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UTILITY COMMITTEE AGENDA April 25, 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-mail at CityClerk@dover.de.us) should you wish to be recognized. AGENDA ADDITIONS/DELETIONS 1. East Dover Hills Water Line Replacement Project 2. Division Street Inflow & Infiltration Project 3. Review of Utility Related CIP’s (Electric and Water/Wastewater) (January and February) 4. PACE/NAES Report 5. Updates A. Green Energy Funding and Programming B. State Sustainable Energy Utility (SEU) Programs and Legislation 6. Adjournment by 5:55 P.M. /tm S:\AGENDAS & MINUTES\Committee-Agendas\2011\04-25-2011 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.

City of Dover Capital Investment Plan Project Tracking Report January 31, 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 2 729 ,729,628 Federal and/or State Grants 4,270,348 1,000,000 45,248 135,152 5,450,748 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 1,019,629 300,000 58,709 2,797,792 4,176,130 Interest Earned 10,900 - - 40,700 51,600 Total Funding Sources (Unaudited) $ 8,902,720 $ 1,300,000 $ 10,681,049 $ 4,494,722 $ 26,216,062 Page 1 of 5

City of Dover General Fund - Major CIP Projects January, 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 - constuction started / Bid 2 LB0901 M/G New Library Project $ 18,200,000 $ 24,679,934 $ 1,356,957 $ 23,322,977 5.5% $ 6,687,039 $ 7,630,663 $ 619,891 8.1% Started Pack B - bidding started. 3 Totals - FY09 $ 18,200,000 $ 24,679,934 $ 1,356,957 $ 23,322,977 5.5% $ 6,687,039 $ 7,630,663 $ 619,891 8.1% 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 $ 63,675 $ 461,333 $ (397,658) 724.5% $ 735,185 $ 735,185 $ 461,333 62.8% Started Vehicles being ordered. Core Law Enforcement Server 11 PD1001 Replacement - 53,500 30,108 23,392 56.3% - 53,500 30,108 56.3% Started Specifications done. 12 PD1101 Public Assembly Room Upgrade - 20,000 - 20,000 0.0% - 20,000 - 0.0% 13 PR1101 Playground Improv 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 Concrete Program 50,000 50,000 45,759 4,241 91.5% 50,000 50,000 45,759 91.5% Started Complete with contractor portion. 16 ST1102 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. 17 MR1101 Downtown Security Cameras 31,500 31,500 - 31,500 0.0% 31,500 31,500 - 0.0% Started Contract signed. 18 Totals - FY11 $ 445,175 $ 563,675 $ 850,152 $ (286,477) 150.8% $ 1,161,685 $ 1,235,185 $ 850,152 68.8% 19 20 Grand Totals $ 18,695,175 $ 25,283,609 $ 2,235,738 $ 23,047,871 8.8% $ 7,848,724 $ 8,902,720 $ 1,495,544 16.8% 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 January, 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 $ 431,076 $ 48,072 90.0% $ 121,891 $ 121,891 $ 73,819 60.6% Started Ongoing. 3 Totals $ 400,000 $ 479,148 $ 431,076 $ 48,072 90.0% $ 121,891 $ 121,891 $ 73,819 60.6% 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 Trying to move this to Library Project if 10 Schutte Parking Lot $ 21,950 $ 21,950 $ - $ 21,950 0.0% $ 21,950 $ 21,950 $ - 0.0% State approves. 11 Turnberry Drive 40,000 40,000 40,000 - 100.0% 40,000 40,000 40,000 100.0% Curb work complete, paving in 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. 16 CT1108 Mitschner Road (incl. CDBG) 169,066 169,066 246,672 (77,606) 145.9% 169,066 169,066 246,672 145.9% In progress. 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% CT1162 Library Access Rd. 105,000 105,000 - 105,000 0.0% 105,000 105,000 - 0.0% 21 ST1101 Street & Alley Program 300,000 300,000 175,926 124,074 58.6% 300,000 300,000 175,926 58.6% In progress. 22 State Agreements not yet rec'd 458,968 346,468 - 346,468 0.0% 346,468 346,468 - 0.0% Agreements have not been received. 23 Totals $ 1,163,659 $ 1,051,159 $ 543,224 $ 507,935 51.7% $ 1,051,159 $ 1,051,159 $ 543,224 51.7% 24 25 Grand Totals $ 1,690,609 $ 1,657,257 $ 1,014,299 $ 642,958 61.2% $ 1,300,000 $ 1,300,000 $ 657,043 50.5% 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 January, 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 South Governors Ave. Water Main Upgrade $ 200,000 $ 200,000 $ 2,664 $ 197,336 1.3% $ - $ 197,336 $ - 0.0% Complete Done. 3 WD0804 M 1.0 MG Elevated Water Storage Tower 4,196,600 2,590,000 11,062 2,578,938 0.4% - 193,377 4,439 2.3% Started Selecting Tank Model & Site; FY11 = Constr. 4 WD0805 M Piney Point Well 398,800 665,000 61,414 603,586 9.2% - 162,525 8,939 5.5% Started DNREC permiting; FY11 = Constr. 5 WW0809 M South Governors Ave. Sewer Main 300,000 291,000 13,561 277,439 4.7% - 279,244 1,805 0.6% Complete Done. 6 WW0810 M/SL US 13 East Sanitary Sewer Interceptor 2,376,800 3,409,641 2,443,587 966,054 71.7% - 2,335,862 1,575,426 67.4% Complete Functionally completed, some minor site restoration. 7 Totals - FY08 $ 7,472,200 $ 7,155,641 $ 2,532,288 $ 4,623,353 35.4% $ - $ 3,168,344 $ 1,590,608 50.2% 8 9 FY2009 10 WQ0905 M/SL Bayard Avenue $ 590,910 $ 590,910 $ 237,336 $ 353,574 40.2% $ - $ 584,420 $ 230,846 39.5% 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% Done Done. 12 WQ0907 M/SL Route 13 Water Main 1,058,700 1,035,898 142,748 893,150 13.8% - 967,801 18,752 1.9% Started Going to bid. 13 R Water Quality Improvements FY09 $ 2,518,317 $ 2,504,404 $ 557,262 $ 1,947,142 22.3% $ - $ 2,399,921 $ 397,773 58.9% Started 14 15 WW0902 M/SL DE State University Pumping Station Repl. $ 386,400 $ 386,400 $ 293,367 $ 93,033 75.9% - 240,324 147,652 61.4% Completed Done. Done. Overage covered by US 13 Interceptor 16 WW0905 M/SL Fox Hall/Retreat Force Main Rerouting 133,100 139,245 238,789 (99,544) 171.5% - - 20,351 0.0% Completed (WW0810). 17 WW0907 M/SL Acorn Lane Pump Station Replace. 386,400 386,400 293,904 92,496 76.1% - 210,528 118,393 56.2% Completed Done. 18 Totals - FY09 $ 3,424,217 $ 3,416,449 $ 1,383,322 $ 2,033,127 40.5% $ - $ 2,850,773 $ 684,169 24.0% 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 1,799,668 6,369 1,793,299 0.4% - 1,798,447 5,148 0.3% Started Construction to start in April. 23 WW1007 M Fox Hall Pump Station 427,900 52,000 43,077 8,923 82.8% 375,900 426,044 41,221 9.7% Started Going out to bid. 24 WW1008 M Heatherfield Force Main Rerouting 220,400 40,000 35,175 4,825 87.9% 229,200 267,916 33,891 12.6% Started Going out to bid. 25 WW1010 I Tar Ditch Interceptor Upgrade 518,230 518,230 12,487 505,744 2.4% - 516,781 11,038 2.1% Started Reviewing design. 26 WS1001 Various Pump Motor Replacements 45,248 45,248 - 45,248 0.0% - 45,248 - 0.0% Started Grant approved. Ordering begun. 27 Totals - FY10 $ 3,066,778 $ 2,510,146 $ 120,212 $ 2,389,934 4.8% $ 605,100 $ 3,086,332 $ 91,298 3.0% 28 29 FY2011 30 WD1101 Misc. Distribution 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 Program 60,000 60,000 - 60,000 0.0% 60,000 60,000 - 0.0% Started Work starting in March\April. 32 WQ1101 Water Quality Improvements 500,000 500,000 - 500,000 0.0% 500,000 500,000 26,448 5.3% Not Started See above FY09. 33 WW1101 M/SL Inflow/Infiltration Removal 500,000 500,000 - 500,000 0.0% 500,000 500,000 - 0.0% Started Will start after FY10 is done. 34 WW1102 R Scada Technology Equip Upgrade 82,100 82,100 62,913 19,187 76.6% 82,100 82,100 62,913 76.6% Started 2 of 7 installed. 35 WW1103 Del State/Del Tech Force Main Rerouting 286,500 286,500 3,801 282,699 1.3% 286,500 286,500 3,801 1.3% Done Shifted completion to interceptor (WW0810). 36 WW1104 Lepore Road Pump Station Replacement 52,000 52,000 7,700 44,300 14.8% 52,000 52,000 7,700 14.8% Started Design with Braun.. 37 WW1105 R Misc. Sewer System Improvements 35,000 35,000 35,152 (152) 100.4% 35,000 35,000 35,152 100.4% Started Ongoing as needed. 38 Totals - FY11 $ 1,575,600 $ 1,575,600 $ 109,567 $ 1,466,034 7.0% $ 1,575,600 $ 1,575,600 $ 136,014 8.6% 39 40 Grand Totals $ 15,538,795 $ 14,657,836 $ 4,145,388 $ 10,512,448 28.3% $ 2,180,700 $ 10,681,049 $ 2,502,090 23.4% 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 January, 2011 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Hide 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 2,068,260 550,725 1,517,535 26.6% - 250,000 30,264 12.1% Completed Done. 4 Totals - FY06 $ 12,328,450 $ 10,762,042 $ 9,312,486 $ 1,449,556 86.5% $ - $ 254,242 $ 34,506 13.6% 5 6 FY 2008 7 EG0801 Unit 3 Turb Bearing Fire Protect Deluge $ 50,000 $ 50,000 $ 44,720 $ 5,280 89.4% $ - $ 50,000 $ 44,720 89.4% Completed Final training needed. 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 (Replmnt) $ 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 Replacement 85,000 85,000 26,577 58,423 31.3% - - 9,859 0.0% Completed Done. 14 EG1009 Photovoltaic Install @ McKee Run - - 65,065 (65,065) 0.0% - 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 70,087 70,010 77 99.9% - 70,087 70,010 99.9% 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. Done. This project is over budget due to having addtiional bond 18 EU1003 B Buchanan Acres 406,000 865,144 1,207,967 (342,823) 139.6% - 129,502 129,502 100.0% Completed proceeds to spend. 19 20 Totals - FY10 $ 3,386,452 $ 3,407,017 $ 3,463,238 $ (56,221) 101.7% $ - $ 573,476 $ 583,257 101.7% 21 22 FY2011 23 --- V hi ehicles & E i quipment $ 1 8 58,200 $ 1 8 58,200 $ 113,437 $ 44,763 1 71.7% $ 1 8 58,200 $ 1 8 58,200 $ 113,437 71.7% 1 Started V hi echicles being d ordered. 24 EE1101 Substation PT & CT Replacement 256,218 256,218 179,885 76,333 70.2% 256,218 256,218 179,885 70.2% Started Material being received. 25 EE1102 Replace of 69 kV Breakers 100,000 100,000 7,220 92,780 7.2% 100,000 100,000 7,220 7.2% Completed Installed. 26 EE1103 Lighting Rehabilitation 100,000 100,000 107,644 (7,644) 107.6% 100,000 100,000 107,644 107.6% Completed Foxhall done. 27 EE1104 Walker Road OH Conversion 350,511 350,511 - 350,511 0.0% 350,511 - - 0.0% Dropped Funds reappropriated. 28 EE1105 Engineering Misc Equipment Replmnt 40,000 40,000 24,751 15,249 61.9% 40,000 40,000 24,751 61.9% 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 EE1111 UG Transformers 120,536 120,536 68,867 51,669 57.1% 120,536 120,536 68,867 57.1% Started Ongoing as needed. 31 EE1111 UG Conductors 529,464 529,464 139,160 390,304 26.3% 529,464 529,464 139,160 26.3% Started Ongoing as needed. 32 EE1111 Meters 50,000 50,000 52,151 (2,151) 104.3% 50,000 50,000 52,151 104.3% Started Ongoing as needed. 33 EE1112 69kV Sub Switch Replacement - 180,000 - 180,000 0.0% - 180,000 - 0.0% 34 EG1101 Unit 3 Cooling Tower Fill 353,338 353,338 371,513 (18,175) 105.1% 353,338 398,338 371,513 93.3% Completed Done. 35 EG1102 Units 1 & 2 Cooling Tower 218,730 218,730 70,280 148,450 32.1% 218,730 173,730 70,280 40.5% Completed Done. 36 EG1103 Unit 3 Tubine Inspection 348,000 348,000 - 348,000 0.0% 348,000 - - 0.0% Started Scoping Cosntruciton in FY12 Funding reallocated to Unit 1 37 EG1104 Unit 3 Aux System Components 113,000 113,000 - 113,000 0.0% 113,000 - - 0.0% Deferred repair. Defered to FY12 . 38 EG1105 Plant Misc Equipment Replmnt 71,000 71,000 60,726 10,274 85.5% 71,000 71,000 60,726 85.5% Started Ongoing as needed. Funding reallocated Unit 1 repair. 39 EG1106 Unit 3 Stack Repairs 25,000 25,000 - 25,000 0.0% 25,000 - - 0.0% Deffered Defered to FY12. Scoping, some funding 40 EG1107 Units 1 & 2 Life Extension 276,000 276,000 23,601 252,399 8.6% 276,000 180,000 23,601 13.1% Started reallocated Unit 1 repair. Emergency repair; Budget 41 EG1108 Unit 1 Turbine Outage - - 424,747 (424,747) 0.0% - 412,000 424,747 103.1% Completed amendment approved in Dec. 42 EG1109 Unit 3 FD & ID FAN CNRL UP 45,000 45,000 - 45,000 0.0% 45,000 - - 0.0% Deferred Next fiscal year. 43 EG1110 Unit 3 DCS Com & Software 30,000 30,000 - 30,000 0.0% 30,000 - - 0.0% Deffered Next fiscal year. 44 EG1111 Unit 2 Boiler Inspection & Repair - 175,000 102,151 72,849 58.4% - 175,000 102,151 58.4% Completed Emergency repair. 45 EG1112 Unit 3 Heat Expansion Joint - 65,000 - 65,000 0.0% - 65,000 - 0.0% Not Started Scheduled Spring outage. 46 EG1113 Units 1 & 2 Control Modifications - 150,000 - 150,000 0.0% - 150,000 - 0.0% Not Started Scheduled Spring outage. 47 EG1114 Unit 3 Gas Line Modification - 60,000 - 60,000 0.0% - 60,000 - 0.0% Not Started Scheduled Spring outage. 48 EU1101 Distribution Upgrades 400,000 400,000 175,147 224,853 43.8% 400,000 373,018 175,147 47.0% Started Ongoing as needed. 49 $ 3,609,497 $ 4,239,497 $ 1,944,767 $ 2,294,730 45.9% $ 3,609,497 $ 3,617,004 $ 1,944,767 53.8% 50 51 Grand Totals $ 19,374,399 $ 18,458,556 $ 14,765,212 $ 3,693,344 80.0% $ 3,609,497 $ 4,494,722 $ 2,607,250 58.0% 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 Page 5 of 5

