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UTILITY COMMITTEE AGENDA JULY 22, 2013 - 5:00 P.M . CITY HALL COUNCIL CHAMBERS 15 LOOCKERMAN PLAZA DOVER , DELAWARE Public comments are welcomed on any item and will be permitted at appropriate times. When possible, please notify the City Clerk (736-7008 or e-mail at CityClerk@dover.de.us) should you wish to be recognized. AGENDA ADDITIONS/DELETIONS 1. Proposed Amendments - Water/Wastewater Capital Improvement Projects (CIP) (Due to Time Constraints, This Item Has Been Placed on the Council Agenda for the Meeting Being Held Later in the Evening) (Staff Recommends Approval of the Proposed Amendments) 2. TEA/NAES Report (March and April) (Staff Recommends Acceptance of the Reports) 3. Adjournment by 5:55 p.m. /tm S:\AGENDAS-MINUTES-PACKETS\Committee-Agendas\2013\07-22-2013 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.

The Energy Authority, Inc. Monthly Management Committee Update – March 2013 April 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 $343,619 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 $93.59/MWh. The actual cost of all power supply (capacity AND energy) was $88.48/MWh. The cost of energy alone was $61.74/MWh, versus a budgeted energy cost of $69.61. Dover’s hedge purchases totaled 47,372 MWh, which was 80% of the projected load and 80% of the actual load. Dover’s power purchases from hedge transactions totaled $2,910,970. Purchases from PJM (energy and fees) totaled $1,146,602 with DA Energy purchases totaling $734,413 and Balancing Spot Market Energy totaling a credit of $182,833. Dover’s total load was 59,004 MWh versus a forecasted load of 59,450 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1440 MWh. Dover’s actual energy purchase from the SunPark installation was 1423 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 59,450 59,004 446 Wholesale Load 58,010 57,581 429 Hedged Volume (MWh) 47,372 47,372 - Unhedged Volume (MWh) 10,638 10,209 429 Dover SunPark Volume (MWh) 1,440 1,423 17 Renewable Energy Credits Volume 216 136 80 Hedged Cost ($/MWh) $ 60 $ 61 $ (1) Unhedged Energy Cost ($/MWh) $ 110 $ 59 $ 51 Solar Energy Cost ($/MWh) $ 83 $ 86 $ (3) Energy Costs ($/MWh) $69.61 $61.74 $7.87 All-in Costs - Energy, Capacity and RECs ($/MWh) $93.59 $88.48 $5.12 2

B. Generation Summary: Dover generated 0.07 MWh in the month. Net generation revenue was $867,074 vs. a budget of $898,302. This delta was mainly due to higher than budgeted O&M costs. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 0.07 All In Generation Margin PJM Bill Energy $ 1,195.64 PJM Capacity $ 1,205,977.50 Black Start, Reactive Credit, DASR & EFORp $ 36,373.16 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ (487.00) Gross Margin $ 1,243,059.30 Production Margin Generation Production Revenues (PJM) $ 1,195.64 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ (487.00) Gross Production Margin $ 708.64 $/Mwh All In Generation Margin $ 17,028,209.53 $/Mwh Generation Production Margin $ 9,707.33 4

C. Emissions Summary: Emissions Allowance Summary through March 31, 2013 CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowance Seasonal Annual s 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 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) 3/31/2013 2013 Emissions 0 0 0 REMAINING ALLOWANCES 11,053 1123 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). On January 24, 2013, the full DCA 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. 3 Seasonal NOx values are subject to verification by NAES. 5

refused to rehear a decision of the three-judge panel. On March 29, 2013 EPA, filed a petition with the U.S. Supreme Court asking it to hear the agency’s appeal of the DCA decision to vacate CSAPR. As of the date of this report, the Supreme court has not accepted or rejected EPA’s petition. 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 (4/22/2013) Commodity $/Ton Tons Extended Value (Bid/Offer Avg.) SO2 Allowances $ 0.60 11,053 $6,632 NOx Allowances - Seasonal $20.004 1123 2,240 NOx Allowances - Annual $40.00 192 7,680 TOTAL $16,552 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 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. In March, 19 tons of emissions were recorded during a VanSant black-start test. 4 The most recent Seasonal NOx price available to TEA was received on April 1, 2013. 6

CO2 Allowance Summary (3/31/2013) 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 (19) 15,527 120,032 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:  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 7

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. The next RGGI auction will be held on June 5, 2013. Dover has not registered to participate in this upcoming auction. RGGI futures prices posted on Intercontinental Exchange (ICE) are currently $3.40/ton. Based on ICE futures prices, the value of Dover’s existing RGGI allowance bank (120,032 tons) is approximately $408,109. 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 February 2013, Dover has accumulated a total of 4,195 SRECS from this contract. 8

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 $169,720 for Dover’s 4,243 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 $42,430. 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 on April 26th. 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 March, there were no reportable or lost time accidents or injuries. The facility has now gone 899 days without an OSHA recordable accident and 899 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 March, no units were dispatched by PJM nor were they self-dispatched. All Units were in a planned outage starting March 4. A Black Start capability test was successfully competed on Unit 11. Work continues on the installation of the industrial waste water discharge system. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of March were $375,277. The actual expenses are $32,021 or 9.33% over the approved budget of $343,256. The principal reason for the unfavorable variance was due to timing of expenses for overhead crane testing and replacement of instrumentation on the water treatment storage tank 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 in power year 2012-13 and 2013-14. Prices have dropped in power year 2014-15 and 2015-16 resulting in a lower blended cost. 9

The current projected cost of service is below: Blended Cost Power Year Hedge Ratio ($/MWh) 2012-13 81% $61.55 2013-14 57% $52.51 2014-15 36% $47.84 2015-16 14% $46.60 10

