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1 August 6, 2012

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3 Table of Contents Executive Summary... vii 1.0 Introduction Existing System Overview...2 Electric Service Area and Load... 2 Electric Generating Units... 4 Purchase Power Contracts... 6 Transmission System Forecast Assumptions Electric Load Forecast and Capacity Requirements...8 Electric Load Forecast... 8 System Reserves and New Capacity Requirements Fuel and Electric Market Prices...12 Natural Gas Prices Electric Market Prices Coal Prices Supply Side Resource Options Supply Side Resource Options - Renewable Energy...18 Renewable Energy Options Colorado Renewable Energy Standard (CO RES) Renewable Energy Certificates Renewable Energy Options Renewable Customer-Side Options Renewable Energy Summary Supply-Side Resource Options Conventional Resources Demand-Side Management Resource Options...30 Benchmarking Colorado Springs Utilities DSM Performance Low, Medium and High Scenarios in 2009 Electric DSM Potential Study Electric DSM Scenarios in the 2012 EIRP Environmental Considerations...35 Environmental Impacts Environmental Summary Public Participation, Outreach and Research...39 Public Outreach Summary iii

4 8.0 Scenarios and Portfolios...47 Development and Selection of Preferred Alternative Scenarios Scenario Results Capacity Expansion Plans with Requirements for New Resources Portfolio Selection Analysis of Portfolios...56 Risk Analysis Rate Analysis Kepner-Tregoe Analysis Final Ranking of Portfolios Recommendations and Action Plan Addendum of Recent EIRP Developments...65 Appendix A. Colorado Springs Utilities Current Electric DSM Programs... A-1 Appendix B. Approval Process...B-1 iv

5 List of Tables Table ES.1: Summary of Ranking of Portfolios ix Table 2.1: Existing Generation Resources 4 Table 2.2: Purchase Power Contracts 7 Table 3.1: Electric Load Forecast of March Table 3.2: Electric Resources, Reserve Margins and Capacity Requirements (MW) 12 Table 4.1: Resource Alternatives Data 17 Table 4.1.1: Renewable Scenarios 19 Table 4.2: KEMA Study Wind Integration Costs 23 Table 5.1 DSM benchmarking comparison 31 Table 5.2 DSM Potential Study results for Table 5.3 DSM Potential Study results for Table 6.1 Summary of Environmental and CO 2 Adders 38 Table 8.1: 2011 EIRP Scenarios and Cost Results 50 Table 8.2: Capacity Expansion Plans with New Resources for Scenarios 1 and 2 52 Table 8.3: Portfolio Summary Key Resources Added and Assumptions 53 Table 8.4: Capacity Expansion Plans with the Selected Portfolios 54 Table 9.1: Portfolio Risk Ranking 57 Table 9.2: Portfolio rate impacts and rankings 58 Table 9.3: KT Categories and Weights 59 Table 9.4: Kepner-Tregoe Analysis Scores for Each Portfolio 60 Table 9.5: KT Ranking 60 Table 9.6: Final Ranking of Portfolios 61 Table 11.1: Scenario Summary and Key Resource Additions 67 Table 11.2: Present value of 20-year costs for the two new scenarios 67 v

6 Figures Figure 2.1: City of Colorado Springs 2 Figure 2.2: Colorado Springs Utilities Service Territory 3 Figure 2.3: Tesla Hydro Station 4 Figure 2.4: Capacity Mix 5 Figure 2.5: Front Range Generating Station 5 Figure 2.6: USAFA Solar Generating Station 7 Figure 3.1: Electric Summer Peak Demand Forecast 11 Figure 3.2: Natural Gas Price Forecast with High and Low 13 Figure 3.3: Electric Market Price Forecast with High and Low 14 Figure 3.4: Coal Price Forecast with High and Low Range (Illustrated by Nixon 1 Prices) 15 Figure 4.1: United States Air Force Academy (USAFA) Solar Generating Station 16 Figure 4.2: Colorado Springs Utilities CO RES Compliance 20 Figure 5.1 Annual percent reduction in electric retail sales in each scenario 33 FIGURE 7.1 EIRP PUBLIC PARTICIPATION PROCESS 40 Figure 7.2 Residential Customer Willingness to Pay for Renewables 43 Figure 7.3 Business Customer Willingness to Pay for Renewables 43 Figure 8.1: Modeling and Analysis Process Flow Diagram 48 Figure 8.2: Scenario Sensitivity Analysis 51 Figure 9.1: Portfolio Cost Distributions 57 Figure A-1: Historical DSM Performance A-4 vi

7 Executive Summary Colorado Springs Utilities 2012 Electric Integrated Resource Plan (EIRP) is a long-term strategic plan used to guide resource acquisition, conservation and demand-side management decisions to meet customer electric demand through the year The EIRP is required to be updated every five years by Western Area Power Administration (Western) in order to qualify for federal hydropower purchases. Also, due to the industry changes and the economy, Colorado Springs Utilities has updated the 2008 EIRP through a process which began in early The EIRP process combines technical analysis and public participation to ensure low cost, reliable and environmentally conscious electric supply. The EIRP analysis examines our existing portfolio of resources and carefully evaluates expansions that include conventional supply-side resources, power purchases, renewable and Demand-Side Management (DSM) resources. The objective of the EIRP process is to evaluate and manage all resource options in order to determine not the just least cost plan, but a balanced set of new resources based on the projected demand forecast, environmental considerations, renewable energy goals, and other input assumptions. The EIRP includes an emphasis on environmental stewardship and a new Energy Vision for Colorado Springs Utilities. The Energy Vision 2020 s goal is to provide 20 percent of its total electric energy through renewable sources, provide opportunities to achieve efficiencies with the goal of reducing average electric use by one percent each year through 2020, and maintain a 20 percent regional cost advantage. The Energy Vision 2020 reflects the preference reported by some of Colorado Springs Utilities customers for higher levels of renewable energy and energy efficiency as well as a trend towards higher renewable mandates by the State legislature. Colorado Springs Utilities evaluated the Energy Vision 2020 plan for going beyond the current minimum requirements in the EIRP in order to determine the magnitude of the additional costs. The 2012 EIRP reflects changes in internal and external drivers which include a new load forecast, the new Energy Vision, the Colorado Renewable Energy Standard (CO RES) and potential environmental regulations. The process considers renewable resources, reduced wind costs, integration costs of intermittent resources, natural gas prices and market volatility, DSM and energy efficiency programs. Customer focus on cost as well as our community s expectations for environmental stewardship in the generation of electricity is also considered in the 2012 EIRP. Public Involvement Colorado Springs Utilities sought significant customer involvement and input in the 2012 EIRP. Public involvement helped to revise the 37 scenarios and define the ultimate selection of portfolios. Public input included the EIRP Advisory Group, a select group of volunteers who acted as the objective voice of public input from a cross section of the community. Public outreach also included four public meetings which invited everyone from the community to participate in an open decision-making process. Executive Summary vii

8 The EIRP Advisory Group s comments were included in the portfolio creation, the technical analysis, in the Kepner-Tregoe evaluation, and selection of the recommended portfolio. Key inputs from the EIRP Advisory Group centered on renewable power, DSM levels, the selection of assumptions, and economic conditions. A geothermal resource and a range for coal costs were added when requested during the public process. The EIRP Process The EIRP process considers various evaluation criteria and recommends a portfolio of resources that provides a balanced and responsible low-cost plan. The EIRP meets reliability requirements, is fiscally sound and flexible, promotes environmental stewardship, and balances risk and cost. The 2012 EIRP process includes the following steps: assessment of generating resources and assumptions definition of scenario options combining multiple projections for high-mid-low load growth, renewable resources, demand-side management, potential environmental regulations, natural gas prices, coal prices and wholesale market prices evaluation of scenarios and capacity expansion plans with the Ventyx System Optimizer capacity expansion model cost and risk evaluation of portfolios using stochastic analysis with the Ventyx Planning and Risk detailed, hourly model assessment of rate impacts of the portfolios using the corporate financial model evaluation of portfolios using Kepner-Tregoe (KT) to include the impact of nonquantitative factors The cost, risk and non-quantitative considerations were combined to arrive at recommended portfolios. In the EIRP process, supply-side resource options and DSM resources are evaluated on an equitable basis and integrated in a comprehensive manner. The results are used for 10-year budgets and implementation. The 2012 EIRP evaluated 37 scenarios combining multiple projections for high, medium, and low conditions for factors such as natural gas, coal and electric market prices; load and environmental impacts. The 2012 EIRP analysis also includes scenarios with higher levels of renewables and DSM options. The Ventyx System Optimizer Model was used to analyze each of the 37 scenarios and identified the mix of existing and future resources that results in the lowest cost to meet projected load. The capacity expansion plans resulting from the scenarios runs were consolidated into a smaller number of seven resource portfolios. Executive Summary viii

9 Analysis of Portfolios Risk Analysis: The seven portfolios were subjected to three sets of analyses to select the recommended portfolios. The first analysis was the detailed (hourly) modeling and stochastic risk analysis using the Ventyx Planning and Risk Model. The Planning and Risk model performs Monte Carlo simulation by varying load, gas prices, and market prices stochastically. That is, instead of running a single load or price or a high and low load/price, distributions of loads and prices are developed. The model is run multiple (100) times with different loads and prices from these distributions. The result of the stochastic analysis is the expected value and 95 th percentile of the distribution of net present value of costs for the portfolio, which represents their cost and risk. The resulting risk ranking is summarized in Table ES-1 which shows that Energy Vision 2020, Portfolio 1, had the lowest risk followed by Energy Vision with High Load, Portfolio 4. Table ES.1: Summary of Ranking of Portfolios Portfolio Rate Rank Risk Rank KT Rank Final Rank T T T Rate Ranking: The impact on customers rates was the second analysis of the portfolios. The costs from the Planning and Risk Model were transferred to the corporate financial model. The rate changes above or below the existing base-case rate increases were then used to rank the portfolios. Factors such as load and natural gas prices could result in actual rate increases that are different than those in the EIRP analysis based on the assumptions here. Both, Current Business, Portfolio 2, and Current Business with Low Gas Price, Portfolio 6, had the lowest rate increases, which resulted in the highest ranking shown in Table ES.1. These were followed by Energy Vision 2020, Portfolio 1, and EV 2020 with High Load, Portfolio 4. EV 2020 with 50 MW wind in 2013, Portfolio 3 and Energy Vision with High Renewable, Portfolio 5 have substantially higher rate impacts Kepner-Tregoe (KT) Analysis: The third analysis of the portfolios was a KT Analysis to evaluate factors other than cost. The KT analysis was performed in conjunction with the EIRP Advisory Group to reach an informed consensus. In the KT analysis, the portfolios were ranked relative to one another in eight different categories. As summarized in Table ES-1, Current Business with Low Gas Price, Portfolio 6, ranked highest in the KT rankings, Current Business, Portfolio 2, ranked next followed by EV 2020 with No Wind until RPS Required, Portfolio 7. Executive Summary ix

