002 A.0000745.002 A.0000745.004 A.0000752.006 A.0000957.005

Parkers Lake 345kV NERC Order 754 Blue Lake 345kV NERC Order 754 Upgrade Chisago 345kV NERC Order 754 Monitoring Logging RTCA MN Asset Management Software MN NSPM SD Physical Security Infrsturc NSPM (ND) Physical Security Infrsturc NSPM Geo Mag Dist (GMD) NSPM Electro Mag Pulse (EMP)

Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Regional Expansion Total

Huntley Wilmarth 345* Huntley Wilmarth 345* Huntley Wilmarth 345* Huntley Wilmarth 345* Huntley Wilmarth 345* Google Data Center Google Data Center Google Data Center Google Data Center Google Data Center

A.0000835.001 A.0000835.003 A.0000835.004 A.0000835.005 A.0000835.006 A.0001365.001 A.0001365.002 A.0001365.003 A.0001365.004 A.0001365.005

Huntley Wilmarth Precertification Huntley Wilmarth 345 ROW N/S Huntley Wilmarth 345 Line N/S Wilmarth 345 Sub Expansion for HW Line 0982 WLM-Crandall HW 2nd Circuit N/S 0827 SCL SNL 0827 SNL LIB 5573 SNL SHC 5574 SNL SHC Snuffys Landing Sub

Communications Infrastructure Comm Network Program Communications Infrastructure Comm Network Program Communications Infrastructure Comm Network Program Communications Infrastructure Comm Network Program Communications Infrastructure Comm Network Program Communications Infrastructure NSPM COMM Circuit Upgrades Communication Infrastructure Total

A.0001320.007 A.0001320.017 A.0001320.018 A.0001320.019 A.0001320.020 A.0001357.002

NSPM Comm Network Program Comm AS King - Private Comm Network Black Dog - Private Comm Network Prairie Island - Private Comm Network Rosemount - Private Comm Network NSPM 2017 COMM Circuit Upgrades

NSPM Total

*Those projects that will be recovered through the Transmission Cost Recovery Rider

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 5 of 8

Addition Amount ($000s)

2021

2022

2023

NSPM (Total State of MN NSPM (Total State of MN NSPM (Total State of MN

Company) Elec. JUR Company) Elec. JUR Company) Elec. JUR

In-Service Date

279 227 304
0 0 0 0 101 0 24,897

203 165 222
0 0 0 0 74 0 17,476

0 0 0 3,156 843 2,893 2,614 1,010 198 40,347

0 0 0 2,302 615 2,110 1,906 736 145 29,421

0 0 0 1,866 1,028 0 0 2,020 0 28,923

0 0 0 1,361 750 0 0 1,473 0 21,092

3/30/2021 12/15/2021 12/15/2021 10/31/2024 12/31/2025 12/15/2022 12/15/2022 10/31/2024 12/31/2022

0 1,456 61,313 3,260 7,204 1,391
0 0 0 0 74,624

0 1,062 44,711 2,378 5,253 1,014
0 0 0 0 54,417

0 63 4,149 90
0 0 518 518 518 12,274 18,130

0 46 3,026 66
0 0 378 378 378 8,950 13,221

0

0

12/30/2021

0

0

12/31/2021

0

0

12/31/2021

0

0

12/15/2021

0

0

5/30/2021

0

0

9/15/2021

0

0

7/15/2022

0

0

7/15/2022

0

0

7/15/2022

0

0

7/15/2022

0

0

3,940 0 0 0 0
170 4,110

2,873 0 0 0 0
124 2,997

15,859 354 353 353 353 170
17,443

11,565 258 258 258 257 124
12,720

25,516 0 0 0 0
170 25,686

18,607 0 0 0 0
124 18,731

12/15/2025 1/15/2022 1/15/2022 1/15/2022 1/15/2022 12/31/2025

257,995 179,261

211,604 154,306

233,422 170,216

Northern States Power Company
Transmission Capital Plant Additions
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPW Additions Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal

Project Name
Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Rebuild Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment Major Line Refurbishment ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Relay ELR - Transformers ELR - Transformers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers ELR - Breakers S&E - Line S&E - Line S&E - Line W3203 Briggs-LaCrosse Upgrade W3203 Briggs-LaCrosse Upgrade W3205 LaCrosse-Coulee Line ELR Line ELR Transmission UAV Flights W3432 LaCrosse-Coulee 69 kV rebuild

WBS Level 2 #
A.0000689.022 A.0000689.023 A.0000689.030 A.0000689.034 A.0000689.035 A.0000689.036 A.0000689.043 A.0000689.045 A.0000689.047 A.0000689.049 A.0000689.050 A.0000583.003 A.0000583.047 A.0000583.052 A.0000583.053 A.0000583.054 A.0000583.056 A.0000583.057 A.0000503.002 A.0000503.023 A.0000503.024 A.0000503.025 A.0000503.027 A.0000503.028 A.0000503.029 A.0000503.030 A.0000503.033 A.0000503.035 A.0000503.036 A.0000503.037 A.0000503.040 A.0000503.041 A.0000398.002 A.0000398.006 A.0000397.010 A.0000397.020 A.0000397.022 A.0000397.023 A.0000397.024 A.0000397.025 A.0000397.026 A.0000397.027 A.0000397.029 A.0000397.031 A.0000397.032 A.0000397.034 A.0000495.021 A.0000495.024 A.0000495.026 A.0002030.001 A.0002030.002 A.0000689.024 A.0000327.017 A.0000327.022 A.0000855.002 A.0001239.001

