Exhibit ES Integrated Resource Plan for Cheyenne Light, Fuel & Power

Transcription

1 Integrated Resource Plan for Cheyenne Light, Fuel & Power June 2011

2 Table of Contents ES.0 Executive Summary...ES-1 ES.1 Summary...ES-1 ES.2 Action Plan...ES-1 ES.3 Company Background...ES-2 ES.4 The Planning Environment...ES-2 ES.5 Assumptions...ES-2 ES.6 Demand-Side Management...ES-2 ES.7 Supply-Side Resources...ES-3 ES.8 Resource Need Assessment...ES-3 ES.9 Resource Evaluation...ES-4 ES.10 Risk Analysis...ES-5 ES.11 Preferred Plan Selection...ES-7 ES.12 Conclusion...ES Introduction Company Background Objectives IRP Process Planning Environment The Future of Coal-Fired Generation Climate Change Legislation Carbon Capture and Sequestration Technologies Environmental Regulatory Requirements Grid Modernization Plug-in Hybrid Electric Vehicles New Transmission Construction Assumptions Coal Price Forecasts Natural Gas Price Forecasts Market Price Forecasts Financial Parameters Planning Reserves Emissions Costs Load Forecast Demand-Side Management Residential Space and Water Heating Refrigerator Pick Up Program Residential High-Efficiency Lighting Residential Energy Audit Commercial/Industrial Prescriptive Rebates...19 Cheyenne Light 2011 IRP i

3 5.6 Commercial/Industrial Custom Rebates Total Electric DSM Portfolio Supply-Side Resources Existing Resources New Conventional Resources Coal Combined Cycle Combustion Turbine Firm Market Purchase New Renewable Resources Photovoltaics Wind Resource Need Assessment Analysis Risk Analysis Stochastic Analysis Risk Profiles Stress Tests Step Load Economy Interchange Market Environmental Selection of the Preferred Plan Sensitivity Drivers Comparison to 2005 and 2007 IRP Conclusions and Recommendations Action Plan...39 Appendix A Software Used in Analysis...40 A.1 Markets Module...40 A.2 Portfolio Module...42 A.3 Capacity Expansion Module...42 A.4 Financial Module...43 A.5 Risk Module...44 Appendix B Cheyenne Light, Fuel & Power Load and Resource Balance Preferred Plan...45 Abbreviations...46 Cheyenne Light 2011 IRP ii

4 List of Tables Table ES-1. Ranges for Selected Uncertainty Variables...ES-6 Table 3-1. Coal Price Forecast...10 Table 3-2. Monthly Henry Hub Natural Gas Prices ($/MMBtu)...11 Table 3-3. Financial Parameters...12 Table 3-4. Carbon Tax Assumptions (Environmental Scenarios Only)...14 Table 4-1. Cheyenne Light Peak Demand and Energy Forecast Table 4-2. Load Forecast Comparison...17 Table 5-1. DSM Electric Program Portfolio Year Table 5-2. DSM Electric Program Portfolio Year Table 5-3. DSM Electric Program Portfolio Year Table 5-4. DSM Program Budgets Year Table 5-5. DSM Program Budget Allocation Year Table 5-6. DSM Program Portfolio Summary...21 Table 6-1. Cheyenne Light Existing Resources...22 Table 6-2. Coal-Fired Power Plant Performance Parameters...23 Table 6-3. Combined Cycle Power Plant Performance Parameters...23 Table 6-4. Combustion Turbine Power Plant Performance Parameters...24 Table 6-5. PV Performance Parameters...25 Table 6-6. Wind Performance Parameters...25 Table 7-1. Optimal Expansion Plans...28 Table 8-1. Ranges for Selected Uncertainty Variables...31 Table 8-2. Preferred Plan Resource Comparison...38 Table B-1. Load and Resource Summary Preferred Plan...45 Cheyenne Light 2011 IRP iii

5 List of Figures Figure ES-1. Cheyenne Light Load and Resource Summary...ES-4 Figure ES-2. Deterministic PVRR for Scenarios...ES-5 Figure ES-3. Scenarios Risk Profiles ( )...ES-6 Figure ES-4. Preferred Plan Resource Additions...ES-8 Figure 2-1. Possible Timeline for Environmental Regulatory Requirements for the Utility Industry...6 Figure 3-1. Natural Gas Price Forecast Henry Hub...11 Figure 3-2. Reference Case On-Peak Electricity Prices Wyoming Region...12 Figure 4-1. Cheyenne Light, Fuel and Power 7-Year Historical and 20-Year Forecasted Peak...16 Figure 4-2. Cheyenne Light, Fuel and Power 7-Year Historical and 20-Year Forecasted Energy...16 Figure 7-1. Cheyenne Light Load and Resource Summary...26 Figure 7-2. Deterministic PVRR for Scenarios...29 Figure 8-1. Scenarios Risk Profiles ( )...32 Figure 8-2. Step Load Deterministic PVRR...33 Figure 8-3. Economy Interchange Stress Test Deterministic PVRR...34 Figure 8-4. Environmental Stress Test Deterministic PVRR...34 Figure 8-5. Preferred Plan Resource Additions...36 Figure 8-6. Preferred Plan Tornado Chart ( )...37 Figure A-1. Sample Topology...40 Figure A-2. MRX Decision Basis...41 Figure A-3. Sample Reports...43 Figure A-4. Overview of Process...44 Cheyenne Light 2011 IRP iv

6 ES.0 Executive Summary ES.1 Summary The 2011 Cheyenne Light, Fuel and Power Company (Cheyenne Light) integrated resource plan (IRP) was completed to provide a road map for defining the appropriate system upgrades, modifications, and additions required to ensure reliable and economic service to Cheyenne Light s customers now and for the future. The IRP examined the needs of those customers with a thorough consideration of generation, including renewable energy and purchased power. The preferred plan meets the objectives of the company to: Ensure a reasonable level of price stability for its customers Generate and provide reliable and economic electricity service while complying with all environmental standards Manage and minimize risk Continually evaluate renewables for our energy supply portfolio, being mindful of the impact on customer rates. In preparing this IRP, Cheyenne Light conformed to the Wyoming Public Service Commission Guidelines Regarding Electric IRPs, including hosting a stakeholder meeting on February 10, 2011, in Cheyenne, Wyoming. The comments and feedback provided during the meeting were incorporated in the IRP analysis, as appropriate. None of the comments or feedback had a material impact on the IRP process or final results. ES.2 Action Plan Cheyenne Light s action plan listed below provides a template for the actions that should be taken over the next several years. Cheyenne Light will continue to monitor market conditions and regulatory developments so that the items in the action plan can be adapted to address actual conditions as they occur. Cheyenne Light s plan is as follows: In the near term, continue to purchase a firm 6 x 16 energy product during the summer months to provide for the current and future summer capacity shortfall. Build or otherwise procure three small combustion turbines for operation in After completion, monitor market conditions and opportunities for conversion to combined cycle operation. Seek opportunities to develop economic renewable resources particularly wind and solar. Actively review and prepare for load growth in the service territory. Monitor transmission developments in the Western U.S. Cheyenne Light 2011 IRP ES-1

7 ES.3 Company Background Cheyenne Light serves approximately 39,300 electric customers and 34,500 natural gas customers in Cheyenne and a large portion of Laramie County, Wyoming, including natural gas service to Pine Bluffs, Burns, and Carpenter in eastern Laramie County, Wyoming. Its 2010 summer peak electric load was 176 MW. Cheyenne Light s future resource need has historically been evaluated in conjunction with Black Hills Power, Inc. In 2005 Cheyenne Light and Black Hills Power completed a joint resource plan which resulted in a Certificate of Public Convenience and Necessity (CPCN) from the Wyoming Public Service Commission (WPSC) for the construction of the coal-fired Wygen II unit. The need for Wygen II was deemed necessary to serve Cheyenne Light s load, and is a Cheyenne Light rate-based resource. In 2007 Cheyenne Light and Black Hills Power completed a joint resource plan which resulted in a CPCN from the WPSC for the construction of the coal-fired Wygen III unit. The need for Wygen III was deemed necessary to serve Black Hills Power s load, and is a Black Hills Power rate-based resource. Cheyenne Light s 2011 IRP is the first plan, since Black Hills Corporation acquired Cheyenne Light in January of 2005 that exclusively analyzes the future resource needs of Cheyenne Light s customers. ES.4 The Planning Environment Planning for future generating resources in the electric utility industry involves the consideration and evaluation of many uncertainties. Those uncertainties have increased in number and magnitude over the last several decades. Cheyenne Light has considered the impacts of uncertainties that include the future of coal-fired generation, grid modernization, and plug-in hybrid electric vehicles. The uncertainties regarding the future of coal-fired generation include climate change legislation, carbon capture and sequestration technologies, and environmental regulatory requirements. Changes in the market that could result from the construction of new transmission also need to be monitored. ES.5 Assumptions A wide variety of data assumptions must be made for integrated resource planning modeling. A 20-year planning horizon was used as the basis for the modeling assumptions. Other key assumptions include the load forecast, coal price forecasts, natural gas price forecasts, market price forecasts, financial parameters, planning reserves, and emissions costs. ES.6 Demand-Side Management Cheyenne Light s demand-side management programs include residential and commercial programs. The residential electric portfolio offers customers opportunities to save energy with lighting, electric water heating, and second refrigerator turn-in Cheyenne Light 2011 IRP ES-2

8 programs. This portfolio also offers an energy audit program. The commercial electric portfolio includes both a prescriptive rebate program and a custom rebate program. ES.7 Supply-Side Resources Cheyenne Light currently owns one generating resource, the coal-fired Wygen II unit, and purchases the remainder of its requirements through power purchase agreements (PPA) for coal-fired, natural gas-fired, and wind resources. All of the current PPAs will expire during the planning horizon of this plan. In the IRP modeling, resources that could be used to replace the expiring PPAs and to provide for future load growth included both conventional and renewable resources. Conventional resources included coal, natural gas-fired combined cycle units (CC), natural gas-fired combustion turbines (SC or CT), and firm market power. The renewable resources considered included solar and wind. ES.8 Resource Need Assessment The Cheyenne Light system is expected to experience load growth of approximately 1.5% per year. Over the planning horizon, all of Cheyenne Light s PPAs expire. An assumption in this IRP is that the PPA for Wygen I is replaced in kind at the time of its expiration. The Happy Jack and Silver Sage PPAs (both wind resources) expire in 2028 and 2029, respectively. The totality of the requirements for new resources, incorporating the need for a minimum planning reserve margin of 15% and reflecting that Cheyenne Light has no future committed resources in its generation portfolio, is shown on Figure ES-1. The capacity deficit in any year is reflected as the distance between the line labeled Peak Demand + 15% Reserves and the top of the shaded blocks for Existing Resources. The capacity deficit reaches over 150 MW by the end of the planning horizon. Cheyenne Light recognizes that as a standalone system, its reserve margin requirement is higher than the 15% reserve margin assumption. Cheyenne Light anticipates negotiating a reserve sharing agreement with Black Hills Power in an effort to manage its reserve requirements and maintain a reliable system. Cheyenne Light 2011 IRP ES-3

