case studies in electric power

Case Studies in Electric Power

Electricity Case Studies Apr 19, 20232

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

Argentina and ChileCase Study


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.


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.


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.


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


Plant Availability

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


New Argentinean Plants in Database

• Argentina demonstrates that a developing country can attract capacity with reasonable financing terms


New Capacity in Argentina

• The current reserve margin in Argentina is 89% due to merchant capacity additions


Prices in Argentinean Market


Un-served Energy in Argentina and Losses


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).


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


Capacity Up-Lift in Argentina


Market Structure - Capacity Pricing Using Up-Lifts

• Generators whose plants are scheduled for dispatched one day in advance or Generators whose plants are scheduled for dispatched one day in advance or who are actually dispatched receive a pre-determined capacity payment for hours who are actually dispatched receive a pre-determined capacity payment for hours falling outside low periods.falling outside low periods.


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


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


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


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


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.


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.

California Power Crisis


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.


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.


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


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.


Outages Caused by the California Crisis


Other Crisis Impacts

• Rolling Blackouts

• PG&E Bankruptcy

• Edison Electric Near Bankruptcy

• State Budgetary Surplus Eliminated

• Governor Arnold


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


• 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.


• 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.


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.


Economic Variables are Non-Linear and Difficult to Evaluate with Statistical Analysis of Historic Data

• 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.

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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.

California Orgeon Border Prices

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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


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

Supply and Demand


Figure 2Western Generation Mix Options

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


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.


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Similar Problems in New Zealand


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

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General Conditions in California that Made Markets Difficult

• Hydro System

• Reliant on Imports of Energy

• Difficult to Build NGCC

• Hydro was 23% below previous levels

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California Case Study demonstrates what is not a Success

• One problem often cited was that the market framework did not encourage development of new capacity

• Lack of Capacity was Related to Market Power Exercise

• Was it prudent to consider California in Developing Market Framework


In-State Generation After Considering Reduced Imports from Hydro Resources


Why was Capacity not developed in California Framework

• Market Prices Did Not Justify Additions

• Environmental Constraints

• No Bilateral Contracts

• No Capacity Prices

• No Market Monitoring to Build Capacity Supporting Hydro (as in New Zealand)

• IPP Contracts Made Problem Worse

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Demand Response Argument

April 19, 2023 www.edbodmer.com 59


Lack of Demand Reduction

Pacific Gas & Electric

Southern California Edison

San Diego Gas & Electric


Power Contract Issues

• Variability in spot price versus total generation

• Use of contracts to limit dependence on spot prices

the state initiated requirement for California's investor-owned utilities to sell all of their generation into, and buy all of their energy needs from, the PX should be eliminated. The buy/sell requirement led to over-reliance on spot markets and over-exposure to short-term price fluctuations.


Market Power

• FERC: “there is clear evidence that the California market structure and rules provide the opportunity for sellers to exercise market power when supply is tight and can result in unjust and unreasonable rates.”


Price Caps Established


Market Power and Game Playing

• But a detailed examination of recently released internal memos by Enron Corp. lawyers, transcripts of trader conversations gathered by investigators, and scores of interviews with market participants and regulators yields a comprehensive look at how the U.S. energy industry cashed in on and contributed to California's energy crisis. Among the findings:

Energy companies seized on loopholes and local shortages to charge prices hundreds of times higher than normal.

Suppliers withheld power from the state's primary market, and sometimes idled power plants to induce shortages and boost prices.

Gas companies manipulated supplies and prices, driving up the cost of a main ingredient of electricity.

Enron played a much bigger role than previously believed in California's energy market. Its trading strategies overwhelmed regulators and drove up prices.

• Almost from the start, participants on all sides probed for weaknesses. One way the ISO seeks to ensure reliability is to pay plant operators to keep generators on standby to meet last-minute surges in demand. In the market's first weeks, payments for this service, set by auction, were typically less than $10 a megawatt-hour. (A megawatt-hour is roughly the amount of power needed to supply 1,000 homes for an hour.)

• Then on July 13, 1998 -- 3-1/2 months after deregulation started -- a unit of Houston-based Dynegy Corp. offered to supply standby power at $9,999 a megawatt-hour. Dynegy was exploiting the fact that the market had been set up with few rules on what suppliers could charge. The ISO had to accept the bid because it expected high power demand and there were few other offers of standby power. Thus, Dynegy and three other suppliers wound up splitting $8 million for keeping plants on call for five hours, according to state and federal records. Dynegy declines to comment on the incident.


Manipulation of Natural Gas Prices

• Charge that El Paso, a Texas Natural Gas company was manipulating the price, and manipulating behavior on the main pipeline into California. He showed me his evidence. I thought it was a dead-bang, absolute case of price manipulation.

• The CPUC claimed El Paso had increased natural gas prices in California, by withholding capacity on its pipeline. The FERC found that El Paso had the ability to exercise market power. El Paso and the CPUC settled the case in late-2003 for $1.6 billion.


Enron Market Manipulation

• On December 2, 2001, Enron filed for bankruptcy. Subsequently, allegations were made that Enron, through its affiliates, used its market position to distort electric and natural gas markets in the West. These allegations included the claim that Enron’s filing for bankruptcy had caused a substantial decline in spot prices and, thus, demonstrated that Enron had been manipulating prices.

• Strategies engaged in by Enron traders, including “Ricochet,” “Get Shorty,” “Death Star,” and “Fat-Boy.”

• Enron’s trading strategies used false information in an attempt to manipulate prices also found that the published natural gas prices at the California border could not be independently verified and may have been manipulated.

• Enron owned a number of qualifying facilities.


FERC Report on Market Manipulation

• The Report found evidence of significant market manipulation in Western energy markets during 2000 and 2001.

• According to the Final Report, increases in spot gas prices contributed to the price increases in the electricity markets. Dysfunctions in the natural gas market appeared to stem, in part, from efforts to manipulate price indices compiled by trade publications, including reporting of false data and wash trading.


Comments on Market Power

• I believe that they are engaging in cartel behavior--or cartel-like behavior. They can--through manipulating whether their power plant runs on a particular day, and through manipulating the old system of biding--dramatically increase the price of power, or dramatically reduce the supply on any given day, which creates an artificial shortage, and then drives up the price power.

• Yes, in order to create a shortage in the winter, because California has plenty of power capacity in the winter. To put a number to it, we only use about roughly 30,000 megawatts a day at peak of power in California in a winter day. We have 41,000 megawatts available in California--power plants ready to run. So we've got a big cushion on any given day.

• But what happened starting in December, and continuing through January and February, is the folks who could run, didn't run--dropping the available amount of power down to--imagine this--just below what our power needs were, creating an artificial shortage and driving prices up.


Enron Strategies in California

• No company devised more ways to take advantage of the system than Enron, which remade itself in the 1990s from a pipeline company to an energy trader. The Houston energy giant bought Portland General Electric Co., a regional utility located in Portland, Ore., in 1997, and set up a trading desk later run by Tim Belden. A former researcher at a federal energy lab who typically rode his bike to work, Mr. Belden spent 15-hour days combing through regulatory filings trying to crack the code of California's new market, according to former employees in the office.

• He wasn't afraid to take chances. A former co-worker recalls Mr. Belden losing $100,000 of Enron's money on an "experiment" to see how prices would react if Enron simultaneously exported power from California at several locations.

• Mr. Belden quickly focused on wringing profits from the state's aging and inadequate transmission network. Enron bid aggressively at the ISO's 1999 auction for transmission rights on heavily used lines, which gave Enron priority for moving electricity on these lines, and a share of the ISO's fees for allocating capacity.

• Enron devised multiple strategies for overloading transmission lines and reaping payments for relieving the congestion it had created, according to the memo by Enron's lawyers and interviews with former traders. The congestion fees could be so lucrative -- as much as $600 a megawatt-hour -- that Enron regularly transferred power across the state and sold it at a loss, with the fees more than making up the difference, according to a former Enron trader.

• By the summer of 2000, Enron traders had a portfolio of such tactics, with colorful nicknames such as "Death Star" and "Red Congo." Both involved scheduling power to flow in one direction on the ISO system, and in the opposite direction on another system outside the ISO's control, such as a transmission line operated by California cities. In that way, Enron could be paid for "relieving" congestion on the ISO system without actually putting power on or taking it off the grid. To execute these strategies, Enron created complicated chains of transactions using out-of-state partners.


