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3.0 ERMUSR 07-08-2009 Elk River Municipal Utilities 13069 Orono Parkway • P.O. Box 430 Phone: 763.441.2020 Elk River, MN 55330-0430 Fax: 763.441.8099 July 6, 2009 To: Elk River Municipal Utilities Commission John Dietz Jerry Gumphrey Daryl Thompson From: Troy Adams Subject: Review and Consider Big Stone II Participation and Wholesale Power Supply Options In follow-up to the joint Council/Commission meeting on June 29th, this Special Commission Meeting has been scheduled. This meeting will allow the Utilities Commission to make a decision on whether or not to support participation in Big Stone II (BSII). If the Commission decides to support Big Stone II participation, the next step would be taking that decision to the Council at the scheduled joint meeting on July 13th and request Council support. To address some of the concerns mentioned at the previous meeting, Central Minnesota Municipal Power Agency (CMMPA)has provided some additional financing and cost recovery explanation. The financing explanation covers the costs and dates applicable to ERMU for participation in BSII. The cost recovery explanation covers different scenarios for the BSII project and how they would specifically impact ERMU. These scenarios include: The project going into service as planned, the project having a"No-Go"vote in September 2009, the project having a"Go"vote in September 2009 but not ever getting a shovel in the ground, the project being cancelled mid-construction, and the project being cancelled in 2016. Also included with this is a spreadsheet with an ERMU analysis on the impact of the third scenario to the ratepayers. This ERMU analysis confirms the CMMPA cost recovery analysis for this scenario. Central Minnesota Municipal Power Agency has also provided a report addressing job creation through the construction of BSII. Although these jobs are not in Elk River, the report has been provided for Commission review as supplemental information. Willmar Municipal Utilities has recently gone through the same decision making process that Elk River Municipal Utilities is currently going through. The City of Willmar is of similar population to Elk River and the electric utility is of similar size. Willmar Municipal Utilities has generation facilities and purchases some of their energy from Great River Energy. Through CMMPA, Willmar Municipal Utilities will be participating in the BSII for a 30MW share. '',, Because Willmar Municipal Utilities was involved earlier in the process, their financial situation is not identical, but very similar. Bruce Gomm the General Manager of Willmar Municipal Utilities has offered to speak at the Commission Meeting to discuss how Willmar came to terms with the risks involved in the decision to participate in BSII. As a supplemental update, the Connexus Energy will be meeting with Great River Energy on July 7th to discuss their potential involvement in the scenarios of providing an all requirements purchase power contract with ERMU, a partial requirements purchase power contract with ERMU, or the acquisition of the electric utility. I hope to be able to provide a verbal update at the Commission meeting. Also, CMMPA has expressed interest in providing a similar contract for ERMU. A proposal from CMMPA is included for Commission review. Southern Minnesota Municipal Power Agency (SMMPA) has also expressed interest in providing energy for ERMU through an all requirements type contract. There may also be an option for a partial requirements contract with SMMPA. The decision regarding ERMU's participation in BSII has had an extremely tight time schedule which in no way has been ideal. However, the project continues to warrant merit of consideration. Ultimately the decision will be rooted in the Commission's long term vision for the Utilities and comfort with the assessed risks. . _,, ... . ,-,4•9*- —\ - , . '. .• "t' ..77.A.; ,„1--.*. ''': ...' .. ,. orfP."1/. ' i — • ,f 1 * - -'..'4....... p, , • 1 ' .::,* . :'.:. _ ... , , . 61 •...,....,.":"..•,r.: M it--= -,—,. ... . . — _,... 4... Agency , .. . , TT • 41 ,1161."::. ,,-; , ,,. . •.. - -- - .-' i• ,„ - .. . _. - - --i.. :. i -, :1 : . : k et b" •• .,*., '....' ----7•'''' 14 "-* . •.•; Services • ----- 4.. .„..„.,. _ , , •11". _1. ,:g' 1 ..' 4 ''' 15.ti?"14•1';.''.:-'1.,;1'; ' ''''''174;14' "ML:2-.:- '- ' .. . .,,. ! IlEi..._ "- • Big Stone II Financing Elk River Municipal Utilities Commission July 8, 2009 Central Minnesota Municipal Power Agency 1//://4„076/11.1 ipjak Air' iliro.I' ( ( BSPII Financingy,:„,, Overview ..... LC ost s t o b e fi nanced Ti me S ch edule ERM U opti . 4',,..4,- ons .. ....__ - - .scar A -- - _. te: . 7 lg., mow" .4�,. '"" •yam~ w.. '.,�''."!' i. S Al �'•. -_.... , . 1 7 Jr 2 ( ( Background: BSPII Project Costs for Early 2016 In-service Development Cost (30 Megawatt Share) : • One-time true-up payment (up through 8/31/09) : $ 2 . 6 M1 • Ongoing development costs $51k/month Starts 9/1/09 and runs to financial close Financial close scheduled for Fall 2010. Project Cost (30 Megawatt share) : • Construction Cost : $ 100 M2 • Interest During Construction (IDC) : 23 M3 • Total Project Cost : $ 123 M 1 . Estimated true up payment due 11/1/09, based on estimate of project costs through 8/31/09. Development cost true-up to be adjusted in subsequent months to reflect actual costs. 2. Cost shown in nominal dollars, and includes both plant and associated transmission and includes all development costs. Transmission represents about 16% of total project costs. Previous discussion amount of $90 million was order-of-magnitude figure using $3,000/kW, based on $3,220/kW project cost estimate for 2014/2015 in-service provided ERMU on April 15, 2009. 3 3. IDC to be included in bonding, so ERMU customers do not pay until plant in-service. #,CA A BSPII First Year Cost Summary •-•.. 630 MW unit, 2016 In-Service Current Cost Component Cost/MWh Generation Capital $29 . 60 Fuel $ 14. 38 Operation & Maintenance $ 5 . 72 Subtotal $49.70 Transmission $ 5 .83 Total $55.53* Assumes soft development costs are not reimbursed. If development costs are reimbursed, total cost would increase to $55.95. *Previous estimate (4/15/09) was $53.60/MWh for 2014/2015 in-service. Difference is about $1/MWh for escalation due to later in-service date, and $1/MWh for change in 4 assumed interest rate from 5% to 5/5%. BSPII Financing me„Overview Costs to be financed Time Schedule ERMU options z_. ., • ., �• d W - - 5 Big Stone II Financing:• Time Schedule Development Costs ■ One-time ERMU development cost true-up payment $2.6 million True-up for costs from project start through 8/31/09. Payment due November 1, 2009 ▪ Ongoing monthly development cost payments A Costs starting 9/1/09 n $51k/month Continues to financial close in Fall 2010. Permanent Financing ■ Financial close in Fall 2010 (assume 9/1/2010) • Can roll-in development costs into permanent financing . 1 . As in the RW Beck study, as a conservative estimate this figure does not include potential revenue benefits to ERMU of transmission ownership. 