FINANCIAL AND OPERATING RATIOS of Public …...responded to APPA’s Performance Indicator Survey,...

FINANCIAL AND OPERATING RATIOSof Public Power Utilities

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PUBLISHED DECEMBER 2017

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FINANCIAL AND OPERATING RATIOSof Public Power Utilities

4 FINANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES FINANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES 5

ABOUT THIS REPORT

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

Association (APPA) on financial and operating ratios. Many of the ratios in this

report were suggested by the APPA Performance Management Committee and its

predecessor, the APPA Task Force on Performance Indicators.

The report was prepared by the APPA Regulatory Affairs Department.

COMMENTS OR QUESTIONS ABOUT THIS REPORT

APPA 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 Crytal Dr.

Suite 1000

Arlington, VA 22202

202/467-2969

CONTENTS

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

A. The 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. Median Values by Customer Size Class ........................................................................................................................................ 11

B. Median Values by Region ............................................................................................................................................................. 12

C. Median Values 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: APPA PERFORMANCE INDICATOR SURVEY, 2016 ................................................................................................... 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 191 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 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 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. The 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 APPA Performance Indicator Survey, 2016, 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.

B. Utilities in the ReportThe utilities included in this report are those that responded to APPA’s Performance Indicator Survey, 2016. The survey was sent to all public power utilities whose sales to consumers account for approximately 50 percent or more of their total sales, and who also have retail sales or sales for resale of 100,000 megawatt-hours or more.

Direct comparisons with the 2015 ratio report should not be made because the composition of utilities included for each ratio may have changed. Although 191 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 are excluded from calculations if there is reason to believe the information is incorrect, e.g., extreme values, etc.

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.

INTRODUCTIONFINANCIAL RATIOS NO. of UTILITIES MEDIAN

1. Revenue per KWH

a. All Retail Customers 191 $0.097

b. Residential Customers 191 $0.108

c. Commercial Customers 191 $0.101

d. Industrial Customers 171 $0.073

2. Debt to Total Assets 177 0.324

3. Operating Ratio 191 0.854

4. Current Ratio 188 2.48

5a. Times Interest Earned 152 4.90

5b. Debt Service Coverage 150 3.04

6. Net Income per Revenue Dollar 188 $0.055

7. Uncollectible Accounts per Revenue Dollar 183 $0.0016

OPERATING RATIOS

8. Retail Customer per Non-Power Generation Employee 191 327

9. Total O&M Expense per KWH Sold 191 $0.081

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer 190 $513

11. Total Power Supply Expense per KWH Sold 191 $0.062

12. Purchased Power Cost per KWH 190 $0.059

13. Retail Customers per Meter Reader* 151 6,244

14. Distribution O&M Expense per Retail Customer 171 $174

15. Distribution O&M Expense per Circuit Mile 171 $6,582

16. Customer Accounting, Service, and Sales Expense per Retail Customer 171 $63

17. Administrative and General Expense per Retail Customer 171 $181 OTHER RATIOS

18. Labor Expense per Worker-Hour 185 $39.10

19. Energy Loss Percentage 183 3.58%

20. System Load Factor 188 55.4%

21. Capital Expenditures to Depreciation Expense 180 1.20

* 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 class size and number of responses in each class are shown in the chart below. (Two wholesale entities with no retail customers 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.

Finally, respondents are grouped into categories based upon the percent of total power requirements generated by the utility. 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.

24 8

37

48

19

55

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

26

101

26

38

50 to 100%

No Generation

10 to 50%

More than 0 but less than 10%

Number of Responses, by Generation

47

12

56

51

25

West

Northeast

Southeast

North/Central Plains

Southwest

Number of Responses, by Region

C. Definitions, Data Sources and ComputationsDefinitions of each ratio are found in Section III, “Detailed Tables,” and information on data sources and computations are 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 APPA Performance Indicators Survey, 2016.

D. 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. A high or low value for a given ratio for an individual utility, relative to the median for a group, may be due to particular policies or situations faced by a utility, and may 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 may 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, etc.);

* 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 that may affect public power systems in some states;

* 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 APPA 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 APPA Performance Indicators Survey.

SUMMARY TABLESTABLE A: 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 $0.085 $0.092 $0.095 $0.098 $0.102 $0.094

