Anexo

UTILITY COMMITTEE AGENDA APRIL 14, 2014 - 5:00 P.M. CITY HALL COUNCIL CHAMBERS 15 LOOCKERMAN PLAZA DOVER, DELAWARE Public comments are welcomed on any item and will be permitted at appropriate times. When possible, please notify the City Clerk (736-7008 or e-mail at CityClerk@dover.de.us) should you wish to be recognized. AGENDA ADDITIONS/DELETIONS 1. Proposed Amendments to the Retail Customer Demand Response Program (Staff recommends revising the second paragraph of the Retail Customer Demand Response to include energy efficiency) 2. TEA/NAES Report (February) (Staff recommends acceptance of the report) 3. Garrison Oak Technical Park Project Updates A. City Infrastructure (Committee action not required) B. Calpine Energy Center (Committee action not required) C. Dover Sun Park (Committee action not required) 4. Adjournment by 5:25 p.m. /tm S:\AGENDAS-MINUTES-PACKETS-PRESENTATIONS-ATT&EXH\Committee-Agendas\2014\04-14-2014 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 DEPARTMENT OF ORIGIN: City Manager’s Office DATE SUBMITTED: April 8, 2014 PREPARED BY: Scott D. Koenig, P.E., City Manager SUBJECT: Proposed Amendment to the Demand Response Program REFERENCE: N/A RELATED PROJECT: N/A REVIEWED BY: Scott D. Koenig, P.E., City Manager EXHIBITS: Exhibit A – Page 31 of the City of Dover Electric Rates & Tariffs EXPENDITURE REQUIRED: N/A AMOUNT BUDGETED: N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIME TIMETABLE: Implement tariff change upon final approval of City Council. RECOMMENDED ACTION: Revise the 2nd paragraph of the Retail Customer Demand Response to include energy efficiency. BACKGROUND AND ANALYSIS The City of Dover partners with DEMEC to manage our Demand Response Program (DRP). DEMEC functions as our Authorized Designee per our approved tariff. Recently, DEMEC has asked for the City to clarify whether or not Energy Efficiency is included in the Demand Response Program. This inquiry was forwarded to Kirk Betts, Betts & Holt, LLP to review since Mr. Betts functions as the City’s power supply attorney. Mr. Betts has replied as follows: “The intent of the provision was to include PJM’s Demand (Load) Response programs subject to Dover or its authorized designee having oversight of the participant and its performance. At the time this rule was drawn, I believe Dover focused on capacity and ancillary services markets, not the more passive Energy Efficiency program. Demand reduction was important since Dover needed to plan its capacity purchases and wanted to take into account these resources in its planning. “It would be reasonable to include Energy Efficiency under the same terms as the highlighted paragraph. I recommend a short amendment to include “Energy Efficiency” in the highlighted paragraph where the programs are listed, notwithstanding that most of those are ancillary services. “I believe including it is consistent with the intent of the drafters at the time and presumably now, but it should be documented in the rule. Programmatically, Energy Efficiency is bid into the RPM market for up to 4 years, but there is a requirement to demonstrate the change, which Converge would do. It is good to have this information since it does affect the City’s forward energy positions.” Based on Mr. Betts’ opinion, staff proposes the 2nd paragraph (highlighted on the exhibit) be amended to read as follows: “Dover or its authorized designee may allow a Customer to bid DR into PJM’s ancillary services market for energy imbalance, energy efficiency, spinning reserves, supplemental reserves, reactive power and voltage control, or regulation and frequency response ancillary services, subject to the same terms and conditions.”

The Energy Authority, Inc. Monthly Management Committee Update – February 2014 March 27, 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 $1,165,513 over budget due to higher load and higher market prices caused by below normal weather temperatures. Dover’s budgeted cost for all power supply (capacity AND energy) was $81.18/MWh. The actual cost of all power supply (capacity AND energy) was $92.09/MWh. The cost of energy alone was $64.95/MWh, versus a budgeted energy cost of $49.42. Dover’s hedge purchases totaled 41,760 MWh, which was 68% of the actual load. The budgeted hedge purchase totaled 27,840, which was 50% of the budgeted load. Dover’s power purchases from hedge transactions totaled $1,996,784. Purchases from PJM (energy and fees) totaled $2,228,410 with DA Energy purchases totaling $992,520, DA transmission congestion totaling $300,952 and Reactive Services Charges totaling $67,525. Dover’s total load was 61,423 MWh versus a forecasted load of 55,324 MWh. Dover’s planned energy purchase from the SunPark solar installation was 1,151 MWh. Dover’s actual energy purchase from the SunPark installation was 993 MWh. 1

Supply Source Summary: Supply Variance: Budget Actual Variance Gross Load 55,324 61,423 (6,099) Wholesale Load 54,173 60,430 (6,257) Hedged Volume (MWh) 27,840 41,760 (13,920) Unhedged Volume (MWh) 26,333 18,670 7,663 Dover SunPark Volume (MWh) 1,151 993 158 Renewable Energy Credits Volume 173 121 52 Hedged Cost ($/MWh) $ 54.29 $ 47.82 $ 6 Unhedged Energy Cost ($/MWh) $ 42.62 $ 101.27 $ (59) Solar Energy Cost ($/MWh) $ 87 $ 102 $ (15) Energy Costs ($/MWh) $49.42 $64.95 ($15.53) All-in Costs - Energy, Capacity and RECs ($/MWh) $81.18 $92.09 ($10.92) 2

B. Generation Summary: Dover generated 632 MWh in the month. Net generation revenue was $875,148 vs. a budget of $875,310. 3

