# Simplified Distribution System Cost Methodologies for Distributed Generation

Discussion Draft February 2001 Wayne Shirley Regulatory Assistance Project
The increased availability and decreasing costs of distributed generation technology (DG) presents new challenges in regulation of distribution utilities. One of the key requirements in assessing DG is to gain a workable understanding of the cost of DG itself and of the alternative costs that might be incurred or avoided in the absence or presence of DG. Because the choices to install DG will be largely decentralized, every effort should be made to reveal these costs to as many of the stakeholders as possible, including distribution utilities, customers, DG purveyors, ISOs and system planners. It is equally important to reveal these costs to regulators who are in the position to see the big picture and develop appropriate policies for encouraging or discouraging DG, as necessary.


## This paper will focus on the actual costs of distribution utilities in the U.S. We have drawn upon a number of sources for this analysis. The principal source of data for this paper is the FERC Form 1 database for the years 1994-1999. We have alsodrawn upon individual case studies to demonstrate the significant deviation between particular distribution expansion costs and average marginal and average embedded costs. 

# Simplified Distribution System Cost Methodologies for Distributed Generation

Discussion Draft

February 2001 Wayne Shirley RegulatoryAssistance Project

The increased availability and decreasing costs ofdistributed generation technology (DG) presents new challenges in regulation ofdistribution utilities. One ofthe keyrequirements in assessing DG is to gain a workable understanding ofthe cost ofDG itselfand ofthe alternative costs that might be incurred or avoided in the absence orpresence ofDG. Because the choices to install DG will be largelydecentralized, every effort shouldbe made to reveal these costs to as many ofthe stakeholders as possible, including distribution utilities, customers, DGpurveyors, 1S0s and system planners. It

## is equally important to reveal these costs to regulators who are in the positionto see the bigpicture and develop appropriate policies for encouraging or discouraging DG, as necessary.

This paperwill focus onthe actual costs ofdistribution utilities in the U.S. We have drawn upon a number ofsources for this analysis. The principal source ofdata for this paperis the FERC Form 1 database for the years 1994-1999. We have alsodrawnupon individual case studies to demonstrate the significant deviation betweenparticular distribution expansion costs and average marginal and average embedded costs.

-1-

## The Components of Distribution Costs.

As a beginning point, we analyzed the average embedded and average marginal costs for 93 U.S. utilities for the period 1995-1999.' The first step in this process is to determined what accounts should be analyzed and group those into useful categories. Table x shows the FERC uniform distribution plant-in-service accounts, as reported in the FERC Form 1.



## FERC Distribution Accounts (360) Land and Land Rights (361) Structures and Improvements (362) Station Equipment (363) Storage Battery Equipment (364) Poles, Towers, and Fixtures (365) Overhead Conductors and Devices (366) Underground Conduit (367) Underground Conductors and Devices (368) Line Transformers (369) Services (370) Meters (371) Installations on Customer Premises (372) Leased Property on Customer Premises (373) Street Lighting and Signal Systems 

## Most distribution system expansion projects fall into one of four categories:

Improvements or expansion of transformers and substations Improvements or expansion of distribution lines and feeders Customer specific equipment 

## Other activities, such as street lighting and signal systems.

With this in mind, the FERC accounts can be grouped as follows:

1 We began with the entire FERC Form 1 database for the years 1994-1999. However, many of the reporting utilities do not have distribution plant and so were excluded from the group used for this analysis. In addition, a number of utilities were excluded because they had incomplete data in the available database. Finally, because a number of the calculations used for this analysis required comparison of investments to growth in system peak and system sales, utilities who had zero values in any year for those data were also excluded. The resulting data set includes 93 utilities. The included utilities are listed in Appendix A.


## -2- 

## The Components ofDistribution Costs.

As a beginningpoint, we analyzed the average embedded and average marginal costs for 93 U.S. utilities for the period 1995-1999. I 

## The first step 

# in this process is to determined what accounts should be analyzed and group those into useful categories. Table x shows the FERC uniform distribution plant-in-service accounts, as reported in the FERC Form 1.

FERC Distribution Accounts (360) Land and Land Rights (361) Structures and Improvements (362) Station Equipment (363) Storage BatteryEquipment (364) Poles, Towers, and Fixtures (365) Overhead Conductors and Devices (366) Underground Conduit (367) Underground Conductors and Devices (368) Line Transformers (369) Services (370) Meters (371) Installations on CustomerPremises (372) Leased Property on Customer Premises (373) Street Lighting and Signal Systems



## Most distribution system expansionprojects fall into one offour categories:

• Improvements or expansion oftransformers and substations
• Improvements or expansion ofdistribution lines and feeders Customer specific equipment
• Other activities, such as street lighting and signal systems.

With this inmind, the FERC accounts canbe grouped as follows:

I 

### We began with the entire FERC Form 1 database for the years 1994-1999. However, many ofthe reporting utilities do nothave distribution plant and so were excluded from the group used for this analysis. In addition, a number ofutilities were excludedbecause they had incomplete data in the available database. Finally, because a number ofthe calculations used for this analysis required comparison ofinvestments to growth in system peak and system sales, utilities who had zero values in any year for those data were also excluded. The resulting data set includes 93 utilities. The includedutilities are listed in Appendix A. 

## -2-

## • Transformer & Substation investments (a portion of accounts 360 and 361 plus account 362) 

## • Lines and Feeders investments (the balance of accounts 360 and 361 plus accounts 363, 364, 365, 366, 367 and 368) • Customer specific investments (accounts 369, 370, 371 and 372) and • Street lighting and signal systems (account 373).
For purposes of the costs that might be avoided or deferred through the use of DG, only accounts 360 through 368 are of interest. With exception of accounts 360 and 361, most of the accounts clearly are related to specific types of distribution plant. Accounts 360 and 361 represent costs incurred for both transformers & substations and for lines and feeders. We assigned 25% of these accounts to transformers & substation and 75% of these accounts to lines & feeders. 

## In addition to investments in plant-in-service, we analyzed the associated operations and maintenance (O&M) expenses for lines & feeders and for transformers & substations. The distribution O&M accounts are reflected in Table x:

FERC FORM 1 DISTRIBUTION EXPENSES Operation (580) Operation Supervision and Engineering (581) Load Dispatching (582) Station Expenses (583) Overhead Line Expenses (584) Underground Line Expenses (585) Street Lighting and Signal System Expenses (586) Meter Expenses (587) Customer Installations Expenses (588) Miscellaneous Expenses (589) Rents Maintenance (590) Maintenance Supervision and Engineering (591) Maintenance of Structures (592) Maintenance of Station Equipment (593) Maintenance of Overhead Lines (594) Maintenance of Underground Lines (595) Maintenance of Line Transformers (596) Maintenance of Street Lighting and Signal Systems (597) Maintenance of Meters (598) Maintenance of Miscellaneous Distribution Plant



## -3- Transformer & 

## Substation investments (a portion ofaccounts 360 and 361 plus account 362) Lines and Feeders investments (the balance ofaccounts 360 and 361 plus accounts 363, 364, 365, 366, 367 and 368) Customer specific investments (accounts 369, 370, 371 and 372) and Street lighting and signal systems (account 373).

Forpurposes ofthe costs that might be avoided or deferred through the use ofDG, only accounts 360 through 368 are ofinterest. With exception ofaccounts 360 and 361, most ofthe accounts clearly are related to specific types ofdistributionplant. Accounts 360 and 361 represent costs incurred for both transformers & 

## substations and for lines and feeders. We assigned 25% of these accounts to transformers & 

## substation and 75% ofthese accounts to lines & 

## feeders.

In 

## addition to investments inplant-in-service, we analyzed the associated operations and maintenance (O&M) expenses for lines & feeders and for transformers & substations. The distribution O&M accounts are reflected in Table x:

FERC FORM 1DISTRIBUTION EXPENSES Operation (580) Operation Supervision and Engineering (581) Load Dispatching (582) Station Expenses (583) Overhead Line Expenses (584) Underground Line Expenses (585) Street Lighting and Signal System Expenses (586) Meter Expenses (587) CustomerInstallations Expenses (588) Miscellaneous Expenses (589) Rents Maintenance (590) Maintenance Supervision and Engineering (591) Maintenance ofStructures (592) Maintenance ofStation Equipment (593) Maintenance ofOverhead Lines (594) Maintenance ofUnderground Lines (595) Maintenance ofLine Transformers (596) Maintenance ofStreet Lighting and Signal Systems (597) Maintenance ofMeters (598) Maintenance ofMiscellaneous Distribution Plant



## -3-

## Accounts 582 and 592 were assigned directly to Transformers & Substations. Accounts 583,

584, 593 and 594 were assigned directly to Lines and Feeders. Account 591 was assigned 25% to Transformers & Substations and 75% to Lines and Feeders, consistent with the allocation of plant in service. Finally, Account 580 was assigned 25% to Transformers & Substations and 50% to Lines and Additions, with the assumption that the remaining 25% would be associated with the other distribution expenses categories (meters, customer installations, street lighting, etc.). While a more detailed study for a particular company might result in different assignments, these allocations provide a reasonable proxy for purposes of this paper.

1000000000

900000 000

800000 000

700000000

600000 000

500000 000

400000 000

300000 000

200000 000

100000000 4 Transformer/Substation Plant -Linear (Transformer/Substation Plant)

- - --

y = 59217x +4E+0t, R'07855

-- 

### -

-- - n E

- 4

- - -

0 0 5000 10000 15000 20000 25000



## Embedded Costs for U.S. Utilities
A review of the FERC Form 1 data reveals that distribution system investment vary from year to year for any given utility. As a result, any one year might distort the experience of each utility. For this analysis, we collected the data for the five years 1995-1999 and computed the average additions to plant in service for each FERC account.



## -4- 

## Accounts 582 and 592 were assigned directlyto Transformers & 

## Substations. Accounts 583, 584,593 and 594 were assigned directlyto Lines and Feeders. Account 591 was assigned 25% to Transformers & 

## Substations and 75% to Lines and Feeders, consistent with the allocation of plant in service. Finally, Account 580 was assigned 25% to Transformers & 

## Substations and 50% to Lines and Additions, with the assumption that the remaining 25% would be associated with the other distribution expenses categories (meters, customer installations, street lighting, etc.). While a more detailed study for a particular companymightresult in different assignments, these allocations provide a reasonable proxy for purposes ofthis paper.

1995-19995Yr. Average Transformer/Substation Plant In Service as a Function of Average System Peal<

1000000000

900000000

800000000

700000000

600000000

500000000

400000000

300000000

200000000

100000000

0 0 5000 10000 15000 20000 25000



## Embedded Costs for U.S. Utilities

A review ofthe FERC Form 1 data reveals that distribution system investment vary from year to year for any given utility. As a result, anyone year might distort the experience ofeachutility. Forthis analysis, we collectedthe data for the five years 1995-1999 and computed the average additions to plant in service for each FERC account.

