Attachment

UTILITY COMMITTEE AGENDA August 8, 2011 - 5:00 P.M. - Council Chambers - City Hall - City of Dover 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. PACE/NAES Monthly Report (May) 2. Update - Green Energy Funding and Programming 3. Proposed Ordinance #2011-20 - Chapter 110 - Utilities, Article III - Water Service, Division 1 - Generally, Section 110-67 - Private Wells 4. Adjournment by 5:30 P.M. /tm S:\AGENDAS & MINUTES\Committee-Agendas\2011\08-08-2011 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.

4401 Fair Lakes Court Fairfax, VA 22033 USA Phone: 1.703.818.9100 www.paceglobal.com City of Dover May Monthly Report Energy and Operations Management June 23, 2011 This Report was produced by Pace Global Energy Services, LLC (“Pace Global”) and is meant to be read as a whole and in conjunction with this disclaimer. Any use of this Report other than as a whole and in conjunction with this disclaimer is forbidden. Any use of this Report outside of its stated purpose without the prior written consent of Pace Global is forbidden. Except for its stated purpose, this Report may not be copied or distributed in whole or in part without Pace Global’s prior written consent. This Report and the information and statements herein are based in whole or in part on information obtained from various sources as of May, 2011. While Pace Global believes such information to be accurate, it makes no assurances, endorsements or warranties, express or implied, as to the validity, accuracy or completeness of any such information, any conclusions based thereon, or any methods disclosed in this Report. Pace Global assumes no responsibility for the results of any actions and inactions taken on the basis of this Report. By a party using, acting or relying on this Report, such party consents and agrees that Pace Global, its employees, directors, officers, contractors, advisors, members, affiliates, successors and agents shall have no liability with respect to such use, actions, inactions, or reliance. This Report does contain some forward-looking opinions. Certain unanticipated factors could cause actual results to differ from the opinions contained herein. Forward-looking opinions are based on historical and/or current information that relate to future operations, strategies, financial results or other developments. Some of the unanticipated factors, among others, that could cause the actual results to differ include regulatory developments, technological changes, competitive conditions, new products, general economic conditions, changes in tax laws, adequacy of reserves, credit and other risks associated with City of Dover and/or other third parties, significant changes in interest rates and fluctuations in foreign currency exchange rates. Further, certain statements, findings and conclusions in this Report are based on Pace Global’s interpretations of various contracts. Interpretations of these contracts by legal counsel or a jurisdictional body could differ. Setting the Pace in energy since 1976 Washington • Houston • Columbia • London • Moscow

TABLE OF CONTENTS 1.0 – Executive Summary ..............................................................................................................2 2.0 – Budget Report .......................................................................................................................5 2.1 – Variance Report ..................................................................................................................6 2.2 – Variance Analysis ...............................................................................................................8 3.0 – Energy management .............................................................................................................9 3.1 – Purchased Power .................................................................................................................9 3.2 – Generation Management ...................................................................................................12 3.3 – Emissions and Allowance Management ...........................................................................19 4.0 – Operations Management ....................................................................................................24 Appendices ....................................................................................................................................40 I. PJM Invoice Breakdown ....................................................................................................40 II. Load, All In Energy and all in cost of service table...........................................................41 III. Glossary .............................................................................................................................42 1

1.0 – EXECUTIVE SUMMARY Generation MWh's: Actual v Budget All In Unit Energy Cost - Actual v Budget Actual Load vs Budget Load 30,000 100,000 $94 25,000 $92 75,000 $90 20,000 $88 MWh MWh $/MWh 15,000 50,000 $86 $84 10,000 25,000 $82 5,000 $80 0 $78 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen Budget Actual Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA Purchased Power Management Wholesale load for the month of May was 62,114 MWhs, versus a weather normalized projected load of 58,744 MWhs. Hedged transactions accounted for 51,360 MWhs or 83% of this volume (87% of forecasted load) at a cost of $3.56 million. Spot Market purchases resulted in a PJM charge of $639 thousand (a $662 thousand charge in the Day Ahead market and a $23 thousand credit in the Real Time market). Other PJM related charges accounted for an additional cost of $1.53 million, inclusive of all load related fees. The May Energy Only Unit Cost, excluding capacity obligations and credits, was $2.16/MWh favorable compared to the budgeted value of $80.01/MWh. On January 24, 2011, the City of Dover reviewed and approved Pace’s and NAES’ submittal of a revised budget for Dover’s FY2010-11 (the “Reset Budget”). The purpose of this Reset Budget was to provide a mid-year update as to the anticipated cost-of-service for FY2010-11. Dover’s projected all in Cost of Service for FY2010-11 is $89.87/MWh, or $0.58/MWh favorable as compared to the Reset Budget1. Generation and Asset Management Net generation for the month of May credited by PJM was 1,218 MWhs and the budget did not expect any generation. On May 31 both McKee Unit 3 and Van Sant Unit 11 were dispatched by PJM. In aggregate, Dover’s units were dispatched for 22 hours during the month, creating a generation production margin of $71 thousand (after fuel costs). The McKee units completed its spring outage on May 23 which started on March 28. On May 16, McKee units performed operational testing under natural gas and fuel oil to verify working status of controls modification made to the burner management system. 1 The projected all in Cost of Service is based on YTD actual results for 11 months and 1 month of projected costs. The Reset Budget was reviewed and approved by City of Dover. 2

Emissions Allowance Management Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through May 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 N/A 2003-2006 139 Carryover 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 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (2) (4) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 52 72 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $0.50/ton broker fee for SO2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NO x seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 3

(3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $36,848.75 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $3.75/ton, 3976 post-CAIR SO2 allowances trading at $2.50/ton, 72 NOx annual allowances trading at $195/ton, and 52 NOx seasonal allowances trading at $17.50/ton. EMISSIONS & ALLOWANCE SUMMARY Through May 31, 2011 Allowance Allowance Emissions Emissions Allowances Allowances Allowance Vintage Allocation Month Sold Month Sold Balance SO2 – 2007-10 10,157 N/A 131 N/A 4,847 5,179 SO2 – 2011 1,988 0 2 0 0 1,986 2 NOx Annu – 2009 80 0 13 0 45 22 NOx Seas – 2009 53 0 6 0 25 22 NOx Annu – 2010 78 0 122 0 (22) (22) NOx Seas – 2010 50 0 122 0 (53) (19) NOx Annu – 2011 76 1 4 0 0 72 3 NOx Seas – 2011 51 2 2 0 0 49 Operations Management Summary During the month of May, there were no reportable or lost time accidents or injuries. The facility has now gone 229 days without an OSHA recordable accident and 229 consecutive days without a lost time reportable accident. There were zero Environmental Notices of Violations issued. There were three near miss events and three environmental deviations. Unit 3 was dispatched once and Unit 11 was dispatched twice with one of these dispatches later canceled. Monthly Budget Variance - The actual expenses attributable to O&M of the two sites for the month of May were $445,311. The expenses were $17,203 or 4.02% over the approved budget of $428,108. The principal reason for the negative variance is due to higher than budgeted expenses in electric and combustion turbine maintenance which were partially offset by lower costs in personnel expenses and materials. 2 Approximately 10 tons of NOx emissions resulted from the February 2010 McKee Run testing associated with the Pollution Remediation project and the June 2010 emission testing project. 3 The EPA reallocated 2 additional seasonal NOx allowances into the McKee Run 2011 account. 4

Risk Management Summary Forward PJM power prices were mixed since the last reporting period. Prices increased as above average temperatures were seen across much of the country, pushing the nearer term of the forward curve higher while the further out portion fell slightly. Forward Dover Zone power prices for FY 2011-2012, FY 2012-2013, FY 2013-2014, and FY 2014-2015 all changed by approximately -$0.91/MWh to $0.90/MWh (representing a range of a -1.50% decrease and a 1.71% increase, respectively) compared with the last reporting period. The individual years’ hedge ratios and Cost-of-Service projections are shown in the table below: Wholesale Cost-of-Service Summary (Projected) Date 6/16/2011 Budget June May Apr Cost-of- Cost-of Year-to Cost-of Cost-of Hedge Power Year Service Service Year Service Service 1 Ratio Budget $/MWh Increase $/MWh $/MWh 2010-2011 $82.15 $85.86 88% -3.7% $85.93 $85.83 2011-2012 N/A $79.66 85% -7.2% $79.47 $79.53 2012-2013 N/A $72.93 76% -8.4% $72.91 $73.02 2013-2014 N/A $71.60 48% -1.8% $71.87 $71.96 2014-2015 N/A $71.05 22% -0.8% $71.80 $71.75 1 Note that the "Cost-of-Service" column does not reflect the SREC benefit the City will receive since the SREC prices are currently unknown *Difference in COS from asset management due to generation & O&M **Not inclusive of budget update 5

