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UTILITY COMMITTEE AGENDA MAY 12, 2014 - 4:00 P.M. CITY HALL COUNCIL CHAMBERS 15 LOOCKERMAN PLAZA DOVER, DELAWARE Public comments are welcomed on any item and will be permitted at appropriate times. When possible, please notify the City Clerk (736-7008 or e-mail at CityClerk@dover.de.us) should you wish to be recognized. AGENDA ADDITIONS/DELETIONS 1. Capital School District Request to Transfer Equivalent Dwelling Unit (EDU) Credits (Dover High School) (Staff advises that, based upon the technical merits, the transfer of EDU credits can be authorized, as requested, in accordance with the Dover Code of Ordinances) 2. Annual Review and Approval of Governing Policy For Energy Commodity Risk Management (Staff recommends approval of the proposed amendments and adoption of the policy, as amended) 3. Quarterly Review of Utility Related Capital Investment Plan (CIP) (Electric and Water/Wastewater) (Committee action not required) 4. TEA/NAES Report (March) (Staff recommends acceptance of the report) 5. Updates (Committee action is not required on the items below) A. Green Energy Funding and Programming B. National Pollution Discharge Elimination System (NPDES) Municipal Separate Storm Sewer Systems (MS4) Permit C. Garrison Oak Technical Park Project Updates c-1. City Infrastructure c-2. Calpine Energy Center c-3. Dover Sun Park 6. Adjournment by 4:55 p.m. /tm S:\AGENDAS-MINUTES-PACKETS-PRESENTATIONS-ATT&EXH\Committee-Agendas\2014\05-12-2014 UTILITY.wpd THE AGENDA ITEMS AS LISTED MAY NOT BE CONSIDERED IN SEQUENCE. THIS AGENDA IS SUBJECT TO CHANGE TO INCLUDE THE ADDITION OR THE DELETION OF ITEMS, INCLUDING EXECUTIVE SESSIONS.

ACTION FORM PROCEEDING: Utility Committee AGENDA ITEM NO.: DEPARTMENT OF ORIGIN: Public Works – Water/Wastewater DATE SUBMITTED: 04/17/14 PREPARED BY: Sharon Duca, P.E., Public Works Director / City Engineer SUBJECT: Capital School District Request to Transfer Equivalent Dwelling Unit (EDU) Credits (Dover High School) REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager EXHIBITS: Dover High School – EDU Transfer Request letter dated April 15, 2014 Department of Public Works Impact Fee Calculations sheet dated April 16, 2014 EXPENDITURE REQUIRED: N/A AMOUNT BUDGETED: N/A FUNDING SOURCE: N/A TIMETABLE: Upon approval from Council, and application for Certificate of Occupancy, credits will be transferred. RECOMMENDED ACTION: The City of Dover Code of Ordinances authorizes City Council to transfer Equivalent Dwelling Unit (EDU) credits from one property to another property. Capital School District has provided the info necessary to support a transfer from 1 Pat Lynn Drive to 1 Dover High Drive. Based upon the technical merits the transfer of EDUs can be authorized. BACKGROUND AND ANALYSIS The Capital School District is currently completing construction on the new Dover High School at 1 Dover High Drive in Dover. Within the campus, a greenhouse and new sports facilities will also be provided. As part of this project, as identified in the attached EDU Transfer Request letter from Capital School District, the main high school building at 1 Pat Lynn Drive in Dover is to be demolished in October 2014, the greenhouse at 1 Pat Lynn Drive is to be relocated to 1 Dover High Drive during the demolition phase, and the stadium at 1 Pat Lynn Drive is not planned to be demolished or relocated. Due to the project extents outlined, Capital School District has requested that the EDU credits generated at 1 Pat Lynn Drive, due to the high school building demolition and greenhouse relocation, be transferred to 1 Dover High Drive and applied toward the new high school building and greenhouse EDUs subject to impact fees. Per the City of Dover Code of Ordinances, two (2) references are applicable to this request. The first code reference is located in Chapter 110, Article III – Water Service, Division 3 – Water Impact Fees, Section 110- 208 (d), and the second code reference is located in Chapter 110, Article IV – Wastewater Service, Division 3 – Wastewater Impact Fees, Section 110-283 (c). Both sections state that “No EDUs shall be transferred from one property to another property, whether or not such properties are owned by the same person, without the approval of city council.” City staff has completed the associated impact fee calculations which are attached. Capital School District has provided the information necessary to support the transfer request. As such, City Council can authorize the transfer as long as the referenced structures at 1 Pat Lynn Drive are demolished and properly disconnected from the water and wastewater systems. In addition, any redevelopment and / or expansion at 1 Pat Lynn Drive will be subject to all impact fees resulting from new EDUs assessed at that time.

City of Dover, Delaware Governing Policy For Energy Commodity Risk Management Effective: September 10, 2012 Approved by: City of Dover Council Date: September 10, 2012

TABLE OF CONTENTS PURPOSE OF THE RISK MANAGEMENT POLICY ................................................................34 A. Introduction...................................................................................................................34 B. Scope of Policy ..............................................................................................................34 C. Objectives and Risk Philosophy .................................................................................45 D. Policy Administration ..................................................................................................45 MANAGEMENT AND CONTROLS ...........................................................................................56 A. Utility Committee of The City Council .....................................................................56 B. Executive Risk Management Committee ..................................................................56 1. City Manager .............................................................................................................................. 7 2. Director of the Utility............................................................................................................... 78 3. Controller .................................................................................................................................. 78 4. TEA Member Services Manager............................................................................................. 89 DISCUSSION OF RISKS .............................................................................................................89 MARKETING AND TRADING PRACTICES ..........................................................................910 A. Standards of Conduct ................................................................................................910 B. Products, Activities and Limitations .......................................................................910 C. Contract Documentation and Confirmations.......................................................1011 D. Training..........................................................................................................................11 E. New Product Protocol .............................................................................................1112 RISK LIMITS AND RISK MEASUREMENTS.......................................................................1112 A. Limits..........................................................................................................................1112 1. Volume/Maturity/Value Limits ....................................................................................... 1112 2. Volume Limits ...................................................................................................................... 1213 3. Locational Limits .................................................................................................................. 1213 B. Stress Testing and Back Testing .............................................................................1213 C. Instances of Exceeding Risk Limits........................................................................1213 CREDIT POLICY ......................................................................................................................1213 A. Measuring Credit Risk .............................................................................................1314 B. Analysis and Extension of Credit Limits ..............................................................1314 C. Instances of Exceeding Credit Limits ........................................................................14 REPORTING .............................................................................................................................1415 A. Risk Reporting ..........................................................................................................1415 B. Credit Reporting .......................................................................................................1516 C. Hedge Effectiveness Reporting ..............................................................................1617 INFORMATION TECHNOLOGY SYSTEMS ........................................................................1617 POLICY DISTRIBUTION AND COUNSEL ...........................................................................1617 A. Distribution Outside The City ................................................................................1617 B. Designated Counsel .................................................................................................1617 APPENDIX A – Approved Products .........................................................................................1718 APPENDIX B – Approved Counterparties and Threshold Tables ............................................1819 APPENDIX C – Business Risks ................................................................................................2223 APPENDIX D – Glossary ..........................................................................................................2324 APPENDIX D – Swap Transaction Representative ..................................................................2526 2

PURPOSE OF THE RISK MANAGEMENT POLICY A. Introduction The City of Dover (“City”) and its customers are routinely exposed to energy price risk, volume variability risk, basis risk and credit risk – herein referred to collectively as energy commodity risk - in the normal conduct of serving its electric load requirements. Volatility of energy commodity prices and volumetric uncertainty (either supply/generation or load obligations) impose a substantial and direct risk to the City’s financial and operating performance. By authority of its charter, the City has responsibility for overseeing the City’s electricity operations, including the management of its cost of serving Dover’s customers. By agreement dated May 6, 2011 and approved by the City (the “EMA”), the City has engaged The Energy Authority, Inc. (“TEA”) to assist the City with Asset Management and Strategic Planning Services, Risk Management Services, and Energy Management Services. This Policy for Energy Commodity Risk Management (“Policy”) is established the explicit understanding that the City has retained and delegated responsibilities to TEA to provide Risk Management Services. Additionally, the City has issued this Policy for dealing with the philosophy, framework and delegation of responsibilities necessary to govern activities related to Dover’s energy commodity risk management. As set forth herein, the City has established an organizational structure, delegated responsibility and established internal controls and procedures to ensure that all transactional and oversight activities are conducted in compliance with this Policy and in accordance with the City’s normal reporting, legal, financing and regulatory requirements relating to energy assets and transactions. B. Scope of Policy This Policy covers all transactions entered into the by the City of Dover designed to meet the City’s electric load requirement and the management of risk related to these transactions. In the event of conflict between this Policy and the EMA, the Policy shall control. This Policy is separate and distinct from enterprise risk management policies and procedures addressing the City’s safe operation of its generating stations and energy 3

infrastructure, insurance requirements, permit compliance, employee matters regulatory compliance with laws and regulations of the State of Delaware and Federal Agencies such as EPA, FERC, NERC and CFTC or other potential risks to the City beyond the purchase and sale of fuel and electric power and its ancillary products. C. Objectives and Risk Philosophy The objectives of the Policy are to identify energy commodity price and credit risk exposures and give the City a framework for the quantification and management of these exposures. The Policy will identify the reports needed to convey how the identified risk exposures can potentially impact the City’s overall cost of providing electricity service to its customers and report on the risk management of the transactions associated with City’s electric load requirements. Under the Policy, risk management activities will be conducted consistent with the City’s overall objective of appropriate risk mitigation. There are several objectives of the Policy which, when taken and executed together, serve to manage the City’s energy commodity price exposures. Specifically, the Policy:  Establishes framework for developing credit limits for counterparties and quantifies and manages the credit exposures related to potential counterparty abrogation  Quantifies the impact of the above exposures on City’s financial results  Manages the impact of the above exposures in line with the City’s identified level of risk tolerance  Provides clear delineation of responsibilities and authority, outline a separation of duties, and ensure reporting of risk is timely and accurate.  Ensures that the impact of any action affecting the City’s position is consistently quantified, monitored and authorized. The City’s risk management activities will be conducted consistent with its overall objective of appropriate risk mitigation and never for purposes of speculation. D. Policy Administration This Policy has been approved by the Executive Risk Management Committee and The Utility Committee of the Dover City Council. The Utility Committee must approve modifications to the Policy with the exception of the appendix information which can be modified with the approval of the Executive Risk Management Committee. 4

MANAGEMENT AND CONTROLS This Policy articulates the management and organization of the City and TEA to serve as a control framework outlining delegation of duties and responsibilities. A. Utility Committee of The City Council The Utility Committee of The City Council (The Committee) has a responsibility to provide approval of this Policy. With this approval, The Committee also assumes additional duties. They will understand the risks the City is and could be exposed to due to their energy commodity risk management activities. In this role, the Committee will have a responsibility to also understand the City’s policies and procedures, internal controls and systems which are used to help manage the City’s energy commodity risks. The Committee will approve any amendments to the Policy or limits within. The Executive Risk Management Committee will update the Committee periodically regarding the Policy and its functions. It will be the Committee’s responsibility to:  Discuss guidelines and strategic policies that govern the process by which the Energy Risk Management Committee assesses and manages risks  Review and approve the risk policy at least annually  Approve new members of the Executive Risk Management Committee  Acknowledge the risk inherent in transactions covered under this Policy B. Executive Risk Management Committee An Executive Risk Management Committee (“ERMC”) has been formed to provide executive management oversight for the City’s energy commodity risk management activities. The ERMC is charged with the creation, amendment and administration of this Policy, including acquiring any approvals required by the Utility Committee, and will ensure that all energy commodity risk management activities of the City are performed consistent with this Policy. The ERMC will meet at least monthly to review compliance and conduct its business as described in this Policy. The ERMC shall be comprised of the following voting members: The City Manager, The Director of Utility, The City’s Controller and TEA’s Member Client Service Manager. The City’s ERMC will make decisions following the process outlined in this Policy. TEA’s Member Client Services Manager may include representatives from other areas within TEA in the monthly ERMC meetings who will attend in person or by conference call as non-voting advisors. Other City employees and TEA staff may also be asked to 5

attend meetings from time-to-time, as the ERMC deems necessary. The responsibilities of the ERMC shall include:  Establish scope and frequency for management reporting to the Utility Committee.  No less than annually, review the City’s Energy Commodity Policies and Procedures for correctness and completeness.  Review and approve any new risk report or change to an existing risk report provided by TEA to monitor risks outlined in this Policy.  Understand and approve any models, methodologies, and assumptions used for measuring risks such as volume risk, process risk, counterparty risk and commodity risk.  Monitor the City’s risks and ensure they are within the limits and are being managed according to what is indicated within the City’s Policy and associated procedures  Understand the City’s risk management objectives and risk tolerances.  Review and approve the risk management and trading strategy programs and associated risk. Each program should be reviewed to ensure alignment with Policy objectives and compliance with risk limits within this Policy.  Periodically review any risk management program approved in light of recent market changes, and ensure continued compliance with its established guidelines  Review and approve new products, markets, trading counterparties and credit limits  Review all violations and exceptions to this Policy and report such to the Committee.  Approve the individuals or companies that engage in the City’s commodity transactions and are subject to the limits within this Policy.  Ensure that the individuals or companies authorized to transact on behalf of the City as well as manage its risks, are appropriately trained and qualified.  Ensure independence and segregation of duties between front, middle and back office at TEA. Recommend changes to this Policy to the City’s Utility Committee for approval and ensure the Utility Committee understands the City’s overall compliance with this Policy and associated procedures The ERMC will meet at least monthly to review risks identified and reported on by the Policy, this meeting shall be chaired by The City Manager. Minutes of each meeting of the ERMC shall be recorded and reflect any decisions and follow-up action items to be performed. These minutes will be reviewed and approved by the members of the ERMC in a timely manner. Each member of the ERMC has a unique role as defined below: 6

1. City Manager The City Manager is independent of all commercial functions and carries the responsibility of establishment and maintenance of risk management for the City. The City Manager will be a voting member of the ERMC and act as a chair of the ERMC. Other responsibilities include:  Ensure this Policy is maintained.  Oversee reviews of the City’s energy commodity risks, limits, risk measurement methodologies and models, and programs and recommend changes to the ERMC.  Ensure potential transactions and their impacts on the City’s risks and limits defined within this Policy.  Develop and monitor the implementation of the Policy, and oversee other risk management processes and procedures established by this Policy or otherwise by the ERMC. 2. Director of the Utility The Director of the Utility is responsible for all trading, hedging, pricing, structuring, and market and operational risk management activities associated with the City. The Director of the Utility will be a voting member of the ERMC. Other responsibilities include:  Review the effectiveness of transaction processing systems and procedures relating to risk measurement.  Recommend operational risk and business risk assessment guidelines. 3. Controller The Controller is independent of all commercial functions and carries the responsibility of the City’s accounting practices. The Controller will be a voting member on the ERMC. Other responsibilities include:  Perform financial accounting including accounting for hedging and derivatives activities.  Comply with tax rules and make appropriate tax elections.  Record realized and unrealized gains and losses.  Reconcile general ledger, cash transactions and margin accounts.  Implement tax-hedge accounting policies and other regulatory tax requirements.  Develop and maintain documentation outlining standard procedures for conducting business.  Invoice counterparties and resolve billing disputes.  Perform daily/weekly/monthly transaction checkout with counterparties. 7