Prices versus Marginal Cost


Outages Increased

• Outages: Year 2000 Planned and Unplanned Outages increased by 53% in June, 57% in July and 23.5% in August compared to 1999.

• Average megawatts out of service increased by 77% in June, 121% in July and 461% in August above the same period in 1999.

• California's power plants started getting sick. By mid-November, 2000, nearly one-fourth of the state's generating capacity sat idle for planned maintenance or emergency repairs, more than three times the outage rate in November 1999. But it was difficult to determine, even after state officials began surprise plant inspections, whether the outages were a deliberate attempt to make money by shrinking supply or the predictable result of running 30-year-old plants hard all summer.

• "There's something broken in every power plant all the time," says S. David Freeman, director of California's public-power authority, who formerly ran municipal utilities in Sacramento and Los Angeles. Under the old system, Mr. Freeman says, utilities tried to keep plants running. But under the new system, he says, generators had incentives not to.


Units Off-Line During California Crisis



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• Price volatility was Price volatility was affected by plant affected by plant outages that were outages that were in part driven by in part driven by problems with IPP problems with IPP contractscontracts

• suppliers began offering less power to the daily auctions at the Power Exchange and at higher prices. On the afternoon of June 28, for example, prices climbed to $750 a megawatt-hour, four to five times as high as on similarly hot days in the summer of 1999. Power Exchange investigators later concluded that all of the power-plant operators -- Dynegy, Williams, Duke Energy Corp., Reliant Energy Inc. and Mirant Corp. -- as well as marketers such as Enron had at times withheld electricity from its daily auctions. The suppliers may have tried to sell the power to the ISO or out-of-state buyers, hoping to fetch a higher price. Or, they may have idled the plants, hoping to induce a scarcity that would drive prices even higher.


Were Maintenance Outages Expected of Manipulated

• Maintenance occurred at generating plants that were 30 to 40 years old. These generating facilities were operated at a significantly higher rate in 2000 than in previous years. Most of the generating facilities were out-of-service because of tube leaks and casing problems, turbine seal leaks and turbine blade wear, valve failure, pump, and pump motor failures.

• Staff did not discover any evidence suggesting that the audited companies were scheduling maintenance or incurring outages in an effort to influence prices. Rather, the companies appeared to have taken whatever steps were necessary to bring the generating facilities back on- line as soon as possible by accelerating maintenance and incurring additional expenses. Also, the outages did not necessarily correlate to the movement of prices on a given day.

• However, it is practically impossible to accurately determine whether such outages are orchestrated or not because plants frequently run with physical problems and the timing of repairs and maintenance is often a judgment call on the part of plant owners or operators.


• Contributing to the increase in electricity prices during the crisis were even more dramatic increases in the natural gas price than had occurred earlier in 2000. In December, the California natural gas price jumped to about $50 per million Btu, a factor of 10 higher than it had been.

• Although this price peak lasted for only two weeks, the spot natural gas prices in California remained above $10 per million BTU until June of 2001 (see Figure 25, based on data from Enerfax.com). These high prices did not result from limitations in the availability of natural gas at the wellhead or at market centers, as shown by the prices of natural gas at Henry Hub, Louisiana, the major market center. Rather the price spike resulted directly from the large demand for natural gas to fuel electric generators during the winter when the demand for natural gas naturally peaks, coupled by limitations in the pipeline capacity to transport natural gas within the State and the absence of natural gas held in storage from previous months.

• The sharp increase in natural gas prices, coming just when investor-owned utilities were not paying generators for electricity they sold, provided strong incentives for generators either to stop producing electricity or to bid very high prices to sell the electricity they did generate. Thus, these natural gas prices probably contributed substantially to the wholesale electricity price increases during the crisis, particularly to the December electricity price spikes.


Manipulation of Natural Gas Prices

• Suppliers again showed their ability to adapt to new rules, this time by possibly manipulating natural-gas prices. Gas prices were a key ingredient in FERC's formula for determining justifiable electricity prices during that period. FERC investigators believe Enron and others may have manipulated gas prices to boost allowable electricity prices. On Jan. 31 alone, investigators say, Enron did 174 natural-gas trades with one other unidentified company, helping to send gas prices in California up 33% in a single day. Investigators proposed changes to the electricity-price formula that would reduce justifiable power prices on some days by two-thirds.


Exercise of Market Power in California Meltdown

• Market Power resulted in significant increases in pricesMarket Power resulted in significant increases in prices


Prices did not Reflect Competitive Outcomes


Average California PX price and MC

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Kernel Regression ofLerner Index vs. Capacity Ratio

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Monopoly Rents Due to Market Power


Market Share and Market Power

• Current standard of 20 percent market share gives no assurance of whether a seller can inflate the market price

• As low as 5 percent market share can create a problem when the demand is more than 95 percent of the total available capacity.

• In this case, a supplier with 5 percent of market share becomes pivotal.


End of the Crisis

• Suddenly, in June, 2001, it was over. The long-term contracts were in place. Gas prices began to fall. More hydro-power was available. Users, reeling from a slowing economy and higher rates, embraced calls for conservation. And finally, FERC imposed price caps across the West, eliminating some loopholes and signaling a new, tougher stand against power suppliers. With peak power demand down 14% from a year earlier, wholesale power prices fell by almost half in June and declined further each month for the rest of 2001.

• A year later, an uneasy calm has settled over California's electricity grid. The last rolling blackout was in May 2001. The state survived near-record demand for power during a July heat wave.


• The premise that “The Market will Provide” is too simple for a critical infrastructure such as the electric energy system - can have both over & under supply

• Some one has to have the responsibility for ensuring adequate generation supply

• Construction of power plants is very capital intensive so builders want some guarantees of revenue for several years to lower their risks

• The time delay from when it is obvious new plants are needed to when they can be sited, built and on-line is 2 to 4 years.

• Single Price Auction structure breaks down when there is a scarcity of supply

• Bi-lateral deals and forward contracting for blocks of energy is essential to reduce risks and guarantee adequate energy supplies

Lessons Learned – California ISO


California Lessons

• The California power crisis produced the following useful lessons:

A mandated, deregulated, wholesale bid-based spot market is too complex to operate and too difficult to monitor for abuse of market power for all but the most advanced developing countries.

Long-term contracts should be allowed as a form of insurance for distributors purchasing from a new spot market. A vesting contract that fixes the sale price for trade between existing or new generators and distributors for five or more years should be established before the market goes into operation. They also provide at least initial protection against market power.


California Lessons Continued

• Retail tariffs should be aligned with the costs of wholesale power. Regulators should avoid rate freezes that expose distributors to the possibility of an unsustainable squeeze on their cash flow occurring when rising wholesale power costs approach or even exceed fixed retail rates.

• A poorly designed power market will not operate properly, and inadequate attempts or delays in correcting market distortions will spill over into a serious financial crisis.

• One or more commercially viable entities must have a legal obligation to provide adequate supplies for Small retail power users who prefer to deal with a default supplier rather than shop around in the market for a supplier and face volatile spot market prices.


Implications of California Meltdown

• What really could have been done differently in California

Don’t create markets when there is:

Reliance on significant hydro

A tight reserve margin

Restrictions on natural gas supply

Transmission constraints that limit competition

The market should not

Explicitly limit bilateral contracts because all of the prices will be at the marginal cost

Begin when prices do not equal long-run marginal cost --stranded investment problem

Involve a single-buyer model where there is limited retail access


Implications for Market Analysis

• Should Bilateral Contracts be Encouraged?

• Should Retail Customer Choice be Limited to Create More Creditworthy Off-takers?

• Should Industrial Customer Choice without Fixed Tariff Rates be Demanded?

• Should Capacity Markets be Implemented?

• Should Price Caps be Implemented and if so, at what Level?

• How can Forward Markets be Developed?

• What Market Monitoring Systems should be Established to Limit Market Power?


May 18, 2001Subic Group 90

Latest Photograph of Plant Under Construction


• Frequent brown outs ranging from 2 to 12 hrs daily in early 1991.

• Cancelled Batam Nuclear plant when it was almost complete.

• Projected growth in electricity demand requires commissioning of new plants and rehabilitation of old plants.

