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HomeMy WebLinkAboutCOUNCIL - COMPLETE AGENDA - 10/11/2011 - COMPLETE AGENDACITY COUNCIL AGENDA Karen Weitkunat, Mayor Council Chambers Kelly Ohlson, District 5, Mayor Pro Tem City Hall West Ben Manvel, District 1 300 LaPorte Avenue Lisa Poppaw, District 2 Fort Collins, Colorado Aislinn Kottwitz, District 3 Wade Troxell, District 4 Cablecast on City Cable Channel 14 Gerry Horak, District 6 on the Comcast cable system Darin Atteberry, City Manager Steve Roy, City Attorney Wanda Krajicek, City Clerk The City of Fort Collins will make reasonable accommodations for access to City services, programs, and activities and will make special communication arrangements for persons with disabilities. Please call 221-6515 (TDD 224- 6001) for assistance. ADJOURNED MEETING October 11, 2011 6 p.m. 1. Call Meeting to Order. 2. Roll Call. 3. Executive Session Authorized. The meeting of October 4, 2011, was adjourned to this date and time to allow the Council to consider adjourning into Executive Session for the purpose of meeting with the City Attorney regarding legal issues, as permitted under Section 2-31(a)(2) of the City Code. 4. Pineridge Natural Area Transmission Line Construction Alternatives Study. (staff: Steve Catanach, John Stokes, Ginger Purvis; 1 hour discussion) Staff will be presenting a draft study which examines alternative construction methodologies. The study examines the environmental, economic, aesthetic, reliability and schedule impacts of the potential alternatives. Staff is seeking Council direction on what alternative, if any, it wishes to pursue. Key to the discussion of potential alternatives is Western Area Power Administration’s (Western) adamant position denying consideration of undergrounding its existing and future transmission facilities. Western has also indicated that, within a decade, it plans to upgrade the overhead transmission line crossing Pineridge Natural Area. This position significantly limits options available to address view shed impacts. An underground option is examined and the probable Western line across Pineridge is illustrated, but ultimately due to Western’s position, the majority of options examined are related to alternate overhead construction methods. Options examined include: • Relocate the proposed line to one of three alternate routes in order to lessen visual impacts. • Change the appearance of the proposed line through the use of either galvanized (silver) or other color treatment. • In place of the proposed tall single poles, use shorter double pole construction similar to the existing line. • Decrease the number of poles in the Pineridge area by extending the distance between poles. This will require taller poles. • Rather than building a double circuit line, upgrade just the existing. This would require additional substation equipment. • Underground the new line and leave the existing Western line in place. In addition to the transmission line alternatives, staff and SAIC have also prepared a report that examines potentially available Distributed Generation (DG) technologies that might be available. While City staff recognizes an immediate need to provide additional electric requirements to the Loveland and south Fort Collins areas, integration of DG technologies are also being studied to augment our future electrical demand. Fort Collins cannot dictate what the City of Loveland does and does not do on its system; however the hope is that the information will be of value as the City looks at the integration of DG on its systems. 5. Other Business. 6. Adjournment. Karen Weitkunat, Mayor Council Information Center Kelly Ohlson, District 5, Mayor Pro Tem City Hall West Ben Manvel, District 1 300 LaPorte Avenue Lisa Poppaw, District 2 Fort Collins, Colorado Aislinn Kottwitz, District 3 Wade Troxell, District 4 Cablecast on City Cable Channel 14 Gerry Horak, District 6 on the Comcast cable system Darin Atteberry, City Manager Steve Roy, City Attorney Wanda Krajicek, City Clerk The City of Fort Collins will make reasonable accommodations for access to City services, programs, and activities and will make special communication arrangements for persons with disabilities. Please call 221-6515 (TDD 224- 6001) for assistance. WORK SESSION October 11, 2011 after the Adjourned Meeting 1. Call Meeting to Order. 2. Residential Electric Rate Options, Efficiency and Conservation. (staff: Brian Janonis, Patty Bigner, John Phelan, Laurie D’Audney, Bill Switzer, Steve Catanach; 90 minute discussion) In two previous City Council work sessions, May 10 and September 13, 2011, staff presented electric rate design principles, four residential rate options, a change to the residential demand rate and a pilot Time of Use rate for electric vehicles. At the September 13 Work Session, Council also discussed a change to the General Service (GS) or commercial rate proposed by staff that will result in two rate classes, a GS (up to 25 kW) and GS 25 (25 – 50 kW). The September 13 Work Session resulted in two areas of follow-up: (1) further review of the four residential electric rate options with answers to five specific questions as noted in the work session summary; and (2) scheduling of a work session discussion on energy efficiency and water conservation. Staff and SAIC consultant Joe Mancinelli will provide additional information to answer questions from Council regarding the four residential energy rate options. Also, for this follow-up work session, staff will present a review of the City’s efficiency and conservation programs. Ordinances for General Service (GS or commercial) rate changes and the Residential Demand (RD) rate will be considered on October 18, 2011 and November 1, 2011. These Ordinances do not include proposed changes to the Residential (R) energy rate. Public outreach for these draft ordinances began on September 29 with a post card mailed to out-of-city limits customers and a public notice published in the Coloradoan on October 2, 2011. Once the Ordinances are adopted, additional public outreach will take place, beginning with a bill insert mailed throughout late November and December. Feedback from this work session will be used in drafting rate ordinances for public comment and Council consideration and implementation early in 2012. The tentative schedule for implementing changes to the Residential (R) rate include beginning public notification on November 6, followed by First Reading of the Residential rate Ordinance on November 15 and Second Reading on December 6, 2011. If this tentative schedule is finalized, the rate change will be effective February 1, 2012. Public outreach will begin January 1, 2012. Additional outreach will occur throughout the spring and early summer as needed to support customer understanding. 3. Presentation of the City Manager's Recommended 2012 Budget Revision Requests. (staff: Darin Atteberry, Mike Beckstead; 90 minute discussion) The purpose of this work session is to review the 2012 Budget Revision Requests to be considered for inclusion in the 2012 Annual Appropriation Ordinance. The Ordinance will be considered on First Reading on October 18, 2011. 4. Other Business. 5. Adjournment. DATE: October 11, 2011 STAFF: Steve Catanach John Stokes, Ginger Purvis AGENDA ITEM SUMMARY FORT COLLINS CITY COUNCIL 4 SUBJECT Pineridge Natural Area Transmission Line Construction Alternatives Study. EXECUTIVE SUMMARY Staff will be presenting a draft study which examines alternative construction methodologies. The study examines the environmental, economic, aesthetic, reliability and schedule impacts of the potential alternatives. Staff is seeking Council direction on what alternative, if any, it wishes to pursue. Key to the discussion of potential alternatives is Western Area Power Administration’s (Western) adamant position denying consideration of undergrounding its existing and future transmission facilities. Western has also indicated that, within a decade, it plans to upgrade the overhead transmission line crossing Pineridge Natural Area. This position significantly limits options available to address view shed impacts. An underground option is examined and the probable Western line across Pineridge is illustrated, but ultimately due to Western’s position, the majority of options examined are related to alternate overhead construction methods. Options examined include: • Relocate the proposed line to one of three alternate routes in order to lessen visual impacts. • Change the appearance of the proposed line through the use of either galvanized (silver) or other color treatment. • In place of the proposed tall single poles, use shorter double pole construction similar to the existing line. • Decrease the number of poles in the Pineridge area by extending the distance between poles. This will require taller poles. • Rather than building a double circuit line, upgrade just the existing. This would require additional substation equipment. • Underground the new line and leave the existing Western line in place. In addition to the transmission line alternatives, staff and SAIC have also prepared a report that examines potentially available Distributed Generation (DG) technologies that might be available. While City staff recognizes an immediate need to provide additional electric requirements to the Loveland and south Fort Collins areas, integration of DG technologies are also being studied to augment our future electrical demand. Fort Collins cannot dictate what the City of Loveland does and does not do on its system; however the hope is that the information will be of value as the City looks at the integration of DG on its systems. BACKGROUND / DISCUSSION To address reliability issues, Platte River Power Authority (Platte River) is in the final stages of upgrading the area transmission network by adding 230-kV transmission facilities, in particular the Dixon Creek to Horseshoe interconnection project (Project). To date, Platte River has accomplished two phases of the Dixon Creek to Horseshoe transmission line. This report addresses issues that have been raised related to the Phase III of the Platte River Project which extends from Dixon Creek Substation to Horsetooth Tap Switching Station. A point of contention for Phase III has been the section that is planned to be constructed overhead by rebuilding the existing Western Area Power Administration (Western) 115-kV line through the Pineridge Natural Area in Fort Collins as a double-circuit steel pole line. This section was planned to complete the Dixon Creek to Horseshoe 230-kV transmission corridor conversion by a summer 2012 in-service deadline. Construction staging for Phase III began in the spring of 2011. As activity on the project escalated, citizens began to take notice. Although the required public process for notification was followed from 2005 up through today, a significant number of citizens were unaware of the project. As observed at Council meetings, and through other media, there has been concern voiced with the impact the project will have on the Pineridge Natural Area. As noted, the required public engagement process was done as part of the project. However, there was not a strong focused October 11, 2011 -2- ITEM 4 process to build informed consent or at a minimum acceptance of the project. Projects such as the Pineridge transmission project require a heightened level of engagement with the community and more specifically those stakeholders that are directly affected by a project. In this case, as with any large project that has substantial impact, the minimum process does not adequately achieve the required level of engagement. As a result, Platte River and the City have devoted significant resources exploring opportunities to address citizen concerns, which should have been done throughout the project. On August 16, 2011, City Council , by motion, directed staff (1) to attempt to negotiate with the Platte River Power Authority a written agreement to postpone the commencement of construction of Phase III of the Dixon Creek Substation to Horseshoe Substation Transmission Line project pending the completion of a rigorous, in-depth data- based analysis and review of the project and its related impacts as presently designed, as well as the pros, cons, costs and benefits of the project and further pending the review and consideration of that analysis by the Fort Collins City Council and the other member cities of PRPA; (2) if such an agreement has not been negotiated and signed between PRPA and City on or before August 26, 2011, to work with the Mayor to schedule a special meeting of the City Council to be held no later than August 31, 2011, for the purpose of seeking Council approval of the commencement of such litigation as may be necessary for the City to seek adjunctive relief from a court of competent jurisdiction adjoining the construction of the project; and (3) to prepare such legal documents as may be necessary to file such a court action pending further direction from the Council. On August 25, 2011, the Platte River Board of Directors passed a motion directing: “Platte River Power Authority to temporarily delay further construction activities associated with Phase III of the Dixon Creek – Horseshoe transmission upgrade until October 18, 2011, provided an agreement, suitable to the General Manager, can be reached with the City of Fort Collins in order to use this period of delay to study alternative means to complete the 230 kV circuit presently under construction that will provide a redundant transmission circuit to the City of Loveland. During the period between now and October 18, staff is directed to cooperate fully with the City of Fort Collins to retain a mutually agreeable, nationally recognized engineering consultant to complete the referenced study. The results of the study of alternative means to complete the 230 kV transmission circuit will be presented to the City Council of Fort Collins on October 18 for action by the City Council. Due to the critical importance of the new 230 kV circuit to the reliability of service to the City of Loveland and residents of south Fort Collins, any alternatives must complete the connection by June 1, 2012. Fort Collins must pay the incremental costs of any alternative pursued. Platte River is willing to pay a reasonable amount for the retention of the engineering consultant, such amount not to exceed one half of the expenses.” The end result of a multi stepped process has been to develop the Agreement signed on August 31, 2011 (Attachment 1). In that Agreement, the City of Fort Collins and Platte River Power Authority agreed to hire SAIC / R.W. Beck to analyze the Dixon Creek – Horseshoe project and examine alternative ways to accomplish the purposes of the project. Staff, Platte River and SAIC have been diligently working on the Alternatives Study. The initial schedule called for the study to be completed by October 10, 2011 for inclusion in the Council packet for the October 18, 2011 meeting. In order to provide information for the October 11, 2011 adjourned meeting, the study materials that are attached are a 90% draft of the final report (Attachments 2 and 3). FINANCIAL / ECONOMIC IMPACTS Please see attached draft report provided by R.W. Beck / SAIC. ENVIRONMENTAL IMPACTS Please see attached draft report provided by R.W. Beck / SAIC. October 11, 2011 -3- ITEM 4 STAFF RECOMMENDATION Utilities and Natural Resources staff recommend that the appropriate City departments work with Platte River to develop guidelines that define the expectations, procedures and processes that should be utilized in order to insure that citizens are engaged, informed and considered throughout all phases of a project. BOARD / COMMISSION RECOMMENDATION Due to the limited time frame associated with developing the study there was no opportunity to present the material to any board or commission. PUBLIC OUTREACH Pending the action taken by City Council, public outreach will be conducted to present potential alternatives to the public. ATTACHMENTS 1. Interim Agreement Regarding Phase III of the Dixon Creek – Horseshoe Transmission Line Project Between City of Fort Collins and Platte River Power Authority 2. Draft Pineridge Transmission Project Alternatives Study 3. Draft Distributed Generation Alternatives Study Draft Report Pineridge Transmission Alternatives Study City of Fort Collins, Colorado October 2011 Draft Report Pineridge Transmission Alternatives Study City of Fort Collins, Colorado October 2011 This report has been prepared for the use of the client for the specific purposes identified in the report. The conclusions, observations and recommendations contained herein attributed to SAIC constitute the opinions of SAIC. To the extent that statements, information and opinions provided by the client or others have been used in the preparation of this report, SAIC has relied upon the same to be accurate, and for which no assurances are intended and no representations or warranties are made. SAIC makes no certification and gives no assurances except as explicitly set forth in this report. © 2011 SAIC All rights reserved. File: 00545503/3105111014-1000 Pineridge Transmission Alternatives Study City of Fort Collins, Colorado Table of Contents Letter of Transmittal Table of Contents List of Tables List of Figures Executive Summary Section 1 PLATTE RIVER TRANSMISSION NETWORK AND SYSTEM RELIABILITY ......................................................................................... 1-1 1.1 Load Growth ............................................................................................ 1-1 1.2 Transmission Planning ............................................................................. 1-1 Section 2 WESTERN’S FACILITIES AND LONG-RANGE PLANS ................ 2-1 2.1 Western Transmission in Pineridge Natural Area ................................... 2-1 Section 3 DIXON CREEK – HORSESHOE LINE CONFIGURATION ............ 3-1 3.1 Platte River Proposed Project .................................................................. 3-1 3.1.1 Phase I – Horseshoe Substation to Trilby Substation .................. 3-1 3.1.2 Phase II – Trilby Substation to Horsetooth Tap........................... 3-3 3.1.3 Phase III – Horsetooth Tap to Dixon Creek Substation ............... 3-4 3.2 Phase III Schedule .................................................................................... 3-5 3.3 Phase III Cost ........................................................................................... 3-5 3.4 Phase III Environmental Impacts ............................................................. 3-6 3.4.1 Biological Resource Impacts ....................................................... 3-6 3.4.2 Aesthetic Impacts ......................................................................... 3-7 Section 4 ALTERNATIVE STRUCTURE CONFIGURATIONS ....................... 4-1 4.1 Range of Options Considered .................................................................. 4-1 4.2 Painted Structures .................................................................................... 4-1 4.3 Alternative Structure Types ..................................................................... 4-2 4.4 Double-Circuit H-Frame .......................................................................... 4-3 4.4.1 Schedule ....................................................................................... 4-5 4.4.2 Cost .............................................................................................. 4-6 4.4.3 Biological and Natural Resource Impacts .................................... 4-7 4.4.4 Aesthetic Impacts ......................................................................... 4-7 4.5 Single-Circuit 230-kV H-Frame ............................................................ 4-10 Section 5 SPAN LENGTH INCREASE .................................................................. 5-1 5.1 Interrelationship of Span Length and Structure Height ........................... 5-1 Table of Contents iv SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 5.2 Schedule ................................................................................................... 5-2 5.3 Cost .......................................................................................................... 5-2 5.4 Biological and Natural Resource Impacts ............................................... 5-4 5.5 Aesthetic Impacts ..................................................................................... 5-4 Section 6 PARTIAL UNDERGROUND ALTERNATIVE ALONG CURRENT ROUTE.................................................................................................. 6-1 6.1 Description ............................................................................................... 6-1 6.2 Schedule ................................................................................................... 6-1 6.3 Cost .......................................................................................................... 6-2 6.4 Biological and Natural Resource Impacts ............................................... 6-4 6.5 Aesthetic Impacts ..................................................................................... 6-4 Section 7 ALTERNATIVE ROUTES ..................................................................... 7-1 7.1 Initially Considered Routes ..................................................................... 7-1 7.2 Magenta Route Alternative – Follow Lower Ridge Line in Pineridge Natural Area ............................................................................ 7-6 7.2.1 Route Description ........................................................................ 7-6 7.2.2 Easements .................................................................................... 7-6 7.2.3 Schedule ....................................................................................... 7-6 7.2.4 Cost .............................................................................................. 7-8 7.2.5 Environmental Impacts ................................................................ 7-9 7.2.6 Aesthetic Impacts ......................................................................... 7-9 7.3 Orange Route Alterative – South Centennial Drive .............................. 7-12 7.3.1 Route Description ...................................................................... 7-12 7.3.2 Easements .................................................................................. 7-12 7.3.3 Schedule ..................................................................................... 7-13 7.3.4 Cost ............................................................................................ 7-14 7.3.5 Environmental Impacts .............................................................. 7-15 7.3.6 Aesthetics ................................................................................... 7-16 7.4 Green Route Alternative – South Taft Hill Road and West Drake Road ....................................................................................................... 7-19 7.4.1 Route Description ...................................................................... 7-19 7.4.2 Easements .................................................................................. 7-19 7.4.3 Schedule ..................................................................................... 7-19 7.4.4 Cost ............................................................................................ 7-21 7.4.5 Environmental Impacts .............................................................. 7-22 7.4.6 Aesthetics ................................................................................... 7-22 Section 8 TEMPORARY LINE ............................................................................... 8-1 8.1 Required Interconnection Timeline ......................................................... 8-1 8.2 Temporary Line Configuration – Wooden Structures ............................. 8-1 8.3 Schedule ................................................................................................... 8-3 8.4 Cost .......................................................................................................... 8-3 8.5 Biological and Natural Resource Impacts ............................................... 8-4 8.6 Aesthetic Impacts ..................................................................................... 8-4 Table of Contents File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC v List of Tables Table 1-1 Loveland Peak Load History ...................................................................... 1-1 Table 3-1 Span, Height, and Right-of-Way Information ............................................ 3-4 Table 3-2 Implementation Schedule Phase III Existing Contract ............................... 3-5 Table 4-1 230-kV H-frame Span, Height, and Right-of-Way Information ................ 4-4 Table 4-2 Cost Comparison Double-circuit H-frame Structure Alternative ............... 4-7 Table 5-1 Cost Comparison Long Span Alternative ................................................... 5-3 Table 6-1 Implementation Schedule Partial Underground in Pineridge Natural Area ..................................................................................................... 6-2 Table 6-2 Cost Comparison Partial Underground Alternative .................................... 6-3 Table 7-1 Alternate Route Screening Matrix .............................................................. 7-3 Table 7-2 Implementation Schedule Magenta Route Alternative .............................. 7-7 Table 7-3 Cost Comparison Magenta Route Alternative ............................................ 7-8 Table 7-4 Implementation Schedule Orange Route Alternative .............................. 7-13 Table 7-5 Cost Comparison Orange Route Alternative ............................................ 7-15 Table 7-6 Implementation Schedule Green Route Alternative ................................ 7-20 Table 7-7 Cost Comparison Green Route Alternative .............................................. 7-22 Table 8-1 Implementation Schedule Temporary Wood Pole Line in Pineridge Natural Area ..................................................................................................... 8-3 Table 8-2 Estimated Cost Temporary Transmission Line .......................................... 8-4 Table of Contents vi SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 List of Figures Figure 2-1. Western 230-kV and 115-kV H-Frame Transmission Line Structures 2-2 Figure 2-2. Existing Western 115-kV H-Frame Transmission Line in Pineridge Natural Area ..................................................................................... 2-3 Figure 2-3. Photo Simulation – Future Western 230-kV H-Frame Transmission Line in Pineridge Natural Area .................................................. 2-3 Figure 3-1. Underground 230-kV Transmission Ductbank Cross-Section ................. 3-2 Figure 3-2. Underground 230-kV Transmission Ductbank Vault (24’Lx8’Wx8’H) .............................................................................................. 3-2 Figure 3-3. Double-Circuit 230-kV Transmission Line Structure .............................. 3-3 Figure 3-4. Existing Western 115-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) ..................................................... 3-8 Figure 3-5. Proposed Platte River 230-kV Tubular Steel Pole Transmission Line (Looking South in Pineridge Natural Area) ...................... 3-9 Figure 4-1. Photo Simulation Painted Single Steel Poles ........................................... 4-2 Figure 4-2. Double-Circuit 230-kV Lattice Tower ..................................................... 4-3 Figure 4-3. Double-Circuit 230-kV H-Frame ............................................................. 4-4 Figure 4-4. Existing Western 115-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) ..................................................................... 4-8 Figure 4-5. Photo Simulation: Double-Circuit 230-kV Tubular Steel Pole Transmission Line (Looking South in Pineridge Natural Area) ...................... 4-9 Figure 4-6. Photo Simulation: Double-Circuit 230-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) ...................... 4-9 Figure 4-7. Western 230-kV and 115-kV H-Frame Transmission Line Structures ........................................................................................................ 4-10 Figure 4-8. Photo Simulation: Single-Circuit 230-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) ........................................... 4-11 Figure 4-9. Existing Fordham 230-115 kV Substation in Longmont ....................... 4-12 Figure 7-1. Phase III Initial Route Alternatives (2010 Imagery) ................... 7-1 Figure 7-2. Phase III Viable Route Alternatives (2010 Imagery) .................. 7-5 Figure 7-2. Existing view of Dixon Reservoir from Burns Ranch (Looking northwest) ....................................................................................... 7-10 Figure 7-3. Existing view of Pineridge from Burns Ranch (Looking west) 7-10 Figure 7-4. Platte River 230-kV Tubular Steel Pole Transmission Line (Looking northwest at Dixon Reservoir) ............................................... 7-11 Figure 7-5. Platte River 230-kV H-Frame Transmission Line (Looking northwest at Dixon Reservoir) ........................................................ 7-11 Figure 7-6. Platte River 230-kV Transmission Lines (Looking west at Pineridge) 7-12 Figure 7-7. Existing view of Dixon Reservoir from Burns Ranch (Looking northwest) ....................................................................................... 7-16 Figure 7-8. Existing view of Pineridge from Burns Ranch (Looking west) 7-17 Table of Contents File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC vii Figure 7-9. Platte River 230-kV Tubular Steel Pole Transmission Line (Looking northwest at Dixon Reservoir) ............................................... 7-18 Figure 7-10.Platte River 230-kV Tubular Steel Pole Transmission Line (Looking west at Pineridge) ........................................................................... 7-18 File: 005445/3105111014-1000 EXECUTIVE SUMMARY Platte River Power Authority (Platte River) is responsible for designing and operating the high-voltage electric transmission system that serves the cities of Estes Park, Fort Collins, Longmont, and Loveland (Cities). The Cities have grown over the past decade and peak load has increased to the point that the existing transmission system is not sufficient to provide the required redundancy to reliably meet Fort Collins, Longmont, and Loveland needs. Section 1 of this document discusses the specifics of the transmission reliability issues facing the northern Front Range Colorado transmission corridor in Larimer County that serves these cities and alternatives for addressing those issues. To address reliability issues, Platte River is in the final stages of upgrading the area transmission network by adding 230-kV transmission facilities, in particular the Dixon Creek to Horseshoe interconnection project (Project). To date Platte River has accomplished two phases of the Dixon Creek to Horseshoe transmission line. This report addresses issues that have been raised related to Phase III of the Platte River Project which extends from Dixon Creek Substation to Horsetooth Tap Switching Station. A point of contention for Phase III has been the section that is planned to be constructed overhead by rebuilding the existing Western Area Power Administration (Western) 115-kV line through the Pineridge Natural Area in Fort Collins as a double- circuit steel pole line, as simulated in Figure EX-1. Figure EX-1 - Proposed Platte River 230-kV Tubular Steel Pole Transmission Line (Looking South in Pineridge Natural Area) EXECUTIVE SUMMARY 2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 This section was planned to complete the Dixon Creek to Horseshoe 230-kV transmission corridor conversion by a summer 2012 in-service deadline. By not completing the Dixon Creek – Horsetooth segment, the 230-kV circuit capability of the first two phases will not be realized and Platte River will not be able to provide transmission reliability per North American Electric Reliability Corporation (NERC) standards when the Cities’ loads exceed 550 MW. Platte River stated that this load level was exceeded 178 hours during 2011 as of August 22nd and is expected to be exceeded more frequently next summer based on projected 2.75% annual load increases; therefore an alternative solution needs to be completed before June 2012 or a temporary line must be in place by that time. As of October 2011, the design, permitting and some of the material procurement has been completed for Phase III as proposed by Platte River. This phase is presently being delayed until it can be demonstrated that other alternative ways to accomplish the purposes of the Project have been examined. This report evaluates a number of physical alternatives for Phase III as compared to Platte River’s existing transmission plan for the completion of the Dixon Creek – Horsetooth Tap 230-kV circuit, which is described in detail in Section 3. For discussion purposes the Dixon Creek – Horsetooth Tap line is described as having a southern section and a northern section, The southern section is 2.4 miles long extending from Horsetooth Tap Switching Station to the area of Spring Canyon Dam. The northern section is 1.4 miles long extending from the area of Spring Canyon Dam, through the Pineridge Natural Area, to Dixon Creek Substation. Western’s Plans Since Platte River’s proposed Project utilizes the Western Right-of-Way (R/W) in the Pineridge Natural Area and also involves rebuilding Western’s existing transmission line onto new structures, it is important to understand Western’s long range plans in consideration of any potential changes to the Project and their position in general towards underground transmission facilities. Western has clearly communicated the following: 1. Western is willing to relocate to an alternate route, provided, there is no cost to Western, their technical requirements are accommodated and they retain a R/W from Horsetooth Tap to Dixon Creek. 2. Western will not consider undergrounding their existing line or any new lines. 3. If the Platte River line is built elsewhere and the Western line remains in the Pineridge Natural Area, Western has indicated that it is in their long range plans to upgrade the existing line crossing Pineridge with overhead construction within a decade. Anticipating future growth, they plan to rebuild for 230-kV using larger structures than those in place today. A photo simulation of the probable Western line across Pineridge for this scenario is shown in Figure EX-2. EXECUTIVE SUMMARY File: 005445/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 3 Figure EX-2 – Photo Simulation Western Line rebuilt to 230-kV Western’s position significantly limits options available to address view shed impacts. An underground option for the new Platte River line is examined, but the Western line would remain. Therefore, the majority of options examined are related to alternate overhead construction methods. Temporary Impacts of Adopting an Alternative As a part of this study it was determined that, in the event that an alternative is adopted for Phase III of Platte River’s proposed Project that cannot be completed by next summer (2012), reliability issues dictate that a temporary 230-kV line will need to be built. This could be a parallel wood pole line through the area or completion of the line as designed subject to later removal. Any temporary parallel line through the southerly line section would require easements over private property. If the owners are not willing to grant easements, a lengthy condemnation process would likely be required. In addition the timeline for environmental permitting of a temporary line in Larimer County would not support completion of the parallel line in time to meet the in-service date. Therefore completion of the line as designed may be the only viable temporary solution for the southerly section. For the northerly section, from Spring Canyon dam a temporary line could be located adjacent to the existing Western 115-kV line if easements and environmental permitting can be obtained in time. Construction for this temporary line is anticipated to have biological and natural resource impacts very similar to constructing the EXECUTIVE SUMMARY 4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 proposed Project. The temporary line would have additional biological and natural resource impacts from the construction activities associated with its future removal. The temporary line will also have aesthetic impacts for the duration of the line being in place, which is estimated to be two years Potential Phase III Alternatives The range of options considered under this study included evaluation of structure changes to the line proposed by Platte River as well as routing alternatives. The options examined include: 1. Change the appearance of the proposed line through the use of either galvanizing (silver) or other color treatment for the poles 2. In place of the proposed tall single poles use alternative structure types, such as shorter double pole construction similar to the existing line; 3. Rather than building a double circuit line upgrade just the existing line. This would require additional substation equipment. 4. Decrease the number of poles in the Pineridge area by extending the distance between the poles (longer spans). This will require taller poles. 5. Underground the new line along the proposed route through Pineridge and leave the existing Western line in place; and 6. Relocate the proposed line to one of three alternative routes in order to lessen visual impacts. In evaluating each of the above alternatives the analyses considered the timeline for completion of the alternative, costs of the alternative, its biological and natural resource (environmental) impacts, and its aesthetic impacts. Color Treatment Platte River’s proposed single pole structures are made of weathering steel which overtime darkens to a deep brown color and is thought to resemble the appearance of wood poles when viewed from a distance. This was selected over galvanized steel, which has a shiny appearance that can be highly visible in sunlight or bright light conditions and would increase the aesthetic impact of tubular steel poles in the Pineridge Natural Area. Another option is painted steel, available in a wide range of color options to blend into the environment; however surface scratches or damage will expose the underlying steel to corrosion damage. A photo simulation of painted poles is shown in Figure EX-3. If painted poles were to be used for the Phase III structures, it is not feasible to use the poles already procured by Platte River. EXECUTIVE SUMMARY File: 005445/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 5 Figure EX-3 Photo Simulation Painted Single Pole Structures Alternative Structure Types Three alternative structure types were considered. A double-circuit lattice tower as shown in Figure EX-4 is commonly used in the industry, but would have more environmental and aesthetic impact and a higher cost than the proposed Project. EXECUTIVE SUMMARY 6 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure EX-4 Double-Circuit 230-kv Lattice Tower Figure EX-5 is a photo simulation of double circuit 230-kV steel H-frame structures along the alignment in the Pineridge Natural Area. It would also have more environmental and aesthetic impact and a higher cost than the proposed Project. EXECUTIVE SUMMARY File: 005445/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7 Figure EX-5 Photo Simulation Double-Circuit 230-kV H-frame Upgrade of Existing Line A single-circuit 230-kV H-frame as shown in Figure EX-1 could possibly provide adequate reliability if coupled with a $10 million, 5 acre, 230-115-kV substation. However, the single-circuit option would be owned and controlled by Western and would not provide the firm capacity Platte River requires. Longer Spans The option of using longer spans is anticipated to result in much taller structures (135 to 150 feet), depending on final design and conductor selection. The poles may also have a larger diameter and be quite massive; therefore this option was deemed to not be preferred over the proposed Project. Partial Undergrounding Along Proposed Route Undergrounding of the Platte River line on the proposed route through Pineridge may address the aesthetic impact of larger double-circuit structures but has substantial tradeoffs. Since Western would not allow undergrounding of its circuit and since Western plans to upgrade the existing overhead line, the aesthetic impact is represented by the photo simulation shown above in Figure EX-1. The underground alternative is anticipated to have extensive physical impacts on biological and natural resource as a result of trenching through the Pineridge Natural Area. This alternative EXECUTIVE SUMMARY 8 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 also has substantial cost implications since it is estimated to cost approximately $7 Million more than the proposed Project. Alternative Routes An initial screening analysis identified three viable routing options for the proposed Platte River 230-kV line separate from the existing 115-kV Western line route. These are color-coded on Figure EX-6 as follows; 1. Magenta route- Lower ridgeline in Pineridge Natural Area (overhead, but reduced visibility in the natural area) 2. Orange Route- South Centennial Drive (overhead, but at a greater distance from the City and less impact on the natural area ) 3. Green Route- South Taft Hill R and West Drake (overhead/underground hybrid east of the natural area) Figure EX-6 Alternative Routes Review of these routing alternatives weighed the environmental and aesthetic impacts using a subjective scale of low to high impact, as well as the cost and construction schedule. Table EX-1 below illustrates how the three alternatives compare to each EXECUTIVE SUMMARY File: 005445/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 9 other and to undergrounding along the proposed Pineridge route. The project development costs shown include the materials and construction required for the alternative as well as the engineering, permitting, right-of-way, construction management and interest during construction. Other costs related to adoption of an alternative include costs for the temporary line and any sunk costs related to materials or construction already in place which would need to be abandoned. EXECUTIVE SUMMARY 10 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Table EX-1 Alternative Route Comparison Route ID Route Description Technical Solution Environmental Impact Aesthetic Impact Cost Yellow 1 (Platte River Proposed Project) 3.7 miles Utilize existing 75-ft Western R/W from Horsetooth Tap to Dixon Creek Substation through Horsetooth Reservoir Area and Pineridge Natural Area. Double-circuit tubular steel pole line supporting both Platte River’s proposed 230-kV circuit and Western’s existing 115-kV circuit. Medium – construction roads required along the northern portion. Southern portion utilize helicopter construction. High – Major impact for recreational users of Natural Area and Horsetooth Reservoir. $8.5M Yellow 2 (Partial UG) 3.7 miles (1.4 UG) Utilize existing 75-ft Western R/W from Horsetooth Tap to Dixon Creek Substation through Horsetooth Reservoir Area and Pineridge Natural Area. Overhead from Horsetooth Tap to near Spring Canyon Dam (as designed), then underground (as a single circuit) to Dixon Creek Substation; Western remains as single circuit overhead line. High – construction roads required and continuous trench/bore (with pits) along the northern portion. Southern portion utilize helicopter construction. Medium – No major, long term aesthetic impact through Pineridge Natural Area. Transmission line visible from Natural Area and Horsetooth Reservoir. $15.3M Green 2 (Partial UG) 5.1 miles (3.1 UG) EXECUTIVE SUMMARY File: 005445/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 11 Orange 4.2 miles Utilize existing 75-ft Western R/W from Horsetooth Tap to Spring Canyon Dam, then north along S Centennial Dr, east near Dixon Canyon Rd, across Dixon Reservoir to Dixon Creek Substation. Overhead double-circuit tubular steel poles (230-kV Platte River and Western 115-kV). Low – construction in existing Western R/W and public R/W. Medium – Adds very tall structures in area with overhead distribution lines. $10.4M File: 005455/3105111014-1000 Section 1 PLATTE RIVER TRANSMISSION NETWORK AND SYSTEM RELIABILITY 1.1 Load Growth Platte River Power Authority (Platte River) is responsible for designing and operating the electric transmission system that serves the cities of Estes Park, Fort Collins, Longmont, and Loveland (Cities). Electric systems are designed to serve peak load, which is when the instantaneous Megawatt (MW) demand is the highest. In the northern Front Range Colorado area, peak loads typically occur between 4 PM and 6 PM on a summer weekday when business and residential cooling requirements and evening activities overlap. Peak load at Loveland has increased approximately 37% over the past ten years as shown in Table 1-1. Overall system growth in the Platte River Power Authority (Platte River) service area has increased 20% during that timeframe. Peak load has increased to the point that the 115-kV transmission system is not sufficient to provide the required redundancy to reliably meet Fort Collins, Longmont, and Loveland needs. Table 1-1 Loveland Peak Load History Date Time MW 7/18/2011 18:00 156 7/26/2010 17:00 145 7/24/2009 16:00 135 8/1/2008 17:00 153 7/23/2007 17:00 146 6/14/2006 17:00 137 7/22/2005 17:00 137 7/13/2004 16:00 125 7/17/2003 16:00 122 7/30/2002 17:00 114 1.2 Transmission Planning It is required per the North American Electric Reliability Corporation (NERC) Transmission Planning (TPL) standards (TPL-001 through TPL-004, in particular) to conduct power flow studies to effectively demonstrate the reliability of the electric system under contingency situations, such as loss of a network transmission line. In performing these extensive contingency analyses, the effect of an outaged facility on Section 1 1-2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 the rest of the transmission system is evaluated under a variety of system loading conditions, transmission configurations, and generation dispatch patterns. Two transmission lines connect the City of Loveland to generation resources. On the east side of Loveland is a Platte River 230-kV line capable of serving approximately 472 MW. On the west side of the cities is a Western Area Power Administration (Western) 115-kV line capable of serving approximately 109 MW peak load. Current system planning studies, as well as 10-year transmission planning studies conducted in 2004, have conclusively demonstrated the urgent need to provide additional capacity between Fort Collins and Loveland to address the contingency loss of the existing 230-kV line between the two cities. In 2004, Platte River considered several alternatives and determined the most economical solution was to build a 230-kV circuit (Dixon Creek Substation to Horseshoe Substation). In addition, the Colorado Coordinated Planning Group, which is a statewide consortium (including Tri-State and Xcel Energy) have collectively concluded that the Dixon Creek – Horseshoe 230-kV circuit is an appropriate transmission solution for the area. With the load growth existing in the upper portion of the Front Range from Colorado Springs toward the Wyoming border, future transmission improvements are scheduled to take place from Southern Wyoming to Northern Colorado in order to accommodate the expanded import capability from the generation resources north of the Colorado border. The scheduled improvements will have an effect of increased power flows through the eastern part of Colorado in the Front Range. Over 70 percent of the state’s load exists between Fort Collins and Colorado Springs within 40 miles of either side of Interstate 25; thus, the proposed parallel 230-kV transmission lines will also serve to boost the overall system reliability. The two segments of this comprehensive 230-kV upgrade north of Horseshoe Substation (Phase I) and west of Trilby Substation (Phase II) have already been completed, and the section south of Dixon Creek Substation through Pineridge Natural Area (Phase III) is the last phase in preparation for the anticipated summer 2012 loading conditions in the Loveland area. The last section in question will aid in alleviating the 115-kV circuit contingency loading that occurs with a 230-kV circuit outage. This report addresses issues that have been raised related to the Phase III of the Platte River Project which extends from Dixon Creek Substation to Horsetooth Tap switching station. A point of contention for Phase III has been the section that is planned to be constructed overhead by rebuilding the existing Western Area Power Administration (Western) 115-kV line through the Pineridge Natural Area in Fort Collins as a double-circuit steel pole line. This section was planned to complete the Dixon Creek to Horseshoe 230-kV transmission corridor conversion by a summer 2012 in-service deadline. By leaving the remaining Dixon Creek – Horsetooth segment at 115-kV, the 230-kV circuit capability of the two previously upgraded 115-kV circuits will not be realized and Platte River will not be able to provide transmission reliability per North American Electric Reliability Corporation (NERC) standards when the Cities’ loads exceed 550 MW. Platte River stated that this load level was exceeded 178 hours PLATTE RIVER TRANSMISSION NETWORK AND SYSTEM RELIABILITY File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 1-3 during 2011 as of August 22nd and is expected to be exceeded more frequently next summer based on projected 2.75% annual load increases. The design, permitting, and some of the material procurement have been completed for Phase III as proposed by Platte River. This phase is presently being delayed until it can be demonstrated that other alternatives have been adequately evaluated. This report evaluates a number of physical alternatives for Phase III as compared to Platte River’s existing transmission plan for the completion of the Dixon Creek – Horsetooth Tap 230-kV circuit. File: 005455/3105111014-1000 Section 2 WESTERN’S FACILITIES AND LONG-RANGE PLANS 2.1 Western Transmission in Pineridge Natural Area Since Platte River’s proposed Phase III of the Dixon Creek to Horsetooth project in the Pineridge Natural Area also involves Western’s existing transmission line and right-of-way, it is important to understand Western’s long-range plans for these facilities. Based upon a brief discussion with Western regarding their plans for the existing 115- kV line we were able to determine the following: 1. The existing line utilizes wood H-frame structures, is 60 years old, and is nearing the end of its useful life. Western indicated that given its age, they would need to rebuild the line within 10 years. 