Description
W3477 RBL STR 368 69Kv Rebuild Line W3477 STR 368 MFD 69kV Rebuild Line W3604 Port Wing Rebuild for DIST Sub W3408 Mondovi to GMN Tap W3408 GMN Tap to STR 563 W3408 STR 563 to Nelson W3321 STR 140 to Phillips Tap Rebuild W3320 Osprey to STR 54 Rebuild W3320 STR 54 to Hawkins Rebuild W3408 Naples to Mondovi W3320 Hawkins to Catawba Rebuild NSPW Major Line Refurbishment,Line NSW3454 Refurbishment Str 98 to 118 W3304 Hay River to Pine Lake W3304 Pine Lake to Three Lakes Rebuild W3304 Three Lakes to Willow River Tap W3213 RCD WHT Repl Strs 53 to 206 W3213 RCD WHT REPL STRS PH 2 NSPW - 2016 - ELR - Relays Cedar Falls-Relaying CLL,ECL,MEN,RCD Cotton School-Relaying ALC,SPL,SEV,Bus1 Flambeau-Relaying PFA,PFA Hurley-Rpl Sync Cond Relays and Cntrls Jackson Co-Relaying ALC,HAF,MLE Jim Falls-Relaying RCL,HYD,HLC Park Falls-Relaying FLB1,FLB2 Seven Mile-Relaying ECL,ELS,LON,CTS,SEM Spokesville-Relaying CTS,TCN,TCN T-Corners-Relaying SPE,WIT,MFD,SPL Tremval-Relaying ALC,IDP,MLE Crystal Cave Relaying River Falls Relaying NSPW ELR Transformers ELR - ECL TR10 Replacement NSPW - 2016 - ELR - Breakers Flambeau-Replace Bkrs 3R132,3R133,3R254 Jackson Co-Replace Bkrs 4L6,4L7,4L8,4L9 Lacrosse-Replace Bkrs 4L44,4L45 Lacrosse-Replace Bkrs 6L4,6L5,6L7 Menomonie-Replace Bkrs 4E63,4E64 Monroe Co-Replace Bkrs 4L76,4L77 Marshland-Replace Bkrs Prentice-Replace Bkr 4R6 T-Corners-Replace Bkr 4E22 Cumberland-Rpl Bkr 4R84 Bayfront Replace Breakers 5R42 & 5R47 NSPW S&E 69kV, Line MI S&E 34.5kV, Line NSPW Priority Defects 69kV Line W3203 Briggs Lacrosse Rlbd Line W3203 Briggs Lacrosse Rebuild W3205 LaCrosse Coulee Rebuild NSPW 69kV Line ELR 2016 MI 34.5kV TLine ELR Line NSPW Transmission UAV W3432 LaCrosse-Coulee 69 kV rebuild

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 6 of 8

2021 NSPW (Total State of MN
Company) Elec. JUR

Addition Amount ($000s) 2022
NSPW (Total State of MN Company) Elec. JUR

2023 NSPW (Total State of MN
Company) Elec. JUR In-Service Date

4,868 0 0
2,204 0 0 0
3,966 0
2,483 0 0
291 2,678
0 0 0 6,565 0 1,338 1,327 0 579 0 1,127 0 1,272 886 1,387 1,008 326 309 101 0 0 0 0 580 1,539 0 0 1,087 291 400 156 1,037 1,402 50 2,553 0 0 9,775 2,860 50 4,401 0

3,550 0 0
1,607 0 0 0
2,892 0
1,811 0 0
212 1,953
0 0 0 4,787 0 976 968 0 422 0 822 0 928 646 1,011 735 238 225 74 0 0 0 0 423 1,122 0 0 792 212 292 114 756 1,022 37 1,862 0 0 7,128 2,086 37 3,210 0

0 4,520
0 0 3,107 0 4,059 0 3,418 0 0 2,675 0 0 3,270 0 6,704 0 4,257 0 0 0 0 0 0 0 0 0 0 0 0 0 2,994 6,383 3,753 0 0 0 0 0 0 0 0 0 0 0 3,404 50 1,802 0 9 0 2,264 50 0 4,322

0 3,296
0 0 2,266 0 2,960 0 2,492 0 0 1,950 0 0 2,384 0 4,889 0 3,104 0 0 0 0 0 0 0 0 0 0 0 0 0 2,183 4,654 2,736 0 0 0 0 0 0 0 0 0 0 0 2,482 37 1,314 0 7 0 1,651 37 0 3,152

0 0 4,724 0 0 3,421 0 0 0 0 3,447 2,982 0 0 0 1,986 0 0 1,962 0 0 602 0 904 0 625 0 0 0 0 0 0 4,419 0 2,751 620 1,222 0 0 20 20 0 0 0 0 0 1,402 50 1,552 11,194 0 0 2,462 50 0 0

0 0 3,445 0 0 2,495 0 0 0 0 2,514 2,175 0 0 0 1,448 0 0 1,431 0 0 439 0 659 0 456 0 0 0 0 0 0 3,223 0 2,006 452 891 0 0 14 14 0 0 0 0 0 1,022 37 1,132 8,163 0 0 1,795 37 0 0

4/30/2021 5/1/2022 6/1/2023 6/15/2021 5/15/2022 5/15/2023 1/15/2022 4/27/2021 4/15/2022 4/5/2021 4/15/2023 12/31/2025 6/1/2021 7/15/2021 12/15/2022 12/15/2023 1/15/2022 12/15/2021 12/31/2025 12/15/2021 12/15/2021 12/15/2023 2/15/2021 12/15/2023 12/15/2021 12/15/2023 12/15/2021 5/31/2021 12/15/2021 12/15/2021 5/15/2021 5/15/2021 12/15/2024 2/15/2022 12/31/2025 12/15/2023 12/15/2023 12/15/2021 2/15/2021 11/30/2023 11/30/2023 11/15/2021 3/15/2021 5/31/2021 12/15/2021 1/15/2021 12/31/2025 12/15/2025 12/15/2025 5/15/2023 10/31/2022 1/15/2021 12/15/2025 12/15/2025 10/15/2021 12/15/2022