b. Residential Customers $0.102 $0.108 $0.109 $0.107 $0.116 $0.111

c. Commercial Customers $0.095 $0.102 $0.102 $0.102 $0.105 $0.094

d. Industrial Customers $0.079 $0.077 $0.069 $0.074 $0.076 $0.067

2. Debt to Total Assets 0.182 0.185 0.240 0.336 0.479 0.578

3. Operating Ratio 0.896 0.885 0.866 0.867 0.776 0.691

4. Current Ratio 10.38 2.49 2.98 1.90 3.33 1.57

5a. Times Interest Earned a 8.55 7.27 3.75 2.87 1.89

5b. Debt Service Coverage a 4.16 3.59 3.80 2.90 1.85

6. Net Income per Revenue Dollar $0.068 $0.083 $0.092 $0.116 $0.099 $0.082

7. Uncollectible Accounts per Revenue Dollar $0.0003 $0.0026 $0.0026 $0.0026 $0.0026 $0.0038

8. Retail Customer per Non-Power Generation Employee 251 347 349 332 311 322

9. Total O&M Expense per KWH Sold $0.067 $0.081 $0.082 $0.086 $0.085 $0.056

10. Total O&M Expense (Excluding Power Supply Exp.) per Retail Customer $451 $560 $469 $499 $588 $517

11. Total Power Supply Expense per KWH Sold $0.057 $0.069 $0.065 $0.063 $0.060 $0.043

12. Purchased Power Cost per KWH $0.053 $0.067 $0.063 $0.058 $0.063 $0.043

13. Retail Customers per Meter Reader 3,253 4,836 5,788 6,594 8,839 12,439

14. Distribution O&M Expense per Retail Customer $207 $152 $179 $162 $199 $150

15. Distribution O&M Expense per Circuit Mile $5,356 $5,916 $5,864 $5,702 $11,780 $9,777

16. Customer Accounting, Service, and Sales Expense per Retail Customer $80 $64 $52 $59 $59 $89

17. Administrative and General Expense per Retail Customer $259 $185 $181 $152 $239 $185

18. Labor Expense per Worker-Hour $37.81 $34.01 $38.97 $38.62 $42.41 $45.30

19. Energy Loss Percentage 4.00% 3.69% 3.37% 3.82% 3.40% 3.86%

20. System Load Factor 56.5% 55.7% 55.6% 52.8% 55.7% 58.5%

21. Capital Expenditures to Depreciation Expense 0.65 1.06 1.34 1.27 1.43 1.31

a: Medians are not calculated for fewer than 5 responses


TABLE B: MEDIAN VALUES BY REGION TABLE C: MEDIAN VALUES BY POWER GENERATION CLASS*

NorthRatio Northeast Southeast Central/Plains Southwest West

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

1. Revenue per KWH

a. All Retail Customers $0.131 $0.098 $0.096 $0.095 $0.088

b. Residential Customers $0.131 $0.110 $0.114 $0.105 $0.104

c. Commercial Customers $0.141 $0.104 $0.103 $0.094 $0.090

d. Industrial Customers $0.115 $0.072 $0.080 $0.073 $0.063

2. Debt to Total Assets 0.245 0.299 0.274 0.386 0.405

3. Operating Ratio 0.923 0.880 0.859 0.833 0.813

4. Current Ratio 2.01 1.96 2.69 3.49 2.32

5a. Times Interest Earned 3.36 6.89 4.83 4.89 2.93

5b. Debt Service Coverage 3.36 3.97 2.98 3.09 2.509

6. Net Income per Revenue Dollar $0.047 $0.048 $0.049 $0.083 $0.061

7. Uncollectible Accounts per Revenue Dollar $0.0028 $0.0017 $0.0007 $0.0024 $0.0014

8. Retail Customer per Non-Power Generation Employee 354 293 366 320 345

9. Total O&M Expense per KWH Sold $0.111 $0.087 $0.082 $0.071 $0.072

10. Total O&M Expense (Excluding Power

Supply Exp.) per Retail Customer $707 $400 $546 $526 $584

11. Total Power Supply Expense per KWH Sold $0.070 $0.073 $0.060 $0.055 $0.045

12. Purchased Power Cost per KWH $0.068 $0.070 $0.060 $0.050 $0.043

13. Retail Customers per Meter Reader 6,208 6,099 6,310 5,649 7,220

14. Distribution O&M Expense per Retail Customer $163 $165 $151 $175 $206

15. Distribution O&M Expense per Circuit Mile $10,177 $5,543 $5,864 $6,454 $9,683

16. Customer Accounting, Service, and Sales

Expense per Retail Customer $110 $54 $56 $52 $94

17. Administrative and General Expense per Retail Customer $213 $150 $207 $170 $185

18. Labor Expense per Worker-Hour $47.01 $30.23 $38.71 $37.31 $50.28

19. Energy Loss Percentage 3.36% 4.07% 3.25% 4.06% 3.00%

20. System Load Factor 52.9% 54.8% 57.9% 53.4% 57.1%

21. Capital Expenditures to Depreciation Expense 1.08 1.26 1.04 1.30 1.25

1. Revenue per KWH

a. All Retail Customers $0.098 $0.097 $0.092 $0.131

b. Residential Customers $0.106 $0.109 $0.110 $0.113

c. Commercial Customers $0.100 $0.112 $0.096 $0.096

d. Industrial Customers $0.073 $0.078 $0.074 $0.070

2. Debt to Total Assets 0.255 0.353 0.381 0.538

3. Operating Ratio 0.874 0.872 0.816 0.724

9. Total O&M Expense per KWH Sold $0.085 $0.089 $0.071 $0.063

11. Total Power Supply Expense per KWH Sold $0.071 $0.064 $0.055 $0.043

12. Purchased Power Cost per KWH $0.068 $0.058 $0.051 $0.041

17. Administrative and General Expense per Retail Customer $164 $172 $223 $223

18. Labor Expense per Worker-Hour $37.61 $37.81 $45.67 $42.87

19. Energy Loss Percentage 3.92% 3.36% 2.90% 3.42%

21. Capital Expenditures to Depreciation Expense 1.27 1.08 1.28 0.93

* 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.