9 Figure ES-1 Cheyenne Light Load and Resource Summary 350 MW Peak Demand + 15% Reserves Existing Resources Capacity Deficit Year ES.9 Resource Evaluation The process used to determine the preferred resource portfolio for Cheyenne Light began by identifying eleven scenarios, also referred to as plans, to run through the Capacity Expansion module. 1 Each capacity expansion model scenario selected an economic resource portfolio to serve the load subject to the assumptions of that scenario. Each of the resource portfolios were then run through a production cost model, and were modeled with the base case scenario assumptions to determine the relative present value of revenue requirements (PVRR). The PVRR for scenarios 1 through 9 and 11 when run on a deterministic basis are shown on Figure ES-2. As can be seen on Figure ES-2, with the exception of the step load and low load cases, the PVRRs for the cases are within approximately 2% of each other. 1 Specific details for each scenario are provided in Section 7.1 of this report. Cheyenne Light 2011 IRP ES-4

10 Figure ES-2 Deterministic PVRR for Scenarios 20 Year PVRR $1,400 $1,300 Million $ $1,200 $1,100 $1,000 Base Environmental High Gas Low Gas High Load Low Load Step Load Source: Ventyx 2x No Firm Market 3 SCs 2014 ES.10 Risk Analysis Utilities must plan for future customer needs for electricity in an environment of significant uncertainty. Thus, the analysis conducted for this IRP examined uncertainty under a variety of possible future conditions. Analyses conducted to quantify the risk associated with the various scenarios included stochastic analysis, and specific examination of 1) the effects of a step load increase in the Cheyenne Light demand for electricity, 2) the effects of not having a market available for economy interchange, and 3) the effects of the environmental scenario on the preferred resource portfolio. Ventyx s Strategic Planning model uses a structural approach to forecasting prices that captures the uncertainties in demand, fuel prices, supply and costs. The uncertainties examined in this IRP include those reflected in Table ES-1 which shows the minimum and maximum values used for selected uncertainty variables. Cheyenne Light 2011 IRP ES-5

11 Table ES-1 Ranges for Selected Uncertainty Variables Variable Minimum Maximum Mid-Term Peak Mid-Term Energy Long-Term Demand Mid-Term Gas Oil Price Long-Term Gas Coal Unit Availability Gas Unit Availability Pulverized Coal Capital Costs Combustion Turbine Capital Costs Combined Cycle Capital Costs Wind Capital Costs Source: Ventyx Cumulative probability distributions, also known as risk profiles, provide the ability to visually assess the risks associated with a decision under uncertainty. These risk profiles are one of the results of the stochastic analysis conducted by Ventyx, resource planning consultant for Cheyenne Light. The risk profiles for the scenarios with the exception of the step load scenarios are shown on Figure ES % Figure ES-3 Scenarios Risk Profiles ( ) Risk Profiles 90% 80% Cumulative Probability 70% 60% 50% 40% 30% 20% 10% 0% $1,000 $1,025 $1,050 $1,075 $1,100 $1,125 $1,150 $1,175 $1,200 Present Value of Revenue Requirements (Millions $) Base Plan Environmental Plan High Gas Low Gas High Load Low Load 2x Base Base-No Firm Market 3 SCs 2014 Source: Ventyx Figure ES-3 shows that with the exception of the low load case, the risk profile for the preferred plan (3 SCs 2014) is to the left and lower than any other case except that labeled the base plan. The base plan resource portfolio includes installation of a 90 Cheyenne Light 2011 IRP ES-6

12 MW aeroderivative CT in 2014 and firm market purchases in 2011, 2012, and 2013 to meet the summer peak requirements. Cheyenne Light s 2011 IRP did not need to consider any unit retirements or retrofits to existing units or perform any special studies. However, three stress tests were examined to further evaluate Cheyenne Light s risk exposure due to future uncertainty. These three stress tests involved the consideration of step load in 2014, the examination of results if no economy interchange market were available, and an environmental stress test. The Cheyenne, Wyoming area is very attractive for possible future economic development that in some cases results in significant increases in requirements for electricity what has been referred to in this IRP as step load increases. The potential for passage of carbon legislation to address perceived global climate change, changes as Democrats and Republicans alternate leadership roles in Washington, DC. With the difficulty many utilities experience in permitting and siting both new generation and new transmission, it is possible that the economy interchange market will not be as robust in the future as it has been in the past. Further risk mitigation analysis included consideration of shaft risk and flexibility for installing additional resources (expansion) and/or converting resources from simple cycle combustion turbine operation to combined cycle operation in the future as the load grows and as environmental and political considerations change. ES.11 Preferred Plan Selection The analysis undertaken in the course of preparing this IRP provided information to Cheyenne Light senior management that was key in identifying the resource portfolio that would provide the future electricity needs of customers and minimize risk in the face of an uncertain future. The preferred plan for Cheyenne Light, reflected on Figure ES-4, shows a reliance on the market for block purchases in July and August of 2011, 2012, and In 2014, Cheyenne Light intends to build or otherwise procure three simple cycle small CTs of approximately 36 MW net output each. The expectation at Cheyenne Light is that the site for the three CTs will be selected for expansion possibilities and will be in the Cheyenne, Wyoming area. Thus, there will be space to install a fourth CT at the site when additional resources are needed. In addition, the footprint will accommodate converting CTs to combined cycle configuration. The CTs should be able to provide regulation for the wind resources in the Cheyenne area which would give Cheyenne Light the additional option of self-providing ancillary services. In the longer term, the preferred plan shows additional wind resources in 2019 and two additional CTs in 2022 and In all other years, firm market purchases provide stopgaps for July and August peak demand requirements until the need for resources extends to multiple months. Although the preferred plan resource portfolio does not reflect any coal-fired additions, Cheyenne Light will continue to evaluate the appropriateness of building more coal units in the future as demand continues to grow. Cheyenne Light 2011 IRP ES-7

13 175 Figure ES-4 Preferred Plan Resource Additions Preferred Plan Resource Additions Simple Cycle Wind Firm Capacity 100 MW Source: Ventyx The base scenario identified the installation of a 90 MW aeroderivative CT in However, the shaft risk associated with installing a 90 MW aeroderivative CT on a system with a 176 MW peak is significantly higher than the shaft risk associated with three smaller CTs. In addition, the operational flexibility with the aeroderivative is limited when compared to the flexibility that would result from the installation of the three small CTs. It is possible to operate only one small CT at a time and the minimum load on the aeroderivative is higher than running one CT. Although the heat rate (which determines fuel consumption per MWh generated) on the aeroderivative CT is lower than the small CT, the capital cost between the two is comparable: $1,020/kW for the small CT versus $1,016/kW for the aeroderivative and the deterministic PVRR differential is small. Over the long term, the option of converting the small CTs to a combined cycle configuration provides Cheyenne Light the option to reduce the heat rate. The heat rate for each 2 x 1 CC unit would be lower than that expected for either the aeroderivative or the small CTs and Cheyenne Light customers would benefit from the increased efficiency. To deal with load growth uncertainty, to enable expansion possibilities, to mitigate shaft risk, and to handle future environmental regulation, Cheyenne Light senior management has selected the scenario that includes the installation of three small CTs in 2014 as the preferred plan. Cheyenne Light 2011 IRP ES-8

14 ES.12 Conclusion This IRP provides a road map to define the system upgrades, modifications, and additions that are required to ensure reliable and least cost electric service to Cheyenne Light s customers now and into the future. The resources selected in the preferred plan balance cost with the need to mitigate risk and provide for operational flexibility for Cheyenne Light. The preferred plan meets Cheyenne Light s objectives to: Ensure a reasonable level of price stability for its customers Generate and provide safe, reliable electricity service while complying with all environmental standards Manage and minimize risk Continually evaluate renewables for our energy supply portfolio, being mindful of the impact on customer rates. Cheyenne Light 2011 IRP ES-9

15 1.0 Introduction 1.1 Company Background Cheyenne Light, Fuel and Power Company (Cheyenne Light) serves approximately 39,300 electric customers and 34,500 natural gas customers in Cheyenne and a large portion of Laramie County, Wyoming, including natural gas service to Pine Bluffs, Burns, and Carpenter in eastern Laramie County, Wyoming. Cheyenne Light set its all time peak of 176 MW in the winter of 2008, then, matched that peak in the summer of Cheyenne Light was included in the integrated resource planning (IRP) modeling for both the 2005 IRP and the 2007 IRP, although both IRPs reflected a preferred plan that was predicated on combining the generation resources of Cheyenne Light with Black Hills Power. The 2005 IRP was part of the Certificate of Public Convenience and Necessity (CPCN) filing for the coal fired power plant Wygen II, before the Wyoming Public Service Commission (WPSC). The Wygen II plant is a Cheyenne Light rate-based resource. The 2007 IRP was part of the CPCN filing for the coal fired power plant Wygen III, before the WPSC. The Wygen III resource is a Black Hills Power rate-based resource. Since the 2007 IRP was completed, several important changes have occurred in the electric utility industry: While natural gas prices continue to be volatile, the recent emergence of shale gas has introduced relative stability into natural gas pricing. However, there is much for the industry to learn with respect to the future of shale gas production and its expected influence on future natural gas pricing. Just a few years ago the enactment of carbon cap and trade or similar carbon reduction legislation appeared imminent; in early 2011 that no longer appears to be the case. Such enactment is exceedingly dependent on politics and the political party in power in Washington, DC. Clean Air and other regulations being promulgated by the Environmental Protection Agency are expected to cause many retirements of small, older coalfired units around the country. The effects of the earthquake and tsunami in Japan in March 2011 are expected to impact market prices for electricity over the planning horizon and eventually impact the operation of existing and construction and operation of proposed nuclear units in the U.S. 1.2 Objectives The IRP was completed to provide a road map for defining the appropriate system upgrades, modifications, and additions required to ensure reliable and economic service to Cheyenne Light s customers now and into the future. This IRP addresses resource needs for Cheyenne Light for the planning horizon. The IRP examined the Cheyenne Light 2011 IRP 1