2. Western has no system studies indicating a need to upgrade the circuit to 230-kV, but given the expanding prevalence of a 230-kV grid in the area, they would opt to design and rebuild the line to 230-kV standards. 3. If Western were to rebuild the line as a single circuit 230-kV line, without the Platte River line, they would prefer to utilize a wood H-frame structure. 4. Western’s typical right-of-way (R/W) width for 230-kV single circuit H-frame construction is 125 feet, which is common and appropriate for this type construction. Rebuilding the line at 230-kV with H-frames would require expansion of the existing 75-foot R/W by acquisition of an additional 50-foot width from Fort Collins. 5. Western is opposed to undergrounding their circuit at 115 kV or 230 kV. They indicated a willingness to negotiate and support expansion of the existing R/W or acquisition of an alternative route R/W provided there is no cost to them and their technical requirements are accommodated. In the event the Platte River 230-kV transmission line utilizes one of the other route alternatives considered in this report and Western’s line remains in the Pineridge Natural Area information is provided below to illustrate the difference in Western’s structure types for 115-kV and 230-kV lines. A Western 230-kV H-frame would have almost double the pole spacing (22 feet versus 12 feet) and much wider crossarms (45 feet versus 25 feet) compared to the existing 115-kV H-frame. Figure 2-1 is a photograph that Western provided of an existing transmission corridor that illustrates the relative sizes between their 115-kV and 230-kV H-frame structures. Section 2 2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study Figure 2-1. Western 230-kV and 115-kV H-Frame Transmission Line Structures Figure 2-2 is a photograph of the existing Western 75-foot R/W and 115-kV transmission line in the Pineridge Natural Area. For any alternatives considered in this report where the Western line is not rebuilt or relocated from the Pineridge Natural Area, Figure 2-3 provides a photo simulation illustrating Western’s future plan to rebuild their line at 230-kV. WESTERN’S FACILITIES AND LONG-RANGE PLANS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 3 Figure 2-2. Existing Western 115-kV H-Frame Transmission Line in Pineridge Natural Area Figure 2-3. Photo Simulation – Future Western 230-kV H-Frame Transmission Line in Pineridge Natural Area Section 2 4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study In the event that Western could not obtain the additional R/W necessary to build a single circuit 230-kV wood H-frame line in the Pineridge Natural Area, the existing R/W would be sufficient to accommodate a single-pole 230-kV line. This concept was not explored in the discussions with Western. File: 005455/3105111014-1000 Section 3 DIXON CREEK – HORSESHOE LINE CONFIGURATION 3.1 Platte River Proposed Project The Platte River proposed project seeks to create a 230-kV transmission interconnection between the Dixon Creek Substation in Fort Collins and the Horseshoe Substation in Loveland, as a second 230-kV power source for Loveland, as more fully explained in Section 1 of this report. In order to accomplish this 230-kV interconnection, Platte River divided the transmission line into three segments or phases as further described below. To date Platte River has completed both Phase I and Phase II of the transmission line. This report focuses on the Phase III segment from Horsetooth Tap Switching Station to Dixon Creek Substation, located within Larimer County and the City of Fort Collins. 3.1.1 Phase I – Horseshoe Substation to Trilby Substation Phase I consists of the Platte River single circuit 230-kV transmission line, from Horseshoe Substation in Loveland to Trilby Substation in Fort Collins, a distance of approximately 2.4 miles. This line is constructed as an underground transmission line in a concrete-encased ductbank and utilizes three power cables, one per phase. The underground ductbank includes seven underground vaults along its alignment for cable pulling and splicing purposes. These underground vaults are spaced approximately 1,300 feet to 1,900 feet apart. We understand that Phase I was placed underground due to the difficulty in locating and obtaining a viable R/W for an overhead line. Figure 3-1 includes a cross section of the underground line, illustrating the ductbank configuration. Figure 3-2 is a depiction of the underground vaults. The 230-kV power cable is a jacketed cable consisting of a solid dielectric insulation, referred to as XLPE, around a stranded copper wire (2000 kcmil) as the electrical conductor. The 230-kV line transitions from overhead construction to underground construction by utilizing a tubular steel riser structure outside Trilby Substation. Section 3 2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure 3-1. Underground 230-kV Transmission Ductbank Cross-Section Figure 3-2. Underground 230-kV Transmission Ductbank Vault (24’Lx8’Wx8’H) We understand that Phase I was completed for a total cost of $11,583,000, or $4.8 Million per mile. These costs included engineering, permitting, right-of-way, materials, contract construction, construction management, and interest during construction. DIXON CREEK – HORSESHOE LINE CONFIGURATION File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 3 3.1.2 Phase II – Trilby Substation to Horsetooth Tap Phase II from Trilby Substation to Horsetooth Tap consists of rebuilding an existing Tri-State Generation & Transmission (G&T) 115-kV transmission line, combined with the Platte River 230-kV transmission line for a distance of approximately 3.1 miles. This double circuit line is constructed as an overhead line utilizing steel poles. The line consists of 31 steel poles with six power cables, three on each side of the pole, as electrical conductors and one optical ground wire near the top of the pole for both lightning protection and communication purposes. The overhead line is primarily located within public road R/W, routed along West Trilby Road for approximately two-thirds of its length. The remaining third of the line is routed cross-country mostly in the Horsetooth Reservoir Area. Phase II uses “tangent” structures as shown in Figure 3-3. It is a single, self- supporting steel pole structure made of weathering steel and is mounted on a drilled concrete pier foundation. It uses “braced-post” insulator assemblies that extend 8 to 10 feet from the face of the pole, with six total phase positions: three on one side for Platte River and three on the other side for Tri-State G&T. The steel poles range in height from 80 to 135 feet tall, with roughly seventy percent of the poles being 90 feet. The 230-kV power cable consists of a bare cable with aluminum wires stranded over steel wires, referred to as ACSR, as the electrical conductor. The drilled pier foundations range in size from 6 to 9 feet in diameter and 18 to 42 feet in depth. Figure 3-3. Double-Circuit 230-kV Transmission Line Structure Section 3 4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Phase II was completed for a total cost of $3,438,000 or $1.1 Million per mile. These costs included engineering, permitting, right-of-way, materials, contract construction, construction management, and interest during construction. 3.1.3 Phase III – Horsetooth Tap to Dixon Creek Substation Phase III from Horsetooth Tap Switching Station to Dixon Creek Substation consists of rebuilding an existing Western 115-kV transmission line to 230-kV standards, combined with the Platte River 230-kV transmission line for a distance of approximately 3.7 miles. This double-circuit line is planned to be constructed as an overhead line utilizing a total of 34 steel poles similar to those used for Phase II. The line is routed within the existing 75-foot R/W for Western’s 115-kV line. For approximately two-thirds of the length of Phase III, the Western R/W is routed upslope from, and generally along West County Road 38E to near the Spring Canyon Dam. The line section along West County Road 38E utilizes 20 poles with design spans of about 400 to 850 feet, with one span adjacent to the dam of over 1,300 feet. The structures for this portion of Phase III range in height from 90 feet to 120 feet with the majority of poles being from 100 feet to 115 feet tall. From near the Spring Canyon Dam, the route turns into and passes through the Pineridge Natural Area for approximately 1.4 miles. This portion of Phase III proceeds from the area of Spring Canyon Dam, generally north, passing near and to the east of a group of homes in Burns Ranch subdivision and then continues to the Dixon Creek Substation. This portion of Phase III utilizes 14 steel poles with design spans of about 500 to 660 feet. Structures in the Pineridge Natural Area range in height from 85 feet to 105 feet with the majority of poles being from 90 to 95 feet tall. This design for Phase III was adopted principally to fit in the existing 75-foot Western R/W, and the typical design spans are suited to fitting in this corridor. See Table 3-1 for a summary of level ground spans, heights, and R/W needs. Table 3-1 Span, Height, and Right-of-Way Information Notes: 1 Based on level ground spans, 1272 ACSR Bittern conductor and loading criteria from Phase III. 2 Right-of-way width based on NESC Rule 234 clearances to the edge of right of way plus some margin for a nominal width. Other considerations like working room and access may increase this dimension. Span (ft) Height (ft above ground) Minimum Right of Way Width (ft) 600 87 75 700 92 75 800 97 75 900 102 100 1000 108 100 1100 115 100 DIXON CREEK – HORSESHOE LINE CONFIGURATION File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 5 The foundations range in diameter from 6 feet to 12 feet with the most common diameter 7 feet. The foundation depths range from 17 feet to 41 feet with the most common depths being 19 feet and 24 to 26 feet. These foundations are larger than the foundations for the existing Western H-frame structures because each single pole and its footing need to withstand the total load while the H-frame splits the load between two foundations. 3.2 Phase III Schedule The schedule established by Platte River for completion of the entire Dixon Creek Substation to Horseshoe Substation 230-kV circuit is May 2012 in order to have the interconnection in place prior to when summer peak loads occur. Phase III is the final segment necessary to complete the project. We understand that steel poles for Phase III have been fabricated and delivered to the project site and a construction contract has been negotiated and construction is ready to begin. Below in Table 3-2 is an estimated schedule for completion of Phase III as presently proposed by Platte River. Table 3-2 Implementation Schedule Phase III Existing Contract Phase Start Finish Cumulative Restart Construction 10/19/11 Mobilize 10/19/11 10/26/11 Construct Foundations 10/24/11 4/13/12 Erect Poles and Frame 1/2/12 5/5/12 String, Sag, and Clip 2/6/12 5/25/12 Test and Commission 5/7/12 5/28/12 152 days Notes: 1. Based on favorable winter construction conditions. Construct difficult to reach and high ground first. 2. Based on willingness and availability of Phase III contractor to renegotiate or restart their contract. 3.3 Phase III Cost Cost information provided by Platte River for Phase III indicates a total material and construction cost of $7.1 Million. Other costs for engineering, permitting, right-of- way, construction management, and interest during construction are estimated to be about 20% of the material and construction cost, resulting in a total Phase III cost of $8.5 Million or $2.3 Million per mile. The significant cost difference between Phase II and Phase III may be attributed to the fact that the majority of Phase II is located adjacent to public roads and a majority of Phase III is located in rough terrain with difficult access, with helicopter construction planned for some of these areas. Section 3 6 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 3.4 Phase III Environmental Impacts Transmission line construction activities that result in physical ground disturbance may result in environmental impacts to natural and biological resources and include access roads/trails for moving materials and construction crews, excavation for foundations, assembly and erection of structures, and wire stringing. Construction period impacts can often be mitigated through adoption of storm water and erosion control practices as well as re-vegetation of disturbed areas following construction activities. Other potential environmental impacts during the operating life of the transmission facilities include ground disturbance for any periodic maintenance activities, avian collisions with wires, and the aesthetic impact of the visual presence of man-made features in the natural environment. This project is a replacement of an existing line. Impacts may be less than for a project involving a new line on a previously undisturbed easement. Platte River completed research into environmental conditions in 2008 and provided this information to Western for use in their National Environmental Policy Act (NEPA) process. Subsequently Platte River conducted additional literature research and field survey in early September 2011 related to biological resources in the vicinity of the Western R/W from Dixon Creek Substation to Horsetooth Tap. A study of cultural resources from Dixon Creek to Horseshoe was conducted in 2008. A second survey was conducted in the vicinity of Spring Creek (Site 5LR205) near the Western R/W in September 2011. In order to address aesthetic impacts in this study a number of photo simulations were prepared for the proposed project and several alternatives routes. Information resulting from the above efforts is summarized below for Phase III. 3.4.1 Biological Resource Impacts The biological review for Phase III encompassed an area 150 feet wide, centered on the existing Western transmission line. This review considered federal and state threatened and endangered species as well as species of concern identified by Larimer County and the City of Fort Collins. The 2011 field survey confirmed the findings of earlier studies, related to federal threatened and endangered species, determining that these species or their preferred habitat are not present in the R/W, and construction and operation of the transmission line would not have adverse environmental impacts to threatened and endangered species. State listed species of concern or potential habitat were identified during the environmental studies for the proposed transmission line. The relevant species are the bald eagle, black-tailed prairie dog, western burrowing owl, and migratory and nesting birds. No eagle nests were observed, but the Colorado Division of Parks and Wildlife did note their primary concerns were potential effects to bald eagle foraging habitats and collision impacts. The R/W for Phase III does include a black-tailed prairie dog DIXON CREEK – HORSESHOE LINE CONFIGURATION File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7 colony for approximately 1,700 feet of its length. Mitigation measures for this species may be recommended by the City of Fort Collins. Western burrowing owls are closely associated with prairie dog colonies however the 2011 surveys found no evidence of burrowing owls and there are no known recent or historical occurrences of owls at this site. A number of native avian species were observed within the R/W and there is potential habitat for various birds protected by the Migratory Bird Treaty Act. For construction during the breeding season – April through September – surveys should be conducted to determine if any nests are present in the R/W. The City of Fort Collins has identified butterfly and plant communities as species of concern. The R/W includes suitable habitat for six butterflies of concern and four plants of concern. Of the four plant species, only Bell’s Twinpod was observed in three separate populations, two of which may be directly impacted by construction. Efforts will focus on avoiding impacts during construction. If avoidance is not possible, the City will develop mitigation plans such as relocation of the plants to suitable habitat outside of the project area or removal and replanting in the same location after the completion of the project. In addition two sensitive natural plant communities were identified in the R/W, Xeric Tallgrass Prairie and Mountain Mahogany-Skunkbush/Big Bluestem Shrubland. The Xeric Tallgrass Prairie is an area roughly 275 feet by 350 feet and the Mountain Mahogany-Skunkbush/Big Bluestem Shrubland encompasses the entire R/W from Spring Canyon Dam south to Horsetooth Tap. The City may have recommendations to minimize impacts to these vegetation communities during construction. 3.4.2 Aesthetic Impacts The aesthetic impact of a transmission facilities can be a highly subjective determination. The elements that affect aesthetic impact include the scenic quality, viewer sensitivity and the viewing distance. The scenic quality of the area being viewed is created by a combination of the physical features, vegetation, color, adjacent scenery and scarcity. The viewer sensitivity is related to the value the viewing public places on the visual landscape as well as the extent or frequency that the landscape is viewed by the public. The viewing distance relates to how prominent a transmission facility will be in the visual landscape as determined by whether the line is in the foreground, middleground or background. The aesthetic impact of a transmission line is created when a view shed is disrupted; when the structures are out of proportion with the surrounding environment; or when the structures contrast with the landscape in the background, for example the line is prominent on the skyline. The Pineridge Natural Area includes varied landforms and a high scenic quality along with native vegetation. The area also contains manmade features in the form of an existing transmission line. Viewer sensitivity might be considered relatively high as this is an area often viewed during recreational activities and easily accessible to a large population. Other existing impacts to scenic quality include bike and pedestrian trails and adjacent land owner developments. Section 3 8 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 In terms of the viewing distance and how to gauge the prominence of transmission facilities, photographs of the existing landscape and photo simulations of the proposed Phase III line were prepared. Figure 3-4 illustrates the existing Western 115-kV H-frame transmission line looking south from a recreational trail near Burns Ranch subdivision into the Pineridge Natural Area. Figure 3-4. Existing Western 115-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) Figures 3-5 illustrates Platte River’s proposed double-circuit, tubular steel pole 230- kV transmission line structures located in the existing Western transmission line R/W. DIXON CREEK – HORSESHOE LINE CONFIGURATION File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 9 Figure 3-5. Proposed Platte River 230-kV Tubular Steel Pole Transmission Line (Looking South in Pineridge Natural Area) File: 005455/3105111014-1000 Section 4 ALTERNATIVE STRUCTURE CONFIGURATIONS 4.1 Range of Options Considered In evaluating alternatives to the proposed construction for Phase III in the Pineridge Natural Area, the first consideration was to identify modifications which could potentially be incorporated along the route identified for Phase III. The three primary options identified were the use of alternative structure configurations, increasing span lengths to reduce the number of structures, or utilizing underground construction. This section of the report addresses alternative structure configurations. 4.2 Painted Structures Platte River’s proposed single pole structures are made of weathering steel which overtime darkens to a deep brown color and is thought to resemble the appearance of wood poles when viewed from a distance. When viewed against a light colored background or against the skyline the dark color of these structures may be more prominent than if an alternative pole color was used. There are two other potential surface treatments used for utility structures, these being galvanized steel or painted. In all cases pole surface treatment is an important element of the design for transmission lines as these provide protection against corrosion of the steel pole material. Weathering steel by its nature forms a protective cover that limits pole corrosion and in the event of surface scratches or damage is self healing. Galvanized steel provides a thin zinc coating that is corrosion resistant however surface scratches or damage will expose the underlying steel to corrosion damage. Maintenance for these instances entails cleaning the damaged area and applying a zinc rich paint. Painted steel provides a thin coating that is corrosion resistant however surface scratches or damage will expose the underlying steel to corrosion damage. Maintenance for these instances entails cleaning the damaged area and applying paint. In some instances combinations of these protective coatings are utilized, for example galvanized steel poles with a painted coating. It is important to note that due to the manner in which weathering steel develops a protective layer, the use of paint over weathering steel is not an option. This means that if painted poles were to be used for the Phase III structures it is not feasible to use the poles already procured by Platte River. Therefore use of this option requires construction of a temporary wood pole line while procurement of new poles proceeds and the costs for the structures currently in hand would be a sunk cost. Galvanized steel has a shiny appearance that can be highly visible in sunlight or bright light conditions. This alternative surface treatment is not anticipated to lessen the aesthetic impact of tubular steel poles in the Pineridge Natural Area. Section 4 2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 There are a wide range of color options to choose from for painted structures. Typically the color is selected to allow the structures to blend into the environment where they are installed. This selection is difficult since the color of the viewing background will vary depending on lighting conditions, seasons and vantage point. A color commonly used in the industry tends to be in the gray spectrum. Figure 4-1 is a photo simulation of the proposed Platte River single pole structures painted light gray. Figure 4-1. Photo Simulation Painted Single Steel Poles 4.3 Alternative Structure Types There are two other basic structure types that are utilized in the industry, namely lattice towers or H-frame structures. When considering these two structure types it was noted that a lattice tower would be very similar to the proposed steel poles from a circuit configuration and structure height standpoint as shown in Figure 4-2. From a visual aesthetic perspective lattice towers may have advantages when they will be in more distant or background views, due to their ability to blend with the landscape where viewers are essentially “looking through” the structures. Conversely when lattice towers are in foreground views they are seen as a bulkier structure than single steel poles and may convey a sense that is more of an industrial type facility. For these reasons the lattice tower alternative was not considered viable for the Pineridge Natural Area. ALTERNATIVE STRUCTURE CONFIGURATIONS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 3 Source: ATC Figure 4-2. Double-Circuit 230-kV Lattice Tower The H-frame structure type was determined a reasonable candidate for use in the Pineridge Natural Area and is further analyzed below. 4.4 Double-Circuit H-Frame Figure 4-3 depicts a double-circuit 230-kV H-frame structure. This structure is similar in form to the structures in place today on the Western 115-kV transmission line. The double-circuit H-frame has an additional crossarm for the second circuit. Although of the same general form as the existing line, the structure is generally larger, reflecting both the higher voltage (230-kV) of Phase III as well as the increased physical loadings the structure will need to support from the greater number of wires being carried. Section 4 4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure 4-3. Double-Circuit 230-kV H-Frame The double-circuit 230-kV H-frame will have a greater leg spacing and longer crossarms than the existing Western line. It utilizes V-String insulator assemblies that serve two main purposes: they provide increased holding capacity for the heavy vertical loads expected on the wires, and they restrain insulator positions so they do not swing out and require additional R/W width. The width of this structure is 60 feet, based on 11-foot spacing from each 230-kV phase conductor to each pole, and considering pole width and arm extension beyond the outside phase wires. The structure height above ground will depend on many factors such as span length, conductor tension limits, and terrain. For data selected for the Phase III portion of the Dixon Creek - Horseshoe 230-kV Line, we estimate that the structure heights will range from 85 to 100 feet corresponding to level ground span lengths from 600 feet to 900 feet. See Table 4-1 for a summary of span, structure height, and R/W information. Table 4-1 230-kV H-frame Span, Height, and Right-of-Way Information Span (ft) Height (ft above ground) Minimum Right of Way Width (ft) 600 84 75 700 89 75 800 95 75 ALTERNATIVE STRUCTURE CONFIGURATIONS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 5 900 102 75 1000 110 100 Notes: 1 Based on level ground spans, 1272 ACSR Bittern conductor and loading criteria from Phase III. 2 Right of way width based on NESC Rule 234 clearances to the edge of right of way plus some margin for a nominal width. Other considerations like working room and access may increase this dimension. The structure shown in Figure 4-2 is representative of a “tangent” structure, which is the prevalent structure type in the Pineridge Natural Area. Tangent structures are used on straight sections of transmission lines; therefore, where a line angle (turning point, or direction change) does occur, variations of this structure will have to be implemented similar to the three pole structures in place on the existing Western line. It is possible to select any three of the six conductor positions to belong to Platte River with the other three belonging to Western. In actuality, two logical configurations exist. First, all top arm positions could belong to one utility with the bottom arm positions belonging to the other utility. This makes the upper circuit difficult to reach safely without taking an outage on the lower circuit. The other configuration is to assign one set of outer positions to one utility with a middle position and with the other utility taking the remaining three positions. This makes access to the outside conductors easier and may only entail one circuit outage. Access to the middle phase however is still an issue and may require an outage of the other utility’s circuit. This is not expected to be a frequent maintenance need, but should be anticipated. This structure is not a Platte River or Western standard. As mentioned there is an operational issue related to working on one of the circuits. It is very dangerous to work on or around 230-kV circuits and requires specialized “hot-line” maintenance techniques that the crews of the two utilities may not be set up to employ. 4.4.1 Schedule If this structure type were adopted by Platte River and Western for the Pineridge Natural Area, the construction for the portion of Phase III from Horsetooth Tap to the area of the Spring Canyon Dam could proceed as presently planned. However, the redesign and procurement process for roughly 40% of the line must be started anew. This redesign entails verification of structure dimensions, developing loading and concept drawings for the double-circuit steel H-frames to solicit bids from steel structure manufacturers. This redesign and bid process through selection of a structure supplier might take an estimated 3 months. Once the structure supplier is established an additional 1 to 2 months would be required to finish calculations, steel drawings, and approval of shop drawings. Fabrication of the structures and delivery requires another 4 to 6 months depending on plant capacity and schedules. Overall this redesign and procurement process is expected to be on the critical path and is estimated to entail a schedule time of 8 to 11 months. Assuming that the original contractor for Phase III would be retained to construct this variation it would be necessary to modify the construction drawings and contract for this change. This would occur in parallel with the new steel procurement effort described above. Section 4 6 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 This structure change results in additional work not required for the single steel poles; therefore, construction of the segment through the Pineridge Natural Area is anticipated to take longer than if the single steel poles were used. The additional work consists of digging and placing an additional foundation at each structure location since each structure has two steel poles instead of one (current design). The double- circuit H-frame will also be much heavier than the single pole structures of the current design and would likely require additional equipment and crew time to set the structures. In total the construction time for this segment is estimated to be 6 to 7 months. Additional delay may also occur if new environmental studies are required due to the redesign or expansion of the easement. Based on the additional time for material procurement and for construction of the double-circuit H-frames, it appears this option would not be completed in accordance with the in-service date for Phase III, thereby necessitating the establishment of a temporary connection from the area of Spring Canyon Dam to Dixon Creek. As further described in Section 8, it may be possible to install a temporary 230-kV wood pole line along the proposed route (within the Pineridge Natural Area). 4.4.2 Cost To estimate the costs for use of double-circuit H-frame structures, it was assumed a typical H-frame will be 95 feet tall, and will sit atop two concrete pier foundations. The foundations are anticipated to be about 6 to 7 feet in diameter each and 10 to 15 feet deep. Table 4-2 summarizes the cost for use of double-circuit H-frame structures versus the cost for the proposed Project. As shown, no change in cost from the proposed route for the south portion of this alternative is expected. The cost estimate includes: 1. the material and construction costs for the southern portion of Phase III, as proposed by Platte River; 2. the material and construction costs for the northern portion of Phase III through Pineridge Natural Area, as indicated above; 3. other project development costs such as engineering, permitting, right-of-way, construction management, etc.; 4. the cost of re-engineering and associated permitting for the northern portion of the route; 5. the cost of engineering, permitting, materials, etc. expended for the proposed Project that will be of no value to the Project if double-circuit H-frame structures are used; and 6. the cost to install the temporary 230-kV line. ALTERNATIVE STRUCTURE CONFIGURATIONS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7 Table 4-2 Cost Comparison Double-circuit H-frame Structure Alternative Alternative Proposed Project Engineering Costs 1 $0.52 million $1.42 Million South Section Material and Construction: Horsetooth Tap to Spring Canyon Dam $5.30 Million $5.30 Million North Section Material and Construction: Spring Canyon Dam to Dixon Creek Substation $2.62 Million $1.80 Million Sunk Costs $0.59 Million $0 Temporary 230-kV Wood Pole Line 2 $0.86 Million $0 Total $10.96 Million $8.52 Million Project Cost Differential + 2.44 Million (29% Increase) 1 Engineering Costs include incurred and planned costs for the Proposed Project, including engineering, permitting, right-of-way, construction contract administration/construction management, and interest during construction. Engineering Costs are estimated to be approximately 20% of the material and construction costs, based on Phase I and Phase II. 2 Temporary Line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Sunk costs for the double-circuit H-frame structure alternative include the proportionate amount of Engineering Costs for the proposed Project that will not be constructed, as well as the cost of the steel pole structures already procured and received by Platte River. 4.4.3 Biological and Natural Resource Impacts Many of the environmental impacts for use of an H-frame structure type are anticipated to be the same as for the proposed single steel poles. For example, the number and location of access roads is expected to be very similar for the two structure types. Therefore, the discussion below is limited to environmental impacts that are in addition to what would occur if the proposed project were built. The main additional impact due to the use of H-frame structures is related to foundation construction. The H-frame structure type will require two foundations as opposed to the single foundation of the steel poles. In effect, this doubles the area of ground disturbance and potential impacts to sensitive resources as compared to the proposed project. However, the area disturbed for each foundation will be relatively confined such that although more ground is disturbed, the total area disturbed is not expected to cause significant impacts. In terms of specific plant or animal species impacts, the structure locations can typically be adjusted for short distances so that their footprint avoids an impact. This is similar for the single steel poles. 4.4.4 Aesthetic Impacts In order to compare aesthetic impacts for utilizing a double-circuit H-frame versus the proposed single steel poles there are two or three areas where the H-frame structures Section 4 8 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 present a different visual element. The 230-kV H-frame will be taller and have more bulk than the existing Western H-frame, but they will be shorter than the proposed single steel poles. The 230-kV H-frame could be considered “wider,” or not as slender, when compared to the proposed single steel poles since it has two legs each of which are anticipated to be of a large diameter. In addition, the 60-foot long heavy crossarm on the 230-kV H-frame is expected to add to a sense of massiveness for these structures. Looking at a transverse view, a person would see differing levels of wires for the different structure configurations. The Western H-frame has two different levels of wire with 5 wires total, the proposed steel poles would have four different levels of wire with 8 wires total, and the double-circuit H-frame would have three different levels of wire with 8 wires total. To provide a sense of how the different structure types may appear, the following figures illustrate the existing Western line and the potential single steel poles or H-frame. Figure 4-4. Existing Western 115-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) ALTERNATIVE STRUCTURE CONFIGURATIONS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 9 Figure 4-5. Photo Simulation: Double-Circuit 230-kV Tubular Steel Pole Transmission Line (Looking South in Pineridge Natural Area) Figure 4-6. Photo Simulation: Double-Circuit 230-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) Section 4 10 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 4.5 Single-Circuit 230-kV H-Frame Electrically, it may be possible to provide the required capacity and reliability by rebuilding the existing Western 115-kV H-Frame transmission line from Dixon Creek to Horsetooth Tap as a 230-kV line without adding a second circuit. Figure 4-7 in illustrates the relative sizes between a 115-kV and 230-kV single-circuit H-frame. Figure 4-8 is a photo simulation of this type of line in the Pineridge Natural Area. Figure 4-7. Western 230-kV and 115-kV H-Frame Transmission Line Structures ALTERNATIVE STRUCTURE CONFIGURATIONS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 11 Figure 4-8. Photo Simulation: Single-Circuit 230-kV H-Frame Transmission Line (Looking South in Pineridge Natural Area) This option would require installation of a 230-115 kV substation at the Horsetooth Tap location, including 230 and 115 kV breakers, at least one 230-115 kV autotransformer, and associated equipment and relaying. The substation would require the acquisition of approximately 5 acres of land. The infrastructure costs (excluding land) for this substation would be around $10 million. An aerial photo of the Fordham 230-115 kV Substation in Longmont is shown in Figure 4-8 as an example of what the substation might look like. Section 4 12 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure 4-8. Existing Fordham 230-115 kV Substation in Longmont Platte River would need to study this option to determine if it would meet the long- term needs of both Platte River and Western. When this option was discussed with Western, they provided the following comments:  Western's position would be that they would have to own the entire line and then grant a contractual capacity right to Platte River. Western would not accept an arrangement where Platte River owned the line and granted Western capacity rights. (This also applies to any reroute option that Western would be a party to.)  Western would expect to retain no less than the full capacity of the current 115-kV line in a new 230-kV circuit initially and the right to recall up to the full capacity of the 230-kV circuit when system studies or other factors show Western has a need. Based on the comments from Western, it is anticipated Platte River would not want to make this kind of an investment without acquiring ownership and long-term firm capacity to serve the Cities’ needs. Further, this arrangement would require Platte River to pay Western’s transmission wheeling rate for transmission outages in the Loveland area. The worst case scenario is estimated to be approximately $16,000 per day in 2012. The transmission outage scenarios could be routine maintenance of a line or terminal equipment, forced outages that are sustained by equipment failure, or outages associated with system construction activities. The impacts of the single-circuit H-frame line would be similar to those of the double- circuit line, but the substation would add additional biological, natural resource, and aesthetic impacts. Due to these obstacles, replacement of the existing 115-kV line ALTERNATIVE STRUCTURE CONFIGURATIONS File: 005455/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 13 from Dixon Creek to Horsetooth Tap with a single-circuit 230-kV H-frame line was not considered as a viable alternative for Platte River’s purposes. File: 00545503/3105111014-1000 Section 5 SPAN LENGTH INCREASE 5.1 Interrelationship of Span Length and Structure Height Another alternative considered as an adjustment to the proposed construction for Phase III was to potentially modify the line through the use of longer spans. It is technically feasible to lengthen overhead spans so that there are fewer structures in the Pineridge Natural Area. However, it is important to recognize a basic axiom of transmission line design: longer spans mean taller structures and/or higher conductor tensions. An option would be to utilize the same conductor and pole configuration as planned for the Phase III project to span 1,300 feet. This is anticipated to reduce the number of structures in the Pineridge Natural Area from 13 to 6 but would require poles on the order of 145 feet above ground. Not only would they be tall, but they would likely be more massive structures with base diameters on the order of 10 feet with correspondingly large pier foundations. It may also be difficult for all of the construction activities to be completed within the confines of the existing 75 foot easement. In combination with the idea of increasing the span length the concept of utilizing stronger standard conductors, which could be pulled up tighter, reducing sag and structure height was considered. For instance, substituting a 1272 kcmil 54/19 ACSR (code name “Pheasant”) conductor for the planned “Bittern” conductor results in about a 20 foot reduction in pole height for a 1,300-foot span. Other special conductor types were also considered. One type, ACCR (“Aluminum Conductor Composite Reinforced”), has reportedly been used by Platte River on the Timberline – Harmony 230-kV line. The review of the special conductor as an alternative determined that pole heights could potentially be reduced an additional 5 feet. This alternative was not considered viable in view of the fact these type conductors may be 2.5 times the cost of standard conductors and result in a relatively small increment of height reduction. A result of using stronger and higher tensions is that this places greater loads on termination and line angle structures, which translates to larger structures. Since the design criteria for the proposed line includes load cases for broken conductor, any increase in conductor tensions will also have an impact on the size of tangent structures. So even though the dimensional design of the tangent structure pole top may not change, the size of the poles (i.e., thickness of steel or diameter of shaft at the base of the pole) will almost certainly increase. If the structure loading and size increase there will also be corresponding changes to the foundations. Section 5 2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 5.2 Schedule If longer spans and taller structures were adopted by Platte River and Western for the Pineridge Natural Area, the construction for the portion of Phase III from Horsetooth Tap to the area of the Spring Canyon Dam could proceed as presently planned, utilizing the current structures and conductor. However, the redesign and procurement process for roughly 40% of the line must be started anew. This redesign entails developing a new line layout, verification of structure dimensions, and developing loading and concept drawings for the new taller steel poles to solicit bids from steel structure manufactures. This redesign and bid process through selection of a structure supplier might take an estimated 3 months. Once the structure supplier is established an additional 1 to 2 months would be required to finish calculations, steel drawings and approval of shop drawings. Fabrication of the structures and delivery requires another 4 to 6 months depending on plant capacity and schedules. Overall this redesign and procurement process is expected to be on the critical path and is estimated to entail a schedule time of 8 to 11 months. Assuming that the original contractor for Phase III would be retained to construct this variation it would be necessary to modify the construction drawings and contract for this change. This would occur in parallel with the new line layout and steel procurement effort described above. The structure changes due to increased span lengths results in fewer structures which may reduce the work through the Pineridge Natural Area, however, this may be partially offset due to the much larger foundations and poles which will entail additional work compared to the proposed structures. Overall the construction time for this segment may be relatively close to the time planned under the proposed Project. In total the material procurement and construction for this alternative is estimated to be 9 to 10 months. Additional delay may occur if new environmental studies are required due to the redesign of the line with longer spans. Based on the additional time for material procurement of the taller steel poles it appears this option would not be completed in accordance with the in-service date for Phase III, thereby necessitating establishing some type of temporary connection from the area of Spring Canyon Dam to Dixon Creek Substation. 5.3 Cost To estimate the costs for use of longer spans we first considered utilizing the same conductor as the proposed Project. Due to the increased sags the structures would need to be 145 feet tall. Utilizing a conductor that can be installed at higher tensions (less sag) the structure heights can be reduced by about 10 feet (135 feet tall). The taller structures and increased span lengths significantly increase the foundation loadings resulting in foundations estimated to be about 10 feet in diameter and 25 feet deep. The higher strength conductor will also be more costly than for the proposed Project but the additional cost to purchase the stronger conductor was warranted as the SPAN LENGTH INCREASE File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 3 reduction in structure height results in structure and foundation cost savings that exceed the additional conductor costs. The conductor installation cost was estimated to be about the same for either conductor type. Table 5-1 summarizes the cost for use of longer spans versus the cost for the proposed Project. As shown, no change in cost from the proposed route for the south portion of this alternative is expected. The cost estimate includes: 1. the material and construction costs for the southern portion of Phase III, as proposed by Platte River; 2. the material and construction costs for the northern portion of Phase III through Pineridge Natural Area, as indicated above; 3. other project development costs such as engineering, permitting, right-of-way, construction management, etc.; 4. the cost of re-engineering and associated permitting for the northern portion of the route; 5. the cost of engineering, permitting, materials, etc. expended for the proposed Project that will be of no value to the Project if longer span lengths are used; and 6. the cost to install the temporary 230-kV line. Table 5-1 Cost Comparison Long Span Alternative Long Span Alternative Proposed Project Engineering Costs 1 $1.48 million $1.42 Million South Section Material and Construction: Horsetooth Tap to Spring Canyon Dam $5.30 Million $5.30 Million North Section Material and Construction: Spring Canyon Dam to Dixon Creek Substation $2.09 Million $1.80 Million Sunk Costs $0.59 Million $0 Temporary 230-kV Wood Pole Line 2 $0.86 Million $0 Total $10.32 Million $8.52 Million Project Cost Differential + $1.80 Million (21% Increase) 1 Engineering Costs include incurred and planned costs for the Proposed Project, including engineering, permitting, right-of-way, construction contract administration/construction management, and interest during construction. Engineering Costs are estimated to be approximately 20% of the material and construction costs, based on Phase I and Phase II. 2 Temporary Line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Sunk costs for the longer span length alternative include the proportionate amount of Engineering Costs for the proposed Project that will not be constructed, as well as the cost of the steel pole structures already procured and received by Platte River. Section 5 4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 5.4 Biological and Natural Resource Impacts In general the type of environmental impacts for the long span alternative are anticipated to be the same as for the proposed single steel poles, for example the amount and location of access roads is expected to be very similar. However the area of disturbance and amount of environmental impacts are anticipated to be less than for the proposed Project due to constructing half as many foundations and structures. In terms of specific plant or animal species impacts, the structure locations can typically be adjusted for short distances so that their footprint avoids an impact. This is similar for the proposed Project. 