Case Studies in Electric Power
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
Electricity Case Studies
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2
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.
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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.
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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.
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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
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Plant Availability
•
Plant Availability has dramatically improved from about 60% in 19931994 to 75-80%
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New Argentinean Plants in Database
•
Argentina demonstrates that a developing country can attract capacity with
reasonable financing terms
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New Capacity in Argentina
•
The current reserve margin in Argentina is 89% due to merchant capacity
additions
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Prices in Argentinean Market
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Un-served Energy in Argentina and Losses
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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).
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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
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Capacity Up-Lift in Argentina
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Market Structure - Capacity Pricing Using Up-Lifts
•
Generators whose plants are scheduled for dispatched one day in advance or
who are actually dispatched receive a pre-determined capacity payment for hours
falling outside low periods.
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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
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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
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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
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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
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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.
Electricity Case Studies
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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.
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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.
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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 deregulated 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.
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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
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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.
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Outages Caused by the California Crisis
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Other Crisis Impacts
• Rolling Blackouts
• PG&E Bankruptcy
• Edison Electric Near Bankruptcy
• State Budgetary Surplus Eliminated
• Governor Arnold
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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
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•
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.
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•
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.
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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.
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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.
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.
Sub-Prime versus Other Spreads
2000
California Orgeon Border Prices
160
1600
140
1400
120
Basis Spreads
1200
A-rated
1000
• .
BBB-rated
BB-rated
800
Sub-Prime
140.8
139.0
100
80
60
600
40
400
20
18.5
19.3
1996
1997
28.0
31.6
1998
1999
26.1
-
200
Electricity Case Studies
2000
2001
6/3/2008
5/3/2008
4/3/2008
3/3/2008
2/3/2008
1/3/2008
12/3/2007
11/3/2007
9/3/2007
10/3/2007
8/3/2007
7/3/2007
6/3/2007
5/3/2007
4/3/2007
3/3/2007
2/3/2007
1/3/2007
12/3/2006
11/3/2006
9/3/2006
10/3/2006
8/3/2006
7/3/2006
6/3/2006
5/3/2006
4/3/2006
3/3/2006
2/3/2006
0
1/3/2006
• .
$/MWH
1800
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2002
Oil Price Errors from EIA
Actual Annual Oil Prices and Prices Forecast by EIA
160.00
N
o
140.00
m
i
n p 120.00
a e
l r 100.00
Actual
1998 Forecast
1999 Forecast
2000 Forecast
2001 Forecast
2002 Forecast
2003 Forecast
2004 Forecast
O B
i a
l r
r
P e
r l
i
c
e
s
80.00
2005 Forecast
2006 Forecast
60.00
2007 Forecast
2008 Forecast
40.00
2009 Forecast
2010 Forecast
20.00
0.00
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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
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Supply and Demand

Demand for Electricity Increased a Bit More than Expected
Healthy California Economy
Growth of Electricity-intensive Products
Decline in the Retail Price of Electricity

Supply of Electricity Did Not Increase
Until Recently No New Generating Plants on Line
 But Many in pipeline
 Slow Regulatory Approval Process
Hydro Supplies from Pacific Northwest and Southwest Decreased

Costs of Electricity Generation Increased
Prices of Natural Gas increased
Prices of NOx Prices skyrocketed under RECLAIM project
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Percent of Total Generation
Figure 2
Western Generation Mix Options
(% of Installed MW Capacity)
100%
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
0
20
Nuclear/Other
Geothermal
Wind
Coal
Gas
Hydro
0
E
ng
i
t
s
xi
2
4
00
p
Ex
e
e
ct
d
1
20
0
s
Ga
1
20
0
h
Ot
e
h
rt
an
s
ga
Source: Western Governors’ Association,
Conceptual Plans for Electricity Transmission
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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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Supply and Demand During a Typical Day
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Trends in Electricity Demand
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Supply and Peak Demand
Projected Monthly Peak Load, 2001
(MW)
60,000
50,000
40,000
Load+
Op. Res.
Load
30,000
20,000
10,000
0
APR
MAY
JUN
Gen Cap
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JUL
Dynamics
AUG
SEP
Imports
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Electricity Usage in California
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Forecast of Electricity Prices Before the California Crisis
The published analyses, including those done by the California
Energy Commission and those published through
the academic community all forecast relatively low wholesale
prices.
