financial and operating ratios of public power utilities...the utilities included in the report can...

FINANCIAL AND OPERATING RATIOSof Public Power Utilities

FNANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES 1

FINANCIAL AND OPERATING RATIOS of Public Power Utilities

Copyright © 2019 by the American Public Power Association

All rights reserved. Published by the American Public Power Association

www.PublicPower.org

Contact [email protected] or 202-467-2900.

The American Public Power Association is the voice of not-for-profit, community-owned utilities that power 2,000 towns and cities nationwide. We represent public power before the federal government to protect the interests of the more than 49 million people that public power utilities serve, and the 93,000 people they employ. Our association advocates and advises on electricity policy, technology, trends, training, and operations. Our members strengthen their communities by providing superior service, engaging citizens, and instilling pride in community-owned power.

2 FINANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES

This is the latest in the annual report series prepared by the American Public Power Association (Association) on financial and operating ratios. Many of the ratios in this report were suggested by the Association’s Performance Management Committee and its predecessor, the Task Force on Performance Indicators.

The report was prepared by the Association’s Regulatory Affairs Department.

ABOUT THIS REPORT

Comments or Questions about the ReportMembers are encouraged to comment on the content and format of this report. Comments or questions should be directed to Paul Zummo, Director, Policy Research and Analysis at [email protected] or at:

American Public Power Association 2451 Crystal Dr., Suite 1000 Arlington, VA 22202 202-467-2969


TABLE OF CONTENTS

I. INTRODUCTION 4

Report Format 5

Utilities in the Report 7

Definitions, Data Sources and Computations 7

Factors Influencing Ratios 7

II. SUMMARY TABLES 8

Median Values by Customer Size Class 9

Median Values by Region 10

Median Values by Power Generation Class 11

III. DETAILED TABLES 12

1. Revenue per Kilowatt-hour 12

2. Debt to Total Assets 15

3. Operating Ratio 16

4. Current Ratio 17

5a. Times Interest Earned 18

5b. Debt Service Coverage 19

6. Net Income per Revenue Dollar 20

7. Uncollectible Accounts per Revenue Dollar 21

8. Retail Customers per Non-power-generation Employee 22

9. Total Operation and Maintenance Expense per Kilowatt-hour Sold 23

10. Total Operation and Maintenance Expense per Retail Customer 24

11. Total Power Supply Expense per Kilowatt-hour Sold 25

12. Purchased Power Cost per Kilowatt-hour 26

13. Retail Customers per Meter Reader 27

14. Distribution Operation and Maintenance Expenses per Retail Customer 28

15. Distribution Operation and Maintenance Expenses per Circuit Mile 29

16. Customer Accounting, Customer Service and Sales Expenses per Retail Customer 30

17. Administrative and General Expenses per Retail Customer 31

18. Labor Expense per Worker-hour 32

19. Energy Loss Percentage 33

20. System Load Factor 34

21. Capital Expenditures to Depreciation Expense 35

APPENDIX A: 2018 Performance Indicators Survey 36

APPENDIX B: Data Sources and Computational Procedures 38

APPENDIX C: Regional Definitions 41

APPENDIX D: Utilities Included in the 2018 Report 42


This report presents data for 21 categories of financial and operating ratios for 119 of the largest publicly owned elec-tric utilities in the United States. The ratios can be a useful tool in assessing electric utility performance. However, they do not provide definitive information, nor should the level of any indicator be taken as the “correct” level of perfor-mance.

It is important that users be familiar with definitions of ratios and the variables that may affect them. Although the groupings of the ratios by customer size class, region and net power generation adjust for major variables, other factors may also influence the ratios. The financial and operating ratios provide a useful starting point for analy-ses and may be used to pinpoint areas in need of further investigation. The ratios should be analyzed in conjunction with other information and should not be the sole basis for broad conclusions.

Report FormatSummary tables listing median values of the ratios are pre-sented in Section II by customer size class, region and net power generation. Section III presents detailed breakdowns for each ratio with the number of utilities, means, medi-ans and first and third quartile values. The information is organized by customer size, region and net generation. Definitions and descriptive information precede each set of tables. A copy of the 2018 Performance Indicator Survey as well as formulas, data sources, definitions of regions, and the utilities included in the report can be found in Appen-dices A through D.

Medians and number of responses for each ratio are pre-sented in the following table for all regions, customer size classes, and generation classes.

INTRODUCTION


Utilities in the ReportThe utilities included in this report are those that re-sponded to the American Public Power Association’s 2018 Performance Indicator Survey. The survey was sent to all public power utilities with sales to consumers that account for approximately 50 percent or more of their total sales, and that also have retail sales or sales for resale of 100,000 megawatt-hours or more.

Direct comparisons with the 2017 ratio report should not be made because the composition of utilities included for each ratio may have changed. Although 119 utilities are included in this report, not all of the utilities were in-corporated into each of the ratios. Many utilities did not have or did not provide information necessary for certain

ratios. Also, data are excluded from calculations if there is reason to believe the information is incorrect (e.g., extreme values).

The respondents are grouped into six customer size classes. Mean, median, and first and third quartile values are calculated for each of these classes. Means are weighted — calculated by summing the values for all utilities, and then computing the ratio from these totals. Since large utilities heavily influence the mean (particularly when there are only a small number of utilities in the sample), medians provide a better measure of the typical utility. The class size and number of responses in each class are shown in the chart below. (Two wholesale entities with no retail custom-ers are excluded.)

FINANCIAL RATIOS UTILITIES MEDIAN

1. Revenue per KWH

a. All Retail Customers 119 $0.096

b. Residential Customers 118 $0.109

c. Commercial Customers 118 $0.101

d. Industrial Customers 108 $0.072

2. Debt to Total Assets 118 0.286

3. Operating Ratio 119 0.845

4. Current Ratio 118 2.79

5a. Times Interest Earned 94 4.93

5b. Debt Service Coverage 92 3.63

6. Net Income per Revenue Dollar 119 $0.071

7. Uncollectible Accounts per Revenue Dollar 115 $0.0015

OPERATING RATIOS

8. Retail Customer per Non-Power Generation Employee 117 318

9. Total O&M Expense per KWH Sold 118 $0.078

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer 115 $544

11. Total Power Supply Expense per KWH Sold 118 $0.061

12. Purchased Power Cost per KWH 118 $0.058

13. Retail Customers per Meter Reader* 92 7,110

14. Distribution O&M Expense per Retail Customer 108 $184

15. Distribution O&M Expense per Circuit Mile 108 $8,755

16. Customer Accounting, Service, and Sales Expense per Retail Customer 108 $66

17. Administrative and General Expense per Retail Customer 108 $179

OTHER RATIOS

18. Labor Expense per Worker-Hour 110 $42.78

19. Energy Loss Percentage 112 2.87%

20. System Load Factor 115 58.4%

21. Capital Expenditures to Depreciation Expenses 115 $1.18

*Only includes utilities with at least one meter reader. For changes to the methodology of this ratio, see the detailed breakdown in Section III.


Utilities are also grouped based on geographic location. The five regions are based on combined NERC regions (see Appendix C). The regions and number of utilities in each are shown in the following chart.

More than 100,000 Customers

50,000 to 100,000 Customers

20,000 to 50,000 Customers 10,000 to 20,000 Customers



7

21

3329

15

14

Number of Responses, by Customer Size Class

7

40

36

11

25

North/Central Plains

Number of Responses, by Region

Northeast

Southeast

Southwest

West


Finally, respondents are grouped into categories based upon the percent of total power requirements generated by the util-ity. The classes range from “none” (or zero generation) to “50 to 100 percent” generation. The number of utilities in each category is shown in the chart below.

13

22

26

57No generation

more than 0 but less than 10%

50 to 100%

10 to 50%

Number of Responses, by Utility Generation

Definitions, Data Sources and ComputationsDefinitions of each ratio are found in Section III, “Detailed Tables,” and information on data sources and computa-tions are provided in Appendix B. The data in this report come from two sources: the Department of Energy’s Energy Information Administration (EIA) report Form EIA-861 for 2018; and the Association’s 2018 Performance Indicators Survey.

