Attachment

UTILITY COMMITTEE AGENDA MARCH 9, 2015 - 5:15 P.M. CITY HALL COUNCIL CHAMBERS 15 LOOCKERMAN PLAZA DOVER, DELAWARE PUBLIC COMMENTS ARE WELCOMED ON ANY ITEM AND WILL BE PERMITTED AT APPROPRIATE TIMES. WHEN POSSIBLE, PLEASE NOTIFY THE CITY CLERK (736-7008 OR E-MAIL AT CITYCLERK@DOVER.DE.US) SHOULD YOU WISH TO BE RECOGNIZED. AGENDA ADDITIONS/DELETIONS 1. ACCEPTANCE OF WASTEWATER FROM THE PROPOSED WINDING CREEK DEVELOPMENT (OUTSIDE CITY OF DOVER LIMITS) (STAFF RECOMMENDS AUTHORIZING THE CITY MANAGER TO ENTER INTO AN AGREEMENT TO ACCEPT WASTEWATER FROM THE WINDING CREEK DEVELOPMENT) 2. PROPOSAL TO PERFORM REVIEW AND UPDATE OF THE ELECTRIC SYSTEM FINANCIAL MODEL, COMPLETE COST OF SERVICE ANALYSIS, AND DEVELOP PROPOSED RATE ADJUSTMENTS (STAFF RECOMMENDS ACCEPTANCE OF THE BURNS & MCDONNELL GROUP PROPOSAL) 3. TEA/NAES REPORT (JANUARY) (STAFF RECOMMENDS ACCEPTANCE OF THE REPORT) 4. GARRISON OAK TECHNICAL PARK PROJECT UPDATES (COMMITTEE ACTION NOT REQUIRED ON THE BELOW ITEMS) A. CITY INFRASTRUCTURE B. CALPINE ENERGY CENTER C. DOVER SUN PARK 5. ADJOURNMENT BY 5:55 P.M. /TM S:\AGENDAS-MINUTES-PACKETS-PRESENTATIONS-ATT&EXH\COMMITTEE-AGENDAS\2015\03-09-2015 UTILITY.WPD THE AGENDA ITEMS AS LISTED MAY NOT BE CONSIDERED IN SEQUENCE. THIS AGENDA IS SUBJECT TO CHANGE TO INCLUDE THE ADDITION OR THE DELETION OF ITEMS, INCLUDING EXECUTIVE SESSIONS.

ACTION FORM PROCEEDING: Utility Committee AGENDA ITEM: DEPARTMENT OF ORIGIN: Public Works DATE SUBMITTED: 02/27/15 PREPARED BY: Sharon J. Duca, P.E., Public Works Director / City Engineer SUBJECT: Acceptance of Wastewater – Winding Creek Development (Outside of City Limits) REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager EXHIBITS: 1)Aerial Exhibit, 2)Rates & Tariff EXPENDITURE REQUIRED: $ N/A AMOUNT BUDGETED: $ N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIME TABLE: Agreement with Developer will be created upon action by City Council. RECOMMENDED ACTION: Granting authorization to the City Manager to enter into an agreement to accept wastewater from Winding Creek Development BACKGROUND AND ANALYSIS Winding Creek Delaware, LLC, is proposing to construct a new 208 unit residential community west of the City of Dover. Kent County prefers a central disposal methodology, as opposed to on-site solution within the development. To meet the requests of the County it is proposed to provide wastewater service is through an on-site pump station that will send the effluent to the City of Dover wastewater system. A technical feasibility study was conducted by Morris & Ritchie Associates, Inc. (Consulting Engineer) which evaluated the impacts of the projected sewage flow on the existing sanitary sewer system that is owned by the City of Dover and operated by the Department of Public Works. Staff reviewed the technical feasibility study and has required improvements to existing infrastructure to be made by the developer of the residential community. Said improvements will be the sole financial responsibility of the developer. All system improvements must be complete, operational and approved by the City prior to accepting wastewater flow from the community. Additionally, a legal agreement must be finalized between the City of Dover and Winding Creek Delaware, LLC with respect to service rates and impact fees. According to the Kent County Department of Public Works, the amount of wastewater produced by this development can be assimilated into the current allocations under the current Contract User Agreement with Kent County. Due to the above, the City of Dover Department of Public Works recommends acceptance of wastewater from the proposed Winding Creek development and that City Council grant authorization to the City Manager to enter into an agreement with Winding Creek Delaware, LLC. Estimated Fiscal Impact (208-unit Residential Community) using current out-of-city rates & fees: Impact Fees: $6,184.00 / E.D.U. ($2,100 COD Water, $1,900 COD Sewer, $2,080 KC Sewer, $104 COD Admin Fee) X 208 units = $1,286,272.00 (To be received over a 5-7 year period) - $853,632 to the City of Dover; balance to K.C. Estimated Monthly Sewer Bill: 208 units X 7 Tgals/month = 1,456 Tgals X $7.82 / Tgals = $11,385.92 + $2.50 = $11,388.42 Estimated Monthly Expenses: 1,456 Tgals X ($2.34 + $1.50 + $2.45 / Tgals) = $9,158.24 Estimated Net Revenue: $11,388.42 - $9,158.24 = $2,230.18 per month at full build-out

City of Dover

ACTION FORM PROCEEDING: Utility Committee Meeting DATE: March 9, 2015 DEPARTMENT OF ORIGIN: Finance Department DATE SUBMITTED: 02/27/15 PREPARED BY: Scott Koenig, City Manager & Donna Mitchell, Controller/Treasurer SUBJECT: Electric – Cost of Service & Rate Design Study REFERENCE: N/A RELATED PROJECT: FY16 Budget & Five Year Forecast APPROVALS: Committee/Council EXHIBITS: N/A EXPENDITURE REQUIRED: $28,500 TIMETABLE: To Be Completed by May 4, 2015 RECOMMENDED ACTION: As outlined in the attached proposal, staff recommends the Cost of Service and Rate Design Study for FY 16 by the Burns & McDonnell Group. In light of recent changes in the City’s power supply requirements, staff is recommending an update to the electric rate study and forecast by Burns & McDonnell under the continuity of service provision of the purchasing policy. A copy of the proposal that outlines the scope of service is attached for further review. These changes are as listed below: 1. The changes in the load profile for NRG created revenue shortfalls in FY14. The cost of service rate was previously developed on a lower load and demand profile than they are using today. 2. The forecasted load is flat, therefore rates will need to be adjusted to pick up the fixed cost not being covered. 3. PJM has made recent changes to the capacity performance rules. (A presentation is planned for March 23 to review with the Utility Committee these changes) 4. PJM is now requiring more oil inventory due to last year’s polar vortex. 5. The City’s commercial rates are not competitive with other public power suppliers in the State and staff is requesting cost of service allocations be validated and updated. The fee proposed by Burns & McDonnell is the same fee that was paid in the last full cost of service analysis in 2012.