II. Budget Report Variance Report: Budget Actual Variance Mar-13 Mar-13 Gross Load 59,450 59,004 446 Power Supply Hedged Energy $2,843,755 $2,910,970 ($67,215) PJM- Energy $1,165,286 $601,967 $563,319 PJM - Transmission and Fees $313,000 $544,634 ($231,634) Dover SUN Park Energy $129,132 $129,900 ($768) Management Fees $83,000 $83,000 $0 Capacity UCAP Obligated Purchased $1,029,954 $950,037 $79,917 Subtotal - Power Supply $5,564,127 $5,220,508 $343,619 Power Generation O&M & Fixed Fuel Plant O&M $343,256 $375,277 ($32,021) Subtotal Generation O&M $343,256 $375,277 ($32,021) Power Generation Production Margin Economic and reliability dispatch $0 ($1,196) $1,196 Fixed Fuel and Transport Charges $0 $487 ($487) Subtotal Generation Production Margin $0 ($709) $709 Power Generation Non-Production Revenue Generation Capacity Credit ($1,205,978) ($1,205,978) ($1) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($35,580) ($36,373) $793 Subtotal - Non-Production Revenue ($1,241,558) ($1,242,351) $793 SubTotal - All Generation ($898,302) ($867,782) ($30,520) Total - Utilities Cost $4,665,825 $4,352,726 $313,099 Unit Costs Total - Power Supply $93.59 $88.48 $5.12 Total - Power Generation ($15.11) ($14.71) ($0.40) Final Cost of Service to City of Dover Ratepayers $78.48 $73.77 $4.71 11

Variance Analysis: Power Supply  Dover consumed 446 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 above forecast.  The result of lower overall costs for more power was a net power supply cost of $88.48/MWh, $5.12/MWh lower than budget.  For the month, the city realized a favorable variance of $343,619 for power supply vs. the monthly budget.  Dover Sun Park generated 17 MWh less than what was forecasted. Generation  Power generation had an unfavorable budget variance of $30,520.  Plant O&M expenses had an unfavorable budget variance of $32,021 for the month. 12

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 568,081 572,529 (4,448) Power Supply Hedged Energy $29,935,965 $29,038,094 $897,871 PJM- Energy $10,466,152 $6,151,748 $4,314,404 PJM - Transmission and Fees $2,817,000 $3,762,616 ($945,616) Dover SUN Park Energy $993,371 $1,042,479 ($49,107) Management Fees $747,000 $747,000 $0 Capacity UCAP Obligated Purchased $9,103,463 $8,399,193 $704,270 Subtotal - Power Supply $54,062,951 $49,141,131 $4,921,821 Power Generation O&M & Fixed Fuel Plant O&M $4,008,438 $3,909,570 $98,868 Subtotal Generation O&M $4,008,438 $3,909,570 $98,868 Power Generation Production Margin Economic and reliability dispatch ($1,124,312) ($1,866,792) $742,480 Fixed Fuel and Transport Charges $586,004 $949,301 ($363,297) Subtotal Generation Production Margin ($538,308) ($917,490) $379,182 Power Generation Non-Production Revenue Generation Capacity Credit ($10,659,288) ($10,659,285) ($4) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($320,220) ($383,258) $63,038 Subtotal - Non-Production Revenue ($10,979,508) ($11,042,543) $63,035 SubTotal - All Generation ($7,509,378) ($8,050,463) $541,085 Total - Utilities Cost $46,553,573 $41,090,668 $5,462,906 Unit Costs Total - Power Supply $95.17 $85.83 $9.34 Total - Power Generation ($13.22) ($14.06) $0.84 Final Cost of Service to City of Dover Ratepayers $81.95 $71.77 $10.18 13

III. Operations Management NAES Corporation Dover, Delaware March 2013 Monthly Report Unit 3 Generator Rotor that has been removed for Inspection and Testing 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 March, there were no restricted work days or lost time accidents. The facility has now gone two years, five months and nineteen days (899 days total) through March 31, 2013 without an OSHA Recordable Accident or a Lost Time reportable accident. The plant received no Notice of Violations (NOVs) during the month and a number of reporting activities were completed during the month. The March DMR was submitted for the McKee Run site with no NPDES exceedences. The annual e-GGRT EPA Greenhouse Gas reports were submitted for the McKee Run and VanSant facilities. The annual Tier II EPA Chemical Inventory reports were submitted for the McKee Run and VanSant facilities. The Title V air permits for the McKee Run and VanSant facilities were advertised by DNREC with no comment received. The McKee Run NPDES permit renewal was submitted with the facility intending to move to a General Storm Water Permit at the end of this current permit cycle. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (March) (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 4,144 37,660.50 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 899 Days since last Lost Time Accident 899 Mechanical work is nearly complete on the Industrial Wastewater Project with both Mechanical and Electrical contractors currently onsite. Project completion is anticipated for May 2013. 16

Emissions (NOx & SO2) All data thru 3/31/13 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 0.0 0.0 0.0 0.0 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 0.0 0.0 0.0 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* *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. 17

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 19 15,527 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 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 18

2.0 Financial Financial – Current Month Month – March Actual Budget Variance Personnel 237,611 241,742 4,131 Materials & Supplies 8,356 7,490 (866) Administrative Expenses 129,310 94,024 (35,286) Total $375,277 $343,256 ($32,021) Financial – Fiscal Year to Date Number of Months – 9 Actual Budget Variance Personnel 2,259,248 2,329,294 70,046 Materials & Supplies 166,828 170,930 4,102 Administrative Expenses 1,483,493 1,508,214 24,721 Total $3,909,569 $4,008,438 $98,869 2.1 Variance analysis: The City of Dover Finance Department has closed the books for the month of March 2013. The expenses for March are $375,277 against a budgeted amount of $343,256 for an unfavorable variance of $32,021 or ≈ 9.33%. The variance was due to the following: PERSONNEL EXPENSES – A favorable monthly variance of $11,692 was due to having a lower than budgeted straight time labor and labor burdens. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $866 was due primarily to the timing of the invoice for the annual MP2 (CMMS) maintenance contract. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $35,286 was due to expenses for overhead crane load test – inspection, video recorder replacement (budgeted for later in year), level indicators for Unit #3 water treatment storage tanks, and main gas isolation valve replacement. The budget is currently forecasted to finish this fiscal year at $5,838,495 expensed versus an approved budget of $5,914,900 thereby realizing a 98.71% 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 March. All units started the spring outage at 0700 hours on March 4, 2013. The annual Black Start test of Unit 11 was successfully completed on March 13, 2013 and reported as such in the PJM eDART system. Net generation is zero due to the unit being self-sufficient during the course of the testing. Month March 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 1 1 Gross Generation MWh 0.0 0.0 0.0 0.0 0.086 0.086 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 31.530 31.530 137.812 200.872 5.699 206.571 Auxiliaries purchased MWh 31.530 31.530 137.812 200.872 5.699 206.571 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 103.592 103.592 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 0.0 103.592 103.592 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 % 0.00 0.00 0.00 0.00 0.00 0.00 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 665.000 665.000 665.000 1,995.000 665.000 2,660.000 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 79.0 79.0 79.0 237.00 79.0 316.00 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. 20

