8. Monthly Rate Adjustment

Transcription

1

2 Baltimore Gas and Electric Company -- Gas 92-A with Daily Metering Equipment) is $ per therm. The rate for customers equipped with Daily Metering Equipment electing Standby Service is $ per therm. The rate charged to Suppliers will be the rate for POLR Capacity cost adjusted for Gross Receipt Taxes and PSC Assessment. The rate for Suppliers is $ per therm. 8. Monthly Rate Adjustment The Delivery Price under Schedules D and C is adjusted to reflect test year base rate revenues established in the latest base rate proceeding, after adjustment to recognize the change in the number of customers from the test year level. The change in revenues associated with the Customer Charge is the change in number of customers multiplied by the Customer Charge for the rate schedule. The change in revenues associated with throughput is the test year average use per customer multiplied by the net number of customers added since the like-month during the test year and multiplying that product by the Delivery Price for the rate schedule. The change in revenues associated with Customer Charge and throughput is added to test year revenue to restate test year revenues for the month to include the revised values. Actual revenues collected for the month are compared to the restated test year revenues and any difference is divided by estimated sales for the second succeeding month to obtain the adjustment to the applicable Delivery Price. Any difference between actual and estimated sales is reconciled in the determination of the adjustment for a future month. The Monthly Rate Adjustment is calculated separately for Schedule D, Schedule C, excluding Daily Metered customers, and Schedule C Daily Metered customers only. Details of the calculation of the billing adjustment are filed monthly with the Public Service Commission. Revenues associated with the GAC adder, using test year data from the most recently approved base rate case, are excluded from the Rider 8 Monthly Rate Adjustment target base revenues, subject to an adjustment to reflect the difference between the rate charged to suppliers for using BGE s bill and the revenues reflected in test year data from the most recently approved base rate case. P.S.C. Md. G-9 (Suppl ) Filed 12/15/201712/16/2016 Effective With February Billings

3 Baltimore Gas and Electric Company -- Gas 92-A with Daily Metering Equipment) is $ per therm. The rate for customers equipped with Daily Metering Equipment electing Standby Service is $ per therm. The rate charged to Suppliers will be the rate for POLR Capacity cost adjusted for Gross Receipt Taxes and PSC Assessment. The rate for Suppliers is $ per therm. 8. Monthly Rate Adjustment The Delivery Price under Schedules D and C is adjusted to reflect test year base rate revenues established in the latest base rate proceeding, after adjustment to recognize the change in the number of customers from the test year level. The change in revenues associated with the Customer Charge is the change in number of customers multiplied by the Customer Charge for the rate schedule. The change in revenues associated with throughput is the test year average use per customer multiplied by the net number of customers added since the like-month during the test year and multiplying that product by the Delivery Price for the rate schedule. The change in revenues associated with Customer Charge and throughput is added to test year revenue to restate test year revenues for the month to include the revised values. Actual revenues collected for the month are compared to the restated test year revenues and any difference is divided by estimated sales for the second succeeding month to obtain the adjustment to the applicable Delivery Price. Any difference between actual and estimated sales is reconciled in the determination of the adjustment for a future month. The Monthly Rate Adjustment is calculated separately for Schedule D, Schedule C, excluding Daily Metered customers, and Schedule C Daily Metered customers only. Details of the calculation of the billing adjustment are filed monthly with the Public Service Commission. Revenues associated with the GAC adder, using test year data from the most recently approved base rate case, are excluded from the Rider 8 Monthly Rate Adjustment target base revenues, subject to an adjustment to reflect the difference between the rate charged to suppliers for using BGE s bill and the revenues reflected in test year data from the most recently approved base rate case. P.S.C. Md. G-9 (Suppl. 441) Filed 12/15/2017 Effective With February 2018 Billings