10 Combined Ranking: The final ranking of the portfolios was the combined ranking of the three analyses discussed above using equal weighting. Energy Vision 2020, Portfolio 1, Current Business, Portfolio 2, and Current Business with Low Gas Price, Portfolio 6, tied for the highest final ranking, as shown in Table ES.1. After discussion with the EIRP Advisory Group and UPAC, Current Business, Portfolio 2, was recommended to the Utilities Board and approved. Pursuing the Energy Vision 2020, Portfolio 1, was also approved by the Utilities Board. These portfolios are described in more detail in the following section. The Preferred Portfolios The two portfolios described below were determined to be the preferred portfolios through the 2012 EIRP process. The preferred portfolio is Current Business Case, Portfolio 2. Energy Vision 2020, Portfolio 1, was determined to also be a desirable second solution. Colorado Springs Utilities may pursue more renewable power in the future, and hopefully move to the Energy Vision 2020 after gaining experience with its initial purchase of 50 MW of wind generation. Portfolio 2 - Current Business Case The Current Business case meets the requirements of current renewable regulations. The Current Business case provides 10 percent of its total electric energy through renewable sources by 2020, and provides opportunities to achieve efficiencies with the goal of reducing average electric use by 4 percent. The Current Business case complies with the 10 percent Renewable Energy Standard by 2020 as required by current renewable goals. Portfolio 1 - Energy Vision 2020 Colorado Springs Utilities developed the Energy Vision for 2020, whose general provisions are to provide 20 percent of its total electric energy through renewable sources by 2020, provide opportunities to achieve efficiencies with the goal of reducing average electric use by 10 percent, while maintaining a 20 percent regional cost advantage. Portfolio 2 Portfolio 1 Current Business Energy Vision MW of wind in MW of wind in 2013 Geothermal in 2018 Geothermal in 2023 Nixon Upgrade in 2018 Biomass in 2024 Pueblo Hydro in 2029 Pueblo Hydro in 2025 LM6000 Nat. Gas CT in % RPS by % RPS by % DSM by % DSM by 2020 Executive Summary x

11 The Action Plan The Action Plan identifies the steps to be taken to meet future demand and potential emerging industry and regulatory needs. Key steps included in the Action Plan are: issue a wind RFP for the purchase of approximately 50 MW of wind power analyze the impact of the actual peak demand in 2011 exceeding the peak forecast in 2011 continue the examination of potential new renewable resources and an efficiency upgrade at an existing power plant explore opportunities for marketing surplus generation continue to analyze transmission system import and export capability explore opportunities such as solar gardens, energy efficiency, and Smart Grid The Action Plan will serve as Colorado Springs Utilities guide for electric resource planning in the coming years. Several steps in the Action Plan have been accomplished, such as issuing the wind RFP for the purchase of 50 MW of wind power, and purchasing 108,000 MWh of wind power per year in 2013 and 2014 from Xcel Energy. Also, reviewing the impact of increased peak demand in both 2011 and most recently in In October 2011, Colorado Springs Utilities received approval from the Utilities Board to offer a new community solar garden pilot program for up to 2 MW total and up to 500 kw in any one location. The pilot program sold out almost immediately. Executive Summary xi

12 1.0 Introduction Colorado Springs Utilities developed the 2012 Electric Integrated Resource Plan (EIRP) to evaluate its supply and demand-side resource options. The 2012 EIRP is also prepared and submitted to the Western Area Power Administration (Western) in compliance with Section 114 of the Energy Policy Act of 1992 (EPAct). The EPAct requires Western customers to have an open planning process in which all reasonable resource options are considered. The EIRP also evaluated the new Energy Vision for The Energy Vision 2020 s goal is to provide 20 percent of its total electric energy through renewable sources, provide opportunities to achieve efficiencies with the goal of reducing average electric use by 10 percent by 2020, and maintain a 20 percent regional cost advantage. The Energy Vision 2020 reflects the preference reported by some of Colorado Springs Utilities customers for higher levels of renewable energy and energy efficiency as well as a trend towards higher renewable mandates by the State legislature. The Energy Vision 2020 plan for going beyond the current minimum requirements will be evaluated as one of the scenarios in the EIRP in order to determine the magnitude of the additional costs. The EIRP considers multiple evaluation criteria and recommends a portfolio of resources that meets reliability requirements, is fiscally sound, promotes environmental stewardship, is flexible, and balances risk and cost over a 20 year period. The 2012 EIRP updates the 2008 EIRP with an eye toward the new Energy Vision, compliance with potential environmental regulations and renewable energy standards, while reflecting new forecast information and resource options. Changes that have occurred and warrant an update of the EIRP include: 1. Decreased wind costs 2. Decreased fuel prices 3. Revised resource costs 4. Updated load forecast 5. Updated environmental and green house gas outlook 6. Revised Colorado Renewable Energy Standard (CO RES) As Colorado Springs Utilities contemplates resource options electric transmission access needs be considered for resources outside our service area. Colorado Springs Utilities has transmission near the City of Colorado Springs, but limited access to resources distant from the City. 1.0 Introduction 1

13 2.0 Existing System Overview The City of Colorado Springs, Colorado, is a home rule municipal corporation located in the south central Front Range of Colorado. The key sectors of the economy of the City and the surrounding area are service industries, retail businesses, construction industries, military installations, the high technology industry and tourism. The City owns and operates Colorado Springs Utilities as an enterprise under certain Colorado Constitution and City Charter provisions. The Charter states that Utilities funds are to be kept separate from all other funds of the City, and that Utilities net earnings are to be appropriated solely for the operations of Utilities. Figure 2.1: City of Colorado Springs Colorado Springs Utilities is a four service utility providing electricity, natural gas water and wastewater. Springs Utilities takes advantage of opportunities between our four utility services to reduce costs borne by customers. For example, the construction and operation of the Tesla hydroelectric unit at the outlet of the tunnel, that conveys water from Rampart Reservoir to the Pine Valley and McCullough Water Treatment Plants. In a similar way, the recently installed Cascade hydroelectric unit generates electricity using water that flows through a water service pipeline. Electric Service Area and Load The electric system provides retail service to metropolitan Colorado Springs and Manitou Springs and delivers special contract power to the Air Force Academy (USAFA), Peterson Air Force Base, Fort Carson, and Cheyenne Mountain Air Station. Colorado Springs Utilities has an electric franchise to serve Manitou Springs through Existing System Overview 2

14 Colorado Springs Utilities' electric service area is shown in Figure 2.2 and is approximately 470 square miles serving 212,966 electric meter accounts as of Dec, The overall area includes Colorado Springs, Manitou Springs, Chipita Park, Green Mountain Falls, parts of Security, and other unincorporated areas of El Paso and Teller counties. The electric transmission and distribution system consists of 232 miles of transmission lines and 3,311 miles of distribution lines, which includes 2,442 miles of underground lines. Figure 2.2: Colorado Springs Utilities Service Territory The most recent electric system peak of 878 megawatts (MW) with a 61.6 percent annual load factor was recorded in Residential, commercial and industrial loads are each roughly one third of the 4,736,000 megawatt-hours (MWh) electric system load. Residential average annual use per customer in 2010 was 7,923 kilowatt hours. The 10 largest customers of the electric system in 2010 had consumption of 832,778 MWh, or 19.1 percent of sales. The system s military customers, purchase a small portion of their power from Western. 2.0 Existing System Overview 3

15 Figure 2.3: Tesla Hydro Station Electric Generating Units Colorado Springs Utilities owns and operates ten thermal generating units and six hydroelectric units totaling 1,072 MW of installed generation capacity, as shown in Table 2.1and Figure 2.4 Most of the energy is generated from 462 MW of coal-fired capacity and the natural gas-fired 460 MW Front Range Power Project. Capacity ratings may differ slightly between summer and winter seasons. Table 2.1: Existing Generation Resources Summer Winter Primary Capacity Capacity Unit Type Fuel Generation (MW) (MW) Ruxton 1 0 Conv. Hydro Manitou Conv. Hydro Manitou Conv. Hydro Manitou Conv. Hydro Tesla Hydro Ponded Hydro Cascade Conv. Hydro Birdsall Steam Turbine Natural gas Birdsall Steam Turbine Natural gas Birdsall Steam Turbine Natural gas Drake Steam Turbine Coal Drake Steam Turbine Coal Drake Steam Turbine Coal Nixon Steam Turbine Coal Nixon Comb. Turbine Natural gas Nixon Comb. Turbine Natural gas Front Range Comb. Cycle Natural gas Total generation Existing System Overview 4

16 Figure 2.4: Capacity Mix Coal units are operated as base load facilities, while natural gas and hydro units are used to meet intermediate and peaking loads. In December 2010, the organization fully acquired the additional half of the Front Range Power Project that it did not already own. The natural gasfueled Front Range Power Plant now represents approximately 43 percent of Colorado Springs Utilities installed capacity. When economical, Colorado Springs Utilities also purchases market power as needed to supplement existing generation resources. Figure 2.5: Front Range Generating Station The four coal units provide low-cost, base load energy for the electric system. Colorado Springs Utilities has an ongoing preventative maintenance program for its generating units, and the coal units are assumed to remain available throughout the EIRP study period. The coal units consistently exceed average availability and reliability levels reported for similarly-sized units. Colorado Springs Utilities has a total of 575 MW of natural-gas fired generation (based on summer capacity ratings): the Front Range Power Project, two 30 MW combustion turbines located at the Nixon Power Plant, and three steam units totaling 55 MW at the Birdsall plant. 2.0 Existing System Overview 5

