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Home My WebLink AboutPACKET Utilities Committee 2006-09-21AGENDA TOWN OF ESTES PARK UTILITIES COMMITTEE 8 a.m. Thursday, September 21, 2006 Preparation date: 9/14/06 *Revision date: 9/19/06 ACTION ITEMS PUBLIC COMMENT Light & Power Department 1. "Card Shop" Christmas Decoration Restoration Bid Request to accept bid 2. Habitat Request Request for a waiver of any costs for making electrical connections for this future sub- division. (3 lots) *3. Finance Folding and Inserting Machine Request to upgrade existing machine Water Department 1. Looping Project Engineering Request to accept low bid 2. MOU Water Lease BOR Request for signature REPORTS Light and Power 1. Light & Power Financial Reports 2. Platte River Power Authority - Integrated Resource Plan - John Bleem 3. Update - Net Metering Rate Water 1. Water Financial Reports 2. Regulation Update Administration 1. Utility Scope of Service Documents Note: The Utilities Committee reserves the right to consider other appropriate items not available at the time the agenda was prepared. r hp LaserJet 3015 0 ]Â® HP LASERJET FAX invent Sep-19-2006 2:32PM Fax Call Report Job Date Time Type Identification Duration Pages Result 350 9/19/2006 2:26:17PM Send 5869561 0:39 1 OK 351 9/19/2006 2:27:02PM Send 5869532 0:00 0 Busy 352 9/19/2006 2:28:36PM Send 5869532 0:50 1 OK 353 9/19/2006 2:29:31PM Send 5861691 0:57 1 OK .354 9/19/2006 2:30:33PM Send 6353677 0:50 1 OK 355 9/19/2006 2:31:28PM Send 5771590 0:59 1 OK j . 1 TOWN of ESTES PARK Inter-Office Memorandum September 13, 2006 TO: The Utilities Committee FROM: Bob Goehring & Mike Mangelser(~~ SUBJECT: Christmas Decoration Display Replication-"The Card Shop" Background: The Light and Power Fund, page 285, contains $20,000.00 for the authentic replication of the Buel Porter Christmas Display known as "The Card Shop". Project specifications were compiled and a formal RFP was sent to (8) licensed sign vendors. One proposal was received from local sign vendor Signs of Life, Inc owned and operated by Mark Igel in the amount of 15,917.00. This particular vendor was successful last year in replicating "Santa and his Reindeer". Cost/Budget: Cost: 1) Signs of Life $15,917.00 . Budget: $20,000.00 Account # 502-6501-560-2615 Action: Staff recommends that we contract with "Signs of Life" for the amount specified. MM 1-1 . i + Vendors who received 2006 Request for Proposals - the Card Shop (all held current Town business licenses) Gardner Signs, Inc. Jim Neenan 8101 SW Frontage Road Ft. Collins, CO 80525 JC Signs Jarred Griess 7225 W. 9th Avenue Lakewood, CO 80214 Shaw Sign and Awning Jonathan Harshaw 901 SW Frontage Road Ft. Collins, CO 80524 Signs, of Life Mark Igel 168 Stanley Circle Estes Park, CO 80517 ABC Signworks, Inc. L. Wilton Lyles 301 C Smokey Street Ft. Collins, CO 80525 Biltrite Sign Service, Inc. Lynn Clark 4315 Industrial Parkway Evans, CO 80620 Longmont Signs Paul Kelley 4315 Industrial Parkway Evans, CO 80620 Unink Printworks Aaron Petzie 700 Ken Pratt Blvd. Unit 109 Longmont, CO 80501 adbi Â· '----42*-#: 44Â· V , ..3. 7 Â¥ ;- 1 41 4~ ' ~2Â·:,rA. ., ~31/*:.i~:Ei.35 20.BOX.1-20GU**V 170MACGREGORAVENUE ESTES PARK. COLORADO 80517 CHRISTMAS DECORATION DISPLAY REPLICATION "The Card Shop" REQUEST FOR PROPOSALS MAYOR John Baudek BOARD OF TRUSTEES Chuck Levine Dorla Eisenlauer Eric Blackhurst Bill Pinkham Wayne Newsome Richard Homeier TOWN ADMINISTRATOR Randy Repola PUBLIC WORKS DIRECTOR Robert Goehring PHONE: 970-586-5331 FAX: 970-586-6909 . REQUEST FOR PROPOSALS CHRISTMAS DECORATION DISPLAY REPLICATION "The Card Shop" 1) BACKGROUND: In 2005, the Town of Estes Park had an authentic replication made of one of its seven plywood Christmas displays. Santa and his reindeer were created using digital computer imaging with the end result being very similar to the original. 2) OBJECTIVE: In 2006, the Town of Estes Park would like to continue with the authentic replication of another one of the plywood displays: "The Card Shop," aka "Santa and his Helpers." 3) PROJECT DEADLINE: The creation of the display needs to be completed by November 15, 2006. Final installation ofthe display needs to be completed by November 22,2006. 4) PROPOSAL SUBMISSION DATE: Proposal must be submitted by Tuesday, September 5,2006 by 5:00 p.m. to: Michael R Mangelsen, Public Works Manager Public Works Department 170 MacGregor P. O. Box 1200 Estes Park, CO 80517 Phone: (970) 577-3583 /FAX: (970) 586-6909 If interested in the project, please contact Mike. 5) CONTRACTORS RESPONSIBILITIES: The contractor will provide all labor, equipment, and materials necessary to emulate the process that was used to accomplish last year's replication. Contractor will install at the desired location the sleeves required to easily assemble and disassemble the display. 6) SLEEVES: Sleeves must be concealed and protected when not in use, but must be easily relocated for re-use during the holidays. Page 1 7) INITIAL ASSEMBLY: Initial assembly will be the contractor's responsibility and should be included in the proposal. No additional compensation will be made at the end of the project for assembly. 8) TOWN BUSINESS LICENSE All contractors and sub-contractors must have on record with the Town of Estes Park a current, valid Town business license. 9) UNFORSEEN DIFFICULTIES: Any problem or difficulty encountered will be addressed or governed by the Town's General Conditions for similar projects. A copy of these conditions is on file at the Municipal Building. 10) INSURANCE AND WORKMENS COMPENSATION: Prior to the notice to proceed, the contractor will provide the Town with proof of Workmen's Compensation and Insurance to the following limits: A. Statutory Workmen's Compensation B. Contractor's Public Liability and Property Damage: Bodily Iniurv: Each Person $250,000 Each Accident $600,000 Property Damage: Each Accident $250,000 All Accidents $600,000 Automobile Public Liability and Property Damage: Bodily Iniury: Each Person $250,000 Each Accident $600,000 Property Damage: Each Accident $250,000 11) WARRANTY: All work, as outlined in the Project Specifications, shall be guaranteed free from defects, flaws and other irregularities as outlined by the Owner for a period of two full calendar years. Warranty is to commence the date that all punch items are completed and the Owner receives written notice from the Contractor with the request for final payment. 12) ACCEPTANCE OR REJECTION OF PROPOSALS: The Town reserves the right to accept or reject any or all proposals. Page 2 TOWN ofESTES PARK Inter-Office Memorandum September 15, 2006 TO: Utilities Committee FROM: Bob Goehring SUBJECT: Light and Power Fee Waiver Request for Habitat for Humanity of Estes Valley Background; I have received a request from Habitat for Humanity of Estes Valley for a waiver of any costs from Light and Power for a future development (3 lots) in Ferguson Sub- Division (see attached). In the past, the Water Department has waved water connection fees for Habitat for Humanity. To my knowledge, Light and Power has not. As the development is in the future, Infrastructure costs are not known. Cost Underground connect fees are: $190.00 X3= $570.00 Overhead connect fees are: $290.00 X3= $870.00 Action Staff recommends not to exceed a dollar amount determined by the Utilities Committee. This dollar amount will be given to Habitat for Humanity of Estes Valley so they may continue their planning. 1 7 Habitat for Humanity of Estes Valley Building houses in partnership with God's people in need RO. Box 2745 â€¢ Estes Park, Colorado 80517 â€¢ (970) 586-8301 2 August, 2006 Bob Goehring Public Works Department Town of Estes Park P.O. Box 1200 Estes Park, CO 80517 Dear Bob, Sometime this fall Habitat for Humanity of Estes Valley, Inc. will submit a subdivision plan together with a request for rezoning and annexation for Lot 1, Block 1, Ferguson Subdivision in the Estes Valley. The lot will be subdivided into three minimum sized lots on which Habitat plans to construct affordable homes for three Estes Valley low income families. Van Hom Engineering has developed plans for the subdivision infrastructure and Habitat would like to begin the infrastructure upon approval of the application. The costs associated with the infrastructure will be carried by the mortgages on the 1hree homes. Costs of the most recent home completed by Habitat have increased signilicantly over our previous homes and Habitat is seeking ways b reduce the total costs. Habitat is requesting a waiver from the Town of Estes Park of any costs incurred from making the electrical connedions for this future subdivision and the three homes. Habitat is deeply appreciative of the support that the Town of Estes Park has provided these past few years - the water taps for eleven homes, financial grants and the assistance and support by the Community Development Department in our applications for the Habitat Subdivision, the Mangleson Subdivision, our building permits and subsequent Certificate of Occupancies. Habitat will appreciate your consideration of our request for a waiver of the costs of the electrical connections required for this future subdivision and its three homes. Sincerely, 0ULâ€žg,ze, ~14447 0 Wendell Amos, Director Habitat for Humanity of Estes Valley, Inc. TAr (~~ Printed on Recycled Paper Finance, Light & Power, Water Departments Memo To: Utility Committee Town Administrator Repola From: Steve McFarland, Finance Officer Date: September 19, 2006 Subject: Replacement of folding/insert machine Background In the March 2006 utility committee meeting, it was proposed and approved that monies be made available, within budgeted parameters, to acquire a Pitney Bowes D1-400 Fast Pac Inserting System to replace the old Neopost SI 72 machine. The Neopost machine was suffering from normal wear and tear and was due to be replaced. The Pitney Bowes machine, at a price of $7,193, was approved and subsequently acquired. . Over the past several months, it has become apparent that the new machine lacks the capacity to handle our needs in a timely manner. Our operation requires mailing 5,000+ billings, two times per month. While the machine is technically capable of handling the workload, its physical limitations (ex: it can only hold 50 bills at a time) forces Jim Allen to continually monitor the machine for re- stocking. Pitney Bowes has provided excellent support and has made numerous timely visits to our site in attempts to address the limitations of the machine. They have added various parts to the machine in an effort to make it more productive, but it simply lacks the capacity to keep up with our needs. As a result, Jim frequently spends 8 hours or more per billing cycle when 4 hours should be sufficient. Pitney Bowes has offered us a higher capacity machine (DI 425), normally listed at $15,000, for a reduced cost of$11,782. I reminded Pitney Bowes that initially one ofour options was to remain with Neopost, purchasing an equivalent machine from them for $11,470. Pitney Bowes responded with a revised price of $11,459. Jim and I believe that Pitney Bowes has made every effort to ensure customer satisfaction in our situation. Budget Since we have already committed $7,193 for the Dl-400 machine, the new machine represents only an additional $4,266 expenditure, which would be charged to 502-7001-580.33-32. This account has $15,000 allotted for the folding/inserting machine, ofwhich only $7,193 has been spent. The $4,266 would otherwise be spent in less than one year in Jim's time monitoring the machine, so we believe that this is an efficient use of funds. Action: Staffrequests permission to upgrade Pitney Bowes DI 400 folding/inserting machine to Pitney Bowes DI 425 folding/inserting machine at additional net cost listed above ($4,266), totaling $11,459 for the macline. â€¢ Page 2 .-% .gi . -- .111 0 0 . 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Patient bills and you control of 0MR marks, go do some-d ~ Recognition ci statements, third party billing. each mailing. Financial Services. Confirmation The marks and Â·,W c Get More Mai[Out, Fa you would ever imagined possible, with .se!-las Jaiqasul SZ17 ICI/08Â£ la 841 Real Estate. "Latest listing" mailings, free valuation offers, brochures. Professional Services. Invoices, state- ments. announcements, newsletters. sfiulliel.u t.nbuel-aiqel.leA Ja410 pue dn paads 01 sadoleAula Lida.J wasui ueD noA leuoiloulojd ppe 'osuodsau Jaluotsno thank-you letters, Water Department ,Â«R\~ ESTES PARK Inter-Office Memorandum 2AYER To: Bob Goehring From: Jeff Boles Date: 9/18/2006 Re: 2006 Water Line Project Background: The water line replacement project budgeted for 2006 is to replace an old existing 4" line that goes at an angle through properties next to building foundations and underneath one garage. This area is across Aspen Avenue, Birch Avenue and Landers Street to the corner of Landers Street and Columbine Avenue. Request for Proposals were sent out for design and construction management of this project. Proposals: HDR Engineering No Proposal Submitted Red Oak Consulting No Proposal Submitted Stantec Engineering Survey & Easement Review $6406.00 Bid Drawings/Specifications $11,587.00 Bid Phase Services $2,240.00 Construction Administration $3,388.00 Record Drawings $1,635 Total $25,256.00 Van Horn Engineering & Surveying General Office $442.00 Staff / Engineering $1,332.00 Two-Person Field $2,220.00 Site Visit $432.00 Computer Drafting $1,104.00 License Professional $273.00 Material Cost $450.00 Total $6,253.00 Landmark Engineering Site Survey & Topographic Mapping $4,500.00 Civil Engineering/Geotechnical $6,820.00 Bidding/Construction Management $10,640.00 Reimbursable Expenses $1,500.00 Total $23,460.00 Recommended Action: Proceed with Van Horn Engineering & Surveying for Design and Construction Management of the 2006 Waterline Project in the amount of $6,253.00. 1 1 2 1 1 COLUMBINE r ||~ j j / COLUMBINE i ./ 1 \ j Howls ~ i 1 r , FL 2 1 -1 0 1 0 1 1 1 - I 1 - 1 ASPEN .-\ i to 0 0 -Â·1 I 1 - 1 I //- ' i ---*-----te~~~x '- - \ / 4(9Â«4 rJ -_ -LANDERS_ Green is new proposed 8" ~ TOWN ofESTES PARK Inter-Office Memorandum September 15, 2006 TO: Utilities Committee FROM: Bob Goehring SUBJECT: MOU between Bureau of Reclamation Estes Valley Recreation and Parks Department (EVRPD) and Town of Estes Park Background; Mary's Lake Campground is on property owned by the United Sates. The campground is managed on behalf of Bureau of Reclamation by EVRPD. Currently the property is in a location that cannot be served by the Town's Water System. The well that supplies water to the Campground must provide an augmentation plan to the Water Court. This plan is a condition of securing a court decree for the well to be used for the campground. Cost/Budget The Bureau of Reclamation is requesting a 25 year lease thru this MOU, for 1 acre ft Windy Gap water per year for their augmentation plan. The EVRPD would be required to make the lease payment. (Currently $350.00 per year.) This fee may be adjusted annually to reflect actual costs. The Town of Estes Park has adequate Windy Gap Water for this request. Action Staff recommends approval of this MOU between the Town of Estes Park and the Bureau of Reclamation and the Estes Valley Recreation and Parks Department (EVRPD) to lease one acre ft ofWindy Gap water for 25 years. 