Generation Breakdown: City of Dover Monthly Wholesale Generation February, 2014 Net Generation for February 632.45 All In Generation PJM - Generation Economic and Reliability Dispatch $ 56,438.97 Generation Capacity Credit $ 1,200,500.00 Black Start and Transmission Losses $ 88,522.50 Natural Gas & Oil Consumption Purchases for Generation $ (80,198.60) Natural Gas Transport $ (4,855.07) Eastern Shore Cashout $ 10,810.80 Oil Consumption $ 3,022.97 Production Margin PJM - Generation Economic and Reliability Dispatch $ 56,438.97 Natural Gas & Oil Consumption Purchases for Generation $ (80,198.60) Natural Gas Transport $ (4,855.07) Eastern Shore Cashout $ 10,810.80 Oil Consumption $ (3,022.97) Gross Production Margin $ (20,826.87) $/MWh Generation Production Gross Margin $ (32.93) 4

C. Emissions Summary: Emissions Allowance Summary through February 28th, 2013 The CAIR units (McKee Run 3 & VanSant) did operate during the month of January, 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 C.Y.T.D. 2013 Emissions (0) (20) (20) 2/28/14 2014 YTD Emissions (1.1) (0) (6.4) REMAINING ALLOWANCES 13,039.9 99 243.6 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). In response to an EPA appeal to the U.S. Supreme Court, the Supreme Court heard arguments on December 10th, 2013. The Court did not indicate when it plans to release an opinion in the CSAPR case. In a related proceeding, at the end of 2013, Governors from eight Northeastern states petitioned EPA to add nine Southern and Midwestern states to the Ozone Transport Region (OTR). If the Supreme Court rules against EPA in the CSAPR case, EPA would need to act on the OTR petition within 18 months of its filing. Market liquidity for CAIR allowances continues to be low, with few transactions occurring. The following table shows estimated values for Dover’s banked allowances, based on broker bids & offers: Mark-to-Market for CAIR Allowances (3/20/2014) Commodity $/Ton Tons Extended (Bid/Offer Avg.) Value SO2 Allowances (2009 & earlier) $ 1.35 5,089 $ 6,870 SO2 Allowances (2010-13) $ 0.65 7,950.9 5,168 NOx Allowances - Seasonal $18.00 99 1,782 NOx Allowances - Annual $40.00 243.6 9,744 TOTAL $23,564 Regional Greenhouse Gas Initiative The State of Delaware is a participant in the Regional Greenhouse Gas Initiative (RGGI). The City of Dover must comply with RGGI by surrendering carbon dioxide (CO2) allowances pursuant to the State of Delaware’s laws (Title 7, Chapter 60, Sub-Title II-A). Delaware has elected a combined emissions allowance allocation/auction mechanism for RGGI, in which 40% of CO2 allowances were allocated to sources for 2009, declining by 8% per year so that by 2014, all CO2 allowances are auctioned. Dover had more than a sufficient number of RGGI allowances allocated to it to cover its requirements through the first compliance period (calendar years 2009-2011). Any unused allowances are carried over (“banked”) for subsequent years. The table below shows RGGI allowance allocations, deductions and the cumulative balance by year (column 8). 6

CO2 Allowance Summary (2/28/2014) 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) 11,793 104,505 3 2013 0 15,032 514 24,818 (10,231) 16,091 119,091 2014 0 -0- -0- -0- (4,458) 114,634 After 2013, Dover no longer receives allocations of RGGI allowances. The Cumulative Balance (column 8) – aka “Banked Allowances”) can be utilized for generation in 2014 and future 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, it will be able to maintain a positive balance through 2016–2025, depending on actual annual energy production in 2012 and beyond. On February 7, 2013, RGGI proposed changes to its Model Rule. The Delaware Department of Natural Resources published the final rule on December 1, 2013 the Delaware Register of Regulations with an effective date of December 11, 20134. NOTE: The new RGGI rule includes a provision which will eliminate some portion of banked allowances in future years. TEA will be investigating the potential impact of this provision on Dover’s RGGI allowance bank. Dover could elect to sell all or a portion of its banked allowances now and re-acquire allowances at a later date; however TEA is currently of the opinion that Dover will be better off retaining its banked allowances for use during future compliance years. The most recent RGGI auction occurred on March 5th, 2014; the auction cleared at $4.00/ton. The next auction will occur on June 4th, 2014. RGGI futures settlement prices posted on Intercontinental Exchange (ICE) on March 20th, 2014 ranged from $4.26 to $4.48/ton, depending settlement month. Based on the March 20th, 2014 3 Includes Q3 2013 allocations of 7,846,757 for McKee Run and 1,424,677 for VanSant. 4 http://regulations.delaware.gov/register/december2013/final/17%20DE%20Reg%20644%2012-01-13.pdf 7

Intercontinental Exchange prices for March, 2014 ($4.26/ton), the value of Dover’s existing 114,634 ton RGGI allowance bank is $488,341. 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. Through the end of January 2014, Dover has accumulated a total of 6,8525 SRECS from these renewable energy resources. The nearest viable market for Dover’s SRECs is Pennsylvania. Pennsylvania’s March 3, 2014 SREC auction cleared separately for 2012/2013 through 2013/2014 vintage allowances. Clearing prices and Dover’s SREC market value estimate are shown in the table below. SREC Vintage Auction Clearing Price SREC Quantity Market Value (June 1 – May 31) $ 4.01 2010/2011 13 $ 52 (Aug-13 Auction) $ 40.01 2011/2012 2,375 95,024 (Jan 2014 Auction) $55.00 2012/2013 2,725 149,875 (March 2014 Auction) $55.00 2013/2014 1,739 96,645 (March 2014 Auction) TOTAL 6,852 $341,596 TEA continues to recommend to Dover to retain these allowances for compliance with its Renewable Portfolio Standard which DEMEC is working on. Once Dover has an approved RPS in place, it may be required to retire a portion of its current SREC balance for compliance in the 2012/13 future compliance year. Any remaining SRECs could be used for the 2013/14 compliance year. NOTE: SRECs in both Delaware and Pennsylvania expire without value after 3 years. Dover currently has thirteen (13) 2010/2011. Based on a recent discussion with DEMEC staff, this expiration provision is not likely to be of concern within the current compliance year. If Dover has not accumulated adequate non-solar RECs, it will need to acquire some from DEMEC for the 2013/2014 compliance year. DEMEC has told TEA that it will likely have sufficient non-solar RECs for Dover’s requirements. Dover can purchase and 5 Includes 121 RECs for Sun Park generation in January 2014 which had not been posted to Dover’s PJM GATS account as of March 24 th, 2014. 8