February 26, 2015 Ms. Donna S. Mitchell, CPA Controller/Treasurer City of Dover 5 East Reed Street Weydandt Hall, Suite 300 Dover, DE 19901 Subject: Proposal to Perform Review and Update of the Electric System Financial Model, Complete Cost of Service Analysis, and Develop Proposed Rate Adjustments Dear Ms. Mitchell: Burns & McDonnell is pleased to submit this letter proposal to perform a review and update of the Dover Electric System financial forecasts and assist with rate development for implementation in Fiscal Year (FY) 2016. Burns & McDonnell is prepared to complete a review of the FY 2015 Electric System financial forecast initially updated by the City of Dover then prepare an update of the cost of service analysis. Once these efforts are completed, we will perform rate development utilizing the most recently developed cost-of-service analysis. Scope of Work The major elements of the proposed Scope of Work include review of the financial forecast for 2015 and the subsequent four years, incorporating the resulting test year data in the most recently completed cost- of-service allocations, and review of the resulting cost based electric rates resulting from the financial forecast and cost-of-service elements of the spreadsheet model. The major elements of the proposed Scope of Work include the following: 1. Review and Update Financial Forecast 2. Update Cost-of-Service Analysis 3. Review Electric Rates and Prepare Necessary Revisions Review Financial Forecast Burns & McDonnell will review the financial forecast model initially updated by the City. The financial forecast is utilized to determine the adequacy of revenues for a five-year forecast period. The updated financial forecast includes projections of annual revenues under existing rates and the annual revenue requirement, including purchased power costs, all operating expenses, capital requirements, debt service requirements, and reserve requirements, by year for the forecast period. The financial forecast model identifies the overall change in revenue required to provide for adequate funding for capital improvement programs, to meet all recurring annual operating and capital expenditures, to cover all debt service requirements, and to maintain sufficient cash balances and capital reserves. Prior to finalization of the financial forecast model, the City and Burns & McDonnell will agree on the updated financial forecast model results and the assessment of estimated impacts on the revenue requirements of the Electric System. Burns & McDonnell and the City will conduct a conference call to review the model results and discuss any necessary revisions. 9400 Ward Parkway \ Kansas City, MO 64114 O 816-333-9400 \ F 816-333-3690 \ burnsmcd.com

Donna S. Mitchell City of Dover February 26, 2015 Page 2 Update Cost-of-Service Analysis Burns & McDonnell will next incorporate the updated test year data resulting from the financial forecast into the cost-of-service analysis model previously prepared by Burns & McDonnell in the last rate study update completed for the City. This analysis will be completed using FY 2016 as the test year. The cost- of-service analysis will include the development of updated allocation factors based on Dover data and assumptions, as appropriate, which will serve as the bases for functionalizing and unbundling of costs. Prior to finalization of the cost-of-service analysis, the City and Burns & McDonnell will discuss and agree on the revisions to the model based on the FY 2016 test year and the assessment of estimated impacts on the cash flow of the Electric System. Burns & McDonnell and the City will discuss the cost- of-service analysis model in a meeting at the City’s offices. Review Electric Rates and Prepare Necessary Revisions Burns & McDonnell will update the rate model to reflect the financial forecast and cost-of-service results. The update to the rate model will reflect the most recently completed fiscal year’s billing data. This billing data along with the rate model output will be reviewed by Burns & McDonnell to determine if the resulting rates would generate the necessary revenues as determined in the cost-of-service analysis model. If modifications are necessary for the resulting rates, Burns & McDonnell will develop rate revisions for consideration by the City. This phase of the Study will be the most demanding due to the specific objectives which must be met in the design of rates. This phase of the Study will require extensive communication and coordination with the City. Proposed Budget Burns & McDonnell proposes to perform the proposed services for a lump sum fee of $28,500. This fee is based on the required effort for completing the desired services. This fee includes expenses for one trip to Dover to review preliminary forecast results. If additional meetings in Dover are requested they can be completed for additional fees to cover time and expenses. Burns & McDonnell appreciates the opportunity to provide the City of Dover continued service in these important matters. Should you have any questions regarding the material presented herein please call Ted Kelly at (816) 822-3208. If this proposal for the review and update services is acceptable please indicate by signing below and returning one copy of the letter. Sincerely, BURNS & McDONNELL Jeffrey J. Greig Ted J. Kelly Senior Vice President Project Director JJG/TJK

Donna S. Mitchell City of Dover February 26, 2015 Page 3 Authorization for Model Review, Cost of Service Analysis, and Rate Development Services Accepted by:

The Energy Authority, Inc. Monthly Management Committee Update – January 2015 February 26, 2015 Prepared by: Robert Trinnear Client Services Manager 904.360.1309 rtrinnear@teainc.org

TABLE OF CONTENTS I. Executive Summary 1 II. Budget Report 12 III. Operations Management 15 IV. Appendix 29 i

