Attachment

UTILITY COMMITTEE AGENDA DECEMBER 9, 2013 - 5:00 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. Service Agreement for the Natural Gas Distribution System in the Garrison Oak Technical Park (GOTP) - Chesapeake Utilities Corporation (Staff Recommends Authorizing the City Manager to Execute the Service Agreement with Chesapeake Utilities Corporation) 2. TEA/NAES Report (October) (Staff Recommends Acceptance of the Report) 3. Updates A. Calpine Energy Center (Committee Action Not Required) B. Dover Sun Park (Committee Action Not Required) C. Garrison Oak Technical Park Project (Committee Action Not Required) 4. Adjournment by 5:55 p.m. /tm S:\AGENDAS-MINUTES-PACKETS\Committee-Agendas\2013\12-09-2013 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 NO.: DEPARTMENT OF ORIGIN: City Manager’s Office DATE SUBMITTED: 12/02/2013 PREPARED BY: Scott D. Koenig, P.E., City Manager SUBJECT: Service Agreement for the Natural Gas Distribution System in the Garrison Oak Technical Park (GOTP) – Chesapeake Utilities Corporation REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: Controller EXHIBITS: Copy of the Draft Service Agreement EXPENDITURE REQUIRED: N/A AMOUNT BUDGETED: N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIMETABLE: As soon as possible. RECOMMENDED ACTION: Recommend to City Council to authorize the City Manager to execute the Service Agreement with Chesapeake Utilities Corporation for the Natural Gas Distribution System within the Garrison Oak Technical Park (GOTP). BACKGROUND AND ANALYSIS The City of Dover is acting as the developer of the Garrison Oak Technical Park. As the developer, we believe it will be advantageous to offer natural gas service to the various tenants in the industrial park. Therefore, we have requested that natural gas infrastructure be installed within the technical park so that it is available to potential purchasers and tenants. Attached is a standard service agreement submitted by Chesapeake Utilities which outlines the respective responsibilities of the City as well as Chesapeake Utilities. All costs to install the required infrastructure will be the responsibility of Chesapeake Utilities Corporation; however, the agreement includes a revenue shortfall calculation that the City of Dover would be responsible for should the revenues from the investment not be equal to or in excess of the initial capital investment within the first six (6) years after the effective date of the agreement. The maximum financial exposure to the City of Dover is estimated to be less than $130,000. Staff believes the provision of natural gas service throughout the Garrison Oak Technical Park will be a benefit to current and future tenants and recommends approval of the agreement.

Service Agreement for Natural Gas Distribution System This Agreement (“Agreement”) is made and entered into as of the ___ day of ___________, 2013 by and between The City of Dover, Delaware, a municipality of the State of Delaware (“Developer”) whose address is 15 Loockerman Plaza, Dover, DE, and Chesapeake Utilities Corporation, a Delaware corporation (“Company”) whose address is 350 South Queen Street, Dover, DE, 19904. RECITALS 1. Developer expects to promote development of a community named Garrison Oak Technical Park, consisting of, among other things, multiple commercial and industrial lots located in Dover, Delaware (the “Project”). 2. Company desires to install a natural gas distribution system within the areas of the Project and Developer has agreed to permit Company to install such a system within the Project pursuant to the terms and conditions hereinafter set forth. NOW, THEREFORE, in consideration of the mutual covenants set forth herein, and for other good and valuable considerations, the receipt and sufficiency of which are hereby acknowledged, Company and Developer hereby agree as follows. 1. Installation of Gas Distribution System. Company agrees to install a natural gas distribution system within such portion of the Project, including all necessary distribution lines, meters and ancillary facilities (collectively, the “Gas Distribution System”) necessary to provide natural gas service to all commercial facilities built in the Project (not to include any facilities that obtain natural gas delivery service from Eastern Shore Natural Gas Company). The location of the gas lines and all related infrastructure and improvements relating to the Gas Distribution System shall be subject to Developer’s express prior approval, which shall not be unreasonably withheld or delayed. Developer has provided Company a subdivision plan relating to the Project which is attached hereto as Exhibit A (reflecting lots, streets and easements), otherwise referred to as the “Plat.” To the extent such Plat does not cover the entire Project, Developer shall provide supplemental plat(s) to Company from time to time with respect to the remainder of the Project and such supplemental plats shall be incorporated into Exhibit A. Upon the completion of the installation of each portion of the Gas Distribution System, Company expressly agrees to restore the real property in the Project upon and within which such portion of the Gas Distribution System was installed to substantially the same condition existing prior to commencement of the installation of such portion of the Gas Distribution System. 2. Preparation for Installation and Easements. Developer agrees to provide adequate physical and legal access to the Project including recorded, assignable easements and/or rights of way to all