Northern States Power Company
Transmission Capital Plant Additions
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPW Additions Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Asset Renewal Total
Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement

Project Name
Group 1 Switch Replacements Group 1 Switch Replacements Group 1 Switch Replacements S&E - Sub S&E - Sub RTU - EMS Upgrade - NSPW RTU - EMS Upgrade - NSPW Unserviceable - Relays - NSPW Unserviceable Brkr Rplmt Program NSPW Reloc B NSPW Reloc B Tools COM Substation Tools Line Field Ops Tools Line Field Ops Tools STAC Cable Sub
Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Bayfield Loop Hurley Norrie 115kV Hurley Norrie 115kV Hurley Norrie 115kV Hurley Norrie 115kV DCP Elmwood Substation DCP Elmwood Substation DCP Elmwood Substation DCP Elmwood Substation DCP Elmwood Substation DCP Elmwood Substation DCP Elmwood Substation Twin Town Area Upgrades Twin Town Area Upgrades Twin Town Area Upgrades Bayfront to Ironwood 88 kV Bayfront to Ironwood 88 kV Install Turtle Lake Area Substation Install Turtle Lake Area Substation Install Turtle Lake Area Substation Bayfront to Ironwood Bad River Res ROW Western WI / E. Metro Upgrade NSPW Galloping Conductors Rest Lake-Presque Isle

WBS Level 2 #
A.0000444.005 A.0000444.045 A.0000444.052 A.0000075.008 A.0000075.009 A.0000423.003 A.0000423.011 A.0000396.003 A.0000287.014 A.0000496.022 A.0000496.024 A.0006059.431 A.0006059.430 A.0006059.497 A.0001019.004 A.0001248.004

Description
NSPW Switch Rplmts, Line W3408 Naples Replace SW W3612 DPC Butternut SW MI S&E, Sub NSPW S&E, Sub NSPW ELR - RTU,Comm LaCrosse RTU Comm WI Unserviceable Relay Unserviceable Breaker Replmnts, Sub MI MI Reloc B 34.5kV Line NSPW Reloc B 69kV Line NSPW Com Tool Tool Blanket WI, Line EPZ Mats NSPW NSPW STAC Tools W3470 Reterm at CAB DCP

A.0000193.006 A.0000193.007 A.0000193.008 A.0000193.009 A.0000193.010 A.0000193.011 A.0000193.012 A.0000193.013 A.0000193.014 A.0000193.015 A.0000193.016 A.0000193.017 A.0000193.018 A.0000193.019 A.0000193.020 A.0001169.001 A.0001169.002 A.0001169.003 A.0001169.004 A.0010163.003 A.0010163.004 A.0010163.005 A.0010163.006 A.0010163.007 A.0010163.008 A.0010163.009 A.0001159.002 A.0001159.003 A.0001159.004 A.0000567.006 A.0000567.009 A.0001395.003 A.0001395.004 A.0001395.005 A.0001193.001 A.0001437.002 A.0000762.001 A.0001198.001

Bayfield Second Circuit-PKC TAM Bayfield Second Circuit-FSC TAM Bayfield Second Circuit-W3602 Reterm Bayfield Second Circuit-W3603 Rebld Bayfield Second Circuit-W3604 Reterm Bayfield Second Circuit-BFT-STS Reterm Bayfield Second Circ FSC-Tie Switch Bayfield Second Circ Tie Switch PKC Bayfield Second Circ W3601 Rebuild Bayfield Second Circ-W3603 ROW Bayfield Second Circ-W3604 ROW Bayfield Second Circ-W3602 ROW Bayfield Second Circ-W3601 ROW Bayfield Second Circ-PKC Comm Bayfield Second Circ-FSC Comm Hurley - Norrie 115kV Hur NRR 115kV MI 1.2 Miles NRR 115kV Yard Improvements HUR 115kV Yard Improvements DCP Elmwood Substation W3466 In Out at ELM Sub W3415 Reterm to ELM Sub W3466 MEN to ELM Sub W3466 RLM to ELM Sub DCP Elmwood Substation Land Elmwood Substation 69kV Sub COMM Turtle Lake - Almena Line Turtle Lake Cap Bank Addition Turtle Lake Comm W3351 BFT - IRW ROW BFT IRW Permit Line SAP W3429 Pine Street to Lake Camelia W3429 Pine Street to Twin Town SUB Install Turtle Lake Area Sub DCP W3351 Bad River Res ROW Willow River Sub 20 MVAR CAP NSPW 2019 Galloping Mitigation Rest Lake Presque Isle ROW

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 7 of 8

2021 NSPW (Total State of MN
Company) Elec. JUR

Addition Amount ($000s) 2022
NSPW (Total State of MN Company) Elec. JUR

2023 NSPW (Total State of MN
Company) Elec. JUR In-Service Date

1,083 433 0 49
1,177 984 29 493 467 50 384 385 74 50 12 26
64,592

790 316
0 36 859 718 21 359 341 37 280 281 54 36
9 19 47,101

1,083 0 0
49 1,177
981 0
492 468 50 384 400 77 50
12 0 62,264

789 0 0
36 859 715
0 359 341 37 280 292 56 36
9 0 45,404

1,085 0 0
49 1,177
981 0
491 467 50 384 220 81 50
12 0 51,464

791 0 0
36 859 716
0 358 341 37 280 160 59 36
9 0 37,529

12/31/2025 3/31/2021 6/1/2021 12/31/2024 12/31/2025 12/31/2024 2/15/2021 12/31/2025 12/31/2025 12/15/2025 12/15/2025 12/31/2025 12/31/2025 12/31/2025 12/31/2025 12/31/2020

