FERC RTO Cost-Benefit Analysis: Summary of Study and Results

Transcription

1 FERC RTO Cost-Benefit Analysis: Summary of Study and Results Prepared by: ICF Consulting February 27, 2002

2 Outline I. Overview of Study II. Process and Analytic Approach Basis for Study Collaboration with Commission Staff and State Officials Analytic Approach: Simulation Modeling and Related Research Scenarios Selected for Study Major Assumptions III. Results Production Costs and Energy Prices Costs of RTO Establishment and Operation Net Economic Impacts Discussion 2

3 I. Overview of Study

4 Cost/Benefit Analysis: Summary of Approach The Commission announced further cost/benefit analyses and federal-state consultations in the November 7, 2001 order providing guidance on continued processing of RTO filings. The purpose of the analysis is to determine whether and, if so, how RTOs will yield customer savings and to provide a quantitative basis for the appropriate number of RTOs. Computer modeling scenarios were developed by combining sets of analytic assumptions. Because the Commission described three major types of economic benefits in Order No. 2000, three policy scenarios were developed to analyze relative contributions of different assumptions to economic outcomes: The Transmission and Generation Case, combining transmission efficiencies with improvements in generator performance; The Transmission Only Case, with improvements to the transmission grid only; and The Demand Response Case, adding limited demand response to the Transmission and Generation Case assumptions. Two sensitivity cases were also developed, a Larger RTO Case and a Smaller RTO Case, to examine the impacts of varying RTO scope alone. 4

5 Cost/Benefit Analysis: Summary of Results The policy scenarios result in a wide range of potential economic benefits. Production cost savings for the entire system range from $1 billion to $10 billion per year. On a net present value basis over the 20-year time frame of the study, total production cost savings range from $7 billion to $60 billion. Estimates of RTO establishment costs range from $1 billion to $5.75 billion, but these are onetime costs. On a net basis, implementation of RTO policy leads to gains even if RTO benefits are relatively low while costs are relatively high. The sensitivity cases examining RTO scope show that larger RTOs lead to larger economic gains. These effects are in the range of $ million per year. The assumption that RTOs lead to improvements in generator efficiency, particularly through better generator performance, is the most important factor determining the results. Energy price impacts vary across regions. Most regions show price declines, but a few regions show price increases. The increases are small and transient, but raise issues of equity and revenue distribution. 5

6 II. Process and Analytic Approach

7 Collaborative Process for Framing the Problem ICF worked with FERC staff to develop the initial framework for this study. A State PUC Panel was engaged via a series of conference calls, considering: Issues to be addressed; Analytic methods; and Specific state concerns. On January 8, 2002 an all-day meeting with the State PUC Panel and FERC staff was held at ICF Headquarters in Fairfax, VA. This collaborative process framed issues and provided input on scenario selection. Actual analysis and final results were not subject to revision by FERC or state officials. 7

8 Analytic Framework FRAMING ANALYSIS REPORTING SCENARIO DEFINITION SIMULATION MODELING ASSUMPTION DEVELOPMENT RESULTS INTEGRATION AND DOCUMENTATION RESEARCH REQUIREMENTS RESEARCH AND QUANTIFICATION 8

9 Analytic Framework: The Integrated Planning Model (IPM ) for Long-Run Market Simulation Environmental Compliance Technologies and Costs Electric Demand Gas Supply Coal Supply Existing and New Generation Technologies IPM RTO Regulatory Scenarios Capacity Additions Fuel Consumption Electric Prices Capital, O&M, and Fuel Costs Emissions 9

10 The IPM Modeling Framework ICF used the national Integrated Planning Model (IPM ) to analyze the impacts of RTOs on power markets, regional generation, and the transmission system. IPM is a linear programming model with a detailed representation of every boiler and generator operating in the United States. The model determines the least cost means of meeting electric energy and capacity requirements, while complying with specified regulatory scenarios. In addition to optimizing wholesale and environmental markets, IPM simultaneously optimizes coal production, transportation and consumption. IPM contains 40 coal producing regions and has over 10 coal types defined by rank and sulfur content. Each coal plant is assigned to one of over 40 coal demand regions characterized by location and mode of delivery including rail, barge, and truck. Natural gas prices are derived within IPM using a similar supply curve and transportation network. 10

11 IPM Regional Map Upstate NY Montana PACNW NWPP East RMA NOCAL MAPP COMED WUMS ILMO SPP-N MECS So. ECAR PJM-W VIEP NEPOOL Downstate NY PJM East PJM South LILCO New York City SOCAL AZ-NM SPP-W Entergy TVA DUKE CP&L ERCOT Southern SCEG Florida 11

