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Home My WebLink AboutCOUNCIL - AGENDA ITEM - 01/10/2017 - ELECTRIC CAPACITY FEESDATE: STAFF: January 10, 2017 Lance Smith, Utilities Strategic Finance Director WORK SESSION ITEM City Council SUBJECT FOR DISCUSSION Electric Capacity Fees. EXECUTIVE SUMMARY The purpose of this work session is to provide the Council with an overview of the current Electric Capacity Fee (ECF) and review proposed changes to the current approach. The current method utilizes a planning model that is based on greenfield development. As the City experiences more redevelopment this method fails to appropriately assign capital costs to this new load. Staff proposes a change in the cost allocation methodology that uses actual system value to assign costs to new loads. This change would make the ECF methodology consistent with the water and wastewater utilities and more accurately reflect the cost of redevelopment in the community. Scott Burnham of NewGen Strategies and Solutions will give the presentation. GENERAL DIRECTION SOUGHT AND SPECIFIC QUESTIONS TO BE ANSWERED 1. Does Council support bringing the change in the cost allocation methodology for the Electric Capacity Fees (ECF) forward for consideration? BACKGROUND / DISCUSSION The ECF is a one-time charge that is designed to recover the initial cost of adding new development to the electric system. The operations and maintenance costs are recovered through monthly charges and not through the ECF. In addition to the ECF there is a Building Site Charge (BSC) which recovers costs associated with building on site electric facilities. The BSC is based on actual time and materials at the specific development. Together these two charges represent the total electric plant investment fee (PIF) for new development. The ECF only recovers costs for the distribution system and not any costs associated with adding new demand to the generation or transmission systems. Platte River Power Authority does not charge any plant investment fee for its system and instead, collects the associated costs through monthly energy and demand charges. The decision tree below outlines the policy path that brought about the current state of the Electric Capacity Fees (ECF). The decision process starts in the upper left corner and ends at the upper right corner. Staff has been working under the assumption that the current state of allocating 100% ECF charges by demand is still preferred by Council as outlined in Section 26-473 of the Municipal Code and as such, staff has been focused on improving this allocation process. January 10, 2017 Page 2 In 2016 Fort Collins Utilities hired NewGen Strategies to survey how ECFs are collected by other electric utilities and to provide assistance building a revised ECF model to allocate capital costs to new load on the system. This effort was led by Scott Burnham. Mr. Burnham’s expertise includes financial feasibility, cost of service and rate design analysis, asset valuation, and restructuring for electric utilities. He leads and manages rate studies, acquisition, privatization, and competitive assessment engagements for NewGen’s clients. Current Model The current ECF is calculated by utilizing a system planning model that was originally developed in the early 1980s and has been updated several times to reflect inflation and changes in system design standards and policy. This underlying model assumes a certain system design and allocates the costs of this system design based on the square footage, the linear footage that abuts the public right- of-way, and demand (kilowatt or kW) of the new development. These components of the current ECF calculations for residential and commercial/industrial customers are explained as follows: Residential 1. Square footage charge. This applies to the total area of a development, excluding dedicated streets and City-owned park land. This charge pays for base (minimum) main feeder lines and local distribution circuits to general load areas. This includes related electrical equipment such as fuses and switches. The model for this is based on a main feeder circuit encompassing a 4 square-mile area. 2. Front Footage Charge. This fee applies to all footage of property adjacent to dedicated City streets within a development, regardless of which side the primary line etc., is on, including that which is adjacent to open space and detention ponds. This pays for installation of primary lines, vaults, installation of distribution transformers (not the transformer itself), and switchgear on adjacent dedicated streets. Also included in this fee is a charge to pay for installation of streetlights along City streets. 3. Dwelling unit charge. This fee is based on the anticipated electric load (kW) of each dwelling unit. This pays for the proportional share of augmented main feeder lines required over the base main feeder system, and a proportional share of the substation and distribution transformers. Commercial/Industrial 1. Square Footage charge. Same as residential above. 2. Front Footage charge. This fee applies to all footage of property adjacent to dedicated City streets within a development, regardless of which side the primary line etc., is on, including that which is adjacent to open space and detention ponds. This pays for the installation of primary lines and vaults on adjacent dedicated streets. Also included in this fee is a charge to pay for installation of streetlights along City streets. The commercial/industrial front footage charges are higher than residential due to more 3 phase lines, switchgear etc., and a higher lighting level is required for commercial. January 10, 2017 Page 3 3. Capacity. This charge is based on total amps of service capacity (NOT fuse size), and pays for: a. Augmented main feeder lines required over the base main feeder system (see Square Footage above). b. The distribution transformer(s) and the development’s proportionate share of the substation transformer. The