Attachment

UTILITY COMMITTEE AGENDA August 22, 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. Discussion - Informational Presentation by Delaware Electric Cooperative 2. Discussion - Infrastructure Improvements to the Garrison Tract 3. Review of Utility Related Capital Investment Plan (CIP) (Electric and Water/Wastewater) 4. PACE/NAES Monthly Report (May and June) 5. Adjournment by 5:55 P.M. /tm S:\AGENDAS & MINUTES\Committee-Agendas\2011\08-22-2011 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.

Memorandum Interim City Manager P. O. Box 475 City Hall/ The Plaza Dover, Delaware 19903-0475 Phone: (302) 736-7026 Fax: (302) 736-4217 E-mail: skoenig@dover.de.us TO: Utility Committee Members FROM: Scott D. Koenig, P.E. Interim City Manager DATE: August 16, 2011 SUBJECT: Informational Presentation by Delaware Electric Cooperative Attached are the staff responses to the Delaware Electric Cooperative presentation. Additional budgetary information will be discussed at the committee meeting but is not included in this packet. SDK/yml Attachment

WHY DOVER RESIDENTS SHOULD CONTINUE TO OWN THE ELECTRIC SYSTEM Stakeholder Advantages of owning electric system Advantages of selling the system City of Dover Reliability of electric service (the System DEC electric rates are lower; Residents Average Interruption Duration Index is 50% however, with the new of the De. Electric Cooperative, using latest regulations for coal-powered data available). generation this may not be According to DEMEC, Dover has the third true in the future. lowest rate in Delaware. Electric rates are not tax- Owners of the system. deductible. Local governance – local managers/officials Electric supply choice is not a with which to discuss the operation. current option; however, this Owner of the energy from Dover Sun Park. can be implemented with a Currently purchasing blocks of energy 5 simple vote of Council. years in the future to provide rate stability. Because of the transfer of over $11M to the General Fund the tax rates are lower which assists Economic Development activities. Lower taxes and competitive rates draw new businesses to Dover. Electric rates are lowered when the budget carry-forward balances are greater than policy (March of 2011). All Technicians/Lineworkers are based in Dover to respond to emergencies. Current customers can have their electric service installed underground from the service point to the home without charge – this is not normally performed by other utilities. City Leadership/ Economic Development through bundled Increased tax payments would Elected Officials tax/electric rate combination. be deductible. Not able to control future energy costs for Holding the future energy the consumer/ owners. The current policy is portfolio increases financial rate stability – it is unknown what the future risk – conversion to an Open- policy might be through other providers. access system could also At DEC Council would only have two votes reduce this risk. on an eleven member board. Electric rates would not Long-term stable cash transfers are highly subsidize the maintenance of probable. the Street Lights. Availability of reserves should a catastrophic City leadership and elected incident occur. officials must understand the Total control of energy delivery issues and complexities of operating an over local system upgrades. electric system and making The installation of banners, flag pole ropes, informed decisions. city building exterior lighting, snow removal A large one-time infusion of from roofs, holiday signs (for example first cash into the general fund. night pole, peace sign.) and other public There is a liability risk with

WHY DOVER RESIDENTS SHOULD CONTINUE TO OWN THE ELECTRIC SYSTEM service functions would become an open owning an electric system; issue. however, this is somewhat mitigated through State law. Commercial and The current practice of the Utility is to begin Purchasing energy in advance Industrial purchasing energy five years in advance to does not allow customers to Customers provide price stability for all customers. take advantage of dips in the An open access system could be market. implemented for all customers if approved Open access to other energy by the governing body. suppliers. Reliable power delivered as indicated by the low outage indices. Reduced tax obligation due to the transfer of over $11M from electric revenue. Technical support to customers. Assistance is provided to customers that have failures in equipment owned by the customer. City Departments The fiber optic system used for the city General Fund staffing could be building network, two way radio and reduced. downtown cameras is installed, owned, and maintained by the electric department. Future maintenance and installation will need to be supported through public services, including the required vehicles/equipment. Giving the rights to pole ownership to other utilities may result in the City of Dover having to pay for pole attachments for the City cameras and banners. The electric division prioritizes the restoration of critical Water and Waste Water facilities during emergency restoration to assure continued service of these facilities. The Operations Center currently supports Electric, Water, Waste Water, Public Services and Facilities with a 24/7 emergency customer service contact. City enforcement currently uses the threat of cutting electric service for delinquent licensing, permits, trash, etc. – oftentimes gleaning this information through electric billing. Some construction equipment is shared throughout the City departments and the electric department currently provides/ performs heavy lifting equipment for these

WHY DOVER RESIDENTS SHOULD CONTINUE TO OWN THE ELECTRIC SYSTEM divisions. Street light maintenance would become a Public Services function/expense. This would include design and installation. Electric utility provides the storage and shipment of regulated waste for the City, for example florescent light bulbs, lighting ballast, etc. During storms the other City Departments assist in the restoration process, reducing outage time. Utility personnel provide assistance to other department during storm emergencies. DEC is a member of Old Dominion Electric Cooperative (ODEC) and it is through this cooperative that they procure their energy. ODEC currently owns over 400 Mw from a coal fired power plant and is in the process of constructing another plant. While the current unit provides a less expensive source of energy, EPA recently released regulations that may require extensive upgrading to meet the new emission requirements. ODEC also owns over 200 Mw of the North Anna nuclear power plant and again currently provides attractive energy costs but in light of the recent events extensive capital improvements may be required to continue the operation of the plant. Additionally, ODEC is in the process of permitting the Cypress Creek Power Station in Dendron, VA, which currently is envisioned as a 1,500 Mw coal fired power plant. Again, the financial and environmental impact of the project is unknown, but the external regulations could drive these costs up as well. Lastly, Northern Virginia Electric Cooperative recently withdrew its membership from ODEC and stated that they wanted “…the opportunity to directly manage the risks associated with power supply…”

EXCERPT - UTILITY COMMITTEE MEETING MINUTES OF JUNE 27, 2011 Informational Presentation by Delaware Electric Cooperative on the Pros and Cons of Their Purchase of the City of Dover Electric System Mr. Bonar advised members that they would be considering the possibility of an outside entity taking over the operation of the City of Dover Electric Department. He indicated that the Delaware Electric Cooperative (DEC) had expressed interest in pursuing this option. Mr. Bonar introduced Mr. J. William Andrew, President and CEO of DEC. Mr. Andrew stated that he was contacted by Mr. Bonar approximately two (2) weeks ago requesting that the Co-op present information regarding the possibility of DEC purchasing the City of Dover Electric System. He stated that DEC evaluated public information and toured the City of Dover Electric System and determined that it was an excellent system. Mr. Andrew and Mr. Gary D. Cripps, Chief Financial Officer (CFO) of DEC, provided a presentation on the Pros and Cons of DEC Purchasing the City of Dover Electric System (Attachment #1). Mr. Cripps stated that both the City of Dover and DEC have positive attributes and felt that the two (2) organizations would function better together. He indicated that a consolidation of these business enterprises would be fruitful for many years to come. Referring to the Key Benefits, listed on Page 2 of the presentation, Mr. Cripps stated that members of DEC are controlled by a Board of Directors who are elected annually in August and serve three (3) year terms. He noted that Mr. William Wells, Chairman of the Board of Directors, was also present. Mr. Cripps stated that if Council opts to proceed with the proposal, City of Dover utility customers would realize lower utility rates and that the impact would be approximately $25M per year. He advised members that consolidation with the City of Dover would provide rate stability over the long term, particularly as it relates to the market and the effects of economic development in the State of Delaware. Mr. Cripps stated that DEC has a Power Supply Contract, which will expire in 2054, with Old Dominion Electric Cooperative, headquartered in Richmond, Virginia. He explained that Old Dominion Electric Cooperative is asset based and serves 600,000 customers in the aggregate. Mr. Cripps noted the importance of economic development and indicated that DEC’s first priority is to protect current businesses in the City of Dover and Kent and Sussex Counties. He advised members that DEC has 32,000 customers in Kent County and the City of Dover has 23,000 customers. Mr. Cripps stated that if DEC purchases the City of Dover’s Electric system, their customer base would increase to 55,000 in Kent County, which would necessitate the establishment of a DEC facility in Dover. In addition, he stated that there would be a need for two (2) additional districts, as well as two (2) additional members to serve on the DEC Board of Directors. Mr. Cripps stated that one of the key benefits of consolidation would be that City of Dover residents would retain ownership of the utility system. He advised members that DEC is an electric cooperative, a not-for-profit organization, and not an investor-owned utility. Mr. Cripps noted that this proposal is very different in that respect from a previous offer from Delmarva Power and Light, which was entertained by the City in 1993. He emphasized the benefit of retaining membership and ownership of the utility.

Excerpt - Utility Committee Meeting Minutes of June 27, 2011 Page 2 Mr. Cripps stated that the load diversity for DEC is 82% residential and that, long term, this is problematic. He explained that DEC needs additional commercial customers in order to obtain a better balance and more diversity. Mr. Cripps noted that without diversity, rates would increase and future generations would have a difficult time paying their utility bills. He explained that over the past one (1) to (2) decades, commercial expansion has occurred near the metro areas and, as a result, DEC has lost service territory to municipalities, which is the greatest single threat to DEC. He stated that by consolidating the City of Dover and DEC, this threat would be mitigated. Mr. Cripps advised members that DEC is run from a government standpoint, as is the City of Dover’s utility, noting that DEC is administered by an elected Board of Directors and Chairman. If the Co-op acquired the City’s Electric Department, DEC would escalate from 83,000 members to 106,000 members, which would assist with power supply contracts, allow human resource needs to be absorbed, and provide opportunities to take advantage of material discounts that may become available. He noted that in the past, DEC and the City have purchased items jointly, which resulted in significant savings for the City. Mr. Cripps acknowledged that municipalities considering similar options often express concerns about the future, noting that initial rates following acquisition may be favorable but future rates are uncertain. He advised members that DEC is open to competition and does not have a monopoly on their customers. He explained that their customers may choose to obtain electric supply from anyone that sells it in Delaware. Mr. Cripps stated that deregulation has benefitted DEC by forcing the organization to remain “agile” and maintain its competitive position. He advised members that operating a utility involves environmental, legislative, regulatory, and financial risk, and that the City’s risk would be mitigated by consolidation. He indicated that the influence of a commercial mix and density would lower DEC’s average cost and would yield great long-term benefits. Mr. Cripps stated that acquiring the City’s utility would result in a significant financial windfall. He explained that, for DEC customers, one of the big advantages would be economies on infrastructure leverage, i.e., infrastructure capital needs in some areas that can be supported by infrastructure that is already in place. Referring to the Stakeholder Matrix on Page 3, Mr. Cripps explained that when a cooperative makes a margin, the margin is distributed to customers and is not turned into a profit. He noted that for the past two (2) years, DEC’s Board of Directors authorized over $5M to be paid back to customers in the form of checks or as credits on their utility bills. In response to Mr. Bonar, Mr. Cripps stated that if the capital credit exceeds $30 a check is issued to customers, and if it is under $30 a credit is applied to customer utility bills. In regard to the City Leadership/Elected Officials listed on Page 3, Mr. Cripps stated that financing the City government would be accomplished through economic development and not by raising taxes or rates. He explained that an examination of the City’s financial data indicates that approximately $27M is in reserves and stated that a consolidation of the two (2) organizations would not include a transfer of those reserves. Mr. Cripps noted that a potential disadvantage for the City would be the inability to balance its budget through the Electric Fund; however, he noted that DEC has a proposed solution to this concern that would be outlined further during the presentation. He explained that loss of operational control would be another potential disadvantage.

Excerpt - Utility Committee Meeting Minutes of June 27, 2011 Page 3 Mr. Cripps advised members that one (1) potential disadvantage to DEC members is that the acquired area (the City of Dover) may be excluded from access to the U. S. Department of Agriculture (USDA) Rural Utilities Service (RUS) Program, which provides below market funding for electric utilities. Referring to Page 4, Mr. Cripps stated that the commercial loads involved support generation decisions and that, in regard to generation, the City should examine its commercial load and power forecast for the next 5, 10, 15 and 20 years ahead. He noted that consideration of the other 600,000 members that are part of the power supply group can significantly impact those decisions. In reference to the commercial and industrial customers, Mr. Cripps noted that lower rates would impact large accounts such as the Bayhealth Medical Center and Dover Downs Race Track. Regarding energy management services and technical support, Mr. Cripps stated that DEC has a highly qualified staff, including a number of individuals with Masters of Business Administration degrees and approximately five (5) Professional Engineers in the Engineering Department. Referring to the map on Page 5, Mr. Andrew stated that DEC serves 83,000 customers over 1,100 square miles, including the majority of the service territory in Kent and Sussex County. He explained that DEC surrounds the City of Dover and is contiguous in many areas. As a result, he stated that the City and DEC have a shared infrastructure. Mr. Andrew stated that the DEC can provide additional support to the City of Dover infrastructure and indicated that the City of Dover has an excellent electric system which is comparable to Delaware Electric Cooperative’s system. He noted that DEC provides only electric service and the City of Dover, like other municipalities, provides multiple services. Mr. Andrew stated that electric rates are currently high, and commercial and industrial sectors are consistently under pressure for competitive advantages. He noted that the City of Dover has lost more that 295 commercial and industrial customers in the past two (2) years. Mr. Andrew advised members that State and regulatory burdens are increasing and extremely costly to the power industry. Recognizing that cities need additional funds to run their governments, he stated that electric systems require cash and capital to operate. He felt that consolidating the City’s electric system with DEC would “free up” resources the City could devote to other utilities without raising rates or increasing taxes. Referring to Page 6 of the presentation, Mr. Andrew stated that DEC rates are approximately 36% lower than the average rates in Delaware and that they have been able to maintain that for several years. He also noted that their rates were reduced during the last few years. Mr. Andrew indicated that the State of Delaware has passed possibly the most stringent renewable portfolio standards in the country; however, the fact that prices are already high raises concerns that the State will have challenges attracting and retaining businesses that rely on competitive electric prices. Mr. Andrew noted that DEC has perhaps the largest percentage of renewable portfolio in the State of Delaware, including 253 MW of wind that is producing energy daily. In addition he stated that DEC has a significant amount of landfill gas biomass and some hydro power. Mr. Andrew advised members that DEC is currently working on major solar facilities and hopes to operate these within the next two (2) years.