2.0 – BUDGET REPORT 2.1 – VARIANCE REPORT Budget Actual Variance May-11 May-11 May-11 Load Forecast 58,744 62,114 (3,370) Power Supply Power Supply $3,608,499 $3,560,754 $47,745 Power Supply Management $188,947 $186,272 $2,674 Capacity Charges - Load $1,078,286 $1,078,284 $3 PJM Charges - Load $902,621 $1,088,697 ($186,077) Total - Power Supply $5,778,353 $5,914,007 ($135,654) Generation Plant Operations $428,108 $445,311 ($17,203) Generation Fuel $0 $89,542 ($89,542) Capacity Credits ($1,002,527) ($1,002,528) $0 PJM Credits ($34,012) ($194,319) $160,307 Total - Generation ($608,431) ($661,994) $53,562 Emission Allowance Sales Total - Emission Allowance Sales $0 $0 $0 Total Power Supply & Generation $5,169,922 $5,252,014 ($82,092) Total Power Supply, Generation & Emission Sales $5,169,922 $5,252,014 ($82,092) Unit Costs Total – Power Supply $98.36 $95.21 $3.15 Total - Generation + Emission Sales ($10.36) ($10.66) $0.30 Final Cost of Service to City of Dover Ratepayers $88.01 $84.55 $3.45 6

Budget Actual Variance YTD YTD YTD Load Forecast 685,080 696,363 (11,282) Power Supply Power Supply $43,624,115 $43,394,940 $229,175 Power Supply Management $2,126,745 $2,115,909 $10,835 Capacity Charges - Load $11,650,406 $11,650,406 ($0) PJM Charges - Load $12,147,178 $13,110,533 ($963,355) Total - Power Supply $69,548,443 $70,271,788 ($723,345) Generation Plant Operations $5,224,239 $5,149,111 $75,128 Generation Fuel $3,138,177 $3,465,596 ($327,419) Capacity Credits ($10,845,058) ($10,845,059) $1 PJM Credits ($5,448,591) ($5,880,578) $431,986 Total - Generation ($7,931,234) ($8,110,930) $179,696 Emission Allowance Sales Total - Emission Allowance Sales $11,695 $11,695 $0 Total Power Supply & Generation $61,617,209 $62,160,858 ($543,650) Total Power Supply, Generation & Emission Sales $61,628,904 $62,172,553 ($543,650) Unit Costs Total – Power Supply $101.52 $100.91 $0.61 Total - Generation + Emission Sales ($11.56) ($11.63) $0.07 Final Cost of Service to City of Dover Ratepayers $89.96 $89.28 $0.68 7

2.2 – VARIANCE ANALYSIS Power Supply  Power Supply realized a favorable $48 thousand variance compared to the budget. This favorable variance was primarily due to the timing of Dover’s options purchase and payment of the associated premium. During FY2009-10 the City of Dover purchased Options as insurance to protect Dover from incremental energy cost exposure. The current City of Dover power supply and generation budget indicates that 100% of this purchase was expensed as a Power Supply Cost in the FY2009-10 period; however the FY2010-11 budget accrues this expense monthly.  PJM Charges for Load experienced a negative $186 thousand variance relative to the monthly budget. This variance was driven by Dover’s open position, which was 46% higher than budget. A larger volume of open positions, coupled with higher than projected PJM energy open prices, resulted in a total Open Position cost that was $307 thousand greater than budget. Additional factors contributing to the unfavorable variance included i) a $112 thousand unfavorable variance in PJM Ancillary charges and ii) a $27 thousand unfavorable variance in Transmission Loss Refunds. Offsetting these unfavorable variances were a $170 thousand favorable variances in Load Following and a $97 thousand favorable variance in Basis costs.  For the month the City realized a $138 thousand unfavorable net variance between Power Supply (fixed positions) and PJM Charges for Load (open positions, transmission, etc.). The change in volume resulted in an unfavorable $252 thousand variance, and the change in price resulted in a favorable $114 thousand variance. Hence, all of the unfavorable variance can be attributed to volume changes.  The Power Supply Management variance is merely an estimate at this point. Generation  Plant O&M reported an unfavorable variance of $17 thousand compared to the revised monthly O&M reset Budget of $428 thousand (the overall reset plant budget for FY 2010-11 was approved by the City Council on March, 2011). The timing of electric invoice and higher than expected combustion turbine maintenance resulted in unfavorable variance. 8

3.0 – ENERGY MANAGEMENT 3.1 – PURCHASED POWER Management Highlights  Dover’s May load was 62,114 MWh, which was 5.7% above the weather normalized load of 58,744 MWh. Hedge volumes accounted for 83% of actual load for the month.  The May All In Unit Energy cost (excluding capacity) of $77.85 per MWh is $2.16 per MWh lower than the monthly budget. Actual Load vs Budget Load 100,000 75,000 MWh 50,000 25,000 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Actual 9

All In Unit Energy Cost - Actual v Budget $94 $92 $90 $88 $/MWh $86 $84 $82 $80 $78 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($/MWh) Actual ($/MWh) Budget WA Actual WA 10

Purchased Power Variance Report Budget Actual Variance May-11 May-11 May-11 City of Dover Load Load Obligation (MWh) 58,744 62,114 (3,370) Unit Energy Costs ($ per MWh) Energy Cost (inc. Load Following & Pace Fees) $72.78 $69.08 $3.71 Pass Through $6.30 $7.90 ($1.60) Incentive Fees $0.93 $0.88 $0.05 Total - All In Unit Energy Cost $80.01 $77.85 $2.16 Purchased Power Variance Analysis  The actual Dover load of 62,114 MWh was 5.7% above the projected May load of 58,744 MWh.  The All In Unit Energy Cost was $2.16 per MWh lower than budget due to a decreased load following and basis charges. Offsetting these positive variances was an increased open position volume and a higher than budgeted energy price, an unfavorable PJM Ancillary charge and a lower than projected transmission related refund.  The Management Incentive fee variance on a $/MWh basis is merely an estimate at this point. PJM Power Balancing and Load Related Fees Purchased Power (Hedges): 51,360 MWhs @ $69.33/MWh: $3,560,754 Power Balancing; Additional PJM, and Energy Manager Fee4: $2,353,253 Total Cost to Serve Load (62,114 MWhs) $5,914,007 All In $/MWh load cost inclusive of Energy Management Fees: $95.21/MWh 4 Includes estimated Incentive Fees. 11

3.2 – GENERATION MANAGEMENT  PJM dispatched McKee Run Unit 3 and Van Sant Unit 11 on May 31st for 22 hours. Dover’s units generated 1,218 MWhs in aggregate for the PJM market and the budget did not expect any generation for the month.  The McKee units started a planned outage on March 28 that ended on May 23. On May 16, these units performed operational tests consuming 355 dth of natural gas and 754 gallons of fuel oil no.2. The testing fuel costs are expected under EG1112 and EG1113 projects. Generation MWh's: Actual v Budget 30,000 25,000 20,000 MWh 15,000 10,000 5,000 0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget Gen Actual Gen 12

2010-11 Generation Production Margin v Budget $1,500 Thousands $1,250 $1,000 $750 $500 $250 $0 Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Budget ($) Actual ($) 13

Generation Management Variance Report Budget Actual Variance May-11 May-11 May-11 Self-Supplied Capacity from Gen (MW) McKee Run 1 17 17 0 McKee Run 2 17 17 0 McKee Run 3 100.3 100.3 0 Van Sant 39 39 0 Self Supplied Capacity from Gen (MW) 173.3 173.3 0 Additional Capacity from PJM Incremental Auction 1.7 1.7 0 Total Capacity from Gen (MW) 175 175 0 Gen Capacity Sales to PJM ($/MW.d) $186.12 $186.12 $0.00 Incremental Auction Sales to PJM ($/MW.d) $50.00 $50.00 $0.00 Power Sales Power Sales (MWh) 0 1,218 1,218 Sales Revenue ($ per MWh) $0.00 ($131.51) $131.51 Power Sales Revenue ($) $0 ($160,118.87) $160,119 Variable Fuel & Transport Fuel Oil No.2 Volume - McKee (gal) 0 0 0 Fuel Oil No.2 - McKee ($/gal) $0.00 $0.00 $0.00 Fuel Oil No.2 Cost of Goods Sold - McKee ($) $0 $0.00 $0 Fuel Oil No.2 Volume - Van Sant (gal) 0 0 0 Fuel Oil No.2 - Van Sant ($/gal) $0.00 0.00 $0.00 Fuel Oil No.2 Cost of Goods Sold - Van Sant ($) $0.00 0.00 $0.00 Gas Volume (Dth) 0 14,420 (14,420) Unit Gas Price ($/Dth) $0.00 $5.48 ($5.48) Variable Gas Cost ($) $0.00 $78,991.35 ($78,991.35) Transport ($) $0.00 $10,550.39 ($10,550.39) Variable Gas and Transport Costs ($) $0.00 $89,541.74 ($89,541.74) Variable Fuel & Transport Costs ($) $0.00 $89,541.74 ($89,541.74) Testing $0.00 $0.00 $0.00 Generation Production Margin $0.00 ($70,577.13) $70,577.13 Generation Capacity Payment Total - Generation Capacity Payment ($1,002,527) ($1,002,528) $0 14

