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Case Studies in Electric Power

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  1. Case Studies in Electric Power

  2. Contents • Argentina and Chile – State versus Private • California Power Crisis – Problems with De-regulated Market • Philippines – Benefits and Problems with Single Buyer Model • Drax in the UK -- Merchant Power • Enron Dahbol in India – PPA Contracts

  3. Argentina and ChileCase Study

  4. History – Argentina and Chile • The reform of the electricity sector in Argentina that began in the early 1990s was widely seen as an example for the developing world. Argentina quickly established a stable institutional design to govern electricity provision, considerably improved the financial and technical performance of the sector, and had one of the most advanced electricity systems in the developing world – with open access to the grid and competitive wholesale markets. • During the 1980s Chile became the first country in the world to break up power monopolies, progressively withdraw the state from management - but not regulation - of the electricity supply industry, and divest state ownership in most of them to private investors.

  5. Argentina Privatization • The principal goals of the electricity restructuring in Argentina were: • (i) to improve the economic and technical efficiency of the electricity market, and • (ii) to ensure adequate long-term investment levels in electricity. • In the process of unbundling, the major electric utilities were commercialized – in the case of SEGBA, this process has begun as early as 1989. The original round of privatization was very competitive. • Roughly 10,000 MW of Argentina’s total installed capacity of 18,300 MW has been sold, leaving about ten power generators under the ownership of federal or provincial governments.

  6. Capacity Ownership in Argentina • The restrictions placed in IPPs were largely to protect the competitive composition of the wholesale market. First, no single generation company was allowed to provide for more than 10% of national generation capacity. • Additionally, IPPs were prohibited from owning majority shares in electricity transmission facilities.

  7. Efficiency In Argentina Market – Heat Rates • A couple of simple statistics illustrate significant improvements in the productivity of generating plants. The above chart shows the amount of fuel used relative to electricity output has declined significantly

  8. Plant Availability • Plant Availability has dramatically improved from about 60% in 1993-1994 to 75-80%

  9. New Argentinean Plants in Database • Argentina demonstrates that a developing country can attract capacity with reasonable financing terms

  10. New Capacity in Argentina • The current reserve margin in Argentina is 89% due to merchant capacity additions

  11. Prices in Argentinean Market

  12. Un-served Energy in Argentina and Losses

  13. Chile Privatization • Privatization in Chile increased the productivity of utilities by: • cutting energy losses by more than half to 8.3 percent in 1997, • by doubling labor productivity in distribution, and • by tripling energy generation by worker in the largest generating company. • Although privatized companies became substantially more efficient, however, these gains were only transferred to customers in areas characterized by competition. • In the main market, the regulated wholesale price of electrical energy fell by 37 percent. In contrast, the final price to customers did not fall to reflect the huge productivity gains that were achieved after privatization. Between 1987 and 1998 the regulated price to consumers fell by only 17 percent. This situation led to spectacular increases in the profit rates of distribution companies: the rate of return of the largest distributor rose from 10.4 percent to 35 percent in this period. These profit rates are striking considering the low market risks carried by distribution monopolies (Fischer and Serra 2000).

  14. Argentina Market Pre-Requisites • Investment Climate • Country Bond Rating: S&P BBB- • Billions of USD in Foreign Investment • Physical • Economics of Natural Gas Combined Cycle • Natural Gas Availability • Transmission System • Rates/Regulatory • Industrial Customer Rates • Separation into Multiple Companies • Unbundled System • Cost-based Energy Bids • Capacity Price Up-lifts

  15. Capacity Up-Lift in Argentina

  16. Market Structure - Capacity Pricing Using Up-Lifts • Generators whose plants are scheduled for dispatched one day in advance or who are actually dispatched receive a pre-determined capacity payment for hours falling outside low periods.

  17. Financing of AES Panara • Combined Cycle Plant (830 MW) • Sponsors: AES and CEA; Plant Cost $448 Million • Financing • Equity $154 Million: 34% • IDB – A Loan $ 66 Million: 15%; 14.5 Year • IDB – B Loan $ 66 Million: 15%: 12.5 Year • JEXM Direct $ 81 Million: 19% • JEXM Comml $ 81 Million: 19% • No long-term Contracts • Plant Operation - 1999

  18. AES Panara – Financing Structure • Analysis Model Driven • Current and projected capacity • Analyse • Hydro conditions, planned capacity, interest rates, fuel dynamics, capacity payments • High DSCR’s – 2.31 in first 5 years • Trapped Cash • Cash Sweep Mechanisms • Forward Looking Financial Ratios • 12 Month Debt Service Reserve

  19. La Plata Cogeneration Plant • 128 MW Combined Cycle • Cost $110 Million or $859/kW • Debt Financing $75 Million (68%) • OPIC Guaranteed • Term: 12 Years • Electricity Sales • 73 MW to Refinery • 55 MW to Grid