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 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 statistics page of APPA’s website at https://www.publicpower.org/public-power/stats-and-facts/industry-statistics-and-reports

DETAILED TABLESTABLE 1A. REVENUE PER KWH: ALL RETAIL CUSTOMERS

TABLE 1B. REVENUE PER KWH: RESIDENTIAL CUSTOMERS

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

Total 191 $0.104 $0.083 $0.097 $0.110


Total 191 $0.119 $0.099 $0.108 $0.122

1. Customer Size Class

2,000 to 5,000 Customers 8 $0.072 a $0.085 a

5,000 to 10,000 Customers 37 0.091 0.084 0.092 0.101

10,000 to 20,000 Customers 48 0.090 0.081 0.095 0.106

20,000 to 50,000 Customers 55 0.093 0.085 0.098 0.114

50,000 to 100,000 Customers 19 0.106 0.093 0.102 0.120

More than 100,000 Customers 24 0.108 0.085 0.094 0.110

2. Region

Northeast 12 0.160 0.117 0.131 0.143

Southeast 56 0.096 0.091 0.098 0.103

North Central/Plains 51 0.092 0.084 0.096 0.106

Southwest 25 0.093 0.082 0.095 0.101

West 47 0.108 0.072 0.088 0.117

3. Generation

No generation 101 0.095 0.084 0.098 0.104

more than 0 but less than 10% 38 0.124 0.083 0.097 0.115

10 to 50% 26 0.093 0.082 0.092 0.1084

50 to 100% 26 0.105 0.085 0.096 0.129


2,000 to 5,000 Customers 8 $0.095 a $0.102 aa

5,000 to 10,000 Customers 37 0.106 0.099 0.108 0.117

10,000 to 20,000 Customers 48 0.106 0.098 0.109 0.122

20,000 to 50,000 Customers 55 0.107 0.097 0.107 0.123

50,000 to 100,000 Customers 19 0.118 0.106 0.116 0.129


2. Region

Northeast 12 0.181 0.124 0.131 0.156

Southeast 56 0.108 0.101 0.110 0.118


Southwest 25 0.105 0.097 0.105 0.113

West 47 0.122 0.092 0.104 0.132

3. Generation

No generation 101 0.105 0.097 0.106 0.118


10 to 50% 26 0.107 0.099 0.110 0.118

50 to 100% 26 0.120 0.107 0.113 0.139

a: Quartiles are not calculated for fewer than 9 responses



TABLE 1C. REVENUE PER KWH: COMMERCIAL CUSTOMERS

TABLE 1D. REVENUE PER KWH: INDUSTRIAL CUSTOMERS

TABLE 2. DEBT TO TOTAL ASSETS


Total 191 $0.106 $0.090 $0.101 $0.115


Total 171 $0.073 $0.063 $0.073 $0.090


Total 177 0.559 0.173 0.324 0.489


2,000 to 5,000 Customers 8 $0.087 a $0.095 a

5,000 to 10,000 Customers 37 0.103 0.095 0.102 0.113

10,000 to 20,000 Customers 48 0.102 0.090 0.102 0.116

20,000 to 50,000 Customers 55 0.103 0.085 0.102 0.115

50,000 to 100,000 Customers 19 0.110 0.092 0.105 0.124


2. Region

Northeast 12 0.148 0.119 0.141 0.151

Southeast 56 0.100 0.099 0.104 0.113


Southwest 25 0.090 0.084 0.094 0.105

West 47 0.114 0.079 0.090 0.129

3. Generation

No generation 101 0.100 0.093 0.102 0.112


10 to 50% 26 0.093 0.090 0.096 0.120

50 to 100% 26 0.106 0.087 0.096 0.134


2,000 to 5,000 Customers 8 $0.062 $0.061 $0.079 $0.095

5,000 to 10,000 Customers 36 0.076 0.069 0.077 0.088

10,000 to 20,000 Customers 42 0.068 0.062 0.069 0.084

20,000 to 50,000 Customers 48 0.064 0.059 0.074 0.097

50,000 to 100,000 Customers 16 0.086 0.071 0.076 0.094


2. Region

Northeast 11 0.106 0.094 0.115 0.129

Southeast 50 0.066 0.063 0.072 0.080


Southwest 21 0.069 0.068 0.073 0.082

West 42 0.077 0.055 0.063 0.100

3. Generation

No generation 92 0.071 .0.062 0.073 0.087


10 to 50% 24 0.079 0.067 0.074 0.088

50 to 100% 21 0.073 0.057 0.070 0.104


2,000 to 5,000 Customers 7 0.210 a 0.182 a

5,000 to 10,000 Customers 36 0.232 0.125 0.185 0.338

10,000 to 20,000 Customers 43 0.268 0.159 0.240 0.365

20,000 to 50,000 Customers 48 0.416 0.223 0.336 0.529

50,000 to 100,000 Customers 19 0.457 0.351 0.479 0.544


2. Region

Northeast 11 0.787 0.148 0.245 0.441

Southeast 54 0.609 0.180 0.299 0.486


Southwest 22 0.499 0.222 0.386 0.536

West 42 0.535 0.242 0.405 0.542

3. Generation

No generation 91 0.368 0.154 0.252 0.387


10 to 50% 24 0.501 0.213 0.381 0.567

50 to 100% 26 0.575 0.395 0.538 0.591




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 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 utility’s financial policies.