Factors Influencing RatiosEach of the ratios in this report may be influenced by a variety of economic, environmental and technical factors. Aggregating the data may mask significant differences. When making comparisons, users of the data should attempt to understand the various factors that might affect a particular ratio. An individual utility with a high or low value for a given ratio relative to the median for a group is not necessarily indicative of a performance problem but might be due to particular policies or situations faced by the utility.

The groupings in this report adjust for regional variations, differences in utility size based on the number of customers served, and differences in operations based on the propor-tion of power requirements generated by the utility. Other factors that might influence the ratios include:

l Composition of customers served;

l Geographic location;

l Population density;

l Source of power supply (and physical, economic, or institutional barriers to acquiring alternative power supply);

l Amount of taxes, payments in lieu of taxes, contribu-tions and free electricity or services that a utility makes to or receives from local government;

l Number of contract employees used (e.g., consultants, contract labor for maintenance, tree trimming);

l Financial policies (e.g., proportion of major capital expenditures financed by long-term debt versus current revenue);

l Management policies (e.g., the extent to which a utility focuses on customer service or other programs);

l Regulatory policies;

l Relatively small number of utilities reporting data on a particular ratio (small numbers of utilities frequently appear in the detailed breakdowns);

l Degree of precision of the data component; or

l Differences in utility reporting periods.

Ratios are calculated from fiscal year and calendar year data.


The following tables present summary data on the 21 financial and operating ratios by customer size class (Table A), by region (Table B) and by generation class (Table C). These tables present medians for each of the ratios. Defi-nitions and detailed data including means, medians and quartiles appear in Section III. Data sources and calcula-tion procedures are found in Appendix B.

The average number of retail customers reported by each utility on the 2018 Performance Indicators Survey deter-mines customer size class. Responding utilities are grouped into five geographic regions: Northeast, Southeast, North Central/Plains, Southwest, and West. The regions corre-spond to combined regions of the North American Electric Reliability Council (NERC). See Appendix C for a detailed description of the regions.

Generation refers to the power a utility produces and is based upon the utility’s net generation as a percent of total sources of energy as reported on the 2018 Performance Indicators Survey.

SUMMARY TABLES


TABLE A. MEDIAN VALUES BY CUSTOMER SIZE CLASS

2,000 to 5,000 to 10,000 20,000 to 50,000 to More than 5,000 10,000 20,000 50,000 100,000 100,000 Ratio Customers Customers Customers Customers Customers Customers

1. Revenue per KWH

a. All Retail Customers $0.098 $0.091 $0.086 $0.100 $0.104 $0.096

b. Residential Customers $0.100 $0.103 $0.108 $0.113 $0.116 $0.112

c. Commercial Customers $0.097 $0.102 $0.096 $0.107 $0.105 $0.093

d. Industrial Customers $0.061 $0.075 $0.071 $0.075 $0.073 $0.069

2. Debt to Total Assets 0.236 0.218 0.209 0.291 0.409 0.535

3. Operating Ratio 0.931 0.879 0.859 0.825 0.790 0.677

4. Current Ratio 4.27 2.31 2.96 3.23 3.00 1.62

5a. Times Interest Earned a 10.80 8.23 4.98 3.31 2.62

5b. Debt Service Coverage a 8.66 4.44 3.84 2.60 2.35

6. Net Income per Revenue Dollar $0.063 $0.102 $0.101 $0.114 $0.100 $0.128

7. Uncollectible Accounts per Revenue Dollar $0.0005 $0.0025 $0.0026 $0.0027 $0.0021 $0.0032

8. Retail Customer per Non-Power Generation Employee 200 255 348 347 298 301

9. Total O&M Expense per KWH Sold $0.092 $0.081 $0.078 $0.085 $0.073 $0.061

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer $622 $610 $510 $531 $586 $504

11. Total Power Supply Expense per KWH Sold $0.074 $0.066 $0.060 $0.062 $0.046 $0.045

12. Purchased Power Cost per KWH $0.067 $0.061 $0.062 $0.059 $0.045 $0.050

13. Retail Customers per Meter Reader 2,559 5,193 7,510 6,899 10,758 19,190

14. Distribution O&M Expense per Retail Customer $173 $206 $199 $196 $194 $140

15. Distribution O&M Expense per Circuit Mile $5,347 $6,595 $9,012 $7,734 $11,173 $11,146

16. Customer Accounting, Service, and Sales Expense per Retail Customer $101 $64 $56 $62 $82 $99

17. Administrative and General Expense per Retail Customer $353 $158 $187 $145 $212 $186

18. Labor Expense per Worker-Hour $35.79 $39.27 $42.42 $41.29 $50.85 $49.42

19. Energy Loss Percentage 2.88% 2.93% 2.40% 2.92% 2.76% 2.99%

20. System Load Factor 55.8% 60.5% 57.1% 55.4% 64.0% 60.4%

21. Capital Expenditures to Depreciation Expenses $1.99 $0.89 $1.17 $1.08 $1.30 $1.56

a Medians are not calculated for fewer than 5 responses


TABLE B. MEDIAN VALUES BY REGION

North Ratio Northeast Southeast Central/Plains Southwest West

1. Revenue per KWH

a. All Retail Customers $0.132 $0.098 $0.092 $0.095 $0.091

b. Residential Customers $0.157 $0.112 $0.108 $0.104 $0.107

c. Commercial Customers $0.144 $0.106 $0.099 $0.090 $0.092

d. Industrial Customers $0.099 $0.071 $0.077 $0.072 $0.064

2. Debt to Total Assets 0.329 0.277 0.212 0.355 0.343

3. Operating Ratio 0.859 0.872 0.837 0.784 0.836

4. Current Ratio 1.86 2.79 2.96 3.23 2.47

5a. Times Interest Earned 10.00 6.53 5.10 4.79 3.54

5b. Debt Service Coverage 4.51 4.71 3.62 3.87 2.73

6. Net Income per Revenue Dollar $0.074 $0.056 $0.077 $0.100 $0.078

7. Uncollectible Accounts per Revenue Dollar $0.0015 $0.0017 $0.0008 $0.0031 $0.0015

8. Retail Customer per Non-Power Generation Employee 383 310 334 359 297

9. Total O&M Expense per KWH Sold $0.108 $0.088 $0.076 $0.068 $0.063

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer $823 $473 $539 $544 $638

11. Total Power Supply Expense per KWH Sold $0.073 $0.071 $0.061 $0.055 $0.046

12. Purchased Power Cost per KWH $0.072 $0.069 $0.059 $0.051 $0.043

13. Retail Customers per Meter Reader 6,766 7,454 6,703 7,510 8,208

14. Distribution O&M Expense per Retail Customer $212 $193 $159 $183 $224

15. Distribution O&M Expense per Circuit Mile $16,551 $10,844 $5,779 $7,510 $9,793

16. Customer Accounting, Service, and Sales Expense per Retail Customer $68 $64 $58 $62 $109

17. Administrative and General Expense per Retail Customer $279 $169 $158 $161 $181

18. Labor Expense per Worker-Hour $52.14 $36.20 $41.29 $35.62 $50.37

19. Energy Loss Percentage 2.84% 2.92% 2.65% 4.18% 2.86%

20. System Load Factor 57.3% 54.6% 59.7% 58.4% 63.9%

21. Capital Expenditures to Depreciation Expenses $1.08 $1.07 $1.18 $0.89 $1.30


TABLE C. MEDIAN VALUES BY POWER GENERATION CLASS*

No More than 0 Ratio Generation but less than 10% 10 to 50% 50 to 100%

1. Revenue per KWH

a. All Retail Customers $0.097 $0.091 $0.093 $0.132

b. Residential Customers $0.108 $0.104 $0.116 $0.112

c. Commercial Customers $0.092 $0.110 $0.097 $0.094

d. Industrial Customers $0.072 $0.073 $0.077 $0.070

2. Debt to Total Assets 0.244 0.307 0.380 0.454

3. Operating Ratio 0.874 0.854 0.824 0.696

9. Total O&M Expense per KWH Sold $0.085 $0.073 $0.068 $0.058

11. Total Power Supply Expense per KWH Sold $0.072 $0.060 $0.055 $0.042

12. Purchased Power Cost per KWH $0.069 $0.054 $0.042 $0.045

17. Administrative and General Expense per Retail Customer $145 $220 $207 $208

18. Labor Expense per Worker-Hour $40.27 $41.65 $46.51 $49.13

19. Energy Loss Percentage 3.09% 2.83% 2.48% 2.77%

21. Capital Expenditures to Depreciation Expenses $1.27 $1.02 $1.09 $1.30

* Only those ratios affected by power generation are included in this table


The following tables present a detailed breakdown of each of the 21 ratios. Each table includes the ratio by customer size class, region, and generation class. The numbers of responses are presented along with the mean, median and first and third quartiles of the ratio for each class.