'tx a United States Department of the Interior /1.b.AA) DEPARTHENT OF THE INTER/OP... f 4% Uoll - 1 17 k - - I **0-9 # BUREAU OF RECLAMATION -~~%L2222&8~= Eastern Colorado Area Office 11056 West County RD 18E IN REPLY Loveland, Colorado 80537-9711 REFER TO: EC-1320 WTR-4.00 AUG 2 9 2006 Mr. Stanley C. Gengler Estes Valley Recreation and Park District P.O. Box 1379 Estes Park, CO 80517 Subject: Memorandum of Understanding (MOU) No. 06AG602154 for Providing Augmentation Water for Mary's Lake Campground Well - Colorado-Big Thompson (C-BT) Project, Colorado Dear Mr. Gengler: Enclosed is a copy of the MOU for providing augmentation water for Mary's Lake Campground Well. Also enclosed are three original signature pages for the Estes Valley Recreation and Park District to execute. Ifthe terms and conditions ofthe proposed MOU are acceptable to the District, please have the three original signature pages signed on behalf of the District. Please return the three signed original signature pages. We will return one fully executed original MOU to the District upon signature on behalf of the Bureau of Reclamation and the Town of Estes Park. If you have any questions, please contact Joel Fenolio at 970-962-4396 or jfenolio@gp.usbr.gov. Sincerely, Red L Ore Fred R. Ore Area Manager Enclosure -1 cc: Mr. Gregory White Mr. Bob Goehring Attorney at Law Director of Public Works & Utilities North Park Place Town of Estes Park 1423 West 29th Street 170 Macgregor Ave Loveland, CO 80538 Estes Park, CO 80517 (w/0 enclosure) (w/0 enclosure) D. 1 . - United States Department of the Interior ge~~ &1 BUREAU OF RECLAMATION -\24~E*'~- Eastern Colorado Area Office 11056 West County RD 18E IN REPLY Loveland, Colorado 80537-9711 REFER TO: EC-1320 AUG 2 9 2006 WTR-4.00 Mr. Bob Goehring Director Of Public Works & Utilities Town of Estes Park 170 Macgregor Ave Estes Park, CO 80517 Subject: Memorandum of Understanding (MOU) No. 06AG602154 for Providing Augmentation Water for Mary's Lake Campground Well - Colorado-Big Thompson (C-BT) Project, Colorado Dear Mr. Goehring: Enclosed is a copy ofthe MOU for providing augmentation water for Mary's Lake Campground Well. Also enclosed are three original signature pages for the Town of Estes to execute. If the terms and conditions of the proposed MOU are acceptable to the Town, please have the three original signature pages signed on behalf of the Town. Please return the three signed original signature pages. We will return one fully executed original MOU to the Town upon signature on behalf ofthe Bureau of Reclamation and the Estes Valley Recreation and Park District. Ifyou have any questions, please contact Joel Fenolio at 970-962-4396 or jfenolio@gp.usbr.gov. Sincerely, 960_2.94 Fred R. Ore Area Manager Enclosure -1 cc: Mr. Gregory White Mr. Stanley C. Gengler Attorney at Law Estes Valley Recreation and Park District North Park Place P.O. Box 1379 1423 West 29th Street Estes Park, CO 80517 Loveland, CO 80538 (w/0 enclosure) (w/copy of MOU) 21 U.S. DEPARTMENT OF THE INTERIOR BUREAU OF RECLAMATION GREAT PLAINS REGION EASTERN COLORADO AREA OFFICE COLORADO-BIG THOMPSON PROJECT MEMORANDUM OF UNDERSTANDING MOU No. 06AG602154 FOR Providing Augmentation Water for Mary's Lake Campground Well This Memorandum of Understanding (MOU) among the United States Department of the Interior, Bureau of Reclamation, Eastern Colorado Area Office (Reclamation), Estes Valley Recreation and Parks District (District) and the Town of Estes Park, a municipal corporation (Town), (collectively referred to as "the parties") identifies the roles and responsibilities for providing augmentation water for Mary's Lake Campground well. 1. EXPLANATORY RECITALS WHEREAS, Mary's Lake is a feature of the Colorado-Big Thompson Project, a federal facility of the United States; and WHEREAS, Mary's Lake Campground is on property owned by the United States , located at 2120 Mary's Lake Road (Property), and is a recreational feature of the Colorado-Big Thompson Project. The campground is managed on behalf of Reclamation by the District pursuant to a Memorandum of Understanding between Reclamation and the District (formerly known as The Rocky Mountain Metropolitan Recreation District) dated June 18, 1984, Contract No. 4-07-70-L2114; and WHEREAS, due to its location, the Property currently cannot be economically served by the Town's water system; and WHEREAS, the water to support Mary's Lake Campground is currently provided by a well located on the Property (Well); and WHEREAS, Reclamation is the applicant for adjudication of water rights for the Well in the District Court, Water Division No. 1, under Case Number 95CW187; and must provide an augmentation plan as a condition of securing a court decree for the Well water rights; and WHEREAS, The Town is the owner of three (3) units of Windy Gap Project water ("Windy Gap Water'") as such units are defined in the Allotment Contract between the Municipal Subdistrict of the Northern Colorado Water Conservancy District ("Municipal Subdistrict") and the Town. The Town utilizes its Windy Gap Water as part of an augmentation and exchange plan decreed in Case No. 97CW126, Water Division No.1. The Town also owns units of Colorado-Big Thompson Project water ("C-BT Water"), which it can use pursuant to the policies and regulations of the Northern Colorado Water Conservancy District ("Northern District") and the Municipal Subdistrict; and WHEREAS, the Town has agreed to provide a source of augmentation water for the well upon the terms and conditions described in this MOU. NOW, THEREFORE, in consideration of the mutual covenants hereinafter set forth, the parties agree as follows: 11. TERM OF THIS AGREEMENT This MOU shall be effective on the date of execution by the parties and shall remain in effect for a period of 25 years unless terminated sooner in accordance with the provisions of Article IV. The MOU may be renewed upon mutually agreeable terms and in accordance with applicable Federal and State laws and the United States' policies in effect or as established by the Secretary of the Interior at that time. 111. AGREEMENT TO LEASE WATER A. Agreement to Lease Water. The Town agrees to enter into a renewable twenty- five (25) year lease agreement (Lease) with the District to provide a maximum of one (1) acre-foot each calendar year of the Town's Windy Gap Water, or, in the Town's discretion, from such other water rights owned by or otherwise available to the Town which may be lawfully used to supply water to the District, and in accordance with any applicable regulations of the Municipal Subdistrict and Northern District. The water shall be delivered by the Town at locations suitable for replacement of depletions by the District consistent with the manner and points of delivery set forth in the Town's augmentation and exchange plan in Case No. 97CW126. B. Initial Lease Period. The parties recognize that the MOU dated July 18, 1984, between Reclamation and the District was for a 25-year period and shall expire on July 18, 2009. Reclamation and the District intend to enter into a new long term MOU for management of the Property to take effect on or about July 18, 2009. The Town agrees that the initial Lease with the District shall be for a period of twenty-five (25) years and may thereafter be renewed for a twenty-five (25) year period, and continue to be renewable for twenty-five (25) year periods thereafter. C. Assignment of Lease. The lease agreement shall provide that in the event that the District ceases to manage the Property the lease shall be assigned to Reclamation or to the successor manager of the Property designated by Reclamation. D. Lease Payments. The Lease agreement shall provide for nonrefundable payment by the District of Three Hundred Fifty and no/100 dollars ($350.00) per year, in advance, for the use of up to the one (1) acre-foot of water. The payment obligation shall not be contingent upon the actual usage of the water during that year; and upon written notice and supporting documentation given by the Town to the District, the Lease price of $350.00 may be adjusted yearly by the Town to reflect the actual cost for the delivery of Windy Gap water to the Town. The payment for any partial year shall be prorated. There will be no federal funds expended for this Lease payment. E. Use of Leased Water. The leased water supplied by the Town must be used pursuant to a court approved plan for augmentation or exchange, or pursuant to a State Engineer approved temporary substitute supply plan, to replace out-of-priority water depletions occurring in connection with pumping of the Well for domestic and irrigation uses associated with the Property. F. Deliveries of Water. The Town will make deliveries of the water described in Article 111.A. as directed by the District upon reasonable advanced notice. The specific timing and amounts of these deliveries will be determined by the State Engineer pursuant to the terms of a plan for augmentation or exchange approved by the water court or temporary substitute supply plan approved by the State Engineer. Reclamation will endeavor to obtain a water court decree, which does not require releases at such times or in such quantities as are burdensome to the Town. G. Augmentation Plan. Reclamation has the right to seek and obtain water court approval of a plan for augmentation or exchange, or a State Engineer approved temporary substitute supply plan, using the water described in Article Ill.A. ads a source of augmentation or replacement water. All such proceedings shall be conducted by water rights counsel and engineering consultants selected by Reclamation, at Reclamation's sole cost and expense. No application, stipulation, or consent decree shall be filed, signed, or adopted by Reclamation without prior review by and consent of the Town; provided, however, that in no event shall the Town unreasonably withhold such consent. The Town shall not file a statement of opposition to Reclamation's water court application, and the Town shall fully cooperate with Reclamation in connection with the application by providing such information and assistance as is reasonably requested by Reclamation, its water rights counsel, or its engineering consultants. Reclamation will structure any application for approval of plan for augmentation or exchange to require the least number and the largest quantities of deliveries of water as is acceptable to the water court and the State Engineer. No change of the Town's water rights shall be applied for or reviewed in such proceedings. Reclamation will be solely responsible for operating and maintaining the existing totalizing flow meter or such other device as may be required by the water court or State Engineer to operate the augmentation plan. Reclamation will also be solely responsible for preparing, maintaining, and compiling accounting forms or other reports required by the State Engineer in connection with the augmentation plan., Reclamation will promptly provide the Town with copies of any reports (including accounting forms) to or correspondence with the State Engineer relating to the augmentation plan, including the monthly records of the water pumped that are maintained by the District's Concessioner pursuant to the Amendment dated April 16, 1996 of the Concession Contract dated December 18, 1984, or as may be required in future agreements between the District and its Concessioner. H. Approvals. Reclamation and the District will be responsible for obtaining all necessary authorizations, approvals, water court decrees, and permits from any and all private entities, and local state, and federal agencies, as may be required to effectuate the Lease. Reclamation and the District will provide copies of any such authorizations, approvals, and permits to the Town upon its request. 1. Untreated Water. The water delivered to the District under the Lease is untreated or non-potable water of whatever quality, and is now or in the future, will be available from the sources specified herein. Delivery of non-potable water under the Lease will be on an "as is" basis only, and the Town does not warrant the quality of the water. The Town does not warrant the suitability of the water for any particular purpose, and Reclamation and the District hereby acknowledge that they have made their own evaluation of the Town's water and its appropriateness for use by exchange at the Property. Reclamation and the District will not make any claim against the Town arising from the quality of water delivered, and the Town shall have no water treatment responsibility for non-potable water made available under the Lease other than such responsibility it would have otherwise apart from the Lease. J. Costs and Charges. The Town will be responsible for payment of all costs and expenses related to providing the augmentation water under the Lease. There will be no federal funds expended for any such costs or expenses. K. Curtailment. The Town represents that, under reasonable and foreseeable circumstances, it should have adequate water to make deliveries as described under the Lease. Reclamation and the District recognize that the water provided hereunder is presently surplus to the Town's needs, but that the Town's water supply is dependent upon natural water resources that are variable in quantity of supply from year to year, and which can be affected by causes beyond the Town's control. The Town will not be liable for failure to adequately anticipate availability of the Town's water supply or for an actual failure of Town's water supply. In times of such shortage or failure, the Town may refuse to supply water or curtail the amount of water provided pursuant to the Lease in order to meet the Town's reasonable municipal needs for water, provided that the Town will in such event refund to the District a pro rata share of the District's annual rental payment for that year. The Town will make a reasonable attempt to notify the District in advance of any interruptions of delivery. IV. TERMINATION This MOU may be terminated by Reclamation with ninety (90) days prior written notice to the other parties, or otherwise upon mutual agreement of all of the parties. V. ASSIGNMENT No assignment or transfer of this MOU or any right or interest therein by any party shall be valid until approved in writing by the other parties. VI. NOTICES Any notice, demand, payment, refund or request authorized or required by this MOU shall be deemed to have been given when mailed postage prepaid or delivered to the Area Manager, Eastern Colorado Area Office, Bureau of Reclamation, 11056 West County Road 18E, Loveland, Colorado 80537, for Reclamation; and to the Town Administrator, The Town of Estes Park P.O. Box 1200, Estes Park, CO 80517, with a copy to Gregory A. White, Esq. 1423 West 2gth Street, Loveland, CO 80538, for the Town; and to the Executive Director, Estes Valley Recreation and Parks District, 690 Big Thompson Avenue, P. O. Box 1379, Estes Park, CO 80517 for the District. The designation of the addressee or the address may be changed by notice given in the same manner as provided in this Article for other notices. VII. REQUIRED CLAUSES During the performance of this MOU, the parties agree to abide by the terms of the Executive Order 11246 on nondiscrimination and will not discriminate against any person because of race, color, religion, sex or national origin. No member or delegate to Congress, or resident Commissioner, shall be admitted to any share or part of this MOU or to any benefit arising from it. However, this clause does not apply to this MOU to the extent that this MOU is made with a corporation for the corporation's general benefit. . Finance, Light & Powers Water Departments Memo To: Utility Committee Town Administrator Repola From: Steve MeFarland, Finance Officer Date: September 21,2006 Subject: Utility committee report Background Pursuant to the request made from the Committee in the June 15, 2006 meeting, I am attaching this memo to summarize the enclosed utility reports. Body Light & Power â€¢ August 2005 and August 2006 display several variances from one another, the most prominent of which is the booking oftwo purchases from PRPA totaling $735,440. Booking two PRPA purchases in August has now brought YTD 2005 and 2006 into sync. In reviewing the revenue and expense line items in comparison to percent completion of the year (67%), it can be seen that revenues are running slightly ahead of expectations (69%), and that overall expenditures are running under budget (58%). Further, total expenses per kWh in 2006 ($0.072) compare favorably to 2005 ($0.074). In the "charts and graphs" section, revenues seem to be slowly climbing towards budget, and are now projected to fall short by $38,000. The projected amounts change as data from a year ago is dropped and current months are added. The forecast for the year retraced very slightly from last month. Water The water department is running significantly ahead of 2005, based largely on revenues (see bar chart). The trend has been basically flat for several months, but the good news is that it has settled in at about a $293,000 projected surplus in forecasted revenues. Revenues are running at 77% of budget, whereas O&M expenses are at 59%. These are both on the "comfortable" side of the 67% of the expended calendar. Additionally, total expenditures per gallon are $0.005 in 2006 vs $0.006 in 2005. Conclusion We do not see any material concerns reflected in the August 2006 financials, and are pleased with the condition ofthe Enterprise Funds at this point in time. Additional detail Although it does not show up in these reports, significant reallocations have been made to the investment positions in August. Historically, GASB has required that the Ild Position of cash plus investments in a fund be positive. As our cash and investments are pooled, a fund could conceivably carry a negative balance in cash and a positive balance in investments, so long as the investment amount is greater. Over the past few years, this practice has attracted "heartburn" in the accounting world, to the point where we have decided to begin carrying positive cash balances in all funds. This has resulted in approximately $3,600,000 in cash being shifted between 11 funds. The biggest "winners" in this process are the Enterprise funds (L&P, Water), with $2,575,000 being shifted into Enterprise investment accounts. The net affect of this is that we can expect a dramatic increase in interest income in the Enterprise funds for the foreseeable future. Action steps requested - None. â€¢ Page 2 MONTHLY PEAK DEMAND 25500 23500 21500 -0-2004 -*-2005 19500 -0-2006 17500 mil- 15500 13500 11500 - , 1 , 1 1 1 1 Id , Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec MONTHLY ENERGY PURCHASES 12,000 -FE Fi 7 - 4% 43 18/ A f J 10,000 -03: 4 -7 I. ** A 0 33- 71_ 33- P $ Wh #e #4 M: Ah-0 A 4 0,15 4.41 /. 4% 8,000 ---$4 -2 -,4 -3% -4 -94 - 4 0% I --4-52- -0 - M 2004 0% 5% pt ft a 2005 44 4 A 31 3% 02006 5% A ** 2 53 321 6,000 -2 -j -A -183 -41 -A -94 -0* -44-*s -A- 1 28 0- 0% 04 04 2% 553 34 55{ 4-4. 58% M 58 /52% 41 9 4 0 09 54 88: 2 386 9 R * 34 21 *4 3% A 32% 14 23 *% _54 2 44 4,000 -2* -#: -ft -Ft -6t -04 -A -A 8-2 -SIS- 0 3 %* 04% #m *3:R gy *9 1* 2,000 @# i t~ / N i /' i 40 i 7_* i /"\ , 0,v ,03 , 44 , ->53 , 44 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec R L&P 6 Monthly MWH SYSTEM KW '*AN<4Â«<4<411&414%4 12Â»***Â« 'pÂ»$ 9/**g/*tgE&3*K ~<1Â«1Â«Â«1Â«cÂ«Â«<9Â«1Â«cÂ«e<~H=# YTD ENERGY PURCHASES 120,000 100,000 80,000 - 0.60% YTD 2006 VS 2005 â€žer #3 0. *- - m 2004 %%0-4 #M %23 S- 4 02005 60,000 n _43 -541_49 ei.0 3< -A E * * 6 47 02006 $ # 7% i i r Â¢ 40,000 -03 04 ~4 -PE-Z---4.-40- 20,000 tri--'tz--11 : 1. - 1- 3% 0% E *30% 3 44 4 F PE &2 0. p i / 4 1 55.: 4 01 *i- 11 6- 4 * t Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YTD POWER COST vs. BUDGET ($1,000) 0 BUDGET Â¤ACTUAL 5,000 4,500 4,000 3,500 y 3,000 2,500 2,000 1,500 1,000 MT- 500 m I-~ 11-111-1 1% 3 1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec R L&P 7 6644<46,6*~t~k' luku~~0<'0((ddi Â£8288*89288838883%23*.322%888 1,2664465,2 YTD MWH Purchased ELECTRIC SALES BY MONTH ($1,000) 1,200 1,100 1,000 - 900 --= i 0 2004 + 1 4 - -4 m 2005 700 -< E - 1 0 -5 r 1- 1 -r T 02006 -: 1 4 Â§% , E m: 1 300 19121, R 1 - 1 4 1 1.-*2- 1 0 1.