16 needs of those customers with a thorough consideration of generation, including renewable energy and short-term purchased power. Prudent utility practices were employed in the preparation of the IRP and a full range of practical resource alternatives, including renewables, were evaluated. Comprehensive modeling was undertaken using Ventyx Capacity Expansion and Strategic Planning powered by MIDAS Gold software modules (see Appendix A). The Ventyx modeling included 1) optimization of resource selection using linear programming techniques, 2) in-depth modeling of resource portfolios using production costing models, and 3) risk analysis using stochastic techniques. The preferred plan meets Cheyenne Light s objectives to: Ensure a reasonable level of price stability for its customers Generate and provide safe, reliable electricity service while complying with all environmental standards Manage and minimize risk Continually evaluate renewables for an energy supply portfolio, being mindful of the impact on customer rates 1.3 IRP Process In preparing this IRP, Cheyenne Light conformed with the Wyoming Public Service Commission Guidelines Regarding Electric IRPs, including hosting a stakeholder meeting on February 10, 2011, in Cheyenne, Wyoming. The comments and feedback provided during the meeting were incorporated in the IRP analysis, as appropriate. None of the comments or feedback had a material impact on the IRP process or final results. Cheyenne Light 2011 IRP 2

17 2.0 Planning Environment Planning for future generating resources in the electric utility industry involves the consideration and evaluation of many uncertainties. Those uncertainties have increased in number and magnitude over the last several decades. Cheyenne Light has considered the impacts of uncertainties that include the future of coal-fired generation, grid modernization, plug-in hybrid electric vehicles, and new transmission construction. The following discussion regarding the future of coal-fired generation touches on climate change legislation, carbon capture and sequestration technologies, and environmental regulatory requirements. 2.1 The Future of Coal-Fired Generation For many years, most of the base load energy needs in this country have been provided by coal-fired generation. As a fuel, coal has many merits: It is dense (meaning it has a high heating value in a compressed space) There are extensive and efficient supply chains that have been built over many decades It is relatively low cost and has experienced much less price volatility than other fuels. Coal is also quite abundant in this country (the estimated supply is hundreds of years of usage), helping to ensure national energy security. One of the on-going issues surrounding coal as a fuel for electricity generation is that it produces more carbon dioxide (CO 2 ) emissions per unit of energy output than any other fuel about twice as much as natural gas. CO2 is a greenhouse gas that is often cited as one of the causes of global climate change. Today the future of coal-fired generation for electric utilities is a major uncertainty. Coal faces competitive pressure from natural gas in the short term and in the long term from renewable resources or other emerging technologies. But coal plants continue to be built in developing nations, particularly China. Some sources report that China is, on the average, adding one new 500 MW coal plant per week. It took many decades to build up the current infrastructure of coal-fired power plants in the U.S., so existing coal-fired generation will continue to be a large producer of electricity during the 20-year planning horizon of this IRP and beyond. Carbon capture and sequestration (CCS) has yet to be proven on a commercial scale and may or may not be practical in any given location depending on the geology at the site Climate Change Legislation The effects of greenhouse gases on the atmosphere and on the Earth s climate have been a subject of debate in the U.S. and worldwide for many years. On May 19, 2010, the National Research Council, an arm of the National Academies, issued three reports that Cheyenne Light 2011 IRP 3

18 concluded global climate change is occurring and that it is caused in large part by human activities. The reports recommend some form of carbon pricing system as the most costeffective way to reduce emissions. The reports posit that cap-and-trade, taxing emissions or some combination of the two could provide the needed incentive to reduce the carbon emissions. The reports further state that major technological and behavioral changes will be required; business as usual will not address the climate change issue. Among those changes, the reports recommend the capturing and sequestering of CO 2 from power plants and factories as well as scrubbing CO 2 directly from the atmosphere. How these reports will be translated into regulation and laws at the local, state and national levels remain to be seen, continuing this uncertainty in the planning period of Cheyenne Light s IRP. Cheyenne Light cannot predict if any particular carbon mitigation strategy will be enacted into law or when such might occur. The Fall 2010 Fall Reference Case from Ventyx no longer includes carbon costs in its base case. However, Cheyenne Light did consider levels of potential carbon regulation in the future in its risk analysis for this IRP Carbon Capture and Sequestration Technologies 2 Carbon capture and sequestration (CCS) technologies are currently being researched and tested in an effort to remove CO 2 from the atmosphere. Carbon capture is defined as the separation and entrapment of CO 2 from large stationary sources including power plants, cement manufacturing, ammonia production, iron and non-ferrous metal smelters, industrial boilers, refineries, and natural gas wells. Carbon sequestration means the capture and secure storage of CO 2 that would otherwise be emitted to or remain in the atmosphere. CO 2 can also be removed from the atmosphere through what is termed enhancing natural sinks by increasing its uptake in soils and vegetation (reforestation) or in the ocean (iron fertilization). CO 2 capture processes fall into three general categories: (1) flue gas separation, (2) oxyfuel combustion in power plants, and (3) pre-combustion separation. Each process has associated economic (cost) and energy (kwh) penalties. For flue gas separation, the capture process is typically based on chemical absorption where the CO 2 is absorbed in a liquid solvent by formation of a chemically bonded compound. The captured CO 2 is used for various industrial and commercial processes such as the production of urea, foam blowing, carbonated beverages, and dry ice production. Other processes being examined for CO 2 capture from the flue gas include membrane separation, cryogenic fractionation, and adsorption using molecular sieves. An alternative to flue gas separation is to burn the fossil fuel in pure or enriched oxygen. The flue gas will then contain mostly CO 2 and water vapor. The water vapor can be condensed and the CO 2 can be compressed and piped directly to a storage site. Whereas for flue gas separation, the separation took place after combustion, now the separation 2 Howard Herzog and Dan Golomb, Carbon Capture and Storage from Fossil Fuel Use, as published in the Encyclopedia of Energy, Cheyenne Light 2011 IRP 4

19 occurs in the intake air where oxygen and nitrogen need to be separated. The air separation unit alone can impose a 15% efficiency penalty on generation output. Pilot scale studies have indicated that this method of carbon capture can be retrofitted on existing pulverized coal units. Pre-combustion capture is usually applied in coal gasification combined cycle power plants. The process involves gasifying the coal to produce a synthetic gas. That gas reacts with water to produce CO 2 and hydrogen fuel. The hydrogen fuel is used in the turbine to produce electricity and the CO 2 is captured. Once the CO 2 is captured, it must be stored in a manner in which it will not be emitted back into the atmosphere. Such storage needs to be: 1) long-term, preferably hundreds to thousands of years, 2) at minimal cost including transportation to the storage site, 3) with no risk of accident, 4) with minimal environmental impact, and 5) without violating any national or international laws or regulations. Potential storage media include geologic sinks and the deep ocean. Geologic sinks include deep saline formations (subterranean and sub-seabed), depleted oil and gas reservoirs, enhanced oil recovery, and unminable coal seams. Deep ocean storage includes direct injection into the water column at intermediate or deep depths. If CO 2 is regulated (either via cap and trade or a tax) with an associated requirement to significantly reduce CO 2 emissions in the future, CCS will need to be proven as a viable technology in order for coal-fired generation to continue to be a resource option. For purposes of this IRP, Cheyenne Light assumed CCS has not progressed enough to be a viable alternative for this IRP during the entire twenty-year planning horizon Environmental Regulatory Requirements Cheyenne Light personnel are closely monitoring environmental regulations and requirements to determine what actions need to be undertaken to ensure compliance and to understand the costs associated with compliance. Among other issues, Cheyenne Light is currently tracking issues relating to ozone; sulfur dioxide (SO 2 ); nitrogen dioxide (NO 2 ); the Clean Air Interstate Rule (CAIR) and its impending replacement rule, the Clean Air Transport Rule (CATR); water; particulate matter, specifically for 2.5 micrometers (PM 2.5 ); the Coal Combustion Residuals (CCR) rule relating to ash; mercury and hazardous air pollutants (Hg/HAPS); and CO 2, (see Figure ). 3 Generating Buzz, Power Engineering, July 2010, p. 80. Cheyenne Light 2011 IRP 5

20 Figure 2-1 Possible Timeline for Environmental Regulatory Requirements for the Utility Industry Revised Ozone NAAQS Beginning CAIR Phase I Seasonal NOx Cap CAIR Vacated CAIR Remanded Ozone Reconsidered Ozone NAAQS NO2 Primary NAAQS SO2 Primary NAAQS Proposed CAIR Replacement Rule Expected CO2 Regulation SO 2 /NO 2 Final CAIR Replacement Rule Expected Effluent Guidelines proposed rule expected SO2/NO2 Secondary NAAQS CAIR 316(b) final rule expected Effluent Guidelines Final rule expected Water Next Ozone NAAQS Revision 316(b) Compliance 3-4 yrs after final rule Effluent Guidelines Compliance 3-5 yrs after final rule '08 '09 '10 '11 '12 '13 '14 '15 '16 '17 CAMR & Delisting Rule vacated PM-2.5 SIPs due ( 97) Begin CAIR Phase I Annual NOx Cap Begin CAIR Phase I Annual SO2 Cap Proposed Rule for CCBs Management PM2.5 Next PM- Final 2.5 Rule for NAAQS CCBs Revision Mgmt HAPs MACT proposed rule 316(b) proposed rule expected HAPS MACT final rule expected Final EPA Nonattainment Designations Ash PM-2.5 SIPs due ( 06) New PM-2.5 NAAQS Designations Begin Compliance Requirements under Final CCB Rule (ground water monitoring, double monitors, closure, dry ash conversion) Compliance with CAIR Replacement Rule Hg/HAPS Beginning CAIR Phase II Annual SO2 & NOx Caps HAPS MACT Compliance 3 yrs after final rule CO 2 Beginning CAIR Phase II Seasonal NOx Cap -- adapted from Wegman (EPA 2003) Updated Cheyenne Light 2011 IRP 6