12
10
8
6
4
2.9
3.1
2.6
2.5
2.7
2.9
3.1
3.1 3.3
3.6
4.2
2
20
10
20
09
20
08
20
07
20
06
20
05
20
04
20
03
20
02
20
01
20
00
0
California Energy Commission “Market Clearing Prices… 2000-2010”, Feb. 2000, p. 6
Cautious Development Scenario, nominal dollars
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Actual Costs of Wholesale Power
30
27.1
26.8
25
10
20
8
15
6
10
7.4
4
5
11.5
12
10.7
2.9
3.1
1998
1999
2
0
1999
2000
2001
$40 BILLION MORE !!
Electricity Case Studies
0
2000
2001
ISO Control Area,
ISO Department of Market Analysis
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Price History
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Electricity Prices Relative to Natural Gas Prices
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Similar Problems in New Zealand
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Factors that Cause Volatility in Electricity Prices and
Electricity Costs
•
Volatility in Electricity Prices
 Demand Volatility (Higher or Lower Economic Growth)
 Hydro and Renewable Volatility
 Fuel Price Volatility
 Outage Volatility
•
Effect of Risks
 On Prices
 On Costs
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Western U.S. Supply Curve
250
Incremental Cost ($/MW)
200
Average Load
Peak Load
150
100
50
0
85200
95200
105200 115200 125200 135200 145200 155200 165200
Load (MW)
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Prices and Loads Before the Crisis
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Variability in Hydro from Fluctuation in Hydro
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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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Mountain Snowpack 2001 v.s. 2002
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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
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In-State Generation After Considering Reduced Imports
from Hydro Resources
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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
17 March 2016
Electricity Case Studies
www.edbodmer.com
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59
Lack of Demand Reduction
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San Diego Gas & Electric
Southern California Edison
Pacific 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.
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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.”
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Price Caps Established
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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.
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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.
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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.
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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.
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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.
Electricity Case Studies
March 16
69
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.
Electricity Case Studies
March 16
70
Prices versus Marginal Cost
Electricity Case Studies
March 16
71
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.
Electricity Case Studies
March 16
72
Units Off-Line During California Crisis
17 March 2016
Electricity Case Studies
www.edbodmer.com
March 16
73
73
Physical Withholding
Statewide Average Daily Forced or Scheduled Megawatts Off Line
Price volatility was
affected by plant
outages that were
in part driven by
problems with IPP
contracts
14,000
12,000
10,000
MW
•
16,000
8,000
6,000
4,000
2,000
Ja
nFe 99
bM 99
ar
A 99
pr
M -99
ay
Ju 99
n9
Ju 9
l
A -99
ug
Se 99
pO 99
ct
N 99
ov
D 99
ec
Ja 99
nFe 00
bM 00
ar
A 00
pr
M -00
ay
Ju 00
n0
Ju 0
l-0
A
ug 0
Se 00
pO 00
ct
N 00
ov
D 00
ec
Ja 00
nFe 01
bM 01
ar
A 01
pr
M -01
ay
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A -01
ug
-0
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0
•
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.
Electricity Case Studies
March 16
74
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.
Electricity Case Studies
March 16
75
•
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.
Electricity Case Studies
March 16
76
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 twothirds.
Electricity Case Studies
March 16
77
Exercise of Market Power in California Meltdown
• Market Power resulted in significant increases in prices
Electricity Case Studies
March 16
78
Prices did not Reflect Competitive Outcomes
Electricity Case Studies
March 16
79
Average California PX price and MC
PX price
Competitive Price
180.00
160.00
140.00
($/MWh)
120.00
100.00
80.00
60.00
40.00
20.00
0.00
Apr-98
Jul-98
Nov-98
Feb-99
May-99
Aug-99
Dec-99
Mar-00
Jun-00
Oct-00
March 16
80
Month
Electricity Case Studies
Jan-01
Kernel Regression of
Lerner Index vs. Capacity Ratio
May - December 1999
Cal
NE
PJM
1
0.9
0.8
(p-MC)/p
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
Residual Demand/ Capacity
Electricity Case Studies
March 16
81
1
Monopoly Rents Due to Market Power
Electricity Case Studies
March 16
82
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.
Electricity Case Studies
March 16
83
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.
Electricity Case Studies
March 16
84
Lessons Learned – California ISO
•
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
Electricity Case Studies
March 16
85
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.
Electricity Case Studies
March 16
86
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.
Electricity Case Studies
March 16
87
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
Electricity Case Studies
March 16
88
Implications for Market Analysis
•
Should Bilateral Contracts be Encouraged?
•
Should Retail Customer Choice be Limited to Create More Creditworthy Offtakers?
•
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?
