Anexo

UTILITY COMMITTEE AGENDA JANUARY 14, 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. Request for Alley Abandonment (paper) - 971 and 975 Forest Street 2. TEA/NAES Report (October) 3. Update - Garrison Oak Technical Park Project 4. Adjournment by 5:25 P.M. /tm S:\AGENDAS-MINUTES-PACKETS\Committee-Agendas\2013\01-14-2013 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: DEPARTMENT OF ORIGIN: Public Works DATE SUBMITTED: 1/9/2013 PREPARED BY: Sharon J. Duca, P.E., Public Works Director / City Engineer SUBJECT: Request for Alley Abandonment (paper) to 971 and 975 Forest Street REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager EXHIBITS: Attachment A – Map EXPENDITURE REQUIRED: $ N/A AMOUNT BUDGETED: $ N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIMETABLE: The references alley shall be abandoned upon approval by City Council. RECOMMENDED ACTION: Abandonment of the subject alley with conveyance to 971 and 975 Forest Street currently owned by Faithwork LLC. BACKGROUND AND ANALYSIS The City Clerk’s Office received a letter from Mr. Tolano D. Anderson, dated November 21, 2012, requesting that the unimproved alley located approximately 150 feet north of Forest Street from the intersection of Carver Road, be abandoned. Mr. Anderson states that the alley condition as well as an inability to safely utilize the space creates a significant hardship. Mr. Anderson also stated that he owns all real property abutting the alley and requests that the alley be conveyed to 971 and 975 Forest Street. Public Works staff has confirmed that the alley is unimproved. No public utility easements will be required. Records indicate that all abutting parcels are owned by Faithwork LLC. In light of the information provided the Department of Public Works has no objection to the abandonment of the subject alley and recommends conveyance of the same to the parcels represented by 971 and 975 Forest Street. Conveyance shall be in proportions complimentary to the existing lot widths of these parcels. It should be noted that 983 Forest Street appears to utilize the unimproved alley for access. As this parcel is also owned by Faithwork LLC, it is recommended that the owner establish cross access easements between 971, 975 and 983 Forest Street at the time of conveyance.

Alley Adjacent to 971 & 975 Forest Street Proposed Alley Abandonment 34 33 30 . ! . ! 65 27 20 21 × 951 Carver Rd 955 991 983 987 975 971 . ! × . ! ! . Forest St . ! 0 45 90 180 Feet ¯ Legend Date Printed: January 7, 2013 §Ò ! × Hydrants File: m:\gis_data\projects/tech_mxds Overhead Electric Pole . Manholes ! \st_abandonment_map Underground Electric Lines Sewer Line Department: Public Works GIS Overhead Electric Lines Right of Way to be Abandoned City of Dover, Delaware Water Main Dover Parcels Hydrant Line

The Energy Authority, Inc. Monthly Management Committee Update – October 2012 November 30, 2012 Prepared by: Jamie Mahne Vice President, Client Services 904.360.1374 jmahne@teainc.org

TABLE OF CONTENTS I. Executive Summary 1 II. Budget Report 11 III. Operations Management 14 IV. Appendix 27 i

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $630,604 under budget due to lower PJM fees for RT Energy. Dover’s budgeted cost for all power supply (capacity AND energy) was $91.98/MWh. The actual cost of all power supply (capacity AND energy) was $84.68/MWh. The cost of energy alone was $58.22/MWh, versus a budgeted energy cost of $67.85. The primary driver in the difference was the cost of unhedged energy. The city budgeted unhedged energy and PJM charges at $78/MWh. The actual cost of unhedged energy and PJM charges was $34/MWh – this decrease was due to lower PJM costs in the real time. Dover’s hedge purchases totaled 46,450MWh, which was 79% of the projected load and 82% of the actual load. Dover’s power purchases from hedge transactions totaled $2,897,450. Purchases from PJM (energy and fees) totaled $783,034, with DA Energy purchases totaling $583,266 and Balancing Spot Market Energy totaling a credit of $268,454. Dover’s total load was 56,736 MWh versus a forecasted load of 59,094 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1,250MWh. Dover’s actual energy purchase from the SunPark installation was 1,021 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 59,094 56,736 2,358 Wholesale Load 57,844 55,715 2,129 Hedged Volume (MWh) 46,450 46,450 - Unhedged Volume (MWh) 11,394 9,265 2,129 Dover SunPark Volume (MWh) 1,250 1,021 229 Renewable Energy Credits Volume 188 252 (65) Hedged Cost ($/MWh) $ 65 $ 62 0 Unhedged Energy Cost ($/MWh) $ 78 $ 34 $ 44 Solar Energy Cost ($/MWh) $ 83 $ 86 $ (3) Energy Costs ($/MWh) $67.85 $58.22 $9.62 All-in Costs - Energy, Capacity and RECs ($/MWh) $91.98 $84.68 $7.29 2

