Emerging Issues for State Energy Plans & Integrated Resource Planning

Emerging Issues for State Energy Plans & Integrated Resource Planning Presented to: Governors' Energy Advisors Policy Institute NATIONAL GOVERNORS ASSOCIATION Presented by: Philip Q Hanser 31 May, 2012 Copyright 2012 The Brattle Group, Inc. www.brattle.com Antitrust/Competition Commercial Damages Environmental Litigation and Regulation Forensic Economics Intellectual Property International Arbitration International Trade Product Liability Regulatory Finance and Accounting Risk Management Securities Tax Utility Regulatory Policy and Ratemaking Valuation Electric Power Financial Institutions Natural Gas Petroleum Pharmaceuticals, Medical Devices, and Biotechnology Telecommunications and Media Transportation

Today s Focus How large is the coal power plant retirement issue? Why are coal plants retiring? How can states address these issues? Restructured markets Traditionally regulated 2

Potential Coal Plant Retirements Most studies conducted in the last year or so estimate 30-60 GW of coal capacity (10-20% of existing fleet) at risk for retirement by 2020 due to weak market conditions plus EPA regulations. More retirements likely now, due to falling gas and power prices. 4

Projected (& announced) Coal Plant Retirements Most of the projected and announced coal retirements are in NERC regions RFC (12-19 GW, 12 GW announced) and SERC (10-11 GW, 8 GW announced). 3-13 GW projected (<3 GW announced) 2-3 GW (<1 GW announced) 12-25 GW (12 GW announced) 3-4 GW (2 GW announced) 1-2 GW (<1 GW announced) 3 GW (2 GW announced) 10-11 GW (8 GW announced) 1 GW (<1 GW announced) 5

Announced Coal Retirements by State Texas, North and South Carolina, Tennessee, Ohio, Kentucky, Pennsylvania, West Virginia, and Illinois have greater than 1000 MW of announced retirements 6

Announced Coal Retirements as % of Total Capacity Ohio, West Virginia, and Tennessee have the greatest percentage of capacity retiring 7

How large is the coal power plant retirement issue? There may be a resource adequacy problem, although most appear to be localized It appears that some flexibility by EPA will be needed to prevent this from happening For example: Can all of the retrofits be accomplished with the current supply chain? Recent Brattle report for MISO suggests either resource constraints will bind or make the retrofits significantly more expensive New gas pipeline capacity could also become a binding constraint with a significant switch to gas-fired generation Meeting the environmental regulatory requirements on the current schedule will likely raise the costs of retrofits. 8

Future Price (US$/MMBtu) NYMEX Natural Gas 12-Month Average Future Prices (January 2000 - May 2012) 15.0 12.0 9.0 6.0 3.0 0.0 Source: NYMEX data obtained from Bridge & Bloomberg. 10

Future Price (US$/MMBtu) 6.0 NYMEX Natural Gas Monthly Future Prices (September 2011 - May 2012) Sep 2011 5.0 Nov 2011 4.0 Jan 2012 Mar 2012 May 2012 3.0 2.0 1.0 0.0 Source: NYMEX data obtained from Bloomberg. 11

Emerging EPA Regulations Regulation Status Pollutant Targeted CSAPR Final rule, delayed with court ruling NO x, SO 2 Utility MACT Final HAPs (mercury, acid gases, PM) Compliance Options SCR/SNCR, FGD/DSI, fuel switch, allowance purchases Expected Date of Compliance 2012(?) and 2014 ACI, baghouse, FGD/DSI 2015/2016 316(b) Proposed Cooling water Impingement: Mesh screens; Entrainment: Case-by-case, may include cooling towers 2018 Combustion byproducts (ash) Proposed Ash, control equipment waste Bottom ash dewatering, dry fly ash silos, etc. 2015 Revised Ozone Standard Final expected in May 2012 NO x SCR/SNCR (and allowance purchases under CSAPR)??? GHG Performance Standards (Tailoring Rule Step 3) Final expected in May 2012 GHGs from new, modified and potentially existing plants Efficiency improvements, CCS 2013 12

Capital Costs of Major Control Equipment Capital costs are significantly more expensive for smaller units Retrofit costs for major equipment such as wet scrubber and SCR are comparable to cost of a new gas CC at about $1000/kW CAPITAL COST OF CONTROL EQUIPMENT (2011 $/kw) Unit Size (MW) Equipment 50 200 600 Wet Scrubber 904 734 513 Dry Scrubber 774 628 448 DSI 42 39 39 SCR 273 234 188 SNCR 51 51 51 Baghouse 504 387 219 ACI 29 27 19 Source: EPA IPM 4.10 Basecase assumptions and EEI 2011 Study 13