- 1 -Â¥ 1 1 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YEAR TO DATE ELECTRIC SALES ($1,000) 10,000 Â·Â· ~10,138,088~ 9,000 5.75% 2006 YTD VS - 8,000 2005 - F 7,000 -- CZZ] 2004 - - - - - f 6,000 -- CZEZ12005 - 5,000-- 02006 -- 4,000 --- -Budget -- _ _ _ - __ ___ 3,000 -- -& - -R - P 1? 2,000 1,000 --All- - -- -- -- -- -- -ft - 0 - Ull, __ - 1Â·--- 1Â·Â·Â·---T---*1 ---Â·Â·iÂ·Â·_a_..__- 7--Â·Â·-7'-- Â·Â·Â·-Â·Â·Â·Â·-Â·Â·-Â·Â·Â·Â·Â·Â·Â·- Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec R L&P 8 -' 24*11*=Â»4 15 2 2 2 2222&22 8 S zoms!22 530 - 0 8*&1 >. N '3 Â©\ _C C %%%*% 00000 %*Â§%* Â©ddeÂ© N r- 74 00 ./ Câ‚¬N rn N r. -- SR -- re --- rn lit- C> - 0 A.Wrr,- 1- 2&2= e r.1* * Sgao C E-1- â‚¬- 8 TO el - 02 E 3 9 - 2 - tr, 0 3 <0 8 2 - M -0 0 E. 0 5 2 6,26 2 6 0 5 5 C. a U %81 09('95 DOE'gOE 100'0 1000 8.E'f 091'99 86*'65 %*t 8Lf'! tt, L09'686 500 0 900 0 (BL9'ZZ) 8Lt' I Et 008'80* 9t'1'9Z NEO'* I fL 1'0* %Z9 5Â£8' Egg Â£Â£1'6Â£6 LOO 0 LOO'O 20*'*Z 5Â£8'185 LEE'L09 L68'89 696'EL lnO Si@Jsue.Ii Butwiado %85 ELI'l 90'9 Â§19'0Lf'01 EL0'0 fLO'O *81'64 ELI'!50'9 Lit'001'9 (6/269Â£) ELI'IEO' I f#6' I L9 s aimipuodxzl lelol MONTH TO DATE YEAR TO DATE BUDGET vs. YTD net assets (assets - liabilities) $10,811,188 $10,811,188 ginn ng unrestricted (usable) fund balance 3,444,416 $2,748,086 $2,748,086 $2,748,086 768,093 765,517 (2,576) 6,391,972 6,712,616 32 ,644 0.077 0.080 9,741,005 6,712,616 Other 26,363 778,~64 276,402 278,970 ,568 0.003 0.003 397,863 278.970 70% Total Revenues 794,456 6,668,374 6,991,586 0.081 0.083 10,138,868 6,991,586 69% Source of Supply 346,348 735,440 (389,09 ) 2,996,498 2,993,921 2,57 0.036 4,702,000 2,993,921 Distribution and Maintenance 93,428 120,660 906,032 963,624 (57.59 ) 1,571,262 963,624 Customer Billing and Acc unts 39,001 8,074 389,400 354,342 35,05 674,571 354,342 nistration and Gene 79,853 83 667,520 4 1,285,342 667,520 2,303 If 3,300 2,303 Total O&M Expenses 558,801 948,24 (389,447 5,024 ,822 4,981,710 3 12 0.061 8,236,475 4,981,710 i I t'(*6 (Lt79'Ift) 96Â£'ELE Â£ I f' 0*6 Llo'995 (IZE'Â§LO (608'EST) Clf'Zzl (Imideo aio.laq sainlipuadxa (ERZ'Â§95) V/N (Â£80Â§99) (ESE'555) 0 (16Â£'85) (16Â£'85) 0 SallneS lOt{10 01 pole)0[le,/pJA 1000.I q SE) 0Â£1 '58 E (L*9'[ Ef) (L88'ES!) OEI'Â§8Â£ LIO'895 (ZIL'Â£[t) (0001 10 Z 1 5'ZZ I l{1UOUI JOJ uo!"sod qswo ui @Sueu 91CE[l'Eli 687'91*'8 9!Z'EEI'ES 912'Et!'Â£$ Jouellq pury (aiqusn) poiouisolun Butpuy[ AUGUST AUGUST VAR VAR Per kWh Per kW Budget 2005 200 1310 SanU@Aal Jo Kouotou@p/SsooxED [elotqns HT AND POWER FUND H FLOW COMPARISON peration and Maintenance Expense TOWN OF ESTES PARK LIGHT AND POWER TRENDS Type Summary Date August-06 12 - month moving average Total % Total % of Avg Avg Avg # ofaccts KWH Growth Revenues Total Rev % Cum Rev/KWH KWH/Cust Rev/Cust Residential 7,359 3,803,629 -0.3% $340,215 42% 42% $0.0899 517 $46.21 Gen Serv Small 1.578 2,029,233 -0.3% $179,650 22% 64% $0.0887 1,285 $113.75 Gen Serv Large 92 2,804,055 0.0% $171,003 21% 85% $0.0612 30,508 $1,861.33 Residential Demand 406 728,669 -0.3% $63,717 8% 93% $0.0912 1,800 $157.33 Res Energy / Time of Day 231 393,119 0.1% $23,810 3% 96% $0.0626 1,702 $103.05 Municipal 61 241,650 0.0% $18,716 2% 99% $0.0775 3,971 $307.59 RMNP - Small Admin 19 61,820 -0.2% $2,808 0% 99% $0.0455 3,254 $147.82 RMNP - Large Admin 6 63,840 -0.2% $2,627 0% 99% $0.0416 10,640 $437.85 Wind Power 98 0 #DIV/0! $2,107 0% 100% N/A 0 $21.53 Res Basic Energy 14 18,261 2.2% $1,542 0% 100% $0.0853 1,347 $113.11 GSS - Comml - Energy TOD 13 17,643 0.6% $1,178 0% 100% $0.0674 1,329 $88.80 GSL - Comml - Time of Day 1 10,865 0.0% $755 0% 100% $0.0705 10,865 $755.02 Outdoor Area Lighting 16 0 #DIV/0! $215 0% 100% N/A 0 $13.40 Res Time of Day 5 7,244 -1.0% $203 0% 100% #DIV/0! #DIV/0! #DIV/0! RMNP - Administrative 2 614 0.4% $31 0% 100% N/A 307 $15.71 9,900 avg $808,576 100% annual revenues at this pace: $9,702,914 budget $9,741,005 projected over/under: | ($38,091)| (1) CD >0 (D O ~ Glo -- do LA, 1 1 1 m.. 00. 4 .A %...4/- -000 1 le senue Â¤ Budgeted 2006 eoed JUGJJ n L&P Revenue Progress 04 ,t#b $9,800,000 $9,750,000 $9,700,000 - $9,650,000 - - 000'009'6$ - 000'099'6$ - 000'009'6$ SEPTEMBER 2006 UTILITIES COMMITTEE NOTE: THE NET METERING RATE UPDATE WILL BE A VERBAL REPORT 9/14/2006 Water Sales by Month ($) 350,000 300,000 - 250,000 - - 7 1- f 1 1 / t - 200,000 / 1 Â¤ 2004 $ 1 1 1 Â¤ 2005 ---f j j , 4 -1 150,000 -- 7 -7~ _Gr 7 -5-5-5-5-5-5- 5-7- 02006 1 1 4ttt//,t $ t **,,#/ 100,000 -- t -- t t, t / 1 1 11**14 , 1 1 Itit'* t 50,000 - / - / - litt' 1 / 1 / 1 *,,t/I I , ,/,t/* , 1 1 3 3 3 3 5- 0- ' ' ' Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Water Sales Year-To-Date ($1,000) 2,500 $2,128,000 2,000 ...1,.- 92004 â‚¬ 8 M 2005 1 1,500 0 2006 -t, 11 -7,1 1 , it -Budget , 11 1 / 1,000 - 12.17% 2006 YTD VS 2005 1 -3 2 '' 1 1 1 't '' 500 .m[m f i 6-6-5- -0- 4 1 1. /1 1 It ./. 52/ i Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec RW5 6\\\\\\\\ \\\\\\\\\\\\\\\\\\\\ Ap-,4,0.0.4e.,..,1-f,Jiliâ€žnâ€ž; \\ \\\\\\\\\\\\\\L \ \\ V.,\\\\:...\93 %gÂ£ii -2 -22 2 2 2 2 %0 \0 &6334Â°R Â£ 6 Mt--5 - 2% 93&9203: F 5 a 000190. 0 a dii- r-, M -M'.1000 h e -9 - fr, # - fl 5 3 5 Â§ Â§ R % 0 0Â© 9 2 0 d E Â« =Â©C~re, N re i N 3Â§ 888Â§8 ~00 6. 01 eeded 00 2 16 M *Egg %Â§% 0 g 00 000 000 - ~6 4-1 @29Â°8 2 .1 re M M 0 0 Â°9 - o M M Z - M _ L N & 4 0 - 4 fÂ·r. 0 _ 00 - 1 0, a W 0 2 * 0 7-5=21 01-Â·-rr;.r, -T Or'r O ERRE 0000-0 61 - - r-rri meNIrr, - 1 M - -0-1-0 CD Nâ€¢r,00 0 0 001-0,000\ 000'0 en -00000 rri 01 L.r3 85% 4 %44 ri 00:22 Ornâ€¢novel 0 O - rr, CD â€¢r;-00â€¢t) 0 ho (r, E-U m 4 4 5 06 N mâ€¢rbrle/ -r 2 6 4 01 - r : Lu U 1 -% 5 3 go = 8 2 6 -2 0 Z 2 5 AUGUST AUGUST VAR VAR Per Budget YTD YTD % %49 Â£Â£09 60Â£'Â£6 000 0 000 0 EEL'E9 6L6'9 (fLB) 565'11 Jrlo SJ@JSUBil BU!,elodo %8t 800'EOS' I EZZ'8Â£1'E 9000 900'0 800'205'1 91Â§'ES*'1 62*'88 260'891 samlipuodxa [elol TH-TO-DATE MONTH TO DATE YEAR TO DATE YEAR TO DATE 2005 2006 2006 of Budget % ofyr> 67% Beginning net assets (assets - liabilities) $17.810.446 $17,810.446 Beginning unrestricted (usable) fund balance 3.162.805 $2.682.987 $2,682,987 100% Water sales 293,339 1,461.929 1,639,869 177.940 0.006 2,137.800 1.639,869 77 Plant Development Tap Fees 94.339 lit.138 16,799 0. 111.138 Water rights Tap Fees 239,984 234.305 (5.679) 234,305 160'5Â£ ZIO'LEf 000 0 I 00'0 0*015 1 I 60'Â§Â£ l Ei'Z61 L6Z'86 L6Z'86 le]!duo Â£99'[65 (fES'tot) 1 Â£99'165 018'86Â£ 19'lti 400'6Â£ I (Imide, alopq samupuodxo Ely'Et,Â£'Â£$ â‚¬51'6LE'ES Eld'EfE'Â£$ Els'Et'E'ES poueleq pung (oiqusn) polouls@Jun Nuipul and Maintenance 415,087 421,987 0.002 0.002 695,409 88Â£'982 000 0000 C ) 045'Â£81 899'001 slunooiv 2899+9 1) Â£19'ZOE 9t,0'IEBE 8'0 01 9ZE'O[EE 5000 '*02) 968'OLE'I 5LZ'99 I'l 1 6631) Â£64'95 1 Source of Supply 77,347 110,692 C 0.000 0.000 137.900 9Lf'EOE 000 0 000 0 88L'Â£Â£ IEI'6Â£ JO!11 os *10(] 35,290 ) 290,127 352,064 ( 37) 0.001 0.001 543,647 (VEKEOf) SIL 19E 5Zg'099 018'86[ t,91'EN LOL'081 Â£59'LE liluoul iol uoilisod LISE) ul o,Nut:43 (E98'89) E98'89 (roL'I) EOL'I SJOinOS 10410 01 pole,OlIE/p@Al@031 4SE j Other 56,074 108.359 52,28 Total Revenues 1.852,326 2,093.671 241,34 CASH FLOW COMPARISON Operation and Maintenance Expense JOAO SOTIUOA@J JO KOU@!Ouop/SS@Oxg) ~810:qns ATER FUND vs. 2005 Revenues Expenditures 'E . TOWN OF ESTES PARK WATER DEPARTMENT TRENDS Type Summary Date August-06 12 - month moving average Total % Total % of % of Avg Avg Avg # of accts Gal Growth Revenues Tot Revs Cum Rev/Gal Gal/Cust Rev/Cust Urban Residential 2,613 13,249,363 -1.7% $74,729 37% 37% $0.006 5,059 $28.56 Urban Commercial 721 13,334,976 -1.4% $50,490 25% 62% $0.004 18,473 $69.94 Rural Residential 1,285 5,030,008 4.0% $53,607 26% 88% $0.012 3,912 $41.70 Rural Commercial 101 2,073,340 -0.2% $12,293 6% 94% $0.007 20,696 $122.59 Bulk Water 1,104,333 3.7% $11,480 6% 100% $0.012 avg: $202,598 100% annual revenues at this pace: $2,431,174 budget $2,137,800 projected over/under: | $293,374 1 - 00 02. -~----.---- 00. i 9/3 -9 --9-w--- ~6 Water Revenue Progress El Budgeted 2006 _ _ _ _ ~ 2Rlelv6enu~enues a Current Pace + 2,29 $2,250,000 - 000'000$ $2,200,000 - $2,150,000 -- - 000'OOLIES - 000'090'3$ - 000'000'3$ ./ED Stl43. UNITED STATES ENVIRONMENTAL PROTECTION AGENCY CINCINNATI, OHIO 45268 df 44 pRolip Office of Ground Water and Drinking Water August 28,2006 RE: PWS Registration for the Unregulated Contaminant Monitoring Regulation PWSID CO0135257 leif Boles Town of Estes Park P.O. Box 1200 Estes Park, CO 80517 Your CRK is: ~ Dear Public Water System: The Safe Drinking Water Act (SDWA), as amended in 1996, requires the U.S. Environmental Protection Agency (EPA) to establish criteria for a program to monitor unregulated contaminants and to identify no more than 30 contaminants to be monitored every five years. EPA identified and published unregulated contaminants for the previous Unregulated Contaminants Monitoring Regulation (UCMR) cycle (i.e., UCMRI), and a revised approach for -monitoring;-in the Federal Register [64 FR 50555] dated September 17. 1 999. The purpose of monitoring for unregulated contaminants in drinking water is to provide data to support the EPA Administrator's decisions concerning whether or not to regulate these contaminants in the future for the protection of public health. Under the proposed second cycle of the revised Unregulated Contaminants Monitoring Regulation (UCMR.2) [70 FR 49093 dated August 22, 20051 community water systems and non-transient, non-community water systems serving a total population more than 10,000 persons on June 30,2005 which do nol purchase all their finished water must monitor for unregulated contaminants. These public water systems (PWSs) are responsible for collecting drinking water samples, having them analyzed properly, reporting the results, and notifying the public of the results. Our records indicate that your water system is subject to the UCMR requirements. EPA will again be using an Internet-based electronic reporting system that utilizes a secure access portal know as the Central Data Exchange (CDX) to gain access to the reporting database known as the Safe Drinking Water Accession and Review System (SDWARS). The UCMR-2, if finalized as proposed, will require you to report your water system's contacts, ensure proper sample location inventory is defined and review your predefined sampling schedule, These tasks are on a strict schedule once the regulation is published, You are also encouraged to review and approve your analytical results in SDWARS. Your laboratory(ics) will post the data for submission to you as the client PWS. After you review and approve these results, they are released to your State and EPA as your official UCMR2 results, For you to access SDWARS you need to establish a CDX account. Internet Address (URL) e htlp://www,epa.gov Recycled/Recyclable e Printed with Vegetable Oil Based Inks on 100% Postconsumor, Process Chlorine Free Recycled Paper 60'tow/4/9.9. . 0 In anticipation of the UCMR-2 being published later this year, we are providing you with an opportunity to register via CDX now, so that your account will be ready when the regulation is published. To register go to http://cdx.epa.gov/preregistration, Enter the customer retrieval key (CRK) listed above and then follow the directions to complete registration. We recommend you do this as soon as possible, as the CRK may expire in 90 days. Once a CDX account for SDWARS is established, you may nominate other individuals to serve as representatives for your organization using the Nominate User link in the left sidebar on the main SDWARS page. A CRK will be generated within SDWARS for the nominee to use in establishing their own account. Your cooperation in implementing these requirements is appreciated. EPA recommends that you review the EPA Office of Ground Water and Drinking Water UCMR2 Website (www.epa.gov/safewater/ucmr/ucmr2/index.html) for more information on the proposed regulation. For technical and implementation questions please contact the UCMR Message Center at 1- 800-949-1581. Thank you for your cooperation. Sincerely, 41-L/L Gregory J. Carroll. Director Technical Support Center 1 . Administration Memo TO: Utilities Committee From: Randy Repola ~~ Date: September 20,2006 Subject: Scope of Services documents Background Attached to this memo are spreadsheet documents that staffmembers have drafted to outline the scope of services provided by his/her respective department(s). The draft scope of services documents are intended to provide a brief overview of the primary services provided by each department. In many instances, a department provides additional services, however, they are either incidental to a primary service, or so infrequent that the impact on operating costs or service levels is nonexistent. In addition, the measures o f efficiency and effectiveness are "dashboard" indicators ofthe performance of each department. In most cases, the "dashboard" indicators will provide a quarter-to-quarter or year over year comparison of trends or department performance. The objective is simply to be able to evaluate our operations annually and not necessarily against other communities (partly due to the fact that there are no known benchmark comparisons readily available at this time). It is anticipated that the scope details and "dashboard" metrics will be modified over time as we utilize this tool to evaluate operations. Budget There is no cost associated with this project. However, the scope documents should be useful when evaluating expansion or reduction o f services or existing service levels either from an operational or budget perspective. Action No action is required at this time. However, during the upcoming budget study sessions and over the next year, Committee members are encouraged to provide feedback and input on the both the scope content as well as the metrics so as to ultimately develop these documents into useful tools both for operational as well as policy-making decisions. LIGHT AND POWER DEPARTMENT Scope of Services __ad#.L,2~_..Us,.ILL GOAL: To provide our customers with Electricity per National Energy Safety Code Standards. Services Required Records Management Multi Agency Switching Integrated Resource Plan Maintain 2 Substations and 300 Miles of Distribution System Energy Information Administration Construct Electrical Infrastructure for New Development Consumer Usage/Billing Information Promote Energy Efficiency Load Shedding Plan Promote Renewable Energy thru Platte River Power Authority Wheeling Power To Rocky Mountain National Park Required Personal Read both Electric and Water Meters Journeyman Lineman Maintain Street Lights Certified Meter Technician Special Events; Flags, Banners, Christmas Decorations. Certified Energy Manager Lightning Protection (at customer request /expense) Certified Public Buyer Member Platte River Authority Green Energy Certifed Thru PRPA t-2 2.r . ' ' rf . 2006 (YTD) Total Revenue 9,117,643 10,303,444 6,991,585 Light and Power Department Total Expense Budget 7,891,644 8,361,022 8,527,425.00 Customer Base 9,713 9,841 10,025 Employees 26.3 26.4 26.7 Budget Source of Supply $ 4,291,364 $ 4,613,129 $ 4,702,000 Budget Distribution $ 1,717,358 $ 1,474,888 $ 1,571,262 Budget Customer Accounts $ 639,102 $ 639,105 $ 674,571 Administration and General $ 1,118,116 $ 1,329,905 $ 1,274,292 Transfer To General Fund 9% of Utility Sales $ 825,399 $ 898,600 $ 885,133 Services Source of Supply Purchased Power KwH 124,841,660 126,207,880 84,294,433 Distribution Miles of Distribution System 301.1 301.9 303.1 Customer Accounts Meter Reading number of Water and Electric Reads 179364 181764 Efficiency Source of Supply Source of Supply % of Budget Expenses (Purchased Power) 54.4% 55.256 55.1% Distribution Customer per Mile 32 33 33 O&M cost per mile $ 5,703.61 $ 4,885.35 $ 5,183.97 Customer Accounts KwH per Customer 12,853 12,825 8,408 Cost per Read $ 0.07 $ 0.08 Net Revenue per KwH $ 0.073 $ 0.082 $ 0.083 WATER DEPARTMENT Scope of Services 11.. _Li_ . .~~didl 1-a... 1 GOAL: To provide our customers with Drinking water that meets all CDOH and EPA Regulations. ' Sentices Required Records Management Order/Purchase/ Lease Water CDOH Reports Contract Review, Easements, Other EPA Reports Planning Forecasting Operations and Historical Data Water Order, Delivery, Accounting Augmentation Plan, Report NCWCD Watershed Management Report to River Commissioner Planning Forecasting Produce Water for Public Distribution Water Plant and Distribution System Maintenance Maintain Water Mains and Fire Hydrants Customer Billing . . )4) g 'I' rL....., i.b hâ€¢Â·/*4Â· ....1 .UÂ·.0, .... ' State Required Personal Meter Maintenance Class A Water Operators Maintain Backflow Prevention Program Class 3 Distribution System Operators Troubleshoot Customer PSI and Volume Problems Certified Backflow Prevention Technician Locate Water Mains and Service Lines Maintain Systems Maps ~~ iÂ·gÂ·t :il.~~ 1~ - 2004 . f 2005 - ~ 2006 mp). Total Revenue $ 2,698,743 $ 2,636,711 $ 1,608,039 Water Department Total Expense Budget $ 1,865,515 $ 2,281,814 $ 2,582,766 Customer Base 4579 4630 4804 Employees 12.2 12.2 14.29 Budget Source of Supply $ 127,172 $ 133,900 $ 110,692 Budget Purification $ 439,517 $ 461,313 $ 481,980 Budget Distribution $ 477,253 $ 631,190 $ 695,409 SERVICES 2004 2005 2006 Source Of Supply Water Rights = USA (always 500 ac ft) + Windy Gap (up to 300) + CBT 1217 ac ft = 2017 ac ft Amount Treated 751 635 914 Leased 197 134 218 Total Used Acre Ft 948 769 1132 Surplus 582 783 856 Purification Total Produced MG 478,258,600 555,912,600 321,921,200 Distribution Total Miles of Distribution 103.73 105.65 106.58 Total Gallons Delivered (metered) 425,650,154 455,848,332 263,975,384 Efficiency Source Of Supply Goal Use or Lease 80% of Water Rights % Used Efficiency 62% 50% 57% Revenue per Acre Foot $ 2,255 $ 2,930 $ 1,187 .Expense per Acre Foot $ 134 $ 174 $ 98 Purification Goal to Meet State/EPA Standards NTU .30 >.30 >.30 >.30 Expense Per 1000 Gal $ 0.84 $ 0.64 $ 1.66 Distribution Leakage Index Goal 85% for Accounted Water 89% 82% 82% Distribution Cost Per Mile $ 4,601 $ 5,974 $ 6,525 Net Revenue per 1000 gal delivered (metered) $ 6.34 $ 5.78 $ 6.09 Scope of Services: Information Technology Department Operate and Maintain the Network and associated equipment. SERVICES Records Management PC Support, replacement, installation, management, and software maintenance Software Licenses Printer, Copier, Fax, Scanner, Multifunction Support External Connectivity PDA, Blackberry, Cell phone, Phone handsets Supporl Network Security AN - Boardroom, Firehouse, Training Rooms, Museum Maintenance Contracts User Training Database maintenance Network PlanVEquipment Facility Security Light & Power, Water SCADA support AS400 1 C -- _ 2005 1._ _ 2006 I 2007 2- Revenue $253,496 $319,400 $392,188 Budget Expense $294,221 $290,922 $392,188 Maintenance Services Tec Support Goal 4hr Total # of network equipment 110 135 # of Workstations 120 148 148 Expense per Workstation $2,451.84 $1,965.69 $2,649.92 0 -i ./ -7 , I.