Generation Management Variance Analysis Fuel Expense  PJM dispatched Dover’s McKee Run Unit 3 and Van Sant Unit 11 during the month. During that period the units consumed natural gas related to economic power generation. The McKee units also burned natural gas and fuel oil once during the month for operational testing purposes (See “Fuel and Transportation” and “Purchased Commodity Fuel Oil Summary”). The fuel expenses related to operational testing should be accrued under EG1112 and EG1113 projects. Generation Production Margin Transaction Volumes Revenue/(Cost) PJM Invoice for Power Sold 1,218 MWhs $160,118.87 Fuel and Transport 14,420 Dth gas/ 0 gal #2 oil ($78,991.35) 0 gal #2 oil Low Sulfur Generation Production Margin 1,218 MWhs $70,577.13 The following non-production energy revenues and costs are generally fixed and are not directly related to generation dispatch and power production. Effective September 2009 FERC approved the City of Dover’s reactive supply service compensation resulting in approximately $29 thousand of revenue per month. PJM Invoice (Black Start) $4,545 Reactive Supply Credit $29,468 Fuel Oil Tank Heating & Black Start Gas Supply $0 Eastern Shore Demand Charge $0 Eastern Shore Transport and Imbalance Charge $0 Synchronized Reserved Credit $187 Transco Demand Charge $0 Non-Production Energy Revenue/(Costs) $34,200 15

Fuel and Transportation  PJM dispatched McKee Unit 3 and Van Sant Unit 11 for total of 22 hours. The following table provides a summary of spot gas purchases during the month: Date Volume (Dth) Price ($/Dth) Total Commodity Cost ($) Hess Corp 16-May 800 $4.65 $3,720.00 17-May 300 $4.55 $1,365.00 30-May 1,500 $5.20 $7,800.00 31-May 9,000 $5.25 $47,250.00 31-May 4,000 $5.50 $22,000.00 Cash-Out (275) $4.36 ($1,199.00) Sub-Total 15,325 $5.28 $80,936.00 PESCO Sub-Total 0 $0.00 $0.00 NJNG Sub-Total 0 $0.00 $0.00 CIPs (355) $5.48 ($1,944.65) Total 14,970 $5.28 $78,991.35  The operational testing fuel expenses, provided below, should be recorded under the appropriate CIPs projects (EG1113 and EG1112). CIPs Volume (Dth) Price ($/Dth) Total Commodity Cost ($) EG1113 280 $5.48 $1,533.81 EG1112 75 $5.48 $410.84 Sub-Total 355 $5.48 $1,944.65 16

Due to the conversion from #6 residual oil to low sulfur #2 oil, the need for a constant supply of natural gas to heat the #6 oil is no longer required. Some gas will still be required for winter space heating of the building(s). Pace will coordinate with NAES on the procurement of such supply. This expense will now fall under the plant’s utility costs and be paid and budgeted for by the station. Gas Transportation Purchased City of Dover decided not to renew agreements with the Eastern Shore Natural Gas Pipeline (“ESNG”) and TransCo to provide firm natural gas deliveries to the McKee Run and Van Sant stations. The City of Dover previously notified ESNG and TransCo of its intent to terminate these existing firm capacity agreements and, as a result, the City no longer pays firm demand charges or adjustments. ESNG FT Demand Charge $ 0 TransCo FT Demand Charge $ 0 Total Purchases $ 0 Other Gas Purchases Commodity and transportation imbalances on Eastern Shore Pipeline for the month resulted in no charge. The components of this charge are summarized as follows: Eastern Shore Transport and Imbalance Charges Imbalance/Dth Estimated Cost/Dth Estimated Total Cost 276 $4.78 $1,319.28 Transport Volume/Dth $/Dth Total Cost Firm/IT 15,601 $0.5917 $9,231.11 Net Charge $10,550.39 17

Purchased Commodity Fuel Oil Summary McKee Run Unit 3 and Van Sant Unit 11 were dispatched during the month into PJM consuming natural gas. In addition, McKee units 1 & 2 conducted operational testing purposes on May 17th consuming approximately 754 gal of #2 fuel oil. The McKee Run tank must maintain 3 days of load equivalent dispatches for its units. Tank Inventory Estimates as of May 31 Tank Tank Capacity Inventory In Days of Burn (gallon) (gallon) (Typical Dispatch5) McKee Run (#2 Fuel 2,554,105 451,081 3 Oil) Van Sant 258,000 153,043 3 (#2 Fuel Oil) The following table represents fuel oil consumed to test McKee Units 1 & 2. The inventory fuel oil cost of $1,530.62 should be expensed under CIP EG1112 project. May 2011 Fuel Oil Consumption McKee Run Date #2 Oil Inventory Market Price Inventory Market Cost Burns / gal Price ($/gal) ($/gal) Cost 17-May 754 $2.03 NA ($1,530.62) NA Total 754 ($1,530.62) 5 As measured by tank level instruments. Tank levels may change due to oil temperature. 18

3.3 – EMISSIONS AND ALLOWANCE MANAGEMENT Given the regulatory uncertainty surrounding the allowance markets, Dover has elected not to include revenues from emission allowance sales in its 2010-2011 fiscal year budget. Dover purchased and retired 53 NOX seasonal allowances on November 23rd 2010, in order to meet their 2010 NOX seasonal compliance position. Additionally, Dover purchased 22 NOX annual allowances on February 11, 2011, in order to cover their 2010 NOX annual compliance position. In January 2011, Dover was allocated 1,988 SO2 allowances, 42 NOX seasonal allowances, and 76 NOX annual allowances. Dover has the appropriate number of allowances were set aside for retirement (see Exhibit 1). Exhibit 1: Emissions and Allowance Summary through May 31, 2011 2010-2011 EMISSIONS & ALLOWANCE SUMMARY SO2 NOx 1 1 Date Action Allowance Sale Revenue Allowance Sale Revenue 2 Allocation Price Allocation Price Seas. Ann. 1/1/08 2007 Carryover 549 0 -- -- -- 1/1/09 2008 Carryover 2,691 0 1/1/09 2009 Allocation 2,723 -- -- 53 80 -- -- 2/1/10 2010 Allocation 1,988 50 78 1/1/11 2011 Allocation 1,988 49 76 4/1/11 2011 Reallocation 2 N/A 2003-2006 139 Carryover 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 YTD (1) -- -- (6) (13) -- -- 3 Emissions 12/31/10 2010 YTD -- -- -- (54) (54) -- -- Emissions 10/31/10 EPA Linearity (68) (68) Testing Req. 2011 2010 Deficit NOx 53 22 Purchases 12/31/11 2011 YTD (2) (2) (4) Emissions Totals - Allowances 3,189 pre-CAIR -- $0 52 72 -- $0 3,976 CAIR3 $0 $0 Total Revenue $0 Notes: (1) Revenue calculations account for a $.50/ton broker fee for SO 2, $10/ton broker fee for NOx annual and $5/ton broker fee for NOX seasonal. (2) Per the Clean Air Interstate Rule, in 2009, NOx emissions will be governed by a seasonal and annual program. The NOx seasonal emissions pertain only to emissions (May 1 – Sep 30), similar to the previous trading regimen. Annual emissions cover the entire year. 19

(3) CAIR allowances are retired at a rate of 2 allowances for each ton emitted. Pre-CAIR allowances retain a 1 allowance to 1 ton value for compliance. It is assumed that pre-CAIR allowances will be retired before CAIR allowances. Given current dispatch expectations, the market value of the remaining 2007-2011 Dover allowance inventory is approximately $36,848.75 at the time of this report. This represents 3,189 pre-CAIR SO2 allowances trading at $3.75/ton, 3976 post-CAIR SO2 allowances trading at $2.50/ton, 72 NOx annual allowances trading at $195/ton, and 52 NOx seasonal allowances trading at $17.50/ton. SO2 Existing SO2 allowances continue to have little value as the market awaits the release of the final version of the Environmental Protection Agency’s (EPA) Clean Air Transport Rule (Transport Rule). See Figure 1 – SO2 Prices. With an ample bank of existing SO2 allowances in the market and the expectation that the final Transport Rule will require covered facilities to hold and retire SO2 compliance instruments issued under the new program, prices for current vintage or older allowances are expected to remain very low. Figure 1 – SO2 Prices since Last Monthly Report SO2 Allowance Prices (May / June) $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 2009 (pre-CAIR) 2010/2011 (post-CAIR) NOx NOX annual allowance prices rebounded some in the wake of high temperatures in late May and early June (See Figure 2 – NOX Annual Prices since Last Monthly Report.) A hot 2010 summer helped push NOX annual prices near $550/ton. A similarly hot summer this year could place some upward pressure on NOX annual pricing. With that said, as with SO2 allowances, if the Transport Rule implements as expected in 2012, NOX allowances will have no value beyond meeting 2011 compliance requirements. With no incentive to bank allowances, it is unlikely that 20