17 Thirty-five MW of hydroelectric generation comes from several plants. The Tesla hydroelectric unit has a capacity of 28 MW. The Ruxton hydroelectric unit is 1.0 MW in size and operates only during the summer seasons. Manitou Hydro consists of three units with a combined capacity of 5.5 MW including one recent unit. The new Cascade unit is operated at 0.5 MW. All of the hydro units are on Springs Utilities water system pipelines. Colorado Springs Utilities is a member of the Rocky Mountain Reserve Group, a group of power suppliers operating in Colorado, Wyoming, Nebraska and South Dakota. Membership advantages include the pooling of reserve capacities and providing mutual assistance during generating plant outages. Purchase Power Contracts The Springs Utilities electric resources are supplemented with long-term power purchase contracts. These are shown in Table 2.2 and include: Two contracts for hydroelectric power with Western A purchase contract for wind that expires in 2013 A purchase contract of 5.2 MW for solar power from the United States Air Force Academy Solar Project Western Area Power Administration Purchases: Colorado Springs Utilities receives allocations of federal hydropower under contracts with the Western s Salt Lake City Integrated Area Projects (SLCA/IP), and Loveland Area Projects (LAP). The SLCA/IP contract provides MW in the summer and MW in the winter. The LAP contract provides MW in the summer and MW in the winter. These contacts currently extend to September 30, 2024 and were assumed to remain in effect during the EIRP study period. Wind Power Purchase: The one MW wind contract was signed in February, 1998, for a term of 15 years, and the contract expires in February, USAFA Solar Generating Station Purchase: The 5.2 MW solar contract is from the U.S. Air Force Academy Solar Project, which began commercial operation on July 1, SunPower owns and operates the facility, and Colorado Springs Utilities has the option to purchase the project in 10 years. Its 18,888 solar panels cover 43 acres. Renewable Energy: Colorado Spring Utilities renewable energy consists of the USAFA solar project and 28 MW from the Tesla Hydroelectric Plant and the other smaller hydro units. Colorado Springs Utilities offers one megawatt of wind as Green Power for purchase by customers (which is currently sold out). A portion of the Western hydro qualifies as renewable under the Colorado Renewable Energy Standard. 2.0 Existing System Overview 6

18 Figure 2.6: USAFA Solar Generating Station Table 2.2: Purchase Power Contracts Summer Winter Capacity Capacity Purchases (MW) (MW) Western - LAC Western - SLC Wind 1 1 USAFA Solar Note - Summer capacity is from April to September, and winter capacity is from October to March Transmission System Electric transmission access is an important consideration when contemplating adding resource options. Springs Utilities is interconnected with Western, Xcel Energy and Tri-State Generation and Transmission. The Springs Utilities transmission system is geographically limited to the load serving area in and around Colorado Springs resulting in limited access to resources outside of the city. As a member of the Colorado Coordinated Planning Group (CCPG), Colorado Springs Utilities is positioned to take advantage of partnering opportunities in transmission projects that could provide additional access to economic sources of conventional and renewable generation. 2.0 Existing System Overview 7

19 3.0 Forecast Assumptions This chapter provides the key load, fuel and market price forecasts used in the EIRP. The new capacity required as a result of the load forecast is also shown in this chapter. High and low ranges of the forecasts are also summarized in this chapter. 3.1 Electric Load Forecast and Capacity Requirements Electric Load Forecast The 20-year electric load forecast was developed by Colorado Springs Utilities staff during the first quarter of The forecasting methodology is econometric modeling with incremental end-use analyses. In econometric modeling, historic data for number of customers and use per customer are related to explanatory variables such as price, economic activity, monthly factors and weather variables. The historic relationship is then used to forecast future levels of number of customers and use per customer. The Forecast Pro XE modeling package was used to estimate the regression equations for customers and use per customer. Econometric modeling requires a forecast of economic activity. The key forecast is the population forecast from the Colorado State Demographer in the Colorado Department of Local Affairs. Using this forecast helps ensure consistency between Colorado Springs Utilities forecast and other government forecasts. Economic variables, other than population, are derived from Moody s Economics forecasts for El Paso County. In addition to economic data, the impact of price increases is also incorporated in the forecast. The econometric analysis determines price elasticity, the amount by which sales change for a given change in price. The prices used in the econometric analyses are four-service typical utility bills by customer class. Four-service typical bills are used because customers are assumed to respond more to their total bill than to an individual service cost or an average or marginal price. Forecasts of four-service typical bills are from the Colorado Springs Utilities financial model and incorporate the impact of future sales levels, fuel costs and budgeted capital and operations and maintenance costs. Typical four-service utility bills increase approximately 4.3 percent per year for residential customers and 4.1 percent per year for non-residential customers over the forecast horizon. These estimates include electric cost adjustment (ECA) and gas cost adjustment (GCA), increased operating costs, and planned infrastructure additions. 3.0 Forecast Assumptions 8

20 Econometric models can not include the impact of changes that were not present in the historical data. For this reason, incremental end use or engineering modeling is used in the forecast to include the effect of future changes. Federal appliance efficiency standards for refrigerators and freezers have changed several times in the past, and are anticipated to be reflected in the historical data. Future appliance standards for refrigerators and freezers, therefore, do not require an adjustment of the econometric forecast. The impact of future laws or standards for other major appliances or end uses needs to be incorporated in the forecast, however. New federal laws or appliance efficiency standards have been announced for incandescent fluorescent lighting, air conditioners, clothes washers, dishwashers, furnace fans, ranges and ovens. The projected impacts of these changes are incorporated as an adjustment to the econometric forecast based on estimates of the usage reduction for each end-use due to the law or standard, saturation rates for these appliances, and the replacement rates of the old equipment. The electric load forecast also implicitly incorporates Colorado Springs Utilities historic demand-side management program impact but not new demand-side programs. New or incremental demand-side management programs are analyzed in the resource planning process. Table 3.1 and Figure 3.1 present the electric load forecast published in March, Figure 3.1 shows that demand was growing rapidly in the decade of the 1990s and flattened in the decade of the 2000 s. Demand is projected to grow more slowly in the next several years due to slow economic recovery and the impact of appliance efficiency standards. This lower projected growth rate is one of the reasons that an update to the EIRP is appropriate. High and low ranges on the forecast were developed based on historic forecast accuracy. The range starts small and increases to plus and minus 12.6 percent, as shown in Figure Electric Load Forecast and Capacity Requirements 9

21 Table 3.1: Electric Load Forecast of March Electric Load Forecast System energy System peak System load factor Level Change Level Change Annual Year (GWh) (%) (MW) (%) (%) , % , % % 63% , % % 63% , % % 63% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % % 62% , % 1, % 61% , % 1, % 61% , % 1, % 61% , % 1, % 61% , % 1, % 61% , % 1, % 61% 3.1 Electric Load Forecast and Capacity Requirements 10

22 Megawatts Figure 3.1: Electric Summer Peak Demand Forecast 1,400 1,200 1, History High Medium Low System Reserves and New Capacity Requirements Colorado Springs Utilities planning reserve margin is 18 percent of summer peak demand (excluding firm purchases from Western). The reserve margin includes projected Rocky Mountain Reserve Group contingency reserves as well as projected regulating reserve requirements. In addition to projected operating reserves, the planning reserve requirements include reserves for uncertainty in forecasts of load and generation capacity. These uncertainties make it prudent for Colorado Springs Utilities to maintain a planning reserve margin in this range. Several years are required to permit and build new generating units, or to create and put into place demand-side management programs that can reduce load growth. Delays can also be experienced as generating units are built. Actual penetration rates and load reductions from demand-side management programs may not achieve the projected values. Over a period of a few years, regional reserve margins may decline as loads grow faster than anticipated, or as planned resource additions are delayed. When these risk events occur, the result may be power shortages, price spikes and substantially higher purchase costs in regional power markets, and possibly brownouts or blackouts. Thus, a planning reserve margin is used to ensure that native electric loads have a high probability of being met. 3.1 Electric Load Forecast and Capacity Requirements 11

23 Table 3.2 shows Colorado Springs Utilities resources, forecasted electric peak demand, and resulting reserve margins. Reserve margins are calculated in megawatts and in percent of peak demand. As a result of the flattening of demand in the decade of the 2000 s and the impact of energy efficiency in the forecast, Table 3.2 shows that Colorado Springs Utilities has a planning reserve margin above 18 percent through 2029 (at the level of DSM used in the table). Under these demand forecast and DSM projections, Colorado Springs Utilities would need new, firm capacity resources to meet its load and reserve requirements after Other factors such, as renewable requirements, add new resources earlier than this. Note also that one set of DSM impacts is shown in Table 3.2, but alternative levels of DSM and energy efficiency are examined in the EIRP. Table 3.2: Electric Resources, Reserve Margins and Capacity Requirements (MW) Planning forecast Less 4% DSM Net Load Requirement Generation Resources: Drake Drake Drake Nixon Nixon Nixon Birdsall Birdsall Birdsall Hydro Front Range Total CSU Generation Purchased Power: Western Purchases Xcel Wind Purchase USAFA Solar Total Purchases Total Current Resources Reserve Margin- MW Reserve Margin - % 41% 41% 41% 41% 39% 38% 36% 34% 33% 31% 30% 29% 27% 25% 22% 20% 18% 16% 14% Desired Reserve Margin 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% 18% Desired Reserve (MW) Surplus/(Deficit) after Reserves Fuel and Electric Market Prices Fuel and electric market prices are important assumptions in the EIRP. The primary fuels are natural gas and coal. This section also includes a discussion of the electric market prices. Electric market prices are related to natural gas prices as natural gas-fired generating units are often the ones selling power into the market. 3.2 Fuel and Electric Market Prices 12