Electricity Case Studies
March 16
89
Latest Photograph of Plant Under Construction
May 18,Subic
2001 Group
Electricity Case Studies
90
March 16
90
Philippine Power Market - Background
•
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
Electricity Case Studies
March 16
91
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
Electricity Case Studies
March 16
92
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 NPCgenerated electricity (US$0.0637/kWh), the inability of the
government to finance rapid expansion of the power sector
made private investment extremely attractive.
Electricity Case Studies
March 16
93
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.
Electricity Case Studies
March 16
94
Growth in Electricity Generation from EIA
Prediction was for
about 9% Growth
Electricity Case Studies
March 16
95
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.
Electricity Case Studies
March 16
96
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).
Electricity Case Studies
March 16
97
Philippines Contracts
Electricity Case Studies
March 16
98
Capacity was Added over Many Years
Electricity Case Studies
March 16
99
Additions of Capacity by Type
Electricity Case Studies
March 16
100
Diesel Added Early/Gas and Hydro Added Later
Electricity Case Studies
March 16
101
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.
Electricity Case Studies
March 16
102
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.
Electricity Case Studies
March 16
103
Comparative Plant Costs
Electricity Case Studies
March 16
104
Cost of Plants per kW
Electricity Case Studies
March 16
105
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.
Electricity Case Studies
March 16
106
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.
Electricity Case Studies
March 16
107
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.
Electricity Case Studies
March 16
108
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.
Electricity Case Studies
March 16
109
List of Projects and
PPA Terms
Electricity Case Studies
March 16
110
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
Electricity Case Studies
$21.6/kW/Month
March 16
111
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
Electricity Case Studies
March 16
112
Case Study - Funding
Enron - Subic Bay, Philippines
Philippines
Government
Performance
Undertaking
Napocor
Buyout
Rights
•Capacity Charge
•O&M Charge
•Energy Charge
PPA
Electricity Case Studies
Equip’t Cos.
Warranties
Fluor Daniel
15-year
BOT
Concession
Supply
Fuel Free
Ground
Lease
Enron Power
Operating Co.
EPC
Enron Power
Phils. Op’g Co.
Turnkey
Construction
Contract
O&M
Agreement
113MW
Subic
Power
Corp.
Completion
Guarantee
65%
Enron
Corp.
Enron Subic
Power Corp
Enron Power
Philippines Corp
35%
Insurances
Philippine
Investors
US$105 million, 15-year Notes
March 16
113
113 MW Diesel Generator Power Station
Subic Bay, Philippines
Sources of Funds:
Notes
$ 105 M
Subordinated Note
Contr. Of Shareholders
Working Capital
TOTAL
7
28
2
$ 142
Uses of Funds:
Turnkey Contractor
Bonus to Turnkey Contractor
Development and other related costs and Fees
$ 112 M
7
14
Pre operating, Start-up and Commissioning Costs
3
IDC
4
Working Capital
2
TOTAL
Electricity Case Studies
$ 142
March 16
114
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
Electricity Case Studies
115
March 16
115
Conclusion from Investor Perspective
In Conclusion:
 Attractive Return
 Well Structured Deal
 Solid Sponsors (Enron, NAPOCOR and the Philippine Government)
 Manageable Risks
 Minimum Take:
Electricity Case Studies
US$ 20 Million
March 16
116
Bond issue under rule 144 A
• BORROWER
• Amount
• Maturity
- Subic Power Corporation
- USD 105 million
- 15 years
• Payments of Principal & Interest are fully guaranteed by Enron Corporation until the
Facility Completion Date.
• Repayment
• Interest is accrued
•Interest base and Margin
Electricity Case Studies
- equal semi-annual Jun 28/Dec 28.
- 9 1/2 % p.a payable semi annual.
- US Treasuries 15 Y + 385 bp fixed rate
March 16
117
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.
Electricity Case Studies
March 16
118
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
Electricity Case Studies
March 16
119
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
Electricity Case Studies
March 16
120
Sensitivity Cases
What If
Base Case
Availability = 81%
Operating expenses
are 50% higher/yr
Interest Rate is 12%
Electricity Case Studies
Min
DSCR
1.39
1.25
1.19
Min
Interest
Cover
2.01
1.80
1.72
PV Loan
Cover
Ratio
1.53
1.36
1.23
Equity
IRR
(Post Tax)
19%
14%
9%
1.37
1.77
1.40
17%
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121
Adjusted Results
Electricity Case Studies
March 16
122
Other Assumptions
Electricity Case Studies
March 16
123
Case 2: Quezon Case
Electricity Case Studies
March 16
124
Quezon Sources and Uses
Electricity Case Studies
March 16
125
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.
