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Douglas L. Biden, President

Douglas L. Biden, President

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Douglas L. Biden, President

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  1. Douglas L. Biden, President Remarks Before IECPA Conference May 9, 2007

  2. AES Beaver Valley Allegheny Energy Cogentrix Energy, Inc. Edison Mission Group Exelon Generation First Energy Corporation Mirant Corporation PPL Generation Group Reliant Energy Sunbury Generation LP, and UGI Development Company Electric Power Generation Association • For those of you who don’t know EPGA here is a list of • ourmembers: • These companies own and operate approximately • 122,000 MW of electric generating capacity in the U.S. • My comments today are my own and do not necessarily represent the views of any particular EPGA member company with respect to any specific issue.

  3. Let’s Be Real • What follows are my views on what’s going to happen when the retail electricity price caps are lifted in PA. • The fact that there may be significant rate increases at the end of an 11-14 year rate freeze during which time key fuel prices rose two to four fold should not be a surprise to anyone. It should be expected. • For perspective, if electric prices increased by same rate as CPI since the Competition Act passed in 1996, electric rates would be almost 40% higher in 2010. • PA consumers pay 12% less for electricity today than they paid in 1996 (adjusted for inflation)

  4. Major Factors That Will Influence Electricity Prices • Fuel Prices • Environmental Issues • Clean Air Interstate Rule (CAIR) • Mercury Regulations • Clean Water Act – Section 316(B) • OTC High Electricity Demand Days (HEDD) • “CAIR-Plus”? • Climate Change – federal, regional, state? • Alternative Energy Portfolio Standards (AEPS) Implementation • Regulatory Uncertainty and its Negative Impact on Electric Capacity Expansion • Demand Response – ability to successfully connect wholesale and retail markets without relying on subsidies

  5. Fuel Prices • Generation constitutes largest component of total cost of electricity and fuel comprises 80-90% of generation so I will focus on generation and I will start with fuel. • Type of Fuel Used by Marginal Units in PJM. • You can see that coal and natural gas set the “market clearing price” in PJM over 95% of the hours.

  6. Fuel Prices (Cont.) • The price of these two pivotal fuels increased markedly in PJM in recent years as the following chart demonstrates (prices in dollars per MBTU). Source – 2006 PJM State of the Market Report.

  7. Fuel Prices (Cont.) • Natural gas prices increased almost four-fold between 1999 and 2005 before softening in 2006. • Coal prices more than doubled between 2000 and 2005, but moderated somewhat in 2006. • Despite these dramatic fuel price increases, load-weighted average LMP rose only 56% between 1999 and 2006. • And, load-weighted LMP declined by almost 16% in 2006 to $53.35/MWH (from $63.45 in 2005) despite record peak demand. • Although coal prices softened in 2006 markets are beginning to tighten again.

  8. Fuel Prices (Cont.) • Demand for Eastern Appalachian high sulfur coal is expected to rise significantly as more scrubbers are installed to comply with CAIR. • Rockies Express pipeline and Dominion Cove Point LNG will add significantly to regional gas supplies. • AES Sparrows Point LNG (Balto.) and BP Crown Landing LNG (near Phila.) would have daily send out capacities of 1.5 and 1.2 billion cubic feet respectively. • In addition to numerous LNG facilities expected to be completed in the GOM, Dept. of Interior trying to open up parts of the Outer Continental Shelf to exploration, 85% of which currently remains off limits.

  9. Fuel Prices (Cont.) • So, news is not all “gloom and doom” on the fuels front. • And, as we discovered last year and in 3 of the last 8 years, wholesale prices can go down (especially when fuel prices decline), not just up. • EIA data available in 5-year intervals. Based on its projections natural gas prices paid by power plants are projected to be 24% below 2005 levels (reference case) in 2010. • Steam coal prices to power plants in 2010 are projected by EIA to be about 12% above 2005 levels.

