Anexo

UTILITY COMMITTEE AGENDA JANUARY 12, 2015 - 5:15 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. DEDICATION OF RIGHTS-OF-WAY AND PUBLIC INFRASTRUCTURE - EDEN HILL PHASE 1 (ACCEPTANCE OF RIGHTS-OF-WAY AND PUBLIC INFRASTRUCTURE IN THE EDEN HILL, PHASE I SUBDIVISION. DEDICATION IS TO INCLUDE ALL OF THE REFERENCED PUBLIC IMPROVEMENTS.) 2. TEA/NAES REPORTS (SEPTEMBER, OCTOBER, AND NOVEMBER) (STAFF RECOMMENDS ACCEPTANCE OF THE REPORTS) 3. UPDATES (COMMITTEE ACTION NOT REQUIRED ON THE BELOW ITEMS) A. GREEN ENERGY FUNDING AND PROGRAMMING B. NATIONAL POLLUTION DISCHARGE ELIMINATION SYSTEM (NPDES) MUNICIPAL SEPARATE STORM SEWER SYSTEMS (MS4) PERMIT C. GARRISON OAK TECHNICAL PARK PROJECT UPDATES C-1. CITY INFRASTRUCTURE C-2. CALPINE ENERGY CENTER C-3. DOVER SUN PARK 4. ADJOURNMENT BY 5:55 P.M. /TM S:\AGENDAS-MINUTES-PACKETS-PRESENTATIONS-ATT&EXH\COMMITTEE-AGENDAS\2015\01-12-2015 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: 12/29/14 PREPARED BY: Sharon J. Duca, P.E., Public Works Director / City Engineer SUBJECT: Dedication of Rights-of-Way and Public Infrastructure – Eden Hill Phase I REFERENCE: N/A RELATED PROJECT: N/A APPROVALS: City Manager EXHIBITS: Attachment A – List of Public Improvements to be accepted by the City of Dover Attachment B – Map EXPENDITURE REQUIRED: $ N/A AMOUNT BUDGETED: $ N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIME TIMETABLE: All infrastructure improvements will become the responsibility of the City of Dover upon acceptance by City Council. RECOMMENDED ACTION: Acceptance of rights-of-way and public infrastructure in the Eden Hill, Phase I Subdivision. Dedication is to include all of the referenced public improvements. BACKGROUND AND ANALYSIS Pettinaro Construction Company, Inc., responsible party for completing the public infrastructure within the Eden Hill, Phase I development, has requested that all public infrastructure improvements be dedicated to the City of Dover for permanent ownership and maintenance. Attachment A outlines all of the public improvements associated with this phase of the development. The total construction value of the public improvements is $1,734,706. Attachment B shows the general location and configuration of the subject rights-of-way. The Pettinaro Construction Company has completed construction of the improvements in accordance with City standards and specifications. After construction was completed, City staff inspected the public improvements and developed a list of repairs to be made to meet the City of Dover Standards and Specifications for Public Works Construction. As of this date, all work required by the Public Works Director has been completed. A one (1) year Maintenance Agreement and a Release of Liabilities will be submitted as part of the dedication process. Required as-built drawings of the infrastructure as well as videos of the sanitary sewer mains have been provided to staff.

DEDICATION OF RIGHTS-OF-WAY AND PUBLIC INFRASTURCTURE EDEN HILL PHASE I ATTACHMENT A The following is a list of all public improvements which are to be accepted by the City of Dover: Sewer Utility Infrastructure (Construction Value = $393,180): 8” SDR-35 PVC Sanitary Sewer Main - 9,546 l.f. 6” SDR-35 PVC Sanitary Sewer Laterals - 1,760 l.f. (83 laterals) 4' Diameter Sanitary Sewer Manholes - 12 ea. (70.14 v.f.) Water Utility Infrastructure (Construction Value = $161,820): 10” Ductile Iron (Class 52 Cement Lined) Water Main - 4,550 l.f. 8” Ductile Iron (Class 52 Cement Lined) Water Main - 2,680 l.f. 6” Ductile Iron (Class 52 Cement Lined) Water Main - 121 l.f. 1” Polyethylene Water Service Lines - 1,760 l.f. (83 services) 10” Gate Valve - 19 ea. 8” Gate Valve - 14 ea. 6” Hydrant Valve - 4 ea. Fire Hydrants - 4 ea. Storm Water Infrastructure (Construction Value = $347,200 ): Catch Basins - 84 ea. 4’ Diameter Storm Water Manholes - 5 ea. 15” Type III Reinforced Concrete Pipe - 2,800 l.f. 18” Type III Reinforced Concrete Pipe - 1,605 l.f. 21” Type III Reinforced Concrete Pipe - 132 l.f. 24” Type III Reinforced Concrete Pipe - 601 l.f. 30” Type III Reinforced Concrete Pipe - 646 l.f. 36” Type III Reinforced Concrete Pipe - 165 l.f. 42” Type III Reinforced Concrete Pipe - 185 l.f. 48” Type III Reinforced Concrete Pipe - 2,156 l.f. 19” x 30” Type III Reinforced Concrete Elliptical Pipe - 283 l.f. 38” x 60” Type III Reinforced Concrete Elliptical Pipe - 311 l.f. Flared End Sections (Concrete) - 3 ea.

Street Infrastructure (1.318 miles) (Construction Value = $832,506 ): Wemyss Road Station 0+49 to Station 6+64 615 l.f. Lloyd Street Station 0+00 to Station 9+42 942 l.f. South Greenberry Lane Station 0+00 to Station 7+40 740 l.f. Ann Moore Street Station 0+00 to Station 8+00 800 l.f. Ridgely Boulevard Station 2+50 to Station 12+00 950 l.f. Ruth Way Station 0+00 to Station 6+00 600 l.f. Alley A Station 0+00 to Station 5+00 500 l.f. Alley B Station 0+00 to Station 3+90 390 l.f. Alley C Station 0+00 to Station 2+23 223 l.f. Alley D Station 0+00 to Station 2+96 296 l.f. Alley G Station 2+00 to Station 3+96 196 l.f. Alley H Station 0+00 to Station 3+90 390 l.f. Alley I Station 0+00 to Station 3+90 390 l.f.

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The Energy Authority, Inc. Monthly Management Committee Update – September 2014 October 23, 2014 Prepared by: Robert Trinnear Client Services Manager 904.360.1309 rtrinnear@teainc.org

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

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $304,262 under budget driven by lower prices and lower PJM fees. Dover’s budgeted cost for all power supply (capacity AND energy) was $70.63/MWh. The actual cost of all power supply (capacity AND energy) was $65.78/MWh. The cost of energy alone was $44.44/MWh, versus a budgeted energy cost of $46.79. Dover’s hedge purchases totaled 52,080 MWh, which was 81% of the actual load. The budgeted hedge purchase totaled 38,352, which was 60% of the budgeted load. Dover’s power purchases from hedge transactions totaled $2,398,418. Purchases from PJM (energy and fees) totaled $720,904. This number includes DA spot market energy charges of $572,474 and Reactive Service charges of $580. Dover’s total load was 64,099 MWh versus a forecasted load of 64,001 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1,224 MWh. Dover’s actual energy purchase from the SunPark installation was 1,603 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 64,001 64,099 (98) Wholesale Load 62,777 62,496 281 Hedged Volume (MWh) 38,352 52,080 (13,728) Unhedged Volume (MWh) 24,425 10,416 14,009 Dover SunPark Volume (MWh) 1,224 1,603 (379) Renewable Energy Credits Volume 184 301 (117) Hedged Cost ($/MWh) $ 49.23 $ 46.05 $ 3.17 Unhedged Energy Cost ($/MWh) $ 39.54 $ 25.40 $ 14.14 Solar Energy Cost ($/MWh) $ 115.11 $ 115.97 $ (0.86) Energy Costs ($/MWh) $46.79 $44.44 $2.35 All-in Costs - Energy, Capacity and RECs ($/MWh) $70.63 $65.78 $4.86 2

B. Generation Summary: Dover generated 4,344 MWh in the month. Net generation revenue was $503,821 vs. a budget of $378,745. 3

Generation Breakdown: City of Dover Monthly Wholesale Generation September, 2014 Net Generation 4344.42 All In Generation PJM - Generation Economic and Reliability Dispatch $ 379,805.13 Generation Capacity Credit $ 702,347.40 Black Start and Transmission Losses $ 54,200.90 Natural Gas & Oil Consumption Purchases for Generation $ (163,215.00) Natural Gas Transport $ (30,436.09) Eastern Shore Cashout $ 1,193.30 Oil Consumption $ - Production Margin PJM - Generation Economic and Reliability Dispatch $ 379,805.13 Natural Gas & Oil Consumption Purchases for Generation $ (163,215.00) Natural Gas Transport $ (30,436.09) Eastern Shore Cashout $ 1,193.30 Oil Consumption $ - Gross Production Margin $ 187,347.34 $/MWh Generation Production Gross Margin $ 43.12 4

C. Emissions Summary: Emissions Allowance Summary through September 30, 2014 McKee Run3 and VanSant Unit 11 (Dover’s two units covered by the Clean Air Interstate Rule or CAIR) operated during the month of August, so there were additional emissions during this period. CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowances Seasonal Annual 1/1/09 2008 Carryover 3,240 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 2,039 50 78 1/1/11 2011 Allocation 1,988 49 78 4/1/11 2011 Reallocation 2 4 1/11/12 2012 Allocation 1,988 51 80 10/4/2012 2013 Allocation 1,988 49 76 2014 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 11/15/13 NOx Annual Sales (DEMEC) (5) 12/31/13 2013 Emissions (0) (20) (20) 8/31/14 2014 CYTD Emissions (1) (36) (44) REMAINING ALLOWANCES 13,040 99 201 On August 21, 2012, a three-judge panel of the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s Cross State Air Pollution Rule (CSAPR) which would have become effective on January 1, 2012. The DCA instructed EPA to continue 1 Per CAIR, starting in 2009, NOx emissions are governed by a seasonal and annual program. 2 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 5

administering the Clean Air Interstate Rule (CAIR). EPA appealed the DCA ruling to the U.S. Supreme Court, which heard arguments on December 10th, 2013. On April 29th, 2014, the U.S. Supreme Court overturned the DCA opinion; however it did not immediately reinstate CSAPR. It sent the rule back to the DCA for further action consistent with the Supreme Court’s opinion. On June 26th, 2014, EPA requested the DCA to reinstate CSAPR, with Phase 1 compliance deadlines being changed by 3 years to 2015 and 2016, and Phase 2 compliance deadlines being changed to 2017. EPA is preparing “ministerial” revisions to CSPAR so that it conforms to certain issues raised by the DCA in its 2012 action. To date, the DCA has not acted on EPA’s motion to lift the DCA’s stay from 2012. While Delaware is included in the CAIR footprint, it is not included in the CSAPR footprint. CAIR allowances cannot be used for CSAPR compliance, so Dover’s CAIR allowances will become valueless when CSAPR is reinstated. The separate Clean Air Act acid rain deposition control program will remain in effect, however the CAIR provisions for SO2 will also disappear for Delaware. 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 settlement prices on the Intercontinental Exchange (ICE). Mark Value for CAIR Allowances Commodity $/Ton Tons Market Value ICE Settlement as of Oct. 17th, 2014 SO2 Allowances (2009 & earlier) $ 1.35 5,089 $ 6,870 SO2 Allowances (2010-14) $ 0.85 7,951 6,758 NOx Allowances - Seasonal $25.00 99 2,475 NOx Allowances - Annual $50.003 201 10,050 TOTAL $26,153 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 adopted 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. 3 Mid-market price from Evolution Markets 10/16/2014 6

Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). CO2 Allowance Summary (9/30/2014) 1 2 3 4 5 6 7 8 CO2 Allowances Annual CO2 CO2 (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance Allowances Prior to Sale) CO2 Vintage Sold YTD Allowances Emitted Allowance Balance McKee Balance VanSant Run 2009 0 60,128 2,056 62,184 (5,796) 56,388 56,388 2010 0 48,102 1,645 49,747 (32,971) 16,776 73,164 2011 0 36,077 1,234 37,311 (17,763) 19,548 92,712 2012 0 27,058 925 27,983 ( 15,265) 12,718 105,430 4 2013 0 22,879 1,939 24,818 (10,231) 14,587 120,017 2014 0 -0- -0- -0- (25,426) (25,426) 94,591 Dover no longer receives allocations of RGGI allowances (columns 3-5). The Cumulative Balance (column 8) – aka “Banked Allowances” can be utilized for generation in 2014 and future years. Note that the 2014 emissions through the end of August are larger than four out of the last five years. Once the banked allowances have been fully utilized, Dover will be required to purchase RGGI allowances through the auctions or through over-the-counter markets. Assuming that Dover does not sell any banked allowances and produces 25,000 tons per year, it should be able to maintain a positive balance through around 2018. 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 spot auction occurred on September 3rd, 2014; the auction cleared at $4.88/ton. The next auction will occur on December 3rd, 2014. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on September 19, 2014 ranged from $5.02 to $5.47/ton, depending settlement month and vintage. Based on the September 19, 2014 ICE price for the December 2014 strip ($5.06/ton), the 4 Includes Q3 2013 allocations of 7,846.757 for McKee Run and 1,424.677 for VanSant. 7

estimated market value of Dover’s existing 94,591 ton RGGI allowance bank is $478,630. During the September 25, 2014 Management Committee meeting, Dover staff asked if it would be reasonable to begin purchases of additional RGGI allowances in anticipation of future needs because market prices are expected to increase in the future. This will be addressed in a separate presentation. Renewable Energy Certificates Dover owns two photovoltaic systems totaling 15 kW, consisting of (one 5 kW unit at the Utilities Administration Building and two 5 kW units at the McKee Run generating station. Dover also receives solar energy produced by the 10 MW Dover Sun Park which is owned by White Oak Solar Energy, LLC. In addition to the all of the physical energy produced by the Sun Park, Dover receives 15% of Sun Park’s SRECS. Dover participates in the Delaware Municipal Electric Corporation’s (DEMEC) Renewable Portfolio Standard (RPS) for compliance with the State of Delaware’s RPS laws applicable to municipal utilities. The first compliance period under DEMEC’s RPS was the 12 months ending May 2014. Through the end of August 2014, Dover had accumulated a total of 8,797 SRECS from these renewable energy resources. On October 3, 2014, TEA transferred 2,941 of Dover’s SRECS to DEMEC for retirement in accordance with the RPS requirement for the first compliance period. These SRECS which were transferred to DEMEC were assigned a cost of $534,589. While Delaware does periodically hold auctions for SRECs, these auctions are for size tiers N1 – N3, E1 and E2. The Dover Sun Park is in the N4 tier for very large facilities. State-wide carve outs for Tier 4 has been fully subscribed, so there is not a market for tier 4 SRECs in Delaware. The nearest viable market for Dover’s SRECs is Pennsylvania. Daily settlement prices from FlettExchange Environmental services (www.flettexchange.com) were used for 2011/12 through 2014/15 vintage allowances. The October 17, 2014 daily settlement prices for Pennsylvania SRECS are used in the table below. SREC Vintage Auction Clearing Price SREC Balance Market Value (June 1 – May 31) 2011/2012 $0 0 0 2012/2013 $23.00 2,172 49,956 2013/2014 $30.00 2,701 81,030 2014/2015 $30.00 983 29,490 TOTAL 5,856 $160,476 8

TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard (RPS) which DEMEC is working on. Dover’s annual SREC acquisition for the last three years is slightly below the 2013/14 compliance requirements. Compliance requirements will increase in future years. Dover will need to determine how it plans to comply with these increasing SREC requirements in the future before its existing bank of allowances is depleted. During the September 25, 2014 Management Committee meeting, Dover staff asked for an overview of SREC prices. This will be addressed in a separate presentation. D. Operations Management Summary: During the month of September there were no reportable or lost time accidents or injuries. The facility has now gone 1,447 days without an OSHA recordable accident and 1,447 consecutive days without a lost time reportable accident. There were no Environmental Notices of Violations or exceedances issued. There were three near misses reported. McKee Run Unit 3 was dispatched 8 times and Unit 11 was dispatched once by PJM. On September 29, the planned outages started for all units and are scheduled until December 1, 2014. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of September were $440,075 against a budgeted amount of $362,631 for an unfavorable variance of $77,444 or 21.36%. The principal reasons for the unfavorable variance were due to the timing of payroll invoices, higher water and water treatment chemical costs, and higher electricity costs associated with higher operating hours. E. Risk Management Summary: Forward power prices in PJM are slightly lower than last month. The current projected cost of service is below: Blended Cost Monthly Change PY Hedge Ratio ($/MWh) ($/MWh) 2014-15 80% $ 46.72 $ (0.18) 2015-16 70% $ 44.13 $ (0.01) 2016-17 33% $ 42.91 $ (0.20) 2017-18 31% $ 43.60 $ (0.43) 2018-19 15% $ 44.14 $ (0.74) 9

