Attachment

UTILITY COMMITTEE AGENDA SEPTEMBER 9, 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. Public Notification - Power Outages (Staff Recommends Reviewing the Electric Outage Public Notification Procedures and Internal Standing Orders on an Annual Basis and Implementing Changes Based on Comments Received During the Review) 2. TEA/NAES Report (June and July) (Staff Recommends Acceptance of the Report) 3. 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) 4. Adjournment by 5:55 p.m. /tm S:\AGENDAS-MINUTES-PACKETS\Committee-Agendas\2013\09-09-2013 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: City Manager’s Office DATE SUBMITTED: 9/04/13 PREPARED BY: Scott D. Koenig, P.E., City Manager SUBJECT: Public Notification – Power Outages REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager EXHIBITS: Exhibit A – Public Notification Procedure; Exhibit B – Internal Standing Orders EXPENDITURE REQUIRED: N/A AMOUNT BUDGETED: N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIMETABLE: If requested, implement changes immediately. RECOMMENDED ACTION: Review the Electric Outage Public Notification Procedures and Internal Standing Orders on an annual basis and implement changes based on comments received during the review. BACKGROUND AND ANALYSIS Attached are the existing Electric Outage Public Notification Procedures and the Internal Standing Orders for the Electric Department. The Public Notification Procedures is currently implemented when more than one-third (1/3) of the City is affected or the outage is expected to be four (4) hours or longer in duration. In addition to these procedures, the System Operations Center has begun sending email notifications to the City Manager when there are any power outages. Since the System Operations staff is part of the system restoration, some of these emails occur after the fact. Others occur while the outage is in the process of being restored depending upon the intensity of the work involved in restoring the outage. The City Manager will forward the emails to City Council if they so desire to receive them.

City of Dover Electric Revenue Fund FY 2013 by Month Electric Supply & Generation - Cost per MWh by Supply Source Original 100% June YTD Budget Budget % Power Supply & Generation Power Supply - Hedged Energy $ 3,399,040 $ 37,698,282 $ 39,468,900 95.5% Power Supply Management 83,000 996,000 996,000 100.0% Capacity Charges - Load 1,319,328 11,587,934 12,564,800 92.2% Dover Sun Park - Energy 188,262 1,595,826 1,414,500 0.0% Dover Sun Park - REC's 43,285 370,256 351,600 0.0% PJM Charges - Energy 702,584 6,024,702 13,752,300 0.0% PJM Charges - Transmission & Fees 527,142 7,103,571 3,756,000 189.1% Total Power Supply 6,262,641 65,376,570 72,304,100 90.4% Plant Operations 1,115,725 5,719,083 5,914,900 96.7% Generation Fuel 31,723 1,023,574 586,000 174.7% Capacity Credits (1,286,250) (14,318,588) (14,318,600) 100.0% PJM Spot Market Energy - Dispatch (64,906) (1,930,510) (1,124,300) 171.7% PJM Credits (Black Start/Reactive Pwr) (29,718) (502,984) (427,000) 117.8% Total Generation (233,426) (10,009,425) (9,369,000) 106.8% Total Power Supply & Plant 6,029,215 55,367,145 62,935,100 88.0% Budget Load (MWh) 67,241 750,296 750,296 Actual Gross Load (MWh) - Total Supply 69,373 752,869 Actual Gross Load (MWh) - PJM 67,311 735,175 MWh Hedged 54,400 597,637 MWh Unhedged 12,911 118,434 MWh Generated - 19,104 MWh Purchased/Generated - Solar 2,062 17,694 MWh Power Supply $ (non-Solar) $ 89.60 $ 86.25 MWh Solar Energy $ 91.31 $ 90.19 MWh Generation $ (4.29) $ (47.47) Net Plant Revenue $ (non-Generation) $ (200,243) $ (9,102,489) All In MWh Supply & Generation $ $ 110.83 $ 73.05 $ 83.88 Solar REC's MWh 309 2,689 MWh Solar REC $ (one month lag) $ 140.08 $ 137.69

The Energy Authority, Inc. Monthly Management Committee Update – June 2013 July 25, 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 $738,471 under budget due to lower than budgeted cost of energy purchases. Dover’s budgeted cost for all power supply (capacity AND energy) was $103.48/MWh. The actual cost of all power supply (capacity AND energy) was $89.65/MWh. The cost of energy alone was $61.84/MWh, versus a budgeted energy cost of $76.25. Dover’s hedge purchases totaled 54,400 MWh, which was 81% of the projected load and 78% of the actual load. Dover’s power purchases from hedge transactions totaled $3,339,040. Purchases from PJM (energy and fees) totaled $1,229,726 with DA Energy purchases totaling $726,021 and Balancing Spot Market Energy totaling a credit of $177,178. Dover’s total load was 69,373 MWh versus a forecasted load of 67,241 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1973 MWh. Dover’s actual energy purchase from the SunPark installation was 2062 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 67,241 69,373 (2,132) Wholesale Load 65,268 67,311 (2,043) Hedged Volume (MWh) 54,400 54,400 - Unhedged Volume (MWh) 10,868 12,911 (2,043) Dover SunPark Volume (MWh) 1,973 2,062 (89) Renewable Energy Credits Volume 296 334 (38) Hedged Cost ($/MWh) $ 67 $ 62 $ 4 Unhedged Energy Cost ($/MWh) $ 121 $ 54 $ 67 Solar Energy Cost ($/MWh) $ 83 $ 86 $ (3) Energy Costs ($/MWh) $76.25 $61.84 $14.41 All-in Costs - Energy, Capacity and RECs ($/MWh) $103.48 $89.65 $13.82 2

B. Generation Summary: Dover generated 693.9 MWh in the month. Net generation revenue was $228,222 vs. a budget of $323,184. This delta was mainly due to higher than budgeted O&M costs. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 693.90 All In Generation Margin PJM Bill Energy $ 64,906.02 PJM Capacity $ 1,286,250.00 Black Start, Reactive Credit, DASR & EFORp $ 29,717.12 Gas Purchases $ (43,450.00) Oil Purchases $ - Transport / Cash Out $ 328.13 Gross Margin $ 1,337,751.27 Production Margin Generation Production Revenues (PJM) $ 64,906.02 Gas Purchases $ (43,450.00) Oil Purchases $ - Transport / Cash Out $ 328.13 Gross Production Margin $ 21,784.15 4

C. Emissions Summary: Emissions Allowance Summary through June 30, 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 10/4/2012 2013 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 6/30/2013 2013 Emissions 0 2 2 REMAINING ALLOWANCES 11,053 73 192 On August 21, 2012, a three-judge panel of the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s Cross State Air Pollution Rule (CSAPR) which would have become effective on January 1, 2012. The DCA instructed EPA to continue administering the Clean Air Interstate Rule (CAIR). EPA has appealed this ruling to the U.S. Supreme Court, and the Court has agreed to review the DCA opinion. A ruling is not expected before June, 2014. 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 (7/22/2013) Commodity $/Ton Tons Extended (Bid/Offer Avg.) Value SO2 Allowances (2009 & earlier) $ 1.38 5,089 $ 7,023 SO2 Allowances (2010-13) $0.60 5,964 3,578 NOx Allowances - Seasonal $18.00 73 1,314 NOx Allowances - Annual $40.00 192 7,680 TOTAL $19,595 Regional Greenhouse Gas Initiative The State of Delaware is a participant in the Regional Greenhouse Gas Initiative (RGGI). The City of Dover must comply with RGGI by surrendering carbon dioxide (CO2) allowances pursuant to the State of Delaware’s laws (Title 7, Chapter 60, Sub-Title II-A). Delaware has elected a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). CO2 Allowance Summary (6/30/2013) 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 (934) 14,612 119,117 6