NOX annual allowances will increase much above current levels, unless generators have vastly underestimated their compliance needs for 2011. NOX seasonal allowances lost some value over last month. Allowances continue to trade in low volumes and around $20/ton (See Figure 3 – NOX 2011.) As with NOX annual and SO2 allowances, new trading rules under the Transport Rule are unlikely to allow current vintage NOX seasonal allowances to qualify for compliance. Figure 2 – NOX Annual Prices since Last Monthly Report NOX Annual Allowance Prices (May / June) $300.00 $250.00 $200.00 $150.00 $100.00 $50.00 $0.00 Figure 3 – NOX Annual Prices since Last Monthly Report NOX Seasonal Allowance Prices (May / June) $20.50 $20.00 $19.50 $19.00 $18.50 $18.00 $17.50 $17.00 $16.50 $16.00 21

SO2 and NOx Outlook The final Transport Rule, setting new emissions trading rules, is expected to be released in June or July and implemented in January 2012. The expectation is that there will be new allowances for SO2 and NOX emissions, leaving little value for the existing bank of allowances beyond this year’s compliance requirements. It is difficult to estimate what the future compliance costs for SO2 and NOX emissions will be under new trading rules with a number of variables still unknown - the release of the final Transport Rule should provide some clarity. Senator Tom Carper (D-Delaware), one of the key proponents of a “legislative fix” to the SO2 and NOX market rules, announced this month that he will not pursue passing a multi-pollutant in this Congress. While there remain some proposals in the House of Representatives to delay EPA implementation of various air pollution rules, expectation is that legislation impacting these markets will not be enacted this year or next. With that, EPA’s Transport Rule will likely be the regulatory mechanism moving forward, although there remains the possibility that lawsuits filed after the final rule is released could delay implementation. RGGI and Federal Carbon Outlook RGGI allowance prices continue to price at very low levels, as the market is substantially over supplied, forcing prices to levels at or near the statutory price floor (see Figure 4 – RGGI Allowance Prices). Figure 4 – RGGI Allowance Prices since Last Monthly Report RGGI Prices (May / June) $1.95 $1.90 $1.85 $1.80 The big news in RGGI has been the announcement from New Jersey Governor Chris Christie that the state will withdraw from RGGI at the end of this year. The announcement is not expected to have an enormous impact on the market, but could be an impetus for other states to 22

follow suit. Although currently there are no expectations of other states exiting the program as New Hampshire, Delaware, and Maine have all recently voted down similar efforts to withdraw from RGGI and New York, Maryland, and Massachusetts, the three largest members in terms of emissions, remain committed to the program. RGGI program administrators are meeting to review program rules as part of their 2012 Comprehensive Review process. With the program over allocated, the major issue is whether anything can be done to lower the cap or limit the amount the existing bank can qualify for compliance. If the program continues with the existing planned caps and banked allowances are permitted for compliance at full value, RGGI allowances are likely to remain near current levels for the next several years. In Congress, there has been little movement or discussion on climate legislation nor is any expected through 2012. EPA will remain the primary driver at the federal level, although has recently announced that they will delay the release of proposed GHG emission limits for power plants, which were originally scheduled to be released this July. Proposed rules are now expected in September, although EPA maintains that final rules will be released in May 2012, as scheduled. 23

4.0 – OPERATIONS MANAGEMENT Management Highlights  During the month of May, there were no restricted work days or lost time accidents. The facility has now gone 229 days without an OSHA recordable accident or a lost time reportable accident. Three Near Misses were recorded for the month.  The plant received no Notice of Violations (NOVs). There was one environmental deviation on the amount of dissolved solids (TDS) going to the outfall. There were three opacity deviations that resulted from testing the updated controls while combusting #2 fuel oil on Unit 1.  The Units 1, 2, and 3 planned outages were cleared on Monday May 23 at 0600 hours.  Unit 11 was dispatched by PJM on May 30 but then the dispatch was cancelled later by PJM. The unit was dispatched on the following day and ran for 8.216 hours. Unit 3 was dispatched on May 31and ran for 13.750 hours. Units 1 and 2 were available but never dispatched.  On May 18, the modifications to the Unit 3 Burner Management System were tested and eventually the test was successful and the system deemed operational.  On May 17th, Erik Petty received a NAES Service Recognition Award from Vincent Scire, Plant Manager, in recognition of completing 10 years of service working at the City of Dover Generating Facilities.  The following is the NAES Monthly Report as submitted to PGAM. 24

NAES Corporation Dover, Delaware May 2011 Monthly Report Erik Petty (left), Operator II, is shown being presented the NAES Service Recognition Award by Vincent Scire, Plant Manager, in recognition of completing 10 years of service working at the City of Dover Generating Facilities. Mr. Petty also received a commemorative polo shirt for passing the PJM System Operator Certification exam. 25

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 26

1.0 Environmental, Health and Safety: During the month of May, there were no restricted work days or lost time accidents. The facility has now gone 229 days without an OSHA recordable accident or a lost time reportable accident. Three Near Misses were recorded for the month. 1) A LO/TO procedure to replace a valve on the caustic system in the VanSant DI was not effectively isolated due to water pressure still remaining on the line as the valve was in the process of being removed. 2) Upon startup, Unit 3 experienced low vacuum. An immediate investigation found that the exhaust hood cover plate was not completely tightened. 3) Scaffold erected to gain access to the Unit 3 expansion joint and ductwork combusted due to exposure to heat emitting from the air heater top guide bearing area during a unit dispatch. Wood planking had been installed directly over the air heater which then got hot and began to smolder. The flames were put out with an extinguisher and the planking was removed. The plant received no Notice of Violations (NOVs). There was one environmental deviation on the amount of dissolved solids (TDS) going to the outfall. There were three opacity deviations that resulted from testing the updated controls while combusting #2 fuel oil on Unit 1. Environmental, Health and Safety Statistics Month Fiscal Year to Date (May) (7/1/10-6/30/11) NOVs 0 0 Opacity Deviations 3 16 Environmental Deviations 1 1 OSHA Recordable 0 1 OSHA LTA's 0 0 First Aid cases 0 0 Restricted Workday Accident 0 0 Near Miss 3 9 Man Hours Worked 4,062.00 99,227.50 Date last OSHA Recordable 10/14/10 Date last Lost Time Accident 10/14/10 Days since last OSHA recordable 198 Days since last Lost Time Accident 198 27

Emissions (NOx & SO2) All data thru 5/31/11 NOx Summary - Year (May-Sept.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 4.2 0.6 6.4 2010 0.7 2.2 119.2 3.3 125.4 2011 0.0 0.0 1.4 0.2 1.6 NOx Summary - Year (Jan. – Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.9 0.7 10.1 0.6 12.3 2010 0.7 2.2 119.2 3.3 125.4 2011 0.0 0.0 2.6 1.7 4.3 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 Van Sant YTD Van Sant Run Run (Yr/Season) (Yr/Season) (Yr/Season) (Yr/Season) 2009 45/25 75/50 5/3 12/5 - 1/1 0/0 – 0/0 18/0 4/2 119**/119** - 22##/53# – 2010 0 73/47* 5/3 -46/0 2/0 3/3 0/0 2011 0 71/48### 5/3 3/1 – 2/0 0/0 - 0/0 68/47### 3/3 Note ** - Higher NOx emissions are attributed to data substitution rules that use significantly higher emission rates than actually were emitted. The implementation of the data substitution rules were caused by performing a linearity test outside the grace period. NAES ESS was able to provide assistance in reducing the NOx emissions from 137 tons to 119 tons since the October report. A petition to the EPA was sent out in February that would result in a reduction in reported emissions. The EPA has given preliminary approval to the petition request although it is not official until the plant receives a signed EPA approval. Until the issue is resolved, the EPA has locked the annual account and no allowances will be deducted until that time. Note# - 53 tons were purchased to help compensate for the shortage in seasonal NOx allowances. Note## - 22 tons were purchased to help compensate for the shortage in annual NOx allowances. Note###- 2 tons were reallocated by the EPA to the McKee Run 2011 account. SO2 Summary - Year (Jan.-Dec.)Tons Year Unit #1 Unit #2 Unit #3 Unit #11 TOTAL 2009 0.05 0.05 0.1 0.2 0.4 2010 0.0 0.0 0.3 0.0 0.3 2011 0.0 0.0 0.1 0.5 0.6 Note: Data is as of 5/31/2011 28