retire a portion of these non-solar RECs during the current compliance and fiscal years, or it can defer acquisition until the June – August, 2014 time frame, after the exact amount of non-solar REC requirements is known. D. Operations Management Summary: During the month of February there were no reportable or lost time accidents or injuries. The facility has now gone 1,230 days without an OSHA recordable accident and 1,230 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued and there was one opacity deviation on Unit 2 on startup. There were no Near Miss incidents. In the month of February, Units 1, 2, and 3 were not dispatched By PJM. Unit 11 was dispatched once by PJM. Capacity tests for Units 1,2, and 3 were successfully completed. Monthly Budget Variance – The actual expenses attributable to O&M of the two sites for the month of February were $390,956 against a budgeted amount of $355,495 for an unfavorable variance of $35,461 or 9.98%. The principal reasons for the unfavorable variance were due to unscheduled overtime, higher water, sewer, and electrical costs to support unscheduled generation. Also contributing to the unfavorable variance was the timing of insulation repairs which were budgeted later in the year. E. Risk Management Summary: Forward power prices in PJM are higher than last month though out the hedging time horizon. The current projected cost of service is below: Blended Cost Monthly Change PY Hedge Ratio ($/MWh) ($/MWh) 2013-14 78% $ 52.19 $ 0.16 2014-15 65% $ 46.44 $ 0.97 2015-16 46% $ 42.50 $ 0.55 2016-17 18% $ 41.16 $ 0.82 2017-18 10% $ 41.98 $ 1.41 9

II. Budget Report Variance Report: Budget Actual Variance Feb-14 Feb-14 Gross Load 55,324 61,423 (6,099) Power Supply Hedged Energy $1,511,560 $1,996,784 ($485,224) PJM - Energy, Congestion & Losses $1,122,370 $1,890,712 ($768,342) PJM - ARR, Transmission and Fees $395,000 $337,698 $57,302 Dover SUN Park Energy $100,175 $101,681 ($1,506) Dover SUN Park RECs $25,000 $17,301 $7,699 Management Fees $83,000 $83,000 $0 PJM - Capacity UCAP Obligated Purchased $1,253,880 $1,229,322 $24,558 Subtotal - Power Supply $4,490,985 $5,656,498 ($1,165,513) Power Generation O&M Plant O&M $355,770 $390,956 ($35,186) Subtotal Generation O&M $355,770 $390,956 ($35,186) Power Generation Production Margin PJM - Economic and reliability dispatch $0 ($56,439) $56,439 Fixed Fuel and Transport Charges $0 $79,357 ($79,357) Subtotal Generation Production Margin $0 $ 22,918.05 ($22,918) Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($1,200,500) ($1,200,500) $0 Emissions Allowance Sales $0 $0 $0 PJM - Black Start & Transmission Losses ($30,580) ($88,523) $57,943 Subtotal - Non-Production Revenue ($1,231,080) ($1,289,023) $57,943 SubTotal - All Generation (875,310) ($875,148) ($162) Total - Utilities Cost $3,615,675 $4,781,349 ($1,165,674) Unit Costs Total - Power Supply $81.18 $92.09 ($10.92) Total - Power Generation ($15.82) ($14.25) ($1.57) Final Cost of Service to City of Dover Ratepayers $65.35 $77.84 ($12.49) 10

Variance Analysis: Power Supply  Dover consumed 6,099 MWh more than forecast for the month.  PJM energy costs were higher than expected as high market prices occurred during the month driven by the much below normal temperatures. Hedged costs were higher than forecasted due to an additional layering in of hedges. PJM Fees were slightly lower than budget.  Hedges were placed at below budget levels, however higher market prices more than offset this benefit. Higher market prices resulted in a net power supply cost of $92.09/MWh, $10.92/MWh above budget.  For the month, the city realized an unfavorable variance of $1,165,513 for power supply vs. the monthly budget.  Dover Sun Park generated 158 MWh less than forecast. Generation  Power generation had an unfavorable budget variance of $162.  Plant O&M expenses had an unfavorable budget variance of $35,186 for the month. 11