- f g l\~-r - to )V - i 1 2-fi i , . 16. . 3. 4 i k 4 - 2006 7 & ,.i.:4*JA#:'' . 4 .,+ 7.'.. I' -Ii. -7 1 ./ r . INTEGRATED RESOURCE ,- w PLAN i .1 -AB. VIA'll \ PLATTE RIVER POWER AUTHORITY Estes Park Â· Fort Collins â€¢ Longmont â€¢ Loveland Â¢* Platte River Power Authority DRAFT 2007 Integrated Resource Plan Updated August 28,2006 Table of Contents I. Executive Summary 1 II. Recent Trends in Electrical Load Growth 3 III. System Load Foreca~ 7 IV. Current Resources 11 V. Load/Resource Balance and Resource Need< 14 VI. Resource Supply Alternativeâ‚¬ 18 VII. Renewable Energy 26 VIII. Demand-Side Management 28 IX. Recommended Actions 37 X. Public Participation 39 . I. Executive Summary Platte River Power Authority (Platte River), in coordination with its member municipalities (Estes Park, Fort Collins, Longmont and Loveland), has prepared this Integrated Resource Plan (IRP). An IRP provides information associated with the planning of resource acquisitions to meet customers' future electrical energy needs, including capacity and energy supply resources, renewable energy and energy efficiency options (referred to as demand side management or DSM). The planning process must balance rate impacts, reliability and environmental effects, with the resulting plans informed by both technical analysis and public review. Resource planning is a continuous and dynamic process, and this IRP represents a view of conditions as they stand at a narrow window in time. Many of the issues and assumptions presented here will change as customers' needs and available resource options evolve. This IRP is written in the context of a long-term horizon (2007 through 2018), with emphasis on the next five-years. Platte River and the member municipalities plan to implement several action items related to resource planning and acquisition, including: (1) addition of a new GE7FA gas-fired peaking resource at the Rawhide site by the summer of 2009, (2) expansion of energy efficiency programs, (3) continued implementation of the Renewable Energy Supply Policy, (4) monitoring of developments in regional generation and transmission resources to ensure a position in any new options of benefit to Platte River and its members, and (5) monitoring of changes in customer loads to support contingency planning. The municipalities served by Platte River have seen significant growth in business activity, population, and demand for electricity over the past ten years. In 2005, Platte River provided 47% more energy to 35% more customers than in 1995, with summer peak demand increasing by 80%. Growth rates are anticipated to slow over the long term; however, factors such as business relocation, economic conditions, annexation variability and the potential expansion of distributed generation make accurate forecasting a challenge, particularly over the long term. The most recent 10-year load forecast is included as part of this IRP. Platte River's existing electrical generation resource portfolio includes a mix of hydropower (via federal contracts), coal-fired generation (located at Rawhide and Craig stations), natural gas turbines (four units at the Rawhide site) and wind turbines (located at the Medicine Bow Wind Project in Wyoming). These resources, along with a small quantity of purchases from the wholesale market (less than 1 % of total energy requirements), are adequate to meet the needs of Platte River's members for the next few years. However, given Platte River's reserve and reliability requirements, and considering load forecast variability and market purchase limitations, a new resource is needed in 2009. Since the late 1970's, the member municipalities and Platte River have developed numerous programs to encourage efficient generation, transmission, distribution, and use of energy. Over the next five years (2007 through 2011), DSM programs will be expanded, with the goal of achieving demand savings of 17 MW and energy savings of 108,000 MWh per year by the end of 2011. In March of 2006, Platte River's Board of Directors approved a Renewable Energy Supply Policy, which guides Platte River as it plans for and acquires new renewable sources to meet the needs of its owner municipalities. The policy provides direction regarding the level of 1 DRAFT renewable sources to be obtained, the type of sources considered acceptable to meet municipal renewable requirements, the anticipated impacts of renewable sources on future resource planning and the approach to be used for pricing renewable sources for sale to the member municipalities. By 2018, Platte River anticipates providing renewable energy (from sources other than WAPA hydropower) at a level of approximately 360,000 MWh/yr, or about 10% of total predicted energy supply to the municipalities. Though renewable energy sources are not expected to provide peak capacity, they can provide energy and environmental benefits. Resource planning in general and this IRP in particular have been the topic of several public communications processes in recent years. Through customer and community surveys, public hearings, customer meetings, media releases, meetings with community groups and public meetings of the Platte River Board of Directors, an effective exchange of information on the issues of electric load growth and resource planning has occurred (and will continue) among the member utilities, boards and councils, customers, and citizens of the member communities. It is anticipated that a final 2007 IRP will be approved by resolution of the Platte River Board of Directors during the fall of 2006. It will also be submitted to the Western Area Power Administration, in accordance with the directives of the Energy Policy Act of 1992. Updates will be provided on an annual basis. 2 DRAFT II. Recent Trends in Electrical Load Growth The municipalities served by Platte River have seen significant growth in business activity, population, and demand for electricity over the past ten years. In 2005, Platte River provided 47% more energy to 35% more customers than in 1995, with summer peak demand increasing by 80%. Figure 1 shows the overall trends in energy and peak demand on the Platte River system. Figure 2 breaks out the energy usage, peak demand and ten-year population growth rates by municipality. Figure 1 Historical Growth Trends 90% 80% - 35%increase in population / 1 70% -- 47%increase in energy - 80%increase in peak demand 60% - 50% 40% ---0 . 30% ----- ---- - f 20% .#...- -...... 0-- 10% * 0% 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 - - Population Peak Demand - 0 - Energy Figure 2 1995 Energy 2005 Energy 1995-2005 1995 - 2005 10 Year Cities Requirements Requirements Energy Growth Summer Peak Population (MWh) (MWh) Rate Demand Growth Growth Rate* Estes Park 100,203 126,208 26% 35% 48% Fort Collins 988,530 1,432,566 45% 73% 29% Longmont 509,435 792,503 56% 97% 44% Loveland 430,267 634,684 48% 88% 37% Aggregate 2,028,435 2,985,961 47% 80% 35% *Source: State Demography Office. Ten year growth rates based on 2004 data (2005 data was not available) 3 DRAFT Growth in electric demand has come not only from new business and residential customers, but also from an increase in the average use of electricity per customer. A significant portion of this increased demand has been attributed to more extensive use of both residential and commercial air conditioning, together with greater reliance on computers and other electrical technologies. Figure 3 below presents the historical and projected growth for summer, winter and annual peak demand. As of 2005, the summer and winter peak load grew at an average of 5.8% and 3.0%, respectively, over the past five years. In 1997, Platte River's annual maximum system peak changed over from the winter season to the summer season. The peak demand disparity between summer and winter has widened in recent years; during 2005, the summer peak demand was 35%, or 159 MW, greater than the winter peak demand for the 2004/2005 winter season. Figure 3 SUMMER PEAK WINTER PEAK BILLABLE PEAKS Peak Annual Five-Year Avg. Peak Annual Five-Year Avg. Billable Annual Five-Year Arg. Year Year Year (MW) Change % Change '4 (MiDChane*Chane* Peak(MiVChan,e'kChange % - _162*(LUL_LILL~ILL~ 1996 346 0.9% 4.3% 96-97 364 6.7% 5.8% 1996 3,945 5.6% 4.8% 1997 371 7.2% 6.0% 97-98 361 -0.8% 3.8% 1997 4,054 28% 5.2% 1998 411 10.8% 6.7% 98-99 392 8.6% 5.1% 1998 4,282 5.6% 5.1% 1999 431 4.9% 6.7% 99-00 386 -1.5% 4.2% 1999 4,376 2.2% 4.4% 2000 466 8.1% 6.3% 00-01 429 11.1% 4.7% 2000 4,783 9.3% 5.1% 2001 497 6.7% 7.5% 01-02 417 -2.8% 2.8% 2001 4,994 4.4% 4.8% 2002 533 7.2% 7.5% 02-03 430 3.1% 3.6% 2002 5,294 6.0% 5.5% 2003 559 4.9% 6.3% 03-04 460 7.0% 3.3% 2003 5.415 2.3% 4.8% 2004 576 3.1% 6.0% 04-05 459 -0.2% 3.5% 2004 5,466 0.9% 4.5% 2005 618 7.2% 5.8% 05-06 497 8.3% 3.0% 2005 5,695 4.2% 3.6% --74)RIC:1.$IIORL<:.0l-7<)Rl.C:K 2006 6t 7 -0.2% 4.4% 06-07 485 -2.5% 3.0% 2006 5,837 2.5% 3.2% 2007 636 3.2% 3.6% 07-08 496 2.3% 2.9% 2007 5,991 2.6% 2.5% 2008 656 3.1% 3.2% 08-09 507 2.3% 2.0% 2008 6,144 2.6% 2.6% 2009 675 3.0% 3.2% 09-10 518 2.2% 2.5% 2009 6.297 2.5% 2.9% 2010 695 2.9% 2.4% 10-11 529 2.2% 1.3% 2010 6.449 2.4% 2.5% 2011 714 2.8% 3.0% 11-12 541 2.1% 2.2% 2011 6,603 2.4% 2.5% 2012 734 27% 29% 12-13 552 2.1% 2.2% 2012 6,759 2.4% 2.4% 2013 754 2.7% 2.8% 13-14 564 2.1% 2.1% 2013 6,916 2.3% 2.4% 2014 774 2.7% 2.8% 14-15 575 2.0% 2.1% 2014 7,072 2.3% 2.3% 2015 794 2.6% 2.7% 14-16 587 2.1% 2.1% 2015 7,231 2.2% 2.3% *Summer (April-September) *Winter (October-March) Figure 4 presents a summary of the historical and projected growth in energy supplied by Platte River. Billable peaks represent the sum of all monthly peak demands for the year. The average annual summer and winter energy growth rates for the 5-year period ending 2005 were 3.0% and 2.6% respectively. In summary, summer peak demand growth has outpaced growth in winter peak, summer energy and winter energy, as indicated by 5-year averages in Figures 3 and 4. Winter peak, summer energy and winter energy have had similar growth (all close to 3%) over the last 5 years. 4 DRAFT Figure 4 SUMMER WINTER ANNUAL }'ear Energy Annual Five-Year A:g. Year Energy Annual Five-Year Avg. Year Energy Annual Five-Year Arg. (GWh) Change % Change % _ _ (GWh) Change % Change 5% *Wh) Change % Chanxe % 1996 1,052 3.9% 4.8% 96-97 1,087 6.1% 4.3% 1996 2,133 5.151 4.8% 1997 1.098 4.4% 5.4% 97-98 1.131 4.Ove 4.0% 1997 2,213 3.7% 5.4% 1998 1,153 5.0% 5.4% 98-99 1,165 3.1% 4.1% 1998 2,298 3.9% 5.4% 1999 1,213 5.2% 4.8% 99-00 1.226 5.2% 4.4% leg 2,404 46% 4.4% 2000 1,311 8.1% 5.3% 00-01 1.312 7.0% 5.7% 2000 2,587 7.6% 5.0% 2001 1,357 3.5% 5.2% 01-02 1,335 1.8% 4.2% 2001 2.670 3.2% 4.656 2002 1,415 4.3% 5.2% 02-03 1,374 2.9% 4.0% 2002 2,781 4.2% 4.7% 2003 1.453 2.7% 4.7% 03-04 1.420 3.4% 4.0Â°/6 2003 2,846 2.3% 4.4% 2004 1,442 -0.8% 3.5% 04-05 1,442 1.5% 3.3% 2004 2,885 1.4% 3.7% 2005 1.523 5.6% 3.ove 05-06 1,492 3.5% 2.6% 2005 2,991 3.7% 2.9% 2007 1.600 2.5% 25% 07-08 1.562 2.3% 2.6% 2007 3.145 2.4% 2.5% 2008 1,640 2.5% 2.4% 08409 1,597 2.2% 2.4% 2008 3.220 2.4% 2.5% 2009 1.679 2.4% 3.1% 09-10 1,632 2.2% 2.5% 2009 3.294 2.3% 2.7% 2010 1,719 2.4% 2.5% 10-11 1.667 2.1% 2.2% 2010 3.369 2.3% 2.4% 2011 1,759 2.3% 2A% 11-12 1.703 2.1% 2.2% 2011 3.444 2.2% 2.3% 2012 1,799 2.3% 2.4% 12-13 1,739 2.1% 2.2% 2012 3,520 2.2% 2.3% 2013 1.840 2.3% 2.3% 13-14 1.775 2.1% 2.1% 2013 3,597 2.2% 2.2% 2014 1,881 2.2% 2.3% 14-15 1.811 2.0% 2.1% 2014 3,673 2.18/0 2.2% 2015 1,922 2.2% 2.3% 15-16 1,847 2.0% 2.1% 2015 3.751 2.1% 2.2% *Summer (April-September) 'Winter (October-March) Figure 5 shows the annual load duration curves from 1995 and 2005. Over this period, the peak load demands during relatively few hours on summer peak days have grown 80%, while demands during the rest of the year have grown much slower. Figure 5 700 80% Increase 600 l A 500 ~ 400 -~ 46% Increase 300 S.. 200 ~ 100 ----- - -- ------- -------- -- -19~-20051 0 1 877 1753 2629 3505 4381 5257 6133 7009 7885 8760 Hours 5 DRAFT City Load (MW) Figure 6 illustrates the summer peak-day load profile for the summer seasons 2002 through 2005. Over this period the summer peak increased by 85 MW, or about 28 MW per year. Figure 7 shows the winter peak-day load profile for the same years. From 2002 through 2005 the winter peak has increased by 67 MW, or about 22 MW per year. Figure 6 Summer Peak Day Load Profile 650 600 550 ,ts;@51~E~b.- 500 â€ž31*-e'l-'â„¢.UEL-- 450 /07 1%, 350 *4*w 300 -%--lr-.-ir-Ii,z-**1rvAC 250 200 150 100 50 0 1 2 3 4 5 6 7 8 9 101112131415161718192021222324 Hour - 07/22/05 -I- 07/13/04 - 07/17/03 --*-07/30/02 Figure 7 Winter Peak Day Load Profile 650 600 550 i 500 92>-44- --J 450 h- Tri ./ i '4:1 i 350 ..\- 300 -J 250 200 150 I 100 - --- -- -- ----- -- -- I 50 0 1 2 3 4 5 6 7 8 9 101112131415161718192021222324 Hour -0-12/06/05 ---01/05/05 -+- 01/05/04 ---*e-02/24/03 ~ 6 DRAFT Demand - MW Demand - MW III. System Load Forecast 1. Method Platte River retained UFS (Utility Financial Solutions) to create a long-term load forecast using an econometric model to forecast projected energy and demand growth. Econometric modeling uses multiple forecasts of independent variables to project the growth of a dependent variable. Platte River's econometric model uses population, weather and employment as independent variables to project demand and energy growth. Woods & Poole (W&P), an independent economic forecasting consulting firm, provided forecasts for population and employment. W&P's most recent employment and population forecast for Larimer and Boulder counties show a significant decline from historical growth rates. While Platte River's owner municipalities' populations have grown at an annual average rate of 3.0% between 1991 and 2004, W&P's forecast projects average annual population growth of 1.7% for the 2006-2024 period. This forecasted decline in population and employment contribute to the forecasted reduction in peak demand growth. To forecast the independent weather variables used in Platte River's peak demand projections, average weather conditions (either Cooling Degree Days or Heating Degree Days) for the period 1991 to 2004 were applied. While this long run average should reflect "average" weather conditions, weather variability in any given year may be higher or lower than the long run average. 2. 10-Year Municipal Load Forecast The following are the highlights of the 2006 Ten-Year Forecast: â€¢ The ten-year summer demand growth is approximately 20 MW per year, with an average annual growth rate of 2.5% for the 2006 to 2015 period. â€¢ The ten-year winter demand growth is approximately 11 MW per year, with an annual growth rate of 1.7% for the 2006 to 2015 period. â€¢ Average annual energy growth rate is 2.3% for the 2006 to 2015 period. Figure 3 above details the most recent 10-year projected seasonal peak demand forecast for the aggregate of the municipalities' loads. The data are taken from the 2006 Budget Forecast. As can be seen from this figure, the five-year average growth rate for Platte River's base summer demand is projected to decline from 5.8% in the summer of 2005 to 2.7% in the summer of 2015. The five-year average growth rate in base winter demand is projected to decline from 3.5% from the 2004-2005 winter to an annual seasonal growth rate of 2.1 % during the final interval of the 10-year forecast. As indicated in Figure 4, the summer five-year average energy growth rate is projected at 2.3% in 2015, down from 3.0% in 2005. The winter five-year average energy growth rate is projected at 2.1 % in 2015/2016, down from 2.6% in 2005/2006. Figures 8 and 9 depict historical and projected summer and winter demand for 1995 through 2015, along with the high and low forecast intervals. It is expected that the summer peak load will continue to dominate, driven in part by the more widespread use of air conditioning systems. 7 DRAFT Figure 8 Summer Peak Demand (Historical and Forecasted) 1,000 900 0 0 800 0 2 700 0 X O X E X X X 600 / W X X 500 400 300 % -- Actual --Base- Forecast x Low Forecast o High Forecast Figure 9 Winter Peak Demand (Historical and Forecasted) 1,000 900 800 700__- Z 0 0 600 L 0 O U 0 0 0 V n -O cr ~ 9< 0-= O 0 300 00 Â© M Z 5 4?143* c., 4 - Â©9Â© -- o Actual -0- Base-Forecast x Low Forecast o High Forecast 8 DRAFT Summer Peak Demand 1995 - 1997 1 1999 - j 2003 2005 - LOOZ 6002 IIOE FIOI < slot Winter Peak Demand 91-SI Figure 10 depicts historical and projected annukl energy from 1995 through 2015, along with the high and low forecast intervals. Figure 10 Annual Energy (Historical and Forecasted) 4,500 4,000 0 0 3,500 0 0 X X X X 3,000 - - # 2,500 ~,lv.'.'. 