TABLE 4. CURRENT RATIO

TABLE 5A. TIMES INTEREST EARNED

TABLE 3. OPERATING RATIO


Total 188 1.50 1.49 2.48 3.90


Total 152 1.55 1.87 4.90 10.60


Total 191 0.741 0.766 0.854 0.918


2,000 to 5,000 Customers 7 5.95 a 10.38 a

5,000 to 10,000 Customers 37 2.43 1.58 2.49 4.05

10,000 to 20,000 Customers 47 2.53 1.89 2.98 5.08

20,000 to 50,000 Customers 54 1.37 1.07 1.90 3.27

50,000 to 100,000 Customers 19 2.90 1.90 3.33 5.27


2. Region

Northeast 12 1.53 1.32 2.01 5.72

Southeast 56 1.30 1.40 1.96 3.59


Southwest 24 1.99 1.88 3.49 5.04

West 46 1.29 1.41 2.32 3.95


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

5,000 to 10,000 Customers 26 9.22 5.29 8.55 14.19

10,000 to 20,000 Customers 37 6.78 4.75 7.27 15.58

20,000 to 50,000 Customers 43 3.71 2.21 3.75 11.04

50,000 to 100,000 Customers 18 2.35 1.22 2.87 5.74


2. Region

Northeast 6 1.93 2.06 3.36 8.92

Southeast 47 1.92 2.11 6.89 14.13

North Central/Plains 40 -2.09 1.68 4.83 12.50

Southwest 21 1.70 2.25 4.89 10.14

West 38 2.00 1.52 2.93 6.25


2,000 to 5,000 Customers 8 0.863 a 0.896 a

5,000 to 10,000 Customers 37 0.887 0.857 0.885 0.927

10,000 to 20,000 Customers 48 0.871 0.813 0.866 0.920

20,000 to 50,000 Customers 55 0.850 0.793 0.867 0.920

50,000 to 100,000 Customers 19 0.799 0.743 0.776 0.830


2. Region

Northeast 12 0.764 0.851 0.923 0.965

Southeast 56 0.781 0.812 0.880 0.929


Southwest 25 0.641 0.731 0.833 0.864

West 47 0.720 0.733 0.813 0.881

3. Generation

No generation 101 0.879 0.817 0.872 0.923


10 to 50% 26 0.782 0.760 0.816 0.906

50 to 100% 26 0.665 0.667 0.724 0.787


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 may vary considerably at other times of the year.

5a. Times Interest EarnedDefinition: TThe 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

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.

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 may be influenced by a utility’s financial policies.

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 may be influenced by the availability of alternative power options and the costs of purchased power.


TABLE 5B. DEBT SERVICE COVERAGE

TABLE 6. NET INCOME PER REVENUE DOLLAR


Total 150 1.37 1.64 3.04 6.69


Total 188 $0.036 $0.021 $0.055 $0.097


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

5,000 to 10,000 Customers 24 3.66 1.78 4.16 8.61

10,000 to 20,000 Customers 36 2.22 1.86 3.59 6.76

20,000 to 50,000 Customers 44 1.03 1.87 3.80 9.25

50,000 to 100,000 Customers 18 0.36 1.60 2.90 5.14


2. Region

Northeast 7 1.11 1.82 3.36 6.19

Southeast 46 2.27 1.82 3.97 9.03


Southwest 21 0.67 1.63 3.09 6.02

West 39 2.86 1.49 2.50 3.39


2,000 to 5,000 Customers 8 $0.036 a $0.068 a

5,000 to 10,000 Customers 37 0.095 0.026 0.044 0.083

10,000 to 20,000 Customers 47 0.066 0.029 0.062 0.092

20,000 to 50,000 Customers 54 0.064 0.021 0.041 0.116

50,000 to 100,000 Customers 18 0.059 0.016 0.070 0.099


2. Region

Northeast 12 0.076 0.021 0.047 0.068

Southeast 56 0.048 0.024 0.048 0.074

North Central/Plains 50 -0.146 0.014 0.049 0.099

Southwest 25 0.050 0.050 0.083 0.121

West 45 0.073 0.019 0.061 0.101

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 may be influenced by a utility’s financial policies.

The ratio may 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 7. UNCOLLECTIBLE ACCOUNTS PER REVENUE DOLLAR


Total 183 $0.0035 $0.0007 $0.0016 $0.0027


2,000 to 5,000 Customers 7 $0.0035 a $0.0003 a

5,000 to 10,000 Customers 36 0.0020 0.0006 0.0014 0.0026

10,000 to 20,000 Customers 43 0.0028 0.0007 0.0016 0.0026

20,000 to 50,000 Customers 54 0.0031 0.0009 0.0017 0.0026

50,000 to 100,000 Customers 19 0.0019 0.0009 0.0015 0.0026


2. Region

Northeast 12 0.0059 0.0024 0.0028 0.0049

Southeast 55 0.0021 0.0008 0.0017 0.0029


Southwest 25 0.0036 0.0014 0.0024 0.0036

West 46 0.0045 0.0008 0.0014 0.0022


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 191 305 257 327 424


2,000 to 5,000 Customers 8 213 a 251 a

5,000 to 10,000 Customers 37 298 235 347 419

10,000 to 20,000 Customers 48 325 274 349 430

20,000 to 50,000 Customers 55 314 272 332 474

50,000 to 100,000 Customers 19 285 285 311 360

More than 100,000 Customers 24 306 274 322 379

2. Region

Northeast 12 367 300 354 403

Southeast 56 304 242 293 379

North Central/Plains 51 268 264 366 433

Southwest 25 384 273 320 402

West 47 282 258 345 462


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.