2012-2013 Fiscal Year-to-Date - March McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 96.282 71.970 285.597 453.849 22.699 476.548 Starts # 3 2 26 31 5 36 Gross Generation MWh 668.79 582.202 18,797.488 20,048.48 714.904 20,763.384 Net Generation MWh 628.855 541.673 17,317.513 18,488.041 714.287 19,202.328 Total Auxiliaries MWh 295.344 295.937 2,994.758 3,586.039 31.388 3,442.244 Auxiliaries purchased MWh 255.409 255.409 1,514.783 2,025.601 30.857 2,056.458 Fuel Gas Used MMBTU 9,483 8,108, 199,166.724 216,348 8,532.592 224,888 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 8,644 224,992 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 % 0.54 0.49 2.60 2.08 0.28 1.68 Availability Factor % 66.70 66.70 66.70 66.70 66.70 66.70 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 2,177 2,177 2,177 6,531 2,177 8,708 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 4,306.218 4,327.030 4,113.570 12,746.818 4,376.934 17,123.752 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 143,520 143,857 0 337 152,150 0 (8,293) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through 3/31//13 Actual Starts Factored Starts Fired Hours VanSant 1307 2,236.25 4,218.86 Since HGP - Dec 2004 231 568.55 835.28 21

Team Report: The operators continue to use the Plant Readiness Program for training and refreshing their plant knowledge on different systems to improve the plant’s reliability. Some of the training involved promotes teamwork with other staff members to work together to find a solution and to promote further discussions on equipment operation. The operators also use the GPi Learning courses to improve their knowledge and skills. The GPI online training which supports our safety, OSHA, and environmental training are being used by the teams to complete their training for the year. Along with the GPI OSHA training the operators review the plant’s safety procedures. The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. They assisted in the natural gas line purge on Unit 3 in preparation of the installation of the pipe blank and in the purge on Units 1 and 2 gas lines. The Operations staff has also supported the outage by performing various LO/TO tasks needed to test or place equipment in or out or service. . Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both the Operations and Maintenance areas to help in maintaining the plant. 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 22

4.0 Maintenance During the month of March, the Plant Maintenance staff continued addressing the backlog of work orders and completing outage activities. There were sixty-two work orders issued with seventy-five work orders being completed during the month. There was no safety work orders entered into the plant’s Computerized Maintenance Management System (MP2) during the month. The table below summarizes the monthly work order activities. Work Order Report March - 2013 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 10 1 4 7 2 47 6 18 35 3 43 0 5 38 4 6 0 0 6 5 18 6 2 22 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 80 49 46 83 Totals 204 62 75 191 Note: PMs are included in the priority totals Notable activities during the month include:  NAES Mechanical Maintenance Staff completed outage inspections on Unit 3 boiler, wind box, air register dampers and all associated duct work. There were no issues found during all of these inspections.  NAES Turbine Services was on site to inspect and test the Unit 3 generator stator and rotor. During the testing there were no issues found during any of the inspections or tests. As part of work, NAES IC&E Staff provided support in the dismantling and reassembly of the generator by removing and reinstalling all necessary wiring and instrumentation equipment to complete the inspection and testing of the unit.  APEX Piping System was on site to replace two tubes at the A2 burner throat. After the replacement of the tubes was complete, a hydro was performed on the boiler in which it was pressurized to approximately 1660psi. There were no leaks on the tubes that were repaired or any other leaks in the boiler. 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 40%. 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 Some turbine parts (turbine 9th stage blading) have been ordered Progress: The FY2013 work scope package being developed Units 1 & 2 EG1304 Schedule: Work to be completed during the spring outage 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 FY2013 work scope package being developed. Units 1&2 Stack Schedule: Work to be completed during the spring outage or EG1310 Repairs deferred until 2015. Inspection was completed in November and report is forthcoming so scoping documents may be developed. Progress: Valuation of the benefits of various technologies has been VanSant Capacity EG1311 completed and TEA is recommending implementation of the Wet Increase Compression Technology at an approximate cost of $1.5M. Plant 24

staff to develop cost schedule and COD Management to bring forward to COD Council for decision on the project. Schedule: COD Management Team to work on approval of project going forward. Progress: Contract work has been awarded and vendor has mobilized to the plant. Disassembly has been undertaken and testing Unit 3 Generator has been completed with no issues found. EG1312 Repairs Schedule: Oil flush and air leak check of the generator are slated to be completed in April with an operational check of the unit to forward shortly afterwards. Progress: Mechanical and electrical installation work has been started. Mechanical work is 80% complete and electrical work is MR Industrial Waste EG1214 40%. water System Schedule: Installation work slated for completion in April with testing of system to commence immediately thereafter. Unit 1 Gland Steam Progress: NA EG1301 Seal Repair Schedule: Work is complete. 25