21 The uncertainty related to the myriad of rules expected from the U.S. Environmental Protection Agency (EPA) is significant. The American Public Power Association (APPA) projects that the coal-fired power sector will see near-constant retrofits from 2012 through 2018, competition for scarce engineering and construction services and equipment, large-scale unit retirements, possible shortfalls in reserve margin requirements, an increase in natural gas generation, and a worrisome chance that financial resources could be misallocated and investments left stranded. 4 APPA believes that the EPA hopes to force closure of 50% of the fleet of coal-fired generating units in the U.S. in the next 10 years which would reduce the CO 2 emissions by a commensurate 50%. The cost of such a transition is in the hundreds of billions of dollars Grid Modernization The term Grid Modernization or Smart Grid is frequently used in discussions among government agencies, equipment manufacturers, and the utility industry. However, the definition of that term varies significantly depending on who is leading the discussion. For Cheyenne Light s purposes in preparing this IRP, Smart Grid will mean integrating the electrical infrastructure with the communications network. This will lead to an automated electric power system that monitors and controls grid activities, ensuring twoway flow of electricity and information between power plants and consumers and all points in-between. Such an enhanced system will facilitate: 6 improved electricity flows from power plants to consumers consumer interaction with the grid improved response to power demand reduced incidence of generation resource outages more consistent and reliable power quality increased reliability and security more efficient overall operation Some of the technologies that will be required in order for the U.S. to realize this vision for the grid of the future include: 7 Smart meters for advanced measurement Integrated two-way communications Active customer interface including home area networks with in-home displays 4 Eric Wagman, Expect a Mess as EPA Rules Take Hold, Power Engineering, July 2010, p Ibid. Edison Electric Institute, Potential Impacts of Environmental Regulation in the U.S., January Smart Grid basics, Wotruba, Bill, Enabling the Smart Grid, Power Engineering, May 2010, p Joe Miller, Horizon Energy Group, The Smart Grid How do we get there? Get_There-452.html. Cheyenne Light 2011 IRP 7

22 Meter data management systems Distribution management system with advanced and ubiquitous sensors Distribution geographical information system Substation automation including sensors to monitor transformers, relays, digital fault recorders, breakers, and station batteries Advanced protection and control schemes Advanced grid control devices The enhancements of the electricity infrastructure in this manner are expected to lead to many benefits including active management and control of electricity generation, transmission, distribution and usage in real time; an optimal balance between supply and demand; reduced numbers of outages; more consistent and reliable power quality; increased reliability and security; and more efficient overall operation, among others. 8 Reduced incidence of outages. Modern grids will lead to embedded automation and control devices. Thus energy producers and the operators of the transmission and distribution systems will be able to anticipate, detect, and respond to system problems more quickly than is possible with the technology in place currently. More consistent and reliable power quality. When supply and demand are more optimally balanced, operation will be leaner and more efficient which in turn leads to higher levels of customer service. Increased reliability and security. With the capabilities of the enhanced communication system and associated real-time monitoring, power companies will have increased visibility of the entire generation, transmission, and distribution systems and thus an increased ability to resist both physical threats and cyber attacks. Operations that are networked tend to have increased reliability and reduced expensive downtime. The modern grid may also increase redundancy, in turn, leading to fewer service disruptions. More efficient overall operation. The modern grid should reduce bottlenecks and relieve grid congestion. Fewer outages and less congestion may lead to lower costs to customers and, potentially, fewer emissions. Cheyenne Light has completed installation of advanced metering infrastructure (AMI) on all its residential and commercial customers. 2.3 Plug-in Hybrid Electric Vehicles Electric vehicles, and their associated battery technology, have been under development for several decades. Today s hybrid electric vehicles, available for purchase by the mass market and part of the rental car fleet, have significantly advanced the likelihood that such cars can be a commercial success and not just an oddity. Hybrid electric vehicles recharge themselves as they are still fueled by gasoline or similar fuel. The next step in the evolution of personal transportation appears to be plug-in hybrid electric vehicles 8 Smart Grid basics, Wotruba, Bill, Enabling the Smart Grid, Power Engineering, May 2010, p. 52. Cheyenne Light 2011 IRP 8

23 (PHEV) and plug-in electric vehicles, which are dependent on advances in battery technology. This evolutionary step could have significant impacts on the electric utility industry. PHEVs will require charging, presumably daily. Without a modernized grid, or a smart plug, the PHEVs could recharge during on-peak periods, thus increasing an electric utility s load and potentially causing the need for new generating capacity. A smart plug would only allow charging during a utility s off-peak hours. In addition, PHEVs represent what transmission planners call mobile loads. This means that the car might be charged at home, at the office, at the mall, or any other location. Such flexibility for the customer will require accommodation through the design or redesign of the transmission and distribution systems which have yet to occur on any utility system in the country including Cheyenne Light s. No changes to the load forecast or modifications to the transmission and distribution plans are contained in this IRP as would be necessary to accommodate widespread adoption of PHEVs in Cheyenne Light s service territory. 2.4 New Transmission Construction If the Energy Gateway project is successfully completed by PacifiCorp 9 (portions of which have been constructed or are already under construction), the energy market in Wyoming may be significantly altered from what exists today. This significant expansion of the existing electricity infrastructure in the West will transverse portions of Wyoming, Colorado, Utah, Montana, Idaho, Washington, and Oregon although it is not expected to impact any existing transmission constraints that limit the export of power from the Gillette, Wyoming area. Cheyenne Light may have additional access to transmission services and markets through this transmission expansion. The potential opening of additional markets and the ability to send larger amounts of renewable energy around the Western Electricity Coordinating Council (WECC) may increase or decrease the economy energy available to Cheyenne Light and increase or decrease the price of that energy. Price and availability of energy will be dependent on many factors that Cheyenne Light will monitor. 9 Idaho Power is a partner with Rocky Mountain Power (a subsidiary of PacifiCorp) on the Gateway West portion of the Energy Gateway project. Other portions of the project include Gateway South and Gateway Central. Cheyenne Light 2011 IRP 9

24 3.0 Assumptions A wide variety of data assumptions must be made for IRP modeling. Key assumptions described in the following paragraphs include coal price forecasts, natural gas price forecasts, market price forecasts, financial parameters, planning reserves, and emissions costs. The Ventyx 2010 Fall Reference Case for the Western Electricity Coordinating Council (WECC) was used for the long-term natural gas and electric price forecasts. The load and energy forecast is described in its own section of the report that follows this one. 3.1 Coal Price Forecasts Cheyenne Light used a coal price forecast that reflects the cost currently incurred for fuel from the Wygen II coal-fired generating unit. The prices as of May 2010 are shown in Table Natural Gas Price Forecasts Table 3-1 Coal Price Forecast Year $/MMBtu Cheyenne Light used the natural gas price forecasts from the Ventyx 2010 Fall Reference Case. The Henry Hub values were adjusted for transportation costs to more accurately reflect the price of natural gas as actually delivered to Cheyenne Light generating facilities located in Cheyenne, Wyoming. The Henry Hub natural gas prices are shown monthly in Table 3-2 and Figure 3-1. Cheyenne Light 2011 IRP 10

25 Table 3-2 Monthly Henry Hub Natural Gas Prices ($/MMBtu) Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Source: Ventyx Figure 3-1 Natural Gas Price Forecast - Henry Hub $/MMBtu Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23 Jan-24 Jan-25 Jan-26 Jan-27 Jan-28 Jan-29 Jan-30 Year Source: Ventyx 3.3 Market Price Forecasts Electricity price estimates for the Wyoming region were derived from Ventyx s 2010 Fall Reference Case and are the basis on which Cheyenne Light s market transactions were priced. The on-peak electricity prices for Wyoming are shown in Figure 3-2. Values are Cheyenne Light 2011 IRP 11

26 shown for the four scenarios that require the development of correlated natural gas and market prices base, environmental, low gas and high gas. The descriptions for these scenarios are found in Section 7.0. Figure 3-2 Reference Case On-Peak Electricity Prices Wyoming Region $/MWh Financial Parameters Base Environmental High Gas Low Gas Source: Ventyx The financial parameters used in this IRP are summarized in Table 3-3. Table 3-3 Financial Parameters Component Annual Rate (%) Interest Rate 6.25 Discount Rate* 7.41 Income Tax Rate 35 Rate of Escalation 2.5 Capital Structure Equity 52 Debt 48 Wyoming Property Tax Rate 0.35 Wyoming 20-year Fixed Charge Rate Wyoming 30-year Fixed Charge Rate Wyoming 50-year Fixed Charge Rate 9.95 *After tax weighted average cost of capital Cheyenne Light 2011 IRP 12

27 A discount rate of 7.41% was used to examine the present value of revenue requirements (PVRR) in this analysis. Levelized fixed charge rates applied to the capital costs for new resources examined in the IRP included 9.95% for future coal investments, 10.91% for combined cycle investments, 11.05% for solar and wind investments, and 10.91% for combustion turbines. Book lives of 50 years were used for coal, 30 years for combined cycle and combustion turbines, and 20 years for wind and solar. Tax lives of 20 years were used for coal, combined cycle, and combustion turbines. A tax life of 5 years was used for solar and wind. 3.5 Planning Reserves Planning reserve margin is defined as the additional capacity required in excess of a utility s peak forecasted demand to ensure resource adequacy for a reliable generation portfolio. Historically around the country, the level of planning reserve margin has generally varied from 15% to 20%. A minimum planning reserve margin of 15% was used in this IRP which is consistent with what other utilities use in the western region and is generally regarded as prudent utility practice. Cheyenne Light recognizes that as a standalone system, its reserve margin requirement is higher than the 15% reserve margin assumption. Cheyenne Light anticipates negotiating a reserve sharing agreement with Black Hills Power in an effort to manage its reserve requirements and maintain a reliable system. 3.6 Emission Costs No carbon taxes are assumed in Ventyx s 2010 Fall Reference Case and thus no carbon taxes are assumed to be put in place during the planning horizon for the base scenario assumptions. For the environmental scenarios, the carbon taxes developed by Ventyx, starting in 2015 and shown in Table 3-4 were assumed. Cheyenne Light 2011 IRP 13

28 Table 3-4 Carbon Tax Assumption (Environmental Scenarios Only) Year Carbon Tax ($/ton) Source: Ventyx Cheyenne Light 2011 IRP 14

29 4.0 Load Forecast The Cheyenne Light load forecast represents an average annual trended forecast growth rate of 1.5%, and known load additions. The peak demand and energy forecast was developed by trending historical peak demands and annual energy and modifying the result to reflect the load gains projected for the National Center for Atmospheric Research (NCAR) and Swan Ranch development as well as other industrial customers. The 2009 load shape was used to develop the hourly load forecast from the peak demand and annual energy projections. This load forecast assumes no large scale implementation of plug-in hybrid electric vehicles (PHEV) and no changes in the load shape over the planning horizon. The peak demand and energy forecast values shown in Table 4-1 and Figures 4-1 and 4-2 reflect the losses that need to be provided to the Western Area Power Administration under the Network Integration Transmission System agreement (NITS). Table 4-1 Cheyenne Light Peak Demand and Energy Forecast Year Peak Demand Growth in Peak Annual Energy Growth in Annual Load Factor (%) (MW) Demand (%) (MWh) Energy (%) ,136, ,262, ,334, ,395, ,416, ,438, ,459, ,481, ,503, ,526, ,549, ,572, ,596, ,620, ,644, ,669, ,694, ,719, ,745, ,771, Source: Ventyx Cheyenne Light 2011 IRP 15