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 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 purchased power), transmission, distribution, customer

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 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 on-going basis.

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 may 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 191 $0.064 $0.064 $0.081 $0.095


2,000 to 5,000 Customers 8 $0.057 a $0.067 a

5,000 to 10,000 Customers 37 0.080 0.073 0.081 0.096

10,000 to 20,000 Customers 48 0.075 0.066 0.082 0.097

20,000 to 50,000 Customers 55 0.075 0.066 0.086 0.100

50,000 to 100,000 Customers 19 0.050 0.072 0.085 0.095


2. Region

Northeast 12 0.075 0.096 0.111 0.121

Southeast 56 0.072 0.075 0.087 0.090


Southwest 25 0.054 0.060 0.071 0.089

West 47 0.069 0.055 0.072 0.085

3. Generation

No generation 101 0.082 0.072 0.085 0.094


10 to 50% 26 0.060 0.057 0.071 0.098

50 to 100% 26 0.055 0.051 0.063 0.076



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


Total 190 $568 $365 $513 $713


2,000 to 5,000 Customers 8 $818 a $451 a

5,000 to 10,000 Customers 37 635 365 560 830

10,000 to 20,000 Customers 47 544 361 469 648

20,000 to 50,000 Customers 55 547 321 499 695

50,000 to 100,000 Customers 19 748 433 588 738


2. Region

Northeast 12 658 595 707 928

Southeast 56 447 281 400 511


Southwest 25 530 413 526 722

West 47 591 478 584 757


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 may be affected by population density and the mix of customers between various classes (residential, commercial, industrial or other). Also, the extent that a utility services a large number of 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, hydraulic and other types of generation. Operation and

maintenance 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 191 $0.047 $0.046 $0.062 $0.075


2,000 to 5,000 Customers 8 $0.046 a $0.057 a

5,000 to 10,000 Customers 37 0.063 0.057 0.069 0.077

10,000 to 20,000 Customers 48 0.060 0.053 0.065 0.075

20,000 to 50,000 Customers 55 0.057 0.044 0.063 0.077

50,000 to 100,000 Customers 19 0.037 0.050 0.060 0.071


2. Region

Northeast 12 0.053 0.064 0.070 0.088

Southeast 56 0.059 0.065 0.073 0.077


Southwest 25 0.038 0.042 0.055 0.060

West 47 0.047 0.039 0.045 0.062

3. Generation

No generation 101 0.067 0.057 0.070 0.077


10 to 50% 26 0.040 0.041 0.055 0.065

50 to 100% 26 0.040 0.037 0.043 0.052



12. Purchased Power Cost per Kilowatt-hourDefinition: The ratio of the cost of purchased power to the amount 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.

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 meters without having to send a meter reader to the customer’s residence or business, these utilities require

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 may 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.

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 have added a new category 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, 34 utilities reported zero meter readers, and all of them were in the “80% or more” class for advanced meter percent.

