Direct Testimony and Schedules Leanna M. Chapman Before ...€¦ · In our last rate case, Docket...

Direct Testimony and Schedules Leanna M. Chapman

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-15-826 Exhibit___(LMC-1)

Property Taxes

November 2, 2015

TABLE OF CONTENTS

I. Introduction 1

II. Property Tax Expense Forecasts 9

A. Forecast Methodology 9

B. Data Inputs 15

1. Plant 15

2. Net Operating Income 15

3. DOR Capitalization Rates 16

4. DOR Weighting of Cost and Income Indicators of Value 17

5. Local Tax Rates 17

III. Historical Analysis 18

IV. Conclusion 24

Schedules

Statement of Qualifications Schedule 1

NSPM Property Taxes 2016 Schedule 2

2015 and 2016 NSPM Property Tax Comparison Schedule 3

2017 NSPM Property Tax Schedule 4

2016 and 2017 NSPM Property Tax Comparison Schedule 5

2018 NSPM Property Tax Schedule 6

2017 vs 2018 NSPM Property Tax Schedule 7

2012 – 2014 Tax Rate Comparisons

Historic Property Taxes from 2001

Schedule 8

Schedule 9

Pre-filed Discovery Appendix A

Docket No. E002/GR-15-826 Chapman Direct

i

I. INTRODUCTION 1

2

Q. PLEASE STATE YOUR NAME AND OCCUPATION. 3

A. My name is Leanna M. Chapman. I am Manager of Tax Reporting for Xcel 4

Energy Services Inc. 5

6

Q. PLEASE SUMMARIZE YOUR QUALIFICATIONS AND EXPERIENCE. 7

A. I have over 10 years of corporate tax experience, including serving as Manager 8

of Tax Reporting for Xcel Energy Services Inc. In my current position, I 9

oversee and manage the compliance, accounting, and planning responsibilities 10

associated with Xcel Energy’s property and sales/use taxes. A summary of my 11

qualifications and experience is provided as Exhibit___(LMC-1), Schedule 1. 12

13

Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS PROCEEDING? 14

A. I provide Northern States Power Company’s (NSPM or the Company) 15

property tax expense forecast for 2016, 2017, and 2018, the proposed multi-16

year rate plan period. Specifically, I discuss our overall forecast methodology 17

and the inputs we used to develop the forecasts in each year. I also provide a 18

discussion of how property taxes were treated in our last rate case, and 19

historical information related to our property taxes. 20

21

Q. BEFORE TURNING TO FORECAST DETAILS, PLEASE DISCUSS WHAT YOU BELIEVE 22

THE GOAL IS IN DETERMINING THE APPROPRIATE LEVEL OF PROPERTY TAXES 23

TO INCLUDE IN RATES. 24

A. Property taxes are a necessary cost of providing service to our customers. 25

While property taxes may fluctuate due to changes dictated by the Minnesota 26

Department of Revenue (DOR) and changes in tax rates at the local level, 27


1

increases in our property taxes are largely due to investments in our system. 1

As such, we believe rates should be set to allow the Company to recover this 2

cost of service and at the same time ensure customers pay only actual property 3

taxes incurred. 4

5

Q. THAT SOUNDS STRAIGHTFORWARD. WHY HAVE PROPERTY TAXES BEEN AN 6

ISSUE IN PREVIOUS RATE CASES? 7

A. We believe there are two reasons property taxes have been an issue in our 8

recent rate cases – timing and forecast assumptions. First, the timing of a rate 9

case does not generally match the timing of when we receive information that 10

determines our final tax bill each year. Thus the Commission is required to 11

make a decision about property taxes to be included in rates before we receive 12

key pieces of information that can significantly affect the calculation – namely, 13

the final DOR valuation and local tax rates. 14

15

Second, we acknowledge that in the past we have used a conservative 16

approach in forecasting, and our property tax forecasts have been higher than 17

actuals in a number of years. We understand this is a concern when we 18

request that rates be set using a forecasted level of property taxes. 19

20

Q. WHAT HAVE YOU DONE TO ADDRESS THESE ISSUES IN THIS CASE? 21

A. We have attempted to resolve these issues first by using different inputs for 22

some variables in our forecasting calculation. Using these inputs produces a 23

lower property tax forecast compared to what it would have been using the 24

approach we used in the past. Second, while we are requesting that the 25

Commission approve these forecasted amounts for inclusion in rates, we are 26

also proposing a true-up mechanism that will ensure customers pay only actual 27


2

property taxes incurred. In our most recent rate case, where actual property 1

taxes were lower than what we had forecasted, we used a similar mechanism 2

and we were able to reflect the lower actual property tax amounts through an 3

interim rate refund and lower final rates. We believe this worked well in our 4

last rate case, and we are proposing similar treatment of property taxes in this 5

case. I provide further detail about what occurred and how property taxes 6

were treated in our last rate case in Section III of my testimony. 7

8

Q. WHAT ARE THE COMPANY’S FORECASTED PROPERTY TAX EXPENSE AMOUNTS 9

FOR THE MULTI-YEAR RATE PLAN PERIOD? 10

A. Our 2016-2018 total Company property tax forecasts, by state taxing 11

jurisdiction, are shown in Table 1 below. For comparison purposes, Table 1 12

also shows our actual 2014 property taxes and our current 2015 forecast. 13

Table 1 also provides this information at the Minnesota electric jurisdictional 14

level. Company witnesses Ms. Anne E. Heuer and Mr. Charles R. Burdick 15

provide support for the Minnesota electric jurisdiction property tax expense 16

amounts. Detailed calculations of the total Company property tax expense for 17

2016-2018 are provided in Exhibit___(LMC-1), Schedules 2 through 7. 18

Table 1 19 Forecasted NSPM Property Tax Expense 20

($ Million) 21 22

23

24

25

26

27

28

Component 2014 Actual

2015 Forecast

2016 Forecast

2017 Forecast

2018 Forecast

Minnesota Taxing Jurisdiction $179.9 $197.5 $225.8 $237.3 $245.6

North Dakota Taxing Jurisdiction $2.8 $3.2 $4.2 $5.1 $5.1

South Dakota Taxing Jurisdiction $3.5 $3.7 $3.8 $3.8 $3.8

Total Company $186.2 $204.4 $233.8 $246.2 $254.5

MN Electric Jurisdiction $133.9 $147.7 $168.3 $176.8 $182.6


3

Since Minnesota taxes account for over 96 percent of the total Company 1

property taxes, the discussion in my testimony focuses on the Minnesota 2

taxing jurisdiction. In addition, unless noted otherwise, the numbers I provide 3

are for both electric and gas, consistent with how we estimate property taxes 4

for financial statement purposes. 5

6

Q. YOU MENTIONED THESE FORECAST AMOUNTS WERE DEVELOPED USING A 7

DIFFERENT APPROACH THAN THE COMPANY HAS USED IN PRIOR RATE CASES. 8

PLEASE ELABORATE. 9

A. While our overall forecasting approach is the same, based on our experience 10

and comments of the Minnesota Department of Commerce (Department) in 11

our last rate case, we are using different data inputs for some of the variables 12

in our property tax forecast calculation. Specifically, our forecasts in this case 13

reflect the most recent actual Minnesota DOR valuation inputs, which were 14

finalized in July 2015. We believe making this change may resolve some of the 15

issues that arose in our last rate case. 16

17

Q. PLEASE DESCRIBE THIS CHANGE AND THE EFFECT IT HAS ON THE COMPANY’S 18

FORECASTED PROPERTY TAX EXPENSE IN THIS CASE. 19

A. In prior rate cases, due to uncertainty about the DOR’s position in our final 20

valuation, we used a more conservative forecasting approach that reflected 21

projected or default values for the DOR valuation inputs. While the DOR’s 22

final valuation remains uncertain from year to year, some of the valuation 23

inputs appear to have stabilized. As a result, we believe forecasting property 24

taxes using the actual DOR valuation inputs received in 2015 is appropriate. 25

Using the most recent actual DOR valuation inputs reduces our forecasted 26

property tax expense amounts in this case compared to what they would have 27


4

been under the more conservative approach we used in prior cases. Table 2 1

below shows our 2016-2018 forecasted property tax expense in this case 2

compared to what the amounts would have been had we continued to use the 3

more conservative approach we used in prior cases. 4

Table 2 5 Forecasted NSPM Property Tax Expense 6

($ Million) 7 8 9 10 11 12

13

14

I discuss the DOR valuation inputs further in Section II.B. of my testimony. 15

In addition, I provide a historical analysis of our property taxes, including 16

further discussion of the change in forecasting inputs since our last rate case, 17

in Section III. 18

19

Q. WHAT WAS THE COMMISSION’S DECISION RELATED TO PROPERTY TAXES IN 20

YOUR LAST RATE CASE? 21

A. In our last rate case, Docket No. E002/GR-13-868, the Commission 22

approved $137 million in property taxes for 2014, with an incremental amount 23

of $4 million related to capital projects approved for recovery in the 2015 step 24

year. The Commission also required an annual compliance filing to show 25

actual property taxes and provide customer refunds if necessary. Our June 30, 26

2015 compliance filing in that docket showed final 2014 property taxes of 27

$133.9 million, $3.1 million less than the amount approved in rates. Rather 28

than providing a customer refund, the timing in that case allowed us to 29

incorporate the lower 2014 property tax amount when implementing final 30

2016

Forecast

2017

Forecast

2018

Forecast

Forecast in Current Case $233.8 $246.2 $254.5

Forecast Under Method Used in Prior Case $245.1 $257.4 $267.3

Difference between Current and Prior Method ($11.3) ($11.2) ($12.8)


5

rates for 2014 and 2015. I provide additional discussion of our last case in 1

Section III. 2

3

Q. HOW DO THE 2016-2018 FORECASTED PROPERTY TAX AMOUNTS COMPARE 4

WITH THE LEVEL OF PROPERTY TAXES APPROVED BY THE COMMISSION AND 5

INCLUDED IN RATES? 6

A. Tables 3 and 4 below make two comparisons. First, Table 3 shows the 7

property tax expense currently included in rates for 2014 and 2015 compared 8

to the jurisdictionalized 2016-2018 forecasted amounts. We note that the 9

large increase (approximately $30 million) between 2015 and 2016 reflects the 10

fact that only a small portion of our property taxes in 2015 (associated with 11

the approved capital step projects for 2015) was approved for recovery in 12

rates. 13

Table 3 14 NSPM Jurisdictionalized Property Tax Expense 15

($ Million) 16 17 18 19

20

21 22

Second, Table 4 shows our 2016-2018 forecasts compared to 2014 actuals and 23

our full, current 2015 forecasted amount. Compared to our current 2015 24

forecast, the increase in forecasted property tax expense in 2016 is $19.3 25

million on a jurisdictional basis. As shown in Exhibit___(LMC-1), Schedule 3, 26

the Minnesota taxing jurisdiction accounts for virtually all of the year-to-year 27

increases in property taxes. 28

29

2014 In Rates

2015 In Rates

2016 Forecast

2017 Forecast

2018 Forecast

Property Tax Expense $133.9 $137.9 $168.3 $176.8 $182.6

Increase over Previous Year $4 $30.4 $8.5 $5.8


6

Table 4 1 NSPM Jurisdictionalized Property Tax Expense 2

($ Million) 3 4 5

6

7

8

Q. IS THE COMPANY SEEKING TO RECOVER PROPERTY TAXES AS PART OF ITS 9

MULTI-YEAR RATE PLAN PROPOSAL? 10

A. Yes. Company witness Ms. Anne E. Heuer has incorporated the 2016 11

forecasted amount into the 2016 revenue requirements, and Company witness 12

Mr. Charles R. Burdick has incorporated the 2017 and 2018 forecasted 13

amounts into the multi-year rate plan revenue requirements. As I mentioned 14

earlier, we also propose an annual compliance filing and true-up that would 15

allow rates to reflect actual property taxes for each year. 16

17

Q. WHY IS THE COMPANY INCLUDING FORECASTED PROPERTY TAX AMOUNTS IN 18

THE 2017 AND 2018 REVENUE REQUIREMENTS WHEN THE COMPANY IS 19

PROPOSING TO USE ESCALATION INDICES TO ESTABLISH EXPENSE LEVELS FOR 20

OTHER OPERATIONS AND MAINTENANCE (O&M) COSTS IN THE 2017 AND 21

2018 PLAN YEARS? 22

A. Property taxes are essentially a capital related cost of service, and our 23

investments are the biggest driver of increases in our property taxes. In fact, 24

the only data inputs that change in forecasting property taxes for 2017 and 25

2018 in this case are the investment forecast components. Under this 26

forecasting approach, the incremental increases in 2017 and 2018 can be 27

attributed to our forecasted additional investment. Finally, we believe 28

2014 Actual

2015 Forecast

2016 Forecast

2017 Forecast

2018 Forecast

Property Tax Expense $133.9 $147.7 $168.3 $176.8 $182.6

Increase over Previous Year $13.8 $20.6 $8.5 $5.8


7

including forecasted property tax amounts in rates for 2017 and 2018 is 1

appropriate because we are also proposing a true-up mechanism that would 2

reflect actual property taxes for each year. 3

4

Q. PLEASE DESCRIBE THE COMPANY’S PROPOSED TRUE-UP MECHANISM. 5

A. Given the expected procedural schedule for this case, we believe it will be 6

possible to reflect actual property taxes for 2016 in final rates, while 2017 and 7

2018 rates would include forecasted property tax amounts. We propose to 8

submit annual compliance filings that will show actual property taxes for 2017 9

and 2018 once they are finalized. Any over-recovery could be refunded, or 10

any under-recovery could be charged, through an appropriate mechanism at 11

that time. I discuss our proposal for an annual compliance filing and true-up 12

more specifically in Section II below, where I present the property tax 13

information timeline in more detail. 14

15

Q. IF SUCH A SYMMETRICAL TRUE-UP IS NOT ADOPTED, WHAT DO YOU 16

RECOMMEND? 17

A. For the reasons discussed in detail in my testimony, I believe a symmetrical 18

true-up is reasonable and fair to both customers and the Company. However, 19

if the Commission does not agree with that approach, I believe the forecasted 20

property tax levels I have presented should be used for the purpose of setting 21

rates. These forecasts represent the most accurate information available at 22

this time. 23

24

Q. HOW IS YOUR TESTIMONY ORGANIZED? 25

A. I present the remainder of my testimony in the following sections: 26

• Section II: Property Tax Expense Forecasts; 27


8

• Section III: Historical Analysis; and 1

• Section IV: Conclusion. 2

3

Q. DO YOU PROVIDE ANY ADDITIONAL INFORMATION RELATED TO PROPERTY 4

TAXES? 5

A. Yes. Appendix A provides a list of relevant information requests from the 6

12-961 and 13-868 rate cases that I have already responded to in this case 7

(with new time frames as appropriate to reflect the November 2, 2015 filing 8

date of this case), indicating where the responsive information is included in 9

my testimony or schedules, or if it is provided in Appendix A. 10

11

II. PROPERTY TAX EXPENSE FORECASTS 12

13

A. Forecast Methodology 14

Q. PLEASE DESCRIBE HOW UTILITY PROPERTY IS VALUED AND TAXED IN 15

MINNESOTA. 16

A. Utility property taxes are based on the value of the Company’s real and 17

personal property, the class rate, and local tax rates. Most of our property is 18

valued by the DOR as a unit, with land and certain buildings valued by local 19

taxing jurisdictions. Our DOR unit value is apportioned to each local taxing 20

jurisdiction. Local jurisdictions then combine the value of our locally assessed 21

property with their apportioned share of the DOR value to set our overall 22

market value. Our overall market value is multiplied by the applicable class 23

rate to determine tax capacity, which is then multiplied by the local tax rate to 24

arrive at our property tax liability. 25

26


9

Q. GIVEN THIS PROCESS, HOW DOES THE COMPANY FORECAST ITS PROPERTY 1

TAXES? 2

A. We forecast property taxes based on the same key variables used in prior rate 3

cases, such as investments, DOR valuation inputs, and effective tax rate. We 4

also propose to update our property tax forecasts to incorporate actual 5

information on an annual basis. As I noted earlier, we propose to provide an 6

annual compliance filing showing actual property taxes once finalized. This 7

would be submitted in June of each year showing the actual property taxes for 8

the prior year. 9

10

Q. WHAT DATA INPUTS DID THE COMPANY USE TO DEVELOP ITS 2016 PROPERTY 11

TAX FORECAST? 12

A. Our current 2016 property tax forecast is based on the data shown in Table 5 13

below. 14

Table 5 15 Inputs to 2016 Property Tax Forecast 16

17 18 19 20 21 22 23

24

25

26

Q. DID THE COMPANY USE SIMILAR VARIABLES IN ITS 2014 RATE CASE 27

APPLICATION? 28

A. Yes. We used the same variables in our last rate case application. 29

Category Variable Data Inputs

Investments Plant Projected December 31, 2015 Plant Balances

Net Operating Income Actual 2014 and Projected 2015 Net Operating Income

DOR Valuation Inputs

DOR Capitalization Rates

Actual 2015 DOR Capitalization Rates (Received June 2015)

DOR Weighting of Indicators of Value

Actual 2015 DOR Weighting (Received July 2015)

Effective Tax Rate Local Tax Rates 2014 Effective Rate

(Received March and April 2015)


10

Q. YOU MENTIONED EARLIER THAT SOME OF THE DATA INPUTS USED IN THIS 1

CASE HAVE CHANGED COMPARED TO THE LAST CASE. WHICH DATA INPUTS 2

ARE DIFFERENT? 3

A. Our forecast in this case reflects the most recent actual data and calculation 4

methodologies from the DOR for three data inputs: Net Operating Income, 5

DOR Capitalization Rates, and DOR Weighting of Indicators of Value. Our 6

forecast also reflects the most recent effective tax rate. I will discuss details 7

related to each of these in Section B below. 8

9

Q. ARE THESE DATA INPUTS THE MOST APPROPRIATE TO USE IN FORECASTING 10

THE 2016 PROPERTY TAX EXPENSE? 11

A. Yes. The information in Table 5 represents the most current information 12

available at this time and results in a reasonable and sound forecast of the 13

2016 property tax expense. 14

15

Q. IN THIS CASE YOU PROVIDE PROPERTY TAX FORECASTS FOR 2017 AND 2018 AS 16

WELL. WHICH OF THE DATA INPUTS CHANGE IN THE FORECAST CALCULATION 17

FOR THOSE YEARS? 18

A. The only data inputs that change in forecasting property taxes for 2017 and 19

2018 are the investment forecast component. We update these inputs because 20

we have projected plant balances and net operating income projections for 21

2017 and 2018, and it is reasonable to update our forecast to include that 22

information. 23

24

The 2017 and 2018 forecasts, however, use the same DOR valuation inputs 25

and effective tax rate shown in Table 5. The DOR and local taxing authorities 26

control these variables and can make different decisions that affect these 27


11

inputs every year. As such, we do not forecast these inputs. We believe using 1

the most recent, actual information available at this time, as shown in Table 5, 2

is appropriate for our 2017 and 2018 forecasts. 3

Q. YOU MENTIONED EARLIER THAT THE COMPANY UPDATES ITS INTERNAL 4

PROPERTY TAX FORECASTS AS VARIOUS INFORMATION IS RECEIVED DURING 5

THE YEAR. WHEN DOES THE COMPANY RECEIVE SUCH INFORMATION? 6

A. Figure 1 below shows when we will receive information regarding our 2016 7

property taxes in 2016 and 2017. This schedule is the same every year, so can 8

be applied to information we will receive related to 2017 and 2018 property 9

taxes as well. 10

Figure 1 11 2016 Property Tax Timeline 12

13 Q. THE COMPANY HAS INCORPORATED SOME UPDATED INFORMATION INTO ITS 14

FORECASTS AT VARIOUS TIMES DURING THE COURSE OF SOME PRIOR RATE CASE 15

PROCEEDINGS. PLEASE EXPLAIN HOW THE COMPANY PROPOSES TO UPDATE 16

ITS FORECASTS IN THIS CASE. 17

A. We propose to submit updated information in an annual filing once property 18

taxes for a given year are final. For example, our first update would be filed 19

after we receive 2016 property tax statements in the spring of 2017. That 20


12

filing would include final property tax amounts for 2016. Given the expected 1

schedule for this case, we believe the final 2016 property tax amounts could be 2

incorporated into final rates, the same way we were able to incorporate final 3

2014 property taxes in our last rate case. Because we would have the updated 4

actual 2016 DOR valuation inputs and actual effective tax rate at that time, we 5

would also provide updated 2017 and 2018 forecasts in that filing to 6

incorporate those inputs. We would file our next update after we receive final 7

2017 property tax information in the spring of 2018. 8

9

Q. GIVEN THE PROCEDURAL TIMELINE FOR THIS CASE, WHAT LEVEL OF 10

PROPERTY TAXES WOULD BE INCLUDED IN RATES FOR 2017 AND 2018? 11

A. The level of property taxes included in rates for 2017 and 2018 would depend 12

on the timing of the Commission’s final decision in this case, but would use 13

the forecasted property taxes based on the most recent data inputs available at 14

the time the Commission makes its decision. In this case, we believe that 15

could be the forecasts included in our spring 2017 compliance filing. 16

17

Q. PLEASE EXPLAIN HOW YOUR PROPOSAL FOR AN ANNUAL COMPLIANCE FILING 18

AND TRUE-UP MECHANISM WOULD WORK FOR 2017 AND 2018 PROPERTY 19

TAXES. 20

A. We propose to submit annual compliance filings that will show actual property 21

taxes for 2017 and 2018 after we receive final property tax statements in the 22

spring of the following years. Our compliance filings would show actual 23

property taxes compared to the amount included in rates for the respective 24

year. Any over-recovery could be refunded – or symmetrically, any under-25

recovery could be charged – through an appropriate mechanism at that time. 26

27


13

Q. IN YOUR LAST RATE CASE, THE COMMISSION APPROVED IN RATES A 1

FORECASTED LEVEL OF PROPERTY TAXES FOR 2014 AND REQUIRED A 2

CUSTOMER REFUND IF ACTUAL PROPERTY TAXES WERE LESS THAN 3

FORECASTED. WHY DO YOU BELIEVE A TRUE-UP MECHANISM, RATHER THAN 4

SIMPLY A REFUND PROVISION, IS APPROPRIATE IN THIS CASE? 5

A. In the past, due to the uncertainty and year-to-year variability of some DOR 6

valuation inputs, we used a more conservative forecasting approach. As a 7

result, there were concerns about our property tax forecast being too high, 8

which resulted in the property tax refund provision included in our last rate 9

case. Since then, we have made changes to some of the data inputs used in 10

our forecasts. Overall, these changes result in property tax forecasts in this 11

case that are lower than what they would have been using the more 12

conservative approach we used in the past. 13

14

Because our property tax forecasts in this case are lower, and there is still 15

uncertainty about final DOR valuations each year, final property taxes could 16

be higher or lower than our forecasts. Thus, we believe a symmetrical true-up 17

mechanism is appropriate in this case. A true-up mechanism that reflects 18

actual property taxes in a given year – either higher or lower than what is 19

approved for inclusion in rates – allows the Company to recovery this cost of 20

providing service and at the same time ensures customers only pay actual 21

property tax amounts for a given year. 22

23

B. Data Inputs 24

1. Plant 25

Q. WHAT PLANT DATA DID THE COMPANY USE IN ITS 2016, 2017 AND 2018 26

PROPERTY TAX FORECASTS? 27


14

A. Our current 2016 property tax forecast is based upon our current projection 1

of December 31, 2015 plant balances. The Company’s final 2016 property tax 2

expense will be based on the final December 31, 2015 plant balances. 3

Similarly, the 2017 and 2018 property tax forecasts are based upon our current 4

projections of December 31, 2017 and 2018 plant balances, respectively, and 5

final property taxes for those years will be based on the final plant balances as 6