 Develop and maintain documentation outlining standard procedures for conducting business. 4. TEA Member Client Services Manager The TEA Member Client Service Manager roles and responsibilities are defined exhibit B of the EMA between the City and TEA. The TEA Client Member Service Manager will be a voting member on the ERMC. Other responsibilities include:  Monitor risk reports between ERMC meetings.  Report to the Committee and the ERMC on the City’s adherence to all limits and functions within this policy.  Engage the ERMC in discussions regarding events or developments that could expose the company to potential losses.  Recommend to the ERMC specific risk limits consistent with the City’s risk management objectives, risk tolerance, and risk management policy.  Coordinate and distribute independent market fundamental analysis.  Provide advisory support and recommendations as specified in Article 5 of the EMA. DISCUSSION OF RISKS This Policy covers the management of all material energy market risks faced by the City. A comprehensive list of risks that are or could be relevant to City is shown in Appendix C of the Policy. Among the most critical of these risks are commodity risk, counterparty risk, process risk, volume risk, and budget risk. These risks are measured by the limit structure and controls outlined in the Policy. Commodity risk represents the potential adverse impacts to the value of the City’s portfolio due to changes in the market. Commodity risk encompasses volatility risk, forward price risk, basis risk, correlation risk and liquidity risk. Counterparty risk represents the potential losses the City could incur due to delivery risk and receivable risk. Delivery risk stems from a supplier or trading counterparty that is unable or unwilling to perform on its commitments including but not limited to delivery or receipt of commodities. Receivable Risk includes the City’s risk associated with a counterparty’s timeliness of payment for services rendered. Process risks represents the risks associated with process problems including, but not limited to, inaccurate data capture, untimely trade execution or settlement problems. Controls over process risks are embedded in the organizational structure of TEA through the design processes and operating procedures. 8

Volume Risk represents the potential for unforeseen changes from projections of excess or shortfall of capacity or energy from the actual needs. When variances are large coupled with large costs to transact and adverse moves in market prices this risk could be realized. In management of this risk, the City must be aware of the fact that unexpected variations in volume are often highly correlated with price movements. Budget Risk represents the potential to deviate outside of tolerable bounds of the City’s budget. Deviations from budget can be caused by forecast error or unforeseeable adverse changes in market prices. MARKETING AND TRADING PRACTICES A. Standards of Conduct Individuals authorized to transact for the City shall not misrepresent, conceal or withhold information regarding energy commodity trading and risk management transactions to any person responsible for the accurate recording and/or reporting of such transactions; participate in any such transaction or similar activity for the benefit of any party other than the City; or hold or be a beneficiary of any financial interest in any entity with which the employee is engaged in trading or other business activity (other than ownership of an interest in a mutual fund managed by another party). Further, no employee authorized to place or execute such transactions may engage in trading power or energy commodities derivative instruments for his or her personal account. B. Products, Activities and Limitations Pursuant to achieving the City’s core objectives for the purpose of energy commodity risk management, the following limitations shall apply.  Permissible instruments will be restricted to the products and instruments specified in Appendix A – Approved Products of the Policy; o All physical forward transactions shall be governed by the Edison Electrical Institutive (EEI), North American Energy Standards Board (NAESB), or similar agreements with counterparties approved by the City. o The City reserves the right to enter into financial hedge transactions to effectuate Policy objectives, but does not authorize TEA to enter into financial hedge transactions on its behalf. Any such financial transactions that the City may enter into shall be governed by ISDA agreements with counterparties as approved by the City.  The maturity for each permissible instrument will be restricted to the maturity limits specified in the risk limits section of the Policy. 9

 Transaction volumes for each risk management transaction will be restricted to the amounts specified in the Risk Limits section of the Policy.  Risk management transactions will be outlined in the City of Dover Hedge Program which will be approved by the ERMC. Risk management transactions may include the following: o Hedging the forward price of purchased power for delivery to the City as needed to meet its electric load requirements. o Hedging the forward price of natural gas and fuels as needed to generate power to meet the City’s electric load requirements. o Unwinding of hedges to accommodate changes in expected load requirements, or for economic reasons subject to explicit constraints set by the ERMC. C. Contract Documentation and Confirmations No over-the-counter transaction may be executed until an EEI, NAESB, or similar agreement has been authorized by the City, approved by the ERMC and fully executed by the parties. Written confirmations will be required from counterparties, as defined in the Master Service Agreement between the City and counterparty, within one business day or such longer time as required by the contract in question for all risk management transactions. Contemporaneous with any commitments and prior to receipt of written confirmations, verbal commitments shall be memorialized internally as to instrument structure, quantity, relevant time horizon, price and any other relevant terms; such internal documentation shall be time stamped and correlated to the ultimate written confirmation to or from the counterparty. Both the internal documentation as well as the written confirmation from the counterparty shall be provided to TEA’s Risk Control Group immediately upon receipt for verification. In the event that there is a material failure to provide timely documentation or confirmations, then at the City Manager’s sole discretion, the offending individual’s authorization may be suspended. Similarly, if the failure to provide timely documentation or confirmations is due to the failure of counterparty, then at the discretion of the City Manager, a moratorium may be imposed on transactions with that counterparty. In such cases, the City Manager shall notify the ERMC of the issues leading to the suspension or moratorium shall. Nothing herein shall inhibit the City Manager from bringing control issues to the TEA’s Member Client Services Manager prior to a decision on materiality or the imposition of a suspension of trading privileges or counterparty moratorium. 10

D. Training The ERMC will ensure that all City employees and/or TEA Staff that will execute transactions on behalf of the City will have appropriate training in the markets in which the transactions occur. E. New Product Protocol As required to manage the City’s energy commodity risk the ERMC shall approve new products provided the requirements of the New Product Approval Procedure are met. RISK LIMITS AND RISK MEASUREMENTS A. Limits The limit structure is designed to quantify the types of risk in City’s energy commodity portfolio. The City will manage and report on its energy commodity market risk using Volume/Maturity/Value Limits, a Cost of Service Limit and a Hedge Loss Limit. 1. Volume/Maturity/Value Limits Transaction limits for the Individuals Authorized to execute transactions and the maturity limits for each permissible instrument are listed below. Transactions for amounts in excess of those listed may be executed only upon approval of the ERMC. This limit, maturity and value structure is not intended for use when transacting day- ahead and real time in the PJM market. Maximum Daily Notional Limits Volume/Maturity/Value Limits Volume Value ($000) Balance of the Month through 12 Months 50 20,000 Power Between 13 Months and 24 Months 50 20,000 (MW) Between 25 Months and 36 Months 25 10,000 Hourly Limit Between 37 Months and 48 Months 25 10,000 Between 49 Months and 60 Months 25 10,000 Balance of the Month through 12 Months 30,000 400 Natural Gas Between 13 Months and 24 Months 30,000 400 (MMBtu) Between 25 Months and 36 Months 10,000 200 Monthly Limit Between 37 Months and 48 Months 10,000 200 Between 49 Months and 60 Months 10,000 200 Balance of the Month through 12 Months 6,000 400 #2/#6 Fuel Oil Between 13 Months and 24 Months 6,000 400 (Bbl) Between 25 Months and 36 Months 3,000 200 Monthly Limit Between 37 Months and 48 Months 3,000 200 Between 49 Months and 60 Months 3,000 200 11

The amounts in the table above refer to the maximum volume of orders that can be placed in any one day the individuals authorized to conduct trades for the specified time period. On any one day the maximum transaction volume placed can be for up to 50 MegaWatts per hour for every hour during a single calendar month (including both on-peak and off-peak hours), OR 25,000 MMBtu per month for all months pertinent to the natural gas transaction, OR 6,000 Bbl per month for all months pertinent to the oil transaction. 2. Volume Limits For no reason should a transaction be executed that exceeds the City’s electric load requirements. If there is an adjustment to the City’s electric load requirements and the existing transactions greater than 100% of the adjusted electric load requirements the ERMC will review and approve the offsetting strategy deployed in sufficient proportion to mitigate the encroachment. 3. Locational Limits Non-Commodity Transactions must support the requirement of one of the City’s generation units, native load or transaction locations. B. Stress Testing and Back Testing The City’s positions shall be periodically stress tested and models shall be back tested. The processes around these tests are outlined in the Stress Testing and Back Testing Procedure. C. Instances of Exceeding Risk Limits Should the City or TEA enter into a transaction that causes the portfolio to exceed any above mentioned limits the Director of the Utility shall, in addition to notifying the ERMC, also notify the Chair of The Committee as soon as practicable and shall provide periodic reports to the Chair on the status the transactions for as long as the City is exceeding its limits. The ERMC will review and determine whether any liquidation or offsetting of transactions is warranted. The incident will be documented as a Policy Exception by the Director of the Utility. CREDIT POLICY Credit Risk is the risk due to the uncertainty in a counterparty’s ability to meet its contractual obligations. The primary objective of this credit policy is to mitigate, to the extent commercially reasonable, the credit risks associated with transactions covered in this Policy while still allowing the City to achieve its objectives. 12

A. Measuring Credit Risk The status of credit risk will be measured and reported through reports provided by TEA. The current credit exposure will be reported at the agreement level via a Counterparty Credit Report provided by TEA. This information will be made available in real time to TEA trading personnel so that it can be checked prior to executing transactions for the City. Those responsible for risk oversight at the City and TEA will have access to this information no less frequently than once per day. The ERMC will monitor overall credit utilization and any credit exceptions at least monthly. When measuring the current credit risk, netting will be applied to the exposure if the City’s contract with a counterparty includes provisions for netting. B. Analysis and Extension of Credit Limits Physical and financial commodity transactions will be executed with counterparties approved by the ERMC with credit available to support the transactions. The creditworthiness of a counterparty will be determined by both qualitative and quantitative factors. Factors shall include, but not limited to:  A company’s debt credit ratings provided by the rating agencies.  Financial data such as an analysis of the income statement, balance sheet, and cash flow, as well as liquidity and capital structure.  Subjective factors such as company’s fuel diversity, overall size, risk management policy and internal controls, geographic diversity, and market intelligence. A credit limit is the amount of unsecured credit granted to a counterparty. Unsecured credit exposure includes amounts owed by the counterparty, whether billed or not, and the mark-to-market differences in value of any collateral which the counterparty has provided the City. Any net exposure above the collateral threshold will require the posting of collateral by a counterparty. Further information on the City’s procedure for establishing credit is contained in the Counterparty & Credit Review Process. Collateral thresholds, term limitations and credit exposure limits will be subject to the maximums indicated in Appendix B, based upon the lower of the S&P and Moody’s credit ratings. At no time will the City incur a credit exposure with any counterparty greater than $60,000,000. 13

C. Instances of Exceeding Credit Limits The City and TEA are restricted by the credit limits approved by the ERMC. The ERMC can suspend trading with a counterparty, if that counterparty’s credit limit has been reached or exceeded. The City or TEA traders shall not exceed the Counterparty Credit Limit by executing transactions with any counterparty without approval of the ERMC. The ERMC will determine when it’s appropriate to require additional collateral if a counterparty’s credit exposure exceeds its credit limit. Collateral includes standing letter of credit, cash, and prepayments. All credit exceptions will be documented and reported to the ERMC and the Committee as Policy Exceptions. REPORTING A. Risk Reporting Preparation of timely reports is critical to monitoring risk. TEA will furnish the required reports on a regular frequency for the City in a format acceptable to the ERMC. In addition, the ERMC and its designees will be provided access to the City’s risk reports as updated daily via TEA’s secure Web Portal. Reports required on a monthly basis and for periodic meetings of the ERMC include the following:  Profit and Loss Report The Profit and Loss (P&L) Report shows the daily realization of transactions at either the transaction price or the market price as transaction roll from unrealized to realized. This report should show volumes, transaction prices and market prices of realized physical and financial power and fuel transactions.  Mark to Market Report The Mark to Market (“MTM”) Report conveys the potential transaction exposure if the energy commodity portfolio was liquidated at the most recent market settlement prices. This report should show volumes, transaction prices and market prices of unrealized physical and financial power and fuel transactions. 14

 Activity Report The Activity Report presents a summary of all energy commodity risk management activities undertaken, including new transactions taken, existing transactions settled/liquidated, and any transactions unwound.  Cost of Service Report The City’s exposure to energy price risk shall be monitored and reported on a Cost-of- Service basis. All calculations are at the wholesale level. The Cost-of-Service recognizes all prior (expired) months within the Power Year on the basis of actual (incurred) costs, and recognizes all forward (pending) months within the Power Year on the basis of expected forward power and fuel prices and expected forward load-following risks. As defined below, the Cost-of-Service is an aggregation of Forward Energy Commodity Portfolio Cost, the Load Following Cost Expectation and the City’s Budget Target for Purchase Power Expense. o The Net Purchased Power Cost shows the net cost of all physical and financial transactions related to the City’s anticipated commodity requirements for power and fuel and is based on the price of all hedge transactions plus the forward market price of all unhedged transactions valued at current forward prices for energy commodities, customer-level cost per MWH of all physical and financial transactions related to Dover’s actual plus anticipated energy. o The expected fixed costs defined as load-serving entity (LSE) capacity costs, transmission costs and TEA management fees. o The Expected Load-Following Cost for a specified power year is defined as the expected cost (or revenue) associated with intra-month load variations due to weather or other events affecting demand. As an interim measure due to lack of necessary market information and the rapid evolution of the PJM RTO market, the ERMC has specified $2.50 per MWH as an estimate of the Load Following Cost to be used for estimating the City’s Forward Cost-of-Service Report. The ERMC will update the Expected Load Following estimate while lack of necessary market information persists no less than annually. o The Budget Target for Purchase Power Expense represents the City’s view of expected purchase power expense. B. Credit Reporting  Counterparty Credit Report The Counterparty Credit Report conveys the exposure to all counterparties with which the City has credit exposure resulting from its energy commodity risk management activities.  CFTC Reporting The City understands that transacting over the counter (OTC) swaps carries an additional Commodity Futures Trading Commission (CFTC) reporting function. Once 15

required by the CFTC, the City will report on how the City generally meets its financial obligations associated with entering into non-cleared swaps in a manner acceptable to the CFTC. C. Hedge Effectiveness Reporting If the City’s transactions require a hedge effectiveness test, those testing results will be reported to the ERMC no later than one month after the end of the financial reporting period. The report will include a summary of testing methodology, assumptions of the testing and the outcome of results with a pass or fail by transaction. INFORMATION TECHNOLOGY SYSTEMS Since information systems play a vital role in The City’s trading abilities, the City shall ensure that the information systems and technology used to store all transaction information is maintained and secure. The City’s transactions will be stored in TEA’s enterprise trading and risk management system. TEA uses the TriplePoint Commodity XL (CXL) system, integrated with Commodity XL for Credit Risk (Credit Risk). TEA has assigned a Database Administrator (DBA) that is charged with the database security and maintenance for the transaction database, CXL. The following safeguards for data security and backup will be installed:  Transaction data stored in the system of record will be replicated daily to ensure data redundancy;  The CXL database will be backed up at least daily after the close of business. POLICY DISTRIBUTION AND COUNSEL A. Distribution Outside The City The City’s Policy is restricted to the use of the City and TEA organizations. It shall not be distributed outside these organizations without the consent the ERMC. B. Designated Counsel Questions about the interpretation of any matters of this Policy should be referred to ERMC. The ERMC will provide clarification and explanation on any updates to this Policy. All legal matters stemming from this Policy will be referred to the City’s Legal Counsel. 16