Excerpt - Utility Committee Meeting Minutes of June 27, 2011 Page 4 Referring to Page 7 of the presentation, Mr. Cripps stated that according to the City of Dover balance sheet, the net asset value of the City of Dover plant is $80M - $90M; however, he noted that typically municipal accounting capitalizes property at a low rate, and this is something that DEC recognizes. Mr. Cripps stated that the City of Dover and DEC would need to structure how the transfer would occur and how payments could be made that would equal the revenue stream that the City has been accustomed to over the years. He explained that rates for City customers would convert immediately to Cooperative rates. Mr. Cripps advised members that DEC would open a Kent County Operations Center in Dover and would possibly lease facilities in use by the City of Dover. He indicated that qualified City electric department employees would be needed by DEC, and it is hoped that the consolidation would have no impact on human resources. In addition, he stated that the City would gain the Cooperative as a substantial taxpayer. Referring to Page 8, Mr. Andrew stated that the rate differential per year is $25M as of 2010 and is based on the latest information from the City of Dover that is publicly available. He indicated that the future value, based on the net present value over a 15-year period is more than $200M to rate payers and more than $300M over a 30-year period. In regard to economic development, Mr. Andrew advised members that energy is the second largest cost to businesses and stated that DEC can preclude that by making the City of Dover one of the lowest priced incorporated areas in the region. Regarding long-term competitive power supply, Mr. Andrew stated that Old Dominion Electric Cooperative is consistently seeking new energy-producing and capacity-producing businesses. In conclusion, Mr. Andrew advised members that a consolidated enterprise would be a benefit to everyone and that rates would not rise due to consolidation. He noted that rate increases will occur; however, mitigating and retaining competitiveness will assist in maintaining and bringing employment to the City of Dover. Mr. Andrew felt the net value of $93M is understated and that DEC can structure several financial instruments and provide a net payment or a combination of payment and an annuity. He stated that if there is a need to meet the outlay of capital that is currently obtained each year from the power plant, this can be accomplished. It was his recommendation that members authorize an in-depth analysis and business case with an independent third-party market specialist. Mr. Andrew noted that DEC reviewed public information over a two (2) week period and that more detailed information will need to be reviewed. He indicated that DEC is a transparent organization and that they are willing to review the information together with the City. Mr. Andrew advised members that it is costing the rate payers of the City of Dover $68,000 per day for each day that the City does not move forward. In response to Mr. Snaman’s question regarding DEC taking over current City of Dover purchase contracts, Mr. Andrew stated that this is an issue that would take further research. He noted that if DEC purchase contracts run for several years and are out of market, this would be an obstacle that must be evaluated. Responding to Mr. Snaman, Mr. Andrew stated that Delaware Electric Cooperative is a member of PJM.

Excerpt - Utility Committee Meeting Minutes of June 27, 2011 Page 5 In response to Mr. Blakeman’s question regarding the transfer of longevity and benefits for current City of Dover employees, Mr. Andrew stated that there are several legal matters involved and that this is an issue that the City of Dover and DEC would need to resolve. He noted that these details would be included in a contract. Mr. Cripps noted that DEC employees are also organized under the IBEW union. He reiterated that DEC would be interested in having all qualified electric department employees join their team. Responding to Mr. Hutchison’s question as to whether the City could charge an excise tax if DEC were to make the purchase, Mr. Cripps stated that this matter would have to be determined by the solicitor. Mr. Cripps noted that the idea has been discussed and that he had not heard anyone dispute the possibility. Mr. Leary stated that he came to the meeting with a good deal of scepticism which has increased since the presentation. He explained that DEC has listed the short-term benefits of purchasing the City of Dover’s electric system but not the long-term benefits. Noting the importance of the City’s current ability to utilize revenue generated by the electric utility, he indicated that a great deal of additional study would be required before he would agree with such a proposal. Responding, Mr. Andrew noted that the City would have access to an asset-owned facility that has a record of being very reliable and is a low-cost provider in the State of Delaware. He explained that he would welcome an opportunity to discuss additional questions that members may have regarding the long-term benefits. In response to Mr. Anderson’s question regarding how DEC will work with residents who require additional time to pay their utility bills, Mr. Cripps stated that DEC has policies and procedures in place for residents who are not able to pay their utility bills at the time they are due. He explained that the Board donated $250,000 last year to assist customers with their bills and works closely with the Salvation Army and Catholic Social Services. He noted that DEC has a lot of flexibility in setting up payments and provides opportunities for customers to meet their utility obligations. Responding to Mr. Anderson, Mr. Andrew stated that the outage rates, at worst, should stay the same. He explained that DEC would have an operations center located in Dover and would utilize current City of Dover employees. Mr. Andrew noted that the increased infrastructure and technological efforts and capabilities should assist in this area and that supplying power to the City will not involve some of the challenges of rural areas, although tree trimming would be an important priority. Responding to Mr. Bonar, Mr. Andrew felt that if the City decides to study the transfer of their electric system further and hire a third party consultant, DEC would be willing to support the cost, especially if a transfer of ownership would take place; however, he wanted to ensure that the City is focused on moving forward. Mr. Andrew stated that DEC is willing to provide a price on a Request For Proposal (RFP) basis that is equal and fair or to discuss such a proposal on an exclusive basis. Mr. Bonar relayed his appreciation to DEC and to employees in attendance from the City of Dover.

Excerpt - Utility Committee Meeting Minutes of June 27, 2011 Page 6 He advised members that if the City decides to move forward with the transfer of the electric system, he would insist that employees retain their benefits and longevity. Mr. Bonar noted that employees were promised these benefits when they were hired and felt that it was important to retain them. He explained that this a challenging and difficult decision that will require a great deal of study before Council makes a determination. The Committee took no action.

Memorandum Interim City Manager P. O. Box 475 City Hall/ The Plaza Dover, Delaware 19903-0475 Phone: (302) 736-7026 Fax: (302) 736-4217 E-mail: skoenig@dover.de.us TO: Utility Committee Members FROM: Scott D. Koenig, P.E. Interim City Manager DATE: August 12, 2011 SUBJECT: Infrastructure Improvements – Garrison Tract On Wednesday, August 3, 2011, senior city staff (Scott Koenig, Bill Neaton, Ann Marie Townshend, & Ron Lunt) met with representatives of the Calpine Corporation to discuss the potential construction of new power generation facility to be located on the Garrison Oak Tract. Attached is a summary status of the proposed project. SDK/sdk Attachment

Champe Fisher, Vice President 500 Delaware Avenue, Suite 600 Wilmington, DE 19801 302-468-5325 302-468-5401 F August 15, 2011 Mr. Scott Koenig, Interim City Manager City of Dover 15 E. Loockerman Street Dover, DE 19903 Subject: Garrison Energy Center Infrastructure Update Dear Mr. Koenig, Per your request below is an infrastructure update on the Garrison Energy Center development project (“GEC”): 1. GEC is anticipated to be a nominal 618 MW power generation facility which is planned to be built in two phases. (Each nominally rated at 309 MW). Targeted commercial operation date for the first phase is June 1, 2015; 2. Updated permitting for GEC is underway as the project is being enhanced to employ a more energy efficient technology; 3. Calpine is presently in negotiations with Eastern Shore Natural Gas to bring natural gas to GEC and the Garrison Oak Technical Park via a new gas pipeline – presently anticipated to be a 6 mile 16” lateral pipeline; 4. GEC’s electric interconnection process with PJM has been delayed by over three (3) months. Calpine expects to receive GEC’s System Impact Study from PJM at the end of September 5, 2011; and 5. Calpine is working with Becker Morgan to integrate GEC’s infrastructure requirements with those of the Garrison Oak Technical Park. GEC will keep you updated as to further developments. Please do not hesitate to contact me with any questions. Sincerely, Champe Fisher Vice President cc: William Neaton, City of Dover Economic Development Manager Ronald Lunt, City of Dover, Public Utilities Director, Public Utilities Department

City of Dover Capital Investment Plan Project Tracking Report June 30, 2011 *** Preliminary *** Points to Remember - * Original Project Budget = Original Total Project Budget initially included in approved annual budget. * Latest Project Budget = Revised Total Project Budget included in most recent approved annual budget or one of the following: bond resolution, revolving fund loan agreement, Council approved budget amendment, or City Manager approved amendment as per the Budget Amendment Procedure. * Current Fiscal Year - Revised Fiscal Year Budget = Current Year approved project budgets plus carry forward balances of unspent budgets in the prior fiscal year. Project Carry Forward balances will be submitted to City Council for amendment in January 2010. Can also be amended with City Manager approval per the Budget Amendment Procedure. * Water Quality, Inflow/Infiltration, Distribution Upgrades and New Development projects are budgeted as a blanket project and once individual projects are identified and estimated they are created using an allocation of the overall budgeted amount. * Status and Comments provided by City Manager. * For Finance purposes projects are considered completed when placed in service and all charges have been processed. Community Water & Total Current Year Budget Funding Sources General Transportation Wastewater Electric CIP Budget Balance $ 113,156 $ - $ - $ - $ 113,156 Project Carry Forward Balances 88,083 - 953,238 850,736 1,892,057 Federal and/or State Grants 4,270,348 1,000,000 28,877 242,523 5,541,748 New Revolving Fund Loans - - 863,060 - 863,060 Carry Forward Construction Loan Balances - - 6,201,973 254,757 6,456,730 Bond Proceeds - - - 415,585 415,585 Impact Fees - - 758,821 - 758,821 Income from Sale of Assets - - - - - Parkland Reserve 36,872 - - - 36,872 Library Reserve & Contributions 3,363,732 - - 3,363,732 Transfer from Operating Funds 924,884 325,000 58,709 2,797,792 4,106,385 Interest Earned 10,900 - - 40,700 51,600 Total Funding Sources (Unaudited) $ 8,807,975 $ 1,325,000 $ 8,864,678 $ 4,602,093 $ 23,599,746 Page 1 of 5

City of Dover General Fund - Major CIP Projects June, 2011 *** Preliminary *** 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 $ 3,545,763 $ 21,134,171 14.4% $ 6,687,039 $ 7,630,663 $ 2,808,697 36.8% Started Bid Pack B - Construction Started. 3 Totals - FY09 $ 18,200,000 $ 24,679,934 $ 3,545,763 $ 21,134,171 14.4% $ 6,687,039 $ 7,630,663 $ 2,808,697 36.8% 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 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 $ 620,179 $ 115,006 84.4% $ 735,185 $ 640,440 $ 620,179 96.8% Complete Core Law Enforcement 11 PD1001 Server Replacement - 53,500 52,488 1,012 98.1% - 53,500 52,488 98.1% Complete Public Assembly Room 12 PD1101 Upgrade - 20,000 20,000 - 100.0% - 20,000 20,000 100.0% Complete Playground Improv 13 PR1101 Program - 15,000 12,952 2,048 86.3% 15,000 15,000 12,952 86.3% Complete 14 PR1102 Skate Park - 30,000 - 30,000 0.0% 30,000 30,000 - 0.0% Deferred 15 ST1101 Transfer to CT Fund 300,000 300,000 300,000 - 0.0% 300,000 300,000 300,000 100.0% Complete 16 ST1102 Concrete Program 50,000 50,000 50,123 (123) 100.2% 50,000 50,000 50,123 100.2% Complete Downtown Security 17 MR1101 Cameras 31,500 31,500 31,500 - 100.0% 31,500 31,500 31,500 100.0% Complete 18 Totals - FY11 $ 445,175 $ 1,235,185 $ 1,087,242 $ 147,943 88.0% $ 1,161,685 $ 1,140,440 $ 1,087,242 95.3% 19 20 Grand Totals $ 18,695,175 $ 25,955,119 $ 4,661,633 $ 21,293,486 18.0% $ 7,848,724 $ 8,807,975 $ 3,921,439 44.5% 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. G = Grant funded project Page 2 of 5

City of Dover Community Transportation & General Fund Street Funds - Major CIP Projects June, 2011 *** Preliminary *** 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 $ 492,970 $ (13,822) 102.9% $ 121,891 $ 121,891 $ 135,713 111.3% Started Ongoing. 3 Totals $ 400,000 $ 479,148 $ 492,970 $ (13,822) 102.9% $ 121,891 $ 121,891 $ 135,713 111.3% 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 10 Schutte Parking Lot $ 21,950 $ 21,950 $ - $ 21,950 0.0% $ 21,950 $ 21,950 - 0.0% Deferred 11 C Turnberry Drive 40,000 74,719 74,719 - 100.0% 40,000 74,719 74,719 100.0% Complete 12 Totals $ 61,950 $ 96,669 $ 74,719 $ 21,950 77.3% $ 61,950 $ 96,669 $ 74,719 77.3% 13 14 FY 2011 15 CT1051 C Washington Street $ 104,000 $ 154,540 $ 154,540 $ - 100.0% $ 104,000 $ 154,540 $ 154,540 100.0% Complete Mitschner Road (incl. CDBG and CDBG-R covered 16 CT1108 CDBG) 169,066 272,779 246,672 26,107 90.4% 272,779 304,026 246,672 81.1% Complete $134,961 of expense 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 10,546 1,329 88.8% 11,875 11,875 10,546 88.8% Complete 19 CT1142 Governor's Ave. Rebuild 1,000 1,000 561 439 56.1% 1,000 1,000 561 56.1% Complete 20 CT1161 Towne Point 7,500 7,500 7,400 100 98.7% 7,500 7,500 7,400 98.7% Complete 21 CT1162 Library Access Rd. 105,000 105,000 120,000 (15,000) 114.3% 105,000 120,000 120,000 100.0% Complete Voshell's Cove Sign CT1188 Repair - 2,859 2,859 - 100.0% - 2,859 2,859 100.0% Complete 22 ST1101 Street & Alley Program 300,000 239,741 94,012 145,729 300,000 239,741 - Hiawatha Lane 35,955 Complete Susan Place 31,246 Complete Delaware Ave Alley 3,834 Complete Reed Street 22,977 Complete Balance not used rolls to next Total Street & Alley Prog 300,000 239,741 94,012 145,729 39.2% 300,000 239,741 94,012 39.2% Fiscal Year State Agreements not yet Agreements have not been 23 applied for or received 458,968 346,468 - 346,468 0.0% 196,508 193,649 - 0.0% received. 24 Totals $ 1,163,659 $ 1,148,012 $ 642,840 $ 505,172 56.0% $ 1,004,912 $ 1,041,440 $ 642,840 64.0% 25 26 Grand Totals $ 1,690,609 $ 1,788,829 $ 1,210,529 $ 578,300 67.7% $ 1,253,753 $ 1,325,000 $ 853,272 68.1% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is rebudgeted to start over each fiscal year. Page 3 of 5