30 400 Figure 4-1 Cheyenne Light, Fuel and Power 7-Year Historical and 20-Year Forecasted Peak 350 Annual Peak (MW) Trended Growth Rate: 1.5% 80% Confidence Band: +/-.5% Trended Load Factor: 71.1% Source: Ventyx 2,500,000 Figure 4-2 Cheyenne Light, Fuel and Power 7-Year Historical and 20-Year Forecasted Energy Annual Energy (MWh) 2,000,000 1,500,000 1,000, ,000 Trended Growth Rate: 1.5% 80% Confidence Band: +/-.5% Source: Ventyx Table 4-2 provides a side-by-side comparison of the values projected for peak demand and annual energy in the 2005 IRP, the 2007 IRP, and in the forecast prepared for this 2011 IRP. The forecast from the 2007 IRP reflects a very strong economy and thus a Cheyenne Light 2011 IRP 16

31 higher load growth than is seen for the 2011 IRP. This most recent forecast reflects the economic downturn and the resulting effects. Table 4-2 Load Forecast Comparison 2005 IRP 2007 IRP 2011 IRP Year Peak Annual Peak Annual Peak Annual Demand Energy Demand Energy Demand Energy ,052, * 984,865* ,068, * 1,001,911* ,084, * 1,042,332* ,100, ,055, * 1,071,842* ,117, ,156, * 1,109,305* ,133, ,190, * 1,101,315* ,150, ,223, ,136, ,168, ,279, ,262, ,185, ,324, ,334, ,203, ,372, ,395, ,221, ,407, ,416, ,239, ,443, ,438, ,479, ,459, ,516, ,481, ,554, ,503, ,592, ,526, ,632, ,549, ,673, ,572, ,715, ,596, ,758, ,620, ,644, ,847, ,669, , ,694, ,719, ,745, ,771,487 * Actual historic data used by Ventyx to create load forecast Cheyenne Light 2011 IRP 17

32 5.0 Demand-Side Management In its April 30, 2010 report titled 3 Year Energy Efficiency Plan, Cheyenne Light documented the energy efficiency programs that will be implemented in its service territory. In the context of an IRP, such programs are generally referred to as demandside management or DSM. In this section of the IRP report, only the programs that are being implemented for electric customers and their effects on peak demand and/or energy are presented. The residential electric portfolio offers customers opportunities to save energy with lighting, electric water heating, and second refrigerator turn-in programs. This portfolio also offers an energy audit program. The commercial electric portfolio provides both a prescriptive rebate program and a custom rebate program. A brief description of each program is provided below. 5.1 Residential Space and Water Heating This program offers rebates to Cheyenne Light residential customers when they replace existing electric tank water heaters with high-efficiency models or when they install highefficiency electric tank water heaters in new single-family dwellings. The incentive is $75 per water heater. 5.2 Refrigerator Pick Up Program The Refrigerator Pickup Program will encourage residential or small business customers to turn in old inefficient refrigerators. As part of the program, an incentive will be given to the customer. Initially, a $30 payment will be offered per qualifying unit. The contractor will handle scheduling, transportation and disposal. The contractor will also provide nameplate data on units to assist in impact evaluation. Goals of approximately 800 units for year 1, 825 units for year 2 and 850 units for year 3 have been established. 5.3 Residential High-Efficiency Lighting This program offers residential customers the ability to purchase up to ten ENERGY STAR qualified compact fluorescent lamps (CFL) at a local retailer at a reduced cost. Specific rebate levels will be determined through arrangements negotiated with retailers in the service territory. Rebates would be available for different wattage sizes, different configurations (standard and recessed), different styles (3-way), and so forth. Rebate levels may vary depending upon the type of CFL and its associated retail cost. 5.4 Residential Energy Audit This program will provide on-site audits to customers. The objective of the audit program is to provide recommendations to customers about ways they can reduce the energy consumption in their homes. Audit recommendations may include suggested behavioral changes, suggestions about implementing low-cost and easy to install energy- Cheyenne Light 2011 IRP 18

33 saving measures, and suggestions about repairing, upgrading, or replacing larger, relatively expensive equipment or systems. The audit program will be delivered by trained professionals where eligible measures will be installed or left with the customer. In addition, an on-line audit will be made available to customers. Eligible measures include power cost monitors (as part of a pilot program), weather stripping around doors and windows, door sweep(s), hot water heater blanket, hot water pipe insulation, furnace filter replacement, low flow showerheads, faucet aerators, and CFLs. 5.5 Commercial/Industrial Prescriptive Rebates This program provides rebates of pre-determined amounts, also known as prescriptive rebates, to commercial and industrial customers to replace similar, less energy-efficient equipment. Eligible electric system measures include lighting, motors, variable speed drives, ventilation, and cooking equipment. 5.6 Commercial/Industrial Custom Rebates This program is designed to buy down energy-efficient upgrades to a two-year payback or, alternatively, it covers up to one-half of the incremental cost of the equipment. Specifically, this program provides incentives for the installation of energy-efficient electric equipment not specified in the prescriptive rebate program. Generally, this includes measures for which there would be a wide variation in cost, depending on the specifics of the facility. 5.7 Total Electric DSM Portfolio The projected program participation and impacts for years 1 through 3 of the program are shown on Tables 5-1 through 5-3. Program Name Table 5-1 DSM Electric Program Portfolio Year 1 Annual Demand Participation Goal Savings Year 1 Annual Program Impacts (kwh) (kw) Water Heating ,716 Refrigerator Pick-Up Program ,078 Lighting 3, ,370,948 Energy Audit ,786 Residential Total 4, ,421,528 C/I Prescriptive Rebate ,860,677 C/I Custom Rebate ,178,610 Total C/I ,039,286 TOTAL 4, ,460,814 Cheyenne Light 2011 IRP 19

34 Program Name Table 5-2 DSM Electric Program Portfolio Year 2 Annual Demand Participation Goal Savings Year 2 Annual Program Impacts (kwh) (kw) Water Heating ,716 Refrigerator Pick-Up Program ,111 Lighting 3, ,621,699 Energy Audit ,786 Residential Total 4, ,697,312 C/I Prescriptive Rebate ,012,914 C/I Custom Rebate ,414,332 Total C/I ,427,246 TOTAL 4, ,124,557 Program Name Table 5-3 DSM Electric Program Portfolio Year 3 Annual Demand Participation Goal Savings Year 3 Annual Program Impacts (kwh) (kw) Water Heating ,894 Refrigerator Pick-Up Program ,145 Lighting 4, ,842,820 Energy Audit ,786 Residential Total 5, ,951,645 C/I Prescriptive Rebate ,300,473 C/I Custom Rebate ,414,332 Total C/I ,714,805 TOTAL 5,521 1,041 6,666,450 The program budgets for Year 1 are shown on Table 5-4. Table 5-4 DSM Program Budgets Year 1 Sector Program Budget Allocation Residential High Efficiency Space Heat and $12,600 Water Heat Residential Refrigerator Pick-Up Program $136,000 Residential High-Efficiency Lighting $31,000 Residential Energy Audit $27,463 TOTAL RESIDENTIAL $207,063 Commercial/Industrial Prescriptive Rebate $345,230 Commercial/Industrial Custom Rebate $206,250 TOTAL C/I $551,480 TOTAL $758,543 Cheyenne Light 2011 IRP 20

35 The program budgets allocated to program expenditure categories are shown on Table 5-5 for the electric program portfolio. Table 5-5 DSM Program Budget Allocation Year 1 Administration Delivery Marketing Incentives Evaluation Total $70,600 $151,163 $71,800 $418,080 $46,900 $758,543 A summary table for all three years of the DSM program portfolio is shown as Table 5-6, including the results of the Total Resource Cost (TRC) test. The participation, demand savings, and kwh savings for the programs cumulate. Thus in Year 3, the total participation, kw savings, and kwh savings equal Year 1 + Year 2 + Year 3. Total demand savings in Year 3 is approximately 3 MW, assuming that all savings would occur at the time of the system peak. These demand savings have been subtracted from the peak demand in the load forecast (and the peak demand used in the modeling) as shown in the Load and Resource Summary balance for the Preferred Plan in Appendix B. Table 5-6 DSM Program Portfolio Summary Year Proposed Budget TRC Participation kw Savings kwh Savings 1 $758, , ,460,814 2 $814, , ,124,557 3 $887, ,521 1,041 6,666,450 Total $2,460,509 Cheyenne Light 2011 IRP 21

36 6.0 Supply-Side Resources 6.1 Existing Resources The resources available to Cheyenne Light to meet customer obligations include coalfired units and long-term power purchase agreements (PPA) as shown in Table 6-1. Resources committed under the PPAs include coal, natural gas, and wind. Wygen I (coal), Wygen II (coal), and the Neil Simpson CT (natural gas) are located in the Gillette, Wyoming area. Happy Jack and Silver Sage are wind resources located in the Cheyenne, Wyoming area. Table 6-1 Cheyenne Light Existing Resources Power Plant Fuel Capacity Start Date Type (MW)**** Wygen II Coal Long-Term Power Type Capacity Start End Term Purchase Agreements (MW)**** Date Date Wygen I Firm ** 10 Neil Simpson CT 2 Firm *** 3 Happy Jack Firm 15* Silver Sage Firm 10* TOTAL *The accredited capacity for each of the wind PPAs (Happy Jack and Silver Sage) is 10% of the total capacity. **In the RP modeling, the Wygen I PPA was assumed to be replaced in kind after expiration. ***Federal Energy Regulatory Commission (FERC) has approved a contract extension through August 31,2014 **** All capacity shown as net capacity 6.2 New Conventional Resources A variety of conventional supply-side resources were examined and considered in preparing this IRP. These include coal, different configurations of natural gas-fired combined cycle, several types of natural gas-fired simple cycle combustion turbine, and a firm market purchase. A brief description of each type of resource and the cost and other parameters used for modeling are described below Coal New pulverized coal-fired units were modeled and are assumed to be located in the Gillette, Wyoming area near the Wyodak plant site. Each new unit is rated at 100 MW at the time of the summer system peak. Data used for modeling new coal-fired units are shown in Table 6-2. Cheyenne Light 2011 IRP 22

