Attachment

UTILITY COMMITTEE AGENDA JUNE 10, 2013 - 5:30 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. Proposed Revisions to the Dark Fiber Leasing Standard Operating Policy (Staff Recommends Approval of the Revisions, As Submitted) 2. TEA/NAES Report (February) (Committee Action Not Required) 3. Quarterly Review of Utility Related Capital Investment Plan (CIP) (Electric and Water/Wastewater)(January, February, and March) (This Item Was Deferred in May Due to the Annual Council Meeting) (Committee Action Not Required) 4. Updates A. Calpine Energy Center (Committee Action Not Required) B. Dover Sun Park (Committee Action Not Required) C. Garrison Oak Technical Park Project (Committee Action Not Required) 5. Adjournment by 5:55 p.m. /tm S:\AGENDAS-MINUTES-PACKETS\Committee-Agendas\2013\06-10-2013 UTILITY.wpd THE AGENDA ITEMS AS LISTED MAY NOT BE CONSIDERED IN SEQUENCE. THIS AGENDA IS SUBJECT TO CHANGE TO INCLUDE THE ADDITION OR THE DELETION OF ITEMS, INCLUDING EXECUTIVE SESSIONS.

ACTION FORM PROCEEDING: Utility Committee AGENDA ITEM NO.: DEPARTMENT OF ORIGIN: Electric Department. DATE SUBMITTED: 5-28-13 PREPARED BY: Steve Enss, Interim Electric Director SUBJECT: Dark Fiber Policy Revision of Cost REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager, Controller EXHIBITS: Policy (page 6) EXPENDITURE REQUIRED: N/A AMOUNT BUDGETED: NA FUNDING SOURCE (Dept./Page in CIP & Budget): NA TIMETABLE: To become effective upon Council approval. RECOMMENDED ACTION: Staff recommends that the attached Dark Fiber Leasing Standard Operating Policy be revised as submitted. BACKGROUND AND ANALYSIS The City of Dover Electric Department owns and operates a fiber optic loop around the perimeter of the City. This loop is used as part of the electric transmission protection system, two-way radio communication system, and data/telephone transmission for City and Utility facilities. Within this fiber network there are spare fibers that are not utilized or planned to be utilized in the near future. Bayhealth Medical Center, Windstream and the State of Delaware have all leased lines from the Electric Department. The original policy was created and approved by City Council January 14, 2008. Dark fiber leasing is a common practice among Public Power Utilities as a method to enhance utilization of fiber assets, provide customers an affordable high-speed communication path, and generate additional revenue to offset operation expenses. Dark fiber leasing is a practice where the utility would provide a fiber path between two points and the customer installs the electronic communication equipment which provides the communication path. Based on the abundant request for fiber optic installations in FY13, we felt that our rates may need to be adjusted. The requests that were approved, accounted for about 42% of our new service budget. We investigated our cost compared to other local fiber optic providers and found that our rates were much lower than that of other local providers. We found that the going rate for private fiber suppliers was $65 to $125 per mile/pair/month. Converting our rate to the same rate structure would be equivalent to $10.08 per mile/pair/month. It is our recommendation that the rate be adjusted to $.005 per strand/foot/month. This would be equivalent to $52.80 per mile/pair/month. 1

CITY OF DOVER DARK FIBER LEASING STANDARD OPERATING POLICY ADOPTED BY CITY COUNCIL EFFECTIVE DATE: ?/??/13 1

TABLE OF CONTENTS TABLE OF CONTENTS ------------------------------------------------------------------------------------ 2 DARK FIBER LEASING ----------------------------------------------------------------------------------- 4 STANDARD OPERATING POLICY --------------------------------------------------------------------- 4 Overview -------------------------------------------------------------------------------------------------------- 4 Grant of Lease ------------------------------------------------------------------------------------------------- 4 Length of Agreement ----------------------------------------------------------------------------------------- 4 Annual Escalation Fee -------------------------------------------------------------------------------------- 5 Request for Service Form ----------------------------------------------------------------------------------- 5 Route and Design --------------------------------------------------------------------------------------------- 5 Compensation ------------------------------------------------------------------------------------------------- 5 Lease Fee ------------------------------------------------------------------------------------------------------- 5 New Extension Fee ------------------------------------------------------------------------------------------- 6 Existing Fiber Lease Fee ------------------------------------------------------------------------------------ 6 Lease payments------------------------------------------------------------------------------------------------ 7 Damage to COD Facilities ---------------------------------------------------------------------------------- 7 Engineering Fee ---------------------------------------------------------------------------------------------- 7 Estimate Accuracy -------------------------------------------------------------------------------------------- 7 Testing and Acceptance of Dark fiber -------------------------------------------------------------------- 7 Accessing Access Points ------------------------------------------------------------------------------------- 7 New Fiber Installations -------------------------------------------------------------------------------------- 8 Access Points -------------------------------------------------------------------------------------------------- 8 Demarcation --------------------------------------------------------------------------------------------------- 8 Equipment Security ------------------------------------------------------------------------------------------ 8 Electrically-Induced Noise ---------------------------------------------------------------------------------- 8 Restoration ----------------------------------------------------------------------------------------------------- 8 Interference ---------------------------------------------------------------------------------------------------- 9 Customers Duty of Noninterference ----------------------------------------------------------------------- 9 Remedies for Interference ----------------------------------------------------------------------------------- 9 Technical Disagreements------------------------------------------------------------------------------------ 9 2

Taxes, Licenses, Liens --------------------------------------------------------------------------------------- 9 City of Dover Racks and Equipment --------------------------------------------------------------------- 10 Maintenance -------------------------------------------------------------------------------------------------- 10 Dark fiber ----------------------------------------------------------------------------------------------------- 10 Customers Notification of Outage ------------------------------------------------------------------------ 10 Restoration Priority ----------------------------------------------------------------------------------------- 11 Relocation ----------------------------------------------------------------------------------------------------- 11 Dark fiber ----------------------------------------------------------------------------------------------------- 11 Reclamation -------------------------------------------------------------------------------------------------- 12 Representations and Warranties -------------------------------------------------------------------------- 13 Assignment and Transfer ---------------------------------------------------------------------------------- 14 Indemnification ---------------------------------------------------------------------------------------------- 14 Insurance------------------------------------------------------------------------------------------------------ 14 Default --------------------------------------------------------------------------------------------------------- 15 Termination --------------------------------------------------------------------------------------------------- 15 For Cause, Without Illegality------------------------------------------------------------------------------ 15 For Cause, With Illegality---------------------------------------------------------------------------------- 16 Surrender of Dark fiber Upon Termination ------------------------------------------------------------ 16 Renewal Provisions ------------------------------------------------------------------------------------------ 16 General Provisions ------------------------------------------------------------------------------------------ 16 Costs------------------------------------------------------------------------------------------------------------ 16 No Third Party Beneficiaries ------------------------------------------------------------------------------ 16 No Partnership ----------------------------------------------------------------------------------------------- 16 Binding Effect ------------------------------------------------------------------------------------------------ 16 Severability ---------------------------------------------------------------------------------------------------- 17 Force Majeure------------------------------------------------------------------------------------------------ 17 Waiver --------------------------------------------------------------------------------------------------------- 17 Headings ------------------------------------------------------------------------------------------------------ 17 No Implied Representations ------------------------------------------------------------------------------- 17 Integrated SOP and Amendments ------------------------------------------------------------------------ 17 3

DARK FIBER LEASING STANDARD OPERATING POLICY Overview The City of Dover Public Utilities, Electric Division, (COD) owns certain fiber optic facilities and desires to lease certain unused fiber-strands on its metropolitan area fiber optic communications network (facilities) to private parties. This concept will initiate enhanced utilization of assets, provide customers affordable dark fiber usage, and generate additional revenue. The City of Dover believes that the interests of the consumer-owners will be well served by using a portion of City’s unused fiber optic capacity in accordance with the rules and regulations contained herein. These requirements do not replace, but are supplemental to ordinances adopted by the Dover City Council and your elected officials which set the policy for the City of Dover Public Utilities (COD). The COD may from time to time supplement, alter or otherwise change the policies contained herein as may be necessitated by changing conditions for the protection of the interest of the customer, the COD, or the general public. Grant of Lease The COD hereby grants to customers, a license to use excess fibers in the COD fiber optic network (“Dark fiber”), as identified on a case-by-case basis, as determined by the City of Dover Public Utilities, Electric Engineering Division. In instances where the COD does not have spare fiber, fiber may be installed and paid for by the customer as outlined in this Standard Operating Policy (SOP). The COD retains the right to use and otherwise lease additional fibers along the COD fiber optic network as it sees fit, this is not an exclusive right. No use of the COD facilities or payment of any charges required under this lease shall create or vest in the customer any easements or other ownership of property rights of any nature in the dark fiber or the COD facilities. Terms Length of Agreement The term of agreement for fiber leasing may be granted for five-years (5) or ten-years (10) by mutual agreement between the COD and the customer. The lease rate at the time of the installation shall be leveled at the agreed upon rate for the term of the initial agreement subject to the annual escalation 4

fee as defined in “Annual Escalation Fee” below. At the end of the initial term of the agreement, the customer shall have the right to renew this lease, subject to COD consent, for an additional five (5) years at the lease rate effective at the time the lease is renewed. The customer shall receive a minimum of 90 days written notice of cancellation of this agreement upon the expiration of the initial agreement. Immediately upon termination by the expiration of the term hereof or otherwise, the customer shall peaceably surrender the dark fiber to the COD in the original condition, with exception to reasonable wear and tear. Annual Escalation Fee The annual fee for the dark fiber will escalate based on the Consumer Price Index for Urban Wage Earners and Clerical Workers (CPI-W): Selected areas, all items index - Philadelphia-Wilmington- Atlantic City PA-NJ-DE-MD (CPI) as published by the U.S. Department of Labor’s Bureau of Labor Statistics not to exceed 5% increase per year but not less then current year’s fee. Request for Service Form When a customer desires to investigate the option of leasing dark fiber from the COD, the customer shall complete a Dark Fiber Application which will include the requesters name, company if applicable, fiber strands desired, location of requested access points, and related information. The COD will investigate the feasibility of the application with the customer, and if determined feasible, the COD will collect the Engineering Fee as outlined on Page 7 – “Engineering Fee”. Upon payment of the Engineering Fee the COD will develop a comprehensive project plan which will also include an estimated monthly fee as outlined on Page 6 - “New Extension Fee” and “Existing Fiber Lease Fee”. If the customer accepts the project plan and fee schedule, the final section of the Dark Fiber Application shall be executed which commits both the customer and the COD to completion of the project and compensation. Route and Design The COD Engineering Division will develop the route and design of any new extensions. The customer has the right to accept, reject, or suggest alternatives in the design; however, the COD decision will be final. Compensation Lease Fee The customer shall pay to the COD for use of the Dark fiber a lease fee subject to adjustments as provided below. Fees will be based on the date of acceptance of the fiber for the initial lease term and shall be priced at “dollars/fiber strand/foot/month”. 5

