ARIZONA PUBLIC SERVICE COMPANY
RESOURCE PLAN REPORT
January 29, 2009
How to Read this Report
Following the Executive Summary, this Resource Planning Report has been divided into four parts, specifically to facilitate a careful dialogue of the Resource Plan, its development, and the analyses that support the selected Resource Plan. While each part can be reviewed independently, all readers should consider beginning their review with the Executive Summary and Part I, which together deliver the fundamental elements of this Resource Plan. Part I provides a review of the APS Resource Plan and the Action Plan. Part II addresses APS’s resource needs and some of the current challenges in resource planning. Part III describes APS’s current portfolio of resources, including transmission; provides a review of available resource options; and reviews the portfolio level analysis used in the development of this Resource Plan. Finally, Part IV provides a detailed discussion of four topics that APS believes will play an increasingly important role during the time period covered by this Resource Plan.
A table of acronyms and a glossary of terms used in this Report follow the Table of Contents.
TABLE OF CONTENTS
EXECUTIVE SUMMARY ...... 1
1.1 INTRODUCTION ...... 5
1.1.A. Purpose...... 5
1.1.B. Key Considerations for Resource Planning...... 5
1.1.C. The Resource Planning Process...... 7
1.1.D. APS Resource Needs ...... 9
1.2 APS’S PROPOSED RESOURCE PLAN...... 12
1.2.A. APS Resource Plan Overview ...... 12
1.2.B. Fundamentals of the APS Resource Plan ...... 14
1.2.C. Three-Year Action Plan...... 20
1.2.D. Transmission Needs...... 21
1.2.E. Regulatory Actions to Support this Resource Plan...... 25
1.3 STAKEHOLDER INVOLVEMENT IN THE DEVELOPMENT OF THIS PLAN ...... 27
2.1 CURRENT CHALLENGES IN RESOURCE PLANNING...... 30
2.1.A. Cost Escalation...... 30
2.1.B. Environmental Regulation...... 33
2.1.C. Natural Gas Price Levels and Volatility ...... 38
2.1.D. Financial Sustainability...... 39
2.1.E. Retail Competition...... 46
2.2 NEEDS ASSESSMENT ...... 48
2.2.A. Load Forecast Summary ...... 48
2.2.B. Outlook for Annual System Peak Demand and Energy ...... 49
2.2.C. Customer Growth...... 51
2.2.D. Residential Use Per Customer ...... 57
2.2.E. Non-Residential Use Per Customer ...... 61
2.2.F. Wholesale and Extra Large Retail Customer Sales ...... 62
2.2.G. Annual System Peak Demand and Total System Energy...... 63
2.3 GAP ANALYSIS...... 64
2.3.A. Reliability and Reserve Margins...... 66
2.3.B. Regional Capacity and WECC ...... 67
2.4 MARKETS AND PROCUREMENT...... 68
3.1 THE COMPANY’S CURRENT PORTFOLIO ...... 71
3.1.A. Summary of Existing Resources...... 71
3.1.B. Existing Resources...... 72
3.1.C. Outlook for Existing Resources...... 78
3.1.D. Energy Mix ...... 80
3.1.E. Other Key Parameters...... 81
3.1.F. Efficiency Improvements...... 84
3.1.G. Transmission System ...... 85
3.2 TECHNOLOGY COMPARISONS...... 92
3.2.A. Energy Efficiency Programs...... 93
3.2.B. Distributed Energy...... 94
3.2.C. Demand Response...... 96
3.2.D. Solar Technologies (Non-Distributed)...... 97
3.2.E. Wind...... 101
3.2.F. Geothermal...... 102
3.2.G. Biomass and Biogas...... 103
3.2.H. Natural Gas Combustion Turbines (Peaking Units) ...... 104
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3.2.I. Natural Gas Combined Cycle ...... 106
3.2.J. Coal...... 107
3.2.K. Nuclear...... 111
3.2.L. Summary of Resource Options...... 113
3.2.M. Economic Analysis ...... 114
3.2.N. Value Adjusted Supply Analysis ...... 120
3.3 RESOURCE PORTFOLIO ANALYSIS...... 126
3.3.A. Analysis of Energy Efficiency Cases...... 126
3.3.B. Analysis of Supply-Side Resource Planning Cases...... 136
3.3.C. Sensitivity Analysis ...... 151
3.4 CONCLUSION OF RESOURCE PORTFOLIO ANALYSIS...... 161
SPECIAL TOPICS ...... 163
4.1 TRANSMISSION NEEDS FOR RENEWABLE RESOURCES ...... 164
4.2 BACKGROUND ON NUCLEAR DEPLOYMENT ...... 170
4.2.A. LICENSING PROCESS ...... 170
4.2.B. EARLY SITE PERMIT...... 171
4.2.C. STANDARD DESIGN CERTIFICATION...... 172
4.2.D. COMBINED CONSTRUCTION PERMIT AND OPERATING LICENSE ...... 173
4.2.E. INTERVENTION AND LITIGATION RISK ...... 173
4.2.F. USED NUCLEAR FUEL...... 174
4.2.G. TRANSMISSION...... 174
4.2.H. MOVING FORWARD ...... 175
4.3 ADDITIONAL INFORMATION ON ENERGY EFFICIENCY PROGRAM IMPLEMENTATION...... 176
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4.3.A. SHORT-TERM DSM ACTION PLAN (2009 TO 2011)...... 177
4.3.B. LONG-TERM DSM ACTION PLAN (2012 AND BEYOND)...... 179
4.4 SOLAR GENERATION...... 181
4.4.A. SOLAR GENERATION PATTERNS ...... 181
4.4.B. SPRING-TIME OPERATION ...... 183
4.4.C. SUMMER OPERATION ...... 185
4.4.D. SUMMARY...... 186
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TABLE OF FIGURES
Figure 1 Summer Season Resource Requirements vs. Existing Resources..... 11 Figure 2 APS Resource Plan – Loads and Resources...... 14 Figure 3 Energy Sources to Meet Growth through 2025...... 15 Figure 4 Projected Energy Mix for 2025 ...... 16 Figure 5 Renewable Energy (non-distributed) Versus RES Targets ...... 16
Figure 6 Projection of CO2 Emissions ...... 17 Figure 7 Projected Natural Gas Consumption ...... 18 Figure 8 Cumulative Capital Spending Requirements...... 19 Figure 9 Projection of Average System Cost...... 20 Figure 10 BLS Cost Index for New Utility Construction...... 31 Figure 11 BLS Cost Index for Boilers, Heat Exchangers and Condensers ...... 32 Figure 12 BLS Cost Index for Iron and Steel Pipe ...... 32
Figure 13 Approximate CO2 Emission Rates...... 34 Figure 14 Impact of GHG Cap-and-Trade Legislation...... 36 Figure 15 History of NYMEX Natural Gas Prices ...... 39 Figure 16 Revenue Requirement Reduction Through CWIP ...... 43 Figure 17 Load Growth Drivers...... 50 Figure 18 Overview of Peak Demand and System Energy...... 50 Figure 19 APS Residential Customer Growth...... 51 Figure 20 Arizona Population Growth by Component...... 52 Figure 21 Arizona Householder Rates by Age ...... 55 Figure 22 Arizona Population by Age Group...... 56 Figure 23 Components of APS Residential Customer Growth ...... 57 Figure 24 Average Home size...... 59 Figure 25 Changes in Residential Use per Customer to 2028 ...... 60 Figure 26 Changes in Non-Residential Use Per Customers to 2028 ...... 61 Figure 27 Summer Season Resource Requirements vs. Existing Resources..... 64 Figure 28 Growth in System Energy Requirements ...... 65
Figure 29 Resource Acquisition, 2004 to Present...... 69 Figure 30 Summer 2009 Long-Term Resources (Capacity in MW) ...... 71 Figure 31 APS-Owned Generating Capacity (Summer 2009)...... 72 Figure 32 Long-Term Conventional and Renewable PPAs (Summer 2009) .... 75 Figure 33 Outlook for Existing Resources...... 78 Figure 34 Projected Energy Mix for 2009 ...... 81 Figure 35 Projected Natural Gas Burn for 2009 ...... 82
Figure 36 Projected CO2 Emissions for 2009 ...... 83 Figure 37 Projected Water Consumption for 2009...... 84 Figure 38 APS/Arizona Transmission and Generation...... 86 Figure 39 APS-Owned Transmission Capacity on Major Paths (Summer 2009)...... 87 Figure 40 APS Eastern Transmission Path and Uses...... 88 Figure 41 Mead Transmission Path and Uses...... 89 Figure 42 Navajo Transmission Path and Uses ...... 90 Figure 43 Palo Verde Transmission Path and Uses...... 91 Figure 44 Resource Availability Timeline...... 92 Figure 45 Typical Summer Day Production Profiles...... 99 Figure 46 Qualitative Resource Factors...... 113 Figure 47 Comparison of Average Delivered Cost...... 117 Figure 48 Economic Comparison of Resource Technologies...... 118 Figure 49 CSP Production and APS Load Profile ...... 121 Figure 50 New Mexico Wind Production and APS Load Profile...... 122 Figure 51 On Peak Capacity Factor of Wind and Solar Power Plants ...... 123 Figure 52 Value Adjusted Life Cycle Costs in $/MWh...... 124 Figure 53 Energy Efficiency Supply Curve (in MWs of Peak Capacity Reduction) ...... 128 Figure 54 Energy Efficiency Supply Curve (in GWhs of Energy Reduction) .. 128 Figure 55 Payback Acceptance Curves...... 130
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Figure 56 Scenario Description (2008-2025) ...... 131 Figure 57 Summary of Resource Additions for Energy Efficiency Scenarios...... 132 Figure 58 Energy Efficiency Scenarios – CPW of Revenue Requirements...... 133 Figure 59 Natural Gas Consumption for Energy Efficiency Scenarios...... 133
Figure 60 CO2 Emissions for Energy Efficiency Scenarios ...... 134 Figure 61 Cumulative Capital Expenditures for Energy Efficiency Scenarios...... 135 Figure 62 Average System Cost for Energy Efficiency Scenarios...... 136 Figure 63 Summary of Scenarios – Relative Energy Mix ...... 146 Figure 64 Characterizing Nuclear and Solar Scenarios by Gas Burn and
CO2 Emissions ...... 147 Figure 65 Summary of Costs for Nuclear and Solar Scenarios ...... 147 Figure 66 Annual Natural Gas Burn in BCF ...... 148
Figure 67 Annual CO2 Emissions (Short tons)...... 149 Figure 68 Cumulative Capital Expenditures...... 150 Figure 69 Summary of Capital Expenditures...... 150 Figure 70 Summary of Costs for Scenarios ...... 151 Figure 71 Average System Cost ($/MWh) ...... 151
Figure 72 Results of CO2 Sensitivity Analysis vs. All Gas Scenario ...... 152
Figure 73 Results of CO2 Sensitivity Analysis for Energy Efficiency Scenarios...... 153 Figure 74 Average System Cost for CO2 Sensitivity Analysis ...... 153 Figure 75 High Natural Gas Price Sensitivity for Resource Scenarios ...... 154 Figure 76 High Natural Gas Price Sensitivity Case for Energy Efficiency Scenarios...... 154 Figure 77 Illustration of Risk Reduction Benefits ...... 155 Figure 78 Impact of Higher Nuclear Construction Cost...... 156 Figure 79 Renewable Cost Sensitivity Analysis...... 157
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Figure 80 Peak Load Forecast Sensitivities...... 158 Figure 81 Solar Energy Development Potential in Palo Verde Area ...... 165 Figure 82 Monthly Transmission Usage – Eastern Path...... 166 Figure 83 Typical Monthly Energy Production – Aragonne Wind ...... 167 Figure 84 APS Transmission System with Wind Area Identified...... 168 Figure 85 Wind Energy Potential...... 168 Figure 86 Geothermal Energy Potential ...... 169 Figure 87 Savings from Energy Efficiency (GWhs)...... 176 Figure 88 Annual Energy Efficiency Spending...... 177 Figure 89 Solar Generation Profiles for March Day...... 182 Figure 90 Solar Generation Profiles for July Day ...... 183 Figure 91 Photovoltaic Fixed Position for a March Day ...... 184 Figure 92 Photovoltaic Fixed Position for a July Day...... 185
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TABLE OF ACRONYMS
ABWR Advanced Boiling Water Reactor ACC Arizona Corporation Commission ADEQ Arizona Department of Environmental Quality AFUDC Allowance for Funds Used During Construction APS Arizona Public Service Company BART Best Available Retrofit Technology BCF Billion Cubic Feet BLS Bureau of Labor Statistics BTA Biennial Transmission Assessment BTU British Thermal Units CAISO California Independent System Operator CC Combined Cycle CCS Carbon Capture and Sequestration CFL Compact Fluorescent Lighting CFR Code of Federal Regulations CHP Combined Heat and Power
CO2 Carbon Dioxide COL Construction and Operating License COLA Construction and Operating License Application CPW Cumulative Present Worth CSP Concentrated Solar Photovoltaic CT Combustion Turbine CWIP Construction Work in Progress DE Distributed Energy DOE Department of Energy DR Demand Response DSM Demand-Side Management DSMAC Demand-Side Management Adjustment Charge DSW Desert Southwest ELCC Effective Load Carrying Capability EPA Environmental Protection Agency EPC Engineering, Procurement, and Construction ESP Early Site Permit EHV Extra-High Voltage
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GHG Greenhouse Gases GWh Gigawatt Hour HV High Voltage HVAC Heating, Ventilation and Air Conditioning IGCC Integrated Gasification Combined-Cycle Combustion ITAAC Inspections, Tests, Analyses and Acceptance Criteria ITC Investment Tax Credit JDG Joint Development Group kW Kilowatt kWh Kilowatt Hour kV Kilovolt MER Monitoring, Evaluation and Reporting mmBTU Million British Thermal Unit MW Megawatt MWh Megawatt Hour NAU Northern Arizona University
NOx Nitrogen Oxide NRC Nuclear Regulatory Commission NYMEX New York Mercantile Exchange O&M Operation and Maintenance PAC Payback Acceptance Curve PAF Program Acceptance Factor POLR Provider of Last Resort PPA Purchased Power Agreement PTC Production Tax Credit PV Photovoltaic PVNGS Palo Verde Nuclear Generating Station R-COLA Reference Construction and Operating License Application REIP Renewable Energy Incentive Program RES Renewable Energy Standards RFP Request for Proposal SCRs Selective Catalytic Reduction SDGE San Diego Gas & Electric Company
SO2 Sulphur Dioxide SRP Salt River Project
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STAR Solar Technology and Research TRC Total Resource Cost WCI Western Climate Initiative WECC Western Electricity Coordinating Council
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GLOSSARY OF TERMS
Baseload Plant An electric generating plant devoted to the production of electricity on a relatively continuous basis. Baseload plants are typically operated for the majority of the hours during a given year and are taken off-line relatively infrequently. Baseload plants usually have a low variable production cost relative to other production facilities available to the system. British Thermal Units (BTU) Used to describe the heat content of fuel. The price of fuel is typically expressed in terms of dollars per million BTUs (or $/mmBTUs). Cap and Trade An approach used to control emissions by providing economic incentives for achieving reductions. A central authority (usually a government or international body) sets a limit or cap on the amount that can be emitted. Companies or other groups are issued emission permits and are required to hold an equivalent number of allowances (or credits) which represent the right to emit a specific amount. The total amount of allowances cannot exceed the cap, limiting total emissions to that level. Companies that need to increase their emissions must buy allowances from those that emit less. The transfer of allowances is referred to as a trade. In effect, the buyer is paying a charge for emitting, while the seller is being rewarded for having reduced emissions by more than was needed. Capacity The maximum amount of electricity a generation source can produce in any given moment. Capacity is usually measured in units of megawatts (MWs). It should be noted that most generation sources are not operated at their maximum capacity rating during all hours that they are generating electricity. See Capacity Factor Capacity Factor Capacity factor is a value used to express the average production level of a generating unit over a given period of time. Capacity factor is expressed as a percentage of the maximum possible production if the generating unit had operated at its maximum capacity rating for all
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hours during the period. For example, a generating facility which operates at an average of 60% of its maximum capacity over a measured period has a capacity factor of 60% for that period. CO2 See Greenhouse Gas, Emissions Combined Cycle Twin-stage natural gas-fired power plants that deliver higher fuel efficiency. In the first stage, a gaseous fuel source (natural gas, gaseous coal, etc.) is combusted in a gas turbine. The turbine is used to drive an electric generator. In the second stage, waste heat is captured from the gas turbine’s hot exhaust gases in a heat recovery steam generator (“HRSG”). The steam that is produced in the HRSG is used to drive a steam turbine and produce additional electricity. This beneficial use of the residual heat content in the gas turbine’s exhaust stream contributes to the excellent fuel efficiency of the combined cycle power plant. Combustion Turbines (also These electric generating plants operate on a referred to as a gas turbine) similar principle to the engines on jet airplanes. Ambient air is compressed to high pressures in the compressor section of the machine. A gaseous fuel source is added to this compressed air and combusted in the combustor section. The resulting hot gases are then expanded through a turbine section that provides the driving force for both an electric generator and the compressor section. Commodity Hedging See Hedging Strategies Concentrated Solar Power Technologies that concentrate solar energy to generate electricity. This class of solar technologies includes solar trough, power towers, dish stirling, and concentrating photovoltaics. Conventional Resources Conventional generating resources include a broad class of technologies that use coal, nuclear, natural gas, or fuel oil to generate electricity.
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Customer-Side Resource Several resource options rely upon active Programs participation by customers to produce either a reduction in energy consumption or peak demand. Various energy efficiency programs are directed at achieving reductions in customer energy consumption. These would include alternative rate schedules that incent these reductions, more efficient equipment, or improvements to a building’s thermal envelope. Peak demand reduction programs generally target reductions during the highest usage periods of the year through special rate schedules (such as time-of- use prices), energy storage options, or demand response programs. Day-Ahead Call Option A call option provides the buyer of the option with the right, but not the obligation, to receive a predetermined amount of electric energy during a specified delivery period. The buyer usually pays a reservation fee (referred to as the option premium) to the seller to obtain this right. When the buyer exercises the right to receive energy, the buyer also pays the seller for the energy received based upon a predetermined price or formula. These call option contracts also specify how much advance notice the buyer must provide to the seller in order to receive energy. With a “day- ahead” option, the buyer must provide this notice on the day prior to receiving the energy. Delivered Cost Delivered cost is used to refer to the cost of power produced by a generating unit (or a purchased power contract) where the cost of delivering the electric power from the generating source to the load center (area of customer consumption) has also been included in the cost. Demand The rate at which electricity is being used at any one given time. Demand differs from energy use, which reflects the total amount of electricity consumed over a period of time. Demand Response Demand response is a broad category that includes both requests for customer load reductions initiated by the utility or load reductions initiated by customers in response to price signals. Utility-initiated demand response measures could include direct load control
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programs, such as residential air conditioners, partial or curtailable load reductions, and complete load interruptions. Price response includes real-time pricing, dynamic pricing, critical peak pricing, time-of-use rates, and demand bidding or buyback programs. Demand-Side Management The planning, implementation, and monitoring of (DSM) utility activities designed to encourage consumers to modify patterns of electricity usage, including the timing and level of electricity demand. Dispatchable Generating units (or purchased power contracts) in which the rate of power production can be adjusted or varied based upon economic or other considerations. Different types of generating units have varying degrees of dispatchability either for technical or economic reasons. Distributed Energy A term referring to a small generator, typically 10 megawatts or smaller, that is sited at or near load, and that is attached to the distribution grid or the customer’s electrical system. Distributed generation can serve as a primary or backup energy source and can use various technologies, including combustion turbines, reciprocating engines, fuel cells, wind generators, and solar photovoltaics. Dry Cooling The typical steam power plant requires cooling water to improve overall cycle efficiency by returning the exhaust steam to a liquid state that can then be returned to the boiler to produce more steam. In a dry-cooled power plant, the exhaust steam is cooled by use of air-cooled condensers thereby eliminating the use of water from this portion of the power production process. However, the air-cooled condensers are more expensive and overall plant efficiency is reduced versus water-cooled plants. Early Site Permit (ESP) The early site permit was established under 10 CFR Part 52. The ESP process allows an applicant to obtain federal regulatory approval to site a new nuclear power facility on either a new site or a site already hosting a nuclear power plant. The ESP addresses environmental issues associated with the site.
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Effluent Wastewater, treated or untreated, that flows out of a treatment plant, sewer, or industrial outfall. Generally refers to wastes discharged into surface waters. Emissions Discharges into the atmosphere from stacks, other vents, and surface areas of commercial and industrial facilities; from residential chimneys; and from motor vehicle, locomotive, or aircraft exhaust. Energy Efficiency In the context of resource planning, energy efficiency refers to actions taken by consumers to reduce their overall consumption of electric energy. These reductions could be the result of installation of more efficient equipment, improvements to the thermal envelopes of structures, or behavioral changes. Energy efficiency improvements can be incented through utility-sponsored programs, mandated by building codes or other standards or simply implemented by the customer. Greenhouse Gas (GHG) A collection of gaseous substances, primarily consisting of carbon dioxide, methane, and nitrogen oxides which have been shown to warm the earth's atmosphere by trapping solar radiation. Greenhouse gases also include chlorofluoro- carbons (“CFCs”), a group of chemicals used primarily in cooling systems and which are now either outlawed or severely restricted by most industrialized nations. (Power) Grid An interconnected network of electric power transmission lines. The United States power grid, which covers most of the country as well as parts of Canada and Mexico, is made up of three major networks: - Eastern Interconnect - Western Interconnect - Texas Interconnect These networks include extra-high-voltage connections between individual utilities, which transfer electrical energy from one part of the network to another. The Interconnects distribute electricity in their respective areas. Each of these grids has a network of smaller units or power pools that enable better management of power
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distribution. Hedging The attempt to eliminate at least a portion of the risk associated with owning an asset or having an obligation by acquiring an asset or obligation with offsetting risks. For example, a company that has an obligation to purchase fuel oil in six months may want to eliminate the risk that prices will increase before that time. In this case, the company could hedge, or reduce, that risk by purchasing a futures contract that provides the right to purchase fuel oil at a fixed price. Any profit or loss on the futures contract should offset the effects of higher or lower oil prices at the time the company needs to buy oil. Hub In the context of the electric grid, a hub is a location on the transmission network having a high concentration of interconnected transmission lines, generating sources and/or counterparties willing to transact such that this location becomes a location having a great deal of commercial activity. Hybrid Cooling Hybrid cooling systems utilize a combination of water cooling and dry cooling techniques. The relative contribution from each is dependent upon the plant design, weather conditions, and water consumption policies. See also Dry Cooling. Independent Power Producers A producer of electrical energy which is not a (IPP) public utility but which makes electric energy available for sale to utilities. IPP’s may be privately-held facilities or non-energy industrial concerns capable of feeding excess energy into the system. Interconnection A connection between two electric systems permitting the transfer of electric energy in either direction. Additionally, an interconnection refers to the facilities that connect a generator to a system. Intermediate Resource Intermediate generation resources usually fulfill a somewhat flexible role in the generating system. During some times of the year, these generating units will be started in the morning hours, used to meet daytime peak loads and then brought off-line in the evening. The operation may change during heavier load times of the year when these units
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may operate in more of a baseload manner and remain on-line for all hours of the day. Intermittent Resource Intermittent generating resources have some degree of variability in the production pattern, typically due to weather conditions. An example of an intermittent generating source is a wind project. The power output from the wind project is entirely dependent upon the wind conditions and will fluctuate with changes in wind conditions. Load The moment-to-moment measurement of the power requirement in the entire system. Load Center A point at which the load of a given area is assumed to be concentrated. Load Pocket A geographic area that has a high demand of energy. For example, the metro Phoenix area is considered a load pocket. Megawatt (MW) One megawatt equals one million watts. See Watt. Megawatt Hour (MWh) See Watthour. Nameplate Rating Each generating unit has a nameplate rating that specifies the maximum expected output of the generating unit. This nameplate rating could be dependent upon specified conditions (like ambient temperature). Nuclear Regulatory The federal agency responsible for the regulation Commission (NRC) and inspection of nuclear power plants to assure safety. Nuclear Fuel Fissionable materials of such composition and enrichment that when placed in a nuclear reactor will support a self-sustaining fission chain reaction and produce heat in a controlled manner for process use. Peak Demand The greatest demand that occurred or is expected to occur during a prescribed time period. Peaking Units These generation units usually see relatively infrequent service during the non-summer months. During the summer, peaking units are used during the hot summer afternoons in response to high customer demands. It is not unusual for peaking units to operate less than 10% of the hours during the year.
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Photovoltaic The technology used to convert the sun’s rays directly into electricity. Purchased Power Agreement A contractual agreement between two entities for the sale of electric energy and capacity from a specific generating unit, utility system, or unspecified wholesale market sources. Rate Base The value established by a regulatory authority upon which a utility is permitted to earn a specified rate of return. Generally, this represents the amount of property used and useful in public service. Regulating Reserves The amount of generating capacity a central power system must maintain actively connected to the electric power system and electrically synchronized for the purpose of dynamically balancing the supply and demand for electricity. Renewable Energy An energy resource that is replaced rapidly by a natural, ongoing process and that is not nuclear or fossil fuel. Request for Proposal (RFP) An invitation for suppliers, often through a bidding process, to submit a proposal on a specific commodity or service. Scrubbers A device that removes emissions from an air stream. The gases are removed either by absorption or chemical reaction. Simple Cycle See Combustion Turbine. Spinning Reserves Spinning reserve is available generating capacity that is synchronously connected to the electric grid and capable of automatically responding to frequency deviations on the system. Summer Peak See Peak Demand. Thermal Energy Storage The storage of energy as heat for use at another time. Tracking (Solar) The ability of a solar technology to follow the sun across the sky. By following the sun, the solar technology can increase total energy production as compared to a solar technology without tracking. Transmission The transportation of bulk energy along a network or grid of power lines. It is often intended to refer specifically to high-voltage (69,000 volts or higher) electricity of the type bought and sold on the wholesale market. An additional stage of service, referred to as distribution, is required to
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actually deliver usable low-voltage energy to an end-use customer. Watthour The total amount of energy used in one hour by a device that requires one watt of power for continuous operation. Electric energy is commonly sold to retail customers and measured in kilowatt-hours. Watt The electrical unit of real power or rate of doing work; specifically, the rate of energy transfer equivalent to one ampere flowing due to an electrical pressure of one volt at unity power factor. Wholesale Customer In the energy industry, this term refers to any party that purchases electricity in bulk for resale to end-use customers. Wholesale customers may include marketers, utilities and distribution companies, co-ops, and any other entity engaged in energy resale. Wholesale Supplier Wholesale energy sales can be made between producers, marketers, brokers, utility companies, and select high-volume, end-use customers, any of which is considered a wholesale supplier. The most common form of wholesale energy transaction is one made between energy producers or marketers and utility companies that serve the general public.
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EXECUTIVE SUMMARY
This Resource Plan Report (“Report”) has been developed during a time of unprecedented challenges. During the past year, energy prices have exhibited unusually high volatility, the Arizona economy has rapidly transitioned from robust growth to recessionary conditions, and inflationary factors have led to significant increases in costs. In addition, pending climate change policies could significantly impact how electricity will be produced in this country. It is against this backdrop that Arizona Public Service Company (“APS” or “Company”) has brought forward the resource plan (“Resource Plan”) set forth in this Report. Despite all of these uncertainties and dramatic changes, it is critical that APS continue to satisfy its customers’ electricity needs in a reliable and cost-effective manner. To accomplish this vital task, APS must continue to plan for and develop the electricity resources needed to meet future customer needs.
The Arizona Corporation Commission’s (“ACC” or “Commission”) approval or acknowledgement of this plan, and the process by which such outcome is achieved, will allow APS to begin pursuing a resource plan that presents many benefits to Arizona. The Commission’s approval or acknowledgement will ratify resource choices as a starting point for a roadmap designed to fulfill the state’s long-term resource needs. However, this is only the first step in a series of required regulatory approvals to make this Resource Plan a reality. The Commission’s engagement in this planning process will enable APS to pursue a resource future that departs from a traditional “least-cost” resource plan. Some of those benefits are quantified as part of this Resource Plan; others will manifest over time. The goal of this Resource Plan is to provide a diverse portfolio of resources which reasonably balances reliability, cost, environmental impacts, and considers the many uncertainties that exist today.
By 2025, APS expects to require about 6,500 megawatts (“MWs”) of new capacity resources; the majority of which are due to growth in customer peak loads. Additionally, APS projects that its total system energy requirement will grow by almost 17,000 gigawatt hours (“GWhs”) by 2025. This represents an increase of more than 50 percent over 2009 levels.
This Resource Plan will allow Arizona to increase its commitment to non-fossil fuel resources and to prevent emissions of 30 million metric tons of carbon dioxide (“CO2”) over the plan timeframe. This Resource Plan describes a path to further increase the role of energy efficiency in our customers’ homes and businesses. It will facilitate APS’s pursuit of renewable resources above and beyond the Renewable Energy Standard (“RES”) requirements.1 With the Commission’s approval, APS will accelerate the adoption of renewable resources, doubling the RES requirement in 2015 and ultimately delivering over 50 percent more renewable energy to its customers. This Resource Plan describes the potential addition of a new baseload nuclear resource. The Commission’s approval or acknowledgement of this Resource Plan will signal the Commission’s
1 A.A.C. R14-2-1801 through 1816.
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DRAFT agreement with APS’s intention to pursue this resource—a carbon emission-free baseload resource that compliments the addition of renewable resources and strengthens Arizona’s fuel diversity. Perhaps most importantly, approval or acknowledgment of this Resource Plan will enable APS and its customers to work collaboratively with the Commission on creating a long range plan for Arizona’s energy future. This Report describes those actions that APS believes are required within the next three years to advance this agenda (the “Action Plan”). This Report also provides the basis for these recommended actions using a planning timeframe that extends through the year 2025.
As a result of recent economic changes, APS has observed a marked slowing of the growth in energy requirements over the last year. Because of this slowdown and based upon the latest load forecast, APS anticipates that current resources, planned additions of renewable resources (both distributed and non-distributed), demand-side customer programs (including energy efficiency and demand response), and near-term market opportunities will be sufficient to meet expected peak capacity needs through 2015. APS expects growth to return to normal levels within the next several years and that this growth will lead to a large, long-term need for electric resources.
APS’s Resource Plan does not include new coal-fired generation resources. Despite some economic advantages, at this time, APS believes that the risk of future climate change legislation and the resulting potential for significant increases in cost currently make coal-fired generation an unattractive resource choice. An important feature of this Resource Plan is that it does not place undue reliance on any single resource type, but rather relies upon four energy resource types to meet future customer needs. The four primary elements of the Resource Plan are: 1) an increased role for energy efficiency; 2) significant additions of renewable resources; 3) the potential for a new nuclear resource; and 4) purchases from the wholesale markets or gas-fired capacity additions to meet future peak demand.
In addition to the new generating resources, the transmission infrastructure will need to be expanded to accommodate these new resources. This will include expansion beyond the transmission identified in APS’s current ten-year transmission plan. Specifically, APS believes that additional transmission capacity will be needed to bring new resources (including solar) from Palo Verde and Gila Bend into the Phoenix load pocket. Transmission investment would also be required to support new nuclear capacity.
This Resource Plan provides Arizona with a number of important benefits, including:
1. This Resource Plan represents an important step towards meeting the climate change challenge. This Resource Plan facilitates APS’s departure from a resource planning approach that would rely heavily on natural gas resources; and, therefore, virtually all of the growth in customer energy
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consumption through 2025 will be met with resources having no carbon emissions. As a result, under this plan APS’s CO2 emissions in 2025 are expected to be very close to current levels.
2. APS’s consumption of natural gas in 2025, whether through purchased power or owned or contracted capacity, will be within about ten percent of current levels, thereby controlling the risk to our customers of volatile natural gas prices.
3. The Resource Plan is based largely upon energy sources that can be developed within the state of Arizona and the southwest, which will reduce reliance on energy sources imported into the region and which are more susceptible to price fluctuation driven by geopolitical forces.
Resource planning must be viewed as a continuous process rather than a specific outcome, and APS expects that the Resource Plan will evolve as time passes and uncertainties are eliminated or changed. For example, if the cost of solar resources continues to decline relative to other resource options, then APS’s next resource plan is likely to place a further increased emphasis on solar resources. Similarly, if APS finds additional energy efficiency opportunities at appropriate price levels, then future resource plans could incorporate higher levels of energy efficiency savings. This type of evolution should be expected as part of the resource planning process.
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PART I
2009 APS RESOURCE PLAN
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1.1 INTRODUCTION
1.1.A. Purpose
This Report provides a summary of APS’s Resource Plan, the technical analysis supporting the Resource Plan, and the associated Action Plan. The period covered by this Resource Plan spans from 2009 to 2025, a 17-year horizon. It should be noted that the choices made as part of this resource planning process will impact Arizona for the vast majority of this century.
In consideration of the Commission Staff’s efforts to revise integrated resource planning rules for Arizona, APS has structured this Report to address the filing requirements that are anticipated to become part of the eventual rules. Recognizing that these rules are still in draft form and under development at the time of this writing, there may ultimately be some discrepancy between the information set forth in this Report and that required by the final rules.
1.1.B. Key Considerations for Resource Planning
As part of the resource planning process, minimizing cost is and will always be an important consideration in the development of a resource plan. However, in addition to cost, managing key risk factors also must be considered. Today, unprecedented challenges and uncertainties demand consideration of several key risk factors. These items are listed below and are followed by a brief discussion of each item.
• Diversity of energy sources • Financial sustainability • Resource self-sufficiency • Positioning for climate change policy • Long-term planning for resource needs • High reliability • Need for flexibility
The diversity of energy sources is one of the most important planning considerations. Despite the best efforts of utility resource planners and other stakeholders involved in resource planning, it is impossible to anticipate all future risks. For example, when the current fleet of coal-fired power plants was constructed in the 1960s and 1970s, the planners of that era could not have anticipated the potentially significant cost impacts related to today’s debate on climate change policy. Additionally, even though natural gas resources offer many advantages as compared to other generation choices, it is difficult to accurately forecast natural gas prices, and, as a result, there is a wide range of potential outcomes associated with natural gas generation. Risk analysis can shed light on some of these concerns. However, risk analysis can only focus upon
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DRAFT those risks that are known and apparent to utility planners today. It is difficult to anticipate all of the issues that may emerge in the future that could present challenges to one or more elements of the Company’s portfolio.
The above examples highlight the risk of over-reliance upon any single energy source and reinforce the need to strive for diversity in the energy supply portfolio. The examples also help to point out some of the danger of focusing only upon cost minimization in the resource planning process. A single-minded focus on cost minimization can lead to over-reliance on whichever energy source happens to be the least-cost option at that point in time.
Financial sustainability is perhaps the most important resource planning consideration for the Company. This refers to the ability of APS to maintain its financial health while taking on the large commitments that will be required to carry out this Resource Plan. In later sections of this Report, the magnitude of these future commitments will be highlighted. It is important to note that APS is not embarking upon this endeavor from a position of financial strength. APS’s current credit ratings barely remain within the investment grade category. Therefore, APS’s financial condition must be enhanced so that APS will be able to attract the necessary capital investment at a reasonable cost to carry out the Resource Plan recommended in this Report.
Resource self-sufficiency is another concept that APS has considered in the development of this Resource Plan. In the context of resource planning, self-sufficiency can be defined as the degree of long-term control that APS has over a specific energy source. There is a meaningful benefit, which is often hard to quantify, to examining self- sufficiency as part of the resource planning process.
Climate change is a difficult challenge facing the entire nation. With many climate change initiatives advancing at the local, state, national and international levels, it is reasonable to assume that utilities will be faced with future regulations controlling emissions of greenhouse gases (“GHG”), such as CO2. Although the final form is not known at this time, these future regulations will likely impose additional costs on utility operations and provide an economic incentive to pursue energy resource options with lower CO2 emission characteristics. Therefore, APS believes that it is in the best interests of APS and its customers to position the energy supply portfolio to address this issue.
Electric generation units are long-lived assets. The resources selected in today’s resource planning process can be expected to remain a part of APS’s energy supply portfolio for a long time. As an example, a baseload nuclear plant identified in this Resource Plan would not begin producing power until after 2020. Because new nuclear plants will receive a 40-year operating license from the Nuclear Regulatory Commission (“NRC”), the decision to proceed with this type of new resource is likely to remain a part of the energy supply portfolio until late in this century. Although near-term customer price impacts must not be ignored, it is important that the resource planning process
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DRAFT maintains a long-term focus so that the resources necessary to support continued strong economic growth in the APS service territory and the state are developed.
APS customers expect highly reliable electric service. This is also a necessary ingredient for strong economic growth in the APS service territory and the state. There are many aspects to maintaining highly reliable electric service. Continued expansion of APS’s electric resources and transmission infrastructure, and avoiding over-reliance on external short-term markets, is required to assure highly reliable service for APS’s customers.
Finally, flexibility is one of the most important elements of a successful resource planning process. No one can clearly forecast the future and predict the levels of the many important resource planning variables such as customer growth, natural gas prices, and construction costs. Consequently, the long-term success of the resource planning process will depend more upon the ability to respond to and accommodate changes in key planning variables than upon the ability to precisely forecast these key variables. It is important that all parties appreciate this need for flexibility and understand the dynamic nature of resource planning. It is also important that the regulatory structure supports the need for flexibility and avoids disincentives to adjusting resource plans to accommodate the ever-changing situation.
1.1.C. The Resource Planning Process
The overall purpose of the resource planning process is to identify a set of resources that meets the future electricity needs of APS’s customers in a balanced and cost-effective manner, while also satisfying our customers’ desire for reliable electric service, price stability, and environmental responsibility. Resource planning is an integral part of APS’s business planning functions and involves input and involvement from many different departments within the Company.
In the past, resource planning was often referred to as “least-cost planning.” The primary purpose of the planning effort was to select a resource plan that resulted in the lowest cost of providing service to customers in the future. There is a growing recognition in the industry that a narrow focus on “least-cost” may no longer be appropriate. The recent volatility of natural gas prices and the current debate surrounding climate change are just two examples of major risk factors and uncertainties that must be addressed in the resource planning process. These risk factors greatly complicate the decision-making process because it is difficult, if not impossible, to evaluate all of the uncertainties that can impact the resource choices, and, in many cases, the solutions that address these uncertainties can result in higher costs to customers (at least in the near term).
The resource planning process begins with a forecast of future customer electricity needs which is typically modeled over a thirty-year period. The next step in the process
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DRAFT involves a comparison of the existing resource portfolio to these projected future customer needs. The result of this comparison is the “gap” or the amount of future customer needs that cannot be met by existing resources. This is followed by a comparison of different resource technologies to meet these future needs. This step typically involves both quantitative and qualitative analyses of different resource alternatives, including conventional generation, renewable resources, and demand-side measures (energy efficiency and distributed generation). Viable resource options are then brought forward for portfolio-level analysis in which alternative resource expansion plans are developed and analyzed through detailed production cost simulations. These detailed simulations combine the new resource alternatives with the existing resource portfolio and allow for projections of future costs (as well as other key parameters like emissions and capital spending). The cost analysis provides an estimate of the future total system cost of each resource alternative. These include costs for fuel, purchased power, capital and transmission for new power plants, energy efficiency program costs, natural gas transportation, and emissions allowance costs for currently regulated emissions, such as 2 Sulfur Dioxide (“SO2”).
Risk analysis and strategies to address risks play an important role in the resource planning process. The risk analysis process involves both quantitative and qualitative assessments of future potential risks, such as changes in fuel prices or future environmental regulations (the current issues surrounding climate change are a good example of this). Because many risks cannot be easily quantified, the risk assessment process inevitably requires a great deal of judgment.
The end result of the resource planning process is a specific set of actions or steps that will provide for a robust set of resources to meet future customer needs. Some of these actions/steps will involve actual resource acquisition (such as APS’s recent Purchased Power Agreement (“PPA”) to acquire the entire output from the proposed Solana solar plant), while others might involve preliminary steps, such as issuing a Request for Proposal (“RFP”) to evaluate demand response alternatives or completing initial permitting of a new baseload resource. These preliminary steps are an important means of addressing the risks inherent in long-term resource planning.
Resource planning is a continuous process at APS and is frequently referred to as a “learning process.” An important aspect of resource planning is monitoring external market factors (e.g., new technologies, commodity markets, local economic conditions, interest rates, and legislative proposals) for key changes that could impact APS’s
2 Notably, the baseline economic projections do not include cost projections related to potential future emissions regulations (these are addressed in the risk analysis process) or societal impacts (i.e., benefits to the local economy, land use, visual impacts, etc.). Several parties have suggested that APS should explicitly include a cost related to CO2 emissions in the resource planning analysis process. Although APS has decided not to include this factor in the baseline economic analysis at this time due to the uncertain timing and outcome of climate policy, APS recognizes that it is an important factor that must be considered in the decision-making process, and, therefore, has included specific sensitivity analyses to address the questions around this risk factor.
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DRAFT resource strategies. APS stays actively engaged with market participants on many fronts to assess the market conditions. This ever-changing external environment further serves to reinforce the need for flexibility in both APS’s resource planning processes and in the accompanying regulatory processes so that plans can more easily be adjusted for changes. It is likely that APS’s Resource Plan will be modified in the future as we continually learn more from our market monitoring and procurement activities. As an example, it may be desirable to further increase solar resources if future cost and technology trends make solar more competitive with conventional resource options.
1.1.D. APS Resource Needs
One of the hallmarks of Arizona and the APS service territory is the historic growth in customers and their energy consumption. This characteristic is expected to continue for the next two decades despite a short-term outlook that looks less robust. Although APS currently expects the next several years to bring relatively weak economic growth, the Arizona economy is expected to return to more normal levels of growth, albeit lower than historical rates due to the difficulty of maintaining the same growth rate with a larger population and economic base. Continued population migration into Arizona will lead to an average annual customer growth rate of 2.6 percent through 2025. A detailed discussion of APS’s growth forecasts and resource needs assessment is included in Sections 2.2 and 2.3 of this Report.
The demand and energy projections depend on several components that build up the overall demand. The vast majority of the demand is driven by residential and business customers with peak demands of less than three MWs. Growth in the numbers of these customers and in the average use per customer is almost entirely responsible for the expected growth in system peak and energy. Additionally, APS serves approximately 80 customers with peak demands greater than three MWs, as well as a handful of wholesale customers. While these customers account for a modest share of APS’s total system peak and energy requirements, they have a small impact on the future growth in demand.
The APS system peak demand3 is expected to grow to approximately 11,400 MWs by 2025 from 7,321 MWs in 2009, an average annual growth rate of 2.8 percent. Over the previous 20 years (1988-2008), APS’s peak demand increased at the rate of 3.7 percent per year, so the current forecast reflects a slower rate of growth in percentage terms. In absolute megawatts, the peak demand is increasing at an average rate of 269 MWs per year, which is greater than the average increase experienced in the previous 20 years of 189 MWs per year.
3 System peak demand is the greatest demand for energy that occurred or is expected to occur during a prescribed time period. Demand is measured in MWs referring to the generation capacity required to meet the actual or expected demand.
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Energy consumption is increasing at a similar rate.4 Over the next 20 years, annual electricity sales will increase from about 32,800 GWhs in 2009 to 49,800 GWhs in 2025, an average annual growth rate of 2.6 percent. The forecasted increases in energy consumption fully consider the impacts of currently funded energy efficiency programs over the planning horizon. Over the previous 20 years, energy sales increased at a rate of 3.0 percent per year. The single largest contributor to this growth is the increase in the number of customers, primarily driven by steady and sustained population growth. From 2009 to 2025, the number of customers served each year will increase at an average annual rate of 2.6 percent. By 2025, APS will be serving almost 1.7 million customers and the state of Arizona will have almost 10 million residents.
APS has sufficient existing resources (owned generation plus purchases) to meet forecasted customer needs through 2013. Load growth will create a need for additional resources in 2014 and beyond. By 2020, APS will need approximately 4,000 MWs of additional resources to meet projected customer needs. This amount grows to approximately 6,500 MWs by 2025. Customer growth is the major reason for this future resource need. Another reason for this future resource need is the fact that several existing purchased power contracts expire in the coming years.5 The following figure graphically demonstrates the future capacity needs and the required reserve generation to support meeting those capacity needs.
4 Energy consumption describes the use (or delivery) of electricity over a specific time, typically measured in kilowatt hours (“kWhs”). A kWh will provide a kilowatt (“kW”) of electricity for one hour to the customer. Twelve watt hours will operate a typical table lamp equipped with a compact fluorescent light bulb for one hour. 5 Expiring contracts will reduce contracted capacity resources by over 2,400 MW by 2022.
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Figure 1 – Summer Season Resource Requirements vs. Existing Resources
Capacity Needs (MWs) (Summer Season Resource Requirement Versus Existing Resources) 14,000
12,000 Resource Need Existing Resources 10,000
8,000
6,000
4,000
2,000
0 2009 2011 2013 2015 2017 2019 2021 2023 2025
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1.2 APS’s PROPOSED RESOURCE PLAN
1.2.A. APS Resource Plan Overview
APS’s proposed Resource Plan represents a careful balancing of key objectives. Rather than a “least-cost” plan, the Resource Plan aims to strike a balance between minimizing costs to customers, while also addressing identified risk factors, such as reliance on natural gas and CO2 emissions levels. The Resource Plan does not rely on a single resource option to meet future resource requirements. APS believes this is a critical feature of the Resource Plan in light of the heightened uncertainty in the current planning environment.
The Resource Plan identifies four specific energy resources as key opportunities: energy efficiency, renewable resources, potential new nuclear generation, and purchases of gas-fired generation that would primarily support peaking needs. As described throughout this Report, early investment in these resources will retain the greatest range of future options for Arizona and APS. These four opportunities, each with its unique nuances, will help APS meet Arizona’s growing energy needs while mitigating our customers’ exposure to risks associated with volatile fuel costs, carbon regulation, or reliance on only one resource type.
It is critical to note that while this Resource Plan describes a specific mix of resource technologies, in terms of energy and capacity contributions, those outcomes are likely to change. Future revisions of this Resource Plan will recognize those changes.
The primary components of the Resource Plan include the following:
1. Future energy efficiency initiatives are expected to meet 587 MWs of the overall capacity need by 2025. This is in addition to energy efficiency savings that have already been accomplished through year-end 2008. From an energy perspective, the energy efficiency programs are projected to satisfy more than 3,100 GWhs of the total increase in energy consumption by 2025 based upon continuation and expansion of existing efforts. Details on APS’s energy efficiency initiatives related to Demand Side-Management (“DSM”) are provided in Part IV of this Report.
2. Renewable resources comprise a very significant part of the Resource Plan. APS expects to add over 1,650 MWs of renewable resources, and those resources are expected to meet about 44 percent of the growth in energy consumption by 2025. Significantly, the Resource Plan accelerates the adoption of renewable energy sources by doubling the RES requirement by 2015. This acceleration will ensure APS’s continued engagement in renewable markets, and open near-term opportunities for resource development in and around Arizona. For the upcoming 17-year period,
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APS’s recommended Resource Plan includes over 17,000 GWhs of renewable energy beyond the current RES requirements. Additionally, depending upon the type of renewable resources acquired, these resources are expected to make a sizeable contribution towards meeting summer peak capacity needs. The ultimate mix of renewable resources is expected to be determined through a range of procurement initiatives. For purposes of the Resource Plan, APS has assumed that the majority of future non-distributed renewable resources would be solar plants with some contribution from future wind and geothermal resources.6
3. APS’s Resource Plan includes the potential for an addition of new baseload nuclear capacity in 2022 and 2023. The Resource Plan includes a total of 800 MWs of potential new nuclear capacity comprised of 400 MWs in each of two nuclear units. Such a nuclear addition would make a sizeable contribution to APS’s energy supply portfolio. At an assumed annual average capacity factor of 91 percent, nuclear capacity could produce about 6,400 GWhs of energy per year. This would satisfy approximately 38 percent of the expected growth in energy consumption by 2025.
4. The fourth element of the Resource Plan is generation capacity needed predominantly to meet future peak demand. With this Resource Plan, APS aims to reduce the overall fraction of natural gas resources as part of the overall portfolio and drive natural gas resources to more directly serve peak resource needs. The Resource Plan describes that need as up to approximately 3,500 MWs of peaking capacity by 2025. The majority of this capacity—over 2,400 MWs—represents capacity required to replace contracted long-term purchases that expire during the planning period.
In this Resource Plan, APS assumed that gas-fired resources would serve future peaking capacity, whether through wholesale purchases or the construction or acquisition of peaking capacity. Such an assumption was necessary for the evaluation of the Resource Plan, including such elements as overall gas burns, likely carbon emission profiles, required capacity reserve margins, and potential capital costs. However, APS believes that active engagement of the renewable energy market and energy efficiency opportunities, including increased opportunities for demand response, may identify ways in which these resources could play an increasing role in meeting peaking requirements. Similarly, APS believes that wholesale market participants could offer contractual products developed from resources other than the combustion turbines that traditionally are used for peaking capacity that may also meet the Company’s peaking needs.
6 This total includes the contribution from distributed renewable resources, but does not include existing renewable resource contracts, such as the Solana solar plant.
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1.2.B. Fundamentals of the APS Resource Plan
The annual loads and resources compilation is provided in Figure 2, which shows the annual expected resource needs and additions from 2009 to 2025. Additionally, the figure demonstrates the timing for expiration of existing long-term purchase arrangements from various wholesale suppliers.
Figure 2 – APS Resource Plan - Loads and Resources
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 996 1,026 1,036 1,051 1,063 1,100 1,141 1,184 1,227 1,268 1,309 1,349 1,461 1,502 1,543 1,585 1,628 4. Total Load Requirements 8,317 8,398 8,510 8,663 8,784 9,105 9,457 9,828 10,203 10,561 10,914 11,254 11,669 12,015 12,363 12,714 13,070
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00 0 00 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0 0 0 000 0 000 0 00 0 00 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 0 00 0 00 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0 0 00 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 25 55 86 124 159 194 230 272 316 357 396 432 466 499 530 559 587 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0 0 0 0 70 220 320 343 343 343 343 343 423 423 703 703 793 18. Baseload Nuclear 0 0 0 0 000 0 000 0 0 400 800 800 800 19. Gas Combined Cycle 0 0 0 0 000 0 000 528 528 528 528 528 528 20. Peaking Resources 0 0 0 0 000 282 1,034 1,410 1,692 1,974 2,726 2,726 2,726 2,726 3,008 21. Short-Term Market Purchases 0 0 0 0 000 434 490 409 417 447 486 106 399 430 22. Total Future Resource Additions: 41 81 125 180 293 489 637 1,437 2,312 2,671 3,023 3,924 4,818 5,314 5,673 6,024 6,485 23. Total Resources: 8,231 8,629 8,704 9,052 9,161 9,357 9,505 9,828 10,203 10,561 10,914 11,254 11,669 12,015 12,363 12,714 13,070
New Renewable Nameplate Capacity ? 100 106 106 389 459 659 809 855 855 855 955 955 1,035 1,035 1,314 1,314 1,664
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ? New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
The following figure illustrates the additional energy sources and their contribution to meeting the growth in customer energy needs by 2025. The forecasted growth in customer energy consumption is approximately 17,000 GWhs by 2025, an increase of over 50 percent over this same timeframe. Renewable energy resources provide the largest single contribution meeting 44 percent of the total growth in energy needs. The other two sources (energy efficiency and nuclear) would also contribute substantially towards meeting this future energy need.
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Figure 3 – Energy Sources to Meet Growth through 2025
18,000
16,000
14,000 Nuclear
12,000
10,000 Energy Efficiency 8,000
6,000 Annual Energy (GWHs) Renewable 4,000 Resources
2,000
0
The following series of figures provide further detail on the selected Resource Plan. The first figure depicts the projected energy mix for 2025. The results clearly illustrate the diversity of the future energy supply, a key feature of the Resource Plan. Each energy source is less than one-third of the total portfolio with nuclear serving as the largest single resource at 32 percent. Renewable resources and energy efficiency combine to contribute almost one quarter of the total energy portfolio.7 Through leveraging natural gas resources that would serve mostly summer peaking capacity, and with the aggressive addition of non-natural gas resources, natural gas is reduced to only 21 percent of the energy mix by 2025.
7 Note that renewable resources would represent 18% of APS’s retail energy sales by 2025 when measured in the same manner as the RES methodology. Figure 4 is based upon total system energy requirements, rather than as a percent of retail sales as is the case with the RES targets.
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Figure 4 – Projected Energy Mix for 2025
2025 Projected Energy Mix
Renewable (16%)
Nuclear (32%) New EE (7%)
Natural Gas (21%) Coal (24%)
Note: The energy divisor for this figure is total system energy requirements that include retail and wholesale energy sales plus expected system energy losses. This divisor is different than that used to calculate resource contribution as defined in the RES.
Accelerating the addition of renewable resources, as described by this Resource Plan, will result in double the energy required by the RES in 2015. This Resource Plan will also ultimately result in 50 percent more renewable energy than required by the RES by 2025.
Figure 5 – Renewable Energy (non-distributed) Versus RES Targets
(GWHs) 7,000
6,000
5,000 Total Renewable Energy (non-distributed) 4,000
3,000
2,000 RES Target (non-distributed) 1,000
0 2009 2011 2013 2015 2017 2019 2021 2023 2025
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Figure 6 shows projected CO2 emissions through 2025 as a result of the Resource Plan. The expected trend in CO2 emissions over the next six years is flat to slightly declining from current levels. This is due to relatively slow load growth in conjunction with the continued planned addition of clean energy sources, like existing energy efficiency programs and renewable energy purchases such as energy that will be provided from the Solana solar plant. Although there is an increase in overall CO2 emissions in the middle part of the planning period, CO2 emissions would return to approximately current levels if new nuclear units were constructed. This is a significant positive attribute of APS’s Resource Plan. It allows APS to satisfy an increase of over 50 percent in customer energy consumption with effectively no increase in CO2 emissions.
Figure 6 – Projection of CO2 Emissions
Total System CO2 Emissions (Millions of Metric Tons) 24
22
20
18
16
14
12
10 2009 2011 2013 2015 2017 2019 2021 2023 2025
The trend in natural gas consumption follows much the same pattern (and for the same reasons) as the trend in CO2 emissions. Natural gas consumption in 2014 is projected to be below 2009 levels as APS implements energy efficiency programs and adds renewable resources. If one assumes that a new nuclear resource is developed between 2015 and 2022, the Resource Plan forecasts an increased demand on natural gas generation during that period. However, if new nuclear capacity is constructed, natural gas consumption returns to levels that are within approximately ten percent of 2009 amounts once the nuclear resource is on-line.
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Figure 7 – Projected Natural Gas Consumption
Total System Natural Gas Consumption (Millions of mmBTUs per year) 140
130 120
110 100
90 80
70 60
50
40
30 20
10 0 2009 2011 2013 2015 2017 2019 2021 2023 2025
The capital investment required to implement the Resource Plan is described by the following figure. This representation shows the total amount of capital investment required to implement the Resource Plan regardless of whether APS actually constructs and owns new generation resources itself or whether resources are owned by other companies and the power is sold to APS through long-term purchased power contracts. The capital spending represented for transmission is only that investment specifically required to support the delivery of new resources to the load center. It does not include other transmission investments that will be required to satisfy future customer demands or transmission projects already identified in the last 10-year transmission plan filing.8 The figure shows that approximately $18 billion of capital investment will be required by 2025 to develop the resources described by the Resource Plan.
8 APS made its most recent ten-year transmission plan filing on January 31, 2008 in Docket No. E- 00000D-07-0376. Some of the projects identified in the ten-year transmission plan are necessary to implement this Resource Plan. APS’s upcoming 2009 ten-year transmission plan filing will be completed shortly after this Report.
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Figure 8 – Cumulative Capital Spending Requirements
Cumulative Capital Spending ($Billions) 20 Renewable Generation 18 Transmission 16 Conventional Generation 14
12
10
8
6
4
2
0 2009 2011 2013 2015 2017 2019 2021 2023 2025
Note: These costs also include those costs needed to comply with resources required to meet the RES.
The final figure provides a projection of the estimated customer price impacts associated with deployment of this Resource Plan through 2025. The average cost in this figure does not include all components of APS’s cost structure; it illustrates only the costs associated with the supply-side of APS’s operations. This depiction includes the costs to implement customer-side resource programs, such as energy efficiency and distributed energy. Implementation of the Resource Plan will result in a sizeable increase in costs as new resources are added to the system. This highlights the fact that most new resources are expected to cost significantly more than the average current cost of APS’s existing resource base.
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Figure 9 – Projection of Average System Cost
Average System Cost (in cents/KWH) 16
14
12
10
8
6
4
2 2009 2011 2013 2015 2017 2019 2021 2023 2025
1.2.C. Three-Year Action Plan
APS anticipates that the activities required during the next three years (2009 through 2011) will be focused primarily on implementation of energy efficiency programs, renewable resource procurement (including both distributed and non- distributed renewable resources), and initial development steps for the potential nuclear power project. These actions are further explained below. The anticipated need for peaking resources does not begin until 2016, so APS does not believe that specific activity will be required during this Action Plan timeframe beyond the continued exploration of opportunities for additional renewable resources and expansion of energy efficiency measures. However, if attractive market opportunities develop during this three-year timeframe, APS may undertake procurement activities. Additional details related to each of the following activities are provided in Part II of this Report.
1. Renewable Resources – The Resource Plan includes almost 400 MWs (nameplate rating) of renewable resources within the 2013 to 2016 timeframe. Procurement efforts related to acquiring these renewable resources will be the predominant procurement activities undertaken by APS as part of the Action Plan. It is important to note that the Resource Plan should be viewed as a general guideline in terms of timing, amount, and types of renewable resources. The exact timing, amounts, and types of renewable resources will be determined through procurement activities as this provides the best means to factor relevant market variables into the process.
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a. Completion of renewable procurement activities initiated under the on- going 2008 renewable resource RFP – At this time, the quantity or specific types of resources that will be procured under this RFP are not known. APS does not expect to procure all of the identified renewable resource needs through this RFP.
b. Future RFPs – Timing of future renewable resource RFPs will be determined at a future date and will be dependent upon the outcome of the current RFP and market variables.
c. Distributed Energy – Continued growth of customer programs and the resulting participation, along with the identification and implementation of strategies to increase the role and best leverage the opportunities presented by distributed energy, will be an important focal area during the Action Plan timeframe.
2. Nuclear Resources – While APS does not expect to commit to construction of a nuclear power plant within the Action Plan period, the Company will engage in activities that would allow a thorough evaluation of new nuclear as a baseload resource in the 2022 timeframe. Those activities will include evaluation of current technologies, suitable sites and siting requirements, cost estimates, regulatory processes and scheduling options. The specific actions undertaken by the Company during this timeframe would be calibrated to preserve the option to deploy a new nuclear resource as soon as 2022.
3. Energy Efficiency – The ramp-up of expenditure levels for existing energy efficiency programs and introduction of new programs required to accomplish higher energy reduction targets are included in the Action Plan. Details of APS’s near-term efforts are provided in Part IV of this Report.
4. Peaking Resources – Activity during the three-year window may also include securing one or more potential sites for future development and market activity designed to preserve resource procurement opportunities.
1.2.D. Transmission Needs
Transmission is an important component of APS’s Resource Plan. Adequate transmission either must currently exist or must be planned and constructed to support future resource plans. Transmission, usually required for the deliverability of the resource to load, plays a key role in integrated resource planning from both a cost and timing standpoint. APS’s resource planning and transmission planning organizations coordinate their plans to ensure consistency in the two plans as they are developed. With the help of the resource planning organization, the transmission planning organization
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APS also participates in the Commission’s Biennial Transmission Assessment (“BTA”) in which the adequacy and reliability of Arizona’s existing and planned transmission system is examined as required by A.R.S. § 40-360.02. As part of this process, APS and other members of the electric industry must file ten-year plans outlining specific information relating to their plans for new transmission during the ten-year period. The Commission recently concluded its Fifth BTA in which it examined and assessed the ten- year plans covering the 2008 to 2017 timeframe.9
Maximizing the utilization of the existing transmission system is important to the resource planning process, as well as the transmission planning process. Application of concepts such as “energy only” use of the eastern transmission path provides a way to utilize existing transmission to a greater degree in order to bring renewable wind energy to APS customers at the lowest possible cost. APS foresees future use potential for the existing transmission paths as described below:10
1. Eastern Transmission Path
The eastern transmission path will continue to be used to bring the current baseload resources as well as peaking resources to APS’s load center. It will also be used, as described previously, to bring “energy only” wind resources to APS’s load. Additionally, after 2020 when the PacifiCorp diversity exchange expires,11 additional wind resources will be able to utilize the eastern transmission path to bring renewable resources to APS’s load. Lastly, the path is currently used, and will continue to be used, to provide an “as available” path to APS’s load for times when economically beneficial energy can be imported on this path.
2. Palo Verde Transmission Path
The Palo Verde path is a very important path to APS customers because of the diversity of resources that can utilize the path. The Palo Verde transmission path is used to bring in many existing resources, including nuclear, combined cycle gas, and long-term purchase power. As a major market hub, it is also used to fill short-term resource needs with short-term market purchases and hedges. Looking forward, the Palo Verde path can be used for additional long- term and short-term market purchases from physical assets that currently exist
9 Decision No. 70635 (Dec. 11, 2008). 10 Each of these transmission paths is discussed in more detail in Section 3.1.G. below. 11 See discussion in Section 3.1.B.iv.
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at or near the Palo Verde hub.12 In addition, the area around and west of the Palo Verde hub contains some of the best solar resources in the country. APS expects that at least a portion of the future solar resources specified in the Resource Plan will be developed in relatively close proximity to this hub area and will be supported by this transmission. APS currently has plans to expand the capability of this valuable transmission path.
3. Navajo Transmission Path
The Navajo transmission path will continue to be used to bring existing baseload resources to APS load. The Navajo path is not an active hub or market for power and, as such, has limited uses. However, APS uses this path to import power on an as-needed basis. In such case, this path can be used to purchase resources from the California Independent System Operator (“CAISO”) at Moenkopi.13 Additionally, the path can be used to bring wind resources to APS load. The area in and around Moenkopi has been identified as a potentially good wind resource, and there is potential of purchasing future wind resources in that area which could utilize the remaining capability of this path.
4. Mead Transmission Path
Currently, the Mead transmission path is partially utilized by APS with a peaking PPA purchase. The Mead substation is a liquid trading hub14 and, therefore, one of the future uses of this path is expected to be as a purchase point for market purchases and hedges. Additionally, there are good wind resources in the area around Mead, and the path has the potential to be used to deliver wind resources to APS load.
The additional utilization of the existing transmission system as described above provides a good start to enabling the acquisition of resources to serve APS’s customers. However, as load grows, additional transmission needs will develop.
Several of the projects included in APS’s latest ten-year transmission plan are an important part of implementing the Resource Plan. The following projects all play a role in increasing APS’s ability to bring various resources15 from the Palo Verde area into the Phoenix load pocket:
12 The Palo Verde hub includes the Palo Verde, Hassayampa, and future Delaney substations, as well as the Gila Bend area. 13 Moenkopi is a site in northern Arizona at which APS’s transmission system is interconnected to the CAISO grid. 14 A liquid trading hub is a location on the transmission system with favorable characteristics such that it can support robust trading activity. Favorable characteristics include: numerous potential buyers and sellers, and a large amount of generating resources and/or transmission lines. 15 Examples are the Solana solar plant and the other solar resources described by this Resource Plan.
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• Palo Verde hub to Sun Valley • Sun Valley to TS-9 • TS-9 to Pinnacle Peak
To implement this Resource Plan, additional transmission will be required beyond that described in the existing ten-year transmission plans. The additional transmission will include three main components: i) additional transmission capacity from the Palo Verde hub to the Phoenix load center; ii) additional transmission for specific interconnections to the existing and planned transmission system; and iii) additional transmission infrastructure needed to support a new nuclear resource. This transmission discussion is limited to transmission lines that will need to be built to allow the delivery of remotely located resources to the Phoenix load center. Additional transmission upgrades will be required inside the Phoenix load center to accommodate future load growth, and these upgrades will be addressed in future ten-year transmission plan reports.
First, additional transmission capacity will need to be built from the Palo Verde hub to the Phoenix load center. This transmission capacity is a robust component of the overall APS transmission and resource need. The Resource Plan includes almost 750 MWs of new solar power plants by 2025.16 In addition to the interconnection facilities needed to support new generation resources near the hub, APS expects to require additional Palo Verde transmission capacity to deliver these resources to load. Future load growth patterns are likely to play a role in determining the most advantageous options for new Palo Verde transmission capacity. However, APS currently expects to require additional Palo Verde transmission capacity in the 2018 timeframe.
Second, additional transmission will need to be built for specific interconnections to the existing and planned transmission system. Although specific sites have not been determined for the future peaking resources included in this Resource Plan, APS expects that some portion of these resources will be located either within or adjacent to the Phoenix load center. The transmission facilities required to interconnect these resources will depend on the specific locations of those resources. These facilities may range from adding a bay to an existing substation to building several miles of transmission line and a new substation.
The final transmission component beyond those in the ten-year plan would be the additional transmission infrastructure that would be needed to support a nuclear resource. At this time, APS has not completed the selection of a preferred location for a future nuclear plant. However, it is likely that multiple extra-high voltage (“EHV”) transmission lines will be needed to support this major resource addition. APS will furnish additional information on this topic in future resource plan updates and ten-year transmission plan filings as the project specifics are further developed.
16 This amount is in addition to the Solana solar plant.
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1.2.E. Regulatory Actions to Support this Resource Plan
Constructive regulatory support will be absolutely necessary to enable APS to implement this Resource Plan. It is crucial that APS is in alignment with the Commission when making long-term resource planning and procurement decisions, because billions of dollars of commitments must be made to provide reliable energy to Arizona. APS will not be able to consider capital-intensive resource options, such as those outlined in the Resource Plan, without clear support from the Commission for its resource choices.
Several areas of regulatory support will be necessary to enable APS to implement the Resource Plan. Competition for available capital investment dollars, especially in today’s uncertain and risky economy, will require a strong financial footing. Rebuilding APS’s financial strength to the point where future resource options can be effectively evaluated and pursued is critical to ensure this resource planning process can be implemented. New investment in infrastructure will require APS to regain its solid investment grade credit rating and will require APS to earn its authorized return on equity capital on a regular basis.
One of the early regulatory actions that will be important in furthering this Resource Plan is ACC approval or acknowledgement of the plan or a modified version of the plan. This will ensure that APS understands which resource choices should serve as the starting point in a roadmap designed to fulfill the state’s long-term resource needs. Another important regulatory action that is critical to implementing the levels of energy efficiency identified in the Resource Plan is to address the financial disincentive that currently affects the ratemaking structure for these programs.17 A constructive resolution of this issue is needed for APS to increase energy efficiency programs to the level identified in the Resource Plan.
APS anticipates that the following regulatory actions will be required for specific activities described by the Action Plan:
a. Approval of long-term renewable purchase contracts. APS is not certain as to the exact timing of these regulatory approval requests as they will be largely dependent upon the results of currently on-going and future procurement activities.
b. Approval of costs for renewable projects that are above the costs of conventional generation to allow APS to surpass the RES requirement.
c. Approval of future program filings for energy efficiency programs. Although regulatory processes are already in place for this, timely regulatory action will be required to support achievement of the aggressive
17 See Docket No. E-01345A-08-0172.
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energy efficiency levels recommended in this Resource Plan. Additionally, as mentioned above, adequate mechanisms must be adopted that remove the current financial disincentives for the Company to increase its investment in energy efficiency.
d. Approval of future filings for distributed energy program enhancements, specific projects and/or unique opportunities to leverage distributed energy resources.
e. Commission approval of costs incurred for activities that allow for the thorough evaluation of new nuclear as a baseload resource in the 2022 timeframe. The Company will need certainty of recovery of these costs regardless of the final decision on moving forward with a new nuclear plant.
The Financial Sustainability section in Part II of this Report provides more discussion on subjects that will necessitate increased collaboration to achieve the objectives of the Resource Plan and meet Arizona’s growing energy needs.
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1.3 STAKEHOLDER INVOLVEMENT IN THE DEVELOPMENT OF THIS PLAN
As part of the process of preparing this Report, APS conducted a number of formal and informal meetings with various stakeholder groups. These meetings were used to present current information to the stakeholders on APS’s need for new resources (the gap between projected electric loads and the capabilities of current resources), the types of new resources available to meet the need, and the costs of meeting the need utilizing alternative resource portfolios. The meetings also were used to receive stakeholder views on various topics related to the process of planning for new resources, such as the costs of complying with climate change legislation and the hedging of fuel costs.
As part of the Alternative Resource Plan filing made in January 2008, the Company conducted six stakeholder meetings using an independent facilitator to manage these meetings.18 The meetings were broadly attended with 35 to 50 stakeholders from state government agencies, city representatives, merchant generators, conventional and renewable energy developers, consultants in the energy field, energy efficiency advocates, representatives from some of APS’s large customers, and other utilities attending each meeting. Stakeholders were encouraged to participate in the meetings and were given opportunities to make presentations to the group as part of the agenda.
The meetings concluded with the Company eliciting stakeholder feedback on a wide range of subjects related to the stakeholder meeting subjects, process, and attendance. Many participants completed the questionnaire and provided feedback during the discussion period.
The Company also engaged other stakeholders through a series of informal meetings conducted throughout the state. Meetings were conducted from Yuma to Flagstaff with representatives from various governmental organizations (i.e., city councils) and APS customers. APS made informational presentations relating to its future resource needs, engaged in question and answer sessions relating to those needs, and elicited participant views. These views were captured and have been added to those obtained from the six formal stakeholder meetings.
APS believes that the stakeholder process provided valuable insight for purposes of developing a resource plan that departs from traditional “least-cost” planning principles. The Company also believes that these meetings have provided stakeholders with a better understanding of the resource planning process, the current need for new resources, and the resource alternatives that could be used to fill that need. APS is
18 The agendas for these meetings, along with all the presentations and other reference materials from the meetings, are available on the web at www.aps.com/resources. APS also filed a summary of each stakeholder meeting with the ACC in the Resource Alternative Report docket (see Docket No. E-01345A- 08-0010).
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DRAFT supportive of the need for, and value of, having additional stakeholder involvement in the resource planning process. As part of this docket, APS intends to conduct an additional stakeholder meeting to discuss the Resource Plan and this Report. APS also expects that these parties will continue to participate in the resource planning process.
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PART II
RESOURCE PLANNING: CHALLENGES, NEEDS, AND MARKETS
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2.1 CURRENT CHALLENGES IN RESOURCE PLANNING
The current economic and business environment presents major challenges for resource planning. From an economic perspective, Arizona is currently experiencing a dramatic economic downturn that has resulted in a reduction in economic growth. APS’s near-term customer growth has decreased to a relatively minimal level, and it is important to recognize the challenge that this poses for resource planning. One goal of resource planning is to provide needed electricity resources in an economically efficient manner. This is increasingly difficult to achieve when the goal, which is defined by customer load growth, becomes unstable and difficult to predict. Regardless of the current national economic climate and its impact on the regional economy, however, Arizona remains an attractive place to live and conduct business. APS expects customer growth to return to more typical levels within the next several years.
Some of the required electric resources described by this Resource Plan unavoidably involve long lead times. It is vital that APS, the Commission, and other stakeholders in Arizona’s energy future maintain a long-term perspective on growth and the energy resources needed to meet future needs. This growth challenge also points to the need for communication and flexibility in the resource planning process. Customer growth trends must be continually monitored and resource plans will need to be adjusted based upon insights from economic observations, continued market engagement efforts, and technological evolution.
Arizona and APS face several major challenges beyond those that are caused by uncertainty in growth. This section will provide a brief overview of each of these challenges as listed below:
• Cost Escalation • Environmental Regulation • Natural Gas Price Levels and Volatility • Financial Sustainability • Retail Competition
2.1.A. Cost Escalation
Rapidly rising costs are affecting virtually every business, including APS. The cost of expanding the electricity production and delivery infrastructure has quickly risen over the last couple of years. For example, APS estimates that the cost of constructing a new natural gas-fired combined cycle power plant has more than doubled in the six years since 2002 when APS completed construction of its newest natural gas power plant, the Redhawk Power Plant. Through our ongoing procurement processes and market evaluations, APS has also observed substantial increases in the price of renewable energy projects over the last four years, particularly for wind and geothermal resources. Several factors are tied to these cost trends; one with a particularly large impact is the global
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DRAFT demand for many commodities, such as crude oil, steel, cement, and copper. This demand has increased as emerging economies, such as China and India, have expanded their manufacturing capacity and internal consumption.
The following figures illustrate cost trends that are relevant to electric resource construction. Indexes are useful tools for purposes of monitoring price trends. An index is a basket of goods, defined by the purpose of the index itself, whose prices/values are aggregated and monitored for purposes of observing market trends. The first figure presents an index that is based on Bureau of Labor Statistics (“BLS”) data and representative of general construction cost trends. All of the indexes presented have seen significant increases over the 10-year period shown, a trend that is broadly observed throughout the utility industry.
Figure 10 – BLS Cost Index for New Utility Construction
Index New Construction (BLS Index) Value 225
200
175
150
125
100 Jan-98 Jan-99 Jan-00 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04 Dec-05 Dec-06 Dec-07
Source: Bureau of Labor Statistics (BLS)
The next two figures show specific cost categories that are closely related to power plant construction costs. These figures show several periods of rapid and distinct increases in cost, most notably in 2003 and again in 2007.
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Figure 11 – BLS Cost Index for Boilers, Heat Exchangers, and Condensers
Index Power Boilers, Heat Exchanges & Condensers (BLS Index) Value 350
325
300
275
250
225
200
175
150
125
100 Jan-98 Jan-99 Jan-00 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04 Dec-05 Dec-06 Dec-07
Source: Bureau of Labor Statistics (BLS)
Figure 12 – BLS Cost Index for Iron and Steel Pipe
Index Iron & Steel Pipe (BLS Index) Value 350
325
300
275
250
225
200
175
150
125
100 Jan-98 Jan-99 Jan-00 Dec-00 Dec-01 Dec-02 Dec-03 Dec-04 Dec-05 Dec-06 Dec-07
Source: Bureau of Labor Statistics (BLS)
These cost trends pose unique challenges. First, it is difficult to predict what infrastructure projects will cost because major projects typically require several years of planning and development prior to actual construction. The above figures highlight that costs for utility projects can change dramatically during a multi-year development and
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DRAFT construction period. Second, this rising and unstable cost environment has made it difficult for companies that specialize in power plant construction to control their costs, and they have become unwilling to enter into contracts that guarantee fixed construction costs. Thus, utilities (and power plant developers) have had to accept a much greater percentage of the risk of changes in construction costs for major infrastructure projects.
Recently, some commodity prices have begun to moderate as the economies of the United States and other countries have slowed. As of the time of this writing, crude oil prices have fallen below $50 per barrel (after reaching a high of over $140 per barrel in the summer of 2008) and copper prices have fallen below $2 per pound (after reaching a high of approximately $4 per pound in the summer of 2008). While this decline in commodity costs is welcome, it does not diminish the uncertainty or the magnitude of uncertainty in planning for future costs.
2.1.B. Environmental Regulation
APS currently faces unparalleled challenges with respect to environmental regulation. During the early years of this Resource Plan, new environmental requirements that will apply to APS, primarily through the federal Clean Air Act, are anticipated; though precisely how and to what extent remains uncertain. In addition to these anticipated requirements, there is also substantial discourse regarding the need for new environmental regulations to address climate change. These expected but uncertain environmental regulations, in addition to existing regulations, make resource planning particularly challenging.
Within the next three to five years, APS expects to become subject to new environmental requirements under two key Clean Air Act programs: the Regional Haze program and mercury regulation. The Regional Haze program requires an analysis of the impacts of air emissions from facilities on visibility in pristine air areas, such as the Grand Canyon. If cost-effective pollution control technology can be effectively implemented to minimize regional haze and improve visibility in such areas, facilities will be required to install those controls, known as the “Best Available Retrofit Technology” or “BART.” The precise nature of those controls has not yet been determined. Ultimately, the Environmental Protection Agency (“EPA”) and the Arizona Department of Environmental Quality (“ADEQ”) will specify what constitutes BART for APS’s facilities.
Another anticipated environmental regulatory program is mercury control. Although the U.S. Court of Appeals for the D.C. Circuit recently struck down the federal Clean Air Mercury Rule,19 the EPA is now mandated to issue new regulations requiring reductions in mercury emissions. The EPA has not yet proposed such regulations, but those rules may require additional pollution control measures at APS’s power plants.
19 New Jersey v. EPA, 517 F.3d 574 (D.C. Cir. 2008).
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Finally, the debate surrounding climate change and climate change legislation continues to escalate. There are currently regulatory/legislative initiatives advancing at the state, regional, and national levels. In all of these initiatives, it is clear that the electric utility industry will play a central role in any climate change regulatory scheme. APS believes it is likely that climate change requirements will be enacted, at either the state or federal level, within the next several years. Therefore, climate change is a key issue in this Resource Plan and the choices that it advocates.
A key challenge of the resource planning process is determining how to incorporate the potential of future climate change regulatory schemes into the decision- making process. Although potential regulatory schemes are advancing, at this time it is not possible to ascertain the exact parameters of these programs or to accurately predict the monetary value or impacts of CO2 emissions. These potential CO2 costs will be reflected qualitatively in the technology screening analysis that follows in Part III of this Report and quantitatively in the resource portfolio analysis, also in Part III of this Report.
For context, the following figure provides a comparison of the approximate CO2 emission rates of various resource technology types.
Figure 13 – Approximate CO2 Emission Rates
Resource Average CO2 Technology Emission Comments (metric tons / MWh) Existing Coal Units Number represents a projection of fleet- 0.98 wide average for 2009 New Conventional Coal20 APS’s projection for a new, supercritical, pulverized coal unit using hybrid-cooling 0.86 technology (size is approx. 470 MWs) and without CCS Existing Gas Combined Cycle Projection based upon APS’s anticipated 0.42 utilization patterns for Redhawk plant Existing Gas Combustion Projection based upon APS’s anticipated Turbines 0.61 utilization patterns for Sundance plant Nuclear 0 Energy Efficiency 0 Renewable Sources (wind, solar, geothermal) 0 Note: Values are calculated based on calendar year 2009 results derived from analysis of the Resource Plan.
From the above figure, it is clear that conventional coal units are the most CO2 intensive resource technology in APS’s generation portfolio, with approximately double the
20 Appendix 1 - APS Resource Alternatives Report, January 2008 (available at http://www.aps.com/_files/various/ResourceAlt/APS_Resource_Alternative_Technical_Analysis_010708 .pdf).
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DRAFT emissions rate of natural gas combined cycle units. Emission rates for the new conventional coal units illustrated in Figure 13 do not assume the addition of any emission controls for CO2, such as carbon capture and sequestration (“CCS”). While CCS technologies have the potential to reduce emissions from coal generation, APS believes these technologies are several years away from broad commercial deployment. Also noted in the above figure are several resource technologies (nuclear, energy efficiency and renewable resources) that have no CO2 emissions. Adding technologies to APS’s resource portfolio that have no CO2 emissions will provide a cost advantage in any scenario in which costs are ascribed to CO2, because they will reduce the Company’s cost exposure relative to a default resource plan. The risk mitigation element was highly valued in the development of APS’s Resource Plan.
2.1.B.i. GHG Policy and Regulation
Arizona is one of several states participating in a regional climate change program called the Western Climate Initiative (“WCI”). In all, seven western states and three Canadian provinces are involved in the WCI. Recently, the WCI released design recommendations for a program to control and reduce GHG emissions. The WCI recommendation envisions a regional cap-and-trade program with the overall goal of reducing GHG emissions by 15 percent below 2005 levels by 2020. Arizona’s former Governor Napolitano had committed to reduce Arizona’s GHG emissions to Year 2000 levels by 2020, which is an estimated 11 percent reduction below the Year 2005 level. This regional cap-and-trade program is slated to begin in 2012 for major stationary emission sources (such as electric generation plants).
The United States Congress has been actively debating potential legislation to address climate change for a number of years. The United States Senate conducted floor debate on a number of bills in 2008. Although none of the bills passed, it is useful to look at the provisions of the more developed and discussed bills as they represent the most detailed insights on climate change legislation discussed in Congress. Generally, the goal of this type of legislation is to gradually reduce GHG emissions by moderate levels through the planning timeframe in this Resource Plan (most frequently referenced at about 20 percent below current levels by 2020), and by more aggressive levels through the middle of this century (about 60 to 80 percent below current levels by 2050). Cap- and-trade legislation would establish a national market for emission allowances, and it would provide an allocation to a number of industries including the electric power sector.
APS has reviewed the provisions of a broad range of proposed legislation and compared the “range” of anticipated allowance allocation to APS’s expected CO2 emissions under a default resource plan expansion scenario and under this Resource Plan. For this analysis, the cap-and-trade program would start in 2012, and by 2031, the allocation of allowances to electric utilities would be completely eliminated. The following figure compares a reasonable estimation of anticipated allocation of allowances with the projected CO2 emissions under both a default resource plan scenario in which
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DRAFT natural gas generation would be used to meet future needs and under the Resource Plan proposed in this Report.
Figure 14 – Impact of GHG Cap-and-Trade Legislation
Projected Impact of Future CO2 Legislation
22 Projected Emissions 20 "All Gas Default" Plan 18
CO2 Emissions 16 "Resource Plan" Gap of 12.9 MM tons to 14 Resource Plan
12 Gap of 18.0 MM tons to 10 All Gas Default Plan
8
6 Assumed Allowance 4 Allocation
2
0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
The figure illustrates the large potential gap between APS’s potential CO2 emissions and the expected allocation of allowances. This gap is projected to be about 10 million metric tons in 2015 in the default resource plan and about nine million metric tons in 2015 in this Resource Plan, a gap reduction of approximately one million metric tons. In the near-term, the cost of resolving the allowance deficiency will be largely a function of the market price for allowances. Several prominent consultants and government agencies have developed estimates of the expected allowance prices in 2015. Based on a review of these estimates and based on an assessment with respect to the timeframes in this Resource Plan, APS estimated a lower end price of $25 per metric ton in 2012 and $36 per metric ton in 2024. At this allowance price, APS’s costs under the default resource plan would increase by $525 million in 2024, representing an approximately 18 percent price increase for customers.21 Under the proposed Resource Plan, APS’s costs would increase by $460 million in 2024, a risk mitigation of $65 million. Also, based on consultant and government cost estimates, APS estimated a higher end price of $50 per metric ton in 2015, which would result in $71 per metric ton in 2024 based on an assumed escalation rate of 3.0 percent. Using this allowance price, APS’s costs would increase by $1.051 billion in 2024 under the default resource plan,
21 This is compared to a current annual revenue requirement level of $3.0 billion.
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DRAFT representing a price increase to customers of approximately 35 percent. Under the proposed Resource Plan, the cost increase would be $920 million in 2024, a risk mitigation of $131 million over the default resource plan.
One additional indicator of the potential for future climate change requirements comes from newly-elected President Obama, who has indicated his support for climate change legislation. He is a vocal proponent of enacting a climate change regulatory regime based upon a cap-and-trade mechanism. It is likely to take the incoming administration some months to develop adequately detailed legislation for APS to model cost impacts.
2.1.B.ii. Near-term Implications of Climate Regulation
In the long-term, compliance with climate change policies can be influenced by the resource choices that result from the resource planning process, a primary purpose of this Resource Plan. It is difficult and costly to make significant changes to APS’s resource portfolio in the near-term; APS would have only three options to achieve compliance with GHG regulations during that period. First, some of the allowance deficiencies22 could be satisfied through the purchase of allowances in the open market at the prevailing emission allowance price. The second option would be to switch generation resources to lower emission resources to reduce APS’s total CO2 emissions (“fuel switching”). The third option would involve purchasing emission “offsets” to counterbalance CO2 emissions from generation resources.
ICF Consulting has conducted analyses for the WCI to estimate future emission allowance prices.23 The reported estimates range from $24 per metric ton to $71 per metric ton24 depending upon program design parameters, such as the scope of the emissions source and the degree to which offsets will be allowed to meet CO2 reduction targets.
Fuel switching to reduce APS’s total CO2 emissions would involve increasing generation from existing natural gas resources and reducing generation from existing coal resources. The total cost of a fuel switching strategy would depend greatly on fuel price differentials—the difference between natural gas prices and coal prices. These fuel price differentials are likely to be impacted by the extent to which other electric utilities adopt the same strategies. For example, assume that for each megawatt hour (“MWh”) of coal generation that is replaced with natural gas generation, CO2 emissions would be reduced by 0.55 metric tons and that each MWh of natural gas generation will cost roughly $40
22 Deficiencies are measured as the difference between total Company emissions and amount of allowances allocated directly to APS. 23 Appendix B of Western Climate Initiative Design Recommendations for the WCI Regional Cap-and- Trade Program dated September 23, 2008. 24 Cost estimates are for Year 2020 allowance prices.
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DRAFT per MWh more than the coal generation.25 Achieving an emissions reduction of one million metric tons, or about 6 percent of APS’s projected emissions for 2009, would require that 1.82 million MWhs of coal generation be replaced with the identical amount of natural gas generation. The cost of this one million metric ton emission reduction would be approximately $73 million.
An emission offset is an emission reduction project undertaken to address GHG emissions that are not included within the scope of the cap-and-trade program. A reforestation program is a good example of an emission offset project. In its current format, the WCI program has capped the use of offsets to represent no more than 49 percent of the total emission reductions required from 2012 to 2020. Offsets do have the potential to serve as a cost containment mechanism for achieving compliance with GHG regulation.
2.1.C. Natural Gas Price Levels and Volatility
For many years, the price of natural gas was relatively stable. In recent years, the global demand for natural gas and uncertainties surrounding its production has resulted in higher prices and unprecedented volatility. As a result, projecting natural gas prices into the future is one of the most difficult challenges in the resource planning process. Because of the high degree of market price volatility, the projected natural gas price used in the resource planning analysis is oftentimes not reflective of actual market conditions by the time the analysis process is completed. Figure 15 provides some indication of this extreme price volatility.
25 Based upon an assumed coal price of $1.75/mmBTU with a heat rate of 10.5 mmBTUs/MWh and a natural gas price of $8.00/mmBTU with a heat rate of 7.5 mmBTUs/MWh.
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Figure 15 – History of NYMEX Natural Gas Prices
NYMEX Natural Gas Prices (prompt month) 14
13
12
11
10
9
($/mmBTU) 8
7
6
5
4 1/3/2006 6/2/2006 10/30/2006 3/29/2007 8/26/2007 1/23/2008 6/21/2008 11/18/2008
Over the course of the last two years, the New York Mercantile Exchange (“NYMEX”) prompt month contract26 has traded at prices below $5/mmBTU and above $14/mmBTU. In fact, the natural gas price has fallen from over $14/mmBTU in July 2008 to under $6/mmBTU in December 2008. This type of short-term price variability clearly illustrates the risk of over-reliance on natural gas resources and the difficulty in conducting meaningful resource planning analysis with respect to natural gas costs. For this reason, it is important to conduct a risk analysis to highlight sensitivities within the resource planning framework. Wildly fluctuating prices are particularly undesirable with respect to resource planning and operating economics, therefore a key function of the Resource Plan is to investigate the level of reliance on natural gas consumption.
2.1.D. Financial Sustainability
Regulatory support from the Commission will be necessary for APS to secure financial sustainability and to allow APS to implement the Resource Plan. As large financial commitments must be made by APS to ensure that our customers are served with reliable energy, APS must be aligned with the Commission in making long-term resource planning and procurement decisions. Without clear Commission support, APS will not be able to consider or implement capital-intensive resource options such as those outlined in the Resource Plan.
Commission acknowledgement of this Resource Plan is the first in a series of very important actions necessary to implement this Resource Plan. Acknowledgement will
26 This is a contract for the next delivery month.
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DRAFT represent a ratification of the starting point for a roadmap designed to fulfill the state’s long-term resource needs.
2.1.D.i Regulatory Environment for Resource Planning
A resource planning process that results in an ACC decision provides an increased level of regulatory certainty that will be necessary to effectively implement the Resource Plan. Recognition that a utility’s long-term planning choices are reasonable is essential to allow APS to attract the necessary investment dollars to proceed with major long-term resource planning. To that end, if the Commission approves or acknowledges the reasonableness of this Resource Plan, and subsequent updates to this Resource Plan, that approval or acknowledgement should be given considerable weight in subsequent Commission proceedings, such as ratemaking proceedings in which the infrastructure additions will be placed into rate base.
The resource planning process will also provide the public with an understanding of APS’s planning process, and the ACC’s approval or acknowledgement of the Resource Plan will provide the public with confidence that a reasonable long-term resource plan will be executed to meet their future energy needs. This process will also provide potential counterparties that would contract with APS to provide generating resources with assurances of APS’s ability to recover the costs of the new resources and its ability to meet its obligations under such contracts.
It is also important that the approval process for this Resource Plan be expeditious. The competitive market is dynamic, and rapidly changing conditions will impact the cost and availability of energy resources.
2.1.D.ii. Flexibility Within the Planning Process
Resource plans and the Commission’s approval or acknowledgment of those plans provide a firm foundation for the overall resource planning process. However, long-term plans of any kind are subject to changing conditions which are largely or entirely outside the control of the utility or the Commission. This uncertainty can create substantial financial risk for projects that have not been specifically approved or accepted by the Commission, and the Company will need more than the approval or acknowledgement of the overall Resource Plan to obtain necessary financing for projects. Because costs for resources are substantial, APS will not be able to commence significant resource acquisition or construction without the Commission’s clear acceptance of specific projects.
Significant future changes, such as new regulations, supply-side constraints, and dramatic cost increases, could materially impact a long-term resource choice that had been previously determined to be a preferred resource within an approved or acknowledged resource plan. Under these circumstances, while it may have been
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DRAFT reasonable initially to pursue a specific resource, the more prudent approach may be to pursue another resource option altogether. For this reason, allowing APS to amend this Resource Plan will significantly mitigate the inherent risks and uncertainties for significant future financial investment.
2.1.D.iii Approval with Periodic Review
Electric generation projects evolve over several phases—from planning to development to the actual construction of the plant and finally commencement of commercial operation. A number of significant decisions are made, and APS is required to spend substantial capital dollars, during each phase of a generation project. This project life-cycle lends itself well to a regulatory policy, as exists in the current version of the modified resource planning rules, in which a utility seeks approval to construct a specific resource, consistent with an acknowledged integrated resource plan, and, upon approval, provides the Commission with periodic updates on the progress of the project. These updates would allow the Commission to review and approve any changes proposed by the utility, taking into consideration new information such as impacts of environmental mandates, changes in economic conditions, and the availability and applicability of new technology. At the conclusion of each annual review, those costs that had been reviewed and approved by the Commission could be recovered through one of the cost recovery mechanisms discussed below.
Significantly, in this regulatory model, if these annual updates show that a previously approved project is no longer feasible or economical and the Commission agrees that cancellation of the project is prudent, costs expended on that project to date should then be recoverable as well. Such an approach significantly minimizes the risks involved in the types of large-scale, long-term investments that the Company will need to make to implement its Resource Plan.
2.1.D.iv Cost Recovery
Unlike the regulatory model discussed above, traditionally cost recovery for a capital project is determined when the company includes that plant in rate base in a formal rate case. The delays between a planning decision, capital expenditures, resource operation, and ultimately cost recovery increases uncertainty for the company and its prospective lenders. This approach will not work for long-term resource projects in the current economic climate. When such risks are accepted by businesses and the financial community, it is typically under the expectation of increased returns.
The magnitude of expenditures required to implement this Resource Plan is great, several times greater than APS’s total current capitalization. As such, APS could not risk its financial viability to make these considerable expenditures and may not be able to access capital markets at all without some certainty that the Commission concurs with a project, and some assurance that related expenditures will be recovered. The following
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DRAFT mechanisms are successfully utilized cost recovery mechanisms that individually, or in some cases combined, create an even stronger cost recovery policy to allow utilities to meet expanding capital expenditure requirements required as a result of an acknowledged resource plan.
a. Construction Work In Progress (“CWIP”) in Rate Base
One tool that the Commission could consider to both smooth the future rate impact of a large capital project, and improve cash flows and the utility’s balance sheet during a period of high capital spending is the inclusion of CWIP27 in rate base. In fact, this mechanism was used when Palo Verde was constructed for precisely these reasons.
Because of its direct relation to the Company’s construction program, this tool is particularly useful to prevent the erosion of cash flow that would otherwise result from the levels of capital spending required in APS’s Resource Plan. Providing CWIP in rate base also reduces the impact of a single, substantial rate increase to customers by phasing into rates the capital expenditures associated with a given project over time. By providing greater cash flow, this regulatory tool also reduces the utility’s financing costs and the overall level of the investment that is capitalized upon completion, thereby lowering the long-term costs that would be passed to customers. Moreover, because this plant adjustment produces a return on a base of the actual costs the Company incurs, the costs are known and measurable. Including these costs in rates can be accomplished through either an adjustment mechanism of the type described below or by including a fixed amount in rate base during a formal rate proceeding (or a combination of these two approaches).
The inclusion of CWIP in rates over the entire construction period lowers the total capitalized cost and, as a result, lowers the Company’s revenue requirement at the plant’s in-service date. This type of regulatory support has a profound impact on the ability of a utility to secure the financing needed to construct the project. APS believes that this regulatory treatment is a necessary component of successfully developing capital intensive resources, such as new baseload power plants and new solar power plants. Figure 16 illustrates the magnitude of this reduction in revenue requirements at the plant’s in-service date, comparing resource development under traditional development financing and resource development leveraging CWIP in rates. As can be seen in the figure below, the revenue requirements after the in-service date under the CWIP case is about 27 percent less than under the traditional case due to the reduced capital cost.
27 Construction Work in Progress (CWIP) is the balance shown on a utility’s balance sheet for on-going construction that is not yet completed.
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Figure 16 – Revenue Requirement Reduction Through CWIP
1,200
Depreciation 1,000 Income Taxes Capital Costs
s 800
600 $ Million $
400
200
0 Traditional CWIP in rates
Assuming: a 1,000 MW baseload capacity plant at a direct construction cost of $5.0 billion spent over a seven-year period in a pattern traditionally experienced for baseload plants; new financing, consisting of 50% debt at a 7% annual cost rate and 50% equity issued at $35/share with a $2.10 dividend rate and at an 11% cost rate; and that the construction expenditures and financings are incurred at the beginning of each year. The Company’s income tax rate is 40%.
Allowance of CWIP in rate base has been increasingly acknowledged as a significant strategic regulatory tool in jurisdictions throughout the nation. In Indiana, CWIP associated with a pre-approved construction plan is specifically allowed into rate base, and costs incurred between rate cases may be deferred, on an interim basis until the project is complete.28 Nuclear power plant construction costs in Louisiana may be recovered through CWIP in rate base (including cash earnings), and annual prudence reviews are required although earlier approvals cannot be revisited.29 Lignite coal project costs in North Dakota may be recovered through CWIP in rate base and between rate cases, may be recovered through an adjustor clause.30
b. Accounting Orders
Another specific device that could help preserve the Company’s financial integrity is a Commission order that allows the Company to change its general accounting methodology to record certain costs as deferrals for recovery at a future date. This option would give the Company the ability to defer certain costs associated with implementation of an acknowledged resource plan for recovery in a future rate case. The accounting
28 IND. CODE § 8-1-8.5-6.5 (2009); IND. ADMIN. CODE tit. 170, art. 4, rule 6 (2009). 29 Louisiana PSC General Order No. R-29712 (May 18, 2007). 30 N.D. CENT. CODE § 49-06-02 (2009).
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DRAFT method is beneficial to the utility because it would not be required to expense costs for income statement purposes, which would help the utility maintain its financial integrity.
The accounting order is particularly useful for major resource projects where some of the costs for preliminary studies and engineering work may be expensed. These costs can be substantial prior to the determination of a specific project and location. An accounting order can be particularly useful for generating plants utilizing clean coal technology where research and development expenses will necessarily be a part of any pre-construction cost, however, the primary use for accounting deferral orders is to synchronize cost recognition with the date a new plant can be reflected in rates. An accounting order allowing deferral of these costs for later recovery eliminates the downward pressure of such expenses on the utility’s financial condition and assures recovery of substantial legitimate costs related to construction of a generating plant and its placement into service.
While an accounting order would not improve cash flow until the Company’s next rate case and, therefore, is a less desirable regulatory tool than adjustor mechanisms or allowance of CWIP in rate base, it would nevertheless improve the Company’s non-cash earnings and give APS additional certainty of cost recovery.
c. Adjustor Mechanisms
Adjustor mechanisms are effective cost recovery regulatory tools that are used in Arizona and around the country. They are most widely used to recover fuel and purchased power expense, but in recent years some states have used these mechanisms for recovery of increasing capital costs caused by changing environmental regulations31 and high levels of investment in new infrastructure necessitated by growth. These mechanisms improve a utility’s cash flow to alleviate the financial pressure faced during periods of massive capital expenditure obligations.
Several jurisdictions allow recovery of pre-construction and CWIP for electric generating facilities through an adjustment mechanism. Colorado has implemented an automatic recovery process for the planning, development, construction, and operating costs associated with clean coal technology based generating plant, where recovery is initially permitted through an adjustment mechanism which includes a utility’s authorized cost of capital.32 Utilities in the state of Florida may request recovery of actual and projected pre-construction costs, including carrying costs, for new nuclear facilities through a Capacity Cost Recovery Adjustment Clause; if the utility cancels construction of the facility, any CWIP balance and attendant carrying cost remaining at the time of cancellation will be recovered through the clause.33 Virginia and South Carolina have
31 An example of this in the water context is the use of cost recovery mechanisms to recover costs required to comply with federal arsenic regulations. 32 COLO. REV. STAT. § 40-3.2-102. 33 FLA. ADMIN. CODE §. 25-6.0423 (2008).
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DRAFT instituted similar mechanisms.34 The majority of these adjustment mechanisms used to recover CWIP are designed to be reviewed and recalculated on an annual basis, and most are allowed to recover projected annual costs subject to true-up calculations.
Although there are some restrictions on the use of adjustor mechanisms under Arizona law, these tools should be examined as a means to address the substantial capital expenditures necessary to implement APS’s Resource Plan.
d. Market Transactions (PPAs or Hedging)
Market transactions are contractual agreements that obligate APS to make future payments to a counterparty under the terms of the agreement. PPA transactions provide APS with a resource of power for the term of the contract. Commodity hedging transactions, like forward natural gas contracts, provide APS with a specified amount of commodity at a fixed price in the future. While these contracts are generally allowed current recovery treatment by the ACC, these transactions may require Commission involvement to provide additional levels of support.
PPA contracts are treated as fixed obligation contracts by credit rating agencies who assign a debt equivalent (imputed debt) to them when evaluating APS’s credit- worthiness. This process stresses APS’s financial metrics (debt ratio, debt coverage ratio and funds from operation to debt ratio) and, thereby, requires APS to adjust its capital structure depending on the amount and type of contracts outstanding and the amount of direct regulatory support provided by the ACC.
Hedging transactions also require regulatory support. APS currently uses a commodity hedging program to enhance the level of price stability for customers. It is vital to understand that this hedging program will produce a fixed cost35 for the future commodity to be delivered that may be either higher or lower than the cost that would have been incurred if all the required commodity was purchased at the time it was needed. The hedging program is designed to limit volatility in the commodity price over time by averaging the price over several buy dates instead of just one date. The regulatory support for hedging is necessary because the difference between the hedged price and the spot price should not be a factor for cost recovery purposes, no matter which is higher or lower. However, the magnitude of the costs involved in commodity hedging is quite large.36
Renewable PPA transactions also require another layer of regulatory support to address the RES requirements and the regulatory treatment of costs above “avoided cost,”
34 S.C. CODE OF LAWS §§ 58-33-220(17); -225 (2007); VA. CODE § 56-585.1(A)(6) (2008). 35 This is the sum of all the costs of the hedging transactions divided by the sum of the contracted for commodity quantities. 36 For example, through January 7, 2009, APS contracted for over $1.0 billion of energy commodities in accordance with the Company’s commodity hedging program.
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DRAFT as well as renewable energy purchases that are in excess of the RES energy requirements. Regulatory support is necessary before the Company enters into a long-term above “avoided cost”37 resource contract. Without such support, APS’s credit-worthiness would discourage the long-term commitments that will be needed to substantially increase renewable energy resources in Arizona. This issue is particularly salient as APS strives to surpass the RES energy requirement.
e. Energy Efficiency and Demand-Side Management
Demand-side resources, such as energy efficiency and demand response, are an integral part of APS’s Resource Plan. This Resource Plan includes several programs that provide customers with various opportunities to conserve energy and reduce electric bills. As the Commission has recognized, these programs provide significant benefits: they are emission-free energy resources that help APS manage peak load and help customers manage rate increases. Moreover, by encouraging customers to save energy, these programs allow the Company to avoid fuel costs and postpone the construction of new generation to meet growing demand, and thus can be a low-cost alternative relative to other resources. Nevertheless, there is a fundamental financial tension created by these programs. Without regulatory policies that align financial requirements with the implementation of cost-effective energy efficiency programs, declining energy sales can seriously erode a utility’s financial health and serve as a disincentive for the pursuit of this resource option.
2.1.E. Retail Competition
Recently, following an application for a Certificate of Convenience and Necessity by a competitive electric service provider, the Commission decided to examine again whether retail competition is in the public interest.38 If retail competition proceeds in Arizona, it would introduce a significant uncertainty into the resource planning process. Competitive retail providers typically enter into contracts in which they are only obligated to provide service to the retail customers for the duration of the current contract. Under this structure of retail service, the incumbent electric utility remains the provider of last resort (“POLR”). The POLR is required to provide the retail customer with service in the event of a contract default (the competitive retail provider goes out of business), or if the retail customer chooses to return to standard utility service (this could occur if the market conditions no longer favor buying from market sources).
For these reasons, a future competitive retail market in Arizona has an impact on APS’s ability to prepare its long-term resource plans. If APS cannot predict its future service obligation to customers, it cannot design a resource portfolio that would best meet future customer needs. Additionally, given the added complexities of potential climate change policies, volatile commodity costs, and economic conditions, the best designed
37 This is a contract that is expected to exceed the cost of other available resource options. 38 See Decision No. 70485 (Sept. 3, 2008).
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DRAFT portfolio today could lead to an inefficient portfolio if customers are allowed to seek service from alternative sources. It would be difficult to include a major new baseload resource in the future resource portfolio without receiving strong regulatory support that the utility will be allowed to recover the investment from all customers for whom it was designed to benefit.
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2.2 NEEDS ASSESSMENT
The first part of this section will present APS’s forecast of future customer needs (commonly referred to as the “load forecast”). The load forecast discussion is followed by a comparison of the future customer needs with APS’s existing resource portfolio. These comparisons will illustrate the “gap” that needs to be filled with future resource additions.
In forecasting load, energy efficiency and distributed energy resources play a unique role. These resources are atypical in traditional load forecasting in that they effectively produce reductions in customer energy demand and, therefore, increased contributions from those resources would reduce future loads. To maintain analytical symmetry, the following load forecast and resulting gap analysis was developed prior to inclusion of expected impacts from Company-sponsored energy efficiency programs and distributed energy resources installed as a result of Company actions. Both of these resources are accounted for in the resource-side analysis.
2.2.A. Load Forecast Summary
Historically, APS’s service territory has experienced growth in customers and their energy consumption. Continued population migration into Arizona and the aging of the population in Arizona will lead to an average annual customer growth rate of 2.6 percent through 2025. This population and related customer growth is the single most important factor in the Company’s peak demand growth over the same time period, which is forecasted to be 2.8 percent per year. These characteristics are forecasted to continue for the next two decades despite a short-term outlook that looks less robust. After the next several years of relatively weak economic growth, it is expected that the Arizona economy will return to more normal levels of growth, even though such growth will be at lower rates due to the difficulty of maintaining the same growth rate with a larger economic and population base.
Although population growth may be the major determinant in demand growth, the demand and energy projections depend on analysis of several components that contribute to the overall demand. The vast majority of the demand growth is driven by growth in residential and business customers with peak demands less than 3 MWs. Growth in the numbers of these customers and in the average use per customer is almost entirely responsible for the expected growth in system peak and energy. Additionally, APS serves approximately 80 customers with peak demands greater than 3 MWs, as well as a handful of wholesale customers. These customers account for a modest share of APS’s total system peak and energy requirements, and they have a very small impact on the future growth in demand. The sections that follow describe how APS develops its projections for each of these important components and how the components are tied together to complete the forecast.
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2.2.B. Outlook for Annual System Peak Demand and Energy
This Resource Plan is focused on the anticipated capacity and energy needs through the year 2025. APS expects that in the year 2025, our customers will require almost 50,000 GWhs of energy to be generated or purchased, and they will demand over 11,400 MWs during the highest-use hour of the year. These amounts reflect substantial increases in energy demand and peak use from the amounts seen today. While 2025 commands much of the attention in the ensuing gap and portfolio analyses, the following discussion is structured to provide an understanding of growth 20 years into the future by comparing it to the 20-year period ending in 2008. The symmetry of these 20-year periods is helpful in understanding where the future is likely to differ from the past.
The APS system peak demand is expected to grow from 7,026 MWs in 2008 to 12,400 MWs by 2028, an average annual growth rate of 2.9 percent. Accounting for relatively mild weather on the peak day in 2008, the weather-normalized 2008 system peak was 7,277 MWs. Using the weather-normalized 2008 system peak as the starting point for the forecast yields a slightly lower average annual growth rate of 2.7 percent over the 20-year period. Over the previous 20 years (1988-2008), APS’s peak demand increased at the rate of 3.7 percent per year, so the current forecast reflects a slower rate of growth in percentage terms. In absolute megawatts, the peak demand is increasing at an average annual rate of 269 MWs per year, which is greater than the average increase experienced in the previous 20 years of 189 MWs per year.
Energy consumption is increasing at a very similar rate. Over the next 20 years, annual electricity sales will increase from 30,100 GWhs in 2008 to 53,700 GWhs in 2028, an average annual growth rate of 2.6 percent. Over the previous 20 years, energy sales increased at a rate of 3.0 percent per year. The trend is the same when measuring total system energy, which reflects the amount of energy required to be generated or purchased in order to meet customer demand plus the line losses incurred in transmission and distribution of the energy.
The single largest contributor to this growth is the increase in the number of customers, primarily driven by steady and sustained population growth. Figure 17 shows the projected growth in electricity sales decomposed into the amount related to customer increases and the amount related to increased energy intensity. From 2008 to 2028, the number of customers served each year will increase at an average annual rate of 2.5 percent. By 2028, APS will be serving almost 1.8 million customers and the state of Arizona will have almost 10 million residents. Figure 18 provides an overview of some of these key statistics. Also included in Figure 18 are the values for peak demand, energy, and customers in the year 2025.
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Figure 17 – Load Growth Drivers
Load Growth Drivers
50,000 Energy due to growth in factors other than customer growth
40,000
Total Energy Need
30,000
2008 Energy Level
20,000 Electricity Demand (GWH) Demand Electricity
10,000
-
7 2 3 9 4 5 98 99 04 10 11 16 000 005 006 012 017 018 1996 199 19 19 2 2001 200 200 20 2 2 2007 2008 200 20 20 2 2013 201 201 20 2 2 2019 2020
Figure 18 – Overview of Peak Demand and System Energy
1988 1998 2008 2018 2028 2025 Levels System Peak Demand (MW) 3,240 5,072 7,026 9,293 12,397 11,442 System Energy (000 GWh) 16.6 23.0 30.1 40.9 53.7 49.8 Annual Load Factor (%) 58.3 51.7 52.2 50.1 49.1 49.6 APS Customers (000,000) 0.57 0.78 1.10 1.41 1.80 1.69
Percent Change System Peak Demand 57 39 32 33 System Energy 39 40 27 31 Annual Load Factor (11) 1 (4) (2) APS Customers 37 42 28 27 Note: Historical system peak and energy amounts have been adjusted to remove the impact of the Citizens Utilities/Unisource Energy wholesale power agreement with APS. The contract was terminated with APS in 2001, and the historical sales and peak information are presented here without these amounts in order to display a more accurate picture of the Company’s underlying energy demand trends.
Figure 18 demonstrates the close correspondence between the percentage growth in the Company’s peak demand over time and the growth in system energy and customers over the same period, with the exception of the 1988-98 period. During that period, the average load factor dropped 11 percent as low load factor residential and small business customers grew much faster than the average, and the Company experienced reductions in certain high demand/high load factor customers. Over the last 10 years, the load factor
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DRAFT has remained much more stable, and the customer and energy growth rates almost completely account for the growth in peak demand.
In terms of electricity sales, residential customers account for 45 percent of APS’s total sales in 2008. This share is expected to grow to 52 percent by 2028. Small and medium business customers will maintain their share of total sales at 41 percent, while the share of sales to extra large business customers and wholesale customers is expected to be smaller.
2.2.C. Customer Growth
Of APS’s total customer level, the vast majority are residential customers. Although residential customers account for only 45 percent of total sales, they account for 96 percent of the total number of customers served by APS. This relationship is likely to remain by 2028. The number of residential customers is expected to grow to 1.8 million, an increase of almost 625,000 or 2.5 percent per year. Figure 19 shows this projected growth in context with APS’s historical customer growth rates.
Figure 19 – APS Residential Customer Growth
APS Residential Customer Growth
9%
8%
7%
6%
5%
4%
Change from Prior Year Prior from Change 3%
2%
1%
0%
6 2 1 7 3 2 8 4 3 60 96 17 957 9 963 96 97 978 98 984 98 99 9 999 00 005 00 01 0 020 02 1954 1 1 1 1 1969 1 1975 1 1 1 1 1990 1 1 1 2 2 2 2011 2 2 2 2 2026
APS projects the number of future residential customers by multiplying projected population counts by APS’s geographic market share, adjusted for the number of people per household. The largest determinant of the growth in customers is the expected growth in population, which is mostly accounted for by the significant amount of net migration experienced by the state. Figure 20 shows the historical and projected growth in the state’s population separated into the amount contributed by migrants to the state and by the net natural increase, defined as births each year minus the number of deaths
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DRAFT each year. As one can see from the figure, the contribution from net natural increase is very stable from year to year, but the contribution from net migration is quite volatile.
Figure 20 – Arizona Population Growth by Component
Arizona Population Growth by Component
7%
6%
5%
4%
3%
2%
Change over Prior Year Change Net Migration
1% Net Natural Increase 0%
1 7 0 6 2 5 1 7 0 6 9 5 8 7 8 9 9 0 0 1 1 2 974 9 983 9 9 9 0 0 0 0 022 0 197 1 1 198 1 1 1989 1 1 1998 2 2004 2 2 2013 2 201 2 2 202
It comes as no surprise that migration is an important contributor to the state’s economic growth and, directly related to that, the state’s demand for energy. Additionally, it is clear that people move to Arizona when economic conditions are good, job growth is plentiful, and new construction is robust. Not surprisingly, migration to Arizona is lowest when economic conditions are poor. Each of the declines in net migration observed in Figure 20 coincides with an economic recession at the national level, and it is not coincidental that Arizona’s economic performance suffers during such times. Also evident from the figure is the current slump in migration that began in 2007 and took firm hold in 2008. This decline in migration is mirrored in the customer growth pattern for 2007 and 2008 in Figure 19.
At the time of this Report, the national economy is in recession, the depth and duration of which cannot be determined with any reasonable certainty at this juncture. The Arizona economy is poised to suffer its slowest period of growth in the last 50 years. The Arizona economy relies heavily on population growth to create jobs in construction and other growth-related industries like real estate and financial services, and when population growth slows, it has an amplified impact because the job losses in these related industries lead to additional out-migration and a corresponding lower net in- migration.
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Currently in Arizona, housing and commercial retail space are significantly overbuilt, meaning that the next several years will be marked by very low rates of construction activity in those markets. Without a need for substantial numbers of construction workers during this period, overall population and economic growth will remain very modest until the excess capacity in housing and retail can be absorbed. At the low rates of growth currently being experienced, APS expects that this will take several years. The financial turmoil at the national and international level casts even more doubt on the possibility of a quick recovery since the dearth of lending activity does not appear to be unwinding despite significant intervention on the part of central banks and governments. Figures 19 and 20 both show the extent to which growth will be restrained over the next four years.
While acknowledging that the next several years will be challenging in terms of healthy economic growth in the state, it is also true that the long-term fundamentals that have driven the state’s sustained population growth over the last 40 years remain, or are expected to be returning, in a few years. Key among these is continued housing affordability and its contribution to the overall quality of life for Arizona residents. After increasing rapidly between 2004 and 2006, housing prices39 have declined to pre-boom levels and, as a result of the significant amounts of excess capacity in housing, are likely to continue declining for the near future. As prices decline and affordability returns, migration to the state will begin to pick up again and increase the rate at which the excess housing capacity is absorbed. Once the excess capacity begins to evaporate, homebuilders will start building at higher rates. They will then need to begin re- importing skilled construction workers from other states, which will accelerate the absorption of any remaining excess capacity. Therefore, APS expects a rather rapid increase in population and customer growth to begin the next cycle of growth (consistent with what has been seen in past economic cycles). This pattern can be seen in Figures 19 and 20.