SO2 Allowances Summary SO2 Allowances Available Total SO2 SO2 (Per Unit, Prior to Sale & Tons Emitted SO2 SO2 Allowance Allowances Reconciliation) – Allowances Vintage Sold - YTD U3 and U11 Balance Unit #3 Unit #11 YTD 2003-2006 139 138 1 0 0 2007 2455 2585 138 98 170 2008 2392 2585 138 32 299 2009 0 2585 138 0 2723 2010 0 1850 138 0 1988 2011 0 1850 138 1 1987 Note: Data is as of 5/31/2011 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 Van Sant 2009 0 59,805 1,699 5,796 55,708 2010 0 47,844 1,636 32,971 16,509 2011 0 35,883 1,227 2257 34,853 2012 0 23,922 818 0 24,740 2013 0 11,961 409 0 12,370 Note: All CO2 allowance values are provided by the RGGI CO2 Allowance Tracking System 29

2.0 Financial Financial – Current Month Month –May 2011 Actual Budget Variance Personnel 235,236 250,336 15,100 Materials & Supplies 5,682 20,060 14,378 Administrative Expenses 204,393 157,712 (46,681) Total $445,311 $428,108 (17,203) Financial – Fiscal Year to Date Number of Months - 11 Actual Budget Variance Personnel 2,765,473 2,777,373 11,900 Materials & Supplies 227,577 244,701 17,124 Administrative Expenses 2,156,045 2,133,436 (22,609) Total $5,149,095 $5,155,510 $6,415 2.1 Variance analysis: The adjusted (annual reset) budget for May was $428,108. The actual expenses for May were $445,311 for an unfavorable variance of $17,203 or ≈ 4.02%. The variance was due to the following: PERSONNEL EXPENSES – Lower straight labor, overtime, and labor burdens accounted for a favorable variance of $15,100. MATERIALS AND SUPPLIES EXPENSES- Lower than budgeted expenses in Medical Supplies, Water Treatment Chemicals, Computer Hardware, and City Building Maintenance contributed to realizing a favorable variance of $14,378. ADMINISTRATIVE EXPENSES – Higher than budgeted expenses in the areas of Electric (due to billing cycle – both April and May booked in May), Training / Conference / Food, Environmental Expenses, Home Office Labor, Other Equipment /Maintenance , Radio Repairs - Maintenance, and Combustion Turbine Maintenance costs which contributed to an unfavorable variance of $46,681. The majority of the unfavorable variance was due to Electric billing ($43,000 of the $46,681 variance) The current budget forecast for the current fiscal year is $6,156,900 expensed versus an adjusted budget of $6,163,315 thereby realizing a 99.90%.expense rate. 30

3.0 Operations Unit Operations / Outages / Trips The Units 1, 2, and 3 planned outages were cleared on Monday May 23 at 0600 hours. Unit 11 was dispatched by PJM on May 30 but then the dispatch was cancelled later by PJM. The unit was started twice and was online for 1.420 hours. The unit would come on line but could not raise load due to a blown fuse which affected the ability of the control system to sense the unit was online. The unit was dispatched on the following day and ran with no further problems for 8.216 hours. Unit 3 was dispatched on May 31st and ran for 13.750 hours. Units 1 and 2 were available but never dispatched. Month – May 2011 McKee McKee McKee MRS Van Sant 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 13.750 13.750 9.636 23.386 Starts # 0 0 1 1 3 4 Gross Generation MWh 0.0 0.0 1,021.413 1,021.413 280.167 1,301.580 Net Generation MWh 0.0 0.0 946.317 946.317 279.942 1,226.259 Total Auxiliaries MWh 24.378 24.378 244.201 292.957 2.755 295.712 Auxiliaries purchased MWh 24.378 24.378 169.105 217.861 2.530 220.391 Fuel Gas Used MMBTU 12.228* 12.228* 11,101.389 11,125.845 3,851.820 14,977.665 Fuel Oil Used MMBTU 52.177* 52.177* 0.0 104.354* 0.0 104.354* Fuel Oil Used Gallons 377.00* 377.00* 0.0 754.00* 0.0 754.00* Total Fuel MMBTU 64.405* 64.405* 11,101.389 11,230.199 3,851.820 11,230.199 Net Heat Rate BTU/KWh 0.0 0.0 11,731 11,731 13,759 12.745 Unit Trips # 0 0 0 0 0 0 Capacity Factor % 0.0 0.0 1.35 1.01 0.0 0.78 Availability Factor % 31.45 31.45 31.45 31.45 100.00 48.59 Commercial % 0 0 0 0 0 0 Unavailability (CU) Planned Outage Hours Hours 510.000 510.000 510.000 1,530.000 0.0 1,530.000 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 234.000 234.000 220.250 688.250 734.364 1,422.614 Hours HW Boiler Gas Usage MMBTU 0 0 Pilot Gas Usage MMBTU 38,212.500 38,212.500 76,425.000 76,425.000 # Note: Does not include HWB or Pilot Gas. Fuel usage numbers are taken from fuel flow instruments. * Indicates testing fuel for Units 1 & 2 for the week of May 16. This testing was to operationally check out the controls modifications made to the burner management system during the Spring outage. 31

2010-2011 Fiscal Year-to-Date (11 Months) McKee McKee McKee MRS Van Sant Total Unit 1 Unit 2 Unit 3 Facility Unit 11 All Units Capacity MW 17 17 102 136 39 175 On Line Hours Hrs 13.033 128.966 659.006 801.005 147.426 948.310 Starts # 1 3 45 49 38 87 Gross Generation MWh 154.626 1,216.601 46,591.698 47,962.925 4,915.614 52,878.539 Net Generation MWh 147.111 1,141.623 43,915.013 45,203.747 4,912.183 50,115.930 Total Auxiliaries MWh 334.847 402.309 5,641.134 6,378.290 44.710 6,423 Auxiliaries purchased MWh 327.332 327.332 2,847.249 3,501.913 41.250 3,543.163 Fuel Gas Used MMBTU 2,195.478 15,258.078 463,120.226 480,573.782 57,796.096 538,369.878 Fuel Oil Used MMBTU 52.177 52.177 17,721.260 17,825.614 3,790.097 21,615.711 Fuel Oil Used Gallons 377.00 377.00 125,088 125,842 27,385 153,227 Total Fuel MMBTU 2,247.655 15,310.255 480,841.486 498,399.396 65,175.489 563,574.885 Net Heat Rate BTU/KWh 14,841 13,355 11,700 13,299 13,476 13,388 Unit Trips # 1 0 3 4 3 7 Capacity Factor % 0.11 0.84 5.26 4.07 1.48 3.35 Availability Factor % 59.88 67.10 67.02 64.67 96.92 72.73 Commercial % 6.6 0 0.03* 0.85 0 0.66 Unavailability (CU) Planned Outage Hours Hours 2,645.500 2,645.500 2,645.500 7,936.500 247.317 10,829.317 Maintenance Outage Hours 0.0 0.0 0.0 0.0 5.433 5.433 Hours Forced Outage Hours Hours 579.830 0 6.317 586.15 0 586.15 Reserve Shutdown Hours 4,814.670 5,265.534 4,800.393 14,880.597 7,639.820 22,520.417 Hours HW Boiler Gas Usage MMBTU 4,816.910 4,816.910 Pilot Gas Usage MMBTU 38,212.500 38,212.500 76,425.000 76,425.000 Note: * Calculation does not include 3.317 hours that were Outside Management Control (OMC) Fuel Oil Inventory Monthly Monthly Fuel Monthly FY 10-11 Fuel FY 10-11 Inventory Inventory Purchases Inventory Inventory Purchases Inventory (Start) (End) (Month) (Change) (Start) (YTD) (Change) McKee Run (#2 Fuel Oil) 451,200 452,081 0 881 448,556 118,549 3,525 Van Sant 152,369 153,043 0 674 143,099 38,079 9,944 (#2 Fuel Oil) Note: As measured by tank level instruments. Tank levels may change due to oil temperature. 32

Van Sant Lifetime through 5/31/11 Actual Starts Factored Starts Fired Hours Van Sant 1256 2169.15 4120.76 Since HGP - Dec 2004 203 501.45 737.18 Team Report: On May 18, the modifications to the Unit 3 Burner Management System were tested by putting different natural gas burners in service then tripping burners to test to determine which gas valves would trip and compare with the ladder logic. After going through all nine burners, the test was successful and the system deemed operational. The testing was done without putting the unit on line. Operations personnel provided support to maintenance by working on Preventative Maintenance (PM) work orders or other work orders that they have the necessary skills to complete successfully. The Operations Department continues to utilize the Flex Team in both Operations and Maintenance areas to help in maintaining the plant. Capacity Testing – FY 2010-2011 Summer 2010 (June 1- Aug 31) Winter 2010-2011 (Dec 1- Mar 1) Unit Rated Net Reported Net Unit Rated Net Reported Net Capability (MW) Capability (MW) Capability (MW) Capability (MW) 1 17 17.20 1 17 * 2 17 18.09 2 17 * 3 102 102.68 3 102 105.61 Van Sant 39 39.30 11 39 43.833 Total 175 178.67 Total 175 149.443 33