4 Rider 7 EFFECTIVE 02/01/18 FILED 12/15/17 SYSTEM GROWTH POLR A. COST COMPONENT TOTAL 1. ESTIMATED UNMITIGATED COST OF FIRM PIPELINE a. Estimated Total Available Capacity - Winter 2017/18 (Filing Attachment 2a) 982,212 b. Estimated Capacity to serve BGE Gas Commodity Service, Schedule C Standby Winter 2017/18 (Filing Attachment 2a) 929,354 c. Estimated Capacity for System Growth and POLR = a - b 52,858 d. Estimated Total Requirements as POLR four winters in future 2021/22 1,063,569 (Filing Attachment 2b) e. Estimated Total Requirements as POLR for current winter 2017/18 1,026,127 (Filing Attachment 2b) f. Estimated System Growth Capacity = d - e 37,442 g. Estimated POLR Capacity = if f > c then g = 0, else g = c - f 15,416 15,416 g1. Estimated System Growth Capacity = if g =0 then g1 = c, else g1 = f 37,442 37,442 g2. Estimated Capacity for System Growth and POLR =g +g1 52,858 h. Weighted Average Cost of Capacity Firm Transportation Capacity Cost WACC Columbia 405,076 $ 3,581,693 Dominion 178,994 1,535,023 Hardy 23, ,217 Transco 56, , ,587 $ 5,812,746 $ 8.76 i. Estimated Annualized Cost of Capacity = g1 x h x 12 and g x h x 12 $ 3,935,891 $ 1,620,507 $ 5,556,398 j. Estimated Incremental Cost of Peaking Contracts (Filing Attachment 1 - section D) $ - $ - k. Total Estimated Unmitigated Cost of Capacity = i + j $ 3,935,891 $ 1,620,507 $ 5,556,398 SYSTEM GROWTH POLR TOTAL 2. ESTIMATED MITIGATION OF RESERVED a. Total Estimated Mitigation Revenues Applicable to Capacity Costs (Filing Attachment 1 - section B) $ 723,125 b. Allocated Capacity from Part 1 (in Dth) = 1.g1, 1.g and 1.g2 37,442 15,416 52,858 c. Percent of Mitigation Allocated to Category = Category Total / Grand Total 70.84% 29.16% d. Allocated Mitigation to Category = a x c $ 512, $ 210, $ 723,125 e. Estimated Amount of Capacity to be Released as Recallable (in Dth) (Filing Attachment 1 - section C) 47,858 f. Estimated Incremental Cost of Releasing Recallable Capacity (Filing Attachment 1 - section C) $ 825,267 g. Adjustment of Capacity Costs = f and neg(f) $ 825,267 $ (825,267) h. Total Estimated Mitigation Revenue Credited to Capacity = d + g $ 1,337,529 $ (614,404) $ 723, ESTIMATED COST OF FIRM PIPELINE AFTER MITIGATION a. Estimated Unmitigated Capacity Cost from Part 1 = 1k $ 3,935,891 $ 1,620,507 $ 5,556,398 b. Estimated Mitigation from Part 2 = 2h $ 1,337,529 $ (614,404) $ 723,125 c. Estimated Capacity Cost After Mitigation = a - b $ 2,598,362 $ 2,234,911 $ 4,833, RECONCILIATION COMPONENT FOR a. Actual Mitigated Capacity Cost for (Filing Attachment 5) $ 1,481,021 $ 2,891,708 $ 4,372,729 b. Actual Revenue Collected for (Filing Attachment 4) $ 1,372,056 $ 2,096,222 $ 3,468,278 c. Prior Year Imbalance $ (244,954) $ (904,741) $ (1,149,695) d. Excess or Shortage of Actual Costs vs. Estimated Costs = a - b + c $ (135,989) $ (109,255) $ (245,244) e. Total Estimated Cost After Mitigation plus Reconciliation = 3c + 4d $ 2,462,373 $ 2,125,657 $ 4,588, CALCULATION OF RATES FOR COST a. Estimated Annual Throughput for Firm Supplier Gas Commodity Service Customers (excl CL AMR) - Dth 27,657,593 b. Estimated Annual Throughput for all Firm Distribution Customers (incl. CL AMR standby) - Dth 70,860,223 c. Rate for Capacity Costs ($/Dth) =4e / 5b $ d. Third Party Suppliers Rate for POLR ($/Dth) =4e / 5a 0.077