B. Generation Summary: Generation Revenue FY2012-13 $1,600,000 $1,400,000 $1,200,000 $1,000,000 $800,000 $600,000 $400,000 $200,000 $- Jul-12 Aug-12Sep-12 Oct-12 Nov- Dec-12 Jan-13 Feb-13 Mar- Apr-13 May- Jun-13 12 13 13 Budget Actual Dover did not generate any electricity in the month. Net generation revenue was $856,293 vs. a budget of $884,459. This delta was mainly due to higher than budgeted O&M costs. 3

Generation Breakdown: City of Dover's Wholesale Generation Net Generation Mwh 0.00 All In Generation Margin PJM Bill Energy $ - PJM Capacity $ 1,205,977.50 Black Start, Reactive Credit, DASR & EFORp $ 36,373.16 Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Margin $ 1,242,350.66 Production Margin Generation Production Revenues (PJM) $ - Gas Purchases $ - Oil Purchases $ - Transport / Cash Out $ - Gross Production Margin $ - $/Mwh All In Generation Margin $ - $/Mwh Generation Production Margin $ - 4

Fuel Purchases: There were no fuel purchases in the month. Transportation and Imbalance: There were no fuel transportation charges in the month. 5

C. Emissions Summary: Emissions Allowance Summary through October 31, 2012 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 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) 10/31/12 2012 Emissions2 (1) (37) (37) TOTAL ALLOWANCES 9,065 65 118 On August 21, 2012, the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s “Transport Rule” (aka Cross State Air Pollution Rule or CSAPR) which would have become effect on January 1, 2012. Additionally, DCA said EPA must continue administering the Clean Air Interstate Rule (CAIR), CSAPR’s predecessor, pending the issuance of a valid replacement rule. EPA submitted a petition for an en banc rehearing to the DCA on October 5, 2012 and is awaiting a ruling on the petition. Market liquidity for CAIR allowances continues to be low, with few transactions occurring. The following table shows estimated values as of November 30, 2012, based on broker bids & offers: 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. 6

Mark-to-Market for CAIR Allowances (9/24/2012) Commodity $/Ton Tons Extended Value SO2 Allowances $ 0.75 9,065 $ 6,799 NOx Allowances - Seasonal $27.50 65 1,787 NOx Allowances - Annual $40.00 118 4,720 TOTAL $13,306 Regional Greenhouse Gas Initiative The State of Delaware is a participant in the Regional Greenhouse Gas Initiative (RGGI). The City of Dover must comply with RGGI by surrendering carbon dioxide (CO2) allowances pursuant to the State of Delaware’s laws (Title 7, Chapter 60, Sub-Title II-A). Delaware has elected a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover has had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The cumulative balance of unused RGGI allowances held by Dover were 92,712 tons as of the end of Calendar year 2011, as shown in the table below. During the months of June - October, 2012, Dover’s generating units produced 15,265 tons of CO2 emissions, thus reducing the amount available in the allowance bank. CO2 Allowance Summary (10/31/2012) 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 3 2013 0 15,032 514 15,546 - 15,546 120,836 3 2013 allocations have not been added to Dover’s RGGI COATS account. These are listed for the purpose of showing the last expected allocation of RGGI allowances. 7