Once the forecasted horizon goes beyond the current business cycle, the projection reverts to a long-term trend so as not to speculate on the timing of future business cycles. In the current projection, the current cycle plays out by about 2015 and population growth settles in to its long-term trend at that point. This long-term trend shows migration rates gradually slowing down as the population base gets larger and larger. The result is that Arizona is expected to add just over one million people in each of the next decades, supported by the assessment that quality of life and affordability issues relative to neighboring states will remain favorable.
While population growth is the single most important determinant of growth in residential customers, other factors also come into play. Most notably, the number of people per household has been steadily declining for decades, leading to rates of customer growth substantially above the rate of population growth. In 1970, an average household in Arizona had 3.3 people. By 2000, the latest year for which comprehensive
39 These are housing prices as measured by the Case-Shiller Home Price Index.
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DRAFT data are available, this ratio had declined to 2.7 people per household, a reduction of almost 18 percent. This change in people per household added approximately 0.7 percent in excess of the population growth rate to the customer growth rate, all of which occurred in the 1970s and 1980s.
Going forward, the rate of change in the number of people per household is expected to slow substantially. By 2030, the Company projects that this ratio will have declined an additional 10 percent, about half of the decline seen in the previous 30 years.40
The analysis of householder rates by age group reveals that within any specific age group, the householder rate has remained fairly stable since 1960 for most age groups. However, there are significant differences in the householder rate by age group. Figure 21 displays these trends. More than 60 percent of people aged 65 or older head a household, but only 45 percent of people between the ages of 25 and 34 head a household. At the very bottom tier of householder rates are those people between the ages of 15 and 24 where fewer than 20 percent are the head of a household – for natural and obvious reasons.
40 To determine the future number of people per household, historical householder rates were analyzed by age of householder. In this context, householder rates refer to the number of people in a certain age group who are heads of a household divided by the total number of people in that same age group. For example, if there were 100 people between the ages of 35 and 44, and 55 of those people were the head of a household, the householder rate for 35-44 year olds would be 55 percent. The other 45 people in that age group are not heads of household, and the most common reason is that they are married to someone who is a head of the household (whether or not their spouse happens to be in the same age group). Other common reasons relate to children or parents living in a household headed by a parent or adult child, respectively.
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Figure 21 – Arizona Householder Rates by Age
Arizona Householder Rates by Age
70%
60%
50%
40%
30%
20% % of Population Heading a Household a of Heading Population %
10%
0% 15-24 25-34 35-44 45-64 65+ Total Age Group 1970 1980 1990 2000 2010 2020 2030
The number of people per household is determined by averaging these various householder rates for any given year, weighting each one by the number of people in each age group as a share of the total population. Even though the age-specific householder rates do not change much from year to year, the effect of the changing age distribution of the population can have quite a dramatic effect as seen in Figure 21. The householder rate for the total population is displayed at the far right side of the figure and shows an increase from 30 percent in 1970 to 38 percent in 2000. Almost all of this increase can be attributed to the aging of the Arizona population as the baby boomer contingent moved from very low householder rates to much higher householder rates. In 1970, baby boomers were between the ages of 24 and 6 years old. By 2000, baby boomers had aged by 30 years and were between the ages of 54 and 36 and were much more likely to head a household than they were 30 years before. Looking ahead, by 2025, virtually all of the baby boomer contingent will be in the 65 years and older category and will push the overall householder rate even higher. The inverse of this overall householder rate is the number of people per household. Figure 22 shows the population shares accounted for by various age groups and, in particular, highlights the dramatic shift in the 65 years and older age group.
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Figure 22 – Arizona Population by Age Group
Arizona Population Shares by Age Group
35%
30%
25%
20%
15% % of Total Population %
10%
5%
0%
4 8 0 4 6 0 2 6 8 4 8 0 4 6 0 2 6 8 7 8 9 0 1 2 98 99 99 01 02 02 1970 1972 19 1976 197 1 1982 198 19 1988 1 1 1994 199 19 2000 2002 20 2006 200 2 2012 201 20 2018 2 2 2024 202 20 2030 <15 15-24 45-64 65+
A major factor influencing the rate of growth in APS’s residential customer accounts compared to the overall population growth for the state is the share of the population growth occurring in APS’s franchised service territory. Historically, this rate has hovered in the range of 37 to 38 percent, but it has been trending higher in large part due to the population growth in the metro Phoenix area relative to the balance of the state, and due to APS’s share of population growth within the metro Phoenix region. For example, during the growth boom of the early- to mid-1980s, the Southeast Valley communities of Tempe, Mesa, and Chandler grew much faster than the rest of the metro Phoenix area. Electric service in these cities is mostly provided by the Salt River Project (“SRP”) or the City of Mesa and, during this time, APS’s share of new residential electric customers was as low as 38 percent. However, during the 1990s and in recent years, particularly as the West Valley communities have become more popular for new housing developments, APS’s share of new customers has hovered around 50 percent. In the current forecast, APS expects to maintain its share of new residential customers at the 50 percent level in the metro Phoenix region and expects that Maricopa County will continue to grow modestly faster than the balance of the state. As a result, APS’s share of total household growth will continue to increase slightly each decade. Figure 23 provides a summary of each of these major factors as they contribute to APS’s customer forecast.
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Figure 23 – Components of APS Residential Customer Growth 1970 1980 1990 2000 2010 2020 2030 Levels AZ Population (000,000) 1.79 2.74 3.68 5.17 6.46 7.97 9.45 Persons per Household 3.28 2.84 2.68 2.70 2.66 2.52 2.44 AZ Households (000,000) 0.55 0.96 1.38 1.91 2.43 3.16 3.88 Territory Share (%) 37.7 36.8 38.1 39.1 41.1 42.1 43.0 APS Customers (000,000) 0.21 0.36 0.52 0.75 1.00 1.33 1.67
Percent Change AZ Population 53 35 40 25 23 19 Persons per Household -14 -6 1 -1 -5 -3 AZ Households 76 43 39 27 30 23 Territory Share -2 3 3 5 2 2 APS Customers 72 48 43 33 33 25 Notes: The percent change reflects the change in level from the prior 10 year value.
The forecast for non-residential retail customers is developed much more simply than the forecast for residential customers. Growth in non-residential customers typically matches the magnitude of residential customer growth in percent terms but generally follows residential customer growth with about a year lag. The forecast assumes this relationship continues into the future. Furthermore, non-residential customers are broken into ten different building segments and growth in each of these segments is projected based on historical trends in each segment’s share of total customers.
Finally, the customer forecast for wholesale and extra large retail customers assumes that current customers remain as customers, unless specific knowledge has come forth about prospective shut-downs or contractual terms indicate a specific termination of service date.41
2.2.D. Residential Use Per Customer
In addition to growth in consumption from adding new residential customers, the average use per residential customer will continue to increase total consumption as well. In the last 20 years, average annual usage has increased a total of 33 percent, an average annual rate of 1.5 percent. Over the next 20 years, this rate of growth is expected to slow by about half. Under current projections, average usage will be 16 percent greater in 2028 than in 2008 under normal weather conditions, which represents an average annual growth rate of 0.7 percent per year, before considering the impacts of APS’s energy efficiency programs and distributed energy reductions.
Several factors have been important influences on the growth in residential average usage. Larger homes and the increasing saturation of electronics in the home
41 In the current forecast, only one such customer has a specific termination date reflected.
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DRAFT have both helped propel usage upward, while continued efficiency improvements in both new and existing homes and small declines in electricity’s share of water and space heating have helped to partially offset the increases. APS uses an end-use model to forecast desert area customer energy use for five major appliances42 and the aggregate of all other uses (referred to as “base” usage). Econometric models employing a conditional demand analysis approach are used to benchmark the end-use model to historic values from which the projections are based.43 The most recent conditional demand analysis was conducted with customer survey data from 2005 and matched billing records for 2005 and 2006.44
The forecast of aggregate residential usage is determined by this forecast of desert area customer usage and a fixed relationship between high country usage and desert area usage. While sufficient data is available to break down desert area usage into the six categories mentioned above, similar data is not available in a sufficient amount to generate comparable analyses for high country customer usage. Space cooling is much less prevalent in APS’s high country territory, electric space and water heating saturations are very low, and swimming pools are virtually non-existent. Additionally, the climate zone for the high country is much more dispersed and variable than that for the desert area. These factors make the application of conditional demand analysis much more difficult and costly to perform on high country customer usage. However, the historical relationship between high country usage and desert area usage has been very stable over the past 30 years (approximately 51 percent) and is assumed to remain so in the forecast period.
The largest contributor to increasing average desert area usage historically has been the size of new customers’ homes. As homes get larger, customers’ space cooling and heating needs increase and the space available to hold more electronic equipment – such as televisions, audio equipment, computers and related peripherals, and personal electronics – increases. Between 1987 and 2007, the average size of single family homes in APS’s metro Phoenix service territory increased from under 1,600 square feet to almost 1,900 square feet, an increase of 19 percent, as new construction averaged 2,000 square feet or more. In recent years, average new construction has ranged between 2,200 and 2,400 square feet. The current forecast assumes that new homes in the desert area continue to average around 2,200 square feet.45 Figure 24 shows these trends for the metro Phoenix single family home market.
42 The five major uses are space cooling, space heating, water heating, refrigerators, and swimming pool pumps. 43 Conditional demand analysis is a process which identifies systematic differences in household energy consumption that are related to differences in demographic characteristics and the presence or absence of certain electric appliances. 44 The Company conducted a customer home use survey in 2008 and intends to complete another conditional demand analysis using the acquired data in 2009. 45 Embedded in this projection is the assumption that the most recent increase in the size of new construction to 2,400 square feet was a short-run anomaly driven by the excess investment in housing and that the size of new housing will not be sustained at those levels.
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Figure 24 – Average Home Size
Average Home Size APS Metro Phoenix Single Family Homes
2,600
2,400
2,200
2,000
1,800 Square Feet Square 1,600
1,400
1,200
1,000
2 4 9 1 18 996 1982 1984 1986 1988 1990 19 1994 1 1998 2000 2002 2004 2006 2008 2010 2012 20 2016 20 2020 2022 2024 2026 2028 New Existing
Between 1987 and 2007, improvements in air-conditioner, heat pump, and refrigerator efficiencies produced significant reductions in aggregate residential usage. The amount of electricity used for space cooling (holding home size and weather effects constant) decreased by almost 30 percent in this time period, and refrigerators experienced an even greater 47 percent decline. The trend for space heating efficiency is very similar to the space cooling efficiency, but differs slightly due to annual differences in electric/gas market share across the years. These efficiency gains result from the installation of more efficient equipment in new housing and in replacing worn-out existing equipment based on the equipment that meets federal standards and is commercially available at the time. Looking ahead, these naturally-occurring efficiency46 gains will continue, albeit at lower rates. Average space cooling is expected to be 19 percent more efficient in 2028 than in 2008, and average refrigerator usage is expected to be 16 percent lower by 2028. Combined with the increase in space heating efficiency, average desert area residential usage will be more than 1,000 kWhs lower in 2028 than today’s levels as a result of these trends.
The forecast also expects some small saturation changes among the key equipment types for desert area customers. The saturations of electric space heating and electric water heating continue to decline in the forecast as new customers get added at a slightly lower rate than the existing average. In contrast, the saturation of central space cooling continues to increase slightly, although it is already quite high at 94 percent in 2008. No
46 Energy efficiency opportunities that do not require utility sponsored incentive programs to be realized are referred to as “naturally-occurring.”
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DRAFT material changes are anticipated in swimming pool ownership or the ownership of second refrigerators. When combined, these saturation changes result in a reduction to average residential usage by 2028 of just over 100 kWhs, about one-tenth of the change related to increasing efficiency. Figure 25 summarizes the principal changes in residential usage by 2025.
Figure 25 – Changes in Residential Use per Customer to 2028
Average Annual Usage in 2028 (kWh/Customer) 16,020
Increase from 2008 2,179 -- Desert Area 2,220 -- High Country 1,126
Desert Area Increases -- Home Size and Base 3,383 -- Naturally-Occurring Efficiency (1,058) -- Changes in Saturations, Net (106)
The preceding discussion outlines the key drivers of APS’s expected changes in average residential usage over the next 17 years under a conventional view of the world. Several factors are not included in the forecast. First, as noted earlier, this forecast does not include the impacts of APS’s energy efficiency programs since the magnitude of the investments in energy efficiency will be a function of policy choices and the economics of available demand-side options. Also, the prospective impacts of distributed energy technologies are not included in this forecast (e.g., the possibility of increased penetration of solar water heating technologies and the resulting impact on household consumption). APS will continue to drive increased adoption of renewable distributed energy technologies.
Second, this forecast does not speculate on the timing and adoption rates of new technologies that are not yet commercially available and do not have any historical track record of technological improvements. For example, no widespread saturation of electric vehicles is assumed to occur even though it is conceivable that electric vehicles may develop quickly enough to have an impact on electricity demand in 17 years.
Third, as a general concept, APS does not assume that electric rates will deviate significantly from the rate of inflation over the 17-year period. This assumption is not meant to be a forecast of the timing and magnitude of future rate requests. This is a simplifying assumption intended to keep potential price elasticity impacts from clouding the discussion of the key trends underlying future demand.
Fourth, the usage projections implicitly assume no significant disruption to the economics or availability of natural gas or other fuels relative to electricity and that household economics (income levels, cost, and preferences for housing, etc.) continue to
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DRAFT trend in normal and predictable ways. In essence, with respect to these influences on the forecast, the future continues to evolve much like the past in the absence of any discrete marker indicating a change in direction.
2.2.E. Non-Residential Use Per Customer
Average use per customer for non-residential customers is expected to increase by fewer than five percent between 2008 and 2028. Non-residential retail customers include those customers classified as commercial, industrial, irrigation, or street lighting customers. Customers larger than three megawatts are tracked individually and the projections for these customers will be discussed in the next section. Almost all of the consumption from the remaining customers is accounted for by those in the commercial and industrial classes. To gain a better understanding of usage trends for these customers, this group is further disaggregated into ten building types, and usage per customer is projected by building type. Figure 26 shows the ten building types and the change in average usage by building type segment.
Figure 26 – Changes in Non-Residential Use per Customer to 2028 Use in 2028 % of Total Building Segment (MWh/Cust) % Change Customers
Hospitals 1,058 3.3 0.2 Groceries 751 29.7 0.6 Schools 633 23.7 1.0 Hotels 365 7.0 0.8 Manufacturing 310 0.0 2.1 Restaurants 195 19.3 2.6 Warehouses 133 21.4 2.4 Retail Stores 102 18.0 22.4 Offices 100 -1.1 24.5 All Other 64 3.3 43.3
Total 106 4.7% 100.0%
Several facts are immediately apparent from the above figure. First, there is great variability in the average level of electricity consumption depending on the type of business a customer is engaged in. Hospitals tend to be large in size and their operations require the use of machinery and equipment that use a lot of electricity. These characteristics make them about ten times larger than the average commercial and industrial customer. Groceries also tend to have large footprints and the use of freezers and refrigeration raises their usage above that of other segments. Offices and retail stores are the least electric intensive of the segments.
Second, there is great variability in the growth rates of segment usage. Usage in five of the ten segments is expected to grow by 20-30 percent by 2028 while usage in
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DRAFT four segments is not expected to grow much at all (three percent or less). This diversity in the rate of growth is almost entirely attributable to the size of new customers being added to each segment. Groceries, restaurants, warehouses, and retail stores are all examples of segments where the trend has been to build much larger establishments, and the electricity consumption of these larger buildings raises the average usage within the segment. Hospitals, manufacturing establishments, offices and the miscellaneous “All Other” segment have shown no such trend, so the growth in average usage is very slight. In fact, in virtually all segments (with the exception of schools), usage for any specified vintage of buildings is quite constant and shows no discernable trend up or down. Schools are the only building type where usage for existing buildings has been growing over time.
Third, it should be clear from the table that the vast majority (90 percent) of APS’s commercial and industrial customers are office buildings, retail stores, or fall into the miscellaneous category.47 On average, these three segments have lower usage than the other building types, and the average across all segments reflects these large shares. On a total consumption basis, the share accounted for by these segments is significantly lower. Although offices and retail stores account for roughly the same amount of consumption within the sector as they account for in the number of customers (about 45 percent), the miscellaneous category accounts for a significantly lower share of total consumption (26 percent) than of total customers (43 percent).
The same overriding assumptions used in the development of the residential usage forecast are also factors in the non-residential usage forecast. Namely, these projections are prior to the impacts of any of APS’s energy efficiency programs, brand new technologies are not explicitly assumed to exist, retail electric prices do not significantly deviate from overall inflation, and there is no sustained significant dislocation in retail energy markets (prices and availability) or economic conditions from what has been observed historically.
2.2.F. Wholesale and Extra Large Retail Customer Sales
The final component of the customer and electricity sales forecast relates to extra large retail customers (those larger than three MWs) and native load wholesale customers, who are in APS’s control area, and have had a long-standing contractual relationship with APS. Currently, there are 84 extra-large retail customers and 13 native load wholesale customers that are included in the peak demand and energy forecast presented here.48
47 The miscellaneous category includes building types like houses of worship, theaters, museums, sports arenas, and certain accounts with no building type. 48 One of the wholesale contracts expires within the next 5 years, leaving only 12 wholesale customers thereafter.
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Due to their size and the ability for any one of these customers to have a meaningful impact on the overall system load and the associated distribution and transmission network, each customer’s energy demand is tracked and forecasted individually. Companies interested in potentially establishing service in APS’s service territory are also tracked individually. Account representatives maintain contact with both existing and potential customers and provide updates on any planned expansions or reductions in operations so that the impacts of those changes can be reflected in the load forecast. Such changes are primarily foreseeable within the first few years of the forecast. If no changes are known, the customer’s consumption is assumed to remain constant. In the current forecast, these individual large customers account for seven percent of total electricity sales in 2028.
2.2.G. Annual System Peak Demand and Total System Energy
The final component of the development of the peak demand and energy forecast is the addition of line losses to total electricity sales and the calculation of the annual peak demand. Total electricity sales are the sum of all class or segment electricity sales. Each class or segment electricity sales amount is the product of the number of customers and average usage within that class or segment. These sales amounts are reflective of electricity demand at the customer meter level. In order to determine how much electricity needs to be produced by APS’s generators or purchased, line losses must be added to the electricity sales forecast. The Company’s average energy line loss percentage over the last ten years is 7.8 percent, so that amount is added to total sales to determine the total system energy that must be generated or purchased.
Once total system energy is determined, the annual peak demand can be determined by trending the historically achieved summer load factor. In the current forecast, the summer load factor trends downward slightly from 65.6 percent in 2008 to 64.0 percent in 2028, and the resulting peak demand increases from 7,321 MWs in 2009 to almost 12,400 MWs in 2028.
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2.3 GAP ANALYSIS
The next series of figures illustrate the “gap” between future customer requirements and APS’s existing resource portfolio. Based upon current load projections, APS will require significant new capacity resources in the future, as illustrated in the figure below, which compares the forecasted total resource requirements with APS’s existing capacity portfolio.49
APS has sufficient existing long-term resources50 to meet the forecasted customer needs through 2013. Note that APS has already completed sufficient short-term purchases to satisfy required resource needs for the summer of 2009. However, the load growth will create a need for additional resources in 2014 and beyond. By 2020, APS will need approximately 4,000 MWs of additional resources to meet projected customer needs. This amount grows to approximately 6,500 MWs by 2025. Customer growth is a predominant factor for this future resource need. However, another reason for the gap in resources is the fact that several existing purchased power contracts expire in the coming years (as described in the previous section), which will reduce existing capacity resources by over 2,000 MWs by 2022.
Figure 27 - Summer Season Resource Requirements vs. Existing Resources
Capacity Needs (MWs) (Summer Season Resource Requirement Versus Existing Resources) 14,000 2025 Gap Resource Need 2020 Gap 6,573 MWs Existing Resources 3,988 MWs 12,000
10,000
8,000
6,000
4,000
2,000
0 2009 2011 2013 2015 2017 2019 2021 2023 2025
49 The total resource requirement (blue bars in Figure 27) is the addition of the expected customer peak load and the reserve requirements. Additionally, for this comparison, the projected customer peak load does not include the potential impacts (reductions) due to future energy efficiency activities or distributed renewable energy implementation. 50 This includes owned generation plus purchases.
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There are several risk factors that should be mentioned regarding the outlook for future capacity needs. First, several renewable resources that are included in the forecast are currently in the development phase and have not begun to produce electricity. The Solana solar project is a good example of this. The more obvious risk factor associated with the projected capacity needs relates to its dependence upon the forecast of future customer needs. As discussed in the section containing the review of the load forecast, there are many factors that can influence future customer needs which could have a dramatic impact on the forecasted need for future resources.
Figure 28 illustrates a different aspect of the future resource need – the growth in overall energy need.51 The figure shows the growth in energy consumption above the 2009 base level.52 By 2025, the total system energy need has increased by almost 17,000 GWhs, which is an increase of over 50 percent above 2009 levels. To put the magnitude of this growth into perspective, it is useful to compare the expected growth to certain reference points.
1. The growth is almost twice the amount of energy produced by APS’s share of the Palo Verde nuclear plant;53 or 2. The growth equals the output from approximately 20 solar power plants like Solana.54
Figure 28 – Growth in System Energy Requirements
(GWHs) Change in Expected Energy Need (over 2009) 20,000 +16,782 GWHs
15,000
10,000
5,000
0 2009 2011 2013 2015 2017 2019 2021 2023 2025
(5,000)
51 Includes both forecasted customer consumption and system-wide energy losses. 52 Total system energy is projected to be about 32,800 GWhs in 2009. 53 APS’s share of Palo Verde output amounts to about 9,000 GWhs per year. 54 The Solana solar plant is expected to produce about 900 GWhs of energy per year.
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It is clear from the two previous figures that APS will need to acquire a significant amount of resources in the coming years to reliably meet expected customer needs. From a capacity perspective, the amount of new resources needed by 2025 exceeds the amount of APS’s current owned generating capacity. The energy needs represent a multi-faceted challenge. Because APS’s existing baseload energy sources (coal and nuclear plants) are essentially at full utilization already, it will be a significant challenge to meet these future energy needs without dramatically increasing reliance on natural gas while also beginning to address the climate change issue.
2.3.A. Reliability and Reserve Margins
The reliability of the electric system is an important aspect of resource planning. APS’s customers expect a very high level of reliability, and, in fact, reliability is an important part of supporting a thriving business climate for Arizona. The reliability of the supply system is part of the study work that APS performs on a periodic basis. The starting point for this study work is establishment of reliability criteria. APS has established a reliability criterion55 of not more than one expected outage event in ten years. This means that APS would provide sufficient resources such that the expected probability of a service outage occurrence is less than or equal to one event in ten years. From a practical perspective, the resource planning analysis process determines the quantity of capacity reserves that are required in order to satisfy this reliability criterion. The capacity reserves56 provide additional resources that can be called upon in the event that a generating unit experiences an unplanned shutdown or customer loads are higher than expected.
As part of this planning analysis, APS has conducted a reliability assessment using a probabilistic analysis technique. This analysis technique is commonly referred to as Loss of Load Probability analysis. For the current study, APS had to adjust previous analysis techniques in order to address the unique issues that new renewable resources introduce. For renewable resources, it is important to properly model and account for any correlation effects between the production patterns of the renewable resource and APS’s customer loads as these effects could impact the reliability analysis. The study indicates that APS will require a 15 percent capacity reserve margin during the summer months in order to satisfy the reliability criteria. This figure is consistent with current planning reserve margins as determined by prior reliability studies. APS will continue to periodically update this analysis and will report on the results in future resource plan reports.
55 This reliability criterion is related to resource supply. 56 Capacity reserves are resources (generating units, demand response, etc.) that exceed the expected customer requirements.
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2.3.B. Regional Capacity and WECC
APS depends upon the regional wholesale market for purchases and sales of electricity. Two important aspects of the regional market are: 1) projected Capacity Reserve Margins for the Desert Southwest (“DSW”) and the Western Electricity Coordinating Council (“WECC”); and 2) new power projects planned in this region. Regional power supply conditions directly impact APS’s resource planning and procurement processes and help APS to perform its gap analysis.
“Capacity Reserve Margin” refers to the amount of installed generating capacity over and above the projected peak load and assumed reserve requirements. It serves to account for weather impacts on unit performance during peak load conditions, planned unit maintenance activities, and transmission import/export capabilities. No requirement for planning reserves is mandated in the region; however, WECC assumes an average requirement of 13.7 percent across all sub-regions. A positive Capacity Reserve Margin indicates there is adequate generation supply for a sub-region, while a negative Capacity Reserve Margin may indicate a potential for supply shortages or a need for new generating resources.
WECC conducts periodic system-wide assessments of resource adequacy for each of its sub-regions and records the results in the “Power Supply Assessment” report. The report tabulates the projected Capacity Reserve Margins for peak seasons (summer and winter) under several power plant construction scenarios. One scenario assumes completion of only new plants known to be under active construction. A second scenario assumes completion of plants under active construction plus plants that have undergone significant development.
The most recent Power Supply Assessment report was published in November 2008, and covers the period from 2009 through 2017. The report indicates that the DSW sub-region (Arizona, New Mexico and southern Nevada) should have a small surplus of power supply margin in 2009, a small deficit in 2010, and deficit growth which reaches 8,000 MW by 2017. These results are based on projected load growth of about 1.8 percent per year for the sub-region, and do not necessarily reflect the current economic conditions. Lower load growth would push the need for new resources out for some time, the extent of which has not yet been modeled.
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2.4 MARKETS AND PROCUREMENT
APS conducts various procurement activities to acquire the capacity and energy necessary to fill the gap between existing resources and customer demand. Within certain constraints, such as applicable regulations and APS’s overall resource planning objectives, a goal of the procurement process is to secure the resources needed at the lowest possible cost. For example, under the RES rules, APS is required to obtain a certain percentage of its energy from renewable resources. However, the specific types of renewable resources utilized and the ownership structure of the generating facilities are decisions that APS makes during its procurement process in which cost is a primary consideration. Using the procurement process to identify and secure the best resources available will be especially important for two of the elements of APS’s Resource Plan: expanding the use of renewable resources, and increasing peak capacity.
An integral part of a successful procurement process is active involvement in the energy marketplace. Being constantly involved in energy-related markets involves developing and maintaining relationships with market participants, such as energy wholesalers, project developers, and equipment manufacturers; staying current on industry issues, such as emerging technologies, legislative activity, and construction costs; and monitoring relevant financial conditions. APS strives to be fully informed of these key issues so that it can recognize and capitalize on opportunities when they arise. The Company is also aware of the numerous parties that are necessary for efficient resource development and tries to form productive, on-going relationships with these potential partners.
APS’s procurement process includes: (i) acquiring resources for short-term needs through power purchase agreements and its energy hedging program; and (ii) securing rights to receive energy in the future through long-term power purchase agreements, asset purchases, partnerships with plant developers, and other methods. These acquisitions are pursued through a variety of techniques, such as RFPs, bi-lateral negotiations, and auctions. The Company is fully committed to following applicable FERC and Commission regulations, including the procurement Best Practices, the self-build requirements of Commission Decision No. 67744, the RES rules, the Code of Conduct, and the Standards of Conduct.
APS has used its procurement process to obtain resources on favorable terms from a variety of sources. For example, the Company recently acquired the Sundance units and power from merchant combined cycle generation plants at costs below that of constructing new units. Figure 29 shows the variety of resources acquired over the last few years through APS’s procurement efforts.
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Figure 29 – Resource Acquisition, 2004 to Present
Note: Total capacity of resources acquired is 2,943 MWs.
As part of its on-going procurement efforts, APS has also reconsidered its position on the appropriate time-frame for the Company’s hedging program. APS discussed commodity hedging strategies in the Alternative Resource Plan filing and during a stakeholder meeting in the spring of 2008.57 At that time, APS projected an increase in natural gas consumption over the next couple of years and, therefore, recommended an expansion of the current commodity hedging program from three years to five years. The economic climate and resulting load growth forecast has changed substantially since last spring. Further, as a result of the planned addition of energy efficiency and renewable resources, natural gas consumption is not expected to increase through 2014. Therefore, APS no longer believes that it needs to increase the scope of the commodity hedging program at this time but will periodically reassess this issue.
During the planning period, APS will issue RFPs for long-term resource needs and will continue using a variety of means to acquire the most attractive resources possible. The Company will stay engaged in the market for all commercially viable or soon-to-be viable technologies and monitor other important developments. Particular attention will be paid to renewable resources because of their emergence as an increasingly valuable addition to the Company’s resource portfolio. Using the procurement process described in this section, APS will acquire the renewable resources and peaking capacity necessary to carry out the Resource Plan. These procurement-related activities will allow APS to remain nimble in resource selection and responses to market opportunities.
57 Docket No. E-01345A-08-0010 (Jan. 7, 2008).
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PART III
APS’S CURRENT RESOURCES, RESOURCE OPTIONS, AND PORTFOLIO ANALYSIS
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3.1 THE COMPANY’S CURRENT PORTFOLIO
Understanding APS’s existing resource portfolio is an important first step in the resource planning process. The existing portfolio of generating units and purchase contracts provides the foundation for meeting future customer needs. Additionally, future resource choices are somewhat dependent upon the composition of the existing resources and the risk factors inherent in the portfolio. Several dimensions of the existing resource portfolio are reviewed in this section including capacity, energy source diversity, natural gas burns, projected CO2 emissions, and estimated water consumption. This data provides both an overview of the existing resource portfolio and some of the baseline data for understanding the key risk drivers impacting the portfolio and the choice of future resources.
3.1.A. Summary of Existing Resources
Figure 30 provides a summary of APS’s existing resource portfolio. For the summer of 2009, APS will have approximately 8,350 MWs of long-term resources.58 A more detailed listing of existing generating units and purchased power contracts (maximum capacity, fuel type, in-service date, emission rates, etc.) is provided in Appendix 4.
Figure 30 - Summer 2009 Long-Term Resources (Capacity in MW) Company-Owned Generation: Existing: Capacity (MWs) Avg. Age (years) Nuclear 1,147 21 Coal 1,750 37 Gas Combined Cycles 1,900 9 Gas/Oil CTs and Steam 1,466 28 Renewable 4 6 Total Company-Owned Generation 6,267
Purchased Power Contracts: Conventional: Purchases/Exchanges/Tolling 1,868
Renewable: Wind (nameplate) 187 Geothermal 10 LFG/Biomass 18
Total Purchased Power Contracts 2,083
Total Resources 8,350
58 Wind resources are included at their nameplate capacity rating which does not indicate their expected production levels during peak load periods.
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3.1.B. Existing Resources
APS’s existing resource portfolio includes a diverse fleet of generation units, conventional PPAs, and renewable energy PPAs. These existing resources are described below.
Current Generation Facilities
APS’s portfolio of owned generating capacity is summarized in the following figure. For the year 2009, APS-owned generating capacity totals 6,267 MWs (summer ratings).
Figure 31 - APS-Owned Generating Capacity (Summer 2009) APS-Owned Generating Capacity
Yr 2009 CAPACITY FUEL RATING TYPE (MWs) 1 PALO VERDE 1-2-3 Nuclear 1,147 2 FOUR CORNERS 1-2-3 Coal 560 3 FOUR CORNERS 4-5 Coal 228 4 CHOLLA 1-2-3 Coal 647 5 NAVAJO 1-2-3 Coal 315 6 WEST PHOENIX CC 1-2-3 Natural Gas 255 7 WEST PHOENIX CC 4 Natural Gas 117 8 WEST PHOENIX CC 5 Natural Gas 506 9 WEST PHOENIX CT 1-2 Natural Gas 110 10 REDHAWK 1-2 Natural Gas 984 11 OCOTILLO STM 1-2 Natural Gas 220 12 OCOTILLO CT 1-2 Natural Gas 110 13 SAGUARO STM 1-2 Natural Gas 210 14 SAGUARO CT 1-2 Natural Gas 110 15 SAGUARO CT 3 Natural Gas 79 16 SUNDANCE 1-10 Natural Gas 420 17 YUCCA CT 1-4 Nat. Gas/ Oil 147 18 YUCCA CT 5-6 (new) Natural Gas 96 19 DOUGLAS Oil 16 20 CONVENTIONAL GENERATION SUBTOTAL 6,277
21 TOTAL EXISTING RENEWABLES (as of 12/31/2006) Solar 6
22 SEASONAL RATING ADJUSTMENT (16)
23 TOTAL APS GENERATION W/ RENEW. 6,267
Notes: CC - combined cycle CT - combustion turbine
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3.1.B.i. Nuclear Generation
The Palo Verde Nuclear Generating Station (“PVNGS”),59 which is located about 50 miles west of Phoenix, is the largest nuclear generation facility in the United States, and its three units produce approximately 30,000 GWhs of electricity annually (total plant). APS owns 29.1 percent of the plant; APS’s total capacity ownership is 1,147 MWs (2009 value). A portion of Palo Verde Unit 2 was sold and leased back in 1986. The initial term of this lease will expire in 2016 and will be subject to renewal.
3.1.B.ii. Coal Generation
Cholla Power Plant
The Cholla Power Plant is located in northeastern Arizona near Holbrook. APS operates the plant and owns Units 1, 2, and 3, which have a total capacity of 647 MWs. PacifiCorp owns Unit 4, which is the largest unit at the plant. Coal for this plant is currently supplied from the McKinley Mine in western New Mexico, approximately 60 miles east of the power plant. The coal is delivered to the power plant via the BNSF interstate railway. In the near future, the coal source for this power plant will change to Peabody’s El Segundo mine, which is also located in western New Mexico.
Four Corners Power Plant
The Four Corners Power Plant is located on the Navajo Reservation west of Farmington, New Mexico. APS is the operator of this five unit plant, which can generate approximately 2,060 MWs. Units 1, 2, and 3 are wholly owned by APS; APS has a 15 percent ownership interest in Units 4 and 5. APS’s total generating capacity is 788 MWs. Coal for the plant is supplied by BHP Billiton from its Navajo Mine located on the Navajo Reservation in close proximity to the power plant.
Navajo Generating Station
The Navajo Generating Station is a jointly-owned facility operated by SRP and is located in northern Arizona on the Navajo Reservation near the town of Page. The plant is owned by a partnership of five utility companies and the U.S. Bureau of Reclamation; APS owns 14 percent (315 MWs). The plant has three coal-fueled, steam-electric generating units. The Navajo Generating Station’s coal requirements are purchased from a supplier with long-term leases with the Navajo Nation and the Hopi Tribe. The coal is delivered to the power plant via a dedicated electric railway.
59 PVNGS is operated by APS and is owned by a consortium of seven utilities in the Southwest.
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3.1.B.iii. Natural Gas
Redhawk Power Plant
The Redhawk Power Plant, which has been in operation since mid-2002, is APS’s largest combined cycle (“CC”) power plant. The plant is located near the PVNGS, west of Phoenix, and is owned and operated by APS. The Redhawk units (along with Unit 5 at West Phoenix Power Plant) are the most efficient gas-fired generators that APS owns. The Redhawk plant is comprised of two 492 MW natural gas-fueled combined cycle units for a total capacity of 984 MWs.
Ocotillo Power Plant
The Ocotillo Power Plant, located in Tempe, has two steam boilers and two combustion turbine units that are capable of generating 330 MWs. The APS Solar Technology and Research (“STAR”) Center is also located on the grounds of the Ocotillo Power Plant and performs state-of-the-art research and development regarding solar and other renewable generation.
Sundance Power Plant
APS purchased the 420 MW Sundance Power Plant in the spring of 2005. This peaking plant is located in Coolidge. The simple-cycle, natural gas-fueled station consists of ten quick-start combustion turbines.
West Phoenix Power Plant
Located in southwest Phoenix, the West Phoenix Power Plant has seven generating units, consisting of two combustion turbine units and five units that employ combined cycle technology. West Phoenix is capable of generating 988 MWs of electricity.
Saguaro Power Plant
The Saguaro Power Plant, located north of Tucson along I-10, has two steam units and three combustion turbine units. APS operates and owns all five of the generating units that have a combined capacity of approximately 399 MWs.
Douglas Power Plant
The Douglas Power Plant, located in the town of Douglas in southeastern Arizona, is comprised of one 16 MW combustion turbine unit. The plant is operated and serviced by employees from the Saguaro Power Plant.
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Yucca Power Plant
APS operates the Yucca Power Plant near Yuma in southwestern Arizona. The Company owns six combustion turbine units at the plant that produce 243 MWs. The plant’s other combustion turbine unit and one steam unit are owned by the Imperial Irrigation District.
3.1.B.iv. Long-Term Purchases (Conventional Resources)
In addition to the owned generating capacity, APS has contracted for several long- term power purchases, which consist of both renewable and conventional PPAs. The figure below provides a listing of the long-term PPAs in place for the summer of 2009. APS also enters into numerous short-term purchase agreements for the purpose of meeting summer season capacity requirements, as well as to take advantage of opportunities to procure more economical energy supplies.
Figure 32 - Long-Term Conventional and Renewable PPAs (Summer 2009) Long-Term Purchased Power Agreements
YEAR 2009 CAPACITY PURCHASE RATING TYPE (MWs) 1 SRP TERRITORIAL & CONTINGENT N/A 238 2 PACIFICORP SEASONAL EXCHANGE EXCHANGE 480 3 CC TOLLING #1 GAS CC TOLL 500 4 GAS CALL OPTION MARKET OPTION 150 5 MARKET CALL OPTION MARKET OPTION 500 6 TOTAL CONVENTIONAL PURCHASES 1,868
7 ARAGONNE WIND WIND 90 8 CE TURBO GEOTHERMAL 10 9SWMP BIOMASS BIOMASS 14 10 LANDFILL GAS PROJECT LANDFILL GAS 3 11 HIGH LONESOME WIND WIND 97 12 TOTAL RENEWABLE (NAMEPLATE) 214
PacifiCorp Seasonal Exchange Agreement
APS has a seasonal capacity/energy exchange agreement with PacifiCorp. APS receives 480 MWs of capacity and resultant energy from PacifiCorp during the summer season, during APS’s peak demand, and returns this same amount of capacity and energy to PacifiCorp during the winter. This contract expires following the winter season of 2020-2021.
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SRP Territorial & Contingent Capacity Agreement
APS purchases approximately 238 MWs (2009 estimated value) of capacity and energy from SRP. Under the terms of this agreement, SRP has a contractual right to terminate this agreement by providing a three-year advance notice to APS. SRP has notified APS that it has opted to terminate this agreement effective in June 2010.
Merchant Combined Cycle Tolling Agreement #1
APS has a 500 MW tolling agreement with a merchant power plant with combined cycle technology that is located west of Phoenix. This PPA provides APS with full dispatch control of the 500 MW unit. APS is responsible for delivery of fuel to the power plant. This PPA began delivery in 2007 and expires in 2017.
Merchant Combined Cycle Tolling Agreement #2
APS has a 560 MW tolling agreement with a merchant power plant with combined cycle technology that is located west of Phoenix. This PPA provides APS with full dispatch control of the 560 MW unit during the summer season. APS is responsible for delivery of fuel to the power plant. This PPA will begin delivery in June 2010 and expires in 2019.
Long-Term Contracts for Day-Ahead Call Options
APS has two contracts for day-ahead call options. The first is comprised of 500 MWs of day-ahead call options from a wholesale marketing company. This PPA provides APS with the ability to call upon peaking power supplies on a day-ahead basis for the summer season. This PPA began delivery in June 2007 and expires in September 2015. The second contract is comprised of 150 MWs of day-ahead call options from another wholesale marketing company. That PPA provides APS with the ability to call upon peaking power supplies on a day-ahead basis for the summer season. It began delivery in June 2007 and will expire following the summer of 2016, unless APS exercises its option to extend the contract for an additional five years.
Demand Response Contract
APS has entered into a contract with a third-party provider of demand response for 100 MWs of demand response resource. This contract covers a 15-year period and begins in 2010. This demand response contract allows APS to request (through the third- party provider) participating commercial and industrial customers to reduce consumption levels within previously agreed to limitations. This contract includes a ramp-up period for the first several years of the contract period. The full 100 MW capacity amount is not expected until after the first summer season of the contract. Because this is a demand- side resource, the APS system does not realize transmission or distribution line losses in
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“making this energy available.” As a result this capacity has an increased benefit to the APS system, reflected as 105 MWs in the loads and resource summary.
3.1.B.v. Long-Term Purchases (Renewable Resources)
APS has several existing PPAs with renewable generating resources. Some of these resources have begun operations, and some will begin to produce power within the next several years.
90 MW Aragonne Mesa Wind Project
APS has a twenty year PPA to purchase the entire output of the Aragonne Mesa wind project located in New Mexico. Ninety megawatts of wind capacity is delivered to APS at the Four Corners switchyard. This project began making energy deliveries to APS in December 2006.
283 MW Solana CSP Solar Project
APS has entered into a 30-year PPA to purchase the output from the Solana solar project, which will be located just west of Gila Bend. This power plant will be based on solar trough technology and will also include six hours of thermal energy storage. The project is expected to begin deliveries of power to APS in early 2012.
97 MW High Lonesome Wind Project
APS has a 30-year PPA to purchase the entire output of the High Lonesome wind project, located in New Mexico. This wind capacity will be delivered to APS at the Four Corners switchyard. This project is expected to begin producing power in 2009.
10 MW Geothermal Project
APS has a long-term PPA to purchase the output from a 10 MW geothermal power plant that is located in the Salton Sea area of southeastern California. This capacity is delivered to the APS system in Yuma. This project began delivering energy to APS in January 2006, and extends through 2029.
Landfill Gas Projects
APS has three separate PPAs to purchase the output from landfill gas projects that will be located in the metropolitan Phoenix area. These projects have not begun commercial operations, and two of the projects are expected to begin producing power within the next two years.
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Biomass Project
APS has a long-term PPA to purchase a portion of the output (14.5 MWs) from a biomass facility that is located in northeastern Arizona. This project began commercial operation in the spring of 2008.
Utility-Owned Renewable Resources
APS currently owns approximately 6 MWs of solar resources. The largest of these installations is the solar photovoltaic (“PV”) system located at the Prescott Airport site. This location alone includes over 3 MWs of solar PV generation. Another major installation is the 1 MW solar trough system located adjacent to the Saguaro Power Plant.
3.1.C. Outlook for Existing Resources
As described in the previous section, APS has several resources that will expire during the course of this Resource Plan’s forecast period. The figure below provides a representation of the capacity outlook for APS’s existing resources.60
Figure 33 – Outlook for Existing Resources
(MWs) Existing Resources (Capacity at Summer Peak Conditions) 10,000 Conventional PPAs 9,000 (plus DR) Renewable 8,000 PPAs
7,000
6,000
5,000
4,000
3,000 Owned Generation 2,000
1,000
0 2009 2011 2013 2015 2017 2019 2021 2023 2025
60 “Existing resources” includes both company-owned generation and PPAs. Existing resources also includes resources that APS has already contracted for, although some of these resources are still in the development or construction process and have not yet begun to produce electricity.
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Over the next several years, APS’s base of existing resources expands from the current level of approximately 8,200 MWs to more than 8,800 MWs. The vast majority of this expansion is the result of long-term PPAs that APS has entered into for both conventional and renewable resources. The figure above shows a decline in the total capacity resources after 2015. This is when some of the existing long-term PPAs for conventional resources begin to expire. By 2025, all of the existing long-term conventional PPAs will have expired and the total capacity resources will have declined to just under 6,600 MWs.
An important assumption in this outlook is that all of APS’s existing owned generation will continue to be economically viable generation sources and will remain a part of APS’s resource portfolio. APS is taking steps through periodic maintenance activities and capital improvements to maintain the existing generation fleet in a condition that will ensure the long-term viability of these generating units. However, there remains a possibility that outside forces will impact the continued viability of some of the generation resources.
There are potentially three main issues/forces impacting the ability of existing owned resources to continue to provide economic service. The first is the need for significant new investments to replace aging components or for new equipment to meet changing environmental requirements. The second is receiving necessary extensions to existing licenses or leases. The third is the potential for increased costs to comply with future GHG legislation.
Generally, existing resources, given the advantage of their “sunk” capital costs, tend to provide significant economic advantages to customers when compared to the option of retirement and replacement with newly constructed power plants. In light of the current debate surrounding the climate change issue, APS’s existing coal units provide a good illustration of these issues.
The existing coal units provide significant economic value to APS’s customers. In the near-term, the most viable energy source to replace the energy derived from the existing coal units would be natural gas.61 However, because the cost of natural gas fuel is substantially higher than coal, costs would rise substantially. The existing coal resources have fuel costs of about $1.5 to $2/mmBTU, compared to expected natural gas prices in the range of $8 to $10/mmBTU.
For example:
Assume that 500 MWs of existing coal generation is replaced with 500 MWs of gas combined cycle resource with a 7,000 BTUs per MWh heat rate. At a natural gas price of $8/mmBTU, this resource will have an
61 This could involve a combination of both new natural gas generating units and increased production from existing units.
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annual fuel cost of $206 million (when operated at an 85 percent capacity factor). In contrast, the 500 MWs of existing coal resource would have an annual fuel cost of $78 million (assuming 10,500 BTUs per MWh heat rate and $2/mmBTU coal price). In this simple illustration, the existing coal resource provides an annual savings of $128 million.
The coal unit also provides an important risk reduction benefit by reducing overall levels of natural gas consumption. In the preceding illustration, without the coal resource, 26 BCF more natural gas would be consumed per year. This would represent a significant increase in APS’s natural gas consumption. If retirement of existing coal units becomes a meaningful national trend, then it is likely to impact natural gas price levels and further widen the cost differential illustrated above.
There are several other considerations that could come into play in the future. First, APS may have to make significant investments in existing coal units due to changing environmental requirements (other than climate change). Second, future climate change requirements are likely to increase the cost of existing coal resources relative to other generation resources, such as natural gas. Either of these factors could impact the economic attractiveness of APS’s existing coal resources. With full consideration of the above discussion, APS does not believe that it is prudent at this time to consider retirement of the existing coal resources. This situation will require close monitoring in the coming years as many of the important factors evolve.
Several of APS’s existing resources will require extensions of either leases or operating licenses in the future. The Palo Verde Unit 2 sale and lease back will expire in 2016 and will be subject to renewal. The original 40-year operating licenses for the Palo Verde nuclear units will expire in the 2025 through 2027 timeframes. APS filed license extensions on December 15, 2008 with the NRC which would extend the operating licenses for the Palo Verde units for an additional 20 years. Additionally, the plant site lease for the Four Corners power plant and the related transmission facilities expires in 2016 and must be renewed. APS expects all of these extensions to be granted under economic terms that will allow these resources to continue to provide economic service.
3.1.D. Energy Mix
The diversity of the energy sources APS uses to meet its customers’ needs is an important aspect of resource planning. Diversification of energy sources is a key element of managing the long-term portfolio risk. In the long-term, it is difficult to anticipate all of the different types of risk that can impact the cost and viability of each of the different energy sources. For this reason, it is important that APS strive to achieve a balanced portfolio of energy sources and avoid over-reliance on any single energy source.
The figure shown below depicts the relative contribution of each energy source in APS’s resource portfolio. APS’s portfolio of energy sources is reasonably well-balanced
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Figure 34 – Projected Energy Mix for 2009
2009 Projected Energy Mix Renewable New EE (2%) (2%)
Nuclear (26%) Natural Gas (33%)
Coal (37%)
3.1.E. Other Key Parameters
An important risk factor facing many electric utilities today is the volatility of natural gas prices. Figure 35 provides a summary of APS’s projected natural gas consumption for 2009, approximately 77 billion cubic feet (“BCF”) for the year.63 The projection does not include the potential impact of short-term purchases of electricity in the wholesale market. While these short-term purchases could reduce the quantity of natural gas that APS actually consumes, the price of these electricity purchases is
62 The energy contribution from conventional purchase contracts is included within the natural gas category because these long-term purchases are linked to natural gas through either tolling arrangements (in which APS actually delivers the fuel to the power plant) or via pricing indexes in which the price of electric energy is directly linked to natural gas prices. 63 This projection also includes natural gas that APS is responsible for providing for tolled generating units.
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The figure below demonstrates that the vast majority (about 95 percent) of the natural gas that APS burns occurs in the high efficiency combined cycle units. Only a relatively small amount of the estimated gas consumption occurs in the less efficient peaking units. Because of their efficiency, these combined cycle units provide a “hedge” against increases in natural gas prices in much the same way that a more fuel-efficient automobile provides a hedge against rising gasoline prices for the average consumer.
Figure 35 – Projected Natural Gas Burn for 2009
2009 Projected Natural Gas Burn
90 Peaking 80 (owned + purchases) 70 Tolled CCs 60
50
40
30 Owned CCs 20
10
0
The following figure shows the projected CO2 emissions for the APS portfolio in 64 2009. The figure shows that close to 75 percent of the total estimated CO2 emissions for 2009 come from APS’s coal-fired power plants. The next largest source of CO2 emissions are the natural gas-fired combined cycle power plants at just under 25 percent of the total.
64 APS has assigned an emissions rate to each source of energy that is used to meet APS customer requirements. This includes developing an estimated emissions rate for electricity purchases from other providers via long-term contracts. Although these estimates are not precise because the ultimate source cannot be identified in advance for some of the contracts, it is more important to assign an estimated emissions rate to each source for the resource planning studies.
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Figure 36 – Projected CO2 Emissions for 2009 2009 Projected CO2 Emissions Peaking (2 slices) Tolled CC's (owned + purch.) (1.2 MM tons) (0.4 MM tons)
Owned CC's (2.8 MM tons)
Coal (12.3 MM tons)
Total Estimated is 16.7 MM tons
Water availability and consumption are important issues in Arizona. Figure 37 illustrates the projected water consumption from APS’s energy sources for 2009. As was the case in the previous figure concerning CO2 emissions, APS has estimated the water consumption rates for energy sources used to meet projected customer requirements.65
The estimated total water consumption for 2009 is approximately 56,000 acre-feet. A large portion of the water use is from reclaimed water sources. The use of reclaimed water sources is estimated to comprise 46 percent of the total water use in 2009. APS’s Palo Verde Nuclear Generating Station and Redhawk Power Plant utilize treated sewage effluent as their cooling water sources.
65 This is inclusive of generation sources that APS owns or controls through tolling arrangements or for long-term purchased power contracts.
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Figure 37 – Projected Water Consumption for 2009 2009 Projected Water Consumption 60,000
All Other 50,000
40,000
30,000 Redhawk CC
20,000 Utilize Reclaimed Palo Verde Water 10,000 Sources
0
3.1.F. Efficiency Improvements
APS is continuously evaluating opportunities to improve power plant efficiency in a cost-effective manner. Any project undertaken at a power plant must be justified by one of these three criteria: i) regulatory requirements; ii) reliability needs; or iii) economics. Most projects are justified through economics. Similar to resource planning economic evaluations, these economic calculations are made from a customer cost perspective. Projects with the best return on the capital investment are undertaken.
In the economic calculations used to justify projects, there are tiers of justification criteria, based on how definite the savings for the project would be. The highest tier, with the least ambiguity, includes fuel savings and capacity increases. Lower tiers might include savings in maintenance materials or labor cost. Projects that decrease fuel use without reducing output or increase output without increasing fuel use are the most likely to be approved. These two criteria essentially define power plant efficiency.66
Of course, simply increasing power output or decreasing fuel use is not enough to justify a project. To be approved, a project must provide more benefits than it costs to complete, preferably much more. Thus, efficiency improvements must pay for themselves in terms of additional power output or reduced fuel use.
66 Efficiency is simply a measure of output (i.e., power) divided by input (i.e., fuel). Any project that increases power output or decreases fuel use necessarily improves efficiency.
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APS engineers are constantly looking for ways to increase output without increasing fuel burn or to decrease fuel use and maintain the same output. For example, recent projects at Cholla have increased the capacity from 245 MWs to 260 MWs on Unit 2 and from 260 MWs to 271 MWs on Unit 3 at the same fuel burn rate and with no increase in air emissions.
In 1997, APS initiated a program to improve heat rates at the fossil fuel generating units. APS looked for obstacles to improving heat rates and came up with a list of potential changes. This included both physical and operational changes. APS reduced the number of non-productive unit starts, reduced hot standby times, increased minimum operating loads, optimized start-up curves, and changed the way units were dispatched to avoid short run times. APS also eliminated gas leaks, reduced auxiliary load by shutting down equipment not required, addressed cooling tower cleanliness, used thermal imaging to detect areas of heat loss, and upgraded turbine blades where appropriate. Despite the aging of the units, heat rates have been maintained, and in some cases improved over the last ten years, with no increase in air emissions.
3.1.G. Transmission System
APS has developed a transmission system that enables delivery of resources to APS load. The following figure depicts the existing EHV and high voltage (“HV”) transmission system as it relates to the APS resources and load centers.
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Figure 38 – APS/Arizona Transmission and Generation APS EHV & OUTER DIVISION 115/230 KV TRANSMISSION PLANS 2009 - 2018
NAVAJO TO CRYSTAL FOUR CORNERS
MOENKOPI TO ELDORADO
TO GLEN SELIGMAN CANYON (WAPA) TO MEAD / MARKETPLACE COCONINO
ROUND (W 2 circuits AP YAVAPAI VALLEY A) VERDE FLAGSTAFF FLAGSTAFF CHOLLA BAGDAD (WAPA) WILLOW (APS) LAKE ( 2012 SR ( P W ) A Line Relocation P SUGARLOAF A ) ) A 2010 P 2009 A
W ( DUGAS CORONADO 2009 PREACHER TS9 GAVILAN CANYON 2010 PEAK 2010 SUN VALLEY MAZATZAL DELANY 2014 2013 2014 2016 WEST 2014 WING PINNACLE HARQUAHALA PEAK LIBERTY PALO VERDE- HASSAYAMPA RUDD KYRENE COOLIDGE JOJOBA KNOX VALLEY FARMS REDHAWK SUNDANCE TO GILA RIVER/ DESERT IMPERIAL 2013 TBD PINAL CENTRAL PANDA SANTA BASIN VALLEY 2014 2011 N.GILA ROSA GILA BEND CASA GRANDE TS12 Milligan 2012 2009 YUCCA TAT MOMOLI SAGUARO ORACLE SAN MANUEL LEGEND JUNCTION
EXISTING 500 KV LINES ADAMS EXISTING 345 KV LINES EXISTING 230 KV LINES POWER PLANT EXISTING 115 KV LINES
PLANNED 500KV LINES NUCLEAR POWER PLANT MURAL PLANNED 230KV LINES 115KV & ABOVE SUBSTATION (EXISTING) 12/24/08 230KV & ABOVE SUBSTATION (FUTURE) NORTH Transmission Planning
Substation locations and line routings depict an electrical connection only and do not reflect any assumed physical locations or routing.
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Current Transmission Facilities
APS owns all or a part of several major transmission paths in the states of Arizona, New Mexico, and Nevada. These transmission paths deliver energy from baseload, intermediate, and peaking facilities (as described in the previous section) as well as from various long-term purchase agreements. APS owns a total of 7,035 MWs of transmission capacity on four main transmission paths. The following figure provides an overview of this transmission.
Figure 39 – APS-Owned Transmission Capacity on Major Paths (Summer 2009) Transmission Path APS Total Capacity (MW) Eastern Path 1340/1925* Mead to Phoenix 349 Navajo to Phoenix 559 Palo Verde/Gila Bend to Valley 2862
* 1340MW represents the northern portion of the path from Four Corners to Cholla and 1925MW represents the southern portion of the path from Cholla to the valley
1. Eastern Arizona Transmission Path
The eastern Arizona transmission path is made up of several EHV and HV transmission segments.67 This path is fully utilized by APS and is used to deliver numerous resources to APS customers as shown in Figure 40.
67 These include the Four Corners to Cholla 345kV lines, the Cholla to Pinnacle Peak 345kV lines, the Cholla to Saguaro 500kV line, and the Saguaro to Kyrene 230kV line(s).
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Figure 40 – APS Eastern Transmission Path and Uses
Uses of Eastern Path: Four Corners to Cholla: Four Corners TTC =1340MW - 186MW (Others Use) - 782MW (Baseload Use) - 230MW (Summer PAC Use) - 190MW (Renewable Wind Use) Cholla - 50MW (Peak Contract Use) = -98MW (Oversubscribed) 0MW*
Cholla to Saguaro/Kyrene & Pinnacle Peak TTC =1925MW - 1340MW (Four Corners Resources) Phoenix - 350MW (Others Use) Pinnacle Peak Metro Area - 650MW (Baseload use) Kyrene + 731MW (Delivery to Load/others) - 396MW (Peaking Unit use) - 15MW (Renewable Use) = -95MW (Oversubscribed) * Transmission path lends itself to use by wind as an energy only resource
Saguaro
2. Mead Transmission Path
The Mead transmission path is made up of one 500 kilovolt (“kV”) transmission line from the Mead substation in Nevada to the Westwing substation in Phoenix. APS is a minority owner in the line. This transmission line provides transmission capacity to deliver resources from the Mead area to APS load. This path is currently used by APS to deliver purchased power peaking resources to APS customers as shown in Figure 41. Mead is also a major market hub in the southwest and provides a liquid trading point for APS.
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Figure 41 – Mead Transmission Path and Uses Mead Current uses of Mead Path: TTC =349MW (with 2009 upgrade) - 225MW (Peaking PPA Use) = 124MW (Available for resources) 124MW (2009)
Westwing Phoenix Metro Area
3. Navajo Transmission Path
The Navajo transmission path is made up of two 500 kV transmission lines that run from the Navajo Generating Station to the Westwing substation. This path is used by APS to deliver base load resources to APS customers as shown in Figure 42. There is currently transmission capacity available to use for new resources. APS currently considers the availability of capacity on this path to be available for short-term use, since the path is interconnected to the CAISO at Moenkopi and purchases could be made from California sources on a short-term basis.
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Figure 42 – Navajo Transmission Path and Uses
Navajo Current uses of Navajo Path: TTC =766MW (with 2010 upgrade) CAISO Moenkopi - 315MW (Baseload Resource) = 451MW (Available for resources) Northern Area Loads
TS-9 451MW (2010)
Westwing Phoenix Pinnacle Peak Metro Area
4. Palo Verde Transmission Path
The Palo Verde transmission path is made up of several EHV and HV transmission segments.68 These transmission lines all provide transmission capacity to deliver resources from the Palo Verde area to APS load. This path is used by APS to deliver numerous resources to APS customers as shown in Figure 43. Palo Verde is a major market hub in the southwest and provides a liquid trading point for APS. In addition to APS’s existing resources, there are currently combined cycle gas resources available to market participants with access to the Palo Verde hub. APS continues to expand this capacity due to the diversity of resources available in the Palo Verde area and to the west of the Palo Verde area.
68 These include the two Palo Verde to Westwing 500kV lines, the 500kV line from Hassyampa to Kyrene, the 500kV line from Hassayampa to Rudd, the 500kV line from Hassayampa to North Gila, and the 230kV line from Gila Bend/Panda to Liberty/Rudd.
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Figure 43 – Palo Verde Transmission Path and Uses Current uses of Palo Verde East Path: Palo Verde East: TTC =3508MW - 50MW (Others Use) - 1148MW (Baseload Use) - 1520MW (Combined Cycle Gas Use) - 375MW (Peaking PPA Use) + 84MW (Delivery to Load/Others) TS-9 = 499MW (Available for resources)
Sun Valley
Delaney Westwing Palo Verde Phoenix Pinnacle Peak Hub Metro Area Kyrene Rudd 168MW
Yuma Liberty Gila Bend/Panda
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3.2 TECHNOLOGY COMPARISONS
This section provides a description of the resource options that APS has available to satisfy future customer needs. It provides a brief discussion of each resource option, key benefits and risks, and the results of a screening level economic assessment of the technologies. Importantly, this analysis factors in knowledge gained in response to several APS RFPs and significant study efforts.
An important aspect of examining resource choices is the timeframe in which different resources may actually be implemented. Figure 44 below provides a graphic representation of timeframes required for implementation of various resource options.69 A key observation from the figure is the extensive lead time required to implement new baseload resources. Because of the necessary permitting and construction timeframes, APS would need to begin actively evaluating the nuclear options now for those resources to be in-service when needed.
Figure 44 – Resource Availability Timeline
Phase 1 Phase 2 Phase 3 Phase 4
New Nuclear
New Conventional Coal
New Gas CTs/CCs
Renewable Resources
EE & DR & DE ST Market Purchases & Existing Merchants 2009 2011 2015 2020 2022
In examining resource options, APS analyzes demand-side, conventional and renewable resources, and developing technologies. Each of the resource options has a unique set of characteristics, benefits, and risks that must be taken into consideration. APS must also assess the status of the technology in the overall technology development cycle. The technological maturity is a key consideration in the resource planning process because it indicates a potential source of risk that can differentiate one technology from another.
69 Figure 44 is an illustrative representation of resource lead times and is not intended to represent situations in which significant development or permitting efforts have already been accomplished for the resource.
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3.2.A. Energy Efficiency Programs
APS currently has a DSM program that provides customers with various opportunities to conserve energy and reduce their electricity usage. The primary objective of APS’s DSM program is to reduce the amount of energy that APS customers would otherwise consume in the absence of these programs. These reductions in customer consumption result in several positive benefits including: reduced generation from fossil-fueled power plants; lower levels of air emissions (including CO2); reduced water consumption for generation; and deferral of the need to construct new power plants and transmission lines. From a customer perspective, the DSM programs provide tools to help them manage their electric bills and provide environmental benefits by installing energy efficient measures in their homes and businesses. Further description of APS- sponsored DSM programs is provided in Special Topics Section 4.1.C.
Pursuant to the 2005 APS general rate case decision, APS was required to spend $48 million on DSM from 2005 to 2007 with $10 million per year to be recovered through base rates and any additional amounts to be recovered through a customer surcharge calculated through a backward-looking DSM Adjustment Charge (“DSMAC”) mechanism.70 The programs implemented since the April 2005 decision have achieved a reported lifetime energy savings of more than 4,683 GWhs.71 Under recently approved plans, APS will spend a total of $76.5 million on DSM programs between 2008 and 2010 on Commission approved energy efficiency programs.72
a. Benefits of Energy Efficiency
Energy efficiency programs can provide for significant environmental benefits including reduced air emissions (including CO2) and water consumption. Energy efficiency also reduces system energy losses and the need to construct major infrastructure, such as new generating plants and transmission lines. Participating customers can proactively control their energy costs and lower their electricity bills.
b. Risks of Energy Efficiency
Because the success of energy efficiency programs depends upon customer participation levels, they are not controllable to the same extent as supply-side resources. Additionally, because the rate structures for most utilities result in a large percentage of fixed costs being recovered through consumption-based energy charges, the reduced energy sales resulting from energy efficiency programs can impact the ability of the utility to fully recover fixed costs of service. Regulatory policies and mechanisms are
70 Decision No. 67744 (Apr. 7, 2005). 71 This is measured through June 2008 and is in addition to the savings resulting from the pre-2005 DSM programs. 72 Decision No. 70666 (Dec. 24, 2008).
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The cost to implement energy efficiency will inevitably increase over time, as the “high savings with low cost” measures, such as compact fluorescent lighting, are saturated or legislated as standard equipment and future energy efficiency programs will need to turn to the “high savings with higher cost” measures. These latter measures will require a higher utility incentive to induce customers to make a larger investment in energy efficient equipment, therefore driving up the cost of implementing energy efficiency over time. From 2005 to 2007, APS was able to implement energy efficiency programs at an average cost of around one cent per lifetime kWh. The cost of future energy efficiency programs is expected to at least double or triple, although the exact magnitude of cost escalation depends on many factors and is largely unknown at this time.
Additionally, because the cost of energy efficiency programs is borne by customers, there is a realistic threshold of spending that a customer is willing to bear to fund these programs. Even though there may be a high level of technical, economic, and market potential for energy efficiency, the rate impact on the customer needs to be considered as a constraining factor as well.
3.2.B. Distributed Energy
Distributed Energy (“DE”) resources73 are small-scale renewable generation sources located on or near a customer’s premises. The RES rules require that a portion of the renewable energy requirements be obtained from DE and that the installed resources result from residential systems and non-residential systems in equal proportions.74 As part of the RES requirements, the energy generated or displaced by the DE system is applied towards the percentage of the utility’s total renewable energy requirement. The required DE percentage in 2009 is 15 percent of the total renewable energy requirement and that increases to 30 percent by 2012 and beyond.75 While a great number of technologies are eligible under the rules, APS believes that the majority of the installations will continue to be solar hot water and solar PV systems.
73 Qualified distributed energy resources pursuant to the RES rules include: Biogas or Biomass Electricity Generators; Grid-tied and Off-grid Solar Photovoltaic Generators; Biomass or Biogas Thermal Systems; Non-residential Solar Pool Heating Systems; Geothermal Space Heating and Process Heating Systems; Geothermal Electricity Generators; Renewable Combined Heat and Power Systems (“CHP”); Non- residential Solar Daylighting, Solar Heating, Ventilation, and Air Conditioning (“Solar HVAC”); Solar Industrial Process Heating and Cooling; Solar Space Cooling; Solar Space Heating; Solar Water Heaters; Grid-tied and Off-grid Wind Generators of 1 MW or less; Fuel Cells that use only renewable fuels; and New Hydropower Generators of 10 MW or less. See A.A.C. R14-2-1802.B. 74 A.A.C. R14-2-1801. 75 A.A.C. R-14-2-1804 and 1805.
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From program inception in 2002 through the end of 2008, APS has facilitated the installation of approximately 6.7 MWs of solar PV systems and over 1,000 solar hot water systems through its Renewable Energy Incentive Program (“REIP”). This program provides incentives to participants located in APS’s service territory that reduce the participants’ cost of installing distributed renewable systems. For residential and small commercial systems, APS pays one-time up-front incentives and for larger commercial systems, production-based incentives are paid. These incentives are designed to be paid over 10, 15, or 20 years and are based on the actual output of the distributed energy systems.
The distributed energy portion of the RES requirements rises dramatically over the next several years. For example, the 2009 distributed target is estimated to be 88,000 MWhs increasing to approximately 400,000 MWhs in 2013. APS believes that the incentives alone may not provide enough participation to meet or exceed the distributed targets, especially considering the current economic conditions. Going forward, APS is evaluating a number of new concepts or program enhancements which are designed to increase the level of participation and which would be designed to further leverage the benefits of distributed energy resources. Some of these enhancements may include additional distributed RFPs similar to the 2008 RFP discussed below, RFPs targeted towards specific technologies, participant groups, or geographic areas, or non-traditional distributed business models aimed at driving specific outcomes.
Previous evaluation efforts have resulted in a number of new distributed programs currently in the implementation stage. This includes a home builder program designed to incent builders to include renewables and energy efficiency as standard practice in new construction and a public assistance program that will focus on the unique needs of customers in the low income, schools, governmental and non-profit segments. APS believes that it will need to continually evaluate additional options and new features that increase customer participation to ensure success of its distributed energy programs. In addition, APS believes that DE resources can provide specific value to the overall portfolio of resources. Continued pursuit and definition of those opportunities is an important aspect of APS’s efforts with respect to DE.
1. Risks and Benefits of Distributed Energy
In an effort to increase APS’s understanding of role and opportunities with widespread implementation of DE resources, APS has undertaken three key efforts. Each of these activities is expected to provide information that will clarify and quantify the costs, risks, and benefits associated with DE resources. Because each of these activities is ongoing, the results are not yet fully incorporated into this Report.
First, APS initiated a comprehensive study involving all interested stakeholders. In February 2008, APS issued an RFP to study the operating impacts and valuation of DE technologies in the APS service territory. RW Beck was awarded the contract in March
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2008 to conduct the project with the primary goal of assessing the value of distributed solar energy generation on the APS system. In September 2008, RW Beck completed the project’s Task 1 in which four distributed solar technologies (residential PV, residential solar water heaters, commercial PV, and commercial solar day lighting) were identified for further study. In the remaining tasks, the study will evaluate the capacity and energy values provided by these solar applications and their impacts on system operations, economics, and reliability. Realistic deployment scenarios will be presented to serve as guidance to APS, customers, and renewable energy stakeholders for achieving the values identified in the study. The project is scheduled to be completed in February 2009.
Second, APS has been conducting a Photovoltaic Performance Study to determine expected production from photovoltaic systems that have been installed since 2002. Approximately 100 systems are being inspected for installation standards and annual actual performance data is being compiled to compare with predicted performance metrics. The results of this study are expected in 2010.
Third, APS began a competitive DE procurement process. In August 2008, APS issued an RFP to invite proposals for up to 200,000 MWhs per year from qualified DE resources. With this RFP, APS is seeking to explore opportunities to increase the cost effective deployment of DE in greater quantities. The RFP specified start dates for delivery between January 1, 2009 and December 31, 2013 from new installations with contract terms of 5 to 30 years, and each installation must be clearly identified with, and specifically related to, an APS retail customer or customers. In October 2008, APS received 26 proposals from 12 renewable suppliers, all but one of which are photovoltaic generators. APS has been in the process of reviewing and evaluating the DE proposals. The selection of winning bid(s) will be announced in May 2009. Additionally, the RFP will help inform APS about business models that might better serve the needs of customers and DE developers as the role of this resource grows in APS’s portfolio.
APS’s current resource planning analyses include a forecast of future DE installations and costs to meet the RES targets. The portfolio analysis (in the next section of this Report) includes DE resources at levels required for RES compliance, and all portfolio alternatives contain the same assumed amount of DE. APS is hopeful that information learned in the above-mentioned efforts will be factored into future resource planning analyses and that the additional opportunities for DE resources will be identified.
3.2.C. Demand Response
While the main objective of energy efficiency programs is to reduce customer energy consumption during all periods of the year, the primary objective of demand
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DR programs have been around for decades, in the form of load controllers, time- of-use rates, thermal storage, and interruptible rates. For many years, APS had interruptible pricing contracts with some large industrial customers. APS has also achieved a high customer participation in time-of-use pricing options.77 DR programs have seen a recent surge in interest due to increases in the cost of conventional technologies, increased value seen in the environmental benefits of distributed solutions, and advancement of enabling technologies.
In June 2008, APS filed its Demand Response & Load Management Program Study with the ACC, which describes various control technologies and strategies to achieve economic benefits from reducing customer loads during peak load hours. They include direct load control, customer load response, and scheduled load management programs.
In September 2007, APS issued an RFP for Commercial and/or Industrial Load Management to initiate its first DR program implementation. Five bidders responded to this RFP with a wide range of proposed DR options on maximum capacity (MW), maximum callable hours, days, and events per year, and maximum and minimum duration per event. These offers allowed an opportunity to analyze the capacity value of a DR program by using the effective load carrying capability (“ELCC”) methodology. The ELCC analysis results showed that the proposed DR programs have capacity values within the 70 percent to 80 percent range during the 2008 to 2015 time period.
As a result of the RFP, in November 2008, APS filed for Commission approval for the implementation of a 100 MW commercial and industrial DR program.78 APS continues to investigate additional opportunities for DR as the industry continues to evolve. Areas of current interest include residential load control, progressive rate structures, ice storage technologies, and coordinated dispatch of standby generation.
3.2.D. Solar Technologies (Non-Distributed)
Arizona has abundant sunshine and wide tracts of relatively flat land – the two main requirements for solar technologies. There are two main solar technologies that are
76 Broadly defined, DR programs can include any or all of the following: A/C cycling; auto-DR systems; miscellaneous equipment controls; thermal energy storage; scheduled water pumping; curtailable load; interruptible rates; time-of-use rates; critical peak pricing; demand bidding/buyback; and real-time pricing. 77 Approximately 450,000 residential customers were participating in time-of-use pricing options as of December 2007. 78 Docket No. E-01345A-08-0569. This program is a 15-year (2010-2024), summer only (June- September), maximum 80 hours/year, 7 days per week, maximum 1 event/day and 6 hours/event.
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DRAFT suitable for deployment in utility-scale applications: i) solar thermal trough; and ii) solar PV.
Solar thermal power plants produce electricity by converting the sun’s energy into thermal energy, often in the form of a heated fluid. The thermal energy associated with the heated fluid is then used to produce steam, which then drives a steam turbine generator. Common solar thermal technologies include parabolic trough, parabolic dish, and power tower. Of the three technologies, the parabolic trough technology is the one that has been most extensively deployed in the utility-scale setting.79
In contrast, solar PV systems convert sunlight directly into electricity. The solar collectors are comprised of a number of solar cells and are connected to the local electric loads or the electric grid via inverters and other power conditioners. The solar PV systems can be designed to either track the motion of the sun (either on a single axis or two axes) or to remain stationary, also referred to as “fixed”.
One of the key differences between solar thermal and solar PV technologies is the relative flexibility of the application. The solar thermal technologies are more readily able to employ either co-firing with natural gas or thermal energy storage technologies. As a result, availability increases and their energy production can be better matched to customer energy consumption patterns. In this way, some of the natural limitations of solar energy can be mitigated. Figure 45 provides an illustration of this benefit.
79 For the parabolic trough plant, the heated fluid flows through a tube at the focal point of a row of parabolic shaped mirrors. The mirrors focus the sun’s energy onto the tube, which heats the internal fluid. The mirrors are rotated during the day to track the sun and keep the sun’s energy focused onto the tube.
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Figure 45 – Typical Summer Day Production Profiles
Fixed Horizontal CSP w/6 Hr Storage Load Profile
10,000 120
9,000 100 8,000 7,000 80 ~44MW 6,000 Difference
5,000 60
4,000 Load MW (7/6/2015) 40 3,000
2,000 Capacity) (100MW MW Production 20 1,000
0 0 1 2 3 4 5 6 7 8 9 101112131415161718192021222324
A typical summer day production profile for a solar trough plant (with thermal storage) with a fixed-orientation solar PV plant. The solar trough plant is producing at full production levels at the time of maximum APS customer demand (roughly 5:00 p.m.), while the solar PV plant is producing at less than 60 percent of its full production level.
Parabolic trough power plants have been in operation in California for approximately 20 years. Plants that have been more recently constructed in the United States include the APS 1 MW solar trough facility at its Saguaro Power Plant site, and the 64 MW solar trough facility in southern Nevada. There are no solar power tower facilities currently in commercial operation in the United States, but this technology is promising because of its ability to achieve higher operating temperatures/pressures improving the efficiency of the conversion of solar energy into electricity.
APS entered into a PPA for all of the output from the Solana solar plant, a new 280 MW solar trough power plant to be located just west of Gila Bend, Arizona. The developer of this power plant is Abengoa Solar Inc. Abengoa will develop, build, and operate this solar plant, which will be equipped with a molten salt thermal energy storage system that will provide six hours of energy storage capability. APS anticipates that this solar plant will be completed and producing power by 2012.
a. Benefits of Solar Technology
In general, solar technologies produce a disproportionate share of energy during certain seasons of the year (summer) and times of the day (daylight hours) when APS’s customer consumption is high. In fact, a solar trough plant can be expected to produce 64 percent of its annual energy production during the months of May through October when APS’s customer consumption is at the highest levels. During these months, APS’s need for natural gas generation sources is also at the highest levels, so solar technologies have the potential to effectively displace a large portion of the incremental natural gas consumption on APS’s system.
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Perhaps the most significant advantage of the solar thermal technology, such as the parabolic trough and the power tower, is the potential for storage of thermal energy. This allows for a shifting of the solar energy output to better match the customer demand for electricity. The thermal energy storage system allows for solar energy to be stored, so that the “stored” solar power plant can produce at peak levels during the late afternoon and evening hours after the sun’s intensity diminishes or ceases. This provides for an effective peak capacity resource that may reduce the need for conventional peaking resources.
The solar thermal power plant requires no fuel source to operate. Although some of the existing solar trough plants have been equipped with natural gas burners as a backup source to ensure plant operability during periods of low solar input, APS believes that much of this benefit may be achieved through use of thermal storage systems to provide high reliability for the plant during peak summer periods. Similar to many renewable technologies, solar thermal technologies do not emit greenhouse gases.
b. Risks of Solar Technology
Cost is currently one of the most constraining factors for solar technologies. The estimated capital cost for a solar trough power plant is approximately $4,500-$7,500 per kW. This is approximately four times the cost of building a natural gas combined cycle power plant.80 This capital cost estimate can vary substantially depending upon the configuration of the solar plant (e.g., design can vary on the amount of thermal energy storage or the size of the solar collection field). Solar power plants require a significant amount of land. The land requirement for a 250 MW parabolic trough power plant is approximately three square miles.
The current tax subsidies are substantial benefits for solar plants and their recent extension through 2016 provides the solar industry with certainty. Congress also modified the law such that electric utilities like APS are now able to qualify for this tax credit. This could facilitate more utility ownership of large-scale solar projects in the future. APS intends to investigate whether this opportunity will provide a more economical solution for our customers in the future.
The other issue for solar power is its intermittency. Although Arizona enjoys some of the highest solar radiation in the country, storm clouds and summer monsoons can have a critical and unexpected impact on solar generation. If solar generation output is not certain, utilities must obtain other more reliable generation in order to ensure that they have sufficient capacity available at the time of the system peak. Storage or gas augmentation could solve this intermittency issue for solar thermal generation at a reasonable cost. Batteries can serve the same function for PV generation, but at present, battery solutions are very expensive.
80 The gas unit would have fuel costs while the solar plant would not.
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3.2.E. Wind
Wind turbines convert wind energy to electric energy through the use of a turbine- generator that is typically positioned between 50 and 100 meters above the ground. Utility-scale wind energy systems consist of multiple wind turbines, each ranging in capacity from one to four megawatts. These wind facilities (“wind farms”) may be sized as large as typical thermal generating units (100-500 MW). The wind industry has seen dramatic growth over the last several years, as developers and utilities utilize this relatively low cost source of renewable energy. For states with abundant, high-quality wind resources, wind often represents the least expensive source of renewable energy. Wind development has also benefited from federal (and in some cases state) tax incentives.81
Arizona has a limited amount of wind resources. Recently, Black & Veatch completed a study on potential Arizona renewable generation for APS, SRP, and Unisource. The Black & Veatch Report estimated that there are only approximately 1,500 MWs (990 MWs of identified sites plus 500 MWs of already planned wind projects) of developable wind energy in Arizona.82 Arizona’s potential wind resources tend to be located across the northern half of the state. The Black & Veatch Report’s estimates are consistent with APS’s observations through previous competitive procurement efforts.
The quality of the potential wind energy resource is not as strong in Arizona as in some other western states, and this impacts the cost-effectiveness of the wind resource. In a recent wind integration study, commissioned by APS and conducted by Northern Arizona University (“NAU”) (the “NAU Study”),83 various industry experts and APS concluded that capacity factors for wind generation in Arizona are likely to average around 30 percent on an annual basis.84 In contrast, capacity factors in the neighboring state of New Mexico range between about 35 and 40 percent. Because equipment costs are approximately the same, these lower average capacity factors mean that Arizona wind energy is likely to be more expensive than what is available in some other western states. Variance in wind regimes and site-specific costs means that individual projects will vary.
a. Benefits of Wind Technology
One of the primary benefits of wind energy involves its renewable nature and its independence from volatile fuel markets. Wind turbines produce no CO2 emissions and
81 See 26 U.S.C. § 45. The production-based tax credit is approximately $20 per MWh for wind energy (for the initial ten years of the project). 82 BLACK & VEATCH, ARIZONA RENEWABLE ENERGY ASSESSMENT (Sept. 2007) (available at http://www.bv.com/resources/energy_brochures/renewables/rsrc_AZ_RenewableEnergyAssessment.pdf). 83 NORTHERN ARIZONA UNIVERSITY, ARIZONA PUBLIC SERVICE WIND INTEGRATION COST IMPACT STUDY at 30 (Sept. 2007) (available at http://www.wind.nau.edu/documents/APS_Wind_Integration_Study_Final9-07_000.pdf). 84 The 30 percent capacity factor is representative of the best sites in Arizona.
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DRAFT no waste stream. They can be located on rugged, nearly inaccessible land, and an entire utility-scale wind farm requires only a few skilled staff to operate and maintain it. There is a robust development industry for wind technology, and certain of these developers have proven track-records, siting expertise, and the resources to attract significant front- end financial commitments for wind turbine equipment purchases.
b. Risks of Wind Technology
Wind is an intermittent resource in that it can only produce electricity when the wind is blowing. Therefore, it has a degree of unpredictability that other resources do not have. This unpredictability leads to increased system operating expenses for the utility system, because the utility must have other generating sources available to compensate. According to the NAU Study, the integration cost is estimated to range from $1 to $4 per MWh, based upon a wind energy penetration of between one percent and ten percent.
Predominant regional wind energy production occurs in the spring when APS customer loads are not at peak levels. Wind energy’s contribution to meeting summer peak loads is expected to be a fraction of the rated generation output.85
The ability to procure wind turbines and associated equipment can be a concern as developers compete for the available supply of turbines and specialized construction services. This means that the most profitable wind sites are likely to be developed first and consume the available supply of equipment.
Another issue associated with wind resources is the possibility of termination of federal production tax credits, which are currently set to expire on December 31, 2009. This tax credit is currently valued at about $20/MWh for all energy produced in the first ten years of the project’s life.86 If the tax credit is not extended, it will have a major impact on the economics of this resource.
3.2.F. Geothermal
Geothermal resources utilize the heat trapped in the earth to generate steam to drive turbine generators. The technology to extract the heat energy from sites continues to advance, but the basic technology is considered to be mature and proven. Geothermal resources typically operate as baseload plants and produce a relatively stable output over a long period of time. The operations and maintenance requirements for these plants are similar to existing steam plants.
Arizona has a very limited known supply of high-temperature geothermal resources. The known high-temperature areas are in the eastern part of Arizona and the
85 APS uses a generic planning assumption of 20 percent capacity value at the time of system peak, and specific wind projects are analyzed based upon their expected production profiles. 86 See 26 U.S.C. § 45.
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DRAFT data assessing the sites are preliminary. According to the Black & Veatch Report, the potential for geothermal projects in Arizona is assumed to be small (15 to 20 MWs).87 In contrast, a known and much larger proven supply of geothermal resources exists in the Salton Sea area of California. APS has an existing power purchase agreement with a geothermal plant from that area. California utilities also have an aggressive renewable energy standard to meet, so there is likely to be significant competition for this geothermal resource.
a. Benefits of Geothermal Resources
Geothermal plants can provide a stable, baseload supply of power that does not emit any greenhouse gases. Additionally, because the fuel for a geothermal plant is a combination of water and the heat of the earth, there is no fuel price volatility concern. The existing technology is mature, with only incremental advances in the area of heat extraction. Geothermal plants operate in a stable manner, similar to a conventional baseload power plant and do not have the intermittent production concerns associated with some other renewable technologies.
b. Risks of Geothermal Resources
Because the closest significant source of good quality geothermal resources is located in California, there is expected to be significant competition for the resource. Additionally, the California electric utilities are taking steps to ensure access to this in- state geothermal resource by developing new transmission lines.88
Geothermal resources also qualify for the federal production tax credit and are subject to the same cost risks should the tax credit expire.
3.2.G. Biomass and Biogas
Biomass technologies are commonly characterized as solid, direct-fired, biomass gasification, and biomass co-fired with coal. In the direct-fired and co-fired examples, the biomass feedstock is burned to produce steam to drive a conventional steam turbine generator. The thermal cycle is similar to a coal plant. In the biomass gasification technology, the biomass feedstock is gasified to produce a gas fuel that can be burned in a combined cycle plant to drive a gas turbine generator. Both coal and biomass gasification power plants are an emerging technology with a promise of more efficient use of the feedstock and more effective pollution controls. Biogas technologies are associated with the combustion of the gas that is generated from the anaerobic digestion of animal manure or from landfill gas.
87 BLACK & VEATCH, ARIZONA RENEWABLE ENERGY ASSESSMENT, at 5-65. 88 An example is the San Diego Gas & Electric Company (“SDGE”) Sunrise Power Link project, which is expected to run 150 miles between the Imperial Valley and San Diego.
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Biomass and biogas resources are expected to be operated as baseload resources in that they would provide a relatively stable source of power with limited fluctuations. The biomass and biogas facilities are generally small due to the limited nature of the supply of feedstock. It is typically not economical to transport the feedstock to a larger steam turbine generator site. The result is relatively small biomass plants which acquire feedstock from sources in relatively close proximity to the plant. This size limitation adversely impacts the economics of each project. In addition to the size of each project, there is a relatively limited supply of biomass and biogas feedstock in Arizona due to the arid climate. The Black & Veatch Report estimates that there is the potential for up to 250 MWs of biomass/biogas generation resources throughout the entire state of Arizona.89 Therefore, these resources are not expected to play a major role in APS’s long-term renewable energy plans.
a. Benefits of Biomass/Biogas
Although biomass and biogas plants utilize a combustion process and emit CO2, at this time they are considered carbon neutral since they emit a similar amount of CO2 as is absorbed from the atmosphere during the growth phase of the feed stock. For landfill gas projects, power production makes beneficial use of the methane gas, which would otherwise be flared or released to the atmosphere. Another important benefit of biomass and biogas generation resources is that some of these plants can be sited within the load pocket. An example is small landfill gas generation projects that can be sited at existing landfills, which are typically located inside the load pocket. This favorable siting helps APS to incrementally increase its resource capacity with a relatively small transmission and distribution investment.
b. Risks of Biomass/Biogas
The first risk associated with biomass/biogas resources is the potential termination of tax credits that apply. An additional concern is the long-term availability and cost of the feedstock. In the case of forest thinning, there currently is a good deal of political momentum (and funding) for thinning the forests in the western states to reduce fire danger. Additionally, production levels from landfill gas projects are somewhat dependent upon rainfall and could decline under persistent drought conditions.
3.2.H. Natural Gas Combustion Turbines (Peaking Units)
Because of the characteristics of customer load requirements, APS expects to have a significant need for resources (generation or demand-response) that can fulfill a “peaking” role for its electric system. This peaking role addresses the need for reliable capacity during the summer peak season. The overall need for energy from a peaking resource is typically less than 10 percent capacity factor for the entire year. Among conventional resource options, the natural gas combustion turbine (“CT”) provides the
89 BLACK & VEATCH, ARIZONA RENEWABLE ENERGY ASSESSMENT, at 4-23.
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DRAFT preferred solution for meeting this need. While these units are not as fuel-efficient as a combined cycle unit, they require lower capital investment. In addition, because of their lower utilization rates, fuel efficiency is less important than the ability of the CT units to start quickly to respond to operational contingencies and to meet the peak demand.
A CT consists of three sections: a compressor, combustor, and power turbine. Ambient air is drawn into the compressor section of the machine, and it is then compressed. Natural gas is then added to this compressed air in the combustion chamber. The resulting hot, compressed gases are then expanded through a turbine section to drive an electric generator. Several manufacturers produce and sell these CTs, and each manufacturer typically has several different models to choose from. The different models can vary significantly in terms of performance characteristics, such as efficiency, size, and startup times. Some of the newest models have heat rates just below 10,000 BTU per kWh and are capable of starting from cold conditions and achieving full rated output in less than ten minutes.
a. Benefits of Natural Gas CTs
The technology for CT units is mature. APS has extensive operating experience with this type of generating unit, as CT units have been in-service on the APS system for approximately thirty years. CTs can bring numerous operational benefits to the electric system, including rapid contingency response and load following capability. Due to the size of commercially-available units (from about 40 to 150 MWs), these units can be incrementally deployed in a manner to more closely match the growth in customer needs. This relatively small incremental size helps APS avoid “lumpiness”90 of resource additions, thereby minimizing capital risk and optimizing the operation of the entire resource portfolio.
The development and construction lead times for CT units are substantially less than for new baseload coal or nuclear units. New CT power plants can be developed in less than two years, excluding the procurement and regulatory approval processes. CT units have a relatively low initial capital cost; the current installed cost is in the approximate range of $750 to $1,100 per kW. This is approximately one-third of the cost of installing new baseload coal plants. In addition, CTs can be located in relatively close proximity to the load centers, thereby lessening the need for major transmission investments.
b. Risks of Natural Gas CTs
The primary risk associated with this technology is the price volatility associated with the natural gas fuel source. This risk is dampened by the relatively low expected utilization of CTs. Because of their relative inefficiency (as compared to combined cycle
90 “Lumpiness” refers to the potential for having surplus capacity for one or more years following completion of a large generation or transmission project.
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units), CTs have a relatively high operating cost. Although CTs emit CO2, they are not expected to become a major source of CO2 emissions because of the rather limited utilization of peaking units.
3.2.I. Natural Gas Combined Cycle
Natural gas CC units have been the most popular form of new generation in the last decade and have been deployed extensively on a national and local level. The technology involves adding a heat recovery system to capture the exhaust heat from a simple cycle CT. In this manner, the exhaust heat can be used to produce steam and generate additional electricity by employing a steam turbine without consuming any additional fuel. This makes the CC technology exceptionally efficient, with net plant heat rates around 7,000 BTUs per kWh, which is approximately 30 percent more efficient than CT technology.
Most of the merchant generation facilities that were built in Arizona in the last ten years employ CC technology.91 Approximately 6,000 MWs of merchant-owned CC units were built in Arizona by multiple companies. Pinnacle West Energy also constructed approximately 1,600 MWs of CC plants in Arizona, which were subsequently transferred to APS ownership.92 These units are now an integral part of the APS system and account for the majority of the natural gas fueled energy produced by APS.
a. Benefits of Natural Gas Combined Cycles
Natural gas CC technology is mature, and APS has extensive operating experience, as it has operated CC units since the mid-1970s. Natural gas CC units are valuable for electric system operations, and, although they cannot be started as quickly as CTs, they are especially effective at following system load fluctuations. They provide a good source of spinning and regulating reserves.93 They are also a flexible resource in that these units are capable of cycling on and off every day. In addition, they are fully capable of extended baseload operations.
Development and construction lead times are substantially less for CC units when compared with new baseload coal or nuclear units. New CC power plants can be developed in under three years, excluding procurement and regulatory approval processes. Natural gas CCs have an installed cost of approximately $1,300 per kW, which is about half the cost of new baseload coal plants. In addition, CC units can be located in fairly close proximity to the load center, thereby reducing the cost of transmission.
91 The CTs at the Sundance plant are an exception. 92 The Commission approved this transfer of assets in Decision No. 67744 (Apr. 7, 2005). 93 Both types of reserves are a necessary part of providing for a highly reliable electric system because they allow for a rapid response to system contingencies, such as the loss of a major generating unit, and respond to the normal fluctuations in customer demand.
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While CO2 emissions are an issue for CC technology, the carbon content of the fuel is significantly less than coal. The high efficiency of the plants yields CO2 emission rates that are approximately 45 to 50 percent of those of a conventional coal plant. They can be equipped with dry-cooling technologies to significantly reduce water consumption.94 APS has assumed the use of dry-cooling technology in its capital cost and performance estimates for this technology.
b. Risks of Natural Gas Combined Cycles
The primary risk associated with this technology is the price volatility associated with the natural gas fuel source. Also influential are fuel transportation and hedging strategies needed to minimize cost volatility. This is a significant risk for CC plants because these plants are used more extensively than CTs. In addition, the potential for a mandated carbon tax is also a concern for CC plants. Although their CO2 emissions rates are much lower than coal plants, these CC plants are a significant source of CO2 emissions because of their utilization.
3.2.J. Coal
Because of the importance of coal as an energy source for the nation, there are extensive technology development efforts on-going for future coal technologies. However, much of this development is in its early stages. Technologies for economically capturing CO2 emissions are not yet commercially viable. Prior to 2020, state-of-the-art pulverized coal technology is expected to remain as the most economically viable and technologically mature option for utilizing coal. In this section, a brief discussion of clean coal technology development efforts is presented. This is followed by a more detailed discussion of the benefits and risks of conventional, pulverized coal technology.
a. Clean Coal Technologies
Clean coal technologies are still in the early development phase. “Clean coal technology” describes a group of developing energy generation technologies, the goal of which is to reduce air emissions and other pollutants from coal-burning power plants. As coal is our most plentiful domestic energy resource and is expected to remain the nation’s largest single fuel source for electricity through 2030,95 these technologies are increasingly recognized as pivotal in meeting stringent state and federal environmental mandates and future carbon dioxide emission limitations. Specific clean coal technologies include:
94 Water consumption on the order of 110 gallons per MWh can be obtained by utilizing air-cooled condensers, a reduction of over 210 gallons per MWh over conventional wet-cooled condensers. 95 Energy Information Administration, U.S. Department of Energy, Annual Energy Outlook 2007 at 56 (Feb. 2007) (available at http://www.eia.doe.gov/oiaf/archive/aeo07/index.html).
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• Supercritical and Ultra-Supercritical Pulverized Coal Combustion. Supercritical and ultra-supercritical coal plants use higher steam temperatures and pressures to improve plant efficiencies and reduce plant emissions. Supercritical units are considered to be a mature technology and several new units are currently under construction in the United States. Ultra-supercritical units require extensive use of alloy steels. This technology has been built in Japan and Europe. However, there is some uncertainty regarding the long-term effects of high temperature and pressure on the boiler tubes and steam piping. From a CO2 emissions perspective, these technologies bring incremental improvements in CO2 emissions (versus conventional pulverized coal plants) because of better fuel efficiency.
• Advanced Pressurized Circulating Fluidized Bed Combustion. This technology incorporates upward blowing jets of air mixed with coal to produce complete combustion at relatively low temperatures. At this time, first- generation systems are undergoing commercial demonstration and have only been tested in pilot scale.96 This technology is typically deployed in applications in which low-grade waste coals are available.
• Integrated Gasification Combined-Cycle Combustion (“IGCC”). These plants utilize a technology that gasifies coal to create a synthetic gas (“syngas”), which can then be used to power combustion turbines. Air pollutant emissions are low with the exception of CO2. Several IGCC coal projects are being discussed across the country at the present time. The perceived benefit of IGCC technology is its potential to facilitate the capture and removal of CO2 from the syngas prior to the combustion process. It also has the potential to be less expensive than pulverized coal plants in which CO2 must be separated from the large volumes of exhaust gas after the combustion process.
Although there are potential benefits of IGCC technology, only two IGCC plants are currently in commercial service in the United States. Both of these plants are located in eastern states and their construction costs were heavily subsidized. The western states present additional challenges for IGCC due to differing fuel characteristics and higher elevations. IGCC plants will produce significantly less output at the higher elevations because of the lower density of the air.
Furthermore, neither of the two existing IGCC plants has incorporated carbon capture into their processes. The CO2 emissions from the existing IGCC plants are essentially the same as would be emitted from a similarly sized pulverized coal unit. Carbon capture (and sequestration) technologies have yet to be
96 National Energy Technology Lab., U.S. Department of Energy Combustion – Fluidized – Bed Combustion Program Status (available at http://www.netl.doe.gov/technologies/coalpower/advresearch/combustion/FBC/fbc-status.html).
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demonstrated at commercial scale on an IGCC unit. Additionally, the cost estimates for IGCC plants are significantly higher than for building a pulverized coal plant. Installed costs for this technology are close to 50 percent higher than for a similarly-sized pulverized coal unit (even without the inclusion of CO2 capture technology).
There have been a number of IGCC projects discussed across the nation and some of these projects may move forward with further development efforts. Within the last year or two, several of these IGCC projects have been either cancelled or delayed. Tampa Electric Company cancelled an IGCC project in Florida. Moreover, the developers of the Bowie project in Arizona decided to convert their planned IGCC coal project to natural gas peaking units.97 This developer cited market economics, regulatory uncertainty, and public misunderstanding as reasons for its decision to cancel the IGCC project. XCEL Energy, located in Colorado, also has delayed its IGCC project.
While IGCC technology and other technologies warrant continued monitoring by APS for long-term deployment, APS has concluded that the only viable option (from a technology perspective) for deployment of a coal-fueled generating unit prior to 2020 would be using conventional, supercritical pulverized coal technology.
b. Pulverized Coal
Pulverized coal units are characterized by their boiler operating conditions, which are sub-critical, super-critical, or ultra-super-critical. The principal difference in each of these is the temperature and pressure of the steam cycle. Higher temperature and pressure lead to an increasingly more efficient power plant. The trend in newer coal plants is towards super-critical and ultra-super-critical because they bring improvements in thermal efficiencies (and, therefore, reduced environmental emissions). The environmental performance of these new pulverized coal units has improved dramatically over the years. New pulverized coal units are equipped with scrubbers to remove SO2, selective catalytic reduction (“SCRs”) to remove nitrogen oxides (“NOx”), fabric filters for particulate removal, and activated carbon injection (or other technologies) for mercury control. These state-of-the-art controls have made the current generation of pulverized coal units much cleaner than previous coal-fired power plants.
Additionally, because water use for electric generation is a particular concern in Arizona, APS’s planning studies assume that low water use technologies will be employed if APS were to construct a new coal plant. Hybrid cooling configurations can reduce water use to approximately 320 gallons per MWh. A comparable wet-cooled unit uses approximately 640 gallons per MWh. However, the low water use technology adds to the construction cost of the plant and reduces the overall plant efficiency. These
97 “Bowie Power Plant Developers Opt for Natural Gas,” Keith J. Allen, Sierra Vista Herald/ Bisbee Daily Review (Sept. 5, 2007).
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Of particular concern for pulverized coal plants are the CO2 emissions. A new, pulverized coal plant can be expected to emit roughly one ton of CO2 for each MWh of electricity produced. Although there are efforts underway to develop technologies to efficiently capture the CO2 from the exhaust stream of these plants, these efforts are still in the research and development phase. At best, APS does not expect these technologies to be ready for commercial-scale deployment until after 2020, and it is uncertain as to the costs associated with these control technologies. For these reasons, the pulverized coal technology discussed as a resource alternative in this technical analysis does not include CO2 capture and sequestration. Therefore, the cost to comply with any future carbon tax or cap-and-trade program would represent a very significant cost risk for this technology.
i. Benefits of Pulverized Coal
Coal is a plentiful fuel in the United States, and a proven transportation infrastructure for coal is in place. Coal contributes to energy independence by reducing the need for imported energy sources (such as liquefied natural gas). Pulverized coal units are commercially proven and a mature technology. APS has close to 50 years of experience with this technology. United States pulverized coal-fired plants have achieved an average equivalent availability factor of approximately 85 percent over the last five years.98 Although coal commodity prices have risen over the last ten years, they have not exhibited significant volatility. Increased utilization of coal can provide more price stability to APS’s energy portfolio.
ii. Risks of Pulverized Coal
Pulverized coal plants are capital intensive. The installed cost for a new pulverized coal plant is in the range of $2,500 to $3,000 per kW, approximately $2.5 to $3.0 billion for a 1,000 MW coal plant. This is more than twice the cost of a natural gas combined cycle plant. Additionally, pulverized coal plant development will be subject to significant cost escalation pressures. The engineering and construction of a coal-fired plant requires a significant amount of steel and concrete. Global competition for materials and equipment has increased plant costs. In addition, the cost of skilled labor has risen sharply and the dwindling of an experienced workforce may continue to exert upward pressure on costs. Pulverized coal units involve long construction lead times. APS estimates that it takes approximately eight years to go from the start of permitting to commercial operation.
Pulverized coal plants can be very difficult to permit. There are difficulties locating coal plants near population centers and federally-protected environments. In
98 See North American Electric Reliability Corporation Generating Availability Data System (“NERC GADS”) for years 2002-2006.
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As discussed previously, pulverized coal units have a significant risk related to any potential future carbon tax or cap-and-trade program. At this time, APS believes that it is likely that climate change policies will be put in place at either the national or regional level within the next several years. It is uncertain as to how a future CO2 regulatory program will be structured or how costly it will be to retrofit a pulverized coal unit to allow for carbon capture and sequestration. It is difficult to quantify the risk associated with new coal generation resources. For these reasons, APS does not believe that new coal resources are in the best interests of its customers at this time and has not included them in its Resource Plan.
3.2.K. Nuclear
Concerns about rising fossil fuel costs and GHG emissions are driving a renewed interest in the development of nuclear resources. Public and political acceptance is continuing to grow as the “GHG-free” nature of nuclear units is increasingly viewed as a critical component of environmentally responsible electric generation.
Nuclear holds promise because it provides an energy source with a relatively stable price that does not produce CO2 emissions. The next generation of nuclear plants represents an evolutionary step from the previous generation. Some of the new designs employ passive safety systems to both improve safety performance and to simplify plant designs. The newest designs also claim improved constructability based on both the reduction in the number of systems in the design and modular construction techniques.
Some of the same limitations associated with coal plants would also apply to nuclear plants. Cooling water supplies are a concern for both types of plants and the deployment of hybrid cooling technologies can increase plant capital cost and reduce efficiencies. Furthermore, nuclear power plants are difficult and costly to locate in close proximity to the load centers, so it is likely that new transmission lines will be required.
A detailed overview of nuclear generation and plant design options is included in Part IV of this Report.
a. Benefits of Nuclear Power
Perhaps the biggest benefit of nuclear power is the absence of GHG emissions. Nuclear is the only large-scale generation source other than renewable resources that can provide a significant amount of energy without CO2 emissions. As compared to natural gas, nuclear fuel is a stable energy source that can significantly improve the stability of
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APS’s energy portfolio. The nuclear technologies that are currently being offered in the United States market are based on proven nuclear technology. GE’s Advanced Boiling Water Reactor (“ABWR”) technology is already in commercial service in Japan, and the first unit of Areva’s plant design is currently being constructed in Finland. The advances associated with the newer designs are evolutionary and retain the commercially-proven aspects of existing plants.
b. Risks of Nuclear
In the past, licensing a nuclear plant through the NRC was a multi-step process fraught with uncertainties. These uncertainties often led to significant cost overruns, as utilities were faced with having to make numerous changes to their design and construction practices between the beginning of the project and the commercial operations date. The NRC has since redesigned the licensing process so that owners/applicants may now seek construction and operating licenses in a single step – the combined construction permit and operating license (“COL”) process. The COL process requires significant financial commitment up-front. Although this new licensing process is viewed as a significant improvement from the past, it has not yet been tested, so there is a degree of uncertainty as to whether it will, in fact, solve some of the issues inherent in the previous licensing process. The success of this licensing reform is an important aspect of reducing the risk involved with new nuclear power plant projects. The previous generation of nuclear plants was exposed to costly licensing delays and retrofit requirements. Delays can significantly increase the overall cost of a plant due to the large capital investment and the cost to finance that investment during the construction phase.
The ultimate disposal of spent nuclear fuel remains an unresolved issue for the nuclear industry. Nuclear plants have limited design capacity for the storage of spent nuclear fuel. That design capacity is associated with storing spent nuclear fuel under water as it cools and continues to decay to lower radioactive levels. The federal government has a legal commitment to the owner/operators of the nation’s nuclear facilities to accept spent nuclear fuel for permanent, off-site storage. This commitment has driven the efforts to develop and license the Yucca Mountain storage facility in Nevada. To date, the federal government has not succeeded in establishing a permanent repository, and spent nuclear fuel from existing nuclear plants continues to be stored at the individual power plant sites either in the spent fuel pools or in on-site dry cask storage facilities. However, the Department of Energy (“DOE”) has entered into new contracts for disposal of spent nuclear fuel with a number of COL applicants. Therefore, DOE has expressly signaled that it remains obligated to accept spent nuclear fuel from the nation’s commercial nuclear power plants, including plants that have yet to be licensed and built.
A highly skilled workforce is required to construct, operate, and maintain a nuclear plant. Nuclear vendors have estimated that the new reactor technologies can be operated and maintained with a workforce of between 250 and 750 people per unit. The nuclear industry estimates that the average age of the existing nuclear power industry
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3.2.L. Summary of Resource Options
The following figures provide high level summaries of the resource technology options. Figure 46 presents a qualitative summary of some of the key resource planning parameters for each technology.
Figure 46 – Qualitative Resource Factors
Economic/ Resource Reliability Environment Risk Impacts Value
Reduces many risk factors Avoids construction (natural gas, CO2, construction Resource is at of new infrastructure All Emissions costs, etc.) Energy Efficiency load center, (generation and reduced, Customer acceptance/adoption and Some DR transmission), No water or land of EE and DR measures Demand Response measures are Reduces system usage Cost escalation to implement EE dispatchable energy losses programs over time
Heavy summer production, Potentially full Abundant resource in AZ, Co-fire & No air emissions, Solar Thermal capacity value, High cost, No fuel costs or risk, storage ability High Land usage Some dispatchability Dependence on tax subsidies with storage, close to load centers
Less than full Abundant resource in AZ, Heavy summer on- No air emissions, Solar Photovoltaic output at peak No fuel costs or risk, peak production High land usage load hour Dependence on tax subsidies
Intermittent Mature – Low Risk, No fuel Non-dispatchable, generation, No air emissions, costs or risk, System integration Wind Limited Visual and avian Dependency on tax subsidies, costs, contribution to impacts Robust wind development Remote locations peak industry Unproven availability in AZ Dependable Non-dispatchable, (good availability in neighboring No air emissions, Geothermal resource Full capacity value, states), Low land use High capacity factor No fuel costs or risk
Some locations at Small unit size, Biomass/ load areas, Forest health Dependable Potential resource decline, Biogas Full capacity value, benefits resource Long term fuel supply High capacity factor
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Economic/ Resource Reliability Environment Risk Impacts Value
Dispatchable Dispatched to meet Gas resource, peak needs, Low land use, Lowest capital investment, Combustion Quick start Siting proximity to Low water use Shorter lead times, Turbine capability load Fuel price volatility
Dispatchable CO2 emissions resource less than ½ of Gas Siting proximity to Must manage fuel price capable of PC coal, Combined load, volatility, daily cycling, Minimal water Cycle High efficiency Lower capital investment, Good source of use with dry Shorter lead times reserves cooling No air emissions, Spent fuel Dependable High initial Fuel price stability, Nuclear disposal and resource investment Permitting/Licensing/ cost Development Cooling water requirements Fuel: relative price stability Higher CO & abundance, Exposure to High initial 2 Pulverized Dependable emissions, future environmental investment, Coal resource Cooling water legislation, Remote locations requirements Difficulty in permitting & development Low air emissions (as compared to Fuel: stable price & Lower conventional abundant, availability and High initial IGCC Coal coal), High cost resource and less investment CO emissions potential cost of carbon maneuverable 2 issue, capture and sequestration Cooling water requirements
3.2.M. Economic Analysis
This section of the Report presents major assumptions, economic results, and quantification of risk factors associated with the resource technologies previously summarized. It tabulates results for each technology so that they may be directly compared with each other on a one-to-one basis. This is a simplified approach that is used to give clarity to resource comparisons and provide input to the next level of study – portfolio analysis. It develops the Delivered Cost of Electricity for the technologies in dollars per MWh over the life of the asset, and then makes adjustments based on the value added from an APS system perspective.
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3.2.M.i. Delivered Cost Analysis
The delivered cost analysis is a screening tool that has been commonly used in the utility industry for several decades. It estimates the lifetime levelized cost of a resource at an assumed capacity factor, and is most effectively used to compare similar duty cycle resources (e.g., base to base, peaking to peaking). In this analysis, APS has used its own capital structure and financing assumptions for the non-renewable resources. This is done for comparison purposes only to keep technologies on a level playing field, and does not intend to specify whether these plants would be self-built or acquired through purchase power agreements. Methods of procurement will be determined at the appropriate time in the actual resource procurement process.
The major components of the delivered cost analysis are capital cost, fuel cost, operation and maintenance (“O&M”) expenses, power plant fuel efficiency (heat rate), capacity factor, and transmission cost and losses. Carbon emission costs have not been monetized in the baseline results, but are addressed in the sensitivity analysis section. Delivered cost of energy efficiency options is included for comparison.
3.2.M.ii. Capital Cost
Capital costs, or the initial construction and financing costs, associated with constructing new resources come from a variety of sources. The cost of construction over the last few years has been extremely volatile, which makes it difficult to predict with certainty the cost of constructing new resources. The delivered cost analysis is performed using the most current information available to APS and assumes a 2008 in- service date for all technologies. To reflect the uncertainty, reasonable ranges of capital costs are provided. Where results are given as single points, they generally reflect mid- points of the ranges and are not intended to imply precision.
3.2.M.iii. Renewable Technologies
To estimate the delivered cost of renewable technologies, APS has relied extensively on information received from bidders in recent RFPs. In 2007, APS issued a renewable RFP which resulted in a total of 64 qualified offers. APS received offers for Biomass/Biogas (4), Geothermal (5), Wind (25), and Solar (30). In 2008, APS issued renewable RFPs in conjunction with a Joint Development Group (“JDG”) for solar thermal resources and independently for all types of renewable resources. While the results of these RFPs are not fully known because the evaluation processes are still on- going, APS can note that we have evaluated many more offers representing a variety of technologies and have gained a wealth of information and understanding of our renewable resource options. This knowledge base contributes greatly to the resource planning process and the creation of various resources strategies.
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In the present analysis, capital cost information is provided in a way that is consistent with APS’s recent experience. The baseline PPA information assumes that tax credits and production tax credits are available and factored into the pricing. Care has been taken not to expose any of our respondents’ confidential information, but to adequately portray information based on a composite of the more economically viable projects.99
3.2.M.iv. Conventional Gas/Coal Technologies
Conventional technologies refer to pulverized coal, combined cycle combustion turbines, and simple cycle combustion turbines. APS has estimated the capital cost of these technologies based on recent conceptual level design and cost estimates from qualified architect and engineering firms. Integrated gasification combined cycle costs have been estimated in this same way. These estimates incorporate all necessary environmental equipment to meet known NOx, mercury, and SO2 emission standards. Additionally, recognizing Arizona’s water situation, the cost of hybrid or dry cooling is reflected in both capital cost and operating parameters. APS also adds in owners’ costs and infrastructure costs, such as interconnection, gas pipeline, and water acquisition. These cost estimates are typically updated annually and were last updated in the summer of 2008.
3.2.M.v. Nuclear Power Plant
Since a new nuclear plant has not been built in the United States in over 20 years, the cost to construct one is difficult to estimate. To estimate the cost of a new nuclear plant, APS relied upon publicly available information and made appropriate adjustments. In its Combined Application for Certificate of Environmental Compatibility, South Carolina Electric & Gas Company provided a cost estimate for a two unit nuclear plant.100 Georgia Power has also proposed a new nuclear plant and has publicly released cost data.101 These projects are at the head of the first wave of COL applicants in their development since both projects have executed engineering, procurement, and construction (“EPC”) contracts. APS used an average of the above costs, and then increased the cost to reflect hybrid cooling which would likely be required in Arizona.
99 In addition to “supply and demand” pricing and commodity price impacts, there are physical factors that can contribute to wide cost ranges. Some of these factors for solar thermal, for example, are size of the plant, cooling type (wet/dry/hybrid), whether or not it has energy storage and how much, and solar multiple. 100 SCE&G V.C. Summer Nuclear Station, Units 2 and 3 COL Application, Part 1, 1.3.2.2. 101 Georgia Power, Application for Certification of Units 3 and 4 at Plant Vogtle, Docket No. 27800-U, filed 8/1/08.
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3.2.M.vi. Transmission
The delivered cost analysis also includes estimated transmission costs to integrate new conventional and renewable resources into the transmission grid. In general, the estimated transmission costs do not represent specific new power plant sites, but are meant to be indicative of the general level of transmission expense associated with a new resource type.
3.2.M.vii. Delivered Cost Results
Figure 47 provides the levelized cost results for a representative set of technology types broken into their cost components: capital cost (PPA), fuel, O&M, and transmission. This figure indicates that the levelized cost of some energy efficiency measures may be less than half the cost of the other technologies. It also indicates that, for coal and nuclear resources, capital is the largest component and suggests that the uncertainty in capital cost is an important risk to consider. Likewise, the combined cycle plant delivered cost is dominated by its fuel component, again suggesting that uncertainty in fuel prices may be its dominant risk.
Figure 48 provides economic information for additional technologies. This figure more appropriately shows capital cost ranges, ranges in total delivered cost estimates and the risk impact associated with key risk variables.
Figure 47 – Comparison of Average Delivered Cost
Make Up of Average Delivered Cost (Lifecycle Cost, 2008 In-Service Date)
200
180
160
140
120
Transmission 100 O&M ($/MWh) 80 Fuel PPA PPA PPA 60 Capital 40
20
0 y ) ) ) S r l S) S ar C CC ea ol cienc fi o f Gas CC Nucl (w/ C E (w/ CSP S Geotherma CC (w/o CC IGCC Coal IG Wind (Low CF Energy
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Note that the average delivered cost102 is a levelized cost over the estimated economic life of each technology and includes an estimate of the transmission costs that would be required to implement the particular resource. To illustrate the sensitivity of the costs to changes in assumptions, the average delivered cost has been “stressed” by estimating the impact of a change in a single input103 assumption to the average delivered cost. Costs will vary for specific projects and sites. Figure 48 – Economic Comparison of Resource Technologies
Impact of Single Capital Avg. Delivered Stress to Avg. Resource Cost Cost – Baseline Notes Cost ($/KW) ($/MWH) ($/MWH)
Energy N/A 10-50 N/A Wide variety of measures Efficiency
Solar Thermal 4,500- 155-190 Stress is no Investment + 55 Trough 7,500 (30-41% CF) Tax Credit (“ITC”)
Solar PV 2,900- 145-170 +50 Stress is no ITC (utility scale) 4,000 (27% CF)
Solar Thermal 3,500- 130-140 +50 Stress is no ITC Dish Stirling 4,000 (26% CF)
2,000- 120-145 Stress is no Production Wind + 15 2,500 (30-35% CF) Tax Credit (“PTC”)
4,000- Geothermal 120-130 + 15 Stress is no PTC 4,500
Biomass/ 1,500- 105-120 + 10 Stress is no PTC Biogas 3,500
102 The average delivered costs assume that the current level of federal tax credits continue (for each of the renewable resource technologies) and does not include any assumed costs for CO2. 103 These cost estimates are high-level cost estimates that are utilized for long-term resource planning studies.