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $42,952 above budget driven by higher load. Dover’s budgeted cost for all power supply (capacity AND energy) was $75.82/MWh. The actual cost of all power supply (capacity AND energy) was $70.86/MWh. The positive $4.96 budget variance was driven by PJM fees. The cost of energy alone was $50.26/MWh, versus a budgeted energy cost of $48.29 driven by higher market prices. Dover’s hedge purchases totaled 50,040 MWh, which was 75% of the actual load. The budgeted hedge purchase totaled 33,624, which was 55% of the budgeted load. Dover’s power purchases from hedge transactions totaled $2,298,382. Purchases from PJM (energy and fees) totaled $1,419,876. This number includes DA spot market energy charges of $596,388 and Network Integration Transmission Service charges of $397,786. Reactive Services charges were $2,528. Dover’s total load was 66,380 MWh versus a forecasted load of 61,473 MWh. Dover’s planned energy purchase from the SunPark solar installation was 922 MWh. Dover’s actual energy purchase from the SunPark installation was 695 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 61,473 66,380 (4,908) Wholesale Load 60,551 65,685 (5,135) Hedged Volume (MWh) 33,624 50,040 (16,416) Unhedged Volume (MWh) 26,927 15,645 11,281 Dover SunPark Volume (MWh) 922 695 227 Renewable Energy Credits Volume 138 71 67 Hedged Cost ($/MWh) $ 48.76 $ 45.93 $ 2.83 Unhedged Energy Cost ($/MWh) $ 45.41 $ 61.19 $ (15.78) Solar Energy Cost ($/MWh) $ 115.12 $ 115.93 $ (0.81) Energy Costs ($/MWh) $48.29 $50.26 ($1.97) All-in Costs - Energy, Capacity and RECs ($/MWh) $75.82 $70.86 $4.96 2

B. Generation Summary: Dover generated 0 MWh in the month. Net generation revenue was $370,223 vs. a budget of $464,214. 3

Generation Breakdown: City of Dover Monthly Wholesale Generation Formula January 2015 Net Generation 0.00 D Production Margin PJM - Generation Economic and Reliability Dispatch $ - A Natural Gas & Oil Consumption Purchases for Generation $ - Natural Gas Transport $ - Eastern Shore Cashout $ - Oil Consumption $ - Subtotal: Natural Gas & Oil Consumption $ - B Gross Production Margin $ - C = (A + B) $/MWh Generation Production Gross Margin $ - E = (C/D) PJM - Capacity Generation Capacity Credit $ 725,758.98 Reactive Supply and Transmission Losses $ 64,547.72 Subtotal: PJM - Capacity $ 790,306.70 F All in Generation Margin All in Generation Margin Total $ 790,306.70 (G = C + F) 4

C. Emissions Summary: Emissions Allowance Summary through January 31, 2015 Due to a series of federal court decisions discussed in previous monthly reports, beginning January 1, 2015 the reinstated CSAPR replaces CAIR. The final CAIR true- ups for 2014 will occur in 2015, after which CAIR allowances will have no value. EPA CAMD will remove all post-2014 CAIR allowances from the Allowance Tracking System on March 3, 2015. While Delaware was included in the CAIR footprint, it is not included in the CSAPR footprint. CAIR allowances cannot be used for CSAPR compliance. A separate Clean Air Act acid rain deposition control program governs the Clean Air Act Title IV SO2 national allowance trading program, and this will remain in effect, however the CAIR provisions for SO2 have been eliminated for sources in Delaware. Starting with this month’s report, the detailed history of CAIR allowances has been removed. The table below presents estimated market value for residual CAIR NOx allowances and the Title IV SO2 allowances. Market prices were provided by Evolution Markets (http://www.evomarkets.com/) and Bloomberg Finance L.P. Mark Value for CAIR Allowances Commodity $/Ton Tons Market Value February, 2015 SO2 Allowances – Title IV $0.375 15,028 $ 5,635 NOx Allowances - Seasonal $0.001 99 0 NOx Allowances - Annual $ 3.75 201 754 TOTAL $ 6,389 Regional Greenhouse Gas Initiative The State of Delaware is a participant in the Regional Greenhouse Gas Initiative (RGGI). The City of Dover must comply with RGGI by surrendering carbon dioxide (CO2) allowances pursuant to the State of Delaware’s laws (Title 7, Chapter 60, Sub-Title II-A). Delaware adopted a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. 1 No ICE or Broker price was available for seasonal NOx allowances 5

Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). CO2 Allowance Summary (1/31/2015) 1 2 3 4 5 6 7 8 CO2 CO2 Allowances Annual CO2 Allowances (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance (Sold) Prior to Sale) CO2 Vintage Purchased Allowances Emitted Allowance Balance McKee Balance YTD VanSant Run 2009 0 60,128 2,056 62,184 (5,796) 56,388 56,388 2010 0 48,102 1,645 49,747 (32,971) 16,776 73,164 2 2011 0 36,077 1,234 37,311 (17,746) 19,565 92,729 2012 0 27,058 925 27,983 ( 15,957) 12,026 104,755 2013 0 22,879 1,939 24,818 (10,231) 14,587 119,343 2014 1,000 -0- -0- -0- (25,426) (25,426) 94,917 2015 -0- -0- -0- -0- -0- -0- 94,917 Dover no longer receives allocations of RGGI allowances (columns 3-5). The cumulative balance can be utilized for generation in 2014 and future years. Note that the 2014 emissions were larger than four out of the last five years. Once the banked allowances have been fully utilized, Dover will be required to purchase RGGI allowances through the auctions or through over-the-counter markets. Assuming that Dover does not sell any banked allowances and produces 25,000 tons of CO2 emissions annually, it should be able to maintain a positive balance through around 2018. In anticipation of needing additional RGGI allowances in the future, Dover participated in Auction 26 held on December 3, 2014. It submitted a tiered bid totaling 4,000 allowances. It was awarded 1,000 allowances from its highest price bid, with the auction clearing price of $5.21/ton. Based on the February 20, 2015 ICE price for the February 2015 strip ($5.59/ton), the estimated market value of Dover’s existing 94,917 ton RGGI allowance bank is $530,586. 2 2011 and 2012 emissions corrected to match values in RGGI COATS. 6