City of Dover Capital Investment Plan Project Tracking Report February 28, 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 2 729 ,729,628 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 1,019,629 300,000 58,709 2,797,792 4,176,130 Interest Earned 10,900 - - 40,700 51,600 Total Funding Sources (Unaudited) $ 8,902,720 $ 1,300,000 $ 10,681,049 $ 4,585,722 $ 26,307,062 Page 1 of 5

City of Dover General Fund - Major CIP Projects February, 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 $ 1,604,906 $ 23,075,028 6.5% $ 6,687,039 $ 7,630,663 $ 867,840 11.4% Started Bid Pack B - Construction Started. 3 Totals - FY09 $ 18,200,000 $ 24,679,934 $ 1,604,906 $ 23,075,028 6.5% $ 6,687,039 $ 7,630,663 $ 867,840 11.4% 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 $ 461,492 $ 273,693 62.8% $ 735,185 $ 735,185 $ 461,492 62.8% Started Vehicles being ordered. Core Law Enforcement Server 11 PD1001 Replacement - 53,500 35,708 17,792 66.7% - 53,500 35,708 66.7% Started Specifications done. 12 PD1101 Public Assembly Room Upgrade - 20,000 - 20,000 0.0% - 20,000 - 0.0% 13 PR1101 Playground Improv 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 Concrete Program 50,000 50,000 45,759 4,241 91.5% 50,000 50,000 45,759 91.5% Started Complete with contractor portion. 16 ST1102 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. 17 MR1101 Downtown Security Cameras 31,500 31,500 17,325 14,175 55.0% 31,500 31,500 17,325 55.0% Started Contract signed. 18 Totals - FY11 $ 445,175 $ 1,235,185 $ 873,236 $ 361,949 70.7% $ 1,161,685 $ 1,235,185 $ 873,236 70.7% 19 20 Grand Totals $ 18,695,175 $ 25,955,119 $ 2,506,770 $ 23,448,349 9.7% $ 7,848,724 $ 8,902,720 $ 1,766,576 19.8% 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 February, 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 $ 441,498 $ 37,650 92.1% $ 121,891 $ 121,891 $ 84,241 69.1% Started Ongoing. 3 Totals $ 400,000 $ 479,148 $ 441,498 $ 37,650 92.1% $ 121,891 $ 121,891 $ 84,241 69.1% 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 Trying to move this to Library Project if 10 Schutte Parking Lot $ 21,950 $ 21,950 $ - $ 21,950 0.0% $ 21,950 $ 21,950 $ - 0.0% State approves. 11 Turnberry Drive 40,000 40,000 40,000 - 100.0% 40,000 40,000 40,000 100.0% Curb work complete, paving in 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. 16 CT1108 Mitschner Road (incl. CDBG) 169,066 272,779 246,672 26,107 90.4% 272,779 272,779 246,672 90.4% In progress. 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% CT1162 Library Access Rd. 105,000 105,000 - 105,000 0.0% 105,000 105,000 - 0.0% 21 ST1101 Street & Alley Program 300,000 300,000 179,271 120,729 59.8% 300,000 300,000 179,271 59.8% In progress. 22 State Agreements not yet rec'd 458,968 346,468 - 346,468 0.0% 242,755 242,755 - 0.0% Agreements have not been received. 23 Totals $ 1,163,659 $ 1,154,872 $ 546,569 $ 608,303 47.3% $ 1,051,159 $ 1,051,159 $ 546,569 52.0% 24 25 Grand Totals $ 1,690,609 $ 1,760,970 $ 1,028,067 $ 732,903 58.4% $ 1,300,000 $ 1,300,000 $ 670,810 51.6% 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 February, 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 South Governors Ave. Water Main Upgrade $ 200,000 $ 200,000 $ 2,664 $ 197,336 1.3% $ - $ 197,336 $ - 0.0% Complete Done. Selecting Tank Model & Site; FY11 = 3 WD0804 M 1.0 MG Elevated Water Storage Tower 4,196,600 2,590,000 12,847 2,577,153 0.5% - 193,377 6,224 3.2% Started Constr. 4 WD0805 M Piney Point Well 398,800 665,000 63,499 601,501 9.5% - 162,525 11,024 6.8% Started DNREC permiting; FY11 = Constr. 5 WW0809 M South Governors Ave. Sewer Main 300,000 291,000 13,561 277,439 4.7% - 279,244 1,805 0.6% Complete Done. 6 WW0810 M/SL US 13 East Sanitary Sewer Interceptor 2,376,800 3,409,641 2,884,955 524,686 84.6% - 2,335,862 2,016,793 86.3% Complete Done. 7 Totals - FY08 $ 7,472,200 $ 7,155,641 $ 2,977,526 $ 4,178,115 41.6% $ - $ 3,168,344 $ 2,035,846 64.3% 8 9 FY2009 10 WQ0905 M/SL Bayard Avenue $ 590,910 $ 590,910 $ 243,276 $ 347,634 41.2% $ - $ 584,420 $ 236,786 40.5% 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 1,035,898 148,606 887,292 14.3% - 967,801 24,610 2.5% Started Going to bid. Start in May. 13 Water Quality Improvements FY09 $ 2,518,317 $ 2,504,404 $ 569,060 $ 1,935,344 22.7% $ - $ 2,399,921 $ 409,571 60.5% Started 14 15 WW0902 M/SL DE State University Pumping Station $ 386,400 $ 386,400 $ 293,367 $ 93,033 75.9% - 240,324 147,652 61.4% Completed Done. Done. Overage covered by US 13 16 WW0905 M/SL Fox Hall/Retreat Force Main Rerouting 133,100 139,245 238,789 (99,544) 171.5% - - 20,351 0.0% Completed Interceptor (WW0810). 17 WW0907 M/SL Acorn Lane Pump Station Replace. 386,400 386,400 294,040 92,360 76.1% - 210,528 118,529 56.3% Completed Done. 18 Totals - FY09 $ 3,424,217 $ 3,416,449 $ 1,395,256 $ 2,021,193 40.8% $ - $ 2,850,773 $ 696,104 24.4% 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 1,221 1,798,779 0.1% - 1,798,447 - 0.0% Started Construction to start in July. 23 WW1007 M/SL Fox Hall Pump Station 427,900 52,000 46,076 5,924 88.6% 375,900 426,044 44,220 10.4% Started Out to bid. 24 WW1008 M/SL Heatherfield Force Main Rerouting 220,400 40,000 35,534 4,466 88.8% 229,200 267,916 34,250 12.8% Started Out ot bid. 25 WW1010 I Tar Ditch Interceptor Upgrade 518,230 518,230 15,081 503,149 2.9% - 516,781 13,632 2.6% Started Reviewing design. 26 WS1001 Various Pump Motor Replacements 45,248 45,248 - 45,248 0.0% - 45,248 - 0.0% Started Grant approved. Ordering begun. 27 Totals - FY10 $ 3 066 ,066,778 $ 2 510 ,510,478 $ 121,017 $ 2 389 ,389,461 4.8% $ 605,100 $ 3 086 ,086,332 $ 92,103 3.0% 28 29 FY2011 30 WD1101 Misc. Distribution 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 Program 60,000 60,000 - 60,000 0.0% 60,000 60,000 - 0.0% Started Work starting in March\April. 32 WQ1101 WQI - Loockerman Street 500,000 60,000 35,677 24,323 59.5% 500,000 60,000 35,677 59.5% Not Started See above FY09. 33 WQ1102 WQI - Columbia Avenue - 303,000 637.50 302,363 0.2% - 303,000 638 0.2% Not Started See above FY09. 34 WQ1103 WQI - Ross Street - 117,000 637.50 116,363 0.5% - 117,000 638 0.5% Not Started See above FY09. 35 WQ1104 WQI - William Street - 10,000 637.50 9,363 6.4% - 10,000 638 6.4% Not Started See above FY09. 36 WQ1105 WQI - West Street (W. Alley) - 10,000 637.50 9,363 6.4% - 10,000 638 6.4% Not Started See above FY09. 37 WW1101 M/SL Inflow/Infiltration Removal 500,000 500,000 6,113.82 493,886 1.2% 500,000 500,000 6,114 1.2% Started Will start after FY10 is done. 38 WW1102 R Scada Technology Equip Upgrade 82,100 82,100 63,589 18,511 77.5% 82,100 82,100 63,589 77.5% Started 4 of 7 installed. Shifted completion to interceptor 39 WW1103 Del State/Del Tech Force Main Rerouting 286,500 286,500 3,451 283,049 1.2% 286,500 286,500 3,451 1.2% Done (WW0810). 40 WW1104 SL Lepore Road Pump Station Replacement 52,000 52,000 13,135 38,865 25.3% 52,000 52,000 13,135 25.3% Started Design with Braun. 41 WW1105 R Misc. Sewer System Improvements 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 $ 159,668 $ 1,415,932 10.1% $ 1,575,600 $ 1,575,600 $ 159,668 10.1% 43 44 Grand Totals $ 15,538,795 $ 14,658,168 $ 4,653,466 $ 10,004,702 31.7% $ 2,180,700 $ 10,681,049 $ 2,983,720 27.9% 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. 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 February, 2011 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Hide 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 2,068,260 550,725 1,517,535 26.6% - 250,000 30,264 12.1% Completed Done. 4 Totals - FY06 $ 12,328,450 $ 10,762,042 $ 9,312,486 $ 1,449,556 86.5% $ - $ 254,242 $ 34,506 13.6% 5 6 FY 2008 Unit 3 Turb Bearing Fire Protect 7 EG0801 Deluge $ 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 (Replmnt) $ 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 Replacement 85,000 85,000 26,577 58,423 31.3% - - 9,859 0.0% Completed Done. 14 EG1009 Photovoltaic Install @ McKee Run - 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 Replacement 256,218 256,218 202,419 53,799 79.0% 256,218 256,218 202,419 79.0% Started Material being received. 25 EE1102 Replace of 69 kV Breakers 100,000 100,000 60,792 39,208 60.8% 100,000 100,000 60,792 60.8% 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. pp 28 EE1105 Engineering Misc Equipment Replmnt 40,000 40,000 24,751 15,249 61.9% 40,000 40,000 24,751 61.9% 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 - 91,000 705 90,295 0.0% - 91,000 705 0.8% Started Electric line relocation. 