Estimates on Total Cost of Compliance Retrofit capital expenditures of $70-$130 Billion expected to comply with emerging suite of EPA regulations Annualized total cost of compliance will likely exceed $10 Billion per year. ESTIMATES FOR COST OF COMPLIANCE WITH EMERGING EPA REGULATIONS Compliance Costs by 2020 Study Covered Regulations CapEx for Retrofits Total Costs MISO Utility MACT, CSAPR, Ash, and $32 Billion in MISO not available Cooling Water EPA CSAPR not available ~$1 Billion per year EPA Utility MACT $5.2 Billion per year $10.9 Billion per year Brattle Utility MACT and CSAPR $70-130 Billion not available EEI/ICF Bipartisan Policy Center Utility MACT, CSAPR, Ash, and Cooling Water Utility MACT, CSAPR, Ash, and Cooling Water 85-113 Billion not available ~$10 Billion per year $14.5-18.1 Billion per year 14

Why are coal plants retiring? Significantly lower natural gas prices both now and going forward are reducing coal generators expected profitability Renewables, primarily wind generation at night, aggravate the problem because they reduce coal plants revenues during low load conditions Inability to operate at minimum loads at night reduces capability to bid in profitably during the day by raising commitment costs. Many coal plants compete by exploring ways to justify lower bid prices (and finding ways to reduce their variable costs). Going forward costs of EPA regulatory compliance is a final straw on the camel s back for smaller, older plants 15

A Few Takeaways In the short run, There will be some areas which may have local resource adequacy/transmission security issues. Capacity market prices will likely rise in the face of coal plant retirements Some RTOs/utilities will need to learn how to operate systems with significantly more gas on their system than they are accustomed Combustion turbine capacity factors will likely rise and, since they are relatively expensive to run, peak (and average) prices may rise Incidents of natural gas shortages for generation may increase These will be related to bottlenecks on the pipeline system, not lack of commodity 17

A Few Takeaways In the long run, New coal plants are unlikely to be built, removing a fuel from the energy resource portfolio. Dependence on natural gas-fired generation will increase Gas prices are inherently more volatile than coal and with greater levels of natural gas generation there may be more volatility in electricity prices The natural gas pipeline system will need expansion, although the localness of natural gas from shale may reduce the need for long pipeline expansion. With low gas prices, pipeline owners will not want to bear the costs of expanded storage Coordination between the natural gas pipeline system and the electrical system will become more important Some generators may be required to have onsite storage of fuel oil as a natural gas alternative for emergencies 18

State Challenges Restructured Markets Short-term perspective and resource mix of capacity markets Dealing with the existing coal plants Role of load serving entities/local distribution companies 19

Capacity Markets of the RTOs Alberta Electric System Operator * Energy-only MISO * Bilateral capacity market * Proposed to centralize Ontario Independent Electricity System Operator * Very long term PPA for capacity revenues * Ontario Power Authority (OPA) purchases for reliability requirements New Brunswick System Operator * Regulated planning California ISO * Bilateral capacity market * Redesign being considered Southwest Power Pool * Regulated planning Electric Reliability Council of Texas * Energy-only ISO New England * 3-year look ahead New York ISO * 1-mon. to 6-mon. look ahead PJM Interconnection * 3-yr. look-ahead * 1-yr. capacity price/obligation 20

Projected coal retirements vs. reserve margins - capacity markets 13 GW projected/127 GW/>30% (U.S. only) (<1 GW announced) 2-3 GW/61 GW/ 19% (U.S. only) (<1 GW announced) 3-4 GW/196 GW/ 30% (not including Canada) (2 GW announced) 12-25 GW/193 GW/ 30% (12 GW announced) 10-11 GW/212 GW/>30% (8 GW announced) 1-2 GW/65 GW/ 20% (<1 GW announced) 3 GW/74 GW/ 14% (2 GW announced) 1 GW/61 GW/>30% (<1 GW announced) (Capacity/reserve margins as of Summer, 2011.) 21

RTO capacity markets have a less than three year forward perspective (sometimes much less) Price Price Price Forward Period Procurement Demand Curve California Bilateral Only n/a MISO Bilateral + Voluntary Auction n/a NYISO Bilateral + Mandatory Auction MW PJM Bilateral + Mandatory Auction MW ISO-NE Bilateral + Mandatory Auction Price Floor MW 22

Long-term resource adequacy? Evidence to date suggests that six month - three year forward capacity markets will sustain resource adequacy for the foreseeable future Quick response when need arises, although much of it from demand response New gas capacity could strain existing pipeline system Current forecasts of demand don t suggest accelerating resource needs But many demand forecasts are showing an upward trend 23

Long-term resource development Difficult to gain generation project financing under current structure Wholesale market restructuring shifted risk to suppliers Imposing long-term contracts would provide security to generators but shifts the risk to customers instead Some states retail supply auctions may prevent an efficient level of longterm contracting (since the contracts are limited to 1-3 years) However, the last capacity market auction in PJM attracted 5 GWs of new capacity App. 1 GW is under state contract Another 1 GW is a regulated market participant 24

Long-term resource development Enabling private market entities to engage in effective longterm contracting for cost and risk management isn t easy RTOs could lengthen the adequacy planning window, but debt financing may require more assurance of a consistent revenue stream than the market can support voluntarily or through market rule (and administratively impose longterm commitments that shift risks to customers) Banks look for long-term contracts and revenue guarantees, without these they will reduce the amount of non-recourse debt they will provide (so merchant generators must rely more on balance sheet to finance) 25