areas of the Project where any portion of the Gas Distribution System is to be installed. Developer shall grant to Company such easements on Developer’s property as are reasonably necessary for Company to construct and maintain the Gas Distribution System on or to the Project, provided (i) if Company causes damage to the easement area during construction and maintenance of the Gas Distribution System, Company agrees to restore the easement area so damaged to substantially the same condition prior to said construction and maintenance; and, (ii) the easements shall otherwise be in form and substance acceptable to Company. Developer agrees to provide Company with plats of the Project that indicate the locations of the easements and/or rights of way where portions of the Gas Distribution System are to be installed by Company. Company shall have the right to make copies of such plats at Company’s sole cost and expense. Company shall bear all costs related to the construction of the Gas Distribution System. Developer reserves the right to relocate any easement granted to Company if necessary for the development of the Project in Developer’s determination, provided that the portion of the Gas Distribution System subject to such revised easements has not yet been installed. If Developer desires to modify any easement relating to any portion of the Gas Distribution System after such system has been installed, then Developer must obtain Company’s advance written consent to any easement modification and the Developer shall reimburse Company for any design and other costs associated with any relocation of the Gas Distribution System necessitated by such revised easements. 3. Coordination of Installation. Company agrees to cooperate with Developer with respect to the construction of the Gas Distribution System so as not to interfere with or delay Developer’s construction of any portion of the Project. In the event that Developer intends to construct the Project in multiple phases (each a “Phase”), Developer shall advise Company from time to time of its anticipated construction schedule for each Phase of the Project. Such schedule should provide Company with sufficient time to construct the Gas Distribution System within the various Phases of the Project. 4. Ownership of Gas Distribution System. The Gas Distribution System shall remain the exclusive property of Company at all times during and following the expiration or earlier termination of this Agreement. Company shall have the sole obligation and responsibility for the maintenance of the Gas Distribution System. Company shall at all times maintain the Gas Distribution System in accordance with the plans and specifications originally approved by all appropriate governmental agencies. This obligation shall survive the termination of this Agreement and shall inure to benefit all end-user consumers within the Project. Company hereby agrees to indemnify, defend and hold harmless Developer and its officers, directors, employees, successors and/or assigns from and against all third party claims, liabilities, suits, damages, costs and expenses including, without limitations reasonable attorneys’ fees and court costs at trial and all appellate level(s), arising from or in connection with construction, operation or maintenance of the Gas Distribution System. 5. Gas Appliance Requirement. In recognition of the investment made by Company in constructing the Gas Distribution System, Developer agrees that all of the units to be

constructed in the Project by Developer (or any builder approved by the Developer) shall make all possible efforts to utilize natural gas for heating purposes. Developer shall inform each Builder within the Project of the need to install natural gas appliances in compliance with the requirements of the preceding sentence. Developer agrees that interior gas piping, venting, etc., installed in all of the units constructed within the Project will conform to applicable codes and will be so sized as to satisfy existing requirements for the ultimate utilization of natural gas. Developer further agrees to make a reasonable effort to utilize natural gas in common areas of the Project. 6. Revenue Shortfall. Upon the completion of the sixth year anniversary of the effective date of this Agreement, should the sum of the Projects net revenue (based on the Company’s rates in effect from time to time and as approved by the Delaware Public Service Commission) from the delivery of natural gas by the Company to each facility located within the Project fall short of the investment required for the project, currently estimated at one hundred thirty thousand dollars ($130,000), then Developer will pay the Company the amount of the shortfall. The Projects net revenues exclude revenues from the Gas Sales Service Rate (GSR) and taxes. The shortfall will be calculated consistent with the six times (6X) net revenue test on file with the Public Service Commission and will include a gross-up for taxes. Developer will pay any shortfall amount within thirty (30) days from the time the Company gives notice that such shortfall has occurred. An example of the calculation to be used in calculating any revenue shortfall is attached hereto as Exhibit B. 7. Assignment. If Developer desires to convey to other builders or developers any or all of the land upon which the Project is to be developed, Developer shall provide the Company with written notice of said intent a minimum of thirty (30) days prior to any conveyance. Notwithstanding any such conveyance Developer shall remain liable to Company under this Agreement, including any payment required for any revenue shortfall, as defined in Section 6 above. 8. Sole Agreement. This Agreement supersedes any and all other agreements, either oral or in writing, between the parties hereto with respect to the subject matter hereof and contains all of the covenants, agreements and other obligations between the parties with respect to the subject matter hereof. There are no collateral agreements, promises or undertakings whatsoever by either party hereto which in any way touches upon the subject of this Agreement. 9. Binding Agreement. This Agreement shall be binding upon, and shall inure to the benefit of, the parties hereto, and their respective successors and assigns, and no assignment shall relieve either party of such party’s obligations hereunder without written consent of the other party, except as otherwise provided herein. 10. Notices. All notices, requests, approvals, demands, and other communications required or permitted to be given under this Agreement shall be in writing and shall be sent by hand

delivery or certified U. S. Mail, return receipt requested, postage prepaid. Any such communication shall be deemed to have been given and shall be effective upon delivery in the case of hand delivery and three (3) business days after being deposited in the United States mail in the case of mail delivery. Communications shall be addressed in accordance with the first paragraph hereof, or at such other address, as the party to whom the communication is sent shall have designated hereafter in accordance with the provisions of this paragraph. IN WITNESS WHEREOF, the parties hereto have caused this Service Agreement for Natural Gas Distribution System to be signed by their respective duly authorized personnel as of the date first above written. CHESAPEAKE UTILITIES CORPORATION – DELAWARE DIVISION By: _________________________________ Name: Jeffrey R. Tietbohl Title: Vice President City of Dover By: _________________________________ Name: _______________________________ Title: ________________________________

EXHIBIT B – Example of Revenue Shortfall Calculation under Paragraph 6. Actual Capital cost = $130,000 Actual Net Revenues* Year 1 $5,000 Year 2 $10,000 Year 3 $15,000 Year 4 $20,000 Year 5 $30,000 Year 6 $35,000 Total $115,000 Shortfall payment due = $130,000 - $115,000 = $15,000 plus gross-up for taxes *Net revenues are total revenues less revenue from the Gas Sales Service Rate (GSR) and taxes.