37 6.2.2 Combined Cycle Table 6-2 Coal-Fired Power Plant Performance Parameters Parameter Value Size, MW (net) summer 100 Size, MW (net) winter 100 Full load heat rate, Btu/kWh 11,500 Fixed O&M, $/kw-year (2010 $) Variable O&M, $/MWh (2010 $) 4.00 Capital Cost, $/kw (2010 $) 2,627 In a combustion turbine combined cycle facility, the hot exhaust gases from the combustion pass through a heat recovery steam generator (HRSG). The steam generated by the HRSG is expanded through a steam turbine, which, in turn, drives an additional generator. Combustion turbine combined cycle systems typically burn natural gas and are available in a variety of sizes and configurations. One or more combustion turbines may exhaust to a single HRSG and generator. Parameters used to model several different configurations of a combined cycle (CC) facility as a resource are shown in Table 6-3. These resources include a 1 x 1 (one combustion turbine and one HRSG) combined cycle unit with duct firing (DF), a 2 x 1 (two combustion turbines and one HRSG), and a 3 x 1 (three combustion turbines and one HRSG). Table 6-3 Combined Cycle Power Plant Performance Parameters Parameter 1 x 1 DF 2 x 1 3 x 1 Size, MW (net) - summer Size, MW (net) - winter Full load heat rate, Btu/kWh 8,168 7,547 7,562 Fixed O&M, $/kw-year (2010 $) Variable O&M, $/MWh (2010 $) Capital Cost, $/kw (2010 $) 1,427 1,372 1, Combustion Turbine Combustion turbines (CT) typically burn natural gas and/or No. 2 fuel oil and are available in a wide variety of sizes and configurations. Combustion turbines are generally used for peaking and reserve purposes because of their relatively low capital costs, higher full load heat rate, and the higher cost of fuel when compared to conventional base load capacity. Combustion turbines have the added benefit of providing quick-start capability in certain configurations. An additional benefit is that combustion turbines can be installed in stages and converted to combined cycle operation at a later point in time. Certain combustion turbines can regulate for wind generation as Cheyenne Light 2011 IRP 23

38 well. Parameters used to model several different configurations of combustion turbines as a resource are shown in Table 6-4. Table 6-4 Combustion Turbine Power Plant Performance Parameters Parameter Small CT Large CT Aeroderivative CT Size, MW (net) - summer Size, MW (net) - winter Full load heat rate, Btu/kWh 9,566 10,500 9,000 Fixed O&M, $/kw-year (2010 $) Variable O&M, $/MWh (2010 $) Capital Cost, $/kw (2010 $) 1, , Firm Market Purchase Cheyenne Light has assumed that, due to its small size relative to the market, it will be able to purchase firm market power in July and August. This stopgap measure covers its peak demand shortfall and defers the need to install new resources until the need for capacity extends to multiple months. The product would be firm power available 6 x 16 (six days per week, sixteen hours per day for all on-peak hours). The model is able to select the firm market power in blocks, up to a total of 50 MW (two blocks). The energy cost is the forecasted cost of energy at Palo Verde. The block size has been selected based on the minimum size of the blocks of power typically available for this type of product in the market. 6.3 New Renewable Resources Renewable resources considered in this IRP included solar photovoltaics and wind Photovoltaics A 10 MW solar photovoltaic (PV) generation facility was available as one of the renewable options. A PV or solar cell is made of semiconducting material, typically wafer-based crystalline silicon technology, configured such that when sunlight hits the cells, the electrons flow through the material and produce electricity. Usually, about 40 solar cells are combined to form a module. Modules can be characterized as flat plate or concentrator systems. About 10 modules make up a flat plate PV array. Approximately ten to twenty arrays would be required to provide enough electricity for a typical household. Parameters used to model PV are shown in Table 6-5. Cheyenne Light 2011 IRP 24

39 Table 6-5 PV Performance Parameters Parameter Value Size, MW (net) summer and winter 10 Fixed O&M, $/kw-year (2010 $) Capital Cost, $/kw (2010 $) 6, Wind Wind turbines use their blades to collect the kinetic energy of the wind. The blades are connected to a drive shaft that turns an electric generator to produce electricity. Wyoming is ranked seventh in terms of wind energy potential among the 50 states with the possibility to develop 85,000 MW. Parameters used to model wind in this IRP are shown in Table 6-6. Table 6-6 Wind Performance Parameters Parameter Value Size, MW (net) summer and winter 30 Fixed O&M, $/kw-year (2010 $) Capital Cost, $/kw (2010 $) 1,530 The model input assumed a federal Production Tax Credit of $.022 kwh (2010$) for units on-line before Cheyenne Light 2011 IRP 25

40 7.0 Resource Need Assessment The Cheyenne Light system is expected to experience load growth of approximately 1.5% per year. Over the planning horizon, all of Cheyenne Light s PPAs expire. An assumption of this IRP is that the PPA for Wygen I is replaced in kind at the time of its expiration. The Happy Jack and Silver Sage PPAs expire in 2028 and 2029, respectively. The totality of the requirements for new resources, incorporating the need for a minimum planning reserve margin of 15% and reflecting that Cheyenne Light has no future committed resources in its generation portfolio, is shown on Figure 7-1. The capacity deficit in any year is reflected as the distance between the line labeled Peak Demand + 15% Reserves and the top of the shaded blocks for Existing Resources. The capacity deficit reaches over 150 MW by the end of the planning horizon. Cheyenne Light recognized that as a standalone system, its reserve margin requirement would be higher than the 15% reserve margin assumption. Cheyenne Light anticipates negotiating a reserve sharing agreement with Black Hills Power in an effort to manage its reserve requirements and maintain a reliable system. 350 Figure 7-1 Cheyenne Light Load and Resource Summary MW Peak Demand + 15% Reserves Existing Resources Capacity Deficit Year 7.1 Analysis The process used to determine the preferred resource portfolio for Cheyenne Light over the planning horizon began by identifying eleven scenarios (also referred to as plans) to run through the Capacity Expansion module. These eleven scenarios are : 1. Base Scenario Wygen I modeled at 60 MW for entire study (PPA replaced in kind at date of expiration) Neil Simpson CT 2 PPA expires September 2014 Happy Jack PPA expires August 2028 Cheyenne Light 2011 IRP 26

41 Silver Sage PPA expires September 2029 Up to 50 MW of firm market purchase is available in July and August in a 6 x 16 product 2. Environmental Scenario Same build assumptions as Base Scenario Assumes CO 2 emission cap begins in 2015; requirement for 80% reduction below 2005 CO 2 emissions levels by 2050 and a national Renewable Portfolio Standard (RPS) begins in and later, the RPS target is 12% of retail sales for utilities with load greater than 4 TWh Natural gas and market prices correlate with carbon prices 3. High Gas Scenario Same build assumptions as Base Scenario Natural gas and market prices correlate with Ventyx high gas scenario (corresponds to limited shale gas supply scenario 90 th percentile of Ventyx probability distribution) 4. Low Gas Scenario Same build assumptions as Base Scenario Natural gas and market prices correlate with Ventyx low gas scenario (corresponds to best shale gas supply scenario 10 th percentile of Ventyx probability distribution) 5. High Load Scenario Same build assumptions as Base Scenario High load forecast (0.5 percentage points higher growth in every year of planning horizon) 6. Low Load Scenario Same build assumptions as Base Scenario Low load forecast (0.5 percentage points lower growth in every year of planning horizon) 7. Step Load Scenario Same build assumptions as Base Scenario 50 MW load increase in 2014 from base load forecast 8. Base Scenario with 2 x 1 combined cycle in 2014 Same build assumptions as Base Scenario Forced in a 2 x 1 combined cycle unit in Base Scenario with No Firm Market Same build assumptions as Base Scenario No Firm Market Purchases in July and August 10. Step Load Scenario with 3 x 1 combined cycle in 2014 Step Load Scenario assumptions Forced in a 3 x 1 combined cycle unit in Three Small CTs in 2014 Same build assumptions as Base Scenario Force on three small CTs in 2014 These scenarios resulted in the resource portfolios shown in Table 7-1. Cheyenne Light 2011 IRP 27

42 Table Optimal Expansion Plans (Net Capacity) Year Base Enviro High Gas 2011 Firm MW MW 2014 Aero 90 MW Wind 30 MW; Firm 2019 Small CT 36 MW Firm 50 MW 50 MW Aero 90 MW Small CT 36 MW Firm 50 MW 50 MW Aero 90 MW Small CT 36 MW Low Gas Firm 50 MW 50 MW Aero 90 MW Small CT 36 MW High Load Firm 50 MW 50 MW Aero 90 MW Small CT 36 MW Wind 60 MW Low Load Firm 50 MW 50 MW Aero 90 MW Wind 30 MW 2023 Wind 30 MW Small CT 36 MW Wind 30 MW; Firm 2029 Small CT 36 MW Wind 30 MW; Firm Small CT 36 MW Small CT 36 MW Small CT 36 MW Firm 2030 Small CT 36 MW Small CT 36 MW Wind 60 MW Step Load Firm 50 MW 50 MW Large CT 160 MW Coal 100 MW 2x Firm 50 MW 50 MW 2x1 CC 92 MW Small CT 36 MW Wind 30 MW Small CT 36 MW Base No Firm Market Firm 50 MW 50 MW Aero 90 MW Small CT 36 MW Wind 30 MW Small CT 36 MW (Source: Ventyx) 3x Step Load Firm 50 MW 50 MW 3x1 CC 137 MW Small CT 36 MW Coal 100 MW 3 CTs 2014 Firm 50 MW 50 MW 3 Small CTs 109 MW Wind 30 MW; Firm Small CT 36 MW Small CT 36 MW Cheyenne Light 2011 IRP 28

43 Each of the resource portfolios were then run through a production cost model, and were modeled with the base case scenario assumptions to determine the relative present value of revenue requirements (PVRR). The PVRR for scenarios 1 through 9 and 11 when run on a deterministic basis are shown on Figure 7-2. As can be seen on the Figure 7-2, with the exception of the step load and low load cases, the PVRRs for the cases are within approximately 2% of each other. $1,400 Figure 7-2 Deterministic PVRR for Scenarios 20 Year PVRR $1,300 Million $ $1,200 $1,100 $1,000 Base Environmental High Gas Low Gas High Load Low Load Step Load 2x No Firm Market 3 SCs 2014 Source: Ventyx Cheyenne Light 2011 IRP 29