12 IPM Model Regions National IPM divides the United States into model regions, closely resembling NERC regions. ICF further disaggregates NERC regions based on known transmission bottlenecks (i.e. sub-regions in which spot prices are expected to diverge significantly), or when clients request specific regional breakouts. All IPM regions have a representation of the electric transmission system that connects neighboring regions. The inter-regional transmission connections allow for the transfer of both capacity and energy and allow for broad price equilibration when transmission capacity is available. For this study, ICF modeled a total of 32 regions in order to best capture the effects of RTOson the national grid. 12

13 IPM Coal Supply Regions Northwest Western Northern Great Plains Eastern Northern Great Plains Central West Mid-West WA MW ME ND MP Northern Appalachia WP Rockies US UC AZ WG CG CU CS NS CD NR CR IA MO KS OK AN AS IL AS IN KW AL PW PC OH WN WS KE TN VA MD Central Appalachia LA Southwest TX Southern Appalachia Gulf 13

14 Representation of Coal Supply, Demand, and Transportation in IPM IPM forecasts coal production from over 40 supply regions: Bituminous, sub-bituminous, lignite 12 different sulfur grades Each coal power plant is assigned to one of 41 coal demand regions based on location and mode of delivery. Coal transportation network links coal supply and demand regions. Coal consumption by sulfur grade is a function of electricity generation levels, air pollution regulations, and oil and gas prices. 14

15 NANGAS Supply Regions POF: Pacific Offshore ANS PON: Pacific Onshore SJ: San Juan MD RF: Rockies Foreland WI: Williston P: Permian MC: Mid-Continent AET: Arkla-East Texas BC ALB TGC: Texas Gulf Coast GMW: Gulf of Mexico-West GMC: Gulf of Mexico-Central WL NP: Norphlet DG SL: South Louisiana RF WF: West Florida MW PON AP MF: MAFLA Onshore MC SJ MW: Mid-West CP AP: Appalachia EI POF MF ANS: Alaska North Slope P AET SL MD: MacKenzie Delta Supply TGC NP Supply-LNG AB: Alberta LC WF GMC BC: British Columbia GMW MEX SI: Sable Island DI: Distrigas CP: Cove Point EI: Elba Island LC: Lake Charles Wyoming, Colorado and parts of Utah, Arizona, New Mexico, South Dakota and Montana constitute Rockies in NANGAS SI 15

16 Gas Market Approach ICF s natural gas price forecasts are derived from results from ICF s North American Natural Gas Analysis System (NANGAS). The NANGAS model has descriptive and analytic capability that allows assessment of gas resources and markets from reservoir to burner-tip, working from a database of more than 17,000 U.S. and Canadian reservoirs. The NANGAS model also contains: explicit characterizations of the performance and market penetration rate of E&P technologies; detailed regional/sectoral/seasonal demand criteria; site-specific investment, operating and environmental compliance cost; and a pipeline network simulation that analyzes supply, demand, and transportation interactions consistently and comprehensively. Natural gas commodity and transportation prices are assumed to vary with demand on a seasonal basis in accordance with historical trends -- higher commodity and transportation prices in winter and lower prices in other seasons. The impact of demand changes on natural gas prices is endogenously handled within IPM using supply curves generated from NANGAS. 16

17 Placing Model Results in Context The IPM framework estimates electric generation costs, which represent about two-thirds of the total cost of providing electricity to end-use customers. While the model includes transmission charges, it does not directly estimate other transmission and distribution costs. IPM focuses on those generation costs that are relevant for short term operations and long term investments. The generation costs excluded from the modeling framework are not expected to be changed by RTO policy since they are already incurred and therefore are insensitive to regulatory changes. The main relevant costs not directly estimated by the model are for incremental transmission investments and transmission operations; these were estimated by the research team separately from the IPM modeling work. 17

18 RTO Configuration for the Main RTO Policy Scenarios NEPOOL PACNW MONTANA NOCAL NWPPE RMA MAPP WUMS COMED SPPN ILMO DSNY UPSNY MECS PJMW SOECAR VIEP LILCO NYC PJME PJMS SOCALNV AZNM SPPW ENTERGY TVA DUKE CAPO SCEG SOCO ERCOT FRCC 18

19 Scenarios Analyzed RTO Configuration No RTOs; 32- region structure 4 RTOs and ERCOT 2 RTOs and ERCOT 9 RTOs and ERCOT Type of RTO- Related Economic Benefit Specific Model Assumption Base Case Transmission Only RTO Policy Scenarios Transmission/ Generation Demand Response Sensitivity I: Larger RTOs Sensitivity Cases Sensitivity II: Smaller RTOs Reduced Inter- Regional Barriers to Trade Base Case assumption No transmission hurdle rates within RTOs; hurdle rates converge to $2 per MWh between RTOs beginning in 2004 Transmission Transmission Capability Expansion Capacity Sharing Base Case assumption 75% of energy transfer capability Increased by 5% from 2004 onward 100% of electricity transfer capability Reserve Margins Decline over time to system - wide average of 15% by 2020 Decline over time to system -wide average of 13% by 2020 Generation Efficiency Improvements Base Case assumption Fossil-fired Units: Heat rate improves by 6% by 2010 and availability increases by 2.5% Demand Response Demand Response Not analyzed 3.5% reduction in peak beginning in 2006 Not analyzed 19