24 Gas Prices - $/MMBtu Natural Gas Prices Natural gas price forecasts were obtained from three sources and averaged. Natural gas commodity market traded futures were the primary source of the natural gas price forecasts used in the EIRP. Two sources of futures data were used, one from BP and one from Goldman Sachs. The third source was the natural gas price forecast from PIRA Energy Group, an international energy consulting firm specializing in global energy market analysis and intelligence. The resulting natural gas price forecast is shown in Figure 3.2 and had prices that started at $4.29/mmBtu in 2012 and increased to $10.49/mmBtu in High and low natural gas prices were also developed based on historical forecast error. The high and low ranges were plus and minus 40 percent. A reduction in natural gas prices in 2011 has been included in the forecasts, and in the last chapter includes a discussion of recent developments in Figure 3.2: Natural Gas Price Forecast with High and Low High Medium Low Electric Market Prices Electric market prices were developed by Colorado Springs Utilities Energy Supply Department based on historic prices and PIRA forecasts. Electric market purchases often come from natural gas-fired combined cycle power plants similar to the Front Range plant. Electric market prices need to be consistent with the natural gas forecast, or the model will reduce or increase operation of Front Range and purchase power instead. This also means that in scenarios that changed fuel prices or power costs, electric market prices also needed to be changed. Electric Market prices were also developed for on-peak and off-peak periods. High and low forecasts were developed based on historical forecast error and were plus and minus 32 percent around the base forecast. The forecast of on-peak prices is illustrated in Figure

25 Electric Market Prices - Avg On-Peak $/MWH Figure 3.3: Electric Market Price Forecast with High and Low High Medium Low Coal Prices Coal prices were developed by the Colorado Springs Utilities Fuels and Material Management section and reflect the cost of coal at the mine as well as rail delivery charges. Separate coal prices were also developed for each of our coal-fired generating units. In 2012, coal costs reflect a mix of Colorado coal and Powder River Basin (PRB) coal at the Drake units. The Drake units are projected to convert to 100 percent PRB in 2013 after modifications to the units. This should result in considerable cost savings. High and low ranges on coal were not initially included in the EIRP analysis because historically the use of long term contracts had resulted in little volatility in coal prices. The EIRP team was encouraged to include high and low ranges on coal at the first public meeting and by the EIRP Advisory Group. Coal is different from natural gas, which is purchased on a daily basis, in that coal is purchased under contracts where the price is set for several years. Reviewing the data showed, however, that coal price volatility had begun to change. During the 2008 run-up in commodity prices, spot coal prices had also increased significantly due, in part, to Chinese demand. As a result, the Fuels and Material Management section developed high and low forecasts of coal prices for use in the EIRP analysis. The base case and high and low ranges are shown in Figure 3.4. A range is not included in the early years because coal is already under contract at a set price. The high and low coal prices expand over time and are not symmetric. The range starts at plus 43 percent and minus 24 percent in 2015 and grows to plus 63 percent and minus 39 percent in

26 Coal Prices -Nixon 1 $/MMBtu Figure 3.4: Coal Price Forecast with High and Low Range (Illustrated by Nixon 1 Prices) High Low Medium 15

27 4.0 Supply Side Resource Options Colorado Springs Utilities evaluated 38 conventional and renewable resource options, which are listed in Table 4.1. Conventional resource options include natural-gas fired combustion turbines, natural-gas fired combined cycle generating plants with and without carbon capture and sequestration (CCS), advanced pulverized coal-fired generating units with and without CCS, an efficiency upgrade at the existing Nixon plant, fuel cells, and nuclear options. Renewable resources include wind, solar thermal, solar photovoltaic, solar photovoltaic rebates, biogas, geothermal, biomass co-firing, and several hydro generators. Other resource options include municipal solid waste, pumped storage, and several power purchase agreements from wind, solar, coal and nuclear resources. The geothermal resource was added in response to a request made during the public participation process for the 2012 EIRP. Transmission costs for some of the renewable projects were included in their cost. Table 4.1 Resource Alternatives Data has the capital costs, heat rates, operation and maintenance costs, and available dates for the resource alternatives. These resources are discussed in more detail in the following sections. These costs are screening level costs. If an option is selected, it means that the project would need to be analyzed in greater detail. Selection does not mean that a project would move directly to construction. Figure 4.1: United States Air Force Academy (USAFA) Solar Generating Station 4.0 Supply Side Resource Options 16

28 Table 4.1: Resource Alternatives Data Plant Costs Date Nominal Heat Overnight Fixed O&M Total Non-Fuel Data Fuel Plant Type Available Capacity Rate Capital Cost Cost Variable Cost* Source CF MW Btu / kwh 2010 $ / kw 2010 $ / MWh 2019 Coal Single Unit APC 100/150 9,800 $3,271 $35.97 $ % 2019 Coal Single Unit APC 300 8,800 $3,191 $35.97 $ % 2025 Coal Single Unit APC w ith CCS 100/150 12,000 $5,129 $76.62 $ % 2019 Coal Single Unit IGCC 100/150 8,700 $3,626 $59.23 $ % 2025 Coal Single Unit IGCC w ith CCS 100/150 10,700 $5,263 $69.30 $ % 2014 Coal Nixon Optimized Plant Retrofit 15 10,100 $2,000 $35.00 $ % 2017 Gas Conventional NGCC 488 7,050 $1,001 $14.39 $ % 2017 Gas Advanced NGCC 342 6,430 $1,026 $14.62 $ % 2025 Gas Advanced NGCC w ith CCS 291 7,525 $2,000 $30.25 $ % 2014 Gas Conventional CT F-Class 135 9,975 $817 $6.70 $ % 2020 Gas Advanced CT F-Class 180 9,750 $802 $6.70 $ % 2014 Gas LM ,118 $1,009 $6.98 $ % 2014 Gas LMS ,722 $1,009 $6.98 $ % 2012 Gas Fuel Cells 10 9,500 $6,557 $ $ % 2025 Nuclear Single Unit Nuclear 1,100 N/A $6,000 $88.75 $ % 2018 Nuclear Nuclear Small Modular Reactor 25 N/A $3,920 $6.70 $ % 2013 Biomass Biomass Cofiring 20 10,745 $500 $20.00 $ % 2012 Wind Onshore Wind 50 N/A $2,494 $28.07 $ % 2012 Solar Solar Thermal 100 N/A $4,356 $64.00 $ % 2012 Solar CSR Solar Thermal 40 N/A $3,750 $64.00 $ % 2011 Solar PV Rebate - Residential 0.3 N/A $2,000 $0.00 $ % 2011 Solar PV Rebate - Commercial 0.4 N/A $2,000 $0.00 $ % 2012 Solar Small Photovoltaic 7 N/A $5,787 $26.04 $ % 2012 Solar Large Photovoltaic 150 N/A $4,547 $16.70 $ % 2017 Waste Municipal Solid Waste 34 18,000 $7,856 $ $ % 2012 Waste Biogas ,500 $511 $1.00 $ % 2017 Geothermal Binary Geothermal** 10 N/A $4,028 $43.82 $ % 2018 Hydro Pueblo Dam Hydro 10 N/A $1,704 $53.00 $ % 2017 Hydro Pumped Storage 50 N/A $5,266 $13.03 $ % 2014 Hydro Small Hydro 6 N/A $6,600 $36.47 $ % 2012 Hydro Micro Hydro 0.2 N/A $1,200 $20.00 $ % 2019 Coal Coal PPA 100 N/A N/A N/A $ % 2019 Nuclear Nuclear PPA 25 N/A N/A N/A $ % 2012 Solar Solar PPA 5 N/A N/A N/A $ % 2013 Wind Wind PPA a 25 N/A N/A N/A $ % 2013 Wind Wind PPA b 25 N/A N/A N/A $ % 2014 Wind Wind PPA c 25 N/A N/A N/A $ % 2013 Wind Wind PPA d 25 N/A N/A N/A $ % Sources: United States. Energy Information Administration. Updated Capital Cost Estimates for Electricity Generation Plants. Washington DC: EIA Office 1 of Energy Analysis, EIA Study Nov *Uses Denver location-based Overnight Capital Cost. Some prices have been scaled. < 2 In-House Evaluation Direct Testimony and Exhibits of Gregory L. Ford on Behalf of Public Service Company of Colorado, 10M-245E (Public Utilities Commission of 3 the State of Colorado August 13, 2010). United States. Department of the Interior. Bureau of Reclamation. Hydropow er Resource Assessment at Existing Reclamation Facilities < w w.usbr.gov/pow er/assessmentreport/usbrhydroassessmentfinalreportmarch2011.pdf> Notes / Abbreviations: CF Capacity Factor CCS Carbon Capture and Sequestration IGCC Integrated Gasification Combined Cycle NGCC Natural Gas Combined Cycle APC Advanced Pulverized Coal Wind PPA a With Integration costs up to 50 MW per KEMA study Wind PPA b With Integration costs for over 50 MW per KEMA study Wind PPA c Low er price, integration costs over 50 MW per KEMA study Wind PPA d Low er price, integration costs over 50 MW per KEMA study, PTC expired Total Non-Fuel Variable Cost includes Variable O&M and Integration costs. An integration cost from $3.50/MWh-$64.50/MWh * depending on capacity w as applied to the follow ing resources: Onshore Wind, Solar Thermal, CSR Solar Thermal, Large and Small Photovoltaic, and Wind PPA's a-d. A transmission cost of $3.28/kW-Month w as applied to the follow ing units: Binary Geothermal, Pueblo Dam Hydro, and Wind ** PPA c and d. 4.0 Supply Side Resource Options 17

29 4.1 Supply Side Resource Options - Renewable Energy Renewable Energy Options Renewable energy is defined as an energy source that is replaced or replenished rapidly by natural processes. Renewable energy technologies generally have a lower environmental impact than fossil-fueled technologies. Renewable energy includes solar and wind power, hydropower, geothermal, and various types of biomass. As part of the renewable energy options analysis, Colorado Springs Utilities will determine the direction for renewable energy programs at customer facilities, Colorado Springs Utilities facilities, and as community demonstration projects. Colorado Renewable Energy Standard (CO RES) In November 2004, Colorado voters approved an initiative that created a renewable energy standard for retail electric utilities in Colorado that serve over 40,000 customers. The language of that initiative is codified in C.R.S. Section (Colorado Renewable Energy Standard or CO RES) and it has been subsequently modified several times by the Colorado General Assembly. For municipal utilities like Colorado Springs Utilities, CORES requires that energy from qualifying renewable energy resources must be at least one percent of electric retail sales for the years 2008 through 2010, three percent for the years 2011 through 2014, six percent for the years 2015 through 2019 and 10 percent for year 2020 and thereafter. The CO RES requires that this electricity come from qualifying renewable energy resources, which include solar, wind, geothermal, biomass, existing hydroelectric generation with a nameplate rating of 30 megawatts or less, and new hydroelectric generation with a nameplate rating of 10 megawatts or less. The CO RES allows utilities to generate directly or purchase the power generated from qualifying renewable resources, or to acquire the environmental attributes of power generated from these resources in the form of Renewable Energy Certificates (RECs). Utilities may both buy and sell the RECs associated with their qualifying renewable energy resources. The CO RES also establishes a maximum retail rate impact for compliance with CO RES requirements of one percent of the total electric bill annually for each customer of a cooperative electric association that is a qualifying utility and two percent for each customer of an investorowned utility. In 2005, Colorado Springs City Council, in its capacity as Colorado Springs Utilities Board of Directors, adopted a resolution to voluntarily comply with the CO RES requirements. In 2006, Colorado Springs Utilities submitted a Self-Certification Statement to the Public Utilities Commission for the State of Colorado (CO PUC) regarding its Renewable Energy Standard. The Self-Certification Statement filed with the CO PUC is for informational purposes only and is not subject to CO PUC approval. 4.1 Supply Side Resource Options - Renewable Energy 18