5 EFFECTIVE 02/01/18 FILED 12/15/17 B. GAS CHOICE PROGRAM COST COMPONENT TOTAL 1. Estimated Gas Choice Program Expenditures (Filing Attachment 3 Section C) $ - 2. Reconciliation Component for Gas Choice Program Costs a. Actual Expenditures for Gas Choice Programs (Dec16-Nov17) (60,620) b. Revenue Collected for Gas Choice Programs (Dec16-Nov17) (Filing Attachment 4) $ 134,394 c. Prior Year Imbalance $ 37,765 d. Excess or Shortage of Costs vs. Revenues = a - b + c $ (157,249) 3. Total Estimated Expenditures plus Reconciliation = 1+2d $ (157,249) 4. Estimated Annual Throughput for all Firm Distribution Customers (excl all CL AMR) - Dth 70,795, Gas Choice Program Cost Rate Before Cap - $/Dth =3 / 4 $ (0.002) 6. Rate Cap - $/Dth $ Gas Choice Program Cost Rate After Cap - $/Dth = smaller of 5 or 6 $ (0.002) C. DETERMINATION OF GCRC BILLING RATES SYSTEM GROWTH POLR 1. Rate for System Growth Capacity Costs = A5c ($ / Dth) $ System Growth Capacity Costs adjusted for GRT and PSC Assessment = "1" / ( ) ($ / Dth) $ System Growth Capacity Costs adjusted for GRT and PSC Assessment = "2" / 10 rounded ($ / th) $ Rate for POLR Capacity Costs = A5d ($ / Dth) $ POLR Capacity Costs adjusted for GRT and PSC Assessment = "4" / ( ) ($ / Dth) $ POLR Capacity Costs adjusted for GRT and PSC Assessment = "5" / 10 rounded ($ / th) $ Rate for Gas Choice Programs Costs = B7 ($ / Dth) $ (0.002) 8. Gas Choice Programs Costs adjusted for GRT and PSC Assessment = "7" / ( ) ($ / Dth) $ (0.002) 9. Gas Choice Programs Costs adjusted for GRT and PSC Assessment = "8" / 10 rounded ($ / th) $ (0.0002) Billing Rate for all firm distribution customers (excl. CL AMR customers) = "3" + "9" ($ / th) $ Billing Rate for CL AMR standby service customers = "3" ($ / th) $ Billed Rate for Third Party Suppliers = "6" ($ / th) $

6 Filing Attachment 1 CALCULATION OF MITIGATION REVENUE, INCREMENTAL COST AND PEAKING CONTRACT COST Mitigation Calculation Estimate A. Reserve Capacity Breakdown 1. Estimated Capacity for System Growth and POLR 52,858 Attachment 2a (from Capacity Plan - Appendix A) 2. Non-recallable 0 3. Recallable =A.1-A.2 52,858 B. Mitigation Revenue Estimate Estimated Nov17-Mar18 Off-System Sales Avg Daily Volume (Dth) Days Daily Margin Winter Margin 1. Non-recallable =A $ $ Recallable =A.3 52, $ $723, Difference =B.1 - B.2 $ Estimated Mitigation $723, C. Incremental Cost of Releasing Recallable Capacity 1. Growth Capacity (Dth) 37,442 Attachment 2b (from Capacity Plan - Appendix B) 2. Capacity Held (under contract) (Dth) 52, Adjustment (Dth) 5, Potential Non-Recallable (Dth) =C.2 - C.3. 47, Actual Non-Recallable (Dth) 0 Days Daily Margin 6. Difference & Incremental Cost =C.4 - C.5. 47, $ $825, D. Peaking Contract Cost - Winter required $0.00