0 0 0 0 0 0 0 0 0 123 0 0 120 0 0 0 0 0 0 0 0 0 0 0 0 130 5,599 569 208 2,250 600 597 0 868 1,693 0 1,383 100

0 0 0 0 0 0 0 0 0 90 0 0 87 0 0 0 0 0 0 0 0 0 0 0 0 94 4,083 415 152 1,641 438 435 0 633 1,235 0 1,009 73

4,627 6,153
196 11,735
196 655 1,280 1,240 14,587
0 55 55
0 152 152
0 0 0 0 4,274 91 1,137 408 408 0 0 0 0 0 1,750 0 0 0 0 0 0 0 150

3,374 4,487
143 8,557
143 477 933 904 10,637
0 40 40
0 111 111
0 0 0 0 3,116 66 829 297 297 0 0 0 0 0 1,276 0 0 0 0 0 0 0 109

40 0 5 2,310 5 0 0 20 0 0 0 0 0 0 0 1,944 1,388 1,276 4,059 0 0 0 0 0 0 0 0 0 0 0 0 0 350 0 0 1,420 0 400

29 0 4
1,684 4 0 0 15 0 0 0 0 0 0 0
1,417 1,012
931 2,960
0 0 0 0 0 0 0 0 0 0 0 0 0 256 0 0 1,035 0 292

11/15/2022 2/15/2022
11/15/2022 11/15/2022 11/15/2022 2/15/2022 2/15/2022 11/15/2022 2/15/2022 4/15/2021 5/15/2022 5/15/2022 4/15/2021 11/15/2022 2/15/2022 12/15/2023 12/15/2023 12/15/2023 12/15/2023 2/15/2022 2/15/2022 2/15/2022 2/15/2022 2/15/2022 11/15/2020 12/15/2021 9/15/2021 6/15/2021 3/15/2021 12/15/2022 12/31/2021 6/15/2021 12/15/2023 6/15/2021
2/1/2021 5/30/2023 3/31/2021 4/15/2024

Northern States Power Company
Transmission Capital Plant Additions
Addition Amounts Represent Total Project Costs Including AFUDC

Capital Budget Groupings NSPW Additions Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Regional Expansion Regional Expansion Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Reliability Requirement Total
Interconnection Interconnection Interconnection Interconnection Interconnection Interconnection Interconnection Interconnection Total
Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Physical Security and Resiliency Total
n/a Regional Expansion Total
Communications Infrastructure Communications Infrastructure Communications Infrastructure Communications Infrastructure Communications Infrastructure Communications Infrastructure Total
NSPW Total

Project Name
FIN Reinforce TR1 FIN Reinforce TR1 TACT ROW by Permit DCP Kinnickinnic DCP Kinnickinnic Wissota Beach Sub Rebuild DCP Ironwood Substation DCP Ironwood Substation Clear Lake Area Sub DCP Clear Lake Area Sub DCP Copperwood Mine
IA Tariff Fund SFNU MTEP18 NSPM DPC Arkansaw Tap Interconnection DPC Switch Interconnections DPC Switch Interconnections DPC Switch Interconnections DPC Switch Interconnections
Physical Security Physical Security Physical Security Physical Security Physical Security Physical Security OT Cyber Security NSPW OT Cyber Security NSPW NSPW Geomagnetic Disturbances (GMD) NSPW Electro Mag Pulse (EMP)
n/a
Comm Network Program NSPW COMM Circuit Upgrades AGIS FLISR Cedar Falls Relaying - COMM Spokesville Relaying - COMM

WBS Level 2 #
A.0001415.001 A.0001415.002 A.0000943.022 A.0000879.002 A.0001247.001 A.0001247.002 A.0010173.006 A.0010164.003 A.0010164.004 A.0001186.002 A.0001186.008 A.0001266.005

Description
FIN Reinforce TR1 DCP FIN Reinforce TR1 Comm DCP Jim Falls Bkr Replacement NSPW USDA F S Ottawa MI 22 26 ROW W3426 Reterm at Kin DCP Kin Rbld 69 23 9kV Sub TAM DCP BMN New 69 23 9kV Sub DCP PKR 115 12.5kV SUB DCP W3325 In Out at PKR SUB DCP Clear Lake Area Sub TAM Clear Lake Area Sub TAM Retire Copperwood Mine Eng Svc Agrment

A.0000076.003 A.0001463.001 A.0001177.001 A.0000873.008 A.0000873.009 A.0000873.010 A.0000873.011

IA Tariff Fund NSPW SFNU WI Pre Con W3415 Tap to DPC at Arkansaw Sub DPC W3408 Interconnection W3408 DPC N-5 Tie Nelson W3427 DPC N-4 Tie Clear Lake W3403 DPC Hanson Tap SW

A.0000710.002 A.0000710.006 A.0000710.024 A.0000710.025 A.0000710.034 A.0000710.035 A.0001457.001 A.0001457.002 A.0000766.005 A.0000775.005

NSPW Physical Security Sub Infrstruc NSPW Physical Security Comm La Crosse Physical Security Comm Stone Lake Physical Security Comm La Crosse Physical Security Infrastr Stone Lake Physical Security Infrastr Monitoring Logging RTCA WI Asset Management Software WI NSPW Geomagnetic Disturbance (GMD) NSPW Electro Mag Pulse (EMP)

n/a

n/a

A.0001320.010 A.0000487.001 D.0001902.026 A.0001481.001 A.0001482.001

NSPW Comm Network Program Comm NSPW 2017 COMM Circuit Upgrades AGIS FLISR NSPW Transmission Precon Cedar Falls Relaying - COMM Spokesville Relaying - COMM