9 2,000 + 1,500 -- 1,000 500 4, m M -1 --3Â·Â· Actual - Base- Forecast x Low Forecast o High Forecast 3. Factors Affecting Load Growth A number of factors introduce uncertainty into load projections for the Platte River system. Several of these are discussed here. A. Annexations and Urban Growth Boundaries Each of the four member municipalities is characterized by its own set of policies that guide decision-making processes for annexation and changes to urban growth boundaries. Urban growth boundaries define the limits for a municipality's future footprint of homes and businesses upon the landscape, which impacts electricity consumption. New construction outside the urban growth area will typically fall under the county's jurisdiction, not that of the municipality. In the future, new developments outside of urban growth boundaries could be proposed, accompanied by requests for annexation into the adjacent municipality. Depending upon the size and number of such projects, growth outside the urban growth boundaries of the cities may have significant impact on the municipalities' future load growth. Annexations of existing loads may also occur and these could increase loads beyond the forecasted level. Platte River and the municipalities will monitor this issue. 9 DRAFT Annual Energy 1997 - 1999 - 2003 2005 - Loot 6003 - IIOZ - CIOZ SIOE B. New Energy Intensive Loads Advances in computing technology and the need for secure data have led to expansion of web and data server installations, which are typically high energy users. These large installations can increase peak loads by over 50 MW within a few years. Given the owner municipalities' historically low and stable electric rates (and other attractive characteristics), several entities with large loads (5 MW to 48 MW) have considered locating within the members' service areas. The assumptions supporting the current load forecast do not include new large energy intensive loads. Platte River and the cities continue to work closely together on this issue. C. Local and National Economic Conditions The population forecast used to develop our electric energy forecasts predicts a significant decline in population growth rates (vs. historical rates). Between 1991 and 2004, population growth has averaged 3.0% for the region. For forecasting future energy and demand requirements, Platte River used the Woods & Poole forecast, which averages 1.7% annual population growth. The actual rate of population growth and strength of economic conditions in the region will impact future demand and energy growth rates. D. Restructuring/Market Trends Events over the last several years in California and other regions have significantly diminished the momentum behind electric industry restructuring (particularly at the retail level). The current regulatory and legislative environment leaves the timing of restructuring in Colorado uncertain, but it is unlikely that retail competition will be implemented for the next several years. Changes in municipal loads that may occur due to industry restructuring are not included in the current forecast. E. Distributed Generation Distributed Generation (DG) technologies such as fuel cells, micro-turbines, small-scale co- generation, photovoltaics, small-scale reciprocating engines, and small wind turbines have garnered a great deal of interest in recent years. To date, the relatively high cost of these technologies has limited their widespread installation. Many organizations are vigorously working to overcome these barriers. As the cost of distributed generation technologies continues to drop in future years, some of the loads in Platte River's owner communities may be affected. The extent of the impact depends on the rate of acceptance of DG technologies and on the degree to which Platte River participates in their implementation. Platte River will continue to closely monitor ongoing developments in distributed generation, both to maintain a watch on competitive developments in the industry and to understand the benefits and risks of directly implementing DG technologies as they continue to mature. 10 DRAFT IV. Current Resources To fulfill its mission, Platte River has developed and contracted for a diversified mix of reliable, cost-effective and environmentally responsible resources. An overview of each of Platte River's current resources is provided below. 1. Rawhide Energy Station The Rawhide Energy Station consists of Rawhide Unit 1, a 274 MW (net capacity) coal-fired generating facility, with cooling reservoir, coal-handling facilities, emissions control equipment, and related transmission facilities. Rawhide Unit 1 commenced commercial operation on March 31, 1984. The station is located approximately 20 miles north of Fort Collins and is connected to Platte River's system by two double circuit 230 kV transmission lines. The site includes four gas-fired combustion turbines, Rawhide Units A, B, C, and D; these units are discussed in further detail below. At inception in 1984, Rawhide Unit 1 was equipped with the best available emissions control technology, and has seen several emissions control upgrades since. Rawhide Unit 1 is one of the lowest emitting coal-burning energy stations in the U.S., as can be seen in Figure 11. Figure 11 SO2 Emissions, lbs per million Btu NOx Emissions, lbs per million Btu 1.40-~ '+ 0.40 --' I / 1.20-,1 0.35- - 0.30 1 1 01 . 0.25 -/, 0.80 -' 1 -- M 7- /1 1 tâ‚¬ 1 2 0.60 / J 2 0.15 0.40-'/ /1 J 0.05-- , 0.10 : 0.00-- Rawhide 2006 Rawhide 20/r WY,ALCO,UT 2005 National Rawhide 2006 Rawhide 20yr WY,AZ,CO,UT 2005 National ag ag coal plants, avg, all coad avg avg coal plants, avg, all coal 2005 ag plants plants 2005 avg 2. Yampa Project (Craig Units 1 and 2) The Yampa Project consists of Craig Units 1 and 2, both of which are coal-fired - each rated at 428 MW (net capacity). Platte River owns an 18% share of Units 1 and 2, or 77 MW per unit, for a total of 154 MW. The Yampa Project is located in northwestern Colorado, approximately four miles southwest of Craig. The site includes the generation facilities, a coal handling facility, a small water storage reservoir, and related transmission facilities. The $120 million Yampa Environmental Project was completed in 2004, which reduced SC)2, NOx, and particulate emissions from the plant. Due to recent upgrades to the emission control systems, Craig Units 1 and 2 are now among the lowest emitting coal-fired plants in Colorado (and throughout the U.S.), as indicated in Figure 12. Platte River also owns approximately 190 MW of transmission 11 DRAFT capacity in the path from western to eastern Colorado, which is used to deliver Platte River's share of the Yampa Project output. Figure 12 SO2 Emissions, lbs per million Btu NOx Emissions, lbs per million Btu // . .... ..M 1.40, 0.407 1 ~ 7 /4 9 1.20- - 0.35 -' 7 -LI~=4 i . D 038 / - E I .1--1 3 0.25-/ 0.80-J I i\ CO , 0.60- 8 0.15'" 0 i--j~li ;1__0 -~ ~ EE O.20 / 0.40-,/ 0.20 -*'-- 0.10-~~ ' _ I ~ _ hi _ 0.05-' 7 0.00, Craig Unit 1&2 Craig Pre- WY,ALCO,UT 2005 National Craig Unit 1&2 Craig Pre- WY,ALCO,UT 2005 National 2005 59 Decree ati coal plants, 2005 a,g, all coal 2005 aig Decree apg coal plants, 2005 89 all coal al plants plants avg 3. Western Area Power Administration Supply Contracts Platte River receives allocations of federal hydropower under contracts from the Western Area Power Administration's (WAPA) Loveland Area Project (LAP) and the Colorado River Storage Project (CRSP). These allocations vary by season. The LAP contract was extended in March 1996 to run through September 2024. Platte River receives monthly quantities of approximately 30 MW to 34 MW of LAP capacity throughout the year. It is expected that these allocations may be reduced in 2009. Platte River's guaranteed capacity from CRSP was reduced on March 1, 1997, as part of Amendment No. 4 to the CRSP agreement. This reduced capacity is referred to as Sustainable Hydropower (SHP). For long-range load and resource planning, Platte River uses the SHP quantity as the capacity expected to be available from CRSP. Platte River expects to receive approximately 55 MW to 62 MW of CRSP capacity during the summer season and 75 MW to 85 MW of CRSP capacity during the winter season. The final element of the CRSP supply is an as-available resource, based upon the capacity difference between contract-rate-of-delivery and Sustainable Hydropower quantities. This difference is referred to as Western Replacement Power (WRP) and represents capacity and energy that Platte River can schedule from WAPA. The price for this energy is not known until after the power is delivered. For long-range resource planning, any market purchases required to meet loads are assumed to be met first from WRP purchases. 4. Wind Generation In 1998, Platte River completed the development and commercial startup of two 600 kW commercial wind turbines at its Medicine Bow Wind Project site (MBWP). Together with the City of Fort Collins, Platte River was the first utility in Colorado to provide wind energy to its customers. Five more 660 kW turbines were added in 1999, followed by another two units in 2000. During 2005, a new 2.5 MW wind turbine was installed (Clipper Liberty), making a total 12 DRAFT Ibs/mmetu 1- -i 9. of ten turbines (8.3 MW) at Platte River's Medicine Bow site. All member municipalities purchase renewable energy from the turbines and the output of one turbine is sold to Tri-State Generation and Transmission Association. 5. Peaking Units As a result of ongoing load and resource planning, Platte River's Board of Directors has approved the purchase of four GE7EA natural gas fired combustion turbines (Rawhide Units A, B, C, and D). Three of these units were commercially available for generation in 2002 and the fourth was brought on line in the spring of 2004. Each unit provides 65 MW of summer peaking capacity. A 14-mile natural gas pipeline was constructed to supply fuel to the units. The pipeline has adequate capacity to supply up to 10 similarly sized gas turbines. These units provide peaking capacity as well as backup reserve capacity in the event of an outage at one of Platte River's base load resources. 6. Forced Outage Assistance Agreement An agreement has been executed with Tri-State Generation and Transmission Association, whereby 100 MW of capacity is provided to Platte River in the event of an outage at Rawhide Unit 1. In exchange for this capacity provision, Platte River provides 100 MW of capacity to Tri- State in the event of an outage at Craig Unit 3. The agreement applies for a time period of up to one week per occurrence. 7. Photovoltaic Plant Platte River continues to operate a photovoltaic system that was installed as a pilot project in 1986. Initially, four sets of modules (10 kW total) were operated in different configurations so that side-by-side comparisons of effectiveness could be made. A final report on system performance was issued in 1992. Since then, two configurations have remained in operation, for a total capacity of about 7 kW (maximum). Platte River continues evaluation of the two remaining systems for long-term performance and reliability. The solar system is also used to charge two electric vehicles in Platte River's fleet. These vehicles (Toyota RAV4s) have significantly improved range and performance relative to earlier models of electric vehicles. With photovoltaic charging, the vehicles are essentially "zero emission" vehicles. 8. Demand Side Management Finally, Platte River works jointly with its owner municipalities to implement customer demand side management (DSM). DSM programs are described in more detail in Section VIII of this document. 13 DRAFT V. Load/Resource Balance and Resource Needs Platte River's system load characteristics and the resources available to serve that load are summarized in the foregoing sections. We now turn to the issue of matching resources with load. In this section, we summarize the balance between Platte River's annual loads and resources, and we review the risks associated with the unanticipated loss of Platte River's largest resource. Platte River's resource decisions are based on ensuring an adequate level of resources to meet loads, particularly when the largest resource (Rawhide Unit 1) is off line. Other resource decision criteria include rate impact, operational characteristics of new resources, appropriate matching of short-term and long-term needs of the municipalities, financial risk, and environmental considerations. In addition, any resource development undertaken by Platte River will be considered within the context of the resource plans and activities of other utilities and independent power generators in the region. Ensuring an adequate level of resources to meet loads is addressed quantitatively by considering four criteria: (1) maintain resources to ensure that loads do not exceed Platte River's resources by more than 65 MW in the event of an outage of Rawhide Unit 1 (in other words, ensure no more than 65 MW is required to be purchased from the wholesale market), (2) maintain a minimum reserve margin of 15%, (3) ensure loss of load probability (LOLP) of less than 5% at the peak hour, and (4) ensure loss of load expectation (LOLE) of less than 1 day in 10 years. Platte River's Board approved the first criterion during prior resource planning efforts; the other criteria have been analyzed during this planning cycle to enhance decision making. Load and resource comparisons are based on a seasonal peak-day analysis. Figures 13 and 14 highlight the historical and projected summer and winter load duration curves. The shape of the curves has not changed markedly in recent years and is not expected to change substantially in the future. Figure 13 Figure 14 Historical & Forecast Platte River Summer Historical & Forecast Platte River Winter Load Duration Curves, MW Load Duration Curves, MW 900 800 ---~ 800 ~ 700 (&2 700 600 ~.(,4-_ ~ 500 ~ ~------ -~-------- ---- --------~ ~~~ ~~~~~ ~~~~~~ 600 1 1 500 'b~27--- 400-~- ---â‚¬ 400 ~ Ii 300 300 1 11 200 200 ---- 1 1 100 - ------- -- -- --- -1 - - -- 2 100 ---- -- i I 2 0 1 1 1 501 1001 1501 2001 2501 3001 3501 4001 1 501 1001 1501 2001 2501 3001 3501 4001 -2003 -2004 -2005 -2010 -2015 ~03.04 --0Â£05 - 05-06 - 10-11 - 15-16 14 DRAFT 1. Projected Balance of Loads and Resources (with all resources available) Figures 15 and 16 present the summer and winter peak-month loads and resources balance in table form for years 2006 through 2015, assuming all firm resources are available. Loads include the aggregated municipality load, Xcel Energy contract deliveries, transmission system losses and reserves (required to meet unanticipated demand or to counteract the sudden, unforeseen loss of a major resource). The need to maintain large dedicated reserves is moderated substantially by Platte River's participation in the Rocky Mountain Reserve Group, an association of neighboring generating entities that have agreed to cooperatively assist each other in the event that a generating unit goes down. This arrangement helps ensure that system-wide reserve requirements are met at all times. Currently available resources include Rawhide Unit 1, Platte River's share of Craig Units 1 and 2, the CRSP and LAP hydroelectric contracts with WAPA, and the gas turbine peaking units A, B, C and D at Rawhide. Deficits are made up first through purchases of WAPA Replacement Power (WRP) and then through open market purchases. Surpluses may be sold by contract or in the short-term market as availability and market demand permit. Figure 15 SUMMER PEAK MONTH FORECAST 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Loads City Loads 617 636 656 675 695 714 734 754 774 794 DSM (1) (2) (4) (7) (10) 03) (17) (19) (22) (25) (28) Xcel Energy 30 30 - - - Required Reserves 25 27 28 29 29 30 31 32 33 34 Losses 11 12 12 12 12 13 13 13 14 14 681 701 689 706 723 741 759 777 796 814 Resources Rawhide 274 274 278 278 278 278 278 278 278 278 Craig 154 154 154 154 154 154 154 154 154 154 CRSP 60 60 60 60 60 60 60 60 60 60 LAP 30 30 30 30 30 30 30 30 30 30 Peaking 260 260 260 260 260 260 260 260 260 260 778 778 782 782 782 782 782 782 782 782 Surplus (Deficit) 97 77 93 76 59 41 23 5 (14) (32) Reseve Margin (2) 24.3% 20.7% 18.3% 15.5% 12.8% 10.1% 7.5% 5.0% 2.5% 0.2% ADSM based on data provided by each city and Platte River estimates. (2) Reserve margin calculation excludes firm surplus sales and required reserves. As indicated in Figure 15, the reserve margin drops to a level very close to the 15% reliability limit in 2009. 15 DRAFT Figure 16 WINTER PEAK MONTH FORECAST 06-07 07-08 08-09 09-10 10-11 11-12 12-13 13-14 14-15 14-16 Loads City Loads 485 496 507 518 529 541 552 564 575 587 DSM (1) (2) (4) (5) (7) (10) (12) (14) 03 (19) (22) Xcel Energy 30 30 - - Reserves 27 27 28 29 30 31 32 33 34 35 Losses 9 9 9 9 10 10 10 10 10 11 549 558 539 549 559 570 580 590 600 611 Resources Rawhide 274 274 278 278 278 278 278 278 278 278 Craig 154 154 154 154 154 154 154 154 154 154 CRSP 85 85 85 85 85 85 85 85 85 85 LAP 31 31 31 31 31 31 31 31 31 31 Peaking 260 260 260 260 260 260 260 260 260 260 804 804 808 808 808 808 808 808 808 808 Surplus (Deficit) 255 246 269 259 249 238 228 218 208 197 Reseve Margin (2) 63.5% 60.4% 58.2% 55.4% 52.7% 50.0% 47.5% 45.0% 42.7% 40.3% ADSM based on data provided by each city and Platte River estimates. (2) Reserve margin calculation excludes firm surplus sales and required reserves. 