current method has several challenges. The costs for these components (square footage, front footage, and dwelling units/capacity) are calculated through the use of visual basic code (VBA) to access databases that contain assembly information and cost data. As a result, it is cumbersome to update these calculations if changes need to be made to the underlying planning model. For example, it is difficult to modify the calculations so that the model includes mixed use developments or higher density developments. Additionally, the planning model has difficulty assigning costs for capital work required for redevelopment, such as adding a circuit for additional load. As the City has evolved since the 1980s and development has been more often redevelopment, it is appropriate that the ECF model evolves as well. The proposed model addresses these challenges and simplifies the charge calculation. Proposed Model As a result of the trend toward higher density developments and redevelopments, and the dynamic nature of the electric system in general, staff recommends changing the methodology of the ECF model to address the concerns raised above. The proposed methodology is based on the “buy-in” method for plant investment fees outlined by the American Water Works Association (AWWA) and is conceptually similar with the Plan Investment Fees (PIF) models for the water and wastewater utilities. This method takes the value of the utilized electric system, i.e., the amount of the system that is needed to serve the current load and no more, and divides this dollar value by the current kilowatt (kW) demand. This calculation results in the $/kW rate that was used to build the current system to meet the current demand. New load on the system would buy into the electric system at this $/kW rate. Where excess capacity exists within the current system, new development is buying into that excess capacity and the ratepayers recover some of their system investment. This simplifies the calculation and administration of the ECFs. In addition to these simplifications, the proposed methodology also uses actual data to allocate costs instead of a planning model. Demands, non-coincident peaks (NCP), for the residential and commercial/industrial customer classes are calculated from Advanced Metering Infrastructure (AMI) data and are used to allocate the system costs proportionally to each class based on the class NCP. This allocation method provides a different $/kW buy in rate for each of these classes and is consistent with standard cost allocation practices in utility rate making. Due to the large variation in demands from the commercial class a sliding scale was implemented for the $/kW rate for commercial customers, as the load from a commercial customer increases the buy-in rate increases as well to allocate the additional system costs required to serve large loads. Lastly, this proposed method is flexible and adapts to changes in development by using actual system values and actual demands as opposed to the current method. Comparison of the Model Results As with any change in methodology, it is necessary to compare the charges under the new model with those under the previous model. This is challenging because the cost of adding a new development to the system depends on the nature of the development. The table below compares the existing ECF to the proposed ECF for several different sizes of development. Most of the comparisons show a decrease in the ECF but it is project specific so a higher charge is possible. The Building Site Charge (BSC) will also be updated for inflation and this adjustment may offset some of the savings seen in the table below. January 10, 2017 Page 4 Customer Type Example Load kW Existing ECF ($) Proposed ECF ($) Difference ($) Percent Change Residential 34 single family 150 Amp units 9 $86,310 $52,273 -$34,037 -39% Multi-Family 195 Units 200 units 7.9 $544,988 $269,907 -$275,081 -50% Multi-Family 320 Units 325 units 7.9 $432,151 $438,599 $6,448 1% Large Commercial Building 600 Amp, 480Volt, 3 phase, 40,000 sq. ft., 175 linear ft. 185 $43,830 $79,421 $35,591 81% Commercial - Three Phase Office 200 Amp, 208Volt, 3 phase, 40,000 sq. ft., 175 linear ft. 27 $13,824 $10,388 -$3.436 -25% Commercial - Single Phase Office 200 Amp, 240 Volt, 1 phase, 40,000 sq. ft., 175 linear ft. 18 $12,133 $6,769 -$5,364 -44% Conclusion Staff recommends changing the ECFs as proposed and seeks guidance on bringing the proposed changes forward. ATTACHMENTS 1. NewGen Strategies Memo Re: Revised PIF Model and Review (PDF) 2. Powerpoint presentation (PDF) Memorandum Economics | Strategy | Stakeholders | Sustainability www.newgenstrategies.net 225 Union Boulevard Suite 305 Lakewood, CO 80228 Phone: (720) 633-9514 To: Justin Fields and Randy Reuscher From: Scott Burnham Date: December 29, 2016 Re: Revised PIF Model and Review The City of Fort Collins (the City), and Fort Collins Utilities (referred to herein as the Utility or Utilities) retained NewGen Strategies and Solutions, LLC (NewGen) to assist with the review, development, and implementation of a revised electric Plant Investment Fee (PIF) model. The existing PIF model collects funds from developers for the costs associated with the necessary improvements to serve new electric load. The existing model and process to determine the PIF is cumbersome to update and is based on a historic approach that does not necessarily reflect changes that have occurred within the City in recent years. NewGen and Utilities have developed an updated PIF model that addresses these issues. The purpose of this memorandum is to provide a detailed description of the issues facing Utilities with respect to recovering its system investments and the methodology proposed for the revised PIF model. Background Like most utilities in the country, the Utility currently charges fees to developers to extend or expand existing electric service to new customers and/or new load. The Utility charges developers for the materials