7 Filing Attachment 2a DAILY RESERVE - GAS COMMODITY SERVICE, SCHEDULE C STANDBY & CRITICAL USE LOAD (FROM THE 2017 PLAN) CITY GATE DELIVERABILITY EXPIRATION DATE AVAILABLE FOR THE WINTER OF: (17-18) (18-19) (19-20) (20-21) (21-22) TRANSCO FT-NT 10/18 21,500 21,500 21,500 21,500 21,500 COLUMBIA FTS 10/19&22&24&33 142, , , , ,925 NTS 10/19&22&24 63,000 63,000 63,000 63,000 63,000 FSS / SST 3/20&26 141, , , , ,937 FSS / SST 3/20&25 53,214 53,214 53,214 53,214 53,214 DOMINION GSS / FTNN 3/23 39,929 39,929 39,929 39,929 39,929 FTNN 3/23 60,071 60,071 60,071 60,071 60,071 MID ATL EXP FT 10/19 25,000 25,000 25,000 25,000 25,000 TCO RLSD FT CAP FT 10/22 4,000 4,000 4,000 4,000 4,000 HARDY STOR HSS / TPS 3/23 23,017 23,017 23,017 23,017 23,017 TRANSCO POTOMAC FT 10/27 25,000 25,000 25,000 25,000 25,000 DTI USA STORAGE SST / FTNN 3/25 38,994 38,994 38,994 38,994 38,994 TRANSCO MAC FT 10/32 10,000 10,000 10,000 10,000 10,000 ALLEGHENY STORAGE GSS/FTNN 3/29 15,000 15,000 15,000 15,000 15,000 BGE PIPELINE 663, , , , ,587 PEAK SHAVING SPRING GARDENS LNG 311, , , , ,500 NOTCH CLIFF PROPANE AIR 85,000 85,000 85,000 85,000 85,000 LESS OPERATIONAL CONTINGENCY 77,875 77,875 77,875 77,875 77,875 PEAK SHAVING AVAIL 318, , , , ,625 LESS OSS / RELEASE PLUS PEAKING CONTRACT TOTAL AVAILABLE 982, , , , ,212 TOTAL DESIGN DAY FIRM LOAD 1,025,267 1,035,172 1,046,089 1,053,747 1,062,677 ALL FIRM SERVICE CUSTOMERS 189, , , , ,383 LESS DRS CUSTOMERS PLUS CL AMR STANDBY FIRM DESIGN DAY LOAD FOR SALES CUSTS 836, , , , ,186 PLUS PEAK SHAVING FOR DRS 28,218 28,490 28,791 29,001 29,247 PLUS RESERVE FOR PARKING & BALANCING 64,487 65,112 65,799 66,281 66,842 TOTAL REQUIREMENTS 929, , , , ,276 DAILY RESERVE DAILY RESERVE 52,858 43,869 33,973 27,031 18,936

