financial and operating ratios of public power utilities

FINANCIAL AND OPERATING RATIOSof Public Power Utilities

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PUBLISHED DECEMBER 2018

© 2018 American Public Power Association

www.PublicPower.org

FINANCIAL AND OPERATING RATIOSof Public Power Utilities

4 FINANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES

ABOUT THIS REPORT

This is the latest in the annual report series prepared by the American Public Power

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 Regulatory Affairs Department.

COMMENTS OR QUESTIONS ABOUT THIS REPORT

Members 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

([email protected]), or at:

American Public Power Association

2451 Crystal Dr.

Suite 1000

Arlington, VA 22202

202-467-2969

FINANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES 5

CONTENTS

INTRODUCTION ...................................................................................................................................................................................... 6

A. Report Format ................................................................................................................................................................................ 6

B. Utilities in the Report ...................................................................................................................................................................... 7

C. Definitions, Data Sources and Computations ................................................................................................................................. 9

D. Factors Influencing Ratios .............................................................................................................................................................. 9

SUMMARY TABLES ............................................................................................................................................................................... 10

A. Financial and Operating Ratios, by Customer Size Class .............................................................................................................. 11

B. Financial and Operating Ratios, by Region ................................................................................................................................... 12

C. Financial and Operating Ratios, by Generation Class ................................................................................................................... 13

DETAILED TABLES ................................................................................................................................................................................ 14

1. Revenue per KWH ........................................................................................................................................................................ 14

2. Debt to Total Assets ..................................................................................................................................................................... 17

3. Operating Ratio ............................................................................................................................................................................ 18

4. Current Ratio ................................................................................................................................................................................ 19

5a. Times Interest Earned ................................................................................................................................................................. 19

5b. Debt Service Coverage ............................................................................................................................................................... 20

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 O&M Expense per KWH Sold ............................................................................................................................................... 23

10. Total O&M Expense (Excluding Power Supply Expense) per Retail Customer ............................................................................. 24

11. Total Power Supply Expense per KWH Sold ............................................................................................................................... 25

12. Purchased Power Cost per KWH ............................................................................................................................................... 26

13. Retail Customers per Meter Reader ............................................................................................................................................ 27

14. Distribution O&M Expenses per Retail Customer ........................................................................................................................ 28

15. Distribution O&M Expenses per Circuit Mile ................................................................................................................................ 29

16. Customer Accounting, Customer Service and Sales Expense 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 Expenses .......................................................................................................................... 35

APPENDIX A: 2017 PERFORMANCE INDICATORS SURVEY ............................................................................................................ 36

APPENDIX B: DATA SOURCES AND COMPUTATIONAL PROCEDURES ......................................................................................... 38

APPENDIX C: MAP OF NERC REGIONS ............................................................................................................................................. 40

APPENDIX D: UTILITIES INCLUDED IN THE REPORT ...................................................................................................................... 41


This report presents data for 21 categories of financial and operating ratios for 138 of the largest publicly-owned electric 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 performance.

It is important that users be familiar with definitions of ratios and the variables that can affect them. Although the groupings of the ratios by customer size class, region and net power generation adjust for major variables, other factors might also influence the ratios. The financial and operating ratios provide a useful starting point for analyses 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.

A new ratio has been added to this report: Capital Expenditures to Depreciation Expenditure. This ratio was added on a pilot basis and is subject to modification based on feedback from participants.

A. Report FormatSummary tables listing median values of the ratios are presented 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, medians and first and third quartile values. The information is provided by customer size, region and generation groupings. Definitions and descriptive information precede each set of tables. A copy of the American Public Power Association’s 2017 Performance Indicators Survey, as well as formulas, data sources, definitions of regions, and the utilities included in the report can be found in Appendices A, B, C and D.

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

INTRODUCTION


B. Utilities in the ReportThe utilities included in this report are those that responded to the Association’s 2017 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 total sales, and that also have retail sales or sales for resale of 100,000 megawatt-hours or more.

Direct comparisons with the 2016 ratio report should not be made because the composition of utilities included for each ratio might have changed. Although 138 utilities are included in this report, not all of the utilities were incorporated into each of the ratios. Many utilities did not have, or did not provide information necessary for,

particular ratios. Also, data were excluded from calculations if there was 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 means - calculated by summing the values for all utilities, and then computing the ratio from these totals. Since large utilities heavily influence the mean value (particularly when there are only a small number of utilities in the sample), median values provide a better measure of the typical utility.

FINANCIAL RATIOS NO. of UTILITIES MEDIAN

1. Revenue per KWH

a. All Retail Customers 138 $0.097

b. Residential Customers 138 $0.109

c. Commercial Customers 138 $0.101

d. Industrial Customers 124 $0.074

2. Debt to Total Assets 132 0.321

3. Operating Ratio 135 0.850

4. Current Ratio 135 2.66

5a. Times Interest Earned 112 3.74

5b. Debt Service Coverage 112 2.78

6. Net Income per Revenue Dollar 137 $0.055

7. Uncollectible Accounts per Revenue Dollar 133 $0.0015

OPERATING RATIOS

8. Retail Customer per Non-Power Generation Employee 138 313

9. Total O&M Expense per KWH Sold 138 $0.080

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer 136 $540

11. Total Power Supply Expense per KWH Sold 138 $0.061

12. Purchased Power Cost per KWH 137 $0.059

13. Retail Customers per Meter Reader* 109 6,609

14. Distribution O&M Expense per Retail Customer 128 $184

15. Distribution O&M Expense per Circuit Mile 127 $7,637

16. Customer Accounting, Service, and Sales Expense per Retail Customer 128 $62

17. Administrative and General Expense per Retail Customer 127 $194 OTHER RATIOS

18. Labor Expense per Worker-Hour 131 $41.04

19. Energy Loss Percentage 132 3.39%

20. System Load Factor 133 57.4%

21. Capital Expenditures to Depreciation Expense 134 1.14

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


The number of responses in each class size are shown in the chart below. Two wholesale entities with no retail customers were excluded.

Utilities are grouped and ratios calculated 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.