APPENDIX A – Approved Products The following shall constitute a list of approved forward hedge products to be utilized by TEA to manage the City’s energy commodity portfolio:  Forward Physical Power Peak  Forward Physical Power Off-Peak  Forward Physical Power All Hours  Forward Physical Natural Gas Delivered Dover via Eastern Shore Pipeline  Forward Physical Residual Fuel Oil (#6) Delivered Dover  Forward Physical Residual Fuel Oil (#2) Delivered Dover  Capacity  Forward Financial Power Peak  Forward Financial Power Off-Peak  Forward Financial Power All Hours  Financial Call Option  Financial Put Option  PJM Demand Bids and Generation Offers  PJM InSchedules  PJM Transmission Products o Financial Transmission Rights o Annual Auction Revenue Rights  PJM Tier 2 Synchronized Reserves The above instruments can be executed by TEA on behalf of the City of Dover for the current and next two successive Power Years (July to June). 17

APPENDIX B – Approved Counterparties and Threshold Tables This Appendix establishes approved counterparties and their Collateral thresholds. Collateral thresholds, term limitations and credit exposure limits that are subject to the following maximums based upon the lower of the S&P and Moody’s credit ratings: Credit Thresholds from Dover Extended to the Counterparty Constellation Energy Threshold S&P Moody's $ 60,000,000 AAA Aaa $ 50,000,000 AA‐ to AA+ Aa3 to Aa1 $ 50,000,000 A‐ to A+ A3 to A1 $ 40,000,000 BBB+ Baa1 $ 30,000,000 BBB Baa2 $ 20,000,000 BBB‐ Baa3 $ ‐ Below BBB‐ Below Baa3 Integrys Threshold S&P Moody's $ 20,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ Aa3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ 1,000,000 BBB‐ Baa3 $ ‐ Below BBB‐ Below Baa3 Sempra Energy Threshold S&P Moody's $ 20,000,000 A or above A2 or above $ 20,000,000 A‐ to A+ A3 $ 15,000,000 BBB+ Baa1 $ 10,000,000 BBB Baa2 $ ‐ BBB‐ or lower Baa3 or lower Conectiv Threshold S&P Moody's Unspecified * Above BBB+ Above Baa3 $ ‐ Below BBB‐ Below Baa3 * Conectiv does not have a defined credit threshold, so for planning purposes, a 18

$10,000,000 threshold is imposed as a conservative limit Macquarie Cook Power Threshold S&P Moody's $ 25,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ Aa3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below FPL Energy Threshold S&P Moody's $ 30,000,000 AAA Aaa $ 25,000,000 AA‐ to AA+ Aa3 to Aa1 $ 20,000,000 A‐ to A+ A3 to A1 $ 15,000,000 BBB+ Baa1 $ 10,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below Deutsche Bank Threshold S&P Moody's $ 25,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ Aa3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below Barclays Bank Threshold S&P Moody's $ 25,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ Aa3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below 19

Credit Thresholds from the Counterparty Extended to Dover Constellation Energy Threshold Fitch Moody's $ 40,000,000 AA‐ or Above Aa3 or above $ 30,000,000 A+ A1 $ 20,000,000 A A2 $ 10,000,000 A‐ A3 $ ‐ BBB or below Baa1 or below Integrys Threshold Fitch Moody's $ 20,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ Aa3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ 1,000,000 BBB‐ Baa3 $ ‐ Below BBB‐ Below Baa3 Sempra Energy Threshold Fitch Moody's $ 27,000,000 A‐ or above A3 or above $ 5,000,000 BBB+ Baa1 $ 1,000,000 BBB Baa2 $ ‐ BBB‐ or lower Baa3 or lower Conectiv Threshold Fitch Moody's Unspecified * Above BBB+ Above Baa3 $ ‐ Below BBB‐ Below Baa3 *Conectiv does not have a defined credit threshold, so for planning purposes, a $10,000,000 threshold is imposed as a conservative limit 20

Macquarie Cook Power Threshold Fitch Moody's $ 25,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ AA3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below FPL Energy Threshold Fitch Moody's $ 23,000,000 AAA Aaa $ 18,000,000 AA‐ to AA+ AA3 to Aa1 $ 13,000,000 A‐ to A+ A3 to A1 $ 8,000,000 BBB+ Baa1 $ 3,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below Deutsche Bank Threshold Fitch Moody's $ 25,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ AA3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below Barclays Bank Threshold Fitch Moody's $ 25,000,000 AAA Aaa $ 20,000,000 AA‐ to AA+ AA3 to Aa1 $ 15,000,000 A‐ to A+ A3 to A1 $ 10,000,000 BBB+ Baa1 $ 5,000,000 BBB Baa2 $ ‐ BBB‐ or below Baa3 or below 21

APPENDIX C – Business Risks Business Risks Topology Commodity Counterpart Process Risk Volume Risk Budget Risk Risk y Risk Receivables Market Load Market Price Risk Risk Deadline Risk Uncertainty Uncertainty Performance Reporting Load Volume Risk Supply Risk Risk Risk Uncertainty M2M/Forward Generation Forecast Error Curve Risk Uncertainty Liquidity Risk Basis Risk 22

APPENDIX D – Glossary Back Office – That part of a trading organization which handles transaction accounting, confirmations, management reporting, and working capital management. Bilateral Transaction - Any physical or financial transaction between two counterparties, neither of whom is an Exchange or market entity (e.g. MISO). Capacity – The real power output rating of a generator or system, typically in megawatts, measured on an instantaneous basis. Commodity - A basic good used in commerce that is interchangeable with other commodities of the same type. Commodities are most often used as inputs in the production of other goods or services. The quality of a given commodity may differ slightly, but it is essentially uniform across producers. When they are traded on an exchange, commodities must also meet specified minimum standards, also known as a basis grade. Financial Bilateral Transaction – A Bilateral Transaction that is non-physical and is defined by a Source Point, Sink Point, and Delivery Point that may be any CP Nodes as specified by the Midwest ISO. Financial Forward – An agreement regarding a position in a specified commodity, a specified price, and a specified future settlement date, that does not result in physical delivery of the commodity. Rather one party in the agreement makes a payment to the other party on the basis of the commodity price at the future date. Front Office – That part of a trading organization which solicits customer business, services existing customers, executes trades and ensures the physical delivery of commodities. Hedging Transaction - A transaction designed to reduce the exposure of a specific outstanding position or portfolio; “fully hedged” equates to complete elimination of the targeted risk and “partially hedged” implies a risk reduction of less than 100%. Mark-to-Market Value – A measure of the current value of unrealized positions; includes both Open Positions and Closed Positions. Middle Office – That part of a trading organization that measures and reports on market risks, develops risk management policies and monitors compliance with those 23

policies, manages contract administration and credit, and keeps management and the Board informed on risk management issues. Policy – Dover’s Governing Policy for Energy Commodity Risk, as amended and approved by The Utility Committee. Portfolio – A collection of transactions. Realized Gains/(Losses) – The amount earned (or lost) from a transaction , considered to be realized once the time for performance has lapsed (e.g. delivery of power in the case of physical transactions or expiration of an option in the case of financial transactions). Term – The total duration of a contract, defined as the number of days between the beginning flow date and ending flow date, inclusive. Unrealized Gains/ (Losses) – The amount expected to earn (lose) on a specific transaction(s); however, the time for performance has not lapsed. The total value of Unrealized Gains/ (Losses) is the Mark-to-Market value. 24

APPENDIX D – Swap Transaction Representative Purpose: To ensure that the City of DoverXXXX, a Special Entity under the Dodd-Frank Financial Reform Act, selects a qualified representative (“Representative”) to provide advice and guidance when entering into swap transactions with Swap Dealers or Major Swap Participants. Definitions: Special Entity: As defined in 7 U.S.C. 6s(h)(2)(C) and further interpreted in 17 C.F.R. 23.401(c). XXXXThe City of Dover is a Special Entity as defined by 17 C.F.R. 23.401(c)(2). Swap Dealer: As defined in 7 U.S.C. 1a(49) and further interpreted in 17 C.F.R. 1.3(ggg) Major Swap Participant: As defined in 7 U.S.C. 1a(33) and further interpreted in 17 C.F.R. 1.3(hhh) Representative: As defined in this policy and 17 C.F.R. 23.450 Policy: Selection: XXXXThe City of Dover shall endeavor to seek and employ an individual or entity that will voluntarily act as a Representative for all energy commodity swap transactions between XXXX and any Swap Dealer or Major Swap Participant. The Representative must meet the following qualifications identified in 17 C.F.R. 23.450(b): (i) Has sufficient knowledge to evaluate the transaction and risks; (ii) Is not subject to a statutory disqualification; (iii) Is independent of the swap dealer or major swap participant; (iv) Undertakes a duty to act in the best interests of the Special Entity it represents; (v) Makes appropriate and timely disclosures to the Special Entity; (vi) Evaluates, consistent with any guidelines provided by the Special Entity, fair pricing and the appropriateness of the swap; and (vii) In the case of a Special Entity as defined in § 23.401(c)(2) or (4), is subject to restrictions on certain political contributions imposed by the Commission, the Securities and Exchange Commission, or a self-regulatory organization subject to the jurisdiction of the Commission or the Securities and Exchange Commission; provided however, that this paragraph (b)(1)(vii) of this section shall not apply if the representative is an employee of the Special Entity. The Representative and XXXXthe City of Dover shall enter into a legal agreement that binds the Representative to comply with items (i) through (vii) in this policy. 25

At no longer than any 12 month interval, the City of Dover XXXX shall review the performance of the Representative to ensure compliance with items (i) through (vii) in this policy. 26

City of Dover Capital Investment Plan Project Tracking Report Quarterly Report as of March 31, 2014 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 W ater & Total Current Year Budget Funding Sources General Transportation W astewater Electric CIP Budget Balance $ 2,961,200 $ 209,200 $ 4,734,000 $ 518,300 $ 8,422,700 Restricted MSA (non Public Safety) 251,200 - - - 251,200 Contractor Contributions 264,800 - - - 264,800 General Billings for Reimbursement of Expense - - - 440,000 440,000 Debt Financing - - 4,129,900 - 4,129,900 Other State/Federal Grants 165,000 - - - 165,000 Impact Fee Reserves - - 390,000 - 390,000 State Community Transportation Funds 60,500 1,308,700 - - 1,369,200 Gifts/Donations 5,000 - - - 5,000 Transfer from Impact Fee Reserve - - 1,000,000 - 1,000,000 Transfer from General Fund 1,278,300 - - 1,278,300 Transfer from Operating Funds - - 2,563,200 4,918,600 7,481,800 Transfer from Parkland Reserve 80,000 - - - 80,000 Interest Income - 500 25,000 25,200 50,700 Total Funding Sources (Unaudited) $ 5,066,000 $ 1,518,400 $ 12,842,100 $ 5,902,100 $ 25,328,600

City of Dover General Fund - Major CIP Projects Quarterly Report as of March 31, 2014 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project Current Revised Fiscal Project Project Project To Date Budget % Budget Fiscal Year Fiscal Year YTD Budget % Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Balance Spent Status Comments 1 FY 2009 2 LB0901 M/G/L New Library Project $ 18,200,000 $ 20,469,100 $ 20,450,297 $ 18,803 99.9% $ - $ 411,500 $ 76,198 $ 335,302 18.5% Complete LEED Certification complete in FY 2014 3 Totals - FY 2009 $ 18,200,000 $ 20,469,100 $ 20,450,297 $ 18,803 99.9% $ - $ 411,500 $ 76,198 $ 335,302 18.5% 4 5 FY 2013 Asbestos survey done of building; Future 6 PR1301 Roof Replacement @ Dover Park $ 30,000 $ 30,000 $ 6,995 $ 23,005 23.3% $ - $ - $ - $ - 0.0% On Hold plans for building being evaluated 7 ST1302 Street & Alley Program - 1,414,500 - 1,414,500 0.0% - - - - 0.0% FY 2014 Moved to General Capital Projects Fund 8 ST1304 Garrison Farm Improvements 1,924,000 2,000,000 124,642 1,875,358 6.2% - 1,936,100 60,705 1,875,395 3.1% In process Financed by Future Capacity Reserve 9 ST1405 G FY 2012 MSA - Capital non-safety - 265,215 89,722 175,493 33.8% - 251,200 75,759 175,441 30.2% In process Restricted MSA Funding 10 11 Totals - FY 2013 $ 1,954,000 $ 3,709,715 $ 221,359 $ 3,488,356 6.0% $ - $ 2,187,300 $ 136,464 $ 2,050,836 6.2% 12 13 FY 2014 14 --- Vehicles & Equipment $ 963,800 $ 963,900 $ 517,723 $ 446,177 53.7% $ 909,700 $ 963,900 $ 517,723 $ 446,177 53.7% In process 15 CS1402 Security Cameras/Fence 55,000 55,000 - 55,000 0.0% 55,000 55,000 - 55,000 0.0% 16 FR1400 Annual Contribution to Robbins Hose 238,500 238,500 238,515 (15) 100.0% 238,500 238,500 238,515 (15) 100.0% Complete Truck Payments 17 IT1400 Server & Backup Solution 7,000 7,000 - 7,000 0.0% 7,000 7,000 - 7,000 0.0% 18 PD1401 Copier Replacement 10,000 9,100 8,865 235 97.4% 10,000 9,100 8,865 235 97.4% In process 19 PD1402 Totaled Vehicle Replacement 20,000 20,000 - 20,000 0.0% 20,000 20,000 - 20,000 0.0% 20 PR1401 A/C System @ Pitts Center 65,000 65,000 - 65,000 0.0% 65,000 65,000 - 65,000 0.0% 21 PR1402 Schutte Park Land Improvement 30,000 30,000 - 30,000 0.0% 30,000 30,000 - 30,000 0.0% 22 ST1402 FY 2014 Concrete Program 70,000 45,500 2,680 42,820 5.9% 70,000 45,500 2,680 42,820 5.9% In process Bids going out in February 23 ST1403 B/L FY 2014 Bonded Street Program 740,000 692,100 335,445 356,655 48.5% - 692,100 335,445 356,655 48.5% In process Approximately 70% complete 24 PD1302 Police Parking Lot 50,000 51,800 - 51,800 0.0% - 51,800 - 51,800 0.0% 25 ST1404 Village of Westover IV 264,800 264,800 135,431 129,369 51.1% - 264,800 135,431 129,369 51.1% 26 ST1406 Wesley College Infrastructure Reimb 24,500 24,500 24,500 0.0% - 24,500 - 24,500 0.0% 27 28 Totals - FY 2014 $ 2,538,600 $ 2,467,200 $ 1,238,659 $ 1,228,541 50.2% $ 1,405,200 $ 2,467,200 $ 1,238,659 $ 1,228,541 50.2% 29 30 31 Grand Totals $ 22,692,600 $ 26,646,015 $ 21,910,316 $ 4,735,699 82.2% $ 1,405,200 $ 5,066,000 $ 1,451,322 $ 3,614,678 28.6% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is re-budgeted to start over each fiscal year. G = Grant funded project B/L = To be financed through bonds or commercial loan.