Capacity markets don t incent portfolio diversity Capacity markets are technology-neutral A kilowatt is a kilowatt is a kilowatt kws don t come in identifiable flavors or colors Does not even have to be iron-in-the-ground just deliverable RTOs may consider modifications to capacity market design to reduce the current all the eggs in one basket situation 26

Capacity markets don t incent portfolio diversity: Renewables Renewables intermittency prevents them from being good capacity resources (resources are therefore assigned low capacity value, e.g. 13% of nameplate for wind) They may even create a new need for more capacity that is very flexible (first step however, should be to fix the A/S markets and wait to see if there is any real concern) Incentives for renewables must come from outside of the market (not capacity credits) Regulatory mandates on buyers Environmental regulations that make other options less economically attractive However, storage technologies complementary to renewables do benefit from capacity markets (although currently storage growth is minimal, with the only substantial storage from legacy pumped hydro) 27

Dealing with the existing coal plants Current coal plants and their modification/replacement States must address stranded costs for retired plants Not an issue for merchant plants Incumbents vs. new entrants Reliability greater than RTO goal? Is the state comfortable with the RTO s level of reliability? 28

Role of load serving entities/local distribution companies LSEs/LDCs role in the future may be larger Smart Grid technology will be key Increased operational benefits through customer participation Greater rates of demand response will reduce impact of increased volatility of energy prices May also reduce capacity market price increases Local/distributed generation options could be increasingly important Very smart grid integrated with larger electrical system How small can the distributed generation go? 29

State Challenges Traditional Markets Resource diversity Greenhouse gases? Role of distribution system 30

Resource Diversity There is a need for resource diversity going forward, but it isn t costless Kilowatt-hours aren t fungible like financial assets Generation alternatives aren t simple substitutes for one another and there isn t a market that permits easy conversion from one to another Opportunity costs Trade-off between current investment vs. future investment Forecasting will have a greater role Timing of investments Variability and sources of future demand Optionality and vigilance to markets and technology will be key 31

Long-term resource adequacy and diversity? Track records for forecasting distant needs are not very impressive! Example of Utility that Consistently Over-Forecasts Example of Utility that Consistently Under-Forecasts Load Forecasting Track Record Mid-Western Utilities 32

Greenhouse gases? Many states would like to address the issue of greenhouse gases in their long-term resource plans Lack of federal legislation prohibits explicit dollar valuation of GHGs Including a shadow price for GHGs in an IRP analysis can yield different options than an IRP without Creates approval quandary for commissions and utilities How much is carbon capture and sequestration worth? Opportunity cost of low-carbon generation Choosing a resource emitting 0 GHG, but costing $100/MWh over a combined cycle gas turbine costing $50/ MWh and emitting 0.4 tons GHG/MWh implies a GHG cost of $125/ton ([100-50]/0.4) 33

Role of distribution system The distributions systems role in the future may be larger Smart Grid technology will be key Increased operational benefits through customer participation Greater rates of demand response will reduce impact of increased volatility of energy prices May also reduce capacity market price increases Local/distributed generation options could be increasingly important Very smart grid integrated with larger electrical system How small can the distributed generation go? 34

Energy Efficiency and Demand Response Energy efficiency and demand response will continue to be foundational to any integrated resource plan going forward, but Assessing demand response requires a non-trivial level of research by the utility Statistically soundly designed and realistic pilots with as broad a set of options and participants as possible Projecting energy efficiency impacts is still in a relatively primitive state of development Lack of data and behavioral models Equipment and buildings existing and projected What determines/influences energy behavior Rebound effects? How to incorporate in forecast 35

Today s Focus How large is the coal power plant retirement issue? Why are coal plants retiring? How can state regulators address these issues? Restructured markets Traditionally regulated 36

Speaker Bio and Contact Information Insert corporate headshot here. Philip Q Hanser Principal Cambridge, MA phil@brattle.com (617) 864-7900 (617) 864-1576 Mr. Hanser assists clients in issues ranging from market structure and market power and associated regulatory questions, to specific operational and strategic issues, such as transmission pricing, resource planning, and retail tariff strategies. He also has expertise in fuels procurement, environmental issues, forecasting, marketing and demand-side management, renewables integration, and other complex management and financial matters. Over his thirty years in the industry, Mr. Hanser has appeared as an expert witness before the Federal Energy Regulatory Commission (FERC), numerous state public service and siting commissions, arbitration panels, and in federal and state courts. He served six years on the American Statistical Association s Advisory Committee to the Energy Information Administration (EIA) and serves as a referee for both IAEE and IEEE journals. Prior to joining The Brattle Group, Mr. Hanser held teaching positions at the University of the Pacific, University of California at Davis, and Columbia University, and has served as a guest lecturer at the Massachusetts Institute of Technology, Stanford University, and the University of Chicago. He was the manager of the Demand-Side Management Program at the Electric Power Research Institute (EPRI) before joining Brattle. He has published widely in leading industry and economic journals. The views expressed in this presentation are strictly those of the presenter(s) and do not necessarily state or reflect the views of The Brattle Group, Inc. 37

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