Renewable Energy Certificates Dover owns two photovoltaic systems totaling 15 kW, consisting of (one 5 kW unit at the Utilities Administration Building and two 5 kW units at the McKee Run generating station. Dover also receives solar energy produced by the 10 MW Dover Sun Park which is owned by White Oak Solar Energy, LLC. In addition to the all of the physical energy produced by the Sun Park, Dover receives 15% of Sun Park’s Solar Renewable Energy Credits (SRECS). Dover participates in the Delaware Municipal Electric Corporation’s (DEMEC) Renewable Portfolio Standard (RPS) for compliance with the State of Delaware’s RPS laws applicable to municipal utilities. The first compliance period under DEMEC’s RPS was for the 36 months ending May 2014. Through the end of December, 2014, Dover had accumulated a total of 6,479 SRECS from these renewable energy resources, net of 2,941 SREC transferred to DEMEC for retirement on October 3, 2014 in accordance with the RPS requirement for the first compliance period. While Delaware does periodically hold auctions for SRECs, these auctions are for size tiers N1 – N3, E1 and E2. The Dover Sun Park is in the N4 tier for very large facilities. State-wide carve outs for Tier 4 has been fully subscribed, so there is not a market for tier 4 SRECs in Delaware. The nearest viable market for Dover’s SRECs is Pennsylvania. Daily settlement prices from Flett Exchange Environmental services (www.flettexchange.com) were used for 2011/12 through 2014/15 vintage allowances. The February 19, 2015 daily settlement prices for Pennsylvania SRECS are used in the table below. SREC Vintage Market Clearing Price SREC Balance3 Market Value (June 1 – May 31) 2012/2013 $30.00 2,172 65,160 2013/2014 $35.00 2,701 94,535 2014/2015 $40.00 1,606 64,240 TOTAL 6,479 $222,935 TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard (RPS). Additionally, Dover will need to acquire additional SRECs in future years. 3 SREC Balances have been corrected in this monthly report 7

D. Operations Management Summary: During the month of January, there was one reportable lost time accidents when an employee slipped on a patch of ice resulting in a broken ankle. The facility has now gone 19 days without an OSHA recordable accident and 19 consecutive days without a lost time reportable accident. There were no Environmental Notices of Violations or exceedances issued. There were no near misses reported.. There were no unit dispatches during the month for PJM and there were no self- scheduled unit operations. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of January were $420,084 against a budgeted amount of $436,781 for a favorable variance of $16,697 or 3.82%. The principal reasons for the favorable variance were due to having lower payroll expenses, lower water usage expenses and lower permit fees than budgeted. E. Risk Management Summary: Forward power prices in PJM have increased from last month. The current projected cost of service is below: Blended Monthly Cost Change PY Hedge Ratio ($/MWh) ($/MWh) 2014-15 80% $ 46.69 $ 0.36 2015-16 69% $ 43.71 $ 0.46 2016-17 45% $ 42.37 $ 0.51 2017-18 34% $ 42.77 $ 0.70 2018-19 19% $ 42.67 $ 0.98 8

II. Budget Report Budget Actual Variance Jan-15 Jan-15 Gross Load 61,473 66,380 (4,908) Power Supply Hedged Energy $1,639,421 $2,298,382 ($658,961) PJM - Energy, Congestion & Losses $1,222,841 $957,382 $265,459 PJM - ARR, Transmission and Fees $769,244 $462,494 $306,750 Dover SUN Park Energy $106,137 $80,567 $25,570 Dover SUN Park RECs $16,690 $9,828 $6,862 Management Fees $83,000 $83,000 $0 PJM - Capacity UCAP Obligated Purchased $823,464 $812,097 $11,367 Subtotal - Power Supply $4,660,797 $4,703,749 ($42,952) Power Generation O&M Plant O&M $436,781 $420,084 $16,697 Subtotal Generation O&M 436,781.00 420,084.00 $16,697 Power Generation Production Margin PJM - Economic and reliability dispatch ($446,560) $ - ($446,560) Fixed Fuel and Transport Charges $322,150 $ - $322,150 Subtotal Generation Production Margin ($124,410) $ - ($124,410) Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($740,515) $ (725,758.98) ($14,756) Capacity Replacement Charge $11,160 $ - $11,160 PJM - Reactive Supply & Transmission Losses ($47,230) $ (64,547.72) $17,318 Subtotal - Non-Production Revenue ($776,585) ($790,307) $13,722 SubTotal - All Generation (464,214) ($370,223) ($93,991) Total - Utilities Cost $4,196,583 $4,333,526 ($136,943) Unit Costs Total - Power Supply $75.82 $70.86 $4.96 Total - Power Generation ($7.55) ($5.58) ($1.97) Final Cost of Service to City of Dover Ratepayers $68.27 $65.28 $2.98 9

Variance Analysis: Power Supply  Dover consumed 4,908 MWh more than forecast for the month.  PJM transmission and fees were lower than expected with minimal monthly reactive services charges.  This resulted in a net power supply cost of $70.86/MWh, $4.96/MWh below budget.  For the month, the city realized an unfavorable variance of $42,952 for power supply vs. the monthly budget.  Dover Sun Park generated 227 MWh less than forecast. Generation  Power generation had an unfavorable budget variance of $93,991.  Plant O&M expenses had a favorable budget variance of $16,697 for the month. 10