The Energy Authority, Inc. Monthly Management Committee Update – October 2013 November 21, 2013 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 $324,485 over budget due to higher reactive services costs. Dover’s budgeted cost for all power supply (capacity AND energy) was $82.00/MWh. The actual cost of all power supply (capacity AND energy) was $86.92/MWh. The cost of energy alone was $48.11/MWh, versus a budgeted energy cost of $49.33. Dover’s hedge purchases totaled 44,560 MWh, which was 76% of the actual load. The budgeted hedge purchase totaled 33,280, which was 57% of the budgeted load. Dover’s power purchases from hedge transactions totaled $2,225,782. Purchases from PJM (energy and fees) totaled $1,239,043 with DA Energy purchases totaling $386,659 and Reactive Services Charges totaling $377,806. Dover’s total load was 58,343 MWh versus a forecasted load of 57,888 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1,294 MWh. Dover’s actual energy purchase from the SunPark installation was 1,180 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 57,888 58,343 (455) Wholesale Load 56,594 57,163 (569) Hedged Volume (MWh) 33,280 44,560 (11,280) Unhedged Volume (MWh) 23,314 12,603 10,711 Dover SunPark Volume (MWh) 1,294 1,180 114 Renewable Energy Credits Volume 194 300 (106) Hedged Cost ($/MWh) $ 55.50 $ 49.95 $ 5.55 Unhedged Energy Cost ($/MWh) $ 38 $ 37 $ 2 Solar Energy Cost ($/MWh) $ 87 $ 102 $ (15) Energy Costs ($/MWh) $49.33 $48.11 $1.22 All-in Costs - Energy, Capacity and RECs ($/MWh) $82.00 $86.92 ($4.92) 2

B. Generation Summary: Dover generated 0 MWh in the month. Net generation revenue was $872,401 vs. a budget of $973,657. This delta was mainly due to higher plant O&M during the month. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 0.00 All In Generation Margin PJM - Economic and reliability dispatch (GEN) $ - PJM - Generation Capacity Credit (GEN) $ 1,329,125.00 PJM - Black Start & Transmission Losses (GEN) $ 50,818.18 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Margin $ 1,379,943.18 Production Margin PJM - Economic and reliability dispatch (GEN) $ - Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Production Margin $ - $/Mwh All In Generation Margin $ - $/Mwh Generation Production Margin $ - 4

C. Emissions Summary: Emissions Allowance Summary through November 15, 2013 (Includes Nov15, 2011 sale of Seasonal NOx to DEMEC) CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowances Seasonal Annual 1/1/09 2008 Carryover 3,240 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 2,039 50 78 1/1/11 2011 Allocation 1,988 49 78 4/1/11 2011 Reallocation 2 4 1/11/12 2012 Allocation 1,988 51 80 10/4/2012 2013 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 10/31/13 C.Y.T.D. 2013 Emissions 0 (20) (20) 11/15/13 NOx Seas. Sales (DEMEC) (5) REMAINING ALLOWANCES 11,053 50 174 On August 21, 2012, a three-judge panel of the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s Cross State Air Pollution Rule (CSAPR) which would have become effective on January 1, 2012. The DCA instructed EPA to continue administering the Clean Air Interstate Rule (CAIR). EPA has appealed this ruling to the U.S. Supreme Court, and the Court has agreed to review the DCA opinion. A ruling is not expected before June, 2014. 1 Per CAIR, starting in 2009, NOx emissions are governed by a seasonal and annual program. 2 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 5

Market liquidity for CAIR allowances continues to be low, with few transactions occurring. The following table shows estimated values for Dover’s banked allowances, based on broker bids & offers: Mark-to-Market for CAIR Allowances (11/18/2013) Commodity $/Ton Tons Extended (Bid/Offer Avg.) Value SO2 Allowances (2009 & earlier) $ 1.38 5,089 $ 7,023 SO2 Allowances (2010-13) $ 0.68 5,964 4,056 NOx Allowances - Seasonal $18.00 50 900 NOx Allowances - Annual $40.00 174 6,960 TOTAL $18,939 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 has elected 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. 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 (10/31/2013) 1 2 3 4 5 6 7 8 CO2 Allowances Available Annual CO2 CO2 (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance Allowances Prior to Sale) CO2 Vintage Sold YTD Allowances Emitted Allowance Balance McKee Balance 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 2011 0 36,077 1,234 37,311 (17,763) 19,548 92,712 6

2012 0 27,058 925 27,983 ( 15,265) 11,793 104,505 2013 YTD 0 15,032 514 15,546 (8,726) 6,820 111,325 After 2013, Dover will no longer receive allocations of RGGI allowances. The Cumulative Balance (column 8) – aka “Banked Allowances”) can be utilized for generation in future years (including 2013). 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, it will be able to maintain a positive balance through 2016–2025, depending on actual annual energy production in 2012 and beyond. On February 7, 2013, RGGI proposed changes to its Model Rule. The proposed changes have been included in previous monthly reports. With the release of the Updated Model Rule, the RGGI states now plan to revise their CO2 Budget Trading Programs through their individual state-specific statutory and regulatory processes. Each RGGI state seeks to complete their state specific processes such that the proposed changes to the program would take effect on January 1, 2014. The Delaware Department of Natural Resources expects to publish a draft rule in the Delaware Register in the near future. Dover could elect to sell all or a portion of its banked allowances now and re-acquire allowances at a later date; however TEA is currently of the opinion that Dover will be better off retaining its banked allowances for use during future compliance years. The most recent RGGI auction occurred on September 5, 2013; the auction cleared at $2.67/ton. The next auction will occur on December 4, 2013. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on November 18, 2013 ranged from $2.95 to $3.25/ton, depending settlement month. Based on the average Intercontinental Exchange prices for December 2013 settlement ($2.95/ton), the value of Dover’s existing 111,325 ton RGGI allowance bank is approximately $328,409. 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 SRECS. Through the end of September 2013, Dover has accumulated a total of 6,310 SRECS from these renewable energy resources. The nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s September 2013 SREC auction cleared separately for 2010/2011 through 2013/2014 vintage allowances. Clearing prices and Dover’s SREC market value estimate are shown in the table below. 7