31 EE1111 UG Transformers 120,536 120,536 77,703 42,833 64.5% 120,536 120,536 77,703 64.5% Started Ongoing as needed. 32 EE1111 UG Conductors 529,464 521,896 179,199 342,697 34.3% 529,464 521,896 179,199 34.3% 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% 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 Scoping construction in FY12. Funding reallocated to Unit 1 38 EG1104 Unit 3 Aux System Components 113,000 - - - 0.0% 113,000 - - 0.0% Deferred repair. 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. Funding reallocated Unit 1 40 EG1106 Unit 3 Stack Repairs 25,000 - - - 0.0% 25,000 - - 0.0% Deffered repair. Defered to FY12. Scoping, some funding 41 EG1107 Units 1 & 2 Life Extension 276,000 225,000 41,546 183,454 18.5% 276,000 225,000 41,546 18.5% Started reallocated Unit 1 repair. Emergency repair; Budget 42 EG1108 Unit 1 Turbine Outage - 412,000 424,747 (12,747) 0.0% - 412,000 424,747 103.1% Completed amendment approved in Dec. 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 - 124,000 102,151 21,849 82.4% - 124,000 102,151 82.4% Completed Emergency repair. 46 EG1112 Unit 3 Heat Expansion Joint - 65,000 - 65,000 0.0% - 65,000 - 0.0% Started Started with spring outage. 47 EG1113 Units 1 & 2 Control Modifications - 150,000 18,223 131,777 12.1% - 150,000 18,223 12.1% Started Started with spring outage. 48 EG1114 Unit 3 Gas Line Modification - 60,000 - 60,000 0.0% - 60,000 - 0.0% Started Started with spring outage. 49 EU1101 Distribution Upgrades 400,000 373,018 255,578 117,440 68.5% 400,000 373,018 255,578 68.5% Started Ongoing as needed. 50 $ 3,609,497 $ 3,708,081 $ 2,192,378 $ 1,515,703 59.1% $ 3,609,497 $ 3,708,081 $ 2,192,378 59.1% 51 52 Grand Totals $ 19,374,399 $ 18,221,630 $ 15,012,823 $ 3,208,807 82.4% $ 3,609,497 $ 4,585,722 $ 2,854,861 62.3% 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 January Monthly Report Energy and Operations Management February 24, 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 January, 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 January was 64,462 MWhs, versus a weather normalized projected load of 60,136 MWhs. Hedged transactions accounted for 53,040 MWhs or 83% of this volume (88% of forecasted load) at a cost of $3.87 million. Spot Market purchases resulted in a PJM charge of $1.57 million (a $1.57 million charge in the Day Ahead market and a $6 thousand charge in the Real Time market). Other PJM related charges accounted for an additional cost of $1.36 million, inclusive of all load related fees. January Energy Only Unit Cost, excluding capacity obligations and credits, was $5.11/MWh unfavorable compared to the budgeted value of $86.66/MWh. On January 24, 2011, City of Dover reviewed and approved Pace and NAES submittal on 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 $88.65/MWh, or $1.78/MWh favorable as compared to the Reset Budget1. Generation and Asset Management Net generation for the month of January credited by PJM was 1,267 MWhs and the budget did not expect any generation. During the month both McKee Unit 3 and Van Sant Unit 11 were dispatched by PJM. In aggregate, Dover’s units were dispatched for 26 hours during the month, creating a generation production margin of $34 thousand (after fuel costs). Unit 3 and Van Sant units also conducted and successfully completed PJM Winter Capacity Testing for the month. Emissions Allowance Management Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in their 2010-2011 fiscal year budget. Dover 1 The projected all in Cost of Service is based on YTD actual results for 7 months and 5 months of projected costs. 2

purchased and retired 53 NOX seasonal allowances on November 23rd in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover is expected to purchase 22 NOX annual allowances on February in order to cover their 2010 NOX annual compliance position. Dover has dispatched units and the appropriate number of allowances are set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through January 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx Date Action Allowance Sale Revenue1 Allowance Sale Revenue1 Allocation Price Allocation2 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 -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 12/31/11 2011 YTD (2) (2) Emissions Totals - Allowances 3,191 -- $0 52 52 -- $0 3,974 CAIR $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 NOx seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $65,193 at the time of this report. This represents 3,191 3

pre-CAIR SO2 allowances trading at $8.50/ton, 3,974 post-CAIR SO2 allowances trading at $5/ton, 52 NOx annual allowances trading at $325/ton, and 52 NOx seasonal allowances trading at $25/ton. EMISSIONS & ALLOWANCE SUMMARY Through January 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 2 0 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 0 (44) NOx Seas – 2010 50 0 122 0 (53) (19) NOx Annu – 2011 76 2 0 0 0 74 NOx Seas – 2011 49 0 0 0 0 49 Operations Management Summary During the month of January, there were no reportable or lost time accidents or injuries. The facility has now gone 109 days without an OSHA recordable accident and 109 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued and no near miss events. There were four opacity deviations that occurred during a Unit 3 operation. Unit 3 was dispatched once and VanSant was dispatched twice during the month. Winter capacity tests were completed successfully on both of these units during these operating periods. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of January were $337,207. The expenses were $144,600 or 30.0% under the approved budget (or $84,000 or 20% under the reset budget) of $481,807. The principal reason for the positive variance is due to the timing of payments for electricity, Contractual Services, and Permit costs paid in December. 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. 4

Risk Management Summary Forward PJM power prices fell across the board since the last reporting period. The fall in prices in the front of the curve was driven by moderate temperatures, with the expectation of continued warmer temperatures, combined with the upcoming shoulder months, which are historically cheaper. Forward Dover Zone power prices for FY 2010-11 decreased by $1.80/MWh (a decrease of 3.45%) since the last reporting period while FY 2011-2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all changed by approximately -$0.54/MWh to -$3.38/MWh (representing a range of 0.96% decrease and a 6.40% decrease, respectively) compared with the last reporting period. The individual years’ hedge ratios and Cost-of-Service projections, with the cost impact of expected solar plant volumes, is shown in the table below: Wholesale Cost-of-Service Summary (Projected) Date 2/17/2011 Budget February Jan Dec Cost-of Cost-of- Service Year-to Forecasted Cost-of Cost-of Hedge Power Year Service w/Solar Ratio Year over 2009- Service Service Budget Costs Only Increase 10 Budget $/MWh $/MWh $/MWh* 2010-2011 N/A $85.65 89% -4.3% -8.50% $85.15 $84.93 2011-2012 N/A $78.94 85% -8.6% -16.35% $79.52 $79.49 2012-2013 N/A $72.22 76% -8.7% -23.60% $72.69 $73.04 2013-2014 N/A $70.08 48% -3.1% -25.98% $70.61 $71.46 2014-2015 N/A $68.08 16% -3.0% -28.18% $68.94 $70.24 *Note that the "Cost-of-Service w/Solar Costs Only" column does not reflect the SREC benefit the City will receive since the SREC prices are currently unknown **Assumes solar generation will start in June 2011 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance Jan-11 Jan-11 Jan-11 Load Forecast 60,136 64,462 (4,326) Power Supply Power Supply $3,914,238 $3,865,362 $48,876 Power Supply Management $190,242 $190,522 ($280) Capacity Charges - Load $1,078,287 $1,078,287 $0 PJM Charges - Load $1,107,048 $1,860,072 ($753,024) Total - Power Supply $6,289,815 $6,994,243 ($704,428) Generation Plant Operations $421,207 $337,207 $84,000 Generation Fuel $0 $237,651 ($237,651) Capacity Credits ($1,002,527) ($1,002,528) $0 PJM Credits ($34,012) ($305,692) $271,680 Total - Generation ($615,333) ($733,362) $118,029 Emission Allowance Sales Total - Emission Allowance Sales $0 $0 $0 Total Power Supply & Generation $5,674,482 $6,260,881 ($586,399) Total Power Supply, Generation & Emission Sales $5,674,482 $6,260,881 ($586,399) Unit Costs Total – Power Supply $104.59 $108.50 ($3.91) Total - Generation + Emission Sales ($10.23) ($11.38) $1.14 Final Cost of Service to City of Dover Ratepayers $94.36 $97.13 ($2.76) 6

