Telephone Fax April 3, 2017

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1 Damon L. Krieger Assistant General Counsel BGE Legal Department 2 Center Plaza, 12 th Floor 110 West Fayette Street Baltimore, MD Telephone Fax damon.krieger@bge.com April 3, 2017 VIA ELECTRONIC FILING David J. Collins, Executive Secretary Maryland Public Service Commission William Donald Schaefer Tower 6 St. Paul Street, 16 th Floor Baltimore, Maryland Re: Case No Electric Reliability Investment (ERI) Initiative Updated Report on 2017 Expansion of the Poorest Performing Feeders Program Dear Mr. Collins: Pursuant to the Letter Order that the Maryland Public Service Commission (the Commission ) issued on December 17, 2014 in Case No (Docket No. 90, Maillog No ), Baltimore Gas and Electric Company ( BGE ) files this updated report on the 2017 Expansion of the Poorest Performing Feeders Program (the Expansion of the PPF Program ). The Expansion of the PPF Program is one of the five Electric Reliability Investment ( ERI ) initiative programs that the Commission authorized BGE to recover through a surcharge mechanism, which went into effect on June 1, See Order No , Case No (December 13, 2013)(conditionally approving ERI initiative for cost recovery through a surcharge mechanism). I. Introduction On or about March 6, 2017, BGE completed its field inspection work of the feeders selected for inclusion in the 2017 Expansion of the PPF Program. As required by the Commission s December 17, 2014 Letter Order, this report contains updated feeder-specific work plans, milestones, cost estimates, and projected performance benefits. In addition, BGE has recalculated the 2017 ERI initiative revenue requirement using the updated cost information for the 2017 Expansion of the PPF Program included in this report. Based upon the results of this recalculation, BGE recommends updating the ERI initiative surcharge rates effective May 1, 2017, which would result in a monthly charge for the average residential customer using 925 kwh per month that is $.02 less than the current residential ERI surcharge rate.

2 David J. Collins, Executive Secretary April 3, 2017 Page 2 II. Updated Report on the 2017 Expansion of the PPF Program A. Scope of Work and Feeder-Specific Work Plans In compliance with Code of Maryland Regulation ( COMAR ) , BGE files an annual report with the Commission that includes a list of three percent (3%) of the electric distribution feeders on BGE s system that it has identified as having the poorest feeder reliability. As further required by COMAR, BGE targets the feeders on this list for reasonable remediation measures to improve the feeder performance level. BGE s Expansion of the PPF Program will double the number of feeders identified by BGE as part of the COMAR base requirements; thus, each year during the ERI initiative, BGE will target a total of six percent (6%) of the electric distribution feeders on its system for reasonable remediation measures to improve the feeder performance level. Additional details regarding the 2017 Expansion of the PPF Program, including the feeder selection process, are in BGE s November 1, 2016 ERI initiative compliance filing and throughout the record in Case No See Maillog No ; see generally Case No The type and extent of remediation measures that BGE will perform on each of the feeders included in the 2017 Expansion of the PPF Program depends upon a number of factors, including, but not limited to, feeder configuration, feeder conditions, reliability history, and cost. In determining the appropriate remediation measures to complete, BGE analyzes each feeder s configuration and reliability data, considers improvements already planned, and performs a field inspection if the feeder meets certain criteria. 1 Feeder remediation measures that BGE will perform as part of the 2017 Expansion of the PPF Program include additions, replacements, and/or enhancements of: Wildlife Protection (e.g., missing and defective) Fuses, Cut-outs, Brackets (e.g., obsolete and defective; new fuse locations) Insulation (e.g., cracked, broken, missing) Guy Wire and Accessories (e.g., broken, missing, obsolete, excessive corrosion) Lightning Arresters (L/A) (e.g., missing and defective) Equipment (e.g., defective or broken overhead transformers, transformer leads, leaking and flashed pothead, and other associated accessories) Cross-Arms (e.g., defective or broken; includes 8 cross arms, 10ʹ cross arms, 12ʹcross arms and associated components) 1 Feeders where the cause of more than half of the interruptions in 2016 were attributed to Underground Conductor, Underground Equipment, Public Interference, or Vegetation were not subject to a visual field inspected in 2017 because such causes are enough to determine proper remediation. A feeder was also not inspected visually if the sum of interruptions by these causes totaled more than 75% of the feeder s interruptions.