• State-owned Generating Company was NAPCOR; Approx. 72% of NAPCOR’s capacity is in Luzon.

• Frequent closure of existing plants due to deterioration of oil based plants.

• Failure to undertake regular maintenance of certain plants

• Postponed maintenance due to insufficient power reserve

• The S&P bond rating for the Philippines was BB

Philippine Power Market - Background


Background on Existing State-Owned Utility Company

• Approx. 72% of NAPOCOR’s capacity is in Luzon.

• Existing plant capacity exceeds peak demand (est. at 3,473 MW).

• NAPOCOR unable to operate its plants at full capacity, only 2,333 MW (50%) of 4,639 MW total Luzon capacity.

• Frequent closure of existing plants due to deterioration of oil based plants.

• Failure to undertake regular maintenance of certain plants

• Postponed maintenance due to insufficient power reserve


Context of Power Crisis in Early 1990’s

• To understand the rush to welcome private investment in the early 1990s, it helps to also see the cost of the chronic blackouts of that time.

• At the peak of the shortage, the blackouts averaged 12-14 hours per day, 300 days per year.

• A World Bank report in 1994 estimated that gross economic cost of the outages was US$0.50/kWh.

• Thus, even though IPP-generated electricity (average cost US$0.0652/kWh) at the time was more expensive that NPC-generated electricity (US$0.0637/kWh), the inability of the government to finance rapid expansion of the power sector made private investment extremely attractive.


Legislation and the Power Shortage

• The Philippines entered the IPP market early, with a 1988 presidential decree authorizing private investment in the generation sector. Major investment in IPPs occurred in response to a 1991-93 electricity crisis.

• The Electric Power Crisis Act passed in 1993 authorized negotiating IPP contracts on a fast track basis.

• In terms of addressing the power shortage, this law was a success—several thousand megawatts of generating capacity was installed in the country in the first 18 months.

• Most of the generating capacity built during this time was based on combustion turbines or diesel systems—the only generation plants that could be brought to operation within a year—which are characterized by low initial capital costs, but high operating costs.

• The fast track authority under this law expired in April 1994.


Growth in Electricity Generation from EIA

Prediction was for about 9% Growth


Fast Track Contracting

• Because of the power crisis, the government had no significant leverage in the negotiations. The unstable political condition created a situation where “economy risks” required a premium placed on project returns.

• The entry of some IPPs had to be on a “fast-track” basis and some were contracted through negotiations rather than competitive bidding.

• In contrast, Thailand bided out its first batch of IPP capacity during the time when its economic performance was the envy of all ASEAN. As a result, the offers were very competitive (some offers took on the FOREX risk) and represented about ten times more capacity than what EGAT had asked for.


Three Rounds of Development

• The IPP sector in the Philippines developed in three main rounds.

First, the plants contracted in the early 1990s to address the power crisis were largely oil-fired plants with 5-12 year PPAs. These tended to be expensive because: (1) the rapid capital recovery period under short PPAs, (2) the extreme pressure on government negotiators stemming from the grave electricity crisis, and (3) the high fuel cost oil plants were dispatched as baseload facilities during the crisis.

Second, a wave of large baseload coal plants – most importantly Pagbilao (700MW), Sual (1200MW), and Quezon (originally 440MW, now rated at 460MW). These reached operation between 1996 and 2000 and had longer PPAs (up to 25 years).

Third, a round of big hydro/irrigation projects and natural gas plants that reached operation from 1998 to 2002, including Casecnan hydro (140MW), San Roque hydro (345MW), CBK hydro (640MW), Ilijan natural gas (1200MW), Santa Rita natural gas (1000MW) and San Lorenzo natural gas (500MW).


Philippines Contracts


Capacity was Added over Many Years


Additions of Capacity by Type


Diesel Added Early/Gas and Hydro Added Later


Initial Contracts

• The country had its first Build-Operate-Transfer contract in 1987, with Hopewell Holdings Ltd. of Hong Kong tycoon Gordon Wu as the proponent. Hopewell constructed two 100-megawatt gas turbine plants in Luzon.

• The venture was deemed so successful that the government was encouraged to enter into more BOT power contracts and even enact the BOT law (Republic Act 7718) that would allow Napocor to tap the private sector more effectively. Past and present government officials agree that the early Hopewell contracts provided the model for all future power deals with the private sector.

• But Napocor soon found itself with more IPP contracts, and more power, than it could handle, and what was once thought of as a brilliant solution to the country's power needs have now become problems themselves. At the time it was accumulating IPP contracts, the government had also let the private Manila Electric Co. (Meralco) to build its own power plants, which later exacerbated an energy oversupply.


Summary of Capacity and Costs

• By 1998, foreign owned IPPs accounted for US$6 billion of investment and 4800 MW of generating capacity. Over 90% of new capacity installed during the 1990s came from foreign owned IPPs.

• Average capital cost of $1,250 per kW.

• IPP capacity with PPAs is now 55% of the total capacity.

• The first contract was signed in 1988 and more than forty projects have been built in total. IPPs in the Philippines have exhibited a wide variety of characteristics from fuel choice to the composition of project sponsors and the identity of the offtaker. IPPs in the Philippines have largely earned healthy returns, even in the wake of economic crises and a highly visible renegotiation of most of the PPAs in the sector. From the country perspective, returns have been mixed. Political instability and poor sector planning have led to expensive electricity.


Comparative Plant Costs


Cost of Plants per kW


Philippines PPA Features

• Capacity-based formula with take or pay and capacity nominated by the IPP.

• Energy-based formula, a percentage is applied on a contracted or guaranteed annual energy.

• Availability fee formula carries both the capacity recovery and the fixed O&M fees. These fees are payable as long as the facility is available even if not dispatched.

• NPC is responsible for the supply of fuel, with delivery at site. Storage, usage and management of the fuel are within the control of the IPP. This was because NPC has tax-exempt privileges with respect to fuel oil purchases and government-to-government arrangements for coal; making fuel pass through charges to consumers cheaper.

• Fee payments by NPC to the IPPs have large dollar denominated components. NPC thus bears the currency risk to the extent of the dollar payments.


Philippines PPA Provisions Continued

• Payments in IPP contracts have both Capacities cost recovery and O&M component. In turn, the O&M portion is subject to escalation. In some of the geothermal contracts, fees are bundled into a single energy charge and escalation is pegged thereon to as high as 75%.

• Escalation is based on varying factors depending on the project such as salary adjustment of personnel, movement of local and foreign consumer price indices, and the peso-dollar exchange rate.

• A number of NPC’s obligations are fully backed up by a government guarantee or performance undertaking. Very few contracts have only partial government performance undertaking depending on stipulations regarding payments of fees, privatization, and foreign exchange convertibility.


PPA Provisions

• The take-or-pay provisions ensure that the IPP proponents are paid up to the level of the minimum energy off-take (MEOT) whether the government utility was able to sell the power or not.

• IPP liabilities estimates up to the remaining terms of the contracts is in-between $6 - $ 8B in net present value. The buy-out figure of $11.8 B is gross since the Government can turn around and sell the capacity to another party.

• In 1992, the GDP was US$52 billion. PPA buyout in total would be 21% of GDP.


BOT and Sovereign Guarantee

• Ownership structure for IPPs in the Philippines is dominated by the BOT form. The prevalence of BOT contracts as opposed to other forms results from the fact that the “transfer” element of the project makes the project eligible for a sovereign guarantee. Formally, only solicited projects are eligible for this guarantee – a rule that invited substantial controversy in the case of the CBK hydro project, which although unsolicited, received a performance undertaking from the Department of Finance.


List of Projects and PPA Terms


Case 1: Enron Subic

• Summary

Financial Close: 1993 (First Round)

Commercial Operation: 1994

PPA Agreement: 15 Years; Guarantee by Government

Bonds: $105 Million

Maturity 15 Years

Repayment Level

Interest Rate 9.5% (3.68% spread to Treasury)

Minimum DSCR 1.37

Completion Guarantee/Liquidated Damages

Capacity Charge $21.6/kW/Month


BOT/PPA Contract

• 15 year BOT and toll process

• NAPOCOR (government owned generation company) to supply fuel & take electricity - no fuel availability risk

• Capacity fee $21.6/kW/month on available capacity

• Capacity fee is dollar denominated – no direct foreign exchange risk, overseas a/c

• O&M fixed fee and energy fee is in Peso - $4.56/kW/Month

• heat rate penalty & bonuses

• buy out rights @ NPV capacity fees- late payment, change of BOT law, war, etc


Enron PowerPhilippines Corp

PhilippinesGovernment

EnronCorp.