20 7

23

33

19

36

More than 100,000 Customers 2,000 to 5,000 Customers

5,000 to 10,000Customers

10,000 to 20,000 Customers

50,000 to 100,000Customers

20,000 to 50,000 Customers

Number of Responses, by Customer Size

31

9

40

37

21

West

Northeast

Southeast

North/Central Plains

Southwest

Number of Responses, by Region


Finally, respondents are grouped into categories based on the percent of total power requirements generated by the utility. The classes range from “none” (or “no generation”) to “50 to 100 percent” generation. The number of utilities in each category is shown in the chart below.

22

66

23

27

50 to 100%

No Generation

10 to 50%

More than 0 but less than 10%

Number of Responses, by Generation

C. Definitions, Data Sources and ComputationsDefinitions of each ratio are found in Section III, Detailed Tables, and information on data sources and computations is provided in Appendix B. The data in this report come from two sources: the Department of Energy, Energy Information Administration (EIA) report Form EIA-861; and the Association’s 2017 Performance Indicators Survey.

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

The groupings in this report adjust for differences in utility size based on the number of customers served, regional variations, and differences in operations related to the proportion of power requirements generated by the utility. Factors that might influence the ratios include:

• Number and composition of customers served;

• Geographic location;

• Population density;

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

• Amount of taxes, payments in lieu of taxes, contributions and free electricity or services that a utility makes to or receives from a local government;

• Number of contract employees used by a utility (e.g., consultants, contract labor for maintenance, tree trimming);

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

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

• Regulatory policies;

• Relatively small number of utilities reporting data on a particularratio (e.g., small numbers of utilities frequently appear in the detailed breakdowns);

• Degree of precision of the data component; or

• 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 median values for each of the ratios. Definitions and detailed data including means, medians and quartile values appear in Section III. Data sources and calculation procedures are found in Appendix B.

The average number of retail customers reported by each utility on the Performance Indicators Survey determines customer size class. Responding utilities are grouped into five geographic regions: Northeast, Southeast, North Central/Plains, Southwest, and West. The regions correspond 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 Performance Indicators Survey.

SUMMARY TABLES


TABLE A. FINANCIAL & OPERATING RATIOS: MEDIAN VALUES BY CUSTOMER SIZE CLASS

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

1. Revenue per KWH

a. All Retail Customers $0.086 $0.097 $0.096 $0.096 $0.103 $0.096

b. Residential Customers $0.101 $0.105 $0.111 $0.106 $0.115 $0.113

c. Commercial Customers $0.092 $0.101 $0.101 $0.103 $0.106 $0.094

d. Industrial Customers $0.071 $0.077 $0.070 $0.072 $0.076 $0.073

2. Debt to Total Assets 0.140 0.204 0.196 0.308 0.512 0.563

3. Operating Ratio 0.936 0.901 0.862 0.860 0.776 0.681

4. Current Ratio 5.68 2.58 2.77 3.08 4.10 1.77

5a. Times Interest Earned a 13.07 6.52 5.76 1.66 2.02

5b. Debt Service Coverage a 2.24 3.80 4.36 1.88 1.94

6. Net Income per Revenue Dollar $0.030 $0.075 $0.079 $0.122 $0.078 $0.106

7. Uncollectible Accounts per Revenue Dollar $0.0005 $0.0019 $0.0027 $0.0041 $0.0031 $0.0037

8. Retail Customer per Non-PowerGeneration Employee 196 258 343 318 293 315

9. Total O&M Expense per KWH Sold $0.074 $0.090 $0.084 $0.083 $0.088 $0.062

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer $497 $484 $501 $573 $584 $503