The table shows that the “Allocated CO2 Allowances” (column 5) are declining. After 2013, Dover will no longer receive allocations of RGGI allowances. 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 have been included in previous monthly reports. 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. Delaware has held two workgroup meetings on (5/14/2013 & 6/18/2013), and the Department of Natural Resources expects to publish a draft rule in the Delaware Register in the near future. 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 June 7, 2013 and the auction cleared at $3.21/ton. The next auction will occur on September 4, 2013. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on July 23, 2013 ranged from $3.27 to $3.50/ton, depending on vintage. Based on the average ICE futures prices, the value of Dover’s existing RGGI allowance bank (119,117 tons) is approximately $410,652. Vintage Balance (Tons) Settlement Extended Value Price ($/Ton) 2009 56,388 $3.48 $196,230 2010 16,776 $3.50 58,716 2011 19,548 $3.50 68,418 2012 11,793 $3.35 39,507 2013 14,612 $3.27 47,781 TOTAL 119,117 $410,652 7

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. 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 May 2013, Dover has accumulated a total of 5,113 SRECS from these renewable energy resources. The nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s July 2013 SREC auction cleared at $10/MWh. Using this price, Dover’s SRECs would have a market value of $51,130. 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. D. Operations Management Summary: During the month of June, there were no reportable or lost time accidents or injuries. The facility has now gone 990 days without an OSHA recordable accident and 990 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued and there were no Near Miss incidents. In the month of June, Unit 3 was dispatched once by PJM during which it was on-line for 10.7 hours. All Units were in a planned outage starting March 4 and were closed out on June 3, 2013. Final work continued on the installation of the industrial waste water discharge system with an early July completion date. Monthly Budget Variance – Since the City of Dover has not yet closed it books on the month/FY13, actual expenses including accruals attributable to the O&M of both sites for the month of June are estimated to be approximately $1,109,529 against a budgeted amount of $998,647 for an unfavorable variance of $110,883 or 11.1%. The principal reasons for the unfavorable variance was due to higher than budgeted Operator Incentive, Accruals of various expenses and timing of other invoices for payment. 8

E. Risk Management Summary: Forward power prices in PJM are similar to last month. The blended cost has decreased in 2013-2014 but increased in 2014-2015 and 2015-2016. The current projected cost of service is below: Blended Cost Monthly Year Hedge Ratio ($/MWh) Change 2013-14 62% $ 51.33 $ (0.33) 2014-15 38% $ 46.41 $ 0.67 2015-16 15% $ 45.19 $ 0.62 9

II. Budget Report Variance Report: Budget Actual Variance Jun-13 Jun-13 Gross Load 67,241 69,373 (2,132) Power Supply Hedged Energy $3,632,320 $3,399,040 $233,280 PJM- Energy $1,317,933 $702,584 $615,349 PJM - Transmission and Fees $313,000 $527,142 ($214,142) Dover SUN Park Energy $176,929 $188,262 ($11,333) Management Fees $83,000 $83,000 $0 Capacity UCAP Obligated Purchased $1,434,646 $1,319,328 $115,318 Subtotal - Power Supply $6,957,828 $6,219,357 $738,471 Power Generation O&M & Fixed Fuel Plant O&M $998,646 $1,109,529 ($110,883) Subtotal Generation O&M $998,646 $1,109,529 ($110,883) Power Generation Production Margin Economic and reliability dispatch $0 ($64,906) $64,906 Fixed Fuel and Transport Charges $0 $43,122 ($43,122) Subtotal Generation Production Margin $0 ($21,784) $21,784 Power Generation Non-Production Revenue Generation Capacity Credit ($1,286,250) ($1,286,250) $0 Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($35,580) ($29,717) ($5,863) Subtotal - Non-Production Revenue ($1,321,830) ($1,315,967) ($5,863) SubTotal - All Generation ($323,184) ($228,222) ($94,962) Total - Utilities Cost $6,634,644 $5,991,134 $643,510 Unit Costs Total - Power Supply $103.48 $89.65 $13.82 Total - Power Generation ($4.81) ($3.29) ($1.52) Final Cost of Service to City of Dover Ratepayers $98.67 $86.36 $12.31 10

Variance Analysis: Power Supply  Dover consumed 2,132 MWh more 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 below forecast.  The result of lower overall costs for more power was a net power supply cost of $89.65/MWh, $13.82/MWh lower than budget.  For the month, the city realized a favorable variance of $738,471 for power supply vs. the monthly budget.  Dover Sun Park generated 89 MWh more than forecast. Generation  Power generation had an unfavorable budget variance of $94,962.  Plant O&M expenses had an unfavorable budget variance of $110,883 for the month. 11

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 750,296 752,870 (2,574) Power Supply Hedged Energy $39,468,889 $38,100,074 $1,368,815 PJM- Energy $13,752,305 $7,827,207 $5,925,098 PJM - Transmission and Fees $3,756,000 $5,301,066 ($1,545,066) Dover SUN Park Energy $1,506,492 $1,626,799 ($120,308) Management Fees $996,000 $996,000 $0 Capacity UCAP Obligated Purchased $12,564,792 $11,587,934 $976,858 Subtotal - Power Supply $72,044,478 $65,439,081 $6,605,397 Power Generation O&M & Fixed Fuel Plant O&M $5,914,900 $5,829,862 $85,038 Subtotal Generation O&M $5,914,900 $5,829,862 $85,038 Power Generation Production Margin Economic and reliability dispatch ($1,124,312) ($1,947,770) $823,458 Fixed Fuel and Transport Charges $586,004 $1,025,766 ($439,762) Subtotal Generation Production Margin ($538,308) ($922,004) $383,696 Power Generation Non-Production Revenue Generation Capacity Credit ($14,318,591) ($14,318,587) ($4) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($426,960) ($485,722) $58,762 Subtotal - Non-Production Revenue ($14,745,551) ($14,804,309) $58,758 SubTotal - All Generation ($9,368,959) ($9,896,451) $527,492 Total - Utilities Cost $62,675,519 $55,542,630 $7,132,889 Unit Costs Total - Power Supply $96.02 $86.92 $9.10 Total - Power Generation ($12.49) ($13.14) $0.66 Final Cost of Service to City of Dover Ratepayers $83.53 $73.77 $9.76 12

III. Operations Management NAES Corporation Dover, Delaware June 2013 Monthly Report McKee Run Generating Station 13

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

1.0 Environmental, Health and Safety: During the month of June, there were no restricted work days or lost time accidents. The facility has now gone two years, eight months and sixteen days (990 days) through June 30, 2013 without an OSHA Recordable Accident or a Lost Time reportable accident. A NAES sponsored webinar was attended by the O&M Manager and Compliance Manager regarding the major LOTO (SMP-03) revision currently taking place. The facility has begun work to roll out the new program and train all employees by the targeted completion date of July 31, 2013. The Plant Safety Training Matrix has been updated for calendar year 2013 and is being tracked on a monthly basis for all employees. The training program includes the inclusion of the General Physics on-line training system as well as plant safety procedures and policies. Safety Procedures and associated quizzes are currently being updated. As they are completed, staff will retrain on each one to ensure they understand what changes have been made, if any, to the programs. The plant received no Notice of Violations (NOVs) during the month. The June (May Discharge) DMR was submitted for the McKee Run site with no NPDES exceedences. Work and shakedown on the Industrial Wastewater Project was completed. The facility is waiting on system as-built drawings, as well as working with the City of Dover and Kent County to finalize reporting and monitoring requirements for billing and regulatory purposes. The system is expected to “go-live” in July 2013. A NAES sponsored webinar was attended by the Compliance Manager on Title V Part 75 QA/QC reporting and monitoring. In particular, the webinar covered ECMPS data submissions and how to appropriately track QA/QC deadlines and requirements. As the facility uses VIM, our DAHS vendor, this is currently being done effectively with a secondary review performed monthly by the facility to ensure accuracy. 15