4.0 Maintenance During the month of May, plant maintenance staff continued addressing the backlog of work orders. There were forty-five work orders issued with sixty-seven work orders being completed during the month. The table below summarizes the monthly work order activities. Work Order Report May - 10 Outstanding From Outstanding Previous Issued This Completed at the end of Priority # Months Month This Month the month 1 9 3 5 7 2 27 4 7 24 3 35 16 13 38 4 35 0 1 34 5 10 0 7 3 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 49 22 34 37 Totals 165 45 67 143 Note: PM's are included in the priority totals Notable activities during the month include: 1) Maintenance, IC&E and Operations Staff completed the Unit 3 natural gas piping purge utilizing the NAES SMP-22 gas purge procedure. Safe removal of natural gas from the piping with a nitrogen purge was completed. The mechanical contractor removed three sections of piping and installed three new burner level gas trip valves. The ICE technicians completed the electrical connections in preparation for making the system operational. 2) Maintenance mechanical staff completed eight weeks of outage work at the McKee Run Generating Station. Annual inspections and preventive maintenance activities were completed on Unit 3. Work activities included the replacement of the supply and return oil piping and isolation valves on Units 1 and2 boiler fronts. The new valves had limit switches installed for control feedback. 34

3) IC&E staff investigated a problem with VanSant not being able to increase load after being synchronized to the system grid. The PLC and generator breaker was checked. Two fuses were found blown in the FU 1 block of the control cab. The Unit was started and able to pick up load as normal. 4) IC&E staff completed eight weeks of outage work at McKee Run Generating Station. Units 1 and 2 outage work assigned to them included the installation of new control cabinets, LED lights, conduit and wiring for the controls modifications intended to bring the units into compliance with NFPA guidelines. 35

5.0 Capital Improvement Projects (CIP) Project Description Update Number Progress: No other work is planned for this project during the Unit 3 Cooling remainder of the fiscal year. EG1101 Tower Life Schedule: Work scope development for next year will commence in Extension April 2011. Progress: The scope of work on the lower, lower decking support Units 1 & 2 Cooling and stairways improvement was completed in May. Tower casing EG1102 Tower Life is being replaced post outage and has no effect on unit operation. Extension Schedule: Work will be completed by the end of June 2011. Progress: Started on the development of the project work scope Unit 3 Turbine documents. EG1103 Schedule: This project has been deferred until 2011-2012 fiscal Inspection year. Progress: Started on the development of the project work scope Unit 3 Aux System documents. EG1104 Components Schedule: Deferred until 2011-2012 fiscal year. Progress: This project is for the unexpected capital costs due to Miscellaneous equipment failure. EG1105 Capital Equipment Schedule: Funds to date have been used to cover the cost of the Replacements Unit 3 600-lb steam station valve repairs, Unit 3 Cooling Water Booster Pump Repairs and circuit breakers. Progress: Started on the development of the project work scope EG1106 Unit 3 Stack Repairs document. Schedule: Deferred until 2011-2012 fiscal year. Progress: The planned work was scheduled to be completed in Units 1 & 2 Life early May. EG1107 Extension Schedule: The work was completed in May. Other work has been scheduled for the 2011-2012 fiscal year. Unit 1 Forced Progress: The repair work has been completed. EG1108 Outage Repairs Schedule: This work is complete. Progress: Started on the development of the project work scope Unit 3 FD & ID Fan documents. EG1109 Damper Upgrade Schedule: Deferred until 2011-2012 fiscal year. Unit 3 DCS Progress: Started on the development of the project work scope EG1110 Computers & documents. Software Upgrades Schedule: Deferred until 2011-2012 fiscal year. Progress: Inspections and other repairs were completed during the Unit 2 Boiler Fall 2010 Outage. EG1111 Inspections and Schedule: Miscellaneous work is being wrapped up to complete the Repairs project. 36

Progress: The work was completed on the expansion joint in May. Unit 3 Air Heater Insulation and lagging reinstallation will commence in June 2011 EG1112 Expansion Joint Schedule: The work will be completed by the end of June 2011 Progress: The work was completed and tested the week of May 16. Units 1 & 2 Controls Schedule: Final installation of the control system wiring and system EG1113 Modifications checkout and testing was completed on May 20. Progress: The gas line was successfully purged and the gas lines Unit 3 Gas Line were cut for each deck and new gas valves were installed. Testing EG1114 Modifications was completed on May 18. Schedule: The work was completed and tested on May 18. 5.1 CIP Budget Approved Latest Project Description Budget Estimate Number ($ X 1000) ($ X 1000) EG1101 Unit 3 Cooling Tower Life Extension 398 372 EG1102 Units 1 & 2 Cooling Tower Life Extension 173 90 EG1103 Unit 3 Turbine Inspection 348 348 EG1104 Unit 3 Aux System Components 188 188 Miscellaneous Capital Equipment EG1105 77 66 Replacements EG1106 Unit 3 Stack Repairs 25 25 EG1107 Units 1 & 2 Life Extension 225 225 EG1108 Unit 1 Forced Outage Repairs 412** 424 EG1109 Unit 3 FD & ID Fan Damper Upgrade 45 45 Unit 3 DCS Computers & Software EG1110 30 30 Upgrades EG1111 Unit 2 Boiler Inspections and Repairs 124## 111 EG1112 Unit 3 Air Heater Expansion Joint 65## 75 EG1113 Units 1 & 2 Controls Modifications 150## 150 EG1114 Unit 3 Gas Line Modifications 60## 40 ** This project was not budgeted for 2011. ## Project was not in original FY11 CIP but was approved by COD Council in late 2010. 37

6.0 General Plant Information Training: CEMS training was completed at VanSant for the Operations staff to allow checks to be completed on a daily basis by operators. VanSant is a remote site that is three miles away from McKee Run. Completing the daily checks by operators will provide consistency in work tasks and aid in ensuring tasks are completed in a timely manner. Training of all plant employees was held in May to educate them on being able to recognize Arc Flash Levels as well as identifying the applicable PPE to ensure their personal safety and the safety of others who may be in the arc flash exposure area. Subsequent to the training, the plant’s uniform policy has been revised to reflect the new safety standards. 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. Used Oil training was conducted to familiarize employees with a plan revision and subsequent operational changes. Personnel: On May 13th, Erik Petty successfully passed the PJM System Operator Certification exam. Mr. Petty received a shirt to commemorate his achievement for passing the PJM Operator exam. On May 17th, Erik Petty received a NAES Service Recognition Award from Vincent Scire, Plant Manager, in recognition of completing 10 years of service working at the City of Dover Generating Facilities. 38

Calendar of Events Date Units 1, 2, and 3 Spring Outage March 28, 2011 – May 23, 3011 NOx Ozone Season Starts May 1, 2011 EIA-923 Report May 6, 2011 VanSant 5 Year SPCC Plan Recertification June 27, 2011 Fiscal Year 2010-2011 Ends June 30, 2011 PJM Summer Capacity Test Period June 1, 2011- August 31, 2011 Toxic Release Inventory (TRI) Annual Report July 1, 2011 Unit 3 RATA Testing July 12, 2011 McKee Run and VanSant Title V Semi-Annual Certification Due August 1, 2011 NOx Ozone Season Ends September 30, 2011 One Year Accident Free October 14, 2011 Units 1, 2, 3 and 11 Fall Outage TBD Winter Capacity Period December 1, 2011 to February 28, 2012 McKee Run and VanSant Title V Annual Certification Due February 1, 2012 NOx Emissions Reconciliation Due March 1, 2012 SO2 Emissions Reconciliation Due March 1, 2012 SARA III Report March 1, 2012 Annual VanSant Black Start Test March , 2012 Units 1, 2, 3 and 11 Spring Outage TBD Air Emission Inventory April 1, 2012 McKee Run Title V Permit Renewal April 20, 2012 EIA-860 Report April 29, 2011 7.0 Summary of NAES Performance to Date Plant Performance FY 2010-2011 Measure Month Year to Date YTD FY Maximum Incentive Incentive Commercial 0% 0.66% $63,262 $89,586 Unavailability (CU) Safety 1 1 $8,398 $16,797 Environmental 0 0 $16,797 $16,797 Capacity Tests Summer Winter Summer Winter Completed Unit 1 No No Yes Yes* $3,360 $3,360 Unit 2 No No Yes Yes* $3,360 $3,360 Unit 3 No No Yes Yes $20,157 $20,157 Unit 11 No No Yes Yes $6,719 $6,719 Total YTD 77.85% Total YTD Incentive $122,052 $156,775 Incentive % Note - * Unit did not operate in the Winter period and was in the PJM Winter Capacity Test Exemption Program. 39