II. Budget Report Budget Actual Variance Sep-14 Sep-14 Gross Load 64,001 64,099 (98) Power Supply Hedged Energy $1,887,922 $2,398,418 ($510,496) PJM - Energy, Congestion & Losses $965,809 $264,581 $701,228 PJM - ARR, Transmission and Fees $607,555 $456,324 $151,232 Dover SUN Park Energy $140,900 $185,885 ($44,985) Dover SUN Park RECs $38,555 $42,307 ($3,752) Management Fees $83,000 $83,000 $0 PJM - Capacity UCAP Obligated Purchased $796,901 $785,866 $11,035 Subtotal - Power Supply $4,520,642 $4,216,380 $304,262 Power Generation O&M Plant O&M $362,631 $440,075 ($77,444) Subtotal Generation O&M $362,631 $440,075 ($77,444) Power Generation Production Margin PJM - Economic and reliability dispatch $0 $ (379,805) $379,805 Fixed Fuel and Transport Charges $0 $ 192,458 ($192,458) Subtotal Generation Production Margin $0 $ (187,347) $187,347 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($716,626) $ (702,347.40) ($14,279) Capacity Replacement Charge $10,800 $ - $10,800 PJM - Black Start & Transmission Losses ($35,550) $ (54,200.90) $18,651 Subtotal - Non-Production Revenue ($741,376) ($756,548) $15,172 SubTotal - All Generation ($378,745) ($503,821) $125,076 Total - Utilities Cost $4,141,897 $3,712,559 $429,338 Unit Costs Total - Power Supply $70.63 $65.78 $4.86 Total - Power Generation ($5.92) ($7.86) $1.94 Final Cost of Service to City of Dover Ratepayers $64.72 $57.92 $6.80 10

Variance Analysis: Power Supply  Dover consumed 98 MWh more than forecast for the month.  PJM transmission and fees were lower than expected with minimal monthly reactive services charges.  This resulted in a net power supply cost of $65.78/MWh, $4.86/MWh below budget.  For the month, the city realized a favorable variance of $304,362 for power supply vs. the monthly budget.  Dover Sun Park generated 379 MWh more than forecast. Generation  Power generation had a favorable budget variance of $125,076.  Plant O&M expenses had an unfavorable budget variance of $77,444 for the month. 11

Budget Actual Variance YTD YTD Gross Load 217,036 208,235 8,801 Power Supply Hedged Energy $6,458,775 $7,980,302 ($1,521,527) PJM - Energy, Congestion & Losses $3,762,419 $2,134,621 $1,627,798 PJM - ARR, Transmission and Fees $2,010,197 $1,394,609 $615,588 Dover SUN Park Energy $566,145 $633,004 ($66,859) Dover SUN Park RECs $130,730 $138,676 ($7,946) Management Fees $249,000 $249,000 $0 PJM - Capacity UCAP Obligated Purchased $2,443,830 $2,394,438 $49,392 Subtotal - Power Supply $15,621,096 $14,924,650 $696,446 Power Generation O&M Plant O&M $1,694,993 $1,510,514 $184,479 Subtotal Generation O&M $1,694,993 $1,510,514 $184,479 Power Generation Production Margin PJM - Economic and reliability dispatch ($1,339,680) ($1,946,803) $607,123 Fixed Fuel and Transport Charges $966,800 $991,866 ($25,066) Subtotal Generation Production Margin ($372,880) ($954,937) $582,057 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($2,197,656) ($2,144,923) ($52,733) Capacity Replacement Charge $33,120 $0 $33,120 PJM - Black Start & Transmission Losses ($156,675) ($168,048) $11,373 Subtotal - Non-Production Revenue ($2,321,211) ($2,312,971) ($8,240) SubTotal - All Generation ($999,098) ($1,757,393) $758,295 Total - Utilities Cost $14,621,998 $13,167,257 $1,454,741 Unit Costs Total - Power Supply $71.97 $71.67 $0.30 Total - Power Generation ($4.60) ($8.44) $3.84 Final Cost of Service to City of Dover Ratepayers $67.37 $63.23 $4.14 12

Operations Management NAES Corporation Dover, Delaware September 2014 Monthly Report Jeff Luff, Operator II, is congratulated by Lance Berryhill, Operations Supervisor, for successfully achieving PJM System Operator Certification. 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 September, there were no restricted work days or lost time accidents. The facility has now gone 3 years, 11 months and 16 days (1,447 days) through September, 2014 without an OSHA Recordable Accident or a Lost Time reportable accident. The facility will achieve the milestone of 4 years of being Accident-free on October 14, 2014. There were three Near Misses reported in September at McKee Run. The first Near Miss occurred when an Operator was asked to open a boiler blow down valve adjacent to the Neutralization Pit. The insulated boiler blow down pipeline is located approximately six feet above grade and runs parallel to the ground surface. The boiler blow down valve is located atop of the pipe and the Operator needed a ladder to gain access to the valve. The Operator selected a four foot ladder to help him gain access to the valve. The Operator stepped on the ladder and placed his right hand on the insulated pipe for stability before he donned work gloves and turned the valve. Upon putting his bare hand on the metal-sheathed pipe run for stability, he felt the sharp metallic edge from a metal insulation banding strap clip on the back side of the pipe sheathing. The Operator immediately retracted his hand and no scrapes or injuries were sustained. The second Near Miss occurred during the removal of a 4160 volt breaker. Two ICE Technicians attempted to remove the breaker from its cubicle. Upon removing the breaker from the cubicle, the wheels of the breaker cart became restricted because of the uneven flooring. Additional effort was needed to move and adjust the breaker into a safe and stable position. No injuries occurred however there existed a possibility of a strained back. A product is being researched that will be installed to smooth out the area. The third Near Miss occurred when the plant was in the process of receiving tanker truck deliveries as part of a bulk purchase to replenish the plant’s supply of red dyed diesel daily. A routine inspection was conducted to see how the progress at the fuel oil off-loading area. At the time of the Compliance Coordinator’s arrival, the fuel oil delivery driver and two NAES Operators had just completed off-loading a fuel oil tanker truck, had shut the unloading pumps off, had put the hoses put away and were having a discussion. The Compliance Coordinator immediately noticed one of the employees smoking a lit cigarette next to the off-loading manifold. As he was approached, the employee extinguished the lit cigarette. Follow-up actions to this event included refresher training by the employee in plant safety procedures and additional signage was posted to warn/remind anyone that smoking is prohibited in this area. Additionally, safety policies will be reviewed and updated to be more prescriptive in addressing smoking limitations and designating smoking areas. The plant received no Notice of Violations (NOVs) during the month. The September DMR was submitted for the McKee Run site with no NPDES exceedences. There were no opacity deviations from any unit in September. 15

DNREC performed a Partial Compliance Evaluation (PCE) audit for the McKee Run and VanSant Generation Stations in August 2014 as part of the Title V air permit. DNREC indicated they would have liked to have visually observed VanSant’s combustion turbine run and collect a No. 2 fuel oil sample, regardless if the facility is operating on fuel oil. To date, we have received verbal confirmation of passing the audit with no issues; however, a representative fuel oil sample was the last item before a written final notice is issued. Late in the month, the plant received notification from the DNREC via email that a fuel oil sample from VanSant will not be necessary to complete the 2014 PCE audit. During the month of September, there were fifteen IWW discharges to the Kent County Sewer. The monthly sampling occurred on September 17, 2014. The laboratory analytical data indicated no exceedences. The September SIU Report was submitted to Kent County. McKee Run began the Unit #3 cooling tower restoration project on September 29, 2014. In the month of September, there were two roll-offs of cooling tower plastic debris totaling 6.84 tons sent to the Sandtown Landfill. Wood debris generated as part of the restoration work was sampled and will be analyzed according to DNREC and Sandtown Landfill requirements to determine how the material will disposed. Wood disposal will begin once the analytical data is returned, submitted to the DSWA and approved by the landfill for disposal. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (September) (7/1/14-6/30/15) NOVs 0 0 Opacity Deviations 0 1 Environmental Deviations 0 0 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 3 8 Man Hours Worked 4,533 66,797.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,447 Days since last Lost Time Accident 1,447 16

Emissions (NOx, CO2 & SO2) All data thru 9/30/14 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 2014 0.4 0.6 35.0 0.8 36.8 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 2014 0.8 1.1 39.8 3.7 45.4 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 0.0 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 2014 0.0 0.0 0.4 0.6 1.0 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) 2013 and 160/78 9/8 earlier 2014 0 71/46 5/3 40/35 - 4/1 0/0 – 0/0 31/11 1/2 Total NOx Allowance Balance 191/89 10/10 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. **Note – The facility transferred Ozone Season allowances to a third party. SO2 Allowances Summary SO2 Allowances Available SO2 Allowance SO2 Allowances (Per Unit, Prior to Sale & Total SO2 Tons Emitted– SO2 Allowances Vintage Sold - YTD Reconciliation) U3 and U11 YTD Balance* Unit #3 Unit #11 2013 and 0 10,365 690 2 11,053 earlier 2014 0 1850 138 1 1,987 Total SO2 Allowance Balance 13,040 *Note – Emissions allowances are deducted according to oldest vintage first, 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 2013 and 0 194,244 7,799 82,026 120,017 earlier 2014 0 0 0 25,426 25,426 Total CO2 Allowance Balance 94591 *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. Note: All emissions (NOx, SO2 and CO2) totals for 2013 are unofficial. #Note: Additional CO2 Emission Values were added to 2013 balances by RGGI COATS- 7,846.757 for McKee Run and 1,424.677 for VanSant 18

2.0 Financial Financial – Current Month Month – September Actual Budget Variance Personnel 259,901 247,700 (12,201) Materials & Supplies 57,204 21,850 (35,354) Administrative Expenses 122,970 93,081 (29,889) Total $440,075 $362,631 ($77,444) Financial – Fiscal Year to Date Number of Months – 3 Actual Budget Variance Personnel 696,013 864,800 168,787 Materials & Supplies 133,617 111,950 (21,667) Administrative Expenses 680,883 718,243 37,360 Total $1,510,513 $1,694,993 $184,480 2.1 Variance analysis: The actual expenses for the month of September are $440,075 against a budgeted amount of $362,631 for an unfavorable variance of $77,444 or 21.36%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $12,201 was due to the timing of payroll invoices. As a result, this impacted three (3) labor accounts – Straight Time, Overtime, and Labor Burdens. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $35,354 was due to higher than budgeted water costs and purchase of water treatment chemicals as a result of higher operating hours than was originally budgeted/forecast. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $16,475 due to higher than anticipated electricity costs as a result of higher operating hours than was originally budgeted/forecast. The forecasted expenses for this fiscal year are $6,071,621 expensed versus an approved budget of $6,141,100 thereby realizing a 98.8 % expenditure rate. 19

3.0 Operations Unit Operations / Outages / Trips: Unit 3 was dispatched eight times and Unit 11 once by PJM in the month of September. Units 1 and 2 were not dispatched for the month of September. On September 29, the planned outage was started on all units and is scheduled until December 1, 2014. Month September 2014 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 84.298 84.298 3.633 87.931 Starts # 0 0 8 8 1 9 Gross Generation MWh 0.0 0.0 4,662.226 4,662.226 115.084 4,777.310 Net Generation MWh 0.0 0.0 4,246.891 4,246.891 114.997 4,361.888 Total Auxiliaries MWh 0.0 0.0 697.632 697.632 1.502 699.134 Auxiliaries purchased MWh 26.524 26.524 282.297 282.297 1.415 283.712 Fuel Gas Used MMBTU 0.0 0.0 49,303.867 49,303.867 1,524.712 50,828.579 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 49,303.867 49,303.867 1,524.712 50,828.579 Net Heat Rate BTU/KWh 0.0 0.0 11.609 11.609 13.259 12.434 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 5.78 3.99 0.40 3.18 Availability Factor % 94.31 94.31 94.31 94.31 94.31 94.31 Commercial % 0.0 0.0 0.0 0.0 0.0 0.0 Unavailability (CU) Planned Outage Hours Hours 41.000 41.000 41.000 123.000 41.000 164.000 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 679.000 679.000 594.702 1,952.702 675.367 2,628.069 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 0.0 0.0 0.0 0.0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 20

2014-2015 Fiscal Year-to-Date 3 Month 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 30.966 35.134 433.682 499.782 17.350 517.132 Starts # 3 5 33 41 5 46 Gross Generation MWh 261.694 252.941 22,525.426 23,040.061 578.081 23,618.142 Net Generation MWh 247.853 233.930 20,511.856 20,993.639 567.702 21,561.341 Total Auxiliaries MWh 97.170 102.340 2,968.338 3,167.848 3.837 3,171.685 Auxiliaries purchased MWh 83.329 83.329 954.768 1,121.426 3.458 1,124.884 Fuel Gas Used MMBTU 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 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 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 Net Heat Rate BTU/KWh 15.253 13.916 11.825 13.664 13.278 13.471 Unit Trips # 1 3 0.0 4 1 5 Capacity Factor % 0.66 0.62 9.11 6.88 0.66 5.49 Availability Factor % 98.14 98.14 97.80 98.03 98.14 98.06 Commercial % 0.0 0.0 0.35 0.11 0.0 0.09 Unavailability (CU) Planned Outage Hours Hours 41.000 41.000 41.000 123.000 41.000 164.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 7.667 7.667 0.0 7.667 Reserve Shutdown Hours 2,136.034 2,131.866 1,725.651 5,993.551 2,149.650 8,143.201 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 527.631 527.631 1,055.263 1,055.263 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 14-15 Fuel FY 14-15 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (FYTD) (Change) McKee Run (#2 Fuel Oil) 445,913 647,719 200,476 201,806 452,963 200,476 194,756 VanSant 73,319 124,053 52,066 50,734 73,572 52,066 50,481 (#2 Fuel Oil) VanSant Lifetime through September 2014 Actual Starts Factored Starts Fired Hours VanSant 1372 2,349.75 4,333.90 Since HGP - Dec 2004 261 682.05 950.32 Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 21

Team Report: The Operations staff continues to support maintenance activities during the planned outage by serving as Confined Space Attendants for confined space areas as well as other support tasks. They assisted in the natural gas line purge on Unit 3 in preparation of the installation of the pipe blank and in the purge on Units 1 and 2 natural gas lines. The Operations staff has also supported the outage by performing various LO/TO tasks needed to test or place equipment in or out or service. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the 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 2014-2015 Summer 2014 (June 1- Aug 31) Winter 2014-2015 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.4 1 17 17* 2 17 17.5 2 17 17* 3 102 103.99 3 102 102* 11 39 39.8# 11 39 39* Total 175 175 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program. Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 22

4.0 Maintenance During the month of September, the Plant Maintenance staff continued addressing the backlog of work orders. There were forty-six work orders issued with eighty-four work orders being completed during the month. No safety work orders were 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 September - 2014 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 45 1 26 20 2 57 5 10 52 3 67 4 16 55 4 6 0 1 5 5 13 1 1 13 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 62 35 30 67 EM 0 0 0 0 Totals 250 46 84 212 Note: PM Work Orders are included in the priority totals Notable activities during the month include: The NAES Operations, Maintenance and IC&E Staff completed the clean out of Unit 3 cooling tower cold water basin. The basin was cleaned as part of the cooling tower project for the fall outage. This clean out ensures that the proper water quality is achieved in the cooling tower and that all construction debris will be able to be removed prior to the tower being placed back into service. The NAES IC&E staff discovered a voltage imbalance while conducting the monthly battery inspection at VanSant Generating Station. They discovered that a position limit switch on the gas purge valve had failed. They replaced the switch and the voltage imbalance issue was resolved. The NAES Maintenance Staff and Carey’s Diesel replaced all of the injectors in the starting diesel engine for the gas turbine at the VanSant Generating Station. This was completed to improve the performance of the diesel engine and will help with the start-up ramp rate of the unit. The NAES IC&E Staff installed a new flow meter on TG-3 station which controls Unit 3 Cooling Tower blowdown. The new flow meter equipment is more reliable and the previous one and will ensure that proper blow down rates are achieved. 23

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: All work planned is now complete. Follow-up activities include contacting suppliers for the replacement of the damaged rotor expansion instrumentation. This equipment is obsolete and will be replaced with current technology. Replacement of other turbine supervisory instrumentation will also be investigated. High vibration experienced EG1212 Unit 3 Turbine Repairs during hot starts will require an additional balancing. Plant staff is collecting data that will help determine where and how much balance weight will need to be installed in the next outage. Schedule: Continuing to pursue the replacement rotor expansion instrumentation and evaluate balancing of turbine-generator for Spring 2014 Outage. Progress: Pre-job meeting held with contractor in preparation of September 29 start. Manpower arrived on September 29 and began Unit #3 Cooling demolition of old material in fill section of tower. EG1402 Tower Repairs Schedule: Demolition activities will continue and once complete, repairs will begin to be made to fill area, hot water basin and other miscellaneous repair activities. Progress: The recently completed hanger adjustments were checked with the unit in the hot (running) position. Minor adjustments are needed on several hangers and will attempt to complete in the coming months. Future operations should provide an opportunity to check the adjustments. McKee Run HEP Pipe EG1406 Work for Fall 2014 work was awarded. Contractor to be onsite in mid- Repairs October. Schedule: One section of pipe is scheduled for replacement is included as part of the scope for the fall of 2014. This work has been awarded and will commence in early October. Progress: Work scope is still being developed for an RFP. COD staff is Metering System continuing their efforts to remake the communication link with Cartanza. EG1407 Upgrades Schedule: Work activities are moving forward. Working with COD staff to finalize RFP documents for release in October period. Progress: Plant received the construction permit from the DNREC and will continue with installation plans. VanSant Capacity EG1416 Schedule: Equipment skids are scheduled to arrive in early October and Increase foundations will be poured in the same time period. Other miscellaneous material are on order including the MCC sections. Progress: Work scopes being developed for Fall 2014 and Spring 2015 Unit #3 Auxiliary Outages. EG1503 System Component Schedule: Fall 2014 work scopes were developed and will commence in Replacement October. Progress: Work scopes being developed for Fall 2014 and Spring 2015 Unit#3 Boiler System EG1504 Outages. Repairs Schedule: Fall 2014 work is scheduled for October start. VanSant Station Progress: Work scope is being deferred until next FY. EG1505 Component Schedule: Work scopes will continue to be developed for next fiscal year. 24