and the associated installation labor costs required to provide electricity to the new load. Some of the materials required are considered “on-site” (this is equipment unique to the customer, such as service drops to the customer’s premise). “Off-site” equipment is that which is located further from the customer premise and includes items such as switch gear, conductor, and other distribution system equipment. The Utility currently bills the customer directly for the costs of the on-site equipment and labor. The off-site equipment and labor form the basis for the existing PIF charge. Fees similar to the PIF are common in the water and wastewater utility industry. Given the large fixed costs associated with the installation of conveyance structures and associated pumping stations, these costs have been quantified and charged to new development by most water and wastewater utilities in the country. In fact, the Utility has existing water and wastewater PIF charges that are based on the value of the investments it has made to provide these services. Such fees have historically been less common for electric utilities, as costs of expanding and maintaining the electric system have typically been recovered through the sale of electricity to the end users (via an energy or $/kilowatt hour (kWh) charge.) This approach results in all customers paying for the costs of new development. However, many electric utilities do have some type of investment fee recovery mechanism, which may be referred to as a line extension policy, electric service connection fees, customer / electrical connection charge, electrical connection fee, account initiation charge, system development charge, or impact fee. By charging the developer an upfront fee, the utility is able to ensure that new development is paying all, or at least a portion, of the costs of being added to the system. ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 2 NewGen PIF Model Memo_12292016 Existing Model / Load Growth The existing Utility electric PIF model was designed for a period of infrastructure growth primarily driven by “greenfield” or newly developed areas. As the City has grown, the potential locations for greenfield development have decreased and more development is occurring in areas of existing infrastructure (such as buildings, roads, City-services, etc.). These “brownfield” or “redevelopment” areas may or may not require updated or additional electric infrastructure on behalf of the Utility to serve the new load. When a redevelopment requires no additional infrastructure to be served, there is no PIF charge. This change in development patterns within the City has resulted in increased density, including multi-story commercial / residential developments, as well as other high-load applications. The result is that the existing electric system as a whole requires a variety of investment in capital improvements to maintain reliability and serve the increased load. However, the existing PIF methodology does not adequately recover the Utility’s costs or reflect the value associated with these system-wide capital improvements. Because of the method in which the existing PIF is calculated, the result is that the PIF charge is not consistent with the City’s stated policy objective of having “growth pay for growth”. Proposed Model NewGen and the Utility have jointly developed a proposed PIF model designed to recover system costs associated with the existing system. The proposed model is consistent with the Utility’s approach for its water and wastewater impact fees, and is based, in part, on guidance provided by the American Water Works Association (AWWA). The proposed PIF model utilizes a system value approach that recognizes the use of the system by existing customers as the basis for the PIF for new load. This approach suggests that the costs associated with load growth for future customers is similar to the average, or embedded, costs of the system. New customers are “buying-in” to the existing system via the PIF charge. The model determines a PIF based on a $/kilowatt ($/kW) charge for residential and combined “general service” applications (the Utility’s three general service customer classes will have the same $/kW PIF charges). The system value was determined by the Utility utilizing a replacement cost approach. This system value was reduced by the outstanding debt, which is included in the retail rates and is intended to recover a certain portion of the fixed costs of the system. As the Utility invests in the system via its Capital Improvement Plan (CIP), as well as other non-capital (equipment that is expensed) programs, the system value will be updated on an annual basis. The load (kW) is the existing peak load (or demand) of the respective class (residential or combined general service). Additional detail on the methodology utilized to develop the proposed PIF is provided in the attached Appendix A-1. The system value and class loads are then used to arrive at a $/kW charge for each customer class. ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 3 NewGen PIF Model Memo_12292016 Study Results The results of the proposed model PIF charges compared to the existing PIF charges by example loads for each customer class is provided is provided in Table 1 below: Table 1 Example PIF Charges Customer Class Group Example Load Existing PIF Proposed PIF Difference Residential 150 amp, 6,000 sq. ft., 60 linear ft., 9 kW $2,342 $1,537 ($805) General Service 600 amp, 480 v, 3 phase, 40,000 sq. ft., 175 linear ft., 166 kW $43,800 $79,421 $35,591 *Note: Rounded The differences in the existing and proposed PIF charges reflect the differences between the investment costs to be collected. The proposed approach is based on allocating the utilized capacity within the existing system on a $/kW basis by class to future load. The existing PIF model is based on an outdated concept relative to costs for infrastructure required to serve four square miles based on a