Electricity Case Studies
March 16
126
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.
Electricity Case Studies
March 16
127
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
Electricity Case Studies
March 16
128
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.
Electricity Case Studies
March 16
129
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.
Electricity Case Studies
March 16
131
Philippines IPP Contracts
Reserve Margin is
about 155%
Estimated
Growth – 9.2%
Actual
Growth – 3%
Electricity Case Studies
March 16
132
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$52 billion. PPA buyout in total
would be 21% of GDP.
Electricity Case Studies
March 16
133
Effects of PPA Program
•
The effects of the PPA capacity charges were exacerbated by
the structure and implementation of the IPP program. The rapid
build-out of IPPs during the 1990s meant that with the impact
of the Asian financial crisis in 1998, the cost of electricity
began to explode dramatically due to a combination of:
 the high fixed cost of the IPPs (capacity payments or minimum
offtake) and
 the escalating foreign exchange liability stemming from deep
reliance on foreign capital.
•
The controversial “PPA” pass-through mechanism began
climbing rapidly with the crisis, eventually becoming larger than
the base rate itself.
Electricity Case Studies
March 16
134
Exchange Rates
Depreciation in exchange rates
of about 70% caused increases
in capacity charges
Electricity Case Studies
March 16
135
Risk Mitigation and Purchasing Power Parity
•
Purchasing Power Parity
 Change in exchange rate (versus USD)
 Current exchange rate x (1+local inflation)/(1+US$ 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
Electricity Case Studies
March 16
136
Example of Purchasing Power Parity and Inflation
Philippines Exchange Rate and Inflation Rate
60.00%
60.00
50.00%
50.00
40.00%
40.00
30.00%
30.00
Infllation Rate
Exchange Rate
20.00%
20.00
10.00%
10.00
0.00%
0.00
Electricity Case Studies
March 16
137
Index of Exchange Rate and Purchasing Power
Electricity Case Studies
March 16
138
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.
Electricity Case Studies
March 16
139
High Power Rates (Excluding Europe)
Price Comparison from Wikipedia
35.00
C
e
n 30.00
t
s
25.00
28.80
p
e 20.00
r
15.31
k 15.00
W
h 10.00
11.61
10.44
10.15
9.28
7.11
6.95
Finland
7.42
6.18
5.00
0.00
March 16
Canada
Malaysia
USA
South Africa
Perú
Iceland
HK - Kolowoon
Electricity Case Studies
HK - Island
Singapore
Philippines
U
S
D
11.80
Australia
i
n
12.30
140
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.
Electricity Case Studies
March 16
141
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.
Electricity Case Studies
March 16
142
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..."
Electricity Case Studies
March 16
144
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.
Electricity Case Studies
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
•
.
March 16
145
Debt to Income versus Debt to Capital
• 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.
Household Debt/GDP
1.00
0.80
0.60
0.40
0.20
0.00
Jan 53
Jan 55
Jan 57
Jan 59
Jan 61
Jan 63
Jan 65
Jan 67
Jan 69
Jan 71
Jan 73
Jan 75
Jan 77
Jan 79
Jan 81
Jan 83
Jan 85
Jan 87
Jan 89
Jan 91
Jan 93
Jan 95
Jan 97
Jan 99
Jan 01
Jan 03
Jan 05
Jan 07
• 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.
Index of Housing Growth and Population Growth
1.6
1.5
Population Index
1.4
• The second chart shows that the
housing as measured by
cumulative starts has increased by
about 40% more than population.
Housing Index
1.3
1.2
1.1
1
0.9
90 Nov
91 Jun
92 Jan
92 Aug
93 Mar
93 Oct
94 May
94 Dec
95 Jul
96 Feb
96 Sep
97 Apr
97 Nov
98 Jun
99 Jan
99 Aug
00 Mar
00 Oct
01 May
01 Dec
02 Jul
03 Feb
03 Sep
04 Apr
04 Nov
05 Jun
06 Jan
06 Aug
07 Mar
07 Oct
08 May
0.8
Electricity Case Studies
March 16
146
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
30
29.0
28
• .
27.0
26
GBP/MWH
24
22
20
23.0
24.0
26.0
24.0
21.0
25.0
22.0
20.0
18
19.0
17.0
16
15.5
14
• .
12
10
1990 1991 1992 1993 1994 1995 1996 1997 1999 2000 2001 2002 2003
Electricity Case Studies
March 16
147
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.