City of Dover Water/Wastewater Improvement & Extension Fund - Major CIP Projects June, 2011 *** Preliminary *** 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 S. Gov. Ave. Water Main Done. Awaiting Invoices from the 2 WD0807 Upgrade $ 200,000 $ 200,000 $ 2,664 $ 197,336 1.3% $ - $ 197,336 $ - 0.0% Complete State Selecting Tank Model & Site; FY13 3 WD0804 M 1.0 MG Elevated Water Storage 4,196,600 2,590,000 21,084 2,568,916 0.8% - 193,377 14,461 7.5% Started = Constr. 4 WD0805 M Piney Point Well 398,800 665,000 67,682 597,318 10.2% - 162,525 15,207 9.4% Started DNREC permiting; FY11 = Constr. Done. Awaiting Invoices from the 5 WW0809 M S. Governors Ave. Sewer Main 300,000 291,000 13,561 277,439 4.7% - 279,244 1,805 0.6% Complete State US 13 East Sanitary Sewer 6 WW0810 M/SL Interceptor 2,376,800 3,409,641 2,943,812 465,829 86.3% - 2,313,958 2,075,651 89.7% Complete 7 Totals - FY08 $ 7,472,200 $ 7,155,641 $ 3,048,803 $ 4,106,838 42.6% $ - $ 3,146,440 $ 2,107,124 67.0% 8 9 FY2009 10 WQ0905 M/SL Bayard Avenue $ 590,910 $ 490,910 $ 286,790 $ 204,120 58.4% $ - $ 484,420 $ 280,300 57.9% Started Started construction in March. 11 WQ0906 M/SL East side N. State Street 868,707 178,611 177,178 1,433 99.2% - 148,715 148,175 99.6% Complete Phase one complete. 12 WQ0907 M/SL Route 13 Water Main 1,058,700 2,226,783 396,732 1,830,051 17.8% - 2,158,686 272,736 12.6% Started Going to bid. Start in May. 13 R Water Quality Improve FY09 $ 2,518,317 $ 2,896,304 $ 860,701 $ 2,035,603 29.7% $ - $ 2,791,821 $ 701,212 170.1% Started 14 DE State University Pumping 15 WW0902 M/SL Station $ 386,400 $ 386,400 $ 321,267 $ 65,133 83.1% - 240,324 175,552 73.0% Complete Fox Hall/Retreat Force Main 16 WW0905 M/SL Rerouting 133,100 139,245 238,789 (99,544) 171.5% - 20,351 20,351 100.0% Complete 17 WW0907 M/SL Acorn Lane P/S Replace. 386,400 386,400 321,908 64,492 83.3% - 210,528 146,397 69.5% Complete 18 Totals - FY09 $ 3,424,217 $ 3,808,349 $ 1,742,665 $ 2,065,684 45.8% $ - $ 3,263,024 $ 1,043,512 32.0% 19 20 FY2010 21 WD1002 R Remote Control & Monitor Wells $ 55,000 $ 55,000 $ 55,000 $ (0) 100.0% $ - $ 31,896 $ 31,896 100.0% Complete 22 WW1001 M/SL Inflow/Infiltration Removal 1,800,000 - 924,200 (924,200) 0.0% - - 922,979 0.0% Started Budget in FY 12; Started in May 23 WW1007 M/SL Fox Hall Pump Station 427,900 392,044 50,213 341,831 12.8% 375,900 409,044 48,357 11.8% Started Out to bid. Heatherfield Force Main 24 WW1008 M/SL Rerouting 220,400 324,916 48,695 276,221 15.0% 229,200 284,916 47,411 16.6% Started Out to bid. 25 WW1010 I Tar Ditch Interceptor Upgrade 518,230 518,230 22,871 495,359 4.4% - 516,781 21,422 4.1% Started Reviewing design. 26 WS1001 Various Pump Motor Replace 45,248 28,877 28,877 - 100.0% - 28,877 28,877 100.0% Complete 27 Totals - FY10 $ 3,066,778 $ 1,319,067 $ 1,129,855 $ 189,212 85.7% $ 605,100 $ 1,271,514 $ 1,100,941 86.6% 28 29 FY2011 30 WD1101 Misc. Disb. System Upgrade $ 60,000 $ 38,100 $ 10,045 $ 28,055 26.4% $ 60,000 $ 38,100 $ 10,045 26.4% Complete 31 WD1102 Wellhead Redevelopment 60,000 60,000 59,336.00 664 98.9% 60,000 60,000 59,336 98.9% Complete 32 WQ1101 WQI - Loockerman Street 500,000 110,000 104,626 5,374 95.1% 500,000 110,000 104,626 95.1% Complete 33 WQ1102 WQI - Columbia Avenue - 5,000 4,250.00 750 85.0% - 5,000 4,250 85.0% Complete Construction in FY12. 34 WQ1103 WQI - Ross Street - 5,000 4,250.00 750 85.0% - 5,000 4,250 85.0% Complete Construction in FY12. 35 WQ1104 WQI - William Street - 5,000 4,250.00 750 85.0% - 5,000 4,250 85.0% Complete Construction in FY12. 36 WQ1105 WQI - West Street (W. Alley) - 5,000 4,250.00 750 85.0% - 5,000 4,250 85.0% Complete Construction in FY12. 37 WW1101 M/SL Inflow/Infiltration Removal 500,000 500,000 32,366.88 467,633 6.5% 500,000 500,000 32,367 6.5% Started Will complete after FY10 is done. 38 WW1102 R Scada Tech. Equip. Upgrade 82,100 82,100 76,264 5,836 92.9% 82,100 82,100 76,264 92.9% Started 4 of 7 installed. Del State/Del Tech Force Main Shifted completion to interceptor 39 WW1103 Rerouting 286,500 286,500 - 286,500 0.0% 286,500 286,500 - 0.0% Done (WW0810). 40 WW1104 SL Lepore Road P/S Replacement 52,000 52,000 55,536 (3,536) 106.8% 52,000 52,000 55,536 106.8% Complete 41 WW1105 R Misc. Sewer System Improve 35,000 35,000 35,152 (152) 100.4% 35,000 35,000 35,152 100.4% Complete 42 Totals - FY11 $ 1,575,600 $ 1,183,700 $ 390,326 $ 793,374 33.0% $ 1,575,600 $ 1,183,700 $ 390,326 33.0% 43 44 Grand Totals $ 15,538,795 $ 13,466,757 $ 6,311,649 $ 7,155,108 46.9% $ 2,180,700 $ 8,864,678 $ 4,641,903 52.4% 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 June, 2011 *** Preliminary *** TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project % Current Revised Fiscal % Project Project Project To Date Budget Budget Fiscal Yr. Fiscal Yr. YTD Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments 1 FY 2006 2 EE0601 M/B 69 KV feeders 3 and 4 $ 11,060,000 $ 8,693,782 $ 8,761,762 $ (67,980) 100.8% $ - $ 4,242 $ 4,242 100.0% Complete 3 EE0603 M/S Governor's Avenue Rebuild 1,268,450 2,068,260 552,362 1,515,898 26.7% - 250,000 31,901 12.8% Complete 4 Totals - FY06 $ 12,328,450 $ 10,762,042 $ 9,314,123 $ 1,447,919 86.5% $ - $ 254,242 $ 36,143 14.2% 5 6 FY 2008 7 EG0801 Unit 3 Turb Bearing Fire Protect De $ 50,000 $ 50,000 $ 44,720 $ 5,280 89.4% $ - $ 50,000 $ 44,720 89.4% Complete 8 Totals - FY08 $ 50,000 $ 50,000 $ 44,720 $ 5,280 89.4% $ - $ 50,000 $ 44,720 89.4% 9 10 FY2010 11 EG1001 B Vansant CT Mark IV Control $ 700,000 $ 610,000 $ 438,687 $ 171,313 71.9% - $ 152,050 $ 152,050 100.0% Complete 12 EG1002 B McKee Run Entrance Road 240,000 240,000 156,878 83,122 65.4% - 154,244 156,399 101.4% Complete 13 EG1005 Work Mgmt. System Replace 85,000 85,000 26,577 58,423 31.3% - - 9,859 0.0% Complete 14 EG1009 Photovoltaic Install @ McKee - 65,065 65,065 - 100.0% - 65,065 65,065 100.0% Complete 15 EE1005 M/B Mid City Substation 1,488,461 993,711 975,819 17,892 98.2% - 1,087 1,087 100.0% Complete 16 EE1009 S LED Lighting Replacement 70,087 86,457 86,456 1 100.0% - 86,457 86,456 100.0% Complete 17 EU1002 B Crossgates 396,904 543,075 524,391 18,684 96.6% - 1,441 1,440 100.0% Complete 18 EU1003 B Buchanan Acres 406,000 1,094,646 1,207,967 (113,321) 110.4% - 129,502 129,502 100.0% Complete 19 20 Totals - FY10 $ 3,386,452 $ 3,717,954 $ 3,481,840 $ 236,114 93.6% $ - $ 589,846 $ 601,859 102.0% 21 22 FY2011 23 --- Vehicles & Equipment $ 158,200 $ 158,200 $ 113,437 $ 44,763 71.7% $ 158,200 $ 158,200 $ 113,437 71.7% Complete 24 EE1101 Substation PT & CT Replace 256,218 256,218 216,932 39,286 84.7% 256,218 256,218 216,932 84.7% Complete 25 EE1102 Replace of 69 kV Breakers 100,000 100,000 98,292 1,708 98.3% 100,000 100,000 98,292 98.3% Complete 26 EE1103 Lighting Rehabilitation 100,000 107,645 107,644 1 100.0% 100,000 107,645 107,644 100.0% complete 27 EE1104 Walker Road OH Conversion 350,511 - - - 0.0% 350,511 - - 0.0% Deferred 28 EE1105 Engineering Misc. Equip. Replace 40,000 40,000 31,467 8,533 78.7% 40,000 40,000 31,467 78.7% Complete 29 EE1106 Substation Batteries 24,500 24,500 23,489 1,011 95.9% 24,500 24,500 23,489 95.9% Complete 30 EE1107 Wyoming Mill Road Realignment - 91,000 47,877 43,123 0.0% - 91,000 47,877 52.6% Complete 31 EE1111 UG Transformers 120,536 120,536 109,268 11,268 90.7% 120,536 120,536 109,268 90.7% Complete 32 EE1111 UG Conductors 529,464 521,820 494,950 26,870 94.9% 529,464 521,820 494,950 94.9% Complete 33 EE1111 Meters 50,000 50,000 52,151 (2,151) 104.3% 50,000 50,000 52,151 104.3% Complete 34 EE1112 69kV Sub Switch Replacement - 180,000 144,593 35,407 80.3% - 180,000 144,593 80.3% Complete 35 EG1101 Unit 3 Cooling Tower Fill 353,338 383,338 371,513 11,825 96.9% 353,338 383,338 371,513 96.9% Complete 36 EG1102 Units 1 & 2 Cooling Tower 218,730 173,730 134,138 39,592 77.2% 218,730 173,730 134,138 77.2% Complete 37 EG1103 Unit 3 Turbine Inspection 348,000 - - - 0.0% 348,000 - - 0.0% Deferred Construction in FY12. 38 EG1104 Unit 3 Aux System Components 113,000 - - - 0.0% 113,000 - - 0.0% Deferred Deferred 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% Complete 40 EG1106 Unit 3 Stack Repairs 25,000 - - - 0.0% 25,000 - - 0.0% Deferred Deferred to FY12. 41 EG1107 Units 1 & 2 Life Extension 276,000 225,000 212,669 12,331 94.5% 276,000 225,000 212,669 94.5% Complete 42 EG1108 Unit 1 Turbine Outage - 412,000 424,747 (12,747) 103.1% - 412,000 424,747 103.1% Complete Emergency repair 43 EG1109 Unit 3 FD & ID FAN CNRL UP 45,000 - - - 0.0% 45,000 - - 0.0% Deferred Next fiscal year. 44 EG1110 Unit 3 DCS Com & Software 30,000 - - - 0.0% 30,000 - - 0.0% Deferred Next fiscal year. 45 EG1111 Unit 2 Boiler Inspection & Repair - 124,000 111,523 12,477 89.9% - 124,000 111,523 89.9% Started Emergency repair. 46 EG1112 Unit 3 Heat Expansion Joint - 65,000 67,193 (2,193) 103.4% - 80,000 67,193 84.0% Started Started with spring outage. 47 EG1113 Units 1 & 2 Control Modifications - 150,000 124,300 25,700 82.9% - 150,000 124,300 82.9% Started Started with spring outage. 48 EG1114 Unit 3 Gas Line Modification - 60,000 23,794 36,207 39.7% - 60,000 23,794 39.7% Started Started with spring outage. 49 EU1101 Distribution Upgrades 400,000 373,018 368,709 4,309 98.8% 400,000 373,018 368,709 98.8% Complete 50 $ 3,609,497 $ 3,693,005 $ 3,344,739 $ 348,266 90.6% $ 3,609,497 $ 3,708,005 $ 3,344,739 90.2% 51 52 Grand Totals $ 19,374,399 $ 18,223,001 $ 16,185,422 $ 2,037,579 88.8% $ 3,609,497 $ 4,602,093 $ 4,027,460 87.5% 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. 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 May Monthly Report Energy and Operations Management June 23, 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 May, 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 May was 62,114 MWhs, versus a weather normalized projected load of 58,744 MWhs. Hedged transactions accounted for 51,360 MWhs or 83% of this volume (87% of forecasted load) at a cost of $3.56 million. Spot Market purchases resulted in a PJM charge of $639 thousand (a $662 thousand charge in the Day Ahead market and a $23 thousand credit in the Real Time market). Other PJM related charges accounted for an additional cost of $1.53 million, inclusive of all load related fees. The May Energy Only Unit Cost, excluding capacity obligations and credits, was $2.16/MWh favorable compared to the budgeted value of $80.01/MWh. On January 24, 2011, the City of Dover reviewed and approved Pace’s and NAES’ submittal of a revised budget for Dover’s FY2010-11 (the “Reset Budget”). The purpose of this Reset Budget was to provide a mid-year update as to the anticipated cost-of-service for FY2010-11. Dover’s projected all in Cost of Service for FY2010-11 is $89.87/MWh, or $0.58/MWh favorable as compared to the Reset Budget1. Generation and Asset Management Net generation for the month of May credited by PJM was 1,218 MWhs and the budget did not expect any generation. On May 31 both McKee Unit 3 and Van Sant Unit 11 were dispatched by PJM. In aggregate, Dover’s units were dispatched for 22 hours during the month, creating a generation production margin of $71 thousand (after fuel costs). The McKee units completed its spring outage on May 23 which started on March 28. On May 16, McKee units performed operational testing under natural gas and fuel oil to verify working status of controls modification made to the burner management system. 1 The projected all in Cost of Service is based on YTD actual results for 11 months and 1 month of projected costs. The Reset Budget was reviewed and approved by City of Dover. 2

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 purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through May 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 N/A 2003-2006 139 Carryover 9/29/09 SO2 Sales (1,500) 11/12/09 NOX Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (2) (4) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 52 72 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $0.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 3

(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 $36,848.75 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $3.75/ton, 3976 post-CAIR SO2 allowances trading at $2.50/ton, 72 NOx annual allowances trading at $195/ton, and 52 NOx seasonal allowances trading at $17.50/ton. EMISSIONS & ALLOWANCE SUMMARY Through May 31, 2011 Allowance Allowance Emissions Emissions Allowances Allowances Allowance Vintage Allocation Month Sold Month Sold Balance SO2 – 2007-10 10,157 N/A 131 N/A 4,847 5,179 SO2 – 2011 1,988 0 2 0 0 1,986 2 NOx Annu – 2009 80 0 13 0 45 22 NOx Seas – 2009 53 0 6 0 25 22 NOx Annu – 2010 78 0 122 0 (22) (22) NOx Seas – 2010 50 0 122 0 (53) (19) NOx Annu – 2011 76 1 4 0 0 72 3 NOx Seas – 2011 51 2 2 0 0 49 Operations Management Summary During the month of May, there were no reportable or lost time accidents or injuries. The facility has now gone 229 days without an OSHA recordable accident and 229 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were three near miss events and three environmental deviations. Unit 3 was dispatched once and Unit 11 was dispatched twice with one of these dispatches later canceled. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of May were $445,311. The expenses were $17,203 or 4.02% over the approved budget of $428,108. The principal reason for the negative variance is due to higher than budgeted expenses in electric and combustion turbine maintenance which were partially offset by lower costs in personnel expenses and materials. 2 Approximately 10 tons of NOx emissions resulted from the February 2010 McKee Run testing associated with the Pollution Remediation project and the June 2010 emission testing project. 3 The EPA reallocated 2 additional seasonal NOx allowances into the McKee Run 2011 account. 4