1. Revenue per Kilowatt-houra. All retail customers – The ratio of total electric op-erating revenues from sales to ultimate customers to total kilowatt-hour sales. This ratio measures the revenue re-ceived for each kilowatt-hour of electricity sold to all classes of customers, including residential, commercial, industrial, public street and highway lighting and other customers.

b. Residential customers – The ratio of residential revenue to residential sales. This ratio measures the rev-enue received for each kilowatt-hour of electricity sold to residential customers.

c. Commercial customers – The ratio of commercial revenue to commercial sales. This ratio measures the rev-enue received for each kilowatt-hour of electricity sold to commercial customers.

d. Industrial customers – The ratio of industrial reve-nue to industrial sales. This ratio measures the revenue re-ceived for each kilowatt-hour of electricity sold to industrial customers.

The definition of commercial and industrial customers may vary between utilities, with the resulting classification based on specific load characteristics or demand rather than on a popular definition of “commercial” or “industrial.” Revenue and sales data include only full-service (bundled sales), thus data for customers who purchase power from an alternative supplier are excluded.

More detailed revenue-per-kilowatt hour data, including data for all retail electric utilities in the United States, can be found on the Association’s stats and facts page at www.PublicPower.org/Public-Power/Stats-and-Facts

DETAILED TABLES


TABLE 1A. REVENUE PER KWH: ALL RETAIL CUSTOMERS

Utilities Mean (weighted) 1st Quartile Median 3rd Quartile

Total 119 $0.098 $0.084 $0.096 $0.108

1. Customer Size Class

2,000 to 5,000 Customers 7 $0.070 a $0.098 a

5,000 to 10,000 Customers 21 0.084 0.081 0.091 0.102

10,000 to 20,000 Customers 33 0.085 0.078 0.086 0.101

20,000 to 50,000 Customers 29 0.100 0.091 0.100 0.119

50,000 to 100,000 Customers 15 0.097 0.089 0.104 0.120

More than 100,000 Customers 14 0.101 0.090 0.096 0.100

2. Region

Northeast 7 0.106 a 0.132 a

Southeast 36 0.102 0.091 0.098 0.108

North Central/Plains 40 0.087 0.083 0.092 0.107

Southwest 11 0.092 0.085 0.095 0.103

West 25 0.101 0.071 0.091 0.105

3. Generation

No generation 57 0.098 0.085 0.097 0.105

More than 0 but less than 10% 26 0.087 0.074 0.091 0.102

10 to 50% 22 0.099 0.081 0.093 0.116

50 to 100% 13 0.101 0.087 0.096 0.119

a Quartiles are not calculated for fewer than 9 responses

TABLE 1B. REVENUE PER KWH: RESIDENTIAL CUSTOMERS


Total 118 $0.114 $0.098 $0.109 $0.120


2,000 to 5,000 Customers 6 $0.094 a $0.100 a

5,000 to 10,000 Customers 21 0.104 0.096 0.103 0.118

10,000 to 20,000 Customers 33 0.103 0.098 0.108 0.119

20,000 to 50,000 Customers 29 0.111 0.101 0.113 0.128

50,000 to 100,000 Customers 15 0.115 0.104 0.116 0.128


2. Region


Southeast 36 0.113 0.102 0.112 0.118


Southwest 11 0.106 0.093 0.104 0.116

West 25 0.119 0.086 0.107 0.124

3. Generation

No generation 56 0.109 0.099 0.108 0.118


10 to 50% 22 0.115 0.099 0.116 0.139

50 to 100% 13 0.117 0.104 0.112 0.120



TABLE 1C. REVENUE PER KWH: COMMERCIAL CUSTOMERS


Total 118 $0.100 $0.089 $0.101 $0.112


2,000 to 5,000 Customers 6 $0.099 a $0.097 a

5,000 to 10,000 Customers 21 0.100 0.094 0.102 0.111

10,000 to 20,000 Customers 33 0.098 0.083 0.096 0.110

20,000 to 50,000 Customers 29 0.107 0.097 0.107 0.113

50,000 to 100,000 Customers 15 0.107 0.090 0.105 0.125


2. Region


Southeast 36 0.103 0.098 0.106 0.111


Southwest 11 0.089 0.081 0.090 0.099

West 25 0.103 0.086 0.092 0.129

3. Generation

No generation 56 0.103 0.093 0.104 0.110


10 to 50% 22 0.100 0.090 0.097 0.127

50 to 100% 13 0.098 0.087 0.094 0.108


TABLE 1D. REVENUE PER KWH: INDUSTRIAL CUSTOMERS


Total 108 $0.071 $0.063 $0.072 $0.086


2,000 to 5,000 Customers 5 $0.057 a $0.061 a

5,000 to 10,000 Customers 20 0.068 0.069 0.075 0.086

10,000 to 20,000 Customers 32 0.066 0.063 0.071 0.085

20,000 to 50,000 Customers 25 0.073 0.064 0.075 0.087

50,000 to 100,000 Customers 13 0.074 0.055 0.073 0.093


2. Region


Southeast 31 0.071 0.064 0.071 0.080


Southwest 10 0.069 0.063 0.072 0.077

West 23 0.073 0.056 0.064 0.077

3. Generation

No generation 51 0.069 0.064 0.072 0.083


10 to 50% 21 0.083 0.065 0.077 0.106

50 to 100% 11 0.071 0.063 0.070 0.086



2. Debt to Total AssetsThe ratio of long-term debt, plus current and accrued lia-bilities, to total assets and other debits. This ratio measures a utility’s ability to meet its current and long-term liabilities based on the availability of assets.

Long-term debt includes bonds, advances from the munici-pality, other long-term debt, any unamortized premium on long-term debt and any unamortized discount on long-term debt. Current and accrued liabilities include warrants, notes and accounts payable, payables to the municipality,

customer deposits, taxes accrued, interest accrued, and miscellaneous current and accrued liabilities. Total assets and other debits include utility plant, investments, current and accrued assets, and deferred debits.

This ratio may be influenced by the extent to which its components include information applicable to the non-electric portion of the utility, if any (e.g., gas, water or other). In addition, the ratio may be influenced by a utili-ty’s financial policies.

TABLE 2. DEBT TO TOTAL ASSETS


Total 118 0.496 0.156 0.286 0.468


2,000 to 5,000 Customers 7 0.205 a 0.236 a

5,000 to 10,000 Customers 20 0.380 0.128 0.218 0.372

10,000 to 20,000 Customers 33 0.227 0.121 0.209 0.305

20,000 to 50,000 Customers 29 0.367 0.186 0.291 0.468

50,000 to 100,000 Customers 15 0.416 0.330 0.409 0.535


2. Region


Southeast 36 0.484 0.168 0.277 0.485


Southwest 11 0.466 0.211 0.355 0.477

West 24 0.548 0.284 0.343 0.547

3. Generation

No generation 56 0.396 0.154 0.244 0.345


10 to 50% 22 0.607 0.188 0.380 0.592

50 to 100% 13 0.488 0.345 0.454 0.520



3. Operating RatioThe ratio of total electric operation and maintenance ex-penses to total electric operating revenues. This ratio mea-sures the proportion of revenues received from electricity sales, rate adjustments and other electric activities required to cover the operation and maintenance costs associated with producing and selling electricity.