YTD Variance Report: Budget Actual Variance YTD YTD Gross Load 506,540 525,468 (18,928) Power Supply Hedged Energy $17,796,306 $20,427,246 ($2,630,940) PJM - Energy, Congestion & Losses $8,175,287 $13,404,768 ($5,229,481) PJM - ARR, Transmission and Fees $3,160,000 $5,782,737 ($2,622,737) Dover SUN Park Energy $873,015 $1,037,904 ($164,889) Dover SUN Park RECs $200,000 $244,890 ($44,890) Management Fees $664,000 $664,000 $0 PJM - Capacity UCAP Obligated Purchased $10,881,883 $10,684,245 $197,638 Subtotal - Power Supply $41,750,491 $52,245,790 ($10,495,299) Power Generation O&M Plant O&M $3,650,984 $3,598,525 $52,459 Subtotal Generation O&M $3,650,984 $3,598,525 $52,459 Power Generation Production Margin PJM - Economic and reliability dispatch ($230,472) ($5,371,245) $5,140,774 Fixed Fuel and Transport Charges $0 $2,126,863 ($2,126,863) Subtotal Generation Production Margin ($230,472) ($3,244,382) $3,013,910 Power Generation Non-Production Revenue PJM - Generation Capacity Credit ($10,418,625) ($10,418,625) $0 Emissions Allowance Sales $0 $0 $0 PJM - Black Start & Transmission Losses ($274,640) ($940,080) $665,440 Subtotal - Non-Production Revenue ($10,693,265) ($11,358,705) $665,440 SubTotal - All Generation ($7,272,753) ($11,004,561) $3,731,809 Total - Utilities Cost $34,477,738 $41,241,229 ($6,763,490) Unit Costs Total - Power Supply $82.42 $99.43 ($17.00) Total - Power Generation ($14.36) ($20.94) $6.58 Final Cost of Service to City of Dover Ratepayers $68.07 $78.48 ($10.42) 12

III. Operations Management NAES Corporation Dover, Delaware February 2014 Monthly Report New Compliance Coordinator, Mark Gramer 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 February, there were no restricted work days or lost time accidents. The facility has now gone 3 years and 135 days (1,230 days) through February 28, 2014 without an OSHA Recordable Accident or a Lost Time reportable accident. There were no Near Miss incidents during the month. The plant received no Notice of Violations (NOVs) during the month. The February (January Discharge) DMR was submitted for the McKee Run site with no NPDES exceedences. There was one opacity deviation on Unit 2 during unit operations in the month. During the month of February, there were twelve (12) IWW discharges to the Kent County Sewer. Sampling was conducted on one of the discharges, as is required by the IWW Permit. Results have yet to be received. The January SIU Report was submitted to Kent County. Environmental, Health, and Safety Statistics Month Fiscal Year to Date (February) (7/1/13-6/30/14) NOVs 0 0 Opacity Deviations 1 11 Environmental Deviations 0 0 OSHA Recordable 0 0 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 0 2 Man Hours Worked 4,234.75 34,231.00 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 1,230 Days since last Lost Time Accident 1,230 15

Emissions (NOx, CO2 & SO2) All data thru 2/28/14 NOx Summary – Ozone Season (May-Sep) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2011 1.8 1.5 31.4 1.4 36.1 2012 1.2 1.0 35.8 1.0 33.1 2013 1.1 1.7 19.3 1.3 23.4 2014 0.0 0.0 0.0 0.0 0.0 NOx Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2011 1.8 1.5 32.6 2.9 38.8 2012 1.2 1.1 35.8 1.0 36.9 2013 1.1 1.7 19.4 1.3 23.5 2014 0.5 0.5 3.5 2.9 7.4 SO2 Summary - Year (Jan-Dec) Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2011 0.0 0.0 0.1 0.5 0.6 2012 0.0 0.0 0.0 0.1 0.1 2013 0.0 0.0 0.0 0.2 0.2 2014 0.0 0.0 0.5 0.6 1.1 CO2 Allowances Summary CO2 CO2 CO2 Allowances Available Total CO2 CO2 Allowance Allowances (Per Facility, Prior to Tons Emitted Allowance Vintage Sold YTD Sale) Balance McKee Run VanSant 2009 0 60,128 2,056 5,796 56,388 2010 0 48,102 1,645 32,971 16,776 2011 0 36,077 1,234 17,763 19,548 2012 0 27,058 925 15,265 11,793 2013 0 22,879# 1,939# 10,231 14,587 2014 0 0 0 4,458 (4,458) Total CO2 Allowance Balance 114,634 *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 16

CAIR NOx Allowances Summary* NOx Allowances CAIR CAIR NOx Available Total NOx NOx Allowance Balance CAIR NOx NOx Allowances (Per Facility, Prior to Tons Emitted Allowances Allowance Sold YTD Sale) (Yr/ Season) Purchased Vintage McKee McKee VanSant YTD VanSant Run McKee Run - Run (Yr/Season) (Yr/Season) (Yr/Season) VanSant (Yr/Season) 2010 and 3*** 27/0 0/2 earlier 2011 0 77/48 5/3 33/31– 3/1 0/0 - 0/0 42/10 2/2 2012 2** 75/46 5/3 36/36 – 1/1 0/0 - 0/0 39/10 2/0 2013 5** 77/48 5/3 19/19 – 1/1 0/0 - 0/0 58/24 4/2 2014 0 71/46 5/3 3.5/0 - 2.9/0 0/0 – 0/0 67.5/46 2.1/3 Total NOx Allowance Balance 233.5/90 10.1/9 *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 Total SO2 Tons (Per Unit, Prior to Sale & Emitted – SO2 Allowances SO2 Allowance SO2 Allowances Reconciliation) U3 and U11 Balance Vintage Sold - YTD Unit #3 Unit #11 YTD 2010 and earlier 0 4815 276 0 5089 2011 0 1850 138 1 1988* 2012 0 1850 138 1 1988* 2013 0 1850 138 0 1988* 2014 0 1850 138 1.1 1986.9 Total SO2 Allowance Balance 13,039.9 *Note – Emissions allowances are deducted according to oldest vintage first, unless otherwise directed. 17