of December 31 each year. 7

8

2. Net Operating Income 9

Q. WHAT NET OPERATING INCOME DATA DID THE COMPANY USE IN ITS 2016, 10

2017 AND 2018 PROPERTY TAX FORECASTS? 11

A. Our current 2016 property tax forecast is based upon actual 2014 net 12

operating income and our current projection of 2015 net operating income. 13

The Company’s final 2016 property tax expense will be based upon actual 14

2014 and 2015 net operating income. The calculation method for net 15

operating income is dictated by the DOR. The DOR used a two-year 16

weighted average method for 2015 property taxes, which was a deviation from 17

the three-year weighted average method used in prior years and included in 18

our forecast methodology in our last rate case. We use the two-year weighted 19

method in our 2016-2018 property tax forecasts. 20

21

Our 2017 net operating income is based on projected 2015 and 2016 net 22

operating income. Final 2017 net operating income will be based on actual 23

2015 and 2016 net operating income. 24

25


15

Following the same process, 2018 net operating income is based on projected 1

2016 and 2017 net operating income. Final 2018 net operating income will be 2

based on actual 2016 and 2017 net operating income. 3

4

3. DOR Capitalization Rates 5

Q. WHAT DOR CAPITALIZATION RATES DID THE COMPANY USE IN ITS 2016, 2017 6

AND 2018 PROPERTY TAX FORECASTS? 7

A. Our 2016, 2017 and 2018 property tax forecasts are based on the most recent 8

actual information available, which are the actual DOR capitalization rates we 9

received in 2015. Final property taxes will be based on the DOR’s final 10

capitalization rates for each year. 11

12

Use of the most recent actual DOR capitalization rates is a deviation from the 13

methodology we employed in our last rate case, where we used a projected 14

value for DOR capitalization rates. We believe use of the 2015 actual 15

capitalization rates is appropriate because it is the most recent actual 16

information available. 17

18

4. DOR Weighting of Cost and Income Indicators of Value 19

Q. WHAT WEIGHTING OF THE COST AND INCOME INDICATORS OF VALUE DID THE 20

COMPANY USE IN ITS 2016, 2017, AND 2018 PROPERTY TAX FORECASTS? 21

A. Our 2016, 2017, and 2018 property tax forecasts are based on the most recent 22

actual information available, which are the actual DOR weightings of the cost 23

and income indicators of value we received in 2015. Final property taxes will 24

be based on the DOR’s weightings for each specific year. 25

26


16

Because the DOR reviews and may adjust these weightings every year, and 1

prior years’ weightings do not dictate the DOR’s decision in any year, in 2

previous rate cases we incorporated the more conservative default equal 3

weightings into our property tax forecast. Use of the most recent actual DOR 4

weightings is a deviation from the methodology we employed in our last rate 5

case. However, the DOR has deviated from the default weightings in recent 6

years, and we believe using the most recent weightings provides a reasonable 7

property tax forecast. We believe use of the 2015 actual weightings of the cost 8

and income indicator of value is appropriate because it is the most recent 9

actual information available. 10

11

5. Local Tax Rates 12

Q. WHAT LOCAL TAX RATES DID THE COMPANY USE IN ITS 2016, 2017 AND 2018 13

PROPERTY TAX FORECAST? 14

A. Our current forecast of the 2016, 2017 and 2018 property tax expense is based 15

upon 2014 local tax rates. The local tax rates are mathematically converted 16

into an effective tax rate as provided in Exhibit___(LMC-1), Schedule 8. This 17

is the most accurate recent tax rate data available at this time. Specifically, the 18

effective tax rate used in our forecasts is based upon 2014 final tax statements 19

received in March and April 2015. Final 2016, 2017 and 2018 property taxes 20

will be based on the final statements received in March and April of the 21

following year. 22

23

III. HISTORICAL ANALYSIS 24

25

Q. WHAT IS DRIVING THE INCREASE IN 2016 MINNESOTA PROPERTY TAXES FROM 26

THE 2015 LEVELS? 27


17

A. As described above, the Company’s property tax expense is a function of 1

three primary variables: investments; DOR valuation inputs; and local 2

property tax rates. The increase in our forecasted 2016 Minnesota taxing 3

jurisdiction property tax expense is driven by the investment variable. For 4

example, our 2016 property tax forecast includes over $1.3 billion in additional 5

taxable property and over $55 million in additional net operating income. 6

Schedule 3 compares our 2016 forecast to 2015 property tax expense. 7

8

Q. WHAT IS DRIVING THE INCREASE IN 2017 AND 2018 MINNESOTA PROPERTY 9

TAXES? 10

A. Like the change between 2015 and 2016, the increase in 2017 and 2018 11

property taxes is driven by the investment variable. Schedules 5 and 7 show 12

how our additional investments impact the 2017 and 2018 forecasts. 13

14

Q. ARE THE FORECASTED INCREASES IN 2016, 2017 AND 2018 MINNESOTA 15

PROPERTY TAXES CONSISTENT WITH PAST INCREASES IN MINNESOTA 16

PROPERTY TAXES? 17

A. Yes. As Minnesota taxes account for over 96 percent of total Company 18

property taxes, Figure 2 below shows NSPM property taxes for the Minnesota 19

taxing jurisdiction for 2001 through 2018. As shown, property taxes have 20

increased significantly each year since 2010. 21


18

Figure 2 1 NSPM Minnesota Taxing Jurisdiction Property Taxes 2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

Exhibit___(LMC-1), Schedule 9 shows the Company’s property taxes since 18

2001. 19

20

Q. PROPERTY TAXES APPROVED BY THE COMMISSION FOR INCLUSION IN RATES 21

WERE BASED ON A 2014 FORECASTED AMOUNT. PLEASE DISCUSS IN DETAIL 22

WHAT OCCURRED IN THE LAST RATE CASE. 23

A. Table 6 below shows the changes in our property tax forecast for 2014 during 24

the course of our last rate case, and shows the final amounts approved by the 25

Commission for 2014 and 2015. 26

27 28

$105 $108 $111 $124

$135

$162 $166 $180

$198

$226 $237

$245

$0

$50

$100

$150

$200

$250

2007 2008 2009 2010 2011 2012 2013 2014 2015* 2016* 2017* 2018*

($ M

illio

ns)

* Forecast


19

Table 6 1 Minnesota Electric Jurisdiction Property Taxes 2

Docket No. E002/GR-13-868 3 4 5 6 7 8 9 10 11

In our last rate case, we proposed 2014 rates to include property tax amounts 12

based on our 2014 forecast of $150 million on a Minnesota electric 13

jurisdictional basis. The Company agreed to the Department’s proposed $9 14

million reduction in 2014 property tax expense to $141 million, subject to a 15

true-up capped at $145 million. In January 2015, we updated our 2014 test 16

year property taxes to be $137 million based on Truth in Taxation notices 17

received in December 2014. 18

19

The Commission approved the $137 million to be included in 2014 rates, with 20

an incremental increase of $4 million related to capital projects approved for 21

recovery in the 2015 step year. The Commission also approved a refund 22

mechanism if the amount on the final 2014 property tax statements were less 23

than the amount included in rates. In that case, we would make ongoing 24

annual refunds of the difference (on a Minnesota electric jurisdictional basis) 25

until filing our next rate case. 26

27

Final 2014 property taxes shown on the property tax statements in March 28

2015 were $133.9 million on a Minnesota electric jurisdictional basis, or $3.1 29

2014 2015

Initial Forecast $150 ---

Updated Forecast (DOR Valuation) $141 ---

Updated Forecast (Year End Tax Rates) $137 ---

Actual Amount (Final Tax Statements) $133.9 ---

Included In Rates $133.9 $137.9


20

million less than the amount reflected in rates. The decrease from the estimate 1

based on December 2014 Truth in Taxation notices to the final property tax 2

statements was due to a slight overall decrease in local tax rates, with changes 3

to market value exclusions also having a very minor impact. In its June 30, 4

2015 compliance filing, the Company proposed to incorporate the lower 5

amount into the 2014 and 2015 revenue requirement calculations, resulting in 6

a slightly higher 2014 interim refund and through the setting of final rates, 7

eliminating the need for a separate property tax refund. 8

9

Q. WHAT DROVE THE $9 MILLION REDUCTION THE COMPANY AGREED TO IN 10

THAT CASE? 11

A. During the course of that proceeding, we received the final DOR valuation for 12

2014 which was lower than the value used to forecast property taxes in the 13

2014 rate case. The primary driver of that reduction was the final DOR 14

weighting of the cost and income indicators of value. Rather than the 50/50 15

default weightings used in our forecast in that case, the DOR adjusted the 16

Company’s weightings of the cost indicator of value and the income indicator 17

of value to be 35 percent and 65 percent, respectively. 18

19

Q. DO YOU EXPECT A SIMILAR REDUCTION TO THE 2016-2018 PROPERTY TAX 20

FORECASTS PRESENTED IN THIS CASE? 21

A. No. Our forecasts in this case are based on the most recent actual DOR 22

weightings of 35 percent and 65 percent. Using this data input up front 23

results in a lower property tax forecast. 24

25


21

Q. WHY DID YOU MAKE THE CHANGE USE THE MOST RECENT ACTUAL DOR 1

WEIGHTINGS IN THIS CASE? 2

A. The DOR is authorized to alter the default weightings.1 We meet with the 3

DOR each year and advocate for increased weighting of the income indicator 4

of value. Table 7 below shows the final DOR weighting for the past five 5

years. Although the DOR weightings can change every year, based on the 6

recent stability of these inputs, we expect similar weightings going forward. 7

Thus, we believe using the most recent actual weightings results in an accurate 8

forecast. 9

Table 7 10 Historical DOR Weightings of the 11

Cost and Income Indicators of Value 12 13 14 15 16 17 18 19 20 21

22

Q. IS THERE ANY OTHER CHANGE RELATED TO DOR VALUATION YOU WOULD 23

LIKE TO HIGHLIGHT? 24

A. Yes. For 2014, the DOR changed the way it calculates the Company’s net 25

operating income. 26

27

1 Minn. R. 8100.0300, subp. 4a, part B.

Year Electric

Cost Indicator

Income Indicator

2011 45% 55%

2012 45% 55%

2013 35% 65%

2014 35% 65%

2015 35% 65%


22

Q. PLEASE DESCRIBE THIS CHANGE AND THE EFFECT IT HAS ON THE COMPANY’S 1

PROPERTY TAXES. 2

A. Previously, the DOR calculated our net operating income (NOI) using a 3

weighted three-year average, reflecting a 25/35/40 percent weighting with 40 4

percent weight being given to the most recent year. For 2014, the DOR used 5

a weighted two-year average, reflecting a 40/60 percent weighting with 60 6

percent weight begin given to the most recent year. In our current period of 7

high investment, use of the two-year average results in higher property taxes 8

for the Company. Table 8 below shows the NOI calculations for the past five 9

years. 10

Table 8 11 Historical DOR Weightings of Net Operating Income 12

13 14 15 16 17 18 19 20 21 22

Q. IS IT APPROPRIATE TO INCORPORATE THIS METHOD OF CALCULATION INTO 23

COMPANY’S PROPERTY TAX FORECASTS? 24

A. Yes. Using the DOR 2015 NOI calculation method reflects the most recent 25

actual information available, and we expect the DOR will continue to use this 26

method of calculation for the Company’s NOI going forward. 27

28

Year Electric

Prior Year 1

Prior Year 2

Prior Year 3

2011 40% 35% 25%

2012 40% 35% 25%

2013 40% 35% 25%

2014 40% 35% 25%

2015 60% 40% 0%


23

IV. CONCLUSION 1

2

Q. PLEASE SUMMARIZE YOUR TESTIMONY. 3

A. The forecasted 2016, 2017 and 2018 total Company property tax expense is 4

$233.7 million, $246.2 million and $254.0 million, respectively. Forecasted 5

property taxes are increasing due to ongoing system investments and represent 6

a continuation of recent increases. 7

8

Our forecasts in this case reflect different data inputs for some variables, 9

namely the actual DOR valuation inputs and local tax rates received in 2015. 10

Using the most recent actual DOR valuation inputs reduces our forecasted 11

property tax expense amounts in this case compared to what they would have 12

been under the more conservative approach we used in prior cases. We 13

believe using the actual 2015 DOR valuation inputs and local tax rates results 14

in accurate forecasts. 15

16

The Company is seeking recovery of property taxes as part of its multi-year 17

rate plan, with rates that include forecasted property tax amounts. The 18

Company is also proposing an annual compliance filing and true-up 19

mechanism that would reflect actual property taxes in a given year. This 20

approach would allow the Company to recovery this cost of providing service 21

and at the same time ensure that customers only pay actual property tax 22

amounts for a given year. 23

24

Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY? 25

A. Yes, it does. 26


24

Northern States Power Company Docket No. E002/GR-15-826 Exhibit__(LMC-1), Schedule 1

Page 1 of 1

Statement of Qualifications Leanna M. Chapman

Current Responsibilities

As Manager, Tax Reporting , I oversee and manage the compliance, accounting, and planning responsibilities associated with Xcel Energy’s property and sales/use taxes.

Experience

2008 – Present Xcel Energy Inc. Manager, Tax Reporting

2004 – 2008 Deloitte & Touche LLP Lead Audit Senior

Education

2003 Master of Accountancy University of South Dakota

2003 Bachelor of Science – Business Administration University of South Dakota

Docket No. E002/GR-15-826Exhibit____(LMC-1), Schedule 2

Page 1 of 2

Northern States Power CompanyTotal Company Property Taxes

Electric GasSYSTEM UNIT VALUE CALCULATION

Plant In Service, 12/31/15 Forecast 17,149,342,643 1,333,020,462CWIP, 12/31/15 Forecast 607,258,386 11,349,113Depreciation, 12/31/15 Forecast (6,114,339,627) (612,321,495)Cost Indicator of Value A $11,642,261,401 $732,048,080

Income Indicator2013 NOI x 25% or 0% 0 10,353,1012014 NOI x 35% or 40% 199,663,578 16,353,6122015 Estimated NOI x 40% or 60% 341,821,336 20,096,800

NOI to Capitalize $541,484,914 $46,803,513Capitalization Rate 7.40% 7.30%

Income Indicator of Value B $7,317,363,697 $641,144,010

Apply Weightings 35/65 50/50Cost Indicator $4,074,791,500 $366,024,000Income Indicator $4,756,286,400 $320,572,000

Total System Unit Value C $8,831,077,900 $686,596,000

ALLOCATION OF SYSTEM VALUEMN Plant in Service 16,389,639,716 1,221,353,186System Plant in Service 17,756,601,028 1,344,369,575Plant Ratio x 90%-Elec / x 75%-Gas 83.07% 68.14%MN Gross Revenue 3,731,409,068 674,888,573System Gross Revenue 4,239,532,104 762,665,589Revenue Ratio x 10%-Elec / x 25%-Gas 8.80% 22.12%

MN Allocated Value Percentage 91.87% 90.26%MN Allocated Value D $8,113,111,300 $619,721,500

Depreciable Plant Deductions 2,154,609,249 58,486,056Land 180,216,966 3,393,588CWIP 335,287,463 6,124,597Other - Held for Future Use 0 0Subtotal 2,670,113,678 68,004,241Ratio - System Unit Value / Cost Indicator 75.85% 93.79%

DEDUCTIONS TO MN ALLOCATED VALUE $2,025,281,200 $63,781,200Sliding Scale Market Value Exclusion $200,000,000 $0

DEDUCT/EXCL TO MN ALLOCATED VALUE E $2,225,281,200 $63,781,200Apportionable Market Value $5,887,830,100 $555,940,300Effective Tax Rate 3.3% 3.3%FORECASTED PROPERTY TAX - Elec & Gas $194,298,393 $18,346,030

Rounded $194,300,000 $18,300,000Total Electric & Gas $212,600,000Locally Assessed $11,100,000Wind Production $2,100,000

TOTAL MINNESOTA FORECASTED PROPERTY TAX $225,800,000

North Dakota & South Dakota Property Tax $8,000,000

TOTAL NSPM FORECASTED PROPERTY TAX $233,800,000

2016 FTY

Northern States Power Company Docket No. E002/GR-15-826Exhibit____(LMC-1), Schedule 2

Page 2 of 2

Support for the Calculation of Minnesota Apportionable Market Value

A

B

C

D

E

The cost factor to be considered in the utility valuation formula is the original cost less depreciation of the system plant, plusthe cost of improvements to the system plant, plus the original cost of all types of construction work in progress that areinstalled by the assessment date, plus the cost of property held for future use, plus the cost of contributions in aid ofconstruction.

Minn. R. 8100.0300, subp. 3 describes in part the cost indicator of value as:

Minn. R. 8100.0100, subp. 9 defines net operating earnings as follows:Net operating earnings” means earnings from the system plant of the utility after the deduction of operating expenses,depreciation, and taxes, but before any deduction for interest.

Minn. R. 8100.0300, subp. 4, explains the process for calculating the income indicator of value:The income indicator of value is estimated by weighting the capitalized net operating earnings of the utility company for themost recent three years as follows: most recent year, 40 percent; previous year, 35 percent; and final year, 25 percent.Utilities may request the removal of nonrecurring items of income or expense. The commissioner must determine if removalof the item is appropriate. The net income is capitalized by applying a capitalization rate that is computed by using the bandof investment method. This method considers:

Minn. R. 8100.0100, subp. 5, defines capitalization rate as:“Capitalization rate” means the relationship of income to capital investment or value, expressed as a percentage.

A. the capital structure of utilities;B. the cost of debt or interest rate;C. the yield on preferred stock of utilities;D. the yield on common stock of utilities; andE. the risk-free rate, relative risk, and risk premiums for public utility companies.

Capitalization rates are computed each year for electric companies, gas distribution companies, natural gas transmissionsystems, and fluid pipeline companies. The rates are recalculated each year using the method described in this subpart.

Minn. R. 8100.0300, subp. 5, explains the process for calculating the system unit value:

The allocation of value of gas distribution companies must be made considering the same factors as are used to determinethe allocation of value of electric companies. The weight given to the original cost factor is 75 percent, and gross revenue isweighted 25 percent.

Minn. R. 8100.0400, subp. 3, explains the process for calculating the allocation of gas value attributable to Minnesota:

The unit value of the utility company is equal to the total of the weighted indicators of value. The total weighting must equal100 percent. The default weightings of the indicators are: market indicator, 0 percent; cost indicator, 50 percent; incomeindicator, 50 percent.

Minn. R. 8100.0400, subp. 2, explains the process for calculating the allocation of electric value attributable to Minnesota:The original cost of the utility property located in Minnesota divided by the total original cost of the property in all states ofoperation is weighted at 90 percent. Gross revenue derived from operations in Minnesota divided by gross operationsrevenue from all states is weighted at ten percent.

The Minnesota portion of the unit value is reduced by the value included in the unit value of the company for land, rights-of-way, nonoperating property, and exempt property. This amount is calculated by determining the ratio of the unit valuecomputed in part 8100.0300, subpart 5, to the cost less depreciation allowed in part 8100.0300, subpart 3. This ratio ismultiplied by the cost less depreciation of the property to be deducted.

Minn. R. 8100.0500, subp. 2, describes the types of property excluded from the valuation performed under Rule 8100.0300:

Minn. R. 8100.0500, subp. 1, explains the process for adjusting the valuation performed under Rule 8100.0300:After the Minnesota portion of the unit value of the utility company, except for electric cooperatives, is determined, anyproperty which is non-formula-assessed or which is exempt from ad valorem tax, is deducted from the Minnesota portion ofthe unit value. Only that qualifying property located within the state of Minnesota may be excluded.

Minn. R. 8100.0500, subp. 3, further explains the calculation of deduction to Minnesota value:

The following properties are valued by the local or county assessor and, therefore, the formula provided herein for thevaluation of utility property is not applicable to such property:A. land;B. nonoperating property; andC. rights-of-way


Page 1 of 2

Total Company Property Taxes

Electric Gas Electric Gas Electric GasSYSTEM UNIT VALUE CALCULATION

Plant In Service, 12/31 15,489,122,573 1,240,775,385 17,149,342,643 1,333,020,462 1,660,220,070 92,245,077CWIP, 12/31 906,506,966 9,776,240 607,258,386 11,349,113 (299,248,580) 1,572,873Depreciation, 12/31 (6,009,343,119) (580,409,993) (6,114,339,627) (612,321,495) (104,996,508) (31,911,502)Cost Indicator of Value A $10,386,286,420 $670,141,632 $11,642,261,401 $732,048,080 1,255,974,981 61,906,448

Income IndicatorYear 1 NOI x 25% or 0% 0 7,857,005 0 10,353,101 0 2,496,096Year 2 NOI x 35% or 40% 186,782,982 14,494,341 199,663,578 16,353,612 12,880,596 1,859,270Year 3 NOI x 40% or 60% 299,495,366 18,689,842 341,821,336 20,096,800 42,325,970 1,406,958

NOI to Capitalize $486,278,348 $41,041,188 $541,484,914 $46,803,513 55,206,565 5,762,325Capitalization Rate 7.40% 7.30% 7.40% 7.30% 0 0

Income Indicator of Value B $6,571,329,032 $562,208,057 $7,317,363,697 $641,144,010 746,034,665 78,935,953

Apply Weightings 35/65 50/50 35/65 50/50Cost Indicator $3,635,200,247 $335,070,816 $4,074,791,500 $366,024,000 439,591,253 30,953,184Income Indicator $4,271,363,871 $281,104,028 $4,756,286,400 $320,572,000 484,922,529 39,467,972

Total System Unit Value C $7,906,564,118 $616,174,844 $8,831,077,900 $686,596,000 924,513,782 70,421,156

ALLOCATION OF SYSTEM VALUEMN Plant in Service 15,439,739,125 1,137,708,834 16,389,639,716 1,221,353,186 949,900,591 83,644,352System Plant in Service 16,395,629,539 1,250,551,625 17,756,601,028 1,344,369,575 1,360,971,489 93,817,950Plant Ratio x 90%-Elec / x 75%-Gas 84.75% 68.23% 83.07% 68.14% (0) (0)MN Gross Revenue 3,731,409,068 674,888,573 3,731,409,068 674,888,573 0 0System Gross Revenue 4,239,532,104 762,665,589 4,239,532,104 762,665,589 0 0Revenue Ratio x 10%-Elec / x 25%-Gas 8.80% 22.12% 8.80% 22.12% 0 0

MN Allocated Value Percentage 93.55% 90.35% 91.87% 90.26% (0) (0)MN Allocated Value D $7,396,590,700 $556,714,000 $8,113,111,300 $619,721,500 716,520,600 63,007,500

Depreciable Plant Deductions 2,043,407,958 57,553,575 2,154,609,249 58,486,056 111,201,291 932,481Land 180,216,966 3,393,588 180,216,966 3,393,588 0 0CWIP 512,862,889 5,413,559 335,287,463 6,124,597 (177,575,426) 711,038Other - Held for Future Use 0 0 0 0 0 0Subtotal 2,736,487,813 66,360,722 2,670,113,678 68,004,241 (66,374,135) 1,643,519Ratio - System Unit Value / Cost Indicator 76.13% 91.95% 75.85% 93.79% (0) 0

DEDUCTIONS TO MN ALLOCATED VALUE E $2,083,288,200 $61,018,700 $2,025,281,200 $63,781,200 (58,007,000) 2,762,500Sliding Scale Market Value Exclusion $200,000,000 $0 $200,000,000 $0 0 0

DEDUCT/EXCL TO MN ALLOCATED VALUE $2,283,288,200 $61,018,700 $2,225,281,200 $63,781,200 (58,007,000) 2,762,500Apportionable Market Value $5,113,302,500 $495,695,300 $5,887,830,100 $555,940,300 774,527,600 60,245,000Effective Tax Rate 3.3% 3.3% 3.3% 3.3% 0 0FORECASTED PROPERTY TAX - Elec & Gas $168,738,983 $16,357,945 $194,298,393 $18,346,030 25,559,411 1,988,085

Rounded $168,700,000 $16,400,000 $194,300,000 $18,300,000 25,600,000 1,900,000Total Electric & Gas $185,100,000 $212,600,000 27,500,000Locally Assessed $11,100,000 $11,100,000 0Wind Production $1,300,000 $2,100,000 800,000

TOTAL MINNESOTA FORECASTED PROPERTY TAX $197,500,000 $225,800,000 28,300,000

North Dakota & South Dakota Property Tax $6,900,000 $8,000,000 1,100,000

TOTAL NSPM FORECASTED PROPERTY TAX $204,400,000 $233,800,000 29,400,000

Reasons for Changes:

Minnesota Income 15,900,000Plant 11,600,000Renewables 800,000

28,300,000

North Dakota Renewables 1,000,000

South Dakota 100,000

Total Increase / (Decrease) 29,400,000

2015 vs. 20162015 Accrual Forecast 2016 FTY


Page 2 of 2Support for the Calculation of Minnesota Apportionable Market Value

A

B

C

D

E



Minn. R. 8100.0500, subp. 1, explains the process for adjusting the valuation performed under Rule 8100.0300:After the Minnesota portion of the unit value of the utility company, except for electric cooperatives, is determined, anyproperty which is non-formula-assessed or which is exempt from ad valorem tax, is deducted from the Minnesota portion ofthe unit value. Only that qualifying property located within the state of Minnesota may be excluded.