113MWSubicPowerCorp.

PhilippineInvestors

15-yearBOTConcession

NapocorSupply

Fuel Free

•Capacity Charge•O&M Charge

•Energy ChargePPA

Enron PowerOperating Co.

TurnkeyConstructionContract

CompletionGuarantee

Equip’t Cos. Warranties

US$105 million, 15-year Notes

BuyoutRights

Enron SubicPower Corp

O&MAgreement

PerformanceUndertaking

GroundLease

Insurances

Fluor Daniel

Enron PowerPhils. Op’g Co.

EPC

65%

35%

Case Study - FundingEnron - Subic Bay, Philippines


113 MW Diesel Generator Power StationSubic Bay, Philippines

Sources of Funds:

Notes $ 105 M

Subordinated Note 7

Contr. Of Shareholders 28

Working Capital 2

TOTAL $ 142

Uses of Funds:

Turnkey Contractor $ 112 M

Bonus to Turnkey Contractor 7

Development and other related costs and Fees 14

Pre operating, Start-up and Commissioning Costs 3

IDC 4

Working Capital 2

TOTAL $ 142


Subic Covenants

• Financial Covenants

Debt Service Cover Ratio 1.10

Debt Service Reserve Account: 6mos debt service deposit

Debt Payment Account: monthly retention

Restrictions on

additional indebtedness other than

financing acquisition of Additional Facilities @ max 75% financing scheduled payments to EPOC subordinated debt < US$ 25mln working capital loan

shareholder payments / repayments

payments of sub-debt

investments other than permitted investments

May 18, 2001 115


In Conclusion:

Attractive Return

Well Structured Deal

Solid Sponsors (Enron, NAPOCOR and the Philippine Government)

Manageable Risks

Minimum Take: US$ 20 Million

Conclusion from Investor Perspective


• BORROWER - Subic Power Corporation• Amount - USD 105 million• Maturity - 15 years

• Payments of Principal & Interest are fully guaranteed by Enron Corporation until the Facility Completion Date.

• Repayment - equal semi-annual Jun 28/Dec 28.• Interest is accrued - 9 1/2 % p.a payable semi annual.•Interest base and Margin - US Treasuries 15 Y + 385 bp fixed rate

Bond issue under rule 144 A


Key Defaults

• Failure to pay principal/ interest within 15 days after due dates

• Fails to perform following covenants

maintain DSRA, DPA & Revenue account & payments therein

amendment of project contracts or merge/ sell assets outside indenture

default on other indebtedness over $1 mn. - right of acceleration not waived

Ceasure of BOT/ Performance undertaking and/ or reduction under BOT by over 2% and modification of Performance u’tkg. for the same

Enron’s completion guarantee held invalid/ unenforceable

NAPOCOR’s bankruptcy and Govt.’s non-confirmation of performance u’tkg.


Completion Guarantee

• Completion Guarantee

• All principal and interest payments on the Notes are guaranteed fully by Enron Corporation, and severally, in proportion to their ownership interest in the Company, by House of Investment (HI) and Rizal Commercial Banking Corporation (RCBC).

• Security:

Mortgage on all real property and security interest on all substantial tangible property.

Security interest in Company’s cash and investment.

Collateral assignment of:

BOT Agreement

Turnkey Construction contract

Performance Undertaking

Other project contracts


EPC Contract

• EPOC wrap- Fluor Daniels assistance & local contracts

• $112m fixed price

• LDs $6m capacity, $10m heat rate

• $2m scope discrepancy

• bonus payments for $3.6m capacity and $3m heat rate

• 12-19 month warranty with liquidated damages per day


What IfMin

DSCRMin

InterestCover

PV LoanCoverRatio

EquityIRR

(Post Tax)Base Case 1.39 2.01 1.53 19%Availability = 81% 1.25 1.80 1.36 14%Operating expensesare 50% higher/yr

1.19 1.72 1.23 9%

Interest Rate is 12% 1.37 1.77 1.40 17%

Sensitivity Cases


Adjusted Results


Other Assumptions


Case 2: Quezon Case


Quezon Sources and Uses


Quezon Contractual Structure

• The EPC contractor for the project was Bechtel Overseas Corporation. The project was constructed under a lump sum turnkey Engineering, Procurement and Construction Management contract (“EPCM”) to facilitate financing with non-recourse debt.

• Equipment sourcing was concentrated with US vendors (GE, Foster Wheeler) in order to maximize the use of export credit finance from US Exim.

• The O&M contractor for the project is Covanta. Operations and maintenance is performed on a cost plus basis pursuant to a 25-year agreement providing a monthly fee of $160,000 as of the commercial operations date.

• The project is managed by Intergen under a 25-year management services agreement providing an annual fee of approximately $400,000 as ofthe commercial operations date.


Quezon PPA

• Quezon sells its entire electricity output to Meralco via a 25-year PPA. The tariff is comprised of capacity payments, O&M payments and energy payments.

• The capacity payments include the return of and on debt and equity capital required to finance the project.

• O&M payments cover both fixed and variable costs of running the plant. A component of the fixed O&M charges is also accumulated over several years to fund periodic major maintenance overhauls necessary to keep the plant in proper condition.

• The energy payment covers the cost of coal consumed in the actual production of electricity and is billed through to Meralco at actual cost. Quezon was designed to run as a baseload plant, and the PPA specifies a minimum energy offtake by Meralco of 100% of Quezon’s output.


Quezon Costs

• Capacity and O&M Charges

Capacity Charge: $18.8/kW/Mo Fixed

Fixed O&M Charge; $8.63/kW/Mo Escalating

Transmission Charge: $1.3/kW/Mo

• Energy Charges

Fuel Charge/MWH

Variable O&M Charge/MWH

• Total Cost of Power at 70% Capacity Factor

Approximately 10 Cents/kWh


Financial Results

• Original models by Intergen called for a 23% IRR for equity in the project.

• Intergen itself realized some profit in the 1997 sale of a 26% interest to Global Power Investments, which generated a 12% profit.

• The project has endured periods of technical default under the loan documents, due to non-payment by Meralco. However, the debt service has been uninterrupted.

• The PPA has been renegotiated at various times. Bilateral renegotiations between Meralco and Quezon served to clarify items that were important to both sides.

Philippines Case - Results


Capacity and Demand

• By 1998, peak capacity was 11,988 MW while peak demand was 6,421 MW. Demand projections in the early- and mid-1990s forecast demand growth ranging from 9.5-12% per year.

• A 1994 report by the World Bank already warned implicitly against the risk of over-commitment through the uncoordinated signing of PPAs, which essentially passed demand risk to the consumer through take-or-pay provisions.

• The costs of IPPs were often high because the new capacity was not consistent with the least-cost expansion path and the private sector required high rates of return.

• The focus on production rather than efficient distribution put the public sector in the position of retaining that activity in which it was least effective and restricting the private sector from performing the customer focused activities (distribution and supply) where it had real expertise. At the same time, it isolated the private sector from the market through a combination of regulated pricing and guarantees against commercial risks.


Philippines IPP Contracts

Reserve Margin is about 155%

Estimated Growth – 9.2%

Actual Growth – 3%


PPA Provisions

• The take-or-pay provisions ensure that the IPP proponents are paid up to the level of the minimum energy off-take (MEOT) whether the government utility was able to sell the power or not.

• IPP liabilities estimates up to the remaining terms of the contracts is in-between $6 - $ 8B in net present value. The buy-out figure of $11.8 B is gross since the Government can turn around and sell the capacity to another party.

• In 1992, the GDP was US$52 billion. PPA buyout in total would be 21% of GDP.


Effects of PPA Program

• The effects of the PPA capacity charges were exacerbated by the structure and implementation of the IPP program. The rapid build-out of IPPs during the 1990s meant that with the impact of the Asian financial crisis in 1998, the cost of electricity began to explode dramatically due to a combination of:

the high fixed cost of the IPPs (capacity payments or minimum offtake) and

the escalating foreign exchange liability stemming from deep reliance on foreign capital.