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Impact of Single Capital Avg. Delivered Stress to Avg. Resource Cost Cost – Baseline Notes Cost ($/KW) ($/MWH) ($/MWH)
300-330 Stress is 30% higher Gas CT 750-1,050 + 30 (10% CF) Natural gas price
Gas Stress is 30% higher Combined 1,300-1,400 110-115 + 20 Natural gas price Cycle
Stress is 25% higher Nuclear 4,500-5,200 115-130 + 20 capital cost
Pulverized Stress is 25 $/ton CO2 2,500-3,000 90-100 + 35 Coal cost
Stress is 25 $/ton CO2 IGCC Coal 4,500-5,000 125-135 +35 cost
1. Capital cost is stated in 2008 dollars and includes Allowance for Funds Used During Construction (“AFUDC”). AFUDC is a non-cash credit to income meant to offset the real cost of debt and equity financing on the income statement. 2. Average delivered cost is stated in 2008 dollars. Costs are levelized over the estimated life of each asset. 3. Average delivered cost includes estimated transmission costs. 4. Conventional generation technologies are evaluated at 75 percent average annual capacity factor (except where noted). 5. The baseline average cost does not include costs related to risk factors such as natural gas prices, CO2 costs, capital costs, and loss of tax subsidies. 6. IGCC cost estimates do not include projections of costs related to CO2 capture and sequestration.
The figures provide a comparison of the different resource technologies, yet these comparisons do not tell the entire story. It can be misleading to simply focus on the average delivered cost of a renewable resource. Of equal importance to the average delivered cost is the value that the renewable resource brings to the overall system. For example, a wind resource with heavy spring season production and limited contribution to peak summer load will bring substantially less value than a solar trough plant with thermal energy storage, because a larger percentage of the energy production from solar thermal with energy storage occurs during heavy load periods of the summer. In order to address these limitations and put renewable resources on a more comparable basis, APS uses a “Value Adjusted Supply Analysis” approach. Similar approaches are also being used by others in the utility industry.
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3.2.N. Value Adjusted Supply Analysis
To put all renewable resources on a comparable basis with each other (e.g., solar vs. wind or solar vs. conventional-dispatchable), APS starts with the delivered average cost and makes several “Value Adjustments”. These adjustments are intended to capture differing values (i.e., avoided costs) that the technologies bring to APS’s system, and those results more closely replicate results from full portfolio level economic analysis. The adjustments are as follows:
• Capacity and energy equivalent basis – enables comparison of resources with different capacity factors. • Capacity value – contribution towards meeting APS peak load, supplemented with combustion turbine capacity. • Energy value – summer on peak delivery versus average around the clock delivery. The benefit for summer on peak is assumed to be 500 BTU/kWh times the forecast gas price. • System integration costs – currently only a wind integration cost is assessed ($3.95/MWh). In the future and at high penetration levels it may be appropriate to include an integration cost for solar (without storage).
The capacity value refers to the amount of resource capacity expected to be available to meet APS’s summer peak loads and is expressed as a percentage of the resource’s maximum summer rating. APS uses the industry standard ELCC methodology to assign capacity value to intermittent resources. This methodology recognizes that there is a fairly high correlation between weather patterns (sunshine/cloudiness) and APS’s hourly system loads. For example, on APS’s highest load days, it is likely that the sun will be shining, and a solar plant would be producing energy. In contrast, on cloudy summer days, APS’s load is lower, and solar generation is also lower.
3.2.N.i. Capacity Value and Select Renewable Resources
The capacity value of solar generation is affected by two main factors: 1) whether or not the plant has storage capability and how much; and 2) whether the plant employs technologies to track the sun’s path (“tracking”) or whether the position of the solar collection devices are fixed (“fixed position”). For example, a solar thermal power plant with six hours of storage is expected to be available to meet super-peak loads in the late afternoon and even the early evening. For this reason, a solar plant with six hours of storage would be assigned 100 percent capacity value. Alternatively, a solar plant without energy storage, but with tracking, is likely to produce energy for the highest load hours (4:00 p.m. to 5:00 p.m.) but energy production will drop off when the sun goes down.
APS still experiences relatively high loads past sunset when the solar plant is not generating. Therefore, a capacity value of 70 percent is assigned to tracking solar plants.
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A fixed position (or non-tracking) plant will typically deliver its highest output at or near noon. The output from such a plant drops off as the sun moves to the west. By 4:00 p.m. or 5:00 p.m., the fixed position solar plant may only be producing at about half of its maximum rated output. Non-tracking solar generation is assigned a capacity value of 50 percent. These values were determined as part of the APS Distributed Energy study, which will be filed with the ACC in February 2009.
These capacity values are generic in nature. They assume locations generally between Phoenix and Yuma. It should be noted that as more and more solar generation is employed on APS’s system, the capacity value will decrease – particularly for solar generation that does not employ storage technologies. With increasingly large amounts of solar generation, it may become increasingly difficult to follow customer loads and operate the rest of the units on APS’s generation system. Figure 49 – CSP Production and APS Load Profile
CSP w/6 Hr Storage Load Profile 10,000 120 9,000 100 8,000
7,000 80 6,000 5,000 60 4,000 40 3,000 Load MW (7/6/2015) 2,000 20 1,000
Production MW (100MW Capacity) 0 0
1 2 3 4 5 6 7 8 9 101112131415161718192021222324
APS has also conducted ELCC studies on wind generation. Seasonal wind patterns tend to blow more in the spring and winter and less in the summer. There is a somewhat favorable diurnal pattern for Arizona wind generation in which the wind blows more in the summer afternoons and evenings and less in the morning and mid-day. Overall, however, the summer afternoon level is reduced from what it is in the windy seasons. An actual example of how wind generation matched up with APS load on its peak load day in 2007 is shown below. At 4:00 pm, APS load was very near its highest, and the wind plant was producing less than 15 percent of its nameplate output. APS’s system peak occurred at 5:00 pm, and the wind plant was producing about 25 percent of its rated output. A 20 percent capacity value is generically assigned to wind projects. This value could vary significantly depending on location of the plant and availability of
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Figure 50 – New Mexico Wind Production and APS Load Profile
8,000 100 System Peak 90 7,000
APS System Load 80 6,000 70
5,000 60 4,000 50
Load (MW) Load 40 3,000 30 (MW) Output Aragonne 2,000 20 1,000 Wind Output 10
0 0 1 2 3 4 5 6 7 8 9 101112131415161718192021222324
Geothermal, biomass, and biogas resources generally produce energy evenly around the clock and across the seasons, so they are assumed to have 100 percent capacity value.
3.2.N.ii. Energy Value and Renewable Resources
The energy value of resource options is another important determinant of overall value to the APS system. Specifically, the time when an intermittent resource provides energy can significantly affect its value. Solar generation provides a disproportionate amount of power in summer afternoons when the value of power is higher; therefore, an adjustment is made to the delivered cost of that generation to reflect its high value to the system. The figure below shows that the summer on peak capacity factor for a solar plant (with storage) is more than double the capacity factor for a “generic” wind plant during the same summer time period. Detailed production simulations of APS’s system indicate that solar generation is more valuable than wind or around-the-clock generation by a differential amount of approximately 500 BTU/kWh times the natural gas price. So, if gas is assumed to be $8/mmBTU, solar generation would receive a $4/MWh credit in the value adjustment.
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Figure 51 – On Peak Capacity Factor of Wind and Solar Power Plants
3.2.N.iii. Capacity Value Adjustment
One of the keys to making meaningful comparisons of renewable resource options is to make them capacity and energy equivalent. In this case, the reference point is based on a 75 percent capacity factor or 0.1522 kWs dependable capacity per MWh of energy production. To the extent that a renewable resource is different than the reference point, it is incremented or decremented by simple cycle combustion turbine capacity costs to maintain the reference point. This, in effect, mimics how capacity costs would be factored into a full portfolio level resource expansion planning analysis.
3.2.N.iv. System Integration Costs
System integration costs may be imposed by operation of some non-dispatchable resources such as wind or large amounts of solar. Due to their intermittent and/or unpredictable nature, additional operating reserves may need to be carried on the rest of the system to effectively follow APS load and meet WECC reliability requirements. Based on the NAU Study, a system integration cost of $3.95/MWh is added to wind generation in the value adjustment.104
3.2.N.v. Value Adjusted Life Cycle Costs
Starting with the delivered cost analysis and making the adjustments described above results in the value-adjusted life cycle costs shown in Figure 52. Note that only
104 NORTHERN ARIZONA UNIVERSITY, ARIZONA PUBLIC SERVICE WIND INTEGRATION COST IMPACT STUDY, at 30.
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DRAFT very small adjustments have been made to geothermal and biomass/biogas since they have 100 percent capacity value, produce energy evenly around-the-clock and across seasons, and they are expected to operate reasonably close to the 75 percent reference capacity factor level. The largest adjustments are made to solar and wind. Solar life cycle costs are adjusted downward by 10 to 25 percent while wind life cycle costs are adjusted upward by 10 to 15 percent. This analysis indicates that it would be more economic for APS to pursue new solar resources than wind generation and that solar generation may be more competitive with combined cycle and nuclear generation than the price alone would indicate.
Figure 52 – Value Adjusted Life Cycle Costs in $/MWh
Value Adjusted Life Cycle Costs in $/MWh
Value Adjus ted 180 Delivered Cost Delivered Cost 160 Value Adjus ted
140
120
100
$/MWh 80
60
40
20
0 Gas CC Nuclear Biogas Biomass PV Fixed CSP 6 Hr Geothermal PV Conc. AZ Wind Stg.
3.2.N.vi. Resource Option Summary
After a detailed review of the above summarized information related to resource technology options commercially available to meet APS’s growing resource needs, the following observations are made:
1. Because of substantial availability and after adjusting for value, solar generation is currently cost competitive with other renewable resources and represents the most attractive renewable resource alternative for Arizona.
2. Distributed energy resources, while currently relatively costly, may present opportunities for both the APS system and APS customers.
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3. Natural gas resources are the lowest-cost resource from a capital cost perspective. For this reason, these resources tend to be economical solutions for meeting peaking needs where the resource utilization is relatively low.
4. Energy efficiency provides the lowest average delivered cost resource at this time.
5. Conventional coal generation has the lowest cost of the conventional resource options. However, risk factors associated with the development and operation of this resource precludes it from serious consideration for the foreseeable future.
6. APS has portrayed a relatively wide range of expected capital costs for future nuclear generation. Even within this wide range, there remains a degree of uncertainty concerning the cost of building new nuclear units. Despite these uncertainties, nuclear represents the most viable conventional energy option at the present time.
7. After adjusting for value, wind generation appears to have limited economic potential in Arizona.
8. At the current time, IGCC appears to be a fairly expensive option, both from an initial capital cost and an average delivered cost perspective. Additional monitoring of industry developments is warranted to determine if cost and technology improvements materialize for this technology which would allow coal to be utilized for future resource needs.
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3.3 RESOURCE PORTFOLIO ANALYSIS
For this resource planning analysis effort, the portfolio analysis was separated into two distinct portions. First, analysis was conducted on varying levels of energy efficiency savings. All of these cases were compared to a reference resource plan that included only new natural gas resources to meet future requirements and did not include any future energy efficiency activities. The second branch of analysis compared alternative supply-side resource portfolios against this same reference plan. This analysis approach was taken in order to allow for a clear and simple illustration of the economic and other benefits of energy efficiency investment. The results of both sets of analyses were used to inform the selection of the Resource Plan. Each of the analysis branches are described in the remaining text of this section. While this Resource Plan covers the period through 2025, because many economic analyses require a longer (30-year) study period, the “study period” should not be confused with the timeline covered by this Resource Plan.
Distributed Energy resources pose a unique challenge with respect to the resource planning process. Many technologies included in this category of resource in fact affect APS’s resource needs much like the implementation of energy efficiency technologies. As such, it is reasonable to include the analysis of those technologies using methods similar to those employed in evaluating energy efficiency, and varying levels of DE resource implementation would result in analyses echoing those used in evaluating energy efficiency – using specifics related to the attributes of DE resources. However, it is also reasonable to describe scenarios whereby DE resources could be employed as supply-side resources. Those scenarios may prove increasingly reasonable as APS continues to increase its understanding of the specific attributes related to DE resources.
For the analysis that follows, it was assumed that APS would achieve compliance with the RES DE targets in each year. The impacts of those resources are included in all of the following scenario analyses. In the future, it may become reasonable to include additional DE resources as either part of the load reduction analysis tied to energy efficiency or as part of the supply-side resources.
3.3.A. Analysis of Energy Efficiency Cases
In late 2005, APS commissioned ICF International to conduct a baseline study to investigate the status of energy-efficiency products and practices within the APS service territory. The objective was to establish the existing baseline efficiency levels in residential homes and commercial buildings within the APS service territory. The study employed various techniques including the review and analysis of existing information on customer baseline appliance/equipment efficiency levels, original market research targeting APS customers, and trade allies to obtain information on baseline efficiency levels and energy-efficiency measure costs and building energy simulations of a wide
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In order to facilitate the development and implementation of long-range energy efficiency plans for comparison to supply-side alternatives, APS commissioned ICF to conduct another study to investigate and quantify the potential impacts of APS-sponsored programs to promote energy efficiency technologies. The results of this study are published in a report entitled APS Energy Efficiency Market Potential Study by ICF International and dated August 24, 2007 (“Market Potential Study”).106
The Market Potential Study first identified a population of 223 candidate measures that are potentially applicable to the APS service area. Market research information and survey data obtained for the Baseline Study were relied on for this process. A qualitative screening process was used to determine a measure’s suitability for successful implementation. The qualitative screening was based on various criteria, such as energy impacts, market size, technology maturity, and cost and complexity of delivery. The top 149 highest-scored measures were carried forward for technical and economic analyses.
In the technical analysis, building energy simulation modeling and other techniques were used to quantify the impact of a measure on the customers’ demand and energy consumption. A measure’s estimated impacts, coupled with its existing saturation and applicability drawn from the Baseline Study, were then used to estimate its technical potential in the APS service territory. In the economic analysis phase, a measure’s life- cycle costs were compared with supply-side avoided costs to determine its economic feasibility based on the Total Resource Cost (“TRC”) test. The estimated quantity (kW or kWh) of a measure that passes the TRC test constitutes its economic potential. This economic potential can be summarized in the supply curve. A simplified way to represent the supply curve is to plot the economic potential of energy efficiency measures against their economic cost-effectiveness as measured by the TRC benefit/cost (B/C) ratio. This depiction provides a readily available look at how much energy savings is available for a given level of cost-effectiveness. The following two figures show the supply curves in MWs and GWhs for all energy efficiency measures considered in the technical and economic analyses.
105 Available at http://www.aps.com/_files/various/ResourceAlt/APS_Baseline_Report_03-09-07.pdf. 106 Available at http://www.aps.com/_files/various/ResourceAlt/ICF_APS_Market_Potential_Report_08- 24-07.pdf.
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Figure 53 – Energy Efficiency Supply Curve (in MWs of Peak Capacity Reduction)
5
4
3
2 EE Measures are cost- 1/TRC Benefit/Cost Ratio effective up to the point that 1/TRC =1.0 1
0 0 200 400 600 800 1000 1200 1400 1600 1800 Energy Efficiency Potential in MW
Figure 54 – Energy Efficiency Supply Curve (in GWhs of Energy Reduction)
5
4
3
2 EE Measures are cost- 1/TRC Benefit/Cost Ratio effective up to the point that 1/TRC =1.0 1
0 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 Energy Efficiency Potential in GWh
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The estimated economic potential of energy efficiency measures, documented in the Market Potential Study, served as a basis for the development of four long-term energy efficiency scenarios for the resource planning analysis process. Naturally, only measures having TRC B/C ratios greater than or equal to 1.0 were included in the scenarios. An energy efficiency scenario as defined herein is the market potential of energy savings at an assumed value of program acceptance factor (“PAF”) and a given level of rebate incentive. These are the program design parameters that drive the achievable level of program market penetration. For simplicity and ease of reference, an energy efficiency program’s rebate incentive is expressed as a percentage of the incremental cost of purchasing a higher-efficiency appliance or other type of equipment (energy efficiency measure) as compared to a standard-efficiency unit (base case). For instance, a 50 percent incremental incentive means the incentive paid to program participants is equal to 50 percent of the incremental cost between a high-efficiency unit and a standard-efficiency unit.
In order to project the market penetration of an energy efficiency measure, the payback acceptance curve (“PAC”) was used. The PAC shows the relationship between an energy efficiency program’s market share (the percentage of customers willing to participate) and its expected payback period. The payback period is determined by the participant cost test. Two payback acceptance curves were used in the energy efficiency scenario development process:
Residential Market Share = 1.2154e-0.2895P Non-Residential Market Share = 1.0658e-0.4524P
* Where P is payback period in years.
The residential and non-residential PACs are graphically illustrated in the following figure.
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Figure 55 – Payback Acceptance Curves
DSM Payback Acceptance Curves 100%
90%
k 80%
70% Residential Non-Residential 60%
50%
40%
30%
20% Percent of Customers Accepting PercentPaybac of Customers
10%
0% 0123456789101112131415 Paybacks (Years)
There are two major types of costs associated with an energy efficiency program: rebate or incentive payments from APS to program participants; and program administration costs to cover the costs of training, marketing, implementing, customer education, and measurement, evaluation, and research (“MER”). For long-term planning purposes, the program administration costs are assumed to equal 30 percent of rebate incentive payments anticipated for a certain level of program market penetration.
The first energy efficiency scenario considered is based upon realizing about 40 percent of the total market potential achievable with a 50 percent incremental incentive strategy and a PAF of 0.6. For the 2008 to 2025 timeframe, this scenario has an annual average spending level of $19.5 million per year. The scenario is expected to result in year 2025 capacity and energy savings of 277 MWs and 1,546 GWhs, respectively.107 The load factor of this scenario is approximately 63.7 percent, which is much higher than the overall system load factor of 48.7 percent. Scenario 1 lowers the system load factor to 48.7 percent, which is expected because of the higher energy intensity embedded in the energy efficiency savings.
The second scenario is based on achieving full market potential with a 50 percent incremental incentive strategy and a PAF of 0.6. For the 2008-2025 timeframe, this scenario has an annual average spending level of $78 million. With the inclusion of system losses, the year 2025 capacity and energy savings resulting from Scenario 2 are 642 MWs and 3,223 GWhs, respectively. The load factor of this scenario is approximately 57.3 percent, which lowers the reference case system load factor from 49.1 to 48.6 percent.
107 This is after including the additional benefits of reductions in system capacity and energy losses.
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Scenario 3 is more aggressive than both Scenarios 1 and 2 and is based on achieving full market potential with a 75 percent incremental incentive strategy and a PAF of 0.6. For the 2008 to 2025 timeframe, this scenario has an average annual spending level of about $175 million. With the inclusion of savings in system losses, the year 2025 capacity and energy savings resulting from Scenario 3 are 949 MWs and 4,705 GWhs, respectively. The load factor of this scenario is approximately 56.6 percent which has the effect of lowering the reference case system load factor from 49.1 to 48.4 percent.
The fourth scenario is the most aggressive as it attempts to achieve full energy efficiency market potential with a 100 percent incremental incentive strategy and a PAF of 0.6. For the 2008 to 2025 timeframe, this scenario projects an average annual spending level of close to $320 million. With the inclusion of system losses, the year 2025 capacity and energy savings resulting from Scenario 4 are 1,352 MW and 6,627 GWhs, respectively. The load factor of this scenario is approximately 56.0 percent, which lowers the reference case system load factor from 49.1 to 48.1 percent.
The next figure provides a summary of each scenario. Each of these energy efficiency scenarios was simulated through the full production cost modeling process, and a revenue requirements analysis was prepared for each scenario. Other results from the analysis include identification of emission reductions, natural gas consumption and water consumption for each scenario.
Figure 56 – Scenario Description (2008 – 2025)
Scenario 1 Scenario 2 Scenario 3 Scenario 4
Strategy Incentive (% of Incremental) 50% 50% 75% 100% PAF 0.6 0.6 0.6 0.6 Spending in $Million 2008-2025 Total 482 1,824 4,062 7,461 Annual Average 1 $19.5 $78 $175 $320 System Impacts in Year 2025 Capacity Reduction MW 277 642 949 1,352 Energy Reduction GWH 1,546 3,223 4,705 6,627 Load Factor 63.7% 57.3% 56.6% 56.0% 2008-2025 Total Reductions CO2 Emission, tons (106) 9.7 18.8 26.3 37.6 Water Usage, acre-feet (000) 18 34 45 67 Gas Burn, BCF 126 252 351 498 Note: 1. Represented in annual real dollars (2008$) beginning in year 2011, which are escalated/compounded to present total spending dollars.
The default resource plan, which relies on gas-fired generation and renewable resources (distributed and non-distributed) only up to compliance with the RES rules,
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DRAFT was developed for the purpose of evaluating the energy efficiency portfolios. This renewable generation is the same in all of the energy efficiency scenarios. Four levels of energy efficiency were evaluated, ranging from 277 MWs to 1,352 MWs by the year 2025. Natural gas resources (combined cycles and combustion turbines) were added as needed to meet the balance of projected load requirements. Resource addition mixes for each of the scenarios are summarized in Figure 57. In Scenario 4 over 1,500 MWs of conventional resources are deferred by 2025 through achieving 1,350 MWs of peak demand savings from energy efficiency. This difference is due to the additional benefit that energy efficiency also would allow APS to save the 15 percent reserve requirement applied to conventional resources.
Figure 57 – Summary of Resource Additions for Energy Efficiency Scenarios
Cumulative Resource Additions by 2025 (in MWs)
Plan Description EE Nuclear Gas-CT Gas-CC Mkt Renew. Total All Gas BAU w/ DE 0 0 4,188 1,056 470 1,268 6,982 EE Sce 1 277 0 3,848 1,056 491 1,268 6,940 EE Sce 2 642 0 3,508 1,056 411 1,268 6,885 EE Sce 3 949 0 3,660 528 434 1,268 6,839 EE Sce 4 1,352 0 3,168 528 463 1,268 6,779
Plan Comparisons EE Sce 1 O/(U) BAU w DE 277 0 (340) 0 21 0 (42) EE Sce 2 O/(U) BAU w DE 642 0 (680) 0 (59) 0 (97) EE Sce 3 O/(U) BAU w DE 949 0 (528) (528) (36) 0 (143) EE Sce 4 O/(U) BAU w DE 1,352 0 (1,020) (528) (7) 0 (203)
Long-term economic analysis was performed on the four scenarios based on a 30- year planning horizon (2008 − 2037). The long-term look fully accounts for the effects of energy efficiency programs on many aspects of system resource mix such as supply side resource diversity over time and end effects of capacity deferral due to system load reductions. Figure 58 summarizes the results of the revenue requirements analysis. Costs of the energy efficiency programs include the incentive costs paid by APS to the participating customers as well as program administration costs as discussed above. Benefits of the energy efficiency programs are avoided capacity (generation and transmission) and avoided energy costs (fuel, O&M, and purchased power).
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Figure 58 – Energy Efficiency Scenarios - Cumulative Present Worth (“CPW”) of Revenue Requirements
CPW of Revenue Requirements ($B, 2008-2037) Gas Imputed EE+ Emis Plan Description Gen Trans. PP Xport Debt DE Cost Total All Gas BAU w/ DE 35.7 1.3 6.2 1.1 0.2 1.0 (0.2) 45.344 EE Sce 1 34.6 1.3 6.1 1.0 0.2 1.2 (0.2) 44.317 EE Sce 2 33.2 1.3 6.1 1.0 0.2 2.0 (0.2) 43.660 EE Sce 3 32.1 1.2 6.0 0.9 0.2 3.4 (0.2) 43.722 EE Sce 4 30.6 1.2 6.0 0.8 0.2 5.4 (0.2) 44.100
Plan Comparisons EE Sce 1 O/(U) BAU w DE (1.2) (0.0) (0.1) (0.1) 0.0 0.3 (0.0) (1.027) EE Sce 2 O/(U) BAU w DE (2.5) (0.1) (0.1) (0.1) 0.0 1.1 (0.0) (1.684) EE Sce 3 O/(U) BAU w DE (3.6) (0.1) (0.2) (0.2) 0.0 2.4 (0.0) (1.622) EE Sce 4 O/(U) BAU w DE (5.1) (0.2) (0.2) (0.2) 0.0 4.5 (0.0) (1.244)
The revenue requirements analysis indicates that Scenario 2 has nearly $1.7 billion of cost savings versus the reference plan. While Scenarios 3 and 4 still show economic benefits, they are less than those of Scenario 2.
3.3.A.i. Natural Gas Consumption
As indicated below, in the reference case, APS’s natural gas consumption would more than double from current levels by 2025. Implementation of Scenario 2 (642 MWs by 2025) would reduce gas burn by 24 BCF (15 percent) in 2025, while Scenario 4 would reduce it by 47 BCF (30 percent). The figure below clearly demonstrates the beneficial impact of energy efficiency programs in that they will reduce natural gas consumption and yield a significant risk reduction benefit.
Figure 59 – Natural Gas Consumption for Energy Efficiency Scenarios
Annual Natural Gas Burn (BCF)
180
160 EE Sce 1 EE Sce 2
EE Sce 3 EE Sce 4 140 BAU w DE
120 (BCF) 100
80
60
40 2009 2011 2013 2015 2017 2019 2021 2023 2025
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3.3.A.ii. CO2 Emissions
In the default resource plan, APS’s CO2 emissions would increase by about 32 percent by 2025 from current levels. Implementation of Scenario 2 would reduce 2025 emissions by 1.7 million tons per year (7 percent), while implementation of Scenario 4 would reduce 2025 emissions by 3.3 million tons (14 percent) below default resource plan levels. Once again, the figure below provides a clear indication of the beneficial impact of energy efficiency programs. With looming climate change legislation, energy efficiency can provide a significant reduction in CO2 emissions and the related cost risk to APS’s customers.
Figure 60 – CO2 Emissions for Energy Efficiency Scenarios
Annual CO2 Emissions (Short tons)
26,000,000
25,000,000
EE Sce 1 24,000,000 EE Sce 2 EE Sce 3 23,000,000 EE Sce 4 BAU w DE 22,000,000
21,000,000 (Tons) 20,000,000
19,000,000
18,000,000
17,000,000
16,000,000 2009 2011 2013 2015 2017 2019 2021 2023 2025
3.3.A.iii. Capital Expenditures
Cumulative capital expenditures for new generation and transmission would exceed $8 billion by 2025 in the default resource plan (excluding renewable generation). Implementation of Scenario 2 would result in the deferral of 680 MWs of simple cycle combustion turbines, reducing generation and associated transmission capital expenditures by $1.2 billion (14 percent). Implementation of Scenario 4 would allow deferral of 528 MWs of CC capacity, 1,020 MWs of CT generation capacity, and associated transmission. This would reduce capital expenditures by $2.5 billion (29 percent) by 2025.
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Figure 61 – Cumulative Capital Expenditures for Energy Efficiency Scenarios
Cumulative Capital Expenditures 10,000.0
9,000.0
EE Sce 1 EE Sce 2 8,000.0 EE Sce 3 EE Sce 4 7,000.0 BAU w DE
6,000.0
5,000.0
($Millions) 4,000.0
3,000.0
2,000.0
1,000.0
0.0 2009 2011 2013 2015 2017 2019 2021 2023 2025
3.3.A.iv. System Cost
APS’s average system cost includes carrying costs of existing and new generation capital expenditures, fuel, purchased power, carrying costs of new transmission and energy efficiency costs. In the default resource plan, APS’s average system cost in 2025 would be 84 percent higher than current costs. As implementation of energy efficiency measures reduces energy use, fixed costs are spread over fewer energy sales, and the system average cost is higher. Implementation of Scenario 4 would increase average system costs by nine percent above the 2025 default resource plan, while Scenario 2 would increase average system costs by two percent. This indicates that though customers participating in the energy efficiency programs would reduce their electric bills, non-participating customers could face higher electric bills. The following figure shows that this effect is relatively slight for Scenarios 1 and 2, while Scenarios 3 and 4 have a more pronounced impact.
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Figure 62 – Average System Cost for Energy Efficiency Scenarios
Average System Cost ($/MWH)
135
125 EE Sce 1 EE Sce 2 EE Sce 3 115 EE Sce 4 BAU w DE
105
($/MWH) 95
85
75
65 2009 2011 2013 2015 2017 2019 2021 2023 2025
3.3.A.v. Summary
The analysis of the energy efficiency scenarios clearly shows the beneficial impacts of implementing energy efficiency programs. Energy efficiency is the only resource option available at this time that can provide economic benefits as compared to conventional or renewable resource options while also providing environmental benefits and other risk reduction benefits. APS’s recommended Resource Plan includes a targeted amount of energy efficiency that is based upon Scenario 2 with a more gradual ramp-up of incentive spending from current levels.
3.3.B. Analysis of Supply-Side Resource Planning Cases
By definition, a resource plan is a careful balance between a wide range of drivers, some of which are tied to individual resource technologies and some of which are the result of the blend of resource technologies selected. The drivers are both quantitative and qualitative in nature, and broadly include portfolio economics, risk trade-offs, and issues related to energy and public policy. A portfolio level analysis is required to demonstrate possible outcomes as they relate to the selection of specific supply-side resources. The previous sections provided a comparison and summary of different technologies that are available to satisfy future resource needs, important assumptions necessary for the resource planning analysis process and the value of energy efficiency in any future resource plan. This section will demonstrate the results of incorporating supply-side technology resources into APS’s resource portfolio under a range of
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This step involves both quantitative and qualitative analyses of different resource alternatives, including conventional generation, renewable resources, and energy efficiency (demand-side measures and distributed generation). Resource options or “scenarios” are brought forward for portfolio-level analysis in which alternative resource expansion plans are developed and analyzed through detailed production cost simulations. These detailed simulations combine the new resource alternatives with the existing resource portfolio and allow for projections of future costs (as well as other key parameters like emissions, water usage, and fuel consumption). The cost analysis provides an estimate of the future total system cost of each resource alternative and includes costs for fuel, purchased power, capital and transmission for new power plants, energy efficiency program costs, natural gas transportation, and emissions allowance costs for regulated emissions, such as SO2.
To elucidate the economic effects of different resource technology options, it is helpful to build a descriptive range of plausible scenarios. Each scenario can then be used to demonstrate the results of specific resource related choices, such as the use of a specific resource type and/or the timing of resource deployment. This approach allows for a simplified comparison of the available resource options by illustrating the effects of specific choices against the backdrop of a resource plan that could be used to meet APS’s future resource needs. In addition, this method is helpful in exploring sensitivities related to assumptions used within the analysis of the selected scenarios. For example, sensitivity analysis can be used to explore the effects of a change in the forecast price of natural gas or to explore impacts of carbon pricing resulting from GHG regulation.
Resource portfolio analysis requires the selection of discrete scenarios; however, in reality the alternatives described in the scenarios used in this evaluation are not mutually exclusive. The sizing of specific resources, timing of resource deployment, and any range of variables related to risk trade-offs can be adjusted to create a veritable continuum of resource portfolios. The scenarios chosen for presentation in this Report were selected based upon the learnings obtained from many other resource planning studies. Each scenario thoughtfully demonstrates the effects of balancing future resource needs with the drivers impacting resource selection.
3.3.B.i. Common Elements
It is important to note that each of the scenarios shares several common elements. Most notably, all of the resource portfolio scenarios are designed to satisfy APS’s resource needs through 2025. In fact, the scenarios all share the same strategy in the years prior to 2013, in part because APS is generally well situated to satisfy its needs through that year, and in part because several of the resource technology alternatives
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1. Renewable energy resources are added to meet no less than the RES requirement of 15 percent by 2025. Specifically, as described within these scenarios, the resource additions will result in the addition of nearly 1,300 MWs of utility-scale wind, solar, and geothermal generation above and beyond those already in service today.
2. Distributed resources will be added to meet no less than 30 percent of the RES requirement by 2025.
3.3.B.ii. The Role of Natural Gas Generation
As noted in the previous section, natural gas generation plays a critical role in the resource planning analysis. Low capital costs, short lead-times, and relatively low environmental impacts have led natural gas generation to become the reference resource type in the resource planning process.
In this resource planning analysis, natural gas generation plays two fundamental roles. First, as noted above and described below in more detail, a resource planning strategy that relies on natural gas generation to meet all of APS’s resource needs (beyond the renewable resources required to meet RES targets) serves as the reference point against which all other planning options (scenarios) are evaluated. Second, APS believes natural gas will continue to play an important role in helping to meet future resource needs. Unless described otherwise, the portfolio scenarios presented in this section include the addition of at least some natural gas generation. In many instances, the additional natural gas capacity described in the resource planning scenarios will replace expiring contracts for market resources.
Absent a well-vetted, well-supported, long-term resource plan driven by a clear vision, a regional energy policy, and appropriate regulatory support measures, the industry will continue to pursue those resources that manifest the lowest investment. In APS’s case, natural gas generation is the least-cost resource. While not necessarily satisfying specific objectives for portfolio diversification and the associated benefits, a resource plan that relies on meeting all foreseeable resource needs with natural gas generation serves as a reasonable reference against which all other alternatives are compared.
3.3.B.iii. Sensitivity Analysis
In presenting an evaluation of specific resource alternative scenarios, it is critical also to understand key risk components related to any one option. While there are a great number of variables in the economic analysis of the presented supply-side scenarios, a
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The risk analysis process involves both quantitative and qualitative assessments of future potential risks, such as changes in fuel prices or future environmental regulations (the current issues surrounding climate change are a good example of this). Because many risks cannot be easily quantified, the risk assessment process inevitably requires a great deal of judgment.
a. Cost of Carbon Emissions
Although perhaps controversial, the baseline economic projections do not include cost projections related to potential future GHG emissions regulations. Several parties in the Resource Alternative Report process suggested that APS should explicitly include a cost related to CO2 emissions (GHG cost) in the resource planning analysis process. Although APS has decided not to include this factor in the baseline economic analysis at this time due to the uncertain timing and outcome of climate policy, APS recognizes that it is an important factor that must be considered in the decision-making process because of the increasing likelihood of climate change legislation at either the federal or regional level. Two alternative costs for carbon have specifically been included in the sensitivity analysis of each resource scenario, $25 per short ton and $50 per short ton. For both of these sensitivity cases, the carbon cost is assessed beginning in 2012. Additionally, the carbon cost is assumed to escalate over time at a rate of 3 percent per year.
b. Fuel Costs
More than any other resource technology option, the cost of natural gas generation is highly dependent on the cost of fuel. Since natural gas generation has the potential to play a significant role in many of the resource planning alternatives, a discrete sensitivity for an increase in cost, at 30 percent above that presently forecast, is presented for each of the scenarios.
c. Technology Costs
Each of the technology alternatives is saddled with the prospect of changing development costs. In some instances, the risk (or opportunity) of this change is increased above those forces that generally apply to resource development at large. For example, there are those who speculate that the costs of developing solar resources (PV or CSP) will decline or, at a minimum, increase at a rate slower than the rate of increase for non-solar resources. While there remains uncertainty surrounding the assumptions that would drive the cost of solar development down, it is a reasonable observation that large-scale solar development is in its infancy and that the ultimate deployment of large- scale solar could indeed drive costs down. A sensitivity is included that describes the
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Similarly, the current and forecast cost to develop renewable resources is hinged on specific tax treatments. While there are a broad range of favorable tax related treatments applied to renewable generation, two are specifically identified for sensitivity analysis in this section because of the magnitude of their impact on the final cost of developing the affected resources. The production tax credit (“PTC”) applies to both wind and geothermal generation and is currently set to expire at year-end 2009 for wind and year-end 2010 for geothermal. The investment tax credit (“ITC”) applies to all types of solar generation and is currently set to expire at year-end 2016. Since both the PTC and ITC are set to expire well within the timeframe covered by the Resource Plan, a sensitivity analysis is included whereby neither of the tax credits is further extended beyond the scheduled expiration date. For the PTC, this applies to all wind projects deployed after 2009 and for geothermal projects deployed after 2010. For the ITC, this applies to solar projects deployed after 2016.
Increased interest and growing commitments for expansion of the national nuclear generation fleet are helping to better forecast the cost of construction; however, until such time as contractual commitments are firmly established, the ultimate costs will not be known. Given the long timeline, relative uncertainty, and magnitude of commitment necessary for the inclusion of nuclear generation in the resource portfolio, it is necessary to consider the prospect of development costs substantially higher than established in the baseline assumptions. The analysis that follows includes a sensitivity analysis that projects nuclear generation costs 25 percent higher than currently forecast.
d. Changes in APS’s Forecast Load
Some of the issues surrounding the load forecast were described in a previous section of this Report. It is difficult to predict both the severity and length of the current economic downturn. Likewise, it is also difficult to predict the timing and strength of the recovery following the current business cycle. For this sensitivity analysis, APS developed both high and low load growth sensitivities around the current expected load growth case. The impact of these two sensitivities were qualitatively assessed for how they would impact APS’s recommended Resource Plan and how flexible the Resource Plan is for accommodating changes in the load forecast.
108 The inflationary factor of three percent is applied to all conventional resource costs in the baseline analysis.
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e. Summary of Analysis Sensitivities
The follow discrete sensitivities were applied to each of the resource planning scenarios:
• Two sensitivities are provided reflecting discrete carbon costs: o carbon at $25/ton; and o carbon at $50/ton. • Natural gas prices are 30 percent higher than the baseline forecast. • The cost of solar will decline (or alternatively increase at a slower rate) relative to other generation technology options. Solar technologies are modeled to increase at 1.5 percent annually, while all other technologies increase in cost with the rate of inflation (assumed to be 3.0 percent annually). • Current favorable tax treatments for renewables are not extended beyond their current effective expiration dates: o the PTC is not available for wind added after 2009 and geothermal generation added after 2012; and o the ITC is not available for solar generation added after 2016. • The cost for developing nuclear generation exceeds that currently forecasted by 25 percent.
3.3.B.iv. Resource Portfolio Alternatives Scenarios
The following resource portfolio analysis and presented scenarios are based on APS’s long history of experience in resource planning, stakeholder input from the resource planning workshops, and the most current market and resource information available. We present three scenarios that are designed to explore the implications of selecting only one resource technology alternative for purposes of meeting APS’s future resource needs. Those three scenarios describe “all” natural gas, nuclear, and solar options. Neither the nuclear nor the solar scenarios are presented to impart the possibility of relying on only one resource technology option as a desirable outcome from this resource planning process. Rather, the nuclear and solar scenarios are designed to highlight the economic differences between the two resource technology alternatives. Specifically, the scenarios were designed to result in approximately the same total energy contribution and as a result, approximately the same total impact to APS’s carbon profile.
In addition, four scenarios are presented to describe the range of balanced resource portfolio options that are reasonably available to meet APS’s resource needs. As was previously noted, these four scenarios simply mark four points along a continuum of potential outcomes. Each of the four scenarios highlights the growing role APS envisions for solar resources in the Company’s resource portfolio. The specific timing for solar resource additions has been selected to maximize the benefit for the ITC before its planned expiration in 2016. The detailed information related to all of the scenarios,
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a. Reference Scenario: All Natural Gas
The all natural gas (“All Gas”) scenario satisfies all incremental energy needs (beyond that met through the implementation of renewable resources to comply with the RES rules) through 2025 with the addition of natural gas generation resources. The All Gas reference scenario is included to demonstrate the most likely resource outcome absent specific energy policy and appropriate regulatory support measures. Under this scenario, 528 MWs of combined cycle generation are added in both 2020 and 2021. This scenario represents both the highest prospective carbon portfolio and creates the greatest future risk related to natural gas price fluctuation.
All Gas Reference - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 0 0 0 4,230 1,056 5,286 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
b. Nuclear Scenario
The nuclear scenario (“Nuclear”) satisfies a portion of the incremental energy needs through the addition of 315 MWs of nuclear generation in both 2022 and 2023. The inclusion of this scenario is designed to provide a clear comparison of the cost of nuclear generation against the costs of natural gas generation and against solar generation. In this scenario, the addition of nuclear diminishes the need for intermediate natural gas generation and some natural gas peaking capacity relative to the All Gas scenario. It includes the addition of 528 MWs of combined cycle generation in 2020. Relative to the All Gas reference scenario, this scenario represents a moderate reduction in the projected carbon profile of the resource mix.
Nuclear - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 630 0 0 4,136 528 5,294 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
c. Solar Scenario
The solar scenario (“Solar”) is designed to satisfy a portion of the incremental energy needs through the addition of solar generation while aiming to achieve a moderate reduction in the carbon profile relative to the All Gas reference. The inclusion of this
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Solar - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 0 1,400 0 3,854 0 5,254 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
A second solar scenario (“Solar 2”) was evaluated to help explore the implications of using a blend of CSP and PV in meeting the objectives of the Solar scenario. While that scenario is not included in this section, insights from that scenario are included in the scenarios that follow. Specifically, for the Solar 2 scenario, the 1,400 MWs of CSP from the Solar scenario were replaced with 700 MWs of CSP and 1,148 MWs of PV, which was aimed to achieve the same total energy contribution. Details of the Solar 2 scenario are included in Appendix 2.
Review of Solar 2 highlights that in many respects solar resources, regardless of technology, produce many of the same system benefits. For example, after all resources are operational, both Solar and Solar 2 result in the same gas burn and carbon profile for the resulting resource portfolio. Likewise, once installed, both Solar and Solar 2 demonstrate very similar average annual system costs. For purposes of this analysis, CSP is assumed to include six hours of thermal storage and, as a result, more PV capacity is required to replace the energy “removed” when PV has been modeled to replace CSP.109 While the two scenarios represent different total capacities, the capital costs for each are similar, where the total capital expense through 2025 for the Solar scenario is approximately $22.6 billion and the total capital expense through 2025 for Solar 2 is approximately $21.7 billion. APS believes that it is appropriate to use a balance of both CSP and PV solar resources in the resource planning scenarios described below. The actual mix of solar resources will be determined through future procurement activities.
d. Scenario 1: 500 MW Nuclear and 290 MW Solar
The 500 MW nuclear and 290 MW solar scenario (“Scenario 1”) is designed to satisfy incremental energy needs through the addition of both nuclear and solar generation. While neither the addition of the nuclear resource nor the addition of the
109 CSP with thermal storage will produce more energy per unit capacity than solar resources without storage.
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DRAFT solar resource increase APS’s carbon profile, the cumulative composition of resource technologies in this scenario results in only a moderate reduction of carbon emissions relative to the All Gas reference scenario. The scenario includes the addition of 100 MWs in 2014 and 2015 and 90 MWs in 2016 of CSP; and 250 MWs of nuclear in 2022 and 2023. The scenario reduces the need for both natural gas intermediate and peaking capacity relative to the All Gas reference scenario.
Scenario 1 - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 500 290 0 3,948 528 5,266 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
e. Scenario 2: 650 MW Nuclear and 800 MW Solar
The 650 MW nuclear and 800 MW solar scenario (“Scenario 2”) is designed to satisfy incremental energy needs through the addition of both nuclear and solar generation while aiming to achieve a more moderate increase in carbon emissions relative to 2008 levels (note that all of these cases are prior to incorporating the beneficial impacts of incremental energy efficiency investments). The scenario describes the addition of 100 MWs of CSP in 2014, 2015, and 2016; 100 MWs of PV in 2014 to 2017 and 92 MWs in 2018; and 325 MWs of nuclear in 2022 and 2023. This scenario reduces the need for both natural gas intermediate and peaking capacity relative to the All Gas scenario.
Scenario 2 - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 650 300 492 3,572 528 5,542 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
f. Scenario 3: 800 MW Nuclear and 400 MW Solar
The 800 MW nuclear and 400 MW solar scenario (“Scenario 3”) is designed to satisfy incremental energy needs through the addition of both nuclear and solar generation, while aiming to achieve a more moderate increase in carbon emissions relative to 2008 levels. Scenario 3 contrasts with Scenario 2 in that it attempts to demonstrate the results of the increased role of nuclear generation. The scenario includes the addition of 100 MWs in 2014 and 50 MWs in 2015 of CSP; 100 MWs of PV in 2014 and 2015 and 46 MWs in 2016; and 400 MWs of nuclear in 2022 and 2023. The scenario reduces the need for both natural gas intermediate and peaking capacity relative to the All Gas scenario.
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Scenario 3 - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 800 150 246 3,666 528 5,390 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
g. Scenario 4: 800 MW Nuclear and 2,000 MW Solar
The 800 MW nuclear and 2,000 MW solar scenario (“Scenario 4”) is designed to satisfy incremental energy needs through the addition of both nuclear and solar generation while aiming to decrease carbon emissions to below current levels. The primary impact of implementing this scenario is eliminating the need for intermediate gas generation and dramatically reducing the need to replace/increase natural gas peaking capacity. Scenario 4 represents a plausible option for reducing carbon emissions in conformance with Arizona’s commitment to the WCI (after the impacts of energy efficiency are also added to this scenario). The scenario includes the addition of 100 MWs of CSP in 2014 to 2020 and 50 MWs in 2021; 100 MWs of PV in 2014 and 2015, 200 MWs in 2016 to 2020, and 30 MWs in 2021; and 400 MWs of nuclear in 2022 and 2023.
Scenario 4 - Resource Additions Thru 2025 (in MW) Nuclear Solar Solar Gas Peaking Gas CC Total (CSP) (PV) Additions1 800 750 1,230 3,102 0 5,882 Note: 1. Additions required to meet RES compliance (approximately 1,300 MWs) are included in all scenarios (but not explicitly portrayed in this summary table).
h. Summary of Energy Mix from all Resource Alternative Scenarios
One way to summarize the scenarios is to illustrate the resulting energy mix of the portfolio in 2025. The following figure provides the energy mix for 2025. Under the All Gas reference case, natural gas comprises approximately 40 percent of the system energy mix in 2025. The scenarios represent a progression of increasing amounts of other resource additions (i.e., not natural gas resources) and the natural gas contribution decreases with each scenario. In Scenario 4, natural gas represents just 19 percent of the overall system energy mix by 2025.
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Figure 63 – Summary of Scenarios – Relative Energy Mix
Energy Mix (Year 2025) 100% Renew. 14% 16% 90% 19% 16% 25% 80% 40% 26% 70% Gas 30% 26% 19% 60%
50% 26% 26% 24% 27% 40% Coal 30% 28% 20% 19% 29% 32% 32% 27% 10% Nuclear
0% All Gas Scenario 1 Scenario 2 Scenario 3 Scenario 4 reference
Note: Renewable energy contribution illustrated in this figure is not directly comparable to RES targets as this chart is based upon total system energy requirements (rather than as a percent of retail sales as is the case with the RES targets).
3.3.B.v. Summary of Results
Portfolio-level simulations provide a means to measure the impact of resource decisions upon the overall resource portfolio. Each of the previously described resource scenarios was simulated through APS’s production cost model to assess the economics and the key risk parameters (capital costs, natural gas consumption, and CO2 and other emissions). The following sections describe the results of that analysis.
Beginning the overview of the portfolio-level analysis with a review of the characteristics differentiating between nuclear and solar resources will prove helpful when reviewing the results of the four prospective resource scenarios. While both the Nuclear and Solar scenarios were designed to achieve the same ultimate (year 2025) energy contribution, it is valuable to note that manifesting the benefit of a nuclear resource with respect to both natural gas burn and carbon emissions will take some years. The incremental nature of solar resources allows for their progressive addition over a longer and earlier window of the planning horizon. Therefore, while the long-term benefits of both of these carbon-emissions free resources is very similar, relying on nuclear alone will increase near-term risk resulting from reliance on natural gas and a near-term increase in carbon emissions.
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Figure 64 – Characterizing Nuclear and Solar Scenarios by Gas Burn and CO2 Emissions
Annual Natural Gas Burn (BCF) Annual CO2 Emissions (Short tons)
25,000,000
All Gas 160 All Gas 24,000,000
Nuclear Nuclear 23,000,000 140 Solar Solar
22,000,000 120 (BCF) (Tons) 21,000,000
100
20,000,000
80 19,000,000
60 18,000,000 2009 2011 2013 2015 2017 2019 2021 2023 2025 2009 2011 2013 2015 2017 2019 2021 2023 2025
Perhaps the most pronounced long-term distinctions between the Nuclear and Solar scenarios are those surrounding cost. The table below summarizes both cumulative and annual average system costs for both of the scenarios.
Figure 65 – Summary of Costs for Nuclear and Solar Scenarios CPW of Revenue Requirements Average Annual System Cost (billions of $s, 2008-2037) $/MWH Cumulative Increase above Increase over System Cost Increase above Total All Gas 2009 Cost in 2025 All Gas All Gas 45.997 - 181% 127.5 - Nuclear 46.534 0.537 183% 128.4 0.9 Solar 47.352 1.355 189% 132.6 5.1
In all instances, the simulations include the cost for generation additions, incremental transmission requirements, purchased power, natural gas transport, imputed debt, and costs for emission (not including prospective costs for carbon). Costs for nuclear generation additions are modeled assuming CWIP in rates as a necessary financial support measure during the development and construction phase. The Solar scenario shows a cost increase of approximately $1.4 billion over the All Gas reference case and about $0.8 billion more than the Nuclear scenario (both numbers represent the cumulative present worth of revenue requirements over the 30 year study period). The average annual system cost projected for 2009 is $70.3/MWh. The Solar scenario represents an eight percent cost increase above the All Gas reference and a six percent increase over the Nuclear scenario.
The next comparisons illustrate the differences between the All Gas reference case and the previously described Scenarios 1-4. First, an important measure of portfolio risk is the percentage of the energy portfolio met by natural gas energy sources (including both generation and energy purchased from the market). The following chart
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Figure 66 – Annual Natural Gas Burn in BCF
160 All Gas Scenario 1 Scenario 2 Scenario 3 Scenario 4 140
120 (BCF)
100
80
60 2009 2011 2013 2015 2017 2019 2021 2023 2025
Under the All Gas reference scenario, the total annual gas burn climbs to nearly 155 BCF, an approximate doubling of the 2009 gas consumption of approximately 77 BCF. All four of the planning scenarios represent a marked decrease in reliance on natural gas resources, and therefore, each will impart a reduction in the risks associated with natural gas resources. This decreasing reliance on natural gas resources is most clearly manifested in two key areas. First, it is observed below in the projected annual carbon emissions of each of the four scenarios. Second, the decreased reliance on natural gas resources is observed in the sensitivity analysis for natural gas costs. As the scenarios decreasingly rely on natural gas, their “up-side” cost risk decreases when higher natural gas costs are forecast. This chart allows a relatively simple qualitative risk assessment. It is easy to see the differences in the scenarios in terms of the natural gas consumption. This is demonstrated further below in the next important risk illustration.
The All Gas reference scenario projects an APS portfolio-wide carbon emissions increase of approximately six million tons—a 30 percent increase over current carbon emissions. The four planning scenarios can be generally grouped into three categories: 1) moderate reduction in carbon emissions relative to the All Gas reference (Scenario 1); 2)
110 The scenarios share identical resource additions prior to 2013.
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DRAFT dramatic decrease in carbon emissions relative to the All Gas reference (Scenarios 2 and 3) but not below 2009 carbon emissions; and 3) decrease from 2009 carbon emissions (Scenario 4). It is important to note that under all scenarios, carbon emissions are projected to increase until nuclear resources are brought into service. Scenarios that increasingly leverage the use of solar resources manage to slow the rate of carbon emission increases until the dramatic drop caused by nuclear resource additions. As with natural gas, the risk of cost impacts resulting from carbon regulation decreases with the forecast reduction in carbon emissions.
Figure 67 – Annual CO2 Emissions (Short tons)
26,000,000
25,000,000 All Gas Scenario 1 24,000,000 Scenario 2 Scenario 3 23,000,000 Scenario 4
22,000,000
21,000,000 (Tons) 20,000,000
19,000,000
18,000,000
17,000,000
16,000,000 2009 2011 2013 2015 2017 2019 2021 2023 2025
As has been highlighted throughout this Report, the increasing demand on capital expenditures to meet customer resource needs through 2025 is very large, ranging from nearly $14 billion for the All Gas reference to nearly $26 billion for Scenario 4. The following figure is a helpful comparison of projected capital expenditures associated with each of the planning scenarios. The graph includes capital expenditures associated with conventional and renewable resource additions and transmission and provides a way to compare the expected capital requirements associated with each scenario. It is not meant to presume a specific procurement method (i.e., build versus buy).
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Figure 68 – Cumulative Capital Expenditures
25,000.0 All Gas Scenario 1 Scenario 2 20,000.0 Scenario 3 Scenario 4 )
15,000.0 ($ Millions ($ 10,000.0
5,000.0
0.0 2009 2011 2013 2015 2017 2019 2021 2023 2025
While the demand on capital is very great by 2025, it is also important to recognize that commitments on capital are very significant as soon as 2015. Figure 68 helps to demonstrate that significance. As was observed in the Nuclear/Solar economic comparison, as each of the planning scenarios increasingly relies on solar resources, the capital cost of that scenario increases. By 2025, those differences could exceed $7.5 billion between Scenario 1 and Scenario 4, which represents a more than $11.5 billion dollar increase over the All Gas reference scenario.
Figure 69 – Summary of Capital Expenditures Cumulative Capital Expenditures (billions $s) 2015 2020 2025 All Gas 1.44 7.13 14.18 Scenario 1 3.33 10.95 18.09 Scenario 2 4.37 13.27 19.80 Scenario 3 3.33 12.21 19.21 Scenario 4 5.04 18.63 25.74
The average annual system cost and the 30-year present worth economic comparisons provide excellent tools for review of the cumulative portfolio impacts of each of the scenarios. The average annual system cost is also an excellent vehicle for monitoring the end impacts of the sensitivities that were evaluated as part of this portfolio-level analysis. While a cross-comparison of each scenario and the relevant sensitivities, both individually and cumulatively, is certainly plausible, it is not necessary to demonstrate the most important observations of this analysis. Each of the analyses and results from the sensitivities has been included as Appendix 2.
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Figure 70 – Summary of Costs for Scenarios CPW of Revenue Requirements Average Annual System Cost (billions of $s, 2008-2037) $/MWH Cumulative Increase above System Cost Increase above All Gas Total All Gas in 2025 All Gas 45.997 - 127.5 - Scenario 1 46.797 0.800 128.9 1.4 Scenario 2 47.175 1.178 130.1 2.6 Scenario 3 47.036 1.039 129.5 2.0 Scenario 4 48.169 2.172 135.2 7.7
Figure 71 – Average System Cost ($/MWh)
145
135 All Gas
Scenario 1
125 Scenario 2
Scenario 3 115 Scenario 4
105 ($/MWH)
95
85
75
65 2009 2011 2013 2015 2017 2019 2021 2023 2025
3.3.C. Sensitivity Analysis
Under the baseline assumptions (no cost for carbon, no changes to the forecast cost of natural gas, and capital costs as currently projected), the All Gas reference provides for the lowest overall system cost. This “discount” is most pronounced in the years prior to operation of a nuclear facility; thereafter, the difference between the All Gas reference and each of the modeled resource portfolio scenarios declines. Increasing the relative role for solar in each of the scenarios results in a higher ultimate average system cost in 2025. This result is highly dependent upon the forecast natural gas price and represents a significant uncertainty due to the demonstrated volatility of natural gas prices.
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The following series of figures illustrate the effects of the sensitivity analyses across scenarios. The first set of comparisons illustrates the results of the CO2 sensitivity cases. As described previously, two carbon cost sensitivity cases were analyzed: the first with a starting carbon cost of $25/ton (short ton); and the second with a carbon cost of $50/ton (also short ton). The impact on the economics of each scenario is shown below. The figure provides a comparison of the economic impacts for the 30-year study period, which are presented as the cost (or savings) versus the All Gas reference case. Although all of the resource scenarios still show costs as compared to the All Gas reference case, all scenarios show dramatic improvement with increasing carbon costs, particularly under the $50/ton carbon cost sensitivity. Additionally, Scenario 3 comes close to break-even economics under the $50/ton sensitivity case.
Figure 72 – Results of CO2 Sensitivity Analysis vs. All Gas Scenario CO2 Sensitivity Cases
Base CO2 @50 CO2 @25 (no CO2)
Scenario #4
Scenario #3
Scenario #2
Scenario #1
0.0 0.5 1.0 1.5 2.0 2.5 (CPW of Rev. Rqm'ts, $Billions)
The identical type of figure for the four energy efficiency scenarios is provided below. Once again, each scenario provides increasingly more favorable results with the inclusion of carbon costs.
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Figure 73 – Results of CO2 Sensitivity Analysis for Energy Efficiency Scenarios CO2 Sensitivity Cases Base CO2 @50 CO2 @25 (no CO2)
EE Scen. #4
EE Scen. #3
EE Scen. #2
EE Scen. #1
(3.0) (2.5) (2.0) (1.5) (1.0) (0.5) 0.0 (CPW of Rev. Rqm'ts, $Billions)
The next figure provides a different comparison of the CO2 sensitivity analysis. This figure illustrates how the different carbon costs impact the average system cost in 2025. It is interesting to note that all of the resource scenarios have an average cost that is below the reference case for the $50/ton carbon cost sensitivity.
The CO2 sensitivity analysis is an important part of this resource planning study. Although future carbon costs will be somewhat dependent upon the design features of future climate change regulatory structures, APS believes that carbon costs in the range represented by the two sensitivity cases are possible and seem to be within the range of potential carbon costs described in a number of studies of future cap-and-trade regulatory schemes.
Figure 74 – Average System Cost for CO2 Sensitivity Analyses
Comparison of Average System Cost for 2025 (all values in $/MWH)
Base Analysis (no CO2) CO2 at 25 $/ton CO2 at 50 $/ton Yr 2025 Over / Yr 2025 Over / Yr 2025 Over / Average (Under) Average (Under) Average (Under) Cost Reference Cost Reference Cost Reference All Gas - Reference Case 127.5 - 143.2 - 158.8 - Scenario #1 (500 Nuc, 290 Solar) 128.9 1.4 142.6 (0.6) 156.2 (2.6) Scenario #2 (650 Nuc, 800 Solar) 130.1 2.6 142.7 (0.5) 155.3 (3.5) Scenario #3 (800 Nuc, 400 Solar) 129.5 2.0 142.1 (1.1) 154.6 (4.2) Scenario #4 (800 Nuc, 2000 Solar) 135.2 7.7 146.1 2.9 156.9 (1.9)
The next figures provide a summary of the results from the high natural gas price sensitivity cases. The first figure provides results for the four resource scenarios while
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Figure 75 – High Natural Gas Price Sensitivity for Resource Scenarios
High Natural Gas Prices - Sensitivity Case
High Gas Base
Scenario #4
Scenario #3
Scenario #2
Scenario #1
0.0 0.5 1.0 1.5 2.0 2.5 (CPW of Rev. Rqm'ts, $Billions)
Figure 76 – High Natural Gas Price Sensitivity Case for Energy Efficiency Scenarios
High Natural Gas Prices - Sensitivity Case
High Gas Base
EE Scen. #4
EE Scen. #3
EE Scen. #2
EE Scen. #1
(2.5) (2.0) (1.5) (1.0) (0.5) 0.0 (CPW of Rev. Rqm'ts, $Billions)
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The next figure provides another perspective on the risk reduction impacts of pursuing resources that do not consume natural gas. The following figure illustrates the range of average system cost for the All Gas reference with resource Scenario 3. As shown in a previous figure (Figure 75), resource Scenario 3 provides a substantial reduction in natural gas burns versus the reference case. In 2025, this amounts to a reduction of about 50 BCF. The figure compares the range of potential impacts on average system cost under both high and low natural gas price sensitivities. This is an excellent illustration of the much wider range of outcomes under the All Gas reference resulting from the significantly higher natural gas consumption. Scenario 3 would provide a meaningful reduction in the volatility of customer prices.
Figure 77 – Illustration of Risk Reduction Benefits
Year 2025 - Range of Average System Cost (Natural Gas Price Sensitivities)
Low Gas Base High Gas
Scen #3
Reference
110 115 120 125 130 135 140 (Avg. System Cost in $/MWH)
The next sensitivity analysis concerns the cost of constructing new nuclear power plants. With any major construction project, there is significant uncertainty surrounding construction costs. With nuclear power plants, this uncertainty is presently heightened because of the lack of recent experience in this country with the construction of new nuclear plants. For this sensitivity, the cost of building a new nuclear power plant is increased by 25 percent relative to the base assumption. Although this sensitivity analysis was conducted for all resource scenarios that include a nuclear addition, the results are illustrated in the following figure for the Nuclear scenario only (this scenario included 630 MWs of nuclear resource). The figure shows the impact on the average system cost for the increase in nuclear construction costs as compared to the All Gas reference. Following the in-service date of a nuclear plant, average system cost is increased by about $3/MWh with the assumed 25 percent higher construction cost. From
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Figure 78 – Impact of Higher Nuclear Construction Cost Sensitivity of Average System Cost 140 Nuclear Note - Nuclear with base cost is solid blue line w/ Hi Cost 130
120
110
"All Gas" 100 Reference
($/MWH) 90
80
70
60 2009 2011 2013 2015 2017 2019 2021 2023 2025
The following sensitivity comparisons illustrate several uncertainties around the future cost of renewable resources. For simplicity, the uncertainties are shown in the figure below by comparing the Solar scenario (in which 1,400 MWs of CSP are added) versus the All Gas reference. The first sensitivity results in a large increase in cost for renewable resources under the assumption that the current federal tax incentives are not extended beyond their current expiration dates. The second sensitivity assumes that solar becomes more cost competitive with conventional resources over time by assuming a cost escalation rate of one-half the assumed rate of inflation. Figure 79 shows that under this second sensitivity, the cost differential between renewable resources and conventional resources (as portrayed through the All Gas reference) is greatly reduced and the renewable scenario approaches parity by 2025.
111 The base nuclear scenario showed a cost of $0.54 billion more than the reference case.
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Figure 79 – Renewable Cost Sensitivity Analysis Sensitivity of Average System Cost 140 No PTC or Note - Renewable with base cost is solid blue line ITC 130
120 1.5% 110 Escalation
"All Gas" 100 Reference
($/MWH) 90
80
70
60 2009 2011 2013 2015 2017 2019 2021 2023 2025
The current economic conditions highlight the difficulty in forecasting customer growth. Long-term growth trends will exhibit more stability than short-term trends that are influenced by economic cycles; however, near-term volatility induces a degree of uncertainty in forecasting long-term customer growth. The following figure illustrates the impact of changes in long-term customer growth rates on APS’s peak load forecast. Figure 80 shows the high and low load forecast sensitivity cases along with the base case peak load forecast.112
112 All load forecasts depict peak load prior to factoring the impact of customer side efforts such as energy efficiency and distributed energy.
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Figure 80 – Peak Load Forecast Sensitivities
Peak Load Forecast Prior to EE and DE Impacts 14,000
13,000
12,000 Base Forecast +1,262 MWs
11,000 High Load Sensitivity -1,010 MWs
10,000 (MWs)
9,000
8,000 Low Load Sensitivity
7,000
6,000 2009 2011 2013 2015 2017 2019 2021 2023 2025
The high load sensitivity case results in a peak load that is more than 1,200 MWs higher than the base case in 2025. The low load sensitivity case results in a peak load that is approximately 1,000 MWs lower than the base case in 2025.
One measure of the robustness of this Resource Plan is the degree of flexibility it embodies. This flexibility is largely dependent upon the type of resources included and the timing of necessary commitments to those resources. For example, APS’s Resource Plan includes a substantial quantity of gas-fired peaking resources. This type of resource is relatively flexible because decisions related to resource procurement can generally be made within about three years of the needed in-service date of that resource. Additionally, these resources can be procured in relatively small increments such that the quantity of planned additions can be adjusted to more closely match the expected need. The renewable resources specified in APS’s Resource Plan also provide for a degree of flexibility. The lead-times associated with these resources are relatively short, allowing for adjustment of procurement efforts in response to changes in customer needs. In contrast, baseload resource additions typically represent the biggest challenge to the flexibility of a resource plan. Baseload resources can involve extensive lead-times in which major capital commitments must be made many years in advance of the needed in- service date. For a new nuclear plant, the actual construction and startup testing phase is projected to be about 5 years. However, significant commitments related to project development and procurement of long lead-time plant components must precede the construction phase. Additionally, these large baseload projects may be carried out by a consortium of utility companies due to the size of the required investment and relatively large size of individual nuclear units. As the project development moves forward, it can become increasingly costly and difficult to make adjustments in response to changing
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In response to higher or lower customer load relative to forecast conditions used to develop this Resource Plan, APS will revisit and adjust the size and timing of resources included in this Resource Plan. The extent and nature of the revisions will be largely dependent upon the circumstances that exist at the time and will factor in other appropriate variables in addition to the changed customer requirements. However, all other things being equal, APS will strive to maintain the overall philosophy of this Resource Plan. Some of the resource plan changes that would be considered in response to changing customer requirements include:
1. Changes to the timing and quantity of future peaking resources. For example, under the low load sensitivity, the first required peaking resource addition could be delayed until 2017 and the total amount of peaking resource needed by 2025 would then be reduced.
2. Timing and quantity of baseload generation could change. For example, under the high load sensitivity, APS would require increased baseload generation amounts. Advancing the in-service date for the baseload unit additions may not be possible depending upon the status of the development process. Similarly, for the low load sensitivity case, less baseload generation may be required.
3. Adjustments to the timing and quantity of renewable resources could also occur in response to changing load forecasts. These adjustments could be constrained by the necessity to comply with the minimum levels established by the RES rules. Otherwise, with the relatively short lead-times associated with renewable resources, procurement plans can be adjusted to either increase or decrease renewable resource additions in response to changing customer demand and opportunities unveiled by technology development and cost reductions.
Water is playing an increasing role in resource technology selection in Arizona and in the southwest. While it is possible to model portfolio demand on water resources, those modeling results are filled with speculation surrounding public policy, technology efficiencies, and ultimately the availability of actual water resources (including potential future sources for effluent). For example, recent public policy decisions suggest that future gas generation will require the use of dry cooling technologies. While demanding similar water usage, planned CSP facilities in the southwest are not currently employing hybrid or dry cooling technologies. While this is likely the result of a combination of factors (the public desire to increase solar usage and moderate costs, and little operating experience with dry cooled CSP), it is not presently clear whether or when this might
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Analysis of potential water use for the modeled scenarios is included in Appendix 2. The All Gas reference serves as a useful benchmark for prospective demands on water resources. Water consumption in 2009 is expected to be approximately 56,000 acre-feet (total system including estimated impact of water consumed through “tolled” units controlled through long-term PPAs). The All Gas reference projects water usage in 2025 to exceed 72,000 acre-feet. Because all future natural gas resources are assumed to be dry-cooled, all increases in water consumption can be attributed to resource additions (specifically CSP and geothermal) associated with meeting the RES requirements. APS anticipates that future revisions of the Resource Plan will place an increased focus on water consumption and more specifically on strategies to minimize water consumption for the resources selected.
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3.4 Conclusion of Resource Portfolio Analysis
Several conclusions can be drawn from the analyses results and other resource comparisons presented in this section. First, energy efficiency is the only resource type that can reduce both CO2 emissions and natural gas consumption while also improving the overall system economics and, therefore, also providing risk reduction benefits. Other available resource options, such as renewable resources and nuclear generation, can provide these same risk reduction benefits, but these resource types result in cost increases. The magnitude of the potential cost impact is largely dependent upon future natural gas and carbon prices.
Second, with the exception of energy efficiency, all viable resource options have significant risk factors associated with them. In the case of natural gas resources, fuel price volatility is the predominant risk factor. The cost of renewable resources will be impacted greatly by the future availability of federal tax credits and the successful commercial deployment and operation of new system designs at utility scale. The cost of new nuclear resources contains many uncertainties resulting from the lack of recent construction experience in the U.S. The magnitude of these potential risks reinforces the need to pursue a portfolio based resource planning approach—a multi-faceted resource strategy to meet future needs.
The third key conclusion is that resource lead-times are an important aspect to consider in the development of the Resource Plan. Although many resources can be implemented in relatively short timeframes, nuclear resources require a lengthy development and construction lead-time. Because this resource planning analysis illustrates the significant benefits that new nuclear resources can bring to APS’s supply portfolio, the required lead-times result in the conclusion that APS must begin the development process now in order to preserve the option for this resource to be brought into service in the 2022 timeframe, if still appropriate.
Based on these conclusions, observations from the sensitivity analyses, and reasonable judgment related to future risks, APS concluded that a combination of energy efficiency Scenario 2 and supply-side Scenario 3 provides the best balance of interests for both APS and its customers in meeting long-term resource needs.
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PART IV
SPECIAL TOPICS
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SPECIAL TOPICS
This section of the Report is devoted to a discussion of special topics of interest. Four topics are included within this section:
4.1 The capability to deliver renewable resources over the existing transmission system and the need for new transmission.
4.2 Background on the steps and issues associated with developing a new nuclear power plant.
4.3 Additional information on Energy Efficiency program implementation.
4.4 An overview of solar generation.
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4.1 TRANSMISSION NEEDS FOR RENEWABLE RESOURCES
Renewable resources are generally located remotely from load centers. For APS, the situation is no different. However, APS has, with the use of analysis, publicly available information, RFP results, and interconnection queues, determined that the transmission needed for renewable resources is essentially the same transmission needed to support non-renewable resources and that the existing transmission system has the capability to support additional renewable resources. In other words, the additional transmission that APS needs to build to support a resource plan without renewable resources is generally the same as the transmission needed to support renewable resources – even renewable resources in excess of current RES standards.
The capability of solar energy resources to serve the state of Arizona is well documented, and the solar resource in parts of Arizona is some of the best in the world. Although there are several areas in Arizona that have very good solar resources, the area in, around, and west of Palo Verde is a prime location for solar generation.113 As discussed earlier, Palo Verde transmission supports this solar resource which is the basis for the Resource Plan’s call for expanding that capacity.
There are currently over 4,700 MWs of interconnection requests on the APS transmission system for solar resources. Of these, over 2,400 MWs are located in areas that would utilize the Palo Verde transmission system as discussed. Additionally, in APS’s 2008 Renewable RFP, more than 4,500 MWs of solar resources were proposed to APS. Over 2,500 MWs of those 4,500 MWs proposed were located in areas that would utilize the Palo Verde transmission. As shown in the following figure, these projects would provide energy far in excess of the RES requirements.
113 The Palo Verde area includes Palo Verde, Harquahala Junction (Delaney), and Gila Bend areas.
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Figure 81 – Solar Energy Development Potential in Palo Verde Area
Solar Energy Potential in Palo Verde Area1
Solar MWs that Solar Potential to Meet Total Solar would utilize PV RES Requirement from MWs Trans Energy in GWh2 PV Area (%)4 : 2008 renewable RFP 4500 2500 6630 149% APS Interconnection Queue3 4700 2400 6365 143%
RES Requirement in 2025 (non-DG Portion): 4458
1. Palo Verde area includes Palo Verde, Harquahala Junction (Delaney), and Gila Bend Areas 2. Assumes 50% CSP w/storage and 50% PV – energy from 2008 RFP bid averages 3. APS Interconnection queue as of November 12, 2008 4. Note that these percentages are based only on RFP bids and interconnection queue data - it is expected that the amount of solar resource in this area far exceeds these numbers
It is important to note that the above table only represents the solar resource potential in the Palo Verde area as defined earlier. It is expected that additional solar resource will be available in other areas on APS’s system
APS has done considerable analysis of wind resources and their availability to APS customers, as well as their cost as compared to alternative renewable resources. Through this analysis, APS has determined that the ability to access wind resources exists today within the capabilities of the existing transmission system and without the need to build new, long-line transmission in order to access it. This capability exists through existing transmission paths that are not fully utilized (such as the Navajo transmission path) and paths that are fully utilized during limited heavy usage times of the year (summer afternoons) but have surplus capacity for other times of the year.
In an effort to expand our ability to utilize wind resources, APS has borrowed the concept of “conditional firm” transmission as defined by FERC and has adapted a similar concept to use on APS’s system for the benefit of APS’s customers. As a result, APS has contracted for wind energy that is delivered on a constrained transmission path. In order to understand how this works, it is important to understand that the existing resources that utilize a given path dictate how much time that path is fully utilized. If there are peaking resources that utilize the path for relatively few hours per year, then the path has availability the rest of the year. This is a concept that allows an “energy only” wind project to be considered on a transmission path that is fully utilized (no available transmission capacity) during a limited number of hours of the year. The following charts show the relationship of an expected output for a wind project—in this case the Aragonne wind project (located in New Mexico)—and the transmission usage on APS’s
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“eastern path” by month.114 This concept, executed through contract negotiation with the wind developer, allows the majority of the wind energy from a wind project to be delivered to APS on the existing transmission system. Although there are expected to be times when the wind production must be curtailed (this is anticipated in the contract), the amount of energy production lost due to these curtailments is expected to be minimal.
Figure 82 – Monthly Transmission Usage – Eastern Path
Monthly Transmission Usage Eastern Path
100%
95%
90%
85%
80%
75% Percentage 70%
65%
60%
55%
50% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month
114 Note the correlation between the times when there is significant transmission available and when the wind output is highest from an energy production standpoint.
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Figure 83 – Typical Monthly Energy Production - Aragonne Wind
Aragonne Wind Typical Monthly Energy 40
35
30
25
20 Energy (GWh) 15
10
5
0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month
These “energy only” wind projects provide energy to the APS system, but do not provide capacity since they may be curtailed at peak transmission usage times when APS already has sufficient capacity resources to fully utilize the available transmission capacity. This concept fits well with a wind resource that is not as dependable as a traditional resource due to its intermittent nature.
Along with the “energy only” concept, APS has determined that there are wind resources in areas of Arizona that can be delivered to APS’s load assuming acceptable economics. For example, Figure 84 is a map of APS’s transmission system with areas of potentially developable wind resources shown on the map.
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Figure 84 – APS Transmission System with Wind Area Identified
Navajo Others Transmission Four Systems Corners Mead
124MW (2009) 451MW Cholla (2010) TS-9
0MW* Wind Area TS-5 (Sun Valley) (Eastern New Mexico) Harquahala Junction Westwing (Delaney) Palo Verde Phoenix Pinnacle Peak Hub Metro Area Kyrene Rudd
168MW Wind Area (Northern Mexico – south of CA) Yuma * Transmission path lends itself to use by wind as an energy only resource Others Transmission Systems Saguaro
Figure 85 shows that wind exists in areas where APS either has existing transmission available or where APS can use the “energy only” concept to bring wind energy into its system. For example, using just APS’s existing transmission rights, APS would have the ability to deliver up to about 80 percent of the total 2025 RES non- distributed energy requirements from wind.
Figure 85 – Wind Energy Potential Wind Energy Potential
Capacity Path Factor MW Energy (GWh) Eastern Path1 30% 400 1051 Navajo Path 30% 451 1185 Mead Path 30% 349 917 Palo Verde Path 30% 168 442 3595
RES Requirement in 2025 (non-DG Portion): 4458
Wind Potential to Meet RES Requirement with Existing Transmission (%): 81%
1 Eastern Path Assumes an "Energy Only" Use of Path for Wind
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The geothermal resource in Imperial Valley is located relatively close to APS’s Yuma load pocket. APS’s current geothermal resource utilizes transmission wheeling on the Imperial Irrigation District’s transmission system to deliver the geothermal resource to APS at Yuma (specifically at the Yucca substation). For example, using just APS’s existing transmission rights between Palo Verde and Yuma and the ability to utilize geothermal resources to serve the load requirements in the Yuma area, APS would have the ability to deliver up to 75 percent of the total 2025 RES non-distributed energy requirements with geothermal to APS customers.
Figure 86 – Geothermal Energy Potential Geothermal Energy Potential
Capacity Path Factor MW Energy (GWh) Palo Verde Path 100% 168 1472 1 Yuma Load 100% 216 1892 3364
RES Requirement in 2025 (non-DG Portion): 4458
Geothermal Potential to Meet RES Requirement with Existing Transmission (%): 75%
1 Yuma load indicates the amount of geothermal capacity that could be used in Yuma based on future Yuma load growth and avoiding stranding assets in Yuma
As demonstrated in the above sections, APS has adequate renewable resource potential available in areas that either already have available transmission or areas that are targeted for the addition of transmission facilities that will enable the receipt of renewable resources in amounts that can far exceed this Resource Plan, all of the conceived scenarios, and the RES requirements.
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4.2 BACKGROUND ON NUCLEAR DEPLOYMENT
Utilities are once again viewing nuclear power plants as a viable and attractive means of satisfying the growing need for energy. A number of factors are contributing to this growing interest in nuclear power:
• Environmental concerns (specifically, the potential for future climate change policies) • Excellent performance of currently operating nuclear plants • Natural gas price volatility (the need to develop energy sources other than natural gas) • Public support for nuclear energy
The project development timeframe for a nuclear project will encompass a total of approximately 14 years. A more aggressive approach could decrease the overall schedule by up to two years. Based upon a preliminary cost estimate, APS anticipates that the initial development and licensing steps will cost approximately $130 million. This estimate does not include any costs for site preparation, land, or equipment costs (for ordering long lead-time components). These initial development costs are expected to be shared with other project participants according to their ownership percentages.
This section will provide background on several aspects of nuclear power plant development including a review of the licensing process, a brief summary of used nuclear fuel management and transmission issues, and an overview of the development process moving forward.
4.2.A. Licensing Process
The licensing process for new nuclear power plants is an important and complex element of the development process. The federal government licensed today’s 104 nuclear power plants under Title 10 Code of Federal Regulations (“CFR”) Part 50 (the “Part 50” rules). A review of the licensing timetables for the last 25 commercial nuclear power plants licensed by the NRC under the Part 50 rules confirms that a number of them experienced significant licensing delays, particularly with respect to the issuance of the operating license. The licensing delays that occurred from the mid-1970s through the 1980s were attributable to a combination of economic, political, regulatory, and legal factors.
In 1989, the NRC developed a new licensing process found at 10 CFR Part 52 (the “Part 52” rules). Congress affirmed and strengthened the new licensing process as part of the Energy Policy Act of 1992. This process consists of three separate and distinct subparts:
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• Early Site Permit • Standard Design Certification • Combined Construction Permit and Operating License
Within the past several years, the NRC has issued three ESPs and four reactor plant standard design certifications. At present, they are also reviewing an additional ESP application, three design certification applications and nine COL applications (“COLA”). NRC’s list of nuclear projects that have either already filed for a new ESP or COL or have notified the NRC of their intent to do so includes 23 applications representing 34 new nuclear units. However, it is still too early to reach a final conclusion on the effectiveness of the new process because no plants have gone through the entire Part 52 licensing process at this time.
Support for new nuclear power plants among the public and policymakers is high. In 2002, the DOE developed the Nuclear Power 2010 program, which includes DOE cost-sharing with the industry on a series of ESP and COLAs in order to reduce the uncertainty in the decision-making process for building new nuclear power plants.
Additionally, the Energy Policy Act of 2005 includes a wide range of incentives to encourage new nuclear plant construction, including loan guarantees, production tax credits, and standby insurance. In fact, the recent surge in COLAs was in part triggered by a December 31, 2008 deadline imposed by the government in order to be eligible for these incentives.
A brief description of the Part 52 process follows.
4.2.B. Early Site Permit
The ESP provides approval for siting a new reactor at an existing nuclear plant site or at a new site. Therefore, the ESP process allows an applicant to obtain federal regulatory approval for a new nuclear plant site before making a decision to build a plant. The ESP addresses environmental issues for the operating parameters of a specific design or a generic design. If the proposed site is found suitable and the NRC grants an ESP, the company can save, or bank, the site for up to 20 years until it is ready to build a plant. With a pre-approved site, the applicant can then plan when to move into the construction phase, choosing a power plant design and obtaining regulatory approval to build and operate it. So far, the NRC has granted ESPs for the following sites:
• Clinton (Illinois) (Exelon Generation Company) • Grand Gulf (Mississippi) (System Energy Resources Inc.) • North Anna (Virginia) (Dominion Nuclear)
Additionally, the NRC is currently reviewing an ESP application for Southern Nuclear’s Vogtle site in Georgia.
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4.2.C. Standard Design Certification
Standard design certification allows reactor vendors to secure advance NRC approval of standard plant designs. Following an exhaustive NRC safety review, agency approval of standard designs is formalized via a specific design certification rulemaking. This process allows the public to review and comment on the designs up front—before any construction begins. NRC design certification fully resolves safety issues associated with the design. The design certification application process takes 36 to 60 months to complete, depending on a variety of factors. A certified standard design is good for 15 years.
The standard design certification process offers significant benefits over the Part 50 process utilized for licensing the current generation of commercial nuclear power plants. The standard design certification approach anticipates that reactors will be built in families of the same design, except for a limited number of site-specific differences, whereas currently operating United States nuclear power plants are essentially one-of-a- kind. Standardization will theoretically reduce construction and operating costs, and lead to greater efficiencies and simplicity in nuclear plant operations, including safety, maintenance, training, and spare-parts procurement.
At this time, the NRC has certified four standard designs and three additional designs are currently under review:
Approved: • GE-H ABWR • Combustion Engineering System 80+ (not commercially available) • Westinghouse AP 600 (not commercially available) • Westinghouse AP1000
Under Review: • AREVA EPR • GE-H ESBWR • Mitsubishi APWR
All of these new commercially available nuclear technologies are evolutionary versions of the designs from the previous generation of plants, such as the Palo Verde Nuclear Generating Station. While the design of the PVNGS units is safe and reliable, there have been many lessons learned from the existing nuclear fleet and the newer designs incorporate those lessons learned in the form of enhancements to existing systems and the development of newer, simplified systems offering improvements in areas such as maintenance management, overall nuclear safety, and economics of operation.
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4.2.D. Combined Construction Permit and Operating License
Part 52 also provides for issuance of a COL. A COLA under Part 52 may reference a certified standard design, an ESP, a reference COLA (“R-COLA”), or any combination of these. The R-COLA, usually the first COLA submitted for a particular reactor technology, can be used by subsequent applicants to reduce the scope of their COLA submittal by incorporating, by reference, applicable portions of the R-COLA. If a COLA does not reference an ESP, R-COLA, and/or a standard design certification, the applicant must provide an equivalent level of information in the COLA. This makes the process more effective and efficient by allowing NRC review and a public hearing for a COLA to focus on remaining issues related to plant ownership, design issues not resolved earlier, and organizational and operational programs. Granting a COL signifies resolution of all safety issues associated with the plant.
The one issue that cannot be addressed up front is whether the plant, once built, conforms to the requirements of the license and is ready to operate. For this, Part 52 provides the Inspections, Tests, Analyses and Acceptance Criteria (“ITAAC”) that will be used to assess whether the completed plant conforms to license requirements. Under this process, the ITAAC elements are agreed upon in the COL. The ITAAC then will be used during construction to determine that the constructed plant conforms to its licensing requirements. No applicant has yet been through the entire COLA process. The NRC currently estimates that the review and approval of the first set of COLAs could take as long as 42 months.
4.2.E. Intervention and Litigation Risk
As with Part 50 license applications, Part 52 provides for two hearing opportunities on a COLA. However, the timing and focus of these hearings under Part 52 differ from those offered under Part 50. Under Part 52, the NRC is statutorily required to hold a mandatory uncontested hearing on the application. Apart from the mandatory uncontested hearing, members of the public may petition to intervene as full parties to contest issuance of a COL. This may lead to a contested hearing. Entities or persons may petition to intervene in the NRC facility licensing proceeding by demonstrating standing to intervene and proffering at least one admissible contention (a legal and/or factual concern) challenging the adequacy of the application. These procedures are governed by NRC rules of practice in 10 CFR Part 2.
An NRC Atomic Safety and Licensing Board (“Board”) rules on the admissibility of each petition to intervene and proposed contention. Admitted contentions are subject to an evidentiary hearing. An intervener may ask the NRC to review the Board’s decision on intervention petitions, but such review by the Commission is discretionary. Once the NRC’s internal review and appellate process is complete (i.e., the NRC has taken final agency action and the intervener has exhausted its administrative remedies), the intervener may petition a U.S. Court of Appeals for judicial review of the NRC’s final
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DRAFT order within 60 days of its issuance. The U.S. Court of Appeals (not a federal district court) has direct and exclusive jurisdiction over NRC licensing decisions.
Once the NRC issues the COL, the second hearing opportunity is much narrower. At least 180 days before the scheduled date for initial loading of fuel into the reactor, the NRC publishes a notice providing an opportunity for members of the public to participate in a hearing. The NRC considers a request for a hearing only if the request demonstrates that: (1) the licensee has not met or will not meet the ITAAC acceptance criteria in the COL; and (2) the specific operational consequences of the non-conformance would be contrary to providing reasonable assurance of adequate protection of the public health and safety.
4.2.F. Used Nuclear Fuel
One of the challenges to the viability of a nuclear renaissance is what to do with used (or “spent”) nuclear fuel. This is not a new challenge. The nuclear expansion of the 1970s emphasized the need for a permanent repository for used nuclear fuel. In 2002, DOE determined that the Yucca Mountain site in Nevada would be a suitable site for the national repository and on June 3, 2008, submitted its application to the NRC for a license to construct and operate the Yucca Mountain high-level nuclear waste repository. Congress has set a three-year schedule for the NRC to reach a decision on the application.
Political opposition (particularly among the Nevada Congressional delegation) remains high. However, the DOE has entered into new contracts for disposal of spent nuclear fuel with a number of COL applicants. Therefore, the DOE has expressly signaled that it remains obligated to accept spent nuclear fuel from the nation’s commercial nuclear power plants, including plants that have yet to be licensed and built.
4.2.G. Transmission
Transmission infrastructure needs are another important part of the overall challenge for a new nuclear baseload generation project. Given the current physical and contractual limitations on the Arizona bulk electric system, any addition of baseload generation in the state will likely require significant new transmission facilities to be built. Baseload resources located remotely from the Phoenix load areas will need to deliver either to one of the primary 500/230 kV substations or a new 500/230 kV substation.
The scope, schedule, and resource needs for delivering energy to load centers vary from site to site depending on several factors common to all transmission projects, such as distance from the resource to the interconnection, capacity of the resource, environmental and routing issues, and land ownership. In addition, there are nuclear- specific requirements that will influence the design of the site switchyard and the interconnection scheme. These requirements address the reliability of the off-site power
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4.2.H. Moving Forward
The decision to actually proceed with construction of the nuclear plant does not need to be made at this time. Development activities can proceed to further develop the baseload nuclear option without actually making the final commitment to build the plant. APS believes that this decision-making approach coupled with a step-wise regulatory approval of the different development steps is a prudent way to manage the risk associated with a project of this magnitude. Because of the substantial development costs and project risk, APS will need assurances from the ACC that these development costs can be recovered, even in the event that the project is cancelled or abandoned. A prudent approach to a project of this magnitude and risk will allow for periodic opportunities to reassess the project viability and need, given the existence of other available resource options.
APS anticipates that ACC approval will be requested at discrete points and for discrete activities along the project development timeline. For example, approval of the first phase of development would encompass the activities and costs associated with the ESP preparation and submittal. The next regulatory action could involve approval for activities and costs associated with the COLA phase of the project development. Additional approvals could also be requested for other discrete project steps such as the major outlays that would be required for ordering long lead-time plant components.
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4.3 ADDITIONAL INFORMATION ON ENERGY EFFICIENCY PROGRAM IMPLEMENTATION
The purpose of this section is to describe in further detail the action plan for implementing energy efficiency programs that are expected to achieve the cumulative energy savings contained in the Resource Plan, which calls for over 3,200 GWhs of energy savings from energy efficiency programs by 2025.
Figure 87 – Savings from Energy Efficiency (GWhs) Energy Savings (GWh) Incremental Cumulative 2009 198 378 2010 213 592 2011 179 770 2012 167 937 2013 175 1,112 2014 184 1,296 2015 209 1,505 2016 227 1,732 2017 211 1,943 2018 197 2,140 2019 186 2,326 2020 175 2,501 2021 167 2,668 2022 158 2,826 2023 151 2,978 2024 145 3,123 2025 139 3,261
Achieving these incremental results each year is expected to take annual spending on energy efficiency programs as shown in the figure below. These spending amounts are inclusive of all program related costs, including: 1) customer incentive payments; and 2) program administration costs (i.e., marketing, education, training, implementation, planning and administration), but they do not include any performance incentive to APS for efficiently implementing the programs.
The underlying assumption behind the annual spending estimates is that it will cost more in the future to achieve the same amount of energy savings than it does today. This assumption is based on the premise that the “least expensive” energy efficiency savings will be exhausted in the early years and the “more expensive” (yet still cost effective) programs will need to be incorporated into the portfolio in subsequent years. Said another way, it will be more expensive to convince customers to participate in future programs that have a longer payback to the customer than the programs today.
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Figure 88 – Annual Energy Efficiency Spending Energy Efficiency Spending Annual (million $) 2009 23.1 2010 24.8 2011 33.0 2012 40.0 2013 50.0 2014 60.0 2015 75.0 2016 90.0 2017 90.0 2018 90.0 2019 90.0 2020 90.0 2021 90.0 2022 90.0 2023 90.0 2024 90.0 2025 90.0
The level of energy efficiency considered optimal in the Resource Plan calls for spending to escalate from approximately $23 million in 2009 to approximately $90 million per year by 2016, as shown in the table above. This escalation is necessary to achieve the optimal target of over 3,200 cumulative GWhs by 2025. The ramp-up of spending to achieve this target is very aggressive, with increases in funding of between $10 million to $15 million from one year to the next. The action plan to achieve these targets can best be broken down into a Short-Term Plan (2009-2011) and a Long-Term Plan (2012 and beyond). Each of these plans is described below.
4.3.A. Short-Term DSM Action Plan (2009 to 2011)
APS already has filed with the ACC a 3-year DSM Portfolio Update plan covering the years 2008-2010. This plan was filed with the Commission on December 28, 2007 in Docket No. E-01345A-07-0712 and was approved by the ACC in Decision No. 70666, dated December 24, 2008. This plan calls for spending $76.5 million over the three-year period of 2008-2010. The derivation of the $76.5 million figure is based on the ongoing commitment to spend $19.5 million per year on DSM (the original $16 million per year from the 2005 Settlement Agreement, plus the $3.5 million per year added to the portfolio spending in August 2007,115 for an ongoing spending commitment of $19.5 million per year) or $58.5 million over the three-year period. Additionally, the total spending in 2005-2007 was estimated to be about $30 million and, therefore, to be approximately $18 million less than the commitment in the Settlement Agreement of $48 million. This $18 million shortfall was then added to the $58.5 million ongoing commitment to reach the $76.5 million 3-year target for 2008-2010. At the time of this
115 Decision No. 69879.
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DRAFT writing, it is anticipated that approximately $23.5 million will be spent on DSM in 2008, including the performance incentive. That will leave approximately $53 million to be spent in 2009 and 2010.
In order to achieve the spending target of $53 million in 2009 and 2010, APS expects to continue to implement the same portfolio of programs currently being implemented in 2008 with a few additional program elements. Throughout 2008, the program success continued to grow and the awareness of the programs among APS customers was on the rise. By continuing this momentum into 2009 and 2010, introducing a few new measures within the existing programs, and re-designing other programs, APS believes that the $53 million spending target in 2009-2010 is certainly achievable.
The new measures being considered for introduction into the existing programs in 2009 or 2010 include:
• Energy Star Plus – a second-tier residential new home energy efficiency measure that incents builders to build new homes that use at least 30 percent less energy than the current IECC 2006 standards for new homes. This will be an additional measure added to the current Residential New Construction program. • Direct Install – a measure for small business customers to make it more affordable and attractive for them to invest in energy efficiency through a third-party contractor with little or no up-front capital costs to the small business. This will be an additional measure added to the Small Business program within the Solutions for Business suite of programs.
Other changes in program emphasis being considered in the 2009-2010 timeframe include:
• Re-design of the residential HVAC program to emphasize the quality installation measure in order to ensure more energy savings for a household installing a high efficiency HVAC unit. • Additional emphasis on the residential duct test and repair measure since there are considerable savings to be realized from this measure and a large market to potentially participate in the program. • Increased promotion of the Home Performance with Energy Star measure to provide existing households with a more comprehensive ability to assess their entire household for energy efficiency improvement opportunities. • More targeting of the Solutions for Business program to specific commercial or industrial sectors, such as health care, lodging, government, small business, and irrigation customers.
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Through these actions, APS should be able to achieve the remainder of the spending and savings targets from the existing Portfolio Update Plan budget for 2009 and 2010, despite the current economic slowdown in Arizona.
In 2011, the anticipated spending in the Resource Plan climbs to $33 million. That level of spending may also be achievable with continued expansion of the existing programs as outlined above, or it may require the introduction of other new programs. Some of the potential new programs and measures currently under consideration to replace programs being phased out or to add to the existing portfolio include:
Residential • Refrigerator recycling • High efficiency clothes washers • High efficiency pool pumps/pool timers • Shade screens and window treatments • High efficiency window replacements • Shade trees and other urban heat island mitigation strategies • Programmable thermostats • Ceiling Insulation • LED and other high efficiency lighting
Commercial • Upstream buy-down program for commercial high efficiency motors • Heat island mitigation strategies
These programs will be introduced, as needed, in the 2010-2011 timeframe, to achieve the short-term savings targets specified in the early years of this Resource Plan. Other programs may also be introduced that replace existing programs that are no longer cost effective or that are made obsolete by building codes and equipment standards increases.
One program that will be impacted by increased federal equipment standards will be the Compact Fluorescent Lighting (“CFL”) measure within the Consumer Products program. By 2012, CFLs will become the residential lighting standard and therefore will not need to be incentivized through a utility program. As this market transformation to the new CFL standard occurs, the APS Consumer Products program will need to transition away from the CFL incentive measure and toward even higher efficiency lighting measures or other high efficiency appliances to replace the CFL measure. This program transformation is expected to occur in the 2011 to 2012 timeframe.
4.3.B. Long-Term DSM Action Plan (2012 and beyond)
At this point, there is less certainty and specificity about the exact programs and measures that will be part of the energy efficiency program portfolio in 2012 and beyond.
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Between now and 2012, APS will be evaluating many different measures for cost effectiveness with the potential of adding them to our portfolio of programs. These evaluations will be based on the estimated incremental cost of installing various measures and the resulting energy savings from those measures. The measures with the most appeal to our customers, the broadest potential for adoption, and the highest benefit/cost ratio will be incorporated into our programs at the appropriate time in order to achieve the savings targets. APS will continue to work with the DSM Collaborative group to identify and initiate these new programs. There are over 200 potential new measures that were included in the 2007 Market Potential Study, and they will continue to be evaluated with updated incremental and energy savings estimates. This list of measures includes items such as:
• High efficiency dishwashers, clothes dryers, water heaters, and refrigerators; • Advanced HVAC technology such as variable speed motors, water cooled condensers, and advanced unitary compressors; • Building envelope enhancements such as insulation, windows, phase change drywall, radiant barriers, window film, and shade screens; and • Commercial control systems for pumps, fans, and compressed air.
APS is currently building a DSM Planning Model that will allow us to consider many of these end-use technologies as potential energy saving measures to include in our program portfolio. This model will be used on an annual basis, in conjunction with an evaluation of the Resource Plan, to determine the most cost effective set of DSM measures to include in future programs that will achieve the energy savings called for in the Resource Plan.
It is anticipated that these future measures and programs that are currently unspecified will be needed to expand the program spending to the $50 million per year level and beyond, as is specified in the current Resource Plan beginning in 2012. This level of spending and energy savings will also need to include new energy saving technologies that will be evaluated as they become available in the future. While the exact make-up of the future DSM programs cannot be specified at this time, it is clear that a significant expansion of current program measures, awareness, and participation will be required to meet the energy reduction targets beyond 2012 that are called for in this Resource Plan.
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4.4 SOLAR GENERATION
APS expects solar generation to play an important role in meeting the energy needs of Arizona. Some of the best quality solar resources in the world can be found in Arizona. APS believes that Arizona’s high quality solar resource provides a strong reason to aggressively pursue solar generation for meeting future resource needs. This resource plan includes renewable resources in excess of the amount required to meet the RES targets, and it is possible that future updates to the Resource Plan will incorporate even higher amounts of solar resources as the technologies and costs improve. The purpose of this section is to describe the generation characteristics of solar resources and the role that they can fulfill in APS’s resource portfolio.
The following sections provide sample solar generation patterns for different times of the year and for different technologies. These sample solar generation patterns are compared to the customer energy consumption (“APS’s system load patterns”) to provide an indication of how solar generation can match APS’s system load patterns. Study year 2018 was selected for use in the examples with specific focus on a spring day (March) and a summer day (July). In the spring, APS system loads are relatively low because heavy air conditioning requirements are not yet present, yet solar generation can be relatively high. In the summer, the APS system experiences the highest level of customer energy load and the need for late afternoon energy generation is at its highest, the “peak load”. APS’s peak load in 2018 is forecasted to be 8,784 MWs after accounting for the contributions from planned energy efficiency and distributed generation.
4.4.A. Solar Generation Patterns
The following figures illustrate typical solar generation production profiles for three types of solar generation. The first figure is an example of a fixed position photovoltaic generator with a 10 degree south facing orientation. Fixed position indicates that the solar collection panels are mounted in such a way that their orientation to the sun is constant. The second figure demonstrates production for a photovoltaic generator with one axis tracking capability. One axis tracking is a mechanical mounting system that allows the solar collection panels to follow the movement of the sun across the daily horizon. The third figure demonstrates production for a solar thermal trough system that includes six hours of thermal energy storage. Solar thermal troughs use mirrors which follow the sun’s daily path and concentrate the heat from the sun on a thermal fluid used as part of a conventional steam generator. Thermal storage capabilities can be added in limited capacities to trough systems to smooth out production and sometimes temporally shift the generator output.
Figures 89 and 90 portray the daily generation patterns for all three types of solar technology installations in the months of March and July and, for comparison purposes, show the hourly demand on the APS system. As demonstrated in Figure 89, the fixed position solar generator begins generation when the sun comes up, increases its output
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DRAFT until mid-day when the sun is most directly overhead, and then decreases for the rest of the day until the sun dips below the horizon. Figure 90 shows that the tracking photovoltaic system reaches its maximum daily output within a few hours of sunrise, maintaining relatively high production throughout the day, and then dropping off swiftly into sunset. The solar trough with the addition of thermal energy storage demonstrates the rapid achievement of full load in the morning and delivering power into the evening past sunset. Photovoltaic systems do not achieve 100 percent of their nameplate rated output in either of the two example months—March and July. Photovoltaic systems achieve their full rated output only during times of the year when the sun is directly overhead, which is dependant on the tilt angle of the specific installation, and the ambient temperatures are cool. Photovoltaic unit performance generally decreases as ambient temperature increases. The ramp up and ramp down116 cannot be managed for the fixed position photovoltaic units, can be managed to some degree for the tracking photovoltaic (though that would result in the permanent loss of energy), and can be more effectively managed for solar trough with storage.
Figure 89 – Solar Generation Profiles for March Day
Typical March Day (3/09/2018) MWs 100% 4,500
90% 4,000
80% 3,500
70% 3,000 60% System Load 2,500 50% 2,000 40% 1,500 30% 1,000 20%
10% 500
0% 0 1 2 3 4 5 6 7 8 9 101112131415161718192021222324
Fixed PV PV One Axis Tracker Parabolic Trough – 6 hrs storage
116 The ability to manage the start of energy production from a generating system is referred to as ramp up. The ability to control the timing of a generator’s “end” of production is referred to as ramp down.
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DRAFT
Figure 90 – Solar Generation Profiles for July Day
Typical July Day (7/16/2018) MWs 100% 10,000
90% 9,000
80% 8,000
70% 7,000
60% 6,000
50% 5,000 System Load 40% 4,000
30% 3,000
20% 2,000
10% 1,000
0% 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24
Fixed PV PV One Axis Tracker Parabolic Trough – 6 hrs storage
A simple measure of the value of any generation resource is how well its production can be managed to match the electric system demand. This is particularly pronounced for solar generation. Typically, customer consumption is much higher during the daylight hours and this is clearly shown in both the March and July system load profile. Solar generation provides an excellent source of daytime energy that can be used to serve this customer demand. In the July peak load periods, capacity requirements117 predominate and utilities must procure sufficient capacity resources to meet the late afternoon system peak load. The previous figure shows the benefits of deploying energy storage technologies for satisfying this late afternoon peak. Solar trough systems with the addition of energy storage are capable of operating at full capability at six or seven in the evening, and, therefore, they can provide energy during the summer system peak hour.
4.4.B. Spring-Time Operation
The figures contained in this section provide a visual representation of the impact of incorporating significant amounts of solar generation into the APS system during the spring months. The figure below highlights that, with moderate ambient temperatures,118 APS system demand in the spring does not change much over the course of the day.119
117 Capacity requirement refers to the need to meet system demand for energy over the relatively short time periods in the late summer afternoon. 118 During periods with moderate temperatures, customer energy usage typical does not include heavy energy usage resulting from heating or cooling homes and businesses. 119 The total system demand is represented by the sum of all of the colors in the chart.
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DRAFT
Night-time loads are projected to be approximately 3,000 MW, with daytime loads in the 4,000 – 4,500 MW range, remaining fairly flat across the day. The yellow and orange colors represent the impact of incorporating increasing amounts of fixed-position solar photovoltaic into the system. The remaining blue areas represent customer load that would need to be served with other types of resources.
Figure 91 – Photovoltaic Fixed Position for a March Day
2018 March Peak Load With Photovoltaic (Baseline 100 Tilt South Facing)
10,500 Based on 2005 Historic Data
9,500
8,500
7,500
6,500
5,500 MW
4,500
3,500
2,500
1,500
500 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 1st 1000MW PV 2nd 1000MW PV 3rd 1000MW PV
The figure shows that the solar photovoltaic energy would provide a significant contribution during the middle portion of the day and would reduce the need for other generation sources during that period. However, with increasing amounts of solar photovoltaic energy, the remaining customer load will become somewhat more difficult to serve. During the middle of the day, the output from large baseload generating resources will need to be reduced to accommodate the production of the solar energy resources.120 Beyond the operational challenges imposed on baseload resources, gas- fired generators will need to be used to meet the customer load, above that served by the baseload resources, in the morning and evening hours and will most likely need to be turned off during the middle part of the day. This additional starting and stopping of gas- fired units is a less efficient use of these units and will impose an additional maintenance burden on this equipment.
120 Baseload resources are designed to achieve maximum output and economic efficiency by running nearly all hours of the year. Some baseload resources are simply not capable of daily ramp up and ramp down operation (“cycling”). Those capable of daily cycling incur higher operating and maintenance costs.
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DRAFT
This figure also helps to demonstrate the potential benefits of coupling solar generation with energy storage technologies. Energy storage can help broaden the contribution from solar generation to other times of the day to help improve the overall operation of the system.
4.4.C. Summer Operation
The following figure provides an illustration of the impact of fixed position photovoltaic during an APS system peak demand day in July. On these days, APS’s minimum customer demand is around 5,000 MWs in the morning, rising to a peak of about 9,000 MWs at about 5:00 pm, and then declining into the evening hours. Similar to the production in March, solar energy contributes significantly towards meeting customer load requirements during the daylight hours. Solar energy is expected to decrease the reliance on natural gas-fired generation during those periods of high solar production. Additionally, the solar energy contributes towards reducing the system peak load which occurs around 5:00 pm. Importantly, the reduction in peak load decreases as more solar resources are incorporated into the system. Note that the third block of solar resources results in very little additional peak load reduction; rather, the system peak has simply shifted to later in the evening—in this example about 7:00 pm. Again, this example highlights the benefits of adding thermal storage and therefore extending the use of solar energy.
Figure 92 – Photovoltaic Fixed Position for a July Day
2018 July Peak Load With Photovoltaic (Baseline 100 Tilt South Facing)
10,000 Based on 2005 Historic Data
9,000
8,000
7,000
6,000 W M 5,000
4,000
3,000
2,000
1,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 1st 1000MW PV 2nd 1000MW PV 3rd 1000MW PV
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DRAFT
4.4.D. Summary
Solar generation can provide significant benefits to the APS resource portfolio. Solar resources provide energy at times that match well with the APS system because the energy production occurs during the daylight hours when customer consumption levels are high. There will be challenges as increasing amounts of solar energy are incorporated into the APS system. APS believes that energy storage technologies must play an important role in helping to maintain the highest value for solar resources and will be necessary to support increasing solar penetration levels. This analysis helped to highlight for APS some of the important value propositions presented by the Solana power plant. Solana will incorporate a molten salt thermal energy storage system that will be used to extend the plant’s operating times and maximize benefits to the APS system.
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RESOURCE PLAN REPORT
APPENDIX 1
SELECTED RESOURCE PLAN ANNUAL TABLES
TABLE OF CONTENTS
APPENDIX 1
1. SELECTED RESOURCE PLAN
Table 1 Loads and Resources Summary
Table 2 Total Revenue Requirements
Table 3 CO2 Total Plant Emissions (in Tons)
Table 4 Annual Natural Gas Burns (in BCF)
Table 5 Annual Own Load Energy Requirements (in GWh)
Appendix 1 Page i
TABLE 1. SELECTED RESOURCE PLAN LOADS AND RESOURCES TABLE
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 996 1,026 1,036 1,051 1,063 1,100 1,141 1,184 1,227 1,268 1,309 1,349 1,461 1,502 1,543 1,585 1,628 4. Total Load Requirements 8,317 8,398 8,510 8,663 8,784 9,105 9,457 9,828 10,203 10,561 10,914 11,254 11,669 12,015 12,363 12,714 13,070
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 25 55 86 124 159 194 230 272 316 357 396 432 466 499 530 559 587 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 000070220320343343343343343423423703703793 18. Baseload Nuclear 0000000000000400800800800 19. Gas Combined Cycle 00000000000528528528528528528 20. Peaking Resources 00000002821,034 1,410 1,692 1,974 2,726 2,726 2,726 2,726 3,008 21. Short-Term Market Purchases 0000000434490409417447449486106399430 22. Total Future Resource Additions: 41 81 125 180 293 489 637 1,437 2,312 2,671 3,023 3,924 4,818 5,314 5,673 6,024 6,485
23. Total Resources: 8,231 8,629 8,704 9,052 9,161 9,357 9,505 9,828 10,203 10,561 10,914 11,254 11,669 12,015 12,363 12,714 13,070
New Renewable Nameplate Capacity ● 100 106 106 389 459 659 809 855 855 855 955 955 1,035 1,035 1,314 1,314 1,664
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 1 TABLE 1. TABLE 2. SELECTED RESOURCE PLAN TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 50.0 2,155.7 67.0 2009 549.1 787.5 42.1 412.2 8.6 1,799.6 76.8 308.1 384.8 (8.3) 42.5 14.5 (1.2) 81.6 2,313.6 71.1 2010 573.3 736.2 41.5 422.9 20.9 1,794.8 115.7 335.4 451.1 (9.1) 42.2 24.5 (9.5) 82.3 2,376.4 73.1 2011 580.5 770.7 43.5 419.9 28.5 1,843.1 102.9 277.4 380.2 (10.0) 43.4 23.2 (10.0) 107.1 2,377.1 72.9 2012 578.7 683.7 39.7 423.8 30.7 1,756.6 105.2 437.6 542.9 (14.0) 42.5 27.8 (10.5) 134.9 2,480.0 75.4 2013 583.5 686.6 41.6 429.0 49.2 1,789.9 105.8 484.9 590.7 (19.0) 44.3 27.2 (10.9) 115.8 2,538.1 76.7 2014 601.0 779.4 47.5 446.3 66.1 1,940.4 106.2 545.4 651.5 (24.3) 51.0 29.0 (11.7) 134.5 2,770.3 81.6 2015 639.1 790.6 47.9 462.7 76.3 2,016.7 106.6 663.9 770.4 (33.0) 51.8 29.2 (12.3) 160.7 2,983.7 85.3 2016 798.3 857.4 53.3 436.7 103.7 2,249.3 139.4 705.8 845.2 (37.0) 59.0 27.0 (12.8) 220.0 3,350.6 93.0 2017 989.0 1,058.8 67.2 452.0 120.2 2,687.2 165.8 601.5 767.3 (39.2) 64.8 23.8 (13.5) 230.5 3,720.9 100.4 2018 1,184.0 1,210.4 80.7 470.0 163.0 3,108.0 127.4 538.2 665.6 (38.4) 72.8 21.4 (14.4) 241.7 4,056.6 106.6 2019 1,326.5 1,223.1 82.2 485.2 180.0 3,297.1 122.0 581.1 703.0 (5.2) 75.5 20.7 (15.4) 252.7 4,328.4 111.0 2020 1,589.1 1,428.3 103.1 508.8 192.2 3,821.5 67.5 468.9 536.4 (2.6) 80.9 18.1 (16.6) 263.6 4,701.3 117.8 2021 1,885.2 1,508.2 113.2 539.0 239.1 4,284.7 67.8 574.6 642.4 0.0 89.4 23.6 (17.7) 274.7 5,297.1 129.7 2022 2,171.9 1,523.3 114.5 575.6 254.6 4,639.9 61.5 554.4 615.9 0.0 95.2 22.7 (19.1) 286.0 5,640.6 135.0 2023 2,177.4 1,355.6 100.2 622.4 247.3 4,502.9 20.6 778.6 799.2 0.0 80.3 26.5 (20.8) 298.4 5,686.4 133.1 2024 2,026.1 1,399.9 101.8 646.7 240.2 4,414.7 24.4 779.7 804.2 0.0 79.3 25.6 (22.0) 310.8 5,612.4 128.5 2025 2,040.1 1,424.8 103.6 663.6 235.5 4,467.5 52.1 998.2 1,050.3 0.0 85.6 32.1 (23.4) 323.5 5,935.5 133.0 2026 2,080.6 1,560.1 116.6 682.5 249.3 4,689.1 57.5 1,000.6 1,058.1 0.0 92.4 30.8 (24.7) 262.4 6,108.1 133.6 2027 2,129.3 1,700.5 127.9 700.8 252.4 4,911.0 51.1 1,015.5 1,066.6 0.0 101.9 30.4 (25.7) 258.3 6,342.4 135.4 2028 2,200.3 1,806.7 137.6 725.1 245.6 5,115.4 60.4 1,020.6 1,080.9 0.0 113.9 29.1 (27.1) 258.7 6,570.9 136.9 2029 2,277.8 1,978.7 151.9 750.7 261.8 5,420.8 47.9 1,019.4 1,067.3 0.0 128.5 27.6 (29.0) 251.9 6,867.2 139.3 2030 2,343.8 2,126.4 164.3 776.7 265.6 5,676.8 61.3 1,011.6 1,073.0 0.0 138.3 26.1 (31.0) 243.1 7,126.2 141.1 2031 2,404.8 2,262.7 175.3 803.6 259.8 5,906.2 48.6 1,012.9 1,061.5 0.0 148.7 24.5 (32.6) 232.8 7,341.0 142.0 2032 2,478.1 2,476.4 193.0 833.5 277.7 6,258.7 36.9 1,018.0 1,054.9 0.0 164.8 22.8 (35.6) 220.5 7,686.2 145.5 2033 2,552.2 2,613.1 204.5 862.2 281.6 6,513.6 44.6 1,049.9 1,094.5 0.0 171.0 22.7 (37.6) 206.4 7,970.7 147.2 2034 2,587.2 2,748.7 218.1 891.3 273.9 6,719.2 51.7 1,278.4 1,330.1 0.0 192.1 32.4 (40.9) 189.4 8,422.3 152.2 2035 2,620.0 2,926.3 234.2 920.5 291.6 6,992.6 58.3 1,321.5 1,379.8 0.0 206.9 32.3 (43.6) 170.0 8,737.9 154.5 2036 2,683.4 3,058.3 246.0 956.7 297.5 7,241.8 15.0 1,370.0 1,385.0 0.0 218.2 32.1 (47.1) 147.6 8,977.6 155.6 2037 2,727.3 3,257.1 264.7 968.5 290.2 7,507.9 71.5 1,414.6 1,486.1 0.0 237.3 31.9 (47.2) 122.1 9,338.1 158.3
CPW@ 7.86% (2008-2017) 4,181.6 5,247.4 304.9 2,887.9 294.8 12,916.7 709.9 2,920.9 3,630.8 (122.8) 313.9 155.8 (57.4) 813.7 17,650.8 78.1
(2008-2027) 9,872.7 9,715.2 628.2 4,701.0 990.2 25,907.3 934.2 5,106.9 6,041.1 (142.6) 580.0 232.9 (118.1) 1,683.5 34,184.1 95.4
(2008-2037) 13,518.1 13,324.9 911.3 5,937.6 1,393.8 35,085.7 1,008.8 6,774.6 7,783.4 (142.6) 823.4 274.2 (171.2) 2,000.7 45,653.8 104.5
APPENDIX 1 TABLE 2. TABLE 3. SELECTED RESOURCE PLAN TOTAL PLANT CO2 EMISSIONS (TONS)
2008 18,427,317 2009 18,425,326 2010 18,507,039 2011 18,210,227 2012 18,082,066 2013 18,029,948 2014 18,116,346 2015 18,334,339 2016 18,959,731 2017 19,800,098 2018 20,683,218 2019 20,661,418 2020 20,836,796 2021 21,151,801 2022 20,452,684 2023 18,603,274 2024 18,438,427 2025 18,244,232 2026 18,900,707 2027 19,755,186 2028 20,140,986 2029 21,008,087 2030 21,797,353 2031 22,323,630 2032 22,863,571 2033 23,575,620 2034 23,856,125 2035 24,682,127 2036 24,975,100 2037 25,491,598
(2008-2017) 184,892,438
(2008-2027) 382,620,180
(2008-2037) 613,334,378
APPENDIX 1 TABLE 3. TABLE 4. SELECTED RESOURCE PLAN ANNUAL NATURAL GAS BURNS (in BCF)
2008 73.6 2009 75.5 2010 73.2 2011 72.3 2012 68.2 2013 67.2 2014 74.1 2015 78.5 2016 86.7 2017 94.1 2018 100.7 2019 97.7 2020 104.4 2021 109.0 2022 105.6 2023 82.9 2024 83.1 2025 82.7 2026 91.8 2027 100.4 2028 106.0 2029 116.7 2030 124.5 2031 131.3 2032 146.3 2033 150.9 2034 157.9 2035 166.2 2036 170.3 2037 180.5
(2008-2017) 763.2
(2008-2027) 1,721.4
(2008-2037) 3,172.1
APPENDIX 1 TABLE 4. TABLE 5. SELECTED RESOURCE PLAN ANNUAL OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,551.8 2010 32,513.7 2011 32,626.2 2012 32,903.0 2013 33,089.0 2014 33,952.6 2015 34,996.8 2016 36,029.7 2017 37,059.4 2018 38,038.9 2019 38,996.2 2020 39,912.4 2021 40,832.2 2022 41,767.5 2023 42,708.9 2024 43,659.9 2025 44,622.6 2026 45,732.0 2027 46,853.5 2028 47,982.1 2029 49,282.4 2030 50,496.7 2031 51,711.1 2032 52,831.0 2033 54,139.8 2034 55,354.2 2035 56,568.5 2036 57,679.8 2037 58,997.1
APPENDIX 1 TABLE 5.