5.5 Aesthetic Impacts If longer spans are used there will be approximately half the number of support structures as in the proposed Project within the Pineridge Natural Area. The longer span structures will likely appear as more massive than the proposed project since they will be approximately 50% taller with noticeably larger diameters (10 feet versus 5 feet). In addition the poles will be higher in the air and as such may be more visible above the horizon – against the sky. Due to the height and size of these structures it is possible that an observer near Dixon Creek Substation may be able to see full structures in the foreground and the tops of all of the structures as far as Spring Canyon Dam. Although the poles will be at a greater spacing the wires may not appear different to the casual observer since they will be as near to the ground at mid-span as they are for the proposed Project. File: 00545503/3105111014-1000 Section 6 PARTIAL UNDERGROUND ALTERNATIVE ALONG CURRENT ROUTE 6.1 Description This alternative utilizes underground transmission for the Platte River 230-kV circuit from the area near the base of Spring Canyon Dam into and through approximately 1.4 miles of the Pineridge Natural Area to Dixon Creek Substation. For approximately 2.4 miles, from Horsetooth Tap to the area near Spring Canyon Dam, the circuit would utilize overhead construction, as currently proposed by Platte River. As noted in Section 2 of this report, Western is opposed to undergrounding their circuit so it would remain above ground for all of Phase III, including through Pineridge. The underground portion of the Platte River 230-kV line would consist of a single- circuit 230-kV underground ductbank with underground vaults, similar to what was utilized for Phase I of the Project and as illustrated in Figures 3-1 and 3-2. Short sections of the ductbank may be constructed using directional drilling or boring techniques in order to mitigate specific local impacts. The ductbank will be located to one side of Western’s existing 75-foot transmission line R/W. Ideally, the ductbank would be located inside the existing Western R/W boundaries, but to be acceptable to Western, it would need to allow for Western’s proposed rebuild of their overhead facilities in the future. Therefore, a new easement may be required from the City of Fort Collins outside of the existing Western R/W for the Platte River underground facilities and preferably outside of any proposed expansion of the Western R/W to accommodate their rebuilt overhead facilities. However, the current Natural Areas Easement Policy prohibits the granting of new easements that allow for overhead lines within any City-owned Natural Area. Since the easement would be for an underground line it appears that this policy may not apply. 6.2 Schedule Table 6-1 identifies the estimated implementation schedule for this route alternative. Assuming favorable winter construction conditions and use of the current Phase III design of the overhead line for the south section, the contractor will re-start work on the 2.4-mile south section on October 19, 2011. Finally, this schedule assumes that environmental studies and associated mitigation plans could be completed and approved by the appropriate authorities within this schedule. Section 6 2 SAIC Energy, Environment & Infrastructure, LLC Alternative Report Section 6_final draft.docx 10/6/11 Table 6-1 Implementation Schedule Partial Underground in Pineridge Natural Area Phase Start Finish Cumulative Restart Construction for South Segment 10/19/11 Mobilize 10/19/11 10/26/11 Stake / Construct Piers 10/24/11 2/15/12 Erect Poles and Install Framing 1/2/12 3/31/12 String, Sag and Clip Conductor 2/01/12 4/30/12 Finalize Alignment for North Segment 10/31/11 11/30/11 Final Design 12/01/11 4/15/12 Material Procurement for North Segment 3/15/12 11/15/12 Design for Temporary Line 11/01/11 1/31/12 R/W acquisition for Temporary Line 12/01/11 2/29/12 Material Procurement for Temporary Line 1/01/12 2/29/12 Modify Construction Contract 1/15/12 2/15/12 Construct Temporary Line NTP 2/20/12 Set Poles and Install Framing 3/01/12 4/15/12 String, Sag and Clip Conductor 4/16/12 5/15/12 Test and Commission 5/16/12 5/31/12 Procure Construction Contract for UG 4/16/12 6/15/12 UG Construction NTP 6/22/12 Mobilize 7/01/12 7/15/12 Dixon Creek Substation Modifications 7/16/12 9/15/12 Ductbank Construction 9/16/12 11/15/12 Cable Installation 11/16/12 12/31/12 Test and Commission 1/01/13 1/15/13 404 days Due to the lead time for procurement of 230-kV underground cable, construction of this alternative will not be complete by the required in-service date. As a result, a temporary 230-kV transmission line will be required (by May 2012 and remain in service) until the underground portion of this route can be completed. Refer to Section 8 of this report for a discussion of details associated with possible use of a temporary 230-kV line. 6.3 Cost Table 6-2 illustrates the difference in cost between the proposed Phase III overhead double-circuit steel single pole transmission line and the cost estimated for Phase III PARTIAL UNDERGROUND ALTERNATIVE ALONG CURRENT ROUTE File: 000000/99-99999-99999-9999 SAIC Energy, Environment & Infrastructure, LLC 3 with undergrounding construction for the northern 1.3 miles of Phase III from the base of Spring Canyon Dam to Dixon Creek Substation (through the Pineridge area). The cost estimate includes: 1. the material and construction costs for Phase III as proposed by Platte River; 2. other project development costs such as engineering, permitting, construction management, etc. 3. the cost of re-engineering and associated permitting for the northern portion of the route; 4. the cost of engineering, permitting, materials, etc. expended for the proposed Project that will be of no value to the Project if the underground alternative is selected; and 5. the cost to install the temporary 230-kV line. Table 6-2 Cost Comparison Partial Underground Alternative Partial UG Alternative Proposed Project Engineering Costs 1 $1.74 Million $1.42 Million South Section OH Material and Construction: Horsetooth Tap to Spring Canyon Dam $5.30 Million $5.30 Million North Section UG Material and Construction: Spring Canyon Dam to Dixon Creek Substation $6.80 Million $1.80 Million Sunk Costs $0.59 Million $0 Temporary 230-kV Line 2 $0.86 Million $0 Total $15.29 Million $8.52 Million Project Cost Differential +6.77 Million (79% Increase) 1 Engineering Costs include incurred and planned costs for the Proposed Project, including engineering, permitting, right-of-way, construction contract administration/construction management, and interest during construction. Engineering Costs are estimated to be approximately 20% of the material and construction costs for overhead facilities and 10% for underground facilities (given the higher per mile cost of construction), based on Phase I and Phase II. 2 Temporary Line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Costs of the underground section are anticipated to be substantially above what was experienced for the Phase I construction along South Shields Street due to the expected presence of rock and additional boring required for environmental protection of sensitive habitat. The cost estimate assumes approximately 15 percent of the total underground length may be installed using boring methods. Sunk costs for the underground alternative include the proportionate amount of Engineering Costs and the structures procured for the proposed Project that will not be installed. Section 6 4 SAIC Energy, Environment & Infrastructure, LLC Alternative Report Section 6_final draft.docx 10/6/11 6.4 Biological and Natural Resource Impacts As indicated in Section 3.4, environmental studies were conducted along the existing Western transmission line route for the proposed single steel pole design, which identified a number of species of concern. For the southern portion of this alternative through the Horsetooth Reservoir Area the biological and natural resource impacts will be as identified by Platte River for the proposed Project. Regardless of whether the line is constructed underground or overhead, construction roads will be required along the alignment through the Pineridge Natural Area for vehicle and equipment access. Since the underground portion of this alternative will require excavating a continuous trench for 1.4 miles through the Pineridge Natural Area, ground disturbance will be extensive and significant, when compared to the disturbance associated with the single steel pole design currently proposed. Construction may utilize boring methods to mitigate ground disturbance through sensitive habitat. Although boring requires large pits on either end of the bore that present a larger impact to the environment. Bore pit locations will need to be carefully selected to avoid sensitive habitat. It is anticipated that some portions of the underground trench would impact species or habitat of concern and mitigation measures may not be sufficient to reduce these impacts to a less than significant level. No significant impacts are anticipated due to construction of the proposed single pole design. 6.5 Aesthetic Impacts The aesthetic impacts for the southern portion of this alternative through Horsetooth Tap Reservoir Area will be the same as for the proposed Project, with the exception that a large transition structure would be required to allow the overhead line to be re- directed underground. The transition structure will set at or near the southern end of Pineridge. The height of this structure is estimated to be 110 feet to 120 feet. In the Pineridge Natural Area, the new underground 230-kV line would result in some temporary visual scars to the landscape during construction that are anticipated to diminish rapidly once revegetation occurs. A benefit of installing the 230-kV transmission line underground is that following restoration of the area impacted by construction there would be very little change to the visual character of the area. However, the Western line would still remain in place until Western decides to rebuild their overhead line at some point in the future. With the exception of the transition structure, the only above-grade sign of the underground facility would be the vault access ways visible at the ground surface (vaults are spaced about every 1,300 to 1,900 feet) and red-colored utility markers (i.e., typically small posts about 3 to 4 feet tall) that will be located above the underground utility and spaced approximately every 500 feet. As noted in Section 2, at some time in the future, the Western 115-kV transmission line would be rebuilt to 230-kV utilizing larger H-frame structures as simulated in Figure 2-3. File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-1 Section 7 ALTERNATIVE ROUTES 7.1 Initially Considered Routes The first step in evaluating alternatives to the proposed Project was to quickly identify a range of potential route alternatives. Figure 7-1 identifies a diverse set of routes that were evaluated as part of this study. These routes were initially subjected to screening criteria to narrow the options to a workable set of alternatives. The potential alternatives were identified based on implementation cost, availability of a corridor for construction of the line, land use and development, environmental impacts, construction disturbance, aesthetic impacts, and operational considerations. The largest hurdle with any of the listed alternatives is the inability to complete by the June 2012 deadline. Figure 7-1. Phase III Initial Route Alternatives (2010 Imagery) Section 7 7-2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 A summary of the characteristics and evaluation of this group of initially considered alternatives is provided in Table 7-1. This table identifies the routes that were carried forward for further analysis. ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-3 Table 7-1 Alternate Route Screening Matrix Route ID Route Description Technical Solution Environmental Impact Aesthetic Impact Cost Yellow 1 (Platte River Proposed Project) 3.7 miles Utilize existing 75-ft Western R/W from Horsetooth Tap to Dixon Creek Substation through Horsetooth Reservoir Area and Pineridge Natural Area. Double-circuit tubular steel pole line supporting both Platte River’s proposed 230-kV circuit and Western’s existing 115-kV circuit. Medium – construction roads required along the northern portion. Southern portion utilize helicopter construction. High – Major impact for recreational users of Natural Area and Horsetooth Reservoir. $8.5M Yellow 2 (Partial UG) 3.7 miles (1.4 UG) Utilize existing 75-ft Western R/W from Horsetooth Tap to Dixon Creek Substation through Horsetooth Reservoir Area and Pineridge Natural Area. Overhead from Horsetooth Tap to near Spring Canyon Dam (as designed), then underground (as a single circuit) to Dixon Creek Substation; Western remains as single circuit overhead line. High – construction roads required and continuous trench/bore (with pits) along the northern portion. Southern portion utilize helicopter construction. Medium – No major, long term aesthetic impact through Pineridge Natural Area. Transmission line visible from Natural Area and Horsetooth Reservoir. $15.3M Green 1 5.1 miles North in public road R/W along S Taft Hill Rd, then west along W Section 7 7-4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Blue 1 6.1 miles North in public road R/W along S Shields St, then west along W Drake Rd. Overhead single-circuit 230-kV tubular steel poles. Low – construction in developed public R/W. High – adds very tall structures in area where electric utilities are underground. $16.8M Blue 2 6.1 miles North in public road R/W along S Shields St, then west along W Drake Rd. Underground single-circuit 230- kV ductbank. Low – construction in developed public R/W. Low – overhead only in area with existing overhead distribution. $37.5M Red 1 8.0 miles Within public road R/W east along W Trilby Rd, north along SR-287, then west along W Drake Rd. Overhead single-circuit 230-kV tubular steel poles. Low – construction in developed public R/W. High – adds very tall structures in area where electric utilities are underground. $18.3M Red 2 8.0 miles Within public road R/W east along W Trilby Rd, north along SR-287, then west along W Drake Rd. Underground single-circuit 230- kV ductbank. Low – construction in developed public R/W. Low – no visible facilities. $45.5M Magenta 4.1 miles Utilize existing 75-ft Western R/W from Horsetooth Tap to Spring Canyon Dam as proposed, then north along the base of the ridge through Pineridge Natural Area to near Dixon Canyon Rd, east across Dixon Reservoir to Dixon Creek Substation. ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-5 In summary, the alternative routes that were further evaluated are illustrated in Figure 7-2 and include: 1. Magenta Route: following the proposed Project route through the Horsetooth Reservoir Area then branching off along the lower ridge line in Pineridge Natural Area. 2. Orange Route: following the proposed Project route through the Horsetooth Reservoir Area then branching off along South Centennial Drive. 3. Green Route: tapping into the Phase II line on West Trilby Road and running within the public road R/W of South Taft Hill Road and West Drake Road. Figure 7-2. Phase III Viable Route Alternatives (2010 Imagery) These three route alternatives are described in more detail below, and provide implementation schedule forecasts and estimates of Project costs, as well as environmental and aesthetic impacts. Section 7 7-6 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 7.2 Magenta Route Alternative – Follow Lower Ridge Line in Pineridge Natural Area 7.2.1 Route Description The Magenta Route alternative is approximately 4.1 miles (or 0.3 miles longer than the proposed Project). It follows the same route as the proposed alignment within the Western 115-kV transmission line R/W for approximately 2.4 miles from Horsetooth Tap switching station through the Horsetooth Reservoir Area to near the base of Spring Canyon Dam. At this juncture, the route continues along the proposed alignment for another 1/4 mile where it branches off to the north-northwest along the toe of the slope of Pineridge through the Pineridge Natural Area. The transmission line R/W would be located generally below the existing vegetation line. The route continues in this direction until near Dixon Canyon Road where it turns and heads east, crossing the Dixon Reservoir, passing to the north of Burns Ranch and into Dixon Creek Substation. Two structure configuration options could be utilized for the Magenta Route alternative: 1) steel poles, similar to the proposed Project, or 2) a double-circuit H- frame. 7.2.2 Easements The Magenta Route alternative requires establishment of a new transmission line R/W through the Pineridge Natural Area that could be exchanged for the existing Western R/W. The R/W width may vary from 75 to 125 feet depending on structure and conductor selection and final design. Assuming many of the steel pole structures procured for Phase III could be reused for this route alternative, a 75-foot easement is anticipated to suffice. The City of Fort Collins owns the Pineridge Natural Area. Parcels crossed by this route are zoned Public Open Lands District. It is unclear at this time what process the City of Fort Collins and Larimer County may require for evaluating and eventually approving this alternative route. 7.2.3 Schedule The schedule in Table 7-2 is based on completion of the southern part of this route, from Horsetooth Tap switching station to near the Spring Canyon Dam, using the current design. Meanwhile efforts would be started to finalize the new alignment for the northern section, conduct surveying, geotechnical and environmental studies, update the design for the new alignment, obtain all necessary jurisdictional approvals, and prepare a new or modified steel pole procurement contract. This schedule assumes that environmental studies and associated mitigation plans could be completed and approved by the appropriate authorities within this schedule. As noted above, efforts would be made to reuse existing and delivered poles for Phase III, but this cannot be assured. Regardless, this route is approximately 0.4 miles ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-7 longer than the proposed Project and includes additional heavy angle/deadend structures. Table 7-2 Implementation Schedule Magenta Route Alternative Phase Start Finish Cumulative Restart Construction for South Segment 10/19/11 Mobilize 10/19/11 10/26/11 Stake / Construct Piers 10/24/11 2/15/12 Erect Poles and Install Framing 1/02/12 3/15/12 String, Sag and Clip Conductor 2/01/12 4/15/12 Design for Temporary Line 11/01/11 1/31/12 R/W acquisition for Temporary Line 12/01/11 2/29/12 Material Procurement for Temporary Line 1/02/12 2/29/12 Modify Construction Contract 1/15/12 2/15/12 Construct Temporary Line NTP 2/20/12 Mobilize 2/20/12 2/29/12 Set Poles and Install Framing 3/01/12 4/15/12 String, Sag and Clip Conductor 4/16/12 5/15/12 Test and Commission 5/16/12 5/31/12 Finalize Alignment for North Segment 10/31/11 11/30/11 Surveying Revised Route 11/30/11 1/31/12 Geotechnical Studies 11/30/11 1/31/12 R/W Acquisition for North Segment 12/01/11 5/31/12 Final Design 12/01/11 4/15/12 Environmental Field Studies / Review 12/01/11 8/31/12 Material Procurement for North Segment 3/15/12 9/30/12 Modify Construction Contract for North 4/16/12 6/01/12 Construct North Segment NTP 7/15/12 Mobilize 7/15/12 7/31/12 Construct Piers 8/01/12 10/31/12 Erect Poles and Install Framing 10/01/12 11/15/12 String, Sag and Clip Conductor 11/16/12 12/15/12 Test and Commission 12/16/12 12/31/12 400 days As a result of the additional activities for the northern part of the Magenta Route alternative, it is shown that Phase III would not be completed by the required in- service date and therefore would require a temporary 230-kV line to be installed. As Section 7 7-8 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 further described in Section 8, it may be possible to install a temporary 230-kV wood pole line along the proposed route (within the Pineridge Natural Area). 7.2.4 Cost Table 7-3 summarizes the cost of the Magenta Route alternative versus the cost for the proposed Project. As shown, no change in cost from the proposed route for the south portion of this alternative is expected. The cost estimate includes: 1. the material and construction costs for the southern portion of Phase III, as proposed by Platte River; 2. the material and construction costs for the northern portion of Phase III through Pineridge Natural Area, as indicated above; 3. other project development costs such as engineering, permitting, right-of-way, construction management, etc.; 4. the cost of re-engineering and associated permitting for the northern portion of the route; 5. the cost of engineering, permitting, materials, etc. expended for the proposed Project that will be of no value to the Project if the Magenta Route is selected; and 6. the cost to install the temporary 230-kV line. Table 7-3 Cost Comparison Magenta Route Alternative Magenta Route Alternative Proposed Project Engineering Costs 1 $1.52 million $1.42 Million South Section Material and Construction: Horsetooth Tap to Spring Canyon Dam $5.30 Million $5.30 Million North Section Material and Construction: Spring Canyon Dam to Dixon Creek Substation $2.30 Million $1.80 Million Sunk Costs $0.18 Million $0 Temporary 230-kV Wood Pole Line 2 $0.86 Million $0 Total $10.16 Million $8.52 Million Project Cost Differential + $1.64 Million (19% Increase) 1 Engineering Costs include incurred and planned costs for the Proposed Project, including engineering, permitting, right-of-way, construction contract administration/construction management, and interest during construction. Engineering Costs are estimated to be approximately 20% of the material and construction costs, based on Phase I and Phase II. 2 Temporary Line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Sunk costs for the Magenta Route alternative include the proportionate amount of Engineering Costs for the proposed Project that will not be constructed. ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-9 7.2.5 Environmental Impacts With this new route, additional environmental studies will be required for the northern section of Phase III. It is anticipated that species of concern similar to those found during review of the proposed Project will be encountered. Since structure locations are relatively flexible, if species or habitat of concern are encountered, impacts can be mitigated by shifting structure locations ahead or back on the alignment. However, placement of the overhead line in close proximity to Dixon Reservoir may increase avian impacts with the transmission lines and structures. Mitigation measures to minimize impacts such as increasing the visibility of the overhead cables may be necessary. Construction impacts of the transmission line along this route alternative is expected to be similar to the proposed route, if single steel poles are used. The major construction period impact will be the development of roads for vehicle and equipment access, assuming no significant environmental mitigation is required. Structure site impacts may slightly increase if H-frame structures are used since each structure will include two foundations. 7.2.6 Aesthetic Impacts There is no change in the aesthetic impacts for the southern portion of the Magenta Route alternative, since it will be constructed per the proposed Project design. Figure 7-2 is an existing view from Burns Ranch looking northwest across the Dixon Reservoir. Section 7 7-10 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure 7-2. Existing view of Dixon Reservoir from Burns Ranch (Looking northwest) Figure 7-3 is an existing view looking west toward the ridgeline. The jogging trail bed is elevated and blocks from view the base of the ridge. Figure 7-3. Existing view of Pineridge from Burns Ranch (Looking west) Relocating the transmission line to the base of Pineridge removes the transmission line from the foreground of residences in Burns Ranch and further from the existing recreational trails. Conversely this relocation may move the transmission line into view sheds for residences above Pineridge or closer to recreational uses near the reservoir at the north end of the Pineridge Natural Area. The relocated transmission line will be set with Pineridge in the background, simulated in Figures 7-4 through 7- 6. Mitigation efforts that may be undertaken to minimize avian impacts will likely increase cable visibility within the view shed. Figures 7-4 and 7-5 is the same view from Burns Ranch across the Dixon Reservoir simulating double-circuit 230-kV steel pole and H-frame structures, respectively. ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-11 Figure 7-4. Platte River 230-kV Tubular Steel Pole Transmission Line (Looking northwest at Dixon Reservoir) Figure 7-5. Platte River 230-kV H-Frame Transmission Line (Looking northwest at Dixon Reservoir) Section 7 7-12 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure 7-6 is the view looking west toward the ridgeline. The elevation of the jogging trail bed compared to the residences hides the structures located at the base of the ridge. Figure 7-6. Platte River 230-kV Transmission Lines (Looking west at Pineridge) 7.3 Orange Route Alterative – South Centennial Drive 7.3.1 Route Description The Orange Route alternative, similar to the Magenta Route, follows the same alignment as the proposed Project within the Western 115-kV transmission line R/W for approximately 2.2 miles from Horsetooth Tap switching station through the Horsetooth Reservoir Area to the top of Spring Canyon Dam. At this juncture, the route turns generally north, crosses Spring Canyon Dam with a single long span and continues along South Centennial Drive, within Larimer County’s public road R/W for 1.3 miles. Near Dixon Canyon Road, the alignment turns east, crosses the Dixon Reservoir, passes north of Burns Ranch and terminates at the Dixon Creek Substation. The last 1/2 mile of this route is located in the Pineridge Natural Area. 7.3.2 Easements The Orange Route alternative is anticipated to require very little new transmission line R/W. The southern 2.2 miles of this route are located in existing Western transmission line R/W. From there, it is anticipated that an engineering solution is available to construct the line completely within the public road R/W of South ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-13 Centennial Drive. It is assumed, given the fixed width of the public road R/W, only steel pole structures are feasible for this route. Where the route turns east from South Centennial Drive in the gap in the ridge near Dixon Canyon Road, the alignment crosses one privately-owned parcel located in Larimer County, currently zoned FA1 – Farming. After crossing this parcel, the alignment re-enters public road R/W (of Dixon Canyon Road) for about 0.05 miles. However, if an easement cannot be negotiated for this parcel, an engineering solution should be available to continue the line north for approximately 0.1 miles to the intersection with Dixon Canyon Road and proceed within the public road R/W of Dixon Canyon Road for 0.1 miles, essentially going around the privately-owned parcel. The final 1/2 mile of the Orange Route crosses two parcels located within the Pineridge Natural Area, owned by the City of Fort Collins and zoned Public Open Lands District. The transmission line R/W width, for the R/W located outside the public road R/W, may vary from 75 to 125 feet depending on structure and conductor selection and final design. Assuming many of the steel pole structures procured for Phase III could be reused for this route alternative and that steel poles are the only feasible option along South Centennial Drive (without requiring additional R/W width), a 75-foot easement is anticipated to suffice. 7.3.3 Schedule The schedule below, in Table 7-4, is based on a favorable winter construction period allowing completion of the southern part of this route, from Horsetooth Tap switching station to near the Spring Canyon Dam using the current design. Meanwhile efforts would be started to finalize the new alignment for the northern section, negotiate and acquire R/W (as required), conduct surveying, geotechnical and environmental studies, update the design for the new alignment, and prepare a new or modified steel pole procurement contract. Efforts would be made to reuse existing and delivered poles for Phase III, but this cannot be assured. It is anticipated that the Larimer County approval process to locate facilities within their right-of-way may take up to one year to complete. The construction contract would also be modified for the realignment and delay of schedule. Table 7-4 Implementation Schedule Orange Route Alternative Phase Start Finish Cumulative Restart Construction for South Segment 10/19/11 Mobilize 10/19/11 10/26/11 Stake / Construct Piers 10/24/11 2/15/12 Erect Poles and Install Framing 1/02/12 3/15/12 Section 7 7-14 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Phase Start Finish Cumulative String, Sag and Clip Conductor 2/01/12 4/15/12 Design for Temporary Line 11/01/11 1/31/12 R/W acquisition for Temporary Line 12/01/11 2/29/12 Material Procurement for Temporary Line 1/02/12 2/29/12 Modify Construction Contract 1/15/12 2/15/12 Construct Temporary Line NTP 2/20/12 Mobilize 2/20/12 2/29/12 Set Poles and Install Framing 3/01/12 4/15/12 String, Sag and Clip Conductor 4/16/12 5/15/12 Test and Commission 5/16/12 5/31/12 Finalize Alignment for North Segment 10/31/11 11/30/11 Surveying Revised Route 11/30/11 1/31/12 Geotechnical Studies 11/30/11 1/31/12 R/W Acquisition for North Segment 12/01/11 5/31/12 Finalize Design 12/01/11 4/15/12 Environmental Field Studies / Review 12/01/11 7/31/12 Larimer County Approval Process 12/01/11 11/30/12 Material Procurement for North Segment 3/15/12 9/30/12 Modify Construction Contract for North 4/16/12 6/01/12 Construct North Segment NTP 7/15/12 Mobilize 12/01/12 12/07/12 Construct Piers 12/08/12 3/15/13 Erect Poles and Install Framing 2/20/13 4/07/13 String, Sag and Clip Conductor 3/20/13 4/20/13 Test and Commission 4/21/13 5/07/13 527 days As a result of the additional activities for the northern part of the Orange Route alternative, it is shown that Phase III would not be completed by the required in- service date and therefore would require a temporary 230-kV line to be installed. As further described in Section 8, a temporary 230-kV wood pole line would be installed along the proposed route (within the Pineridge Natural Area). 7.3.4 Cost Table 7-5 summarizes the cost of the Orange Route alternative versus the cost for the proposed Project. As shown, no change in cost from the proposed route for the south portion of this alternative is expected. The cost estimate includes: ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-15 1. the material and construction costs for the southern portion of Phase III, as proposed by Platte River; 2. the material and construction costs for the northern portion of Phase III along South Centennial Road and through Pineridge Natural Area, as indicated above; 3. other project development costs such as engineering, permitting, right-of-way, construction management, etc.; 4. the cost of re-engineering and associated permitting for the northern portion of the route; 5. the cost of engineering, permitting, materials, etc. expended for the proposed Project that will be of no value to the Project if the Orange Route is selected; and 6. the cost to install the temporary 230-kV line. Table 7-5 Cost Comparison Orange Route Alternative Orange Route Alternative Proposed Project Engineering Costs 1 $1.50 Million $1.42 Million South Section Material and Construction: Horsetooth Tap to Spring Canyon Dam $5.30 Million $5.30 Million North Section Material and Construction: South Centennial Drive to Dixon Creek Substation $2.20 Million $1.80 Million Sunk Costs $0.21 Million $0 Temporary 230-kV Wood Pole Line 2 $1.19 Million $0 Total $10.40 Million $8.52 Million Project Cost Differential +1.88 Million (22% Increase) 1 Engineering Costs include incurred and planned costs for the Proposed Project, including engineering, permitting, right-of-way, construction contract administration/construction management, and interest during construction. Engineering Costs are estimated to be approximately 20% of the total material and construction costs, based on Phase I and Phase II. 2 Temporary Line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Sunk costs for the Orange Route alternative include the proportionate amount of Engineering Costs for the proposed Project that will not be constructed. 7.3.5 Environmental Impacts Additional environmental studies will be required for the northern section of the Orange Route alternative, where the alignment turns north on South Centennial Drive. Although much of this route is located within public road R/W, it is anticipated that species of concern similar to those found during review of the proposed Project, may be encountered beyond the limits of the existing improvements (i.e., roadway). This is certainly the case at the north end of this section, near Dixon Creek Substation, where Section 7 7-16 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 the route is again located in Pineridge Natural Area. Since structure locations are relatively flexible, if species or habitat of concern are encountered, impacts can be mitigated by shifting structure locations ahead or back on the alignment. Construction impacts of the transmission line along this route alternative is expected to be similar to the Phase II route along West Trilby Road. Construction vehicle and equipment access will be from existing roads. Impacts, such as ground disturbance, at each structure location would be similar to the proposed Project. 7.3.6 Aesthetics There is no change in the aesthetic impacts for the southern portion of the Orange Route alternative, since it will be constructed per the proposed Project design. Figure 7-7 is an existing view from Burns Ranch looking northwest across the Dixon Reservoir. Figure 7-7. Existing view of Dixon Reservoir from Burns Ranch (Looking northwest) Figure 7-8 is an existing view looking west toward the ridgeline. ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-17 Figure 7-8. Existing view of Pineridge from Burns Ranch (Looking west) Relocating the transmission line along South Centennial Drive removes the transmission line from the foreground of residences in Burns Ranch and further from the existing recreational trails. From the viewpoint of these residences, as well as from the recreational trails, the transmission line structures would be partially hidden by Pineridge. However, the structure tops would be visible, in some cases through the tree line at the top of the ridge, but in other locations, against the backdrop of the sky. Conversely this relocation may move the transmission line into the foreground views for residences along South Centennial Drive. The relocated transmission line is simulated in Figures 7-9 and 7-10. Section 7 7-18 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Figure 7-9. Platte River 230-kV Tubular Steel Pole Transmission Line (Looking northwest at Dixon Reservoir) Figure 7-10.Platte River 230-kV Tubular Steel Pole Transmission Line (Looking west at Pineridge) ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-19 7.4 Green Route Alternative – South Taft Hill Road and West Drake Road 7.4.1 Route Description The Green route alternative does not utilize any portion of the proposed Phase III Project (i.e., existing Western transmission line R/W, located in the Horsetooth Reservoir Area and Pineridge Natural Area). This route is located entirely within public road R/W of South Taft Hill Road and West Drake Road and consists of both overhead and underground construction. The Green Route will tap into the recently completed Phase II transmission line (Trilby to Horsetooth Tap) near the intersection of West Trilby Road and South Taft Hill Road. At this point, the existing tangent structure would be replaced with a deadend structure to accommodate the 90-degree angle the 230-kV circuit would turn as it proceeds north. For approximately 2.0 miles through mostly undeveloped area, this route would remain overhead. Through this section of the Green Route, an existing overhead distribution line already exists. It is anticipated that the distribution circuit would be attached to the new transmission line as underbuild. South of West Harmony Road, where residential development begins, the alignment would go underground for the remainder of the Green Route. The route continues north on South Taft Hill Road, turns west on West Drake Road and ends at the Dixon Creek Substation. The design of the underground section would be similar to that of Phase I from Horseshoe Substation to Trilby Substation. Since this route includes underground transmission, Western has indicated that it would not relocate its existing 115-kV line with Platte River. Therefore, this route consists of only a single 230-kV circuit for Platte River. Western would remain in their existing R/W and has indicated that at some time in the future (within the next 10 to 15 years), Western plans to upgrade their line to 230-kV. Western’s standard 230- kV structure is an H-frame structure, similar to but taller and wider than the 115-kV structures for their existing line. 7.4.2 Easements The Green route is assumed to be entirely located with the public road R/W of West Trilby Road, South Taft Hill Road and West Drake Road. Therefore, no easements are anticipated to be required. 7.4.3 Schedule The schedule below, in Table 7-6, does not allow any near-term construction based on the existing design for Phase III to proceed. Efforts would commence immediately to finalize the new alignment, conduct surveying, perform any geotechnical and environmental studies, update the design for the new alignment, and prepare a new or modified steel pole procurement contract. Materials for the underground portion of the construction would also need to be procured. Efforts would be made to reuse Section 7 7-20 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 existing and delivered poles for the overhead portion of Phase III, but this cannot be assured. The construction contract would also be modified for the realignment and delay of schedule. A separate construction contract may be considered for the underground portion of this route. Table 7-6 Implementation Schedule Green Route Alternative Phase Start Finish Cumulative Restart Construction for South Segment 10/19/11 Mobilize 10/19/11 10/26/11 Stake / Construct Piers 10/24/11 2/15/12 Erect Poles and Install Framing 1/02/12 3/15/12 String, Sag and Clip Conductor 2/01/12 4/15/12 Design for Temporary Line 11/01/11 1/31/12 R/W acquisition for Temporary Line 12/01/11 2/29/12 Material Procurement for Temporary Line 1/02/12 2/29/12 Negotiate Construction Contract 1/15/12 2/15/12 Construct Temporary Line NTP 2/20/12 Mobilize 2/20/12 2/29/12 Set Poles and Install Framing 3/01/12 4/15/12 String, Sag and Clip Conductor 4/16/12 5/15/12 Test and Commission 5/16/12 5/31/12 ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-21 Phase Start Finish Cumulative Finalize Alignment for Green Route 10/31/11 11/30/11 Surveying 11/30/11 2/29/12 Geotechnical Studies 11/30/11 1/31/12 Final Design 12/01/11 5/31/12 Permitting 12/01/11 5/31/12 Material Procurement 3/15/12 12/31/12 Procure Construction Contract 6/01/12 7/31/12 Construction NTP 8/07/12 Mobilize 8/15/12 8/31/12 Construct Piers (south section) 9/01/12 12/15/12 Erect Poles and Install Framing 12/16/12 2/15/13 String, Sag and Clip Conductor 2/16/13 3/15/13 Dixon Creek Substation Modifications 10/01/12 11/30/12 Ductbank Construction (north section) 9/01/12 2/29/13 Cable Installation 2/15/13 5/15/13 Test and Commission 4/16/13 5/31/13 541 days As a result of the additional activities for the Green Route alternative, it is shown that Phase III would not be completed by the required in-service date and therefore would require a temporary 230-kV line to be installed. As further described in Section 8, a temporary 230-kV wood pole line would be installed along West County Road 38E from Horsetooth Tap switching station to Spring Canyon Dam and along the existing Western R/W within the Pineridge Natural Area. 7.4.4 Cost Table 7-7 summarizes the cost of the Green Route alternative versus the cost for the proposed Project. The cost estimate includes: 1. the material and construction costs for the Phase III Project, as proposed by Platte River; 2. the material and construction costs for the Green Route along South Taft Hill Road and West Drake Road, as indicated above; 3. other project development costs such as engineering, permitting, right-of-way, construction management, etc.; 4. the cost of re-engineering and associated permitting for the Green Route; 5. the cost of engineering, permitting, materials, etc. expended for the proposed Project that will be of no value to the Project if the Green Route is selected; and 6. the cost to install the temporary 230-kV line. Section 7 7-22 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/11 Table 7-7 Cost Comparison Green Route Alternative Green Route Alternative Proposed Project Engineering Costs 1 $1.45 Million $1.42 Million Material and Construction $13.13 Million $7.10 Million Sunk Costs $4.57 Million $0 Temporary 230-kV Wood Pole Line 2 $7.40 Million $0 Total $26.55 Million $8.52 Million Project Cost Differential +18.03 Million (212% Increase) 1 Engineering Costs include incurred and planned costs for the Proposed Project, including engineering, permitting, right-of-way, construction contract administration/construction management, and interest during construction. Engineering Costs are estimated to be approximately 20% of the total material and construction costs, based on Phase I and Phase II. 2 Temporary Line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Sunk costs for the Green Route alternative include all Engineering Costs for the proposed Project, procurement and material costs for structures that cannot be reused for the overhead portion of the Green Route, and the costs associated with the portion of Phase II 230-kV line from the Green Route tap location to Horsetooth Tap switching station. Note that this section of the Phase II line would need to remain in operation as the second circuit on this line is owned by Tri-State G&T. 7.4.5 Environmental Impacts Additional environmental studies will be required for the Green Route alternative; however, it is anticipated that the majority of this route, since it is located in developed areas, would not encounter the level of species of concern as would be expected in the Pineridge Natural Area for the proposed Project or Magenta route. Construction impacts of the transmission line along the Green Route alternative is expected to be similar to the Phase I (underground) and Phase II (overhead) routes along South Shields Road and West Trilby Road, respectively. Construction vehicle and equipment access will be from existing roads. 7.4.6 Aesthetics Visually, the new transmission line along the southern 2.0 miles of this route along South Taft Hill Road is in a relatively undeveloped area and would be similar to the existing 230-kV line along West Trilby Road, except the Green Route will only be a single circuit. Note, the existing Phase II line from Trilby Substation to Horsetooth Tap switching station is a double-circuit steel pole line. The circuit on the north side of the pole is Platte River’s 230-kV circuit. The underground portion of the line would result in some temporary ground disturbance to the existing R/W improvements (e.g., paved roads, sidewalks and driveways, and landscaping) during construction. ALTERNATIVE ROUTES File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 7-23 Permanent evidence of the underground utility would be vault access ways visible at the ground surface (vaults are spaced about every 1,300 to 1,900 feet) and red-colored utility markers (i.e., typically small posts about 3 to 4 feet tall) that will be located above the underground utility and spaced approximately every 500 feet. As noted in Section 2 at some time in the future the Western 115-kV transmission line would be rebuilt to 230-kV utilizing larger H-frame structures as simulated in Figure 2-3. File: 00545503/3105111014-1000 Section 8 TEMPORARY LINE 8.1 Required Interconnection Timeline The Dixon Creek to Horseshoe Transmission Project is scheduled for completion by June 1, 2012 in order to meet reliability requirements for electric power delivery to south Fort Collins and the City of Loveland under contingency conditions. For alternatives considered in this report that would not establish an acceptable transmission interconnection by the required date, temporary facilities would be necessary. Information related to the routing, schedule, costs and impacts of these temporary facilities is provided below for each of the temporary interconnections identified. 8.2 Temporary Line Configuration – Wooden Structures The concept for the temporary 230-kV line is to provide a relatively simple line design with readily or quickly available materials that provides reliable short term transmission by June 1, 2012 in order to bridge the time until a final solution is in place. For all route alternatives, the temporary line is proposed to be a single circuit 230-kV line, built parallel to the Western 115-kV line through the Pineridge Natural Area. The temporary line would consist of single wood poles configured with either davit arms and suspension insulators, horizontal vee insulators, or single horizontal post insulators. The temporary wooden structures would be set directly in the ground. (As discussed below, use of the steel poles delivered for the proposed Phase III as temporary structures would require base plate connections and concrete pier footings.) Where practical the temporary structures would be set adjacent to the existing H- frames owned by Western to avoid midspan blowout clearance infringements (i.e., wind blowing the line beyond existing easement restrictions). Depending upon the clearances that could be obtained from the existing Western line, the temporary line may also require a temporary R/W. It is noted that the current Natural Areas Easement Policy prohibits the granting of new easements that allow for overhead lines within any City owned Natural Area. The temporary line would be designed for the same basic loading conditions as the proposed project. It was assumed that the temporary line structures would consist of a 90-foot, Class H3 or H4 wood pole, directly embedded in the ground for a height above ground of approximately 80 feet. Figure 8-1 illustrates a single-circuit wood pole configuration. Such structures would be capable of supporting 300- to 400-foot spans of 230-kV line and associated insulator equipment. Section 8 2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/1110/5/11 Figure 8-1. Single-Circuit Wood Pole Configuration Some of the wood poles for the temporary 230-kV line (i.e., non-tangent structures) would require guys and anchors to support the load, including loads during windy conditions, of particular concern in this area. It is anticipated that engineering solutions are available to locate guys and anchors in the R/W or temporary R/W. For the Green Route alternative, which does not utilize any portion of the proposed Project, a temporary line is necessary for the southern section of the proposed Project from Horsetooth Tap to near the Spring Canyon Dam. In this area a wood temporary line along W County Road 38E or parallel to the Western line was considered but it appears R/W and permitting issues would not be resolved in time to meet the required in service date. In this case the temporary solution in the southern section would be to build the Phase III line as planned, namely a double-circuit 230-kV steel pole line. Once the Green Route alternative was completed and the temporary line is no longer needed only the Western circuit installed on the southern section must remain in service. TEMPORARY LINE File: 00545503/3105111014-1000 SAIC Energy, Environment & Infrastructure, LLC 3 8.3 Schedule Table 8-1 identifies the estimated implementation schedule for completing the temporary line by the required in-service date for the 230-kV Phase III transmission line. This schedule applies to the 1.4-mile single-circuit wood pole line installed in the Pineridge Natural Area and is applicable to the H-frame, Long Span, Partial Underground alternatives, and the Magenta and Orange Routes. Table 8-1 Implementation Schedule Temporary Wood Pole Line in Pineridge Natural Area Phase Start Finish Cumulative Design for Temporary Line 11/01/11 1/31/12 R/W acquisition for Temporary Line 12/01/11 2/29/12 Material Procurement for Temporary Line 1/01/12 2/29/12 Modify Construction Contract 1/15/12 2/15/12 Construct Temporary Line NTP 2/20/12 Set Poles and Install Framing 3/01/12 4/15/12 String, Sag and Clip Conductor 4/16/12 5/15/12 Test and Commission 5/16/12 5/31/12 213 days Although this schedule also applies to the Green Route (Section 7), the southern section of the proposed Project must also be in service to complete the interconnection of Phase II to Dixon Creek Substation. However, the southern section of the proposed Project is not part of the final Green Route infrastructure. Further, the schedules presented in Sections 6 and 7 for the route alternatives do not include removal of the temporary facilities after the permanent transmission line is in service. 