Budget Actual Variance YTD YTD Source Formula G = (Net PJM PJM load Inschedules + Wholesale Load + White Oak-Dover Dover SunPark Gross Load 449,367 447,785 1,582 invoice Mwh) Power Supply TEA Deal capture system, verified by settlement checking out Hedged Energy $12,909,112 $16,173,152 ($3,264,040) with counterparties PJM - Energy, Congestion & Losses $7,667,455 $4,159,292 $3,508,163 PJM Invoice PJM - ARR, Transmission and Fees $4,466,711 $3,232,407 $1,234,304 PJM WhiteInvoice Oak-Dover Dover SUN Park Energy $1,018,777 $1,049,763 ($30,986) Invoice Dover SUN Park RECs $218,630 $232,248 ($13,618) White Oak-Dover Management Fees $581,000 $581,000 $0 Annual Contract PJM - Capacity UCAP Obligated Purchased $5,711,123 $5,617,031 $94,092 PJM Invoice Subtotal - Power Supply $32,572,808 $31,044,893 $1,527,915 A Power Generation O&M Plant O&M $3,362,817 $3,587,593 ($224,776) Monthly NAES report Subtotal Generation O&M $3,362,817 $3,587,593 ($224,776) B Power Generation Production Margin PJM - Economic and reliability dispatch ($1,786,240) ($1,946,803) $160,563 PJM Invoice Fixed Fuel and Transport Charges TEA Deal capture system, verified by settlement checking out with counterparties and $1,288,950 $991,866 $297,084 pipeline. Subtotal Generation Production Margin ($497,290) ($954,937) $457,647 C Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($5,135,827) ($5,024,547) ($111,280) PJM Invoice Budgeted amount for incremental 3.6 mw purchase. Actuals been shown in PJM - Capacity UCAP Obligated Capacity Replacement Charge $77,400 $0 $77,400 purchased. PJM - Reactive Supply & Transmission Losses ($283,200) ($391,354) $108,154 PJM Invoice Subtotal - Non-Production Revenue ($5,341,627) ($5,415,901) $74,274 D SubTotal - All Generation ($2,476,100) ($2,783,244) $307,144 E = (B+C+D) Total - Utilities Cost $30,096,708 $28,261,648 $1,835,060 F = (A+E) Unit Costs Total - Power Supply $72.49 $69.33 $3.16 H = (A/G) Total - Power Generation ($5.51) ($6.22) $0.71 I = (E/G) Final Cost of Service to City of Dover Ratepayers $66.98 $63.11 $3.86 J =( H+I) 11

Operations Management NAES Corporation Dover, Delaware January 2015 Monthly Report Sarah Maher, new Administrative Assistant, is adapting well to her new duties. 12

Table of Contents 1.0 Environmental, Health, and Safety 2.0 Financial 3.0 Operations 4.0 Maintenance 5.0 CIP 6.0 General Plant Information 7.0 Summary of NAES Performance 13

1.0 Environmental, Health and Safety: During the month of January, there was one lost time accident on January 12, 2015. The loss time accident occurred while an Operator was conducting routine inspections at the VanSant Generation Station. The Operator stepped onto a concrete sidewalk on the northern side of the DI Building and slipped on a thin veneer of ice. His left leg slid out from under him and he landed on his back. The operator was later diagnosed with a fractured lower ankle. The facility has now gone 19 days through January 31, 2015 without an OSHA Recordable Accident or a Lost Time reportable accident. There were no Near Misses reported in January at McKee Run. The plant received no Notice of Violations (NOVs) during the month. McKee Run collected samples as part of the new NPDES permit. The pH, total recoverable iron and PCB-TMDL samples were submitted to a laboratory for analysis. The PCB samples are still being analyzed while the pH results were included on a revised December 2014 DMR. It was later determined the lab bottle-ware was not preserved according to lab standards and the total recoverable iron samples were deemed invalid. Additional sampling for total recoverable iron will be collected in the 1st quarter of 2015. The January DMR was submitted to DNREC for the McKee Run site with no NPDES exceedences. Since no units ran in January, there were no opacity deviations from any unit in January. During the month of January, there were no IWW discharges to the Kent County Public Works sewer system. There was no monthly sampling in January. The January SIU Report was submitted to Kent County Public Works. On January 30, 2015, McKee Run and VanSant submitted to DNREC the annual Water Allocation Report. This report documents the monthly well water usage for the entire year and monthly well depth measurements. On January 30, 2015, the annual Title V Certification Report was submitted to DNREC for the McKee Run and VanSant facilities. Concurrently, with the annual Title V Certification, McKee Run and VanSant submitted the Semi-Annual Certification from July 1, 2014 to December 31, 2014. Additionally, the VanSant Quarterly Opacity Report was submitted at the same time. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (January) (7/1/14-6/30/15) NOVs 0 0 Opacity Deviations 0 1 Environmental Deviations 0 0 OSHA Recordable 1 1 OSHA LTA's 1 1 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 12 Man Hours Worked 4,080.5 83,603.75 Date last OSHA Recordable 1/12/15 Date last Lost Time Accident 1/12/15 Days since last OSHA recordable 19 Days since last Lost Time Accident 19 14

CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant* Run McKee Run - Run* (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2013 and 160/78 9/8 earlier 2014 0 71/46 5/3 40/35 - 4/1 0/0 – 0/0 31/11 1/2 2015# NA NA NA NA NA NA NA Total NOx Allowance Balance 191/89 10/10 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. **Note – The facility transferred Ozone Season allowances to a third party. #Note – CSPAR replaces CAIR. Delaware is not in CSPAR program SO2 Allowances Summary SO2 Allowances Available SO2 Allowance SO2 Allowances (Per Unit, Prior to Sale & Total SO2 Tons Emitted– SO2 Allowances Vintage Sold - YTD Reconciliation) U3 and U11 YTD Balance* Unit #3 Unit #11 2013 and 0 10,365 690 2 11,053 earlier 2014 0 1850 138 1 1,987 2015 0 1850 138 0 1,988 Total SO2 Allowance Balance 15,028 *Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 15

CO2 Allowances Summary CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Bought/Sold Sale) Balance YTD McKee Run VanSant 2013 and 0 194,244 7,799 82,700* 119,343* earlier 2014 1,000** 0 0 25,426 (24,426) 2015 0 0 0 0 0 Total CO2 Allowance Balance 94,917 *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. **Note; 1,000 CO2 Tons Purchased in 2014 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 2014 0.4 0.6 35.0 0.8 36.8 2015 0.0 0.0 0.0 0.0 0.0 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 2014 0.8 1.1 39.8 3.7 45.4 2015 0.0 0.0 0.0 0.0 0.0 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 0.0 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 2014 0.0 0.0 0.4 0.6 1.0 2015 0.0 0.0 0.0 0.0 0.0 16