APPENDICES I. PJM INVOICE BREAKDOWN The PJM bill is a record of all Electricity Transactions, Transmission Services, Ancillary Services and Miscellaneous fees that allow the PJM to operate. Below is a list of the line items on the PJM bill including all generator activity. PJM Bill Line Items Gen Load Net Day Ahead Energy $130,982.16 ($662,397.52) ($531,415.36) Realtime Energy $15,685.56 $23,159.05 $38,844.61 Transmission Losses Credits $0.00 $41,068.93 $41,068.93 Network Integration Transmission Service Charges $0.00 ($265,765.79) ($265,765.79) Inadvertent Interchange Charges $0.00 ($3,430.94) ($3,430.94) Regulation Charges $0.00 ($28,221.88) ($28,221.88) Synchronized Reserve Charges $0.00 ($14,518.49) ($14,518.49) Balancing Operating Reserves Charges $0.00 ($11,935.81) ($11,935.81) Day Ahead Operating Reserves Charges $0.00 ($12,520.24) ($12,520.24) Day-ahead Scheduling Reserve $0.00 $126.91 $126.91 Synchronous Condensing Charges $0.00 ($46.96) ($46.96) Reactive Services Charges $0.00 ($107,290.04) ($107,290.04) Meter Correction Charges $0.00 ($4,678.40) ($4,678.40) Day-ahead Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserve for Load Response $0.00 $0.00 $0.00 Balancing Operating Reserves Credits $13,451.15 $0.00 $13,451.15 Day Ahead Operating Reserves Credits $0.00 $0.00 $0.00 Locational Reliability Charges $0.00 ($1,080,033.18) ($1,080,033.18) Capacity Transfer Rights Credits $0.00 $1,745.61 $1,745.61 Capacity Resource Deficiency Credits $0.00 $4.03 $4.03 Demand Response and ILR Compliance Penalty Credits $0.00 $0.00 $0.00 RPM Auction Credits $1,002,527.60 $0.00 $1,002,527.60 Auction Revenue Rights Credits $0.00 $31,448.26 $31,448.26 Synchronized Reserve Credits $187.72 $0.00 $187.72 PJM Scheduling System Control and Dispatch Service Charges $0.00 ($15,851.78) ($15,851.78) Transmission Owner Scheduling System Control and Dispatch Service Charges $0.00 ($4,708.54) ($4,708.54) Reactive Supply and Voltage Control from Generation Sources Service Charges $0.00 ($31,898.48) ($31,898.48) Reactive Supply Credit $29,467.58 $0.00 $29,467.58 Black Start Service Charges $0.00 ($1,002.01) ($1,002.01) North American Electric Reliability Corporation (NERC) Charge $0.00 ($551.33) ($551.33) Reliability First Corporation (RFC) Charges $0.00 ($836.52) ($836.52) Expansion Cost Recovery Charges $0.00 ($408.58) ($408.58) Transmission Enhancement Charges $0.00 ($16,003.08) ($16,003.08) Black Start Service Credits $4,544.50 $0.00 $4,544.50 Non-Firm Point-to-Point Transmission Service Credits $0.00 $401.92 $401.92 Generation Deactivation $0.00 $741.04 $741.04 Market Monitoring Unit (MMU) Funding $0.00 ($326.77) ($326.77) 40

Organization of PJM States, Inc. (OPSI) Funding $0.00 ($39.28) ($39.28) FERC Annual Recovery $0.00 ($3,567.86) ($3,567.86) PJM Annual Membership $0.00 $0.00 $0.00 EFOR-P $0.00 $0.00 $0.00 DPL Settlement B $0.00 ($0.18) ($0.18) PPA $0.00 $357.13 $357.13 $1,196,846.27 ($2,166,980.78) ($970,134.51) II. LOAD, ALL IN ENERGY AND ALL IN COST OF SERVICE TABLE Budget Load Actual Load Budget AIE Actual AIE Actual YTD AIE Budget AICS Actual AICS Actual YTD AICS (MWh) (MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) Jul 83,163 83,163 $90.72 $90.72 $90.72 $81.36 $81.36 $81.36 Aug 78,755 78,755 $82.76 $82.76 $86.85 $83.03 $83.03 $82.17 Sep 66,782 66,782 $82.73 $82.73 $85.65 $91.13 $91.13 $84.79 Oct 56,452 56,452 $79.72 $79.72 $84.47 $87.24 $87.24 $85.27 Nov 54,396 54,396 $82.56 $82.56 $84.17 $91.56 $91.56 $86.28 Dec 63,566 63,566 $87.33 $87.33 $84.67 $98.22 $98.22 $88.16 Jan 60,136 64,462 $86.66 $91.77 $85.65 $94.36 $97.13 $89.40 Feb 54,199 54,900 $85.32 $84.37 $85.51 $94.11 $92.95 $89.77 Mar 56,334 57,414 $85.66 $81.75 $85.14 $93.39 $89.70 $89.77 Apr 52,554 54,359 $83.85 $81.20 $84.80 $92.99 $89.53 $89.74 May 58,744 62,114 $80.01 $77.85 $84.18 $87.28 $84.55 $89.28 Jun 67,331 $80.51 $96.23 41

III. GLOSSARY Energy Only Unit Cost ("EOU") accounts for the wholesale energy costs excluding capacity obligations, capacity credits for Dover-owned generation, generation revenues, generating plant costs, the black start ancillary services credit for the Van Sant plant, and revenues associated with the sale of emission allowances. The AIE includes the costs from settling the hedged or forward transactions; the energy bought on the ISO (Independent System Operator or PJM) day-ahead to cover the open position (un-hedged); load following costs associated with balancing the actual load in the ISO real-time market; energy management service related fees; the ISO transmission charges and credits to load serving entities; the ISO ancillary services charges such as generation regulation, spinning reserve, and reactive power; and the ISO administrative charges and cost of service recovery fees. All In Cost of Service ("AICS") accounts for the net cost of wholesale power to the City of Dover Electric Utility. The AICS starts with the AIE and adds the costs or credits from capacity obligations, capacity credits for Dover-owned generation, generation revenues, generating plant costs, the black start ancillary services credit for the Van Sant plant, and revenues associated with the sale of emission allowances. Black Start is a generating ancillary service that is the process of restoring a generating plant to service without the support of an external power supply to power auxiliary equipment needed for start up operations. Capacity UCAP Obligated Purchased is the obligation and payment by all load serving entities in PJM including Dover for the Unforced Capacity (UCAP) requirement from PJM that satisfies the PJM reserve requirements. Generation Capacity Credit: is the credit provided to generators for supply capacity to the system. The price is determined by the PJM Reliability Pricing Market auction process that includes three auctions for each capacity year. Generation Production Margin accounts for the variable margin excluding variable O&M and emissions. The Generation Production Margin is calculated by taking the PJM revenues credited to the plant including any balancing charges or credits less the fuel costs. Generation Production Margin includes both “Economic and reliability dispatch” and “Testing.” Economic and reliability dispatch equals the margin achieved when Dover’s generating plants are dispatched by PJM for either economic dispatch (the system energy price is greater than the Dover bid price) or reliability dispatch whereby PJM pays the generating cost of the plants for the hours the plant is run to support the system. Generation Testing equals the Generation Production Margin associated with testing. This is usually expected to be a negative margin because the plant is potentially being dispatched / run when energy prices do not cover its costs. Non-Production Revenue equals the credits from PJM to Dover for Generation Capacity Credit, the Black Start Revenue and the sales by Dover of Emission Allowances. 42