2. At ERMU's option, CMMPA can accomplish bonding to finance all ERMU participation 6 in the Project, including development costs and interest. oirApA CMMPA BSPII Finance Plan Phase 1 : Phase 2: Phase 3: Development Construction In-Service ERMU Joins Project Financial Close In-Service Sept 2009 Fall 2010 Early 2016 Interim MCMU Financing Permanent Financing 1 Current CMMPA ' Participants Pay No P & I Start Paying Debt Pay P & I on Interim ; Roll interim development ► plus Financing Only financing into permanent financing. Fuel and 0 & M New Participant (ERMU) Financing Project Cost and One-time true-up payment , Interest During Construction Plus ongoing monthly development costs and interest on true-up. BSPII Project Phase 1 oev'l Development Phase Includes Project expenditures from inception through permitting activities up to financial close . To minimize current cost impact, we have funded these costs using bond pool interim financing from Midwest Consortium of Municipal Utilities (MCMU) managed by Minnesota Municipal Utility Association (MMUA) CMMPA participants are currently paying Principal and Interest on interim loan Will roll development cost principal balance into permanent bond issue at financial close Decision as to whether to reimburse participants for development costs still needs to be made Power Sales Agreement (PSA) with CMMPA participants allows the flexibility to do so 8 { True-UpDevelopmentCost and epikCosts going forward (assuming Elk River participates in 30 MW) Elk River's True-up Cost: By August 31 , 2009, one-time buy-in cost to Elk River to true- up costs among (internal and external ) participants will be about $87,000/MW . Assuming 30 MW, this would equate to approximately $2.6 Million Elk River's Development Cost going forward From 9/ 1/09 to Financial Close on 9/ 1/ 10 Elk River's share of Monthly P & I costs on MCMU interim financing (for the duration of time between the CON and Financial Close) would be approximately $ 1,390 per MW per month Assuming 30 MW this would equate to approximately $41,630/month. If ERMU finances the $2.6 million true-up payment, interest on that financing would be an additional $8,666/month . Total monthly payments to Fall 2010 would be about $50,300/month. ERMU can have CMMPA finance these monthly payments in the true-up bonding together with the $2.6 million, if desired. Total development cost at financial close is 9 projected to be approximately $115,000 per MW. ( ( ( BSPII Project Phase 2 ePAConstruction Phase Includes expenditures from Financial Close to Commercial Operation Date ( COD ) Engineering Procurement Construction With the all permits " in - hand ", CMMPA will secure permanent financing Projects such as BSPII have the ability to finance the interest During Construction (IDC) In other words, borrow with no orincinal or interest pa ments until commercial operation The projected interest cost during construction will be projected and the amount of bonds issued will be grossed-up such that bond proceeds are used to make interest payments During the construction phase, participants will not have to be assessed costs until after the Commercial Operation Date (COD ) Unless they elect to pay for Interest During Construction (IDC) 10 BSPII Project Phase 3 epA Commercial Operations Phase After commercial operation date (COD) currently estimated to be 1 - 1 - 2016 We will start making principal and interest payments on bonds Elk River' s approximate cost during operation would be as follows : Fixed Monthly Charge = $23,267/MW-month (to cover debt service and fixed 0 &M) Variable Energy Charge = $20. 10/MWh • TOTAL COST = $55 . 53/MWh Includes busbar cost plus transmission 11 1 BSPII FinancingPi R Overview Costs to be financed Time Schedule ERMU options • ,• _ -ti -- 11 - 12 f . ERMU FinancingOptions ERMU can do all of its own financing , if desired . Or, as an alternative, CMMPA offers to do all financing • We are already doing this for our other participants One-time true up payment on November 1, 2009 (some CMMPA participants are increasing their participation shares) . Ongoing development costs to financial close (9/1/09 to 9/1/10) CMMPA can finance these costs for ERMU as well . Permanent financing of entire project at financial close. ERMU has option of being paid back for its contributions to development costs, or: Roll development costs into permanent financing . • Elk River would need to provide information for CMMPA's bonding agency's review as to credit worthiness. ERMU can take advantage of CMMPA financing development, or opt to finance the ERMU share yourselves. 13 < < < eFA Questions ? orAFA 459 South Grove Street Blue Earth, MN 56013 Phone : ( 507) 526-2193 Website : www.cmmpa .org 14 Appendix A epA Expenditures and Amortization This Appendix provides details of project expenditures and amortization . There are three time periods to consider : • Phase 1 : Development • Phase 2 : Construction • Phase 3 : Operations 15 Expenditures and Amortization Phase 1 : Development* (Assumes 30 MW FRMU Share) One-time true- up payment For costs up to 8/31/2009 : $2 . 6 million Due 11/ 1/09 Ongoing development costs ■ 9/ 1/2009 to financial close ( Est. 9/ 1/2010) ■ $ 51 , 000/month, 13 months : $663,000 • Interest on these monthly costs : $ 19, 000 • Interest on $2 . 6 million true-up : $ 155,000 $8,666/month, 13 months Total development cost by financial close $3.4 million To be rolled into permanent financing in Phase 2 . * Assumes CMMPA does bond financing for all ERMU costs 16 and interest, at 5.5% interest rate. Expenditures and Amortization Phase 2: Construction* (Assumes 30 MW F.RMU Share) Project construction cost : $ 100 million Includes both plant and transmission . Includes the $3 . 4M development cost from Phase 1 . Interest During Construction • Interest on the $ 100M to 2016 in-service $23 million • To be included in bonding . Total capital cost To be recovered in rates during Phase 3 : $ 123 million * Assumes CMMPA does bond financing for all ERMU costs 17 and interest, at 5.5 /o interest rate. • • Expenditures and Amortization Phase 3: Operations* (Assumes 30 MW FIRMU Share) Project construction cost : $ 123 million From Phase 2 This is the amount to be recovered in rates . Amortization in customer rates ■ Similar to a house mortgage payment. • Customer payments start at in -service January 2016 • $ 123 million , amortized over 30 years at 5 . 5% interest rate . $ 123M * (A/P, 30 years, 5 . 5%) = $698, 380/month • Capital - related cost of project : $35.43/ MWh * Assumes CMMPA does bond financing for all ERMU costs 18 and interest, at 5.5% interest rate. x{ AV• ° t 1 '''ll: 1* [ ., _7:-.."- - . ,., A,,,, • CM PA Nor ��.al 4 . i: Tv :?„2„-----___;:;:ka y♦ @gqq �'t c-- lAdgi _._ Services , ,, Big Stone II Cost Recovery Scenarios Elk River Municipal Utilities Commission July 8, 2009 Central Minnesota Municipal Power Agency e S verview Big Stone II cost Recovery Scenarios a,. Cost recovery over life of operating plant Cost recovery in event of project cancellation K. t 1 to re. • „I/ 2 1ackground: Project Costs for Early 2016 In-service Project Cost (for 30 Megawatt share) : ® Construction Cost: $ 100 ML2 ■ Interest During Construction (IDC) : 23 M3 ■ Total Project Cost : $ 123 M4 1 . Cost shown in nominal dollars, and includes both plant and associated transmission and all development costs. Includes cost escalation for all expenditures to the year in which they are expended during the construction period. Transmission represents about 16% of total project costs. 2. Previous discussion amount of $90 million was order-of-magnitude figure using $3,000/kW, based on $3,220/kW project cost estimate for 2014/2015 in-service provided ERMU on April 15, 2009. 3. Accumulated interest on construction expenditures during the construction period as of the date of commercial operation. IDC to be included in bonding, so ERMU customers do not pay until plant is in-service. 3 4. Total amount to be recovered during the project lifetime (30 years book life) Background: Expenditure and Exposure for Project Construction1 — Cash Expenditures Cancellation Cost Exposure ai z E z v , • 0% 0% 1/1/10 1/1/11 1/1/12 1/1/13 1/1/14 1/1/15 1/1/16 Date 1 . Cost trajectory shown is for construction costs not including IDC, Using same per-unit curve 4 for cost recovery Scenario D yields conservative (high) estimate of recovery costs including IDC. Background: e. • - Cost Accumulation and Amortization* (30 MW share) • Arnow mO�lation through rates (3°Years)as :47. Sy 0 $0 1/1/2010 1/1/2016 Commercial Operation Date 5 * Conceptual illustration only. Not to scale. ( ( ( i'APA Cost Recovery Scenarios Scenario A : Project goes in -service in early 2016 Scenorip ,O. : Project cancelled in September 2009 5Tceporio c: Project cancelled in September 2010 Scenorio, ..P : Project cancelled in June 2012 5c:poorigE: Project cancelled after construction completed in 2016 . 0 a • 0. 6 .:,,,,,,„ .„:„,,,,,: !ii.,,i., _, Cost „- ecovery Scenarios epA Scenario A: Project Goes In-Service 1/1/2016 ERMU Project Cost (for 30 Megawatt share) : Si 2 3 M Debt payments starting at in -service date (2016) : • $ 123 million, 30 years recovery at 5 . 