  20. Implications of Argentina Case Study • Divest generation into many companies at outset • Generation was split into multiple companies and vertical integration was not allowed at the outset • Markets work well when efficiencies are available • Natural gas was available and could new combined cycle plants could compete with existing capacity; hydro fluctuations caused problems for merchant plants • Financing MPP’s in developing country requires multilateral support, but can be accomplished • Plant costs are competitive with developing countries • Capacity prices can be stable, but can promote excess capacity • Markets can work with cost based energy pricing and administrative capacity prices

  21. Argentina – Postscript • After having been a model for developing countries, Argentina economy collapsed during a four year period from 1999-2003. The seeds of this collapse had been apparent for some time – for example in the ballooning external-debt-to-GDP ratio, which rose from 28% to 51% during the 1990s, while total debt service as a percentage of exports rose to 97% by 1999. • Internal consumption plummeted, fiscal policy contracted, and private investment has all but disappeared. In 2001, Argentina abandoned the currency peg that had maintained 1:1 parity between the dollar and peso throughout the 1990s, and watched its currency lose 200% of its value in a matter of months.

  22. Argentina Financial Crisis • During the period 1992-2000, from the initial privatization until the recent national crisis, IPPs for the most part thrived in a strong market overseen by a stable regulatory regime. • Since the crisis, IPPs (and all private infrastructure sectors) have been locked in ongoing disputes with the government regarding aggressive policies in the aftermath of the devaluation. These measures included freezing of tariffs and limits on expatriation of profits.

  23. California Power Crisis

  24. California Crisis Introduction • During the period of May 2000 – May 2001 prices of electricity skyrocketed, there were numerous power outages and one of the largest and oldest utility companies in the country was forced to declare bankruptcy. • The crisis led to fierce debates between people who advocate free markets in electricity and people who argue that market liberalization is bad policy and commentaries on the crisis continue to be influenced by the source of party making the commentary. • It is clear that the situation in California put a stop to the deregulation movement around the whole world. • It is also clear that very sophisticated analysts who developed the California market had not predicted the possibility of the price spikes in their risk analysis even though the fundamental factors that supposedly caused the crisis including demand growth, low water flow, plant outages and fuel price volatility were predictable. • Those who developed pricing models could not predict the possibility of extreme scenarios outside of relatively narrow ranges.

  25. De-regulation • A few year before the California crisis virtually nobody questioned the benefits of de-regulation. Utility companies, competitive suppliers, environmental groups, consumer representatives and government regulators all groups supported de-regulation. Legislation that de-regulated the industry was often passed by unanimous margins and competition was replacing government oversight all over the world. That has all changed with the California crisis and the financial demise of Enron. • According to the Wall Street Journal: • “It was one of the great fantasies of American Business: a deregulated market that would send cheaper and more reliable supplies of electricity coursing into homers and offices across the nation…Now with the power industry hovering uneasily between regulation and deregulation, it faces the prospect of a market that combines the worst features of both: a return to government restrictions, mixed with volatility and price spikes as companies struggle to meet the nation’s energy needs.” • Understanding pricing and valuation in competitive markets is not less of an issue because of questions related to the efficacy of regulation. Indeed, the problems with Enron and California demonstrate the immense complexity of risk assessment, pricing and valuation issues in the industry.

  26. California Crisis Issues • What was the cause – was it changes in demand and supply, problems with the design of the market or was it a fundamental problem with deregulating markets? • Can mechanisms be designed to avoid similar problems in other markets or is the problem fundamental to markets? • Economic and Financial Issues • Use of history in making forecasts of the value of electricity • Dramatic changes in value with different hydro conditions • Differences between upside potential and downside risk • Non-linear movement of value in electricity

  27. Belief that Problems were or were not Inherent with Market Systems • Argument that the problem was just the manner in which California set up the structure of the market: • The California power crisis of 2001 gave reform an unjustified bad image. The spectacular collapse of the Californian power market in 2001 -- due mainly to design faults -- has created the impression that liberalization of power markets is too risky for developing countries. • Argument that the problem is inherent in de-regulated markets • Difficulties in implementing competition in power markets so by now well known, as illustrated by California.s experience. Full competition in the wholesale power market should therefore not be attempted for the foreseeable future in most developing countries.

  28. Outages Caused by the California Crisis

  29. Other Crisis Impacts • Rolling Blackouts • PG&E Bankruptcy • Edison Electric Near Bankruptcy • State Budgetary Surplus Eliminated • Governor Arnold

  30. Opinion about the California Crisis Depend on Perspective • Advocates of Competition • Problems were in the structure of the market • Consumers did not see prices • Long-term contracts not allowed • Capacity pricing not structured • Transmission not structured correctly • Obstacles to building new plant • Critiques of Competition • Problems inherent in competitive markets • Exercise of Market power will occur • Market did not encourage building • Market cannot work in hydro systems

  31. At the end of May--in fact, on May 22, 2000 --there was an unseasonably hot day. Power use went up some in California, but the price of power skyrocketed--much more than the demand for that day.