2.0 Financial Financial – Current Month Month – January Actual Budget Variance Personnel 250,616 260,000 9,384 Materials & Supplies 9,238 14,500 5,262 Administrative Expenses 160,230 162,281 2,051 Total $420,084 $436,781 $16,697 Financial – Fiscal Year to Date Number of Months – 7 Actual Budget Variance Personnel 1,808,411 1,921,200 112,789 Materials & Supplies 204,325 166,050 (38,275) Administrative Expenses 1,299,554 1,275,567 (23,987) Total $3,312,290 $3,362,817 $50,527 2.1 Variance analysis: The actual expenses for the month of January are $420,084 against a budgeted amount of $436,781 for a favorable variance of $16,697 or 3.82%. The variance was due to the following: PERSONNEL EXPENSES – A favorable monthly variance of $9,384 was due to having a less than full complement of staff and limited overtime expenses. As a result, this impacted three (3) labor accounts – Straight Time, Overtime, and Labor Burdens. MATERIALS AND SUPPLIES EXPENSES- A favorable monthly variance of $5,262 was due to lower water usage than budgeted. ADMINISTRATIVE EXPENSES – A favorable monthly variance of $2,051 due to lower permit fees than anticipated and annual fire protection systems inspections not yet completed. A portion of this was offset by higher than anticipated electricity costs. The forecasted expenses for this fiscal year are $6,116,273 expensed versus an approved budget of $6,141,100 thereby realizing a 99.60% expenditure rate. 17

3.0 Operations Unit Operations / Outages / Trips: No units were dispatched by PJM and none were self- dispatched for the month of January. All units were ready and available for dispatch if needed. Month - January 2015 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 0.0 0.0 0.0 0.0 0.0 0.0 Auxiliaries purchased MWh 36.412 36.412 187.283 260.107 8.282 268.389 Fuel Gas Used# MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 100.00 100.00 100.00 100.00 100.00 100.00 Commercial % 0.0 0.0 0.0 0.0 0.0 0.0 Unavailability (CU) Planned Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 744 744 737.000744 744.0002,232 497.000 744.000 744 744.0001,971.000 1,971.0002,976 744.000 744.000 737.000 1,971.0 737.00 Hours HW Boiler Gas Usage MMBTU 1,459 1,459 Pilot Gas Usage MMBTU 0.0 0.0 0.0 0.0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 18

2014-2015 Fiscal Year-to-Date (7 Months) McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 30.966 35.134 433.682 499.782 17.350 517.132 Starts # 3 5 33 41 5 46 Gross Generation MWh 261.694 252.941 22,525.426 23,040.061 578.081 23,618.142 Net Generation MWh 247.853 233.930 20,511.856 20,993.639 567.702 21,561.341 Total Auxiliaries MWh 212.429 217.599 3,633.922 4,063.950 24.705 4,088.655 Auxiliaries purchased MWh 198.588 198.588 1,670.472 2,067.648 24.326 2,091.974 Fuel Gas Used MMBTU 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 Net Heat Rate BTU/KWh 15.253 13.916 11.825 13.664 13.278 13.471 Unit Trips # 1 3 0 4 1 5 Capacity Factor % 0.28 0.27 3.90 2.94 0.28 2.35 Availability Factor % 70.70 70.70 65.90 69.10 70.70 69.50 Commercial % 0.0 0.0 0.15 0.05 0.0 0.04 Unavailability (CU) Planned Outage Hours Hours 1,512.000 1,512.000 1,752.000 4,776.000 1,512.000 6,288.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 7.667 7.667 0.0 7.667 Reserve Shutdown Hours 3,617.034 3,612.866 2,966.651 10,196.551 3,630.650 13,827.201 Hours HW Boiler Gas Usage MMBTU 3,480.856 3,480.856 Pilot Gas Usage MMBTU 527.631 527.631 1,055.263 1,055.263 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 14-15 Fuel FY 14-15 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (FYTD) (Change) McKee Run (#2 Fuel Oil) 722,625 722,625 0 0 452,963 279,528 269,662 VanSant 216,587 215,575 0 1,012 73,572 148,595 142,003 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through January 2015 Actual Starts Factored Starts Fired Hours VanSant 1372 2,349.75 4,333.90 Since HGP - Dec 2004 261 682.05 950.32 19

Team Report: Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both the Operations and Maintenance areas to assist with maintenance of the plant. Capacity Testing – FY 2014-2015 Summer 2014 (June 1- Aug 31) Winter 2014-2015 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.4 1 17 17* 2 17 17.5 2 17 17* 3 102 103.99 3 102 102* 11 39 39.8# 11 39 39* Total 175 175 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program. Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 20

4.0 Maintenance During the month of January, the Plant Maintenance staff continued addressing the backlog of work orders. There were sixty-four work orders issued with eighty work orders being completed during the month. There were three safety work orders entered into the plant’s Computerized Maintenance Management System (MP2) during the month. The table below summarizes the monthly work order activities. Work Order Report January - 2015 Outstanding From Issued This Completed Outstanding at the Priority # Previous Month Month This Month end of the month 1 39 11 20 30 2 47 9 12 44 3 53 1 9 45 4 5 0 1 4 5 12 5 0 17 SW1 0 3 0 3 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 85 35 38 82 EM 0 0 0 0 Totals 241 64 80 225 Note: PM Work Orders are included in the priority totals Notable activities during the month include: The NAES Maintenance staff fabricated four new screen holders/chutes for the Unit 3 cooling tower screens. Fabrication of new screens for the tower was the next order of business. The first one was fabricated and installed. The new screens will give provide an increased ability to catch any debris that might make its way to the pump thereby averting possible damage from debris entering the pump. The NAES IC&E staff assisted US Tank Protectors in completing the cathodic protection testing for the underground fuel oil lines at VanSant Generating Station. The testing was completed with no discrepancies found with the underground fuel oil lines. There were two minor items that need to be repaired on the testing stations. Work orders have been issued to make the repairs. The NAES IC&E Staff removed outdated fluorescent lighting in the DI area at the McKee Run Generating Station. The DI area was dark in several places making it difficult to monitor the operation of the water processing unit. The new lighting is also brighter thus making the DI area a safer place to work especially when working with chemicals. 21