5%/year interest rate = $698,380/month1, 2 ERMU customers pay for Big Stone II project debt service starting at in -service date in 2016 . • ($698, 380 per month )/( 19,710 MWh per month of BSPII output3) = $35 .43/MWh, or 3 . 54 cents/kWh of Big Stone II output. • ERMU payments for BSPII construction are fixed at this number for 30 years. 1 . Amortization is ($123 million * (A/P, 30 years, 5.5%))/12 months per year, starting 1/1/2016. 2. As in the RW Beck study, as a conservative estimate this figure does not include potential revenue benefits to ERMU of transmission ownership. ,7 3. 30 MW ERMU share in BSPII, average monthly plant output at 90% capacity factor. CostRecovery (cont'd) PA Scenario B : Project Cancelled in Fall 2009 Scenario B : • ERMU signs Big Stone II Letter of Intent (LOI) by July 15 . 1 LOI includes a contingency clause regarding the project "Go/No- Go" vote in September. • Project "Go/No-Go" vote of current project Co-Owners in September is "No-Go". • Project is cancelled . Cost Recovery Outcome for ERMU : Minimal • ERMU has no obligation to join the Project, or to pay for development costs. • ERMU's only expenses would be : Cost of RW Beck planning study (Associate Member for Planning efforts with CMMPA, approved earlier) . Cost and time of ERMU's own due-diligence efforts 1 . Letter of Intent under review by ERMU legal counsel. 8 CostScenarios (cont'd) rAPys► Scenario C: Project Cancelled in Fall 2010 Scenario C : 1 • ERMU signs Big Stone II Letter of Intent (LOI) by July 15 . ■ Project "Go/No-Go" vote of current project Co-Owners in September is "Go". • ERMU joins project in Fall 2009 . ■ ERMU investments in Project up to Fall 2010 . One-time catch-up payment for costs pre-8/31/09 : $2.60 million2 Monthly development payments from 9/1/09 and interest on the $2.6 million to 9/1/2010 : $0.84 million3 Total ERMU investment by 9/1/2010 : $3 .44 million • Project is not able to accomplish financial closing in Fall, 2010 . • Project is cancelled . 1 . CMMPA believes that, although this Scenario C is possible, once a "Go" vote is made in September 2009, the Project will continue through and beyond financial close. 2. One-time payment to be made by 11/1/09 to join the project, per the Letter of Intent. CMMPA will provide bonding for this payment at ERMU's option. 9 3. Assumes CMMPA finances ERMU monthly $51 k development payments to financial close. Cost F' ecovery (cont'd) epys, Scenario C: Project cancelled in Fall 2010 (coned) ERMU Investment (for 30 Megawatt share) : $ 3 . 44 M ERMU customers pay for project cancellation (starting September 2010) : • $3 .44 million principal, five (5) years recovery at 5 . 5%/year interest rate = $65,640/months • Assuming ERMU retail revenue is about $2 million/month : This represents an ERMU retail rate increase of ($65,640 per month/$2 million) = about 3.3%. Or, assuming retail rate of 10 cents/kWh, the rate increase would be 0.33 cents/kWh . 10 e ist 11' ecovery Scenarios (cont'd) eR4 Scenario DD: Project Cancelled J 2012 Scenario D : 1 • Project completes construction through June 2012 . • Project cancelled on 7/ 1/2012 . • Project construction is about one-half completed (see chart 4). • Plant portion of project has no market (salvage) value. • Transmission portion of project has 100% market value. And represents about 16% of total project cost to-date. • ERMU must recover BSPII plant costs from utility customers. • ERMU must replace planned BSPII plant output with other resources.2 1 . This is a very unlikely scenario. While possible, CMMPA views the probability of this Scenario occurring as low. 2. Replacement resources assumed to be Connexus incremental costs, RW Beck study Case 1 B. 11 Lost l'oecovery Scenarios (cont'd) Q.PA Scenario D : Project Cancelled 7 /1/2012 (cont'd) ERMU Project Cost (for 30 Megawatt share) = $60 M less 16% ( s10 M ) for transmission -- s50 M Debt payments starting at in -service date : . • $ 103 million, 30 years recovery at 5 . 5%/year interest rate = $293,000/month ERMU customers pay for Big Stone II plant debt service starting at in -service date in 2016 • ($293,000 per month)/(25,810 MWh per month of ERMU retail sales2) = $ 11/MWh, or 1 . 1 cents/kWh on ERMU retail sales in 2016 . • If ERMU retail rate in 2012 is 13 cents/kWh', this would be a rate increase of about 8% . 1 . From RW Beck study, Chart 16. Study shows production costs (wholesale rate) will increase about 3 cents/kWh in 2012 compared to current rates. Current retail rate is about 10 cents/kWh. 12 2. From RW Beck study Chart 27: ERMU monthly retail sales in 2012 after CIP impacts I I • Cost ' ecove Scenarios (cont'd) eRN Scenario E: Project Cancelled in 2016 Scenario E : 1 • Project completes construction through 2015, and is ready for in-service in early 2016. ® Project cancelled before plant goes in-service. ▪ Plant portion of project has no market (salvage value) . ▪ Transmission portion of project has 100% market value. And represents about 16% of total project cost. • ERMU must recover BSPII plant costs from utility customers. • ERMU must replace planned BSPII plant output with other resources.2 1 . This is an extreme worst-case scenario. While possible, CMMPA views the probability of this Scenario occurring as remote. 2. Replacement resources assumed to be Connexus incremental costs, RW Beck study Case 1 B. 13 Cost 'x ecovery Scenarios (cont'd) it Scenario E : Project cancelled in 2016 (cont'd) ERMU Project Cost (for 30 Megawatt share) = $ 123 M , less 16% ( $ 20 M ) for transmission = $ 103 M Debt payments starting at in -service date : . • $ 103 million, 30 years recovery at 5. 5%/year interest rate = $585,000/month ERMU customers pay for Big Stone II plant debt service starting at in -service date in 2016 • ($585,000 per month )/(28,060 MWh per month of ERMU retail sales2) = $21/MWh, or 2 . 1 cents/kWh on ERMU retail sales in 2016 . ■ If ERMU retail rate in 2016 is 14 cents/kWh', this would be a rate increase of about 15% . 1 . From RW Beck study, Chart 16. Study shows production costs (wholesale rate) will increase about 4 cents/kWh in 2016 compared to current rates. Current retail rate is about 10 cents/kWh. 14 2. From RW Beck study Chart 27: ERMU monthly retail sales in 2016 after CIP impacts I rARN Questions ? -.0(7,44. • Ak\' 459 South Grove Street Blue Earth, MN 56013 Phone : (507) 526-2193 Website : www.cmmpa.org 15 • , 1 ,. r :.j , Cnl / f, om• 1\ r :� ...� ��J. CIA ...-0 , .., 'awe.. ii.„ ilk i ' .:„. Agency . __ ; ,. . . . _ a 0 _, ., . . . "'—ti '.-.X.::::, 1.,,,,..,voii Services , . . ,,, ...,............„ .,_ _ Big Stone II Job Creation Elk River Municipal Utilities Commission July 8, 2009 Central Minnesota Municipal Power Agency PLFIA, • : "di rt ePA. OV eady55 no, ect o s Construction Start : Spring 2010 For plant project : Average of 640 well-paid union jobs during the 2010-2015 construction period . Peak employment of about 1,200 jobs. El Likely to be a large draw for skilled labor in a multi-state region . For 140 miles of transmission lines : a Additional well-paid union jobs. For local area : • 500 to 600 full and part-time jobs in the four-county local area for support of plant construction, and housing, apparel, food service, entertainment, etc. for workers and their families. 2 ig Ste ne ii Pr . ject: QPA " over ' ea +w y Green jo s Additional Green Jobs : ■ BSPII project's transmission lines will enable 800 to 1 ,000 Megawatts of additional wind energy development in the region . • Represents a potential doubling of capital investment compared to BSPII alone (about $2 Billion) . • Employment for wind energy per Megawatt is similar to or larger than for coal plants. • Additional green jobs for wind energy development enabled by Big Stone II transmission lines will be similar to or more than that for the Big Stone II plant alone. 