8.4 Cost Table 8-2 presents the costs for the temporary facilities, as presented in this report for the alternative structure configurations and span lengths, and route alternatives. The temporary line costs include associated engineering, permitting, right-of-way, materials, contract construction, construction contract administration/construction management and interest during construction. Section 8 4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Transmission Alternatives Study 10/6/1110/5/11 Table 8-2 Estimated Cost Temporary Transmission Line Route Alternative Report Section Reference Estimated Cost H-frame 4 $860,000 Long Span 5 $860,000 Partial Underground 6 $2,820,000 Magenta 7 $860,000 Orange 7 $1,190,000 Green 7 $2,820,000 8.5 Biological and Natural Resource Impacts The environmental impacts for a temporary wooden structure line are expected to be additive to those impacts, discussed elsewhere, for the permanent 230-kV line. Many of the environmental impacts for construction of the temporary wooden structure line are anticipated to be the same as for the proposed single steel poles, for example the amount and location of access roads is expected to be very similar. The temporary wood pole line would likely require additional structures resulting in an increase in the number of areas with concentrated ground disturbance to auger holes and set poles. However, there would be quite a bit of flexibility in span lengths to mitigate impacts to specific localized resources by shifting individual structures short distances. The temporary wooden structure line would have additional traffic impact on any construction roads and additional ground disturbance in the Pineridge Natural Area due to the need to return at some future time to remove the facility. 8.6 Aesthetic Impacts For a temporary wooden structure line constructed adjacent to the existing Western R/W it is anticipated the line would be perceived as adding visual clutter. Since this transmission line would only be in place until the permanent facility is completed any aesthetic impacts are expected to be short term. Draft Report Pineridge Distributed Generation Alternatives Study City of Fort Collins, Colorado October 2011 Draft Report Pineridge Distributed Generation Alternatives Study City of Fort Collins, Colorado October 2011 This report has been prepared for the use of the client for the specific purposes identified in the report. The conclusions, observations and recommendations contained herein attributed to SAIC constitute the opinions of SAIC. To the extent that statements, information and opinions provided by the client or others have been used in the preparation of this report, SAIC has relied upon the same to be accurate, and for which no assurances are intended and no representations or warranties are made. SAIC makes no certification and gives no assurances except as explicitly set forth in this report. © 2011 SAIC All rights reserved. File: 005455/3105111014-2000 Pineridge Distributed Generation Alternatives Study City of Fort Collins, Colorado Table of Contents Letter of Transmittal Table of Contents List of Tables List of Figures Executive Summary Section 1 LOAD GROWTH AND CONTINGENCY REQUIREMENTS .......... 1-1 1.1 Load Growth ............................................................................................ 1-1 1.2 Transmission Contingency Requirements ............................................... 1-1 1.3 Peak Load Reduction ............................................................................... 1-3 Section 2 POTENTIAL TECHNOLOGIES ........................................................... 2-1 2.1 Distributed Generation Options ............................................................... 2-1 2.1.1 Waste Diversion ........................................................................... 2-1 2.1.2 Solar Photovoltaic ........................................................................ 2-2 2.1.3 Solar Thermal Electric ................................................................. 2-3 2.1.4 Gas Turbines ................................................................................ 2-4 2.1.5 Fuel Cells ..................................................................................... 2-6 2.1.6 Combined Heat and Power .......................................................... 2-7 2.2 Load Reduction and Load Shifting Options ............................................ 2-8 2.2.1 Emergency Gen Sets in Area ....................................................... 2-8 2.2.2 Advanced Metering Infrastructure and Automatic Meter Reading ...................................................................................... 2-10 2.2.3 Community Energy Storage ....................................................... 2-11 2.2.4 Hybrid Ice Air Conditioning ...................................................... 2-13 2.3 Renewable Incentives ............................................................................ 2-14 2.3.1 Renewable Energy Credits (RECs) ............................................ 2-14 2.3.2 Incentives ................................................................................... 2-14 2.4 Summary ................................................................................................ 2-16 Table of Contents iv SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 List of Tables Table 1-1 Summer 2011 Peak City Loads 7/18/2011 ................................................. 1-1 Table 2-1 Summary of Colorado Incentives ............................................................. 2-14 Table 2-2 Summary of Peak Load Reduction Options ............................................. 2-17 Table of Contents File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC v List of Figures Figure 1-1. Platte River Peak Hours Above 550 MW, 5/28/11 – 8/30/11 .................. 1-3 File: 005455/3105111014-2000 EXECUTIVE SUMMARY Peak Load Reduction Requirements If existing and projected Cities’ loads can be reduced and limited to 550 MW, the proposed 230-kV line may not be required. This past summer (2011) a peak load reduction of up to 70 MW in the Loveland area and 15 MW in the Fort Collins Harmony Substation area for approximately 178 hours would have been required to meet this criteria. Additional peak load reduction in these areas will be required to offset the projected 2.75% annual load increases. Technologies can be used to reduce peak loads by utilizing distributed generation, to serve load locally instead of through the transmission system, and peak load reduction techniques that directly control customer loads or economically incentivize the customer to reduce loads during peak hours. Table E-1 summarizes the distributed generation and load reduction or load shifting technologies discussed in this report. High-level planning assumptions are used to attempt the quantify a potential capacity reduction and cost of each technology, assuming a peak load reduction of 85 MW for 178 hours/year, as well as the likely schedule required to implement it. None of these technologies could be implemented in time to resolve the transmission issues anticipated next summer without the Dickson-Horseshoe 230-kV line and it is doubtful that any single solution could achieve the desired load reduction in a reasonable time period, but a combination of technologies could provide significant benefit. Costs on most of these technologies are still substantially higher than traditional peak generation resources that provide comparable peak power at a cost of approximately $650/kW and $1.3 million ongoing annual operating costs. Table ES-1 Summary of Peak Load Reduction Options Peak Load Reduction Options Type MW MW at Peak Hour Cost/ kW Total Cost Ongoing Annual Costs Site Availability Installation Timeframe (Mo) Notes Municipal Solid Waste Generation 14 14 $ 4,500 $ 63M $ 5M Larimer County Landfill 24 mo Landfill solid waste dried and burned to generate electricity Biomass Generation 35 35 $ 4,500 $ 157M $ 5M Horseshoe Substation biomass location 24 mo Biomass gas burned to generate electricity Solar PV w/ Battery Storage Generation 85 85 $ 5,410 $ 460M $10M Requires 400+ acres 18 Mo+ Battery storage required to shift the timing of electricity put onto the grid to peak hours. Solar Thermal Electric Generation 85 85 $ 4,000 $ 340M $6M Requires 500+ acres 24 Mo Molten salt storage creates steam to generate electricity at any time of day including peaks. Gas Turbines Generation 95 95 $ 1,000 $95.5M $3M Minimum of 15 acres 24 - 36 Mo Only included EPC costs and add 15 percent for owner's costs Fuel Cells Generation 85 85 $ 8,000 $ 680M TBD. Requires survey for natural gas fuel and location 24 - 36 Mo New technologies at cutting edge, may or may not be available by next summer in sufficient quantities. Combined Heat and Power Generation 100 100 $ 1,350 $ 135M $5M Minimum of 15 acres 24 Mo Major long lead equipment (CT and STG) needs to procured prior to EPC Contract. Only included EPC costs and add 15 percent for owner's costs Emergency Gen Sets in Area Load Reduction 2.5 2 $ 260 $ 518K $50k to $117k Peak Load Reduction Options Type MW MW at Peak Hour Cost/ kW Total Cost Ongoing Annual Costs Site Availability Installation Timeframe (Mo) Notes Smart Meters w/ TOU Rates Load Reduction/S hifting 85 85 $ 100 $ 8.5M $ .85 M Cost to install 30k Loveland residential and commercial electric meters only. Does not include cost for 65k meters in Ft. Collins Install smart meters in Loveland commercial and residential properties. Use higher rate band during 4 p.m. to 8 p.m. in both Loveland and Ft. Collins to lower peak usage. Community Energy Storage (CES) Load Shifting 135 85 $ 3,125 $ 265M $ 5.3M TBD. Requires 2650 locations 24 - 36 Mo Batteries provide home backup and can send power to the grid during peak hours Hybrid Ice Air Conditioning Load Shifting 46 46 $ 1,700 $ 76M $ 1.5M 1/4 to 1/3 of buildings 24 Mo 2500 (+- 30%) ice systems to install. Operates 800 hours/yr. during peaks. Local production facilities could be built between Loveland and Ft. Collins, good for local economy and shorten delivery/installation timeframes. File: 005455/3105111014-2000 Section 1 LOAD GROWTH AND CONTINGENCY REQUIREMENTS 1.1 Load Growth Platte River Power Authority (Platte River) is responsible for designing and operating the electric transmission system that serves the cities of Estes Park, Fort Collins, Longmont, and Loveland (Cities). Electric systems are designed to serve peak load, which is when the instantaneous Megawatt (MW) demand is the highest. In the northern Front Range Colorado area, it typically occurs between 4 PM and 6 PM on a summer weekday when business and residential cooling requirements and evening activities overlap. The combined actual peak load of the four cities in 2011 was approximately 640 MW as shown in Table 1-1. Under more extreme summer weather, the 2011 load was forecasted at 671 MW. Loads are projected to increase to 687 MW by 2012, and increase about 2.75% per year to 2020. Table 1-1 Summer 2011 Peak City Loads 7/18/2011 City MW Estes Park 17 Fort Collins 292 Longmont 175 Loveland 140 Praxair 16 Total 640 Traditionally, transmission planning has been reactive to load growth. Planners project the peak load at each substation for ten to twenty years in the future and determine what transmission upgrades are required to serve that load Projected load growth is based on population and economic forecasts and historic correlation between these factors and peak electric system loads, factoring in weather conditions. Another solution that is beginning to be considered is to control and limit the peak load growth that the transmission system is required to serve by utilizing distributed generation and/or peak load reduction technologies in specific areas. 1.2 Transmission Contingency Requirements The North American Electric Reliability Corporation (NERC) Transmission Planning (TPL) standards require transmission owners and operators to conduct power flow studies to effectively demonstrate the reliability of the electric system under contingency situations, such as loss of a transmission line. In performing these Section 1 1-2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 extensive contingency analyses, the effect of an outaged facility on the rest of the transmission system is evaluated under a variety of system loading conditions, transmission configurations, and generation dispatch patterns. If studies determine that loss of a transmission element overloads another element or causes an unacceptable reduction in voltage, the transmission utility must upgrade the system to prevent this from happening, effectively requiring redundant supplies to most substations. If upgrades are not completed in time to prevent the overloads, the transmission operator must develop a mitigation plan for potential contingencies. Both Platte River and Western Area Power Authority (Western) own and operate 115-kV and/or 230-kV lines that serve the Cities. The 230-kV lines can deliver twice as much power as the 115-kV lines using the same size conductors, but require taller poles and more distance between the wires. Two transmission lines connect the cities of Fort Collins and Loveland to generation resources north and south of the cities. On the east side of the cities is a Platte River 230-kV line capable of serving approximately 472 MW. On the west side of the cities is a Western Area Power Administration (Western) 115-kV line capable of serving approximately 109 MW peak load. Other 115-kV lines serve Loveland from the east and the south. The cities have grown over the past decade and peak load has increased to the point that the 115-kV lines are not sufficient to provide the required redundancy to Fort Collins, Longmont, and Loveland. Current system planning studies, as well as 10-year transmission planning studies conducted in 2004, have conclusively demonstrated the urgent need to provide additional capacity between Fort Collins and Loveland to address the contingency loss of the existing 230-kV line between the two cities when the combined city loads exceeds 550 MW. In 2004, Platte River considered several alternatives and determined the most economical solution was to build a 230-kV circuit (Dixon Creek Substation to Horseshoe Substation). In addition, the Colorado Coordinated Planning Group, which is a statewide consortium (including Tri-State and Xcel Energy) have collectively concluded that the Dixon Creek – Horseshoe 230-kV circuit is an appropriate transmission solution for the area. With the load growth existing in the upper portion of the Front Range from Colorado Springs toward the Wyoming border, future transmission improvements are scheduled to take place from Southern Wyoming to Northern Colorado in order to accommodate the expanded import capability from the generation resources north of the Colorado border. The scheduled improvements will have an effect of increased power flows through the eastern part of Colorado in the Front Range. Over 70 percent of the state’s load exists between Fort Collins and Colorado Springs within 40 miles of either side of Interstate 25; thus, the proposed parallel 230-kV transmission lines will also serve to boost the overall system reliability of customers outside of the Larimer County load territory. Platte River has constructed additional 230-kV lines to Fort Collins and Longmont, and is in the process of completing a 230-kV line to serve Loveland. The two segments of this comprehensive 230-kV upgrade north of Horseshoe Substation and west of Trilby Substation have already been completed and the section south of Dixon LOAD GROWTH AND CONTINGENCY REQUIREMENTS File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 1-3 Creek Substation through Pineridge Natural Area is the last phase in preparation for the anticipated summer 2012 loading conditions in the Loveland area. The last section in question will aid in alleviating the 115-kV circuit contingency loading with 345-kV and 230-kV circuit outages to the east and north of the Fort Collins/Loveland area. By leaving the remaining Dixon Creek – Horsetooth segment at 115-kV, the 230-kV circuit capability of the two previously upgraded 115-kV circuits will not be realized and Platte River will not be able to provide transmission reliability per NERC standards when the Cities’ loads exceed 550 MW, which they did for 178 hours during 2011 as of August 22nd. 1.3 Peak Load Reduction If existing and projected Cities’ loads can be reduced and limited to 550 MW, the proposed 230-kV line may not be required. Figure 1-1 illustrates the days, times, and amounts that system load has exceeded 550 MW from June through August 2011. Figure 1-1. Platte River Peak Hours Above 550 MW, 5/28/11 – 8/30/11 According to Platte River’s load flow analysis, this past summer (2011) a peak load reduction of up to 70 MW in the Loveland area and 15 MW in the Fort Collins Harmony Substation area would have been necessary to avoid equipment overloads during a single contingency outage scenario. Additional peak load reduction in these areas will be required to offset the projected 2.75% annual load increases. The following section describes potential technologies that can be used to reduce peak loads by utilizing distributed generation to serve load locally instead of through the transmission system, and peak load reduction techniques that directly control customer loads or economically incentivize the customer to reduce loads during peak hours. File: 005455/3105111014-2000 Section 2 POTENTIAL TECHNOLOGIES 2.1 Distributed Generation Options 2.1.1 Waste Diversion For the purposes of this discussion, we will focus on waste-to-energy facilities fueled by municipal solid waste (“MSW”) or biomass. Waste-to-energy is the process where MSW or biomass is used as a fuel to heat tubes of water in a boiler. The high temperatures produced by burning the waste convert the water into steam, which is then used to drive a steam turbine generator that produces electricity. The resulting ash must be landfilled, but the waste volume is reduced by approximately 90 percent. Municipal Solid Waste Based on information provided by the Larimer County Landfill (the “Landfill”), which is jointly owned by Larimer County (25 percent), the City of Fort Collins (50 percent), and the City of Loveland (25 percent), the Landfill receives approximately 600 tons per day (“TPD”) of MSW. The estimated useful life of the Landfill is 2027. Larimer County has purchased land near Wellington for possible use as a future solid waste management site. Until needed by the Solid Waste Department, the property will be managed by the Larimer County Parks and Open Lands Department. The following is a planning level capital cost estimate on the cost of building a waste- to-energy facility south of the Horseshoe Substation based on the following assumptions:  600 TPD of MSW available for the waste-to-energy facility to be located within the city of Loveland (187,200 tons per year (“TPY”))  The MSW is contracted under long-term contracts to the city of Loveland in the amount of 187,000 tons per year to the waste-to-energy facility  600 kilowatt-hours per ton of MSW  8,000 hours of operation per year  $4,500 per kilowatt (“kW”) installed cost  24-month construction schedule after environmental permitting is completed and environmental permitting could take as long as two years to complete  Facility site available  Non-fuel operations and maintenance (“O&M”) costs are not included but would range from approximately fixed $10/kW month and variable $0.04 per kilowatt- hour (“kWh”) Section 2 2-2 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 Using the assumptions above, the waste-to-energy facility could generate approximately 14 megawatts (“MW”) at a cost of approximately $63,000,000. Biomass Biomass is plant matter that can be used to generate electricity with steam turbines & gasifiers or produce heat, usually by direct combustion. Wood energy is derived both from direct use of harvested wood as a fuel and from wood waste streams. Examples include forest residues (such as dead trees, branches and tree stumps), yard clippings, wood chips and even municipal solid waste. Biomass also includes plant or animal matter that can be converted into fibers or other industrial chemicals, including biofuels. Industrial biomass can be grown from numerous types of plants, including miscanthus, switchgrass, hemp, corn, poplar, willow, sorghum, sugarcane, and a variety of tree species, ranging from eucalyptus to oil palm (palm oil). The following is a planning level capital cost estimate on the cost of building a biomass facility that produces electricity south of the Horseshoe Substation based on the following assumptions:  467,000 TPY of biomass available for the biomass facility  The 467,000 TPY of biomass is under long-term contracts with the city of Loveland  $25 per green ton of biomass delivered to the biomass facility  600 kilowatt-hours per ton of biomass  40 percent moisture in the biomass  8,000 hours of operation per year  $4,500 per kW installed cost  24-month construction schedule after environmental permitting is completed, and environmental permitting could take as long as 18 months to complete  Facility site available  Non-fuel O&M costs are not included but would range from approximately fixed $10/kW month and variable $0.04 per kWh  35 MW capacity Using the assumptions above, the biomass facility would cost approximately $157,000,000. 2.1.2 Solar Photovoltaic The goal for this project is to reduce the peak hour electric load or increase electric generation in Loveland and Ft. Collins by 85 MW to meet the peak summer demand. There are many kinds of Solar Photovoltaic (“PV”) technologies, including monocrystalline multicrystalline, thin film, and concentrated solar using dish engines. POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-3 But the inherent issue with using Photovoltaic panels for this particular application however, is that electricity would need to be stored during the day for use on cloudy days and for use during peak hours, defined as 4:00 p.m. through 8:00 p.m. This is well after the sun has peaked for solar PV generation so there is a mis-alignment in terms of when electricity is generated by solar panels and when it is required. If a suitable storage system can be provided at reasonable cost, then the use of solar PV energy might be appropriate. Here is an example of a solar farm providing the equivalent of 85 MW of power for four hours per day (140 MWh total) by storing the daily solar energy in batteries and discharging it during the peak hours Solar PV Solution Assumptions:  79 MW of solar panels near Loveland  Sufficient space, 500 acres  Land cost is not included in kW cost estimate  Location is within ¼ mile of a transmission line with available capacity  Solar Radiance is 5.39 kWh/sq m/day (this is the kilowatt hours per square meter per day, or Solar Insolation, representing the intensity and duration of the sun during an average day in Loveland)  System Efficiency = 80 percent (due to wiring and inverter losses etc.)  Includes 500 MWh of batteries for one day’s worth of storage  Assumes batteries discharge less than 80 percent to maintain battery life  Batteries discharge up to 4 hours per occurrence during peak hours  Installation cost for solar and batteries $530M total or $6,215/kW  Ongoing annual cost for property tax and maintenance approximately $10M Note that this system would require a minimum of one day’s worth of battery storage, or four hours, to fill in during the peak hours. Utility scale NaS(Sodium Sulfur) batteries are costly so Lithium ion batteries at $425/kWh have been assumed. Solar Thermal Electric technology, also known as Concentrated Solar Power (“CSP”) with Thermal Energy Storage (“TES”) however may be able to solve the problem of storage too, so electricity can be generated during peak hours and discharged during peak load hours as described next. 2.1.3 Solar Thermal Electric CSP systems use mirrors to concentrate sunlight and heat a working fluid. The fluid is then used to drive a steam turbine and generate electricity. Various CSP technologies are available and distinguished by how the heat is collected and subsequently used to create electricity. Section 2 2-4 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 Parabolic Trough Parabolic trough systems use rows of parabolic concentrating mirror assemblies (the “trough”) arranged from north to south on a given plant site to enable tracking the east-west motion of the sun. The mirrors concentrate sunlight onto a tube, through which synthetic oil passes, and the oil is heated to approximately 750 degrees Fahrenheit (“ºF”). The heated oil then passes through a series of heat exchangers to generate steam, which is subsequently used in a steam turbine to generate electricity. Thermal Energy Storage CSP systems using molten salt as the heat transfer fluid, can be integrated with Thermal Energy Storage (TES) systems to store thermal energy for later use to generate steam. In a trough plant, the fluid collects solar energy heat as it circulates through the solar field, then passes through a boiler to drive the steam turbine. Molten salt is stored in large insulated concrete tanks or vats so that during cloudy days or peak periods it can be sent to the steam turbine to generate electricity as required. The larger the tanks, the more energy can be stored to make it through longer stretches of cloudy days. The potential operational benefits of solar thermal with storage are great however.. CSP with TES has the potential for 24-hour operation which would allow solar thermal energy to shave peak loads in Ft. Collins and Loveland, assuming sufficient land can be found for the facilities. Most PV and CSP systems require between 4 and 10 acres per peak MW of output and for effective deployment, land must be largely flat, preferably with less than a two percent grade. The approximate costs for a concentrated solar power “trough” system with storage are as follows:  Two days of 4-hour 85 MW peak loads  Costs in the $4000/kW range  Total cost $340M  Longer storage requirements would increase the molten salt volumes required and increase cost  Requires approximately 500+ acres; the cost of land is not included 2.1.4 Gas Turbines Gas turbines are used quite commonly to generate electricity. For example, the LM6000 gas turbine manufactured by General Electric (“GE”) provides 54,610 shaft horsepower (40,700 kW) from either end of the low-pressure rotor system, which rotates at 3,600 rotations per minute. This twin spool design with the low-pressure turbine operating at 60 Hertz eliminates the need for a conventional power turbine. Its high efficiency and installation flexibility make it ideal also for a wide variety of utility power generation and industrial applications, especially peaker and cogeneration plants. POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-5 The GE LM6000 PC is rated to provide more than 43 MW with a thermal efficiency of around 42 percent lower heating value (“LHV”) at ISO conditions (59°F, sea level, and 60 percent relative humidity). With options, this can be increased to around 50 MW rated power. This unit has applications in power generation for combined cycle or peak power. Other applications include combined heat & power for industrial & independent power producers. Typical users:  Hospitals  Airports  Pulp and paper, cement, mining plants  Gas pipelines, refineries, gas production  Utilities  Cruise ships and fast ferries The overall EPC costs for a simple-cycle (“SC”) plant in northern Colorado is estimated at $930 kW to $1,000 kW. This cost has an accuracy level of +30 to -15 percent and is based on present day 2011 dollars and does not include escalation and owner’s costs, which is discussed below. Many factors can impact the EPC price of a facility including: size, site ambient conditions, delivery voltage, fuel supply pressure, use of secondary or tertiary fuels, type of heat rejection system, emissions control equipment, indoor versus outdoor installations, type of wastewater treatment, conditions of the site, date of contract, project location schedule acceleration of schedule and others. These costs are based on specific set of conditions listed below:  Size: 45 MW  Two GE LM6000’s  Natural fuel only  Project location: Northern Colorado  Performance assumed to be at ISO ambient conditions  Delivery voltage: 69 kV  Outdoor equipment In addition to the variations in the EPC costs, other highly variable project costs are also incurred. These costs, which are not typically directly associated with the EPC contract, are referred to as owner indirect and other costs. These costs may include the following:  Electrical interconnection costs to install transmission lines or upgrade the existing utility system Section 2 2-6 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11  Fuel interconnection costs  Permitting fees  Development fees (preliminary engineering, preparation and negotiation of contracts, and other legal and professional fees)  Taxes or payments in lieu of taxes  Financing fees including interest during construction, legal fees, lender fees, and insurance (i.e. efficacy insurance)  Other site or regional related costs Based on our experience reviewing projects for financing, these fees can be 15 percent, or higher, of the EPC costs which are not included in the cost above. The overall construction schedule is approximately 18 to 20 months from the award of the EPC contract to commercial operation of the plant. Included in this time frame is detailed design, balance of plant procurement, construction, and commissioning. Permitting and project development would have to start one to two years prior to the award of the EPC contract. Generally, however, a 90 MW SC plants in development today can be constructed in approximately two to three years which includes permitting, long lead procurement, construction, and commissioning. 2.1.5 Fuel Cells New technologies that may be considered include the fuel cell which takes natural gas (methane) and water, in a chemical process, generates electricity, heat, and releases less pollutants than even burning natural gas in a gas turbine. Such systems are fairly new when it applies to providing electricity for a building or home. These systems make little or noise, so have an advantage in areas where noisy generation plants would be unwelcome. Planning level costs for the Bloom Energy solid oxide fuel cell (“SOFC”) are as follows:  One-time installation fees are in the $7,000 to $12,000/kW range after government and other state incentives; we’ll use $8,000/kW for large installations  Figures include warranty costs recommended since the fuel cell stack will need replacement in five to ten years  Cost for 85 MW system is approximately $680,000,000  Cost for natural gas to generate 85 MW for 178 hours is around $6,000/hour or $1M annually  Installation time frame is 24 - 36 months POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-7 2.1.6 Combined Heat and Power Combined heat and power (“CHP”) facilities, also known as “cogeneration” plants are typically electric power plants that use their own waste heat to warm nearby buildings, heat water, warm greenhouses or warehouses, or for other practical purposes, instead of just disposing of the heat. Typically the facility that generates electricity must be near where the waste heat can be put to good use. CHP systems are able to increase the total energy utilization of primary energy sources and because it is usually cost effective, CHP is steadily gaining popularity in all sectors of the energy economy due to rising fossil fuel costs and concerns over the environment from greenhouse gasses and global warming. Traditional power plants are roughly 30 percent efficient when generating electricity. A CHP system however generates the electricity, and then uses remaining heat for hot water or space heating, achieving efficiencies up to 80 percent or more. For the Loveland area, it would be good to survey the existing power generating plants, and nearby industries to determine if there are any facilities that might be able to benefit nearby companies with their waste heat. Perhaps a mutually beneficial arrangement can be made, which lowers overall electrical demand, and reducing the base electrical load. The overall engineering, procurement and construction (“EPC”) costs for a combined- cycle (“CC”) plant in northern Colorado is estimated at $1,300 kW to $1,400 kW. This cost has a accuracy level of +30 to – 15 percent and is based on present day 2011 dollars and does not include escalation and owner’s costs, which is discussed below. Many factors can impact the EPC price of a facility including: size, site ambient conditions, delivery voltage, fuel supply pressure, use of secondary or tertiary fuels, type of heat rejection system, emissions control equipment, indoor versus outdoor installations, type of wastewater treatment, conditions of the site, date of contract, project location schedule acceleration of schedule and others. These costs are based on specific set of conditions listed below:  Size: 100 MW  1 – PG7121EA\  1 – 30 MW Steam Turbine Generator  Natural fuel only  Project location: Northern Colorado  Performance assumed to be at ISO ambient conditions  Delivery voltage: 69 kV  Outdoor equipment Section 2 2-8 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 In addition to the variations in the EPC costs, other highly variable project costs are also incurred. These costs, which are not typically directly associated with the EPC contract, are referred to as owner indirect and other costs. These costs may include the following:  Electrical interconnection costs to install transmission lines or upgrade the existing utility system  Fuel interconnection costs  Permitting fees  Development fees (preliminary engineering, preparation and negotiation of contracts, and other legal and professional fees)  Taxes or payments in lieu of taxes  Financing fees including interest during construction, legal fees, lender fees, and insurance (i.e. efficacy insurance)  Other site or regional related costs Based on our experience reviewing projects for financing, these fees can be 15 percent, or higher, of the EPC costs which are not included in the cost above. The overall construction schedule is approximately 20 to 24 months from the award of the EPC contract to commercial operation of the plant. Included in this time frame is detailed design, balance of plant procurement, construction, and commissioning. Permitting and project development would have to start one to two years prior to the award of the EPC contract. Generally, however, a 100 MW CC plants in development today can be constructed in approximately two and a half to four years which includes permitting, long lead procurement, construction, and commissioning. 2.2 Load Reduction and Load Shifting Options 2.2.1 Emergency Gen Sets in Area A Load Reduction Management System (“LRMS”) can be implemented to control the operation of back-up diesel generators that supply emergency power to water and sewer system pumps and pumping stations operated by the water authority and other municipal agencies, and possibly cooperating corporate entities in the Ft. Collins and Loveland area. During peak loads, the back-up generators would be brought online to power the back-up water and wastewater pumps, or provide backup power to the operation, temporarily reducing the load on the grid. When peak periods are over, the pumps and buildings would be brought back online and the back-up generators turned off. This option is possible only if there are sufficient back-up diesel generators that can be used. We are assuming 20 units may be available between businesses and municipalities in Ft. Collins and Loveland, which will reduce load on the grid by approximately 10 MW. POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-9 To insure this is a feasible option, an inventory should be taken of the companies, electric, water and power authority to determine the number of “gen sets” (back-up generators) that might be available for this approach. If feasible, then information on gen set manufacturer, model, capacity, control panel model, and the transfer switch make and model would be required. For the dispatch of existing back-up generators, a remotely controlled interface unit must be installed at the stand-by generator. When the control unit receives a command to start, it will send a signal to the generator to engage the existing automatic transfer switch to operate, simulating an outage has occurred. This operation will cause the generator to start and transfer the appropriate loads to back-up generator and is a relatively simple task assuming that the interface to the generator is straight forward, depending upon the make and model. If there is an issue with turning off water pumps temporarily during a forced back-up connection, then the transfer switch must be replaced with a “closed” transition transfer switch which will eliminate the problem but at an additional cost. Frequent dispatch may also have other issues as well such as restrictions or permit limits on run time, air pollution limits, operational issues due to water back flows, etc. In addition, deep wells may have issues with the water flowing in reverse direction when the pumps are temporarily turned off and would require a longer time delay before restarting the pumps. Along with remote control, the diesel back-up generators would also be monitored for critical start/stop, fuel level, electric output and other operational conditions depending upon the age, make and model of the generator, control panel and transfer switch. Since most back-up generators are tested on a regular basis anyway, monitoring them and controlling them remotely would eliminate the truck rolls and labor costs to manually test each of the backup generators. To reduce load by 85 MW, a significant number of back-up generators in the range of 850 would need to be turned on. There will not be nearly enough to cover the entire 85 MW requirement between Ft. Collins and Loveland but 20 units seems to be a reasonable number, with an average generator rating of 625 kW. Assumptions:  10 MW of peak demand load to be reduced 178 hours per year.  The average diesel backup generator rating is 625 kW (ranges from 10 kW to 2,000 kW).  Current installed generators are made by major vendors like Caterpillar, Onan, Generac, Cummins etc. and transfer switches are capable of being remotely managed within reasonable complexities.  Generator output is 80 percent of rated load. Generating 10 MW would require approximately 20 diesel generators (10 MW/625 kW/.80 = 20); no environmental issues would prohibit diesel operation.  75 percent of the generators use open transfer switches allowing standard stand- alone remote terminal units (“RTUs”) for remote control. Section 2 2-10 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11  25 percent of the generators use closed transition transfer switches providing no interruption in power to the pump when switching to backup.  80 percent of diesel generator sites have Internet access for remote management/control.  15 percent of diesel generator sites require cellular access for remote management/control.  Five percent of diesel generator sites require satellite access for remote management/control.  Remote monitoring, management and control would require fully integrated demand management system.  Includes integration into Supervisory Control and Data Acquisition (“SCADA”) or Smart Grid applications.  Installed cost is approximately $518,000.  Or $260/kW.  Installation timeframe would be approximately 6 to 12 months. On-going cost of diesel fuel should also be considered in this scenario, which could cost up to $1,000 per year to generate 2 MW for 178 hours, depending upon the price for diesel fuel. These ongoing costs however would be reduced or eliminated since a portion of this fuel expense would have been paid for to run regularly scheduled backup generator tests anyway. It is not uncommon to run monthly tests for a good portion of the day. In this scenario, running backup tests during peak hours would help reduce the utility’s peak loads, something the utility could make attractive to the companies with backup generators by offering incentives. 2.2.2 Advanced Metering Infrastructure and Automatic Meter Reading In early 2012 Ft. Collins will begin rolling out an Advanced Metering Infrastructure (AMI) system to 55,000 residential housing units and 10,000 commercial buildings. One advantage of having AMI is that the utility can offer various rate packages based on rate bands, Time Of Use (TOU) rates, variable pricing and other services based on the technology. Various pricing bands during the day can motivate customers to consume or not to consume electricity. If Ft. Collins were to install the meters and then implement pricing for peak hours, off-peak hours, and variable rate hours, it will see a reduction in demand during the peak hour rate band. As an example, if the higher cost peak rate band were set for 4:00 p.m. until 8:00 p.m. the utility is very likely to see a reduction in demand during those hours. Loveland does not have a smart grid plan but in a first phase, if they were to install an Automatic Meter Reading system (AMR) in residential and commercial accounts, it could be done fairly easily without having to build a data communications network back to the utility command center. In the first phase, Automatic Meter Readers (AMR) could drive by and wirelessly collect interval data from the meters for billing POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-11 purposes. The implementation of the AMR however would allow Loveland to incorporate various rate plans like Ft. Collins. Then as financing and design efforts proceed, eventually convert to a fully automatic meter infrastructure if they so desire. Reducing peak hour usage however could be accomplished.  30,000 electric smart meters could be installed in Loveland (4615 commercial, 25385 residential)  Cost per meter installed approximately $265 each on average  On-going cost to read meters w/ AMR approximately $2 per month each  Total Cost to install: $7,950,000  Installed cost is $115/ kW  Both utilities use peak rates between 4:00 p.m. and 8:00 p.m. with exact TOU hours to be determined  Potential is provided for Ft. Collins and Loveland to potentially reduce substantial demand during peak hours 2.2.3 Community Energy Storage Community Energy Storage (“CES”) consists of a large battery back-up system installed by the utility in neighborhoods, that serves several houses, typically associated with neighborhood transformers at the grid edge. If CES units were installed in the Loveland and Ft. Collins area, the utility could use them as a kind of buffer, to feed electric power into the grid during peak hours, and fill them up with low cost electricity during off-peak hours. The first installation of CES systems recently began in the U.S. providing back-up power to an average of four homes per CES unit. These units will also be used to reduce electrical load by powering homes during periods of peak energy consumption, with the overall process managed through a “control hub,” at the nearby sub-station. Each of these CES battery units for Loveland and Ft. Collins will be sized at 50 kWh. Depending on the day and time of the outage, and remaining power in each battery, each CES unit can supply around four hours of back-up power to each of four houses depending on the level of battery charge, time of day, and actual load. Note that back- up times will increase when neighbors are aware they are on back-up power. Besides shortening or eliminating the amount of time a customer is without power, CES units can also be used to supply energy to the houses during peak electrical periods, say between 4 p.m. to 8 p.m., on hot summer days when air conditioners are running on high. With a CES unit feeding power to the houses during these peak times, the overall load on the electric grid is reduced. By relieving the strain on the electric system during these peak periods, the utility can reduce the price of electricity at those times, and in general delay the need for future power plants or transmission lines which helps lower overall energy costs. Section 2 2-12 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 Once qualified properties are selected for the location of CES battery systems, the installation process takes about three days for each CES, which is usually located next to an existing pad mounted neighborhood transformer. The following is a planning level capital cost estimate to install 2,650 x 50 kW CES battery systems, a total of 135 MW nameplate capacity based on the following assumptions:  Size of each CES battery is 50 kW.  Each transformer supports on average four homes with an average total load of 8 kW.  CES provides power for those four homes an average of four hours per occurrence (outage).  Batteries are used during 178 hours of annual peak period load.  Charging of batteries occurs during off-peak periods at times of lowest electrical cost.  CES would conservatively be discharged only up to 64 percent per occurrence to maintain long term battery life.  For each occurrence each CES reduces load on the grid 8 kW x 4 h = 32 kWh.  Discharging 2650 CES units x 32 kWh = 85 MWh.  $ 31,25 / kW is the installed cost based on output.  Energy cost savings should also be considered. If the price difference between off- peak (when battery is “filled”) and peak (when battery is discharged) is $.10 / kW then savings to the utility will be $.10 x 32 kWh x 2,650 CES units = $8,480 per occurrence.  45 occurrences of 4 hours each per year (178 hours total).  Installation of 2,188 CES units will take approximately 36-months after permitting is completed.  Maintenance costs are not included in above.  This assumes there are actually enough locations to actually install the quantity of batteries proposed. Such a study would need to be completed first. Utilizing the assumptions above, the CES capability could be engineered to reduce load by approximately 85 MW during 178 peak hours for an installation cost of approximately $265,000,000. Cost savings due to keeping homes on back-up power has not been factored in for items like reduced food spoilage, basement flooding prevented, or increased personal health and safety etc. Upfront costs for CES are determined mainly by the size of the battery. As installations increase in the future, battery costs will continue to drop due to volumes of scale. And when re-cycled batteries can be incorporated into the vendor products, there will be significant cost reductions in this technology. POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-13 2.2.4 Hybrid Ice Air Conditioning During summer month peak hours, one of the largest consumers of electricity, if not the largest load is air conditioning. Approximately 30 percent to 40 percent of a building’s load on a hot day may be used for this purpose. In Loveland and Ft. Collins, reducing air conditioning load during the critical 4:00 p.m. to 8:00 p.m. peak hours could be accomplished using hybrid “ice and electric” air conditioning technology, reducing the electric load substantially when needed the most. These hybrid systems are typically installed on the roofs of large residential and commercial structures, and connected to existing air conditioners. They create ice during the low cost, off-peak hours and use the ice later during the hot afternoon and evening peak periods for cooling purposes. Some new air conditioning models from manufacturers like Carrier/Trane are built with a ready-made “ice coil” and can easily be connected to one of these hybrid ice storage units, making installation very simple. Other air conditioners can’t be converted, or due to location, space or power constraints cannot be converted. Other air conditioning systems require slight modifications but can be upgraded to accept the connection. Overall, about one third of them can be converted. One approach to implementing such a program could be for the utility to install such units at no cost, to motivate building owners to participate. Not only would owners of hybrid air conditioning systems see annual electrical cost savings in the 10 – 20% range, but the utility would see a reduced load during the critical peak periods and could control the systems. Based on the last 10 years of data for the area, and an analysis by the hybrid air conditioning company  The Average Peak Day is July 19th  Average Peak Hour is 4:45 p.m.to 5:45 p.m.  