• The controversial “PPA” pass-through mechanism began climbing rapidly with the crisis, eventually becoming larger than the base rate itself.


Exchange Rates

Depreciation in exchange rates of about 70% caused increases in capacity charges


Risk Mitigation and Purchasing Power Parity

• Purchasing Power Parity

Change in exchange rate (versus USD)

Current exchange rate x (1+local inflation)/(1+US$ inflation)

How purchasing power parity mitigates risk

In theory people in the country are willing to pay higher nominal prices because of inflation and the net cash flow for the project should be the same

For example, if the inflation rate increases to 20%, the exchange rate should reflect depreciation in the currency of 20%.

Problems with purchasing power parity assumption

Large devaluations can occur without inflation rate changes

For example, the East Asian Crisis of 1997


Example of Purchasing Power Parity and Inflation


Index of Exchange Rate and Purchasing Power


Result – High Power Rates

• Exceptionally high power rates were cited as one reason why Intel Philippines, one of the country's biggest foreign investors and largest employers, with over 5,000 workers, plans to close down its Philippine operations and divert the company's investments to lower-cost Vietnam and Malaysia. A recent government survey showed that the high cost of electricity is one of the main reasons why foreign investors are reluctant to locate their businesses in the Philippines.

• According to the Heads of ASEAN Power Utilities/Authorities, a consultative group attached to the 10-member Association of Southeast Asian Nations, the average cost of electricity in the Philippines last year was 17.5 US cents per kilowatt-hour (kWh). That is more than three times the 5.38 per kWh cost in Vietnam, and is markedly higher then the 6.77 per kWh cost in Indonesia, 7.67 per kWh in Malaysia and 8.50 per kWh in Thailand. Even high-cost Singapore recorded cheaper power rates at 13.07 per kWh.


High Power Rates (Excluding Europe)


Philippines – Contract Review

• The process began with a 2001 electricity sector reform law (“EPIRA”) that required the appointment of an inter-agency commission (“IAC”) to review the IPP contracts, which by 2001 had become politically and economically vulnerable.

• The law also mandated the unbundling of electricity rates in consumer bills. This seemingly innocuous measure allowed Filipino citizens to see for the first time the precise origins of the costs that created some of the highest electricity rates in Asia.

What they saw was that the power purchase adjustment that financed the state utility’s IPP obligations was almost equal to the cost of the actual electricity consumed.


Philippines – Review of Contracts

• The IAC Review covered a total of 35 projects—all of Napocor’s operating contracts with IPPs. Of these, six were cleared, and the other 29 contracts were found to have issues of various kinds and were targeted for renegotiation.

• Upon completing the review, the IAC handed responsibility for implementing its findings to the Power Sector Assets and Liabilities Management Corporation (“PSALM”).

First, IPPs would bear cost or fee reductions that were not contrary to the terms of the original contract—most commonly the project companies made a collateral agreement not to nominate the full 105% or 110% that the contract allowed, or clarified ambiguous terms in a manner advantageous to the government.

Second, PSALM also considered a negotiated buy-out when the sponsor firms were interested in exiting the project.

Operation Phase – Revenue Risks and Price Volatility and the Case of AES Drax


Convincing Yourself That Unrealistic Optimistic Forecasts Will Occur – Firehouse Effect

• It seems obvious that the base case should represent likely comments rather than optimistic or best case estimates. However, models often represent optimistic rather than likely outcomes. The Firehouse effect – Fireman with too much time agree on many things that an outside, impartial observer would find ludicrous.

• Examples:

LBO’s: Some transactions were based on assumptions that companies could achieve levels of performance – revenue growth, operating margins, capital utilization – never before achieved. Buyers had no concrete plans.

Yet as the number of participants in the hot market increased, discipline declined. The swelling ranks of LBO firms bid up prices for takeover prospects encouraged by investment bankers, who stood to reap large advisory fees, as well as with the help of commercial bankers, who were willing to support aggressive financing plans.

S&P

Financial projections …are probably inherently skewed toward successful results...hiding the true technical and operating risks inherent in many projects..."


Don’t Ignore Basic Supply and Demand

• Investors and bankers did not account for the obvious prospective oversupply of homes in their analyses. This surplus of residential homes could be verified by a simple drive around sprawling suburban areas of American cities where it was apparent that supply was increasing much faster than the overall population.

Merchant Power in U.S.

• In many project finance cases where the same mistake has been made. For example, there was a massive increase in supply in the Telecommunications industry and the merchant power industry that resulted in a very high default rate.

• Estimated $100 Billion Loss in Merchant Markets

• .


Debt to Income versus Debt to Capital

• Part of the problem was relying on debt to the value of assets rather than on debt to income. The chart below shows that the level of debt relative to aggregate income was dramatically increasing.

• The same mistake has been made in project finance where a 20%-30% equity buffer gives a bank comfort that equity investment comes after debt investment.

• The second chart shows that the housing as measured by cumulative starts has increased by about 40% more than population.

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Index of Housing Growth and Population Growth

Population Index

Housing Index


Ignoring Economics and Long-Run Marginal Cost when Evaluating Prices

• Loans were granted on the presumption that housing prices would follow historic trends and continue to increase. The most fundamental of economic principles dictate that prices eventually move to long-run marginal cost, or the cost of building a new home. As a corollary, economics suggests that prices can move to short-run marginal when surplus capacity exists. The graph of median housing prices in the U.S. shown below illustrates how the basic economic principles were ignored.

• .

• .

AES Drax and UK Merchants

Declines in prices were not predicted in merchant electricity markets after increases in supply. Losses were estimated to be $100 billion. In the U.K. changes in the market structure and increased supply pushed prices to marginal cost.

UK Annual Electricity Prices

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The U.K. Market

• The deregulation process started in 1990, after the UK Electricity Act signed in 1988.

• Central Electricity Generating Board was, until 1990, responsible for the generation and transmission of electricity. After market opening, generation is carried over by

National Power, and PowerGen (fossil fuel generators)

British Energy and Magnox (nuclear)

Eastern group, and a good number of independent generators recently created.

Scottish generation companies and Electricite de France are in charge of imports into England and Wales.

• Total generation capacity is 70GwH.

• Low voltage transmission is done through 12 companies (Regional Electricity Companies, or RECs). High voltage transmission is done by the National Grid Company.

• Any approved generator can generate into the grid and contract through the transmission companies delivery to retailers.


UK Electricity (2)

• Prices are fixed through an auction mechanism, where each generator can submit offers for prices for different leads, with additional information such as operational restrictions, for each half-hour period for the day-after. The market operator performs a demand forecast as a function of bids, and uses a process matching bids and offers, which results in a System Marginal Price, and the schedule for the next day. The final price is revised one month later, and gives rise to additio0nal charges or rebates.

• System Marginal Price (SMP) is the largest price reached in the auction process.


Contract versus Commodity Price

• Risk analysis has similarities in contract versus non-contract transactions

Similarities

Need to assess economic viability in either case because of incentives to abrogate contract if the plant is uneconomic

Some suggest that contracts are not a good idea because of long-term problems.

Differences

Must assess the credit quality of the off-taker

Small risks become large in transaction with many contracts

Heat rate degradation Plant availability Contract penalties Interest rate changes


Merchant Plant Activity

• “…in the US, private companies that own merchant plants have lost of more than $100 billion in market capitalization.”

• Banks are “now highly reluctant to take merchant risk of any kind… and they are skeptical about long-term purchase or tolling contracts that in any way are considered to be out of the money.”

• “Merchants will have to redesign their business models. Those players that have 80-90 percent of their capital in the form of debt won't survive. The ratings agencies have said that such debt-to-capital ratios must be in the 50-50 range to earn investment grade status so that the cost of borrowing is reasonable.”

• The merchant plant activity has been very high.

New Merchant Capacity in Database

2,075 1,335 1,229

3,5804,869

2,494

5,136

9,783

13,924

29,513

23,942

-

5,000.00

10,000.00

15,000.00

20,000.00

25,000.00

30,000.00

35,000.00

1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003

MW


Background on UK Market

• The United Kingdom de-regulated its power system before any country in Continental Europe, North America or Asia in the late 1980’s after parliament passed the Electricity Act of 1989. In the initial years after deregulation, prices to consumers fell by about 30% and electric industries in other countries began to follow the lead of Britain.