planning model (which is why the example load in Table 1 includes the square feet and linear feet of the new development). The existing PIF methodology does not recognize the changes in development, such as increased density, mixed use projects, and changes in customer demands, or the changes in capital required to serve these projects. The proposed PIF methodology recognizes these changes and is based on a methodology whereby “growth pays for growth.” This approach is consistent with industry best practices in the water / wastewater utilities and is becoming increasingly adopted in the electric utility industry (see Appendix A-2 for a review of other electric utility approaches to similar fees, and Appendix A-3 for details on the Utility’s existing PIF structure). Summary The existing PIF model and charges have served the City and Utilities well during a period of expanding its services and greenfield growth. However, in recent years the growth in the City has turned inward, resulting in redevelopment and higher load density projects and applications. The result is that the Utility’s PIF model needs to be updated to reflect these realities and to recover infrastructure costs associated with the entire system, not just the costs defined by the City over 20 years ago. This proposed change in the PIF model methodology will serve the City by collecting the portion of historic costs invested to build the excess capacity of the existing system. Further, the proposed changes will allow the City to better align its PIF methodology with its policy objectives of having growth pay for growth. Appendix A-1 The City imposes an impact fee on developer’s requesting water and wastewater utility services. The structure for these fees has been in place since approximately 2006. These impact fees are designed to recover costs associated with the capacity of their entire utility system, as well as selected improvements ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 4 NewGen PIF Model Memo_12292016 associated with their capital improvement plans. This approach follows the guidance provided by AWWA, as described in detail below. Utilities indicated that the existing water/wastewater impact fee structure is preferred to the existing electric impact fee structure as it is easier to update, does not require detailed modeling results from other Utilities departments, and is defensible. AWWA Approach As indicated above, the Utility’s water/wastewater fees follow the guidance provided in the AWWA M1 manual. The M1 manual is recognized as the industry best practices and provides details on the modeling methodologies. The M1 manual describes several mechanisms for the development of System Development Charges (SDC) for one-time charges paid by a new water system customer for system capacity. The following is a summary of the AWWA approaches, as well as how they may apply to the Utility’s electric PIF development. The calculation of the SDC is, in very basic terms, the total value of each utility function divided by the appropriate units (in the AWWA manual, the units are typically gallons) to develop a per unit charge. The AWWA methods include the Buy-In Method, the Incremental Cost Method, and the Combined Cost Approach. The Buy-In Method is typically used where there is sufficient capacity in the existing system to meet both near-term and long-term needs. Utilizing this approach allows a developer to “buy” a proportional share of capacity at the value of the existing facilities. This approach is based on the principle of achieving capital equity between existing and new customers. The value of the existing system can either be at a depreciated original cost or a replacement cost. Using replacement costs reflects the cost of providing new expansion capacity to customers as if the capacity was added at the time the new customer connected to the system. Proposed PIF Approach for Fort Collins Working with Utility staff, NewGen has developed a revised approach to the electric PIF model. Looking ahead toward build-out of the City, the Utility expects to see more growth in areas of redevelopment as the City’s “greenfield” areas disappear. Additionally, the Utility believes that the capacity of the existing systems (with some CIP and other non-capital investments) can meet the load of these redevelopment areas. Thus a Buy-In approach was developed for the Utility’s new PIF model. This approach has been incorporated into a revised electric PIF fee model, iterations of which have been provided to Utilities for review. The following provides a summary of the methodology employed to develop and the mechanisms used within the revised PIF model. Existing System Valuation – the model relies on an estimate of the valuation of the existing electric system, based on input from Utilities. This valuation represents a replacement cost approach, which was provided by Utilities and was not independently validated. As Utilities implements its Asset Management System, it will be important to update the Existing System Valuation in the revised PIF model accordingly. Credit for Outstanding Debt Principal – the model includes a line item for the outstanding debt principal associated with financing for the existing system value. This line serves as a credit to the total system value for PIF. This line item follows the guidance provided by the AWWA M1 manual and ensures that the debt issued for the existing system is recovered fully from retail rates (and not the PIF). ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 5 NewGen PIF Model Memo_12292016 System Usage Data – the model utilizes the Non-Coincident Peak (NCP) of the system (and customer classes) by which the total system investment is divided. The NCP is the sum of each customer class’ NCP, which represents the peak demand (in kW) for that class whenever it occurs. System / Customer Class – the revised PIF develops a unit fee ($/kW) based on the entire system as determined by customer classes (residential and commercial). Appendix A-2 NewGen has developed a detailed comparison of how other utilities recover fixed costs through PIF charges and/or other comparable mechanisms. For this comparison we have reviewed the practices of the other Platte River Power Authority (PRPA) members (Loveland, Longmont, and Estes Park). Additionally, we have reviewed the practices of selected municipal, investor-owned and cooperative utilities in Colorado and other states. Platte River Power Authority Members The three other PRPA members vary in their approach to comparable PIF charges. Both Loveland and Longmont have fee structures in place; however, Estes Park does not. The Longmont fee structure is based on the amperage rating of the customer’s panel, as well as type of service (Residential, Commercial) to determine the Electric Community Investment fee. Proceeds from this fee are dedicated to growth related electric utility capital improvement projects. The Longmont fee ranges from $310 to $1,858 for residential applications and $619 to $128,546 for commercial applications. The City of Loveland has a Plant Investment Fee that varies by customer class. Their PIF provides for the “additional electric transmission, substation and distribution facilities made necessary by the extension of electric service to new connections”. For residential applications, the fee is $1,450 for service size of 150 amps or less and $1,860 for service size of greater than 150 amps. For commercial applications, the Loveland PIF varies by each class, but is based on the energy utilized on a monthly basis (monthly bill) and ranges from $0.00587 to $0.00570 per kWh. Rather than collecting all of the costs of new development upfront, Loveland collects it through monthly charges. For a commercial (general service) customer with a peak demand of 166 kW and usage of 60,000 kWh/month, the fee would be approximately $4,200/year. The City of Loveland has recently proposed a new rate schedule, which includes an increase to its PIF by approximately 4%. Other Industry Approaches NewGen conducted a review of selected utility development charges for this assignment. There does not appear to be an “industry standard” for service fees for development. However, most utilities have some type of line extension policy that provides customers with a detailed assessment of the costs to be incurred for additional service. Some of the utilities provide a credit either in the form of a Construction Allowance or a revenue credit over a certain period of time, based on future sales. Additionally, most utilities offer some form of rebate to original applicants who install facilities that are subsequently utilized by new customers (within a specific period of time). ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 6 NewGen PIF Model Memo_12292016 This review included an assessment of these types of charges within the State of Colorado (for municipal, cooperative, and investor owned electric utilities), as well as selected utilities in Utah and California. Table A-2 provides a summary of the findings from our review: Table A-2 Summary of Findings Name Utility Type Fee Type PIF Year Refund Period Comments United Power (Coop) Co-op $/Extension by Class $/amp, per phase 2004 5-year Overhead standard Public Service Company of Colorado (Xcel Energy) IOU $/Customer or $/kW N/A 2014 10-year Construction Allowance; Fee’s based on COS; Overhead standard. Colorado Springs Municipal Revenue Guarantee N/A 2016 5-Year Overhead standard. Fees for Underground in tariff by length, type, customer Poudre Valley REA (Coop) Co-op $/kVA System Capacity 2016 5-Year Contribution In Aid required; fee for larger service Provo City Municipal $/kVa Impact Fee 2008 N/A Fee by Amp (Service Size) and service phase / voltage Individual Results United Power (Cooperative) United Power (United) is a cooperative that is served wholesale power by Tri-State Generation and Transmission (Tri-State). United has several fees for Residential and Non-Residential (Commercial and Industrial) customer types that are based on its costs for designing line extensions for future service. In addition to the design fees, United charges a “Subdivision Line Extension” fee based on per extension plus a per lot charge. United also charges a Plant Investment Fee that is $150 per 100 amps, which is intended to recover current or future increases in United’s transmission or distribution system plan investment necessitated by Line Extensions and/or new loads. United does not include any cost sharing for joint trenching, whereby an underground trench designed for an electric line or facility may be shared with another utility (communications, water, wastewater, etc.). However, United does include a provision in its policy that allows for a proportional refund to original applicants if future applicants connect to an existing line extension within a five-year period. Xcel Energy (IOU) Public Service Company of Colorado (aka Xcel Energy), an investor-owned utility (IOU), provides a construction allowance to customers requiring a line extension that is based in part on the allocated costs per customer for various components derived from its most recent cost of service (COS) filing with the Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 7 NewGen PIF Model Memo_12292016 applicants can obtain a partial refund for new applicants utilizing the line extensions paid by the original applicants. Xcel defines two types of line extension: A Service Lateral portion and a Distribution portion. The Service Lateral is for facilities installed by Xcel between its distribution line and the point of delivery for the customer, which provides service exclusively for the individual customer’s use. The Service Lateral investment charge is similar to the “on-site” Building Site Fee charged by Utilities (See Appendix A-3), subject to the construction allowance. The construction allowance is derived from the gross, embedded, lateral plant investment