RESOURCE PLAN REPORT
APPENDIX 2
PORTFOLIO ANALYSIS ANNUAL TABLES
TABLE OF CONTENTS
APPENDIX 2
1. ENERGY EFFICIENCY ANALYSIS
1.1 Default Scenario (No Future EE)
Table 1 EE-D Loads and Resources Summary
Table 2 EE-D Total Revenue Requirements
Table 3 EE-D Own Load Energy Requirements (in GWh)
1.2 EE Scenario 1 (40% market potential, 50% incentive strategy, 0.6 PAF, $19.5M annual spending, 277 MW EE by 2025)
Table 4 EE-1 Loads and Resources Summary
Table 5 EE-1 Total Revenue Requirements
Table 6 EE-1 Own Load Energy Requirements (in GWh)
1.3 EE Scenario 2 (100% market potential, 50% incentive strategy, 0.6 PAF, $78M annual spending, 642 MW EE by 2025)
Table 7 EE-2 Loads and Resources Summary
Table 8 EE-2 Total Revenue Requirements
Table 9 EE-2 Own Load Energy Requirements (in GWh)
1.4 EE Scenario 3 (100% market potential, 75% incentive strategy, 0.6 PAF, $175M annual spending, 949 MW EE by 2025)
Table 10 EE-3 Loads and Resources Summary
Table 11 EE-3 Total Revenue Requirements
Table 12 EE-3 Own Load Energy Requirements (in GWh)
Appendix 2 Page i
TABLE OF CONTENTS – APPENDIX 2 (cont)
1.5 EE Scenario 4 (100% market potential, 100% incentive strategy, 0.6 PAF, $320M annual spending, 1,352 MW EE by 2025)
Table 13 EE-4 Loads and Resources Summary
Table 14 EE-4 Total Revenue Requirements
Table 15 EE-4 Own Load Energy Requirements (in GWh)
1.6 Comparison of Default Scenario to EE Scenarios
Table 16 EE Scenario Annual Natural Gas Burns (in BCF)
Table 17 EE Scenario Total Water Usage (in Acre-Feet)
Table 18 EE Scenario CO2 Total Plant Emissions (in Tons)
2. SUPPLY SIDE RESOURCE ANALYSIS
2.1 Default Scenario (All Gas)
Table 19 SS-D Loads and Resources Summary
Table 20 SS-D Total Revenue Requirements
Table 21 SS-D Own Load Energy Requirements (in GWh)
2.2 Nuclear Scenario (630 MW Nuclear Generation by 2025)
Table 22 SS-N Loads and Resources Summary
Table 23 SS-N Total Revenue Requirements
Table 24 SS-N Own Load Energy Requirements (in GWh)
Appendix 2 Page ii
TABLE OF CONTENTS – APPENDIX 2 (cont)
2.3 Solar Scenario 1 (1,400 MW CSP Generation by 2020)
Table 25 SS-S1 Loads and Resources Summary
Table 26 SS-S1 Total Revenue Requirements
Table 27 SS-S1 Own Load Energy Requirements (in GWh)
2.4 Solar Scenario 2 (700 MW CSP and 1,148 MW PV Generation by 2020)
Table 28 SS-S2 Loads and Resources Summary
Table 29 SS-S2 Total Revenue Requirements
Table 30 SS-S2 Own Load Energy Requirements (in GWh)
2.5 SS Scenario 1 (500 MW Nuclear and 290 MW Solar Generation by 2025)
Table 31 SS-1 Loads and Resources Summary
Table 32 SS-1 Total Revenue Requirements
Table 33 SS-1 Own Load Energy Requirements (in GWh)
2.6 SS Scenario 2 (650 MW Nuclear and 800 MW Solar Generation by 2025)
Table 34 SS-2 Loads and Resources Summary
Table 35 SS-2 Total Revenue Requirements
Table 36 SS-2 Own Load Energy Requirements (in GWh)
2.7 SS Scenario 3 (800 MW Nuclear and 400 MW Solar Generation by 2025)
Table 37 SS-3 Loads and Resources Summary
Table 38 SS-3 Total Revenue Requirements
Table 39 SS-3 Own Load Energy Requirements (in GWh)
Appendix 2 Page iii
TABLE OF CONTENTS – APPENDIX 2 (cont)
2.8 SS Scenario 4 (800 MW Nuclear and 2,000 MW Solar Generation by 2025)
Table 40 SS-4 Loads and Resources Summary
Table 41 SS-4 Total Revenue Requirements
Table 42 SS-4 Own Load Energy Requirements (in GWh)
2.9 Comparison of Default Scenario to SS Scenarios
Table 43 SS Scenario Annual Natural Gas Burns (in BCF)
Table 44 SS Scenario CO2 Total Plant Emissions (in Tons)
3. RISK ANALYSIS
3.1 Risk Analysis A (Carbon cost at $25/Ton)
Table 45 Selected Plan SP/A Total Revenue Requirements
Table 46 EE-D/A Total Revenue Requirements
Table 47 EE-1/A Total Revenue Requirements
Table 48 EE-2/A Total Revenue Requirements
Table 49 EE-3/A Total Revenue Requirements
Table 50 EE-4/A Total Revenue Requirements
Table 51 SS-D/A Total Revenue Requirements
Table 52 SS-N/A Total Revenue Requirements
Table 53 SS-S1/A Total Revenue Requirements
Table 54 SS-S2/A Total Revenue Requirements
Appendix 2 Page iv
TABLE OF CONTENTS – APPENDIX 2 (cont)
3.1 Risk Analysis A (Carbon cost at $25/Ton) (cont)
Table 55 SS-1/A Total Revenue Requirements
Table 56 SS-2/A Total Revenue Requirements
Table 57 SS-3/A Total Revenue Requirements
Table 58 SS-4/A Total Revenue Requirements
3.2 Risk Analysis B (Carbon cost at $50/Ton)
Table 59 Selected Plan SP/B Total Revenue Requirements
Table 60 EE-D/B Total Revenue Requirements
Table 61 EE-1/B Total Revenue Requirements
Table 62 EE-2/B Total Revenue Requirements
Table 63 EE-3/B Total Revenue Requirements
Table 64 EE-4/B Total Revenue Requirements
Table 65 SS-D/B Total Revenue Requirements
Table 66 SS-N/B Total Revenue Requirements
Table 67 SS-S1/B Total Revenue Requirements
Table 68 SS-S2/B Total Revenue Requirements
Table 69 SS-1/B Total Revenue Requirements
Table 70 SS-2/B Total Revenue Requirements
Table 71 SS-3/B Total Revenue Requirements
Table 72 SS-4/B Total Revenue Requirements
Appendix 2 Page v
TABLE OF CONTENTS – APPENDIX 2 (cont)
3.3 Risk Analysis C (Natural gas cost increase of 30%)
Table 73 Selected Plan SP/C Total Revenue Requirements
Table 74 EE-D/C Total Revenue Requirements
Table 75 EE-1/C Total Revenue Requirements
Table 76 EE-2/C Total Revenue Requirements
Table 77 EE-3/C Total Revenue Requirements
Table 78 EE-4/C Total Revenue Requirements
Table 79 SS-D/C Total Revenue Requirements
Table 80 SS-N/C Total Revenue Requirements
Table 81 SS-S1/C Total Revenue Requirements
Table 82 SS-S2/C Total Revenue Requirements
Table 83 SS-1/C Total Revenue Requirements
Table 84 SS-2/C Total Revenue Requirements
Table 85 SS-3/C Total Revenue Requirements
Table 86 SS-4/C Total Revenue Requirements
3.4 Risk Analysis D (Cost of Solar increases at 1.5% annually, other costs increase at rate of inflation of 3.0%)
Table 87 Selected Plan SP/D Total Revenue Requirements
Table 88 SS-D/D Total Revenue Requirements
Table 89 SS-N/D Total Revenue Requirements
Table 90 SS-S1/D Total Revenue Requirements
Appendix 2 Page vi
TABLE OF CONTENTS – APPENDIX 2 (cont)
Table 91 SS-S2/D Total Revenue Requirements
Table 92 SS-1/D Total Revenue Requirements
Table 93 SS-2/D Total Revenue Requirements
Table 94 SS-3/D Total Revenue Requirements
Table 95 SS-4/D Total Revenue Requirements
3.5 Risk Analysis E (No PTC available after 2009, no ITC available after 2016)
Table 96 Selected Plan SP/E Total Revenue Requirements
Table 97 SS-D/E Total Revenue Requirements
Table 98 SS-N/E Total Revenue Requirements
Table 99 SS-S1/E Total Revenue Requirements
Table 100 SS-S2/E Total Revenue Requirements
Table 101 SS-1/E Total Revenue Requirements
Table 102 SS-2/E Total Revenue Requirements
Table 103 SS-3/E Total Revenue Requirements
Table 104 SS-4/E Total Revenue Requirements
3.6 Risk Analysis F (Cost of Nuclear Generation increases by 25%)
Table 105 Selected Plan SP/F Total Revenue Requirements
Table 106 SS-N/F Total Revenue Requirements
Table 107 SS-1/F Total Revenue Requirements
Table 108 SS-2/F Total Revenue Requirements
Appendix 2 Page vii
TABLE OF CONTENTS – APPENDIX 2 (cont)
3.6 Risk Analysis F (Cost of Nuclear Generation increases by 25%) (cont)
Table 109 SS-3/F Total Revenue Requirements
Table 110 SS-4/F Total Revenue Requirements
Appendix 2 Page viii
TABLE 1. DEFAULT ENERGY EFFICIENCY SCENARIO (EE-D) NO FUTURE ENERGY EFFICIENCY LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 00007070707070707070150150430430520 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 000000000005281,056 1,056 1,056 1,056 1,056 20. Peaking Resources 00000008461,692 2,068 2,350 2,726 3,008 3,478 3,572 3,854 4,230 21. Short-Term Market Purchases 00000121467456469435487465448453414459428 22. Total Future Resource Additions: 16 26 39 55 135 266 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 459 459 459 459 459 559 559 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 Table 1. TABLE 2. DEFAULT ENERGY EFFICIENCY SCENARIO (EE-D) NO FUTURE ENERGY EFFICIENCY TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 26.6 2,134.4 66.3 2009 549.1 800.3 43.0 412.2 8.6 1,813.3 85.7 309.4 395.1 (8.3) 43.8 14.7 (1.2) 56.0 2,313.4 70.7 2010 573.3 763.9 42.8 422.9 20.9 1,823.9 120.7 341.1 461.8 (9.1) 44.4 24.8 (9.5) 54.8 2,391.2 72.7 2011 580.5 796.7 44.4 419.9 28.5 1,870.0 101.8 309.4 411.2 (10.0) 47.3 29.2 (9.9) 67.0 2,404.8 72.4 2012 578.7 721.4 42.1 423.8 30.7 1,796.7 104.2 457.6 561.8 (14.0) 45.9 28.2 (10.5) 84.9 2,493.1 74.0 2013 583.5 742.5 44.9 429.0 49.2 1,849.1 104.8 496.3 601.1 (19.0) 49.8 28.2 (10.8) 51.4 2,550.0 74.9 2014 597.5 873.2 52.8 446.3 91.2 2,060.9 119.7 465.9 585.6 (24.3) 58.0 25.8 (11.6) 54.9 2,749.3 78.4 2015 641.6 915.8 55.8 463.2 103.8 2,180.2 151.2 529.0 680.2 (33.0) 62.5 23.1 (12.1) 58.3 2,959.2 81.5 2016 843.0 988.2 62.6 440.5 140.5 2,474.7 157.8 553.0 710.8 (37.0) 69.9 20.2 (12.7) 93.4 3,319.3 88.4 2017 1,017.2 1,221.6 79.8 458.3 175.7 2,952.7 156.0 439.1 595.0 (39.2) 77.0 17.2 (13.4) 100.0 3,689.3 95.1 2018 1,116.3 1,371.1 92.1 476.4 184.5 3,240.4 125.2 372.2 497.4 (38.4) 85.6 15.0 (14.3) 107.3 3,893.0 97.4 2019 1,148.9 1,447.9 98.7 491.8 180.6 3,367.9 124.0 409.8 533.8 (5.2) 95.4 14.3 (15.2) 114.3 4,105.3 99.8 2020 1,295.6 1,668.9 120.0 516.0 193.4 3,793.8 66.9 285.6 352.5 (2.6) 99.7 11.9 (16.5) 121.1 4,359.8 103.2 2021 1,519.6 1,773.5 137.7 549.7 199.8 4,180.3 67.3 344.1 411.5 0.0 109.6 15.2 (17.5) 127.8 4,827.0 111.4 2022 1,666.1 1,917.0 153.6 575.1 196.6 4,508.4 52.1 320.2 372.3 0.0 128.5 14.5 (18.8) 134.8 5,139.6 115.7 2023 1,635.1 1,978.3 158.5 594.3 191.8 4,558.0 52.3 453.3 505.6 0.0 126.6 18.5 (20.1) 142.6 5,331.2 117.1 2024 1,644.1 2,117.7 170.3 607.2 206.0 4,745.4 53.0 457.5 510.5 0.0 136.0 17.8 (21.1) 150.3 5,538.8 118.8 2025 1,685.9 2,172.4 175.9 624.1 212.3 4,870.5 51.9 607.6 659.4 0.0 144.0 24.5 (22.3) 158.2 5,834.4 122.2 2026 1,740.5 2,331.5 188.7 642.3 207.3 5,110.3 46.7 612.2 658.8 0.0 152.6 23.5 (23.8) 92.2 6,013.6 122.7 2027 1,859.3 2,457.9 206.9 664.3 202.5 5,390.9 9.8 630.1 640.0 0.0 163.0 22.4 (24.8) 92.2 6,283.7 125.1 2028 1,935.4 2,612.7 225.9 689.6 218.5 5,682.1 54.7 639.9 694.6 0.0 176.4 21.3 (26.1) 98.1 6,646.3 129.1 2029 1,995.8 2,806.4 243.2 713.3 223.3 5,982.0 48.7 644.3 692.9 0.0 195.1 20.1 (28.1) 98.0 6,959.9 131.5 2030 2,099.1 3,002.2 261.9 739.3 218.7 6,321.2 34.1 640.3 674.3 0.0 208.6 18.8 (30.1) 97.3 7,290.1 134.4 2031 2,153.3 3,128.7 275.2 764.6 237.4 6,559.2 39.9 771.1 811.0 0.0 221.6 25.4 (31.7) 96.8 7,682.3 138.2 2032 2,177.5 3,343.0 296.1 791.2 243.0 6,850.8 53.8 862.3 916.1 0.0 237.9 28.9 (34.8) 96.2 8,095.1 142.4 2033 2,246.9 3,527.6 314.0 818.0 237.0 7,143.5 52.0 898.6 950.5 0.0 250.9 29.2 (36.9) 95.9 8,433.3 144.8 2034 2,349.4 3,762.0 340.7 847.7 259.6 7,559.4 41.2 938.9 980.1 0.0 280.2 29.5 (40.2) 95.1 8,904.1 149.4 2035 2,454.9 3,930.4 356.8 877.7 264.0 7,883.9 30.1 978.8 1,008.9 0.0 294.1 29.8 (42.9) 94.4 9,268.3 152.1 2036 2,525.0 4,139.9 377.1 912.4 257.7 8,212.2 69.0 1,026.5 1,095.5 0.0 310.9 30.1 (46.3) 93.8 9,696.1 156.0 2037 2,566.2 4,344.0 401.0 922.6 253.8 8,487.7 36.7 1,069.8 1,106.5 0.0 327.5 30.3 (46.5) 93.3 9,998.8 157.7
CPW@ 7.86% (2008-2017) 4,216.7 5,627.0 329.2 2,893.1 369.3 13,435.2 758.3 2,697.4 3,455.7 (122.8) 346.6 150.3 (57.0) 415.1 17,623.1 76.3
(2008-2027) 8,909.3 11,489.6 780.8 4,670.9 989.5 26,840.0 984.7 4,055.1 5,039.7 (142.6) 723.2 204.2 (116.2) 807.6 33,356.0 89.8
(2008-2037) 12,190.3 16,458.8 1,222.9 5,847.1 1,343.5 37,062.6 1,053.4 5,265.7 6,319.1 (142.6) 1,080.0 242.2 (168.1) 950.7 45,343.9 99.5
APPENDIX 2 TABLE 2. TABLE 3. DEFAULT ENERGY EFFICIENCY SCENARIO (EE-D) NO FUTURE ENERGY EFFICIENCY OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,385.0
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,104.9
APPENDIX 2 TABLE 3. TABLE 4. ENERGY EFFICIENCY SCENARIO 1 (EE-1) 40% MARKET POTENTIAL, 50% INCENTIVE STRATEGY, 0.6 PAF, $19.5M ANNUAL SPENDING, 277 MW EE by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 996 1,026 1,036 1,052 1,066 1,105 1,149 1,197 1,244 1,290 1,335 1,379 1,495 1,539 1,584 1,629 1,675 4. Total Load Requirements 8,317 8,398 8,510 8,664 8,787 9,110 9,466 9,841 10,220 10,583 10,940 11,284 11,702 12,052 12,403 12,757 13,116
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 00000000000000000 13. Total Existing Resources: 8,190 8,520 8,520 8,790 8,786 8,786 8,786 8,285 7,785 7,785 7,785 7,225 6,745 6,595 6,585 6,585 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 25 55 86 115 138 157 173 187 200 211 222 233 242 252 261 269 277 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000100100100100100100100100150150430430520 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 000000000005281,056 1,056 1,056 1,056 1,056 20. Peaking Resources 00000007161,584 1,924 2,206 2,546 2,792 3,320 3,320 3,660 3,848 21. Short-Term Market Purchases 000000321446422411451453491426471449491 22. Total Future Resource Additions: 41 81 125 171 303 332 680 1,555 2,435 2,798 3,155 4,059 4,957 5,457 5,818 6,172 6,532
23. Total Resources: 8,231 8,601 8,646 8,961 9,089 9,118 9,466 9,841 10,220 10,583 10,940 11,284 11,702 12,052 12,403 12,757 13,116
New Renewable Nameplate Capacity ● 100 106 106 389 489 489 489 489 489 489 589 589 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 Table 4. TABLE 5. ENERGY EFFICIENCY SCENARIO 1 (EE-1) 40% MARKET POTENTIAL, 50% INCENTIVE STRATEGY, 0.6 PAF, $19.5M ANNUAL SPENDING, 277 MW EE by 2025 LOADS AND RESOURCES SUMMARY (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 50.0 2,157.7 67.1 2009 549.1 790.6 42.5 412.2 8.6 1,803.0 83.6 307.3 390.9 (8.3) 43.3 14.7 (1.2) 82.4 2,324.8 71.4 2010 573.3 743.5 42.3 422.9 20.9 1,802.9 119.4 336.8 456.2 (9.1) 43.3 24.8 (9.5) 84.0 2,392.7 73.6 2011 580.5 767.4 43.0 419.9 28.5 1,839.2 102.1 302.8 404.9 (10.0) 45.3 29.2 (10.0) 88.3 2,387.0 73.2 2012 578.7 686.2 40.2 423.8 30.7 1,759.6 104.5 449.8 554.2 (14.0) 44.1 28.2 (10.5) 108.1 2,469.8 75.0 2013 583.5 702.9 42.5 429.0 49.2 1,807.2 105.0 485.8 590.8 (19.0) 46.8 28.2 (10.9) 74.9 2,518.1 75.9 2014 597.5 822.7 50.0 446.3 77.8 1,994.3 105.5 457.6 563.0 (24.3) 54.5 25.8 (11.7) 78.7 2,680.4 78.5 2015 629.5 864.6 52.2 462.7 97.5 2,106.5 133.5 517.1 650.6 (33.0) 58.5 23.1 (12.2) 82.7 2,876.4 81.5 2016 808.1 927.3 58.4 438.9 141.1 2,373.8 156.8 544.4 701.2 (37.0) 65.2 20.2 (12.7) 118.3 3,229.1 88.6 2017 975.6 1,151.7 74.5 456.4 160.7 2,818.9 156.6 433.2 589.7 (39.2) 71.7 17.2 (13.4) 125.7 3,570.6 94.9 2018 1,078.1 1,294.9 86.6 474.5 178.4 3,112.4 120.0 365.8 485.8 (38.4) 79.5 15.0 (14.3) 133.8 3,773.8 97.3 2019 1,109.9 1,364.5 92.4 489.6 182.0 3,238.3 122.5 403.8 526.3 (5.2) 88.7 14.3 (15.2) 141.6 3,988.8 100.0 2020 1,256.3 1,575.3 113.3 513.6 179.0 3,637.6 67.3 283.3 350.7 (2.6) 92.4 11.9 (16.5) 149.2 4,222.6 103.2 2021 1,469.8 1,677.8 130.5 546.9 194.4 4,019.4 69.5 342.3 411.8 0.0 102.3 15.2 (17.5) 156.9 4,688.0 111.7 2022 1,609.8 1,812.9 145.2 572.0 199.7 4,339.6 54.8 320.3 375.0 0.0 120.1 14.5 (18.9) 164.7 4,995.0 116.1 2023 1,581.2 1,869.5 149.9 591.1 194.9 4,386.5 53.0 453.3 506.3 0.0 118.2 18.5 (20.2) 173.5 5,182.9 117.6 2024 1,592.5 2,002.1 160.9 604.0 190.1 4,549.5 52.0 457.7 509.6 0.0 126.8 17.8 (21.2) 182.2 5,364.8 118.9 2025 1,633.5 2,051.1 165.9 620.4 206.0 4,677.0 55.7 607.5 663.2 0.0 134.2 24.5 (22.4) 191.1 5,667.5 122.7 2026 1,674.2 2,202.8 177.8 638.0 211.6 4,904.4 57.6 613.0 670.6 0.0 142.2 23.5 (23.9) 126.0 5,842.8 123.2 2027 1,785.9 2,324.3 195.3 659.5 207.2 5,172.2 20.7 630.6 651.3 0.0 152.2 22.4 (24.9) 125.2 6,098.5 125.4 2028 1,880.5 2,472.0 213.5 685.1 201.4 5,452.6 55.7 639.2 694.9 0.0 164.9 21.3 (26.2) 130.0 6,437.5 129.2 2029 1,938.7 2,657.5 230.0 708.5 218.4 5,753.1 56.0 645.6 701.6 0.0 183.0 20.1 (28.2) 128.6 6,758.2 132.0 2030 2,033.5 2,844.1 248.0 734.0 224.1 6,083.7 39.1 641.0 680.0 0.0 195.8 18.8 (30.2) 126.3 7,074.5 134.7 2031 2,107.4 2,964.0 260.1 759.7 219.2 6,310.4 34.3 770.3 804.7 0.0 207.6 25.4 (31.7) 123.8 7,440.2 138.3 2032 2,145.4 3,169.0 280.3 786.4 239.1 6,620.2 46.5 861.3 907.8 0.0 223.4 28.9 (34.9) 121.0 7,866.3 143.0 2033 2,216.2 3,344.5 297.1 813.1 245.4 6,916.2 43.1 897.4 940.5 0.0 235.7 29.2 (36.9) 117.9 8,202.7 145.4 2034 2,297.6 3,565.1 322.2 841.8 239.8 7,266.5 54.6 939.1 993.8 0.0 263.8 29.5 (40.2) 113.8 8,627.2 149.5 2035 2,370.4 3,726.7 337.4 870.5 260.3 7,565.2 50.6 981.1 1,031.7 0.0 277.3 29.8 (42.9) 109.5 8,970.7 152.1 2036 2,454.6 3,928.6 356.8 905.5 268.0 7,913.6 27.2 1,026.0 1,053.2 0.0 293.1 30.1 (46.3) 104.5 9,348.1 155.3 2037 2,511.5 4,120.8 379.4 915.8 263.0 8,190.5 88.2 1,070.3 1,158.5 0.0 309.0 30.3 (46.6) 99.0 9,740.9 158.7
CPW@ 7.86% (2008-2017) 4,172.9 5,410.2 316.2 2,891.1 351.3 13,141.6 737.6 2,656.8 3,394.3 (122.8) 331.6 150.3 (57.1) 581.3 17,419.3 76.8
(2008-2027) 8,707.5 10,948.7 742.4 4,659.5 960.1 26,018.1 968.8 4,008.1 4,976.9 (142.6) 682.5 204.2 (116.6) 1,068.3 32,690.8 90.1
(2008-2037) 11,908.0 15,658.0 1,160.5 5,827.7 1,307.4 35,861.6 1,041.6 5,218.8 6,260.4 (142.6) 1,017.8 242.2 (168.5) 1,246.0 44,316.8 99.7
APPENDIX 2 TABLE 5. TABLE 6. ENERGY EFFICIENCY SCENARIO 1 (EE-1) 40% MARKET POTENTIAL, 50% INCENTIVE STRATEGY, 0.6 PAF, $19.5M ANNUAL SPENDING, 277 MW EE by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,551.8 2010 32,513.7 2011 32,626.2 2012 32,944.3 2013 33,185.3 2014 34,131.7 2015 35,280.2 2016 36,450.1 2017 37,642.5 2018 38,773.0 2019 39,871.5 2020 40,920.5 2021 41,965.6 2022 43,020.1 2023 44,074.6 2024 45,133.5 2025 46,199.7 2026 47,407.9 2027 48,623.2 2028 49,841.3 2029 51,215.5 2030 52,512.0 2031 53,808.6 2032 55,019.3 2033 56,401.7 2034 57,698.2 2035 58,994.8 2036 60,197.4 2037 61,372.1
(2008-2017) 339,497.5
(2008-2027) 775,487.0
(2008-2037) 1,332,547.8
APPENDIX 2 TABLE 6. TABLE 7. ENERGY EFFICIENCY SCENARIO 2 (EE-2) 100% MARKET POTENTIAL, 50% INCENTIVE STRATEGY, 0.6 PAF, $78M ANNUAL SPENDING, 642 MW EE by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 987 1,010 1,017 1,031 1,041 1,077 1,119 1,163 1,208 1,251 1,294 1,335 1,448 1,491 1,533 1,576 1,620 4. Total Load Requirements 8,308 8,382 8,491 8,642 8,763 9,083 9,435 9,807 10,184 10,544 10,898 11,240 11,656 12,003 12,353 12,704 13,062
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 00000000000000000 13. Total Existing Resources: 8,190 8,520 8,520 8,790 8,786 8,786 8,786 8,285 7,785 7,785 7,785 7,225 6,745 6,595 6,585 6,585 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 88 158 214 261 304 342 378 411 442 472 500 526 551 576 599 621 642 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000100100100100100100100100150150430430520 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 000000000005281,056 1,056 1,056 1,056 1,056 20. Peaking Resources 00000004701,244 1,584 1,924 2,206 2,452 2,886 2,980 3,226 3,508 21. Short-Term Market Purchases 00000085435484452414455475488422477411 22. Total Future Resource Additions: 104 184 253 317 469 517 649 1,522 2,398 2,759 3,113 4,015 4,911 5,408 5,768 6,120 6,477
23. Total Resources: 8,294 8,704 8,773 9,107 9,255 9,303 9,435 9,807 10,184 10,544 10,898 11,240 11,656 12,003 12,353 12,704 13,062
New Renewable Nameplate Capacity ● 100 106 106 389 489 489 489 489 489 489 589 589 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 7. TABLE 8. ENERGY EFFICIENCY SCENARIO 2 (EE-2) 10% MARKET POTENTIAL, 50% INCENTIVE STRATEGY, 0.6 PAF, $78M ANNUAL SPENDING, 642 MW EE by 2025) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 103.2 2,210.9 68.7 2009 549.1 778.3 41.9 412.2 8.6 1,790.2 78.4 302.8 381.2 (8.3) 42.6 14.7 (1.2) 139.4 2,358.7 73.0 2010 573.3 722.2 41.3 422.9 20.9 1,780.6 116.2 332.0 448.2 (9.1) 42.1 24.8 (9.5) 139.0 2,416.2 75.2 2011 580.5 741.4 42.0 419.9 28.5 1,812.3 102.6 298.4 401.1 (10.0) 43.6 29.2 (10.0) 152.6 2,418.9 75.1 2012 578.7 657.4 38.5 423.8 30.7 1,729.1 105.0 443.7 548.7 (14.0) 42.2 28.2 (10.5) 172.8 2,496.5 77.0 2013 583.5 671.6 40.6 429.0 49.2 1,773.9 105.6 476.1 581.6 (19.0) 44.4 28.2 (10.9) 141.1 2,539.4 78.0 2014 597.5 782.8 47.8 446.3 66.1 1,940.5 106.0 449.4 555.3 (24.3) 51.8 25.8 (11.7) 147.1 2,684.5 80.4 2015 629.5 820.3 49.8 462.7 90.1 2,052.4 113.7 506.8 620.5 (33.0) 54.8 23.1 (12.2) 153.3 2,859.0 83.0 2016 780.9 876.2 54.7 437.7 138.7 2,288.1 143.8 534.4 678.2 (37.0) 60.7 20.2 (12.7) 191.3 3,188.9 89.8 2017 917.4 1,087.7 69.8 453.7 161.2 2,689.8 164.3 426.1 590.4 (39.2) 66.9 17.2 (13.5) 200.9 3,512.6 96.0 2018 1,013.2 1,221.1 81.2 471.4 163.6 2,950.5 130.1 360.4 490.5 (38.4) 73.4 15.0 (14.4) 211.6 3,688.2 98.0 2019 1,050.1 1,282.5 86.4 486.6 176.1 3,081.7 123.3 398.6 521.9 (5.2) 82.0 14.3 (15.3) 221.8 3,901.3 100.9 2020 1,198.2 1,481.2 106.4 510.4 180.5 3,476.7 66.8 280.6 347.4 (2.6) 84.7 11.9 (16.6) 232.0 4,133.6 104.3 2021 1,412.2 1,576.8 123.1 543.5 179.6 3,835.1 69.8 340.3 410.1 0.0 94.1 15.2 (17.6) 242.4 4,579.4 112.9 2022 1,539.3 1,702.9 136.4 567.9 176.6 4,123.1 62.1 320.7 382.8 0.0 111.1 14.5 (19.0) 252.8 4,865.3 117.1 2023 1,518.4 1,751.6 140.7 587.0 190.2 4,187.9 53.7 452.3 506.0 0.0 108.8 18.5 (20.2) 264.0 5,065.0 119.1 2024 1,527.3 1,875.7 151.0 599.6 194.9 4,348.5 52.9 457.3 510.3 0.0 116.3 17.8 (21.2) 275.2 5,246.8 120.6 2025 1,576.4 1,917.0 155.0 616.1 192.1 4,456.6 50.0 606.4 656.4 0.0 123.4 24.5 (22.5) 287.3 5,525.6 124.1 2026 1,614.3 2,061.3 166.3 633.3 207.1 4,682.3 53.0 612.7 665.7 0.0 130.3 23.5 (24.0) 224.8 5,702.6 124.9 2027 1,647.8 2,196.6 178.9 649.3 212.0 4,884.6 59.4 633.0 692.4 0.0 142.2 22.4 (25.0) 220.8 5,937.4 126.8 2028 1,736.1 2,344.0 192.9 672.6 206.9 5,152.4 49.4 639.5 688.9 0.0 155.2 21.3 (26.3) 220.9 6,212.5 129.5 2029 1,825.5 2,524.9 208.4 696.6 225.2 5,480.6 46.9 644.7 691.6 0.0 172.6 20.1 (28.3) 215.7 6,552.3 132.9 2030 1,904.7 2,702.9 224.8 721.0 230.2 5,783.7 48.7 642.3 691.0 0.0 185.1 18.8 (30.2) 208.8 6,857.1 135.7 2031 1,969.4 2,817.1 236.2 745.7 224.8 5,993.2 40.0 771.2 811.2 0.0 196.5 25.4 (31.8) 200.8 7,195.3 138.9 2032 2,012.2 3,014.1 254.4 772.1 244.6 6,297.3 48.9 861.4 910.3 0.0 211.3 28.9 (34.9) 191.3 7,604.1 143.6 2033 2,087.4 3,179.8 270.1 798.3 250.8 6,586.5 42.3 897.7 940.0 0.0 222.7 29.2 (36.9) 180.4 7,922.0 146.0 2034 2,173.0 3,396.8 293.9 826.6 245.0 6,935.1 50.5 939.3 989.8 0.0 250.4 29.5 (40.2) 167.2 8,331.9 150.1 2035 2,269.0 3,547.2 308.0 855.3 237.5 7,217.0 33.3 979.4 1,012.7 0.0 263.1 29.8 (42.9) 152.2 8,631.9 152.1 2036 2,345.9 3,738.5 325.9 889.3 261.5 7,561.2 66.3 1,025.8 1,092.1 0.0 277.5 30.1 (46.4) 134.9 9,049.5 156.3 2037 2,393.8 3,927.2 346.7 898.8 270.0 7,836.6 28.2 1,070.2 1,098.4 0.0 293.3 30.3 (46.6) 115.3 9,327.3 158.0
CPW@ 7.86% (2008-2017) 4,131.8 5,220.1 305.2 2,889.2 339.3 12,885.7 718.3 2,616.6 3,334.9 (122.8) 317.9 150.3 (57.3) 1,008.5 17,517.3 78.4
(2008-2027) 8,453.7 10,421.8 704.0 4,644.4 923.7 25,147.6 962.9 3,961.8 4,924.7 (142.6) 641.4 204.2 (117.0) 1,772.5 32,430.8 91.4
(2008-2037) 11,467.4 14,900.1 1,084.2 5,791.7 1,274.9 34,518.3 1,031.0 5,172.6 6,203.6 (142.6) 958.6 242.2 (168.9) 2,048.8 43,660.0 100.7
APPENDIX 2 TABLE 8. TABLE 9. ENERGY EFFICIENCY SCENARIO 2 (EE-2) 100% MARKET POTENTIAL, 50% INCENTIVE STRATEGY, 0.6 PAF, $78M ANNUAL SPENDING, 642 MW EE by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,317.5 2010 32,139.9 2011 32,188.4 2012 32,403.8 2013 32,538.8 2014 33,381.6 2015 34,428.7 2016 35,501.2 2017 36,598.8 2018 37,638.6 2019 38,649.4 2020 39,614.5 2021 40,578.8 2022 41,555.1 2023 42,534.7 2024 43,522.9 2025 44,522.5 2026 45,665.1 2027 46,818.0 2028 47,976.9 2029 49,304.2 2030 50,547.4 2031 51,790.5 2032 52,940.8 2033 54,276.9 2034 55,520.0 2035 56,763.2 2036 57,904.8 2037 59,033.9
(2008-2017) 333,670.3
(2008-2027) 754,769.8
(2008-2037) 1,290,828.4
APPENDIX 2 TABLE 9. TABLE 10. ENERGY EFFICIENCY SCENARIO 3 (EE-3) 100% MARKET POTENTIAL, 75% INCENTIVE STRATEGY, 0.6 PAF, $175M ANNUAL SPENDING, 949 MW EE by 2025) LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 981 1,000 1,003 1,013 1,020 1,054 1,093 1,134 1,177 1,218 1,258 1,298 1,409 1,449 1,490 1,532 1,574 4. Total Load Requirements 8,302 8,372 8,477 8,625 8,742 9,059 9,409 9,779 10,153 10,511 10,863 11,203 11,617 11,962 12,310 12,660 13,016
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 00000000000000000 13. Total Existing Resources: 8,190 8,520 8,520 8,790 8,786 8,786 8,786 8,285 7,785 7,785 7,785 7,225 6,745 6,595 6,585 6,585 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 125 226 308 379 443 500 553 602 649 693 735 775 813 850 884 918 949 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000100100100100100100100100150150430430520 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 000000000000528528528528528 20. Peaking Resources 00000001881,056 1,338 1,584 2,452 2,734 3,168 3,168 3,414 3,660 21. Short-Term Market Purchases 0000000496434443483451421419434477434 22. Total Future Resource Additions: 140 252 347 434 607 675 739 1,493 2,367 2,726 3,078 3,977 4,871 5,367 5,725 6,075 6,431
23. Total Resources: 8,330 8,772 8,868 9,224 9,393 9,460 9,524 9,779 10,153 10,511 10,863 11,203 11,617 11,962 12,310 12,660 13,016
New Renewable Nameplate Capacity ● 100 106 106 389 489 489 489 489 489 489 589 589 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 10. TABLE 11. ENERGY EFFICIENCY SCENARIO 3 (EE-3) 100% MARKET POTENTIAL, 75% INCENTIVE STRATEGY, 0.6 PAF, $175 ANNUAL SPENDING, 949 MW EE by 2025 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 179.8 2,287.5 71.1 2009 549.1 768.3 41.5 412.2 8.6 1,779.8 77.4 301.6 379.0 (8.3) 42.1 14.7 (1.2) 247.2 2,453.3 76.3 2010 573.3 704.5 40.7 422.9 20.9 1,762.4 115.6 328.3 443.9 (9.1) 41.1 24.8 (9.5) 245.9 2,499.5 78.5 2011 580.5 718.6 40.8 419.9 28.5 1,788.3 102.8 294.0 396.7 (10.0) 42.2 29.2 (10.0) 259.0 2,495.5 78.6 2012 578.7 631.2 37.1 423.8 30.7 1,701.5 105.1 435.8 541.0 (14.0) 40.6 28.2 (10.6) 282.5 2,569.3 80.7 2013 583.5 641.4 38.7 429.0 49.2 1,741.9 105.7 468.0 573.7 (19.0) 42.1 28.2 (10.9) 250.8 2,606.8 81.8 2014 597.5 743.9 45.8 446.3 66.1 1,899.6 106.1 442.3 548.4 (24.3) 48.9 25.8 (11.7) 259.6 2,746.3 84.2 2015 629.5 776.9 47.4 462.7 78.0 1,994.6 106.5 497.0 603.4 (33.0) 51.7 23.1 (12.2) 269.4 2,897.0 86.2 2016 743.4 827.1 51.4 436.2 110.1 2,168.1 144.8 526.4 671.2 (37.0) 57.3 20.2 (12.8) 311.2 3,178.2 91.9 2017 867.9 1,029.1 65.7 451.5 146.1 2,560.3 164.0 419.0 583.1 (39.2) 62.3 17.2 (13.5) 324.6 3,494.8 98.2 2018 972.5 1,154.5 76.9 469.3 161.5 2,834.7 126.7 353.8 480.5 (38.4) 68.2 15.0 (14.4) 340.0 3,685.5 100.8 2019 995.6 1,208.9 81.5 483.8 179.0 2,948.8 130.2 392.7 523.0 (5.2) 76.3 14.3 (15.3) 354.3 3,896.1 103.9 2020 1,112.5 1,413.4 97.2 504.5 183.9 3,311.5 71.3 283.6 354.9 (2.6) 80.6 11.9 (16.6) 369.0 4,108.7 107.0 2021 1,324.6 1,505.9 110.0 535.9 199.4 3,675.8 64.1 342.6 406.6 0.0 90.0 15.2 (17.6) 384.6 4,554.7 115.8 2022 1,462.8 1,629.4 123.0 560.3 204.0 3,979.5 51.5 319.6 371.1 0.0 106.6 14.5 (19.0) 399.1 4,851.8 120.6 2023 1,428.4 1,673.4 126.7 578.6 198.7 4,005.8 51.2 452.7 503.9 0.0 103.7 18.5 (20.3) 413.7 5,025.4 122.1 2024 1,429.1 1,790.8 135.9 590.4 193.8 4,140.0 55.3 457.7 512.9 0.0 110.4 17.8 (21.3) 428.6 5,188.4 123.3 2025 1,467.9 1,827.0 139.5 606.3 191.0 4,231.7 54.0 608.0 662.0 0.0 117.0 24.5 (22.6) 446.7 5,459.3 126.8 2026 1,514.2 1,962.1 149.7 623.3 186.7 4,436.0 53.1 612.8 665.9 0.0 123.0 23.5 (24.1) 387.7 5,612.1 127.2 2027 1,630.1 2,074.1 165.6 644.2 203.7 4,717.7 13.8 630.1 643.9 0.0 132.6 22.4 (25.1) 377.6 5,869.1 129.7 2028 1,715.9 2,204.6 181.3 668.9 209.4 4,980.2 51.7 639.7 691.4 0.0 143.8 21.3 (26.3) 370.1 6,180.5 133.3 2029 1,766.8 2,376.3 195.9 691.2 203.4 5,233.6 59.8 644.5 704.3 0.0 159.8 20.1 (28.4) 358.7 6,448.1 135.4 2030 1,846.9 2,545.2 211.6 715.2 198.0 5,517.0 58.4 642.2 700.6 0.0 171.3 18.8 (30.3) 344.2 6,721.6 137.6 2031 1,914.6 2,651.5 221.7 739.8 218.0 5,745.7 47.0 770.7 817.7 0.0 182.0 25.4 (31.9) 327.1 7,066.0 141.2 2032 1,959.8 2,843.3 239.3 765.9 224.8 6,033.1 53.2 861.5 914.7 0.0 196.7 28.9 (35.0) 306.7 7,445.1 145.6 2033 2,037.3 2,996.8 253.6 792.0 218.5 6,298.3 43.7 897.2 940.8 0.0 207.8 29.2 (37.0) 283.1 7,722.2 147.3 2034 2,125.3 3,199.1 275.8 820.0 239.9 6,660.1 49.1 938.9 988.0 0.0 233.3 29.5 (40.3) 254.9 8,125.5 151.5 2035 2,205.0 3,345.3 289.2 848.1 246.5 6,934.1 39.0 979.9 1,019.0 0.0 244.5 29.8 (43.0) 222.4 8,406.8 153.3 2036 2,273.1 3,528.4 306.1 881.5 241.6 7,230.8 59.8 1,026.0 1,085.8 0.0 259.0 30.1 (46.5) 184.9 8,744.1 156.3 2037 2,322.5 3,708.1 324.5 890.4 236.7 7,482.2 64.3 1,070.9 1,135.2 0.0 274.2 30.3 (46.6) 142.0 9,017.4 158.1
CPW@ 7.86% (2008-2017) 4,089.6 5,044.7 295.3 2,887.4 311.2 12,628.1 713.6 2,582.0 3,295.6 (122.8) 305.7 150.3 (57.4) 1,729.1 17,928.7 81.5
(2008-2027) 8,175.3 9,993.7 658.8 4,622.3 908.0 24,358.1 946.7 3,923.4 4,870.2 (142.6) 611.6 204.2 (117.3) 2,951.1 32,735.3 94.2
(2008-2037) 11,110.5 14,213.5 1,015.8 5,760.5 1,236.1 33,336.5 1,025.0 5,134.2 6,159.2 (142.6) 906.5 242.2 (169.4) 3,389.1 43,721.5 103.3
APPENDIX 2 TABLE 11. TABLE 12. ENERGY EFFICIENCY SCENARIO 3 (EE-3) 100% MARKET POTENTIAL, 75% INCENTIVE STRATEGY, 0.6 PAF, $175M ANNUAL SPENDING, 949 MW EE by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,148.3 2010 31,820.7 2011 31,742.1 2012 31,846.2 2013 31,879.0 2014 32,629.3 2015 33,590.6 2016 34,582.6 2017 35,604.3 2018 36,572.6 2019 37,515.2 2020 38,415.4 2021 39,317.9 2022 40,234.5 2023 41,157.4 2024 42,091.8 2025 43,040.4 2026 44,133.2 2027 45,238.9 2028 46,353.1 2029 47,637.7 2030 48,837.2 2031 50,036.7 2032 51,142.4 2033 52,435.8 2034 53,635.2 2035 54,834.8 2036 55,931.6 2037 57,018.1
(2008-2017) 328,014.7
(2008-2027) 735,732.0
(2008-2037) 1,253,594.6
APPENDIX 2 TABLE 12. TABLE 13. ENERGY EFFICIENCY SCENARIO 4 (EE-4) 100% MARKET POTENTIAL, 100% INCENTIVE STRATEGY, 0.6 PAF, $320 ANNUAL SPENDING, 1,352 MW EE by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 974 987 984 990 992 1,023 1,058 1,096 1,136 1,174 1,212 1,248 1,357 1,395 1,434 1,473 1,513 4. Total Load Requirements 8,295 8,359 8,458 8,601 8,714 9,028 9,374 9,741 10,112 10,467 10,816 11,153 11,565 11,908 12,253 12,601 12,955
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 00000000000000000 13. Total Existing Resources: 8,190 8,520 8,520 8,790 8,786 8,786 8,786 8,285 7,785 7,785 7,785 7,225 6,745 6,595 6,585 6,585 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 173 315 433 534 626 708 784 855 922 986 1,046 1,103 1,158 1,210 1,260 1,307 1,352 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000100100100100100100100100150150430430520 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 000000000000528528528528528 20. Peaking Resources 000000007169621,244 2,112 2,300 2,734 2,734 2,980 3,168 21. Short-Term Market Purchases 0000000394460482465413458438436463463 22. Total Future Resource Additions: 188 341 472 589 790 883 970 1,455 2,326 2,682 3,031 3,928 4,820 5,313 5,669 6,017 6,370
23. Total Resources: 8,378 8,861 8,992 9,380 9,576 9,668 9,756 9,741 10,112 10,467 10,816 11,153 11,565 11,908 12,253 12,601 12,955
New Renewable Nameplate Capacity ● 100 106 106 389 489 489 489 489 489 489 589 589 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 13. TABLE 14. ENERGY EFFICIENCY SCENARIO 4 (EE-4) 100% MARKET POTENTIAL, 100% INCENTIVE SPENDING, 0.6 PAF, $320M ANNUAL SPENDING, 1,352 MW EE by 2025) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 302.2 2,409.9 74.9 2009 549.1 756.2 41.1 412.2 8.6 1,767.3 77.4 297.7 375.1 (8.3) 41.5 14.7 (1.2) 407.3 2,596.4 81.3 2010 573.3 683.7 39.6 422.9 9.5 1,728.9 115.6 322.3 437.9 (9.1) 39.4 24.8 (9.5) 406.2 2,618.7 83.4 2011 580.5 687.9 39.2 419.9 9.5 1,737.0 102.8 288.1 390.8 (10.0) 40.3 29.2 (10.0) 419.5 2,596.8 83.4 2012 578.7 598.3 35.3 423.8 21.6 1,657.7 105.1 425.7 530.8 (14.0) 38.0 28.2 (10.6) 448.3 2,678.6 86.1 2013 583.5 602.3 36.4 429.0 48.8 1,700.1 105.7 454.8 560.5 (19.0) 39.3 28.2 (11.0) 417.5 2,715.7 87.6 2014 597.5 695.8 42.9 446.3 68.8 1,851.3 106.1 431.2 537.3 (24.3) 45.5 25.8 (11.8) 430.9 2,854.7 90.2 2015 629.5 724.3 44.2 462.7 66.9 1,927.6 106.5 482.0 588.5 (33.0) 47.6 23.1 (12.3) 446.3 2,987.9 92.0 2016 718.4 764.0 48.1 435.1 91.9 2,057.4 135.8 513.2 648.9 (37.0) 52.8 20.2 (12.8) 493.8 3,223.3 96.6 2017 811.0 953.9 60.7 449.0 106.8 2,381.4 160.8 409.7 570.5 (39.2) 56.9 17.2 (13.6) 513.1 3,486.4 101.6 2018 896.3 1,069.3 70.8 465.9 145.5 2,647.8 132.9 347.0 479.8 (38.4) 61.8 15.0 (14.5) 535.3 3,686.8 104.8 2019 926.2 1,115.3 74.7 480.3 180.6 2,777.1 131.4 385.3 516.7 (5.2) 69.4 14.3 (15.4) 555.6 3,912.4 108.6 2020 1,053.9 1,303.3 89.7 501.2 192.0 3,140.2 66.7 279.8 346.5 (2.6) 72.0 11.9 (16.7) 576.8 4,128.1 112.0 2021 1,253.6 1,388.8 101.8 531.9 190.3 3,466.4 66.0 340.0 405.9 0.0 80.8 15.2 (17.7) 600.1 4,550.8 120.8 2022 1,384.2 1,500.6 113.2 555.7 186.1 3,739.8 56.7 319.6 376.3 0.0 96.2 14.5 (19.1) 620.9 4,828.7 125.4 2023 1,353.1 1,537.5 116.1 573.9 181.2 3,761.8 53.1 452.5 505.5 0.0 93.7 18.5 (20.4) 641.0 5,000.2 127.0 2024 1,356.9 1,646.8 124.6 585.6 195.7 3,909.6 54.0 456.8 510.8 0.0 99.1 17.8 (21.4) 661.6 5,177.5 128.7 2025 1,395.9 1,672.6 127.5 601.0 201.7 3,998.7 56.6 606.9 663.4 0.0 104.9 24.5 (22.7) 688.4 5,457.2 132.7 2026 1,446.3 1,799.2 137.4 618.0 197.7 4,198.7 50.1 612.1 662.2 0.0 110.1 23.5 (24.2) 635.1 5,605.5 133.0 2027 1,481.0 1,926.2 147.7 633.3 213.8 4,401.9 61.3 633.2 694.5 0.0 121.7 22.4 (25.2) 616.3 5,831.6 135.0 2028 1,548.2 2,056.1 158.6 655.2 218.8 4,636.9 53.7 640.8 694.6 0.0 133.1 21.3 (26.4) 597.2 6,056.7 136.9 2029 1,631.4 2,222.9 172.5 678.1 213.6 4,918.5 58.9 644.7 703.7 0.0 148.0 20.1 (28.5) 576.4 6,338.2 139.4 2030 1,716.6 2,384.0 186.5 701.7 208.4 5,197.1 54.4 643.2 697.6 0.0 159.0 18.8 (30.4) 550.3 6,592.5 141.4 2031 1,789.1 2,481.4 195.7 725.8 227.9 5,420.0 40.0 771.1 811.0 0.0 169.2 25.4 (32.0) 519.3 6,913.0 144.7 2032 1,838.8 2,665.4 211.2 751.5 234.5 5,701.4 43.0 861.6 904.6 0.0 182.9 28.9 (35.1) 482.5 7,265.1 148.8 2033 1,916.4 2,809.5 224.2 776.8 229.1 5,956.1 45.0 897.2 942.2 0.0 192.4 29.2 (37.1) 439.3 7,522.2 150.3 2034 2,009.5 3,009.8 244.4 804.5 249.7 6,318.0 32.0 938.4 970.4 0.0 218.4 29.5 (40.4) 388.3 7,884.2 154.0 2035 2,091.7 3,143.5 256.7 832.0 254.4 6,578.3 34.5 979.3 1,013.7 0.0 228.8 29.8 (43.1) 329.3 8,136.9 155.4 2036 2,160.8 3,314.4 272.5 864.7 248.6 6,861.0 36.4 1,025.1 1,061.5 0.0 241.9 30.1 (46.5) 261.1 8,409.0 157.5 2037 2,193.4 3,483.7 288.5 872.5 243.1 7,081.3 67.1 1,071.2 1,138.3 0.0 255.9 30.3 (46.7) 182.7 8,641.9 158.8
CPW@ 7.86% (2008-2017) 4,050.3 4,823.2 282.6 2,885.7 249.5 12,291.3 707.5 2,528.4 3,236.0 (122.8) 289.9 150.3 (57.6) 2,824.4 18,611.4 86.3
(2008-2027) 7,893.2 9,383.1 615.7 4,605.8 837.0 23,334.9 955.0 3,861.5 4,816.5 (142.6) 565.8 204.2 (117.8) 4,741.6 33,402.7 98.9
(2008-2037) 10,635.6 13,338.7 931.2 5,722.1 1,179.0 31,806.7 1,025.3 5,072.6 6,097.9 (142.6) 840.2 242.2 (170.0) 5,425.9 44,100.3 107.5
APPENDIX 2 TABLE 14. TABLE 15. ENERGY EFFICIENCY SCENARIO 4 (EE-4) 100% MARKET POTENTIAL, 100% INCENTIVE STRATEGY, 0.6 PAF, $320M ANNUAL SPENDING, 1,352 MW EE by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 31,925.8 2010 31,400.9 2011 31,155.0 2012 31,112.4 2013 31,010.8 2014 31,640.3 2015 32,490.0 2016 33,377.7 2017 34,301.9 2018 35,178.2 2019 36,033.5 2020 36,851.2 2021 37,675.1 2022 38,516.3 2023 39,367.3 2024 40,234.0 2025 41,118.1 2026 42,148.4 2027 43,194.8 2028 44,253.1 2029 45,482.4 2030 46,626.3 2031 47,770.2 2032 48,819.9 2033 50,058.0 2034 51,201.9 2035 52,345.8 2036 53,386.7 2037 54,417.9
(2008-2017) 320,586.4
(2008-2027) 710,903.4
(2008-2037) 1,205,265.5
APPENDIX 2 TABLE 15. TABLE 16. ENERGY EFFICIENCY SCENARIO COMPARISONS ANNUAL NATURAL GAS BURNS (BCF)
EE-D EE-1 EE-2 EE-3 EE-4
2008 73.6 73.6 73.6 73.6 73.6 2009 76.8 75.7 74.3 73.2 71.8 2010 76.6 74.1 71.5 69.4 66.7 2011 75.7 72.0 68.7 65.9 62.0 2012 73.1 68.7 64.9 61.3 56.6 2013 75.0 69.8 65.3 61.3 55.7 2014 86.4 79.9 74.7 69.7 63.4 2015 94.9 88.3 82.4 76.7 69.5 2016 103.3 95.8 89.4 83.3 75.0 2017 113.1 105.0 97.4 90.4 81.4 2018 118.2 109.6 101.1 93.5 83.7 2019 123.2 114.0 104.8 96.7 86.3 2020 129.7 119.9 110.0 103.0 91.6 2021 136.7 127.0 116.5 109.2 97.3 2022 147.2 136.8 125.8 118.4 105.5 2023 148.5 137.9 126.1 118.6 105.3 2024 156.9 145.9 133.7 125.6 111.8 2025 157.8 146.5 133.8 125.5 110.9 2026 167.9 156.1 143.1 133.9 119.0 2027 173.8 161.8 150.5 139.2 126.2 2028 183.0 170.4 159.0 146.7 133.7 2029 194.5 181.6 170.0 157.1 143.8 2030 205.4 191.9 179.9 166.4 152.8 2031 210.1 196.1 183.9 170.0 155.8 2032 224.7 210.2 197.4 183.4 168.8 2033 232.4 217.4 204.0 189.1 174.0 2034 245.9 230.1 216.7 200.9 185.8 2035 251.2 235.4 221.2 205.5 189.8 2036 260.5 244.3 229.7 213.6 197.2 2037 269.5 252.7 238.1 221.6 204.8
(2008-2017) 848.5 802.9 762.3 724.7 675.8
(2008-2027) 2,308.3 2,158.2 2,007.8 1,888.4 1,713.5
(2008-2037) 4,585.5 4,288.4 4,007.7 3,742.7 3,419.8
APPENDIX 2 TABLE 16. TABLE 17. ENERGY EFFICIENCY SCENARIO COMPARISONS TOTAL WATER USAGE (Acre-Feet)
EE-D EE-1 EE-2 EE-3 EE-4
2008 56,553 56,553 56,553 56,553 56,553 2009 56,601 56,369 56,078 55,842 55,591 2010 56,594 56,141 55,714 55,336 54,829 2011 57,783 57,065 56,563 56,028 55,330 2012 59,646 58,728 58,100 57,454 56,571 2013 60,635 59,607 58,864 58,031 56,983 2014 61,644 60,518 59,641 58,720 57,528 2015 63,026 61,876 60,868 59,888 58,576 2016 64,578 63,369 62,311 61,293 59,937 2017 65,725 64,530 63,464 62,417 60,986 2018 67,631 66,425 65,311 64,191 62,718 2019 67,460 66,189 65,013 63,861 62,267 2020 66,952 65,717 64,557 64,027 62,450 2021 67,069 65,898 64,729 64,474 62,899 2022 67,698 66,564 65,400 65,112 63,557 2023 70,723 69,503 68,257 67,900 66,294 2024 71,518 70,299 69,002 68,637 66,956 2025 72,275 70,976 69,637 69,260 67,522 2026 73,179 71,934 70,524 70,121 68,356 2027 73,518 72,315 71,449 70,489 69,289 2028 74,161 72,959 72,471 71,171 70,411 2029 75,117 73,923 73,352 72,108 71,302 2030 75,973 74,773 74,304 72,927 72,147 2031 77,785 76,565 76,027 74,716 73,891 2032 77,780 76,557 76,074 74,728 73,928 2033 79,291 78,080 77,571 76,265 75,440 2034 79,534 78,378 77,905 76,613 75,894 2035 81,449 80,306 79,723 78,438 77,576 2036 82,677 81,469 80,874 79,546 78,679 2037 83,320 82,136 81,582 80,384 79,538
(2008-2017) 602,786 594,754 588,156 581,562 572,885
(2008-2027) 1,300,808 1,280,575 1,262,036 1,249,634 1,225,195
(2008-2037) 2,087,896 2,055,721 2,031,921 2,006,530 1,974,001
APPENDIX 2 TABLE 17. TABLE 18. ENERGY EFFICIENCY SCENARIO COMPARISONS TOTAL PLANT EMISSIONS (Tons)
EE-D EE-1 EE-2 EE-3 EE-4
2008 18,427,140 18,427,140 18,427,140 18,427,140 18,427,140 2009 18,558,694 18,455,091 18,324,016 18,228,504 18,113,474 2010 18,815,611 18,614,677 18,418,104 18,247,933 18,020,670 2011 18,492,853 18,162,624 17,934,570 17,692,666 17,377,440 2012 18,554,738 18,140,551 17,860,387 17,566,406 17,165,679 2013 18,695,151 18,225,565 17,886,359 17,510,201 17,031,164 2014 19,117,282 18,622,319 18,221,654 17,811,369 17,275,580 2015 19,772,732 19,237,543 18,784,990 18,338,178 17,750,554 2016 20,366,323 19,784,728 19,265,016 18,773,700 18,132,906 2017 21,368,293 20,742,604 20,171,223 19,629,935 18,912,965 2018 22,088,159 21,421,562 20,805,251 20,217,635 19,448,560 2019 22,651,967 21,950,233 21,281,229 20,657,568 19,822,591 2020 22,722,005 22,000,271 21,289,770 20,801,998 19,922,504 2021 23,190,260 22,470,102 21,749,351 21,274,293 20,377,561 2022 23,478,721 22,735,218 21,963,397 21,444,492 20,516,638 2023 23,666,799 22,901,189 22,108,629 21,558,295 20,594,612 2024 24,379,473 23,593,249 22,751,221 22,180,395 21,174,630 2025 24,332,031 23,502,666 22,618,156 22,027,890 20,988,447 2026 24,773,066 23,943,693 23,012,107 22,390,111 21,314,430 2027 25,327,842 24,501,291 23,707,091 22,928,240 21,981,571 2028 25,936,991 25,099,714 24,340,717 23,484,789 22,594,825 2029 26,673,314 25,816,572 25,023,754 24,152,776 23,241,268 2030 27,630,088 26,755,546 25,973,830 25,049,368 24,119,898 2031 27,964,842 27,062,340 26,255,697 25,326,029 24,377,157 2032 28,304,454 27,387,658 26,574,353 25,633,025 24,657,227 2033 29,075,730 28,146,676 27,310,471 26,356,414 25,376,923 2034 29,680,082 28,710,852 27,879,172 26,880,135 25,914,683 2035 30,358,054 29,383,089 28,503,277 27,498,952 26,475,636 2036 30,930,540 29,925,233 29,020,192 27,995,485 26,948,741 2037 31,306,525 30,275,302 29,375,590 28,343,698 27,275,764
(2008-2017) 192,168,818 188,412,841 185,293,458 182,226,032 178,207,571
(2008-2027) 428,779,141 417,432,314 406,579,660 397,706,950 384,349,113
(2008-2037) 716,639,761 695,995,297 676,836,713 658,427,622 635,331,234
APPENDIX 2 TABLE 18. TABLE 19. DEFAULT SUPPLY SIDE SCENARIO (SS-D) ALL GAS LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 00007070707070707070150150430430520 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 000000000005281,056 1,056 1,056 1,056 1,056 20. Peaking Resources 00000008461,692 2,068 2,350 2,726 3,008 3,478 3,572 3,854 4,230 21. Short-Term Market Purchases 00000121467456469435487465448453414459428 22. Total Future Resource Additions: 16 26 39 55 135 266 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 459 459 459 459 459 559 559 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 19. TABLE 20. DEFAULT SUPPLY SIDE SCENARIO (SS-D) ALL GAS TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 597.5 865.6 52.3 446.3 66.1 2,027.9 116.3 466.2 582.5 (24.3) 56.6 24.8 (11.6) 54.9 2,710.7 77.3 2015 629.5 899.8 54.6 462.7 89.7 2,136.3 153.0 529.2 682.2 (33.0) 60.3 22.1 (12.1) 58.3 2,914.0 80.3 2016 830.9 991.0 63.1 439.7 138.4 2,463.0 165.0 551.2 716.2 (37.0) 69.2 19.2 (12.6) 93.4 3,311.3 88.2 2017 1,021.9 1,223.2 79.9 457.9 176.0 2,958.9 159.6 438.7 598.3 (39.2) 77.1 16.1 (13.4) 100.0 3,697.8 95.3 2018 1,139.3 1,401.4 94.8 476.5 185.3 3,297.3 123.1 373.0 496.1 (38.4) 87.4 13.8 (14.2) 107.3 3,949.2 98.8 2019 1,176.3 1,430.0 97.3 491.8 181.0 3,376.5 125.2 416.2 541.3 (5.2) 91.0 13.2 (15.2) 114.3 4,116.0 100.1 2020 1,331.8 1,669.3 120.4 516.2 193.5 3,831.2 68.3 293.2 361.5 (2.6) 99.2 10.8 (16.5) 121.1 4,404.6 104.3 2021 1,562.5 1,742.4 135.6 550.2 200.1 4,190.8 63.1 398.9 462.0 0.0 105.9 16.4 (17.5) 127.8 4,885.5 112.7 2022 1,704.7 1,898.3 152.3 575.4 196.1 4,526.7 52.2 374.3 426.5 0.0 124.0 15.6 (18.8) 134.8 5,208.7 117.2 2023 1,685.9 1,941.1 155.5 595.0 191.6 4,569.1 46.4 598.6 645.0 0.0 121.4 19.6 (20.1) 142.6 5,477.6 120.3 2024 1,701.1 2,068.4 166.3 608.2 205.5 4,749.5 46.7 599.3 646.0 0.0 127.8 18.8 (21.1) 150.3 5,671.2 121.6 2025 1,769.1 2,142.4 173.7 625.9 210.9 4,922.0 47.3 818.1 865.3 0.0 140.3 25.5 (22.3) 158.2 6,089.0 127.5 2026 1,824.7 2,305.2 186.7 644.3 205.5 5,166.4 51.5 820.7 872.1 0.0 150.0 24.4 (23.8) 92.2 6,281.3 128.2 2027 1,927.7 2,427.0 204.5 665.8 200.8 5,425.8 22.1 835.6 857.7 0.0 158.5 24.2 (24.8) 92.2 6,533.6 130.0 2028 2,034.7 2,592.0 224.4 692.3 216.8 5,760.1 38.3 840.2 878.5 0.0 174.1 23.0 (26.1) 98.1 6,907.7 134.1 2029 2,095.7 2,781.9 241.1 716.1 222.0 6,056.8 53.9 839.5 893.4 0.0 191.6 21.8 (28.1) 98.0 7,233.4 136.7 2030 2,237.1 2,940.0 263.4 746.2 253.9 6,440.5 17.5 831.6 849.0 0.0 201.0 20.5 (30.1) 97.3 7,578.2 139.7 2031 2,342.7 3,110.9 283.9 775.5 267.1 6,780.1 36.0 832.9 868.9 0.0 217.6 19.2 (31.7) 96.8 7,950.9 143.0 2032 2,389.4 3,336.8 306.5 803.2 284.4 7,120.4 54.0 837.6 891.6 0.0 234.8 17.8 (34.8) 96.2 8,326.0 146.5 2033 2,481.4 3,529.2 325.8 831.2 289.2 7,456.9 44.3 869.9 914.2 0.0 247.3 17.9 (36.9) 95.9 8,695.3 149.3 2034 2,565.6 3,673.7 345.1 860.8 281.9 7,727.1 34.4 1,098.4 1,132.8 0.0 267.5 27.9 (40.2) 95.1 9,210.2 154.5 2035 2,624.0 3,866.8 363.0 889.7 273.0 8,016.6 49.1 1,141.6 1,190.6 0.0 283.4 28.1 (42.9) 94.4 9,570.3 157.1 2036 2,695.6 4,047.2 380.9 925.1 294.4 8,343.2 13.8 1,189.6 1,203.4 0.0 299.7 28.3 (46.3) 93.8 9,922.0 159.6 2037 2,743.5 4,296.8 409.6 935.9 300.5 8,686.4 78.1 1,234.7 1,312.8 0.0 325.2 28.5 (46.6) 93.3 10,399.5 163.5
CPW@ 7.86% (2008-2017) 4,206.2 5,601.6 327.4 2,892.2 345.9 13,373.2 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 (57.0) 415.1 17,510.4 75.8
(2008-2027) 9,048.0 11,407.9 775.0 4,672.1 965.3 26,868.4 975.4 4,301.3 5,276.7 (142.6) 704.8 196.7 (116.3) 807.6 33,595.3 90.4
(2008-2037) 12,573.7 16,319.5 1,223.9 5,862.1 1,356.1 37,335.3 1,036.7 5,701.1 6,737.8 (142.6) 1,053.1 230.5 (168.1) 950.7 45,996.7 100.9
APPENDIX 2 TABLE 20. TABLE 21. DEFAULT SUPPLY SIDE SCENARIO (SS-D) ALL GAS OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 21. TABLE 22. NUCLEAR SUPPLY SIDE SCENARIO (SS-N) 630 MW NUCLEAR GENERATION by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 00007070707070707070150150430430520 18. Baseload Nuclear 0000000000000315630630630 19. Gas Combined Cycle 00000000000528528528528528528 20. Peaking Resources 00000008461,692 2,068 2,350 2,726 3,572 3,666 3,666 3,760 4,136 21. Short-Term Market Purchases 00000121467456469435487465412478218451420 22. Total Future Resource Additions: 16 26 39 55 135 266 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 459 459 459 459 459 559 559 639 639 918 918 1,268
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 22. TABLE 23. NUCLEAR SUPPLY SIDE SCENARIO (SS-D) 630 MW NUCLEAR GENERATION by 2025 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Tot Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 2014 600.3 865.6 52.3 446.3 66.1 2,030.7 116.3 466.2 582.5 (24.3) 56.6 24.8 (11.6) 54.9 2,713.5 2015 637.1 899.8 54.6 462.7 89.7 2,143.9 153.0 529.2 682.2 (33.0) 60.3 22.1 (12.1) 58.3 2,921.6 2016 864.3 991.0 63.1 439.7 138.4 2,496.4 165.0 551.2 716.2 (37.0) 69.2 19.2 (12.6) 93.4 3,344.7 2017 1,104.5 1,223.2 79.9 457.9 176.0 3,041.5 159.6 438.7 598.3 (39.2) 77.1 16.1 (13.4) 100.0 3,780.4 2018 1,285.6 1,401.4 94.8 476.5 185.3 3,443.6 123.1 373.0 496.1 (38.4) 87.4 13.8 (14.2) 107.3 4,095.5 2019 1,401.2 1,430.0 97.3 491.8 181.0 3,601.4 125.2 416.2 541.3 (5.2) 91.0 13.2 (15.2) 114.3 4,340.9 2020 1,647.9 1,669.3 120.4 516.2 193.5 4,147.3 68.3 293.2 361.5 (2.6) 99.2 10.8 (16.5) 121.1 4,720.7 2021 1,941.9 1,761.2 132.0 547.7 232.0 4,614.8 59.4 400.9 460.3 0.0 108.1 16.4 (17.5) 127.8 5,309.9 2022 2,197.7 1,825.3 137.5 581.9 243.2 4,985.6 52.6 374.4 426.9 0.0 118.7 15.6 (18.9) 134.8 5,662.8 2023 2,188.7 1,703.2 128.0 622.9 236.2 4,879.1 27.0 598.6 625.7 0.0 104.7 19.6 (20.3) 142.6 5,751.3 2024 2,071.2 1,771.2 134.0 645.2 247.5 4,869.2 32.8 599.3 632.1 0.0 105.6 18.8 (21.4) 150.3 5,754.5 2025 2,108.9 1,822.5 138.3 663.2 252.1 4,984.9 48.2 818.1 866.4 0.0 115.9 25.5 (22.7) 158.2 6,128.1 2026 2,156.1 1,984.7 151.3 682.6 245.8 5,220.6 52.4 820.7 873.1 0.0 123.9 24.4 (24.1) 92.2 6,310.0 2027 2,252.8 2,122.2 167.6 705.3 239.8 5,487.7 23.0 835.6 858.5 0.0 133.6 24.2 (25.2) 92.2 6,571.1 2028 2,335.9 2,253.8 182.7 732.3 233.8 5,738.5 59.5 840.2 899.7 0.0 146.0 23.0 (26.5) 98.1 6,878.8 2029 2,393.6 2,444.6 199.7 757.5 227.7 6,023.1 53.3 839.4 892.7 0.0 163.5 21.8 (28.4) 98.0 7,170.6 2030 2,534.2 2,588.3 218.9 789.4 244.4 6,375.1 17.0 831.6 848.6 0.0 172.4 20.5 (30.4) 97.3 7,483.4 2031 2,604.0 2,740.6 236.8 819.2 249.1 6,649.8 57.8 832.9 890.7 0.0 185.3 19.2 (31.9) 96.8 7,809.8 2032 2,643.2 2,977.1 257.9 848.4 243.4 6,969.9 52.1 837.6 889.7 0.0 203.2 17.8 (35.1) 96.2 8,141.7 2033 2,735.5 3,139.1 273.6 878.4 262.4 7,288.9 42.6 869.9 912.5 0.0 212.9 17.9 (37.1) 95.9 8,491.0 2034 2,804.2 3,289.2 291.9 909.4 267.0 7,561.7 32.7 1,098.4 1,131.2 0.0 235.0 27.9 (40.4) 95.1 9,010.4 2035 2,847.3 3,488.3 310.1 939.8 257.8 7,843.2 47.6 1,141.6 1,189.1 0.0 251.3 28.1 (43.1) 94.4 9,363.1 2036 2,904.6 3,651.4 325.3 976.6 280.5 8,138.4 12.4 1,189.6 1,202.0 0.0 265.5 28.3 (46.5) 93.8 9,681.5 2037 2,942.3 3,880.8 349.5 989.0 287.2 8,448.8 76.7 1,234.7 1,311.4 0.0 289.0 28.5 (46.7) 93.3 10,124.2
CPW@ 7.86% (2008-2017) 4,267.7 5,601.6 327.4 2,892.2 345.9 13,434.7 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 (57.0) 415.1 17,571.9
(2008-2027) 10,161.6 11,012.8 726.4 4,719.3 1,045.1 27,665.1 965.3 4,302.0 5,267.3 (142.6) 674.8 196.7 (116.7) 807.6 34,352.2
(2008-2037) 14,075.3 15,378.1 1,103.1 5,976.8 1,419.4 37,952.7 1,033.0 5,701.8 6,734.9 (142.6) 976.6 230.5 (168.9) 950.7 46,533.9
APPENDIX 2 TABLE 23. tal
$/MWH
66.3 70.3 72.2 71.5 73.6 74.5 77.4 80.5 89.1 97.5 102.4 105.5 111.8 122.5 127.4 126.3 123.4 128.4 128.8 130.8 133.6 135.5 137.9 140.5 143.3 145.7 151.2 153.7 155.7 159.2
76.0
92.5
102.1
APPENDIX 2 TABLE 23. TABLE 24. NUCLEAR SUPPLY SIDE SCENARIO 630 MW NUCLEAR GENERATION by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 24. TABLE 25. SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1) 1,400 MW CSP GENERATION by 2020 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000702704706708701,070 1,270 1,470 1,550 1,550 1,830 1,830 1,920 18. Baseload Nuclear 00000000000000000 19. Gas Combined Cycle 00000000000000000 20. Peaking Resources 00000002829401,034 1,222 1,880 2,632 3,102 3,196 3,478 3,854 21. Short-Term Market Purchases 00000067420421469415439480485446491460 22. Total Future Resource Additions: 16 26 39 55 135 345 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,213 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 659 859 1,059 1,259 1,459 1,759 1,959 2,039 2,039 2,318 2,318 2,668
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 25. TABLE 26. SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1) 1,400 MW CSP GENERATION by 2020 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 597.5 828.1 50.6 446.3 66.1 1,988.5 106.2 582.0 688.2 (24.3) 53.9 30.0 (11.7) 54.9 2,779.5 79.3 2015 629.5 830.0 50.5 462.7 89.7 2,062.4 112.3 759.3 871.6 (33.0) 54.7 32.6 (12.2) 58.3 3,034.4 83.6 2016 755.9 877.6 55.5 436.7 123.4 2,249.0 141.7 910.8 1,052.6 (37.0) 60.7 35.1 (12.7) 93.4 3,440.9 91.7 2017 871.2 1,053.4 67.6 451.5 153.3 2,597.0 158.1 936.1 1,094.2 (39.2) 64.2 37.5 (13.5) 100.0 3,840.3 99.0 2018 936.7 1,174.3 78.2 467.5 162.7 2,819.3 128.7 1,010.0 1,138.6 (38.4) 70.4 40.8 (14.4) 107.3 4,123.7 103.1 2019 940.0 1,157.9 77.2 480.9 158.1 2,814.0 125.5 1,193.8 1,319.3 (5.2) 70.6 45.8 (15.4) 114.3 4,343.5 105.6 2020 1,038.2 1,333.0 90.5 500.3 171.4 3,133.4 66.2 1,240.8 1,307.0 (2.6) 75.4 49.2 (16.7) 121.1 4,666.7 110.5 2021 1,210.1 1,427.8 98.2 527.7 195.2 3,459.0 70.2 1,347.3 1,417.5 0.0 85.5 54.2 (17.7) 127.8 5,126.3 118.3 2022 1,343.7 1,580.2 108.6 549.9 200.0 3,782.3 63.1 1,327.3 1,390.4 0.0 103.7 52.8 (19.0) 134.8 5,445.1 122.5 2023 1,337.6 1,618.9 112.6 568.7 194.7 3,832.5 57.0 1,551.6 1,608.6 0.0 100.7 56.1 (20.4) 142.6 5,720.1 125.6 2024 1,365.3 1,738.2 121.5 581.1 189.9 3,996.0 57.0 1,554.0 1,611.0 0.0 105.6 54.6 (21.3) 150.3 5,896.2 126.4 2025 1,445.7 1,808.6 127.6 598.0 206.7 4,186.7 57.3 1,771.2 1,828.4 0.0 118.7 60.6 (22.6) 158.2 6,330.0 132.6 2026 1,531.0 1,961.2 139.0 616.2 211.3 4,458.7 50.0 1,773.6 1,823.6 0.0 127.6 58.7 (24.0) 92.2 6,536.9 133.4 2027 1,604.0 2,108.2 151.4 633.0 206.7 4,703.2 45.1 1,788.5 1,833.6 0.0 137.9 57.7 (25.0) 92.2 6,799.7 135.3 2028 1,685.0 2,288.6 165.9 655.3 223.0 5,017.8 60.5 1,794.9 1,855.4 0.0 156.1 55.6 (26.3) 98.1 7,156.7 139.0 2029 1,778.4 2,467.6 180.7 678.7 227.2 5,332.8 54.2 1,792.4 1,846.6 0.0 173.0 53.4 (28.3) 98.0 7,475.5 141.3 2030 1,946.1 2,612.8 200.1 708.2 221.3 5,688.5 17.3 1,784.5 1,801.9 0.0 181.4 51.1 (30.3) 97.3 7,789.9 143.6 2031 2,063.4 2,773.4 219.7 736.4 255.1 6,047.9 35.4 1,785.9 1,821.3 0.0 196.6 48.8 (31.8) 96.8 8,179.5 147.1 2032 2,120.6 3,001.2 238.8 762.9 292.5 6,416.0 53.4 1,792.4 1,845.8 0.0 214.6 46.2 (35.0) 96.2 8,583.9 151.0 2033 2,222.0 3,191.2 256.0 789.7 297.3 6,756.2 43.8 1,822.9 1,866.7 0.0 225.3 45.1 (37.0) 95.9 8,952.2 153.7 2034 2,314.7 3,351.1 273.3 818.1 289.9 7,047.0 33.9 2,051.4 2,085.3 0.0 246.9 53.8 (40.3) 95.1 9,487.8 159.2 2035 2,381.5 3,524.3 289.7 845.7 307.6 7,348.8 48.5 2,094.5 2,143.0 0.0 263.3 52.7 (43.0) 94.4 9,859.1 161.8 2036 2,462.9 3,698.7 305.5 879.7 313.6 7,660.3 13.2 2,144.3 2,157.5 0.0 277.6 51.4 (46.5) 93.8 10,194.1 164.0 2037 2,521.9 3,960.2 331.3 889.2 306.5 8,009.1 77.6 2,187.6 2,265.2 0.0 305.2 50.1 (46.7) 93.3 10,676.3 167.9
CPW@ 7.86% (2008-2017) 4,097.5 5,404.3 314.5 2,887.7 327.6 13,031.6 710.6 3,279.5 3,990.1 (122.8) 323.4 168.8 (57.1) 415.1 17,749.1 76.8
(2008-2027) 7,987.2 10,240.2 648.6 4,600.9 917.4 24,394.4 955.8 7,719.2 8,675.0 (142.6) 624.0 333.2 (117.0) 807.6 34,574.7 93.1
(2008-2037) 11,097.6 14,663.4 997.9 5,730.6 1,313.2 33,802.8 1,021.1 10,537.1 11,558.2 (142.6) 942.5 409.1 (169.1) 950.7 47,351.6 103.9
APPENDIX 2 TABLE 26. TABLE 27. SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1) 1,400 MW CSP GENERATION by 2020 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 27. TABLE 28. SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2) 700 MW CSP and 1,148 MW PV GENERATION by 2020 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 0000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 9. Purchase - SRP T&C 238 000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 00000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0 0 0 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690
14. Future Planned Resource Additions: 15. Energy Efficiency * 0000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 17. Renewable Energy Resources * 0000702454204957709451,120 1,295 1,424 1,424 1,704 1,704 18. Baseload Nuclear 0000000000000000 19. Gas Combined Cycle 0000000000000000 20. Peaking Resources 00000004701,034 1,128 1,316 2,068 2,820 3,290 3,290 3,666 21. Short-Term Market Purchases 000000117407427500471426418423478429 22. Total Future Resource Additions: 16 26 39 55 135 320 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,188 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798
New Renewable Nameplate Capacity ● 100 106 106 389 459 709 959 1,109 1,459 1,709 2,059 2,309 2,487 2,487 2,766 2,766
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 28. 2025
11,442 1,716 13,158
6,270 0 315 0 0 0 0 6,585
0 339 1,794 0 0 3,948 492 6,573
13,158
3,116
APPENDIX 2 TABLE 28. TABLE 29. SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2) 700 MW CSP and 1,148 MW PV GENERATION by 2020 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 597.5 833.0 50.4 446.3 66.1 1,993.3 106.2 572.0 678.1 (24.3) 54.3 29.8 (11.7) 54.9 2,774.4 79.1 2015 629.5 837.6 50.4 462.7 89.7 2,069.9 116.6 738.9 855.6 (33.0) 55.4 32.2 (12.2) 58.3 3,026.2 83.4 2016 780.9 906.8 57.0 437.7 137.8 2,320.2 143.2 817.0 960.2 (37.0) 62.5 31.6 (12.7) 93.4 3,418.1 91.1 2017 899.9 1,067.6 67.8 452.7 160.2 2,648.3 157.5 893.4 1,050.9 (39.2) 65.5 36.7 (13.5) 100.0 3,848.6 99.2 2018 955.1 1,190.2 79.2 468.4 161.3 2,854.1 131.6 955.9 1,087.4 (38.4) 72.0 39.8 (14.4) 107.3 4,107.8 102.7 2019 957.6 1,179.2 78.4 481.8 172.6 2,869.7 132.3 1,126.2 1,258.5 (5.2) 72.6 44.6 (15.5) 114.3 4,339.0 105.5 2020 1,069.4 1,361.0 92.0 501.9 177.6 3,201.9 67.5 1,156.4 1,223.9 (2.6) 77.6 47.6 (16.7) 121.1 4,652.8 110.2 2021 1,250.1 1,443.7 98.6 529.7 193.1 3,515.2 61.7 1,302.8 1,364.5 0.0 86.5 54.6 (17.8) 127.8 5,131.0 118.4 2022 1,382.1 1,594.2 109.7 551.9 198.3 3,836.2 51.6 1,285.6 1,337.2 0.0 104.8 53.2 (19.1) 134.8 5,447.1 122.6 2023 1,358.7 1,633.4 113.0 570.3 222.3 3,897.6 56.1 1,509.7 1,565.8 0.0 101.9 56.5 (20.4) 142.6 5,744.0 126.1 2024 1,390.6 1,754.4 122.1 582.8 232.2 4,082.1 52.6 1,512.4 1,565.0 0.0 106.7 55.1 (21.4) 150.3 5,937.7 127.3 2025 1,464.6 1,824.2 128.6 599.6 246.9 4,263.9 56.7 1,729.4 1,786.0 0.0 120.0 61.0 (22.7) 158.2 6,366.6 133.3 2026 1,537.2 1,978.0 140.5 617.4 250.6 4,523.7 56.8 1,731.7 1,788.5 0.0 128.7 59.2 (24.1) 92.2 6,568.0 134.1 2027 1,663.7 2,093.2 156.6 638.6 244.6 4,796.6 19.7 1,746.6 1,766.2 0.0 136.5 58.1 (25.2) 92.2 6,824.5 135.8 2028 1,762.6 2,247.9 175.4 663.6 237.6 5,087.1 56.5 1,753.2 1,809.6 0.0 151.2 56.1 (26.4) 98.1 7,175.7 139.3 2029 1,840.8 2,432.5 190.7 686.8 231.9 5,382.7 50.3 1,750.6 1,800.9 0.0 169.5 53.9 (28.5) 98.0 7,476.5 141.3 2030 2,006.8 2,580.8 210.0 716.5 286.4 5,800.4 13.6 1,742.6 1,756.2 0.0 176.8 51.6 (30.5) 97.3 7,851.9 144.7 2031 2,102.0 2,740.8 229.4 744.1 309.1 6,125.4 54.2 1,743.9 1,798.1 0.0 192.0 49.2 (32.0) 96.8 8,229.5 148.0 2032 2,165.3 2,964.3 248.5 771.1 300.8 6,450.0 48.5 1,750.9 1,799.4 0.0 210.2 46.7 (35.2) 96.2 8,567.3 150.7 2033 2,280.7 3,149.9 265.1 798.8 317.7 6,812.1 39.1 1,780.9 1,820.1 0.0 220.9 45.6 (37.2) 95.9 8,957.4 153.8 2034 2,349.3 3,296.0 281.9 826.5 321.9 7,075.7 53.8 2,009.4 2,063.2 0.0 240.5 54.3 (40.6) 95.1 9,488.3 159.2 2035 2,423.1 3,479.4 298.5 854.7 311.9 7,367.5 42.6 2,052.5 2,095.2 0.0 256.0 53.2 (43.3) 94.4 9,823.0 161.2 2036 2,520.4 3,642.1 315.0 889.6 332.0 7,699.1 31.6 2,102.6 2,134.2 0.0 269.8 52.0 (46.7) 93.8 10,202.2 164.1 2037 2,578.3 3,896.3 340.4 899.4 337.8 8,052.2 95.2 2,145.7 2,240.9 0.0 297.7 50.6 (46.8) 93.3 10,688.0 168.0
CPW@ 7.86% (2008-2017) 4,123.6 5,432.9 315.2 2,888.8 338.2 13,098.6 713.4 3,194.9 3,908.3 (122.8) 325.6 166.3 (57.2) 415.1 17,733.9 76.7
(2008-2027) 8,099.1 10,318.2 653.3 4,607.6 982.2 24,660.5 950.9 7,469.5 8,420.4 (142.6) 630.1 330.0 (117.3) 807.6 34,588.7 93.1
(2008-2037) 11,290.7 14,678.7 1,016.7 5,750.1 1,416.1 34,152.4 1,021.4 10,225.2 11,246.6 (142.6) 940.8 406.7 (169.7) 950.7 47,384.8 103.9
APPENDIX 2 TABLE 29. TABLE 30. SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2) 700 MW CSP and 1,148 MW PV GENERATION by 2020 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 30. TABLE 31. SUPPLY SIDE SCENARIO 1 (SS-1) 500 MW NUCLEAR and 290 MW SOLAR GENERATION by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 000070170270360360360360360440440720720810 18. Baseload Nuclear 0000000000000250500500500 19. Gas Combined Cycle 00000000000528528528528528528 20. Peaking Resources 00000005641,410 1,786 2,068 2,444 3,196 3,478 3,478 3,572 3,948 21. Short-Term Market Purchases 0000021267448461427479457498441246479448 22. Total Future Resource Additions: 16 26 39 55 135 266 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 559 659 749 749 749 849 849 929 929 1,208 1,208 1,558
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 31. TABLE 32. SUPPLY SIDE SCENARIO 1 (SS-1) 500 MW NUCLEAR and 290 MW SOLAR GENERATION by 2025 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 599.7 847.3 51.3 446.3 66.1 2,010.8 107.9 524.0 631.9 (24.3) 55.3 27.4 (11.6) 54.9 2,744.2 78.3 2015 635.5 865.0 52.4 462.7 89.7 2,105.3 130.6 643.6 774.2 (33.0) 57.4 27.4 (12.2) 58.3 2,977.4 82.0 2016 819.9 934.6 59.4 438.2 137.8 2,389.9 154.6 725.4 880.0 (37.0) 64.7 26.8 (12.7) 93.4 3,405.1 90.7 2017 1,025.0 1,159.4 75.5 455.2 160.8 2,875.9 161.2 616.9 778.1 (39.2) 72.4 23.7 (13.4) 100.0 3,797.5 97.9 2018 1,195.6 1,332.5 89.9 473.7 177.6 3,269.3 124.7 552.8 677.5 (38.4) 81.9 21.3 (14.3) 107.3 4,104.7 102.7 2019 1,297.4 1,359.1 92.1 489.0 181.5 3,419.2 126.7 596.8 723.5 (5.2) 85.5 20.6 (15.2) 114.3 4,342.7 105.6 2020 1,527.6 1,592.1 114.7 513.3 194.0 3,941.7 69.7 477.1 546.8 (2.6) 93.3 18.0 (16.5) 121.1 4,701.8 111.3 2021 1,793.0 1,685.4 126.0 544.1 225.3 4,373.8 70.5 584.5 655.0 0.0 102.3 23.5 (17.5) 127.8 5,264.8 121.5 2022 2,033.2 1,765.7 132.9 576.2 233.5 4,741.6 56.8 559.9 616.7 0.0 114.5 22.6 (18.9) 134.8 5,611.3 126.3 2023 2,033.9 1,676.6 126.0 613.1 227.2 4,676.8 29.4 784.3 813.6 0.0 102.9 26.4 (20.3) 142.6 5,742.0 126.1 2024 1,936.9 1,755.8 132.4 633.0 221.4 4,679.6 39.9 785.3 825.2 0.0 104.7 25.5 (21.4) 150.3 5,763.8 123.6 2025 1,978.4 1,810.2 137.1 650.6 236.4 4,812.7 55.2 1,003.8 1,058.9 0.0 115.5 32.0 (22.7) 158.2 6,154.7 128.9 2026 2,047.3 1,971.2 149.8 670.3 240.5 5,079.1 48.0 1,006.3 1,054.2 0.0 123.4 30.7 (24.1) 92.2 6,355.6 129.7 2027 2,159.4 2,102.5 166.1 693.1 234.7 5,355.8 11.1 1,021.2 1,032.2 0.0 132.7 30.4 (25.1) 92.2 6,618.2 131.7 2028 2,245.0 2,239.5 182.0 719.8 228.0 5,614.2 48.1 1,026.2 1,074.3 0.0 145.6 29.0 (26.5) 98.1 6,934.7 134.7 2029 2,306.2 2,427.7 198.4 744.6 222.6 5,899.5 42.2 1,025.0 1,067.2 0.0 162.9 27.6 (28.4) 98.0 7,226.8 136.6 2030 2,451.3 2,601.8 213.7 776.1 239.9 6,282.7 6.0 1,017.2 1,023.3 0.0 174.9 26.1 (30.4) 97.3 7,573.8 139.6 2031 2,525.6 2,763.6 228.9 805.5 283.4 6,607.1 47.1 1,018.5 1,065.6 0.0 190.0 24.5 (31.9) 96.8 7,952.0 143.1 2032 2,568.5 2,998.5 249.2 834.3 295.3 6,945.9 41.7 1,024.3 1,066.0 0.0 207.5 22.8 (35.0) 96.2 8,303.4 146.1 2033 2,642.6 3,167.5 265.2 863.1 312.4 7,250.8 56.2 1,055.5 1,111.7 0.0 217.5 22.7 (37.0) 95.9 8,661.7 148.7 2034 2,700.5 3,325.0 283.3 893.0 316.7 7,518.5 45.8 1,284.1 1,329.9 0.0 240.6 32.4 (40.3) 95.1 9,176.1 154.0 2035 2,748.7 3,518.5 301.5 922.9 307.8 7,799.4 60.1 1,327.2 1,387.3 0.0 256.7 32.3 (43.0) 94.4 9,527.1 156.4 2036 2,810.9 3,683.0 316.5 959.2 328.5 8,098.1 24.6 1,375.7 1,400.2 0.0 271.3 32.2 (46.5) 93.8 9,849.1 158.4 2037 2,877.7 3,923.8 340.9 972.0 333.2 8,447.6 14.1 1,420.3 1,434.5 0.0 295.4 32.0 (46.7) 93.3 10,256.1 161.3
CPW@ 7.86% (2008-2017) 4,206.7 5,513.4 321.6 2,890.2 338.5 13,270.3 729.6 2,938.5 3,668.1 (122.8) 331.6 153.7 (57.0) 415.1 17,659.0 76.4
(2008-2027) 9,707.0 10,768.8 708.7 4,695.6 1,013.0 26,893.0 951.5 5,152.7 6,104.2 (142.6) 656.6 230.6 (116.8) 807.6 34,432.6 92.7
(2008-2037) 13,491.6 15,157.6 1,076.3 5,931.5 1,427.3 37,084.3 1,009.5 6,828.9 7,838.4 (142.6) 963.4 271.8 (168.9) 950.7 46,797.1 102.6
APPENDIX 2 TABLE 32. TABLE 33. SUPPLY SIDE SCENARIO 1 (SS-1) 500 MW NUCLEAR and 290 MW SOLAR GENERATION by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 33. TABLE 34. SUPPLY SIDE SCENARIO 2 (SS-2) 650 MW NUCLEAR and 800 MW SOLAR GENERATION by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000702203705205706166166166966969769761,066 18. Baseload Nuclear 0000000000000325650650650 19. Gas Combined Cycle 000000000000528528528528528 20. Peaking Resources 00000003761,222 1,504 1,880 2,726 3,008 3,102 3,102 3,196 3,572 21. Short-Term Market Purchases 000000167476439453411447430486216449418 22. Total Future Resource Additions: 16 26 39 55 135 295 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,163 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 659 859 1,059 1,159 1,251 1,351 1,351 1,431 1,431 1,710 1,710 2,060
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 34. TABLE 35. SUPPLY SIDE SCENARIO 2 (SS-2) 650 MW NUCLEAR and 800 MW SOLAR GENERATION by 2025 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 600.4 837.3 50.8 446.3 66.1 2,000.9 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 2,765.8 78.9 2015 637.3 846.7 51.1 462.7 89.7 2,087.5 120.9 707.6 828.5 (33.0) 56.0 30.6 (12.2) 58.3 3,015.7 83.1 2016 802.8 902.3 56.8 437.2 137.8 2,336.8 152.0 830.5 982.5 (37.0) 62.0 32.0 (12.7) 93.4 3,456.9 92.1 2017 1,003.1 1,110.7 71.1 453.4 160.2 2,798.5 161.9 759.2 921.1 (39.2) 68.6 30.5 (13.5) 100.0 3,866.0 99.7 2018 1,177.2 1,267.3 84.5 471.3 161.9 3,162.3 126.7 730.0 856.7 (38.4) 77.4 29.7 (14.3) 107.3 4,180.6 104.6 2019 1,304.3 1,294.3 86.8 486.7 174.2 3,346.4 122.6 773.5 896.1 (5.2) 80.8 28.8 (15.3) 114.3 4,445.9 108.1 2020 1,539.1 1,540.5 105.3 508.3 195.4 3,888.5 65.4 661.5 726.9 (2.6) 90.5 26.1 (16.6) 121.1 4,833.9 114.4 2021 1,834.3 1,616.6 117.3 539.8 234.2 4,342.1 64.3 766.0 830.3 0.0 98.1 31.5 (17.6) 127.8 5,412.2 124.9 2022 2,111.1 1,662.0 124.8 576.1 245.5 4,719.5 58.8 744.3 803.1 0.0 106.1 30.4 (19.0) 134.8 5,774.9 130.0 2023 2,108.6 1,541.5 115.5 617.7 238.5 4,621.8 31.2 968.6 999.9 0.0 93.8 34.1 (20.6) 142.6 5,871.6 128.9 2024 1,992.5 1,604.8 120.2 640.2 231.5 4,589.3 36.1 970.1 1,006.3 0.0 94.7 33.0 (21.7) 150.3 5,851.9 125.5 2025 2,034.1 1,650.4 124.0 658.0 227.8 4,694.3 51.5 1,188.1 1,239.7 0.0 103.9 39.3 (23.0) 158.2 6,212.4 130.1 2026 2,085.1 1,804.3 137.2 677.3 242.2 4,946.1 55.7 1,190.6 1,246.3 0.0 111.3 37.9 (24.4) 92.2 6,409.4 130.8 2027 2,131.6 1,965.4 149.2 695.3 245.5 5,186.9 58.2 1,205.5 1,263.7 0.0 123.3 37.3 (25.4) 92.2 6,678.1 132.9 2028 2,218.6 2,092.0 161.2 720.2 239.7 5,431.7 52.7 1,211.0 1,263.7 0.0 135.6 35.8 (26.6) 98.1 6,938.1 134.7 2029 2,307.2 2,284.8 176.2 746.2 233.9 5,748.2 46.7 1,209.3 1,256.1 0.0 153.4 34.1 (28.6) 98.0 7,261.2 137.2 2030 2,451.3 2,422.9 194.7 777.7 250.4 6,097.0 10.3 1,201.5 1,211.8 0.0 160.8 32.4 (30.6) 97.3 7,568.6 139.5 2031 2,524.4 2,571.9 211.9 807.1 255.0 6,370.4 51.1 1,202.9 1,254.0 0.0 174.1 30.6 (32.1) 96.8 7,893.7 142.0 2032 2,565.9 2,806.4 231.8 836.0 248.1 6,688.2 45.7 1,208.5 1,254.2 0.0 191.7 28.7 (35.3) 96.2 8,223.8 144.7 2033 2,660.2 2,964.5 246.0 865.6 267.6 7,004.0 36.5 1,239.9 1,276.3 0.0 200.2 28.3 (37.3) 95.9 8,567.4 147.1 2034 2,708.2 3,118.5 263.1 895.4 315.6 7,300.8 51.1 1,468.4 1,519.4 0.0 221.8 37.6 (40.6) 95.1 9,134.2 153.3 2035 2,762.1 3,309.4 281.3 925.6 326.5 7,604.9 40.0 1,511.5 1,551.5 0.0 238.4 37.3 (43.3) 94.4 9,483.1 155.6 2036 2,815.4 3,468.7 295.7 961.7 346.1 7,887.6 79.0 1,560.4 1,639.4 0.0 252.3 36.8 (46.7) 93.8 9,863.1 158.7 2037 2,863.9 3,691.5 317.6 973.9 351.5 8,198.4 18.5 1,604.6 1,623.1 0.0 274.9 36.3 (46.9) 93.3 10,179.1 160.0
CPW@ 7.86% (2008-2017) 4,189.1 5,458.3 317.2 2,888.8 338.2 13,191.6 722.3 3,112.3 3,834.6 (122.8) 327.4 162.2 (57.1) 415.1 17,750.9 76.8
(2008-2027) 9,782.6 10,389.8 674.0 4,696.3 1,017.1 26,559.9 951.0 5,903.7 6,854.7 (142.6) 629.9 263.8 (117.3) 807.6 34,856.0 93.8
(2008-2037) 13,565.6 14,501.7 1,012.0 5,934.9 1,425.7 36,439.9 1,014.9 7,854.1 8,869.0 (142.6) 914.1 313.7 (169.8) 950.7 47,175.0 103.5
APPENDIX 2 TABLE 35. TABLE 36. SUPPLY SIDE SCENARIO 2 (SS-2) 650 MW NUCLEAR and 800 MW SOLAR GENERATION by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 36. TABLE 37. SUPPLY SIDE SCENARIO 3 (SS-3) 800 MW NUCLEAR and 400 MW SOLAR GENERATION by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 000070220320343343343343343423423703703793 18. Baseload Nuclear 0000000000000400800800800 19. Gas Combined Cycle 00000000000528528528528528528 20. Peaking Resources 00000005641,410 1,786 2,068 2,444 3,290 3,290 3,290 3,290 3,666 21. Short-Term Market Purchases 000000217465478444496474421496151478447 22. Total Future Resource Additions: 16 26 39 55 135 295 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,163 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 659 809 855 855 855 955 955 1,035 1,035 1,314 1,314 1,664
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 37. TABLE 38. SUPPLY SIDE SCENARIO 3 (SS-3) 800 MW NUCLEAR and 400 MW SOLAR GENERATION by 2025 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 2,766.5 78.9 2015 639.1 855.8 51.6 462.7 89.7 2,098.9 125.2 678.0 803.3 (33.0) 56.8 29.2 (12.2) 58.3 3,001.3 82.7 2016 835.8 936.2 59.0 438.2 137.8 2,407.0 153.7 720.8 874.4 (37.0) 64.8 27.0 (12.7) 93.4 3,416.8 91.0 2017 1,064.4 1,160.4 75.1 455.2 160.8 2,915.9 164.4 611.0 775.4 (39.2) 72.4 23.8 (13.4) 100.0 3,834.9 98.9 2018 1,265.3 1,333.4 89.8 473.7 177.6 3,339.8 127.7 547.1 674.7 (38.4) 82.2 21.4 (14.3) 107.3 4,172.8 104.4 2019 1,404.5 1,361.8 92.1 489.0 181.5 3,528.9 129.6 589.9 719.5 (5.2) 85.9 20.7 (15.2) 114.3 4,448.9 108.1 2020 1,678.1 1,593.7 114.6 513.3 194.0 4,093.7 72.5 471.3 543.8 (2.6) 93.3 18.1 (16.5) 121.1 4,850.9 114.8 2021 1,995.4 1,686.5 126.1 544.6 240.9 4,593.5 63.5 578.2 641.8 0.0 102.4 23.6 (17.6) 127.8 5,471.6 126.3 2022 2,288.1 1,718.4 129.0 581.8 256.3 4,973.6 57.5 554.4 611.9 0.0 110.3 22.7 (19.0) 134.8 5,834.3 131.3 2023 2,288.8 1,557.1 116.6 628.8 249.0 4,840.3 23.2 778.6 801.9 0.0 94.6 26.5 (20.5) 142.6 5,885.2 129.2 2024 2,132.9 1,609.1 120.0 653.3 241.7 4,757.1 33.4 779.8 813.2 0.0 94.5 25.6 (21.7) 150.3 5,818.9 124.8 2025 2,159.1 1,650.8 124.0 671.0 255.7 4,860.5 56.1 998.1 1,054.2 0.0 103.3 32.1 (23.0) 158.2 6,185.3 129.5 2026 2,223.5 1,808.0 137.7 691.4 259.1 5,119.7 48.9 1,000.6 1,049.5 0.0 110.9 30.8 (24.3) 92.2 6,378.7 130.2 2027 2,332.2 1,949.5 153.1 714.8 252.8 5,402.5 11.9 1,015.5 1,027.5 0.0 120.9 30.4 (25.4) 92.2 6,648.0 132.3 2028 2,414.9 2,067.6 167.7 742.1 245.5 5,637.8 48.9 1,020.6 1,069.5 0.0 132.3 29.1 (26.8) 98.1 6,940.0 134.8 2029 2,471.1 2,257.6 183.8 767.6 239.5 5,919.6 43.0 1,019.4 1,062.4 0.0 148.7 27.6 (28.7) 98.0 7,227.6 136.6 2030 2,549.2 2,420.8 197.7 794.9 256.1 6,218.7 41.7 1,011.5 1,053.2 0.0 160.1 26.1 (30.7) 97.3 7,524.7 138.7 2031 2,595.6 2,574.3 211.6 822.2 260.4 6,464.0 59.0 1,012.9 1,071.9 0.0 172.8 24.5 (32.2) 96.8 7,797.7 140.3 2032 2,647.4 2,810.6 231.3 852.1 278.2 6,819.5 53.3 1,018.1 1,071.3 0.0 190.3 22.8 (35.3) 96.2 8,164.9 143.7 2033 2,737.1 2,965.2 245.5 882.2 283.5 7,113.3 43.8 1,049.9 1,093.7 0.0 199.1 22.7 (37.3) 95.9 8,487.4 145.7 2034 2,780.7 3,119.5 262.9 912.4 275.0 7,350.4 58.3 1,278.4 1,336.7 0.0 222.4 32.4 (40.5) 95.1 8,996.4 151.0 2035 2,829.6 3,316.0 281.2 943.1 266.6 7,636.5 47.1 1,321.5 1,368.7 0.0 238.1 32.3 (43.3) 94.4 9,326.7 153.1 2036 2,901.6 3,472.3 295.0 980.7 288.3 7,937.9 36.1 1,370.0 1,406.1 0.0 251.9 32.1 (46.7) 93.8 9,675.1 155.6 2037 2,937.4 3,695.6 317.2 993.2 294.1 8,237.4 99.7 1,414.6 1,514.4 0.0 273.7 31.9 (46.9) 93.3 10,103.8 158.9
CPW@ 7.86% (2008-2017) 4,236.0 5,503.7 320.5 2,890.2 338.5 13,288.8 726.6 2,971.1 3,697.8 (122.8) 331.0 155.8 (57.1) 415.1 17,708.6 76.6
(2008-2027) 10,274.6 10,556.9 690.8 4,722.9 1,051.2 27,296.4 946.8 5,166.7 6,113.5 (142.6) 641.0 232.9 (117.2) 807.6 34,831.6 93.7
(2008-2037) 14,215.2 14,661.1 1,031.8 5,988.6 1,445.8 37,342.5 1,023.6 6,834.4 7,858.0 (142.6) 922.8 274.2 (169.8) 950.7 47,035.8 103.2
APPENDIX 2 TABLE 38. TABLE 39. SUPPLY SIDE SCENARIO 3 (SS-3) 800 MW NUCLEAR and 400 MW SOLAR GENERATION by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 39. TABLE 40. SUPPLY SIDE SCENARIO 4 (SS-4) 800 MW NUCLEAR and 2,000 MW SOLAR GENERATION by 2025 LOADS AND RESOURCES SUMMARY
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 1. Load Requirements: 2. Peak Demand (prior to EE and DE) 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293 9,605 9,905 10,207 10,513 10,820 11,128 11,442 3. Reserve Requirements 1,000 1,034 1,049 1,070 1,086 1,129 1,175 1,225 1,274 1,322 1,369 1,414 1,531 1,577 1,623 1,669 1,716 4. Total Load Requirements 8,321 8,406 8,523 8,681 8,808 9,134 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
5. Existing Resources: 6. Existing Generation 6,267 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 6,270 7. Seasonal Exchange 480 480 480 480 480 480 480 480 480 480 480 480 00000 8. Purchases - Renewable Energy * 55 61 61 331 326 326 326 326 326 326 326 326 325 325 315 315 315 9. Purchase - SRP T&C 238 0000000000000000 10. Purchases - Gas CC Tolling 500 1,060 1,060 1,060 1,060 1,060 1,060 1,060 560 560 560 000000 11. Purchases - Market Call Options 650 650 650 650 650 650 650 150 150 150 150 150 150 0000 12. Demand Response Contract 0 28 59 83 83 83 83 105 105 105 105 105 105 105 105 105 0 13. Total Existing Resources: 8,190 8,548 8,579 8,873 8,868 8,868 8,868 8,391 7,891 7,891 7,890 7,330 6,850 6,700 6,690 6,690 6,585