2. Load/Resource Balance During Forced Outage of Largest Resource Due to the relatively large size of Platte River's largest resource, and due to declining reserves and tightening transmission constraints in the region, the loss of a generating unit could seriously impact the reliability of the Platte River system. Replacement power sources are limited, and at times replacement power is not available. Also, scheduling of transmission to deliver power from other generators to Platte River's system is often a challenge. The forced- outage rate for Platte River's thermal generating units has historically been about 3.5% per year. The extent of Platte River's exposure to reliability and market risk during such outage periods depends on the timing and duration of an outage. Platte River's resource planning philosophy includes carrying reserves or maintaining access to firm resource capacity that is sufficient to meet load obligations even if its largest generating unit (Rawhide Unit 1) is out of service. As indicated above, one of our reliability criteria is to add new resources if the resource deficit during an outage at Rawhide Unit 1, is forecast to exceed 65 MW. Deficits less than 65 MW may be met through market purchases or other resource solutions, such as the Forced Outage Assistance Agreement with Tri-State. Should a forced outage occur at Rawhide Unit 1, this agreement would be invoked first as a source of replacement power. After invoking this option, Platte River would use one or more of the following sources to meet loads: WAPA Replacement Power, wholesale market purchases or the combustion turbine units. Assuming the Forced Outage Assistance Agreement and WAPA Replacement Power purchases have both been fully utilized in the event of an outage of Rawhide Unit 1 (assuming all other 16 DRAFT resources are available), the deficits remaining to be covered by market purchases are shown for the 10-year forecasting horizon as the last line in Figure 17 (summer) and Figure 18 (winter). Figure 17 shows deficits in 2006 through 2009, with a 2009 deficit very close to the maximum level allowed in the current reserve policy criteria (56 MW vs. 65 MW). Figure 18 projects no market exposure during the winter season. Figure 17 SUMMER PEAK MONTH FORECAST - RAWHIDE OUT OF SERVICE 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Loads City Loads 617 636 656 675 695 714 734 754 774 794 DSM (1) (2) (4) (7) (10) (13) (17) (19) (22) (25) (28) Xcel Energy 0 0 - - Required Reserves 25 27 28 29 29 30 31 32 33 34 Losses 11 12 12 12 12 13 13 13 14 14 651 671 689 706 723 741 759 777 796 814 Resources Rawhide 0 0 0 0 0 0 0 0 0 0 Shaft Sharing 100 100 100 100 100 100 100 100 100 100 Craig 154 154 154 154 154 154 154 154 154 154 CRSP 60 60 60 60 60 60 60 60 60 60 LAP 30 30 30 30 30 30 30 30 30 30 Peaking 260 260 260 260 260 260 260 260 260 260 WRP 46 46 46 46 46 46 46 46 46 46 650 650 650 650 650 650 650 650 650 650 Surplus (Deficit) (1) (21) (39) (56) (73) (91) (109) (127) (146) (164) ADSM based on data provided by each city and Platte River estimates. Figure 18 WINTER PEAK MONTH FORECAST - RAWHIDE OUT OF SERVICE 06-07 07-08 08-09 09-10 10-11 11-12 12-13 13-14 14-15 14-16 Loads City Loads 485 496 507 518 529 541 552 564 575 587 DSM (I) (2) (4) (5) 8 (10) (12) (14) (13 (19) (22) Xcel Energy 30 30 - Reserves 27 21 22 23 24 25 26 27 28 29 Losses 9 9 9 9 10 10 10 10 10 11 549 553 533 543 554 564 574 585 595 605 Resources Rawhide 0 0 0 0 0 0 0 0 0 0 Shaft Sharing 100 100 100 100 100 100 100 100 100 100 Craig 154 154 154 154 154 154 154 154 154 154 CRSP 85 85 85 85 85 85 85 85 85 85 LAP 31 31 31 31 31 31 31 31 31 31 Peaking 260 260 260 260 260 260 260 260 260 260 WRI? 30 30 30 30 30 30 30 30 30 30 630 630 630 630 630 630 630 630 630 630 Surplus (Deficit) 81 77 97 87 76 66 56 45 35 25 m DSM based on data provided by each city and Platte River estimates. 17 DRAFT 3. Timing of New Resource Need All four of Platte River's resource reliability criteria are very close to the planning limits in 2009. With all resources available and operating, the reserve margin drops to 15.5% in 2009, within less than 1 % of the 15% criterion. With the largest resource (Rawhide Unit 1) off line, required market purchases are estimated at 56 MW, only 9 MW less than the 65 MW criterion. Loss of Load Probability and Loss of Load Expectation are also very close to the limits set for these criteria. Note that there are several uncertainties that could quickly tighten the load/resource balance within the next few years. On the load side, these include the potential for large new facilities locating within the municipalities, uncertainty in weather, expansion of use of air conditioning, uncertainty regarding DSM program impacts, potential annexations by the municipalities and changes in population. On the resource side, the supply of capacity from regional markets has tightened substantially due to the drought, growth across the region exceeding resource additions, and increasing transmission constraints. Given these factors, it is recommended that a new capacity resource be on line before the summer of 2009. VI. Resource Supply Alternatives 1. Context for Resource Scenario Evaluation It is important to periodically study a variety of future resource alternatives, since there is a long lead time associated with bringing new resources on line. Moreover, opportunities for joint development of resources may present themselves at any time. Analyses of options are regularly reviewed and revised by Platte River's resource planning team, and new studies are initiated to take into account ongoing developments in load forecasts, technology, regulation, environmental conditions, competitive factors, new resources and markets, pricing, and political conditions. As indicated earlier, Platte River needs new resources that meet the municipalities requirements during the peak summer season. The focus here is toward firm resources that are available during this time frame. Non-dispatchable renewable energy options, such as wind and solar, provide little or no reliable capacity at peak times and are not included as an option to meet peak capacity or reserve needs. However, renewable resources can provide energy supply, as well as environmental and other benefits. Renewable energy planning is discussed later, in Section VII of this report. 2. Firm Resource Options In the 2002 IRP, Platte River recommended participation with Tri-State (and other entities) in the study of a jointly owned coal resource to meet future resource needs. This unit planned for Southeast Colorado was referred to as the Colorado Generation Project. Tri-State recently announced the delay of this project until at least 2017 and has decided to pursue new 18 DRAFT generation at a coal-fired facility near Holcomb, Kansas. Tri-State has informed Platte River that participation in the Holcomb facility is limited to purchase power contracts only (no joint ownership is being offered) and has refunded participants for their investment in the study of the Colorado Generation Project. Given the significant transmission investment required to reach the Holcomb facility, along with the fact that no long-term supply resource is being offered, Platte River has no serious interest in pursuing a purchase agreement from the Holcomb facility at this time. Other joint projects may be available for consideration in the future, but at this time there are no viable opportunities for Platte River to participate in regional generation projects that could meet our resource need by 2009. After review of all options available to meet our needs, three key alternatives have been identified, as summarized below. 1. Coal-firedgeneration at the Rawhide site (Rawhide Unit 2) - This option involves installation of a 100 MW coal-fired unit, utilizing pulverized coal or fluidized bed coal combustion technology. The Rawhide site was originally designed and constructed with additional coal-fired generation in mind. Physical layout of the site and the coal handling facilities are situated in such a way that a second coal unit could be constructed without substantially modifying existing structures. The Rawhide site also offers a 4,300 acre area owned by Platte River, a trained workforce, water availability, coal handling facilities, rail access, transmission access, and proximity to our municipal load centers. 2. Simple-cycle gas-fired generation - The lowest capital cost alternative to increase generating capability would be to install additional simple-cycle combustion turbine (CT) units at the Rawhide site. Simple-cycle units are suited to intermittent operations, characteristic of a peaking resource. They can be quickly started during periods of high demand and easily shut down for off-peak periods and for maintenance. The following peaking unit options were considered: Installed kW Cost Capacitv Rating Fuel Efficiency GE7EA Medium 65 MW Lowest GELMS100 Highest 75 MW Highest GE7FA Lowest 138 MW Medium 3. Purchase of capacity - Market based capacity purchases could be used to meet future resource needs instead of building additional generation. Use of gas-fired combined cycle technology at the Rawhide facility was also considered briefly. This option involves recovering heat from two (or more) of the peaking units to make steam that feeds a steam turbine generator. This option is clearly not cost effective due to the need to operate two peaking units at high gas costs in order to obtain additional capacity from the steam unit. This option would also significantly increase maintenance costs for the peaking units and would limit operational flexibility of the units. In the following sections, the three options described above are reviewed from several perspectives, beginning with environmental considerations. 19 DRAFT 3. Environmental Considerations Platte River staff assesses and evaluates the environmental effects of every proposed action that is brought forward for consideration by management or the Board. This practice is an integral part of the decision-making process. The selection and specification of a generating resource is a particularly important decision, not only because of the substantial effects on the reliability of electric service and impact on rates, but also because of the short and long-term environmental implications inherent in each resource acquisition decision. Recognizing this, the Platte River Board has adopted an Environmental Policy and a set of Environmental Principles to guide management and staff in planning and day-to-day operations and to clearly communicate a set of priorities to everyone in the organization. The policy and principles are summarized in Figure 19. In practice, the "environmentally responsible" aspect of Platte River's mission is carried out through the operation of its Environmental Management System (EMS), described graphically in Figure 20. The EMS enables staff and management to coordinate efforts to continuously evaluate environmental performance. This focus on environmental performance ensures compliance with complex and changing regulations through ongoing internal compliance assessment, document/data control, training, program implementation, management review, and continuous improvement. For example, Platte River has implemented ongoing environmental performance at Rawhide. Although Rawhide has been equipped since startup with controls that maintain emissions levels well below the plant's operating permit conditions (which themselves are among the lowest in the industry), Platte River has implemented options for improvements that reduce emissions even further. Early in the decade, changes were made to reduce SO2 emission by about 10% and in 2005 a separated over-fire air burner control system was installed that reduces NOx emissions by about 40%. 20 DRAFT .. Figure 19 PLATTE RIVER POWER AUTHORITY Environmental Policy and Principles Platte River provides reliable, low-cost electricity in an environmentally responsible manner to its owner communities of Estes Park, Fort Collins, Longmont and Loveland. Depending on water storage conditions, over one-quarter of the municipalities' electrical energy requirements are served from renewable resources including hydropower and wind. Platte River's other energy resources are fueled with coal and natural gas. Platte River uses state-of-the-art air quality control systems at its power generation stations and meets or exceeds all applicable environmental laws and regulations. As new legislation and regulations are proposed, Platte River participates in public processes and supports additional control requirements where costs are commensurate with measurable environmental benefits. In addition, as technology improves and opportunities arise, Platte River will be proactive in evaluating and implementing improvements in its power operations that balance environmental and other socio-economic concerns. Platte River Power Authority... â€¢ considers environmental factors an integral part of all planning, design, construction, and operating decisions. â€¢ reinforces environmental compliance through program reviews, training, and by communicating environmental values throughout the organization. â€¢ encourages public participation in planning for the location of major facilities as a means of avoiding and resolving conflicts and to achieve a balance between the need for an economic electric supply and environmental quality. â€¢ conserves natural resources such as water, soils, grasslands, and wetland areas through efficient use and careful planning. Where needed, Platte River restores land disturbed by its operations. â€¢ encourages employees to bring environmental issues forward to assure Platte River's compliance with applicable laws, rules, regulations, and permits. â€¢ strives to reduce environmental health and safety risks to its employees and the communities in which it operates by (i) maintaining safe and healthful working conditions, (ii) responsible design and operation of its facilities, and (iii) being prepared for emergencies. â€¢ works with its customers to support cost-effective programs to conserve energy. â€¢ coordinates its generation and transmission planning with neighboring utilities to minimize over- building or under-utilization. â€¢ considers environmentally progressive technologies such as wind and solar power in addition to other renewable technologies to meet its future generation needs. 21 DRAFT Figure 20 Management Review and Objectives Â« Internal Compliance Cl Training Assessment Air - Electric Waste Operations Management Water - Environmental ESA Management System Rawhide Compliance SPCC - Environmental Facilities Multimedia Policy and - ~ - Management Assessment Principles - Environmental Regulatory Goals Review Mani~~ent f _ ~Environmental Mgmt - General Program Commitment Compliance Green Organization Database Management Program Implementation System Annual Workplan - ~ - Toxic Materials / Hazardous / Continuous Improvement Permit Waste Geographic Information System Management Document Control - Meteorological Data Capital Project Rawhide - Budgets and - Emissions Operating Improvements Instructions and - Guidelines Project Environ. - Planning, Monitoring and Mitigation Specific to planning for the next resources, an assessment of various generation technologies and combinations of these technologies was conducted to determine the best fit for Platte River's near term generation needs. Each potential new resource was evaluated for environmental impacts (a 100 MW coal-fired unit using pulverized coal or fluidized bed, a 65 MW GE7EA, a 138 MW GE7FA and a 75 MW GELMS gas-fired unit). The combined impact of a coal unit and gas-fired unit was also considered to evaluate long term planning issues. The environmental analysis was primarily focused on air quality impacts. Specific modeling of criteria pollutant emissions (SO2, NOx, CO, and particulate matter) and a general analysis of other emission effects (CO2, mercury, etc.) were conducted. It was concluded from these assessments that both the coal and gas-fired units and a combination of the two were permittable. However, it was determined that the gas-fired unit alone would have the least environmental impact and was the best overall choice from an environmental perspective. A comparison of environmental impacts for the generation types (at equivalent capacity factor) is provided in Figures 21 and 22. For planning purposes, it is assumed that a mandatory cost specifically associated with the emission of carbon will occur by 2012, beginning at a cost of approximately $9.00 per ton (2012) and increasing over time. 22 DRAFT Figure 21 Coal vs. Gas Emissions ///, i *. 4--4.- ... ...--.. - 0.08 lbs/MMBtu 0.054 ijlf"A~~ / 1 Gas ' 0.04 Y / I Coal 003 r 4 1 L" 1 0.02Â©(.f I Im, 1 ~ ....:..~---*-9- 0.019/ ~1'U -r ,9 3 Coal O.00-Lut_, 0 NOx SO2 --*...--1 CO PM Figure 22 Coal vs. Gas - Other Impacts 100*T 90% 4-- -1. i. - I- lf- - 60%~ ~-k ~---- Relative 50%-~1 lili- ' impacts 0Â°kil k *4 i I Coal - --/.Fi.L 10% -1/ L --- fÂ¥ O% L_... 4 Coal CO2 -T--4 X Gas Hg Ash -7- H2O 23 DRAFT 4. Matching of Resource Type with Municipalities' Needs For the next several years, considering the needs of the member municipalities, Platte River's load and resource analysis shows that a new resource would primarily be called upon during peak-load conditions. For example, for the 10-year period 2009 through 2018, about 95% of the municipalities' energy needs can be met with existing baseload resources and only 5% is needed from existing peaking units, purchased power and new resources (primarily at or near summer peak periods). Given the size of any conceivable new coal plant, the owner municipalities would consume only a small portion of the output for many years. Surplus generation from the base-load unit could be sold into the wholesale market, but this approach introduces significant risk, particularly given the difficulty in obtaining a long-term sales agreement with other entities in the region. Purchase of peaking capacity from the market may also provide for the municipalities' needs. However, given the limited power supply available in the market at times of peak (vs. regional loads), there appear to be no opportunities for acquiring purchased capacity for more than one year at a time. This would lead to significant reliability risk in the future. Clearly, a gas-fired peaking unit is more suited to meet the needs identified in the short-term. In the longer term, another resource will eventually be needed. At this time, it is assumed that both short and longer term resources would be gas-fired. However, this may be reconsidered in the future as loads, market conditions and other variables change, or if new joint project options become available. 