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 2
Page 8 of 8

2021 NSPW (Total State of MN
Company) Elec. JUR

Addition Amount ($000s) 2022
NSPW (Total State of MN Company) Elec. JUR

2023 NSPW (Total State of MN
Company) Elec. JUR In-Service Date

529 23 237 0 0 0 22 10 10
5 2 0 15,077

385 16 173 0 0 0 16 8
8 4 2 0 10,995

0 0 0 80 60 0 0 0 0 0 0 0 49,440

0 0 0 58 44 0 0 0 0 0 0 0 36,053

0 0 0 0 0 0 0 0 0 0 0 0 13,217

0 0 0 0 0 0 0 0 0 0 0 0 9,638

5/15/2021 5/15/2021 5/15/2021 1/15/2022 12/15/2021 12/15/2021 12/15/2020 10/15/2020 10/15/2020 11/20/2020 6/30/2021
6/1/2022

0 117 1,241
0 244 234 266 2,102

0 85 905 0 178 171 194 1,533

6,112 1,904
0 244
0 0 0 8,259

4,457 1,388
0 178
0 0 0 6,023

3,004 4,023
0 0 0 0 0 7,027

2,190 2,934
0 0 0 0 0 5,124

12/31/2024 1/1/2026
3/30/2021 3/15/2022 9/15/2021 12/31/2021 4/30/2021

2,810 973 759
1,649 1,449 1,358
0 0 0 0 9,000

2,049 710 554
1,203 1,057
990 0 0 0 0
6,563

1,114 202 0 0 0 0 819 272 501 158
3,066

812 147
0 0 0 0 597 198 365 115 2,236

502 150
0 0 0 0 485 332 0 0 1,469

366 110
0 0 0 0 353 242 0 0 1,071

12/15/2024 12/25/2025 12/15/2021 12/15/2021 12/15/2021 12/15/2021 10/31/2024 12/31/2025 12/31/2022 12/31/2022

0

0

0

0

0

0

0

0

0

0 n/a

0

0

5,024 170 0 1 1
5,196

3,663 124 0 1 1
3,789

5,025 171 256 0 0
5,451

3,664 125 186 0 0
3,975

9,931 170 0 0 0
10,101

7,242 124 0 0 0
7,366

12/15/2025 12/31/2025 12/31/2022 12/15/2021 12/15/2021

95,967

69,981

128,481

93,691

83,278

60,728

Northern States Power Company Transmission's O&M Costs by Category: 2017-2023

Cost Category Internal Labor Contract Labor and Consulting Employee Expenses Fees Materials Other Total

2017 Actual $21.40 $4.70 $2.70 $3.50 $3.60 $5.10 $41.00

Transmission's O&M Costs by Category: 2017-2023

NSPM-Electric

($000,000)

2018

2019

2017 ­ 2019

2020

Actual

Actual

Average

Forecast

$22.00

$20.40

$21.30

$20.00

$4.50

$4.50

$4.60

$3.90

$2.90

$2.70

$2.80

$2.30

$3.50

$3.40

$3.50

$3.50

$3.30

$2.50

$3.10

$1.70

$4.10

$2.60

$3.90

$2.60

$40.30

$36.10

$39.20

$34.00

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 3
Page 1 of 1

2021 Budget $21.50 $4.50 $3.10 $3.70 $2.50 $2.90 $38.20

2022 Budget $22.10 $4.50 $3.10 $3.90 $2.40 $2.70 $38.70

2023 Budget $22.80 $4.40 $3.10 $4.20 $2.30 $3.60 $40.40

Northern States Power Company

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 4
Page 1 of 1

NSP System Transmission Expenses ($000's)
Description
NSP JPZ payments and GRE JPZ charges MISO Network Service MISO Transmission Expansion Plan (RECB) Schedule 2 (Reactive Supply) MISO Schedules 10, 10-FERC MISO Schedules 16 and 17 MISO Schedule 24 Schedule 1 (Sch, Sys Ctrl & Disp) Sch 33 - Blackstart Sch 45 - NREAC Recovery Other native load deliveries SPP Point-to-Point MISO Point-to-Point MISO System Studies Self-Funded Network Upgrades Courtenay Wind Project - Point-to-Point and Interconnection Upgrades
Total Expense
Less:
MISO Schedules 10, 10-FERC - Regional Markets portion MISO Schedules 16 and 17 MISO Schedule 24
Note: Regional Markets Items [See Note #1]
MISO Transmission Expansion Plan (RECB)
Note: Items Collected through TCR
Blazing Star 2 Wind Project Blazing Star 1 Wind Project Border Winds Dakota Range 1 & 2 Wind Project Fox Tail Wind Farm Freeborn Wind Farm Courtenay Wind Project - Point-to-Point and Interconnection Upgrades
Note: Items Collected through RES

2019 ACTUALS

(000's)

$

60,404

$

7,761

$

131,177

$

9,625

$

11,392

$

8,569

$

1,222

$

234

$

30

$

1

$

73

$

86

$

80

$

80

$

-

$

1,708

2021 BUDGET

(000's)

$

58,414

$

11,377

$

128,622

$

11,512

$

11,162

$

8,319

$

1,172

$

631

$

30

$

2

$

71

$

75

$

85

$

33

$

4,145

$

1,708

2022 BUDGET

(000's)

$

60,066

$

11,896

$

129,969

$

11,657

$

11,866

$

8,033

$

1,208

$

660

$

31

$

2

$

71

$

78

$

88

$

34

$

5,415

$

1,708

2023 BUDGET

(000's)

$

61,236

$

12,241

$

128,381

$

11,649

$

12,122

$

8,431

$

1,244

$

679

$

32

$

2

$

71

$

80

$

91

$

35

$

5,415

$

1,708

$

232,443 $

237,359 $

242,783 $

243,419

$

254 $

$

8,569 $

$

1,222 $

$

10,045 $

248 $ 8,319 $ 1,172 $
9,739 $

266 $ 8,033 $ 1,208 $
9,507 $

$

131,177 $

128,622 $

129,969 $

$

131,177 $

128,622 $

129,969 $

$

1,319 $

2,589 $

$

89 $

89 $

$

336 $

336 $

$

1,078 $

1,078 $

$

891 $

891 $

$

400 $

400 $

$

1,708 $

1,708 $

1,708 $

$

1,708 $

5,822 $

7,092 $

270 8,431 1,244
9,945
128,381
128,381
2,589 89
336 1,078
891 400 1,708
7,092

Net Base Rate Transmission Expense

$

89,513 $

93,176 $

96,215 $

98,001

Note #1 MISO energy and ancillary services market administration charges are reflected in Commercial Operations portion of Energy Supply budget and included in base rates.