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. 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. RGGI auction and spot prices have remained in the $1.92 - $2.05/ton range. The most recent RGGI auction occurred on September 5, 2012 and the auction cleared at $1.93/ton. Based on this auction, the value of Dover’s existing RGGI allowance bank (104,505 tons) is approximately $201,695 (excluding allocations for 2013 which have not yet been allocated). RGGI’s next auction is scheduled for December 5, 2012. RGGI is currently conducting a program review pursuant to the original RGGI memorandum of understanding between participating states. As a result of these activities, coupled with declining allocations, TEA believes that there is a reasonable expectation that RGGI market prices could increase over the next few years. 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. 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 43 Solar Renewable Energy Certificates (SRECS). Additionally, Dover 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 September, 2012, Dover has accumulated a total of 3,566 SRECS from this contract. These SRECS have also been recorded in Dover’s GATS account. 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 8

auction was $40/MWh, resulting in a market value of $144,360 for Dover’s 3,609 SRECs. It should be noted, however, that the nearest viable market for Dover’s SRECs is Pennsylvania which has market price mid-point of $20, half of the price from the most recent Delaware auction price. TEA is recommending that Dover retain these allowances for compliance with its Renewable Portfolio Standard which we understand 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 October, there were no reportable or lost time accidents or injuries. The facility has now gone 748 days without an OSHA recordable accident and 748 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were no Near Miss incidents. All Units were in Planned outages during the month. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of October were $386,058. The actual expenses are $28,959 or 8.11% over the approved budget of $357,099. The principal reasons for the unfavorable variance were due to higher electric, water and chemical usage, contractual services, and home office support needed due to the Admin Manager vacancy. 9

E. Risk Management Summary: Forward power prices in PJM have risen slightly since last month resulting in a higher blended cost. The current projected cost of service is below: Power Year Hedge Ratio Blended Cost ($/MWh) 2012-13 80% $61.56 2013-14 46% $52.00 2014-15 27% $48.32 2015-16 14% $47.63 10

II. Budget Report Variance Report: Budget Actual Variance Oct-12 Oct-12 Gross Load Forecast 59,094 56,736 2,358 Power Supply Hedged Energy $3,013,494 $2,897,450 $116,044 PJM- Energy $883,650 $314,812 $568,838 PJM - Transmission and Fees $313,000 $468,221 ($155,221) Dover SUN Park Energy $112,094 $90,971 $21,123 Management Fees $83,000 $83,000 $0 Capacity UCAP Obligated Purchased $1,029,954 $950,133 $79,821 Subtotal - Power Supply $5,435,192 $4,804,587 $630,604 Power Generation O&M & Fixed Fuel Plant O&M $357,099 $386,058 ($28,959) Subtotal Generation O&M $357,099 $386,058 ($28,959) Power Generation Production Margin Economic and reliability dispatch $0 $0 $0 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation Production Margin $0 $0 $0 Power Generation Non-Production Revenue Generation Capacity Credit ($1,205,978) ($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 ($884,459) ($856,293) ($28,166) Total - Utilities Cost $4,550,733 $3,948,295 $602,438 Unit Costs Total - Power Supply $91.98 $84.68 $7.29 Total - Power Generation ($14.97) ($15.09) $0.13 Final Cost of Service to City of Dover Ratepayers $77.01 $69.59 $7.42 11

Variance Analysis: Power Supply  Dover consumed 2,358 MWh more than what was forecasted for the month.  PJM costs were lower than expected, but PJM’s fees were higher than forecast. The net result was a net power supply cost of $84.68/MWh, $7.29/MWh lower than budget.  For the month, the city realized a favorable variance of $630,604 for power supply vs. the monthly budget.  Dover Sun Park generated 228 MWh less than what was forecasted. Generation  Power generation had an unfavorable budget variance of $28,166.  Plant O&M expenses had an unfavorable budget variance of $28,959 for the month. 12