44 8.0 Risk Analysis Utilities must plan for future customer needs for electricity in an environment of significant uncertainty. Thus, the analysis conducted for this IRP examined uncertainty under a variety of possible future conditions. Analyses conducted to quantify the risk associated with the various scenarios included stochastic analysis, and specific examination of 1) the effects of a step load increase in the Cheyenne Light demand for electricity, 2) the effects of not having a market available for economy interchange, and 3) the effects of the environmental scenario on the preferred resource portfolio. 8.1 Stochastic Analysis Ventyx s Strategic Planning model uses a structural approach to forecasting prices that captures the uncertainties in demand, fuel prices, supply and costs. Regional forward price curves are generated across multiple scenarios using a stratified Monte Carlo sampling program. Scenarios are driven by a wide range of market drivers that take into account statistical distributions, correlations, and volatilities. The market uncertainty drivers developed for the specific Wyoming market prices are also used when evaluating the resource mix. During the evaluations, the prices and associated uncertainties provide sufficient information about the market to allow for proper evaluation of alternatives. For example, high gas prices would generally result in high on-peak prices. The following uncertainties were examined in the IRP and resulted in 50 future scenarios for price development and portfolio evaluation: Demand o Mid-Term Peak by region o Mid-Term Energy by region o Long-Term Demand (to consider uncertainty in the rate of long-term load growth) Fuel Prices o Mid-Term Gas Price o Mid-Term Oil Price o Long-Term Gas, Oil and Coal Price (to consider the price uncertainty in the long-term supply/demand balance) Emission Prices o Long-Term SO x, NO x, and CO 2 Price Supply o Mid-Term Coal Unit Availability by region o Mid-Term Nuclear Unit Availability by region o Mid-Term Gas Unit Availability by region o Mid-Term Hydro Output by region Capital Cost o Long-Term Pulverized Coal Capital Cost o Long-Term Aero, Combustion Turbine and Combined Cycle Capital Cost o Long-Term Wind Capital Cost Cheyenne Light 2011 IRP 30

45 The range of values for each of these parameters is developed using either uniform distribution or standard deviations for two related variables that are then correlated. The ranges for some of the variables considered (with 1.0 being the middle) are shown in Table 8-1. Table 8-1 Ranges for Selected Uncertainty Variables Variable Minimum Maximum Mid-Term Peak Mid-Term Energy Long-Term Demand Mid-Term Gas Oil Price Long-Term Gas Coal Unit Availability Gas Unit Availability Pulverized Coal Capital Costs Combustion Turbine Capital Costs Combined Cycle Capital Costs Wind Capital Costs Source: Ventyx 8.2 Risk Profiles During the stochastic analysis, the expansion plans optimized for each case remain the same. The analysis examines the cost of each expansion plan assuming 50 different futures and tabulates the PVRR expected for each of those 50 futures. A risk profile for each expansion plan is then constructed using all 50 of those future PVRR points. Cumulative probability distributions, also known as risk profiles, provide the ability to visually assess the risks associated with a decision under uncertainty. These risk profiles are one of the results of the stochastic analysis conducted by Ventyx for Cheyenne Light. The risk profiles for the scenarios with the exception of the step load scenarios are shown on Figure 8-1. Cheyenne Light 2011 IRP 31

46 100% Figure 8-1 Scenarios Risk Profiles ( ) Risk Profiles 90% 80% Cumulative Probability 70% 60% 50% 40% 30% 20% 10% 0% $1,000 $1,025 $1,050 $1,075 $1,100 $1,125 $1,150 $1,175 $1,200 Present Value of Revenue Requirements (Millions $) Base Plan Environmental Plan High Gas Low Gas High Load Low Load 2x Base Base-No Firm Market 3 SCs 2014 Source: Ventyx Figure 8-1 shows that with the exception of the low load case, the risk profile for the preferred plan (3 SCs 2014) is to the left and lower than any other case except that labeled the base plan. The resource installed in 2014 in the base plan is a 90 MW aeroderivative CT. Firm market purchases are selected in each of 2011, 2012, and 2013 in the base plan to meet the summer peak requirements. 8.3 Stress Tests This Cheyenne Light IRP did not need to consider any unit retirements or retrofits to existing units or perform any special studies. However, three stress tests were examined to help provide the information needed for senior management s decision on the preferred plan. These three stress tests involved the consideration of step load in 2014, the examination of results if no economy interchange market were available, and an environmental stress test Step Load Economic development activities in the Cheyenne area have led to the possibility that a large load could materialize in the near future. For this analysis, Cheyenne Light looked at the relative impacts of a 50 MW increase in load in As shown on Table 7-1, the model selected a large CT (160 MW) in To mitigate shaft risk and to size the resource more suitably for Cheyenne Light, a case was constructed to force the installation of a 3 x 1 CC in 2014 instead of the large CT. For the 3 x 1 CC in 2014 step load case, the model determined that it would install an additional CT in 2015 as well (see Table 7-1). The deterministic PVRRs calculated for each of these two step load cases are shown in Figure 8-2. Cheyenne Light 2011 IRP 32

47 Figure 8-2 Step Load Deterministic PVRR 20 Year PVRR $1,350 $1,300 $1,250 Million $ $1,200 $1,150 $1,100 $1,050 $1, Economy Interchange Market Source: Ventyx To ensure that economy interchange sales and purchases estimates over the planning horizon were not influencing the selection of the preferred plan, a stress test was performed to examine two cases with and without the availability of economy interchange. This stress test is a gauge of market risk. The case with an aeroderivative installed in 2014 (comparable in cost to the preferred plan) is compared with the higher efficiency 2x1 CC in The deterministic PVRR for each case with and without the availability of economy interchange is shown in Figure 8-3. The difference between plan 1 and plan 8 decreases from $33.52 million (with an available economy energy market) to $18.27 million when economy energy is not available. This shows that plan 1 is relying on the available economy energy market to serve Cheyenne Light s energy needs. Importantly, the preferred plan with 3 CTs in 2014 will support conversion to 2x1 CCs in the future, further helping mitigate market risk. Cheyenne Light 2011 IRP 33

48 Figure 8-3 Economy Interchange Stress Test Deterministic PVRR $1,110 Aero vs 2x1 in Year PVRR $1,100 $1,090 Millions $ $1,080 $1,070 $1,060 $1,050 $1,040 $1,030 Plan 1 - Aero 2014 Plan 8-2x Plan 1 - Aero 2014 Plan 8-2x Base Scenario No Econ Interchange Source: Ventyx Environmental To provide additional information about the effects of environmental legislation/regulation particularly for CO 2, a stress test was conducted comparing the environmental scenario to the plan with 3 small CTs installed in 2014, but with the environmental assumptions as opposed to the base assumptions. The deterministic PVRR results for this stress test, shown in Figure 8-4, demonstrates that the PVRR for the 3 small CTs in 2014 is only marginally higher than for the base plan, with the added benefits of shaft risk mitigation and much greater flexibility for staging and gradual conversion to combined cycle operation. Figure 8-4 Environmental Stress Test Deterministic PVRR $1,220 Environmental Scenario 20 Year PVRR $1,210 Millions $ $1,200 $1,190 $1,180 $1,170 Source: Ventyx Cheyenne Light 2011 IRP 34

49 8.4 Selection of the Preferred Plan The analysis undertaken in the course of preparing this IRP provided information to Cheyenne Light senior management that was key in identifying the resource portfolio that would minimize risk in the face of an uncertain future. The Cheyenne, Wyoming area is very attractive for possible future economic development that in some cases results in significant increases in requirements for electricity what has been referred to in this IRP as step load increases. The potential for passage of carbon legislation to address perceived global climate change, changes as Democrats and Republicans alternate leadership roles in Washington, DC. With the difficulty many utilities experience in permitting and siting both new generation and new transmission, it is possible that the economy interchange market will not be as robust in the future as it has been in the past. In addition, the Cheyenne Light system is small relative to the market and the size of supply-side resources available. Shaft risk is a consideration as is flexibility for installing additional resources (expansion) and/or converting resources from simple cycle combustion turbine operation to combined cycle operation in the future as the load grows and as environmental and political considerations change. The preferred plan for Cheyenne Light, reflected on Figure 8-5, shows a reliance on the market for block purchases in July and August of 2011, 2012, and In 2014, Cheyenne Light intends to build or otherwise procure three simple cycle small CTs of approximately 36 MW net output each. Cheyenne Light believes that the self-build option provides the lowest costs for its customers. Risks associated with issuing a request for proposals (RFP) for resources and contracting with an independent power producer include recontracting risk, risks of step increases in load, and paying for incremental costs of transmission, among others. The expectation at Cheyenne Light is that the site for the three CTs will be selected for its expansion possibilities and that it will be in the Cheyenne, Wyoming area. Thus, there will be room to install a fourth CT at the site when the timing is right. In addition, the footprint will accommodate the installation of two HRSGs and generators at the site resulting in two 2 x 1 combined cycle units if and when such resources are needed in the future to supply customers demand for electricity. The CTs should be able to provide regulation for the wind resources in the Cheyenne area which would obviate the need for Cheyenne Light to pay others to provide this ancillary service. In the longer term, the preferred plan shows additional wind resources in 2019 and two additional CTs in 2022 and In all other years, firm market purchases provide stopgaps for July and August peak demand requirements until the need for resources is year round. Although the preferred plan resource portfolio does not reflect any coal-fired additions, Cheyenne Light will continue to evaluate the appropriateness of building more coal units in the future as its demand continues to grow. Cheyenne Light 2011 IRP 35

50 175 Figure 8-5 Preferred Plan Resource Additions Preferred Plan Resource Additions Simple Cycle Wind Firm Capacity 100 MW Source: Ventyx As previously discussed, the shaft risk associated with installing a 90 MW aeroderivative CT in 2014 on a system with a 176 MW peak is significantly higher than the shaft risk associated with the three smaller CTs. In addition, the operational flexibility with the aeroderivative CT is limited when compared to the flexibility that would result from the installation of the three small CTs. Although the heat rate (which determines fuel consumption per MWh generated) on the aeroderivative CT is lower than the small CT, the capital cost between the two is comparable ($1,020/kW [small CT] versus $1,016/kW [aeroderivative CT]), and the deterministic PVRR differential is small. In addition, it is possible to operate only one small CT at a time which adds to the operational flexibility of the preferred plan versus the scenario with the aeroderivative CT. The minimum load on the aeroderivative CT is higher than running one CT. An additional benefit with the three small CTs is that the site can be built to accommodate four small CTs. The site can also be selected such that there are expansion possibilities enabling Cheyenne Light to install an HRSG and generator for each pair of CTs and convert the site eventually to two 2 x 1 CCs. Over the long term, the heat rate for each 2 x 1 CC unit would be lower than that expected for either the aeroderivative CT or the small CTs and Cheyenne Light customers would experience that efficiency benefit. To prudently manage for load growth uncertainty, to enable expansion possibilities, to mitigate shaft risk, and to handle future environmental regulation, Cheyenne Light senior management has selected the scenario that includes the installation of three small CTs in 2014 as the preferred plan. 8.5 Sensitivity Drivers The magnitude of the influence that any specific driving factor has in determining the PVRR can be represented in what is called a tornado chart. The values on this chart are Cheyenne Light 2011 IRP 36