Replacement Progress: Work scopes developed and sent out for bids and award in early McKee Run/VanSant September. Bids were reviewed, evaluated and contracts awarded. EG1506 Safety Improvements Schedule: Work activities planned for completion in Fall 2014 outage and spring 2015. McKee Run Units #1- Progress: Project on Hold EG1507 #2 Component Schedule: Project on Hold Replacement Progress: Plant staff completed development of paint specifications and bid requests were to be received in mid-August. McKee Run/VanSant EG1508 Schedule: Bids will be evaluated and determination made thereafter as to Structural Preservation how to proceed. Work will need to be completed in warmer temperatures, spring 2015 6.0 General Plant Information Jeff Luff. Operator II, successfully achieved PJM System Operator Certification when he passed the PJM exam. Training: Plant employees continue General Physics safety training and environmental courses to enhance their overall knowledge of permit and safety requirements. As the GPI courses are being completed the employee reviews the standard operating procedure (SMP) for the same topic they are training on to review NAES policy and score a minimum 80% on a quiz before they can complete the SMP. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Compressed Air Injury”. 25

Calendar of Events Date Annual VanSant Black Start Test TBD Units 1, 2, 3 and 11 Fall Outage Starts September 29, 2014 NOx Ozone Season Ends September 30, 2014 Four Year Accident Free October 14, 2014 NPDES Permit Expires (DNREC has Extended) November 1, 2014 Winter Capacity Period December 1, 2014 to February 28, 2015 NOx Emissions Reconciliation Due March 1, 2015 SO2 Emissions Reconciliation Due March 1, 2015 SARA III / Tier II Report Due March 1, 2015 Units 1, 2, and 3 Spring Outage TBD – Spring 2015 Unit 11 Spring Outage TBD – Spring 2015 Air Emission Inventory April 30, 2015 NOx Ozone Season Starts May 1, 2015 PJM Summer Capacity Test Period June 1, 2015 – August 31, 2015 FY 2014-201454 Budget Year Begins July 1, 2015 Toxic Release Inventory (TRI) Annual Report July 1, 2015 Semi-Annual Title V Certification Due July 31, 2015 7.0 Summary of NAES Performance to Date Plant Performance FY 2014-2015 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.00% 0.05% $94,679 $96,875 Unavailability (CU) Safety 0 0 $18,163 $18,163 Environmental 0 0 $18,163 $18,163 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes No $3,634 $3,634 Unit 2 No No Yes No $3,634 $3,634 Unit 3 No No Yes No $21,797 $21,797 Unit 11 No No Yes No $7,266 $7,266 Total YTD 98.7% Total YTD Incentive $167,335 $169,532 Incentive % Note*: All units have successfully completed the Summer (FY 2014-2015) Testing for PJM and are now entered in the PJM Winter Capacity Test Exemption Program. 26

III. Appendix 1 – PJM Invoice Breakdown Gen Load Grand Total 480-8102-592-95-49 1610 Locational Reliability $787,991.40 $787,991.40 2630 Capacity Transfer Rights $58.80 $58.80 2661 Capacity Resource Deficiency ($2,184.60) ($2,184.60) 480-8102-592-95-49 Total $785,865.60 $785,865.60 480-8102-592-95-50 1600 RPM Auction $14,277.60 $14,277.60 2600 RPM Auction ($716,625.00) ($716,625.00) 480-8102-592-95-50 Total ($702,347.40) ($702,347.40) 480-8102-592-95-90 1100 Network Integration Transmission Service $406,720.80 $406,720.80 1108 Transmission Enhancement $71,646.00 $71,646.00 1242 Day-Ahead Load Response Charge Allocation $175.75 $175.75 1243 Real-Time Load Response Charge Allocation $364.58 $364.58 1301 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $10,793.15 $10,793.15 1303 PJM Scheduling, System Control and Dispatch Service - Market Support $2,625.11 $2,625.11 1304 PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $89.23 $89.23 1305 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $921.90 $921.90 1306 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,847.86 $1,847.86 1307 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($299.80) ($299.80) 1308 PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($529.44) ($529.44) 1310 PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($132.16) ($132.16) 1311 PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($5.42) ($5.42) 1312 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($40.50) ($40.50) 1313 PJM Settlement, Inc. $299.80 $299.80 1314 Market Monitoring Unit (MMU) Funding $272.71 $272.71 1315 FERC Annual Recovery $4,478.04 $4,478.04 1316 Organization of PJM States, Inc. (OPSI) Funding $44.65 $44.65 1317 North American Electric Reliability Corporation (NERC) $682.56 $682.56 1318 Reliability First Corporation (RFC) $969.60 $969.60 1320 Transmission Owner Scheduling, System Control and Dispatch Service $4,739.55 $4,739.55 1330 Reactive Supply and Voltage Control from Generation and Other Sources Service $36,237.61 $36,237.61 1340 Regulation and Frequency Response Service $12,480.12 $12,480.12 1360 Synchronized Reserve $1,698.99 $1,698.99 1362 Non-Synchronized Reserve $114.03 $114.03 1365 Day-ahead Scheduling Reserve $2.54 $2.54 1370 Day-ahead Operating Reserve $8,129.70 $8,129.70 1375 Balancing Operating Reserve $6,010.37 $6,010.37 1376 Balancing Operating Reserve for Load Response ($0.95) ($0.95) 1378 Reactive Services $580.34 $580.34 1380 Black Start Service $2,351.85 $2,351.85 1730 Expansion Cost Recovery $408.30 $408.30 1911 Michigan - Ontario Interface Phase Angle Regulators $198.73 $198.73 1932 Generation Deactivation Refund ($696.77) ($696.77) 2108 Transmission Enhancement ($63,193.77) ($63,193.77) 2140 Non-Firm Point-to-Point Transmission Service ($360.62) ($360.62) 2420 Load Reconciliation for Transmission Losses $136.86 $136.86 2510 Auction Revenue Rights ($53,391.00) ($53,391.00) 2912 CT Lost Opportunity Cost Allocation ($46.80) ($46.80) 480-8102-592-95-90 Total $456,323.50 $456,323.50 480-8102-592-95-91 1200 Day-ahead Spot Market Energy $572,474.19 $572,474.19 1205 Balancing Spot Market Energy ($143,582.22) ($143,582.22) 1210 Day-ahead Transmission Congestion ($153,679.38) ($153,679.38) 1215 Balancing Transmission Congestion $19,816.66 $19,816.66 1220 Day-ahead Transmission Losses ($11,833.24) ($11,833.24) 1225 Balancing Transmission Losses $892.19 $892.19 1230 Inadvertent Interchange $717.69 $717.69 1245 Emergency Load Response ($60.13) ($60.13) 1250 Meter Error Correction ($4,688.79) ($4,688.79) 1400 Load Reconciliation for Spot Market Energy ($11,270.78) ($11,270.78) 1410 Load Reconciliation for Transmission Congestion ($3,283.60) ($3,283.60) 1420 Load Reconciliation for Transmission Losses ($686.11) ($686.11) 1430 Load Reconciliation for Inadvertent Interchange ($3.56) ($3.56) 1440 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service ($62.84) ($62.84) 1441 Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund $3.11 $3.11 1442 Load Reconciliation for Schedule 9-6 - Advanced Second Control Center ($10.44) ($10.44) 1444 Load Reconciliation for Market Monitoring Unit (MMU) Funding ($1.16) ($1.16) 1445 Load Reconciliation for FERC Annual Recovery ($21.36) ($21.36) 1446 Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding ($0.21) ($0.21) 1447 Load Reconciliation for North American Electric Reliability Corporation (NERC) ($3.26) ($3.26) 1448 Load Reconciliation for Reliability First Corporation (RFC) ($4.63) ($4.63) 1450 Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service ($22.61) ($22.61) 1460 Load Reconciliation for Regulation and Frequency Response Service ($64.22) ($64.22) 1470 Load Reconciliation for Synchronized Reserve ($6.14) ($6.14) 1472 Load Reconciliation for Non-Synchronized Reserve ($1.66) ($1.66) 1475 Load Reconciliation for Day-ahead Scheduling Reserve ($0.04) ($0.04) 1478 Load Reconciliation for Balancing Operating Reserve ($8.43) ($8.43) 1480 Load Reconciliation for Synchronous Condensing ($0.03) ($0.03) 1490 Load Reconciliation for Reactive Services ($28.48) ($28.48) 480-8102-592-95-91 Total $264,580.52 $264,580.52 480-8102-592-95-92 1200 Day-ahead Spot Market Energy ($350,062.30) ($350,062.30) 1205 Balancing Spot Market Energy $90,922.79 $90,922.79 1210 Day-ahead Transmission Congestion ($128,129.05) ($128,129.05) 1215 Balancing Transmission Congestion $6,388.81 $6,388.81 1220 Day-ahead Transmission Losses $3,896.26 $3,896.26 1225 Balancing Transmission Losses $1,487.79 $1,487.79 2370 Day-ahead Operating Reserve ($867.70) ($867.70) 2375 Balancing Operating Reserve ($3,441.73) ($3,441.73) 480-8102-592-95-92 Total ($379,805.13) ($379,805.13) 480-8102-592-95-93 2220 Transmission Losses ($24,703.49) ($24,703.49) 2330 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) ($29,467.58) 2360 Synchronized Reserve ($27.43) ($27.43) 2365 Day-ahead Scheduling Reserve ($2.40) ($2.40) 480-8102-592-95-93 Total ($54,200.90) ($54,200.90) Grand Total $ (1,136,353.43) $ 1,506,769.62 $370,416.19 27

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The Energy Authority, Inc. Monthly Management Committee Update – October 2014 November 20, 2014 Prepared by: Robert Trinnear Client Services Manager 904.360.1309 rtrinnear@teainc.org

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

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $482,097 under budget driven by lower prices and lower PJM fees. Dover’s budgeted cost for all power supply (capacity AND energy) was $71.31/MWh. The actual cost of all power supply (capacity AND energy) was $64.45/MWh. The cost of energy alone was $39.60/MWh, versus a budgeted energy cost of $46.08. Dover’s hedge purchases totaled 45,320 MWh, which was 81% of the actual load. The budgeted hedge purchase totaled 36,328, which was 63% of the budgeted load. Dover’s power purchases from hedge transactions totaled $1,962,527. Purchases from PJM (energy and fees) totaled $578,587. This number includes DA spot market energy charges of $454,086 and Reactive Service charges of $2,065. Dover’s total load was 56,013 MWh versus a forecasted load of 57,385 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1,294 MWh. Dover’s actual energy purchase from the SunPark installation was 1,213 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 57,385 56,013 1,372 Wholesale Load 56,091 54,800 1,291 Hedged Volume (MWh) 36,328 45,320 (8,992) Unhedged Volume (MWh) 19,763 9,480 10,283 Dover SunPark Volume (MWh) 1,294 1,213 81 Renewable Energy Credits Volume 194 240 (46) Hedged Cost ($/MWh) $ 46.11 $ 43.30 $ 2.81 Unhedged Energy Cost ($/MWh) $ 41.50 $ 12.11 $ 29.39 Solar Energy Cost ($/MWh) $ 115.12 $ 115.97 $ (0.85) Energy Costs ($/MWh) $46.08 $39.60 $6.48 All-in Costs - Energy, Capacity and RECs ($/MWh) $71.31 $64.45 $6.86 2

B. Generation Summary: Dover generated 0 MWh in the month. Net generation revenue was $207,586 vs. a budget of $365,669. 3

Generation Breakdown: City of Dover Monthly Wholesale Generation Formula October, 2014 Net Generation 0.00 D Production Margin PJM - Generation Economic and Reliability Dispatch $ - A Natural Gas & Oil Consumption Purchases for Generation $ - Natural Gas Transport $ - Eastern Shore Cashout $ - Oil Consumption $ - Subtotal: Natural Gas & Oil Consumption $ - B Gross Production Margin $ - C = (A + B) $/MWh Generation Production Gross Margin $ - E = (C/D) PJM - Capacity Generation Capacity Credit $ 725,758.98 Black Start and Transmission Losses $ 53,152.88 Subtotal: PJM - Capacity $ 778,911.86 F All in Generation Margin All in Generation Margin Total $ 778,911.86 (G = C + F) 4

C. Emissions Summary: Emissions Allowance Summary through October 31, 2014 McKee Run 3 and VanSant Unit 11 (Dover’s two units covered by the Clean Air Interstate Rule or CAIR) were not operated during the month of October, so there were no additional emissions during this period. CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowances Seasonal Annual 1/1/09 2008 Carryover 3,240 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 2,039 50 78 1/1/11 2011 Allocation 1,988 49 78 4/1/11 2011 Reallocation 2 4 1/11/12 2012 Allocation 1,988 51 80 10/4/2012 2013 Allocation 1,988 49 76 2014 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 11/15/13 NOx Annual Sales (DEMEC) (5) 12/31/13 2013 Emissions (0) (20) (20) 8/31/14 2014 CYTD Emissions (1) (36) (44) REMAINING ALLOWANCES 13,040 99 201 On August 21, 2012, a three-judge panel of the U.S. District Court of Appeals (DCA) in Washington vacated EPA’s Cross State Air Pollution Rule (CSAPR) which would have become effective on January 1, 2012. The DCA instructed EPA to continue 1 Per CAIR, starting in 2009, NOx emissions are governed by a seasonal and annual program. 2 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 5

administering the Clean Air Interstate Rule (CAIR). EPA appealed the DCA ruling to the U.S. Supreme Court, which heard arguments on December 10th, 2013. On April 29th, 2014, the U.S. Supreme Court overturned the DCA opinion; however it did not immediately reinstate CSAPR. It sent the rule back to the DCA for further action consistent with the Supreme Court’s opinion. On June 26th, 2014, EPA requested the DCA to reinstate CSAPR, with Phase 1 compliance deadlines being changed by 3 years to 2015 and 2016, and Phase 2 compliance deadlines being changed to 2017. EPA is preparing “ministerial” revisions to CSPAR so that it conforms to certain issues raised by the DCA in its 2012 action. The DCA lifted the stay on October 23rd, 2014 and scheduled a hearing on remaining issues for March 15, 2015. While Delaware is included in the CAIR footprint, it is not included in the CSAPR footprint. CAIR allowances cannot be used for CSAPR compliance, so Dover’s CAIR allowances will become valueless when CSAPR is reinstated. The separate Clean Air Act acid rain deposition control program will remain in effect, however the CAIR provisions for SO2 will also disappear for Delaware. 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 settlement prices on the Intercontinental Exchange (ICE). Mark Value for CAIR Allowances Commodity $/Ton Tons Market Value ICE Settlement as of Nov. 18th, 2014 SO2 Allowances (2009 & earlier) $ 1.35 5,089 $ 6,870 SO2 Allowances (2010-12) $ 0.85 3,975 3,379 SO2 Allowances (2013-15) $1.35 3,976 5,368 NOx Allowances - Seasonal $25.003 99 2,475 NOx Allowances - Annual $65.00 201 13,065 TOTAL $31,157 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 adopted a combined emissions allowance allocation/auction mechanism for 3 Value from previous month; no ICE or Broker price was available for seasonal NOx allowances 6

RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). CO2 Allowance Summary (10/31/2014) 1 2 3 4 5 6 7 8 CO2 Allowances Annual CO2 CO2 (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance Allowances Prior to Sale) CO2 Vintage Sold YTD Allowances Emitted Allowance Balance McKee Balance VanSant Run 2009 0 60,128 2,056 62,184 (5,796) 56,388 56,388 2010 0 48,102 1,645 49,747 (32,971) 16,776 73,164 4 2011 0 36,077 1,234 37,311 (17,746) 19,565 92,729 2012 0 27,058 925 27,983 ( 15,957) 12,026 104,755 2013 0 22,879 1,939 24,818 (10,231) 14,587 119,342 2014 0 -0- -0- -0- (25,426) (25,426) 93,917 Dover no longer receives allocations of RGGI allowances (columns 3-5). The cumulative balance can be utilized for generation in 2014 and future years. Note that the 2014 emissions through the end of October are larger than four out of the last five years. Once the banked allowances have been fully utilized, Dover will be required to purchase RGGI allowances through the auctions or through over-the-counter markets. Assuming that Dover does not sell any banked allowances and produces 25,000 tons of CO2 emissions annually, it should be able to maintain a positive balance through around 2018. 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 spot auction occurred on September 3rd, 2014; the auction cleared at $4.88/ton. The next auction will occur on December 3rd, 2014. Based on the November 18th, 2014 ICE price for the December 2014 strip ($5.19/ton), the 4 2011 and 2012 emissions corrected to match values in RGGI COATS. 7

estimated market value of Dover’s existing 93,917 ton RGGI allowance bank is $487,429. Renewable Energy Certificates Dover owns two photovoltaic systems totaling 15 kW, consisting of (one 5 kW unit at the Utilities Administration Building and two 5 kW units at the McKee Run generating station. Dover also receives solar energy produced by the 10 MW Dover Sun Park which is owned by White Oak Solar Energy, LLC. In addition to the all of the physical energy produced by the Sun Park, Dover receives 15% of Sun Park’s SRECS. Dover participates in the Delaware Municipal Electric Corporation’s (DEMEC) Renewable Portfolio Standard (RPS) for compliance with the State of Delaware’s RPS laws applicable to municipal utilities. The first compliance period under DEMEC’s RPS was the 36 months ending May 2014. Through the end of October 2014, Dover had accumulated a total of 6,098 SRECS from these renewable energy resources, net of 2,941 SREC transferred to DEMEC for retirement in accordance with the RPS requirement for the first compliance period. While Delaware does periodically hold auctions for SRECs, these auctions are for size tiers N1 – N3, E1 and E2. The Dover Sun Park is in the N4 tier for very large facilities. State-wide carve outs for Tier 4 has been fully subscribed, so there is not a market for tier 4 SRECs in Delaware. The nearest viable market for Dover’s SRECs is Pennsylvania. Daily settlement prices from FlettExchange Environmental services (www.flettexchange.com) were used for 2011/12 through 2014/15 vintage allowances. The November 18, 2014 daily settlement prices for Pennsylvania SRECS are used in the table below. SREC Vintage Market Clearing Price SREC Balance Market Value (June 1 – May 31) 2011/2012 $0 0 0 2012/2013 $23.00 1,834 42,182 2013/2014 $30.00 2,735 82,050 2014/2015 $40.50 1,529 61,924 TOTAL 6,098 $180,156 TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard (RPS) which DEMEC is working on. Dover’s annual SREC acquisition for the last three years is slightly below the 2013/14 compliance requirements. Compliance requirements will increase in future years. Dover will need to determine how it plans to comply with these increasing SREC requirements in the future before its existing bank of allowances is depleted. 8

D. Operations Management Summary: During the month of October there were no reportable or lost time accidents or injuries. The facility has now gone 1,478 days without an OSHA recordable accident and 1,478 consecutive days without a lost time reportable accident. There were no Environmental Notices of Violations or exceedances issued. There were two near misses reported. All Units were in a planned outage during the entire month and therefore had not opportunities to generate for PJM. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of October were $571,326 against a budgeted amount of $389,581 for an unfavorable variance of $181,745 or 46.60%. The principal reasons for the unfavorable variance were due to; having three (3) payrolls expensed in October rather than the two (2) that were budgeted, payouts to personnel who terminated their employment at the facility, and higher variable costs for water, sewer, and electricity. E. Risk Management Summary: Forward power prices in PJM are slightly lower than last month. The current projected cost of service is below: Blended Cost Monthly Change PY Hedge Ratio ($/MWh) ($/MWh) 2014-15 80% $ 46.72 $ (0.18) 2015-16 70% $ 44.13 $ (0.01) 2016-17 33% $ 42.91 $ (0.20) 2017-18 31% $ 43.60 $ (0.43) 2018-19 15% $ 44.14 $ (0.74) 9

II. Budget Report Budget Actual Variance Oct-14 Oct-14 Source Formula G = (Net PJM Wholesale Load + PJM load Inschedules + Dover White Oak-Dover SunPark Gross Load 57,385 56,013 1,372 invoice Mwh) Power Supply TEA Deal capture system, verified by settlement checking out Hedged Energy $1,675,194 $1,962,527 ($287,333) with counterparties PJM - Energy, Congestion & Losses $820,148 114,786 $705,362 PJM Invoice PJM - ARR, Transmission and Fees $515,925 463,802 $52,123 PJM Invoice White Oak-Dover Dover SUN Park Energy $148,960 $140,672 $8,288 Invoice White Oak-Dover Dover SUN Park RECs $25,410 $33,221 ($7,811) Invoice Management Fees $83,000 $83,000 $0 Annual Contract PJM - Capacity UCAP Obligated Purchased $823,464 $811,997 $11,467 PJM Invoice Subtotal - Power Supply $4,092,101 $3,610,004 $482,097 A Power Generation O&M Plant O&M 389,581 $571,326 (181,745) Monthly NAES report Subtotal Generation O&M 389,581.00 571,326.00 ($181,745) B Power Generation Production Margin PJM - Economic and reliability dispatch $0 $ - $0 PJM Invoice Fixed Fuel and Transport Charges TEA Deal capture system, verified by settlement checking out with counterparties and $0 $ - $0 pipeline. Subtotal Generation Production Margin $0 $ - $0 C Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($740,515) $ (725,759) ($14,756) PJM Invoice Budgeted amount for incremental 3.6 mw purchase. Actuals been shown in PJM - Capacity UCAP Obligated Capacity Replacement Charge $11,160 $ - $11,160 purchased. PJM - Black Start & Transmission Losses ($25,895) $ (53,153) $27,258 PJM Invoice Subtotal - Non-Production Revenue ($755,250) ($778,912) $23,662 D SubTotal - All Generation (365,669.00) ($207,586) ($158,083) E = (B+C+D) Total - Utilities Cost $3,726,432 $3,402,418 $324,014 F = (A+E) Unit Costs Total - Power Supply $71.31 $64.45 $6.86 H = (A/G) Total - Power Generation ($6.37) ($3.71) ($2.67) I = (E/G) Final Cost of Service to City of Dover Ratepayers $64.94 $60.74 $4.19 J =( H+I) 10

Variance Analysis: Power Supply  Dover consumed 1,372 MWh less than forecast for the month.  PJM transmission and fees were lower than expected with minimal monthly reactive services charges.  This resulted in a net power supply cost of $64.45/MWh, $6.86/MWh below budget.  For the month, the city realized a favorable variance of $482,097 for power supply vs. the monthly budget.  Dover Sun Park generated 81 MWh less than forecast. Generation  Power generation had an unfavorable budget variance of $158,083.  Plant O&M expenses had an unfavorable budget variance of $181,745 for the month. 11

Budget Actual Variance YTD YTD Source Formula G = (Net PJM Wholesale Load + PJM load Inschedules + Dover White Oak-Dover SunPark Gross Load 274,421 264,247 10,173 invoice Mwh) Power Supply TEA Deal capture system, verified by settlement checking out Hedged Energy $8,133,969 $9,942,829 ($1,808,860) with counterparties PJM - Energy, Congestion & Losses $4,582,567 $2,249,406 $2,333,161 PJM Invoice PJM - ARR, Transmission and Fees $2,526,122 $1,858,411 $667,711 PJM Invoice White Oak-Dover Dover SUN Park Energy $715,105 $773,676 ($58,571) Invoice White Oak-Dover Dover SUN Park RECs $156,140 $171,897 ($15,757) Invoice Management Fees $332,000 $332,000 $0 Annual Contract PJM - Capacity UCAP Obligated Purchased $3,267,294 $3,206,436 $60,858 PJM Invoice Subtotal - Power Supply $19,713,197 $18,534,654 $1,178,543 A Power Generation O&M Plant O&M $2,084,574 $2,081,840 $2,734 Monthly NAES report Subtotal Generation O&M $2,084,574 $2,081,840 $2,734 B Power Generation Production Margin PJM - Economic and reliability dispatch ($1,339,680) ($1,946,803) $607,123 PJM Invoice Fixed Fuel and Transport Charges TEA Deal capture system, verified by settlement checking out with counterparties and $966,800 $991,866 ($25,066) pipeline. Subtotal Generation Production Margin ($372,880) ($954,937) $582,057 C Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($2,938,171) ($2,870,682) ($67,489) PJM Invoice Budgeted amount for incremental 3.6 mw purchase. Actuals been shown in PJM - Capacity UCAP Obligated Capacity Replacement Charge $44,280 $0 $44,280 purchased. PJM - Black Start & Transmission Losses ($182,570) ($221,201) $38,631 PJM Invoice Subtotal - Non-Production Revenue ($3,076,461) ($3,091,883) $15,422 D SubTotal - All Generation ($1,364,767) ($1,964,979) $600,212 E = (B+C+D) Total - Utilities Cost $18,348,430 $16,569,675 $1,778,755 F = (A+E) Unit Costs Total - Power Supply $71.84 $70.14 $1.69 H = (A/G) Total - Power Generation ($4.97) ($7.44) $2.46 I = (E/G) Final Cost of Service to City of Dover Ratepayers $66.86 $62.71 $4.16 J =( H+I) 12

Operations Management NAES Corporation Dover, Delaware October 2014 Monthly Report VanSant Capacity Project – Newly Installed Wet Compression Pump Skids 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 October, there were no restricted work days or lost time accidents. The facility has now gone 4 years and 17 days (1,478 days) through October, 2014 without an OSHA Recordable Accident or a Lost Time reportable accident. The employees at the facility successfully achieved the four years Accident-free milestone on October 14, 2014. There were two Near Misses reported in October at McKee Run. The first Near Miss occurred while an Operator was filling the caustic day tank. The Operator stood on a plastic 5-gallon pail to visually observe the liquid level refill to its original operating level inside the day tank. The height of the tank rim/cover is approximately five and half feet from ground surface and is a challenge to visually observe the refilling process. Upon discovering the situation, several other Operators collectively approached the Operator and advised him to cease that operation. The corrective action was to purchase a new 4 foot fiberglass ladder that is dedicated to the caustic and acid day tanks areas. The second Near Miss occurred at the Unit #3 Cooling Tower where a restoration project is underway. Two licensed solid waste solid waste transporters were retained by the plant to transport construction and demolition (C&D) debris from the project site to the local landfill. Two waste streams were being generated from this project; plastic debris from the cooling tower and pressure treated wood. Wood samples had been collected but were undergoing analysis and plant staff was waiting for the final results before the waste could be removed from the plant site. On Friday, October 3, 2014, both transporters were contacted and given specific instructions to suspend service until Monday October 6, 2014. At approximately 0630 hours on Saturday October 4, 2014, one of the haulers picked up an unauthorized roll-off load of pressure treated wood, transported it and disposed of it at the Sandtown landfill. Upon discovery of this action approximately one hour after the incident, NAES contacted the landfill and informed them of the situation. No management was on-site the day of the incident and the Sandtown landfill operator instructed NAES to call on Monday and discuss the situation with the landfill manager. On Monday, the landfill manger was contacted by plant staff and the resolution was that the plant needed to submit a Delaware Solid Waste Authority (DSWA) Special Waste form along with any laboratory analysis for the DSWA to review and to determine disposition of the material. The Special Waste form was completed, submitted to DSWA along with lab data, and shortly afterwards received a DSWA Special Waste approval letter to be used to dispose of this material. McKee Run received a Special Waste approval letter from DSWA for up to 400 tons of pressure treated wood from the Unit #3 Cooling Tower restoration project. In the month of October a total of 17.04 tons for Special Waste was hauled to DSWA’s Sandtown landfill in Felton, DE. McKee Run used a contractor to remove approximately 600-gallons of oily water from the plant. In addition, the contractor was also used to remove 500-gallons of oil and oily water from the VanSant oil/water separator tank. The plant received no Notice of Violations (NOVs) during the month. The October DMR was submitted for the McKee Run site with no NPDES exceedences. There were no opacity deviations from any unit in October. On October 21, 2014 McKee Run and VanSant completed the annual opacity (COMS) auditing certification requirement. Due to recent changes in air regulations, McKee Run and VanSant underwent the new requirements which mandate that electric generating stations perform opacity 15

COMS filter audit certifications on a quarterly basis rather than the previous years’ annual certification. Therefore, on October 21, 2014, both McKee Run and VanSant completed and passed the 2014 quarterly opacity COMS filter certifications. The next quarterly opacity certification is schedule for March of 2015. As required by the air permit, the City of Dover submitted the Quarterly Excess Emissions Report to DNREC and EPA for the VanSant facility. During the month of October, there were no IWW discharges to the Kent County Sewer system. Since there were no monthly discharges, no monthly sample was collected. The October SIU Report was still submitted to Kent County indicating no discharges occurred. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (October) (7/1/14-6/30/15) NOVs 0 0 Opacity Deviations 0 1 Environmental Deviations 0 0 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 2 10 Man Hours Worked 4,706.5 71,503.75 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,478 Days since last Lost Time Accident 1,478 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 2013 and 0 194,244 7,799 82,700** 119,343** earlier 2014 0 0 0 25,426 (25,426) Total CO2 Allowance Balance 93,917** *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. Note: All emissions (NOx, SO2 and CO2) totals for 2013 are unofficial. #Note: Additional CO2 Emission Values were added to 2013 balances by RGGI COATS- 7,846.757 for McKee Run and 1,424.677 for VanSant **Note: 2011 and 2012 Emissions in previous reports were incorrect. The October 2014 Report now correctly reflects the actual emissions. 16

NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 2014 0.4 0.6 35.0 0.8 36.8 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 2014 0.8 1.1 39.8 3.7 45.4 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 2014 0.0 0.0 0.4 0.6 1.0 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) 2013 and 160/78 9/8 earlier 2014 0 71/46 5/3 40/35 - 4/1 0/0 – 0/0 31/11 1/2 Total NOx Allowance Balance 191/89 10/10 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. **Note – The facility transferred Ozone Season allowances to a third party. SO2 Allowances Summary SO2 Allowances Available SO2 Allowance SO2 Allowances (Per Unit, Prior to Sale & Total SO2 Tons Emitted– SO2 Allowances Vintage Sold - YTD Reconciliation) U3 and U11 YTD Balance* Unit #3 Unit #11 2013 and 0 10,365 690 2 11,053 earlier 2014 0 1850 138 1 1,987 Total SO2 Allowance Balance 13,040 *Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 17

2.0 Financial Financial – Month Month – October Actual Budget Variance Personnel 390,982 245,800 (145,182) Materials & Supplies 37,494 10,200 (27,294) Administrative Expenses 142,850 133,581 (9,269) Total $571,326 $389,581 ($181,745) Financial – Fiscal Year to Date Number of Months – 4 Actual Budget Variance Personnel 1,086,996 1,110,600 23,604 Materials & Supplies 171,111 122,150 (48,961) Administrative Expenses 823,733 851,824 28,091 Total $2,081,840 $2,084,574 $2,734 2.1 Variance analysis: The actual expenses for the month of October are $571,326 against a budgeted amount of $389,581for an unfavorable variance of $181,745 or 46.60%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $145,182 was due to three (3) payroll periods being expensed versus the (2) that were budgeted. In addition, there were payouts to personnel who terminated their employment at the facility. As a result, this impacted three (3) labor accounts – Straight Time, Overtime, and Labor Burdens. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $27,294 was due to higher than budgeted water and sewer costs than was originally budgeted. Additionally, new computers were purchased, as recommended by City IT Department that was originally budgeted for later in the fiscal year. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $9,269 due to higher than anticipated electricity costs. A portion of this negative variance was offset by lower than anticipated costs in insurance and environmental costs. The forecasted expenses for this fiscal year are $6,136,266 expensed versus an approved budget of $6,141,100 thereby realizing a 99.92% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips: On September 29, a planned outage was started on all units and is scheduled until December 1, 2014. Month October 2014 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 0.0 0.0 0.0 0.0 0.0 0.0 Auxiliaries purchased MWh 19.819 19.819 140.291 179.928 2.317 182.245 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Commercial % 0.0 0.0 0.0 0.0 0.0 0.0 Unavailability (CU) Planned Outage Hours Hours 744.000 744.000 744.000 2,232.000 744.000 2,976.000 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 0.0 0.0 0.00.0 0.0 0.0 0.00.0 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 0.0 0.0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 19

2014-2015 Fiscal Year-to-Date (4 Months) 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 30.966 35.134 433.682 499.782 17.350 517.132 Starts # 3 5 33 41 5 46 Gross Generation MWh 261.694 252.941 22,525.426 23,040.061 578.081 23,618.142 Net Generation MWh 247.853 233.930 20,511.856 20,993.639 567.702 21,561.341 Total Auxiliaries MWh 116.989 122.159 3,108.629 3,347.776 6.154 3,353.930 Auxiliaries purchased MWh 103.148 103.148 1,095.059 1,301.355 5.775 1,307.130 Fuel Gas Used MMBTU 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 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 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 Net Heat Rate BTU/KWh 15.253 13.916 11.825 13.664 13.278 13.471 Unit Trips # 1 3 0.0 4 1 5 Capacity Factor % 0.49 0.47 6.81 5.15 0.49 4.11 Availability Factor % 73.41 73.41 73.15 73.32 73.41 73.34 Commercial % 0.0 0.0 0.26 0.09 0.0 0.06 Unavailability (CU) Planned Outage Hours Hours 785.000 785.000 785.000 2,355.000 785.000 3,140.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 7.667 7.667 0.0 7.667 Reserve Shutdown Hours 2,136.034 2,131.866 1,725.651 5,993.551 2,149.650 8,143.201 Hours HW Boiler Gas Usage MMBTU 0.0 0.0 Pilot Gas Usage MMBTU 527.631 527.631 1,055.263 1,055.263 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 14-15 Fuel FY 14-15 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (FYTD) (Change) McKee Run (#2 Fuel Oil) 647,719 667,988 22,419 20,269 452,963 222,895 215,025 VanSant 124,053 130,879 7,446 6,826 73,572 59,512 57,307 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through October 2014 Actual Starts Factored Starts Fired Hours VanSant 1372 2,349.75 4,333.90 Since HGP - Dec 2004 261 682.05 950.32 20