• Virtually all of the formerly government owned generating capacity was divided into three companies, two of which – National Power and PowerGen – owned power plants that were privatized, while the third was a government owned company that controlled nuclear stations.

• Prices were set through a bidding process along with an administrative uplift that was intended to compensate for capacity that was available but not used. Since there were only two firms in the market, some argued that prices did not reflect marginal cost but rather were set in an ologopolistic manner

•


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1990/1 1992/3 1994/5 1996/7 1998/9 2000/1

Transport UpliftUpliftCapacity PaymentSMP

£/MWh

(99/00)

Market Based Prices in the UK – Not too Much Volatility


Financing of Merchant Plants

• If the structure of the market remained static and demand grew at a similar rate to new capacity additions, the historic stable prices and low volatility would imply that investments could support a relatively high level of debt and implicitly have a low cost of capital.

• Many of the new plants that were built were able to achieve high levels of debt financing.


Economics of Combined Cycle Under Existing Prices

• Because of the innovations in the technical efficiency of combined cycle gas plants, profit could be realized from selling power at the ologopolistic prices. The table below shows that power plants could be constructed profitably at historic prices realized in the past of ₤22.5/MWH to ₤26.5/MWH and achieve more than a 15% return as long as debt financing was available.

Equity Price 26.50 Equity Price 24.50 Equity Price 22.50

Debt Pct Equity IRR Debt Pct Equity IRR Debt Pct Equity IRR0.0% 11.6% 0.0% 10.3% 0.0% 9.0%

19.2% 12.6% 19.2% 11.2% 19.2% 9.7%37.3% 14.1% 37.3% 12.4% 37.3% 10.6%54.5% 16.4% 54.5% 14.3% 54.5% 12.1%62.8% 18.1% 62.8% 15.7% 62.8% 13.1%70.8% 20.7% 70.8% 17.8% 70.8% 14.7%78.7% 24.9% 78.7% 21.2% 78.7% 17.2%86.4% 33.5% 86.4% 28.1% 86.4% 22.3%93.9% 69.6% 93.9% 56.8% 93.9% 42.6%


Surplus Capacity from New Construction

• The underlying assumption of stable prices depended on limited surplus capacity and continuation of the ologopolistic market structure. Neither of these assumptions were reasonable.

First, capacity was being added much faster than demand as demonstrated by the following table. The increase in capacity was due to the fact that natural gas combined cycle facilities could operate profitability at pricing levels that historically existed in the market.

The private power plants that were developed increased the U.K. reserve margin (the amount of capacity divided by the peak load) to more than 25%, far above the typical reserve margin criteria used in the industry of 15%.

Natural Gas and Conventional 18.5Nuclear 1.2Total 19.7

Demand Growth 2.7

UK Demand and Supply GW


Case of AES Drax

• Drax, a 3,960 MW station commissioned in two parts in 1974 and 1986, is the largest coal plant in Europe.

• In mid 1999, the plant was purchased by AES from National Power (renamed Innogy) for £1,963 million. This amounted to $758/kW – higher than NGCC plants which dispatched ahead of the coal plant.

(the plant sale was driven by the government ordered divestitures associated with reducing market concentration.)

• To finance the acquisition, AES injected £224 million of its own equity, resulting in a debt to capital ratio of about 90%. The debt consisted of bonds which initially carried an investment grade rating of Baa2 by Moody’s. The debt term was 15 years with a spread of 165 basis points and 90 basis points fee.

GBP Millions PercentAES DRAX Holdings Limited Bonds 400.00 18.2%AES DRAX Energy Senior Notes 267.00 12.1%In Power Bank Facility 1,308.00 59.5%Equity 224.00 10.2%Total Capitalization 2,199.00 100.0%


AES Drax Continued

• Drax Debt was Investment Grade:

S&P highlighted uncertainty surrounding generation prices as a concern, but stated that one of the deal’s strengths was its 15 year hedging agreement: “The hedging agreement underpins a large portion of the debt service during the first seven years of the contract thereby reducing merchant risk.”

• Other Transactions were more aggressive than Drax

Often 80% Debt Financing

Long Tenors

• TXU Defaulted on a payment to DRAX

TXU lost One Million core customers

Contract was Way Out of the Money

S&P estimates that contracts are out of the money by between GBP 500 million and GBP 1.3 billion

• Bid to buy back DRAX for 1 Billion GBP (plant was sold by same company for 1.87 GBP)


Analysis of Market Prices by Experts and Rating Agencies

• For example, according to a Moody’s pre-sale report issued in May 2000 on the AES Drax plant, “We do not expect … a sudden and marked fall in wholesale electricity prices in England and Wales.”


AES Time Line

• “The initial assumptions on which the AES Drax companies relied when making the original investment assumed that it would have the protection of its long-term Hedging Contract with TXU Europe and that electricity prices would remain at a certain level. Since we acquired the Drax Power Station electricity prices have declined on average by approximately 40% and in November 2002 our Hedging Contract with TXU Europe was terminated and the TXU group entered into administration.” Drax Annual Report


Political Pressure over Market Concentration

• The precept that the market would remain ologopolistic was also not sustainable.

• Moody’s: “the dissatisfaction with the Pool relates essentially to the scope for manipulation that generators with significant market power enjoy under the Pool’s complex rules.”

• The ability to exercise market power is demonstrated on the graph below which shows that market clearing prices were generally higher than the marginal cost of running plants before markets were reformed in 2000.

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Reforms and Market Concentration in UK 1990 and 2000

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• The problems for banks exposed the sector boil down to one thing: overcapacity. There is calculated to be roughly 22% overcapacity and it is therefore not surprising that prices have slumped so spectacularly. Prices are now around 17 to 18 per MWH, down 40% from levels prior to NETA’s introduction.

• The atomization of the generation sector was a function of new entrants and forced sales and pricing power was lost before NETA was introduced.

• .

After Reforms Before Reforms


Break-up of Coal Fired Generation


Profits of Participants


Electricity Prices

Although NETA has impacted electricity prices, NETA has not generally been considered to be the principal underlying cause behind the decline in UK power prices; this is more likely due to the over-capacity in the UK generation market, increased competition and fragmentation of the market.

AES Drax Annual Report

UK Annual Electricity Prices

23.024.0

27.0

29.0

24.0

21.022.0

26.025.0

20.019.0

17.015.5

10

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1990 1991 1992 1993 1994 1995 1996 1997 1999 2000 2001 2002 2003

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P/M

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Prices can move to short-run marginal cost


AES Drax Bond Rating Time Line

• Rating Action 25 JUL 2000 MOODY'S ASSIGNS (P)Baa3 RATING TO AES DRAX HOLDINGS LIMITED AND (P) Ba2 TO AES DRAX ENERGY LIMITED PROJECT FINANCE BONDS

• Rating Action 20 APR 2001 MOODY'S CONFIRMS AES DRAX'S DEBT RATINGS; CHANGES OUTLOOK TO NEGATIVE

• Rating Action 7 DEC 2001 MOODY'S DOWNGRADES AES DRAX HOLDINGS Ltd BONDS AND INPOWER Ltd BANK LOAN FROM Baa3 TO Ba1, AND AES DRAX ENERGY Ltd NOTES FROM Ba2 TO B1

• Rating Action 1 MAR 2002 MOODY'S PUTS AES DRAX ENERGY LTD HIGH YIELD NOTES RATED B1 ON REVIEW FOR DOWNGRADE

• Rating Action 13 AUG 2002 MOODY'S PLACES Ba1 DEBT RATINGS OF AES DRAX HOLDINGS LTD AND INPOWER LTD, AND B1 RATINGS OF AES DRAX ENERGY LTD ON REVIEW FOR DOWNGRADE

• Rating Action 21 AUG 2002 MOODY'S DOWNGRADES DEBT RATINGS OF AES DRAX HOLDINGS LtD, INPOWER LtD, AND AES DRAX ENERGY LtD

• Rating Action 14 OCT 2002 MOODY’S DOWNGRADES DEBT RATINGS OF INPOWER LTD AND AES DRAX HOLDINGS LTD TO Caa1, AND DEBT RATINGS OF AES DRAX ENERGY LTD TO Ca. ALL RATINGS ARE LEFT ON REVIEW FOR FURTHER DOWNGRADE

• Rating Action 7 NOV 2002 MOODY'S DOWNGRADES DEBT RATINGS OF INPOWER LTD AND AES DRAX HOLDINGS LTD TO Caa2, AND DEBT RATINGS OF AES DRAX ENERGY LTD TO C

• Rating Action 19 JAN 2004 MOODY’S WITHDRAWS RATINGS ON DRAX POWER PROJECT


AES Stock Price

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AES: Beta 1.81 Stock Volatiltiy 46.2% S&P Volatility 11.4%

AES

S&P Index


Drax Case


Contract Viability

• Project finance is a long-term business and long-term contracts that give advantage to one side are vulnerable

It is impossible to provide in advance for every event that may affect a project contract in the future.