6.0 General Plant Information  The XL Insurance Representatives Neal Grabow and Steve Behrens who were onsite in February for their annual inspection provided the plant with a draft of their 2013 report. Plant staff reviewed the document and provided several suggested edits on some of the language and also clarified some technical points regarding the plant. The report was also provided to COD management for their review and comments. Goal is to provide Mr. Grabow with those edits in early April.  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.  The data was entered into PJM eGADS for the verification of completion of the Winter Capacity Test. Since all the units were in the Winter Test Exemption Program and the units did not operate, summer test data is used for the verification. Training:  OES-NA was on site on March 18th and 19th for PJM simulation training. PJM requires 30 simulation credits for the three year Generation System operator certification. The only method to receive these credits is to attend PJM System Operator seminar or to have qualified training observed by PJM. Voltage Control, Congestion Management, and Emergency Operations was covered in the two day class using laptops. Five operators and two supervisors attended the class. BL England sent an Operations supervisor for training. This class will supply the operator with 14 simulation credits.  Plant employees continue General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy as well.  Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. 26

Calendar of Events Date 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 March 30, 2013 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 EIA-860 Report February 28, 2014 EIA-923 Report 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 $ (1,117.24) $ (1,117.24) Balancing Operating Reserve $ (1,193.00) $ 21,207.94 $ 20,014.94 Balancing Spot Market Energy $ (2.54) $ (182,830.31) $ (182,832.85) Balancing Transmission Congestion $ (0.01) $ (8,590.32) $ (8,590.33) Balancing Transmission Losses $ (0.09) $ 4,349.66 $ 4,349.57 Black Start Service $ (6,905.58) $ 1,995.96 $ (4,909.62) Capacity Resource Deficiency $ (510.88) $ (510.88) Capacity Transfer Rights $ (33,318.18) $ (33,318.18) Day-ahead Operating Reserve $ 6,488.89 $ 6,488.89 Day-ahead Scheduling Reserve $ 64.93 $ 64.93 Day-ahead Spot Market Energy $ 734,413.39 $ 734,413.39 Day-ahead Transmission Congestion $ (49,202.62) $ (49,202.62) Day-ahead Transmission Losses $ 76,130.72 $ 76,130.72 Expansion Cost Recovery $ 427.49 $ 427.49 FERC Annual Recovery $ 3,515.22 $ 3,515.22 Generation Deactivation Refund $ (758.35) $ (758.35) Inadvertent Interchange $ (303.95) $ (303.95) Load Management Test Failure $ (199.95) $ (199.95) Load Reconciliation for Balancing Operating Reserve $ (26.92) $ (26.92) Load Reconciliation for FERC Annual Recovery $ (6.84) $ (6.84) Load Reconciliation for Inadvertent Interchange $ (4.51) $ (4.51) Load Reconciliation for Market Monitoring Unit (MMU) Funding $ (0.44) $ (0.44) Load Reconciliation for North American Electric Reliability Corporation (NERC) $ (1.15) $ (1.15) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $ (23.73) $ (23.73) Load Reconciliation for Reactive Services $ (143.98) $ (143.98) Load Reconciliation for Regulation and Frequency Response Service $ 161.33 $ 161.33 Load Reconciliation for Reliability First Corporation (RFC) $ (1.64) $ (1.64) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $ (3.06) $ (3.06) Load Reconciliation for Spot Market Energy $ 6,987.49 $ 6,987.49 Load Reconciliation for Synchronized Reserve $ 99.31 $ 99.31 Load Reconciliation for Transmission Congestion $ 2,221.44 $ 2,221.44 Load Reconciliation for Transmission Losses $ 664.76 $ 664.76 Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $ (8.54) $ (8.54) Locational Reliability $ 984,894.18 $ 984,894.18 Market Monitoring Unit (MMU) Funding $ 172.77 $ 172.77 Meter Error Correction $ (2,762.21) $ (2,762.21) Network Integration Transmission Service $ 292,797.79 $ 292,797.79 Non-Firm Point-to-Point Transmission Service $ (395.83) $ (395.83) North American Electric Reliability Corporation (NERC) $ 590.79 $ 590.79 Organization of PJM States, Inc. (OPSI) Funding $ 40.78 $ 40.78 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $ 1,559.76 $ 1,559.76 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $ 948.91 $ 948.91 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $ 9,996.22 $ 9,996.22 PJM Scheduling, System Control and Dispatch Service - Market Support $ 2,259.12 $ 2,259.12 PJM Scheduling, System Control and Dispatch Service - Market Support Offset $ (307.21) $ (307.21) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $ 92.54 $ 92.54 PJM Settlement, Inc. $ 307.21 $ 307.21 Reactive Services $ 163,363.08 $ 163,363.08 Reactive Supply and Voltage Control from Generation and Other Sources Service $ (29,467.58) $ 33,308.23 $ 3,840.65 Regulation and Frequency Response Service $ 14,916.39 $ 14,916.39 Reliability First Corporation (RFC) $ 844.82 $ 844.82 RPM Auction $ (1,205,977.50) $ (1,205,977.50) Synchronized Reserve $ 10,933.30 $ 10,933.30 Transmission Enhancement $ 23,052.94 $ 23,052.94 Transmission Losses $ (26,018.10) $ (26,018.10) Transmission Owner Scheduling, System Control and Dispatch Service $ 4,389.59 $ 4,389.59 Balancing Operating Reserve for Load Response $ (2.09) $ (2.09) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $ (0.08) $ (0.08) Load Reconciliation for Day-ahead Scheduling Reserve $ 0.09 $ 0.09 Load Reconciliation for Synchronous Condensing $ (0.01) $ (0.01) Demand Resource and ILR Compliance Penalty $ (95.79) $ (95.79) Day-Ahead Load Response Charge Allocation $ 182.11 $ 182.11 Real-Time Load Response Charge Allocation $ 40.98 $ 40.98 Incremental Capacity Transfer Rights $ (1,028.27) $ (1,028.27) Michigan - Ontario Interface Phase Angle Regulators $ 180.96 $ 180.96 Non-Synchronized Reserve $ 702.63 $ 702.63 CT Lost Opportunity Cost Allocation $ (10.23) $ (10.23) Load Reconciliation for Non-Synchronized Reserve $ 7.36 $ 7.36 $ (1,243,546.30) $ 2,096,638.65 $ 853,092.35 28