Risk Management Summary Forward PJM power prices were mixed since the last reporting period. Prices increased as above average temperatures were seen across much of the country, pushing the nearer term of the forward curve higher while the further out portion fell slightly. Forward Dover Zone power prices for FY 2011-2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all changed by approximately -$0.91/MWh to $0.90/MWh (representing a range of a -1.50% decrease and a 1.71% 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 6/16/2011 Budget June May Apr 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 $85.86 88% -3.7% $85.93 $85.83 2011-2012 N/A $79.66 85% -7.2% $79.47 $79.53 2012-2013 N/A $72.93 76% -8.4% $72.91 $73.02 2013-2014 N/A $71.60 48% -1.8% $71.87 $71.96 2014-2015 N/A $71.05 22% -0.8% $71.80 $71.75 1 Note that the "Cost-of-Service" column does not reflect the SREC benefit the City will receive since the SREC prices are currently unknown *Difference in COS from asset management due to generation & O&M **Not inclusive of budget update 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance May-11 May-11 May-11 Load Forecast 58,744 62,114 (3,370) Power Supply Power Supply $3,608,499 $3,560,754 $47,745 Power Supply Management $188,947 $186,272 $2,674 Capacity Charges - Load $1,078,286 $1,078,284 $3 PJM Charges - Load $902,621 $1,088,697 ($186,077) Total - Power Supply $5,778,353 $5,914,007 ($135,654) Generation Plant Operations $428,108 $445,311 ($17,203) Generation Fuel $0 $89,542 ($89,542) Capacity Credits ($1,002,527) ($1,002,528) $0 PJM Credits ($34,012) ($194,319) $160,307 Total - Generation ($608,431) ($661,994) $53,562 Emission Allowance Sales Total - Emission Allowance Sales $0 $0 $0 Total Power Supply & Generation $5,169,922 $5,252,014 ($82,092) Total Power Supply, Generation & Emission Sales $5,169,922 $5,252,014 ($82,092) Unit Costs Total – Power Supply $98.36 $95.21 $3.15 Total - Generation + Emission Sales ($10.36) ($10.66) $0.30 Final Cost of Service to City of Dover Ratepayers $88.01 $84.55 $3.45 6

Budget Actual Variance YTD YTD YTD Load Forecast 685,080 696,363 (11,282) Power Supply Power Supply $43,624,115 $43,394,940 $229,175 Power Supply Management $2,126,745 $2,115,909 $10,835 Capacity Charges - Load $11,650,406 $11,650,406 ($0) PJM Charges - Load $12,147,178 $13,110,533 ($963,355) Total - Power Supply $69,548,443 $70,271,788 ($723,345) Generation Plant Operations $5,224,239 $5,149,111 $75,128 Generation Fuel $3,138,177 $3,465,596 ($327,419) Capacity Credits ($10,845,058) ($10,845,059) $1 PJM Credits ($5,448,591) ($5,880,578) $431,986 Total - Generation ($7,931,234) ($8,110,930) $179,696 Emission Allowance Sales Total - Emission Allowance Sales $11,695 $11,695 $0 Total Power Supply & Generation $61,617,209 $62,160,858 ($543,650) Total Power Supply, Generation & Emission Sales $61,628,904 $62,172,553 ($543,650) Unit Costs Total – Power Supply $101.52 $100.91 $0.61 Total - Generation + Emission Sales ($11.56) ($11.63) $0.07 Final Cost of Service to City of Dover Ratepayers $89.96 $89.28 $0.68 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 $186 thousand variance relative to the monthly budget. This variance was driven by Dover’s open position, which was 46% 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 $307 thousand greater than budget. Additional factors contributing to the unfavorable variance included i) a $112 thousand unfavorable variance in PJM Ancillary charges and ii) a $27 thousand unfavorable variance in Transmission Loss Refunds. Offsetting these unfavorable variances were a $170 thousand favorable variances in Load Following and a $97 thousand favorable variance in Basis costs.  For the month the City realized a $138 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 $252 thousand variance, and the change in price resulted in a favorable $114 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 an unfavorable variance of $17 thousand compared to the revised monthly O&M reset Budget of $428 thousand (the overall reset plant budget for FY 2010-11 was approved by the City Council on March, 2011). The timing of electric invoice and higher than expected combustion turbine maintenance resulted in unfavorable variance. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights  Dover’s May load was 62,114 MWh, which was 5.7% above the weather normalized load of 58,744 MWh. Hedge volumes accounted for 83% of actual load for the month.  The May All In Unit Energy cost (excluding capacity) of $77.85 per MWh is $2.16 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 May-11 May-11 May-11 City of Dover Load Load Obligation (MWh) 58,744 62,114 (3,370) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $72.78 $69.08 $3.71 Pass Through $6.30 $7.90 ($1.60) Incentive Fees $0.93 $0.88 $0.05 Total - All In Unit Energy Cost $80.01 $77.85 $2.16 Purchased Power Variance Analysis  The actual Dover load of 62,114 MWh was 5.7% above the projected May load of 58,744 MWh.  The All In Unit Energy Cost was $2.16 per MWh lower than budget due to a decreased load following and basis charges. Offsetting these positive variances was an increased open position volume and a higher than budgeted energy price, an unfavorable PJM Ancillary charge and a lower than projected transmission related refund.  The Management Incentive fee variance on a $/MWh basis is merely an estimate at this point. PJM Power Balancing and Load Related Fees Purchased Power (Hedges): 51,360 MWhs @ $69.33/MWh: $3,560,754 Power Balancing; Additional PJM, and Energy Manager Fee4: $2,353,253 Total Cost to Serve Load (62,114 MWhs) $5,914,007 All In $/MWh load cost inclusive of Energy Management Fees: $95.21/MWh 4 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT  PJM dispatched McKee Run Unit 3 and Van Sant Unit 11 on May 31st for 22 hours. Dover’s units generated 1,218 MWhs in aggregate for the PJM market and the budget did not expect any generation for the month.  The McKee units started a planned outage on March 28 that ended on May 23. On May 16, these units performed operational tests consuming 355 dth of natural gas and 754 gallons of fuel oil no.2. The testing fuel costs are expected under EG1112 and EG1113 projects. 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 May-11 May-11 May-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 $0.00 Power Sales Power Sales (MWh) 0 1,218 1,218 Sales Revenue ($ per MWh) $0.00 ($131.51) $131.51 Power Sales Revenue ($) $0 ($160,118.87) $160,119 Variable Fuel & Transport Fuel Oil No.2 Volume - McKee (gal) 0 0 0 Fuel Oil No.2 - McKee ($/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 $0.00 Gas Volume (Dth) 0 14,420 (14,420) Unit Gas Price ($/Dth) $0.00 $5.48 ($5.48) Variable Gas Cost ($) $0.00 $78,991.35 ($78,991.35) Transport ($) $0.00 $10,550.39 ($10,550.39) Variable Gas and Transport Costs ($) $0.00 $89,541.74 ($89,541.74) Variable Fuel & Transport Costs ($) $0.00 $89,541.74 ($89,541.74) Testing $0.00 $0.00 $0.00 Generation Production Margin $0.00 ($70,577.13) $70,577.13 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 McKee Run Unit 3 and Van Sant Unit 11 during the month. During that period the units consumed natural gas related to economic power generation. The McKee units also burned natural gas and fuel oil once during the month for operational testing purposes (See “Fuel and Transportation” and “Purchased Commodity Fuel Oil Summary”). The fuel expenses related to operational testing should be accrued under EG1112 and EG1113 projects. Generation Production Margin Transaction Volumes Revenue/(Cost) PJM Invoice for Power Sold 1,218 MWhs $160,118.87 Fuel and Transport 14,420 Dth gas/ 0 gal #2 oil ($78,991.35) 0 gal #2 oil Low Sulfur Generation Production Margin 1,218 MWhs $70,577.13 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 Synchronized Reserved Credit $187 Transco Demand Charge $0 Non-Production Energy Revenue/(Costs) $34,200 15

Fuel and Transportation  PJM dispatched McKee Unit 3 and Van Sant Unit 11 for total of 22 hours. The following table provides a summary of spot gas purchases during the month: Date Volume (Dth) Price ($/Dth) Total Commodity Cost ($) Hess Corp 16-May 800 $4.65 $3,720.00 17-May 300 $4.55 $1,365.00 30-May 1,500 $5.20 $7,800.00 31-May 9,000 $5.25 $47,250.00 31-May 4,000 $5.50 $22,000.00 Cash-Out (275) $4.36 ($1,199.00) Sub-Total 15,325 $5.28 $80,936.00 PESCO Sub-Total 0 $0.00 $0.00 NJNG Sub-Total 0 $0.00 $0.00 CIPs (355) $5.48 ($1,944.65) Total 14,970 $5.28 $78,991.35  The operational testing fuel expenses, provided below, should be recorded under the appropriate CIPs projects (EG1113 and EG1112). CIPs Volume (Dth) Price ($/Dth) Total Commodity Cost ($) EG1113 280 $5.48 $1,533.81 EG1112 75 $5.48 $410.84 Sub-Total 355 $5.48 $1,944.65 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. 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 276 $4.78 $1,319.28 Transport Volume/Dth $/Dth Total Cost Firm/IT 15,601 $0.5917 $9,231.11 Net Charge $10,550.39 17

Purchased Commodity Fuel Oil Summary McKee Run Unit 3 and Van Sant Unit 11 were dispatched during the month into PJM consuming natural gas. In addition, McKee units 1 & 2 conducted operational testing purposes on May 17th consuming approximately 754 gal of #2 fuel oil. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of May 31 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch5) McKee Run (#2 Fuel 2,554,105 451,081 3 Oil) Van Sant 258,000 153,043 3 (#2 Fuel Oil) The following table represents fuel oil consumed to test McKee Units 1 & 2. The inventory fuel oil cost of $1,530.62 should be expensed under CIP EG1112 project. May 2011 Fuel Oil Consumption McKee Run Date #2 Oil Inventory Market Price Inventory Market Cost Burns / gal Price ($/gal) ($/gal) Cost 17-May 754 $2.03 NA ($1,530.62) NA Total 754 ($1,530.62) 5 As measured by tank level instruments. Tank levels may change due to oil temperature. 18

3.3 – EMISSIONS AND ALLOWANCE MANAGEMENT Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through May 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 N/A 2003-2006 139 Carryover 9/29/09 SO2 Sales (1,500) 11/12/09 NOX Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (2) (4) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 52 72 -- $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 NOx seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 19

(3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $36,848.75 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $3.75/ton, 3976 post-CAIR SO2 allowances trading at $2.50/ton, 72 NOx annual allowances trading at $195/ton, and 52 NOx seasonal allowances trading at $17.50/ton. SO2 Existing SO2 allowances continue to have little value as the market awaits the release of the final version of the Environmental Protection Agency’s (EPA) Clean Air Transport Rule (Transport Rule). See Figure 1 – SO2 Prices. With an ample bank of existing SO2 allowances in the market and the expectation that the final Transport Rule will require covered facilities to hold and retire SO2 compliance instruments issued under the new program, prices for current vintage or older allowances are expected to remain very low. Figure 1 – SO2 Prices since Last Monthly Report SO2 Allowance Prices (May / June) $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2009 (pre-CAIR) 2010/2011 (post-CAIR) NOx NOX annual allowance prices rebounded some in the wake of high temperatures in late May and early June (See Figure 2 – NOX Annual Prices since Last Monthly Report.) A hot 2010 summer helped push NOX annual prices near $550/ton. A similarly hot summer this year could place some upward pressure on NOX annual pricing. With that said, as with SO2 allowances, if the Transport Rule implements as expected in 2012, NOX allowances will have no value beyond meeting 2011 compliance requirements. With no incentive to bank allowances, it is unlikely that 20

NOX annual allowances will increase much above current levels, unless generators have vastly underestimated their compliance needs for 2011. NOX seasonal allowances lost some value over last month. Allowances continue to trade in low volumes and around $20/ton (See Figure 3 – NOX 2011.) As with NOX annual and SO2 allowances, new trading rules under the Transport Rule are unlikely to allow current vintage NOX seasonal allowances to qualify for compliance. Figure 2 – NOX Annual Prices since Last Monthly Report NOX Annual Allowance Prices (May / June) $300.00 $250.00 $200.00 $150.00 $100.00 $50.00 $0.00 Figure 3 – NOX Annual Prices since Last Monthly Report NOX Seasonal Allowance Prices (May / June) $20.50 $20.00 $19.50 $19.00 $18.50 $18.00 $17.50 $17.00 $16.50 $16.00 21

SO2 and NOx Outlook The final Transport Rule, setting new emissions trading rules, is expected to be released in June or July and implemented in January 2012. The expectation is that there will be new allowances for SO2 and NOX emissions, leaving little value for the existing bank of allowances beyond this year’s compliance requirements. It is difficult to estimate what the future compliance costs for SO2 and NOX emissions will be under new trading rules with a number of variables still unknown - the release of the final Transport Rule should provide some clarity. Senator Tom Carper (D-Delaware), one of the key proponents of a “legislative fix” to the SO2 and NOX market rules, announced this month that he will not pursue passing a multi-pollutant in this Congress. While there remain some proposals in the House of Representatives to delay EPA implementation of various air pollution rules, expectation is that legislation impacting these markets will not be enacted this year or next. With that, EPA’s Transport Rule will likely be the regulatory mechanism moving forward, although there remains the possibility that lawsuits filed after the final rule is released could delay implementation. RGGI and Federal Carbon Outlook RGGI allowance prices continue to price at very low levels, as the market is substantially over supplied, forcing prices to levels at or near the statutory price floor (see Figure 4 – RGGI Allowance Prices). Figure 4 – RGGI Allowance Prices since Last Monthly Report RGGI Prices (May / June) $1.95 $1.90 $1.85 $1.80 The big news in RGGI has been the announcement from New Jersey Governor Chris Christie that the state will withdraw from RGGI at the end of this year. The announcement is not expected to have an enormous impact on the market, but could be an impetus for other states to 22

follow suit. Although currently there are no expectations of other states exiting the program as New Hampshire, Delaware, and Maine have all recently voted down similar efforts to withdraw from RGGI and New York, Maryland, and Massachusetts, the three largest members in terms of emissions, remain committed to the program. RGGI program administrators are meeting to review program rules as part of their 2012 Comprehensive Review process. With the program over allocated, the major issue is whether anything can be done to lower the cap or limit the amount the existing bank can qualify for compliance. If the program continues with the existing planned caps and banked allowances are permitted for compliance at full value, RGGI allowances are likely to remain near current levels for the next several years. In Congress, there has been little movement or discussion on climate legislation nor is any expected through 2012. EPA will remain the primary driver at the federal level, although has recently announced that they will delay the release of proposed GHG emission limits for power plants, which were originally scheduled to be released this July. Proposed rules are now expected in September, although EPA maintains that final rules will be released in May 2012, as scheduled. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights  During the month of May, there were no restricted work days or lost time accidents. The facility has now gone 229 days without an OSHA recordable accident or a lost time reportable accident. Three Near Misses were recorded for the month.  The plant received no Notice of Violations (NOVs). There was one environmental deviation on the amount of dissolved solids (TDS) going to the outfall. There were three opacity deviations that resulted from testing the updated controls while combusting #2 fuel oil on Unit 1.  The Units 1, 2, and 3 planned outages were cleared on Monday May 23 at 0600 hours.  Unit 11 was dispatched by PJM on May 30 but then the dispatch was cancelled later by PJM. The unit was dispatched on the following day and ran for 8.216 hours. Unit 3 was dispatched on May 31and ran for 13.750 hours. Units 1 and 2 were available but never dispatched.  On May 18, the modifications to the Unit 3 Burner Management System were tested and eventually the test was successful and the system deemed operational.  On May 17th, Erik Petty received a NAES Service Recognition Award from Vincent Scire, Plant Manager, in recognition of completing 10 years of service working at the City of Dover Generating Facilities.  The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware May 2011 Monthly Report Erik Petty (left), Operator II, is shown being presented the NAES Service Recognition Award by Vincent Scire, Plant Manager, in recognition of completing 10 years of service working at the City of Dover Generating Facilities. Mr. Petty also received a commemorative polo shirt for passing the PJM System Operator Certification exam. 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 May, there were no restricted work days or lost time accidents. The facility has now gone 229 days without an OSHA recordable accident or a lost time reportable accident. Three Near Misses were recorded for the month. 1) A LO/TO procedure to replace a valve on the caustic system in the VanSant DI was not effectively isolated due to water pressure still remaining on the line as the valve was in the process of being removed. 2) Upon startup, Unit 3 experienced low vacuum. An immediate investigation found that the exhaust hood cover plate was not completely tightened. 3) Scaffold erected to gain access to the Unit 3 expansion joint and ductwork combusted due to exposure to heat emitting from the air heater top guide bearing area during a unit dispatch. Wood planking had been installed directly over the air heater which then got hot and began to smolder. The flames were put out with an extinguisher and the planking was removed. The plant received no Notice of Violations (NOVs). There was one environmental deviation on the amount of dissolved solids (TDS) going to the outfall. There were three opacity deviations that resulted from testing the updated controls while combusting #2 fuel oil on Unit 1. Environmental, Health and Safety Statistics Month Fiscal Year to Date (May) (7/1/10-6/30/11) NOVs 0 0 Opacity Deviations 3 16 Environmental Deviations 1 1 OSHA Recordable 0 1 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 3 9 Man Hours Worked 4,062.00 99,227.50 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 198 Days since last Lost Time Accident 198 27