Operation and maintenance expenses include the costs of power production, purchased power, transmission, distri-bution, customer accounting, customer service, sales, and administrative and general expenses. This ratio may be influenced by the availability of alternative power options and the costs of purchased power.

TABLE 3. OPERATING RATIO


Total 119 0.745 0.772 0.845 0.902


2,000 to 5,000 Customers 7 1.002 a 0.931 a

5,000 to 10,000 Customers 21 0.915 0.845 0.879 0.937

10,000 to 20,000 Customers 33 0.860 0.816 0.859 0.899

20,000 to 50,000 Customers 29 0.823 0.784 0.825 0.906

50,000 to 100,000 Customers 15 0.793 0.698 0.790 0.874


2. Region


Southeast 36 0.771 0.800 0.872 0.907


Southwest 11 0.717 0.707 0.784 0.837

West 25 0.722 0.706 0.836 0.906

3. Generation

No generation 57 0.856 0.828 0.874 0.909


10 to 50% 22 0.732 0.697 0.824 0.935

50 to 100% 13 0.677 0.633 0.696 0.784



4. Current RatioThe ratio of total current and accrued assets to total current and accrued liabilities. This is a measure of the utility’s short-term liquidity (i.e., the ability to pay bills). The current ratio takes a snapshot of the utility’s liquidity at a point in time and thus may vary considerably at other times of the year.

Total current and accrued assets include cash and working funds, temporary cash investments, notes and accounts receivable, receivables from the municipality, materials and supplies, prepayments and miscellaneous current and accrued assets. Total current and accrued liabilities include warrants, notes and accounts payable, payables to the municipality, customer deposits, taxes accrued, interest accrued, and miscellaneous current and accrued liabilities.

TABLE 4. CURRENT RATIO


Total 118 1.48 1.86 2.79 4.53


2,000 to 5,000 Customers 7 3.43 a 4.27 a

5,000 to 10,000 Customers 20 1.39 1.83 2.31 4.07

10,000 to 20,000 Customers 33 3.15 2.01 2.96 4.83

20,000 to 50,000 Customers 29 3.56 1.87 3.23 4.85

50,000 to 100,000 Customers 15 2.68 1.93 3.00 4.74


2. Region


Southeast 36 2.25 1.89 2.79 4.08


Southwest 11 2.74 2.19 3.23 7.19

West 25 0.96 1.32 2.47 4.79



5a. Times Interest EarnedThe ratio of net electric utility income, plus interest paid on long-term debt, to interest on long-term debt. This ra-tio measures the ability of a utility to cover interest charges and is indicative of the safety margin to lenders. Utilities

that do not report any long-term debt are excluded from this ratio.

This ratio might be influenced by a utility’s financial poli-cies.

TABLE 5A. TIMES INTEREST EARNED


Total 94 2.42 2.72 4.93 11.35


2,000 to 5,000 Customers 4 b a b a

5,000 to 10,000 Customers 13 8.89 4.22 10.80 26.69

10,000 to 20,000 Customers 25 6.87 4.34 8.23 14.39

20,000 to 50,000 Customers 23 4.15 2.84 4.98 8.97

50,000 to 100,000 Customers 15 2.73 2.19 3.31 6.89


2. Region


Southeast 29 2.46 3.83 6.53 11.55


Southwest 9 3.82 3.88 4.79 13.65

West 21 2.24 2.37 3.54 5.69

a Quartiles are not calculated for fewer than 9 responses b Means and Medians are not calculated for fewer than 5 responses


5b. Debt Service CoverageThe ratio of net revenues available for debt service to total long-term debt service for the year. This ratio measures the utility’s ability to meet its annual long-term debt obligation.

Net revenues available for debt service equal net elec-tric utility operating income (operating revenues minus

operating expenses) plus net electric utility non-operating income, plus depreciation. Debt service includes principle and interest payments on long-term debt.

This ratio might be influenced by a utility’s financial poli-cies.

TABLE 5B. DEBT SERVICE COVERAGE


Total 92 3.50 2.06 3.63 6.88


2,000 to 5,000 Customers 4 b a b a

5,000 to 10,000 Customers 13 10.06 4.33 8.66 12.65

10,000 to 20,000 Customers 24 2.13 2.63 4.44 6.88

20,000 to 50,000 Customers 23 3.94 2.00 3.84 5.29

50,000 to 100,000 Customers 15 2.06 1.90 2.60 3.01


2. Region


Southeast 27 2.62 1.95 4.71 8.23


Southwest 9 2.53 2.74 3.87 6.04

West 21 4.89 2.07 2.73 4.41

a Quartiles are not calculated for fewer than 9 responses b Means and Medians are not calculated for fewer than 5 responses


6. Net Income per Revenue DollarThe ratio of net electric utility income to total electric operating revenues. This ratio measures the amount of in-come remaining after accounting for operation and main-tenance expenses, depreciation, taxes and tax equivalents, for every dollar received from sales of electricity.

The ratio might be influenced by the type and availability of power supply options and by the amount of taxes and tax equivalents that a utility transfers to the municipality or other governmental body. Financial policies and the amount of debt may also affect this ratio (e.g., how a utility finances capital investments).

TABLE 6. NET INCOME PER REVENUE DOLLAR


Total 119 $0.073 $0.039 $0.071 $0.102


2,000 to 5,000 Customers 7 $0.073 a $0.063 a

5,000 to 10,000 Customers 21 0.072 0.019 0.051 0.102

10,000 to 20,000 Customers 33 0.071 0.050 0.076 0.101

20,000 to 50,000 Customers 29 0.084 0.041 0.063 0.114

50,000 to 100,000 Customers 15 0.078 0.060 0.078 0.100


2. Region


Southeast 36 0.057 0.027 0.056 0.080


Southwest 11 0.142 0.078 0.100 0.221

West 25 0.075 0.043 0.078 0.123



7. Uncollectible Accounts per Revenue DollarThis ratio will be influenced by the financial and customer service policies of the utility.

TABLE 7. UNCOLLECTIBLE ACCOUNTS PER REVENUE DOLLAR


Total 115 $0.0027 $0.0005 $0.0015 $0.0027


2,000 to 5,000 Customers 7 $0.0027 a $0.0005 a

5,000 to 10,000 Customers 20 0.0028 0.0003 0.0015 0.0025

10,000 to 20,000 Customers 31 0.0017 0.0006 0.0015 0.0026

20,000 to 50,000 Customers 29 0.0026 0.0009 0.0017 0.0027

50,000 to 100,000 Customers 14 0.0012 0.0005 0.0013 0.0021


2. Region

Northeast 7 0.0062 a 0.0015 a

Southeast 35 0.0014 0.0009 0.0017 0.0024


Southwest 11 0.0034 0.0024 0.0031 0.0034

West 24 0.0041 0.0004 0.0015 0.0029


The ratio of total uncollectible accounts to total electric util-ity operating revenues. This ratio measures the portion of each revenue dollar that will not be collected by the utility.


8. Retail Customers per Non-power-generation Employee

are not properly prorated, or that employees involved in resale transactions are included. Part-time employees are assumed to work half-time (i.e., two part-time employees are counted as one full-time employee). To the extent that this assumption is violated, the ratio will be biased. Con-tract employees include only those individuals performing regular utility work on an ongoing basis.

TABLE 8. RETAIL CUSTOMERS PER NON-POWER-GENERATION EMPLOYEE


Total 117 291 254 318 402


2,000 to 5,000 Customers 7 174 a 200 a

5,000 to 10,000 Customers 20 264 220 255 343

10,000 to 20,000 Customers 33 318 262 348 417

20,000 to 50,000 Customers 28 325 284 347 428

50,000 to 100,000 Customers 15 220 279 298 360

More than 100,000 Customers 14 305 276 301 402

2. Region

Northeast 7 363 a 383 a

Southeast 35 337 249 310 356

North Central/Plains 39 217 242 334 423

Southwest 11 331 279 359 405

West 25 289 266 297 416


The ratio of the average number of retail customers from all classes to the total number of full-time, part-time and contract employees not involved in the generation of power. This ratio measures the average number of customers served by each non-generation employee.