14. Future Planned Resource Additions: 15. Energy Efficiency * 00000000000000000 16. Distributed Renewable Energy * 16 26 39 55 65 75 86 107 129 152 176 200 226 253 281 309 339 17. Renewable Energy Resources * 0000702203705707709701,170 1,370 1,515 1,515 1,795 1,795 1,885 18. Baseload Nuclear 0000000000000400800800800 19. Gas Combined Cycle 00000000000000000 20. Peaking Resources 00000003761,034 1,128 1,316 1,974 2,726 2,726 2,726 2,726 3,102 21. Short-Term Market Purchases 000000167426427475421445421496151478447 22. Total Future Resource Additions: 16 26 39 55 135 295 623 1,478 2,359 2,724 3,083 3,988 4,888 5,389 5,752 6,107 6,573
23. Total Resources: 8,206 8,574 8,618 8,928 9,003 9,163 9,491 9,869 10,250 10,615 10,973 11,319 11,738 12,090 12,442 12,798 13,158
New Renewable Nameplate Capacity ● 100 106 106 389 459 659 859 1,159 1,459 1,759 2,159 2,459 2,619 2,619 2,898 2,898 3,248
* Note resources shown as their expected capacity contribution at time of system peak - Existing resources exclude short-term market purchase or sale transactions ● New Renewable Nameplate Capacity includes all future renewable resources plus any existing renewable resources in service after Jan 1, 2009. (Lines 8 and 17)
APPENDIX 2 TABLE 40. TABLE 41. SUPPLY SIDE SCENARIO 4 (SS-4) 800 MW NUCLEAR and 2,000 MW SOLAR GENERATION by 2025 TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 0.0 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 0.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 0.0 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 0.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 0.0 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 0.0 2,535.0 74.5 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 (0.1) 2,766.4 78.9 2015 639.1 846.7 51.1 462.7 89.7 2,089.4 120.9 707.6 828.5 (33.0) 56.0 30.6 (12.2) 58.3 (0.1) 3,017.4 83.1 2016 810.8 893.6 56.0 437.2 137.8 2,335.4 147.5 863.5 1,011.1 (37.0) 61.7 33.7 (12.8) 93.4 (0.0) 3,485.4 92.9 2017 996.9 1,067.7 67.8 452.4 160.2 2,745.0 158.0 893.5 1,051.5 (39.2) 65.5 36.7 (13.5) 100.0 (0.0) 3,946.0 101.7 2018 1,142.4 1,184.6 78.7 468.4 161.3 3,035.4 128.6 974.2 1,102.8 (38.4) 71.6 40.7 (14.4) 107.3 (0.0) 4,304.9 107.7 2019 1,244.7 1,168.9 77.5 481.8 157.3 3,130.3 125.4 1,163.1 1,288.5 (5.2) 71.6 46.4 (15.5) 114.3 (0.9) 4,629.5 112.5 2020 1,458.0 1,342.9 90.4 501.3 170.4 3,562.9 66.1 1,214.9 1,281.1 (2.6) 76.4 50.4 (16.8) 121.1 (1.4) 5,071.1 120.1 2021 1,728.5 1,421.8 96.9 528.7 217.2 3,993.0 63.4 1,370.7 1,434.1 0.0 84.8 57.6 (17.8) 127.8 (2.8) 5,676.8 131.0 2022 2,020.5 1,442.2 98.1 564.9 233.0 4,358.7 59.5 1,354.9 1,414.4 0.0 91.4 56.2 (19.3) 134.8 (2.6) 6,033.6 135.8 2023 2,031.1 1,304.1 86.8 611.4 226.4 4,259.8 25.2 1,578.8 1,604.0 0.0 76.7 59.5 (21.1) 142.6 (20.1) 6,101.4 134.0 2024 1,884.8 1,364.5 90.5 635.4 268.2 4,243.5 35.2 1,582.2 1,617.5 0.0 76.8 57.9 (22.3) 150.3 (36.9) 6,086.9 130.5 2025 1,920.4 1,403.2 93.3 652.5 288.1 4,357.6 57.9 1,798.6 1,856.5 0.0 84.1 63.8 (23.6) 158.2 (39.1) 6,457.5 135.2 2026 1,994.2 1,538.8 104.5 672.4 280.9 4,590.8 50.6 1,800.8 1,851.4 0.0 91.2 61.9 (24.9) 92.2 (28.7) 6,633.8 135.4 2027 2,058.2 1,686.4 115.9 690.8 294.6 4,845.9 45.6 1,815.7 1,861.3 0.0 102.1 60.8 (25.9) 92.2 (24.8) 6,911.8 137.6 2028 2,131.6 1,801.0 125.2 714.8 296.9 5,069.5 61.0 1,822.5 1,883.5 0.0 114.5 58.7 (27.2) 98.1 (21.5) 7,175.5 139.3 2029 2,211.6 1,975.6 139.8 740.1 288.6 5,355.6 54.7 1,819.8 1,874.5 0.0 130.7 56.5 (29.1) 98.0 (12.8) 7,473.4 141.2 2030 2,300.1 2,134.2 152.5 766.5 304.2 5,657.6 52.9 1,811.8 1,864.7 0.0 141.7 54.1 (31.1) 97.3 (11.3) 7,773.0 143.3 2031 2,377.1 2,281.6 164.3 793.7 307.7 5,924.4 47.5 1,813.0 1,860.5 0.0 154.0 51.7 (32.6) 96.8 (9.2) 8,045.5 144.7 2032 2,452.3 2,506.5 183.1 823.3 300.2 6,265.4 42.2 1,820.1 1,862.3 0.0 171.3 49.1 (35.6) 96.2 (5.3) 8,403.5 147.9 2033 2,527.8 2,660.1 195.5 851.7 317.6 6,552.7 56.8 1,850.0 1,906.8 0.0 178.5 47.9 (37.6) 95.9 (4.0) 8,740.1 150.0 2034 2,586.0 2,818.5 210.0 881.3 320.6 6,816.5 46.4 2,078.5 2,124.9 0.0 201.7 56.5 (40.9) 95.1 (3.4) 9,250.4 155.2 2035 2,658.1 3,001.7 227.5 911.7 311.0 7,110.0 35.5 2,121.7 2,157.2 0.0 217.9 55.3 (43.7) 94.4 (2.5) 9,588.7 157.4 2036 2,713.1 3,151.7 239.7 947.4 331.4 7,383.4 74.7 2,171.8 2,246.6 0.0 229.9 54.0 (47.2) 93.8 (2.8) 9,957.7 160.2 2037 2,764.9 3,369.0 259.7 959.2 335.8 7,688.6 14.3 2,214.8 2,229.1 0.0 251.5 52.5 (47.2) 93.3 (1.5) 10,266.4 161.4
CPW@ 7.86% (2008-2017) 4,191.7 5,433.7 315.2 2,888.3 338.2 13,167.1 718.2 3,192.1 3,910.3 (122.8) 325.8 166.0 (57.2) 415.1 (0.1) 17,804.2 77.1
(2008-2027) 9,530.1 9,741.7 604.8 4,675.7 1,032.8 25,585.1 944.7 7,646.5 8,591.3 (142.6) 582.9 337.5 (118.4) 807.6 (41.3) 35,602.1 95.8
(2008-2037) 13,141.1 13,405.3 873.5 5,897.4 1,491.8 34,809.0 1,018.9 10,505.1 11,524.0 (142.6) 835.8 417.7 (171.6) 950.7 (54.2) 48,168.8 105.6
APPENDIX 2 TABLE 41. TABLE 42. SUPPLY SIDE SCENARIO 4 (SS-4) 800 MW NUCLEAR and 400 MW SOLAR GENERATION by 2025 OWN LOAD ENERGY REQUIREMENTS (GWh)
2008 32,171.7 2009 32,731.8 2010 32,892.0 2011 33,217.8 2012 33,673.2 2013 34,025.9 2014 35,064.3 2015 36,292.3 2016 37,534.2 2017 38,791.4 2018 39,981.8 2019 41,136.5 2020 42,238.3 2021 43,333.3 2022 44,435.5 2023 45,535.2 2024 46,637.5 2025 47,745.3 2026 48,993.4 2027 50,246.5 2028 51,500.3 2029 52,917.3 2030 54,252.7 2031 55,588.2 2032 56,833.5 2033 58,259.0 2034 59,594.5 2035 60,929.8 2036 62,166.8 2037 63,600.7
(2008-2017) 346,394.6
(2008-2027) 796,677.8
(2008-2037) 1,372,320.6
APPENDIX 2 TABLE 42. TABLE 43. SUPPLY SIDE SCENARIO COMPARISONS ANNUAL NATURAL GAS BURNS (BCF)
SS-D SS-N SS-S1 SS-S2 SS-1 SS-2 SS-3 SS-4
2008 73.6 73.6 73.6 73.6 73.6 73.6 73.6 73.6 2009 76.6 76.6 76.6 76.6 76.6 76.6 76.6 76.6 2010 75.5 75.5 75.5 75.5 75.5 75.5 75.5 75.5 2011 75.9 75.9 75.9 75.9 75.9 75.9 75.9 75.9 2012 72.9 72.9 72.9 72.9 72.9 72.9 72.9 72.9 2013 73.0 73.0 73.0 73.0 73.0 73.0 73.0 73.0 2014 85.1 85.1 80.1 80.9 82.6 81.4 81.4 81.4 2015 92.8 92.8 83.3 84.5 88.1 85.8 87.0 85.8 2016 103.2 103.2 88.6 92.7 96.1 92.0 96.5 91.0 2017 113.3 113.3 92.7 94.7 105.6 100.0 105.9 94.7 2018 122.2 122.2 95.9 98.3 114.3 107.1 114.5 97.6 2019 120.5 120.5 89.8 92.9 112.5 105.5 113.0 91.8 2020 129.5 129.5 94.1 97.6 121.3 116.0 121.6 95.8 2021 132.8 134.7 100.4 102.6 126.9 119.9 127.1 100.5 2022 144.9 136.0 112.5 114.6 130.2 119.6 124.9 97.9 2023 144.3 117.1 112.5 114.5 115.2 101.5 102.1 78.8 2024 151.4 118.5 119.5 121.7 117.9 103.0 102.2 80.5 2025 154.5 119.8 122.8 124.9 119.5 103.9 102.8 81.4 2026 165.3 131.0 133.1 135.3 130.7 114.6 113.8 90.3 2027 170.7 138.8 141.6 140.9 137.8 124.8 122.3 99.6 2028 180.9 146.1 153.5 150.5 145.7 131.7 128.5 105.9 2029 192.0 157.8 164.2 161.8 157.2 143.8 140.5 116.7 2030 199.6 164.5 171.3 169.2 166.6 150.3 149.1 125.4 2031 208.2 171.9 179.6 177.5 174.8 157.8 156.8 133.0 2032 223.1 188.3 195.1 192.7 191.0 174.3 173.4 148.8 2033 231.7 194.5 204.0 201.2 197.8 180.3 179.1 154.8 2034 237.9 201.8 211.8 208.1 205.7 188.3 187.0 163.5 2035 245.6 210.9 218.6 215.6 214.2 196.9 196.2 172.1 2036 252.5 216.6 225.6 221.7 220.1 202.7 201.6 177.6 2037 265.4 228.4 239.8 235.4 232.7 214.1 213.1 188.9
(2008-2017) 841.9 841.9 792.2 800.4 819.9 806.7 818.3 800.3
(2008-2027) 2,277.9 2,110.1 1,914.4 1,943.5 2,046.1 1,922.5 1,962.6 1,714.7
(2008-2037) 4,514.8 3,991.0 3,877.9 3,877.4 3,952.0 3,662.7 3,688.0 3,201.3
APPENDIX 2 TABLE 43. TABLE 44. SUPPLY SIDE SCENARIO COMPARISONS CO2 TOTAL PLANT EMISSIONS (Tons)
SS-D SS-N SS-S1 SS-S2 SS-1 SS-2 SS-3 SS-4
2008 18,427,317 18,427,317 18,427,317 18,427,317 18,427,317 18,427,317 18,427,317 18,427,317 2009 18,528,365 18,528,365 18,528,365 18,528,365 18,528,365 18,528,365 18,528,365 18,528,365 2010 18,715,038 18,715,038 18,715,038 18,715,038 18,715,038 18,715,038 18,715,038 18,715,038 2011 18,537,583 18,537,583 18,537,583 18,537,583 18,537,583 18,537,583 18,537,583 18,537,583 2012 18,524,901 18,524,901 18,524,901 18,524,901 18,524,901 18,524,901 18,524,901 18,524,901 2013 18,554,573 18,554,573 18,554,573 18,554,517 18,554,573 18,554,573 18,554,573 18,554,573 2014 19,032,066 19,032,066 18,656,706 18,642,023 18,842,213 18,712,756 18,712,756 18,712,756 2015 19,596,172 19,596,172 18,832,297 18,820,279 19,215,617 18,944,747 19,040,972 18,944,533 2016 20,389,992 20,389,992 19,247,885 19,431,077 19,836,969 19,438,791 19,781,250 19,301,580 2017 21,366,129 21,366,129 19,816,056 19,836,804 20,801,747 20,280,488 20,772,355 19,837,249 2018 22,355,551 22,355,551 20,418,823 20,462,304 21,786,428 21,171,535 21,764,118 20,399,098 2019 22,458,796 22,458,796 20,083,273 20,128,074 21,895,307 21,257,763 21,857,022 19,995,605 2020 22,694,748 22,694,748 20,109,096 20,186,555 22,122,424 21,704,731 22,093,395 19,984,638 2021 22,925,541 23,072,863 20,580,416 20,535,663 22,514,625 21,987,382 22,486,257 20,329,010 2022 23,328,987 22,730,589 21,114,799 21,063,575 22,336,562 21,512,197 21,904,897 19,712,318 2023 23,357,181 21,406,412 21,086,045 21,057,068 21,303,225 20,128,783 20,192,297 17,882,585 2024 23,999,477 21,543,265 21,752,540 21,709,783 21,532,448 20,199,690 20,163,750 17,914,649 2025 24,117,103 21,497,466 21,890,957 21,854,705 21,526,614 20,170,971 20,075,169 17,832,902 2026 24,588,397 22,126,660 22,403,126 22,368,343 22,124,959 20,800,368 20,761,610 18,543,143 2027 25,128,892 22,805,470 23,148,196 22,900,101 22,794,507 21,680,306 21,493,199 19,468,554 2028 25,789,503 23,258,448 23,963,182 23,589,209 23,294,595 22,221,349 21,908,665 19,944,674 2029 26,515,694 24,122,076 24,674,824 24,320,194 24,113,556 23,108,415 22,803,346 20,864,884 2030 27,273,075 24,832,831 25,396,839 25,065,405 25,000,670 23,795,507 23,641,639 21,737,490 2031 27,853,542 25,382,003 25,944,559 25,634,663 25,610,063 24,339,933 24,240,635 22,354,327 2032 28,202,124 25,869,918 26,363,513 26,030,153 26,115,357 24,851,068 24,786,115 22,978,151 2033 29,027,070 26,608,783 27,214,098 26,898,751 26,863,375 25,611,354 25,528,444 23,745,465 2034 29,193,351 26,895,172 27,514,508 27,122,525 27,161,591 25,917,395 25,861,420 24,138,633 2035 30,013,610 27,775,106 28,267,772 27,933,167 28,016,185 26,795,941 26,755,216 25,009,015 2036 30,434,926 28,142,512 28,685,072 28,312,998 28,385,349 27,154,012 27,101,920 25,350,830 2037 31,056,553 28,716,348 29,423,384 29,056,111 29,008,031 27,741,530 27,676,169 25,960,526
(2008-2017) 191,672,136 191,672,136 187,840,721 188,017,904 189,984,323 188,664,559 189,595,110 188,083,895
(2008-2027) 426,626,809 414,363,955 400,427,993 400,284,075 409,921,424 399,278,285 402,386,824 380,146,397
(2008-2037) 711,986,257 675,967,151 667,875,743 664,247,252 673,490,197 650,814,790 652,690,393 612,230,392
APPENDIX 2 TABLE 44. TABLE 45. RISK ANALYSIS A - CARBON COST AT $25/TON SELECTED PLAN (SP/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 50.0 2,155.7 67.0 2009 549.1 787.5 42.1 412.2 8.6 1,799.6 76.8 308.1 384.8 (8.3) 42.5 14.5 (1.2) 81.6 2,313.6 71.1 2010 573.3 736.2 41.5 422.9 20.9 1,794.8 115.7 335.4 451.1 (9.1) 42.2 24.5 (9.5) 82.3 2,376.4 73.1 2011 580.5 770.7 43.5 419.9 28.5 1,843.1 102.9 277.4 380.2 (10.0) 43.4 23.2 (10.0) 107.1 2,377.1 72.9 2012 578.7 683.7 39.7 423.8 30.7 1,756.6 105.2 437.6 542.9 (14.0) 42.5 27.8 234.4 134.9 2,725.0 82.8 2013 583.5 686.6 41.6 429.0 49.2 1,789.9 105.8 484.9 590.7 (19.0) 44.3 27.2 241.9 115.8 2,790.8 84.3 2014 601.0 779.4 47.5 446.3 66.1 1,940.4 106.2 545.4 651.5 (24.3) 51.0 29.0 252.9 134.5 3,034.9 89.4 2015 639.1 790.6 47.9 462.7 76.3 2,016.7 106.6 663.9 770.4 (33.0) 51.8 29.2 268.3 160.7 3,264.2 93.3 2016 798.3 857.4 53.3 436.7 103.7 2,249.3 139.4 705.8 845.2 (37.0) 59.0 27.0 296.0 220.0 3,659.4 101.6 2017 989.0 1,058.8 67.2 452.0 120.2 2,687.2 165.8 601.5 767.3 (39.2) 64.8 23.8 331.2 230.5 4,065.6 109.7 2018 1,184.0 1,210.4 80.7 470.0 163.0 3,108.0 127.4 538.2 665.6 (38.4) 72.8 21.4 381.8 241.7 4,452.8 117.1 2019 1,326.5 1,223.1 82.2 485.2 180.0 3,297.1 122.0 581.1 703.0 (5.2) 75.5 20.7 407.1 252.7 4,750.9 121.8 2020 1,589.1 1,428.3 103.1 508.8 192.2 3,821.5 67.5 468.9 536.4 (2.6) 80.9 18.1 439.2 263.6 5,157.1 129.2 2021 1,885.2 1,508.2 113.2 539.0 239.1 4,284.7 67.8 574.6 642.4 0.0 89.4 23.6 490.6 274.7 5,805.4 142.2 2022 2,171.9 1,523.3 114.5 575.6 254.6 4,639.9 61.5 554.4 615.9 0.0 95.2 22.7 496.4 286.0 6,156.1 147.4 2023 2,177.4 1,355.6 100.2 622.4 247.3 4,502.9 20.6 778.6 799.2 0.0 80.3 26.5 461.9 298.4 6,169.1 144.4 2024 2,026.1 1,399.9 101.8 646.7 240.2 4,414.7 24.4 779.7 804.2 0.0 79.3 25.6 485.1 310.8 6,119.6 140.2 2025 2,040.1 1,424.8 103.6 663.6 235.5 4,467.5 52.1 998.2 1,050.3 0.0 85.6 32.1 507.8 323.5 6,466.7 144.9 2026 2,080.6 1,560.1 116.6 682.5 249.3 4,689.1 57.5 1,000.6 1,058.1 0.0 92.4 30.8 577.5 262.4 6,710.3 146.7 2027 2,129.3 1,700.5 127.9 700.8 252.4 4,911.0 51.1 1,015.5 1,066.6 0.0 101.9 30.4 658.1 258.3 7,026.2 150.0 2028 2,200.3 1,806.7 137.6 725.1 245.6 5,115.4 60.4 1,020.6 1,080.9 0.0 113.9 29.1 723.1 258.7 7,321.1 152.6 2029 2,277.8 1,978.7 151.9 750.7 261.8 5,420.8 47.9 1,019.4 1,067.3 0.0 128.5 27.6 809.8 251.9 7,705.9 156.4 2030 2,343.8 2,126.4 164.3 776.7 265.6 5,676.8 61.3 1,011.6 1,073.0 0.0 138.3 26.1 881.9 243.1 8,039.1 159.2 2031 2,404.8 2,262.7 175.3 803.6 259.8 5,906.2 48.6 1,012.9 1,061.5 0.0 148.7 24.5 946.0 232.8 8,319.7 160.9 2032 2,478.1 2,476.4 193.0 833.5 277.7 6,258.7 36.9 1,018.0 1,054.9 0.0 164.8 22.8 996.8 220.5 8,718.6 165.0 2033 2,552.2 2,613.1 204.5 862.2 281.6 6,513.6 44.6 1,049.9 1,094.5 0.0 171.0 22.7 1,058.9 206.4 9,067.1 167.5 2034 2,587.2 2,748.7 218.1 891.3 273.9 6,719.2 51.7 1,278.4 1,330.1 0.0 192.1 32.4 1,101.9 189.4 9,565.1 172.8 2035 2,620.0 2,926.3 234.2 920.5 291.6 6,992.6 58.3 1,321.5 1,379.8 0.0 206.9 32.3 1,174.2 170.0 9,955.7 176.0 2036 2,683.4 3,058.3 246.0 956.7 297.5 7,241.8 15.0 1,370.0 1,385.0 0.0 218.2 32.1 1,222.1 147.6 10,246.9 177.7 2037 2,727.3 3,257.1 264.7 968.5 290.2 7,507.9 71.5 1,414.6 1,486.1 0.0 237.3 31.9 1,287.1 122.1 10,672.5 180.9
CPW@ 7.86% (2008-2017) 4,181.6 5,247.4 304.9 2,887.9 294.8 12,916.7 709.9 2,920.9 3,630.8 (122.8) 313.9 155.8 898.0 813.7 18,606.1 82.3
(2008-2027) 9,872.7 9,715.2 628.2 4,701.0 990.2 25,907.3 934.2 5,106.9 6,041.1 (142.6) 580.0 232.9 2,406.2 1,683.5 36,708.4 102.4
(2008-2037) 13,518.1 13,324.9 911.3 5,937.6 1,393.8 35,085.7 1,008.8 6,774.6 7,783.4 (142.6) 823.4 274.2 3,867.6 2,000.7 49,692.6 113.8
APPENDIX 1 TABLE 45. TABLE 46. RISK ANALYSIS A - CARBON COST AT $25/TON DEFAULT ENERGY EFFICIENCY SCENARIO (EE-D/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 26.6 2,134.4 66.3 2009 549.1 800.3 43.0 412.2 8.6 1,813.3 85.7 309.4 395.1 (8.3) 43.8 14.7 (1.2) 56.0 2,313.4 70.7 2010 573.3 763.9 42.8 422.9 20.9 1,823.9 120.7 341.1 461.8 (9.1) 44.4 24.8 (9.5) 54.8 2,391.2 72.7 2011 580.5 796.7 44.4 419.9 28.5 1,870.0 101.8 309.4 411.2 (10.0) 47.3 29.2 (9.9) 67.0 2,404.8 72.4 2012 578.7 721.4 42.1 423.8 30.7 1,796.7 104.2 457.6 561.8 (14.0) 45.9 28.2 246.3 84.9 2,749.8 81.7 2013 583.5 742.5 44.9 429.0 49.2 1,849.1 104.8 496.3 601.1 (19.0) 49.8 28.2 259.0 51.4 2,819.8 82.9 2014 597.5 873.2 52.8 446.3 91.2 2,060.9 119.7 465.9 585.6 (24.3) 58.0 25.8 279.5 54.9 3,040.4 86.7 2015 641.6 915.8 55.8 463.2 103.8 2,180.2 151.2 529.0 680.2 (33.0) 62.5 23.1 307.7 58.3 3,279.0 90.4 2016 843.0 988.2 62.6 440.5 140.5 2,474.7 157.8 553.0 710.8 (37.0) 69.9 20.2 335.7 93.4 3,667.6 97.7 2017 1,017.2 1,221.6 79.8 458.3 175.7 2,952.7 156.0 439.1 595.0 (39.2) 77.0 17.2 376.8 100.0 4,079.5 105.2 2018 1,116.3 1,371.1 92.1 476.4 184.5 3,240.4 125.2 372.2 497.4 (38.4) 85.6 15.0 423.9 107.3 4,331.1 108.3 2019 1,148.9 1,447.9 98.7 491.8 180.6 3,367.9 124.0 409.8 533.8 (5.2) 95.4 14.3 468.5 114.3 4,589.0 111.6 2020 1,295.6 1,668.9 120.0 516.0 193.4 3,793.8 66.9 285.6 352.5 (2.6) 99.7 11.9 499.1 121.1 4,875.4 115.4 2021 1,519.6 1,773.5 137.7 549.7 199.8 4,180.3 67.3 344.1 411.5 0.0 109.6 15.2 557.3 127.8 5,401.7 124.7 2022 1,666.1 1,917.0 153.6 575.1 196.6 4,508.4 52.1 320.2 372.3 0.0 128.5 14.5 598.4 134.8 5,756.8 129.6 2023 1,635.1 1,978.3 158.5 594.3 191.8 4,558.0 52.3 453.3 505.6 0.0 126.6 18.5 637.8 142.6 5,989.1 131.5 2024 1,644.1 2,117.7 170.3 607.2 206.0 4,745.4 53.0 457.5 510.5 0.0 136.0 17.8 697.8 150.3 6,257.7 134.2 2025 1,685.9 2,172.4 175.9 624.1 212.3 4,870.5 51.9 607.6 659.4 0.0 144.0 24.5 732.4 158.2 6,589.1 138.0 2026 1,740.5 2,331.5 188.7 642.3 207.3 5,110.3 46.7 612.2 658.8 0.0 152.6 23.5 800.4 92.2 6,837.9 139.6 2027 1,859.3 2,457.9 206.9 664.3 202.5 5,390.9 9.8 630.1 640.0 0.0 163.0 22.4 876.1 92.2 7,184.6 143.0 2028 1,935.4 2,612.7 225.9 689.6 218.5 5,682.1 54.7 639.9 694.6 0.0 176.4 21.3 956.5 98.1 7,629.0 148.1 2029 1,995.8 2,806.4 243.2 713.3 223.3 5,982.0 48.7 644.3 692.9 0.0 195.1 20.1 1,044.7 98.0 8,032.8 151.8 2030 2,099.1 3,002.2 261.9 739.3 218.7 6,321.2 34.1 640.3 674.3 0.0 208.6 18.8 1,131.0 97.3 8,451.2 155.8 2031 2,153.3 3,128.7 275.2 764.6 237.4 6,559.2 39.9 771.1 811.0 0.0 221.6 25.4 1,194.3 96.8 8,908.3 160.3 2032 2,177.5 3,343.0 296.1 791.2 243.0 6,850.8 53.8 862.3 916.1 0.0 237.9 28.9 1,243.2 96.2 9,373.1 164.9 2033 2,246.9 3,527.6 314.0 818.0 237.0 7,143.5 52.0 898.6 950.5 0.0 250.9 29.2 1,315.4 95.9 9,785.5 168.0 2034 2,349.4 3,762.0 340.7 847.7 259.6 7,559.4 41.2 938.9 980.1 0.0 280.2 29.5 1,381.6 95.1 10,325.8 173.3 2035 2,454.9 3,930.4 356.8 877.7 264.0 7,883.9 30.1 978.8 1,008.9 0.0 294.1 29.8 1,455.0 94.4 10,766.1 176.7 2036 2,525.0 4,139.9 377.1 912.4 257.7 8,212.2 69.0 1,026.5 1,095.5 0.0 310.9 30.1 1,525.6 93.8 11,268.0 181.3 2037 2,566.2 4,344.0 401.0 922.6 253.8 8,487.7 36.7 1,069.8 1,106.5 0.0 327.5 30.3 1,592.2 93.3 11,637.5 183.6
CPW@ 7.86% (2008-2017) 4,216.7 5,627.0 329.2 2,893.1 369.3 13,435.2 758.3 2,697.4 3,455.7 (122.8) 346.6 150.3 995.8 415.1 18,675.9 80.8
(2008-2027) 8,909.3 11,489.6 780.8 4,670.9 989.5 26,840.0 984.7 4,055.1 5,039.7 (142.6) 723.2 204.2 2,895.1 807.6 36,367.2 97.9
(2008-2037) 12,190.3 16,458.8 1,222.9 5,847.1 1,343.5 37,062.6 1,053.4 5,265.7 6,319.1 (142.6) 1,080.0 242.2 4,741.2 950.7 50,253.2 110.2
APPENDIX 2 TABLE 46. TABLE 47. RISK ANALYSIS A - CARBON COST AT $25/TON ENERGY EFFICIENCY SCENARIO 1 (EE-1/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 50.0 2,157.7 67.1 2009 549.1 790.6 42.5 412.2 8.6 1,803.0 83.6 307.3 390.9 (8.3) 43.3 14.7 (1.2) 82.4 2,324.8 71.4 2010 573.3 743.5 42.3 422.9 20.9 1,802.9 119.4 336.8 456.2 (9.1) 43.3 24.8 (9.5) 84.0 2,392.7 73.6 2011 580.5 767.4 43.0 419.9 28.5 1,839.2 102.1 302.8 404.9 (10.0) 45.3 29.2 (10.0) 88.3 2,387.0 73.2 2012 578.7 686.2 40.2 423.8 30.7 1,759.6 104.5 449.8 554.2 (14.0) 44.1 28.2 235.9 108.1 2,716.1 82.4 2013 583.5 702.9 42.5 429.0 49.2 1,807.2 105.0 485.8 590.8 (19.0) 46.8 28.2 246.9 74.9 2,775.8 83.6 2014 597.5 822.7 50.0 446.3 77.8 1,994.3 105.5 457.6 563.0 (24.3) 54.5 25.8 266.3 78.7 2,958.4 86.7 2015 629.5 864.6 52.2 462.7 97.5 2,106.5 133.5 517.1 650.6 (33.0) 58.5 23.1 293.1 82.7 3,181.6 90.2 2016 808.1 927.3 58.4 438.9 141.1 2,373.8 156.8 544.4 701.2 (37.0) 65.2 20.2 319.3 118.3 3,561.1 97.7 2017 975.6 1,151.7 74.5 456.4 160.7 2,818.9 156.6 433.2 589.7 (39.2) 71.7 17.2 358.6 125.7 3,942.7 104.7 2018 1,078.1 1,294.9 86.6 474.5 178.4 3,112.4 120.0 365.8 485.8 (38.4) 79.5 15.0 403.9 133.8 4,192.0 108.1 2019 1,109.9 1,364.5 92.4 489.6 182.0 3,238.3 122.5 403.8 526.3 (5.2) 88.7 14.3 446.8 141.6 4,450.9 111.6 2020 1,256.3 1,575.3 113.3 513.6 179.0 3,637.6 67.3 283.3 350.7 (2.6) 92.4 11.9 476.2 149.2 4,715.3 115.2 2021 1,469.8 1,677.8 130.5 546.9 194.4 4,019.4 69.5 342.3 411.8 0.0 102.3 15.2 533.7 156.9 5,239.3 124.8 2022 1,609.8 1,812.9 145.2 572.0 199.7 4,339.6 54.8 320.3 375.0 0.0 120.1 14.5 573.3 164.7 5,587.2 129.9 2023 1,581.2 1,869.5 149.9 591.1 194.9 4,386.5 53.0 453.3 506.3 0.0 118.2 18.5 611.2 173.5 5,814.3 131.9 2024 1,592.5 2,002.1 160.9 604.0 190.1 4,549.5 52.0 457.7 509.6 0.0 126.8 17.8 669.7 182.2 6,055.7 134.2 2025 1,633.5 2,051.1 165.9 620.4 206.0 4,677.0 55.7 607.5 663.2 0.0 134.2 24.5 701.8 191.1 6,391.8 138.4 2026 1,674.2 2,202.8 177.8 638.0 211.6 4,904.4 57.6 613.0 670.6 0.0 142.2 23.5 769.0 126.0 6,635.6 140.0 2027 1,785.9 2,324.3 195.3 659.5 207.2 5,172.2 20.7 630.6 651.3 0.0 152.2 22.4 843.8 125.2 6,967.1 143.3 2028 1,880.5 2,472.0 213.5 685.1 201.4 5,452.6 55.7 639.2 694.9 0.0 164.9 21.3 922.9 130.0 7,386.5 148.2 2029 1,938.7 2,657.5 230.0 708.5 218.4 5,753.1 56.0 645.6 701.6 0.0 183.0 20.1 1,009.3 128.6 7,795.6 152.2 2030 2,033.5 2,844.1 248.0 734.0 224.1 6,083.7 39.1 641.0 680.0 0.0 195.8 18.8 1,093.7 126.3 8,198.4 156.1 2031 2,107.4 2,964.0 260.1 759.7 219.2 6,310.4 34.3 770.3 804.7 0.0 207.6 25.4 1,154.6 123.8 8,626.5 160.3 2032 2,145.4 3,169.0 280.3 786.4 239.1 6,620.2 46.5 861.3 907.8 0.0 223.4 28.9 1,201.7 121.0 9,102.9 165.4 2033 2,216.2 3,344.5 297.1 813.1 245.4 6,916.2 43.1 897.4 940.5 0.0 235.7 29.2 1,272.1 117.9 9,511.7 168.6 2034 2,297.6 3,565.1 322.2 841.8 239.8 7,266.5 54.6 939.1 993.8 0.0 263.8 29.5 1,335.1 113.8 10,002.5 173.4 2035 2,370.4 3,726.7 337.4 870.5 260.3 7,565.2 50.6 981.1 1,031.7 0.0 277.3 29.8 1,406.8 109.5 10,420.4 176.6 2036 2,454.6 3,928.6 356.8 905.5 268.0 7,913.6 27.2 1,026.0 1,053.2 0.0 293.1 30.1 1,474.5 104.5 10,868.9 180.6 2037 2,511.5 4,120.8 379.4 915.8 263.0 8,190.5 88.2 1,070.3 1,158.5 0.0 309.0 30.3 1,538.2 99.0 11,325.7 184.5
CPW@ 7.86% (2008-2017) 4,172.9 5,410.2 316.2 2,891.1 351.3 13,141.6 737.6 2,656.8 3,394.3 (122.8) 331.6 150.3 948.3 581.3 18,424.8 81.2
(2008-2027) 8,707.5 10,948.7 742.4 4,659.5 960.1 26,018.1 968.8 4,008.1 4,976.9 (142.6) 682.5 204.2 2,767.3 1,068.3 35,574.8 98.0
(2008-2037) 11,908.0 15,658.0 1,160.5 5,827.7 1,307.4 35,861.6 1,041.6 5,218.8 6,260.4 (142.6) 1,017.8 242.2 4,551.4 1,246.0 49,036.8 110.3
APPENDIX 2 TABLE 47. TABLE 48. RISK ANALYSIS A - CARBON COST AT $25/TON ENERGY EFFICIENCY SCENARIO 2 (EE-2/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 103.2 2,210.9 68.7 2009 549.1 778.3 41.9 412.2 8.6 1,790.2 78.4 302.8 381.2 (8.3) 42.6 14.7 (1.2) 139.4 2,358.7 73.0 2010 573.3 722.2 41.3 422.9 20.9 1,780.6 116.2 332.0 448.2 (9.1) 42.1 24.8 (9.5) 139.0 2,416.2 75.2 2011 580.5 741.4 42.0 419.9 28.5 1,812.3 102.6 298.4 401.1 (10.0) 43.6 29.2 (10.0) 152.6 2,418.9 75.1 2012 578.7 657.4 38.5 423.8 30.7 1,729.1 105.0 443.7 548.7 (14.0) 42.2 28.2 228.8 172.8 2,735.9 84.4 2013 583.5 671.6 40.6 429.0 49.2 1,773.9 105.6 476.1 581.6 (19.0) 44.4 28.2 238.1 141.1 2,788.5 85.7 2014 597.5 782.8 47.8 446.3 66.1 1,940.5 106.0 449.4 555.3 (24.3) 51.8 25.8 255.7 147.1 2,951.9 88.4 2015 629.5 820.3 49.8 462.7 90.1 2,052.4 113.7 506.8 620.5 (33.0) 54.8 23.1 280.7 153.3 3,151.8 91.5 2016 780.9 876.2 54.7 437.7 138.7 2,288.1 143.8 534.4 678.2 (37.0) 60.7 20.2 304.6 191.3 3,506.2 98.8 2017 917.4 1,087.7 69.8 453.7 161.2 2,689.8 164.3 426.1 590.4 (39.2) 66.9 17.2 342.0 200.9 3,868.1 105.7 2018 1,013.2 1,221.1 81.2 471.4 163.6 2,950.5 130.1 360.4 490.5 (38.4) 73.4 15.0 385.5 211.6 4,088.0 108.6 2019 1,050.1 1,282.5 86.4 486.6 176.1 3,081.7 123.3 398.6 521.9 (5.2) 82.0 14.3 426.2 221.8 4,342.7 112.4 2020 1,198.2 1,481.2 106.4 510.4 180.5 3,476.7 66.8 280.6 347.4 (2.6) 84.7 11.9 453.6 232.0 4,603.8 116.2 2021 1,412.2 1,576.8 123.1 543.5 179.6 3,835.1 69.8 340.3 410.1 0.0 94.1 15.2 510.2 242.4 5,107.2 125.9 2022 1,539.3 1,702.9 136.4 567.9 176.6 4,123.1 62.1 320.7 382.8 0.0 111.1 14.5 547.3 252.8 5,431.6 130.7 2023 1,518.4 1,751.6 140.7 587.0 190.2 4,187.9 53.7 452.3 506.0 0.0 108.8 18.5 583.7 264.0 5,669.0 133.3 2024 1,527.3 1,875.7 151.0 599.6 194.9 4,348.5 52.9 457.3 510.3 0.0 116.3 17.8 639.7 275.2 5,907.7 135.7 2025 1,576.4 1,917.0 155.0 616.1 192.1 4,456.6 50.0 606.4 656.4 0.0 123.4 24.5 669.3 287.3 6,217.4 139.6 2026 1,614.3 2,061.3 166.3 633.3 207.1 4,682.3 53.0 612.7 665.7 0.0 130.3 23.5 733.6 224.8 6,460.3 141.5 2027 1,647.8 2,196.6 178.9 649.3 212.0 4,884.6 59.4 633.0 692.4 0.0 142.2 22.4 812.8 220.8 6,775.2 144.7 2028 1,736.1 2,344.0 192.9 672.6 206.9 5,152.4 49.4 639.5 688.9 0.0 155.2 21.3 892.4 220.9 7,131.1 148.6 2029 1,825.5 2,524.9 208.4 696.6 225.2 5,480.6 46.9 644.7 691.6 0.0 172.6 20.1 976.4 215.7 7,557.0 153.3 2030 1,904.7 2,702.9 224.8 721.0 230.2 5,783.7 48.7 642.3 691.0 0.0 185.1 18.8 1,060.4 208.8 7,947.8 157.2 2031 1,969.4 2,817.1 236.2 745.7 224.8 5,993.2 40.0 771.2 811.2 0.0 196.5 25.4 1,119.2 200.8 8,346.2 161.2 2032 2,012.2 3,014.1 254.4 772.1 244.6 6,297.3 48.9 861.4 910.3 0.0 211.3 28.9 1,165.0 191.3 8,804.0 166.3 2033 2,087.4 3,179.8 270.1 798.3 250.8 6,586.5 42.3 897.7 940.0 0.0 222.7 29.2 1,233.2 180.4 9,192.1 169.4 2034 2,173.0 3,396.8 293.9 826.6 245.0 6,935.1 50.5 939.3 989.8 0.0 250.4 29.5 1,295.2 167.2 9,667.4 174.1 2035 2,269.0 3,547.2 308.0 855.3 237.5 7,217.0 33.3 979.4 1,012.7 0.0 263.1 29.8 1,363.4 152.2 10,038.2 176.8 2036 2,345.9 3,738.5 325.9 889.3 261.5 7,561.2 66.3 1,025.8 1,092.1 0.0 277.5 30.1 1,428.4 134.9 10,524.3 181.8 2037 2,393.8 3,927.2 346.7 898.8 270.0 7,836.6 28.2 1,070.2 1,098.4 0.0 293.3 30.3 1,491.1 115.3 10,865.0 184.0
CPW@ 7.86% (2008-2017) 4,131.8 5,220.1 305.2 2,889.2 339.3 12,885.7 718.3 2,616.6 3,334.9 (122.8) 317.9 150.3 909.7 1,008.5 18,484.2 82.7
(2008-2027) 8,453.7 10,421.8 704.0 4,644.4 923.7 25,147.6 962.9 3,961.8 4,924.7 (142.6) 641.4 204.2 2,647.3 1,772.5 35,195.0 99.2
(2008-2037) 11,467.4 14,900.1 1,084.2 5,791.7 1,274.9 34,518.3 1,031.0 5,172.6 6,203.6 (142.6) 958.6 242.2 4,376.0 2,048.8 48,204.9 111.2
APPENDIX 2 TABLE 48. TABLE 49. RISK ANALYSIS A - CARBON COST AT $25/TON ENERGY EFFICIENCY SCENARIO 3 (EE-3/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 179.8 2,287.5 71.1 2009 549.1 768.3 41.5 412.2 8.6 1,779.8 77.4 301.6 379.0 (8.3) 42.1 14.7 (1.2) 247.2 2,453.3 76.3 2010 573.3 704.5 40.7 422.9 20.9 1,762.4 115.6 328.3 443.9 (9.1) 41.1 24.8 (9.5) 245.9 2,499.5 78.5 2011 580.5 718.6 40.8 419.9 28.5 1,788.3 102.8 294.0 396.7 (10.0) 42.2 29.2 (10.0) 259.0 2,495.5 78.6 2012 578.7 631.2 37.1 423.8 30.7 1,701.5 105.1 435.8 541.0 (14.0) 40.6 28.2 221.5 282.5 2,801.4 88.0 2013 583.5 641.4 38.7 429.0 49.2 1,741.9 105.7 468.0 573.7 (19.0) 42.1 28.2 228.4 250.8 2,846.1 89.3 2014 597.5 743.9 45.8 446.3 66.1 1,899.6 106.1 442.3 548.4 (24.3) 48.9 25.8 244.8 259.6 3,002.8 92.0 2015 629.5 776.9 47.4 462.7 78.0 1,994.6 106.5 497.0 603.4 (33.0) 51.7 23.1 268.4 269.4 3,177.7 94.6 2016 743.4 827.1 51.4 436.2 110.1 2,168.1 144.8 526.4 671.2 (37.0) 57.3 20.2 290.8 311.2 3,481.7 100.7 2017 867.9 1,029.1 65.7 451.5 146.1 2,560.3 164.0 419.0 583.1 (39.2) 62.3 17.2 326.3 324.6 3,834.6 107.7 2018 972.5 1,154.5 76.9 469.3 161.5 2,834.7 126.7 353.8 480.5 (38.4) 68.2 15.0 367.9 340.0 4,067.8 111.2 2019 995.6 1,208.9 81.5 483.8 179.0 2,948.8 130.2 392.7 523.0 (5.2) 76.3 14.3 407.0 354.3 4,318.5 115.1 2020 1,112.5 1,413.4 97.2 504.5 183.9 3,311.5 71.3 283.6 354.9 (2.6) 80.6 11.9 438.2 369.0 4,563.5 118.8 2021 1,324.6 1,505.9 110.0 535.9 199.4 3,675.8 64.1 342.6 406.6 0.0 90.0 15.2 494.7 384.6 5,066.9 128.9 2022 1,462.8 1,629.4 123.0 560.3 204.0 3,979.5 51.5 319.6 371.1 0.0 106.6 14.5 529.8 399.1 5,400.6 134.2 2023 1,428.4 1,673.4 126.7 578.6 198.7 4,005.8 51.2 452.7 503.9 0.0 103.7 18.5 564.6 413.7 5,610.3 136.3 2024 1,429.1 1,790.8 135.9 590.4 193.8 4,140.0 55.3 457.7 512.9 0.0 110.4 17.8 619.3 428.6 5,828.9 138.5 2025 1,467.9 1,827.0 139.5 606.3 191.0 4,231.7 54.0 608.0 662.0 0.0 117.0 24.5 647.5 446.7 6,129.5 142.4 2026 1,514.2 1,962.1 149.7 623.3 186.7 4,436.0 53.1 612.8 665.9 0.0 123.0 23.5 710.1 387.7 6,346.3 143.8 2027 1,630.1 2,074.1 165.6 644.2 203.7 4,717.7 13.8 630.1 643.9 0.0 132.6 22.4 782.3 377.6 6,676.6 147.6 2028 1,715.9 2,204.6 181.3 668.9 209.4 4,980.2 51.7 639.7 691.4 0.0 143.8 21.3 857.9 370.1 7,064.7 152.4 2029 1,766.8 2,376.3 195.9 691.2 203.4 5,233.6 59.8 644.5 704.3 0.0 159.8 20.1 940.3 358.7 7,416.8 155.7 2030 1,846.9 2,545.2 211.6 715.2 198.0 5,517.0 58.4 642.2 700.6 0.0 171.3 18.8 1,021.0 344.2 7,772.9 159.2 2031 1,914.6 2,651.5 221.7 739.8 218.0 5,745.7 47.0 770.7 817.7 0.0 182.0 25.4 1,078.4 327.1 8,176.2 163.4 2032 1,959.8 2,843.3 239.3 765.9 224.8 6,033.1 53.2 861.5 914.7 0.0 196.7 28.9 1,122.4 306.7 8,602.5 168.2 2033 2,037.3 2,996.8 253.6 792.0 218.5 6,298.3 43.7 897.2 940.8 0.0 207.8 29.2 1,188.8 283.1 8,948.0 170.6 2034 2,125.3 3,199.1 275.8 820.0 239.9 6,660.1 49.1 938.9 988.0 0.0 233.3 29.5 1,247.3 254.9 9,413.1 175.5 2035 2,205.0 3,345.3 289.2 848.1 246.5 6,934.1 39.0 979.9 1,019.0 0.0 244.5 29.8 1,313.8 222.4 9,763.6 178.1 2036 2,273.1 3,528.4 306.1 881.5 241.6 7,230.8 59.8 1,026.0 1,085.8 0.0 259.0 30.1 1,376.3 184.9 10,166.8 181.8 2037 2,322.5 3,708.1 324.5 890.4 236.7 7,482.2 64.3 1,070.9 1,135.2 0.0 274.2 30.3 1,437.0 142.0 10,501.0 184.2
CPW@ 7.86% (2008-2017) 4,089.6 5,044.7 295.3 2,887.4 311.2 12,628.1 713.6 2,582.0 3,295.6 (122.8) 305.7 150.3 870.9 1,729.1 18,857.0 85.7
(2008-2027) 8,175.3 9,993.7 658.8 4,622.3 908.0 24,358.1 946.7 3,923.4 4,870.2 (142.6) 611.6 204.2 2,547.1 2,951.1 35,399.6 101.9
(2008-2037) 11,110.5 14,213.5 1,015.8 5,760.5 1,236.1 33,336.5 1,025.0 5,134.2 6,159.2 (142.6) 906.5 242.2 4,212.1 3,389.1 48,103.1 113.6
APPENDIX 2 TABLE 49. TABLE 50. RISK ANALYSIS A - CARBON COST AT $25/TON ENERGY EFFICIENCY SCENARIO 4 (EE-4/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 302.2 2,409.9 74.9 2009 549.1 756.2 41.1 412.2 8.6 1,767.3 77.4 297.7 375.1 (8.3) 41.5 14.7 (1.2) 407.3 2,596.4 81.3 2010 573.3 683.7 39.6 422.9 9.5 1,728.9 115.6 322.3 437.9 (9.1) 39.4 24.8 (9.5) 406.2 2,618.7 83.4 2011 580.5 687.9 39.2 419.9 9.5 1,737.0 102.8 288.1 390.8 (10.0) 40.3 29.2 (10.0) 419.5 2,596.8 83.4 2012 578.7 598.3 35.3 423.8 21.6 1,657.7 105.1 425.7 530.8 (14.0) 38.0 28.2 211.4 448.3 2,900.6 93.2 2013 583.5 602.3 36.4 429.0 48.8 1,700.1 105.7 454.8 560.5 (19.0) 39.3 28.2 216.0 417.5 2,942.8 94.9 2014 597.5 695.8 42.9 446.3 68.8 1,851.3 106.1 431.2 537.3 (24.3) 45.5 25.8 230.5 430.9 3,097.0 97.9 2015 629.5 724.3 44.2 462.7 66.9 1,927.6 106.5 482.0 588.5 (33.0) 47.6 23.1 252.3 446.3 3,252.5 100.1 2016 718.4 764.0 48.1 435.1 91.9 2,057.4 135.8 513.2 648.9 (37.0) 52.8 20.2 272.7 493.8 3,508.9 105.1 2017 811.0 953.9 60.7 449.0 106.8 2,381.4 160.8 409.7 570.5 (39.2) 56.9 17.2 305.4 513.1 3,805.4 110.9 2018 896.3 1,069.3 70.8 465.9 145.5 2,647.8 132.9 347.0 479.8 (38.4) 61.8 15.0 344.8 535.3 4,046.1 115.0 2019 926.2 1,115.3 74.7 480.3 180.6 2,777.1 131.4 385.3 516.7 (5.2) 69.4 14.3 381.2 555.6 4,309.1 119.6 2020 1,053.9 1,303.3 89.7 501.2 192.0 3,140.2 66.7 279.8 346.5 (2.6) 72.0 11.9 410.2 576.8 4,555.0 123.6 2021 1,253.6 1,388.8 101.8 531.9 190.3 3,466.4 66.0 340.0 405.9 0.0 80.8 15.2 465.3 600.1 5,033.8 133.6 2022 1,384.2 1,500.6 113.2 555.7 186.1 3,739.8 56.7 319.6 376.3 0.0 96.2 14.5 498.6 620.9 5,346.4 138.8 2023 1,353.1 1,537.5 116.1 573.9 181.2 3,761.8 53.1 452.5 505.5 0.0 93.7 18.5 531.2 641.0 5,551.7 141.0 2024 1,356.9 1,646.8 124.6 585.6 195.7 3,909.6 54.0 456.8 510.8 0.0 99.1 17.8 583.3 661.6 5,782.2 143.7 2025 1,395.9 1,672.6 127.5 601.0 201.7 3,998.7 56.6 606.9 663.4 0.0 104.9 24.5 609.3 688.4 6,089.2 148.1 2026 1,446.3 1,799.2 137.4 618.0 197.7 4,198.7 50.1 612.1 662.2 0.0 110.1 23.5 669.3 635.1 6,298.9 149.4 2027 1,481.0 1,926.2 147.7 633.3 213.8 4,401.9 61.3 633.2 694.5 0.0 121.7 22.4 745.3 616.3 6,602.2 152.8 2028 1,548.2 2,056.1 158.6 655.2 218.8 4,636.9 53.7 640.8 694.6 0.0 133.1 21.3 822.1 597.2 6,905.3 156.0 2029 1,631.4 2,222.9 172.5 678.1 213.6 4,918.5 58.9 644.7 703.7 0.0 148.0 20.1 902.6 576.4 7,269.2 159.8 2030 1,716.6 2,384.0 186.5 701.7 208.4 5,197.1 54.4 643.2 697.6 0.0 159.0 18.8 981.3 550.3 7,604.2 163.1 2031 1,789.1 2,481.4 195.7 725.8 227.9 5,420.0 40.0 771.1 811.0 0.0 169.2 25.4 1,036.7 519.3 7,981.6 167.1 2032 1,838.8 2,665.4 211.2 751.5 234.5 5,701.4 43.0 861.6 904.6 0.0 182.9 28.9 1,078.2 482.5 8,378.5 171.6 2033 1,916.4 2,809.5 224.2 776.8 229.1 5,956.1 45.0 897.2 942.2 0.0 192.4 29.2 1,143.2 439.3 8,702.5 173.8 2034 2,009.5 3,009.8 244.4 804.5 249.7 6,318.0 32.0 938.4 970.4 0.0 218.4 29.5 1,201.0 388.3 9,125.6 178.2 2035 2,091.7 3,143.5 256.7 832.0 254.4 6,578.3 34.5 979.3 1,013.7 0.0 228.8 29.8 1,263.2 329.3 9,443.2 180.4 2036 2,160.8 3,314.4 272.5 864.7 248.6 6,861.0 36.4 1,025.1 1,061.5 0.0 241.9 30.1 1,323.0 261.1 9,778.5 183.2 2037 2,193.4 3,483.7 288.5 872.5 243.1 7,081.3 67.1 1,071.2 1,138.3 0.0 255.9 30.3 1,381.0 182.7 10,069.6 185.0
CPW@ 7.86% (2008-2017) 4,050.3 4,823.2 282.6 2,885.7 249.5 12,291.3 707.5 2,528.4 3,236.0 (122.8) 289.9 150.3 820.0 2,824.4 19,489.0 90.4
(2008-2027) 7,893.2 9,383.1 615.7 4,605.8 837.0 23,334.9 955.0 3,861.5 4,816.5 (142.6) 565.8 204.2 2,397.5 4,741.6 35,918.0 106.4
(2008-2037) 10,635.6 13,338.7 931.2 5,722.1 1,179.0 31,806.7 1,025.3 5,072.6 6,097.9 (142.6) 840.2 242.2 3,997.5 5,425.9 48,267.9 117.7
APPENDIX 2 TABLE 50. TABLE 51. RISK ANALYSIS A - CARBON COST AT $25/TON DEFAULT SUPPLY SIDE SCENARIO (SS-D/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 597.5 865.6 52.3 446.3 66.1 2,027.9 116.3 466.2 582.5 (24.3) 56.6 24.8 277.2 54.9 2,999.5 85.5 2015 629.5 899.8 54.6 462.7 89.7 2,136.3 153.0 529.2 682.2 (33.0) 60.3 22.1 302.9 58.3 3,229.0 89.0 2016 830.9 991.0 63.1 439.7 138.4 2,463.0 165.0 551.2 716.2 (37.0) 69.2 19.2 336.4 93.4 3,660.3 97.5 2017 1,021.9 1,223.2 79.9 457.9 176.0 2,958.9 159.6 438.7 598.3 (39.2) 77.1 16.1 376.7 100.0 4,087.9 105.4 2018 1,139.3 1,401.4 94.8 476.5 185.3 3,297.3 123.1 373.0 496.1 (38.4) 87.4 13.8 431.8 107.3 4,395.3 109.9 2019 1,176.3 1,430.0 97.3 491.8 181.0 3,376.5 125.2 416.2 541.3 (5.2) 91.0 13.2 462.5 114.3 4,593.7 111.7 2020 1,331.8 1,669.3 120.4 516.2 193.5 3,831.2 68.3 293.2 361.5 (2.6) 99.2 10.8 498.2 121.1 4,919.3 116.5 2021 1,562.5 1,742.4 135.6 550.2 200.1 4,190.8 63.1 398.9 462.0 0.0 105.9 16.4 548.6 127.8 5,451.7 125.8 2022 1,704.7 1,898.3 152.3 575.4 196.1 4,526.7 52.2 374.3 426.5 0.0 124.0 15.6 593.3 134.8 5,820.9 131.0 2023 1,685.9 1,941.1 155.5 595.0 191.6 4,569.1 46.4 598.6 645.0 0.0 121.4 19.6 627.0 142.6 6,124.8 134.5 2024 1,701.1 2,068.4 166.3 608.2 205.5 4,749.5 46.7 599.3 646.0 0.0 127.8 18.8 684.3 150.3 6,376.6 136.7 2025 1,769.1 2,142.4 173.7 625.9 210.9 4,922.0 47.3 818.1 865.3 0.0 140.3 25.5 724.5 158.2 6,835.8 143.2 2026 1,824.7 2,305.2 186.7 644.3 205.5 5,166.4 51.5 820.7 872.1 0.0 150.0 24.4 793.4 92.2 7,098.5 144.9 2027 1,927.7 2,427.0 204.5 665.8 200.8 5,425.8 22.1 835.6 857.7 0.0 158.5 24.2 868.3 92.2 7,426.7 147.8 2028 2,034.7 2,592.0 224.4 692.3 216.8 5,760.1 38.3 840.2 878.5 0.0 174.1 23.0 950.6 98.1 7,884.4 153.1 2029 2,095.7 2,781.9 241.1 716.1 222.0 6,056.8 53.9 839.5 893.4 0.0 191.6 21.8 1,038.2 98.0 8,299.8 156.8 2030 2,237.1 2,940.0 263.4 746.2 253.9 6,440.5 17.5 831.6 849.0 0.0 201.0 20.5 1,115.8 97.3 8,724.2 160.8 2031 2,342.7 3,110.9 283.9 775.5 267.1 6,780.1 36.0 832.9 868.9 0.0 217.6 19.2 1,189.4 96.8 9,171.9 165.0 2032 2,389.4 3,336.8 306.5 803.2 284.4 7,120.4 54.0 837.6 891.6 0.0 234.8 17.8 1,238.6 96.2 9,599.4 168.9 2033 2,481.4 3,529.2 325.8 831.2 289.2 7,456.9 44.3 869.9 914.2 0.0 247.3 17.9 1,313.1 95.9 10,045.3 172.4 2034 2,565.6 3,673.7 345.1 860.8 281.9 7,727.1 34.4 1,098.4 1,132.8 0.0 267.5 27.9 1,358.2 95.1 10,608.6 178.0 2035 2,624.0 3,866.8 363.0 889.7 273.0 8,016.6 49.1 1,141.6 1,190.6 0.0 283.4 28.1 1,438.0 94.4 11,051.1 181.4 2036 2,695.6 4,047.2 380.9 925.1 294.4 8,343.2 13.8 1,189.6 1,203.4 0.0 299.7 28.3 1,500.4 93.8 11,468.7 184.5 2037 2,743.5 4,296.8 409.6 935.9 300.5 8,686.4 78.1 1,234.7 1,312.8 0.0 325.2 28.5 1,579.1 93.3 12,025.2 189.1
CPW@ 7.86% (2008-2017) 4,206.2 5,601.6 327.4 2,892.2 345.9 13,373.2 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 989.3 415.1 18,556.6 80.3
(2008-2027) 9,048.0 11,407.9 775.0 4,672.1 965.3 26,868.4 975.4 4,301.3 5,276.7 (142.6) 704.8 196.7 2,872.3 807.6 36,583.9 98.5
(2008-2037) 12,573.7 16,319.5 1,223.9 5,862.1 1,356.1 37,335.3 1,036.7 5,701.1 6,737.8 (142.6) 1,053.1 230.5 4,702.3 950.7 50,867.2 111.6
APPENDIX 2 TABLE 51. TABLE 52. RISK ANALYSIS A - CARBON COST AT $25/TON NUCLEAR SUPPLY SIDE SCENARIO (SS-N/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 600.3 865.6 52.3 446.3 66.1 2,030.7 116.3 466.2 582.5 (24.3) 56.6 24.8 277.2 54.9 3,002.3 85.6 2015 637.1 899.8 54.6 462.7 89.7 2,143.9 153.0 529.2 682.2 (33.0) 60.3 22.1 302.9 58.3 3,236.7 89.2 2016 864.3 991.0 63.1 439.7 138.4 2,496.4 165.0 551.2 716.2 (37.0) 69.2 19.2 336.4 93.4 3,693.8 98.4 2017 1,104.5 1,223.2 79.9 457.9 176.0 3,041.5 159.6 438.7 598.3 (39.2) 77.1 16.1 376.7 100.0 4,170.5 107.5 2018 1,285.6 1,401.4 94.8 476.5 185.3 3,443.6 123.1 373.0 496.1 (38.4) 87.4 13.8 431.8 107.3 4,541.6 113.6 2019 1,401.2 1,430.0 97.3 491.8 181.0 3,601.4 125.2 416.2 541.3 (5.2) 91.0 13.2 462.5 114.3 4,818.6 117.1 2020 1,647.9 1,669.3 120.4 516.2 193.5 4,147.3 68.3 293.2 361.5 (2.6) 99.2 10.8 498.2 121.1 5,235.4 123.9 2021 1,941.9 1,761.2 132.0 547.7 232.0 4,614.8 59.4 400.9 460.3 0.0 108.1 16.4 553.5 127.8 5,880.9 135.7 2022 2,197.7 1,825.3 137.5 581.9 243.2 4,985.6 52.6 374.4 426.9 0.0 118.7 15.6 573.2 134.8 6,254.8 140.8 2023 2,188.7 1,703.2 128.0 622.9 236.2 4,879.1 27.0 598.6 625.7 0.0 104.7 19.6 559.3 142.6 6,331.0 139.0 2024 2,071.2 1,771.2 134.0 645.2 247.5 4,869.2 32.8 599.3 632.1 0.0 105.6 18.8 596.4 150.3 6,372.4 136.6 2025 2,108.9 1,822.5 138.3 663.2 252.1 4,984.9 48.2 818.1 866.4 0.0 115.9 25.5 627.9 158.2 6,778.8 142.0 2026 2,156.1 1,984.7 151.3 682.6 245.8 5,220.6 52.4 820.7 873.1 0.0 123.9 24.4 700.1 92.2 7,034.2 143.6 2027 2,252.8 2,122.2 167.6 705.3 239.8 5,487.7 23.0 835.6 858.5 0.0 133.6 24.2 777.5 92.2 7,373.8 146.8 2028 2,335.9 2,253.8 182.7 732.3 233.8 5,738.5 59.5 840.2 899.7 0.0 146.0 23.0 848.7 98.1 7,754.0 150.6 2029 2,393.6 2,444.6 199.7 757.5 227.7 6,023.1 53.3 839.4 892.7 0.0 163.5 21.8 939.0 98.0 8,138.1 153.8 2030 2,534.2 2,588.3 218.9 789.4 244.4 6,375.1 17.0 831.6 848.6 0.0 172.4 20.5 1,011.6 97.3 8,525.5 157.1 2031 2,604.0 2,740.6 236.8 819.2 249.1 6,649.8 57.8 832.9 890.7 0.0 185.3 19.2 1,080.7 96.8 8,922.5 160.5 2032 2,643.2 2,977.1 257.9 848.4 243.4 6,969.9 52.1 837.6 889.7 0.0 203.2 17.8 1,133.0 96.2 9,309.8 163.8 2033 2,735.5 3,139.1 273.6 878.4 262.4 7,288.9 42.6 869.9 912.5 0.0 212.9 17.9 1,200.4 95.9 9,728.5 167.0 2034 2,804.2 3,289.2 291.9 909.4 267.0 7,561.7 32.7 1,098.4 1,131.2 0.0 235.0 27.9 1,248.0 95.1 10,298.7 172.8 2035 2,847.3 3,488.3 310.1 939.8 257.8 7,843.2 47.6 1,141.6 1,189.1 0.0 251.3 28.1 1,327.3 94.4 10,733.5 176.2 2036 2,904.6 3,651.4 325.3 976.6 280.5 8,138.4 12.4 1,189.6 1,202.0 0.0 265.5 28.3 1,383.7 93.8 11,111.7 178.7 2037 2,942.3 3,880.8 349.5 989.0 287.2 8,448.8 76.7 1,234.7 1,311.4 0.0 289.0 28.5 1,456.4 93.3 11,627.3 182.8
CPW@ 7.86% (2008-2017) 4,267.7 5,601.6 327.4 2,892.2 345.9 13,434.7 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 989.3 415.1 18,618.1 80.6
(2008-2027) 10,161.6 11,012.8 726.4 4,719.3 1,045.1 27,665.1 965.3 4,302.0 5,267.3 (142.6) 674.8 196.7 2,756.2 807.6 37,225.1 100.2
(2008-2037) 14,075.3 15,378.1 1,103.1 5,976.8 1,419.4 37,952.7 1,033.0 5,701.8 6,734.9 (142.6) 976.6 230.5 4,425.6 950.7 51,128.4 112.1
APPENDIX 2 TABLE 52. TABLE 53. RISK ANALYSIS A - CARBON COST AT $25/TON SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 597.5 828.1 50.6 446.3 66.1 1,988.5 106.2 582.0 688.2 (24.3) 53.9 30.0 267.3 54.9 3,058.4 87.2 2015 629.5 830.0 50.5 462.7 89.7 2,062.4 112.3 759.3 871.6 (33.0) 54.7 32.6 282.0 58.3 3,328.5 91.7 2016 755.9 877.6 55.5 436.7 123.4 2,249.0 141.7 910.8 1,052.6 (37.0) 60.7 35.1 304.2 93.4 3,757.8 100.1 2017 871.2 1,053.4 67.6 451.5 153.3 2,597.0 158.1 936.1 1,094.2 (39.2) 64.2 37.5 331.7 100.0 4,185.5 107.9 2018 936.7 1,174.3 78.2 467.5 162.7 2,819.3 128.7 1,010.0 1,138.6 (38.4) 70.4 40.8 373.9 107.3 4,512.0 112.9 2019 940.0 1,157.9 77.2 480.9 158.1 2,814.0 125.5 1,193.8 1,319.3 (5.2) 70.6 45.8 389.3 114.3 4,748.2 115.4 2020 1,038.2 1,333.0 90.5 500.3 171.4 3,133.4 66.2 1,240.8 1,307.0 (2.6) 75.4 49.2 416.2 121.1 5,099.5 120.7 2021 1,210.1 1,427.8 98.2 527.7 195.2 3,459.0 70.2 1,347.3 1,417.5 0.0 85.5 54.2 472.0 127.8 5,615.9 129.6 2022 1,343.7 1,580.2 108.6 549.9 200.0 3,782.3 63.1 1,327.3 1,390.4 0.0 103.7 52.8 518.8 134.8 5,982.9 134.6 2023 1,337.6 1,618.9 112.6 568.7 194.7 3,832.5 57.0 1,551.6 1,608.6 0.0 100.7 56.1 548.2 142.6 6,288.7 138.1 2024 1,365.3 1,738.2 121.5 581.1 189.9 3,996.0 57.0 1,554.0 1,611.0 0.0 105.6 54.6 604.0 150.3 6,521.5 139.8 2025 1,445.7 1,808.6 127.6 598.0 206.7 4,186.7 57.3 1,771.2 1,828.4 0.0 118.7 60.6 642.6 158.2 6,995.1 146.5 2026 1,531.0 1,961.2 139.0 616.2 211.3 4,458.7 50.0 1,773.6 1,823.6 0.0 127.6 58.7 710.6 92.2 7,271.5 148.4 2027 1,604.0 2,108.2 151.4 633.0 206.7 4,703.2 45.1 1,788.5 1,833.6 0.0 137.9 57.7 791.0 92.2 7,615.6 151.6 2028 1,685.0 2,288.6 165.9 655.3 223.0 5,017.8 60.5 1,794.9 1,855.4 0.0 156.1 55.6 877.2 98.1 8,060.2 156.5 2029 1,778.4 2,467.6 180.7 678.7 227.2 5,332.8 54.2 1,792.4 1,846.6 0.0 173.0 53.4 962.0 98.0 8,465.8 160.0 2030 1,946.1 2,612.8 200.1 708.2 221.3 5,688.5 17.3 1,784.5 1,801.9 0.0 181.4 51.1 1,035.8 97.3 8,856.0 163.2 2031 2,063.4 2,773.4 219.7 736.4 255.1 6,047.9 35.4 1,785.9 1,821.3 0.0 196.6 48.8 1,105.5 96.8 9,316.9 167.6 2032 2,120.6 3,001.2 238.8 762.9 292.5 6,416.0 53.4 1,792.4 1,845.8 0.0 214.6 46.2 1,155.4 96.2 9,774.3 172.0 2033 2,222.0 3,191.2 256.0 789.7 297.3 6,756.2 43.8 1,822.9 1,866.7 0.0 225.3 45.1 1,228.6 95.9 10,217.9 175.4 2034 2,314.7 3,351.1 273.3 818.1 289.9 7,047.0 33.9 2,051.4 2,085.3 0.0 246.9 53.8 1,277.7 95.1 10,805.8 181.3 2035 2,381.5 3,524.3 289.7 845.7 307.6 7,348.8 48.5 2,094.5 2,143.0 0.0 263.3 52.7 1,351.7 94.4 11,253.8 184.7 2036 2,462.9 3,698.7 305.5 879.7 313.6 7,660.3 13.2 2,144.3 2,157.5 0.0 277.6 51.4 1,411.3 93.8 11,651.8 187.4 2037 2,521.9 3,960.2 331.3 889.2 306.5 8,009.1 77.6 2,187.6 2,265.2 0.0 305.2 50.1 1,493.5 93.3 12,216.4 192.1
CPW@ 7.86% (2008-2017) 4,097.5 5,404.3 314.5 2,887.7 327.6 13,031.6 710.6 3,279.5 3,990.1 (122.8) 323.4 168.8 934.6 415.1 18,740.7 81.1
(2008-2027) 7,987.2 10,240.2 648.6 4,600.9 917.4 24,394.4 955.8 7,719.2 8,675.0 (142.6) 624.0 333.2 2,578.2 807.6 37,269.9 100.3
(2008-2037) 11,097.6 14,663.4 997.9 5,730.6 1,313.2 33,802.8 1,021.1 10,537.1 11,558.2 (142.6) 942.5 409.1 4,287.1 950.7 51,807.8 113.6
APPENDIX 2 TABLE 53. TABLE 54. RISK ANALYSIS A - CARBON COST AT $25/TON SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 597.5 833.0 50.4 446.3 66.1 1,993.3 106.2 572.0 678.1 (24.3) 54.3 29.8 266.9 54.9 3,052.9 87.1 2015 629.5 837.6 50.4 462.7 89.7 2,069.9 116.6 738.9 855.6 (33.0) 55.4 32.2 281.6 58.3 3,320.0 91.5 2016 780.9 906.8 57.0 437.7 137.8 2,320.2 143.2 817.0 960.2 (37.0) 62.5 31.6 309.3 93.4 3,740.1 99.6 2017 899.9 1,067.6 67.8 452.7 160.2 2,648.3 157.5 893.4 1,050.9 (39.2) 65.5 36.7 332.3 100.0 4,194.4 108.1 2018 955.1 1,190.2 79.2 468.4 161.3 2,854.1 131.6 955.9 1,087.4 (38.4) 72.0 39.8 375.2 107.3 4,497.4 112.5 2019 957.6 1,179.2 78.4 481.8 172.6 2,869.7 132.3 1,126.2 1,258.5 (5.2) 72.6 44.6 390.6 114.3 4,745.1 115.3 2020 1,069.4 1,361.0 92.0 501.9 177.6 3,201.9 67.5 1,156.4 1,223.9 (2.6) 77.6 47.6 418.6 121.1 5,088.1 120.5 2021 1,250.1 1,443.7 98.6 529.7 193.1 3,515.2 61.7 1,302.8 1,364.5 0.0 86.5 54.6 470.4 127.8 5,619.1 129.7 2022 1,382.1 1,594.2 109.7 551.9 198.3 3,836.2 51.6 1,285.6 1,337.2 0.0 104.8 53.2 517.0 134.8 5,983.1 134.6 2023 1,358.7 1,633.4 113.0 570.3 222.3 3,897.6 56.1 1,509.7 1,565.8 0.0 101.9 56.5 547.2 142.6 6,311.6 138.6 2024 1,390.6 1,754.4 122.1 582.8 232.2 4,082.1 52.6 1,512.4 1,565.0 0.0 106.7 55.1 602.3 150.3 6,561.5 140.7 2025 1,464.6 1,824.2 128.6 599.6 246.9 4,263.9 56.7 1,729.4 1,786.0 0.0 120.0 61.0 641.1 158.2 7,030.4 147.2 2026 1,537.2 1,978.0 140.5 617.4 250.6 4,523.7 56.8 1,731.7 1,788.5 0.0 128.7 59.2 709.2 92.2 7,301.4 149.0 2027 1,663.7 2,093.2 156.6 638.6 244.6 4,796.6 19.7 1,746.6 1,766.2 0.0 136.5 58.1 781.2 92.2 7,630.9 151.9 2028 1,762.6 2,247.9 175.4 663.6 237.6 5,087.1 56.5 1,753.2 1,809.6 0.0 151.2 56.1 862.0 98.1 8,064.2 156.6 2029 1,840.8 2,432.5 190.7 686.8 231.9 5,382.7 50.3 1,750.6 1,800.9 0.0 169.5 53.9 947.2 98.0 8,452.2 159.7 2030 2,006.8 2,580.8 210.0 716.5 286.4 5,800.4 13.6 1,742.6 1,756.2 0.0 176.8 51.6 1,021.5 97.3 8,903.8 164.1 2031 2,102.0 2,740.8 229.4 744.1 309.1 6,125.4 54.2 1,743.9 1,798.1 0.0 192.0 49.2 1,091.7 96.8 9,353.3 168.3 2032 2,165.3 2,964.3 248.5 771.1 300.8 6,450.0 48.5 1,750.9 1,799.4 0.0 210.2 46.7 1,140.1 96.2 9,742.6 171.4 2033 2,280.7 3,149.9 265.1 798.8 317.7 6,812.1 39.1 1,780.9 1,820.1 0.0 220.9 45.6 1,213.8 95.9 10,208.4 175.2 2034 2,349.3 3,296.0 281.9 826.5 321.9 7,075.7 53.8 2,009.4 2,063.2 0.0 240.5 54.3 1,258.7 95.1 10,787.5 181.0 2035 2,423.1 3,479.4 298.5 854.7 311.9 7,367.5 42.6 2,052.5 2,095.2 0.0 256.0 53.2 1,335.0 94.4 11,201.3 183.8 2036 2,520.4 3,642.1 315.0 889.6 332.0 7,699.1 31.6 2,102.6 2,134.2 0.0 269.8 52.0 1,392.1 93.8 11,641.0 187.3 2037 2,578.3 3,896.3 340.4 899.4 337.8 8,052.2 95.2 2,145.7 2,240.9 0.0 297.7 50.6 1,474.1 93.3 12,208.9 192.0
CPW@ 7.86% (2008-2017) 4,123.6 5,432.9 315.2 2,888.8 338.2 13,098.6 713.4 3,194.9 3,908.3 (122.8) 325.6 166.3 937.0 415.1 18,728.1 81.1
(2008-2027) 8,099.1 10,318.2 653.3 4,607.6 982.2 24,660.5 950.9 7,469.5 8,420.4 (142.6) 630.1 330.0 2,577.8 807.6 37,283.9 100.3
(2008-2037) 11,290.7 14,678.7 1,016.7 5,750.1 1,416.1 34,152.4 1,021.4 10,225.2 11,246.6 (142.6) 940.8 406.7 4,263.1 950.7 51,817.6 113.7
APPENDIX 2 TABLE 54. TABLE 55. RISK ANALYSIS A - CARBON COST AT $25/TON SUPPLY SIDE SCENARIO 1 (SS-1/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 599.7 847.3 51.3 446.3 66.1 2,010.8 107.9 524.0 631.9 (24.3) 55.3 27.4 272.2 54.9 3,028.1 86.4 2015 635.5 865.0 52.4 462.7 89.7 2,105.3 130.6 643.6 774.2 (33.0) 57.4 27.4 292.5 58.3 3,282.1 90.4 2016 819.9 934.6 59.4 438.2 137.8 2,389.9 154.6 725.4 880.0 (37.0) 64.7 26.8 320.8 93.4 3,738.6 99.6 2017 1,025.0 1,159.4 75.5 455.2 160.8 2,875.9 161.2 616.9 778.1 (39.2) 72.4 23.7 360.3 100.0 4,171.3 107.5 2018 1,195.6 1,332.5 89.9 473.7 177.6 3,269.3 124.7 552.8 677.5 (38.4) 81.9 21.3 414.8 107.3 4,533.8 113.4 2019 1,297.4 1,359.1 92.1 489.0 181.5 3,419.2 126.7 596.8 723.5 (5.2) 85.5 20.6 445.2 114.3 4,803.0 116.8 2020 1,527.6 1,592.1 114.7 513.3 194.0 3,941.7 69.7 477.1 546.8 (2.6) 93.3 18.0 480.1 121.1 5,198.4 123.1 2021 1,793.0 1,685.4 126.0 544.1 225.3 4,373.8 70.5 584.5 655.0 0.0 102.3 23.5 535.2 127.8 5,817.6 134.3 2022 2,033.2 1,765.7 132.9 576.2 233.5 4,741.6 56.8 559.9 616.7 0.0 114.5 22.6 559.9 134.8 6,190.1 139.3 2023 2,033.9 1,676.6 126.0 613.1 227.2 4,676.8 29.4 784.3 813.6 0.0 102.9 26.4 555.8 142.6 6,318.1 138.8 2024 1,936.9 1,755.8 132.4 633.0 221.4 4,679.6 39.9 785.3 825.2 0.0 104.7 25.5 596.0 150.3 6,381.2 136.8 2025 1,978.4 1,810.2 137.1 650.6 236.4 4,812.7 55.2 1,003.8 1,058.9 0.0 115.5 32.0 629.0 158.2 6,806.4 142.6 2026 2,047.3 1,971.2 149.8 670.3 240.5 5,079.1 48.0 1,006.3 1,054.2 0.0 123.4 30.7 700.0 92.2 7,079.7 144.5 2027 2,159.4 2,102.5 166.1 693.1 234.7 5,355.8 11.1 1,021.2 1,032.2 0.0 132.7 30.4 777.1 92.2 7,420.4 147.7 2028 2,245.0 2,239.5 182.0 719.8 228.0 5,614.2 48.1 1,026.2 1,074.3 0.0 145.6 29.0 850.2 98.1 7,811.3 151.7 2029 2,306.2 2,427.7 198.4 744.6 222.6 5,899.5 42.2 1,025.0 1,067.2 0.0 162.9 27.6 938.7 98.0 8,193.8 154.8 2030 2,451.3 2,601.8 213.7 776.1 239.9 6,282.7 6.0 1,017.2 1,023.3 0.0 174.9 26.1 1,018.8 97.3 8,623.0 158.9 2031 2,525.6 2,763.6 228.9 805.5 283.4 6,607.1 47.1 1,018.5 1,065.6 0.0 190.0 24.5 1,090.8 96.8 9,074.7 163.2 2032 2,568.5 2,998.5 249.2 834.3 295.3 6,945.9 41.7 1,024.3 1,066.0 0.0 207.5 22.8 1,144.2 96.2 9,482.6 166.8 2033 2,642.6 3,167.5 265.2 863.1 312.4 7,250.8 56.2 1,055.5 1,111.7 0.0 217.5 22.7 1,212.3 95.9 9,911.0 170.1 2034 2,700.5 3,325.0 283.3 893.0 316.7 7,518.5 45.8 1,284.1 1,329.9 0.0 240.6 32.4 1,260.8 95.1 10,477.2 175.8 2035 2,748.7 3,518.5 301.5 922.9 307.8 7,799.4 60.1 1,327.2 1,387.3 0.0 256.7 32.3 1,339.3 94.4 10,909.4 179.0 2036 2,810.9 3,683.0 316.5 959.2 328.5 8,098.1 24.6 1,375.7 1,400.2 0.0 271.3 32.2 1,396.1 93.8 11,291.6 181.6 2037 2,877.7 3,923.8 340.9 972.0 333.2 8,447.6 14.1 1,420.3 1,434.5 0.0 295.4 32.0 1,471.8 93.3 11,774.6 185.1
CPW@ 7.86% (2008-2017) 4,206.7 5,513.4 321.6 2,890.2 338.5 13,270.3 729.6 2,938.5 3,668.1 (122.8) 331.6 153.7 965.0 415.1 18,681.1 80.8
(2008-2027) 9,707.0 10,768.8 708.7 4,695.6 1,013.0 26,893.0 951.5 5,152.7 6,104.2 (142.6) 656.6 230.6 2,699.1 807.6 37,248.5 100.3
(2008-2037) 13,491.6 15,157.6 1,076.3 5,931.5 1,427.3 37,084.3 1,009.5 6,828.9 7,838.4 (142.6) 963.4 271.8 4,381.1 950.7 51,347.1 112.6
APPENDIX 2 TABLE 55. TABLE 56. RISK ANALYSIS A - CARBON COST AT $25/TON SUPPLY SIDE SCENARIO 2 (SS-2/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 600.4 837.3 50.8 446.3 66.1 2,000.9 106.2 556.1 662.3 (24.3) 54.7 29.0 268.7 54.9 3,046.2 86.9 2015 637.3 846.7 51.1 462.7 89.7 2,087.5 120.9 707.6 828.5 (33.0) 56.0 30.6 285.0 58.3 3,312.9 91.3 2016 802.8 902.3 56.8 437.2 137.8 2,336.8 152.0 830.5 982.5 (37.0) 62.0 32.0 309.5 93.4 3,779.1 100.7 2017 1,003.1 1,110.7 71.1 453.4 160.2 2,798.5 161.9 759.2 921.1 (39.2) 68.6 30.5 345.2 100.0 4,224.6 108.9 2018 1,177.2 1,267.3 84.5 471.3 161.9 3,162.3 126.7 730.0 856.7 (38.4) 77.4 29.7 396.4 107.3 4,591.3 114.8 2019 1,304.3 1,294.3 86.8 486.7 174.2 3,346.4 122.6 773.5 896.1 (5.2) 80.8 28.8 425.5 114.3 4,886.6 118.8 2020 1,539.1 1,540.5 105.3 508.3 195.4 3,888.5 65.4 661.5 726.9 (2.6) 90.5 26.1 466.8 121.1 5,317.2 125.9 2021 1,834.3 1,616.6 117.3 539.8 234.2 4,342.1 64.3 766.0 830.3 0.0 98.1 31.5 518.0 127.8 5,947.8 137.3 2022 2,111.1 1,662.0 124.8 576.1 245.5 4,719.5 58.8 744.3 803.1 0.0 106.1 30.4 532.1 134.8 6,326.0 142.4 2023 2,108.6 1,541.5 115.5 617.7 238.5 4,621.8 31.2 968.6 999.9 0.0 93.8 34.1 514.9 142.6 6,407.1 140.7 2024 1,992.5 1,604.8 120.2 640.2 231.5 4,589.3 36.1 970.1 1,006.3 0.0 94.7 33.0 548.3 150.3 6,421.8 137.7 2025 2,034.1 1,650.4 124.0 658.0 227.8 4,694.3 51.5 1,188.1 1,239.7 0.0 103.9 39.3 579.0 158.2 6,814.4 142.7 2026 2,085.1 1,804.3 137.2 677.3 242.2 4,946.1 55.7 1,190.6 1,246.3 0.0 111.3 37.9 649.7 92.2 7,083.4 144.6 2027 2,131.6 1,965.4 149.2 695.3 245.5 5,186.9 58.2 1,205.5 1,263.7 0.0 123.3 37.3 733.4 92.2 7,436.9 148.0 2028 2,218.6 2,092.0 161.2 720.2 239.7 5,431.7 52.7 1,211.0 1,263.7 0.0 135.6 35.8 806.9 98.1 7,771.7 150.9 2029 2,307.2 2,284.8 176.2 746.2 233.9 5,748.2 46.7 1,209.3 1,256.1 0.0 153.4 34.1 897.0 98.0 8,186.8 154.7 2030 2,451.3 2,422.9 194.7 777.7 250.4 6,097.0 10.3 1,201.5 1,211.8 0.0 160.8 32.4 967.3 97.3 8,566.6 157.9 2031 2,524.4 2,571.9 211.9 807.1 255.0 6,370.4 51.1 1,202.9 1,254.0 0.0 174.1 30.6 1,034.9 96.8 8,960.7 161.2 2032 2,565.9 2,806.4 231.8 836.0 248.1 6,688.2 45.7 1,208.5 1,254.2 0.0 191.7 28.7 1,086.8 96.2 9,345.9 164.4 2033 2,660.2 2,964.5 246.0 865.6 267.6 7,004.0 36.5 1,239.9 1,276.3 0.0 200.2 28.3 1,153.9 95.9 9,758.5 167.5 2034 2,708.2 3,118.5 263.1 895.4 315.6 7,300.8 51.1 1,468.4 1,519.4 0.0 221.8 37.6 1,200.9 95.1 10,375.8 174.1 2035 2,762.1 3,309.4 281.3 925.6 326.5 7,604.9 40.0 1,511.5 1,551.5 0.0 238.4 37.3 1,278.8 94.4 10,805.2 177.3 2036 2,815.4 3,468.7 295.7 961.7 346.1 7,887.6 79.0 1,560.4 1,639.4 0.0 252.3 36.8 1,333.2 93.8 11,243.0 180.9 2037 2,863.9 3,691.5 317.6 973.9 351.5 8,198.4 18.5 1,604.6 1,623.1 0.0 274.9 36.3 1,405.2 93.3 11,631.2 182.9
CPW@ 7.86% (2008-2017) 4,189.1 5,458.3 317.2 2,888.8 338.2 13,191.6 722.3 3,112.3 3,834.6 (122.8) 327.4 162.2 946.1 415.1 18,754.2 81.2
(2008-2027) 9,782.6 10,389.8 674.0 4,696.3 1,017.1 26,559.9 951.0 5,903.7 6,854.7 (142.6) 629.9 263.8 2,584.6 807.6 37,557.9 101.1
(2008-2037) 13,565.6 14,501.7 1,012.0 5,934.9 1,425.7 36,439.9 1,014.9 7,854.1 8,869.0 (142.6) 914.1 313.7 4,186.0 950.7 51,530.8 113.0
APPENDIX 2 TABLE 56. TABLE 57. RISK ANALYSIS A - CARBON COST AT $25/TON SUPPLY SIDE SCENARIO 3 (SS-3/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 2,801.3 82.3 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 268.7 54.9 3,046.9 86.9 2015 639.1 855.8 51.6 462.7 89.7 2,098.9 125.2 678.0 803.3 (33.0) 56.8 29.2 287.6 58.3 3,301.1 91.0 2016 835.8 936.2 59.0 438.2 137.8 2,407.0 153.7 720.8 874.4 (37.0) 64.8 27.0 319.2 93.4 3,748.7 99.9 2017 1,064.4 1,160.4 75.1 455.2 160.8 2,915.9 164.4 611.0 775.4 (39.2) 72.4 23.8 359.5 100.0 4,207.8 108.5 2018 1,265.3 1,333.4 89.8 473.7 177.6 3,339.8 127.7 547.1 674.7 (38.4) 82.2 21.4 414.1 107.3 4,601.2 115.1 2019 1,404.5 1,361.8 92.1 489.0 181.5 3,528.9 129.6 589.9 719.5 (5.2) 85.9 20.7 443.9 114.3 4,908.0 119.3 2020 1,678.1 1,593.7 114.6 513.3 194.0 4,093.7 72.5 471.3 543.8 (2.6) 93.3 18.1 479.1 121.1 5,346.6 126.6 2021 1,995.4 1,686.5 126.1 544.6 240.9 4,593.5 63.5 578.2 641.8 0.0 102.4 23.6 534.3 127.8 6,023.4 139.0 2022 2,288.1 1,718.4 129.0 581.8 256.3 4,973.6 57.5 554.4 611.9 0.0 110.3 22.7 545.4 134.8 6,398.6 144.0 2023 2,288.8 1,557.1 116.6 628.8 249.0 4,840.3 23.2 778.6 801.9 0.0 94.6 26.5 517.1 142.6 6,422.9 141.1 2024 2,132.9 1,609.1 120.0 653.3 241.7 4,757.1 33.4 779.8 813.2 0.0 94.5 25.6 547.0 150.3 6,387.5 137.0 2025 2,159.1 1,650.8 124.0 671.0 255.7 4,860.5 56.1 998.1 1,054.2 0.0 103.3 32.1 575.5 158.2 6,783.7 142.1 2026 2,223.5 1,808.0 137.7 691.4 259.1 5,119.7 48.9 1,000.6 1,049.5 0.0 110.9 30.8 648.2 92.2 7,051.3 143.9 2027 2,332.2 1,949.5 153.1 714.8 252.8 5,402.5 11.9 1,015.5 1,027.5 0.0 120.9 30.4 726.1 92.2 7,399.6 147.3 2028 2,414.9 2,067.6 167.7 742.1 245.5 5,637.8 48.9 1,020.6 1,069.5 0.0 132.3 29.1 794.3 98.1 7,761.0 150.7 2029 2,471.1 2,257.6 183.8 767.6 239.5 5,919.6 43.0 1,019.4 1,062.4 0.0 148.7 27.6 884.3 98.0 8,140.6 153.8 2030 2,549.2 2,420.8 197.7 794.9 256.1 6,218.7 41.7 1,011.5 1,053.2 0.0 160.1 26.1 960.7 97.3 8,516.1 157.0 2031 2,595.6 2,574.3 211.6 822.2 260.4 6,464.0 59.0 1,012.9 1,071.9 0.0 172.8 24.5 1,030.5 96.8 8,860.4 159.4 2032 2,647.4 2,810.6 231.3 852.1 278.2 6,819.5 53.3 1,018.1 1,071.3 0.0 190.3 22.8 1,083.9 96.2 9,284.0 163.4 2033 2,737.1 2,965.2 245.5 882.2 283.5 7,113.3 43.8 1,049.9 1,093.7 0.0 199.1 22.7 1,150.0 95.9 9,674.7 166.1 2034 2,780.7 3,119.5 262.9 912.4 275.0 7,350.4 58.3 1,278.4 1,336.7 0.0 222.4 32.4 1,198.3 95.1 10,235.2 171.7 2035 2,829.6 3,316.0 281.2 943.1 266.6 7,636.5 47.1 1,321.5 1,368.7 0.0 238.1 32.3 1,276.8 94.4 10,646.8 174.7 2036 2,901.6 3,472.3 295.0 980.7 288.3 7,937.9 36.1 1,370.0 1,406.1 0.0 251.9 32.1 1,330.6 93.8 11,052.4 177.8 2037 2,937.4 3,695.6 317.2 993.2 294.1 8,237.4 99.7 1,414.6 1,514.4 0.0 273.7 31.9 1,401.8 93.3 11,552.5 181.6
CPW@ 7.86% (2008-2017) 4,236.0 5,503.7 320.5 2,890.2 338.5 13,288.8 726.6 2,971.1 3,697.8 (122.8) 331.0 155.8 959.2 415.1 18,724.9 81.0
(2008-2027) 10,274.6 10,556.9 690.8 4,722.9 1,051.2 27,296.4 946.8 5,166.7 6,113.5 (142.6) 641.0 232.9 2,624.8 807.6 37,573.6 101.1
(2008-2037) 14,215.2 14,661.1 1,031.8 5,988.6 1,445.8 37,342.5 1,023.6 6,834.4 7,858.0 (142.6) 922.8 274.2 4,217.1 950.7 51,422.6 112.8
APPENDIX 2 TABLE 57. TABLE 58. RISK ANALYSIS A - CARBON COST AT $25/TON SUPPLY SIDE SCENARIO 4 (SS-4/A) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 0.0 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 0.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 0.0 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 0.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 245.5 84.9 0.0 2,735.8 81.2 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 255.4 51.4 0.0 2,801.3 82.3 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 268.7 54.9 (0.1) 3,046.8 86.9 2015 639.1 846.7 51.1 462.7 89.7 2,089.4 120.9 707.6 828.5 (33.0) 56.0 30.6 285.0 58.3 (0.1) 3,314.6 91.3 2016 810.8 893.6 56.0 437.2 137.8 2,335.4 147.5 863.5 1,011.1 (37.0) 61.7 33.7 305.6 93.4 (0.0) 3,803.8 101.3 2017 996.9 1,067.7 67.8 452.4 160.2 2,745.0 158.0 893.5 1,051.5 (39.2) 65.5 36.7 332.3 100.0 (0.0) 4,291.8 110.6 2018 1,142.4 1,184.6 78.7 468.4 161.3 3,035.4 128.6 974.2 1,102.8 (38.4) 71.6 40.7 373.3 107.3 (0.0) 4,692.6 117.4 2019 1,244.7 1,168.9 77.5 481.8 157.3 3,130.3 125.4 1,163.1 1,288.5 (5.2) 71.6 46.4 386.5 114.3 (0.9) 5,031.4 122.3 2020 1,458.0 1,342.9 90.4 501.3 170.4 3,562.9 66.1 1,214.9 1,281.1 (2.6) 76.4 50.4 412.1 121.1 (1.4) 5,500.0 130.2 2021 1,728.5 1,421.8 96.9 528.7 217.2 3,993.0 63.4 1,370.7 1,434.1 0.0 84.8 57.6 463.6 127.8 (2.8) 6,158.2 142.1 2022 2,020.5 1,442.2 98.1 564.9 233.0 4,358.7 59.5 1,354.9 1,414.4 0.0 91.4 56.2 471.4 134.8 (2.6) 6,524.2 146.8 2023 2,031.1 1,304.1 86.8 611.4 226.4 4,259.8 25.2 1,578.8 1,604.0 0.0 76.7 59.5 436.7 142.6 (20.1) 6,559.1 144.0 2024 1,884.8 1,364.5 90.5 635.4 268.2 4,243.5 35.2 1,582.2 1,617.5 0.0 76.8 57.9 466.2 150.3 (36.9) 6,575.4 141.0 2025 1,920.4 1,403.2 93.3 652.5 288.1 4,357.6 57.9 1,798.6 1,856.5 0.0 84.1 63.8 492.5 158.2 (39.1) 6,973.6 146.1 2026 1,994.2 1,538.8 104.5 672.4 280.9 4,590.8 50.6 1,800.8 1,851.4 0.0 91.2 61.9 563.8 92.2 (28.7) 7,222.5 147.4 2027 2,058.2 1,686.4 115.9 690.8 294.6 4,845.9 45.6 1,815.7 1,861.3 0.0 102.1 60.8 646.8 92.2 (24.8) 7,584.4 150.9 2028 2,131.6 1,801.0 125.2 714.8 296.9 5,069.5 61.0 1,822.5 1,883.5 0.0 114.5 58.7 715.1 98.1 (21.5) 7,917.7 153.7 2029 2,211.6 1,975.6 139.8 740.1 288.6 5,355.6 54.7 1,819.8 1,874.5 0.0 130.7 56.5 803.8 98.0 (12.8) 8,306.2 157.0 2030 2,300.1 2,134.2 152.5 766.5 304.2 5,657.6 52.9 1,811.8 1,864.7 0.0 141.7 54.1 879.2 97.3 (11.3) 8,683.3 160.1 2031 2,377.1 2,281.6 164.3 793.7 307.7 5,924.4 47.5 1,813.0 1,860.5 0.0 154.0 51.7 947.4 96.8 (9.2) 9,025.4 162.4 2032 2,452.3 2,506.5 183.1 823.3 300.2 6,265.4 42.2 1,820.1 1,862.3 0.0 171.3 49.1 1,001.9 96.2 (5.3) 9,441.0 166.1 2033 2,527.8 2,660.1 195.5 851.7 317.6 6,552.7 56.8 1,850.0 1,906.8 0.0 178.5 47.9 1,066.7 95.9 (4.0) 9,844.5 169.0 2034 2,586.0 2,818.5 210.0 881.3 320.6 6,816.5 46.4 2,078.5 2,124.9 0.0 201.7 56.5 1,115.4 95.1 (3.4) 10,406.7 174.6 2035 2,658.1 3,001.7 227.5 911.7 311.0 7,110.0 35.5 2,121.7 2,157.2 0.0 217.9 55.3 1,190.3 94.4 (2.5) 10,822.7 177.6 2036 2,713.1 3,151.7 239.7 947.4 331.4 7,383.4 74.7 2,171.8 2,246.6 0.0 229.9 54.0 1,241.2 93.8 (2.8) 11,246.0 180.9 2037 2,764.9 3,369.0 259.7 959.2 335.8 7,688.6 14.3 2,214.8 2,229.1 0.0 251.5 52.5 1,311.6 93.3 (1.5) 11,625.3 182.8
CPW@ 7.86% (2008-2017) 4,191.7 5,433.7 315.2 2,888.3 338.2 13,167.1 718.2 3,192.1 3,910.3 (122.8) 325.8 166.0 938.1 415.1 (0.1) 18,799.5 81.4
(2008-2027) 9,530.1 9,741.7 604.8 4,675.7 1,032.8 25,585.1 944.7 7,646.5 8,591.3 (142.6) 582.9 337.5 2,384.3 807.6 (41.3) 38,104.9 102.6
(2008-2037) 13,141.1 13,405.3 873.5 5,897.4 1,491.8 34,809.0 1,018.9 10,505.1 11,524.0 (142.6) 835.8 417.7 3,853.0 950.7 (54.2) 52,193.4 114.5
APPENDIX 2 TABLE 58. TABLE 59. RISK ANALYSIS B - CARBON COST AT $50/TON SELECTED PLAN (SP/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 50.0 2,155.7 67.0 2009 549.1 787.5 42.1 412.2 8.6 1,799.6 76.8 308.1 384.8 (8.3) 42.5 14.5 (1.2) 81.6 2,313.6 71.1 2010 573.3 736.2 41.5 422.9 20.9 1,794.8 115.7 335.4 451.1 (9.1) 42.2 24.5 (9.5) 82.3 2,376.4 73.1 2011 580.5 770.7 43.5 419.9 28.5 1,843.1 102.9 277.4 380.2 (10.0) 43.4 23.2 (10.0) 107.1 2,377.1 72.9 2012 578.7 683.7 39.7 423.8 30.7 1,756.6 105.2 437.6 542.9 (14.0) 42.5 27.8 479.3 134.9 2,969.9 90.3 2013 583.5 686.6 41.6 429.0 49.2 1,789.9 105.8 484.9 590.7 (19.0) 44.3 27.2 494.6 115.8 3,043.6 92.0 2014 601.0 779.4 47.5 446.3 66.1 1,940.4 106.2 545.4 651.5 (24.3) 51.0 29.0 517.5 134.5 3,299.5 97.2 2015 639.1 790.6 47.9 462.7 76.3 2,016.7 106.6 663.9 770.4 (33.0) 51.8 29.2 548.8 160.7 3,544.8 101.3 2016 798.3 857.4 53.3 436.7 103.7 2,249.3 139.4 705.8 845.2 (37.0) 59.0 27.0 604.8 220.0 3,968.2 110.1 2017 989.0 1,058.8 67.2 452.0 120.2 2,687.2 165.8 601.5 767.3 (39.2) 64.8 23.8 675.9 230.5 4,410.3 119.0 2018 1,184.0 1,210.4 80.7 470.0 163.0 3,108.0 127.4 538.2 665.6 (38.4) 72.8 21.4 777.9 241.7 4,849.0 127.5 2019 1,326.5 1,223.1 82.2 485.2 180.0 3,297.1 122.0 581.1 703.0 (5.2) 75.5 20.7 829.5 252.7 5,173.3 132.7 2020 1,589.1 1,428.3 103.1 508.8 192.2 3,821.5 67.5 468.9 536.4 (2.6) 80.9 18.1 895.1 263.6 5,613.0 140.6 2021 1,885.2 1,508.2 113.2 539.0 239.1 4,284.7 67.8 574.6 642.4 0.0 89.4 23.6 998.9 274.7 6,313.7 154.6 2022 2,171.9 1,523.3 114.5 575.6 254.6 4,639.9 61.5 554.4 615.9 0.0 95.2 22.7 1,011.9 286.0 6,671.7 159.7 2023 2,177.4 1,355.6 100.2 622.4 247.3 4,502.9 20.6 778.6 799.2 0.0 80.3 26.5 944.6 298.4 6,651.8 155.7 2024 2,026.1 1,399.9 101.8 646.7 240.2 4,414.7 24.4 779.7 804.2 0.0 79.3 25.6 992.3 310.8 6,626.7 151.8 2025 2,040.1 1,424.8 103.6 663.6 235.5 4,467.5 52.1 998.2 1,050.3 0.0 85.6 32.1 1,039.1 323.5 6,998.0 156.8 2026 2,080.6 1,560.1 116.6 682.5 249.3 4,689.1 57.5 1,000.6 1,058.1 0.0 92.4 30.8 1,179.7 262.4 7,312.5 159.9 2027 2,129.3 1,700.5 127.9 700.8 252.4 4,911.0 51.1 1,015.5 1,066.6 0.0 101.9 30.4 1,342.0 258.3 7,710.1 164.6 2028 2,200.3 1,806.7 137.6 725.1 245.6 5,115.4 60.4 1,020.6 1,080.9 0.0 113.9 29.1 1,473.2 258.7 8,071.2 168.2 2029 2,277.8 1,978.7 151.9 750.7 261.8 5,420.8 47.9 1,019.4 1,067.3 0.0 128.5 27.6 1,648.5 251.9 8,544.7 173.4 2030 2,343.8 2,126.4 164.3 776.7 265.6 5,676.8 61.3 1,011.6 1,073.0 0.0 138.3 26.1 1,794.7 243.1 8,952.0 177.3 2031 2,404.8 2,262.7 175.3 803.6 259.8 5,906.2 48.6 1,012.9 1,061.5 0.0 148.7 24.5 1,924.7 232.8 9,298.3 179.8 2032 2,478.1 2,476.4 193.0 833.5 277.7 6,258.7 36.9 1,018.0 1,054.9 0.0 164.8 22.8 2,029.1 220.5 9,750.9 184.6 2033 2,552.2 2,613.1 204.5 862.2 281.6 6,513.6 44.6 1,049.9 1,094.5 0.0 171.0 22.7 2,155.3 206.4 10,163.6 187.7 2034 2,587.2 2,748.7 218.1 891.3 273.9 6,719.2 51.7 1,278.4 1,330.1 0.0 192.1 32.4 2,244.7 189.4 10,707.8 193.4 2035 2,620.0 2,926.3 234.2 920.5 291.6 6,992.6 58.3 1,321.5 1,379.8 0.0 206.9 32.3 2,392.0 170.0 11,173.5 197.5 2036 2,683.4 3,058.3 246.0 956.7 297.5 7,241.8 15.0 1,370.0 1,385.0 0.0 218.2 32.1 2,491.4 147.6 11,516.1 199.7 2037 2,727.3 3,257.1 264.7 968.5 290.2 7,507.9 71.5 1,414.6 1,486.1 0.0 237.3 31.9 2,621.5 122.1 12,006.8 203.5
CPW@ 7.86% (2008-2017) 4,181.6 5,247.4 304.9 2,887.9 294.8 12,916.7 709.9 2,920.9 3,630.8 (122.8) 313.9 155.8 1,853.3 813.7 19,561.4 86.5
(2008-2027) 9,872.7 9,715.2 628.2 4,701.0 990.2 25,907.3 934.2 5,106.9 6,041.1 (142.6) 580.0 232.9 4,930.4 1,683.5 39,232.7 109.5
(2008-2037) 13,518.1 13,324.9 911.3 5,937.6 1,393.8 35,085.7 1,008.8 6,774.6 7,783.4 (142.6) 823.4 274.2 7,906.3 2,000.7 53,731.4 123.0
APPENDIX 2 TABLE 59. TABLE 60. RISK ANALYSIS B - CARBON COST AT $50/TON DEFAULT ENERGY EFFICIENCY SCENARIO (EE-D/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 26.6 2,134.4 66.3 2009 549.1 800.3 43.0 412.2 8.6 1,813.3 85.7 309.4 395.1 (8.3) 43.8 14.7 (1.2) 56.0 2,313.4 70.7 2010 573.3 763.9 42.8 422.9 20.9 1,823.9 120.7 341.1 461.8 (9.1) 44.4 24.8 (9.5) 54.8 2,391.2 72.7 2011 580.5 796.7 44.4 419.9 28.5 1,870.0 101.8 309.4 411.2 (10.0) 47.3 29.2 (9.9) 67.0 2,404.8 72.4 2012 578.7 721.4 42.1 423.8 30.7 1,796.7 104.2 457.6 561.8 (14.0) 45.9 28.2 503.0 84.9 3,006.5 89.3 2013 583.5 742.5 44.9 429.0 49.2 1,849.1 104.8 496.3 601.1 (19.0) 49.8 28.2 528.9 51.4 3,089.7 90.8 2014 597.5 873.2 52.8 446.3 91.2 2,060.9 119.7 465.9 585.6 (24.3) 58.0 25.8 570.6 54.9 3,331.6 95.0 2015 641.6 915.8 55.8 463.2 103.8 2,180.2 151.2 529.0 680.2 (33.0) 62.5 23.1 627.5 58.3 3,598.9 99.2 2016 843.0 988.2 62.6 440.5 140.5 2,474.7 157.8 553.0 710.8 (37.0) 69.9 20.2 684.1 93.4 4,016.0 107.0 2017 1,017.2 1,221.6 79.8 458.3 175.7 2,952.7 156.0 439.1 595.0 (39.2) 77.0 17.2 767.0 100.0 4,469.6 115.2 2018 1,116.3 1,371.1 92.1 476.4 184.5 3,240.4 125.2 372.2 497.4 (38.4) 85.6 15.0 862.0 107.3 4,769.2 119.3 2019 1,148.9 1,447.9 98.7 491.8 180.6 3,367.9 124.0 409.8 533.8 (5.2) 95.4 14.3 952.1 114.3 5,072.6 123.3 2020 1,295.6 1,668.9 120.0 516.0 193.4 3,793.8 66.9 285.6 352.5 (2.6) 99.7 11.9 1,014.7 121.1 5,391.0 127.6 2021 1,519.6 1,773.5 137.7 549.7 199.8 4,180.3 67.3 344.1 411.5 0.0 109.6 15.2 1,132.1 127.8 5,976.5 137.9 2022 1,666.1 1,917.0 153.6 575.1 196.6 4,508.4 52.1 320.2 372.3 0.0 128.5 14.5 1,215.6 134.8 6,374.0 143.4 2023 1,635.1 1,978.3 158.5 594.3 191.8 4,558.0 52.3 453.3 505.6 0.0 126.6 18.5 1,295.7 142.6 6,647.0 146.0 2024 1,644.1 2,117.7 170.3 607.2 206.0 4,745.4 53.0 457.5 510.5 0.0 136.0 17.8 1,416.8 150.3 6,976.7 149.6 2025 1,685.9 2,172.4 175.9 624.1 212.3 4,870.5 51.9 607.6 659.4 0.0 144.0 24.5 1,487.1 158.2 7,343.8 153.8 2026 1,740.5 2,331.5 188.7 642.3 207.3 5,110.3 46.7 612.2 658.8 0.0 152.6 23.5 1,624.7 92.2 7,662.1 156.4 2027 1,859.3 2,457.9 206.9 664.3 202.5 5,390.9 9.8 630.1 640.0 0.0 163.0 22.4 1,776.9 92.2 8,085.5 160.9 2028 1,935.4 2,612.7 225.9 689.6 218.5 5,682.1 54.7 639.9 694.6 0.0 176.4 21.3 1,939.2 98.1 8,611.6 167.2 2029 1,995.8 2,806.4 243.2 713.3 223.3 5,982.0 48.7 644.3 692.9 0.0 195.1 20.1 2,117.6 98.0 9,105.6 172.1 2030 2,099.1 3,002.2 261.9 739.3 218.7 6,321.2 34.1 640.3 674.3 0.0 208.6 18.8 2,292.1 97.3 9,612.3 177.2 2031 2,153.3 3,128.7 275.2 764.6 237.4 6,559.2 39.9 771.1 811.0 0.0 221.6 25.4 2,420.2 96.8 10,134.2 182.3 2032 2,177.5 3,343.0 296.1 791.2 243.0 6,850.8 53.8 862.3 916.1 0.0 237.9 28.9 2,521.2 96.2 10,651.1 187.4 2033 2,246.9 3,527.6 314.0 818.0 237.0 7,143.5 52.0 898.6 950.5 0.0 250.9 29.2 2,667.6 95.9 11,137.7 191.2 2034 2,349.4 3,762.0 340.7 847.7 259.6 7,559.4 41.2 938.9 980.1 0.0 280.2 29.5 2,803.3 95.1 11,747.6 197.1 2035 2,454.9 3,930.4 356.8 877.7 264.0 7,883.9 30.1 978.8 1,008.9 0.0 294.1 29.8 2,952.8 94.4 12,264.0 201.3 2036 2,525.0 4,139.9 377.1 912.4 257.7 8,212.2 69.0 1,026.5 1,095.5 0.0 310.9 30.1 3,097.5 93.8 12,839.9 206.5 2037 2,566.2 4,344.0 401.0 922.6 253.8 8,487.7 36.7 1,069.8 1,106.5 0.0 327.5 30.3 3,230.9 93.3 13,276.2 209.5
CPW@ 7.86% (2008-2017) 4,216.7 5,627.0 329.2 2,893.1 369.3 13,435.2 758.3 2,697.4 3,455.7 (122.8) 346.6 150.3 2,048.5 415.1 19,728.6 85.4
(2008-2027) 8,909.3 11,489.6 780.8 4,670.9 989.5 26,840.0 984.7 4,055.1 5,039.7 (142.6) 723.2 204.2 5,906.3 807.6 39,378.5 106.0
(2008-2037) 12,190.3 16,458.8 1,222.9 5,847.1 1,343.5 37,062.6 1,053.4 5,265.7 6,319.1 (142.6) 1,080.0 242.2 9,650.4 950.7 55,162.4 121.0
APPENDIX 2 TABLE 60. TABLE 61. RISK ANALYSIS B - CARBON COST AT $50/TON ENERGY EFFICIENCY SCENARIO 1 (EE-1/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 50.0 2,157.7 67.1 2009 549.1 790.6 42.5 412.2 8.6 1,803.0 83.6 307.3 390.9 (8.3) 43.3 14.7 (1.2) 82.4 2,324.8 71.4 2010 573.3 743.5 42.3 422.9 20.9 1,802.9 119.4 336.8 456.2 (9.1) 43.3 24.8 (9.5) 84.0 2,392.7 73.6 2011 580.5 767.4 43.0 419.9 28.5 1,839.2 102.1 302.8 404.9 (10.0) 45.3 29.2 (10.0) 88.3 2,387.0 73.2 2012 578.7 686.2 40.2 423.8 30.7 1,759.6 104.5 449.8 554.2 (14.0) 44.1 28.2 482.2 108.1 2,962.5 89.9 2013 583.5 702.9 42.5 429.0 49.2 1,807.2 105.0 485.8 590.8 (19.0) 46.8 28.2 504.7 74.9 3,033.6 91.4 2014 597.5 822.7 50.0 446.3 77.8 1,994.3 105.5 457.6 563.0 (24.3) 54.5 25.8 544.4 78.7 3,236.4 94.8 2015 629.5 864.6 52.2 462.7 97.5 2,106.5 133.5 517.1 650.6 (33.0) 58.5 23.1 598.3 82.7 3,486.8 98.8 2016 808.1 927.3 58.4 438.9 141.1 2,373.8 156.8 544.4 701.2 (37.0) 65.2 20.2 651.3 118.3 3,893.1 106.8 2017 975.6 1,151.7 74.5 456.4 160.7 2,818.9 156.6 433.2 589.7 (39.2) 71.7 17.2 730.6 125.7 4,314.7 114.6 2018 1,078.1 1,294.9 86.6 474.5 178.4 3,112.4 120.0 365.8 485.8 (38.4) 79.5 15.0 822.1 133.8 4,610.2 118.9 2019 1,109.9 1,364.5 92.4 489.6 182.0 3,238.3 122.5 403.8 526.3 (5.2) 88.7 14.3 908.9 141.6 4,912.9 123.2 2020 1,256.3 1,575.3 113.3 513.6 179.0 3,637.6 67.3 283.3 350.7 (2.6) 92.4 11.9 968.9 149.2 5,208.0 127.3 2021 1,469.8 1,677.8 130.5 546.9 194.4 4,019.4 69.5 342.3 411.8 0.0 102.3 15.2 1,085.0 156.9 5,790.6 138.0 2022 1,609.8 1,812.9 145.2 572.0 199.7 4,339.6 54.8 320.3 375.0 0.0 120.1 14.5 1,165.5 164.7 6,179.5 143.6 2023 1,581.2 1,869.5 149.9 591.1 194.9 4,386.5 53.0 453.3 506.3 0.0 118.2 18.5 1,242.6 173.5 6,445.7 146.2 2024 1,592.5 2,002.1 160.9 604.0 190.1 4,549.5 52.0 457.7 509.6 0.0 126.8 17.8 1,360.6 182.2 6,746.6 149.5 2025 1,633.5 2,051.1 165.9 620.4 206.0 4,677.0 55.7 607.5 663.2 0.0 134.2 24.5 1,426.1 191.1 7,116.1 154.0 2026 1,674.2 2,202.8 177.8 638.0 211.6 4,904.4 57.6 613.0 670.6 0.0 142.2 23.5 1,561.9 126.0 7,428.5 156.7 2027 1,785.9 2,324.3 195.3 659.5 207.2 5,172.2 20.7 630.6 651.3 0.0 152.2 22.4 1,712.5 125.2 7,835.8 161.2 2028 1,880.5 2,472.0 213.5 685.1 201.4 5,452.6 55.7 639.2 694.9 0.0 164.9 21.3 1,872.0 130.0 8,335.6 167.2 2029 1,938.7 2,657.5 230.0 708.5 218.4 5,753.1 56.0 645.6 701.6 0.0 183.0 20.1 2,046.7 128.6 8,833.1 172.5 2030 2,033.5 2,844.1 248.0 734.0 224.1 6,083.7 39.1 641.0 680.0 0.0 195.8 18.8 2,217.6 126.3 9,322.3 177.5 2031 2,107.4 2,964.0 260.1 759.7 219.2 6,310.4 34.3 770.3 804.7 0.0 207.6 25.4 2,341.0 123.8 9,812.9 182.4 2032 2,145.4 3,169.0 280.3 786.4 239.1 6,620.2 46.5 861.3 907.8 0.0 223.4 28.9 2,438.4 121.0 10,339.6 187.9 2033 2,216.2 3,344.5 297.1 813.1 245.4 6,916.2 43.1 897.4 940.5 0.0 235.7 29.2 2,581.2 117.9 10,820.8 191.9 2034 2,297.6 3,565.1 322.2 841.8 239.8 7,266.5 54.6 939.1 993.8 0.0 263.8 29.5 2,710.4 113.8 11,377.8 197.2 2035 2,370.4 3,726.7 337.4 870.5 260.3 7,565.2 50.6 981.1 1,031.7 0.0 277.3 29.8 2,856.6 109.5 11,870.2 201.2 2036 2,454.6 3,928.6 356.8 905.5 268.0 7,913.6 27.2 1,026.0 1,053.2 0.0 293.1 30.1 2,995.3 104.5 12,389.7 205.8 2037 2,511.5 4,120.8 379.4 915.8 263.0 8,190.5 88.2 1,070.3 1,158.5 0.0 309.0 30.3 3,122.9 99.0 12,910.4 210.4
CPW@ 7.86% (2008-2017) 4,172.9 5,410.2 316.2 2,891.1 351.3 13,141.6 737.6 2,656.8 3,394.3 (122.8) 331.6 150.3 1,953.8 581.3 19,430.2 85.6
(2008-2027) 8,707.5 10,948.7 742.4 4,659.5 960.1 26,018.1 968.8 4,008.1 4,976.9 (142.6) 682.5 204.2 5,651.2 1,068.3 38,458.7 105.9
(2008-2037) 11,908.0 15,658.0 1,160.5 5,827.7 1,307.4 35,861.6 1,041.6 5,218.8 6,260.4 (142.6) 1,017.8 242.2 9,271.4 1,246.0 53,756.8 120.9