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load Forecast 272,123 280,196 (8,073) Power Supply Hedged Energy $14,718,667 $14,231,102 $487,565 PJM- Energy $5,229,658 $2,174,061 $3,055,597 PJM - Transmission and Fees $1,252,000 $2,642,628 ($1,390,628) Dover SUN Park Energy $575,127 $594,880 ($19,753) Management Fees $332,000 $332,000 $0 Capacity UCAP Obligated Purchased $4,086,591 $3,769,839 $316,752 Subtotal - Power Supply $26,194,043 $23,744,511 $2,449,532 Power Generation O&M & Fixed Fuel Plant O&M $1,898,613 $1,864,068 $34,545 Subtotal Generation O&M $1,898,613 $1,864,068 $34,545 Power Generation Production Margin Economic and reliability dispatch ($1,124,312) ($1,864,289) $739,977 Fixed Fuel and Transport Charges $586,004 $942,183 ($356,179) Subtotal Generation Production Margin ($538,308) ($922,106) $383,798 Power Generation Non-Production Revenue Generation Capacity Credit ($4,785,009) ($4,785,007) ($2) Emissions Allowance Sales $0 $0 $0 Black Start & Reactive Power Revenue ($142,320) ($201,393) $59,073 Subtotal - Non-Production Revenue ($4,927,329) ($4,986,400) $59,071 SubTotal - All Generation ($3,567,024) ($4,044,437) $477,413 Total - Utilities Cost $22,627,019 $19,700,074 $2,926,945 Unit Costs Total - Power Supply $96.02 $86.53 $9.49 Total - Power Generation ($13.30) ($14.41) $1.11 Final Cost of Service to City of Dover Ratepayers $82.72 $72.12 $10.60 13

III. Operations Management NAES Corporation Dover, Delaware October 2012 Monthly Report Operator II, Mike Shane, is congratulated by Plant Manager, Vince Scire, for successfully achieving his PJM Gen Ops System Certification. 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 October, there were no restricted work days or lost time accidents. The facility has now gone two years and eighteen days (748 days total) through October 31, 2012 without an OSHA Recordable Accident or a Lost Time reportable accident. The September DMR was submitted for the McKee Run site with no NPDES exceedences. The plant received no Notice of Violations (NOVs) during the month. Work continues on the IWDP (wastewater) permit with Kent County. Quotes for Mechanical work have been requested and will be evaluated once received with contract award to follow thereafter. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (October) (7/1/12-9/30/12) 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 4,545.75 17,152.75 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 748 Days since last Lost Time Accident 748 Emissions (NOx & SO2) All data thru 10/31/12 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 31.4 1.4 36.1 2012 1.2 1.0 35.8 1.0 33.1 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 88.7 3.3 94.7 2011 1.8 1.5 32.6 2.9 38.8 16

SO2 Allowances Summary SO2 Allowances Available Total SO2 2012 1.2SO2 1.0 Unit, Prior (Per 35.8 to Sale & 1.0 Tons Emitted36.8 SO2 SO2 Allowance Allowances Reconciliation) SO2 Summary - Year (Jan-Dec) Tons – Allowances Vintage Year Sold - Unit #1YTD Unit #2 Unit #3 UnitU3 #11and U11TOTAL Balance Unit #3 Unit #11 YTD 2009 0.05 0.05 0.1 0.2 0.4 2010 and earlier 0 4815 276 0 5089 20112010 0.0 0 0.01850 0.3 138 0.0 1 0.3 1988* 20122011 0.0 0 0.01850 0.1 138 0.5 1 0.6 1988* *Note – Emissions 2012 allowances 0.0are deducted0.0 according to 0.0 oldest vintage0.1 first or unless0.1 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 0 15,546 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 1 29/30 0/2 earlier 2011 0 77#/48# 5/3 33/31– 3/1 0/0 - 0/0 44#/17# 2/2 2012 0 75/48 5/3 36/36 – 1/1 0/0 - 0/0 39/12 4/2 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. 17