Northern States Power Company
NSP System Transmission Revenues ($000's)
Description
Network JPZ - GRE/SMMPA/MRES Network Service - Midwest ISO Tariff MISO Transmission Expansion Plan (RECB) Point-to-Point Firm, Point-to-Point Non Firm Schedule 2 (Reactive Supply) Tm-1 GFAs Fixed GFA Contracts Self-Funded Network Upgrades MISO Schedule 24 - Balancing Authority Schedule 1 (Sch, Sys Ctrl & Disp) GRE O&M service Marshall TOPS Agreement
Total Revenue Collected
Less:
Schedule 2 (Reactive Supply) Note: Revenues transfer to Energy Supply
MISO Transmission Expansion Plan (RECB) Note: Included as credit in TCR Rider
GRE O&M service Marshall TOPS Agreement Note: Revenues transfer to Distribution
Net Base Rate Transmisison Revenue

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 5
Page 1 of 1

2019 ACTUALS

(000's)

$

56,936

$

25,163

$

137,734

$

7,923

$

8,592

$

-

$

418

$

-

$

1,068

$

528

$

227

$

137

2021 BUDGET

(000's)

$

52,066

$

30,595

$

131,068

$

6,353

$

8,773

$

-

$

423

$

1,610

$

1,170

$

544

$

226

$

144

2022 BUDGET

(000's)

$

55,598

$

28,755

$

138,255

$

6,199

$

8,773

$

-

$

426

$

4,710

$

1,187

$

544

$

226

$

148

2023 BUDGET

(000's)

$

57,185

$

29,618

$

136,928

$

6,205

$

8,773

$

-

$

427

$

4,710

$

1,223

$

544

$

226

$

151

$

238,727 $

232,970 $

244,821 $

245,991

$

8,592 $

8,773 $

8,773 $

8,773

$

8,592 $

8,773 $

8,773 $

8,773

$

137,734 $

131,068 $

138,255 $

136,928

$

137,734 $

131,068 $

138,255 $

136,928

$

227 $

226 $

226 $

226

$

137 $

144 $

148 $

151

$

364 $

370 $

373 $

377

$

92,036 $

92,760 $

97,420 $

99,913

Northern States Power Company

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 6
Page 1 of 3

Joint Zonal Revenues and Expenses - 2021 Budget Year

Revenue

NSP JPZ

GRE

SMMPA

Jan-21

$ 3,016,062 $

483,368 $

Feb-21

$ 2,577,565 $

441,503 $

Mar-21

$ 2,594,849 $

459,649 $

Apr-21

$ 2,282,698 $

411,408 $

May-21

$ 3,113,053 $

537,518 $

Jun-21

$ 3,430,265 $

611,635 $

Jul-21

$ 3,640,880 $

696,868 $

Aug-21

$ 3,626,648 $

630,240 $

Sep-21

$ 3,338,874 $

599,751 $

Oct-21

$ 2,350,545 $

494,875 $

Nov-21

$ 2,718,873 $

447,305 $

Dec-21

$ 3,023,956 $

477,603 $

Total

$ 35,714,267 $ 6,291,722 $

MRES 445,534 $ 412,310 $ 429,751 $ 395,782 $ 426,907 $ 475,150 $ 499,456 $ 489,847 $ 452,815 $ 411,523 $ 424,381 $ 449,150 $
5,312,606 $

Total 3,944,965 3,431,378 3,484,248 3,089,888 4,077,477 4,517,050 4,837,203 4,746,735 4,391,440 3,256,943 3,590,559 3,950,709
47,318,595

GRE JPZ Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Total

GRE

$

396,792

$

395,610

$

325,530

$

313,140

$

353,980

$

450,406

$

498,938

$

472,470

$

435,950

$

325,862

$

371,380

$

406,978

$ 4,747,037

Total GRE Revenue $ 40,461,303.84

Total Transmission Joint Zonal Revenue

Expense NSP JPZ Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Total

GRE

SMMPA

CMMPA

$ 2,657,372 $ 1,135,846 $

101,198 $

$ 2,356,955 $ 1,007,437 $

89,757 $

$ 2,390,118 $ 1,021,612 $

91,020 $

$ 2,118,678 $

905,590 $

80,683 $

$ 2,606,411 $ 1,114,063 $

99,257 $

$ 3,339,109 $ 1,427,242 $

127,159 $

$ 3,841,385 $ 1,641,930 $

146,287 $

$ 3,669,984 $ 1,568,668 $

139,760 $

$ 3,118,733 $ 1,333,046 $

118,767 $

$ 2,421,863 $ 1,035,181 $

92,229 $

$ 2,408,054 $ 1,029,279 $

91,703 $

$ 2,726,640 $ 1,165,453 $

103,835 $

$ 33,655,301 $ 14,385,348 $ 1,281,655 $

NWEC 43,441 $ 38,530 $ 39,072 $ 34,634 $ 42,608 $ 54,585 $ 62,796 $ 59,994 $ 50,983 $ 39,591 $ 39,365 $ 44,573 $ 550,170 $

