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COSA Results for 2020

 

 

June 17, 2019

 

to:

Kevin Owens

from:

  Gail Tabone

subject:

COSA Results for 2020

 

Based on your financial forecast for 2020, and all of the other data provided, we have completed our initial COSA and a summary of the results are included in this memo. This reflects several changes resulting from our discussion with the Risk Management Committee. The results are a starting point for rate design, which is not addressed in this memo. 

 

Revenue Requirements

 The revenue requirements show the 2020 forecast results and will be the test year for the COSA.

 
The following are the revenue requirements assumptions: 

  • Power supply costs are based on the 2019 budget amounts for power purchases and transmission costs as a starting point.  The resulting cost per kWh for power supply, and $-kW-month cost for transmission, were then applied to the 2020 forecast loads.  The resulting 2020 forecast is higher than what is in your 2020 financial forecast because it is calculated out based on the loads each month rather than based on 2019 numbers plus a % increase.  This is important because we want the power costs and revenues to both be based on the detailed load amounts.
  • The transmission costs were increased by the 53% proposed by Northwestern.  The resulting annual cost for 2020 is projected at $728,241.
  • Other costs were based on the 2020 financial forecast, split into the various detailed FERC accounts based on the 2018 actual costs by detailed FERC account. 
  • The revenue requirement includes depreciation, interest and operating margins as provided in the financial forecast.  The margin was adjusted to equal the exact amount collected after the revenues and costs included in the COSA.  It is slightly different than what was in the financial forecast.
  • The revenue requirement deducts revenue for other sources and therefore only reflects the revenues that need to be collected in retail rates.

The following table provides a summary of the projected revenue requirements.  There is no need for a rate increase for 2020.  The amounts in the 2020 financial forecast are also shown for comparison purposes.  The difference from the financial forecast is that power supply costs are higher by $240,446, partly due to higher transmission charges and partly due to the way the cost was calculated based on loads.  The revenues are higher by $300,332 based on the detailed revenue calculations.  This results in a margin that is higher by $59,887.

 

Table 1

2020 Revenue Requirement

 FERC Account

Expenses

 

COSA 

Financial Forecast

 

Power Purchases

   

 

 XXXX

Demand Charges (OATT Transmission)

 

$728,241

 

 XXXX

Energy Charges

 

$2,687,688

 

 

Total Purchased Power

 

$3,415,929

$3,175,483

 

Transmission

   

 

                  570.00

Maint. of Station Equipment

 

$8,942

$8,942

 

Distribution

   

 

                  580.00

Op. Supervision & Engineering

 

$135,141

 

                  582.00

Line and Station Expenses

 

$66,863

 

                  583.00

Overhead Lines

 

$247,611

 

                  584.00

Underground Lines

 

$58,705

 

                  586.00

Meters

 

$41,166

 

                  587.00

Customer Installations

 

$3,935

 

                  588.00

Misc. Distribution

 

$479,123

 

                  589.00

Rents

 

$1,669

 

                  592.00

Maint. of Station Equipment

 

$10,552

 

                  593.00

Maint. of Overhead Lines

 

$550,495

 

                  594.00

Maint. Of Underground Lines

 

$70,183

 

                  595.00

Maint. of Line Transformers

 

$25,832

 

 

Total Distribution

 

$1,691,277

$1,691,277

 

Customer Service, Accounts, & Sales

   

 

                  902.00

Meter Reading

 

$59,105

 

                  903.00

Customer Records Collection

 

$329,628

 

                  908.00

Customer Assistance

 

$11,016

 

                  910.00

Misc. Customer Service & Information

 

$130,673

 

                  912.00

Demonstrating & Selling

 

$5,242

 

 

Total Customer Service, Accounts & Sales

 

$535,664

$535,664

 

Administrative & General

   

 

                  920.00

Administrative & General Salaries

 

$387,726

 

                  921.00

Office Supplies

 

$52,670

 