The allocation of value of gas distribution companies must be made considering the same factors as are used to determinethe allocation of value of electric companies. The weight given to the original cost factor is 75 percent, and gross revenue isweighted 25 percent.


The unit value of the utility company is equal to the total of the weighted indicators of value. The total weighting must equal100 percent. The default weightings of the indicators are: market indicator, 0 percent; cost indicator, 50 percent; incomeindicator, 50 percent.





The cost factor to be considered in the utility valuation formula is the original cost less depreciation of the system plant, plusthe cost of improvements to the system plant, plus the original cost of all types of construction work in progress that areinstalled by the assessment date, plus the cost of property held for future use, plus the cost of contributions in aid ofconstruction.



Minn. R. 8100.0300, subp. 4, explains the process for calculating the income indicator of value:The income indicator of value is estimated by weighting the capitalized net operating earnings of the utility company for themost recent three years as follows: most recent year, 40 percent; previous year, 35 percent; and final year, 25 percent.Utilities may request the removal of nonrecurring items of income or expense. The commissioner must determine if removalof the item is appropriate. The net income is capitalized by applying a capitalization rate that is computed by using the bandof investment method. This method considers:


Page 1 of 2




Income Indicator2014 NOI x 25% or 0% 0 11,681,1512015 Estimated NOI x 35% or 40% 227,880,891 17,584,7002016 Estimated NOI x 40% or 60% 353,867,536 20,794,800













2017 FTY


Page 2 of 2


A

B

C

D

E



Minn. R. 8100.0500, subp. 1, explains the process for adjusting the valuation performed under Rule 8100.0300:After the Minnesota portion of the unit value of the utility company, except for electric cooperatives, is determined, anyproperty which is non-formula-assessed or which is exempt from ad valorem tax, is deducted from the Minnesota portionof the unit value. Only that qualifying property located within the state of Minnesota may be excluded.




The allocation of value of gas distribution companies must be made considering the same factors as are used todetermine the allocation of value of electric companies. The weight given to the original cost factor is 75 percent, andgross revenue is weighted 25 percent.


The unit value of the utility company is equal to the total of the weighted indicators of value. The total weighting mustequal 100 percent. The default weightings of the indicators are: market indicator, 0 percent; cost indicator, 50 percent;income indicator, 50 percent.





The cost factor to be considered in the utility valuation formula is the original cost less depreciation of the system plant,plus the cost of improvements to the system plant, plus the original cost of all types of construction work in progress thatare installed by the assessment date, plus the cost of property held for future use, plus the cost of contributions in aid ofconstruction.



Minn. R. 8100.0300, subp. 4, explains the process for calculating the income indicator of value:The income indicator of value is estimated by weighting the capitalized net operating earnings of the utility company forthe most recent three years as follows: most recent year, 40 percent; previous year, 35 percent; and final year, 25percent. Utilities may request the removal of nonrecurring items of income or expense. The commissioner must determineif removal of the item is appropriate. The net income is capitalized by applying a capitalization rate that is computed byusing the band of investment method. This method considers:

Docket No. E002/GR-15-826Exhibit___(LMC-1), Schedule 5

Page 1 of 2



Plant In Service, 12/31 17,149,342,643 1,333,020,462 18,077,601,803 1,414,976,000 928,259,161 81,955,537CWIP, 12/31 607,258,386 11,349,113 641,938,988 20,614,715 34,680,602 9,265,602Depreciation, 12/31 (6,114,339,627) (612,321,495) (6,584,387,398) (650,588,733) (470,047,771) (38,267,238)Cost Indicator of Value A $11,642,261,401 $732,048,080 $12,135,153,393 $785,001,981 492,891,991 52,953,901

Income IndicatorYear 1 NOI x 25% or 0% 0 10,353,101 0 11,681,151 0 1,328,050Year 2 NOI x 35% or 40% 199,663,578 16,353,612 227,880,891 17,584,700 28,217,313 1,231,088Year 3 NOI x 40% or 60% 341,821,336 20,096,800 353,867,536 20,794,800 12,046,200 698,000





ALLOCATION OF SYSTEM VALUEMN Plant in Service 16,389,639,716 1,221,353,186 17,052,029,276 1,304,046,987 662,389,559 82,693,801System Plant in Service 17,756,601,028 1,344,369,575 18,719,540,791 1,435,590,715 962,939,763 91,221,139Plant Ratio x 90%-Elec / x 75%-Gas 83.07% 68.14% 81.98% 68.13% (0) (0)MN Gross Revenue 3,731,409,068 674,888,573 3,731,409,068 674,888,573 0 0System Gross Revenue 4,239,532,104 762,665,589 4,239,532,104 762,665,589 0 0Revenue Ratio x 10%-Elec / x 25%-Gas 8.80% 22.12% 8.80% 22.12% 0 0

MN Allocated Value Percentage 91.87% 90.26% 90.78% 90.25% (0) (0)MN Allocated Value D $8,113,111,300 $619,721,500 $8,494,517,100 $663,682,400 381,405,800 43,960,900

Depreciable Plant Deductions 2,154,609,249 58,486,056 2,128,999,255 58,442,685 (25,609,994) (43,371)Land 180,216,966 3,393,588 180,216,966 3,393,588 0 0CWIP 335,287,463 6,124,597 413,394,202 9,602,678 78,106,739 3,478,081Other - Held for Future Use 0 0 0 0 0 0Subtotal 2,670,113,678 68,004,241 2,722,610,423 71,438,951 52,496,745 3,434,710Ratio - System Unit Value / Cost Indicator 75.85% 93.79% 77.11% 93.68% 0 (0)

DEDUCTIONS TO MN ALLOCATED VALUE E $2,025,281,200 $63,781,200 $2,099,404,900 $66,924,000 74,123,700 3,142,800Sliding Scale Market Value Exclusion $200,000,000 $0 $200,000,000 $0

DEDUCT/EXCL TO MN ALLOCATED VALUE $2,225,281,200 $63,781,200 $2,299,404,900 $66,924,000Apportionable Market Value $5,887,830,100 $555,940,300 $6,195,112,200 $596,758,400 307,282,100 40,818,100Effective Tax Rate 3.3% 3.3% 3.3% 3.3% 0 0FORECASTED PROPERTY TAX - Elec & Gas $194,298,393 $18,346,030 $204,438,703 $19,693,027 10,140,309 1,346,997

Rounded $194,300,000 $18,300,000 $204,400,000 $19,700,000 10,100,000 1,400,000Total Electric & Gas $212,600,000 $224,100,000 11,500,000Locally Assessed $11,100,000 $11,100,000 0Wind Production $2,100,000 $2,100,000 0


North Dakota & South Dakota Property Tax $8,000,000 $8,900,000 900,000


2017 FTY 2016 vs. 20172016 FTY

Northern States Power Company Docket No. E002/GR-15-826Exhibit___(LMC-1), Schedule 5

Page 2 of 2


A

B

C

D

2E+10

E



















Page 1 of 2




Income Indicator2015 Estimated NOI x 25% or 0% 0 12,560,5002016 Estimated NOI x 35% or 40% 235,911,691 18,195,4502017 Estimated NOI x 40% or 60% 363,641,536 21,361,600













2018 FTY


Page 2 of 2


A

B

C

D

E



















Page 1 of 2



Plant In Service, 12/31 18,077,601,803 1,414,976,000 18,694,700,292 1,500,020,607 617,098,489 85,044,608CWIP, 12/31 641,938,988 20,614,715 660,599,529 12,202,489 18,660,541 (8,412,226)Depreciation, 12/31 (6,584,387,398) (650,588,733) (7,148,323,875) (691,224,911) (563,936,477) (40,636,177)Cost Indicator of Value A $12,135,153,393 $785,001,981 $12,206,975,946 $820,998,185 71,822,553 35,996,204

Income IndicatorYear 1 NOI x 25% or 0% 0 11,681,151 0 12,560,500 0 879,349Year 2 NOI x 35% or 40% 227,880,891 17,584,700 235,911,691 18,195,450 8,030,800 610,750Year 3 NOI x 40% or 60% 353,867,536 20,794,800 363,641,536 21,361,600 9,774,000 566,800





ALLOCATION OF SYSTEM VALUEMN Plant in Service 17,052,029,276 1,304,046,987 17,663,129,512 1,371,876,203 611,100,237 67,829,216System Plant in Service 18,719,540,791 1,435,590,715 19,355,299,821 1,512,223,096 635,759,030 76,632,382Plant Ratio x 90%-Elec / x 75%-Gas 81.98% 68.13% 82.13% 68.04% 0 (0)MN Gross Revenue 3,731,409,068 674,888,573 3,731,409,068 674,888,573 0 0System Gross Revenue 4,239,532,104 762,665,589 4,239,532,104 762,665,589 0 0Revenue Ratio x 10%-Elec / x 25%-Gas 8.80% 22.12% 8.80% 22.12% 0 0

MN Allocated Value Percentage 90.78% 90.25% 90.93% 90.16% 0 (0)MN Allocated Value D $8,494,517,100 $663,682,400 $8,673,619,500 $691,949,700 179,102,400 28,267,300

Depreciable Plant Deductions 2,128,999,255 58,442,685 2,067,670,058 58,345,100 (61,329,197) (97,585)Land 180,216,966 3,393,588 180,216,966 3,393,588 0 0CWIP 413,394,202 9,602,678 389,141,987 2,707,893 (24,252,215) (6,894,785)Other - Held for Future Use 0 0 0 0 0 0Subtotal 2,722,610,423 71,438,951 2,637,029,011 64,446,581 (85,581,412) (6,992,370)Ratio - System Unit Value / Cost Indicator 77.11% 93.68% 78.14% 93.48% 0 (0)

DEDUCTIONS TO MN ALLOCATED VALUE E $2,099,404,900 $66,924,000 $2,060,574,500 $60,244,700 (38,830,400) (6,679,300)Sliding Scale Market Value Exclusion $200,000,000 $0 $200,000,000 $0

DEDUCT/EXCL TO MN ALLOCATED VALUE $2,299,404,900 $66,924,000 $2,260,574,500 $60,244,700Apportionable Market Value $6,195,112,200 $596,758,400 $6,413,045,000 $631,705,000 217,932,800 34,946,600Effective Tax Rate 3.3% 3.3% 3.3% 3.3% 0 0FORECASTED PROPERTY TAX - Elec & Gas $204,438,703 $19,693,027 $211,630,485 $20,846,265 7,191,782 1,153,238

Rounded $204,400,000 $19,700,000 $211,600,000 $20,800,000 7,200,000 1,100,000Total Electric & Gas $224,100,000 $232,400,000 8,300,000Locally Assessed $11,100,000 $11,100,000 0Wind Production $2,100,000 $2,100,000 0


North Dakota & South Dakota Property Tax $8,900,000 $8,900,000 0


2018 FTY 2017 vs. 20182017 FTY


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A

B

C

D

E



















Page 1 of 3

Northern States Power CompanyMinnesota Property Taxes 2012

COUNTY Total Taxes Total Value Blended Rate Total Taxes Total Value Blended Rate

Anoka 2,756,815 66,677,000 0.041 2,748,695 66,677,000 0.041Becker 44,364 1,638,800 0.027 45,142 1,638,800 0.028Beltrami 29,500 938,300 0.031 30,363 938,300 0.032Benton 1,455,672 35,264,900 0.041 1,483,052 35,264,900 0.042Blue Earth 2,249,004 73,822,300 0.030 2,247,242 73,822,300 0.030Brown 184,288 5,038,700 0.037 181,670 5,038,700 0.036Carver 1,619,056 41,675,900 0.039 1,618,704 41,675,900 0.039Cass 210,034 7,786,400 0.027 190,118 7,786,400 0.024Chippewa 1,029,266 27,881,200 0.037 1,032,480 27,881,200 0.037Chisago 3,427,080 74,348,300 0.046 3,423,370 79,746,300 0.043Clay 292,658 11,289,700 0.026 290,984 11,302,600 0.026Crow Wing 473,439 16,925,500 0.028 470,483 16,925,500 0.028Dakota 12,260,625 341,956,800 0.036 12,227,822 341,942,400 0.036Dodge 318,384 10,296,200 0.031 398,551 10,296,200 0.039Douglas 150,104 4,464,200 0.034 152,707 4,924,500 0.031Faribault 16,624 552,500 0.030 16,361 552,500 0.030Freeborn 30,858 798,400 0.039 30,614 798,400 0.038Goodhue 16,066,347 552,028,000 0.029 16,037,444 552,033,300 0.029Hennepin 35,114,272 817,247,900 0.043 33,509,686 817,107,000 0.041Houston 135,800 3,294,300 0.041 130,599 3,294,300 0.040Hubbard 2,918 140,700 0.021 2,880 140,700 0.020Isanti 92,804 2,643,000 0.035 92,514 2,643,000 0.035Itasca 189,846 6,689,600 0.028 193,572 6,689,600 0.029Jackson 656,520 25,455,300 0.026 653,758 25,455,300 0.026Kandiyohi 432,230 11,704,100 0.037 431,550 11,704,100 0.037Koochiching 329,400 11,410,000 0.029 328,986 11,410,000 0.029Lac qui Parle 1,000 45,200 0.022 1,000 45,200 0.022Lake of the Woods 189,546 5,346,900 0.035 185,900 5,346,900 0.035Le Sueur 301,760 9,804,600 0.031 299,016 9,804,600 0.030Lincoln 776,608 28,101,600 0.028 768,268 30,017,900 0.026Lyon 902,940 28,884,800 0.031 878,484 32,390,600 0.027Martin 142,600 6,069,800 0.023 142,282 6,069,800 0.023Mc Leod 248,168 5,894,600 0.042 247,228 5,894,600 0.042Meeker 155,516 3,692,800 0.042 154,854 3,692,800 0.042Morrison 8,568 270,900 0.032 8,494 270,900 0.031Mower 212,556 8,088,500 0.026 210,220 8,343,800 0.025Murray 904,184 37,746,500 0.024 895,870 37,753,500 0.024Nicollet 418,278 13,358,300 0.031 422,253 13,358,300 0.032Nobles 1,491,672 57,343,600 0.026 1,476,796 57,786,900 0.026Norman 13,234 553,700 0.024 12,879 553,700 0.023Olmstead 272,994 7,119,500 0.038 272,752 7,119,500 0.038Pine 221,282 6,678,900 0.033 220,032 6,678,900 0.033Pipestone 423,378 12,537,500 0.034 418,465 12,537,500 0.033Polk 83,712 3,493,600 0.024 83,620 3,493,600 0.024Pope 279,004 8,080,200 0.035 275,278 8,080,200 0.034Ramsey 20,945,690 489,589,900 0.043 21,092,777 489,393,900 0.043Redwood 82,390 2,263,600 0.036 80,436 2,263,600 0.036Renville 632,706 20,017,100 0.032 638,534 20,045,300 0.032Rice 1,889,746 52,391,000 0.036 1,887,280 52,388,300 0.036Rock 38,736 1,637,300 0.024 41,910 1,637,300 0.026Roseau 712,700 16,991,700 0.042 708,139 16,991,700 0.042St. Louis 818,931 24,030,100 0.034 821,906 24,030,100 0.034Scott 2,160,578 58,637,200 0.037 2,155,748 58,637,200 0.037Sherburne 12,263,172 448,342,000 0.027 12,350,896 448,342,000 0.028Sibley 274,487 6,723,000 0.041 271,476 6,723,000 0.040Stearns 3,748,950 106,926,800 0.035 3,751,004 105,222,400 0.036Steele 32,222 877,800 0.037 32,036 877,800 0.036Todd 52,024 1,485,400 0.035 51,916 1,485,400 0.035Wabasha 379,220 10,631,500 0.036 376,557 10,631,500 0.035Waseca 454,906 12,830,200 0.035 449,502 14,246,395 0.032Washington 14,741,214 437,175,300 0.034 14,780,272 437,175,300 0.034Watonwan 268,566 9,183,300 0.029 277,971 9,183,300 0.030Wilkin 2,616 96,300 0.027 2,604 96,300 0.027Winona 932,390 28,158,300 0.033 903,121 28,158,300 0.032Wright 15,461,040 539,948,600 0.029 15,131,212 539,948,600 0.028Yellow Medicine 137,236 4,685,100 0.029 136,306 4,685,100 0.029Referendums Est 800,000 Reflected above

Subtotal 163,444,428 4,667,701,000 0.0350 160,884,643 4,679,091,195 0.0344

Truth-in-Taxation Notices Property Tax Statements


Page 2 of 3



Anoka 2,780,381 67,137,700 0.041 2,771,458 67,137,700 0.041Becker 69,808 2,517,400 0.028 68,870 2,517,400 0.027Beltrami 96,427 2,991,500 0.032 94,338 2,991,500 0.032Benton 1,467,197 34,756,200 0.042 1,465,140 34,756,200 0.042Blue Earth 2,139,351 74,761,300 0.029 2,224,040 74,761,300 0.030Brown 171,281 4,952,500 0.035 169,929 4,952,500 0.034Carver 1,647,335 42,517,300 0.039 1,657,258 42,517,300 0.039Cass 190,897 7,786,400 0.025 244,704 9,806,300 0.025Chippewa 984,496 28,106,900 0.035 976,138 28,106,900 0.035Chisago 3,463,492 80,429,300 0.043 3,453,126 80,234,800 0.043Clay 262,077 11,548,000 0.023 260,528 11,548,000 0.023Crow Wing 479,927 17,130,500 0.028 476,947 17,130,500 0.028Dakota 12,819,961 356,046,900 0.036 12,886,846 356,159,500 0.036Dodge 384,668 10,264,000 0.037 374,026 10,264,000 0.036Douglas 230,139 6,994,400 0.033 234,312 7,633,200 0.031Faribault 14,853 546,000 0.027 14,757 546,000 0.027Freeborn 29,599 802,600 0.037 28,332 802,600 0.035Goodhue 16,156,107 543,202,800 0.030 16,066,431 543,515,600 0.030Hennepin 35,392,624 831,908,700 0.043 35,095,903 831,908,700 0.042Houston 150,218 3,337,900 0.045 133,258 3,337,900 0.040Hubbard 53,326 1,968,700 0.027 52,776 1,968,700 0.027Isanti 99,428 2,673,400 0.037 99,950 2,673,400 0.037Itasca 194,241 6,689,600 0.029 242,062 7,949,500 0.030Jackson 594,320 26,205,400 0.023 587,186 26,205,400 0.022Kandiyohi 419,435 11,763,800 0.036 414,142 11,763,800 0.035Koochiching 323,370 11,191,100 0.029 326,590 11,191,100 0.029Lac qui Parle 1,002 45,300 0.022 852 45,300 0.019Lake of the Woods 182,330 5,244,300 0.035 182,788 5,244,300 0.035Le Sueur 458,913 15,731,200 0.029 457,150 15,731,200 0.029Lincoln 750,710 31,996,300 0.023 745,102 31,996,300 0.023Lyon 933,407 36,491,200 0.026 924,190 36,491,200 0.025Martin 131,356 6,060,400 0.022 130,892 6,060,400 0.022Mc Leod 272,567 7,000,800 0.039 273,085 7,000,800 0.039Meeker 164,064 4,149,300 0.040 161,214 4,149,300 0.039Morrison 8,588 274,100 0.031 8,548 274,100 0.031Mower 214,813 9,531,600 0.023 213,436 9,531,600 0.022Murray 788,922 37,197,700 0.021 778,294 37,197,700 0.021Nicollet 418,667 13,507,900 0.031 422,637 13,507,900 0.031Nobles 1,290,247 55,673,800 0.023 1,271,956 55,673,800 0.023Norman 5,604 255,100 0.022 5,503 255,100 0.022Olmstead 276,307 7,568,800 0.037 269,025 7,568,800 0.036Pine 225,184 6,700,900 0.034 225,126 6,700,900 0.034Pipestone 420,183 13,871,200 0.030 411,967 13,871,200 0.030Polk 71,306 3,523,500 0.020 71,236 3,523,500 0.020Pope 270,117 8,311,200 0.033 265,958 8,311,200 0.032Ramsey 22,226,251 516,362,500 0.043 22,242,700 516,362,500 0.043Redwood 91,502 2,864,300 0.032 87,424 2,864,300 0.031Renville 701,737 24,781,600 0.028 690,411 24,781,600 0.028Rice 1,927,402 53,620,800 0.036 1,972,150 53,620,800 0.037Rock 37,633 1,632,600 0.023 36,770 1,632,600 0.023Roseau 716,102 17,586,200 0.041 707,960 17,586,200 0.040St. Louis 853,658 25,072,300 0.034 859,364 25,346,600 0.034Scott 2,232,715 60,496,600 0.037 2,230,428 60,496,600 0.037Sherburne 12,449,463 436,521,200 0.029 12,256,978 436,521,200 0.028Sibley 282,063 7,110,300 0.040 276,826 7,112,200 0.039Stearns 4,135,855 117,660,000 0.035 4,116,894 117,713,000 0.035Steele 60,741 1,653,700 0.037 58,738 1,653,700 0.036Todd 99,810 2,962,100 0.034 99,452 2,962,100 0.034Wabasha 418,158 11,898,000 0.035 415,906 11,898,000 0.035Waseca 447,883 15,155,000 0.030 498,077 15,190,000 0.033Washington 15,435,457 438,712,000 0.035 15,402,160 439,793,900 0.035Watonwan 243,173 9,089,200 0.027 244,640 9,089,200 0.027Wilkin 2,494 96,600 0.026 2,558 96,600 0.026Winona 904,407 28,568,500 0.032 893,229 28,568,500 0.031Wright 14,596,451 510,733,000 0.029 14,593,120 510,732,941 0.029Yellow Medicine 134,096 5,028,100 0.027 129,476 5,028,100 0.026Referendums Est 800,000 Reflected above