New Extension Fee The lease rate will be based on total cost recovery of any new extension during the initial term, plus 5% annually for maintenance and an 8.5% annual rate of return. The customer that requests the extension shall be responsible for the entire cost of the extension.  If within one-half of the initial lease term another party wishes to connect to the extension the new second party will be responsible for one-half of the original extension fee for the section they are using.  The initial customer will have their portion of the extension lease rate reduced by 50% for the duration of the contract.  It will not be retroactive and will only apply from that period forward.  If the new party starts leasing after the one-half period, the original party pays the entire fee as developed in the original contract term.  For example: Customer A is paying $200/month for a new extension fee and $100 for lease of the COD existing fiber for a total of $300 per month for a ten year lease. o If in year 4, customer B decides to lease fiber from the COD and the COD utilizes ½ of customer A’s original extension the following formula will be utilized:  $200/month x 72 months (months remaining in the original extension fee) = $14,400 (balance of funds owed the COD)/2 (fiber length used) = $7,200 (funds needed to pay the cost of the extension)/2 (cost split between the two parties) $3,600 = revenue needed from both parties. This will result in party A paying $3,600 + $7,200 (for extension fee)/72 (months left in lease term) = $150 + $100 (both monthly fees) for original lease of COD existing fiber for a monthly total of $250. o Customer B will pay $3,600 for the lease of the original extension and the monthly total will be prorated for the duration of the new contract plus any lease fees for the existing COD fiber. o If Customer B uses the Customer A fiber after the original contract has been in effect for more than ½ of the original term, then Customer A continues to pay the original payment and Customer B will be charged for the fiber under the Existing Fiber lease rate.  Extension installation Only COD personnel (or their designee) will install fiber extensions. The customer will be responsible for all expenses incurred by the COD, prorated into the monthly fee. Existing Fiber Lease Fee For installations where the COD determines that ist has spare fibers and the fiber route is not part of a new extension lease the leasing rate shall be based on an estimated cost of the current installation. This cost assumes a ten (10) year depreciation plus 5% annually for maintenance and an 8.5% annual rate of return. This cost is $0.0009541 $0.005/fiber strand/foot/month. This rate shall be reviewed annually based on current dark Fiber Lease agreements in the local area. 6

Lease payments Fees shall be calculated on a monthly basis and paid annually, in advance, and shall be billed on the first business day of the month after the customer accepts the fiber. The fees will be considered due and payable at the time the customer is billed. No fees will be due until both the COD and the Customer agrees on the acceptance date, which approval will not be unreasonably withheld. If the acceptance date occurs after the beginning of the month, the first monthly fee shall be prorated from the acceptance date to the beginning of the next month: however, the prorated fees shall be for that partial month only and will be added to the following years annual fee, both of which will be billed on the beginning of the next month. Damage to COD Facilities The COD will be compensated for any damages to the COD facilities caused by the customer or their contractor. Engineering Fee A one-time engineering fee of $200 (two-hundred dollars) will be charged for each splice location where the customer proposes to access the COD fiber optic network and/or each customer access point. This fee covers the documentation cost for the splice location and design for the installation. Installation costs and lease payments are not included in this amount. Estimate Accuracy During the development of the cost estimates for the dark fiber lease, the customer will have the opportunity to examine the components of the costs to ensure its accuracy. The actual cost will be based on the true cost of installation of new extensions and the formula accepted by the governing body for costs related to existing fiber. The customer will execute the request for service form based on the estimated costs and thereby accept the actual cost upon completion. The COD will guarantee that the actual cost will not increase more than 10% over the estimate but may be lower if the actual cost is less than the estimated cost. Testing and Acceptance of Dark fiber The COD will perform acceptance tests to ensure that the dark fibers meet the standard industry specifications. The COD will provide the customer with written results of such tests, if requested by the customer. If the dark fibers fail to meet the standard industry specifications, the COD shall repair or substitute fibers that meet the required tests and specifications, unless the customer otherwise accepts the original fibers. Upon receipt of test results, if requested, the customer shall accept the dark fibers and such date shall be the Acceptance Date. Under no circumstances shall the customer accept the dark fibers later than thirty days after the COD completes the acceptance test. Accessing Access Points The COD shall have nonexclusive ingress and egress rights to access the dark fiber at the access points (“Access Points”) shown on the Request for Service Form at all times for construction, installation, operation, inspection, maintenance, repair and removal of COD facilities. If additional access to termination locations is required after initial installation, the COD should provide seventy- 7

two (72) hour notice prior to accessing the site(s) when practical. At location(s) where the customer is accessing the fiber at COD locations the customer will provide forty-eight (48) hour notice to the COD prior to accessing the site(s). The customer will notify the COD if possible disruption of the dark fiber circuit might occur. New Fiber Installations The COD will install new fiber extensions, including the appropriate hardware, and provide any splicing required in conjunction with the project with either internal staff or contractors, solely at the COD discretion. Access Points The COD will be responsible for all cost of material and installation of the access point(s) for the COD facilities which are located at the customers’ demarcation point. The access point(s) will normally be a patch panel unless mutually agreed upon to be a splice point. Demarcation The COD will provide the patch panel and terminations of the COD fiber at the patch panel. The point of demarcation will be the patch panel connectors or up to, but not including, the splice. The COD shall retain ownership of designated splice tray, which contains dark fiber or the patch panel, but shall not have ownership of any fiber or equipment beyond this point. Equipment Security The COD shall not provide security for the customer and shall not be liable for burglary, vandalism, losses, or damage, unless the COD is grossly negligent. The COD shall not be liable for losses or damage to customers’ facilities resulting from a failure of towers or poles, substation equipment, communications houses, electric power or other COD facilities unless the COD is grossly negligent. The COD is not responsible or liable for cyber security of the fiber. Electrically-Induced Noise The customer shall be responsible for designing and shielding the customer facilities to function properly in the presence of electric and magnetic fields and other electrically-induced noise and interference normally present in the proximity of electric utility installations. The COD shall not be liable for, nor shall the COD be required, to eliminate any noise or interference with customers facilities resulting from the operations of electric utility installations or auxiliary equipment such as relay and control systems or telemetry systems. For purposes of the Interference provisions herein, this paragraph shall constitute the COD prior disclosure of the presence of electric utility installations on the Premises where the customers’ facilities may be installed. Restoration The COD shall provide at no cost, monthly standby emergency restoration service for the fiber optic network. In the event of an outage requiring emergency restoration, the COD will be responsible for any restoration expenses. 8

Interference Customers Duty of Noninterference The Customer shall install, operate and maintain the customers facilities in a manner which will not physically or electronically interfere with or cause signal degradation to the COD electric, wastewater, or water system operations, with COD communications systems, existing as of the date of the dark fiber lease or with any prior leases, provided the COD has disclosed to the customer the existence of (but not necessarily the identities of) and technical information relevant to the prior leases. The customers’ duty to avoid interference in accordance with the terms of this SOP shall remain absolute throughout the lease terms, irrespective of favorable pre-installation analyses or varying operating conditions, provided the COD supplied technical information is accurate and complete. If the customers’ equipment causes interference after the initial lease begins, the customer shall correct it as soon as practical after proper notification. Remedies for Interference In the event that the customers facilities or operations interfere with the COD system or with those of prior customers leases (including interference affecting one or more fiber segment), then upon written notice from the COD, the customer shall at its own expense correct the interference within seventy-two (72) hours from notice, even if the customers’ facilities are operating in compliance with the FCC regulations. If the customers fails to eliminate the interference within the required time, then after an additional twenty-four (24) hour grace period for the customer to eliminate the interference, the COD shall have the right to immediately enter the premises and shut down the customers facilities until the customer can eliminate the interference or, as a last resort, to terminate the affected dark fiber segment. In the event of termination, the COD shall remove the COD facilities from the customers’ premises within a reasonable time. The customer shall compensate the COD for any new line extensions and/or make them whole for any build-out expenses. Technical Disagreements If the customer disagrees on the existence, source or extent of interference, the COD may engage an independent engineering firm to perform impartial analyses to determine the cause of the interference. The COD shall be entitled to reimbursement for the cost of such analyses by the customer if the customer is found to be causing the interference. Taxes, Licenses, Liens During the term of the agreement, customer shall pay, when due, all applicable taxes, including premise or property taxes, sales and use taxes, or any other fees in lieu of taxes assessed pursuant to the use of the Dark fiber by customer. The customer shall keep the dark fiber free from all liens, including but not limited to mechanics liens, and encumbrances by reason of the use of the dark fiber by the customer. The customers’ failure to pay such is a breach of this agreement. If the customer fails to pay the above mentioned taxes, assessments, or other fees when due, the COD shall have the right to terminate the lease and demand immediate payment for any expenses related to the fiber 9

optic cable extension. City of Dover Racks and Equipment As additional consideration, the COD shall have the option to install racks and equipment, at its sole expense, within the customer’s point of presence which is located at the mutually agreed upon access point(s). The point of presence in existing locations is where the customer’s network has termination points for the COD fiber. The type and location of such racks and equipment shall be agreed to in writing between the COD and the customer in separate agreement. The COD may compensate the customer for this collocation at a rate that is mutually determined to be reasonable and just. Said racks, as well as any and all electronic equipment installed therein, shall be and remain the sole and exclusive property of the COD, and the customer shall neither make any claim on or claim any property interest in such equipment, nor shall the customer permit any lien or other encumbrance upon the COD equipment by the customer or any third party. Said racks and any and all equipment placed thereon shall be installed in accordance with the COD standard practices. Absent emergency situations, the COD shall be able to access said racks and equipment during the term of the agreement upon reasonable notice to the customer and shall be solely responsible for their operation, maintenance and repair. Upon termination of this lease by the expiration of the term hereof or otherwise, the COD shall immediately remove said racks as well as any and all electronic equipment installed thereon and shall leave the area in its original condition, reasonable wear and tear excepted unless mutually agreed to leave the COD equipment in the current location. Maintenance Dark fiber The customer agrees to pay all costs (time and material) of maintenance/repair of the network if the required work is caused by the customer’s improper connection to the dark fiber. The customer agrees to use reasonable efforts to perform such maintenance, if required, to not cause damage to the COD fiber. Customers Notification of Outage Subject to Force Majeure, the customer will notify the COD to respond to outage emergencies in connection with the dark fiber. The customer shall call the COD at 302/736-7086, the System Operations Center, to schedule all maintenance operations and to report service interruptions. In the event of interruptions longer than 24 hours, the COD will, as soon as is reasonably possible, provide alternate capacity to the customer subject to availability within the customer’s facilities. In 10

the event of an interruption longer than 96 hours, the customer shall be entitled to an abatement of its fees, equal to the total interruption time, to be deducted from the next payment otherwise due under this SOP. The period(s) of any interruption(s) shall be measured from the time the COD actually receives notice, to the time the service is reportedly restored to the customer. Scheduled outages, for maintenance purposes, shall not be counted as interruptions. Scheduled outages shall be those outages of which customer has had at least a five (5)-day advance notice. To the extent possible, the customer and the COD shall agree upon the times maintenance will be performed so as not to interfere with customers business, however the COD retains the right to perform maintenance on dark fiber upon proper notification to customer without a mutual agreement between parties. The customer shall provide the COD – Electric Engineering Division, a contact name and number for notifications of potential fiber work that might interrupt the service or other issues that may arise. The COD does NOT GUARANTEE continuous dark fiber service and will not be liable for any loss, cost, damage or expense to any customer occasioned by an interruption of service. Restoration Priority In the event that the COD electrical and/or communications service capacity and the customer dark fiber capacity are interrupted, restoration of the customer’s dark fiber shall be at all times subordinate to restoration of COD electrical and communications system. Should the COD not be able to effect repairs within twenty-four (24) hours after notice of the emergency, both parties agree to meet to determine methods to restore the customers fiber(s) including consideration of the COD granting the customer permission to make repairs to the COD connections and/or dark fiber and to restore its capacity, as long as such restoration efforts do not interfere with the COD restoration activities. Payment for this restoration shall be mutually agreed upon prior to the customer performing the work. Both parties acknowledge that, in the event that an outage is caused by a natural disaster, weather, automobile accident or similar incident, which causes a simultaneous electrical power outage, that the electrical power must first be restored prior to the fiber network. It is further acknowledged by the Parties that as a Municipal Electric Utility, the COD has a duty to provide electrical services to its customers, and that provision of said electrical services shall be the COD top priority. Relocation Dark fiber The customer shall request no changes in the location of the dark fiber access point without sixty (60) days written notification to the COD. If the customer desires, for any reason, to relocate any of the facilities used or required in providing the dark fiber, such relocation shall be undertaken at the customer’s sole cost and expense and shall be paid to the COD within 30 days after receipt of the invoice. 11