FUND SUMMARY Total Collected $ 651,183.02 DEMEC Admin Fee Paid $ 18,312.19 State Admin Fee Paid $ 13,987.88 Grants Paid $ 389,412.50 Grants/Fees Reserved and Amount Owed $ 238,121.75 Energy Depot Paid $ 31,519.82 Efficiency Programs Paid $ 34,068.34 *Funds Available $ (74,239.46) * As of 07/28/2011 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 Reye Solar - Res $ 12,762.50 $ 750.00 $ - 4/16/2008 Lakeland Commercial Group Geo - Comm $ 10,800.00 $ 750.00 $ - 6/19/2008 & 08/25/2008 L.D. Shank - Triad Farms Solar - Comm $ 30,000.00 $ 750.00 $ - 10/6/2008 City of Dover Solar - Comm $ 40,820.00 $ 750.00 $ - 10/21/2008 Robert & Cynthia Hartman Geo HP- Res $ 1,800.00 $ 135.00 $ - 10/21/2008 Robert Varipapa Geo HP- Res $ 2,400.00 $ 180.00 $ - 2/27/2009 David Jump Solar - Res $ 15,000.00 $ 750.00 $ - 2/27/2009 Jakob Seren Solar - Res $ 15,000.00 $ 750.00 $ - 2/27/2009 William Sweet Solar - Res $ 15,000.00 $ 750.00 $ - 3/31/2009 LD Shank - Triad Farms Solar WH-Comm $ 3,000.00 $ 225.00 $ - 3/31/2009 Warren & Joan Seaver Geo HP- Res $ 3,000.00 $ 225.00 $ - 4/22/2009 William Sweet Solar HW $ 3,000.00 $ 225.00 $ - 4/28/2009 State of DE/DNREC - DE Solar - Comm $ 30,000.00 $ 750.00 $ - 4/29/2009 Delaware Primary Care, LLC Solar - Comm $ 30,000.00 $ 750.00 $ - 9/11/2009 NCALL Solar - Comm $ 30,000.00 $ 750.00 $ - 9/11/2009 D. Brian Beckman Geo HP- Res $ 2,000.00 $ 150.00 $ - 9/21/2009 LKSC Dover, LLC Kids Cottage Solar - Comm $ 29,925.00 $ 750.00 $ - 10/5/2009 Mark F. Boller Geo HP- Res $ 3,000.00 $ 225.00 $ - 10/5/2009 John Welgan Solar - Res $ 15,000.00 $ 750.00 $ - 11/4/2009 LKSC Dover, LLC Kids Cottage Geo - Comm $ 12,000.00 $ 750.00 $ - 3/25/2010 Minaxi Patel Solar - Res $ 15,000.000 $ 750.000 $ - 3/23/2010 J. McGiffin Jr. & K. Doyle Geo HP- Res $ 3,000.000 $ 225.000 $ - 5/28/2010 Nancy Warner Geo HP- Res $ 1,200.000 $ 90.000 $ - 6/2/2010 David Teel Geo HP - Res $ 1,800.000 $ 135.000 $ - 6/2/2010 Dewey J. Barich Geo HP- Res $ 2,400.00 $ 180.000 $ - 7/12/2010 Mike & Sharonb Laverty Solar - Res $ 5,105.000 $ 382.880 $ - 8/19/2010 James Grilli Geo HP- Res $ 1,800.00 $ 135.000 $ - 8/19/2010 Michael Noble Solar - Res $ 15,000.000 $ 750.000 $ - 9/17/2010 David Teel Solar - Res $ 7,500.000 $ - $ 562.500 3/8/2011 Michael & Carol Apgar Solar - Res $ 7,500.000 $ - $ 562.500 3/17/2011 Elizabeth Murphey School Geo HP - Comm $ 9,200.000 $ - $ 690.000 5/24/2011 Richard Avant Geo HP - Res $ 2,400.000 $ - $ 180.000

6/23/2011 Charles Messina Plumbing Solar - Comm $ 10,000.000 $ - $ 750.000 Total $ 389,412.50 $ 13,987.88 $ 2,745.00 PENDING APPLICATIONS Grant Date Reserved Applicant Type Reservation 3/20/2009 City of Dover Geo HP $ 166,179.25 10/26/2009 Charles Bounds Geo HP- Res $ 1,935.000 1/27/2010 Pat's Pizzeria Solar - Comm $ 30,750.000 1/17/2011 Pat's Pizzeria Hot Water - Comm $ 10,750.000 2/2/2011 Arturo Sanchez Solar - Res $ 8,062.500 3/29/2011 Psychiatric Access Central DE Solar - Comm $ 13,937.500 7/8/2011 Michael J. Kopp Geo - Res $ 2,472.500 7/11/2011 Ruth Ann Piper Geo - Res $ 1,290.000 $ 235,376.75 ENERGY DEPOT FEES 3/3/2008 Start-up Fees $5,872.50 4/15/2008 Start-up Fees $1,957.50 4/15/2008 Mar, Apr, May 2008 $1,692.13 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 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 Total Paid $31,519.82 ENERGY EFFICIENCY CAMPAIGNS/EDUCATION PROGRAMS 1,500 CFL Campaign & 10/21/2008 Educational Literature $5,012.29 12/11/2008 Reimbursement for Green $3,459.12 Thermal Imager for Home Audits 3/31/2009 Program $5,581.12 Eco @ Home Energy Conserv. 1/4/2011 Calendars $20,015.81 Total $34,068.34

ACTION FORM PROCEEDING Utility Committee DEPARTMENT OF ORIGIN: City Manager’s Office DATE SUBMITTED: July 28, 2011 PREPARED BY: Ann Marie Townshend, AICP, Director of Planning & Community Development on behalf of Scott D. Koenig, P.E., Interim City Manager SUBJECT: Proposed ordinance to prohibit new private shallow wells within the City limits and to clarify that wells for geothermal heating and cooling systems are permitted in accordance with certain criteria. REFERENCE: Dover Code, Chapter 110 – Utilities, Article III – Water Service, Division 1 – Generally, Section 110-67 – Private Wells RELATED PROJECT: N/A REVIEWED BY: Scott D. Koenig, P.E., Interim City Manager; Ron Lunt, Public Utilities Director EXHIBITS: Draft Ordinance #2011-20 EXPENDITURE REQUIRED: N/A AMOUNT BUDGETED:N/A FUNDING SOURCE (Dept./Page in CIP & Budget): N/A TIME TIMETABLE: RECOMMENDED ACTION: Staff recommends that the Committee forward the proposed ordinance to City Council for first reading on August 22, 2011 and final reading and City Council Action on September 12, 2011. BACKGROUND AND ANALYSIS The proposed ordinance would prohibit new private shallow wells within the City of Dover. This prohibition will protect the water resources of the unconfined aquifer from which the City draws a portion of its water supply, as well as protect the City’s Certificate of Public Convenience & Necessity (CPCN). Currently, private shallow wells, for irrigation purposes in particular, are permitted in accordance with certain criteria specified in the ordinance. Additionally, geothermal technology for heating and cooling is an emerging technology that was not contemplated when this section of the code was implemented. Geothermal systems require well permits from DNREC, although they do not draw water from the ground. The proposed ordinance would clarify that wells associated with the installation of closed loop geothermal systems are permitted within the City of Dover in accordance with specified criteria.

CITY OF DOVER PROPOSED ORDINANCE #2011-20 1 BE IT ORDAINED BY THE MAYOR AND COUNCIL OF THE CITY OF DOVER, IN COUNCIL 2 MET: 3 That Chapter 110 - Utilities, Article III - Water Service, Division 1 - Generally, Section 110-67 - Private 4 Wells, be amended by deleting text indicated in red strikeout (subsection (b) Shallow wells in its entirety) 5 and inserting text indicated in bold, blue, italics as follows: 6 Sec. 110-67. Private wells. 7 (a) When authorized. It shall be unlawful and a nuisance for any person to dig, drill or otherwise 8 excavate any well more than 150 feet below the surface of the ground within the city, or one 9 mile thereof, without the permission of the city council given by resolution. No permission 10 shall be given for a well on any property where a potable water supply is available. 11 (b) Shallow wells. Shallow wells may be drilled into and water withdrawn from the unconfined 12 aquifers within the limits of the city, subject to the following: 13 (1) All wells shall require a permit from the state department of natural resources and 14 environmental control or other regulatory agency and the approval of the city setting 15 forth construction details, design yield, and withdrawal rates. 16 (2) All wells must have the approval of the state board of health or other similar regulatory 17 agency for their intended use. 18 (3) A detailed plan showing the well location, well construction, piping plan and connection 19 details shall be submitted with the application. 20 (4) All wells shall be metered by an approved device and daily pumping records maintained. 21 (5) All water derived from shallow wells shall be used only for boiler makeup, cooling water 22 use, and underground irrigation systems. 23 (6) Any revisions, changes or deviations from the original permit must be in the same 24 manner as the original permit. 25 (7) There shall be no interconnection with any public water supply, nor shall the shallow 26 well be used as a potable water supply for human consumption. 27 (8) Private irrigation systems shall be completely underground, with no connections or 28 outlets that could be used for human consumption. Irrigation shall be by sprinkler heads. 29 (b) Geothermal wells. Wells may be drilled for the purpose of the installation of a geothermal 30 heating and cooling system within the limits of the city, subject to the following: 31 (1) These wells shall not be authorized for withdrawal or injection. They will function 32 as borings, filled with a bentonite grout, with a piping system that acts as a heat 33 exchanger to dissipate/absorb heat from the system to the ground. 34 (2) There shall be no interconnection with any public water supply, nor shall the 35 geothermal well be used as a potable water supply for human consumption. 36 (3) No well shall be located within any city right-of-way or utility easement without 37 written authorization from the city manager. 38 ADOPTED: * 39 SYNOPSIS 40 The proposed ordinance would eliminate the allowance of new private shallow wells within the 41 City of Dover, and adds language to clarify that geothermal wells are permitted provided they 42 meet certain criteria. 43 Actions History 44 August 8, 2011 - Scheduled for Consideration by the Utility Committee 45 S:\ORDINANCES\2011\Draft\Ordinance 2011-20 - Irrigation Wells REVISED CURRENT.wpd