Subtotal 166,296,296 4,738,969,500 0.0351 165,053,268 4,744,565,041 0.0348



Page 3 of 3



Anoka 2,768,474 70,908,200 0.039 2,768,466 70,906,800 0.039Becker 71,072 2,618,600 0.027 70,002 2,618,600 0.027Beltrami 94,306 3,006,600 0.031 94,727 3,006,600 0.032Benton 1,434,807 35,114,100 0.041 1,430,722 35,114,100 0.041Blue Earth 2,249,768 77,861,200 0.029 2,256,325 77,861,200 0.029Brown 223,928 7,324,500 0.031 187,609 7,324,500 0.026Carver 1,847,165 50,031,200 0.037 1,834,244 50,031,200 0.037Cass 245,932 9,918,500 0.025 246,146 9,918,500 0.025Chippewa 1,042,028 30,523,700 0.034 1,039,926 30,523,700 0.034Chisago 3,451,399 82,325,900 0.042 3,441,908 82,325,900 0.042Clay 340,074 16,204,700 0.021 338,167 16,204,700 0.021Crow Wing 486,044 17,427,600 0.028 484,324 17,427,600 0.028Dakota 13,877,638 389,213,500 0.036 13,868,079 389,203,500 0.036Dodge 404,990 10,472,900 0.039 404,854 10,431,100 0.039Douglas 1,112,778 14,771,700 0.075 430,260 14,771,700 0.029Faribault 17,702 613,300 0.029 17,707 613,300 0.029Freeborn 30,009 829,300 0.036 29,578 829,300 0.036Grant 20,524,150 719,984,200 0.029 20,533,673 719,650,600 0.029Goodhue 51,414 2,096,400 0.025 53,730 2,096,400 0.026Hennepin 35,713,665 887,723,600 0.040 35,632,031 882,971,700 0.040Houston 138,097 3,428,700 0.040 137,358 3,428,700 0.040Hubbard 53,712 1,993,900 0.027 53,970 1,993,900 0.027Isanti 105,610 2,752,400 0.038 104,668 2,752,400 0.038Itasca 243,455 7,965,500 0.031 243,740 7,965,500 0.031Jackson 580,956 25,750,200 0.023 578,060 25,750,200 0.022Kandiyohi 408,667 12,004,300 0.034 407,348 12,004,300 0.034Koochiching 328,883 11,136,900 0.030 324,172 11,136,900 0.029Lac qui Parle 886 47,100 0.019 816 47,100 0.017Lake of the Woods 181,897 5,218,900 0.035 190,342 5,218,900 0.036Le Sueur 483,321 16,628,500 0.029 483,572 16,628,500 0.029Lincoln 703,320 32,473,900 0.022 691,170 32,473,900 0.021Lyon 1,026,102 40,856,800 0.025 1,019,614 40,856,800 0.025Martin 138,530 6,420,400 0.022 138,430 6,420,400 0.022Mc Leod 312,853 8,805,200 0.036 308,970 8,805,200 0.035Meeker 182,261 4,671,500 0.039 181,290 4,620,100 0.039Morrison 8,990 279,500 0.032 8,988 279,500 0.032Mower 217,332 9,831,600 0.022 223,740 9,831,600 0.023Murray 722,508 37,244,900 0.019 719,596 37,244,900 0.019Nicollet 428,243 13,879,900 0.031 427,293 13,879,900 0.031Nobles 1,219,343 57,023,600 0.021 1,246,666 57,023,600 0.022Norman 11,566 552,500 0.021 12,210 552,500 0.022Olmstead 312,624 8,823,900 0.035 309,579 8,363,700 0.037Ottertail 228,500 6,920,400 0.033 193,540 6,920,400 0.028Pine 225,486 6,615,400 0.034 224,826 6,615,400 0.034Pipestone 383,733 13,764,000 0.028 381,256 13,764,000 0.028Polk 62,714 3,601,100 0.017 62,704 3,601,100 0.017Pope 277,983 8,639,200 0.032 280,570 8,639,200 0.032Ramsey 22,163,573 539,801,600 0.041 22,344,745 539,801,600 0.041Redwood 470,295 21,998,900 0.021 478,606 21,998,900 0.022Renville 902,792 35,001,500 0.026 899,873 35,001,500 0.026Rice 1,914,110 54,803,600 0.035 1,898,190 54,803,600 0.035Rock 37,546 1,725,600 0.022 37,368 1,725,600 0.022Roseau 708,856 17,479,500 0.041 709,521 17,479,500 0.041St. Louis 972,176 28,484,700 0.034 968,888 28,484,700 0.034Scott 3,044,900 87,310,100 0.035 3,041,068 87,310,100 0.035Sherburne 12,339,713 456,198,800 0.027 12,299,272 456,161,400 0.027Sibley 963,411 36,861,100 0.026 1,030,558 36,861,100 0.028Stearns 4,595,251 131,552,500 0.035 4,599,144 131,552,500 0.035Steele 32,050 909,900 0.035 31,140 909,900 0.034Todd 134,636 3,955,600 0.034 130,838 3,957,400 0.033Wabasha 393,071 11,016,600 0.036 393,325 10,858,200 0.036Waseca 470,819 14,313,700 0.033 466,545 14,313,300 0.033Washington 15,456,218 460,370,300 0.034 15,370,502 460,667,200 0.033Watonwan 262,446 9,675,500 0.027 262,384 9,675,500 0.027Wilkin 56,315 2,405,500 0.023 56,478 2,405,500 0.023Winona 879,006 28,267,200 0.031 892,460 28,267,200 0.032Wright 18,520,868 769,883,100 0.024 18,496,770 769,883,100 0.024Yellow Medicine 153,773 6,071,100 0.025 152,364 6,071,100 0.025Referendums Est 500,000 Reflected above

Subtotal 179,946,741 5,494,386,300 0.0328 178,677,005 5,488,838,500 0.0326



Page 1 of 1

Year Minnesota North

DakotaSouth

Dakota Total NSPMNSPM Electric

Minnesota Electric

JurisdictionIncluded in Base Rates

Recovered in Riders

2001 $112 $3 $3 $118 $107 $88 $104 $0 2002 $109 $3 $3 $115 $101 $84 $104 $0 2003 $107 $3 $3 $113 $99 $81 $104 $0 2004 $103 $3 $3 $109 $98 $80 $104 $0 2005 $103 $4 $3 $110 $97 $80 $104 $0 2006 $107 $4 $3 $114 $101 $82 $87 $0 2007 $105 $3 $3 $111 $97 $79 $87 $0 2008 $108 $3 $3 $114 $98 $79 $87 $4 2009 $111 $2 $3 $116 $103 $83 $77 $3 2010 $124 $3 $3 $130 $116 $94 $77 $6 2011 $135 $3 $3 $141 $124 $101 $100 $0 2012 $162 $3 $3 $168 $152 $125 $101 $1 2013 $166 $3 $3 $172 $153 $123 $138 $1 2014 $180 $3 $3 $186 $167 $134 $133 $1

2015 As Ordered* $138 $137 $1 2015E Current Forecast $197 $3 $4 $204 $186 $148 $147 $1

2016E Initial Filing $226 $4 $4 $234 $213 $168 $165 $3 2017E Initial Filing $237 $5 $4 $246 $224 $177 $172 $5 2018E Initial Filing $245 $5 $4 $254 $231 $183 $177 $6

Property Tax Expense($ millions)

Index

Case Description Addressed in 2016 TY Case

12-961 DOC 138 A. Please reconcile the estimated market value from the old rate case schedule to the amounts shown in the current rate case schedule. Schedule 3

12-961 DOC 138 B. Please footnote the source and provide the detailed calculation of each line item in the current rate case schedule for the year 2016. Appendix A, 12-13

12-961 DOC 138C. A footnote on the current rate case schedule indicates that the 2016 - 2018 capitalization rates are estimated. (1) Please provide the detailed calculation of the estimate. (2) Were the estimates made by the Department of Revenue (DOR) or Xcel Energy? (3) Please provide the actual capitalization rates for 2014 and 2015.

Testimony p. 16

12-961 DOC 138 D. Please identify the amount and provide the detailed calculation of the Minnesota jurisdictional test-year property tax in the current rate case.

Volume 4, Test Year Workpapers, P6. Property Tax

12-961 DOC 138 E. Please provide the actual property tax expense for 2014 and 2015. Schedule 3

12-961 DOC 138F. Does Xcel have any plant or portion of plant that is non-regulated? If yes, how is the non-regulated plant handled for property taxes, including all calculations. Appendix A, 01

12-961 MCC 105 Please identify changes in property taxes from 2004 forward, please add columns; one identifying amounts in base rates or otherwise recovered and one for total taxes paid in each year. Schedule 8

12-961 MCC 124

Please describe the assessment and levy systems to determine Xcel's property taxes within its service territory. Please describe the separate property tax treatment for buildings, equipment, land, structures, machinery, spent fuel, and any other major classes of property.

Appendix A, 02-03

12-961 MCC 125 At what time during the year are property taxes determined, assessed and paid? To what jurisdictions are the payments made? Testimony p. 12 Figure 1, p. 3 Table 1

12-961 MCC 126For ratemaking purposes, are property taxes determined system-wide and then allocated to Xcel's regulatory jurisdictions, or are the property taxes determined separately and kept within each jurisdiction? Please explain. Volume 4, Test Year

Workpapers, P6. Property Tax

12-961 MCC 127 Please provide total annual property taxes assessed and levied by taxing authorities for the 8-year period 2009-2016 with 2016 estimated. Schedule 8

12-961 MCC 128 What have been the principal reasons for any property tax increases? Are these trends likely to continue into 2016 and beyond? Please explain. Testimony p. 17-18

12-961 MCC 129Please show property taxes to be paid in the 2016 test year separately for transmission plant, distribution plant, generation plant and combined total of all property taxes. Allocations and estimates are acceptable. Also provide property taxes each as a percent of net plant investment in each of the foregoing categories.


12-961 XLI 103Please provide a copy of the materials describing the Homestead Market Value Exclusion.

Appendix A, 04-05

12-961 XLI 104 Please state the local property tax rates before and after the Homestead Market Value Exclusion was enacted. Schedule 9

12-961 XLI 106Please provide a copy of Schedule 2 in electronic native (i.e., EXCEL or compatible) format with all formulas and links intact.

Appendix A, 06

12-961 XLI 109

a. Please define the term Cost Indicator of Value. c. Please define the term NOI to Capitalize and explain how this term is measured. d. Please reconcile the 2016 Electric NOI to Capitalize with the proposed return presented in Exhibit AEH-1, Schedule 3. e. Please define the term Capitalization Rate. f. Please reconcile the Capitalization Rate with the proposed rate of return. g. Please explain how the deductions to MN allocated value were determined.

Appendix A, 07

12-961 XLI 109b. Please reconcile the 2016 Electric Cost Indicator of Value to the proposed plant investments/rate base presented in Exhibit AEH-1, Schedule 8. Appendix A, 07

12-961 XLI 109 h. Please provide documentation supporting the effective tax rates. Schedule 9

12-961 XLI 109 i. Please provide documentation supporting the locally assessed amounts.

Appendix A, 07

12-961 XLI 109 j. Please provide work papers showing how the property tax reflected on this schedule was adjusted to the test year revenue requirement amount.


12-961 XLI 110Please provide the following actual information for the latest available year for each local tax jurisdiction that NSPM pays property tax: a. DOR apportioned unit value. b. Overall market value. c. Class rate. d. Tax rate. Appendix A, 08

12-961 XLI 113

Concerning the test year property tax expense estimate: a. Please reconcile the following Electric amounts to the beginning 2016 test year amounts shown on Exhibit AEH-1, Schedule 4, page 2: i. Plant In-service ii. CWIP iii. Depreciation (Reserve) b. Please provide all work papers and sources used to determine the Electric inputs for the Deductions for MN Allocated Value items: i. Depreciable Plant Deductions ii. Land iii. CWIP c. Please provide all work papers and sources used to determine the inputs for and explain how these items were allocated to electric and gas: i. Locally Accessed ii. Wind Production

Appendix A, 09-11

13-868 DOC 195Please footnote each line item in the above referenced Schedule 2 to source documentation in detailed workpapers that develop the line item, and provide the information or reference its location in the pre-filed documents. Appendix A, 12-16

13-868 DOC 196

The following questions all relate to the calculation of property tax:A. Is it true, that for purposes of determining the net operating income (NOI) to capitalize, three yearsof income are considered: the most recent year weighted at 40 percent; the previous year weightedat 35 percent; and the final year weighted at 25 percent?B. If (A) above is true, please identify the specific years that were used in the development of the 2014test year property taxes in this proceeding; and indicate which of the years use actual data andwhich of the year’s use forecast data.C. If (A) above is true, please identify the specific years that were used in the development of the 2013test year property taxes in the Company’s last electric rate proceeding, Docket No. E002/GR-12-961; and indicate which of the year’s use actual data and which of the years use forecast data.

Testimony p. 15, 22-23

13-868 DOC 198

Subject: Property Tax Reference: Direct Testimony of James J. Duevel Exhibit_____(JJD-1), Schedule 2, Page 1 of 3 Exhibit_____(JJD-1), Schedule 8, Page 3 of 3 A. Please explain why the 3.30 percent rate (based on 20124 Truth-in-Taxation Notices) was used to estimate the 2016 Property Tax Rate when the average rate from the actual 2012 Property Tax Statements is 3.44 percent? Schedule 9

13-868 DOC 2147Subject: Property Tax. Reference: Direct Testimony of James J. Duevel at Pages 18-20Exhibit ___ (JJD-1), Schedule 11, Page 1 of 3. Xcel’s June 12, 2014 Response to MCC Information Request No. 248, Attachment AC. Please provide an estimate of the MN Jurisdictional Property Tax for 2015.

a-b, d) N/Ac) Schedule 8

IR No.

Property Taxes Pre-Filed Discovery - 2016 Minnesota Electric Rate Case

Northern States Power Company

Docket No. E002/GR-15=826 Exhibit____(LMC-1), Appendix A

Page 1 of 72

Index

Case Description Addressed in 2016 TY Case

IR No.

Property Taxes Pre-Filed Discovery - 2016 Minnesota Electric Rate Case

13-868 MCC 239

With respect to Property Taxes please provide:a) Amount claimed in the last rate case.b) Amount approved and in rate base from last rate case.c) Amounts actually paid for property taxes 2010-2015.d) Please explain the assessment and appeal process.e) Identify if the amounts in c) include refunds or adjustments after appeals.f) Please identify refunds or adjustments by year 2010-2015 (provide tax year appealed and year adjustment or refund was received separately).g) Please identify amount clamed in this rate case and identify if gross or net of expected appeals.With respect to any calculations, please provide Excel spreadsheet with formulae, also provide, total company and MN jurisdiction information.

a-c) Schedule 8d-g) Appendix A, 17

13-868 MCC 246

Referring to MCC -239 please provide the following on a "revised" Attachment A, two additional columns that identify:• For years in which Xcel filed a rate case, tbe amount included in the initial filing for test year amount requested for recovery.• Proposed tax assessments based on preliminary values issued by DOR, prior to appeal or informal adjustment "opportunity to discuss" (we are assuming "NSPM Electric" column is tbe actual tax paid (except when identified as testimony/order/filing)).

Appendix A, 18


Docket No. E002/GR-15-826 Exhibit____(LMC-1), Appendix A

Page 2 of 72

Docket No. E002/GR-12-961 Information Request No. DOC-138, Part F __________________________________________________________________

Question: Subject: Property Tax Reference: Exhibit___(LMC-1), Schedule 2, Page 1 of 1

F. Does Xcel have any plant or portion of plant that is non-regulated? If yes, how is the non-regulated plant handled for property taxes, including all calculations. Response: F. Yes, the Company owns a steam line that connects the Sherco generation plant to an adjacent Liberty Paper facility. This steam line is non-regulated property. There are no property taxes corresponding to this non-regulated steam line because it is not treated as taxable property by either the MN DOR or local taxing jurisdictions. The non-regulated steam line falls outside the definition of “operating property” and is therefore not subject to valuation by the MN DOR for property tax purposes. The steam line is also not included in the calculation of local property taxes, because it is personal property, not real estate. Thus, there are no property taxes corresponding to this non-regulated steam line. __________________________________________________________________ Preparer: Leanna Chapman Title: Manager Tax Reporting Department: Tax Services

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Docket No. E002/GR-12-961 Information Request No. MCC-124 __________________________________________________________________

Question: Please describe the assessment and levy systems to determine Xcel's property taxes within its service territory. Please describe the separate property tax treatment for buildings, equipment, land, structures, machinery, spent fuel, and any other major classes of property. Response: A. Assessment and Levy Systems Minnesota The first step in the property tax process is determining the value of the Company’s property. In Minnesota, different types of utility property are valued differently. Utility operating property is valued by the Minnesota Department of Revenue (DOR) using the formulas described in Minnesota Rule 8100.0300. Non-operating property (e.g. offices, garages, warehouses, land, etc.) is valued by local assessors using traditional valuation techniques. The DOR also determines how much of the Company’s total system value is attributable to Minnesota.1 The Minnesota value is then apportioned to each county.2 Counties add the portion apportioned to them with the property they assess themselves to arrive at our tax base within the jurisdiction. Finally, each jurisdiction applies its own individual property tax rate to our tax base to determine our property tax liability. Please see Minnesota Rules, Chapter 8100 for additional detail on the Minnesota property tax system. Also, Attachment A which is a MN House of Representatives Information Brief on Minnesota property taxation of electric utilities (dated October 2006) provides additional, conceptual, discussion of the Minnesota system. We caution, however, that the report in Attachment A does not reflect post-2006 legislative changes. North Dakota North Dakota Century Code § 57-06-14 explains how utility property is valued in that state. The assessment process in North Dakota is similar to the Minnesota process

1 Minn. R. 8100.0400. 2 Minn. R. 8100.0600.

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described above. Please see Chapter 57-06 of the North Dakota Century Code for additional detail on the North Dakota property tax system. South Dakota South Dakota Codified Laws §10-35-10.1 explains how utility property is valued in that state. The assessment process in South Dakota is similar to the Minnesota process described above. Please see Chapter 10-35 of the South Dakota Codified Laws for additional detail on the South Dakota property tax system. B. Property Taxes by Property Type The table below details the Minnesota property tax treatment of different categories of utility property:

Property Category

Minnesota

Subject to Property

Tax?

State Assessed or

Locally Assessed?

Buildings Yes Both Equipment Yes State Land Yes Locally Structures Yes State Machinery Yes State Spent Fuel (pad and casks) Yes State

__________________________________________________________________ Preparer: Leanna Chapman Title: Manager Tax Reporting Department: Tax Services

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INFORMATION BRIEF Minnesota House of Representatives Research Department 600 State Office Building St. Paul, MN 55155 Karen Baker, Legislative Analyst, 651-296-8959 Steve Hinze, Legislative Analyst, 651-296-8956 Updated: October 2006

Primer on Minnesota’s Property Taxation of Electric Utilities

Updated to include laws enacted in the 2006 legislative session

This information brief summarizes the current structure of electric utility property taxation. The brief covers the following topics:

• The characteristics of, methods for valuing, and property tax paid by the different types of electric utilities

• The special personal property tax exemptions granted by the legislature for electric utilities

• Sales tax exemptions for the construction of power plants • The production tax that applies to wind energy conversion systems used as

an electric power source Contents Introduction....................................................................................................................................2 Types of Electric Utilities ..............................................................................................................2 Determining a Utility’s Value .......................................................................................................4

New Rules for Determining a Utility’s Value .....................................................................5 Property Tax...................................................................................................................................5

Class Rate Schedule — Major Property Types by Class.....................................................6 Statewide Utility Market Value and Property Taxes ...........................................................7

Exemptions .....................................................................................................................................8 Electric Utilities ...................................................................................................................8 Energy and Pollution Control Property..............................................................................18

Wind Energy Conversion Systems .............................................................................................19 The Past: 1991 through 2003 Property Tax .......................................................................19 The Present: 2004 and Thereafter, Wind Energy Production Tax (WEPT) ......................20 Production Incentives.........................................................................................................22

This publication can be made available in alternative formats upon request. Please call 651-296-6753 (voice); or the Minnesota State Relay Service at 1-800-627-3529 (TTY) for assistance. Many House Research Department publications are also available on the Internet at: www.house.mn/hrd/hrd.htm.

Docket No. E002/GR-12-961 Information Request No. MCC-124, Attachment A

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House Research Department Updated: October 2006 Primer on Minnesota’s Property Taxation of Electric Utilities Page 2

Introduction Changes in the regulation and economics of the electric utility industry are making state and local utility taxes more important. These changes also raise policy questions about the way state and local governments tax utilities.

For most of the 20th century, utilities operated as regulated monopolies: they were stable businesses that earned regulated and, more or less, guaranteed rates of return. Because regulations typically allowed property taxes to be recovered through the utility’s rates, the level of taxes had little effect on the rate of return earned by the utility. Furthermore, utility taxes provided a convenient and stable way for state and local governments to raise generous amounts of revenue.

Federal regulations, adopted in the 1990s, allowing competition in wholesale pricing of electric power has begun to change the economics of the industry. Some states have also begun to allow retail competition. If competitive market forces set utility prices, state and local taxes can affect the rate of return on and viability of utility investments. Utility consumers (especially large commercial and industrial customers) have become more aware of the effect of taxes on their utility bills and, along with the utilities, are seeking to reduce utility taxes, including property taxes.

The Minnesota Legislature has made a variety of utility property tax changes in response to this changing environment. This information brief:

• Describes the various types of utilities and how Minnesota taxes utility property

• Discusses methods of valuing utility property

• Provides data on the total property taxes paid by utilities

• Lists exemptions and special provisions granted by the legislature over the last 20 years

• Describes the taxation of wind energy conversion systems, which was based on property through payable 2003 and, beginning in calendar year 2004, based on production

Types of Electric Utilities Investor-owned utilities (IOUs) are private, for-profit corporations whose rates are regulated by the Minnesota Public Utilities Commission (PUC). The five IOUs that serve Minnesota (Xcel, Allete, Alliant, Ottertail, and Northwestern Wisconsin Electric) are vertically integrated utilities; the IOUs generate, transmit, and distribute their own electricity and may also buy power from wholesale producers. Property owned by these utilities is subject to property tax, unless specifically exempted.