The Energy Authority, Inc. Monthly Management Committee Update – April 2013 May 23, 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 $276,810 under budget due to lower than budgeted cost of energy purchases. Dover’s budgeted cost for all power supply (capacity AND energy) was $98.45/MWh. The actual cost of all power supply (capacity AND energy) was $93.08/MWh. The cost of energy alone was $64.85/MWh, versus a budgeted energy cost of $72.35. Dover’s hedge purchases totaled 43,040 MWh, which was 81% of the projected load and 80% of the actual load. Dover’s power purchases from hedge transactions totaled $2,748,192. Purchases from PJM (energy and fees) totaled $1,033,320 with DA Energy purchases totaling $664,276 and Balancing Spot Market Energy totaling a credit of $176,021. Dover’s total load was 53,468 MWh versus a forecasted load of 53,365 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1732 MWh. Dover’s actual energy purchase from the SunPark installation was 2112 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 53,365 53,468 (103) Wholesale Load 51,633 51,356 277 Hedged Volume (MWh) 43,040 43,040 - Unhedged Volume (MWh) 8,593 8,316 277 Dover SunPark Volume (MWh) 1,732 2,112 (380) Renewable Energy Credits Volume 260 213 47 Hedged Cost ($/MWh) $ 64 $ 64 $ 0 Unhedged Energy Cost ($/MWh) $ 110 $ 63 $ 47 Solar Energy Cost ($/MWh) $ 83 $ 86 $ (3) Energy Costs ($/MWh) $72.35 $64.85 $7.50 All-in Costs - Energy, Capacity and RECs ($/MWh) $98.45 $93.08 $5.37 2

B. Generation Summary: Dover generated 64.80 MWh in the month. Net generation revenue was $696,589 vs. a budget of $823,117. This delta was mainly due to higher than budgeted O&M costs. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 64.80 All In Generation Margin PJM Bill Energy $ 2,333.91 PJM Capacity $ 1,167,075.00 Black Start, Reactive Credit, DASR & EFORp $ 36,373.16 Gas Purchases $ (8,170.00) Oil Purchases $ - Transport / Cash Out $ (781.04) Gross Margin $ 1,196,831.03 Production Margin Generation Production Revenues (PJM) $ 2,333.91 Gas Purchases $ (8,170.00) Oil Purchases $ - Transport / Cash Out $ (781.04) Gross Production Margin $ (6,617.13) 4

C. Emissions Summary: Emissions Allowance Summary through April 30, 2013 CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowance Seasonal Annual s 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) 3/31/2013 2013 Emissions 0 0 1 REMAINING ALLOWANCES 11,053 1123 189 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). On January 24, 2013, the full DCA 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. 3 Seasonal NOx values are subject to verification by NAES. 5

refused to rehear a decision of the three-judge panel. On March 29, 2013 EPA, filed a petition with the U.S. Supreme Court asking it to hear the agency’s appeal of the DCA decision to vacate CSAPR. As of the date of this report, the Supreme Court has not accepted or rejected EPA’s petition. 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 (5/20/2013) Commodity $/Ton Tons Extended Value (Bid/Offer Avg.) SO2 Allowances (2009) $ 1.38 3,050 $4,209 SO2 Allowances (2010-13) $ 0.73 8,003 5,842 NOx Allowances - Seasonal $16.50 1123 1,848 NOx Allowances - Annual $40.00 189 7,560 TOTAL $19,459 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 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. In March, 19 tons of emissions were recorded during a VanSant black-start test and in April, 105 ton were recorded during unit testing during the spring 2013 semi-annual maintenance outage. 6

CO2 Allowance Summary (3/31/2013) 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 (124) 15,422 119,927 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 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. 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. The next RGGI auction will be held on June 5, 2013. Dover has not registered to participate in this upcoming auction. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on May 20, 2013 ranged from $3.32 to $3.40/ton, averaging $3.37/ton. Based on the average ICE 7

futures prices, the value of Dover’s existing RGGI allowance bank (119,927 tons) is approximately $404,154. 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 49 Solar Renewable Energy Certificates (SRECS) for all generation through March 2013. 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 March 2013, Dover has accumulated a total of 4,408 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 March 2013 auction ranged from a high of $86.60/MWh for Tier N2 to a low of $34.59 for Tier E1. This results in a theoretical market value of $155,995 by using a Delaware auction price of $35/MWh for Dover’s 4,457 SRECs. It should be noted, however, that the nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s March 2013 SREC auction cleared at $13/MWh. Using this price, Dover’s SRECs would have a market value of $57,941. SREC-Delaware (www.srecdelaware.com) is also conducting a spot SREC auction for existing SRECs between May 15th and May 22. Results from this spot auction were not available at the time of this 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. 8

D. Operations Management Summary: During the month of April, there were no reportable or lost time accidents or injuries. The facility has now gone 929 days without an OSHA recordable accident and 929 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 April, no units were dispatched by PJM nor were they self dispatched. All Units were in a planned outage starting March 4. New Title V Air Permits for McKee Run and VanSant were received and are now in effect for the next five years. Work continues on the installation of the industrial waste water discharge system with the mechanical work essentially complete. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of April were $500,242. The actual expenses are $120,704 or 31.80% over the approved budget of $379,538. The principal reason for the unfavorable variance was due to timing of expenses for labor (3 payrolls billed versus 2 payrolls budgeted), and electrical usage. E. Risk Management Summary: Forward power prices in PJM are similar to last month. The blended cost has decreased slightly in 2013–14 and increased slightly in 2015-16. The current projected cost of service is below: Blended Cost Power Year Hedge Ratio ($/MWh) 2012-13 81% $61.53 2013-14 60% $52.36 2014-15 38% $47.92 2015-16 14% $46.81 9