3 Poles (e.g., defective, rotten, leaning, needs to be guyed) David J. Collins, Executive Secretary April 3, 2017 Page 3 Distribution Automation ( DA ) Reclosers, Vacuum Load Hydraulic ( VL ) Reclosers, TripSaver-II ( TS ) Devices, and Electronic Resettable Sectionalizers ( ERS ) 2 Miscellaneous Equipment (i.e., all other categories not belonging to one of the above including, but not limited to, loose or damaged primary/tie wire, phase floating, broken spacer (narrow construction), frayed neutral wire, floating phase/wire off insulator, loose single phase pin top, and missing ground wires) As part of the Expansion of the PPF Program, BGE also inspects the overhead equipment on the selected feeders to identify locations that may benefit from additional vegetation management work. This is an important part of addressing potential reliability issues, since vegetation interference with overhead lines and equipment represents the highest cause of overhead outages on the distribution system. Once locations are identified, BGE performs surgical trimming, which primarily consists of removing all overhanging branches of weakwooded species from above the lines of all three-phase feeder mains in open wire configurations. Surgical trimming benefits customers by reducing the number of sustained customer interruptions caused by tree-related outages. As mentioned previously, on or about March 6, 2017, BGE completed field inspections for twenty (20) of the forty (40) feeders that were selected for inclusion in the 2017 Expansion of the PPF Program. All forty (40) feeders also underwent vegetation inspections. Based upon the field inspections, overhead vegetation inspections, and other analysis performed by BGE, a work plan was prepared for each of the forty (40) feeders. The following Table 1 summarizes the feeder-specific work plans: 2 13kV DA Reclosers are protective devices installed on the feeder main. DA Reclosers reduce the number of sustained customer interruptions experienced after a fault on the main by automatically restoring healthy portions of the feeder. Beginning in 2016, in addition to OH DA Reclosers, BGE also began evaluating feeders for padmounted DA Reclosers under the Expansion of the PPF Program to help improve its underground system reliability. BGE did not identify any opportunities to deploy pad-mounted DA Reclosers as part of the 2017 Expansion of the PPF Program. VL Reclosers are hydraulically controlled reclosers installed in single, two, and three-phase configuration on feeder taps and laterals. The primary purpose of a VL Recloser is to turn sustained outages into momentary outages by providing fault isolation and reclosing capability on taps and laterals. TS Devices are functionally similar to VL Reclosers, with the exception that they can be mounted on fuse cut-outs. TS Devices are ideally suited for lateral and tap circuits that frequently experience momentary fault interruptions. An ERS is a single-phase electronic device that can isolate faults on 13kV feeders. The primary purpose of an ERS is to turn sustained outages into momentary outages by enabling upstream recloser fast trips to more effectively clear temporary faults.

4 David J. Collins, Executive Secretary April 3, 2017 Page 4 Table 1: 2017 Expansion of the PPF Program Feeder-Specific Work Plans Quantity / Units of Equipment Renewal and Enhancements Feeders W/L Fuse / Cross- DA / Fuse / TS Insul. L/A Poles Misc. C/O Arms / ERS / VL VM Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Y Total N/A