20 Scenario Development Scenarios combine specific modeling assumptions into complete sets of parameters that are intended to represent alternative potential outcomes. Both regulatory assumptions and market assumptions must be specified to develop a complete modeling scenario. For this analysis, three main policy scenarios and two sensitivity scenarios have been analyzed and reported. Results are compared to a Base Case that represents the status quo or no-action regulatory alternative (Order No. 888 without the subsequent RTO Initiative as embodied in Order No. 2000). The major assumptions used in developing the policy scenarios and sensitivity cases are outlined in the above table. 20

21 Model Calibration To represent inter-regional barriers to trade, the IPM model was calibrated to a base year (2000) using changes in the transmission link charges to replicate actual regional generation for that year. The regional generation pattern that occurred in 2000 incorporates the inefficiencies in today s power system that RTOs are intended to remedy. This process of changing the transmission link charges resulted in a set of transmission hurdle rates that include both actual tariff charges and a representation of implicit barriers to economic trades. This process has been used in several prior national analyses of competitive policy in the electric utility sector, including studies by the FERC and the Department of Energy. These transmission hurdle rates were then reduced in order to simulate the effects of RTO policy on inter-regional trade. In the Base Case, some easing of these hurdle rates (25% over ten years) is also assumed to reflect gradual improvements due to existing policies. 21

22 III. Results

23 Changes to Transmission Grid Affect Power Flows Reducing transmission hurdle rates affects the pattern of inter-regional trade in electricity. These changes occur over very large areas of the country; analyzing these effects requires analytic tools with national scope. In the scenarios analyzed for this study, inter-regional trade shifts towards Florida in the Eastern Interconnection and California in the Western Interconnection. In the Eastern Interconnection, shifts in regional generation and large interregional power flows change the export pattern of Midwestern regions away from the Northeast and towards the Southeast. In the Western Interconnection, regions throughout the Interior West export more power towards California. 23

24 Changes in Power Flows Affect Economic Outcomes Increasing the opportunities for inter-regional trade allows regions with lower production costs to export more power and displace higher-cost production in importing regions. At the same time, changes in the assumptions that describe generators and market efficiencies also result in economic changes. For example, changes in reserve margin requirements and inter-regional reserve sharing can result in deferral of new plant construction to meet reserve needs. The impact of such changes is measured in two ways in the IPM framework. The model estimates both production costs and wholesale energy prices. While these two measures usually move together, they do not always coincide. In some regions, changes in inter-regional trade create energy price effects that are greater than the efficiency savings in production costs. In other regions the reverse is true. 24

25 System-Wide Production Costs for Policy Cases (Millions of Year 2000 Dollars, NPV in Billions) Base Case 89,493 94, , , , Transmission/Generation Case Savings from Base % Savings From Base 88,414 1, % 91,972 2, % 104,254 5, % 123,057 6, % 142,289 7, % Transmission Only Case Savings from Base % Savings from Base Demand Response Case Savings from Base % Savings from Base 89, % 88,343 1, % 93, % 89,997 4, % 108, % 101,941 7, % 128, % 120,451 8, % 148,468 1, % 139,361 10, % Note: NPV at 6.97% discount rate, in billions of dollars NPV % % % 25

26 RTO Policy Cases Result in Production Cost Savings The Transmission and Generation Case is intended to represent a likely outcome of RTO policy as described by the Commission. It combines transmission system changes with improvements in generator performance, as envisioned in Order No In this case, system-wide production cost savings increase over time, reaching over $5 billion per year by Over a 20-year period this scenario results in a net present value savings of over $40 billion. In the Transmission Only Case production cost savings are smaller, reaching over $750 million per year by 2010 and resulting in a 20-year net present value savings of $6.9 billion. This reflects a scenario where there are no generator efficiency improvements resulting from RTO policy. The Demand Response Case results in the largest savings among the policy cases analyzed for this study. Production cost savings reach over $7.5 billion by 2010 and the 20-year net present value savings total over $60 billion. This scenario adds a moderate level of demand response, consistent with what is expected in a competitive market, to the generator improvements included in the RTO Policy Case. 26