11. Total Power Supply Expense per KWH Sold $0.065 $0.071 $0.066 $0.062 $0.059 $0.044

12. Purchased Power Cost per KWH $0.062 $0.067 $0.068 $0.059 $0.051 $0.047

13. Retail Customers per Meter Reader 3,072 4,549 6,252 7,145 7,974 12,771

14. Distribution O&M Expense per Retail Customer $246 $159 $181 $200 $190 $159

15. Distribution O&M Expense per Circuit Mile $5,266 $5,108 $7,508 $6,650 $10,284 $11,106

16. Customer Accounting, Service, and Sales Expense per Retail Customer $71 $61 $54 $58 $73 $82

17. Administrative and General Expense per Retail Customer $219 $168 $198 $182 $243 $190

18. Labor Expense per Worker-Hour $38.02 $34.59 $39.70 $37.22 $45.27 $48.56

19. Energy Loss Percentage 2.86% 3.44% 2.59% 3.48% 3.29% 3.73%

20. System Load Factor 57.2% 57.8% 57.6% 56.5% 61.0% 59.0%

21. Capital Expenditures to Depreciation Expense $0.64 $1.11 $1.12 $1.32 $1.48 $1.07

a: Medians are not calculated for fewer than 5 responses


TABLE B. FINANCIAL & OPERATING RATIOS: MEDIAN VALUES BY REGION

NorthRatio Northeast Southeast Central/Plains Southwest West

1. Revenue per KWH

a. All Retail Customers $0.135 $0.099 $0.094 $0.091 $0.090

b. Residential Customers $0.138 $0.111 $0.111 $0.105 $0.105

c. Commercial Customers $0.144 $0.104 $0.103 $0.092 $0.090

d. Industrial Customers $0.123 $0.069 $0.081 $0.074 $0.064

2. Debt to Total Assets 0.156 0.303 0.237 0.393 0.385

3. Operating Ratio 0.909 0.891 0.854 0.807 0.791

4. Current Ratio 2.01 2.20 2.78 4.01 3.02

5a. Times Interest Earned 3.91 5.76 4.90 2.89 3.70

5b. Debt Service Coverage 3.32 2.58 2.67 2.16 3.01

6. Net Income per Revenue Dollar $0.055 $0.034 $0.065 $0.048 $0.081

7. Uncollectible Accounts per Revenue Dollar $0.0032 $0.0016 $0.0006 $0.0026 $0.0016

8. Retail Customer per Non-Power Generation Employee 322 308 343 290 301

9. Total O&M Expense per KWH Sold $0.116 $0.091 $0.079 $0.073 $0.063

10. Total O&M Expense (Excluding Power

Supply Exp.) per Retail Customer $956 $434 $524 $574 $567

11. Total Power Supply Expense per KWH Sold $0.071 $0.075 $0.062 $0.054 $0.044

12. Purchased Power Cost per KWH $0.065 $0.072 $0.063 $0.051 $0.040

13. Retail Customers per Meter Reader 7,277 6,399 6,608 5,423 6,605

14. Distribution O&M Expense per Retail Customer $197 $171 $167 $122 $200

15. Distribution O&M Expense per Circuit Mile $23,016 $6,687 $7,036 $6,149 $7,551

16. Customer Accounting, Service, and Sales

Expense per Retail Customer $96 $58 $56 $64 $112

17. Administrative and General Expense per Retail Customer $285 $163 $204 $234 $234

18. Labor Expense per Worker-Hour $51.53 $32.83 $41.03 $34.84 $52.08

19. Energy Loss Percentage 2.44% 3.67% 3.02% 4.12% 3.28%

20. System Load Factor 55.0% 55.1% 60.4% 58.5% 57.4%

21. Capital Expenditures to Depreciation Expense $1.28 $1.29 $1.11 $1.10 $1.15


TABLE C. FINANCIAL & OPERATING RATIOS: MEDIAN VALUES BY POWER GENERATION CLASS*

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

1. Revenue per KWH

a. All Retail Customers $0.098 $0.091 $0.095 $0.135

b. Residential Customers $0.106 $0.105 $0.112 $0.114

c. Commercial Customers $0.093 $0.112 $0.097 $0.095

d. Industrial Customers $0.071 $0.074 $0.080 $0.071

2. Debt to Total Assets 0.230 0.366 0.439 0.489

3. Operating Ratio 0.888 0.851 0.817 0.688

9. Total O&M Expense per KWH Sold $0.088 $0.078 $0.076 $0.063

11. Total Power Supply Expense per KWH Sold $0.074 $0.060 $0.056 $0.046

12. Purchased Power Cost per KWH $0.069 $0.054 $0.042 $0.047

17. Administrative and General Expense per Retail Customer $162 $202 $284 $227

18. Labor Expense per Worker-Hour $37.48 $38.56 $44.66 $44.79

19. Energy Loss Percentage 3.67% 3.08% 2.41% 3.40%

21. Capital Expenditures to Depreciation Expense $1.32 $1.04 $1.28 $0.92

* 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 a breakdown of 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 quartile values of the ratio for each class.

1. Revenue per Kilowatt-houra. All retail customers – The ratio of total electric operating revenues from sales to ultimate customers to total kilowatt-hour sales. This ratio measures the amount of revenue received 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 revenues to residential sales. This ratio measures the amount of revenue received for each kilowatt-hour of electricity sold to residential customers.

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

d. Industrial customers – The ratio of industrial revenues to industrial sales. This ratio measures the amount of revenues received for each kilowatt-hour of electricity sold to industrial customers.

The definitions of commercial and industrial customers can 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 statistics page of the Association’s website at www.PublicPower.org/public-power/stats-and-facts/industry-statistics-and-reports.