The ratio may be influenced by the mix of customers and by population density. It will be influenced by the extent that employees shared with other (non-electric) departments


9. Total Operation and Maintenance Expense per Kilowatt-hour Sold

purchased power), transmission, distribution, customer ac-counting, customer services, sales, and administrative and general functions of the electric utility. Because power sup-ply expenses typically comprise the largest component of total operation and maintenance expenses, this ratio might be influenced by the proportion of power generated by a utility and the availability of alternative power supplies. Kilowatt-hours of electricity produced but not sold (i.e., en-ergy furnished without charge, energy used internally, and energy losses) are not included in the denominator.

TABLE 9. TOTAL O&M EXPENSE PER KWH SOLD


Total 118 $0.059 $0.062 $0.078 $0.092


2,000 to 5,000 Customers 6 $0.067 a $0.092 a

5,000 to 10,000 Customers 21 0.078 0.074 0.081 0.092

10,000 to 20,000 Customers 33 0.071 0.063 0.078 0.091

20,000 to 50,000 Customers 29 0.073 0.071 0.085 0.096

50,000 to 100,000 Customers 15 0.044 0.055 0.073 0.094


2. Region


Southeast 36 0.078 0.078 0.088 0.092


Southwest 11 0.058 0.055 0.068 0.082

West 25 0.062 0.051 0.063 0.083

3. Generation

No generation 56 0.082 0.077 0.085 0.093


10 to 50% 22 0.060 0.052 0.068 0.078

50 to 100% 13 0.049 0.045 0.058 0.063


The ratio of total electric utility operation and maintenance expenses, including the cost of generated and purchased power, to total kilowatt-hour sales to ultimate and resale customers. This ratio measures average total operation and maintenance expenses associated with each kilowatt-hour of electricity sold, either for resale or to ultimate customers.

Included in operation and maintenance costs are the expenses associated with power supply (generation and


10. Total Operation and Maintenance Expense (Excluding Power Supply Expense) per Retail Customer

The costs of power supply (generation and purchased power) are excluded from the ratio. This ratio might be affected by population density and the mix of customers between various classes (residential, commercial, industrial or other). Also, the extent to which a utility services resale customers will influence the ratio.

TABLE 10. TOTAL O&M EXPENSE (EXCLUDING POWER SUPPLY EXPENSE) PER RETAIL CUSTOMER


Total 115 587 410 544 704


2,000 to 5,000 Customers 6 963 a 622 a

5,000 to 10,000 Customers 20 716 450 610 771

10,000 to 20,000 Customers 31 586 409 510 750

20,000 to 50,000 Customers 29 548 340 531 672

50,000 to 100,000 Customers 15 835 467 586 767


2. Region


Southeast 34 455 364 473 627


Southwest 11 553 371 544 582

West 25 628 502 638 696


The ratio of total electric utility operation and maintenance expenses, excluding all costs of power supply, to the total number of ultimate customers.

Operation and maintenance expenses include the costs of transmission, distribution, customer accounting, customer services, sales and administrative and general expenses.


11. Total Power Supply Expense per Kilowatt-hour Soldnance expenses include the costs of fuel, labor, supervision, engineering, materials and supplies, and also include the costs of purchased power. The ratio may be influenced by the geographic location of the utility, the availability of alternative power supplies, the degree to which the utility can generate its own power, and access to transmission. The ratio does not include kilowatt-hours produced but not sold (i.e., energy used internally, energy furnished without charge, or energy losses).

TABLE 11. TOTAL POWER SUPPLY EXPENSE PER KWH SOLD


Total 118 $0.044 $0.046 $0.061 $0.075


2,000 to 5,000 Customers 6 $0.049 a $0.074 a

5,000 to 10,000 Customers 21 0.060 0.053 0.066 0.073

10,000 to 20,000 Customers 33 0.056 0.051 0.060 0.073

20,000 to 50,000 Customers 29 0.055 0.047 0.062 0.075

50,000 to 100,000 Customers 15 0.033 0.043 0.046 0.073


2. Region


Southeast 36 0.063 0.062 0.071 0.075


Southwest 11 0.043 0.041 0.055 0.063

West 25 0.043 0.040 0.046 0.058

3. Generation

No generation 56 0.067 0.058 0.072 0.078


10 to 50% 22 0.040 0.040 0.055 0.060

50 to 100% 13 0.035 0.032 0.042 0.047


The ratio of the total costs of power supply to total sales to both ultimate and resale customers. This ratio measures all power supply costs, including generation and purchased power, associated with the sale of each kilowatt-hour of electricity.

The ratio includes operation and maintenance costs arising from all generation types, including steam, nuclear, hydrau-lic, and other types of generation. Operation and mainte-


12. Purchased Power Cost per Kilowatt-hour

ments to the cost data were made in a few cases to elimi-nate power exchanges. The cost reflects the amount billed, including adjustments and other charges.

The ratio might be influenced by the geographic location of the utility, availability of alternative power supplies, ac-cess to transmission, and the type of purchase agreement, such as firm power, economy power, or surplus sales.

TABLE 12. PURCHASED POWER COST PER KWH


Total 118 $0.051 $0.043 $0.058 $0.071


2,000 to 5,000 Customers 6 $0.048 a $0.067 a

5,000 to 10,000 Customers 21 0.054 0.045 0.061 0.071

10,000 to 20,000 Customers 33 0.056 0.048 0.062 0.072

20,000 to 50,000 Customers 29 0.054 0.047 0.059 0.072

50,000 to 100,000 Customers 15 0.041 0.036 0.045 0.069


2. Region


Southeast 36 0.069 0.061 0.069 0.074


Southwest 11 0.046 0.044 0.051 0.054

West 25 0.043 0.035 0.043 0.055

3. Generation

No generation 56 0.064 0.053 0.069 0.074


10 to 50% 22 0.039 0.031 0.042 0.057

50 to 100% 13 0.040 0.033 0.045 0.062


The ratio of the cost of purchased power to the amount of kilowatt-hours purchased. This ratio measures the pur-chased power component of power supply costs.

Purchased power includes purchases from investor-owned utilities, municipalities, cooperatives or other public au-thorities for subsequent distribution and sale to ultimate customers. It does not include power exchanges. Adjust-


13. Retail Customers per Meter ReaderThe ratio of retail customers to the number of meter readers employed by the utility. This measures the average number of retail customers served by each meter reader.

The number of meter readers includes the total number of full-time meter readers plus half of all part-time meter readers. It is assumed that all part-time employees work half-time (i.e., one full-time employee is equivalent to two part-time employees). Population density, frequency of me-ter readings, and the technology or methods used to read meters will influence the ratio.

As more utilities implement advanced meters that can read customer meters without having to send a meter reader to the customer’s residence or business, these utilities require fewer meter readers to cover their service territories. Some

utilities have installed advanced meters in all of their ser-vice territory, and no longer employ meter readers. These utilities have been excluded from the customer size and region summaries of this ratio. We have added a new cat-egory for this ratio that shows the percentage of a utility’s customers that have advanced meters installed, and utilities with zero meter readers are captured in this ratio.

The first and third quartile and median figures in this final category still reflect only those utilities with at least one meter reader. The weighted mean in this category does include all utilities, with or without meter readers. Overall, 27 utilities reported zero meter readers, and all of them were in the “80% or more” class for advanced meter percent.