APPENDIX 2 TABLE 61. TABLE 62. RISK ANALYSIS B - CARBON COST AT $50/TON ENERGY EFFICIENCY SCENARIO 2 (EE-2/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 103.2 2,210.9 68.7 2009 549.1 778.3 41.9 412.2 8.6 1,790.2 78.4 302.8 381.2 (8.3) 42.6 14.7 (1.2) 139.4 2,358.7 73.0 2010 573.3 722.2 41.3 422.9 20.9 1,780.6 116.2 332.0 448.2 (9.1) 42.1 24.8 (9.5) 139.0 2,416.2 75.2 2011 580.5 741.4 42.0 419.9 28.5 1,812.3 102.6 298.4 401.1 (10.0) 43.6 29.2 (10.0) 152.6 2,418.9 75.1 2012 578.7 657.4 38.5 423.8 30.7 1,729.1 105.0 443.7 548.7 (14.0) 42.2 28.2 468.2 172.8 2,975.2 91.8 2013 583.5 671.6 40.6 429.0 49.2 1,773.9 105.6 476.1 581.6 (19.0) 44.4 28.2 487.2 141.1 3,037.5 93.4 2014 597.5 782.8 47.8 446.3 66.1 1,940.5 106.0 449.4 555.3 (24.3) 51.8 25.8 523.1 147.1 3,219.3 96.4 2015 629.5 820.3 49.8 462.7 90.1 2,052.4 113.7 506.8 620.5 (33.0) 54.8 23.1 573.5 153.3 3,444.7 100.1 2016 780.9 876.2 54.7 437.7 138.7 2,288.1 143.8 534.4 678.2 (37.0) 60.7 20.2 622.0 191.3 3,823.6 107.7 2017 917.4 1,087.7 69.8 453.7 161.2 2,689.8 164.3 426.1 590.4 (39.2) 66.9 17.2 697.5 200.9 4,223.6 115.4 2018 1,013.2 1,221.1 81.2 471.4 163.6 2,950.5 130.1 360.4 490.5 (38.4) 73.4 15.0 785.3 211.6 4,487.8 119.2 2019 1,050.1 1,282.5 86.4 486.6 176.1 3,081.7 123.3 398.6 521.9 (5.2) 82.0 14.3 867.7 221.8 4,784.2 123.8 2020 1,198.2 1,481.2 106.4 510.4 180.5 3,476.7 66.8 280.6 347.4 (2.6) 84.7 11.9 923.9 232.0 5,074.0 128.1 2021 1,412.2 1,576.8 123.1 543.5 179.6 3,835.1 69.8 340.3 410.1 0.0 94.1 15.2 1,038.0 242.4 5,634.9 138.9 2022 1,539.3 1,702.9 136.4 567.9 176.6 4,123.1 62.1 320.7 382.8 0.0 111.1 14.5 1,113.6 252.8 5,997.9 144.3 2023 1,518.4 1,751.6 140.7 587.0 190.2 4,187.9 53.7 452.3 506.0 0.0 108.8 18.5 1,187.7 264.0 6,273.0 147.5 2024 1,527.3 1,875.7 151.0 599.6 194.9 4,348.5 52.9 457.3 510.3 0.0 116.3 17.8 1,300.5 275.2 6,568.6 150.9 2025 1,576.4 1,917.0 155.0 616.1 192.1 4,456.6 50.0 606.4 656.4 0.0 123.4 24.5 1,361.1 287.3 6,909.3 155.2 2026 1,614.3 2,061.3 166.3 633.3 207.1 4,682.3 53.0 612.7 665.7 0.0 130.3 23.5 1,491.3 224.8 7,217.9 158.1 2027 1,647.8 2,196.6 178.9 649.3 212.0 4,884.6 59.4 633.0 692.4 0.0 142.2 22.4 1,650.5 220.8 7,613.0 162.6 2028 1,736.1 2,344.0 192.9 672.6 206.9 5,152.4 49.4 639.5 688.9 0.0 155.2 21.3 1,811.0 220.9 8,049.8 167.8 2029 1,825.5 2,524.9 208.4 696.6 225.2 5,480.6 46.9 644.7 691.6 0.0 172.6 20.1 1,981.1 215.7 8,561.7 173.6 2030 1,904.7 2,702.9 224.8 721.0 230.2 5,783.7 48.7 642.3 691.0 0.0 185.1 18.8 2,151.0 208.8 9,038.4 178.8 2031 1,969.4 2,817.1 236.2 745.7 224.8 5,993.2 40.0 771.2 811.2 0.0 196.5 25.4 2,270.2 200.8 9,497.2 183.4 2032 2,012.2 3,014.1 254.4 772.1 244.6 6,297.3 48.9 861.4 910.3 0.0 211.3 28.9 2,364.9 191.3 10,003.9 189.0 2033 2,087.4 3,179.8 270.1 798.3 250.8 6,586.5 42.3 897.7 940.0 0.0 222.7 29.2 2,503.4 180.4 10,462.3 192.8 2034 2,173.0 3,396.8 293.9 826.6 245.0 6,935.1 50.5 939.3 989.8 0.0 250.4 29.5 2,630.7 167.2 11,002.9 198.2 2035 2,269.0 3,547.2 308.0 855.3 237.5 7,217.0 33.3 979.4 1,012.7 0.0 263.1 29.8 2,769.7 152.2 11,444.6 201.6 2036 2,345.9 3,738.5 325.9 889.3 261.5 7,561.2 66.3 1,025.8 1,092.1 0.0 277.5 30.1 2,903.2 134.9 11,999.1 207.2 2037 2,393.8 3,927.2 346.7 898.8 270.0 7,836.6 28.2 1,070.2 1,098.4 0.0 293.3 30.3 3,028.7 115.3 12,402.6 210.1
CPW@ 7.86% (2008-2017) 4,131.8 5,220.1 305.2 2,889.2 339.3 12,885.7 718.3 2,616.6 3,334.9 (122.8) 317.9 150.3 1,876.6 1,008.5 19,451.2 87.0
(2008-2027) 8,453.7 10,421.8 704.0 4,644.4 923.7 25,147.6 962.9 3,961.8 4,924.7 (142.6) 641.4 204.2 5,411.5 1,772.5 37,959.2 106.9
(2008-2037) 11,467.4 14,900.1 1,084.2 5,791.7 1,274.9 34,518.3 1,031.0 5,172.6 6,203.6 (142.6) 958.6 242.2 8,920.9 2,048.8 52,749.8 121.7
APPENDIX 2 TABLE 62. TABLE 63. RISK ANALYSIS B - CARBON COST AT $50/TON ENERGY EFFICIENCY SCENARIO 3 (EE-3/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 179.8 2,287.5 71.1 2009 549.1 768.3 41.5 412.2 8.6 1,779.8 77.4 301.6 379.0 (8.3) 42.1 14.7 (1.2) 247.2 2,453.3 76.3 2010 573.3 704.5 40.7 422.9 20.9 1,762.4 115.6 328.3 443.9 (9.1) 41.1 24.8 (9.5) 245.9 2,499.5 78.5 2011 580.5 718.6 40.8 419.9 28.5 1,788.3 102.8 294.0 396.7 (10.0) 42.2 29.2 (10.0) 259.0 2,495.5 78.6 2012 578.7 631.2 37.1 423.8 30.7 1,701.5 105.1 435.8 541.0 (14.0) 40.6 28.2 453.5 282.5 3,033.4 95.3 2013 583.5 641.4 38.7 429.0 49.2 1,741.9 105.7 468.0 573.7 (19.0) 42.1 28.2 467.8 250.8 3,085.5 96.8 2014 597.5 743.9 45.8 446.3 66.1 1,899.6 106.1 442.3 548.4 (24.3) 48.9 25.8 501.3 259.6 3,259.3 99.9 2015 629.5 776.9 47.4 462.7 78.0 1,994.6 106.5 497.0 603.4 (33.0) 51.7 23.1 549.1 269.4 3,458.3 103.0 2016 743.4 827.1 51.4 436.2 110.1 2,168.1 144.8 526.4 671.2 (37.0) 57.3 20.2 594.3 311.2 3,785.3 109.5 2017 867.9 1,029.1 65.7 451.5 146.1 2,560.3 164.0 419.0 583.1 (39.2) 62.3 17.2 666.1 324.6 4,174.4 117.2 2018 972.5 1,154.5 76.9 469.3 161.5 2,834.7 126.7 353.8 480.5 (38.4) 68.2 15.0 750.1 340.0 4,450.1 121.7 2019 995.6 1,208.9 81.5 483.8 179.0 2,948.8 130.2 392.7 523.0 (5.2) 76.3 14.3 829.3 354.3 4,740.8 126.4 2020 1,112.5 1,413.4 97.2 504.5 183.9 3,311.5 71.3 283.6 354.9 (2.6) 80.6 11.9 892.9 369.0 5,018.2 130.6 2021 1,324.6 1,505.9 110.0 535.9 199.4 3,675.8 64.1 342.6 406.6 0.0 90.0 15.2 1,006.9 384.6 5,579.2 141.9 2022 1,462.8 1,629.4 123.0 560.3 204.0 3,979.5 51.5 319.6 371.1 0.0 106.6 14.5 1,078.7 399.1 5,949.5 147.9 2023 1,428.4 1,673.4 126.7 578.6 198.7 4,005.8 51.2 452.7 503.9 0.0 103.7 18.5 1,149.6 413.7 6,195.3 150.5 2024 1,429.1 1,790.8 135.9 590.4 193.8 4,140.0 55.3 457.7 512.9 0.0 110.4 17.8 1,259.8 428.6 6,469.5 153.7 2025 1,467.9 1,827.0 139.5 606.3 191.0 4,231.7 54.0 608.0 662.0 0.0 117.0 24.5 1,317.7 446.7 6,799.6 158.0 2026 1,514.2 1,962.1 149.7 623.3 186.7 4,436.0 53.1 612.8 665.9 0.0 123.0 23.5 1,444.2 387.7 7,080.4 160.4 2027 1,630.1 2,074.1 165.6 644.2 203.7 4,717.7 13.8 630.1 643.9 0.0 132.6 22.4 1,589.8 377.6 7,484.0 165.4 2028 1,715.9 2,204.6 181.3 668.9 209.4 4,980.2 51.7 639.7 691.4 0.0 143.8 21.3 1,742.2 370.1 7,949.0 171.5 2029 1,766.8 2,376.3 195.9 691.2 203.4 5,233.6 59.8 644.5 704.3 0.0 159.8 20.1 1,909.1 358.7 8,385.5 176.0 2030 1,846.9 2,545.2 211.6 715.2 198.0 5,517.0 58.4 642.2 700.6 0.0 171.3 18.8 2,072.2 344.2 8,824.1 180.7 2031 1,914.6 2,651.5 221.7 739.8 218.0 5,745.7 47.0 770.7 817.7 0.0 182.0 25.4 2,188.6 327.1 9,286.4 185.6 2032 1,959.8 2,843.3 239.3 765.9 224.8 6,033.1 53.2 861.5 914.7 0.0 196.7 28.9 2,279.8 306.7 9,759.9 190.8 2033 2,037.3 2,996.8 253.6 792.0 218.5 6,298.3 43.7 897.2 940.8 0.0 207.8 29.2 2,414.6 283.1 10,173.7 194.0 2034 2,125.3 3,199.1 275.8 820.0 239.9 6,660.1 49.1 938.9 988.0 0.0 233.3 29.5 2,535.0 254.9 10,700.7 199.5 2035 2,205.0 3,345.3 289.2 848.1 246.5 6,934.1 39.0 979.9 1,019.0 0.0 244.5 29.8 2,670.6 222.4 11,120.4 202.8 2036 2,273.1 3,528.4 306.1 881.5 241.6 7,230.8 59.8 1,026.0 1,085.8 0.0 259.0 30.1 2,799.0 184.9 11,589.6 207.2 2037 2,322.5 3,708.1 324.5 890.4 236.7 7,482.2 64.3 1,070.9 1,135.2 0.0 274.2 30.3 2,920.6 142.0 11,984.7 210.2
CPW@ 7.86% (2008-2017) 4,089.6 5,044.7 295.3 2,887.4 311.2 12,628.1 713.6 2,582.0 3,295.6 (122.8) 305.7 150.3 1,799.2 1,729.1 19,785.3 89.9
(2008-2027) 8,175.3 9,993.7 658.8 4,622.3 908.0 24,358.1 946.7 3,923.4 4,870.2 (142.6) 611.6 204.2 5,211.5 2,951.1 38,064.0 109.6
(2008-2037) 11,110.5 14,213.5 1,015.8 5,760.5 1,236.1 33,336.5 1,025.0 5,134.2 6,159.2 (142.6) 906.5 242.2 8,593.7 3,389.1 52,484.6 124.0
APPENDIX 2 TABLE 63. TABLE 64. RISK ANALYSIS B - CARBON COST AT $50/TON ENERGY EFFICIENCY SCENARIO 4 (EE-4/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.3 40.2 404.2 8.6 1,719.3 74.5 273.1 347.6 (10.8) 38.6 13.9 (1.0) 302.2 2,409.9 74.9 2009 549.1 756.2 41.1 412.2 8.6 1,767.3 77.4 297.7 375.1 (8.3) 41.5 14.7 (1.2) 407.3 2,596.4 81.3 2010 573.3 683.7 39.6 422.9 9.5 1,728.9 115.6 322.3 437.9 (9.1) 39.4 24.8 (9.5) 406.2 2,618.7 83.4 2011 580.5 687.9 39.2 419.9 9.5 1,737.0 102.8 288.1 390.8 (10.0) 40.3 29.2 (10.0) 419.5 2,596.8 83.4 2012 578.7 598.3 35.3 423.8 21.6 1,657.7 105.1 425.7 530.8 (14.0) 38.0 28.2 433.4 448.3 3,122.6 100.4 2013 583.5 602.3 36.4 429.0 48.8 1,700.1 105.7 454.8 560.5 (19.0) 39.3 28.2 443.1 417.5 3,169.8 102.2 2014 597.5 695.8 42.9 446.3 68.8 1,851.3 106.1 431.2 537.3 (24.3) 45.5 25.8 472.8 430.9 3,339.2 105.5 2015 629.5 724.3 44.2 462.7 66.9 1,927.6 106.5 482.0 588.5 (33.0) 47.6 23.1 516.9 446.3 3,517.1 108.3 2016 718.4 764.0 48.1 435.1 91.9 2,057.4 135.8 513.2 648.9 (37.0) 52.8 20.2 558.2 493.8 3,794.4 113.7 2017 811.0 953.9 60.7 449.0 106.8 2,381.4 160.8 409.7 570.5 (39.2) 56.9 17.2 624.4 513.1 4,124.4 120.2 2018 896.3 1,069.3 70.8 465.9 145.5 2,647.8 132.9 347.0 479.8 (38.4) 61.8 15.0 704.1 535.3 4,405.4 125.2 2019 926.2 1,115.3 74.7 480.3 180.6 2,777.1 131.4 385.3 516.7 (5.2) 69.4 14.3 777.8 555.6 4,705.7 130.6 2020 1,053.9 1,303.3 89.7 501.2 192.0 3,140.2 66.7 279.8 346.5 (2.6) 72.0 11.9 837.1 576.8 4,981.9 135.2 2021 1,253.6 1,388.8 101.8 531.9 190.3 3,466.4 66.0 340.0 405.9 0.0 80.8 15.2 948.3 600.1 5,516.9 146.4 2022 1,384.2 1,500.6 113.2 555.7 186.1 3,739.8 56.7 319.6 376.3 0.0 96.2 14.5 1,016.3 620.9 5,864.1 152.2 2023 1,353.1 1,537.5 116.1 573.9 181.2 3,761.8 53.1 452.5 505.5 0.0 93.7 18.5 1,082.8 641.0 6,103.3 155.0 2024 1,356.9 1,646.8 124.6 585.6 195.7 3,909.6 54.0 456.8 510.8 0.0 99.1 17.8 1,188.0 661.6 6,386.9 158.7 2025 1,395.9 1,672.6 127.5 601.0 201.7 3,998.7 56.6 606.9 663.4 0.0 104.9 24.5 1,241.3 688.4 6,721.2 163.5 2026 1,446.3 1,799.2 137.4 618.0 197.7 4,198.7 50.1 612.1 662.2 0.0 110.1 23.5 1,362.7 635.1 6,992.4 165.9 2027 1,481.0 1,926.2 147.7 633.3 213.8 4,401.9 61.3 633.2 694.5 0.0 121.7 22.4 1,515.9 616.3 7,372.7 170.7 2028 1,548.2 2,056.1 158.6 655.2 218.8 4,636.9 53.7 640.8 694.6 0.0 133.1 21.3 1,670.7 597.2 7,753.8 175.2 2029 1,631.4 2,222.9 172.5 678.1 213.6 4,918.5 58.9 644.7 703.7 0.0 148.0 20.1 1,833.6 576.4 8,200.3 180.3 2030 1,716.6 2,384.0 186.5 701.7 208.4 5,197.1 54.4 643.2 697.6 0.0 159.0 18.8 1,993.0 550.3 8,615.9 184.8 2031 1,789.1 2,481.4 195.7 725.8 227.9 5,420.0 40.0 771.1 811.0 0.0 169.2 25.4 2,105.3 519.3 9,050.3 189.5 2032 1,838.8 2,665.4 211.2 751.5 234.5 5,701.4 43.0 861.6 904.6 0.0 182.9 28.9 2,191.6 482.5 9,491.8 194.4 2033 1,916.4 2,809.5 224.2 776.8 229.1 5,956.1 45.0 897.2 942.2 0.0 192.4 29.2 2,323.4 439.3 9,882.7 197.4 2034 2,009.5 3,009.8 244.4 804.5 249.7 6,318.0 32.0 938.4 970.4 0.0 218.4 29.5 2,442.4 388.3 10,367.0 202.5 2035 2,091.7 3,143.5 256.7 832.0 254.4 6,578.3 34.5 979.3 1,013.7 0.0 228.8 29.8 2,569.5 329.3 10,749.5 205.4 2036 2,160.8 3,314.4 272.5 864.7 248.6 6,861.0 36.4 1,025.1 1,061.5 0.0 241.9 30.1 2,692.5 261.1 11,148.1 208.8 2037 2,193.4 3,483.7 288.5 872.5 243.1 7,081.3 67.1 1,071.2 1,138.3 0.0 255.9 30.3 2,808.7 182.7 11,497.4 211.3
CPW@ 7.86% (2008-2017) 4,050.3 4,823.2 282.6 2,885.7 249.5 12,291.3 707.5 2,528.4 3,236.0 (122.8) 289.9 150.3 1,697.6 2,824.4 20,366.6 94.4
(2008-2027) 7,893.2 9,383.1 615.7 4,605.8 837.0 23,334.9 955.0 3,861.5 4,816.5 (142.6) 565.8 204.2 4,912.9 4,741.6 38,433.3 113.8
(2008-2037) 10,635.6 13,338.7 931.2 5,722.1 1,179.0 31,806.7 1,025.3 5,072.6 6,097.9 (142.6) 840.2 242.2 8,165.1 5,425.9 52,435.5 127.8
APPENDIX 2 TABLE 64. TABLE 65. RISK ANALYSIS B - CARBON COST AT $50/TON DEFAULT SUPPLY SIDE SCENARIO (SS-D/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 597.5 865.6 52.3 446.3 66.1 2,027.9 116.3 466.2 582.5 (24.3) 56.6 24.8 566.1 54.9 3,288.4 93.8 2015 629.5 899.8 54.6 462.7 89.7 2,136.3 153.0 529.2 682.2 (33.0) 60.3 22.1 617.9 58.3 3,544.0 97.7 2016 830.9 991.0 63.1 439.7 138.4 2,463.0 165.0 551.2 716.2 (37.0) 69.2 19.2 685.4 93.4 4,009.4 106.8 2017 1,021.9 1,223.2 79.9 457.9 176.0 2,958.9 159.6 438.7 598.3 (39.2) 77.1 16.1 766.8 100.0 4,478.0 115.4 2018 1,139.3 1,401.4 94.8 476.5 185.3 3,297.3 123.1 373.0 496.1 (38.4) 87.4 13.8 877.9 107.3 4,841.4 121.1 2019 1,176.3 1,430.0 97.3 491.8 181.0 3,376.5 125.2 416.2 541.3 (5.2) 91.0 13.2 940.2 114.3 5,071.4 123.3 2020 1,331.8 1,669.3 120.4 516.2 193.5 3,831.2 68.3 293.2 361.5 (2.6) 99.2 10.8 1,013.0 121.1 5,434.0 128.7 2021 1,562.5 1,742.4 135.6 550.2 200.1 4,190.8 63.1 398.9 462.0 0.0 105.9 16.4 1,114.8 127.8 6,017.8 138.9 2022 1,704.7 1,898.3 152.3 575.4 196.1 4,526.7 52.2 374.3 426.5 0.0 124.0 15.6 1,205.5 134.8 6,433.1 144.8 2023 1,685.9 1,941.1 155.5 595.0 191.6 4,569.1 46.4 598.6 645.0 0.0 121.4 19.6 1,274.2 142.6 6,771.9 148.7 2024 1,701.1 2,068.4 166.3 608.2 205.5 4,749.5 46.7 599.3 646.0 0.0 127.8 18.8 1,389.6 150.3 7,082.0 151.9 2025 1,769.1 2,142.4 173.7 625.9 210.9 4,922.0 47.3 818.1 865.3 0.0 140.3 25.5 1,471.3 158.2 7,582.7 158.8 2026 1,824.7 2,305.2 186.7 644.3 205.5 5,166.4 51.5 820.7 872.1 0.0 150.0 24.4 1,610.7 92.2 7,915.8 161.6 2027 1,927.7 2,427.0 204.5 665.8 200.8 5,425.8 22.1 835.6 857.7 0.0 158.5 24.2 1,761.4 92.2 8,319.8 165.6 2028 2,034.7 2,592.0 224.4 692.3 216.8 5,760.1 38.3 840.2 878.5 0.0 174.1 23.0 1,927.3 98.1 8,861.2 172.1 2029 2,095.7 2,781.9 241.1 716.1 222.0 6,056.8 53.9 839.5 893.4 0.0 191.6 21.8 2,104.6 98.0 9,366.1 177.0 2030 2,237.1 2,940.0 263.4 746.2 253.9 6,440.5 17.5 831.6 849.0 0.0 201.0 20.5 2,261.7 97.3 9,870.1 181.9 2031 2,342.7 3,110.9 283.9 775.5 267.1 6,780.1 36.0 832.9 868.9 0.0 217.6 19.2 2,410.4 96.8 10,393.0 187.0 2032 2,389.4 3,336.8 306.5 803.2 284.4 7,120.4 54.0 837.6 891.6 0.0 234.8 17.8 2,512.0 96.2 10,872.8 191.3 2033 2,481.4 3,529.2 325.8 831.2 289.2 7,456.9 44.3 869.9 914.2 0.0 247.3 17.9 2,663.1 95.9 11,395.3 195.6 2034 2,565.6 3,673.7 345.1 860.8 281.9 7,727.1 34.4 1,098.4 1,132.8 0.0 267.5 27.9 2,756.7 95.1 12,007.0 201.5 2035 2,624.0 3,866.8 363.0 889.7 273.0 8,016.6 49.1 1,141.6 1,190.6 0.0 283.4 28.1 2,918.8 94.4 12,532.0 205.7 2036 2,695.6 4,047.2 380.9 925.1 294.4 8,343.2 13.8 1,189.6 1,203.4 0.0 299.7 28.3 3,047.1 93.8 13,015.4 209.4 2037 2,743.5 4,296.8 409.6 935.9 300.5 8,686.4 78.1 1,234.7 1,312.8 0.0 325.2 28.5 3,204.7 93.3 13,650.8 214.6
CPW@ 7.86% (2008-2017) 4,206.2 5,601.6 327.4 2,892.2 345.9 13,373.2 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 2,035.6 415.1 19,602.9 84.8
(2008-2027) 9,048.0 11,407.9 775.0 4,672.1 965.3 26,868.4 975.4 4,301.3 5,276.7 (142.6) 704.8 196.7 5,861.0 807.6 39,572.5 106.5
(2008-2037) 12,573.7 16,319.5 1,223.9 5,862.1 1,356.1 37,335.3 1,036.7 5,701.1 6,737.8 (142.6) 1,053.1 230.5 9,572.7 950.7 55,737.6 122.3
APPENDIX 2 TABLE 65. TABLE 66. RISK ANALYSIS B - CARBON COST AT $50/TON NUCLEAR SUPPLY SIDE SCENARIO (SS-N/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 600.3 865.6 52.3 446.3 66.1 2,030.7 116.3 466.2 582.5 (24.3) 56.6 24.8 566.1 54.9 3,291.2 93.9 2015 637.1 899.8 54.6 462.7 89.7 2,143.9 153.0 529.2 682.2 (33.0) 60.3 22.1 617.9 58.3 3,551.7 97.9 2016 864.3 991.0 63.1 439.7 138.4 2,496.4 165.0 551.2 716.2 (37.0) 69.2 19.2 685.4 93.4 4,042.8 107.7 2017 1,104.5 1,223.2 79.9 457.9 176.0 3,041.5 159.6 438.7 598.3 (39.2) 77.1 16.1 766.8 100.0 4,560.6 117.6 2018 1,285.6 1,401.4 94.8 476.5 185.3 3,443.6 123.1 373.0 496.1 (38.4) 87.4 13.8 877.9 107.3 4,987.7 124.7 2019 1,401.2 1,430.0 97.3 491.8 181.0 3,601.4 125.2 416.2 541.3 (5.2) 91.0 13.2 940.2 114.3 5,296.3 128.7 2020 1,647.9 1,669.3 120.4 516.2 193.5 4,147.3 68.3 293.2 361.5 (2.6) 99.2 10.8 1,013.0 121.1 5,750.1 136.1 2021 1,941.9 1,761.2 132.0 547.7 232.0 4,614.8 59.4 400.9 460.3 0.0 108.1 16.4 1,124.4 127.8 6,451.8 148.9 2022 2,197.7 1,825.3 137.5 581.9 243.2 4,985.6 52.6 374.4 426.9 0.0 118.7 15.6 1,165.3 134.8 6,846.9 154.1 2023 2,188.7 1,703.2 128.0 622.9 236.2 4,879.1 27.0 598.6 625.7 0.0 104.7 19.6 1,139.0 142.6 6,910.7 151.8 2024 2,071.2 1,771.2 134.0 645.2 247.5 4,869.2 32.8 599.3 632.1 0.0 105.6 18.8 1,214.2 150.3 6,990.2 149.9 2025 2,108.9 1,822.5 138.3 663.2 252.1 4,984.9 48.2 818.1 866.4 0.0 115.9 25.5 1,278.6 158.2 7,429.5 155.6 2026 2,156.1 1,984.7 151.3 682.6 245.8 5,220.6 52.4 820.7 873.1 0.0 123.9 24.4 1,424.2 92.2 7,758.4 158.4 2027 2,252.8 2,122.2 167.6 705.3 239.8 5,487.7 23.0 835.6 858.5 0.0 133.6 24.2 1,580.1 92.2 8,176.4 162.7 2028 2,335.9 2,253.8 182.7 732.3 233.8 5,738.5 59.5 840.2 899.7 0.0 146.0 23.0 1,723.9 98.1 8,629.2 167.6 2029 2,393.6 2,444.6 199.7 757.5 227.7 6,023.1 53.3 839.4 892.7 0.0 163.5 21.8 1,906.4 98.0 9,105.5 172.1 2030 2,534.2 2,588.3 218.9 789.4 244.4 6,375.1 17.0 831.6 848.6 0.0 172.4 20.5 2,053.7 97.3 9,567.6 176.4 2031 2,604.0 2,740.6 236.8 819.2 249.1 6,649.8 57.8 832.9 890.7 0.0 185.3 19.2 2,193.4 96.8 10,035.2 180.5 2032 2,643.2 2,977.1 257.9 848.4 243.4 6,969.9 52.1 837.6 889.7 0.0 203.2 17.8 2,301.1 96.2 10,477.9 184.4 2033 2,735.5 3,139.1 273.6 878.4 262.4 7,288.9 42.6 869.9 912.5 0.0 212.9 17.9 2,437.9 95.9 10,966.0 188.2 2034 2,804.2 3,289.2 291.9 909.4 267.0 7,561.7 32.7 1,098.4 1,131.2 0.0 235.0 27.9 2,536.3 95.1 11,587.1 194.4 2035 2,847.3 3,488.3 310.1 939.8 257.8 7,843.2 47.6 1,141.6 1,189.1 0.0 251.3 28.1 2,697.7 94.4 12,103.9 198.7 2036 2,904.6 3,651.4 325.3 976.6 280.5 8,138.4 12.4 1,189.6 1,202.0 0.0 265.5 28.3 2,813.9 93.8 12,541.8 201.7 2037 2,942.3 3,880.8 349.5 989.0 287.2 8,448.8 76.7 1,234.7 1,311.4 0.0 289.0 28.5 2,959.6 93.3 13,130.5 206.5
CPW@ 7.86% (2008-2017) 4,267.7 5,601.6 327.4 2,892.2 345.9 13,434.7 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 2,035.6 415.1 19,664.4 85.1
(2008-2027) 10,161.6 11,012.8 726.4 4,719.3 1,045.1 27,665.1 965.3 4,302.0 5,267.3 (142.6) 674.8 196.7 5,629.0 807.6 40,097.9 107.9
(2008-2037) 14,075.3 15,378.1 1,103.1 5,976.8 1,419.4 37,952.7 1,033.0 5,701.8 6,734.9 (142.6) 976.6 230.5 9,020.1 950.7 55,722.9 122.2
APPENDIX 2 TABLE 66. TABLE 67. RISK ANALYSIS B - CARBON COST AT $50/TON SOALR SUPPLY SIDE SCENARIO 1 (SS-S1/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 597.5 828.1 50.6 446.3 66.1 1,988.5 106.2 582.0 688.2 (24.3) 53.9 30.0 546.2 54.9 3,337.3 95.2 2015 629.5 830.0 50.5 462.7 89.7 2,062.4 112.3 759.3 871.6 (33.0) 54.7 32.6 576.1 58.3 3,622.7 99.8 2016 755.9 877.6 55.5 436.7 123.4 2,249.0 141.7 910.8 1,052.6 (37.0) 60.7 35.1 621.1 93.4 4,074.7 108.6 2017 871.2 1,053.4 67.6 451.5 153.3 2,597.0 158.1 936.1 1,094.2 (39.2) 64.2 37.5 676.9 100.0 4,530.6 116.8 2018 936.7 1,174.3 78.2 467.5 162.7 2,819.3 128.7 1,010.0 1,138.6 (38.4) 70.4 40.8 762.2 107.3 4,900.3 122.6 2019 940.0 1,157.9 77.2 480.9 158.1 2,814.0 125.5 1,193.8 1,319.3 (5.2) 70.6 45.8 793.9 114.3 5,152.8 125.3 2020 1,038.2 1,333.0 90.5 500.3 171.4 3,133.4 66.2 1,240.8 1,307.0 (2.6) 75.4 49.2 849.0 121.1 5,532.3 131.0 2021 1,210.1 1,427.8 98.2 527.7 195.2 3,459.0 70.2 1,347.3 1,417.5 0.0 85.5 54.2 961.6 127.8 6,105.6 140.9 2022 1,343.7 1,580.2 108.6 549.9 200.0 3,782.3 63.1 1,327.3 1,390.4 0.0 103.7 52.8 1,056.6 134.8 6,520.7 146.7 2023 1,337.6 1,618.9 112.6 568.7 194.7 3,832.5 57.0 1,551.6 1,608.6 0.0 100.7 56.1 1,116.8 142.6 6,857.3 150.6 2024 1,365.3 1,738.2 121.5 581.1 189.9 3,996.0 57.0 1,554.0 1,611.0 0.0 105.6 54.6 1,229.3 150.3 7,146.8 153.2 2025 1,445.7 1,808.6 127.6 598.0 206.7 4,186.7 57.3 1,771.2 1,828.4 0.0 118.7 60.6 1,307.7 158.2 7,660.2 160.4 2026 1,531.0 1,961.2 139.0 616.2 211.3 4,458.7 50.0 1,773.6 1,823.6 0.0 127.6 58.7 1,445.2 92.2 8,006.1 163.4 2027 1,604.0 2,108.2 151.4 633.0 206.7 4,703.2 45.1 1,788.5 1,833.6 0.0 137.9 57.7 1,607.0 92.2 8,431.6 167.8 2028 1,685.0 2,288.6 165.9 655.3 223.0 5,017.8 60.5 1,794.9 1,855.4 0.0 156.1 55.6 1,780.7 98.1 8,963.6 174.1 2029 1,778.4 2,467.6 180.7 678.7 227.2 5,332.8 54.2 1,792.4 1,846.6 0.0 173.0 53.4 1,952.3 98.0 9,456.1 178.7 2030 1,946.1 2,612.8 200.1 708.2 221.3 5,688.5 17.3 1,784.5 1,801.9 0.0 181.4 51.1 2,101.9 97.3 9,922.1 182.9 2031 2,063.4 2,773.4 219.7 736.4 255.1 6,047.9 35.4 1,785.9 1,821.3 0.0 196.6 48.8 2,242.9 96.8 10,454.2 188.1 2032 2,120.6 3,001.2 238.8 762.9 292.5 6,416.0 53.4 1,792.4 1,845.8 0.0 214.6 46.2 2,345.8 96.2 10,964.6 192.9 2033 2,222.0 3,191.2 256.0 789.7 297.3 6,756.2 43.8 1,822.9 1,866.7 0.0 225.3 45.1 2,494.3 95.9 11,483.5 197.1 2034 2,314.7 3,351.1 273.3 818.1 289.9 7,047.0 33.9 2,051.4 2,085.3 0.0 246.9 53.8 2,595.7 95.1 12,123.8 203.4 2035 2,381.5 3,524.3 289.7 845.7 307.6 7,348.8 48.5 2,094.5 2,143.0 0.0 263.3 52.7 2,746.4 94.4 12,648.6 207.6 2036 2,462.9 3,698.7 305.5 879.7 313.6 7,660.3 13.2 2,144.3 2,157.5 0.0 277.6 51.4 2,869.0 93.8 13,109.6 210.9 2037 2,521.9 3,960.2 331.3 889.2 306.5 8,009.1 77.6 2,187.6 2,265.2 0.0 305.2 50.1 3,033.6 93.3 13,756.6 216.3
CPW@ 7.86% (2008-2017) 4,097.5 5,404.3 314.5 2,887.7 327.6 13,031.6 710.6 3,279.5 3,990.1 (122.8) 323.4 168.8 1,926.2 415.1 19,732.4 85.4
(2008-2027) 7,987.2 10,240.2 648.6 4,600.9 917.4 24,394.4 955.8 7,719.2 8,675.0 (142.6) 624.0 333.2 5,273.5 807.6 39,965.1 107.6
(2008-2037) 11,097.6 14,663.4 997.9 5,730.6 1,313.2 33,802.8 1,021.1 10,537.1 11,558.2 (142.6) 942.5 409.1 8,743.3 950.7 56,264.0 123.4
APPENDIX 2 TABLE 67. TABLE 68. RISK ANALYSIS B - CARBON COST AT $50/TON SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 597.5 833.0 50.4 446.3 66.1 1,993.3 106.2 572.0 678.1 (24.3) 54.3 29.8 545.4 54.9 3,331.4 95.0 2015 629.5 837.6 50.4 462.7 89.7 2,069.9 116.6 738.9 855.6 (33.0) 55.4 32.2 575.4 58.3 3,613.8 99.6 2016 780.9 906.8 57.0 437.7 137.8 2,320.2 143.2 817.0 960.2 (37.0) 62.5 31.6 631.3 93.4 4,062.2 108.2 2017 899.9 1,067.6 67.8 452.7 160.2 2,648.3 157.5 893.4 1,050.9 (39.2) 65.5 36.7 678.0 100.0 4,540.2 117.0 2018 955.1 1,190.2 79.2 468.4 161.3 2,854.1 131.6 955.9 1,087.4 (38.4) 72.0 39.8 764.7 107.3 4,887.0 122.2 2019 957.6 1,179.2 78.4 481.8 172.6 2,869.7 132.3 1,126.2 1,258.5 (5.2) 72.6 44.6 796.6 114.3 5,151.1 125.2 2020 1,069.4 1,361.0 92.0 501.9 177.6 3,201.9 67.5 1,156.4 1,223.9 (2.6) 77.6 47.6 853.8 121.1 5,523.4 130.8 2021 1,250.1 1,443.7 98.6 529.7 193.1 3,515.2 61.7 1,302.8 1,364.5 0.0 86.5 54.6 958.6 127.8 6,107.3 140.9 2022 1,382.1 1,594.2 109.7 551.9 198.3 3,836.2 51.6 1,285.6 1,337.2 0.0 104.8 53.2 1,053.0 134.8 6,519.2 146.7 2023 1,358.7 1,633.4 113.0 570.3 222.3 3,897.6 56.1 1,509.7 1,565.8 0.0 101.9 56.5 1,114.7 142.6 6,879.2 151.1 2024 1,390.6 1,754.4 122.1 582.8 232.2 4,082.1 52.6 1,512.4 1,565.0 0.0 106.7 55.1 1,226.1 150.3 7,185.2 154.1 2025 1,464.6 1,824.2 128.6 599.6 246.9 4,263.9 56.7 1,729.4 1,786.0 0.0 120.0 61.0 1,304.9 158.2 7,694.2 161.2 2026 1,537.2 1,978.0 140.5 617.4 250.6 4,523.7 56.8 1,731.7 1,788.5 0.0 128.7 59.2 1,442.5 92.2 8,034.7 164.0 2027 1,663.7 2,093.2 156.6 638.6 244.6 4,796.6 19.7 1,746.6 1,766.2 0.0 136.5 58.1 1,587.5 92.2 8,437.2 167.9 2028 1,762.6 2,247.9 175.4 663.6 237.6 5,087.1 56.5 1,753.2 1,809.6 0.0 151.2 56.1 1,750.5 98.1 8,952.6 173.8 2029 1,840.8 2,432.5 190.7 686.8 231.9 5,382.7 50.3 1,750.6 1,800.9 0.0 169.5 53.9 1,922.8 98.0 9,427.8 178.2 2030 2,006.8 2,580.8 210.0 716.5 286.4 5,800.4 13.6 1,742.6 1,756.2 0.0 176.8 51.6 2,073.5 97.3 9,955.8 183.5 2031 2,102.0 2,740.8 229.4 744.1 309.1 6,125.4 54.2 1,743.9 1,798.1 0.0 192.0 49.2 2,215.5 96.8 10,477.0 188.5 2032 2,165.3 2,964.3 248.5 771.1 300.8 6,450.0 48.5 1,750.9 1,799.4 0.0 210.2 46.7 2,315.5 96.2 10,918.0 192.1 2033 2,280.7 3,149.9 265.1 798.8 317.7 6,812.1 39.1 1,780.9 1,820.1 0.0 220.9 45.6 2,464.8 95.9 11,459.4 196.7 2034 2,349.3 3,296.0 281.9 826.5 321.9 7,075.7 53.8 2,009.4 2,063.2 0.0 240.5 54.3 2,557.9 95.1 12,086.8 202.8 2035 2,423.1 3,479.4 298.5 854.7 311.9 7,367.5 42.6 2,052.5 2,095.2 0.0 256.0 53.2 2,713.2 94.4 12,579.5 206.5 2036 2,520.4 3,642.1 315.0 889.6 332.0 7,699.1 31.6 2,102.6 2,134.2 0.0 269.8 52.0 2,831.0 93.8 13,079.9 210.4 2037 2,578.3 3,896.3 340.4 899.4 337.8 8,052.2 95.2 2,145.7 2,240.9 0.0 297.7 50.6 2,995.0 93.3 13,729.8 215.9
CPW@ 7.86% (2008-2017) 4,123.6 5,432.9 315.2 2,888.8 338.2 13,098.6 713.4 3,194.9 3,908.3 (122.8) 325.6 166.3 1,931.1 415.1 19,722.2 85.4
(2008-2027) 8,099.1 10,318.2 653.3 4,607.6 982.2 24,660.5 950.9 7,469.5 8,420.4 (142.6) 630.1 330.0 5,273.0 807.6 39,979.1 107.6
(2008-2037) 11,290.7 14,678.7 1,016.7 5,750.1 1,416.1 34,152.4 1,021.4 10,225.2 11,246.6 (142.6) 940.8 406.7 8,695.9 950.7 56,250.4 123.4
APPENDIX 2 TABLE 68. TABLE 69. RISK ANALYSIS B - CARBON COST AT $50/TON SUPPLY SIDE SCENARIO 1 (SS-1/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 599.7 847.3 51.3 446.3 66.1 2,010.8 107.9 524.0 631.9 (24.3) 55.3 27.4 556.0 54.9 3,311.9 94.5 2015 635.5 865.0 52.4 462.7 89.7 2,105.3 130.6 643.6 774.2 (33.0) 57.4 27.4 597.1 58.3 3,586.7 98.8 2016 819.9 934.6 59.4 438.2 137.8 2,389.9 154.6 725.4 880.0 (37.0) 64.7 26.8 654.3 93.4 4,072.0 108.5 2017 1,025.0 1,159.4 75.5 455.2 160.8 2,875.9 161.2 616.9 778.1 (39.2) 72.4 23.7 734.1 100.0 4,545.0 117.2 2018 1,195.6 1,332.5 89.9 473.7 177.6 3,269.3 124.7 552.8 677.5 (38.4) 81.9 21.3 843.9 107.3 4,962.9 124.1 2019 1,297.4 1,359.1 92.1 489.0 181.5 3,419.2 126.7 596.8 723.5 (5.2) 85.5 20.6 905.5 114.3 5,263.4 127.9 2020 1,527.6 1,592.1 114.7 513.3 194.0 3,941.7 69.7 477.1 546.8 (2.6) 93.3 18.0 976.7 121.1 5,694.9 134.8 2021 1,793.0 1,685.4 126.0 544.1 225.3 4,373.8 70.5 584.5 655.0 0.0 102.3 23.5 1,088.0 127.8 6,370.3 147.0 2022 2,033.2 1,765.7 132.9 576.2 233.5 4,741.6 56.8 559.9 616.7 0.0 114.5 22.6 1,138.8 134.8 6,768.9 152.3 2023 2,033.9 1,676.6 126.0 613.1 227.2 4,676.8 29.4 784.3 813.6 0.0 102.9 26.4 1,131.9 142.6 6,894.2 151.4 2024 1,936.9 1,755.8 132.4 633.0 221.4 4,679.6 39.9 785.3 825.2 0.0 104.7 25.5 1,213.5 150.3 6,998.7 150.1 2025 1,978.4 1,810.2 137.1 650.6 236.4 4,812.7 55.2 1,003.8 1,058.9 0.0 115.5 32.0 1,280.8 158.2 7,458.2 156.2 2026 2,047.3 1,971.2 149.8 670.3 240.5 5,079.1 48.0 1,006.3 1,054.2 0.0 123.4 30.7 1,424.1 92.2 7,803.8 159.3 2027 2,159.4 2,102.5 166.1 693.1 234.7 5,355.8 11.1 1,021.2 1,032.2 0.0 132.7 30.4 1,579.3 92.2 8,222.6 163.6 2028 2,245.0 2,239.5 182.0 719.8 228.0 5,614.2 48.1 1,026.2 1,074.3 0.0 145.6 29.0 1,726.8 98.1 8,688.0 168.7 2029 2,306.2 2,427.7 198.4 744.6 222.6 5,899.5 42.2 1,025.0 1,067.2 0.0 162.9 27.6 1,905.8 98.0 9,160.9 173.1 2030 2,451.3 2,601.8 213.7 776.1 239.9 6,282.7 6.0 1,017.2 1,023.3 0.0 174.9 26.1 2,068.0 97.3 9,672.2 178.3 2031 2,525.6 2,763.6 228.9 805.5 283.4 6,607.1 47.1 1,018.5 1,065.6 0.0 190.0 24.5 2,213.5 96.8 10,197.4 183.4 2032 2,568.5 2,998.5 249.2 834.3 295.3 6,945.9 41.7 1,024.3 1,066.0 0.0 207.5 22.8 2,323.4 96.2 10,661.8 187.6 2033 2,642.6 3,167.5 265.2 863.1 312.4 7,250.8 56.2 1,055.5 1,111.7 0.0 217.5 22.7 2,461.7 95.9 11,160.4 191.6 2034 2,700.5 3,325.0 283.3 893.0 316.7 7,518.5 45.8 1,284.1 1,329.9 0.0 240.6 32.4 2,561.9 95.1 11,778.3 197.6 2035 2,748.7 3,518.5 301.5 922.9 307.8 7,799.4 60.1 1,327.2 1,387.3 0.0 256.7 32.3 2,721.6 94.4 12,291.7 201.7 2036 2,810.9 3,683.0 316.5 959.2 328.5 8,098.1 24.6 1,375.7 1,400.2 0.0 271.3 32.2 2,838.6 93.8 12,734.2 204.8 2037 2,877.7 3,923.8 340.9 972.0 333.2 8,447.6 14.1 1,420.3 1,434.5 0.0 295.4 32.0 2,990.2 93.3 13,293.0 209.0
CPW@ 7.86% (2008-2017) 4,206.7 5,513.4 321.6 2,890.2 338.5 13,270.3 729.6 2,938.5 3,668.1 (122.8) 331.6 153.7 1,987.1 415.1 19,703.2 85.3
(2008-2027) 9,707.0 10,768.8 708.7 4,695.6 1,013.0 26,893.0 951.5 5,152.7 6,104.2 (142.6) 656.6 230.6 5,515.0 807.6 40,064.4 107.8
(2008-2037) 13,491.6 15,157.6 1,076.3 5,931.5 1,427.3 37,084.3 1,009.5 6,828.9 7,838.4 (142.6) 963.4 271.8 8,931.2 950.7 55,897.2 122.6
APPENDIX 2 TABLE 69. TABLE 70. RISK ANALYSIS B - CARBON COST AT $50/TON SUPPLY SIDE SCENARIO 2 (SS-2/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 600.4 837.3 50.8 446.3 66.1 2,000.9 106.2 556.1 662.3 (24.3) 54.7 29.0 549.2 54.9 3,326.6 94.9 2015 637.3 846.7 51.1 462.7 89.7 2,087.5 120.9 707.6 828.5 (33.0) 56.0 30.6 582.2 58.3 3,610.1 99.5 2016 802.8 902.3 56.8 437.2 137.8 2,336.8 152.0 830.5 982.5 (37.0) 62.0 32.0 631.8 93.4 4,101.4 109.3 2017 1,003.1 1,110.7 71.1 453.4 160.2 2,798.5 161.9 759.2 921.1 (39.2) 68.6 30.5 703.8 100.0 4,583.2 118.2 2018 1,177.2 1,267.3 84.5 471.3 161.9 3,162.3 126.7 730.0 856.7 (38.4) 77.4 29.7 807.1 107.3 5,002.1 125.1 2019 1,304.3 1,294.3 86.8 486.7 174.2 3,346.4 122.6 773.5 896.1 (5.2) 80.8 28.8 866.2 114.3 5,327.4 129.5 2020 1,539.1 1,540.5 105.3 508.3 195.4 3,888.5 65.4 661.5 726.9 (2.6) 90.5 26.1 950.2 121.1 5,800.6 137.3 2021 1,834.3 1,616.6 117.3 539.8 234.2 4,342.1 64.3 766.0 830.3 0.0 98.1 31.5 1,053.5 127.8 6,483.3 149.6 2022 2,111.1 1,662.0 124.8 576.1 245.5 4,719.5 58.8 744.3 803.1 0.0 106.1 30.4 1,083.2 134.8 6,877.2 154.8 2023 2,108.6 1,541.5 115.5 617.7 238.5 4,621.8 31.2 968.6 999.9 0.0 93.8 34.1 1,050.4 142.6 6,942.5 152.5 2024 1,992.5 1,604.8 120.2 640.2 231.5 4,589.3 36.1 970.1 1,006.3 0.0 94.7 33.0 1,118.2 150.3 6,991.7 149.9 2025 2,034.1 1,650.4 124.0 658.0 227.8 4,694.3 51.5 1,188.1 1,239.7 0.0 103.9 39.3 1,181.0 158.2 7,416.4 155.3 2026 2,085.1 1,804.3 137.2 677.3 242.2 4,946.1 55.7 1,190.6 1,246.3 0.0 111.3 37.9 1,323.7 92.2 7,757.4 158.3 2027 2,131.6 1,965.4 149.2 695.3 245.5 5,186.9 58.2 1,205.5 1,263.7 0.0 123.3 37.3 1,492.3 92.2 8,195.7 163.1 2028 2,218.6 2,092.0 161.2 720.2 239.7 5,431.7 52.7 1,211.0 1,263.7 0.0 135.6 35.8 1,640.5 98.1 8,605.3 167.1 2029 2,307.2 2,284.8 176.2 746.2 233.9 5,748.2 46.7 1,209.3 1,256.1 0.0 153.4 34.1 1,822.5 98.0 9,112.3 172.2 2030 2,451.3 2,422.9 194.7 777.7 250.4 6,097.0 10.3 1,201.5 1,211.8 0.0 160.8 32.4 1,965.2 97.3 9,564.5 176.3 2031 2,524.4 2,571.9 211.9 807.1 255.0 6,370.4 51.1 1,202.9 1,254.0 0.0 174.1 30.6 2,101.9 96.8 10,027.7 180.4 2032 2,565.9 2,806.4 231.8 836.0 248.1 6,688.2 45.7 1,208.5 1,254.2 0.0 191.7 28.7 2,208.9 96.2 10,468.0 184.2 2033 2,660.2 2,964.5 246.0 865.6 267.6 7,004.0 36.5 1,239.9 1,276.3 0.0 200.2 28.3 2,345.0 95.9 10,949.6 187.9 2034 2,708.2 3,118.5 263.1 895.4 315.6 7,300.8 51.1 1,468.4 1,519.4 0.0 221.8 37.6 2,442.5 95.1 11,617.3 194.9 2035 2,762.1 3,309.4 281.3 925.6 326.5 7,604.9 40.0 1,511.5 1,551.5 0.0 238.4 37.3 2,600.9 94.4 12,127.3 199.0 2036 2,815.4 3,468.7 295.7 961.7 346.1 7,887.6 79.0 1,560.4 1,639.4 0.0 252.3 36.8 2,713.2 93.8 12,623.0 203.1 2037 2,863.9 3,691.5 317.6 973.9 351.5 8,198.4 18.5 1,604.6 1,623.1 0.0 274.9 36.3 2,857.4 93.3 13,083.3 205.7
CPW@ 7.86% (2008-2017) 4,189.1 5,458.3 317.2 2,888.8 338.2 13,191.6 722.3 3,112.3 3,834.6 (122.8) 327.4 162.2 1,949.4 415.1 19,757.4 85.5
(2008-2027) 9,782.6 10,389.8 674.0 4,696.3 1,017.1 26,559.9 951.0 5,903.7 6,854.7 (142.6) 629.9 263.8 5,286.5 807.6 40,259.9 108.4
(2008-2037) 13,565.6 14,501.7 1,012.0 5,934.9 1,425.7 36,439.9 1,014.9 7,854.1 8,869.0 (142.6) 914.1 313.7 8,541.8 950.7 55,886.6 122.6
APPENDIX 2 TABLE 70. TABLE 71. RISK ANALYSIS B - CARBON COST AT $50/TON SUPPLY SIDE SCENARIO 3 (SS-3/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 3,067.5 90.2 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 549.2 54.9 3,327.3 94.9 2015 639.1 855.8 51.6 462.7 89.7 2,098.9 125.2 678.0 803.3 (33.0) 56.8 29.2 587.5 58.3 3,601.0 99.2 2016 835.8 936.2 59.0 438.2 137.8 2,407.0 153.7 720.8 874.4 (37.0) 64.8 27.0 651.1 93.4 4,080.6 108.7 2017 1,064.4 1,160.4 75.1 455.2 160.8 2,915.9 164.4 611.0 775.4 (39.2) 72.4 23.8 732.4 100.0 4,580.7 118.1 2018 1,265.3 1,333.4 89.8 473.7 177.6 3,339.8 127.7 547.1 674.7 (38.4) 82.2 21.4 842.6 107.3 5,029.7 125.8 2019 1,404.5 1,361.8 92.1 489.0 181.5 3,528.9 129.6 589.9 719.5 (5.2) 85.9 20.7 903.1 114.3 5,367.2 130.5 2020 1,678.1 1,593.7 114.6 513.3 194.0 4,093.7 72.5 471.3 543.8 (2.6) 93.3 18.1 974.8 121.1 5,842.3 138.3 2021 1,995.4 1,686.5 126.1 544.6 240.9 4,593.5 63.5 578.2 641.8 0.0 102.4 23.6 1,086.1 127.8 6,575.2 151.7 2022 2,288.1 1,718.4 129.0 581.8 256.3 4,973.6 57.5 554.4 611.9 0.0 110.3 22.7 1,109.7 134.8 6,963.0 156.7 2023 2,288.8 1,557.1 116.6 628.8 249.0 4,840.3 23.2 778.6 801.9 0.0 94.6 26.5 1,054.8 142.6 6,960.6 152.9 2024 2,132.9 1,609.1 120.0 653.3 241.7 4,757.1 33.4 779.8 813.2 0.0 94.5 25.6 1,115.6 150.3 6,956.2 149.2 2025 2,159.1 1,650.8 124.0 671.0 255.7 4,860.5 56.1 998.1 1,054.2 0.0 103.3 32.1 1,173.9 158.2 7,382.2 154.6 2026 2,223.5 1,808.0 137.7 691.4 259.1 5,119.7 48.9 1,000.6 1,049.5 0.0 110.9 30.8 1,320.8 92.2 7,723.8 157.7 2027 2,332.2 1,949.5 153.1 714.8 252.8 5,402.5 11.9 1,015.5 1,027.5 0.0 120.9 30.4 1,477.6 92.2 8,151.1 162.2 2028 2,414.9 2,067.6 167.7 742.1 245.5 5,637.8 48.9 1,020.6 1,069.5 0.0 132.3 29.1 1,615.4 98.1 8,582.1 166.6 2029 2,471.1 2,257.6 183.8 767.6 239.5 5,919.6 43.0 1,019.4 1,062.4 0.0 148.7 27.6 1,797.2 98.0 9,053.5 171.1 2030 2,549.2 2,420.8 197.7 794.9 256.1 6,218.7 41.7 1,011.5 1,053.2 0.0 160.1 26.1 1,952.1 97.3 9,507.4 175.2 2031 2,595.6 2,574.3 211.6 822.2 260.4 6,464.0 59.0 1,012.9 1,071.9 0.0 172.8 24.5 2,093.1 96.8 9,923.0 178.5 2032 2,647.4 2,810.6 231.3 852.1 278.2 6,819.5 53.3 1,018.1 1,071.3 0.0 190.3 22.8 2,203.0 96.2 10,403.2 183.0 2033 2,737.1 2,965.2 245.5 882.2 283.5 7,113.3 43.8 1,049.9 1,093.7 0.0 199.1 22.7 2,337.3 95.9 10,861.9 186.4 2034 2,780.7 3,119.5 262.9 912.4 275.0 7,350.4 58.3 1,278.4 1,336.7 0.0 222.4 32.4 2,437.1 95.1 11,474.0 192.5 2035 2,829.6 3,316.0 281.2 943.1 266.6 7,636.5 47.1 1,321.5 1,368.7 0.0 238.1 32.3 2,596.9 94.4 11,966.9 196.4 2036 2,901.6 3,472.3 295.0 980.7 288.3 7,937.9 36.1 1,370.0 1,406.1 0.0 251.9 32.1 2,707.9 93.8 12,429.8 199.9 2037 2,937.4 3,695.6 317.2 993.2 294.1 8,237.4 99.7 1,414.6 1,514.4 0.0 273.7 31.9 2,850.5 93.3 13,001.2 204.4
CPW@ 7.86% (2008-2017) 4,236.0 5,503.7 320.5 2,890.2 338.5 13,288.8 726.6 2,971.1 3,697.8 (122.8) 331.0 155.8 1,975.4 415.1 19,741.1 85.4
(2008-2027) 10,274.6 10,556.9 690.8 4,722.9 1,051.2 27,296.4 946.8 5,166.7 6,113.5 (142.6) 641.0 232.9 5,366.8 807.6 40,315.6 108.5
(2008-2037) 14,215.2 14,661.1 1,031.8 5,988.6 1,445.8 37,342.5 1,023.6 6,834.4 7,858.0 (142.6) 922.8 274.2 8,603.9 950.7 55,809.5 122.4
APPENDIX 2 TABLE 71. TABLE 72. RISK ANALYSIS B - CARBON COST AT $50/TON SUPPLY SIDE SCENARIO 4 (SS-4/B) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 0.0 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 0.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 0.0 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 0.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 501.5 84.9 0.0 2,991.7 88.8 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 521.7 51.4 0.0 3,067.5 90.2 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 549.2 54.9 (0.1) 3,327.2 94.9 2015 639.1 846.7 51.1 462.7 89.7 2,089.4 120.9 707.6 828.5 (33.0) 56.0 30.6 582.2 58.3 (0.1) 3,611.8 99.5 2016 810.8 893.6 56.0 437.2 137.8 2,335.4 147.5 863.5 1,011.1 (37.0) 61.7 33.7 624.0 93.4 (0.0) 4,122.2 109.8 2017 996.9 1,067.7 67.8 452.4 160.2 2,745.0 158.0 893.5 1,051.5 (39.2) 65.5 36.7 678.1 100.0 (0.0) 4,637.6 119.6 2018 1,142.4 1,184.6 78.7 468.4 161.3 3,035.4 128.6 974.2 1,102.8 (38.4) 71.6 40.7 760.9 107.3 (0.0) 5,080.3 127.1 2019 1,244.7 1,168.9 77.5 481.8 157.3 3,130.3 125.4 1,163.1 1,288.5 (5.2) 71.6 46.4 788.4 114.3 (0.9) 5,433.4 132.1 2020 1,458.0 1,342.9 90.4 501.3 170.4 3,562.9 66.1 1,214.9 1,281.1 (2.6) 76.4 50.4 841.0 121.1 (1.4) 5,928.9 140.4 2021 1,728.5 1,421.8 96.9 528.7 217.2 3,993.0 63.4 1,370.7 1,434.1 0.0 84.8 57.6 945.1 127.8 (2.8) 6,639.7 153.2 2022 2,020.5 1,442.2 98.1 564.9 233.0 4,358.7 59.5 1,354.9 1,414.4 0.0 91.4 56.2 962.0 134.8 (2.6) 7,014.9 157.9 2023 2,031.1 1,304.1 86.8 611.4 226.4 4,259.8 25.2 1,578.8 1,604.0 0.0 76.7 59.5 894.4 142.6 (20.1) 7,016.8 154.1 2024 1,884.8 1,364.5 90.5 635.4 268.2 4,243.5 35.2 1,582.2 1,617.5 0.0 76.8 57.9 954.7 150.3 (36.9) 7,063.8 151.5 2025 1,920.4 1,403.2 93.3 652.5 288.1 4,357.6 57.9 1,798.6 1,856.5 0.0 84.1 63.8 1,008.7 158.2 (39.1) 7,489.8 156.9 2026 1,994.2 1,538.8 104.5 672.4 280.9 4,590.8 50.6 1,800.8 1,851.4 0.0 91.2 61.9 1,152.4 92.2 (28.7) 7,811.2 159.4 2027 2,058.2 1,686.4 115.9 690.8 294.6 4,845.9 45.6 1,815.7 1,861.3 0.0 102.1 60.8 1,319.5 92.2 (24.8) 8,257.1 164.3 2028 2,131.6 1,801.0 125.2 714.8 296.9 5,069.5 61.0 1,822.5 1,883.5 0.0 114.5 58.7 1,457.3 98.1 (21.5) 8,660.0 168.2 2029 2,211.6 1,975.6 139.8 740.1 288.6 5,355.6 54.7 1,819.8 1,874.5 0.0 130.7 56.5 1,636.6 98.0 (12.8) 9,139.1 172.7 2030 2,300.1 2,134.2 152.5 766.5 304.2 5,657.6 52.9 1,811.8 1,864.7 0.0 141.7 54.1 1,789.6 97.3 (11.3) 9,593.6 176.8 2031 2,377.1 2,281.6 164.3 793.7 307.7 5,924.4 47.5 1,813.0 1,860.5 0.0 154.0 51.7 1,927.3 96.8 (9.2) 10,005.4 180.0 2032 2,452.3 2,506.5 183.1 823.3 300.2 6,265.4 42.2 1,820.1 1,862.3 0.0 171.3 49.1 2,039.4 96.2 (5.3) 10,478.5 184.4 2033 2,527.8 2,660.1 195.5 851.7 317.6 6,552.7 56.8 1,850.0 1,906.8 0.0 178.5 47.9 2,171.0 95.9 (4.0) 10,948.8 187.9 2034 2,586.0 2,818.5 210.0 881.3 320.6 6,816.5 46.4 2,078.5 2,124.9 0.0 201.7 56.5 2,271.7 95.1 (3.4) 11,563.0 194.0 2035 2,658.1 3,001.7 227.5 911.7 311.0 7,110.0 35.5 2,121.7 2,157.2 0.0 217.9 55.3 2,424.2 94.4 (2.5) 12,056.6 197.9 2036 2,713.1 3,151.7 239.7 947.4 331.4 7,383.4 74.7 2,171.8 2,246.6 0.0 229.9 54.0 2,529.5 93.8 (2.8) 12,534.3 201.6 2037 2,764.9 3,369.0 259.7 959.2 335.8 7,688.6 14.3 2,214.8 2,229.1 0.0 251.5 52.5 2,670.5 93.3 (1.5) 12,984.1 204.2
CPW@ 7.86% (2008-2017) 4,191.7 5,433.7 315.2 2,888.3 338.2 13,167.1 718.2 3,192.1 3,910.3 (122.8) 325.8 166.0 1,933.4 415.1 (0.1) 19,794.8 85.7
(2008-2027) 9,530.1 9,741.7 604.8 4,675.7 1,032.8 25,585.1 944.7 7,646.5 8,591.3 (142.6) 582.9 337.5 4,887.1 807.6 (41.3) 40,607.6 109.3
(2008-2037) 13,141.1 13,405.3 873.5 5,897.4 1,491.8 34,809.0 1,018.9 10,505.1 11,524.0 (142.6) 835.8 417.7 7,877.5 950.7 (54.2) 56,217.9 123.3
APPENDIX 2 TABLE 72. TABLE 73. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SELECTED PLAN (SP/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 50.0 2,357.4 73.3 2009 549.1 935.1 42.4 412.2 8.6 1,947.5 76.8 379.3 456.1 (8.3) 42.6 14.5 (1.2) 81.6 2,532.8 77.8 2010 573.3 877.6 42.2 422.9 20.9 1,936.9 115.7 403.0 518.7 (9.1) 42.5 24.5 (9.5) 82.3 2,586.2 79.5 2011 580.5 916.5 44.6 419.9 28.5 1,990.0 102.9 330.4 433.3 (10.0) 43.5 23.2 (10.0) 107.1 2,577.1 79.0 2012 578.7 815.2 41.2 423.8 30.7 1,889.6 105.2 493.6 598.9 (14.0) 42.7 27.8 (10.6) 134.9 2,669.2 81.1 2013 583.5 816.7 43.2 429.0 49.2 1,921.6 105.8 537.4 643.1 (19.0) 44.5 27.2 (10.9) 115.8 2,722.4 82.3 2014 601.0 934.0 49.9 446.3 66.1 2,097.4 106.2 592.6 698.7 (24.3) 51.0 29.0 (11.7) 134.5 2,974.5 87.6 2015 639.1 936.8 49.5 462.7 76.3 2,164.4 106.6 726.6 833.2 (33.0) 52.2 29.2 (12.3) 160.7 3,194.5 91.3 2016 798.3 1,013.0 55.6 436.7 103.7 2,407.3 139.4 780.8 920.2 (37.0) 59.2 27.0 (12.8) 220.0 3,583.8 99.5 2017 989.0 1,264.6 68.8 452.0 120.2 2,894.6 165.8 650.1 815.9 (39.2) 64.9 23.8 (13.5) 230.5 3,977.0 107.3 2018 1,184.0 1,448.0 81.6 470.0 163.0 3,346.6 127.4 575.6 703.0 (38.4) 72.7 21.4 (14.4) 241.7 4,332.6 113.9 2019 1,326.5 1,456.5 83.0 485.2 180.0 3,531.3 122.0 618.6 740.6 (5.2) 74.9 20.7 (15.3) 252.7 4,599.6 118.0 2020 1,589.1 1,719.9 103.6 508.8 192.2 4,113.6 67.5 474.7 542.1 (2.6) 80.9 18.1 (16.6) 263.6 4,999.2 125.3 2021 1,885.2 1,817.9 114.0 539.0 239.1 4,595.3 67.8 580.7 648.5 0.0 89.3 23.6 (17.7) 274.7 5,613.8 137.5 2022 2,171.9 1,828.7 115.5 575.6 254.6 4,946.4 61.5 554.5 616.0 0.0 95.1 22.7 (19.1) 286.0 5,947.1 142.4 2023 2,177.4 1,598.5 101.3 622.4 247.3 4,746.9 20.6 778.6 799.2 0.0 79.9 26.5 (20.8) 298.4 5,930.2 138.9 2024 2,026.1 1,650.7 102.4 646.7 240.2 4,666.1 24.4 779.8 804.2 0.0 79.1 25.6 (22.0) 310.8 5,863.7 134.3 2025 2,040.1 1,678.3 104.3 663.6 235.5 4,721.6 52.1 998.2 1,050.3 0.0 85.6 32.1 (23.4) 323.5 6,189.7 138.7 2026 2,080.6 1,849.2 117.3 682.5 249.3 4,978.8 57.5 1,000.6 1,058.1 0.0 92.1 30.8 (24.7) 262.4 6,397.6 139.9 2027 2,129.3 2,023.7 128.4 700.8 252.4 5,234.6 51.1 1,015.5 1,066.6 0.0 101.7 30.4 (25.7) 258.3 6,665.9 142.3 2028 2,200.3 2,154.5 138.4 725.1 245.6 5,463.9 60.4 1,020.6 1,080.9 0.0 113.8 29.1 (27.1) 258.7 6,919.4 144.2 2029 2,277.8 2,370.6 152.6 750.7 261.8 5,813.4 47.9 1,019.4 1,067.3 0.0 128.3 27.6 (29.0) 251.9 7,259.5 147.3 2030 2,343.8 2,552.4 164.9 776.7 265.6 6,103.3 61.3 1,011.6 1,073.0 0.0 138.6 26.1 (31.0) 243.1 7,553.1 149.6 2031 2,404.8 2,720.0 176.2 803.6 259.8 6,364.3 48.6 1,012.9 1,061.5 0.0 148.5 24.5 (32.5) 232.8 7,799.1 150.8 2032 2,478.1 2,996.6 193.8 833.5 277.7 6,779.8 36.9 1,018.0 1,054.9 0.0 164.7 22.8 (35.6) 220.5 8,207.2 155.3 2033 2,552.2 3,163.6 205.1 862.2 281.6 7,064.7 44.6 1,049.9 1,094.5 0.0 170.9 22.7 (37.6) 206.4 8,521.7 157.4 2034 2,587.2 3,334.7 218.8 891.3 273.9 7,305.8 51.7 1,278.4 1,330.1 0.0 192.0 32.4 (40.8) 189.4 9,008.9 162.8 2035 2,620.0 3,554.5 235.1 920.5 291.6 7,621.8 58.3 1,321.5 1,379.8 0.0 206.9 32.3 (43.6) 170.0 9,367.1 165.6 2036 2,683.4 3,715.7 246.9 956.7 297.5 7,900.2 15.0 1,370.0 1,385.0 0.0 218.1 32.1 (47.0) 147.6 9,636.0 167.1 2037 2,727.3 3,969.5 265.3 968.5 290.2 8,220.8 71.5 1,414.6 1,486.1 0.0 237.3 31.9 (47.2) 122.1 10,051.0 170.4
CPW@ 7.86% (2008-2017) 4,181.6 6,239.2 313.1 2,887.9 294.8 13,916.7 709.9 3,330.9 4,040.9 (122.8) 314.8 155.8 (57.4) 813.7 19,061.6 84.3
(2008-2027) 9,872.7 11,565.7 638.8 4,701.0 990.2 27,768.5 934.2 5,552.6 6,486.8 (142.6) 580.3 232.9 (118.2) 1,683.5 36,491.3 101.8
(2008-2037) 13,518.1 15,923.6 923.1 5,937.6 1,393.8 37,696.2 1,008.8 7,220.4 8,229.2 (142.6) 823.7 274.2 (171.2) 2,000.7 48,710.3 111.5
APPENDIX 2 TABLE 73. TABLE 74. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% DEFAULT ENERGY EFFICIENCY SCENARIO (EE-D/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 877.9 40.5 404.2 8.6 1,855.3 74.5 339.1 413.6 (10.8) 38.5 13.9 (0.9) 26.6 2,336.1 72.6 2009 549.1 952.1 43.4 412.2 8.6 1,965.4 85.7 380.0 465.7 (8.3) 43.8 14.7 (1.1) 56.0 2,536.2 77.5 2010 573.3 911.8 43.8 422.9 20.9 1,972.7 120.7 410.4 531.1 (9.1) 44.5 24.8 (9.5) 54.8 2,609.4 79.3 2011 580.5 950.7 46.0 419.9 28.5 2,025.6 101.8 363.7 465.5 (10.0) 47.2 29.2 (10.0) 67.0 2,614.6 78.7 2012 578.7 865.3 43.4 423.8 30.7 1,941.8 104.2 516.3 620.5 (14.0) 46.6 28.2 (10.5) 84.9 2,697.6 80.1 2013 583.5 886.1 46.5 429.0 49.2 1,994.3 104.8 555.9 660.7 (19.0) 49.7 28.2 (10.8) 51.4 2,754.5 81.0 2014 597.5 1,048.6 55.4 446.3 91.2 2,239.0 119.7 524.8 644.4 (24.3) 58.3 25.8 (11.7) 54.9 2,986.5 85.2 2015 641.6 1,098.2 58.0 463.2 103.8 2,364.7 151.2 601.8 753.0 (33.0) 62.4 23.1 (12.1) 58.3 3,216.5 88.6 2016 843.0 1,179.0 64.4 440.5 140.5 2,667.4 157.8 639.3 797.1 (37.0) 70.0 20.2 (12.7) 93.4 3,598.4 95.9 2017 1,017.2 1,469.7 80.8 458.3 175.7 3,201.7 156.0 498.0 653.9 (39.2) 77.0 17.2 (13.4) 100.0 3,997.3 103.0 2018 1,116.3 1,655.3 92.7 476.4 184.5 3,525.1 125.2 412.3 537.5 (38.4) 85.6 15.0 (14.2) 107.3 4,217.9 105.5 2019 1,148.9 1,745.6 99.0 491.8 180.6 3,665.9 124.0 455.9 579.9 (5.2) 95.4 14.3 (15.2) 114.3 4,449.6 108.2 2020 1,295.6 2,030.3 120.5 516.0 193.4 4,155.7 66.9 294.1 361.0 (2.6) 99.7 11.9 (16.5) 121.1 4,730.3 112.0 2021 1,519.6 2,161.5 138.7 549.7 199.8 4,569.3 67.3 351.9 419.2 0.0 109.5 15.2 (17.5) 127.8 5,223.6 120.5 2022 1,666.1 2,342.4 154.8 575.1 196.6 4,934.9 52.1 321.0 373.1 0.0 128.4 14.5 (18.8) 134.8 5,566.9 125.3 2023 1,635.1 2,416.5 159.6 594.3 191.8 4,997.4 52.3 453.8 506.1 0.0 126.5 18.5 (20.1) 142.6 5,771.0 126.7 2024 1,644.1 2,592.3 171.4 607.2 206.0 5,221.1 53.0 458.1 511.2 0.0 135.9 17.8 (21.1) 150.3 6,015.1 129.0 2025 1,685.9 2,658.5 176.9 624.1 212.3 5,357.6 51.9 608.7 660.5 0.0 143.8 24.5 (22.3) 158.2 6,322.3 132.4 2026 1,740.5 2,862.3 189.7 642.3 207.3 5,642.1 46.7 612.7 659.4 0.0 152.5 23.5 (23.8) 92.2 6,545.9 133.6 2027 1,859.3 3,020.0 207.7 664.3 202.5 5,953.9 9.8 630.3 640.1 0.0 162.8 22.4 (24.8) 92.2 6,846.7 136.3 2028 1,935.4 3,215.9 226.8 689.6 218.5 6,286.2 54.7 640.5 695.1 0.0 176.3 21.3 (26.1) 98.1 7,251.0 140.8 2029 1,995.8 3,459.8 244.2 713.3 223.3 6,636.3 48.7 645.2 693.8 0.0 195.0 20.1 (28.1) 98.0 7,615.1 143.9 2030 2,099.1 3,706.3 263.4 739.3 218.7 7,026.7 34.1 641.0 675.1 0.0 208.5 18.8 (30.1) 97.3 7,996.2 147.4 2031 2,153.3 3,865.2 276.2 764.6 237.4 7,296.7 39.9 771.8 811.8 0.0 221.5 25.4 (31.7) 96.8 8,420.5 151.5 2032 2,177.5 4,145.5 297.2 791.2 243.0 7,654.3 53.8 863.9 917.7 0.0 237.8 28.9 (34.8) 96.2 8,900.1 156.6 2033 2,246.9 4,375.4 315.0 818.0 237.0 7,992.3 52.0 899.9 951.8 0.0 250.8 29.2 (36.9) 95.9 9,283.2 159.3 2034 2,349.4 4,676.8 341.6 847.7 259.6 8,475.1 41.2 940.3 981.6 0.0 280.1 29.5 (40.2) 95.1 9,821.2 164.8 2035 2,454.9 4,884.1 357.7 877.7 264.0 8,838.5 30.1 979.8 1,009.9 0.0 294.0 29.8 (42.9) 94.4 10,223.8 167.8 2036 2,525.0 5,149.6 378.0 912.4 257.7 9,222.8 69.0 1,027.7 1,096.7 0.0 310.8 30.1 (46.3) 93.8 10,707.9 172.2 2037 2,566.2 5,409.1 401.7 922.6 253.8 9,553.5 36.7 1,071.1 1,107.8 0.0 327.4 30.3 (46.5) 93.3 11,065.8 174.6
CPW@ 7.86% (2008-2017) 4,216.7 6,720.5 337.8 2,893.1 369.3 14,537.3 758.3 3,138.4 3,896.6 (122.8) 347.1 150.3 (57.0) 415.1 19,166.6 83.0
(2008-2027) 8,909.3 13,869.2 792.1 4,670.9 989.5 29,230.9 984.7 4,539.0 5,523.7 (142.6) 723.5 204.2 (116.3) 807.6 36,231.2 97.5
(2008-2037) 12,190.3 20,024.3 1,235.7 5,847.1 1,343.5 40,640.9 1,053.4 5,751.2 6,804.6 (142.6) 1,080.2 242.2 (168.1) 950.7 49,407.9 108.4
APPENDIX 2 TABLE 74. TABLE 75. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% ENERGY EFFICIENCY SCENARIO 1 (EE-1/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 877.9 40.5 404.2 8.6 1,855.3 74.5 339.1 413.6 (10.8) 38.5 13.9 (0.9) 50.0 2,359.5 73.3 2009 549.1 938.7 42.8 412.2 8.6 1,951.4 83.6 378.4 462.0 (8.3) 43.3 14.7 (1.2) 82.4 2,544.4 78.2 2010 573.3 887.3 43.1 422.9 20.9 1,947.5 119.4 404.0 523.4 (9.1) 43.5 24.8 (9.5) 84.0 2,604.7 80.1 2011 580.5 913.6 44.4 419.9 28.5 1,986.9 102.1 354.0 456.0 (10.0) 45.4 29.2 (10.0) 88.3 2,585.9 79.3 2012 578.7 820.8 41.8 423.8 30.7 1,895.8 104.5 503.4 607.8 (14.0) 44.1 28.2 (10.5) 108.1 2,659.5 80.7 2013 583.5 837.5 43.9 429.0 49.2 1,943.2 105.0 539.9 644.9 (19.0) 46.8 28.2 (10.9) 74.9 2,708.2 81.6 2014 597.5 986.6 52.7 446.3 77.8 2,160.9 105.5 511.1 616.6 (24.3) 54.5 25.8 (11.7) 78.7 2,900.5 85.0 2015 629.5 1,031.8 54.3 462.7 97.5 2,275.9 133.5 586.6 720.1 (33.0) 58.3 23.1 (12.2) 82.7 3,115.1 88.3 2016 808.1 1,103.3 60.4 438.9 141.1 2,551.8 156.8 625.7 782.5 (37.0) 65.4 20.2 (12.7) 118.3 3,488.5 95.7 2017 975.6 1,382.3 76.0 456.4 160.7 3,051.0 156.6 486.8 643.3 (39.2) 71.8 17.2 (13.4) 125.7 3,856.4 102.4 2018 1,078.1 1,555.7 87.1 474.5 178.4 3,373.8 120.0 404.6 524.6 (38.4) 79.3 15.0 (14.3) 133.8 4,073.8 105.1 2019 1,109.9 1,641.2 92.9 489.6 182.0 3,515.6 122.5 446.3 568.8 (5.2) 88.6 14.3 (15.2) 141.6 4,308.5 108.1 2020 1,256.3 1,910.3 113.6 513.6 179.0 3,972.9 67.3 290.8 358.2 (2.6) 92.2 11.9 (16.5) 149.2 4,565.2 111.6 2021 1,469.8 2,037.0 131.4 546.9 194.4 4,379.4 69.5 350.4 419.9 0.0 102.1 15.2 (17.5) 156.9 5,056.0 120.5 2022 1,609.8 2,208.0 146.4 572.0 199.7 4,735.8 54.8 321.0 375.8 0.0 120.0 14.5 (18.9) 164.7 5,392.0 125.3 2023 1,581.2 2,273.7 151.1 591.1 194.9 4,791.9 53.0 454.1 507.0 0.0 118.0 18.5 (20.2) 173.5 5,588.8 126.8 2024 1,592.5 2,442.3 162.0 604.0 190.1 4,990.8 52.0 458.3 510.3 0.0 126.7 17.8 (21.1) 182.2 5,806.6 128.7 2025 1,633.5 2,500.8 166.9 620.4 206.0 5,127.7 55.7 608.5 664.2 0.0 133.9 24.5 (22.4) 191.1 6,119.1 132.4 2026 1,674.2 2,693.7 178.9 638.0 211.6 5,396.3 57.6 613.7 671.3 0.0 142.0 23.5 (23.9) 126.0 6,335.2 133.6 2027 1,785.9 2,846.7 195.9 659.5 207.2 5,695.2 20.7 630.9 651.6 0.0 152.1 22.4 (24.9) 125.2 6,621.6 136.2 2028 1,880.5 3,033.2 214.2 685.1 201.4 6,014.4 55.7 639.6 695.3 0.0 164.8 21.3 (26.2) 130.0 6,999.6 140.4 2029 1,938.7 3,266.6 230.7 708.5 218.4 6,362.9 56.0 646.9 702.9 0.0 182.9 20.1 (28.2) 128.6 7,369.2 143.9 2030 2,033.5 3,501.2 249.1 734.0 224.1 6,741.9 39.1 641.7 680.8 0.0 195.6 18.8 (30.2) 126.3 7,733.2 147.3 2031 2,107.4 3,651.0 261.0 759.7 219.2 6,998.3 34.3 770.8 805.1 0.0 207.6 25.4 (31.7) 123.8 8,128.4 151.1 2032 2,145.4 3,918.8 281.3 786.4 239.1 7,371.0 46.5 862.4 908.9 0.0 223.3 28.9 (34.9) 121.0 8,618.1 156.6 2033 2,216.2 4,136.8 297.9 813.1 245.4 7,709.4 43.1 898.6 941.7 0.0 235.6 29.2 (36.9) 117.9 8,996.9 159.5 2034 2,297.6 4,420.4 323.0 841.8 239.8 8,122.5 54.6 940.8 995.5 0.0 263.7 29.5 (40.2) 113.8 9,484.9 164.4 2035 2,370.4 4,618.8 338.2 870.5 260.3 8,458.2 50.6 982.6 1,033.3 0.0 277.2 29.8 (42.9) 109.5 9,865.1 167.2 2036 2,454.6 4,874.2 357.7 905.5 268.0 8,860.0 27.2 1,027.1 1,054.3 0.0 293.0 30.1 (46.3) 104.5 10,295.5 171.0 2037 2,511.5 5,118.8 379.9 915.8 263.0 9,189.1 88.2 1,071.7 1,159.9 0.0 308.9 30.3 (46.6) 99.0 10,740.7 175.0
CPW@ 7.86% (2008-2017) 4,172.9 6,448.7 324.9 2,891.1 351.3 14,188.8 737.6 3,077.3 3,814.8 (122.8) 331.8 150.3 (57.2) 581.3 18,887.1 83.2
(2008-2027) 8,707.5 13,178.1 753.6 4,659.5 960.1 28,258.7 968.8 4,469.4 5,438.1 (142.6) 682.3 204.2 (116.7) 1,068.3 35,392.4 97.5
(2008-2037) 11,908.0 18,995.0 1,172.9 5,827.7 1,307.4 39,211.0 1,041.6 5,681.6 6,723.2 (142.6) 1,017.4 242.2 (168.6) 1,246.0 48,128.7 108.2
APPENDIX 2 TABLE 75. TABLE 76. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% ENERGY EFFICIENCY SCENARIO 2 (EE-2/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 877.9 40.5 404.2 8.6 1,855.3 74.5 339.1 413.6 (10.8) 38.5 13.9 (0.9) 103.2 2,412.7 75.0 2009 549.1 923.0 42.2 412.2 8.6 1,935.2 78.4 372.8 451.2 (8.3) 42.5 14.7 (1.2) 139.4 2,573.6 79.6 2010 573.3 862.1 42.1 422.9 20.9 1,921.3 116.2 396.1 512.3 (9.1) 42.5 24.8 (9.5) 139.0 2,621.4 81.6 2011 580.5 884.1 43.2 419.9 28.5 1,956.2 102.6 344.5 447.1 (10.0) 43.9 29.2 (10.0) 152.6 2,609.0 81.1 2012 578.7 788.1 40.2 423.8 30.7 1,861.4 105.0 492.8 597.8 (14.0) 42.5 28.2 (10.6) 172.8 2,678.1 82.6 2013 583.5 798.1 42.1 429.0 49.2 1,901.9 105.6 526.7 632.3 (19.0) 44.6 28.2 (10.9) 141.1 2,718.2 83.5 2014 597.5 937.5 50.4 446.3 66.1 2,097.8 106.0 496.7 602.7 (24.3) 51.8 25.8 (11.7) 147.1 2,889.2 86.6 2015 629.5 977.6 51.5 462.7 90.1 2,211.4 113.7 570.3 684.0 (33.0) 55.0 23.1 (12.2) 153.3 3,081.7 89.5 2016 780.9 1,039.8 56.8 437.7 138.7 2,453.8 143.8 609.9 753.7 (37.0) 61.0 20.2 (12.7) 191.3 3,430.3 96.6 2017 917.4 1,300.8 71.3 453.7 161.2 2,904.3 164.3 477.0 641.4 (39.2) 66.8 17.2 (13.5) 200.9 3,778.0 103.2 2018 1,013.2 1,463.6 81.9 471.4 163.6 3,193.7 130.1 394.7 524.8 (38.4) 73.4 15.0 (14.4) 211.6 3,965.7 105.4 2019 1,050.1 1,535.2 87.2 486.6 176.1 3,335.2 123.3 438.4 561.7 (5.2) 82.3 14.3 (15.3) 221.8 4,194.9 108.5 2020 1,198.2 1,787.0 106.9 510.4 180.5 3,783.0 66.8 288.7 355.5 (2.6) 84.7 11.9 (16.6) 232.0 4,448.0 112.3 2021 1,412.2 1,906.7 124.0 543.5 179.6 4,166.0 69.8 347.3 417.1 0.0 94.0 15.2 (17.6) 242.4 4,917.1 121.2 2022 1,539.3 2,065.7 137.5 567.9 176.6 4,487.0 62.1 321.5 383.7 0.0 111.0 14.5 (19.0) 252.8 5,230.0 125.9 2023 1,518.4 2,122.9 141.6 587.0 190.2 4,560.2 53.7 452.6 506.3 0.0 108.5 18.5 (20.2) 264.0 5,437.3 127.8 2024 1,527.3 2,279.3 151.9 599.6 194.9 4,753.0 52.9 458.0 510.9 0.0 116.2 17.8 (21.2) 275.2 5,651.9 129.9 2025 1,576.4 2,327.2 156.1 616.1 192.1 4,867.9 50.0 607.0 657.0 0.0 123.0 24.5 (22.5) 287.3 5,937.3 133.4 2026 1,614.3 2,510.2 167.2 633.3 207.1 5,132.1 53.0 613.3 666.4 0.0 130.1 23.5 (24.0) 224.8 6,152.9 134.7 2027 1,647.8 2,681.9 179.1 649.3 212.0 5,370.1 59.4 634.0 693.4 0.0 142.2 22.4 (25.0) 220.8 6,424.0 137.2 2028 1,736.1 2,868.4 193.2 672.6 206.9 5,677.0 49.4 640.1 689.5 0.0 155.2 21.3 (26.2) 220.9 6,737.7 140.4 2029 1,825.5 3,095.6 208.8 696.6 225.2 6,051.7 46.9 645.7 692.6 0.0 172.5 20.1 (28.3) 215.7 7,124.4 144.5 2030 1,904.7 3,318.7 225.4 721.0 230.2 6,400.1 48.7 643.5 692.2 0.0 185.0 18.8 (30.2) 208.8 7,474.6 147.9 2031 1,969.4 3,461.2 236.6 745.7 224.8 6,637.7 40.0 772.0 812.0 0.0 196.5 25.4 (31.8) 200.8 7,840.5 151.4 2032 2,012.2 3,718.4 254.8 772.1 244.6 7,002.0 48.9 862.9 911.7 0.0 211.2 28.9 (34.9) 191.3 8,310.3 157.0 2033 2,087.4 3,923.5 270.6 798.3 250.8 7,330.6 42.3 898.9 941.2 0.0 222.7 29.2 (36.9) 180.4 8,667.2 159.7 2034 2,173.0 4,202.2 294.3 826.6 245.0 7,741.0 50.5 940.8 991.3 0.0 250.4 29.5 (40.2) 167.2 9,139.2 164.6 2035 2,269.0 4,386.3 308.4 855.3 237.5 8,056.5 33.3 980.4 1,013.7 0.0 263.0 29.8 (42.9) 152.2 9,472.4 166.9 2036 2,345.9 4,628.1 326.3 889.3 261.5 8,451.2 66.3 1,027.0 1,093.2 0.0 277.5 30.1 (46.4) 134.9 9,940.5 171.7 2037 2,393.8 4,867.5 347.0 898.8 270.0 8,777.2 28.2 1,071.3 1,099.6 0.0 293.2 30.3 (46.6) 115.3 10,269.1 174.0
CPW@ 7.86% (2008-2017) 4,131.8 6,216.8 313.6 2,889.2 339.3 13,890.7 718.3 3,013.6 3,731.9 (122.8) 318.6 150.3 (57.3) 1,008.5 18,919.9 84.7
(2008-2027) 8,453.7 12,512.1 715.0 4,644.4 923.7 27,248.8 962.9 4,396.2 5,359.1 (142.6) 641.9 204.2 (117.0) 1,772.5 34,966.9 98.5
(2008-2037) 11,467.4 18,030.3 1,095.8 5,791.7 1,274.9 37,660.1 1,031.0 5,608.6 6,639.7 (142.6) 959.0 242.2 (168.9) 2,048.8 47,238.2 109.0
APPENDIX 2 TABLE 76. TABLE 77. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% ENERGY EFFICIENCY SCENARIO 3 (EE-3/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 877.9 40.5 404.2 8.6 1,855.3 74.5 339.1 413.6 (10.8) 38.5 13.9 (0.9) 179.8 2,489.3 77.4 2009 549.1 909.2 41.8 412.2 8.6 1,920.9 77.4 371.8 449.2 (8.3) 42.0 14.7 (1.2) 247.2 2,664.6 82.9 2010 573.3 841.2 41.3 422.9 20.9 1,899.7 115.6 390.3 505.9 (9.1) 41.4 24.8 (9.5) 245.9 2,699.0 84.8 2011 580.5 854.4 41.9 419.9 28.5 1,925.2 102.8 338.7 441.5 (10.0) 42.4 29.2 (10.0) 259.0 2,677.3 84.3 2012 578.7 756.5 38.8 423.8 30.7 1,828.4 105.1 479.0 584.1 (14.0) 40.6 28.2 (10.6) 282.5 2,739.3 86.0 2013 583.5 759.8 40.3 429.0 49.2 1,861.9 105.7 515.0 620.7 (19.0) 42.4 28.2 (11.0) 250.8 2,774.0 87.0 2014 597.5 888.6 47.9 446.3 66.1 2,046.4 106.1 485.7 591.8 (24.3) 48.8 25.8 (11.8) 259.6 2,936.3 90.0 2015 629.5 923.1 48.9 462.7 78.0 2,142.3 106.5 556.2 662.6 (33.0) 51.7 23.1 (12.2) 269.4 3,104.0 92.4 2016 743.4 974.8 53.3 436.2 110.1 2,317.7 144.8 600.6 745.4 (37.0) 57.5 20.2 (12.8) 311.2 3,402.3 98.4 2017 867.9 1,226.0 67.2 451.5 146.1 2,758.7 164.0 467.2 631.2 (39.2) 62.6 17.2 (13.5) 324.6 3,741.6 105.1 2018 972.5 1,376.0 78.1 469.3 161.5 3,057.5 126.7 386.5 513.3 (38.4) 68.1 15.0 (14.4) 340.0 3,941.0 107.8 2019 995.6 1,439.9 82.4 483.8 179.0 3,180.7 130.2 431.2 561.4 (5.2) 76.3 14.3 (15.3) 354.3 4,166.5 111.1 2020 1,112.5 1,700.9 97.4 504.5 183.9 3,599.2 71.3 291.5 362.8 (2.6) 80.5 11.9 (16.6) 369.0 4,404.2 114.6 2021 1,324.6 1,816.0 110.6 535.9 199.4 3,986.5 64.1 350.4 414.5 0.0 89.8 15.2 (17.6) 384.6 4,873.0 123.9 2022 1,462.8 1,969.1 124.1 560.3 204.0 4,320.3 51.5 320.2 371.7 0.0 106.2 14.5 (19.0) 399.1 5,192.9 129.1 2023 1,428.4 2,022.6 127.5 578.6 198.7 4,355.7 51.2 453.2 504.4 0.0 103.6 18.5 (20.3) 413.7 5,375.7 130.6 2024 1,429.1 2,169.7 136.7 590.4 193.8 4,519.7 55.3 458.3 513.6 0.0 110.4 17.8 (21.3) 428.6 5,568.7 132.3 2025 1,467.9 2,212.3 140.1 606.3 191.0 4,617.5 54.0 609.1 663.1 0.0 116.9 24.5 (22.6) 446.7 5,846.2 135.8 2026 1,514.2 2,383.6 150.4 623.3 186.7 4,858.2 53.1 613.4 666.5 0.0 122.9 23.5 (24.0) 387.7 6,034.8 136.7 2027 1,630.1 2,523.0 165.9 644.2 203.7 5,166.9 13.8 630.4 644.2 0.0 132.4 22.4 (25.1) 377.6 6,318.5 139.7 2028 1,715.9 2,688.2 181.6 668.9 209.4 5,464.0 51.7 640.4 692.1 0.0 143.8 21.3 (26.3) 370.1 6,664.9 143.8 2029 1,766.8 2,902.1 196.5 691.2 203.4 5,760.0 59.8 645.5 705.2 0.0 159.7 20.1 (28.3) 358.7 6,975.4 146.4 2030 1,846.9 3,114.1 212.3 715.2 198.0 6,086.6 58.4 643.3 701.7 0.0 171.2 18.8 (30.3) 344.2 7,292.2 149.3 2031 1,914.6 3,245.9 222.3 739.8 218.0 6,340.6 47.0 771.4 818.4 0.0 182.0 25.4 (31.9) 327.1 7,661.6 153.1 2032 1,959.8 3,496.6 239.9 765.9 224.8 6,687.0 53.2 862.7 915.9 0.0 196.6 28.9 (35.0) 306.7 8,100.2 158.4 2033 2,037.3 3,685.5 254.1 792.0 218.5 6,987.5 43.7 898.3 941.9 0.0 207.7 29.2 (37.0) 283.1 8,412.5 160.4 2034 2,125.3 3,945.7 276.3 820.0 239.9 7,407.2 49.1 940.2 989.3 0.0 233.2 29.5 (40.3) 254.9 8,873.8 165.4 2035 2,205.0 4,124.1 289.7 848.1 246.5 7,713.4 39.0 981.2 1,020.2 0.0 244.4 29.8 (43.0) 222.4 9,187.3 167.5 2036 2,273.1 4,354.2 306.7 881.5 241.6 8,057.2 59.8 1,027.0 1,086.8 0.0 258.9 30.1 (46.4) 184.9 9,571.5 171.1 2037 2,322.5 4,583.0 324.9 890.4 236.7 8,357.5 64.3 1,072.2 1,136.5 0.0 274.2 30.3 (46.6) 142.0 9,893.9 173.5
CPW@ 7.86% (2008-2017) 4,089.6 5,993.9 302.9 2,887.4 311.2 13,585.0 713.6 2,963.4 3,677.0 (122.8) 306.2 150.3 (57.5) 1,729.1 19,267.4 87.5
(2008-2027) 8,175.3 11,963.2 668.7 4,622.3 908.0 26,337.6 946.7 4,341.3 5,288.0 (142.6) 611.8 204.2 (117.3) 2,951.1 35,132.8 101.1
(2008-2037) 11,110.5 17,145.7 1,026.6 5,760.5 1,236.1 36,279.4 1,025.0 5,553.6 6,578.6 (142.6) 906.6 242.2 (169.4) 3,389.1 47,083.9 111.2
APPENDIX 2 TABLE 77. TABLE 78. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% ENERGY EFFICIENCY SCENARIO 4 (EE-4/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 877.9 40.5 404.2 8.6 1,855.3 74.5 339.1 413.6 (10.8) 38.5 13.9 (0.9) 302.2 2,611.7 81.2 2009 549.1 894.0 41.3 412.2 8.6 1,905.2 77.4 366.8 444.2 (8.3) 41.4 14.7 (1.2) 407.3 2,803.4 87.8 2010 573.3 814.4 40.5 422.9 9.5 1,860.6 115.6 380.6 496.2 (9.1) 39.8 24.8 (9.5) 406.2 2,809.1 89.5 2011 580.5 817.1 40.2 419.9 9.5 1,867.2 102.8 328.8 431.5 (10.0) 40.6 29.2 (10.0) 419.5 2,767.9 88.8 2012 578.7 716.3 36.9 423.8 21.6 1,777.4 105.1 463.4 568.5 (14.0) 38.4 28.2 (10.6) 448.3 2,836.2 91.2 2013 583.5 710.8 37.8 429.0 48.8 1,810.0 105.7 496.3 602.0 (19.0) 39.4 28.2 (11.0) 417.5 2,867.2 92.5 2014 597.5 830.5 44.7 446.3 68.8 1,987.8 106.1 466.5 572.5 (24.3) 45.5 25.8 (11.8) 430.9 3,026.4 95.6 2015 629.5 856.7 45.6 462.7 66.9 2,061.4 106.5 536.1 642.6 (33.0) 47.9 23.1 (12.3) 446.3 3,176.1 97.8 2016 718.4 897.5 49.4 435.1 91.9 2,192.4 135.8 580.3 716.0 (37.0) 53.2 20.2 (12.8) 493.8 3,425.7 102.6 2017 811.0 1,130.3 62.2 449.0 106.8 2,559.3 160.8 453.3 614.1 (39.2) 57.1 17.2 (13.6) 513.1 3,708.1 108.1 2018 896.3 1,268.2 72.2 465.9 145.5 2,848.0 132.9 376.5 509.4 (38.4) 61.9 15.0 (14.5) 535.3 3,916.7 111.3 2019 926.2 1,320.5 75.5 480.3 180.6 2,983.0 131.4 419.7 551.1 (5.2) 69.3 14.3 (15.4) 555.6 4,152.7 115.2 2020 1,053.9 1,556.3 90.0 501.2 192.0 3,393.4 66.7 287.9 354.6 (2.6) 72.2 11.9 (16.7) 576.8 4,389.5 119.1 2021 1,253.6 1,665.1 102.3 531.9 190.3 3,743.2 66.0 346.6 412.5 0.0 80.7 15.2 (17.7) 600.1 4,834.2 128.3 2022 1,384.2 1,804.4 114.4 555.7 186.1 4,044.9 56.7 320.1 376.9 0.0 96.2 14.5 (19.1) 620.9 5,134.3 133.3 2023 1,353.1 1,847.6 116.7 573.9 181.2 4,072.5 53.1 452.9 505.9 0.0 93.5 18.5 (20.4) 641.0 5,311.1 134.9 2024 1,356.9 1,981.6 125.9 585.6 195.7 4,245.7 54.0 457.3 511.3 0.0 99.0 17.8 (21.4) 661.6 5,514.1 137.1 2025 1,395.9 2,013.4 128.3 601.0 201.7 4,340.3 56.6 607.6 664.1 0.0 104.7 24.5 (22.7) 688.4 5,799.3 141.0 2026 1,446.3 2,172.4 138.5 618.0 197.7 4,573.0 50.1 612.5 662.6 0.0 109.9 23.5 (24.1) 635.1 5,980.1 141.9 2027 1,481.0 2,332.1 148.4 633.3 213.8 4,808.6 61.3 634.1 695.4 0.0 121.7 22.4 (25.2) 616.3 6,239.2 144.4 2028 1,548.2 2,496.4 159.2 655.2 218.8 5,077.8 53.7 641.7 695.4 0.0 133.1 21.3 (26.4) 597.2 6,498.4 146.8 2029 1,631.4 2,704.7 173.2 678.1 213.6 5,401.0 58.9 645.8 704.7 0.0 148.0 20.1 (28.4) 576.4 6,821.8 150.0 2030 1,716.6 2,906.6 187.1 701.7 208.4 5,720.3 54.4 644.8 699.2 0.0 159.0 18.8 (30.4) 550.3 7,117.3 152.6 2031 1,789.1 3,026.6 196.3 725.8 227.9 5,965.8 40.0 771.7 811.7 0.0 169.2 25.4 (32.0) 519.3 7,459.4 156.2 2032 1,838.8 3,267.5 211.8 751.5 234.5 6,304.1 43.0 863.0 906.0 0.0 182.8 28.9 (35.1) 482.5 7,869.2 161.2 2033 1,916.4 3,443.2 224.8 776.8 229.1 6,590.5 45.0 898.2 943.2 0.0 192.4 29.2 (37.0) 439.3 8,157.5 163.0 2034 2,009.5 3,699.7 245.0 804.5 249.7 7,008.5 32.0 939.9 971.9 0.0 218.3 29.5 (40.4) 388.3 8,576.2 167.5 2035 2,091.7 3,863.4 257.2 832.0 254.4 7,298.7 34.5 980.3 1,014.7 0.0 228.8 29.8 (43.1) 329.3 8,858.3 169.2 2036 2,160.8 4,078.2 273.0 864.7 248.6 7,625.3 36.4 1,026.0 1,062.4 0.0 241.9 30.1 (46.5) 261.1 9,174.2 171.8 2037 2,193.4 4,292.0 289.1 872.5 243.1 7,890.2 67.1 1,072.5 1,139.6 0.0 255.9 30.3 (46.7) 182.7 9,452.0 173.7
CPW@ 7.86% (2008-2017) 4,050.3 5,718.8 289.8 2,885.7 249.5 13,194.0 707.5 2,882.4 3,589.9 (122.8) 290.8 150.3 (57.7) 2,824.4 19,869.0 92.1
(2008-2027) 7,893.2 11,186.3 625.6 4,605.8 837.0 25,148.0 955.0 4,248.4 5,203.4 (142.6) 566.6 204.2 (117.8) 4,741.6 35,603.6 105.4
(2008-2037) 10,635.6 16,027.6 942.0 5,722.1 1,179.0 34,506.5 1,025.3 5,461.2 6,486.5 (142.6) 841.0 242.2 (170.0) 5,425.9 47,189.4 115.1
APPENDIX 2 TABLE 78. TABLE 79. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% DEFAULT SUPPLY SIDE SCENARIO (SS-D/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 597.5 1,038.7 55.3 446.3 66.1 2,203.9 116.3 524.0 640.3 (24.3) 56.8 24.8 (11.7) 54.9 2,944.7 84.0 2015 629.5 1,073.3 56.9 462.7 89.7 2,312.0 153.0 604.1 757.1 (33.0) 60.2 22.1 (12.1) 58.3 3,164.6 87.2 2016 830.9 1,181.5 65.0 439.7 138.4 2,655.4 165.0 637.7 802.7 (37.0) 69.3 19.2 (12.6) 93.4 3,590.3 95.7 2017 1,021.9 1,471.8 81.0 457.9 176.0 3,208.6 159.6 497.6 657.2 (39.2) 76.9 16.1 (13.4) 100.0 4,006.2 103.3 2018 1,139.3 1,693.7 95.3 476.5 185.3 3,590.2 123.1 415.6 538.7 (38.4) 87.4 13.8 (14.2) 107.3 4,284.8 107.2 2019 1,176.3 1,721.9 97.7 491.8 181.0 3,668.8 125.2 460.1 585.3 (5.2) 91.1 13.2 (15.2) 114.3 4,452.2 108.2 2020 1,331.8 2,030.1 121.0 516.2 193.5 4,192.5 68.3 301.6 369.9 (2.6) 99.2 10.8 (16.5) 121.1 4,774.2 113.0 2021 1,562.5 2,120.2 136.5 550.2 200.1 4,569.6 63.1 406.2 469.4 0.0 105.9 16.4 (17.5) 127.8 5,271.5 121.7 2022 1,704.7 2,318.0 153.5 575.4 196.1 4,947.6 52.2 374.4 426.6 0.0 123.9 15.6 (18.8) 134.8 5,629.7 126.7 2023 1,685.9 2,365.5 156.6 595.0 191.6 4,994.7 46.4 598.6 645.0 0.0 121.3 19.6 (20.1) 142.6 5,903.1 129.6 2024 1,701.1 2,525.9 167.4 608.2 205.5 5,208.1 46.7 599.3 646.0 0.0 127.6 18.8 (21.1) 150.3 6,129.8 131.4 2025 1,769.1 2,619.6 174.6 625.9 210.9 5,400.1 47.3 818.1 865.4 0.0 140.2 25.5 (22.3) 158.2 6,567.1 137.5 2026 1,824.7 2,827.2 187.8 644.3 205.5 5,689.5 51.5 820.7 872.1 0.0 149.9 24.4 (23.8) 92.2 6,804.2 138.9 2027 1,927.7 2,979.4 205.2 665.8 200.8 5,978.8 22.1 835.6 857.7 0.0 158.4 24.2 (24.8) 92.2 7,086.5 141.0 2028 2,034.7 3,188.5 225.3 692.3 216.8 6,357.5 38.3 840.2 878.5 0.0 174.0 23.0 (26.1) 98.1 7,505.1 145.7 2029 2,095.7 3,428.2 242.0 716.1 222.0 6,704.0 53.9 839.5 893.4 0.0 191.5 21.8 (28.1) 98.0 7,880.6 148.9 2030 2,237.1 3,625.4 264.5 746.2 253.9 7,127.1 17.5 831.6 849.0 0.0 200.9 20.5 (30.1) 97.3 8,264.6 152.3 2031 2,342.7 3,840.3 285.3 775.5 267.1 7,510.9 36.0 832.9 868.9 0.0 217.4 19.2 (31.7) 96.8 8,681.5 156.2 2032 2,389.4 4,133.6 308.0 803.2 284.4 7,918.6 54.0 837.6 891.6 0.0 234.7 17.8 (34.8) 96.2 9,124.1 160.5 2033 2,481.4 4,375.1 326.9 831.2 289.2 8,303.8 44.3 869.9 914.2 0.0 247.2 17.9 (36.9) 95.9 9,542.2 163.8 2034 2,565.6 4,559.5 346.2 860.8 281.9 8,614.0 34.4 1,098.4 1,132.8 0.0 267.4 27.9 (40.2) 95.1 10,096.9 169.4 2035 2,624.0 4,799.6 364.3 889.7 273.0 8,950.6 49.1 1,141.6 1,190.6 0.0 283.4 28.1 (42.9) 94.4 10,504.2 172.4 2036 2,695.6 5,025.4 382.2 925.1 294.4 9,322.7 13.8 1,189.6 1,203.4 0.0 299.6 28.3 (46.3) 93.8 10,901.4 175.4 2037 2,743.5 5,346.5 410.5 935.9 300.5 9,736.9 78.1 1,234.7 1,312.8 0.0 325.0 28.5 (46.6) 93.3 11,450.0 180.0
CPW@ 7.86% (2008-2017) 4,206.2 6,682.7 335.9 2,892.2 345.9 14,462.9 751.2 3,113.0 3,864.2 (122.8) 338.9 141.9 (57.1) 415.1 19,043.1 82.4
(2008-2027) 9,048.0 13,755.7 786.2 4,672.1 965.3 29,227.3 975.4 4,786.0 5,761.4 (142.6) 705.1 196.7 (116.3) 807.6 36,439.1 98.1
(2008-2037) 12,573.7 19,833.4 1,236.8 5,862.1 1,356.1 40,862.1 1,036.7 6,185.9 7,222.6 (142.6) 1,053.2 230.5 (168.2) 950.7 50,008.2 109.7
APPENDIX 2 TABLE 79. TABLE 80. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% NUCLEAR SUPPLY SIDE SCENARIO (SS-N/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 600.3 1,038.7 55.3 446.3 66.1 2,206.7 116.3 524.0 640.3 (24.3) 56.8 24.8 (11.7) 54.9 2,947.5 84.1 2015 637.1 1,073.3 56.9 462.7 89.7 2,319.7 153.0 604.1 757.1 (33.0) 60.2 22.1 (12.1) 58.3 3,172.3 87.4 2016 864.3 1,181.5 65.0 439.7 138.4 2,688.9 165.0 637.7 802.7 (37.0) 69.3 19.2 (12.6) 93.4 3,623.7 96.5 2017 1,104.5 1,471.8 81.0 457.9 176.0 3,291.2 159.6 497.6 657.2 (39.2) 76.9 16.1 (13.4) 100.0 4,088.8 105.4 2018 1,285.6 1,693.7 95.3 476.5 185.3 3,736.5 123.1 415.6 538.7 (38.4) 87.4 13.8 (14.2) 107.3 4,431.1 110.8 2019 1,401.2 1,721.9 97.7 491.8 181.0 3,893.7 125.2 460.1 585.3 (5.2) 91.1 13.2 (15.2) 114.3 4,677.1 113.7 2020 1,647.9 2,030.1 121.0 516.2 193.5 4,508.6 68.3 301.6 369.9 (2.6) 99.2 10.8 (16.5) 121.1 5,090.4 120.5 2021 1,941.9 2,144.6 132.9 547.7 232.0 4,999.1 59.4 408.8 468.2 0.0 107.9 16.4 (17.5) 127.8 5,702.0 131.6 2022 2,197.7 2,219.9 138.5 581.9 243.2 5,381.2 52.6 374.4 427.0 0.0 118.6 15.6 (18.9) 134.8 6,058.4 136.3 2023 2,188.7 2,049.3 129.0 622.9 236.2 5,226.3 27.0 598.6 625.7 0.0 104.7 19.6 (20.3) 142.6 6,098.5 133.9 2024 2,071.2 2,129.8 134.8 645.2 247.5 5,228.6 32.8 599.3 632.1 0.0 105.7 18.8 (21.4) 150.3 6,114.1 131.1 2025 2,108.9 2,190.5 139.5 663.2 252.1 5,354.1 48.2 818.1 866.4 0.0 115.8 25.5 (22.7) 158.2 6,497.3 136.1 2026 2,156.1 2,397.7 152.1 682.6 245.8 5,634.4 52.4 820.7 873.1 0.0 123.7 24.4 (24.1) 92.2 6,723.7 137.2 2027 2,252.8 2,569.3 168.4 705.3 239.8 5,935.6 23.0 835.6 858.5 0.0 133.6 24.2 (25.1) 92.2 7,019.0 139.7 2028 2,335.9 2,734.2 183.7 732.3 233.8 6,219.8 59.5 840.2 899.7 0.0 145.9 23.0 (26.5) 98.1 7,360.1 142.9 2029 2,393.6 2,974.2 200.6 757.5 227.7 6,553.6 53.3 839.4 892.7 0.0 163.4 21.8 (28.4) 98.0 7,701.1 145.5 2030 2,534.2 3,152.4 219.6 789.4 244.4 6,939.9 17.0 831.6 848.6 0.0 172.3 20.5 (30.4) 97.3 8,048.2 148.3 2031 2,604.0 3,340.8 237.9 819.2 249.1 7,251.1 57.8 832.9 890.7 0.0 185.1 19.2 (31.9) 96.8 8,410.9 151.3 2032 2,643.2 3,647.4 259.1 848.4 243.4 7,641.4 52.1 837.6 889.7 0.0 203.1 17.8 (35.1) 96.2 8,813.2 155.1 2033 2,735.5 3,847.3 274.8 878.4 262.4 7,998.3 42.6 869.9 912.5 0.0 212.8 17.9 (37.1) 95.9 9,200.3 157.9 2034 2,804.2 4,039.4 293.0 909.4 267.0 8,313.0 32.7 1,098.4 1,131.2 0.0 234.9 27.9 (40.3) 95.1 9,761.6 163.8 2035 2,847.3 4,287.5 311.3 939.8 257.8 8,643.6 47.6 1,141.6 1,189.1 0.0 251.2 28.1 (43.1) 94.4 10,163.4 166.8 2036 2,904.6 4,489.9 326.6 976.6 280.5 8,978.2 12.4 1,189.7 1,202.0 0.0 265.4 28.3 (46.5) 93.8 10,521.2 169.2 2037 2,942.3 4,781.7 350.6 989.0 287.2 9,350.8 76.7 1,234.7 1,311.4 0.0 288.8 28.5 (46.7) 93.3 11,026.1 173.4
CPW@ 7.86% (2008-2017) 4,267.7 6,682.7 335.9 2,892.2 345.9 14,524.4 751.2 3,113.0 3,864.2 (122.8) 338.9 141.9 (57.1) 415.1 19,104.6 82.7
(2008-2027) 10,161.6 13,226.6 737.4 4,719.3 1,045.1 29,890.0 965.3 4,786.9 5,752.2 (142.6) 675.2 196.7 (116.7) 807.6 37,062.3 99.7
(2008-2037) 14,075.3 18,567.1 1,115.7 5,976.8 1,419.4 41,154.3 1,033.0 6,186.8 7,219.8 (142.6) 976.8 230.5 (168.9) 950.7 50,220.5 110.1
APPENDIX 2 TABLE 80. TABLE 81. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 597.5 992.3 53.3 446.3 66.1 2,155.6 106.2 635.3 741.5 (24.3) 54.2 30.0 (11.7) 54.9 3,000.1 85.6 2015 629.5 985.2 52.7 462.7 89.7 2,219.8 112.3 826.0 938.3 (33.0) 54.8 32.6 (12.2) 58.3 3,258.7 89.8 2016 755.9 1,038.3 57.5 436.7 123.4 2,411.7 141.7 986.3 1,128.0 (37.0) 60.7 35.1 (12.7) 93.4 3,679.1 98.0 2017 871.2 1,256.8 68.8 451.5 153.3 2,801.5 158.1 983.9 1,142.0 (39.2) 64.4 37.5 (13.5) 100.0 4,092.8 105.5 2018 936.7 1,401.2 79.2 467.5 162.7 3,047.1 128.7 1,044.2 1,172.8 (38.4) 70.4 40.8 (14.4) 107.3 4,385.7 109.7 2019 940.0 1,373.4 77.8 480.9 158.1 3,030.2 125.5 1,227.1 1,352.6 (5.2) 70.6 45.8 (15.4) 114.3 4,593.0 111.7 2020 1,038.2 1,596.6 90.8 500.3 171.4 3,397.4 66.2 1,246.7 1,312.8 (2.6) 75.5 49.2 (16.7) 121.1 4,936.7 116.9 2021 1,210.1 1,714.0 98.5 527.7 195.2 3,745.6 70.2 1,353.6 1,423.8 0.0 85.5 54.2 (17.7) 127.8 5,419.2 125.1 2022 1,343.7 1,908.5 108.9 549.9 200.0 4,110.9 63.1 1,327.4 1,390.5 0.0 103.8 52.8 (19.0) 134.8 5,773.8 129.9 2023 1,337.6 1,953.5 112.8 568.7 194.7 4,167.3 57.0 1,551.6 1,608.6 0.0 100.8 56.1 (20.3) 142.6 6,055.1 133.0 2024 1,365.3 2,102.9 121.6 581.1 189.9 4,360.8 57.0 1,554.0 1,611.0 0.0 105.6 54.6 (21.3) 150.3 6,261.1 134.2 2025 1,445.7 2,190.1 127.8 598.0 206.7 4,568.3 57.3 1,771.2 1,828.5 0.0 118.6 60.6 (22.6) 158.2 6,711.6 140.6 2026 1,531.0 2,384.0 139.2 616.2 211.3 4,881.8 50.0 1,773.6 1,823.6 0.0 127.6 58.7 (24.0) 92.2 6,959.9 142.1 2027 1,604.0 2,569.1 151.3 633.0 206.7 5,164.0 45.1 1,788.5 1,833.6 0.0 137.9 57.7 (25.0) 92.2 7,260.5 144.5 2028 1,685.0 2,797.7 165.9 655.3 223.0 5,526.9 60.5 1,794.9 1,855.4 0.0 156.1 55.6 (26.3) 98.1 7,665.9 148.9 2029 1,778.4 3,022.6 180.9 678.7 227.2 5,887.9 54.2 1,792.5 1,846.7 0.0 173.0 53.4 (28.3) 98.0 8,030.7 151.8 2030 1,946.1 3,203.9 200.3 708.2 221.3 6,279.9 17.3 1,784.5 1,801.9 0.0 181.3 51.1 (30.3) 97.3 8,381.1 154.5 2031 2,063.4 3,403.7 220.5 736.4 255.1 6,679.0 35.4 1,785.9 1,821.3 0.0 196.6 48.8 (31.8) 96.8 8,810.6 158.5 2032 2,120.6 3,701.4 239.4 762.9 292.5 7,116.8 53.4 1,792.4 1,845.9 0.0 214.5 46.2 (35.0) 96.2 9,284.6 163.4 2033 2,222.0 3,938.1 256.4 789.7 297.3 7,503.6 43.8 1,822.9 1,866.7 0.0 225.3 45.1 (37.0) 95.9 9,699.6 166.5 2034 2,314.7 4,141.9 273.8 818.1 289.9 7,838.3 33.9 2,051.4 2,085.3 0.0 246.9 53.8 (40.3) 95.1 10,279.0 172.5 2035 2,381.5 4,357.6 290.0 845.7 307.6 8,182.4 48.5 2,094.5 2,143.0 0.0 263.3 52.7 (43.0) 94.4 10,692.7 175.5 2036 2,462.9 4,573.9 306.3 879.7 313.6 8,536.3 13.2 2,144.3 2,157.5 0.0 277.6 51.4 (46.5) 93.8 11,070.1 178.1 2037 2,521.9 4,910.7 331.7 889.2 306.5 8,960.1 77.6 2,187.6 2,265.2 0.0 305.2 50.1 (46.7) 93.3 11,627.2 182.8
CPW@ 7.86% (2008-2017) 4,097.5 6,433.9 323.0 2,887.7 327.6 14,069.7 710.6 3,704.3 4,414.9 (122.8) 324.1 168.8 (57.2) 415.1 19,212.6 83.1
(2008-2027) 7,987.2 12,259.0 658.3 4,600.9 917.4 26,423.0 955.8 8,176.8 9,132.6 (142.6) 624.8 333.2 (117.0) 807.6 37,061.5 99.7
(2008-2037) 11,097.6 17,706.2 1,008.2 5,730.6 1,313.2 36,855.9 1,021.1 10,994.7 12,015.8 (142.6) 943.3 409.1 (169.1) 950.7 50,863.0 111.6
APPENDIX 2 TABLE 81. TABLE 82. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 597.5 999.4 53.4 446.3 66.1 2,162.7 106.2 625.1 731.2 (24.3) 54.7 29.8 (11.7) 54.9 2,997.3 85.5 2015 629.5 995.4 52.4 462.7 89.7 2,229.7 116.6 807.4 924.0 (33.0) 55.5 32.2 (12.2) 58.3 3,254.4 89.7 2016 780.9 1,074.6 58.8 437.7 137.8 2,489.7 143.2 896.8 1,040.0 (37.0) 62.5 31.6 (12.7) 93.4 3,667.4 97.7 2017 899.9 1,275.9 69.1 452.7 160.2 2,857.8 157.5 941.3 1,098.8 (39.2) 65.5 36.7 (13.5) 100.0 4,106.2 105.9 2018 955.1 1,423.5 79.9 468.4 161.3 3,088.2 131.6 990.4 1,122.0 (38.4) 71.9 39.8 (14.4) 107.3 4,376.4 109.5 2019 957.6 1,402.8 78.7 481.8 172.6 3,093.6 132.3 1,160.7 1,293.0 (5.2) 72.5 44.6 (15.4) 114.3 4,597.3 111.8 2020 1,069.4 1,634.4 92.2 501.9 177.6 3,475.5 67.5 1,161.8 1,229.3 (2.6) 77.7 47.6 (16.7) 121.1 4,931.8 116.8 2021 1,250.1 1,735.8 98.9 529.7 193.1 3,807.6 61.7 1,308.3 1,370.1 0.0 86.5 54.6 (17.8) 127.8 5,428.9 125.3 2022 1,382.1 1,928.2 110.0 551.9 198.3 4,170.5 51.6 1,285.7 1,337.3 0.0 104.5 53.2 (19.1) 134.8 5,781.3 130.1 2023 1,358.7 1,974.2 113.2 570.3 222.3 4,238.7 56.1 1,509.7 1,565.8 0.0 101.9 56.5 (20.4) 142.6 6,085.0 133.6 2024 1,390.6 2,125.4 122.2 582.8 232.2 4,453.2 52.6 1,512.5 1,565.1 0.0 106.7 55.1 (21.4) 150.3 6,308.9 135.3 2025 1,464.6 2,212.9 128.5 599.6 246.9 4,652.6 56.7 1,729.5 1,786.2 0.0 120.0 61.0 (22.7) 158.2 6,755.4 141.5 2026 1,537.2 2,407.9 140.6 617.4 250.6 4,953.8 56.8 1,731.7 1,788.5 0.0 128.7 59.2 (24.1) 92.2 6,998.3 142.8 2027 1,663.7 2,549.3 157.0 638.6 244.6 5,253.1 19.7 1,746.6 1,766.2 0.0 136.7 58.1 (25.1) 92.2 7,281.3 144.9 2028 1,762.6 2,745.1 176.2 663.6 237.6 5,585.1 56.5 1,753.2 1,809.6 0.0 151.2 56.1 (26.4) 98.1 7,673.7 149.0 2029 1,840.8 2,977.9 191.6 686.8 231.9 5,929.0 50.3 1,750.7 1,801.0 0.0 169.4 53.9 (28.4) 98.0 8,022.8 151.6 2030 2,006.8 3,160.7 211.2 716.5 286.4 6,381.6 13.6 1,742.6 1,756.2 0.0 176.7 51.6 (30.4) 97.3 8,432.9 155.4 2031 2,102.0 3,362.2 230.7 744.1 309.1 6,748.2 54.2 1,743.9 1,798.1 0.0 191.9 49.2 (32.0) 96.8 8,852.1 159.2 2032 2,165.3 3,652.4 249.7 771.1 300.8 7,139.3 48.5 1,751.0 1,799.5 0.0 210.2 46.7 (35.2) 96.2 9,256.6 162.9 2033 2,280.7 3,884.6 266.1 798.8 317.7 7,547.9 39.1 1,780.9 1,820.1 0.0 220.8 45.6 (37.2) 95.9 9,693.1 166.4 2034 2,349.3 4,069.6 283.2 826.5 321.9 7,850.6 53.8 2,009.5 2,063.2 0.0 240.4 54.3 (40.5) 95.1 10,263.1 172.2 2035 2,423.1 4,298.7 299.5 854.7 311.9 8,187.8 42.6 2,052.5 2,095.2 0.0 256.0 53.2 (43.2) 94.4 10,643.3 174.7 2036 2,520.4 4,501.5 316.3 889.6 332.0 8,559.7 31.6 2,102.6 2,134.2 0.0 269.7 52.0 (46.7) 93.8 11,062.7 178.0 2037 2,578.3 4,827.2 341.4 899.4 337.8 8,984.1 95.2 2,145.7 2,240.9 0.0 297.7 50.6 (46.8) 93.3 11,619.8 182.7