Budget Actual Variance YTD YTD YTD Load Forecast 463,249 467,576 (4,326) Power Supply Power Supply $29,116,550 $29,067,674 $48,876 Power Supply Management $1,383,186 $1,383,466 ($280) Capacity Charges - Load $7,476,394 $7,476,394 ($0) PJM Charges - Load $8,841,659 $9,594,683 ($753,023) Total - Power Supply $46,817,790 $47,522,217 ($704,427) Generation Plant Operations $3,531,624 $3,447,624 $84,000 Generation Fuel $3,138,177 $3,375,827 ($237,651) Capacity Credits ($6,964,307) ($6,964,307) $0 PJM Credits ($5,312,543) ($5,584,223) $271,680 Total - Generation ($5,607,049) ($5,725,078) $118,029 Emission Allowance Sales Total - Emission Allowance Sales $3,445 $3,445 $0 Total Power Supply & Generation $41,210,740 $41,797,139 ($586,398) Total Power Supply, Generation & Emission Sales $41,214,185 $41,800,584 ($586,398) Unit Costs Total – Power Supply $101.06 $101.64 ($0.57) Total - Generation + Emission Sales ($12.10) ($12.24) $0.14 Final Cost of Service to City of Dover Ratepayers $88.97 $89.40 ($0.43) 7

2.2 – VARIANCE ANALYSIS Power Supply • Power Supply realized a favorable $48 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 $753 thousand variance relative to the monthly budget. This variance was driven by Dover’s open position, which was 61% 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 $499 thousand greater than budget. Secondary major factor associated with this unfavorable variance included a $417 thousand unfavorable variance in Basis costs. Offsetting these unfavorable variances were a $145 thousand favorable variance in Load Following and a $21 thousand favorable variance in the Transmission Loss Refund. • For the month an unfavorable $704 thousand net variance between Power Supply (fixed positions) and PJM Charges for Load (open positions, transmission, etc.) was realized due to an unfavorable $384 thousand variance, caused by a change in volume, and an unfavorable $320 thousand variance, caused by a change in price. Hence, 55% of the unfavorable variance can be attributed to volume changes with 45% of the unfavorable variance being attributed to price changes. • The Power Supply Management variance is merely an estimate at this point. Generation • Plant O&M reported a favorable variance of $84 thousand compared to the monthly O&M reset Budget of $421 thousand (or $144 thousand favorable compared to the original budget of $482 thousand). The principal reasons for this favorable variance were (i) lower than expected labor costs and burdens, (ii) decreased spending in materials and supplies expenses and (iii) lower than budgeted electric and water & sewer expenses. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights • Dover’s January load was 64,462 MWh, which was 7.2% above the weather normalized load of 60,136 MWh. Hedge volumes accounted for 82.3% of actual load for the month. • The January All In Unit Energy cost (excluding capacity) of $91.77 per MWh is $5.11 per MWh higher 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 Jan-11 Dec-11 Dec-11 City of Dover Load Load Obligation (MWh) 60,136 64,462 (4,326) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $79.54 $85.04 ($5.50) Pass Through $6.19 $5.82 $0.37 Incentive Fees $0.93 $0.91 $0.02 Total - All In Unit Energy Cost $86.66 $91.77 ($5.11) Purchased Power Variance Analysis • The actual Dover load of 64,462 MWh was 7.2% above the projected January load of 60,136 MWh. • The All In Unit Energy Cost was $5.11 per MWh higher than budget due to increased open volume purchases, increased energy costs, an unfavorable basis variance and a higher than projected basis cost. Offsetting these negative variances were decreased load following charges and a favorable 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): 53,040 MWhs @ $72.88/MWh: $3,865,362 Power Balancing; Additional PJM, and Energy Manager Fee3: $3,128,881 Total Cost to Serve Load (64,462 MWhs) $6,994,243 All In $/MWh load cost inclusive of Energy Management Fees: $108.50/MWh 3 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT • During the month, PJM dispatched McKee Run Unit 3 and Van Sant Unit 11 generating 1,267 MWhs. The budget did not expect any generation for the month. Unit 3 and Van Sant units also conducted and successfully completed PJM Winter Capacity Testing for the 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 Jan-11 Jan-11 Jan-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 $0.00 Power Sales Power Sales (MWh) 0 1,267 (1,267) Sales Revenue ($ per MWh) $0.00 ($214.51) $214.51 Power Sales Revenue ($) $0 ($271,679.50) $271,680 Variable Fuel & Transport Fuel Oil No.2 Volume - McKee (gal) 0 25,707 (25,707) Fuel Oil No.2 - McKee ($/gal) $0.00 $2.07 ($2.07) Fuel Oil No.2 Cost of Goods Sold - McKee ($) $0 $53,213.49 ($53,213) Fuel Oil No.2 Volume - Van Sant (gal) 0 37,013 (37,013) Fuel Oil No.2 - Van Sant ($/gal) $0.00 1.92 ($1.92) Fuel Oil No.2 Cost of Goods Sold - Van Sant ($) $0.00 71,064.96 ($71,064.96) Gas Volume (Dth) 0 5,721 (5,721) Unit Gas Price ($/Dth) $0.00 $19.82 ($19.82) Variable Gas Cost ($) $0.00 $113,372.16 ($113,372.16) Transport ($) $0.00 0 $0.00 Variable Gas and Transport Costs ($) $0.00 $113,598.82 ($113,598.82) Variable Fuel & Transport Costs ($) $0 $237,650.61 ($237,651) Testing $0.00 $0.00 $0.00 Generation Production Margin $0.00 ($34,028.89) $34,028.89 Generation Capacity Payment Total - Generation Capacity Payment ($1,002,527) ($1,002,528) $0 14

Generation Management Variance Analysis Fuel Expense • PJM dispatched Dover’s units into the market and McKee Run Unit 3 and Van Sant units consume natural gas and fuel oil to generate 1,267MWh. Furthermore, these units also performed and completed PJM Winter Capacity Testing for the month. Generation Production Margin Transaction Volumes Revenue/(Cost) PJM Invoice for Power Sold 1,267 MWhs $271,679 Fuel and Transport 5,721 Dth gas/ 25,707 gal #2 oil ($237,651) 37,013 gal #2 oil Low Sulfur Generation Production Margin 1,267 MWhs $34,029 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 McKee Run Unit 3 consumed 5,721 Dth. Date Volume (Dth) Price ($/Dth) Total Commodity Cost ($) Hess Corp Sub-Total 0 $0.00 $0.00 PESCO 23-Jan 455 $19.38 $8,817.90 23-Jan (184) $4.36 ($802.24) 24-Jan 4,000 $18.23 $72,920.00 24-Jan 1,450 $22.37 $32,436.50 Sub-Total 5,721 $19.82 $113,372.16 NJNG Sub-Total 0 $0.00 $0.00 Total 5,721 $19.82 $113,372.16 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 McKee Run Unit 3 and Van Sant Unit 11 were dispatched into PJM consuming fuel oil. In addition, the aforementioned Dover units conducted PJM Winter Capacity testing this month. In aggregate, the units consumed approximately 62,720 gal of #2 fuel oil for the month. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of January 31 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch4) McKee Run (#2 Fuel 2,554,105 442,388 3 Oil) Van Sant 258,000 113,097 3 (#2 Fuel Oil) January 2011 Fuel Oil Consumption McKee Run and Van Sant Date #2 Oil Inventory Market Price Inventory Market Cost Burns / gal Price ($/gal) ($/gal) Cost 23-Jan 13,571 $2.07 NA ($28,092) NA 24-Jan 37,013 $1.92 NA ($71,065) NA 24-Jan 12,136 $2.07 NA ($25,121) NA Total 62,720 ($124,278) 4 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 their 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover is expected to purchase 22 NOX annual allowances on February in order to cover their 2010 NOX annual compliance position. Dover has dispatched units and the appropriate number of allowances are set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through January 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx Date Action Allowance Sale Revenue1 Allowance Sale Revenue1 Allocation Price Allocation2 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 -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 12/31/11 2011 YTD (2) (2) Emissions Totals - Allowances 3,191 -- $0 52 52 -- $0 3,974 CAIR $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 NOx seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 19

Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $65,193 at the time of this report. This represents 3,191 pre-CAIR SO2 allowances trading at $8.50/ton, 3,974 post-CAIR SO2 allowances trading at $5/ton, 52 NOx annual allowances trading at $325/ton, and 52 NOx seasonal allowances trading at $25/ton. SO2 SO2 prices remain relatively flat with vintage 2009 or earlier allowances trading around $9/ton and vintage 2010 allowances or later trading around $5/ton (see Figure 1 – SO2 Prices since Last Monthly Report). SO2 prices will likely remain at or near these pricing levels until either EPA releases final rules for the Clean Air Transport Rule (Transport Rule) or Congress passes legislation regulating the markets. Figure 1 – SO2 Prices since Last Monthly Report SO2 Allowance Prices (Jan / Feb) $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 2009 (pre‐CAIR) 2010/2011 (post‐CAIR) NOx NOX annual allowance prices have leveled off some after consecutive months of climbing (See Figure 2 – NOX annual prices since last monthly report.) On February 11, 2011, Dover executed an agreement to purchase 22 NOX annual allowances at $365/ton in order to cover a portion of their 2010 emissions. Dover paid a slightly higher price than the then current “market price” due to the small number of allowances Dover sought to purchase. Pace Global solicited pricing offers for about a week and was able to secure allowances at this price, which was substantially lower than other offers it received. Pace Global advised Dover to purchase allowances at that time in order to avoid paying a higher price closer to the statutory deadline for retiring allowances of March 1, 2011. 20

NOX seasonal prices remained completely flat at $25/ton (See Figure 3 – NOX seasonal prices since last monthly report.) Figure 2 – NOX annual prices since last monthly report NOX Annual Allowance Prices (Jan / Feb) $360.00 $340.00 $320.00 $300.00 $280.00 $260.00 $240.00 $220.00 $200.00 Figure 3 – NOX seasonal prices since last monthly report NOX Seasonal Allowance Prices (Jan / Feb) $30.00 $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 SO2 and NOx Outlook 21

The SO2 and NOX markets continue to be hampered by regulatory uncertainty. While market participants await the release of the final Transport Rule, congressional action around the issue appears to be picking up. This week, Representative Ed Whitfield (R-Kentucky) announced that there is draft legislation circulating among the House of Representatives that would effectively keep CAIR in place. Meanwhile, Senator Carper (D-Delaware) continues to champion a bill that would keep CAIR in place until 2012, and then tighten emissions caps in later years. Despite some early rumblings that Congress might try to cut EPA’s budget for regulating SO2, NOX and other traditional or criteria pollutants, the House’s 2011 proposed budget takes aim at GHG regulations but would leave other regulatory programs largely in place. RGGI and Federal Carbon Outlook RGGI allowance prices continue to flounder around the statutory floor price of $1.86/ton. RGGI is substantially over supplied and as a result allowances prices have remained extremely low (see Figure 4 – RGGI Allowance Prices). Figure 4 – RGGI Allowance Prices RGGI Prices (Jan / Feb) $1.95 $1.90 $1.85 The conversion potential of RGGI allowances into federal allowance volume in a national carbon market remains the main support for RGGI pricing. However, with major uncertainty surrounding the ultimate ability to pass legislation in the near-term, RGGI allowance prices continue to remain very low. 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 $285,000. 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 22