City of Dover Community Transportation & General Fund Street Funds - Major CIP Projects (Final) Quarterly Report as of March 31, 2014 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project Current Revised Fiscal Project Project Project To Date Budget % Budget Fiscal Year Fiscal Year YTD Budget % Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Balance Spent Status Comments 1 FY 2002 Authorization from Legislature to reallocate to South Street and project should finish by end of 2 CT0212 South Street paving $ 80,400 $ 80,400 $ - $ 80,400 0.0% $ - $ 80,400 $ - $ 80,400 0.0% year 3 Totals - FY 2002 $ 80,400 $ 80,400 $ - $ 80,400 0.0% $ - $ 80,400 $ - $ 80,400 0.0% 4 5 FY 2009 6 CT0555 Little League Park paving $ 11,600 $ 11,600 $ - $ 11,600 0.0% $ - $ - $ - $ - 0.0% Re-program for signage 7 Totals - FY 2009 $ 11,600 $ 11,600 $ - $ 11,600 0.0% $ - $ - $ - $ - 0.0% 8 9 FY 2007 10 CT0708 E. Water Street Brick $ 65,000 $ 65,000 $ - $ 65,000 0.0% $ - $ - $ - $ - 0.0% Specialty contract needed 11 Totals - FY 2007 $ 65,000 $ 65,000 $ - $ 65,000 0.0% $ - $ - $ - $ - 0.0% 12 13 FY 2009 Trying to re-program for Schutte 14 CT0977 M Schutte Parking Lot $ 22,000 $ 22,000 $ - $ 22,000 0.0% $ - $ - $ - $ - 0.0% park sidewalk 15 Totals - FY 2009 $ 22,000 $ 22,000 $ - $ 22,000 0.0% $ - $ - $ - $ - 0.0% 16 17 FY 2012 18 CT1201 M North Street Roundabout $ 500,000 $ 572,200 $ 228,427 $ 343,773 39.9% $ - $ 572,200 $ 228,427 $ 343,773 39.9% 35% Site work initiated 19 TE0601 M Lincoln Park Center 900,000 1,423,500 523,277 900,223 36.8% - - - - 0.0% Started On-going 20 Totals - FY 2012 $ 1,400,000 $ 1,995,700 $ 751,704 $ 1,243,996 37.7% $ - $ 572,200 $ 228,427 $ 343,773 39.9% 21 22 FY 2013 23 CT1317 Wesley College Phase I 148,600 119,240 119,240 (0) 100.0% $ - $ 79,985 $ 79,985 $ 0 100.0% Complete awaiting bill Transfer to General Fund for Security Prior year unused GF Allocation 24 MR1301 Cameras 102,400 102,400 102,400 - 100.0% - 54,200 54,160 40 99.9% moved to Capital Project Fund. 25 CT1369 Bayard Ave, Orchard Ave & Morris Dr. 130,000 289,378 120,613 168,765 41.7% - 289,378 120,613 168,765 41.7% FY 2013 CT agreement 26 Totals - FY 2013 $ 381,000 $ 511,018 $ 342,253 $ 168,765 67.0% $ - $ 423,563 $ 254,758 $ 168,806 60.1% 27 28 FY 2014 29 CTxxxx Unapplied CT Projects (placeholder) $ 500,000 $ 500,000 $ - $ 500,000 0.0% $ 500,000 $ 373,137 $ - $ 373,137 0.0% Future CT Agreements 30 ST1401 American Ave - 62,800 62,800 - 100.0% - 62,800 62,800 - 100.0% Prior year unused GF Allocation 31 Transfer to General Fund - 6,300 6,340 (40) 100.6% - 6,300 6,340 (40) 100.6% Prior year unused GF Allocation. 32 Totals - FY 2014 $ 500,000 $ 569,100 $ 69,140 $ 499,960 12.1% $ 500,000 $ 442,237 $ 69,140 $ 373,097 15.6% 33 34 Grand Totals $ 2,460,000 $ 3,254,818 $ 1,163,097 $ 2,091,721 35.7% $ 500,000 $ 1,518,400 $ 552,324 $ 966,076 36.4% 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 re-budgeted to start over each fiscal year. C = Project funded by combination of CT Funds and General Fund B/L = To be financed through bonds or commercial loan.

Water/Wastewater Improvement & Extension Fund - Major CIP Projects Quarterly Report as of March 31, 2014 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project % Approved Revised Fiscal % Status / Project Project Project To Date Budget Budget Fiscal Year Fiscal Year YTD Budget Budget % Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Balance Spent Complete Comments 1 FY 2008 2 WD0804 M 1.0 MG Elevated Water Storage $ 4,196,600 $ 2,556,000 $ 85,327 $ 2,470,673 3.3% $ 390,000 $ 2,473,500 $ 2,779 $ 2,470,721 0.1% 3.2% Design & land purchase underway 3 WD0805 M Piney Point Well 398,800 1,096,200 1,034,646 61,554 94.4% - 580,000 518,507 61,493 89.4% 85.0% Awarded bid JJID Feb. 2013 4 Totals - FY 2008 $ 4,595,400 $ 3,652,200 $ 1,119,973 $ 2,532,227 30.7% $ 390,000 $ 3,053,500 $ 521,286 $ 2,532,214 17.1% 5 6 FY 2009 7 WQ0907 SL/O Rt. 13 Water Main $ 1,023,700 $ 2,326,000 $ 2,314,772 $ 11,228 99.5% $ - $ 152,800 $ 141,577 $ 11,223 92.7% 100.0% Complete 6/30/13, in Litigation 8 9 FY 2010 10 WW1010 I Tar Ditch Interceptor Upgrade $ 518,200 $ 518,200 $ 50,082 $ 468,118 9.7% $ - $ 486,300 $ 18,110 $ 468,190 3.7% 6.2% Easement request sent to residents 11 12 FY 2013 Project awarded on 1/27, pre construction 13 WW1304 M Garrison Farm Improvements $ 1,828,000 $ 3,116,000 $ 243,643 $ 2,872,357 7.8% $ - $ 3,116,000 $ 135,481 $ 2,980,519 4.3% In Process meeting to follow. Project awarded, 95% design, 14 WD1302 M Garrison Farm Storage Tank 1,828,000 4,022,400 345,121 3,677,279 8.6% - 4,022,400 132,525 3,889,875 3.3% In Process construction to begin in Spring. Project designed, re-programmed for out 15 II1306 FY 2013 I & I Design 1,000,000 748,900 22,608 726,292 3.0% - - - - 0.0% year. 16 II1404 Basin #5 I & I Buck Drive - 342,000 10,963 331,037 3.2% - 342,000 10,963 331,037 3.2% In Process Project under design, 60% complete. 17 II1309 Dover Downs PS Upgrade - 16,000 15,864 136 99.2% - 16,000 15,864 136 99.2% Complete Completed by September 2013 18 II1310 Puncheon Run PS Upgrade - 21,000 20,020 980 95.3% - 21,000 20,020 980 95.3% Complete Completed in July 2013 19 Totals - FY 2013 $ 4,656,000 $ 8,266,300 $ 658,218 $ 7,608,082 52.2% $ - $ 7,517,400 $ 314,853 $ 7,202,547 4.2% 20 21 FY 2013 All vehicles have been ordered, awaiting 22 --- Vehicles & Equipment $ 354,000 $ 153,600 $ 62,890 $ 90,710 40.9% $ 354,000 $ 153,600 $ 62,890 $ 90,710 40.9% In Process delivery #422 (2/6/14) Contractor completed one wellhead 23 WD1401 Wellhead Redevelopment 75,000 75,000 31,685 43,315 42.2% 75,000 75,000 31,685 43,315 42.2% In Process redevelopment, started on second. 24 WD1403 Emergency Generators 80,000 60,000 - 60,000 0.0% 80,000 60,000 - 60,000 0.0% In Process Generator ordered, delivery late Feb. 25 WW1401 Inflow/Infiltration Removal 1,003,800 406,900 - 406,900 0.0% 1,013,800 406,900 - 406,900 0.0% In Process Buck Drive 60% designed Design 95% complete, DelDOT to bid out 26 TBD Denny's Road Water Main - 33,200 - 33,200 0.0% - 33,200 - 33,200 0.0% In Process 27 WD1201 I Pay-As-You-Go Water Station - 30,200 - 30,200 0.0% - 30,200 - 30,200 0.0% Staff finalizing bid documents 28 WD1304 Columbia Well - 34,800 25 34,775 0.1% - 34,800 25 34,775 0.1% no update 29 WQ1402 West Dover Connector - 11,000 6,637 4,363 60.3% - 11,000 6,637 4,363 60.3% In Process Design continuing, out to bid April 2014 30 WQ1401 Water Quality Improvements 905,000 - - - 0.0% 905,000 - - - 0.0% no update Design complete. Purchase materials in 31 WW1204 Baltray Pump Station - 104,100 - 104,100 0.0% - 104,100 - 104,100 0.0% In Process February 2014 32 WW1205 Dover Brook Pump Station - 52,800 - 52,800 0.0% - 52,800 - 52,800 0.0% Bids due April 15, 2014. 33 WW1206 Brandywine Pump Station - 368,100 640 367,460 0.2% - 368,100 640 367,460 0.2% In Process Design 95% complete, need to acquire 34 WW1207 McKee PS - 47,300 - 47,300 0.0% - 47,300 - 47,300 0.0% Need to rebid project. 35 WW1301 Hazeltville Rd Interceptor - 30,000 - 30,000 0.0% - 30,000 - 30,000 0.0% Survey to begin in coming weeks. 36 WW1302 Lakeview PS - 52,000 - 52,000 0.0% - 52,000 - 52,000 0.0% Survey to begin in coming weeks. 37 WW1303 Westover PS - 65,000 - 65,000 0.0% - 65,000 - 65,000 0.0% Survey to begin in coming weeks. 38 II1401 Kent Ave. Repair - 75,000 20,903 54,097 27.9% - 75,000 20,903 54,097 27.9% In Process 95% complete 39 II1402 West Dover Connector - 33,100 19,912 13,188 60.2% - 33,100 19,912 13,188 60.2% Design continuing, out to bid April 2014 40 Totals - FY 2014 $ 2,417,800 $ 1,632,100 $ 142,692 $ 1,489,408 0.0% $ 2,427,800 $ 1,632,100 $ 142,692 $ 1,489,408 8.7% 41 42 Grand Totals $ 13,211,100 $ 16,394,800 $ 4,285,737 $ 12,109,063 26.1% $ 2,817,800 $ 12,842,100 $ 1,138,518 $ 11,703,582 8.9% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. R = Recurring project - a project that begins and ends each fiscal year and is re-budgeted to start over each fiscal year. SL = State Loan Project - construction phase is financed I = Impact Fee (partially) financed project O = Operating revenues