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Rural electric associations (co-ops) are nonprofit organizations whose rates are overseen by a board composed of co-op members.1 Co-ops are not vertically integrated. There are two basic types of co-ops:

• Distribution cooperatives provide retail electric service directly to Minnesota consumers. There are about 40 distribution co-ops in Minnesota. The distribution co-ops pay a fee of 10 cents per customer in lieu of the property tax on their distribution lines located outside of incorporated areas.2 This fee is collected by the Department of Revenue (DOR) and deposited in the general fund. For fiscal year 2005, the statewide total collections were about $48,000. Any of their distribution lines that are located within incorporated areas are subject to property tax; however, the majority of the lines are outside of incorporated areas and pay the in-lieu fee of 10 cents per customer. Co-op-owned substations are subject to property tax.

• Generation and transmission cooperatives generate and transmit electricity to distribution co-ops. There are six generation and transmission cooperatives that serve Minnesota distribution co-ops.3 Generation and transmission cooperatives are generally subject to property taxation, unless specifically exempted.

Municipal utilities (Munis) are public, nonprofit utilities overseen by local public utilities commissions or city councils. Munis are generally not vertically integrated. As with co-ops, there are two kinds of municipal utilities.

• Distribution Munis, like their cooperative counterparts, provide retail electric services to Minnesota consumers. There are about 125 distribution Munis in Minnesota.

• Municipal power agencies (MPAs) provide distribution Munis with generation and transmission services. There are six MPAs operating in Minnesota.4

Both distribution Munis and MPAs are generally exempt from property tax, but an MPA pays in-lieu payments to each taxing authority within whose taxing jurisdiction its property is situated. These in-lieu payments equal the amounts of taxes which would have been payable if its property were owned by a private person. Minn. Stat. § 453.54, subd. 20.

Distribution Munis, while not subject to a specific statutory requirement to pay in-lieu taxes to taxing jurisdictions in which they operate, often do make contributions (monetary and otherwise) to their host city.

1 One distribution cooperative, Dakota Electric Association, has elected to be rate-regulated by the PUC. 2 Minn. Stat. §§ 273.40 and 273.41. 3 The six “G&T” co-ops are: Basin Electric Power Association, Dairyland Power Cooperative, East River

Electric Power Cooperative, L&O Power Cooperative, Minnkota Power Cooperative, and Great River. 4 The six MPAs are: Missouri River Energy Services, Heartland Consumer Power District, Southern

Minnesota MPA, Central Minnesota MPA, Northern Minnesota MPA, and Minnesota MPA.


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http://www.revisor.leg.state.mn.us/bin/getpub.php?type=s&num=453.54

























Independent power producers (IPPs) are nonutility power producers that generate electricity solely for sale at wholesale and have no transmission or distribution lines (e.g., NRG, Landfill Gas, Minnesota Methane, Gas Recovery, and American Transmission Company (LLC of Wisconsin Power)). IPPs are generally private corporations, subject to property tax (unless specifically exempted), but are treated as utilities for property tax purposes.

Determining a Utility’s Value Utilities are valued and assessed under a “dual” property tax system:

1) The Department of Revenue (DOR) values the property that constitutes the utility’s operating property using the unit value system. The “unit value” method estimates the market value for the entity as an integrated whole, rather than valuing each part and parcel separately. The unit value is then apportioned among the jurisdictions where the property is located, based on a formula.

2) Local assessors value the utility’s nonoperating property, which consists of all offices, garages, warehouses, and land.

There are three approaches to valuing property—cost, income, and sales (market). However, DOR uses only cost and income in establishing market values of electric utilities. Sales are considered, but are not used due to lack of data and other concerns.

Prior to January 1, 2000, cost (less depreciation) was the only factor used in determining the value of co-ops. However, beginning with the 2000 assessment, a co-op could elect on the unit-value basis or continue to be valued using cost (less depreciation) as the only factor.5, 6

The current unit-value formula that DOR uses in determining the market value of the utility is:

0.75 x (the original cost7 of the utility property less allowable depreciation8), plus 0.25 x (the utility’s capitalized income during the most recent three years9)

Given this approach, the property values of Minnesota electric utilities have remained relatively stable for property-tax purposes. Some states rely more heavily on utilities’ income-producing

5 Minnesota Rules, part 8100.0300, subpart 6, allows co-ops this option. 6 Cost is used as the factor in determining the market value of MPAs, since no MPA has elected the unit-value

option. 7 In determining property values, DOR also includes improvements and the cost of construction in progress on

the date of the assessment. 8 Minnesota Rules, part 8100.0300, subpart 3, limits electric companies’ allowable depreciation for property-

tax purposes to 20 percent of the cost of the property, plus 50 percent of the excess amount (over the 20 percent). 9 The income component of the equation uses the utility’s net income for the most recent three years weighted

consecutively at 40 percent, 35 percent, and 25 percent, respectively, and applies at a capitalization rate. Minnesota Rules, part 8100.0100, subpart 5, defines the capitalization rate as the relationship of income to capital investment or value, expressed as a percentage.


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http://www.revisor.leg.state.mn.us/bin/getpub.php?type=r&num=8100.0300
































House Research Department Updated: October 2006 Primer on Minnesota’s Property Taxation of Electric Utilities Page 5 ability to determine property values and consequently experience wider variations in their property valuations. DOR is in the process of adopting new administrative rules for determining a utility’s valuations (see discussion below).

DOR then determines what portion of an electric company’s total property value is allocated to Minnesota using the following formula:

Minnesota’s share of total value = 0.90 x (original cost of utility property in Minnesota/total original cost of utility property in all states of operation) plus

0.10 x (gross operating revenue from Minnesota operations/gross operating revenue from all states)

DOR then deducts from the Minnesota allocation the (1) utility nonoperating property (i.e., land, offices, garages, warehouses, etc.) and (2) rights-of-way, since these items are valued by local assessors. Lastly, the Minnesota portion of utility property is adjusted to exclude property statutorily exempt from Minnesota property taxes (e.g., pollution control equipment).

New Rules for Determining a Utility’s Value

As a result of administration valuation appeals and tax court cases involving utilities, the Commissioner of Revenue is updating the administrative rules prescribing the method for the valuation and assessment of utility companies for property tax purposes. DOR hired an independent consultant to prepare a report on current rules. DOR staff have analyzed the consultant’s report, received comments from other interested parties regarding the report, and held open forum meetings to receive comments on the report.

An advisory committee was formed in the fall of 2005 to help DOR write suggested changes to the rules. The committee consists of seven members representing various types of utilities, seven members representing counties, and various DOR employees. The committee met several times, reviewed proposed changes to the rule, and provided the department with comments and suggestions with respect to both valuation policy and specific rule language. The rulemaking process is moving forward and the department’s goal is to have a new rule in place for the 2007 assessment year. The department has also indicated that it may use the advisory committee to give advice on any suggested future rule amendments.

Property Tax After DOR determines the market value of the utility’s operating property, it certifies the value to the county auditor where the property is located, and the property becomes part of the local tax base.

The county auditor applies the appropriate class rates to the market value. A listing of the major property classes and their respective class rates for taxes payable in 2006 is shown in the table


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House Research Department Updated: October 2006 Primer on Minnesota’s Property Taxation of Electric Utilities Page 6 below.10 These class rates apply statewide and are set by the legislature. The table also shows whether the state general tax and school operating referendum levies apply to the properties.

Class Rate Schedule — Major Property Types by Class Taxes Payable 2006

Class Rate

Subject to State Tax

Subject to Operating (Excess Levy) Referenda11

Residential Homestead: Up to $500,000 market value Over $500,000 market value

1.0% 1.25

no no

yes yes

Apartments (4 or more units) 1.25 no yes

Commercial-Industrial-Public Utility:12

Up to $150,000 Over $150,000 Electric generation machinery

1.5 2.0 2.0

yes yes no

yes yes yes

Agricultural Land & Buildings Homestead:13

Up to $600,000 market value Over $600,000 market value

Nonhomestead

0.55 1.0 1.0

no no no

no no no

House Research Department

Applying the appropriate class rate to the utility’s market value yields the utility’s net tax capacity. The utility’s property tax is determined by multiplying its net tax capacity times:

1) the total local tax rate (i.e., the county, city/town, school district, and special taxing districts), plus

2) the statewide general tax rate (where applicable; see table above)

For property taxes payable in 2006, the table on the following page shows the statewide utility market value by type of property and estimated property tax. Utility personal property is taxable as shown in the table, even though personal property (including both inventories and attached machinery) of nonutility businesses have been exempt since the early 1970s.

10 The table is a very abbreviated listing of the class rates. There are numerous subclasses of property and

minor exceptions within the major classes. 11 School operating referendum levies (sometimes called “excess levy” referenda) and all county, city, and

town referendum levies are levied on referendum market value. School debt levies are levied against all property based on net tax capacity.

12 A utility is allowed to receive the first-tier class rate (up to the $150,000 market value limit) on only one property per county.

13 House, garage, and one acre treated the same as residential homestead.


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Statewide Utility Market Value and Property Taxes by Type of Property14

Taxes Payable in 2006 (all figures in millions)

Type of Property Market Value Amount

Market Value % of Total

Tax Amount

Percent of Total

Effective Tax Rate

Land and buildings $856 11.7% $27.2 12% 3.3%

Electric generation machinery 1,457 19.9 32.9 13.9 2.3

Other machinery 1,169 15.9 36.8 17.8 3.2

Transmission lines15 1,704 23.2 55.5 24.7 3.4

Distribution lines 212 2.9 7.4 3.7 3.5

Pipelines 1,934 26.4 61.2 27.9 3.2

Total $7,332 100.0% $221 100.0% 3.1% House Research Department

To put this in context with all property on a statewide basis for taxes payable in 2006:

• The total taxable market value of utility property ($7.3 billion) is about 1.6 percent of the total taxable market value of all property ($464 billion);

• The total utility property tax of $221 million is about 3.5 percent of the total tax on all property ($6,244 million).

Thus, utility property taxes (3.5 percent) are more than twice the utility’s property share of taxable market value (1.6 percent).16

Utility property is not uniformly distributed throughout the state. Therefore, the proportion of taxable utility market value and tax within any particular taxing district to its total market value and tax varies dramatically within the state.

Power line credit. Incentives for landowners to accept transmission lines on their property will likely be a legislative issue in the near future. A property tax credit enacted in 1980 to address this issue is worth noting, even though the total dollar amount of credits paid are small. The power line credit was established to reduce the property tax burden of those taxpayers whose properties have high-voltage electrical lines on them, as an incentive for taxpayers to accept

14 The market value and taxes in this category are for all utilities. Due to data constraints, it is not easy to separate the values and taxes by type of utility. However, electric utilities constitute over two-thirds of the total value of all utility property.

15 Includes value and tax amounts for transmission and distribution lines that are excluded from the general tax base in determining tax rates and are subject to the countywide tax rate. For taxes payable in 2004, these lines were valued at $195 million with a tax burden of $5.7 million. Minn. Stat. § 273.37, subd. 2.

16 The comparable ratios for commercial/industrial (nonutility) are 31.3 percent taxes to 13.1 percent taxable market value.


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these power lines. In order to qualify for the credit, the property must be crossed by a transmission line of 200KV or more, constructed after June 30, 1974.

In 1981, utility companies made direct payments to qualifying property owners to compensate them for having these high voltage lines pass over their property. However, the direct payments were changed to property tax credits beginning with taxes payable in 1982/1983. For taxes payable in 2006, the total statewide power line property tax credit was only $81,900. Minn. Stat. § 273.42.

Exemptions In Minnesota, a utility’s attached machinery and other personal property is taxable (i.e., transformers, turbines, etc.).17, , 18 19 Over the past two decades, the legislature has granted many property tax exemptions for the attached machinery and other personal property at newly constructed facilities. These exemptions have been adopted in response to requests from companies proposing to build new electric generating facilities20 in Minnesota (see list of exemptions made since 1994 below). With the precedent for these exemptions so well established, it is quite likely that this trend will continue for future proposed facilities.21

Electric Utilities

The following is a list of the proposed facilities for which their attached machinery and other personal property have been exempted from property taxation by the legislature in the past 20 years. As one can see, many exemptions have been enacted. No general exemption has ever been enacted for this type of property, although there has been discussion about enacting that type of legislation, instead of exempting the attached machinery and personal property one facility at a time. Some of the facilities have also been granted exemptions from sales tax for construction materials and supplies. These exemptions are shown as footnotes.

1994 L.S. Power Plant: Exemption for a cogeneration system that used natural gas as a primary fuel. The exemption required that the plant be constructed before July 1, 1997. The plant was constructed in Cottage Grove and is operational. Laws 1994, ch. 513. Minn. Stat. § 272.02, subd. 29.

17 Personal property of nonutility commercial and industrial businesses are exempt (i.e., inventories, tools,

marchinery, etc.). 18 Companies in Minnesota that generate electric power for their own use, and not for resale, are exempt from

taxation on the personal property used to generate the power. Minn. Stat. § 272.027. 19 Personal property used primarily for the abatement and control of air, water, or land pollution is exempt from

property tax. Minn. Stat. § 272.01, subd. 10. 20 These facilities have primarily been peaking and intermediate-load facilities. 21 Many assume that even if electric restructuring were to occur, transmissions and distribution lines would

probably remain taxable because they are not subject to competition as are the actual generation facilities.


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http://www.revisor.leg.state.mn.us/bin/getpub.php?type=l&year=1994&sn=0&num=513

































1996/2005 Market value exclusion for electric power generation efficiency:

1996: Exemption for facility that produces electricity at very high efficiency levels and has significantly lower pollution emissions than conventional power production facilities. It provides for a subtraction equal to 5 percent of market value of qualifying property for each percentage point that the facility is operating above 35 percent efficiency. Although this is a general exemption, it was designed for a specific company (Koch Refining; now called Flint Hills Resources) and project, which was to be a cogeneration facility. The required efficiency level could only be met by existing power production facilities in Minnesota by implementing significant and expensive changes to the facility. This provision is often referred to as the “cogeneration” provision, since at that time, those were the only types of facilities that could achieve the required efficiency. Laws 1996, ch. 444. Minn. Stat. § 272.0211, subd. 2.

2005: The 2005 Legislature modified the formula for determining a plant’s efficiency for the market value exclusion; the new formula uses a ratio of energy output to energy input during normal base-load operation. The threshold for a generation facility to qualify for the sliding scale market value exclusion was increased from 35 percent to 40 percent, and the exclusion for each percentage point above the threshold was increased from 5 percent to 8 percent. This formula increase updates the sliding scale exclusion to today’s efficiency standards, given the new technology now available. Laws 2005, ch. 151, art. 3, secs. 9 and 10.

DOR has granted market value exclusions for a few facilities under this law. They are Xcel’s Black Dog plant (Burnsville), Minnesota Power’s plant at Potlatch (Cloquet/Carlton County), and two natural gas-fired peaking plants serving Dakota Electric (Hastings and Lakeville) owned by Energy Alternatives (wholly owned subsidiary of Dakota Electric).

1997 Biomass, waste wood:22 Exemption for equipment that is part of a system that generates biomass electric energy and satisfies a portion of the Prairie Island biomass mandate on Xcel Energy in section 216B.2424, or a system that produces energy using waste wood.

Exemption requires local approval of the governing bodies of each affected county, city/town, and school district. That approval may be rescinded by a later referendum if a petition is signed by 10 percent of

22 Minn. Stat. § 297A.71, subd. 8. The 1997 Legislature also enacted a law that exempted the purchases of

construction materials and supplies from the sales and use taxes imposed for a system that meets the requirements. This law was recodified in 2000. (Laws 1997, ch. 231, art. 7, sec. 27; Laws 2000, ch. 418, art. 1, sec. 15.)


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http://www.revisor.leg.state.mn.us/bin/getpub.php?type=s&num=297A.71

























the voters in the county voting in the last general election. Property exempted under this provision is limited to a maximum of five assessment years, beginning with the assessment year immediately following when the personal property is put into operation. No known facilities qualify for the exemption under this provision. Laws 1997, ch. 231, art. 2, sec. 8. Minn. Stat. § 272.02, subd. 43.

1997 Laskin Plant (St. Louis County): Provision has expired. Exemption for equipment of a facility with a capacity of 110 megawatts, whose operation was integral to the development and operation of a new, adjacent industrial park.

Exemption required local approval from the governing bodies of the county, city/town, and school district. Approval could have been rescinded by a later referendum if a petition were signed by at least 10 percent of the number of persons voting in the county in the last general election. Exemption could not exceed five years beginning with the assessment year immediately following when the property was put into operation and expired thereafter. This exemption expired if the industrial park was not built by July 1, 2001. This exemption was enacted for a plant proposed for St. Louis County. However, no exemption was granted under this provision and it has expired. Laws 1997, ch. 231, art. 2, sec. 57 (never codified in Minnesota Statutes).

1999 Lakefield Junction (Martin County): Exemption for equipment of a peaking facility proposed to be constructed in Martin County that is part of a simple-cycle, combustion-turbine electric generation facility that exceeds 250 megawatts of installed capacity.

The exemption required that construction of the facility begin after July 1, 1999, and before July 1, 2003. The plant is in operation and is owned by Great River Energy. Laws 1999, ch. 243, art. 5, sec. 3. Minn. Stat. § 272.02, subd. 33.

1999 Rapids Energy Center, Grand Rapids (Itasca County): Facility plans cancelled. Exemption for equipment of a facility if the electric generating facility was operational on January 2, 1999, and sold to a Minnesota electric utility. This was enacted for a plant proposed to be sold to Minnesota Power and expanded from 30 megawatts to 250 megawatts. Plans to build this facility were cancelled in August 2002. Laws 1999, ch. 243, art. 5, sec. 4. Minn. Stat. § 272.027, subd. 2.

1999 Direct-reduction steel mill: Exemption for equipment of an electric generating facility if the facility, when completed, has a capacity of at least 450 megawatts; is adjacent to a taconite mine direct-reduction steel mill; and supplies over 60 percent of its electricity generated in the prior


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year to the adjacent direct-reduction plant and steel mill. No construction has begun on this facility. Laws 1999, ch. 243, art. 5, sec. 4. Minn. Stat. § 272.027, subd. 3.

2000 Pleasant Valley Station (Mower County): Exemption for equipment of an electric generation peaking facility, proposed to be constructed in Mower County by Great River Energy, that is a simple-cycle, combustion-turbine electric generation facility that exceeds 250 megawatts of installed capacity.

Construction of this facility had to begin after January 1, 2000, and before January 1, 2004. This facility has been constructed and is in operation. Laws 2000, ch. 490, art. 5, sec. 4. Minn. Stat. § 272.02, subd. 44.

2001/2003/2005 Fibro Minn (Swift County)23

2001: A personal property exemption was granted by the 2001 Legislature for a plant that was to be built in the city of Benson (Swift County). It was designed to generate power using poultry litter as a primary fuel source to satisfy a portion of the Prairie Island biomass mandate under section 216B.2424. Construction was to begin by December 31, 2002. Laws 2001, 1st spec. sess. ch. 5, art. 3, sec. 18.

2003: The 2003 Legislature extended the construction date to December 31, 2003. Laws 2003, ch. 127, art. 2, sec. 6.

2005: The 2005 Legislature extended the date by which construction must begin in order for a facility to qualify for a personal property tax exemption from December 31, 2003, to December 31, 2005. Laws 2005, ch. 151, art. 3, sec. 1. Minn. Stat. § 272.02, subd. 47.

2001 Waste tire cogeneration facility (Fillmore County):24 Provision has expired. Exemption for equipment of an electric generating facility designed to use waste tires as a primary source and that was a cogeneration electric generating facility of 15 to 25 megawatts of installed capacity.

23 Minn. Stat. § 297A.71, subd. 25. The 2001 Legislature enacted a law that exempted the purchases of

construction materials and supplies from the sales and use taxes imposed for a system that uses poultry litter and other biomass electric generation facility. The expiration date was extended in 2005 and is effective for sales from June 30, 2001, to July 1, 2007. Laws 2001, ch. 5, art. 3, sec. 18; Laws 2000, ch. 151, art. 3, sec. 1.

24 Minn. Stat. § 297A.71, subd. 27. The 2001 Legislature also enacted a law that exempted the purchases of construction materials and supplies from the sales and use taxes imposed for a system that utilizes waste tires as a primary fuel in generating electricity. This provision has expired. Laws 2001, ch. 5, art. 3, sec. 69.


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Construction of the facility had to begin after January 1, 2000, and before January 1, 2004. This exemption was enacted for a facility proposed to be located in the city of Preston (Fillmore County). This facility received its air permit from the MPCA in July 2003, but the developer withdrew the project. Laws 2001, 1st spec. sess., ch. 5, art. 3, sec. 19. Minn. Stat. § 272.02, subd. 48.

2001/2006 Biomass electric generating facility25

2001: Exemption for equipment of an electric generating facility designed to utilize biomass as a primary fuel source. It must also be constructed for generating power that will be sold under a contract approved by the PUC, for a biomass mandate imposed under section 216B.2424.

Although this exemption was written broadly to apply to any facility that met the criteria and for which construction began after January 1, 2000, and before December 31, 2002, only the St. Paul district energy facility qualified for the exemption. The plant is operated by Trigent Cinergy. Laws 2001, 1st spec. sess., ch. 5, art. 3, sec. 21.

2006: The 2006 Legislature extended the construction date to December 31, 2005, to allow the Laurentian biomass facility (a joint project of the cities of Hibbing and Virginia) to qualify for the exemption. Laws 2006, ch. 259, art. 4, sec. 5. Minn. Stat. § 272.02, subd. 45.

2001/2003 Northom; Itasca Power Company26, 27

2001: Exemption for equipment of a new wood-burning biomass generation facility that satisfies a portion of the biomass mandate imposed on Xcel Energy (Northern States Power) in the Prairie Island legislation (1994 and 2003). The facility must have a generation capacity of between 10 and 20 megawatts; be located in a certain northern area; utilize biomass residue wood, sawdust, bark, chipped


construction materials and supplies made by municipal joint powers to construct, expand, or improve electric generation facilities used to meet the biomass mandate. There is no expiration date for this provision. Laws 2005, ch. 3, art. 5, sec. 16.

26 Minn. Stat. § 297A.71, subd. 21. The 2000 Legislature enacted a law that exempted the purchases of construction materials and supplies from the sales and use taxes imposed for a system that utilizes residue wood, sawdust, bark, chipped wood or brush to generate electricity, uses a grate combination system, and has a gross capacity of 15 to 21 megawatts. This provision expired in July 2005. Laws 2000, ch. 418, art. 1.

27 The exemption granted under this section is effective regardless of whether the facility is needed or selected to fulfill some portion of the biomass mandate.


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wood, or brush as a primary fuel source; and be operational by December 31, 2002. Laws 2001, 1st spec. sess., ch. 5, art. 3, sec. 13. Minn. Stat. §§ 216B.2424, subd. 5; 216B.1691, subd.6.

2003: The 2003 Legislature extended the operational date by an additional three years to December 31, 2005. Laws 2003, ch. 127, art. 2, sec. 31.

Additionally, the legislature required Xcel Energy to enter into a power purchase agreement with this facility by January 1, 2004, for 10 to 20 megawatts of biomass energy and capacity at a price not to exceed $55 per megawatt-hour. Contract referred to the PUC; no facility yet under construction. Laws 2003, 1st spec. sess., ch. 11.