II. Budget Report Variance Report: Budget Actual Variance Apr-13 Apr-13 Gross Load 53,365 53,468 (103) Power Supply Hedged Energy $2,757,242 $2,748,192 $9,050 PJM- Energy $948,265 $526,299 $421,966 PJM - Transmission and Fees $313,000 $507,021 ($194,021) Dover SUN Park Energy $155,317 $192,841 ($37,524) Management Fees $83,000 $83,000 $0 Capacity UCAP Obligated Purchased $996,729 $919,391 $77,339 Subtotal - Power Supply $5,253,553 $4,976,744 $276,810 Power Generation O&M & Fixed Fuel Plant O&M $379,538 $500,242 ($120,704) Subtotal Generation O&M $379,538 $500,242 ($120,704) Power Generation Production Margin Economic and reliability dispatch $0 ($2,334) $2,334 Fixed Fuel and Transport Charges $0 $8,951 ($8,951) Subtotal Generation Production Margin $0 $6,617 ($6,617) Power Generation Non-Production Revenue Generation Capacity Credit ($1,167,075) ($1,167,075) $0 Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($35,580) ($36,373) $793 Subtotal - Non-Production Revenue ($1,202,655) ($1,203,448) $793 SubTotal - All Generation ($823,117) ($696,589) ($126,528) Total - Utilities Cost $4,430,436 $4,280,155 $150,282 Unit Costs Total - Power Supply $98.45 $93.08 $5.37 Total - Power Generation ($15.42) ($13.03) ($2.40) Final Cost of Service to City of Dover Ratepayers $83.02 $80.05 $2.97 10

Variance Analysis: Power Supply  Dover consumed 103 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 slightly below forecast.  The result of lower overall costs for more power was a net power supply cost of $93.08/MWh, $5.37/MWh lower than budget.  For the month, the city realized a favorable variance of $276,810 for power supply vs. the monthly budget.  Dover Sun Park generated 380 MWh more than forecast. Generation  Power generation had an unfavorable budget variance of $126,528.  Plant O&M expenses had an unfavorable budget variance of $120,704 for the month. 11

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 621,446 625,998 (4,552) Power Supply Hedged Energy $32,693,207 $31,786,286 $906,921 PJM- Energy $11,414,417 $6,678,047 $4,736,370 PJM - Transmission and Fees $3,130,000 $4,269,638 ($1,139,638) Dover SUN Park Energy $1,148,689 $1,235,320 ($86,631) Management Fees $830,000 $830,000 $0 Capacity UCAP Obligated Purchased $10,100,192 $9,318,584 $781,608 Subtotal - Power Supply $59,316,505 $54,117,875 $5,198,630 Power Generation O&M & Fixed Fuel Plant O&M $4,387,976 $4,409,812 ($21,836) Subtotal Generation O&M $4,387,976 $4,409,812 ($21,836) Power Generation Production Margin Economic and reliability dispatch ($1,124,312) ($1,869,126) $744,814 Fixed Fuel and Transport Charges $586,004 $958,252 ($372,248) Subtotal Generation Production Margin ($538,308) ($910,873) $372,565 Power Generation Non-Production Revenue Generation Capacity Credit ($11,826,363) ($11,826,360) ($4) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($355,800) ($419,632) $63,832 Subtotal - Non-Production Revenue ($12,182,163) ($12,245,991) $63,828 SubTotal - All Generation ($8,332,495) ($8,747,052) $414,557 Total - Utilities Cost $50,984,010 $45,370,822 $5,613,187 Unit Costs Total - Power Supply $95.45 $86.45 $9.00 Total - Power Generation ($13.41) ($13.97) $0.56 Final Cost of Service to City of Dover Ratepayers $82.04 $72.48 $9.56 12

III. Operations Management NAES Corporation Dover, Delaware April 2013 Monthly Report New Valve Stations - Part of the Industrial Waste Water Project 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 April, there were no restricted work days or lost time accidents. The facility has now gone two years, six months and sixteen days (929 days) through April 30, 2013 without an OSHA Recordable Accident or a Lost Time Reportable Accident. The plant received no Notice of Violations (NOVs) during the month. The April (March Discharge) DMR was submitted for the McKee Run site with no NPDES exceedences. The new Title V Air Permits for the McKee Run and VanSant facilities were issued by DNREC and are now in effect for the next five year permit cycle. Mechanical work is essentially complete on the Industrial Wastewater Project with Electrical and Control System work remaining, followed by a system shake-down. Project completion is anticipated for June 2013. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (April) (7/1/12-4/30/13) 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 4,371.25 46,403 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 929 Days since last Lost Time Accident 929 15

Emissions (NOx & SO2) All data thru 4/30/13 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 0.0 0.0 0.0 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 0.1 0.0 0.0 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 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 1/0 – 0/0 0/0 - 0/0 70/46 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 16

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* *Note – Emissions allowances are deducted according to oldest vintage first or 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 15,032 514 124 15,422 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. 17