SREC Vintage Auction Clearing Price SREC Quantity Market Value (June 1 – May 31) $ 4.01 13 2010/2011 $ 52 (Aug-13 Auction) 20011/2012 $ 8.21 2,375 19,499 2012/2013 $11.01 2,725 30,002 2013/2014 $14.00 1,197 16,758 TOTAL 6,310 $66,311 TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard which DEMEC is working on. Once Dover has an approved RPS in place, it may be required to retire a portion of its current SREC balance for compliance in the 2012/13 future compliance year. Any remaining SRECs could be used for the 2013/14 compliance year. NOTE: SRECs in both Delaware and Pennsylvania expire without value after 3 years. Dover currently has thirteen (13) 2010/2011. Based on a recent discussion with DEMEC staff, this expiration provision is not likely to be of concern within the current compliance year. If Dover has not accumulated adequate non-solar RECs, it will need to acquire some from DEMEC for the 2013/2014 compliance year. DEMEC has told TEA that it will likely have sufficient non-solar RECs for Dover’s requirements. Dover can purchase and retire a portion of these non-solar RECs during the current compliance and fiscal years, or it can defer acquisition until the June – August, 2014 time frame, after the exact amount of non-solar REC requirements is known. 8

D. Operations Management Summary: During the month of October, there were no restricted work days or lost time accidents. On October 14, 2013, the plant successfully completed three years without and OSHA Recordable Accident or a Lost Time Reportable Accident. The facility has now gone three years and 15 days (1,110 days) through October 31, 2013 without an OSHA Recordable Accident or a Lost Time reportable accident. In the month of October, there were no MW’s generated. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of September were $507,542 against a budgeted amount of $391,048 for an unfavorable variance of $116,494 or 29.79%. The principal reason for the unfavorable variance was due to 3 payroll periods in October rather than the 2 that had been budgeted. E. Risk Management Summary: Forward power prices in PJM are lower than last month. The current projected cost of service is below: Blended Monthly Cost Change Power Year Hedge Ratio ($/MWh) ($/MWh) 2013-14 76% $ 48.82 $ (0.22) 2014-15 49% $ 43.46 $ (0.62) 2015-16 23% $ 40.97 $ (1.00) 9

II. Budget Report Variance Report: Budget Actual Variance Oct-13 Oct-13 Gross Load 57,888 58,343 (455) Power Supply Hedged Energy $1,847,150 $2,225,782 ($378,632) PJM - Energy, Congestion & Losses $895,844 460,428 $435,416 PJM - ARR, Transmission and Fees $395,000 774,874 ($379,874) Dover SUN Park Energy $112,621 $120,840 ($8,218) Dover SUN Park RECs $25,000 $42,894 ($17,894) Management Fees $83,000 $83,000 $0 PJM - Capacity UCAP Obligated Purchased $1,388,224 $1,363,506 $24,717 Subtotal - Power Supply $4,746,839 $5,071,324 ($324,485) Power Generation O&M Plant O&M 391,048.00 $507,542 (116,494.00) Subtotal Generation O&M 391,048.00 507,542.00 ($116,494) Power Generation Production Margin PJM - Economic and reliability dispatch $0 $ - $0 Fixed Fuel and Transport Charges $0 $ - $0 Subtotal Generation Production Margin $0 $ - $0 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($1,329,125) $ (1,329,125.00) $0 Emissions Allowance Sales $0 $ - $0 PJM - Black Start & Transmission Losses ($35,580) $ (50,818.18) $15,238 Subtotal - Non-Production Revenue ($1,364,705) ($1,379,943) $15,238 SubTotal - All Generation (973,657.00) ($872,401) ($101,256) Total - Utilities Cost $3,773,182 $4,198,923 ($425,741) Unit Costs Total - Power Supply $82.00 $86.92 ($4.92) Total - Power Generation ($16.82) ($14.95) ($1.87) Final Cost of Service to City of Dover Ratepayers $65.18 $71.97 ($6.79) 10

Variance Analysis: Power Supply  Dover consumed 455 MWh more than forecast for the month.  PJM energy costs were lower than expected as less market purchases were required. Hedged costs were higher than forecasted due to an additional layering in of hedges. PJM Fees were well above budget, driven by large reactive services charges.  The result of the higher overall cost for reactive services was a net power supply cost of $86.92/MWh, $4.92/MWh higher than budget.  For the month, the city realized an unfavorable variance of $324,485 for power supply vs. the monthly budget.  Dover Sun Park generated 114 MWh less than forecast. Generation  Power generation had an unfavorable budget variance of $101,256.  Plant O&M expenses had an unfavorable budget variance of $116,494 for the month. 11

