Attachment

UTILITY COMMITTEE AGENDA June 13, 2011 - 5:00 P.M. - Council Chambers - City Hall - City of Dover 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-m ail at CityClerk@dover.de.us) should you wish to be recognized. AGENDA ADDITIONS/DELETIONS 1. Dedication of Rights-of-Way and Public Infrastructure - Blue Hen Apartments 2. Universal Recycling Grants - Recycling Services Reimbursement Agreement 3. Review of Utility Related Capital Investment Plan (CIP) (Electric and Water/Wastewater) 4. PACE/NAES Report (March and April) 5. Updates - National Pollution Discharge Elimination System (NPDES) Municipal Separate Storm Sewer Systems (MS4) Permit 6. Adjournment by 5:55 P.M. /tm S:\AGENDAS & MINUTES\Committee-Agendas\2011\06-13-2011 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 Services DATE SUBMITTED: 05/24/2011 PREPARED BY: Scott D. Koenig, P.E., Public Services Manager SUBJECT: Dedication of Rights-of-Way & Public Infrastructure – Blue Hen Apartments REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager EXHIBITS: Attachment A – List of Public Improvements to be accepted by the City of Dover Attachment B – Map EXPENDITURE REQUIRED: $ N/A AMOUNT BUDGETED: $ N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIME TIMETABLE: All infrastructure improvements will become the responsibility of the City of Dover upon action by City Council. RECOMMENDED ACTION: Acceptance of dedication of rights-of-way and public infrastructure adjacent to the Blue Hen Apartment Complex. Dedication is to include all of the referenced public improvements. BACKGROUND AND ANALYSIS The developer of the Blue Hen Apartment Complex, Pettinaro Construction Co., Inc. has requested that all public infrastructure improvements adjacent to this project be dedicated to the City of Dover for permanent ownership and maintenance. Attachment A outlines all of the public improvements associated with this project. The total construction value of the public improvements is $240,750. Attachment B shows the general location and configuration of the subject rights-of-way. Pettinaro Construction, Co., Inc. has constructed all of the improvements in accordance with City standards and specifications. After construction was completed, City staff inspected the public improvements and provided the developer with a list of repairs to be made to meet the City of Dover Standards and Specifications for Public Works Construction. As of this date, all work related to the public infrastructure has been completed by the developer. A one (1) year Maintenance Agreement, Letter of Credit and a Release of Liabilities will be submitted by the developer as part of the dedication process. In addition, as-built drawings of the subject improvements and rights-of-way have been submitted to the City of Dover for our permanent records. J:\MyFiles\Projects\Paperless Packet\ActionForm.wpd

DEDICATION OF RIGHTS-OF-WAY AND PUBLIC INFRASTURCTURE AREA ADJACENT TO BLUE HEN APARTMENTS ATTACHMENT A The following is a list of all public improvements which are to be accepted by the City of Dover: Street Infrastructure (0.3040 miles) (Construction Value = $ 240,750): Blue Hen Boulevard Station 0+00 to Station 11+60 1,160 l.f. Haslet Street Station 0+00 to Station 4+45 445 l.f.

ATTACHMENT B Blue Hen Boulevard & Haslet Street Right of Way to be Dedicated to the City of Dover S Little Creek R d Moriarity St Roberta Ave Ha s let St Le v yC ou r vd tLn Bl H en ue Bl 0 100 200 400 Feet ¯ Date Printed: May 24, 2011 Date Created: May 24, 2011 Legend File: m:\gis_data\projects\tech_mxds \street_dedication_blue_hen_blvd Dover Parcels Department: Public Services GIS City of Dover, Delaware Right of Way to be Dedicated

ACTION FORM PROCEEDING: Utility Committee AGENDA ITEM DEPARTMENT OF ORIGIN: Public Services DATE SUBMITTED: June 2, 2011 PREPARED BY: Scott D. Koenig, P.E., Public Services Manager SUBJECT: Universal Recycling Grants – Recycling Services Reimbursement Agreement REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager, City Controller EXHIBITS: Attachment A – Recycling Services Reimbursment Agreement – Contract # 11-URG025 EXPENDITURE REQUIRED: $101,151.00. AMOUNT BUDGETED: N/A FUNDING SOURCE (Dept./Page in CIP & Budget): DNREC will reimburse the City of Dover for up to $101,151.00 per the agreement. TIMETABLE: Works shall begain as soon as possible and be completed by September 15, 2011. RECOMMENDED ACTION: Authorize staff to execute the Recycling Services Reimbursement Agreement (Contract # 11- URG025) between DNREC and the City of Dover. The City of Dover will be eligible for reimbursement up to $101,151.00 for work and/or services identified in the agreement. BACKGROUND AND ANALYSIS In June 2010, the State of Delaware passed legislation which established Universal Recycling in Delaware. This legislation requires the the implementation of comprehensive residential and commercial recycling programs by municipalities and waste haulers. It also established the Delaware Recycling Fund and the Recycling Grants and Low-Interest Program to defray the costs of implementation, and funds, with funding derived by the conversion of the former bottle deposit to a Recycling Fee on beverage containers. In January 2011, the City of Dover submitted a series of grant applications related to the implementation of a comprehensive recycling program. In April 2011, the City of Dover was informed that we have received Universal Recycling Grant funding in the amount of $101,151 as follows: 1) Public Information & Education for Customers - $ 15,000.00 2) “Schedule Change” Flyers Reimbursment - $ 3,115.00 3) Curbside Recycling Container Labels (Qty. = 15,250) - $ 2,798.00 4) Purchase of 1,782 wheeled recycling carts - $ 80,238.00 Total: $ 101,151.00 Staff is requesting authorization to execute the reimbursement agreement labeled as Attachment A and begin the work associated with the agreement. The City of Dover expended funds in FY-2011 for the purchase of wheeled recycling containers, curbside recycling container labels and “Schedule Change” flyers. All of these expenses related to the implementation of the curbside program and will be eligible for reimbursement once the agreement has been signed. These expenses are part of the funds identified in 2), 3) and 4) listed above.

City of Dover Capital Investment Plan Project Tracking Report April 30, 2011 Points to Remember - * Original Project Budget = Original Total Project Budget initially included in approved annual budget. * Latest Project Budget = Revised Total Project Budget included in most recent approved annual budget or one of the following: bond resolution, revolving fund loan agreement, Council approved budget amendment, or City Manager approved amendment as per the Budget Amendment Procedure. * Current Fiscal Year - Revised Fiscal Year Budget = Current Year approved project budgets plus carry forward balances of unspent budgets in the prior fiscal year. Project Carry Forward balances will be submitted to City Council for amendment in January 2010. Can also be amended with City Manager approval per the Budget Amendment Procedure. * Water Quality, Inflow/Infiltration, Distribution Upgrades and New Development projects are budgeted as a blanket project and once individual projects are identified and estimated they are created using an allocation of the overall budgeted amount. * Status and Comments provided by City Manager. * For Finance purposes projects are considered completed when placed in service and all charges have been processed. Community Water & Total Current Year Budget Funding Sources General Transportation Wastewater Electric CIP Budget Balance $ 113,156 $ - $ - $ - $ 113,156 Project Carry Forward Balances 88,083 - 953,238 850,736 1,892,057 Federal and/or State Grants 4,270,348 1,000,000 45,248 226,152 5,541,748 New Revolving Fund Loans - - 863,060 - 863,060 Carry Forward Construction Loan Balances - - 8,001,973 254,757 8,256,730 Bond Proceeds - - - 415,585 415,585 Impact Fees - - 758,821 - 758,821 Income from Sale of Assets - - - - - Parkland Reserve 36,872 - - - 36,872 Library Reserve & Contributions 3,363,732 - - 3,363,732 Transfer from Operating Funds 924,884 325,000 58,709 2,797,792 4,106,385 Interest Earned 10,900 - - 40,700 51,600 Total Funding Sources (Unaudited) $ 8,807,975 $ 1,325,000 $ 10,681,049 $ 4,585,722 $ 25,399,746 Page 1 of 5

City of Dover General Fund - Major CIP Projects April, 2011 Hide TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project Current Revised Fiscal Project Project Project To Date Budget % Budget Fiscal Yr. Fiscal Yr. YTD % Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments 1 FY2009 Bid Pack A - Done. 2 LB0901 M/G New Library Project $ 18,200,000 $ 24,679,934 $ 1,764,308 $ 22,915,626 7.1% $ 6,687,039 $ 7,630,663 $ 1,027,242 13.5% Started Bid Pack B - Construction Started. 3 Totals - FY09 $ 18,200,000 $ 24,679,934 $ 1,764,308 $ 22,915,626 7.1% $ 6,687,039 $ 7,630,663 $ 1,027,242 13.5% 4 5 FY2010 6 PR1001 Pitts Center Addition $ 50,000 $ 40,000 $ 28,629 $ 11,371 71.6% $ - $ 36,872 $ 25,501 69.2% Complete Complete. 7 Totals - FY10 $ 50,000 $ 40,000 $ 28,629 $ 11,371 71.6% $ - $ 36,872 $ 25,501 69.2% 8 9 FY2011 10 Vehicles & Equipment $ 63,675 $ 735,185 $ 515,703 $ 219,482 70.1% $ 735,185 $ 640,440 $ 515,703 80.5% Started Vehicles being ordered. Core Law Enforcement 11 PD1001 Server Replacement - 53,500 52,488 1,012 98.1% - 53,500 52,488 98.1% Started Specifications done. Public Assembly Room 12 PD1101 Upgrade - 20,000 8,000 12,000 40.0% - 20,000 8,000 40.0% Playground Improv 13 PR1101 Program - 15,000 12,952 2,048 86.3% 15,000 15,000 12,952 86.3% Complete BB Courts paved. 14 PR1102 Skate Park - 30,000 - 30,000 0.0% 30,000 30,000 - 0.0% Not Started In discussions with equipment provider 15 ST1101 Transfer to CT Fund 300,000 300,000 300,000 - 0.0% 300,000 300,000 300,000 100.0% Started Transfer to Com Transp Fund - December. 16 ST1102 Concrete Program 50,000 50,000 45,918 4,082 91.8% 50,000 50,000 45,918 91.8% Started Complete with contractor portion. Downtown Security 17 MR1101 Cameras 31,500 31,500 31,500 - 100.0% 31,500 31,500 31,500 100.0% Started Contract signed. 18 Totals - FY11 $ 445,175 $ 1,235,185 $ 966,561 $ 268,624 78.3% $ 1,161,685 $ 1,140,440 $ 966,561 84.8% 19 20 Grand Totals $ 18,695,175 $ 25,955,119 $ 2,759,497 $ 23,195,622 10.6% $ 7,848,724 $ 8,807,975 $ 2,019,303 22.9% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is rebudgeted to start over each fiscal year. G = Grant funded project Page 2 of 5

City of Dover Community Transportation & General Fund Street Funds - Major CIP Projects April, 2011 Hide TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project Current Revised Fiscal Project Project Project To Date Budget % Budget Fiscal Yr. Fiscal Yr. YTD % Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments 1 FY 2006 2 TE0601 M Lincoln Park Center $ 400,000 $ 479,148 $ 458,472 $ 20,676 95.7% $ 121,891 $ 121,891 $ 101,215 83.0% Started Ongoing. 3 Totals $ 400,000 $ 479,148 $ 458,472 $ 20,676 95.7% $ 121,891 $ 121,891 $ 101,215 83.0% 4 5 FY 2007 6 E. Water Street Brick $ 65,000 $ 65,000 $ - $ 65,000 0.0% $ 65,000 $ 65,000 - 0.0% Specialty contract needed. 7 Totals $ 65,000 $ 65,000 $ - $ 65,000 0.0% $ 65,000 $ 65,000 $ - 0.0% 8 9 FY 2009 Will try to re-program this $ into 10 Schutte Parking Lot $ 21,950 $ 21,950 $ - $ 21,950 0.0% $ 21,950 $ 21,950 - 0.0% a sidewalk for Schutte Park. Curb work complete, paving in 11 Turnberry Drive 40,000 40,000 40,000 - 100.0% 40,000 40,000 40,000 100.0% process. 12 Totals $ 61,950 $ 61,950 $ 40,000 $ 21,950 64.6% $ 61,950 $ 61,950 $ 40,000 64.6% 13 14 FY 2011 15 CT1051 Washington Street $ 104,000 $ 104,000 $ 104,000 $ - 100.0% $ 104,000 $ 104,000 $ 104,000 100.0% Complete. Complete. Not all of the CT Mitschner Road (incl. funds were used, CDBG and 16 CT1108 CDBG) 169,066 272,779 246,672 26,107 90.4% 272,779 304,026 246,672 81.1% CDBG-R covered $134,961 17 CT1086 Delaware Ave 6,250 6,250 6,250 - 100.0% 6,250 6,250 6,250 100.0% Complete. 18 CT1118 Oak Road Signage 11,875 11,875 10,375 1,500 87.4% 11,875 11,875 10,375 87.4% Just received. 19 CT1142 Governor's Ave. Rebuild 1,000 1,000 - 1,000 0.0% 1,000 1,000 - 0.0% 20 CT1161 Towne Point 7,500 7,500 - 7,500 0.0% 7,500 7,500 - 0.0% Complete. Remaining exp w/be 21 CT1162 Library Access Rd. 105,000 105,000 103,555 1,445 98.6% 105,000 120,000 103,555 86.3% in May. 22 ST1101 Street & Alley Program 300,000 300,000 179,271 120,729 59.8% 300,000 325,000 179,271 59.8% In progress. State Agreements not yet Agreements have not been 23 rec'd 458,968 346,468 - 346,468 0.0% 196,508 196,508 - 0.0% received. 24 Totals $ 1,163,659 $ 1,154,872 $ 650,124 $ 504,748 56.3% $ 1,004,912 $ 1,076,159 $ 650,124 64.7% 25 26 Grand Totals $ 1,690,609 $ 1,760,970 $ 1,148,596 $ 612,374 65.2% $ 1,253,753 $ 1,325,000 $ 791,339 63.1% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is rebudgeted to start over each fiscal year. Page 3 of 5