Combined peak summer load is 461 MW for both Loveland and Ft. Collins  Portions of peak load due to air conditioning is assumed to be 30 percent  33% of AC sites can accept an ice air conditioner  Potential MW reduction is 46 MW or 10 percent of the summer peak load split between Loveland with 16MW and Ft. Collins 30 MW respectively  Requires 2514 (plus or minus 30 percent) ice air conditioners with direct load control  Installed cost is $76M  Cost is $1700/kW  Plus 2% annual maintenance or $1.5M/year Section 2 2-14 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 2.3 Renewable Incentives 2.3.1 Renewable Energy Credits (RECs) When an organization reduces its emissions of greenhouse gases and other pollutants through energy efficiency and renewable energy projects, those reductions have financial value. Companies, utilities, governments, and others are willing to purchase those emissions reductions to either voluntarily offset their own emissions or satisfy government mandates that they do so. For example, roughly half the states in the U.S. have adopted renewable portfolio standards (“RPS”) that require utilities to generate a percentage of their power from renewable resources. Utilities can meet these requirements by either producing electricity from wind turbines, solar power or other renewable resources, or by purchasing RECs from organizations that do. Some companies do not want to own the renewable energy assets Those who cannot participate, may choose to enter into a power purchase agreement which allows a third party to install and own renewable facilities on the company’s property. The third party takes full advantage of the federal tax reductions, accelerated depreciation, state incentives, local incentives, and utility incentives. In turn it sells power back to the original company at a reduced rate. The third party can also own the RECs generated by owning the renewable energy resources and can either provide them to the organization which is hosting the project or can sell them on the open market. 2.3.2 Incentives There are various incentives for renewable energy based on technology, state, utility, and special interest groups. The tax incentive with the largest impact on renewables for individuals and companies has been the Federal Tax Credit, now extended to 2017, providing up to 30 percent off the gross cost to install renewable energy systems along with the Modified Accelerated Cost Recovery System (“MACRS”) allowing accelerated 5-year depreciation of such assets. Table 2-1 summarizes some of the types of incentives available in Colorado. Details on some of the specific programs follows. Table 2-1 Summary of Colorado Incentives Incentive Description 3rd Party Solar Power Purchase Agreement Policies Colorado Power Purchase Agreement Senate Bill 09-051; PUC Decision C09-0990 described at http://www.dora.state.co.us/puc/docketsdecisions/decisions/2009/C09- 0990_08R-424E.pdf Energy Efficient Resource Standards Electricity sales and demand reduction of 5% of 2006 numbers by 2018 (statutory requirement); natural gas savings requirements vary by utility Grant Programs for Renewables State, Utility, Local, Private programs POTENTIAL TECHNOLOGIES File: 005455/3105111014-2000 SAIC Energy, Environment & Infrastructure, LLC 2-15 Interconnection Policies 10,000 kW system capacity limit in Colorado Loan Programs for Renewables State programs plus other Net Metering Policies IOUs no limit, co-ops & municipals 10kW/25kW PACE (Property Assessed Clean Energy) Financing Policies Property tax Assessed Clean Energy Programs Property Tax Incentives for Renewables Some State Exemptions or special assessments Rebate Programs for Renewables State, Utility, Local, Non profit Renewable Portfolio Standard Policies 30% by 2020 (IOUs) 10% by 2020 (co-ops & large municipals) Renewable Portfolio Standard Policies with Solar/Distributed Generation Provisions Colorado: 3% DG by 2020 1.5% customer-sited by 2020 Sales Tax Incentives for Renewables State exemption + local gov (option) authorized to offer exemption or deduction Colorado Property Tax Exemption for Residential Renewable Energy Equipment For Colorado property taxation purposes, renewable energy systems as defined under § 40-1-102 (11), C.R.S., that are used to produce two (2) megawatts or less of electricity are classified as personal property and assessed by the county assessor. The following are examples of renewable energy systems (property): photovoltaics (solar), hydroelectric, and wind turbine property. A description of this program can be found at http://dsireusa.org/incentives/incentive.cfm?Incentive_Code=CO188F&re=1&ee=1 Colorado Renewable Energy Property Tax Assessment Colorado Renewable Energy Property Tax Assessment based on Senate Bill 177, enacted in April of 2009, allows for large-scale solar facilities (2 MW or larger) installed on or after January 1, 2009, to follow the same method for property tax assessments as wind-energy facilities. Wind facilities in operation prior to June 1, 2006, and solar facilities installed prior to January 1, 2009, are assessed using the same method as other renewables. In 2010, Senate Bills 174, 177, and 19, respectively, extended this methodology to equipment used to produce electricity from geothermal, biomass, and certain hydro resources. See more at http://dsireusa.org/incentives/incentive.cfm?Incentive_Code=CO46F&re=1&ee=1 Colorado Sales and Use Tax Exemption for Renewable Energy Equipment Colorado exempts from the state's sales and use tax all sales, storage, and use of components used in the production of alternating current electricity from a renewable energy source. Effective July 1, 2009, through July 1, 2017, all sales, storage, and use of components used in solar thermal systems are also exempt from the state's sales and use tax. The exemption for systems which produce electricity from a renewable resource includes but is not limited to PV systems, solar thermal-electric systems, small wind systems, biomass systems, or geothermal systems. See more at http://dsireusa.org/incentives/incentive.cfm?Incentive_Code=CO160F&re=1&ee=1 Section 2 2-16 SAIC Energy, Environment & Infrastructure, LLC Pineridge Distributed Generation Alternatives Study 10/6/11 Colorado Local Option for – Sales and Use Tax Exemption for Renewable Energy Systems for Solar Water Heat, Solar Thermal Electric, Photovoltaics, Wind, Biomass, Geothermal Electric, Other Renewables Colorado enacted legislation in April 2007 (SB 145) to authorize counties and municipalities to offer property or sales tax rebates or credits to residential and commercial property owners who install renewable energy systems on their property. HB 1126 of May 2009 added solar thermal (non-electric) systems to the list of renewable energy equipment eligible for the sales and use tax exemption, and expires in 2017. See more at http://dsireusa.org/incentives/incentive.cfm?Incentive_Code=CO50F&re=1&ee=1 Feed-In-Tariff A Feed-In-Tariff (“FIT”) is a contract that utilities sponsor, whereby other companies and individuals generate electricity and sell the power at specified rates back to the utility. The advantage of a FIT is that a person or company can set up an alternative energy system and sell power to the utility without having certain limitations, like in a net metering agreement. (A net metering plan typically limits the amount of electricity one can sell back to a utility by what that person or entity consumes, at or below the consumer rate.) A FIT has fewer restrictions and it sets specific kWh rates that the utility will pay over a period of time like 10 or 15 years for solar, biomass, or wind generated electricity. Such timeframes help developers recoup the cost of the investment. Recent FITS in the US were announced by Northern Indiana Power Company in June and were sold out in a matter of weeks, and the Oregon FIT was sold out 45 minutes after it was released, due to its generous solar rates. See http://solaroregon.org/residential-solar/steps-to-solar/solar-electric/feed-in-tariff and http://www.dsireusa.org/incentives/incentive.cfm?Incentive_Code=IN79F&re=1&ee= 0 2.4 Summary Table 2-1 summarizes the distributed generation and load reduction or load shifting technologies discussed in this report. High-level planning assumptions are used to attempt the quantify a potential capacity reduction and cost of each technology, assuming a peak load reduction of up to 85 MW for 178 hours/year (based on Platte River’s estimate as of August 22nd), as well as the likely schedule required to implement it. None of these technologies could be implemented in time to resolve the transmission issues anticipated next summer without the Dixon Creek-Horseshoe 230-kV line, and it is doubtful that any single solution could achieve the desired load reduction in a reasonable time period. However, a combination of technologies could provide significant benefit. Table 2-2 Summary of Peak Load Reduction Options Peak Load Reduction Options Type MW MW at Peak Hour Cost/ kW Total Cost Ongoing Annual Costs Site Availability Installation Timeframe (Mo) Notes Municipal Solid Waste Generation 14 14 $ 4,500 $ 63M $ 5M Larimer County Landfill 24 mo Landfill solid waste dried and burned to generate electricity Biomass Generation 35 35 $ 4,500 $ 157M $ 5M Horseshoe Substation biomass location 24 mo Biomass gas burned to generate electricity Solar PV w/ Battery Storage Generation 85 85 $ 5,410 $ 460M $ 10M Requires 400+ acres 18 Mo+ Battery storage required to shift the timing of electricity put onto the grid to peak hours. Solar Thermal Electric Generation 85 85 $ 4,000 $ 340M $ 6M Requires 500+ acres 24 Mo Molten salt storage creates steam to generate electricity at any time of day including peaks. Gas Turbines Generation 95 95 $ 1,000 $95.5M $ 3M Minimum of 15 acres 24 - 36 Mo Only included EPC costs and add 15 percent for owner's costs Fuel Cells Generation 85 85 $ 8,000 $ 680M $ 1M TBD. Requires survey for natural gas fuel and location 24 - 36 Mo New technologies at cutting edge, may or may not be available by next summer in sufficient quantities. Combined Heat and Power Generation 100 100 $ 1,350 $ 135M $ 5M Minimum of 15 acres 24 Mo Major long lead equipment (CT and STG) needs to procured prior to EPC Contract. Only included EPC costs and add 15 percent for owner's costs Emergency Gen Sets in Area Load Reduction 12.5 10 $ 52 $ 518K $ 500k to $700k Requires existing diesel backup generators Peak Load Reduction Options Type MW MW at Peak Hour Cost/ kW Total Cost Ongoing Annual Costs Site Availability Installation Timeframe (Mo) Notes Smart Meters w/ TOU Rates Load Reduction/S hifting 85 85 $ 100 $ 8.5M $ .85 M Cost to install 30k Loveland residential and commercial electric meters only. Does not include cost for 65k meters in Ft. Collins Install smart meters in Loveland commercial and residential properties. Use higher rate band during 4 p.m. to 8 p.m. in both Loveland and Ft. Collins to lower peak usage. Community Energy Storage (CES) Load Shifting 135 85 $ 3,125 $ 265M $ 5.3M TBD. Requires 2650 locations 24 - 36 Mo Batteries provide home backup and can send power to the grid during peak hours Hybrid Ice Air Conditioning Load Shifting 46 46 $ 1,700 $ 76M $ 1.5M 1/4 to 1/3 of buildings 24 Mo 2500 (+- 30%) ice systems to install. Operates 800 hours/yr. during peaks. Local production facilities could be built between Loveland and Ft. Collins, good for local economy and shorten delivery/installation timeframes. Karen Weitkunat, Mayor Council Information Center Kelly Ohlson, District 5, Mayor Pro Tem City Hall West Ben Manvel, District 1 300 LaPorte Avenue Lisa Poppaw, District 2 Fort Collins, Colorado Aislinn Kottwitz, District 3 Wade Troxell, District 4 Cablecast on City Cable Channel 14 Gerry Horak, District 6 on the Comcast cable system Darin Atteberry, City Manager Steve Roy, City Attorney Wanda Krajicek, City Clerk The City of Fort Collins will make reasonable accommodations for access to City services, programs, and activities and will make special communication arrangements for persons with disabilities. Please call 221-6515 (TDD 224- 6001) for assistance. WORK SESSION October 11, 2011 after the Adjourned Meeting 1. Call Meeting to Order. 2. Residential Electric Rate Options, Efficiency and Conservation. (staff: Brian Janonis, Patty Bigner, John Phelan, Laurie D’Audney, Bill Switzer, Steve Catanach; 90 minute discussion) In two previous City Council work sessions, May 10 and September 13, 2011, staff presented electric rate design principles, four residential rate options, a change to the residential demand rate and a pilot Time of Use rate for electric vehicles. At the September 13 Work Session, Council also discussed a change to the General Service (GS) or commercial rate proposed by staff that will result in two rate classes, a GS (up to 25 kW) and GS 25 (25 – 50 kW). The September 13 Work Session resulted in two areas of follow-up: (1) further review of the four residential electric rate options with answers to five specific questions as noted in the work session summary; and (2) scheduling of a work session discussion on energy efficiency and water conservation. Staff and SAIC consultant Joe Mancinelli will provide additional information to answer questions from Council regarding the four residential energy rate options. Also, for this follow-up work session, staff will present a review of the City’s efficiency and conservation programs. Ordinances for General Service (GS or commercial) rate changes and the Residential Demand (RD) rate will be considered on October 18, 2011 and November 1, 2011. These Ordinances do not include proposed changes to the Residential (R) energy rate. Public outreach for these draft ordinances began on September 29 with a post card mailed to out-of-city limits customers and a public notice published in the Coloradoan on October 2, 2011. Once the Ordinances are adopted, additional public outreach will take place, beginning with a bill insert mailed throughout late November and December. Feedback from this work session will be used in drafting rate ordinances for public comment and Council consideration and implementation early in 2012. The tentative schedule for implementing changes to the Residential (R) rate include beginning public notification on November 6, followed by First Reading of the Residential rate Ordinance on November 15 and Second Reading on December 6, 2011. If this tentative schedule is finalized, the rate change will be effective February 1, 2012. Public outreach will begin January 1, 2012. Additional outreach will occur throughout the spring and early summer as needed to support customer understanding. 3. Presentation of the City Manager's Recommended 2012 Budget Revision Requests. (staff: Darin Atteberry, Mike Beckstead; 90 minute discussion) The purpose of this work session is to review the 2012 Budget Revision Requests to be considered for inclusion in the 2012 Annual Appropriation Ordinance. The Ordinance will be considered on First Reading on October 18, 2011. 4. Other Business. 5. Adjournment. DATE: October 11, 2011 STAFF: Brian Janonis, Patty Bigner, John Phelan, Laurie D’Audney, Bill Switzer, Steve Catanach Pre-taped staff presentation: available at fcgov.com/clerk/agendas.php WORK SESSION ITEM FORT COLLINS CITY COUNCIL SUBJECT FOR DISCUSSION Residential Electric Rate Options, Efficiency and Conservation. EXECUTIVE SUMMARY In two previous City Council work sessions, May 10 and September 13, 2011, staff presented electric rate design principles, four residential rate options, a change to the residential demand rate and a pilot Time of Use rate for electric vehicles. At the September 13 Work Session, Council also discussed a change to the General Service (GS) or commercial rate proposed by staff that will result in two rate classes, a GS (up to 25 kW) and GS 25 (25 – 50 kW). The September 13 Work Session resulted in two areas of follow-up: (1) further review of the four residential electric rate options with answers to five specific questions as noted in the work session summary; and (2) scheduling of a work session discussion on energy efficiency and water conservation. Staff and SAIC consultant Joe Mancinelli will provide additional information to answer questions from Council regarding the four residential energy rate options. Also, for this follow-up work session, staff will present a review of the City’s efficiency and conservation programs. Ordinances for General Service (GS or commercial) rate changes and the Residential Demand (RD) rate will be considered on October 18, 2011 and November 1, 2011. These Ordinances do not include proposed changes to the Residential (R) energy rate. Public outreach for these draft ordinances began on September 29 with a post card mailed to out-of-city limits customers and a public notice published in the Coloradoan on October 2, 2011. Once the Ordinances are adopted, additional public outreach will take place, beginning with a bill insert mailed throughout late November and December. Feedback from this work session will be used in drafting rate ordinances for public comment and Council consideration and implementation early in 2012. The tentative schedule for implementing changes to the Residential (R) rate include beginning public notification on November 6, followed by First Reading of the Residential rate Ordinance on November 15 and Second Reading on December 6, 2011. If this tentative schedule is finalized, the rate change will be effective February 1, 2012. Public outreach will begin January 1, 2012. Additional outreach will occur throughout the spring and early summer as needed to support customer understanding. October 11, 2011 Page 2 GENERAL DIRECTION SOUGHT AND SPECIFIC QUESTIONS TO BE ANSWERED 1. Has sufficient information been provided to support City Council’s decision to adopt a residential energy rate ordinance with one of the four options? 2. Which of the four options proposed for consideration does City Council prefer for implementation? BACKGROUND / DISCUSSION I. RESIDENTIAL ELECTRIC RATE OPTIONS As noted in the September 13, 2011 Work Session Summary, four electric rate options were proposed for Council discussion including: • Single Tier (current rate structure) • Seasonal (Platte River Power Authority pass-through) • Three Tier • Five Tier As follow-up to its discussion, Council requested the following additional information: 1. Assumptions related to elasticity (in plain English) – what kind of impact can be expected? What is the corresponding carbon reduction? Price elasticity of demand is a measure used in economics to show the responsiveness, or elasticity, of the quantity demanded of a good to a change in its price. It is expressed as percentage change in quantity demanded in response to a one percent change in price (holding constant all the other determinants of demand). Price elasticity is almost always negative, meaning as price rises, demand declines. The resulting carbon reduction is determined by the calculated energy reduction, converted to carbon based on the most recent conversion factors, coordinated with Climate Action Plan reporting. (See Attachment 4, Price Elasticity Graphs and Attachment 5, Estimated Reduction in Carbon Emissions) Are the options designed to be revenue neutral? If demand and energy are reduced, the purchase power requirements will also be reduced lowering overall revenue requirements. Yes, the options are designed to be revenue neutral. The term, “Revenue Neutrality” in the utility industry, and applied here, is the concept that each of the proposed rate form options is planned to collect the same amount of revenue from residential customers. Generally, Fort Collins does not collect more revenue than the cost of service from its retail rate classes (customers). During any given year, revenues may slightly exceed costs or fall short with the variations adding to or reducing reserves. With the reduction of demand and energy, purchase power requirements will also be reduced. (See Attachment 6, System Benefits and Attachment 7, Relationship Between System Costs and Retail Price) October 11, 2011 Page 3 Based on the experience of SAIC, as well as its review of industry literature, there does not appear to be any indication that a tiered rate structure would result in higher system demands than a non-tiered rate structure. While the impact on reduced demand is anticipated to be less than the reduction in energy due to a tiered rate structure, no studies (with which SAIC is familiar), have indicated a higher system demand as a result of implementing tiered rates. 2. Provide more data on the monthly variation in bill impacts, including the typical variation in monthly use. The table below shows average annual customer use expressed in terms of average and median for residential customers on two housing types (does not include residential demand rate customers). This information helps with understanding that the graphs illustrating average bill impacts use data points along the entire range of customer use, whereas the median, or group of customers in the middle, may have less of an impact. More information on this question is answered below. 2010 Residential Energy Rate Data Summary Statistics 2010 Data Total kWh/mo Single Family kWh/mo Multifamily kWh/mo Average 691 794 508 1st Quartile 353 444 253 Median 568 667 405 3rd Quartile 877 987 639 3. Provide sample (8 to 10) scenarios of year round use and the price impacts of the options. Examples: Large users with no AC, large users with AC, small users with AC, small users without AC, etc. A group of Utility staff/friends offered their billing data to help answer this question. This includes energy use among customers with various home sizes, family sizes and lifestyles offered their billing information for this request. (See Attachment 8, Bill Impacts on Selected Customers) Additional Information Relevant to Consideration of Change Rate Form A histogram has been compiled of customer bills that shows the distribution of the bills of a sample of low income customers and the range of their electricity use. Although customer data about income level is not generally known, this group of customers participated in a special program and provided their billing data voluntarily for staff analysis. (Attachment 9, Energy Usage for Low Income Customers) October 11, 2011 Page 4 Based on limited knowledge, as well as anecdotal information and the prevalence of low income assistance programs throughout the country, Utilities is expanding programs to assist this sector of its customers. Currently, Utilities offers payment assistance, zero interest loans and incentives for efficiency upgrades, but this assistance is not provided based on income qualifications. New programs will expand financing, offer additional audit and conservation assistance as well as other financial considerations. Similar provisions will be provided to customers with special medical needs. These programs are being planned regardless of the rate form adopted by City Council; however staff recognizes that all rate increases, and changes to rates (increasing blocks or tiers) that are designed to encourage conservation place an additional financial burden on low income customers, particularly those with higher than average energy use. Future Time of Use Rates The Advanced Meter Infrastructure (AMI) project involves installation of new digital meter technology that allows customers more information about their energy use, potentially supporting a new rate form for Fort Collins Utilities know as a Time of Use rate. Time of Use rates allow a price to be established not just for the unit of energy used, but also for the time of day when the energy is used. This provides a more accurate price signal to the customer, better reflecting the actual cost to generate and deliver electricity at different times throughout the day. Once the AMI project is completed, electricity use data will be compiled and may be used to develop Time of Use rates for residential customers. However, Utilities does not currently have the necessary data to accurately develop a Time of Use rate for its residential customers. II. CONSERVATION AND EFFICIENCY Efficiency and conservation are primary strategies related to City and Utility policies and resource related objectives. In recent years these programs and related outreach have received a number of awards and kudos from industry organizations. A. Recognition for Fort Collins Utilities Outreach • In 2009, Fort Collins Utilities launched a conservation messaging platform, Fort Collins Conserves. The messaging campaign received the Savvy Award of Excellence from the City-County Communications and Marketing Association in 2010 recognizing outreach achievement in support of public policy. Fort Collins Conserves provides a unified approach for both water and electricity conservation and efficiency outreach. Water • In 2010, Water Conservation Specialist Laurie D’Audney was awarded the Alice Darilek Water Conservation Award from the Rocky Mountain Section of the American Water Works Association. The award recognizes an individual for exceptional performance and commitment to water conservation in the region. October 11, 2011 Page 5 • Western Resource Advocate’s 2011 report, Filling the Gap: Commonsense Solutions for Meeting Front Range Water Needs, recognizes Acceptable Planned Water Supply Projects that meet their six “smart” principles including, “make full and efficient use of existing water supplies and reusable return flows before developing new diversion projects. The Utilities’ Halligan Reservoir Enlargement is labeled an acceptable project as long as efficiency measures are implemented first. Energy • Fort Collins energy efficiency and conservation programs have begun to garner regional and national attention in the last several years. One gauge is simply the inquiries that are now coming to Utilities staff from other utilities and efficiency organizations around the country. In the last six months staff has fielded questions about how it is structuring programs and achieving results from E-Source, the Southwest Energy Efficiency Project (SWEEP), the National Renewable Energy Lab, the Department of Energy, the Environmental Protection Agency and many public utilities. • Earlier this year, SWEEP noted in a press release related to Fort Collins 2010 efficiency savings that, “This is one of the highest savings percentages achieved by any electric utility in the southwest region, demonstrating that even a small utility can implement very effective energy efficiency programs.” ( http://www.swenergy.org/news/news/default.aspx?Year=2011#336) • SWEEP also published a brief report earlier this year in which they noted, “While this utility is small in scale, its DSM programs are large in stature, outperforming most municipal and many investor owned utility DSM programs across the country.” (http://www.swenergy.org/publications/documents/Municipal%20Utility%20Energy%20 Efficiency%20Programs%20-%20Leading%20Lights.pdf) B. Policy Basis and Overview The City’s Climate Action Plan, Energy Policy, Water Supply and Demand Management Policy and Water Conservation Plan establish the policy direction for Fort Collins Utilities programs ranging from education and conservation messages to financial incentives designed to reach City Council goals and reflect community values. In 2003, Council adopted the Electric Energy Supply Policy, followed by the adoption of the Climate Action Plan in 2008 and the current Energy Policy in 2009. These policies clearly emphasize the need for implementation of various strategies and programs for the reduction of electricity use and associated carbon emissions. The Water Supply and Demand Management Policy was adopted by City Council in 2003, providing general direction on water conservation practices. The City’s Water Conservation Plan was approved by the Colorado Water Conservation Board in 2010. In the following descriptions, staff outlines the specifics of policy, what types of programs and services are offered to the community, how outcomes are tracked and reported and the overall benefits of conservation and efficiency from several perspectives. October 11, 2011 Page 6 Climate Action Plan Over a decade ago, Fort Collins was among the first wave of communities in the nation to commit to reducing local greenhouse emissions. City Council adopted a greenhouse gas reduction goal for 2010 and a plan to meet it. In 2008, Council adopted new carbon reduction goals for the Fort Collins community of reducing communitywide emissions 20% below 2005 levels by 2020 and 80% below 2005 levels by 2050. In December 2008, City Council adopted an updated Climate Action Plan for the entire community. (See www.fcgov.com/climateprotection/pdf/climate_action_plan.pdf.) Energy Policy The City of Fort Collins Energy Policy was adopted in January 2009. The primary goals of the Energy Policy are to sustain high-system reliability and to contribute to the community’s climate protection goals and economic health. Water Supply and Demand Management Policy and Water Conservation Plan Since 2003, the Water Supply and Demand Management Policy has provided general criteria for decisions regarding water supply projects, acquisition of water rights and demand management measures. The policy sets water use goals to be achieved by 2010, 185 gallons per capita per day (gpcd) for annual water consumption and 475 gallons per capita (gpc) for peak daily demand. Work is currently in progress to review and update the policy. In 2009, the City’s Water Conservation Plan was approved by the Colorado Water Conservation Board. The Plan reflects specific measures, metrics and costs related to the demand management criteria outlined in the Water Supply and Demand Management Policy. The Plan sets a demand goal of 140 gpcd, a decrease from the 185 gpcd goal in the policy. The Energy Policy, Water Supply and Demand Management Policy and Water Conservation Plan can be found at www.fcgov.com/utilities/what-we-do. Lowest Cost Resources Beyond the policy basis for efficiency and conservation, it has been demonstrated by programs here and around the country that efficiency and conservation are the lowest cost resource for energy and water. As the well known adage goes, the cheapest energy is energy that is not used at all. Efficiency programs can “deliver” electricity at a cost from one to five cents per kilowatt-hour, well below both retail and wholesale costs. Energy efficiency potential studies across the world come to common conclusions that we could be far more efficient in our use of energy and that there are significant barriers to achieving the potential benefits. Efficiency and conservation programs are designed to reduce these barriers to help customers be able to manage their energy use and bills. Water conservation has historically been viewed by the water industry as a temporary source of supply that is invoked during times of drought or other water shortage. This view of conservation’s October 11, 2011 Page 7 role is rapidly changing as utilities use conservation as a viable long-term water supply option. By implementing water conservation programs, Utilities has saved considerable capital and operating costs by deferring a treated water storage reservoir from 2007 to 2015 and delaying an expansion at the water reclamation facility from 2010 to 2028. Complementary Benefits There are many complementary benefits to pursuing and achieving efficiency and conservation savings. Together, these represent the triple-bottom-line benefits promised through sustainability: • Manage and reduce the community’s utility bills. Money not spent on monthly utilities has been demonstrated through research to be used on other goods and services in the local community. • Reduce carbon and pollutant emissions from fossil fuel power plants and reduce direct emissions from on-site natural gas use. Saving water decreases the amount of chemicals and energy used to produce, deliver and heat drinking water. • Improve comfort, health, safety and productivity from efficiency projects. For example, home combustion safety can be addressed or improved lighting quality from business efficiency projects. Customer Expectations Last but not least, Fort Collins customers expect Utilities to provide programs and services related to efficiency and conservation. Through customer satisfaction and other surveys, the results consistently show high levels of support related to these programs. A 2010 market survey found that 88 percent of those surveyed recognized the City as an environmental steward. 21st Century Utilities, Plan Fort Collins Efficiency and conservation are integral to Plan Fort Collins and the Utilities for the 21st Century initiative, which closely align with a broader community vision of protecting and preserving our quality of life in Northern Colorado. Because of the impacts of our environmental footprint and the many challenges facing municipal utilities today, the Utilities for the 21st Century initiative created an ambitious and intentional approach to how we conduct business. The initiative has helped us re-envision our historic and future actions within a framework of sustainable decisions and policy choices. The intention is to deliver a level of service our customers expect and do it in an environmentally and socially responsible way while making the best economic choices for the long term. Our purpose is what guides us today: inspiring community leadership by reducing environmental impact while benefitting customers, the economy and society. October 11, 2011 Page 8 History of Efficiency and Conservation Programs Faced with a drought in 1977, the Utilities hired its first staff dedicated to water conservation, with an emphasis on education programs. With City Council adoption of the Water Demand Management Policy in 1992, the program expanded with a fulltime staff member, additional conservation measures and educational efforts, and landscape and irrigation regulations. The program continues to grow; first with the 2003 Water Supply and Demand Management Policy and then the 2009 Water Conservation Plan. City Council adopted the measures recommended in the Water Conservation Plan through the Budgeting for Outcomes process for the 2011-2012 budgets. Today we offer a full range of incentives, education and regulation. Additionally, Utilities has provided programs and services to help customers manage their energy use for over 25 years. Early programs focused on education, with events such as the Environmental Program Series. Other programs which started in the early 1980s include Energy Score Home Energy Ratings and the ZILCH (Zero Interest Loan for Conservation Help) programs. In 1998, the first commercial financial program, the Integrated Design Assistance Program, started by supporting high performance new construction. Research studies on the state of residential construction performance were also completed in the mid-1990s which led to new education and training initiatives. In 2002 and 2003, Fort Collins began offering appliance rebates through a partnership with ENERGY STAR and Platte River began offering their first commercial and residential rebate programs. The adoption of the Electric Energy Supply Policy in 2003 led to the first dedicated funding for energy efficiency. Since that time, Utilities has added programs and resources in order to reach the goals laid out in the City’s climate and energy policies. Current programs are described later in this agenda item summary. C. Efficiency and Conservation Program Elements Conservation programs use a variety of strategies, or tools, together which provide a comprehensive approach to saving energy and water. Each element addresses specific barriers which customers face when trying to manage their utility use. • Financial incentives: Efficiency alternatives typically carry a price premium in the marketplace. Rebates or incentives are designed to help offset the additional first cost when making the decision to purchase an efficient piece of equipment. This may apply to nearly any energy or water using device, from heating and air conditioning equipment to appliances to light bulbs. A second use for incentives is to encourage the replacement of inefficient technology before the end of its life. Replacing working but inefficient fluorescent lighting or high water use toilets are examples. • Technical assistance: Customers often do not have the internal resources to help them make complex decisions about the best strategies for improving efficiency. Utilities technical assistance resources can provide a roadmap to assist customers make the most effective decisions for their home or business. October 11, 2011 Page 9 • Education: Education is the foundation which helps people understand how their utility use impacts their personal life, the community and our local and global environment. Utilities has a robust education program which serves youth and adults. • Trade allies: Trade allies are the direct service providers within our community. They include retailers, other supply chain vendors, contractors, designers and consultants. Utilities programs promote the awareness of our programs amongst this group, training related to best practices and standards and maintaining provider lists for customer information. • Marketing, outreach, communications, recognition: Efficiency and conservation programs can only be successful based upon the participation of customers. Effective marketing and outreach drives customer awareness, interest and knowledge about available programs. Recognition of customers can also provide a key motivation to help them reach their own goals, such as that provided by the Climate Wise program. • Rate forms: Rate forms can provide additional motivation and alignment with available conservation and efficiency programs. N In 2003, the water rate structures were revised in response to the drought and continue as a means to send a strong conservation message. Residential customers currently have a three-tiered water rate. Commercial and multi-family customers are on a seasonal rate with higher rates from May through September. Commercial rates also have a second tier for higher water use. N Tiered electric rates are under discussion at this work session. There are a number of strategic approaches to achieving efficiency and conservation savings. While they are useful to provide a general understanding of demand side strategies, they are not mutually exclusive. The various strategies reinforce each other and are best used together. • Direct energy or water savings (sometimes called resource acquisition) uses incentives and rebates to achieve quantifiable project results. This is a proven approach of using direct payments to customers to encourage them to use a more efficient technology. The goal for targeted energy savings is essentially to buy energy and demand savings. The strengths of this approach are in the degree of control and measurability. By tracking the number of participants for each rebate type, the budgets and impacts can be well defined and evaluated. • Market transformation strategies promote the manufacture, distribution and purchase of energy and water efficient products and services. The goal of this approach is to establish sustained market share of these products and services and document quantifiable energy and water savings. Market transformation works to remove barriers that limit the adoption of high efficiency products or services. Examples of market barriers include limited availability of energy efficient products, lack of consumer awareness of the products and their benefits, resistance to new products in general and an over emphasis on upfront cost versus operating costs. October 11, 2011 Page 10 • Behavioral programs are relatively new, but are able to quantify the savings achieved through encouraging conservation behavior. Utilities Home Energy Reports is an example of a program which provides specific education and awareness information to a subset of customers. The effects of the additional information can be measured based on the response of a large group of customers compared to those who do not receive the report. Principles for Program Design and Evaluation The following list summarizes a number of principles for how staff design and implement efficiency and conservation programs. • Leverage other successful programs from peer utilities. Most programs have models from which we can learn what has worked or not worked in other service territories. Utilities are generally very willing to share their experiences, results and lessons learned. As we have become more successful with our programs, we are being consulted on a regular basis by other utilities. • There is a robust body of work in the regulatory arena and professional organizations for how to calculate, verify and evaluate efficiency program results. Utilities uses these best practices for reporting on our overall and program specific results. • Minimum efficiency standards continue to change over time, typically with federal regulations on common products (i.e., toilets, refrigerators, motors, light bulbs). Program rebate criteria and levels need to evolve and adapt to ensure that funds are accountable for higher efficiency and utility savings. Collaboration Collaboration is another key principle for Fort Collins implementation of efficiency and conservation programs, deserving of its own section. Key collaborative partnerships include: • Platte River Power Authority: Platte River also has energy efficiency goals with dedicated staff and funding. Several of the programs are administered at the Platte River level on behalf of all four member cities. The mix of programs and funding levels has varied over the last nine years, reflecting the varied goals of each member community and Platte River. Platte River currently provides approximately one quarter of total energy efficiency expenditures in Fort Collins. • Platte River member cities: Utilities also works directly with the other member cities, sharing results, program materials, planning and results. For example, starting in fall 2011, Fort Collins and Loveland are sharing responsibility for the Home Efficiency Program contractor list. • Community partners: Key community partners include Colorado State University, Larimer County and Poudre School District. CSU has implemented many efficiency projects, both in campus buildings and in CSU housing. Utilities has also provided support for education and behavioral change competitions implemented in campus housing. Poudre School District has been a leader in the design, construction and operation of high performance buildings. October 11, 2011 Page 11 With the assistance of Utilities’ efficiency programs, PSD has gained a national reputation for their green new construction and ENERGY STAR labeled schools. Utilities has worked for three years with the Larimer County Youth Conservation Corp to provide direct efficiency assistance to low income customers while providing job training to young adults. • Governor’s Energy Office (GEO): The GEO has provided several grants to Fort Collins related to energy efficiency. The grants have helped to improve the efficiency of municipal buildings, establish a Northern Colorado ENERGY STAR Homes program and demonstrate the capability of using advanced data systems to enhance efficiency programs. The GEO continues to consult with Fort Collins to help demonstrate best practices in efficiency for other utilities in Colorado. • Utilities regularly works with local stakeholders to design programs, reach customers and provide valuable feedback. These stakeholders include the Chamber of Commerce, Fort ZED, the Fort Collins Board of Realtors, the Fort Collins Sustainability Group and the Community for Sustainable Energy. D. Efficiency and Conservation Programs and Services Utilities offers a comprehensive portfolio of programs and services designed to reach all customer sectors and a wide range of end uses. The following tables list program and service offerings from two view points. First the programs are structured to how they reach residential and business customers, both for existing buildings and new construction. The second table shows these programs from an end use and operational perspective. Together they provide a clear picture of Utilities efficiency and conservation portfolio. For a complete list of programs, see www.fcgov.com/conserve. The programs are also linked closely to a wide range of related initiatives, including: • Demand response and load management: The Energy Policy also includes goals related to load management. Programs are offered related to residential electric water heaters and air conditioners and for businesses to help them control coincident demand bill components. • Distributed generation and renewable energy programs are often the next step for customers after implementation of efficiency and conservation measures. • Advanced metering and pricing are also linked because of the relationship between information and specific bill components. With our large commercial rates, close attention is focused on both general efficiency and conservation opportunities as well as time differentiated load management. This will become an increasing focus as the new advanced meters are installed in the coming two years. October 11, 2011 Page 12 Fort Collins Utilities Efficiency and Conservation Programs and Services (sector view) Sector Building Type Program or Service Residential Existing • Home Efficiency Program (audits, rebates, contractors) • Consumer products (energy and water) • Home Energy Reports • Environmental Program Series • Sprinkler system audits New • NoCO ENERGY STAR Homes • Green Building Code amendments • Consumer products (energy and water) Commercial and Industrial Existing • Efficiency assessments • Electric Efficiency Program incentives (equipment and custom) • LightenUP Program incentives (business lighting) • Consumer products (energy and water) • Energy Challenge • Climate Wise • Landscape and irrigation Standards for Water Conservation New • Integrated Design Assistance Program • Green Building Code amendments • Consumer products (water) Fort Collins Utilities Efficiency and Conservation Programs and Services (end use view) Program Type Description Consumer Products • ENERGY STAR clothes washer and dishwasher rebates • Refrigerator and freezer recycling • Compact fluorescent light bulbs • LED lighting (bulbs and holiday lighting) • Watersense labeled toilet and urinal rebates • Sprinkler equipment rebates Retrofit and capital upgrade incentives • Insulation and air sealing • Business lighting • Major equipment for business • Custom energy and water incentives • Office equipment/information technology • Food service equipment (energy and water) • Refrigeration equipment • Windows October 11, 2011 Page 13 Program Type Description Operations, conservation, education, technical assistance • Business building tune-up (retro-commissioning) • Business Efficiency Challenge • Home Energy Reports • Xeriscape Design Clinics • Xeriscape Demonstration Garden • Sprinkler system audits • Environmental Program Series • Business Innovation Fair • Climate Wise • Efficiency Assessments Regulations • Wasting water enforcement • Landscape and Irrigation Standards for Water Conservation • Building Code Green Amendments E. Accountability and Reporting The Energy Policy has two objectives which relate to efficiency and conservation. One is related to carbon emissions and the other is verifiable electricity savings. As noted, Fort Collins has a community goal of reducing carbon emissions 20% below 2005 levels by 2020. One of the Energy Policy objectives is to support this community goal with reductions at the same level from the electric utility sector. Fort Collins annually reports on the community emissions with the Climate Action Plan Status report and the Energy Policy Annual Update. A critical distinction of the emissions reporting at the community scale is that it is by definition an inventory. In this respect, “everything” counts because the results incorporate the local economy, weather impacts and all customer efficiency and conservation behavior. The Energy Policy also has a specific objective related to efficiency and conservation program results. This objective is to annually achieve verifiable program savings equivalent to 1.5% of the community’s electricity use. This is often mischaracterized as having the outcome that Fort Collins electric use will be reduced by 1.5% per year. The net impact of whether electricity use goes up or down is first and foremost tied to economic activity and weather. If electricity use would have grown by 2.0% in a given year, it should be reduced to 0.5% with successful efficiency program implementation. This efficiency program annual target is an aggressive goal compared to many utilities around the country. However, it is also very valuable because it provides a specific electric savings target which supports both budgeting and reporting. The Water Conservation Plan sets a goal of 140 gallons per capita per day (gpcd) by the year 2020. This goal represents realistic and achievable demand reductions in all customer sectors. Achieving this goal will provide an additional measure of reliability to the water supply system to ensure high quality serve to customers in case of future drought, climate change and unforeseen shortages. The per capita annual consumption is calculated by dividing annual total system-wide water use by the population served and 365 days. This calculation is adjusted for weather to provide a fair October 11, 2011 Page 14 comparison with other years. Utilities monitors water demand and reports the gcpd calculations through an annual report. In 2010, the adjusted average demand was estimated to be 144 gpcd, compared with 147 gpcd in 2009. F. Program Results This section summarizes the quantifiable results of Utilities efficiency and conservation programs. Various metrics are used which together help to describe a comprehensive picture of both the community’s electricity and water use as well as energy efficiency program savings. Attachment 10 shows charts of the results described here. Water Efficiency and Conservation Results Water use trends have continued to decrease based on a number of factors. Historical use (1985- 1992) was over 230 gpcd. Low-flow plumbing standards and metered water taps contributed to the reduction of per capita water use which was 196 gpcd in the pre-drought period (1993-2001). More recently, when adjusted for the weather conditions of 2010, per capita use declined from 2009. Tiered and seasonal water rates, and continuing water conservation efforts, have all contributed to the trend of decreased water use. The most recent period from 2004-2010 water use is at 153 gpcd. Energy Efficiency and Conservation Program Results The following sections describe specific metrics related the community’s electricity use and savings from verified efficiency programs. • Community Carbon Emissions from Electricity Sector: The 2010 Energy Policy update documents electricity carbon emissions from the community. Compared to the 2005 baseline, emissions were over 11% less in 2010. • Community Electric Use Per Capita (2002 – 2010): While electricity use per capita is not one of the Energy Policy goals, it is one indicator of how efficient the community is in using electricity. Compared to the 2005 baseline, per capita electricity use was 8.8% less in 2010. • Customers Served through Efficiency Programs (2002 – 2010): Efficiency programs have completed 689 business projects, over 19,000 residential rebates and over 175,000 retailer transactions since 2002. The programs are successfully reaching a wide range of our customer base. • Fort Collins Efficiency Programs – Annual Electricity Savings (2002 – 2010): Annual program savings is a key metric for Utilities, as it relates to the Energy Policy goal and can be benchmarked with other utilities. Since 2002, programmatic savings have increased an average of 48% per year, reaching over 20 million kilowatt-hours in 2010. • Fort Collins Efficiency Programs – Cumulative Annual Electricity Savings (2002 – 2010): Energy efficiency projects have a lifetime, based on the technology and project type. Projects completed this year continue to save energy in years two and beyond. This metric reflects the annual savings from current and past years combined. In 2011, the community October 11, 2011 Page 15 is using over 84 million kilowatt-hours less than they would have without efficiency program savings. • Fort Collins Efficiency Programs – Investment and Customer Savings (2002 – 2010): It is also important to document the investment and savings related to efficiency programs. Since 2002, Utilities and Platte River have invested over $9M in efficiency programs. The savings for customers has accumulated to over $5M PER YEAR in 2011. ATTACHMENTS 1. PowerPoint Presentation 2. Work Session Summary, May 10, 2011 3. Work Session Summary, September 13, 2011 4. Price Elasticity Graphs 5. Estimated Reduction in Carbon Emissions 6. System Benefits 7. Relationship Between System Costs and Retail Price 8. Bill Impacts on Selected Customers 9. Energy Usage of Low Income Customers 10. Efficiency and Conservation Results and Metrics Attachment 1, October 11, 2011 1 © 2011 by R. W. Beck, An SAIC Company. All Rights Reserved. Residential Electric Rate Options; Efficiency and Conservation FORT COLLINS CITY COUNCIL WORK SESSION October 11, 2011 R. W. Beck, An SAIC Company | 22 Council Direction During September 13, 2011 work session, Council requested more information related to the residential electric rate options: ƒ Price elasticity ƒ Benefits to the system ƒ Customer impacts ƒ Efficiency and conservation programs Attachment 1, October 11, 2011 2 R. W. Beck, An SAIC Company | 33 Agenda/Purpose ƒ Council Direction & Response ƒ Definitions/Clarifications ƒ Price Elasticity ƒ Residential Customer Class Rate Design and Staff Recommendations ƒ Efficiency and Conservation Programs Briefing R. W. Beck, An SAIC Company | 44 Questions for City Council 1. Has sufficient information been provided to support City Council’s decision to adopt a residential energy rate ordinance with one of the four electric rate options? 