Electricity Case Studies
March 16
148
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.
Electricity Case Studies
March 16
149
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 longterm problems.
 Differences
 Must assess the credit quality of the off-taker
 Small risks become large in transaction with many contracts




Electricity Case Studies
Heat rate degradation
Plant availability
Contract penalties
Interest rate changes
March 16
150
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-tocapital ratios must be in the 50-50 range
to earn investment grade status so that
the cost of borrowing is reasonable.”
New Merchant Capacity in Database
35,000.00
29,513
30,000.00
23,942
25,000.00
MW
•
20,000.00
13,924
15,000.00
9,783
10,000.00
5,000.00
3,580
2,075
1,335
1,229
5,136
4,869
2,494
1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003
The merchant plant activity has been
very high.
Electricity Case Studies
March 16
151
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
•
Electricity Case Studies
March 16
152
Market Based Prices in the UK – Not too Much Volatility
£/MWh
(99/00)
40
Transport Uplift
Uplift
Capacity Payment
SMP
35
30
25
20
15
10
5
0
1990/1
1992/3
Electricity Case Studies
1994/5
1996/7
1998/9
2000/1
March 16
153
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.
Electricity Case Studies
March 16
154
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.
Electricity Case Studies
March 16
155
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.
UK Demand and Supply GW
Natural Gas and Conventional
Nuclear
Total
Demand Growth
2.7
 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%.
Electricity Case Studies
18.5
1.2
19.7
March 16
156
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.
AES DRAX Holdings Limited Bonds
AES DRAX Energy Senior Notes
In Power Bank Facility
Equity
Total Capitalization
Electricity Case Studies
GBP Millions
400.00
267.00
1,308.00
224.00
2,199.00
Percent
18.2%
12.1%
59.5%
10.2%
100.0%
March 16
157
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)
Electricity Case Studies
March 16
158
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.”
Electricity Case Studies
March 16
159
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
Electricity Case Studies
March 16
160
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.”
120
SMP, marginal cost
•
100
80
60
40
20
0
•
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.
Electricity Case Studies
0
10000
20000
30000
40000
50000
60000
70000
Demand, capacity
Marginal cost (Frontier estimates)
March 16
Sample Pool price outcomes
161
Reforms and Market Concentration in UK 1990 and 2000
•
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.
30000
20000
20000
10000
10000
Electricity Case Studies
Powergen
British Energy
National
Power
TXU
AES
Edison
Mission
Bnfl Magnox
EDF
.
NRG
•
Scottish Power
0
Scottish &
Southern
0
40000
30000
30000
20000
20000
10000
10000
0
0
March 16
National
Power
30000
40000
PowerGen
40000
50000
Nuclear
Electric
40000
50000
60000
NGC
50000
60000
EDF
50000
70000
Own capacity
Cumulative
Max demand
Min demand
Scottish Power
60000
70000
Scottish Hydro
Electric
60000
70000
Generation capacity (assuming 95% availability)
Before Reforms
Own capacity
Cumulative
Max demand
Min demand
70000
Other
Generation capacity (assuming 95% availability)
After Reforms
162
Break-up of Coal Fired Generation
Electricity Case Studies
March 16
163
Profits of Participants
Electricity Case Studies
March 16
164
Electricity Prices
UK Annual Electricity Prices
30
29.0
28
27.0
26
GBP/MWH
24
23.0
22
24.0
26.0
24.0
21.0
20
18
Prices can move to
short-run marginal cost
25.0
22.0
20.0
19.0
17.0
16
15.5
14
12
10
1990 1991 1992 1993 1994 1995 1996 1997 1999 2000 2001 2002 2003
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 overcapacity in the
UK generation
market, increased
competition and
fragmentation of
the market.
AES Drax Annual
Report
Electricity Case Studies
March 16
165
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
Electricity Case Studies
•
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
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AES Stock Price
AES:
Beta 1.81 Stock Volatiltiy 46.2% S&P Volatility 11.4%
25
20
15
AES
S&P Index
10
5
0
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Drax Case
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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.
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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%
Electricity Case Studies
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Crash of Merchant Power
17 March 2016
Electricity Case Studies
www.edbodmer.com
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171
Merchant Power Return Assumptions
17 March 2016
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172
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?
Electricity Case Studies
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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.