TABLE 12. PURCHASED POWER COST PER KWH

TABLE 13. RETAIL CUSTOMERS PER METER READER


Total 190 $0.056 $0.042 $0.059 $0.0723


Total* 151 10,173 4,368 6,244 10,696


2,000 to 5,000 Customers 8 $0.045 a $0.053 a

5,000 to 10,000 Customers 37 0.061 0.057 0.067 0.072

10,000 to 20,000 Customers 47 0.058 0.046 0.063 0.072

20,000 to 50,000 Customers 55 0.054 0.042 0.058 0.074

50,000 to 100,000 Customers 19 0.049 0.048 0.063 0.073


2. Region

Northeast 12 0.042 0.051 0.068 0.086

Southeast 55 0.067 0.063 0.070 0.073


Southwest 25 0.060 0.044 0.050 0.065

West 47 0.057 0.037 0.043 0.057

3. Generation

No generation 101 0.064 0.051 0.067 0.074

More than 0 but less than 10% 37 0.044 0.046 0.058 0.068

10 to 50% 26 0.047 0.036 0.051 0.061

50 to 100% 26 0.064 0.031 0.041 0.064


22,000 to 5,000 Customers 6 2,794 a 3,253 a

5,000 to 10,000 Customers 27 6,080 3,947 4,836 6,532

10,000 to 20,000 Customers 41 5,563 3,644 5,788 7,105

20,000 to 50,000 Customers 42 7,271 4,681 6,594 10,537

50,000 to 100,000 Customers 14 12,752 7,075 8,839 23,833

More than 100,000 Customers 21 11,650 9,821 12,439 28,518

2. Region

Northeast 9 8,520 5,012 6,208 8,235

Southeast 43 10,057 4,109 6,099 13,291

North Central/Plains 42 11,354 4,354 6,310 10,523

Southwest 21 9,136 3,644 5,649 7,329

West 36 10,961 5,086 7,220 11,091

3. Advanced Meter Percent**

No advanced meters 19 3,432 3,444 4,079 5,823

More than 0 but less than 40% 41 6,485 4,248 5,832 8,005

40 to 80% 16 11,251 4,121 4,668 11,049

80% or more 112 20,388 5,818 8,207 16,6945


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 TABLE 15. DISTRIBUTION O&M EXPENSES PER CIRCUIT MILE


Total 171 $175 $123 $174 $227


Total 1171 $8,714 $4,357 $6,582 $11,967


2,000 to 5,000 Customers 7 $305 a $207 a

5,000 to 10,000 Customers 32 234 110 152 278

10,000 to 20,000 Customers 41 209 134 179 241

20,000 to 50,000 Customers 49 194 124 162 236

50,000 to 100,000 Customers 18 227 165 199 224


2. Region

Northeast 12 250 125 163 252

Southeast 49 140 122 165 191


Southwest 23 130 110 175 233

West 42 200 174 206 297


2,000 to 5,000 Customers 7 $4,207 a $5,356 a

5,000 to 10,000 Customers 32 5,617 3,802 5,916 10,463

10,000 to 20,000 Customers 41 6,492 4,202 5,864 11,562

20,000 to 50,000 Customers 49 4,805 3,944 5,702 9,849

50,000 to 100,000 Customers 18 11,570 7,184 11,780 16,247

More than 100,000 Customers 24 10,496 5,555 9,777 18,494

2. Region

Northeast 12 19,358 8,423 10,177 15,240

Southeast 49 6,527 3,529 5,543 10,185

North Central/Plains 45 6,554 4,732 5,864 8,672

Southwest 23 5,377 3,657 6,454 12,694

West 42 10,687 4,962 9,683 23,052

a: Quartiles are not calculated for fewer than 9 responses a: Quartiles are not calculated for fewer than 9 responses

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.

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.

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.

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 171 $112 $43 $63 $95


2,000 to 5,000 Customers 7 $90 a $80 a

5,000 to 10,000 Customers 32 74 47 64 92

10,000 to 20,000 Customers 41 60 39 52 74

20,000 to 50,000 Customers 49 84 42 59 102

50,000 to 100,000 Customers 18 80 44 59 96


2. Region

Northeast 12 120 59 110 165

Southeast 49 72 43 54 67


Southwest 23 72 40 52 74

West 42 155 61 94 146


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, 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 also 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 may 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 may affect the ratio.

TABLE 17. ADMINISTRATIVE AND GENERAL EXPENSES PER RETAIL CUSTOMER


Total 171 $200 $128 $181 $273


2,000 to 5,000 Customers 7 $303 $183 $259 $311

5,000 to 10,000 Customers 32 226 157 185 270

10,000 to 20,000 Customers 41 235 94 181 339

20,000 to 50,000 Customers 49 195 88 152 257

50,000 to 100,000 Customers 18 293 172 239 304


2. Region

Northeast 12 260 173 213 317

Southeast 49 197 125 150 197


Southwest 23 197 112 170 296

West 42 150 123 185 269

3. Generation

No generation 84 187 99 168 252

More than 0 but less than 10% 37 218 140 172 260

10 to 50% 24 217 146 223 371

50 to 100% 26 196 147 223 410



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

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 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).

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).

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 18. LABOR EXPENSE PER WORKER-HOUR