If for any reason, the COD is required to relocate any of the dark fiber facilities for its convenience, or by any third party including, but not limited to a government entity, whenever reasonably possible, the COD shall give the customer at least thirty (30) days notice, or as much time as the COD can reasonably provide. This notice will include all pertinent information and the impact of the relocation to the customer’s service. All costs associated with such required relocation, which are not paid by a third party, shall be the sole responsibility of the COD. During any relocation(s), scheduled outages may occur; the COD will keep the duration of these outages as short as possible. Access Points The COD shall make no changes in the location or configuration of the Access Points to the dark fiber without consultation with the customer. The customer agrees that any relocation required of the dark fiber or access points shall be limited to the shortest practical route reasonably available. In the event relocation of the customer’s access points is required by any third party, any governmental agency, or in conjunction with the electric system needs of the COD, all costs associated with such required relocation of the customers access points, which are not paid by a third party shall be the sole responsibility of the customer. In the event of such relocation requirement, the COD shall use reasonable efforts to provide alternate locations for access points. If the customer requests a relocation of the access point the customer will be financially responsible for any COD expenses related to the relocation. After any relocation is completed, the customer’s fee shall be adjusted accordingly with regard to the length of fiber used by customer; however, if the dark fiber length is reduced and the dark fiber was a new extension for the customer, the fee shall not be reduced for the initial term. Reclamation Subject to the terms, conditions and limitations set forth in this SOP, the COD shall have the right to terminate from time to time the lease of any or all of the dark fiber on any or all segments of the network for use (and solely for use) directly by the COD. In the event that the COD desires to reclaim any dark fiber, the COD shall give notice of such intent to the customer at least twelve (12) months prior to the date of reclamation (Reclamation Notice). The Reclamation Notice shall identify each leased fiber on each segment, which the COD desires to reclaim, and the intended date of reclamation. At any time following receipt of a Reclamation Notice, the customer may initiate negotiations with the COD as to possible alternatives to reclamation, including, for example, (1) greater compression of COD traffic on the fibers within the network already in use by the COD, (2) alternate or additional optoelectronic equipment, (3) alternate routes, and/or (4) installation of additional fibers within the fiber network. The customer and the COD each shall conduct any such negotiations in good faith. The exact alternative(s) to reclamation (if any) and the allocation of the costs thereof between the 12

parties shall be subject to mutual consent. Unless otherwise agreed between the customer and the COD, reclamation shall be effective on the date of reclamation set forth in the Reclamation Notice. Representations and Warranties The COD is not a Telecommunications Company. The development of this SOP does not classify the COD as a Telecommunications Company, Telecommunications Carrier, Telecommunications Service Provider or any other telecommunications entity as defined by federal or state laws, rules, regulations or administrative orders, nor will the COD come under the jurisdiction or regulation of any State or Federal regulatory agency with regulates such entities, including, without limitation, the Federal Communications Commission (FCC) or the applicable State Commission. In the event that the existence of this SOP results in a final order or determination by any court or regulatory or governmental entity (including, but not limited to, the FCC or the applicable State Commission) that classifies the COD as a Telecommunications Company, Telecommunications Carrier, Telecommunications Service Provider or any other telecommunication entity as defined by federal or state laws, rules, regulation or administrative orders, the customer shall indemnify and hold the COD, its officers and employees harmless from and against any cost, expense, fine or other financial penalty under federal or state laws, rules, regulations, or administrative orders, which the COD is legally liable to pay as a result of such classification, provided, however, that the COD shall take all reasonable steps to mitigate and minimize any such expenses, fines or other financial penalties. In no event shall the customers’ indemnification hereunder exceed the total of customer payment to the COD during the previous twelve months for the use of the COD fiber optic strands under this fiber lease(s) and applicable extensions. In the event of any such determination, the customer and COD agree, to cooperate with each other to determine whether and to what extent this SOP can be amended so as to remove that classification and permit continued performance by both parties, subject to the COD right to cancellation as contained in this SOP. Notwithstanding any other provision of this SOP, if customer is required to make payments under this indemnification, then the customer will have the right to immediately terminate this lease. Such termination, however, shall not extinguish the customers’ obligation to indemnify the COD for all monetary amounts levied until the time of the termination and shall not extinguish the customer obligation to pay any other amounts owing to the COD pursuant to this SOP and lease. The COD confirmed through its City Solicitor that there are no State Regulations that would bar it from providing dark fiber leasing at the time of the inception of this SOP. The customer represents that, to its knowledge, after due inquiry, it has the right and authority to enter into this agreement and grant the rights and Licenses contained herein. The COD represents that, to its knowledge, after due inquiry, it has all licenses, permits and rights authorizing it to enter into this Agreement. 13

The COD is a municipally owned utility certified in Delaware to provide electric and other services to Dover and some of the surrounding area. Assignment and Transfer Unless specifically provided herein, the COD shall not assign, transfer or sublet any of the privileges described in this SOP without the prior written consent of the customer, said consent not to be unreasonably withheld, provided that the COD may assign, transfer or sublet its rights hereunder to a parent, or wholly-owned affiliate or subsidiary company or purchaser of all or substantially all of its assets or stock without consent of the customer. The customer will not, directly or indirectly, or through a controlled affiliate of the customer, transfer or sublet any of the privileges described in this SOP to a third party. Indemnification The customer does hereby release and agrees to indemnify, defend and save harmless the City of Dover and its agents from and against all claims, actions, causes of action, demands, judgments, costs, expenses and all damages of every kind and nature, incurred by or on behalf of any person or corporation whatsoever, predicated upon injury to or death of any person or loss of or damage to property of whatever ownership, including the parties to this SOP and their employees, and arising out of or connected with, in any manner, directly or indirectly, the COD operations or rights granted under this SOP. Insurance The customer agrees to execute and deliver to the COD at the time of acceptance and execution of a fiber lease commitment, a commercial general liability insurance policy, including public liability, contractual liability, premises liability, and property damage, acceptable to and approved by the City Risk Manager, covering bodily injury and property damage, premises, operations described hereunder and products therein, in amounts of $150,000 per individual; $600,000 per occurrence. The City of Dover shall be listed as an additional named insured in any required liability insurance policy. Such policies shall state that this coverage is to function as the "primary" insurance coverage for the customer. Certified copies of the above policy, or a certificate evidencing the existence thereof, or a binder shall be delivered to the COD upon the execution of a fiber lease. In the event a binder is delivered, it shall be replaced within ten days by a certificate of insurance. Each such policy or certificate shall contain a valid provision or endorsement that the policy may not be canceled, terminated, changed or modified without giving thirty days written notice thereof to the COD. 14

A renewal certificate shall be delivered to the COD at least fifteen days prior to a policy's expiration date except for any policy expiring on or after the expiration date of this agreement. The customer further shall at all times maintain adequate Workmen's Compensation Insurance with an authorized insurance company insuring the payment of compensation to all employees engaged in the operation of the facility. Failure to maintain or provide proof of insurance shall constitute an immediate breach of the Agreement and shall be considered cause for termination of this Agreement at the sole discretion of the COD. At all times during the term of this agreement, the customer shall maintain and shall require its contractor and subcontractors, which do any work in connection with this agreement, to maintain insurance coverage as described herein and will produce proof of insurance on demand by the COD. Excess liability/umbrella coverage for limits of not less than $1,000,000 excess of $1,000,000 each occurrence. Such insurance shall name the COD, its officers, agents, and employees as additional insured. In the event the customer fails to obtain the required insurance, the COD reserves the right to purchase insurance on the account of the customer, but is not required to do so. Default In the event either Party shall fail to observe or perform any of the terms and provisions of this agreement and such failure shall continue for a period of thirty (30) days after receipt of written notice from the non-defaulting party (“Default”), then the non-defaulting party may terminate this agreement, provided however, that where such Default cannot reasonably be cured within such period, and the defaulting party has proceeded promptly to cure the same and is prosecuting such cure with diligence, the time for curing such Default shall be extended for an amount of time, not to exceed sixty (60) days, as may be necessary under the circumstances to complete such cure. If the customer is the defaulting party the COD shall immediately issue an invoice for any outstanding extension expenses. Termination The COD may, at its sole discretion, terminate this lease agreement upon the conditions set forth for cause and at its discretion. For Cause, Without Illegality The COD may terminate this agreement and may repossess the Dark fiber in the event that any payment or amount is not furnished by the customer as set forth in the Compensation Section, hereof, 15

when due, upon giving fifteen days written notice to the customer of the COD intention to terminate unless full and proper payment is made to the COD of all monies due on or before the expiration of the fifteen day period indicated in the notice. For Cause, With Illegality The COD may, at its sole discretion, terminate this agreement, effective immediately, upon the giving of written notice of termination, in the event that COD is deemed to engage in, or permits, the violation, pursuant to the appropriate standard of proof provided by law, of any federal, state or city penal law or ordinance in the operation of said facility. Surrender of Dark fiber Upon Termination On the customers expiration date or any earlier termination of customers rights to use any or all of the dark fiber under this agreement, regardless of the reason for termination, the customer shall promptly (1) remove all of its equipment and other property from the COD fiber, and (2) peaceably quit and surrender the dark fiber to the COD in a condition consistent with condition of fiber and access points on the original acceptance date. Renewal Provisions The customer shall provide ninety (90) days notice of intent to renew dark fiber agreement prior to date of expiration of current agreement and the COD agrees to extend the agreement when feasible. General Provisions Costs Except as otherwise expressly provided above, each party shall bear all of its own attorney’s fees and other expenses related to a fiber lease. No Third Party Beneficiaries None of the terms or conditions in this SOP shall give or allow any claim, benefit, or right of action by any third person not a party hereto. Any person other than the COD or the customer receiving services or benefits under this SOP shall be only an incidental beneficiary. No Partnership The Parties acknowledge and agree that fiber lease or service does not create a partnership between, or a joint venture of, the customer and the COD. Binding Effect This SOP and subsequent agreement shall be binding upon, and shall inure to the benefit of, the parties hereto and their respective successors and assigns. 16

Severability In the event any term, covenant or condition of this SOP and/or lease agreement, or the application of such term covenant or condition, shall be held invalid as to any person or circumstance by any court having jurisdiction, all other terms, covenants and conditions of this SOP and their application shall not be affected thereby, but shall remain in force and effect unless a court holds that the invalid term, covenant or condition is not separable from all other terms covenants and conditions of the SOP. Force Majeure Neither party shall be liable to the other for any failure of performance under this SOP/lease agreement due to causes beyond its control, including, but not limited to: acts of God, fire, terrorist attack, flood or other catastrophes, adverse weather conditions, material or facility shortages or unavailability not resulting from such party’s failure to timely place orders therefore, lack of transportation, the imposition of any governmental codes, ordinances, laws, rules, regulations or restrictions, national emergencies, insurrections, riots, wars, or strikes, lock-outs, work stoppages or other labor difficulties. Waiver No delay or omission by either party to exercise any right or power occurring upon non-compliance or failure of performance by the other party shall impair that right or power or be construed to be a waiver thereof. A waiver by either party of any of the covenants, conditions or agreements to be performed by the other party shall not be construed to be a general waiver of any such covenants, conditions or agreements, but the same shall be and remain at all times in full force and effect. Headings The Section headings herein are for convenience and reference only, and in no way define or limit the scope and content of this SOP or in any way affect its provisions. No Implied Representations No representations, agreements, covenants, warranties, or certifications, express or implied, shall exist as between the parties, except as specifically set forth in this SOP and subsequent fiber lease. Integrated SOP and Amendments This SOP is an integration of the entire understanding of the parties with respect to the matters set forth herein and shall include completed request for service application. The COD reserves the right to modify or change this SOP from time to time without notice to any party leasing dark fiber. These modifications will be approved by the City Council through accepted methods. 17

The Energy Authority, Inc. Monthly Management Committee Update – February 2013 March 28, 2013 Prepared by: Robert Trinnear Client Services Manager 904.360.1309 rtrinnear@teainc.org