GRE JPZ Jan-21 Feb-21 Mar-21 Apr-21 May-21 Jun-21 Jul-21 Aug-21 Sep-21 Oct-21 Nov-21 Dec-21 Total

GRE

$

314,299

$

275,049

$

305,024

$

262,982

$

252,830

$

315,831

$

411,049

$

364,851

$

275,259

$

296,954

$

313,844

$

347,867

$ 3,735,841

Total GRE Expense $ 37,391,142.03

Total Transmission Joint Zonal Expense

Net Transmission Joint Zonal

Net Transmission Joint Zonal Payment for NSP Pricing Zone Net Transmission Joint Zonal Payment for GRE Pricing Zone

$52,065,632

MMPA 97,603 $ 86,569 $ 87,787 $ 77,817 $ 95,731 $ 122,643 $ 141,091 $ 134,795 $ 114,548 $ 88,953 $ 88,446 $ 100,147 $ 1,236,131 $

MRES 131,028 $ 116,216 $ 117,851 $ 104,467 $ 128,516 $ 164,643 $ 189,409 $ 180,958 $ 153,777 $ 119,416 $ 118,735 $ 134,444 $ 1,659,459 $

$ 58,413,935
($6,348,303)
$ (7,359,499) $ 1,011,196

RPU

Total

150,813 $ 4,317,301

133,764 $ 3,829,227

135,646 $ 3,883,105

120,241 $ 3,442,110

147,921 $ 4,234,506

189,504 $ 5,424,885

218,009 $ 6,240,908

208,282 $ 5,962,440

176,997 $ 5,066,851

137,447 $ 3,934,681

136,664 $ 3,912,246

154,744 $ 4,429,836

1,910,031 $ 54,678,095

-

Northern States Power Company

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 6
Page 2 of 3

Joint Zonal Revenues and Expenses - 2022 Budget Year

Revenue

NSP JPZ

GRE

SMMPA

Jan-22

$ 3,232,390 $

518,038 $

Feb-22

$ 2,762,441 $

473,170 $

Mar-22

$ 2,780,965 $

492,617 $

Apr-22

$ 2,446,425 $

440,916 $

May-22

$ 3,336,337 $

576,071 $

Jun-22

$ 3,676,301 $

655,505 $

Jul-22

$ 3,902,023 $

746,851 $

Aug-22

$ 3,886,771 $

675,444 $

Sep-22

$ 3,578,356 $

642,769 $

Oct-22

$ 2,519,138 $

530,370 $

Nov-22

$ 2,913,884 $

479,388 $

Dec-22

$ 3,240,850 $

511,859 $

Total

$ 38,275,882 $ 6,742,998 $

MRES 477,490 $ 441,883 $ 460,575 $ 424,170 $ 457,527 $ 509,230 $ 535,279 $ 524,981 $ 485,293 $ 441,040 $ 454,820 $ 481,365 $
5,693,654 $

Total 4,227,918 3,677,494 3,734,157 3,311,511 4,369,935 4,841,036 5,184,153 5,087,196 4,706,417 3,490,548 3,848,092 4,234,074
50,712,534

GRE JPZ Jan-22 Feb-22 Mar-22 Apr-22 May-22 Jun-22 Jul-22 Aug-22 Sep-22 Oct-22 Nov-22 Dec-22 Total

GRE

$

408,379

$

407,161

$

334,978

$

322,216

$

364,282

$

463,600

$

513,589

$

486,327

$

448,711

$

335,321

$

382,204

$

418,870

$ 4,885,639

Total GRE Revenue $ 43,161,520.39

Total Transmission Joint Zonal Revenue

Expense NSP JPZ Jan-22 Feb-22 Mar-22 Apr-22 May-22 Jun-22 Jul-22 Aug-22 Sep-22 Oct-22 Nov-22 Dec-22 Total

GRE

SMMPA

CMMPA

$ 2,778,929 $ 1,135,857 $

101,179 $

$ 2,464,769 $ 1,007,448 $

89,741 $

$ 2,499,449 $ 1,021,623 $

91,004 $

$ 2,215,592 $

905,600 $

80,669 $

$ 2,725,636 $ 1,114,074 $

99,239 $

$ 3,491,850 $ 1,427,256 $

127,137 $

$ 4,017,102 $ 1,641,947 $

146,261 $

$ 3,837,860 $ 1,568,684 $

139,735 $

$ 3,261,394 $ 1,333,060 $

118,746 $

$ 2,532,647 $ 1,035,192 $

92,212 $

$ 2,518,206 $ 1,029,290 $

91,687 $

$ 2,851,365 $ 1,165,465 $

103,817 $

$ 35,194,798 $ 14,385,495 $ 1,281,426 $

NWEC 43,461 $ 38,548 $ 39,090 $ 34,651 $ 42,628 $ 54,611 $ 62,826 $ 60,023 $ 51,007 $ 39,610 $ 39,384 $ 44,594 $ 550,433 $

GRE JPZ Jan-22 Feb-22 Mar-22 Apr-22 May-22 Jun-22 Jul-22 Aug-22 Sep-22 Oct-22 Nov-22 Dec-22 Total

GRE

$

323,728

$

283,301

$

314,175

$

270,871

$

260,415

$

325,306

$

423,380

$

375,797

$

283,517

$

305,863

$

323,260

$

358,303

$ 3,847,916

Total GRE Expense $ 39,042,713.77

Total Transmission Joint Zonal Expense

Net Transmission Joint Zonal

Net Transmission Joint Zonal Payment for NSP Pricing Zone Net Transmission Joint Zonal Payment for GRE Pricing Zone

$55,598,172

MMPA 97,591 $ 86,558 $ 87,776 $ 77,807 $ 95,719 $ 122,627 $ 141,073 $ 134,778 $ 114,534 $ 88,942 $ 88,435 $ 100,134 $ 1,235,973 $