TABLE 13. RETAIL CUSTOMERS PER METER READER


Total* 92 14,321 4,928 7,110 12,765


2,000 to 5,000 Customers 6 2,572 a 2,559 a

5,000 to 10,000 Customers 15 7,330 4,561 5,193 7,335

10,000 to 20,000 Customers 25 8,915 5,013 7,510 13,713

20,000 to 50,000 Customers 25 7,010 5,339 6,899 10,614

50,000 to 100,000 Customers 10 12,776 7,471 10,758 16,980

More than 100,000 Customers 11 21,969 8,612 19,190 43,475

2. Region

Northeast 5 8,752 a 6,766 a

Southeast 27 9,915 5,470 7,454 12,426

North Central/Plains 32 15,994 4,817 6,703 14,009

Southwest 9 10,352 4,821 7,510 10,785

West 19 22,627 5,219 8,208 10,970

3. Advanced Meter Percent**

No advanced meters 9 5,007 3,751 4,821 10,591

More than 0 but less than 40% 25 5,641 4,552 5,462 8,300

40 to 80% 8 6,324 a 6,266 a

80% or more 79 21,071 5,604 7,523 17,223

a Quartiles are not calculated for fewer than 9 responses * Total figure includes only utilities with at least one meter reader**Weighted Mean and Utility Count includes utilities with zero meter readers


14. Distribution Operation and Maintenance Expenses per Retail Customer

Population density and the mix of customer classes served by the utility will influence the ratio.

Those utilities that do not allocate expenses to all three cat-egories of (1) distribution expense; (2) customer account-ing, customer service, and sales expense; and (3) admin-istrative and general expense are excluded from ratios 14 through 17.

TABLE 14. DISTRIBUTION O&M EXPENSES PER RETAIL CUSTOMER


Total 108 $165 $138 $184 $256


2,000 to 5,000 Customers 5 $255 a $173 a

5,000 to 10,000 Customers 18 261 126 206 273

10,000 to 20,000 Customers 30 213 156 199 277

20,000 to 50,000 Customers 27 218 149 196 265

50,000 to 100,000 Customers 14 207 167 194 255


2. Region


Southeast 32 156 139 193 283


Southwest 10 186 128 183 255

West 24 170 171 224 266


The ratio of total distribution operation and maintenance expenses to the total number of retail customers. This ratio measures the average distribution expense associated with delivering power to each retail customer.

Distribution costs include expenses associated with labor, supervision, engineering, materials and supplies used in the operation and maintenance of the distribution system.


15. Distribution Operation and Maintenance Expenses per Circuit Mile

The ratio will be affected by population density, the mix of customer classes served by the utility, the dispersion of cus-tomers within the utility’s service territory, and the propor-tion of underground and overhead distribution lines.

Utilities that do not allocate expenses to all three catego-ries of (1) distribution expense; (2) customer accounting, customer service, and sales expense; and (3) administrative and general expense are excluded from ratios 14 through 17.

TABLE 15. DISTRIBUTION O&M EXPENSES PER CIRCUIT MILE


Total 108 $7,560 $4,937 $8,755 $13,983


2,000 to 5,000 Customers 5 $4,160 a $5,347 a

5,000 to 10,000 Customers 18 8,552 5,081 6,595 11,649

10,000 to 20,000 Customers 30 8,073 5,002 9,012 14,737

20,000 to 50,000 Customers 27 4,958 4,147 7,734 15,264

50,000 to 100,000 Customers 14 9,199 6,083 11,173 15,926

More than 100,000 Customers 14 8,330 6,006 11,146 13,339

2. Region

Northeast 7 13,726 a 16,551 a

Southeast 32 8,446 3,933 10,844 15,706

North Central/Plains 35 7,358 4,887 5,779 10,339

Southwest 10 7,113 5,545 7,510 13,028

West 24 7,069 5,465 9,793 15,531


The ratio of distribution operation and maintenance expenses to the total circuit miles of distribution line. This measures the total distribution costs associated with each circuit mile of distribution line used to deliver power to customers.

Distribution costs include expenses associated with labor, supervision, engineering, materials and supplies used in the operation and maintenance of the distribution system.


16. Customer Accounting, Customer Service and Sales Expenses per Retail Customerservice programs such as energy services or conservation programs. The ratio will be influenced by the degree to which the utility provides various energy services and other types of customer programs, and also by the mix of cus-tomer classes it serves.

Utilities that do not allocate expenses to all three catego-ries of (1) distribution expense; (2) customer accounting, customer service, and sales expense; and (3) administrative and general expense are excluded from ratios 14 through 17.

TABLE 16. CUSTOMER ACCOUNTING, CUSTOMER SERVICE AND SALES EXPENSE PER RETAIL CUSTOMER


Total 108 $137 $49 $66 $103


2,000 to 5,000 Customers 5 $124 a $101 a

5,000 to 10,000 Customers 18 113 46 64 99

10,000 to 20,000 Customers 30 64 41 56 82

20,000 to 50,000 Customers 27 88 47 62 109

50,000 to 100,000 Customers 14 102 61 82 112


2. Region


Southeast 32 85 49 64 102


Southwest 10 70 52 62 96

West 24 202 75 109 165


The ratio of total customer accounting, service, and sales expenses to the total number of retail customers. This ratio measures the average expenses incurred by the utility in handling each customer’s account. This includes the costs of obtaining and servicing all retail customers. Uncollectible accounts and meter reading expenses are included in this ratio.

The ratio includes the costs of labor, materials and other expenses associated with advertising, billing, collections, records, and handling inquiries and complaints. It also includes the costs of promoting and providing customer


17. Administrative and General Expenses per Retail Customerproperty insurance and claims, pensions and benefits, and other expenses not provided for elsewhere.

Those utilities that do not allocate expenses to all three cat-egories of (1) distribution expense; (2) customer account-ing, customer service, and sales expense; and (3) admin-istrative and general expense are excluded from ratios 14 through 17.

The amount and type of the utility’s generation might affect the ratio.

TABLE 17. ADMINISTRATIVE AND GENERAL EXPENSES PER RETAIL CUSTOMER


Total 108 $193 $120 $179 $281


2,000 to 5,000 Customers 5 $409 a $353 a

5,000 to 10,000 Customers 18 349 140 158 270

10,000 to 20,000 Customers 30 248 91 187 332

20,000 to 50,000 Customers 27 185 85 145 265

50,000 to 100,000 Customers 14 296 160 212 238


2. Region


Southeast 32 198 137 169 248


Southwest 10 159 92 161 214

West 24 149 104 181 281

3. Generation

No generation 51 186 92 145 239

More than 0 but less than 10% 23 229 152 220 332

10 to 50% 20 214 150 207 295

50 to 100% 13 181 138 208 308


The ratio of total electric utility administrative and general expenses to the total number of retail customers. This ratio measures the average administrative and general expenses incurred by the utility on behalf of each retail customer.

Administrative and general expenses are those electric op-eration and maintenance expenses not allocable to the costs of power production (generation and power purchases), transmission, distribution, or customer accounting, service and sales. Items which may be included are compensation of officers and executives, office supplies, professional fees,


18. Labor Expense per Worker-hourThe ratio of total annual earnings of full-time, part-time, and contract labor employees to the total number of hours worked during the year by these employees. This ratio measures the actual cost of labor to the utility.

Total annual earnings include all payroll compensation received by full-time, part-time, or contract employees, including straight-time pay, overtime pay, and payment for time not worked such as sick pay, vacation pay, holiday pay,

or other payments. Fringe benefits, such as health care pre-miums paid by the employer, are excluded. Hours worked includes total productive hours spent at work, including both straight time and overtime hours worked. Hours paid but not worked, such as on holidays or other paid leave, are not included. This is not the same as a wage rate, which is simply the earnings per hour. A wage rate generally in-cludes hours not worked (such as vacation or sick pay).

TABLE 18. LABOR EXPENSE PER WORKER HOUR


Total 110 $48.96 $35.56 $42.78 $49.78


2,000 to 5,000 Customers 7 $41.32 a $35.79 a

5,000 to 10,000 Customers 17 38.87 35.54 39.27 44.48

10,000 to 20,000 Customers 30 41.36 37.66 42.42 44.31

20,000 to 50,000 Customers 29 41.98 34.58 41.29 49.82

50,000 to 100,000 Customers 13 49.91 46.26 50.85 51.55


2. Region


Southeast 31 42.84 32.47 36.20 45.15


Southwest 11 42.78 34.38 35.62 45.33

West 23 52.95 47.85 50.37 55.10

3. Generation

No generation 50 41.57 33.65 40.27 47.28


10 to 50% 21 50.68 42.55 46.51 50.52

50 to 100% 12 51.46 40.96 49.13 50.99



19. Energy Loss PercentageThe ratio of total energy losses to total sources of energy. This ratio measures how much energy is lost in the utility’s electrical system and is an indicator of the efficiency of the electrical system. It represents the percentage of electrical energy that is bought or generated by the utility, but is not available to be sold to customers (or for the utility’s own use).