-4-

## We reviewed the relationship of investment to both system peak and to system sales. Using the

five year average investment, system peak and system sales data, it becomes clear that, as one would expect, the investment in Transformers and Substations and in Lines and Feeders are highly correlated with system peak. Chart x shows data for Transformers and Substations against system peak, along with a trend-line plot.
The R2 for the trendline is .78, indicating a relatively high correlation between investment and system peak. Similar analysis for Lines and Feeders, also reflects an RZ of .78. When compared to system sales, the RZ drops slightly to .76 and .75 for Transformers & Substations and for Lines & Feeders, respectively. This may be somewhat deceptive, however, because system sales are likely more related to system peak. In addition, the system is generally sized to meet peak needs, not to meet the volume of energy passing through the system. Accordingly, we will focus on system peak as the driver for embedded costs.
We also analyzed the relationship of overall system size to investment per MW of system peak. That is, do costs per MW go up or down as a function of the overall size of the utility? As might be expected, there was virtually no correlation between cost per MW and overall system size. Indeed, no economies of scale are apparent from the data. Trend lines for these data show Res of .04 and .03. High distribution costs can occur in small as well as large utilities. 

## Wereviewed the relationship ofinvestment to both system peak and to system sales. Using the five year average investment, system peak and system sales data, it becomes clear that, as one would expect, the investment in Transformers and Substations and in Lines and Feeders are highly correlated with system peak. Chart x shows data for Transformers and Substations against system peak, along with a trend-line plot.

The 

# R2 for the trendline is .78, indicating a relativelyhigh correlation between investment and system peak. Similar analysis for Lines and Feeders, also reflects an 

# R2 of.78. When compared to system sales, the 

# R2 drops slightlyto .76 and .75 for Transformers & 

## Substations and for Lines & 

## Feeders, respectively. This maybe somewhat deceptive, however, because system sales are likely more related to systempeak. In addition, the system is generally sized to meet peakneeds, notto meet the volume ofenergypassing through the system. Accordingly, we will focus on system peak as the driver for embedded costs.

We also analyzed the relationship ofoverall system size to investmentperMW ofsystem peak. That is, do costs perMW go up or down as a function ofthe overall size ofthe utility? As might be expected, there was virtuallyno correlationbetween cost perMW and overall system size. Indeed, no economies ofscale are apparent from the data. Trend lines for these data show R2

## s of .04 and .03. High distribution costs can occur in small as well as large utilities.

-5-

## Transformers and Substation Embedded Costs

Table x shows the average embedded investment in Transformers and Substations as a function of average system peak for the twenty-five highest cost utilities:

Table x

25 Highest Cost Utilities Based on Transformers and Substations/ Average Transformer and Substation Investment/ System Peak System Peak

System Peak (S/MW) (MWs) 1 Newport Electric Corporation $ 134,768 102.4 2 Consolidated Edison Company of New York, $ 96,377 9195.4 3 Chugach Electric Association, Inc. $ 82,719 392.2 4 Monongahela Power Company $ 77,301 1813 5 Potomac Electric Power Company $ 75,400 5688.6 6 Fitchburg Gas and Electric Light Company $ 67,880 86.6 7 Pennsylvania Electric Company $ 67,460 2597.6 8 PP&L, Inc. $ 66,983 6490.8 9 Utilicorp United, Inc. $ 66,599 1151.6 10 St. Joseph Light & Power Company $ 65,721 361 11 West Penn Power Company $ 64,808 3239.6 12 Alaska Electric Light and Power Company $ 62,051 62.6 13 Otter Tail Power Company $ 58,060 621.6 14 Baltimore Gas and Electric Company $ 56,847 6062 15 Upper Peninsula Power Company $ 56,708 141 16 Rockland Electric Company $ 56,660 354.8 17 PacifiCorp $ 56,627 7938 18 Niagara Mohawk Power Corporation $ 55,464 6104.2 19 Central Hudson Gas & Electric Corporation $ 55,435 923.4 20 Pacific Gas and Electric Company $ 54,955 16955.2 21 Union Electric Company $ 54,473 7866.6 22 Metropolitan Edison Company $ 54,393 2229.8 23 New Hampshire Electric Cooperative, Inc. $ 53,734 164.6 24 MDU Resources Group, Inc. $ 53,517 407 25 The Potomac Edison Company $ 53,202 2523.4

93 Company Average $ 41,798 3875.4 

## Transfonners and Substation Embedded Costs

Table x shows the average embedded investment in Transfonners and Substations as a function ofaverage system peak for the twenty-five highest costutilities:

Table x Transfonners and 25 Highest Cost Utilities Based on Substations! Average Transfonner and Substation Investment! System Peak System Peak Svstem Peak ($IM\Yl (MWs) I Newport Electric Corporation $ 134,768 102.4 2 Consolidated Edison Company ofNew York, $ 96,377 9195.4 3 Chugach Electric Association, Inc. $ 82,719 392.2 4 Monongahela Power Company $ 77,301 1813 5 Potomac Electric Power Company $ 75,400 5688.6 6 Fitchburg Gas and Electric Light Company $ 67,880 86.6 7 Pennsylvania Electric Company $ 67,460 2597.6 8 PP&L, Inc. $ 66,983 6490.8 9 Utilicorp United, Inc. $ 66,599 1151.6 10 St. Joseph Light & Power Company $ 65,721 361 II West Penn Power Company $ 64,808 3239.6 12 Alaska Electric Light and Power Company $ 62,051 62.6 13 OtterTail Power Company $ 58,060 621.6 14 Baltimore Gas and Electric Company $ 56,847 6062 15 Upper Peninsula Power Company $ 56,708 141 16 Rockland Electric Company $ 56,660 354.8 17 PacifiCorp $ 56,627 7938 18 Niagara Mohawk Power Corporation $ 55,464 6104.2 19 Central Hudson Gas & Electric Corporation $ 55,435 923.4 20 Pacific Gas and Electric Company $ 54,955 16955.2 21 Union Electric Company $ 54,473 7866.6 22 Metropolitan Edison Company $ 54,393 2229.8 23 New Hampshire Electric Cooperative, Inc. $ 53,734 164.6 24 MDU Resources Group, Inc. $ 53,517 407 25 The Potomac Edison Company $ 53,202 2523.4

93 Comoanv Avera!!e $ 41.798 3875.4



## -6-

## Conversely, Table x shows the average embedded investment in Transformers and Substations as

a function of average system peak for the twenty-five least cost utilities:

Table x Transformers 25 Lowest Cost Utilities Based on Embedded and Average Transformer and Substation Investment/ Substations/ System

System Peak System Peak Peak I Madison Gas and Electric Company $ 6,712 603.2 2 Public Service Company of New Hampshire $ 12,216 1359 3 Kingsport Power Company $ 14,780 401.4 4 Indiana Michigan Power Company $ 16,972 4267.4 5 Ohio Power Company $ 17,830 5810.8 6 Holyoke Water Power Company $ 18,717 22.6 7 Central Power and Light Company $ 20,693 4226.2 8 Kansas Gas and Electric Company $ 21,091 2174.8 9 Entergy Gulf States, Inc. $ 21,396 6389.2 10 Kentucky Utilities Company $ 21,501 3513 11 Southwestern Public Service Company $ 21,932 4059.6 12 Northwestern Public Service $ 22,177 694.4 13 Northern States Power Company (Wisconsin) $ 22,209 2795.4 14 Ohio Edison Company $ 22,739 5609.8 15 Pennsylvania Power Company $ 23,394 850.2 16 Exeter & Hampton Electric Company $ 24,461 107.2 17 Duke Energy Corporation $ 24,482 15615.4 18 Entergy Arkansas, Inc. $ 25,593 5838 19 Carolina Power & Light Company $ 26,420 9665.6 20 Cleco Utility Group Inc. $ 26,858 1598.8 21 Kentucky Power Company $ 27,138 1385.8 22 Southwestern Electric Power Company $ 27,563 4188.4 23 Appalachian Power Company $ 28,181 6495.4 24 Wheeling Power Company $ 28,367 289.2 25 Columbus Southern Power Company $ 28,538 3484.4

93 Comnanv Ave g

age S 41.798 

## On an average basis, the deviation from the average for the lowest and highest cost utilities is fairly dramatic ranging from approximately one-seventh of the average for the lowest cost utility to over three times the average for the highest cost utility. The standard deviation for the group is approximately $19,000, meaning that approximately 95% of the utilities are in the range from



## -7- 

## Conversely, Table x shows the average embedded investment in Transformers and Substations as a function ofaverage system peak for the twenty-five least cost utilities:

Table x Transfonners 25 Lowest Cost Utilities Based on Embedded and Average

Transfonner and Substation Investment/ Substationsl System System Peak System Peak Peak 1 Madison Gas and Electric Company $ 6,712 603.2 2 Public Service Company ofNewHampshire $ 12,216 1359 3 Kingsport Power Company $ 14,780 401.4 4 Indiana Michigan Power Company $ 16,972 4267.4 5 Ohio Power Company $ 17,830 5810.8 6 Holyoke Water Power Company $ 18,717 22.6 7 Central Power and Light Company $ 20,693 4226.2 8 Kansas Gas and Electric Company $ 21,091 2174.8 9 Entergy GulfStates, Inc. $ 21,396 6389.2 10 Kentucky Utilities Company $ 21,501 3513 11 Southwestern Public Service Company $ 21,932 4059.6 12 Northwestern Public Service $ 22,177 694.4 13 Northern States PowerCompany (Wisconsin) $ 22,209 2795.4 14 Ohio Edison Company $ 22,739 5609.8 15 Pennsylvania Power Company $ 23,394 850.2 16 Exeter & Hampton Electric Company $ 24,461 107.2 17 Duke Energy Corporation $ 24,482 15615.4 18 Entergy Arkansas, Inc. $ 25,593 5838 19 Carolina Power & Light Company $ 26,420 9665.6 20 Cleco Utility Group Inc. $ 26,858 1598.8 21 Kentucky Power Company $ 27,138 1385.8 22 SouthwesternElectric Power Company $ 27,563 4188.4 23 Appalachian Power Company $ 28,181 6495.4 24 Wheeling Power Company $ 28,367 289.2 25 Columbus Southern Power Company $ 28,538 3484.4



## en C:omnHnv Av"raf'e 1; 4179R


## On an average basis, the deviation from the average for the lowest and highest costutilities is fairly dramatic ranging from approximately one-seventh ofthe average for the lowest cost utility to over three times the average for the highest cost utility. The standard deviation for the group is approximately $19,000, meaning that approximately 95% ofthe utilities are in the range from

-7-

## approximately one-half the average to 1.5 times the average. This is a relatively large spread,

indicating the need to consider individual utility circumstances carefully. 