DETAILED TABLES


TABLE 1a. REVENUE PER KWH: ALL RETAIL CUSTOMERS

TABLE 1b. REVENUE PER KWH: RESIDENTIAL CUSTOMERS

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

Total 138 $0.098 $0.084 $0.097 $0.112


Total 138 $0.113 $0.099 $0.109 $0.123

1. Customer Size Class

2,000 to 5,000 Customers 7 $0.069 a $0.086 a

5,000 to 10,000 Customers 23 0.087 0.081 0.097 0.104

10,000 to 20,000 Customers 33 0.090 0.079 0.096 0.117

20,000 to 50,000 Customers 36 0.098 0.087 0.096 0.116

50,000 to 100,000 Customers 19 0.102 0.093 0.103 0.125

More than 100,000 Customers 20 0.098 0.092 0.096 0.102

2. Region

Northeast 9 0.117 0.126 0.135 0.146

Southeast 40 0.096 0.094 0.099 0.107

North Central/Plains 37 0.094 0.084 0.094 0.109

Southwest 21 0.095 0.083 0.091 0.099

West 31 0.102 0.071 0.090 0.125

3. Generation

No generation 66 0.096 0.085 0.098 0.105

More than 0 but less than 10% 27 0.095 0.079 0.091 0.117

10 to 50% 23 0.098 0.083 0.095 0.113

50 to 100% 22 0.100 0.090 0.099 0.126


2,000 to 5,000 Customers 7 $0.094 a $0.101 a

5,000 to 10,000 Customers 23 0.106 0.097 0.105 0.114

10,000 to 20,000 Customers 33 0.105 0.098 0.111 0.133

20,000 to 50,000 Customers 36 0.109 0.099 0.106 0.121

50,000 to 100,000 Customers 19 0.116 0.104 0.115 0.136


2. Region

Northeast 9 0.119 0.122 0.138 0.155

Southeast 40 0.110 0.101 0.111 0.117


Southwest 21 0.109 0.094 0.105 0.112

West 31 0.118 0.088 0.105 0.128

3. Generation

No generation 66 0.106 0.098 0.106 0.118


10 to 50% 23 0.113 0.101 0.112 0.126

50 to 100% 22 0.116 0.105 0.114 0.136

a: Quartiles are not calculated for fewer than 9 responses



TABLE 1c. REVENUE PER KWH: COMMERCIAL CUSTOMERS

TABLE 1d. REVENUE PER KWH: INDUSTRIAL CUSTOMERS


Total 138 $0.100 $0.089 $0.101 $0.115


Total 124 $0.073 $0.063 $0.074 $0.091


2,000 to 5,000 Customers 7 $0.087 a $0.092 a

5,000 to 10,000 Customers 23 0.102 0.095 0.101 0.111

10,000 to 20,000 Customers 33 0.106 0.086 0.101 0.128

20,000 to 50,000 Customers 36 0.107 0.092 0.103 0.116

50,000 to 100,000 Customers 19 0.110 0.091 0.106 0.128


2. Region

Northeast 9 0.134 0.126 0.144 0.156

Southeast 40 0.102 0.099 0.104 0.112


Southwest 21 0.093 0.085 0.092 0.095

West 31 0.104 0.081 0.090 0.136

3. Generation

No generation 66 0.102 0.095 0.103 0.112


10 to 50% 23 0.098 0.086 0.097 0.119

50 to 100% 22 0.098 0.089 0.095 0.133


2,000 to 5,000 Customers 7 $0.059 a $0.071 a

5,000 to 10,000 Customers 22 0.070 0.070 0.077 0.089

10,000 to 20,000 Customers 31 0.069 0.065 0.070 0.089

20,000 to 50,000 Customers 30 0.072 0.061 0.072 0.084

50,000 to 100,000 Customers 16 0.076 0.060 0.076 0.095


2. Region

Northeast 9 0.093 0.073 0.123 0.128

Southeast 34 0.071 0.063 0.069 0.079


Southwest 18 0.066 0.063 0.074 0.079

West 28 0.076 0.056 0.064 0.102

3. Generation

No generation 59 0.069 0.062 0.071 0.084


10 to 50% 22 0.082 0.068 0.080 0.099

50 to 100% 18 0.075 0.063 0.071 0.099




TABLE 2. DEBT TO TOTAL ASSETS


Total 132 0.512 0.176 0.321 0.517


2,000 to 5,000 Customers 6 0.193 a 0.140 a

5,000 to 10,000 Customers 22 0.360 0.143 0.204 0.345

10,000 to 20,000 Customers 31 0.303 0.165 0.196 0.357

20,000 to 50,000 Customers 34 0.349 0.168 0.308 0.477

50,000 to 100,000 Customers 19 0.479 0.361 0.512 0.575


2. Region

Northeast 9 0.412 0.124 0.156 0.334

Southeast 39 0.508 0.194 0.303 0.511


Southwest 20 0.514 0.181 0.393 0.608

West 30 0.533 0.239 0.385 0.528

3. Generation

No generation 61 0.384 0.154 0.230 0.372


10 to 50% 22 0.604 0.249 0.439 0.580

50 to 100% 22 0.519 0.311 0.489 0.580


2. Debt to Total AssetsDefinition: The ratio of long-term debt, plus current and accrued liabilities, 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 municipality, 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 might 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). In addition, the ratio might be influenced by a utility’s financial policies.


TABLE 3. OPERATING RATIO


Total 135 0.737 0.765 0.850 0.914


2,000 to 5,000 Customers 7 0.854 a 0.936 a

5,000 to 10,000 Customers 23 0.904 0.859 0.901 0.940

10,000 to 20,000 Customers 32 0.863 0.826 0.862 0.920

20,000 to 50,000 Customers 34 0.845 0.806 0.860 0.907

50,000 to 100,000 Customers 19 0.802 0.755 0.776 0.845


2. Region

Northeast 8 0.891 a 0.909 a

Southeast 40 0.795 0.840 0.891 0.938


Southwest 21 0.669 0.745 0.807 0.863

West 29 0.717 0.714 0.791 0.876

3. Generation

No generation 64 0.887 0.832 0.888 0.938


10 to 50% 23 0.751 0.736 0.817 0.912

50 to 100% 21 0.645 0.607 0.688 0.801


3. Operating RatioDefinition: The ratio of total electric operation and maintenance expenses to total electric operating revenues. This ratio measures 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, distribution, customer accounting, customer service, sales, and administrative and general expenses. This ratio can be influenced by the availability of alternative power options and the costs of purchased power.


TABLE 4. CURRENT RATIO

TABLE 5a. TIMES INTEREST EARNED


Total 135 1.50 1.54 2.66 4.37


Total 112 2.15 1.67 3.74 8.55


2,000 to 5,000 Customers 6 5.77 a 5.68 a

5,000 to 10,000 Customers 22 1.90 1.56 2.58 4.09

10,000 to 20,000 Customers 32 1.93 1.76 2.77 4.24

20,000 to 50,000 Customers 36 2.47 1.63 3.08 4.67

50,000 to 100,000 Customers 19 3.62 1.86 4.10 5.87


2. Region

Northeast 9 0.89 0.82 2.01 4.53

Southeast 40 1.76 1.56 2.20 3.94


Southwest 20 2.15 1.95 4.01 5.38

West 31 1.10 1.40 3.02 5.02


2,000 to 5,000 Customers 3 b a b a

5,000 to 10,000 Customers 14 6.86 3.19 13.07 19.89

10,000 to 20,000 Customers 27 5.08 3.65 6.52 9.20

20,000 to 50,000 Customers 29 4.24 2.71 5.76 9.70

50,000 to 100,000 Customers 19 2.13 1.10 1.66 4.08


2. Region


Southeast 35 2.23 1.48 5.76 9.49


Southwest 18 1.59 1.33 2.89 16.97

West 27 2.46 2.25 3.70 5.92


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

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

5a. Times Interest EarnedDefinition: The ratio of net electric utility income, plus interest paid on long-term debt, to interest on long-term debt. This ratio measures the ability of a utility to cover

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.

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 policies.


TABLE 5b. DEBT SERVICE COVERAGE

TABLE 6. NET INCOME PER REVENUE DOLLAR


Total 112 1.88 1.64 2.78 5.68


Total 137 $0.062 $0.019 $0.055 $0.097


2,000 to 5,000 Customers 3 b a b a

5,000 to 10,000 Customers 14 2.12 1.44 2.24 4.05

10,000 to 20,000 Customers 27 2.30 2.02 3.80 5.46

20,000 to 50,000 Customers 30 1.47 2.18 4.36 7.82

50,000 to 100,000 Customers 18 1.84 1.26 1.88 3.52


2. Region


Southeast 34 2.34 1.38 2.58 5.28


Southwest 18 0.54 1.24 2.16 6.18

West 27 4.58 1.87 3.01 5.99


2,000 to 5,000 Customers 7 $0.062 a $0.030 a

5,000 to 10,000 Customers 23 0.045 0.019 0.034 0.075

10,000 to 20,000 Customers 32 0.058 0.039 0.066 0.079

20,000 to 50,000 Customers 36 0.088 0.032 0.070 0.122

50,000 to 100,000 Customers 19 0.044 0.007 0.034 0.078


2. Region

Northeast 9 0.065 -0.009 0.055 0.122

Southeast 40 0.042 0.011 0.034 0.064


Southwest 21 0.041 0.020 0.048 0.094

West 31 0.096 0.057 0.081 0.143

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


5b. Debt Service CoverageDefinition: The 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.