                  923.00

Outside Services

 

$128,109

 

                  924.00

Property Insurance

 

$15,154

 

                  925.00

Injuries and Damages

 

$7,155

 

                  926.00

Employee Pension & Benefits

 

$89,415

 

                  930.10

General Advertising

 

$71,282

 

                  930.20

Misc. General Expense

 

$287,182

 

                  935.00

Maintenance of General Plant

 

$136,170

 

 

Total Administrative & General

 

$1,174,864

$1,174,864

 

Depreciation

   

 

                  403.60

Distribution Plant

 

$965,456

 

                  403.70

General Plant

 

$67,967

 

 

Total Depreciation

 

$1,033,424

$1,033,424

 

Taxes

   

 

                  408.00

Property Tax

 

$2,839

$2,839

 

Interest and Debt Service Expense

   

 

                  427.00

Interest on Long-Term Debt

 

$606,746

 

                  431.00

Other Interest Expense

 

$3,000

 

 

Total Interest / Debt Service Expense

 

$609,746

$609,746

 

Operating Margins

 

$513,472

$453,585

 

Revenue Requirement Before Other Revenues

 

$8,983,317

$8,685,825

 

Other Revenues

   

 

                  450.00

Forfeited Deposits

 

$21,500

 

                  451.00

Misc. Service Revenues

 

$4,400

 

                  454.00

Rent - Electric Properties

 

$12,000

 

                  456.00

Misc. Revenue (Other)

 

$166

 

 419&424

Dividends from Affiliates, Interest

 

$51,106

 

 415&416

Income (Loss) from Equity Investments

 

$70,230

 

 

Total Other Revenues

 

$159,402

$164,242

 

REVENUE REQUIREMENT for COST ALLOCATION

 

$8,826,754

$8,521,582

 

REVENUES FROM RATES AND OTHER REVENUES

 

$8,986,156

$8,685,824

 

Cost of Service Study

A cost of service analysis (COSA) is concerned with the equitable allocation of the revenue requirement to the various customer classes of service.  The following are the assumptions used in the COSA:

  • Power supply purchases are allocated on the basis of energy. Wholesale transmission costs are allocated on the sum of the 12 monthly coincident peaks. 
  • BEC’s internal transmission costs are allocated on the basis of the annual system coincident peak.
  • Both the 100% demand and minimum system methods are used for allocating distribution costs, and a non-coincident peak is used for allocation.
  • Customer service and accounts costs are allocated on the basis of the number of customers.
  • The Southern Exit amortization listed as a separate item under A&G and is classified as customer-related and allocated on the number of customers weighted for the average kWh per customer.
  • Most other A&G costs are allocated on the basis of assignments developed by BEC.  Based on the total of the various assignments made by BEC, the result is 5% distribution and 95% customer-related.  The distribution portion was allocated on the basis of the NCP while the customer portion was allocated on the basis of customers weighted for the average kWh per customer.
  • Depreciation and interest payments are assigned on the basis of plant. 
  • Margin is allocated on the basis of all revenue.
  • AMI data for some residential customers during the winter months was used to develop load factors and coincidence factors for the residential class.  Hourly data for the Belfry substation was used to help develop load factors and coincidence factors for the irrigation class. 
  • Revenues were based on specific rate components times the load forecast of customers, demand and energy amounts.  It differs from the financial forecast because of the more detailed approach.

 2020 COSA results are summarized for the minimum system approach in Table 2 and for the 100 percent demand approach in Table 3. 