## Lines & Feeders Embedded Costs
The twenty-five highest cost utilities for Lines & Feeders are reflected in Table x:

Table x 25 Highest Cost Companies Based on Lines and Feeders/ Average Lines and Feeders Investment/ System Peak System Peak System Peak I New Hampshire Electric Cooperative, Inc. $ 732,359 165 2 Consolidated Edison Company of New York, Inc. $ 561,676 9,195 3 San Diego Gas & Electric Company $ 473,140 3,559 4 Pacific Gas and Electric Company $ 408,353 16,955 5 Utilicorp United, Inc. $ 394,455 1,152 6 Newport Electric Corporation $ 380,109 102 7 Pennsylvania Electric Company $ 373,906 2,598 8 Upper Peninsula Power Company $ 371,541 141 9 Western Massachusetts Electric Company $ 357,637 749 10 Arizona Public Service Company $ 351,932 4,747 11 Sierra Pacific Power Company $ 345,162 1,322 12 Alaska Electric Light and Power Company $ 342,116 63 13 Potomac Electric Power Company $ 333,235 5,689 14 Niagara Mohawk Power Corporation $ 313,868 6,104 15 Maine Public Service Company $ 310,351 102 16 Public Service Company of New Mexico $ 307,406 1,255 17 Metropolitan Edison Company $ 304,107 2,230 18 PP&L, Inc. $ 300,383 6,491 19 Connecticut Light and Power Company, The $ 298,669 4,457 20 Exeter & Hampton Electric Company $ 296,226 107 21 Fitchburg Gas and Electric Light Company $ 295,944 87 22 Puget Sound Energy, Inc. $ 294,115 4,378 23 PacifiCorp $ 288,250 7,938 24 Public Service Company of New Hampshire $ 271,570 1,359 25 Central Hudson Gas & Electric Corporation $ 261,193 923

93 Company Average $ 234.506 

## approximately one-halfthe average to 1.5 times the average. This is a relatively large spread, indicating the need to consider individual utility circumstances carefully. Lines & 

## Feeders Embedded Costs

The twenty-five highest cost utilities for Lines & 

## Feeders are reflected in Table x:

Table x 25 Highest Cost Companies Based on Lines and Feeders! Average Lines and Feeders Investment! Svstem Peak SvstemPeak Svstem Peak I New Hampshire Electric Cooperative, Inc. $ 732,359 165 2 Consolidated Edison Company ofNew York, Inc. $ 561,676 9,195 3 San Diego Gas & Electric Company $ 473,140 3,559 4 Pacific Gas and Electric Company $ 408,353 16,955 5 Utilicorp United, Inc. $ 394,455 1,152 6 Newport Electric Corporation $ 380,109 102 7 Pennsylvania Electric Company $ 373,906 2,598 8 UpperPeninsula Power Company $ 371,541 141 9 Western Massachusetts Electric Company $ 357,637 749 10 Arizona Public Service Company $ 351,932 4,747 II Sierra Pacific Power Company $ 345,162 1,322 12 Alaska Electric Light and Power Company $ 342,116 63 13 Potomac Electric Power Company $ 333,235 5,689 14 Niagara Mohawk Power Corporation $ 313,868 6,104 15 Maine Public Service Company $ 310,351 102 16 Public Service Company ofNewMexico $ 307,406 1,255 17 Metropolitan Edison Company $ 304,107 2,230 18 PP&L, Inc. $ 300,383 6,491 1 9 Connecticut Light and Power Company, The $ 298,669 4,457 20 Exeter & Hampton Electric Company $ 296,226 107 21 Fitchburg Gas and Electric Light Company $ 295,944 87 22 Puget Sound Energy, Inc. $ 294,115 4,378 23 PacifiCorp $ 288,250 7,938 24 Public Service Company ofNew Hampshire $ 271,570 1,359 25 Central Hudson Gas & Electric Corporation $ 261,193 923

93 CompanyAverage $ 234506



## -8-

## Conversely, Table x data for the twenty-five least cost utilities for Lines & Feeders is reflected in

Table x: Table x

25 Lowest Cost Companies Based on Lines and Feeders/ System Average

System Lines and Feeders Investment/ System Peak Peak Peak I Northern States Power Company (Wisconsin) $ 79,787 2795.4 2 Northwestern Public Service $ 88,950 694.4 3 Southwestern Public Service Company $ 91,505 4059.6 4 Ohio Power Company $ 108,150 5810.8 5 Kingsport Power Company $ 111,003 401.4 6 Indiana Michigan Power Company $ 113,119 4267.4 7 Southern Indiana Gas and Electric Company $ 127,916 1053.6 8 Kentucky Utilities Company $ 132,055 3513 9 Western Resources, Inc. $ 143,303 2717.2 10 Entergy Gulf States, Inc. $ 145,449 6389.2 11 Southwestern Electric Power Company $ 147,379 4188.4 12 Wheeling Power Company $ 148,440 289.2 13 Kansas Gas and Electric Company $ 148,880 2174.8 14 Indianapolis Power & Light Company $ 151,250 2799.6 15 The Dayton Power and Light Company $ 151,763 2966.6 16 El Paso Electric Company $ 151,943 1385.8 17 PSI Energy, Inc. $ 152,497 5380.2 18 Carolina Power & Light Company $ 156,623 9665.6 19 Florida Power Corporation $ 157,648 8183.4 20 TXU Electric Company $ 158,486 20485.4 21 Entergy Arkansas, Inc. $ 159,235 5838 22 West Texas Utilities Company $ 160,461 1489.6 23 Ohio Edison Company $ 166,622 5609.8 24 Cleveland Electric Illuminating Company, $ 171,681 4179 25 Appalachian Power Company $ 173,467 6495.4
All Companies Average $ 234,506 

## For Lines & Feeders, the deviation from the average for the lowest and highest cost utilities is also fairly dramatic, though not as great as the variability for Transformers & Substations, ranging from approximately one-third the average for the lowest cost utility to over three times the average for the highest cost utility. The standard deviation for the group is approximately $99,000, meaning that approximately 95% of the utilities are in the range from about 60% of the average to 1.4 times the average. Again, this is a relatively large spread, indicating the need to consider individual utility circumstances carefully.



## -9- 

## Conversely, Table x data for the twenty-five least costutilities for Lines & 

## Feeders is reflected in Table x: Table x Lines and Average 25 Lowest Cost Companies Based on Feeders! System System Lines and Feeders Investment! Svstem Peak Peak Peak 1 Northern States Power Company (Wisconsin) $ 79,787 2795.4 2 Northwestern Public Service $ 88,950 694.4 3 Southwestern Public Service Company $ 91,505 4059.6 4 Ohio Power Company $ 108,150 5810.8 5 Kingsport Power Company $ 111,003 401.4 6 Indiana Michigan Power Company $ 113,119 4267.4 7 Southern Indiana Gas and Electric Company $ 127,916 1053.6 8 Kentucky Utilities Company $ 132,055 3513 9 Western Resources, Inc. $ 143,303 2717.2 10 Entergy GulfStates, Inc. $ 145,449 6389.2 1 I Southwestern Electric Power Company $ 147,379 4188.4 12 Wheeling Power Company $ 148,440 289.2 13 Kansas Gas and Electric Company $ 148,880 2174.8 14 Indianapolis Power & Light Company $ 151,250 2799.6 15 The Dayton Power and Light Company $ 151,763 2966.6 16 EI Paso Electric Company $ 151,943 1385.8 17 PSI Energy, Inc. $ 152,497 5380.2 18 Carolina Power & Light Company $ 156,623 9665.6 19 Florida Power Corporation $ 157,648 8183.4 20 TXU Electric Company $ 158,486 20485.4 21 Entergy Arkansas, Inc. $ 159,235 5838 22 West Texas Utilities Company $ 160,461 1489.6 23 Ohio Edison Company $ 166,622 5609.8 24 Cleveland Electric Illuminating Company, $ 171,681 4179 25 Appalachian Power Company $ 173,467 6495.4

All Companies Average $ 234506


## ForLines & 

## Feeders, the deviation from the average for the lowest andhighest cost utilities is also fairly dramatic, though not as great as the variability for Transformers & 

## Substations, ranging from approximately one-third the average for the lowest cost utilityto over three times the average for the highest cost utility. The standard deviation for the group is approximately $99,000, meaning that approximately 95% ofthe utilities are in the range from about 60% ofthe average to 1.4 times the average. Again, this is a relatively large spread, indicating the need to consider individual utility circumstances carefully.

-9-

## Transformer & Substation Embedded O&M Costs



## In addition to investments in plant in service, we analyzed the associated O&M costs for the two categories of distribution plant. Table x shows the Lines & Feeders O&M costs per MW for the twenty-five highest cost utilities: Table x Twenty-five Highest Cost Utilities Lines & Feeders Average Based on Lines & Feeders O&M O&M System Peak I Metropolitan Edison Company $ 154,777 102 2 Carolina Power & Light Company $ 41,024 923 3 TXU Electric Company $ 35,135 1890 4 Potomac Electric Power Company $ 30,636 850 5 New Hampshire Electric Cooperative, Inc. $ 25,430 165 6 Upper Peninsula Power Company $ 18,626 141 7 Newport Electric Corporation $ 17,258 102 8 Consolidated Edison Company of New York, $ 17,089 9195 9 The United Illuminating Company $ 16,739 886 10 Niagara Mohawk Power Corporation $ 16,269 6104 11 Western Massachusetts Electric Company $ 15,097 749 12 Connecticut Light and Power Company, The $ 13,657 4457 13 Public Service Company of New Hampshire $ 13,622 1359 14 Pacific Gas and Electric Company $ 12,674 16955 15 PP&L, Inc. $ 12,200 3654 16 Monongahela Power Company $ 12,010 2230 17 Portland General Electric Company $ 11,777 2598 18 Chugach Electric Association, Inc. $ 11,703 392 19 Rockland Electric Company $ 11,528 355 20 Wisconsin Public Service Corporation $ 11,162 1645 21 West Penn Power Company $ 10,616 3240 22 Utilicorp United, Inc. $ 10,441 1152 23 Alaska Electric Light and Power Company $ 10,236 63 24 PacifiCorp $ 9,547 6491 25 Mt. Cannel Public Utility Co $ 9,112 37

93 Company Average $ 9,748 

## Transformer & Substation Embedded O&M Costs



# In addition to investments in plant in service, we analyzed the associated O&M costs for the two categories ofdistribution plant. Table x shows the Lines & Feeders O&M costs per MW for the twenty-five highest costutilities: Table x Twenty-five Highest Cost Utilities Lines & Feeders Average Based on Lines & Feeders O&M O&M Svstem Peak I Metropolitan Edison Company $ 154,777 102 2 Carolina Power & Light Company $ 41,024 923 3 TXU Electric Company $ 35,135 1890 4 Potomac Electric Power Company $ 30,636 850 5 New Hampshire Electric Cooperative, Inc. $ 25,430 165 6 Upper Peninsula Power Company $ 18,626 141 7 Newport Electric Corporation $ 17,258 102 8 Consolidated Edison Company ofNew York, $ 17,089 9195 9 The United Illuminating Company $ 16,739 886 10 Niagara Mohawk Power Corporation $ 16,269 6104 II Western Massachusetts Electric Company $ 15,097 749 12 Connecticut Light and Power Company, The $ 13,657 4457 13 Public Service Company ofNew Hampshire $ 13,622 1359 14 Pacific Gas and Electric Company $ 12,674 16955 15 PP&L, Inc. $ 12,200 3654 16 Monongahela Power Company $ 12,010 2230 17 Portland General Electric Company $ 11,777 2598 18 Chugach Electric Association, Inc. $ 11,703 392 19 Rockland Electric Company $ 11,528 355 20 Wisconsin Public Service Corporation $ 11,162 1645 21 West Penn Power Company $ 10,616 3240 22 Utilicorp United, Inc. $ 10,441 1152 23 Alaska Electric Light and Power Company $ 10,236 63 24 PacifiCorp $ 9,547 6491 25 Mt. Carmel Public Utility Co $ 9,112 37