Electric Improvement & Extension Fund - Major CIP Projects Quarterly Report as of March 31, 2014 TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project % Current Revised Fiscal % Project Project Project To Date Budget Budget Fiscal Year Fiscal Year YTD Budget Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Balance Spent Status Comments 1 FY2012 2 EG1212 M Unit 3 Turbine Inspection/Repair $ 1,494,000 $ 1,653,536 $ 909,239 $ 744,297 55.0% $ 1,149,800 $ 1,149,800 $ 405,502 $ 744,298 35.3% In process Will complete Spring outage 3 EG1214 M Industrial WW Discharge System 272,000 272,000 283,767 (11,767) 104.3% - 8,000 9,418 (1,418) 117.7% Complete Expenses are a 100% 4 Totals - FY 2012 $ 1,766,000 $ 1,925,536 $ 1,193,006 $ 732,530 62.0% $ 1,149,800 $ 1,157,800 $ 414,920 $ 742,880 35.8% 5 6 FY 2013 7 EE1308 M Horsepond Substation Upgrade $ 761,800 $ 761,800 $ 392,345 $ 369,455 51.5% $ 591,800 $ 1,301,100 $ 361,494 $ 939,606 27.8% In process Under Construction 8 EE1312 M General Scott Switchgear 1,155,000 1,150,000 10,614 1,139,386 0.9% 800,000 55,000 10,614 44,386 19.3% In process Under Design 9 EE1314 Capitol Park Upgrade - 248,000 320,423 (72,423) 129.2% 248,000 220,551 27,449 88.9% In process Under Construction 10 EE1330 Morris Estates 1 Upgrade - 32,600 253,283 (220,683) 776.9% - 32,600 10,883 21,717 33.4% In process Under Construction 11 EG1312 Generator Repairs - 4,200 - 4,200 0.0% - 4,200 - 4,200 0.0% Complete Expenses are a 100% 12 Totals - FY 2013 $ 1,916,800 $ 2,196,600 $ 976,664 $ 1,219,936 44.5% $ 1,391,800 $ 1,640,900 $ 603,543 $ 1,037,357 36.8% 13 14 FY 2014 15 --- Vehicles & Equipment $ 660,000 $ 704,600 $ 267,939 $ 436,661 38.0% $ 660,000 $ 704,600 $ 267,939 $ 436,661 38.0% In Process Ordered 16 EE1401 Air Condition Replacement Monitors 12,000 12,000 - 12,000 0.0% 12,000 12,000 - 12,000 0.0% 17 EE1402 Substation Battery Replacement 24,500 24,500 - 24,500 0.0% 24,500 24,500 - 24,500 0.0% In Process Under Design 18 EE1403 Distribution Upgrades 400,000 61,000 - 61,000 0.0% 400,000 61,000 - 61,000 0.0% 19 EE1404 Lighting Improvements 50,000 50,000 46,920 3,080 93.8% 50,000 50,000 46,920 3,080 93.8% In Process Under Construction 20 EE1405 Distribution Feeder Replacement Program 277,500 - - - 0.0% 277,500 - - - 0.0% 21 EE1406 Distribution Capacitors & Controls 60,000 60,000 29,328 30,672 48.9% 60,000 60,000 29,328 30,672 48.9% Complete Complete 22 EE1407 Transmission Line Maintenance Program 75,000 - - - 0.0% 75,000 - - - 0.0% 23 EE1408 Substation Switch Replacement 80,000 - - - 0.0% 80,000 - - - 0.0% 24 EE1410 Air Mobility Command - 13,500 31,801 (18,301) 235.6% - 13,500 31,801 (18,301) 235.6% In Process New Design 25 EE1411 Bergald Lane (DAFB) - 29,000 28,709 291 99.0% - 28,800 28,709 91 99.7% Complete Complete 26 EE1412 Capital City Trail - 26,500 21,448 5,052 80.9% - 26,500 21,448 5,052 80.9% Complete Complete 27 EE1413 Lebanon 400 Feeder - 20,000 11,774 8,226 58.9% - 20,000 11,774 8,226 58.9% In Process Material Ordered 28 EE1414 New Developments 600,000 144,000 89 143,911 0.1% 600,000 118,700 89 118,611 0.1% 29 EE1417 Bayside Drive (Persimmon Tree to White Oak Rd - 42,300 38,634 3,666 91.3% - 42,300 38,634 3,666 91.3% Complete Complete 30 EE1418 The Grande - 28,000 10,068 17,932 36.0% - 28,000 10,068 17,932 36.0% Complete Complete 31 EE1419 Home 2 Suites Hotel - 37,000 38,534 (1,534) 104.1% - 37,000 38,534 (1,534) 104.1% In Process Under Construction 32 EE1421 Richardson Circle Upgrade - 91,000 36,844 54,156 40.5% - 91,000 36,844 54,156 40.5% In Process Under Construction 33 EE1423 7-Eleven New Service - 5,800 4,397 1,403 75.8% - 5,300 4,397 903 83.0% Complete Complete 34 EE1424 McKee Run Substation Repairs - 45,000 - 45,000 0.0% - 45,000 35,820 9,180 79.6% In Process Under Construction 35 EE1425 EZ-Pass Delaware - 12,000 9,351 2,649 77.9% - 10,800 9,351 1,449 86.6% Complete Complete 36 EE1426 Eden Hill Entrance - 52,400 8,206 44,194 15.7% - 52,400 8,206 44,194 15.7% In Process Under Construction 37 EE1428 Tidewater General Green - 34,000 17,248 16,752 50.7% - 34,000 17,248 16,752 50.7% In Process Under Construction 38 EE1429 Clearview Meadows - 88,000 4,108 83,892 4.7% - 85,300 4,108 81,192 4.8% Not Started 39 EE1430 Calpine Equipment Move - 83,000 31,329 51,671 37.7% - 83,000 31,329 51,671 37.7% Complete Complete 40 EE1431 Generals Green Lighting - 20,500 3,411 17,089 16.6% - 20,500 3,411 17,089 16.6% In Process Under Construction 41 EE1432 Connective @ 409 Pickering Beach Rd - 20,200 555 19,645 2.7% - 20,200 555 19,645 2.7% In Process Under Construction 42 EE1433 Chandale Airport - - 13,581 (13,581) 0.0% - - 13,581 (13,581) 0.0% 43 EE1434 50 Wolfcreek - Dr. Patel - 6,100 4,345 1,755 71.2% - 6,100 4,345 1,755 71.2% In Process Under Construction 44 EE1435 Patriot Village - 29,900 27,563 2,337 92.2% - 29,900 27,563 2,337 92.2% In Process Under Construction Will complete Spring outage - 45 EG1402 Unit 3 Cooling Tower Repairs 42,000 42,000 31,575 10,425 75.2% 42,000 42,000 31,575 10,425 75.2% In Process PO for work issued 46 EG1404 McKee Run #3 Aux System Component 116,000 116,000 108,096 7,904 93.2% 116,000 116,000 108,096 7,904 93.2% In Process Will complete Spring outage 47 EG1405 VanSant #11 Component Replacement 32,000 32,000 30,588 1,412 95.6% 32,000 32,000 30,588 1,412 95.6% In Process Will complete Spring outage Will complete Spring outage - 48 EG1406 McKee Run Energy Pipe Replacement 80,000 80,000 3,340 76,660 4.2% 80,000 80,000 3,340 76,660 4.2% In Process PO for work issued Multi-year project - Design to 49 EG1407 Metering System Upgrades 25,000 25,000 - 25,000 0.0% 25,000 25,000 - 25,000 0.0% In Process be complete Spring 50 EG1408 McKee/VanSant Safety & Compliance 86,000 86,000 - 86,000 0.0% 86,000 86,000 - 86,000 0.0% In Process Will complete in Spring 51 EG1409 McKee Run Natural Gas Valves 65,000 65,000 - 65,000 0.0% 65,000 65,000 - 65,000 0.0% In Process Will complete Spring outage Work on hold pending 52 EG1413 McKee/VanSant Preserve Structure 42,000 42,000 - 42,000 0.0% 42,000 42,000 - 42,000 0.0% In Process additional funds needed 53 EG1415 McKee Run Units 1 & 2 component Replacement 105,000 105,000 31,173 73,827 29.7% 105,000 105,000 31,173 73,827 29.7% In Process Will Complete spring outage Multi-year project - Design to 54 EG1416 VanSant Capacity Increase 250,000 250,000 27,265 222,735 10.9% 250,000 250,000 27,265 222,735 10.9% In Process be complete Spring 55 TBD GOTP Transmission Line Relocation - 550,000 - 550,000 0.0% 550,000 - 550,000 0.0% Unplanned project 56 Totals - FY 2014 $ 3,082,000 $ 3,133,300 $ 918,219 $ 2,215,081 0.0% $ 3,082,000 $ 3,103,400 $ 954,039 $ 2,149,361 30.7% 57 58 Grand Totals $ 6,764,800 $ 7,255,436 $ 3,087,889 $ 4,167,547 37.3% $ 5,623,600 $ 5,902,100 $ 1,972,502 $ 3,929,598 33.4% Legend M = Multi-year project - a project with a specific schedule to occur over multiple years. B = Bonded Project R = Recurring project - a project that begins and ends each fiscal year and is re-budgeted to start over each fiscal year. S = State fully or partially reimbursed project

The Energy Authority, Inc. Monthly Management Committee Update – March 2014 April 24, 2014 Prepared by: Robert Trinnear Client Services Manager 904.360.1309 rtrinnear@teainc.org

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

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $244,610 over budget due to higher load. Dover’s budgeted cost for all power supply (capacity AND energy) was $80.71/MWh. The actual cost of all power supply (capacity AND energy) was $79.71/MWh. The cost of energy alone was $49.78/MWh, versus a budgeted energy cost of $47.58. Dover’s hedge purchases totaled 44,225 MWh, which was 73% of the actual load. The budgeted hedge purchase totaled 29,980, which was 53% of the budgeted load. Dover’s power purchases from hedge transactions totaled $2,101,245. Purchases from PJM (energy and fees) totaled $1,147,324 which included DA Energy purchases totaling $938,725 and Reactive Services Charges totaling $26,920. Dover’s total load was 60,865 MWh versus a forecasted load of 57,082 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1,605 MWh. Dover’s actual energy purchase from the SunPark installation was 1,346 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 57,082 60,865 (3,783) Wholesale Load 55,477 59,519 (4,042) Hedged Volume (MWh) 29,980 44,225 (14,245) Unhedged Volume (MWh) 25,497 15,294 10,203 Dover SunPark Volume (MWh) 1,605 1,346 259 Renewable Energy Credits Volume 241 149 92 Hedged Cost ($/MWh) $ 54.16 $ 47.51 $ 7 Unhedged Energy Cost ($/MWh) $ 37.35 $ 51.68 $ (14) Solar Energy Cost ($/MWh) $ 87 $ 102 $ (15) Energy Costs ($/MWh) $47.58 $49.78 ($2.20) All-in Costs - Energy, Capacity and RECs ($/MWh) $80.71 $79.71 $1.00 2

B. Generation Summary: Dover generated 0 MWh in the month. Net generation revenue was $1,009,044 vs. a budget of $999,294. 3

Generation Breakdown: City of Dover Monthly Wholesale Generation March, 2014 Net Generation 0 All In Generation PJM - Generation Economic and Reliability Dispatch $ - Generation Capacity Credit $ 1,329,125.00 Black Start and Transmission Losses $ 77,191.91 Natural Gas & Oil Consumption Purchases for Generation $ - Natural Gas Transport $ - Eastern Shore Cashout $ - Oil Consumption $ - Production Margin PJM - Generation Economic and Reliability Dispatch $ - Natural Gas & Oil Consumption Purchases for Generation $ - Natural Gas Transport $ - Eastern Shore Cashout $ - Oil Consumption $ - Gross Production Margin $ - $/MWh Generation Production Gross Margin $ - 4

C. Emissions Summary: Emissions Allowance Summary through February 28th, 2013 The CAIR units (McKee Run 3 & VanSant) did operate during the month of January, so there were additional emissions during this period. CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowances Seasonal Annual 1/1/09 2008 Carryover 3,240 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 2,039 50 78 1/1/11 2011 Allocation 1,988 49 78 4/1/11 2011 Reallocation 2 4 1/11/12 2012 Allocation 1,988 51 80 10/4/2012 2013 Allocation 1,988 49 76 2014 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 11/15/13 NOx Annual Sales (DEMEC) (5) 12/31/13 C.Y.T.D. 2013 Emissions (0) (20) (20) 2/28/14 2014 YTD Emissions (1.1) (0) (6.4) REMAINING ALLOWANCES 13,039.9 99 243.6 On August 21, 2012, a three-judge panel of the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s Cross State Air Pollution Rule (CSAPR) which would have become effective on January 1, 2012. The DCA instructed EPA to continue 1 Per CAIR, starting in 2009, NOx emissions are governed by a seasonal and annual program. 2 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 5

administering the Clean Air Interstate Rule (CAIR). In response to an EPA appeal to the U.S. Supreme Court, the Supreme Court heard arguments on December 10th, 2013. The Court did not indicate when it plans to release an opinion in the CSAPR case. In a related proceeding, at the end of 2013, Governors from eight Northeastern states petitioned EPA to add nine Southern and Midwestern states to the Ozone Transport Region (OTR). If the Supreme Court rules against EPA in the CSAPR case, EPA would need to act on the OTR petition within 18 months of its filing. Market liquidity for CAIR allowances continues to be low, with few transactions occurring. The following table shows estimated values for Dover’s banked allowances, based on broker bids & offers: Mark-to-Market for CAIR Allowances (3/20/2014) Commodity $/Ton Tons Extended (Bid/Offer Avg.) Value SO2 Allowances (2009 & earlier) $ 1.35 5,089 $ 6,870 SO2 Allowances (2010-13) $ 0.65 7,950.9 5,168 NOx Allowances - Seasonal $18.00 99 1,782 NOx Allowances - Annual $40.00 243.6 9,744 TOTAL $23,564 Regional Greenhouse Gas Initiative The State of Delaware is a participant in the Regional Greenhouse Gas Initiative (RGGI). The City of Dover must comply with RGGI by surrendering carbon dioxide (CO2) allowances pursuant to the State of Delaware’s laws (Title 7, Chapter 60, Sub-Title II-A). Delaware has elected a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). 6

CO2 Allowance Summary (2/28/2014) 1 2 3 4 5 6 7 8 CO2 Allowances Annual CO2 CO2 (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance Allowances Prior to Sale) CO2 Vintage Sold YTD Allowances Emitted Allowance Balance McKee Balance VanSant Run 2009 0 60,128 2,056 62,184 (5,796) 56,388 56,388 2010 0 48,102 1,645 49,747 (32,971) 16,776 73,164 2011 0 36,077 1,234 37,311 (17,763) 19,548 92,712 2012 0 27,058 925 27,983 ( 15,265) 11,793 104,505 3 2013 0 15,032 514 24,818 (10,231) 16,091 119,091 2014 0 -0- -0- -0- (4,458) 114,634 After 2013, Dover no longer receives allocations of RGGI allowances. The Cumulative Balance (column 8) – aka “Banked Allowances”) can be utilized for generation in 2014 and future years. Once the banked allowances have been fully utilized, Dover will be required to purchase RGGI allowances through the auctions or through over-the-counter markets. Assuming that Dover does not sell any banked allowances, it will be able to maintain a positive balance through 2016–2025, depending on actual annual energy production in 2012 and beyond. On February 7, 2013, RGGI proposed changes to its Model Rule. The Delaware Department of Natural Resources published the final rule on December 1, 2013 the Delaware Register of Regulations with an effective date of December 11, 20134. NOTE: The new RGGI rule includes a provision which will eliminate some portion of banked allowances in future years. TEA will be investigating the potential impact of this provision on Dover’s RGGI allowance bank. Dover could elect to sell all or a portion of its banked allowances now and re-acquire allowances at a later date; however TEA is currently of the opinion that Dover will be better off retaining its banked allowances for use during future compliance years. The most recent RGGI auction occurred on March 5th, 2014; the auction cleared at $4.00/ton. The next auction will occur on June 4th, 2014. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on March 20th, 2014 ranged from $4.26 to $4.48/ton, depending settlement month. Based on the March 20th, 2014 3 Includes Q3 2013 allocations of 7,846,757 for McKee Run and 1,424,677 for VanSant. 4 http://regulations.delaware.gov/register/december2013/final/17%20DE%20Reg%20644%2012-01-13.pdf 7