per customer, as indicated in the Company’s most recent rate filing. Distribution line extension facilities include primary and secondary distribution lines, transformer costs, and all appurtenant facilities, excepting service laterals necessary to supply service to the applicant. The construction allowance is derived from the gross, embedded distribution plant investment per customer (or per kilowatt demand, for demand customers). Xcel identifies some extensions as “uneconomic”, to which a construction allowance is not applicable, and applicants are required to pay all construction costs. Uneconomic extensions are those greater than 0.5 miles from existing facilities or those for which a construction allowance would be less than 8% of the total construction costs. Xcel provides tariff pricing for its construction allowance that differentiates by Service Lateral and Distribution portion by class type: Residential, Commercial and Industrial, and Lighting. Such pricing is then differentiated by rate schedules within retail classes. The Service Lateral portion is a fixed allowance and the Distribution portion is based on future load ($/kW, depending on rate schedule). Colorado Springs Colorado Springs Utilities (CSU), a municipally-owned utility, defines their line extension policy in terms of utility and customer provisions and service limitations as applied to primary and main distribution lines. CSU installs, owns, and maintains the equipment for line extensions, based on an overhead service drop (service line) to a customer’s premises. No PIF is charged upfront, instead the associated costs are socialized across the rate class through on-going monthly charges. Customers are required to pay in the form of a contribution in aid-of-construction if they wish to underground these facilities, which varies by linear foot depending on length and type of line and customer class (single phase primary, three-phase main line for residential and non-residential) per CSU’s tariff schedule. Customers pay a design fee to CSU for the proposed facilities, as well as for inspection and connection services. CSU requires a revenue guarantee or deposit for three-phase main line extensions greater than 0.5 miles long. If the revenues anticipated in each year, over a five-year period, are less than 30% of the total cost, CSU may bill the customer for the revenue shortfall. CSU uses the five-year period to determine if additional customers to an existing extension would result in a reduction in deposits to existing customers. If additional customers result in a greater deposit, it will result in a separate new extension. Poudre Valley REA (Cooperative) Poudre Valley REA (PVREA) is a cooperative served by Tri-State in areas adjacent to the City of Fort Collins. PVREA has a line extension policy that provides for service to new customers in its service territory. Costs are paid by the applicant based on the costs of constructing, installing, or upgrading the line extension ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 8 NewGen PIF Model Memo_12292016 and facilities necessary to serve the new load. The costs paid are considered “Contribution-in-Aid-of- Construction” (CAIC), and including all costs to PVREA and its power supplier (Tri-State). The CAIC does not include additional capacity, size or strength in excess of what is actually necessary to meet the requirements of the applicant. However, if the applicant’s requested level of service exceeds 50 kVA (1 phase), 100 kVA (2 phase), or 150 kVA (3 phase), PVREA imposes an additional charge of $5.00 / kVA. Additionally, PVREA may impose a fixed charge per month per customer for new service in sparsely populated areas. Residential customers are eligible for rebates for a period of five years depending on the number of additional customers utilizing the previous investments made. Provo City (Municipal) Provo City, Utah, is a municipal electric provider that charges an impact fee in a fashion similar to the PIF fee Utility employs for its water utility. Provo’s impact fee is based on the current value of selected assets (transmission and substation facilities), as well as the projected value of the improvements (from their capital plan) for these assets. Provo does not provide a credit for past contributions and the value is not adjusted for existing debt (as its debt is related to generation and non-impact fee facilities). Provo determines the average fee on a dollar per kW (estimated demand) and then applies a diversity factor and a utilization factor. The diversity factor applied reflects the ratio of the systems actual peak demand to the sum of the individual customer peak demands. The utilization factor is applied to the customer’s panel size (where they take service) as it relates to actual usage (rated capacity of the customer’s panel compared to demand utilized by the customer). Both the diversity factor and the utilization factor serve to reduce the value of the impact fee. Provo publishes its fee schedule as a range by service (voltage and phase) and the requested rating of a customers’ panel (in amperage). California Utilities The big three investor owned utilities in California (Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric) all have similar line extension policies. The applicant is typically responsible for excavation, substructures and conduits and protective structures, or the utility may charge the applicant for such work. The utility will furnish and install cables, switches, transformers, and other distribution facilities. The utilities will complete a line extension without charge, provided the total cost is not greater than the construction allowance. The allowance is based on the ratio of the net revenues from the customer to a cost of service factor, which is defined in their rate filings. The current allowance for residential line extensions ranges from approximately $2,400 to $3,400, depending on the utility. Municipal utilities in California vary in