An aggrieved party will take advantage of any flaw to get out of an onerous obligation.

• The underlying contract must make economic sense to both parties.


Commodity Prices Merchant Electricity Plant Financing in UK

• Before Financial Meltdown

Leverage -- 75-80%

Debt tenor -- 20 years

Credit spread -- 150-200 basis points

Equity IRR – 13%-15%

• After Meltdown

Leverage 50%

Debt tenor 10 Years

Credit spread 250 basis points

Equity IRR – 16%


Crash of Merchant Power



Merchant Power Return Assumptions


Case Study of Unsustainable Contacts or Inappropriate Political Interference – Dabol


Introduction from Harvard Case Study

• This project is new-it's definitely a pioneer and as a result the policies and approvals are still evolving. But precisely because of its pioneer status and government interest at the top, many in India feel that this project has moved quite rapidly.

• Judging from our Philippines experience, the first project through certainly paves the way. The first one is like a "baptism" for the country-after that you can use boilerplate documents; people are educated about the process .... The fact is that we've already invested $13.2 million with Bechtel and GE on this project, so we're very committed .... If we didn't believe in this project and the importance of it to India, we wouldn't be doing it. We believe in the goal of cheap power in abundance for India ....

• The stakes are high for India too. By having three large American companies involved, issues of national pride and the sincerity of economic reform naturally arise .... This project is really important for India. It symbolizes that real change has occurred, that they can get it done. Foreign investment will follow as will greater economic growth. This is a bellwether project. Other projects are being held up to see what happens here. If it can't happen here-with the most respectable sponsors, with independent fuel supply, and the most financially stable state-can it happen anywhere in India?


Contract Risk and Dahbol

• Investment in a $3 billion, 10-year liquefied natural gas power plant development project, was the largest development project and the single largest direct foreign investment in India’s history.

• Begun in 1992, the Dabhol power plant near India’s financial capital of Bombay in Maharashtra state was to have gone online by 1997. It was supposed to supply energy-hungry India with more than 2,000 megawatts of electricity, about one-fifth the new energy needed by India each year.

• In a joint venture with U.S. companies General Electric and Bechtel, Enron created an Indian subsidiary, Dabhol Power Co. DPC, which was 65 percent owned by Enron, was to build the power plant. Enron was to develop and operate the plant. Bechtel was to design and construct it, with GE supplying the equipment.

• Enron brokered a deal with Qatar to provide the Dabhol plant 2.5 million tons of liquefied natural gas per year for 25 years, starting in 1997.


Governmentof Maharashtra

Lending Banks

DabholPowerCorp

MaharashtraState

Electricity Board

FullGuarantee

PPA

LoanAgreement

FX Availability

ReserveBank of

India

Ministryof Power

ComfortLetter

Governmentof India

Limitedguarantee

Domestic(Indian)

Financial Institutions

(Banks)

US Exim

Political RiskGuarantee

StateSupport

Agreement

Dabhol Structure


Dabhol Plant

• Project Included

Largest Independent Power Producer – 695 MW + 1,320 MW or 2,015 MW. 22.4% of Capacity of Maharashtra

LNG Re-gasification Plant

LNG Tanker to access supplies in Qatar

85% Debt and 15% Equity

Equity

Enron 65%

Bechtel

GE

Enron Net Income $465 Million

Enron Assets (1993): $12 Billion

Enron Equity (1993): $3.5 Billion


Dabhol Plant Cost

• First phase

• 695 MW plant

• Cost of $920 M

• Construction began 1995, project to come on-line in 1997

• Cost $1323/kW

• Comparable costs $650/kw

• Second phase

• 1,320 MW capacity

• LNG re-gasification plant, storage, and harbor facilities to be built.

• Construction to begin after phase 1 completed

• Cost of $1.88 B

• Cost per $1,466/kW


Cost of New Plants


Comparative Plants


Dabhol Timeline

• May-June, 1992: India invites Enron Corp to explore the possibility of building a large power plant in Maharashtra.

• June 20, 1992: Initial memorandum of understanding signed between Enron and Maharashtra government for a plant with capacity of 2000-2,400 MW. The Maharashtra State Electricity Board is expected to pick up a 10 per cent stake.

• Jan 2, 1993: The Foreign Investment Promotion Board clears proposal for a 1,920 MW plant, expandable to 2,550 MW.

• Dec 8, 1993: The power purchase agreement signed between Dabhol Power Company and MSEB for a 2,015 MW project to be implemented in two phases.

• March-June, 1995: Following state elections, a new Maharashtra government, headed by the Shiv Sena, scraps the project, alleging corruption and high costs.

• Nov 1995: Project re-negotiated with a final capacity of 2,184 MW. MSEB's stake is upped to 30 per cent -- 15 per cent in the first phase, and a further 15 per cent upon completion of the project.

• May, 1996: India extends counter-guarantee to the project, under which the federal government promises to cover any defaults by the state utility.

• May, 1999: Phase one of the project with a capacity of 740 MW begins operating.

• June-Oct 2000: Maharashtra government allies demand scrapping the project because of the cost of the power it produces.

• Oct, 2000: MSEB defaults on its October payment to DPC.

• Dec, 2000: Maharashtra state announces plan to review the project, stating that the tariff is too high.

• Feb, 2001: The Credit Rating Information Services of India Ltd cuts ratings on bonds issued by Maharashtra government due to defaults on payments owed to Dabhol. Enron invokes the Union government guarantee.

• April, 2001: Enron issues a notice of arbitration to the Indian government to collect on the December bill of Rs 1.02 billion.

• April, 2001: Enron invokes the political force majeure clause in its contract with MSEB, stating that unfavorable political conditions have prevented it from fulfilling contractual obligations.

• April 23, 2001: DPC and its lenders meet in London to discuss the payments issue. Enron seeks lenders' permission to issue a notice of termination.

• April 25 2001: The board of Dabhol Power Company authorizes management to terminate the contract any time it chooses.


Structure of Dabhol PPA Contract

• PPA Contracts can transfer all demand and fuel cost risk. The Dabhol PPA contract is illustrated below


Dahbol PPA Tariffs

• The Tariffs were about 7 U.S. cents per kWh increasing to 11 cents over 20 years.

• Comparable plants in the US were selling power at 3-4 cents per kWh.

• Initially IRR was 26.52%

• Officially the ROE allowed was up to 16%

• The contract was indexed to USD


Comparative Plant Costs for Natural Gas


Enron’s Economic Rational Underlying the Transaction


Transparency


Ways to Get Around the Contract

• A common (though unverified) account of one episode in the Dabhol controversy has Maharashtra officials reducing dispatch gradually until the plant shut down, then requesting full dispatch in three hours from a cold start. The PPA required a three hour horizon for full availability; project management protested that this provision did not contemplate ramping up from a cold start (a requirement almost any power plant would have trouble with).

• Despite protests to the contrary (and the fact that a court would likely find such a failure immaterial), the inability to comply with the requirement eroded the leverage of the Dabhol sponsors in the dispute.


Dabhol Issues

• Enron made the headlines over its stance on a massive power blackout that threw more than 200 million people into darkness in northern India. Enron demanded three times the normal rate for supplying power from its Dabhol plant to re-start the stalled electricity stations. Electricity was finally sourced from the government's own units.