2002 Waseca County: Provision has expired. Exemption for equipment of a combined-cycle, natural gas turbine electric generation facility of between 43 and 46 megawatts of installed capacity. The facility had to utilize a combined-cycle gas turbine generator fueled by natural gas, be connected to an existing transmission line, be located on an underground natural gas storage aquifer, be designed as an intermediate load facility, and have received local approval from the governing body of the county for the exemption of personal property.

Construction of the facility had to begin after January 1, 2002, and before January 1, 2004. Laws 2002, ch. 377, art. 4, sec. 7. Minn. Stat. § 272.02, subd. 51.

2002 Beltrami County: Exemption for equipment of a simple-cycle, combustion-turbine electric generation facility of more than 40 megawatts and less than 50 megawatts of installed capacity.

The facility must utilize natural gas as a primary fuel; be located by certain natural gas pipelines and a transmission line; be designed to provide peaking, emergency backup, or contingency services; and satisfy a resource deficiency identified in an approved integrated resource plan filed under section 216B.2422.

Construction of the facility had to begin after January 1, 2001, and before January 1, 2005. The plant is in operation and is owned by Ottertail Power. Laws 2002, ch. 377, art. 4, sec. 8. Minn. Stat. § 272.02, subd. 52.


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2002/2003/2005/2006 Crown Hydro (Minneapolis)28

2002: A personal property exemption was granted by the 2002 Legislature for this plant that was to be built in the city of Minneapolis. It was a 3.2 megawatt, run-of-the-river hydroelectric generation facility. Construction was to begin by January 1, 2004. Laws 2002, ch. 377, art. 4, sec. 9. Minn. Stat. § 272.02, subd. 53.

2003: The 2003 Legislature extended the construction date to January 1, 2005. Laws 2003, ch. 127, art. 2, sec. 7.

2005: The 2005 Legislature provided an additional two years to January 1, 2007, and deleted the requirement that the generating facility be located on publicly owned land. Laws 2005, ch. 151, art. 3, sec. 2.


2002/2006 Rahr Malting (Shakopee/Scott County)

2002: Exemption for equipment of an electric generation facility that has a generation capacity of less than 25 megawatts. The facility must provide process heating needs in addition to electrical generation and utilize agricultural by-products from the malting process and other biomass fuels as its primary fuel source.

Construction of the facility had to begin after January 1, 2002, and before January 1, 2006. Construction began in 2005. The facility was anticipated to be operational in about two years. Laws 2002, ch. 377, art. 4, sec. 10. Minn. Stat. § 272.02, subd. 54.


2002/2003/2006 Mesaba Energy Projects

There are currently two proposed sites for the Mesaba Energy Project, in accordance with Minnesota Statutes, sections 116C.51-69, and Minnesota Rues, part 4400/1150, subpart 1.C. The West Range site is primarily located within the city limits of Taconite in Itasca County. The East Range site is primarily located within the city limits of Hoyt Lakes in St. Louis County. Minn. Stat. §§ 272.02, subd. 55; 216B.1694, subd. 2.


construction materials and supplies used or consumed in the construction of a hydroelectric generating facility for sales from December 31, 2004, to December 31, 2007. This was extended in 2006. Laws 2006, ch. 259, art. 3, sec. 2.


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2002: Exemption for equipment of an electric generation facility sited on an energy park located on an active or former mining or industrial site within the taconite tax relief area. The facility had to have on-site access to existing railroad infrastructure and direct rail access to a Great Lakes port, sufficient private water resources on site, and be designed to host at least 500 megawatts of electric generation.

Construction of the first 250 megawatts at the facility had to commence after January 1, 2002, and before January 1, 2005. This exemption was enacted for a facility proposed to be located in St. Louis County (the old LTV plant site). Construction of up to an additional 750 megawatts had to commence before January 1, 2010. Laws 2002, ch. 377, art. 4, sec. 11.

2003: Legislation was enacted in 2003 providing a number of regulatory incentives for this energy project on the Iron Range. Laws 2003, 1st spec. sess., ch. 11.

2006: No construction commenced under the 2001 or 2003 legislation. The 2006 legislation deleted the requirements that the facility be located on a mining or industrial site (though it still must be in the taconite tax relief area), have direct rail access to a Great Lakes port, and have sufficient private water resources on site. It modified the requirement for on-site access to railroad infrastructure to access to existing railroad infrastructure within less than three miles.

Additionally, the 2006 legislation also required the facility: to be designated as an innovative energy project, to receive resolution approval from the governing body where the proposed facility is to be located, and to have an agreement with the host county, city/township, and school district for a payment in lieu of property taxes. These location requirements were broadened so that the site can be in either St. Louis or Itasca counties.

The law also extended the construction commencement dates to after January 1, 2006, and before January 1, 2010, for the first 500 megawatts of the facility and before January 1, 2015, for the additional 750 megawatts. Laws 2006, ch. 259, art. 4, sec. 8.

2003/2005 Calpine (Mankato/Blue Earth County)

2003: Exemption is for equipment of a combined-cycle, combustion-turbine electric generation facility that exceeds 550 megawatts of installed capacity and designed to utilize natural gas as a primary fuel. The facility cannot be owned by a public utility as defined in section 216B.02, subdivision 4; must be located close to existing natural gas


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pipeline and existing electrical transmission substation and outside the seven-county metro area; must be designed to provide energy and ancillary services; and have received a certificate of need under section 216B.243.

Construction of the facility must begin after January 1, 2004, and before January 1, 2007. Construction of the facility has begun. Laws 2003, ch. 127, art. 2, sec. 8. Minn. Stat. § 272.02, subd. 56.

2005: The 2005 Legislature reduced the plant’s minimum size from 550 to 300 megawatts and allowed any expansion to be exempt without regard to when construction begins. Laws 2005, ch. 151, art. 3, sec. 3.

2003 Great River Energy (Rosemount/Dakota County): Exemption is for equipment of a combined-cycle, combustion-turbine electric generation facility that exceeds 150 megawatts of installed capacity and utilizes natural gas as a primary fuel. It must be owned by an electric generation and transmission cooperative; located close to natural gas pipelines and a high-voltage electric transmission line; designed to provide intermediate energy and ancillary services and received a certificate of need under section 216B.243, demonstrating demand for its capacity; and has received local approval from the county and city in which the site is located.

The exemption will take effect only if the owner of the facility enters into agreements with the governing bodies of the county and the city where the facility is located (in the Dakota Electric service territory). The agreements may include a requirement that the facility pay a host fee to compensate the county and the city for hosting the facility.

Construction of the facility must begin after January 1, 2004, and before January 1, 2009. Plans to build this facility were put on hold due to a multiyear power purchase agreement from another utility. Laws 2003, ch. 127, art. 2, sec. 9. Minn. Stat. § 272.02, subd. 67.

2005 Electric generation facility personal property (Cannon Falls/Goodhue County): Exemption is for equipment that is part of an existing simple-cycle, combustion-turbine electric generation facility that exceeds 290 megawatts of installed capacity. It must utilize natural gas as a primary fuel; be designed to provide peaking, emergency backup, or contingency services; and have received approval from the governing body of the county and city for the exemption.

Construction of the facility must begin after January 1, 2005, and before January 1, 2009. Laws 2005, ch. 151, art. 3, sec. 4. Minn. Stat. § 272.02, subd. 68.


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2005 Electric generation facility personal property (Faribault/Rice County): Exemption is for equipment that is part of an electric generation facility that exceeds 150 megawatts of installed capacity. The facility must be designed as a combined-cycle facility, although initially it will be operated as a simple-cycle combustion turbine and utilize natural gas as a primary fuel.

To qualify for the exemption, the municipal power agency (that will own and operate the facility) must agree to make payments in lieu of property taxes to the host city.

Construction of facility must begin after January 1, 2004, and before January 1, 2006. Construction has begun on the facility. Laws 2005, ch. 151, art. 3, sec. 5. Minn. Stat. § 272.02, subd. 69.

2005 Electric generation facility personal property (Shakopee/Scott County): Exemption is for equipment that is part of an existing simple-cycle, combustion-turbine electric generation facility that exceeds 300 megawatts of installed capacity. It must utilize natural gas as a primary fuel; be designed to provide peaking, emergency backup, or contingency services; and have received approval from the governing body of county and city for the exemption.

Construction of facility expansion must begin after January 1, 2004, and before January 1, 2005. This exemption is for the new attached machinery and personal property for the expansion of an existing plant (Blue Lake) in Shakopee owned by Xcel Energy. Laws 2005, ch. 151, art. 3, sec. 6. Minn. Stat. § 272.02, subd. 70.

2005 Electric generation facility personal property (Cambridge/Isanti County): Exemption is for equipment that is part of a single-cycle, combustion-turbine electric generation facility that exceeds 150 megawatts of installed capacity. The facility must be designed to utilize natural gas as a primary fuel; provide peaking, emergency backup, or contingency services; and have received approval from the governing body of the county and the township for the exemption.

Construction of the facility must begin after July 1, 2005, and before January 1, 2009. This exemption is for a proposed generating facility to be built by Great River Energy in the city of Cambridge (Isanti County). A certificate of need was issued in November 2005; construction should begin in April 2006. Laws 2005, ch. 151, art. 3, sec. 8. Minn. Stat. § 272.02, subd. 71.

2005 Electric generation facility personal property (Blooming Grove Township/Waseca County): Exemption is for equipment that is either


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part of (1) a simple-cycle, combustion-turbine electric generation facility, or (2) a combined-cycle, combustion-turbine electric generation facility that does not exceed 325 megawatts of installed capacity. The facility must be designed as either a peaking or intermediate load facility, and must utilize either a simple-cycle or a combined-cycle combustion-turbine generator fueled by natural gas. The facility must have received approval from the governing body of the county for the exemption.

Construction must begin after January 1, 2006, and before January 1, 2008. This facility/exemption replaces one proposed in 2002 for a facility that was never constructed. Laws 2005, ch. 151, art. 3, sec. 8. Minn. Stat. § 272.02, subd. 72.

2005 Biomass/Minneapolis Midtown Exchange: Exemption is for equipment that is part of an electric generation facility that generates up to 30 megawatts of installed capacity. The facility must be designed to utilize at least 90 percent waste biomass as a fuel, not be owned by a public utility, be located within a city of the first class, have its primary location at a former garbage transfer station, and be designed to have the capability to provide baseload energy and district heating.

Construction of the facility must begin between January 1, 2004, and January 1, 2008. The proposed facility will be located in Minneapolis and will supply energy to the former Sears site (Midtown Exchange). Laws 2005, 1st spec. sess., ch. 3, art. 1, sec. 6. Minn. Stat. § 272.02, subd. 82.

2006 Electric generation facility personal property (Lower St. Anthony/Minneapolis):29 Exemption is for equipment that is part of a 10.3-megawatt run-of-the-river hydroelectric generation facility. Construction must begin after April 30, 2006, and before January 1, 2009. Laws 2006, ch. 259, art. 4, sec. 9. Minn. Stat. § 272.02, subd. 84.

Energy and Pollution Control Property

In addition to the above exemptions, Minnesota also exempts some energy and pollution control equipment from property tax located at facilities that are otherwise subject to property taxes. The estimated market value exempted for these property types for the 2005 assessment was about $680 million. This exemption amount has remained relatively stable in recent years since no major generating facilities have been built. Most of the exemption is for pollution control equipment (some structures are also exempted).

29 The 2006 Legislature exempted from sales tax the materials and supplies used or consumed in the

construction of a 10.3-megawatt hydroelectric generating facility in lower St. Anthony.


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Wind Energy Conversion Systems The taxation of wind in Minnesota has been an important policy question as technology has advanced to make wind systems more economic to install. On the one hand, policymakers wanted to keep the tax on this source of energy low to promote this renewable resource. On the other hand, the areas of the state in which the wind resource is abundant are relatively poor in terms of tax capacity (little industry, etc.). The local government units in these areas want to tax wind energy systems to raise local revenues. Responding to this tension, the legislature has enacted numerous changes to the taxation of wind energy conversion systems ranging from a total exemption, through graduated property tax system, to the current production tax.

The Past: 1991 through 2003 Property Tax

The original law, enacted in 1991, exempted all wind energy conversion systems installed after January 1, 1991, that were used as an electric power source. Laws 1991, ch. 316, sec. 2.

In the following years, numerous changes were made to the taxation or exemption of these systems based on the size of the system. The table below summarizes the tax status of each type of wind energy conversion system for taxes payable in 2003. Minn. Stat. § 272.02, subd. 2.

Taxation of Wind Energy Conversion Systems; Taxes Payable 2003

Size of System Land

Foundations and Support Pads Structures

Turbines, Blades, Transformers, and Equipment

Small (less than 2 megawatts) Taxable Exempt Exempt Exempt

Medium (more than 2 megawatts, but less than 12 megawatts)

Taxable Taxable Exempt for 5 years; 30% taxable thereafter

Exempt

Large (more than 12 megawatts)

Taxable 25% taxable 25% taxable 25% taxable

House Research Department

Prior to the 2000 assessment, county assessors were responsible for valuing wind conversion systems. However, beginning with the 2000 assessment, the responsibility was transferred to DOR. Laws 2000, ch. 490, art. 5, sec. 15. Minn. Stat. § 273.37, subd. 3. This section has been repealed since the wind conversion systems are now exempt from property tax and are subject to an in-lieu production tax.

Defining the Size of System

Under this property tax structure, an important issue was how to define the size of the system. Since smaller units were taxed preferentially, wind developers attempted to make these projects seem smaller than they actually were. The 2001 Legislature reacted by specifying the total size of wind energy conversion systems for purposes of property taxation. These changes required combining the nameplate capacity of all wind energy conversion systems located within five


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House Research Department Updated: October 2006 Primer on Minnesota’s Property Taxation of Electric Utilities Page 20 miles of each other, constructed in the same calendar year, and under the same ownership in determining if the system is a small-, medium-, or large-scale system. These changes applied to wind energy systems installed after January 1, 2001. The changes continue to apply to the wind energy production tax beginning in payable 2004. Laws 2001, 1st. spec. sess., ch. 5, art. 3, sec. 16. Minn. Stat. §272.02, subd. 22.

The 2006 Legislature expanded the definition of wind energy conversion systems to include substations used and owned by one or more wind energy conversion facilities. These substations will now be subject to production tax and exempt from property tax. Laws 2006, ch. 259, sec. 10. Minn. Stat. § 272.029, subd. 1.

Payments in Lieu of Property Tax

The 2001 Legislature also allowed a developer of a new or existing medium- or large-scale wind energy conversion system to negotiate with the city or town and the county where the system is located to establish a payment in lieu of property taxes on the property. The payment is to provide fees or compensation to the host jurisdictions to maintain public infrastructure and services. The payment-in-lieu agreement must be signed by the parties and filed with the Commissioner of Revenue and the county recorder. Upon execution and filing of the agreement, the personal property of the system is exempt from property tax. The exemption is effective for the same duration as the in-lieu payments are in effect. No known negotiations are in effect under this provision. Laws 2001, 1st spec. sess., ch. 5, art. 3, sec. 22. Minn. Stat. § 272.028.

This payment in lieu of property tax was modified to a payment in lieu of the production tax by the 2002 Legislature. Laws 2002, ch. 377, art. 4, sec. 12. Minn. Stat. § 272.028.

The Present: 2004 and Thereafter, Wind Energy Production Tax (WEPT)

The local governments weren’t satisfied with the changes made by the 2001 Legislature. They argued that an acceptable in-lieu payment would not be agreed upon and that the taxes based on property were not sufficient. After lengthy discussions, the legislature enacted a production tax in 2002 beginning with taxes payable in 2004. Laws 2002, ch. 377, art. 4, sec. 13. Minn. Stat. § 272.029, subd. 1.

The new law imposes a production tax on the production of electricity from wind energy conversion systems in lieu of the property tax installed after January 1, 1991. However, the land on which the systems are located remains subject to property tax. Laws 2002, ch. 377, art. 4, sec. 6; further amended by Laws 2002, ch. 400, sec. 9. Minn. Stat. § 272.029, subd. 1.

The production tax rates are based on the size of the wind energy conversion system. They are as follows:

• Large-scale systems (nameplate capacity of more than 12 megawatts) pay 0.12 cents per kilowatt-hour

• Medium-scale systems (nameplate capacity between two and 12 megawatts) pay 0.036 cents per kilowatt-hour


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• Small-scale systems (nameplate capacity of two megawatts or less) pay 0.012 cents per kilowatt-hour

• Exempt from the production tax: Very small conversion systems with a nameplate capacity of 0.25 megawatts or less and small-scale systems (two megawatts or less) owned by a political subdivision

Reporting

By February 1 of each year (beginning in 2005), the owner of the wind energy conversion system must file a report to DOR detailing the amount of electricity produced in the previous calendar year. (The filing date was March 1 for 2004, but the 2005 Legislature changed the date to February 1 to allow DOR and local governments more time for administrative and budget planning purposes.) The tax, based on the size of the wind conversion system, must be paid to the county on or before May 15 and October 15, and distributed along with the regular property tax settlements made by the county treasurer to the local governments.

Tax Distribution

For taxes payable in 2004 and 2005 the distribution of the WEPT revenues are based upon the local tax rates; i.e., the proportion that each of the local taxing jurisdiction’s tax rates were to the total tax rate where the wind energy conversion system is located. The state is not included in the distribution of revenues.

For taxes payable in 2006 and thereafter, the distribution of the WEPT will be fixed percentages: 80 percent to counties, 14 percent to cities/townships, and 6 percent to school districts. Laws 2005, ch. 151, art. 5, sec. 15. Minn. Stat. § 272.029, subd. 6.

The amount of the production tax distributed in 2006 is almost $1.4 million. That tax is based on the calendar year 2005 wind energy production. A county-by-county breakdown of the total tax amount is shown on the following page.


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Total Estimated Wind Production Tax by County Based on 2005 Production Tax, Due in 2006

(Total All Taxing Jurisdictions) Murray $448,483 Lincoln 409,973 Pipestone 403,557 Martin 31,589 Jackson 23,420 Mower 16,984 Dodge 13,185 Rock 5,632 Nobles 1,681 Clay 661 Rice 516 Sherburne 106 Total $1,355,787

Number of Systems

There are 108 private wind energy projects in the state; 95 are categorized as small scale, seven are medium scale, and six are large scale (as of the summer of 2006). There are also five municipal wind energy systems (cities of Elk River, Marshall, and Moorhead, and the Southern Minnesota Municipal Power Agency and the Wisconsin Public Power Inc.). They are small-scale systems and are exempt because they are publicly owned. The majority of the systems are located in southwest Minnesota. Since the tax on these systems is now a production tax, their market value is unknown.

Production Incentives

The legislature provided production incentives to wind facilities under two megawatts. The incentive is equal to 1.5 cents per kilowatt-hour if the facility is developed prior to January 2005; or 1 to 1.5 cents per kilowatt-hour if developed after that date. $9.4 million is available annually for this incentive through 2017. Laws 2005, 1st spec. sess., ch. 1, art. 4, secs. 14 and 51. Minn. Stat. §§ 116C.779, subd. 2; 216C.41, subd. 2.

The 2003 legislation required Xcel Energy to deploy 300 megawatts of wind energy capacity in the state by 2010, in addition to the 825 megawatts the utility is already committed to deploy. Laws 2003, 1st spec. sess., ch. 11. Minn. Stat. § 216B.1691, subd. 6.

For more information about property taxes and electric utilities, visit our web site, www.house.mn/hrd/issinfo/tx_prop.htm.


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http://www.revisor.leg.state.mn.us/bin/getpub.php?type=s&num=116C.779








































Docket No. E002/GR-12-961 Information Request No. XLI-103 __________________________________________________________________

Question: The XLI 100 series relates to the testimony of Leanna Chapman. Please provide a copy of the materials describing the Homestead Market Value Exclusion.

Response: Please see Attachment A. __________________________________________________________________ Preparer: Leanna Chapman

Title: Manager Tax Reporting

Department: Tax Services

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Minnesota Revenue, Understanding Recent Changes in Homestead Benefits 1

What is an exclusion? An exclusion is a reduction in the amount of value subject to tax.

Understanding Recent Changes in Homestead Benefits For Property Tax Purposes

What Changed? The 2011 Legislature repealed the Homestead Market Value Credit, (the homestead credit), and replaced it with a new Homestead Market Value Exclusion. The last year of the credit is for property taxes paid in 2011 and the exclusion begins for property taxes payable in 2012.

The old law with the credit was as simple as: X – Y = Z If your initial tax was X, and your credit was Y, then the tax you had to pay was Z. Under the new law, an exclusion changes the initial tax amount (X), and with the credit gone, the new initial tax becomes the final tax (X = Z). HOW DO HOMESTEAD BENEFITS CHANGE? Under the old law, the credit itself equaled the homestead benefit, and its calculation depended only on the value of the homestead. Because the credit was subtracted from the initial tax amount, the credit affected each taxpayer independently. Under the new law, the exclusion is still calculated using the value of the homestead, but the tax benefit depends on a variety of factors other than homestead value. Because the exclusion is a reduction in the value subject to tax, it also affects tax rates and the taxes of all properties. WHY IS THIS CHANGE COMMONLY RESULTING IN TAX INCREASES? There are four reasons why the change commonly results in increases: 1) State money is no longer reducing total taxes. For 2012, the state was projected to pay

approximately $260 million of local taxes through the credit program. With the change, there will be no state paid credit and the entire local property tax levy will be paid by taxpayers.

2) The reduction in taxable value increases tax rates. With the total taxable value being reduced by the exclusion, raising the same total levy as the prior year requires a higher rate.

3) The reduction in taxable value shifts the relative burdens of who pays. With homestead values reduced, other property types (and homes with higher values) pay a larger share of the tax.

4) The exclusion provides less benefit in low tax rate areas than the credit. The computation of the exclusion and credit amounts are roughly comparable where the tax rate is close to the state average, but in lower tax rate areas the excluded value provides less benefit. High rate areas may see greater benefit.

What is a credit? A credit is a reduction in the amount of taxes due.

Docket No. E002/GR-12-961 Information Request No. XLI-103, Attachment A

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Minnesota Revenue, Understanding Recent Changes in Homestead Benefits 2

AVERAGE TAX RATE ILLUSTRATION Old Law: New Law: Credit Exclusion Estimated Market Value $116,000 $116,000 Exclusion $0 $26,800 Taxable Market Value $116,000 $89,200 Class Rate 1% 1% Net Tax Capacity $1,160 $892 Tax Rate 105.810% 110.920% Gross Tax $1,227 $989 Credit $268 $0 Net Tax $959 $989

LOW TAX RATE ILLUSTRATION Tax Rate 63.486% 66.552% Gross Tax $736 $594 Credit $268 $0 Net Tax $468 $594

COMPUTATION OF CREDIT AND EXCLUSION AMOUNTS Even though the tax benefits of the credit and the exclusion are not equal, the calculation of the exclusion amount is similar to the calculation of the former credit. Both reach their maximum at $76,000 of market value ($304 for the credit; $30,400 for the exclusion). Both reduce to $0 at about $414,000 of market value.

Example: A house valued at $116,000.