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 second peg of these drivers, EPA regulation under their existing authority, may take a serious hit if the House of Representative’s proposed budget, defunding most of EPA’s GHG regulatory programs, is signed into law in its current form. The third peg, regional and state initiatives, got a major boost on December 16, 2010, as the California Air Resource Board approved rules for a cap-and-trade program that will begin in 2012. 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 2014 and 2017. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights • During the month of January, there were no restricted work days or lost time accidents. The facility has now gone 109 days without an OSHA recordable accident and 109 consecutive days without a lost time reportable accident. There were four opacity deviations that occurred during a Unit 3 operation on January 24, 2011. • The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month. • McKee Run Unit 3 and Van Sant Unit 11 were dispatched by PJM for 19.3 hours and 7.4 hours, respectively for the month. These units also performed and passed capacity testing. McKee Run Units 1 and 2 were not dispatched for the month. • Mechanical staff installed fire stop material in cable trays, around conduit piping and areas where fire rated walls have been penetrated. • IC&E staff investigated and completed troubleshooting methods for two oil burner problems on Unit 3 boiler. • Operations teams have been assisting the Maintenance Team in remodeling office areas in the main turbine building. • Jeff Moore has been hired as a contracted employee to help the plant with shipping and billing during Boyd Lord’s absence. • Brian Hoyt has accepted a position with NAES Corporation-Dover as a Compliance Specialist. Brian lives in the Dover area, has prior environmental experience in water and air, and is scheduled to start work on February 14, 2011. • The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware January 2011 Monthly Report Air Compressors and Air Dryer Relocated to the Ground Floor 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 January, there were no restricted work days or lost time accidents. The facility has now gone 109 days without an OSHA recordable accident and 109 consecutive days without a lost time reportable accident. There were four opacity deviations that occurred during a Unit 3 operation on January 24, 2011. The events occurred while the unit was combusting fuel oil and increasing load (from minimum to full) by adding additional oil guns/burners. 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 (January) (7/1/10-6/30/11) NOVs 0 0 Opacity Deviations 4 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 3 Man Hours Worked 3,057.50 81,506.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 109 Days since last Lost Time Accident 109 Emissions (NOx & SO2) All data thru 1/31/11 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 Available NOx Allowance Balance CAIR NOx CAIR NOx (Per Facility, Prior to Sale) Total NOx Allowance Allowances McKee Run Tons Vintage Sold YTD (Yr/Season) Van Sant Emitted McKee Run Van Sant (Yr/Season) (Yr/ (Yr/Season) (Yr/Season) Season) 2009 45/25 75*/50* 5/3 12/5 - 1/1 0/0 – 0/0 18/0 2010 119**/119** 0 73/47* 5/3 0/53# – 0/0 -46/0 - 3/3 2011 0 71/46 5/3 1/0 – 1/0 0/0 - 0/0 70/46 Note *- State Reallocation for McKee Run 2 tons Year 2009, 2 tons Ozone Season 2009 and 1 ton Ozone Season 2010. Note ** - The 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. They are also investigating another option with the EPA that could reduce the emissions further. As of December 31, 2010, the EPA has informed NAES that they will review the petition once they reconvene in January 2011. Note# - 53 tons were purchased to help compensate for the shortage in seasonal NOx allowances. 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 1/31/2011 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 2.3 1986 Note: Data is as of 1/31/2011 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 –January 2011 Actual Budget Variance Personnel 251,497 254,151 2,654 Materials & Supplies 6,683 19,950 13,627 Administrative Expenses 79,027 207,706 128,679 Total $337,207 $481,807 $144,600 Financial – Fiscal Year to Date Number of Months - 7 Actual Budget Variance Personnel 1,787,933 1,799,640 11,707 Materials & Supplies 180,726 113,520 (67,206) Administrative Expenses 1,478,966 1,239,175 (239,791) Total $3,447,624 $3,152,335 ($295,289) 2.1 Variance analysis: The original budget for January was $481,807. The actual expenses for January were $337,207 for a favorable variance of $144,600 or approximately 30.0%. The variance was due to the following: PERSONNEL EXPENSES – A favorable variance of $2,654 was due to lower labor burdens and slightly lower labor costs during the month. MATERIALS AND SUPPLIES EXPENSES – A favorable variance of $13,627 was realized due to lower spending in Janitorial Supplies, Security/Safety Materials, Medical Supplies, Computer Software and Water/Sewer. ADMINISTRATIVE EXPENSES - Lower than budgeted expenses in Electric, Heating Oil/Gas, Training/Conferences/Food, Contractual Services, Right of Ways/Permits, Environmental Expenses, and Other Equipment/Maintenance contributed to a favorable variance of $128,679. Timing of Electric bills and Rights of Ways/Permit Fees were a large contributor to the variance amount. The variance in the YTD Electric account is due to the increased run time in July, which due to plant equipment configuration change (running auxiliaries off the Unit 3 Start-up Transformer) caused a significant increase in the monthly ratcheting demand charge. Boiler Systems incurred an unfavorable variance due to unexpected costs associated with Unit 3 Boiler tube leak repairs. The budget is currently forecast to finish this fiscal year at $6,044,105 expensed versus $5,689,315 budgeted thereby realizing a 106.24% expenditure rate. The high expenditure rate is due primarily to increased unit operation time which to a large scale directly led to an increase in electric and water costs over the original budget. In addition, operational limits created a need 30

for alternate auxiliary power sources that resulted in a higher demand charge for electricity which will continue throughout the rest of the fiscal year and into the next fiscal year. 3.0 Operations Unit Operations / Outages / Trips During the month of January, Unit 3 was dispatched by PJM on January 24th in which it operated for 19.3 hours. Unit 3 was operated on oil most of the day then switched to main gas to complete the winter capacity test. The two hour average for the successful capacity test was 105.61 MWs. Units 1 and 2 were not dispatched for the month of January. Unit 11 was dispatched by PJM twice where it operated for 7.417 hours on oil. Unit 11 successfully completed the winter capacity test with a one hour average of 43.83 MWs. Units 1 and 2 were not dispatched for the month of January. Month – January 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 19.300 19.300 7.417 26.717 Starts # 0 0 1 1 2 3 Gross Generation MWh 0.0 0.0 1,056.826 1,056.826 300.787 1,357.613 Net Generation MWh 0.0 0.0 969.208 969.208 300.519 1,269.727 Total Auxiliaries MWh 35.919 35.919 233.741 305.579 8.775 314.354 Auxiliaries purchased MWh 35.919 35.919 146.123 217.961 8.507 226.468 Fuel Gas Used MMBTU 0.0 0.0 6,755.386 6,755.386 0.0 6,755.386 Fuel Oil Used MMBTU 0.0 0.0 5,232.402 5,232.402 3,654.175 8,887.025 Fuel Oil Used Gallons 0.0 0.0 37,631 37,631 26,403 64,034 Total Fuel MMBTU 0.0 0.0 11,988.237 11,988.237 3,654.175 15,642.412 Net Heat Rate BTU/KWh 0.0 0.0 12,344 12,344 12,160 12,252 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 1.28 0.96 1.01 0.97 Availability Factor % 100.00 100.00 100.00 100.00 100.00 100.00 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 744.00 744.00 724.700 2,212.700 736.583 2,949.283 Hours HW Boiler Gas Usage MMBTU 1,349.040 1,349.040 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 (7 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 13.033 128.966 645.256 787.255 137.044 924.299 Starts # 1 3 44 48 26 74 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 227.866 295.328 4,961.881 5,485.075 27.925 5,513.000 Auxiliaries purchased MWh 220.351 220.351 2,364.536 2,805.238 25.229 2,830.467 Fuel Gas Used MMBTU 2,183.250 15,245.85 452,018.83 469,447.93 53,766.951 523,214.88 0 7 7 7 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 61,146.344 548,315.54 0 8 8 2 Net Heat Rate BTU/KWh 14,841 13,355 11,696 13,297 13,192 13,245 Unit Trips # 1 0 3 4 2 6 Capacity Factor % 0.17 1.30 8.00 6.19 2.30 5.11 Availability Factor % 63.06 74.30 74.18 70.51 100.00 77.88 Commercial % 6.6 0 0.03* 0.85 0 0.66 Unavailability (CU) Planned Outage Hours Hours 1,326.500 1,326.500 1,326.500 3,979.500 0.0 3,979.500 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 579.830 0 6.317 586.15 0 586.15 Reserve Shutdown Hours 3,254.670 3,705.534 3,254.143 10,214.347 5,023.956 15,238.303 Hours HW Boiler Gas Usage MMBTU 2,935.146 2,935.146 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 Note: * depicts a unit that has not completed capacity test for the PJM Winter Capacity Demonstration Period in FY 2010-2011. All units are in the PJM Winter Exemption Program. 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) 452,525 442,388 28,739 (10,137) 448,556 111,362* (6,168) Van Sant 140,065 113,097 0 (26,968) 143,099 0 (30,002) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. Note: * Oil purchases were made in October, 2010 for #2 oil to replenish oil stocks used during testing of Unit 3 during the summer period and in January 2011, 28,739 gallons of oil were purchased due to Unit 3 operational run. Fuel oil purchase is expected to be made in February to replace fuel burned at VanSant in January 2011. Van Sant Lifetime through 11/31/11 Actual Starts Factored Starts Fired Hours Van Sant 1242 2153.65 4109.26 Since HGP - Dec 2004 191 485.95 725.68 Team Report: On January 23, the Operations team accomplished a successful capacity test on Unit 11 and on the following day completed a successful capacity test on Unit 3. Unit 3 achieved a net of 105.61 MWs and VanSant achieved a net of 43.83 MWs. PJM dispatched both units for the day. 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. Operations teams have been assisting the Maintenance Team in remodeling office areas in the main turbine building. The areas will now be used as an office for the Compliance Specialist and the Materials Coordinator within the main plant. 33