Intercontinental Exchange prices for March, 2014 ($4.26/ton), the value of Dover’s existing 114,634 ton RGGI allowance bank is $488,341. Renewable Energy Certificates Dover owns two photovoltaic systems totaling 15 kW, consisting of (one 5 kW unit at the Utilities Administration Building and two 5 kW units at the McKee Run generating station. Dover also receives solar energy produced by the 10 MW Dover Sun Park which is owned by White Oak Solar Energy, LLC. In addition to the all of the physical energy produced by the Sun Park, Dover receives 15% of Sun Park’s SRECS. Through the end of January 2014, Dover has accumulated a total of 6,8525 SRECS from these renewable energy resources. The nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s March 3, 2014 SREC auction cleared separately for 2012/2013 through 2013/2014 vintage allowances. Clearing prices and Dover’s SREC market value estimate are shown in the table below. SREC Vintage Auction Clearing Price SREC Quantity Market Value (June 1 – May 31) $ 4.01 2010/2011 13 $ 52 (Aug-13 Auction) $ 40.01 2011/2012 2,375 95,024 (Jan 2014 Auction) $55.00 2012/2013 2,725 149,875 (March 2014 Auction) $55.00 2013/2014 1,739 96,645 (March 2014 Auction) TOTAL 6,852 $341,596 TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard which DEMEC is working on. Once Dover has an approved RPS in place, it may be required to retire a portion of its current SREC balance for compliance in the 2012/13 future compliance year. Any remaining SRECs could be used for the 2013/14 compliance year. NOTE: SRECs in both Delaware and Pennsylvania expire without value after 3 years. Dover currently has thirteen (13) 2010/2011. Based on a recent discussion with DEMEC staff, this expiration provision is not likely to be of concern within the current compliance year. If Dover has not accumulated adequate non-solar RECs, it will need to acquire some from DEMEC for the 2013/2014 compliance year. DEMEC has told TEA that it will likely have sufficient non-solar RECs for Dover’s requirements. Dover can purchase and 5 Includes 121 RECs for Sun Park generation in January 2014 which had not been posted to Dover’s PJM GATS account as of March 24 th, 2014. 8

retire a portion of these non-solar RECs during the current compliance and fiscal years, or it can defer acquisition until the June – August, 2014 time frame, after the exact amount of non-solar REC requirements is known. D. Operations Management Summary: During the month of March there were no reportable or lost time accidents or injuries. The facility has now gone 1,261 days without an OSHA recordable accident and 1,261 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued and no Near Miss incidents. In the month of March there were no units dispatched by PJM. All units were in planned outage starting March 3. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of March were $397,273 against a budgeted amount of $360,411 for an unfavorable variance of $36,862 or 10.23%. The principal reasons for the unfavorable variance were due to unscheduled overtime, higher water, sewer, and electrical costs to support unscheduled generation in February. Also contributing to the unfavorable variance was the unanticipated repairs to the continuous emissions monitoring equipment on Unit 3. E. Risk Management Summary: Forward power prices in PJM are higher than last month, especially later in the hedging time horizon. The current projected cost of service is below: Blended Cost Monthly Change PY Hedge Ratio ($/MWh) ($/MWh) 2013-14 78% $ 51.98 $ (0.21) 2014-15 66% $ 46.97 $ 0.53 2015-16 53% $ 43.54 $ 1.04 2016-17 18% $ 42.63 $ 1.47 2017-18 10% $ 43.98 $ 2.00 9

II. Budget Report Variance Report: Budget Actual Variance Mar-14 Mar-14 Gross Load 57,082 60,865 (3,783) Power Supply Hedged Energy $1,623,666 $2,101,245 ($477,579) PJM - Energy, Congestion & Losses $952,341 $790,461 $161,880 PJM - ARR, Transmission and Fees $395,000 $356,863 $38,137 Dover SUN Park Energy $139,688 $137,856 $1,833 Dover SUN Park RECs $25,000 $21,304 $3,696 Management Fees $83,000 $83,000 $0 PJM - Capacity UCAP Obligated Purchased $1,388,224 $1,360,801 $27,423 Subtotal - Power Supply $4,606,919 $4,851,529 ($244,610) Power Generation O&M Plant O&M $360,411 $397,273 ($36,862) Subtotal Generation O&M 360,411.00 397,273.00 ($36,862) Power Generation Production Margin PJM - Economic and reliability dispatch $0 $ - $0 Fixed Fuel and Transport Charges $0 $ - $0 Subtotal Generation Production Margin $0 $ - $0 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($1,329,125) ($1,329,125) $0 Emissions Allowance Sales $0 $0 $0 PJM - Black Start & Transmission Losses ($30,580) ($77,192) $46,612 Subtotal - Non-Production Revenue ($1,359,705) ($1,406,317) $46,612 SubTotal - All Generation ($999,294) ($1,009,044) $9,750 Total - Utilities Cost $3,607,625 $3,842,485 ($234,860) Unit Costs Total - Power Supply $80.71 $79.71 $1.00 Total - Power Generation ($17.51) ($16.58) ($0.93) Final Cost of Service to City of Dover Ratepayers $63.20 $63.13 $0.07 10

Variance Analysis: Power Supply  Dover consumed 3,783 MWh more than forecast for the month.  PJM energy costs were higher than expected as high market prices occurred during the month driven by below normal temperatures. Hedged costs were higher than forecasted due to an additional layering in of hedges. PJM Fees were slightly lower than budget.  Hedges were placed at below budget levels and offset the higher market prices. This resulted in a net power supply cost of $79.71/MWh, $1.00/MWh below budget.  For the month, the city realized an unfavorable variance of $244,610 for power supply vs. the monthly budget.  Dover Sun Park generated 259 MWh less than forecast. Generation  Power generation had a favorable budget variance of $9,750.  Plant O&M expenses had an unfavorable budget variance of $36,862 for the month. 11

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 563,622 586,333 (22,711) Power Supply Hedged Energy $19,419,972 $22,528,491 ($3,108,519) PJM - Energy, Congestion & Losses $9,127,628 $14,195,228 ($5,067,600) PJM - ARR, Transmission and Fees $3,555,000 $6,139,600 ($2,584,600) Dover SUN Park Energy $1,012,703 $1,175,760 ($163,056) Dover SUN Park RECs $225,000 $266,194 ($41,194) Management Fees $747,000 $747,000 $0 PJM - Capacity UCAP Obligated Purchased $12,270,107 $12,045,046 $225,061 Subtotal - Power Supply $46,357,410 $57,097,319 ($10,739,909) Power Generation O&M Plant O&M $4,011,395 $3,995,798 $15,597 Subtotal Generation O&M $4,011,395 $3,995,798 $15,597 Power Generation Production Margin PJM - Economic and reliability dispatch ($230,472) ($5,371,245) $5,140,774 Fixed Fuel and Transport Charges $0 $2,126,863 ($2,126,863) Subtotal Generation Production Margin ($230,472) ($3,244,382) $3,013,910 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($11,747,750) ($11,747,750) $0 Emissions Allowance Sales $0 $0 $0 PJM - Black Start & Transmission Losses ($305,220) ($1,017,271) $712,051 Subtotal - Non-Production Revenue ($12,052,970) ($12,765,021) $712,051 SubTotal - All Generation ($8,272,047) ($12,013,605) $3,741,559 Total - Utilities Cost $38,085,364 $45,083,714 ($6,998,351) Unit Costs Total - Power Supply $82.25 $97.38 ($15.13) Total - Power Generation ($14.68) ($20.49) $5.81 Final Cost of Service to City of Dover Ratepayers $67.57 $76.89 ($9.32) 12

III. Operations Management NAES Corporation Dover, Delaware March 2014 Monthly Report Unit 3 Turbine Undergoing Inspection and Overhaul 13

Table of Contents 1.0 Environmental, Health, and Safety 2.0 Financial 3.0 Operations 4.0 Maintenance 5.0 CIP 6.0 General Plant Information 7.0 Summary of NAES Performance 14

1.0 Environmental, Health and Safety: During the month of March, there were no restricted work days or lost time accidents. The facility has now gone 3 years and 166 days (1,261 days) through March, 2014 without an OSHA Recordable Accident or a Lost Time reportable accident. There were no Near Miss incidents during the month. The plant received no Notice of Violations (NOVs) during the month. The March (February Discharge) DMR was submitted for the McKee Run site with no NPDES exceedences. There were no opacity deviations during the month. During the month of March, there were no IWW discharges to the Kent County Sewer. The February SIU Report was submitted to Kent County. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (March) (7/1/13-6/30/14) NOVs 0 0 Opacity Deviations 0 11 Environmental Deviations 0 0 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 2 Man Hours Worked 4,585.50 38,816.50 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,261 Days since last Lost Time Accident 1,261 15

Emissions (NOx, CO2 & SO2) All data thru 3/31/14 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2011 1.8 1.5 31.4 1.4 36.1 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 2014 0.0 0.0 0.0 0.0 0.0 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2011 1.8 1.5 32.6 2.9 38.8 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 2014 0.5 0.5 3.5 2.9 7.4 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2011 0.0 0.0 0.1 0.5 0.6 2012 0.0 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 2014 0.0 0.0 0.5 0.6 1.1 CO2 Allowances Summary CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Sold YTD Sale) Balance McKee Run VanSant 2009 0 60,128 2,056 5,796 56,388 2010 0 48,102 1,645 32,971 16,776 2011 0 36,077 1,234 17,763 19,548 2012 0 27,058 925 15,265 11,793 2013 0 22,879# 1,939# 10,231 14,587 2014 0 0 0 4,458 (4,458) Total CO2 Allowance Balance 114,634 *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. Note: All emissions (NOx, SO2 and CO2) totals for 2013 are unofficial. #Note: Additional CO2 Emission Values were added to 2013 balances by RGGI COATS- 7,846.757 for McKee Run and 1,424.677 for VanSant 16

CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant Run McKee Run - Run (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2010 and 3*** 27/0 0/2 earlier 2011 0 77/48 5/3 33/31– 3/1 0/0 - 0/0 42/10 2/2 2012 2** 75/46 5/3 36/36 – 1/1 0/0 - 0/0 39/10 2/0 2013 5** 77/48 5/3 19/19 – 1/1 0/0 - 0/0 58/24 4/2 2014 0 71/46 5/3 3.5/0 - 2.9/0 0/0 – 0/0 67.5/46 2.1/3 Total NOx Allowance Balance 233.5/90 10.1/9 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. **Note – The facility transferred Ozone Season allowances to a third party. SO2 Allowances Summary SO2 Allowances Available Total SO2 Tons (Per Unit, Prior to Sale & Emitted – SO2 Allowances SO2 Allowance SO2 Allowances Reconciliation) U3 and U11 Balance Vintage Sold - YTD Unit #3 Unit #11 YTD 2010 and earlier 0 4815 276 0 5089 2011 0 1850 138 1 1988* 2012 0 1850 138 1 1988* 2013 0 1850 138 0 1988* 2014 0 1850 138 1.1 1986.9 Total SO2 Allowance Balance 13,039.9 *Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 17

2.0 Financial Financial – Current Month Month – March Actual Budget Variance Personnel 245,469 254,880 9,411 Materials & Supplies 13,969 10,325 (3,644) Administrative Expenses 137,835 95,206 (42,629) Total $397,273 $360,411 ($36,862) Financial – Fiscal Year to Date Number of Months – 9 Actual Budget Variance Personnel 2,225,548 2,450,100 224,552 Materials & Supplies 147,491 179,665 32,174 Administrative Expenses 1,442,795 1,382,110 (60,685) Total $3,815,834 $4,011,875 $196,041 2.1 Variance analysis: The actual expenses for the month of March are $397,273 against a budgeted amount of $360,411 for an unfavorable variance of $36,862 or 10.23%. The variance was due to the following: PERSONNEL EXPENSES – A favorable monthly variance of $9,411 was due to having a less than full complement of employees (Straight Time Labor), although a portion of this savings was offset by higher than budgeted overtime expenses. The corresponding Labor Burden costs were also lower than budgeted for the month of March. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $3,644 was due to higher water – sewer costs than anticipated in order to support generation unit operations in late February. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $42,629 due primarily to unanticipated environmental costs, higher than anticipated electricity costs to support generation unit operations in late February, and repair costs to maintain the CEMS equipment. The forecasted expenses for this fiscal year are $5,787,284 expensed versus an approved budget of $6,015,800 thereby realizing a 96.20% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips No units were dispatched by PJM and none were self-dispatched for the month of March. All units started the spring outage at 0700 hours on March 3, 2014. Month March 2014 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 0.0 0.0 0.0 0.0 0.0 0.0 Auxiliaries purchased MWh 34.507 34.507 159.008 228.022 6.919 234.941 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0.0 0.0 0.0 0.0 0.0 0.0 Capacity Factor % 0.00 0.00 0.00 0.00 0.00 0.00 Availability Factor % 7.53 7.53 7.53 7.53 7.53 7.53 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 688.00 688.00 688.00 2,064.00 688.00 2,752.00 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 55.000 55.000 55.000 165.000 55.000 220.000 Hours HW Boiler Gas Usage MMBTU 1,387.000 1,387.000 Pilot Gas Usage MMBTU 0.0 0.0 0.0 0.0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 19

2013-2014 Fiscal Year-to-Date - March McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 135.697 214.032 263.041 612.770 75.655 688.425 Starts # 7 7 16 30 20 50 Gross Generation MWh 959.877 1,413.560 16,424.707 18,798.144 2,615.094 21,413.238 Net Generation MWh 895.980 1,309.804 15,045.322 17,251.106 2,613.006 19,864.112 Total Auxiliaries MWh 335.587 440.544 2,918.134 3,694.265 37.782 3,732.047 Auxiliaries purchased MWh 314.313 356.843 1,539.193 2,210.349 34.965 2,245.314 Fuel Gas Used MMBTU 8,924.901 15,004.575 146,255.584 170,185.060 19,584.819 189,769.879 Fuel Oil Used MMBTU 5,504.840 4,463.354 36,178.243 46,146.437 15,380.547 61,526.984 Fuel Oil Used Gallons 38,567 31,228 252,473 322,268 108,053 430,321 Total Fuel MMBTU 14,429.741 19,467.929 182,433.827 216,331.497 34,965.366 251,296.863 Net Heat Rate BTU/KWh 15.641 14.141 12.613 14.131 13.198 13.898 Unit Trips # 1 1 0 2 5 7 Capacity Factor % 0.80 1.17 2.24 1.93 1.02 1.73 Availability Factor % 67.50 68.72 68.72 68.31 68.72 68.42 Commercial % 0.95 0.04 0.01 0.13 0.0 0.10 Unavailability (CU) Planned Outage Hours Hours 2,057.000 2,057.000 2,057.000 6,171.000 2,057.000 8,228.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 80.000 0.0 0.0 80.000 0.0 80.000 Reserve Shutdown Hours 4,303.303 4,268.968 4,258.555 12,830.826 4,443.345 17,274.171 Hours HW Boiler Gas Usage MMBTU 6,203.127 6,203.127 Pilot Gas Usage MMBTU 2,375.134 4,694.627 7,069.761 7,069.761 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 13-14 Fuel FY 13-14 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 460,013 461,775 0 1,762 454,725 378,003 7,050 VanSant 72,139 72,561 0 422 146,133 35,000 (73,572) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through March 2014 Actual Starts Factored Starts Fired Hours VanSant 1350 2,311.25 4,306.00 Since HGP - Dec 2004 257 643.55 922.42 20

Team Report: The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. They assisted in the natural gas line purge on Unit 3 in preparation of the installation of the pipe blank and in the purge on Units 1 and 2 natural gas lines. The Operations staff has also supported the outage by performing various LO/TO tasks needed to test or place equipment in or out or service. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2013-2014 Summer 2013 (June 1- Aug 31) Winter 2013-2014 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.2 1 17 17.5 2 17 17.8 2 17 18.2 3 102 103.0 3 102 104.4 11 39 40.9# 11 39 44.05# Total 175 178.9 Total 175 184.1 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program and data has been submitted into the PJM eGADS Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 21