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 275,677 274,895 782 Power Supply Hedged Energy $11,193,694 $11,768,406 ($574,712) PJM - Energy, Congestion & Losses $3,525,909 $3,123,948 $401,961 PJM - ARR, Transmission and Fees $1,580,000 $2,617,557 ($1,037,557) Dover SUN Park Energy $543,246 $689,486 ($146,241) Dover SUN Park RECs $100,000 $167,824 ($67,824) Management Fees $332,000 $332,000 $0 PJM - Capacity UCAP Obligated Purchased $5,508,114 $5,409,985 $98,128 Subtotal - Power Supply $22,782,962 $24,109,207 ($1,424,373) Power Generation O&M Plant O&M $1,970,066 $2,032,174 ($62,108) Subtotal Generation O&M $1,970,066 $2,032,174 ($62,108) Power Generation Production Margin PJM - Economic and reliability dispatch ($230,472) ($1,742,146) $1,511,674 Fixed Fuel and Transport Charges $0 $831,570 ($831,570) Subtotal Generation Production Margin ($230,472) ($910,575) $680,104 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($5,273,625) ($5,273,625) $0 Emissions Allowance Sales $0 $0 $0 PJM - Black Start & Transmission Losses ($142,320) ($352,331) $210,011 Subtotal - Non-Production Revenue ($5,415,945) ($5,625,956) $210,011 SubTotal - All Generation ($3,676,351) ($4,504,358) $828,007 Total - Utilities Cost $19,106,612 $19,604,849 ($498,238) Unit Costs Total - Power Supply $82.64 $87.70 ($5.06) Total - Power Generation ($13.34) ($16.39) $3.05 Final Cost of Service to City of Dover Ratepayers $69.31 $71.32 ($2.01) 12

III. Operations Management NAES Corporation Dover, Delaware October 2013 Monthly Report New Decking over Unit 3 Cooling Tower Hot Water Basin 13

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 14

1.0 Environmental, Health and Safety: During the month of October, there were no restricted work days or lost time accidents. On October 14, 2013, the plant successfully completed three years without and OSHA Recordable Accident or a Lost Time Reportable Accident. The facility has now gone three years and 15 days (1,110 days) through October 31, 2013 without an OSHA Recordable Accident or a Lost Time reportable accident. The October (September discharge) DMR was submitted for the McKee Run site with no NPDES exceedences although it did have high Arsenic levels. There were no opacity deviations during the month. During the month of October, NAES staff submitted a request to Kent County requesting modification of the Industrial Wastewater discharge permit in order to increase the loading level for Arsenic as well as the maximum allowable monthly discharge. In response, Kent County has issued a revised permit for the McKee Run site with the requested levels. The Plant Safety training requirements for OSHA/Safety and Environmental Programs has now been completed by all staff members. The training program includes the inclusion of the General Physics on-line training system as well as plant safety procedures and policies. Safety Procedures and associated quizzes have been updated. Staff has retrained on each one to ensure they understand what changes have been made, if any, to the programs. Plant staff and NAES Environmental Support Services worked with the emissions monitoring equipment services provider to resolve DAHS data issues encountered during Appendix E testing on Unit 11 and Unit 2. During the stack testing, inaccurate fuel flow data was encountered due to a poor wire connection on a CEMS terminal board on Unit 11 and a bad PLC Card (Channel) was found to be problem on Unit 2. The Emission Test Reports were finalized and submitted to EPA/DNREC. Third quarter 2013 EDRs were also submitted to the EPA/DNREC. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (October) (7/1/13-6/30/14) NOVs 0 0 Opacity Deviations 0 0 Environmental Deviations 1 3 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 2 Man Hours Worked 4393.50 17146.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,110 Days since last Lost Time Accident 1,110 15

Emissions (NOx & SO2) All data thru 10/31/13 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 31.4 1.4 36.1 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 32.6 2.9 38.8 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 2012 0.0 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 CO2 Allowances Summary CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Sold YTD Sale) Balance McKee Run VanSant 2009 0 60,128 2,056 5,796 56,388 2010 0 48,102 1,645 32,971 16,776 2011 0 36,077 1,234 17,763 19,548 2012 0 27,058 925 15,265 11,793 2013 0 15,032 514 8,726 6,820 Total CO2 Allowance Balance 111,325 *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. Note: All emissions (NOx, SO2 and CO2) totals for 2013 are unofficial. 16

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) 2010 and 3*** 27/0 0/2 earlier 2011 0 77/48 5/3 33/31– 3/1 0/0 - 0/0 42/10 2/2 2012 2** 75/46 5/3 36/36 – 1/1 0/0 - 0/0 39/10 2/0 2013 0 77/48 5/3 19/19 – 1/1 0/0 - 0/0 58/29 4/2 Total NOx Allowance Balance 166/49 8/6 *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- The facility transferred Annual allowances to a third party SO2 Allowances Summary SO2 Allowances Total SO2 Tons Available Total SO2 Tons Emitted – (Per Unit, Prior Emitted – SO2 Allowances SO2 Allowance SO2 Allowances U3 and U11 to Sale & U3 and U11 Balance Vintage Sold - YTD YTD Reconciliation) YTD Unit #3 Unit #11 2010 and earlier 0 4815 276 0 5089 2011 0 1850 138 1 1988* 2012 0 1850 138 1 1988* 2013 0 1850 138 0 1988* Total SO2 Allowance Balance 11,053 Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 17