93 Companv Average $ 9748



## -10-

## For comparison, Table x reflects the twenty-five least costly utilities in terms of Lines & Feeders

embedded O&M costs per MW of system peak:

Table x

Twenty-five Lowest Cost Utilities Lines & Feeders Average Based on Lines & Feeders O&M O&M/ MW System Peak I Maine Public Service Company $ 593 1,813 2 Pennsylvania Power Company $ 882 7,938 3 Central Hudson Gas & Electric Corporation $ 1,375 9,666 4 Southwestern Public Service Company $ 1,676 4,060 5 The Potomac Edison Company $ 1,804 10,483 6 The Empire District Electric Company $ 2,184 2,967 7 Central Power and Light Company $ 2,586 4,226 8 West Texas Utilities Company $ 2,705 1,490 9 Entergy Gulf States, Inc. $ 2,870 6,389 10 Florida Power Corporation $ 3,032 8,183 11 Northwestern Public Service $ 3,150 694 12 Southwestern Electric Power Company $ 3,468 4,188 13 El Paso Electric Company $ 3,697 1,386 14 PSI Energy, Inc. $ 3,784 5,689 15 Entergy Arkansas, Inc. $ 3, 889 5,838 16 Northern States Power Company $ 4,166 2,795 17 Western Resources, Inc. $ 4,198 2,717 18 IES Utilities Inc. $ 4,219 2,637 19 Arizona Public Service Company $ 4,237 4,747 20 Ohio Power Company $ 4,373 5,811 21 Holyoke Water Power Company $ 4,438 23 22 Indiana Michigan Power Company $ 4,448 4,267 23 Northern Indiana Public Service Company $ 4,588 2,860 24 Virginia Electric and Power Company $ 4,662 14,514 25 Kansas Gas and Electric Company $ 4,713 2,175

93 Company Average $ 9.448 

## Like plant in service amounts, the data show a high degree of variability. The unadjusted standard deviation for Lines & Feeders O&M for the 93 companies is approximately $16,500. However, this value is greatly distorted by the single highest cost utility. If this outlier is ignored, the standard deviation drops to $6,651. Still, this is approximately two-thirds the value of the average itself. In other words, the range of the adjusted standard deviation is from approximately $3,100 to just under $16,400.

-11- 

## For comparison, Table x reflects the twenty-five least costlyutilities in terms ofLines & 

## Feeders embedded O&M costs perMW ofsystem peak:

Table x Lines & Twenty-five Lowest Cost Utilities Feeders Average Based on Lines & Feeders O&M O&M/MW SvstemPeak I Maine Public Service Company $ 593 1,813 2 Pennsylvania Power Company $ 882 7,938 3 Central Hudson Gas & Electric Corporation $ 1,375 9,666 4 Southwestern Public Service Company $ 1,676 4,060 5 The Potomac Edison Company $ 1,804 10,483 6 The Empire District Electric Company $ 2,184 2,967 7 Central Power and Light Company $ 2,586 4,226 8 West Texas Utilities Company $ 2,705 1,490 9 Entergy GulfStates, Inc. $ 2,870 6,389 10 Florida Power Corporation $ 3,032 8,183 II Northwestern Public Service $ 3,150 694 12 Southwestern Electric Power Company $ 3,468 4,188 13 EI Paso Electric Company $ 3,697 1,386 14 PSI Energy, Inc. $ 3,784 5,689 15 Entergy Arkansas, Inc. $ 3,889 5,838 16 Northern States Power Company $ 4,166 2,795 17 Western Resources, Inc. $ 4,198 2,717 18 IES Utilities Inc. $ 4,219 2,637 19 Arizona Public Service Company $ 4,237 4,747 20 Ohio Power Company $ 4,373 5,811 21 Holyoke Water Power Company $ 4,438 23 22 Indiana Michigan Power Company $ 4,448 4,267 23 Northern Indiana Public Service Company $ 4,588 2,860 24 Virginia Electric and Power Company $ 4,662 14,514 25 Kansas Gas and Electric Company $ 4,713 2,175

93 Comoanv Avera!!e $ 9748


## Like plant in service amounts, the data show a high degree ofvariability. The unadjusted standard deviation for Lines & Feeders O&M for the 93 companies is approximately $16,500. However, this value is greatly distorted bythe single highest cost utility. Ifthis outlier is ignored, the standard deviation drops to $6,651. Still, this is approximatelytwo-thirds the value ofthe average itself. In

## other words, the range ofthe adjusted standard deviation is from approximately $3,100 tojustunder $16,400.

-11-

## Finally, Table x reflects embedded O&M costs per MW for Transformers & Substations:

Table x

Twenty-five Highest Cost Utilities Based on Transformers & Substations Average

System Transformers & Substations O&M O&M/MW Peak 1 Metropolitan Edison Company $ 4,447 102 2 The United Illuminating Company $ 1,748 886 3 Alaska Electric Light and Power Company $ 1,426 63 4 Upper Peninsula Power Company $ 1,200 141 5 Carolina Power & Light Company $ 957 923 6 Public Service Company of New Hampshire $ 925 1,359 7 TXU Electric Company $ 889 1,890 8 Portland General Electric Company $ 886 2,598 9 Atlantic City Electric Company $ 872 2,047 10 Consolidated Edison Company of New York, $ 856 9,195 11 Newport Electric Corporation $ 801 102 12 Western Massachusetts Electric Company $ 782 749 13 Mt. Cannel Public Utility Co $ 780 37 14 PP&L, Inc. $ 771 3,654 15 Delmarva Power & Light Company $ 735 2,887 16 Baltimore Gas and Electric Company $ 624 6,062 17 Columbus Southern Power Company $ 608 3,484 18 Connecticut Light and Power Company, The $ 603 4,457 19 Otter Tail Power Company $ 601 622 20 Wheeling Power Company $ 592 289 21 Idaho Power Company $ 585 1,884 22 Cleveland Electric Illuminating Company, $ 573 4,179 23 Holyoke Water Power Company $ 571 23 24 Chugach Electric Association, Inc. $ 564 392 25 Toledo Edison Company, The $ 563 1,158

93 Company Average 462 

## Finally, Table x reflects embedded O&M costs perMW for Transformers & Substations:

Table x Transfonners & Average Twenty-five Highest Cost Utilities Based on Substations System Transfonners & Substations O&M O&MIMW Peak 1 Metropolitan Edison Company $ 4,447 102 2 The United Illuminating Company $ 1,748 886 3 Alaska Electric Light and Power Company $ 1,426 63 4 Upper Peninsula Power Company $ 1,200 141 5 Carolina Power & Light Company $ 957 923 6 Public Service Company ofNew Hampshire $ 925 1,359 7 TXU Electric Company $ 889 1,890 8 Portland General Electric Company $ 886 2,598 9 Atlantic CityElectric Company $ 872 2,047 10 Consolidated Edison Company ofNew York, $ 856 9,195 II Newport Electric Corporation $ 801 102 12 Westem Massachusetts Electric Company $ 782 749 13 Mt. Cannel Public Utility Co $ 780 37 14 PP&L, Inc. $ 771 3,654 15 Delmarva Power & Light Company $ 735 2,887 16 Baltimore Gas and Electric Company $ 624 6,062 17 Columbus Southem Power Company $ 608 3,484 18 Connecticut Light and Power Company, The $ 603 4,457 19 OtterTail Power Company $ 601 622 20 Wheeling Power Company $ 592 289 21 Idaho Power Company $ 585 1,884 22 Cleveland Electric Illuminating Company, $ 573 4,179 23 Holyoke Water Power Company $ 571 23 24 Chugach Electric Association, Inc. $ 564 392 25 Toledo Edison Company, The $ 563 1,158

93 Company Avera"e $ 462



## -12-

## By comparison, Table x reflects similar data for the twenty-five least costly utilities:

Table x
Transformer S & Average Twenty-five Lowestt Cost Utilities Based on Substations System Transformers & Substations O&M O&M/ MW Peak 1 Maine Public Service Company 2 Pennsylvania Power Company 3 Central Hudson Gas & Electric Corporation 4 Indianapolis Power & Light Company 5 The Empire District Electric Company 6 Duke Energy Corporation 7 Niagara Mohawk Power Corporation 8 Southwestern Public Service Company 9 The Potomac Edison Company $ 33 1,813 $ 44 7,938 $ 53 9,666 $ 59 2,800 $ 65 2,967 $ 67 15,615 $ 69 6,104 $ 74 4,060 $ 92 10,483 10 Northern States Power Company (Wisconsin) $ 96 2,795 11 Southwestern Electric Power Company $ 4,188 12 Southern Indiana Gas and Electric Company $ 1,054 13 Oklahoma Gas and Electric Company $ 5,088 14 Central Power and Light Company $ 4,226 15 Florida Power Corporation $ 8,183 16 New Hampshire Electric Cooperative, Inc. 17 Pacific Gas and Electric Company 18 Western Resources, Inc. 19 Union Electric Company 20 Puget Sound Energy, Inc. 21 Kansas Gas and Electric Company 22 Kentucky Utilities Company 23 Wisconsin Power and Light Company 24 West Texas Utilities Company 25 Arizona Public Service Company $ 165 $ 16,955 $ 2,717 $ 7,867 $ 4,378 $ 2,175 $ 3,513 $ 2,278 $ 1,490 $ 4,747

93 Company Average $ 

## Again, the data show a high degree of variability. The unadjusted standard deviation for Transformers & Substations O&M for the 93 companies is $511. However, as in the case of Lines & Feeders, this value is greatly distorted by the single highest cost utility. If this outlier is ignored, the standard deviation drops to $299, approximately two-thirds the value of the average itself. Thus, the range of the adjusted standard deviation is from $162 to $761. These large

-13- Bycomparison, Table x reflects similar data for the twenty-five least costlyutilities:

Table x Transfonner s& Average Twenty-five Lowestt Cost Utilities Based on Substations System Transfonners & Substations O&M O&M/MW Peak I Maine Public Service Company $ 33 1,813 2 Pennsylvania Power Company $ 44 7,938 3 Central Hudson Gas & Electric Corporation $ 53 9,666 4 Indianapolis Power & Light Company $ 59 2,800 5 The Empire District Electric Company $ 65 2,967 6 Duke Energy Corporation $ 67 15,615 7 Niagara Mohawk Power Corporation $ 69 6,104 8 Southwestern Public Service Company $ 74 4,060 9 The Potomac Edison Company $ 92 10,483 10 Northern States Power Company (Wisconsin) $ 96 2,795 11 Southwestern Electric Power Company $ 4,188 12 Southern Indiana Gas and Electric Company $ 1,054 13 Oklahoma Gas and Electric Company $ 5,088 14 Central Power and Light Company $ 4,226 15 Florida Power Corporation $ 8,183 16 NewHampshire Electric Cooperative, Inc. $ 165 17 Pacific Gas and Electric Company $ 16,955 18 Western Resources, Inc. $ 2,717 19 Union Electric Company $ 7,867 20 Puget Sound Energy, Inc. $ 4,378 21 Kansas Gas and Electric Company $ 2,175 22 Kentucky Utilities Company $ 3,513 23 Wisconsin Power and Light Company $ 2,278 24 West Texas Utilities Company $ 1,490 25 Arizona Public Service Company $ 4,747

93 Company Average $ 

## Again, the data show a high degree ofvariability. The unadjusted standard deviation for Transformers & Substations O&M for the 93 companies is $511. However, as inthe case of Lines & 

## Feeders, this value is greatly distorted bythe single highest costutility. Ifthis outlier is ignored, the standard deviation drops to $299, approximately two-thirds the value ofthe average itself. Thus, the range ofthe adjusted standard deviation is from $162 to $761. These large

-13-

## standard deviations means that there are no broad "rules of thumb" that can be drawn from

embedded costs.