City of Dover Water/Wastewater Improvement & Extension Fund - Major CIP Projects April, 2011 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project % Approved Revised Fiscal % Project Project Project To Date Budget Budget Fiscal Yr. Fiscal Yr. YTD Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments 1 FY 2008 2 WD0807 S. Gov. Ave. Water Main Upgrade $ 200,000 $ 200,000 $ 2,664 $ 197,336 1.3% $ - $ 197,336 $ - 0.0% Complete Done. Awaiting Invoices Selecting Tank Model & Site; FY13 = 3 WD0804 M 1.0 MG Elevated Water Storage 4,196,600 2,590,000 15,365 2,574,635 0.6% - 193,377 8,742 4.5% Started Constr. 4 WD0805 M Piney Point Well 398,800 665,000 65,944 599,056 9.9% - 162,525 13,469 8.3% Started DNREC permiting; FY11 = Constr. 5 WW0809 M S. Governors Ave. Sewer Main 300,000 291,000 13,561 277,439 4.7% - 279,244 1,805 0.6% Complete Done. US 13 East Sanitary Sewer 6 WW0810 M/SL Interceptor 2,376,800 3,409,641 2,935,473 474,168 86.1% - 2,335,862 2,067,311 88.5% Complete Done. 7 Totals - FY08 $ 7,472,200 $ 7,155,641 $ 3,033,007 $ 4,122,634 42.4% $ - $ 3,168,344 $ 2,091,328 66.0% 8 9 FY2009 10 WQ0905 M/SL Bayard Avenue $ 590,910 $ 590,910 $ 244,909 $ 346,001 41.4% $ - $ 584,420 $ 238,419 40.8% Started Starting construction in March. 11 WQ0906 M/SL East side N. State Street 868,707 877,596 177,178 700,418 20.2% - 847,700 148,175 17.5% Started Phase one complete. 12 WQ0907 M/SL Route 13 Water Main 1,058,700 1,035,898 164,645 871,253 15.9% - 967,801 40,649 4.2% Started Going to bid. Start in May. 13 R Water Quality Improve FY09 $ 2,518,317 $ 2,504,404 $ 586,733 $ 1,917,671 23.4% $ - $ 2,399,921 $ 427,243 62.5% Started 14 y p g 15 WW0902 M/SL Station $ 386,400 $ 386,400 $ 319,767 $ 66,633 82.8% - 240,324 174,052 72.4% Completed Done. Fox Hall/Retreat Force Main Done. Overage covered by US 13 16 WW0905 M/SL Rerouting 133,100 139,245 238,789 (99,544) 171.5% - - 20,351 0.0% Completed Interceptor (WW0810). 17 WW0907 M/SL Acorn Lane P/S Replace. 386,400 386,400 320,133 66,267 82.9% - 210,528 144,622 68.7% Completed Done. 18 Totals - FY09 $ 3,424,217 $ 3,416,449 $ 1,465,422 $ 1,951,027 42.9% $ - $ 2,850,773 $ 766,269 26.9% 19 20 FY2010 21 WD1002 R Remote Control & Monitor Wells $ 55,000 $ 55,000 $ 23,104 $ 31,896 42.0% $ - $ 31,896 $ - 0.0% Started Material ordered. 22 WW1001 M/SL Inflow/Infiltration Removal 1,800,000 1,800,000 42,396 1,757,604 2.4% - 1,798,447 41,175 2.3% Started Construction to start in July. 23 WW1007 M/SL Fox Hall Pump Station 427,900 52,000 49,337 2,663 94.9% 375,900 426,044 47,481 11.1% Started Out to bid. 24 WW1008 M/SL Heatherfield Force Main Rerouting 220,400 40,000 47,288 (7,288) 118.2% 229,200 267,916 46,004 17.2% Started Out ot bid. 25 WW1010 I Tar Ditch Interceptor Upgrade 518,230 518,230 17,816 500,414 3.4% - 516,781 16,367 3.2% Started Reviewing design. 26 WS1001 Various Pump Motor Replace 45,248 45,248 28,877 16,371 63.8% - 45,248 28,877 63.8% Started Grant approved. Ordering begun. 27 Totals - FY10 $ 3,066,778 $ 2,510,478 $ 208,818 $ 2,301,660 8.3% $ 605,100 $ 3,086,332 $ 179,904 5.8% 28 29 FY2011 30 WD1101 Misc. Disb. System Upgrade $ 60,000 $ 60,000 $ - $ 60,000 0.0% $ 60,000 $ 60,000 $ - 0.0% Started On-going as needed. 31 WD1102 Wellhead Redevelopement 60,000 60,000 6,600.00 53,400 11.0% 60,000 60,000 6,600 11.0% Started Work starting in March\April. 32 WQ1101 WQI - Loockerman Street 500,000 60,000 95,244 (35,244) 158.7% 500,000 110,000 95,244 86.6% Complete Awaiting Final Invoices 33 WQ1102 WQI - Columbia Avenue - 303,000 4,250.00 298,750 1.4% - 253,000 4,250 1.7% Not Started Construction in FY12. 34 WQ1103 WQI - Ross Street - 117,000 4,250.00 112,750 3.6% - 117,000 4,250 3.6% Not Started Construction in FY12. 35 WQ1104 WQI - William Street - 10,000 4,250.00 5,750 42.5% - 10,000 4,250 42.5% Not Started Construction in FY12. 36 WQ1105 WQI - West Street (W. Alley) - 10,000 4,250.00 5,750 42.5% - 10,000 4,250 42.5% Not Started Construction in FY12. 37 WW1101 M/SL Inflow/Infiltration Removal 500,000 500,000 8,344.88 491,655 1.7% 500,000 500,000 8,345 1.7% Started Will start after FY10 is done. 38 WW1102 R Scada Tech. Equip. Upgrade 82,100 82,100 74,264 7,836 90.5% 82,100 82,100 74,264 90.5% Started 4 of 7 installed. Del State/Del Tech Force Main Shifted completion to interceptor 39 WW1103 Rerouting 286,500 286,500 333 286,167 0.1% 286,500 286,500 333 0.1% Done (WW0810). 40 WW1104 SL Lepore Road P/S Replacement 52,000 52,000 47,942 4,058 92.2% 52,000 52,000 47,942 92.2% Started Design with Braun. 41 WW1105 R Misc. Sewer System Improve 35,000 35,000 35,152 (152) 100.4% 35,000 35,000 35,152 100.4% Started Ongoing as needed. 42 Totals - FY11 $ 1,575,600 $ 1,575,600 $ 278,280 $ 1,290,720 17.7% $ 1,575,600 $ 1,575,600 $ 284,880 18.1% 43 44 Grand Totals $ 15,538,795 $ 14,658,168 $ 4,985,527 $ 9,666,041 34.0% $ 2,180,700 $ 10,681,049 $ 3,322,381 31.1% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is rebudgeted to start over each fiscal year. SL = State Loan Project - construction phase is financed I = Impact Fee Financed Project Page 4 of 5

City of Dover Electric Improvement & Extension Fund - Major CIP Projects April, 2011 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project % Current Revised Fiscal % Project Project Project To Date Budget Budget Fiscal Yr. Fiscal Yr. YTD Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments 1 FY 2006 2 EE0601 M/B 69 KV feeders 3 and 4 $ 11,060,000 $ 8,693,782 $ 8,761,762 $ (67,980) 100.8% $ - $ 4,242 $ 4,242 100.0% Completed In service. 3 EE0603 M/S Governor's Avenue Rebuild 1,268,450 2,068,260 552,362 1,515,898 26.7% - 250,000 31,901 12.8% Completed Done. 4 Totals - FY06 $ 12,328,450 $ 10,762,042 $ 9,314,123 $ 1,447,919 86.5% $ - $ 254,242 $ 36,143 14.2% 5 6 FY 2008 7 EG0801 Unit 3 Turb Bearing Fire Protect D $ 50,000 $ 50,000 $ 44,720 $ 5,280 89.4% $ - $ 50,000 $ 44,720 89.4% Completed 8 Totals - FY08 $ 50,000 $ 50,000 $ 44,720 $ 5,280 89.4% $ - $ 50,000 $ 44,720 89.4% 9 10 FY2010 11 EG1001 B Vansant CT Mark IV Control $ 700,000 $ 610,000 $ 438,687 $ 171,313 71.9% - $ 152,050 $ 152,050 100.0% Completed In service. 12 EG1002 B McKee Run Entrance Road 240,000 240,000 154,722 85,278 64.5% - 154,244 154,244 100.0% Completed In service. 13 EG1005 Work Mgmt. System Replace 85,000 85,000 26,577 58,423 31.3% - - 9,859 0.0% Completed Done. 14 EG1009 Photovoltaic Install @ McKee - 65,065 65,065 - 100.0% - 65,065 65,065 100.0% Completed In service. 15 EE1005 M/B Mid City Substation 1,488,461 993,711 975,819 17,892 98.2% - 1,087 1,087 100.0% Completed In service. 16 EE1009 S LED Lighting Replacement 70,087 70,010 70,010 0 100.0% - 70,010 70,010 100.0% Completed Installed on Division. 17 EU1002 B Crossgates 396,904 543,075 524,391 18,684 96.6% - 1,441 1,440 100.0% Completed Done. 18 EU1003 B Buchanan Acres 406,000 1,094,646 1,207,967 (113,321) 110.4% - 129,502 129,502 100.0% Completed Done. 19 20 Totals - FY10 $ 3,386,452 $ 3,701,507 $ 3,463,238 $ 238,269 93.6% $ - $ 573,399 $ 583,257 101.7% 21 22 FY2011 23 --- Vehicles & Equipment $ 158,200 $ 158,200 $ 113,437 $ 44,763 71.7% $ 158,200 $ 158,200 $ 113,437 71.7% Started Vehicles being ordered. 24 EE1101 Substation PT & CT Replace 256,218 256,218 216,932 39,286 84.7% 256,218 256,218 216,932 84.7% Started Material being received. 25 EE1102 Replace of 69 kV Breakers 100,000 100,000 98,292 1,708 98.3% 100,000 100,000 98,292 98.3% Completed Installed. 26 EE1103 Lighting Rehabilitation 100,000 107,645 107,644 1 100.0% 100,000 107,645 107,644 100.0% Completed Fox Hall done. 27 EE1104 Walker Road OH Conversion 350,511 - - - 0.0% 350,511 - - 0.0% Dropped Funds reappropriated. 28 EE1105 Engineering Misc Equip. Replace 40,000 40,000 26,126 13,874 65.3% 40,000 40,000 26,126 65.3% Started Ongoing as needed. 29 EE1106 Substation Batteries 24,500 24,500 23,489 1,011 95.9% 24,500 24,500 23,489 95.9% Completed Done. 30 EE1107 Wyoming Mill Road Realignment - 91,000 47,877 43,123 0.0% - 91,000 47,877 52.6% Started Electric line relocation. 31 EE1111 UG Transformers 120,536 120,536 99,458 21,078 82.5% 120,536 120,536 99,458 82.5% Started Ongoing as needed. 32 EE1111 UG Conductors 529,464 521,896 257,621 264,275 49.4% 529,464 521,896 257,621 49.4% Started Ongoing as needed. 33 EE1111 Meters 50,000 50,000 52,151 (2,151) 104.3% 50,000 50,000 52,151 104.3% Started Ongoing as needed. 34 EE1112 69kV Sub Switch Replacement - 180,000 - 180,000 0.0% - 180,000 - 0.0% Not Started Construction in FY12. 35 EG1101 Unit 3 Cooling Tower Fill 353,338 398,338 371,513 26,825 93.3% 353,338 398,338 371,513 93.3% Completed Done. 36 EG1102 Units 1 & 2 Cooling Tower 218,730 173,730 70,280 103,450 40.5% 218,730 173,730 70,280 40.5% Completed Done. 37 EG1103 Unit 3 Tubine Inspection 348,000 - - - 0.0% 348,000 - - 0.0% Started Construction in FY12. 38 EG1104 Unit 3 Aux System Components 113,000 - - - 0.0% 113,000 - - 0.0% Deferred Defered to FY12. 39 EG1105 Plant Misc Equipment Replmnt 71,000 77,000 66,051 10,949 85.8% 71,000 77,000 66,051 85.8% Started Ongoing as needed. 40 EG1106 Unit 3 Stack Repairs 25,000 - - - 0.0% 25,000 - - 0.0% Deffered Defered to FY12. 41 EG1107 Units 1 & 2 Life Extension 276,000 225,000 41,876 183,124 18.6% 276,000 225,000 41,876 18.6% Started In Progress 42 EG1108 Unit 1 Turbine Outage - 412,000 424,747 (12,747) 0.0% - 412,000 424,747 103.1% Completed Emergency repair 43 EG1109 Unit 3 FD & ID FAN CNRL UP 45,000 - - - 0.0% 45,000 - - 0.0% Deferred Next fiscal year. 44 EG1110 Unit 3 DCS Com & Software 30,000 - - - 0.0% 30,000 - - 0.0% Deffered Next fiscal year. 45 EG1111 Unit 2 Boiler Inspection & Repair - 124,000 111,523 12,477 89.9% - 124,000 111,523 89.9% Completed Emergency repair. 46 EG1112 Unit 3 Heat Expansion Joint - 65,000 44,034 20,966 67.7% - 65,000 44,034 67.7% Started Started with spring outage. 47 EG1113 Units 1 & 2 Control Modifications - 150,000 87,976 62,024 58.7% - 150,000 87,976 58.7% Started Started with spring outage. 48 EG1114 Unit 3 Gas Line Modification - 60,000 12,933 47,067 21.6% - 60,000 12,933 21.6% Started Started with spring outage. 49 EU1101 Distribution Upgrades 400,000 373,018 359,353 13,665 96.3% 400,000 373,018 359,353 96.3% Started Ongoing as needed. 50 $ 3,609,497 $ 3,708,081 $ 2,633,314 $ 1,074,767 71.0% $ 3,609,497 $ 3,708,081 $ 2,633,314 71.0% 51 52 Grand Totals $ 19,374,399 $ 18,221,630 $ 15,455,395 $ 2,766,235 84.8% $ 3,609,497 $ 4,585,722 $ 3,297,433 71.9% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is rebudgeted to start over each fiscal year. B = Bonded Project S = State fully or partially reimbursed project Page 5 of 5

4401 Fair Lakes Court Fairfax, VA 22033 USA Phone: 1.703.818.9100 www.paceglobal.com City of Dover April Monthly Report Energy and Operations Management May 26, 2011 This Report was produced by Pace Global Energy Services, LLC (“Pace Global”) and is meant to be read as a whole and in conjunction with this disclaimer. Any use of this Report other than as a whole and in conjunction with this disclaimer is forbidden. Any use of this Report outside of its stated purpose without the prior written consent of Pace Global is forbidden. Except for its stated purpose, this Report may not be copied or distributed in whole or in part without Pace Global’s prior written consent. This Report and the information and statements herein are based in whole or in part on information obtained from various sources as of April, 2011. While Pace Global believes such information to be accurate, it makes no assurances, endorsements or warranties, express or implied, as to the validity, accuracy or completeness of any such information, any conclusions based thereon, or any methods disclosed in this Report. Pace Global assumes no responsibility for the results of any actions and inactions taken on the basis of this Report. By a party using, acting or relying on this Report, such party consents and agrees that Pace Global, its employees, directors, officers, contractors, advisors, members, affiliates, successors and agents shall have no liability with respect to such use, actions, inactions, or reliance. This Report does contain some forward-looking opinions. Certain unanticipated factors could cause actual results to differ from the opinions contained herein. Forward-looking opinions are based on historical and/or current information that relate to future operations, strategies, financial results or other developments. Some of the unanticipated factors, among others, that could cause the actual results to differ include regulatory developments, technological changes, competitive conditions, new products, general economic conditions, changes in tax laws, adequacy of reserves, credit and other risks associated with City of Dover and/or other third parties, significant changes in interest rates and fluctuations in foreign currency exchange rates. Further, certain statements, findings and conclusions in this Report are based on Pace Global’s interpretations of various contracts. Interpretations of these contracts by legal counsel or a jurisdictional body could differ. Setting the Pace in energy since 1976 Washington • Houston • Columbia • London • Moscow

TABLE OF CONTENTS 1.0 – Executive Summary ..............................................................................................................2 2.0 – Budget Report .......................................................................................................................5 2.1 – Variance Report ..................................................................................................................6 2.2 – Variance Analysis ...............................................................................................................8 3.0 – Energy management .............................................................................................................9 3.1 – Purchased Power .................................................................................................................9 3.2 – Generation Management ...................................................................................................12 3.3 – Emissions and Allowance Management ...........................................................................19 4.0 – Operations Management ....................................................................................................24 Appendices ....................................................................................................................................40 I. PJM Invoice Breakdown ....................................................................................................40 II. Load, All In Energy and all in cost of service table...........................................................41 III. Glossary .............................................................................................................................42 1