2.0 Financial Financial – Current Month Month – February Actual Budget Variance Personnel 252,711 251,265 (1,446) Materials & Supplies 13,424 11,150 (2,274) Administrative Expenses 124,821 93,080 (31,741) Total $390,956 $355,495 ($35,461) Financial – Fiscal Year to Date Number of Months – 8 Actual Budget Variance Personnel 1,980,080 2,195,220 215,140 Materials & Supplies 133,521 169,340 35,819 Administrative Expenses 1,304,959 1,286,904 (18,055) Total $3,418,560 $3,651,464 $232,904 2.1 Variance analysis: The actual expenses for the month of February are $390,956 against a budgeted amount of $355,495 for an unfavorable variance of $35,461 or 9.98%. The variance was due to the following: PERSONNEL EXPENSES – An unfavorable monthly variance of $1,446 was due to unscheduled overtime to support generation unit operations, capacity testing, and training. MATERIALS AND SUPPLIES EXPENSES- An unfavorable monthly variance of $2,274 was due to higher water – sewer costs than anticipated in order to support generation unit operations. ADMINISTRATIVE EXPENSES – An unfavorable monthly variance of $31,741 was due to the timing of invoices for plant wide insulation repairs, unanticipated environmental costs, and higher than anticipated electricity costs to support generation unit operations. The forecasted expenses for this fiscal year are $5,807,568 expensed versus an approved budget of $6,015,800 thereby realizing a 96.54% expenditure rate. 18

3.0 Operations Unit Operations / Outages / Trips In the month of February, Units 1, 2, and 3 were not dispatched; Unit 11 was dispatched once by PJM. The capacity tests for Units 1, 2, and 3 were successfully completed in the month of February. Month February 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 4.800 6.750 7.380 18.930 1.116 20.046 Starts # 1 1 1 3 1 4 Gross Generation MWh 57.225 86.008 488.983 632.216 46.050 678.266 Net Generation MWh 55.447 82.026 451.463 588.936 45.969 634.905 Total Auxiliaries MWh 43.031 45.235 225.541 313.807 8.182 321.989 Auxiliaries purchased MWh 41.253 41.253 188.021 270.527 7.372 277.899 Fuel Gas Used MMBTU 837.930 1,015.002 5,765.759 7,618.691 602.888 8,221.579 Fuel Oil Used MMBTU 0.0 0.0 146.715 146.715 0.0 146.715 Fuel Oil Used Gallons 0.0 0.0 1,023 1,023 0.0 1,023 Total Fuel MMBTU 837.930 1,015.002 5,912.474 7,765.406 602.888 8,368.294 Net Heat Rate BTU/KWh 15.112 12.374 13.085 13.523 13.115 13.421 Unit Trips # 0.0 0.0 0.0 0.0 0.0 0.0 Capacity Factor % 0.49 0.72 0.66 0.64 0.17 0.54 Availability Factor % 100.00 100.00 100.00 100.00 100.00 100.00 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 0.00 0.00 0.00 0.00 0.00 0.00 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 0.0 0.0 0.0 0.0 0.0 0.0 Reserve Shutdown Hours 667.200 665.250 664.620 1997.070 670.884 2667.954 Hours HW Boiler Gas Usage MMBTU 1,239.504 1,239.504 Pilot Gas Usage MMBTU 206.584 268.770 475.354 475.354 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. 19

2013-2014 Fiscal Year-to-Date - February McKee McKee McKee MRS VanSant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 135.697 214.032 263.041 612.770 75.655 688.425 Starts # 7 7 16 30 20 50 Gross Generation MWh 959.877 1,413.560 16,424.707 18,798.144 2,615.094 21,413.238 Net Generation MWh 895.980 1,309.804 15,045.322 17,251.106 2,613.006 19,864.112 Total Auxiliaries MWh 301.080 406.037 2,759.126 3,466.243 30.863 3,497.106 Auxiliaries purchased MWh 279.806 322.336 1,380.185 1,982.327 28.046 2,010.373 Fuel Gas Used MMBTU 8,924.901 15,004.575 146,255.584 170,185.060 19,584.819 189,769.879 Fuel Oil Used MMBTU 5,504.840 4,463.354 36,178.243 46,146.437 15,380.547 61,526.984 Fuel Oil Used Gallons 38,567 31,228 252,473 322,268 108,053 430,321 Total Fuel MMBTU 14,429.741 19,467.929 182,433.827 216,331.497 34,965.366 251,296.863 Net Heat Rate BTU/KWh 15.641 14.141 12.613 14.131 13.198 13.898 Unit Trips # 1 1 0 2 5 7 Capacity Factor % 0.90 1.32 2.53 2.17 1.15 1.95 Availability Factor % 75.16 76.53 76.53 76.07 76.53 76.19 Commercial % 0.95 0.04 0.01 0.13 0.0 0.10 Unavailability (CU) Planned Outage Hours Hours 1,369.000 1,369.000 1,369.000 4,107.000 1,369.000 5,476.000 Maintenance Outage Hours 0.0 0.0 0.0 0.0 0.0 0.0 Hours Forced Outage Hours Hours 80.000 0.0 0.0 80.000 0.0 80.000 Reserve Shutdown Hours 4,248.303 4,213.968 4,203.555 12,665.826 4,388.345 17,054.171 Hours HW Boiler Gas Usage MMBTU 4,816.127 4,816.127 Pilot Gas Usage MMBTU 2,375.134 4,694.627 7,069.761 7,069.761 Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 13-14 Fuel FY 13-14 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 267,019 460,013 194,807 192,994 454,725 378,003 5,288 VanSant 72,139 72,224 0 85 146,133 35,000 (73,909) (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. VanSant Lifetime through February 2014 Actual Starts Factored Starts Fired Hours VanSant 1350 2,311.25 4,306.00 Since HGP - Dec 2004 257 643.55 922.42 20