5. Financial Considerations The options described above were also compared from a financial perspective. A summary of key financial assumptions for new generation options is provided in Figure 23. Figure 23 Gas Coal GE7EA GE7FA LMS100 Rawhide Net Capacity (MW) 65 138 75 100 Heat Rate (MMBtu) 13,470 10,434 8,700 10,030 Installed Cost (Millions) $ 31.8 $ 57.4 $ 52.7 $ 268.0 Cost per kW $ 490 $ 416 $ 703 $ 2,680 Gas units generally have a low capital cost and high operating cost (due to high fuel cost for natural gas), while coal units have high capital costs and low operating costs. One of the key drawbacks for the new Rawhide coal unit is the very high capital cost. This is primarily due to the small size considered (100 MW). The GE7FA unit has the lowest installed cost per unit of capacity and a lower heat rate (higher efficiency) than the GE7EA (existing units at Rawhide). 24 DRAFT Total costs for options considered are summarized in Figure 24 for the period 2009 through 2018. These costs represent the operating cost of existing peaking units, purchased power and new resource additions (capital plus operating). For the Rawhide Unit 2 coal option, the costs are based on a 75% capacity factor and surplus sales revenues are netted against the total cost. Note that two resources are included in this long term comparison, though only one resource is needed for a decision affecting the 2009 time frame. Bringing on the GE7FA unit first leads to the lowest total resource cost. This approach also provides the lowest rate impact to the member municipalities. A summary of advantages and disadvantages of each potential generation resource from a rate risk perspective is provided in Figure 25. Figure 24 Total Resource Costs (2009-2018) (Net of Sales Revenue) $400 $350 $300 . 1 $250 1 1 $200 - $150 $100 $50 -- - 44*1 $- GE7FA2009 / LMS100.2016 LMS100.2009/GE7FA2013 RH2.2012 / LMS100.2014 I Fuel O Carbon 00&M I Debt Service I Purchase Power Figure 25 Peaking Resource Coal Resource â€¢ Advantages â€¢ Advantages â€¢ Matches needs â€¢ Lower fuel cost â€¢ Lower capital cost â€¢ Potential higher utilization â€¢ Low environmental impact â€¢ Surplus sales potential â€¢ Disadvantages â€¢ Disadvantages â€¢ Higher per unit fuel cost â€¢ Does not match need â€¢ Limited utilization â€¢ Higher capital cost â€¢ Higher environmental impact Lower Higher Rate Risk Rate Risk 25 DRAFT Millions I . 6. Other Considerations The reliability of the gas and coal options is comparable, but the reliability of the market purchase option is much lower, as described above. From an operational perspective, it is clear that the GE7FA has several advantages over the LMS100 and the GE7EA unit. All of the gas- fired units match the need for peak capacity and outage support. However, the GE7FA has a higher operating efficiency than the GE7EA unit and has the lowest capital cost per unit of capacity of all gas turbine options considered. In addition, it is a well-proven technology, while the LMS100 unit is an unproven technology at this time. Finally, the GE7FA unit provides more capacity than the other options, which provides additional dispatching flexibility and extends the time frame for considering the next new resource. Therefore, the GE7FA unit is the best option from an operating and planning perspective. VII. Renewable Energy Since 1998, Platte River has provided renewable energy from the Medicine Bow Wind Project. The energy generated at the Medicine Bow site supplements renewable hydropower purchased from Western Area Power Administration (WAPA). As the needs of the owner municipalities have increased, new options for meeting renewable requirements have been identified. For 2005, the level of non-hydro renewable supply represented about 35,000 MWh, or about 1.5% of total energy sales to the owner municipalities. Though all owner municipalities purchase renewable energy, about 90% was supplied to Fort Collins during 2005. In March of 2006, Platte River's Board approved a Renewable Energy Supply Policy. This policy guides Platte River as it plans for and acquires new renewable sources to meet the needs of its owner municipalities. The policy provides guidance regarding the level of renewable sources to be obtained, the type of sources considered acceptable to meet municipal renewable requirements, the anticipated impacts of renewable sources on future resource planning and the approach to be used for pricing renewable sources for sale to the member municipalities. A brief summary of each of these issues is provided below: Level of renewable resources - This is driven by three factors: (1) Fort Collins' Energy Supply Policy, which includes renewable energy goals, (2) Colorado Revised Stature 40-2- 124, which implements a renewable portfolio standard, and (3) voluntary participation in renewable energy programs by customers, particularly large commercial entities. By 2018, municipal requirements for renewable energy from sources other than WAPA hydropower are expected to exceed 360,000 MWh/yr, about 10% of total predicted energy supply to the municipalities. Types of resources - Renewable energy resources considered qualified include solar (photovoltaic or thermal electric systems), wind turbines, geothermal systems, biomass systems and small hydroelectric generation systems. Renewable Energy Certificates (RECs) from any of these sources may also be combined with Platte River's energy resources to provide renewable energy to the municipalities. Impact on resource planning - Due to the intermittent nature of wind, particularly at the time of system peak, Platte River's wind generation is assigned no firm peak capacity 26 DRAFT . value. Wind resources do not reduce the need for firm resources to meet system peak demand. Figure 26 shows the operating history of Platte River's wind project at Medicine Bow during the system peak hour. About 80% of the time, the generation level at time of system peak has been less than 10% of rated output and about one-third of the time, generation was very near zero output. Transmission constraints also limit the delivery of wind generation. Solar energy is relatively expensive, costing $6,000 to $9,000 per kW installed or about $0.20/kWh to $0.35/kWh over the life of the unit (vs. about $0.04/kWh for wind). Solar availability is also relatively low at time of system peak (typically 5 pm to 6 pm on summer days) and the output is intermittent due to cloud cover variation. Small hydro has limited potential due to constraints and regulations on dams in the region and is further constrained by limited transmission. Geothermal sources are limited in this region and biomass production has significant risks associated with fuel supply. For purposes of this resource plan, no renewable energy sources are anticipated to provide firm capacity at the time of system peak. Pricing - A new tariff (Tariff D for pricing renewable energy to the municipalities was initiated in July 2006. This tariff provides a single price for all renewable resources combined, based on cost of service. More details associated with renewable energy planning are provided in the Renewable Energy Supply Policy, a copy of which is available upon request. Figure 26 100% 90% - 80% - 70% 60% - 50% - 45.6% 40% - 30% - 21.6% 20% 10% - 7.3% 5.2% 7.1% 9.4% 0% ~ 1.3% 0.2% A 0.0% I .9 1998 1999 2000 2001 2002 2003 2004 2005 2006 27 DRAFT VIII. Demand-Side Management 1. DSM Programs Operated by Platte River Current Programs Platte River has a five-year history of running incentive-based DSM programs and has provided energy services (energy audits, project financing, power quality, etc.) for nearly 15 years. In 2001 a study was completed by staff, working with Nexant (a regional DSM consultant), to identify programs that could deliver peak demand reduction and associated energy savings. Based on this study, Platte River set a five-year DSM goal of 6 MW, with associated energy savings projected to be 18,000 MWh per year (by 2006). The five-year budget estimated to achieve these savings was $3.1 million. Two programs were selected from several studied based on their capability to meet demand and energy goals while providing service to each of the three customer classes - residential, commercial, and industrial. These two programs - the Cooling Rebate Program (CRP) and Electric Efficiency Program (EEP) - were initiated in 2002. The CRP provides rebates for more efficient residential and commercial air conditioning equipment. The EEP provides incentives for a variety of energy-efficiency technologies that reduce commercial and industrial loads. Figures 27,28, and 29 indicate the performance of these programs relative to the goal and budget for the first four complete years. Figure 27 Figure 28 M CRP - EEP Goal ~ Cm CRP -EEP Goal 7.0 - - + --- 20,000 - ~ 18,000 6.0 A 16,000 t 5.0 , 92 14,000 ---- t .. 2 12,000 4.0 - g 10,000 rl 3.0 -~ ' ; 8,000 . 19 1 E 6,000 ~-I m mÂ«M- U , ~ 4,000 1.0 - 1 2,000 ----- -1 2002 2003 2004 2005 2006 2007 2002 2003 2004 2005 2006 2007 28 DRAFT Megawatts 1/1 Figure 29 9 CRP - EEP Budget i $3,500,000 $3,000,000 $2,500,000 $2,000,000 $1,500,000 ~i,ooomo --~ ~ $500,000 $0 1-1 61 2002 2003 2004 2005 2006 2007 Future DSM Potential During early 2006, an updated assessment of additional DSM potential was completed by Nexant to provide estimates of potential demand reduction, energy savings, and program costs for a range of DSM program options. The assessment indicated a maximum peak reduction of about 35 MW can be obtained by 2011, with energy savings of up to 76,000 MWh per year. Approximately 20 MW (with very little energy savings) could come from summer peak clipping programs (air conditioning control) and the remaining 15 MW (with about 76,000 MWh/yr of energy savings) could be available from a combination of residential and commercial/ industrial efficiency measures (lighting, air conditioning, motors, appliances, etc.). A detailed financial analysis of DSM program costs and benefits was also performed, from Platte River's perspective (wholesale supplier). DSM costs include marketing and promotion, administration, incentives, measurement and verification and lost revenues (due to reduced municipal sales). Direct financial benefits of DSM include deferred capital, reduced fuel usage, lower variable operation and maintenance, reduced losses and increased surplus sales. This financial analysis indicated that energy efficiency programs (those that save energy as well as reduce peak) are more cost effective than peak clipping programs (those that only reduce summer system peak and save little or no energy). Efficiency programs also provide additional value, including environmental benefits, customer service enhancement, local economic development and positive public relations. Given that they are more cost effective and provide environmental and other benefits, energy efficiency programs are preferred going forward. Nexant developed estimates for low, medium and high levels of energy efficiency program expenditures. These are summarized in Figure 30. Cost of conserved energy (at the generator) is estimated at $15/MWh (low case), $18/MWh (mid case) and $24/MWh (high case). To put these costs in perspective, Platte River's average cost to generate energy from existing and proposed resources (fuel plus variable O&M) for the period 2007 to 2018 is about $18/MWh with no carbon costs included. It is assumed that some form of carbon charge will occur in the future, perhaps as early as 2012. 29 DRAFT Figure 30 $24/MWh - 90,000 14 - 49 - 80,000 12 - . ' * - 70,000 * - 60,000 10 - 50,000 % 8- $18/MW~/ E 1 - 40,000 6 -- 30,000 $15/ MWh/' 4- 1/.- - 20,000 2 - 4 10,000 Low Med High â€ž,Peak Savings (MW) -0- Energy Savings (MWh/yr) Proposed Future DSM Plan Over the next five years - 2007 through 2011 - Platte River plans to continue its current DSM programs (with some modifications) and add to them. The new combined goal is to achieve additional demand savings of 6 MW and energy savings of 32,000 MWh/yr by the end of 2011. Compared to the previous five years, these goals provide a similar summer peak demand reduction, but nearly 80% more energy savings. This is close to the mid-level case evaluated by Nexant. The total five-year cost of running the programs required to achieve these savings is estimated as $5.8 million. It is proposed that funding be increased incrementally, by about $180,000/yr (from the current level of $600,000/yr) to about $1.5 million/yr in 2011. The actual level of expenditure by Platte River will depend on market acceptance of DSM programs, DSM expenditures made by the member municipalities, program performance over time and future annual budget review. Future DSM programs will be prioritized based on their cost per unit of energy saved, with the lowest cost programs implemented first. Higher-cost programs may be increased in priority if they produce savings at times that higher-cost resources typically operate. Program selection will also be impacted by the need to offer at least some programs to each customer class (residential, commercial and industrial) in each municipality. Other (non- financial) benefits provided by programs (emission reductions, etc.) will also be considered. The municipal rate impact of the proposed level of DSM is estimated as about 0.2% (by 2011). Proposed efficiency program expenditures are about 1 % of Platte River's total expenses anticipated between 2007 and 2011. 30 DRAFT In addition to these formal DSM programs, Platte River will continue to provide energy and customer services, many of which also help customers reduce energy consumption. These services include conducting energy audits for commercial and industrial customers, providing educational materials aimed at energy-efficiency, and assisting customer in evaluating distributed generation projects. 2. DSM Programs Operated by the Member Utilities Each municipal utility also operates its own conservation and efficiency programs. A summary of current activities and future plans for the municipalities is provided below. Town of Estes Park For the past 13 years, Estes Park has offered a popular and effective electric heat thermal storage program for residential and small-commercial customers, which shifts winter peak load to off- peak hours using thermal-storage electric heaters. Cumulative peak reduction (winter season) through the end of 2005 is a little over 3 MW. The Estes Park Utility Department provides energy-auditing services for commercial and residential customers as well as Mower door testing. The utility also emphasizes the specification of low-loss distribution transformers. Future plans are to continue with all of these programs and to work closely with Platte River DSM staff to identify and facilitate implementation of commercial efficiency and load shifting projects. Fort Collins Utilities Fort Collins Utilities efforts in DSM come from both a historical commitment to help customers manage their electricity use and from the Electric Energy Supply Policy (adopted by City Council in March 2003). The primary goals of the Energy Policy are to maintain high system reliability, maintain competitive electric rates and reduce the environmental impact of electricity generation. One percent of electric rate revenues are directed towards energy efficiency programs and services. The Energy Policy adopted the following specific objective for DSM: â€¢ Develop and promote DSM programs and services â€¢ Reduce per capita electric consumption 10% by the year 2012; and â€¢ Reduce per capita peak day electric demand 15% by the year 2012. The following tables summarize the residential and commercial energy efficiency programs and services offered by Fort Collins Utilities in 2005. Note that some of the programs described herein are the same programs as have been described in Platte River's DSM section. Programs and service are of two general types, those that provide verifiable electricity and demand savings (DSM programs) and those that promote energy efficiency and conservation awareness and education (Community Energy Programs). Several of the programs and services have aspects of both types, resulting in direct energy savings as well as meeting other customer service objectives. 31 DRAFT 2005 Residential Energy Efficiency Programs and Services Program Description Refrigerator and Freezer Recycling Rebate, in-home pickup and comprehensive recycling of Program unwanted refrigerators and freezers Residential Lighting Program Discounted compact fluorescent light bulbs through local retailers, halogen torchiere turn-in program Clothes Washer Rebate Program Rebate for purchase of ENERGY STAR clothes washer Cooling Rebate Program Rebate for high efficiency air conditioners ZILCH Zero interest loans for energy saving home improvements REACH Free home weatherization (based on income eligibility) HotShot Water Heater Control Radio frequency control of electric water heaters for coincident peak demand savings Home Performance with ENERGY Contractor training and support for whole-house approach to STAR improve energy performance of existing homes Energy Score Support for home energy ratings Education and Awareness Energy efficiency education and awareness activities include The Power to Save campaign, What to Look for in a New Home, the Utilities website, Environmental Program Series and various community events. Note: The Cooling Rebate Program is operated by Platte River with support from Fort Collins Utilities. 