1.0 – EXECUTIVE SUMMARY All In Unit Energy Cost - Actual v Budget Generation MWh's: Actual v Budget Actual Load vs Budget Load 30,000 100,000 $94 25,000 $92 75,000 $90 20,000 $88 MWh MWh $/MWh 15,000 50,000 $86 $84 10,000 25,000 $82 5,000 $80 0 $78 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen Budget Actual Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA Purchased Power Management Wholesale load for the month of April was 54,359 MWhs, versus a weather normalized projected load of 52,554 MWhs. Hedged transactions accounted for 49,920 MWhs or 92% of this volume (95% of forecasted load) at a cost of $3.48 million. Spot Market purchases resulted in a PJM charge of $388 thousand (a $372 thousand charge in the Day Ahead market and a $16 thousand charge in the Real Time market). Other PJM related charges accounted for an additional cost of $1.41 million, inclusive of all load related fees. The April Energy Only Unit Cost, excluding capacity obligations and credits, was $2.65/MWh favorable compared to the budgeted value of $83.85/MWh. On January 24, 2011, the City of Dover reviewed and approved Pace’s and NAES’ submittal of a revised budget for Dover’s FY2010-11 (the “Reset Budget”). The purpose of this Reset Budget was to provide a mid-year update as to the anticipated cost-of-service for FY2010-11. Dover’s projected all in Cost of Service for FY2010-11 is $88.64/MWh, or $1.88/MWh favorable as compared to the Reset Budget1. Generation and Asset Management For the month of April the McKee Run and Van Sant units were not dispatched into the PJM market. A relatively low average for on-peak LMPs during the month demonstrated that the PJM system did not generally require support from peaking units. The McKee units started a planned outage on March 28 that will last until May23. The budget did not project any generation for this month. Emissions Allowance Management 1 The projected all in Cost of Service is based on YTD actual results for 10 months and 2 months of projected costs. The Reset Budget was reviewed and approved by City of Dover. 2

Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through April 30, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 N/A 2003-2006 139 Carryover 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 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (3) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 54 73 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $0.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. (3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 3

Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $35,274 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $4/ton, 3,976 post-CAIR SO2 allowances trading at $2.50/ton, 73 NOx annual allowances trading at $157.50/ton, and 54 NOx seasonal allowances trading at $20/ton. EMISSIONS & ALLOWANCE SUMMARY Through April 30, 2011 Allowance Allowance Emissions Emissions Allowances Allowances Allowance Vintage Allocation Month Sold Month Sold Balance SO2 – 2007-10 10,157 N/A 131 N/A 4,847 5,179 SO2 – 2011 1,988 0 2 0 0 1,986 2 NOx Annu – 2009 80 0 13 0 45 22 NOx Seas – 2009 53 0 6 0 25 22 NOx Annu – 2010 78 0 122 0 (22) (22) NOx Seas – 2010 50 0 122 0 (53) (19) NOx Annu – 2011 76 0 3 0 0 73 3 NOx Seas – 2011 51 0 0 0 0 51 Operations Management Summary During the month of April there were no reportable or lost time accidents or injuries. The facility has now gone 198 days without an OSHA recordable accident and 198 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were no near miss events. All three Units at McKee Run were in a planned outage. There were no opportunities to generate during the month and no units were dispatched for PJM. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of April were $413,166. The expenses were $23,599 or 5.40% under the approved budget of $436,765. The principal reason for the favorable variance is due to delayed timing of payments for environmental expenses, home office labor and boiler systems that will occur later in the year. 2 Approximately 10 tons of NOx emissions resulted from the February 2010 McKee Run testing associated with the Pollution Remediation project and the June 2010 emission testing project. 3 The EPA reallocated 2 additional seasonal NOx allowances into the McKee Run 2011 account. 4

Risk Management Summary Forward PJM power prices decreased slightly since the last reporting period. Prices decreased as forecasts called for mild temperatures across most parts of the country. Forward Dover Zone power prices for FY 2010-11 increased by $0.13/MWh (an increase of 0.25%) since the last reporting period while FY 2011-2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all changed by approximately -$0.49/MWh to $0.02/MWh (representing a range of -0.91% decrease and a 0.25% increase, respectively) compared with the last reporting period. The individual years’ hedge ratios and Cost-of-Service projections are shown in the table below: Wholesale Cost-of-Service Summary (Projected) Date 5/19/2011 Budget May Apr Mar Cost-of- Cost-of Year-to Cost-of Cost-of Hedge Power Year Service Service Year Service Service Ratio Budget $/MWh1 Increase $/MWh $/MWh 2010-2011 $82.15 $85.93 88% -3.6% $85.83 $85.82 2011-2012 N/A $79.47 85% -7.5% $79.53 $79.49 2012-2013 N/A $72.91 76% -8.3% $73.02 $73.01 2013-2014 N/A $71.87 48% -1.4% $71.96 $71.87 2014-2015 N/A $71.80 19% -0.1% $71.75 $71.38 1 Note that the "Cost-of-Service" column does not reflect the SREC benefit the City will receive since the SREC prices are currently unknown *Difference in COS from asset management due to generation & O&M **Not inclusive of budget update 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance Apr-11 Apr-11 Apr-11 Load Forecast 52,554 54,359 (1,805) Power Supply Power Supply $3,524,034 $3,481,320 $42,714 Power Supply Management $183,188 $180,833 $2,355 Capacity Charges - Load $1,043,503 $1,043,504 ($1) PJM Charges - Load $699,639 $752,006 ($52,368) Total - Power Supply $5,450,364 $5,457,663 ($7,299) Generation 4 Plant Operations $436,765 $413,166 $23,599 Generation Fuel $0 $0 $0 Capacity Credits ($970,188) ($970,188) $0 PJM Credits ($34,012) ($34,012) $0 Total - Generation ($567,435) ($591,034) $23,599 Emission Allowance Sales Total - Emission Allowance Sales $0 $0 $0 Total Power Supply & Generation $4,882,929 $4,866,629 $16,300 Total Power Supply, Generation & Emission Sales $4,882,929 $4,866,629 $16,300 Unit Costs Total – Power Supply $103.71 $100.40 $3.31 Total - Generation + Emission Sales ($10.80) ($10.87) $0.08 Final Cost of Service to City of Dover Ratepayers $92.91 $89.53 $3.39 4 On March 2011, the City Council reviewed and approved NAES’ latest submittal of a revised plant budget for Dover’s FY2010-11. The budgeted O&M values were updated to match the approved City’s plant budget. 6

Budget Actual Variance YTD YTD YTD Load Forecast 626,336 634,249 (7,912) Power Supply Power Supply $40,015,615 $39,834,186 $181,429 Power Supply Management $1,937,798 $1,929,637 $8,161 Capacity Charges - Load $10,572,119 $10,572,122 ($3) PJM Charges - Load $11,244,557 $12,021,836 ($777,278) Total - Power Supply $63,770,090 $64,357,781 ($587,691) Generation Plant Operations $4,796,131 $4,703,800 $92,331 Generation Fuel $3,138,177 $3,376,054 ($237,877) Capacity Credits ($9,842,531) ($9,842,532) $0 PJM Credits ($5,414,579) ($5,686,259) $271,680 Total - Generation ($7,322,803) ($7,448,936) $126,134 Emission Allowance Sales Total - Emission Allowance Sales $11,695 $11,695 $0 Total Power Supply & Generation $56,447,287 $56,908,845 ($461,558) Total Power Supply, Generation & Emission Sales $56,458,982 $56,920,540 ($461,558) Unit Costs Total – Power Supply $101.81 $101.47 $0.34 Total - Generation + Emission Sales ($11.67) ($11.73) $0.05 Final Cost of Service to City of Dover Ratepayers $90.14 $89.74 $0.40 7

2.2 – VARIANCE ANALYSIS Power Supply  Power Supply realized a favorable $43 thousand variance compared to the budget. This favorable variance was primarily due to the timing of Dover’s options purchase and payment of the associated premium. During FY2009-10 the City of Dover purchased Options as insurance to protect Dover from incremental energy cost exposure. The current City of Dover power supply and generation budget indicates that 100% of this purchase was expensed as a Power Supply Cost in the FY2009-10 period; however the FY2010-11 budget accrues this expense monthly.  PJM Charges for Load experienced a negative $52 thousand variance relative to the monthly budget. This variance was driven by Dover’s open position, which was 69% higher than budget. A larger volume of open positions, coupled with higher than projected PJM energy open prices, resulted in a total Open Position cost that was $116 thousand greater than budget. Additional factors contributing to the unfavorable variance included i) a $42 thousand unfavorable variance in PJM Ancillary charges and ii) a $27 thousand unfavorable variance in Transmission Rights Credits. Offsetting these unfavorable variances were a $115 thousand favorable variances in Load Following and a $23 thousand favorable variance in Basis costs.  For the month the City realized a $10 thousand unfavorable net variance between Power Supply (fixed positions) and PJM Charges for Load (open positions, transmission, etc.). The change in volume resulted in an unfavorable $141 thousand variance, and the change in price resulted in a favorable $131 thousand variance. Hence, all of the unfavorable variance can be attributed to volumn changes.  The Power Supply Management variance is merely an estimate at this point. Generation  Plant O&M reported a favorable variance of $24 thousand compared to the revised monthly O&M reset Budget of $437 thousand (the overall reset plant budget for FY 2010-11 was approved by the City Council on March, 2011). The timing of environmental, home office labor and boiler systems expenses created the favorable variance. These expenses will occur at a later date. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights  Dover’s April load was 54,359 MWh, which was 3.4% above the weather normalized load of 52,554 MWh. Hedge volumes accounted for 92% of actual load for the month.  The April All In Unit Energy cost (excluding capacity) of $81.20 per MWh is $2.65 per MWh lower than the monthly budget. Actual Load vs Budget Load 100,000 75,000 MWh 50,000 25,000 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Actual 9

All In Unit Energy Cost - Actual v Budget $94 $92 $90 $88 $/MWh $86 $84 $82 $80 $78 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA 10

Purchased Power Variance Report Budget Actual Variance Apr-11 Apr-11 Apr-11 City of Dover Load Load Obligation (MWh) 52,554 54,359 (1,805) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $76.26 $72.97 $3.29 Pass Through $6.67 $7.33 ($0.66) Incentive Fees $0.93 $0.90 $0.03 Total - All In Unit Energy Cost $83.85 $81.20 $2.65 Purchased Power Variance Analysis  The actual Dover load of 54,359 MWh was 3.4% above the projected April load of 52,554 MWh.  The All In Unit Energy Cost was $2.65 per MWh lower than budget due to a decreased load following and basis charges. Offsetting these positive variances was an increased open position volume and a higher than budgeted energy price, an unfavorable PJM Ancillary charge and a lower than projected transmission related refund.  The Management Incentive fee variance on a $/MWh basis is merely an estimate at this point. PJM Power Balancing and Load Related Fees Purchased Power (Hedges): 49,920 MWhs @ $69.74/MWh: $3,481,320 Power Balancing; Additional PJM, and Energy Manager Fee5: $1,976,343 Total Cost to Serve Load (54,359 MWhs) $5,457,663 All In $/MWh load cost inclusive of Energy Management Fees: $100.40/MWh 5 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT  During the month, PJM did not dispatch Dover’s units into the market. The McKee units started a planned outage on March 28 that will last until May 23. The budget did not project generation for this month. Generation MWh's: Actual v Budget 30,000 25,000 20,000 MWh 15,000 10,000 5,000 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen 12

2010-11 Generation Production Margin v Budget $1,500 Thousands $1,250 $1,000 $750 $500 $250 $0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($) Actual ($) 13

Generation Management Variance Report Budget Actual Variance Apr-11 Apr-11 Apr-11 Self-Supplied Capacity from Gen (MW) McKee Run 1 17 17 0 McKee Run 2 17 17 0 McKee Run 3 100.3 100.3 0 Van Sant 39 39 0 Self Supplied Capacity from Gen (MW) 173.3 173.3 0 Additional Capacity from PJM Incremental Auction 1.7 1.7 0 Total Capacity from Gen (MW) 175 175 0 Gen Capacity Sales to PJM ($/MW.d) $186.12 $186.12 $0.00 Incremental Auction Sales to PJM ($/MW.d) $50.00 $50.00 $0.00 Power Sales Power Sales (MWh) 0 0 0 Sales Revenue ($ per MWh) $0.00 $0.00 $0.00 Power Sales Revenue ($) $0 $0.00 $0 Variable Fuel & Transport Fuel Oil No.2 Volume - McKee (gal) 0 0 0 Fuel Oil No.2 - McKee ($/gal) $0.00 $0.00 $0.00 Fuel Oil No.2 Cost of Goods Sold - McKee ($) $0 $0.00 $0 Fuel Oil No.2 Volume - Van Sant (gal) 0 0 0 Fuel Oil No.2 - Van Sant ($/gal) $0.00 0.00 $0.00 Fuel Oil No.2 Cost of Goods Sold - Van Sant ($) $0.00 0.00 $0.00 Gas Volume (Dth) 0 0 0 Unit Gas Price ($/Dth) $0.00 0 $0.00 Variable Gas Cost ($) $0.00 0 $0.00 Transport ($) $0.00 0 $0.00 Variable Gas and Transport Costs ($) $0.00 $0.00 $0.00 Variable Fuel & Transport Costs ($) $0 $0.00 $0 Testing $0.00 $0.00 $0.00 Generation Production Margin $0.00 $0.00 $0.00 Generation Capacity Payment Total - Generation Capacity Payment ($970,188) ($970,188) $0 14

Generation Management Variance Analysis Fuel Expense  PJM did not dispatch Dover’s units into the market, nor did the units consume natural gas or fuel oil related to power generation. Generation Production Margin Transaction Volumes Revenue/(Cost) PJM Invoice for Power Sold 0 MWhs $0 Fuel and Transport 0 Dth gas/ 0 gal #2 oil $0 0 gal #2 oil Low Sulfur Generation Production Margin 0 MWhs $0 The following non-production energy revenues and costs are generally fixed and are not directly related to generation dispatch and power production. Effective September 2009 FERC approved the City of Dover’s reactive supply service compensation resulting in approximately $29 thousand of revenue per month. PJM Invoice (Black Start) $4,545 Reactive Supply Credit $29,468 Fuel Oil Tank Heating & Black Start Gas Supply $0 Eastern Shore Demand Charge $0 Eastern Shore Transport and Imbalance Charge $0 Transco Demand Charge $0 Non-Production Energy Revenue/(Costs) $34,013 15

Fuel and Transportation  During the month there were no unit dispatches by PJM. Date Volume (Dth) Price ($/Dth) Total Commodity Cost ($) Hess Corp Sub-Total 0 $0.00 $0.00 PESCO Sub-Total 0 $0.00 $0.00 NJNG Sub-Total 0 $0.00 $0.00 Total 0 $0.00 $0.00 Due to the conversion from #6 residual oil to low sulfur #2 oil, the need for a constant supply of natural gas to heat the #6 oil is no longer required. Some gas will still be required for winter space heating of the building(s). Pace will coordinate with NAES on the procurement of such supply. This expense will now fall under the plant’s utility costs and be paid and budgeted for by the station. 16

Gas Transportation Purchased City of Dover decided not to renew agreements with the Eastern Shore Natural Gas Pipeline (“ESNG”) and TransCo to provide firm natural gas deliveries to the McKee Run and Van Sant stations. The City of Dover previously notified ESNG and TransCo of its intent to terminate these existing firm capacity agreements and, as a result, the City no longer pays firm demand charges or adjustments. ESNG FT Demand Charge $ 0 TransCo FT Demand Charge $ 0 Total Purchases $ 0 Other Gas Purchases Commodity and transportation imbalances on Eastern Shore Pipeline for the month resulted in no charge. The components of this charge are summarized as follows: Eastern Shore Transport and Imbalance Charges Imbalance/Dth Estimated Cost/Dth Estimated Total Cost 0 $0.00 $0.00 Transport Volume/Dth $/Dth Total Cost Firm/IT 0 $0.00 $0.00 Net Charge $0.00 17