2.0 Financial Financial – Current Month Month – October Actual Budget Variance Personnel 231,087 239,870 8,783 Materials & Supplies 26,429 7,557 (18,872) Administrative Expenses 128,542 109,672 (18,870) Total $386,058 $357,099 ($28,959) Financial – Fiscal Year to Date Number of Months – 4 Actual Budget Variance Personnel 921,631 966,946 45,315 Materials & Supplies 111,132 122,128 10,996 Administrative Expenses 831,305 809,539 (21,766) Total 1,864,068 1,898,613 $34,545 2.1 Variance analysis: The City of Dover Finance Department has closed the books for the month of October. The expenses for October are $386,058 against a budgeted amount of $357,099 for an unfavorable variance of $28,959 or ≈ 8.11%. The variance was due to the following: PERSONNEL EXPENSES – A favorable monthly variance of $8,783 was to due to having vacant positions and lower overtime costs due to lack of unit operation in October due to the units being in outage. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $18,872 was due to higher than budgeted Water-Sewer and Water Treatment Chemicals expenses caused by higher than budgeted unit operations in September. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $18,870 was due to higher Electricity, Contractual Services, and Home Office Labor expenses than budgeted. Expenses in Contractual Services increased due to a reclassification of expenses for the Unit #3 DCS Computer and Software annual maintenance agreement. These costs were originally included in CIP EG1204. Home Office Labor costs were higher than budgeted due primarily to increased corporate HR support of the vacant positions and corporate safety support to conduct an onsite audit of the plant’s safety programs. The budget is currently forecasted to finish this fiscal year at $5,899,313 expensed versus a budget of $5,914,900 thereby realizing a 99.57% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips On October 1, 2012 at 0700 hours, all four of the City of Dover units went into a planned fall outage. A number of maintenance activities were planned some of which have already been completed (see maintenance section) and some that will require Operations support. Month October 2012 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 6 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 21.729 21.729 118.987 162.445 2.687 165.132 Auxiliaries purchased MWh 21.729 21.729 118.987 162.445 2.687 165.132 Fuel Gas Used MMBTU 0.0 0.0 32,135.709 32,135.709 0.0 32,135.709 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 32,135.709 32,135.709 0.0 32,135.709 Net Heat Rate BTU/KWh 0.0 0.0 11,826 11,826 0.0 11,826 Unit Trips # 0 0 1 1 0 1 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 0.94 0.94 0.94 0.94 0.94 0.94 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 737.000 737.000 737.000 2,211.000 737.000 2,948.000 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 7.00 7.00 7.00 21.000 7.00 28.000 Hours HW Boiler Gas Usage MMBTU 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

2011-2012 Fiscal Year-to-Date October 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 92.782 71.970 285.597 450.349 22.066 472.415 Starts # 2 2 26 30 4 34 Gross Generation MWh 643.317 582.202 18,797.488 20,023.007 714.818 20,737.825 Net Generation MWh 604.005 541.673 17,317.513 18,463.191 714.287 19,177.478 Total Auxiliaries MWh 146.202 147.419 2,337.717 2,631.338 6.681 2,638.019 Auxiliaries purchased MWh 106.89 106.89 857.742 1,072.522 6.15 1,077.672 Fuel Gas Used MMBTU 9,072.980 8,108.898 199,166.724 216,348.602 8,429.434 224,778.036 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 9,072.980 8,108.898 199,166.724 216,348.602 8,542.001 224,890.603 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 % 0.40 0.36 2.35 1.86 0.28 1.67 Availability Factor % 74.85 74.85 74.85 74.85 75.94 75.12 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 737 737 737 2211 737 2948 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 2,122.218 2,143.030 1,929.570 6,194.818 2,192.934 8,387.752 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 784 898.663 1,682.663 1,682.663 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) 455,169 454,725 0 (444) 454,725 0 444 VanSant 146,301 145,711 0 (590) 152,150 0 (6,439) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 20

VanSant Lifetime through 10/31//12 Actual Starts Factored Starts Fired Hours VanSant 1303 2230.45 4215.86 Since HGP - Dec 2004 229 566.05 832.28 Capacity Testing – FY 2012-2013 Summer 2012 (June 1- Aug 31) Winter 2012-2013 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.0 1 17 * 2 17 17.3 2 17 * 3 102 102.7 3 102 * VanSant 39 39.0 11 39 * Total 175 176.0 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program Team Report: Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both Operations and Maintenance areas to help in maintaining the plant. 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 and score a minimum 80% on a quiz before they can complete the SMP. 21