One conclusion that can be drawn from the data is that the embedded costs of the distribution system are much more heavily weighted toward Lines & Feeders than Transformers & Substations - the former being roughly six times higher than the latter on a per MW peak basis. This is significant for two reasons. First, the much higher cost per MW increases the likelihood that any given DR option may be a preferred alternative to a Line & Feeder system upgrade. Second, Lines & Feeders carry lower loads on an individual basis than do Transformers & Substations and so may be more amenable to alternatives involving very small DG options. On the other hand, DG alternatives for Lines & Feeders will generally involve placement at or near the loads themselves, while DG alternatives to Transformers & Substation improvements generally involve placement of DG at the substation itself, which is generally simpler. Of course, many DR alternatives, such as load management and energy efficiency options are, by their nature, at the site of the load anyway, suggesting that they would be a good fit for consideration as alternatives to Lines & Feeders improvements.
More importantly, for the most expensive of these utilities, average cost per MW for Lines & Feeders is as high as the current installed cost many DG options, including wind and microturbines, strongly suggesting that DG options would have competed well historically, had these technologies been available. Indeed, because all these data represent average costs, there are likely many parts of the systems of these utilities that have even higher costs per MW. 

## Marginal Transformer & Substation Costs
Embedded costs are only the beginning of the story and provide a useful but limited reference point for understanding distribution costs on a going-forward basis. Of much more importance are the marginal costs incurred by utilities as they expand and improve their existing systems. To assess the magnitude of marginal costs for Transformers & Substations and Lines & Feeders, we applied the same cost classifications outlined above to the additions to plant in service and to the annual changes in O&M expenses. One anomaly present in this analysis that is not a problem in the embedded cost analysis is that eleven of the utilities experienced negative load growth during the analysis period, resulting in a slight, though not significant, reduction in the 93 company averages. For purposes of the twenty-five least costly groupings, these utilities have been ignored. It should be noted that these negative growth utilities nonetheless had over $43 million



## -14- 

## standard deviations means that there are no broad "rules ofthumb" that canbe drawn from embedded costs.

One conclusion that canbe drawn from the data is that the embedded costs ofthe distribution system are much more heavily weighted toward Lines & Feeders than Transformers & Substations

- the former being roughly six times higher than the latter on a perMWpeakbasis. This is significant for two reasons. First, the much higher costperMW increases the likelihood that any given DRoption maybe a preferred alternative to a Line & Feeder system upgrade. Second, Lines & Feeders carry lower loads on an individual basis than do Transformers & Substations and so maybe more amenable to alternatives involving very small DG options. On the otherhand, DG alternatives for Lines & Feeders will generally involve placement at ornear the loads themselves, while DG alternatives to Transformers & Substation improvements generally involve placement ofDG at the substation itself, which is generally simpler. Ofcourse, many DR alternatives, such as load management and energy efficiency options are, bytheir nature, atthe site ofthe load anyway, suggesting that theywould be a good fit for consideration
as alternatives to Lines & Feeders improvements.

More importantly, for the most expensive ofthese utilities, average costperMWfor Lines & Feeders is as high as the current installed costmanyDG options, including wind and microturbines, strongly suggesting that DG options wouldhave competed well historically, had these technologies been available. Indeed, because all these data represent average costs, there
are likelymanyparts ofthe systems ofthese utilities that have even higher costs perMW. Marginal Transformer & Substation Costs

Embedded costs are onlythe beginning ofthe story andprovide a useful but limitedreference· point for understanding distribution costs on a going-forward basis. Ofmuch more importance
are the marginal costs incurredbyutilities as they expand and improve their existing systems. To
assess the magnitude ofmarginal costs for Transformers & Substations and Lines & Feeders, we applied the same cost classifications outlined above to the additions to plant in service and to the annual changes in O&M expenses. One anomalypresent in this analysis that is not a problem in the embedded cost analysis is that eleven ofthe utilities experienced negative load growth during the analysis period, resulting in a slight, though not significant, reduction in the 93 company averages. For purposes ofthe twenty-five least costly groupings, these utilities have been ignored. It 

## should be noted that these negative growth utilities nonetheless had over $43 million

-14-

# EofnewinvestmentinLines&FeedersandTransformers&Substations,demonstratingthefactthat,whendisaggregated,anyutilitycanstillfacegrowthconstraintsandotherinvestmentdemandswithinitssystem,evenwhentheoverallcompanydemandisnotgrowing.ThisuncertaintyisreflectedinthegreatervariabilityofinvestmentperMWgrowth.ChartxreflectstheLines&Feedersmarginalinvestmentplottedagainstgrowthinsystempeak.1995-19995Yr.AverageUnesandFeedersGrawthasaFunctionofAverageSystemPeakGlDwth-Linear(5Yr.AverageLinesandFeedersAdditions)Here,theR2forthetrendlineisonly.63,asopposedto.78forembeddedcosts.Nonetheless,therelationshipbetweenloadgrowthandmarginalinvestmentinLines&Feedersisapositiveone,ascanbeclearlyseenjustlookingatthespreadofdatapointsonthechart.AcomparableanalysistestingforarelationshipwithgrowthinsystemsalesyieldsanR2ofonlyapproximately.26,indicatingthatmarginalLines&Feedersinvestmentcosthaslittlerelationshiptototalsystemsalesgrowth.SimilarresultswerefoundforTransformers&Substations.-15-

## Marginal Cost of Transformers & Substations Plant

Table x shows the marginal cost per MW of system peak growth for the twenty-five highest cost utilities: Table x
25 Highest Cost Utilities Transformers & Transformers & Substation Growth Substations/ Peak

Per MW Growth Peak Growth Growth 1 The Potomac Edison Company $ 3,579,279 2 2 Chugach Electric Association, Inc. $ 398,062 9 3 Portland General Electric Company $ 374,748 42 4 New Hampshire Electric Cooperative, Inc. $ 338,568 1 5 Potomac Electric Power Company $ 327,996 53 6 Baltimore Gas and Electric Company $ 298,396 69 7 PacifiCorp $ 274,883 98 8 Pennsylvania Electric Company $ 268,644 20 9 Fitchburg Gas and Electric Light Company $ 256,340 3 10 PP&L, Inc. $ 220,950 57 11 Concord Electric Company $ 219,644 2 12 Public Service Company of New Mexico $ 201,792 20 13 Rockland Electric Company $ 183,676 4 14 Upper Peninsula Power Company $ 179,204 1 15 Otter Tail Power Company $ 160,001 10 16 Central Hudson Gas & Electric Corporation $ 151,096 24 17 West Penn Power Company $ 125,653 52 18 Consolidated Edison Company of New York, $ 123,321 241 19 St. Joseph Light & Power Company $ 121,356 14 20 Pacific Gas and Electric Company $ 113,418 668 21 Consumers Energy Company $ 111,143 192 22 San Diego Gas & Electric Company $ 109,924 62 23 IES Utilities Inc. $ 104,823 41 24 The Detroit Edison Company $ 101,318 267 25 Western Massachusetts Electric Company $ 99,468 7
82 Company Average (excludes companies with negative growth) $135,760 81 Company Average (excludes highest outlier) $93,766 

## Marginal Cost ofTransformers 

## & Substations Plant

Table x shows the marginal cost per MW ofsystem peak growth for the twenty-five highest cost utilities: Table x Transfonners 25 Highest Cost Utilities & Transfonners & Substation Growth Substations! Peak Per MW Growth Peak Growth Growth I The Potomac Edison Company $ 3,579,279 2 2 Chugach Electric Association, Inc. $ 398,062 9 3 Portland General Electric Company $ 374,748 42 4 New Hampshire Electric Cooperative, Inc. $ 338,568 5 Potomac Electric Power Company $ 327,996 53 6 Baltimore Gas and Electric Company $ 298,396 69 7 PacifiCorp $ 274,883 98 8 Pennsylvania Electric Company $ 268,644 20 9 Fitchburg Gas and Electric Light Company $ 256,340 3 10 PP&L, Inc. $ 220,950 57 II Concord Electric Company $ 219,644 2 12 Public Service Company ofNew Mexico $ 201,792 20 13 Rockland Electric Company $ 183,676 4 14 Upper Peninsula Power Company $ 179,204 15 OtterTail Power Company $ 160,001 10 16 Central Hudson Gas & Electric Corporation $ 151,096 24 17 West Penn Power Company $ 125,653 52 18 Consolidated Edison Company ofNew York, $ 123,321 241 19 St. Joseph Light & Power Company $ 121,356 14 20 Pacific Gas and Electric Company $ 113,418 668 21 Consumers Energy Company $ 111,143 192 22 San Diego Gas & Electric Company $ 109,924 62 23 IES Utilities Inc. $ 104,823 41 24 The Detroit Edison Company $ 101,318 267 25 Western Massachusetts Electric Company $ 99,468 7

82 Company Average (excludes companies with negative growth) $135,760 81 Companv Avera"e (excludes hi"hest outlier) $93766



# -16-

## Similarly, Table x reflects the Transformer & Substation marginal costs per MW of system peak

growth for the twenty-five least costly utilities:

Table x

25 Lowest Cost Utilities Transformers & Average Transformers & Substation Growth Substations/ Peak

Per MW Growth Peak Growth Growth I Madison Gas and Electric Company $ 1,310 17 2 Ohio Edison Company $ 6,050 140 3 Public Service Company of New Hampshire $ 7,885 31 4 Pennsylvania Power Company $ 11,821 32 5 The United Illuminating Company $ 14,367 28 6 Kansas Gas and Electric Company $ 17,565 111 7 Entergy Arkansas, Inc. $ 18,758 453 8 Cleveland Electric Illuminating Company, The $ 21,978 139 9 Commonwealth Edison Company $ 22,789 663 10 Entergy Gulf States, Inc. $ 22,966 228 11 Exeter & Hampton Electric Company $ 24,356 3 12 Western Resources, Inc. $ 24,969 114 13 TXU Electric Company $ 27,628 744 14 Toledo Edison Company, The $ 28,895 93 15 Cleco Utility Group Inc. $ 29,103 91 16 Connecticut Light and Power Company, The $ 30,571 138 17 Utilicorp United, Inc. $ 31,806 67 18 Southwestern Electric Power Company $ 31,881 187 19 Atlantic City Electric Company $ 32,885 87 20 Central Power and Light Company $ 34,293 144 21 Kentucky Utilities Company $ 35,756 127 22 Oklahoma Gas and Electric Company $ 36,601 169 23 Delmarva Power & Light Company $ 38,832 144 24 MDU Resources Group, Inc. $ 40,744 10 25 Wisconsin Electric Power Company $ 42,186 205, 82 Company Average (excludes companies with negative growth) $135,760 81 Company Average (excludes highest $93,766 

## Analysis of this information excludes companies with negative growth in system peak to avoid distorting the marginal cost information. This eliminates eleven utilities. For the remaining 82 utilities, the data exhibit a standard deviation of approximately $390,000, a value which exceeds the unadjusted average by a factor of about three times. Elimination of the highest cost utility as

-17- Similarly, Table x reflects the Transformer & 

## Substation marginal costs perMW ofsystempeak growth for the twenty-five least costly utilities:

Table x Transfonners 25 Lowest Cost Utilities & Average Transfonners & Substation Growth Substations/ Peak PerMW Growth Peak Growth Growth I Madison Gas and Electric Company $ 2 Ohio Edison Company $ 3 Public Service Company ofNew Hampshire $ 4 Pennsylvania Power Company $ 5 The United Illuminating Company $ 6 Kansas Gas and Electric Company $ 7 Entergy Arkansas, Inc. $ 8 Cleveland Electric Illuminating Company, The $ 9 Commonwealth Edison Company $ 10 Entergy GulfStates, Inc. $ II Exeter & Hampton Elechic Company $ 12 Western Resources, Inc. $ 13 TXU Electric Company $ 14 Toledo Edison Company, The $ 15 Cleco Utility Group Inc. $ 16 Connecticut Light and Power Company, The $ 17 Utilicorp United, Inc. $ 18 Southwestern Electric Power Company $ 19 Atlantic City Electric Company $ 20 Central Power and Light Company $ 21 Kentucky Utilities Company $ 22 Oklahoma Gas and Electric Company $ 23 Delmarva Power & Light Company $ 24 MDU Resources Group, Inc. $ 25 Wisconsin Electric Power Company $

82 Company Average (excludes companies with negative growth) 81 Company Average (excludes highest 1,310 6,050 7,885 11,821 14,367 17,565 18,758 21,978 22,789 22,966 24,356 24,969 27,628 28,895 29,103 30,571 31,806 31,881 32,885 34,293 35,756 36,601 38,832 40,744 42,186

$135,760 $93766 17 140 31 32 28 III 453 139 663 228

3 114 744

93 91 138 67 187 87 144 127 169 144 10 205



## Analysis ofthis information excludes companies with negative growth in system peakto avoid distorting the marginal cost information. This eliminates elevenutilities. Forthe remaining 82 utilities, the data exhibit a standard deviation ofapproximately $390,000, a value which exceeds the unadjusted average bya factor ofabout three times. Elimination ofthe highest costutility as

-17-

## an outlier in the data reveals a standard deviation of $88,490 against an average of $93,766. This

indicates a very high spread in the values with little or no clustering around the average, reinforcing the need for a case by case analysis.
Marginal Lines & Feeders Plant

## Table x reflects the Lines & Feeders plant growth per MW of system peak growth for the twentyfive highest cost utilities: Table x
25 Highest Cost Utilities Lines and Feeders/ Peak Peak Lines and Feeders Growth Per MW Growth Growth Growth I The Potomac Edison Company $ 19,483,006 2 2 New Hampshire Electric Cooperative, Inc. $ 7,130,319 1 3 Pennsylvania Electric Company $ 2,815,919 20 4 Upper Peninsula Power Company $ 1,902,999 1 5 PP&L, Inc. $ 1,457,472 57 6 Portland General Electric Company $ 1,429,544 42 7 Baltimore Gas and Electric Company $ 1,413,312 69 8 PacifiCorp $ 1,393,458 98 9 Potomac Electric Power Company $ 1,384,774 53 10 San Diego Gas & Electric Company $ 1,383,758 62 11 Western Massachusetts Electric Company $ 1,348,138 7 12 Public Service Company of New Mexico $ 1,192,783 20 13 Concord Electric Company $ 1,088,347 2 14 Consolidated Edison Company of New York, $ 1,071,224 241 15 Arizona Public Service Company $ 942,846 137 16 Newport Electric Corporation $ 915,530 2 17 Public Service Company of New Hampshire $ 853,317 31 18 Carolina Power & Light Company $ 780,526 140 19 IES Utilities Inc. $ 776,525 41 20 Interstate Power Company $ 775,375 17 21 Fitchburg Gas and Electric Light Company $ 762,072 3 22 Duke Energy Corporation $ 731,974 223 23 West Penn Power Company $ 693,374 52 24 Ohio Power Company $ 693,126 54 25 Exeter & Hampton Electric Company $ 691,781 3

82 Company Average (excludes negative $ 894,998 81 Company Adjusted Average (excludes $ 668,315



## -18- an outlier in the data reveals a standard deviation of$88,490 against an average of$93,766. This indicates a very high spread in the values with little orno clustering around the average, reinforcing the need for a case bycase analysis.
Marginal Lines & 

## Feeders Plant

Table x reflects the Lines & 

## Feeders plant growth per MW ofsystem peak growth for the twentyfive highest cost utilities: Table x Lines and 25 Highest Cost Utilities Feeders! Peak Peak Lines and Feeders Growth Per MW Growth Growth Growth I The Potomac Edison Company $ 19,483,006 2 2 New Hampshire Electric Cooperative, Inc. $ 7,130,319 3 Pennsylvania Electric Company $ 2,815,919 20 4 UpperPeninsula Power Company $ 1,902,999 5 PP&L, Inc. $ 1,457,472 57 6 Portland General Electric Company $ 1,429,544 42 7 Baltimore Gas and Electric Company $ 1,413,312 69 8 PacifiCorp $ 1,393,458 98 9 Potomac Electric Power Company $ 1,384,774 53 10 San Diego Gas & Electric Company $ 1,383,758 62 II Western Massachusetts Electric Company $ 1,348,138 7 12 Public Service Company ofNew Mexico $ 1,192,783 20 13 Concord Electric Company $ 1,088,347 2 14 Consolidated Edison Company ofNew York, $ 1,071,224 241 15 Arizona Public Service Company $ 942,846 137 16 Newport Electric Corporation $ 915,530 2 17 Public Service Company ofNew Hampshire $ 853,317 31 18 Carolina Power & Light Company $ 780,526 140 19 lES Utilities Inc. $ 776,525 41 20 Interstate Power Company $ 775,375 17 21 Fitchburg Gas and Electric Light Company $ 762,072 3 22 Duke Energy Corporation $ 731,974 223 23 West Penn Power Company $ 693,374 52 24 Ohio Power Company $ 693,126 54 25 Exeter & Hampton Electric Company $ 691,781 3

82 Company Average (excludes negative $ 894,998 81 CompanvAdiusted Average (excludes $ 668,315



## -18-

## By comparison, Table x reflects the Lines & Feeders plant growth per MW of system peak

growth for the twenty-five lowest cost utilities:

Table x Lines and 25 Lowest Cost Utilities Feeders/ Peak Peak Lines and Feeders Growth Per MW Growth Growth Growth 1 Entergy Arkansas, Inc. $ 108,886 453 2 Kansas Gas and Electric Company $ 155,231 111 3 Toledo Edison Company, The $ 163,059 93 4 Western Resources, Inc. $ 184,459 114 5 Cleveland Electric Illuminating Company, The $ 186,553 139 6 Southwestern Public Service Company $ 186,684 122 7 Southwestern Electric Power Company $ 205,062 187 8 Entergy Gulf States, Inc. $ 216,134 228 9 Kentucky Utilities Company $ 221,642 127 10 Delmarva Power & Light Company $ 228,399 144 11 Southern Indiana Gas and Electric Company $ 243,760 30 12 Pennsylvania Power Company $ 244,399 32 13 St. Joseph Light & Power Company $ 259,617 14 14 Oklahoma Gas and Electric Company $ 263,218 169 15 Atlantic City Electric Company $ 264,515 87 16 Black Hills Corporation $ 267,439 16 17 Cleco Utility Group Inc. $ 272,193 91 18 TXU Electric Company $ 283,040 744 19 Indiana Michigan Power Company $ 285,252 106 20 Florida Power Corporation $ 288,134 273 21 West Texas Utilities Company $ 291,647 49 22 Ohio Edison Company $ 313,524 140 23 Northwestern Public Service $ 318,356 13 24 Metropolitan Edison Company $ 322,170 90 25 Kansas City Power & Light Company $ 337,704 107

82 Company Average (excludes negative $ 894,998 81 Company Adjusted Average (excludes $ 668,315 

## Data for Lines & Feeders marginal costs have a standard deviation of over $2 million per MW on an unadjusted basis. However, excluding the single highest outlier once again lowers the standard deviation significantly to approximately $848,000, some 27% higher than the adjusted average. This still indicates a very wide spread in values for the data, with data spread all along the range from $108,000 per MW to $7.1 million per MW. Careful consideration of individual utility circumstances is a must! 