TABLE 19. ENERGY LOSS PERCENTAGE


Total 185 $48.04 $31.54 $39.10 $46.93


Total 183 4.12% 2.76% 3.58% 4.79%


2,000 to 5,000 Customers 7 $38.63 a $37.81 a

5,000 to 10,000 Customers 37 34.29 29.45 34.01 41.98

10,000 to 20,000 Customers 47 38.38 32.59 38.97 42.35

20,000 to 50,000 Customers 53 39.45 31.10 38.62 47.32

50,000 to 100,000 Customers 18 47.72 38.95 42.41 52.56


2. Region

Northeast 12 70.10 42.91 47.01 52.53

Southeast 55 37.24 27.85 30.23 36.79


Southwest 23 40.05 30.10 37.31 41.17

West 45 53.71 44.90 50.28 55.60

3. Generation

No generation 98 38.17 29.52 37.14 42.78


10 to 50% 25 49.55 38.80 45.67 51.53

50 to 100% 25 48.56 37.82 42.87 48.53


2,000 to 5,000 Customers 7 2.73% a 4.00% a

5,000 to 10,000 Customers 34 4.27 2.86 3.69 5.01

10,000 to 20,000 Customers 45 3.43 2.71 3.37 4.58

20,000 to 50,000 Customers 54 4.38 2.93 3.82 5.67

50,000 to 100,000 Customers 19 3.41 2.29 3.40 3.68


2. Region

Northeast 12 5.94 3.06 3.36 4.73

Southeast 53 3.38 3.13 4.07 4.97


Southwest 23 4.59 3.49 4.06 4.72

West 45 4.37 2.41 3.00 3.91

3. Generation

No generation 94 3.95 2.98 4.03 5.46


10 to 50% 26 2.88 2.27 2.90 3.66

50 to 100% 26 4.21 2.63 3.42 3.99




TABLE 20. SYSTEM LOAD FACTOR


Total 188 59.2% 51.0% 55.4% 62.5%


2,000 to 5,000 Customers 7 55.1% a 56.5% a

5,000 to 10,000 Customers 37 59.3 52.5 55.7 63.3

10,000 to 20,000 Customers 47 58.1 51.9 55.6 62.4

20,000 to 50,000 Customers 55 57.7 48.6 52.8 60.3

50,000 to 100,000 Customers 18 68.4 51.1 55.7 75.3


2. Region

Northeast 12 41.9 48.5 52.9 54.6

Southeast 56 57.1 51.3 54.8 59.3


Southwest 25 62.1 48.0 53.4 63.3

West 45 60.4 50.9 57.1 65.1


20. System Load FactorDefinition: The ratio of the system average load, total sales plus losses (MWh) divided by 8760 (hours), 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).

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

This ratio was added to the report as a measure of capital expenditures, and is subject to revision based upon participant feedback.

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 will give financial planners and rate designers information to support greater unbundling of fixed and variable costs--a goal of competitive rate design.

TABLE 21. CAPITAL EXPENDITURES TO DEPRECIATION EXPENSE


Total 180 $1.71 $0.84 $1.20 $1.77


2,000 to 5,000 Customers 8 $0.97 a $0.65 a

5,000 to 10,000 Customers 34 1.13 0.66 1.06 1.35

10,000 to 20,000 Customers 43 1.68 0.84 1.34 1.83

20,000 to 50,000 Customers 52 2.06 0.93 1.27 1.81

50,000 to 100,000 Customers 19 1.56 1.00 1.43 2.13


2. Region

Northeast 11 1.95 0.94 1.08 1.79

Southeast 53 1.87 0.86 1.26 1.57


Southwest 24 2.07 0.81 1.30 2.36

West 45 1.57 0.89 1.25 1.73

3. Generation

No generation 93 1.47 0.96 1.29 1.75


10 to 50% 24 2.13 0.83 1.28 1.81

50 to 100% 25 1.61 0.68 0.93 1.34



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 A:APPA Performance Indicators Survey, 2016

PART I. EMPLOYMENT, HOURS AND EARNINGS (Calendar Year Ending in 2016)

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)

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 2016)

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 $_________________


9. Total O & M Expense per kWh Sold APPA 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 (APPA Survey, Part III, line 16) - (APPA 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 APPA Survey, Part III, line 11 (EIA Form 861, Schedule 2, Part B, line 11 + line 12) *1000

12. Purchased Power Cost per kWh APPA 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 APPA Survey, Part I, Section C

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

14. Distribution O & M Expenses per Retail Customer APPA 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 APPA Survey, Part III, line 13 APPA Survey, Part II, Section A, Total Distribution Line Circuit Miles

16. Customer Accounting, Customer Service and Sales Expense per Retail Customer APPA 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 APPA 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 (APPA Survey, Part I) Total Hours Worked (APPA 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 APPA Survey, Part II, Section D APPA Survey, Part III, line 6

APPENDIX B: Data Sources and Computational Procedures

The financial and operating ratios in this report are calculated using data from the APPA Performance Indicators Survey, 2016. The APPA Survey includes data on employees, hours worked, earnings, distribution lines, reliability, lost workdays, 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 2016.

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) (APPA Survey, Part III, line 3) + (APPA Survey, part III, line 4) APPA Survey, Part III, line 2

3. Operating Ratio (Total Electric O&M Expense to Total Electric Revenue) APPA Survey, Part III, line 16 APPA Survey, Part III, line 5

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

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

5b. Debt Service Coverage (Electric Utility Income + Depreciation to Total Electric Utility Debt Service Payments on Long-term Debt) (APPA Survey, Part III, line 7) + (APPA Survey, Part III, line 6) APPA Survey, Part II, Section C

6. Net Income per Revenue Dollar APPA Survey, Part III, line 9 APPA Survey, Part III, line 5

7. Uncollectible accounts per Revenue Dollar APPA Survey, Part II, Section B, Uncollectible Accounts APPA Survey, Part III, line 5

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 (APPA Survey, Part I)

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


APPENDIX D: Utilities Included in the 2016 Report

ALABAMADecatur UtilitiesHuntsville UtilitiesRiviera UtilitiesScottsboro Electric Power BoardTroy, City of

ALASKAAnchorage Municipal Light & Power

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

ARKANSASClarksville Light & Water Co.Hope Water & Light Commission Jonesboro City Water & Light City of North Little Rock Electric Department Paragould City Light, Water & Cable

CALIFORNIAAzusa Light & WaterGlendale Water & PowerLodi Electric UtilityLos Angeles Department of Water & PowerMerced Irrigation DistrictModesto Irrigation DistrictPalo Alto, City of Pasadena Water and Power Department Redding, City ofRiverside Public Utilities Sacramento Municipal Utility DistrictSilicon Valley PowerTurlock Irrigation District