  32. High wholesale prices turned out to be a very large risk. But the risk may have been severely underestimated or completely unrecognized by many participants in the process. The utilities could have protected themselves against high wholesale price by entering contracts for financial hedges, designed to cover risks of buying power from a volatile spot market while selling it at a frozen retail rate. However, although such hedge contracts were offered to utilities, they rejected these offers, apparently believing that the hedges included overestimates of the risks and thus that the prices of the hedges were too high.

  33. Long-term Contracts and Reduced Reliance on Spot Prices • The utilities tried as early as 1999 to gain the right to procure electricity on a longer term basis. But the block forward market allowed contracts for no more than one year. More significantly, such markets, by necessity, offered a standardized contract and did not allow the wide range of contractual agreements that would be desirable for a utility to cover its purchases. • But it was a step, albeit a small step, toward allowing the utilities to move away from exclusive reliance on spot markets to acquire electricity. However, until August 2000 the utilities had no right to enter bilateral contracts. • Entering such contracts could have substantially reduced the risk of large changes – up or down – in the acquisition cost of electricity. Utilities with such contracts thereby could have guarded against or at least limited the high risk of large fluctuations in the wholesale price of electricity. But that was not to be the case and thus the system was characterized by unnecessarily large risks. • Divestiture had greatly increased the risk facing investor-owned utilities, although it did not change the inherent system risk. If the utilities had continued to own their generating capacity, they would have faced cost variations that changed with the average generation cost; but because they had divested the assets, they would face cost variations that changed with the marginal cost of electricity. Since the marginal cost is much more volatile than the average cost, divestiture led to far more cost volatility for the investor-owned utilities. • Problem with contracts: options to leave the utility or to come back to the utility.

  34. It is apparent that investors did not appropriately quantify the upside potential relative to the downside risk. The problem is that investors focus on expected returns without paying enough attention to the skweness of the upside and downside returns. The upside return on underlying loans was a credit and a higher margin when the loans were re-financed. . . California Market Prices Prices before the California electricity crisis were relatively low. But most of the forces that lead to the extremely high prices such as high electricity demand, no new capacity and low levels of water in damns could have been predicted. Economic Variables are Non-Linear and Difficult to Evaluate with Statistical Analysis of Historic Data

  35. Oil Price Errors from EIA

  36. Case Study - California Meltdown • Results of Market • Market Power • Bankruptcy of Distributors • Price Volatility • Little Merchant Construction • Regulatory/Market Structure Problems • Stranded Investment Charges • No Retail Price Signals • No Bilateral Contracts • No Capacity Pricing • Characteristics of Physical System • Transmission Bottlenecks • Reliance on Imports • Hydro Volatility • Natural Gas Market Power

  37. Supply and Demand • Demand for Electricity Increased a Bit More than Expected • Healthy California Economy • Growth of Electricity-intensive Products • Decline in the Retail Price of Electricity • Supply of Electricity Did Not Increase • Until Recently No New Generating Plants on Line • But Many in pipeline • Slow Regulatory Approval Process • Hydro Supplies from Pacific Northwest and Southwest Decreased • Costs of Electricity Generation Increased • Prices of Natural Gas increased • Prices of NOx Prices skyrocketed under RECLAIM project

  38. Source: Western Governors’ Association, Conceptual Plans for Electricity Transmission

  39. Volatility in Demand Growth • During the period from 1997 through 2000, the consumption of electricity in California continued to grow slowly as it had for the last ten years. • The California economy was remaining healthy and population was continuing to grow steadily. Per capita electricity use grew modestly during that time. • From 1990 to 2000, use of electricity increased from 26,000 MW average consumption rate to just above 30,000 MW, a growth of 16% over ten years, or 1.4% per year. • Growth in energy consumption, however, was somewhat faster from the 1997 through 2000 period, increasing by almost 2,000 MW during the three years, or an average growth rate of 2.3% per year average. • From 1999 to 2000, average consumption increased slightly more than 1,000 MW, almost 4%. • Peak loads were growing at roughly the same rates.

  40. Supply and Demand During a Typical Day

  41. Trends in Electricity Demand

  42. Supply and Peak Demand

  43. Electricity Usage in California

  44. Forecast of Electricity Prices Before the California Crisis The published analyses, including those done by the California Energy Commission and those published through the academic community all forecast relatively low wholesale prices. ¢/kwh California Energy Commission “Market Clearing Prices… 2000-2010”, Feb. 2000, p. 6Cautious Development Scenario, nominal dollars

  45. Actual Costs of Wholesale Power Total Cost $/Billion Average Cost ¢/Billions ISO Control Area,ISO Department of Market Analysis $40 BILLION MORE !!

  46. Price History

  47. Electricity Prices Relative to Natural Gas Prices

  48. Similar Problems in New Zealand

  49. Factors that Cause Volatility in Electricity Prices and Electricity Costs • Volatility in Electricity Prices • Demand Volatility (Higher or Lower Economic Growth) • Hydro and Renewable Volatility • Fuel Price Volatility • Outage Volatility • Effect of Risks • On Prices • On Costs