CPW@ 7.86% (2008-2017) 4,123.6 6,471.0 323.7 2,888.8 338.2 14,145.2 713.4 3,622.8 4,336.3 (122.8) 326.2 166.3 (57.3) 415.1 19,209.1 83.1
(2008-2027) 8,099.1 12,365.3 662.8 4,607.6 982.2 26,717.0 950.9 7,930.4 8,881.3 (142.6) 630.7 330.0 (117.4) 807.6 37,106.6 99.9
(2008-2037) 11,290.7 17,730.8 1,027.8 5,750.1 1,416.1 37,215.5 1,021.4 10,686.1 11,707.5 (142.6) 941.2 406.7 (169.7) 950.7 50,909.3 111.7
APPENDIX 2 TABLE 82. TABLE 83. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SUPPLY SIDE SCENARIO 1 (SS-1/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 599.7 1,016.7 54.2 446.3 66.1 2,183.1 107.9 579.1 687.0 (24.3) 55.4 27.4 (11.7) 54.9 2,971.7 84.8 2015 635.5 1,028.0 54.6 462.7 89.7 2,270.5 130.6 716.4 847.0 (33.0) 57.4 27.4 (12.2) 58.3 3,215.4 88.6 2016 819.9 1,109.1 61.3 438.2 137.8 2,566.3 154.6 807.5 962.1 (37.0) 64.7 26.8 (12.7) 93.4 3,663.6 97.6 2017 1,025.0 1,390.5 76.6 455.2 160.8 3,108.2 161.2 671.6 832.8 (39.2) 72.4 23.7 (13.4) 100.0 4,084.5 105.3 2018 1,195.6 1,604.3 90.4 473.7 177.6 3,541.7 124.7 594.2 718.8 (38.4) 82.0 21.3 (14.3) 107.3 4,418.4 110.5 2019 1,297.4 1,631.2 92.6 489.0 181.5 3,691.8 126.7 637.8 764.5 (5.2) 85.5 20.6 (15.2) 114.3 4,656.3 113.2 2020 1,527.6 1,930.1 115.2 513.3 194.0 4,280.2 69.7 484.9 554.6 (2.6) 93.3 18.0 (16.5) 121.1 5,048.1 119.5 2021 1,793.0 2,045.8 126.9 544.1 225.3 4,735.0 70.5 591.8 662.3 0.0 102.2 23.5 (17.5) 127.8 5,633.3 130.0 2022 2,033.2 2,143.4 133.9 576.2 233.5 5,120.3 56.8 560.0 616.8 0.0 114.4 22.6 (18.9) 134.8 5,990.0 134.8 2023 2,033.9 2,016.9 127.1 613.1 227.2 5,018.3 29.4 784.3 813.6 0.0 102.8 26.4 (20.3) 142.6 6,083.4 133.6 2024 1,936.9 2,112.2 133.4 633.0 221.4 5,036.9 39.9 785.3 825.2 0.0 104.6 25.5 (21.4) 150.3 6,121.1 131.2 2025 1,978.4 2,176.5 138.3 650.6 236.4 5,180.1 55.2 1,003.8 1,059.0 0.0 115.3 32.0 (22.7) 158.2 6,522.0 136.6 2026 2,047.3 2,383.5 150.5 670.3 240.5 5,492.1 48.0 1,006.3 1,054.2 0.0 123.3 30.7 (24.1) 92.2 6,768.4 138.1 2027 2,159.4 2,546.8 166.9 693.1 234.7 5,800.9 11.1 1,021.2 1,032.2 0.0 132.5 30.4 (25.1) 92.2 7,063.2 140.6 2028 2,245.0 2,717.2 183.0 719.8 228.0 6,092.9 48.1 1,026.2 1,074.3 0.0 145.5 29.0 (26.4) 98.1 7,413.3 143.9 2029 2,306.2 2,955.8 199.2 744.6 222.6 6,428.4 42.2 1,025.0 1,067.2 0.0 162.8 27.6 (28.4) 98.0 7,755.6 146.6 2030 2,451.3 3,171.7 214.8 776.1 239.9 6,853.8 6.0 1,017.2 1,023.3 0.0 174.8 26.1 (30.4) 97.3 8,144.9 150.1 2031 2,525.6 3,375.7 229.7 805.5 283.4 7,220.0 47.1 1,018.5 1,065.6 0.0 190.0 24.5 (31.9) 96.8 8,565.0 154.1 2032 2,568.5 3,680.7 249.9 834.3 295.3 7,628.9 41.7 1,024.5 1,066.2 0.0 207.4 22.8 (35.0) 96.2 8,986.6 158.1 2033 2,642.6 3,889.5 266.0 863.1 312.4 7,973.7 56.2 1,055.5 1,111.7 0.0 217.5 22.7 (37.0) 95.9 9,384.4 161.1 2034 2,700.5 4,091.0 284.1 893.0 316.7 8,285.2 45.8 1,284.2 1,329.9 0.0 240.5 32.4 (40.3) 95.1 9,942.8 166.8 2035 2,748.7 4,332.2 302.3 922.9 307.8 8,613.8 60.1 1,327.2 1,387.3 0.0 256.6 32.3 (43.0) 94.4 10,341.4 169.7 2036 2,810.9 4,536.9 317.2 959.2 328.5 8,952.7 24.6 1,375.7 1,400.3 0.0 271.2 32.2 (46.5) 93.8 10,703.6 172.2 2037 2,877.7 4,844.0 341.5 972.0 333.2 9,368.4 14.1 1,420.4 1,434.5 0.0 295.3 32.0 (46.7) 93.3 11,176.9 175.7
CPW@ 7.86% (2008-2017) 4,206.7 6,570.3 330.1 2,890.2 338.5 14,335.7 729.6 3,374.3 4,103.9 (122.8) 332.0 153.7 (57.1) 415.1 19,160.6 82.9
(2008-2027) 9,707.0 12,916.0 719.6 4,695.6 1,013.0 29,051.2 951.5 5,628.5 6,579.9 (142.6) 656.9 230.6 (116.8) 807.6 37,066.8 99.8
(2008-2037) 13,491.6 18,293.2 1,088.6 5,931.5 1,427.3 40,232.2 1,009.5 7,304.7 8,314.2 (142.6) 963.5 271.8 (168.9) 950.7 50,421.0 110.6
APPENDIX 2 TABLE 83. TABLE 84. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SUPPLY SIDE SCENARIO 2 (SS-2/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 600.4 1,005.2 53.8 446.3 66.1 2,171.8 106.2 609.6 715.8 (24.3) 54.8 29.0 (11.7) 54.9 2,990.2 85.3 2015 637.3 1,006.7 53.2 462.7 89.7 2,249.6 120.9 777.2 898.1 (33.0) 56.1 30.6 (12.2) 58.3 3,247.5 89.5 2016 802.8 1,068.9 58.7 437.2 137.8 2,505.4 152.0 909.4 1,061.4 (37.0) 62.3 32.0 (12.7) 93.4 3,704.7 98.7 2017 1,003.1 1,329.7 72.3 453.4 160.2 3,018.8 161.9 810.7 972.5 (39.2) 68.8 30.5 (13.5) 100.0 4,137.9 106.7 2018 1,177.2 1,520.6 85.2 471.3 161.9 3,416.3 126.7 768.7 895.4 (38.4) 77.4 29.7 (14.3) 107.3 4,473.3 111.9 2019 1,304.3 1,548.3 87.5 486.7 174.2 3,601.0 122.6 812.9 935.5 (5.2) 80.5 28.8 (15.3) 114.3 4,739.6 115.2 2020 1,539.1 1,865.2 105.4 508.3 195.4 4,213.3 65.4 669.0 734.3 (2.6) 90.5 26.1 (16.5) 121.1 5,166.1 122.3 2021 1,834.3 1,958.9 117.7 539.8 234.2 4,684.9 64.3 772.2 836.5 0.0 98.1 31.5 (17.6) 127.8 5,761.2 133.0 2022 2,111.1 2,008.4 125.9 576.1 245.5 5,067.0 58.8 744.4 803.2 0.0 106.1 30.4 (19.0) 134.8 6,122.4 137.8 2023 2,108.6 1,840.9 116.7 617.7 238.5 4,922.3 31.2 968.6 999.9 0.0 94.1 34.1 (20.5) 142.6 6,172.4 135.6 2024 1,992.5 1,915.8 121.2 640.2 231.5 4,901.3 36.1 970.2 1,006.3 0.0 94.6 33.0 (21.7) 150.3 6,163.8 132.2 2025 2,034.1 1,971.1 124.6 658.0 227.8 5,015.6 51.5 1,188.2 1,239.7 0.0 104.1 39.3 (23.0) 158.2 6,534.0 136.9 2026 2,085.1 2,164.7 138.2 677.3 242.2 5,307.4 55.7 1,190.6 1,246.3 0.0 110.9 37.9 (24.3) 92.2 6,770.3 138.2 2027 2,131.6 2,365.3 150.3 695.3 245.5 5,587.9 58.2 1,205.5 1,263.7 0.0 123.0 37.3 (25.3) 92.2 7,078.9 140.9 2028 2,218.6 2,524.8 162.2 720.2 239.7 5,865.5 52.7 1,211.0 1,263.7 0.0 135.5 35.8 (26.6) 98.1 7,371.9 143.1 2029 2,307.2 2,768.2 176.7 746.2 233.9 6,232.0 46.7 1,209.4 1,256.1 0.0 153.4 34.1 (28.6) 98.0 7,745.0 146.4 2030 2,451.3 2,938.7 195.3 777.7 250.4 6,613.4 10.3 1,201.5 1,211.8 0.0 161.1 32.4 (30.6) 97.3 8,085.4 149.0 2031 2,524.4 3,121.6 213.2 807.1 255.0 6,921.3 51.1 1,202.9 1,254.0 0.0 174.0 30.6 (32.1) 96.8 8,444.6 151.9 2032 2,565.9 3,426.2 232.8 836.0 248.1 7,309.1 45.7 1,208.6 1,254.3 0.0 191.7 28.7 (35.2) 96.2 8,844.7 155.6 2033 2,660.2 3,619.8 247.3 865.6 267.6 7,660.6 36.5 1,239.9 1,276.3 0.0 200.1 28.3 (37.2) 95.9 9,223.9 158.3 2034 2,708.2 3,818.1 264.1 895.4 315.6 8,001.3 51.1 1,468.4 1,519.4 0.0 221.8 37.6 (40.5) 95.1 9,834.7 165.0 2035 2,762.1 4,054.1 282.5 925.6 326.5 8,350.8 40.0 1,511.5 1,551.5 0.0 238.3 37.3 (43.2) 94.4 10,229.0 167.9 2036 2,815.4 4,252.9 296.8 961.7 346.1 8,672.9 79.0 1,560.4 1,639.4 0.0 252.2 36.8 (46.7) 93.8 10,648.3 171.3 2037 2,863.9 4,535.5 318.6 973.9 351.5 9,043.5 18.5 1,604.6 1,623.1 0.0 274.9 36.3 (46.8) 93.3 11,024.2 173.3
CPW@ 7.86% (2008-2017) 4,189.1 6,503.0 325.8 2,888.8 338.2 14,244.9 722.3 3,542.3 4,264.6 (122.8) 328.0 162.2 (57.2) 415.1 19,234.9 83.2
(2008-2027) 9,782.6 12,429.7 685.0 4,696.3 1,017.1 28,610.7 951.0 6,371.5 7,322.5 (142.6) 630.4 263.8 (117.4) 807.6 37,375.0 100.6
(2008-2037) 13,565.6 17,441.5 1,024.5 5,934.9 1,425.7 39,392.1 1,014.9 8,321.9 9,336.8 (142.6) 914.5 313.7 (169.8) 950.7 50,595.3 111.0
APPENDIX 2 TABLE 84. TABLE 85. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SUPPLY SIDE SCENARIO 3 (SS-3/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 2,735.9 80.4 2014 601.0 1,005.2 53.8 446.3 66.1 2,172.4 106.2 609.6 715.8 (24.3) 54.8 29.0 (11.7) 54.9 2,990.8 85.3 2015 639.1 1,018.1 53.8 462.7 89.7 2,263.4 125.2 749.0 874.3 (33.0) 56.7 29.2 (12.2) 58.3 3,236.7 89.2 2016 835.8 1,112.3 61.1 438.2 137.8 2,585.2 153.7 802.8 956.4 (37.0) 64.8 27.0 (12.7) 93.4 3,677.0 98.0 2017 1,064.4 1,392.9 76.2 455.2 160.8 3,149.5 164.4 665.8 830.1 (39.2) 72.4 23.8 (13.4) 100.0 4,123.2 106.3 2018 1,265.3 1,606.1 90.3 473.7 177.6 3,613.0 127.7 587.7 715.4 (38.4) 82.0 21.4 (14.3) 107.3 4,486.4 112.2 2019 1,404.5 1,634.7 92.5 489.0 181.5 3,802.2 129.6 631.3 760.9 (5.2) 85.8 20.7 (15.2) 114.3 4,763.5 115.8 2020 1,678.1 1,932.3 115.1 513.3 194.0 4,432.8 72.5 479.1 551.6 (2.6) 93.3 18.1 (16.5) 121.1 5,197.8 123.1 2021 1,995.4 2,048.4 126.9 544.6 240.9 4,956.2 63.5 585.1 648.6 0.0 102.4 23.6 (17.5) 127.8 5,841.1 134.8 2022 2,288.1 2,080.8 129.9 581.8 256.3 5,336.9 57.5 554.4 611.9 0.0 110.3 22.7 (19.0) 134.8 6,197.6 139.5 2023 2,288.8 1,858.2 117.8 628.8 249.0 5,142.5 23.2 778.6 801.9 0.0 94.5 26.5 (20.5) 142.6 6,187.5 135.9 2024 2,132.9 1,918.0 120.8 653.3 241.7 5,066.7 33.4 779.8 813.2 0.0 94.3 25.6 (21.7) 150.3 6,128.3 131.4 2025 2,159.1 1,967.8 124.5 671.0 255.7 5,178.1 56.1 998.2 1,054.3 0.0 103.2 32.1 (23.0) 158.2 6,502.9 136.2 2026 2,223.5 2,166.2 138.3 691.4 259.1 5,478.6 48.9 1,000.6 1,049.5 0.0 110.6 30.8 (24.3) 92.2 6,737.4 137.5 2027 2,332.2 2,342.1 154.0 714.8 252.8 5,796.0 11.9 1,015.5 1,027.5 0.0 120.7 30.4 (25.4) 92.2 7,041.5 140.1 2028 2,414.9 2,486.8 169.0 742.1 245.5 6,058.4 48.9 1,020.6 1,069.5 0.0 132.1 29.1 (26.7) 98.1 7,360.4 142.9 2029 2,471.1 2,727.9 184.5 767.6 239.5 6,390.6 43.0 1,019.4 1,062.4 0.0 148.6 27.6 (28.6) 98.0 7,698.6 145.5 2030 2,549.2 2,931.1 198.4 794.9 256.1 6,729.7 41.7 1,011.5 1,053.2 0.0 160.1 26.1 (30.7) 97.3 8,035.7 148.1 2031 2,595.6 3,120.5 212.6 822.2 260.4 7,011.2 59.0 1,012.9 1,071.9 0.0 172.7 24.5 (32.1) 96.8 8,344.9 150.1 2032 2,647.4 3,427.0 232.2 852.1 278.2 7,436.9 53.3 1,018.1 1,071.4 0.0 190.2 22.8 (35.2) 96.2 8,782.2 154.5 2033 2,737.1 3,616.2 246.4 882.2 283.5 7,765.3 43.8 1,049.9 1,093.7 0.0 199.0 22.7 (37.2) 95.9 9,139.4 156.9 2034 2,780.7 3,814.7 263.6 912.4 275.0 8,046.3 58.3 1,278.4 1,336.7 0.0 222.3 32.4 (40.5) 95.1 9,692.2 162.6 2035 2,829.6 4,058.8 282.1 943.1 266.6 8,380.2 47.1 1,321.5 1,368.7 0.0 238.1 32.3 (43.2) 94.4 10,070.4 165.3 2036 2,901.6 4,252.0 296.0 980.7 288.3 8,718.7 36.1 1,370.0 1,406.1 0.0 251.9 32.1 (46.7) 93.8 10,455.9 168.2 2037 2,937.4 4,535.6 318.0 993.2 294.1 9,078.2 99.7 1,414.6 1,514.4 0.0 273.6 31.9 (46.8) 93.3 10,944.6 172.1
CPW@ 7.86% (2008-2017) 4,236.0 6,560.8 329.1 2,890.2 338.5 14,354.6 726.6 3,405.0 4,131.6 (122.8) 331.3 155.8 (57.2) 415.1 19,208.5 83.1
(2008-2027) 10,274.6 12,639.2 701.7 4,722.9 1,051.2 29,389.5 946.8 5,640.2 6,587.1 (142.6) 641.0 232.9 (117.2) 807.6 37,398.3 100.7
(2008-2037) 14,215.2 17,633.7 1,044.0 5,988.6 1,445.8 40,327.3 1,023.6 7,308.0 8,331.6 (142.6) 922.7 274.2 (169.8) 950.7 50,494.1 110.7
APPENDIX 2 TABLE 85. TABLE 86. RISK ANALYSIS C - NATURAL GAS COST INCREASE of 30% SUPPLY SIDE SCENARIO 4 (SS-4/C) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 878.1 40.5 404.2 8.6 1,855.5 72.7 338.9 411.6 (10.8) 38.5 13.6 (0.9) 26.6 0.0 2,334.1 72.5 2009 549.1 949.3 42.9 412.2 8.6 1,962.2 76.8 380.6 457.3 (8.3) 43.1 14.5 (1.2) 56.0 0.0 2,523.7 77.1 2010 573.3 900.7 43.1 422.9 20.9 1,961.0 115.7 409.8 525.5 (9.1) 43.4 24.5 (9.5) 54.8 0.0 2,590.6 78.8 2011 580.5 953.0 46.2 419.9 28.5 2,028.1 102.9 339.9 442.8 (10.0) 45.0 23.2 (9.9) 67.0 0.0 2,586.2 77.9 2012 578.7 861.8 42.9 423.8 30.7 1,937.9 105.2 506.8 612.0 (14.0) 44.9 27.8 (10.5) 84.9 0.0 2,682.9 79.7 2013 583.5 872.2 45.7 429.0 49.2 1,979.7 105.8 554.3 660.1 (19.0) 47.3 27.2 (10.9) 51.4 0.0 2,735.9 80.4 2014 601.0 1,005.2 53.8 446.3 66.1 2,172.4 106.2 609.6 715.8 (24.3) 54.8 29.0 (11.7) 54.9 (0.1) 2,990.7 85.3 2015 639.1 1,006.7 53.2 462.7 89.7 2,251.5 120.9 777.2 898.1 (33.0) 56.1 30.6 (12.2) 58.3 (0.1) 3,249.2 89.5 2016 810.8 1,057.5 57.9 437.2 137.8 2,501.2 147.5 941.7 1,089.2 (37.0) 61.6 33.7 (12.8) 93.4 (0.0) 3,729.2 99.4 2017 996.9 1,275.9 69.1 452.4 160.2 2,954.5 158.0 941.4 1,099.5 (39.2) 65.5 36.7 (13.5) 100.0 (0.0) 4,203.5 108.4 2018 1,142.4 1,417.3 79.3 468.4 161.3 3,268.8 128.6 1,007.7 1,136.3 (38.4) 71.6 40.7 (14.4) 107.3 (0.0) 4,571.8 114.3 2019 1,244.7 1,388.6 77.9 481.8 157.3 3,350.4 125.4 1,197.3 1,322.7 (5.2) 71.6 46.4 (15.5) 114.3 (1.2) 4,883.6 118.7 2020 1,458.0 1,611.0 90.6 501.3 170.4 3,831.3 66.1 1,220.1 1,286.2 (2.6) 76.3 50.4 (16.8) 121.1 (1.8) 5,344.2 126.5 2021 1,728.5 1,707.0 97.0 528.7 217.2 4,278.3 63.4 1,377.2 1,440.7 0.0 84.7 57.6 (17.8) 127.8 (3.7) 5,967.7 137.7 2022 2,020.5 1,727.9 98.3 564.9 233.0 4,644.7 59.5 1,355.1 1,414.6 0.0 91.4 56.2 (19.3) 134.8 (3.4) 6,318.9 142.2 2023 2,031.1 1,538.5 87.1 611.4 226.4 4,494.5 25.2 1,578.8 1,604.0 0.0 76.7 59.5 (21.1) 142.6 (26.2) 6,329.9 139.0 2024 1,884.8 1,607.7 90.8 635.4 268.2 4,487.0 35.2 1,582.4 1,617.7 0.0 76.8 57.9 (22.2) 150.3 (48.0) 6,319.4 135.5 2025 1,920.4 1,654.7 93.5 652.5 288.1 4,609.3 57.9 1,798.7 1,856.6 0.0 84.1 63.8 (23.6) 158.2 (50.8) 6,697.6 140.3 2026 1,994.2 1,825.5 104.6 672.4 280.9 4,877.6 50.6 1,800.8 1,851.4 0.0 91.2 61.9 (24.9) 92.2 (37.3) 6,912.0 141.1 2027 2,058.2 2,009.1 115.9 690.8 294.6 5,168.6 45.6 1,815.7 1,861.3 0.0 102.1 60.8 (25.9) 92.2 (32.2) 7,227.0 143.8 2028 2,131.6 2,150.4 125.3 714.8 296.9 5,419.0 61.0 1,822.5 1,883.5 0.0 114.5 58.7 (27.2) 98.1 (28.0) 7,518.6 146.0 2029 2,211.6 2,369.8 139.8 740.1 288.6 5,749.8 54.7 1,819.9 1,874.6 0.0 130.8 56.5 (29.1) 98.0 (16.6) 7,863.9 148.6 2030 2,300.1 2,565.4 152.6 766.5 304.2 6,088.8 52.9 1,811.9 1,864.7 0.0 141.7 54.1 (31.1) 97.3 (14.6) 8,200.9 151.2 2031 2,377.1 2,748.8 164.2 793.7 307.7 6,391.6 47.5 1,813.0 1,860.5 0.0 154.0 51.7 (32.6) 96.8 (12.0) 8,509.9 153.1 2032 2,452.3 3,039.0 183.1 823.3 300.2 6,797.9 42.2 1,820.2 1,862.4 0.0 171.2 49.1 (35.6) 96.2 (6.9) 8,934.4 157.2 2033 2,527.8 3,226.7 195.5 851.7 317.6 7,119.3 56.8 1,850.0 1,906.8 0.0 178.5 47.9 (37.6) 95.9 (5.3) 9,305.5 159.7 2034 2,586.0 3,429.0 209.9 881.3 320.6 7,426.9 46.4 2,078.5 2,124.9 0.0 201.7 56.5 (40.9) 95.1 (4.4) 9,859.8 165.4 2035 2,658.1 3,655.5 227.7 911.7 311.0 7,764.1 35.5 2,121.7 2,157.2 0.0 217.7 55.3 (43.6) 94.4 (3.2) 10,241.9 168.1 2036 2,713.1 3,841.2 239.7 947.4 331.4 8,072.9 74.7 2,171.8 2,246.6 0.0 229.8 54.0 (47.2) 93.8 (3.6) 10,646.2 171.3 2037 2,764.9 4,116.9 259.7 959.2 335.8 8,436.5 14.3 2,214.8 2,229.1 0.0 251.5 52.5 (47.2) 93.3 (1.9) 11,013.8 173.2
CPW@ 7.86% (2008-2017) 4,191.7 6,472.0 323.9 2,888.3 338.2 14,214.0 718.2 3,620.0 4,338.3 (122.8) 326.2 166.0 (57.2) 415.1 (0.2) 19,279.4 83.4
(2008-2027) 9,530.1 11,601.5 614.3 4,675.7 1,032.8 27,454.4 944.7 8,107.2 9,051.9 (142.6) 583.3 337.5 (118.5) 807.6 (53.7) 37,919.9 102.1
(2008-2037) 13,141.1 16,034.2 883.0 5,897.4 1,491.8 37,447.5 1,018.9 10,965.8 11,984.7 (142.6) 836.1 417.7 (171.6) 950.7 (70.4) 51,252.0 112.4
APPENDIX 2 TABLE 86. TABLE 87. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SELECTED PLAN (SP/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 50.0 2,155.7 67.0 2009 549.1 787.5 42.1 412.2 8.6 1,799.6 76.8 308.1 384.8 (8.3) 42.5 14.5 (1.2) 81.6 2,313.6 71.1 2010 573.3 736.2 41.5 422.9 20.9 1,794.8 115.7 335.4 451.1 (9.1) 42.2 24.5 (9.5) 82.3 2,376.4 73.1 2011 580.5 770.7 43.5 419.9 28.5 1,843.1 102.9 277.4 380.2 (10.0) 43.4 23.2 (10.0) 107.1 2,377.1 72.9 2012 578.7 683.7 39.7 423.8 30.7 1,756.6 105.2 437.6 542.9 (14.0) 42.5 27.8 (10.5) 134.9 2,480.0 75.4 2013 583.5 686.6 41.6 429.0 49.2 1,789.9 105.8 481.9 587.7 (19.0) 44.3 27.2 (10.9) 115.8 2,535.1 76.6 2014 601.0 779.4 47.5 446.3 66.1 1,940.4 106.2 534.3 640.4 (24.3) 51.0 29.0 (11.7) 134.5 2,759.2 81.3 2015 639.1 790.6 47.9 462.7 76.3 2,016.7 106.6 646.2 752.8 (33.0) 51.8 29.2 (12.3) 160.7 2,966.1 84.8 2016 798.3 857.4 53.3 436.7 103.7 2,249.3 139.4 686.2 825.6 (37.0) 59.0 27.0 (12.8) 220.0 3,331.1 92.5 2017 989.0 1,058.8 67.2 452.0 120.2 2,687.2 165.8 582.0 747.8 (39.2) 64.8 23.8 (13.5) 230.5 3,701.4 99.9 2018 1,184.0 1,210.4 80.7 470.0 163.0 3,108.0 127.4 518.7 646.1 (38.4) 72.8 21.4 (14.4) 241.7 4,037.1 106.1 2019 1,326.5 1,223.1 82.2 485.2 180.0 3,297.1 122.0 561.6 683.6 (5.2) 75.5 20.7 (15.4) 252.7 4,308.9 110.5 2020 1,589.1 1,428.3 103.1 508.8 192.2 3,821.5 67.5 449.4 516.8 (2.6) 80.9 18.1 (16.6) 263.6 4,681.7 117.3 2021 1,885.2 1,508.2 113.2 539.0 239.1 4,284.7 67.8 555.1 623.0 0.0 89.4 23.6 (17.7) 274.7 5,277.6 129.3 2022 2,171.9 1,523.3 114.5 575.6 254.6 4,639.9 61.5 534.9 596.4 0.0 95.2 22.7 (19.1) 286.0 5,621.1 134.6 2023 2,177.4 1,355.6 100.2 622.4 247.3 4,502.9 20.6 714.3 734.8 0.0 80.3 26.5 (20.8) 298.4 5,622.1 131.6 2024 2,026.1 1,399.9 101.8 646.7 240.2 4,414.7 24.4 715.2 739.7 0.0 79.3 25.6 (22.0) 310.8 5,547.9 127.1 2025 2,040.1 1,424.8 103.6 663.6 235.5 4,467.5 52.1 933.8 985.9 0.0 85.6 32.1 (23.4) 323.5 5,871.1 131.6 2026 2,080.6 1,560.1 116.6 682.5 249.3 4,689.1 57.5 936.3 993.7 0.0 92.4 30.8 (24.7) 262.4 6,043.8 132.2 2027 2,129.3 1,700.5 127.9 700.8 252.4 4,911.0 51.1 951.2 1,002.2 0.0 101.9 30.4 (25.7) 258.3 6,278.0 134.0 2028 2,200.3 1,806.7 137.6 725.1 245.6 5,115.4 60.4 956.1 1,016.4 0.0 113.9 29.1 (27.1) 258.7 6,506.4 135.6 2029 2,277.8 1,978.7 151.9 750.7 261.8 5,420.8 47.9 955.0 1,002.9 0.0 128.5 27.6 (29.0) 251.9 6,802.8 138.0 2030 2,343.8 2,126.4 164.3 776.7 265.6 5,676.8 61.3 947.3 1,008.6 0.0 138.3 26.1 (31.0) 243.1 7,061.8 139.8 2031 2,404.8 2,262.7 175.3 803.6 259.8 5,906.2 48.6 948.5 997.1 0.0 148.7 24.5 (32.6) 232.8 7,276.7 140.7 2032 2,478.1 2,476.4 193.0 833.5 277.7 6,258.7 36.9 953.5 990.4 0.0 164.8 22.8 (35.6) 220.5 7,621.7 144.3 2033 2,552.2 2,613.1 204.5 862.2 281.6 6,513.6 44.6 981.6 1,026.2 0.0 171.0 22.7 (37.6) 206.4 7,902.4 146.0 2034 2,587.2 2,748.7 218.1 891.3 273.9 6,719.2 51.7 1,180.6 1,232.3 0.0 192.1 32.4 (40.9) 189.4 8,324.5 150.4 2035 2,620.0 2,926.3 234.2 920.5 291.6 6,992.6 58.3 1,218.3 1,276.6 0.0 206.9 32.3 (43.6) 170.0 8,634.7 152.6 2036 2,683.4 3,058.3 246.0 956.7 297.5 7,241.8 15.0 1,260.7 1,275.7 0.0 218.2 32.1 (47.1) 147.6 8,868.4 153.8 2037 2,727.3 3,257.1 264.7 968.5 290.2 7,507.9 71.5 1,260.7 1,370.7 0.0 237.3 31.9 (47.2) 122.1 9,222.7 156.3
CPW@ 7.86% (2008-2017) 4,181.6 5,247.4 304.9 2,887.9 294.8 12,916.7 709.9 2,883.8 3,593.7 (122.8) 313.9 155.8 (57.4) 813.7 17,613.7 77.9
(2008-2027) 9,872.7 9,715.2 628.2 4,701.0 990.2 25,907.3 934.2 4,950.2 5,884.4 (142.6) 580.0 232.9 (118.1) 1,683.5 34,027.4 95.0
(2008-2037) 13,518.1 13,324.9 911.3 5,937.6 1,393.8 35,085.7 1,008.8 6,502.3 7,511.1 (142.6) 823.4 274.2 (171.2) 2,000.7 45,381.5 103.9
APPENDIX 2 TABLE 87. TABLE 88. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% DEFAULT SUPPLY SIDE SCENARIO (SS-D/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 597.5 865.6 52.3 446.3 66.1 2,027.9 116.3 463.3 579.5 (24.3) 56.6 24.8 (11.6) 54.9 2,707.7 77.2 2015 629.5 899.8 54.6 462.7 89.7 2,136.3 153.0 526.2 679.2 (33.0) 60.3 22.1 (12.1) 58.3 2,911.0 80.2 2016 830.9 991.0 63.1 439.7 138.4 2,463.0 165.0 548.2 713.2 (37.0) 69.2 19.2 (12.6) 93.4 3,308.3 88.1 2017 1,021.9 1,223.2 79.9 457.9 176.0 2,958.9 159.6 435.7 595.3 (39.2) 77.1 16.1 (13.4) 100.0 3,694.8 95.2 2018 1,139.3 1,401.4 94.8 476.5 185.3 3,297.3 123.1 370.0 493.1 (38.4) 87.4 13.8 (14.2) 107.3 3,946.2 98.7 2019 1,176.3 1,430.0 97.3 491.8 181.0 3,376.5 125.2 413.2 538.4 (5.2) 91.0 13.2 (15.2) 114.3 4,113.0 100.0 2020 1,331.8 1,669.3 120.4 516.2 193.5 3,831.2 68.3 290.2 358.5 (2.6) 99.2 10.8 (16.5) 121.1 4,401.6 104.2 2021 1,562.5 1,742.4 135.6 550.2 200.1 4,190.8 63.1 395.9 459.1 0.0 105.9 16.4 (17.5) 127.8 4,882.5 112.7 2022 1,704.7 1,898.3 152.3 575.4 196.1 4,526.7 52.2 371.3 423.5 0.0 124.0 15.6 (18.8) 134.8 5,205.8 117.2 2023 1,685.9 1,941.1 155.5 595.0 191.6 4,569.1 46.4 550.8 597.1 0.0 121.4 19.6 (20.1) 142.6 5,429.7 119.2 2024 1,701.1 2,068.4 166.3 608.2 205.5 4,749.5 46.7 551.3 598.1 0.0 127.8 18.8 (21.1) 150.3 5,623.3 120.6 2025 1,769.1 2,142.4 173.7 625.9 210.9 4,922.0 47.3 770.2 817.5 0.0 140.3 25.5 (22.3) 158.2 6,041.1 126.5 2026 1,824.7 2,305.2 186.7 644.3 205.5 5,166.4 51.5 772.8 824.3 0.0 150.0 24.4 (23.8) 92.2 6,233.4 127.2 2027 1,927.7 2,427.0 204.5 665.8 200.8 5,425.8 22.1 787.7 809.8 0.0 158.5 24.2 (24.8) 92.2 6,485.7 129.1 2028 2,034.7 2,592.0 224.4 692.3 216.8 5,760.1 38.3 792.3 830.6 0.0 174.1 23.0 (26.1) 98.1 6,859.7 133.2 2029 2,095.7 2,781.9 241.1 716.1 222.0 6,056.8 53.9 791.6 845.5 0.0 191.6 21.8 (28.1) 98.0 7,185.6 135.8 2030 2,237.1 2,940.0 263.4 746.2 253.9 6,440.5 17.5 783.7 801.2 0.0 201.0 20.5 (30.1) 97.3 7,530.4 138.8 2031 2,342.7 3,110.9 283.9 775.5 267.1 6,780.1 36.0 785.1 821.0 0.0 217.6 19.2 (31.7) 96.8 7,903.0 142.2 2032 2,389.4 3,336.8 306.5 803.2 284.4 7,120.4 54.0 789.7 843.7 0.0 234.8 17.8 (34.8) 96.2 8,278.0 145.7 2033 2,481.4 3,529.2 325.8 831.2 289.2 7,456.9 44.3 818.1 862.4 0.0 247.3 17.9 (36.9) 95.9 8,643.5 148.4 2034 2,565.6 3,673.7 345.1 860.8 281.9 7,727.1 34.4 1,017.1 1,051.5 0.0 267.5 27.9 (40.2) 95.1 9,128.9 153.2 2035 2,624.0 3,866.8 363.0 889.7 273.0 8,016.6 49.1 1,054.9 1,104.0 0.0 283.4 28.1 (42.9) 94.4 9,483.6 155.6 2036 2,695.6 4,047.2 380.9 925.1 294.4 8,343.2 13.8 1,096.9 1,110.7 0.0 299.7 28.3 (46.3) 93.8 9,829.3 158.1 2037 2,743.5 4,296.8 409.6 935.9 300.5 8,686.4 78.1 1,135.7 1,213.9 0.0 325.2 28.5 (46.6) 93.3 10,300.6 162.0
CPW@ 7.86% (2008-2017) 4,206.2 5,601.6 327.4 2,892.2 345.9 13,373.2 751.2 2,662.1 3,413.3 (122.8) 338.4 141.9 (57.0) 415.1 17,502.2 75.7
(2008-2027) 9,048.0 11,407.9 775.0 4,672.1 965.3 26,868.4 975.4 4,225.8 5,201.2 (142.6) 704.8 196.7 (116.3) 807.6 33,519.7 90.2
(2008-2037) 12,573.7 16,319.5 1,223.9 5,862.1 1,356.1 37,335.3 1,036.7 5,534.6 6,571.3 (142.6) 1,053.1 230.5 (168.1) 950.7 45,830.2 100.5
APPENDIX 2 TABLE 88. TABLE 89. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% NUCLEAR SUPPLY SIDE SCENARIO (SS-N/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 600.3 865.6 52.3 446.3 66.1 2,030.7 116.3 463.3 579.5 (24.3) 56.6 24.8 (11.6) 54.9 2,710.5 77.3 2015 637.1 899.8 54.6 462.7 89.7 2,143.9 153.0 526.2 679.2 (33.0) 60.3 22.1 (12.1) 58.3 2,918.7 80.4 2016 864.3 991.0 63.1 439.7 138.4 2,496.4 165.0 548.2 713.2 (37.0) 69.2 19.2 (12.6) 93.4 3,341.8 89.0 2017 1,104.5 1,223.2 79.9 457.9 176.0 3,041.5 159.6 435.7 595.3 (39.2) 77.1 16.1 (13.4) 100.0 3,777.4 97.4 2018 1,285.6 1,401.4 94.8 476.5 185.3 3,443.6 123.1 370.0 493.1 (38.4) 87.4 13.8 (14.2) 107.3 4,092.5 102.4 2019 1,401.2 1,430.0 97.3 491.8 181.0 3,601.4 125.2 413.2 538.4 (5.2) 91.0 13.2 (15.2) 114.3 4,337.9 105.5 2020 1,647.9 1,669.3 120.4 516.2 193.5 4,147.3 68.3 290.2 358.5 (2.6) 99.2 10.8 (16.5) 121.1 4,717.7 111.7 2021 1,941.9 1,761.2 132.0 547.7 232.0 4,614.8 59.4 397.9 457.4 0.0 108.1 16.4 (17.5) 127.8 5,307.0 122.5 2022 2,197.7 1,825.3 137.5 581.9 243.2 4,985.6 52.6 371.4 423.9 0.0 118.7 15.6 (18.9) 134.8 5,659.8 127.4 2023 2,188.7 1,703.2 128.0 622.9 236.2 4,879.1 27.0 550.8 577.8 0.0 104.7 19.6 (20.3) 142.6 5,703.5 125.3 2024 2,071.2 1,771.2 134.0 645.2 247.5 4,869.2 32.8 551.4 584.1 0.0 105.6 18.8 (21.4) 150.3 5,706.6 122.4 2025 2,108.9 1,822.5 138.3 663.2 252.1 4,984.9 48.2 770.2 818.5 0.0 115.9 25.5 (22.7) 158.2 6,080.3 127.3 2026 2,156.1 1,984.7 151.3 682.6 245.8 5,220.6 52.4 772.8 825.2 0.0 123.9 24.4 (24.1) 92.2 6,262.2 127.8 2027 2,252.8 2,122.2 167.6 705.3 239.8 5,487.7 23.0 787.7 810.7 0.0 133.6 24.2 (25.2) 92.2 6,523.3 129.8 2028 2,335.9 2,253.8 182.7 732.3 233.8 5,738.5 59.5 792.3 851.8 0.0 146.0 23.0 (26.5) 98.1 6,830.9 132.6 2029 2,393.6 2,444.6 199.7 757.5 227.7 6,023.1 53.3 791.5 844.8 0.0 163.5 21.8 (28.4) 98.0 7,122.8 134.6 2030 2,534.2 2,588.3 218.9 789.4 244.4 6,375.1 17.0 783.7 800.7 0.0 172.4 20.5 (30.4) 97.3 7,435.6 137.1 2031 2,604.0 2,740.6 236.8 819.2 249.1 6,649.8 57.8 785.1 842.9 0.0 185.3 19.2 (31.9) 96.8 7,762.0 139.6 2032 2,643.2 2,977.1 257.9 848.4 243.4 6,969.9 52.1 789.7 841.7 0.0 203.2 17.8 (35.1) 96.2 8,093.8 142.4 2033 2,735.5 3,139.1 273.6 878.4 262.4 7,288.9 42.6 818.1 860.7 0.0 212.9 17.9 (37.1) 95.9 8,439.2 144.9 2034 2,804.2 3,289.2 291.9 909.4 267.0 7,561.7 32.7 1,017.1 1,049.9 0.0 235.0 27.9 (40.4) 95.1 8,929.1 149.8 2035 2,847.3 3,488.3 310.1 939.8 257.8 7,843.2 47.6 1,054.9 1,102.4 0.0 251.3 28.1 (43.1) 94.4 9,276.4 152.2 2036 2,904.6 3,651.4 325.3 976.6 280.5 8,138.4 12.4 1,096.9 1,109.3 0.0 265.5 28.3 (46.5) 93.8 9,588.7 154.2 2037 2,942.3 3,880.8 349.5 989.0 287.2 8,448.8 76.7 1,135.7 1,212.4 0.0 289.0 28.5 (46.7) 93.3 10,025.3 157.6
CPW@ 7.86% (2008-2017) 4,267.7 5,601.6 327.4 2,892.2 345.9 13,434.7 751.2 2,662.1 3,413.3 (122.8) 338.4 141.9 (57.0) 415.1 17,563.7 76.0
(2008-2027) 10,161.6 11,012.8 726.4 4,719.3 1,045.1 27,665.1 965.3 4,226.5 5,191.8 (142.6) 674.8 196.7 (116.7) 807.6 34,276.7 92.3
(2008-2037) 14,075.3 15,378.1 1,103.1 5,976.8 1,419.4 37,952.7 1,033.0 5,535.3 6,568.3 (142.6) 976.6 230.5 (168.9) 950.7 46,367.3 101.7
APPENDIX 2 TABLE 89. TABLE 90. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 597.5 828.1 50.6 446.3 66.1 1,988.5 106.2 568.6 674.7 (24.3) 53.9 30.0 (11.7) 54.9 2,766.0 78.9 2015 629.5 830.0 50.5 462.7 89.7 2,062.4 112.3 733.3 845.6 (33.0) 54.7 32.6 (12.2) 58.3 3,008.4 82.9 2016 755.9 877.6 55.5 436.7 123.4 2,249.0 141.7 870.2 1,011.9 (37.0) 60.7 35.1 (12.7) 93.4 3,400.3 90.6 2017 871.2 1,053.4 67.6 451.5 153.3 2,597.0 158.1 878.7 1,036.8 (39.2) 64.2 37.5 (13.5) 100.0 3,782.9 97.5 2018 936.7 1,174.3 78.2 467.5 162.7 2,819.3 128.7 933.5 1,062.1 (38.4) 70.4 40.8 (14.4) 107.3 4,047.2 101.2 2019 940.0 1,157.9 77.2 480.9 158.1 2,814.0 125.5 1,095.9 1,221.4 (5.2) 70.6 45.8 (15.4) 114.3 4,245.5 103.2 2020 1,038.2 1,333.0 90.5 500.3 171.4 3,133.4 66.2 1,118.6 1,184.8 (2.6) 75.4 49.2 (16.7) 121.1 4,544.5 107.6 2021 1,210.1 1,427.8 98.2 527.7 195.2 3,459.0 70.2 1,225.4 1,295.5 0.0 85.5 54.2 (17.7) 127.8 5,004.4 115.5 2022 1,343.7 1,580.2 108.6 549.9 200.0 3,782.3 63.1 1,205.4 1,268.5 0.0 103.7 52.8 (19.0) 134.8 5,323.1 119.8 2023 1,337.6 1,618.9 112.6 568.7 194.7 3,832.5 57.0 1,384.8 1,441.8 0.0 100.7 56.1 (20.4) 142.6 5,553.3 122.0 2024 1,365.3 1,738.2 121.5 581.1 189.9 3,996.0 57.0 1,386.9 1,443.9 0.0 105.6 54.6 (21.3) 150.3 5,729.1 122.8 2025 1,445.7 1,808.6 127.6 598.0 206.7 4,186.7 57.3 1,604.3 1,661.6 0.0 118.7 60.6 (22.6) 158.2 6,163.2 129.1 2026 1,531.0 1,961.2 139.0 616.2 211.3 4,458.7 50.0 1,606.8 1,656.8 0.0 127.6 58.7 (24.0) 92.2 6,370.1 130.0 2027 1,604.0 2,108.2 151.4 633.0 206.7 4,703.2 45.1 1,621.7 1,666.8 0.0 137.9 57.7 (25.0) 92.2 6,632.8 132.0 2028 1,685.0 2,288.6 165.9 655.3 223.0 5,017.8 60.5 1,627.8 1,688.3 0.0 156.1 55.6 (26.3) 98.1 6,989.6 135.7 2029 1,778.4 2,467.6 180.7 678.7 227.2 5,332.8 54.2 1,625.6 1,679.8 0.0 173.0 53.4 (28.3) 98.0 7,308.7 138.1 2030 1,946.1 2,612.8 200.1 708.2 221.3 5,688.5 17.3 1,617.7 1,635.1 0.0 181.4 51.1 (30.3) 97.3 7,623.1 140.5 2031 2,063.4 2,773.4 219.7 736.4 255.1 6,047.9 35.4 1,619.1 1,654.5 0.0 196.6 48.8 (31.8) 96.8 8,012.7 144.1 2032 2,120.6 3,001.2 238.8 762.9 292.5 6,416.0 53.4 1,625.3 1,678.7 0.0 214.6 46.2 (35.0) 96.2 8,416.7 148.1 2033 2,222.0 3,191.2 256.0 789.7 297.3 6,756.2 43.8 1,652.1 1,695.9 0.0 225.3 45.1 (37.0) 95.9 8,781.4 150.7 2034 2,314.7 3,351.1 273.3 818.1 289.9 7,047.0 33.9 1,851.1 1,885.0 0.0 246.9 53.8 (40.3) 95.1 9,287.5 155.8 2035 2,381.5 3,524.3 289.7 845.7 307.6 7,348.8 48.5 1,888.9 1,937.3 0.0 263.3 52.7 (43.0) 94.4 9,653.5 158.4 2036 2,462.9 3,698.7 305.5 879.7 313.6 7,660.3 13.2 1,932.4 1,945.6 0.0 277.6 51.4 (46.5) 93.8 9,982.2 160.6 2037 2,521.9 3,960.2 331.3 889.2 306.5 8,009.1 77.6 1,969.7 2,047.3 0.0 305.2 50.1 (46.7) 93.3 10,458.4 164.4
CPW@ 7.86% (2008-2017) 4,097.5 5,404.3 314.5 2,887.7 327.6 13,031.6 710.6 3,207.9 3,918.6 (122.8) 323.4 168.8 (57.1) 415.1 17,677.5 76.5
(2008-2027) 7,987.2 10,240.2 648.6 4,600.9 917.4 24,394.4 955.8 7,232.7 8,188.5 (142.6) 624.0 333.2 (117.0) 807.6 34,088.2 91.7
(2008-2037) 11,097.6 14,663.4 997.9 5,730.6 1,313.2 33,802.8 1,021.1 9,782.5 10,803.7 (142.6) 942.5 409.1 (169.1) 950.7 46,597.1 102.2
APPENDIX 2 TABLE 90. TABLE 91. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 597.5 833.0 50.4 446.3 66.1 1,993.3 106.2 559.4 665.6 (24.3) 54.3 29.8 (11.7) 54.9 2,761.8 78.8 2015 629.5 837.6 50.4 462.7 89.7 2,069.9 116.6 715.0 831.6 (33.0) 55.4 32.2 (12.2) 58.3 3,002.3 82.7 2016 780.9 906.8 57.0 437.7 137.8 2,320.2 143.2 787.0 930.2 (37.0) 62.5 31.6 (12.7) 93.4 3,388.1 90.3 2017 899.9 1,067.6 67.8 452.7 160.2 2,648.3 157.5 839.7 997.2 (39.2) 65.5 36.7 (13.5) 100.0 3,795.0 97.8 2018 955.1 1,190.2 79.2 468.4 161.3 2,854.1 131.6 884.8 1,016.4 (38.4) 72.0 39.8 (14.4) 107.3 4,036.8 101.0 2019 957.6 1,179.2 78.4 481.8 172.6 2,869.7 132.3 1,035.6 1,167.9 (5.2) 72.6 44.6 (15.5) 114.3 4,248.4 103.3 2020 1,069.4 1,361.0 92.0 501.9 177.6 3,201.9 67.5 1,043.7 1,111.2 (2.6) 77.6 47.6 (16.7) 121.1 4,540.1 107.5 2021 1,250.1 1,443.7 98.6 529.7 193.1 3,515.2 61.7 1,183.2 1,244.9 0.0 86.5 54.6 (17.8) 127.8 5,011.4 115.6 2022 1,382.1 1,594.2 109.7 551.9 198.3 3,836.2 51.6 1,166.0 1,217.6 0.0 104.8 53.2 (19.1) 134.8 5,327.5 119.9 2023 1,358.7 1,633.4 113.0 570.3 222.3 3,897.6 56.1 1,345.2 1,401.3 0.0 101.9 56.5 (20.4) 142.6 5,579.5 122.5 2024 1,390.6 1,754.4 122.1 582.8 232.2 4,082.1 52.6 1,347.6 1,400.3 0.0 106.7 55.1 (21.4) 150.3 5,772.9 123.8 2025 1,464.6 1,824.2 128.6 599.6 246.9 4,263.9 56.7 1,564.9 1,621.6 0.0 120.0 61.0 (22.7) 158.2 6,202.1 129.9 2026 1,537.2 1,978.0 140.5 617.4 250.6 4,523.7 56.8 1,567.2 1,624.1 0.0 128.7 59.2 (24.1) 92.2 6,403.6 130.7 2027 1,663.7 2,093.2 156.6 638.6 244.6 4,796.6 19.7 1,582.1 1,601.8 0.0 136.5 58.1 (25.2) 92.2 6,660.1 132.5 2028 1,762.6 2,247.9 175.4 663.6 237.6 5,087.1 56.5 1,588.4 1,644.9 0.0 151.2 56.1 (26.4) 98.1 7,010.9 136.1 2029 1,840.8 2,432.5 190.7 686.8 231.9 5,382.7 50.3 1,586.2 1,636.4 0.0 169.5 53.9 (28.5) 98.0 7,312.1 138.2 2030 2,006.8 2,580.8 210.0 716.5 286.4 5,800.4 13.6 1,578.1 1,591.7 0.0 176.8 51.6 (30.5) 97.3 7,687.4 141.7 2031 2,102.0 2,740.8 229.4 744.1 309.1 6,125.4 54.2 1,579.5 1,633.6 0.0 192.0 49.2 (32.0) 96.8 8,065.1 145.1 2032 2,165.3 2,964.3 248.5 771.1 300.8 6,450.0 48.5 1,586.1 1,634.6 0.0 210.2 46.7 (35.2) 96.2 8,402.5 147.8 2033 2,280.7 3,149.9 265.1 798.8 317.7 6,812.1 39.1 1,612.5 1,651.6 0.0 220.9 45.6 (37.2) 95.9 8,789.0 150.9 2034 2,349.3 3,296.0 281.9 826.5 321.9 7,075.7 53.8 1,811.6 1,865.4 0.0 240.5 54.3 (40.6) 95.1 9,290.4 155.9 2035 2,423.1 3,479.4 298.5 854.7 311.9 7,367.5 42.6 1,849.3 1,891.9 0.0 256.0 53.2 (43.3) 94.4 9,619.8 157.9 2036 2,520.4 3,642.1 315.0 889.6 332.0 7,699.1 31.6 1,893.0 1,924.7 0.0 269.8 52.0 (46.7) 93.8 9,992.6 160.7 2037 2,578.3 3,896.3 340.4 899.4 337.8 8,052.2 95.2 1,930.2 2,025.4 0.0 297.7 50.6 (46.8) 93.3 10,472.5 164.7
CPW@ 7.86% (2008-2017) 4,123.6 5,432.9 315.2 2,888.8 338.2 13,098.6 713.4 3,132.2 3,845.6 (122.8) 325.6 166.3 (57.2) 415.1 17,671.2 76.5
(2008-2027) 8,099.1 10,318.2 653.3 4,607.6 982.2 24,660.5 950.9 7,005.3 7,956.3 (142.6) 630.1 330.0 (117.3) 807.6 34,124.6 91.8
(2008-2037) 11,290.7 14,678.7 1,016.7 5,750.1 1,416.1 34,152.4 1,021.4 9,496.5 10,517.9 (142.6) 940.8 406.7 (169.7) 950.7 46,656.1 102.3
APPENDIX 2 TABLE 91. TABLE 92. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SUPPLY SIDE SCENARIO 1 (SS-1/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 599.7 847.3 51.3 446.3 66.1 2,010.8 107.9 515.7 623.6 (24.3) 55.3 27.4 (11.6) 54.9 2,736.0 78.0 2015 635.5 865.0 52.4 462.7 89.7 2,105.3 130.6 629.1 759.7 (33.0) 57.4 27.4 (12.2) 58.3 2,963.0 81.6 2016 819.9 934.6 59.4 438.2 137.8 2,389.9 154.6 704.3 858.9 (37.0) 64.7 26.8 (12.7) 93.4 3,384.0 90.2 2017 1,025.0 1,159.4 75.5 455.2 160.8 2,875.9 161.2 595.8 757.0 (39.2) 72.4 23.7 (13.4) 100.0 3,776.5 97.4 2018 1,195.6 1,332.5 89.9 473.7 177.6 3,269.3 124.7 531.8 656.5 (38.4) 81.9 21.3 (14.3) 107.3 4,083.7 102.1 2019 1,297.4 1,359.1 92.1 489.0 181.5 3,419.2 126.7 575.8 702.4 (5.2) 85.5 20.6 (15.2) 114.3 4,321.6 105.1 2020 1,527.6 1,592.1 114.7 513.3 194.0 3,941.7 69.7 456.0 525.7 (2.6) 93.3 18.0 (16.5) 121.1 4,680.7 110.8 2021 1,793.0 1,685.4 126.0 544.1 225.3 4,373.8 70.5 563.4 633.9 0.0 102.3 23.5 (17.5) 127.8 5,243.8 121.0 2022 2,033.2 1,765.7 132.9 576.2 233.5 4,741.6 56.8 538.8 595.7 0.0 114.5 22.6 (18.9) 134.8 5,590.2 125.8 2023 2,033.9 1,676.6 126.0 613.1 227.2 4,676.8 29.4 718.3 747.7 0.0 102.9 26.4 (20.3) 142.6 5,676.1 124.7 2024 1,936.9 1,755.8 132.4 633.0 221.4 4,679.6 39.9 719.3 759.2 0.0 104.7 25.5 (21.4) 150.3 5,697.7 122.2 2025 1,978.4 1,810.2 137.1 650.6 236.4 4,812.7 55.2 937.8 993.0 0.0 115.5 32.0 (22.7) 158.2 6,088.7 127.5 2026 2,047.3 1,971.2 149.8 670.3 240.5 5,079.1 48.0 940.3 988.3 0.0 123.4 30.7 (24.1) 92.2 6,289.6 128.4 2027 2,159.4 2,102.5 166.1 693.1 234.7 5,355.8 11.1 955.2 966.3 0.0 132.7 30.4 (25.1) 92.2 6,552.3 130.4 2028 2,245.0 2,239.5 182.0 719.8 228.0 5,614.2 48.1 960.1 1,008.2 0.0 145.6 29.0 (26.5) 98.1 6,868.6 133.4 2029 2,306.2 2,427.7 198.4 744.6 222.6 5,899.5 42.2 959.0 1,001.3 0.0 162.9 27.6 (28.4) 98.0 7,160.8 135.3 2030 2,451.3 2,601.8 213.7 776.1 239.9 6,282.7 6.0 951.3 957.3 0.0 174.9 26.1 (30.4) 97.3 7,507.9 138.4 2031 2,525.6 2,763.6 228.9 805.5 283.4 6,607.1 47.1 952.6 999.6 0.0 190.0 24.5 (31.9) 96.8 7,886.1 141.9 2032 2,568.5 2,998.5 249.2 834.3 295.3 6,945.9 41.7 958.2 1,000.0 0.0 207.5 22.8 (35.0) 96.2 8,237.4 144.9 2033 2,642.6 3,167.5 265.2 863.1 312.4 7,250.8 56.2 985.6 1,041.8 0.0 217.5 22.7 (37.0) 95.9 8,591.8 147.5 2034 2,700.5 3,325.0 283.3 893.0 316.7 7,518.5 45.8 1,184.8 1,230.5 0.0 240.6 32.4 (40.3) 95.1 9,076.8 152.3 2035 2,748.7 3,518.5 301.5 922.9 307.8 7,799.4 60.1 1,222.4 1,282.5 0.0 256.7 32.3 (43.0) 94.4 9,422.3 154.6 2036 2,810.9 3,683.0 316.5 959.2 328.5 8,098.1 24.6 1,264.9 1,289.4 0.0 271.3 32.2 (46.5) 93.8 9,738.3 156.6 2037 2,877.7 3,923.8 340.9 972.0 333.2 8,447.6 14.1 1,303.3 1,317.5 0.0 295.4 32.0 (46.7) 93.3 10,139.1 159.4
CPW@ 7.86% (2008-2017) 4,206.7 5,513.4 321.6 2,890.2 338.5 13,270.3 729.6 2,903.3 3,632.9 (122.8) 331.6 153.7 (57.0) 415.1 17,623.8 76.3
(2008-2027) 9,707.0 10,768.8 708.7 4,695.6 1,013.0 26,893.0 951.5 4,992.9 5,944.4 (142.6) 656.6 230.6 (116.8) 807.6 34,272.8 92.2
(2008-2037) 13,491.6 15,157.6 1,076.3 5,931.5 1,427.3 37,084.3 1,009.5 6,551.2 7,560.7 (142.6) 963.4 271.8 (168.9) 950.7 46,519.3 102.0
APPENDIX 2 TABLE 92. TABLE 93. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SUPPLY SIDE SCENARIO 2 (SS-2/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 600.4 837.3 50.8 446.3 66.1 2,000.9 106.2 545.0 651.2 (24.3) 54.7 29.0 (11.7) 54.9 2,754.7 78.6 2015 637.3 846.7 51.1 462.7 89.7 2,087.5 120.9 686.8 807.7 (33.0) 56.0 30.6 (12.2) 58.3 2,994.9 82.5 2016 802.8 902.3 56.8 437.2 137.8 2,336.8 152.0 798.3 950.3 (37.0) 62.0 32.0 (12.7) 93.4 3,424.7 91.2 2017 1,003.1 1,110.7 71.1 453.4 160.2 2,798.5 161.9 722.5 884.4 (39.2) 68.6 30.5 (13.5) 100.0 3,829.3 98.7 2018 1,177.2 1,267.3 84.5 471.3 161.9 3,162.3 126.7 688.5 815.2 (38.4) 77.4 29.7 (14.3) 107.3 4,139.1 103.5 2019 1,304.3 1,294.3 86.8 486.7 174.2 3,346.4 122.6 732.0 854.6 (5.2) 80.8 28.8 (15.3) 114.3 4,404.4 107.1 2020 1,539.1 1,540.5 105.3 508.3 195.4 3,888.5 65.4 619.9 685.3 (2.6) 90.5 26.1 (16.6) 121.1 4,792.3 113.5 2021 1,834.3 1,616.6 117.3 539.8 234.2 4,342.1 64.3 724.5 788.8 0.0 98.1 31.5 (17.6) 127.8 5,370.7 123.9 2022 2,111.1 1,662.0 124.8 576.1 245.5 4,719.5 58.8 702.9 761.6 0.0 106.1 30.4 (19.0) 134.8 5,733.4 129.0 2023 2,108.6 1,541.5 115.5 617.7 238.5 4,621.8 31.2 882.2 913.5 0.0 93.8 34.1 (20.6) 142.6 5,785.2 127.0 2024 1,992.5 1,604.8 120.2 640.2 231.5 4,589.3 36.1 883.6 919.7 0.0 94.7 33.0 (21.7) 150.3 5,765.3 123.6 2025 2,034.1 1,650.4 124.0 658.0 227.8 4,694.3 51.5 1,101.7 1,153.3 0.0 103.9 39.3 (23.0) 158.2 6,126.1 128.3 2026 2,085.1 1,804.3 137.2 677.3 242.2 4,946.1 55.7 1,104.2 1,159.9 0.0 111.3 37.9 (24.4) 92.2 6,323.0 129.1 2027 2,131.6 1,965.4 149.2 695.3 245.5 5,186.9 58.2 1,119.2 1,177.3 0.0 123.3 37.3 (25.4) 92.2 6,591.7 131.2 2028 2,218.6 2,092.0 161.2 720.2 239.7 5,431.7 52.7 1,124.4 1,177.1 0.0 135.6 35.8 (26.6) 98.1 6,851.5 133.0 2029 2,307.2 2,284.8 176.2 746.2 233.9 5,748.2 46.7 1,123.0 1,169.7 0.0 153.4 34.1 (28.6) 98.0 7,174.8 135.6 2030 2,451.3 2,422.9 194.7 777.7 250.4 6,097.0 10.3 1,115.2 1,125.4 0.0 160.8 32.4 (30.6) 97.3 7,482.3 137.9 2031 2,524.4 2,571.9 211.9 807.1 255.0 6,370.4 51.1 1,116.5 1,167.6 0.0 174.1 30.6 (32.1) 96.8 7,807.3 140.4 2032 2,565.9 2,806.4 231.8 836.0 248.1 6,688.2 45.7 1,122.0 1,167.7 0.0 191.7 28.7 (35.3) 96.2 8,137.3 143.2 2033 2,660.2 2,964.5 246.0 865.6 267.6 7,004.0 36.5 1,149.6 1,186.0 0.0 200.2 28.3 (37.3) 95.9 8,477.1 145.5 2034 2,708.2 3,118.5 263.1 895.4 315.6 7,300.8 51.1 1,348.6 1,399.7 0.0 221.8 37.6 (40.6) 95.1 9,014.5 151.3 2035 2,762.1 3,309.4 281.3 925.6 326.5 7,604.9 40.0 1,386.3 1,426.3 0.0 238.4 37.3 (43.3) 94.4 9,357.9 153.6 2036 2,815.4 3,468.7 295.7 961.7 346.1 7,887.6 79.0 1,429.1 1,508.1 0.0 252.3 36.8 (46.7) 93.8 9,731.8 156.5 2037 2,863.9 3,691.5 317.6 973.9 351.5 8,198.4 18.5 1,467.2 1,485.6 0.0 274.9 36.3 (46.9) 93.3 10,041.7 157.9
CPW@ 7.86% (2008-2017) 4,189.1 5,458.3 317.2 2,888.8 338.2 13,191.6 722.3 3,059.1 3,781.3 (122.8) 327.4 162.2 (57.1) 415.1 17,697.7 76.6
(2008-2027) 9,782.6 10,389.8 674.0 4,696.3 1,017.1 26,559.9 951.0 5,661.0 6,612.0 (142.6) 629.9 263.8 (117.3) 807.6 34,613.3 93.2
(2008-2037) 13,565.6 14,501.7 1,012.0 5,934.9 1,425.7 36,439.9 1,014.9 7,463.1 8,478.0 (142.6) 914.1 313.7 (169.8) 950.7 46,783.9 102.6
APPENDIX 2 TABLE 93. TABLE 94. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SUPPLY SIDE SCENARIO 3 (SS-3/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 2,532.0 74.4 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 545.0 651.2 (24.3) 54.7 29.0 (11.7) 54.9 2,755.4 78.6 2015 639.1 855.8 51.6 462.7 89.7 2,098.9 125.2 660.4 785.6 (33.0) 56.8 29.2 (12.2) 58.3 2,983.7 82.2 2016 835.8 936.2 59.0 438.2 137.8 2,407.0 153.7 701.2 854.9 (37.0) 64.8 27.0 (12.7) 93.4 3,397.3 90.5 2017 1,064.4 1,160.4 75.1 455.2 160.8 2,915.9 164.4 591.5 755.9 (39.2) 72.4 23.8 (13.4) 100.0 3,815.4 98.4 2018 1,265.3 1,333.4 89.8 473.7 177.6 3,339.8 127.7 527.6 655.2 (38.4) 82.2 21.4 (14.3) 107.3 4,153.3 103.9 2019 1,404.5 1,361.8 92.1 489.0 181.5 3,528.9 129.6 570.4 700.0 (5.2) 85.9 20.7 (15.2) 114.3 4,429.4 107.7 2020 1,678.1 1,593.7 114.6 513.3 194.0 4,093.7 72.5 451.8 524.3 (2.6) 93.3 18.1 (16.5) 121.1 4,831.4 114.4 2021 1,995.4 1,686.5 126.1 544.6 240.9 4,593.5 63.5 558.8 622.3 0.0 102.4 23.6 (17.6) 127.8 5,452.1 125.8 2022 2,288.1 1,718.4 129.0 581.8 256.3 4,973.6 57.5 534.9 592.4 0.0 110.3 22.7 (19.0) 134.8 5,814.8 130.9 2023 2,288.8 1,557.1 116.6 628.8 249.0 4,840.3 23.2 714.3 737.5 0.0 94.6 26.5 (20.5) 142.6 5,820.9 127.8 2024 2,132.9 1,609.1 120.0 653.3 241.7 4,757.1 33.4 715.3 748.7 0.0 94.5 25.6 (21.7) 150.3 5,754.4 123.4 2025 2,159.1 1,650.8 124.0 671.0 255.7 4,860.5 56.1 933.8 989.9 0.0 103.3 32.1 (23.0) 158.2 6,120.9 128.2 2026 2,223.5 1,808.0 137.7 691.4 259.1 5,119.7 48.9 936.3 985.1 0.0 110.9 30.8 (24.3) 92.2 6,314.3 128.9 2027 2,332.2 1,949.5 153.1 714.8 252.8 5,402.5 11.9 951.2 963.1 0.0 120.9 30.4 (25.4) 92.2 6,583.7 131.0 2028 2,414.9 2,067.6 167.7 742.1 245.5 5,637.8 48.9 956.1 1,005.0 0.0 132.3 29.1 (26.8) 98.1 6,875.5 133.5 2029 2,471.1 2,257.6 183.8 767.6 239.5 5,919.6 43.0 955.0 998.0 0.0 148.7 27.6 (28.7) 98.0 7,163.2 135.4 2030 2,549.2 2,420.8 197.7 794.9 256.1 6,218.7 41.7 947.2 988.8 0.0 160.1 26.1 (30.7) 97.3 7,460.3 137.5 2031 2,595.6 2,574.3 211.6 822.2 260.4 6,464.0 59.0 948.5 1,007.5 0.0 172.8 24.5 (32.2) 96.8 7,733.4 139.1 2032 2,647.4 2,810.6 231.3 852.1 278.2 6,819.5 53.3 953.6 1,006.9 0.0 190.3 22.8 (35.3) 96.2 8,100.4 142.5 2033 2,737.1 2,965.2 245.5 882.2 283.5 7,113.3 43.8 981.6 1,025.4 0.0 199.1 22.7 (37.3) 95.9 8,419.1 144.5 2034 2,780.7 3,119.5 262.9 912.4 275.0 7,350.4 58.3 1,180.6 1,238.9 0.0 222.4 32.4 (40.5) 95.1 8,898.6 149.3 2035 2,829.6 3,316.0 281.2 943.1 266.6 7,636.5 47.1 1,218.3 1,265.5 0.0 238.1 32.3 (43.3) 94.4 9,223.5 151.4 2036 2,901.6 3,472.3 295.0 980.7 288.3 7,937.9 36.1 1,260.7 1,296.9 0.0 251.9 32.1 (46.7) 93.8 9,565.9 153.9 2037 2,937.4 3,695.6 317.2 993.2 294.1 8,237.4 99.7 1,299.2 1,398.9 0.0 273.7 31.9 (46.9) 93.3 9,988.4 157.0
CPW@ 7.86% (2008-2017) 4,236.0 5,503.7 320.5 2,890.2 338.5 13,288.8 726.6 2,934.0 3,660.7 (122.8) 331.0 155.8 (57.1) 415.1 17,671.5 76.5
(2008-2027) 10,274.6 10,556.9 690.8 4,722.9 1,051.2 27,296.4 946.8 5,010.0 5,956.8 (142.6) 641.0 232.9 (117.2) 807.6 34,674.9 93.3
(2008-2037) 14,215.2 14,661.1 1,031.8 5,988.6 1,445.8 37,342.5 1,023.6 6,562.1 7,585.7 (142.6) 922.8 274.2 (169.8) 950.7 46,763.4 102.6
APPENDIX 2 TABLE 94. TABLE 95. RISK ANALYSIS D - COST OF SOLAR INCREASES 1.5% ANNUALLY, OTHER COST AT 3.0% SUPPLY SIDE SCENARIO 4 (SS-4/D) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 0.0 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 0.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 0.0 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 0.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 0.0 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 493.8 599.6 (19.0) 47.3 27.2 (10.8) 51.4 0.0 2,532.0 74.4 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 545.0 651.2 (24.3) 54.7 29.0 (11.7) 54.9 (0.1) 2,755.3 78.6 2015 639.1 846.7 51.1 462.7 89.7 2,089.4 120.9 686.8 807.7 (33.0) 56.0 30.6 (12.2) 58.3 (0.1) 2,996.7 82.6 2016 810.8 893.6 56.0 437.2 137.8 2,335.4 147.5 827.4 974.9 (37.0) 61.7 33.7 (12.8) 93.4 (0.0) 3,449.3 91.9 2017 996.9 1,067.7 67.8 452.4 160.2 2,745.0 158.0 839.8 997.9 (39.2) 65.5 36.7 (13.5) 100.0 (0.0) 3,892.3 100.3 2018 1,142.4 1,184.6 78.7 468.4 161.3 3,035.4 128.6 900.5 1,029.1 (38.4) 71.6 40.7 (14.4) 107.3 (0.0) 4,231.2 105.8 2019 1,244.7 1,168.9 77.5 481.8 157.3 3,130.3 125.4 1,066.9 1,192.3 (5.2) 71.6 46.4 (15.5) 114.3 (0.9) 4,533.3 110.2 2020 1,458.0 1,342.9 90.4 501.3 170.4 3,562.9 66.1 1,093.3 1,159.5 (2.6) 76.4 50.4 (16.8) 121.1 (1.4) 4,949.5 117.2 2021 1,728.5 1,421.8 96.9 528.7 217.2 3,993.0 63.4 1,240.5 1,304.0 0.0 84.8 57.6 (17.8) 127.8 (2.8) 5,546.6 128.0 2022 2,020.5 1,442.2 98.1 564.9 233.0 4,358.7 59.5 1,224.8 1,284.2 0.0 91.4 56.2 (19.3) 134.8 (2.6) 5,903.4 132.9 2023 2,031.1 1,304.1 86.8 611.4 226.4 4,259.8 25.2 1,403.8 1,428.9 0.0 76.7 59.5 (21.1) 142.6 (20.1) 5,926.3 130.1 2024 1,884.8 1,364.5 90.5 635.4 268.2 4,243.5 35.2 1,406.8 1,442.1 0.0 76.8 57.9 (22.3) 150.3 (36.9) 5,911.5 126.8 2025 1,920.4 1,403.2 93.3 652.5 288.1 4,357.6 57.9 1,623.5 1,681.4 0.0 84.1 63.8 (23.6) 158.2 (39.1) 6,282.5 131.6 2026 1,994.2 1,538.8 104.5 672.4 280.9 4,590.8 50.6 1,625.7 1,676.4 0.0 91.2 61.9 (24.9) 92.2 (28.7) 6,458.8 131.8 2027 2,058.2 1,686.4 115.9 690.8 294.6 4,845.9 45.6 1,640.7 1,686.3 0.0 102.1 60.8 (25.9) 92.2 (24.8) 6,736.7 134.1 2028 2,131.6 1,801.0 125.2 714.8 296.9 5,069.5 61.0 1,647.1 1,708.1 0.0 114.5 58.7 (27.2) 98.1 (21.5) 7,000.1 135.9 2029 2,211.6 1,975.6 139.8 740.1 288.6 5,355.6 54.7 1,644.8 1,699.4 0.0 130.7 56.5 (29.1) 98.0 (12.8) 7,298.4 137.9 2030 2,300.1 2,134.2 152.5 766.5 304.2 5,657.6 52.9 1,636.8 1,689.7 0.0 141.7 54.1 (31.1) 97.3 (11.3) 7,597.9 140.0 2031 2,377.1 2,281.6 164.3 793.7 307.7 5,924.4 47.5 1,638.0 1,685.5 0.0 154.0 51.7 (32.6) 96.8 (9.2) 7,870.4 141.6 2032 2,452.3 2,506.5 183.1 823.3 300.2 6,265.4 42.2 1,644.7 1,687.0 0.0 171.3 49.1 (35.6) 96.2 (5.3) 8,228.1 144.8 2033 2,527.8 2,660.1 195.5 851.7 317.6 6,552.7 56.8 1,671.1 1,727.8 0.0 178.5 47.9 (37.6) 95.9 (4.0) 8,561.2 146.9 2034 2,586.0 2,818.5 210.0 881.3 320.6 6,816.5 46.4 1,870.1 1,916.4 0.0 201.7 56.5 (40.9) 95.1 (3.4) 9,042.0 151.7 2035 2,658.1 3,001.7 227.5 911.7 311.0 7,110.0 35.5 1,907.8 1,943.4 0.0 217.9 55.3 (43.7) 94.4 (2.5) 9,374.9 153.9 2036 2,713.1 3,151.7 239.7 947.4 331.4 7,383.4 74.7 1,951.7 2,026.4 0.0 229.9 54.0 (47.2) 93.8 (2.8) 9,737.5 156.6 2037 2,764.9 3,369.0 259.7 959.2 335.8 7,688.6 14.3 1,988.7 2,003.0 0.0 251.5 52.5 (47.2) 93.3 (1.5) 10,040.3 157.9
CPW@ 7.86% (2008-2017) 4,191.7 5,433.7 315.2 2,888.3 338.2 13,167.1 718.2 3,128.8 3,847.1 (122.8) 325.8 166.0 (57.2) 415.1 (0.1) 17,741.0 76.8
(2008-2027) 9,530.1 9,741.7 604.8 4,675.7 1,032.8 25,585.1 944.7 7,154.3 8,099.1 (142.6) 582.9 337.5 (118.4) 807.6 (41.3) 35,109.9 94.5
(2008-2037) 13,141.1 13,405.3 873.5 5,897.4 1,491.8 34,809.0 1,018.9 9,732.6 10,751.5 (142.6) 835.8 417.7 (171.6) 950.7 (54.2) 47,396.3 104.0
APPENDIX 2 TABLE 95. TABLE 96. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SELECTED PLAN (SP/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 50.0 2,155.7 67.0 2009 549.1 787.5 42.1 412.2 8.6 1,799.6 76.8 308.1 384.8 (8.3) 42.5 14.5 (1.2) 81.6 2,313.6 71.1 2010 573.3 736.2 41.5 422.9 20.9 1,794.8 115.7 335.4 451.1 (9.1) 42.2 24.5 (9.5) 82.3 2,376.4 73.1 2011 580.5 770.7 43.5 419.9 28.5 1,843.1 102.9 277.4 380.2 (10.0) 43.4 23.2 (10.0) 107.1 2,377.1 72.9 2012 578.7 683.7 39.7 423.8 30.7 1,756.6 105.2 437.6 542.9 (14.0) 42.5 27.8 (10.5) 134.9 2,480.0 75.4 2013 583.5 686.6 41.6 429.0 49.2 1,789.9 105.8 484.9 590.7 (19.0) 44.3 27.2 (10.9) 115.8 2,538.1 76.7 2014 601.0 779.4 47.5 446.3 66.1 1,940.4 106.2 545.4 651.5 (24.3) 51.0 29.0 (11.7) 134.5 2,770.3 81.6 2015 639.1 790.6 47.9 462.7 76.3 2,016.7 106.6 663.9 770.4 (33.0) 51.8 29.2 (12.3) 160.7 2,983.7 85.3 2016 798.3 857.4 53.3 436.7 103.7 2,249.3 139.4 705.8 845.2 (37.0) 59.0 27.0 (12.8) 220.0 3,350.6 93.0 2017 989.0 1,058.8 67.2 452.0 120.2 2,687.2 165.8 601.5 767.3 (39.2) 64.8 23.8 (13.5) 230.5 3,720.9 100.4 2018 1,184.0 1,210.4 80.7 470.0 163.0 3,108.0 127.4 538.2 665.6 (38.4) 72.8 21.4 (14.4) 241.7 4,056.6 106.6 2019 1,326.5 1,223.1 82.2 485.2 180.0 3,297.1 122.0 587.6 709.6 (5.2) 75.5 20.7 (15.4) 252.7 4,334.9 111.2 2020 1,589.1 1,428.3 103.1 508.8 192.2 3,821.5 67.5 475.4 542.9 (2.6) 80.9 18.1 (16.6) 263.6 4,707.8 118.0 2021 1,885.2 1,508.2 113.2 539.0 239.1 4,284.7 67.8 593.3 661.2 0.0 89.4 23.6 (17.7) 274.7 5,315.9 130.2 2022 2,171.9 1,523.3 114.5 575.6 254.6 4,639.9 61.5 573.1 634.6 0.0 95.2 22.7 (19.1) 286.0 5,659.3 135.5 2023 2,177.4 1,355.6 100.2 622.4 247.3 4,502.9 20.6 880.7 901.3 0.0 80.3 26.5 (20.8) 298.4 5,788.6 135.5 2024 2,026.1 1,399.9 101.8 646.7 240.2 4,414.7 24.4 882.1 906.5 0.0 79.3 25.6 (22.0) 310.8 5,714.7 130.9 2025 2,040.1 1,424.8 103.6 663.6 235.5 4,467.5 52.1 1,128.8 1,180.9 0.0 85.6 32.1 (23.4) 323.5 6,066.1 135.9 2026 2,080.6 1,560.1 116.6 682.5 249.3 4,689.1 57.5 1,131.3 1,188.7 0.0 92.4 30.8 (24.7) 262.4 6,238.7 136.4 2027 2,129.3 1,700.5 127.9 700.8 252.4 4,911.0 51.1 1,146.2 1,197.2 0.0 101.9 30.4 (25.7) 258.3 6,473.0 138.2 2028 2,200.3 1,806.7 137.6 725.1 245.6 5,115.4 60.4 1,151.5 1,211.8 0.0 113.9 29.1 (27.1) 258.7 6,701.8 139.7 2029 2,277.8 1,978.7 151.9 750.7 261.8 5,420.8 47.9 1,150.0 1,197.9 0.0 128.5 27.6 (29.0) 251.9 6,997.8 142.0 2030 2,343.8 2,126.4 164.3 776.7 265.6 5,676.8 61.3 1,142.3 1,203.6 0.0 138.3 26.1 (31.0) 243.1 7,256.8 143.7 2031 2,404.8 2,262.7 175.3 803.6 259.8 5,906.2 48.6 1,143.5 1,192.1 0.0 148.7 24.5 (32.6) 232.8 7,471.7 144.5 2032 2,478.1 2,476.4 193.0 833.5 277.7 6,258.7 36.9 1,148.9 1,185.8 0.0 164.8 22.8 (35.6) 220.5 7,817.1 148.0 2033 2,552.2 2,613.1 204.5 862.2 281.6 6,513.6 44.6 1,187.6 1,232.2 0.0 171.0 22.7 (37.6) 206.4 8,108.4 149.8 2034 2,587.2 2,748.7 218.1 891.3 273.9 6,719.2 51.7 1,466.8 1,518.5 0.0 192.1 32.4 (40.9) 189.4 8,610.7 155.6 2035 2,620.0 2,926.3 234.2 920.5 291.6 6,992.6 58.3 1,518.9 1,577.2 0.0 206.9 32.3 (43.6) 170.0 8,935.3 158.0 2036 2,683.4 3,058.3 246.0 956.7 297.5 7,241.8 15.0 1,577.4 1,592.4 0.0 218.2 32.1 (47.1) 147.6 9,185.0 159.2 2037 2,727.3 3,257.1 264.7 968.5 290.2 7,507.9 71.5 1,631.6 1,703.1 0.0 237.3 31.9 (47.2) 122.1 9,555.1 162.0
CPW@ 7.86% (2008-2017) 4,181.6 5,247.4 304.9 2,887.9 294.8 12,916.7 709.9 2,920.9 3,630.8 (122.8) 313.9 155.8 (57.4) 813.7 17,650.8 78.1
(2008-2027) 9,872.7 9,715.2 628.2 4,701.0 990.2 25,907.3 934.2 5,276.4 6,210.6 (142.6) 580.0 232.9 (118.1) 1,683.5 34,353.7 95.9
(2008-2037) 13,518.1 13,324.9 911.3 5,937.6 1,393.8 35,085.7 1,008.8 7,172.5 8,181.3 (142.6) 823.4 274.2 (171.2) 2,000.7 46,051.7 105.4
APPENDIX 2 TABLE 96. TABLE 97. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 DEFAULT SUPPLY SIDE SCENARIO (SS-D/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 597.5 865.6 52.3 446.3 66.1 2,027.9 116.3 466.2 582.5 (24.3) 56.6 24.8 (11.6) 54.9 2,710.7 77.3 2015 629.5 899.8 54.6 462.7 89.7 2,136.3 153.0 529.2 682.2 (33.0) 60.3 22.1 (12.1) 58.3 2,914.0 80.3 2016 830.9 991.0 63.1 439.7 138.4 2,463.0 165.0 551.2 716.2 (37.0) 69.2 19.2 (12.6) 93.4 3,311.3 88.2 2017 1,021.9 1,223.2 79.9 457.9 176.0 2,958.9 159.6 438.7 598.3 (39.2) 77.1 16.1 (13.4) 100.0 3,697.8 95.3 2018 1,139.3 1,401.4 94.8 476.5 185.3 3,297.3 123.1 373.0 496.1 (38.4) 87.4 13.8 (14.2) 107.3 3,949.2 98.8 2019 1,176.3 1,430.0 97.3 491.8 181.0 3,376.5 125.2 422.7 547.8 (5.2) 91.0 13.2 (15.2) 114.3 4,122.5 100.2 2020 1,331.8 1,669.3 120.4 516.2 193.5 3,831.2 68.3 299.7 368.0 (2.6) 99.2 10.8 (16.5) 121.1 4,411.1 104.4 2021 1,562.5 1,742.4 135.6 550.2 200.1 4,190.8 63.1 417.6 480.8 0.0 105.9 16.4 (17.5) 127.8 4,904.3 113.2 2022 1,704.7 1,898.3 152.3 575.4 196.1 4,526.7 52.2 393.1 445.3 0.0 124.0 15.6 (18.8) 134.8 5,227.5 117.6 2023 1,685.9 1,941.1 155.5 595.0 191.6 4,569.1 46.4 700.8 747.1 0.0 121.4 19.6 (20.1) 142.6 5,579.7 122.5 2024 1,701.1 2,068.4 166.3 608.2 205.5 4,749.5 46.7 701.6 748.4 0.0 127.8 18.8 (21.1) 150.3 5,773.6 123.8 2025 1,769.1 2,142.4 173.7 625.9 210.9 4,922.0 47.3 948.7 996.0 0.0 140.3 25.5 (22.3) 158.2 6,219.6 130.3 2026 1,824.7 2,305.2 186.7 644.3 205.5 5,166.4 51.5 951.3 1,002.8 0.0 150.0 24.4 (23.8) 92.2 6,411.9 130.9 2027 1,927.7 2,427.0 204.5 665.8 200.8 5,425.8 22.1 966.2 988.3 0.0 158.5 24.2 (24.8) 92.2 6,664.2 132.6 2028 2,034.7 2,592.0 224.4 692.3 216.8 5,760.1 38.3 971.1 1,009.4 0.0 174.1 23.0 (26.1) 98.1 7,038.6 136.7 2029 2,095.7 2,781.9 241.1 716.1 222.0 6,056.8 53.9 970.1 1,024.0 0.0 191.6 21.8 (28.1) 98.0 7,364.1 139.2 2030 2,237.1 2,940.0 263.4 746.2 253.9 6,440.5 17.5 962.2 979.7 0.0 201.0 20.5 (30.1) 97.3 7,708.9 142.1 2031 2,342.7 3,110.9 283.9 775.5 267.1 6,780.1 36.0 963.5 999.5 0.0 217.6 19.2 (31.7) 96.8 8,081.5 145.4 2032 2,389.4 3,336.8 306.5 803.2 284.4 7,120.4 54.0 968.5 1,022.5 0.0 234.8 17.8 (34.8) 96.2 8,456.9 148.8 2033 2,481.4 3,529.2 325.8 831.2 289.2 7,456.9 44.3 1,007.6 1,051.9 0.0 247.3 17.9 (36.9) 95.9 8,833.0 151.6 2034 2,565.6 3,673.7 345.1 860.8 281.9 7,727.1 34.4 1,286.8 1,321.2 0.0 267.5 27.9 (40.2) 95.1 9,398.6 157.7 2035 2,624.0 3,866.8 363.0 889.7 273.0 8,016.6 49.1 1,339.0 1,388.1 0.0 283.4 28.1 (42.9) 94.4 9,767.7 160.3 2036 2,695.6 4,047.2 380.9 925.1 294.4 8,343.2 13.8 1,397.0 1,410.8 0.0 299.7 28.3 (46.3) 93.8 10,129.4 162.9 2037 2,743.5 4,296.8 409.6 935.9 300.5 8,686.4 78.1 1,451.6 1,529.8 0.0 325.2 28.5 (46.6) 93.3 10,616.5 166.9
CPW@ 7.86% (2008-2017) 4,206.2 5,601.6 327.4 2,892.2 345.9 13,373.2 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 (57.0) 415.1 17,510.4 75.8
(2008-2027) 9,048.0 11,407.9 775.0 4,672.1 965.3 26,868.4 975.4 4,470.8 5,446.3 (142.6) 704.8 196.7 (116.3) 807.6 33,764.8 90.9
(2008-2037) 12,573.7 16,319.5 1,223.9 5,862.1 1,356.1 37,335.3 1,036.7 6,099.0 7,135.7 (142.6) 1,053.1 230.5 (168.1) 950.7 46,394.6 101.8
APPENDIX 2 TABLE 97. TABLE 98. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 NUCLEAR SUPPLY SIDE SCENARIO (SS-N/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 600.3 865.6 52.3 446.3 66.1 2,030.7 116.3 466.2 582.5 (24.3) 56.6 24.8 (11.6) 54.9 2,713.5 77.4 2015 637.1 899.8 54.6 462.7 89.7 2,143.9 153.0 529.2 682.2 (33.0) 60.3 22.1 (12.1) 58.3 2,921.6 80.5 2016 864.3 991.0 63.1 439.7 138.4 2,496.4 165.0 551.2 716.2 (37.0) 69.2 19.2 (12.6) 93.4 3,344.7 89.1 2017 1,104.5 1,223.2 79.9 457.9 176.0 3,041.5 159.6 438.7 598.3 (39.2) 77.1 16.1 (13.4) 100.0 3,780.4 97.5 2018 1,285.6 1,401.4 94.8 476.5 185.3 3,443.6 123.1 373.0 496.1 (38.4) 87.4 13.8 (14.2) 107.3 4,095.5 102.4 2019 1,401.2 1,430.0 97.3 491.8 181.0 3,601.4 125.2 422.7 547.8 (5.2) 91.0 13.2 (15.2) 114.3 4,347.4 105.7 2020 1,647.9 1,669.3 120.4 516.2 193.5 4,147.3 68.3 299.7 368.0 (2.6) 99.2 10.8 (16.5) 121.1 4,727.2 111.9 2021 1,941.9 1,761.2 132.0 547.7 232.0 4,614.8 59.4 419.6 479.1 0.0 108.1 16.4 (17.5) 127.8 5,328.7 123.0 2022 2,197.7 1,825.3 137.5 581.9 243.2 4,985.6 52.6 393.1 445.7 0.0 118.7 15.6 (18.9) 134.8 5,681.5 127.9 2023 2,188.7 1,703.2 128.0 622.9 236.2 4,879.1 27.0 700.8 727.8 0.0 104.7 19.6 (20.3) 142.6 5,853.5 128.5 2024 2,071.2 1,771.2 134.0 645.2 247.5 4,869.2 32.8 701.6 734.4 0.0 105.6 18.8 (21.4) 150.3 5,856.9 125.6 2025 2,108.9 1,822.5 138.3 663.2 252.1 4,984.9 48.2 948.7 997.0 0.0 115.9 25.5 (22.7) 158.2 6,258.8 131.1 2026 2,156.1 1,984.7 151.3 682.6 245.8 5,220.6 52.4 951.3 1,003.7 0.0 123.9 24.4 (24.1) 92.2 6,440.7 131.5 2027 2,252.8 2,122.2 167.6 705.3 239.8 5,487.7 23.0 966.2 989.2 0.0 133.6 24.2 (25.2) 92.2 6,701.8 133.4 2028 2,335.9 2,253.8 182.7 732.3 233.8 5,738.5 59.5 971.1 1,030.7 0.0 146.0 23.0 (26.5) 98.1 7,009.7 136.1 2029 2,393.6 2,444.6 199.7 757.5 227.7 6,023.1 53.3 970.0 1,023.3 0.0 163.5 21.8 (28.4) 98.0 7,301.3 138.0 2030 2,534.2 2,588.3 218.9 789.4 244.4 6,375.1 17.0 962.2 979.2 0.0 172.4 20.5 (30.4) 97.3 7,614.1 140.3 2031 2,604.0 2,740.6 236.8 819.2 249.1 6,649.8 57.8 963.5 1,021.4 0.0 185.3 19.2 (31.9) 96.8 7,940.5 142.8 2032 2,643.2 2,977.1 257.9 848.4 243.4 6,969.9 52.1 968.5 1,020.6 0.0 203.2 17.8 (35.1) 96.2 8,272.7 145.6 2033 2,735.5 3,139.1 273.6 878.4 262.4 7,288.9 42.6 1,007.6 1,050.2 0.0 212.9 17.9 (37.1) 95.9 8,628.6 148.1 2034 2,804.2 3,289.2 291.9 909.4 267.0 7,561.7 32.7 1,286.8 1,319.5 0.0 235.0 27.9 (40.4) 95.1 9,198.8 154.4 2035 2,847.3 3,488.3 310.1 939.8 257.8 7,843.2 47.6 1,339.0 1,386.5 0.0 251.3 28.1 (43.1) 94.4 9,560.5 156.9 2036 2,904.6 3,651.4 325.3 976.6 280.5 8,138.4 12.4 1,397.0 1,409.4 0.0 265.5 28.3 (46.5) 93.8 9,888.8 159.1 2037 2,942.3 3,880.8 349.5 989.0 287.2 8,448.8 76.7 1,451.6 1,528.4 0.0 289.0 28.5 (46.7) 93.3 10,341.2 162.6
CPW@ 7.86% (2008-2017) 4,267.7 5,601.6 327.4 2,892.2 345.9 13,434.7 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 (57.0) 415.1 17,571.9 76.0
(2008-2027) 10,161.6 11,012.8 726.4 4,719.3 1,045.1 27,665.1 965.3 4,471.5 5,436.9 (142.6) 674.8 196.7 (116.7) 807.6 34,521.8 92.9
(2008-2037) 14,075.3 15,378.1 1,103.1 5,976.8 1,419.4 37,952.7 1,033.0 6,099.7 7,132.8 (142.6) 976.6 230.5 (168.9) 950.7 46,931.8 102.9
APPENDIX 2 TABLE 98. TABLE 99. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SOLAR SUPPLY SIDE SCENARIO 1 (SS-S1/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 597.5 828.1 50.6 446.3 66.1 1,988.5 106.2 582.0 688.2 (24.3) 53.9 30.0 (11.7) 54.9 2,779.5 79.3 2015 629.5 830.0 50.5 462.7 89.7 2,062.4 112.3 759.3 871.6 (33.0) 54.7 32.6 (12.2) 58.3 3,034.4 83.6 2016 755.9 877.6 55.5 436.7 123.4 2,249.0 141.7 910.8 1,052.6 (37.0) 60.7 35.1 (12.7) 93.4 3,440.9 91.7 2017 871.2 1,053.4 67.6 451.5 153.3 2,597.0 158.1 986.1 1,144.2 (39.2) 64.2 37.5 (13.5) 100.0 3,890.3 100.3 2018 936.7 1,174.3 78.2 467.5 162.7 2,819.3 128.7 1,111.3 1,240.0 (38.4) 70.4 40.8 (14.4) 107.3 4,225.1 105.7 2019 940.0 1,157.9 77.2 480.9 158.1 2,814.0 125.5 1,354.6 1,480.1 (5.2) 70.6 45.8 (15.4) 114.3 4,504.3 109.5 2020 1,038.2 1,333.0 90.5 500.3 171.4 3,133.4 66.2 1,456.5 1,522.6 (2.6) 75.4 49.2 (16.7) 121.1 4,882.4 115.6 2021 1,210.1 1,427.8 98.2 527.7 195.2 3,459.0 70.2 1,574.8 1,645.0 0.0 85.5 54.2 (17.7) 127.8 5,353.8 123.5 2022 1,343.7 1,580.2 108.6 549.9 200.0 3,782.3 63.1 1,554.8 1,618.0 0.0 103.7 52.8 (19.0) 134.8 5,672.6 127.7 2023 1,337.6 1,618.9 112.6 568.7 194.7 3,832.5 57.0 1,862.5 1,919.5 0.0 100.7 56.1 (20.4) 142.6 6,031.0 132.4 2024 1,365.3 1,738.2 121.5 581.1 189.9 3,996.0 57.0 1,865.5 1,922.5 0.0 105.6 54.6 (21.3) 150.3 6,207.7 133.1 2025 1,445.7 1,808.6 127.6 598.0 206.7 4,186.7 57.3 2,110.6 2,167.8 0.0 118.7 60.6 (22.6) 158.2 6,669.4 139.7 2026 1,531.0 1,961.2 139.0 616.2 211.3 4,458.7 50.0 2,113.0 2,163.0 0.0 127.6 58.7 (24.0) 92.2 6,876.3 140.4 2027 1,604.0 2,108.2 151.4 633.0 206.7 4,703.2 45.1 2,127.9 2,173.0 0.0 137.9 57.7 (25.0) 92.2 7,139.1 142.1 2028 1,685.0 2,288.6 165.9 655.3 223.0 5,017.8 60.5 2,135.0 2,195.5 0.0 156.1 55.6 (26.3) 98.1 7,496.7 145.6 2029 1,778.4 2,467.6 180.7 678.7 227.2 5,332.8 54.2 2,131.8 2,186.0 0.0 173.0 53.4 (28.3) 98.0 7,814.9 147.7 2030 1,946.1 2,612.8 200.1 708.2 221.3 5,688.5 17.3 2,123.9 2,141.3 0.0 181.4 51.1 (30.3) 97.3 8,129.3 149.8 2031 2,063.4 2,773.4 219.7 736.4 255.1 6,047.9 35.4 2,125.3 2,160.7 0.0 196.6 48.8 (31.8) 96.8 8,518.9 153.3 2032 2,120.6 3,001.2 238.8 762.9 292.5 6,416.0 53.4 2,132.5 2,185.9 0.0 214.6 46.2 (35.0) 96.2 8,923.9 157.0 2033 2,222.0 3,191.2 256.0 789.7 297.3 6,756.2 43.8 2,169.3 2,213.2 0.0 225.3 45.1 (37.0) 95.9 9,298.7 159.6 2034 2,314.7 3,351.1 273.3 818.1 289.9 7,047.0 33.9 2,448.5 2,482.4 0.0 246.9 53.8 (40.3) 95.1 9,884.9 165.9 2035 2,381.5 3,524.3 289.7 845.7 307.6 7,348.8 48.5 2,500.7 2,549.2 0.0 263.3 52.7 (43.0) 94.4 10,265.3 168.5 2036 2,462.9 3,698.7 305.5 879.7 313.6 7,660.3 13.2 2,560.8 2,574.0 0.0 277.6 51.4 (46.5) 93.8 10,610.6 170.7 2037 2,521.9 3,960.2 331.3 889.2 306.5 8,009.1 77.6 2,613.4 2,691.0 0.0 305.2 50.1 (46.7) 93.3 11,102.0 174.6
CPW@ 7.86% (2008-2017) 4,097.5 5,404.3 314.5 2,887.7 327.6 13,031.6 710.6 3,302.9 4,013.5 (122.8) 323.4 168.8 (57.1) 415.1 17,772.5 76.9
(2008-2027) 7,987.2 10,240.2 648.6 4,600.9 917.4 24,394.4 955.8 8,505.3 9,461.2 (142.6) 624.0 333.2 (117.0) 807.6 35,360.8 95.2
(2008-2037) 11,097.6 14,663.4 997.9 5,730.6 1,313.2 33,802.8 1,021.1 11,862.2 12,883.4 (142.6) 942.5 409.1 (169.1) 950.7 48,676.8 106.8
APPENDIX 2 TABLE 99. TABLE 100. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SOLAR SUPPLY SIDE SCENARIO 2 (SS-S2/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 597.5 833.0 50.4 446.3 66.1 1,993.3 106.2 572.0 678.1 (24.3) 54.3 29.8 (11.7) 54.9 2,774.4 79.1 2015 629.5 837.6 50.4 462.7 89.7 2,069.9 116.6 738.9 855.6 (33.0) 55.4 32.2 (12.2) 58.3 3,026.2 83.4 2016 780.9 906.8 57.0 437.7 137.8 2,320.2 143.2 817.0 960.2 (37.0) 62.5 31.6 (12.7) 93.4 3,418.1 91.1 2017 899.9 1,067.6 67.8 452.7 160.2 2,648.3 157.5 961.1 1,118.6 (39.2) 65.5 36.7 (13.5) 100.0 3,916.3 101.0 2018 955.1 1,190.2 79.2 468.4 161.3 2,854.1 131.6 1,067.7 1,199.3 (38.4) 72.0 39.8 (14.4) 107.3 4,219.7 105.5 2019 957.6 1,179.2 78.4 481.8 172.6 2,869.7 132.3 1,290.0 1,422.3 (5.2) 72.6 44.6 (15.5) 114.3 4,502.8 109.5 2020 1,069.4 1,361.0 92.0 501.9 177.6 3,201.9 67.5 1,367.4 1,434.9 (2.6) 77.6 47.6 (16.7) 121.1 4,863.8 115.2 2021 1,250.1 1,443.7 98.6 529.7 193.1 3,515.2 61.7 1,538.7 1,600.5 0.0 86.5 54.6 (17.8) 127.8 5,366.9 123.9 2022 1,382.1 1,594.2 109.7 551.9 198.3 3,836.2 51.6 1,521.6 1,573.1 0.0 104.8 53.2 (19.1) 134.8 5,683.0 127.9 2023 1,358.7 1,633.4 113.0 570.3 222.3 3,897.6 56.1 1,829.0 1,885.1 0.0 101.9 56.5 (20.4) 142.6 6,063.3 133.2 2024 1,390.6 1,754.4 122.1 582.8 232.2 4,082.1 52.6 1,832.5 1,885.1 0.0 106.7 55.1 (21.4) 150.3 6,257.7 134.2 2025 1,464.6 1,824.2 128.6 599.6 246.9 4,263.9 56.7 2,077.3 2,133.9 0.0 120.0 61.0 (22.7) 158.2 6,714.5 140.6 2026 1,537.2 1,978.0 140.5 617.4 250.6 4,523.7 56.8 2,079.5 2,136.4 0.0 128.7 59.2 (24.1) 92.2 6,915.9 141.2 2027 1,663.7 2,093.2 156.6 638.6 244.6 4,796.6 19.7 2,094.4 2,114.1 0.0 136.5 58.1 (25.2) 92.2 7,172.4 142.7 2028 1,762.6 2,247.9 175.4 663.6 237.6 5,087.1 56.5 2,101.8 2,158.2 0.0 151.2 56.1 (26.4) 98.1 7,524.3 146.1 2029 1,840.8 2,432.5 190.7 686.8 231.9 5,382.7 50.3 2,098.5 2,148.8 0.0 169.5 53.9 (28.5) 98.0 7,824.4 147.9 2030 2,006.8 2,580.8 210.0 716.5 286.4 5,800.4 13.6 2,090.4 2,104.1 0.0 176.8 51.6 (30.5) 97.3 8,199.7 151.1 2031 2,102.0 2,740.8 229.4 744.1 309.1 6,125.4 54.2 2,091.8 2,145.9 0.0 192.0 49.2 (32.0) 96.8 8,577.4 154.3 2032 2,165.3 2,964.3 248.5 771.1 300.8 6,450.0 48.5 2,099.5 2,148.0 0.0 210.2 46.7 (35.2) 96.2 8,915.9 156.9 2033 2,280.7 3,149.9 265.1 798.8 317.7 6,812.1 39.1 2,135.8 2,175.0 0.0 220.9 45.6 (37.2) 95.9 9,312.3 159.8 2034 2,349.3 3,296.0 281.9 826.5 321.9 7,075.7 53.8 2,415.1 2,468.8 0.0 240.5 54.3 (40.6) 95.1 9,893.9 166.0 2035 2,423.1 3,479.4 298.5 854.7 311.9 7,367.5 42.6 2,467.2 2,509.8 0.0 256.0 53.2 (43.3) 94.4 10,237.7 168.0 2036 2,520.4 3,642.1 315.0 889.6 332.0 7,699.1 31.6 2,527.6 2,559.3 0.0 269.8 52.0 (46.7) 93.8 10,627.2 170.9 2037 2,578.3 3,896.3 340.4 899.4 337.8 8,052.2 95.2 2,579.9 2,675.1 0.0 297.7 50.6 (46.8) 93.3 11,122.2 174.9
CPW@ 7.86% (2008-2017) 4,123.6 5,432.9 315.2 2,888.8 338.2 13,098.6 713.4 3,226.7 3,940.1 (122.8) 325.6 166.3 (57.2) 415.1 17,765.7 76.9
(2008-2027) 8,099.1 10,318.2 653.3 4,607.6 982.2 24,660.5 950.9 8,284.6 9,235.5 (142.6) 630.1 330.0 (117.3) 807.6 35,403.8 95.3
(2008-2037) 11,290.7 14,678.7 1,016.7 5,750.1 1,416.1 34,152.4 1,021.4 11,591.9 12,613.3 (142.6) 940.8 406.7 (169.7) 950.7 48,751.5 106.9
APPENDIX 2 TABLE 100. TABLE 101. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SUPPLY SIDE SCENARIO 1 (SS-1/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 599.7 847.3 51.3 446.3 66.1 2,010.8 107.9 524.0 631.9 (24.3) 55.3 27.4 (11.6) 54.9 2,744.2 78.3 2015 635.5 865.0 52.4 462.7 89.7 2,105.3 130.6 643.6 774.2 (33.0) 57.4 27.4 (12.2) 58.3 2,977.4 82.0 2016 819.9 934.6 59.4 438.2 137.8 2,389.9 154.6 725.4 880.0 (37.0) 64.7 26.8 (12.7) 93.4 3,405.1 90.7 2017 1,025.0 1,159.4 75.5 455.2 160.8 2,875.9 161.2 616.9 778.1 (39.2) 72.4 23.7 (13.4) 100.0 3,797.5 97.9 2018 1,195.6 1,332.5 89.9 473.7 177.6 3,269.3 124.7 552.8 677.5 (38.4) 81.9 21.3 (14.3) 107.3 4,104.7 102.7 2019 1,297.4 1,359.1 92.1 489.0 181.5 3,419.2 126.7 603.3 730.0 (5.2) 85.5 20.6 (15.2) 114.3 4,349.2 105.7 2020 1,527.6 1,592.1 114.7 513.3 194.0 3,941.7 69.7 483.6 553.3 (2.6) 93.3 18.0 (16.5) 121.1 4,708.3 111.5 2021 1,793.0 1,685.4 126.0 544.1 225.3 4,373.8 70.5 603.2 673.7 0.0 102.3 23.5 (17.5) 127.8 5,283.6 121.9 2022 2,033.2 1,765.7 132.9 576.2 233.5 4,741.6 56.8 578.6 635.5 0.0 114.5 22.6 (18.9) 134.8 5,630.0 126.7 2023 2,033.9 1,676.6 126.0 613.1 227.2 4,676.8 29.4 886.4 915.8 0.0 102.9 26.4 (20.3) 142.6 5,844.2 128.3 2024 1,936.9 1,755.8 132.4 633.0 221.4 4,679.6 39.9 887.6 927.5 0.0 104.7 25.5 (21.4) 150.3 5,866.1 125.8 2025 1,978.4 1,810.2 137.1 650.6 236.4 4,812.7 55.2 1,134.4 1,189.6 0.0 115.5 32.0 (22.7) 158.2 6,285.3 131.6 2026 2,047.3 1,971.2 149.8 670.3 240.5 5,079.1 48.0 1,136.9 1,184.9 0.0 123.4 30.7 (24.1) 92.2 6,486.2 132.4 2027 2,159.4 2,102.5 166.1 693.1 234.7 5,355.8 11.1 1,151.8 1,162.9 0.0 132.7 30.4 (25.1) 92.2 6,748.9 134.3 2028 2,245.0 2,239.5 182.0 719.8 228.0 5,614.2 48.1 1,157.1 1,205.2 0.0 145.6 29.0 (26.5) 98.1 7,065.6 137.2 2029 2,306.2 2,427.7 198.4 744.6 222.6 5,899.5 42.2 1,155.6 1,197.8 0.0 162.9 27.6 (28.4) 98.0 7,357.4 139.0 2030 2,451.3 2,601.8 213.7 776.1 239.9 6,282.7 6.0 1,147.9 1,153.9 0.0 174.9 26.1 (30.4) 97.3 7,704.4 142.0 2031 2,525.6 2,763.6 228.9 805.5 283.4 6,607.1 47.1 1,149.2 1,196.2 0.0 190.0 24.5 (31.9) 96.8 8,082.7 145.4 2032 2,568.5 2,998.5 249.2 834.3 295.3 6,945.9 41.7 1,155.2 1,196.9 0.0 207.5 22.8 (35.0) 96.2 8,434.3 148.4 2033 2,642.6 3,167.5 265.2 863.1 312.4 7,250.8 56.2 1,193.2 1,249.4 0.0 217.5 22.7 (37.0) 95.9 8,799.3 151.0 2034 2,700.5 3,325.0 283.3 893.0 316.7 7,518.5 45.8 1,472.5 1,518.3 0.0 240.6 32.4 (40.3) 95.1 9,364.5 157.1 2035 2,748.7 3,518.5 301.5 922.9 307.8 7,799.4 60.1 1,524.6 1,584.7 0.0 256.7 32.3 (43.0) 94.4 9,724.5 159.6 2036 2,810.9 3,683.0 316.5 959.2 328.5 8,098.1 24.6 1,583.1 1,607.6 0.0 271.3 32.2 (46.5) 93.8 10,056.5 161.8 2037 2,877.7 3,923.8 340.9 972.0 333.2 8,447.6 14.1 1,637.3 1,651.5 0.0 295.4 32.0 (46.7) 93.3 10,473.1 164.7
CPW@ 7.86% (2008-2017) 4,206.7 5,513.4 321.6 2,890.2 338.5 13,270.3 729.6 2,938.5 3,668.1 (122.8) 331.6 153.7 (57.0) 415.1 17,659.0 76.4
(2008-2027) 9,707.0 10,768.8 708.7 4,695.6 1,013.0 26,893.0 951.5 5,322.3 6,273.7 (142.6) 656.6 230.6 (116.8) 807.6 34,602.2 93.1
(2008-2037) 13,491.6 15,157.6 1,076.3 5,931.5 1,427.3 37,084.3 1,009.5 7,226.8 8,236.3 (142.6) 963.4 271.8 (168.9) 950.7 47,195.0 103.5
APPENDIX 2 TABLE 101. TABLE 102. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SUPPLY SIDE SCENARIO 2 (SS-2/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 600.4 837.3 50.8 446.3 66.1 2,000.9 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 2,765.8 78.9 2015 637.3 846.7 51.1 462.7 89.7 2,087.5 120.9 707.6 828.5 (33.0) 56.0 30.6 (12.2) 58.3 3,015.7 83.1 2016 802.8 902.3 56.8 437.2 137.8 2,336.8 152.0 830.5 982.5 (37.0) 62.0 32.0 (12.7) 93.4 3,456.9 92.1 2017 1,003.1 1,110.7 71.1 453.4 160.2 2,798.5 161.9 771.1 933.0 (39.2) 68.6 30.5 (13.5) 100.0 3,877.9 100.0 2018 1,177.2 1,267.3 84.5 471.3 161.9 3,162.3 126.7 753.2 879.8 (38.4) 77.4 29.7 (14.3) 107.3 4,203.8 105.1 2019 1,304.3 1,294.3 86.8 486.7 174.2 3,346.4 122.6 803.2 925.8 (5.2) 80.8 28.8 (15.3) 114.3 4,475.6 108.8 2020 1,539.1 1,540.5 105.3 508.3 195.4 3,888.5 65.4 691.3 756.7 (2.6) 90.5 26.1 (16.6) 121.1 4,863.6 115.1 2021 1,834.3 1,616.6 117.3 539.8 234.2 4,342.1 64.3 807.9 872.2 0.0 98.1 31.5 (17.6) 127.8 5,454.2 125.9 2022 2,111.1 1,662.0 124.8 576.1 245.5 4,719.5 58.8 786.3 845.0 0.0 106.1 30.4 (19.0) 134.8 5,816.8 130.9 2023 2,108.6 1,541.5 115.5 617.7 238.5 4,621.8 31.2 1,093.9 1,125.2 0.0 93.8 34.1 (20.6) 142.6 5,996.9 131.7 2024 1,992.5 1,604.8 120.2 640.2 231.5 4,589.3 36.1 1,095.7 1,131.9 0.0 94.7 33.0 (21.7) 150.3 5,977.5 128.2 2025 2,034.1 1,650.4 124.0 658.0 227.8 4,694.3 51.5 1,341.9 1,393.5 0.0 103.9 39.3 (23.0) 158.2 6,366.2 133.3 2026 2,085.1 1,804.3 137.2 677.3 242.2 4,946.1 55.7 1,344.4 1,400.1 0.0 111.3 37.9 (24.4) 92.2 6,563.2 134.0 2027 2,131.6 1,965.4 149.2 695.3 245.5 5,186.9 58.2 1,359.4 1,417.5 0.0 123.3 37.3 (25.4) 92.2 6,831.9 136.0 2028 2,218.6 2,092.0 161.2 720.2 239.7 5,431.7 52.7 1,365.1 1,417.8 0.0 135.6 35.8 (26.6) 98.1 7,092.2 137.7 2029 2,307.2 2,284.8 176.2 746.2 233.9 5,748.2 46.7 1,363.2 1,409.9 0.0 153.4 34.1 (28.6) 98.0 7,415.0 140.1 2030 2,451.3 2,422.9 194.7 777.7 250.4 6,097.0 10.3 1,355.4 1,365.6 0.0 160.8 32.4 (30.6) 97.3 7,722.5 142.3 2031 2,524.4 2,571.9 211.9 807.1 255.0 6,370.4 51.1 1,356.7 1,407.8 0.0 174.1 30.6 (32.1) 96.8 8,047.5 144.8 2032 2,565.9 2,806.4 231.8 836.0 248.1 6,688.2 45.7 1,362.7 1,408.4 0.0 191.7 28.7 (35.3) 96.2 8,378.0 147.4 2033 2,660.2 2,964.5 246.0 865.6 267.6 7,004.0 36.5 1,400.7 1,437.2 0.0 200.2 28.3 (37.3) 95.9 8,728.3 149.8 2034 2,708.2 3,118.5 263.1 895.4 315.6 7,300.8 51.1 1,679.9 1,731.0 0.0 221.8 37.6 (40.6) 95.1 9,345.8 156.8 2035 2,762.1 3,309.4 281.3 925.6 326.5 7,604.9 40.0 1,732.1 1,772.0 0.0 238.4 37.3 (43.3) 94.4 9,703.7 159.3 2036 2,815.4 3,468.7 295.7 961.7 346.1 7,887.6 79.0 1,791.0 1,870.0 0.0 252.3 36.8 (46.7) 93.8 10,093.7 162.4 2037 2,863.9 3,691.5 317.6 973.9 351.5 8,198.4 18.5 1,844.8 1,863.2 0.0 274.9 36.3 (46.9) 93.3 10,419.3 163.8
CPW@ 7.86% (2008-2017) 4,189.1 5,458.3 317.2 2,888.8 338.2 13,191.6 722.3 3,117.9 3,840.2 (122.8) 327.4 162.2 (57.1) 415.1 17,756.5 76.8
(2008-2027) 9,782.6 10,389.8 674.0 4,696.3 1,017.1 26,559.9 951.0 6,152.4 7,103.4 (142.6) 629.9 263.8 (117.3) 807.6 35,104.7 94.5
(2008-2037) 13,565.6 14,501.7 1,012.0 5,934.9 1,425.7 36,439.9 1,014.9 8,365.7 9,380.5 (142.6) 914.1 313.7 (169.8) 950.7 47,686.5 104.6
APPENDIX 2 TABLE 102. TABLE 103. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SUPPLY SIDE SCENARIO 3 (SS-3/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 2,766.5 78.9 2015 639.1 855.8 51.6 462.7 89.7 2,098.9 125.2 678.0 803.3 (33.0) 56.8 29.2 (12.2) 58.3 3,001.3 82.7 2016 835.8 936.2 59.0 438.2 137.8 2,407.0 153.7 720.8 874.4 (37.0) 64.8 27.0 (12.7) 93.4 3,416.8 91.0 2017 1,064.4 1,160.4 75.1 455.2 160.8 2,915.9 164.4 611.0 775.4 (39.2) 72.4 23.8 (13.4) 100.0 3,834.9 98.9 2018 1,265.3 1,333.4 89.8 473.7 177.6 3,339.8 127.7 547.1 674.7 (38.4) 82.2 21.4 (14.3) 107.3 4,172.8 104.4 2019 1,404.5 1,361.8 92.1 489.0 181.5 3,528.9 129.6 596.4 726.0 (5.2) 85.9 20.7 (15.2) 114.3 4,455.4 108.3 2020 1,678.1 1,593.7 114.6 513.3 194.0 4,093.7 72.5 477.8 550.4 (2.6) 93.3 18.1 (16.5) 121.1 4,857.4 115.0 2021 1,995.4 1,686.5 126.1 544.6 240.9 4,593.5 63.5 597.0 660.5 0.0 102.4 23.6 (17.6) 127.8 5,490.3 126.7 2022 2,288.1 1,718.4 129.0 581.8 256.3 4,973.6 57.5 573.1 630.6 0.0 110.3 22.7 (19.0) 134.8 5,853.0 131.7 2023 2,288.8 1,557.1 116.6 628.8 249.0 4,840.3 23.2 880.7 904.0 0.0 94.6 26.5 (20.5) 142.6 5,987.4 131.5 2024 2,132.9 1,609.1 120.0 653.3 241.7 4,757.1 33.4 882.1 915.5 0.0 94.5 25.6 (21.7) 150.3 5,921.2 127.0 2025 2,159.1 1,650.8 124.0 671.0 255.7 4,860.5 56.1 1,128.8 1,184.9 0.0 103.3 32.1 (23.0) 158.2 6,315.9 132.3 2026 2,223.5 1,808.0 137.7 691.4 259.1 5,119.7 48.9 1,131.3 1,180.1 0.0 110.9 30.8 (24.3) 92.2 6,509.3 132.9 2027 2,332.2 1,949.5 153.1 714.8 252.8 5,402.5 11.9 1,146.2 1,158.1 0.0 120.9 30.4 (25.4) 92.2 6,778.7 134.9 2028 2,414.9 2,067.6 167.7 742.1 245.5 5,637.8 48.9 1,151.5 1,200.4 0.0 132.3 29.1 (26.8) 98.1 7,070.9 137.3 2029 2,471.1 2,257.6 183.8 767.6 239.5 5,919.6 43.0 1,150.0 1,193.0 0.0 148.7 27.6 (28.7) 98.0 7,358.2 139.1 2030 2,549.2 2,420.8 197.7 794.9 256.1 6,218.7 41.7 1,142.2 1,183.8 0.0 160.1 26.1 (30.7) 97.3 7,655.3 141.1 2031 2,595.6 2,574.3 211.6 822.2 260.4 6,464.0 59.0 1,143.5 1,202.5 0.0 172.8 24.5 (32.2) 96.8 7,928.4 142.6 2032 2,647.4 2,810.6 231.3 852.1 278.2 6,819.5 53.3 1,149.0 1,202.3 0.0 190.3 22.8 (35.3) 96.2 8,295.8 146.0 2033 2,737.1 2,965.2 245.5 882.2 283.5 7,113.3 43.8 1,187.6 1,231.4 0.0 199.1 22.7 (37.3) 95.9 8,625.1 148.0 2034 2,780.7 3,119.5 262.9 912.4 275.0 7,350.4 58.3 1,466.8 1,525.1 0.0 222.4 32.4 (40.5) 95.1 9,184.7 154.1 2035 2,829.6 3,316.0 281.2 943.1 266.6 7,636.5 47.1 1,518.9 1,566.1 0.0 238.1 32.3 (43.3) 94.4 9,524.1 156.3 2036 2,901.6 3,472.3 295.0 980.7 288.3 7,937.9 36.1 1,577.4 1,613.5 0.0 251.9 32.1 (46.7) 93.8 9,882.5 159.0 2037 2,937.4 3,695.6 317.2 993.2 294.1 8,237.4 99.7 1,631.6 1,731.3 0.0 273.7 31.9 (46.9) 93.3 10,320.8 162.3
CPW@ 7.86% (2008-2017) 4,236.0 5,503.7 320.5 2,890.2 338.5 13,288.8 726.6 2,971.1 3,697.8 (122.8) 331.0 155.8 (57.1) 415.1 17,708.6 76.6
(2008-2027) 10,274.6 10,556.9 690.8 4,722.9 1,051.2 27,296.4 946.8 5,336.2 6,283.1 (142.6) 641.0 232.9 (117.2) 807.6 35,001.2 94.2
(2008-2037) 14,215.2 14,661.1 1,031.8 5,988.6 1,445.8 37,342.5 1,023.6 7,232.3 8,255.9 (142.6) 922.8 274.2 (169.8) 950.7 47,433.7 104.0