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

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $647,823 under budget due to lower than budgeted cost of hedged energy and energy purchases. Dover’s budgeted cost for all power supply (capacity AND energy) was $92.87/MWh. The actual cost of all power supply (capacity AND energy) was $85.59/MWh. The cost of energy alone was $60.25/MWh, versus a budgeted energy cost of $70.32. Dover’s hedge purchases totaled 45,120 MWh, which was 77% of the projected load and 80% of the actual load. Dover’s power purchases from hedge transactions totaled $2,925,512. Purchases from PJM (energy and fees) totaled $865,704 with DA Energy purchases totaling $543,024 and Balancing Spot Market Energy totaling a credit of $162,063. Dover’s total load was 56,258 MWh versus a forecasted load of 58,826 MWh. Dover’s planned energy purchase from the SunPark solar installation was 963 MWh. Dover’s actual energy purchase from the SunPark installation was 908 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 58,826 56,258 2,568 Wholesale Load 57,863 55,350 2,513 Hedged Volume (MWh) 45,120 45,120 - Unhedged Volume (MWh) 12,743 10,230 2,513 Dover SunPark Volume (MWh) 963 908 55 Renewable Energy Credits Volume 144 116 28 Hedged Cost ($/MWh) $ 67 $ 65 $ 2 Unhedged Energy Cost ($/MWh) $ 80 $ 37 $ 42 Solar Energy Cost ($/MWh) $ 83 $ 86 $ (3) Energy Costs ($/MWh) $70.32 $60.25 $10.07 All-in Costs - Energy, Capacity and RECs ($/MWh) $92.87 $85.59 $7.28 2

B. Generation Summary: Dover generated 0 MWh in the month. Net generation revenue was $747,690 vs. a budget of $767,821. This delta was mainly due to higher than budgeted O&M costs. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 0.00 All In Generation Margin PJM Bill Energy $ - PJM Capacity $ 1,089,270.00 Black Start, Reactive Credit, DASR & EFORp $ 36,373.16 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Margin $ 1,125,643.16 Production Margin Generation Production Revenues (PJM) $ - Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Production Margin $ - $/Mwh All In Generation Margin $ - $/Mwh Generation Production Margin $ - 4

C. Emissions Summary: Emissions Allowance Summary through February 28, 2013 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 Jan 2013 2013 Allocation 1,988 51 80 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) 2/28/2013 2013 Emissions 0 0 0 REMAINING ALLOWANCES 11,053 114 198 On August 21, 2012, the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s “Transport Rule” (aka Cross State Air Pollution Rule or CSAPR) which would have become effect on January 1, 2012. Additionally, DCA said EPA must continue administering the Clean Air Interstate Rule (CAIR), CSAPR’s predecessor, pending the issuance of a valid replacement rule. EPA submitted a petition for an en banc rehearing to the DCA on October 5, 2012 and is awaiting a ruling on the petition. 1 Per CAIR, starting in 2009, NOx emissions are governed by a seasonal and annual program. 2 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 5

Market liquidity for CAIR allowances continues to be low, with few transactions occurring. The following table shows estimated values for Dover’s banked allowances, based on broker bids & offers: Mark-to-Market for CAIR Allowances (3/4/2013) Commodity $/Ton Tons Extended Value (Bid/Offer Avg.) SO2 Allowances $ 0.60 11,053 $6,632 NOx Allowances - Seasonal $20.00 114 2,280 NOx Allowances - Annual $35.00 198 6,930 TOTAL $15,842 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 has 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 cumulative balance of unused RGGI allowances held by Dover were 104,505 tons as of the end of Calendar year 2012, as shown in the table below. During January & February 2013, Dover’s generating units have not operated; therefore CO2 emissions have been zero. 6

CO2 Allowance Summary (2/28/2013) 1 2 3 4 5 6 7 8 CO2 Allowances Available Annual CO2 CO2 (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance Allowances Prior to Sale) CO2 Vintage Sold YTD Allowances Emitted Allowance Balance McKee Balance VanSant Run 2009 0 60,128 2,056 62,184 (5,796) 56,388 56,388 2010 0 48,102 1,645 49,747 (32,971) 16,776 73,164 2011 0 36,077 1,234 37,311 (17,763) 19,548 92,712 2012 0 27,058 925 27,983 ( 15,265) 11,793 104,505 2013 0 15,032 514 15,546 - 15,546 120,051 The table shows that the “Allocated CO2 Allowances” (column 5) are declining. After 2013, Dover will no longer receive allocations of RGGI allowances. Actual CO2 emissions (column 6) have varied from 5,796 tons in 2009 to 32,971 tons in 2010. The Cumulative Balance (column 8) – aka “Banked Allowances”) can be utilized for generation in future years (including 2013). Once the banked allowances have been fully utilized, Dover will be required to purchase allowances through the periodic RGGI auctions or through over- the-counter markets. Assuming that Dover does not sell any banked allowances, it will be able to maintain a positive balance through 2016 – 2025, depending on actual annual energy production in 2012 and beyond. On February 7, 2013, RGGI proposed changes to its Model Rule. The proposed changes include: 7

 A reduction of the 2014 regional CO2 budget, “RGGI cap”, from 165 million to 91 million tons – a reduction of 45 percent. The cap would decline 2.5 percent each year from 2015 to 2020.  Additional adjustments to the RGGI cap from 2014-2020. This will account for the private bank of allowances held by market participants before the new cap is implemented in 2014. From 2014-2020 compliance with the applicable cap will be achieved by use of “new” auctioned allowances and “old” allowances from the private bank.  The Minimum Reserve Price for 2014 will be $2.00 and increase by 2.5% per year thereafter.  Cost containment reserve (CCR) of allowances that creates a fixed additional supply of allowances that are only available for sale if CO2 allowance prices exceed certain price levels ($4 in 2014, $6 in 2015, $8 in 2016, and $10 in 2017, rising by 2.5 percent, to account for inflation, each year thereafter.)  Updates to the RGGI offsets program, including a new forestry protocol.  Not reoffering unsold 2012 and 2013 CO2 allowances.  Requiring regulated entities to acquire and hold allowances equal to at least 50 percent of their emissions in each of the first 2 years of the 3 year compliance period, in addition to demonstrating full compliance at the end of each 3 year compliance period.  Commitment to identifying and evaluating potential tracking tools for emissions associated with electricity imported into the RGGI region, leading to a workable, practicable, and legal mechanism to address such emissions. With the release of the Updated Model Rule, the RGGI states now plan to revise their CO2 Budget Trading Programs through their individual state-specific statutory and regulatory processes. Each RGGI state seeks to complete their state specific processes such that the proposed changes to the program would take effect on January 1, 2014. 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 15, 2013 and the auction cleared at $2.80/ton. Based on this auction, the value of Dover’s existing RGGI allowance bank (120,051 tons) is approximately $336,143. The next RGGI auction will be held on June 5, 2013. Dover has not registered to participate in this upcoming auction. 8

Renewable Energy Certificates Dover owns two photovoltaic systems totaling 15 kW, consisting of (a 5 kW unit at the Utilities Administration Building and two 5 kW units at the McKee Run generating station. The output has been recorded on PJM’s Generation Attribute Tracking System (GATS), resulting in a balance of 48 Solar Renewable Energy Certificates (SRECS) for all generation through December 2012. 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 2013, Dover has accumulated a total of 4,059 SRECS from this contract. Given the current SREC market structure, combined with the impact of the Sun Park and other facilities coming on-line in 2011, Dover’s ability to remarket excess SRECs presents unique challenges. Market price for Delaware SRECs from the September 2012 auction was $40/MWh, resulting in a theoretical market value of $164,280 for Dover’s 4,107 SRECs. It should be noted, however, that the nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s February 2013 SREC auction cleared at $10/MWh. Using this price, Dover’s SRECs would have a market value of $41,070. The next auction for Delaware’s RECs opened on March 21st, 2013 and closes on April 12, 2013. Results for this auction should be available for the next monthly report. 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. 9

D. Operations Management Summary: During the month of February, there were no reportable or lost time accidents or injuries. The facility has now gone 868 days without an OSHA recordable accident and 868 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were no Near Miss incidents. In the month of February, no units were dispatched by PJM nor were they self-dispatched. Work continues on the installation of the industrial waste water discharge system and preparations for the spring planned outages for all units. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of February were $377,953. The actual expenses are $20,924 or 5.86% over the approved budget of $357,029. The principal reason for the unfavorable variance was due to timing of expenses for asbestos abatement and insulation repairs which were budgeted later in the year. E. Risk Management Summary: Forward power prices in PJM have risen slightly since last month due to higher forward gas prices and resulting in a slightly higher blended cost. The current projected cost of service is below: Blended Power Cost Year Hedge Ratio ($/MWh) 2012-13 80% $61.43 2013-14 56% $51.86 2014-15 30% $48.06 2015-16 14% $47.24 10

II. Budget Report Variance Report: Budget Actual Variance Feb-13 Feb-13 Gross Load 58,826 56,258 2,568 Power Supply Hedged Energy $3,034,491 $2,925,512 $108,979 PJM- Energy $1,015,925 $380,960 $634,965 PJM - Transmission and Fees $313,000 $484,744 ($171,744) Dover SUN Park Energy $86,357 $82,917 $3,440 Management Fees $83,000 $83,000 $0 Capacity UCAP Obligated Purchased $930,281 $858,098 $72,183 Subtotal - Power Supply $5,463,054 $4,815,231 $647,823 Power Generation O&M & Fixed Fuel Plant O&M $357,029 $377,953 ($20,924) Subtotal Generation O&M $357,029 $377,953 ($20,924) Power Generation Production Margin Economic and reliability dispatch $0 $0 $0 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation Production Margin $0 $0 $0 Power Generation Non-Production Revenue Generation Capacity Credit ($1,089,270) ($1,089,270) $0 Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($35,580) ($36,373) $793 Subtotal - Non-Production Revenue ($1,124,850) ($1,125,643) $793 SubTotal - All Generation ($767,821) ($747,690) ($20,131) Total - Utilities Cost $4,695,233 $4,067,541 $627,692 Unit Costs Total - Power Supply $92.87 $85.59 $7.28 Total - Power Generation ($13.05) ($13.29) $0.24 Final Cost of Service to City of Dover Ratepayers $79.82 $72.30 $7.51 11

Variance Analysis: Power Supply  Dover consumed 2,568 MWh less than what was forecasted for the month.  PJM energy costs were lower than expected, but PJM’s fees were higher than forecast. Hedged costs were under forecast.  The result of lower overall costs for more power was a net power supply cost of $85.59/MWh, $7.28/MWh lower than budget.  For the month, the city realized a favorable variance of $647,823 for power supply vs. the monthly budget.  Dover Sun Park generated 55 MWh less than what was forecasted. Generation  Power generation had an unfavorable budget variance of $20,131.  Plant O&M expenses had an unfavorable budget variance of $20,924 for the month. 12

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 508,631 513,525 (4,894) Power Supply Hedged Energy $27,092,210 $26,127,125 $965,085 PJM- Energy $9,300,866 $3,747,275 $5,553,591 PJM - Transmission and Fees $2,504,000 $5,020,487 ($2,516,487) Dover SUN Park Energy $864,239 $912,579 ($48,340) Management Fees $664,000 $664,000 $0 Capacity UCAP Obligated Purchased $8,073,509 $7,449,156 $624,353 Subtotal - Power Supply $48,498,824 $43,920,623 $4,578,202 Power Generation O&M & Fixed Fuel Plant O&M $3,665,182 $3,534,293 $130,889 Subtotal Generation O&M $3,665,182 $3,534,293 $130,889 Power Generation Production Margin Economic and reliability dispatch ($1,124,312) ($1,865,596) $741,284 Fixed Fuel and Transport Charges $586,004 $948,814 ($362,810) Subtotal Generation Production Margin ($538,308) ($916,782) $378,474 Power Generation Non-Production Revenue Generation Capacity Credit ($9,453,310) ($9,453,307) ($3) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($284,640) ($346,885) $62,245 Subtotal - Non-Production Revenue ($9,737,950) ($9,800,192) $62,242 SubTotal - All Generation ($6,611,076) ($7,182,681) $571,605 Total - Utilities Cost $41,887,748 $36,737,942 $5,149,807 Unit Costs Total - Power Supply $95.35 $85.53 $9.82 Total - Power Generation ($13.00) ($13.99) $0.99 Final Cost of Service to City of Dover Ratepayers $82.35 $71.54 $10.81 13