5 David J. Collins, Executive Secretary April 3, 2017 Page 5 Notwithstanding the above-described work plans for the feeders, a number of circumstances could arise in the field or as a result of additional review and analysis that may require certain variances to the work plans. This is primarily due to the fact that during the period between developing the work plans and commencing construction work, the condition of a feeder may change as a result of events on the system (e.g., storms). Construction crews in the field, therefore, may identify additional opportunities to enhance safety and reliability for customers while executing the work plans. Any variances to the work plans, however, are not anticipated to have any substantial impact on other aspects of the work plans, milestones, or cost estimates. B. Feeder-Specific Milestones and Cost Estimates As directed by the Commission in Order No and its December 17, 2014 Letter Order, BGE has developed a cost estimate and milestone schedule for each of the forty (40) feeders included in the 2017 Expansion of the PPF Program. As a whole, the 2017 Expansion of the PPF Program is now estimated to cost approximately $2.3 million, which is less than the $3.9 million estimated cost that BGE presented to the Commission in its November 1, 2016 compliance filing. Feeder-specific milestones and cost estimates for the 2017 Expansion of the PPF Program are set forth in the following Table 2: Table 2: 2017 Expansion of the PPF Program Feeder-Specific Milestones and Cost Estimates Feeder Milestones Estimated Expenditures Feeders Construction Complete Vegetation Management Complete Inspection Costs Construction Costs Corrective Maintenance Costs Enhanced VM Costs Total (Capital + O&M) / /2017 $3,000 $0 $32,000 $17,000 $52, / /2017 $3,000 $0 $29,000 $22,000 $54, /2017 $0 $0 $0 $25,000 $25, /2017 $0 $0 $0 $11,000 $11, /2017 $0 $0 $0 $43,000 $43, /2017 $0 $0 $0 $36,000 $36, /2017 $0 $0 $0 $20,000 $20, / /2017 $10,000 $0 $40,000 $32,000 $82, / $9,000 $0 $38,000 $0 $47, /2017 $0 $0 $0 $11,000 $11, / /2017 $6,000 $60,000 $22,000 $42,000 $130, / /2017 $9,000 $0 $57,000 $12,000 $78,000 3 Five (5) of the forty (40) feeders do not have any estimated expenditures in 2017 under the Expansion of the PPF Program based upon the results of the vegetation management inspections, evaluation of feeder outage history, and/or mitigation through other reliability enhancements. Regardless, these feeders are still subject to reliability improvement work under routine programs, and it is reasonable and appropriate to project that their reliability will still improve in the near future.

6 David J. Collins, Executive Secretary April 3, 2017 Page 6 Feeder Milestones Estimated Expenditures Feeders Construction Complete Vegetation Management Complete Inspection Costs Construction Costs Corrective Maintenance Costs Enhanced VM Costs Total (Capital + O&M) / /2017 $3,000 $0 $19,000 $12,000 $34, /2017 $0 $0 $0 $34,000 $34, / /2017 $4,000 $88,000 $26,000 $3,000 $121, / /2017 $4,000 $0 $28,000 $21,000 $53, / /2017 $3,000 $180,000 $18,000 $32,000 $233, / /2017 $1,000 $0 $12,000 $9,000 $22, / /2017 $2,000 $0 $19,000 $32,000 $53, $0 $0 $0 $0 $ / /2017 $0 $120,000 $0 $32,000 $152, / /2017 $0 $138,000 $0 $32,000 $170, / /2017 $1,000 $0 $5,000 $20,000 $26, $0 $0 $0 $0 $ /2017 $0 $0 $0 $30,000 $30, / $1,000 $0 $12,000 $0 $13, /2017 $0 $0 $0 $17,000 $17, / /2017 $10,000 $0 $41,000 $3,000 $54, / /2017 $0 $60,000 $0 $38,000 $98, / $1,000 $0 $12,000 $0 $13, $0 $0 $0 $0 $ $0 $0 $0 $0 $ / /2017 $4,000 $0 $41,000 $1,000 $46, / $0 $0 $8,000 $0 $8, / /2017 $0 $180,000 $0 $34,000 $214, /2017 $0 $0 $0 $14,000 $14, $0 $0 $0 $0 $ / /2017 $4,000 $120,000 $23,000 $19,000 $166, /2017 $0 $0 $0 $70,000 $70, / /2017 $3,000 $0 $10,000 $16,000 $29,000 $81,000 $946,000 $492,000 $740,000 $2,259,000 BGE developed the above-listed, feeder-specific cost estimates based upon the current work plan for each feeder. In calculating a feeder-specific cost estimate, BGE used the estimated average cost of completing each type of remediation measure that appears in the individual feeder work plan. Importantly, the actual cost of completing a specific remediation measure on a feeder will vary from location-to-location due to field conditions encountered during execution of the work. This is particularly so with a small sample size like an individual feeder, for which any variability has the potential to result in a significant discrepancy between the cost estimate and actual cost. When ultimately calculated at the program level, however, such variances typically average out. BGE expects the same to occur with respect to the 2017 Expansion of the PPF Program.