2005 Commercial Energy Efficiency Programs and Services Program Description Electric Efficiency Program Incentives for projects that reduce summer peak demand or annual electricity consumption Cooling Rebate Program Rebates for high efficiency air conditioners Integrated Design Assistance Funding and expertise for integrated design of energy efficient Program new buildings HotShot for C&1 customers Radio signal for customer control of coincident peak demand Technical Assistance and Energy Free energy assessments to help customers implement Assessments energy efficency projects Electri-Connect Provides online access to interval electric data for large commercial and industrial customers Keep Current Electronic newsletter, web information resource and "Ask an Expert" tool Education and Awareness Energy efficiency education and awareness activities include The Power to Save campaign, the Utilities website, the Business Environmental Program Series and commercial accounts luncheons. Note: The Cooling Rebate Program and Electric Efficiency Program are operated by Platte River with support from Fort Collins Utilities. The cost of conserved energy is used as a metric for cost-effectiveness of energy efficiency programs. The following tables summarize 2005 DSM program results and the annual energy and demand savings for 2002 through 2005. Funding for the Cooling Rebate Program and the majority of funding for the Electric Efficiency Program comes from Platte River. Program 32 DRAFT effects are for Fort Collins Utilities customers. The results for these two programs are included in- and are not in addition to- Platte River's reported DSM effects. 2005 Energy Efficiency Program Results | Program Activity Annual Annual Program Cost of Energy Demand Cost Conserved Savings Savings Energy (MWh) fkW) ($/kWh) Clothes Washer Rebate Program 901 rebates 101 12 $22,525 $0.025 Cooling Rebate Program 513 rebates 202 294 $154,975 $0.075 Refrigerator and Freezer Recycling 626 units 564 64 $105,598 $0.028 Program Residential Lighting Program 70,498 bulbs 1,738 0 $144,240 $0.012 Residential subtotal 2,604 370 $427,338 $0.021 Electric Efficiency Program 31 projects 6,122 658 $285,050 $0.005 Commercial subtotal 6,122 658 $285,050 $0.005 Total 8,726 1,028 $712,387 $0.010 The Hot Shot demand response program controls residential electric hot water heaters and provides a signal for commercial customers to manage their coincident peak electric demand charges. In 2005 the combined residential and commercial systems controlled approximately 1.7 megawatts of demand on a monthly basis. DSM Program Energy Savings 2002 - 2005 (MWh) Program 2002 2003 2004 2005 Total Program Savings Clothes Washer Rebate Program NA 149 223 101 473 Cooling Rebate Program 190 190 246 202 828 Refrigerator and Freezer Recycling Program NA NA 819 564 1,383 Residential Lighting Program NA NA 140 1,738 1,878 Electric Efficiency Program 242 1,492 2,237 6,122 10,092 Integrated Design Assistance Program 748 111 617 45 1,521 Total Annual Savings 1,180 1,941 4,282 8,771 16,175 DSM Program Demand Savings 2002 - 2005 isummer kW) Program 2002 2003 2004 2005 Total Program Savings Clothes Washer Rebate Program NA 17 25 12 54 Cooling Rebate Program 269 274 358 294 1,195 Refrigerator and Freezer Recycling Program NA NA 94 64 158 Residential Lighting Program NA NA 0 0 0 Electric Efficiency Program 40 224 423 658 1,346 Integrated Design Assistance Program 249 35 214 11 509 Total Annual Savings 558 550 1,115 1,039 3,262 33 DRAFT . DSM programs play a significant role in reducing Fort Collins energy consumption and peak demand power needs. However, other factors play markedly larger roles in affecting the patterns of energy use from year to year. Weather conditions have the largest impact on peak power demands, as demonstrated in 2005 with several record setting hot days in a row. Economic factors also play a large role, as demonstrated by general growth in the Front Range and shifting regional economic patterns. For 2005, DSM program energy savings represented 0.6% of Fort Collins total energy use, accounting for nearly one half of the year-to-year reduction in per capita energy use. Again for 2005, DSM program demand savings represented 0.3% of the annual peak demand, which still increased by 2.5%. Reaching the objectives of the Energy Policy requires a decrease in per capita energy use of nearly 1% per year and a decrease in per capita peak demand of over 2.0% per year. In order to reach the targets of the Energy Policy, on-going and new DSM programs and services will need to: â€¢ reach many more customers through higher participation rates, and â€¢ focus on reducing summer peak demand (targeted specifically within each rate class and customer type). Funding levels will remain at one percent of electric rate revenue, or approximately $700,000 per year. Increased funding and new program offerings from Platte River will be integrated into Fort Collins Utilities existing portfolio of efficiency and demand response programs. The following new or updated DSM programs are planned for 2006 and beyond. â€¢ Integrated Design Assistance Program: This program will be revised with a new code baseline, a whole building option and a prescriptive component based option. Both design and performance incentives will be available. â€¢ Residential Cooling: This new program will target summer residential cooling demand reductions through a comprehensive set of measures. The program will target load reductions in new and existing homes, promotion of alternatives to refrigerant based air conditioning, improved installation practices of home cooling systems and demand response control of air conditioning systems (see next bullet). â€¢ Hot Shot Demand Response: The existing Hot Shot system was upgraded in 2006 with a new personal computer based front end. A maintenance program was initiated to increase the number of working residential control units. The new system will enable a robust program for commercial customers on the GS-50 and GS-750 rate structures and the pilot of a residential air conditioning control program. It is estimated that programs operated by Fort Collins Utilities will lead to energy savings of about 76,000 MWh and peak demand savings of about 7 MW by 2011. These are in addition to savings associated with Platte River programs provided to Fort Collins' customers. i 34 DRAFT . Longmont Power & Communications Longmont Power and Communications (LPC) has been providing energy services and DSM programs for its customers for nearly 10 years. LPC provides resources to help its customers make wise energy-efficiency choices. Free energy audit services are provided to residential and commercial customers. Longmont maintains a web site with a comprehensive summary of energy efficiency programs, guidelines, resources, tools, and links to other government and non-profit agency web sites on energy conservation. Longmont also provides to its residential and commerical customers free publications, guidelines and resource information on energy efficiency. In addition to providing information, LPC provides direct financial support of customers' energy-efficiency upgrades. For several years Longmont has provided incentives for commercial lighting efficiency projects through the Commercial Lighting Incentive Program. This program has ended in favor of providing support through the Electric Efficiency Program and LightenUP, offered in partnership with Platte River. Longmont supports these programs by assisting with program promotion and by providing $40,000 per year in additional incentive money for its customers, boosting Platte River's incentives by about 40 percent. On the residential side, the Light Lease Program, which leased compact fluorescent lamps to residential customers, has ended. However, Longmont currently has a budget of $25,000, which it is using to offer incentives for Energy-Star-rated appliances such as clothes washers, dishwashers, and compact fluorescent lamps. A refrigerator-recycling program is also being considered, contingent upon funding approval by the City Council. A $5,000 budget has also been approved to support a new program offered in partnership with Boulder County that will provide subsidized professional residential audit services. Longmont also plans to continue its voltage reduction program, which reduces voltage within the acceptable range during times of peak electrical consumption, reducing peak power and energy use. Loveland Water and Power The Loveland Department of Water and Power (LWP) has made DSM, especially regarding peak demand management, a top priority for its community as it continues to grow. The primary strategy for DSM will be a direct load control program directed at air conditioning units. For this program, Loveland has budgeted $1 million and are expecting 3.9 MW of peak load control. LWP is still in the planning stages of this program but anticipates activation of the program for the summer of 2007, with a three-year ramp up period. This program will initially focus on residential load, but will eventually be expanded for management of commercial load. LWP will continue to operate its Thrifty Light Project, not only offering peak demand savings for the winter but also energy efficiency throughout the year. Through the Thrifty Light Project, residential customers purchase compact fluorescent lamps from the city to replace incandescent lamps in thousands of residential lampposts for which the city provides energy and also for 35 DRAFT . indoor use. This shaves the winter peak demand by an additional 8 kW for each year's new sales, saves off-peak energy and enables residents to avoid the need to change lamps as often. LWP has also begun providing incentives in addition to those provided through Platte River's Electric Efficiency Program. Loveland will evaluate the impact of this additional incentive level in 2007 to determine continued co-funding support in 2008. 3. Combined DSM Projections The combined impact of the municipalities' and Platte River's DSM programs are expected to provide system peak savings (summer season) of about 17 MW and energy savings of about 108,000 MWh per year by 2011. 36 DRAFT D IX. Recommended Actions Recommendations of this IRP are summarized below. 1. Install a GE7FA gas peaking unit by 2009 As described earlier in this plan, the GEZFA unit has minimal environmental impacts, meets the peak growth needs of the municipalities, is cost effective and provides low operational, environmental and financial risk. An installed date of 2009 is recommended given that all four of Platte River's resource reliability criteria are very close to the planning limits in 2009 and there are several uncertainties that could quickly tighten the load/resource balance within the next few years. These include the potential for large new facilities locating within the municipalities, uncertainty in weather, expansion air conditioning use, uncertainty regarding DSM program impacts, potential annexations by the municipalities, changes in population and tightening of capacity available from regional markets at time of system peak. 2. Execute the proposed DSM Implementation Plan Staff recommends increasing the current level of DSM expenditures that was approved by the Board in 2001. The current budget is $600,000/yr for program costs (or about $750,000/yr including staff salaries and benefits). We recommend increasing this total to the "medium" case developed by Nexant, or $1,500,000/yr, incrementally between now and 2011. This would represent an annual increase of about $180,000 each year (2007 to 2011), with a total five-year expenditure of about $5.8 million. By 2011, annual energy savings would amount to about 35,000 MWh/yr, or about 1 % of total annual energy generation and about 10% of the municipalities' energy growth (through 2011). Municipality DSM programs will also be expanded. The combined impact of the municipalities' and Platte River's DSM programs are expected to provide system peak savings (summer season) of about 17 MW and energy savings of about 108,000 MWh per year by 2011. 3. Continue implementation of the Renewable Energy Supply Policy The policy outlines an estimated need of approximately 380,000 MWh/yr of renewable energy by 2018, or about 10% of the total energy supplied to the municipalities at that time. Actual amounts acquired will depend on implementation of standards dictated by the four municipalities, as well as customer voluntary interest. Staff will continue to seek the most cost effective options from the set of qualified resources identified in the policy. At this time, Renewable Energy Certificates from wind projects appear to provide the most cost effective source, but all qualified resources will be evaluated over time as technologies evolve and markets for renewable energy expand. A copy of Platte River's Renewable Energy Supply Policy is available upon request. 4. Monitor development of regional generation and transmission resources Xcel Energy, Tri-State, Colorado Springs or other utilities in the region may consider development of joint projects in the future. Platte River will continue to maintain relationships with these entities to ensure participation options in any new resource that may be beneficial to us. New technologies such as integrated gasification combined cycle (IGCC) may be developed, which offer environmental and other benefits. Equally vital to the reliable supply of electricity 37 DRAFT , is coordinated transmission planning. Platte River works with the Front Range Planning Group and the Colorado Coordinated Planning Group to review issues associated with transmission constraints and the need for new projects in the region. Platte River will continue to monitor future generation and transmission studies as they develop. The outcomes of such integrated needs assessments are critical to our resource planning efforts not only because favorable opportunities for joint participation in resource development projects may arise, but also because the actions taken by other entities may directly affect the availability and pricing of electric energy, capacity, fuel, transmission, and ancillary services, all of which have implications for the economics of future Platte River projects. 5. Monitor load forecasts and evaluate contingencies There was a dramatic difference between the pattern of peak-load growth observed during the early 1990's and the growth pattern of more recent years. Another shift in the pattern may well be observed over the next few years. In addition, the impact of decisions by large commercial and industrial customers to locate in this area could dramatically change resource needs. The need for new resources and the timing of planning, permitting, and public information processes is strongly dependent on actual load growth. Platte River staff will continue to update load forecasts annually and will continue to seek opportunities to enhance forecasting and resource planning techniques. Staff will also actively pursue contingency options in the event that forecasts or other market factors change significantly over time. These include seeking expanded market purchase options, close coordination with WAPA to maximize value of hydropower resources and minimize supply reductions, evaluation of new transmission paths for power delivery and monitoring of customer generation technologies. 38 DRAFT X. Public Participation Several public communications processes of recent years have influenced the content of this IRP. Frequent interactions between Platte River, the member utilities, municipal boards and councils, and the citizens of member communities have facilitated an effective exchange of information on the public issues of electric load growth, resource supply, and environmental stewardship. These exchanges include: â€¢ Surveys of customers by Platte River and the municipal utilities, soliciting citizens' views on the importance of renewable resources, DSM activities, and environmental concerns, as well as system reliability, cost, and customer service. â€¢ Community surveys assessing attitudes and levels of interest in the addition of wind generating resources to Platte River's resource portfolio. A follow-up survey was also commissioned by Fort Collins Utilities and funded by the Colorado Governor's Office of Energy Conservation. â€¢ Public hearings and permitting proceedings for the gas-peaking units A, B, C, and D at the Rawhide Energy Station and for the upgrading of transmission and substation installations. â€¢ Periodic presentations to key account customers regarding resource planning issues, electric industry trends, renewable energy and DSM. â€¢ Frequent interactions with residential and commercial/industrial customers in each member community while administering DSM programs. â€¢ News releases and advertisements relating to renewable energy and DSM program offerings, construction of new facilities, public hearings for prior IRPs. â€¢ Meetings with the Fort Collins Electric Board, the Loveland Utilities Commission, the Estes Park Board of Trustees Utilities Committee and Longmont City Council to discuss electric energy supply policy, electric system reliability, DSM activity, and renewable energy progranns. â€¢ Additional meetings are planned to review this IRP with the Estes Park Board of Trustees Utilities Committee, the Fort Collins Electric Board, the Longmont City Council and the Loveland Utilities Commission. This draft IRP is available to interested parties. On September 28,2006, the Platte River Board will hold a public hearing, where a summary of the IRP will be presented, followed by public comment and discussion. A final 2007 IRP will be provided to the Platte River Board for their formal approval via resolution. Once approved, this IRP will authorize action by Platte River staff to implement action items described herein. Upon approval, it will also be submitted to Western Area Power Administration, to meet Integrated Resource Plan requirements of the 1992 Energy Policy Act. 39 DRAFT