  

Table 2
Summary of Revenues and Costs – CY 2020
Minimum System Approach

 

Revenues at Current Rates

Net Revenue Requirement

Difference

Revenue to Cost Ratio

 

Residential

$7,226,669

$7,248,591

-$21,922

99.7%

 

Small Commercial

$805,579

$792,708

$12,871

101.6%

 

Large Commercial

$295,956

$269,995

$25,960

109.6%

 

Industrial

$145,178

$133,544

$11,634

108.7%

 

Irrigation

$353,373

$381,916

-$28,544

92.5%

 

TOTAL

$8,826,754

$8,826,754

$0

100%

 

 

 

 

 

 

 

Table 3
Summary of Revenues and Costs – CY 2020

100 Percent Demand Approach

 

Revenues at Current Rates

Net Revenue Requirement

Difference

Revenue to Cost Ratio

 

Residential

$7,226,669

$7,091,616

$135,054

101.9%

 

Small Commercial

$805,579

$794,736

$10,843

101.4%

 

Large Commercial

$295,956

$309,859

-$13,904

95.5%

 

Industrial

$145,178

$159,364

-$14,187

91.1%

 

Irrigation

$353,373

$471,179

-$117,807

75.0%

 

TOTAL

$8,826,754

$8,826,754

$0

100%

 

 

When looking at the revenue to cost ratios it is important to reflect the uncertainty inherent in any COSA due to methodology approaches and uncertainty in the load data used to allocate costs.  For that reason, a range of 90% to 110% is typically used to measure whether customer classes are paying an appropriate share of costs. 

 

Based on the results under the minimum system methodology, all classes are in the 90-110% range and do not need an increase or decrease.  In the 100% demand case, all classes except Irrigation are in the 90-110% range. 

 

For the Irrigation class, the COSA shows that they are still underpaying their cost of service in the 100% Demand case but are above 90% in the Minimum System case.  This is not an unexpected result due to the nature of the service.  On the power supply side, the costs of purchased power do not differ based on season and so there is no benefit to Irrigators related to their summer usage.  Power costs may have been more seasonal in the past, but BEC has changed its power supply source and rates are flat across all hours.  Because they do not peak at the time of the annual peak for BEC they are not allocated any of the transmission-related costs, however, these costs are small for BEC. 

 

The issue is with the distribution costs.  Distribution facilities are designed based on the maximum peak load that the customer might have throughout the year.  For this reason, the distribution costs are allocated on the basis of the non-coincident peak.  The Irrigators receive a full allocation based on their annual peak loads that occur in the summer months.  Unlike other classes, these distribution costs must be spread out over a 4-5 month period rather than the full 12-month period used by other types of customers. 

 

If the Board determines that is appropriate to increase Irrigation rates, it may be difficult to determine who would get a corresponding rate decrease.  Under the 100% demand approach, it would go to the residential and small commercial class.  Under the minimum system study, it would go to the large commercial and industrial classes.  However, given the small amount of revenues associated with the Irrigation class, any offset to the other rates would be small.


Unit Costs

Based on the COSA, Tables 4 and 5 (At the end of the memo) show the unit costs for each customer class.  This will be used to assist in developing rate options.

Next Steps

Once we make any adjustments in the revenue requirements and COSA, we can finalize the results and use the per unit costs as an input in the rate design process.  Based on the revenue to cost ratios resulting from the COSA, we will need policy direction from the Board as to whether there needs to be an overall rate increase or decrease to any of the classes.  Ideally this decision would be made prior to rate design so we know what our revenue targets should be.  It might be possible to do rate design first with revenue set to equal current revenues by class, and then have any overall increases or decreases applied after that is done.

 

Given the discussion among Board members and staff, the rate design step will be much more interactive and take more time than the COSA itself.  In that step, we will identify several options for each class and compare them in terms of design, revenue impacts and bill impacts for customers.  The per unit costs from the COSA, BEC analysis of costs by category, and rate designs for other utilities will all play a role in rate design.  It is likely that there will be several iterations of this process before we reach a final rate design proposal.