4.0 Maintenance During the month of October, the Plant Maintenance staff continued addressing the backlog of work orders and completing outage activities. There were thirty-eight work orders issued with seventy-nine 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 October - 2012 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 15 3 7 11 2 33 7 11 29 3 51 2 8 45 4 5 0 0 5 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 65 26 52 39 Totals 184 38 79 143 Note: PMs are included in the priority totals Notable activities during the month include: 1) The NAES Mechanical and IC&E staff started outage related work activities that will aid in critical unit equipment to safe and reliable condition also maintaining unit availability in the most cost effective manner. All work performed in accordance with safe work practices and without impact to the environment. 2) XL Insurance Boiler Inspector, Mr. Charles Newman, was on site to inspect all three units at McKee Run Generating Station. There were no issues to report concerning Units 2 and 3. One minor concern occurred with Unit 1 regarding a small amount of surface rust found in the steam drum. Plant staff is taking proactive measures to eliminate this occurrence in the future by making slight improvements to the unit’s layup procedure. 3) Siemens Engineering Represetative, Mr. Dave Doneti, was onsite to assist with correcting the problem on the Unit 2 overspeed trip mechanism. In the discovery portion of the job, it was determined that the overspeed pin would not hit the trip arm. Siemens Engineering recommended milling down the flange face of the overspeed trip mechanism housing to achieve the proper clearance for the trip 22

arm. Machine work was completed at an offsite vendor shop and the overspeed trip mechanism was reassembled and tested for proper operation. Testing could be achieved with the unit not running and was found to be in correct working order. Start up of the unit and final testing of the overspeed trip will be completed when the unit is available for start up after all outage work has been completed.  Maintenance staff investigated mechanical concerns with 3B FD fan inboard bearing overheating. Staff disassembled the coupling and bearing to inspect the condition of both. This inspection revealed that the bearing and the coupling had excessive wear. A new bearing was requisitioned from the warehouse and is being installed, in accordance with the manufacture specification. Local manufactures representative has been contacted and is working on getting the price, along with availability of the new coupling. New coupling has been placed on order and will be installed when received. 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. Bid Unit #3 Boiler document being developed. Completion at 5%. EG1202 Systems Schedule: Bids to be obtained in 2nd quarter of 2012 and work to be completed in the spring 2013 outage. Progress: The FY2013 work scope package being developed. Unit 3 Auxiliary Schedule: Some work is being performed on the Unit 3 Condenser EG1203 System Components Drains and other work is scheduled to be complete in the spring outage. Progress: Long lead material requirements being developed for bid. Work scope and specifications for generator work being finalized Unit 3 Turbine EG1212 and should be sent out in early to mid November. Repairs Schedule: Long lead items were identified in the 2nd quarter and will be purchased in the 3rd and 4th quarters. 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: The FY2013 work scope package being developed EG1306 Window Schedule: Work to be completed during the 2ndquarter of 2013. modification Progress: Material has been purchased and delivered to the site at the beginning of the outage. Contract has been awarded for both Unit 3 Air Heater EG1112 expansion joint replacement and for Unit 3 Condenser Drain Tree Expansion Joint replacement. Schedule: The work is schedule to be completed in November. 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 2nd quarter. Schedule: The scoping of work should be completed in the 3rd quarter with bids and revised installation costs identified. Actual repair work will be scheduled for 2014. Progress: The FY2013 work scope package being developed. Units 1&2 Stack EG1310 Schedule: Work to be completed during the spring outage or Repairs deferred until 2014. VanSant Capacity Progress: Valuation of the benefits of various technologies is EG1311 underway. Final decision on moving forward with the project has Increase 24