3 epA. Questions? PEPIN 459 South Grove Street Blue Earth, MN 56013 Phone : (507) 526-2193 Website: www.cmmpa .org 4 f I ( ELK RIVER MUNICIPAL UTILITIES ELECTRIC INCOME STATEMENT PROJECTIONS J A I B I E I F I G I H I I J K L M N 0 1 P 1 R 1 S 1 DESCRIPTION 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2 3 GENELRAL ASSUMPTIONS 4 KWH SOLD 211,298,866 241,837,173 250,649,694 274,675,031 299,790,987 322,471,175 341,439,103 357,145,302 373,573,986 390,758,389 408,733,275 427,535,005 5 INCREASE IN METERS 364 258 300 300 300 300 300 300 300 300 300 300 6 #METERS 8,945 9,203 9,486 9,786 10,086 10,386 10,686 10,986 11,286 11,586 11,886 12,186 7 CONNECT FEE RES. 150,000 125,000 100,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 8 CONNECT FEE COMM/IND 218,182 175,769 150,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 9 10 OPERATIONS 11 REVENUE 0.085200 0.090610 0.091615 0.093100 0.092300 0.091720 0.091250 0.091150 0.088900 0.088900 0.088900 0.088900 12 FROM SALES 18,190,757 21,310,737 22,517,388 25,572,245 27,670,708 29,577,056 31,156,318 32,553,794 33,210,727 34,738,421 36,336,388 38,007,862 13 RATE CHANGE (512,159) (535,718) (672,433) (703,365) (1,021,833) (1,068,838) 14 CONNECTION FEES 368,182 300,769 250,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 15 GENERATION CREDIT 306,023 222,584 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 16 LFG PROJECT 974,040 993,257 1,000,000 1,003,000 1,005,630 1,021,569 1,038,013 1,054,740 1,071,914 1,089,370 1,089,370 1,089,370 17 OTHER 849,860 697,891 502,600 502,600 502,600 502,600 502,600 502,600 502,600 502,600 502,600 502,600 18 TOTAL REV 20,688,862 23,525,238 24,619,988 27,802,845 29,903,938 31,826,225 32,909,772 34,100,416 34,837,808• 36,352,026 37,631,525 39,255,994 19 20 EXPENSE 21 Unit Cost 0.05426, 0.05866 0.06582 0.05869 0.05869 0.05869 0.05869' 0.05869 0.05869 0.05869, 0.05869' 0.05869 22 PURCH POWER 12,175,911 14,778,270 16,079,258 17,732,745 18,685,606 20,099,235 21,281,483 22,260,431 23,284,411 24,355,494 25,475,846 26,647,735 23 LFG EXPENSE 550,062 638,556 634,000 500,376 506,621 516,175 522,648 532,432 542,336 552,360 552,361 552,362 24 PRODUCTION 200,607 247,959 275,250 283,508 292,013 300,773 309,796 319,090 328,663 338,523 348,678 359,139 25 TRANS/DIST 155,337 183,220 181,250 190,313 199,828 209,820 220,311 231,326 242,892 255,037 267,789 281,178 26 MTCE 923,965 1,089,904 1,027,100 1,073,320 1,121,619 1,172,092 1,224,836 1,279,953 1,337,551 1,397,741 , 1,460,640 1,526,368 27 DEPRECIATION 1,920,798 2,057,851 2,060,000 2,163,000 2,271,150 2,384,708 2,503,943 2,629,140 2,760,597 2,898,627 3,043,558 3,195,736 28 INTEREST BONDS 296,136 314,775 307,058 292,098 272,763 252,237 230,805 208,179 184,253 116,042 116,043 116,044 29 OTHER 965,253 972,554 1,224,200 1,260,926 1,298,754 1,337,716 1,377,848 1,419,183 1,461,759 1,505,612 1,550,780 1,597,303 30 CUST EXP 225,034 242,363 244,000 256,200 269,010 282,461 296,584 311,413 326,983 343,333 360,499 378,524 31 LFG PROJECT - 40,000 41,000 42,000 42,000 42,000 43,000 43,000 43,001 43,002 32 ADM/GENERAL 1,752,939 2,062,824 1,867,428 2,035,497 2,218,691 2,418,373 2,636,027 2,873,269 3,131,864 3,413,731 , 3,720,967 4,055,854 33 TOTAL 19,166,042 22,588,276 23,899,544 25,827,981 27,177,055 29,015,589 30,646,280 32,106,417 33,644,309 35,219,499 36,940,163' 38,753,247 34 35 GROSS MARGIN 36 (OPERATION) 1,522,820 936,962 720,444 1,974,865 2,726,883 2,810,636 2,263,493 2,194,000 1,193,499 1,132,527 691,362 502,748 37 %REVENUE 7.36% 3.98% 2.93% 7.10% 9.12% 8.83% 6.88% 6.40% 3.43% 3.12%, 1.84%', 1.28% 38 39 Bond BSII pro)cancel 2010 3,440,000 (787,680) (787,680) (787,680) (787,680) (787,680) 40 Bond SUBSTATION 2,828,349 41 Bond FEEDERS 42 Cmmpa/Mmtg 120,000 150,000 120,000 43 Total Bond Principal, 430,000 320,000 328,750 512,500 532,500 551,250 580,000 605,000 633,750 537,500 561,250 1 590,000 44 LFG PAYMENTS 'LFG Sherburne 187,766 177,060 189,351 191,323 197,438 198,440 201,581 209,353 211,511 219,297 220,213 223,255 45 LFG Overhaul 110,000 330,000 110,000 330,000 46 CAPITAL OPERATIONS 4,114,135 2,056,677 1,754,075 2,305,925 1,835,000 2,305,000 3,820,000 1,915,000 2,320,000 2,320,000 2,600,000 2,900,000 47 75%CAPITAL OFFICE 80,000 63,000 58,875 90,000 90,000 95,000 95,000 95,000 100,000 100,000 100,000 100,000 48 49 50 NET MARGIN (460,732) (1,799,775) (1,760,607) (2,032,563) (825,735) (1,126,734) (3,550,768) (1,418,033) (2,071,762) (2,154,270) (2,790,101) (3,640,507) 51 %REVENUE -2.23% -7.65% -7.15% -7.31% -2.76% -3.54% -10.79% -4.13%' -5.95% -5.93% -7.41% -9.27% 52 53 INVENTORY&ACC PAYABLE ADJ 38,305 835,299 54 DEPRECIATION 1,920,798 2,057,851 2,060,000 2,163,000 2,271,150 2,384,708 2,503,943 2,629,140 2,760,597 2,898,627 3,043,558 3,195,736 55 TRANSFER TO RESTRICTED ACCT - - - 56 ADDITION TO CASH BALANCE 1,498,371 1,093,375 299,393 130,437 1,445,415 1,257,974 (1,046,825) 1,211,107 688,835 744,357 253,457 (444,771) 57 BOND COVERAGE 733,400 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 58 RESTRICTED ACCTS 1,214,131 1.332,802 2,758.832 3,156 052 4,240,114 4,400,262 3.615,133 4.123,463 4,440.089 4,998,357 5,088,450 4,554,872$3.5 Million Goal 59 UNRESTRICTED ACCTS 116,058 125,558 116,658 116,088 118,658 900,000 900,000 1,300,000 1,500,000 1,500,000 1,600,000 1,800,000 60 CASH BALANCE 1,501,039 2,450,192 1,033,062 1,065,671 1,427,025 1,741,518 1,479,812' 1,782,589 1,954,798 2,140,887 2,204,251 2,093,058 61 TOTAL CASH BALANCE 3,539,677 4,633,052 4,932,445 5,062,881 6,508,296 7,766,270 6,719,445 7,930,551 8,619,387 9,363,743 9,617,201 9,172,430 62 63 rate incraasa 3,20% 2.90% 2,70% 2,60% 2.50 SpringsladElec2 Page 1 ( ELK RIVER MUNICIPAL UTILITIES ELECTRIC INCOME STATEMENT PROJECTIONS A -- B.--r--E-1 F I G I H I I I J I K I L I M I N I 0 I P I R I S 1 DESCRIPTION 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2 3 GENELRAL ASSUMPTIONS i 4 KWH SOLD 211,298,866 241,837,173 250,649,694 274,675,031 299,790,987 322,471,175 341,439,103 357,145,302 373,573,986 390,758,389 408,733,275 427,535,005 5 INCREASE IN METERS 364 258 300 300 300 300 300 300 300 300 300 300 6 #METERS 8,945 9,203 9,486 9,786 10,086 10,386 10,686 10,986 11,286 11,586 11,886 12,186 7 CONNECT FEE RES. 150,000 125,000 100,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 8 CONNECT FEE COMM/IND 218,182 175,769 150,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 9 10 OPERATIONS 11 REVENUE 0.085200 0.090610 0.091615 0.090200 0.089670 0.089270 0.088900 0.088900 0.088900 0.088900 0.088900 0.088900 12 FROM SALES 18,190,757 21,310,737 22,517,388 24,775,688 26,882,258 28,787,002 30,353,936 31,750,217 33,210,727 34,738,421 36,336,388 38,007,862 13 RATE CHANGE (512,159) (535,718) (672,433) (703,365) (1,021,833) (1,068,838) 14 CONNECTION FEES 368,182 300,769 250,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 15 GENERATION CREDIT 306,023 222,584 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 16 LFG PROJECT 974,040 993,257 1,000,000 1,003,000 1,005,630 1,021,569 1,038,013 1,054,740 1,071,914 1,089,370 1,089,370 1,089,370 17 OTHER 849,860 697,891 , 502,600 502,600 502,600 502,600 502,600 502,600 502,600 502,600 502,600 502,600 18 TOTAL REV 20,688,862 23,525,238 24,619,988 27,006,288 29,115,488 31,036,171 32,107,391 33,49$,839 34,837,808 36,352,026 37,631,525 39,255,994 19 20 EXPENSE 21 Unit Cost 0.05426 0.05866 0.06582 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 2 2 PURCH POWER 12,175,911 14,778,270 16,079,258 17,732,745 18,685,606 20,099,235 21,281,483 22,260,431 23,284,411 24,355,494 25,475,846 26,647,735 23 LFG EXPENSE 550,062 638,556 634,000 500,376 506,621 516,175 522,648 532,432 542,336 552,360 552,361 552,362 24 PRODUCTION 200,607 247,959 275,250 283,508 292,013 300,773 309,796 319,090 328,663 338,523 348,678 359,139 25 TRANS/DIST 155,337 183,220 181,250 190,313 199,828 209,820 220,311 231,326 242,892 255,037 267,789 281,178 26 MTCE 923,965 1,089,904 1,027,100 1,073,320 1,121,619 1,172,092 1,224,836 1,279,953 1,337,551 1,397,741 1,460,640 1,526,368 27 DEPRECIATION 1,920,798 2,057,851 2,060,000 2,163,000 2,271,150 2,384,708 2,503,943 2,629,140 2,760,597 2,898,627 3,043,558 3,195,736 28 INTEREST BONDS 296,136 314,775 307,058 292,098 272,763 252,237 230,805 208,179 184,253 116,042 116,043 116,044 29 OTHER 965,253 972,554 1,224,200 1,260,926 1,298,754 1,337,716 1,377,848 1,419,183 1,461,759 1,505,612 1,550,780 1,597,303 30 GUST EXP 225,034 242,363 244,000 256,200 269,010 282,461 296,584 311,413 326,983 343,333 360,499 378,524 31 LFG PROJECT - 40,000 41,000 42,000 42,000 42,000 43,000 43,000 43,001 43,002 32 ADM/GENERAL 1,752,939 2,062,824 1,867,428 2,035,497 2,218,691 2,418,373 2,636,027 2,873,269 