Losses include both physical losses that occur in the distri-bution system and metering and billing losses. Generation, purchases, net exchanges and net wheeling are all included in total sources of energy.

TABLE 19. ENERGY LOSS PERCENTAGE


Total 112 3.43 2.24 2.87 4.05


2,000 to 5,000 Customers 6 2.23 a 2.88 a

5,000 to 10,000 Customers 19 3.82 2.43 2.93 4.06

10,000 to 20,000 Customers 30 2.70 2.04 2.40 3.42

20,000 to 50,000 Customers 29 4.72 2.49 2.92 5.25

50,000 to 100,000 Customers 14 3.34 2.24 2.76 3.41


2. Region


Southeast 36 3.37 2.35 2.92 4.69


Southwest 10 3.85 2.78 4.18 5.32

West 23 3.42 1.97 2.86 3.54

3. Generation

No generation 53 3.99 2.43 3.09 4.55


10 to 50% 20 3.08 1.93 2.48 3.15

50 to 100% 12 3.42 2.24 2.77 3.55



20. System Load FactorThe ratio of the system average load, total sales plus losses (in megawatt-hours) divided by 8760 (hours), to system peak demand (typically a summer or winter peak measured during a particular hour at all delivery points and genera-tor busses on a totalized basis).

System load factor is descriptive of the total system load characteristics. It tells system planners how much the over-all system load varies diurnally and seasonally. It is a very broad indicator. It also provides financial planners with information about how to spread fixed costs across energy sales. This will give financial planners and rate designers information to support greater unbundling of fixed and variable costs — a goal of competitive rate design.

TABLE 20. SYSTEM LOAD FACTOR


Total 115 65.3 52.0 58.4 64.9


2,000 to 5,000 Customers 6 71.0 a 55.8 a

5,000 to 10,000 Customers 21 64.9 56.0 60.5 64.1

10,000 to 20,000 Customers 31 58.2 51.3 57.1 62.5

20,000 to 50,000 Customers 28 59.1 48.6 55.4 61.2

50,000 to 100,000 Customers 15 77.8 54.0 64.0 80.5


2. Region


Southeast 35 55.0 49.9 54.6 59.7


Southwest 11 66.4 49.7 58.4 66.6

West 25 64.7 52.5 63.9 76.6



21. Capital Expenditures to Depreciation Expense

TABLE 21. CAPITAL EXPENDITURES TO DEPRECIATION EXPENSES


Total 115 $1.49 $0.85 $1.18 $1.64


2,000 to 5,000 Customers 7 $1.65 a $1.99 a

5,000 to 10,000 Customers 18 1.04 0.58 0.89 1.21

10,000 to 20,000 Customers 32 1.22 0.97 1.17 1.50

20,000 to 50,000 Customers 29 1.46 0.83 1.08 1.43

50,000 to 100,000 Customers 15 1.28 1.03 1.30 1.66


2. Region

Northeast 7 1.52 0.96 1.08 1.70

Southeast 34 1.28 0.63 1.07 1.56


Southwest 10 1.11 0.46 0.89 1.51

West 25 1.64 1.07 1.32 1.76

3. Generation

No generation 54 1.74 0.98 1.27 1.89


10 to 50% 22 1.92 0.75 1.09 1.53

50 to 100% 13 1.33 0.99 1.30 1.40


The amount of capital expenditures in a year divided by depreciation expenses.


PART I. EMPLOYMENT, HOURS AND EARNINGS — Calendar Year Ending In 2018

A. ELECTRIC UTILITY EMPLOYEES A. FULL-TIME B. PART-TIME

1. Total Average No. of Employees

2. Total Annual Hours Worked

3. Total Annual Earnings

B. CONTRACT LABOR EMPLOYEES SUPERVISED EMPLOYEES SUPERVISED BY THE UTILITY BY THE SUPERVISING COMPANY

1. Total Average No. of Employees

2. Total Annual Hours Worked

3. Total Annual Earnings

C. NUMBER OF EMPLOYEES, SELECTED

ELECTRIC UTILITY DEPARTMENTS A. FULL-TIME B. PART-TIME C. CONTRACT

1. No. of Power Production Employees (Include all employees involved in operation and maintenance of power generating facilities.)

2. No. of Meter Readers (If responsible for meters other than electric, prorate employees allocated to electric only.)

PART II. SELECTED ELECTRIC UTILITY STATISTICS — CALENDAR YEAR ENDING IN 2018

A. Distribution Lines (up to 69 kV) Total Distribution Line Circuit Miles (Circuit miles include the total length in miles of separate circuits regardless of the number of conductors used per circuit.)

B. Total Electric Utility Uncollectible Accounts (FERC 904) $

C. Total Electric Utility Debt Service Payments on Long-Term Debt $

D. Capital Expenditures (current calendar year only) $

APPENDIX A

2018 Performance Indicators Survey


PART III. FINANCIAL DATA

BALANCE SHEET REPORT FULL NUMBERS (NOT IN 000’S)

ASSET SIDE

1. Total Current and Accrued Assets

2. Total Assets and Other Debits

LIABILITY SIDE

3. Long-Term Debt: Total Long-Term Debt

4. Total Current and Accrued Liabilities

SELECTED INCOME STATEMENT ITEMS

5. Electric Operating Revenue (Must include only revenue from sales to ultimate consumers and sales for resale)

6. Depreciation Expenses

7. Electric Income (Electric operating income and other Electric income)

8. Interest payment on Long-Term Debt paid during fiscal year (Include the amount of interest on outstanding long-term debt issued or assumed by the utility)

9. Net Income (Electric Income Minus Deductions)

OPERATION AND MAINTENANCE EXPENSES

10. Purchased Power Expenses

11. Total Production Expenses (including purchased power)

12. Transmission Expenses

13. Distribution Expenses

14. Customer Accounts Expenses; Customer Service and Information Expenses; and Sales Expenses

15. Administrative and General Expenses

16. Total Electric Operation and Maintenance Expenses (Sum of lines 11–15)


APPENDIX B

Data Sources and Computational ProceduresThe financial and operating ratios in this report are calculated using data from the Association’s 2018 Performance Indicators Survey. The survey includes data on employees, hours worked, earnings, distribution lines, reliability, lost workdays, uncollect-ible accounts. It also includes financial data formerly reported on Form EIA-412, including balance sheet, income statement and operation and maintenance expense information, as well as data on revenues, kilowatt-hour sales, and customers as reported on the U.S. Department of Energy, Energy Information Administration (EIA) Form EIA-861.

The list below contains data sources and computational procedures for each of the ratios in the report. Definitions are found within the body of the report. All data are for 2018.