their approach to line extension fees. Most municipal utilities have some cost sharing between the applicant and the utility, either through a construction allowance (Los Angeles Department of Water and Power), a flat fee for certain types and lengths of distribution equipment investment (Glendale Water and Power), or charges for specific construction related costs, such as trenching, conduits or backfilling (Sacramento Municipal Utility District). Appendix A-3 - Existing PIF and Related Charges for Fort Collins The Utility charges fees to developers of electric load that reflect the actual costs associated with development. There are currently two types of fees specific for residential and commercial electric customers. These fees are referred to as an Electric Capacity Fee and a Building Site Charge. ATTACHMENT 1 Memorandum Justin Fields and Randy Reuscher December 29, 2016 Page 9 NewGen PIF Model Memo_12292016 The Electric Capacity Fee for Residential applications includes a Square Footage Charge, a Front Footage Charge, a Dwelling Unit Charge and a Primary Service Charge (typically, Residential customers do not apply for primary service, so this charge is not always applicable). These charges all recover costs associated with new service as well as a proportional share of existing investments associated with the new load. The commercial application of the Electric Capacity Fee has a similar Square Footage Charge, Front Footage Charge, and a Capacity charge (based on transformer costs). The residential Building Site Charge is based on an “average” length of service from the transformer to the electric meter. The commercial Building Site Charge includes a Primary Service Charge, and a Transformer installation charge (in a commercial application, the customer is responsible for installing secondary service equipment). These are referred to as “on-site charges” and are not considered part of the PIF. Only the Square Footage Charge, the Front Footage Charge and the Capacity Charge (for commercial customers) are considered in the Utility’s calculation of its PIF. Collectively, these “off-site” charges are referred to as Electric Capacity Fees. The “on-site” charges (collectively the Building Site Charges) are unique to each property and include specific equipment requested in the application, and as such are not included in the commercial PIF. For ease of understanding, Table A-3 provides a summary of the applicable charges and fees for the Utilities. The Electric Capacity Fees are considered in the calculation of the PIF fee, as indicated in bold below. Table A-3 Fort Collins Light and Power Development Charges Customer Type Fee Type Fee Residential Electric Capacity Fee Square Footage Charge Electric Capacity Fee Front Footage Charge Electric Capacity Fee Dwelling Unit Charge Building Site Charge Primary Service Charge* Building Site Charge Secondary Service Charge Commercial Electric Capacity Fee Square Footage Charge Electric Capacity Fee Front Footage Charge Electric Capacity Fee Capacity Building Site Charge Primary Service Charge Building Site Charge Transformer Note: Additional charges may apply for unusual circumstances, as determined by Utilities. Only the Electric Capacity Fees are included in the Utilities Plant Investment Fee. * Primary Service Charge is typically not applicable to Residential (see text). ATTACHMENT 1 January 10, 2017 PROPOSED ELECTRIC CAPACITY FEE MODEL REVISIONS Fort Collins Utilities – City Council 1 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Agenda • What is a Electric Capacity Fee (ECF)? • Existing ECF structure – Platte River four City comparison – Other utilities • Proposed ECF changes – American Water Works Association (AWWA) Manual • Impacts to development community • Recommendations 2 RR1 ATTACHMENT 2 Slide 2 RR1 PRPA (Platte River) 4-City comparison Randy Reuscher, 12/20/2016 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Electric Capacity Fee (ECF)? • What is a ECF? – One time charge that recovers costs of off-site assets needed to provide service • Only for distribution system • Platte River Power Authority (PRPA) recovers costs through wholesale rates • On-site assets unique to each project are billed separately • Is not monthly charges, which recover operations and maintenance – Electric capacity fee, development fee, impact fee – Common in water / wastewater industry – Some type of fee typical for electric utilities 3 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Electric Capacity Fee (ECF)? • Why does Fort Collins have a ECF? – “Greenfield” development necessitated this in the past – Supports “Growth pays for Growth” • Chapter 26 section 473(b) of Code – Able to assign specific costs to serve new load 4 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Electric Capacity Fee (ECF) • Why are we changing the ECF? – Fort Collins ECF based on older growth assumptions – Model is complex, challenging to update – Cumbersome to administer – Need to reflect new realities of the system and development in the community 5 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Existing ECF Structure • Residential Fee Structure – Square Foot Charge ($/sq. ft.) – Front Foot Charge (Linear - $/ft.) – Dwelling Unit Charge ($/dwelling) • Commercial Fee Structure – Square Foot Charge ($/sq. ft.) – Front Foot Charge ($/ft.) – Capacity Fee (estimated usage $/kW) 6 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Existing ECF Structure 7 $- $1,000,000 $2,000,000 $3,000,000 $4,000,000 $5,000,000 $6,000,000 2008 2009 2010 2011 2012 2013 2014 2015 2016 Off Site Electric Development Fee Revenue Off Site Electric Development Fees ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Existing ECF Structure • Existing fee – Assumes “greenfield” development – Based on outdated planning model • New development / re-development – Occurs in areas of “re-development” – City close to “build-out” – Recognizes capacity paid through previous ECF for re-development 8 