4.0 Maintenance During the month of January, plant maintenance staff continued addressing the backlog of work orders. There were fifty-three work orders issued with sixty work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report January - 7 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 5 2 3 4 2 20 7 8 19 3 38 9 10 37 4 50 0 8 42 5 15 3 0 18 SW1 0 0 0 0 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 57 32 31 58 Totals 185 53 60 178 Note: PM's are included in the priority totals Notable activities during the month include: 1) Mechanical staff installed fire stop material in cable trays, around conduit piping and areas where fire rated walls have been penetrated. Sealing these areas in and around the Net 90 computer room completes phase one of this project. Due to fire proof material shelf life and cost this project must be completed in several phases. 2) Maintenance staff installed cement caulking around the indoor caustic tank pedestals due to cracking and spalling of the old material. Third party inspection of the smaller tanks at the generating stations identified these areas in their report as deficient and needed corrective action to be taken. 3) IC&E staff investigated and completed troubleshooting methods for two oil burner problems on Unit 3 boiler. During the most recent cold spell, the unit was called into service and while loading the unit, two oil burners failed to light off. Burner A-1 was found to have a bad flame scanner (oil). The scanner was removed and replaced. The 34

burner was tested and remained in service. B-3 burner was found to have a bad fuse in the net 90 cabinet circuit board which prevented the burner from being put into service. 5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: All electrical equipment and mechanical equipment was Unit 3 Cooling tested and checked out for vibration. This work was completed on EG1101 Tower Life November 21. Extension Schedule: No other work is planned for this project during the remainder of the fiscal year. Progress: Work scope to replace the lower decking has been Units 1 & 2 Cooling completed and we are in the process of going out for bids to be EG1102 Tower Life completed in the Spring 2011 Outage. Extension Schedule: Pre-bid meeting and bids are due by the middle of February 2011. 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 documents. EG1104 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. Some funds have been used to Replacements cover the cost of the Unit 3 600-lb steam station valve repairs, Unit 3 Cooling Water Booster Pump Repairs and circuit breakers for the power distribution system. Progress: Started on the development of the project work scope document. EG1106 Unit 3 Stack Repairs Schedule: Deferred until 2011-2012 fiscal year. Progress: Work scopes have been developed, bid meeting has been held and bids have been received. Bids are now being evaluated and Units 1 & 2 Life EG1107 clarified. Expect to award bid to be awarded in mid-February. Extension Schedule: Scheduled for the Spring Outage 2011. Some of the work has been deferred until the 2011-2012 fiscal year. 35

Unit 1 Forced Progress: The repair work has been completed. EG1108 Outage Schedule: This work is complete. Repairs 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. Progress: Inspections and other repairs were completed during the Unit 2 Boiler Fall 2010 Outage EG1111 Inspections and Schedule: Miscellaneous work is being wrapped up to complete the Repairs project. Progress: Task statements and invitations to bid have been sent out. Unit 3 Air Heater Bid meetings set up for early February. Expansion joint is on order EG1112 Expansion Joint and is expected to be delivered in February 2011. Schedule: This is scheduled for the Spring Outage 2011. Progress: Work scope documents and parts list put together. Most Units 1 & 2 Controls of the parts have been ordered and are beginning to be received at EG1113 Modifications the plant. Schedule: This is scheduled for the Spring Outage 2011. Progress: Task statements and invitations to bid have been sent out. Unit 3 Gas Line Bid meetings set up for early February. Gas valves and other parts EG1114 Modifications have been ordered but not yet received. Schedule: This is scheduled for the Spring Outage 2011. 36

5.1 CIP Budget Approved Latest Project Description Budget Estimate Number ($ X 1000) ($ X 1000) EG1101 Unit 3 Cooling Tower Life Extension 398 372 Units 1 & 2 Cooling Tower Life EG1102 173 110 Extension EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 71 77 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 180 225 Unit 1 Forced Outage EG1108 412** 424 Repairs 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 175## 112 EG1112 Unit 3 Air Heater Expansion Joint 65## 65 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. 37

6.0 General Plant Information Training: Teams continued training within the Plant Readiness Program (PRP) to keep their skills and knowledge of the plant up to date particularly when the generating units are off line or when they are not supporting maintenance activities. The GPI online training which supports our safety and environmental training are being used by the teams to complete their training as they begin the training cycle for the year 2011. GPI also has a number of courses that are used to support operator advancement and refresher training. 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. 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 Weather and Environmental Emergencies, Sabotage and Terrorism Emergencies, PJM Communications and All Call. Other Events: Jeff Moore has been hired as a contracted employee to help the plant with shipping and billing during Boyd Lord’s absence and to aid in the transition of the warehouse inventory into COD’s HTE system. Jeff is a retired City of Dover warehouse worker who has good knowledge of the COD’s HTE inventory system. Brian Hoyt has accepted a position with NAES Corporation-Dover as a Compliance Specialist. Brian lives in the Dover area, has prior environmental experience in water and air, and is scheduled to start work on February 14. Calendar of Events Date Winter Capacity Period December 1, 2010 to February 28, 2011 McKee Run and VanSant Title V Annual Certification Due February 1, 2011 NOx Emissions Reconciliation Due March 1, 2011 SO2 Emissions Reconciliation Due March 1, 2011 SARA III Report March 1, 2011 Annual VanSant Black Start Test March 2011 (Exact Date TBD) Unit 11 Spring Outage March 14, 2011 – March 28, 2011 38

Units 1, 2, and 3 Spring Outage March 28, 2011 – May 23, 3011 Air Emission Inventory April 1, 2011 EIA-923 Report April 15, 2011 EIA-860 Report May 15, 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 #1 Unit Annual Inspection October , 2011 #2 Unit Annual Inspection October , 2011 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 Yes Yes Yes $20,157 $20,157 Unit 11 No Yes 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 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 $229,272.64 ($1,570,438.47) ($1,341,165.83) Realtime Energy $3,388.39 ($5,652.64) ($2,264.25) Transmission Losses Credits $0.00 $91,035.43 $91,035.43 Network Integration Transmission Service Charges $0.00 ($265,765.79) ($265,765.79) Inadvertent Interchange Charges $0.00 ($2,114.42) ($2,114.42) Regulation Charges $0.00 ($20,269.08) ($20,269.08) Synchronized Reserve Charges $0.00 ($19,821.30) ($19,821.30) Balancing Operating Reserves Charges ($601.22) ($15,617.82) ($16,219.04) Day Ahead Operating Reserves Charges $0.00 ($11,132.19) ($11,132.19) Day-ahead Scheduling Reserve $0.00 ($127.37) ($127.37) Synchronous Condensing Charges $0.00 ($107.24) ($107.24) Reactive Services Charges $0.00 ($869.47) ($869.47) Meter Correction Charges $0.00 ($1,125.25) ($1,125.25) 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 $39,619.69 $0.00 $39,619.69 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 ($12,339.39) ($12,339.39) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($4,914.91) ($4,914.91) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($31,621.68) ($31,621.68) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,203.49) ($1,203.49) North American Electric Reliability Corporation (NERC) Charge $0.00 ($575.51) ($575.51) Reliability First Corporation (RFC) Charges $0.00 ($873.16) ($873.16) 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 $742.47 $742.47 40

Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($275.30) ($275.30) Organization of PJM States, Inc. (OPSI) Funding $0.00 ($41.00) ($41.00) FERC Annual Recovery $0.00 ($3,724.23) ($3,724.23) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 $0.81 $0.81 PPA $0.00 $981.40 $981.40 $1,308,219.18 ($2,938,359.22) ($1,630,140.04) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/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 $83.56 $91.20 Mar 56,334 $84.16 $90.46 Apr 52,554 $83.69 $91.16 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 February Monthly Report Energy and Operations Management March 24, 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 February, 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 Generation MWh's: Actual v Budget All In Unit Energy Cost - 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 February was 54,900 MWhs, versus a weather normalized projected load of 54,199 MWhs. Hedged transactions accounted for 48,320 MWhs or 88% of this volume (89% of forecasted load) at a cost of $3.56 million. Spot Market purchases resulted in a PJM charge of $610 thousand (a $689 thousand charge in the Day Ahead market and a $79 thousand credit in the Real Time market). Other PJM related charges accounted for an additional cost of $1.25 million, inclusive of all load related fees. The February Energy Only Unit Cost, excluding capacity obligations and credits, was $0.95/MWh favorable compared to the budgeted value of $85.32/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 $1.65/MWh favorable as compared to the Reset Budget1. Generation and Asset Management For the month of February 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 budget did not project generation for this month. Emissions 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 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

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 February 28, 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 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. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $51,747 at the time of this report. This represents 3,189 3

pre-CAIR SO2 allowances trading at $7/ton, 3,976 post-CAIR SO2 allowances trading at $4/ton, 52 NOx annual allowances trading at $230/ton, and 52 NOx seasonal allowances trading at $30/ton. EMISSIONS & ALLOWANCE SUMMARY Through February 28, 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 February, there were no reportable or lost time accidents or injuries. The facility has now gone 137 days without an OSHA recordable accident and 137 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There was one near miss event related to a small oil leak at the fuel unloading area. 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 February were $428,092. The expenses were $361 or 0.08% over the approved budget of $427,731. The principal reason for the negative variance was higher than budgeted expenses in electric and boiler systems repairs, which were almost completely offset by lower expenses for materials and labor costs. 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. 4

Risk Management Summary Forward PJM power prices increased across the board since the last reporting period. The rise in prices was driven in the near term by recent higher than expected consumption and by global events (Libya, Japan) in the longer term. Forward Dover Zone power prices for FY 2010-11 increased by $0.71/MWh (an increase of 1.42%) since the last reporting period while FY 2011- 2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all increased by approximately $3.34/MWh to $3.91/MWh (representing a range of 6.54% increase and a 6.96% 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 3/17/2011 Budget March Feb Jan Cost-of- Cost-of Year-to Cost-of Cost-of Hedge Power Year Service Service Year Service Service 1 Ratio Budget $/MWh Increase $/MWh $/MWh 2010-2011 $82.15 $85.82 90% -3.7% $85.65 $85.15 2011-2012 N/A $79.49 85% -7.4% $78.94 $79.52 2012-2013 N/A $73.01 76% -8.1% $72.22 $72.69 2013-2014 N/A $71.87 48% -1.6% $70.08 $70.61 2014-2015 N/A $71.38 16% -0.7% $68.08 $68.94 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 proposed budget update 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance Feb-11 Feb-11 Feb-11 Load Forecast 54,199 54,900 (701) Power Supply Power Supply $3,604,252 $3,560,200 $44,052 Power Supply Management $184,719 $181,671 $3,048 Capacity Charges - Load $973,936 $973,937 ($1) PJM Charges - Load $835,383 $890,303 ($54,920) Total - Power Supply $5,598,290 $5,606,111 ($7,821) Generation Plant Operations $433,731 $428,092 $5,639 Generation Fuel $0 $0 $0 Capacity Credits ($905,509) ($905,509) $0 PJM Credits ($34,012) ($34,012) $0 Total - Generation ($505,790) ($511,429) $5,639 Emission Allowance Sales Total - Emission Allowance Sales $8,250 $8,250 $0 Total Power Supply & Generation $5,092,500 $5,094,682 ($2,182) Total Power Supply, Generation & Emission Sales $5,100,750 $5,102,932 ($2,182) Unit Costs Total – Power Supply $103.29 $102.11 $1.18 Total - Generation + Emission Sales ($9.18) ($9.17) ($0.01) Final Cost of Service to City of Dover Ratepayers $94.11 $92.95 $1.16 6