30 Colorado Springs Utilities complies with the statutory requirements of C.R.S. Section and is substantially similar to that adopted by the CO PUC through its RES rules. Colorado Springs Utilities chose to self certify with the CO RES because of the belief that it is appropriate to complement its portfolio of electric supply options with the full range of technology and fuel diversity. Colorado Springs Utilities measures and reports its renewable energy levels as part of the EIRP and as part of the CO RES requirements. The renewable energy levels are one of the scorecard measures upon which the Chief Executive Officer of Colorado Springs Utilities is measured. Colorado Springs Utilities expects to have sufficient qualifying renewable energy resources to comply with the CO RES requirements through In 2006, Colorado Springs Utilities made a substantial purchase of RECs to be received during the years 2006 through Colorado Springs Utilities also being acquiring RECs for its qualifying hydro power from Western s Loveland Area Project RECs in These RECs will be used along with qualifying renewable energy generation from Colorado Springs Utilities-owned hydroelectric generating units to comply with the CO RES. The EIRP examined ways to comply with the CO RES or alternative levels of renewable when additional qualifying renewable energy resources where required. In the EIRP scenario analysis, Colorado Springs Utilities analyzed renewable energy at low (10 percent), medium (20 percent), and high (30 percent) levels by These three levels were evaluated in the analysis in order to cover a range of possible future compliance requirements for municipal utilities and investor owned utilities. The range was also examined in order to identify the cost to move to higher levels of renewables. Table indicates the annual levels of renewable energy evaluated in the EIRP. Table 4.1.1: Renewable Scenarios % Renewables Version Low Medium High % 3% 3% % 5% 5% % 10% 12% % 15% 20% % 20% 30% Renewable Energy Certificates To meet CO RES requirements in the early compliance years, Colorado Springs Utilities entered into a contract for RECs with Western in August In this contract, Colorado Springs Utilities purchased RECs in the following amounts: ,929 MWh ,961 MWh 4.1 Supply Side Resource Options - Renewable Energy 19

31 ,970 MWh ,263 MWh ,809 MWh The Western-purchased RECs ensured that Colorado Springs Utilities was in compliance with CO RES requirements through In 2010, Colorado Springs Utilities acquired additional RECs from Western Loveland Area Projects, which added more hydroelectric RECs to its renewable energy portfolio. Acquisition of the Western hydroelectricity RECs, Western purchased RECs and Colorado Springs Utilities existing hydroelectric energy ensured that Colorado Springs Utilities will be in compliance with CO RES requirements through Figure 4.2 provides an example of Colorado Springs Utilities CO RES compliance through year 2031 under the 10% CO RES requirement. Similar analyses were developed for the 20% and 30% renewable levels. These analyses also changed whenever renewable generation was added prior. Note that banking of credits is allowed under the CO RES, which makes the number of credits from Western RECs and hydro and CSU hydro appear larger in Figure 4-2 in some years prior to Figure 4.2: Colorado Springs Utilities CO RES Compliance Note: Compliance Percentages are: = 1%; = 3%; = 6%; 2020 & future = 10%. 4.1 Supply Side Resource Options - Renewable Energy 20

32 Renewable Energy Options Renewable resources that were evaluated in the EIRP are described below: 20 MW Biomass Co-firing - This resource would co-fire woody biomass gathered primarily from forest thinning with coal in the existing Drake 7 boiler. The boiler creates superheated steam which is then run through a turbine-generator to create electricity. 50 MW Onshore Wind - This facility consists of 33 wind turbine generators, each with a capacity of 1.5 MW, to be constructed by Colorado Springs Utilities for a total design capacity of 50 MW. Each wind turbine includes a variable-speed generator, transmission, yaw drive, and on-board transformer. 100 MW Solar Thermal - This facility uses a solar concentrating thermal process to generate superheated steam used to turn a turbine-generator and create electricity. 40 MW Clear Springs Ranch Solar Thermal - This facility uses a solar concentrating thermal process to generate superheated steam used to turn the existing steam turbine-generator at Front Range Power Plant. 0.3 MW Photovoltaic Rebate Residential - This is a collection of customer-sited and customerowned photovoltaic (PV) facilities that are 10 kilowatts (kw) or less, which convert DC electricity to AC electricity. The 0.3 MW level is approximate level for each year for all 20 years. 0.4 MW Photovoltaic Rebate Commercial - This is a collection of customer-sited and customerowned photovoltaic (PV) facilities that are 25 kilowatts (kw) or less, which convert DC electricity to AC electricity. Like the one above, the 0.4 MW level is the approximate level for each year for all 20 years. 7 MW Small Photovoltaic - This facility consists of Colorado Springs Utilities constructing several ground-mounted, fixed-tilt semiconductor panels in an array to directly convert incident solar radiation in the form of photons into DC electricity, which can then be inverted to AC. 150 MW Large Photovoltaic - This facility consists of Colorado Springs Utilities constructing many ground-mounted, fixed-tilt semiconductor panels in an array to directly convert incident solar radiation in the form of photons into DC electricity, which can then be inverted to AC. Per kw savings are realized given the significant expansion and economies of scale. 34 MW Municipal Solid Waste - This facility uses refuse-fired boilers to burn municipal solid waste. The heat is used to generate steam which can be used to run a turbine-generator and generate electricity. 4.1 Supply Side Resource Options - Renewable Energy 21

33 0.552 MW Biogas - This facility uses biogas, a waste by-product in the wastewater treatment process, as a methane rich fuel to be piped from the digester complex to a dedicated burner at the Nixon 1 boiler. The heat generated from the burning fuel is used to generate steam which runs a turbine-generator to create electricity. 10 MW Binary Geothermal - This facility uses geothermal brine as a heat source. The heated brine from a geothermal well is run through a heat exchanger to generate steam for a turbinegenerator, then re-injected in the geothermal resource. 10 MW Pueblo Dam Hydro - This facility will make use of a turnout being built as part of the Southern Delivery project that returns water to Fountain Creek. The water would leave Pueblo Dam, run a hydroelectric turbine-generator, then flow into Fountain Creek. This project would be in collaboration with the US Bureau of Reclamation. 50 MW Pumped Storage - This facility will produce power during peak hours using water that has been pumped from a lower reservoir to an upper reservoir using electricity from the grid during off-peak hours. 1 MW Small Hydro - This resource consists of up to 6 units similar to the Cascade and Manitou 3 units using locations identified throughout the Colorado Springs Utilities raw water network. 0.2 MW Micro Hydro - The hydroelectric micro-turbine project involves replacing a pressure reducing valve within Colorado Springs Utilities water distribution system with a micro turbinegenerator to recover the energy lost when reducing pressure to meet customer needs. 5 MW Solar Power Purchase Agreement (PPA) - This solar PPA consists of purchasing solar energy from a third party solar photovoltaic developer. The solar energy will be injected into Colorado Springs Utilities electric transmission or distribution system for a period of 20 years or more. Wind Power PPA a - This wind PPA consists of purchasing up to 50 MW of wind power at a cost of $39.00/MWh with a zero annual cost escalation and a 34 percent capacity factor. This option is only available in year Wind Power PPA b - This wind PPA consists of purchasing up to 50 MW of wind power at a cost of $39.00/MWh with a zero annual cost escalation and a 34 percent capacity factor. This option is only available in year Wind Power PPA c - This wind PPA consists of purchasing wind power at a cost of $32.00/MWh with a two percent annual cost escalation and a 49 percent capacity factor. This option is only available in years 2013 and Wind Power PPA d - This wind PPA consists of purchasing wind power at a cost of $54.00/MWh with a two percent annual cost escalation and a 49 percent capacity factor. This option is available in years Supply Side Resource Options - Renewable Energy 22

34 Based on the KEMA wind integration study discussed below, all wind PPA s (i.e., a, b, c and d), were modeled with wind integration costs of $3.50/MWh for the first 50 MW of wind, $19.04/MWh for the next 50 MW of wind and $64.50/MWh for all wind in excess of 100 MW. The following is additional information about the renewable supply-side resource options that have been evaluated. Wind Integration Cost Study Wind power could be a favorable renewable energy resource for Colorado Springs Utilities, possibly offering moderate cost for renewable energy. Wind integration, however, is complex given that wind is an intermediate resource. Before wind can be integrated into Colorado Springs Utilities system, several infrastructure issues must be addressed, which include: transmission access, availability, costs, regulation and impacts on operations. In 2010, KEMA completed a wind integration study for Colorado Springs Utilities. The results of the study show that up to 50 MW of wind can be integrated on the Colorado Springs Utilities system fairly inexpensively, but the cost rises very quickly for more than 50 MW. The Colorado Springs Utilities system has existing ramp capability to regulate 50 MW of wind adequately. With more than 50 MW of wind, the Colorado Springs Utilities Area Control Error (ACE) gets very high at times. With more than 50 MW of wind, significant amounts of over-generation are projected during off peak hours. Estimated wind integration costs, per the KEMA wind integration study, are shown in Table 4.2 below. These are the costs that are used for wind integration in the EIRP. Table 4.2: KEMA Study Wind Integration Costs Amount of Wind Integration Integrated Cost Up to 50 MW $3.50/MWh 50 to 100 MW $19.04/MWh Over 100 MW $64.50/MWh The Federal production tax credit (PTC) currently provides about a $22/MWh subsidy for the first ten years of a renewable energy facility s operation. This incentive currently expires on December 31, Wind projects coming on line after 2012 were assumed to not include the PTC in the ERIP analysis. 4.1 Supply Side Resource Options - Renewable Energy 23