Team Report: Operations personnel continue to support maintenance by working on Preventative Maintenance (PM) work orders and other work orders that they have the necessary skills to successfully complete the task. The Operations Department continues to utilize the Day Shift Workers in both Operations and Maintenance areas to help in maintaining the plant. The operators continue to use the Plant Readiness Program for training and refreshing their plant knowledge on different systems to improve the plant’s reliability. Some of the training involved promotes teamwork with other staff members to work together to find a solution and to promote further discussions on equipment operation. The operators also use the GPi Learning courses to improve their knowledge and skills. The GPI online training which supports plant safety, OSHA, and environmental training requirements are being used by the teams to complete their training for the year. Along with the GPI OSHA training, the operators review the plant’s safety procedures. Capacity Testing – FY 2013-2014 Summer 2013 (June 1- Aug 31) Winter 2013-2014 (Dec 1- Feb 28) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.2 1 17 17.5 2 17 17.8 2 17 18.2 3 102 103.0 3 102 104.4 11 39 40.9# 11 39 44.05# Total 175 178.9 Total 175 184.1 Note: * Denotes Unit is qualified for the PJM Winter Demonstration Period Exemption Program and data has been submitted into the PJM eGADS Note: # Depicts Net Corrected Capacity for Ambient Air Conditions – VanSant Unit only 21

4.0 Maintenance During the month of February, the Plant Maintenance staff continued addressing the backlog of work orders. There were fifty-two work orders issued with ninety-two work orders being completed during the month. There were no safety work orders entered into the plant’s Computerized Maintenance Management System (MP2) during the month. The table below summarizes the monthly work order activities. Work Order Report February - 2014 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Month Month This Month the month 1 20 2 8 14 2 67 9 29 47 3 47 1 12 36 4 6 0 1 5 5 17 0 2 15 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 72 40 40 72 EM 0 0 0 0 Totals 229 52 92 189 Note: PM Work Orders are included in the priority totals Notable activities during the month include: NAES Maintenance Mechanics adjusted Unit 3 cooling tower water distribution flows across the north and south hot water basins during the capacity testing of Unit 3. Equalized water distribution ensures proper cooling of the water. NAES Maintenance Mechanics completed repairs to Units 1 and 2 boiler level sight glass columns. The sight glasses were identified as having poor visibility of the proper water levels as observed from the control room during unit operation events. Each sight glass was disassembled, cleaned and new mica kits installed. Sight glasses operated properly during subsequent unit operations. NAES Maintenance Mechanics removed and repaired various steam and water pipes damaged from extreme weather conditions during the month. The repaired piping was Unit 2 air preheater drain piping, Unit 3 soot blower steam piping and Unit 1 boiler water 22

sample piping to the lab. Each area was removed and replaced with new pipe. No additional work or leaks were observed during February unit operations. NAES IC&E Staff completed repairs to one outdoor eyewash unit. During monthly testing of the eyewash unit, it was discovered that the eyewash water was extremely hot from piping heat tracing cable. IC&E staff installed a temperature controller to better control the water temperature during times of operation. 5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: Cooling Tower decking is 100% complete. Unit #3 Cooling EG1402 Schedule: Remaining inspection work to complete in april-may Tower Repairs timeframe. McKee Run Progress: Work planned for the Fall is 100% complete. Auxiliary Schedule: Remaining Fall outage items were completed in EG1404 Component December. Spring activities to start in March. Replacement VanSant Station Progress: Work planned for the Fall is 100% complete. EG1405 Component Schedule: Project activities for this fiscal year have been completed. Replacement Progress: The recently completed hanger adjustments will need to McKee Run HEP be checked with the unit in the hot (running) position. EG1406 Pipe Repairs Schedule: FAC work inspection vendor selected. Spring work on schedule to start March 10. Progress: Proposal received from vendor. COD and plant personnel have discussed proposal and submitted a list of “to do” items to the Metering System vendor for more information and clarification. EG1407 Upgrades Schedule: Work activities are moving forward. Additional questions have been posed to vendor and work scope is being developed. Waiting on response from vendor. Progress: Work is being planned to be completed in the Spring 2014 McKee outage period. Specifications being written for VanSant breaker EG1408 Run/VanSant Safety installation. Will need to go out for bids once complete. Compliance Items Schedule: Work activities are behind due to Fall Outage activities. McKee Run Natural Progress: Work scheduled for the Spring Outage. EG1409 Gas Block-Bleed Schedule: Work activities are back on track for a Spring Outage Valves completion date. McKee Progress: Plant staff completed development of paint specifications EG1413 and bid requests were received. Run/VanSant 23

Structural Schedule: Bids were received in early September. Work is on hold Preservation due to budget restraints. Progress: Repair vendor selected. Consumables parts have been Unit 3 Turbine EG1212 received. Repairs Schedule: Repair vendor will mobilize March 1 Progress: Cost to be incurred due to repairs on Unit 1 boiler and McKee Run Units turbine were completed in November. EG1415 #1-#2 Component Schedule: Other scope activities being evaluated due to the Repairs announcement to stop operation of units 1 and 2 in 2016. Progress: Capacity increase request is in the PJM queue. Proposals have been received and are being evaluated. Met with DNREC to review the construction permit application. Will submit application VanSant Capacity in March. Facility impact study results provided by PJM indicate no EG1416 Increase additional modifications required. Schedule: Environmental Support contractor is now preparing the Title V Application Modification that will be submitted to the DNREC for project approval. 6.0 General Plant Information The Plant welcomed Mark Gramer as the newly hired Compliance Coordinator on February 19, 2014. Mark brings a wide variety of experience and will be concentrating on learning plant specific requirements for Environmental and Safety issues. 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 as well. Topics discussed during the monthly safety committee meeting were reviewed by the entire staff. The monthly safety topic was on “Take Two For Safety”. Simulation training for PJM operations is scheduled to occur on April 8-9 by a third party vendor. Completion of this training enables plant operators to meet Continuing Education Hours (CEHs) requirements that are part of maintaining their PJM System Ops Certification. 24