Credit = (0.4% x $76,000) – ($40,000 x 0.09%) = $304 – $36 = $268

Exclusion = (40% x $76,000) – ($40,000 x 9%) = $30,400 – $3,600 = $26,800

WANT MORE DETAILS? CONSIDER THIS THEORETICAL ILLUSTRATION Similarly computed amounts do not yield equal benefits:

NOTE: This illustration does not reflect an actual location. WHAT ELSE AFFECTS MY TAXES (IN ADDITION TO THE HOMESTEAD BENEFIT)? Local levy decisions, including the effects of changes in state aid and local budget priorities. Market forces can affect property taxes in two ways:

The value of your property may increase or decrease. The value of other properties may increase or decrease and change the share that your

property is of the total tax base, whether your property’s value changed or not. Various other changes (the classification or your property, eligibility for other benefits, and miscellaneous law changes) may also affect property taxes.

Credit = 0.4% of the first $76,000, minus 0.09% of the value over $76,000.

Exclusion = 40% of the first $76,000, minus 9% of the value over $76,000.

Under the old law the full value was taxed, but the new exclusion lowers the taxable value.

Let’s say you live in a house valued at $116,000.

Different classes of property are taxed at different levels. The first $500,000 of homestead value has a rate of 1%. (Higher value has a rate of 1.25%.)

“Net tax capacity” is a term describing the taxable value after class rates are applied. Again, this is lower under the new law due to the exclusion. Tax rates increase because the exclusion shrinks the taxable value. This illustration shows statewide average rates before and after the change. The gross tax under the old law was higher because there was no exclusion, but the credit reduced the net tax. Under the new law the gross and net are the same. Here the increase is modest, but… Tax rates affect the relative strength of the exclusion because multiplying excluded value by a low rate is less beneficial than multiplying it by a high rate. So, under a “low tax rate” example, the increase in tax is more extreme.

Docket No. E002/GR-12-961 Information Request No. XLI-103, Attachment A

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Question: Please provide a copy of Exhibit LMC-1, Schedule 2 in electronic native (i.e., EXCEL or compatible) format with all formulas and links intact.

Response: To view the live files, please see the CD containing live files of witness exhibits:

Folder: 21 Property Tax-Chapman Subfolder: Discovery File name: Schedule 02 - 2016 NSPM Property Tax.xlsx Schedule 04 - 2017 NSPM Property Tax.xlsx

Schedule 06 - 2018 NSPM Property Tax.xlsx


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Question: Referring to Exhibit LMC-1, Schedule 2: a. Please define the term Cost Indicator of Value. b. Please reconcile the 2016 Electric Cost Indicator of Value to the proposed plant

investments/rate base presented in Exhibit AEH-1, Schedule 8. c. Please define the term NOI to Capitalize and explain how this term is measured. d. Please reconcile the 2016 Electric NOI to Capitalize with the proposed return

presented in Exhibit AEH-1, Schedule 3. e. Please define the term Capitalization Rate. f. Please reconcile the Capitalization Rate with the proposed rate of return

presented in Exhibit AEH-1, Schedule 3. g. Please explain how the deductions to MN allocated value were determined. h. Please provide documentation supporting the effective tax rates. i. Please provide documentation supporting the locally assessed amounts. j. Please provide work papers showing how the property tax reflected on this

schedule was adjusted to the test year revenue requirement amount. Response:

a. Minnesota Administrative Rule 8100.0300, subp. 3 describes in part the cost indicator of value as:

The cost factor to be considered in the utility valuation formula is the original cost less depreciation of the system plant, plus the cost of improvements to the system plant, plus the original cost of all types of construction work in progress that are installed by the assessment date, plus the cost of property held for future use, plus the cost of contributions in aid of construction.

b. The Cost Indicator of Value shown in Exhibit___(LMC-1), Schedule 2 is

calculated according to the formula contained in Minn. R. 8100.0300, subp. 3. The plant investments/rate base information presented in Exhibit___(AEH-1), Schedule 7 is calculated according to the standards and methodology used by the Commission for ratemaking. Importantly, the Company used the same starting point to calculate both the Cost Indicator of Value shown in Exhibit___(LMC-

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1), Schedule 2 and the plant investments/rate base information presented in Exhibit___(AEH-1), Schedule 7. Attachment A to our response to XLI-113 includes a detailed reconciliation of the components of the Cost Indicator of Value and the 2016 Plant Information Budget.

c. Minnesota Administrative Rule 8100.0100, subp. 9 defines net operating earnings

as follows:

Net operating earnings” means earnings from the system plant of the utility after the deduction of operating expenses, depreciation, and taxes, but before any deduction for interest.

Minnesota Administrative Rule 8100.0300, subp. 4, explains the process for calculating the income indicator of value:

The income indicator of value is estimated by weighting the capitalized net operating earnings of the utility company for the most recent three years as follows: most recent year, 40 percent; previous year, 35 percent; and final year, 25 percent. Utilities may request the removal of nonrecurring items of income or expense. The commissioner must determine if removal of the item is appropriate. The net income is capitalized by applying a capitalization rate that is computed by using the band of investment method.

d. The 2016 NOI to Capitalize included in Exhibit LMC-1, Schedule 2 is calculated

according to the formula described in Minn. R. 8100.0300, subp. 4. Specifically, the 2016 NOI to Capitalize is equal the Company’s net operating income for the years 2013, 2014, and 2015 (estimated) unless the DOR used a different weighting percentage for 2015 as follows:

Year Electric Weight Gas Weight 2013 0% 25% 2014 40% 35%

2015 (Estimated) 60% 40% The net operating income amounts for 2013 and 2014 are based on NSPM FERC Form 1 data, adjusted for trading revenues, while 2015 net operating income is based upon a forecast.

The information presented in Exhibit __ (AEH-1), Schedule 3 is based on the standards and methodology used by the Commission in calculating the overall revenue deficiency. In addition to being for different periods (weighted blend of 2013, 2014, and 2015 verses 2016), the net operating income figures used in

Appendix A, 07



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Exhibit___(AEH-1), Schedule 3 are calculated according to the Commission’s ratemaking standards, which are different from FERC Form 1 reporting purposes.

The purposes of the NOI to Capitalize and the proposed return are different and the methodologies used to determine the NOI to Capitalize and the proposed return are different. Accordingly, there is no basis for reconciliation between the two.

e. Minnesota Administrative Rule 8100.0100, subp. 5, defines capitalization rate as:

“Capitalization rate” means the relationship of income to capital investment or value, expressed as a percentage.

Minnesota Administrative Rule 8100.0300, subp. 4 provides additional detail:

The net income is capitalized by applying a capitalization rate that is computed by using the band of investment method. This method considers:

A. the capital structure of utilities; B. the cost of debt or interest rate; C. the yield on preferred stock of utilities; D. the yield on common stock of utilities; and E. the risk-free rate, relative risk, and risk premiums for public utility companies.

Capitalization rates are computed each year for electric companies, gas distribution companies, natural gas transmission systems, and fluid pipeline companies. The rates are recalculated each year using the method described in this subpart.

f. The Capitalization Rates included in Exhibit LMC-1, Schedule 2 are based on the

methodology used by the Minnesota Department of Revenue to determine the value of the Company’s utility property for property tax purposes. They are calculated under the criteria of Minn. Rule 8100.0300, subp. 4 for the purpose of discounting income to determine one of the inputs into the overall valuation of the Company’s utility property.

The rate of return presented in Exhibit___(AEH-1), Schedule 3 is based on the standards and methodology used by the Commission to establish the capital structure and the appropriate Rate of Return (ROR) for the Company for ratemaking purposes, including the Commission’s standards and methodology used to determine the Return on Equity (ROE). The Company’s rate case filing proposed a capital structure, cost of debt (short term and long term) and ROE

Appendix A, 07



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for purposes of setting final rates based on the Commission’s standards and methodologies. Exhibit AEH-1, Schedule 3 reflects the Company’s proposal.

The purposes of the Capitalization Rate and the ROR are different and the methodologies used to determine the Capitalization Rate and ROR are different. Accordingly, there is no basis to expect that the two would be similar to provide a reconciliation.

g. Minnesota Administrative Rule 8100.0500 generally explains the process for

adjusting the valuation performed under Rule 8100.0300. As shown in Exhibit LMC-1, Schedule 2, deductions generally fall into four categories: depreciable plant deductions; land; CWIP; and other – held for future use.

h. Please see Exhibit LMC-1, Schedule 9, which shows the calculation of the

effective tax rate. i. Taxing jurisdictions do not provide the Company with statements detailing the

portion of its property that is state assessed and the portion that is locally assessed; rather, property tax statements show total value. The Company calculates the total value of locally assessed property by subtracting the total value of state assessed property from the total value of all property indicated in the property tax statements. Using this method, the Company calculated the total value of its locally assessed property to be $335 million in 2016.

j. Please see Volume 4, Test Year Workpapers, P6. Property Tax. __________________________________________________________________ Preparer: Leanna Chapman / Anne Heuer

Title: Manager Tax Reporting / Director, Revenue Analysis

Department: Tax Services / Revenue Requirements North

Appendix A, 07



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Question: Please provide the following actual information for the latest available year for each local tax jurisdiction that NSPM pays property tax:

a. DOR apportioned unit value. b. Overall market value. c. Class rate. d. Tax rate.

Response:

a. The DOR apportions the Company’s total unit value to each taxing jurisdiction. The local taxing jurisdictions combine the apportioned unit value with locally assessed property to arrive at the total value that is subject to property tax. The local jurisdictions do not report back to the Company the portion of the total value attributable to state assessed property and the portion assessed locally.

b. Please see Exhibit LMC-1, Schedule 9. c. The class rate is set by the legislature, can be found in Minn. Stat. § 273.13, and

is uniform statewide. d. Please see Exhibit LMC-1, Schedule 9.


Appendix A, 08



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Question:

In reference to Schedule 2, concerning the test year property tax expense estimate: a. Please reconcile the following Electric amounts to the beginning 2016 test year

amounts: i. Plant In-service ii. CWIP iii. Depreciation (Reserve)

b. Please provide all work papers and sources used to determine the Electric inputs

for the Deductions for MN Allocated Value items: i. Depreciable Plant Deductions ii. Land iii. CWIP

c. Please provide all work papers and sources used to determine the inputs for and

explain how these items were allocated to electric and gas: i. Locally Accessed ii. Wind Production

Response:

a. i. Please see Attachment A, Page 1 for the reconciliation of the Electric Plant in

Service from Exhibit LMC-1, Schedule 2 to the Electric Plant in Service Beginning 2016 test year amount.

ii. Please see Attachment A, Page 2 for the reconciliation of the Electric CWIP Balance from Exhibit LMC-1, Schedule 2 to the Electric CWIP Beginning 2016 test year amount.

iii. Please see Attachment A, Page 3 for the reconciliation of the Electric Depreciation Reserve from Exhibit LMC-1, Schedule 2 to the Electric Depreciation Reserve Beginning 2016 test year amount.

b.

i. Please see Attachment B, Page 1 for the calculation of the Depreciable Plant Deductions shown in Exhibit LMC-1, Schedule 2. The Company did not forecast the value of Depreciable Excludables, which is one of the variables

Appendix A, 09



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used to calculate Depreciable Plant Deductions. We therefore calculated a depreciable plant percentage based upon 12/31/2015 forecasts and applied it to the actual 2014 Depreciable Excludables in order to arrive at total Depreciable Plant Deductions.

ii. Please see Attachment B, Page 2 for the calculation of the Land deductions

shown in Exhibit LMC-1, Schedule 2. Note, only value associated with Minnesota land is eligible for deduction. The Company did not forecast the value of land deductions; therefore, as shown on Page 2 of Attachment B, the Land value is based upon actual 2014 year end land values.

iii. Please see Attachment B, Page 3 for the calculation of CWIP

deductions. CWIP deductions are a function of three different CWIP categories: Electric, Common, and Nuclear Fuel. Both Common and Nuclear Fuel CWIP are assumed to be fully deductable, as the majority of common plant is locally assessed and therefore excluded (or deducted) from the valuation of utility property and nuclear fuel is exempt from property taxes. According to Minnesota Administrative Rules 8100.0100 and 8100.0300, the actual amount of Electric CWIP excluded (or deducted) depends on the actual amounts installed as of the assessment date. Because the actual amount installed is currently unknown, we assumed 50% of Electric CWIP would be eligible for deduction.

c. i. As stated in our response to XLI-109, part i, taxing jurisdictions do not provide

the Company with statements detailing the portion of its property that is state assessed and the portion that is locally assessed; rather, property tax statements show total value. The Company calculates the total value of locally assessed property by subtracting the total value of state assessed property from the total value of all property indicated in the property tax statements. Using this method, the Company calculated the total value of its locally assessed property to be $335 million in 2016, which, when multiplied by the 2016 effective rate of 3.3%, results in $11.1 million in property taxes on locally assessed property. Locally assessed amounts are allocated to electric and gas based on percentage of gross plant by function (production, transmission, distribution).

ii. The 2016 Wind Production amount of $2.1 million is based on actual 2014

property taxes paid of $1.3 million for the Wind Energy Production Tax plus an additional $0.8 million for a new wind farm going into service in 2015. The $2.1 million is included in the Electric Production amount in Exhibit LMC-1, Schedule 2. Wind Production is allocated entirely to electric.

Appendix A, 09



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To view the live files, please see the CD containing live files of witness exhibits: Folder: 21 Property Tax-Chapman Subfolder: Appendix A File name: Appendix A 10 - XLI 113 Att A.xls Appendix A 11 - XLI 113 Att B.xls

__________________________________________________________________ Preparer: Shari Cardille / Leanna Chapman

Title: Principal Rate Analyst / Manager Tax Reporting

Department: Revenue Requirements North / Tax Services

Appendix A, 09



Page 39 of 72

Docket No. E002/GR-12-961Information Request No. XLI-113, Attachment A

Northern States Power CompanyTotal Company Plant ReconciliationSchedule 3 to Jurisdictional Cost Of Service Study2016 Beginning Plant Balance

Plant in Service From Schedule 3 Electric 2016

Plant in Service From Schedule 3 17,149,342,643$ Nuclear Fuel 2,300,659,329$ Less Saver Switch Capital Removed 22,705,000$ Less Photovoltaic and HFU Removed 2,190,000$ Plus PreFunded (184,782,000)$ Plus Common Allocation in Case 574,822,000$ Less Common Estimate Income Tax Used 571,321,076$ Less Lakefield Junction 6,127,900$ Less Plant Recorded ARC 556,919,269$ Less Plant Recorded ARC - Common (1,725,331)$ Total 18,682,504,059$

Total - 2016 Budget (CAA Version 96 Rounded to 000's) 18,682,504$

Beginning Plant in Service Rounded to 000's (Workpaper P1-2C) 18,682,507$

Difference (Rounding) 3

COSS Electric 2016

Beginning Plant in Service Rounded to 000's (Workpaper P1-2C) 18,682,507$

Adjustments:Nuclear Fuel Update 465$ Rate Rider Adjustment (188,119)$ New Business CIAC (1,400)$ Total Beginning Plant in Service 18,493,453$

Total Beginning Plant in Service (Workpaper P1-3C) 18,493,454$

Difference (Rounding) (1)$

Appendix A, 10



Page 40 of 72


Northern States Power CompanyTotal Company CWIP ReconciliationSchedule 3 to Jurisdictional Cost Of Service Study2016 Beginning CWIP Balance

CWIP From Schedule 3 Electric 2016

CWIP From Schedule 3 607,258,386$ Plus PreFunded (3,223,000)$ Plus Common Allocation in Case 44,339,000$ Less Common Estimate Income Tax Used 45,013,100$ Total 603,361,286$

Total - 2016 Budget (CAA Version 96 Rounded to 000's) 603,361$

Beginning CWIP Rounded to 000's (Workpaper P1-2I) 603,360$

Difference (Rounding) (1)

COSS Electric 2016

Beginning CWIP Rounded to 000's (Workpaper P1-2I) 603,360$

Adjustments:Rate Rider Adjustment (107,481)$ Total Beginning CWIP 495,879$

Total Beginning CWIP (Workpaper P1-3I) 495,880$

Difference (Rounding) 1

Appendix A, 10



Page 41 of 72


Northern States Power CompanyTotal Company Depreciation Reserve ReconciliationSchedule 3 to Jurisdictional Cost Of Service Study2016 Beginning Depreciation Reserve Balance

Beginning Depreciation Reserve From Schedule 3 Electric 2016

Beginning Depreciation Reserve From Schedule 3 6,114,339,627$ Nuclear Fuel 2,065,086,122$ Less Saver Switch Capital Removed 22,705,000$ Less Photovoltaic Removed 306,000$ Plus PreFunded (30,440,000)$ Plus Common (Including RWIP) Allocation in Case 281,719,000$ Less Common Estimate Income Tax Used 284,817,529$ Less Lakefield Junction 2,026,011$ Less Plant Recorded ARC 130,174,180$ Less Plant Recorded ARC - Common (1,765,438)$ Less Common RWIP Estimate Income Tax Used (227,700)$ Less Sherco Reg Asset and PI EPU Reg Asset Amortization (6,675,384)$ Less Theoretical Reserve - Direct Assign WI (22,006,274)$ Difference Between Financial View and MN Rules 6,384,156$ Total 8,027,734,980$

Total - 2016 Budget (CAA Version 96 Rounded to 000's) 8,027,735$

COSS Electric 2016

Beginning Depreciation Reserve Rounded to 000's (Workpaper P1-2G) 8,027,735$

Adjustments:Like Kind Exchange Program 3,149$ Rate Rider Adjustment (1,606)$ New Business CIAC (455)$ Total Beginning Depreciation Reserve 8,028,823$

Total Beginning Depreciation Reserve (Workpaper P1-3G) 8,028,823$

Appendix A, 10



Page 42 of 72

Information Request No. XLI-113, Attachment B

Calculation of Depreciable Plant Deductions

Plant in Service, 12/31/2015 Forecast 17,149,342,643$ Less: Non-depreciable Amounts in Plant in Service (194,912,446)$

Depreciable Plant in Service 16,954,430,197$ A

Depreciation, 12/31/2015 Forecast 6,114,339,627$ B

Depreciable Plant Percentage 36.06% C = B / A

Depreciable Excludables, 12/31/2015 Forecast 3,369,736,079$ D

Depreciation Amount 1,215,126,830$ E = C x D

Estimated Depreciable Plant Deductions 2,154,609,249$ = D - E

Appendix A, 11



Page 43 of 72


Calculation of Land Deductions

Total Non-Depreciable Excludables, 12/31/2015 Forecast 515,504,429$ Less Non-Land Itmes:

Qualifying CWIP (Electric), 12/31/2015 Forecast (148,752,920)$ Qualifying CWIP (Common Plant), 12/31/2015 Forecast (39,611,528)$ Qualifying CWIP (Nuclear Fuel), 12/31/2015 Forecast (146,923,014)$ Other Held for Future Use - Other, 12/31/2015 Forecast -$

Total Excludable Land, 12/31/2015 Forecast 180,216,966$

Appendix A, 11



Page 44 of 72


CWIP DeductionsCWIP Category

Total CWIP, 12/31/2015 Forecast 493,057,081$ CWIP (Electric), 12/31/2015 Forecast 297,505,841$ CWIP (Common Plant), 12/31/2015 Forecast 39,611,528$ CWIP (Nuclear Fuel), 12/31/2015 Forecast 146,923,014$

CWIP Deduction PercentagesCWIP (Electric) 50%CWIP (Common Plant) 100%CWIP (Nuclear Fuel) 100%

Deductable CWIPCWIP (Electric) 148,752,920$ CWIP (Common Plant) 39,611,528$ CWIP (Nuclear Fuel) 146,923,014$

Total Deductable CWIP 335,287,463$

Appendix A, 11



Page 45 of 72

Docket No. E002/GR-13-868 Information Request No. DOC-195 __________________________________________________________________

Question: Reference: Direct Testimony of Leanna M. Chapman at Page 2 Exhibit_____(LMC-1), Schedule 2 Please footnote each line item in the above referenced Schedule 2 to source documentation in detailed workpapers that develop the line item, and provide the information or reference its location in the pre-filed documents. Response: Please see Attachment A to this response. Attachment A is also included as an electronic file titled “Appendix A 13 - DOC-195 Attachment A.xlsx” submitted with this response. __________________________________________________________________ Preparer: Leanna Chapman



Appendix A, 12



Page 46 of 72

DOC Information Request No. 195Attachment A

Total Company Property Taxes

Electric Gas DOC-195 FootnotesSYSTEM UNIT VALUE CALCULATION

Plant In Service, 12/31/15 Forecast [1] 17,149,342,643 1,333,020,462 Exhibit__(LMC-1), Appendix A 10 (XLI-113, Attachment A) and Page 2 of this attachmentCWIP, 12/31/15 Forecast [2] 607,258,386 11,349,113 Exhibit__(LMC-1), Appendix A 10 (XLI-113, Attachment A) and Page 2 of this attachmentDepreciation, 12/31/15 Forecast [3] (6,114,339,627) (612,321,495) Exhibit__(LMC-1), Appendix A 10 (XLI-113, Attachment A) and Page 3 of this attachmentCost Indicator of Value [4] $11,642,261,401 $732,048,080 Calculation (Sum of 1, 2, and 3)

Income Indicator2013 NOI x 25% or 0% [5] 0 10,353,101 Exhibit__(LMC-1), Appendix A 15 & 16 Page 62014 NOI x 35% or 40% [6] 199,663,578 16,353,612 Exhibit__(LMC-1), Appendix A 15 & 16 Page 62015 Estimated NOI x 40% or 60% [7] 341,821,336 20,096,800 Exhibit__(LMC-1), Appendix A 14 - DOC-195 Attachment B

NOI to Capitalize [8] $541,484,914 $46,803,513 Calculation (Sum of 5, 6 and 7)Capitalization Rate [9] 7.40% 7.30% Exhibit__(LMC-1), Appendix A 15 & 16 Page 6

Income Indicator of Value [10] $7,317,363,697 $641,144,010 Calculation (8 divided by 9)

Apply Weightings 35/65 50/50Cost Indicator [11] $4,074,791,500 $366,024,000 Calculation (4 multiplied by 50%)Income Indicator [12] $4,756,286,400 $320,572,000 Calculation (10 multiplied by 50%)

Total System Unit Value [13] $8,831,077,900 $686,596,000 Calculation (Sum of 11 and 12)

ALLOCATION OF SYSTEM VALUEMN Plant in Service [14] 16,389,639,716 1,221,353,186 Page 4 of this attachment (Electric Total Plant per Forecast + Electric Total CWIP per Forecast) System Plant in Service [15] 17,756,601,028 1,344,369,575 Calculation (Sum of 1 and 2)Plant Ratio x 90%-Elec / x 75%-Gas [16] 83.07% 68.14% Calculation (14 divided by 15 multiplied by 90% Electric / 75% Gas)MN Gross Revenue [17] 3,731,409,068 674,888,573 Exhibit__(LMC-1), Appendix A 15 & 16 Page 3 or 4System Gross Revenue [18] 4,239,532,104 762,665,589 Exhibit__(LMC-1), Appendix A 15 & 16 Page 3 or 4Revenue Ratio x 10%-Elec / x 25%-Gas [19] 8.80% 22.12% Calculation (17 divided by 18 multiplied by 10% Electric / 25% Gas)