3,131,864 3,413,731 3,720,967 4,055,854 33 TOTAL 19,166,042 22,588,276 23,899,544 25,827,981 27,177,055 29,015,589 30,646,280 32,106,417 33,644,309 35,219,499 36,940,163 38,753,247 34 35 GROSS MARGIN 36 (OPERATION) 1,522,820 936,962 720,444 1,178,307 1,938,433 2,020,582 1,461,111 1,390,423 1,193,499 1,132,527 691,362 502,748 37 %REVENUE 7.36% 3.98% 2.93% 4.36% 6.66% 6.51% 4.55% 4.15% 3.43% 3.12% 1.84% 1.28% 38 77 Bond BSII pro)cancel 2010 3,440,000 (787,680) (787,680) (787,680) (787,680) (787.680) 40 Bond SUBSTATION 2,828,349 411 Bond FEEDERS 42 Cmmpa/Mmtg 120,000 150,000 120,000 43 Total Bond Principal 430,000 320,000 328,750 512,500 532,500 551,250 580,000 605,000 633,750 537,500 561,250 590,000 44 LEG PAYMENTS LFG Sherburne 187,766 177,060 189,351 191,323 197,438 198,440 201,581 209,353 211,511 219,297 220,213 223,255 45 LFG Overhaul 110,000 330,000 110,000 330,000 46 CAPITAL OPERATIONS 4,114,135 2,056,677 1,754,075 2,305,925 1,835,000 2,305,000 3,820,000 1,915,000 2,320,000 2,320,000 2,600,000 2,900,000 47 75%CAPITAL OFFICE 80,000 63,000 58,875 90,000 90,000 95,000 95,000 95,000 100,000 100,000 100,000 100,000 48 49 50 NET MARGIN (460,732) (1,799,775) (1,760,607) (2,829,121) (1,614,185) (1,916,788) (4,353,150) (2,221,610) (2,071,762) (2,154,270) (2,790,101) (3,640,507) 51 %REVENUE -2.23% -7.65% -7.15% -10.48% -5.54% -6.18% -13.56% -6.63% -5.95% -5.93% -7.41% -9.27% 52 53 INVENTORY&ACC PAYABLE ADJ 38,305 835,299 54 DEPRECIATION 1,920,798 2,057,851 2,060,000 2,163,000 2,271,150 2,384,708 2,503,943 2,629,140 2,760,597 2,898,627 3,043,558 3,195,736 55 TRANSFER TO RESTRICTED ACCT - - - 56 ADDITION TO CASH BALANCE 1,498,371 1,093,375 299,393 (666,121) 656,965 467,919 (1,849,207) 407,530 688,835 744,357 253,457 (444,771) 57 BOND COVERAGE 733,400 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 58 RESTRICTEDAGCT9 1,214,131 1.332,802 2,758,832 2.558.634 3,051,358 3,268.955 1,882,050 2,187,697 2,454,324 3,012,591 3,202,684 2,869,106$3.5 Million Goal 59 UNRESTRICTED ACCTS 118,088 125,658 118658 116,688 116,658 250,000 250,000 250,000 500,000 500,000 500,000 500,000 60 CASH BALANCE 1,501,039 2,450,192 1,033,062 866,532 1,030,773 1,147,753 685,451 787,333 959,542 1,145,631 1,208,996 1,097,803 61 TOTAL CASH BALANCE 3,539,677 4,633,052 4,932,445 4,266,324 4,923,289 5,391,208 3,542,001 3,949,530 4,638,366 5,382,722 5,636,180 5,191,409 62 63 no rate Increase SpringstadElec2 Page 1 ELK RIVER MUNICIPAL UTILITIES ELECTRIC INCOME STATEMENT PROJECTIONS A I B I E I F I G I H I I I J I K I L I M I N I 0 I P I R I S 1 DESCRIPTION 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2 3 GENELRAL ASSUMPTIONS 4 KWH SOLD 211,298,866 241,837,173 250,649,694 274,675,031 299,790,987 322,471,175 341,439,103 357,145,302 373,573,986 390,758,389 408,733,275 427,535,005 5 INCREASE IN METERS 364 258 300 300 300 300 300 300 300 300 300 300 6 #METERS 8,945 9,203 9,486 9,786 10,086 10,386 10,686 10,986 11,286 11,586 11,886 12,186 7 CONNECT FEE RES. 150,000 125,000 100,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 175,000 8 CONNECT FEE COMM/IND 218,182 175,769 150,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 200,000 9 10 OPERATIONS 11 REVENUE 0.085200 0.090610 0.091615 0.090200 0.089670 0.089270 0.088900 0.088900 0.088900 0.088900 0.088900 0.088900 12 FROM SALES 18,190,757 21,310,737 22,517,388 24,775,688 26,882,258 28,787,002 30,353,936 31,750,217 33,210,727 34,738,421 36,336,388 38,007,862 13 RATE CHANGE (512,159) (535,718) (672,433) (703,365) (1,021,833) (1,068,838) 14 CONNECTION FEES 368,182 300,769 250,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 375,000 15 GENERATION CREDIT 306,023 222,584 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 350,000 16 LFG PROJECT 974,040 993,257 1,000,000 1,003,000 1,005,630 1,021,569 1,038,013 1,054,740 1,071,914 1,089,370 1,089,370 1,089,370 17 OTHER 849,860 697,891 502,600 502,600 502,600 502,600 502,600 '502,600 502,600 502,600 502,600 502,600 18 TOTAL REV 20,688,862 23,525,238 24,619,988 27,006,288 29,115,488 31,036,171 32,107,391 33,496,839 34,837,808 36,352,026 37,631,525 39,255,994 19 20 EXPENSE 21 Unit Cost 0.05426 0.05866 0.06582 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869 0.05869, 22 PURCH POWER 12,175,911 14,778,270 16,079,258 17,732,745 18,685,606 20,099,235 21,281,483 22,260,431 23,284,411 24,355,494 25,475,846 26,647,735 23 LFG EXPENSE 550,062 638,556 634,000 500,376 506,621 516,175 522,648 532,432 542,336 552,360 552,361 552,362 24 PRODUCTION 200,607 247,959 275,250 283,508 292,013 300,773 309,796 319,090 328,663 338,523 348,678 359,139 25 TRANS/DIST 155,337 183,220 181,250 190,313 199,828 209,820 220,311 231,326 242,892 255,037 267,789 281,178 26 MTCE 923,965 1,089,904 1,027,100 1,073,320 1,121,619 1,172,092 1,224,836 1,279,953 1,337,551 1,397,741 1,460,640 1,526,368 27 DEPRECIATION 1,920,798 2,057,851 2,060,000 2,163,000 2,271,150 2,384,708 2,503,943 2,629,140 2,760,597 2,898,627 3,043,558 3,195,736 28 INTEREST BONDS 296,136 314,775 307,058 292,098 272,763 252,237 230,805 208,179 184,253 116,042 116,043 116,044 29 OTHER 965,253 972,554 1,224,200 1,260,926 1,298,754 1,337,716 1,377,848 1,419,183 1,461,759 1,505,612 1,550,780 1,597,303 30 CUST EXP 225,034 242,363 244,000 256,200 269,010 282,461 296,584 311,413 326,983 343,333 360,499 378,524 31 LFG PROJECT - 40,000 41,000 42,000 42,000 42,000 43,000 43,000 43,001 43,002 32 ADM/GENERAL 1,752,939 2,062,824 1,867,428 2,035,497 2,218,691 2,418,373 2,636,027 2,873,269 3,131,864 3,413,731 3,720,967 4,055,854 33 TOTAL 19,166,042 22,588,276 23,899,544 25,827,981 27,177,055 29,015,589 30,646,280 32,106,417 33,644,309 35,219,499 36,940,163 38,753,247 34 35 GROSS MARGIN 36 (OPERATION) 1,522,820 936,962 720,444 1,178,307 1,938,433 2,020,582 1,461,111 1,390,423 1,193,499 1,132,527 691,362 502,748 37 %REVENUE 7.36% 3.98% 2.93% 4.36% 6.66% 6.51% 4.55% 4.15% 3.43% 3.12% 1.84% 1.28% 38 39 Bond SUBSTATION 2,828,349 40 Bond FEEDERS 41 Cmmpa/Mmtg 120,000 150,000 120,000 42 Total Bond Principal 430,000 320,000 328,750 512,500 532,500 551,250 580,000 605,000 633,750 537,500 561,250 590,000 43 LFG PAYMENTS LFG Sherburne 187,766 177,060 189,351 191,323 197,438 198,440 201,581 209,353 211,511 219,297 220,213 223,255 44 LFG Overhaul 110,000 330,000 110,000 330,000 45 CAPITAL OPERATIONS 4,114,135 2,056,677 1,754,075 2,305,925 1,835,000 2,305,000 3,820,000 1,915,000 2,320,000 2,320,000 2,600,000 2,900,000 46 75%CAPITAL OFFICE 80,000 63,000 58,875 90,000 90,000 95,000 95,000 95,000 100,000 100,000 100,000 100,000 47 48 49 NET MARGIN (460,732) (1,799,775) (1,760,607) (2,041,441) (826,505) (1,129,108) (3,565,470) (1,433,930) (2,071,762) (2,154,270) (2,790,101) (3,640,507) 50 %REVENUE -2.23% -7.65% -7.15% -7.56% -2.84% -3.64% -11.10% -4.28% -5.95% -5.93% -7.41% -9.27% 51 52 INVENTORY&ACC PAYABLE ADJ 38,305 835,299 53 DEPRECIATION 1,920,798 2,057,851 2,060,000 2,163,000 2,271,150 2,384,708 2,503,943 2,629,140 2,760,597 2,898,627 3,043,558 3,195,736 54 TRANSFER TO RESTRICTED ACCT - - - 55 ADDITION TO CASH BALANCE 1,498,371 1,093,375 299,393 121,559 1,444,645 1,255,599 (1,061,527) 1,195,210 688,835 744,357 253,457 (444,771) 56 BOND COVERAGE 733,400 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 724,500 57 RESTRICTED ACCTS 1,214.131 1,332,802 2,758.832 3,149,394 4,232,878 4,391,235 3,595,090 4,091,497 4,408,124 4,966,391 5,056,484 4.522,906$3.5 Million Goal 58'UNRESTRICTED ACCTS 116,658 125,558 116,658 116,658 116,658 900,000 900,000 1,300,000 1,500,000 1,500,000 1,600,000 1,800,000 59 CASH BALANCE 1,501,039 2,450,192 1,033,062 1,063,452 1,424,613 1,738,513 1,473,131 1,771,933 1,944,142 2,130,231 2,193,596 2,082,403. 60 TOTAL CASH BALANCE 3,539,677 4,633,052 4,932,445 5,054,004 6,498,649 7,754,248 6,692,721 7,887,930 8,576,766 9,321,122 9,574,580 9,129,809 SpringstadElec2 C>_ �� Page 1 k,,ti p 1 rCMMPA KrAxW .N,. Agency , ,-.- i -, g y r: r • 4 OY . Services ,,, ,, ,, Resource Portfolio Proposal Elk River Municipal Utilities Commission July 8, 2009 Central Minnesota Municipal Power Agency , .....