Purchased Commodity Fuel Oil Summary Neither McKee Run nor Van Sant was dispatched into PJM and no #2 fuel oil was consumed for the month. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of April 30 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch6) McKee Run (#2 Fuel 2,554,105 451,200 3 Oil) Van Sant 258,000 152,369 3 (#2 Fuel Oil) 6 As measured by tank level instruments. Tank levels may change due to oil temperature. 18

3.3 – EMISSIONS AND ALLOWANCE MANAGEMENT Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through April 30, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 N/A 2003-2006 139 Carryover 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 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (3) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 54 73 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 19

(3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $35,274 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $4/ton, 3,976 post-CAIR SO2 allowances trading at $2.50/ton, 73 NOx annual allowances trading at $157.50/ton, and 54 NOx seasonal allowances trading at $20/ton. SO2 SO2 allowances continue to lose value as the likely release of final version of the Environmental Protection Agency’s (EPA) Clean Air Transport Rule (Transport Rule) approaches. Allowances have steadily declined since the lead up to the issuance of the proposed Transport Rule in July 2010 (see Figure 1 – SO2 Prices 2010 - 2011). Should the final Transport Rule adopt similar rules as the proposed version, current vintage SO2 allowances will not be eligible for compliance under the new trading program. Figure 1 – SO2 Prices 2010 - 2011 SO2 Allowance Prices (2010 / 2011) $100.00 $80.00 $60.00 $/ton $40.00 $20.00 $0.00 1/4/2010 2/4/2010 3/4/2010 4/4/2010 5/4/2010 6/4/2010 7/4/2010 8/4/2010 9/4/2010 10/4/2010 11/4/2010 12/4/2010 1/4/2011 2/4/2011 3/4/2011 4/4/2011 5/4/2011 2009 (pre-CAIR) 2010/2011 (post-CAIR) NOx NOX annual allowance prices have steadily declined through most of 2011, continuing their slide from 2010. The late February and early March drop in allowance prices is attributable to the March 1st compliance deadline for 2010 emissions (See Figure 2 – NOX annual prices 2011). Current vintage NOX annual allowances are not expected to be eligible for compliance in the new trading program established by the Transport Rule. Prices between now and the compliance date 20

for 2011 could be volatile, particularly if the high summer temperatures require units to run at levels similar to summer 2010. NOX seasonal prices have remained consistently in the $20 - $30/ton range for all of 2011 (See Figure 3 – NOX seasonal prices 2011.) As with NOX annual and SO2 allowances, new trading rules under the Transport Rule are unlikely to allow current vintage NOX seasonal allowances to qualify for compliance. Figure 2 – NOX annual prices 2011 NOX Annual Allowance Prices 2011 $400.00 $350.00 $300.00 $250.00 $/ton $200.00 $150.00 $100.00 $50.00 $0.00 Figure 3 – NOX seasonal prices 2011 NOX Seasonal Allowance Prices 2011 $35.00 $30.00 $25.00 $20.00 $/ton $15.00 $10.00 $5.00 $0.00 21

SO2 and NOx Outlook Market participants continue to sit largely idle, awaiting some level of regulatory certainty from EPA. The final Transport Rule, setting new emissions trading rules, is expected to be released in June or July this year. The expectation is that there will be new allowances for SO2 and NOX emissions, leaving little value for the existing bank of allowances beyond this year’s compliance requirements. It is difficult to estimate what the future compliance costs for SO2 and NOX emissions will be under new trading rules with a number of variables still unknown - the release of the final Transport Rule should provide some clarity. The method and extent of allowances allocated directly to units, pollution caps, and flexibility in trading will all impact the ultimate compliance costs for regulated units. To date, three separate allowance allocation methodologies have been proposed, which all give Dover varying levels of coverage (See Figure 4 – Three Different Allowance Allocations Proposed by EPA). Figure 4 – Three Different Allowance Allocations Proposed by EPA Original CATR Allocations Annual Ozone 2012 SO2 2014 SO2 NOx Season NOx Plant Allocation Allocation Allocation Allocation McKee Run 2 2 0 14 Van Sant 0 0 5 1 Total 2 2 5 15 New Alternative CATR Allocations: Option 1 Annual Ozone 2012 SO2 2014 SO2 NOx Season NOx Plant Allocation Allocation Allocation Allocation McKee Run 45 45 36 17 Van Sant 3 3 3 1 Total 48 48 38 18 New Alternative CATR Allocations: Option 2 Annual Ozone 2012 SO2 2014 SO2 NOx Season NOx Plant Allocation Allocation Allocation Allocation McKee Run 50 50 37 17 Van Sant 4 4 3 1 Total 53 53 40 19 22

RGGI and Federal Carbon Outlook RGGI allowance prices continue to price at very low levels, as the market is substantially over supplied, forcing prices to levels at or near the statutory price floor (see Figure 5 – RGGI Allowance Prices). Figure 5 – RGGI Allowance Prices RGGI Prices 2011 $1.95 $1.90 $/ton $1.85 $1.80 1/3/2011 2/3/2011 3/3/2011 4/3/2011 5/3/2011 Based on projected generation and emissions, Dover is projected to have an excess of 150,000 allowances through 2013 with a market value at current prices of $283,000. Despite the high level of uncertainty surrounding carbon legislation, Pace Global continues to anticipate an eventual price on carbon at a national level, although the timing, method, and scope of coverage are all substantially unknown at this time. Pace Global expects carbon regulation to evolve through three main drivers: 1. Legislation; 2. EPA regulation under their existing authority; and 3. Linkage of regional and state initiatives. The three carbon pricing drivers will likely develop in parallel and, at times, in concert with one another. Through the three drivers, Pace Global anticipates a national price on carbon emissions via a market based system, or combination of systems, beginning sometime between 2015 and 2018. There have been a number of proposed measures in Congress that would temporarily or permanently negate EPA’s authority to regulate GHGs. Attempts to cut EPA’s regulatory funding for GHG programs in the FY 2011 federal budget were unsuccessful; however the fight will likely continue as Congress debates the FY2012 federal budget. Additionally, bills to permanently repeal EPA’s regulatory authority appear to have stalled for the time being, with insufficient support in the Senate and threats of Presidential veto from the Administration. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights  During the month of April, there were no restricted work days or lost time accidents. The facility has now gone 198 days without an OSHA recordable accident or a lost time reportable accident.  The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month. The EPA reallocated 2 additional NOx seasonal allowances to the McKee Run 2011 account.  No units were dispatched by PJM for the month of April.  The McKee started a planned outage on March 28 that will last until May 23.  XL Insurance contractor was onsite in late April to conduct an annual inspection of the facilities. During his inspection, he toured the plants and reviewed plant documents pertinent to operations, maintenance, safety, environmental and capital projects.  Maintenance, IC&E and Operations Staff completed the Unit 1/2 generator hydrogen fill line purge utilizing the NAES SMP-22 gas purge procedure.  Maintenance staff completed the removal and replacement of the Unit 2 air heater bottom radius seals.  The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware April 2011 Monthly Report New Unit 3 Air Heater Expansion Joint 25

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 26

1.0 Environmental, Health and Safety: During the month of April, there were no restricted work days or lost time accidents. The facility has now gone 198 days without an OSHA recordable accident or a lost time reportable accident. The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month. No further word has been received from the EPA regarding the Unit 3 NOx emissions allowances. Environmental, Health and Safety Statistics Month Fiscal Year to Date (April) (7/1/10-6/30/11) NOVs 0 0 Opacity Deviations 0 13 Environmental Deviations 0 0 OSHA Recordable 0 1 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 6 Man Hours Worked 4,285.25 95,165.50 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 198 Days since last Lost Time Accident 198 Emissions (NOx & SO2) All data thru 4/30/11 NOx Summary - Year (May-Sept.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 119.2 3.3 125.4 2011 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 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 119.2 3.3 125.4 2011 0.0 0.0 1.2 1.6 2.8 27

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 Van Sant YTD Van Sant Run Run (Yr/Season) (Yr/Season) (Yr/Season) (Yr/Season) 2009 45/25 75/50 5/3 12/5 - 1/1 0/0 – 0/0 18/0 4/2 119**/119** - 22##/53# – 2010 0 73/47* 5/3 -46/0 2/0 3/3 0/0 2011 0 71/48### 5/3 1/0 – 2/0 0/0 - 0/0 70/48### 3/3 Note ** - Higher NOx emissions are attributed to data substitution rules that use significantly higher emission rates than actually were emitted. The implementation of the data substitution rules were caused by performing a linearity test outside the grace period. NAES ESS was able to provide assistance in reducing the NOx emissions from 137 tons to 119 tons since the October report. A petition to the EPA was sent out in February that would result in a reduction in reported emissions. The EPA has given preliminary approval to the petition request although it is not official until the plant receives a signed EPA approval. Until the issue is resolved, the EPA has locked the annual account and no allowances will be deducted until that time. Note# - 53 tons were purchased to help compensate for the shortage in seasonal NOx allowances. Note## - 22 tons were purchased to help compensate for the shortage in annual NOx allowances. Note###- 2 tons were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 Note: Data is as of 4/30/2011 SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 2003-2006 139 138 1 0 0 2007 2455 2585 138 98 170 2008 2392 2585 138 32 299 2009 0 2585 138 0 2723 2010 0 1850 138 0 1988 2011 0 1850 138 1 1987 Note: Data is as of 4/30/2011 28

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 Van Sant 2009 0 59,805 1,699 5,796 55,708 2010 0 47,844 1,636 32,971 16,509 2011 0 35,883 1,227 1,380 35,730 2012 0 23,922 818 0 24,740 2013 0 11,961 409 0 12,370 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System 29

2.0 Financial Financial – Current Month Month –April 2011 Actual Budget Variance Personnel 251,971 248,772 (3,199) Materials & Supplies 9,486 12,231 2,745 Administrative Expenses 151,709 175,762 24,053 Total $413,166 $436,765 23,599 Financial – Fiscal Year to Date Number of Months - 10 Actual Budget Variance Personnel 2,530,236 2,527,037 (3,199) Materials & Supplies 221,896 224,641 2,745 Administrative Expenses 1,951,670 1,975,723 24,053 Total $4,703,802 $4,727,401 $23,599 2.1 Variance analysis: The adjusted (annual reset) budget for April was $436,765. The actual expenses for April were $413,166 for a favorable variance of $23,599 or ≈ 5.40%. The variance was due to the following: PERSONNEL EXPENSES - Labor, overtime, and burdens accounted for a total monthly unfavorable variance of $3,199. A lower overtime expense due to scheduling changes and flex time usage was offset by higher than budgeted straight time expenses due to the flex leave payout of a recently terminated (resignation) employee. An increase in burdens was also due to the employee flex leave payout. MATERIALS AND SUPPLIES EXPENSES- Lower expenses in Office Supplies and Security/Safety Materials accounted for a favorable variance of $2,745 for the month of April. ADMINISTRATIVE EXPENSES – During the month of April, a favorable variance of $24,053 was realized due to lower expenses in Environmental Expenses, Home Office Labor, Auxiliary Systems, Boiler Systems, and Combustion Turbine Maintenance. The current budget forecast for the current fiscal year is $6,159,886 expensed versus an adjusted budget of $6,163,315 thereby realizing a 99.94%.expense rate. 30

3.0 Operations Unit Operations / Outages / Trips No units were dispatched by PJM for the month of April. All three units at McKee Run remain in a Planned Outage. Unit 11 at Van Sant is ready and available for dispatch if needed. Month – April 2011 McKee McKee McKee MRS Van Sant 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 24.232 24.232 142.615 191.079 3.687 191.083 Auxiliaries purchased MWh 24.232 24.232 142.615 191.079 3.687 191.083 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 % 0.0 0.0 0.0 0.0 100.00 25.000 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 720.000 720.000 720.000 2,160.000 0.0 2,160.000 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 0.0 0.0 0.0 0.0 720.000 720.000 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 0 0 0 0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 31

2010-2011 Fiscal Year-to-Date (10 Months) McKee McKee McKee MRS Van Sant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 13.033 128.966 645.256 787.255 137.790 1,062.089 On Line Hours Hrs 1 3 44 48 35 83 Starts # 154.626 1,216.601 45,570.285 46,941.512 4,635.447 51,576.959 Gross Generation MWh 147.111 1,141.623 42,968.696 44,257.430 4,632.241 51,189.671 Net Generation MWh 310.469 377.931 5,396.933 6,085.333 41.416 6,126.749 Total Auxiliaries MWh 302.954 302.954 2,678.144 3,284.052 38.720 3,322.772 Auxiliaries purchased MWh 2,183.250 15,245.85 452,018.83 469,447.93 53,944.276 523,392.21 0 7 7 2 Fuel Gas Used MMBTU 0.0 0.0 17,721.260 17,721.260 3,790.097 21,511.357 Fuel Oil Used MMBTU 0.0 0.0 125,088 125,088 27,385 152,473 Fuel Oil Used Gallons 2,183.250 15,245.85 469,740.09 487,169.19 61,323.669 548,492.86 0 8 8 7 Total Fuel MMBTU 14,841 13,355 11,696 13,297 13,192 13,245 Net Heat Rate BTU/KWh 1 0 3 4 3 7 Unit Trips # 0.12 0.92 5.66 4.38 1.63 4.38 Capacity Factor % 62.78 70.73 70.64 68.05 96.61 75.19 Availability Factor % 6.6 0 0.03* 0.85 0 0.66 Commercial 2,135.500 2,135.500 % 2,135.500 6,406.500 247.317 8,789.317 Unavailability (CU) Planned Outage Hours Hours 0.0 0.0 0.0 0.0 5.433 5.433 Maintenance Outage Hours 579.830 0 6.317 586.15 0 586.15 Hours Forced Outage Hours Hours 4,580.670 5,031.534 4,580.143 14,192.347 6,905.456 21,097.803 Reserve Shutdown 13.033 128.966 645.256 787.255 137.790 1,062.089 Hours Hours HW Boiler Gas Usage MMBTU 4,816.910 4,816.910 Pilot Gas Usage MMBTU 0 0 0 0 Note: * Calculation does not include 3.317 hours that were Outside Management Control (OMC) Capacity Testing – FY 2010-2011 Summer 2010 (June 1- Aug 31) Winter 2010-2011 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.20 1 17 * 2 17 18.09 2 17 * 3 102 102.68 3 102 105.61 Van Sant 39 39.30 11 39 43.833 Total 175 178.67 Total 175 149.443 32

Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 10-11 Fuel FY 10-11 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 451,200 451,200 0 0 448,556 118,549 2,644 Van Sant 151,358 152,369 0 1,011 143,099 38,079 9,270 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. Van Sant Lifetime through 4/30/11 Actual Starts Factored Starts Fired Hours Van Sant 1252 2161.15 4110.66 Since HGP - Dec 2004 201 493.45 727.08 Team Report: Operations personnel have been labeling substations, motor control centers and circuit breaker cubicles with Arc Flash Warning labels based on the results of the Arc Flash study. The operators have been placing labeling on plant breaker panels and motor control centers throughout the McKee Run plant and Van Sant facility to aid in ensuring arc flash and shock hazards are more identifiable. In addition, workers will be able to more easily identify the appropriate level of PPE necessary to complete an assigned task related to the piece of equipment as well as protect others who may be in the vicinity of the hazard zones. 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 new gas valves and in the hydrogen line purge to change out the piping. 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 provided support to maintenance by working on Preventative Maintenance (PM) work orders or other work orders that they have the necessary skills to complete successfully. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. 33