7 David J. Collins, Executive Secretary April 3, 2017 Page 7 C. Feeder-Specific Benefit Projections As directed by the Commission in its December 17, 2014 Letter Order, BGE has developed benefit projections for each of the forty (40) feeders included in the 2017 Expansion of the PPF Program. Such information is set forth in the following Table 3: Table 3: 2017 Expansion of the PPF Program Feeder-Specific Benefit Projections # 4 Feeder # Customers Average Excluding MOE 2016 Excluding MOE Projected Excluding MOE Served SAIFI SAIDI SAIFI SAIDI SAIFI SAIDI Feeder Nos were selected using all interruption data excluding major outage event interruption data, excluding planned outage data, and excluding substation event data. Feeder Nos were selected using all interruption including major outage event interruption data, excluding planned outage data, and excluding substation event data.

8 David J. Collins, Executive Secretary April 3, 2017 Page 8 # 4 Feeder # Customers Average Excluding MOE 2016 Excluding MOE Projected Excluding MOE Served SAIFI SAIDI SAIFI SAIDI SAIFI SAIDI Aggregate Performance of All 40 Feeders As BGE has discussed with the Commission on several occasions in connection with this matter, benefit projections on a feeder-specific level are subject to considerable variability. While the work that BGE will complete on these feeders under the 2017 Expansion of the PPF Program will mitigate a variety of historical reliability concerns, BGE cannot predict with any reasonable degree of certainty that a feeder will experience the same types and levels of outages in the future. Accordingly, it remains most appropriate to project and measure the benefits of the 2017 Expansion of the PPF Program on an aggregate basis. III. Updated 2017 Revenue Requirement and Rate Details BGE has recalculated the revenue requirement for the ERI initiative based upon the updated cost information for the 2017 Expansion of the PPF Program included in this report. The new 2017 revenue requirement is $7.3 million, which is $600,000 less than the 2017 revenue requirement calculated by BGE in its November 1, 2016 ERI initiative compliance filing. The following Table 4 includes a volumetric rate for each of the customer classes subject to the ERI initiative surcharge mechanism based upon this recalculated 2017 revenue requirement: Table 4: Recalculated 2017 ERI Initiative Volumetric Rates Customer Class Recalculated Rate effective Current Rate effective 5/1/2017 (per kwh) 1/1/2017 (per kwh) R RL G/GU GS GL/GLP P Attached as Appendices A, B, and C to this letter, respectively, are (1) detailed calculations for the recalculated 2017 revenue requirement, (2) detailed calculations for the recalculated 2017 volumetric rates for each customer class, and (3) Supplement 602 to P.S.C. Md. E-6, Rider 31 Electric Reliability Investment ( ERI ) initiative Charge.