Environmental, Health, and Safety Statistics Month Fiscal Year to Date (June) (7/1/12-6/30/13) NOVs 0 0 Opacity Deviations 0 1 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 4207.50 55911.00 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 990 Days since last Lost Time Accident 990 Emissions (NOx & SO2) All data thru 6/30/13 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 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 1.8 0.0 1.8 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 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 1.9 0.0 1.9 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 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 0.0 0.0 0.0 0.0 16

CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant Run McKee Run - Run (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2010 and 3*** 27/0 0/2 earlier 2011 0 77/48 5/3 33/31– 3/1 0/0 - 0/0 42/10 2/2 2012 2** 75/46 5/3 36/36 – 1/1 0/0 - 0/0 39/10 2/0 2013 0 77/48 5/3 2/2 – 0/0 0/0 - 0/0 75/46 5/3 Total NOx Allowance Balance 183/66 9/7 *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 SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 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* Total SO2 Allowance Balance 11,053 Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 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 15,032 514 934 14,612 Total CO2 Allowance Balance 119,117 *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 17

2.0 Financial Financial – Current Month (Estimated) Month – June Actual Variance Budget (Estimated) (Estimated) Personnel 748,719 733,739 ($14,980) Materials & Supplies 24,395 8,740 ($15,655) Administrative Expenses 336,415 256,167 ($80,248) Total $1,109,529 $998,646 ($110,883) Financial – Fiscal Year to Date (Estimated) Number of Months – 12 Actual Variance Budget (Estimated)) (Estimated) Personnel 3,598,656 3,669,300 70,644 Materials & Supplies 202,291 209,600 7,309 Administrative Expenses 2,028,914 2,036,000 7,086 Total $5,829,861 $5,914,900 85,039 2.1 Variance analysis: The City of Dover Finance Department has not yet closed the books for the month of June 2013. The estimated expenses for June are $1,109,529 against a budgeted amount of $998,647 for an unfavorable variance of $110,883 or ≈ 11.10%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $14,980 was due to the accruals of a payroll(s). Plant budgeted for three (3) payroll periods and an additional week of payroll was expensed as an accrual. Included in these costs are straight time labor, overtime labor, and labor burdens. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $15,655 was due primarily to the purchase of a new server and software upgrades. The server was budgeted for in an earlier month but wasn’t purchased until June. The software upgrades were not originally budgeted; however a budget amendment was processed and approved for this purchase. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $80,248 was due primarily to accrual of monthly electric usage invoice, operator incentive higher than budgeted, additional work in contractual services to support FAC / HEP studies, and expenses related to the VanSant capacity increase feasibility study. The budget is currently forecasted to finish this fiscal year at $5,829,861 expensed versus an approved budget of $5,914,900 thereby realizing a 98.56% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips The Spring Planned Outage for all four units was cleared on June 3 at 0700 hours. Unit 3 was dispatched by PJM once in the month of June and operated without incident. Units 1, 2, and 11 were not dispatched in the month of June. Month June 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 10.700 10.700 0.0 10.700 Starts # 0 0 1 1 0 1 Gross Generation MWh 0.0 0.0 757.121 757.121 0.0 757.121 Net Generation MWh 0.0 0.0 696.098 696.098 0.0 696.098 Total Auxiliaries MWh 18.887 18.887 199.820 237.593 2.330 239.923 Auxiliaries purchased MWh 18.887 18.887 138.797 176.570 2.330 178.900 Fuel Gas Used MMBTU 0.0 0.0 8,001 8,001 0.0 8,001 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 8,001 8,001 0.0 8,001 Net Heat Rate BTU/KWh 0 0 11.494 11.494 0 11.494 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.95 0.71 0.0 0.55 Availability Factor % 92.36 92.36 92.36 92.36 92.36 92.36 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 55.000 55.000 55.000 165.000 55.000 220.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 665.000 665.000 654.3 1,984.3 665.000 2,649.3 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 0 0 0 0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 19

2012-2013 Fiscal Year-to-Date - June 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 71.970 308.713 476.965 22.699 499.664 Starts # 3 2 31 36 5 41 Gross Generation MWh 668.79 582.202 20,015.521 21,266.513 714.904 21,981.417 Net Generation MWh 628.855 541.673 18,424.716 19,595.244 714.287 20,309.531 Total Auxiliaries MWh 359.474 360.067 3,549.610 4,269.151 40.206 4,309.357 Auxiliaries purchased MWh 319.539 319.539 2,019.828 2,658.904 39.675 2,698.579 Fuel Gas Used MMBTU 9,483 8,108 213,543 231,134 8,642 239,777 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, 213,543 231,134 8,642 239,777 Net Heat Rate BTU/KWh 15,021 14,970 12.037 14.007 12,604 13,701 Unit Trips # 0 0 2 2 0 2 Capacity Factor % 0.41 0.37 2.07 1.65 0.21 1.33 Availability Factor % 57.62 57.62 57.77 57.67 57.62 57.66 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 3,696 3,696 3,696 11,088 3,641 14,784 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 4,971.218 4,992.030 4,778.570 14,741.818 5,041.934 19,783.752 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) 452,963 453,844 0 881 454,725 0 (881) VanSant 145,796 146,133 0 337 152,150 0 (6,017) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through 6/30//13 Actual Starts Factored Starts Fired Hours VanSant 1308 2,238.75 4,219.80 Since HGP - Dec 2004 232 571.05 836.22 20

Team Report: Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both the Operations and Maintenance areas to help in maintaining the plant. The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. The Operations staff has also supported the outage by performing various LOTO tasks needed to test or place equipment in or out or service. The Operations staff has been continuing their work on painting the fuel lines now that most of the insulation has been removed from the pipeline. Capacity Testing – FY 2012-2013 Summer 2012 (June 1- Aug 31) Winter 2012-2013 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.0 1 17 17* 2 17 17.3 2 17 17* 3 102 102.7 3 102 102* VanSant 39 39.0 11 39 39* Total 175 176.0 Total 175 175* Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program and data has been submitted into the PJM eGADS 21

4.0 Maintenance During the month of June, the Plant Maintenance staff continued addressing the backlog of work orders and completing outage activities. There were forty-nine work orders issued with seventy-one 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 June - 2013 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 9 6 5 10 2 41 17 28 30 3 37 0 3 34 4 7 0 0 7 5 15 0 1 14 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 28 26 34 20 Totals 137 49 71 115 Note: PM Work Orders are included in the priority totals Notable activities during the month include:  The NAES IC&E Staff removed old inefficient lighting in the DI area. They installed new lighting that is more energy efficient, will illuminate the area much better and will allow for greater ease of operation and maintenance.  The NAES Maintenance Staff completed the lube oil change out on the FD Fans, ID Fans, and Circulating Water Pumps on all three units. The oil was changed out due to recommendations resulting from recent oil analysis results.  The NAES Maintenance Staff moved the tie in point for blowdown off Units 1 and 2 condensers to the Industrial Waste Water System. The original tie in point required an operator to prime the line every time Units 1 & 2 Cooling Tower needed to blown down. With the new tie in point, the blowdown can be easily initiated from the control panel without the need for priming the system. 22