## -19- Bycomparison, Table x reflects the Lines & 

## Feeders plant growth perMW ofsystem peak growth for the twenty-five lowest cost utilities:

Table x Lines and 25 Lowest Cost Utilities 

### Feedersl Peak Peak Lines and Feeders Growth PerMW Growth Growth Growth I Entergy Arkansas, Inc. $ 108,886 453 2 Kansas Gas and Electric Company $ 155,231 III 3 Toledo Edison Company, The $ 163,059 93 4 Westem Resources, Inc. $ 184,459 114 5 Cleveland Electric Illuminating Company, The $ 186,553 139 6 Southwestem Public Service Company $ 186,684 122 7 Southwestem Electric Power Company $ 205,062 187 8 Entergy GulfStates, Inc. $ 216,134 228 9 Kentucky Utilities Company $ 221,642 127 10 Delmarva Power & Light Company $ 228,399 144 II Southem Indiana Gas and Electric Company $ 243,760 30 12 Pennsylvania Power Company $ 244,399 32 13 St. Joseph Light & Power Company $ 259,617 14 14 Oklahoma Gas and Electric Company $ 263,218 169 15 Atlantic CityElectric Company $ 264,515 87 16 BlackHills Corporation $ 267,439 16 17 Cleco Utility Group Inc. $ 272,193 91 18 TXU Electric Company $ 283,040 744 19 Indiana Michigan Power Company $ 285,252 106 20 Florida Power Corporation $ 288,134 273 21 West Texas Utilities Company $ 291,647 49 22 Ohio Edison Company $ 313,524 140 23 Northwestem Public Service $ 318,356 13 24 Metropolitan Edison Company $ 322,170 90 25 Kansas CityPower & Light Company $ 337,704 107

82 Company Average (excludes negative $ 894,998 81 Company Adiusted Average (excludes $ 668315


## Data for Lines & 

## Feeders marginal costs have a standard deviation ofover $2 million perMW on an unadjusted basis. However, excluding the single highest outlier once again lowers the standard deviation significantly to approximately $848,000, some 27% higher than the adjusted average. This still indicates a very wide spread in values for the data, with data spread all along the range from $108,000 perMW to $7.1 million perMW. Careful consideration ofindividual utility circumstances is a must!
-19-

### 0

0

0MarginalO&MCostsWereviewedthedataformarginalO&Mcostsusingthesamemethodsappliedtomarginalinvestmentsinplantinservice.Thesedataexhibitextremevariability,includinglargenegativevalues.ThisappearstobetheresultofcostreductionprogramsandtheperiodicityofO&Mactivities.Inaddition,thereisnoclearbasisfromtheFERCForm1formattotiemarginalO&Mexpensestomarginalplantinvestments.Asaresult,wehavenotutilizedthemarginalO&Mexpensesaspartofouranalysis.Instead,wehaveusedtheembeddedO&Mcostinformationpreviouslydiscussed.Thisprobablytendstoslightlyunderstatethesecosts.GeneralDiscussionofMarginalCostDataMarginalInvestmentLessEmbeddedInvestment2500000200000015000001000000500000o-500000-1000000-1500000-2000000Aswouldbeexpected,themarginalcostsformostutilities(81outofthe93)exceeded theirembeddedcosts.ThedifferentialsforthetotalofLines&FeedersandTransformers&SubstationsarereflectedinChartx.Aboutone-thirdoftheutilitiesarespreadfairlyevenly-20-

## between about $200,000 per MW and $600,000 per MW. This difference between embedded

cost and marginal cost is the principal source of risk for escalating distribution costs, and higher rates, looking forward.
Recent experience in California, Chicago and other urban areas suggest that there is increasing pressure on the distribution infrastructure, especially during peak summer periods. Continued growth will only stress the system further, requiring further investment in the distribution system to alleviate these problems. Even in the analysis period used here, 1995-1999, the 93 utilities reviewed invested over $5.4 billion in their distribution systems. As this number increases over time, the differential between marginal cost and embedded is only likely to widen. The impact on the customer will be a sharply steepening cost curve. Luckily, is it the very parts of the system that are under stress that represent the target opportunities for DG and other DR solutions. System expansions involving brand new construction, new housing subdivisions for examples, cannot generally be deferred with DG or DR solutions. Transformers & Substations and Lines & Feeders that are at or nearing their capacity do represent such opportunities.
The data we have reviewed here exhibit high variability from utility to utility. It should be pointed out that these data are averages for each utility, both in terms of years and, more importantly, of all projects for each year for each utility. Within each utility, there are literally dozens of projects per year involving a wide range of different expenditures. If each utility experiences the kind of variability in costs from project to project as the we have seen from utility to utility, it suggest that many projects may have extremely low costs per MW, while others have extremely large costs per MW. Examination of individual utility data confirms that this is exactly the case. 

## A review of the data for Commonwealth Edison shows high variability in the cost of 963 Lines & Feeders projects considered in 1999. Area specific costs exhibited a standard deviation equal to 94% of the average. Using the standard deviation to establish a range yields a high case equal to 194% of the average and a low case equal to 6% of the average. Similarly, for 214 Transformer & Substation projects, the data showed a standard deviation equal to 76% of the average, yielding a range from 176% of average down to 24% of average. 

## We used these ranges to bound the upper and lower costs for each category for selected utilities and then computed a levelized cost per MW for each category. For this calculation we assumed a thirty year investment life, a 10% cost of capital, a 10% discount rate and a 3% O&M escalation
-21- 

## between about $200,000 perMW and $600,000 perMW. This difference between embedded cost andmarginal cost is the principal source ofrisk for escalating distribution costs, and higher rates, looking forward.

Recent experience in California, Chicago and otherurban areas suggest that there is increasing pressure onthe distribution infrastructure, especially during peak summerperiods. Continued growth will only stress the system further, requiring further investment in the distribution system to alleviate these problems. Even in the analysis periodusedhere, 1995-1999, the 93 utilities reviewed invested over $5.4 billion in their distribution systems. As this number increases over time, the differential betweenmarginal cost and embedded is only likelyto widen. The impact
onthe customer will be a sharply steepening cost curve. Luckily, is it the veryparts ofthe system that are under stress that represent the target opportunities for DG and other DR solutions. System expansions involving brand new construction, new housing subdivisions for examples, cannot generallybe deferred with DG or DR solutions. Transformers & Substations and Lines & Feeders that are at ornearing their capacity do represent such opportunities.

The data we have reviewed here exhibithigh variability from utilityto utility. It 

## should be pointed out that these data are averages for each utility, both in terms ofyears and, more importantly, ofall projects for each year for each utility. Within each utility, there are literally dozens ofprojects peryear involving a wide range ofdifferent expenditures. Ifeach utility experiences the kind ofvariability in costs from project to project as the we have seen from utilityto utility, it suggest that manyprojects mayhave extremely low costs perMW, while others have extremely large costs perMW. Examination ofindividual utility data confirms that this is exactlythe case.

A review ofthe data for Commonwealth Edison shows high variability in the cost of963 Lines & Feeders projects considered in 1999. Area specific costs exhibited a standard deviation equal to 94% ofthe average. Using the standard deviation to establish a range yields a high case equal to 194% ofthe average and a low case equal to 6% ofthe average. Similarly, for 214 Transformer & Substationprojects, the data showed a standard deviation equal to 76% ofthe average, yielding a range from 176% ofaverage down to 24% ofaverage.

We used these ranges to boundthe upper and lower costs for each category for selectedutilities and then computed a levelized cost perMW for each category. Forthis calculation we assumed a thirty year investment life, a 10% cost ofcapital, a 10% discount rate and a 3% O&M escalation

-21-

## rate. With this information, a revenue requirement stream is calculated and present values for

each year are derived. Finally, a deferral value was calculated which is simply the sum of the present values for each year for the number of years in question. Using this method, we derived the value of deferring projects for a number of years ranging from 1 to 30. This method allows us to bracket the potential costs for any of the utilities within our data set.
For example, Table x is a summary of low and high case values for Baltimore Gas and Electric Company, which appears on the highest twenty-five cost utilities for both Transformers & Substations and Lines & Feeders. Not surprisingly, this analysis suggests that Baltimore Gas and Electric may have significant opportunities for utilizing DG in a cost-effective manner.



## Table x Value of Project Deferring DR ($/k

Baltimore Gas and Electric Comnan Transformers & Substations Lines & Feeders

$ 89,007 $ 2,737,616 $ $ 525,463 Case Case Deferral Years Low Low $9 $ 64 $16 $ 337 $ 18 $124 $32 $651 $ 25 $177 $46 $929 4 $ 32 $224 $58 $ 1,176 5 $ 38 $265 $70 $ 1,394 

### 6 $ 44 $ 302 $80 $ 1,588 7 $ 48 $335 $89 $ 1,759 8 $ 53 $363 $98 $ 1,910 9 $ 56 $389 $ 105 $ 2,043 10 $ 60 $411 $112 $ 2,160 11 $ 63 $430 $118 $ 2,264 12 $ 65 $448 $124 $ 2,355 13 $ 67 $463 $129 $ 2,435 14 

### $ 69 $476 $134 $ 2,506 $7 $488 $138 $ 2,568 16 $ 73 $498 $142 $ 2,622 17 $ 74 $507 $145 $ 2,670 18 $ 75 $515 $149 $2,711 19 $ 77 $522 $152 $ 2,747 20 $ 77 $528 $154 $ 2,779 21 $ 78 $533 $157 $ 2,806 $ 79 $537 $159 $ 2,830 23 $ 80 $541 $161 $ 2,851 24 $ 80 $544 $163 $ 2,868 25 $8 $547 $164 $ 2,884 

### 26 $8 $549 

### $166 $ 2,897 27 $ 82 $552 $167 $ 2,908 28 $ 82 $553 $168 $ 2,918 29 $ 82 $555 $169 $ 2,926 30 $ 82 $556 $170 $ 2,933


## -22- 

## rate. With this information, a revenue requirement stream is calculated and present values for each year are derived. Finally, a deferral value was calculated which is simply the sum ofthe present values for each year for the number ofyears in question. Using this method, we derived the value ofdeferringprojects for a number ofyears ranging from 1to 30. This method allows
us to bracketthe potential costs for any ofthe utilities within our data set.

For example, Table x is a summary oflow and high case values for Baltimore Gas and Electric Company, which appears onthe highest twenty-five costutilities for both Transformers & 

## Substations and Lines & 

## Feeders. Not surprisingly, this analysis suggests that Baltimore Gas and Electric mayhave significant opportunities for utilizing DG in a cost-effective manner.

Table x Value ofProiect Defen-ing DR ($/kW) Company Ba[timore Gas and Electric Company Transfonners &

Substations Lines & Feeders Margina[ Cost ($IMW) $1 $ 525 463 $ 89 007 I $ 2 737 616 Case Case Deferra[ Years Low High Low High 1 $9 $ 64 $[6 $ 337 2 $ 18 $124 $32 $65[ 3 $ 25 $177 $46 $929 4 $ 32 $224 $58 $ [ 176 5 $ 38 $265 $70 $ [ 394 6 $ 44 $ 302 $80 $ [ 588 7 $ 48 $335 $89 $ 1 759 

### 8 $ 53 $363 $98 $ 1 910 9 $ 56 $389 $ 105 $ 2 043 10 $ 60 $4[1 $112 $ 2.160 11 $ 63 $430 $118 $ 2 264 12 $ 65 $448 $124 $ 2 355 

### 13 $ 67 $463 $129 $ 2 435 14 $ 69 $476 $134 $ 2 506 15 $ 71 $488 $138 $ 2 568 16 $ 73 $498 $[42 $ 2.622 17 $ 74 $507 $145 $ 2 670 

### [8 $ 75 $515 $149 $ 2 711 19 $77 $522 $152 $ 2 747 20 $77 $528 $154 $ 2 779 21 $ 78 $533 $157 $ 2 806 22 $ 79 $537 $159 $ 2 830 23 $ 80 $541 $[61 $ 2,851 24 $ 80 $544 $163 $ 2 868 25 $ 81 $547 $164 $ 2,884 26 $ 81 $549 $166 $ 2,897 27 $ 82 $552 $167 $ 2 908 28 $ 82 $553 $[68 $ 2 918 29 $ 82 $555 $169 $ 2 926 30 $ 82 $556 $170 $ 2 933


## -22-

## The values reflected here represent the maximum amount the utility should be willing to pay, on

a per-KW basis, to invest in a DR alternative to a given "wires and transformers" project. These values represent possibilities within a very reasonable range of costs

. Individual projects may exhibit values that exceed those shown here, depending upon the circumstances.
Because of the high variation from average cost that each utility might see on its own system, it is not just the high cost utilities that might effectively utilize DR. Table x reflects the same summary information for Southwestern Electric Power Company, a company appearing on both of the lowest cost tables for Transformers & Substations and Lines & Feeders.