Emissions (NOx & SO2) All data thru 5/31/11 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 1.4 0.2 1.6 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 2.6 1.7 4.3 CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee Van Sant YTD Van Sant Run Run (Yr/Season) (Yr/Season) (Yr/Season) (Yr/Season) 2009 45/25 75/50 5/3 12/5 - 1/1 0/0 – 0/0 18/0 4/2 119**/119** - 22##/53# – 2010 0 73/47* 5/3 -46/0 2/0 3/3 0/0 2011 0 71/48### 5/3 3/1 – 2/0 0/0 - 0/0 68/47### 3/3 Note ** - Higher NOx emissions are attributed to data substitution rules that use significantly higher emission rates than actually were emitted. The implementation of the data substitution rules were caused by performing a linearity test outside the grace period. NAES ESS was able to provide assistance in reducing the NOx emissions from 137 tons to 119 tons since the October report. A petition to the EPA was sent out in February that would result in a reduction in reported emissions. The EPA has given preliminary approval to the petition request although it is not official until the plant receives a signed EPA approval. Until the issue is resolved, the EPA has locked the annual account and no allowances will be deducted until that time. Note# - 53 tons were purchased to help compensate for the shortage in seasonal NOx allowances. Note## - 22 tons were purchased to help compensate for the shortage in annual NOx allowances. Note###- 2 tons were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 Note: Data is as of 5/31/2011 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 1 1987 Note: Data is as of 5/31/2011 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 2257 34,853 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 –May 2011 Actual Budget Variance Personnel 235,236 250,336 15,100 Materials & Supplies 5,682 20,060 14,378 Administrative Expenses 204,393 157,712 (46,681) Total $445,311 $428,108 (17,203) Financial – Fiscal Year to Date Number of Months - 11 Actual Budget Variance Personnel 2,765,473 2,777,373 11,900 Materials & Supplies 227,577 244,701 17,124 Administrative Expenses 2,156,045 2,133,436 (22,609) Total $5,149,095 $5,155,510 $6,415 2.1 Variance analysis: The adjusted (annual reset) budget for May was $428,108. The actual expenses for May were $445,311 for an unfavorable variance of $17,203 or ≈ 4.02%. The variance was due to the following: PERSONNEL EXPENSES – Lower straight labor, overtime, and labor burdens accounted for a favorable variance of $15,100. MATERIALS AND SUPPLIES EXPENSES- Lower than budgeted expenses in Medical Supplies, Water Treatment Chemicals, Computer Hardware, and City Building Maintenance contributed to realizing a favorable variance of $14,378. ADMINISTRATIVE EXPENSES – Higher than budgeted expenses in the areas of Electric (due to billing cycle – both April and May booked in May), Training / Conference / Food, Environmental Expenses, Home Office Labor, Other Equipment /Maintenance , Radio Repairs - Maintenance, and Combustion Turbine Maintenance costs which contributed to an unfavorable variance of $46,681. The majority of the unfavorable variance was due to Electric billing ($43,000 of the $46,681 variance) The current budget forecast for the current fiscal year is $6,156,900 expensed versus an adjusted budget of $6,163,315 thereby realizing a 99.90%.expense rate. 30

3.0 Operations Unit Operations / Outages / Trips The Units 1, 2, and 3 planned outages were cleared on Monday May 23 at 0600 hours. Unit 11 was dispatched by PJM on May 30 but then the dispatch was cancelled later by PJM. The unit was started twice and was online for 1.420 hours. The unit would come on line but could not raise load due to a blown fuse which affected the ability of the control system to sense the unit was online. The unit was dispatched on the following day and ran with no further problems for 8.216 hours. Unit 3 was dispatched on May 31st and ran for 13.750 hours. Units 1 and 2 were available but never dispatched. Month – May 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 13.750 13.750 9.636 23.386 Starts # 0 0 1 1 3 4 Gross Generation MWh 0.0 0.0 1,021.413 1,021.413 280.167 1,301.580 Net Generation MWh 0.0 0.0 946.317 946.317 279.942 1,226.259 Total Auxiliaries MWh 24.378 24.378 244.201 292.957 2.755 295.712 Auxiliaries purchased MWh 24.378 24.378 169.105 217.861 2.530 220.391 Fuel Gas Used MMBTU 12.228* 12.228* 11,101.389 11,125.845 3,851.820 14,977.665 Fuel Oil Used MMBTU 52.177* 52.177* 0.0 104.354* 0.0 104.354* Fuel Oil Used Gallons 377.00* 377.00* 0.0 754.00* 0.0 754.00* Total Fuel MMBTU 64.405* 64.405* 11,101.389 11,230.199 3,851.820 11,230.199 Net Heat Rate BTU/KWh 0.0 0.0 11,731 11,731 13,759 12.745 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 1.35 1.01 0.0 0.78 Availability Factor % 31.45 31.45 31.45 31.45 100.00 48.59 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 510.000 510.000 510.000 1,530.000 0.0 1,530.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 234.000 234.000 220.250 688.250 734.364 1,422.614 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 38,212.500 38,212.500 76,425.000 76,425.000 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. * Indicates testing fuel for Units 1 & 2 for the week of May 16. This testing was to operationally check out the controls modifications made to the burner management system during the Spring outage. 31

2010-2011 Fiscal Year-to-Date (11 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 13.033 128.966 659.006 801.005 147.426 948.310 Starts # 1 3 45 49 38 87 Gross Generation MWh 154.626 1,216.601 46,591.698 47,962.925 4,915.614 52,878.539 Net Generation MWh 147.111 1,141.623 43,915.013 45,203.747 4,912.183 50,115.930 Total Auxiliaries MWh 334.847 402.309 5,641.134 6,378.290 44.710 6,423 Auxiliaries purchased MWh 327.332 327.332 2,847.249 3,501.913 41.250 3,543.163 Fuel Gas Used MMBTU 2,195.478 15,258.078 463,120.226 480,573.782 57,796.096 538,369.878 Fuel Oil Used MMBTU 52.177 52.177 17,721.260 17,825.614 3,790.097 21,615.711 Fuel Oil Used Gallons 377.00 377.00 125,088 125,842 27,385 153,227 Total Fuel MMBTU 2,247.655 15,310.255 480,841.486 498,399.396 65,175.489 563,574.885 Net Heat Rate BTU/KWh 14,841 13,355 11,700 13,299 13,476 13,388 Unit Trips # 1 0 3 4 3 7 Capacity Factor % 0.11 0.84 5.26 4.07 1.48 3.35 Availability Factor % 59.88 67.10 67.02 64.67 96.92 72.73 Commercial % 6.6 0 0.03* 0.85 0 0.66 Unavailability (CU) Planned Outage Hours Hours 2,645.500 2,645.500 2,645.500 7,936.500 247.317 10,829.317 Maintenance Outage Hours 0.0 0.0 0.0 0.0 5.433 5.433 Hours Forced Outage Hours Hours 579.830 0 6.317 586.15 0 586.15 Reserve Shutdown Hours 4,814.670 5,265.534 4,800.393 14,880.597 7,639.820 22,520.417 Hours HW Boiler Gas Usage MMBTU 4,816.910 4,816.910 Pilot Gas Usage MMBTU 38,212.500 38,212.500 76,425.000 76,425.000 Note: * Calculation does not include 3.317 hours that were Outside Management Control (OMC) Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 10-11 Fuel FY 10-11 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 451,200 452,081 0 881 448,556 118,549 3,525 Van Sant 152,369 153,043 0 674 143,099 38,079 9,944 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 32

Van Sant Lifetime through 5/31/11 Actual Starts Factored Starts Fired Hours Van Sant 1256 2169.15 4120.76 Since HGP - Dec 2004 203 501.45 737.18 Team Report: On May 18, the modifications to the Unit 3 Burner Management System were tested by putting different natural gas burners in service then tripping burners to test to determine which gas valves would trip and compare with the ladder logic. After going through all nine burners, the test was successful and the system deemed operational. The testing was done without putting the unit on line. Operations personnel provided support to maintenance by working on Preventative Maintenance (PM) work orders or other work orders that they have the necessary skills to complete successfully. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2010-2011 Summer 2010 (June 1- Aug 31) Winter 2010-2011 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.20 1 17 * 2 17 18.09 2 17 * 3 102 102.68 3 102 105.61 Van Sant 39 39.30 11 39 43.833 Total 175 178.67 Total 175 149.443 33

4.0 Maintenance During the month of May, plant maintenance staff continued addressing the backlog of work orders. There were forty-five work orders issued with sixty-seven work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report May - 10 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 9 3 5 7 2 27 4 7 24 3 35 16 13 38 4 35 0 1 34 5 10 0 7 3 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 49 22 34 37 Totals 165 45 67 143 Note: PM's are included in the priority totals Notable activities during the month include: 1) Maintenance, IC&E and Operations Staff completed the Unit 3 natural gas piping purge utilizing the NAES SMP-22 gas purge procedure. Safe removal of natural gas from the piping with a nitrogen purge was completed. The mechanical contractor removed three sections of piping and installed three new burner level gas trip valves. The ICE technicians completed the electrical connections in preparation for making the system operational. 2) Maintenance mechanical staff completed eight weeks of outage work at the McKee Run Generating Station. Annual inspections and preventive maintenance activities were completed on Unit 3. Work activities included the replacement of the supply and return oil piping and isolation valves on Units 1 and2 boiler fronts. The new valves had limit switches installed for control feedback. 34

3) IC&E staff investigated a problem with VanSant not being able to increase load after being synchronized to the system grid. The PLC and generator breaker was checked. Two fuses were found blown in the FU 1 block of the control cab. The Unit was started and able to pick up load as normal. 4) IC&E staff completed eight weeks of outage work at McKee Run Generating Station. Units 1 and 2 outage work assigned to them included the installation of new control cabinets, LED lights, conduit and wiring for the controls modifications intended to bring the units into compliance with NFPA guidelines. 35

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: No other work is planned for this project during the Unit 3 Cooling remainder of the fiscal year. EG1101 Tower Life Schedule: Work scope development for next year will commence in Extension April 2011. Progress: The scope of work on the lower, lower decking support Units 1 & 2 Cooling and stairways improvement was completed in May. Tower casing EG1102 Tower Life is being replaced post outage and has no effect on unit operation. Extension Schedule: Work will be completed by the end of June 2011. Progress: Started on the development of the project work scope Unit 3 Turbine documents. EG1103 Schedule: This project has been deferred until 2011-2012 fiscal Inspection 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 capital costs due to Miscellaneous equipment failure. EG1105 Capital Equipment Schedule: Funds to date have been used to cover the cost of the Replacements Unit 3 600-lb steam station valve repairs, Unit 3 Cooling Water Booster Pump Repairs and circuit breakers. Progress: Started on the development of the project work scope EG1106 Unit 3 Stack Repairs document. Schedule: Deferred until 2011-2012 fiscal year. Progress: The planned work was scheduled to be completed in Units 1 & 2 Life early May. EG1107 Extension Schedule: The work was completed in May. Other work has been scheduled for 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 documents. EG1109 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. 36

Progress: The work was completed on the expansion joint in May. Unit 3 Air Heater Insulation and lagging reinstallation will commence in June 2011 EG1112 Expansion Joint Schedule: The work will be completed by the end of June 2011 Progress: The work was completed and tested the week of May 16. Units 1 & 2 Controls Schedule: Final installation of the control system wiring and system EG1113 Modifications checkout and testing was completed on May 20. Progress: The gas line was successfully purged and the gas lines Unit 3 Gas Line were cut for each deck and new gas valves were installed. Testing EG1114 Modifications was completed on May 18. Schedule: The work was completed and tested on May 18. 5.1 CIP Budget Approved Latest Project Description Budget Estimate Number ($ X 1000) ($ X 1000) EG1101 Unit 3 Cooling Tower Life Extension 398 372 EG1102 Units 1 & 2 Cooling Tower Life Extension 173 90 EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 77 66 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 225 225 EG1108 Unit 1 Forced Outage Repairs 412** 424 EG1109 Unit 3 FD & ID Fan Damper Upgrade 45 45 Unit 3 DCS Computers & Software EG1110 30 30 Upgrades EG1111 Unit 2 Boiler Inspections and Repairs 124## 111 EG1112 Unit 3 Air Heater Expansion Joint 65## 75 EG1113 Units 1 & 2 Controls Modifications 150## 150 EG1114 Unit 3 Gas Line Modifications 60## 40 ** This project was not budgeted for 2011. ## Project was not in original FY11 CIP but was approved by COD Council in late 2010. 37

6.0 General Plant Information Training: CEMS training was completed at VanSant for the Operations staff to allow checks to be completed on a daily basis by operators. VanSant is a remote site that is three miles away from McKee Run. Completing the daily checks by operators will provide consistency in work tasks and aid in ensuring tasks are completed in a timely manner. Training of all plant employees was held in May to educate them on being able to recognize Arc Flash Levels as well as identifying the applicable PPE to ensure their personal safety and the safety of others who may be in the arc flash exposure area. Subsequent to the training, the plant’s uniform policy has been revised to reflect the new safety standards. Plant employees continue General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy as well. Used Oil training was conducted to familiarize employees with a plan revision and subsequent operational changes. Personnel: On May 13th, Erik Petty successfully passed the PJM System Operator Certification exam. Mr. Petty received a shirt to commemorate his achievement for passing the PJM Operator exam. On May 17th, Erik Petty received a NAES Service Recognition Award from Vincent Scire, Plant Manager, in recognition of completing 10 years of service working at the City of Dover Generating Facilities. 38