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: Minor repairs made to cooling tower. Additional work slated for Units 1 & 2 Cooling EG1102 FY18 Tower Repairs Schedule: Work complete for FY13. Multi-year project. Progress: Work scheduled for the Spring 2013 outage is 100% Unit #3 Boiler complete. EG1202 Systems Schedule: Multi-year project with additional work slated for FY15. Progress: Work scheduled for the Spring 2013 outage is at 100% Unit 3 Auxiliary completion. EG1203 System Components Schedule: Multi-year project with FY14 work now in planning stages. Progress: Plant staff continues working with OEM to determine long lead material requirements. Unit 3 Turbine Schedule: Long lead items will be procured in the spring of 2013. EG1212 Repairs Some turbine parts (turbine 9th stage blades) have been ordered and received. List of consumables is being finalized and quotes requested thereafter. Progress: Work on hold for present time. Units 1 & 2 EG1304 Schedule: Work on hold for present time. Components Repairs Turbine Level Progress: Feedback from insurance company revealed that this EG1306 Window recommendation will be withdrawn. modification Schedule: Work complete. 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 FY2016 work scope package being developed. Units 1&2 Stack EG1310 Schedule: Work deferred until 2016. Inspection was completed in Repairs November and scoping documents will be developed based on 23

inspection report findings. Progress: Valuation of the benefits of various technologies has been completed and TEA has recommended implementation of the Wet Compression Technology at an approximate cost of $1.5M. Plant VanSant Capacity EG1311 staff has developed a cost schedule and amended the CIP which was Increase approved by the COD City Council at the June 24, 2013 meeting Schedule: Plant Staff and TEA to develop scoping documents and proceed with getting regulatory approvals. Progress: Project is complete except for final invoicing and payment Unit 3 Generator of parts and services. EG1312 Repairs Schedule: Project is expected to be closed out in July/August time period. Progress: Mechanical and electrical installation work is complete. MR Industrial Waste “As-built” drawings are to be submitted for finalization. Final EG1214 water System permit is expected to be received from Kent County in early July. Schedule: Project to be entirely complete no later than August 2013. Unit 1 Gland Steam Progress: NA EG1301 Schedule: Work is complete. Seal Repair 24

6.0 General Plant Information  TEA has evaluated the findings of the McHale and Associates Report (Capacity upgrade opportunities for VanSant) and has imported the data into their financial model. From this, TEA developed a presentation that was presented at the March COD/TEA/NAES Management Meeting in which they recommended implementation of the Wet Compression Technology with an estimated cost of $1.5 million dollars. A number of action items were also identified that need to be followed up by NAES and by TEA including updating the project CIP costing and having a discussion with the DNREC regarding the effect the power increase could have on emissions. Included in the action item list was a breakdown of project costs and time frame when those costs would be expected to be expensed.  The Spring Outage in PJM eDART has now been closed. The outage had officially begun on March 4, 2013 at 0700 hours and continued until it was closed out on June 3, 2013 at 0700 hours. Some planned activities were not completed during the allocated time frame and are now scheduled for completion during the fall outage along with a number of other tasks including replacement of the Unit 3 Cooling Tower Hot Water Basin Deck Cover. Training:  Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Heat Exhaustion”. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff.  Plant employees continue using the General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed, the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy as well 25

Calendar of Events Date 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 EIA-860 Report February 28, 2014 EIA-923 Report February 28, 2014 NOx Emissions Reconciliation Due March 1, 2014 SO2 Emissions Reconciliation Due March 1, 2014 SARA III Report March 1, 2014 NPDES Permit Renewal Due March 4, 2014 Units 1, 2, and 3 Spring Outage March , 2014 – June , 2014 Unit 11 Spring Outage March , 2014 – June , 2014 Annual VanSant Black Start Test March , 2014 Air Emission Inventory March , 2014 NOx Ozone Season Starts May 1, 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% $93,022 $93,022 Unavailability (CU) Safety 0 0 $17,440 $17,440 Environmental 0 0 $17,440 $17,440 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,488* $3,488 Unit 2 No No Yes Yes* $3,488* $3,455 Unit 3 No No Yes Yes* $20,930* $20,930 Unit 11 No No Yes Yes* $6,977* $6,977 Total YTD 100.00% Total YTD Incentive $162,788 $162,788 Incentive % Note: All units have successfully completed the PJM Summer Capacity Tests and were entered into the PJM Winter Capacity Test Exemption Program*. The YTD Incentive calculation reflects this information. 26

IV. Appendix – PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights ($26,010.90) ($26,010.90) Balancing Operating Reserve ($1,246.28) $23,537.32 $22,291.04 Balancing Operating Reserve for Load Response $166.39 $166.39 Balancing Spot Market Energy $2,096.34 ($177,178.27) ($175,081.93) Balancing Transmission Congestion $59.68 $8,849.24 $8,908.92 Balancing Transmission Losses $90.76 $5,029.82 $5,120.58 Black Start Service $1,936.99 $1,936.99 Capacity Resource Deficiency ($330.35) ($330.35) Capacity Transfer Rights ($18,612.90) ($18,612.90) CT Lost Opportunity Cost Allocation ($16.80) ($16.80) Day-Ahead Load Response Charge Allocation $306.07 $306.07 Day-ahead Operating Reserve ($5,869.44) $8,828.24 $2,958.80 Day-ahead Scheduling Reserve ($172.89) $718.05 $545.16 Day-ahead Spot Market Energy ($51,609.42) $726,020.92 $674,411.50 Day-ahead Transmission Congestion ($6,353.76) $16,374.23 $10,020.47 Day-ahead Transmission Losses ($2,073.90) $95,985.58 $93,911.68 Expansion Cost Recovery $427.50 $427.50 FERC Annual Recovery $4,088.77 $4,088.77 Generation Deactivation Refund ($758.35) ($758.35) Generation Resource Rating Test Failure ($76.65) ($76.65) Inadvertent Interchange ($619.31) ($619.31) Incremental Capacity Transfer Rights ($1,704.30) ($1,704.30) Load Reconciliation for Balancing Operating Reserve $41.17 $41.17 Load Reconciliation for Day-ahead Scheduling Reserve $0.14 $0.14 Load Reconciliation for FERC Annual Recovery $49.53 $49.53 Load Reconciliation for Inadvertent Interchange ($5.85) ($5.85) Load Reconciliation for Market Monitoring Unit (MMU) Funding $3.20 $3.20 Load Reconciliation for Non-Synchronized Reserve $5.09 $5.09 Load Reconciliation for North American Electric Reliability Corporation (NERC) $8.32 $8.32 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $0.57 $0.57 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $171.90 $171.90 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund ($4.92) ($4.92) Load Reconciliation for Reactive Services $2,734.76 $2,734.76 Load Reconciliation for Regulation and Frequency Response Service $162.55 $162.55 Load Reconciliation for Reliability First Corporation (RFC) $11.90 $11.90 Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $24.48 $24.48 Load Reconciliation for Spot Market Energy $29,423.35 $29,423.35 Load Reconciliation for Synchronized Reserve $82.30 $82.30 Load Reconciliation for Transmission Congestion ($315.77) ($315.77) Load Reconciliation for Transmission Losses $507.41 $507.41 Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $61.85 $61.85 Locational Reliability $1,339,975.80 $1,339,975.80 Market Monitoring Unit (MMU) Funding $269.39 $269.39 Meter Error Correction ($5,070.84) ($5,070.84) Michigan - Ontario Interface Phase Angle Regulators $191.90 $191.90 Miscellaneous Bilateral ($523.53) ($523.53) Network Integration Transmission Service $331,131.30 $331,131.30 Non-Firm Point-to-Point Transmission Service ($437.85) ($437.85) Non-Synchronized Reserve $37.26 $37.26 North American Electric Reliability Corporation (NERC) $687.19 $687.19 Organization of PJM States, Inc. (OPSI) Funding $47.42 $47.42 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,509.35 $1,509.35 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $913.50 $913.50 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $11,627.23 $11,627.23 PJM Scheduling, System Control and Dispatch Service - Market Support $2,642.78 $2,642.78 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($367.92) ($367.92) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $112.36 $112.36 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($23.40) ($23.40) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($329.86) ($329.86) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($77.25) ($77.25) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($3.99) ($3.99) PJM Settlement, Inc. $367.92 $367.92 Reactive Services $129,955.76 $129,955.76 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) $34,385.92 $4,918.34 Real-Time Load Response Charge Allocation $114.61 $114.61 Regulation and Frequency Response Service $16,916.46 $16,916.46 Reliability First Corporation (RFC) $982.69 $982.69 RPM Auction ($1,286,250.00) ($1,286,250.00) Synchronized Reserve $ 1,517.62 $ 1,517.62 Transmission Enhancement $4,569.53 $4,569.53 Transmission Losses ($27,172.76) ($27,172.76) Transmission Owner Scheduling, System Control and Dispatch Service $5,105.80 $5,105.80 Grand Total $ (1,380,873.14) $ 2,549,054.31 $ 1,168,181.17 27