27 Regional Firm Energy Prices, 2010: Base Case 27

28 Energy Prices: RTO Policy Case Change from Base (%) in

29 Changes in Regional Energy Prices Vary As discussed above, changes in inter-regional exports can lead to a variety of changes in regional energy prices. This is because of regional variations on supply curves and how marginal prices are set at varying levels of demand within each region. The maps on the two slides above show the Base Case energy prices for the year 2010, followed by the percentage changes in annual average energy prices for the same year in the RTO Policy Case. These are percentage changes from the Base Case prices in that year. From the maps it can be seen that while most regions experience energy price declines, these are not uniform, and there are a few regions that experience price increases. These price increases are generally small (a few percent at most) and diminish over time. 29

30 System-Wide Production Costs for Sensitivity Cases (Millions of Year 2000 Dollars, NPV in Billions) Larger RTOs Savings from Base % Savings from Base Smaller RTOs Savings from Base % Savings from Base ,301 1, % 88,452 1, % 91,893 2, % 92,031 2, % 104,185 5, % 104,319 5, % 123,000 6, % 123,192 6, % 142,190 7, % 142,368 7, % NPV % % 30

31 Sensitivity Cases Address RTO Configuration The Larger RTO Case and the Smaller RTO Case are intended to indicate how changing the configuration and size of RTOs affects economic outcomes. For these sensitivity scenarios, changes in RTO configuration are represented by changes in transmission assumptions only. No explicit link is made between RTO configuration and the potential for market or generator improvements. The results of these two sensitivity cases, as seen in the table on the above slide, show that RTO size does matter. The difference between the Larger RTO Case and the Smaller RTO case in terms of production costs is on the order of $ million per year. While these results tend to indicate that larger RTOs lead to greater economic benefits, the economic impacts of RTO configuration alone are much smaller than the impacts of improved market performance. If RTO size is tied to improved market performance, the importance of RTO size would be much greater. 31

32 RTO Costs are Also Uncertain Information about the costs for existing Independent System Operators (ISOs) has been collected in order to estimate the costs of RTO establishment and operation. A series of cost indicators were developed to compare existing ISO costs and extrapolate these costs throughout the country. Cost indicators included: Cost per installed MW; Cost per MWh generated; Cost per customer; Cost per square mile of territory; and Cost per network node. Based on these indicators, a set of higher and lower cost models of RTO expansion were quantified. The lower cost model results in an average low-cost estimate of $1 billion for RTO establishment while the average high-cost estimate is $5.75 billion. These are one-time costs, as opposed to recurring or annual costs. Although this is a very wide range of cost estimates, the lack of information about the relationship between RTO functionality and infrastructure requirements makes it difficult to reduce the uncertainty in cost estimates. However, within this range RTO operating costs are assumed to be a net wash, since there could be either cost savings or cost increases relative to the operating costs of current control areas. 32

33 Conclusions: Net Economic Impacts of RTO Policy Under the analytic assumptions considered in this analysis, the net economic impacts of RTO policy will be positive even if RTO benefits are toward the low end of the range while RTO costs are at the high end of the range. If RTOs lead to improvements in market efficiency and incentives for generator performance, as modeled in the RTO Policy Case, net benefits will total tens of billions of dollars over time. Improved demand response would likely add to these savings, resulting in 20-year savings of over $60 billion dollars in the Demand Response Case. While there are production cost net benefits to RTO policy as analyzed here, the regional energy price impacts vary. Most regions show price declines. A few regions show small energy price increases, although these tend to diminish over time. This in turn raises equity and revenue distribution issues that go beyond the scope of this study, because regions where local prices increase should also realize gains in export revenues. Changes in RTO scope, as examined in the Larger RTO Case and the Smaller RTO Case, can result in larger economic benefits. The economic importance of RTO scope, however, appears to be much smaller than the effects of improved market efficiencies. Possible linkages between RTO scope and market performance would make RTO scope and configuration more important. 33

34 Conclusions: Uncertainties and Further Analyses The range of potential costs and benefits quantified here is broad. Narrowing the range of estimates may be possible with further research and evidence. However, it is unlikely that the uncertainties can be eliminated. The most important uncertainties for this analysis are the extent to which RTOs will lead to improved market performance, and the need for extensive infrastructure investments in order to establish RTOs across the country. Better market performance would increase the policy s benefits, while reduced RTO infrastructure investments would minimize costs. Regional variations in economic impacts appear to be an important aspect of this regulatory policy. More detailed regional analyses could be performed, including more sensitivity analysis to show how market fundamentals and regulatory decisions can change regional impacts. Similarly, further national-level analysis could suggest more detailed information about how RTO configuration affects the results, and allow for sensitivity analysis of key modeling assumptions, such as demand growth and transmission availability. 34