Budget Actual Variance YTD YTD YTD Load Forecast 517,448 522,476 (5,027) Power Supply Power Supply $32,720,802 $32,627,874 $92,928 Power Supply Management $1,567,905 $1,565,038 $2,867 Capacity Charges - Load $8,450,330 $8,450,331 ($1) PJM Charges - Load $9,677,042 $10,484,986 ($807,943) Total - Power Supply $52,416,080 $53,128,229 ($712,149) Generation Plant Operations $3,965,355 $3,875,716 $89,639 Generation Fuel $3,138,177 $3,376,054 ($237,877) Capacity Credits ($7,869,816) ($7,869,816) $0 PJM Credits ($5,346,555) ($5,618,235) $271,680 Total - Generation ($6,112,839) ($6,236,281) $123,441 Emission Allowance Sales Total - Emission Allowance Sales $11,695 $11,695 $0 Total Power Supply & Generation $46,303,240 $46,891,948 ($588,708) Total Power Supply, Generation & Emission Sales $46,314,935 $46,903,643 ($588,708) Unit Costs Total – Power Supply $101.30 $101.69 ($0.39) Total - Generation + Emission Sales ($11.79) ($11.91) $0.12 Final Cost of Service to City of Dover Ratepayers $89.51 $89.77 ($0.27) 7

2.2 – VARIANCE ANALYSIS Power Supply  Power Supply realized a favorable $44 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 $55 thousand variance relative to the monthly budget. This variance was driven by Dover’s open position, which was 12% 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 $98 thousand greater than budget. Additional factors contributing to the unfavorable variance included i) a $165 thousand unfavorable variance in Basis costs and ii) a $9 thousand unfavorable variance in Transmission Rights Credits. Offsetting these unfavorable variances were a $215 thousand favorable variance in Load Following and a $6 thousand favorable variance in PJM Ancillary charges.  For the month the City realized an $11 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 $57 thousand variance, and the change in price resulted in a favorable $46 thousand variance. Hence, all of the unfavorable variance can be attributed to volume changes.  The Power Supply Management variance is merely an estimate at this point. Generation  Plant O&M reported a favorable variance of $5 thousand compared to the monthly O&M reset Budget of $434 thousand ($361 unfavorable variance compared to the original budget of $428 thousand). Lower than projected materials and supply costs partially created the favorable variance. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights  Dover’s February load was 54,900 MWh, which was 1.3% above the weather normalized load of 54,199 MWh. Hedge volumes accounted for 88% of actual load for the month.  The February All In Unit Energy cost (excluding capacity) of $84.37 per MWh is $0.95 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 Feb-11 Feb-11 Feb-11 City of Dover Load Load Obligation (MWh) 54,199 54,900 (701) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $78.19 $77.30 $0.89 Pass Through $6.20 $6.16 $0.04 Incentive Fees $0.93 $0.91 $0.02 Total - All In Unit Energy Cost $85.32 $84.37 $0.95 Purchased Power Variance Analysis  The actual Dover load of 54,900 MWh was 1.3% above the projected February load of 54,199 MWh.  The All In Unit Energy Cost was $0.95 per MWh lower than budget due to a decreased load following charges and a favorable PJM ancillary charges. Offsetting these positive variances were due an increased open volume purchases, increased energy costs, an unfavorable basis variance 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): 48,320 MWhs @ $73.68/MWh: $3,560,200 Power Balancing; Additional PJM, and Energy Manager Fee3: $2,045,911 Total Cost to Serve Load (54,900 MWhs) $5,606,111 All In $/MWh load cost inclusive of Energy Management Fees: $102.11/MWh 3 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT  During the month, PJM did not dispatch Dover’s units into the market. The budget did not expect any generation for the 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 Feb-11 Feb-11 Feb-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 ($34,028.89) $34,028.89 Generation Capacity Payment Total - Generation Capacity Payment ($905,509) ($905,509) $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 were 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. Due to a low fuel inventory level at McKee Run and Van Sant, Pace procured a quantity of fuel oil sufficient to bring the City of Dover’s inventory into compliance with approved levels. This procurement resulted in three transactions with Hess for a total of 35,500 gallons of no. 2 fuel oil. These purchases were completed in late January, with fuel delivers occurring on February 2011. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of February 28 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch4) McKee Run (#2 Fuel 2,554,105 449,438 3 Oil) Van Sant 258,000 150,852 3 (#2 Fuel Oil) February 2011 Fuel Oil Purchases Date Vendor #2 Oil Price ($/gal) Total Cost gal 26-Jan Hess 14,200 $2.9107 $41,332.47 31-Jan Hess 14,200 $2.9107 $41,332.47 01-Feb Hess 7,100 $2.9107 $20,666.23 Total 35,500 $2.9107 $103,331.17 4 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 February 28, 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 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. 19

Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $51,747 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $7/ton, 3,976 post-CAIR SO2 allowances trading at $4/ton, 52 NOx annual allowances trading at $230/ton, and 52 NOx seasonal allowances trading at $30/ton. SO2 There has been very little movement in SO2 allowance prices as market participants await final rules reforming the markets (see Figure 1 – SO2 Prices since Last Monthly Report). Figure 1 – SO2 Prices since Last Monthly Report SO2 Allowance Prices (Feb / Mar) $10.00 $8.00 $6.00 $4.00 $2.00 $0.00 2009 (pre-CAIR) 2010/2011 (post-CAIR) NOx NOX annual allowance prices have experienced a steep decline over the last month losing nearly 1/3rd of their value (See Figure 2 – NOX annual prices since last monthly report.) The compliance date for units retiring allowances was March 1st which partially explains the drop in allowance prices. Most buyers / compliance entities met their demand on or prior to March 1, causing a post “true-up” fall in market prices. The other factor placing downward pressure on allowance prices is the current scheduled start of the Clean Air Transport Rule (Transport Rule) which, based on the proposed rule, is scheduled to begin in 2012. It is uncertain whether existing NOX annual allowances would be eligible to carry over into the Transport Rule for compliance. NOX seasonal prices ticked up $5/ton trading most recently at $30/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 (Feb / Mar) $340.00 $320.00 $300.00 $280.00 $260.00 $240.00 $220.00 $200.00 Figure 3 – NOX seasonal prices since last monthly report NOX Seasonal Allowance Prices (Feb / Mar) $31.00 $30.00 $29.00 $28.00 $27.00 $26.00 $25.00 $24.00 $23.00 $22.00 SO2 and NOx Outlook The SO2 and NOX markets continue to be defined by regulatory uncertainty. Market participants await the release of the final Transport Rule for guidance. Unfortunately, the release of the final rule may only further confuse the market. The proposed rules would place caps at the state level allowing only limited opportunity to trade allowances across state borders. Interstate trading 21

would be severely limited by strict state caps that only permit incremental variability. If the final rule utilizes a similar approach, there may a push from Congress to step in and draft legislation. Senator Carper (D-Delaware) continues to champion a bill that would keep CAIR in place until 2012, and then tighten emissions caps in later years. RGGI and Federal Carbon Outlook RGGI allowance prices continue to flounder around the statutory floor price of $1.86/ton. RGGI is substantially over supplied and as a result allowances prices have remained extremely low (see Figure 4 – RGGI Allowance Prices). Figure 4 – RGGI Allowance Prices RGGI Prices (Feb / Mar) $1.95 $1.90 $1.85 The conversion potential of RGGI allowances into federal allowance volume in a national carbon market remains the main support for RGGI pricing. However, with major uncertainty surrounding the ultimate ability to pass legislation in the near-term, RGGI allowance prices continue to remain very low. 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 $291,000. 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. 22

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. It appears at this time that attempts to cut EPA’s regulatory funding for GHG programs in the FY 2011 federal budget will be unsuccessful; however there are bills in both the House and Senate to permanently repeal their authority. While President Obama has consistently stated that he will veto any bill negating EPA’s GHG regulatory authority, the attempts add another layer of uncertainty to the future of GHG regulations. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights  During the month of February, there were no restricted work days or lost time accidents. The facility has now gone 137 days without an OSHA recordable accident and 137 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 February.  There was one Near Miss reported for the month. An operator found a small oil leak of approximately one quart around the fuel oil unloading station after oil truck deliveries were completed. The affected area was promptly cleared of the oil-saturated soil which was then made ready for proper disposal.  The Maintenance and IC&E Staff, with assistance from the Operations Teams, completed a total renovation of an office located near the maintenance shop area.  Maintenance and IC&E Staff completed the removal and re-installation of the two air compressors and other air system components.  IC&E Staff completed two work orders for repairs at units 1 and 2 cooling tower.  Brian Hoyt started work on February 14 with NAES Corporation-Dover as a Compliance Specialist.  The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware February 2011 Monthly Report A Warm Welcome to the Newest Addition to the Plant Staff, Brian Hoyt, Compliance Specialist! 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 February, there were no restricted work days or lost time accidents. The facility has now gone 137 days without an OSHA recordable accident and 137 consecutive days without a lost time reportable accident. There was one Near Miss reported for the month. An operator found a small oil leak of approximately one quart around the fuel oil unloading station after oil truck deliveries were completed. It was determined that the oil leaked from the hose the truck driver used. The affected area was promptly cleared of the oil-saturated soil which was then made ready for proper disposal. The existing procedure was updated to reflect additional precautions that need to be taken to ensure this type of incident does not occur again. 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 (February) (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 1 4 Man Hours Worked 4,413 85,919.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 137 Days since last Lost Time Accident 137 Emissions (NOx & SO2) All data thru 2/28/11 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 27

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 CAIR NOx Allowances Summary* NOx Allowances Available NOx Allowance Balance CAIR NOx CAIR NOx (Per Facility, Prior to Sale) Total NOx Allowance Allowances McKee Run Tons Vintage Sold YTD (Yr/Season) Van Sant Emitted McKee Run Van Sant (Yr/Season) (Yr/ (Yr/Season) (Yr/Season) Season) 2009 45/25 75/50 5/3 12/5 - 1/1 0/0 – 0/0 18/0 2010 119**/119** 22##/53# – 0 73/47* 5/3 -46/0 - 3/3 0/0 2011 0 71/48### 5/3 1/0 – 1/0 0/0 - 0/0 70/48### 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 2/28/2011 28

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 2/28/2011 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 –February 2011 Actual Budget Variance Personnel 242,290 249,376 7,086 Materials & Supplies 14,438 18,350 3,912 Administrative Expenses 171,364 160,005 (11,359) Total $428,092 $427,731 ($361) Financial – Fiscal Year to Date Number of Months - 8 Actual Budget Variance Personnel 2,030,223 2,046,516 16,293 Materials & Supplies 195,163 131,870 (63,293) Administrative Expenses 1,650,330 1,399,179 (251,148) Total $3,875,716 $3,580,065 ($298,148) 2.1 Variance analysis: The original budget for February was $427,731. The actual expenses for February were $428,092 for an unfavorable variance of $361 or approximately .08%. The variance was due to the following: PERSONNEL EXPENSES – A favorable variance of $7,086 was due to lower labor burdens and slightly lower labor costs during the month. MATERIALS AND SUPPLIES EXPENSES – A favorable variance of $3,912 was realized due to lower spending in Computer Software, Computer Hardware and Water/Sewer. ADMINISTRATIVE EXPENSES - Higher than budgeted expenses in Electric, Auxiliary Equipment, and Boiler Systems contributed to an unfavorable variance of $11,359. The variance in the YTD Electric account is due to the increased run time in July, which due to plant equipment configuration change (running auxiliaries off the Unit 3 Start-up Transformer) caused a significant increase in the monthly ratcheting demand charge. Boiler Systems incurred an unfavorable variance due to unexpected costs associated with Unit 3 Boiler tube leak repairs. As of February 28, the budget had not been reset by the City of Dover to compensate the plant for the additional operational expenses. The budget is currently forecast to finish this fiscal year at $6,099,467 expensed versus $5,694,315 budgeted thereby realizing a 107.12% expenditure rate. 30