2.0 Financial Financial – Current Month Month – April Actual Budget Variance Personnel 353,989 243,603 (110,386) Materials & Supplies 4,666 18,040 13,374 Administrative Expenses 141,587 117,895 (23,692) Total $500,242 $379,538 ($120,704) Financial – Fiscal Year to Date Number of Months – 10 Actual Budget Variance Personnel 2,613,237 2,572,897 (40,340) Materials & Supplies 171,494 188,970 17,476 Administrative Expenses 1,625,080 1,626,109 1,029 Total $4,409,811 $4,387,976 ($21,835) 2.1 Variance analysis: The City of Dover Finance Department has closed the books for the month of April 2013. The expenses for April are $500,242 against a budgeted amount of $379,538 for an unfavorable variance of $120,704 or ≈ 31.80%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $110,386 was due to having three (3) payroll periods billed versus the two (2) that had been originally budgeted for April. Included in these costs are straight time labor, overtime labor, and labor burdens. MATERIALS AND SUPPLIES EXPENSES- A favorable monthly variance of $13,374 was due primarily to lower water costs and to the timing of the invoice for the computer server that has been ordered but not yet received. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $23,692 was due primarily to two (2) monthly electric usage invoices being booked in month of April instead of one as had been originally budgeted. The budget is currently forecasted to finish this fiscal year at $5,838,166 expensed versus an approved budget of $5,914,900 thereby realizing a 98.70% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips For the entire month of April, all units were in the spring outage. On April 29, plant staff tested Unit 3 boiler and turbine as a follow up on repairs/inspections performed on the equipment earlier in the outage. The unit was on line for approximately four and half hours during which the boiler and natural gas system along with the turbine generator were checked out. A problem was found with the B-1 natural gas valve which caused the boiler to trip a couple of times. A shorted wire was found to be the cause of the problem. The wire was repaired and the unit operated with no further incidences. Month April 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 4.533 4.533 0.0 4.533 Starts # 0 0 1 1 0 1 Gross Generation MWh 0.0 0.0 82.760 82.760 0.0 82.760 Net Generation MWh 0.0 0.0 68.211 68.211 0.0 68.211 Total Auxiliaries MWh 23.714 23.714 189.144 236.571 3.643 240.214 Auxiliaries purchased MWh 23.714 23.714 174.595 222.022 3.643 225.665 Fuel Gas Used MMBTU 0.0 0.0 1,608.122 1,608.122 0.0 1,608.122 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 1,608.122 1,608.122 0.0 1,608.122 Net Heat Rate BTU/KWh 0 0 23,576 23,576 0 23,576 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.09 0.09 0.0 0.09 Availability Factor % 0.00 0.00 0.00 0.00 0.00 0.00 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 720.000 720.000 720.000 2,160.000 720.000 2,880.000 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 0.0 0.0 0.0 0.0 0.0 0.0 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 - April 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 71.970 290.130 458.382 22.699 481.081 Starts # 3 2 27 32 5 37 Gross Generation MWh 668.79 582.202 18,880.248 20,131.240 714.904 20,846.144 Net Generation MWh 628.855 541.673 17,385.724 18,556.252 714.287 19,270.539 Total Auxiliaries MWh 319.058 319.651 3,183.902 3,822.611 35.031 3,917.642 Auxiliaries purchased MWh 279.123 279.123 1,689.378 2,247.624 34.500 2,282.124 Fuel Gas Used MMBTU 9,483 8,108 200,774.846 218365.846 8,532.592 226,898 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, 200,774.846 218365.846 8,644 226,898 Net Heat Rate BTU/KWh 15,021 14,970 11.967 13,986 12,604 13,629 Unit Trips # 0 0 1 1 0 1 Capacity Factor % 0.49 0.44 2.35 1.87 0.25 1.51 Availability Factor % 60.90 60.90 60.90 60.90 60.90 60.90 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 2,897 2,897 2,897 8,691 2,897 11,588 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 4,306.218 4,327.030 4,113.570 12,746.818 4,376.934 17,123.752 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) 448,556 450,319 0 1,763 454,725 0 (4,406) VanSant 143,857 144,827 0 970 152,150 0 (7,323) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through 4/30/13 Actual Starts Factored Starts Fired Hours VanSant 1307 2,236.25 4,218.86 Since HGP - Dec 2004 231 568.55 835.28 20

Team Report: The Operations staff has been removing insulation from the outside fuel line from the tank to the plant. They have been painting the lines as they remove the insulation. 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 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. 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 April, the Plant Maintenance staff continued addressing the backlog of work orders and completing outage activities. There were fifty-four work orders issued with ninety-one work orders being completed during the month. There was no safety work orders entered into the plant’s Computerized Maintenance Management System (MP2) during the month. The table below summarizes the monthly work order activities. Work Order Report April - 2013 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 21 3 14 10 2 41 11 16 36 3 46 3 9 40 4 6 0 0 6 5 17 0 0 17 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 93 37 52 78 Totals 224 54 91 187 Note: PMs are included in the priority totals Notable activities during the month include:  NAES Mechanical Maintenance Staff completed the flush on the Unit 3 Generator Bearings (#4 and #5 bearings) and oil system. There was no major debris found in the lube oil system  NAES IC&E staff completed the change out of the main gas stop valve on Unit 3. They made all necessary wiring changes and one relay was added for the Gas Fuel Trip Relay. This relay will be removed once logic changes have been made to the system. The valve was tested for proper operation and flow prior to and during the unit checkout.  Plant staff continued to support the work being performed on the Industrial Waste Water Project. All of the piping was tested at 40 psi with no leaks on the system. In addition, pumps have been tested for proper operation and heat trace wiring will be completed in the near future. 22

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 70%. Insulation is scheduled for May/June time period. EG1202 Systems Schedule: Tube repairs are complete and the ductwork has been repaired. Unit was operated and no more problems encountered. 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: Plant staff working with OEM to determine long lead Unit 3 Turbine material requirements. Schedule: Long lead items will be procured EG1212 Repairs in the spring of 2013. Some turbine parts (turbine 9th stage blading) have been ordered. Progress: FY2013 work scope in development stage. Units 1 & 2 EG1304 Schedule: Work on hold for present time. Replacement of K heater Components Repairs level controllers deferred to 2016 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 2016. Progress: The FY2013 work scope package being developed. Units 1&2 Stack Schedule: Work to be completed during the spring outage or EG1310 Repairs deferred until 2015. Inspection was completed in November and report is forthcoming so scoping documents may be developed. Progress: Valuation of the benefits of various technologies has been VanSant Capacity EG1311 completed and TEA is recommending implementation of the Wet Increase Compression Technology at an approximate cost of $1.5M. Plant 23

staff to develop cost schedule and COD Management to bring forward to COD Council for decision on the project. Schedule: COD Management Team to work on approval of project going forward. Progress: Contract work was awarded and vendor has completed Unit 3 Generator work. Unit has been tested for proper operation. Air leak test and oil EG1312 Repairs flush completed prior to start-up. Schedule: Operational check of the unit completed. Progress: Mechanical and electrical installation work has been started. Mechanical work is 95% complete and electrical work is MR Industrial Waste EG1214 50%. water System Schedule: Installation work slated for completion in May with testing of system to commence immediately thereafter. Unit 1 Gland Steam Progress: NA EG1301 Seal Repair Schedule: Work is complete. 24