Team Report: OES-NA was on site for the purpose of providing PJM simulation training to Operations staff members. PJM requires thirty (30) simulation hours (credits) in order to maintain the three year Generation System operator certification. The only method to receive these credits is to attend a PJM System Operator seminar or to have qualified training observed by PJM. Voltage Control, Congestion Management, and Emergency Operations are some of the topics covered in the two day class using laptops. Four operators and one supervisor attended the class from the plant staff. This class will supply the operator attendees with fourteen (14) simulation credits. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both the Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2014-2015 Summer 2014 (June 1- Aug 31) Winter 2014-2015 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.4 1 17 17* 2 17 17.5 2 17 17* 3 102 103.99 3 102 102* 11 39 39.8# 11 39 39* Total 175 175 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program. Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 21

4.0 Maintenance During the month of October, the Plant Maintenance staff continued addressing the backlog of work orders. There were forty-one work orders issued with ninety-seven work orders being completed during the month. No safety work orders were 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 - 2014 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 24 4 6 22 2 55 5 14 46 3 57 2 18 41 4 5 0 0 5 5 16 0 3 13 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 84 30 56 58 EM 0 0 0 0 Totals 241 41 97 185 Note: PM Work Orders are included in the priority totals Notable activities during the month include: The NAES Maintenance & Operations Staff opened the Deaerator heater and storage tanks in preparation for an inspection of both vessels by an outside testing company. The testing company completed their inspections of the deareator heater and storage tank. There were no issues with the inspections that were conducted. The NAES Maintenance Staff and Operations staff cleaned out the industrial waste water neutralization pit in preparation to the installation of a new pit liner. A vendor installed a new liner in the pit and once complete staff members reinstalled equipment that had been taken out of service to expedite the liner installation. The neutralization pit is now in service. The NAES IC&E Staff and STI-CEMS completed the quarterly audit of the opacity monitors at the McKee Run and VanSant Generating Stations. All of the opacity monitors passed the audit with no issues. 22

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: All work planned is now complete. Follow-up activities include contacting suppliers for the replacement of the damaged rotor expansion instrumentation. This equipment is obsolete and will be replaced with current technology. Replacement of other turbine supervisory instrumentation will also be investigated. High vibration experienced EG1212 Unit 3 Turbine Repairs during hot starts will require an additional balancing. Plant staff is collecting data that will help determine where and how much balance weight will need to be installed in the next outage. Schedule: Continuing to pursue the replacement rotor expansion instrumentation and evaluate balancing of turbine-generator for Spring 2015 Outage. Progress: Contractor began work on September 29 and continued work throughout the month. Fill material, transitional sections, several louvers to gain access to the fill section were removed as well as a number of defective columns were removed and replaced. Unit #3 Cooling EG1402 Schedule: Demolition activities in the fill area of additional columns Tower Repairs (defective) and hot water basin planking will continue into November. Project is behind schedule and additional funds will be needed to address failed support columns within the fill section, particularly in the middle sections below the water line header. Progress: The recently completed hanger adjustments were checked with the unit in the hot (running) position. Minor adjustments are needed on several hangers and will attempt to complete in the coming months. Future operations should provide an opportunity to check the adjustments. McKee Run HEP Pipe EG1406 One section of pipe identified as thinning was replaced by boiler Repairs contractor. FAC Inspection was conducted in late October with a preliminary report that there are no issues. Final report to be provided within the next several weeks. Schedule: Final report expected in November or December time period. Progress: Work scope is still being developed for an RFP. COD staff is Metering System continuing their efforts to remake the communication link with Cartanza. EG1407 Upgrades Schedule: Work activities are moving forward. Working with COD staff to finalize RFP documents for release later in the calendar year. Progress: Plant received the construction permit from the DNREC and will continue with installation plans. VanSant Capacity Schedule: Equipment skids arrived in early October and were installed on EG1416 Increase the newly poured foundations (once they cured). Other miscellaneous materials are on order including the MCC sections and are currently waiting for delivery. Progress: Work scopes being developed for the Spring 2015 Outage. Unit #3 Auxiliary Some work in process of being completed for Fall 2014 Outage. EG1503 System Component Schedule: Fall 2014 work commenced in October. Spring 2015 Outage Replacement work scopes being developed. 23

Progress: Work scopes being developed for the Spring 2015 Outage. Unit#3 Boiler System Some work in process of being completed for Fall 2014 Outage. EG1504 Repairs Schedule: Fall 2014 work commenced in October. Spring 2015 Outage work scopes being developed. VanSant Station Progress: Work scope is being deferred until next FY. EG1505 Component Schedule: Work scopes will continue to be developed for next fiscal year. Replacement Progress: Work scopes developed and sent out for bids and award in early September. Bids were reviewed, evaluated and contracts awarded. McKee Run/VanSant EG1506 Schedule: Work activities planned for completion in Fall 2014 outage and Safety Improvements spring 2015. Parts are on order and expected to arrive in late November and early December. McKee Run Units #1- Progress: Project on Hold EG1507 #2 Component Schedule: Project on Hold Replacement Progress: Plant staff completed development of paint specifications and bid requests were to be received in mid-August. McKee Run/VanSant EG1508 Schedule: Bids will be evaluated and determination made thereafter as to Structural Preservation how to proceed. Work will need to be completed in warmer temperatures, spring 2015 6.0 General Plant Information Aaron Jester, Senior Operator II, decided to pursue an opportunity elsewhere in the power industry. His last day was October 16 on which send-off celebration was held to say farewell and wish him good luck on his future endeavor. Kathleen Cooper, Administrative Assistant, submitted her resignation on October 23 with her final date of employment as November 7. On-going efforts are being made to fill two (2) open Operator positions and one (1) Administrative Assistant. Training: Plant employees continue General Physics environmental courses to enhance their overall knowledge of permit requirements. As the GPI courses are being completed the employee reviews the permit and then has to score a minimum 80% on a quiz before they can complete the training on the permit. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Precautions for All Workers during the Flu Season”. 24

Calendar of Events Date Annual VanSant Black Start Test TBD Units 1, 2, 3 and 11 Fall Outage Starts September 29, 2014 NOx Ozone Season Ends September 30, 2014 Four Year Accident Free October 14, 2014 NPDES Permit Expires (DNREC has Extended) November 1, 2014 Winter Capacity Period December 1, 2014 to February 28, 2015 NOx Emissions Reconciliation Due March 1, 2015 SO2 Emissions Reconciliation Due March 1, 2015 SARA III / Tier II Report Due March 1, 2015 Units 1, 2, and 3 Spring Outage TBD – Spring 2015 Unit 11 Spring Outage TBD – Spring 2015 Air Emission Inventory April 30, 2015 NOx Ozone Season Starts May 1, 2015 PJM Summer Capacity Test Period June 1, 2015 – August 31, 2015 FY 2014-201454 Budget Year Begins July 1, 2015 Toxic Release Inventory (TRI) Annual Report July 1, 2015 Semi-Annual Title V Certification Due July 31, 2015 7.0 Summary of NAES Performance to Date Plant Performance FY 2014-2015 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.00% 0.05% $94,679 $96,875 Unavailability (CU) Safety 0 0 $18,163 $18,163 Environmental 0 0 $18,163 $18,163 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes No $3,634 $3,634 Unit 2 No No Yes No $3,634 $3,634 Unit 3 No No Yes No $21,797 $21,797 Unit 11 No No Yes No $7,266 $7,266 Total YTD 98.7% Total YTD Incentive $167,335 $169,532 Incentive % Note*: All units have successfully completed the Summer (FY 2014-2015) Testing for PJM and are now entered in the PJM Winter Capacity Test Exemption Program. 25

III. Appendix 1 – PJM Invoice Breakdown Gen Load Grand Total 480-8102-592-95-49 Capacity Resource Deficiency ($2,321.16) ($2,321.16) Capacity Transfer Rights $60.76 $60.76 Locational Reliability $814,257.78 $814,257.78 480-8102-592-95-49 Total $811,997.38 $811,997.38 480-8102-592-95-50 RPM Auction ($725,758.98) ($725,758.98) 480-8102-592-95-50 Total ($725,758.98) ($725,758.98) 480-8102-592-95-90 Auction Revenue Rights ($55,170.70) ($55,170.70) Balancing Operating Reserve $4,149.14 $4,149.14 Balancing Operating Reserve for Load Response $0.78 $0.78 Black Start Service $1,948.73 $1,948.73 CT Lost Opportunity Cost Allocation ($48.36) ($48.36) Day-Ahead Load Response Charge Allocation $247.02 $247.02 Day-ahead Operating Reserve $8,956.90 $8,956.90 Day-ahead Operating Reserve for Load Response $0.05 $0.05 Expansion Cost Recovery $408.27 $408.27 FERC Annual Recovery $3,914.41 $3,914.41 Generation Deactivation Refund ($686.54) ($686.54) Load Reconciliation for Transmission Losses $67.01 $67.01 Market Monitoring Unit (MMU) Funding $224.37 $224.37 Michigan - Ontario Interface Phase Angle Regulators $206.26 $206.26 Network Integration Transmission Service $420,278.16 $420,278.16 Non-Firm Point-to-Point Transmission Service ($347.00) ($347.00) Non-Synchronized Reserve $454.01 $454.01 North American Electric Reliability Corporation (NERC) $596.63 $596.63 Organization of PJM States, Inc. (OPSI) Funding $39.01 $39.01 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,627.89 $1,627.89 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $952.63 $952.63 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $9,434.72 $9,434.72 PJM Scheduling, System Control and Dispatch Service - Market Support $2,166.35 $2,166.35 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($217.45) ($217.45) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $86.03 $86.03 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($115.63) ($115.63) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($1,288.07) ($1,288.07) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($297.38) ($297.38) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($14.66) ($14.66) PJM Settlement, Inc. $217.45 $217.45 Reactive Services $2,064.55 $2,064.55 Reactive Supply and Voltage Control from Generation and Other Sources Service $36,269.99 $36,269.99 Real-Time Load Response Charge Allocation $745.87 $745.87 Regulation and Frequency Response Service $14,924.16 $14,924.16 Reliability First Corporation (RFC) $847.56 $847.56 Synchronized Reserve $4,461.82 $4,461.82 Transmission Enhancement $2,554.55 $2,554.55 Transmission Owner Scheduling, System Control and Dispatch Service $4,142.99 $4,142.99 480-8102-592-95-90 Total $463,801.52 $463,801.52 480-8102-592-95-91 Balancing Spot Market Energy ($116,448.91) ($116,448.91) Balancing Transmission Congestion $21,565.05 $21,565.05 Balancing Transmission Losses ($12.42) ($12.42) Day-ahead Spot Market Energy $454,085.78 $454,085.78 Day-ahead Transmission Congestion ($237,718.61) ($237,718.61) Day-ahead Transmission Losses $2,997.46 $2,997.46 Emergency Load Response ($15.64) ($15.64) Inadvertent Interchange $52.83 $52.83 Load Reconciliation for Balancing Operating Reserve $2.72 $2.72 Load Reconciliation for FERC Annual Recovery ($10.87) ($10.87) Load Reconciliation for Inadvertent Interchange ($3.44) ($3.44) Load Reconciliation for Market Monitoring Unit (MMU) Funding ($0.63) ($0.63) Load Reconciliation for Non-Synchronized Reserve ($0.24) ($0.24) Load Reconciliation for North American Electric Reliability Corporation (NERC) ($1.66) ($1.66) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding ($0.11) ($0.11) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service ($31.97) ($31.97) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund $1.57 $1.57 Load Reconciliation for Reactive Services ($33.13) ($33.13) Load Reconciliation for Regulation and Frequency Response Service ($20.56) ($20.56) Load Reconciliation for Reliability First Corporation (RFC) ($2.35) ($2.35) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center ($3.63) ($3.63) Load Reconciliation for Spot Market Energy ($5,905.70) ($5,905.70) Load Reconciliation for Synchronized Reserve ($5.13) ($5.13) Load Reconciliation for Transmission Congestion $734.08 $734.08 Load Reconciliation for Transmission Losses ($163.40) ($163.40) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service ($11.50) ($11.50) Meter Error Correction ($4,263.79) ($4,263.79) 480-8102-592-95-91 Total $114,785.80 $114,785.80 480-8102-592-95-93 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) ($29,467.58) Transmission Losses ($23,685.30) ($23,685.30) 480-8102-592-95-93 Total ($53,152.88) ($53,152.88) Grand Total $ (778,911.86) $ 1,390,584.70 $611,672.84 26

The Energy Authority, Inc. Monthly Management Committee Update – November 2014 December 18, 2014 Prepared by: Robert Trinnear Client Services Manager 904.360.1309 rtrinnear@teainc.org

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

I. Executive Summary A. Power Supply Summary: Overall Power Supply costs were $38,146 under budget driven by lower PJM fees. Dover’s budgeted cost for all power supply (capacity AND energy) was $72.56/MWh. The actual cost of all power supply (capacity AND energy) was $69.90/MWh. The cost of energy alone was $45.82/MWh, versus a budgeted energy cost of $45.69. Dover’s hedge purchases totaled 45,466 MWh, which was 81% of the actual load. The budgeted hedge purchase totaled 33,488, which was 62% of the budgeted load. Dover’s power purchases from hedge transactions totaled $1,897,919. Purchases from PJM (energy and fees) totaled $1,018,352. This number includes DA spot market energy charges of $444,106 and Network Integration Transmission Service charges of $406,721. Dover’s total load was 55,903 MWh versus a forecasted load of 54,377 MWh. Dover’s planned energy purchase from the SunPark solar installation was 912 MWh. Dover’s actual energy purchase from the SunPark installation was 833 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 54,377 55,903 (1,527) Wholesale Load 53,465 55,070 (1,605) Hedged Volume (MWh) 33,488 45,466 (11,978) Unhedged Volume (MWh) 19,977 9,604 10,373 Dover SunPark Volume (MWh) 912 833 79 Renewable Energy Credits Volume 137 182 (45) Hedged Cost ($/MWh) 44.74 41.74 3.00 Unhedged Energy Cost ($/MWh) $ 44.11 $ 59.04 $ (14.93) Solar Energy Cost ($/MWh) $ 115.12 $ 115.97 $ (0.85) Energy Costs ($/MWh) $45.69 $45.82 ($0.13) All-in Costs - Energy, Capacity and RECs ($/MWh) $72.56 $69.90 $2.66 2

B. Generation Summary: Dover generated 0 MWh in the month. Net generation revenue was $459,851 vs. a budget of $290,855. 3

Generation Breakdown: City of Dover Monthly Wholesale Generation Formula November, 2014 Net Generation 0.00 D Production Margin PJM - Generation Economic and Reliability Dispatch $ - A Natural Gas & Oil Consumption Purchases for Generation $ - Natural Gas Transport $0.00 Eastern Shore Cashout $0.00 Oil Consumption $ - Subtotal: Natural Gas & Oil Consumption $ - B Gross Production Margin $ - C = (A + B) $/MWh Generation Production Gross Margin $ - E = (C/D) PJM - Capacity Generation Capacity Credit $ 702,347.40 Black Start and Transmission Losses $ 53,525.66 Subtotal: PJM - Capacity $ 755,873.06 F All in Generation Margin All in Generation Margin Total $ 755,873.06 (G = C + F) 4