4.0 Maintenance During the month of April, plant maintenance staff continued addressing the backlog of work orders. There were forty work orders issued with ninety-two work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report April - 10 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 8 2 6 4 2 22 7 7 22 3 46 7 22 31 4 50 0 4 46 5 11 0 2 9 SW1 0 0 0 0 SW2 2 0 2 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 63 24 49 38 Totals 202 40 92 150 Note: PM's are included in the priority totals Notable activities during the month include: 1. Maintenance, IC&E and Operations Staff completed the Unit 1/2 generator hydrogen fill line purge utilizing the NAES SMP-22 gas purge procedure. Safe removal of hydrogen from the piping by a nitrogen purge was completed and removal of the old piping was done. New stainless steel piping was installed and pressure testing will be done prior to hydrogen being introduced back into the line. 2. The condenser cleaning contractor, Projectile Tube Cleaning, with assistance from NAES staff, completed tube cleaning on both condensers. Upon completion of the tube cleaning, each hotwell was flooded above the condenser tubes and no leaks were found. 3. Maintenance staff completed the removal and replacement of the Unit 2 air heater bottom radius seals. Seals were damaged when the soot blower steam piping failed, causing the arm to hit and damage several sections of seals. Replacement on the entire set will help improve overall air heater efficiency. 34

4. Maintenance staff, with assistance from the City of Dover water department, removed and replaced a fire protection piping spool piece and gasket that had reached the end of its’ service life. During the annual fire protection system testing, a gasket was found to have failed and during the replacement of the gasket, it was discovered that the spool piece also needed replacing. The City of Dover water department was contacted for availability of parts. New parts were expedited to the plant, repairs made to the fire protection system and the system returned to service. 35

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: No other work is planned for this project during the Unit 3 Cooling remainder of the fiscal year. EG1101 Tower Life Schedule: Work scope development for next year will commence in Extension April 2011. Progress: The scope of work on the lower, lower decking support Units 1 & 2 Cooling and stairways improvement will be completed in May. EG1102 Tower Life Schedule: Work is slated to be completed in the Spring 2011 Extension Outage. Progress: Started on the development of the project work scope Unit 3 Turbine documents. EG1103 Inspection Schedule: This project has been deferred until 2011-2012 fiscal year. Progress: Started on the development of the project work scope Unit 3 Aux System EG1104 documents. Components Schedule: Deferred until 2011-2012 fiscal year. Progress: This project is for the unexpected capital costs due to Miscellaneous equipment failure. EG1105 Capital Equipment Schedule: Funds to date have been used to cover the cost of the Replacements Unit 3 600-lb steam station valve repairs, Unit 3 Cooling Water Booster Pump Repairs and circuit breakers. Progress: Started on the development of the project work scope EG1106 Unit 3 Stack Repairs document. Schedule: Deferred until 2011-2012 fiscal year. Progress: The scope of work will be completed in early May.During the inspection, additional work was identified as being needed on Units 1 & 2 Life EG1107 both units. Extension Schedule: A reduced scope of work will be completed in early May. Other work has been deferred until the 2011-2012 fiscal year. Unit 1 Forced Progress: The repair work has been completed. EG1108 Outage Repairs Schedule: This work is complete. Progress: Started on the development of the project work scope Unit 3 FD & ID Fan EG1109 documents. Damper Upgrade Schedule: Deferred until 2011-2012 fiscal year. Unit 3 DCS Progress: Started on the development of the project work scope EG1110 Computers & documents. Software Upgrades Schedule: Deferred until 2011-2012 fiscal year. Unit 2 Boiler Progress: Inspections and other repairs were completed during the EG1111 Inspections and Fall 2010 Outage. Repairs Schedule: Miscellaneous work is being wrapped up to complete the 36

project. Progress: The bid was awarded and expansion joint was installed in April. Insulation and lagging will be installed over the expansion Unit 3 Air Heater EG1112 joint in May. Expansion Joint Schedule: Work continues with the installation of the insulation and the lagging in May. Progress: Work continues with the installation of the wiring and Units 1 & 2 Controls new oil valves. EG1113 Modifications Schedule: Final installation of the control system wiring and system checkout and testing will be completed in late May. Progress: The gas line was successfully purged and the gas lines Unit 3 Gas Line were cut for each deck and new gas valves were installed EG1114 Modifications Schedule: Scheduled to be completed in May during the Spring Outage once the system is operationally checked. 5.1 CIP Budget Approved Latest Project Budget Description Estimate Number ($ X ($ X 1000) 1000) EG1101 Unit 3 Cooling Tower Life Extension 398 372 EG1102 Units 1 & 2 Cooling Tower Life Extension 173 120 EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 77 66 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 225 225 EG1108 Unit 1 Forced Outage Repairs 412** 424 EG1109 Unit 3 FD & ID Fan Damper Upgrade 45 45 Unit 3 DCS Computers & Software EG1110 30 30 Upgrades EG1111 Unit 2 Boiler Inspections and Repairs 124## 124 EG1112 Unit 3 Air Heater Expansion Joint 65## 75 37

EG1113 Units 1 & 2 Controls Modifications 150## 150 EG1114 Unit 3 Gas Line Modifications 60## 60 ** This project was not budgeted for 2011. ## Project was not in original FY11 CIP but was approved by COD Council in late 2010. 6.0 General Plant Information Training: On April 6, Brian Hoyt, Phil Kosek, Ron McNair, and Eric Petty attended DOT/RCRA Hazardous Waste training sponsored by Nexeo Solutions (formerly Ashland). This training encompasses identification, characterization, storage, and handling of facility wastes in compliance with EPA and DOT regulations. Plant employees continue 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. The teams are continuing to train to complete and review their EDQP program. The operators use the program to train for a position desired and also as a review of programs as well reinforce current knowledge. The General Physics and the PJM on line courses are used in the training as well. Personnel: On April 6, Jeff Luff, Operations Supervisor, submitted his resignation to pursue other interests. His official last day of work was April 20. A celebration was held in the control room on April 19th to acknowledge his friendship, his support to the plant and other plant employees and his almost 30 years of service working at City of Dover facilities. Other: Neal Grabow, XL Insurance contractor, was onsite in late April to conduct an annual inspection of the facilities. During his inspection, he toured the plants and reviewed plant documents pertinent to operations, maintenance, safety, environmental and capital projects. He had no new recommendations and was impressed the amount of work activity that had taken place since his site visit last year. 38

Calendar of Events Date Units 1, 2, and 3 Spring Outage March 28, 2011 – May 23, 3011 EIA-860 Report April 29, 2011 EIA-923 Report May 6, 2011 Van Sant 5 Year SPCC Plan Recertification June 27, 2011 Fiscal Year 2010-2011 Ends June 30, 2011 PJM Summer Capacity Test Period June 1, 2011- August 31, 2011 Toxic Release Inventory (TRI) Annual Report July 1, 2011 Unit 3 RATA Testing July 29, 2011 McKee Run and Van Sant Title V Semi-Annual Certification Due August 1, 2011 NOx Ozone Season Starts May 1, 2011 NOx Ozone Season Ends September 30, 2011 One Year Accident Free October 14, 2011 Units 1, 2, 3 and 11 Fall Outage TBD Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and Van Sant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual Van Sant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD Air Emission Inventory April 1, 2012 McKee Run Title V Permit Renewal April 20, 2012 7.0 Summary of NAES Performance to Date Plant Performance FY 2010-2011 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0.66% $63,262 $89,586 Unavailability (CU) Safety 1 1 $8,398 $16,797 Environmental 0 0 $16,797 $16,797 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,360 $3,360 Unit 2 No No Yes Yes* $3,360 $3,360 Unit 3 No No Yes Yes $20,157 $20,157 Unit 11 No No Yes Yes $6,719 $6,719 Total YTD 77.85% Total YTD Incentive $122,052 $156,775 Incentive % Note - * Unit did not operate in the Winter period and was in the PJM Winter Capacity Test Exemption Program 39

APPENDICES I. PJM INVOICE BREAKDOWN The PJM bill is a record of all Electricity Transactions, Transmission Services, Ancillary Services and Miscellaneous fees that allow the PJM to operate. Below is a list of the line items on the PJM bill including all generator activity. PJM Bill Line Items Gen Load Net Day Ahead Energy $0.00 ($372,352.18) ($372,352.18) Realtime Energy $0.00 ($15,702.66) ($15,702.66) Transmission Losses Credits $0.00 $34,387.23 $34,387.23 Network Integration Transmission Service Charges $0.00 ($257,192.70) ($257,192.70) Inadvertent Interchange Charges $0.00 ($2,735.43) ($2,735.43) Regulation Charges $0.00 ($17,288.98) ($17,288.98) Synchronized Reserve Charges $0.00 ($20,933.43) ($20,933.43) Balancing Operating Reserves Charges $0.00 ($5,109.98) ($5,109.98) Day Ahead Operating Reserves Charges $0.00 ($5,332.53) ($5,332.53) Day-ahead Scheduling Reserve $0.00 ($27.06) ($27.06) Synchronous Condensing Charges $0.00 ($13.83) ($13.83) Reactive Services Charges $0.00 ($52,837.50) ($52,837.50) Meter Correction Charges $0.00 $3,477.19 $3,477.19 Day-ahead Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserves Credits $0.00 $0.00 $0.00 Day Ahead Operating Reserves Credits $0.00 $0.00 $0.00 Locational Reliability Charges $0.00 ($1,045,193.40) ($1,045,193.40) Capacity Transfer Rights Credits $0.00 $1,689.30 $1,689.30 Capacity Resource Deficiency Credits $0.00 $0.30 $0.30 Demand Response and ILR Compliance Penalty Credits $0.00 $0.00 $0.00 RPM Auction Credits $970,188.00 $0.00 $970,188.00 Auction Revenue Rights Credits $0.00 $30,433.80 $30,433.80 Synchronized Reserve Credits $0.00 $0.00 $0.00 PJM Scheduling System Control and Dispatch Service Charges $0.00 ($13,831.66) ($13,831.66) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($4,120.12) ($4,120.12) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($31,721.12) ($31,721.12) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,207.84) ($1,207.84) North American Electric Reliability Corporation (NERC) Charge $0.00 ($482.43) ($482.43) Reliability First Corporation (RFC) Charges $0.00 ($731.96) ($731.96) Expansion Cost Recovery Charges $0.00 ($408.60) ($408.60) Transmission Enhancement Charges $0.00 ($16,003.08) ($16,003.08) Black Start Service Credits $4,544.50 $0.00 $4,544.50 Non-Firm Point-to-Point Transmission Service Credits $0.00 $542.26 $542.26 Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($281.06) ($281.06) 40

Organization of PJM States, Inc. (OPSI) Funding $0.00 ($34.38) ($34.38) FERC Annual Recovery $0.00 ($3,121.95) ($3,121.95) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 $508.07 $508.07 PPA $0.00 ($625.50) ($625.50) $1,004,200.08 ($1,795,510.19) ($791,310.11) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) Jul 83,163 83,163 $90.72 $90.72 $90.72 $81.36 $81.36 $81.36 Aug 78,755 78,755 $82.76 $82.76 $86.85 $83.03 $83.03 $82.17 Sep 66,782 66,782 $82.73 $82.73 $85.65 $91.13 $91.13 $84.79 Oct 56,452 56,452 $79.72 $79.72 $84.47 $87.24 $87.24 $85.27 Nov 54,396 54,396 $82.56 $82.56 $84.17 $91.56 $91.56 $86.28 Dec 63,566 63,566 $87.33 $87.33 $84.67 $98.22 $98.22 $88.16 Jan 60,136 64,462 $86.66 $91.77 $85.65 $94.36 $97.13 $89.40 Feb 54,199 54,900 $85.32 $84.37 $85.51 $94.11 $92.95 $89.77 Mar 56,334 57,414 $85.66 $81.75 $85.14 $93.39 $89.70 $89.77 Apr 52,554 54,359 $83.85 $81.20 $84.80 $92.99 $89.53 $89.74 May 58,744 $79.63 $85.58 Jun 67,331 $80.51 $96.23 41

III. GLOSSARY Energy Only Unit Cost ("EOU") accounts for the wholesale energy costs excluding capacity obligations, capacity credits for Dover-owned generation, generation revenues, generating plant costs, the black start ancillary services credit for the Van Sant plant, and revenues associated with the sale of emission allowances. The AIE includes the costs from settling the hedged or forward transactions; the energy bought on the ISO (Independent System Operator or PJM) day-ahead to cover the open position (un-hedged); load following costs associated with balancing the actual load in the ISO real-time market; energy management service related fees; the ISO transmission charges and credits to load serving entities; the ISO ancillary services charges such as generation regulation, spinning reserve, and reactive power; and the ISO administrative charges and cost of service recovery fees. All In Cost of Service ("AICS") accounts for the net cost of wholesale power to the City of Dover Electric Utility. The AICS starts with the AIE and adds the costs or credits from capacity obligations, capacity credits for Dover-owned generation, generation revenues, generating plant costs, the black start ancillary services credit for the Van Sant plant, and revenues associated with the sale of emission allowances. Black Start is a generating ancillary service that is the process of restoring a generating plant to service without the support of an external power supply to power auxiliary equipment needed for start up operations. Capacity UCAP Obligated Purchased is the obligation and payment by all load serving entities in PJM including Dover for the Unforced Capacity (UCAP) requirement from PJM that satisfies the PJM reserve requirements. Generation Capacity Credit: is the credit provided to generators for supply capacity to the system. The price is determined by the PJM Reliability Pricing Market auction process that includes three auctions for each capacity year. Generation Production Margin accounts for the variable margin excluding variable O&M and emissions. The Generation Production Margin is calculated by taking the PJM revenues credited to the plant including any balancing charges or credits less the fuel costs. Generation Production Margin includes both “Economic and reliability dispatch” and “Testing.” Economic and reliability dispatch equals the margin achieved when Dover’s generating plants are dispatched by PJM for either economic dispatch (the system energy price is greater than the Dover bid price) or reliability dispatch whereby PJM pays the generating cost of the plants for the hours the plant is run to support the system. Generation Testing equals the Generation Production Margin associated with testing. This is usually expected to be a negative margin because the plant is potentially being dispatched / run when energy prices do not cover its costs. Non-Production Revenue equals the credits from PJM to Dover for Generation Capacity Credit, the Black Start Revenue and the sales by Dover of Emission Allowances. 42

4401 Fair Lakes Court Fairfax, VA 22033 USA Phone: 1.703.818.9100 www.paceglobal.com City of Dover March Monthly Report Energy and Operations Management April 28, 2011 This Report was produced by Pace Global Energy Services, LLC (“Pace Global”) and is meant to be read as a whole and in conjunction with this disclaimer. Any use of this Report other than as a whole and in conjunction with this disclaimer is forbidden. Any use of this Report outside of its stated purpose without the prior written consent of Pace Global is forbidden. Except for its stated purpose, this Report may not be copied or distributed in whole or in part without Pace Global’s prior written consent. This Report and the information and statements herein are based in whole or in part on information obtained from various sources as of March, 2011. While Pace Global believes such information to be accurate, it makes no assurances, endorsements or warranties, express or implied, as to the validity, accuracy or completeness of any such information, any conclusions based thereon, or any methods disclosed in this Report. Pace Global assumes no responsibility for the results of any actions and inactions taken on the basis of this Report. By a party using, acting or relying on this Report, such party consents and agrees that Pace Global, its employees, directors, officers, contractors, advisors, members, affiliates, successors and agents shall have no liability with respect to such use, actions, inactions, or reliance. This Report does contain some forward-looking opinions. Certain unanticipated factors could cause actual results to differ from the opinions contained herein. Forward-looking opinions are based on historical and/or current information that relate to future operations, strategies, financial results or other developments. Some of the unanticipated factors, among others, that could cause the actual results to differ include regulatory developments, technological changes, competitive conditions, new products, general economic conditions, changes in tax laws, adequacy of reserves, credit and other risks associated with City of Dover and/or other third parties, significant changes in interest rates and fluctuations in foreign currency exchange rates. Further, certain statements, findings and conclusions in this Report are based on Pace Global’s interpretations of various contracts. Interpretations of these contracts by legal counsel or a jurisdictional body could differ. Setting the Pace in energy since 1976 Washington • Houston • Columbia • London • Moscow