6. Net Income per Revenue DollarDefinition: The ratio of net electric utility income to total electric operating revenues. This ratio measures the amount of income remaining after accounting for operation and maintenance expenses, depreciation, taxes and tax equivalents for every dollar received from sales of electricity.

Net revenues available for debt service equal net electric 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 policies.

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 can also affect this ratio (e.g., how a utility finances capital investments).


TABLE 7. UNCOLLECTIBLE ACCOUNTS PER REVENUE DOLLAR


Total 133 $0.0031 $0.0007 $0.0015 $0.0031


2,000 to 5,000 Customers 7 $0.0031 a $0.0005 a

5,000 to 10,000 Customers 23 0.0020 0.0005 0.0015 0.0019

10,000 to 20,000 Customers 29 0.0017 0.0005 0.0009 0.0027

20,000 to 50,000 Customers 35 0.0040 0.0010 0.0021 0.0041

50,000 to 100,000 Customers 19 0.0020 0.0010 0.0014 0.0031


2. Region

Northeast 8 0.0115 a 0.0032 a

Southeast 40 0.0019 0.0009 0.0016 0.0026


Southwest 21 0.0034 0.0014 0.0026 0.0036

West 30 0.0039 0.0008 0.0016 0.0041


7. Uncollectible Accounts per Revenue DollarDefinition: The ratio of total uncollectible accounts to total electric utility operating revenues. This ratio measures the portion of each revenue dollar that will not be collected by the utility.

This ratio will be influenced by the financial and customer service policies of the utility.


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


Total 138 320 256 313 399


2,000 to 5,000 Customers 7 189 a 196 a

5,000 to 10,000 Customers 23 274 223 258 381

10,000 to 20,000 Customers 33 326 285 343 425

20,000 to 50,000 Customers 36 306 258 318 408

50,000 to 100,000 Customers 19 328 281 293 348

More than 100,000 Customers 20 323 271 315 387

2. Region

Northeast 9 331 277 322 414

Southeast 40 322 243 308 372

North Central/Plains 37 300 255 343 431

Southwest 21 380 256 290 393

West 31 297 267 301 395


8. Retail Customers per Non-power-generation EmployeeDefinition: 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 might 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 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. Contract employees include only those individuals performing regular utility work on an ongoing basis.


9. Total Operation and Maintenance Expense per Kilowatt-hour SoldDefinition: The ratio of total electric utility operation and maintenance expenses, including the cost of generated and purchased power, to total kilowatt-hour sales. 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 purchased power), transmission, distribution, customer accounting, customer services, sales, and administrative

and general functions of the electric utility. Because power supply 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., energy 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 138 $0.067 $0.063 $0.080 $0.097


2,000 to 5,000 Customers 7 $0.053 a $0.074 a

5,000 to 10,000 Customers 23 0.082 0.075 0.090 0.102

10,000 to 20,000 Customers 33 0.075 0.063 0.084 0.098

20,000 to 50,000 Customers 36 0.076 0.072 0.083 0.098

50,000 to 100,000 Customers 19 0.072 0.058 0.088 0.098


2. Region

Northeast 9 0.109 0.106 0.116 0.143

Southeast 40 0.080 0.076 0.091 0.098


Southwest 21 0.059 0.055 0.073 0.086

West 31 0.063 0.050 0.063 0.092

3. Generation

No generation 66 0.085 0.075 0.088 0.098


10 to 50% 23 0.059 0.051 0.076 0.096

50 to 100% 22 0.059 0.057 0.063 0.076



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


Total 136 574 410 540 705


2,000 to 5,000 Customers 7 881 a 497 a

5,000 to 10,000 Customers 23 655 410 484 744

10,000 to 20,000 Customers 32 601 381 501 694

20,000 to 50,000 Customers 35 582 394 573 689

50,000 to 100,000 Customers 19 665 457 584 778


2. Region

Northeast 9 905 795 956 1008

Southeast 40 441 364 434 555


Southwest 20 595 398 574 699

West 31 640 485 567 739


10. Total Operation and Maintenance Expense (Excluding Power Supply Expense) Per Retail CustomerDefinition: 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. The costs of power supply (generation and purchased power) are excluded from the ratio. This ratio can 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.


11. Total Power Supply Expense per Kilowatt-hour SoldDefinition: 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, and hydraulic generation. Operation and maintenance

expenses include the costs of fuel, labor, supervision, engineering, materials and supplies, and purchased power. The ratio might 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 138 $0.049 $0.045 $0.061 $0.076


2,000 to 5,000 Customers 7 $0.043 a $0.065 a

5,000 to 10,000 Customers 23 0.066 0.060 0.071 0.082

10,000 to 20,000 Customers 33 0.059 0.053 0.066 0.080

20,000 to 50,000 Customers 36 0.055 0.045 0.062 0.077

50,000 to 100,000 Customers 19 0.054 0.045 0.059 0.073


2. Region

Northeast 9 0.064 0.054 0.071 0.089

Southeast 40 0.065 0.068 0.075 0.081


Southwest 21 0.041 0.039 0.054 0.061

West 31 0.043 0.038 0.044 0.060

3. Generation

No generation 66 0.069 0.059 0.074 0.080


10 to 50% 23 0.039 0.037 0.056 0.067

50 to 100% 22 0.041 0.040 0.046 0.053



12. Purchased Power Cost per Kilowatt-hourDefinition: The ratio of the cost of purchased power to the number of kilowatt-hours purchased. This ratio measures the purchased power component of power supply costs.

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

Adjustments to the cost data were made in a small number of cases to eliminate 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, access 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 137 $0.053 $0.042 $0.059 $0.072


2,000 to 5,000 Customers 7 $0.043 a $0.062 a

5,000 to 10,000 Customers 23 0.061 0.056 0.067 0.077

10,000 to 20,000 Customers 33 0.058 0.039 0.068 0.077

20,000 to 50,000 Customers 36 0.054 0.041 0.059 0.075

50,000 to 100,000 Customers 19 0.049 0.041 0.051 0.070


2. Region

Northeast 9 0.057 0.050 0.065 0.076

Southeast 39 0.071 0.066 0.072 0.078


Southwest 21 0.049 0.047 0.051 0.061

West 31 0.040 0.035 0.040 0.051

3. Generation

No generation 66 0.066 0.056 0.069 0.077


10 to 50% 23 0.038 0.030 0.042 0.067

50 to 100% 21 0.045 0.028 0.047 0.049



13. Retail Customers per Meter ReaderDefinition: The 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 meter readings, and the technology or methods used to read meters will influence the ratio.