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10 Appendix A

11 BALTIMORE GAS AND ELECTRIC SUMMARY OF ERI REVENUE REQUIREMENT 2017 Surcharge - April 2017 Update Poorest Performing 13 kv 34 kv Diverse Selective RATE BASE: Feeder Reclosers Reclosers Routing Undergrounding Total A Capital Expenditures Current Year $1.2 $0.0 $0.0 $9.2 $1.1 $11.5 B Capital Expenditures- Cumulative C Book Depreciation Rate 2.360% 2.360% 2.360% 2.360% 2.360% D = ((A * C)/12*11.5/2) + ((B - A) * C) Depreciation Expense- Book E Depreciation Reserve- Book F = B + E Book Basis G Deferred Income Tax H = (B + E + G) Rate Base I Average Rate Base J ROR (After Tax) 6.49% 6.49% 6.49% 6.49% 6.49% K = I * J Return on Rate Base L Conversion Factor 58.32% 58.32% 58.32% 58.32% 58.32% M = K / L Initial Revenue Requirement COSTS TO RECOVER: Operating Income Need N REVENUE REQUIREMENTS: Revenue Requirement O = (M + N) Plus: Estimated True-Up at December 31, Grand Total Revenue Requirement $7.3

12 Appendix B

13 BALTIMORE GAS AND ELECTRIC COMPANY ELECTRIC RELIABILITY INVESTMENT ("ERI") INITIATIVE CHARGE CALCULATION Step 1. Revenue Requirement ($ in millions) 2017 $ 6,900,000 Step 2. Basis for Allocating Revenue Requirement to Customer Classes 34 kv Percent Peak (NCP) of Total 1. Schedule R 3, % 2. Schedule RL % 3. Schedule G/GU % 4. Schedule GS % 5. Schedule GL/GLP 1, % 6. Schedule P % Total 7, % Step 3. Allocation of Revenue Requirement to Customer Classes (Multiply Step 1 X Step 2) Schedule R $ 3,327, Schedule RL 326, Schedule G/GU 623, Schedule GS 29, Schedule GL/GLP 1,661, Schedule P $ 931,563 6,900,000 Step Revenue Requirement True-Up Schedule R $ 189, Schedule RL $ 18, Schedule G/GU $ 35, Schedule GS $ 1, Schedule GL/GLP $ 94, Schedule P $ 53,144 $ 393,632 Step 5. Allocation of Revenue Requirement to Customer Classes (including True-Up) Schedule R $ 3,517, Schedule RL 345, Schedule G/GU 659, Schedule GS 30, Schedule GL/GLP 1,756, Schedule P $ 984,707 7,293,632 Step 6. Determination of Calendar Billing Determinants Billing Unit Jan - Dec Schedule R MWh 12,101, Schedule RL MWh 993, Schedule G/GU MWh 2,750, Schedule GS MWh 177, Schedule GL/GLP MWh 8,277, Schedule P MWh 5,325,913 Step 7. Monthly Surcharge Calculation (Divide Step 5 by Step 6) Billing Basis Jan - Dec Schedule R per kwh $ Schedule RL per kwh $ Schedule G/GU per kwh $ Schedule GS per kwh $ Schedule GL/GLP per kwh $ Schedule P per kwh $

14 Appendix C

15 108 Electric Retail Baltimore Gas and Electric Company 28. Small Generator Interconnection Standards Availability: For all residential and non-residential customers within the Company s service territory seeking to interconnect energy generation resources to the electric distribution system. In accordance with COMAR : Small Generator Interconnection Standards, the Company has established protocols for the communication, metering, and interconnection with customers who are seeking to install a generation resource. This protocol will ensure the proper engineering and compliance with local, regional, and national codes. Cost: The Customer will be charged in accordance with interconnection levels as determined by COMAR The following application fees apply: Level 1 - No charge; Level 2 - $50 plus $1 per kw of rated generating facility output; Level 3 - $100 plus $2 per kw of rated generating facility output; and Level 4 - $100 plus $2 per kw of rated generating facility output. Approval: After receiving a standard small generator interconnection agreement from the Company, the Customer will have the generation equipment installed and inspected by the local municipality. Upon receiving a certification of inspection from the municipality, the Customer will submit a certificate of completion to the Company. The company will then install the necessary meter equipment on the premises. The Company shall maintain a database to track the installation of new generation resources within the service territory and will submit reports to the Commission in accordance with COMAR Reserved for Future Use P.S.C. Md. E-6 (Suppl.564) Filed 04/29/15 Effective 06/01/15