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Existing ECF Structure – Other Utilities • PRPA utilities – Longmont – Loveland – Estes Park • Colorado Utilities – Colorado Springs – Xcel Energy (IOU) – United Power (Coop) – Poudre Valley REA (PVREA) • Provo, Utah – Similar to proposed “system value” fee 9 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Proposed ECF • “Buy-In Method” • Results in similar charges by other PRPA members • Methodology for electric utilities – Similar to approach by Provo, UT • Equivalent to existing capacity “value” – $/kW basis – Different for Residential / Commercial 10 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Current vs Proposed ECF Structure 11 • Proposed Method – Simplifies Calculation – Relatively easy to explain compared to the current method – Simplifies administration of the charge Class Method Formula Residential Current ECF = [($/ft 2 ) x ft 2 ] + [($/LF) x LF] + [($/du) x #du] Proposed ECF = [$/kW]res x kW Commercial Current ECF = [($/ft 2 ) x ft 2 ] + [($/LF) x LF] + [($/kW) x kW] Proposed ECF = [$/kW]com x kW ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Proposed ECF + System replacement cost (investment) - Adjusted for portion “utilized” - Adjusted for debt service (recovered in rates) = System Value for ECF • Allocated by demand to residential and commercial customers • ECF Rate ($/kW) based on total demand by class – Residential ECF fee by anticipated demand (kW) – Commercial ECF by amperage and voltage 12 System Value $ 181,103,000 (1) ECF Rate ($/kW) Residential Share $88,255,000 $170.83 Commercial Share $92,848,000 $427.64 (2) (1) System Value subject to further review (2) Average rate, see sliding scale ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Proposed ECF • Multifamily will be charged the residential $/kW ECF fee – Distinctions will be made within the residential class • Single family • Multifamily • Electric heat • Panel size 13 Residential Unit Type Peak Demand (kW) Per Unit ECF Charge ($) Single Family 150 amp or less 9.0 $1,537 Single Family 200 amp 11.0 $1,879 Single Family Electric Heat 14.7 $2,511 Multi Family 7.9 $1,349 Multi Family Electric Heat 12.1 $2,067 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Impacts to Electric Development Charges Example ECF Charges (1) 14 (1) Note: Rounded and does not include Building Site Charges Customer Type Example Load kW Existing ECF ($) Proposed ECF ($) Difference ($) Percent Change Residential 34 single family 150 Amp units 9 $86,310 $52,273 -$34,037 -39% Multi-Family 200 Units 200 units 7.9 $544,988 $269,907 -$275,081 -50% Multi-Family 325 Units 325 units 7.9 $432,151 $438,599 $6,448 1% Large Commercial Building 600 Amp, 480Volt, 3 phase, 40,000 sq. ft., 175 linear ft. 185 $43,830 $79,421 $35,591 81% Commercial - Three Phase Office 200 Amp, 208Volt, 3 phase, 40,000 sq. ft., 175 linear ft. 27 $13,824 $10,388 -$3,436 -25% Commercial - Single Phase Office 200 Amp, 240 Volt, 1 phase, 40,000 sq. ft., 175 linear ft. 18 $12,133 $6,769 -$5,364 -44% ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Recommendations/Direction 15 • Recommendation – Adopt updated modeling approach for ECF based on “buy-in” method • Direction sought – What options would Council like staff to consider for implementation? ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Questions? Scott Burnham | NewGen Strategies & Solutions, LLC Executive Consultant Office: (720) 259-1762 | Mobile: (303) 902-9174 sburnham@newgenstrategies.net 16 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Commercial ECF – Implementation Options 17 0 100000 200000 300000 400000 500000 600000 12 AM 02 AM 04 AM 06 AM 08 AM 10 AM 00 PM 02 PM 04 PM 06 PM 08 PM 10 PM Hourly Average Class KW July Peak Day Class Demand Peak Hour Commercial GS Commercial GS25 Commercial GS50 Commercial GS750 Residential ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Commercial ECF – Implementation Options 18 0 500 1000 1500 2000 2500 12 AM 02 AM 04 AM 06 AM 08 AM 10 AM 00 PM 02 PM 04 PM 06 PM 08 PM 10 PM Average Hourly KW per Customer July Peak Day per Customer Demand Peak Hour Commercial GS Commercial GS25 Commercial GS50 Commercial GS750 Residential ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Commercial ECF – Implementation Options 19 -2 -1.5 -1 -0.5 0 0.5 1 1.5 2 2.5 3 3.5 12 AM 02 AM 04 AM 06 AM 08 AM 10 AM 00 PM 02 PM 04 PM 06 PM 08 PM 10 PM Average KW July Peak Day Peak Hour Residential Residential w/Solar ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Commercial ECF – Implementation Options Charges by Demand 20 Commercial by kW Secondary ($/kW) Secondary Total ($) Primary ($/kW) Primary Total ($) Installation Size 10 $368.66 $3,687 $230.94 $2,309 30 $391.72 $11,752 $239.60 $7,188 50 $402.45 $20,122 $243.63 $12,182 70 $409.51 $28,666 $246.29 $17,240 90 $414.79 $37,331 $248.27 $22,344 200 $431.56 $86,311 $254.57 $50,913 400 $446.11 $178,444 $260.03 $104,013 600 $454.62 $272,773 $263.23 $157,938 800 $460.66 $368,530 $265.50 $212,399 1,000 $465.35 $465,347 $267.26 $267,259 2,000 $479.90 $959,802 $272.73 $545,452 3,000 $488.41 $1,465,242 $275.92 $827,772 4,000 $494.45 $1,977,816 $278.19 $1,112,771 5,000 $499.14 $2,495,696 $279.95 $1,399,764 ATTACHMENT 2 NEWGEN STRATEGIES AND SOLUTIONS, LLC Commercial ECF – Implementation Options Charges by Amperage 21 Voltage 208 240 208 240 480 Amps Single Phase Single Phase Three Phase Three Phase Three Phase 10 $173 $202 $311 $362 $757 30 $558 $650 $1,000 $1,164 $2,427 50 $960 $1,118 $1,719 $2,001 $4,165 70 $1,372 $1,597 $2,455 $2,857 $5,942 90 $1,791 $2,084 $3,203 $3,726 $7,746 200 $4,168 $4,848 $7,444 $8,656 $17,966 400 $8,663 $10,074 $15,454 $17,966 $37,239 600 $13,282 $15,442 $23,678 $27,523 $57,006 800 $17,980 $20,902 $32,040 $37,239 $77,092 1,000 $22,739 $26,431 $40,506 $47,075 $97,417 2,000 N/A N/A $83,844 $97,417 $201,368 3,000 N/A N/A $128,250 $148,992 $307,785 ATTACHMENT 2 Colorado Public Utilities Commission. The company allows for a 10-year period in which original ATTACHMENT 1