As more utilities implement advanced meters that can read customer data without having to send a meter reader to the customer’s residence or business, utilities require

fewer meter readers to cover their service territories. Some utilities have installed advanced meters in all of their service territory and no longer employ meter readers. These utilities have been excluded from the customer size and region summaries of this ratio. We added a category for this ratio that shows the percentage of a utility’s customers that have advanced meters installed, and utilities with no 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 109* 9,637 4,628 6,609 10,475


2,000 to 5,000 Customers 7 2,741 a 3,072 a

5,000 to 10,000 Customers 17 4,084 3,148 4,549 6,168

10,000 to 20,000 Customers 23 6,058 5,116 6,252 8,749

20,000 to 50,000 Customers 32 5,748 4,860 7,145 9,577

50,000 to 100,000 Customers 13 7,104 5,845 7,974 9,552

More than 100,000 Customers 17 13,870 10,572 12,771 46,161

2. Region

Northeast 6 6,886 a 7,277 a

Southeast 30 9,408 4,656 6,399 13,212

North Central/Plains 32 11,368 4,608 6,608 10,597

Southwest 19 11,174 3,147 5,423 8,772

West 22 7,958 4,981 6,605 10,639

3. Advanced Meter Percent**

No advanced meters 13 4,731 3,312 4,765 5,915

More than 0 but less than 40% 26 6,822 4,389 6,074 7,901

40 to 80% 10 8,319 3,331 4,712 9,507

80% or more 88 19,158 5,684 8,047 12,687

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


TABLE 14. DISTRIBUTION O&M EXPENSES PER RETAIL CUSTOMER


Total 128 $168 $133 $184 $229


2,000 to 5,000 Customers 7 $282 a $246 a

5,000 to 10,000 Customers 18 170 113 159 220

10,000 to 20,000 Customers 30 218 141 181 244

20,000 to 50,000 Customers 35 198 131 200 243

50,000 to 100,000 Customers 18 218 172 190 250


2. Region

Northeast 9 212 169 197 250

Southeast 37 154 134 171 223


Southwest 19 143 105 122 198

West 29 193 174 200 255


14. Distribution Operation and Maintenance Expenses Per Retail CustomerDefinition: 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.

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 categories 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 127 $7,586 $4,227 $7,637 $13,6633


2,000 to 5,000 Customers 7 $4,578 a $5,266 a

5,000 to 10,000 Customers 18 6,137 3,707 5,108 9,359

10,000 to 20,000 Customers 30 7,785 4,893 7,508 17,107

20,000 to 50,000 Customers 35 4,535 3,596 6,650 12,332

50,000 to 100,000 Customers 17 9,263 6,844 10,284 16,334

More than 100,000 Customers 20 8,607 6,204 11,106 12,451

2. Region

Northeast 9 14,804 13,614 23,016 24,656

Southeast 37 7,902 3,681 6,687 11,610

North Central/Plains 34 8,572 4,783 7,036 9,704

Southwest 19 6,446 3,388 6,149 12,480

West 28 7,548 5,232 7,551 12,926


15. Distribution Operation and Maintenance Expenses per Circuit MileDefinition: The ratio of total distribution operation and maintenance expenses to the total number of 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.

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

Utilities that do not allocate expenses to all three categories 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 128 $112 $44 $62 $93


2,000 to 5,000 Customers 7 $95 a $71 a

5,000 to 10,000 Customers 18 70 45 61 82

10,000 to 20,000 Customers 30 59 37 54 67

20,000 to 50,000 Customers 35 82 43 58 90

50,000 to 100,000 Customers 18 98 54 73 107


2. Region

Northeast 9 133 69 96 186

Southeast 37 69 42 58 66


Southwest 19 68 48 64 80

West 29 185 63 112 163


16. Customer Accounting, Customer Service and Sales Expenses per Retail CustomerDefinition: 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 service 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 by the mix of customer classes it serves.

Utilities that do not allocate expenses to all three categories 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.


17. Administrative and General Expenses per Retail CustomerDefinition: 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 operation 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 might be

included are compensation of officers and executives, office supplies, professional fees, property insurance and claims, pensions and benefits, and other expenses not provided for elsewhere.

Those utilities that do not allocate expenses to all three categories 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.

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

TABLE 17. ADMINISTRATIVE AND GENERAL EXPENSES PER RETAIL CUSTOMER


Total 127 $209 $135 $194 $290


2,000 to 5,000 Customers 7 $317 a $219 a

5,000 to 10,000 Customers 18 205 150 168 240

10,000 to 20,000 Customers 30 260 100 198 321

20,000 to 50,000 Customers 34 249 105 182 277

50,000 to 100,000 Customers 18 256 167 243 312


2. Region

Northeast 9 335 105 285 419

Southeast 37 182 128 163 219


Southwest 18 271 175 234 327

West 29 167 135 234 291

3. Generation

No generation 60 187 102 162 231

More than 0 but less than 10% 24 232 173 202 296

10 to 50% 22 257 170 284 325

50 to 100% 21 201 163 227 373



18. Labor Expense per Worker-HourDefinition: The 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 premiums 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 time, are not included. This is not the same as a wage rate, which is simply the earnings per hour. A wage rate generally includes hours not worked (such as vacation or sick pay).