8 Filing Attachment 2b DAILY RESERVE AS POLR FOR 100% OF FIRM LOAD (FROM THE 2017 PLAN) CITY GATE DELIVERABILITY EXPIRATION DATE AVAILABLE FOR THE WINTER OF: (17-18) (18-19) (19-20) (20-21) (21-22) TRANSCO FT-NT 10/18 21,500 21,500 21,500 21,500 21,500 COLUMBIA FTS 10/19&22&24&33 142, , , , ,925 NTS 10/19&22&24 63,000 63,000 63,000 63,000 63,000 FSS / SST 3/20&26 141, , , , ,937 FSS / SST 3/20&25 53,214 53,214 53,214 53,214 53,214 DOMINION GSS / FTNN 3/23 39,929 39,929 39,929 39,929 39,929 FTNN 3/23 60,071 60,071 60,071 60,071 60,071 MID-ATL EXP FT 10/19 25,000 25,000 25,000 25,000 25,000 TCO RLSD FT FT 10/22 4,000 4,000 4,000 4,000 4,000 HARDY STORAGE HSS / TPS 3/23 23,017 23,017 23,017 23,017 23,017 TRANSCO POTOMAC FT 10/27 25,000 25,000 25,000 25,000 25,000 DTI USA STORAGE SST / FTNN 3/25 38,994 38,994 38,994 38,994 38,994 TRANSCO MAC FT 10/32 10,000 10,000 10,000 10,000 10,000 ALLEGANY STORAGE GSS/FTNN 3/29 15,000 15,000 15,000 15,000 15,000 BGE PIPELINE 663, , , , ,587 SUPPLIER LONG TERM DELIVERABILITY CITY GATE DELIVERABILITY 663, , , , ,587 PEAK SHAVING SPRING GARDENS LNG 311, , , , ,500 NOTCH CLIFF PROPANE AIR 85,000 85,000 85,000 85,000 85,000 LESS OPERATIONAL CONTINGENCY 77,875 77,875 77,875 77,875 77,875 PEAK SHAVING AVAILABLE 318, , , , ,625 PLUS SUPPLIER SHORT TERM DELIVERABILITY LESS OSS / RELEASE PLUS PEAKING CONTRACT TOTAL AVAILABLE 982, , , , ,212 TOTAL DESIGN DAY FIRM LOAD 1,025,267 1,035,172 1,046,089 1,053,747 1,062,677 LESS DRS CUSTOMER LOAD PLUS CL AMR STANDBY PLUS CRITICAL USE FIRM DESIGN DAY LOAD 1,026,127 1,036,040 1,046,966 1,054,631 1,063,569 PLUS PEAK SHAVING FOR DRS PLUS RESERVE FOR PARKING & BALANCING TOTAL REQUIREMENTS 1,026,127 1,036,040 1,046,966 1,054,631 1,063,569 DAILY RESERVE (43,915) (53,828) (64,754) (72,419) (81,357)

9 Filing Attachment 3 ESTIMATED GAS CHOICE PROGRAM EXPENDITURES - Dec Nov SECTION A - Metering Costs These are costs related to the maintenance of sample meters used to forecast daily consumption of DRS customers performed by Metering and IT personnel. $ - SECTION B - Gas Choice Education and Advertising Costs $ - SECTION C - Total Gas Choice Program Expenditures =(A+B) $ -

10 Attachment 4 GCRC REVENUE COLLECTED (Dec16-Nov17) System Growth POLR Gas Total Capacity Capacity Choice GCRC Revenue Revenue Revenue Revenue Collected Collected Subtotal Collected Collected (a) (b) (c)=(a)+(b) (d) (e)=(c)+(d) GCRC Revenue Collected (Dec16-Nov17) - See Note $1,372,056 $2,096,222 $3,468,278 $134,394 $3,602,672 Note: Net of GRT and PSC Assessment.