still not been made. Schedule: Installation was scheduled for the 4th quarter but is dependent on favorable decision to move forward. At present time, this cannot expect to be completed until late 2013, at the earliest. Progress: Parts identification has started and installation bid package Unit 3 Generator EG1312 being developed. Expect to issue bids in the 2nd quarter. Repairs Schedule: Installation work to be completed in the 4th quarter. Progress: Mechanical design is complete and electrical design is approximately 95% complete and under review by plant staff. MR Industrial Waste EG1214 Quotes for Mechanical materials sent out to qualified bidders. water System Schedule: Installation work planned for the 2nd and 3rd quarter of FY. Progress: Work has begun on inspection and repair of seal and Unit 1 Gland Steam bearing. Work is expected to be completed by mid-November with EG1301 Seal Repair a system check of the unit to occur immediately afterwards. Schedule: Installation work planned for the fall outage. 6.0 General Plant Information With the passing of Mr. Phil Kosek in September, the plant is actively recruiting to fill his vacant position as the Administrative Manager for the plant. In this effort, NAES Corporate staff has been supplying substantial support in both helping to fill the vacant position but also to perform and provide direction with the completion of many of the tasks that Mr. Kosek had performed at the plant. The plant has brought on Patricia Braun as a temporary Administrative Assistant to help with administrative functions. Brian Hoyt, Compliance Specialist, assumed the duties of maintaining the Safety Program. His title was changed to Compliance Manager at this time as well. Training: Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Winter Slip Protection” which provided important information on how to avoid injuries that typically might occur during the wintery season. 25

Calendar of Events Date Units 1, 2, 3 and 11 Fall Outage October 1, 2012 – December 3, 2012 Two Year Accident Free October 14, 2012 Winter Capacity Period December 1, 2012 to February 28, 2013 McKee Run and VanSant Title V Annual Certification Due February 1, 2013 Annual VanSant Black Start Test TBD EIA-860 Report February 28, 2013 EIA-923 Report February 28, 2013 NOx Emissions Reconciliation Due March 1, 2013 SO2 Emissions Reconciliation Due March 1, 2013 SARA III Report March 1, 2013 NPDES Permit Renewal Due March 4, 2013 Units 1, 2, and 3 Spring Outage March , 2013 – June 1, 2013 Unit 11 Spring Outage March , 2013 – June 1, 2013 Air Emission Inventory June 30, 2012 NOx Ozone Season Starts May 1, 2013 PJM Summer Capacity Test Period June 1, 2013 – August 31, 2013 Toxic Release Inventory (TRI) Annual Report July 1, 2013 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2013 DRBC Study Due September 15, 2013 NOx Ozone Season Ends September 30, 2013 26

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 Yes* Yes Yes* $3,455* $3,455 Unit 2 No Yes* Yes Yes* $3,455* $3,455 Unit 3 No Yes* Yes Yes* $20,520* $20,520 Unit 11 No Yes* Yes Yes* $6,840* $6,840 Total YTD 100.00% Total YTD Incentive $161,224 $161,224 Incentive % Note: Units 1 and 2 PJM Summer Capacity Tests have been successfully completed and would be entered 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 $ 19,156.25 $ 19,156.25 Balancing Spot Market Energy $ (268,454.24) $ (268,454.24) Balancing Transmission Congestion $ (2,980.89) $ (2,980.89) Balancing Transmission Losses $ (255.24) $ (255.24) Black Start Service $ (6,905.58) $ 2,004.39 $ (4,901.19) Capacity Resource Deficiency $ (246.15) $ (246.15) Capacity Transfer Rights $ (33,318.18) $ (33,318.18) Day-ahead Operating Reserve $ 20,354.33 $ 20,354.33 Day-ahead Scheduling Reserve $ 5.98 $ 5.98 Day-ahead Spot Market Energy $ 583,266.65 $ 583,266.65 Day-ahead Transmission Congestion $ (6,569.08) $ (6,569.08) Day-ahead Transmission Losses $ 53,676.59 $ 53,676.59 Expansion Cost Recovery $ 413.85 $ 413.85 FERC Annual Recovery $ 3,905.66 $ 3,905.66 Generation Deactivation Refund $ (744.31) $ (744.31) Inadvertent Interchange $ 297.30 $ 297.30 Load Reconciliation for Balancing Operating Reserve $ (8.14) $ (8.14) Load Reconciliation for FERC Annual $ (15.42) $ (15.42) Load Reconciliation for Inadvertent $ (1.19) $ (1.19) Load Reconciliation for Market Monitoring Unit (MMU) Funding $ (1.01) $ (1.01) Load Reconciliation for North American Electric Reliability Corporation (NERC) $ (2.42) $ (2.42) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $ (46.23) $ (46.23) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service $ 2.06 $ 2.06 Load Reconciliation for Reactive Services $ (157.80) $ (157.80) Load Reconciliation for Regulation and Frequency Response Service $ (53.25) $ (53.25) Load Reconciliation for Reliability First Corporation (RFC) $ (3.02) $ (3.02) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center $ (5.96) $ (5.96) Load Reconciliation for Spot Market $ (8,258.16) $ (8,258.16) Load Reconciliation for Synchronized $ (11.91) $ (11.91) Load Reconciliation for Transmission Congestion $ (578.22) $ (578.22) Load Reconciliation for Transmission $ (473.72) $ (473.72) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service $ (16.63) $ (16.63) 28