TABLE 18. LABOR EXPENSE PER WORKER-HOUR


Total 131 $48.23 $33.00 $41.04 $49.07


2,000 to 5,000 Customers 7 $39.22 a $38.02 a

5,000 to 10,000 Customers 23 36.47 29.82 34.59 42.61

10,000 to 20,000 Customers 30 40.34 34.07 39.70 43.65

20,000 to 50,000 Customers 34 39.60 32.37 37.22 48.96

50,000 to 100,000 Customers 17 46.44 40.93 45.27 49.72


2. Region


Southeast 39 40.90 29.05 32.83 41.24


Southwest 21 47.92 28.71 34.84 46.05

West 28 52.95 43.62 52.08 56.53

3. Generation

No generation 64 39.90 29.44 37.48 43.56


10 to 50% 21 52.14 41.06 44.66 55.72

50 to 100% 21 51.08 40.02 44.79 50.33



19. Energy Loss PercentageDefinition: The 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 efficiency. 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 distribution 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 132 3.67 2.47 3.39 4.62


2,000 to 5,000 Customers 7 2.07 a 2.86 a

5,000 to 10,000 Customers 21 3.39 2.52 3.44 5.12

10,000 to 20,000 Customers 32 2.82 2.07 2.59 3.94

20,000 to 50,000 Customers 35 4.45 2.98 3.48 5.37

50,000 to 100,000 Customers 18 2.74 2.28 3.29 3.86


2. Region

Northeast 9 2.80 2.03 2.44 3.13

Southeast 40 3.77 2.97 3.67 4.73


Southwest 20 4.38 3.24 4.12 5.21

West 28 3.40 2.29 3.28 3.78

3. Generation

No generation 64 3.88 2.83 3.67 5.12


10 to 50% 20 3.09 1.99 2.41 3.56

50 to 100% 22 3.90 2.98 3.40 4.44



TABLE 20. SYSTEM LOAD FACTOR


Total 133 61.4% 51.7 57.4 63.4


2,000 to 5,000 Customers 6 55.1% a 57.2 a

5,000 to 10,000 Customers 23 61.4 54.0 57.8 62.8

10,000 to 20,000 Customers 32 59.1 53.7 57.6 62.6

20,000 to 50,000 Customers 35 57.3 49.8 56.5 61.6

50,000 to 100,000 Customers 18 67.4 51.1 61.0 77.1


2. Region

Northeast 9 54.5 50.0 55.0 59.7

Southeast 39 56.9 50.9 55.1 58.6


Southwest 20 64.4 53.6 58.5 66.5

West 29 61.0 50.5 57.4 65.8


20. System Load FactorDefinition: The ratio of the system average load, total sales plus losses (MWh) divided by 8,760 (hours per year), to system peak demand (typically a summer or winter peak measured during a particular hour at all delivery points and generator busses on a totalized basis).

System load factor is descriptive of the total system load characteristics. It tells system planners how much the overall 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 metric gives financial planners and rate designers information to support greater unbundling of fixed and variable costs—a goal of competitive rate design.


21. Capital Expenditures to Depreciation ExpenseDefinition: The ratio of the of amount of capital expenditures in a year divided by depreciation expenses.

TABLE 21. CAPITAL EXPENDITURES TO DEPRECIATION EXPENSE


Total 134 $1.38 $0.81 $1.14 $1.76


2,000 to 5,000 Customers 7 $0.71 a $0.64 a

5,000 to 10,000 Customers 20 1.07 0.87 1.11 1.39

10,000 to 20,000 Customers 32 1.56 0.68 1.12 2.07

20,000 to 50,000 Customers 36 1.62 0.86 1.32 2.05

50,000 to 100,000 Customers 19 2.31 1.05 1.48 2.52


2. Region

Northeast 9 1.22 0.81 1.28 1.33

Southeast 38 1.12 0.76 1.29 1.88


Southwest 21 1.48 0.90 1.10 1.92

West 31 1.52 0.92 1.15 1.85

3. Generation

No generation 62 2.01 0.96 1.32 2.13


10 to 50% 23 2.38 0.94 1.28 2.10

50 to 100% 22 1.03 0.71 0.92 1.07



APPENDIX A:American Public Power Association 2017 Performance Indicators Survey

PART I. EMPLOYMENT, HOURS AND EARNINGS (Calendar Year Ending in 2017)

ELECTRIC UTILITY EMPLOYEES FULL-TIME PART-TIME

1. Total Average No. of Employees ____________________________ ____________________________

2. Total Annual Hours Worked ____________________________ ____________________________

3. Total Annual Earnings ____________________________ ____________________________

CONTRACT LABOR EMPLOYEES SUPERVISED EMPLOYEES SUPERVISED (BY THE UTILITY) (BY THE SUPERVISING COMPANY)

Company

1. Total Average No. of Employees ____________________________ ____________________________

2. Total Annual Hours Worked ____________________________ ____________________________

3. Total Annual Earnings ____________________________ ____________________________

NUMBER OF EMPLOYEES, FULL-TIME PART-TIME CONTRACTSELECTED ELECTRIC UTILITY DEPARTMENTS

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 2017)

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.) _________________

TOTAL ELECTRIC UTILITY

Uncollectible Accounts (FERC 904) $_________________

Debt Service Payments on Long-Term Debt $_________________

CAPITAL EXPENDITURES

Current Calendar Year $_________________


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 Procedures

The financial and operating ratios in this report are calculated using data from the Association’s 2017 Performance Indicators Survey. The survey includes data on employees, hours worked, earnings, distribution lines, reliability, lost workdays, and uncollectible 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 2017.

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) (Performance Indicators Survey, part III, line 3) + (Performance Indicators Survey, part III, line 4)

Performance Indicators Survey, part III, line 2

3. Operating Ratio (Total Electric O&M Expense to Total Electric Revenue) Performance Indicators Survey, part III, line 16


4. Current Ratio (Current & Accrued Assets to Current & Accrued Liabilities) Performance Indicators Survey, Part III, line 1 Performance Indicators Survey, Part III, line 4

5a. Times Interest Earned (Net Electric Utility Income + Interest on Long-Term Debt to Interest on Long-Term Debt) (Performance Indicators Survey, part III, line 9) + (Performance Indicators Survey, part III, line 8)


5b. Debt Service Coverage (Electric Utility Income + Depreciation to Total Electric Utility Debt Service Payments on Long-term Debt) (Performance Indicators Survey, part III, line 7) + (Performance Indicators Survey, part III, line 6)

Performance Indicators Survey, Part II, Section C

6. Net Income per Revenue Dollar Performance Indicators Survey, part III, line 9


7. Uncollectible accounts per Revenue Dollar Performance Indicators 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 (Performance Indicators 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 Performance Indicators Survey, Part III, line 16 (EIA Form 861, Schedule 2, Part B, line 11 + line 12) *1000