11 Rider 7 Attachment 5 TRUE-UP OF THE ESTIMATED MITIGATION COST FROM PREVIOUS FILING SYSTEM GROWTH POLR A. COST COMPONENT TOTAL 1. ESTIMATED UNMITIGATED COST OF FIRM PIPELINE a. Estimated Total Capacity Available (Previous Filing Attachment 2a) 982,212 b. Estimated Capacity to serve BGE Gas Commodity Service, Schedule C Standby and Critical Use customers (Previous Filing Attachment 2a) 907,637 c. Estimated Capacity for System Growth and POLR (Previous Filing Attachment 2a) = a - b 74,575 d. Estimated Total Requirements as POLR four winters in future 2020/21 1,056,777 (Previous Filing Attachment 2b) e. Estimated Total Requirements as POLR for current winter 2016/17 1,010,634 (Previous Filing Attachment 2b) f. Estimated System Growth Capacity (Previous Filing Attachment 2a) = d - e 46,143 g. Estimated POLR Capacity (Previous Filing Attachment 2a) = if f > c then g = 0, else g = c - f 28,432 28,432 g1. Estimated System Growth Capacity (Previous Filing Attachment 2a) = if g =0 then g1 = c, else g1 = f 46,143 46,143 g2. Estimated Capacity for System Growth and POLR (Previous Filing Attachment 2a) =g +g1 74,575 h. Actual Weighted Average Cost of Capacity (WACC) $ 9.46 i. Actual Annualized Cost of Capacity = g1 x h x 12 and g x h x 12 $ 5,238,153 $ 3,227,601 $ 8,465,754 j. Actual Incremental Cost of Peaking Contracts (Filing Attachment 6 - section D) $ - $ - k. Total Actual Unmitigated Cost of Capacity = i + j $ 5,238,153 $ 3,227,601 $ 8,465,754 SYSTEM GROWTH POLR TOTAL 2. ACTUAL MITIGATION OF RESERVED a. Total Actual Mitigation Revenues Applicable to Capacity Costs (Filing Attachment 6 - section B) See Note $ 4,093,025 b. Allocated Capacity from Part 1 (in Dth) 1.g1, 1.g and 1.g2 46,143 28,432 74,575 c. Percent of Mitigation Allocated to Category = Category Total / Grand Total 61.87% 38.13% d. Allocated Mitigation to Category = a x c $ 2,532,544 $ 1,560,481 $ 4,093,025 e. Actual Amount of Capacity to be Released as Recallable (in Dth) (Filing Attachment 6 - section C) 71,068 f. Actual Incremental Cost of Releasing Recallable Capacity (Filing Attachment 6 - section C) $ 1,224,589 g. Adjustment of Capacity Costs = f and neg(f) $ 1,224,589 $ (1,224,589) h. Total Actual Mitigation Revenue Credited to Capacity = d + g $ 3,757,133 $ 335,892 $ 4,093, ACTUAL COST OF FIRM PIPELINE AFTER MITIGATION a. Actual Unmitigated Capacity Cost from Part 1 = 1k $ 5,238,153 $ 3,227,601 $ 8,465,754 b. Actual Mitigation from Part 2 = 2h $ 3,757,133 $ 335,892 $ 4,093,025 c. Actual Capacity Cost After Mitigation (Dec16-Nov17) = a - b $ 1,481,021 $ 2,891,708 $ 4,372,729 Note: The Total Mitigation Revenues Applicable to Capacity Costs is limited to the Total Actual Unmitigated Cost of Capacity in Line A.1.k.

12 Attachment 6 TRUE-UP CALCULATION OF MITIGATION REVENUE, INCREMENTAL COST AND PEAKING CONTRACT COST Mitigation Calculation A. Reserve Capacity Breakdown 1. Estimated Capacity for System Growth and POLR 74,575 (Previous Filing, Attachment 1) 2. Non-recallable 0 (Previous Filing, Attachment 1) 3. Recallable =A.1-A.2 74,575 (Previous Filing, Attachment 1) B. Actual Mitigation Revenue Actual Nov16-Mar17 Off-System Sales Avg Daily Volume (Dth) Days Avg Margin Total Winter Margin 1. Non-recallable 98, $ $3,051, Recallable 76, $ $1,041,064 Difference $ Actual Mitigation $4,093,025 C. Incremental Cost of Releasing Recallable Capacity 1. Mitigated Capacity =B.1+B.2 174, Adjustment 5, Potential Non-Recallable =C.1-C.2 169, Actual Non-Recallable =B.1 98,713 Days Avg Margin Difference & Incremental Cost =C.3-C.4 71, $ See Note $1,224,589 D. Peaking Contract Cost $0 Note: If the Average Margin for Recallable Releases exceed the Average Margin for Non-Recallable Releases, there is no Incremental Cost of Releasing Capacity on a Recallable Basis and no need to make an adjustment to the alloxation of Capacity Costs between System Growth Capacity and POLR Capacity