Calendar of Events Date Units 1, 2, and 3 Spring Outage March 28, 2011 – May 23, 3011 NOx Ozone Season Starts May 1, 2011 EIA-923 Report May 6, 2011 VanSant 5 Year SPCC Plan Recertification June 27, 2011 Fiscal Year 2010-2011 Ends June 30, 2011 PJM Summer Capacity Test Period June 1, 2011- August 31, 2011 Toxic Release Inventory (TRI) Annual Report July 1, 2011 Unit 3 RATA Testing July 12, 2011 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2011 NOx Ozone Season Ends September 30, 2011 One Year Accident Free October 14, 2011 Units 1, 2, 3 and 11 Fall Outage TBD Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and VanSant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual VanSant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD Air Emission Inventory April 1, 2012 McKee Run Title V Permit Renewal April 20, 2012 EIA-860 Report April 29, 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 No Yes Yes $20,157 $20,157 Unit 11 No No Yes Yes $6,719 $6,719 Total YTD 77.85% Total YTD Incentive $122,052 $156,775 Incentive % Note - * Unit did not operate in the Winter period and was in the PJM Winter Capacity Test Exemption Program. 39

APPENDICES I. PJM INVOICE BREAKDOWN The PJM bill is a record of all Electricity Transactions, Transmission Services, Ancillary Services and Miscellaneous fees that allow the PJM to operate. Below is a list of the line items on the PJM bill including all generator activity. PJM Bill Line Items Gen Load Net Day Ahead Energy $130,982.16 ($662,397.52) ($531,415.36) Realtime Energy $15,685.56 $23,159.05 $38,844.61 Transmission Losses Credits $0.00 $41,068.93 $41,068.93 Network Integration Transmission Service Charges $0.00 ($265,765.79) ($265,765.79) Inadvertent Interchange Charges $0.00 ($3,430.94) ($3,430.94) Regulation Charges $0.00 ($28,221.88) ($28,221.88) Synchronized Reserve Charges $0.00 ($14,518.49) ($14,518.49) Balancing Operating Reserves Charges $0.00 ($11,935.81) ($11,935.81) Day Ahead Operating Reserves Charges $0.00 ($12,520.24) ($12,520.24) Day-ahead Scheduling Reserve $0.00 $126.91 $126.91 Synchronous Condensing Charges $0.00 ($46.96) ($46.96) Reactive Services Charges $0.00 ($107,290.04) ($107,290.04) Meter Correction Charges $0.00 ($4,678.40) ($4,678.40) 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 $13,451.15 $0.00 $13,451.15 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 $4.03 $4.03 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 $187.72 $0.00 $187.72 PJM Scheduling System Control and Dispatch Service Charges $0.00 ($15,851.78) ($15,851.78) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($4,708.54) ($4,708.54) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($31,898.48) ($31,898.48) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,002.01) ($1,002.01) North American Electric Reliability Corporation (NERC) Charge $0.00 ($551.33) ($551.33) Reliability First Corporation (RFC) Charges $0.00 ($836.52) ($836.52) 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 $401.92 $401.92 Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($326.77) ($326.77) 40

Organization of PJM States, Inc. (OPSI) Funding $0.00 ($39.28) ($39.28) FERC Annual Recovery $0.00 ($3,567.86) ($3,567.86) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 ($0.18) ($0.18) PPA $0.00 $357.13 $357.13 $1,196,846.27 ($2,166,980.78) ($970,134.51) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) Jul 83,163 83,163 $90.72 $90.72 $90.72 $81.36 $81.36 $81.36 Aug 78,755 78,755 $82.76 $82.76 $86.85 $83.03 $83.03 $82.17 Sep 66,782 66,782 $82.73 $82.73 $85.65 $91.13 $91.13 $84.79 Oct 56,452 56,452 $79.72 $79.72 $84.47 $87.24 $87.24 $85.27 Nov 54,396 54,396 $82.56 $82.56 $84.17 $91.56 $91.56 $86.28 Dec 63,566 63,566 $87.33 $87.33 $84.67 $98.22 $98.22 $88.16 Jan 60,136 64,462 $86.66 $91.77 $85.65 $94.36 $97.13 $89.40 Feb 54,199 54,900 $85.32 $84.37 $85.51 $94.11 $92.95 $89.77 Mar 56,334 57,414 $85.66 $81.75 $85.14 $93.39 $89.70 $89.77 Apr 52,554 54,359 $83.85 $81.20 $84.80 $92.99 $89.53 $89.74 May 58,744 62,114 $80.01 $77.85 $84.18 $87.28 $84.55 $89.28 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 June Monthly Report Energy and Operations Management July 28, 2011 This Report was produced by Pace Global Energy Services, LLC (“Pace Global”) and is meant to be read as a whole and in conjunction with this disclaimer. Any use of this Report other than as a whole and in conjunction with this disclaimer is forbidden. Any use of this Report outside of its stated purpose without the prior written consent of Pace Global is forbidden. Except for its stated purpose, this Report may not be copied or distributed in whole or in part without Pace Global’s prior written consent. This Report and the information and statements herein are based in whole or in part on information obtained from various sources as of June, 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 $92 25,000 $90 75,000 20,000 $88 $86 MWh MWh $/MWh 15,000 50,000 $84 10,000 $82 25,000 $80 5,000 $78 0 $76 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen Budget Actual Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA Purchased Power Management Wholesale load for the month of June was 71,891 MWhs, versus a weather normalized projected load of 67,331 MWhs. Hedged transactions accounted for 57,440 MWhs or 80% of this volume (85% of forecasted load) at a cost of $3.94 million. Spot Market purchases resulted in a PJM charge of $1.38 million (a $1.37 million charge in the Day Ahead market and an $11 thousand charge in the Real Time market). Other PJM related charges accounted for an additional cost of $1.04 million, inclusive of all load related fees. The June Energy Only Unit Cost, excluding capacity obligations and credits, was $1.85/MWh unfavorable compared to the budgeted value of $80.34/MWh. On January 24, 2011, the City of Dover reviewed and approved Pace’s and NAES’ submittal of a revised budget for Dover’s FY2010-11 (the “Reset Budget”). The purpose of this Reset Budget was to provide a mid-year update as to the anticipated cost-of-service for FY2010-11. Dover’s Cost of Service for FY2010-11 is $89.70/MWh, or $0.75/MWh favorable as compared to the Reset Budget1. Generation and Asset Management Net generation for the month of June credited by PJM was 4,115 MWhs and the budget did not expect any generation. All Dover units were dispatched by PJM during the month. In aggregate, Dover’s units were dispatched for 123 hours during the month, creating a generation production margin of $563 thousand (after fuel costs). For the month, McKee Units 2 and 3 successfully completed the PJM Capacity Tests for the Summer Demonstration Period. 1 The all in Cost of Service is based on actual results for 12 months of Dover’s costs. The Reset Budget was reviewed and approved by City of Dover. 2

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 purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through June 30, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 5 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) (6) (9) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 48 72 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $0.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. 3

(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. (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 $31,025 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $3.63/ton, 3,976 post-CAIR SO2 allowances trading at $2.13/ton, 52 NOx annual allowances trading at $142.50/ton, and 52 NOx seasonal allowances trading at $15.00/ton. EMISSIONS & ALLOWANCE SUMMARY Through June 30, 2011 Allowance Allowance Emissions Emissions Allowances Allowances Allowance Vintage Allocation Month Sold Month Sold Balance SO2 – 2007-10 10,157 N/A 131 N/A 4,847 5,179 SO2 – 2011 1,988 0 2 0 0 1,986 2 NOx Annu – 2009 80 0 13 0 45 22 NOx Seas – 2009 53 0 6 0 25 22 NOx Annu – 2010 78 0 122 0 (22) (22) NOx Seas – 2010 50 0 122 0 (53) (19) 3 NOx Annu – 2011 80 4 9 0 0 71 4 NOx Seas – 2011 51 4 6 0 0 45 Operations Management Summary During the month of June, there were no reportable or lost time accidents or injuries. The facility has now gone 259 days without an OSHA recordable accident and 259 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were no near miss events. Units 1, 2, 3 and 11 were dispatched by PJM during a three day heat wave. During the month, units 2 and 3 successfully completed the PJM Capacity tests for the summer demonstration period. Monthly Budget Variance - The estimated expenses attributable to O&M of the two sites for the month of June were $1,309,993. These expenses were $302,188 or 29.98% over the approved budget of $1,007,805. The principal reasons for the negative variance were the timing of the insurance payments (billing cycle), electric invoices (due to billing cycle), and water treatment chemicals and water (due to unexpected operations). The final actual expenses will be determined on the closing date for the fiscal year, expected by on or about July 29, 2011. 2 Approximately 10 tons of NOx emissions resulted from the February 2010 McKee Run testing associated with the Pollution Remediation project and the June 2010 emission testing project. 3 The EPA reallocated 4 additional annual NOx allowances into the McKee Run 2011 account. 4 The EPA reallocated 2 additional seasonal NOx allowances into the McKee Run 2011 account. 4

Risk Management Summary Forward PJM power prices were mixed since the last reporting period. Near-term prices decreased as the economic recovery slowed and natural gas storage numbers were bearish, pushing the forward curve lower while further out on the curve increased slightly. Forward Dover Zone power prices for FY 2011-2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all changed by approximately -$5.29/MWh to $1.65/MWh (representing a range of a -9.88% decrease and a 2.77% 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 7/22/2011 Budget July June May 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 2011-2012 N/A $79.88 85% -6.8% $79.66 $79.47 2012-2013 N/A $73.14 76% -8.4% $72.93 $72.91 2013-2014 N/A $72.33 48% -1.1% $71.60 $71.87 2014-2015 N/A $72.30 22% 0.0% $71.05 $71.80 1 Note that the "Cost-of-Service" column does not reflect the SREC benefit the City will receive since the SREC prices are currently unknown *Difference in COS from asset management due to generation & O&M **Not inclusive of budget update 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance Jun-11 Jun-11 Jun-11 Load Forecast 67,331 71,891 (4,560) Power Supply Power Supply $3,998,553 $3,943,828 $54,725 Power Supply Management $194,816 $239,721 ($44,905) Capacity Charges - Load $651,987 $693,359 ($41,372) PJM Charges - Load $1,216,254 $1,725,672 ($509,418) Total - Power Supply $6,061,610 $6,602,580 ($540,970) Generation Plant Operations $1,007,805 $1,309,993 ($302,188) Generation Fuel $106,800 $344,215 ($237,415) Capacity Credits ($574,665) ($573,435) ($1,230) PJM Credits ($104,812) ($942,910) $838,098 Total - Generation $435,128 $137,863 $297,265 Emission Allowance Sales Total - Emission Allowance Sales $0 $0 $0 Total Power Supply & Generation $6,496,738 $6,740,443 ($243,705) Total Power Supply, Generation & Emission Sales $6,496,738 $6,740,443 ($243,705) Unit Costs Total – Power Supply $90.03 $91.84 ($1.81) Total - Generation + Emission Sales $6.46 $1.92 $4.54 Final Cost of Service to City of Dover Ratepayers $96.49 $93.76 $2.73 6

Budget Actual Variance YTD YTD YTD Load Forecast 752,412 768,254 (15,842) Power Supply Power Supply $47,622,668 $47,338,768 $283,899 Power Supply Management $2,321,561 $2,355,630 ($34,069) Capacity Charges - Load $12,302,393 $12,343,764 ($41,372) PJM Charges - Load $13,363,432 $14,836,205 ($1,472,773) Total - Power Supply $75,610,053 $76,874,368 ($1,264,315) Generation Plant Operations $6,163,315 $6,459,104 ($295,789) Generation Fuel $3,244,977 $3,809,584 ($564,607) Capacity Credits ($11,419,723) ($11,418,494) ($1,229) PJM Credits ($5,553,404) ($6,823,487) $1,270,084 Total - Generation ($7,564,835) ($7,973,293) $408,458 Emission Allowance Sales Total - Emission Allowance Sales $11,695 $11,695 $0 Total Power Supply & Generation $68,045,217 $68,901,074 ($855,857) Total Power Supply, Generation & Emission Sales $68,056,912 $68,912,769 ($855,857) Unit Costs Total – Power Supply $100.49 $100.06 $0.43 Total - Generation + Emission Sales ($10.04) ($10.36) $0.32 Final Cost of Service to City of Dover Ratepayers $90.45 $89.70 $0.75 7

2.2 – VARIANCE ANALYSIS Power Supply  Power Supply realized a favorable $55 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 $509 thousand variance relative to the monthly budget. This variance was driven by Dover’s open position, which was 46% 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 $646 thousand greater than budget. Additional factors contributing to the unfavorable variance included i) a $32 thousand unfavorable variance in PJM Ancillary charges; ii) a $37 thousand unfavorable variance in updated transmission charges; and iii) a $32 thousand unfavorable variance in Transmission Loss Refunds. Offsetting these unfavorable variances were a $157 thousand favorable variances in Load Following costs, a $26 thousand favorable variances in transmission related credits, and a $55 thousand favorable variance in Basis costs.  For the month the City realized a $455 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 $360 thousand variance, and the change in price resulted in an unfavorable $95 thousand variance. Hence, all of the unfavorable variance can be attributed to volume and price changes. Generation  Per the City of Dover’s recommendation, the Plant’s O&M expense, provided above, is an estimated until the City’s H.T.E is finalized for the month. Under the estimate, the City realized an unfavorable variance of $302 thousand compared to the revised monthly O&M reset Budget of $1.0 million (the overall reset plant budget for FY 2010-11 was approved by the City Council in March 2011). The principal reasons for the negative variance were the timing of insurance payments and accrual of electricity expenses budgeted for next billing cycle, but expensed during the current month. In addition, Dover’s plants experienced increased chemical and water treatment expenses due to higher than anticipated power generations. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights  Dover’s June load was 71,891 MWh, which was 6.7% above the weather normalized load of 67,331 MWh. Hedge volumes accounted for 80% of actual load for the month.  The June All In Unit Energy cost (excluding capacity) of $82.20 per MWh is $1.85 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 $86 $/MWh $84 $82 $80 $78 $76 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA 10

Purchased Power Variance Report Budget Actual Variance Jun-11 Jun-11 Jun-11 City of Dover Load Load Obligation (MWh) 67,331 71,891 (4,560) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $74.33 $75.99 ($1.66) Pass Through $5.11 $5.40 ($0.29) Incentive Fees $0.90 $0.81 $0.09 Total - All In Unit Energy Cost $80.34 $82.20 ($1.85) Purchased Power Variance Analysis  The actual Dover load of 71,891 MWh was 6.7% above the projected June load of 67,331 MWh.  The All In Unit Energy Cost was $1.85 per MWh higher than budget due to an increased open position volume, a higher than budgeted energy price, an unfavorable PJM Ancillary charge and a lower than projected transmission loss refund. Offsetting these negative variances were a decreased load following and basis charges. PJM Power Balancing and Load Related Fees Purchased Power (Hedges): 57,440 MWhs @ $68.66/MWh: $3,943,828 Power Balancing; Additional PJM, and Energy Manager Fee5: $2,658,752 Total Cost to Serve Load (71,891 MWhs) $6,602,580 All In $/MWh load cost inclusive of Energy Management Fees: $91.84/MWh 5 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT  PJM dispatched all Dover units in June for total of 123 hours. Dover’s units generated 4,115 MWhs in aggregate for the PJM market and the budget did not expect any generation for the month.  Two McKee units (Units 2 and 3) successfully completed its PJM summer 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 Jun-11 Jun-11 Jun-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 1.5 (0.2) Deficient Capacity from PJM Incremental Auction 0 (6.2) (6.2) Total Capacity from Gen (MW) 175 169 (6) Gen Capacity Sales to PJM ($/MW.d) $110.04 $110.04 $0.00 Gen Capacity Purchases from PJM ($/MW.d) $0 $5 ($5) Incremental Auction Sales to PJM ($/MW.d) $50.00 $50.00 $0.00 Power Sales Power Sales (MWh) 0 4,115 4,115 Sales Revenue ($ per MWh) $0.00 ($220.52) $220.52 Power Sales Revenue ($) $0 ($907,330.17) $907,330.17 Variable Fuel & Transport Fuel Oil No.2 Volume - McKee (gal) 0 0 0 Fuel Oil No.2 - McKee ($/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 $0.00 Gas Volume (Dth) 0 54,470 (54,470) Unit Gas Price ($/Dth) $0.00 $5.98 ($5.98) Variable Gas Cost ($) $0.00 $325,795.40 ($325,795.40) Transport ($) $0.00 $18,419.61 ($18,419.61) Variable Gas and Transport Costs ($) $0.00 $344,215.01 ($344,215.01) Variable Fuel & Transport Costs ($) $0.00 $344,215.01 ($344,215.01) Testing $0.00 $0.00 $0.00 Generation Production Margin $0.00 ($563,115.16) $563,115.16 Generation Capacity Payment Total - Generation Capacity Payment ($574,665) ($573,435) ($1,230) 14