10. Total O&M Expense (Excluding Power Supply Expense) per Retail Customer (Performance Indicators Survey, Part III, line 16) - (Performance Indicators 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 Performance Indicators Survey, Part III, line 11 (EIA Form 861, Schedule 2, Part B, line 11 + line 12) *1000

12. Purchased Power Cost per kWh Performance Indicators Survey, part III, line 10 (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 Performance Indicators Survey, Part I, Section C

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

14. Distribution O&M Expenses per Retail Customer Performance Indicators Survey, Part III, line 13 EIA Form 861, Schedule 4, Part A, Total Number of Customers (column e)

15. Distribution O&M Expenses per Circuit Mile Performance Indicators Survey, Part III, line 13 Performance Indicators Survey, Part II, Section A, Total Distribution Line Circuit Miles

16. Customer Accounting, Customer Service and Sales Expense per Retail Customer Performance Indicators Survey, Part III, line 14 EIA Form 861, Schedule 4, Part A, Total Number of Customers (column e)

17. Administrative and General Expenses per Retail Customer Performance Indicators Survey, Part III, line 15 EIA Form 861, Schedule 4, Part A, Total Number of Customers (column e)

18. Labor Expense per Worker-hour Total Labor Expense (Performance Indicators Survey, Part I) Total Hours Worked (Performance Indicators 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) / 8,760 hours per year) / 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 Performance Indicators Survey, Part II, Section D Performance Indicators Survey, Part III, line 6


APPENDIX C: Regional Definitions

The regions used for this report correspond to regions of the North American Electric Reliability Corp. (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. The Association uses the former regions in establishing regional breakdowns to be consistent with prior reports.


APPENDIX D: Utilities Included in the 2017 Report

ALABAMADecatur UtilitiesHuntsville UtilitiesRiviera UtilitiesScottsboro Electric Power Board Troy, City of

ARIZONAElectrical District No. 3 Pinal CountyNavajo Tribal Utility AuthoritySalt River Project

ARKANSAS Clarksville Light & Water Co.Hope Water & Light Commission Jonesboro City Water & Light Paragould City Light, Water & Cable CALIFORNIAAzusa Light & WaterGlendale Water & PowerModesto Irrigation DistrictPasadena Water and Power Department Redding, City ofRiverside Public Utilities Sacramento Municipal Utility DistrictSilicon Valley PowerTurlock Irrigation District COLORADOLoveland Water & Power

CONNECTICUTNorwich Public Utilities

FLORIDABeaches Energy ServiceJEAKeys Energy ServicesKissimmee Utility AuthorityLakeland ElectricOrlando Utilities CommissionTallahassee Electric Utility

GEORGIAMarietta Board of Lights & Water

ILLINOISSpringfield City Water, Light & PowerSt. Charles, City of

INDIANALawrenceburg Municipal UtilitiesRichmond Power and Light IOWAAmes, City ofCedar Falls UtilitiesDenison Municipal UtilitiesMuscatine Power & Water

KANSASKansas City Board of Public UtilitiesMcPherson Board of Public Utilities

KENTUCKYHenderson City Utility CommissionOwensboro Municipal Utilities LOUISIANALafayette Utilities System MASSACHUSETTSBraintree Electric Light DepartmentHolyoke Gas & ElectricMansfield Municipal Electric DepartmentTaunton Municipal Lighting PlantWestfield Gas & Electric Light Department MICHIGANBay City, City ofGrand Haven Board of Light & PowerLansing Board of Water & LightMarquette Board of Light & PowerTraverse City Light & PowerZeeland Board of Public Works

MINNESOTAALP Utilities Austin Utilities Brainerd Public UtilitiesElk River Municipal Utilities Grand Rapids Public Utilities Commission Marshall Municipal Utilities Owatonna Public Utilities Rochester Public Utilities Willmar Municipal Utilities MISSOURICarthage Water and Electric PlantChillicothe, City ofIndependence Power & Light Poplar Bluff Municipal Utilities & City Cable City Utilities of Springfield

MISSISSIPPIGreenwood Utilities Commission NEBRASKAGrand Island, City ofHastings, City of Lincoln Electric System Loup Power District Omaha Public Power DistrictSouthern Public Power District NEW MEXICOFarmington, City of

NEW YORKFairport, Village ofPlattsburgh Municipal Lighting Department NORTH CAROLINAFayetteville Public Works CommissionGreenville Utilities CommissionLexington, City ofMonroe, City ofRocky Mount, City of Shelby, City of OHIOBryan Municipal UtilitiesHudson Public Power Orrville, City ofWesterville Electric Division

OREGONCentral Lincoln People’s Utility District Clatskanie People’s Utility District Eugene Water & Electric BoardMcMinnville Water & LightNorthern Wasco County People’s Utility District Springfield Utility Board SOUTH CAROLINAOrangeburg, City of

SOUTH DAKOTAWatertown Municipal Utilities


TENNESSEE Benton County Electric System Bristol Tennessee Essential Services Brownsville Utility Department Columbia Power & Water Systems Cookeville, City of Covington Electric System Jackson Energy Authority Lewisburg Electric System McMinnville Electric System Memphis Light, Gas and Water DivisionNashville Electric ServiceParis Board of Public UtilitiesPulaski Electric SystemRipley Power & Light Company Sevier County Electric System Tullahoma Utilities Authority TEXAS Austin EnergyBrownsville Public Utilities BoardBryan Texas Utilities College Station, City ofCPS Energy Denton Municipal ElectricGarland, City ofKerrville Public Utility Board Lubbock Power & Light

UTAHHeber Light & Power Co.Lehi CityProvo City Power

VERMONTBurlington Electric Department WASHINGTONBenton PUD Clallam County, Public Utility District No. 1 of Clark Public UtilitiesCowlitz County, Public Utility District No. 1 ofGrays Harbor County, Public Utility District No. 1 ofLewis County, Public Utility District No. 1 ofMason County, Public Utility District No. 3 ofSeattle City Light Tacoma Public Utilities WISCONSINManitowoc Public Utilities Marshfield Utilities Rice Lake Utilities Wisconsin Rapids Water Works & Lighting Commission

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financial and operating ratios of public power utilities

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