  

Table 4

Beartooth Electric Cooperative - 100% Demand

     

SUMMARY OF REVENUE REQUIREMENT UNIT COSTS

BY CUSTOMER CLASS

Schedule 2.1

             

Forecast Year: 2020

Total

Residential 

Small Commercial

Large Commercial

Industrial

Irrigation

Billing Determinants

           

Total Demand (kW)

415,700

356,491

31,894

11,969

4,268

11,078

Total Energy (kWh)

69,710,381

55,587,125

7,426,217

2,529,981

1,608,100

2,558,958

Average Customers

6,244

5,702

463

19

1

59

Assigned Cost/Unit Cost

 

 

 

 

 

 

Power Supply

           

Demand (PD)

$705,083

$565,858

$57,682

$36,434

$11,985

$33,123

$/kW

 

$1.59

$1.81

$3.04

$2.81

$2.99

             

Energy (PE)

$2,603,277

$2,078,324

$277,656

$94,592

$57,029

$95,676

$/kWh

 

$0.037

$0.037

$0.037

$0.035

$0.037

Transmission

           

Demand (TD)

$11,563

$9,915

$1,058

$509

$83

 

$/kW

 

$0.03

$0.03

$0.04

$0.02

 

Distribution

           

Demand (DD)

$3,631,692

$2,854,438

$284,482

$135,192

$64,639

$292,941

$/kW

 

$8.01

$8.92

$11.30

$15.15

$26.44

Customer (DC)

$1,875,139

$1,583,082

$173,858

$43,132

$25,629

$49,440

$/Customer/Month

 

$23

$31

$189

$2,136

$70

Total

$8,826,754

$7,091,616

$794,736

$309,859

$159,364

$471,179

             

Total

           

$/kW

 

$9.62

$10.76

$14.38

$17.97

$29.43

$/kWh

 

$0.037

$0.037

$0.037

$0.035

$0.037

$/Customer/Month

 

$23.14

$31.32

$189.17

$2,135.71

$69.83

Combined Demand/Energy

 

$0.0991

$0.0836

$0.1054

$0.0832

$0.1648

                     

 

 

Table 5

Beartooth Electric Cooperative - Minimum System Analysis

   

SUMMARY OF REVENUE REQUIREMENT UNIT COSTS

BY CUSTOMER CLASS

Schedule 2.1

             

Forecast Year: 2020

Total

Residential 

Small Commercial

Large Commercial

Industrial

Irrigation

Billing Determinants

           

Total Demand (kW)

415,700

356,491

31,894

11,969

4,268

11,078

Total Energy (kWh)

69,710,381

55,587,125

7,426,217

2,529,981

1,608,100

2,558,958

Average Customers

6,244

5,702

463

19

1

59

Assigned Cost/Unit Cost

Production

           

Demand (PD)

$705,083

$565,858

$57,682

$36,434

$11,985

$33,123

$/kW

 

$1.59

$1.81

$3.04

$2.81

$2.99

Energy (PE)

$2,603,277

$2,078,324

$277,656

$94,592

$57,029

$95,676

$/kWh

 

$0.037

$0.037

$0.037

$0.035

$0.037

Transmission

           

Demand (TD)

$11,563

$9,915

$1,058

$509

$83

 

$/kW

 

$0.03

$0.03

$0.04

$0.02

 

Distribution

           

Demand (DD)

$2,480,133

$1,959,736

$197,143

$91,824

$38,634

$192,797

$/kW

 

$5.50

$6.18

$7.67

$9.05

$17.40

Customer (DC)

$3,026,698

$2,634,759

$259,169

$46,636

$25,813

$60,321

$/Customer/Month

 

$39

$47

$205

$2,151

$85

Total

$8,826,754

$7,248,591

$792,708

$269,995

$133,544

$381,916

             

Total

           

$/kW

 

$7.11

$8.02

$10.76

$11.88

$20.39

$/kWh

 

$0.03739

$0.037

$0.037

$0.035

$0.037

$/Customer/Month

 

$38.50

$46.69

$204.54

$2,151.08

$85.20

Combined Demand/Energy

 

$0.0830

$0.0718

$0.0883

$0.0670

$0.1257