MN Allocated Value Percentage [20] 91.87% 90.26% Calculation (Sum of 16 and 19)MN Allocated Value [21] $8,113,111,300 $619,721,500 Calculation (13 multiplied by 20)

Depreciable Plant Deductions [22] 2,154,609,249 58,486,056 Exhibit__(LMC-1), Appendix A 11 (XLI-113, Attachment B) Land [23] 180,216,966 3,393,588 Exhibit__(LMC-1), Appendix A 11 (XLI-113, Attachment B) CWIP [24] 335,287,463 6,124,597 Exhibit__(LMC-1), Appendix A 11 (XLI-113, Attachment B) Other - Held for Future Use [25] 0 0Subtotal [26] 2,670,113,678 68,004,241 Calculation (Sum of 22, 23, 24 and 25)Ratio - System Unit Value / Cost Indicator [27] 75.85% 93.79% Calculation (13 divided by 4)

DEDUCTIONS TO MN ALLOCATED VALUE [28] $2,025,281,200 $63,781,200 Calculation (26 multiplied by 27)Sliding Scale Market Value Exclusion [29] $200,000,000 $0

DEDUCT/EXCL TO MN ALLOCATED VALUE [30] $2,225,281,200 $63,781,200 Calculation (Sum of 28 and 29)Apportionable Market Value [31] $5,887,830,100 $555,940,300 Calculation (21 less 30)Effective Tax Rate [32] 3.3% 3.3% Exhibit__(LMC-1), Schedule 9FORECASTED PROPERTY TAX - Elec & Gas [33] $194,298,393 $18,346,030 Calculation (31 multiplied by 32)

Rounded [34] $194,300,000 $18,300,000 Calculation (Rounding)Total Electric & Gas [35] $212,600,000 Calculation (Sum of 34 for Electric and Gas)Locally Assessed [36] $11,100,000 Exhibit__(LMC-1) Schedule 9 x Appendix A (XLI-109, response i)Wind Production [37] $2,100,000 Estimate based on actual prior year & addition of a new wind farm going into service in 2015

TOTAL MINNESOTA FORECASTED PROPERTY TAX [38] $225,800,000 Calculation (Sum of 35, 36 and 37)

North Dakota & South Dakota Property Tax [39] $8,000,000

TOTAL NSPM FORECASTED PROPERTY TAX [40] $233,800,000 Calculation (Sum of 38 and 39)

2016 FTY

Appendix A, 13



Page 47 of 72


NSPM - System Plant in Service and CWIP

2015 EOYElectric Gas Common Nuclear Fuel Non-Utility

Plant JUR file Total 16,016,699,729 1,230,016,466 649,228,495 2,300,659,329 12,557,148 less:

Plant - Nuclear Fuel (2,300,659,329) Plant - Non-Utility (12,557,148)

add:Plant - ARC 556,919,269 25,331,850 (1,960,604) - - Subtotal 16,573,618,998 1,255,348,315 647,267,891 - -

Lakefield Junction 6,127,900 Common Allocation 569,595,744 77,672,147 (647,267,891)

Total Plant per Forecast 17,149,342,643 1,333,020,462

Electric Gas Common Nuclear Fuel Non-UtilityCWIP JUR file Total 415,322,271 5,210,963 51,151,250 146,923,014 - less:

Plant - Non-Utility - Reclass Nuclear Fuel to Electric 146,923,014 (146,923,014)

Subtotal 562,245,286 5,210,963 51,151,250 - -

Common Allocation 45,013,100 6,138,150 (51,151,250)

Total CWIP per Forecast 607,258,386 11,349,113

denotes calculationdenotes link

Appendix A, 13



Page 48 of 72


NSPM - Depreciation


Reserve JUR file Total 7,202,321,989 573,570,035 323,656,283 2,065,086,122 8,579,449 less:

Acc. Depr. - Nuclear Fuel (2,065,086,122) Acc. Depr. - Decommissioning (1,441,619,536) Acc. Depr. - Non-Utility (8,579,449)

add:Acc. Depr. - ARC 130,174,180 403,776 (2,006,179) - - Acc. Depr. - RWIP (61,387,408) (219,279) (258,750) - - Subtotal 5,829,489,224 573,754,533 321,391,354 - -

Lakefield Junction Depreciation 2,026,011 Common 282,824,391 38,566,962 (321,391,354)

Total per Forecast 6,114,339,627 612,321,495


Appendix A, 13



Page 49 of 72


NSPM - Minnesota Plant in Service and CWIP


Plant JUR file Total 14,841,514,949 1,118,681,382 571,321,076 2,300,659,329 12,356,571 less:

Plant - Nuclear Fuel (2,300,659,329) Plant - Non-Utility (12,356,571)

add:Plant - ARC 556,919,269 25,331,850 (1,960,604) - - Subtotal 15,398,434,218 1,144,013,232 569,360,472 - -

Lakefield Junction 6,127,900 Common Allocation 501,037,215 68,323,257 (569,360,472)

Total Plant per Forecast 15,905,599,333 1,212,336,489

Electric Gas Common Nuclear Fuel Non-UtilityCWIP JUR file Total 297,505,841 3,615,126 45,013,100 146,923,014 - less:

Plant - Non-Utility - Reclass Nuclear Fuel to Electric 146,923,014 (146,923,014)

Subtotal 444,428,855 3,615,126 45,013,100 - -

Common Allocation 39,611,528 5,401,572 (45,013,100)

Total CWIP per Forecast 484,040,383 9,016,698


Appendix A, 13



Page 50 of 72

DOC Information Request No. 195Attachment B - Page 1 of 1

2015 Electric Gas2013 Actual $466,957,455 $41,412,4042014 Actual $499,158,944 $46,724,6052015 Forecasted $569,702,227 $50,242,0002013 Actual 0% 25%2014 Actual 40% 35%2015 Forecasted 60% 40%2013 Actual $0 $10,353,1012014 Actual $199,663,578 $16,353,6122015 Forecasted $341,821,336 $20,096,800Total $541,484,914 $46,803,513

Net Income

Factors

Total Net Income to Capitalize

Appendix A, 14



Page 51 of 72

Summary Appraisal Report

NORTHERN STATES POWER CO

2015 Assessment

REVISED 22-Jul-2015

Property Tax DivisionState Assessed Properties Section

Appendix A, 15



Page 52 of 72

RECONCILIATION OF VALUE

SYSTEM UNIT VALUECost Indicator

Income Indicator

Market Indicator

Direct Indicator

$10,386,286,420

$6,571,329,027

$8,571,069,105

$9,534,869,569

35%

65%

0%

0%

$3,635,200,200

$4,271,363,900

$0

$0

System Unit Value

ALLOCATION OF SYSTEM VALUE

$7,906,564,100

MN Allocation Factor(Carried over from Allocation Page)MN Allocated Value

0.9355

$7,396,590,700

DEDUCTIONS TO MN ALLOCATED VALUE

Deductions to MN Allocated Value(Carried Forward from Deductions Page)

$2,083,288,200

Apportionable 2015 Market Value $5,313,302,500

2015 Assessment of Utility CompaniesAs of January 2, 2015


Appendix A, 15



Page 53 of 72

SYSTEM UNIT ALLOCATION TO MINNESOTA

System Plant Ratio

SYSTEM MN

Utility Plant $14,766,627,631 $13,977,739,432

Additions:

CWIP $684,173,274 $610,122,061

Land $194,912,446 $180,216,966

Electric Common Plant in Service $493,868,762

Common Plant CWIP $31,146,238

Nuclear Fuel-in-Process $191,187,454

Plant Held for Future Use $27,363,449

Lakefield Junction Substation $6,127,900

Acquisition Adjustment $222,385







Total Utility Plant $16,395,629,539 $15,439,739,124

Factor of MN Plant to System Plant 0.9417

Weighting Factor 0.9000

MN Weighted Plant Factor 0.8475

Operating Revenue Ratio

SYSTEM MN

Operating Revenues $4,239,532,104 $3,731,409,068

Ratio of MN Revenue to System Revenue 0.8801

Weighting Factor 0.1000

MN Weighted Factor 0.0880

MN Allocation Factor 93.55%



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DEDUCTIONS TO MINNESOTA ALLOCATED UNIT VALUE

Deductions

Depreciable Excludables $3,369,736,079

Depreciable Plant Percentage 39.36%

Depreciation Amount $1,326,328,121

Net Depreciable Excludables $2,043,407,958

Non-Depreciable Excludables $693,079,854

Total MN Excludables $2,736,487,812

Ratio of System Unit Value and Cost Indicator

System Unit Value $7,906,564,100

System Unit Cost $10,386,286,420

Excludables Ratio 0.7613

Deductions to MN Allocated Value $2,083,288,200

MN Deductions carried forward to MN Allocated Value

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COST INDICATOR

Plant Accounts

Plant In Service $14,766,627,631

CWIP $684,173,274

Land $194,912,446







Total Plant in Service (FERC) $16,395,629,539

Non-Depreciable Plant Costs

CWIP $684,173,274

Land $194,912,446



Held for Future Use $27,363,449

Total Non-Depreciable Plant $1,128,782,861

Plant Depreciation

Accumulated Deprec. & Amortization $5,768,137,421

Common Plant Depreciation $239,318,873

Lakefield Junction Substation Depreciation $1,886,825

Total Plant Depreciation $6,009,343,119

Depreciable Plant $15,266,846,678

Plant Depreciation Percentage Applied to MN 39.36%

(Total Plant Depreciation/Depreciable Plant)

Cost Indicator

Plant in Service $16,395,629,539

Less: Depreciation $6,009,343,119

Cost Indicator of Value $10,386,286,420



SYSTEM UNIT VALUE

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SYSTEM UNIT VALUE

INCOME INDICATOR

Operating Revenues $4,239,532,104

Operation & Maintenance Expense $2,985,187,229

Depreciation & Amortization Expense $481,174,132

Income Taxes $20,310,247

Deferred Income Tax $501,712,241

Taxes Other Than Income $200,716,167

Depreciation Expense for Asset Retirment $7,552,093

Regulatory Debits $29,249,034

(less) Regulatory Credits ($237,748,381)

Investment Tax Credit Adjustment ($1,458,907)

Losses from Disposal of Utility Plant $173,039

(less) Gains from Disposition of Allowances ($828,138)

Accretion Expense $90,144,063

Net Proprietary Trading Revenues $129,878

(less) Provision for Deferred Income Taxes ($348,109,628)

Total Expenses $3,728,203,069

NOI $511,329,035

2012 2013 2014

Net Operating Income $454,405,356 $466,957,455 $499,158,944

0.40 0.60

Weighted Income $186,782,982 $299,495,366

Total of Weighted Income $486,278,348

Cap Rate 7.40%

Income Indicator of Value $6,571,329,027

DIRECT INDICATOR

Income to be Capitalized $486,278,348

Direct Capitalization Rate 5.10%

Direct Indicator of Value $9,534,869,569

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SYSTEM UNIT VALUE

MARKET INDICATOR

Market Approach

Number of Shares 504,117,000

Stock Price $33.30

Share Price Total $16,787,096,100

Percent of Parent Company Attributable to Unit Company 36.20%

Equity Value of Parent Company Attributable to Unit Company $6,076,928,788

Market Value

Market Value of Long Term Debt $13,360,236,000


Portion of LTD of Parent Company that is Attributable to Unit Company $4,836,405,432

Current Liabilities $1,039,535,604

Total Stock & Debt Value $11,952,869,824

(Less) Current Assets $1,092,417,334

(Equals) Total Stock & Debt Value less Current Assets $10,860,452,490

(x) Operating Property Percentage 78.92%


Operating Property Percentage Calculation

Net Property, Plant, & Equipment $10,386,286,420

(/) Total Assets - Current Assets $15,714,816,819

(Equals) Operating Property Percentage 66.09%

Net Carrier Operating Income $518,552,448

(/) Net Carrier Operating Income + Non-Carrier Income + Other Income $565,222,549

(Equals) Carrier Operating Property Percentage 91.74%

Selected Operating Property Percentage 78.92%

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SYSTEM UNIT VALUE

Percent of Parent Company Attributable to Unit Company

Unit Revenues $4,239,532,104

Parent Revenues $11,686,135,000

% of Revenues 36.28%

Unit Net Plant in Service $10,386,286,420

Parent Net Plant $28,756,916,000

% of Net Plant 36.12%


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$ 4,062,815,933Total Excludable Property

Non-Depreciable Excludable Property

Land 180,216,966

MN Qualifying CWIP 485,610,360

Common Plant CWIP 27,252,528

$ 693,079,854Non-Depreciable Excludable Property

Depreciable Excludable Property

Inventory Of Meters 49,438,138

Intangible Plant 317,958,596

Pollution Control 1,188,952,943

Distribution Lines in Rural Areas 56,902,564

General Plant Items 346,555,571

Misc Equipment 96,876,790

Retirements on Books 9,942,420

Monticello Training Center 4,221,122

Prairie Island Training Center 3,806,413

Simulators 36,456,201

Blue Lake Exemption 67,750,502

Wind Farm Exemption 763,411,559

Common Plant 427,157,121

Photovoltaic Devices 306,139

$ 3,369,736,079Depreciable Excludable Property

Itemized List of Excludable Property to MinnesotaAllocated Unit Value


Appendix A, 15



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Summary Appraisal Report


2015 Assessment

Property Tax DivisionState Assessed Properties Section

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RECONCILIATION OF VALUE

SYSTEM UNIT VALUECost Indicator

Income Indicator

Market Indicator

Direct Indicator

$670,141,633

$562,208,055

$982,236,676

$820,823,760

50%

50%

0%

0%

$335,070,800

$281,104,000

$0

$0

System Unit ValueALLOCATION OF SYSTEM VALUE

$616,174,800

MN Allocation Factor(Carried over from Allocation Page)MN Allocated Value

0.9036

$556,775,500

DEDUCTIONS TO MN ALLOCATED VALUEDeductions to MN Allocated Value(Carried Forward from Deductions Page)

$61,018,700

Apportionable 2015 Market Value $495,756,800

Appraiser's comments regarding the company valuationBy default per Minnesota Rule Chapter 8100, the original cost less depreciation model and no growth yield model are completed and given equal weight in the reconciliation of unit value.Based on available information, the department did not deviate from the default weighting for this valuation.

In addition to the default models, the department analyzed a direct income model and a stock & debt model. No weight was placed on either model.

The company did not provide their financial forecasts to the department. As a result, the department was not able to consider additional income models, including a Discounted Cash Flows model. The company is interested in discussing how the department would utilize forecast information.

Additional commentsAccording to the Annual Report 2014, "Xcel Energy is exploring growth opportunities in the natural gas business. In 2014, the company expanded natural gas service to three Minnesota communities, including Barnesville, MN." Page 7

The Annual Report goes on to state, "In the fourth component of our strategic plan, we are making significant investments to upgrade and strengthen our energy systems and exploring other ways to growth our business and insure long-term success. The $14.5 billion of system investments we make over the next five years, for example, grow our rate base, or the value of



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NORTHERN STATES POWER COour assets, by 4.7 percent annually. beyond that, we are focusing in particular on growth opportunities in transmission and natural gas, businesses where we already have a lot of expertise." Page 10

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SYSTEM UNIT ALLOCATION TO MINNESOTASystem Plant Ratio

SYSTEM MNUtility Plant $1,237,133,594 $1,125,252,556Additions:CWIP $9,776,241 $9,062,691Land $3,641,791 $3,393,588Total Utility Plant $1,250,551,626 $1,137,708,835Factor of MN Plant to System Plant 0.9098Weighting Factor 0.7500MN Weighted Plant Factor 0.6824

Operating Revenue RatioSYSTEM MN

Operating Revenues $762,665,589 $674,888,573Ratio of MN Revenue to System Revenue 0.8849Weighting Factor 0.2500MN Weighted Factor 0.2212MN Allocation Factor 90.36%

DEDUCTIONS TO MINNESOTA ALLOCATED UNIT VALUEDeductionsDepreciable Excludables $108,427,986Depreciable Plant Percentage 46.92%Depreciation Amount $50,874,411Net Depreciable Excludables $57,553,575Non-Depreciable Excludables $8,807,147Total MN Excludables $66,360,722

Ratio of System Unit Value and Cost IndicatorSystem Unit Value $616,174,800System Unit Cost $670,141,633Excludables Ratio 0.9195

Deductions to MN Allocated Value $61,018,700MN Deductions carried forward to MN Allocated Value



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COST INDICATORPlant Accounts

Plant In Service $1,237,133,594

CWIP $9,776,241

Land $3,641,791

Total Plant in Service (FERC) $1,250,551,626

Non-Depreciable Plant Costs

CWIP $9,776,241

Land $3,641,791

Total Non-Depreciable Plant $13,418,032

Plant Depreciation

Accumulated Deprec. & Amortization $544,433,078

Common Plant Depreciation $35,976,915

Total Plant Depreciation $580,409,993

Depreciable Plant $1,237,133,594

Plant Depreciation Percentage Applied to MN

46.92%

(Total Plant Depreciation/Depreciable Plant)

Cost Indicator

Plant in Service $1,250,551,626

Less: Depreciation $580,409,993

Cost Indicator of Value $670,141,633



SYSTEM UNIT VALUE

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SYSTEM UNIT VALUEINCOME INDICATOR

Operating Revenues $762,665,589

Operation & Maintenance Expense $631,859,786

Depreciation & Amortization Expense $41,598,852

Income Taxes ($3,875,036)

Deferred Income Tax $94,486,924

Taxes Other Than Income $22,815,507

Depreciation for Asset Retirement Accounts $1,666

Regulatory Debits $336,334

(less) Regulatory Credits ($26,730)

(less) Provision for Deferred Income Taxes ($71,005,441)

Investment Tax Credit Adjustment ($275,941)

Accretion Expense $25,063

Total Expenses $715,940,984

NOI $46,724,605

2012 2013 2014

Net Operating Income $31,428,019 $41,412,404 $46,724,605

Weight Factor 0.25 0.35 0.40

Weighted Income $7,857,005 $14,494,341 $18,689,842

Total of Weighted Income $41,041,188

Cap Rate 7.30%

Income Indicator of Value $562,208,055

DIRECT INDICATOR

Income to be Capitalized $41,041,188

Direct Capitalization Rate 5.00%

Direct Indicator of Value $820,823,760

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SYSTEM UNIT VALUEMARKET INDICATORMarket Approach

Number of Shares 504,117,000

Stock Price $33.30

Share Price Total $16,787,096,100


4.43%

Equity Value of Parent Company Attributable to Unit Company

$743,668,357

Market Value

Market Value of Long Term Debt $13,360,236,000


4.43%

Portion of LTD of Parent Company that is Attributable to Unit Company

$591,858,455

Current Liabilities $79,447,823


(Less) Current Assets $83,489,376

(Equals) Total Stock & Debt Value less Current Assets

$1,331,485,259

(x) Operating Property Percentage 73.77%

Total Stock & Debt Value $982,236,676

Operating Property Percentage Calculation

Net Property, Plant, & Equipment $670,141,632

(/) Total Assets - Current Assets $1,201,024,751

(Equals) Operating Property Percentage 55.80%

Net Carrier Operating Income $39,631,030

(/) Net Carrier Operating Income + Non-Carrier Income + Other Income

$43,197,848

(Equals) Carrier Operating Property Percentage

91.74%

Selected Operating Property Percentage 73.77%

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SYSTEM UNIT VALUEPercent of Parent Company Attributable to Unit Company

Unit Revenues $762,665,589

Parent Revenues $11,686,135,000

% of Revenues 6.53%

Unit Net Plant in Service $670,141,632

Parent Net Plant $28,756,916,000

% of Net Plant 2.33%


4.43%

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Question: With respect to Property Taxes please provide:

a) Amount claimed in the last rate case. b) Amount approved and in rate base from last rate case. c) Amounts actually paid for property taxes 2010-2015. d) Please explain the assessment and appeal process. e) Identify if the amounts in c) include refunds or adjustments after appeals. f) Please identify refunds or adjustments by year 2010-2015 (provide tax year

appealed and year adjustment or refund was received separately). g) Please identify amount clamed in this rate case and identify if gross or net of

expected appeals. With respect to any calculations, please provide Excel spreadsheet with formulae, also provide, total company and MN jurisdiction information. Response:

a)-c) See schedule 8

d) Most utility property (other than land and certain buildings) is valued as a unit by the Minnesota Department of Revenue (DOR). Minnesota Statutes § 273.372 describes the proceedings and appeal process related property valued by the DOR. Specifically, this statute describes the administrative appeal process (subd. 4) and the process to appeal to the Minnesota Tax Court (subd. 2). The statute also describes a less formal process where utilities have an “opportunity to discuss” valuation issues with the DOR. See Minn. Stat. § 273.372, subd. 4 (e). The Company has utilized these informal discussions in recent years to advocate for reasonable valuations rather than undertaking formal appeals. As explained by Company Witness Ms. Leanna Chapman. In her Direct Testimony:

We have discussions and meet with the DOR each year to advance our positions relative to the DOR’s valuation of our property. These activities are part of our ongoing efforts to advocate for a more

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reasonable valuation.

e) The Company did not formally appeal its valuations for the 2010 through 2015 tax years. The amounts included in Exhibit___(LMC-1), Schedule 8, therefore, reflect the final property tax expenses for each year.

f) See response to part e.

g) For the 2016 thru 2018 amounts included in this rate case see schedule 8. As

of the date of this response, no appeals have been filed and these amounts do not include adjustments related to any possible appeals.

__________________________________________________________________ Preparer: Leanna Chapman



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Question: Referring to MCC -239 please provide the following on a "revised" Attachment A, two additional columns that identify:

• For years in which Xcel filed a rate case, the amount included in the initial filing for test year amount requested for recovery.

• Proposed tax assessments based on preliminary values issued by DOR, prior to appeal or informal adjustment "opportunity to discuss" (we are assuming "NSPM Electric" column is the actual tax paid (except when identified as testimony/order/filing)).

Response: We have added the additional information requsted to MCC-239 Attachment A for the Company’s last five electric rate cases. As shown in Column (e) of the table below, the Company has under-forecast property taxes in two of its past five rate cases and over-forecast in the other three. Also, Column (f) of the table below shows that since 2006, actual total Company property taxes for the Minnesota taxing jurisdiction have exceeded the amounts included in rates by approximately $17 million.

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Table Comparison of Total Company Property Taxes for

the Minnesota Taxing Jurisdiction ($ Millions)

(a) (b) (c) (d)=(a)-(b) (e)=(a)-(c) (f)

Year Initial Filing

Total Company,

As Ordered Actual

Difference between Initial Filing and

Ordered

Difference between Initial Filing and

Actual

Cumulative Difference between

Ordered and Actual

2006 $114 $114 $107 $0 $7 $7 2007 $114 $105 $16 2008 $114 $108 $22 2009 $106 $106 $111 $0 ($5) $17 2010 $106 $124 ($1) 2011 $124 $132 $135 ($8) ($11) ($4) 2012 $132 $162 ($34) 2013 $182 $183 $166 ($1) $16 ($17) 2014 $200 $180 $180 $20 $20 ($17)

__________________________________________________________________ Preparer: Leanna Chapman



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Direct Testimony and Schedules Leanna M. Chapman Before ...€¦ · In our last rate case, Docket...

Documents

Transcript of Direct Testimony and Schedules Leanna M. Chapman Before ...€¦ · In our last rate case, Docket...