Calendar of Events Date Winter Capacity Period December 1, 2013 to February 28, 2014 EIA-860 Report TBD EIA-923 Report TBD NOx Emissions Reconciliation Due March 1, 2014 SO2 Emissions Reconciliation Due March 1, 2014 SARA III / Tier II Report Due March 1, 2014 NPDES Permit Expires (DNREC has Extended) March 4, 2014 (TBD) Units 1, 2, and 3 Spring Outage March 3, 2014 – May 30, 2014 Unit 11 Spring Outage March 3, 2014 – May 30, 2014 Annual VanSant Black Start Test March, 2014 Air Emission Inventory March , 2014 NOx Ozone Season Starts May 1, 2014 PJM Summer Capacity Test Period June 1, 2014 – August 31, 2014 FY 2013-2014 Budget Year Ends June 30, 2014 Toxic Release Inventory (TRI) Annual Report July 1, 2014 Semi-Annual Title V Certification Due July 31, 2014 NOx Ozone Season Ends September 30, 2014 Units 1, 2, 3 and 11 Fall Outage October 1, 2014 Four Year Accident Free October 14, 2014 Annual Title V Certifications Due January 30, 2015 7.0 Summary of NAES Performance to Date Plant Performance FY 2013-2014 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0.16% 0.10% $91,087 $94,882 Unavailability (CU) Safety 0 0 $17,790 $17,790 Environmental 0 0 $17,790 $17,790 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No Yes Yes Yes $3,559 $3,559 Unit 2 No Yes Yes Yes $3,559 $3,559 Unit 3 No Yes Yes Yes $21,349 $21,349 Unit 11 No No Yes Yes $7,117 $7,117 Total YTD 97.71% Total YTD Incentive $162,249 $166,045 Incentive % Note: All units successfully completed the Summer and Winter Capacity (FY 2013-2104) testing for PJM. 25

IV. Appendix 1 – PJM Invoice Breakdown Gen Load Grand Total 480-8102-592-95-49 Capacity Resource Deficiency ($2,438.98) ($2,438.98) Capacity Transfer Rights ($17,372.04) ($17,372.04) Incremental Capacity Transfer Rights ($1,511.33) ($1,511.33) Locational Reliability $1,250,644.08 $1,250,644.08 480-8102-592-95-50 RPM Auction ($1,200,500.00) ($1,200,500.00) 480-8102-592-95-90 Auction Revenue Rights ($24,135.38) ($24,135.38) Balancing Operating Reserve $12,786.92 $12,786.92 Balancing Operating Reserve for Load Response ($2.10) ($2.10) Black Start Service $1,807.59 $1,807.59 CT Lost Opportunity Cost Allocation ($15.68) ($15.68) Day-Ahead Load Response Charge Allocation $2,047.48 $2,047.48 Day-ahead Operating Reserve $7,185.12 $7,185.12 Day-ahead Operating Reserve for Load Response $120.22 $120.22 Day-ahead Scheduling Reserve $253.40 $253.40 Demand Resource and ILR Compliance Penalty ($1,800.96) ($1,800.96) Expansion Cost Recovery $405.14 $405.14 FERC Annual Recovery $4,335.35 $4,335.35 Generation Deactivation Refund ($734.39) ($734.39) Load Management Test Failure ($40.04) ($40.04) Load Reconciliation for Transmission Losses $926.63 $926.63 Market Monitoring Unit (MMU) Funding $284.38 $284.38 Michigan - Ontario Interface Phase Angle Regulators $178.40 $178.40 Network Integration Transmission Service $292,660.14 $292,660.14 Non-Firm Point-to-Point Transmission Service ($1,256.59) ($1,256.59) Non-Synchronized Reserve $1,201.68 $1,201.68 North American Electric Reliability Corporation (NERC) $660.83 $660.83 Organization of PJM States, Inc. (OPSI) Funding $43.21 $43.21 PJM Scheduling, System Control and Dispatch Service - Advanced Second Control Center $1,686.33 $1,686.33 PJM Scheduling, System Control and Dispatch Service - Capacity Resource/Obligation Mgmt. $852.60 $852.60 PJM Scheduling, System Control and Dispatch Service - Control Area Administration $10,449.35 $10,449.35 PJM Scheduling, System Control and Dispatch Service - Market Support $2,399.12 $2,399.12 PJM Scheduling, System Control and Dispatch Service - Market Support Offset ($330.65) ($330.65) PJM Scheduling, System Control and Dispatch Service - Regulation Market Administration $75.73 $75.73 PJM Scheduling, System Control and Dispatch Service Refund - Capacity Resource/Obligation Mgmt. ($113.40) ($113.40) PJM Scheduling, System Control and Dispatch Service Refund - Control Area Administration ($1,562.48) ($1,562.48) PJM Scheduling, System Control and Dispatch Service Refund - Market Support ($362.34) ($362.34) PJM Scheduling, System Control and Dispatch Service Refund - Regulation Market Administration ($14.12) ($14.12) PJM Settlement, Inc. $330.65 $330.65 Reactive Services ($67,525.52) ($67,525.52) Reactive Supply and Voltage Control from Generation and Other Sources Service $34,852.13 $34,852.13 Real-Time Load Response Charge Allocation $1,511.75 $1,511.75 Regulation and Frequency Response Service $25,494.49 $25,494.49 Reliability First Corporation (RFC) $938.72 $938.72 Synchronized Reserve $17,617.76 $17,617.76 Transmission Enhancement $9,897.89 $9,897.89 Transmission Owner Scheduling, System Control and Dispatch Service $4,588.58 $4,588.58 480-8102-592-95-91 Balancing Spot Market Energy $464,196.64 $464,196.64 Balancing Transmission Congestion $49,283.75 $49,283.75 Balancing Transmission Losses $28,264.36 $28,264.36 Day-ahead Spot Market Energy $992,520.26 $992,520.26 Day-ahead Transmission Congestion $300,952.38 $300,952.38 Day-ahead Transmission Losses $157,776.37 $157,776.37 Emergency Load Response $302.79 $302.79 Inadvertent Interchange ($2,621.22) ($2,621.22) Load Reconciliation for Balancing Operating Reserve ($343.42) ($343.42) Load Reconciliation for Day-ahead Scheduling Reserve ($1.26) ($1.26) Load Reconciliation for FERC Annual Recovery ($115.16) ($115.16) Load Reconciliation for Inadvertent Interchange $41.30 $41.30 Load Reconciliation for Market Monitoring Unit (MMU) Funding ($7.41) ($7.41) Load Reconciliation for Non-Synchronized Reserve ($2.48) ($2.48) Load Reconciliation for North American Electric Reliability Corporation (NERC) ($19.35) ($19.35) Load Reconciliation for Organization of PJM States, Inc. (OPSI) Funding ($1.34) ($1.34) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service ($399.66) ($399.66) Load Reconciliation for PJM Scheduling, System Control and Dispatch Service Refund $110.90 $110.90 Load Reconciliation for Reactive Services ($5,271.24) ($5,271.24) Load Reconciliation for Regulation and Frequency Response Service ($323.77) ($323.77) Load Reconciliation for Reliability First Corporation (RFC) ($27.68) ($27.68) Load Reconciliation for Schedule 9-6 - Advanced Second Control Center ($43.31) ($43.31) Load Reconciliation for Spot Market Energy ($75,632.06) ($75,632.06) Load Reconciliation for Synchronized Reserve ($157.72) ($157.72) Load Reconciliation for Transmission Congestion ($2,558.48) ($2,558.48) Load Reconciliation for Transmission Losses ($4,571.02) ($4,571.02) Load Reconciliation for Transmission Owner Scheduling, System Control and Dispatch Service ($143.80) ($143.80) Meter Error Correction ($10,496.15) ($10,496.15) 480-8102-592-95-92 Balancing Operating Reserve ($14,781.63) ($14,781.63) Balancing Spot Market Energy ($39,876.85) ($39,876.85) Balancing Transmission Congestion ($1,549.56) ($1,549.56) Balancing Transmission Losses ($230.93) ($230.93) 480-8102-592-95-93 Reactive Supply and Voltage Control from Generation and Other Sources Service ($29,467.58) ($29,467.58) Synchronized Reserve ($3,197.85) ($3,197.85) Transmission Losses ($55,857.07) ($55,857.07) Grand Total $ (1,345,461.47) $ 3,457,731.89 $2,112,270.42 26