2.0 Financial Financial – Current Month Month – October Actual Budget Variance Personnel 333,598 246,170 (87,428) Materials & Supplies 27,965 7,785 (20,180) Administrative Expenses 145,889 138,093 (7,796) Total $507,452 392,048 ($115,404) Financial – Fiscal Year to Date Number of Months – 4 Actual Budget Variance Personnel 994,446 989,515 (4,931) Materials & Supplies 83,112 126,790 43,678 Administrative Expenses 774,652 854,586 79,935 Total $ 1,852,210 $1,970,891 $118,681 2.1 Variance analysis: The expenses for October are $507,452 against a budgeted amount of $392,048 for an unfavorable variance of $115,404 or 29.44%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $87,428 was due to having three (3) payroll periods expensed in this month that had been budgeted for in November. This includes straight time labor, overtime labor, and labor burden costs for October. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $20,180 was due to higher water usage than expected and the purchase of water treatment chemicals that were a result of unplanned PJM dispatches for this time of year. The increase in PJM dispatches were due to higher than normal ambient temperatures and several large generating plants on the grid starting their outages in September. As a result, the Dover units were dispatched/operated more to support the reduction in available generation. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $7,796 was due to higher insurance account costs and higher than budgeted electricity costs experienced in order to support unit operations. The insurance costs were for the environmental liability portion of the site insurance that was included in the budget for July. The forecasted expenses for this fiscal year are $5,966,244 expensed versus an approved budget of $6,015,800 thereby realizing a 99.18 % expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips In the month of October no units were dispatched. Units 1, 2, 3, and 11 started the fall 2013 outage on October 1 at 0700 hours. Month October 2013 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 26.073 26.073 118.740 170.886 0.102 170.988 Auxiliaries purchased MWh 26.073 26.073 118.740 170.886 0.102 170.988 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 0.0 0.0 0.0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 0.94 0.94 0.94 0.94 0.94 0.94 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 737.000 737.000 737.000 2,211.000 593.000 2,948.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 7.00 7.00 7.00 21.000 7.00 28.000 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 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. 19

2013-2014 Fiscal Year-to-Date - October 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 74.765 170.316 183.196 428.277 51.476 479.753 Starts # 2 4 13 19 14 33 Gross Generation MWh 585.171 1,106.123 12,576.985 14,268.280 1,569.051 15,837.330 Net Generation MWh 545.470 1,024.415 11,585.303 13,155.190 1,567.790 14,722.980 Total Auxiliaries MWh 134.754 176.761 1,672.188 1983.703 4.362 1988.065 Auxiliaries purchased MWh 137.676 180.206 680.506 998.388 3.101 1001.489 Fuel Gas Used MMBTU 7,061.376 13,801.068 132,465.224 153,327.670 18,981.931 172,309.60 Fuel Oil Used MMBTU 1,642.633 1,671.506 0.0 3,314.14 2,937.660 6,251.80 Fuel Oil Used Gallons 11,568 11,726 0.0 23,294 20,795 44,089 Total Fuel MMBTU 8,704.009 15,472.574 132,465.224 156,641.81 21,919.591 178,561.40 Net Heat Rate BTU/KWh 15.778 14.477 11.558 13.938 13.838 13.888 Unit Trips # 0 1 0 1 4 5 Capacity Factor % 1.09 2.04 3.85 3.28 1.36 2.85 Availability Factor % 72.32 75.03 75.03 74.03 75.03 74.36 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 737.000 737.000 737.000 2,211.000 737.000 2,948.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 80.000 0.0 0.0 80.000 0.0 80.000 Reserve Shutdown Hours 2,060.235 2,044.684 2,034.400 6,139.32 2,163.524 8,302.84 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 1,473.105 3,733.607 5,206.712 5,206.712 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 13-14 Fuel FY 13-14 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 430,931 428,288 0 (2,,643) 454,725 0 (26,437) VanSant 125,064 124,390 0 (674) 146,133 0 (21,743) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through October 2013 Actual Starts Factored Starts Fired Hours VanSant 1328 2,291.75 4,479.60 Since HGP - Dec 2004 246 624.05 896.02 20

Team Report: The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. They assisted in the natural gas line purge on Unit 3 in preparation of the installation of the pipe blank and in the purge on Units 1 and 2 gas lines. The Operations staff has also supported the outage by performing various LO/TO tasks needed to test or place equipment in or out or service. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2013-2014 Summer 2013 (June 1- Aug 31) Winter 2013-2014 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.2 1 17* 0.0 2 17 17.8 2 17* 0.0 3 102 103.0 3 102* 0.0 VanSant# 39 40.9 11 39* 0.0 Total 175 178.9 Total 175 0.0 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program and data has been submitted into the PJM eGADS Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 21

4.0 Maintenance During the month of October, the Plant Maintenance staff continued addressing the backlog of work orders and preparing for outage activities. There were thirty-seven work orders issued with seventy-five work orders being completed during the month. There were no 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 October - 2013 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 16 1 10 7 2 52 6 21 37 3 40 2 0 42 4 6 0 0 6 5 24 2 7 19 SW1 0 0 0 0 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 56 26 37 45 Totals 194 37 75 156 Note: PM Work Orders are included in the priority totals Notable activities during the month include:  The NAES Maintenance Staff completed the change out of the fuel oil nozzles and fuel oil check valves on Unit 11 at VanSant Generating Station. The nozzles and check valves were changed out to correct high exhaust temperature spread issues when combusting #2 fuel oil. No spread issues were encountered when operating on natural gas. Also replaced on the turbine were two wheelspace thermocouples that staff had been getting bad readings while the unit was operating. They will be checked for proper operation the next time the unit operates.  Annual inspection of Units 1, 2 and 3 Boilers were completed by Charlie Newman, boiler inspector for XL Insurance, Joe Hultberg, plant Chemical vendor representative and plant staff. They inspected the mud drums, steam drums and inside the fire box of the boilers. Minor issues were found that will be addressed when performed dry layup of the boilers and care of the boilers during the run season.  The NAES Maintenance and IC&E staff changed out several worn parts on the Unit 1 throttle valve. Staff had encountered problems with the valve earlier this year and had 22