„..., RN C ( • Th e Risk of No Action TheOpportunity CMMPA Proposal Conclusions 2 L a The ' ' s I No Acti o n Now Elk River has an opportunity to make an important strategic by decision now that will benefit its customers for many years. J The difference between renting generation in a marketplace that is headed for shortages, versus : a Owning and controlling your energy future. Not making a decision now has its own set of significant risks . Regardless of who owns the risk associated with developing generating capacity that services ERMU in the future, Elk River's retail customers will pay for the decisions made regarding their future energy supply . With CMMPA, you would be involved in the decisions that affect your customers in the future . Question: Is it a good idea to have a competitor for your retail customer service area be your sole-source energy supplier too? 3 P:J ..--, (1) (1) , X CM ICI 1,s, magawafts 3 (1) immi•, 0 ,...2 0.2 . 1 -. NI i„.) fi'. 01 01 ‘'''': C 0 i C 0 0 0 0 0 0 0 0 0 , 3 r) 0 C3 0 00 0 0 "79 i , o 0 0 0 0 0 ....., .... kit% IQ 'IN. et) tIQ /' I I i (D i7,,,,,c' , Lc w , C Cl) )•N...I le ) 13 t { 1 T I 120 I --1 I n 0 ri. tu )7 ) rim $00:\ 0 0 tD 0 61%4" 1.911/f ir 1% 0, C 3 170 , Pi I k a)e 1 t70 . 1` z n 1 3 • li-L (1)imik (D ir 1\ I'S.1 0 CO I'D r 4 1 0) CO ril ,C 'V / timilh Viii) ites i 3.3 .0 * ii9 9 I 4 0 )mL e 13 sa 0 0 I •-, t) ch, 03 r- Z_,,,, CD a 3 , g, "It a. e T V10a. 1 '. 1 0 ti P*41 c ,‘,...b , r: -I c 0 5- N... o a) I, ri. I"... 31 -.,l'i .) rto / 0 CUR) rt o 6;1 c'4 3 73 :71, F 1 i tit%, Di IP 1(2 a, INIfti 3 ), a Q0 ,,,,," 0) 4r Na..., 11 71 04 0 -u•, , rt 5- 1 0 ft) °IliCil lk rb a g a o5 , 19 i 0 (1) 1:4% pitit".1 ri ,' z itammL liMie• el) ,.. ---- - QD r2 0 ' m ,, , To - 4, / 9. I I 1... _ - r Iiiiii a 0 t..., _ _ 4 z — • * .X: ix• loft a a. • I r• u A 0 ,Z47 y.; 3 TII 3 Zs ID•*4 0 atlan -,= cou 0 C a„- 0 .44. —• It 7 C OA , 0 fj 0 ;047-0 ti) tt'T3 9.1 F-,-,, Vi , › '0 Tr iii) , PJ ,•". O .......44, K 0 i...1 ...... 0 4 JR C a 1 _J /cw 1. 1I `a J ^� J l�ti.� 7. 23 Declining regional generation capacity reserves means : ■ A tighter regional generation market. ® Generation owners will pull back low-cost energy resources from wholesale customers for their own retail customers. Increasingly, such resources will not be available to municipals who are not already members of an agency. ■ Increasing reliance and dependence on higher-cost natural gas generating resources at the margin . This is where the next Connexus/GRE offer, based on incremental resources at the margin , will likely take ERMU over the long term . 5 , _....___ Coal is close to home ,.., I Other North America 711". Russia 173 0,-- -- ere - ,. .ar .4.1 ft • % 1 'E. ":°Pe 4r4-4"..4.1.4i Other Eurasia China 4r ---,„ S r* -' • -4.- ,,,* -' - States 126 iv Middle ., '..,.• lk j ......::. East%, India i4fr ---..... - • • .... u r IF tkOceania • --....... . tcde 4 Africa Central & Sout' \ .IX 4 ',.. ....."--- s \ America , --........., ••• ,..„4_,..,, i m I t Australia N, d. 1 ° Source: Developed from U.S. Energy Information 0 it , —A Administration. International Energy Annual 2005, Table 8.2, http.ftwww ca..doe govipuiginterriationgliiea2005/1Ab1e82.xis World estimated recoverable coal : 998 billion tons 6 ;4., „,-,, 4..t."`"' tr:rk ( ( ( ; f eso s ark In n • ly orei • - ase I U.S. Net imports of Natural Gas by Source, 1990-2030 Trillion Cubic Feet b History Projections 4 1 • Net imports from Canada Overseas LNG are declining. 2 f, Liquefied natural gas (LNG) _ Canada imports from overseas are x r increasing. 0 Mexico _1 Result: Natural gas will 1990 2004 2010 2020 2030 increasingly be a global Sources: History: Energy Information Administration (EIA), market commodity Annual Energy Review 2005, DOE/EIA-0384(2005) (Washing- ton. DC, August 2006), web site www.eia.doe.gov!emeuIaer (like oil is now) Projections: EIA, Annual Energy Outlook 2007, DOE/EIA- 0383(2007) (Washington, DC, February 2007). 'web site VAT eia.doe.gov/oiaf/aeo. 7 ---_. .c.-4 .- . . -- Natural gas risk: Who holds ', ! -:!!: re ,, ,it .T,, ircfs ,..e. 1 ' -:-, 4,74, ...,* aPh /.. .....t " ,... ,.. ......,... ,...... ,ii, 7 -.,, 419.°. , .,......z L,,, 4*-- eta; l ,t4 - Eastern Europe & 4 1 4- , ,,,,-...-.. Former U.S.S.R. „a. North N America i Wesatein ft:-i. - - ... ,,t -,.... ti :ir !' ,'i • ,,,IN Europe -'*-- Middle :.., East 264 4. r / ..."‘' - tip Caribbean 2 - ... , ,.,i ' 4-1 -m-0, L \ r- „.. C) Africa ' . ' ''' , .sia & Oceania .„,,,,,„ 4 , ... entr.1 & South _rr4..,,i ........... ...b „... Amer', a I % t , .:. \ -\ " ....„til: ..... A 1. Source: Oil and Gas Journal, 2005 data. Proven world gas reserves: 6,044 trillion cubic feet 8 ( ( Natural Gas Prices and Demand are Increasing Real Natural Gas Prices vs. Gas Power Generation Capacity Additions in U.S., 1989 to 2008 Real gas prices have increased by a factor of 4, spurred in part by massive gas capacity increases 250 — — $10.00 $9.00 200 — — $8.00 — $7.00 150 — — $6.00 Cumulative - $5 00 $/mmBtu gas capacity additions 100 $a.00 (GW) - $3.00 i 50 $2.00 $1.00 1 0 -`1 . it A t 1 $0.00 ®cumulatore adtt H H Price Source: Natural Gas and Electricity Costs and Impacts on Industry, White Paper on Expected Near-Term Cost Increases, April 28, 2008, U.S Department of Energy, p. 2 Natural gas prices are relatively low today due to the economy g When the economy comet hack, so will gas prices. Allocation of Risk Three major unknowns: future construction cost, natural gas price, CO2 cost Construction and fuel costs Construction cost for natural gas for Big Stone II and wind alternatives Carbon risk Natural gas risk Shareholder (or City) risk Ratepayer risk 10 Balancing the Risks of Baseload Options The future price and energy independence risk of natural gas is greater than the alternative carbon cost risk of coal.* *Natural gas is also a fossil fuel. It emits 50% to 70% of CO2 per MWh compared to coal, depending on technology used. 11 RW Beck Studyfor E U .......... * re-, . Natural Gas Price Volatility .,.- - , , , , Levelized Power Supply Cost for 2019-2028 ' . Base Low Gas/ High Gas/ Case No CO2 Base CO2 Case 1 - GRE $/MWh $115.43 - $145.13 $81.99 - $101.32 $116.80 - $154.93 t Case 2A - BSII + Gas (Muni) $/MWh $121.23 $90.64 $123.47 i { Case 2B - BSII + Gas (Merchant) $/MWh $146.07 - - Case 3A - Gas (Muni) $/MWh $129.42 $109.77 $149.13 Case 3B - Gas (Merchant) $/MWh $164.59 - - Case 4 - BSII + Mkt $/MWh $124.67 $93.75 $127.39 Plans with large amounts of natural gas in them (Case 1A (GRE) and Case 3) have higher potential price volatility than plans with Big Stone II. *RW Beck study for ERMU 6/15/09, updated 6/30/09 to include High Gas scenario 12 for Case 3A, 6/30/09. I , Balancing the Risks of Baseload Options "Using natural gas to produce baseload electricity is like washing dishes with good Scotch. " Former U. S. Energy Secretary Samuel Bodman 13 1 /-...„ ^-� ff FFF,- 0 J LI I D 4.._> '. f T 6 CD -0 (D c C/)° V) 7,° (D ® ( ( ) i ' 0 rm.. D- - D (D D 0_ = ® ® C D p D • e-)-.1 0 cDC:r (Dx M S 7------. 0. CAD 2 rt 0- C C rr ® 7o e. O Ch O � 7. a � rD C IC r-1- c C3) LCI 0 3 2 5. a' r D 3 (D o . 17:- filim 21 0 5 9L 0 --1 c a) D- cr (1,)i C1) 0 u.) n CD O (1) C � 0 -° m n° in -0 D .41 ri- 2 =. rD ccn < c0 rt rn ci CD 0 t cD _ D 0L � C X � .M111 MI 0 CD CD CD n _Cr' -j (D -< D D oi -1 CO ro O Cl) cli C rt � < o �Do � 3 < CD � 1D- xDrnDo - n C 0 v) 70 al m r. i 0 ^_.. ..,11 r) fl H z et)H D.- D- D r) Z CD CD — V O (X 111) DP via o 10 0 P o �- - o D 2 (In -• CD %< D c) _a 0 m rr r U 0 it m � _. i� T The Beck studyfor ERMU shows that a balanced and diverse energy supply portfolio consisting of : Large quantities of renewables. ■ Large quantities of energy conservation . • A share in the fuel-efficient new Big Stone II power plant project. • Moderate amounts of natural gas-fired facilities and market purchases Is more cost-effective for ERMU customers than likely future offerings from Connexus/GRE . CMMPA proposes to build that diverse, balanced and "green" plan for Elk River over the next few years. 16 ( l ERMU-Owned Portfolios rart*. ', : Mean Lower Costs for Custo ers ERMU-owned resource t1 j portfolios including Big Stone II Results Projected Power Supply Cost t and other resources cost less ERMU Comparison of Power Supply Alternatives I than likely Connexus options. P1Base Scenario I 5180 r=GRC Rango .. -'. ..„, CasP I -CRF Avq s �..so U-O . 