City of Dov er Electric Rev enue Fund FY14 - White Oak Solar Park Incremental Cost Original July August September October November December January February YTD Budget Power Supply & Generation Dover Sun Park - Energy $ 187,421 $ 176,372 $ 204,852 $ 120,839 $ 99,447 $ 64,684 $ 82,605 $ 101,681 $ 1,037,902 $ 1,565,800 Dover Sun Park - REC's 43,005 38,516 42,894 25,307 20,875 13,583 17,301 - 201,481 300,000 Total Power Supply Cost 230,426 214,888 247,746 146,146 120,322 78,267 99,906 101,681 1,239,383 1,865,800 Non-Solar Power Supply Cost (180,227) (154,545) (154,590) (100,770) (79,066) (52,006) (146,406) (91,259) (958,868) (898,706) Incremental Energy Cost $ 50,199 $ 60,343 $ 93,156 $ 45,376 $ 41,256 $ 26,261 $ (46,500) $ 10,423 $ 280,515 $ 967,094 Revenues Customer Sales - Electricity (9,404) (7,389) (7,538) (7,662) (7,721) (7,662) (7,907) (7,950) (63,233) (26,300) Rent Receipts (14,446) - - (14,446) - - (14,807) - (43,699) (58,300) Total Revenues (23,850) (7,389) (7,538) (22,108) (7,721) (7,662) (22,714) (7,950) (106,932) (84,600) Incremental Sun Park Cost $ 26,349 $ 52,954 $ 85,618 $ 23,268 $ 33,535 $ 18,599 $ (69,214) $ 2,473 $ 173,582 $ 882,494 MWh Purchased/Generated - Solar 2,052.584 1,815.656 2,000.128 1,179.844 970.972 631.556 806.536 992.788 10,450.064 18,159.000 MWh $ Solar Energy $ 91.31 $ 97.14 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 102.42 $ 99.32 $ 86.23 Solar REC's MWh 307.000 272.000 300.000 177.000 146.000 95.000 121.000 - 1,418.000 MWh $ Solar REC (one month lag)* $ 140.08 $ 141.60 142.98 142.98 142.98 142.98 142.98 $ - $ 142.09 MWh $ Non-Solar Energy $ 87.81 $ 85.12 $ 77.29 $ 85.41 $ 81.43 $ 82.35 $ 181.52 $ 91.92 Note: Solar REC's are one month behind due to the time the invoice is received.