C. Emissions Summary: Emissions Allowance Summary through November 30, 2014 McKee Run 3 and VanSant Unit 11 (Dover’s two units covered by the Clean Air Interstate Rule or CAIR) were not operated during the month of November, so there were no additional emissions during this period. CAIR EMISSION ALLOWANCE SUMMARY SO2 NOx Allowances1 Date Action Allowances Seasonal Annual 1/1/09 2008 Carryover 3,240 0 0 1/1/09 2009 Allocation 2,723 53 80 2/1/10 2010 Allocation 2,039 50 78 1/1/11 2011 Allocation 1,988 49 78 4/1/11 2011 Reallocation 2 4 1/11/12 2012 Allocation 1,988 51 80 10/4/2012 2013 Allocation 1,988 49 76 2014 Allocation 1,988 49 76 9/29/09 SO2 Sales (1,500) 11/12/09 NOx Ann. Sales (45) 11/13/09 SO2 Sales (1,410) 11/20/09 NOx Seas. Sales (25) 12/31/09 2009 Emissions2 (1) (6) (13) 12/31/10 2010 Emissions 0 (54) (54) 10/31/10 EPA Linearity Testing Req. (68) (68) 2011 2010 Deficit NOx Purchases 53 22 Aug 2011 Revised 2010 ECMPS data 30 30 Nov 2011 NOx Seas. Sales (DEMEC) (1) 12/31/11 2011 Emissions2 (1) (32) (36) 12/31/12 2012 Emissions2 (1) (37) (37) Nov 2012 NOx Seas. Sales (DEMEC) (2) 2/13/2013 NOx Annual. Sales (DEMEC) (3) 11/15/13 NOx Annual Sales (DEMEC) (5) 12/31/13 2013 Emissions (0) (20) (20) 11/30/14 2014 CYTD Emissions (1) (36) (44) REMAINING ALLOWANCES 13,040 99 201 Due to a series of federal court decisions discussed in previous monthly reports, beginning January 1, 2015 the reinstated CSAPR replaces CAIR. The final CAIR true- ups for 2014 will occur in 2015, after which CAIR allowances will have no value. To 1 Per CAIR, starting in 2009, NOx emissions are governed by a seasonal and annual program. 2 Under CAIR, pre-CAIR SO2 allowances are retired at a rate of 2 allowances for each ton emitted. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. 5

avoid confusion, EPA CAMD will remove all post-2014 CAIR allowances from the Allowance Tracking System on March 3, 2015. While Delaware is included in the CAIR footprint, it is not included in the CSAPR footprint. CAIR allowances cannot be used for CSAPR compliance, so Dover’s CAIR allowances will become valueless when CSAPR is reinstated. The separate Clean Air Act acid rain deposition control program which governs SO2 national allowance trading program will remain in effect, however the CAIR provisions for SO2 will also disappear for Delaware. Market liquidity for CAIR allowances is very low, with few transactions occurring. The following table shows estimated values for Dover’s banked allowances, based on mid- point of bids and offers from Evolution Markets. Mark Value for CAIR Allowances Commodity $/Ton Tons Market Value ICE Settlement as of December 12, 2014 SO2 Allowances (2009 & earlier) $ 0.75 5,089 $ 3,817 SO2 Allowances (2010-12) $ 0.38 3,975 1,510 SO2 Allowances (2013-15) $0.38 3,976 1,511 NOx Allowances - Seasonal $0.003 99 0 NOx Allowances - Annual $10.00 201 2,010 TOTAL $ 8,848 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 adopted a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). 3 No ICE or Broker price was available for seasonal NOx allowances 6

CO2 Allowance Summary (12/15/2014) 1 2 3 4 5 6 7 8 CO2 CO2 Allowances Annual CO2 Allowances (Per Facility, Allocated Cumulative CO2 Tons CO2 Allowance (Sold) Prior to Sale) CO2 Vintage Purchased Allowances Emitted Allowance Balance McKee Balance YTD 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 4 2011 0 36,077 1,234 37,311 (17,746) 19,565 92,729 2012 0 27,058 925 27,983 ( 15,957) 12,026 104,755 2013 0 22,879 1,939 24,818 (10,231) 14,587 119,343 2014 1,000 -0- -0- -0- (25,426) (25,426) 94,917 Dover no longer receives allocations of RGGI allowances (columns 3-5). The cumulative balance can be utilized for generation in 2014 and future years. Note that the 2014 emissions through the end of October are larger than four out of the last five years. Once the banked allowances have been fully utilized, Dover will be required to purchase RGGI allowances through the auctions or through over-the-counter markets. Assuming that Dover does not sell any banked allowances and produces 25,000 tons of CO2 emissions annually, it should be able to maintain a positive balance through around 2018. In anticipation of needing additional RGGI allowances in the future, Dover participated in Auction 26 held on December 3, 2014. It submitted a tiered bid totaling 4,000 allowances. It was awarded 1,000 allowances from its highest price bid, with the auction clearing price of $5.21/ton. Based on the November 18th, 2014 ICE price for the December 2014 strip ($5.30/ton), the estimated market value of Dover’s existing 93,917 ton RGGI allowance bank is $503,060. Renewable Energy Certificates Dover owns two photovoltaic systems totaling 15 kW, consisting of (one 5 kW unit at the Utilities Administration Building and two 5 kW units at the McKee Run generating station. Dover also receives solar energy produced by the 10 MW Dover Sun Park which is owned by White Oak Solar Energy, LLC. In addition to the all of the physical energy 4 2011 and 2012 emissions corrected to match values in RGGI COATS. 7

produced by the Sun Park, Dover receives 15% of Sun Park’s Solar Renewable Energy Credits (SRECS). Dover participates in the Delaware Municipal Electric Corporation’s (DEMEC) Renewable Portfolio Standard (RPS) for compliance with the State of Delaware’s RPS laws applicable to municipal utilities. The first compliance period under DEMEC’s RPS was for the 36 months ending May 2014. Through the end of November 2014, Dover had accumulated a total of 6,281 SRECS from these renewable energy resources, net of 2,941 SREC transferred to DEMEC for retirement in accordance with the RPS requirement for the first compliance period. While Delaware does periodically hold auctions for SRECs, these auctions are for size tiers N1 – N3, E1 and E2. The Dover Sun Park is in the N4 tier for very large facilities. State-wide carve outs for Tier 4 has been fully subscribed, so there is not a market for tier 4 SRECs in Delaware. The nearest viable market for Dover’s SRECs is Pennsylvania. Daily settlement prices from Flett Exchange Environmental services (www.flettexchange.com) were used for 2011/12 through 2014/15 vintage allowances. The December 12, 2014 daily settlement prices for Pennsylvania SRECS are used in the table below. SREC Vintage Market Clearing Price SREC Balance Market Value (June 1 – May 31) 2012/2013 $23.00 1,834 42,182 2013/2014 $30.00 2,735 82,050 2014/2015 $42.00 1,712 71,904 TOTAL 6,281 $202,136 TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard (RPS) which DEMEC is working on. D. Operations Management Summary: During the month of November there were no reportable or lost time accidents or injuries. The facility has now gone 1,508 days without an OSHA recordable accident and 1,508 consecutive days without a lost time reportable accident. There were no Environmental Notices of Violations or exceedances issued. There were two near misses reported. All Units were in a Planned outage during the entire month and therefore had no opportunities to generate for PJM. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of November were $296,022 against a budgeted amount of $440,181 for a favorable variance of $144,159 or 32.75%. The principal reasons for the favorable 8

variance were due to; having one payroll expensed in November rather than the three (3) that were budgeted. This was offset by higher than anticipated electrical costs. E. Risk Management Summary: Forward power prices in PJM are mostly unchanged from last month. The current projected cost of service is below: Blended Monthly Cost Change PY Hedge Ratio ($/MWh) ($/MWh) 2014-15 80% $ 46.77 $ 0.05 2015-16 70% $ 44.21 $ 0.08 2016-17 43% $ 42.98 $ 0.07 2017-18 37% $ 43.41 $ (0.19) 2018-19 15% $ 43.79 $ (0.35) 9

II. Budget Report Budget Actual Variance Nov-14 Nov-14 Gross Load 54,377 55,903 (1,527) Power Supply Hedged Energy $1,498,251 $1,897,919 ($399,668) PJM - Energy, Congestion & Losses $881,253 $567,063 $314,190 PJM - ARR, Transmission and Fees $554,364 $451,289 $103,075 Dover SUN Park Energy $104,985 $96,640 $8,345 Dover SUN Park RECs $26,865 $25,192 $1,673 Management Fees $83,000 $83,000 $0 PJM - Capacity UCAP Obligated Purchased $796,901 $786,369 $10,532 Subtotal - Power Supply $3,945,619 $3,907,473 $38,146 Power Generation O&M Plant O&M $440,181 $296,022 $144,159 Subtotal Generation O&M $440,181 $296,022 $144,159 Power Generation Production Margin PJM - Economic and reliability dispatch $0 $ - $0 Fixed Fuel and Transport Charges $0 $0 $0 Subtotal Generation Production Margin $0 $ - $0 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($716,626) $ (702,347.40) ($14,279) Capacity Replacement Charge $10,800 $ - $10,800 PJM - Black Start & Transmission Losses ($25,210) $ (53,525.66) $28,316 Subtotal - Non-Production Revenue ($731,036) ($755,873) $24,837 SubTotal - All Generation (290,855.00) ($459,851) $168,996 Total - Utilities Cost $3,654,764 $3,447,622 $207,142 Unit Costs Total - Power Supply $72.56 $69.90 $2.66 Total - Power Generation ($5.35) ($8.23) $2.88 Final Cost of Service to City of Dover Ratepayers $67.21 $61.67 $5.54 10

Variance Analysis: Power Supply  Dover consumed 1,527 MWh less than forecast for the month.  PJM transmission and fees were lower than expected with minimal monthly reactive services charges.  This resulted in a net power supply cost of $69.90/MWh, $2.66/MWh below budget.  For the month, the city realized a favorable variance of $38,146 for power supply vs. the monthly budget.  Dover Sun Park generated 79 MWh less than forecast. Generation  Power generation had a favorable budget variance of $168,996.  Plant O&M expenses had a favorable budget variance of $144,159 for the month. 11

Budget Actual Variance YTD YTD Source Formula G = (Net PJM Wholesale Load + PJM load Inschedules + Dover White Oak-Dover SunPark Gross Load 328,797 320,151 8,647 invoice Mwh) Power Supply TEA Deal capture system, verified by settlement checking out Hedged Energy $9,632,220 $11,840,748 ($2,208,528) with counterparties PJM - Energy, Congestion & Losses $5,463,820 $2,816,470 $2,647,350 PJM Invoice PJM - ARR, Transmission and Fees $3,080,486 $2,309,699 $770,787 PJM Invoice White Oak-Dover Dover SUN Park Energy $820,090 $870,316 ($50,226) Invoice White Oak-Dover Dover SUN Park RECs $183,005 $197,089 ($14,084) Invoice Management Fees $415,000 $415,000 $0 Annual Contract PJM - Capacity UCAP Obligated Purchased $4,064,195 $3,992,805 $71,390 PJM Invoice Subtotal - Power Supply $23,658,816 $22,442,128 $1,216,688 A Power Generation O&M Plant O&M $2,524,755 $2,377,862 $146,893 Monthly NAES report Subtotal Generation O&M $2,524,755 $2,377,862 $146,893 B Power Generation Production Margin PJM - Economic and reliability dispatch ($1,339,680) ($1,946,803) $607,123 PJM Invoice Fixed Fuel and Transport Charges TEA Deal capture system, verified by settlement checking out with counterparties and $966,800 $991,866 ($25,066) pipeline. Subtotal Generation Production Margin ($372,880) ($954,937) $582,057 C Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($3,654,797) ($3,573,029) ($81,768) PJM Invoice Budgeted amount for incremental 3.6 mw purchase. Actuals been shown in PJM - Capacity UCAP Obligated Capacity Replacement Charge $55,080 $0 $55,080 purchased. PJM - Black Start & Transmission Losses ($207,780) ($274,727) $66,947 PJM Invoice Subtotal - Non-Production Revenue ($3,807,497) ($3,847,756) $40,259 D SubTotal - All Generation ($1,655,622) ($2,424,830) $769,208 E = (B+C+D) Total - Utilities Cost $22,003,194 $20,017,297 $1,985,897 F = (A+E) Unit Costs Total - Power Supply $71.96 $70.10 $1.86 H = (A/G) Total - Power Generation ($5.04) ($7.57) $2.54 I = (E/G) Final Cost of Service to City of Dover Ratepayers $66.92 $62.52 $4.40 J =( H+I) 12

Operations Management NAES Corporation Dover, Delaware November 2014 Monthly Report Hot Water Basin in Unit 3 Cooling Tower Undergoing Repairs as Part of Cooling Tower Refurbishment 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 November, there were no restricted work days or lost time accidents. The facility has now gone 4 years, one month and 16 days (1,508 days) through November, 2014 without an OSHA Recordable Accident or a Lost Time reportable accident. There were two Near Misses reported in November at McKee Run. The first Near Miss occurred while a NAES employee was assessing work progress on the Unit 3 Cooling Tower restoration work. The NAES employee observed wood debris falling down inside the tower’s fill area. The NAES employee was walking outside the tower. While no one was working inside this section of the tower on any of the lower sections, there was potential to do so because there was no caution tape or other barrier in place that could deter entrance to the area. The NAES employee immediately contacted the NAES liaison who then attempted to contact the contractor foreman. While the NAES employee was waiting for the NAES liaison and the contractor foreman to arrive at the site, he continued to stay in the immediate area to ensure no one entered the tower. However, moments later he observed a contractor laborer enter the cell area to perform cleanup activities in the cold water basin area. The NAES employee immediately asked the worker to get out of the cell area. The worker did as requested. Moments after the worker exited the cold water basin area, several large sections of wood debris fell from overheard. The second Near Miss occurred at the Unit #3 Cooling Tower during restoration work. While evaluating work progress and safety work practices of the contractor at the Unit #3 cooling tower, two NAES employees observed a wooden 2" x 4" teetering on the edge of a work platform inside the 2nd cell approximately 30' high above the concrete basin. Even though no one was working in the basin at the time of the incident, there was a potential for this debris to bounce off the vertical and horizontal support system and ultimately bounce off the concrete basin injuring someone. The wooden debris could have struck a nearby worker working at various levels below the work platform. The contractor’s Supervisor was notified immediately and he subsequently instructed the worker to discard the 2” x 4”. The worker carefully dropped the debris from the work platform and onto the concrete basin while no one was working below. During the month of November, a total of 25.23 tons of Special Waste was generated from the Unit #3 Cooling Tower restoration project. The Special Waste, which is pressure treated wood, was disposed of at Delaware Solid Waste Authority (DSWA) in Sandtown, DE under permit # CSW 14.14. The plant received no Notice of Violations (NOVs) during the month. The November DMR was submitted for the McKee Run site with no NPDES exceedences. Since no units ran in November, there were no opacity deviations from any unit in November. During the month of November, there were no IWW discharges to the Kent County Public Works sewer system. Since there were no monthly discharges, no monthly sample was collected. The November SIU Report was still submitted to Kent County Public Works indicating no discharges occurred. In 2005, the McKee Run Generating Station was classified as a major source of Hazardous Air Pollutants (HAPs) according to 40 CFR 63.9 and 40 CFR 63.7545 because the facility operated three (3) industrial boilers that fired No. 6 fuel oil and had the potential to emit 10 tons of one 15

pollutant-hydrochloric acid. In 2008, the McKee Run Generating Station converted to No. 2 fuel oil. Due to the conversion, the McKee Run Generating Station has requested DNREC to remove the McKee Run Generating Station from the obligations of any regulatory requirements of 40 CFR 63.9 and 40 CFR 63.7545 at this time. As part of the wet compression project at VanSant, Heritage/Crystal Clean was retained to thoroughly clean the interior components of the False Start Drain Tank (oil/water separator). Heritage removed any oily water and solids from the pressure washing project with a vacuum truck. The filter screen media was also replaced. All wastes were transported to Heritage’s licensed treatment facility in Wilmington, DE. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (November) (7/1/14-6/30/15) NOVs 0 0 Opacity Deviations 0 1 Environmental Deviations 0 0 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 2 12 Man Hours Worked 3,768.5 75,272.25 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,508 Days since last Lost Time Accident 1,508 16

CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant* Run McKee Run - Run* (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2013 and 160/78 9/8 earlier 2014 0 71/46 5/3 40/35 - 4/1 0/0 – 0/0 31/11 1/2 Total NOx Allowance Balance 191/89 10/10 *Note – Emissions allowances are deducted according to oldest vintage first or unless otherwise directed. **Note – The facility transferred Ozone Season allowances to a third party. SO2 Allowances Summary SO2 Allowances Available SO2 Allowance SO2 Allowances (Per Unit, Prior to Sale & Total SO2 Tons Emitted– SO2 Allowances Vintage Sold - YTD Reconciliation) U3 and U11 YTD Balance* Unit #3 Unit #11 2013 and 0 10,365 690 2 11,053 earlier 2014 0 1850 138 1 1,987 Total SO2 Allowance Balance 13,040 *Note – Emissions allowances are deducted according to oldest vintage first, 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 2013 and 0 194,244 7,799 82,700** 119,343** earlier 2014 0 0 0 25,426 (25,426) Total CO2 Allowance Balance 93,917** *Note: CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System. Note: All emissions (NOx, SO2 and CO2) totals for 2013 are unofficial. #Note: Additional CO2 Emission Values were added to 2013 balances by RGGI COATS- 7,846.757 for McKee Run and 1,424.677 for VanSant **Note: 2011 and 2012 Emissions in previous reports were incorrect. The October 2014 Report now correctly reflects the actual emissions. NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 2014 0.4 0.6 35.0 0.8 36.8 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 2014 0.8 1.1 39.8 3.7 45.4 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2012 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 2014 0.0 0.0 0.4 0.6 1.0 18