Generation Management Variance Analysis Fuel Expense  PJM dispatched all Dover units at least once during the month. During that period the units consumed natural gas related to economic power generation. Generation Production Margin Transaction Volumes Revenue/(Cost) PJM Invoice for Power Sold 4,115 MWhs $970,330.17 Fuel and Transport 54,470 Dth gas/ 0 gal #2 oil ($344,215.01) 0 gal #2 oil Low Sulfur Generation Production Margin 4,115 MWhs $563,115.16 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) $6,112 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 Synchronized Reserved Credit $0 Transco Demand Charge $0 Non-Production Energy Revenue/(Costs) $35,580 15

Fuel and Transportation  PJM dispatched all Dover units for total of 123 hours. The following table provides a summary of spot gas purchases during the month: Date Volume (Dth) Price ($/Dth) Total Commodity Cost ($) Hess Corp 01-Jun 14,000 $5.15 $72,100.00 06-Jun 300 $5.60 $1,680.00 08-Jun 13,000 $6.35 $82,550.00 08-Jun 5,500 $6.35 $34,925.00 09-Jun 13,000 $6.45 $83,850.00 09-Jun 6,500 $5.60 $36,400.00 01-Jun (3,830) $5.12 ($19,609.60) Sub-Total 48,470 $6.02 $291,895.40 PESCO Sub-Total 0 $0.00 $0.00 NJNG 07-Jun 6,000 $5.65 $33,900.00 Sub-Total 6,000 $5.65 $33,900.00 Total 54,470 $5.98 $325,795.40 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 (2,761) $4.41 ($12,176.01) Transport Volume/Dth $/Dth Total Cost Firm/IT 51,708 $0.5917 $30,595.62 Net Charge $18,419.61 17

Purchased Commodity Fuel Oil Summary McKee Run Units 1, 2 and 3 and Van Sant Unit 11 were dispatched during the month into PJM consuming natural gas. No fuel oils were consumed by the units. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of June 30 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch6) McKee Run (#2 Fuel 2,554,105 454,725 3 Oil) Van Sant 258,000 153,212 3 (#2 Fuel Oil) 6 As measured by tank level instruments. Tank levels may change due to oil temperature. 18

3.3 – EMISSIONS AND ALLOWANCE MANAGEMENT Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through June 30, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 5 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) (6) (9) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 48 72 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $0.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 19

(3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $31,025 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $3.63/ton, 3976 post-CAIR SO2 allowances trading at $2.13/ton, 52 NOx annual allowances trading at $142.50/ton, and 52 NOx seasonal allowances trading at $15.00/ton. EPA Issues Final Transport Rule On July 7, 2011, the Environmental Protection Agency (EPA) released the long-anticipated final rule that will regulate the SO2 and NOX emissions markets. The Cross State Air Pollution Rule (CSAPR) will have implications for fossil fuel burning power plants located in 27 states, but does not include compliance requirements for units located in Delaware. Unlike the Clean Air Interstate Rule (CAIR), which regulates the current emissions markets, and the proposed Clean Air Transport Rule (CATR), under CSAPR, Dover will not be required to submit emission allowances for their SO2, annual NOX or seasonal NOX emissions. The CSAPR, similar to CAIR, utilizes a cap-and-trade system whereby regulated facilities must procure emission allowances to account for their emissions from the previous year and submit them to the EPA for compliance. One allowance is equal to one ton of annual SO 2, annual NOX or seasonal NOX (the NOX or ozone season takes place between May 1 and September 30.) Most allowances will be distributed directly to existing facilities, however, because the program is designed to reduce overall emissions, less allowances will be allocated than would be needed in a “business as usual” scenario. Further, in some states, the number of allowances distributed each year will be significantly reduced beginning in 2014. Unlike CAIR, the CSAPR establishes emission caps at the state level with limited variability from those caps each year, thus restricting allowance trading between states. The state caps are intended to ensure that facilities in upwind states do not procure excess allowances (thus allowing more pollution from the upwind states) that might lead to non-attainment of air quality standards for a downwind state. As a consequence, there may be some disparity in the market cost for allowances between states. As with the proposed rule, the SO2 market will be further divided into two groups, Group 1 and Group 2. Sixteen states in Group 1 will see emission caps set in 2012 and then further reduced in 2014. The seven states in Group 2 will have their caps set in 2012, and then remain level in the following years. Facilities can only trade SO2 allowances with facilities located in their same Group. Absent legal, administrative or legislative action, CSAPR requirements will begin on January 1, 2012. While this final rule provides some clarity, uncertainty still exists: lawsuits could delay implementation; Congress could pass legislation overhauling the program; and EPA’s pending air quality standards could further tighten the compliance requirements for facilities covered by 20

this rule. Further, new air quality standards could force EPA to revise which states are covered under the rule. With that said, under the current construct, Dover does not have any compliance requirements under CSAPR. SO2 The release of CSAPR had little impact on the already deflated SO2 allowance market (see Figure 1 – SO2 Prices.) With an ample bank of existing SO2 allowances in the market and the confirmation that CSAPR will require covered facilities to hold and retire SO2 compliance instruments issued under the new program, prices for current vintage or older allowances remain very low. Absent some change to the regulatory construct, little to no movement is expected in current vintage allowance prices. Figure 1 – SO2 Prices since Last Monthly Report SO2 Allowance Prices (May / June) $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2009 (pre-CAIR) 2010/2011 (post-CAIR) NOx After a peak in pricing in early June, NOX annual allowance prices have fallen off some in early July (see Figure 2 – NOX Annual Prices since Last Monthly Report.) Recent warming temperatures across the country could place some upward pressure on allowances prices. However, with no incentive to bank current vintage allowances for future years, as the market transitions to CSAPR, it is unlikely that NOX annual allowances will increase substantially above current levels NOX seasonal allowances have traded fairly steadily and in low volumes over last month (see Figure 3 – NOX .) As with NOX annual and SO2 allowances, new trading rules under CSAPR will not allow current vintage NOX seasonal allowances to qualify for compliance. 21

Figure 2 – NOX Annual Prices since Last Monthly Report NOX Annual Allowance Prices (May - July) $300.00 $250.00 $200.00 $/ton $150.00 $100.00 $50.00 $0.00 Figure 3 – NOX Annual Prices since Last Monthly Report NOX Seasonal Allowance Prices (May - July) $25.00 $20.00 $15.00 $/ton $10.00 $5.00 $0.00 RGGI and Federal Carbon Outlook RGGI allowance prices continue to price at very low levels, as the market is substantially over supplied, forcing prices to levels at or near the statutory price floor (see Figure 4 – RGGI Allowance Prices.) 22

Figure 4 – RGGI Allowance Prices since Last Monthly Report RGGI Prices (May - July) $1.95 $1.90 $/ton $1.85 $1.80 RGGI program administrators are meeting to review program rules as part of their 2012 Comprehensive Review process. With the program over allocated, the major issue is whether anything can be done to lower the cap or limit the amount the existing bank can qualify for compliance. If the program continues with the existing planned caps and banked allowances are permitted for compliance at full value, RGGI allowances are likely to remain near current levels for the next several years. In Congress, there has been little movement or discussion on climate legislation nor is any expected through 2012. EPA will remain the primary driver at the federal level, although has recently announced that they will delay the release of proposed GHG emission limits for power plants, which were originally scheduled to be released this July. Proposed rules are now expected in September, and EPA maintains that final rules will be released in May 2012, as scheduled. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights  During the month of June, there were no restricted work days or lost time accidents. The facility has now gone 259 days without an OSHA recordable accident or a lost time reportable accident. The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month.  The Van Sant SPCC Plan was reviewed and recertified as part of the 5 year review/recertification requirements.  New NOx and CO2 analyzers were installed at McKee Run, both as an upgrade to the existing aged units, and to meet the requirements identified in the 2010 NOx Span/range analysis.  In the month of June, Units 1, 2, 3 and 11 were dispatched by PJM. In the second week of June, all units were dispatched during a three day heat wave. During the month, Units 2 and 3 successfully completed the PJM Capacity Tests for the Summer Demonstration Period.  Art Morris, Senior Operator, retired as of June 30, 2011. Art spent approximately thirty years working for the City of Dover.  The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware June 2011 Monthly Report Art Morris, Senior Operator, bids his adieu at his Retirement Celebration Party after almost 30 years of Service at the plant. 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 June, there were no restricted work days or lost time accidents. The facility has now gone 259 days without an OSHA recordable accident or a lost time reportable accident. The plant received no Notice of Violations (NOVs). There were no environmental deviations or other permit deviations during the month. The Van Sant SPCC Plan was reviewed and recertified as part of the 5 year review/recertification requirements. The annual DNREC/EPA TRI-Form R assessment was completed for both McKee Run and Van Sant. No submission is required for either facility based on the assessment. New NOx and CO2 analyzers were installed at McKee Run, both as an upgrade to the existing aged units, and to meet the requirements identified in the 2010 NOx Span/range analysis. Both analyzers are working well and no issues have been identified. Linearity and RATA testing is scheduled for July 12th as part of the CEMS recertification process. A new NAES Waste Management Plan template has been created for the facility and is in the process of being implemented. Customization and implementation is expected to take several months. Environmental, Health and Safety Statistics Month Fiscal Year to Date (June) (7/1/10-6/30/11) NOVs 0 0 Opacity Deviations 0 16 Environmental Deviations 0 1 OSHA Recordable 0 1 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 9 Man Hours Worked 4,235.75 103,463.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 259 Days since last Lost Time Accident 259 27

Emissions (NOx & SO2) All data thru 6/30/11 NOx Summary - Year (May-Sept.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 119.2 3.3 125.4 2011 0.6 0.5 6.1 0.4 7.6 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 0.6 0.5 7.3 1.9 10.3 CAIR NOx Allowances Summary* NOx Allowances Available NOx Allowance Balance CAIR NOx CAIR CAIR NOx (Per Facility, Prior to Sale) Total NOx Allowances NOx Allowances McKee Run Tons Van Sant Purchased McKee Run Van Sant Allowance Sold YTD (Yr/Season) Emitted (Yr/Season) YTD (Yr/Season) (Yr/Season) Vintage (Yr/ Season) 2009 45/25 75/50 5/3 12/5 - 1/1 0/0 – 0/0 18/0 4/2 119**/119** - 22##/53# – 2010 0 73/47* 5/3 -46/0 2/0 3/3 0/0 2011 0 75###/48### 5/3 7 /6– 2/0 0/0 - 0/0 68###/42### 3/3 Note ** - Higher NOx emissions are attributed to data substitution rules that use significantly higher emission rates than actually were emitted. The implementation of the data substitution rules were caused by performing a linearity test outside the grace period. NAES ESS was able to provide assistance in reducing the NOx emissions from 137 tons to 119 tons since the October report. A petition to the EPA was sent out in February that would result in a reduction in reported emissions. The EPA has given preliminary approval to the petition request although it is not official until the plant receives a signed EPA approval. Until the issue is resolved, the EPA has locked the annual account and no allowances will be deducted until that time. Note# - 53 tons were purchased to help compensate for the shortage in seasonal NOx allowances. Note## - 22 tons were purchased to help compensate for the shortage in annual NOx allowances. Note###- 2 tons (Seasonal and 4 tons (Annual) were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 Note: Data is as of 6/30/2011 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 1 1987 Note: Data is as of 6/30/2011 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 4795 32,315 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 –June 2011 Actual Budget Variance Personnel 616,580 641,305 24,725 Materials & Supplies 41,832 17,669 (24,163) Administrative Expenses 651,581 348,831 (302,750) Total $1,309,993 $1,007,805 ($302,188 ) Financial – Fiscal Year to Date Number of Months - 12 Actual Budget Variance Personnel 3,382,052 3,418,678 36,626 Materials & Supplies 269,410 262,370 (7,040) Administrative Expenses 2,807,626 2,482,267 (325,359) Total $6,459,088 $6,163,315 ($295,773) 2.1 Variance analysis: The City of Dover Finance Department has not yet closed the books for the month of June but has conveyed to PACE that it was permissible to use the expenses booked to date for their final monthly report. The City of Dover plans on closing the books for June on July 29, 2011 or soon thereafter. The adjusted (annual reset) budget for June was $1,007,805. The actual expenses for June were $1,309,993for an unfavorable variance of $302,188 or ≈ 29.98%. The variance was due to the following: PERSONNEL EXPENSES – Lower straight labor, overtime, and labor burdens accounted for a favorable variance of $24,725. MATERIALS AND SUPPLIES EXPENSES- Higher than budgeted expenses in Water/Sewer, Water Treatment Chemicals, Computer Hardware, and City Building Maintenance contributed to realizing an unfavorable variance of $24,163. ADMINISTRATIVE EXPENSES – Higher than budgeted expenses in the areas of Insurance (due to billing cycle), Electric (due to billing cycle), Training / Conference / Food , Contractual Services, Environmental Expenses, Home Office Labor, Other Equipment / Maintenance, Boiler Systems, Continuous Emission Monitors, and Combustion Turbine Maintenance contributed to an unfavorable variance of $302,750. The majority of the unfavorable variance was due to Insurance premium billing. The current budget forecast for the current fiscal year is $6,495,088 expensed versus an adjusted budget of $6,163,315 thereby realizing a 104.8%.expense rate. 30

3.0 Operations Unit Operations / Outages / Trips In the month of June, Units 1, 2, 3 and 11 were dispatched by PJM. In the second week of June, all units were dispatched during a three day heat wave. During the month, Units 2 and 3 successfully completed the PJM Capacity Tests for the Summer Demonstration Period. Month – June 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 29.967 30.750 55.685 116.402 7.250 123.652 Starts # 2 2 4 8 1 9 Gross Generation MWh 278.102 286.102 3,668.068 4,232.410 235.957 4,468.367 Net Generation MWh 264.400 267.194 3,382.809 3,914.403 235.785 4,150.188 Total Auxiliaries MWh 47.055 52.399 474.522 573.976 1.692 575.668 Auxiliaries purchased MWh 33.353 33.353 189.263 255.968 1.520 257.488 Fuel Gas Used MMBTU 4,433.141 3,796.319 37,982.535 46,211.995 3,135.911 49,347.906 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 4,433.141 3,796.319 37,982.535 46,211.995 3,135.911 49,347.906 Net Heat Rate BTU/KWh 16,767 14,208 11,228 14,068 13,300 13,684 Unit Trips # 1 1 0 0 0 0 Capacity Factor % 2.16 2.18 4.61 4.00 0.84 3.29 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 690.033 689.250 664.315 2,043.598 712.750 2,756.348 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 228.575 228.575 457.15 457.15 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 31