4.0 Maintenance During the month of March, the Plant Maintenance staff continued addressing the backlog of work orders. There were fifty-two work orders issued with forty-four work orders being completed during the month. There was no safety work orders entered into the plant’s Computerized Maintenance Management System (MP2) during the month. The table below summarizes the monthly work order activities. Work Order Report March - 2014 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 14 0 0 14 2 55 12 9 58 3 38 1 2 37 4 5 0 0 5 5 15 0 0 15 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 69 39 33 75 EM 0 0 0 0 Totals 196 52 44 204 Note: PM Work Orders are included in the priority totals Notable activities during the month include: NAES Maintenance Staff completed a flush on Unit 3 generator lube oil system. This was completed to ensure that no debris had gotten into the lube oil system while the turbine was being overhauled. In conjunction, a lube oil flush of the turbine was performed by the turbine contractor. Neither flush indicated any debris in the lube oil. NAES Maintenance Staff completed the PM activities on the Unit 3 EHC equipment. During the inspection portion, indications of varnishing present were found.in the EHC storage tank. Plant staff removed the old EHC fluid, cleaned the tank and put in new EHC fluid. New filtration equipment has been placed on order and will be installed when it arrives. NAES IC&E Staff worked on a number of transmitter calibrations, both on Unit 3 and Unit 11 as part of outage work scope. During the month over 30 devices were calibrated. Two transmitters were found to out of calibration and were unable to be adjusted to specifications. New devices were requisitioned and will be set for the proper calibration before being installed. 22

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: Cooling Tower decking is 100% complete. Inspection was conducted in March as a precursor for CIP work scope development next Unit #3 Cooling FY. EG1402 Schedule: Inspection work completion and work scope is being Tower Repairs modified to reflect deficiencies found during inspection. Bid requests and bid meeting to be set up for April-May time period. McKee Run Progress: Work planned for the Fall is 100% complete. Auxiliary Schedule: Remaining Fall outage items were completed in EG1404 Component December. Spring activities to start in March. Replacement VanSant Station Progress: Work planned for the Fall is 100% complete. EG1405 Component Schedule: Project activities for this fiscal year have been completed. Replacement Progress: The recently completed hanger adjustments will need to be checked with the unit in the hot (running) position. McKee Run HEP Schedule: FAC vendor selected and was onsite in early March. At EG1406 Pipe Repairs exit interview, vendor indicated no significant problems although one pipe section should a problem in the near future. Waiting for final report so that future work scope may be determined. Progress: Work scope is being developed for RFP. Finalizing Metering System documents and possible bidders for work. EG1407 Upgrades Schedule: Work activities are moving forward. Working with vendor to finalize RFP documents for release in May. Progress: Work is being planned to be completed in the Spring 2014 McKee outage period. Specifications being written for VanSant breaker EG1408 Run/VanSant Safety installation. Will need to go out for bids once complete. Compliance Items Schedule: Work activities are behind due to Fall Outage activities. McKee Run Natural Progress: Work scheduled for the Spring Outage. EG1409 Gas Block-Bleed Schedule: Work activities are back on track for a Spring Outage Valves completion date. Expect to be complete by end of April. McKee Progress: Plant staff completed development of paint specifications Run/VanSant and bid requests were received. EG1413 Structural Schedule: Bids were received in early September. Work is on hold Preservation due to budget restraints. Progress: Repair vendor selected. Consumables parts have been received. Work commenced and is ongoing. Rotor removed and sent Unit 3 Turbine EG1212 out to shop for 9th stage installation, inspection of the rotor, and Repairs balancing. Schedule: Rotor to return in early April and will be reinstalled upon 23

arrival. Progress: Cost to be incurred due to repairs on Unit 1 Boiler and McKee Run Units turbine were completed in November. EG1415 #1-#2 Component Schedule: Other scope activities being evaluated due to the Repairs announcement to stop operation of units 1 and 2 in 2016. Progress: Submitted permit application to DNEC in March. Facility impact study results provided by PJM indicate no additional modifications required. RFP documents were prepared and sent out VanSant Capacity EG1416 for bids. Bids were returned and are now being evaluated. Increase Schedule: Bid received and are being evaluated. DNREC has received permit application and is now performing review of documents. 6.0 General Plant Information On March 29, 2014, Operator Ron McNair celebrated 15 years with the power plant. The plant held a congratulatory lunch in Ron’s honor on March 28, 2014. Training: 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. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Near Misses”. Simulation training for PJM operations is scheduled to occur on April 8-9 by a third party vendor. Completion of this training enables plant operators to meet Continuing Education Hours (CEHs) requirements that are part of maintaining their PJM System Ops Certification. 24

Calendar of Events Date EIA-860 Report TBD EIA-923 Report TBD NOx Emissions Reconciliation Due March 1, 2014 SO2 Emissions Reconciliation Due March 1, 2014 SARA III / Tier II Report Due March 1, 2014 NPDES Permit Expires (DNREC has Extended) March 4, 2014 (TBD) Units 1, 2, and 3 Spring Outage March 3, 2014 – May 30, 2014 Unit 11 Spring Outage March 3, 2014 – May 30, 2014 Annual VanSant Black Start Test April, 2014 Air Emission Inventory April, 2014 NOx Ozone Season Starts May 1, 2014 PJM Summer Capacity Test Period June 1, 2014 – August 31, 2014 FY 2013-2014 Budget Year Ends June 30, 2014 Toxic Release Inventory (TRI) Annual Report July 1, 2014 Semi-Annual Title V Certification Due July 31, 2014 NOx Ozone Season Ends September 30, 2014 Units 1, 2, 3 and 11 Fall Outage October 1, 2014 Four Year Accident Free October 14, 2014 Winter Capacity Period December 1, 2014 to February 28, 2015 7.0 Summary of NAES Performance to Date Plant Performance FY 2013-2014 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.0% 0.10% $91,087 $94,882 Unavailability (CU) Safety 0 0 $17,790 $17,790 Environmental 0 0 $17,790 $17,790 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes $3,559 $3,559 Unit 2 No No Yes Yes $3,559 $3,559 Unit 3 No No Yes Yes $21,349 $21,349 Unit 11 No No Yes Yes $7,117 $7,117 Total YTD 97.71% Total YTD Incentive $162,249 $166,045 Incentive % Note: All units successfully completed the Summer and Winter Capacity (FY 2013-2104) testing for PJM. 25

IV. Appendix 1 – PJM Invoice Breakdown Gen Load Grand Total 480-8102-592-95-49 Capacity Resource Deficiency ($2,920.20) ($2,920.20) Capacity Transfer Rights ($19,233.33) ($19,233.33) Incremental Capacity Transfer Rights ($1,687.33) ($1,687.33) Locational Reliability $1,384,641.66 $1,384,641.66 480-8102-592-95-49 Total $ 1,360,800.80 $ 1,360,800.80 480-8102-592-95-50 RPM Auction ($1,329,125.00) ($1,329,125.00) 480-8102-592-95-50 Total $ (1,329,125.00) $ (1,329,125.00) 480-8102-592-95-90 Auction Revenue Rights ($26,678.60) ($26,678.60) Balancing Operating Reserve ($131,888.83) ($131,888.83) Balancing Operating Reserve for Load Response ($34.57) ($34.57) Black Start Service $1,862.86 $1,862.86 CT Lost Opportunity Cost Allocation ($17.36) ($17.36) Day-Ahead Load Response Charge Allocation $8.68 $8.68 Day-ahead Operating Reserve $4,325.42 $4,325.42 Day-ahead Scheduling Reserve $40.42 $40.42 Demand Resource and ILR Compliance Penalty ($1,993.92) ($1,993.92) Expansion Cost Recovery $408.27 $408.27 FERC Annual Recovery $4,288.05 $4,288.05 Generation Deactivation Refund ($735.89) ($735.89) Load Management Test Failure ($44.33) ($44.33) Load Reconciliation for Transmission Losses $8,771.12 $8,771.12 Market Monitoring Unit (MMU) Funding $169.78 $169.78 Michigan - Ontario Interface Phase Angle Regulators $181.51 $181.51 Network Integration Transmission Service $326,717.68 $326,717.68 Non-Firm Point-to-Point Transmission Service ($1,278.34) ($1,278.34) Non-Synchronized Reserve $4,217.72 $4,217.72 North American Electric Reliability Corporation (NERC) $653.58 $653.58 Organization of PJM States, Inc. (OPSI) Funding $42.74 $42.74 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,689.07 $1,689.07 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $943.95 $943.95 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $10,335.37 $10,335.37 PJM Scheduling, System Control and Dispatch Service - Market Support $2,359.23 $2,359.23 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($323.76) ($323.76) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $82.92 $82.92 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($125.55) ($125.55) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($1,545.40) ($1,545.40) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($355.74) ($355.74) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($15.45) ($15.45) PJM Settlement, Inc. $323.76 $323.76 Reactive Services $26,919.77 $26,919.77 Reactive Supply and Voltage Control from Generation and Other Sources Service $34,872.27 $34,872.27 Real-Time Load Response Charge Allocation $2,802.83 $2,802.83 Regulation and Frequency Response Service $34,903.87 $34,903.87 Reliability First Corporation (RFC) $928.46 $928.46 Synchronized Reserve $39,540.84 $39,540.84 Transmission Enhancement $9,972.34 $9,972.34 Transmission Owner Scheduling, System Control and Dispatch Service $4,538.54 $4,538.54 480-8102-592-95-90 Total $ 356,863.31 $ 356,863.31 480-8102-592-95-91 Balancing Spot Market Energy $279,162.36 $279,162.36 Balancing Transmission Congestion $31,748.64 $31,748.64 Balancing Transmission Losses $17,546.23 $17,546.23 Day-ahead Spot Market Energy $938,725.03 $938,725.03 Day-ahead Transmission Congestion $262,611.88 $262,611.88 Day-ahead Transmission Losses $176,870.99 $176,870.99 Emergency Load Response $30,326.98 $30,326.98 Inadvertent Interchange ($2,633.67) ($2,633.67) Load Reconciliation for Balancing Operating Reserve ($24,929.01) ($24,929.01) Load Reconciliation for Day-ahead Scheduling Reserve ($2,666.66) ($2,666.66) Load Reconciliation for FERC Annual Recovery ($268.43) ($268.43) Load Reconciliation for Inadvertent Interchange ($50.30) ($50.30) Load Reconciliation for Market Monitoring Unit (MMU) Funding ($15.33) ($15.33) Load Reconciliation for Non-Synchronized Reserve ($873.21) ($873.21) Load Reconciliation for North American Electric Reliability Corporation (NERC) ($40.92) ($40.92) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding ($2.68) ($2.68) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service ($789.62) ($789.62) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund $118.54 $118.54 Load Reconciliation for Reactive Services ($508.90) ($508.90) Load Reconciliation for Regulation and Frequency Response Service ($4,906.51) ($4,906.51) Load Reconciliation for Reliability First Corporation (RFC) ($58.12) ($58.12) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center ($79.38) ($79.38) Load Reconciliation for Spot Market Energy ($707,661.57) ($707,661.57) Load Reconciliation for Synchronized Reserve ($14,539.19) ($14,539.19) Load Reconciliation for Synchronous Condensing ($4.46) ($4.46) Load Reconciliation for Transmission Congestion ($128,904.56) ($128,904.56) Load Reconciliation for Transmission Losses ($52,445.92) ($52,445.92) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service ($284.11) ($284.11) Meter Error Correction ($4,987.55) ($4,987.55) 480-8102-592-95-91 Total $ 790,460.55 $ 790,460.55 480-8102-592-95-93 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) ($29,467.58) Transmission Losses ($47,724.33) ($47,724.33) 480-8102-592-95-93 Total $ (77,191.91) $ (77,191.91) Grand Total $ (1,406,316.91) $ 2,508,124.66 $1,101,807.75 26