TABLE OF CONTENTS 1.0 – Executive Summary ..............................................................................................................2 2.0 – Budget Report .......................................................................................................................5 2.1 – Variance Report ..................................................................................................................6 2.2 – Variance Analysis ...............................................................................................................8 3.0 – Energy management .............................................................................................................9 3.1 – Purchased Power .................................................................................................................9 3.2 – Generation Management ...................................................................................................12 3.3 – Emissions and Allowance Management ...........................................................................19 4.0 – Operations Management ....................................................................................................24 Appendices ....................................................................................................................................39 I. PJM Invoice Breakdown ....................................................................................................39 II. Load, All In Energy and all in cost of service table...........................................................40 III. Glossary .............................................................................................................................41 1

1.0 – EXECUTIVE SUMMARY All In Unit Energy Cost - Actual v Budget Generation MWh's: Actual v Budget Actual Load vs Budget Load 30,000 100,000 $94 $92 25,000 75,000 $90 20,000 $88 MWh MWh $/MWh 15,000 50,000 $86 $84 10,000 25,000 $82 5,000 $80 0 $78 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen Budget Actual Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA Purchased Power Management Wholesale load for the month of March was 57,414 MWhs, versus a weather normalized projected load of 56,334 MWhs. Hedged transactions accounted for 48,155 MWhs or 84% of this volume (85% of forecasted load) at a cost of $3.72 million. Spot Market purchases resulted in a PJM charge of $453 thousand (a $506 thousand charge in the Day Ahead market and a $53 thousand credit in the Real Time market). Other PJM related charges accounted for an additional cost of $1.41 million, inclusive of all load related fees. The March Energy Only Unit Cost, excluding capacity obligations and credits, was $3.91/MWh favorable compared to the budgeted value of $85.66/MWh. On January 24, 2011, the City of Dover reviewed and approved Pace’s and NAES’ submittal of a revised budget for Dover’s FY2010-11 (the “Reset Budget”). The purpose of this Reset Budget was to provide a mid-year update as to the anticipated cost-of- service for the FY2010-11. Dover’s projected all in Cost of Service for FY2010-2011 is $88.78/MWh, or $1.88/MWh favorable as compared to the Reset Budget1. Generation and Asset Management For the month of March the McKee Run and Van Sant units were not dispatched into the PJM market. A relatively low average for on-peak LMPs during the month demonstrated that the PJM system did not generally require support from peaking units. Van Sant unit performed a planned outage from March 14 to 24 and the Units at McKee started a planned outage on March 28 that will last until May23. After several testing attempts, Van San unit successfully completed the annual Black Start Test. The budget did not project generation for this month. Emissions Allowance Management 1 The projected all in Cost of Service is based on YTD actual results for 8 months and 4 months of projected costs. The Reset Budget was reviewed and approved by City of Dover. 2

Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet its 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover its 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Pace has set aside a projected number of allowances to handle estimated dispatch events for the year (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through March 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 N/A 2003-2006 139 Carryover 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 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (2) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 52 74 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $.50/ton broker fee for SO 2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. (3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 3

Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $44,918 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $6/ton, 3976 post-CAIR SO2 allowances trading at $4/ton, 52 NOx annual allowances trading at $170/ton, and 52 NOx seasonal allowances trading at $20/ton. EMISSIONS & ALLOWANCE SUMMARY Through March 31, 2011 Allowance Allowance Emissions Emissions Allowances Allowances Allowance Vintage Allocation Month Sold Month Sold Balance SO2 – 2007-10 10,157 N/A 131 N/A 4,847 5,179 SO2 – 2011 1,988 0 2 0 0 1,986 2 NOx Annu – 2009 80 0 13 0 45 22 NOx Seas – 2009 53 0 6 0 25 22 NOx Annu – 2010 78 0 122 0 (22) (22) NOx Seas – 2010 50 0 122 0 (53) (19) NOx Annu – 2011 76 0 2 0 0 74 NOx Seas – 2011 49 0 0 0 0 49 Operations Management Summary During the month of March, there were no reportable or lost time accidents or injuries. The facility has now gone 168 days without an OSHA recordable accident and 168 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were no near miss events. There were no opportunities to generate during the month and no units were dispatched for PJM. Planned outage on Unit 11 was completed on March 24. A black start test was successfully completed on that unit during the month. McKee Run Units 1, 2 and 3 started a planned outage on March 28. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of March were $414,919. The expenses were $47,908 or 13.05% over the approved budget of $367,0113. The principal reason for the negative variance is due to timing of insurance expenses and higher than budgeted expenses in electric, heating oil and gas,and boiler systems repairs. 2 Approximately 10 tons of NOx emissions resulted from the February 2010 McKee Run testing associated with the Pollution Remediation project and the June 2010 emission testing project. 3 NAES will reflect the reset monthly and year-to-date financial data starting on April 2011 Monthly Report. 4

Risk Management Summary Forward PJM power prices rose slightly since the last reporting period. Prices increased largely due to more moderate temperatures sweeping across much of the country combined with more bullish storage numbers. Forward Dover Zone power prices for FY 2010-11 increased by $0.16/MWh (an increase of 0.31%) since the last reporting period while FY 2011-2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all increased by approximately $0.02/MWh to $0.47/MWh (representing a range of 0.03% increase and a 0.78% increase, respectively) compared with the last reporting period. The individual years’ hedge ratios and Cost-of-Service projections are shown in the table below: Wholesale Cost-of-Service Summary (Projected) Date 4/21/2011 Budget April Mar Feb Cost-of- Cost-of Year-to Cost-of Cost-of Hedge Power Year Service Service Year Service Service Ratio Budget $/MWh1 Increase $/MWh $/MWh 2010-2011 $82.15 $85.65 90% -3.9% $85.82 $85.65 2011-2012 N/A $79.53 85% -7.1% $79.49 $78.94 2012-2013 N/A $73.02 76% -8.2% $73.01 $72.22 2013-2014 N/A $71.96 48% -1.4% $71.87 $70.08 2014-2015 N/A $71.75 16% -0.3% $71.38 $68.08 1 Note that the "Cost-of-Service" column does not reflect the SREC benefit the City will receive since the SREC prices are currently unknown *Difference in COS from asset management due to generation & O&M **Not inclusive of budget update 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance Mar-11 Mar-11 Mar-11 Load Forecast 56,334 57,414 (1,080) Power Supply Power Supply $3,770,779 $3,724,992 $45,787 Power Supply Management $186,705 $183,766 $2,939 Capacity Charges - Load $1,078,286 $1,078,287 ($1) PJM Charges - Load $867,876 $784,844 $83,032 Total - Power Supply $5,903,646 $5,771,889 $131,757 Generation Plant Operations $394,011 $414,918 ($20,907) Generation Fuel $0 $0 $0 Capacity Credits ($1,002,527) ($1,002,528) $0 PJM Credits ($34,012) ($34,012) $0 Total - Generation ($642,529) ($621,622) ($20,907) Emission Allowance Sales Total - Emission Allowance Sales $0 $0 $0 Total Power Supply & Generation $5,261,118 $5,150,267 $110,850 Total Power Supply, Generation & Emission Sales $5,261,118 $5,150,267 $110,850 Unit Costs Total – Power Supply $104.80 $100.53 $4.27 Total - Generation + Emission Sales ($11.41) ($10.83) ($0.58) Final Cost of Service to City of Dover Ratepayers $93.39 $89.70 $3.69 6

Budget Actual Variance YTD YTD YTD Load Forecast 573,782 579,890 (6,107) Power Supply Power Supply $36,491,581 $36,352,866 $138,715 Power Supply Management $1,754,610 $1,748,804 $5,806 Capacity Charges - Load $9,528,616 $9,528,618 ($2) PJM Charges - Load $10,544,919 $11,269,830 ($724,911) Total - Power Supply $58,319,726 $58,900,118 ($580,392) Generation Plant Operations $4,359,366 $4,290,634 $68,732 Generation Fuel $3,138,177 $3,376,054 ($237,877) Capacity Credits ($8,872,343) ($8,872,344) $0 PJM Credits ($5,380,567) ($5,652,247) $271,680 Total - Generation ($6,755,368) ($6,857,902) $102,535 Emission Allowance Sales Total - Emission Allowance Sales $11,695 $11,695 $0 Total Power Supply & Generation $51,564,358 $52,042,216 ($477,858) Total Power Supply, Generation & Emission Sales $51,576,053 $52,053,911 ($477,858) Unit Costs Total – Power Supply $101.64 $101.57 $0.07 Total - Generation + Emission Sales ($11.75) ($11.81) $0.05 Final Cost of Service to City of Dover Ratepayers $89.89 $89.77 $0.12 7

2.2 – VARIANCE ANALYSIS Power Supply  Power Supply realized a favorable $46 thousand variance compared to the budget. This favorable variance was primarily due to the timing of Dover’s options purchase and payment of the associated premium. During FY2009-10 the City of Dover purchased Options as insurance to protect Dover from incremental energy cost exposure. The current City of Dover power supply and generation budget indicates that 100% of this purchase was expensed as a Power Supply Cost in the FY2009-10 period; however the FY2010-11 budget accrues this expense monthly.  PJM Charges for Load experienced a positive $83 thousand variance relative to the monthly budget. This variance was driven by Dover’s load following position, which was $194 thousand favorable compared to budget. In addition, Dover realized a $17 thousand favorable variance in Basis costs. Offsetting these favorable variances included i) a $96 thousand unfavorable variance in Open Position, which was 13% higher than budget; ii) a $16 thousand unfavorable variance in Transmission Rights Credits; and iii) a $10 thousand unfavorable variance in PJM Ancillary charges.  For the month the City realized a $129 thousand favorable net variance between Power Supply (fixed positions) and PJM Charges for Load (open positions, transmission, etc.). The change in volume resulted in an unfavorable $85 thousand variance, and the change in price resulted in a favorable $214 thousand variance. Hence, all of the favorable variance can be attributed to pricing changes.  The Power Supply Management variance is merely an estimate at this point. Generation  Plant O&M reported an unfavorable variance of $21 thousand compared to the monthly O&M reset Budget of $434 thousand ($48 unfavorable variance compared to the original budget of $367 thousand). Higher than projected utilities and boiler repair cost; and the timing of insurance expenses created the unfavorable variance. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights  Dover’s March load was 57,414 MWh, which was 1.9% above the weather normalized load of 56,334 MWh. Hedge volumes accounted for 84% of actual load for the month.  The March All In Unit Energy cost (excluding capacity) of $81.75 per MWh is $3.91 per MWh lower than the monthly budget. Actual Load vs Budget Load 100,000 75,000 MWh 50,000 25,000 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Actual 9

All In Unit Energy Cost - Actual v Budget $94 $92 $90 $88 $/MWh $86 $84 $82 $80 $78 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA 10

Purchased Power Variance Report Budget Actual Variance Mar-11 Mar-11 Mar-11 City of Dover Load Load Obligation (MWh) 56,334 57,414 (1,080) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $78.24 $74.20 $4.04 Pass Through $6.49 $6.64 ($0.15) Incentive Fees $0.93 $0.91 $0.02 Total - All In Unit Energy Cost $85.66 $81.75 $3.91 Purchased Power Variance Analysis  The actual Dover load of 57,414 MWh was 1.9% above the projected March load of 56,334 MWh.  The All In Unit Energy Cost was $3.91 per MWh lower than budget due to a decreased load following and basis charges. Offsetting these positive variances were due to an increased open volume and energy price purchases, an unfavorable PJM Ancillary charges and a lower than projected transmission related refunds.  The Management Incentive fee variance on a $/MWh basis is merely an estimate at this point. PJM Power Balancing and Load Related Fees Purchased Power (Hedges): 48,155 MWhs @ $77.35/MWh: $3,724,992 Power Balancing; Additional PJM, and Energy Manager Fee4: $2,046,897 Total Cost to Serve Load (57,414 MWhs) $5,771,889 All In $/MWh load cost inclusive of Energy Management Fees: $100.53/MWh 4 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT  During the month, PJM did not dispatch Dover’s units into the market. Van Sant unit was under a planned outage for approximately 10 days and the McKee units started a planned outage on March 28 that will last until May 23. For the month, Van San unit successfully completed the annual Black Start Test. The budget did not project generation for this month. Generation MWh's: Actual v Budget 30,000 25,000 20,000 MWh 15,000 10,000 5,000 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen 12

2010-11 Generation Production Margin v Budget $1,500 Thousands $1,250 $1,000 $750 $500 $250 $0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($) Actual ($) 13

Generation Management Variance Report Budget Actual Variance Mar-11 Mar-11 Mar-11 Self-Supplied Capacity from Gen (MW) McKee Run 1 17 17 0 McKee Run 2 17 17 0 McKee Run 3 100.3 100.3 0 Van Sant 39 39 0 Self Supplied Capacity from Gen (MW) 173.3 173.3 0 Additional Capacity from PJM Incremental Auction 1.7 1.7 0 Total Capacity from Gen (MW) 175 175 0 Gen Capacity Sales to PJM ($/MW.d) $186.12 $186.12 $0.00 Incremental Auction Sales to PJM ($/MW.d) $50.00 $50.00 $0.00 Power Sales Power Sales (MWh) 0 0 0 Sales Revenue ($ per MWh) $0.00 $0.00 $0.00 Power Sales Revenue ($) $0 $0.00 $0 Variable Fuel & Transport Fuel Oil No.2 Volume - McKee (gal) 0 0 0 Fuel Oil No.2 - McKee ($/gal) $0.00 $0.00 $0.00 Fuel Oil No.2 Cost of Goods Sold - McKee ($) $0 $0.00 $0 Fuel Oil No.2 Volume - Van Sant (gal) 0 0 0 Fuel Oil No.2 - Van Sant ($/gal) $0.00 0.00 $0.00 Fuel Oil No.2 Cost of Goods Sold - Van Sant ($) $0.00 0.00 $0.00 Gas Volume (Dth) 0 0 0 Unit Gas Price ($/Dth) $0.00 0 $0.00 Variable Gas Cost ($) $0.00 0 $0.00 Transport ($) $0.00 0 $0.00 Variable Gas and Transport Costs ($) $0.00 $0.00 $0.00 Variable Fuel & Transport Costs ($) $0 $0.00 $0 Testing $0.00 $0.00 $0.00 Generation Production Margin $0.00 $0.00 $0.00 Generation Capacity Payment Total - Generation Capacity Payment ($1,002,527) ($1,002,528) $0 14

Generation Management Variance Analysis Fuel Expense  PJM did not dispatch Dover’s units into the market, nor did the units consume natural gas or fuel oil related to power generation. Generation Production Margin Transaction Volumes Revenue/(Cost) PJM Invoice for Power Sold 0 MWhs $0 Fuel and Transport 0 Dth gas/ 0 gal #2 oil $0 0 gal #2 oil Low Sulfur Generation Production Margin 0 MWhs $0 The following non-production energy revenues and costs are generally fixed and are not directly related to generation dispatch and power production. Effective September 2009 FERC approved the City of Dover’s reactive supply service compensation resulting in approximately $29 thousand of revenue per month. PJM Invoice (Black Start) $4,545 Reactive Supply Credit $29,468 Fuel Oil Tank Heating & Black Start Gas Supply $0 Eastern Shore Demand Charge $0 Eastern Shore Transport and Imbalance Charge $0 Transco Demand Charge $0 Non-Production Energy Revenue/(Costs) $34,013 15