16 Baltimore Gas and Electric Company Electric Retail Demand Resource Surcharge Distribution Customers receiving service under Schedules R, RL, G, GU, GS, GL P, or T are subject to a Demand Resource Surcharge. This Surcharge recovers the Contract for Difference payments and associated incremental costs incurred through the issuance of Requests for Proposals (Gap RFPs) as provided in Maryland Public Service Commission Order No in Case No. 9149, issued March 11, The Gap RFP secures a demand response resource commitment for the June 1, 2011 through May 31, 2016 power planning years with a two-year extension provision (June 1, 2016 May 31, 2018). Contracts awarded through the Gap RFP are structured as a Contract for Differences, where the contract price of the demand response resource is compared against the PJM Reliability Pricing Model clearing price and actual delivered capacity for each power planning year. This difference, along with any approved incremental costs, determines the total annual Surcharge amount. Once the annual Surcharge amount is determined, it is allocated proportionately based on each Schedule s Peak Load Contribution to the total peak load. A rate per kilowatt-hour is then derived based on each Schedule s forecasted sales for the planning year. Any imbalance between the actual costs and Surcharge amount shall be reconciled annually over the subsequent planning year. A final, one-time reconciliation shall be conducted upon termination of all Gap RFP contracts. The current Demand Resource Surcharges are available on the BGE website at Electric Reliability Investment Initiative Charge The Electric Reliability Investment ( ERI ) initiative Charge recovers certain expenditures approved during Case No. 9326, Order No or during future compliance filings. Calculation of Charge The ERI initiative Charge is calculated annually and is determined for each rate schedule by first allocating the revenue requirement (based on Eligible Costs as defined below) based on the NCP hourly peak loads (34 kv level) for each Schedule approved during Case No in Order No or any subsequent base rate case during the existence of Rider 31. The resulting amounts, plus any true-up amounts as determined below, are then divided by the estimated per kilowatt-hour billing determinants for each applicable Schedule. Details concerning the calculation of the ERI initiative Charge are filed with and approved by the Commission prior to their use in billing. The ERI initiative Charge shall be separately stated on the Customer s monthly electric bill. (Continued On Next Page) P.S.C. Md. E-6 (Suppl. 544) Filed 04/21/14 Effective 06/01/14

17 110 Electric Retail Baltimore Gas and Electric Company Rider 31 continued Rate Schedule Rate R RL G/GU GS GL P $ per kwh $ per kwh $ per kwh $ per kwh $ per kwh $ per kwh Eligible Costs The revenue requirement for the ERI initiative Charge is based on eligible costs incurred by the Company associated solely with ERI initiative projects filed and approved by the Commission each year. They include the following categories: a) Depreciation and amortization, b) Operation and maintenance costs, c) Earnings on the net investment as determined by applying the Company s most recent Electric authorized rate of return, adjusted for taxes, to the average investment balance net of deferred taxes, and d) Applicable taxes. True-up An annual true-up will be conducted to include: a) For each rate schedule, the Imbalance is the difference between cumulative costs eligible for recovery and revenues collected through the ERI initiative Charge each year. The estimated Imbalance includes the actual data available and 3 months of estimated data. An Imbalance is debited or credited against the costs eligible for recovery each year. During its disposition, an Imbalance accrues a return at the Company s most recent authorized electric system rate of return. Such rate is adjusted for taxes, when the Imbalance represents an under-collection of costs to the Company. P.S.C. Md. E-6 (Suppl ) Filed 11/01/201604/03/2017 Effective 01/01/201705/01/2017