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: All work planned is now complete. Spring activities include the replacement of the turbine supervisory equipment probes and panel and performing balancing of the turbine thereafter. EG1212 Unit 3 Turbine Repairs Schedule: Scheduling of work is in progress that will include the replacement of rotor expansion/vibration instrumentation and balancing of the turbine-generator. Progress: Contractor returned in January to complete work on remaining cells and finish punch list work for the three cells. Due to weather Unit #3 Cooling Tower EG1402 conditions, final checkout of tower is expected in February. Repairs Schedule: Final checkout of tower is expected in February along with final written report. Progress: Work is complete and final report has been received. McKee Run HEP Pipe EG1406 Schedule: Final report received and project may be expected to be closed Repairs once all invoicing has been submitted and paid. Progress: Project on Hold. Metering System Schedule: Project is on Hold until next year when RFP process will begin EG1407 Upgrades again. Project would be slated to be completed once Units 1 and 2 are taken out of service. Progress: The secondary breaker equipment and additional MCC equipment has been received and has been set in place on the foundations. Schedule: Coordination with electrical contractor to develop a timeline to VanSant Capacity EG1416 install the equipment and make tie-ins prior to the Spring Outage is in Increase place. Installation of electrical conduit and wiring is planned for February. Pipe and pipe materials are on order and will be received in February with installation to follow. Unit #3 Auxiliary Progress: Work scopes being developed for the Spring 2015 Outage. EG1503 System Component Schedule: Spring 2015 Outage work scopes being developed. Replacement Unit#3 Boiler System Progress: Work scopes being developed for the Spring 2015 Outage. EG1504 Schedule: Spring 2015 Outage work scopes being developed. Repairs VanSant Station Progress: Work scope is being deferred until next FY. EG1505 Component Schedule: Work scopes will continue to be developed for next fiscal year. Replacement Progress: Contract had been awarded; parts ordered and have been received. Some equipment has been installed. Unit 3 DC breaker for Unit McKee Run/VanSant 3 Emergency Lube oil Pump portion of project is complete. EG1506 Safety Improvements Schedule: Work is planned and has been scheduled for Spring Outage. Some work will require planned power outage to accomplish tie-in of circuitry and equipment. McKee Run Units #1-#2 Progress: Project on Hold EG1507 Component Schedule: Project on Hold Replacement 22

Progress: Plant staff completed development of paint specifications and bid requests were to be received in mid-August. McKee Run/VanSant EG1508 Schedule: Re-evaluation of work scope and bids is needed given the Structural Preservation amount of time since the bids were originally received. 6.0 General Plant Information Sarah Maher began work on December 15, 2014 in the position of Administrative Assistant. Since coming onboard, she has had many opportunities to meet plant staff and is readily adapting to her new work environment. On-going efforts are being made to fill two (2) open Operator positions. Several interviews have been held in this effort. Training: Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Be Safe on Ice”. Calendar of Events Date Winter Capacity Period December 1, 2014 to February 28, 2015 Title V Annual Certifications Due January 31, 2015 NOx Emissions Reconciliation Due March 1, 2015 SO2 Emissions Reconciliation Due March 1, 2015 SARA III / Tier II Report Due March 1, 2015 Units 1, 2, and 3 Spring Outage TBD – Spring 2015 Unit 11 Spring Outage TBD – Spring 2015 Air Emission Inventory April 30, 2015 NOx Ozone Season Starts May 1, 2015 PJM Summer Capacity Test Period June 1, 2015 – August 31, 2015 FY 2014-201454 Budget Year Begins July 1, 2015 Toxic Release Inventory (TRI) Annual Report July 1, 2015 Semi-Annual Title V Certification Due July 31, 2015 NOx Ozone Season Ends September 30, 2014 Annual VanSant Black Start Test TBD Units 1, 2, 3 and 11 Fall Outage Starts TBD Five Years Accident Free October 14, 2015 23

7.0 Summary of NAES Performance to Date Plant Performance FY 2014-2015 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.00% 0.05% $94,679 $96,875 Unavailability (CU) Safety 1 1 $9,082 $18,163 Environmental 0 0 $18,163 $18,163 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,634 $3,634 Unit 2 No No Yes Yes* $3,634 $3,634 Unit 3 No No Yes Yes* $21,797 $21,797 Unit 11 No No Yes Yes* $7,266 $7,266 Total YTD 93.35% Total YTD Incentive $158,254 $169,532 Incentive % Note*: All units have successfully completed the Summer (FY 2014-2015) Testing for PJM and are now entered in the PJM Winter Capacity Test Exemption Program. 24