made temporary repairs until new parts were received. After the new parts were installed, the valve was thoroughly tested for proper operation and then placed back into service.  Third party contractor completed the replacement of decking over the Unit 3 Cooling Tower Hot Water Basin during October. The decking was spongy and was badly in need of replacement. 5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: Work is complete 99%. MR Industrial Waste EG1214 Schedule: Project to be complete in November, 2013 with the final water System revision of Standard Operating Procedures on the system. Unit #3 Cooling Progress: Work is 100% complete EG1402 Tower Repairs Schedule: Work is 100% complete excepting closeout in HTE. McKee Run Progress: Work planned for the Fall is 75% Auxiliary Schedule: Some work activities will be completed in the Fall Outage EG1404 Component and others will be completed in the Spring Outage. Planning is Replacement ongoing for the spring activities. VanSant Station Progress: Work planned for the Fall is 85% complete. EG1405 Component Schedule: Planning activities are underway for the Spring outage. Replacement Progress: Work areas have been scaffolded and many adjustments to the hangars have been made to date. Additional work will be McKee Run HEP completed in November. EG1406 Pipe Repairs Schedule: Fall work activities should complete in November. Adjustments will need to be checked once units are heated up. Spring work still being planned. Progress: Proposal received from vendor. COD and plant personnel have discussed proposal and submitted a list of “to do” items to the Metering System EG1407 vendor for more information and clarification. Upgrades Schedule: Work activities are moving forward. Waiting to hear back from vendor. McKee Progress: Work scheduled for the Fall and Spring. EG1408 Run/VanSant Safety Schedule: Work activities are slightly behind due to Fall Outage Compliance Items activities. McKee Run Natural Progress: Work scheduled for the Spring Outage. EG1409 Gas Block-Bleed Schedule: Work activities are slightly behind due to Fall Outage Valves activities. EG1410 McKee Progress: Crane specifications being developed and will be put out 23

Run/VanSant Crane for bid in mid-November. Replacement Schedule: Work activities are progressing forward. Estimated time period for purchase of crane is approximately January 2014. McKee Progress: Plant staff completed development of paint specifications Run/VanSant and bid requests were received. EG1413 Structural Schedule: Bids were received in early September. Work is on hold Preservation due to budget restraints. Progress: Work scope was developed and put out for bid in September. Quotes have been received and evaluated. Unit 3 Turbine Recommendation of award for COD Council approval will occur in EG1212 Repairs November 2013. Schedule: List of consumables has been finalized and quotes are being received.. Progress: Cost to be incurred due to repairs on Unit 1 boiler and McKee Run Units turbine expected to be complete in November. EG1415 #1-#2 Component Schedule: Other Work activities are anticipated to be completed Repairs during the spring outage. Progress: Bid specifications are being developed and Environmental permit modifications are being investigated. Communications with PJM to get MW into system in the works with possibly a six-month VanSant Capacity wait period is progressing. Capacity increase request is in the PJM EG1416 Increase queue. Schedule: Environmental Support contract work was awarded and data is now being gathered by the contractor for use in the environmental application process. 24

6.0 General Plant Information During the month of October, offers were made to individuals in order to fill the open Operator positions. Both offers were accepted by individuals and will start work in November, once they are cleared through the physical and background screening process. Training:  Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Fire Prevention”. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff.  Plant employees continue using the General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed, the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy as well. Calendar of Events Date Units 1, 2, 3 and 11 Fall Outage October 1, 2013 to November 27, 2013 Three Year Accident Free October 14, 2013 Winter Capacity Period December 1, 2013 to February 28, 2014 Annual Title V Certifications Due January 30, 2104 EIA-860 Report February 28, 2014 EIA-923 Report February 28, 2014 NOx Emissions Reconciliation Due March 1, 2014 SO2 Emissions Reconciliation Due March 1, 2014 SARA III Report March 1, 2014 NPDES Permit Renewal Due March 4, 2014 Units 1, 2, and 3 Spring Outage March, 2014 – June , 2014 Unit 11 Spring Outage March, 2014 – June , 2014 Annual VanSant Black Start Test March, 2014 Air Emission Inventory March, 2014 NOx Ozone Season Starts May 1, 2014 PJM Summer Capacity Test Period June 1, 2014 – August 31, 2014 Toxic Release Inventory (TRI) Annual Report July 1, 2014 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2014 DRBC Study Due September 15, 2014 NOx Ozone Season Ends September 30, 2014 25

7.0 Summary of NAES Performance to Date Plant Performance FY 2013-2014 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.00% 0.09% $91,087 $94,882 Unavailability (CU) Safety 0 0 $17,790 $17,790 Environmental 0 0 $17,790 $17,790 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,559* $3,559 Unit 2 No No Yes Yes* $3,559* $3,559 Unit 3 No No Yes Yes* $21,349* $21,349 Unit 11 No No Yes Yes* $7,117* $7,117 Total YTD 97.71% Total YTD Incentive $162,249* $166,045 Incentive % Note: *All units have successfully completed the PJM Summer Capacity Tests and are now included in the PJM Winter Capacity Test Exemption Program. The YTD Incentive calculation reflects this inform 26