The Energy Authority, Inc. Monthly Management Committee Update – July 2013 August 22, 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 $768,197 over budget due to higher than budgeted cost of energy purchases. Actual market purchases and prices were higher than budgeted. This was driven by the higher than normal temperatures experienced in the Northeast in July. Dover’s budgeted cost for all power supply (capacity AND energy) was $85.03/MWh. The actual cost of all power supply (capacity AND energy) was $88.42/MWh. The cost of energy alone was $63.33/MWh, versus a budgeted energy cost of $60.24. Dover’s hedge purchases totaled 58,720 MWh, which was 77% of the projected load and 72% of the actual load. Dover’s power purchases from hedge transactions totaled $3,452,702. Purchases from PJM (energy and fees) totaled $2,126,891 with DA Energy purchases totaling $1,160,675 and Balancing Spot Market Energy totaling a credit of $92,485. Dover’s total load was 82,072 MWh versus a forecasted load of 76,312 MWh. Dover’s planned energy purchase from the SunPark solar installation was 2075 MWh. Dover’s actual energy purchase from the SunPark installation was 2053 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 76,312 82,072 (5,760) Wholesale Load 74,277 80,019 (5,742) Hedged Volume (MWh) 58,720 58,720 - Unhedged Volume (MWh) 15,557 21,299 (5,742) Dover SunPark Volume (MWh) 2,035 2,053 (18) Renewable Energy Credits Volume 305 309 (4) Hedged Cost ($/MWh) 58.80 58.80 0 Unhedged Energy Cost ($/MWh) $ 63 $ 73 $ (10) Solar Energy Cost ($/MWh) $ 83 $ 91 $ (8) Energy Costs ($/MWh) $60.24 $63.33 ($3.09) All-in Costs - Energy, Capacity and RECs ($/MWh) $85.03 $88.42 ($3.39) 2

B. Generation Summary: Dover generated 7,198 MWh in the month. Net generation revenue was $1,698,577 vs. a budget of $788,783. This delta was mainly due to higher than budgeted market prices and lower than budgeted O&M costs. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 7,197.54 All In Generation Margin PJM Bill Energy $ 1,124,166.28 PJM Capacity $ 1,329,125.00 Black Start, Reactive Credit, DASR & EFORp $ 108,639.72 Gas Purchases $ (370,721.00) Oil Purchases $ - Transport / Cash Out $ (52,999.88) Gross Margin $ 2,138,210.12 Production Margin Generation Production Revenues (PJM) $ 1,124,166.28 Gas Purchases $ (370,721.00) Oil Purchases $ - Transport / Cash Out $ (52,999.88) Gross Production Margin $ 700,445.40 4

C. Emissions Summary: Emissions Allowance Summary through July 31, 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 10/4/2012 2013 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 7/31/2013 C.Y.T.D. 2013 Emissions 0 13 13 REMAINING ALLOWANCES 11,053 60 179 On August 21, 2012, a three-judge panel of the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s Cross State Air Pollution Rule (CSAPR) which would have become effective on January 1, 2012. The DCA instructed EPA to continue administering the Clean Air Interstate Rule (CAIR). EPA has appealed this ruling to the U.S. Supreme Court, and the Court has agreed to review the DCA opinion. A ruling is not expected before June, 2014. 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 (8/15/2013) Commodity $/Ton Tons Extended (Bid/Offer Avg.) Value SO2 Allowances (2009 & earlier) $ 1.38 5,089 $ 7,023 SO2 Allowances (2010-13) $0.68 5,964 4,055 NOx Allowances - Seasonal $21.50 60 1,290 NOx Allowances - Annual $40.00 179 7,160 TOTAL $19,528 Regional Greenhouse Gas Initiative The State of Delaware is a participant in the Regional Greenhouse Gas Initiative (RGGI). The City of Dover must comply with RGGI by surrendering carbon dioxide (CO2) allowances pursuant to the State of Delaware’s laws (Title 7, Chapter 60, Sub-Title II-A). Delaware has elected a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). 6

CO2 Allowance Summary (7/31/2013) 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 (5,814) 8,798 113,303 The table shows that the “Allocated CO2 Allowances” (column 5) are declining. After 2013, Dover will no longer receive allocations of RGGI allowances. 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 have been included in previous monthly reports. 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. The State of Delaware has held two workgroup meetings (5/14/2013 & 6/18/2013) on the proposed rule. The Delaware Department of Natural Resources expects to publish a draft rule in the Delaware Register in the near future. 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 June 7, 2013 and the auction cleared at $3.21/ton. The next auction will occur on September 4, 2013. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on August 15, 2013 ranged from $2.98 to $3.00/ton, depending on vintage. Based on the average ICE 7

futures prices, the value of Dover’s existing RGGI allowance bank (113,303 tons) is approximately $338,776. Vintage Balance (Tons) Settlement Extended Value Price ($/Ton) 2009 56,388 $3.48 $196,230 2010 16,776 $3.50 58,716 2011 19,548 $3.50 68,418 2012 11,793 $3.35 39,507 2013 14,612 $3.27 47,781 TOTAL 119,117 $410,652 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. 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 June 2013, Dover has accumulated a total of 5,424 SRECS from these renewable energy resources. The nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s August 2013 SREC auction cleared separately for 2011, 2012 and 2013 vintage allowances. Clearing prices and Dover’s SREC market value estimate are shown in the table below. SREC SREC Vintage Auction Clearing Price Market Value Quantity 2011 $4.01 1,190 $ 4,772 2012 $5.01 2,799 14,023 2013 $13.00 1,435 18,655 TOTAL 5,424 $37,490 With the exception discussed below, 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. SRECs in both Delaware and Pennsylvania expire without value after 3 years. Dover currently has 7 2010 Vintage SRECs which may expire in the near future. If Dover is not able to use these for compliance with its Renewable Portfolio Standard before they 8

expire, it may not make sense to sell such a small quantity of RECs (market value of around $30). This will become more of a concern in 2014 because Dover began accumulating SRECs from the SunPark in July 2011. TEA stands ready to transfer, retire or sell SRECs upon receipt of instructions from Dover. D. Operations Management Summary: During the month of July, there were no reportable or lost time accidents or injuries. The facility has now gone 1,021 days without an OSHA recordable accident and 1,021 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued and there were no Near Miss incidents. In the month of July, Units 1 and 2 were dispatched once, Unit 3 was dispatched 6 times and Unit 11 was dispatched 4 times by PJM. Unit 1 was forced off line due to a boiler leak and Unit 11 tripped off line and had to be restarted once. Commissioning of the industrial waste water discharge system was completed. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of July were $313,260. The actual expenses are $493,134 or 61.15% under the approved budget of $806,394. The principal reason for the favorable variance was due to timing of expenses for plant general liability and environmental insurance. Additional contributions to the favorable variance were due to accruals for labor into June and lower than anticipated water and sewer costs for the month. 9