1. Revenue per kWh (Dollars)

a. All Retail Customers

EIA Form 861, Schedule 4, Part A, Total Revenue, (column e)

EIA Form 861, Schedule 4, Part A, Total Megawatt-hours (column e)

b. Residential Customers

EIA Form 861, Schedule 4, Part A, Residential Revenue (column a)

EIA Form 861, Schedule 4, Part A, Residential Megawatt-hours (column a)

c. Commercial Customers

EIA Form 861, Schedule 4, Part A, Commercial Revenue (column b)

EIA Form 861, Schedule 4, Part A, Commercial Megawatt-hours (column b)

d. Industrial Customers

EIA Form 861, Schedule 4, Part A, Industrial Revenue (column c)

EIA Form 861, Schedule 4, Part A, Industrial Megawatt-hours (column c)

2. Debt to Total Assets — (Long Term Debt + Current and Accrued Liabilities to Total Assets)

(Association Survey, part III, line 3) + (Association Survey, part III, line 4)

Association Survey, part III, line 2

3. Operating Ratio — (Total Electric O&M Expense to Total Electric Revenue)



4. Current Ratio — (Current & Accrued Assets to Current & Accrued Liabilities)



5a. Times Interest Earned — (Net Electric Utility Income + Interest on Long Term Debt to Interest on Long Term Debt)



5b. Debt Service Coverage — (Electric Utility Income + Depreciation to Total Electric Utility Debt Service Payments on Long-term Debt)


Association Survey, Part II, Section C

6. Net Income per Revenue Dollar




7. Uncollectible accounts per Revenue Dollar

Association Survey, Part II, Section B, Uncollectible Accounts


8. Retail Customers per Non-power-generation Employee

EIA Form 861, Schedule 4, Part A Total number of customers (column e)

Employees – Power Production Employees (Association Survey, Part I)

Employees = Full Time + Part Time/2 + all contract employees (supervised by utility and supervised by contractor)

9. Total O & M Expense per kWh Sold


(EIA Form 861, Schedule 2, Part B, line 11 + line 12) *1000

10. Total O & M Expense (Excluding Power Supply Expense) per Retail Customer

(Association Survey, part III, line 16) - (Association Survey, part III, line 11)

EIA Form 861, Schedule 4, Part A, Total number of customers (column e)

11. Total Power Supply Expense per kWh Sold


(EIA Form 861, Schedule 2, Part B, line 11 + line 12) *1000

12. Purchased Power Cost per kWh


(EIA Form 861, Schedule 2, Part B, line 2) * 1000

13. Retail Customers per Meter Reader

EIA Form 861, Schedule 4, part A, Total number of customers (column e)

Meter Readers (from Association Survey, Part I, Section C)

(Number of Meter Readers = Full Time + Part Time/2 + Contract)

14. Distribution O & M Expenses per Retail Customer



15. Distribution O & M Expenses per Circuit Mile


Association Survey, Part II, Section A, Total Distribution Line Circuit Miles

16. Customer Accounting, Customer Service and Sales Expense per Retail Customer



17. Administrative and General Expenses per Retail Customer




18. Labor Expense per Worker-hour

Total Labor Expense (Association Survey, Part I)

Total Hours Worked (Association Survey, Part I)

Labor Expense = Full-Time Earnings + Part-time Earnings + Contractor Earnings Hours Worked = Full-Time Hours + Part-Time Hours + Contractor Hours (supervised by utility and supervised by contractor)

19. Energy Loss Percentage — Total Energy Losses to Total Sources of Energy

EIA Form 861, Schedule 2, Part B, line 15

EIA Form 861, Schedule 2, Part B, line 10

To express as a percent, multiply the result by 100.

20. System Load Factor — ((Total Sales + Total Energy Losses) / 8760 hrs./yr.) / Highest Hourly Peak Demand

EIA Form 861, Schedule 2 Part B (line 11 + line 12 + line 15) / 8760

(EIA Form 861, Schedule 2, Part A, line 6)

To express as a percent, multiply the result by 100.

21. Capital Expenditures to Depreciation Expanse — Capital Expenditures / Depreciation Expenses

Association Survey, part II, Section D



APPENDIX C

Regional Definitions

The regions used for this report correspond to regions of the North American Electric Reliability Council (NERC) as specified below.

Region Corresponding NERC Region(s)

Northeast NPCC — Northeast Power Coordinating Council

Southeast SERC — Southeastern Electric Reliability Council FRCC — Florida Reliability Coordinating Council

North Central/Plains* MRO — Midwest Reliability Organization RFC — Reliability First Corporation

Southwest SPP — Southwest Power Pool TRE — Texas Reliability Entity

West WECC — Western Electricity Coordinating Council ASCC — Alaska Systems Coordinating Council

*: MAIN, ECAR, and MAAC joined to become the “Reliability First” NERC region, effective January 2006. However, the Energy Information Administration continues to identify utilities by their former NERC regions. APPA uses the former regions in establishing regional


APPENDIX D

Utilities Included in the 2018 Report

AlabamaHuntsville UtilitiesRiviera Utilities

ArizonaNavajo Tribal Utility AuthoritySalt River Project

ArkansasBenton UtilitiesJonesboro City Water & Light Paragould City Light, Water & Cable

CaliforniaModesto Irrigation DistrictPasadena Water and Power Department Redding, City ofRoseville Electric UtilitySacramento Municipal Utility DistrictSilicon Valley Power

ColoradoFort Morgan, City ofLoveland Water & Power

ConnecticutGroton UtilitiesNorwich Public Utilities

DelawareNew Castle Municipal Services

FloridaCity of Ocala Electric UtilityJEAKeys Energy ServicesKissimmee Utility AuthorityLakeland ElectricOrlando Utilities Commission

GeorgiaCrisp County Power CommissionMarietta Board of Lights & Water

IllinoisSpringfield City Water, Light & Power

IndianaLawrenceburg Municipal Utilities

IowaAmes, City ofCedar Falls UtilitiesDenison Municipal UtilitiesMuscatine Power & WaterWaverly Utilities

KansasKansas City Board of Public UtilitiesMcPherson Board of Public Utilities

KentuckyHenderson City Utility CommissionOwensboro Municipal UtilitiesPaducah Power System

MassachusettsHolyoke Gas & ElectricNorth Attleborough Electric Department

MichiganBay City, City ofGrand Haven Board of Light & PowerLowell Light & PowerTraverse City Light & PowerZeeland Board of Public Works

MinnesotaALP Utilities Austin UtilitiesBrainerd Public UtilitiesGrand Rapids Public Utilities CommissionMarshall Municipal Utilities Owatonna Public Utilities Rochester Public Utilities Willmar Municipal Utilities

MissouriChillicothe, City ofKirkwood Electric DepartmentPoplar Bluff Municipal Utilities & City Cable City Utilities of Springfield

MississippiGreenwood Utilities Commission


NebraskaGrand Island, City ofHastings, City of Lincoln Electric SystemLoup Power District Nebraska Public Power District Omaha Public Power DistrictSouthern Public Power District

New MexicoLos Alamos County Utilities

New YorkFairport, Village ofPlattsburgh Municipal Lighting Department

North CarolinaFayetteville Public Works CommissionGreenville Utilities CommissionLexington, City ofMonroe, City ofRocky Mount, City of Shelby, City ofWilson Energy

OhioHudson Public PowerOrrville, City ofWesterville Electric Division

OklahomaStillwater Electric Utility

OregonClatskanie People’s Utility District Eugene Water & Electric BoardMcMinnville Water & LightNorthern Wasco County People’s Utility District Springfield Utility Board

South DakotaWatertown Municipal Utilities

TennesseeBristol Tennessee Essential ServicesColumbia Power & Water Systems Covington Electric System Jackson Energy Authority Lewisburg Electric System McMinnville Electric System Morristown Utility SystemsNashville Electric ServiceParis Board of Public UtilitiesPulaski Electric SystemRipley Power & Light Company

TexasBryan Texas Utilities College Station, City ofLubbock Power & LightWeatherford Municipal Utility

UtahHeber Light & Power Co.Provo City Power

VermontBurlington Electric Department

VirginiaHarrisonburg Electric Commission

WashingtonBenton Public Utility District Clallam County, Public Utility District No. 1 of Cowlitz County, Public Utility District No. 1 ofGrays Harbor County, Public Utility District No. 1 ofLewis County, Public Utility District No. 1 ofSeattle City Light Tacoma Public Utilities

WisconsinKaukauna UtilitiesManitowoc Public Utilities Marshfield UtilitiesReedsburg Utility Commission Rice Lake UtilitiesSun Prairie Utilities Wisconsin Rapids Water Works & Lighting Commission

2451 Crystal Drive Suite 1000

Arlington, VA 22202-4804

www.PublicPower.org

financial and operating ratios of public power utilities...the utilities included in the report can...

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