III. Operations Management NAES Corporation Dover, Delaware February 2013 Monthly Report Newly Installed Industrial Waste Water Pumps 14

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 15

1.0 Environmental, Health and Safety: During the month of February, there were no restricted work days or lost time accidents. The facility has now gone two years, four months and fourteen days (868 days total) through February 28, 2013 without an OSHA Recordable Accident or a Lost Time reportable accident. The January DMR was submitted for the McKee Run site with no NPDES exceedences. The plant received no Notice of Violations (NOVs) during the month. The EPA and the DNREC were onsite for a full Title V compliance audit. During the audit, a preliminary result of “No Findings” was issued. Additional data was sent to EPA/DNREC for review however no issues are anticipated. An audit report is expected to be available within forty-five days. Work continues on the Industrial Wastewater Project with both Mechanical and Electrical Contractor onsite work to commence March 4. Plant personnel continue to make modifications to the existing system to accommodate the project tie-ins and keep project costs lower. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (February) (7/1/12-2/28/13) NOVs 0 0 Opacity Deviations 0 0 Environmental Deviations 0 7 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 4,104.75 33,616.50 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 868 Days since last Lost Time Accident 868 16

Emissions (NOx & SO2) All data thru 2/28/13 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 31.4 1.4 36.1 2012 1.2 1.0 35.8 1.0 33.1 2013 0.0 0.0 0.0 0.0 0.0 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 32.6 2.9 38.8 2012 1.2 1.1 35.8 1.0 36.9 2013 0.0 0.0 0.0 0.0 0.0 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 2012 0.0 0.0 0.0 0.1 0.1 2013 0.0 SO2 0.0 Allowances 0.0 Summary 0.0 0.0 SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 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* *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. 17

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 4/2 2013 0 71/46 5/3 0/0 – 0/0 0/0 - 0/0 71/46 5/3 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. **Note – The facility transferred Ozone Season allowances to a third party. ***Note- The facility transferred Annual allowances to a third party CO2 Allowances Summary* CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Sold YTD Sale) Balance McKee Run VanSant 2009 0 60,128 2,056 5,796 56,388 2010 0 48,102 1,645 32,971 16,776 2011 0 36,077 1,234 17,763 19,548 2012 0 27,058 925 15,265 11,793 2013 0 15,032 514 0 15,546 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 18

2.0 Financial Financial – Current Month Month – February Actual Budget Variance Personnel 247,479 246,079 (1,400) Materials & Supplies 9,037 11,740 2,703 Administrative Expenses 121,437 99,210 (22,227) Total $377,953 $357,029 $(20,924) Financial – Fiscal Year to Date Number of Months – 8 Actual Budget Variance Personnel 2,021,638 2,087,552 65,914 Materials & Supplies 158,471 163,440 4,969 Administrative Expenses 1,354,183 1,414,190 60,007 Total $3,534,292 $3,665,182 $130,890 2.1 Variance analysis: The City of Dover Finance Department has closed the books for the month of February 2013. The expenses for February are $377,953 against a budgeted amount of $357,029 for an unfavorable variance of $20,924 or ≈ 5.86%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $1,400 was due to having higher than expected overtime labor (fill-ins for holidays and vacations). This was partially offset by lower than budgeted labor burdens. MATERIALS AND SUPPLIES EXPENSES- A favorable monthly variance of $2,703 was primarily due to lower than expected water usage and the timing of the invoice for the annual metering system maintenance contract. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $22,227 was due to expenses for asbestos abatement, insulation repairs, and equipment to support gas line purges that are part of outage support. These were partially offset by positive variances in Heating Oil / Gas (milder than normal temperatures) and Fire Protection Systems (timing of invoices for the annual fire equipment inspection). The budget is currently forecasted to finish this fiscal year at $5,865,365 expensed versus an approved budget of $5,914,900 thereby realizing a 99.16% expenditure rate. 19

3.0 Operations Unit Operations / Outages / Trips No units were dispatched by PJM and none were self-dispatched for the month of February. All units were ready and available for dispatch if needed. Month February 2013 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 27.924 27.924 129.252 185.100 5.672 190.772 Auxiliaries purchased MWh 27.924 27.924 129.252 185.100 5.672 190.772 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 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 100.0 100.0 100.0 100.0 100.0 100.0 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 0.00 0.00 0.00 0.00 0.00 0.00 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 672.000 672.000 672.000 2,016,000 672.000 2,688.000 Hours HW Boiler Gas Usage MMBTU 686.243 686.243 Pilot Gas Usage MMBTU 0 0 0 0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 20

2012-2013 Fiscal Year-to-Date - February 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 96.282 71.970 285.597 453.849 22.066 475.915 Starts # 3 2 26 31 4 35 Gross Generation MWh 668.79 582.202 18,797.488 20,048.48 714.818 20,763.298 Net Generation MWh 628.855 541.673 17,317.513 18,488.041 714.287 19,202.328 Total Auxiliaries MWh 263.814 264.407 2,856.946 3,385.167 25.689 3,410.856 Auxiliaries purchased MWh 223.879 223.879 1,376.971 1,824.729 25.158 1,849.887 Fuel Gas Used MMBTU 9,483 8,108, 199,166.724 216,348 8,429, 225,188 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 112.567 112.567 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 5,806 5,806 Total Fuel MMBTU 9,483 8,108, 199,166.724 216,348 8,54 225,301 Net Heat Rate BTU/KWh 15,021 14,970 11.826 13,939 12,604 13,271 Unit Trips # 0 0 1 1 0 1 Capacity Factor % 0.61 0.55 2.93 2.34 0.32 1.89 Availability Factor % 73.90 73.90 73.90 73.90 73.90 73.90 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 1,512 1,512 1,512 4,535 1,512 6,047 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 4,227.218 4,248.030 4,034.570 12,509.818 4,297.934 16,807.752 Hours HW Boiler Gas Usage MMBTU 2,560.313 2,560.313 Pilot Gas Usage MMBTU 1,340 1,049 2,389 2,389 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 12-13 Fuel FY 12-13 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 448,556 448,556 0 0 454,725 0 (6,169) VanSant 143,183 143,520 0 337 152,150 0 (8,630) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through 2/28//13 Actual Starts Factored Starts Fired Hours VanSant 1304 2233.75 4217.96 Since HGP - Dec 2004 230 566.05 834.38 21

Team Report: Operations staff has been assisting maintenance with the piping to the well pump building and from the fire pump room of the Industrial Wastewater Project. Operation staff also LOTO all the units for the spring outage and performed a purge on Units 1 and 2 main gas and pilot gas lines. 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. The Plant Operations staff participates in the OES-NA training that helps prepare them for the PJM Certified System Operator exam and provides some of the required continuing education hours (CEHs) necessary to maintain PJM Certified System Operator qualifications. Additionally, members of the McKee Run staff participated in the PJM system restoration simulation drills/training that was conducted during the month of February, which also contributes CEHS to maintaining their Certified System Operator Certification. Capacity Testing – FY 2012-2013 Summer 2012 (June 1- Aug 31) Winter 2012-2013 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.0 1 17 * 2 17 17.3 2 17 * 3 102 102.7 3 102 * VanSant 39 39.0 11 39 * Total 175 176.0 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program 22

4.0 Maintenance During the month of February, the Plant Maintenance staff continued addressing the backlog of work orders and completing outage activities. There were seventy-one work orders issued with fifty-eight work orders being completed during the month. There were no safety work orders entered into the plant’s Computerized Maintenance Management System (MP2) during the month. The table below summarizes the monthly work order activities. Work Order Report February - 2013 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 14 0 7 7 2 34 20 13 41 3 49 2 9 42 4 7 0 0 7 5 16 2 0 18 SW1 0 0 0 0 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 64 47 29 82 Totals 184 71 58 197 Note: PMs are included in the priority totals Notable activities during the month include:  NAES Mechanical Maintenance Staff completed the relocation of two Hot Water Pumps that will be implemented into to The Industrial Waste Water Project. The old concrete pads were removed and new pads were poured. The pumps were mounted into place and grouting was installed around the base of the pump.  NAES Staff assisted US Tank Protectors in the cathodic protection inspections of the underground oil lines at VanSant. There were no issues found on the system.  NAES Mechanics removed the water lines from the shallow well water building to the hydrogen room. The staff then installed new piping and hangers from the newly installed waste water pump room to the corner of the hydrogen room. It is at this point that the IWW mechanical contractor will tie in their portion of the system. 23

5.0 Capital Improvement Projects (CIP) Project Description Update Number Units 1 & 2 Cooling Progress: The FY2013 work scope package being developed EG1102 Tower Repairs Schedule: Work scheduled to be completed in the 4th quarter Progress: Work scheduled for the Spring 2013 outage. Completion Unit #3 Boiler at 20%. EG1202 Systems Schedule: Bids were obtained; contract work awarded and work to be completed in the Spring 2013 outage. Progress: The FY13 Spring Outage contract work bids have been Unit 3 Auxiliary evaluated and contracts have been awarded. EG1203 System Components Schedule: Scheduled work is on track for completion by end of Spring 2013 outage. Progress: Long lead material requirements being developed for bid. Unit 3 Turbine EG1212 Schedule: Long lead items will be procured in the spring of 2013. Repairs Progress: The FY2013 work scope package being developed Units 1 & 2 EG1304 Schedule: Work to be completed during the spring outage Components Repairs Progress: The FY2013 work scope package being developed, Turbine Level although feedback from insurance company reveals that their EG1306 Window recommendation to perform this work is expected to be withdrawn. modification Schedule: Work to be completed during the 3rd quarter of FY13. Progress: Material has been purchased, delivered ,and has been Unit 3 Air Heater installed EG1112 Expansion Joint Schedule: Work was completed in November. Project will be closed. Progress: Scope of work has changed since this project was proposed as the stack inspection performed in spring of 2012 determined stack lining in worse condition than expected. Activities in 2013 will be to develop repair scope and obtain bids for the work. EG1309 Unit 3 Stack Repairs This should be completed in the 3rd FY quarter. Schedule: The scoping of work should be completed in the 3rd quarter FY13 with bids and revised installation costs identified. Actual repair work will be scheduled for fiscal 2015. Progress: The FY2013 work scope package being developed. Units 1&2 Stack EG1310 Schedule: Work to be completed during the spring outage or Repairs deferred until 2015. Inspection was completed in November and 24

report is forthcoming so scoping documents may be developed. Progress: Valuation of the benefits of various technologies is underway. Final decision on moving forward with the project has still not been made and additional work scope has been added to VanSant Capacity Consultant’s work scope. Presentation is expected from TEA EG1311 Increase regarding results and recommendations going forward. Schedule: Installation was scheduled for the 4th quarter but is dependent on favorable decision to move forward. At present time, this cannot expect to be completed until late 2013, at the earliest. Progress: Contract work has been awarded and vendor is mobilizing Unit 3 Generator for arrival at plant on March 18 to begin inspection. EG1312 Repairs Schedule: Majority of the parts have been received and the inspection still on schedule to be completed in the 4th quarter FY13. Progress: Mechanical and electrical design is complete and contracts have been awarded. MR Industrial Waste EG1214 Schedule: Electrical and Mechanical contracts were awarded. water System Installation work slated for March 2013 start and 4th quarter completion. Progress: Work was completed in November and finalized with an Unit 1 Gland Steam EG1301 operational system check of the unit. Seal Repair Schedule: Work is now complete. 25