2010-2011 Fiscal Year-to-Date (12 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 43.000 159.716 714.691 917.407 154.676 1,072.083 Starts # 3 5 49 57 39 96 Gross Generation MWh 432.728 1,502.703 50,259.766 52,195.197 5,151.571 57,346.714 Net Generation MWh 411.511 1,408.817 47,297.822 49,118.150 5,147.968 54,266.118 Total Auxiliaries MWh 381.902 454.708 6,115.656 6,952.266 46.402 6,998.668 Auxiliaries purchased MWh 360.685 360.685 3,036.512 3,757.882 42.770 3,800.652 Fuel Gas Used MMBTU 6,628.619 19,054.397 501,102.761 526,785.777 60,932.007 587,717.784 Fuel Oil Used MMBTU 52.177 52.177 17,721.260 17,825.614 3,790.097 21,615.711 Fuel Oil Used Gallons 377.00 377.00 125,088 125,842 27,385 153,227 Total Fuel MMBTU 6,680.796 19,106.574 518,824.021 544,611.391 68,311.400 612,922.791 Net Heat Rate BTU/KWh 15,804 13,782 11,464 13,683 13,300 13,492 Unit Trips # 2 1 3 6 3 9 Capacity Factor % 0.28 0.95 5.21 4.06 1.43 3.35 Availability Factor % 63.18 69.80 69.73 67.57 97.17 67.57 Commercial % 6.6 0 0.03* 0.85 0 0.66 Unavailability (CU) Planned Outage Hours Hours 2,645.500 2,645.500 2,645.500 7,936.500 247.317 10,829.317 Maintenance Outage Hours 0.0 0.0 0.0 0.0 5.433 5.433 Hours Forced Outage Hours Hours 579.830 0 6.317 586.15 0 586.15 Reserve Shutdown Hours 5,504.703 5,954.784 5,464.708 16,924.195 8,352.570 25,276.765 Hours HW Boiler Gas Usage MMBTU 4,816.910 4,816.910 Pilot Gas Usage MMBTU 266.894 266.894 533.7880 533.7880 Note: * Calculation does not include 3.317 hours that were Outside Management Control (OMC) 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) 453,844 454,725 0 881 448,556 118,549 6,169 Van Sant 153,043 153,212 0 169 143,099 38,079 10,113 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 32

Van Sant Lifetime through 6/30/11 Actual Starts Factored Starts Fired Hours Van Sant 1257 2172.15 4128.46 Since HGP - Dec 2004 204 504.45 744.88 Team Report: Plant employees continue to study General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed, the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy as well. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders for those work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. During the month of June, Operations successfully completed the PJM Capacity Tests on Units 2 and 3 for the Summer Demonstration Period. Capacity Testing – FY 2010-2011 Summer 2010 (June 1- Aug 31) Winter 2010-2011 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.20 1 17 * 2 17 18.09 2 17 * 3 102 102.68 3 102 105.61 Van Sant 39 39.30 11 39 43.833 Total 175 178.67 Total 175 149.443 33

4.0 Maintenance During the month of June, plant maintenance staff continued addressing the backlog of work orders. There were fifty-nine work orders issued with ninety-four work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report June - 12 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 13 0 7 6 2 37 12 25 24 3 54 9 29 34 4 35 0 1 34 5 2 0 1 1 SW1 0 3 0 3 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 44 35 31 48 Totals 185 59 94 150 Note: PM's are included in the priority totals Notable activities during the month include: 1) Maintenance completed the removal and installation of a new braided gas line to the A-2 main gas burner on Unit 3. It was discovered during the most recent unit dispatch that the gas line had a small gas leak. Operations promptly removed the burner from service and a LOTO was completed for the repair. 2) Maintenance staff completed the annual oil sampling of plant equipment and the results were analyzed by Bentley Tribology Services. Results were received and reviewed by the plant maintenance staff. Based on the sample results, a recommendation to change the oil in two fan motors was acted upon. 3) Operations team members, I,C/E staff and Aqua Tech Technicians investigated problems with the Van Sant DI train. The DI was not able to get extended throughput when the train was put in operation. During the evaluation of the regeneration process, it was discovered several analyzers, probes and transmitters weren’t working properly. Each was calibrated and checked for proper working condition. Upon completion of the evaluation, Aquatech recommended the replacement of five separate pieces of instrumentation equipment. Bids were solicited for the new parts and subsequently 34

ordered. Several weeks later, the I,C/E staff received the Vansant DI parts and promptly went about the process of installing the equipment. Operations was tasked with placing the Van Sant DI in service for final tuning and testing of the new instruments. During the regeneration process it was discovered that more technical support would be needed from Aqua Tech. Aqua Tech was brought back on site and Operations placed the DI in service. Aqua Tech and IC&E staff made several adjustments and optimized the DI water output. Van Sant DI completed its run cycle filling the tank. 4) IC&E staff relocated the low pressure gas switches on Units 1&2 main gas piping to the boilers. In addition, the high pressure gas trip switch settings were adjusted slightly higher to allow for slight deviations on the natural gas system. 5) IC&E staff received the parts for Units 1 and 2 spark igniter rewire. Each igniter was rewired per the Warren Professional Control’s drawing design. New wire and trip relays were installed and field tested. Each worked as designed. 35

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: ATS replaced outside panels on the tower during the Unit 3 Cooling month of June. No other work is planned for this project during the EG1101 Tower Life remainder of the fiscal year. Extension Schedule: Work scope development for next year will commence in September 2011. Units 1 & 2 Cooling Progress: The scope of work on the Tower casing was completed in EG1102 Tower Life June. Extension Schedule: No other work planned for this fiscal year. Progress: Due to higher priority work to address the reliability of Units 1 and 2, this project is being deferred until 2012. As the end of the current fiscal year ends, development of the work scope is in the Unit 3 Turbine EG1103 process of commencing. NAES Turbine Services has been Inspection contacted to aid in this endeavor. Schedule: This project has been deferred until 2011-2012 fiscal year. Progress: Due to higher priority work to address the reliability of Units 1 and 2, this project is being deferred until 2012. As the end of Unit 3 Aux System EG1104 the current fiscal year ends, development of the work scope is in the Components process of commencing. Schedule: Deferred until 2011-2012 fiscal year. Progress: This project is for the unexpected capital costs due to Miscellaneous equipment failure. EG1105 Capital Equipment Schedule: Funds to date have been used to cover the cost of the Replacements Unit 3 600-lb steam station valve repairs, Unit 3 Cooling Water Booster Pump Repairs and circuit breakers. Progress: Due to higher priority work to address the reliability of Units 1 and 2, this project is being deferred until 2012. As the end EG1106 Unit 3 Stack Repairs of the current fiscal year ends, development of the work scope is in the process of commencing. Schedule: Deferred until 2011-2012 fiscal year. Progress: This project is to assess and determine the actions necessary to prolong the life of Units 1 and 2. Repair costs based on inspection results will have to be developed and supplied to the City of Dover in order to make a decision on how and when to proceed. Units 1 & 2 Life EG1107 The plant is still waiting on estimated costs from Siemens. Extension Training of plant staff on the equipment during plant operations and when the units were not operating occurred during the month. Schedule: Other work has been scheduled for the 2011-2012 fiscal year. 36

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 work was completed on the expansion joint insulation Unit 3 Air Heater EG1112 and lagging reinstallation commenced in June 2011. Expansion Joint Schedule: The work will be completed by the end of July 2011 Progress: Work continued with the installation of additional control valves and wiring. Both the modified oil and natural gas systems Units 1 & 2 Controls EG1113 were tested and are now operational, ready for the next dispatch. Modifications Schedule: Parts are on order for the natural gas system and will be installed upon arrival in July. Progress: Work was completed in May. Unit 3 Gas Line EG1114 Schedule: The work was completed and tested on May 18. Modifications 5.1 CIP Budget Approved Latest Project Budget Description Estimate Number ($ X ($ X 1000) 1000) EG1101 Unit 3 Cooling Tower Life Extension 398 372 EG1102 Units 1 & 2 Cooling Tower Life Extension 173 90 EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 77 66 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 225 225 EG1108 Unit 1 Forced Outage Repairs 412** 424 37

EG1109 Unit 3 FD & ID Fan Damper Upgrade 45 45 Unit 3 DCS Computers & Software EG1110 30 30 Upgrades EG1111 Unit 2 Boiler Inspections and Repairs 124## 111 EG1112 Unit 3 Air Heater Expansion Joint 65## 75 EG1113 Units 1 & 2 Controls Modifications 150## 150 EG1114 Unit 3 Gas Line Modifications 60## 40 ** This project was not budgeted for 2011. ## Project was not in original FY11 CIP but was approved by COD Council in late 2010. 6.0 General Plant Information Training: CEMS training on the QA/QC Manual was scheduled for the I,C/E Technicians. Unfortunately, this had to be rescheduled to a date in early July due to work priorities and unit operations. As part of plant improvements, the NOx and CO2 analyzers were replaced. During the replacement, plant staff members were able to get valuable hands-on experience on the equipment. Many staff members attended CPR and First Aid Training held at the plant site and led by instructors from the Delaware Fire School. One class had to be rescheduled due to the dispatch of the generation units. This class session is expected to occur in July. A safety stand-down was put into effect at the end of the month. Vince Scire, Plant Manager, worked with plant staff to implement a strategy that would aid in improving safety awareness among plant personnel as well as heighten visibility and accessibility of plant management among the employees. Vince Scire attended a Frame 6 users meeting. Personnel: Art Morris, Senior Operator, retired as of June 30, 2011. Art spent approximately thirty years working for the City of Dover. He was an asset to the company and to the plant. The absence of his valuable experience will be felt among all staff members. 38

Calendar of Events Date PJM Summer Capacity Test Period June 1, 2011- August 31, 2011 Fiscal Year 2010-2011 Ends June 30, 2011 Toxic Release Inventory (TRI) Annual Report July 1, 2011 Unit 3 RATA Testing July 12, 2011 McKee Run and Van Sant Title V Semi-Annual Certification Due August 1, 2011 NOx Ozone Season Ends September 30, 2011 One Year Accident Free October 14, 2011 Units 1, 2, 3 and 11 Fall Outage TBD Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and Van Sant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual Van Sant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD Air Emission Inventory April 1, 2012 McKee Run Title V Permit Renewal April 20, 2012 EIA-860 Report April 29, 2011 Units 1, 2, and 3 Spring Outage TBD NOx Ozone Season Starts May 1, 2012 EIA-923 Report May 6, 2012 7.0 Summary of NAES Performance to Date Plant Performance FY 2010-2011 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0.66% $63,262 $89,586 Unavailability (CU) Safety 1 1 $8,398 $16,797 Environmental 0 0 $16,797 $16,797 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,360 $3,360 Unit 2 No No Yes Yes* $3,360 $3,360 Unit 3 No No Yes Yes $20,157 $20,157 Unit 11 No No Yes Yes $6,719 $6,719 Total YTD 77.88% Total YTD Incentive $122,052 $156,775 Incentive % Note - * Unit did not operate in the Winter period and was in the PJM Winter Capacity Test Exemption Program. 39

APPENDICES I. PJM INVOICE BREAKDOWN The PJM bill is a record of all Electricity Transactions, Transmission Services, Ancillary Services and Miscellaneous fees that allow the PJM to operate. Below is a list of the line items on the PJM bill including all generator activity. PJM Bill Line Items Gen Load Net Day Ahead Energy $836,010.69 ($1,372,726.48) ($536,715.79) Real-time Energy ($72,344.93) ($10,882.25) ($83,227.18) Transmission Losses Credits $0.00 $46,059.61 $46,059.61 Network Integration Transmission Service Charges $0.00 ($262,228.80) ($262,228.80) Inadvertent Interchange Charges $0.00 ($1,292.36) ($1,292.36) Regulation Charges $0.00 ($30,898.18) ($30,898.18) Synchronized Reserve Charges $0.00 ($6,909.91) ($6,909.91) Balancing Operating Reserves Charges $0.00 ($25,364.83) ($25,364.83) Day Ahead Operating Reserves Charges ($1,492.98) ($6,677.52) ($8,170.50) Day-ahead Scheduling Reserve $0.00 ($10,983.95) ($10,983.95) Synchronous Condensing Charges $0.00 ($10.30) ($10.30) Reactive Services Charges $0.00 ($72,052.64) ($72,052.64) Meter Correction Charges $0.00 $9,120.43 $9,120.43 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 $130,847.57 $0.00 $130,847.57 Day Ahead Operating Reserves Credits $14,309.82 $0.00 $14,309.82 Locational Reliability Charges $0.00 ($693,444.00) ($693,444.00) Capacity Transfer Rights Credits $0.00 $0.00 $0.00 Capacity Resource Deficiency Credits $0.00 $85.20 $85.20 Demand Response and ILR Compliance Penalty Credits $0.00 $0.00 $0.00 RPM Auction Credits $573,435.00 $0.00 $573,435.00 Auction Revenue Rights Credits $0.00 $66,483.30 $66,483.30 Synchronized Reserve Credits $0.00 $0.00 $0.00 PJM Scheduling System Control and Dispatch Service Charges $0.00 ($17,895.67) ($17,895.67) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($5,480.52) ($5,480.52) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($32,199.42) ($32,199.42) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,676.68) ($1,676.68) North American Electric Reliability Corporation (NERC) Charge $0.00 ($641.74) ($641.74) Reliability First Corporation (RFC) Charges $0.00 ($973.63) ($973.63) Expansion Cost Recovery Charges $0.00 ($408.60) ($408.60) Transmission Enhancement Charges $0.00 ($14,539.40) ($14,539.40) Black Start Service Credits $6,111.93 $0.00 $6,111.93 Non-Firm Point-to-Point Transmission Service Credits $0.00 $585.20 $585.20 Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($392.94) ($392.94) 40

Organization of PJM States, Inc. (OPSI) Funding $0.00 ($45.74) ($45.74) FERC Annual Recovery $0.00 ($4,152.80) ($4,152.80) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 ($182.89) ($182.89) PPA $0.00 $29,955.54 $29,955.54 $1,516,344.68 ($2,419,030.93) ($902,686.25) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) Jul 83,163 83,163 $90.72 $90.72 $90.72 $81.36 $81.36 $81.36 Aug 78,755 78,755 $82.76 $82.76 $86.85 $83.03 $83.03 $82.17 Sep 66,782 66,782 $82.73 $82.73 $85.65 $91.13 $91.13 $84.79 Oct 56,452 56,452 $79.72 $79.72 $84.47 $87.24 $87.24 $85.27 Nov 54,396 54,396 $82.56 $82.56 $84.17 $91.56 $91.56 $86.28 Dec 63,566 63,566 $87.33 $87.33 $84.67 $98.22 $98.22 $88.16 Jan 60,136 64,462 $86.66 $91.77 $85.65 $94.36 $97.13 $89.40 Feb 54,199 54,900 $85.32 $84.37 $85.51 $94.11 $92.95 $89.77 Mar 56,334 57,414 $85.66 $81.75 $85.14 $93.39 $89.70 $89.77 Apr 52,554 54,359 $83.85 $81.20 $84.80 $92.99 $89.53 $89.74 May 58,744 62,114 $80.01 $77.85 $84.18 $87.28 $84.55 $89.28 Jun 67,331 71,891 $80.34 $82.20 $84.00 $95.85 $93.76 $89.70 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

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