FUND SUMMARY as of 05/02/2014 Total Collected $ 1,017,895.64 DEMEC Admin Fee Paid $ 54,983.45 State Admin Fee Paid $ 24,316.32 Total Grant Dollars Paid $ 709,720.82 Customer Only Grants/Fees Reserved and Amount Owed $ 18,245.75 Community Project Funds Requested - Dov. Lib - Requested $ 1,970,000.00 Community Project Funds Requested - Dov. Lib -Still Owed $ 1,769,591.68 Energy Depot Fees Paid $ 50,133.25 Efficiency Program Dollars Paid $ 37,268.34 Solar Electric Power Association (SEPA) Fee Paid $ 6,476.41 Unencumbered Funds Available Grants $ 7,205.96 Collected Funds Available for Dover Library $ 109,545.34 Current Grant Payment Delay (Months) 0.0 GRANTS PAID Grant Amount Review Fee Amount Date Grant Paid Applicant Type Paid Paid Owed 9/21/2007 Laura Drew Kelly Geo - Res $ 3,000.00 $ 225.00 $ - 12/5/2007 Domingo Reye Solar - Res $ 12,762.50 $ 750.00 $ - 4/16/2008 Lakeland Commercial Group Geo - Comm $ 10,800.00 $ 750.00 $ - 6/19/2008 & 08/25/2008 L.D. Shank - Triad Farms Solar - Comm $ 30,000.00 $ 750.00 $ - 10/6/2008 City of Dover Solar - Comm $ 40,820.00 $ 750.00 $ - 10/21/2008 Robert & Cynthia Hartman Geo HP- Res $ 1,800.00 $ 135.00 $ - 10/21/2008 Robert Varipapa Geo HP- Res $ 2,400.00 $ 180.00 $ - 2/27/2009 David Jump Solar - Res $ 15,000.00 $ 750.00 $ - 2/27/2009 Jakob Seren Solar - Res $ 15,000.00 $ 750.00 $ - 2/27/2009 William Sweet Solar - Res $ 15,000.00 $ 750.00 $ - 3/31/2009 LD Shank - Triad Farms Solar WH-Comm $ 3,000.00 $ 225.00 $ - 3/31/2009 Warren & Joan Seaver Geo HP- Res $ 3,000.00 $ 225.00 $ - 4/22/2009 William Sweet Solar HW $ 3,000.00 $ 225.00 $ - 4/28/2009 State of DE/DNREC - DE National Solar - Comm $ 30,000.00 $ 750.00 $ - 4/29/2009 Delaware Primary Care, LLC Solar - Comm $ 30,000.00 $ 750.00 $ - 9/11/2009 NCALL Solar - Comm $ 30,000.00 $ 750.00 $ - 9/11/2009 D. Brian Beckman Geo HP- Res $ 2,000.00 $ 150.00 $ - 9/21/2009 LKSC Dover, LLC Kids Cottage Solar - Comm $ 29,925.00 $ 750.00 $ - 10/5/2009 Mark F. Boller Geo HP- Res $ 3,000.00 $ 225.00 $ - 10/5/2009 John Welgan Solar - Res $ 15,000.00 $ 750.00 $ - 11/4/2009 LKSC Dover, LLC Kids Cottage Geo - Comm $ 12,000.00 $ 750.00 $ - 3/25/2010 Minaxi Patel Solar - Res $ 15,000.000 $ 750.000 $ - 3/23/2010 J. McGiffin Jr. & K. Doyle Geo HP- Res $ 3,000.000 $ 225.000 $ - 5/28/2010 Nancy Warner Geo HP- Res $ 1,200.000 $ 90.000 $ - 6/2/2010 David Teel Geo HP - Res $ 1,800.000 $ 135.000 $ - 6/2/2010 Dewey J. Barich Geo HP- Res $ 2,400.00 $ 180.000 $ - 7/12/2010 Mike & Sharonb Laverty Solar - Res $ 5,105.000 $ 382.880 $ - 8/19/2010 James Grilli Geo HP- Res $ 1,800.00 $ 135.000 $ - 8/19/2010 Michael Noble Solar - Res $ 15,000.000 $ 750.000 $ - 9/17/2010 David Teel Solar - Res $ 7,500.000 $ 562.500 $ - 3/8/2011 Michael & Carol Apgar Solar - Res $ 7,500.000 $ 562.500 $ - 3/17/2011 Elizabeth Murphey School Geo HP - Comm $ 9,200.000 $ 690.000 $ - 5/24/2011 Richard Avant Geo HP - Res $ 2,400.000 $ 180.000 $ - 6/23/2011 Charles Messina Plumbing Solar - Comm $ 10,000.000 $ 750.000 $ - 10/4/2011 Charles Bounds Geo HP - Res $ 1,800.000 $ 135.000 $ - 3/29/2011 Psychiatric Access Central DE Solar - Comm $ 13,187.500 $ 750.000 $ - 7/8/2011 Michael J. Kopp Geo - Res $ 2,300.000 $ 135.000 $ 37.50 10/17/2011 City of Dover ** Library Geo - Comm $ 48,267.000 $ - $ - 3/7/2012 Ruth Ann Piper Geo - Res $ 1,200.000 $ 90.00 $ - 3/7/2012 Robert Hall Geo - Res $ 3,000.000 $ 225.00 $ - 3/7/2012 Elizabeth Murphey School Geo - Comm $ 13,800.000 $ 750.00 $ - 3/7/2012 Elizabeth Murphey School Geo - Comm $ 12,000.000 $ 750.00 $ - 3/7/2012 Elizabeth Murphey School Geo - Comm $ 5,400.000 $ 405.00 $ - 3/7/2012 Elizabeth Murphey School Geo - Comm $ 1,800.000 $ 135.00 $ - 3/7/2012 Elizabeth Murphey School Geo - Comm $ 10,200.000 $ 750.00 $ - 3/7/2012 Frank Daniels Geo - Res $ 4,400.00 $ 303.75 $ 26.25 8/15/2012 Chong S. Tamburo-Lepage Geo - Res $ 2,300.00 $ 172.50 $ - 12/5/2012 City of Dover ** Library Geo - Comm $ 152,141.32 $ - $ - 12/19/2012 Christopher W. Los Geo - Res $ 3,000.00 $ 225.00 $ - 1/30/2013 Matthew and Kimberly Chesser Geo - Res $ 3,000.00 $ 225.00 $ - 2/25/2013 Dennis Ho Solar - Res $ 6,775.00 $ 508.13 $ - 6/28/2013 John DeMarie Geo - Res $ 3,000.00 $ 225.00 $ - 10/30/2013 James and Corinna Fritsch Solar - Res $ 5,287.50 $ 396.56 $ - 10/30/2013 James and Deri Austin Solar - Res $ 7,500.00 $ 562.60 $ - 2/28/2014 Calogero Guarraggi Solar - Res $ 7,500.00 $ 562.50 $ - 2/28/2014 Elizbeth Murphy School Geo - Comm $ 3,700.00 $ 277.50 $ - 2/21/2014 Mohammed Fuad Geo - Res $ 3,000.00 $ 225.00 $225.00 4/8/2014 Holly Pfeifer Solar - Res $ 5,750.00 $ 431.25 $431.25 Total $ 689,770.82 $ 23,476.42 $ 720.00 ARRA RELIEF GRANTS PAID Paid by State Customer System Type Amount 6/10/2011 Arturo Sanchez Solar - PV - Res $ 7,500.00 10/19/2011 John Diamond Enterprise LLC Solar - PV - Com $ 30,000.00 10/19/2011 John Diamond Enterprise LLC Geo HP - Com $ 10,000.00 Total $ 47,500.00 RECEIVED APPLICATIONS Grant Reservation Status Applicant Type Request Review Fee Approved Pending Completion Governors Avenue Animal Hospital Solar - PV - Com $ 13,550.75 $ 750.00 Approved Pending Completion Julia M. Pillsbury Geo HP - Res $ 3,000.00 $ 225.00 Total $ 16,550.75 $ 975.00 ENERGY DEPOT FEES SEPA Fees Paid Fee Period Amount Date Measure Cost 3/3/2008 Start-up Fees $ 5,872.50 3/19/2012 2012 Annual Membership $ 2,158.81 4/15/2008 Start-up Fees $ 1,957.50 1/31/2013 2013 Annual Membership $ 2,158.80 4/15/2008 Mar, Apr, May 2008 $ 1,692.13 1/24/2014 2014 Annual Membership $ 2,158.80 7/22/2008 June, July, Aug 2008 $ 1,692.13 10/10/2008 Sept, Oct, Nov 2008 $ 1,692.13 1/2/2009 Dec 08, Jan, Feb 2009 $ 1,692.13 4/3/2008 Mar, Apr, May 2009 $ 1,692.13 7/1/2009 June, July, Aug 2009 $ 1,692.13 9/11/2009 Sept, Oct, Nov 2009 $ 1,692.13 1/4/2010 Dec 09, Jan, Feb 2010 $ 1,692.13 3/29/2010 Mar, April, May 2010 $ 1,692.13 6/30/2010 June, July, Aug 2010 $ 1,692.13 Total $ 6,476.41 10/4/2010 Sept, Oct, Nov 2010 $ 1,692.13

1/3/2011 Dec 2010, Jan, Feb 2011 $ 1,692.13 4/5/2011 Mar, Apr, May 2011 $ 1,692.13 7/8/2011 June, July, Aug 2011 $ 1,692.13 10/4/2011 Sept, Oct, Nov, 2011 $ 1,692.13 1/3/2012 Dec 2011; Jan, Feb 2012 $ 1,692.13 4/5/2012 Mar, Apr, May 2012 $ 1,692.13 7/2/2012 June, July, Aug 2012 $ 1,692.13 10/2/2012 Sept, Oct, Nov 2012 $ 1,692.13 11/30/2012 Dec 12, Jan, Feb 2013 $ 1,692.13 2/25/2013 Mar, Apr, May 2013 $ 1,692.13 7/22/2013 June, July, Aug 2013 $ 1,692.13 8/26/2013 Sept, Oct, Nov, 2013 $ 1,692.13 12/3/2013 Dec 13. Jan, Feb 2014 $ 1,692.13 3/4/2014 Mar, Apr, May 2014 $ 1,692.13 June, July, Aug 2014 Sept, Oct, Nov 2014 Dec 14, Jan, Feb 2015 Total Paid $ 50,133.25 ENERGY EFFICIENCY CAMPAIGNS/EDUCATION PROGRAMS Paid Program Measure Amount 10/21/2008 1,500 CFL Campaign & $ 5,012.29 Reimbursement for Green 12/11/2008 Energy/Information Pamphlets $ 3,459.12 Thermal Imager for Home Audits 3/31/2009 Program $ 5,581.12 Eco @ Home Energy Conserve. 1/4/2011 Calendars $ 20,015.81 Presbyterian Church of Dover - 1/14/2014 Energy Efficiency Grant $3,200.00 Total $ 37,268.34 10/30/2013 Dover Library Community Grant Payment Schedule Dover Library Community Funds Collection - $ 1,970,000.00 Allocation change from Dover Payment Due Date Requested Amount Funds Available Funds Paid to Date Collections 10/17/2011 $ 48,267.00 $ 48,267.00 12/5/2012 $ 152,141.32 $ 152,141.32 $ 5,021.15 1/2 of Oct 2009 GEF Payment June 1, 2014 $ 98,500 $ 109,545.34 $ 4,783.94 1/2 of Nov 2009 GEF Payment June 1, 2015 $ 98,500 $ 4,813.23 1/2 of Dec 2009 GEF Payment June 1, 2016 $ 98,500 $ 5,454.02 1/2 of Jan 2010 GEF Payment June 1, 2017 $ 98,500 $ 5,147.49 1/2 of Feb 2010 GEF Payment June 1, 2018 $ 98,500 $ 4,897.69 1/2 of March 2010 GEF Payment June 1, 2019 $ 98,500 $ 3,976.14 1/2 of April 2010 GEF Payment June 1, 2020 $ 98,500 $ 5,638.90 1/2 of May 2010 GEF Payment June 1, 2021 $ 98,500 $ 5,645.35 1/2 of June 2010 GEF Payment June 1, 2022 $ 98,500 $ 6,590.60 1/2 of July 2010 GEF Payment June 1, 2023 $ 98,500 $ 7,786.09 1/2 of August 2010 GEF Payment June 1, 2024 $ 98,500 $ 6,415.31 1/2 of Sept 2010 GEF Payment June 1, 2025 $ 98,500 $ 5,327.96 1/2 of Oct 2010 GEF Payment June 1, 2026 $ 98,500 $ 4,787.73 1/2 of Nov 2010 GEF Payment June 1, 2027 $ 98,500 $ 4,939.75 1/2 of Dec 2010 GEF Payment June 1, 2028 $ 98,500 $ 5,452.55 1/2 of Jan 2011 GEF Payment June 1, 2029 $ 98,500 $ 5,410.35 1/2 of Feb 2011 GEF Payment June 1, 2030 $ 98,500 $ 4,646.32 1/2 of March 2011 GEF Payment June 1, 2031 $ 98,500 $ 4,742.22 1/2 of April 2011 GEF Payment June 1, 2032 $ 98,500 $ 4,702.48 1/2 of May 2011 GEF Payment June 1, 2033 $ 98,500 $ 5,664.97 1/2 of June 2011 GEF Payment Total $ 1,970,000.00 $ 109,545.34 $ 200,408.32 $ 6,430.15 1/2 of July 2011 GEF Payment $ 6,916.50 1/2 of Aug 2011 GEF Payment $ 6,149.31 1/2 of Sept 2011 GEF Payment $ 5,243.92 1/2 of Oct 2011 GEF Payment $ 4,829.91 1/2 of Nov 2011 GEF Payment $ 4,531.81 1/2 of Dec 2011 GEF Payment $ 4,990.50 1/2 of Jan 2012 GEF Payment $ 5,071.81 1/2 of Feb 2012 GEF Payment $ 4,828.32 1/2 of March 2012 GEF Payment $ 4,857.07 1/2 of April 2012 GEF Payment $ 4,230.04 1/2 of May 2012 GEF Payment $ 5,711.19 1/2 of June 2012 GEF Payment $ 6,085.89 1/2 of July 2012 GEF Payment $ 7,347.66 1/2 of Aug 2012 GEF Payment $ 6,453.66 1/2 of Sept 2012 GEF Payment $ 4,886.43 1/2 of Oct 2012 GEF Payment $ 4,132.99 1/2 of Nov 2012 GEF Payment $ 5,513.86 1/2 of Dec 2012 GEF Payment $ 5,187.25 1/2 of Jan 2013 GEF Payment $ 5,307.83 1/2 of Feb 2013 GEF Payment $ 4,783.25 1/2 of March 2013 GEF Payment $ 4,903.40 1/2 of April 2013 GEF Payment $ 4,673.21 1/2 of May 2013 GEF Payment $ 5,322.04 1/2 of June 2013 GEF Payment $ 6,352.74 1/2 of July 2013 GEF Payment $ 6,519.11 1/2 of Aug 2013 GEF Payment $ 5,995.23 1/2 of Sept 2013 GEF Payment $ 4,913.73 All of Oct 2013 GEF Payment Per Allocation Request from Dover 10/30/2013 $ 8,589.16 All of Nov 2013 GEF Payment $ 8,846.64 All of Dec 2013 GEF Payment $ 9,286.45 All of Jan 2014 GEF Payment $ 10,267.60 All of Feb 2014 GEF Payment $ 8,950.89 All of March 2014 GEF Payment All of April 2014 GEF Payment All of May 2014 GEF Payment All of June 2014 GEF Payment All of July 2014 GEF Payment All of Aug 2014 GEF Payment All of Sept 2014 GEF Payment All of Oct 2014 GEF Payment All of Nov 2014 GEF Payment All of Dec 2014 GEF Payment All of Jan 2015 GEF Payment All of Feb 2015 GEF Payment All of March 2015 GEF Payment $ 309,953.66 Total Collections

City of Dover Electric Revenue Fund FY14 - White Oak Solar Park Incremental Cost Original July August September October November December January February March YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 187,421 $ 176,372 $ 204,852 $ 120,839 $ 99,447 $ 64,684 $ 82,605 $ 101,681 $ 137,856 $ 1,175,757 $ 1,565,800 Dover Sun Park - REC's 43,005 38,516 42,894 25,307 20,875 13,583 17,301 21,304 - 222,785 300,000 Total Power Supply Cost 230,426 214,888 247,746 146,146 120,322 78,267 99,906 122,985 137,856 1,398,543 1,865,800 Non-Solar Power Supply Cost (180,227) (154,545) (154,590) (100,770) (79,066) (52,006) (146,406) (90,909) (106,597) (1,065,115) (1,014,460) Incremental Energy Cost $ 50,199 $ 60,343 $ 93,156 $ 45,376 $ 41,256 $ 26,261 $ (46,500) $ 32,077 $ 31,259 $ 333,428 $ 851,340 Revenues Customer Sales - Electricity (9,404) (7,389) (7,538) (7,662) (7,721) (8,019) (8,071) (7,950) (7,648) (71,402) (26,300) Rent Receipts (14,446) - - (14,446) - - (14,807) - (34,450) (78,149) (58,300) Total Revenues (23,850) (7,389) (7,538) (22,108) (7,721) (8,019) (22,878) (7,950) (42,098) (149,551) (84,600) Incremental Sun Park Cost $ 26,349 $ 52,954 $ 85,618 $ 23,268 $ 33,535 $ 18,242 $ (69,378) $ 24,127 $ (10,839) $ 183,877 $ 766,740 MWh Purchased/Generated - Solar 2,052.584 1,815.656 2,000.128 1,179.844 970.972 631.556 806.536 992.788 1,345.984 11,796.048 18,159.000 MWh $ Solar Energy $ 91.31 $ 97.14 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 99.67 $ 86.23 Solar REC's MWh 307.000 272.000 300.000 177.000 146.000 95.000 121.000 149.000 - 1,567.000 MWh $ Solar REC (one month lag)* $ 140.08 $ 141.60 142.98 142.98 142.98 142.98 142.98 142.98 $ - $ 142.17 MWh $ Non-Solar Energy $ 87.81 $ 85.12 $ 77.29 $ 85.41 $ 81.43 $ 82.35 $ 181.52 $ 91.57 $ 79.20 Note: Solar REC's are one month behind due to the time the invoice is received.