6.0 General Plant Information The XL Insurance Representatives Neal Grabow and Steve Behrens were onsite in February for their annual inspection. Only one new recommendation is expected as a result of the site audit that being the testing of corrosive sulfur in the transformer oil. This is a one-time task. The recommendation to install blast curtains on the Control Windows is expected to be withdrawn after it has been determined that the transformers in the switchyard are beyond the exposure limit from the windows. TEA is evaluating the findings of the McHale and Associates Report (Capacity upgrade opportunities for VanSant) and has imported the data into their financial model. TEA has yet to develop a presentation that will be reviewed by both the City of Dover management Team and NAES – Dover Management. Additional information that had been requested from McHale has been received. TEA is currently analyzing this information to determine the best options for moving forward and will be forwarding a presentation for NAES and TEA management review. The EIA-860 and EIA-923 reports were submitted to the Department of Energy online website during the month of February. Training: 1. OES-NA will be on site on March 25-26 for Simulation Training activities using Computer Based Training modules. The training will take place on two successive days and will give operators training on Voltage Control, Congestion Management, and Emergency Operations. The operators will receive simulation credits towards retaining their PJM System Operator Certification. Teams continued training within the Plant Readiness Program (PRP) to keep their skills and knowledge of the plant up to date particularly when the generating units are off line or when they are not supporting maintenance activities. The GPI online training which supports our safety and environmental training are being used by the teams to complete their training as they begin the training cycle for the year 2013. GPI also has a number of courses that are used to support operator advancement and refresher training. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Portable Electric Generator Safety”. 26

Calendar of Events Date McKee Run and VanSant Title V Annual Certification Due February 1, 2013 EIA-860 Report February 28, 2013 EIA-923 Report February 28, 2013 NOx Emissions Reconciliation Due March 1, 2013 SO2 Emissions Reconciliation Due March 1, 2013 SARA III Report March 1, 2013 NPDES Permit Renewal Due March 4, 2013 Units 1, 2, and 3 Spring Outage March 4, 2013 – June 1, 2013 Unit 11 Spring Outage March 4, 2013 – June 1, 2013 Annual VanSant Black Start Test March 13, 2013 Air Emission Inventory June 30, 2012 NOx Ozone Season Starts May 1, 2013 PJM Summer Capacity Test Period June 1, 2013 – August 31, 2013 Toxic Release Inventory (TRI) Annual Report July 1, 2013 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2013 DRBC Study Due September 15, 2013 NOx Ozone Season Ends September 30, 2013 Units 1, 2, 3 and 11 Fall Outage TBD Three Year Accident Free October 14, 2013 Winter Capacity Period December 1, 2013 to February 28, 2014 7.0 Summary of NAES Performance to Date Plant Performance FY 2012-2013 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0% $92,128 $92,128 Unavailability (CU) Safety 0 0 $17,273 $17,273 Environmental 0 0 $17,273 $17,273 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,455* $3,455 Unit 2 No No Yes Yes* $3,455* $3,455 Unit 3 No No Yes Yes* $20,520* $20,520 Unit 11 No No Yes Yes* $6,840* $6,840 Total YTD 100.00% Total YTD Incentive $161,224 $161,224 Incentive % Note: All units have successfully completed the PJM Summer Capacity Tests and are qualified for entry into the PJM Winter Capacity Test Exemption Program*. The YTD Incentive calculation reflects this information. 27

IV. Appendix – PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights $ (1,009.12) $ (1,009.12) Balancing Operating Reserve $ 122,042.48 $ 122,042.48 Balancing Spot Market Energy $ (162,063.46) $ (162,063.46) Balancing Transmission Congestion $ (5,500.67) $ (5,500.67) Balancing Transmission Losses $ 3,867.92 $ 3,867.92 Black Start Service $ (6,905.58) $ 1,916.01 $ (4,989.57) Capacity Resource Deficiency $ (461.44) $ (461.44) Capacity Transfer Rights $ (30,093.84) $ (30,093.84) Day-ahead Operating Reserve $ 4,158.73 $ 4,158.73 Day-ahead Scheduling Reserve $ 16.47 $ 16.47 Day-ahead Spot Market Energy $ 543,023.83 $ 543,023.83 Day-ahead Transmission Congestion $ (100,456.00) $ (100,456.00) Day-ahead Transmission Losses $ 101,055.12 $ 101,055.12 Expansion Cost Recovery $ 427.56 $ 427.56 FERC Annual Recovery $ 3,394.88 $ 3,394.88 Generation Deactivation Refund $ (758.35) $ (758.35) Inadvertent Interchange $ (93.85) $ (93.85) Load Management Test Failure $ (180.60) $ (180.60) Load Reconciliation for Balancing Operating Reserve $ (16.49) $ (16.49) Load Reconciliation for FERC Annual Recovery $ (18.13) $ (18.13) Load Reconciliation for Inadvertent Interchange $ 0.90 $ 0.90 Load Reconciliation for Market Monitoring Unit (MMU) Funding $ 0.04 $ 0.04 Load Reconciliation for North American Electric Reliability Corporation (NERC) $ (2.84) $ (2.84) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $ (54.34) $ (54.34) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund $ 11.48 $ 11.48 Load Reconciliation for Reactive Services $ (409.40) $ (409.40) Load Reconciliation for Regulation and Frequency Response Service $ (59.58) $ (59.58) Load Reconciliation for Reliability First Corporation (RFC) $ (3.55) $ (3.55) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $ (6.85) $ (6.85) Load Reconciliation for Spot Market Energy $ (8,079.71) $ (8,079.71) Load Reconciliation for Synchronized Reserve $ (12.61) $ (12.61) Load Reconciliation for Transmission Congestion $ (95.14) $ (95.14) Load Reconciliation for Transmission Losses $ (363.25) $ (363.25) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $ (19.55) $ (19.55) Locational Reliability $ 889,581.84 $ 889,581.84 Market Monitoring Unit (MMU) Funding $ 249.03 $ 249.03 Meter Error Correction $ (2,322.93) $ (2,322.93) Network Integration Transmission Service $ 264,462.52 $ 264,462.52 Non-Firm Point-to-Point Transmission Service $ (294.24) $ (294.24) North American Electric Reliability Corporation (NERC) $ 570.56 $ 570.56 Organization of PJM States, Inc. (OPSI) Funding $ 39.37 $ 39.37 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $ 1,557.43 $ 1,557.43 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $ 857.08 $ 857.08 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $ 9,654.01 $ 9,654.01 PJM Scheduling, System Control and Dispatch Service - Market Support $ 2,178.35 $ 2,178.35 PJM Scheduling, System Control and Dispatch Service - Market Support Offset $ (296.69) $ (296.69) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $ 90.60 $ 90.60 PJM Settlement, Inc. $ 296.69 $ 296.69 Reactive Services $ 36,174.96 $ 36,174.96 Reactive Supply and Voltage Control from Generation and Other Sources Service $ (29,467.58) $ 33,224.59 $ 3,757.01 Regulation and Frequency Response Service $ 13,429.77 $ 13,429.77 Reliability First Corporation (RFC) $ 815.91 $ 815.91 RPM Auction $ (1,089,270.00) $ (1,089,270.00) Synchronized Reserve $ 3,313.27 $ 3,313.27 Transmission Enhancement $ 23,052.94 $ 23,052.94 Transmission Losses $ (27,558.74) $ (27,558.74) Transmission Owner Scheduling, System Control and Dispatch Service $ 4,239.34 $ 4,239.34 Balancing Operating Reserve for Load Response $ (5.75) $ (5.75) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $ (0.18) $ (0.18) Load Reconciliation for Day-ahead Scheduling Reserve $ (0.03) $ (0.03) Load Reconciliation for Synchronous Condensing $ (0.13) $ (0.13) Demand Resource and ILR Compliance Penalty $ (86.52) $ (86.52) Day-Ahead Load Response Charge Allocation $ 569.70 $ 569.70 Real-Time Load Response Charge Allocation $ (240.80) $ (240.80) Incremental Capacity Transfer Rights $ (928.76) $ (928.76) Michigan - Ontario Interface Phase Angle Regulators $ 182.12 $ 182.12 Non-Synchronized Reserve $ 849.98 $ 849.98 CT Lost Opportunity Cost Allocation $ (9.24) $ (9.24) Load Reconciliation for Non-Synchronized Reserve $ (0.51) $ (0.51) $ (1,125,643.16) $ 1,723,802.19 $ 598,159.03 28

1 of 5 City of Dover Capital Investment Plan Project Tracking Report March 31, 2013 Points to Remember - * Original Project Budget = Original Total Project Budget initially included in approved annual budget. * Latest Project Budget = Revised Total Project Budget included in most recent approved annual budget or one of the following: bond resolution, revolving fund loan agreement, Council approved budget amendment, or City Manager approved amendment as per the Budget Amendment Procedure. * Current Fiscal Year - Revised Fiscal Year Budget = Current Year approved project budgets plus carry forward balances of unspent budgets in the prior fiscal year. Project Carry Forward balances will be submitted to City Council for amendment in January 2010. Can also be amended with City Manager approval per the Budget Amendment Procedure. * Water Quality, Inflow/Infiltration, Distribution Upgrades and New Development projects are budgeted as a blanket project and once individual projects are identified and estimated they are created using an allocation of the overall budgeted amount. * Status and Comments provided by City Manager. * For Finance purposes projects are considered completed when placed in service and all charges have been processed. Community Water & Total Current Year Budget Funding Sources General Transportation Wastewater Electric CIP Budget Balance $ 62,000 $ 171,400 $ 4,508,500 $ 534,700 $ 5,276,600 Restricted MSA (non Public Safety) 132,200 - - - 132,200 Library Funding - FY11 Budget Balance (95,500) - - - (95,500) Federal and/or State Grants 1,746,000 - - - 1,746,000 Transfer from Library Foundation 71,000 - - - 71,000 Friends of the Library Donation 102,400 - - - 102,400 Kent County Library Contribution 250,000 - - - 250,000 Sale of Assets - Library 1,200,000 - - - 1,200,000 Debt Financing - Green Energy Components 648,500 - - - 648,500 Community Transportation Fund - FY11 Balances - 1,630,050 - - 1,630,050 Debt Financing 2,000,000 - 4,000,000 - 6,000,000 Other State/Federal Grants 324,700 - - - 324,700 Police Grants 33,800 - - - 33,800 Transfer from Capital Reserves - - - 550,000 550,000 Impact Fee Reserves - - 550,000 - 550,000 State Community Transportation Funds - 700,000 - - 700,000 Transfer Loan Proceeds to CT Fund - Street Program - 1,606,700 - - 1,606,700 Transfer from Operating Funds 613,400 - 2,900,000 3,500,000 7,013,400 Transfer from Future Capacity Reserve 2,000,000 - - - 2,000,000 Interest Income - - 25,000 40,700 65,700 Total Funding Sources (Unaudited) $ 9,088,500 $ 4,108,150 $ 11,983,500 $ 4,625,400 $ 29,805,550