Fuel and Transportation  During the month there were no unit dispatches by PJM. Date Volume (Dth) Price ($/Dth) Total Commodity Cost ($) Hess Corp Sub-Total 0 $0.00 $0.00 PESCO Sub-Total 0 $0.00 $0.00 NJNG Sub-Total 0 $0.00 $0.00 Total 0 $0.00 $0.00 Due to the conversion from #6 residual oil to low sulfur #2 oil, the need for a constant supply of natural gas to heat the #6 oil is no longer required. Some gas will still be required for winter space heating of the building(s). Pace will coordinate with NAES on the procurement of such supply. This expense will now fall under the plant’s utility costs and be paid and budgeted for by the station. 16

Gas Transportation Purchased City of Dover decided not to renew agreements with the Eastern Shore Natural Gas Pipeline (“ESNG”) and TransCo to provide firm natural gas deliveries to the McKee Run and Van Sant stations. The City of Dover previously notified ESNG and TransCo of its intent to terminate these existing firm capacity agreements and, as a result, the City no longer pays firm demand charges or adjustments. ESNG FT Demand Charge $ 0 TransCo FT Demand Charge $ 0 Total Purchases $ 0 Other Gas Purchases Commodity and transportation imbalances on Eastern Shore Pipeline for the month resulted in no charge. The components of this charge are summarized as follows: Eastern Shore Transport and Imbalance Charges Imbalance/Dth Estimated Cost/Dth Estimated Total Cost 0 $0.00 $0.00 Transport Volume/Dth $/Dth Total Cost Firm/IT 0 $0.00 $0.00 Net Charge $0.00 17

Purchased Commodity Fuel Oil Summary Neither McKee Run nor Van Sant was dispatched into PJM and no #2 fuel oil was consumed for the month. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of March 31 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch5) McKee Run (#2 Fuel 2,554,105 451,200 3 Oil) Van Sant 258,000 151,358 3 (#2 Fuel Oil) 5 As measured by tank level instruments. Tank levels may change due to oil temperature. 18

3.3 – EMISSIONS AND ALLOWANCE MANAGEMENT Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover its 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Pace has set aside a projected number of allowances to handle the estimated dispatch events for the year (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through March 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 N/A 2003-2006 139 Carryover 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 YTD (1) -- -- (6) (13) -- -- Emissions3 12/31/10 2010 YTD Emissions -- -- -- (54) (54) -- -- 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD Emissions (2) (2) Totals - Allowances 3,189 pre-CAIR -- $0 52 74 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. (3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 19

Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $44,918 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $6/ton, 3976 post-CAIR SO2 allowances trading at $4/ton, 52 NOx annual allowances trading at $170/ton, and 52 NOx seasonal allowances trading at $20/ton. SO2 SO2 allowances continue to have little value in the market, trading below $10/ton for all of 2011 (see Figure 1 – SO2 Prices since Last Monthly Report). The major brokerage houses are reporting very few transactions in the market. Market participants continue to wait for final rules regulating the markets, and even then the value of existing SO2 allowances are unlikely to return to levels we saw two and three years ago. Figure 1 – SO2 Prices since Last Monthly Report SO2 Allowance Prices (Mar / Apr) $8.00 $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 17 Mar 2011 19 Mar 2011 21 Mar 2011 23 Mar 2011 25 Mar 2011 27 Mar 2011 29 Mar 2011 31 Mar 2011 02 Apr 2011 04 Apr 2011 06 Apr 2011 08 Apr 2011 10 Apr 2011 12 Apr 2011 14 Apr 2011 16 Apr 2011 18 Apr 2011 20 Apr 2011 2009 (pre-CAIR) 2010/2011 (post-CAIR) NOx NOX annual allowance prices have continued to decline after the March 1st compliance deadline for 2010 emissions, trading most recently at near record lows (See Figure 2 – NOX annual prices since last monthly report.) With the increasing likelihood that existing allowances will not carry over into the new regulatory program, NOX allowance prices could be volatile during the remainder of 2011, particularly if we see a spike in emissions like we did during the summer of 2010. NOX seasonal prices lost $10/ton trading most recently at $20/ton (See Figure 3 – NOX seasonal prices since last monthly report.) 20

Figure 2 – NOX annual prices since last monthly report NOX Annual Allowance Prices (Mar / Apr) $250.00 $200.00 $150.00 $100.00 $50.00 $0.00 17 Mar 2011 19 Mar 2011 21 Mar 2011 23 Mar 2011 25 Mar 2011 27 Mar 2011 29 Mar 2011 31 Mar 2011 02 Apr 2011 04 Apr 2011 06 Apr 2011 08 Apr 2011 10 Apr 2011 12 Apr 2011 14 Apr 2011 16 Apr 2011 18 Apr 2011 20 Apr 2011 Figure 3 – NOX seasonal prices since last monthly report NOX Seasonal Allowance Prices (Mar / Apr) $35.00 $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 17 Mar 2011 19 Mar 2011 21 Mar 2011 23 Mar 2011 25 Mar 2011 27 Mar 2011 29 Mar 2011 31 Mar 2011 02 Apr 2011 04 Apr 2011 06 Apr 2011 08 Apr 2011 10 Apr 2011 12 Apr 2011 14 Apr 2011 16 Apr 2011 18 Apr 2011 20 Apr 2011 SO2 and NOx Outlook Market participants continue to await regulatory certainty from EPA. The final Transport Rule, setting new emissions trading rules, is expected to be released in June or July this year. The expectation is that there will be new allowances for SO2 and NOX emissions, leaving little value for the existing bank of allowances beyond this year. If the existing bank is to retain any value beyond this year, EPA would have to elect to take a significantly different path than they did in 21

the proposed rule – which is not expected – or Congress would have to pass legislation regulating the markets. At this point, there does not seem to be a tremendous amount of momentum behind legislation in this arena, although that could change quickly depending on industry and other stakeholder reaction after the issuance of the final Transport Rule. RGGI and Federal Carbon Outlook RGGI allowance prices continue to trade at very low amounts, as the market is substantially over supplied, forcing prices to levels at or near the statutory price floor (see Figure 4 – RGGI Allowance Prices). Figure 4 – RGGI Allowance Prices RGGI Prices (Mar / Apr) $1.95 $1.90 $1.85 3/17/2011 3/19/2011 3/21/2011 3/23/2011 3/25/2011 3/27/2011 3/29/2011 3/31/2011 4/2/2011 4/4/2011 4/6/2011 4/8/2011 4/10/2011 4/12/2011 4/14/2011 4/16/2011 4/18/2011 4/20/2011 Based on projected generation and emissions, Dover is projected to have an excess of 145,000 allowances through 2013 with a market value at current prices of $275,500. The first true-up period for RGGI will take place on December 31st, 2011. Despite the high level of uncertainty surrounding carbon legislation, Pace Global continues to anticipate an eventual price on carbon at a national level, although the timing, method, and scope of coverage are all substantially unknown at this time. Pace Global expects carbon regulation to evolve through three main drivers: 1. Legislation; 2. EPA regulation under their existing authority; and 3. Linkage of regional and state initiatives. The three carbon pricing drivers will likely develop in parallel and, at times, in concert with one another. Through the three drivers, Pace Global anticipates a national price on carbon emissions via a market based system, or combination of systems, beginning sometime between 2015 and 2018. 22

There have been a number of proposed measures in Congress that would temporarily or permanently negate EPA’s authority to regulate GHGs. Attempts to cut EPA’s regulatory funding for GHG programs in the FY 2011 federal budget were unsuccessful; however the fight will likely continue as Congress debates the FY2012 federal budget. Additionally, bills to permanently repeal EPA’s regulatory authority appear to have stalled for the time being, with insufficient support in the Senate and threats of Presidential veto from the Administration. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights  During the month of March, there were no restricted work days or lost time accidents. The facility has now gone 168 days without an OSHA recordable accident and 168 consecutive days without a lost time reportable accident.  The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month.  No units were dispatched by PJM for the month of March.  Van Sant unit successfully completed the annual Black Start Test.  Van Sant unit was in a planned outage from March 14 to 24 for an annual inspection and for testing of the CTs, PTs and DC Control Circuitry. The Units at McKee started a planned outage on March 28 that will last until May 23.  Maintenance and IC&E Staff, with assistance from the Reading Crane completed the load testing for the turbine floor overhead crane.  NAES completed the testing of the CTs, PTs, and DC control circuitry at the VanSant Combustion Turbine site. The testing of the devices and equipment is part of the best practices for NERC compliance  On March 29, the plant conducted an Emergency Response Deployment Drill.  The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware March 2011 Monthly Report Ray Lavender (standing-left), Planner/Operations Supervisor, is shown being presented the NAES Service Recognition Award by Vincent Scire, Plant Manager, in recognition of his completing 30 years of service working at the City of Dover Generating Facilities. 25

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 26

1.0 Environmental, Health and Safety: During the month of March, there were no restricted work days or lost time accidents. The facility has now gone 168 days without an OSHA recordable accident and 168 consecutive days without a lost time reportable accident. The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month. Environmental, Health and Safety Statistics Month Fiscal Year to Date (March) (7/1/10-6/30/11) NOVs 0 0 Opacity Deviations 0 13 Environmental Deviations 0 0 OSHA Recordable 0 1 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 2 6 Man Hours Worked 4,961.00 90,880.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 168 Days since last Lost Time Accident 168 Emissions (NOx & SO2) All data thru 3/31/11 NOx Summary - Year (May-Sept.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 119.2 3.3 125.4 2011 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 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 119.2 3.3 125.4 2011 0.0 0.0 1.3 0.7 2.0 27

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 Run (Yr/Season) (Yr/Season) (Yr/Season) (Yr/Season) 2009 45/25 75/50 5/3 12/5 - 1/1 0/0 – 0/0 18/0 4/2 119**/119** - 22##/53# – 2010 0 73/47* 5/3 -46/0 2/0 3/3 0/0 2011 0 71/48### 5/3 1/0 – 1/0 0/0 - 0/0 70/48### 4/3 Note ** - Higher NOx emissions are attributed to data substitution rules that use significantly higher emission rates than actually were emitted. The implementation of the data substitution rules were caused by performing a linearity test outside the grace period. NAES ESS was able to provide assistance in reducing the NOx emissions from 137 tons to 119 tons since the October report. A petition to the EPA was sent out in February that would result in a reduction in reported emissions. The EPA has given preliminary approval to the petition request although it is not official until the plant receives a signed EPA approval. Until the issue is resolved, the EPA has locked the annual account and no allowances will be deducted until that time. Note# - 53 tons were purchased to help compensate for the shortage in seasonal NOx allowances. Note## - 22 tons were purchased to help compensate for the shortage in annual NOx allowances. Note###- 2 tons were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 2.0 0.3 2.3 Note: Data is as of 3/31/2011 SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 2003-2006 139 138 1 0 0 2007 2455 2585 138 98 170 2008 2392 2585 138 32 299 2009 0 2585 138 0 2723 2010 0 1850 138 0 1988 2011 0 1850 138 2 1986 Note: Data is as of 3/31/2011 28

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 Van Sant 2009 0 59,805 1,699 5,796 55,708 2010 0 47,844 1,636 32,971 16,509 2011 0 35,883 1,227 1,105 36,005 2012 0 23,922 818 0 24,740 2013 0 11,961 409 0 12,370 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System 29

2.0 Financial Financial – Current Month Month –March 2011 Actual Budget Variance Personnel 248,042 244,495 (3,547) Materials & Supplies 17,246 10,550 (6,696) Administrative Expenses 149,630 111,965 (37,665) Total $414,918 $367,011 (47,908) Financial – Fiscal Year to Date Number of Months - 9 Actual Budget Variance Personnel 2,278,265 2,291,011 12,746 Materials & Supplies 212,410 142,420 (69,990) Administrative Expenses 1,799,961 1,511,148 (288,813) Total $4,290,636 $3,944,579 ($346,057) 2.1 Variance analysis: The original budget for March was $367,011. The actual expenses for March were $414,919 for an unfavorable variance of ($47,908) or approximately 13.05%. The variance was due to the following: PERSONNEL EXPENSES – Straight Time Labor and burdens accounted for a total unfavorable variance of $3,547. MATERIALS AND SUPPLIES EXPENSES – An unfavorable variance of $6,696 was realized due to spending in Office Supplies, Computer Software and Safety Supplies for the month. ADMINISTRATIVE EXPENSES - Higher than budgeted expenses in Insurance, Electric, Heating Oil / Gas, Contractual Services, Environmental Expenses, Home Office Labor, and Boiler Systems contributed to an unfavorable variance of $37,665. The budget is currently forecast to finish this fiscal year at $6,124,375 expensed versus $6,163,315 budgeted (reset) thereby realizing a 99.55% expenditure rate. Note: The budget has now been reset by the City of Dover Financial Department. Future reports will reflect the reset monthly and year-to-date numbers. 30

3.0 Operations Unit Operations / Outages / Trips No units were dispatched by PJM for the month of March. On March 9, during a Black Start test, Unit 11 tripped after being on line for four minutes due to a bad PLC module in the combustion monitoring protection circuitry. The module was replaced and several days later, the unit successfully completed the annual Black Start Test. VanSant was in a Planned outage from March 14 to 24 for an annual inspection and for testing of the CTs, PTs and DC Control Circuitry. The Units at McKee started a planned outage on March 28 that will last until May23. The scope of work on Units 1 & 2 includes the installation of upgrades to the burner control system, condenser cleaning and inspections of the steam turbines. The work scope on Unit 3 includes the installation of gas valves on each burner deck, the installation of a new expansion joint in the ductwork above the air heater and an annual inspection. Month – March 2011 McKee McKee McKee MRS Van Sant 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 0.750 0.750 Starts # 0 0 0 0 9 9 Gross Generation MWh 0.0 0.0 0.0 0.0 0.680 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 28.923 28.923 150.367 208.213 3.759 211.972 Auxiliaries purchased MWh 28.923 28.923 150.367 208.213 3.759 211.972 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 177.325 177.325 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 0.0 177.325 177.325 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 1 1 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 88.04 88.04 88.04 88.04 66.73 82.71 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 89.0 89.0 89.0 267.0 247.317 247.317 Maintenance Outage Hours 0.0 0.0 0.0 0.0 5.433 5.433 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 654.000 654.000 654.000 1,962.000 489.500 2,451.500 Hours HW Boiler Gas Usage MMBTU 772.850 772.850 Pilot Gas Usage MMBTU 0 0 0 0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 31