6.0 General Plant Information  The XL Insurance Representative Neal Grabow submitted his final report/assessment of the plant to the City of Dover. He removed the requirement to install blast windows on the control room wall and added a requirement that the plant test plant transformers for corrosive sulfur in their oil.  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.  Plant staff is working to complete as many of the remaining outages tasks as possible prior to the end of the outage. Some of the work will be able to be completed when the units come out of the outage. Only a few minor tasks, if any, will need to be deferred until a later date. Training:  Jason Anker was successful in renewing his PJM Generation System Operator certificate for another three years.  Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Texting While Driving”.  On April 5, Brian Hoyt, Lance Berryhill, and Eric Carrow attended DOT/RCRA Hazardous Waste training sponsored by NEXEO Solutions. This training encompasses identification, characterization, storage, and handling of facility wastes in compliance with EPA and DOT regulations.  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.  Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. 25

Calendar of Events Date 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 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 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. 26

IV. Appendix – PJM Invoice Breakdown Gen Load Grand Total Auction Revenue Rights $ (1,081.20) $ (1,081.20) Balancing Operating Reserve $ 32,511.83 $ 32,511.83 Balancing Spot Market Energy $ 19,724.90 $ (195,746.19) $ (176,021.29) Balancing Transmission Congestion $ 69.11 $ (4,289.69) $ (4,220.58) Balancing Transmission Losses $ 355.13 $ 1,200.60 $ 1,555.73 Black Start Service $ (6,905.58) $ 1,915.48 $ (4,990.10) Capacity Resource Deficiency $ (494.40) $ (494.40) Capacity Transfer Rights $ (32,243.40) $ (32,243.40) Day-ahead Operating Reserve $ 4,604.98 $ 4,604.98 Day-ahead Scheduling Reserve $ 8.20 $ 8.20 Day-ahead Spot Market Energy $ (21,769.65) $ 686,046.04 $ 664,276.39 Day-ahead Transmission Congestion $ (286.95) $ (43,007.55) $ (43,294.50) Day-ahead Transmission Losses $ (426.45) $ 44,978.53 $ 44,552.08 Expansion Cost Recovery $ 427.50 $ 427.50 FERC Annual Recovery $ 3,115.16 $ 3,115.16 Generation Deactivation Refund $ (758.35) $ (758.35) Inadvertent Interchange $ (538.44) $ (538.44) Load Management Test Failure -193.500000 -193.500000 Load Reconciliation for Balancing Operating Reserve $ (16.19) $ (16.19) Load Reconciliation for FERC Annual Recovery $ (19.63) $ (19.63) Load Reconciliation for Inadvertent Interchange $ (0.22) $ (0.22) Load Reconciliation for Market Monitoring Unit (MMU) Funding $ (1.27) $ (1.27) Load Reconciliation for North American Electric Reliability Corporation (NERC) $ (3.30) $ (3.30) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $ (68.12) $ (68.12) Load Reconciliation for Reactive Services $ (317.16) $ (317.16) Load Reconciliation for Regulation and Frequency Response Service $ (72.83) $ (72.83) Load Reconciliation for Reliability First Corporation (RFC) $ (4.72) $ (4.72) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $ (8.80) $ (8.80) Load Reconciliation for Spot Market Energy $ (10,740.66) $ (10,740.66) Load Reconciliation for Synchronized Reserve $ (11.55) $ (11.55) Load Reconciliation for Transmission Congestion $ 414.27 $ 414.27 Load Reconciliation for Transmission Losses $ (593.66) $ (593.66) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $ (24.51) $ (24.51) Locational Reliability $ 953,123.40 $ 953,123.40 Market Monitoring Unit (MMU) Funding $ 204.31 $ 204.31 Meter Error Correction $ (2,940.64) $ (2,940.64) Network Integration Transmission Service $ 283,352.70 $ 283,352.70 Non-Firm Point-to-Point Transmission Service $ (293.25) $ (293.25) North American Electric Reliability Corporation (NERC) $ 523.55 $ 523.55 Organization of PJM States, Inc. (OPSI) Funding $ 36.13 $ 36.13 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $ 1,576.60 $ 1,576.60 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $ 918.30 $ 918.30 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $ 8,858.60 $ 8,858.60 PJM Scheduling, System Control and Dispatch Service - Market Support $ 2,008.98 $ 2,008.98 PJM Scheduling, System Control and Dispatch Service - Market Support Offset $ (277.83) $ (277.83) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $ 80.11 $ 80.11 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 $ (251.31) $ (251.31) PJM Scheduling, System Control and Dispatch Service Refund - Market Support $ (58.57) $ (58.57) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration $ (2.82) $ (2.82) PJM Settlement, Inc. $ 277.83 $ 277.83 Reactive Services $ 161,605.25 $ 161,605.25 Reactive Supply and Voltage Control from Generation and Other Sources Service $ (29,467.58) $ 33,216.52 $ 3,748.94 Regulation and Frequency Response Service $ 11,208.91 $ 11,208.91 Reliability First Corporation (RFC) $ 748.71 $ 748.71 RPM Auction $ (1,167,075.00) $ (1,167,075.00) Synchronized Reserve $ 5,250.35 $ 5,250.35 Transmission Enhancement $ 23,052.94 $ 23,052.94 Transmission Losses $ (17,974.56) $ (17,974.56) Transmission Owner Scheduling, System Control and Dispatch Service $ 3,890.02 $ 3,890.02 Balancing Operating Reserve for Load Response $ (168.70) $ (168.70) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $ (0.23) $ (0.23) Load Reconciliation for Day-ahead Scheduling Reserve $ (0.07) $ (0.07) Demand Resource and ILR Compliance Penalty -92.700000 -92.700000 Day-Ahead Load Response Charge Allocation $ 271.92 $ 271.92 Real-Time Load Response Charge Allocation $ 47.05 $ 47.05 Incremental Capacity Transfer Rights $ (995.10) $ (995.10) Michigan - Ontario Interface Phase Angle Regulators $ 182.03 $ 182.03 Non-Synchronized Reserve $ 378.45 $ 378.45 CT Lost Opportunity Cost Allocation $ (9.90) $ (9.90) Load Reconciliation for Non-Synchronized Reserve -0.290000 -0.290000 Grand Total $ (1,205,782.07) $ 1,952,710.54 $ 746,928.47 27