35 Biomass Woody biomass represents a potential opportunity for Springs Utilities, but also presents unique challenges. With the expectation of forest thinning activities to address wildfire threat from pine beetle tree kill, biomass could be available to generate qualifying renewable energy at a price competitive with other renewable energy options. Biomass would be used in a conventional power plant, meaning that it would be a firm resource. Biomass would also have a higher capacity factor than other renewable resources, meaning that a given capacity of biomass would produce much more energy than sources such as wind and solar. Another benefit of using forest thinning for power production is that it reduces the need to burn biomass in the field, which would significantly reduce air emissions. The challenge to biomass is the capital cost of the equipment needed and in obtaining sufficient fuel at an attractive price. There is also a concern that if biomass fuel became too expensive or unavailable, it could lead to a stranded investment. All of Springs Utilities plants were evaluated for biomass co-firing, and Drake Unit Seven, was determined to be the most appropriate unit. Co-firing offers the potential for better economics, but a range of technical and operational issues related to the retrofit of the Drake Power Plant must be carefully addressed in a detailed engineering study, before it can be declared feasible. A separate biomass plant could also be considered, but it would require a considerably higher initial capital investment. Colorado Springs Utilities biomass analysis showed that capital costs associated with converting 20 MW at Drake to wood co-firing unit would be $10 million in Based on the 20 MW output, the cost is $500/kW of biomass capacity. Compared with the cost of a stand-alone biomass plant, which often costs over $3,000/kW for a comparable size, the cost of converting an existing unit to co-firing project is more reasonable. A biomass co-firing test project encompassing the research and design of a biomass injection system for Drake Unit Seven was pursued and test burns were conducted at the plant in 2006 and The boiler manufacturer was contracted to perform computer modeling studies of cofiring in order to determine the viability, effects and capability of firing woody biomass in a pulverized coal boiler. The results indicated a 15 percent co-firing rate was feasible, however the boilers required woody biomass to be fired at 1/16 inch particle size. A United States Department of Agriculture (USDA) Woody Biomass Utilization Grant obtained in 2009, was a catalyst to initiating the processing plant design. Because of capital budget constraints and uncertainty in the delivery cost of woody biomass, the co-firing project has not been undertaken, but Colorado Springs Utilities continues to investigate this option. For example, investigation of a newly designed burner capable of handling larger particle-size biomass is one of the recent activities. 4.1 Supply Side Resource Options - Renewable Energy 24

36 Biogas As a four service utility, Springs Utilities has the benefit of housing both electric generation and wastewater treatment operations under one roof. One advantage in the context of renewable energy is a low cost option for digester gas, or biogas" utilization. While biogas is a waste by-product in the wastewater treatment process, biogas is a methane-rich fuel that can be used for power generation. Currently, less than half of the biogas generated is used for building heat in the winter and to maintain an optimal 95 degrees Fahrenheit reaction temperature in the digesters themselves. With a methane gas content of approximately 60 to 65 percent, it is a valuable resource with a heating value of roughly 600 British Thermal Unit (Btu) per standard cubic foot (scf) (compared to about 1,000 Btu per scf for natural gas). The digester facility is located on Clear Springs Ranch and currently flares off on the order of 150 million scf per year. Because the Nixon Power Plant is located at the same site, a biogas utilization assessment was conducted in 2010 to examine the feasibility of piping treated biogas from the digester complex, to a dedicated burner at the Nixon 1 boiler. Quotes were obtained for the piping and gas scrubbing units that will remove moisture, siloxanes and other corrosive gas components such as sulfur. The biogas projected was estimated to contribute about MW of qualifying renewable energy. Renewable Customer-Side Options Photovoltaics Customer-sited photovoltaics (PV) contribute to the overall Colorado Springs Utilities renewable energy generation through the residential and commercial Renewable Energy Rebate Program (RERP) implemented in In , the RERP paid $2.00 per alternating current (AC) Watt and accounts for approximately 30 percent of the customer s total PV system installed cost. The average PV system size is 4 kw, with total installed systems equaling 703 kw from Interest in the RERP has continued to increase because of declining equipment and installation costs, but some PV projects are often not realized due to the final economic payback analysis. The Federal Tax Credit (30 percent of system cost) increases the cost effectiveness of the installation, but this tax credit is scheduled to end in December PV technology continues to improve while PV equipment and installation costs are declining, which will make PV systems more cost effective in the future. Colorado Springs Utilities implemented a net metering tariff for Renewable Energy Net Metering in This tariff allows excess generation credits to accrue and has an annual reconciliation. System capacity is currently limited to 10 kw for residential PV systems. Commercial PV systems up to 25 kw are allowed with the ability to approve larger systems on a case-by-case basis. 4.1 Supply Side Resource Options - Renewable Energy 25

37 Small Wind In April 2010, Colorado Springs Utilities partnered with the Colorado Governor s Energy Office (the GEO) and offered both residential and business customers rebates for small wind systems. Residential customers were offered $2.00 per direct current (DC) Watt to install wind systems up to 5 kw. Business customers were offered $2.00 per DC Watt to install small wind systems up to 25 kw. Customer acceptance of these systems has been slow in Colorado Springs Utilities electric service territory because of poor wind resources, low wind system capacity factors, and very high customer capital costs. Since April 2010, one residential wind system has been installed and no business installations have occurred. Solar Domestic Hot Water and Solar Thermal In April 2010, Colorado Springs Utilities partnered with the Colorado Governor s Energy Office (the GEO) and offered residential customer rebates for solar domestic hot water systems and offered business customer rebates for solar thermal systems. Residential customers were offered solar domestic hot water rebates up to $3,000 while business customers were offered solar thermal rebates up to $15,000. Customer acceptance of these systems has been slow in Colorado Springs Utilities electric service territory because of very high customer capital costs. Since April 2010, 21 residential solar domestic hot water systems have been installed and one business solar thermal installation has occurred. Green Power Since 1999, Colorado Springs Utilities has offered its electric residential and business customers Green Power (i.e., actual wind energy delivered into Colorado Springs Utilities electric system). Electric customers may purchase Green Power in 100 kilowatt-hour (KWh) blocks at a price of $2.45 per block. Because of program popularity, it has been sold out for quite some time. In calendar year 2010, 723 Green Power customers purchased 16,353 blocks of Green Power. Colorado Springs Utilities plans to add addition wind capacity to the Green Power program when it acquires more wind energy. Renewable Energy Certificates (RECs) Since 2008, Colorado Springs Utilities has offered its customers Renewable Energy Certificates (RECs) so customers can support emerging renewable energy technologies. RECs are offered in 100 kwh blocks at a cost of $0.34. In calendar year 2010, 320 customers retired 138,656 blocks of RECs or 13,866 MWhs of RECs. 4.1 Supply Side Resource Options - Renewable Energy 26

38 Community Solar Gardens In October 2011, Colorado Springs Utilities received approval from the Utilities Board to offer a Community Solar Garden Bill Credit (Pilot Program) Tariff for up to 2 MW total and up to 500 kw in any one location. The pilot program sold out almost immediately. The Community Solar Garden Program provides an opportunity for electric customers to own a solar photovoltaic (PV) system without it being installed on their home or business. The Community Solar Garden Program is open to electric residential and electric educational institution customers that purchase or lease capacity from the community solar garden. The community solar garden must be installed in Colorado Springs Utilities electric service territory and a maximum of 2 megawatts capacity is allowed under the tariff. Each community solar garden must have minimum of 100 kw of capacity, and the maximum capacity is 500 kw. Participating customers receive a $0.09 per kilowatt-hour (kwh) bill credit for the solar energy produced by the community solar garden, plus an incentive payment of $2.00 per alternating current (AC) Watt or 30% of the total PV system purchase/lease cost, whichever is less. The incentive payment is first-come, first-served and subject to availability of funding. Renewable Energy Summary Colorado Springs Utilities has sufficient qualifying renewable energy resources to comply with the CO RES through year Colorado Springs Utilities current portfolio of qualifying renewable energy resources include purchased Western RECs, Western Loveland Area Project hydroelectric RECs, solar PV RECs from Colorado Springs Utilities RERP and Colorado Springs Utilities-owned self-generated hydroelectricity. To meet future CO RES requirements, Colorado Springs Utilities is investigating and analyzing qualifying renewable energy resources that include wind power, solar power, geothermal, hydroelectricity, biomass and biogas. Colorado Springs Utilities also offers a comprehensive portfolio of customer-side renewable energy options which include customer-sited photovoltaics, small wind, solar domestic hot water, solar thermal, Green Power, renewable energy certificates and community solar gardens. Colorado Springs Utilities provides a robust portfolio of supply-side and customer-side renewable energy options that not only meet statutory and regulatory requirements, but also meet the renewable energy expectations of its customers. 4.2 Supply-Side Resource Options Conventional Resources This section addresses the assumptions for conventional resources that were evaluated in the EIRP. The EIRP analysis uses the Ventyx System Optimizer capacity expansion model. This model examines the existing system and then adds resources as needed to meet the projected demand levels including reserves in a least-cost manner while obeying environmental requirements. Renewable resources are evaluated together with conventional resources such as: hydro resources, wind resources, wind power purchase agreements (PPAs), biomass, biogas, solar thermal, solar photovoltaic rebates, solar photovoltaic and geothermal resources. DSM programs were also evaluated on an integrated basis with other resource options. 4.2 Supply-Side Resource Options Conventional Resources 27