3.0 Operations Unit Operations / Outages / Trips No units were dispatched by PJM for the month of February. Month – February 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 29.448 29.448 142.070 200.965 6.045 207.010 Auxiliaries purchased MWh 29.448 29.448 142.070 200.965 6.045 207.010 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 100.00 100.00 100.00 100.00 100.00 100.00 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 672.000 672.000 672.000 2,016.000 672.000 2,688.000 Hours HW Boiler Gas Usage MMBTU 1,109.160 1,109.160 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 (8 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 13.033 128.966 645.256 787.255 137.044 924.299 Starts # 1 3 44 48 26 74 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 257.314 324.776 5,103.951 5,686.040 33.970 5,720.010 Auxiliaries purchased MWh 249.799 249.799 2,506.606 3,006.203 31.274 3,037.927 Fuel Gas Used MMBTU 2,183.250 15,245.85 452,018.83 469,447.93 53,766.951 523,214.88 0 7 7 7 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 61,146.344 548,315.54 0 8 8 2 Net Heat Rate BTU/KWh 14,841 13,355 11,696 13,297 13,192 13,245 Unit Trips # 1 0 3 4 2 6 Capacity Factor % 0.15 1.15 7.08 5.47 2.04 4.52 Availability Factor % 67.32 77.26 77.15 73.91 100.00 80.43 Commercial % 6.6 0 0.03* 0.85 0 0.66 Unavailability (CU) Planned Outage Hours Hours 1,326.500 1,326.500 1,326.500 3,979.500 0.0 3,979.500 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 579.830 0 6.317 586.15 0 586.15 Reserve Shutdown Hours 3,926.670 4,377.534 3,926.143 12,230.347 5,695.956 17,926.303 Hours HW Boiler Gas Usage MMBTU 4,044.060 4,044.060 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 Note: * depicts a unit that has not completed capacity test for the PJM Winter Capacity Demonstration Period in FY 2010-2011. All units are in the PJM Winter Exemption Program. 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) 442,388 449,438 7,187 7,050 448,556 118,549* 882 Van Sant 113,097 150,852 38,079 37,755 143,099 38,079 7,753 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. Note: * Oil purchases were made in October, 2010 for #2 oil to replenish oil stocks used during testing of Unit 3 during the summer period and in January 2011, 28,739 gallons of oil were purchased due to Unit 3 operational run. One truckload of oil that was part of the January oil purchase was off-loaded in February. A fuel oil purchase was made in February to replace fuel burned at Van Sant in January 2011. Van Sant Lifetime through 2/28/11 Actual Starts Factored Starts Fired Hours Van Sant 1242 2153.65 4109.26 Since HGP - Dec 2004 191 485.95 725.68 Team Report: 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. The operators continue to use the Plant Readiness Program for training and refreshing their plant knowledge on different systems to improve the plant’s reliability. Some of the training involved promotes teamwork with other staff members to work together to find a solution and to promote further discussions on equipment operation. The operators also use the GPi Learning courses to improve their knowledge and skills. The GPI online training which supports our safety, OSHA, and environmental training are being used by the teams to complete their training for the year. Along with the GPI OSHA training the operators review the plant’s safety procedures. 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. 33

4.0 Maintenance During the month of February, plant maintenance staff continued addressing the backlog of work orders. There were work twenty-seven orders issued with forty-four work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report February - 8 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 6 1 4 3 2 24 10 15 19 3 28 10 8 30 4 46 0 6 40 5 10 0 1 9 SW1 0 0 0 0 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 63 6 10 59 Totals 177 27 44 160 Note: PM's are included in the priority totals Notable activities during the month include: 1) Mechanical staff installed elongated bolts in every other bolt opening in three storage tank manway lid covers per the AST Inspection Report submitted by MOTT. The MOTT inspection report had identified the need for emergency tank venting in the event the tank became over pressurized. Normal venting of the tank is through one inch piping on each compartment. 2) The Maintenance and IC&E Staff, with assistance from the Operations Teams, completed a total renovation of an office located near the maintenance shop area. New energy efficient air conditioning, heat, lighting and a new ceiling were installed. Outside walls were insulated and the room was painted. This project was completed in advance of the new Compliance Specialist coming on-board at McKee Run. 3) Maintenance and IC&E Staff completed the removal and re-installation of the two air compressors and other air system components. This project consisted of moving two air compressors, one air dryer and the associated electric from the mezzanine level to the 34

ground floor. The ground floor location provides better air flow and cooling for the air compressors. With the air compressors located on the Mezzanine level, they had limited air flow and were exposed to higher ambient air often resulting in the air compressors running hot. During this project, all three air compressors and dryers were tied together as part of a total system with a means of isolating or using different compressors and dryers during times of heavy operation and to aid in taking the equipment out of service for PM servicing. 4) IC&E staff completed another phase of the Arc Flash Project. New breakers and handles were installed on the 480 volt switch gear and Motor Control Centers (MCCs). The final Arc Flash Analysis report was received from Llewyn with some additional actions items needed to complete the final phase of the project. New Arc Flash stickers will be installed on each breaker, along with new breaker/switching procedures and an updated PPE Policy to cover Arc Flash Protection for plant personnel. 5) IC&E Staff completed two work orders for repairs at units 1 and 2 cooling tower. One new pressure switch was installed on the alarm system and one new pressure alarm switch was installed on valve #1. These deficiencies were found during our annual fire protection testing and inspection. 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. 35

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: Bids have been evaluated and award is planned for March. Units 1 & 2 Life EG1107 Schedule: Scheduled for the Spring Outage 2011. Some of the work Extension 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. Progress: Inspections and other repairs were completed during the Unit 2 Boiler Fall 2010 Outage EG1111 Inspections and Schedule: Miscellaneous work is being wrapped up to complete the Repairs project. Progress: The bid was awarded and expansion joint was delivered in Unit 3 Air Heater EG1112 February 2011. Expansion Joint Schedule: This is scheduled for the Spring Outage 2011. Progress: Work scope documents and parts list put together. Most Units 1 & 2 Controls of the parts have been ordered and are beginning to be received at EG1113 Modifications the plant and some installations have started. Schedule: This is scheduled for the Spring Outage 2011. Progress: Bid meetings were completed in February. The bid has Unit 3 Gas Line been awarded. Some parts have been ordered and have been EG1114 Modifications received. Schedule: This is scheduled for the Spring Outage 2011. 36

5.1 CIP Budget Approved Latest Project Description Budget Estimate Number ($ X 1000) ($ X 1000) EG1101 Unit 3 Cooling Tower Life Extension 398 372 Units 1 & 2 Cooling Tower Life EG1102 173 110 Extension EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 71 77 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 180 225 Unit 1 Forced Outage EG1108 412** 424 Repairs 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 175## 130 EG1112 Unit 3 Air Heater Expansion Joint 65## 65 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. 37

6.0 General Plant Information Training: Each employee has been assigned a Safety Manual and Procedure (SMP) to review, update, and to make sure the policy is being followed. This review allows plant staff to provide input and to suggest changes to correct deficiencies they might find in the SMP. In addition, this provides opportunities for the individual to train to become the topic expert on the particular SMP and to aid in the training of all plant personnel on that SMP as well. 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 Gen-Checkout, Two Settlement, Ancillary Services, and Operating Reserves Settlement. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. This month’s safety topic was “Importance of Sleep”. Other Events: Brian Hoyt started work on February 14 with NAES Corporation-Dover as a Compliance Specialist. 38

Calendar of Events Date Winter Capacity Period December 1, 2010 to February 28, 2011 McKee Run and Van Sant Title V Annual Certification Due February 1, 2011 NOx Emissions Reconciliation Due March 1, 2011 SO2 Emissions Reconciliation Due March 1, 2011 SARA III Report March 1, 2011 Annual Van Sant Black Start Test March 2011 (Exact Date TBD) Unit 11 Spring Outage March 14, 2011 – March 28, 2011 Units 1, 2, and 3 Spring Outage March 28, 2011 – May 23, 3011 Air Emission Inventory April 1, 2011 EIA-923 Report April 15, 2011 EIA-860 Report May 15, 2011 Fiscal Year 2010-2011 Ends June 30, 2011 PJM Summer Capacity Test Period June 1, 2011- August 31, 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 #1 Unit Annual Inspection October , 2011 #2 Unit Annual Inspection October , 2011 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 Yes Yes Yes $20,157 $20,157 Unit 11 No Yes 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 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 ($689,670.39) ($689,670.39) Real-time Energy $0.00 $79,462.27 $79,462.27 Transmission Losses Credits $0.00 $58,202.93 $58,202.93 Network Integration Transmission Service Charges $0.00 ($240,046.52) ($240,046.52) Inadvertent Interchange Charges $0.00 ($2,331.34) ($2,331.34) Regulation Charges $0.00 ($14,807.99) ($14,807.99) Synchronized Reserve Charges $0.00 ($19,443.96) ($19,443.96) Balancing Operating Reserves Charges $0.00 ($7,631.18) ($7,631.18) Day Ahead Operating Reserves Charges $0.00 ($8,180.15) ($8,180.15) Day-ahead Scheduling Reserve $0.00 ($61.07) ($61.07) Synchronous Condensing Charges $0.00 ($131.09) ($131.09) Reactive Services Charges $0.00 ($12,626.78) ($12,626.78) Meter Correction Charges $0.00 $3,197.41 $3,197.41 Day-ahead Operating Reserve for Load Response $0.00 ($0.10) ($0.10) 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 ($975,513.84) ($975,513.84) Capacity Transfer Rights Credits $0.00 $1,576.68 $1,576.68 Capacity Resource Deficiency Credits $0.00 $0.34 $0.34 Demand Response and ILR Compliance Penalty Credits $0.00 $0.00 $0.00 RPM Auction Credits $905,508.80 $0.00 $905,508.80 Auction Revenue Rights Credits $0.00 $28,404.88 $28,404.88 Synchronized Reserve Credits $0.00 $0.00 $0.00 PJM Scheduling System Control and Dispatch Service Charges $0.00 ($10,420.34) ($10,420.34) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($4,187.70) ($4,187.70) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($31,750.59) ($31,750.59) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,209.14) ($1,209.14) North American Electric Reliability Corporation (NERC) Charge $0.00 ($490.33) ($490.33) Reliability First Corporation (RFC) Charges $0.00 ($743.98) ($743.98) Expansion Cost Recovery Charges $0.00 ($408.52) ($408.52) 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 $546.77 $546.77 Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($230.39) ($230.39) 40

Organization of PJM States, Inc. (OPSI) Funding $0.00 ($34.95) ($34.95) FERC Annual Recovery $0.00 ($3,173.18) ($3,173.18) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 $2,478.06 $2,478.06 PPA $0.00 $246.34 $246.34 $939,520.88 ($1,864,239.89) ($924,719.01) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/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 $84.16 $90.46 Apr 52,554 $83.69 $91.16 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