2. Which of the four options proposed for consideration does City Council prefer for implementation? Attachment 1, October 11, 2011 3 R. W. Beck, An SAIC Company | 55 Residential Electric Rate Options R. W. Beck, An SAIC Company | 66 Response to City Council Questions ƒ Refined price elasticity calculations ƒ Added price elasticity to Seasonal Rate Option ƒ Minor adjustment to Three and Five‐Tier Rate Options ƒ Calculated proposed rates on a monthly and annual basis for the majority of residential customers ƒ Calculated bill impacts on: ƒ 12 months of historical class billing data ƒ Actual bills from a select group of customers with demographic information (house size, number of occupants, etc) Attachment 1, October 11, 2011 4 R. W. Beck, An SAIC Company | 77 Definitions/Clarifications ƒ Rate Structure is the design of utility’s means of recovering its costs from its customers. An unbundled rate structure shows itemized charges on the bill reflecting the costs associated with each utility function. ƒ Fixed Charge is a monthly charge that recovers the cost of metering, billing, collecting, providing customer service, and all other customer‐related costs. ƒ Distribution Facilities Charge recovers the operational cost of distribution substations, poles, wires, conductors, and transformers required to deliver power to customers. For residential customers this charge is applied on a $/kWh basis. ƒ Energy Charge recovers the cost of fuel, purchased power, and all other variable costs associated with the production of electricity. ƒ Demand Charge recovers fixed production function costs related to building and financing generation facilities. R. W. Beck, An SAIC Company | 88 Definitions/Clarifications ƒ PILOT (Payment in Lieu of Taxes) is a transfer from the Utilities to the City’s General Fund. ƒ Seasonal Rates are a simple type of time‐of‐use rates in which rates vary depending on the time of year. ƒ Tiered Rates/Block Rates are a rate structure that charges differing amounts for each unit of consumption within each tier on a kWh basis. Inclining tiers/blocks, charge higher prices for each unit of energy consumed as consumption increases. ƒ Top Tier/Block is the last tier/block of energy in a tier rate structure ƒ Revenue Neutrality is the concept that each of the proposed rate form options is planned to collect the same amount of revenue from residential customers . Attachment 1, October 11, 2011 5 R. W. Beck, An SAIC Company | 99 Definitions/Clarifications ƒ Time‐of‐Use Rates (TOU) are designed to better reflect variations in the utility’s power costs (seasonally and at various times of the day) and provide an incentive for customers to reduce energy during peak periods and/or shift energy usage to times when the utility’s production is more efficient and costs are lower. ƒ PRPA (Platte River Power Authority) is Fort Collins Utility’s wholesale power supply provider. ƒ Pass Through are costs Fort Collins Utilities incurs from Platte River Power Authority and passes on to customers. R. W. Beck, An SAIC Company | 1100 Definitions/Clarifications ƒ Price elasticity of demand is a measure used in economics to show the responsiveness, or elasticity, of the quantity demanded of a good to a change in its price ƒ It is expressed as percentage change in quantity demanded in response to a one percent change in price (holding constant all the other determinants of demand) ƒ Price elasticity is almost always negative, meaning as price rises, demand declines Attachment 1, October 11, 2011 6 R. W. Beck, An SAIC Company | 1111 Price Elasticity of Electricity Rates Price elasticity varies widely ƒ Electric Power Research Institute (EPRI) reviewed results of numerous pricing pilots; results ranging from ‐0.08 to ‐0.39 ƒ Common finding was that higher‐use customers exhibit larger price elasticity ƒ Brattle Group found that long‐run price elasticity is substantially higher than short‐run price elasticity R. W. Beck, An SAIC Company | 1122 Price Elasticity of Electricity Rates ƒ Public Utilities Fortnightly (August 2008) article ƒ Inclining block rates can provide energy consumption savings ƒ Price elasticity ranges: Distribution of Residential Price Elasticities Low Most Likely High Short Run Block 1 ‐0.01 ‐0.13 ‐0.20 Block 2 ‐0.02 ‐0.26 ‐0.39 Long Run Block 1 ‐0.03 ‐0.39 ‐0.60 Block 2 ‐0.06 ‐0.78 ‐1.17 Source: Ahmad Faruqui, Brattle Group, Inclining Toward Efficiency Attachment 1, October 11, 2011 7 R. W. Beck, An SAIC Company | 1133 Residential Energy Customer Class Single‐family dwellings and individually metered apartments R. W. Beck, An SAIC Company | 1144 Current Residential Rate Current Rate Fixed Charge ($/Bill) $3.91 Distribution Facilities Charge ($/kWh) $0.0220 Total Energy Charge ($/kWh) (Energy Charge + Demand Charge) $0.0532 Attachment 1, October 11, 2011 8 R. W. Beck, An SAIC Company | 1155 Residential Rate Structure Alternatives ƒ Single Tier (Current Rate Structure) ƒ Seasonal Rate (PRPA Pass Through) ƒ Three‐Tier Rate ƒ Five‐Tier Rate * All alternatives are designed to recover the same amount of revenue in 2012. R. W. Beck, An SAIC Company | 1166 Residential Customer Class – Energy Usage Characteristics Attachment 1, October 11, 2011 9 R. W. Beck, An SAIC Company | 1177 Energy Usage Characteristics of Low Income Single Family Households vs. Overall System Low Income single family comparison (2010 data) 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% - 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 kWh block % of bills in block Sample of 179 single family low income Single family population R. W. Beck, An SAIC Company | 1188 Low Income multi-family comparison (2010 data) 0% 2% 4% 6% 8% 10% 12% 14% Attachment 1, October 11, 2011 10 R. W. Beck, An SAIC Company | 1199 Single Tier Single Tier Rate Fixed Charge ($/Bill) $4.48 Distribution Facilities Charge ($/kWh) $0.0252 Total Energy Charge ($/kWh) (Energy Charge + Demand Charge) $0.0540 R. W. Beck, An SAIC Company | 2200 Single Tier 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Monthly Energy Per Bill (kWh) Number of Bills Current Rate Summer % Change Non Summer % Change Annual % Change Attachment 1, October 11, 2011 11 R. W. Beck, An SAIC Company | 2211 Single Tier Bill Impacts ‐ Number of Customers 0 5,000 10,000 15,000 20,000 25,000 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% Number of Customers Range [5.4 to 12%] R. W. Beck, An SAIC Company | 2222 Seasonal Rate (PRPA Pass Through) Seasonal Rate Fixed Charge ($/Bill) $4.48 Distribution Facilities Charge ($/kWh) $0.0256 Total Energy Charge (Energy Charge + Demand Charge) Summer* ($/kWh) $0.0640 Non Summer ($/kWh) $0.0506 *Summer Months: June, July, & August Attachment 1, October 11, 2011 12 R. W. Beck, An SAIC Company | 2233 Seasonal Rate (PRPA Pass Through) 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Monthly Energy Per Bill (kWh) Number of Bills Current Rate Summer % Change Non Summer % Change Annual % Change R. W. Beck, An SAIC Company | 2244 Seasonal Rate (PRPA Pass Through) Bill Impacts ‐ Number of Customers Attachment 1, October 11, 2011 13 R. W. Beck, An SAIC Company | 2255 Tiered Rate Structure Rate Design Objectives ƒ To send a strong pricing signal to large users of electricity to incentivize conservation ƒ To generate sufficient revenue to meet the residential class revenue requirement ƒ To follow the seasonal variation in PRPA wholesale power costs ƒ To design tiered rates so that monthly customer bills will be greater than or equal to bills rendered under the existing rate structure R. W. Beck, An SAIC Company | 2266 How does a Tiered Rate work? Tier (A) Rate ($/kWh) (B) kWh (A x B) Calculation Tier 1 [1-500 kWh] $0.0500 500 $25.00 Tier 2 [501-1000 kWh] $0.0600 500 $30.00 Tier 3 [1001 kWh & Higher] $0.0900 200 $18.00 Total or Average $0.0667 1,200 $73.00 1,200 kWh Customer Attachment 1, October 11, 2011 14 R. W. Beck, An SAIC Company | 2277 Three‐Tier Rate Three-Tier Rate Fixed Charge ($/Bill) $4.48 Distribution Facilities Charge ($/kWh) $0.0256 Total Energy Charge (Energy Charge + Demand Charge) Summer* ($/kWh) Tier 1 [1-500 kWh] $0.0531 Tier 2 [501-1000 kWh] $0.0689 Tier 3 [1001 kWh & Higher] $0.1005 Non Summer ($/kWh) Tier 1 [1-500 kWh] $0.0482 Tier 2 [501-1000 kWh] $0.0520 Tier 3 [1001 kWh & Higher] $0.0603 *Summer Months: June, July, & August R. W. Beck, An SAIC Company | 2288 Three‐Tier Rate 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Attachment 1, October 11, 2011 15 R. W. Beck, An SAIC Company | 2299 Three‐Tier Rate Bill Impacts ‐ Number of Customers R. W. Beck, An SAIC Company | 3300 Five‐Tier Rate Five-Tier Rate Fixed Charge ($/Bill) $4.48 Distribution Facilities Charge ($/kWh) $0.0256 Total Energy Charge (Energy Charge + Demand Charge) Summer* ($/kWh) – June, July & August Tier 1 [1-500 kWh] $0.0514 Tier 2 [501-1000 kWh] $0.0655 Tier 3 [1001kWh – 1500 kWh] $0.0938 Tier 4 [1501-2000 kWh] $0.1362 Tier 5 [2001 kWh & Higher] $0.1873 Non Summer ($/kWh) Tier 1 [1-500 kWh] $0.0482 Tier 2 [501-1000 kWh] $0.0515 Tier 3 [1001kWh 1500 kWh] $0.0577 Tier 4 [1501-2000 kWh] $0.0660 Tier 5 [2001 kWh & Higher] $0.0686 Attachment 1, October 11, 2011 16 R. W. Beck, An SAIC Company | 3311 Five‐Tier Rate 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Monthly Energy Per Bill (kWh) Number of Bills Current Rate Summer % Change Non Summer % Change Annual % Change R. W. Beck, An SAIC Company | 3322 Five‐Tier Rate Bill Impacts ‐ Number of Customers Attachment 1, October 11, 2011 17 R. W. Beck, An SAIC Company | 3333 Comparing All Residential Options 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Monthly Energy Per Bill (kWh) Summer Rates Number of Bills Current Rate Single Tier Seasonal Rate Three‐Tier Rate Five‐Tier Rate R. W. Beck, An SAIC Company | 3344 Comparing All Residential Options 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 Attachment 1, October 11, 2011 18 R. W. Beck, An SAIC Company | 3355 Comparing All Residential Options 23,877 46,131 67,267 76,559 74,925 68,003 58,309 47,721 37,865 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Monthly Energy Per Bill (kWh) Annual Average Rates Number of Bills Current Rate Single Tier Seasonal Rate Three‐Tier Five‐Tier R. W. Beck, An SAIC Company | 3366 Comparing All Residential Options Bill Impacts - Number of Customers 0 5,000 10,000 15,000 20,000 25,000 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% Attachment 1, October 11, 2011 19 R. W. Beck, An SAIC Company | 3377 Comparing All Residential Options Bill Impacts - Number of Customers 0 5,000 10,000 15,000 20,000 25,000 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% Number of Customers Single Tier Seasonal R. W. Beck, An SAIC Company | 3388 Comparing All Residential Options Bill Impacts - Number of Customers 0 5,000 10,000 15,000 20,000 25,000 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% Number of Customers Single Tier Seasonal Three‐Tier Attachment 1, October 11, 2011 20 R. W. Beck, An SAIC Company | 3399 Comparing All Residential Options Bill Impacts - Number of Customers 0 5,000 10,000 15,000 20,000 25,000 0.0% 2.0% 4.0% 6.0% 8.0% 10.0% 12.0% 14.0% 16.0% 18.0% 20.0% Number of Customers Single Tier Seasonal Three‐Tier Five‐Tier R. W. Beck, An SAIC Company | 4400 Bill Impacts on Selected Customers Selected House Square Feet # of Occupants A/C Annual Average (kWh) Highest Winter Usage (kWh) Highest Summer Usage (kWh) A 4,242 2 Yes 633 851 726 B 3,306 4 Yes 1,692 3,026 1,762 C 3,000 3 Yes 928 1,075 1,485 D 2,980 7 No 641 915 594 E 2,850 2 Yes 567 876 650 F 2,700 4 Yes 654 566 1,112 G 2,621 2 Yes 482 615 644 H 2,600 2 Yes 803 1,057 1,137 I 2,500 4 Yes 362 508 406 J 2,275 2 No 507 524 625 K 2,000 2 No 606 1,391 474 Attachment 1, October 11, 2011 21 R. W. Beck, An SAIC Company | 4411 Bill Impacts on Selected Customers R. W. Beck, An SAIC Company | 4422 Bill Impacts on Selected Customers Selected House Average Monthly Bill % Difference Single Tier % Difference Seasonal % Difference Three‐Tier % Difference Five‐Tier A $51.17 6.03% 5.88% 1.92% 0.92% B $126.41 5.61% 5.29% 11.98% 11.33% C $85.00 5.74% 5.51% 6.79% 5.29% D $50.67 6.08% 5.09% 1.05% 0.29% E $45.58 6.11% 6.13% 1.51% 0.59% F $51.67 6.02% 7.83% 4.86% 3.18% G $44.25 6.14% 5.63% 0.97% 0.20% H $70.58 5.83% 5.72% 4.46% 2.97% I $30.83 6.49% 6.22% 0.79% 0.14% J $42.25 6.18% 6.22% 1.01% 0.19% K $47.83 6.08% 4.78% 1.28% 0.52% Attachment 1, October 11, 2011 22 R. W. Beck, An SAIC Company | 4433 System Benefits Estimated Percent Change in Annual Energy No Elasticity Mid Elasticity High Elasticity Seasonal 0.0% ‐1.0% ‐1.5% Three‐Tier 0.0% ‐1.1% ‐1.6% Five‐Tier 0.0% ‐1.2% ‐1.7% Estimated Percent Change in Summer Peak Demand No Elasticity Mid Elasticity High Elasticity Seasonal 0.0% ‐1.8% ‐2.7% Three‐Tier 0.0% ‐1.8% ‐2.6% Five‐Tier 0.0% ‐1.8% ‐2.6% R. W. Beck, An SAIC Company | 4444 System Benefits Estimated Annual GHG Savings (Metric Tons) No Elasticity Mid Elasticity High Elasticity Seasonal 0 3,046 4,518 Three‐Tier 0 3,463 5,031 Five‐Tier 0 3,667 5,185 Estimated Annual Purchased Power Savings ($) No Elasticity Mid Elasticity High Elasticity Seasonal $0 $218,535 $324,174 Three‐Tier $0 $244,370 $354,732 Five‐Tier $0 $257,237 $363,223 Attachment 1, October 11, 2011 23 R. W. Beck, An SAIC Company | 4455 System Benefits Estimated Avoided Capital Cost of New Peaking Capacity ($1,000) No Elasticity Mid Elasticity High Elasticity Seasonal $0 $1,336 $1,982 Three‐Tier $0 $1,336 $1,928 Five‐Tier $0 $1,344 $1,880 R. W. Beck, An SAIC Company | 4466 Summary: Residential Rate Alternatives Single Tier Seasonal (PRPA Pass Through) Three-Tier Five-Tier Increasing Conservation Signal Attachment 1, October 11, 2011 24 R. W. Beck, An SAIC Company | 4477 Staff Recommendation ƒ 3‐Tier Residential Rate ƒ Aligns with Energy Policy and Climate Action Plan ƒ Supports participation in efficiency and conservation programs ƒ Other Considerations ƒ Customer outreach ƒ Expansion of customer assistance programs, including low‐ income and special medical needs R. W. Beck, An SAIC Company | 4488 Efficiency and Conservation Programs (Energy and Water) Attachment 1, October 11, 2011 25 R. W. Beck, An SAIC Company | 4499 ƒ Recognition of Fort Collins Results ƒ Policy Direction and Goals ƒ Rationale for Efficiency Programs ƒ History ƒ Program Elements, Strategies and Principles ƒ Current Programs ƒ Performance Results and Metrics Overview R. W. Beck, An SAIC Company | 5500 Definitions/Clarifications ƒ Efficiency: reducing resource use to achieve the same outcome (light level, comfort, production, etc.) ƒ Conservation: reducing resource use through behavioral change and eliminating waste ƒ Demand‐Side Management: Utility term for programs which impact the “customer side” of the meter ƒ Demand Response: Utility term for programs which strive to impact the time when energy is used (Load management, load control, time‐of‐ use, etc.) Attachment 1, October 11, 2011 26 R. W. Beck, An SAIC Company | 5511 Recognition for Fort Collins ƒ Outreach ƒ 2009 Savvy award for “Fort Collins Conserves” campaign ƒ Water ƒ Water Conservation Specialist Laurie D’Audney was awarded the Alice Darilek Water Conservation Award from the Rocky Mountain Section of the American Water Works Association (2010) ƒ Western Resource Advocate’s report, Filling the Gap: Commonsense Solutions for Meeting Front Range Water Needs, Halligan Reservoir Enlargement labeled an Acceptable Planned Water Supply Projects with associated efficiency measures (2011) R. W. Beck, An SAIC Company | 5522 Recognition for Fort Collins ƒ Energy kudos from the Southwest Energy Efficiency Project (SWEEP) ƒ “This is one of the highest savings percentages achieved by any electric utility in the southwest region, demonstrating that even a small utility can implement very effective energy efficiency programs.” (reporting on 2010 results) ƒ “While this utility is small in scale, its DSM programs are large in stature, outperforming most municipal and many investor owned utility DSM programs across the country.” Municipal Efficiency, Leading Lights (2011) Attachment 1, October 11, 2011 27 R. W. Beck, An SAIC Company | 5533 Energy Related Goals ƒ Climate Action Plan Goals (2008) ƒ Reduce emissions to 20% below 2005 levels by 2020 ƒ Reduce emissions to 80% below 2005 levels by 2050 ƒ Energy Policy (2009) ƒ Support the Climate Action Plan goals ƒ Annual efficiency program savings of 1.5% of the community’s electricity use R. W. Beck, An SAIC Company | 5544 Water Related Goals ƒ Water Supply and Demand Management Policy (2003) ƒ Annual Water Consumption Goal: 185 gallons per person per day (gpcd) by 2010 ƒ Peak Day Use Goal: 475 gpcd by 2010 ƒ Water Conservation Plan (2010) ƒ Annual Water Consumption Goal: 140 gpcd by 2020 Attachment 1, October 11, 2011 28 R. W. Beck, An SAIC Company | 5555 Rationale for Efficiency and Conservation ƒ Lowest cost resource ƒ Efficiency and conservation are the lowest cost resource for energy and water. ƒ Energy programs can deliver electricity at a cost less than purchasing wholesale electricity. ƒ Water conservation programs are cheaper than developing/purchasing new water supply. Also saves on capital and operating costs. R. W. Beck, An SAIC Company | 5566 Sustainability Benefits ƒ Economic ƒ Lower customer’s utility bills ƒ Reduced costs for Utilities ƒ Environmental ƒ Reduce carbon and pollutant emissions ƒ Decrease energy and chemical use ƒ Social ƒ Increase comfort, health, safety and productivity Attachment 1, October 11, 2011 29 R. W. Beck, An SAIC Company | 5577 Community Values ƒ Community values support efficiency and conservation ƒ Customer expectations (survey data) ƒ 21st Century Utilities ƒ Plan Fort Collins ƒ Fort Collins Conserves ƒ Deliver level of service our customers expect with environmental, social and economically responsible outcomes for the long term R. W. Beck, An SAIC Company | 5588 History of Water Conservation ƒ Program began with a drought in 1977 ƒ 1992: Water Demand Management Policy ƒ 2003: Water Supply & Demand Management Policy (currently being updated) ƒ 2010: Water Conservation Plan Attachment 1, October 11, 2011 30 R. W. Beck, An SAIC Company | 5599 History of Energy Programs ƒ Have provided energy programs and services for over 25 years ƒ Early programs: residential program series, ZILCH loans, home energy ratings ƒ 1998: first commercial financial incentive, integrated design assistance ƒ 2002: appliance rebates ƒ 2003 Energy Policy: first dedicated funding R. W. Beck, An SAIC Company | 6600 Efficiency Program Strategies and Principles ƒ Strategies ƒ Reduce barriers ƒ Achieve verifiable energy and water savings ƒ Provide programs for various customer groups ƒ Principles ƒ Leverage other programs ƒ Best practices for verification ƒ Adapt to changing regulations ƒ Collaboration Attachment 1, October 11, 2011 31 R. W. Beck, An SAIC Company | 6611 Efficiency and Conservation Program Elements ƒ Program Elements ƒ Awareness and education ƒ Financial incentives ƒ Technical assistance ƒ Industry partners – building contractors, suppliers, retailers, etc. ƒ Rates/Pricing R. W. Beck, An SAIC Company | 6622 Residential Programs ƒ Existing Homes ƒ Home Efficiency Program (audits, rebates, contractors) ƒ Consumer products (energy and water) ƒ Home Energy Reports ƒ Environmental Program Series ƒ Sprinkler system audits ƒ New Homes ƒ NoCO ENERGY STAR Homes ƒ Green Building Code amendments ƒ Consumer products (energy and water) Attachment 1, October 11, 2011 32 R. W. Beck, An SAIC Company | 6633 Business Programs ƒ Existing Buildings ƒ Efficiency assessments ƒ Electric efficiency program incentives (equipment and custom) ƒ LightenUP program incentives (business lighting) ƒ Consumer products (energy and water) ƒ Energy Challenge ƒ Climate Wise ƒ New Buildings ƒ Integrated Design Assistance Program ƒ Green Building Code amendments ƒ Consumer products (water) R. W. Beck, An SAIC Company | 6644 Efficiency and Conservation Programs by Strategy ƒ Consumer products ƒ Retrofit and capital upgrade incentives ƒ Operations, conservation, education, technical assistance ƒ Regulations Attachment 1, October 11, 2011 33 R. W. Beck, An SAIC Company | 6655 Efficiency and Conservation Programs: Consumer Products ƒ ENERGY STAR® clothes washer and dishwasher rebates ƒ Refrigerator and freezer recycling ƒ Compact fluorescent light bulbs ƒ LED lighting (bulbs and holiday lighting) ƒ WaterSense labeled toilet and urinal rebates ƒ Sprinkler equipment rebates R. W. Beck, An SAIC Company | 6666 Efficiency and Conservation Programs: Retrofit and Capital Upgrade Incentives ƒ Insulation and air sealing ƒ Business lighting ƒ Major equipment for business ƒ Custom energy and water incentives ƒ Office equipment/information technology ƒ Foodservice equipment (energy and water) ƒ Restroom fixtures ƒ Irrigation equipment ƒ Refrigeration equipment ƒ Windows Attachment 1, October 11, 2011 34 R. W. Beck, An SAIC Company | 6677 Efficiency and Conservation Programs: Operations, Conservation, Education, Technical Assistance ƒ Business building tune‐up (retro‐commissioning) ƒ Business Efficiency Challenge ƒ Home Energy Reports ƒ Xeriscape Design Clinics ƒ Xeriscape Demonstration Garden ƒ Sprinkler system audits ƒ Environmental program series ƒ Business Innovation Fair ƒ Climate Wise ƒ Efficiency Assessments R. W. Beck, An SAIC Company | 6688 Efficiency and Conservation Programs: Climate Wise ƒ Climate Wise ƒ Technical assessments ƒ Public recognition ƒ Networking opportunities ƒ Reporting and tracking ƒ Energy ƒ Water ƒ Recycling/Waste ƒ Transportation Attachment 1, October 11, 2011 35 R. W. Beck, An SAIC Company | 6699 Efficiency and Conservation Programs: Regulations ƒ Wasting water enforcement ƒ Landscape and Irrigation Standards for Water Conservation ƒ Building Code Green Amendments R. W. Beck, An SAIC Company | 7700 Program Results and Metrics ‐ Water Water Conservation Plan Goal Attachment 1, October 11, 2011 36 R. W. Beck, An SAIC Company | 7711 Program Results and Metrics ‐ Water R. W. Beck, An SAIC Company | 7722 Program Results and Metrics ‐ Energy Description 2005 (baseline) 2010 Percent Change Carbon emissions 1,198,083 1,062,850 -11.3% Community Carbon Emissions from Electricity Sector Year Business customer projects Residential rebates Retailer transactions 2002 1 580 0 2003 6 1,002 0 2004 17 5,366 0 2005 31 2,040 35,249 2006 42 1,667 33,481 2007 72 1,507 44,137 2008 86 1,931 22,684 2009 145 2,266 25,082 2010 289 2,712 15,857 Total 689 19,071 176,489 Customers Served through Efficiency Programs (2002 – 2010) Attachment 1, October 11, 2011 37 R. W. Beck, An SAIC Company | 7733 Program Results and Metrics ‐ Energy 0 5,000 10,000 15,000 20,000 25,000 megawatt-hours per year 2002 2003 2004 2005 2006 2007 2008 2009 2010 Fort Collins Efficiency Program Savings Annual EE Savings (MWh/yr) Fort Collins Efficiency Programs – Annual Electricity Savings (2002 – 2010) R. W. Beck, An SAIC Company | 7744 Program Results and Metrics ‐ Energy 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 megawatt-hours per year 2002 2003 2004 2005 2006 2007 2008 2009 2010 Fort Collins Efficiency Program Savings Annual EE Savings (MWh/yr) Cumulative annual EE Savings (MWh/yr) 84,000,000 kilowatt-hours Fort Collins Efficiency Programs – Cumulative Annual Electricity Savings (2002 – 2010) Attachment 1, October 11, 2011 38 R. W. Beck, An SAIC Company | 7755 Program Results and Metrics ‐ Energy Fort Collins Efficiency Investment and Customer Savings -$3,000,000 -$2,000,000 -$1,000,000 $0 $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 2002 2003 2004 2005 2006 2007 2008 2009 2010 Annual Investment and Savings FC expenditures PRPA expenditures Cumulative Annual Utility cost savings Fort Collins Efficiency Programs – Investment and Customer Savings (2002 – 2010) R. W. Beck, An SAIC Company | 7766 Thank you! October 11, 2011 FORT COLLINS CITY COUNCIL WORK SESSION Attachment 1, October 11, 2011 39 R. W. Beck, An SAIC Company | 7777 Questions for City Council 1. Has sufficient information been provided to support City Council’s decision to adopt a residential energy rate ordinance with one of the four options? 2. Which of the four options proposed for consideration does City Council prefer for implementation? Utilities City of electric stormwater• wastewater water F : LL 700 Wood Street O rt 0 P0 Box 580 Fort Collins, CO 80522 TDD utilities @fcgov.com fcgov.com/utilities MEMORANDUM Date: May 13,2011 To: Mayor Weitkunat and City Councilmembers Thru: Darin Atteherry, City Manager Brian Janonis, Utilities Executive l)irector From: Patty Bigner, Utilities Customer and Employee Relations Manager P /‘/- Re: Work Session Summary— May 10, 2011 re: Rate Design Philosophy All City Councilmembers were present except Aislinn Kottwitz. Utilities Executive Director Brian Janonis provided introductions and background on the need for financial strategy and the development of the Financial Strategy and Rate Design Philosophy. Staff answering questions included Steve Catanach and Patty Bigner. SAIC Consultant Joe Mancinelli provided a brief presentation on industry trends, emerging technology and its impact on rate design. In addition, SAIC consultant Scott Burnham previously taped a niore comprehensive presentation on the details of the philosophy. City Council generally supported the approach proposed by staff and offered some suggested edits to the document. Council wanted to see how the principles and objectives would he applied to rate forms before considering adoption of the Rate Design Philosophy. Other requests for follow-Lip include: 1. Maps that show boundaries for the four City utilities (this item needs to he compiled - follow— up in separate memo) 2. Comparison of Fort Collins rates to the rest of the state and country to provide context (this item needs to he compiled - follow-up in separate memo) 3. Application of the rate design philosophy to current rate structures (same as number I & 2 — follow—up in separate memo) 4. Describe stall’s vision of what the electric utility of the future might look like (this item will he covered at the Advanced Meter Infrastructure City Council Work Session on June14, 20 I I ATTACHMENT 2 Utilities City of electric. stormwater. wastewater water 700 Wood Street Fort CoLLins 970 224 6003 TDD utilities @fcgov.com fcgov.com/utilities Memorandum Date: September 15, 2011 To: City Councilmembers Thru: Darin Atteberry, City Manager Brian Janonis, Utilities Executive Director From: Patty Bigner, Utilities Customer and Employee Relations Manager Re Work Session Summary (Partial) — September 13, 2011 Electric Rate Options All City Councilmembers were present. Utilities Executive Director Brian Janonis provided introductions and noted that the consideration of a change to the electric rate form is unprecedented in the history of the Light and Power Utility. Presentations were provided by Patty Bigner and SAIC consLiltant Joe Mancinelli. Staff answering questions included Bill Switzer, Steve Catanachm and Patty Bigner. SAIC consultant Joe Mancinelli provided a brief presentation on industry trends and response to those trends by utilities across the country, with specific information on electric rates, customer assistance, time of use rates, and special programs for electric vehicles. The residential energy rate options proposed for Council discussion included: • Single Tier (current rate structure) • Seasonal (Platte River Power Authority IPRPA] pass-through) • Three Tier • Five Tier Staff also proposed phasing out the Residential Demand Rate and suggested limiting the rate to residential customers who could provide documentation of total electric residence (no natural gas). One change to the rate form is proposed for the commercial rate classes. As noted in the Agenda Item Summary, the proposed change to the General Service (GS) or commercial rate class would more accurately reflect electric use of this diverse group of customers. This change would create a fourth commercial rate class to include the lower end of the mid-sized commercial customers by splitting the GS customer class into two customer classes, GS and GS 25. ATTACHMENT 3 Fort City of CoLLins Examples of customers in the proposed GS customer class include housing services for condos and apartments (lights, laundry, etc.); small retail; professional offices; non-profit agencies: and small churches. The proposed GS 25 customer class includes fast loud restaurants, medium- sized churches, restaurants, larger retail, fraternity and sorority houses, convenience stores, copy centers and banks. The remaining large commercial industrial rates will remain in the coincident peak form hut with a seasonal adjustment. Questions for City Council included: Residential Rate Options I. Of the four proposed rate options for the residential energy rate, which specific option is preferred’? 2. Does City Council support the proposed change to the residential demand rate’? Commercial Rate Options 1. Does City Council support the proposed change that would create an additional rate class from the existing General Service rate class? Questions from Councilmembers primarily focused on aspects of the residential energy rate, its merits in addressing carbon reduction and energy efficiency goals, and its impacts on customers as well as the perceived value or lack of value to the system (generation, transmission and distribution). Other questions focused on the impacts to customers related to size of households and square footage of homes, number and type of appliances, and electricity use associated with lifestyle (home office or other differences). City Council requested additional information: 1. Assumptions related to elasticity (in plain English) — what kind of impact can he expected’? What is the corresponding carbon reduction’? 2. Are the options designed to he revenue neutral? If demand and energy are reduced, the purchase power requirements will also be reduced lowering overall revenue requirements. 3. Provide more context on system impacts. How might the tiered rates affect shifts in demand which may have a negative impact on the overall load’? 4. Provide more data on the monthly variation in bill impacts, including the typical variation in monthly use. 5. Provide sample (8 to 10) scenarios of year-round use and the price impacts of the options. Examples: Large users with no air conditioning (AC), large users with AC, small users with AC, small users without AC, etc. Changes to the Residential Demand Rate and the Commercial General Service Rate were discussed and generally seemed acceptable. Councilmembers had a number of unresolved questions regarding the Residential Energy Rate and requested a follow-up Work Session, now scheduled for Oct. II, 2011. Councilmembers recognized that the schedule for implementation 2 City of Fort Collins of the rate, if it is changed, will be delayed beyond January 1,2012. Typically, rate changes occur with the first meter reading of the new year. Staff plans to move forward with rate changes with the exception of the Residential Energy Rate. Rate ordinances for the Residential Demand, GS, GS 25, GS 50 and GS 750 rate classes will be discussed Fort Collins City Council Work Session, Oct 11, 2011 Attachment 4 Price Elasticity Graphs Price elasticity varies widely ƒ Electric Power Research Institute (EPRI) reviewed results of numerous pricing pilots; results ranging from ‐0.08 to ‐0.39 ƒ Common finding was that higher‐use customers exhibit larger price elasticity ƒ Brattle Group found that long‐run price elasticity are substantially higher than short‐run price elasticity ƒ Public Utilities Fortnightly (August 2008) article ƒ Incline block rates can provide energy consumption savings ƒ Price elasticity ranges: Distribution of Residential Price Elasticity Low Most Likely High Block 1 ‐0.01 ‐0.13 ‐0.20 Short Run Block 2 ‐0.02 ‐0.26 ‐0.39 Block 1 ‐0.03 ‐0.39 ‐0.60 Long Run Block 2 ‐0.06 ‐0.78 ‐1.17 Fort Collins City Council Work Session, Oct 11, 2011 Attachment 5 Estimated Reduction in Carbon Emissions Estimated Annual GHG Savings (Metric Tons) No Elasticity Mid Elasticity High Elasticity Seasonal 0 3,046 4,518 Three‐Tier 0 3,463 5,031 Five‐Tier 0 3,667 5,185 Fort Collins City Council Work Session, Oct 11, 2011 Attachment 6 1 System Benefits Estimated Percent Change in Annual Energy No Elasticity Mid Elasticity High Elasticity Seasonal 0.0% ‐1.0% ‐1.5% Three‐Tier 0.0% ‐1.1% ‐1.6% Five‐Tier 0.0% ‐1.2% ‐1.7% Estimated Percent Change in Summer Peak Demand No Elasticity Mid Elasticity High Elasticity Seasonal 0.0% ‐1.8% ‐2.7% Three‐Tier 0.0% ‐1.8% ‐2.6% Five‐Tier 0.0% ‐1.8% ‐2.6% Fort Collins City Council Work Session, Oct 11, 2011 Attachment 6 2 Estimated Avoided Capital Cost of New Peaking Capacity ($1,000) No Elasticity Mid Elasticity High Elasticity Seasonal $0 $1,336 $1,982 Three‐Tier $0 $1,336 $1,928 Five‐Tier $0 $1,344 $1,880 Fort Collins City Council Work Session, Oct 11, 2011 Attachment 7 Relationship Between System Cost and Retail Price To assist in understanding this concept from a different perspective, it may be helpful to understand how cost of service is determined. There is a fundamental relationship between what residential electricity customers use on a monthly basis, what they pay for service and their costs to the system. The cost of service analysis unbundles total electric utility costs into three functions (customer service, electric distribution, and purchased power). The cost structure of each function is different. Costs associated with the customer service function are fixed and do not vary with energy usage. These costs are incurred by the utility largely due to the number of customers on the system. Therefore, the majority of customer service costs are allocated to customer classes based on the number of customers. Costs associated with the distribution function are also fixed. These costs are incurred by the utility to deliver power to the customers regardless of their location. Additionally, infrastructure is sized to meet localized system demands in order to maintain high system reliability. Therefore, if customer use less energy or reduce demand consumption, customer service and distribution costs will not change. The purchased power function is variable. Fort Collins Utilities only pays its wholesale power supplier (Platte River Power) for demand and energy used. Therefore, if customers use less energy or reduce demand consumption, wholesale power costs will be lower. To the extent possible, rate design tries to parallel cost of service results. The cost of service analysis indicates that there are three distinct service offerings by Fort Collins Utilities with the following cost causation characteristics: Function Cost Characteristic Customer Service Fixed Distribution Fixed Purchased Power Variable To equitably recover these costs, a rate structure could have a customer charge ($ per customer per month), a demand charge ($ per kilo-watt (kW)) and an energy charge ($ per kilo-watt hour (kWH)). In fact, these rate structures are often seen for commercial customers. However, residential customers do not typically have demand charges. This is a direct result of metering technology and the fact that residential customer demands are relatively homogenous compared to commercial customer classes. The existing residential rate structure at Fort Collins Utilities includes a customer charge ($3.91 per customer per month) and energy charges (a distribution charge of $0.0220/kWh, a demand charge of $0.0284/kWh, and an energy charge of $0.0248/kWh). The customer charge is designed to recover the cost associated with meters, and customer services (billing systems, etc). These cost are fixed and do not vary with energy usage. The distribution charge is designed to recover utility costs for substations, feeder lines, distribution systems, and energy services. While the distribution charge does not vary with electricity, Fort Collins Utilities has elected to recover these charges on an energy basis rather than a on a per customer basis. Fort Collins Utilities does not have demand meters on these standard residential accounts and therefore cannot implement a demand charge. The demand and energy costs associated with purchased power are recovered through an energy charge in the current rate structure.Because the existing rate includes a fixed (customer charge) and variable (energy charge), the more electricity used on a monthly basis the lower the effective unit rate applicable to that customer. This does not suggest that larger users are paying less in total for utility service. It is merely recognizes that as more units of electricity are used, the fixed cost components of the rate is recovered over more kWh, thus the average costs per unit decreases. See example below: Monthly Use (kWh) / Charge ($) 10 kWh 100 kWh 1,000 kWh Fort Collins City Council Work Session, Oct 11, 2011 Attachment 7 Customer Charge $3.91 $3.91 $3.91 Distribution Charge ($0.0220 / kWh) $0.22 $2.22 $22.20 Demand Charge ($0.0284 / kWh) $0.284 $2.84 $28.4 Energy Charge ($0.0248 / kWh) $0.248 $2.48 $24.8 Total Bill $4.66 $11.45 $79.31 $/kWh $0.47 $0.11 $0.08 In a typical distribution system, small users of electricity place less demand on the system than larger users. However, the rate, as illustrated above, does a good job of recognizing this cost difference as the larger users are paying significantly more towards the utilities demand related costs compared to the smaller users. However, if you look at the unit cost, smaller users pay a higher $/kWh due to the nature of the fixed and variable price structure. This is the same in any industry that has a fixed and variable component. A cell phone bill typically has a fixed portion (for monthly service) and a variable portion (for the number of phone calls made or data received). The larger the variable portion becomes, the lower the unit costs ($/minutes used or $/data received). A refinement in rate design that would add to the equitability of fixed cost recovery associated with the residential rate structure would be the addition of a demand charge, but these options are not available to Fort Collins Utilities at this time. In general, the utility recovers the costs to serve its customers based on its rate structures that vary by customer class. The costs to serve customer classes (residential, commercial, industrial) are different; industrial customers require additional equipment, larger sized power lines, and, of course, additional electricity than residential users. Within the residential customer class, however, the fixed costs to serve a low user and a high user are the same. The variable costs to serve these customers are different; larger users require more energy than lower users. Further, Fort Collins Utilities elects to charge users for the fixed costs of its distribution system on a variable basis, therefore, larger users are contributing more to the costs of the distribution system than smaller users (because they use more electricity and the distribution charge is based on $/kWh). The utility collects the costs to serve each customer class with the rates for that class; therefore, some customers contribute less to the total costs (low users) whereas some contribute more to the total costs (high users). In total, rates are designed such that all of the customers within the class provide the utility with the total costs for the service they receive. Therefore, rates are designed to be revenue neutral for the class such that Fort Collins Utilities neither over- collects or under collects for its costs to serve its customers. Fort Collins City Council Work Session, Oct 11, 2011 Attachment 8 1 Bill Impacts on Selected Customers Selected House Square Feet # of Occupants A/C Annual Average (kWh) Highest Winter Usage (kWh) Highest Summer Usage (kWh) A 4,242 2 Yes 633 851 726 B 3,306 4 Yes 1,692 3,026 1,762 C 3,000 3 Yes 928 1,075 1,485 D 2,980 7 No 641 915 594 E 2,850 2 Yes 567 876 650 F 2,700 4 Yes 654 566 1,112 G 2,621 2 Yes 482 615 644 H 2,600 2 Yes 803 1,057 1,137 I 2,500 4 Yes 362 508 406 J 2,275 2 No 507 524 625 K 2,000 2 No 606 1,391 474 Fort Collins City Council Work Session, Oct 11, 2011 Attachment 8 2 Fort Collins City Council Work Session, Oct 11, 2011 Attachment 8 3 Selected House Average Monthly Bill % Difference Single Tier % Difference Seasonal % Difference Three‐Tier % Difference Five‐Tier A $51.17 6.03% 5.88% 1.92% 0.92% B $126.41 5.61% 5.29% 11.98% 11.33% C $85.00 5.74% 5.51% 6.79% 5.29% D $50.67 6.08% 5.09% 1.05% 0.29% E $45.58 6.11% 6.13% 1.51% 0.59% F $51.67 6.02% 7.83% 4.86% 3.18% G $44.25 6.14% 5.63% 0.97% 0.20% H $70.58 5.83% 5.72% 4.46% 2.97% I $30.83 6.49% 6.22% 0.79% 0.14% J $42.25 6.18% 6.22% 1.01% 0.19% K $47.83 6.08% 4.78% 1.28% 0.52% Fort Collins City Council Work Session, Oct 11, 2011 Attachment 9 Energy Usage of Low Income Customers Low Income single family comparison (2010 data) 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% - 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 kWh block % of bills in block Sample of 179 single family low income Single family population Low Income multi-family comparison (2010 data) 0% 2% 4% 6% 8% 10% 12% 14% - 100 200 300 Fort Collins City Council Work Session, Oct 11, 2011 Attachment 10 Community Water Use, Historic Averages and Goals Description 2005 (baseline) 2010 Percent Change Carbon emissions 1,198,083 1,062,850 -11.3% Community Carbon Emissions from Electricity Sector Water Conservation Plan Goal Fort Collins City Council Work Session, Oct 11, 2011 Attachment 10 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 2002 2003 2004 2005 2006 2007 2008 2009 2010 Per Capita Annual kilowatt‐hours Fort Collins Electric Use Per Capita Community Electric Use Per Capita (2002 – 2010) Year Business customer projects Residential rebates Retailer transactions 2002 1 580 0 2003 6 1,002 0 2004 17 5,366 0 2005 31 2,040 35,249 2006 42 1,667 33,481 2007 72 1,507 44,137 2008 86 1,931 22,684 2009 145 2,266 25,082 2010 289 2,712 15,857 Total 689 19,071 176,489 Customers Served through Efficiency Programs (2002 – 2010) Fort Collins City Council Work Session, Oct 11, 2011 Attachment 10 0 5,000 10,000 15,000 20,000 25,000 megawatt-hours per year 2002 2003 2004 2005 2006 2007 2008 2009 2010 Fort Collins Efficiency Program Savings Annual EE Savings (MWh/yr) Fort Collins Efficiency Programs – Annual Electricity Savings (2002 – 2010) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 megawatt-hours per year 2002 2003 2004 2005 2006 2007 2008 2009 2010 Fort Collins Efficiency Program Savings Annual EE Savings (MWh/yr) Cumulative annual EE Savings (MWh/yr) 84,000,000 kilowatt-hours Fort Collins Efficiency Programs – Cumulative Annual Electricity Savings (2002 – 2010) Fort Collins City Council Work Session, Oct 11, 2011 Attachment 10 Fort Collins Efficiency Investment and Customer Savings -$3,000,000 -$2,000,000 -$1,000,000 $0 $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 2002 2003 2004 2005 2006 2007 2008 2009 2010 Annual Investment and Savings FC expenditures PRPA expenditures Cumulative Annual Utility cost savings Fort Collins Efficiency Programs – Investment and Customer Savings (2002 – 2010) DATE: October 11, 2011 STAFF: Darin Atteberry Mike Beckstead Pre-taped staff presentation: none WORK SESSION ITEM FORT COLLINS CITY COUNCIL SUBJECT FOR DISCUSSION Presentation of the City Manager's Recommended 2012 Budget Revision Requests. EXECUTIVE SUMMARY The purpose of this work session is to review the 2012 Budget Revision Requests to be considered for inclusion in the 2012 Annual Appropriation Ordinance. The Ordinance will be considered on First Reading on October 18, 2011. 