5160 C,st,d_GRE,, , - .. ERMU-owned gas resource g " H r9Ke 2A BSII Gm V,,,,,i 1 ° $140 c.m.2P PSI'r`Ag(0.9,0 nt. ; i " portfolios are next-best to �4s ,ase 3A has(Mum_ µ,�-.� t ' '3 p $1 20 C�.wr•36 C'as(111ercY.=ntt L 1 a $100 Big Stone II-based ones. �. D 580 ro $60 0 t $20 The cost savings between the Big Stone II portfolios and 1 ,, the CURB Incremental Case IA is $6 million to $8 million/year. *RW Beck study for ERMU, Chart 17. 17 ( ( ( 0 0 The Risk of No Action The Opportunity CM M PA Proposal Conclusions 18 n n I 4 � o cu rr (D co O rt o LC) U21 03 ® Cir) CD CD ° rn m CD n it n n 3 o (1..t.1 CD — tea) -1 0 0 14 tD 0 m ■ ■ VI -0 -"C) I OJ 71 CT n -73 P lb c Di ED s , D OJ OJ V' iniasia CO 0 •< .—. 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Li We want to take over and control your retail service area. 1 4 NA k CMMPA means flexible options over time; not "take-it-or-leave-it. " 21 Li1:,, ( i 1 411--t . 1 . s ,...� : � , �.� rtf. li . (cont'd) to The CMMPAagencybusiness model : An analogy a *1 Traditional agency model CMMPA agency model r- - - tibMr 9 " rxe,t.n S Y f Y raw;.f S 01 [vMFi Ao.Ptrglnp r FR L'iUAitg tf4A i _ Or li, 4 ram.: You have to buy the entire record album You buy only the songs or CD, including songs (resources) you don't want. (resources) you want. 22 1 a L 4 f\-rL " <'.: e 1 111 (cont'd) LA c„taw Working with you , and based on your resource needs and preferences, CMMPA proposes to build a customized resource portfolio for ERMU . • To realize the future benefits shown in the RW Beck study. The portfolio will be aimed to complement and eventually replace your current contract with Connexus/GRE when it expires in 2018 . • It will build into a full requirements portfolio over time, using individual resource decisions by ERMU over the period . CMMPA will create a custom CMMPA membership category for ERMU to enable the transition over the coming years. CMMPA offers flexible future alternatives for your resource suppff enabling ERMU to stay independent while managing future costs. 23 ( ( + ePA Building Elk ' 49 /al ' ir t o„?, The diverse and balanced, ERMU-owned and controlled portfolio approach we propose for ERMU is worthy of the title: "Energy City" 24 ( ( 1 raft' I • I, 1 • *la in .`., t♦ 1' 1* les ” . ,I P. en " e • \ i I packag tc ree Componen ts of the ERMU Green, ,,, Package : As a portion of your future resource '` portfolio, the RW Beck study for ERMU . assumed you would achieve the Minnesota Renewable Energy Standard a (RES) of 25% by 2025, in addition to other resources. 25 ( y av esource Portfolio w i ,. : ,r-- S :-a 7) - (f' Components of CMM PA's Green Package for ERMU } Transition of ERMU's existing landfill gas generation output back to ERMU control when Connexus/GRE contract expires. Energy and green credits • Development of additional ERMU landfill gas facilities when timing is right for ERMU . ERMU keeps energy and green credits for its own customers' benefit. CMMPA will market any surplus for ERMU, until ERMU is ready to absorb it for ERMU customers. • Development of new wind or other renewable resources for ERMU to meet or exceed the Minnesota Renewable Energy Standard ( RES) of "25% by 2025". In concert with similar projects for current CMMPA members, or projects unique to ERMU . With CMMPA, Elk River can decide how aggressive you want the renewables element of your resource portfolio to be. 26 -;---'1 FieSt r'''''''''':'-' 71 ,i,i11:' 71" /Ii'l"IP) ie.'" \\\ ° . II '1/4, ' ...,:— ,'. _L.I., .,...i: i\-,0 t ..... ,, 1 Inn ac - . fe r enewables Regional Average Wind Speed Map 45.50 Bi s Stone Pl. 45.,C0 CMMPA members are near the Buffalo Ridge wind fields 4.1,50 1. 4.1An 4 a -. .. eta 43 SG -- CMMPA service area `:, -97.1X+ .,:ti!KJ 5 9f; aq 00 •4.°° -42 00 -910::: '''''.:"0 ''.'1::' _ '''::::: :r...ilt'e...'''''''- '', M.N!nu pi snts .,wy 1 - 27 3 Bit • ' • .• r Res . r e o c ree ac a • - " • Energy Conservation • Components of the CMMPA Green Package for ERMU (continued) : As a portion of your future resource portfolio, the RW Beck study for ERMU assumed you would achieve the aggressive new Minnesota Conservation Improvement Program (CIP) goal of 1.5% per year energy savings, in addition to other resources. 28 ( ( w ...„ , , r • C.) m n �® Ln rn 73 73 0 0 0 0 Z 0 0 Z 3 n C11 cry D Lo n 0D X > O V IQ rI Pi) n (-I- rD s El CD n E f D cD 41 CDt-t o (Dup - D n c� (--tP::1 - CU CA o �- 3 � irD tt rD O kg 0� 3 n.... - cr• co, —.(--r CD -p . . r.t.a) 3 (Dx 3 o n CD O IQ 'it '� c� O 'soi�D CD D CD es 0 O ° - O ci rn D (n n z CD CI) C 14) x 3 (1) E -a — GE) o P-0 CD � 0 � � CD � r�_-r � �, (.0 t-r D r' r� ..... \ si, D- 11) -\-) r--1--0 o n p 0 ..,. 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Z D , CD • cn (f) -1 'i 0 (-1- P 0 0 (i) a ri. -.0 ;71-1 C Z CD a) P 4. rt = 6 rig,. z -.< - —• (f) (D co • (D 0 v) II - 0 — v) C GP La v 73) e) ci) _. cn (I) CD foek (DI•.... ...... 0-- n -1 (D < D r) v) 0 ---h CD a) -0(-I- -i rr 0 D LCD rt 1:1) 0 m V) --1 (1) ••< 0 r-i- il) • v) V) , ( ri- (D s 0 -h , AD 0 y • m Cjtr i ient e % aseloa • Ca . achy (cont'd) Big Stone II supports the " Green PackageLI " Supersized transmission lines that will enable 800 to 1000 MW of additional wind development Will unlock about $2 Billion in private capital investment in renewables. • Supercritical pulverized coal technology, with ultra- supercritical technology being considered Will be one of the most fuel-efficient coal plants in the U .S. • Common scrubber to be added to existing Big Stone I unit as part of the Big Stone II project. Will result in decreased site emissions of SO2, particulates and mercury, while site electric output will be more than doubled. • Plant to be built "carbon-capture retrofit-ready" For when carbon capture technology becomes available. All credible forecasts of meeting future U .S. carbon reduction goals include large amounts of coal power plants with carbon capture. The Big Stone project wa.:i designed to be a part of its Owners' environmentally-responsible resource portfolios. 31 C Ac ie ; r . .. ' - �. . t1 tss I : is ,4„„,..., The Role of o Plants with Capture CO2 Reductions ... Technical Potential* All credible forecasts of meeting proposed 36nr ...._... __... ..._ _ _._...__ __ _ ...._..__.. _._.__.__...,......._._.-__..., ,, U.S. CO2 reductions ! EIA Base Case 2007 include large ai quantities of coal plants c �_- _. with carbon capture. W R9500. KN tb 1elaniy Lard Orew .-+l 5%.7r Load prewtk--r1J'i.1yr Pi ;j/ Rsrvwrbpa 00 0174 ny MO T - 70 OW.by 101E Y 10 NudMor(ianernUan 13,6 OWa by 90OQ di OW,by anC)•:,,-H, No Qairtin0 Plant UperMM I 1110 flute Plant UppnAn U - A 0 dvanaad Coal .neratlonSQMr New NiP1Fn1 CMlC}envy OMNsw Ptrnt i<.ttk!rn0y by 1010-1030 1 by 1020;40%in Me i0C E CC>s „_ tier.* W7dely?7a4!oybd Alter 1020 1MofNwrVsWele Soles—by 201,; Coal plants with CO2 - PH6V Nary ..2.4!yr 7twwrotttrr f11=p 0 1%a date teat!in DSO 0%a(Dame Lard in 1010 I capture and storage ".co 1WS 2000 2005. 2090 2015 3020 2015 Ach+ rng ae targets Is very eggreavve but pntentleny feasible, n te fl at,7,.,.,a...+rs err .:1rr rtr,-.¢f^% 13 Ct- CI ,arGna...z,Nm. *Source: "Electricity Technology in a Carbon-Constrained Future", Electric Power Research Institute (EPRI), February 2007. 32 , I 1 ® • . z O • ., I . • r o • e -F4 icient ew r ase oa G. , acity (cont'd) CMMPA can help you manage your Big Stone II 4b: participation share • We can contract with other utilities to diversify your dependence on a single baseload plant turbine-generator "shaft". Hedging the risk of market replacement energy necessary when the unit is out of service for maintenance. • We can contract for sale of your share of the unit to other entities during the overlap between Big Stone II commercial operation date in 2016 and the end of your GRE contract in 2018 . To avoid duplication of or conflicts with your current full requirements contract with Connexus/GRE. CMMPA operates in the MISO market every day. We can make the transactions necessary to optimize your portfolio over time. 33 ft 1 . • • ' eso c - Portfolio e at .rai Gas-. i ed Casacity and rc ases ERMU 's current oil -fired generating capacity to be retained for ERMU 's use after Connexus/GRE contract expires. To fill out the ERMU resource mix, CMMPA will procure additional natural gas-fired capacity and market purchases . Intermediate duty needs Natural gas-fired combined-cycle units ERMU ownership of a share of new units, or longterm purchases. 