IV. Appendix – PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights ($26,877.93) ($26,877.93) Balancing Operating Reserve $4,381.88 $4,381.88 Balancing Operating Reserve for Load Response $119.52 $119.52 Balancing Spot Market Energy $76,523.13 $76,523.13 Balancing Transmission Congestion $10,141.11 $10,141.11 Balancing Transmission Losses $2,902.68 $2,902.68 Black Start Service $2,357.84 $2,357.84 Capacity Resource Deficiency ($140.95) ($140.95) Capacity Transfer Rights ($19,233.33) ($19,233.33) CT Lost Opportunity Cost Allocation ($17.36) ($17.36) Day-Ahead Load Response Charge Allocation $346.84 $346.84 Day-ahead Operating Reserve $2,127.44 $2,127.44 Day-ahead Scheduling Reserve $2.65 $2.65 Day-ahead Spot Market Energy $386,658.83 $386,658.83 Day-ahead Transmission Congestion ($47,706.09) ($47,706.09) Day-ahead Transmission Losses $29,512.45 $29,512.45 Demand Resource and ILR Compliance Penalty ($3,352.23) ($3,352.23) Emergency Load Response $19,367.41 $19,367.41 Expansion Cost Recovery $427.49 $427.49 FERC Annual Recovery $3,459.91 $3,459.91 Generation Deactivation Refund ($758.28) ($758.28) Inadvertent Interchange ($768.58) ($768.58) Incremental Capacity Transfer Rights ($1,761.11) ($1,761.11) Load Reconciliation for Balancing Operating Reserve $52.30 $52.30 Load Reconciliation for Day-ahead Scheduling Reserve ($1.00) ($1.00) Load Reconciliation for FERC Annual Recovery $22.94 $22.94 Load Reconciliation for Inadvertent Interchange $3.50 $3.50 Load Reconciliation for Market Monitoring Unit (MMU) Funding $1.49 $1.49 Load Reconciliation for Non-Synchronized Reserve ($2.06) ($2.06) Load Reconciliation for North American Electric Reliability Corporation (NERC) $3.86 $3.86 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $0.27 $0.27 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $79.63 $79.63 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund ($2.77) ($2.77) Load Reconciliation for Reactive Services $2,518.75 $2,518.75 Load Reconciliation for Regulation and Frequency Response Service ($84.28) ($84.28) Load Reconciliation for Reliability First Corporation (RFC) $5.51 $5.51 Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $8.68 $8.68 Load Reconciliation for Spot Market Energy ($5,861.42) ($5,861.42) Load Reconciliation for Synchronized Reserve ($4.33) ($4.33) Load Reconciliation for Transmission Congestion ($6,812.61) ($6,812.61) Load Reconciliation for Transmission Losses ($1,270.56) ($1,270.56) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $28.65 $28.65 Locational Reliability $1,384,641.66 $1,384,641.66 Market Monitoring Unit (MMU) Funding $228.03 $228.03 Meter Error Correction ($4,965.50) ($4,965.50) Michigan - Ontario Interface Phase Angle Regulators $206.74 $206.74 Network Integration Transmission Service $342,169.01 $342,169.01 Non-Firm Point-to-Point Transmission Service ($392.87) ($392.87) Non-Synchronized Reserve $155.22 $155.22 North American Electric Reliability Corporation (NERC) $581.52 $581.52 Organization of PJM States, Inc. (OPSI) Funding $40.12 $40.12 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,576.31 $1,576.31 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $943.95 $943.95 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $9,838.95 $9,838.95 PJM Scheduling, System Control and Dispatch Service - Market Support $2,250.00 $2,250.00 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($215.16) ($215.16) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $83.83 $83.83 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($147.56) ($147.56) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($1,727.08) ($1,727.08) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($398.75) ($398.75) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($18.31) ($18.31) PJM Settlement, Inc. $215.16 $215.16 Reactive Services $377,806.16 $377,806.16 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) $34,909.74 $5,442.16 Real-Time Load Response Charge Allocation $661.26 $661.26 Regulation and Frequency Response Service $10,006.51 $10,006.51 Reliability First Corporation (RFC) $831.55 $831.55 RPM Auction ($1,329,125.00) ($1,329,125.00) Synchronized Reserve $ 3,924.58 $ 3,924.58 Transmission Enhancement $4,883.03 $4,883.03 Transmission Losses ($21,350.60) ($21,350.60) Transmission Owner Scheduling, System Control and Dispatch Service $4,320.53 $4,320.53 Grand Total $ (1,379,943.18) $ 2,598,808.50 $1,218,865.32 27

City of Dover Electric Revenue Fund FY14 - White Oak Solar Park Incremental Cost Original July August September October YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 187,421 $ 176,372 $ 204,852 $ 120,839 $ 689,484 $ 1,565,800 Dover Sun Park - REC's 43,005 38,516 42,894 - 124,415 300,000 Total Power Supply Cost 230,426 214,888 247,746 120,839 813,899 1,865,800 Non-Solar Power Supply Cost (180,227) (154,545) (154,590) (101,293) (590,654) (606,146) Incremental Energy Cost $ 50,199 $ 60,343 $ 93,156 $ 19,546 $ 223,245 $ 1,259,654 Revenues Customer Sales - Electricity (9,404) (7,389) (7,538) (7,662) (31,993) (26,300) Rent Receipts (14,446) - - (14,446) (28,892) (58,300) Total Revenues (23,850) (7,389) (7,538) (22,108) (60,885) (84,600) Incremental Sun Park Cost $ 26,349 $ 52,954 $ 85,618 $ (2,562) $ 162,360 $ 1,175,054 MWh Purchased/Generated - Solar 2,052.584 1,815.656 2,000.128 1,179.844 7,048.212 18,159.000 MWh $ Solar Energy $ 91.31 $ 97.14 $ 102.42 $ 102.42 $ 97.82 $ 86.23 Solar REC's MWh 307.000 272.000 300.000 - 879.000 MWh $ Solar REC (one month lag)* $ 140.08 $ 141.60 142.98 $ - $ 141.54 MWh $ Non-Solar Energy $ 87.81 $ 85.12 $ 77.29 $ 85.85 Note: Solar REC's are one month behind due to the time the invoice is received.