2012 BUDGET REVISION SUMMARY General Fund Utility Funds All Other Funds TOTAL (in $M) Funding Sources Sales & Use Tax: Projection compared to budget $ 2.2 $ 0.9 $ 3.1 Interest earnings (0.5) (1.4) (1.9) $ (3.8) Revenue from rate increase 4.1 $ 4.1 Unanticipated available appropriations 0.6 0.2 0.7 $ 1.5 Other Revenue Changes 0.9 2.9 $ 3.8 Total of Revenue Changes 3.2 5.8 $ (0.3) $ 8.7 2012 Budget Revision Requests Utility Stormwater Land Purchases and Purchased Power (4.3) (4.3) Below Market Pay Adjustment (0.1) (0.3) (0.4) (0.8) Water Meter Replacement and Rehabilitation (0.6) (0.6) Microsoft Office 2010 Software Upgrade (0.5) (0.5) Restore Conservation Trust Funds for Trail Construction (0.5) (0.5) All Other 2012 Requests (1.0) (0.6) (0.6) (2.2) Total of Supplemental Appropriations (1.6) (5.8) $ (1.5) (8.9) 2012 Budget Revision Impact to Fund Balance $ 1.6 $ (0.0) $ (1.8) $ (0.2) BACKGROUND / DISCUSSION Since the City changed to a biennial budget in 1998, there has been an opportunity to modify the second year of that budget through a revision process. This process allows for course correction based on changes to anticipated revenue (both higher and lower than originally forecasted), as well as unexpected business requirements that should be addressed prior to the next biennial budget. The funding sources to cover the expenses related to these supplemental appropriations come from increased sales and use tax revenue, unappropriated 2012 forecasted revenue and unanticipated available appropriations. October 11, 2011 Page 2 Following are key objectives which the recommendations are intended to: • Address stated Council priorities • Continue implementation of sustainability goals and objectives • Leverage Mason Corridor synergies • Cover increased costs for power • Implement Stormwater improvements • Provide basic technology support and upgrades for internal organization needs • Correct below-market pay gaps for City employees • Maintain fund balances and start rebuilding reserves in the General Fund to support future needs and economic uncertainty The recommended 2012 budget supplemental appropriations meet these goals. These requests have been evaluated by the Budget Lead Team and reviewed by the Council Finance Committee. The revision process is not part of the City’s official biennial Budgeting for Outcomes process, so there was no review by BFO Results Teams or Boards and Commissions. FINANCIAL / ECONOMIC IMPACTS Citywide, incremental funding sources total $8.7 million. The General Fund portion of that is $3.2 million driven primarily by Sales and Use Tax collections. The rest is comprised of a $5.8 million increase in the Utility funds and a net decrease of $300,000 in other funds. The supplemental appropriations being recommended total $8.9 million. The General Fund share is $1.6 million, $5.8 million is from Utility funds, and the remaining $1.5 million is from other funds such as the Data and Communications Fund. A complete packet of requests is attached. ATTACHMENTS 1. Cover memo dated October 6, 2011 2. 2012 Budget Revision Requests City Manager’s Office City Hall 300 LaPorte Ave. PO Box 580 Fort Collins, CO 80522 970.221.6505 970.224.6107 - fax fcgov.com MEMORANDUM DATE: October 6, 2011 TO: Mayor and Councilmembers FROM: Darin A. Atteberry, City Manager SUBJECT: 2012 Budget Revision Recommendations The purpose of this agenda item is to familiarize and seek feedback from the Council Finance Committee with my recommended revisions to the 2012 Budget before the Appropriations Ordinance goes to first reading October 18 and second reading November 1. General Fund Utility Funds All Other Funds TOTAL (in $M) Funding Sources Sales & Use Tax: Projection compared to budget $ 2.2 $ 0.9 $ 3.1 Interest earnings (0.5) (1.4) (1.9) $ (3.8) Revenue from rate increase 4.1 $ 4.1 Unanticipated available appropriations 0.6 0.2 0.7 $ 1.5 Other Revenue Changes 0.9 2.9 $ 3.8 Total of Revenue Changes 3.2 5.8 $ (0.3) $ 8.7 2012 Budget Revision Requests Utility Stormwater Land Purchases and Purchased Power (4.3) (4.3) Below Market Pay Adjustment (0.1) (0.3) (0.4) (0.8) Water Meter Replacement and Rehabilitation (0.6) (0.6) Microsoft Office 2010 Software Upgrade (0.5) (0.5) Restore Conservation Trust Funds for Trail Construction (0.5) (0.5) All Other 2012 Requests (1.0) (0.6) (0.6) (2.2) Total of Supplemental Appropriations (1.6) (5.8) $ (1.5) (8.9) 2012 Budget Revision Impact to Fund Balance $ 1.6 $ (0.0) $ (1.8) $ (0.2) 2012 BUDGET REVISION SUMMARY * * The use of reserves in all other funds includes over $800k of prior year appropriations in the Data and Communications Fund that were not spent. The other reserves are primarily to cover interest income shortfalls City-wide, supplemental appropriations being recommended total $8.9 million. The General Fund share is $1.6 million, $5.8 million is from Utility funds, and the remaining $1.5 million is from other funds such as the Data and Communications Fund. A complete packet of requests is attached. Following are key objectives which the recommendations are intended to: • Address stated Council priorities • Continue implementation of sustainability goals and objectives • Leverage Mason Corridor synergies • Cover increased costs for power • Implement Stormwater improvements ATTACHMENT 1 • Provide basic technology support and upgrades for internal organization needs • Correct below-market pay gaps for City employees • Maintain fund balances and start rebuilding reserves in the General Fund to support future needs and economic uncertainty The recommended 2012 budget supplemental appropriations meet these goals. Sales tax collections are higher than originally anticipated; we also have unappropriated 2012 forecasted revenue and anticipated budget savings. For the 2012 Budget Revision Requests, staff recommends using approximately $1.8 million of reserves ($810k from Data & Communications Fund reserves, $580k from Water Fund reserves, $300k from Light & Power reserves, and $119k from General Fund Traffic Surcharge reserve as indicated on page 4a). There will also be a need for most City funds to use a modest amount of reserves to cover the projected shortfall in interest earnings. We recommend adding $1.5 million of the additional 2012 revenue into the General Fund reserve balance. The updated revenue and expenses, as well as the individual offers, are summarized on pages 1 through 5. Descriptions of the recommended requests follow the summary pages. The revision process is not part of our official biennial Budgeting for Outcomes process, so there was no review by BFO Results Teams or Boards and Commissions. However, the Executive Leadership Team and I conducted a comprehensive review to determine which requests should be forwarded on for Council's consideration. Revised revenue projections and anticipated fund reserves were carefully considered when making these recommendations. I look forward to our future conversations. Please call me if you’d like to discuss this prior to our meeting. 2012 BUDGET REVISION REQUESTS ATTACHMENT 2 2012 BUDGET REVISION REQUESTS TABLE OF CONTENTS SUMMARY OVERVIEWS Request Summary by BFO Result Area............................................................................... 1 Request Summary by Fund.................................................................................................. 2 Revenue / Expense Revision Summary - All Funds…………………………………………....4a Revenue / Expense Revision Summary - General Fund & Keep Fort Collins Great …....…5 GENERAL FUND REVISION REQUESTS Assistant to the City Manager and CPIO ............................................................................ 7 Police Services Ticket Surcharge Officer............................................................................ 8 Affordable Housing/Human Services.................................................................................. 9 Restore Conservation Trust Funds for Trail Construction ................................................ 21 Development Review Succession Planning...................................................................... 22 Development Review – Customer Service Demand......................................................... 25 PFA Non-Discretionary & Total Compensation Increase.................................................. 31 CMO Policy and Project Manager Increase from 0.8 to 1.0 FTE………………………… . 32 Federal Legislation Analysis and Action…………………………………………………….. .33 Mason Corridor Synergies and Support Services............................................................. 34 Reorganization Office of Sustainability ............................................................................. 35 Below Market Pay Adjustment .......................................................................................... 36 OTHER FUND REVISION REQUESTS (unless already listed above) Keep Fort Collins Great Fund Downtown Ice Rink Installation and Removal......................................................... 41 Downtown Holiday Lighting..................................................................................... 42 Light & Power Fund Light & Power Payments in Lieu of Taxes (PILOT) Increase................................. 43 Purchase Power Increase....................................................................................... 47 Energy Efficiency Financing Program .................................................................... 48 Water Fund Water Payments in Lieu of Taxes (PILOT) Increase.............................................. 49 Water Meter Replacement and Rehabilitation........................................................ 54 Stormwater Fund Household Hazardous Waste Community Event ................................................... 55 Remove Structures from Poudre River Floodway.................................................. 56 Master Plan Flood Mitigation Project Property....................................................... 57 Data & Communications Fund MIS Email, Blackberry & Smart Phone Services.................................................... 58 MIS Network Services Resource Support .............................................................. 59 MIS Technology Customer Software Compliance Support .................................... 60 MIS Technology Customer Support Restructure.................................................... 61 Microsoft Office 2010 Software Upgrade................................................................ 62 2012 Budget Adjustment Requests - BY BFO RESULT AREA Results Related Area Offer # Adjustment Requested Ongoing $ One-Time $ Cultural, Parks & Recreation 21 106.2, 6 Restore Conservation Trust Funds for Trail Construction $546,571 $0 $546,571 $0 Economic Health 41 105.2 Downtown Ice Rink Installation and Removal $40,000 $0 22 108.11 Development Review Succession Planning (1.25 Cont. FTE) $75,341 $0 25 108.11 Development Review - Customer Service Demand (1 FTE) $65,000 $0 42 New Downtown Holiday Lighting $85,000 $0 34 New Mason Corridor Synergies and Support Services $0 $200,000 $265,341 $200,000 Environmental Health 49 100.1 Water Payments in Lieu of Taxes (PILOT) Increase $88,054 $0 55 214.2 Household Hazardous Waste Community Event $22,000 $0 48 New Energy Efficiency Financing Program (.5 FTE) $300,000 0 54 New Water Meter Replacement and Rehabilitation $0 $580,000 35 New Reorganization: Office of Sustainability $122,200 $0 $532,254 $580,000 High Performing Government 7 3.1, 4.1 Assistant to the City Manager and CPIO (1 FTE) $176,320 $0 58 32.1 MIS Email, Blackberry & Smart Phone Services $28,000 $80,000 59 33.4 MIS Network Services Resource Support $0 $62,400 60 35.6 MIS Technology Customer Software Compliance Support $0 $59,488 61 35.6 MIS Technology Customer Support Restructure $30,709 $0 62 New Microsoft Office 2010 Software Upgrade $0 $550,000 32 3.1 CMO Policy and Project Manager Increase from .8 to 1.0 FTE $29,157 $0 33 New Federal Legislation Analysis and Action $79,414 $0 36 Multiple Below Market Pay - Full Adjustment $812,390 $0 $1,155,990 $751,888 Neighborhood Livability 9 85.1 Affordable Housing/Human Services $54,499 $0 $54,499 $0 Safe Community 43 10.1 Light & Power Payments in Lieu of Taxes (PILOT) Increase $121,969 $0 47 11.1 Purchase Power Increase $1,724,505 $0 8 21.1 Police Services Ticket Surcharge Officer (1 FTE) $118,709 $0 31 132.6 PFA Non-Discretionary & Total Compensation Increase $228,926 $0 56 New Remove Structures from Poudre River Floodway $0 $1,000,000 57 New Master Plan Flood Mitigation Project Property $0 $1,600,000 $2,194,109 $2,600,000 Transportation N/A Sub-total $4,748,764 $4,131,888 ALL FUNDS TOTAL: $8,880,652 Page Revision Requests Number Updated 9/30/2011 1 2012 Budget Adjustment Requests - BY FUND Total Fund Related Ongoing & Fund Offer # Adjustment Requested Ongoing $ One-Time $ One-Time General Fund 7 3.1, 4.1 Assistant to the City Manager and CPIO (1 FTE) $176,320 $0 8 21.1 Police Services Ticket Surcharge Officer (1 FTE) $118,709 $0 9 85.1 Affordable Housing/Human Services $54,499 $0 21 106.2, 6 Restore Conservation Trust Funds for Trail Construction $546,571 $0 22 108.11 Development Review Succession Planning (1.25 Cont. FTE) $75,341 $0 25 108.11 Development Review - Customer Service Demand (1 FTE) $65,000 $0 31 132.60 PFA Non-Discretionary & Total Compensation Increase $59,768 $0 32 3.10 CMO Policy and Project Manager Increase from .8 to 1.0 FTE $29,157 $0 33 New Federal Legislation Analysis and Action $79,414 $0 34 New Mason Corridor Synergies and Support Services $0 $150,000 35 New Reorganization Office of Sustainability $91,650 $0 36 Multiple Below Market Pay Adjustment $139,780 $0 Total General Fund $1,436,209 $150,000 $1,586,209 KFCG Fund 31 132.6 PFA Non-Discretionary & Total Compensation Increase $169,158 $0 34 New Mason Corridor Synergies and Support Services (Parking Study) $0 $50,000 41 105.2 Downtown Ice Rink Installation and Removal $40,000 $0 42 New Downtown Holiday Lighting $85,000 $0 36 Multiple Below Market Pay Adjustment $19 $0 Total Keep Fort Collins Great Fund $294,177 $50,000 $344,177 Natural Areas 35 New Reorganization Office of Sustainability $30,550 $0 36 Multiple Below Market Pay Adjustment $28,543 $0 Total Natural Areas Fund $59,093 $0 $59,093 Light & Power 43 10.1 Light & Power Payments in Lieu of Taxes (PILOT) Increase $121,969 $0 47 11.1 Purchase Power Increase $1,724,505 0 48 New Energy Efficiency Financing Program (.5 FTE) $300,000 0 36 Multiple Below Market Pay Adjustment $193,740 $0 Total Light & Power Fund $2,340,214 $0 $2,340,214 Page Revision Requests Number Updated 9/30/2011 2 2012 Budget Adjustment Requests - BY FUND Total Fund Related Ongoing & Fund Offer # Adjustment Requested Ongoing $ One-Time $ One-Time Page Revision Requests Number Water 49 100.1 Water Payments in Lieu of Taxes (PILOT) Increase $88,054 $0 54 New Water Meter Replacement and Rehabilitation $0 $580,000 36 Multiple Below Market Pay Adjustment $77,857 $0 Total Water Fund $165,911 $580,000 $745,911 Stormwater 55 214.2 Household Hazardous Waste Community Event $22,000 $0 56 New Remove Structures from Poudre River Floodway $0 $1,000,000 57 New Master Plan Flood Mitigation Project Property $0 $1,600,000 36 Multiple Below Market Pay Adjustment $45,608 $0 Total Stormwater Fund $67,608 $2,600,000 $2,667,608 Data & 58 32.1 MIS Email, Blackberry & Smart Phone Services $28,000 $80,000 Communications 59 33.4 MIS Network Services Resource Support $0 $62,400 60 35.6 MIS Technology Customer Software Compliance Support $0 $59,488 61 35.6 MIS Technology Customer Support Restructure $30,709 $0 62 New Microsoft Office 2010 Software Upgrade $0 $550,000 36 Multiple Below Market Pay Adjustment $22,890 $0 Total Data & Communications Fund $81,599 $751,888 $833,487 Other Funds 36 Multiple Below Market Pay Adjustment $303,953 $0 $303,953 Total All Funds $4,748,764 $4,131,888 $8,880,652 Updated 9/30/2011 3 Description General Fund Keep Fort Collins Great Natural Areas Light & Power Water Stormwater Data & Communica- tions Other Various Funds TOTAL Funding Sources Sales & Use Tax: Projection compared to budget $ 2,203,000 $ 716,700 $ 182,500 $ 3,102,200 Interest earnings (504,751) (45,826) (400,000) (836,879) (135,141) (39,937) (1,800,000) (3,762,534) Light and Power PILOTs 121,969 121,969 Water PILOTs 88,054 88,054 Development Review revenue 715,000 715,000 CMAQ Grant - Partner Contributions - Revenue from rate increase 2,474,020 1,624,549 4,098,569 Other Revenue Changes 181,280 181,280 Unused 2012 Revenue in the 2011-12 Budget 2,634,245 2,634,245 Available appropriations due to reduced City medical contribution 586,346 56,578 34,627 124,080 93,374 30,277 45,781 530,641 1,501,704 Total of Revenue Changes 3,209,618 773,278 171,301 2,198,100 1,062,324 2,529,381 5,844 (1,269,359) 8,680,487 2012 Budget Revision Requests Sum of 2012 Budget Revision Requests (1,467,500) (344,177) (59,093) (2,040,214) (165,911) (2,667,608) (22,890) (303,953) (7,071,346) Sum of 2012 Budget Revision Requests - From Reserves (118,709) (300,000) (580,000) (810,597) (1,809,306) Total of Supplemental Appropriations (1,586,209) (344,177) (59,093) (2,340,214) (745,911) (2,667,608) (833,487) (303,953) (8,880,652) 2012 Budget Revision Impact to Fund Balance $ 1,623,409 $ 429,101 $ 112,208 $ (142,114) $ 316,413 $ (138,227) $ (827,643) $ (1,573,312) $ (200,165) Notes: 1) The projected increase in 2012 Development Review revenue is based on 2010 volume with the new rate structure approved by Council on September 6th, 2011 2) The sum of 2012 Budget Revision Request in the Other Various Funds column include the $750K budget correction and is offset by the revenue adjustment above 3) The use of reserves in the Light and Power fund could be covered by $45,136,684 of working capital as of December 31, 2010 4) The use of reserves in the Stormwater fund could be covered by $12,070,244 of working capital as of December 31, 2010 5) The use of reserves in the Data and Communications Fund is covered by fund balance of $3,633,068 as of December 31, 2010 6) The use of reserves in the other various funds crosses 23 funds. Review of each fund has confirmed that there is ample reserve available over policy minimum. Revenue & Expenditures by Fund 2012 Budget Revision Summary 4a Updated 10/5/2011 4 General Fund Net Changes to Budget 2011 2012 Sales & Use Tax: Projection compared to budget 2,527,000 2,203,000 Interest earnings (318,238) (504,751) Light and Power PILOTs - 121,969 Water PILOTs - 88,054 Development Review revenue 275,000 715,000 Total revenue changes 2,483,762 2,623,272 Sum of requests (2011 Clean-up and 2012 Revisions) (581,988) (1,586,209) Available appropriations due to reduced City medical contribution 316,577 586,346 Total increase to fund balance 2,218,351 1,623,409 Keep Fort Collins Great Fund Unanticipated Revenue Summary: Transportation - Street Maintenance 270,963 236,511 Other Transportation 139,587 121,839 Police Services 139,587 121,839 Fire & Emergency Services 90,321 78,837 Park & Recreation 90,321 78,837 Other Community Priorities 90,321 78,837 Total Net Change to Anticipated Revenue 821,100 716,700 Other Transportation - Net Changes to Budget 2011 2012 Fund Balance - 139,587 Designated for Fire & Emergency Services: Projection compared to budget 139,587 121,839 Sum of 2012 Budget Revision Requests - (50,000) Total increase to fund balance 139,587 211,426 Fire & Emergency Services - Net Changes to Budget 2011 2012 Fund Balance - 90,321 Designated for Fire & Emergency Services: Projection compared to budget 90,321 78,837 Sum of 2012 Budget Revision Requests - (169,158) Total increase to fund balance 90,321 - Other Community Priorities - Net Changes to Budget 2011 2012 Fund Balance - 90,321 Designated for Other Community Priorities: Projection compared to budget 90,321 78,837 Sum of 2012 Budget Revision Requests - (125,019) Total increase to fund balance 90,321 44,139 2012 General Fund & KFCG Revenue & Expense Revisions Updated 9/30/2011 5 THIS PAGE LEFT INTENTIONALLY BLANK 6 Revision Title: Fund: Contact: Wendy Bricher Result Area: Package/Offer #: 3.1 and 4.1 Total Amount: $176,320 Funding Source #1: Funding Amount #1: $132,619 Funding Source #2: Funding Amount #2: $43,701 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Assistant to the City Manager & CPIO 1.0 FTE - Assistant to the City Manager The City Manager and Executive Leadership Team (ELT) considered ways to enhance the efficiency and effectiveness of the City organization. Changes impacting existing service areas were approved in March 2011 and included the following: 1) Assistant to the City Manager - This new position is an executive level position intended to support the City Manager in pursuing a world class community particularly focused on including sustainability leadership & coordination, community design & special projects, and innovative culture. 2) Assistant to the City Manager - Employee and Communications Services (Restructured Communications and Public Involvement Director Position) overseeing the Human Resource Department and the Communication & Public Involvement Office. 3) Reclassify the current Public Relations Coordinator to the Communications and Public Involvement Manager 100 - General Fund High Performing Government General Fund General Fund 7 Revision Title: Fund: Contact: Tricia Muraguri Result Area: Related Offer #: 21.1 Total Amount: $118,709 Funding Source #1: Funding Amount #1: $118,709 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Police Services Ticket Surcharge Officer 1.0 FTE - Police Traffic Enforcement Officer At the tail end of the 2011 - 2012 budget process, Police Services received authorization to hire an additional Traffic Surcharge Officer. Since the budget process was about over and the proposed budget documents had been sent to print, the position was never included in the authorized count of FTE's. For 2011 the cleanup ordinance will be the mechanism used to appropriate the revenue. This offer appropriates the funding for 2012 to formalize the FTE addition that took place late in 2010. 100 - GENERAL FUND Safe Community General Fund - Traffic Surcharge Reserve 8 Revision Title: Fund: Contact: Joe Frank Result Area: Relative Offer #: 8.3 85.1 Total Amount: $54,499 Funding Source #1: Funding Amount #1: $54,499 FTE Requested: 0.2 FTE - Human Services Grant Administrater 0.1 FTE - Human Services/Affordable Housing Clerical Description: This request is for additional General Fund dollars to adequately resource the Advance Planning Department’s affordable housing, human services and long range planning programs in order to meet federal regulatory compliance and more effectively and efficiently manage these programs. Advance Planning proposes reorganizing the grants and affordable housing programs to provide more case management administration capabilities and full time program management. The timing for this reorganization is optimal due to pending retirements within the programs. Please refer to the accompanying information that follows. 2012 BUDGET REVISION REQUEST Affordable Housing/Human Services 0.3 FTE - Affordable Housing Program Administrater 100 - GENERAL FUND Economic Health General Fund Neighborhood Livability 9 Budget Revision Request: Affordable Housing and Human Services This request addresses a convergence of issues in the affordable housing and human services arena, all of which have reached critical mass since the last BFO cycle. The City maintains a multi-million dollar, long-term commitment to affordable housing and human services through use of annual federal grants (CDBG and HOME), and City funds (Affordable Housing Fund [AHF], Human Service Program [HSP]). In addition to general administration for the above four funding streams, the Affordable Housing and Human Services Program is responsible for: • Implementing the City’s semi-annual Competitive Process, allocating nearly three million dollars to the community each year. • Servicing nearly three dozen annual loan and grants for affordable housing, human services and public facilities programs and projects. • Maintaining federal and financial regulatory compliance. • Managing long-term mandated, complex legal and financial coordination of local housing projects. • Developing and implementing local affordable housing policy. Problem: the work group’s funding and staffing structure is no longer sustainable. Increases to the volume and complexity of caseload management and reporting have overwhelmed existing program staff. Insufficient City funds exist to administer the local programs. Federal funds cannot be used for administration of local programs. Currently, there are no City funds allocated for administration of local Affordable Housing and Human Services Programs. Historically, 100% percent of local funds have gone to projects. While efficiencies have been realized through automation of nearly all functions (financial, project tracking, Competitive Process), the work group can no longer keep pace with influencing pressures such as: • An increase in demand of administrative requirements, resulting in regulatory compliance and program performance issues (examples: Environmental Reviews, Fair Housing regulations, minority jobs and business reporting). See Exhibit A. • An expansion of work obligations both in amount and complexity. See Exhibit B for a snapshot of content and trends. Currently, there are 400 open Home Buyer Assistance files, 100 open long-term housing projects (6-8 are added every year), and $22 million in open housing loans. Coordination of Low Income Housing Tax Credit (LIHTC) considerations for nearly every housing project now requires a minimum of 200 hours staff time up front. It was never even a work task in past years. • Sophisticated skills do not currently exist within the work group; required training is extremely costly. • The number of Human Services projects has nearly doubled in five years. • Local funding (General Fund) for the HSP has increased (60% over five years: $332K to $540K). There has been no corresponding administrative cost resourcing. 10 • Local funding (General Fund) for the AHF program has increased in recent years ($133K to $333K). There has been no corresponding administrative cost resourcing. • Current year federal funding cuts are for CDBG (16.4%/$180,962) and HOME (12.2%/$83,282). Federal funds can no longer cover City tasks. Other communities were polled to learn how they resource similar programs. Many contribute General Fund dollars to affordable housing and human services. The City of Fort Collins does not currently contribute funds for administration of local programs. Pending retirements within the work group represent opportunities for a work group reorganization to achieve short-term efficiencies for 2012, and additional sustainability for 2013 and beyond. This 2012 revision request funds additional resources needed for administration of the City's General Fund and HSP programs, and City-driven tasks for affordable housing administration. Administrative support functions are decreased; affordable housing tasks are more fully addressed. Federal funds will still continue to fund a majority of the work group, resourcing federal-only tasks. The specific General Fund 2012 budget need of $54,499* is represented by: • 0.2 FTE HSP Grant Administrator: $15,445 • 0.1 FTE HSP/AHF clerical/financial support: $5,674 • 0.3 FTE AHF Program Administration: $33,380 (*Note: Request amended as a result of revised personnel costs received from Human Resources) If this funding situation is not addressed, there may be long term impacts to major components of the City’s affordable housing and human services programs. Immediate 2012 consequences may include: Cancellation of 20 contracts for Human Services Program and Keep Fort Collins Great social services projects ($540,733). That action would impact 9,534 low-income community members and 20 local agencies. In addition, the City may be forced to turn away new future CDBG, HOME and local funds due to the inability to meet program management and federal and local regulatory requirements. Staff is currently using federal funding to pay for local administration costs, which is not permissible. 11 EXHIBIT A: YEARLY AND FIVE-YEAR HUD REPORTING AND PROGRAM ADMINISTRATION REQUIREMENTS These requirements are the City’s responsibility as long as there are open files regardless of whether or not the City receives new allocations of CDBG and/or HOME funding. No program income is ever released from the regulations of the funding source. Required Reports Frequency Due FTE Analysis of Impediments to Fair Housing – major document requiring focus groups, extensive research, surveys, public review. Every five years August 15, 2012 .25 every five years 5�year Strategic Plan – major document requiring focus groups, extensive research, surveys, public review. Every five years August 15, 2014 .25 every five years Consolidated Annual Performance Evaluation Report – compilation of information in format required by HUD to prove eligibility of projects and processes Every year December 31 .1 Semi�Annual Labor Standards – review projects requiring Davis Bacon documentation, contact project managers to fill out required form, fill out separate form for City 2 x year October 8 and April 8 .01 Section 3 – review projects requiring Section 3 documentation, contact project managers to fill out required form, submit form electronically 1 x year December 31 .01 Minority, Black and Women’s Enterprise Report – follow form directions to report MBWE contracting 1 x year October 10 .01 Annual Action Plan – submitted every year according to HUD requirements to show planning process for the following year 1 x year August 15 .10 HOME Yearly Report – form which documents program income and other required information, attached to CAPER 1 x year December 31 .01 HOME Match Report – form documents required match (from IDIS report) and how the match was met by non�federal funds attached to the CAPER . OMB Audit Review – required review of all project audits to show adherence to OMB requirements. If there are discrepancies, the agency must be contacted and document how the discrepancy was mitigated. 1 x year June .01 Ongoing required program management Open files monitoring, site visits, project documentation, for approximately 100 open projects ● each project has a monitoring date set up in CDM ● the file is pulled and reviewed for requirements ● the file is reviewed for type of monitoring and if site visit is necessary ● project manager is contacted for a census of current residents, check for rental rates to be within guidelines ● if site visit is necessary (new project or problematic project), set up half a day to review files and units ● if project is also monitored by the State or CHFA, get a copy of the results from the project manager ● if problems are found, document and follow�up with a letter showing required mitigation, and continue to monitor until problem is resolved. Document. ● put all documentation and forms in the file folder ● set up next monitor in CDM ● return project file to cabinet Yearly – currently through 2041 As scheduled by project .05 Program Income processing ● Receive check ● If payoff, pull file ● Verify amount ● Insert amount in program income Excel file. For HOME, document whether it is PI or RE. Monthly Monthly .05 13 If PI, figure admin amount. ● Fill out PI transfer sheet x3 for Accounting, copy check x2, attach original check for Accounting and send, attach copy to copy of transfer sheet for other staff to verify, put copy of both in file. (Required that TWO staff receive on any payment.) ● Fill out Release paperwork and forward to Legal for City Manager signature ● Pull original Note and PN from safe and mark as paid in full ● When Release is signed, attached original docs and forward either to Title Company or to Public Trustee ● Update CDM and, if necessary, HBA databases to show paid in full ● Scan file, shred original, keep scanned file on cd for 5 years minimum ● If amortized loan, verify amount, update Excel file and CDM, fill out Accounting sheet and forward check with copy to other staff. ● Periodic monitoring for noncompliance. ● Yearly report to property owner Program Income competitive process (all notices, contracts, processing payments, etc.) All Program Income must be allocated within six months of receipt to projects which meet the eligibility requirements of either HOME or CDBG, whichever originally allocated the program income. Program eligibility requirements NEVER go away for any federal program income received. This includes all formal Yearly August 15 .25 14 processes including environmentals, public notices, public hearings, legal contracts, requests for reimbursements from projects, setting up and drawing from City finance, setting up and drawing from IDIS, and setting up monitoring as required. HBA monitoring of all open loans on a yearly basis, calling the notes of loans that are out of compliance, documents processing, foreclosures, releases, subordinations, etc. Daily Daily .25 IDIS updates and draws – at least two staff members must be authorized to set up projects, set up draws and authorize draws. Monthly Monthly .05 Files management, database updates, responding to HUD questions, public facility issues, HUD audits. Monthly Monthly .05 15 Human Services Agencies Requested AFH CDBG HOME HSP HSP-KFCG TOTAL BASE Camp: Sliding Scale Fee Tuition Assistance $48,000 $48,000 $48,000 100% Boy & Girls Club: After-School Program $18,309 $11,520 $11,520 63% Catholic Charities Northern: Senior Outreach $10,000 $10,000 $10,000 100% Catholic Charities Northern: Shelter & Supportive Services $48,264 $43,546 $43,546 90% Crossroads Safehouse: Advocacy Program $90,000 $45,000 $45,000 50% Disabled Resource Services: ATI Program $22,054 $22,054 $22,054 100% ELTC: Employment Skills Training $25,000 $17,623 $17,623 70% ELTC: Job Access & Retention Training $4,992 $0 0% Elderhaus: Therapy Center Activity Program $21,202 $21,202 $21,202 100% Elderhaus: Home Front Veterans Program $32,256 $0 0% Family Center: Sliding Scale Fee Tuition Assistance $20,000 $20,000 $20,000 100% Food Bank: Kids Café Program $22,167 $22,167 $22,167 100% HPI: Emergency Rent Assistance $40,000 $40,000 $40,000 100% LCMH: Mental Health Services for Crises Prev. Partner. $41,238 $0 0% Mathews House: Program for At-Risk Youth $29,436 $14,000 $14,000 48% NCAP: Client Services & Homelessness Prevention $25,000 $25,000 $25,000 100% Neighbor to Neighbor: Emergency Rent Assistance $21,000 $21,000 $21,000 100% Neighbor to Neighbor: Housing Counseling $68,906 $39,375 $39,375 57% PSS: Services for Single Parent Families $30,000 $30,000 $30,000 100% Respite Care: Sliding Scale Fee Tuition Assistance $25,000 $19,140 $5,860 $25,000 100% RVNA: Home Health Care Scholarships $35,000 $35,000 $35,000 100% United Day Care Center: Sliding Scale Fee Tuition Assist. $54,000 $54,000 $54,000 100% United Way: 2-1-1 $29,259 $0 0% VOA: Home Delivered Meals $25,116 $25,116 $25,116 100% Women's Resource Center: Dental Care Assist. $29,040 $29,040 $29,040 100% Total $815,239 $158,309 $440,334 $598,643 73% Housing Projects Requested AHF CDBG HOME HSP HSP-KFCG TOTAL CARE: Privincetowne Pre-Development Costs $150,000 $150,000 $150,000 100% EXHIBIT B: Affordable Housing Funds, CDBG, HOME and Human Services Program Spending for Calendar Years 2008, 2009, 2010 and 2011 Funding for 2008 (Spring) Funding for 2008 (Spring) The fiscal year for these programs is October 1st through September 30th of each year. 16 City of Fort Collins: Home Buyer Assistance $200,000 $122,711 $77,289 $200,000 100% City of Fort Collins: Land Bank Program $201,387 $0 0% Ft. Collins Housing Authority - Stanford Acquisition $1,139,000 $201,387 $937,613 $1,139,000 100% Ft. Collins Housing Corp. - Leisure Drive Rehab $216,524 $216,524 $216,524 100% Total $1,906,911 $201,387 $1,060,324 $443,813 $1,705,524 89% Housing Projects Requested AHF CDBG HOME HSP HSP-KFCG TOTAL CARE Housing: Provincetowne On-site Infrastructure $250,000 $250,000 $250,000 100% City of Fort Collins: Home Buyer Assistance - Rentals $50,000 $50,000 $50,000 100% City of Fort Collins: Home Buyer Assistance $200,000 $200,000 $200,000 100% Ft. Collins Housing Corp: Leisure Drive Rehab $116,820 $116,820 $116,820 100% Housing Authority Loveland: Larimer Home Improv. Prog. $100,000 $100,000 $100,000 100% Neighbor to Neighbor: Flooring Replacements $33,600 $33,600 $33,600 100% Total $750,420 $183,600 $566,820 $750,420 100% Human Services Agencies AHF CDBG HOME HSP HSP-KFCG TOTAL BASE Camp: Sliding Scale Fee Tuition Assistance $60,840 $60,831 $60,831 100% Boy & Girls Club: After-School Program $18,309 $18,309 $18,309 100% Catholic Charities: Senior Outreach $10,000 $10,000 $10,000 100% Catholic Charities: Shelter & Supportive Serv. $55,024 $37,856 $37,856 69% Center for Family Outreach: Volunteer Parenting Prog $15,000 $0 0% Consumer Credit Counseling: Financial Counseling $13,000 $0 0% Crossroads Safehouse: Advocacy Program $99,216 $51,542 $51,542 52% Disabled Resource Services: Access to Independence $25,656 $25,656 $25,656 100% ELTC: Employment Skills Training $22,000 $18,000 $18,000 82% ELTC: Evening Class Childcare Assistance $8,000 $0 0% Elderhaus: Therapy Center Activity Program $23,592 $23,592 $23,592 100% The Family Center: Sliding Scale Fee Tuition Assistance $20,000 $20,000 $20,000 100% Food Bank for Larimer County: Kids Café Program $27,959 $27,959 $27,959 100% Homelessness Prev. Initiative: Emergency Rent Assist. $45,000 $40,671 $40,671 90% Live the Victory: The Matthews House $29,120 $0 0% Neighbor to Neighbor: Housing Counseling $68,500 $39,915 $39,915 58% Neighbor to Neighbor: Emergency Rent Assist. $23,000 $23,000 $23,000 100% Northern Colorado Aids Project: Client Services $29,500 $29,500 $29,500 100% Poudre School District: 305 Club Sustainability Program $30,275 $0 0% Funding for 2008 (Fall) Funding for 2009 (Spring) 17 Project Self-Sufficiency: Services for Single Parents $33,000 $18,837 $14,163 $33,000 100% RVNA: Home Health Care Scholarships $38,000 $38,000 $38,000 100% Respite Care: Sliding Scale Fee Tuition Assistance $25,000 $25,000 $25,000 100% Turning Point: Volunteer Coordinator $25,000 $0 0% United Day Care Center: Sliding Scale Fee Tuition $60,000 $54,367 $54,367 91% Volunteers of America: Home Delivered Meals Program $29,108 $29,108 $29,108 100% Women's Resource Center: Dental Care Assistance $38,421 $35,223 $35,223 92% Total $872,520 $201,195 $440,334 $641,529 74% Homelessness Prevention Initiative (HPI) received CDBG-R (ARRA - Stimulus Money) Requested AHF CDBG HOME HSP HSP-KFCG TOTAL CARE: Privincetowne On-site Infrastructure, Part I $500,000 $300,000 $300,000 60% City of Fort Collins: Land Bank Program $140,000 $0 0% Cornerstone Assoc.: Cornerstone Apartments $300,000 $0 0% Ft. Collins Hous. Auth. - Village on Stanford Rehabilitation $450,000 $351,571 $98,429 $450,000 100% N2N - Improvements to Coachlight Plaza Apartments $185,635 $185,635 $185,635 100% City of Fort Collins: Consolidated Plan $15,000 $8,500 $6,500 $15,000 100% Total $1,590,635 $8,500 $843,706 $98,429 $950,635 60% FCHA received $230,466 of CDBG-R (ARRA - Stimulus Money) AHF CDBG HOME HSP HSP-KFCG TOTAL CARE: Provincetowne On-site Infrastructure, Part II $700,000 $20,250 $484,761 $505,011 72% City of Fort Collins: Home Buyer Assistance - Rentals $100,000 $100,000 $100,000 100% Ft. Collins Hous. Auth.: Tenant-Based Rental Assistance $167,900 $167,900 $167,900 100% Ft. Collins Housing Auth.: TBRA-Admin $40,000 $40,000 $40,000 100% Habitat for Humanity: Land Acquisition $75,000 $63,865 $63,865 85% Housing Authority of Loveland: LHIP $100,000 $100,000 $100,000 100% Neighbor to Neighbor: Playground/Landscaping $60,500 $25,000 $25,000 41% Total $1,243,400 $260,250 $88,865 $652,661 $1,001,776 81% Human Services Agencies Requested AFH CDBG HOME HSP HSP-KFCG TOTAL BASE Camp: Sliding Scale Fee Tuition Assistance $63,000 $54,200 $54,200 86% Boy & Girls Club: After-School Program $21,036 $17,458 $17,458 83% Catholic Charities Northern: Senior Outreach $10,000 $7,000 $7,000 70% Catholic Charities Northern: Shelter & Supportive Services $55,000 $29,500 $29,500 54% Crossroads Safehouse: Advocacy Program $99,216 $51,042 $51,042 51% Funding for 2009 (Spring) Funding for 2009 (Fall) Funding for 2010 (Spring) 18 Disabled Resource Services: ATI Program $27,884 $22,010 $22,010 79% ELTC: Employment Skills Training $20,000 $17,500 $17,500 88% Elderhaus: Mindset Therapy Center Activity Program $23,592 $20,142 $20,142 85% Family Center: Sliding Scale Fee Tuition Assistance $25,000 $20,500 $20,500 82% Food Bank: Kids Café Program $27,052 $21,667 $21,667 80% HPI: Emergency Rent Assistance $45,000 $28,516 $11,484 $40,000 89% Mathews House: Program for At-Risk Youth $29,120 $0 0% NCAP: Client Services & Homelessness Prevention $29,500 $24,500 $24,500 83% Neighbor to Neighbor: Emergency Rent Assistance $23,000 $20,200 $20,200 88% Neighbor to Neighbor: Housing Counseling $68,500 $39,415 $39,415 58% PSS: Services for Single Parent Families $33,000 $28,500 $28,500 86% Respite Care: Sliding Scale Fee Tuition Assistance $25,000 $22,500 $22,500 90% RVNA: Home Health Care Scholarships $38,000 $26,100 $26,100 69% Turning Point: Emergency Mental Health Services $10,000 $0 0% United Day Care Center (Teaching Tree): Sliding Scale Fee $60,000 $51,500 $51,500 86% VOA: Home Delivered Meals $29,108 $19,500 $19,500 67% Women's Resource Center: Dental Care Assist. $41,442 $34,725 $34,725 84% Total $803,450 $178,358 $389,601 $567,959 71% Housing Projects Requested AHF CDBG HOME HSP HSP-KFCG TOTAL CARE: Privincetowne Pre-Development Costs, Part III $250,000 $250,000 $250,000 100% City of Fort Collins: Home Buyer Assistance $200,000 $200,000 $200,000 100% Total $450,000 $0 $450,000 $0 $450,000 100% Planning & Housing Projects Requested AHF CDBG HOME HSP HSP-KFCG TOTAL City of Fort Collins: Consolidated Plan Implementation $35,535 $35,535 $35,535 100% City of Fort Collins: Home Buyer Assistance $50,000 $50,000 $50,000 100% CARE: Provincetowne Green CHDO Capacity Grant $50,000 $0 0% Caribou: Caribou Apartments Phase II $300,000 $300,000 $300,000 100% FCHC: Legacy Senior Residences $720,000 $28,890 $187,977 $73,133 $290,000 40% Harvest Construction: Spring Creek Apartments $585,000 $0 0% Housing Authority of Loveland: LHIP $110,000 $110,000 $110,000 100% Total $1,850,535 $188,890 $223,512 $373,133 $785,535 42% Human Services Agencies Requested AFH CDBG HOME HSP HSP-KFCG TOTAL BASE Camp: Sliding Scale Fee Tuition Assistance $57,000 $57,000 $57,000 100% Boy & Girls Club: After-School Program $19,892 $18,644 $18,644 94% CARE Housing: Supportive Services Program $25,000 $0 0% CASA: Program Support $14,976 $9,360 $9,360 63% Funding for 2010 (Spring) Funding for 2010 (Fall) Funding for 2011 (Spring) 19 Catholic Charities Northern: Senior Outreach $12,000 $11,331 $11,331 94% Catholic Charities Northern: Shelter & Supportive Services $75,000 $40,000 $40,000 53% Center for Family Outreach: Youth Diversion Program $17,500 $0 0% ChildSafe: Child Abuse Program $30,000 $0 0% Crossroads Safehouse: Advocacy Program $99,216 $16,469 $25,733 $42,202 43% Disabled Resource Services: ATI Program $28,442 $28,442 $28,442 100% ELTC: Employment Skills Training $2,209 $19,483 $19,483 882% Elderhaus: Mindset Therapy Center Activity Program $23,592 $23,592 $23,592 100% Family Center: Sliding Scale Fee Tuition Assistance $30,000 $30,000 $30,000 100% Food Bank: Kids Café Program $21,000 $21,000 $21,000 100% HPI: Emergency Rent Assistance $45,000 $45,000 $45,000 100% LCMH: Community Dual Disorder Treatment $27,082 $14,000 $14,000 52% LCMH: Employee Assistance-Murphy Center $16,012 $0 0% Matthews House: Program for At-Risk Youth $27,639 $27,639 $27,639 100% Neighbor to Neighbor: Housing Counseling $69,205 $10,175 $30,000 $40,175 58% Neighbor to Neighbor: Emergency Rent Assistance $25,000 $25,000 $25,000 100% NCAP: Client Services & Homelessness Prevention $29,500 $24,500 $24,500 83% PSS: Services for Single Parent Families $33,000 $22,000 $22,000 67% RVNA: Home Health Care Scholarships $35,000 $9,049 $25,951 $35,000 100% Respite Care: Sliding Scale Fee Tuition Assistance $30,000 $30,000 $30,000 100% Suicide Resource Center: R.A.P.P & Hope Programs $3,000 $3,000 $3,000 100% Teaching Tree: Sliding Scale Fee Tuition Assistance $60,000 $60,000 $60,000 100% VOA: Home Delivered Meals $29,200 $29,200 $29,200 100% Women's Resource Center: Dental Care Assist. $44,890 $32,890 $32,890 73% Total $930,355 $149,124 $389,601 $150,733 $689,458 74% Housing Projects Requested AHF CDBG HOME HSP HSP-KFCG TOTAL FCHA: Land Acquisition - Spring Creek Apartments $350,000 $0 0% FCHC: Legacy Senior Housing $430,000 $87,549 $339,615 $427,164 99% Merten: Union Place - Senior Housing $750,000 $750,000 $750,000 100% Total $1,530,000 $837,549 $339,615 $1,177,164 77% Funding for 2011 (Spring) 20 Revision Title: Fund: Contact: Budget Office Result Area: Related Offer #: 106.2,3 and 6 Total Amount: $546,571 Funding Source #1: Funding Amount #1: $546,571 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Restore Conservation Trust Funds for Trail Construction N/A This revision request reduces the amount to be transferred from the Conservation Trust Fund to the General Fund for park maintenance in 2012. This reduction brings the transfer back to the 2010 level of $730,146. The current budgeted transfer in 2012 is $1,276,717 ($934,717 ongoing and $342,000 reserves). Funding for park maintenance at this level is not sustainable in the Conservation Trust Fund and eliminates funding for the trail construction program. When compiling the 2011-2012 budget there were insufficient General Fund revenues to support the parks maintenance expenses approved for 2012. The decision was made to increase the use of Conservation Trust money including the use of reserves for parks maintenance in 2012 and reconsider the funding during the 2012 revision process. If General Fund revenues (primarily Sales and Use Taxes) came in higher than expected, we would backfill the Conservation Trust Fund reserves and ongoing revenue. 100 - GENERAL FUND Culture, Parks and Recreation General Fund 21 Revision Title: Fund: Contact: Steve Dush Result Area: Relative Offer #: 108.11 Total Amount: $75,341 Funding Source #1: Funding Amount #1: $75,341 FTE Requested: Description: The Development Review Center (DRC) will be losing a long-term, 22-year employee (City Planner) at the end of March 2012 due to retirement. In an effort to maintain service levels to the best of our ability, to ensure sufficient time to train and pass on the wealth of information posessed by the current incumbent to a new City Planner, and to implement the automation of planning and development records, we are proposing to implement a succession planning process. Please refer to the accompanying information that follows. .75 FTE - Contractual City Planner/Records Tech 2012 BUDGET REVISION REQUEST Development Review Succession Planning .50 FTE - Contractual City Planner 100 - GENERAL FUND Economic Health General Fund 22 Community Development & Neighborhood Services 281 North College Avenue P.O. Box 580 Fort Collins, CO 80522.0580 970.416.2740 970.224.6134- fax fcgov.com Planning, Development & Transportation Council Finance Committee Information - CDNS September 15, 2011 Revision Request: Development Review Succession Planning FTE Requested: .5 FTE Contractual City Planner and .75 FTE Contractual City Planner/Records Tech Description: The Development Review Center (DRC) will be losing a long-term, 22-year employee (City Planner) at the end of March, 2012 due to retirement. In an effort to maintain service levels to the best of our ability, to ensure sufficient time to train and pass on the wealth of information possessed by the current incumbent to a new City Planner, and to implement the automation of planning and development records, we have submitted this request. Rationale: 1) .5 FTE Contractual City Planner: We are asking for the continuation of an existing City Planner contract for the first six months of 2012. This Planner has been with the City for six years and has been doing an exceptional job. The Planner was RIF'd during the 2010 BFO process, but was hired back as a contractual employee to perform specific duties in Economic Health and Community Development and Neighborhood Services. Continuation of this contract ensures continuity and continued assistance with the work load demands being experienced within the DRC. It also gives staff the time to complete an internal hiring process, something that cannot occur until April, 2012. If this existing position is accommodated by economic health, the request for the monies would still be necessary to accommodate the succession planning by allowing for a new planner to be hired and trained by the retiring planner position that will occur in April of 2012. 