• Indian economists calculated that the after-tax rate of return would actually be 32 percent, about three times the average rate in the US;

• Enron paid $20 million as "educational gifts". Critics consider these payments to be bribes to clear the project;


Contract Off-taker Risk and Dahbol

• Endless disputes over prices and terms of the deal turned the venture into a symbol of what can go wrong in large-scale development projects when cultures collide.

• In April 1993, a World Bank analysis questioned the project's economic viability, citing the high cost of importing and using liquefied natural gas relative to other domestic sources of fuels. Because of those findings, the World Bank refused to provide funds for the project.

• "Price is becoming a sticky issue," the Financial Times reported. "Indian officials see the price as very high compared to domestic gas and imported and indigenous alternative fuels."

• Protesters took to the streets to support demands for changes in the plant's design and -- more broadly -- to oppose the Indian government’s economic liberalization policies. Social activists, lawyers, villagers and farmers banded together in groups opposed to the Enron project.

• The devaluation meant that Dabhol's energy prices would soar to between two and five times the average price in the area.


Problems with PPA’s in Asia

• Some PPA’s featured high prices for a variety of reasons and became very unpopular (Pakistan, India, Indonesia, Philippines)

Exchange rate de-valuation

High capacity prices

Over-capacity

High capital costs

• IPP’s with long term PPA’s have added a substantial stock of generators to developing countries (Pakistan, the Philippines, India, Malaysia, Thailand, Indonesia)

Current Problems

No access to gas from Iran

Nuclear not feasible


Vemagiri Power Project

Capacity of 388.5 MW

15 year PPA for 370 MW

• Natural gas fired (1x1) GE 9FA CCGT

1.64 mmscmd of gas allocated on firm basis

• Project cost US$ 238 mn, project cost is the lowest for any gas based plant constructed in India

• Estimated first year tariff of Rs. 1.94/ kWh (approx 4 cents)

Fixed Charge - Rs. 1.01/kWh

Variable Charge - Rs. 0.93/kWh

VPGL - VemagiriVPGL -

Vemagiri


Dabhol Postscript

• The power plant Phase I which was re-named Ratnagiri Gas and Power Pvt Ltd (RGPL) started operation in May 2006, after a hiatus of over 5 years.

• The plant runs on naphtha supply and LNG.

• GE and Bechtel were fully compensated for their investment

• Reduced Enron interest.

Other Countries


Indonesia

• Indonesia, where almost all twenty-seven IPPs had as a partner a member or associate of the Suharto family. These partners were often “allocated” by the ruling family as a kind of prerequisite to securing a project, but also offered political cover and access in a country where such assets came at a premium.

• With the end of the Suharto regime shortly after the financial crisis had shocked the country’s economy (and created stress for IPPs), the new government faced decisions about private infrastructure contracts that were becoming increasingly expensive as the local currency plummeted.


Malaysia

• It also appears that these practices have resulted in prices that are high and profits that are large for the initial lPPs. Prices have not been officially disclosed, but have been reported to be as high as 15-16 cents per kWh (the IPP price may include required transmission and other non-generation items), compared to a wholesale generation cost of about eight cents per kWh from TNB. In response, the government has not tried to renegotiate the pricing in the IPP contracts (these costs are still passed through to TNB and to customers). However, it has recently required all IPPs and TNB to contribute one percent of their revenues to an Electricity Trust Fund that is used for electrification, power sector research and development, training and education, and consulting studies in renewable energy.


Foreign Exchange Rate Risk

• Recent experiences in the power sector in emerging markets have dramatically illustrated how foreign exchange devaluations can undermine a project's competitive position. Many cross-border projects, particularly infrastructure projects, have revenues denominated in local currencies but have debt obligations in a different currency. The mismatch creates two potential risks.

If the currency exposure is un-hedged, a project could likely experience a cash shortfall sufficient to cause a default if a sudden and severe devaluation occurs.

The second risk occurs when project revenues are contractually indexed so as to pass on the exchange rate risk to off-takers. In this second instance, lenders run the risk that a massive devaluation will make the project's off-take so expensive in the local currency that off-takers cannot afford to purchase the output. Hence, the risk of contract abrogation may soar.


• The limitations of indexing, however, can do little to offset the threat posed by sudden and severe depreciation.

• Standard & Poor's will look to severe scenarios to test a project's robustness in speculative-grade sovereigns or in any other sovereign where the exchange rate regime may be unsustainable. The question is how much devaluation be assumed in the scenarios.

Evaluating Foreign Exchange Rate Risk


Example of Catastrophic Devaluation – PT Pation

• An offtaker or contractor authority who is taking exchange rate risk by indexing the tariff against a foreign currency probably cannot pass on the this indexation after a major devaluation to the local end-users of the product.

• The effect was seen in the Asian crisis of 1997 and in Turkey in 2001, where power purchase contracts under long-term PPA’s had linked tariffs to the foreign currencies. When the power purchasers home currencies suffered huge devaluations, they had obligations under the PPA to increase the tariff and make increased payments.

• These adjustments were not economically or politically realistic.

• Indexation did not work; must evaluate macro-economic data.

• OPIC has debt facility to deal with the problem in Brazil. Comes into play with devaluation and intended to pay back from purchasing power parity notion and the eventual increase in prices.


Catastrophic Foreign Exchange Risk (S&P 2001)


Brazil – Power Crisis of 2001-2002

• In the 1980’s, the monopolistic, state-owned organization of the power market faltered; many power companies were unable to meet investment needs even with state support and concessionary finance. The financial situation of power companies deteriorated as a result of increasing capital costs, low tariffs and over-capacity, as demand growth was lower than anticipated

• From May 2001-March 2002 blackouts were avoided only with a strict rationing regime consisting of a set of penalties and incentives that reduced consumption by 20%. The effect was to essentially cut disco revenues by 20%. In this way, the crisis furthered troubles for private distribution companies, many of which were already fragile after the 1999 devaluation of the Real. Even after the rationing ended the habit of conservation persisted and consumption remained low. Only five years later, is consumption recovering to 2000 levels, in 2005.


Brazil

• All the energy transactions in the Regulated Market are carried out through auctions that are conducted by Aneel in accordance with MME rules. EPE aggregates and reviews the future electricity consumption estimated by the distribution companies. Assuming its estimated future power consumption, EPE provides a list of power plants that can eventually balance supply and demand in the regulated market. Aneel then auctions that list, having in mind its obligation to keep tariffs at the lowest possible prices.

• In auctions for new capacity, investors will bid on a concession to provide a certain amount of “assured energy” to the regulated market. Assured energy is a number determined by government planners that reflects expected hydrological conditions. For a hydro plant, assured energy is the amount of energy that can be produced by the plant in the worst hydrological conditions, given the integrated management of reservoirs. For a thermal plant, assured energy is the amount of electricity expected to be dispatched, given hydrological forecasts. For both types of plants, assured energy is the energy that can be sold under long term contract—whether to the free or regulated market

Midwest Peaking Plants


Standard and Poors and Housing Price Assumptions – Comparison with Iriduim Assumptions

According to one story an investor called the rating agency Standard & Poor’s and asked what would happen to default rates if real estate prices fell.

“The man at S&P couldn’t say; its model for home prices had no ability to accept a negative number. ‘They were just assuming home prices would keep going up…’”

0

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7,000,000

8,000,000

9,000,000

1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Projected and Actual Revenues for Iridium

Actual

Salomon Smith BarneyCredit Suisse/First BostonLehman Brothers

Merrill Lynch

CIBC Oppenheimer


The summer of 98

• Electricity prices hover around the $50 MWh.

• In the summer of 98, during an unusually hot week, a generator broke down in the Northwest US

• The power shortage that resulted increased prices to a historical high of $7,000 MWh, with rumors that in peripheral markets prices rose to $10,000 MWh.

• In money markets, this would be comparable to the DJI rising to 2,000,000, or dropping to 50 pts, in a matter of a few days. While this is an absurd financial analogy, its mathematical implications cannot be ignored.


Resources and Contacts

• My contacts

Ed Bodmer

Phone: +001-630-886-2754

E-mail: [email protected]

• Other Sources

Financial Library – project finance case studies including Eurotunnel and Dabhol

Financial Library – Monte Carlo simulation analysis

case studies in electric power

Documents

losseselectricity case

electricity market

electricity sector

case of segba

electricity output

electricity provision

electricity restructuring

electricity supply industry