39 Conventional resources that were evaluated in the EIRP are described below: 39 MW Combustion Turbine - This turbine is similar in MW size to the GE LM6000 aero derivative combustion turbine and not necessarily a GE unit. 72 MW Combustion Turbine - This turbine is similar in size to the GE LMS 100 combustion turbine. 135 MW Combustion Turbine - This turbine is similar in size to a conventional F-Class combustion turbine. 180 MW Combustion Turbine - This turbine is similar in size to a state of the art F-Class combustion turbine. 488 MW Conventional Combined Cycle Unit - This facility utilizes two natural gas-fueled F- class CTs and associated electric generators, a heat recovery steam generator and a steam turbine and generator operating in combined-cycle mode for higher efficiency. 342 MW Advanced Combined Cycle Unit - This facility utilizes one natural gas-fueled H-class CT and associated electric generator, one heat recovery steam generator and one condensing steam turbine with associated generator operating in combined-cycle mode. 291 MW Advanced Combined Cycle with CCS Unit - This facility utilizes one natural gasfueled H-class CT and associated electric generator, one heat recovery steam generator and one condensing steam turbine with associated generator operating in combined-cycle mode. It also includes carbon capture equipment. 10 MW Fuel Cells - This resource utilizes multiple phosphoric acid fuel cell units, each with a power output of 400 kw, for a total output of 10 MW. 100, 150, 300 MW Advanced Pulverized Coal This would be separate coal-fired, steamelectric generating unit. 100, 150 MW Advanced Pulverized Coal with CCS Units - This would be a separate coal-fired steam-electric generating unit with carbon capture technology 100, 150 MW Integrated Gasification Combined Cycle Units (IGCC) - This facility uses two natural gas-fueled F-class CTs and associated electric generators burning syngas that has been gasified from coal, a heat recovery steam generator and a steam turbine and generator operating in combined-cycle mode. 4.2 Supply-Side Resource Options Conventional Resources 28

40 100, 150 MW Integrated Gasification Combined Cycle with CCS Units - This would be a coalfired IGCC facility that includes carbon capture and storage. The coal-gasification approach enables CO2 to be separated for sequestration prior to it entering the generation module. 15 MW Nixon Optimized Plant Retrofit - This resource includes efficiency and capacity improvements for the existing Nixon Coal Plant. 1,100 MW Single Nuclear Unit - This facility consists of a single nuclear power unit similar to the Westinghouse AP MW PPAs from coal base-load units - This would be a 100 MW purchase from another company. 25 MW PPAs from nuclear base load units - This would be a 25 MW purchase from another company that owns a nuclear resource. 4.2 Supply-Side Resource Options Conventional Resources 29

41 5.0 Demand-Side Management Resource Options Demand-Side Management (DSM) is the planning and implementation of utility activities to encourage customers to modify their level and pattern of electricity use in order to change the utility s load shape. By modifying load use, DSM programs benefit both the utility and its customers. Spring Utilities considers DSM programs as alternative resource options in creating a least-cost plan to meet future energy needs. Changes in the timing and magnitude of electricity demand through DSM can make more productive and cost-effective use of generating resources. Customers benefit because they have more opportunities to control their energy use and overall bill. Colorado Springs Utilities offers a comprehensive portfolio of electric DSM programs to its customers. Details of the current electric DSM programs are listed in Appendix A. Actively promoting DSM programs for many years, Colorado Springs Utilities created a DSM Strategic Plan in The plan set a long term direction for defining Colorado Springs Utilities role in shaping customer behavior regarding energy use, with the goal of creating value for its citizen owners and contributing to the organization s core business. In the 2004 EIRP, electric DSM programs selected for implementation were based on those commonly implemented by other utilities nationwide. To a large extent, screening criteria were qualitative due to time and cost constraints in the EIRP analysis. Since other states or regions differ in demographics, economics and market structure, some of the common DSM programs were not applicable to Colorado Springs. Generally, these best practice electric DSM programs were considered low hanging fruit and were applicable to the limited electric DSM target at that time. Updated in the 2008 EIRP process, the DSM Plan incorporated the latest development in customer demand, fuel prices, environmental and regulatory requirements. One tenet of the 2008 EIRP process that grew from public discussion was the emphasis on increasing DSM efforts. This belief was articulated during public meetings as well as by the Customer Advisory Group (CAG) and the Technical Advisory Group (TAG). Based on the changes in customer demands, an update of the electric DSM targets/goals was deemed necessary Electric DSM Potential Study In order to more comprehensively evaluate DSM programs and to reach higher and more aggressive long term electric DSM targets, a comprehensive electric DSM potential study was recommended in the 2008 EIRP and subsequently completed by Summit Blue Consulting in The Summit Blue DSM Potential Study assessed economically achievable electric DSM potential within the electric service territory for existing and new residential, commercial, and industrial sectors over the next 20 years ( ). 5.0 Demand-Side Management Resource Options 30

42 Benchmarking Colorado Springs Utilities DSM Performance Summit Blues DSM potential estimates were compared with other utilities in country. The results of this benchmarking exercise are summarized in Table 5.1. that was also included in the Summit Blue DSM Potential Study. In the benchmarking, investor owned utilities (IOUs), DSM agencies, municipal and cooperative utilities, and Colorado Springs Utilities were compared based on Summit Blue s 2006 survey data. Colorado Springs Utilities latest data were added to the table for comparison purposes. Table 5.1: DSM benchmarking comparison Energy Savings as % of Sales Demand Savings as % of Peak IOUs and DSM Agencies 0.8% 0.6% 1.8% Municipal & Cooperatives 0.2% 0.5% 0.9% CSU % 0.6% 0.6% CSU % 0.7% 0.5% CSU % 1.0% 0.8% CSU % 1.0% 0.9% CSU % 1.0% 0.8% Costs as % of Revenue Although the above table is useful for benchmarking and reference, the results may not be directly comparable because electric DSM savings may be influenced by many factors. The regulatory environment under which utilities and agencies operate may be different, for example. DSM funding may also be different and may be provided through system benefit charges (SBC). Financial incentives provided by the regulatory agency may also vary. Low, Medium and High Scenarios in 2009 Electric DSM Potential Study DSM is one of the important resources to meet future demand for electricity in light of possible volatile fuel and commodity prices and the possibility of greenhouse gas regulations looming on the horizon. The DSM Potential Study provided data for future long-range electric DSM and EIRP efforts. The DSM Potential Study developed several levels of possible DSM savings, which were: Technical Potential Complete penetration of all DSM measures analyzed in applications where they are deemed technically feasible from an engineering perspective. Economic Potential Refers to the technical potential of those DSM measures that are cost-effective when compared to supply-side resources. Achievable Potential Refers to the amount of DSM savings that would realistically occur in response to specific program funding and DSM measure incentive levels. Economic potential scenarios only include DSM measures that pass the Total Resource Cost (TRC) test. If DSM programs pass the TRC test, it means that the total costs (utility plus participant costs) of implementing DSM programs are less expensive than the costs of investing in supply-side resources. 5.0 Demand-Side Management Resource Options 31

43 The following DSM scenarios were defined by Summit Blue for estimating achievable electric DSM potential within the electric service territory: High Case Scenario Incentives set at 79 percent and 69 percent of DSM measure incremental costs for residential and commercial programs, respectively. It achieves the best of best performance by municipal and co-operative utilities. Medium Case Scenario Incentives set at 50 percent of DSM measure incremental costs for both residential and commercial. It achieves the best practice DSM program performance by Western municipal and co-operative utilities. Low Case Scenario Incentives of 25 percent and 27 percent of DSM measure incremental costs for residential and commercial, respectively. It achieves the average DSM performance results. Tables 5.2 and 5.3 summarize DSM Potential Study results in terms of energy savings as percentage of sales, demand savings as percentage of peak, and program costs as percentage of revenue in 10- and 20- year periods, respectively. These levels take into account the durability of savings over the long term. Table 5.2 DSM Potential Study results for Scenario Achievable Potential Cumulative 10 years Annual Average Energy Savings as % of Sales Demand Savings as % of Peak Costs as % of Revenue High Case 0.75% 1.12% 2.08% Medium Case 0.57% 0.85% 1.54% Low Case 0.34% 0.55% 0.89% Table 5.3 DSM Potential Study results for Scenario Achievable Potential Cumulative 20 years Annual Average Energy Savings as % of Sales Demand Savings as % of Peak Costs as % of Revenue High Case 0.50% 0.75% 1.59% Medium Case 0.44% 0.64% 1.27% Low Case 0.35% 0.52% 0.95% Southwest Energy Efficiency Project (SWEEP) provided feedback recommending Colorado Springs Utilities pursue a more aggressive energy savings DSM goal of 10 percent cumulative savings from based on SWEEP s benchmark performance data from some of the utilities in the southwest region. SWEEP is a public interest organization promoting greater energy efficiency in Arizona, Colorado, Nevada, New Mexico, Utah, and Wyoming. This recommendation was reflected in the proposed Energy Vision Demand-Side Management Resource Options 32

44 Electric DSM Scenarios in the 2012 EIRP The results of the electric DSM Potential Study and the Springs Utilities Energy Vision, along with input from SWEEP and the 2012 EIRP Advisory Group, were used to develop the electric DSM scenarios evaluated on an integrated basis with supply-side options in the 2012 EIRP: High Scenario 10 percent energy reduction by Medium Scenario 6 percent energy reduction by 2020 Low Scenario 4 percent energy reduction by Though summarized in the list above as a percentage of electric retail sales in 2020, the scenarios are technically defined as an average of 1 percent, 0.6 percent and 0.4 percent reduction in electric retail sales each year through Electric retail sales reductions begin in calendar year These annual percentages were extended from 2021 to 2031 in order to obtain electric DSM savings targets for the next 10 years of the 2012 EIRP planning horizon. Figure 5.1 depicts the savings as a percentage of sales from 2011 through 2030 for these three scenarios. Figure 5.1 Annual percent reductions in electric retail sales in each scenario Another Super-High Scenario was proposed for a model run by the EIRP Advisory Group to achieve a 20 percent energy reduction by This scenario targeted a 2% reduction in sales each year to After 2020, the annual energy savings were reduced gradually from 2 percent in 2021 to 0.2 percent in 2030 to take into account issues of achievable potential and market saturation. 5.0 Demand-Side Management Resource Options 33

45 All DSM savings will be validated annually through a detailed measurement and verification process. Historical DSM savings are summarized in Appendix A. In 2011, for example, DSM savings were estimated at 8.9 MW and 21,051 MWH. Savings are conservatively estimated because they are based only on the number of rebates paid and the estimated impact per rebate or for equipment bought with incentives (such as CFL light bulbs). No savings are attributed to education or advertising programs. Colorado Springs Utilities also does not include savings from federal appliance efficiency standards or Energy Star programs unless rebates are paid for the purchase of Energy Star appliances by customers. Achieved DSM savings are part of management and executive goals, including being included on the scorecard for the Chief Executive Officer. 5.0 Demand-Side Management Resource Options 34