51 determined through regression analysis and identify the contribution of each variable to the total change in PVRR. Demand for electricity and natural gas price are the two primary drivers for the preferred plan as shown on Figure 8-6. These were also the two primary drivers for all the other scenarios examined in the IRP. Figure 8-6 Preferred Plan Tornado Chart ( ) 3 SCs 2014 Total Base Revenues Demand Gas Price Energy Market Purchased Power LTD Interest Peak Coal Availability Gas Availability 1,000 1,025 1,050 1,075 1,100 1,125 1,150 1,175 1,200 Present Value of Revenue Requirements (Millions $) 8.6 Comparison to 2005 and 2007 IRP Source: Ventyx In accordance with the Wyoming Public Service Commission s Guidelines Regarding Electric IRPs, for comparison purposes, the load forecast changes between the 2005 IRP, the 2007 IRP and this IRP were shown on Table 4-2. Table 8-2 shows a comparison of the resources in the preferred plan in the 2005 IRP, the resources selected in the 2007 IRP, and the preferred plan resources in the 2011 IRP. Cheyenne Light 2011 IRP 37

52 Year Resources from 2005 IRP ( ) Table 8-2 Preferred Plan Resource Comparison Resources from 2007 IRP ( ) Wygen II 90 MW Wygen II -90 MW, Happy Jack 30 MW Resources from 2011 IRP ( ) [90MW Wygen II is modeled as an existing unit. Happy Jack is operational and modeled as an existing PPA] 2009 Wygen III - 90 MW, 25 MW of firm market power 2010 Wygen III 90 MW 2011 firm market power 2012 Wind PPA 50 MW firm market power 2013 Wygen IV 90 MW, 50 MW firm market power Wind PPA small CTs 109 MW LAST YEAR OF STUDY CT 67 MW 30 MW Wind, of firm market power 2020 of firm market power 2021 of firm market power 2022 Wind PPA Small CT 36 MW 2023 Biomass 11 MW 2024 Wygen V 90 MW Wind PPA, CT 42 MW 2027 Wind PPA 2028 of firm market power 2029 of firm market power 2030 Small CT 36 MW Cheyenne Light 2011 IRP 38

53 9.0 Conclusions and Recommendations This IRP was completed to provide a road map to define the system upgrades, modifications, and additions that may be required to ensure reliable and least cost electric service to its customers now and into the future. A full range of resource alternatives, including renewables, were examined with the emphasis on determining the most robust plan that balances risk, reliability, and cost under a variety of possible future scenarios. The preferred plan meets Cheyenne Light s objectives to: Ensure a reasonable level of price stability for its customers Generate and provide reliable and economic electricity service while complying with all environmental standards Manage and minimize risk Continually evaluate renewables for an energy supply portfolio, being mindful of the impact on customer rates. 9.1 Action Plan The action plan provides a template for the actions that should be taken over the next several years. Cheyenne Light should continue to monitor market conditions and regulatory developments so that the items in the action plan can be adapted to address actual conditions as they occur. Cheyenne Light s plan is as follows: In the near term, continue to purchase a firm 6 x 16 product during the summer months to provide for the summer capacity shortfall. Build or otherwise procure three small combustion turbines for operation in After completion, monitor market conditions and opportunities for conversion to combined cycle operation. Seek opportunities to develop economic renewable resources particularly wind and solar. Actively review and prepare for load growth in the service territory. Monitor transmission developments in the Western U.S. Cheyenne Light 2011 IRP 39

54 Appendix A Software Used in the Analysis Strategic Planning powered by MIDAS Gold was utilized to measure and analyze the consumer value of competition. Strategic Planning includes multiple modules for an enterprise-wide strategic solution. These modules are: Markets Portfolio Financial Risk Strategic Planning is an integrated, fast, multi-scenario zonal market model capable of capturing many aspects of regional electricity market pricing, resource operation, asset and customer value. The markets and portfolio modules are hourly, multi-market, chronologically correct market production modules used to derive market prices, evaluate power contracts, and develop regional or utility-specific resource plans. The financial and risk modules provide full financial results and statements and decision making tools necessary to value customers, portfolios and business unit profitability. A.1 Markets Module Generates zonal electric market price forecasts for single and multi-market systems by hour and chronologically correct for 30 years. Prices may be generated for energy only, bid- or ICAP-based bidding processes. Prices generated reflect trading between transaction groups where transaction group may be best defined as an aggregated collection of control areas where congestion is limited and market prices are similar. Trading is limited by transmission paths and constraints quantities. Figure A-1 Sample Topology Source: Ventyx Cheyenne Light 2011 IRP 40

55 The database is populated with Ventyx Intelligence Market Ops information. Operational information provided for over 10,000 generating units. Load forecasts by zone (where zone may be best defined as utility level) and historical hourly load profiles Transmission capabilities Coal price forecast by plant with delivery adders from basin Gas price forecast from Henry Hub with basis and delivery adders When running the simulation in markets module, the main process of the simulation is to determine hourly market prices. Plant outages are based on a unit derate and maintenance outages may be specified as a number of weeks per year or scheduled. The market based resource expansion algorithm builds resources by planning region based on user-defined profitability and/or minimum and maximum reserve margin requirements in determining prices. In addition, strategic retirements are made of nonprofitable units based on user-defined parameters. Figure A-2 MRX Decision Basis MRX Additions if no constraints (e.g. Overbuild ) Additions (MW) Maximum Reserve Minimum Reserve Years Source: Ventyx MRX Additions if no constraints (e.g. Underbuild ) The markets module simulation process performs the following steps to determine price: Hourly loads are summed for all customers within each Transaction Group. For each Transaction Group in each hour, all available hydro power is used to meet firm power sales commitments. For each Transaction Group and Day Type, the model calculates production cost data for each dispatchable thermal unit and develops a dispatch order. Cheyenne Light 2011 IRP 41

56 The model calculates a probabilistic supply curve for each Transaction Group considering forced and planned outages. Depending on the relative sum of marginal energy cost + transmission cost + scarcity cost between regions, the model determines the hourly transactions that would likely occur among Transaction Groups. The model records and reports details about the generation, emissions, costs, revenues, etc. associated with these hourly transactions. A.2 Portfolio Module Once the price trajectories have been completed in the markets module, the portfolio module may be used to perform utility or region specific portfolio analyses. Simulation times are faster and it allows for more detailed operational characteristics for a utility specific fleet. The generation fleet is dispatched competitively against pre-solved market prices from the markets module or other external sources. Native load may also be used for non-merchant/regulated entities with a requirement to serve. Operates generation fleet based on unit commitment logic which allows for plant specific parameters of: Ramp rates Minimum/maximum run times Start up costs The decision to commit a unit may be based on one day, three day, seven day and month criteria. Forced outages may be based on monte-carlo or frequency duration with the capability to perform detailed maintenance scheduling. Resources may be de-committed based on transmission export constraints. Portfolio module has the capability to operate a generation fleet against single or multiple markets to show interface with other zones. In addition, physical, financial and fuel derivatives with pre-defined or user-defined strike periods, unit contingency, replacement policies, or load following for full requirement contracts are active. A.3 Capacity Expansion Module Capacity Expansion automates screening and evaluation of generation capacity expansion, transmission upgrades, strategic retirement, and other resource alternatives. It is a detailed and fast economic optimization model that simultaneously considers resource expansion investments and external market transactions. With Capacity Expansion, the optimal resource expansion strategy is determined based on an objective function subject to a set of constraints. The typical criterion for evaluation is the expected present value of revenue requirements (PVRR) subject to meeting load plus reserves, and various resource planning constraints. It develops long-term resource Cheyenne Light 2011 IRP 42

57 expansion plans with type, size, location, and timing of capital projects over a 30-year horizon. Decisions to build generating units or expand transmission capacity, purchase or sell contracts, or retire generating units are made based on the expected market value (revenue) less costs including both variable and fixed cost components. The model is a mixed integer linear program (MILP) in which the objective is minimization of the sum of the discounted costs of supplying customer loads in each area with load obligations. The model can be used to also represent areas that provide energy and capacity from power stations or contracts, but have no load obligations. The model includes all existing and proposed plants and transmission lines in a utility system. A.4 Financial Module The financial module allows the user the ability to model other financial aspects regarding costs exterior to the operation of units and other valuable information that is necessary to properly evaluate the economics of a generation fleet. The financial module produces bottom-line financial statements to evaluate profitability and earnings impacts. Figure A-3 Sample Reports Source: Ventyx Cheyenne Light 2011 IRP 43

58 A.5 Risk Module Risk module provides users the capability to perform stochastic analyses on all other modules and review results numerically and graphically. Stochastics may be performed on both production and financial variables providing flexibility not available in other models. Strategic Planning has the functionality of developing probabilistic price series by using a four-factor structural approach to forecast prices that captures the uncertainties in regional electric demand, resources and transmission. Using a Latin Hypercube-based stratified sampling program, Strategic Planning generates regional forward price curves across multiple scenarios. Scenarios are driven by variations in a host of market price drivers (e.g. demand, fuel price, availability, hydro year, capital expansion cost, transmission availability, market electricity price, reserve margin, emission price, electricity price and/or weather) and takes into account statistical distributions, correlations, and volatilities for three time periods (i.e. Short-Term hourly, Mid-Term monthly, and Long-Term annual) for each transact group. By allowing these uncertainties to vary over a range of possible values a range or distribution of forecasted prices are developed. Strategic Planning Enterprise-Wide Portfolio Analysis Figure A-4 Overview of Process Strategic Planning Capacity Expansion Portfolio Simulation Challenge Enterprise-wide solution Best Practice Strategic Planning combines zonal market price trajectories, portfolio analysis, corporate finance, capacity expansion, and risk assessment within a single model. Market Price Trajectories Risk Assessment Velocity Suite Production Statistics Corporate Finance Stochastic Simulation Scenario Simulation Financial Rate Making Source: Ventyx Cheyenne Light 2011 IRP 44