MRES 131,043 $ 116,228 $ 117,864 $ 104,478 $ 128,530 $ 164,661 $ 189,430 $ 180,978 $ 153,794 $ 119,429 $ 118,748 $ 134,459 $ 1,659,640 $

$ 60,065,518
($4,467,346)
$ (5,505,069) $ 1,037,723

RPU

Total

150,798 $ 4,438,858

133,750 $ 3,937,042

135,632 $ 3,992,437

120,229 $ 3,539,026

147,906 $ 4,353,732

189,484 $ 5,577,627

217,987 $ 6,416,626

208,261 $ 6,130,317

176,979 $ 5,209,513

137,433 $ 4,045,465

136,650 $ 4,022,398

154,729 $ 4,554,562

1,909,837 $ 56,217,602

Northern States Power Company

Docket No. E002/GR-20-723 Exhibit___(IRB-1), Schedule 6
Page 3 of 3

Joint Zonal Revenues and Expenses - 2023 Budget Year

Revenue

NSP JPZ

GRE

SMMPA

Jan-23

$ 3,324,458 $

532,794 $

Feb-23

$ 2,841,125 $

486,647 $

Mar-23

$ 2,860,176 $

506,648 $

Apr-23

$ 2,516,107 $

453,475 $

May-23

$ 3,431,367 $

592,480 $

Jun-23

$ 3,781,014 $

674,175 $

Jul-23

$ 4,013,165 $

768,124 $

Aug-23

$ 3,997,478 $

694,683 $

Sep-23

$ 3,680,279 $

661,077 $

Oct-23

$ 2,590,891 $

545,477 $

Nov-23

$ 2,996,881 $

493,042 $

Dec-23

$ 3,333,160 $

526,438 $

Total

$ 39,366,100 $ 6,935,060 $

MRES 491,091 $ 454,469 $ 473,694 $ 436,251 $ 470,559 $ 523,735 $ 550,526 $ 539,934 $ 499,116 $ 453,602 $ 467,775 $ 495,076 $
5,855,828 $

Total 4,348,343 3,782,241 3,840,517 3,405,834 4,494,405 4,978,924 5,331,814 5,232,096 4,840,471 3,589,970 3,957,698 4,354,674
52,156,988

GRE JPZ Jan-23 Feb-23 Mar-23 Apr-23 May-23 Jun-23 Jul-23 Aug-23 Sep-23 Oct-23 Nov-23 Dec-23 Total

GRE

$

420,313

$

419,059

$

344,710

$

331,565

$

374,893

$

477,191

$

528,679

$

500,599

$

461,855

$

345,063

$

393,353

$

431,119

$ 5,028,398

Total GRE Revenue $ 44,394,498.76

Total Transmission Joint Zonal Revenue

Expense NSP JPZ Jan-23 Feb-23 Mar-23 Apr-23 May-23 Jun-23 Jul-23 Aug-23 Sep-23 Oct-23 Nov-23 Dec-23 Total

GRE

SMMPA

CMMPA

$ 2,862,280 $ 1,135,837 $

101,183 $

$ 2,538,698 $ 1,007,430 $

89,744 $

$ 2,574,418 $ 1,021,605 $

91,007 $

$ 2,282,047 $

905,583 $

80,671 $

$ 2,807,389 $ 1,114,054 $

99,243 $

$ 3,596,585 $ 1,427,231 $

127,141 $

$ 4,137,592 $ 1,641,918 $

146,266 $

$ 3,952,973 $ 1,568,656 $

139,740 $

$ 3,359,217 $ 1,333,036 $

118,750 $

$ 2,608,611 $ 1,035,173 $

92,216 $

$ 2,593,737 $ 1,029,271 $

91,690 $

$ 2,936,889 $ 1,165,444 $

103,820 $

$ 36,250,438 $ 14,385,237 $ 1,281,471 $

NWEC 43,446 $ 38,535 $ 39,077 $ 34,639 $ 42,613 $ 54,592 $ 62,804 $ 60,002 $ 50,989 $ 39,596 $ 39,370 $ 44,579 $ 550,243 $

GRE JPZ Jan-23 Feb-23 Mar-23 Apr-23 May-23 Jun-23 Jul-23 Aug-23 Sep-23 Oct-23 Nov-23 Dec-23 Total

GRE

$

333,440

$

291,800

$

323,600

$

278,997

$

268,228

$

335,065

$

436,082

$

387,071

$

292,023

$

315,039

$

332,957

$

369,052

$ 3,963,353

Total GRE Expense $ 40,213,791.06

Total Transmission Joint Zonal Expense

Net Transmission Joint Zonal

Net Transmission Joint Zonal Payment for NSP Pricing Zone Net Transmission Joint Zonal Payment for GRE Pricing Zone

$ 57,185,386

MMPA 97,594 $ 86,561 $ 87,778 $ 77,810 $ 95,722 $ 122,631 $ 141,077 $ 134,782 $ 114,537 $ 88,944 $ 88,437 $ 100,137 $ 1,236,010 $

MRES 131,050 $ 116,235 $ 117,870 $ 104,484 $ 128,537 $ 164,671 $ 189,441 $ 180,988 $ 153,803 $ 119,436 $ 118,755 $ 134,466 $ 1,659,736 $

$ 61,236,257
($4,050,871)
$ 52,156,988 $ 1,065,045

RPU

Total

150,792 $ 4,522,183

133,745 $ 4,010,947

135,627 $ 4,067,382

120,224 $ 3,605,459

147,901 $ 4,435,459

189,478 $ 5,682,328

217,979 $ 6,537,077

208,253 $ 6,245,394

176,972 $ 5,307,304

137,429 $ 4,121,405

136,645 $ 4,097,906

154,723 $ 4,640,059

1,909,769 $ 57,272,904