III. Appendix 1 – PJM Invoice Breakdown Gen Load Grand Total 480-8102-592-95-49 1610 Locational Reliability $814,257.78 $814,257.78 2630 Capacity Transfer Rights $60.76 $60.76 2661 Capacity Resource Deficiency ($2,221.92) ($2,221.92) 480-8102-592-95-49 Total $812,096.62 $812,096.62 480-8102-592-95-50 1600 RPM Auction $14,753.52 $14,753.52 2600 RPM Auction ($740,512.50) ($740,512.50) 480-8102-592-95-50 Total ($725,758.98) ($725,758.98) 480-8102-592-95-90 1100 Network Integration Transmission Service $397,786.42 $397,786.42 1108 Transmission Enhancement $66,224.76 $66,224.76 1242 Day-Ahead Load Response Charge Allocation $170.98 $170.98 1243 Real-Time Load Response Charge Allocation $265.91 $265.91 1301 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $11,417.87 $11,417.87 1302 PJM Scheduling, System Control and Dispatch Service - FTR Administration $25.84 $25.84 1303 PJM Scheduling, System Control and Dispatch Service - Market Support $2,603.58 $2,603.58 1304 PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $79.71 $79.71 1305 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $952.63 $952.63 1306 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,396.00 $1,396.00 1307 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($296.92) ($296.92) 1313 PJM Settlement, Inc. $296.92 $296.92 1314 Market Monitoring Unit (MMU) Funding $327.59 $327.59 1315 FERC Annual Recovery $4,521.25 $4,521.25 1316 Organization of PJM States, Inc. (OPSI) Funding $50.60 $50.60 1317 North American Electric Reliability Corporation (NERC) $796.26 $796.26 1318 Reliability First Corporation (RFC) $1,295.65 $1,295.65 1320 Transmission Owner Scheduling, System Control and Dispatch Service $5,013.87 $5,013.87 1330 Reactive Supply and Voltage Control from Generation and Other Sources Service $35,413.55 $35,413.55 1340 Regulation and Frequency Response Service $11,650.21 $11,650.21 1360 Synchronized Reserve $11,092.65 $11,092.65 1362 Non-Synchronized Reserve $1,350.03 $1,350.03 1365 Day-ahead Scheduling Reserve $121.86 $121.86 1370 Day-ahead Operating Reserve $14,074.46 $14,074.46 1371 Day-ahead Operating Reserve for Load Response $17.12 $17.12 1375 Balancing Operating Reserve $10,580.39 $10,580.39 1376 Balancing Operating Reserve for Load Response ($0.20) ($0.20) 1378 Reactive Services $2,528.30 $2,528.30 1380 Black Start Service $1,899.46 $1,899.46 1730 Expansion Cost Recovery $403.00 $403.00 1911 Michigan - Ontario Interface Phase Angle Regulators $179.86 $179.86 1932 Generation Deactivation Refund ($632.17) ($632.17) 2108 Transmission Enhancement ($62,029.95) ($62,029.95) 2140 Non-Firm Point-to-Point Transmission Service ($1,417.06) ($1,417.06) 2420 Load Reconciliation for Transmission Losses ($366.82) ($366.82) 2510 Auction Revenue Rights ($54,971.37) ($54,971.37) 2666 Load Management Test Failure ($279.93) ($279.93) 2912 CT Lost Opportunity Cost Allocation ($48.36) ($48.36) 480-8102-592-95-90 Total $462,493.95 $462,493.95 480-8102-592-95-91 1200 Day-ahead Spot Market Energy $596,387.61 $596,387.61 1205 Balancing Spot Market Energy $68,475.28 $68,475.28 1210 Day-ahead Transmission Congestion $159,492.02 $159,492.02 1215 Balancing Transmission Congestion $7,845.36 $7,845.36 1220 Day-ahead Transmission Losses $88,288.18 $88,288.18 1225 Balancing Transmission Losses $3,908.73 $3,908.73 1230 Inadvertent Interchange $746.83 $746.83 1250 Meter Error Correction ($3,255.93) ($3,255.93) 1400 Load Reconciliation for Spot Market Energy $31,553.13 $31,553.13 1410 Load Reconciliation for Transmission Congestion $1,784.43 $1,784.43 1420 Load Reconciliation for Transmission Losses $1,480.58 $1,480.58 1430 Load Reconciliation for Inadvertent Interchange $3.88 $3.88 1440 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $175.28 $175.28 1441 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund ($24.02) ($24.02) 1442 Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $21.69 $21.69 1444 Load Reconciliation for Market Monitoring Unit (MMU) Funding $3.35 $3.35 1445 Load Reconciliation for FERC Annual Recovery $59.59 $59.59 1446 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $0.59 $0.59 1447 Load Reconciliation for North American Electric Reliability Corporation (NERC) $9.08 $9.08 1448 Load Reconciliation for Reliability First Corporation (RFC) $12.90 $12.90 1450 Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $63.07 $63.07 1460 Load Reconciliation for Regulation and Frequency Response Service $165.97 $165.97 1470 Load Reconciliation for Synchronized Reserve $42.88 $42.88 1472 Load Reconciliation for Non-Synchronized Reserve $5.22 $5.22 1475 Load Reconciliation for Day-ahead Scheduling Reserve $0.01 $0.01 1478 Load Reconciliation for Balancing Operating Reserve $26.19 $26.19 1490 Load Reconciliation for Reactive Services $109.77 $109.77 480-8102-592-95-91 Total $957,381.67 $957,381.67 480-8102-592-95-92 2220 Transmission Losses ($35,080.14) ($35,080.14) 2330 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) ($29,467.58) 480-8102-592-95-92 Total ($64,547.72) ($64,547.72) Grand Total $ (790,306.70) $ 2,231,972.24 $1,441,665.54 25

City of Dover Electric Revenue Fund FY15 - White Oak Solar Park Incremental Cost Original July August September October November December January YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 227,139 $ 219,981 $ 185,885 $ 140,672 $ 96,640 $ 54,849 $ 80,597 $ 1,005,762 $ 2,067,600 Dover Sun Park - REC's 47,469 42,307 33,221 25,192 17,303 9,828 - 175,320 378,600 Total Power Supply Cost 274,609 262,288 219,105 165,864 113,943 64,677 80,597 1,181,082 2,446,200 Non-Solar Power Supply Cost (170,970) (136,533) (97,948) (80,182) (63,893) (26,259) (48,916) (624,700) (777,547) Incremental Energy Cost $ 103,639 $ 125,755 $ 121,157 $ 85,682 $ 50,050 $ 38,418 $ 31,681 $ 556,381 $ 1,668,653 Revenues Customer Sales - Electricity (9,870) (8,024) (7,893) (7,840) (8,061) (8,135) (8,448) (58,271) (84,600) Rent Receipts (14,807) - - (14,807) - - (15,177) (44,792) (101,400) Total Revenues (24,677) (8,024) (7,893) (22,647) (8,061) (8,135) (23,625) (103,062) (186,000) Incremental Sun Park Cost $ 78,962 $ 117,731 $ 113,264 $ 63,034 $ 41,989 $ 30,283 $ 8,056 $ 453,319 $ 1,482,653 MWh Purchased/Generated - Solar 2,217.724 2,006.392 1,602.868 1,213.000 833.320 472.956 694.980 9,041.240 18,159.000 MWh $ Solar Energy $ 102.42 $ 109.64 $ 115.97 $ 115.97 $ 115.97 $ 115.97 $ 115.97 $ 111.24 $ 113.86 Solar REC's MWh 332.000 301.000 240.000 182.000 125.000 71.000 - 1,251.000 MWh $ Solar REC (one month lag)* 142.98 140.56 138.42 138.42 138.42 138.42 - $ - MWh $ Non-Solar Energy $ 77.09 $ 68.05 $ 61.11 $ 66.10 $ 76.67 $ 55.52 $ 70.38 Note: Solar REC's are one month behind due to the time the invoice is received.