2.0 Financial Financial – Current Month Month – November Actual Budget Variance Personnel 116,654 309,200 192,546 Materials & Supplies 14,574 12,700 (1,874) Administrative Expenses 164,794 118,281 (46,513) Total $296,022 $440,181 $144,159 Financial – Fiscal Year to Date Number of Months – 5 Actual Budget Variance Personnel 1,203,650 1,419,800 216,150 Materials & Supplies 185,685 134,850 (50,835) Administrative Expenses 988,527 970,105 (18,422) Total $2,377,862 $2,524,755 $146,893 2.1 Variance analysis: The actual expenses for the month of November are $296,022 against a budgeted amount of $440,181 for a favorable variance of $144,159 or 32.75%. The variance was due to the following: PERSONNEL EXPENSES – A favorable monthly variance of $192,546 was due to one (1) payroll period being expensed versus the three (3) that were budgeted. Two (2) of the payrolls were invoice timing issues with one being at the beginning of November and one at the end of November. As a result, this impacted three (3) labor accounts – Straight Time, Overtime, and Labor Burdens. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $1,874 was due to higher than budgeted water and sewer costs than was originally budgeted. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $46,513 due to higher than anticipated electricity costs. In addition, the environmental liability insurance was expensed in November and had been budgeted in a previous month. The forecasted expenses for this fiscal year are $6,088,900 expensed versus an approved budget of $6,141,100 thereby realizing a 99.15% expenditure rate. 19

3.0 Operations Unit Operations / Outages / Trips: On September 29, a planned outage was started on all units and is scheduled until December 1, 2014 at 0700 hours on Units 1, 2 and 11. The Unit 3 outage was extended until December 11, 2014 due to continuing work on Unit 3 Cooling Tower. Additional fuel oil was purchased to increase inventories and to take advantage of lower fuel pricing in preparation of possible winter dispatch when natural gas may not be available. Month - November 2014 McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 0.0 0.0 0.0 0.0 0.0 0.0 Starts # 0 0 0 0 0 0 Gross Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Net Generation MWh 0.0 0.0 0.0 0.0 0.0 0.0 Total Auxiliaries MWh 0.0 0.0 0.0 0.0 0.0 0.0 Auxiliaries purchased MWh 25.060 25.060 167.913 218.033 4.479 222.512 Fuel Gas Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Fuel Oil Used Gallons 0.0 0.0 0.0 0.0 0.0 0.0 Total Fuel MMBTU 0.0 0.0 0.0 0.0 0.0 0.0 Net Heat Rate BTU/KWh 0.0 0.0 0.0 0.0 0.0 0.0 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Availability Factor % 0.0 0.0 0.0 0.0 0.0 0.0 Commercial % 0.0 0.0 0.0 0.0 0.0 0.0 Unavailability (CU) Planned Outage Hours Hours 720.000 720.000 720.000 2,160.000 744.000 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 0.0 0.0 0.00.0 0.0 0.0 0.00.0 0.0 0.0 0.0 0.0 Hours HW Boiler Gas Usage MMBTU 706.095 706.095 Pilot Gas Usage MMBTU 0.0 0.0 0.0 0.0 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 20

2014-2015 Fiscal Year-to-Date (5 Months) 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 30.966 35.134 433.682 499.782 17.350 517.132 Starts # 3 5 33 41 5 46 Gross Generation MWh 261.694 252.941 22,525.426 23,040.061 578.081 23,618.142 Net Generation MWh 247.853 233.930 20,511.856 20,993.639 567.702 21,561.341 Total Auxiliaries MWh 142.049 147.219 3,276.542 3,565.810 10.633 3,576.443 Auxiliaries purchased MWh 128.208 128.208 1,313.092 1,569.508 10.254 1,579.762 Fuel Gas Used MMBTU 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 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 3,780.381 3,255.417 238,464.654 245,500.452 7,544.726 253,045.178 Net Heat Rate BTU/KWh 15.253 13.916 11.825 13.664 13.278 13.471 Unit Trips # 1 3 0.0 4 1 5 Capacity Factor % 0.40 0.37 5.48 4.14 0.40 3.30 Availability Factor % 59.01 59.01 58.81 58.94 59.01 58.96 Commercial % 0.0 0.0 0.21 0.07 0.0 0.05 Unavailability (CU) Planned Outage Hours Hours 1,505.000 1,505.000 1,505.000 4,515.000 1,505.000 6,020.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 7.667 7.667 0.0 7.667 Reserve Shutdown Hours 2,136.034 2,131.866 1,725.651 5,993.551 2,149.650 8,143.201 Hours HW Boiler Gas Usage MMBTU 706.095 706.095 Pilot Gas Usage MMBTU 527.631 527.631 1,055.263 1,055.263 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 14-15 Fuel FY 14-15 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (FYTD) (Change) McKee Run (#2 Fuel Oil) 667,988 679,444 15,060 11,456 452,963 234,351 226,481 VanSant 130,879 180,433 51,703 49,554 73,572 111,224 106,861 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through November 2014 Actual Starts Factored Starts Fired Hours VanSant 1372 2,349.75 4,333.90 Since HGP - Dec 2004 261 682.05 950.32 21

Team Report: The Operations staff continued 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 clearing various LO/TO tasks to put equipment back in service to make the units available to the PJM system once the outage is cleared. Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both the Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2014-2015 Summer 2014 (June 1- Aug 31) Winter 2014-2015 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.4 1 17 17* 2 17 17.5 2 17 17* 3 102 103.99 3 102 102* 11 39 39.8# 11 39 39* Total 175 175 Total 175 175 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program. Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 4.0 Maintenance During the month of November, the Plant Maintenance staff continued addressing the backlog of work orders. There were forty-seven work orders issued with thirty-seven 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. 22

Work Order Report November - 2014 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 23 7 6 23 2 44 4 6 42 3 40 0 0 40 4 5 1 0 6 5 13 1 0 14 SW1 0 0 0 1 SW2 0 0 0 0 SW3 0 0 0 0 SW4 0 0 0 0 SW5 0 0 0 0 PM 47 34 25 56 EM 0 0 0 0 Totals 172 47 37 182 Note: PM Work Orders are included in the priority totals Notable activities during the month include: The NAES Maintenance staff assisted Heritage Environmental with the cleaning of the False Start Drain Tank at Vansant Generating Station. The staff changed out the coalescent filter media in the tank after the tank was cleaned. It was then placed back into service. The NAES Maintenance Staff removed and replaced the inlet and by-pass valve for Unit 1 Hotwell. The valves were leaking by causing the Hotwell level to swing causing a possible issue while operating the unit. With the replacement of these valves, the Operations staff will have better control in maintaining the proper hotwell level. The NAES Maintenance Staff assisted the XL Insurance boiler inspector with the inspection the three boilers at the McKee Run Generating Station. There were no issues with any of the inspections of the boilers. While at the site, the boiler inspector also inspected all the non-fired pressure vessels. There were three issues found during the inspection which were promptly corrected while the inspector was at the plant site. 23

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: All work planned is now complete. Follow-up activities include contacting suppliers for the replacement of the damaged rotor expansion instrumentation. This equipment is obsolete and will be replaced with current technology. Replacement of other turbine supervisory instrumentation will also be investigated. High vibration experienced EG1212 Unit 3 Turbine Repairs during hot starts will require an additional balancing. Plant staff is collecting data that will help determine where and how much balance weight will need to be installed in the next outage. Schedule: Continuing to pursue the replacement rotor expansion instrumentation and evaluate balancing of turbine-generator for Spring 2015 Outage. Progress: Contractor began work on September 29 and continued work throughout the month. Fill material, transitional sections, several louvers to gain access to the fill section were removed as well as a number of defective columns were removed and replaced. Unit #3 Cooling EG1402 Schedule: Demolition activities in the fill area of additional columns Tower Repairs (defective) and hot water basin planking were completed in November. Installation of new materials began throughout the month. However, project is behind schedule and additional funds were needed to address failed wood support columns in the Hot Water Basin area. Progress: Work is complete however final report has not yet been McKee Run HEP Pipe EG1406 received. Repairs Schedule: Final report expected in November or December time period. Progress: Work scope is still being developed for an RFP. COD staff is Metering System continuing their efforts to remake the communication link with Cartanza. EG1407 Upgrades Schedule: Work activities are moving forward. Working with COD staff to finalize RFP documents for release later in the calendar year. Progress: No progress made during the month due to plant maintenance support of planned outage. VanSant Capacity Schedule: Electrical equipment due to be received in early December. EG1416 Increase Coordination with contractor to install equipment and make tie-ins is forthcoming. Other miscellaneous materials are on order including the MCC sections and are currently waiting for delivery. Unit #3 Auxiliary Progress: Work scopes being developed for the Spring 2015 Outage. Most EG1503 System Component of work in process of being completed in Fall 2014 Outage. Replacement Schedule: Spring 2015 Outage work scopes being developed. Progress: Work scopes being developed for the Spring 2015 Outage. Unit#3 Boiler System Planned work for Fall 2014 Outage is complete. EG1504 Repairs Schedule: Fall 2014 work commenced in October and was completed in November. Spring 2015 Outage work scopes being developed. VanSant Station Progress: Work scope is being deferred until next FY. EG1505 Component Schedule: Work scopes will continue to be developed for next fiscal year. Replacement 24

Progress: Contract had been awarded and parts were ordered. Schedule: Work activities planned for completion in Fall 2014 outage and McKee Run/VanSant EG1506 spring 2015. Parts are on order and expected to arrive in early December. Safety Improvements Installation will commence once parts arrive. Some work will require planned power outage to accomplish tie-in of circuitry and equipment. McKee Run Units #1- Progress: Project on Hold EG1507 #2 Component Schedule: Project on Hold Replacement Progress: Plant staff completed development of paint specifications and bid requests were to be received in mid-August. McKee Run/VanSant EG1508 Schedule: Bids will be evaluated and determination made thereafter as to Structural Preservation how to proceed. Work will need to be completed in warmer temperatures, spring 2015 6.0 General Plant Information New Administrative Assistant has been hired pending physical examination results. Early December start date is expected. On-going efforts are being made to fill two (2) open Operator positions. Interviews have been held in this effort. Training: Onsite forklift training has been held for Maintenance and Operations staff members by Boyd Lord, Materials Coordinator, on how to use manufacturers forklift attachments. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Safe Driving Tips for Thanksgiving Travel”. 25

Calendar of Events Date Units 1, 2, 3 and 11 Fall Outage Starts September 29, 2014 Four Year Accident Free October 14, 2014 NPDES Permit Expires (DNREC has Extended) November 1, 2014 Winter Capacity Period December 1, 2014 to February 28, 2015 NOx Emissions Reconciliation Due March 1, 2015 SO2 Emissions Reconciliation Due March 1, 2015 SARA III / Tier II Report Due March 1, 2015 Units 1, 2, and 3 Spring Outage TBD – Spring 2015 Unit 11 Spring Outage TBD – Spring 2015 Air Emission Inventory April 30, 2015 NOx Ozone Season Starts May 1, 2015 PJM Summer Capacity Test Period June 1, 2015 – August 31, 2015 FY 2014-201454 Budget Year Begins July 1, 2015 Toxic Release Inventory (TRI) Annual Report July 1, 2015 Semi-Annual Title V Certification Due July 31, 2015 NOx Ozone Season Ends September 30, 2014 Annual VanSant Black Start Test TBD 7.0 Summary of NAES Performance to Date Plant Performance FY 2014-2015 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.00% 0.05% $94,679 $96,875 Unavailability (CU) Safety 0 0 $18,163 $18,163 Environmental 0 0 $18,163 $18,163 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes No $3,634 $3,634 Unit 2 No No Yes No $3,634 $3,634 Unit 3 No No Yes No $21,797 $21,797 Unit 11 No No Yes No $7,266 $7,266 Total YTD 98.7% Total YTD Incentive $167,335 $169,532 Incentive % Note*: All units have successfully completed the Summer (FY 2014-2015) Testing for PJM and are now entered in the PJM Winter Capacity Test Exemption Program. 26

III. Appendix 1 – PJM Invoice Breakdown Gen Load Grand Total 480-8102-592-95-49 Capacity Resource Deficiency ($1,680.86) ($1,680.86) Capacity Transfer Rights $58.80 $58.80 Locational Reliability $787,991.40 $787,991.40 480-8102-592-95-49 Total $786,369.34 $786,369.34 480-8102-592-95-50 RPM Auction ($702,347.40) ($702,347.40) 480-8102-592-95-50 Total ($702,347.40) ($702,347.40) 480-8102-592-95-90 Auction Revenue Rights ($53,198.10) ($53,198.10) Balancing Operating Reserve $3,639.56 $3,639.56 Balancing Operating Reserve for Load Response ($0.68) ($0.68) Black Start Service $2,827.24 $2,827.24 CT Lost Opportunity Cost Allocation ($46.80) ($46.80) Day-Ahead Load Response Charge Allocation $100.74 $100.74 Day-ahead Operating Reserve $5,335.52 $5,335.52 Day-ahead Scheduling Reserve $0.50 $0.50 Expansion Cost Recovery $408.30 $408.30 FERC Annual Recovery $3,949.34 $3,949.34 Generation Deactivation Refund ($676.11) ($676.11) Load Reconciliation for Transmission Losses $35.42 $35.42 Market Monitoring Unit (MMU) Funding $226.23 $226.23 Michigan - Ontario Interface Phase Angle Regulators $191.81 $191.81 Network Integration Transmission Service $406,720.80 $406,720.80 Non-Firm Point-to-Point Transmission Service ($731.64) ($731.64) Non-Synchronized Reserve $785.71 $785.71 North American Electric Reliability Corporation (NERC) $601.94 $601.94 Organization of PJM States, Inc. (OPSI) Funding $39.41 $39.41 PJM Annual Membership Fee $5,000.00 $5,000.00 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,473.30 $1,473.30 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $921.90 $921.90 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $9,518.91 $9,518.91 PJM Scheduling, System Control and Dispatch Service - Market Support $2,183.67 $2,183.67 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($219.43) ($219.43) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $77.99 $77.99 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($111.90) ($111.90) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($1,299.56) ($1,299.56) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($299.87) ($299.87) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($13.28) ($13.28) PJM Settlement, Inc. $219.43 $219.43 Reactive Services $3,274.98 $3,274.98 Reactive Supply and Voltage Control from Generation and Other Sources Service $36,161.63 $36,161.63 Real-Time Load Response Charge Allocation $172.39 $172.39 Regulation and Frequency Response Service $11,362.61 $11,362.61 Reliability First Corporation (RFC) $855.14 $855.14 Synchronized Reserve $5,066.94 $5,066.94 Transmission Enhancement $2,554.55 $2,554.55 Transmission Owner Scheduling, System Control and Dispatch Service $4,180.03 $4,180.03 480-8102-592-95-90 Total $451,288.62 $451,288.62 480-8102-592-95-91 Balancing Spot Market Energy ($33,776.09) ($33,776.09) Balancing Transmission Congestion $1,711.16 $1,711.16 Balancing Transmission Losses ($768.10) ($768.10) Day-ahead Spot Market Energy $444,106.45 $444,106.45 Day-ahead Transmission Congestion $106,659.82 $106,659.82 Day-ahead Transmission Losses $58,220.11 $58,220.11 Inadvertent Interchange ($367.54) ($367.54) Load Reconciliation for Balancing Operating Reserve ($9.63) ($9.63) Load Reconciliation for Day-ahead Scheduling Reserve ($0.01) ($0.01) Load Reconciliation for FERC Annual Recovery ($5.43) ($5.43) Load Reconciliation for Inadvertent Interchange $0.11 $0.11 Load Reconciliation for Market Monitoring Unit (MMU) Funding ($0.30) ($0.30) Load Reconciliation for Non-Synchronized Reserve ($0.22) ($0.22) Load Reconciliation for North American Electric Reliability Corporation (NERC) ($0.83) ($0.83) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding ($0.05) ($0.05) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service ($15.99) ($15.99) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund $0.79 $0.79 Load Reconciliation for Reactive Services ($2.12) ($2.12) Load Reconciliation for Regulation and Frequency Response Service ($17.59) ($17.59) Load Reconciliation for Reliability First Corporation (RFC) ($1.18) ($1.18) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center ($2.18) ($2.18) Load Reconciliation for Spot Market Energy ($3,266.34) ($3,266.34) Load Reconciliation for Synchronized Reserve ($1.30) ($1.30) Load Reconciliation for Transmission Congestion ($322.69) ($322.69) Load Reconciliation for Transmission Losses ($126.73) ($126.73) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service ($5.75) ($5.75) Meter Error Correction ($4,944.96) ($4,944.96) 480-8102-592-95-91 Total $567,063.41 $567,063.41 480-8102-592-95-93 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) ($29,467.58) Transmission Losses ($24,058.08) ($24,058.08) 480-8102-592-95-93 Total ($53,525.66) ($53,525.66) Grand Total $ (755,873.06) $ 1,804,721.37 $1,048,848.31 27