General Fund - Major CIP Projects March 31, 2013 2 of 5 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 Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments FY2009 LB0901 M/G/L New Library Project $ 18,200,000 $ 20,469,080 $ 19,645,688 $ 823,392 96.0% $ 2,535,000 $ 4,089,100 $ 3,356,908 82.1% In Process Overall project 80% Complete on 7/31/12 ST1203 Dump Truck Refurbishment 30,000 24,000 28,725 (4,725) 119.7% - 12,000 16,704 139.2% In Process FY12 MSA - Capital non-safety - 132,200 - 132,200 200.0% - 132,200 - 0.0% Restricted MSA Funding Totals - FY09 $ 18,230,000 $ 20,625,280 $ 19,674,413 $ 950,867 95.4% $ 2,535,000 $ 4,233,300 $ 3,373,612 79.7% FY2013 --- Vehicles & Equipment $ 399,900 $ 399,900 $ 190,626 $ 209,274 47.7% $ 399,900 $ 399,900 $ 190,626 47.7% --- Annual Fire Truck Payments 238,500 238,500 238,515 (15) 100.0% 238,500 238,500 238,515 100.0% Mayor Security Cameras 33,000 33,000 33,000 - 100.0% 33,000 33,000 33,000 100.0% FC1302 B/L City Hall Fire Suppression 288,000 288,000 - 288,000 0.0% 288,000 288,000 - 0.0% Financed by PNC Loan - FY12 FC1303 G City Hall Emergency Generator 93,000 93,000 96,275 (3,275) 103.5% 93,000 93,000 96,275 103.5% DEMA Grant funded IT1301 G Server & Backup Solution 57,000 57,000 56,942 58 99.9% 57,000 107,000 56,942 53.2% $15K is DEMA grant funded PR1301 Dover Park- Roof Replacement 30,000 30,000 - 30,000 0.0% 30,000 30,000 - 0.0% ST1303 B/L Salt Storage Facility-Schutte Park 50,000 50,000 - 50,000 0.0% 50,000 50,000 - 0.0% Financed by PNC Loan - FY12 ST1304 B/L Garrison Farm Improvements 1,924,000 1,924,000 10,013 1,913,987 0.5% 1,924,000 1,950,000 10,013 0.5% Financing to be determined PD1301 G Police Elec Breaker Replacement 33,800 33,800 33,800 - 100.0% 33,800 33,800 33,800 100.0% Police Grant funded PD1302 B/L Police Micro Seal Parking Lots 25,300 25,300 - 25,300 0.0% 25,300 25,300 - 0.0% Financed by PNC Loan - FY12 Totals - FY12 $ 2,501,100 $ 2,501,100 $ 197,030 $ 2,304,070 7.9% $ 3,172,500 $ 3,248,500 $ 659,171 20.3% Debt issuance cost - PNC/Other 56,000 56,000 - 56,000 0.0% 56,000 - - 0.0% Transfer to CT Fund - Streets 1,606,700 1,606,700 - 1,606,700 0.0% 1,606,700 1,606,700 - 0.0% PNC Loan for FY12/FY13 Street Program Grand Totals $ 22,393,800 $ 24,789,080 $ 19,871,443 $ 4,917,637 80.2% $ 7,370,200 $ 9,088,500 $ 4,032,783 44.4% 44.4% 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. G = Grant funded project B/L = To be financed through bonds or commercial loan; Projects will be completed through CT Fund, therefore the loan proceeds will be transferred from Capital Fund into the Community Transportation Fund;

City of Dover Community Transportation & General Fund Street Funds - Major CIP Projects 3 of 5 March 31, 2013 Hide TOTAL PROJECT - PAST, CURRENT & FUTURE BUDGETS CURRENT FISCAL YEAR Original Latest Project Project Current Revised Fiscal Project Project Project To Date Budget % Budget Fiscal Year Fiscal Year YTD % Budget Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments FY 2002 CT0212 North Street sidewalk $ 80,400 $ 80,400 $ - $ 80,400 0.0% $ - $ 80,400 $ - 0.0% Waiting on DDP improvements Totals $ 80,400 $ 80,400 $ - $ 80,400 0.0% $ - $ 80,400 $ - 0.0% FY 2009 CT0555 Little League Park paving $ 11,600 $ 11,600 $ - $ 11,600 0.0% $ - $ 11,600 $ - 0.0% Re-program for signage Totals $ 11,600 $ 11,600 $ - $ 11,600 0.0% $ - $ 11,600 $ - 0.0% FY 2007 CT0708 E. Water Street Brick $ 65,000 $ 65,000 $ - $ 65,000 0.0% $ - $ 65,000 $ - 0.0% Specialty contract needed Totals $ 65,000 $ 65,000 $ - $ 65,000 0.0% $ - $ 65,000 $ - 0.0% FY 2009 CT0977 M Schutte Parking Lot $ 21,950 $ 21,950 $ - $ 21,950 0.0% $ - $ 21,950 $ - 0.0% Deferred Totals $ 21,950 $ 21,950 $ - $ 21,950 0.0% $ - $ 21,950 $ - 0.0% FY2012 CT1201 M North Street Roundabout $ - $ 500,000 $ - $ 500,000 0.0% $ - $ 500,000 $ - 0.0% 35% Site work initiated CT1212 Stoney Creek Lighting - 40,000 8,696 31,304 21.7% - 40,000 8,696 21.7% TE0601 M Lincoln Park Center 900,000 1,423,500 522,687 900,813 36.7% - 911,100 10,359 1.1% Started Totals $ 900,000 $ 1,963,500 $ 531,383 $ 1,432,117 27.1% $ - $ 1,451,100 $ 19,055 0.0% FY2013 CTxxxx Unapplied CT Projects (placeholder) $ 700,000 $ 378,415 $ - $ 378,415 0.0% $ 700,000 $ 378,415 $ - 0.0% Future CT Agreements CT1295 Hazel Road - 61,056 - 61,056 0.0% - 61,056 - 0.0% CT1316 Robbins Hose Station 2 - 111,925 85,823 26,102 76.7% - 111,925 85,823 76.7% CT1317 Wesley College Phase I - 148,604 - 148,604 0.0% - 148,604 - 0.0% ST1301 FY13 Concrete Program 60,000 60,000 6,199 53,801 10.3% 60,000 60,000 6,199 10.3% Financed by PNC Loan - FY12 STxxxx Street & Alley Program 300,000 56,400 56,400 0.0% - 56,400 - 0.0% ST1305 White Oak Tax Ditch - 12,600 - 12,600 0.0% 12,600 - 0.0% MR1301 Security Cameras - 102,400 48,240 54,160 47.1% - 102,400 48,240 47.1% General Fund Appropriations ST1302 FY12/FY13 Street & Alley Program 1,546,700 1,546,700 - 1,546,700 0.0% 1,546,700 1,546,700 - 0.0% Financed by PNC Loan - FY12 $ 2,606,700 $ 2,478,100 $ 140,262 $ 2,337,838 5.7% $ 2,306,700 $ 2,478,100 $ 140,262 6.1% Grand Totals $ 3,593,650 $ 4,528,550 $ 671,645 $ 3,856,905 14.8% $ 2,306,700 $ 4,108,150 $ 159,317 6.9% 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. C = Project funded by combination of CT Funds and General Fund B/L = To be financed through bonds or commercial loan; Projects will be completed through CT Fund, therefore the loan proceeds will be transferred from Capital Fund into the Community Transportation Fund

Water/Wastewater Improvement & Extension Fund - Major CIP Projects March 31, 2013 4 of 5 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 % Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Complete Comments FY 2008 WD0804 M 1.0 MG Elevated Water Storage $ 4,196,600 $ 2,590,000 $ 47,264 $ 2,542,736 1.8% $ 2,000,000 $ 2,166,000 $ 13,255 0.6% Started Staff reviewing agreement docs WD0805 M Piney Point Well 398,800 665,000 118,580 546,420 17.8% 450,000 532,901 44,170 8.3% Started Staff reviewing RFP Totals - FY08 $ 4,595,400 $ 3,255,000 $ 165,844 $ 3,089,156 5.1% $ 2,450,000 $ 2,698,901 $ 57,425 2.1% FY2009 WQ0907 SL/C Rt. 13 Water Main 1,023,700 2,214,600 2,173,195 41,405 98.1% - 192,600 114,868 59.6% 100.0% Complete; Awaiting final charges FY2010 WW1007 M/SL Fox Hall Pump Station 427,900 358,900 353,596 5,304 98.5% - 144,800 89,297 61.7% 98.0% Final punch list items outstanding WW1010 I Tar Ditch Interceptor Upgrade 518,230 495,400 28,014 467,386 5.7% - 490,300 0.0% Started Easement request sent to residents Totals - FY10 $ 946,130 $ 854,300 $ 381,611 $ 472,689 44.7% $ - $ 635,100 $ 89,297 14.1% FY2011 WW1104 SL Lepore Road P/S Replacement 350,000 402,000 283,491 118,509 70.5% - 384,200 210,105 54.7% Started Contractor ordered Station Totals - FY11 $ 350,000 $ 402,000 $ 283,491 $ 118,509 70.5% $ - $ 384,200 $ 210,105 54.7% FY2012 WD1201 Pay-As-You-Go Water Station 30,200 30,200 - 30,200 0.0% - 30,200 - 0.0% Started Specs being developed WQ1202 WQI - New Street - 113,960 26,600 87,360 23.3% - 87,400 - 0.0% Started Project on hold - Design complete WQ1203 WQI - Silver Lake - 279,840 238,576 41,264 85.3% - 62,776 49,578 79.0% 100.0% Complete; Awaiting final charges WW1201 M/SL Inflow/Infiltration Removal (1) 1,000,000 971,900 55,075 916,825 5.7% - - - 0.0% See FY13 I & I Program; $916.800 WW1202 M SCADA Equipment Upgrade 84,900 84,900 76,784 8,116 90.4% 29,300 29,300 - 0.0% Started Awaiting delivery of materials WW1204 M Baltray Pump Station Replacement 125,000 125,000 20,874 104,126 16.7% 100,000 100,000 293 0.3% Started Project on hold - Bid specs ready WW1205 M Dover Brook Gardens Pump Station 65,000 65,000 12,194 52,806 18.8% 50,000 50,000 2,342 4.7% Started Project on hold - Bid specs ready WW1206 M Brandywine Pump Station Rplcmnt 402,000 402,000 33,875 368,125 8.4% 350,000 350,000 293 0.1% Started Project on hold - Bid specs ready WW1207 M McKee Pump Station Comm Rplcmt 55,000 55,000 7,724 47,276 14.0% 45,000 45,000 293 0.7% Started Project on hold - Bid specs ready Totals - FY12 $ 1,762,100 $ 2,127,800 $ 471,702 $ 1,656,098 88.8% $ 574,300 $ 754,676 $ 52,798 7.0% FY2013 --- Vehicles & Equipment $ 524,500 $ 524,500 $ 408,745 $ 115,755 77.9% $ 524,500 $ 527,548 $ 408,745 77.5% Started All ordered or bid WW1301 M Hazlettville Road Interceptor 770,000 770,000 - 770,000 0.0% 30,000 30,000 - 0.0% Not started Project on hold WW1302 M Lakeview Drive PS Replacement 502,000 502,000 26,963.47 475,037 5.4% 52,000 52,000 26,963 51.9% Not started Project on hold WW1303 M Westover Pump Station 768,800 768,800 - 768,800 0.0% 65,000 65,000 - 0.0% Not started Project on hold WW1304 M Garrison Farm Improvements 1,828,000 1,828,000 39,996.51 1,788,003 2.2% 1,828,000 1,828,000 39,997 2.2% Started Pending Council approval 9/24 WD1302 M Garrison Farm Storage Tank 1,828,000 1,828,000 142,660 1,685,340 7.8% 1,828,000 1,828,000 142,660 7.8% Started Pending Council approval 9/24 WD1304 Future Columbia Well Design 55,000 55,000 - 55,000 0.0% 55,000 55,000 - 0.0% Not started Project on hold WD1301 R Wellhead Redevelopment 70,000 70,000 67,675 2,325 96.7% 70,000 67,675 67,675 0.0% 15.0% Contractor finishing Well 10 & 14 WQ1301 North Street WMR 45,000 45,000 47,691.41 (2,691) 106.0% - 45,000 47,691 0.0% N/A Water Quality Improvements 479,000 479,000 - 479,000 0.0% 479,000 479,000 - 0.0% Locations to be determined N/A I & I Improvements (1) 1,000,000 (14,500) - (14,500) 0.0% 1,000,000 902,300 - 0.0% Locations to be determined II1301 New/Reed Street - 330,000 310,493 19,507 - 345,000 310,493 0.0% 65.0% Contractor finishing New Street II1302 Fox Hall - 142,000 145,355 (3,355) - 162,000 145,355 89.7% Scheduled II1303 Morris Estates - 276,000 211,692 64,308 - 241,000 211,692 87.8% Scheduled II1304 Wesley College - 10,000 7,200 2,800 - 10,000 7,200 72.0% Scheduled II1305 NRG sanitary sewer upgrade - 175,000 39,266 135,734 - 175,000 39,266 22.4% Not started Bids due 10/4/12 II1306 I & I Design - 40,000 21,024 18,976 - 40,000 21,024 52.6% In progress Staff reviewing consultant report II1307 Mifflin Road Sewer Rehab 3,500 3,500 - - 3,500 3,500 II1308 Dunkin Donuts SSR - 38,000 36,027 1,973 - 38,000 36,027 WD1306 R Emergency Generators 80,000 80,000 - 80,000 0.0% 80,000 80,000 - 0.0% 85.0% Start on bid docs 10/1/12 $ 7,950,300 $ 7,950,300 $ 1,508,288 $ 6,442,012 0.0% $ 6,011,500 $ 6,974,023 $ 1,508,288 21.6% N/A Debt issuance cost-Garrison Farm 344,000 344,000 - 344,000 0.0% 344,000 344,000 - 0.0% Grand Totals $ 16,971,630 $ 17,148,000 $ 4,984,130 $ 12,163,870 29.1% $ 9,379,800 $ 11,983,500 $ 2,032,781 17.0% Legend (1) Transferred remaining project balance from FY12 to the FY13 I & I Project $916,800 M = Multi-year project - a project with a specific schedule to occur over multiple years. Adjusted Project Budget for FY13 will be $1,916,800 for I & I; Locations to be determined; 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