COLORADOFort Collins UtilitiesLongmont Power & CommunicationsLoveland Water & Power

CONNECTICUTNorwich Public UtilitiesWallingford Department of Public Utilities

FLORIDABeaches Energy ServiceJEAKeys Energy ServicesKissimmee Utility AuthorityLakeland ElectricLeesburg, City ofNew Smyrna Beach Utilities CommissionOcala Utility ServicesOrlando Utilities CommissionTallahassee Electric Utility

GEORGIACity of Calhoun Electric Department Cartersville, City ofCrisp County Power Commission

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

INDIANALawrenceburg Municipal UtilitiesLebanon, City ofMishawaka Utilities

IOWAAmes, City ofCedar Falls UtilitiesDenison Municipal UtilitiesMuscatine Power & WaterVinton Municipal Electric Utility

KANSASKansas City Board of Public Utilities

KENTUCKYHenderson City Utility CommissionMurray Electric System

LOUISIANALafayette Utilities System

MARYLANDEaston Utilities Commission

MASSACHUSETTSHolyoke Gas & ElectricMansfield Municipal Electric DepartmentMiddleborough Gas and Electric DepartmentPeabody Municipal Light PlantTaunton Municipal Lighting PlantWestfield Gas & Electric Light Department

MICHIGANBay City, City ofColdwater Board of Public UtilitiesGrand Haven Board of Light & PowerHolland Board of Public WorksLansing Board of Water & LightMarquette Board of Light & PowerTraverse City Light & Power

MINNESOTAALP Utilities Austin Utilities Brainerd Public UtilitiesElk River Municipal Utilities Grand Rapids Public Utilities Commission Hutchison Utilities Commission Marshall Municipal Utilities Moorhead Public Service New Ulm Public Utilities Owatonna Public Utilities Rochester Public Utilities Willmar Municipal Utilities

MISSOURICarthage Water and Electric PlantChillicothe, City ofHannibal, City ofIndependence Power & Light Marshall Municipal Utilities 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 Nebraska Public Power District Omaha Public Power DistrictPerennial Public Power District Southern Public Power District Wheat Belt Public Power

NEW MEXICOLos Alamos County Utilities

NEW YORKLong Island Power AuthorityMassena Electric DepartmentPlattsburgh Municipal Lighting Department

NORTH CAROLINAFayetteville Public Works CommissionGastonia, City ofGreenville Utilities CommissionKinston, City ofMonroe, City ofRocky Mount, City of Shelby, City ofStatesville, City of

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. APPA uses the former regions in establishing regional breakdowns to be consistent with prior reports.

42 FINANCIAL AND OPERATING RATIOS OF PUBLIC POWER UTILITIES

OHIOBryan Municipal UtilitiesCuyahoga Falls, City of Hudson Public Power Piqua Municipal Power SystemWesterville Electric Division

OKLAHOMAStillwater Electric Utility

OREGONCanby Utility Board Central Lincoln People’s Utility District Clatskanie People’s Utility District Eugene Water & Electric BoardForest Grove, City ofNorthern Wasco County People’s Utility District Springfield Utility Board Tillamook People’s Utility District

SOUTH CAROLINAEasley Combined UtilitiesSantee Cooper (South Carolina Public Service Authority)

SOUTH DAKOTABrookings, City ofWatertown Municipal Utilities

TENNESSEE Alcoa Electric DepartmentAthens Utilities Board Benton County Electric System Bristol Tennessee Essential Services Columbia Power & Water Systems Cookeville, City of Covington Electric System Dickson Electric System Jackson Energy Authority Lafollette Utilities Lewisburg Electric System McMinnville Electric System Memphis Light, Gas and Water DivisionMilan Department of Public Utilities Morristown Utility Systems TENNESSEE continued Nashville Electric ServiceParis Board of Public UtilitiesPulaski Electric SystemRipley Power & Light Company Sevier County Electric System Weakley County Municipal Electric System

TEXASAustin EnergyBrownsville Public Utilities BoardBryan Texas Utilities College Station, City ofCPS Energy Denton Municipal ElectricFloresville Electric Light and Power Systems Georgetown Utility SystemsKerrville Public Utility Board Lubbock Power & Light Weatherford Municipal Utility System

UTAHHeber Light & Power Co.Lehi CityMurray City PowerProvo City PowerSpringville, City ofSt. George, City of

VERMONTBurlington Electric Department

VIRGINIABVU AuthorityDanville Department of Utilities

WASHINGTONBenton PUD Clallam County, Public Utility District No. 1 of Clark Public UtilitiesCowlitz County, Public Utility District No. 1 ofFranklin PUDGrays Harbor County, Public Utility District No. 1 ofLewis County, Public Utility District No. 1 ofMason County, Public Utility District No. 3 ofPacific County, Public Utility District No. 2 ofPort Angeles, City ofSeattle City Light Tacoma Public Utilities

WISCONSINKaukauna Utilities Manitowoc Public Utilities Marshfield Utilities Reedsburg Utility CommissionRice Lake Utilities Wisconsin Rapids Water Works & Lighting Commission

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