E. Risk Management Summary: Forward power prices in PJM are lower than last month. The blended cost has decreased for all years. The current projected cost of service is below: Blended Monthly Cost Change Power Year Hedge Ratio ($/MWh) ($/MWh) 2013-14 62% $51.33 ($0.28) 2014-15 38% $46.41 ($0.67) 2015-16 15% $45.19 ($0.62) 10

II. Budget Report Variance Report: Budget Actual Variance Jul-13 Jul-13 Gross Load 76,312 82,072 (5,760) Power Supply Hedged Energy $3,452,702 $3,452,702 $0 PJM - Energy $975,221 1,557,651 ($582,430) PJM - ARR, Transmission and Fees $395,000 569,240 ($174,240) Dover SUN Park Energy $169,439 $187,421 ($17,983) Dover SUN Park RECs $25,000 $43,285 ($18,285) Management Fees $83,000 $83,000 $0 Capacity UCAP Obligated Purchased $1,388,224 $1,363,483 $24,741 Subtotal - Power Supply $6,488,585 $7,256,782 ($768,197) Power Generation O&M Plant O&M 806,394.00 $493,134 313,260 Subtotal Generation O&M 806,394.00 493,134.00 $313,260 Power Generation Production Margin Economic and reliability dispatch ($230,472) $ (1,124,166.28) $893,695 Fixed Fuel and Transport Charges $0 $ 423,720.88 ($423,721) Subtotal Generation Production Margin ($230,472) $ (700,445.40) $469,974 Power Generation Non-Production Revenue Generation Capacity Credit ($1,329,125) $ (1,329,125.00) $0 Emissions Allowance Sales $0 $ - $0 Black Start & Transmision Losses ($35,580) $ (162,140) $126,560 Subtotal - Non-Production Revenue ($1,364,705) ($1,491,265) $126,560 SubTotal - All Generation (788,782.60) ($1,698,577) $909,794 Total - Utilities Cost $5,699,803 $5,558,206 $141,597 Unit Costs Total - Power Supply $85.03 $88.42 ($3.39) Total - Power Generation ($10.34) ($20.70) $10.36 Final Cost of Service to City of Dover Ratepayers $74.69 $67.72 $6.97 11

Variance Analysis: Power Supply  Dover consumed 5,760 MWh more than what was forecasted for the month.  PJM energy costs were higher than expected and PJM’s fees were higher than forecast. This was due to higher load and market prices. Hedged costs were as forecasted.  The result of higher overall costs for more power was a net power supply cost of $88.42/MWh, $3.39/MWh higher than budget.  For the month, the city realized an unfavorable variance of $768,197 for power supply vs. the monthly budget.  Dover Sun Park generated 18 MWh more than forecast. Generation  Power generation had a favorable budget variance of $909,794.  Plant O&M expenses had a favorable budget variance of $313,260 for the month. 12

III. Operations Management NAES Corporation Dover, Delaware July 2013 Monthly Report Improved Lighting in the Hot Water Boiler Room 13

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

1.0 Environmental, Health and Safety: During the month of July, there were no restricted work days or lost time accidents. The facility has now gone two years, nine months and seventeen days (1,021 days) through July 31, 2013 without an OSHA Recordable Accident or a Lost Time reportable accident. The Plant Safety training matrix has been updated for 2013 and is being tracked on a monthly basis for all employees. The training program includes the inclusion of the General Physics on-line training system as well as plant safety procedures and policies. Safety Procedures and associated quizzes are currently being updated. As they are completed, staff will retrain on each one to ensure they understand what changes have been made, if any, to the programs. The plant received no Notice of Violations (NOVs) during the month. The July (June Discharge) DMR was submitted for the McKee Run site with no NPDES exceedences. Work and shakedown on the Industrial Wastewater Project was completed. The facility is still waiting on system as-built drawings and worked with the City of Dover and Kent County to finalize reporting and monitoring requirements for billing and regulatory purposes. The system went “live” in July 2013 and the plant is now receiving water/sewer bills from the City of Dover. On July 30, Tom Lilly, from the DNREC, conducted his annual compliance audit. He was supplied documentation supporting plant compliance with applicable regulations pertaining to the Title V Air Permits. A return site visit will occur so that Mr. Lilly may observe unit operations and to gather real time operating/emissions data. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (July) (7/1/13-6/30/14) NOVs 0 0 Opacity Deviations 0 0 Environmental Deviations 0 0 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 0 Man Hours Worked 4,558.75 4,558.75 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,021 Days since last Lost Time Accident 1,021 15

Emissions (NOx & SO2) All data thru 7/31/13 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 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 0.9 11.6 1.4 13.9 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 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 0.9 11.7 1.4 14.0 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 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 0.0 0.0 0.0 0.0 SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 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* Total SO2 Allowance Balance 11,053 Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 16

CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant Run McKee Run - Run (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2010 and 3*** 27/0 0/2 earlier 2011 0 77/48 5/3 33/31– 3/1 0/0 - 0/0 42/10 2/2 2012 2** 75/46 5/3 36/36 – 1/1 0/0 - 0/0 39/10 2/0 2013 0 77/48 5/3 12/12 – 1/1 0/0 - 0/0 63/34 4/2 Total NOx Allowance Balance 171/54 8/6 *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 5814 8798 Total CO2 Allowance Balance 113,303 *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 17

2.0 Financial Financial – Current Month (Estimated) Month – July Actual Budget Variance Personnel 185,284 250,345 $65,061 Materials & Supplies 29,746 50,385 $20,639 Administrative Expenses 98,230 505,664 $407,434 Total 313,260 $806,394 $493,134 Financial – Fiscal Year to Date (Estimated) Number of Months – 1 Actual Budget Variance Personnel 185,284 250,345 $65,061 Materials & Supplies 29,746 50,385 $20,639 Administrative Expenses 98,230 505,664 $407,434 Total 313,260 $806,394 $493,134 2.1 Variance analysis: The City of Dover Finance Department has closed the books for the month of July 2013. The expenses for July are $313,260 against a budgeted amount of $806,394 for a favorable variance of $493,134 or 61.15%. The variance was due to the following: PERSONNEL EXPENSES – A favorable monthly variance of $65,061 was to due to the accruals of one week payroll into 2013 and not having full complement of employees. Included in these costs are straight time labor, overtime labor, and labor burdens. MATERIALS AND SUPPLIES EXPENSES- A favorable monthly variance of $20,639 was due primarily to lower than anticipated water / sewer costs for the month. ADMINISTRATIVE EXPENSES – A favorable monthly variance of $407,434 was due primarily to the plant general liability and environmental insurance costs not being expensed in this month as anticipated. These costs will be expensed in August. In addition, invoices have not yet been received as expected for the ABB controls maintenance contract. The forecasted expenses for this fiscal year are $6,015,800 expensed versus an approved budget of $6,015,800 thereby realizing a 100 % expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips In the month of July, Units 1 and 2 were dispatched once, Unit 3 was dispatched 6 times and Unit 11 was dispatched four times by PJM. Unit 1 had to take an eighty hour Forced Outage due to a tube leak and problems with the throttle valve. On July 15th, VanSant was requested on by PJM on the way up on load the unit tripped at 24MW due to flame detector issues. Month July 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 91.000 80.802 171.802 46.646 218.448 Starts # 0 1 6 7 8 15 Gross Generation MWh 0.0 489.597 6,517.113 7,006.710 738.459 7,745.169 Net Generation MWh 0.0 447.067 6,028.496 6,475.563 737.891 7,213.454 Total Auxiliaries MWh 0.0 42.530 676.017 718.547 2.264 720.811 Auxiliaries purchased MWh 42.623 85.153 187.400 315.176 1.696 316.872 Fuel Gas Used MMBTU 0.0 7,305.936 67,858.068 75,164.004 10,203.684 85,367.688 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 17.037 17.037 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 123.10 123.10 Total Fuel MMBTU 0.0 7,305.936 67,858.068 75,164.004 10,220.721 85,384.725 Net Heat Rate BTU/KWh 0 16.340 11.256 12.798 13.851 11.836 Unit Trips # 0 0 0 0 1 1 Capacity Factor % 0.0 3.53 7.94 6.40 2.54 5.54 Availability Factor % 89.25 100.00 100.00 92.42 100.00 97.31 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 80.000 0.0 0.0 80.000 0.0 80.000 Reserve Shutdown Hours 664.000 653.000 663.198 1,962.198 721.354 2,683.552 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 434.605 2,245.107 2,679.712 2,679.712 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 19