Electric Improvement & Extension Fund - Major CIP Projects 5 of 5 March 31, 2013 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 Code Type Description Budget Budget Expenses Balance Spent Budget Budget Expenses Spent Status Comments FY2012 EE1205 M Frazier Substation Upgrade $ 765,200 $ 765,200 $ 484,599 $ 280,601 63.3% $ 610,200 $ 611,800 $ 331,240 54.1% In process Materials ordered EG1202 M Unit 3 Boiler Systems 390,000 250,000 104,758 145,242 41.9% 129,000 167,300 22,106 13.2% In process Will complete Spring outage EG1212 M Unit 3 Turbine Inspection/Repair 1,494,000 1,494,000 413,153 1,080,847 27.7% 115,000 115,000 16,330 14.2% In process Will complete Spring outage EG1214 M Industrial WW Discharge System 272,000 272,000 101,993 170,007 37.5% - 242,000 81,412 33.6% In process EU1202 M Persimmon Tree Lane Feeder Rplcmt 113,500 113,500 44,148 69,352 38.9% - 8,500 12,642 148.7% In process EG1204 Unit 3DCS Comp & Software - - 3,075 (3,075) 0.0% - - 3,075 0.0% Complete Total $ 3,034,700 $ 2,894,700 $ 1,148,651 $ 1,746,049 39.7% $ 854,200 $ 1,144,600 $ 466,805 40.8% FY2013 N/A R Vehicles & Equipment $ 146,000 $ 146,000 $ 22,118 $ 123,882 15.1% $ 146,000 $ 146,000 $ 22,118 15.1% All vehicles received N/A R FY13 New Dvlpmnts - UG Transformers 50,000 57,300 5,028 52,272 8.8% 50,000 42,159 5,028 11.9% Over Budget; Revenue offset EE1313 R FY13 New Dvlpmnts - UG Conductors 350,000 (345,501) 6,958 (352,459) -2.0% 350,000 (236,508) 6,958 -2.9% EE1313 R FY13 New Dvlpmnts - 1 Phase Meters 50,000 23,940 707 23,233 3.0% 50,000 2,493 707 28.4% EE1301 Willow Tree Park - 9,800 13,077 (3,277) 133.4% - 13,078 13,077 100.0% Complete EE1302 Bayard Plaza - 39,400 31,514 7,886 80.0% - 31,515 31,514 100.0% Complete EE1303 Frazier Sub Upgrade - - 3,500 (3,500) 0.0% - - 3,500 0.0% EE1310 YMCA - 22,000 20,916 1,084 95.1% - 20,917 20,916 100.0% Complete EE1311 Super 8 Motel - 6,200 5,802 398 93.6% - 5,802 5,802 100.0% Complete EE1315 State Street Plaza - 8,700 7,207 1,493 82.8% - 8,708 7,207 82.8% EE1317 The Grand Apartments - 79,560 77,378 2,182 97.3% - 77,378 77,378 100.0% Complete EE1318 M & L Ventures Warehouses - 28,800 29,984 (1,184) 104.1% - 29,986 29,984 100.0% Complete EE1319 Proctor & Gamble - 30,000 19,225 10,775 64.1% - 19,225 19,225 100.0% Complete EE1320 Generals Green Lights - 26,000 - 26,000 0.0% - - - 0.0% Cancelled EE1322 Grottos Pizza - 57,600 55,981 1,619 97.2% - 57,598 55,981 97.2% EE1323 Dover High Lighting - 264,200 263,668 532 99.8% - 263,668 263,668 100.0% Complete EE1324 Bayhealth Fiber Wood - 50,000 41,927 8,073 83.9% - 41,928 41,927 100.0% Complete EE1325 Redner's Grocery Store - 16,600 - 16,600 0.0% - - - 0.0% EE1326 DelDot Bridge Project - 90,000 54,340 35,660 60.4% - 55,820 54,340 97.3% EE1327 George & Lynch Asphalt - 25,000 - 25,000 0.0% - 25,000 - 0.0% EE1328 Fiber Blue Hen Project - 49,300 43,643 5,657 88.5% - 43,644 43,643 100.0% Complete EE1329 Calpine Garrison Energy - 183,500 172,106 11,394 93.8% - 189,409 172,106 90.9% EE1331 Dicks Sporting Goods - 34,500 - 34,500 0.0% - 44,100 - 0.0% EE1332 Schutte Park Well - 4,400 - 4,400 0.0% - - - 0.0% Cancelled EE1333 DTCC Relocate Service - 20,300 - 20,300 0.0% - 30,900 - 0.0% EE1334 645 N. Gov Ave Bore - 3,601 3,601 0 100.0% - 3,601 3,601 100.0% Complete EE1335 Windstream Fiber Proj - 19,000 8,765 10,235 46.1% - 13,279 8,765 66.0% EE1336 McDonalds - 16,800 - 16,800 0.0% - 16,800 - 0.0% EE1337 Royal Farms - 20,500 - 20,500 0.0% - 20,500 - 0.0% EE1304 R FY13 Lighting Project & Rehab 100,000 100,000 99,916 84 99.9% 100,000 100,000 99,916 99.9% Route 13 LED Lighting EE1309 R Distribution Capacitors 125,000 125,000 103,493 21,507 82.8% 125,000 125,000 103,493 82.8% EE1307 Division Sub Fence 70,000 55,000 39,345 15,655 71.5% 70,000 55,000 39,345 71.5% EE1308 M Horsepond Substation Upgrade 761,800 761,800 - 761,800 0.0% 170,000 170,000 - 0.0% EE1305 M FY13 69kv Switch Rplmnt Program 135,000 64,000 - 64,000 0.0% 55,000 70,000 - 0.0% EE1306 R Trans Line Maint Program 75,000 4,000 3,986 14 99.7% 75,000 4,000 3,986 99.7% EE1312 M General Scott Switchgear 1,155,000 1,150,000 - 1,150,000 0.0% 50,000 50,000 - 0.0% N/A R FY13 Distribution Upgrades 400,000 12,000 - 12,000 0.0% 400,000 12,000 - 0.0% EE1314 Capitol Park Upgrade - 308,000 24,203 283,797 7.9% - 308,000 24,203 7.9% EE1321 Pleasanton Acres - 80,000 59,158 20,842 73.9% - 80,000 59,158 73.9% N/A R FY13 Distribution Feeder Replacements 277,500 213,500 - 213,500 0.0% 277,500 (61,500) - 0.0% EE1330 Morris Esates 1 Upgrade - 275,000 51,989 223,011 0.0% - 275,000 51,989 18.9% EE1316 Wyoming Avenue Feeder Replacement - 64,000 55,089 8,911 86.1% - 64,000 55,089 86.1% EG1301 Units 1 Repair - Gasket leak - 65,000 88,086 (23,086) 135.5% - 95,000 88,086 92.7% New Project; Not budgeted EG1304 R Units 1 & 2 Component Repairs 52,000 52,000 14,564 37,436 28.0% 52,000 52,000 14,564 28.0% EG1305 R Units 1 & 2 Cooling Tower Life Ext. 37,300 37,300 - 37,300 0.0% 37,300 37,300 - 0.0% EG1306 Turbine Level Window Modifications 85,000 85,000 - 85,000 0.0% 85,000 85,000 - 0.0% This project is not needed. EG1307 Unit 3 Air Heater Expansion Joint 80,000 80,000 47,894 32,106 59.9% 80,000 50,000 47,894 95.8% EG1309 Unit 3 Stack Repairs 27,000 27,000 3,439 23,561 12.7% 27,000 27,000 3,439 12.7% EG1310 Units 1 & 2 Stack Repairs 75,000 75,000 14,000 61,000 18.7% 75,000 75,000 14,000 18.7% EG1311 Van Sant Capacity Increase 550,000 550,000 - 550,000 0.0% 550,000 550,000 - 0.0% EG1312 Unit 3 Generator Repairs 236,000 236,000 28,965 207,035 12.3% 236,000 236,000 28,965 12.3% EG1313 R Unit 3 Aux Sys Components 55,000 55,000 21,345 33,655 38.8% 55,000 55,000 21,345 38.8% $ 4,892,600 $ 5,462,100 $ 1,542,916 $ 3,919,184 28.2% $ 3,115,800 $ 3,480,800 $ 1,542,916 44.3% Grand Totals $ 7,927,300 $ 8,356,800 $ 2,691,567 $ 5,665,233 25.4% $ 3,970,000 $ 4,625,400 $ 2,009,721 43.4% 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

City of Dover Electric Revenue Fund FY13 - White Oak Solar Park Incremental Cost Original July August September October November December January February March April YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 188,115 $ 165,987 $ 149,808 $ 90,971 $ 79,150 $ 54,242 $ 70,417 $ 82,916 $ 129,900 $ 192,841 $ 1,204,346 $ 1,414,500 Dover Sun Park - REC's 43,161 39,370 35,300 21,432 18,631 12,747 16,249 19,059 29,837 - 235,786 351,600 Total Power Supply Cost 231,276 205,356 185,108 112,403 97,781 66,989 86,666 101,975 159,737 192,841 1,440,132 1,766,100 Non-Solar Power Supply Cost (182,544) (155,720) (142,210) (86,418) (77,539) (51,224) (67,991) (77,639) (125,778) (188,650) (1,155,712) (1,112,717) Incremental Energy Cost $ 48,732 $ 49,636 $ 42,898 $ 25,985 $ 20,242 $ 15,765 $ 18,675 $ 24,336 $ 33,959 $ 4,191 $ 284,420 $ 653,383 Revenues Customer Sales - Electricity (8,858) (7,781) (6,991) (7,028) (7,402) (7,427) (7,586) (7,429) (7,153) (8,619) (76,274) (76,274) Rent Receipts (14,094) - - - - (14,094) - (14,446) - (14,446) (57,080) (56,376) Total Revenues (22,952) (7,781) (6,991) (7,028) (7,402) (21,521) (7,586) (21,875) (7,153) (23,065) (133,354) (132,650) Incremental Sun Park Cost $ 25,780 $ 41,855 $ 35,907 $ 18,957 $ 12,840 $ (5,756) $ 11,089 $ 2,461 $ 26,806 $ (18,874) $ 151,066 $ 520,733 MWh Purchased/Generated - Solar 2,097.730 1,893.370 1,682.090 1,021.460 888.720 609.050 771.170 908.078 1,422.622 2,111.938 13,406.228 17,042.000 MWh $ Solar Energy $ 89.68 $ 87.67 $ 89.06 $ 89.06 $ 89.06 $ 89.06 $ 91.31 $ 91.31 $ 91.31 $ 91.31 $ 89.83 $ 83.00 Solar REC's MWh 315.000 315.000 252.000 153.000 133.000 91.000 116.000 136.000 213.000 317.000 1,375.000 MWh $ Solar REC (one month lag) $ 137.02 $ 124.98 $ 140.08 $ 140.08 $ 140.08 $ 140.08 $ 140.08 $ 140.14 $ 140.08 $ - $ 171.48 MWh $ Non-Solar Energy $ 87.02 $ 82.24 $ 84.54 $ 84.60 $ 87.25 $ 84.11 $ 88.17 $ 85.50 $ 88.41 $ 89.33 $ 86.01 Second quarter rent receipt, not received until December 2012;