APPENDIX 2 TABLE 103. TABLE 104. RISK ANALYSIS E - NO PTC AVAILABLE AFTER 2009, NO ITC AVAILABLE AFTER 2016 SUPPLY SIDE SCENARIO 4 (SS-4/E) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 0.0 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 0.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 0.0 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 0.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 0.0 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 0.0 2,535.0 74.5 2014 601.0 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 (0.1) 2,766.4 78.9 2015 639.1 846.7 51.1 462.7 89.7 2,089.4 120.9 707.6 828.5 (33.0) 56.0 30.6 (12.2) 58.3 (0.1) 3,017.4 83.1 2016 810.8 893.6 56.0 437.2 137.8 2,335.4 147.5 863.5 1,011.1 (37.0) 61.7 33.7 (12.8) 93.4 (0.0) 3,485.4 92.9 2017 996.9 1,067.7 67.8 452.4 160.2 2,745.0 158.0 942.2 1,100.3 (39.2) 65.5 36.7 (13.5) 100.0 (0.0) 3,994.7 103.0 2018 1,142.4 1,184.6 78.7 468.4 161.3 3,035.4 128.6 1,073.1 1,201.7 (38.4) 71.6 40.7 (14.4) 107.3 (0.0) 4,403.9 110.1 2019 1,244.7 1,168.9 77.5 481.8 157.3 3,130.3 125.4 1,320.3 1,445.7 (5.2) 71.6 46.4 (15.5) 114.3 (0.9) 4,786.7 116.4 2020 1,458.0 1,342.9 90.4 501.3 170.4 3,562.9 66.1 1,425.9 1,492.0 (2.6) 76.4 50.4 (16.8) 121.1 (1.4) 5,282.1 125.1 2021 1,728.5 1,421.8 96.9 528.7 217.2 3,993.0 63.4 1,611.5 1,675.0 0.0 84.8 57.6 (17.8) 127.8 (2.8) 5,917.6 136.6 2022 2,020.5 1,442.2 98.1 564.9 233.0 4,358.7 59.5 1,595.7 1,655.2 0.0 91.4 56.2 (19.3) 134.8 (2.6) 6,274.4 141.2 2023 2,031.1 1,304.1 86.8 611.4 226.4 4,259.8 25.2 1,903.0 1,928.2 0.0 76.7 59.5 (21.1) 142.6 (20.1) 6,425.6 141.1 2024 1,884.8 1,364.5 90.5 635.4 268.2 4,243.5 35.2 1,907.1 1,942.4 0.0 76.8 57.9 (22.3) 150.3 (36.9) 6,411.8 137.5 2025 1,920.4 1,403.2 93.3 652.5 288.1 4,357.6 57.9 2,151.3 2,209.2 0.0 84.1 63.8 (23.6) 158.2 (39.1) 6,810.2 142.6 2026 1,994.2 1,538.8 104.5 672.4 280.9 4,590.8 50.6 2,153.5 2,204.1 0.0 91.2 61.9 (24.9) 92.2 (28.7) 6,986.6 142.6 2027 2,058.2 1,686.4 115.9 690.8 294.6 4,845.9 45.6 2,168.4 2,214.0 0.0 102.1 60.8 (25.9) 92.2 (24.8) 7,264.5 144.6 2028 2,131.6 1,801.0 125.2 714.8 296.9 5,069.5 61.0 2,176.0 2,236.9 0.0 114.5 58.7 (27.2) 98.1 (21.5) 7,528.9 146.2 2029 2,211.6 1,975.6 139.8 740.1 288.6 5,355.6 54.7 2,172.5 2,227.2 0.0 130.7 56.5 (29.1) 98.0 (12.8) 7,826.1 147.9 2030 2,300.1 2,134.2 152.5 766.5 304.2 5,657.6 52.9 2,164.6 2,217.4 0.0 141.7 54.1 (31.1) 97.3 (11.3) 8,125.7 149.8 2031 2,377.1 2,281.6 164.3 793.7 307.7 5,924.4 47.5 2,165.8 2,213.2 0.0 154.0 51.7 (32.6) 96.8 (9.2) 8,398.2 151.1 2032 2,452.3 2,506.5 183.1 823.3 300.2 6,265.4 42.2 2,173.6 2,215.8 0.0 171.3 49.1 (35.6) 96.2 (5.3) 8,756.9 154.1 2033 2,527.8 2,660.1 195.5 851.7 317.6 6,552.7 56.8 2,209.8 2,266.5 0.0 178.5 47.9 (37.6) 95.9 (4.0) 9,099.9 156.2 2034 2,586.0 2,818.5 210.0 881.3 320.6 6,816.5 46.4 2,489.0 2,535.3 0.0 201.7 56.5 (40.9) 95.1 (3.4) 9,660.9 162.1 2035 2,658.1 3,001.7 227.5 911.7 311.0 7,110.0 35.5 2,541.1 2,576.7 0.0 217.9 55.3 (43.7) 94.4 (2.5) 10,008.2 164.3 2036 2,713.1 3,151.7 239.7 947.4 331.4 7,383.4 74.7 2,601.8 2,676.5 0.0 229.9 54.0 (47.2) 93.8 (2.8) 10,387.6 167.1 2037 2,764.9 3,369.0 259.7 959.2 335.8 7,688.6 14.3 2,653.8 2,668.1 0.0 251.5 52.5 (47.2) 93.3 (1.5) 10,705.4 168.3
CPW@ 7.86% (2008-2017) 4,191.7 5,433.7 315.2 2,888.3 338.2 13,167.1 718.2 3,215.0 3,933.2 (122.8) 325.8 166.0 (57.2) 415.1 (0.1) 17,827.1 77.2
(2008-2027) 9,530.1 9,741.7 604.8 4,675.7 1,032.8 25,585.1 944.7 8,453.9 9,398.7 (142.6) 582.9 337.5 (118.4) 807.6 (41.3) 36,409.5 98.0
(2008-2037) 13,141.1 13,405.3 873.5 5,897.4 1,491.8 34,809.0 1,018.9 11,871.3 12,890.3 (142.6) 835.8 417.7 (171.6) 950.7 (54.2) 49,535.1 108.6
APPENDIX 2 TABLE 104. TABLE 105. RISK ANALYSIS F - COST OF NUCLEAR GENERATION INCREASES by 25% SELECTED PLAN (SP/F) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 50.0 2,155.7 67.0 2009 549.1 787.5 42.1 412.2 8.6 1,799.6 76.8 308.1 384.8 (8.3) 42.5 14.5 (1.2) 81.6 2,313.6 71.1 2010 573.3 736.2 41.5 422.9 20.9 1,794.8 115.7 335.4 451.1 (9.1) 42.2 24.5 (9.5) 82.3 2,376.4 73.1 2011 580.5 770.7 43.5 419.9 28.5 1,843.1 102.9 277.4 380.2 (10.0) 43.4 23.2 (10.0) 107.1 2,377.1 72.9 2012 578.7 683.7 39.7 423.8 30.7 1,756.6 105.2 437.6 542.9 (14.0) 42.5 27.8 (10.5) 134.9 2,480.0 75.4 2013 583.5 686.6 41.6 429.0 49.2 1,789.9 105.8 484.9 590.7 (19.0) 44.3 27.2 (10.9) 115.8 2,538.1 76.7 2014 601.9 779.4 47.5 446.3 66.1 1,941.3 106.2 545.4 651.5 (24.3) 51.0 29.0 (11.7) 134.5 2,771.2 81.6 2015 641.5 790.6 47.9 462.7 76.3 2,019.2 106.6 663.9 770.4 (33.0) 51.8 29.2 (12.3) 160.7 2,986.1 85.3 2016 808.9 857.4 53.3 436.7 103.7 2,259.9 139.4 705.8 845.2 (37.0) 59.0 27.0 (12.8) 220.0 3,361.2 93.3 2017 1,015.2 1,058.8 67.2 452.0 120.2 2,713.5 165.8 601.5 767.3 (39.2) 64.8 23.8 (13.5) 230.5 3,747.1 101.1 2018 1,230.4 1,210.4 80.7 470.0 163.0 3,154.4 127.4 538.2 665.6 (38.4) 72.8 21.4 (14.4) 241.7 4,103.1 107.9 2019 1,397.9 1,223.1 82.2 485.2 180.0 3,368.5 122.0 581.1 703.0 (5.2) 75.5 20.7 (15.4) 252.7 4,399.8 112.8 2020 1,689.5 1,428.3 103.1 508.8 192.2 3,921.9 67.5 468.9 536.4 (2.6) 80.9 18.1 (16.6) 263.6 4,801.6 120.3 2021 2,010.4 1,508.2 113.2 539.0 239.1 4,409.9 67.8 574.6 642.4 0.0 89.4 23.6 (17.7) 274.7 5,422.3 132.8 2022 2,355.9 1,523.3 114.5 575.6 254.6 4,823.8 61.5 554.4 615.9 0.0 95.2 22.7 (19.1) 286.0 5,824.5 139.5 2023 2,382.3 1,355.6 100.2 622.4 247.3 4,707.7 20.6 778.6 799.2 0.0 80.3 26.5 (20.8) 298.4 5,891.3 137.9 2024 2,201.1 1,399.9 101.8 646.7 240.2 4,589.7 24.4 779.7 804.2 0.0 79.3 25.6 (22.0) 310.8 5,787.4 132.6 2025 2,210.6 1,424.8 103.6 663.6 235.5 4,638.0 52.1 998.2 1,050.3 0.0 85.6 32.1 (23.4) 323.5 6,106.0 136.8 2026 2,246.2 1,560.1 116.6 682.5 249.3 4,854.7 57.5 1,000.6 1,058.1 0.0 92.4 30.8 (24.7) 262.4 6,273.7 137.2 2027 2,290.8 1,700.5 127.9 700.8 252.4 5,072.4 51.1 1,015.5 1,066.6 0.0 101.9 30.4 (25.7) 258.3 6,503.8 138.8 2028 2,358.0 1,806.7 137.6 725.1 245.6 5,273.1 60.4 1,020.6 1,080.9 0.0 113.9 29.1 (27.1) 258.7 6,728.6 140.2 2029 2,430.3 1,978.7 151.9 750.7 261.8 5,573.4 47.9 1,019.4 1,067.3 0.0 128.5 27.6 (29.0) 251.9 7,019.7 142.4 2030 2,489.7 2,126.4 164.3 776.7 265.6 5,822.7 61.3 1,011.6 1,073.0 0.0 138.3 26.1 (31.0) 243.1 7,272.1 144.0 2031 2,543.9 2,262.7 175.3 803.6 259.8 6,045.3 48.6 1,012.9 1,061.5 0.0 148.7 24.5 (32.6) 232.8 7,480.2 144.7 2032 2,610.6 2,476.4 193.0 833.5 277.7 6,391.2 36.9 1,018.0 1,054.9 0.0 164.8 22.8 (35.6) 220.5 7,818.7 148.0 2033 2,677.9 2,613.1 204.5 862.2 281.6 6,639.3 44.6 1,049.9 1,094.5 0.0 171.0 22.7 (37.6) 206.4 8,096.4 149.5 2034 2,706.1 2,748.7 218.1 891.3 273.9 6,838.1 51.7 1,278.4 1,330.1 0.0 192.1 32.4 (40.9) 189.4 8,541.2 154.3 2035 2,732.2 2,926.3 234.2 920.5 291.6 7,104.7 58.3 1,321.5 1,379.8 0.0 206.9 32.3 (43.6) 170.0 8,850.1 156.4 2036 2,788.8 3,058.3 246.0 956.7 297.5 7,347.3 15.0 1,370.0 1,385.0 0.0 218.2 32.1 (47.1) 147.6 9,083.1 157.5 2037 2,827.0 3,257.1 264.7 968.5 290.2 7,607.6 71.5 1,414.6 1,486.1 0.0 237.3 31.9 (47.2) 122.1 9,437.9 160.0
CPW@ 7.86% (2008-2017) 4,201.1 5,247.4 304.9 2,887.9 294.8 12,936.3 709.9 2,920.9 3,630.8 (122.8) 313.9 155.8 (57.4) 813.7 17,670.3 78.1
(2008-2027) 10,309.3 9,715.2 628.2 4,701.0 990.2 26,343.9 934.2 5,106.9 6,041.1 (142.6) 580.0 232.9 (118.1) 1,683.5 34,620.7 96.6
(2008-2037) 14,152.6 13,324.9 911.3 5,937.6 1,393.8 35,720.2 1,008.8 6,774.6 7,783.4 (142.6) 823.4 274.2 (171.2) 2,000.7 46,288.3 106.0
APPENDIX 2 TABLE 105. TABLE 106. RISK ANALYSIS F - COST OF NUCLEAR GENERATION INCREASES by 25% NUCLEAR SUPPLY SIDE SCENARIO (SS-N/F) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 601.0 865.6 52.3 446.3 66.1 2,031.4 116.3 466.2 582.5 (24.3) 56.6 24.8 (11.6) 54.9 2,714.2 77.4 2015 639.0 899.8 54.6 462.7 89.7 2,145.8 153.0 529.2 682.2 (33.0) 60.3 22.1 (12.1) 58.3 2,923.5 80.6 2016 872.6 991.0 63.1 439.7 138.4 2,504.8 165.0 551.2 716.2 (37.0) 69.2 19.2 (12.6) 93.4 3,353.1 89.3 2017 1,125.2 1,223.2 79.9 457.9 176.0 3,062.2 159.6 438.7 598.3 (39.2) 77.1 16.1 (13.4) 100.0 3,801.1 98.0 2018 1,322.2 1,401.4 94.8 476.5 185.3 3,480.2 123.1 373.0 496.1 (38.4) 87.4 13.8 (14.2) 107.3 4,132.1 103.3 2019 1,457.4 1,430.0 97.3 491.8 181.0 3,657.6 125.2 416.2 541.3 (5.2) 91.0 13.2 (15.2) 114.3 4,397.1 106.9 2020 1,726.9 1,669.3 120.4 516.2 193.5 4,226.4 68.3 293.2 361.5 (2.6) 99.2 10.8 (16.5) 121.1 4,799.7 113.6 2021 2,040.5 1,761.2 132.0 547.7 232.0 4,713.4 59.4 400.9 460.3 0.0 108.1 16.4 (17.5) 127.8 5,408.5 124.8 2022 2,342.6 1,825.3 137.5 581.9 243.2 5,130.5 52.6 374.4 426.9 0.0 118.7 15.6 (18.9) 134.8 5,807.6 130.7 2023 2,350.0 1,703.2 128.0 622.9 236.2 5,040.4 27.0 598.6 625.7 0.0 104.7 19.6 (20.3) 142.6 5,912.7 129.8 2024 2,209.0 1,771.2 134.0 645.2 247.5 5,007.0 32.8 599.3 632.1 0.0 105.6 18.8 (21.4) 150.3 5,892.3 126.3 2025 2,243.2 1,822.5 138.3 663.2 252.1 5,119.2 48.2 818.1 866.4 0.0 115.9 25.5 (22.7) 158.2 6,262.4 131.2 2026 2,286.5 1,984.7 151.3 682.6 245.8 5,351.0 52.4 820.7 873.1 0.0 123.9 24.4 (24.1) 92.2 6,440.4 131.5 2027 2,379.9 2,122.2 167.6 705.3 239.8 5,614.8 23.0 835.6 858.5 0.0 133.6 24.2 (25.2) 92.2 6,698.2 133.3 2028 2,460.1 2,253.8 182.7 732.3 233.8 5,862.6 59.5 840.2 899.7 0.0 146.0 23.0 (26.5) 98.1 7,003.0 136.0 2029 2,513.8 2,444.6 199.7 757.5 227.7 6,143.3 53.3 839.4 892.7 0.0 163.5 21.8 (28.4) 98.0 7,290.8 137.8 2030 2,649.1 2,588.3 218.9 789.4 244.4 6,490.0 17.0 831.6 848.6 0.0 172.4 20.5 (30.4) 97.3 7,598.3 140.1 2031 2,713.6 2,740.6 236.8 819.2 249.1 6,759.3 57.8 832.9 890.7 0.0 185.3 19.2 (31.9) 96.8 7,919.4 142.5 2032 2,747.5 2,977.1 257.9 848.4 243.4 7,074.2 52.1 837.6 889.7 0.0 203.2 17.8 (35.1) 96.2 8,246.1 145.1 2033 2,834.5 3,139.1 273.6 878.4 262.4 7,387.9 42.6 869.9 912.5 0.0 212.9 17.9 (37.1) 95.9 8,590.0 147.4 2034 2,897.8 3,289.2 291.9 909.4 267.0 7,655.3 32.7 1,098.4 1,131.2 0.0 235.0 27.9 (40.4) 95.1 9,104.0 152.8 2035 2,935.6 3,488.3 310.1 939.8 257.8 7,931.6 47.6 1,141.6 1,189.1 0.0 251.3 28.1 (43.1) 94.4 9,451.4 155.1 2036 2,987.6 3,651.4 325.3 976.6 280.5 8,221.5 12.4 1,189.6 1,202.0 0.0 265.5 28.3 (46.5) 93.8 9,764.5 157.1 2037 3,020.8 3,880.8 349.5 989.0 287.2 8,527.3 76.7 1,234.7 1,311.4 0.0 289.0 28.5 (46.7) 93.3 10,202.7 160.4
CPW@ 7.86% (2008-2017) 4,283.0 5,601.6 327.4 2,892.2 345.9 13,450.1 751.2 2,670.3 3,421.5 (122.8) 338.4 141.9 (57.0) 415.1 17,587.2 76.1
(2008-2027) 10,505.4 11,012.8 726.4 4,719.3 1,045.1 28,008.9 965.3 4,302.0 5,267.3 (142.6) 674.8 196.7 (116.7) 807.6 34,696.1 93.4
(2008-2037) 14,574.9 15,378.1 1,103.1 5,976.8 1,419.4 38,452.3 1,033.0 5,701.8 6,734.9 (142.6) 976.6 230.5 (168.9) 950.7 47,033.5 103.2
APPENDIX 2 TABLE 106. TABLE 107. RISK ANALYSIS F - COST OF NUCLEAR GENERATION INCREASES by 25% SUPPLY SIDE SCENARIO 1 (SS-1/F) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 600.3 847.3 51.3 446.3 66.1 2,011.4 107.9 524.0 631.9 (24.3) 55.3 27.4 (11.6) 54.9 2,744.8 78.3 2015 637.0 865.0 52.4 462.7 89.7 2,106.8 130.6 643.6 774.2 (33.0) 57.4 27.4 (12.2) 58.3 2,979.0 82.1 2016 826.5 934.6 59.4 438.2 137.8 2,396.5 154.6 725.4 880.0 (37.0) 64.7 26.8 (12.7) 93.4 3,411.7 90.9 2017 1,041.4 1,159.4 75.5 455.2 160.8 2,892.3 161.2 616.9 778.1 (39.2) 72.4 23.7 (13.4) 100.0 3,813.9 98.3 2018 1,224.6 1,332.5 89.9 473.7 177.6 3,298.4 124.7 552.8 677.5 (38.4) 81.9 21.3 (14.3) 107.3 4,133.8 103.4 2019 1,342.0 1,359.1 92.1 489.0 181.5 3,463.8 126.7 596.8 723.5 (5.2) 85.5 20.6 (15.2) 114.3 4,387.3 106.7 2020 1,590.3 1,592.1 114.7 513.3 194.0 4,004.4 69.7 477.1 546.8 (2.6) 93.3 18.0 (16.5) 121.1 4,764.5 112.8 2021 1,871.2 1,685.4 126.0 544.1 225.3 4,452.0 70.5 584.5 655.0 0.0 102.3 23.5 (17.5) 127.8 5,343.1 123.3 2022 2,148.2 1,765.7 132.9 576.2 233.5 4,856.6 56.8 559.9 616.7 0.0 114.5 22.6 (18.9) 134.8 5,726.2 128.9 2023 2,162.0 1,676.6 126.0 613.1 227.2 4,804.9 29.4 784.3 813.6 0.0 102.9 26.4 (20.3) 142.6 5,870.1 128.9 2024 2,046.2 1,755.8 132.4 633.0 221.4 4,788.9 39.9 785.3 825.2 0.0 104.7 25.5 (21.4) 150.3 5,873.1 125.9 2025 2,085.0 1,810.2 137.1 650.6 236.4 4,919.3 55.2 1,003.8 1,058.9 0.0 115.5 32.0 (22.7) 158.2 6,261.3 131.1 2026 2,150.8 1,971.2 149.8 670.3 240.5 5,182.6 48.0 1,006.3 1,054.2 0.0 123.4 30.7 (24.1) 92.2 6,459.1 131.8 2027 2,260.3 2,102.5 166.1 693.1 234.7 5,456.7 11.1 1,021.2 1,032.2 0.0 132.7 30.4 (25.1) 92.2 6,719.1 133.7 2028 2,343.5 2,239.5 182.0 719.8 228.0 5,712.8 48.1 1,026.2 1,074.3 0.0 145.6 29.0 (26.5) 98.1 7,033.2 136.6 2029 2,401.6 2,427.7 198.4 744.6 222.6 5,994.9 42.2 1,025.0 1,067.2 0.0 162.9 27.6 (28.4) 98.0 7,322.1 138.4 2030 2,542.5 2,601.8 213.7 776.1 239.9 6,373.9 6.0 1,017.2 1,023.3 0.0 174.9 26.1 (30.4) 97.3 7,665.0 141.3 2031 2,612.5 2,763.6 228.9 805.5 283.4 6,694.1 47.1 1,018.5 1,065.6 0.0 190.0 24.5 (31.9) 96.8 8,039.0 144.6 2032 2,651.3 2,998.5 249.2 834.3 295.3 7,028.7 41.7 1,024.3 1,066.0 0.0 207.5 22.8 (35.0) 96.2 8,386.2 147.6 2033 2,721.2 3,167.5 265.2 863.1 312.4 7,329.4 56.2 1,055.5 1,111.7 0.0 217.5 22.7 (37.0) 95.9 8,740.2 150.0 2034 2,774.8 3,325.0 283.3 893.0 316.7 7,592.8 45.8 1,284.1 1,329.9 0.0 240.6 32.4 (40.3) 95.1 9,250.4 155.2 2035 2,818.8 3,518.5 301.5 922.9 307.8 7,869.5 60.1 1,327.2 1,387.3 0.0 256.7 32.3 (43.0) 94.4 9,597.2 157.5 2036 2,876.8 3,683.0 316.5 959.2 328.5 8,164.0 24.6 1,375.7 1,400.2 0.0 271.3 32.2 (46.5) 93.8 9,915.0 159.5 2037 2,940.0 3,923.8 340.9 972.0 333.2 8,510.0 14.1 1,420.3 1,434.5 0.0 295.4 32.0 (46.7) 93.3 10,318.5 162.2
CPW@ 7.86% (2008-2017) 4,218.9 5,513.4 321.6 2,890.2 338.5 13,282.5 729.6 2,938.5 3,668.1 (122.8) 331.6 153.7 (57.0) 415.1 17,671.2 76.5
(2008-2027) 9,979.9 10,768.8 708.7 4,695.6 1,013.0 27,165.9 951.5 5,152.7 6,104.2 (142.6) 656.6 230.6 (116.8) 807.6 34,705.5 93.4
(2008-2037) 13,888.1 15,157.6 1,076.3 5,931.5 1,427.3 37,480.8 1,009.5 6,828.9 7,838.4 (142.6) 963.4 271.8 (168.9) 950.7 47,193.6 103.5
APPENDIX 2 TABLE 107. TABLE 108. RISK ANALYSIS F - COST OF NUCLEAR GENERATION INCREASES by 25% SUPPLY SIDE SCENARIO 2 (SS-2/F) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 601.1 837.3 50.8 446.3 66.1 2,001.6 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 2,766.5 78.9 2015 639.3 846.7 51.1 462.7 89.7 2,089.5 120.9 707.6 828.5 (33.0) 56.0 30.6 (12.2) 58.3 3,017.7 83.1 2016 811.5 902.3 56.8 437.2 137.8 2,345.4 152.0 830.5 982.5 (37.0) 62.0 32.0 (12.7) 93.4 3,465.5 92.3 2017 1,024.4 1,110.7 71.1 453.4 160.2 2,819.8 161.9 759.2 921.1 (39.2) 68.6 30.5 (13.5) 100.0 3,887.3 100.2 2018 1,215.0 1,267.3 84.5 471.3 161.9 3,200.0 126.7 730.0 856.7 (38.4) 77.4 29.7 (14.3) 107.3 4,218.3 105.5 2019 1,362.3 1,294.3 86.8 486.7 174.2 3,404.4 122.6 773.5 896.1 (5.2) 80.8 28.8 (15.3) 114.3 4,503.9 109.5 2020 1,620.6 1,540.5 105.3 508.3 195.4 3,970.0 65.4 661.5 726.9 (2.6) 90.5 26.1 (16.6) 121.1 4,915.4 116.4 2021 1,936.0 1,616.6 117.3 539.8 234.2 4,443.9 64.3 766.0 830.3 0.0 98.1 31.5 (17.6) 127.8 5,513.9 127.2 2022 2,260.5 1,662.0 124.8 576.1 245.5 4,868.9 58.8 744.3 803.1 0.0 106.1 30.4 (19.0) 134.8 5,924.3 133.3 2023 2,275.0 1,541.5 115.5 617.7 238.5 4,788.3 31.2 968.6 999.9 0.0 93.8 34.1 (20.6) 142.6 6,038.0 132.6 2024 2,134.7 1,604.8 120.2 640.2 231.5 4,731.5 36.1 970.1 1,006.3 0.0 94.7 33.0 (21.7) 150.3 5,994.0 128.5 2025 2,172.6 1,650.4 124.0 658.0 227.8 4,832.8 51.5 1,188.1 1,239.7 0.0 103.9 39.3 (23.0) 158.2 6,351.0 133.0 2026 2,219.7 1,804.3 137.2 677.3 242.2 5,080.6 55.7 1,190.6 1,246.3 0.0 111.3 37.9 (24.4) 92.2 6,543.9 133.6 2027 2,262.7 1,965.4 149.2 695.3 245.5 5,318.1 58.2 1,205.5 1,263.7 0.0 123.3 37.3 (25.4) 92.2 6,809.3 135.5 2028 2,346.7 2,092.0 161.2 720.2 239.7 5,559.8 52.7 1,211.0 1,263.7 0.0 135.6 35.8 (26.6) 98.1 7,066.2 137.2 2029 2,431.1 2,284.8 176.2 746.2 233.9 5,872.2 46.7 1,209.3 1,256.1 0.0 153.4 34.1 (28.6) 98.0 7,385.2 139.6 2030 2,569.8 2,422.9 194.7 777.7 250.4 6,215.5 10.3 1,201.5 1,211.8 0.0 160.8 32.4 (30.6) 97.3 7,687.2 141.7 2031 2,637.4 2,571.9 211.9 807.1 255.0 6,483.5 51.1 1,202.9 1,254.0 0.0 174.1 30.6 (32.1) 96.8 8,006.8 144.0 2032 2,673.5 2,806.4 231.8 836.0 248.1 6,795.9 45.7 1,208.5 1,254.2 0.0 191.7 28.7 (35.3) 96.2 8,331.5 146.6 2033 2,762.4 2,964.5 246.0 865.6 267.6 7,106.2 36.5 1,239.9 1,276.3 0.0 200.2 28.3 (37.3) 95.9 8,669.6 148.8 2034 2,804.9 3,118.5 263.1 895.4 315.6 7,397.5 51.1 1,468.4 1,519.4 0.0 221.8 37.6 (40.6) 95.1 9,230.9 154.9 2035 2,853.2 3,309.4 281.3 925.6 326.5 7,696.0 40.0 1,511.5 1,551.5 0.0 238.4 37.3 (43.3) 94.4 9,574.2 157.1 2036 2,901.0 3,468.7 295.7 961.7 346.1 7,973.2 79.0 1,560.4 1,639.4 0.0 252.3 36.8 (46.7) 93.8 9,948.7 160.0 2037 2,944.9 3,691.5 317.6 973.9 351.5 8,279.4 18.5 1,604.6 1,623.1 0.0 274.9 36.3 (46.9) 93.3 10,260.1 161.3
CPW@ 7.86% (2008-2017) 4,205.0 5,458.3 317.2 2,888.8 338.2 13,207.4 722.3 3,112.3 3,834.6 (122.8) 327.4 162.2 (57.1) 415.1 17,766.8 76.9
(2008-2027) 10,137.3 10,389.8 674.0 4,696.3 1,017.1 26,914.6 951.0 5,903.7 6,854.7 (142.6) 629.9 263.8 (117.3) 807.6 35,210.7 94.8
(2008-2037) 14,081.1 14,501.7 1,012.0 5,934.9 1,425.7 36,955.4 1,014.9 7,854.1 8,869.0 (142.6) 914.1 313.7 (169.8) 950.7 47,690.4 104.6
APPENDIX 2 TABLE 108. TABLE 109. RISK ANALYSIS F - COST OF NUCLEAR GENERATION INCREASES by 25% SUPPLY SIDE SCENARIO 3 (SS-3/F) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 2,535.0 74.5 2014 601.9 837.3 50.8 446.3 66.1 2,002.5 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 2,767.4 78.9 2015 641.5 855.8 51.6 462.7 89.7 2,101.3 125.2 678.0 803.3 (33.0) 56.8 29.2 (12.2) 58.3 3,003.7 82.8 2016 846.4 936.2 59.0 438.2 137.8 2,417.6 153.7 720.8 874.4 (37.0) 64.8 27.0 (12.7) 93.4 3,427.4 91.3 2017 1,090.6 1,160.4 75.1 455.2 160.8 2,942.1 164.4 611.0 775.4 (39.2) 72.4 23.8 (13.4) 100.0 3,861.1 99.5 2018 1,311.7 1,333.4 89.8 473.7 177.6 3,386.3 127.7 547.1 674.7 (38.4) 82.2 21.4 (14.3) 107.3 4,219.2 105.5 2019 1,475.9 1,361.8 92.1 489.0 181.5 3,600.3 129.6 589.9 719.5 (5.2) 85.9 20.7 (15.2) 114.3 4,520.3 109.9 2020 1,778.5 1,593.7 114.6 513.3 194.0 4,194.1 72.5 471.3 543.8 (2.6) 93.3 18.1 (16.5) 121.1 4,951.3 117.2 2021 2,120.6 1,686.5 126.1 544.6 240.9 4,718.7 63.5 578.2 641.8 0.0 102.4 23.6 (17.6) 127.8 5,596.8 129.2 2022 2,472.0 1,718.4 129.0 581.8 256.3 5,157.6 57.5 554.4 611.9 0.0 110.3 22.7 (19.0) 134.8 6,018.2 135.4 2023 2,493.7 1,557.1 116.6 628.8 249.0 5,045.1 23.2 778.6 801.9 0.0 94.6 26.5 (20.5) 142.6 6,090.1 133.7 2024 2,307.9 1,609.1 120.0 653.3 241.7 4,932.0 33.4 779.8 813.2 0.0 94.5 25.6 (21.7) 150.3 5,993.8 128.5 2025 2,329.6 1,650.8 124.0 671.0 255.7 5,031.0 56.1 998.1 1,054.2 0.0 103.3 32.1 (23.0) 158.2 6,355.8 133.1 2026 2,389.1 1,808.0 137.7 691.4 259.1 5,285.3 48.9 1,000.6 1,049.5 0.0 110.9 30.8 (24.3) 92.2 6,544.3 133.6 2027 2,493.6 1,949.5 153.1 714.8 252.8 5,563.9 11.9 1,015.5 1,027.5 0.0 120.9 30.4 (25.4) 92.2 6,809.5 135.5 2028 2,572.6 2,067.6 167.7 742.1 245.5 5,795.4 48.9 1,020.6 1,069.5 0.0 132.3 29.1 (26.8) 98.1 7,097.6 137.8 2029 2,623.6 2,257.6 183.8 767.6 239.5 6,072.1 43.0 1,019.4 1,062.4 0.0 148.7 27.6 (28.7) 98.0 7,380.2 139.5 2030 2,695.1 2,420.8 197.7 794.9 256.1 6,364.6 41.7 1,011.5 1,053.2 0.0 160.1 26.1 (30.7) 97.3 7,670.6 141.4 2031 2,734.8 2,574.3 211.6 822.2 260.4 6,603.1 59.0 1,012.9 1,071.9 0.0 172.8 24.5 (32.2) 96.8 7,936.9 142.8 2032 2,779.8 2,810.6 231.3 852.1 278.2 6,952.0 53.3 1,018.1 1,071.3 0.0 190.3 22.8 (35.3) 96.2 8,297.4 146.0 2033 2,862.8 2,965.2 245.5 882.2 283.5 7,239.1 43.8 1,049.9 1,093.7 0.0 199.1 22.7 (37.3) 95.9 8,613.2 147.8 2034 2,899.6 3,119.5 262.9 912.4 275.0 7,469.3 58.3 1,278.4 1,336.7 0.0 222.4 32.4 (40.5) 95.1 9,115.3 153.0 2035 2,941.7 3,316.0 281.2 943.1 266.6 7,748.7 47.1 1,321.5 1,368.7 0.0 238.1 32.3 (43.3) 94.4 9,438.9 154.9 2036 3,007.0 3,472.3 295.0 980.7 288.3 8,043.3 36.1 1,370.0 1,406.1 0.0 251.9 32.1 (46.7) 93.8 9,780.6 157.3 2037 3,037.1 3,695.6 317.2 993.2 294.1 8,337.1 99.7 1,414.6 1,514.4 0.0 273.7 31.9 (46.9) 93.3 10,203.6 160.4
CPW@ 7.86% (2008-2017) 4,255.5 5,503.7 320.5 2,890.2 338.5 13,308.3 726.6 2,971.1 3,697.8 (122.8) 331.0 155.8 (57.1) 415.1 17,728.1 76.7
(2008-2027) 10,711.2 10,556.9 690.8 4,722.9 1,051.2 27,733.0 946.8 5,166.7 6,113.5 (142.6) 641.0 232.9 (117.2) 807.6 35,268.2 94.9
(2008-2037) 14,849.6 14,661.1 1,031.8 5,988.6 1,445.8 37,976.9 1,023.6 6,834.4 7,858.0 (142.6) 922.8 274.2 (169.8) 950.7 47,670.2 104.6
APPENDIX 2 TABLE 109. TABLE 110. RISK ANALYSIS F - COST OF NUCLEAR GENERATION INCREASES by 25% SUPPLY SIDE SCENARIO 4 (SS-4/F) TOTAL REVENUE REQUIREMENTS (MILLIONS OF DOLLARS)
Generation Purchases Sales Total Capital Variable Fixed Fuel New Sub Sub Gas Imputed EMIS DE-EE DumpEnergy Rev. Req. Fuel O&M + O&M Transmission Total Demand Energy Total Trans Debt Costs Costs Credit $Millions $/MWH
2008 523.9 742.6 40.2 404.2 8.6 1,719.6 72.7 272.9 345.6 (10.8) 38.6 13.6 (1.0) 26.6 0.0 2,132.3 66.3 2009 549.1 797.5 42.6 412.2 8.6 1,810.1 76.8 310.1 386.9 (8.3) 43.0 14.5 (1.2) 56.0 0.0 2,301.0 70.3 2010 573.3 755.6 42.3 422.9 20.9 1,815.0 115.7 340.5 456.2 (9.1) 43.2 24.5 (9.5) 54.8 0.0 2,375.1 72.2 2011 580.5 799.8 44.8 419.9 28.5 1,873.4 102.9 284.3 387.2 (10.0) 44.9 23.2 (9.9) 67.0 0.0 2,375.8 71.5 2012 578.7 721.3 41.7 423.8 30.7 1,796.2 105.2 445.8 551.0 (14.0) 44.4 27.8 (10.5) 84.9 0.0 2,479.8 73.6 2013 583.5 730.3 44.2 429.0 49.2 1,836.3 105.8 496.8 602.6 (19.0) 47.3 27.2 (10.8) 51.4 0.0 2,535.0 74.5 2014 601.9 837.3 50.8 446.3 66.1 2,002.5 106.2 556.1 662.3 (24.3) 54.7 29.0 (11.7) 54.9 (0.1) 2,767.3 78.9 2015 641.5 846.7 51.1 462.7 89.7 2,091.8 120.9 707.6 828.5 (33.0) 56.0 30.6 (12.2) 58.3 (0.1) 3,019.8 83.2 2016 821.4 893.6 56.0 437.2 137.8 2,346.0 147.5 863.5 1,011.1 (37.0) 61.7 33.7 (12.8) 93.4 (0.0) 3,496.0 93.1 2017 1,023.1 1,067.7 67.8 452.4 160.2 2,771.2 158.0 893.5 1,051.5 (39.2) 65.5 36.7 (13.5) 100.0 (0.0) 3,972.2 102.4 2018 1,188.9 1,184.6 78.7 468.4 161.3 3,081.9 128.6 974.2 1,102.8 (38.4) 71.6 40.7 (14.4) 107.3 (0.0) 4,351.4 108.8 2019 1,316.1 1,168.9 77.5 481.8 157.3 3,201.7 125.4 1,163.1 1,288.5 (5.2) 71.6 46.4 (15.5) 114.3 (0.9) 4,700.9 114.3 2020 1,558.4 1,342.9 90.4 501.3 170.4 3,663.3 66.1 1,214.9 1,281.1 (2.6) 76.4 50.4 (16.8) 121.1 (1.4) 5,171.5 122.4 2021 1,853.6 1,421.8 96.9 528.7 217.2 4,118.2 63.4 1,370.7 1,434.1 0.0 84.8 57.6 (17.8) 127.8 (2.8) 5,802.0 133.9 2022 2,204.5 1,442.2 98.1 564.9 233.0 4,542.7 59.5 1,354.9 1,414.4 0.0 91.4 56.2 (19.3) 134.8 (2.6) 6,217.5 139.9 2023 2,236.0 1,304.1 86.8 611.4 226.4 4,464.7 25.2 1,578.8 1,604.0 0.0 76.7 59.5 (21.1) 142.6 (20.1) 6,306.2 138.5 2024 2,059.8 1,364.5 90.5 635.4 268.2 4,418.4 35.2 1,582.2 1,617.5 0.0 76.8 57.9 (22.3) 150.3 (36.9) 6,261.8 134.3 2025 2,091.0 1,403.2 93.3 652.5 288.1 4,528.1 57.9 1,798.6 1,856.5 0.0 84.1 63.8 (23.6) 158.2 (39.1) 6,628.0 138.8 2026 2,159.8 1,538.8 104.5 672.4 280.9 4,756.4 50.6 1,800.8 1,851.4 0.0 91.2 61.9 (24.9) 92.2 (28.7) 6,799.4 138.8 2027 2,219.6 1,686.4 115.9 690.8 294.6 5,007.3 45.6 1,815.7 1,861.3 0.0 102.1 60.8 (25.9) 92.2 (24.8) 7,073.2 140.8 2028 2,289.2 1,801.0 125.2 714.8 296.9 5,227.2 61.0 1,822.5 1,883.5 0.0 114.5 58.7 (27.2) 98.1 (21.5) 7,333.2 142.4 2029 2,364.1 1,975.6 139.8 740.1 288.6 5,508.2 54.7 1,819.8 1,874.5 0.0 130.7 56.5 (29.1) 98.0 (12.8) 7,625.9 144.1 2030 2,446.0 2,134.2 152.5 766.5 304.2 5,803.5 52.9 1,811.8 1,864.7 0.0 141.7 54.1 (31.1) 97.3 (11.3) 7,918.9 146.0 2031 2,516.3 2,281.6 164.3 793.7 307.7 6,063.5 47.5 1,813.0 1,860.5 0.0 154.0 51.7 (32.6) 96.8 (9.2) 8,184.6 147.2 2032 2,584.7 2,506.5 183.1 823.3 300.2 6,397.9 42.2 1,820.1 1,862.3 0.0 171.3 49.1 (35.6) 96.2 (5.3) 8,536.0 150.2 2033 2,653.5 2,660.1 195.5 851.7 317.6 6,678.4 56.8 1,850.0 1,906.8 0.0 178.5 47.9 (37.6) 95.9 (4.0) 8,865.9 152.2 2034 2,704.9 2,818.5 210.0 881.3 320.6 6,935.4 46.4 2,078.5 2,124.9 0.0 201.7 56.5 (40.9) 95.1 (3.4) 9,369.4 157.2 2035 2,770.3 3,001.7 227.5 911.7 311.0 7,222.2 35.5 2,121.7 2,157.2 0.0 217.9 55.3 (43.7) 94.4 (2.5) 9,700.9 159.2 2036 2,818.6 3,151.7 239.7 947.4 331.4 7,488.9 74.7 2,171.8 2,246.6 0.0 229.9 54.0 (47.2) 93.8 (2.8) 10,063.1 161.9 2037 2,864.7 3,369.0 259.7 959.2 335.8 7,788.3 14.3 2,214.8 2,229.1 0.0 251.5 52.5 (47.2) 93.3 (1.5) 10,366.1 163.0
CPW@ 7.86% (2008-2017) 4,211.2 5,433.7 315.2 2,888.3 338.2 13,186.7 718.2 3,192.1 3,910.3 (122.8) 325.8 166.0 (57.2) 415.1 (0.1) 17,823.8 77.1
(2008-2027) 9,966.7 9,741.7 604.8 4,675.7 1,032.8 26,021.7 944.7 7,646.5 8,591.3 (142.6) 582.9 337.5 (118.4) 807.6 (41.3) 36,038.7 97.0
(2008-2037) 13,775.5 13,405.3 873.5 5,897.4 1,491.8 35,443.5 1,018.9 10,505.1 11,524.0 (142.6) 835.8 417.7 (171.6) 950.7 (54.2) 48,803.3 107.0
APPENDIX 2 TABLE 110.
RESOURCE PLAN REPORT
APPENDIX 3
LOAD FORECAST ANNUAL TABLES
TABLE OF CONTENTS
APPENDIX 3
LOAD FORECAST
Table 1 Annual Peak Load Forecast by Class
Table 2 Monthly Peak Load Forecast
Table 3 Own Load Monthly Energy Forecast by Class
Appendix 3 Page i
TABLE 1. ANNUAL PEAK LOAD FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY IMPACTS (in MW)
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 1. Residential 3,442 3,464 3,528 3,614 3,738 3,890 4,058 4,236 4,419 4,600 2. General Service 2,954 2,977 3,005 3,042 3,099 3,201 3,312 3,427 3,541 3,644 Small C&I 2,540 2,564 2,591 2,630 2,687 2,788 2,899 3,015 3,129 3,232 Large C&I 408 408 408 408 408 408 408 408 408 408 Irrigation & Streetlight 6665555544
3. Losses 767 772 783 797 809 839 871 905 940 973 4. Retail Subtotal 1+2+3 7,163 7,214 7,316 7,453 7,646 7,930 8,241 8,569 8,900 9,217 5. Net Wholesale 158 158 158 158 75 75 75 75 75 75 6. Own Load 4+5 7,321 7,372 7,474 7,612 7,722 8,005 8,316 8,644 8,976 9,293
2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
1. Residential 4,780 4,955 5,134 5,317 5,501 5,688 5,879 6,074 6,271 6,471 2. General Service 3,743 3,837 3,929 4,019 4,110 4,199 4,288 4,377 4,466 4,552 Small C&I 3,332 3,425 3,517 3,608 3,698 3,788 3,878 3,967 4,055 4,141 Large C&I 408 408 408 408 408 408 408 408 408 408 Irrigation & Streetlight 4444433333
3. Losses 1,006 1,038 1,069 1,101 1,133 1,166 1,198 1,232 1,265 1,298 4. Retail Subtotal 1+2+3 9,529 9,830 10,132 10,437 10,744 11,053 11,366 11,682 12,002 12,321 5. Net Wholesale 75 75 75 75 75 75 75 75 75 75 6. Own Load 4+5 9,605 9,905 10,207 10,513 10,820 11,128 11,442 11,758 12,077 12,397
APPENDIX 3 TABLE 1. TABLE 2. MONTHLY PEAK LOAD FORECAST BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY IMPACTS (in MW)
Year January February March April May June July August September October November December 2009 4,374.1 3,920.3 3,981.0 4,271.9 5,860.7 6,551.7 7,321.2 7,321.2 6,643.9 5,310.5 4,156.8 4,364.7 2010 4,404.9 3,950.3 4,008.3 4,328.7 5,896.3 6,596.6 7,372.1 7,372.1 6,689.3 5,346.4 4,185.0 4,394.5 2011 4,455.8 3,996.9 4,056.0 4,375.4 5,963.1 6,683.2 7,474.2 7,474.2 6,781.2 5,418.7 4,241.3 4,455.3 2012 4,526.7 4,053.9 4,121.0 4,432.7 6,059.6 6,800.0 7,611.6 7,611.6 6,905.3 5,516.2 4,317.1 4,537.0 2013 4,605.9 4,124.4 4,169.0 4,471.5 6,121.3 6,869.2 7,721.9 7,721.9 7,001.6 5,595.3 4,383.8 4,611.0 2014 4,730.2 4,236.2 4,305.4 4,620.4 6,332.7 7,112.9 8,005.3 8,005.3 7,254.2 5,793.0 4,538.5 4,775.0 2015 4,904.4 4,391.9 4,463.0 4,789.7 6,579.4 7,381.4 8,316.1 8,316.1 7,531.2 6,011.2 4,708.8 4,955.7 2016 5,090.5 4,557.7 4,630.4 4,982.2 6,818.9 7,666.6 8,644.3 8,644.3 7,822.1 6,238.2 4,885.7 5,142.6 2017 5,281.3 4,727.4 4,801.6 5,158.4 7,073.5 7,956.4 8,975.7 8,975.7 8,115.9 6,466.4 5,063.4 5,329.5 2018 5,466.1 4,890.4 4,965.2 5,327.1 7,316.0 8,232.5 9,292.9 9,292.9 8,397.1 6,685.0 5,233.6 5,509.3 2019 5,645.6 5,049.6 5,125.2 5,498.2 7,553.7 8,503.2 9,604.6 9,604.6 8,673.2 6,899.3 5,400.2 5,685.1 2020 5,819.5 5,203.4 5,279.9 5,663.4 7,783.2 8,764.7 9,905.1 9,905.1 8,939.5 7,104.7 5,559.7 5,853.2 2021 5,991.7 5,356.2 5,433.7 5,840.1 8,012.1 9,026.2 10,207.4 10,207.4 9,207.1 7,312.5 5,721.3 6,024.1 2022 6,166.2 5,511.1 5,589.2 5,997.8 8,243.7 9,290.8 10,512.6 10,512.6 9,477.4 7,521.8 5,884.0 6,196.3 2023 6,341.2 5,666.3 5,745.3 6,160.6 8,475.5 9,555.9 10,819.5 10,819.5 9,749.5 7,732.5 6,048.0 6,369.8 2024 6,516.6 5,822.0 5,901.7 6,328.2 8,709.1 9,823.2 11,128.3 11,128.3 10,023.8 7,944.9 6,212.9 6,544.6 2025 6,694.3 5,979.7 6,060.0 6,497.7 8,945.4 10,093.7 11,441.7 11,441.7 10,301.7 8,159.7 6,379.9 6,721.4 2026 6,874.0 6,138.7 6,219.9 6,668.6 9,185.7 10,367.0 11,757.8 11,757.8 10,581.8 8,376.0 6,547.9 6,899.4 2027 7,054.5 6,298.8 6,380.5 6,842.5 9,423.7 10,641.8 12,077.0 12,077.0 10,864.4 8,593.8 6,717.1 7,078.7 2028 7,236.0 6,459.4 6,541.3 7,012.4 9,663.8 10,917.2 12,396.6 12,396.6 11,147.1 8,811.2 6,885.8 7,257.3
APPENDIX 3 TABLE 2. TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2009 01 2,420,084 1,039,456 921,815 202,960 48,126 989 11,041 2,224,387 41,163 2,265,550 154,534 2009 02 2,125,509 931,767 909,459 197,442 49,126 872 10,245 2,098,911 47,473 2,146,384 (20,875) 2009 03 2,260,632 848,170 911,340 201,892 46,126 842 11,089 2,019,459 58,219 2,077,678 182,954 2009 04 2,282,308 804,580 917,491 207,960 47,126 1,380 11,256 1,989,793 75,886 2,065,679 216,629 2009 05 2,841,030 910,254 979,839 208,831 46,151 2,133 11,321 2,158,529 81,819 2,240,348 600,682 2009 06 3,220,942 1,278,783 1,132,166 219,262 48,189 2,698 10,861 2,691,959 98,319 2,790,278 430,664 2009 07 3,630,700 1,635,907 1,254,804 234,112 43,208 2,833 11,630 3,182,494 109,710 3,292,204 338,496 2009 08 3,763,030 1,655,009 1,232,981 230,725 46,201 2,451 11,386 3,178,753 98,331 3,277,084 485,946 2009 09 3,154,399 1,622,803 1,252,606 234,513 47,214 2,338 11,193 3,170,667 91,949 3,262,616 (108,217) 2009 10 2,470,146 1,192,856 1,118,603 222,230 46,220 2,370 11,154 2,593,433 67,464 2,660,897 (190,751) 2009 11 2,263,716 870,276 953,937 217,313 48,189 1,684 11,305 2,102,704 51,712 2,154,416 109,300 2009 12 2,395,063 962,968 956,490 206,812 46,126 1,490 11,184 2,185,070 39,109 2,224,179 170,884
2010 01 2,437,299 1,047,151 929,900 202,960 48,126 993 11,366 2,240,496 41,163 2,281,659 155,640 2010 02 2,140,177 938,594 917,195 197,442 49,126 875 10,544 2,113,776 47,473 2,161,249 (21,072) 2010 03 2,275,991 854,275 919,019 201,892 46,126 842 11,408 2,033,562 58,219 2,091,781 184,210 2010 04 2,297,811 810,291 925,469 207,960 47,126 1,382 11,579 2,003,807 75,886 2,079,693 218,118 2010 05 2,860,632 916,478 988,612 208,831 46,151 2,142 11,644 2,173,858 81,819 2,255,677 604,955 2010 06 3,242,732 1,287,294 1,142,151 219,262 48,189 2,700 11,180 2,710,776 98,319 2,809,095 433,637 2010 07 3,655,636 1,646,647 1,266,338 234,112 43,208 2,845 11,944 3,205,094 109,710 3,314,804 340,832 2010 08 3,788,795 1,665,643 1,244,405 230,725 46,201 2,453 11,702 3,201,129 98,331 3,299,460 489,335 2010 09 3,175,688 1,633,084 1,264,134 234,513 47,214 2,348 11,502 3,192,795 91,949 3,284,744 (109,056) 2010 10 2,486,638 1,200,358 1,128,651 222,230 46,220 2,380 11,470 2,611,309 67,464 2,678,773 (192,135) 2010 11 2,278,704 875,821 962,329 217,313 48,189 1,697 11,629 2,116,978 51,712 2,168,690 110,014 2010 12 2,411,174 969,153 964,948 206,812 46,126 1,501 11,498 2,200,038 39,109 2,239,147 172,027
2011 01 2,461,718 1,061,471 938,125 202,960 48,126 973 11,691 2,263,346 41,163 2,304,509 157,209 2011 02 2,161,846 952,140 925,330 197,442 49,126 857 10,842 2,135,737 47,473 2,183,210 (21,364) 2011 03 2,299,761 867,417 927,402 201,892 46,126 825 11,726 2,055,388 58,219 2,113,607 186,154 2011 04 2,322,528 823,674 934,137 207,960 47,126 1,354 11,900 2,026,151 75,886 2,102,037 220,491 2011 05 2,893,622 932,118 998,494 208,831 46,151 2,098 11,966 2,199,658 81,819 2,281,477 612,145 2011 06 3,283,109 1,309,796 1,154,254 219,262 48,189 2,645 11,498 2,745,644 98,319 2,843,963 439,146 2011 07 3,703,497 1,676,245 1,279,865 234,112 43,208 2,786 12,256 3,248,472 109,710 3,358,182 345,315 2011 08 3,839,467 1,696,309 1,257,480 230,725 46,201 2,403 12,018 3,245,136 98,331 3,343,467 496,000 2011 09 3,219,029 1,663,998 1,278,006 234,513 47,214 2,300 11,812 3,237,843 91,949 3,329,792 (110,763) 2011 10 2,519,925 1,223,653 1,141,169 222,230 46,220 2,331 11,785 2,647,388 67,464 2,714,852 (194,927) 2011 11 2,308,579 893,356 972,958 217,313 48,189 1,661 11,953 2,145,430 51,712 2,197,142 111,437 2011 12 2,444,533 989,137 975,674 206,812 46,126 1,470 11,812 2,231,031 39,109 2,270,140 174,393
APPENDIX 3 TABLE 3. Page 1 of 7 TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2012 01 2,496,759 1,083,384 948,698 202,960 48,126 953 12,015 2,296,136 41,163 2,337,299 159,460 2012 02 2,192,460 972,196 936,019 197,442 49,126 839 11,140 2,166,762 47,473 2,214,235 (21,775) 2012 03 2,332,585 886,142 938,513 201,892 46,126 808 12,046 2,085,527 58,219 2,143,746 188,839 2012 04 2,356,895 842,725 945,860 207,960 47,126 1,326 12,221 2,057,218 75,886 2,133,104 223,791 2012 05 2,938,870 954,085 1,011,633 208,831 46,151 2,054 12,289 2,235,043 81,819 2,316,862 622,008 2012 06 3,337,740 1,340,933 1,170,029 219,262 48,189 2,591 11,817 2,792,821 98,319 2,891,140 446,600 2012 07 3,768,140 1,716,443 1,297,998 234,112 43,208 2,729 12,570 3,307,060 109,710 3,416,770 351,370 2012 08 3,908,558 1,737,283 1,276,244 230,725 46,201 2,353 12,333 3,305,139 98,331 3,403,470 505,088 2012 09 3,277,704 1,704,631 1,298,098 234,513 47,214 2,251 12,121 3,298,828 91,949 3,390,777 (113,073) 2012 10 2,564,818 1,253,868 1,159,347 222,230 46,220 2,282 12,100 2,696,047 67,464 2,763,511 (198,693) 2012 11 2,348,733 915,677 988,591 217,313 48,189 1,627 12,275 2,183,672 51,712 2,235,384 113,349 2012 12 2,489,257 1,014,203 991,878 206,812 46,126 1,439 12,125 2,272,583 39,109 2,311,692 177,565
2013 01 2,545,533 1,112,176 965,239 202,960 48,126 936 12,339 2,341,776 41,163 2,382,939 162,594 2013 02 2,235,741 999,128 952,666 197,442 49,126 824 11,439 2,210,625 47,473 2,258,098 (22,357) 2013 03 2,354,742 911,631 955,800 201,892 46,126 794 12,365 2,128,608 35,056 2,163,664 191,078 2013 04 2,372,911 867,005 963,780 207,960 47,126 1,302 12,544 2,099,717 47,270 2,146,987 225,924 2013 05 2,956,399 982,840 1,031,686 208,831 46,151 2,018 12,611 2,284,137 40,422 2,324,559 631,840 2013 06 3,358,341 1,383,393 1,193,903 219,262 48,189 2,544 12,136 2,859,427 46,334 2,905,761 452,580 2013 07 3,802,364 1,773,163 1,325,201 234,112 43,208 2,680 12,883 3,391,247 55,992 3,447,239 355,125 2013 08 3,951,322 1,796,952 1,303,798 230,725 46,201 2,311 12,649 3,392,636 44,613 3,437,249 514,073 2013 09 3,322,076 1,766,296 1,326,994 234,513 47,214 2,211 12,430 3,389,658 51,887 3,441,545 (119,469) 2013 10 2,601,432 1,300,719 1,185,767 222,230 46,220 2,242 12,415 2,769,593 37,894 2,807,487 (206,055) 2013 11 2,387,084 950,707 1,011,578 217,313 48,189 1,598 12,599 2,241,984 30,250 2,272,234 114,850 2013 12 2,533,650 1,053,976 1,015,506 206,812 46,126 1,413 12,439 2,336,272 16,932 2,353,204 180,446
2014 01 2,597,431 1,153,466 991,700 202,960 48,126 920 12,664 2,409,836 21,450 2,431,286 166,145 2014 02 2,279,093 1,036,730 980,398 197,442 49,126 810 11,736 2,276,242 27,442 2,303,684 (24,591) 2014 03 2,424,687 946,252 985,101 201,892 46,126 779 12,683 2,192,833 35,056 2,227,889 196,798 2014 04 2,444,879 900,547 994,998 207,960 47,126 1,279 12,865 2,164,775 47,270 2,212,045 232,834 2014 05 3,052,080 1,021,817 1,067,248 208,831 46,151 1,982 12,934 2,358,963 40,422 2,399,385 652,695 2014 06 3,473,642 1,438,987 1,237,606 219,262 48,189 2,498 12,454 2,958,996 46,334 3,005,330 468,312 2014 07 3,937,060 1,844,880 1,375,298 234,112 43,208 2,632 13,196 3,513,326 55,992 3,569,318 367,742 2014 08 4,092,531 1,870,241 1,352,870 230,725 46,201 2,269 12,965 3,515,271 44,613 3,559,884 532,647 2014 09 3,440,215 1,838,112 1,377,701 234,513 47,214 2,171 12,739 3,512,450 51,887 3,564,337 (124,122) 2014 10 2,691,783 1,353,301 1,230,841 222,230 46,220 2,201 12,730 2,867,523 37,894 2,905,417 (213,634) 2014 11 2,468,217 989,501 1,049,759 217,313 48,189 1,568 12,923 2,319,253 30,250 2,349,503 118,714 2014 12 2,621,354 1,096,873 1,053,804 206,812 46,126 1,388 12,753 2,417,756 16,932 2,434,688 186,666
APPENDIX 3 TABLE 3. Page 2 of 7 TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2015 01 2,689,595 1,200,667 1,030,430 202,960 48,126 906 12,989 2,496,078 21,450 2,517,528 172,067 2015 02 2,359,025 1,079,196 1,018,650 197,442 49,126 798 12,036 2,357,248 27,442 2,384,690 (25,665) 2015 03 2,509,373 985,103 1,023,702 201,892 46,126 768 13,002 2,270,593 35,056 2,305,649 203,724 2015 04 2,529,622 937,801 1,034,045 207,960 47,126 1,260 13,188 2,241,380 47,270 2,288,650 240,972 2015 05 3,160,824 1,064,620 1,109,194 208,831 46,151 1,952 13,256 2,444,004 40,422 2,484,426 676,398 2015 06 3,601,229 1,500,139 1,286,349 219,262 48,189 2,462 12,774 3,069,175 46,334 3,115,509 485,720 2015 07 4,084,347 1,923,752 1,429,643 234,112 43,208 2,593 13,509 3,646,817 55,992 3,702,809 381,538 2015 08 4,247,438 1,950,930 1,406,429 230,725 46,201 2,236 13,281 3,649,802 44,613 3,694,415 553,023 2015 09 3,570,088 1,918,005 1,432,518 234,513 47,214 2,139 13,048 3,647,437 51,887 3,699,324 (129,236) 2015 10 2,791,758 1,412,292 1,279,928 222,230 46,220 2,169 13,046 2,975,885 37,894 3,013,779 (222,021) 2015 11 2,557,744 1,032,277 1,091,947 217,313 48,189 1,545 13,245 2,404,516 30,250 2,434,766 122,978 2015 12 2,718,362 1,144,083 1,096,429 206,812 46,126 1,367 13,067 2,507,884 16,932 2,524,816 193,546
2016 01 2,788,780 1,252,203 1,071,393 202,960 48,126 896 13,313 2,588,891 21,450 2,610,341 178,439 2016 02 2,444,748 1,125,538 1,058,896 197,442 49,126 789 12,333 2,444,124 27,442 2,471,566 (26,818) 2016 03 2,599,821 1,027,316 1,064,230 201,892 46,126 760 13,320 2,353,644 35,056 2,388,700 211,121 2016 04 2,620,369 978,372 1,075,200 207,960 47,126 1,246 13,509 2,323,413 47,270 2,370,683 249,686 2016 05 3,277,172 1,111,267 1,153,233 208,831 46,151 1,931 13,580 2,534,993 40,422 2,575,415 701,757 2016 06 3,737,622 1,566,351 1,337,630 219,262 48,189 2,434 13,093 3,186,959 46,334 3,233,293 504,329 2016 07 4,241,425 2,008,526 1,486,948 234,112 43,208 2,564 13,823 3,789,181 55,992 3,845,173 396,252 2016 08 4,411,203 2,036,590 1,462,703 230,725 46,201 2,210 13,597 3,792,026 44,613 3,836,639 574,564 2016 09 3,705,650 2,001,703 1,489,436 234,513 47,214 2,115 13,357 3,788,338 51,887 3,840,225 (134,575) 2016 10 2,895,113 1,473,039 1,330,917 222,230 46,220 2,144 13,360 3,087,910 37,894 3,125,804 (230,691) 2016 11 2,649,282 1,075,504 1,135,591 217,313 48,189 1,528 13,569 2,491,694 30,250 2,521,944 127,338 2016 12 2,816,840 1,191,369 1,140,338 206,812 46,126 1,352 13,381 2,599,378 16,932 2,616,310 200,530
2017 01 2,891,680 1,306,120 1,113,446 202,960 48,126 889 13,638 2,685,179 21,450 2,706,629 185,051 2017 02 2,533,502 1,173,788 1,100,300 197,442 49,126 783 12,632 2,534,071 27,442 2,561,513 (28,011) 2017 03 2,693,139 1,071,100 1,105,819 201,892 46,126 754 13,639 2,439,330 35,056 2,474,386 218,753 2017 04 2,713,313 1,020,120 1,117,158 207,960 47,126 1,237 13,831 2,407,432 47,270 2,454,702 258,611 2017 05 3,396,273 1,159,251 1,198,082 208,831 46,151 1,916 13,903 2,628,134 40,422 2,668,556 727,717 2017 06 3,876,973 1,634,363 1,389,655 219,262 48,189 2,416 13,412 3,307,297 46,334 3,353,631 523,342 2017 07 4,401,032 2,095,403 1,544,433 234,112 43,208 2,545 14,137 3,933,838 55,992 3,989,830 411,202 2017 08 4,577,126 2,124,611 1,518,480 230,725 46,201 2,194 13,913 3,936,124 44,613 3,980,737 596,389 2017 09 3,842,577 2,087,940 1,545,226 234,513 47,214 2,099 13,665 3,930,657 51,887 3,982,544 (139,967) 2017 10 2,998,719 1,535,782 1,380,171 222,230 46,220 2,129 13,675 3,200,207 37,894 3,238,101 (239,382) 2017 11 2,740,618 1,120,398 1,177,371 217,313 48,189 1,517 13,892 2,578,680 30,250 2,608,930 131,688 2017 12 2,914,460 1,240,278 1,181,824 206,812 46,126 1,341 13,694 2,690,075 16,932 2,707,007 207,453
APPENDIX 3 TABLE 3. Page 3 of 7 TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2018 01 2,992,127 1,360,395 1,152,843 202,960 48,126 886 13,963 2,779,173 21,450 2,800,623 191,504 2018 02 2,619,070 1,222,267 1,138,245 197,442 49,126 780 12,930 2,620,790 27,442 2,648,232 (29,162) 2018 03 2,782,276 1,115,081 1,143,369 201,892 46,126 751 13,959 2,521,178 35,056 2,556,234 226,042 2018 04 2,801,601 1,061,981 1,154,790 207,960 47,126 1,232 14,153 2,487,242 47,270 2,534,512 267,089 2018 05 3,509,039 1,207,205 1,238,000 208,831 46,151 1,909 14,225 2,716,321 40,422 2,756,743 752,296 2018 06 4,009,179 1,702,096 1,435,781 219,262 48,189 2,407 13,730 3,421,465 46,334 3,467,799 541,380 2018 07 4,552,568 2,181,790 1,595,085 234,112 43,208 2,535 14,449 4,071,179 55,992 4,127,171 425,397 2018 08 4,735,183 2,211,766 1,568,285 230,725 46,201 2,186 14,228 4,073,391 44,613 4,118,004 617,179 2018 09 3,973,701 2,173,113 1,596,040 234,513 47,214 2,091 13,974 4,066,945 51,887 4,118,832 (145,131) 2018 10 3,098,044 1,597,718 1,425,585 222,230 46,220 2,120 13,991 3,307,864 37,894 3,345,758 (247,714) 2018 11 2,828,242 1,164,828 1,216,075 217,313 48,189 1,511 14,215 2,662,131 30,250 2,692,381 135,861 2018 12 3,008,726 1,288,706 1,220,666 206,812 46,126 1,336 14,009 2,777,655 16,932 2,794,587 214,139
2019 01 3,088,952 1,414,061 1,189,460 202,960 48,126 882 14,288 2,869,777 21,450 2,891,227 197,725 2019 02 2,702,242 1,270,267 1,174,240 197,442 49,126 777 13,228 2,705,080 27,442 2,732,522 (30,280) 2019 03 2,869,215 1,158,662 1,179,302 201,892 46,126 748 14,277 2,601,007 35,056 2,636,063 233,152 2019 04 2,888,006 1,103,532 1,191,030 207,960 47,126 1,227 14,475 2,565,350 47,270 2,612,620 275,386 2019 05 3,619,442 1,254,651 1,276,578 208,831 46,151 1,901 14,548 2,802,660 40,422 2,843,082 776,360 2019 06 4,138,529 1,768,919 1,480,351 219,262 48,189 2,397 14,049 3,533,167 46,334 3,579,501 559,028 2019 07 4,701,614 2,267,194 1,644,462 234,112 43,208 2,525 14,763 4,206,264 55,992 4,262,256 439,358 2019 08 4,890,422 2,298,006 1,616,557 230,725 46,201 2,177 14,544 4,208,210 44,613 4,252,823 637,599 2019 09 4,102,411 2,257,677 1,644,954 234,513 47,214 2,083 14,283 4,200,724 51,887 4,252,611 (150,200) 2019 10 3,195,276 1,659,529 1,468,856 222,230 46,220 2,112 14,306 3,413,253 37,894 3,451,147 (255,871) 2019 11 2,913,664 1,209,143 1,252,795 217,313 48,189 1,505 14,539 2,743,484 30,250 2,773,734 139,930 2019 12 3,100,580 1,337,134 1,257,269 206,812 46,126 1,331 14,323 2,862,995 16,932 2,879,927 220,653
2020 01 3,183,055 1,467,338 1,223,917 202,960 48,126 879 14,613 2,957,833 21,450 2,979,283 203,772 2020 02 2,782,726 1,317,810 1,207,967 197,442 49,126 774 13,527 2,786,646 27,442 2,814,088 (31,362) 2020 03 2,953,395 1,201,751 1,213,191 201,892 46,126 746 14,596 2,678,302 35,056 2,713,358 240,037 2020 04 2,971,462 1,144,557 1,225,129 207,960 47,126 1,223 14,797 2,640,792 47,270 2,688,062 283,400 2020 05 3,726,075 1,301,279 1,313,026 208,831 46,151 1,894 14,870 2,886,051 40,422 2,926,473 799,602 2020 06 4,263,727 1,834,580 1,522,496 219,262 48,189 2,388 14,368 3,641,283 46,334 3,687,617 576,110 2020 07 4,845,682 2,350,864 1,691,061 234,112 43,208 2,516 15,076 4,336,837 55,992 4,392,829 452,853 2020 08 5,040,038 2,382,273 1,661,919 230,725 46,201 2,168 14,860 4,338,146 44,613 4,382,759 657,279 2020 09 4,226,145 2,340,062 1,690,875 234,513 47,214 2,075 14,592 4,329,331 51,887 4,381,218 (155,073) 2020 10 3,288,278 1,719,450 1,509,430 222,230 46,220 2,104 14,622 3,514,056 37,894 3,551,950 (263,672) 2020 11 2,994,927 1,252,169 1,286,845 217,313 48,189 1,499 14,862 2,820,877 30,250 2,851,127 143,800 2020 12 3,187,668 1,384,079 1,290,928 206,812 46,126 1,326 14,636 2,943,907 16,932 2,960,839 226,829
APPENDIX 3 TABLE 3. Page 4 of 7 TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2021 01 3,275,188 1,520,245 1,256,904 202,960 48,126 875 14,937 3,044,047 21,450 3,065,497 209,691 2021 02 2,861,790 1,365,177 1,240,432 197,442 49,126 771 13,825 2,866,773 27,442 2,894,215 (32,425) 2021 03 3,036,180 1,244,853 1,245,789 201,892 46,126 743 14,914 2,754,317 35,056 2,789,373 246,807 2021 04 3,053,661 1,185,682 1,257,993 207,960 47,126 1,218 15,119 2,715,098 47,270 2,762,368 291,293 2021 05 3,831,475 1,348,319 1,348,096 208,831 46,151 1,887 15,193 2,968,477 40,422 3,008,899 822,576 2021 06 4,388,164 1,901,071 1,563,154 219,262 48,189 2,379 14,687 3,748,742 46,334 3,795,076 593,088 2021 07 4,989,799 2,435,908 1,736,331 234,112 43,208 2,506 15,390 4,467,455 55,992 4,523,447 466,352 2021 08 5,190,740 2,468,390 1,706,375 230,725 46,201 2,160 15,175 4,469,026 44,613 4,513,639 677,101 2021 09 4,351,097 2,424,564 1,735,944 234,513 47,214 2,067 14,902 4,459,204 51,887 4,511,091 (159,994) 2021 10 3,382,530 1,781,181 1,549,552 222,230 46,220 2,096 14,936 3,616,215 37,894 3,654,109 (271,579) 2021 11 3,077,726 1,296,518 1,321,034 217,313 48,189 1,493 15,185 2,899,732 30,250 2,929,982 147,744 2021 12 3,277,088 1,432,694 1,325,082 206,812 46,126 1,321 14,950 3,026,985 16,932 3,043,917 233,171
2022 01 3,368,755 1,574,498 1,289,884 202,960 48,126 872 15,262 3,131,602 21,450 3,153,052 215,703 2022 02 2,942,154 1,413,849 1,272,908 197,442 49,126 768 14,124 2,948,217 27,442 2,975,659 (33,505) 2022 03 3,120,117 1,289,079 1,278,320 201,892 46,126 740 15,233 2,831,390 35,056 2,866,446 253,671 2022 04 3,136,962 1,227,844 1,290,816 207,960 47,126 1,214 15,440 2,790,400 47,270 2,837,670 299,292 2022 05 3,938,403 1,396,427 1,383,295 208,831 46,151 1,880 15,515 3,052,099 40,422 3,092,521 845,882 2022 06 4,514,337 1,969,011 1,603,862 219,262 48,189 2,370 15,006 3,857,700 46,334 3,904,034 610,303 2022 07 5,135,610 2,522,774 1,781,316 234,112 43,208 2,496 15,702 4,599,608 55,992 4,655,600 480,010 2022 08 5,342,845 2,556,146 1,750,408 230,725 46,201 2,152 15,491 4,601,123 44,613 4,645,736 697,109 2022 09 4,476,995 2,510,444 1,780,619 234,513 47,214 2,059 15,211 4,590,060 51,887 4,641,947 (164,952) 2022 10 3,477,389 1,843,911 1,589,332 222,230 46,220 2,087 15,251 3,719,031 37,894 3,756,925 (279,536) 2022 11 3,160,957 1,341,604 1,354,897 217,313 48,189 1,487 15,509 2,978,999 30,250 3,009,249 151,708 2022 12 3,366,983 1,482,118 1,358,869 206,812 46,126 1,316 15,263 3,110,504 16,932 3,127,436 239,547
2023 01 3,462,456 1,629,204 1,322,537 202,960 48,126 869 15,587 3,219,283 21,450 3,240,733 221,723 2023 02 3,022,457 1,462,841 1,305,004 197,442 49,126 765 14,422 3,029,600 27,442 3,057,042 (34,585) 2023 03 3,204,150 1,333,641 1,310,602 201,892 46,126 737 15,552 2,908,550 35,056 2,943,606 260,544 2023 04 3,220,196 1,270,314 1,323,270 207,960 47,126 1,208 15,763 2,865,641 47,270 2,912,911 307,285 2023 05 4,044,828 1,444,676 1,417,959 208,831 46,151 1,872 15,838 3,135,327 40,422 3,175,749 869,079 2023 06 4,640,323 2,037,323 1,644,037 219,262 48,189 2,360 15,325 3,966,496 46,334 4,012,830 627,493 2023 07 5,281,799 2,610,187 1,826,094 234,112 43,208 2,486 16,016 4,732,103 55,992 4,788,095 493,704 2023 08 5,495,794 2,644,702 1,794,375 230,725 46,201 2,144 15,807 4,733,954 44,613 4,778,567 717,227 2023 09 4,603,870 2,597,450 1,825,183 234,513 47,214 2,051 15,520 4,721,931 51,887 4,773,818 (169,948) 2023 10 3,572,964 1,907,529 1,628,998 222,230 46,220 2,080 15,567 3,822,624 37,894 3,860,518 (287,554) 2023 11 3,244,919 1,387,456 1,388,691 217,313 48,189 1,481 15,832 3,058,962 30,250 3,089,212 155,707 2023 12 3,457,837 1,532,265 1,392,824 206,812 46,126 1,310 15,578 3,194,915 16,932 3,211,847 245,990
APPENDIX 3 TABLE 3. Page 5 of 7 TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2024 01 3,556,113 1,684,220 1,354,838 202,960 48,126 866 15,912 3,306,922 21,450 3,328,372 227,741 2024 02 3,102,835 1,512,185 1,336,824 197,442 49,126 762 14,720 3,111,059 27,442 3,138,501 (35,666) 2024 03 3,288,145 1,378,550 1,342,504 201,892 46,126 734 15,870 2,985,676 35,056 3,020,732 267,413 2024 04 3,303,809 1,313,227 1,355,624 207,960 47,126 1,204 16,084 2,941,225 47,270 2,988,495 315,314 2024 05 4,152,326 1,493,820 1,452,567 208,831 46,151 1,865 16,160 3,219,394 40,422 3,259,816 892,510 2024 06 4,767,627 2,106,812 1,684,174 219,262 48,189 2,351 15,643 4,076,431 46,334 4,122,765 644,862 2024 07 5,429,424 2,699,140 1,870,633 234,112 43,208 2,477 16,330 4,865,900 55,992 4,921,892 507,532 2024 08 5,650,118 2,734,758 1,838,038 230,725 46,201 2,135 16,122 4,867,979 44,613 4,912,592 737,526 2024 09 4,731,968 2,685,877 1,869,598 234,513 47,214 2,043 15,829 4,855,074 51,887 4,906,961 (174,993) 2024 10 3,669,370 1,972,193 1,668,520 222,230 46,220 2,072 15,882 3,927,117 37,894 3,965,011 (295,641) 2024 11 3,329,477 1,434,069 1,422,292 217,313 48,189 1,475 16,155 3,139,493 30,250 3,169,743 159,734 2024 12 3,549,462 1,583,467 1,426,440 206,812 46,126 1,305 15,892 3,280,042 16,932 3,296,974 252,488
2025 01 3,650,856 1,740,351 1,387,042 202,960 48,126 862 16,237 3,395,578 21,450 3,417,028 233,828 2025 02 3,184,109 1,562,500 1,368,579 197,442 49,126 759 15,019 3,193,425 27,442 3,220,867 (36,758) 2025 03 3,372,886 1,424,289 1,374,259 201,892 46,126 731 16,190 3,063,487 35,056 3,098,543 274,343 2025 04 3,388,113 1,356,951 1,387,791 207,960 47,126 1,199 16,407 3,017,434 47,270 3,064,704 323,409 2025 05 4,260,573 1,543,831 1,486,893 208,831 46,151 1,858 16,483 3,304,047 40,422 3,344,469 916,104 2025 06 4,896,147 2,177,620 1,724,041 219,262 48,189 2,342 15,962 4,187,416 46,334 4,233,750 662,397 2025 07 5,578,667 2,789,798 1,914,936 234,112 43,208 2,468 16,642 5,001,164 55,992 5,057,156 521,511 2025 08 5,806,057 2,826,557 1,881,358 230,725 46,201 2,127 16,438 5,003,406 44,613 5,048,019 758,038 2025 09 4,861,597 2,776,238 1,913,670 234,513 47,214 2,035 16,138 4,989,808 51,887 5,041,695 (180,098) 2025 10 3,766,677 2,038,219 1,707,658 222,230 46,220 2,063 16,197 4,032,587 37,894 4,070,481 (303,804) 2025 11 3,414,736 1,481,531 1,455,709 217,313 48,189 1,470 16,479 3,220,691 30,250 3,250,941 163,795 2025 12 3,641,809 1,635,520 1,459,877 206,812 46,126 1,300 16,205 3,365,840 16,932 3,382,772 259,037
2026 01 3,746,851 1,797,517 1,419,376 202,960 48,126 858 16,568 3,485,405 21,450 3,506,855 239,996 2026 02 3,266,066 1,613,606 1,400,230 197,442 49,126 756 15,324 3,276,484 27,442 3,303,926 (37,860) 2026 03 3,458,589 1,470,782 1,406,138 201,892 46,126 728 16,515 3,142,181 35,056 3,177,237 281,352 2026 04 3,473,106 1,401,373 1,419,875 207,960 47,126 1,195 16,736 3,094,265 47,270 3,141,535 331,571 2026 05 4,369,943 1,594,672 1,521,261 208,831 46,151 1,851 16,812 3,389,578 40,422 3,430,000 939,943 2026 06 5,026,091 2,249,654 1,763,904 219,262 48,189 2,333 16,288 4,299,630 46,334 4,345,964 680,127 2026 07 5,729,252 2,881,913 1,958,990 234,112 43,208 2,459 16,961 5,137,643 55,992 5,193,635 535,617 2026 08 5,963,532 2,919,916 1,924,447 230,725 46,201 2,119 16,760 5,140,168 44,613 5,184,781 778,751 2026 09 4,992,157 2,867,974 1,957,328 234,513 47,214 2,027 16,453 5,125,509 51,887 5,177,396 (185,239) 2026 10 3,864,630 2,105,150 1,746,582 222,230 46,220 2,055 16,520 4,138,757 37,894 4,176,651 (312,021) 2026 11 3,500,354 1,529,653 1,488,802 217,313 48,189 1,465 16,809 3,302,231 30,250 3,332,481 167,873 2026 12 3,734,511 1,688,225 1,492,984 206,812 46,126 1,295 16,525 3,451,967 16,932 3,468,899 265,612
APPENDIX 3 TABLE 3. Page 6 of 7 TABLE 3. OWN LOAD MONTHLY ENERGY FORECAST BY CLASS BEFORE ENERGY EFFICIENCY AND DISTRIBUTED ENERGY RESOURCE IMPACTS (in MWhs)
Billed MWH Sales by Class Losses and Monthly Total Commercial & Industrial Streetlighting & Retail Trad. SFR, excl. Net Unbilled Year Month Energy (MWhs) Residential < 3 MW > 3 MW, excl Mines Mines Irrigation Other Pub Auth Subtotal Pac Supplmntl. Total Sales
2027 01 3,842,943 1,855,513 1,451,298 202,960 48,126 858 16,568 3,575,323 21,450 3,596,773 246,170 2027 02 3,348,272 1,665,479 1,431,669 197,442 49,126 756 15,324 3,359,796 27,442 3,387,238 (38,966) 2027 03 3,544,282 1,517,994 1,437,611 201,892 46,126 728 16,515 3,220,866 35,056 3,255,922 288,360 2027 04 3,558,211 1,446,496 1,451,685 207,960 47,126 1,195 16,736 3,171,198 47,270 3,218,468 339,743 2027 05 4,479,424 1,646,384 1,555,167 208,831 46,151 1,851 16,812 3,475,196 40,422 3,515,618 963,806 2027 06 5,156,228 2,322,736 1,803,204 219,262 48,189 2,333 16,288 4,412,012 46,334 4,458,346 697,882 2027 07 5,880,966 2,975,575 2,002,831 234,112 43,208 2,459 16,961 5,275,146 55,992 5,331,138 549,828 2027 08 6,122,064 3,014,714 1,967,328 230,725 46,201 2,119 16,760 5,277,847 44,613 5,322,460 799,604 2027 09 5,123,742 2,961,125 2,000,944 234,513 47,214 2,027 16,453 5,262,276 51,887 5,314,163 (190,421) 2027 10 3,963,078 2,173,176 1,785,263 222,230 46,220 2,055 16,520 4,245,464 37,894 4,283,358 (320,280) 2027 11 3,586,326 1,578,493 1,521,840 217,313 48,189 1,465 16,809 3,384,109 30,250 3,414,359 171,967 2027 12 3,827,756 1,741,822 1,526,019 206,812 46,126 1,295 16,525 3,538,599 16,932 3,555,531 272,225
2028 01 3,939,807 1,914,352 1,483,106 202,960 48,126 852 16,568 3,665,964 21,450 3,687,414 252,393 2028 02 3,430,925 1,718,123 1,462,795 197,442 49,126 750 15,324 3,443,560 27,442 3,471,002 (40,077) 2028 03 3,630,179 1,565,796 1,468,686 201,892 46,126 723 16,515 3,299,738 35,056 3,334,794 295,385 2028 04 3,643,353 1,492,194 1,482,962 207,960 47,126 1,186 16,736 3,248,164 47,270 3,295,434 347,919 2028 05 4,589,068 1,698,752 1,588,559 208,831 46,151 1,837 16,812 3,560,942 40,422 3,601,364 987,704 2028 06 5,286,793 2,396,832 1,841,875 219,262 48,189 2,316 16,288 4,524,762 46,334 4,571,096 715,697 2028 07 6,032,798 3,070,470 2,045,564 234,112 43,208 2,441 16,961 5,412,756 55,992 5,468,748 564,050 2028 08 6,280,825 3,110,886 2,009,050 230,725 46,201 2,103 16,760 5,415,725 44,613 5,460,338 820,487 2028 09 5,255,316 3,055,644 2,043,196 234,513 47,214 2,012 16,453 5,399,032 51,887 5,450,919 (195,603) 2028 10 4,061,279 2,242,158 1,822,734 222,230 46,220 2,040 16,520 4,351,902 37,894 4,389,796 (328,517) 2028 11 3,671,739 1,628,075 1,553,614 217,313 48,189 1,454 16,809 3,465,454 30,250 3,495,704 176,035 2028 12 3,920,259 1,796,065 1,557,729 206,812 46,126 1,285 16,525 3,624,542 16,932 3,641,474 278,785
APPENDIX 3 TABLE 3. Page 7 of 7
RESOURCE PLAN REPORT
APPENDIX 4
DATA TABLES FOR EXISTING RESOURCES
TABLE OF CONTENTS
APPENDIX 4
DATA TABLES FOR EXISTING RESOURCES
Table 1 Existing APS-Owned Conventional Generating Units
Table 2 Long-Term Purchased Power Contracts
Table 3 Existing APS-Owned Solar Facilities
Appendix 4 Page i
DATA TABLES FOR EXISTING RESOURCES
APPENDIX 4
Table 1 – Existing APS-Owned Conventional Generating Units
2008 2008 Non-Summer Summer Heat Rate Heat Rate Variable Fixed Expected Maximum Maximum Minimum at Max. at 50% O&M O&M Duty In-Service Capacity Capacity Capacity Rating Rating Expense Expense Name Fuel Type Cycle Date (MWs) (MWs) (MWs) (BTUs/KWH) (BTUs/KWH) ($/MWH) ($/KW/yr) Notes and Comments 1 Palo Verde #1 Nuclear Baseload 1986 382 382 150 10,385 N/A 0.00 151.00 Represents APS' 29.1% share of unit 2 Palo Verde #2 Nuclear Baseload 1986 382 382 150 10,361 N/A 0.00 151.00 Represents APS' 29.1% share of unit 3 Palo Verde #3 Nuclear Baseload 1986 383 383 150 10,337 N/A 0.00 151.00 Represents APS' 29.1% share of unit 4 Four Corners #1 Coal Baseload 1963 170 170 80 10,750 11,976 2.16 46.40 5 Four Corners #2 Coal Baseload 1963 170 170 80 10,750 11,976 2.16 46.40 6 Four Corners #3 Coal Baseload 1964 220 220 100 10,729 11,844 2.16 46.40 7 Four Corners #4 Coal Baseload 1969 113 113 60 9,687 9,687 1.47 18.77 Represents APS' 15% share of unit 8 Four Corners #5 Coal Baseload 1970 113 113 60 9,687 9,687 1.47 18.77 Represents APS' 15% share of unit 9 Cholla #1 Coal Baseload 1962 110 110 30 10,578 11,370 2.80 42.80 10 Cholla #2 Coal Baseload 1978 260 260 75 10,644 11,495 2.80 42.80 11 Cholla #3 Coal Baseload 1980 271 271 75 10,534 11,058 2.80 42.80 12 Navajo #1 Coal Baseload 1974 105 105 50 10,060 10,060 1.28 30.94 Represents APS' 14% share of unit 13 Navajo #2 Coal Baseload 1975 105 105 50 10,060 10,060 1.28 30.94 Represents APS' 14% share of unit 14 Navajo #3 Coal Baseload 1976 105 105 50 10,060 10,060 1.28 30.94 Represents APS' 14% share of unit Subtotal Baseload Generating Units 2,888 2,888 1,160
1 Redhawk CC #1 Nat. Gas Intermediate 2002 492 474 250 6,974 8,566 3.03 5.48 2 Redhawk CC #2 Nat. Gas Intermediate 2002 492 474 250 6,974 8,566 3.03 5.48 3 West Phoenix CC #1 Nat. Gas Intermediate 1976 85 80 10 9,269 11,497 1.01 11.41 4 West Phoenix CC #2 Nat. Gas Intermediate 1976 85 80 10 9,269 11,497 1.01 11.41 5 West Phoenix CC #3 Nat. Gas Intermediate 1976 85 80 50 9,269 NA 1.01 11.41 Unit can not operate at 50% rating 6 West Phoenix CC #4 Nat. Gas Intermediate 2001 117 107 77 8,037 9,525 2.84 4.52 7 West Phoenix CC #5 Nat. Gas Intermediate 2003 506 490 330 7,290 8,015 2.47 5.37 Subtotal Intermediate Generating Units 1,862 1,785 977
1 Ocotillo Steam 1 Nat. Gas Peaking 1960 110 110 20 10,510 10,928 2.14 14.57 2 Ocotillo Steam 2 Nat. Gas Peaking 1960 110 110 20 10,510 10,928 2.14 14.57 3 Saguaro Steam 1 Nat. Gas Peaking 1954 110 110 20 11,533 12,511 2.68 8.93 4 Saguaro Steam 2 Nat. Gas Peaking 1955 100 100 20 11,610 12,735 2.68 8.93 5 W. Phx CT 1 Nat. Gas Peaking 1972 55 50 4 14,008 17,632 NA 4.50 6 W. Phx CT 2 Nat. Gas Peaking 1973 55 50 4 14,008 17,632 NA 4.50 7 Ocotillo CT 1 Nat. Gas Peaking 1972 55 50 4 14,008 17,632 NA 5.65 8 Ocotillo CT 2 Nat. Gas Peaking 1973 55 50 4 14,008 17,632 NA 5.65 9 Saguaro CT 1 Nat. Gas Peaking 1972 55 50 4 14,008 17,632 NA 5.93 10 Saguaro CT 2 Nat. Gas Peaking 1973 55 50 4 14,008 17,632 NA 5.93 11 Saguaro CT 3 Nat. Gas Peaking 2002 79 76 40 11,596 14,464 4.00 6.49 12 Sundance CT1 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 13 Sundance CT2 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 14 Sundance CT3 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 15 Sundance CT4 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 16 Sundance CT5 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 17 Sundance CT6 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 18 Sundance CT7 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 19 Sundance CT8 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 20 Sundance CT9 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 21 Sundance CT10 Nat. Gas Peaking 2002 42 41 20 9,826 11,778 3.89 6.29 22 Yucca CT 1 Nat. Gas Peaking 1971 19 18 2 14,180 18,550 NA 4.02 23 Yucca CT 2 Nat. Gas Peaking 1971 19 18 2 14,180 18,550 NA 4.02 24 Yucca CT 3 Nat. Gas Peaking 1973 55 52 5 13,579 17,110 NA 4.02 25 Yucca CT 4 Oil Peaking 1974 54 51 5 13,579 17,110 NA 4.02 26 Yucca CT 5 Nat. Gas Peaking 2008 48 47 24 9,811 11,785 3.42 6.29 27 Yucca CT 6 Nat. Gas Peaking 2008 48 47 24 9,811 11,785 3.42 6.29 28 Douglas CT Oil Peaking 1972 16 15 2 14,482 18,944 NA 6.68 Subtotal Intermediate Generating Units 1,518 1,464 408
Appendix 4 Table 1
Table 2 – Long-Term Purchased Power Contracts
Maximum Capacity Capacity Expense 2009 Contract Contract Name Purchase Type (MW) ($M/year) Fuel Type Start Date End Date Notes and Comments Merchant CC Tolling #1 Tolling 500 29.7 Natural Gas Jun, 2007 May, 2017 Merchant CC Tolling #2 Tolling 560 33.3 Natural Gas Jun, 2007 Oct, 2019 Expense is 2010 value SRP T&C Dispachable Capacity/Energy 238 28.2 N/A 1955 June, 2010 Energy price based upon nat. gas PacifiCorp Diversity Exchange Seasonal Exchange 480 N/A N/A 1996 Oct, 2020 Last return winter 2020-2021 Market Call Option #1 Call Option 150 6.6 N/A Jun, 2007 Oct, 2021 Energy priced indexed to nat. gas Market Call Option #2 Call Option 500 6.0 N/A Jun, 2007 Sep, 2015 Energy priced indexed to nat. gas
Appendix 4 Table 2
Table 3 – Existing APS-Owned Solar Facilities
Site Grid-Tied or AC Rating DC Rating Completion Turn-On Name / Description Location Solar Plant type Off-Grid (KWs) (KWs) Date Date 1 ADEQ Covered Parking Phoenix Fixed Horizontal Grid-tied 107.1 126.0 12/1/2002 6/1/2003 2 CT Microdish MJ CPV Test Tempe Concentrator Grid-tied 0.7 1.0 9/3/2004 9/3/2004 3 CT Microdish MJ CPV Test II Tempe Concentrator Grid-tied 1.5 1.8 12/1/2006 4 Deer Valley School (Constitution) Phoenix Fixed at Latitude Grid-tied 3.9 4.5 10/1/1998 10/1/1998 5 Flagstaff Flagstaff Single Axis - Horizontal Grid-tied 80.3 94.5 10/1/1997 10/1/1997 6 Gilbert Nature Center Gilbert Single Axis - Horizontal Grid-tied 122.4 144.0 2/1/2001 2/1/2001 7 Gilbert School District Gilbert Fixed at Latitude Grid-tied 1.9 2.3 4/1/2001 12/1/2001 8 Glendale 1 Tracker Glendale Concentrator Grid-tied 24.0 28.2 4/1/2001 4/1/2001 9 Glendale 2 Tracker Glendale Concentrator Grid-tied 24.0 28.2 4/1/2001 4/1/2001 10 Glendale 3 Tracker Glendale Concentrator Grid-tied 24.0 28.2 4/1/2001 4/1/2001 11 Glendale 4 Tracker Glendale Concentrator Grid-tied 24.0 28.2 4/1/2001 4/1/2001 12 Glendale UPG Glendale Single Axis - Horizontal Grid-tied 76.2 89.6 10/1/1999 10/1/1999 13 Mustang Library Scottsdale Fixed at Latitude Grid-tied 1.9 2.3 12/1/2001 12/1/2001 14 Ocotillo 1 (UPG) Tempe Single Axis - Horizontal Grid-tied 80.3 94.5 4/1/1998 2/1/1998 15 Ocotillo 2 (Maxtracker) Tempe Single Axis - Horizontal Grid-tied 93.8 110.3 10/1/1999 10/1/1999 16 Ocotillo 3 Tempe Single Axis - Horizontal Grid-tied 34.9 41.0 17 Ocotillo Covered Parking Tempe Fixed Horizontal Grid-tied 8.1 9.5 6/1/2001 6/1/2001 18 Phoenix 502 Canopy Phoenix Fixed Horizontal Grid-tied 6.7 7.9 3/1/2003 4/7/2003 19 Prescott Airport AX-C1 Prescott Concentrator Grid-tied 33.6 39.5 6/30/2003 1/22/2004 20 Prescott Airport AX-C2 Prescott Concentrator Grid-tied 33.6 39.5 6/30/2003 7/14/2003 21 Prescott Airport AX-C3 Prescott Concentrator Grid-tied 33.6 39.5 6/30/2003 7/14/2003 22 Prescott Airport AX-C4 Prescott Concentrator Grid-tied 33.6 39.5 12/1/2002 4/1/2003 23 Prescott Airport AX-C5 Prescott Concentrator Grid-tied 33.6 39.5 6/30/2003 1/29/2004 24 Prescott Airport MT-A01 Prescott Single Axis - Horizontal Grid-tied 102.9 121.0 12/31/2002 2/3/2003 25 Prescott Airport MT-A02 Prescott Single Axis - Horizontal Grid-tied 102.9 121.0 10/30/2002 12/1/2002 26 Prescott Airport MT-A03 Prescott Single Axis - Horizontal Grid-tied 109.2 128.5 10/30/2002 12/1/2002 27 Prescott Airport MT-A04 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 12/31/2002 2/3/2003 28 Prescott Airport MT-A05 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 2/28/2003 5/7/2003 29 Prescott Airport MT-A06 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 2/28/2003 5/7/2003 30 Prescott Airport MT-A07 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 4/28/2003 6/30/2003 31 Prescott Airport MT-A08 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 6/14/2003 6/30/2003 32 Prescott Airport MT-A09 Prescott Single Axis - Horizontal Grid-tied 149.4 175.8 9/30/2004 10/4/2004 33 Prescott Airport MT-A10 Prescott Single Axis - Horizontal Grid-tied 146.9 172.8 4/8/2005 4/8/2005 34 Prescott Airport MT-A11 Prescott Single Axis - Horizontal Grid-tied 162.4 191.1 12/30/2005 12/30/2005 35 Prescott Airport MT-A12 Prescott Single Axis - Horizontal Grid-tied 162.4 191.1 12/8/2006 12/8/2006 36 Prescott Airport MT-B01 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 10/30/2002 12/1/2002 37 Prescott Airport MT-B02 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 2/28/2003 5/7/2003 38 Prescott Airport MT-B03 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 2/28/2003 5/7/2003 39 Prescott Airport MT-B04 Prescott Single Axis - Horizontal Grid-tied 128.5 151.2 4/28/2003 6/30/2003 40 Prescott Airport MT-B05 Prescott Single Axis - Horizontal Grid-tied 100.0 117.6 6/14/2003 6/30/2003 41 Prescott Airport MT-B06 Prescott Single Axis - Horizontal Grid-tied 146.9 172.8 9/30/2004 10/4/2004 42 Prescott Airport MT-B07 Prescott Single Axis - Horizontal Grid-tied 160.7 189.0 6/8/2005 6/8/2005 43 Prescott Airport MT-B08 Prescott Single Axis - Horizontal Grid-tied 162.4 191.1 9/14/2005 9/14/2005 44 Prescott Airport MT-B09 Prescott Single Axis - Horizontal Grid-tied 162.4 191.1 12/30/2005 12/30/2005 45 Prescott Airport TT-1 (East) Prescott Single Axis - Tilted Grid-tied 24.5 28.8 2/4/2004 2/4/2004 46 Prescott Airport TT-2 (West) Prescott Single Axis - Tilted Grid-tied 24.5 28.8 2/4/2004 2/4/2004 47 Prescott College Prescott Fixed Horizontal Grid-tied 10.7 12.6 10/15/2004 10/15/2004 48 Prescott ERAU Prescott Single Axis - Horizontal Grid-tied 194.2 228.5 4/1/2001 4/1/2001 49 Saguaro Solar Trough Red Rock Concentrating Solar Thermal Grid-tied 1,000.0 0.0 12/29/2005 12/29/2005 50 San Luis San Luis Fixed at Latitude Grid-tied 1.9 2.3 3/1/1999 3/1/1999 51 Scottsdale Civic Library Scottsdale Fixed at Latitude Grid-tied 1.9 2.3 4/1/1999 4/1/1999 52 Scottsdale Covered Parking Scottsdale Fixed Horizontal Grid-tied 79.3 93.3 1/3/2003 1/3/2003 53 Scottsdale Water Campus - East 1 Scottsdale Single Axis - Horizontal Grid-tied 32.2 37.8 4/1/2002 4/1/2002 54 Scottsdale Water Campus - East 2 Scottsdale Single Axis - Horizontal Grid-tied 32.0 37.7 4/1/2002 4/1/2002 55 Scottsdale Water Campus - East 3 Scottsdale Single Axis - Horizontal Grid-tied 35.9 42.2 4/1/2002 4/1/2002 56 Scottsdale Water Campus - East 4 Scottsdale Single Axis - Horizontal Grid-tied 34.7 40.8 4/1/2002 4/1/2002 57 Scottsdale Water Campus - West 1 Scottsdale Single Axis - Horizontal Grid-tied 29.1 34.2 4/1/2002 4/1/2002 58 Scottsdale Water Campus - West 2 Scottsdale Single Axis - Horizontal Grid-tied 29.1 34.2 4/1/2002 4/1/2002 59 Scottsdale Water Campus - West 3 Scottsdale Single Axis - Horizontal Grid-tied 35.7 42.0 4/1/2002 4/1/2002 60 Scottsdale Water Campus - West 4 Scottsdale Single Axis - Horizontal Grid-tied 28.6 33.6 4/1/2002 4/1/2002 61 ST Micro (Crystalline) Phoenix Fixed Horizontal Grid-tied 21.9 25.7 7/1/2000 7/1/2000 62 STAR Covered Parking Tempe Fixed Horizontal Grid-tied 4.3 5.0 6/1/1999 6/1/1999 63 STAR East 1 Tracker Tempe Concentrator Grid-tied 24.0 28.2 3/1/2002 3/1/2002 64 STAR East 4 Tracker Tempe Concentrator Grid-tied 24.0 28.2 8/1/2002 8/1/2002 65 STAR Rooftop_First Solar Tempe Fixed Horizontal Grid-tied 2.8 3.3 12/1/2003 12/1/2003 66 STAR Test Rooftop_R1E (Astropower) Tempe Fixed at Latitude Grid-tied 2.5 2.9 8/1/2003 8/1/2003 67 STAR Test Rooftop_R1W (Shell) Tempe Fixed at Latitude Grid-tied 2.0 2.4 8/1/2003 8/1/2003 68 STAR Test Rooftop_R2E (Kyocera) Tempe Fixed at Latitude Grid-tied 2.0 2.4 8/1/2003 8/1/2003 69 STAR Test Rooftop_R2W (BP Solar) Tempe Fixed at Latitude Grid-tied 2.5 2.9 8/1/2003 8/1/2003 70 STAR Test Rooftop_R3E (ADEQ Mockup) Tempe Fixed Horizontal Grid-tied 1.4 1.7 8/1/2003 8/1/2003 71 STAR Test Rooftop_R3W (IES) Tempe Fixed Horizontal Grid-tied 2.0 2.4 8/1/2003 8/1/2003 72 STAR Tilted_17V Tempe Single Axis - Tilted Grid-tied 22.9 26.9 6/1/2001 5/31/2001 73 STAR Tilted_50V Tempe Single Axis - Tilted Grid-tied 11.4 13.4 8/1/2001 11/30/2001 74 STAR Tilted_Assorted Tempe Single Axis - Tilted Grid-tied 20.6 24.2 3/1/2002 3/30/2002 75 STAR Tilted_Matrix Tempe Single Axis - Tilted Grid-tied 11.7 13.7 8/1/2001 11/30/2001 76 STAR West 1 Tracker Tempe Concentrator Grid-tied 24.0 28.2 5/1/2001 5/1/2001 77 STAR West 2 FD Tracker Tempe Concentrator Grid-tied 33.6 39.5 9/30/2004 10/4/2004 78 STAR West 3 FD Tracker Tempe Concentrator Grid-tied 33.6 39.5 9/30/2004 10/4/2004 79 STAR West 5 Tracker Tempe Concentrator Grid-tied 24.0 28.2 11/1/2001 11/1/2001 80 STAR West 7 Tracker Tempe Concentrator Grid-tied 24.0 28.2 9/1/2001 9/1/2001 81 Tempe Recycle Ctr. Tempe Fixed at Latitude Grid-tied 1.9 2.3 12/1/1999 2/1/1999 82 Yucca Power Plant Yuma Single Axis - Horizontal Grid-tied 102.9 121.0 1/1/2002 1/1/2002 83 Yuma Wetlands TT-North Yuma Single Axis - Tilted Grid-tied 34.9 41.0 9/3/2005 9/3/2005 84 Yuma Wetlands TT-South Yuma Single Axis - Tilted Grid-tied 34.9 41.0 9/3/2005 9/3/2005 85 Carol Spring Mountain Globe Large Hybrid Off-grid 29.0 34.1 10/1/1996 10/1/1996 86 Gray Wolf Dewey Large Hybrid Off-grid 23.8 28.0 10/1/2002 10/1/2002 Note - Data is as of 09/19/2008 Totals = 5,825.6 5,677.2
Appendix 4 Table 3
RESOURCE PLAN REPORT
APPENDIX 5
DESCRIPTION OF ANALYSIS METHODOLOGY
DESCRIPTION OF ANALYSIS METHODOLOGY
APPENDIX 5
The purpose of Appendix 5 is to provide a general description of the analysis process and tools that APS employed to conduct the resource planning analysis presented within this Report. There are several important pieces to the analysis but the centerpiece is a detailed electric power system simulation model called PROMOD IV. This simulation model was developed by Ventyx Energy and is widely used by resource planning organizations throughout the electric utility industry. APS pays an annual license fee to Ventyx that provides APS the right to utilize the model and receive periodic updates to the software package. APS uses the PROMOD IV model to simulate the operation of the electric system for the entire study period. For this analysis, APS conducted system simulations for the time period from 2009 to 2037.
The PROMOD IV simulation model requires many inputs including hourly load forecasts, fuel prices, generating unit minimum and maximum capacities, heat rate curves (a measure of fuel efficiency versus output level), scheduled maintenance outages, forced outage rates, O&M costs, emission rates, production profiles for renewable generators, and many others. With all of these inputs, the model simulates the operation (commitment and dispatch of each production resource) of the entire electric system over the entire study period. The primary model results include the total system production cost and utilization rates (energy produced) for each production resource.
The PROMOD IV simulation model is used to simulate and compare each unique future resource plan that is investigated in the resource planning analysis process. This allows for a comparison of key model outputs (like fuel cost or emissions) between differing resource strategies.
There are several other pieces that are required to put together the entire economic analysis. The economic analysis displayed in this Report includes costs for the entire production side of the business as well as the major transmission projects that are necessary to implement the Resource Plan. Much of this economic analysis is developed in spreadsheets which build up all of the different cost components, including existing and future investment in current power plants, natural gas pipeline capacity charges, imputed debt, and many others. Costs associated with regulated emissions (like SO2) are developed in a spreadsheet but are based upon output from the production simulation model.
All of the various pieces are brought together in summary spreadsheets which detail the total revenue requirements associated with each alternative resource case. This revenue requirement analysis is a standard utility economic analysis technique. Revenue requirement refers to the amount of revenue that APS must collect from
Appendix 5 Page 1
customers to cover all of the costs associated with the subject plan. The revenue requirement includes all relevant costs including fuel, O&M, pipeline capacity, customer incentive payments for energy efficiency and distributed energy, depreciation, interest on debt, equity return, income taxes, property taxes, and emissions expenses.
Appendix 5 Page 2