2013-2014 Fiscal Year-to-Date - July 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 91.000 80.802 171.802 46.646 218.448 Starts # 0 1 6 7 8 15 Gross Generation MWh 0.0 489.597 6,517.113 7,006.710 738.459 7,745.169 Net Generation MWh 0.0 447.067 6,028.496 6,475.563 737.891 7,213.454 Total Auxiliaries MWh 0.0 42.530 676.017 718.547 2.264 720.811 Auxiliaries purchased MWh 42.623 85.153 187.400 315.176 1.696 316.872 Fuel Gas Used MMBTU 0.0 7,305.936 67,858.068 75,164.004 10,203.684 85,367.688 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 17.037 17.037 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 123.10 123.10 Total Fuel MMBTU 0.0 7,305.936 67,858.068 75,164.004 10,220.721 85,384.725 Net Heat Rate BTU/KWh 0 16.340 11.256 12.798 13.851 11.836 Unit Trips # 0 0 0 0 1 1 Capacity Factor % 0.0 3.53 7.94 6.40 2.54 5.54 Availability Factor % 89.25 100.00 100.00 92.42 100.00 97.31 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 80.000 0.0 0.0 80.000 0.0 80.000 Reserve Shutdown Hours 664.000 653.000 663.198 1,962.198 721.354 2,683.552 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 434.605 2,245.107 2,679.712 2,679.712 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) 453,844 454,725 0 881 454,725 0 0 VanSant 146,133 145,964 0 (169) 152,150 0 (6186) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through 7/31//13 Actual Starts Factored Starts Fired Hours VanSant 1318 2,256.75 4,245.70 Since HGP - Dec 2004 237 589.05 862.12 20

Team Report: Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both the Operations and Maintenance areas to help in maintaining the plant. Work continued on painting the fuel lines now that most of the insulation has been removed from the pipeline. Capacity Testing – FY 2013-2014 Summer 2013 (June 1- Aug 31) Winter 2013-2014 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 0.0 1 17 0.0 2 17 0.0 2 17 0.0 3 102 0.0 3 102 0.0 VanSant 39 0.0 11 39 0.0 Total 175 0.0 Total 175 0.0 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program and data has been submitted into the PJM eGADS 21

4.0 Maintenance During the month of July, the Plant Maintenance staff continued addressing the backlog of work orders and completing outage activities. There were fifty-seven work orders issued with seventy-four 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 July - 2013 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 15 2 7 10 2 53 12 27 38 3 37 5 3 39 4 6 0 0 6 5 14 5 1 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 54 33 36 51 Totals 179 57 74 162 Note: PM Work Orders are included in the priority totals Notable activities during the month include:  The NAES IC&E & Maintenance Staff completed the removal and replacement of the air conditioner in the CEMS building shelter. The air conditioner was replaced because it failed and it was not cost effective to repair the unit. The new is more efficient and has environmentally friendly Freon installed in the unit.  The NAES Maintenance Staff, Sulzer Turbine Services and Siemens troubleshot Unit 1 turbine throttle valve when it was found that it would not open. The throttle valve was taken apart to examine the condition of the valve, but nothing was discovered. The team then disassembled the governor trip valve assembly and discovered a key lodged under the governor trip valve seat which prevented the valve from being reset. The key was from the throttle valve servo motor that had been broken off several years earlier that could not be found. The assembly was reinstalled and tested for proper operation. 22

 The NAES IC&E Staff installed new lighting in the Hot Water Boiler Room and the boiler fronts of Units 1 & 2. The new lighting is more efficient and gives off more limens. This will allow for improved lighting during night shift operational periods. 5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: Mechanical and electrical installation work is complete. MR Industrial Waste “As-built” drawings are to be submitted for finalization. Final EG1214 water System permit was received from Kent County in late July. Schedule: Project to be entirely complete no later than August 2013. Unit #3 Cooling Progress: Bids have been received and are currently being evaluated. EG1402 Tower Repairs Schedule: Work planned to be completed in Fall 2013. McKee Run Progress: Work is being planned and scheduled for the Fall and Auxiliary Spring outages. EG1404 Component Schedule: Work activities are slightly behind due to unit operations. Replacement VanSant Station Progress: Work scheduled for the Fall and Spring. EG1405 Component Schedule: Planning activities are underway for Fall and Spring Replacement outages. Progress: Work scope is being developed and work areas assessed McKee Run HEP EG1406 for proper safety/fall protection. Pipe Repairs Schedule: Work to begin in Fall Outage period. Progress: Initial meeting set up with vendor to aid in system Metering System EG1407 integration and to help determine best system for COD. Upgrades Schedule: Work activities are slightly behind due to unit operations. McKee Progress: Work scheduled for the Fall and Spring. EG1408 Run/VanSant Safety Schedule: Work activities are slightly behind due to unit operations. Compliance Items McKee Run Natural Progress: Work scheduled for the Fall and Spring. EG1409 Gas Block-Bleed Schedule: Work activities are slightly behind due to unit operations. Valves McKee Progress: Crane specifications being developed and will be put out EG1410 Run/VanSant Crane for bid thereafter. Replacement Schedule: Work activities are slightly behind due to unit operations. McKee Progress: Plant staff completed development of paint specifications Run/VanSant and bid requests were sent out. . EG1413 Structural Schedule: Bids should be received in early September with work to Preservation be scheduled for late a late September start. 23

Progress: Plant staff continues working with OEM to determine long lead material requirements. Unit 3 Turbine Schedule: Long lead items were procured in the spring of 2013. EG1414 Repairs Some turbine parts (turbine 9th stage blades) have been ordered and received. List of consumables is being finalized and quotes requested thereafter. McKee Run Units Progress: Cost to be incurred due to repairs on Unit 1 boiler and EG1415 #1-#2 Component turbine. Repairs Schedule: Work activities are slightly behind due to unit operations. Progress: Bid specifications are being developed and Environmental VanSant Capacity permit modifications are being investigated. EG1416 Increase Schedule: Plant Staff and TEA to develop scoping documents and proceed with getting regulatory approvals. 24