46 6.0 Environmental Considerations Colorado Springs Utilities integrated several methodologies for evaluating both the technical and regulatory environmental risks in the 2012 EIRP. Environmental risks could be among the most costly developments to Colorado Springs Utilities customers in the future. Environmental risks were separated into two categories in the EIRP analysis. These two categories were an O&M cost adder for the coal plants and a CO 2 emissions adder. In addition to the environmental variables in the EIRP modeling, the KT analysis included factors that represent the negative health effects and public perception of coal-fired generation. These factors were included as a result of working with the advisory group and feedback from public meetings. The combination of environmental variables in the modeling and the KT analysis provides a comprehensive review of the risks and costs associated with a wide range of environmental impacts to the utility. Environmental Impacts The EIRP included a thorough review of environmental pollutant impacts and their relationship to customer preference and implementation issues. Additionally, we explored the possibility of more stringent air quality standards and CO 2 regulation during the planning period. The objective was to encompass a range of values that would cover the technical environmental regulatory challenges while ensuring that it was possible to differentiate between traditional pollutants and greenhouse gas pollutants. Future environmental scenarios with low, medium and high environmental adders were developed to address the uncertainty of future regulatory standards. Environmental risks were included in the model as two distinct types of costs: The Environmental Adder and the CO 2 Adder. The Environmental Adder is a combination of the capital and operational costs of increasingly stringent controls levelized over the EIRP timeframe. The Environmental Adder represents the total cost of what is currently deemed or expected to be the Best Available Control Technology for particulates, Mercury, SO 2, NO X, CO, and CO 2. The Low scenario for the Environmental Adder used a cost of $1.50/MWh and represented the expected cost of the proposed environmental regulations during the EIRP. The Low scenario reflects the cost for regulations that are known to be forthcoming, but that have not yet been finalized. As a result, the final requirements for emissions control equipment are not known, which means that an estimated cost has been used for the cost of that equipment and its operating costs. The basis of the cost is to provide maximum operation at the most proven removal rates. The Low Environmental Adder of $1.50/MWh includes additional removal of Mercury, improved SO 2 removal rates with direct sorbent injection or Neumann system scrubber technology, dedicated CO monitoring and minor efficiency upgrades to improve CO 2 emissions. The Low Environmental Adder also includes improved NO x removal rates from advanced overfire air systems and advanced low NO X burners. 6.0 Environmental Considerations 35

47 The Low scenario also included the capital cost of the scrubbers or direct sorbent injection system, the O&M costs of these emissions controls, and the impact on Drake and Nixon capacity and heat rate. Initial runs were made giving the Ventyx System Optimizer Model the option of spending the money to add the SOx reduction technology at the units or to shut down the unit. The model determined that adding the SOx reduction technology was the lower cost option under the base-case assumptions included in the EIRP analysis. The Medium Environmental Adder has a cost of $7.50/MWh and includes lower emissions requirements for Mercury, SO 2, CO, NO x, and CO 2. Inclusion of selective catalytic reduction (SCR) systems for substantially higher NO x removal accounts for the largest part of the cost increase above the Low scenario. The Medium Environmental Adder also includes costs for upgraded turbine components to improve efficiency and reduce CO 2 emission rate. With respect to Mercury, national regulations for Mercury had not been finalized at the time of the EIRP. Colorado Springs Utilities generation units emissions of Mercury have been regulated under state law since Under the Colorado regulations, Colorado Springs Utilities generating units were classified as small emitters. Mercury emissions did not reach the threshold to be classified as large emitters. Colorado Springs Utilities purchases coal that is low in Mercury. All of Colorado Springs Utilities are equipped with baghouses, which remove a significant portion of the Mercury emissions. Baghouses are normally the first step in Mercury removal, and Colorado Springs Utilities took this step years ago. In the Low, most likely, scenario, additional Mercury emissions reductions beyond what is allowed under Colorado regulations are not expected to be required. The Low Environmental Adder reflects the expectation, however, that the national Mercury regulations will require additional monitoring equipment be installed. The Low Environmental Adder, therefore, includes the cost of purchasing and operating that monitoring equipment. The Medium Environmental Adder addresses the possibility that regulations would reduce allowable Mercury emissions even further. The Medium Environmental Adder includes additional cost for activated carbon injection, which is then caught in the baghouses. The final step for the Environmental Adder is the high value of $10.00/MWh. This cost includes all cost associated with the first two levels and the addition of equipment to capture and store 50% of the CO 2 emissions from Springs Utilities coal fired generation. The cost of carbon capture and storage is uncertain as it has not be demonstrated at a commercial level. 6.0 Environmental Considerations 36

48 The second environmental factor modeled during the EIRP was the CO 2 Adder. The CO 2 Adder was based on the EPA s market and regulatory experience with the Acid Rain Program s cap and trade approach. The goal of this type of approach was to use market forces to spur technology development through cost pressures. When the Acid Rain Program was started, utilities had the option to address their SO 2 emissions through operational, technological, or financial innovation. The EPA determined that a fixed number of SO 2 allowances would be offered in the US, and utilities that needed additional allowances could purchase allowances or look for ways to reduce their emissions. These market pressures created the conditions for the development and wide scale adoption of SO 2 controls and switching to lower sulfur coal. Assuming that a CO 2 market would operate in a similar fashion, a CO 2 emissions market would be a likely way to evaluate the cost of CO 2 from electric generation regardless of the source. Therefore, a CO2 Adder was included in the EIRP analysis in an attempt to mimic a potential CO 2 market. Four price points in the market were developed in order to help understand what economic and operational pressures this would put on the utility: The current business scenario assumed a continuation of the current situation without a CO 2 Adder. The Low price point for the CO 2 Adder was $3.00/ton. The $3.00 per ton was based on The Regional Greenhouse Gas Initiative (RGGI), a cooperative effort among several northeastern states to reduce greenhouse gas emissions. The RGGI program had the first CO 2 market in the U.S. where prices could be evaluated. The prices began around $3.00/ton but have since declined to approximately $1.75/ton. An initial price of $3.00/ton appeared to be a reasonable starting point for the lower evaluation point. The Medium and High price points evaluated for the CO 2 Adder were a based on the European Union s (EU) Carbon Markets. The EU has established CO 2 emission prices going back to Taking into consideration variability and currency fluctuations, the EU markets have displayed a price between $25.00 and $50.00 per metric ton of CO 2. Thus, the low and high range of the EU s historical CO 2 prices were adopted as the Medium and High price points to evaluate in the EIRP. Environmental Summary Two separate environmental adders, shown in Table 6.1, were used to evaluate the operational and financial risks on the utilities power generating portfolio in order to better understand the risks and uncertainties facing Springs Utilities. The Environmental Adder provided a means to evaluate the technical and regulatory pressures associated with key pollutants from coal-fired generation. The CO 2 Adder addresses the pressure to reduce emissions of greenhouse gases from Springs Utilities generating units. Segregating environmental risks into these two adders provided the flexibility in the modeling to gain insight to the future balance of generation for Springs Utilities. 6.0 Environmental Considerations 37

49 Table 6.1 Summary of Environmental and CO 2 Adders Level Environmental Adder $/MWh CO 2 Adder $/ton Current Low Medium High Environmental Considerations 38

50 7.0 Public Participation, Outreach and Research The 2012 EIRP process included a rigorous public outreach and participation program. Setting the stage for the discussions were the State of Colorado s RES and Springs Utilities Energy Vision As a result, the public process had a heightened emphasis on renewable energy resources and DSM programs to provide customers with greater opportunities to reduce electric use. Figure 7.1 summarizes the public process and key milestones. The public participation phase included public meetings, presentations to community organizations, random surveys, web site, social media, and an EIRP Advisory Group. Internal and External Stakeholders: When initiating the public outreach plan for the 2012 EIRP, staff began with an assessment of internal and external activities since the 2008 EIRP. Since that time, there has been significant community discussion and internal activities related to energy planning. Internally, a wind integration study, bio-mass study, wind RFP and DSM potential study have been completed. Projects since the last EIRP have included constructing the new Cascade Hydroelectric Facility and collaborating with the Neumann Systems Group developing a new emissions control technology. Externally, the community has been involved in sustainability conversations that include energy planning. Those efforts include the City of Colorado Springs Sustainability Plan, Regional Sustainability Plan, Fort Carson Regional Growth Plan, Quality of Life Indicators Report, Dream City 2020, Green Cities Coalition, Pikes Peak Sustainable Business Network, Operation 6035, and the Downtown Partnership Sustainability Committee. Based on stakeholder analysis and strategic engagement activities with diverse groups, the public process consisted of three phases: o Initial phase: introduction and education o Middle phase: scenario and portfolio development o Final phase: portfolio evaluation and selection Staff obtained feedback from the public process. Examples of this feedback include adding geothermal to the list of resources, considering uncertainty in coal prices and adding externalities to the EIRP analysis. Externalities are defined as the by-products of fossil-fueled generation on people and the environment. Externalities consider the sustainability of a portfolio including the effects of resource extraction, air pollution, waste generation, and carbon dioxide emissions. While technical analysis continued, community engagement focused on sharing preliminary scenarios and model results, and obtaining continuous public feedback on the process. Presentations and discussions at the public meetings and the EIRP Advisory Group highlighted the challenges and opportunities that Springs Utilities and our community faces, as well as best management practices and other energy planning considerations. Staff looked to recognize and demonstrate connectivity with other city and regional efforts to ensure the community discussion was framed within a larger context. 7.0 Public Participation, Outreach and Research 39

51 FIGURE 7.1 EIRP PUBLIC PARTICIPATION PROCESS Public Meetings Four public meetings were held as part of the EIRP process. At each of the four public meetings, the agenda was designed to capture public input relevant to each of the EIRP phases. These meetings were: Public Meeting One: Share critical assumptions, data collection and analysis to date, while obtaining public input on the planning process and identification and removal of any gaps before moving forward. Public Meeting Two: Share preliminary scenarios, criteria for screening, as well as the risk factors to be considered in the evaluation. Obtain input to finalize and prioritize scenarios for further study. Public Meeting Three: Share results of scenario screening and portfolio development, leading to a final list of portfolios for consideration. Public Meeting Four: Share final preferred portfolios to be advanced to Utility Policy Advisory Committee (UPAC) and Utilities Board (UB) for review and approval, and 7.0 Public Participation, Outreach and Research 40