  10. Environmental Issues • Environmental regs impact generators’ choice of fuel, O&M and capital costs, as well as unit retirements. • In CAIR and the mercury regs (both federal and state), the generation industry now faces the greatest environmental challenge in its history. • Estimates of capital costs of CAIR alone have been in the range of $80 billion, with total annualized costs in the range of $15 billion. • Phase I emission reduction deadlines for NOx, SO2, and Hg coincide with expiration of generation rate caps in most of the EDC territories (2010). • More stringent Phase II deadlines are imposed in 2015.

  11. Environmental Issues (Cont.) • EPA estimates 5,000 MW will retire because of CAIR and Clean Air Mercury Rule. Consultant estimates are more than double that amount. • PJM estimates as much as 4,000 MW of coal-fired generation could be retired because of more stringent state mercury rules like Pennsylvania’s. • Recent court ruling under section 316(B) of the Clean Water Act could force existing power plants to install cooling towers. Small plants could not recover the hundreds of millions required to install cooling towers. • Ozone Transport Commission (OTC) seeking additional NOx reductions from peaking units on “high electricity demand days”, which are prohibitively expensive.

  12. Environmental Issues (Cont.) • Before we know the full impact on costs and unit retirements of CAIR and mercury regs, some states are proposing their own carbon limits (via RGGI) and considering a “CAIR-Plus” strategy for EGUs. • PJM already predicts that generation retirements in eastern PJM are expected to outpace new capacity additions, leading to greater use of natural gas. These environmental initiatives will accelerate that trend. • We don’t expect federal climate change legislation to have a material impact on rates in the 2010-2011 time frame. We have not yet seen the Rendell Admin’s climate change initiative.

  13. Alternative Energy Portfolio Standards Implementation • The AEPS will not change electricity costs significantly at the time rate caps expire in most of Pennsylvania. • Longer term, proposed changes to geographic scope of market, excluding alternative energy sources (AESs) in MISO from eligibility, could significantly increase the cost of compliance. • Most potential for wind turbine development (dominant tier I resource) is off-shore and in the mid-west plains. • Trying to force the development of thousands of MWs of wind capacity onto the ridge tops of PA is unsound and costly public policy.

  14. Alternative Energy Portfolio Standards Implementation (Cont.) • AESs should be developed where they are most economic, not according to artificial restrictions on geographic scope. • AEPS and RPS mandates will not necessarily lead to less natural gas use. • GE study for NYSERDA found that when electric load was at least 90 percent of the NYISO system peak—when most of the risk of system outage occurs—projected capacity factors of the top 100 wind sites in NY averaged 6 percent. They require reliability backup. • Ironically, state RPS mandates may be one factor pushing construction of new natural gas peakers to support intermittent renewable generation.

  15. Alternative Energy Portfolio Standards Implementation (Cont.) • “For every 10 MW of renewable power put on the grid, you have to build 9 MW of gas.”—Bob Fleck, VP, Wood Mackenzie, April 25. • It will be a challenge to ensure the viability of such back-up capacity going forward. PJM analysis shows that the average net revenue of a new CT over the past 8 years was $30,212 per installed MW year, while annual levelized fixed costs were $73,221.

  16. Regulatory Uncertainty • Generating capacity increased by more than 9,000 MW in PA since electric restructuring began. • In recent years investment in baseload capacity has greatly slowed due to regulatory uncertainty and to market imperfections. • PJM is addressing the latter issue with improvements to its capacity market and exploration of scarcity pricing. • PJM net revenue analysis demonstrates that new CTs, combined cycle and pulverized coal plants have covered only 41%, 59% and 69%, respectively, of their annualized fixed costs over last 8 years, underscoring need for market improvements to support new entry.

  17. Regulatory Uncertainty (Cont.) • We may have restructured, but we are still one of the most capital-intensive industries in the U.S. • Our investors despise uncertainty, particularly after earlier this decade when the merchant generation industry lost $200 billion in market capitalization. • The more uncertain the regulatory environment the higher our cost of capital. • You may recall that investment in new generating capacity nearly came to standstill when we were deciding whether or not to “deregulate” generation.