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R °vr h 1\\V ,\ j / 1rnsrsr J '''%,. \V r • Henning IvILL 6 reckanrkl®. i AC S t AMC Randall® 'S Elbows Lake• •Plata Atarndrle' 151ora• Sauk CentreMelrose PrincetonPrinceton• North Drench o„an�, Ater/owing Elk River ICendlyoht °rov.CityDudala Anoka C1rcIs • • Pines * * Litchfiel•d •o....+n 0 Delano • IAadtsan Willmar North an St.St.Paul • Granite Falls O ti_aim.• erevrMen• Glencoe Shakope Arlington • Neer PreQw Fairfax O • • 'IS Redwood Fins �_ WMlhro i Martha!! p Le Sueur O take C Sleepy Eye .Tyler Q Si Peter ® Kenyon Springfield 0 Janesville • 0 .sec' Owatonna ltoc Mt ter Westbrook lb • Kasson 0 • Mt. Lake `sL.tarti.a a st CMrin ® ® �loominq Prairie 11 Windom • • P.lereon entrenewd- j , 1lr.wstar y0 Welts Lanesboro •Whalen L "e" LaV.l.le Felrmo^" • spring • Caledon►e f, • Adrian lack n Valley+ •Preston • Worthington • Alpn■ • O Blue Earth u chino r� WWwx►►a.11Austin n Mabsl prow r, tilq.tow t •Round Lake jGylon Harmony• e ms* 37 .: *Although not a CMMPA member, Willmar is participating in the Big Stone II Project via the agency. 1 I 1 5 Jr-4'z' cpj Manage future cost increases by : • Owning generation and transmission assets ; rather than renting them . • Reducing dependence on oil and natural gas for baseload generation . Manage future risks by enacting a diverse resource portfolio : Li Renewables ® Energy conservation • Conventional supply resources J Be environmentally responsible Stay independent 38 ai Ya 4na i • t - - - fits The Challenge • ERMU could use many of the benefits of CMMPA membership right now. Examples: Resource planning, project development, participation with other municipal utilities in addressing industry changes. • But, you don 't need them all until your current Connexus/GRE contract expires . Example : MISO Market Participation and daily scheduling The Solution • Create a flexible new CMMPA membership category for ERMU that enables the entire suite of membership benefits as your needs evolve over the next few years. Providing ERMU the opportunity to actively participate in the planning for your future resource options, as well as the development of them. 39 _ . Membershift rt. • Ena .lin •.. e e efits Over ' ime Example: Time Progression of Agency Services Associate Member Planning and Resource Development /4 Full Member MISO Market Participant CIP Dev. CIP Operations Renewables Dev. Renewables Ops as eve op n Gas Operations Baseload Asset Development Baseload Operations Resource Planning Today 2010 2012 2014 2016 2018 2020 2022 2024 40 Time (.." , ,., 7----J ,, ,,,, .„ , 1 Wfrmnl. crsliis _ „--,..L.» Enabling h - -. (cont'd) ': ,, ,,r The Solution (continued ) F € A customized membership category for ERMU 's unique needs and timing Current Proposed ERMU Status ERMU Status !i> Associate Associate Associate Associate Member Full Member Member Member (Planning & Development) Member Resource Planning Services X X X CIP Planning Services X X X CIP Implementation Services Optional Optional Optional Resource Development Participant X Resource Project Participant Optional Optional Optional MISO TO Participant Optional Optional X MISO Scheduling Services X X MISO Market Participant Services Optional Optional Supports Full Agency Budget including Overheads ; X Contribution to Agency Equity X Attends/Participates in All Board Meetings (Non-voting) X Board Member(Voting) X Term (w/ automatic renewal) 1 year 2 years 2 years 2 years 5 years Monthly Fees $ $ 2,500 Negotiable Negotiable $ 5,000 % of Member Total Wholesale Costs (Indicative) 2% to 3% 4 1 ( 1 eaRA, C ; ®p® sal: Overview Building the ERMU Resource Portfolio o Creating a Special CMMPA Membership Category for ERMU Costs and Benefits 42 PiPA CM PA Membership : Costs f�= ofkAl The current annual cost of full CMMPA membership * represents only about 3 % of the members' wholesale power costs from CMMPA . It is likely that the annual cost of being a full CMMPA member is less than the profit margin Connexus is charging ERMU on the current contract . * * * Exclusive of CIP implementation. **Even if adding ERMU as a member would result in zero additional economies of scale for CMMPA's operations. Assumes Connexus' current profit margin on sales 43 to ERMU is 4% to 5% of wholesale energy cost from GRE. I i � C i ' MA % 1 embers rip : osts (cont'd a 5n F1 qq3 :-, , , .,,,, Full CMMPA members have equity investment in y#(.a, the agency . g y Addition of ERMU as a full CMMPA member would entail ERMU " buy- in " payment of a pro- rata share of agency equity IIIFor ERMU, estimated to be : A one-time payment of $300k. o A one-time establishment of ERMU pro rata share of agency working capital . • For other, traditional full requirements agencies, the corresponding equity buy-in amount would likely be in the multiple millions of dollars, with a term of 30 years or more. Because you would be buying into the agency's resource portfolio. CMMPA proposes an Associate Member (Planning and Development) status for ERMU until your GRE contract expires in 2018. 44 es"** %Iwo* 7m- _ ry The Risk of No Action .44yj The Opportunity CMMPA Proposal Conclusions 45 • Elk River has a strategic decision to make regarding its future energy resources . • Own your own future, or: • Have it decided by others. There are significant risks in not taking action now . ■ Increasing dependence on natural gas for a large portion of ERMU customers' future electricity supply. ■ Having no alternatives other than a single supplier/competitor. A diverse, balanced resource portfolio is the best option . ■ Like a diverse investment portfolio of stocks and bonds. ■ Led by Green Package : renewables and energy conservation . ■ Big Stone II is but one of the important components. CMMPA can help you achieve the best, diverse and balanced portfolio, over time . 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' t. rr 3 Elk River Municipal Utilities Big Stone II : Updated Cost Estimate July 8, 2009 Central Minnesota Municipal Power Agency BSPII Installed Capital Cost Summary (630 IVIW Early 2016 In-Service) Capital Cost Summary Generator Transmission Total Total project $ 1 .763 Billion $326 Million $2.089 Billion CMMPA (@ 57. 6 MW) $ 161 Million $ 30 Million $ 191 Million ERMU (@ 30.0 MW) $ 84 Million $ 16 Million $ 100 Million $2798/kW $517/kW $3315/kW Assumptions : These costs include the upfront development costs and costs to-date. These costs are not yet grossed up for Interest During Construction (IDC) and Debt Service Reserve Fund. Pro- rata share of the above cost for each 1 MW participation would be : Generator Transmission Total $2.80 Million $517 Thousand $3. 315 Million Based on updated estimate by Black & Veatch, 6/30/09. This estimate will be used for the project "go/no-go" decision in September 2009. BSPII Project Phase 3 Commercial Operations Phase After commercial operation date ( COD) currently estimated to be 1 - 1 - 2016 We will start making principal and interest payments on bonds Elk River' s approximate cost during operation would be as follows : Fixed Monthly Charge = $23,267/MW-month (to cover debt service and fixed 0 &M) Variable Energy Charge = $20 . 10/MWh TOTAL COST = $55 . 53/MWh Includes bus bar cost plus transmission 3 BSPII First Year Cost Summary at 630 ARV, 2016 In-Service Current Cost Component Cost/MWh Generation Capital $29 . 60 Fuel $ 14 . 38 Operation & Maintenance $ 5 . 72 Subtotal $49.70 Transmission $ 5 . 83 Total $55. 53* Assumes soft development costs are not reimbursed. If development costs are reimbursed, total cost would increase to $55.95. *Previous estimate (4/15/09) was $53.60/MWh for 2014/2015 in-service. Difference is about $1/MWh for escalation due to later in-service date, and $1/MWh for change in 4 assumed interest rate from 5% to 5/5%. i � � 1111r0.4 *-4 H. a'- rk na Questions? CAM 459 South Grove Street Blue Earth, MN 56013 Phone : ( 507) 526-2193 Website : www. cmmpa .org 5 ( +