FUND SUMMARY as of 12/10/2014 Total Collected $ 1,093,392.34 DEMEC Admin Fee Paid $ 62,533.12 State Admin Fee Paid $ 24,316.32 Customer Grants Paid $ 533,263.25 Customer Only Grants/Fees Reserved and Amount Owed $ 4,722.50 Community Project Funds Requested - Dov. Lib - Requested $ 1,970,000.00 Community Project Funds Paid - Dov. Lib $ 298,908.32 Energy Depot Fees Paid $ 55,209.64 Efficiency Program Dollars Paid $ 37,268.34 Solar Electric Power Association (SEPA) Fee Paid $ 6,476.41 Unencumbered Funds Available Grants $ 5,694.44 Funds Available for Dover Library $ 65,000.00 Current Grant Payment Delay (Months) 0.0 GRANTS PAID Grant Amount Review Fee Amount Date Grant Paid Applicant Type Paid Paid Owed 9/21/2007 Laura Drew Kelly Geo-Res $ 3,000.00 $ 225.00 $ - 12/5/2007 Domingo Reyes PV-Res $ 12,762.50 $ 750.00 $ - 4/16/2008 Lakeland Commercial Group Geo-NonRes $ 10,800.00 $ 750.00 $ - 6/19/2008 & 08/25/2008 L.D. Shank - Triad Farms PV-NonRes $ 30,000.00 $ 750.00 $ - 10/6/2008 City of Dover PV-NonRes $ 40,820.00 $ 750.00 $ - 10/21/2008 Robert & Cynthia Hartman Geo-Res $ 1,800.00 $ 135.00 $ - 10/21/2008 Robert Varipapa Geo-Res $ 2,400.00 $ 180.00 $ - 2/27/2009 David Jump PV-Res $ 15,000.00 $ 750.00 $ - 2/27/2009 Jakob Seren PV-Res $ 15,000.00 $ 750.00 $ - 2/27/2009 William Sweet PV-Res $ 15,000.00 $ 750.00 $ - 3/31/2009 LD Shank - Triad Farms SHW-NonRes $ 3,000.00 $ 225.00 $ - 3/31/2009 Warren & Joan Seaver Geo-Res $ 3,000.00 $ 225.00 $ - 4/22/2009 William Sweet SHW-Res $ 3,000.00 $ 225.00 $ - 4/28/2009 State of DE/DNREC - DE National PV-NonRes $ 30,000.00 $ 750.00 $ - 4/29/2009 Delaware Primary Care, LLC PV-NonRes $ 30,000.00 $ 750.00 $ - 9/11/2009 NCALL PV-NonRes $ 30,000.00 $ 750.00 $ - 9/11/2009 D.Brian Beckman Geo-Res $ 2,000.00 $ 150.00 $ - 9/21/2009 LSKC Dover, LLC - Kids Cottage PV-NonRes $ 29,925.00 $ 750.00 $ - 10/5/2009 Mark F. Boller Geo-Res $ 3,000.00 $ 225.00 $ - 10/5/2009 John Welgan PV-Res $ 15,000.00 $ 750.00 $ - 11/4/2009 LSKC LLC/ Kids Cottage Geo-NonRes $ 12,000.00 $ 750.00 $ - 3/25/2010 James G. McGiffin Jr. & Kathleen Geo-Res $ 3,000.000 $ 225.000 $ - 3/23/2010 Minaxi Patel PV-Res $ 15,000.000 $ 750.000 $ - 5/28/2010 Nancy Warner Geo-Res $ 1,200.000 $ 90.000 $ - 6/2/2010 David Teel Geo-Res $ 1,800.000 $ 135.000 $ - 6/2/2010 Dewey J. Barich Geo-Res $ 2,400.00 $ 180.000 $ - 7/12/2010 Mike & Sharon Laverty PV-Res $ 5,105.000 $ 382.880 $ - 8/19/2010 James Grilli Geo-Res $ 1,800.00 $ 135.000 $ - 8/19/2010 Michael Noble PV-Res $ 15,000.000 $ 750.000 $ - 9/17/2010 David Teel PV-Res $ 7,500.000 $ 562.500 $ - 3/8/2011 Michael & Carol Apgar PV-Res $ 7,500.000 $ 562.500 $ - 3/17/2011 Elizabeth Murphey School Geo-NonRes $ 9,200.000 $ 690.000 $ - 5/24/2011 Richard Avant Geo-Res $ 2,400.000 $ 180.000 $ - 6/23/2011 Charles Messina Plumbing & SHW-NonRes $ 10,000.000 $ 750.000 $ - 10/4/2011 Charles Bounds Geo-Res $ 1,800.000 $ 135.000 $ - 3/29/2011 Michael J Kopp Geo-Res $ 2,300.000 $ 135.000 $ 37.500 7/8/2011 Psychiatric Access of Central DE PV-NonRes $ 13,187.500 $ 750.000 $ - 3/7/2012 Ruth Ann Piper Geo-Res $ 1,200.000 $ 90.00 $ - 3/7/2012 Robert Hall Geo-Res $ 3,000.000 $ 225.00 $ - 3/7/2012 Elizabeth Murphey School (Bradford Geo-NonRes $ 13,800.000 $ 750.00 $ - 3/7/2012 Elizabeth Murphey School (Florence Geo-NonRes $ 12,000.000 $ 750.00 $ - 3/7/2012 Elizabeth Murphey School Geo-NonRes $ 5,400.000 $ 405.00 $ - 3/7/2012 Elizabeth Murphey School (Garage Geo-NonRes $ 1,800.000 $ 135.00 $ - 3/7/2012 Frank Daniels Geo-Res $ 4,400.000 $ 303.75 $ 26.25 3/7/2012 Elizabeth Murphey School (Sanford Geo-NonRes $ 10,200.00 $ 750.00 $ - 8/15/2012 Chong S. Tamburo-Lepage Geo-Res $ 2,300.00 $ 172.50 $ - 12/19/2012 Christopher W. Los Geo-Res $ 3,000.00 $ 225.00 $ - 1/30/2013 Matthew and Kimberly Chesser Geo-Res $ 3,000.00 $ 225.00 $ - 2/25/2013 Dennis Ho PV-Res $ 6,775.00 $ 508.13 $ - 6/28/2013 John DeMarie Geo-Res $ 3,000.00 $ 225.00 $ - 10/30/2013 James and Corinna Fritsch PV-Res $ 5,287.50 $ 396.56 $ - 10/30/2013 James and Deri Austin PV-Res $ 7,500.00 $ 562.50 $ - 2/28/2014 Calogero Guarraggi PV-Res $ 7,500.00 $ 562.50 $ - 2/28/2014 Elizabeth Murphey School Geo-NonRes $ 3,700.00 $ 277.50 $ - 2/21/2014 Mohammed Fuad Geo-Res $ 3,000.00 $ - $ 225.00 4/8/2014 Holly Pfeifer PV-Res $ 5,750.00 $ - $ 431.25 5/13/2014 Governors Avenue Animal Hospital PV-NonRes $13,550.75 $ - $ 750.00 7/17/2014 Julia M. Pillsbury Geo-Res $ 3,000.00 $ - $ 225.00 11/7/2014 Elizabeth Murphey School Geo - NonRes $ 3,700.00 $ - $ 277.50 11/7/2014 Elizabeth Murphey School Geo - NonRes $ 3,700.00 $ - $ 277.50 Total $ 525,863.25 $ 24,316.32 $ 2,250.00 ARRA RELIEF GRANTS PAID Paid by State Customer System Type Amount 6/10/2011 Arturo Sanchez Solar - PV - Res $ 7,500.00 10/19/2011 John Diamond Enterprise LLC Solar - PV - Com $ 30,000.00 10/19/2011 John Diamond Enterprise LLC Geo HP - Com $ 10,000.00 Total $ 47,500.00 RECEIVED APPLICATIONS Grant Reservation Status Applicant Type Request Review Fee Approved Pending Completion Rex Bell Geo - Res $ 2,300.00 $ 172.50 Total $ 2,300.00 $ 172.50 ENERGY DEPOT FEES SEPA Fees Paid Fee Period Amount Date Measure Cost 3/3/2008 Start-up Fees $ 5,872.50 3/19/2012 2012 Annual Membership $ 2,158.81 4/15/2008 Start-up Fees $ 1,957.50 1/31/2013 2013 Annual Membership $ 2,158.80 4/15/2008 Mar, Apr, May 2008 $ 1,692.13 1/24/2014 2014 Annual Membership $ 2,158.80 7/22/2008 June, July, Aug 2008 $ 1,692.13 10/10/2008 Sept, Oct, Nov 2008 $ 1,692.13 1/2/2009 Dec 08, Jan, Feb 2009 $ 1,692.13 4/3/2008 Mar, Apr, May 2009 $ 1,692.13

7/1/2009 June, July, Aug 2009 $ 1,692.13 9/11/2009 Sept, Oct, Nov 2009 $ 1,692.13 1/4/2010 Dec 09, Jan, Feb 2010 $ 1,692.13 3/29/2010 Mar, April, May 2010 $ 1,692.13 6/30/2010 June, July, Aug 2010 $ 1,692.13 Total $ 6,476.41 10/4/2010 Sept, Oct, Nov 2010 $ 1,692.13 1/3/2011 Dec 2010, Jan, Feb 2011 $ 1,692.13 4/5/2011 Mar, Apr, May 2011 $ 1,692.13 7/8/2011 June, July, Aug 2011 $ 1,692.13 10/4/2011 Sept, Oct, Nov, 2011 $ 1,692.13 1/3/2012 Dec 2011; Jan, Feb 2012 $ 1,692.13 4/5/2012 Mar, Apr, May 2012 $ 1,692.13 7/2/2012 June, July, Aug 2012 $ 1,692.13 10/2/2012 Sept, Oct, Nov 2012 $ 1,692.13 11/30/2012 Dec 12, Jan, Feb 2013 $ 1,692.13 2/25/2013 Mar, Apr, May 2013 $ 1,692.13 7/22/2013 June, July, Aug 2013 $ 1,692.13 8/26/2013 Sept, Oct, Nov, 2013 $ 1,692.13 12/3/2013 Dec 13. Jan, Feb 2014 $ 1,692.13 3/4/2014 Mar, Apr, May 2014 $ 1,692.13 6/4/2014 June, July, Aug 2014 $ 1,692.13 9/4/2014 Sept, Oct, Nov 2014 $ 1,692.13 12/1/2014 Dec 14, Jan, Feb 2015 $ 1,692.13 Total Paid $ 55,209.64 ENERGY EFFICIENCY CAMPAIGNS/EDUCATION PROGRAMS Paid Program Measure Amount 10/21/2008 1,500 CFL Campaign & Educational $ 5,012.29 Reimbursement for Green 12/11/2008 Energy/Information Pamphlets $ 3,459.12 Thermal Imager for Home Audits 3/31/2009 Program $ 5,581.12 Eco @ Home Energy Conserve. 1/4/2011 Calendars $ 20,015.81 Presbyterian Church of Dover - 1/14/2014 Energy Efficiency Grant $3,200.00 Total $ 37,268.34 10/30/2013 Dover Library Community Grant Payment Schedule Dover Library Community Funds Collection - $ 1,970,000.00 Allocation change from Dover Payment Due Date Requested Amount Funds Paid to Date Collections 10/17/2011 $ 48,267.00 $ 48,267.00 12/5/2012 $ 152,141.32 $ 152,141.32 $ 5,021.15 1/2 of Oct 2009 GEF Payment June 1, 2014 $ 98,500 $ 98,500.00 $ 4,783.94 1/2 of Nov 2009 GEF Payment June 1, 2015 $ 98,500 $ 4,813.23 1/2 of Dec 2009 GEF Payment June 1, 2016 $ 98,500 $ 5,454.02 1/2 of Jan 2010 GEF Payment June 1, 2017 $ 98,500 $ 5,147.49 1/2 of Feb 2010 GEF Payment June 1, 2018 $ 98,500 $ 4,897.69 1/2 of March 2010 GEF Payment June 1, 2019 $ 98,500 $ 3,976.14 1/2 of April 2010 GEF Payment June 1, 2020 $ 98,500 $ 5,638.90 1/2 of May 2010 GEF Payment June 1, 2021 $ 98,500 $ 5,645.35 1/2 of June 2010 GEF Payment June 1, 2022 $ 98,500 $ 6,590.60 1/2 of July 2010 GEF Payment June 1, 2023 $ 98,500 $ 7,786.09 1/2 of August 2010 GEF Payment June 1, 2024 $ 98,500 $ 6,415.31 1/2 of Sept 2010 GEF Payment June 1, 2025 $ 98,500 $ 5,327.96 1/2 of Oct 2010 GEF Payment June 1, 2026 $ 98,500 $ 4,787.73 1/2 of Nov 2010 GEF Payment June 1, 2027 $ 98,500 $ 4,939.75 1/2 of Dec 2010 GEF Payment June 1, 2028 $ 98,500 $ 5,452.55 1/2 of Jan 2011 GEF Payment June 1, 2029 $ 98,500 $ 5,410.35 1/2 of Feb 2011 GEF Payment June 1, 2030 $ 98,500 $ 4,646.32 1/2 of March 2011 GEF Payment June 1, 2031 $ 98,500 $ 4,742.22 1/2 of April 2011 GEF Payment June 1, 2032 $ 98,500 $ 4,702.48 1/2 of May 2011 GEF Payment June 1, 2033 $ 98,500 $ 5,664.97 1/2 of June 2011 GEF Payment Total $ 1,970,000.00 $ 298,908.32 $ 6,430.15 1/2 of July 2011 GEF Payment $ 6,916.50 1/2 of Aug 2011 GEF Payment $ 6,149.31 1/2 of Sept 2011 GEF Payment $ 5,243.92 1/2 of Oct 2011 GEF Payment $ 4,829.91 1/2 of Nov 2011 GEF Payment $ 4,531.81 1/2 of Dec 2011 GEF Payment $ 4,990.50 1/2 of Jan 2012 GEF Payment $ 5,071.81 1/2 of Feb 2012 GEF Payment $ 4,828.32 1/2 of March 2012 GEF Payment $ 4,857.07 1/2 of April 2012 GEF Payment $ 4,230.04 1/2 of May 2012 GEF Payment $ 5,711.19 1/2 of June 2012 GEF Payment $ 6,085.89 1/2 of July 2012 GEF Payment $ 7,347.66 1/2 of Aug 2012 GEF Payment $ 6,453.66 1/2 of Sept 2012 GEF Payment $ 4,886.43 1/2 of Oct 2012 GEF Payment $ 4,132.99 1/2 of Nov 2012 GEF Payment $ 5,513.86 1/2 of Dec 2012 GEF Payment $ 5,187.25 1/2 of Jan 2013 GEF Payment $ 5,307.83 1/2 of Feb 2013 GEF Payment $ 4,783.25 1/2 of March 2013 GEF Payment $ 4,903.40 1/2 of April 2013 GEF Payment $ 4,673.21 1/2 of May 2013 GEF Payment $ 5,322.04 1/2 of June 2013 GEF Payment $ 6,352.74 1/2 of July 2013 GEF Payment $ 6,519.11 1/2 of Aug 2013 GEF Payment $ 5,995.23 1/2 of Sept 2013 GEF Payment $ 4,913.73 All of Oct 2013 GEF Payment Allocation Request from Dover 10/30/2013 - DEMEC to direct more money to library $ 8,589.16 All of Nov 2013 GEF Payment $ 8,846.64 All of Dec 2013 GEF Payment $ 9,286.45 All of Jan 2014 GEF Payment $ 10,267.60 All of Feb 2014 GEF Payment $ 8,950.89 All of March 2014 GEF Payment $ 8,960.46 All of April 2014 GEF Payment $ 8,069.10 All of May 2014 GEF Payment $ 9,357.61 All of June 2014 GEF Payment $ 10,776.24 All of July 2014 GEF Payment $ 10,967.67 All of Aug 2014 GEF Payment $ 10,883.75 All of Sept 2014 GEF Payment $ 8,932.20 All of Oct 2014 GEF Payment All of Nov 2014 GEF Payment All of Dec 2014 GEF Payment All of Jan 2015 GEF Payment All of Feb 2015 GEF Payment All of March 2015 GEF Payment $ 377,900.69 Total Collections

City of Dover Electric Revenue Fund FY15 - White Oak Solar Park Incremental Cost Original July August September October November YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 227,139 $ 219,981 $ 185,885 $ 140,672 $ 96,640 $ 870,316 $ 2,067,600 Dover Sun Park - REC's 47,469 42,307 33,221 25,192 - 148,190 378,600 Total Power Supply Cost 274,609 262,288 219,105 165,864 96,640 1,018,506 2,446,200 Non-Solar Power Supply Cost (170,970) (136,533) (97,948) (80,182) (64,155) (549,788) (677,104) Incremental Energy Cost $ 103,639 $ 125,755 $ 121,157 $ 85,682 $ 32,485 $ 468,718 $ 1,769,096 Revenues Customer Sales - Electricity (9,870) (8,024) (7,893) (7,840) (8,061) (41,688) (84,600) Rent Receipts (14,807) - (32,325) (14,807) - (61,939) (101,400) Total Revenues (24,677) (8,024) (40,218) (22,647) (8,061) (103,627) (186,000) Incremental Sun Park Cost $ 78,962 $ 117,731 $ 80,939 $ 63,034 $ 24,424 $ 365,091 $ 1,583,096 MWh Purchased/Generated - Solar 2,217.724 2,006.392 1,602.868 1,213.000 833.320 7,873.304 18,159.000 MWh $ Solar Energy $ 102.42 $ 109.64 $ 115.97 $ 115.97 $ 115.97 $ 110.54 $ 113.86 Solar REC's MWh 332.000 301.000 240.000 182.000 - 1,055.000 MWh $ Solar REC (one month lag)* 142.98 140.56 138.42 138.42 - $ - MWh $ Non-Solar Energy $ 77.09 $ 68.05 $ 61.11 $ 66.10 $ 76.99 Note: Solar REC's are one month behind due to the time the invoice is received.