  18. Regulatory Uncertainty (Cont.) • Now, investors are again extremely wary of various state initiatives to re-regulate, turn back to integrated resource planning, or adopt measures to put part of the deregulation toothpaste back into the tube. • As a nation, region and state we face an unprecedented challenge: we need to invest billions in new generation and environmental controls to meet a growing demand for electricity and increasingly stringent environmental standards. • EIA estimates that we will need to invest over $400 billion in new generation by 2030 if we are to ensure our energy security and address global climate change.

  19. Regulatory Uncertainty (Cont.) • Wholesale prices must be high enough to recover not only operating costs, but also the capital invested in building new power plants before new plants will be built. • Equally important, investors must be assured that market rules will not be materially altered by legislation or regulation if we are to attract the investment and innovation on the scale needed to meet our energy security and environmental challenges. • For new base-load coal capacity, today is 2012, later for IGCC. • For new nuclear capacity, today is probably 2018. • Bottom line: if power build doesn’t pick up soon we could see the beginning of a capacity shortage in PJM (or major parts of PJM) by early next decade.

  20. Demand Response • Almost everyone says that demand response (DR) is suboptimal. • Suboptimal in relation to what? The true cost—which is revealed by the price of generating that next megawatt hour—the very same price signal generated by the single price auction market operated by PJM. • DR is “suboptimal” because of the disconnect between the wholesale and retail markets. Retail price caps and the general lack of market-based pricing prevents consumers from seeing the true cost. • Price caps greatly limit voluntary participation in DR, preventing loads from determining when they would be willing to accept the loss in production or comfort associated with a loss of electricity.

  21. Demand Response (Cont.) • The best way to connect the wholesale and retail market is to allow consumers, particularly those with elastic demand, to see real-time electricity prices. • This doesn’t mean real-time metering and real-time pricing needs to be imposed on all consumers. • Economic research indicates that a relatively small fraction of the total load facing spot prices could be sufficient to connect the wholesale and retail markets. • As the price caps expire and retail competitors return to Pennsylvania, DR will be a relationship builder for LSEs, a critical piece of what it takes to be competitive.

  22. Components of Annual Load-Weighted Average LMP 2006

  23. Concluding Remarks • You have probably heard different predictions for different utilities regarding projected percentage increases when rate caps expire. • Most (but not all) of the increase can probably be predicted by the difference between the increased zonal LMP and the sum of stranded costs (CTC and ITC), the collection of which is expected to expire with generation rate caps (plus deferred energy and carrying charges if any). • We have a recent pilot in the Penn Power POLR proceeding upon which to base predictions. Rate increases there ranged from 18% for small commercial customers to 50-61% for large commercial customers.

  24. Concluding Remarks (Cont.) • All but 4% of PP large commercial load is now being served by competitive suppliers – at lower rates. • Given the duration of price caps, dramatic escalation in fuel prices, and constant increases in environmental expenditures, is 18-61 percent unreasonable? • Experience in traditionally regulated states indicates rates may well be higher if generation was still regulated at the state level. Between 2000 and 2005, rates rose 47% in Oklahoma, 37% in Georgia, 67% in Louisiana, 53% in Mississippi and 43% in Colorado, resulting largely from fuel price increases.

  25. Concluding Remarks (Cont.) • That is not to say we cannot do better. • We support and commend the PUC’s investigation into potential measures to mitigate future price increases. • We remain hopeful that the PUC will adopt sensible measures to mitigate future price spikes in a way that allows competitive markets to continue to work. • Competition has brought significant efficiency gains to the generation industry and those efficiency gains have benefited all consumers, including industrial customers. • I understand that some members of IECPA are unhappy with certain aspects of electric restructuring.

  26. Concluding Remarks (Cont.) • As we transition from retail rate caps to markets I hope these issues can be resolved. In the meantime I hope we can agree not to be disagreeable and to keep talking. • Seldom over the last 15 years has a major issue arisen that drives up our costs unnecessarily that I have failed to mention the interests of our large manufacturing customers to legislators or regulators, and the link between our costs (and related fuel choices) and the exodus of manufacturing jobs from this state and nation. • In the future, it is my hope, and I’m sure the desire of all of my member companies, that our currently conflicting agendas can give way to greater cooperation.