2) .75 FTE Contractual City Planner/Records Tech: Secondly, we are asking for the move of the retiring Planner to a three-quarter time (.75 FTE) contractual employee, based on feedback from him that he would like to continue in some fashion with the City. Due to the above-referenced training and succession planning needs, as well as the need identified for automation of planning and development records, a position that combines both elements is being proposed. The position would focus 20% of time on City planning, training, and succession efforts, and 80% of time on records management efforts. The pay for the position will be adjusted as well by paying at a City Planner rate for 20% of the time expended and at a Records Tech rate for 80% of the time expended. Doing so results in an hourly wage of $16.80 and an annual salary (at .75 FTE) of $26,000. Annual benefits are estimated to be $15,000, for a total compensation amount of $41,000. We estimate that it will take us approximately 8 years, with a .75 FTE, to convert all Current Planning paper files into an electronic medium (excluding those records already off-site); longer if the FTE is not 100% devoted to this task. Doing so, however, will increase the services provided to customers as they will be able to quickly reference this information online, as well as enhance staff's efficiency by giving all staff quick access to records without having to search for paper files. In combination with the 23 CDNS Council Finance Committee Info September 15, 2011 Page 2 Building and Engineering records already converted to electronic format, as well as other functions such as GIS, we will have a much more robust way of identifying activities that have occurred on properties and providing better guidance, studies and analysis by having more complete information readily available to us. Although the City Planner who will be moving to this position, if approved, is not trained in records management duties, his knowledge of the planning files and related documents make him an invaluable resource for this task. It is much harder to train someone on the planning files, types and purposes of documents, items that should be kept, etc., than it is to train them how to scan and index. As well, knowing the documents is imperative for indexing them appropriately to enable all those who access the documents electronically to find what they are looking for. Outcomes: Approval of this request will assist us in meeting workload demand and service expectations of the Development Review Center. It supports the City’s efforts for succession planning and gives us the opportunity to increase services levels and staff efficiency for the reasons stated above. Data: Perhaps one of the most valuable resources the City has is manifest in the institutional knowledge of its long-term employees. The ability to mine this knowledge while providing an efficient method of file management is a win/win/win for the City, a retiring employee and an incoming employee. Succession planning is key to our workforce as our demographics are changing with the boom of retirements resulting from the aging baby boomers. It takes 30 minutes to 1 hour to prep an individual file for scanning. It takes another 2 hours to completely scan, index and finalize things. Because each file is different and can take more or less time, we are assuming an average 2 hours per file for all – prep, scanning, indexing and finalizing. Assuming 40 files per box, it will take approximately 80 hours per box to convert our planning files from paper to electronic format. We have approximately 156 boxes of information here at 281 (including Historic Preservation and some Zoning files). 156 * 80 = 12,480 hours to get this completed. This does not include any of the boxes we have off-site, which is likely more than the 156 boxes we have here. If we have someone working ¾ time on this, it will take 8 years to complete the transfer of just the records we have on-site. 24 Revision Title: Fund: Contact: Steve Dush Result Area: Package/Offer #: 108.11 Total Amount: $65,000 Funding Source #1: Funding Amount #1: $65,000 FTE Requested: Description: 0.5 FTE - Environmental Planner This request is to increase 2 existing half-time (.5 FTE) positions to full-time (1.0 FTE) in order to help meet the increased demand in the Development Review Center (DRC). Since 2006, 11.7 FTE have been eliminated from the DRC: 4.5 FTE in 2006 as part of the consolidation efforts and 7.2 FTE in 2009 due to a decline in development and building activity. These positions included: 1 FTE Director (Neighborhood & Building Services), 2 FTE Building Inspectors, 1 FTE Plans Analyst, 1 FTE Senior Planner, 1 FTE City Planner, 3 FTE Customer Service Reps, 1 FTE Admin Assistant, 1 FTE Admin Secretary, .5 FTE Environmental Planner and a .2 FTE Civil Engineer. Since 2009, we have seen an increase in activities for both 2010 and YTD 2011. The most marked increase in activity has been with building permits where we are 35% higher than in 2009 as of July 31st. This results in added activities for many staff in the DRC, including Customer Service, Planners, Plans Analysts and Inspectors. As well, added responsibilities from new programs such as Green Building, have also resulted in additional work load. Please refer to the accompanying information that follows. 2012 BUDGET REVISION REQUEST Development Review - Customer Service Demand 0.5 FTE - Building & Permit Tech 100 - GENERAL FUND Economic Health General Fund 25 Community Development & Neighborhood Services 281 North College Avenue P.O. Box 580 Fort Collins, CO 80522.0580 970.416.2740 970.224.6134- fax fcgov.com Planning, Development & Transportation Council Finance Committee Information - CDNS September 15, 2011 Revision Request: Development Review – Customer Service Demand FTE Requested: .5 FTE Building & Development Review Tech and a .5 FTE Environmental Planner Description: This request is to increase 2 existing half-time (.5 FTE) positions to full-time (1.0 FTE) in order to help meet the increased demand in the Development Review Center (DRC). Since 2006, 11.7 FTE have been eliminated from the DRC: 4.5 FTE in 2006 as part of the consolidation efforts and 7.2 FTE in 2009 due to a decline in development and building activity. These positions included: 1 FTE Director (Neighborhood & Building Services), 2 FTE Building Inspectors, 1 FTE Plans Analyst, 1 FTE Senior Planner, 1 FTE City Planner, 3 FTE Customer Service Reps, 1 FTE Admin Assistant, 1 FTE Admin Secretary, .5 FTE Environmental Planner and a .2 FTE Civil Engineer. Since 2009, we have seen an increase in activities for both 2010 and YTD 2011. The most marked increase in activity has been with building permits where we are 35% higher than in 2009 as of July 31st. This results in added activities for many staff in the DRC, including Customer Service, Planners, Plans Analysts and Inspectors. Added responsibilities from new programs such as Green Building, have also resulted in additional work load. Rationale: 1) Customer & Admin Services (CAS) – .5 FTE Building & Development Permit Tech: This position is responsible for all initial customer contact at the DRC, determining customer needs and educating them about DRC processes and procedures; development submittal intake and routing; building and construction permit intake and issuance; plan review on small projects; calculating and collecting fees; tracking approvals/holds for permits and Certificates of Occupancy; contractor licensing; and various financial and reporting duties. The CAS group has experienced a loss of 5.0 FTE since 2006. Although hourly monies were approved as part of the 2011/2012 BFO process, the hourly assistance is not enough to bridge the service gap we are experiencing. This is being realized in the form of work load delays on numerous activities (i.e., wait time for phone calls up to 30 minutes; wait time for customers in lobby up to 45 minutes; delay in permit submittal routings up to 2 weeks, delay in over-the-counter permit issuance up to 3 weeks; delay in fee estimates up to 1 month; delay in contractor licensing duties up to 3 months and items such as web updates, plan filing and records management for development review not being completed at all); climbing comp time balances; and the need for others in the organization to assist with counter coverage and work load creating a backlog in their regular duties. The current situation is unsustainable for the following reasons: A. Comp time is a detrimental way to handle prolonged workload since it creates additional coverage problems as employees use this time in addition to their vacation time, as well as budget problems if an employee leaves with high comp time balances accrued. As well, once the employees reach the maximum accrual allowed, they are 26 no longer able to provide additional assistance. B. Employee burnout and loss of morale are highly likely to increase. C. Any increase in workload will further impact timelines since there is simply no more room to absorb additional work. 2) Current Planning – .5 FTE Environmental Planner: This position was reduced to half- time in 2006. However, with the increase in service demands currently being experienced, as well as the addition of new programs such as Green Building, this position needs to be reinstated to full-time status. Based on preliminary staff analysis, we have found over 75% of wetland-related habitat types occur on private land within our City Limits and our GMA boundaries. Our current .5 FTE is the only person responsible for managing these, and other natural habitats and features, that occur on private land. The main vehicle for protection of these resources is through the Land Use Code, which is implemented by the Development Review Center. So, as well as having the private- land resources to manage, this .5 FTE position is responsible for reviewing and making recommendations on how to protect, maintain, and enhance these resources as part of the development review process. In addition, it is well documented via research and through observations on projects in the City, that native landscapes are much more complex to establish and restore. So often in the applications that come through the DRC, the parcels' existing natural habitats or features have been degraded over time due to the development encroachment surrounding the features. Thus, a significant component of the Development Agreement emphasizes restoring these lands to a higher function, including specific, line-items that stress weed management and control, proper seed mixes and post-construction monitoring. This position is responsible for these duties as well as for inspections of landscaping, wetlands and similar environmental items for several years after approval, to ensure that these things continue to meet what was approved. Current projects include six wetland-specific projects and ten other developments containing natural habitat buffer zones, for a total of almost 30 acres. As Council is aware, these projects require significant staff time to ensure success, as establishing, re-establishing, and ongoing management of native communities requires a long-term commitment from both the developer and staff to ensure commitments are adhered to. Enhanced tracking of these projects via Accela has increased our capacity to ensure compliance in 2011, but more is needed to ensure we are achieving our City’s private land conservation objectives. Based on our current level of resources, we are unable to provide the level of service we believe Council expects in this area. The current incumbent employee frequently works beyond the 20 hours per week allotted for this position. Because the position is exempt, the employee receives no overtime or comp time for these extra efforts. Outcomes: Increasing these positions to full-time will assist us in meeting workload demand and service expectations of the Development Review Center. Data: See graphs on following pages 27 Development Review Center Workload Activity As of July 31, 2011 The following information depicts work load indicators for the Development Review Center (DRC). The data shown compares year-to-date information through July 31 st for 2007 through 2011. Total permits as of the end of July, 2011 are up 35% over 2009, the year where many staff reductions occurred. Total Permits (2007-2011 as of July 31st) 0 1000 2000 3000 4000 5000 2007 2008 2009 2010 2011 Year Number Issued Total Permits New residential permits are up 125% over 2009 numbers. As well, residential additions/alterations are up 41% and residential miscellaneous (i.e., sheds and garages) are up 95% over 2009 numbers. Residential Building Permits (2007 - 2011 as of July 31st) 0 100 200 300 400 500 600 700 New Dw elling Units Additions/Alterations Miscellaneous Type of Permit Numbers Issued 2007 2008 2009 2010 2011 28 New commercial permits are equal to 2009 numbers. Commercial additions/alterations are up 41% and commercial miscellaneous (i.e., sales trailers, temporary sales lots) are 10 times higher than in 2009; however the numbers are very small – 0 permits in 2009; 10 permits in 2011. Commercial Building Permits (2007 - 2011 as of July 31st) 0 50 100 150 200 250 300 350 400 450 500 New Commercial Additions/Alterations Miscellaneous Type of Permit Numbers Issued 2007 2008 2009 2010 2011 Over-the-Counter permits are for things such as basement finishes, roofing, and furnace/water heater replacements. These permits are 33% higher than 2009. Over-the-Counter Building Permits ( 2 007 - 2011 as of July 3 1st ) 2111 2719 1841 2048 2648 0 500 1000 1500 2000 2500 3000 Over-the-Counter Type of Permit Numbers Issued 2007 2008 2009 2010 2011 29 The increase in building permit activity comes with an increase in all ancillary services related to this activity for all employee groups represented in the DRC. This includes customer service at the counter, plan review, inspections, contractor licensing efforts, and customer phone calls. As an example, below is phone call data related only to one employee group of the DRC - Customer & Admin Services. It shows the numbers of incoming phone calls answered by this group for the entire year 2007-2010. The numbers shown for 2011 are the calls that have come in through July 31 st ! So, in the first 7 months of 2011, this group of employees has answered more phones calls than all of 2008, 2009 or 2010. By year- end, we will have far exceeded total calls received in any of the years listed. Phone Calls Received by CAS Group (2011 #s are through July 31st; all other Years are through December 31st) 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000 2007 2008 2009 2010 2011 Year Calls Received Phone Calls 30 Revision Title: Fund: Contact: Tom DeMint Result Area: Package/Offer #: 132.1 - 6 Total Amount: $228,926 Funding Source #1: Funding Amount #1: $59,768 Funding Source #2: Funding Amount #2: $169,158 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Poudre Fire Authority Non Discretionary & Total Compensation Increase N/A In 2012, PFA will incure non-discretionary increases projected as follows: - $ 25,275 Line-item contingency (by PFA Board policy) - $ 50,000 Fuel - $ 11,406 General Liability Insurance - $ 1,330 Wastewater - $ 3,995 Electric $ 92,006 TOTAL Non-Discretionary Increase ($74,709 City's portion or 81.20%) In addition, PFA employee salaries have been frozen since 2009. We conduct an annual total compensation survey of nine Front Range fire departments in October/November, which is the soonest we will have comparison data. However we believe our dedicated employees should receive a modest salary increase of one and a half percent in 2012 based on current projections. The City's portion of a 1.5% salary increase is $154,217. This does not include employees funded by KFCG funds, since those funds will see an increase in 2012. PFA is requesting to provide a 1.5% salary increase ($154,217) and increases in non-discretionary line items ($74,709) for a total City contribution of $228,926. 840 - POUDRE FIRE AUTHORITY Safe Community General Fund Keep Fort Collins Great Fund 31 Revision Title: Fund: Contact: Wendy Williams Result Area: Package/Offer #: 3.1 Total Amount: $29,157 Funding Source #1: Funding Amount #1: $29,157 FTE Requested: Description: 2012 BUDGET REVISION REQUEST CMO Policy and Project Manager Increase from 0.8 to 1.0 FTE 0.2 FTE - Increase from 0.8 to 1.0 FTE This position develops and coordinates needed programs, proposals and analysis on behalf of City Council and the City Manager. It also is responsible for all legislative analysis and advocacy of both State and Federal issues, including support for the Council Leglislative Review Committee (LRC) and lobbying with the Colorado General Assembly. In response to budget shortfalls the position was reduced from 1.0 to .8 in 2010. As a result, the level of service has also been reduced. This offer will enable the City to provide more robust policy and project management and analysis, and to play a more proactive role in advocating for legislative changes with the Colorado General Assembly. 100 - GENERAL FUND High Performing Government General Fund 32 Revision Title: Fund: Contact: Wendy Williams Result Area: Package/Offer #: New Total Amount: $79,414 Funding Source #1: Funding Amount #1: $79,414 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Federal Legislation Analysis and Action 0.5 FTE - Policy and Project Manager The Council Legislative Review Committee has requested that the City take a more proactive role in influencing Federal legislation. This offer includes funding for .5 FTE responsible for tracking, analyzing and advancing the City's position on a variety of bills filed by the United States Congress. The City may also partner with local Congressional representatives to initiate legislation of importance to the City of Fort Collins. This offer includes a rough estimate of $21,000 for Federal lobbying services based in Washington, DC. The City currently belongs to organizations that have some Federal lobbying capacity (e.g. Colorado Municipal League, National League of Cities, ICMA) and these organizations would also be utilized to effect change. All activities, including communicating and coordinating with consultants, partner organizations and the Legislative Review Committee, would be the responsibility of the new 0.5 FTE. 100 - GENERAL FUND High Performing Government General Fund 33 Revision Title: Fund: Contact: Bruce Hendee Result Area: Package/Offer #: New Total Amount: $200,000 Funding Source #1: Funding Amount #1: $150,000 KFCG - Other Transportation $50,000 FTE Requested: Description: The City is about to embark on the largest infrastructure project in its history. The MAX BRT project will cost between $80M-$84million to construct. Additionally City Council last year approved the final Plan Fort Collins Comprehensive Plan which is a far reaching planning document which will guide the city forward for years to come. As part of this document the Mid Town corridor is identified as a major geographic location for economic redevelopment. To this end Council in recent weeks has approved the extension of an Urban Renewal District into the Mid Town area. Taken in combination, it is important to invest in a comprehensive strategy to ensure key strategic activities take place to maximize the chances for success of the corridor. Staff feels there are several key elements needed to ensure success of these major investments. 1. Communication Strategy A. Establish ongoing communication now about the corridor as an economic health corridor. B. Institute a pre construction and during construction communication program similar to the highly recognized TREX program used in Denver during construction of additional lanes and a light rail line. C. Develop branding and a strategy together with local merchants to define the corridor in recognizable terms. Actively communicate with merchants about the benefits of the corridor through a thoughtful campaign. 2. Prepare a parking strategy to encourage the development community to develop at higher densities. This is important to realize the benefits of the TOD concept and reduce sprawl and maximize the potential for success of MAX. Without this strategy developers will develop at lower densities than necessary to meet the intent of the plan. 3. Create an Urban Design Plan which establishes the important framework for future redevelopment. This includes working with local merchants to encourage the formation of a self sustaining Business Improvement District. This plan will establish major districts, character areas, sub-district identities, urban design for the area adjacent to MAX, and for College Avenue. The plan will also include the development an approach for connecting to Foothills Mall, enhanced urban plans for stations, promenade along the corridor, architecture guidelines, and a strategic plan for merchants to use Max for marketing benefits. This plan is an extension of the Mid Town Study which identified key urban study as a next phase. 2012 BUDGET REVISION REQUEST Mason Corridor Synergies and Support Services N/A 100 - GENERAL FUND High Performing Government General Fund 34 Revision Title: Reorganization - Office of Sustainability Fund: Contact: Bruce Hendee Result Area: Package/Offer #: New Total Amount: $122,200 Funding Source #1: Funding Amount #1:$91,650 Natural Areas Fund $30,550 FTE Requested: Description: 2012 BUDGET REVISION REQUEST 1.0 FTE - Sustainability Director 100 - GENERAL FUND Environmental Health General Fund This offer is to retain one FTE for the purposes of heading a new position which would be titled Environmental Services Director. This person would report to the Chief Sustainability Officer (CSO). The Office of Sustainability would be a new City department with the intent of institutionalizing Sustainability as a key component of the City Organization. The organizational change is as follows: Chief Sustainability Officer directs two immediate departments and one possible future department. The structure is based on the Triple Bottom Line of economy, environment, and social health. The CSO would lead the Economic Health Office, Environmental Services Office, and lead efforts to enhance the city position in social health. To accomplish this reorganization the following would occur: 1. Formation of an official Office of Sustainability (OSUS) 2. Hire an Environmental Services Director ( 1 FTE) 3. Environmental Services within the Natural Resources Office would move to OSUS 4. An Environmental Policy specialist moves from utilities to the OSUS. This position is funded through a one year contract extension by Utilities. 35 Revision Title: Fund: Multiple Contact: Amy Sharkey Result Area: Package/Offer #: N/A Total Amount: $812,390 Funding Sources: Funding Amounts: General Fund $139,780 Subsidized Funds Cultural Services & Facilities Fund $14,375 Recreation Fund $17,928 Cemeteries Fund $2,138 Transit Services Fund $2,231 Street Oversizing Fund $4,429 Transportation Services Fund $94,403 General Fund & Subsidized Funds $275,284 Keep Fort Collins Great Fund $19 Neighborhood Parkland Fund $475 Conservation Trust Fund $8,033 Natural Areas Fund $28,543 Golf Fund $4,937 Light & Power Fund $193,740 Water Fund $77,857 Wastewater Fund $66,733 Stormwater Fund $45,608 Equipment Fund $41,724 Self Insurance Fund $1,622 Data & Communications Fund $22,890 Benefits Fund $2,325 Utility Customer Svc. & Admin. Fund $42,600 $537,106 TOTAL $812,390 FTE Requested: None Description: The City's philosophy is to provide a compensation program that is competitive in attracting and retaining quality employees. The goal has been to pay employees, on average, at or slightly above the "target market", based on performance. As a result of Citywide budget reductions for the past few years, nearly 1/3 of City employees have fallen below "market;" 209 of those are merit employees, and 129 are skills-based. Total cost to correct the market problem is $1,424,486. The City will use funds currently appropriated in the 2012 Budget for personnel cost increases to bring 113 merit employees and 129 skills-based employees to within 5% of their respective target market, so long as they are meeting performance expectations. The cost of these increases is $612,096. This budget exception offer requests $812,390 to bring employees fully up to their target market. It represents the difference between the full cost ($1,424,486) of bringing the employees to their respective target market and the amount included in the 2012 Budget ($612,096). This offer is contingent upon City Council's adoption of the 2012 Pay Plan. 2012 BUDGET REVISION REQUEST Below Market Pay Adjustment High Performing Government Reserves Other Funds 36 Below Market Costing – Market Revision Request Data as of August 29, 2011 Our Pay Philosophy • Provide a program that will be competitive in attracting and retaining quality employees needed to execute the City’s vision and mission. The goal is to pay employees, on average, at or slightly above target market based on performance. • The “target market” is the average actual pay for a job. Data is supplied from published surveys. The midpoint of the pay range is set using the “targeted market” information. As with all surveys, there is a percentage of error to consider. For purposes of below market costing +/- 2% will be used as the margin of error. Therefore, 2% below and 2% above the midpoint of the pay range is the “target market”. Target Market - - - - - - - - Pay Grade Minimum Midpoint Maximum Employees should be paid at the targeted market of their pay range unless: • New to the City with entry level experience, knowledge, skills, and abilities • Rehired by the City with entry level experience, knowledge, skills, and abilities • Paid correctly based on knowledge, skills, and abilities • Paid correctly based on experience • New to the position (promoted, transferred, classification changes) • Performance issues (recent past year(s) or current year) • Performance Improvement Plan • Disciplinary Action • Internal equity 37 Current Situation The City currently has 284 merit employees that are below market; this equates to 35% of merit employees • Recommend excluding 75 merit employees from costing because of specific business reasons (employees identified as new hires or rehires, promoted employees, and employees with changes in classification). The rationale for excluding this group of employees is that when they were hired, promoted, etc. their starting salaries were negotiable, and that a business case exists for why they are currently paid below the target market. Also excluded are employees identified with potential performance issues, pay revisions, and changes in occupational groups. • Of the remaining 209 employees, 113 employees are more than 5% (up to 22%) below market Skills-Based Pay employees are currently linked to their 2008 pay ranges due to the fact that we have not been able to grant any type of market increase to employees. Skill ladder pay ranges are set just like merit employee pay ranges by using average actual salaries paid in other public and private organizations as the basis for setting the pay range midpoints, our market. Skills- Based Pay employees have the ability to progress through their entire pay range, up to the pay range maximum, based on established skill ladder criteria. • The City has 129 skills-based pay employees that are “frozen” in the 2008 pay ranges Compensation Levels All City Employees (64% at or above target market, 36% below target market) New Hires & Rehires, 33, 3% Promotions, 16, 2% Classification Changes, 10, 1% Performance Issues, 14, 1% Below Target - Merit, 209, 18% At or Above Target Market, 730, 64% Below Target - SBP, 129, 11% Other, 2, 0% 38 Market Revision Request – Bring eligible Merit and Skill Employees up to Target Market # of Merit Employees Impacted: 209 Cost: $430,131 Impact on General/Subsidized Funds: 122 employees at cost of $252,272 # of Skill-Based Pay Employees Impacted: 129 Cost: $382,259 Impact on General/Subsidized Funds: 9 employees at a cost $23,012 TOTAL # of Employees Impacted: 338 TOTAL Cost: $812,390 TOTAL Impact on General/Subsidized Funds: $275,284 Below Market Costing - Market Exception Request $382,259 Recommended Adjustment $430,131 Recommended Adjustment $335,128 Not Adjusting $0 $100,000 $200,000 $300,000 $400,000 $500,000 $600,000 $700,000 $800,000 $900,000 Merit SBP Employees Cost Below Market Costing - by Fund Merit & SBP ees - Market Exception Request ($812,390) Other Funds $153,168 19% Utility Funds $383,938 47% General Fund & Subsidized Funds $275,284 34% 39 THIS PAGE LEFT INTENTIONALLY BLANK 40 Revision Title: Fund: Contact: Dawna Gorkowski Result Area: Related Offer #: 105.2 Total Amount: $40,000 Funding Source #1: Funding Amount #1: $40,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Downtown Ice Rink Installation and Removal N/A This request is for funding to set up and remove the ice rink in Old Town Square for the 2012/2013 holiday season. As a result of the amendment to the DDA statute, the DDA will be allowed to collect tax increment revenue for a total of 50 years, but in a reduced capacity in the final 20 years. The combined effects of the statutory amendment resulted in a projected revenue reduction for the DDA of 63% beginning in fiscal year 2012. Due to this reduction, the DDA no longer has funding for the ice rink. The DDA initially purchased the ice rink in 2005 for $200,000 and pays the Parks Division to install and remove the rink. The Recreation Department operates the rink. Sufficient revenue is generated from the operation of the rink to cover Recreations costs, but not the installation and removal costs. DDA has funding for the rink in 2011, but not 2012. The ice rink offer (105.2) was purchased in 2011 and 2012 with DDA as the funding source. This offer will take the 2012 budget of $40,000 out of the General Fund and add it to the Keep Fort Collins Great Fund. 254 - KEEP FORT COLLINS GREAT FUND Economic Health KFCG - Other Community Priorities 41 Revision Title: Fund: Contact: Dawna Gorkowski Result Area: Related Offer #: New Total Amount: $85,000 Funding Source #1: Funding Amount #1: $85,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Downtown Holiday Lighting N/A This is a request to fund the downtown holiday lighting for the 2012/2013 holiday season. As a result of the amendment to the DDA statute, the DDA will be allowed to collect tax increment revenue for a total of 50 years, but in a reduced capacity in the final 20 years. The combined effects of the statutory amendment resulted in a projected revenue reduction for the DDA of 63% beginning in fiscal year 2012. Due to this reduction, the DDA no longer has funding for the holiday lights. The DDA initially purchased the lights in 2007 for $100,000. The City, DDA, and Downtown Business Association (DBA) agreed to split the cost of installation and removal of the lights each year. The City and DDA paid $30,000 and DBA paid $15,000. In 2010 neither the City nor the DBA had funding for the lights, so DDA paid the entire cost. The DDA will cover the cost in 2011, but that is the last year. This offer also includes repairs and replacement of lights. The weather, vandalism, and squirrels have taken a toll on the current lights and there is a need to replace light bulbs and some light strands. This offer includes $15,000 for replacement and repair of the lights and $70,000 for installation and removal. 100 - GENERAL FUND Economic Health Keep Fort Collins Great Fund 42 Revision Title: Fund: Contact: Ellen Switzer Steve Catanach Result Area: Related Offer #: 10.1 Total Amount: $121,969 Funding Source #1: Funding Amount #1: $121,969 FTE Requested: Description: Please refer to the accompanying memo for additional information. For the last several years, the Light and Power Fund has been reducing working capital reserves by drawing down reserves for capital improvements and additions instead of collecting new revenues. The draw down on reserves was accelerated due to decreases in interest income and development fee revenues. Without a series of 3.5% rate increases to cover the capital costs of additions and replacement, reserves will be to below minimum policy levels starting as early as 2013. By Charter, the Light and Power Utility makes a contribution to the General Fund as a payment in lieu of taxes (PILOTs). City Code sets PILOTs at 6% of operating revenues. When the 2011-2012 Budget was developed, the 2012 PILOTs budget was based on the 2012 revenues projected at that time. Since last year, the projected electric operating revenues have increased from $101.8 million to $104.0 million. The increase results in PILOTs increases of $121,969 for 2012. The increased operating revenue is a result of a larger retail rate increase than was projected in the 2011-2012 Budget and a slight increase in projected kWh sales. The 2012 rate increase was originally projected at 6.23%. Staff is now recommending an increase of 8.3%. The additional retail rate increase is due to several factors: an increase in wholesale power costs, a slight increase in kWh sales projections, and a larger than projected increase to fund capital programs. 2012 BUDGET REVISION REQUEST Light and Power Payments in Lieu of Taxes (PILOT) Increase N/A 501 - LIGHT & POWER FUND Safe Community Light & Power Fund 43 44 45 46 Revision Title: Fund: Contact: Ellen Switzer Steve Catanach Result Area: Related Offer #: 11.1 Total Amount: $1,724,505 Funding Source #1: Funding Amount #1: $1,724,505 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Purchase Power Increase N/A Platte River Power Authority has revised its 2012 wholesale rate methodology and rate increase projections since the 2011-2012 Budget was prepared. In addition, actual 2010 kWh sales increased slightly for the first time in several years. While the Utilities is projecting no kWh growth for 2011 or 2012, the 2012 purchases are now projected at actual 2010 levels which are higher than the kWh purchases projected in the original 2011-2012 budget. This exception request is for the additional costs associated with the PRPA rate increases and the increased kWh purchases currently projected. With this exception request, the purchase power budget (exclusive of renewable energy) will total $73,410,587. 501 - LIGHT & POWER FUND Safe Community Light & Power Fund 47 Revision Title: Fund: Contact: Patty Bigner Result Area: Package/Offer #: New Total Amount: $300,000 Funding Source #1: Funding Amount #1: $300,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Energy Efficiency Financing Program 0.5 FTE - Administrative Position This offer funds a pilot program to establish an energy efficiency financing program. Although the program is currently being developed, both legal and financial impacts require additional assessment. Utilities will use a consultant to assist in program design. Once developed, the pilot will enable Utilities to understand the level of community need, determine paramenters for making loans and establish a fund for the first year of the program. Based on potential program demand and the necessity of managing the administration of the program, this offer funds an .5 FTE administrative positon ($32,785). This program has the potential to expand to fund water conservation improvements in the 2013 budget but the pilot program will be limited to energy effeciency. The program would be funded from reserves in 2012; however, a rate increase of 0.35% may be needed in 2013 to replenish the reserves used for the program. 501 - LIGHT & POWER FUND Environmental Health Light and Power Fund 48 Revision Title: Fund: Contact: Rita DeCourcey Result Area: Related Offer #: 100.1 Total Amount: $88,054 Funding Source #1: Funding Amount #1: $88,054 FTE Requested: Description: Please refer to the accompanying memo for additional information. Per the City Charter, the Fort Collins Utility is required to make a contribution to the General Fund as a payment in lieu of taxes (PILOTs). City Code sets PILOTs at 6% of operating revenues. When the 2011-2012 Budget was developed, the 2012 PILOTs budget was based on the 2012 revenues projected at that time. Since last year, the projected water operating revenues have been revised to reflect the need for a 6% rate increase to cover the continued decline in demand and reserve requirements. It is expected that water operating revenues will increase from $25.1 million to $26.7 million with the approved rate increase. As a result, PILOTs will increase $88,054 for 2012. The 2012 rate increase was originally projected at 0%, but with continued declines in demand from weather and conservation, staff is now recommending an increase of 6%. The additional rate increase is due to several factors: 1)decline in water demands due to weather, conservation, and economics; 2)decreases in development and non operating revenues requiring operating revenue to cover a larger portion of total costs; and 3) to fund capital programs beyond 2014. 2012 BUDGET REVISION REQUEST Water Payments in Lieu of Taxes (PILOT) Increase N/A 502 - WATER FUND Environmental Health Water Fund 49 50 51 52 53 Revision Title: Fund: Contact: Jon Haukaas Result Area: Related Offer #: New Total Amount: $580,000 Funding Source #1: Funding Amount #1: $580,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Water Meter Replacement and Rehabilitation N/A The meters used to measure water consumption are being upgraded over time. We are in the process of accelerating that upgrade process so that all meters will be compatible with the Advanced Metering Infrastructure (AMI) technology. Additional funds are required to meet the timeline of this upgrade need. 502 - WATER FUND Environmental Health Water Fund Reserves 54 Revision Title: Fund: Contact: Phil Ladd Result Area: Related Offer #: 214.2 Total Amount: $22,000 Funding Source #1: Funding Amount #1: $22,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Household Hazardous Waste Community Event N/A The requested budget exception is based on the amount of material recycled at the 2011 Household Hazardous Waste (HHW) collection event, which was two times the amount anticipated (based on the 2010 event). In order to accommodate the same level of service, $22,000 needs to be added to the budget for 2012. 504 - STORMWATER FUND Environmental Health Stormwater Fund 55 Revision Title: Fund: Contact: Jon Haukaas Phil Ladd Result Area: Related Offer #: New Total Amount: $1,000,000 Funding Source #1: Funding Amount #1: $1,000,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Remove Structures from Poudre River Floodway N/A This request is to fund a land acquisition under the Stormwater Utility's "Willing Seller-Willing Buyer" program. A property owner has expressed interest in selling their property. A majority of this property is in the Poudre River Floodplain including structures in the floodway. This achieves a major safety goal of the Stormwater and Floodplain Programs. The future use of the property could include non-building gateway features on the Poudre River. 504 - STORMWATER FUND Safe Community Stormwater Fund 56 Revision Title: Fund: Contact: Jon Haukaas Phil Ladd Result Area: Related Offer #: New Total Amount: $1,600,000 Funding Source #1: Funding Amount #1: $1,600,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Master Plan Flood Mitigation Project Property N/A The West Vine Basin Master Plan shows the need for a Flood Mitigation storage area to solve potential flooding issues along this drainage way. The ideal location is at the confluence of three existing drainageways. This vacant land has recently been put up for sale. The majority of the property is already impacted by the floodplain limiting its ability to be developed. Additional funding is available from the fees collected by Larimer County for the West Vine basin. The future use of the property would be a joint venture with Natural Areas similar to what is being done with the CIPO project. This purchase would lay the groundwork for a major project in the Stormwater Utility Master Plan. 504 - STORMWATER FUND Safe Community Stormwater Fund 57 Revision Title: Fund: Contact: Chris Banister Result Area: Related Offer #: 32.1 Total Amount: $108,000 Funding Source #1: Funding Amount #1: $108,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST MIS Email, Blackberry & Smart Phone Services N/A MIS will bring Email and PDA services and support in house by the end of 2011. This move requires ongoing, anti- spam maintenance costs to be absorbed by MIS in 2012. This request covers those costs and incorporating anticipated smart phone costs. 603 - DATA AND COMMUNICATIONS FUND High Performing Government Data and Communications Fund Reserves 58 Revision Title: Fund: Contact: Chris Banister Result Area: Related Offer #: 33.4 Total Amount: $62,400 Funding Source #1: Funding Amount #1: $62,400 FTE Requested: Description: 2012 BUDGET REVISION REQUEST MIS Network Services Resource Support 1.0 Hourly FTE Several major projects, including Smart Grid and Mason Corridor, have stretched MIS Network resources. There is minimal opportunity for existing staff to do required routine operations and maintenance on network infrastructure. This resource support has been funded by salary savings from turnover in 2011. MIS does not expect salary savings in 2012. 603 - DATA AND COMMUNICATIONS FUND High Performing Government Data and Communications Fund Reserves 59 Revision Title: Fund: Contact: Chris Banister Result Area: Related Offer #: 35.6 Total Amount: $59,488 Funding Source #1: Funding Amount #1: $59,488 FTE Requested: Description: 2012 BUDGET REVISION REQUEST MIS Technology Customer Software Compliance Support 1.0 Hourly FTE Staying on top of software compliance for the organization has proven difficult using only a portion of an existing classified tech's time. MIS brought in temporary services in 2011 from Adecco to help mitigate the increased demand using salary savings from turnover. MIS does not expect salary savings in 2012 and would like to ensure it retains the current person through 2012. 603 - DATA AND COMMUNICATIONS FUND High Performing Government Data and Communications Fund Reserves 60 Revision Title: Fund: Contact: Chris Banister Result Area: Related Offer #: 35.6 Total Amount: $30,709 Funding Source #1: Funding Amount #1: $30,709 FTE Requested: Description: 2012 BUDGET REVISION REQUEST MIS Technology Customer Support Restructure N/A MIS Technology Customer Support completed a staffing restructure in 2011. A Programmer Analyst position was eliminated and a Technology Systems Manager was added. This covers the cost differential between positions. 603 - DATA AND COMMUNICATIONS FUND High Performing Government Data and Communication Fund Reserves 61 Revision Title: Fund: Contact: Chris Banister Result Area: Related Offer #: New Total Amount: $550,000 Funding Source #1: Funding Amount #1: $550,000 FTE Requested: Description: 2012 BUDGET REVISION REQUEST Microsoft Office 2010 Software Upgrade N/A 603 - DATA AND COMMUNICATIONS FUND High Performing Government Data and Communications Fund Reserves The ongoing use of an older version of the software suite Microsoft Office 2003 has continued to become more of an issue throughout the organization, as staff has experienced various compatibility challenges with other applications and in everyday document collaboration with external agencies and businesses. The timing of this request is based upon the need for MIS to eliminate these compatibility issues, support the organization with a more current, functional tool set, and to allow for a well planned implementation prior to the scheduled obsolescence of the product. Microsoft Office is a primary tool of daily use for a large number of City staff. An upgrade to this product brings current and effective software tools to a significant percentage of staff, supporting and equipping them with technology to work efficiently. Also, the scheduled e-mail migration will implement Exchange version 2010 this Fall, which will allow for further integrated functionality with the requested migration to the Office 2010 platform next year. While providing appropriate technology to the organization is a value, it is also necessary to note that the Office 2003 suite will move to a non-supported status in early 2014. At that point, the City's technology infrastructure would be in a more vulnerable state, as Microsoft would no longer support the product with ongoing critical security patches. As such, it is recommended that the City be fully transitioned prior to that time to avoid loss of support for such a broadly used application. In order to provide the organization the best opportunity to plan and execute this upgrade prior to the loss of support, it is recommended that we begin this transition in 2012. This would be done to allow for appropriate planning and coordination within the organization, as well as the ability to execute the upgrade over a longer period of time. Lengthening the upgrade timeline effectively spreads out the upgrade effort, avoiding extra costs associated with supplemental resources or consulting services that are often used to execute projects more quickly. It would also allow for a more gradual introduction of the new software to staff, which would lessen the disruption of daily services and ease the learning curve. MIS had originally delayed submitting an offer to accomplish this replacement until 2013 due to funding uncertainty in the 2011-2012 BFO cycle. For the reasons stated above, funding for this upgrade is being requested to be included in the 2012 budget. The funding requested is planned to cover all software licenses, as well as education for staff on the use and functionality available with the new product. 62 1 x year December 31 .01 12 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 kWh block % of bills in block Sample of 270 multi-family low income Multi-family population at the City Council Finance Committee on Sept. 26, 2011. Public notification will begin October 2 and Electric Rate Ordinances will be considered by City Council at first reading Oct. 18, 2011. Second reading is Nov. 1, 2011. Next Steps September 26 - Council Finance Committee related to all utilities rates and fees October 11 - Work session on Residential Energy Rate October 18 - I ‘ reading of Electric Rates (without changes to Residential Energy Rate); also I ‘ reading of ordinances for water and wastewater rates and PIFs/development fees October 25 - Work session on Energy Conservation Programs November 1 - 2’ reading of Rates and Fees Jan. 1, 2012 - all rates effective except for Residential Energy Rate Late 2011 or early 2012 - I SI reading of ordinance changing Residential Energy Rate to be effective shortly thereafter. 3 Number of Customers 29,993 42,169 26,392 9,253 7,293 10,533 6,936 6,301 3,549 2,454 3,469 ‐ 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 200,000 ‐10% 0% 10% 20% 30% 40% 50% 60% 70% 80% Annual Number of Bills Percentage Change from Current Bill Monthly Energy Per Bill (kWh) Non Summer Rates Number of Bills Current Rate Single Tier Seasonal Rate Three‐Tier Rate Five‐Tier Rate Monthly Energy Per Bill (kWh) Number of Bills Current Rate Summer % Change Non Summer % Change Annual % Change - 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 2000 2100 2200 2300 2400 2500 2600 2700 2800 2900 3000 kWh block % of bills in block Sample of 270 multi-family low income Multi-family population Energy Usage Characteristics of Low Income Multi‐family Households vs. Overall System 6 - 12 Mo Performing backup generator tests and running during peak hours . Requires existing diesel backup generators 6 - 12 Mo Performing backup generator tests and running during peak hours. Overhead double-circuit tubular steel poles (230-kV Platte River and Western 115-kV). Medium – construction roads required along the northern portion. Southern portion utilize helicopter construction. Medium – Impact for recreational users of Natural Area; line blends with Pineridge background for distant viewers. $10.2M Orange 4.2 miles Utilize existing 75-ft Western R/W from Horsetooth Tap to Spring Canyon Dam, then north along S Centennial Dr, east near Dixon Canyon Rd, across Dixon Reservoir to Dixon Creek Substation. Overhead double-circuit tubular steel poles (230-kV Platte River and Western 115-kV). Low – construction in existing Western R/W and public R/W. Medium – Adds very tall structures in area with overhead distribution lines. $10.4M Drake Rd. Overhead single-circuit 230-kV tubular steel poles. Low – construction in developed public R/W. High – adds very tall structures in area where electric utilities are underground. $16.0M Green 2 (Partial UG) 5.1 miles (3.1 UG) North in public road R/W along S Taft Hill Rd, then west along W Drake Rd. Overhead single-circuit 230-kV tubular steel poles north to W Harmony Rd, then underground to Dixon Creek Substation. Low – construction in developed public R/W. Low – overhead only in area with existing overhead distribution. $26.6M Green 3 5.1 miles North in public road R/W along S Taft Hill Rd, then west along W Drake Rd. Underground single-circuit 230- kV ductbank. Low – construction in developed public R/W. Low – no visible facilities. $33.3M North in public road R/W along S Taft Hill Rd, then west along W Drake Rd. Overhead single-circuit 230-kV tubular steel poles north to W Harmony Rd, then underground to Dixon Creek Substation. Low – construction in developed public R/W. Low – overhead only in area with existing overhead distribution. $26.6M Magenta 4.1 miles Utilize existing 75-ft Western R/W from Horsetooth Tap to Spring Canyon Dam as proposed, then north along the base of the ridge through Pineridge Natural Area to near Dixon Canyon Rd, east across Dixon Reservoir to Dixon Creek Substation. Overhead double-circuit tubular steel poles (230-kV Platte River and Western 115-kV). Medium – construction roads required along the northern portion. Southern portion utilize helicopter construction. Medium – Impact for recreational users of Natural Area; line blends with Pineridge background for distant viewers. $10.2M