## Table x

$99 $142 $180 $213 $243 $269 $293 $314 $332 $348 $363 13 14 15 

### 16 17 18 19 20 21

23 24



### 26 27 28 $9 $57 $52

$9 $58 $53 $9 $58 $53 $9 $59 $54 $9 $59 $55 $9 $59 $56 $9 $60 $56 $9 $60 $57


## -23- $376 $387 $397 $406 $413 $420 $426 $431 $436 $440 $444 $447 $450 $452 $454 $456 

## The values reflected here represent the maximum amount the utility should be willing to pay, on a per-KW basis, to invest in a DR alternative to a given "wires and transformers" project. These values represent possibilities within a very reasonable range ofcosts. Individual projects may exhibit values that exceed those shown here, depending upon the circumstances.

Because ofthe high variation from average cost that each utility might see on its own system, it is notjustthe high cost utilities that might effectivelyutilize DR. Table x reflects the same summaryinformation for Southwestern Electric Power Company, a company appearing onboth ofthe lowest cost tables for Transformers & 

## Substations and Lines & 

## Feeders.

Table x Value ofProject Deferring DR ($/kW)

ompany Southwestern Electric Power Company Transformers & 

### Lines & 

### Feeders

Substations rvtarginal Cost ($IMW) 

### $7,621 $397,210 $56,142 $12,914 Case Case Deferral Years Low High Low High 1 $1 $7 $5 $51 2 $2 $13 $9 $99 3 $3 $19 $13 $142 4 $4 $24 $17 $180 5 $4 $29 $21 $213 6 $5 $33 $24 $243 7 $5 $36 $27 $269 8 $6 $39 $30 $293 9 $6 $42 $33 $314 10 

### $7 $44 $35 $332 11 $7 $46 $37 $348 12 $7 $48 $39 $363 13 $8 $50 $41 $376 14 $8 $51 $43 $387 15 $8 $53 $44 $397 16 $8 $54 $46 $406 17 $8 $55 $47 $413 18 $9 $55 $48 $420 19 $9 $56 $50 $426 20 $9 $57 $51 $431 21 $9 $57 $52 $436 22 $9 $58 $53 $440 23 $9 $58 $53 $444 24 $9 $59 $54 $447 25 $9 $59 $55 $450 26 $9 $59 $56 $452 27 $9 $60 $56 $454 28 $9 $60 $57 $456


## -23-H 30 ^ E $47

$60 $58 $4559 

## These values show that DR alternatives have significant values even for "low cost" utilities. In addition, it should be noted that these values represent capacity values only. Economic dispatch of DG would yield additional energy value to the system. These values have not been analyzed in this paper because they are outside the scope of our review. $4571 $459



## These values show that DR alternatives have significant values even for "lowcost"utilities. 

## In addition, it should be noted that these values represent capacity values only. Economic dispatch ofDG wouldyield additional energyvalue to the system. These values have not been analyzed in this paperbecause they are outside the scope ofour review.

-24-

## Conclusion

Distribution system costs have not historically received a high level of analysis and review by regulators. However, there is every reason to believe that the growth in investment in the distribution system is likely to accelerate over the next several years. Principal causes for this include the deterioration of embedded facilities that are at or near the end of their useful lives, expansion and upgrade of facilities that operate at or near their capacity, and continued growth, both geographically and in terms of intensity, of consumer demand.
While generating costs may experience a decline through technological gains in efficiency, costs of the distribution system will probably continue to increase. Average aggregate annual investments of over $5.4 billion per year were made by the 93 utilities in our study. This translates into an annual revenue requirement increase per year on the order of $1 billion. This is not an insignificant cost and deserves the attention of regulators and the application of appropriate least-cost strategies. 

## While the analysis here cannot provide the basis for making individual choices for specific projects, it does clearly demonstrate that there are many opportunities to implement distributed resources in lieu of traditional wires and transformers solutions. This study should provide the regulator with some guidelines about the important aspects of distribution costs and a framework for assessing the avoided costs of the distribution system. Conclusion

Distribution system costs have not historicallyreceived a high level ofanalysis and review by regulators. However, there is everyreason to believe that the growth in investment inthe distribution system is likelyto accelerate over the next several years. Principal causes for this include the deterioration ofembedded facilities that are at ornearthe end oftheiruseful lives, expansion and upgrade offacilities that operate at ornear their capacity, and continued growth, both geographically and in terms ofintensity, ofconsumer demand.

While generating costs may experience a decline through technological gains in efficiency, costs ofthe distribution system will probably continue to increase. Average aggregate annual investments ofover $5.4 billionperyear were made bythe 93 utilities in our study. This translates into an annual revenue requirement increase peryear onthe order of$1 billion. This is not an insignificant cost and deserves the attention ofregulators and the application of appropriate least-cost strategies.

While the analysis here cannotprovide the basis for making individual choices for specific projects, it does clearly demonstrate that there are manyopportunities to implement distributed
resources in lieu oftraditional wires and transformers solutions. This study should provide the regulator with some guidelines about the important aspects ofdistribution costs and a framework for assessing the avoided costs ofthe distribution system.

-25-

## Appendix A 

## List of Companies Used for Analysis

Alaska Electric Light and Power Company Appalachian Power Company Arizona Public Service Company Atlantic City Electric Company Baltimore Gas and Electric Company Black Hills Corporation Carolina Power & Light Company Central Hudson Gas & Electric Corporation Central Illinois Public Service Company Central Power and Light Company Chugach Electric Association, Inc. Cleco Utility Group Inc. Cleveland Electric Illuminating Company, The Columbus Southern Power Company Commonwealth Edison Company Concord Electric Company Connecticut Light and Power Company, The Consolidated Edison Company of New York, Inc. Consumers Energy Company Delmarva Power & Light Company Duke Energy Corporation El Paso Electric Company Entergy Arkansas, Inc. Entergy Gulf States, Inc. Exeter & Hampton Electric Company Fitchburg Gas and Electric Light Company Florida Power & Light Company Florida Power Corporation Holyoke Water Power Company Idaho Power Company IES Utilities Inc. Indiana Michigan Power Company Indianapolis Power & Light Company Interstate Power Company Kansas City Power & Light Company Kansas Gas and Electric Company Kentucky Power Company Kentucky Utilities Company Kingsport Power Company Madison Gas and Electric Company Maine Public Service Company MDU Resources Group, Inc. Metropolitan Edison Company Monongahela Power Company Mt. Carmel Public Utility Co New Hampshire Electric Cooperative, Inc. Newport Electric Corporation Niagara Mohawk Power Corporation


## -26- 

## Appendix A List ofCompanies Used for Analysis

Alaska Electric Light and Power Company Appalachian Power Company Arizona Public Service Company Atlantic City Electric Company Baltimore Gas and Electric Company Black Hills Corporation Carolina Power & Light Company Central Hudson Gas & Electric Corporation Central Illinois Public Service Company Central Power and Light Company Chugach Electric Association, Inc. Cleco Utility Group Inc. Cleveland Electric Illuminating Company, The Columbus Southern Power Company Commonwealth Edison Company Concord Electric Company Connecticut Light and Power Company, The ConsolidatedEdison Company ofNew York, Inc. Consumers Energy Company Delmarva Power & Light Company Duke Energy Corporation El Paso Electric Company Entergy Arkansas, Inc. Entergy GulfStates, Inc. Exeter & 

### Hampton Electric Company Fitchburg Gas and Electric Light Company Florida Power & Light Company Florida Power Corporation Holyoke Water Power Company Idaho Power Company IES Utilities Inc. Indiana Michigan Power Company Indianapolis Power & Light Company Interstate Power Company Kansas City Power & Light Company Kansas Gas and Electric Company Kentucky Power Company KentuckyUtilities Company Kingsport Power Company Madison Gas and Electric Company Maine Public Service Company MDU Resources Group, Inc. Metropolitan Edison Company Monongahela Power Company Mt. Carmel Public Utility Co New Hampshire Electric Cooperative, Inc. Newport Electric Corporation Niagara Mohawk Power Corporation


## -26-

### Northern Indiana Public Service Company Northern States Power Company (Wisconsin) Northwestern Public Service Ohio Edison Company Ohio Power Company Oklahoma Gas and Electric Company Otter Tail Power Company Pacific Gas and Electric Company PacifiCorp Pennsylvania Electric Company Pennsylvania Power Company Portland General Electric Company Potomac Electric Power Company PP&L, Inc. PSI Energy, Inc. Public Service Company of Colorado Public Service Company of New Hampshire Public Service Company of New Mexico Puget Sound Energy, Inc. Rockland Electric Company San Diego Gas & Electric Company Sierra Pacific Power Company Southern Indiana Gas and Electric Company Southwestern Electric Power Company Southwestern Public Service Company St. Joseph Light & Power Company The Dayton Power and Light Company The Detroit Edison Company The Empire District Electric Company The Potomac Edison Company The United Illuminating Company Toledo Edison Company, The TXU Electric Company Union Electric Company Upper Peninsula Power Company Utilicorp United, Inc. Virginia Electric and Power Company West Penn Power Company West Texas Utilities Company Western Massachusetts Electric Company Western Resources, Inc. Wheeling Power Company Wisconsin Electric Power Company Wisconsin Power and Light Company Wisconsin Public Service Corporation 

### Northern Indiana Public Service Company Northern States Power Company (Wisconsin) Northwestern Public Service Ohio Edison Company Ohio Power Company Oklahoma Gas and Electric Company Otter Tail Power Company Pacific Gas and Electric Company PacifiCorp Pennsylvania Electric Company Pennsylvania Power Company Portland General Electric Company Potomac Electric PowerCompany PP&L, Inc. PSI Energy, Inc. Public Service Company ofColorado Public Service Company ofNew Hampshire Public Service Company ofNewMexico Puget Sound Energy, Inc. Rockland Electric Company San Diego Gas & Electric Company Sierra Pacific Power Company Southern Indiana Gas andElectric Company Southwestern Electric Power Company SouthwesternPublic Service Company St. Joseph Light & Power Company The Dayton Power and Light Company The DetroitEdison Company The Empire District Electric Company The Potomac Edison Company The United Illuminating Company Toledo Edison Company, The TXU Electric Company Union Electric Company UpperPeninsula Power Company Utilicorp United, Inc. Virginia Electric and Power Company WestPenn Power Company WestTexas Utilities Company Western Massachusetts Electric Company Western Resources, Inc. Wheeling Power Company Wisconsin Electric Power Company Wisconsin Power and Light Company Wisconsin Public Service Corporation



## -27-