2010-2011 Fiscal Year-to-Date (9 Months) McKee McKee McKee MRS Van Sant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 13.033 128.966 645.256 787.255 137.790 1,062.089 Starts # 1 3 44 48 35 83 Gross Generation MWh 154.626 1,216.601 45,570.285 46,941.512 4,635.447 51,576.959 Net Generation MWh 147.111 1,141.623 42,968.696 44,257.430 4,632.241 51,189.671 Total Auxiliaries MWh 286.237 353.699 5,254.318 5,894.253 37.729 5,757.739 Auxiliaries purchased MWh 278.722 278.722 2,535.529 3,214.416 35.033 3,249.449 Fuel Gas Used MMBTU 2,183.250 15,245.85 452,018.83 469,447.93 53,944.276 523,392.21 0 7 7 2 Fuel Oil Used MMBTU 0.0 0.0 17,721.260 17,721.260 3,790.097 21,511.357 Fuel Oil Used Gallons 0.0 0.0 125,088 125,088 27,385 152,473 Total Fuel MMBTU 2,183.250 15,245.85 469,740.09 487,169.19 61,323.669 548,492.86 0 8 8 7 Net Heat Rate BTU/KWh 14,841 13,355 11,696 13,297 13,192 13,245 Unit Trips # 1 0 3 4 3 7 Capacity Factor % 0.13 1.02 6.28 4.86 1.81 4.01 Availability Factor % 69.66 78.47 78.38 75.50 96.24 80.69 Commercial % 6.6 0 0.03* 0.85 0 0.66 Unavailability (CU) Planned Outage Hours Hours 1,415.500 1,415.500 1,415.500 4,246.500 247.317 5,898.746 Maintenance Outage Hours 0.0 0.0 0.0 0.0 5.433 5.433 Hours Forced Outage Hours Hours 579.830 0 6.317 586.15 0 586.15 Reserve Shutdown Hours 4,580.670 5,031.534 4,580.143 14,192.347 6,185.456 20,377.803 Hours HW Boiler Gas Usage MMBTU 4,816.910 4,816.910 Pilot Gas Usage MMBTU 0 0 0 0 Note: * Calculation does not include 3.317 hours that were Outside Management Control (OMC) Capacity Testing – FY 2010-2011 Summer 2010 (June 1- Aug 31) Winter 2010-2011 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.20 1 17 * 2 17 18.09 2 17 * 3 102 102.68 3 102 105.61 VanSant 39 39.30 11 39 43.833 Total 175 178.67 Total 175 149.443 32

Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 10-11 Fuel FY 10-11 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 449,438 451,200 0 1,762 448,556 118,549 2,644 Van Sant 150,852 151,358 0 506 143,099 38,079 8,259 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. Van Sant Lifetime through 3/31/11 Actual Starts Factored Starts Fired Hours Van Sant 1252 2161.15 4110.66 Since HGP - Dec 2004 201 493.45 727.08 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. In addition, they have been removing lagging and insulation at various locations on the boiler and on the Air Heater Expansion Joint. In preparation for the VanSant outage, Operations staff performed LO/TO on several pieces of equipment to expedite the start of the projected work scope. Plant employees continue 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. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders for those work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. 4.0 Maintenance During the month of March, plant maintenance staff continued addressing the backlog of work orders. There were seventy-five work orders issued with eighty work orders being completed during the month. 33

The table below summarizes the monthly work order activities. Work Order Report March - 9 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 5 7 4 8 2 25 14 18 21 3 37 16 17 36 4 41 0 1 40 5 9 0 0 9 SW1 0 1 1 0 SW2 0 4 2 2 SW3 0 1 1 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 63 32 36 59 Totals 180 75 80 175 Note: PM's are included in the priority totals Notable activities during the month include: 1. Maintenance and IC&E Staff, with assistance from the Reading Crane completed the load testing for the turbine floor overhead crane. Load testing was completed in front of the turbine overhaul outages. Overall the crane passed the load test and one work order was issued for the repairs. Repairs should be completed before the outage starts and will not hold up any scheduled work. 2. IC&E staff completed the removal and installation of new emergency stairwell lighting. During weekly inspections and testing, several lighting units were found to be nonoperational. Work order was issued and further inspection of other units revealed DC batteries had failed or surpassed their service life. New lighting units have been installed completing this safety work order. 3. Pike Engineering, with assistance from IC&E staff, completed the testing of the CTs, PTs, and DC control circuitry at the VanSant Combustion Turbine site. The testing of the devices and equipment is part of the best practices for NERC compliance PRC-005 Mitigation Plan. 34

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: No other work is planned for this project during the Unit 3 Cooling remainder of the fiscal year. EG1101 Tower Life Schedule: Work scope development for next year will commence in Extension April 2011. Progress: Work scope to replace the lower decking has been Units 1 & 2 Cooling completed, bids received and work was awarded. EG1102 Tower Life Schedule: Work is slated to be completed in the Spring 2011 Extension Outage. Progress: Started on the development of the project work scope Unit 3 Turbine documents. EG1103 Inspection Schedule: This project has been deferred until 2011-2012 fiscal year. Progress: Started on the development of the project work scope Unit 3 Aux System EG1104 documents. Components Schedule: Deferred until 2011-2012 fiscal year. Progress: This project is for the unexpected needs that may occur during a budget year that were unexpected due to equipment failure Miscellaneous for example. EG1105 Capital Equipment Schedule: The funding is in place. Funds have been used to cover Replacements the cost of the Unit 3 600-lb steam station valve repairs, Unit 3 Cooling Water Booster Pump Repairs and circuit breakers. Progress: Started on the development of the project work scope EG1106 Unit 3 Stack Repairs document. Schedule: Deferred until 2011-2012 fiscal year. Progress: The bid has been awarded and work is planned to start in Units 1 & 2 Life April. EG1107 Extension Schedule: Turbine mechanical contractor to begin on April 18. Some of the work has been deferred until the 2011-2012 fiscal year. Unit 1 Forced Progress: The repair work has been completed. EG1108 Outage Repairs Schedule: This work is complete. Progress: Started on the development of the project work scope Unit 3 FD & ID Fan EG1109 documents. Damper Upgrade Schedule: Deferred until 2011-2012 fiscal year. Unit 3 DCS Progress: Started on the development of the project work scope EG1110 Computers & documents. Software Upgrades Schedule: Deferred until 2011-2012 fiscal year. Unit 2 Boiler Progress: Inspections and other repairs were completed during the EG1111 Inspections and Fall 2010 Outage Repairs Schedule: Miscellaneous work is being wrapped up to complete the 35

project. Progress: The bid was awarded and expansion joint was delivered in Unit 3 Air Heater and work will start in April. EG1112 Expansion Joint Schedule: This is scheduled to start in April during the Spring Outage. Progress: Work scope documents and parts list put together. Most of the parts have been ordered and are beginning to be received at Units 1 & 2 Controls EG1113 the plant and the installation of conduit and electrical boxes have Modifications commenced. Schedule: This is scheduled for the Spring Outage 2011. Progress: The bid has been awarded. Some parts have been ordered Unit 3 Gas Line and have been received. Work will start in April. EG1114 Modifications Schedule: This is scheduled to begin in April during the Spring Outage. 5.1 CIP Budget Approved Latest Project Description Budget Estimate Number ($ X 1000) ($ X 1000) Unit 3 Cooling Tower Life Extension EG1101 398 372 Units 1 & 2 Cooling Tower Life Extension EG1102 173 90 EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 77 66 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 225 231 EG1108 Unit 1 Forced Outage Repairs 412** 424 EG1109 Unit 3 FD & ID Fan Damper Upgrade 45 45 Unit 3 DCS Computers & Software EG1110 30 30 Upgrades 36

EG1111 Unit 2 Boiler Inspections and Repairs 124## 111 EG1112 Unit 3 Air Heater Expansion Joint 65## 59 EG1113 Units 1 & 2 Controls Modifications 150## 152 EG1114 Unit 3 Gas Line Modifications 60## 40 ** This project was not budgeted for 2011. ## Project was not in original FY11 CIP but was approved by COD Council in late 2010. 6.0 General Plant Information Training: On March 8 & 9, PJM conducted a system restoration drill. Ron McNair, Rick Barber and Aaron Jester participated in the drill for training purposes. The simulation drill had the operators ask and answer some questions on system operation. Participation in the drill earned each operator simulation credits that go towards maintaining their PJM System Operator certification. The PJM Generation Systems Operator exam study groups continue to meet during the month with different study topics. The study group focuses on subjects that are covered on the exam. This month’s topics were Market Monitoring, PJM Day Ahead Market, Generation outages and eDART. Ron McNair and Rick Barber attended the PJM 2011 PJM System Operator Seminar in the third week of May. This seminar provides updated information on PJM, NERC, and FERC regulations and standards that are coming in the future. It also provides credits to the individual that go toward retaining his PJM Gen Ops Certification. On March 29, the plant conducted an Emergency Response Deployment Drill. The scenario was a fuel oil leak by the transfer pump area. The object was to contain the oil spill with booms (rope was used in place of actual booms) and to keep oil from going to the outfalls or the lake. Actual contacts were made to plant personnel and to clean-up crews to simulate response time. 37

Calendar of Events Date Units 1, 2, and 3 Spring Outage March 28, 2011 – May 23, 3011 Air Emission Inventory April 1, 2011 EIA-860 Report April 29, 2011 EIA-923 Report May 6, 2011 Fiscal Year 2010-2011 Ends June 30, 2011 PJM Summer Capacity Test Period June 1, 2011- August 31, 2011 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2011 NOx Ozone Season Starts May 1, 2011 NOx Ozone Season Ends September 30, 2011 One Year Accident Free October 14, 2011 Units 1, 2, 3 and 11 Fall Outage TBD Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and VanSant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual VanSant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD 7.0 Summary of NAES Performance to Date Plant Performance FY 2010-2011 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0.66% $63,262 $89,586 Unavailability (CU) Safety 1 1 $8,398 $16,797 Environmental 0 0 $16,797 $16,797 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,360 $3,360 Unit 2 No No Yes Yes* $3,360 $3,360 Unit 3 No No Yes Yes $20,157 $20,157 Unit 11 No No Yes Yes $6,719 $6,719 Total YTD 77.85% Total YTD Incentive $122,052 $156,775 Incentive % Note - * Unit is expected to be in the PJM Winter Capacity Test Exemption Program 38

APPENDICES I. PJM INVOICE BREAKDOWN The PJM bill is a record of all Electricity Transactions, Transmission Services, Ancillary Services and Miscellaneous fees that allow the PJM to operate. Below is a list of the line items on the PJM bill including all generator activity. PJM Bill Line Items Gen Load Net Day-ahead Scheduling Reserve $0.00 ($46.40) ($46.40) Synchronous Condensing Charges $0.00 ($65.76) ($65.76) Reactive Services Charges $0.00 ($42,156.55) ($42,156.55) Meter Correction Charges $0.00 $4,582.37 $4,582.37 Day-ahead Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserves Credits $0.00 $0.00 $0.00 Day Ahead Operating Reserves Credits $0.00 $0.00 $0.00 Locational Reliability Charges $0.00 ($1,080,033.18) ($1,080,033.18) Capacity Transfer Rights Credits $0.00 $1,745.61 $1,745.61 Capacity Resource Deficiency Credits $0.00 $0.31 $0.31 Demand Response and ILR Compliance Penalty Credits $0.00 $0.00 $0.00 RPM Auction Credits $1,002,527.60 $0.00 $1,002,527.60 Auction Revenue Rights Credits $0.00 $31,448.26 $31,448.26 Synchronized Reserve Credits $0.00 $0.00 $0.00 PJM Scheduling System Control and Dispatch Service Charges $0.00 ($10,029.88) ($10,029.88) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($4,373.04) ($4,373.04) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($31,817.59) ($31,817.59) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,212.07) ($1,212.07) North American Electric Reliability Corporation (NERC) Charge $0.00 ($512.07) ($512.07) Reliability First Corporation (RFC) Charges $0.00 ($776.89) ($776.89) Expansion Cost Recovery Charges $0.00 ($408.58) ($408.58) Transmission Enhancement Charges $0.00 ($16,003.08) ($16,003.08) Black Start Service Credits $4,544.50 $0.00 $4,544.50 Non-Firm Point-to-Point Transmission Service Credits $0.00 $531.35 $531.35 Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($298.17) ($298.17) Organization of PJM States, Inc. (OPSI) Funding $0.00 ($36.50) ($36.50) FERC Annual Recovery $0.00 ($3,313.57) ($3,313.57) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 ($389.45) ($389.45) PPA $0.00 ($23.55) ($23.55) Day-ahead Scheduling Reserve $0.00 ($46.40) ($46.40) Synchronous Condensing Charges $0.00 ($65.76) ($65.76) Reactive Services Charges $0.00 ($42,156.55) ($42,156.55) 39

Meter Correction Charges $0.00 $4,582.37 $4,582.37 Day-ahead Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserves Credits $0.00 $0.00 $0.00 Day Ahead Operating Reserves Credits $0.00 $0.00 $0.00 Locational Reliability Charges $0.00 ($1,080,033.18) ($1,080,033.18) $1,036,539.68 ($1,863,131.09) ($826,591.41) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) Jul 83,163 83,163 $90.72 $90.72 $90.72 $81.36 $81.36 $81.36 Aug 78,755 78,755 $82.76 $82.76 $86.85 $83.03 $83.03 $82.17 Sep 66,782 66,782 $82.73 $82.73 $85.65 $91.13 $91.13 $84.79 Oct 56,452 56,452 $79.72 $79.72 $84.47 $87.24 $87.24 $85.27 Nov 54,396 54,396 $82.56 $82.56 $84.17 $91.56 $91.56 $86.28 Dec 63,566 63,566 $87.33 $87.33 $84.67 $98.22 $98.22 $88.16 Jan 60,136 64,462 $86.66 $91.77 $85.65 $94.36 $97.13 $89.40 Feb 54,199 54,900 $85.32 $84.37 $85.51 $94.11 $92.95 $89.77 Mar 56,334 57,414 $85.66 $81.75 $85.14 $93.39 $89.70 $89.77 Apr 52,554 $83.69 $91.16 May 58,744 $79.63 $85.58 Jun 67,331 $80.51 $96.23 40

III. GLOSSARY Energy Only Unit Cost ("EOU") accounts for the wholesale energy costs excluding capacity obligations, capacity credits for Dover-owned generation, generation revenues, generating plant costs, the black start ancillary services credit for the Van Sant plant, and revenues associated with the sale of emission allowances. The AIE includes the costs from settling the hedged or forward transactions; the energy bought on the ISO (Independent System Operator or PJM) day-ahead to cover the open position (un-hedged); load following costs associated with balancing the actual load in the ISO real-time market; energy management service related fees; the ISO transmission charges and credits to load serving entities; the ISO ancillary services charges such as generation regulation, spinning reserve, and reactive power; and the ISO administrative charges and cost of service recovery fees. All In Cost of Service ("AICS") accounts for the net cost of wholesale power to the City of Dover Electric Utility. The AICS starts with the AIE and adds the costs or credits from capacity obligations, capacity credits for Dover-owned generation, generation revenues, generating plant costs, the black start ancillary services credit for the Van Sant plant, and revenues associated with the sale of emission allowances. Black Start is a generating ancillary service that is the process of restoring a generating plant to service without the support of an external power supply to power auxiliary equipment needed for start up operations. Capacity UCAP Obligated Purchased is the obligation and payment by all load serving entities in PJM including Dover for the Unforced Capacity (UCAP) requirement from PJM that satisfies the PJM reserve requirements. Generation Capacity Credit: is the credit provided to generators for supply capacity to the system. The price is determined by the PJM Reliability Pricing Market auction process that includes three auctions for each capacity year. Generation Production Margin accounts for the variable margin excluding variable O&M and emissions. The Generation Production Margin is calculated by taking the PJM revenues credited to the plant including any balancing charges or credits less the fuel costs. Generation Production Margin includes both “Economic and reliability dispatch” and “Testing.” Economic and reliability dispatch equals the margin achieved when Dover’s generating plants are dispatched by PJM for either economic dispatch (the system energy price is greater than the Dover bid price) or reliability dispatch whereby PJM pays the generating cost of the plants for the hours the plant is run to support the system. Generation Testing equals the Generation Production Margin associated with testing. This is usually expected to be a negative margin because the plant is potentially being dispatched / run when energy prices do not cover its costs. Non-Production Revenue equals the credits from PJM to Dover for Generation Capacity Credit, the Black Start Revenue and the sales by Dover of Emission Allowances. 41