6.0 General Plant Information  TEA has evaluated the findings of the McHale and Associates Report (Capacity upgrade opportunities for VanSant) and has imported the data into their financial model. From this, TEA developed a presentation that was presented at the March COD/TEA/NAES Management Meeting in which they recommended implementation of the Wet Compression Technology with an estimated cost of $1.5 million dollars. A number of action items were also identified that need to be followed up by NAES and by TEA including updating the project CIP costing and having a discussion with the DNREC regarding the effect the power increase could have on emissions. Included in the action item list was a breakdown of project costs and time frame when those costs would be expected to be expensed.  Plant staff is working to fill two current openings due to personnel changes as a result of an employee resignation and an employee termination. Training:  Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Developing a Safety Culture”. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff.  Plant employees continue using the General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed, the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy as well 25

Calendar of Events Date 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 EIA-860 Report February 28, 2014 EIA-923 Report February 28, 2014 NOx Emissions Reconciliation Due March 1, 2014 SO2 Emissions Reconciliation Due March 1, 2014 SARA III Report March 1, 2014 NPDES Permit Renewal Due March 4, 2014 Units 1, 2, and 3 Spring Outage March , 2014 – June , 2014 Unit 11 Spring Outage March , 2014 – June , 2014 Annual VanSant Black Start Test March , 2014 Air Emission Inventory March , 2014 NOx Ozone Season Starts May 1, 2014 7.0 Summary of NAES Performance to Date Plant Performance FY 2013-2014 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.09% 0.09% $91,087 $93,022 Unavailability (CU) Safety 0 0 $17,440 $17,440 Environmental 0 0 $17,440 $17,440 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No No No $0 $3,488 Unit 2 No No No No $0 $3,455 Unit 3 No No No No $0 $20,930 Unit 11 No No No No $0 $6,977 Total YTD 76.28% Total YTD Incentive $126,667 $162,788 Incentive % Note: No units have successfully completed the PJM Summer Capacity Tests and have until August 31 to complete. The YTD Incentive calculation reflects this information. 26

IV. Appendix – PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights ($26,877.93) ($26,877.93) Balancing Operating Reserve ($34,269.88) $28,835.21 ($5,434.67) Balancing Operating Reserve for Load Response $10.16 $10.16 Balancing Spot Market Energy $27,211.47 $92,484.98 $119,696.45 Balancing Transmission Congestion $140.67 $791.28 $931.95 Balancing Transmission Losses $2,255.22 $6,169.94 $8,425.16 Black Start Service $2,412.06 $2,412.06 Capacity Resource Deficiency ($164.19) ($164.19) Capacity Transfer Rights ($19,233.33) ($19,233.33) CT Lost Opportunity Cost Allocation ($17.36) ($17.36) Day-Ahead Load Response Charge Allocation $347.39 $347.39 Day-ahead Operating Reserve ($12,248.16) $7,877.51 ($4,370.65) Day-ahead Scheduling Reserve ($79,172.14) $40,047.26 ($39,124.88) Day-ahead Spot Market Energy ($1,058,876.48) $1,160,675.19 $101,798.71 Day-ahead Transmission Congestion ($14,430.95) $20,913.87 $6,482.92 Day-ahead Transmission Losses ($33,948.17) $199,845.54 $165,897.37 Expansion Cost Recovery $427.49 $427.49 FERC Annual Recovery $4,878.52 $4,878.52 Generation Deactivation Refund ($758.35) ($758.35) Inadvertent Interchange ($1,131.08) ($1,131.08) Incremental Capacity Transfer Rights ($1,761.11) ($1,761.11) Load Reconciliation for Balancing Operating Reserve $245.85 $245.85 Load Reconciliation for Day-ahead Scheduling Reserve ($35.33) ($35.33) Load Reconciliation for FERC Annual Recovery $168.24 $168.24 Load Reconciliation for Inadvertent Interchange ($11.01) ($11.01) Load Reconciliation for Market Monitoring Unit (MMU) Funding $10.82 $10.82 Load Reconciliation for Non-Synchronized Reserve $4.77 $4.77 Load Reconciliation for North American Electric Reliability Corporation (NERC) $28.28 $28.28 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $1.95 $1.95 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $583.89 $583.89 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund ($16.68) ($16.68) Load Reconciliation for Reactive Services $7,927.04 $7,927.04 Load Reconciliation for Regulation and Frequency Response Service $593.04 $593.04 Load Reconciliation for Reliability First Corporation (RFC) $40.43 $40.43 Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $85.30 $85.30 Load Reconciliation for Spot Market Energy $96,402.08 $96,402.08 Load Reconciliation for Synchronized Reserve $173.11 $173.11 Load Reconciliation for Synchronous Condensing $0.17 $0.17 Load Reconciliation for Transmission Congestion ($4,202.54) ($4,202.54) Load Reconciliation for Transmission Losses $1,734.22 $1,734.22 Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $210.09 $210.09 Locational Reliability $1,384,641.66 $1,384,641.66 Market Monitoring Unit (MMU) Funding $345.70 $345.70 Meter Error Correction ($12,127.67) ($12,127.67) Michigan - Ontario Interface Phase Angle Regulators $210.22 $210.22 Network Integration Transmission Service $342,169.01 $342,169.01 Non-Firm Point-to-Point Transmission Service ($566.30) ($566.30) Non-Synchronized Reserve $377.81 $377.81 North American Electric Reliability Corporation (NERC) $819.89 $819.89 Organization of PJM States, Inc. (OPSI) Funding $56.54 $56.54 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,780.79 $1,780.79 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $943.95 $943.95 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $13,872.98 $13,872.98 PJM Scheduling, System Control and Dispatch Service - Market Support $3,389.28 $3,389.28 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($159.32) ($159.32) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $130.95 $130.95 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($29.45) ($29.45) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($483.74) ($483.74) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($117.33) ($117.33) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($5.68) ($5.68) PJM Settlement, Inc. $159.32 $159.32 Reactive Services $105,146.64 $105,146.64 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) $34,968.14 $5,500.56 Real-Time Load Response Charge Allocation $457.57 $457.57 Regulation and Frequency Response Service $33,659.24 $33,659.24 Reliability First Corporation (RFC) $1,172.45 $1,172.45 RPM Auction ($1,329,125.00) ($1,329,125.00) Synchronized Reserve $1,952.79 $1,952.79 Synchronous Condensing $ 417.14 $ 417.14 Transmission Enhancement $4,883.03 $4,883.03 Transmission Losses ($53,500.44) ($53,500.44) Transmission Owner Scheduling, System Control and Dispatch Service $6,091.98 $6,091.98 Grand Total $ (2,561,931.00) $3,490,373.92 $928,442.92 27

City of Dover Electric Revenue Fund FY 2014 - White Oak Solar Park Incremental Cost Original July YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 187,421 $ 187,421 $ 1,565,800 Dover Sun Park - REC's - - 300,000 Total Power Supply Cost 187,421 187,421 1,865,800 Non-Solar Power Supply Cost (180,264) (180,264) (176,558) Incremental Energy Cost $ 7,157 $ 7,157 $ 1,689,242 Revenues Customer Sales - Electricity (9,404) (9,404) (9,404) Rent Receipts (14,446) (14,446) (58,300) Total Revenues (23,850) (23,850) (67,704) Incremental Sun Park Cost $ (16,693) $ (16,693) $ 1,621,538 MWh Purchased/Generated - Solar 2,053.000 2,053.000 18,159.000 MWh $ Solar Energy 91.29 $ 91.29 $ 86.23 Solar REC's MWh 308.000 308.000 MWh $ Solar REC (one month lag)* $ - $ - MWh $ Non-Solar Energy $ 87.81 Note: Solar REC's is one month behind due to the time the invoice is received.