Locational Reliability $ 984,734.28 $ 984,734.28 Market Monitoring Unit (MMU) Funding $ 258.47 $ 258.47 Meter Error Correction $ (3,228.30) $ (3,228.30) Network Integration Transmission Service $ 295,467.82 $ 295,467.82 Non-Firm Point-to-Point Transmission $ (357.03) $ (357.03) North American Electric Reliability Corporation (NERC) $ 612.19 $ 612.19 Organization of PJM States, Inc. (OPSI) Funding $ 39.10 $ 39.10 PJM Scheduling, System Control and Dispatch Service - Advanced Second $ 1,236.75 $ 1,236.75 PJM Scheduling, System Control and Dispatch Service - Capacity $ 948.91 $ 948.91 PJM Scheduling, System Control and Dispatch Service - Control Area $ 9,591.21 $ 9,591.21 PJM Scheduling, System Control and Dispatch Service - Market Support $ 2,169.85 $ 2,169.85 PJM Scheduling, System Control and Dispatch Service - Market Support Offset $ (317.44) $ (317.44) PJM Scheduling, System Control and Dispatch Service - Regulation Market $ 100.94 $ 100.94 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. $ (169.39) $ (169.39) PJM Scheduling, System Control and Dispatch Service Refund - Control Area $ (1,676.68) $ (1,676.68) PJM Scheduling, System Control and Dispatch Service Refund - Market Support $ (384.22) $ (384.22) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration $ (19.77) $ (19.77) PJM Settlement, Inc. $ 317.44 $ 317.44 Reactive Services $ 19,370.33 $ 19,370.33 Reactive Supply and Voltage Control from Generation and Other Sources Service $ (29,467.58) $ 32,254.77 $ 2,787.19 Regulation and Frequency Response $ 21,770.69 $ 21,770.69 Reliability First Corporation (RFC) $ 765.25 $ 765.25 29

RPM Auction $ (1,205,977.50) $ (1,205,977.50) Synchronized Reserve $ 8,135.66 $ 8,135.66 Synchronous Condensing $ 207.93 $ 207.93 Transmission Enhancement $ 18,945.11 $ 18,945.11 Transmission Losses $ (23,241.03) $ (23,241.03) Transmission Owner Scheduling, System Control and Dispatch Service $ 4,211.76 $ 4,211.76 Balancing Operating Reserve for Load $ (24.72) $ (24.72) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding $ (0.15) $ (0.15) Load Reconciliation for Day-ahead Scheduling Reserve $ (4.76) $ (4.76) Emergency Load Response $ 1,365.09 $ 1,365.09 Demand Resource and ILR Compliance $ (472.77) $ (472.77) Day-Ahead Load Response Charge $ 683.21 $ 683.21 Real-Time Load Response Charge $ 721.12 $ 721.12 Incremental Capacity Transfer Rights $ (1,036.95) $ (1,036.95) Michigan - Ontario Interface Phase Angle Regulators $ 194.25 $ 194.25 Non-Synchronized Reserve $ 232.94 $ 232.94 Grand Total $ (1,242,350.66) $ 1,733,166.51 $ 490,815.85 30