Electricity Case Studies
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Dabhol Structure
Reserve
Bank of
India
Ministry
of Power
Comfort
Letter
Government
of Maharashtra
Government
of India
Full
Guarantee
Maharashtra
State
Electricity
Board
State
Support
Agreement
PPA
FX Availability
Dabhol
Power
Corp
Electricity Case Studies
Limited
guarantee
Domestic
(Indian)
Financial
Institutions
(Banks)
US Exim
Political Risk
Guarantee
Lending Banks
Loan
Agreement
March 16
176
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
Electricity Case Studies
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Dabhol Plant Cost
•
First phase
•
Second phase
•
695 MW plant
•
1,320 MW capacity
•
Cost of $920 M
•
•
Construction began 1995,
project to come on-line in 1997
LNG re-gasification plant,
storage, and harbor facilities to
be built.
•
Cost $1323/kW
•
Construction to begin after
phase 1 completed
•
Comparable costs $650/kw
•
Cost of $1.88 B
•
Cost per $1,466/kW
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Cost of New Plants
Electricity Case Studies
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Comparative Plants
Electricity Case Studies
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Dabhol Timeline
• May-June, 1992: India invites Enron Corp to explore the
possibility of building a large power plant in Maharashtra.
•
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.
• March-June, 1995: Following state elections, a new
Maharashtra government, headed by the Shiv Sena,
scraps the project, alleging corruption and high costs.
•
April, 2001: Enron issues a notice of arbitration to
the Indian government to collect on the December
bill of Rs 1.02 billion.
• 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.
•
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.
• May, 1996: India extends counter-guarantee to the
project, under which the federal government promises to
cover any defaults by the state utility.
•
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.
• May, 1999: Phase one of the project with a capacity of
740 MW begins operating.
•
April 25 2001: The board of Dabhol Power
Company authorizes management to terminate the
contract any time it chooses.
• 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.
Electricity Case Studies
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181
Structure of Dabhol PPA Contract
•
PPA Contracts can transfer all demand and fuel cost risk. The
Dabhol PPA contract is illustrated below
Electricity Case Studies
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182
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
Electricity Case Studies
March 16
183
Comparative Plant Costs for Natural Gas
Electricity Case Studies
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184
Enron’s Economic Rational Underlying the Transaction
Electricity Case Studies
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185
Transparency
Electricity Case Studies
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186
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.
Electricity Case Studies
March 16
187
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 $20 million as "educational gifts". Critics consider
these payments to be bribes to clear the project;
Electricity Case Studies
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188
Contract Off-taker Risk and Dahbol
•
Endless disputes over prices and terms of the deal turned the venture
into a symbol of what can go wrong in large-scale development
projects when cultures collide.
•
In April 1993, a World Bank analysis questioned the project's
economic viability, citing the high cost of importing and using liquefied
natural gas relative to other domestic sources of fuels. Because of
those findings, the World Bank refused to provide funds for the
project.
•
"Price is becoming a sticky issue," the Financial Times reported.
"Indian officials see the price as very high compared to domestic gas
and imported and indigenous alternative fuels."
•
Protesters took to the streets to support demands for changes in the
plant's design and -- more broadly -- to oppose the Indian
government’s economic liberalization policies. Social activists,
lawyers, villagers and farmers banded together in groups opposed to
the Enron project.
•
The devaluation meant that Dabhol's energy prices would soar to
between two and five times the average price in the area.
Electricity Case Studies
March 16
189
Problems with PPA’s in Asia
•
Some PPA’s featured high prices for a variety of reasons and
became very unpopular (Pakistan, India, Indonesia,
Philippines)
 Exchange rate de-valuation
 High capacity prices
 Over-capacity
 High capital costs
•
IPP’s with long term PPA’s have added a substantial stock of
generators to developing countries (Pakistan, the Philippines,
India, Malaysia, Thailand, Indonesia)
 Current Problems
 No access to gas from Iran
 Nuclear not feasible
Electricity Case Studies
March 16
190
Vemagiri Power Project
Capacity of 388.5 MW
 15 year PPA for 370 MW
•
Natural gas fired (1x1) GE 9FA CCGT
 1.64 mmscmd of gas allocated
on firm basis
•
Project cost US$ 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)
VPGL Vemagiri
 Fixed Charge
- Rs. 1.01/kWh
 Variable Charge - Rs. 0.93/kWh
Electricity Case Studies
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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.
Electricity Case Studies
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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.
Electricity Case Studies
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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.
Electricity Case Studies
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195
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.
Electricity Case Studies
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196
Evaluating Foreign Exchange Rate Risk
•
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.
Electricity Case Studies
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197
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.
Electricity Case Studies
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Catastrophic Foreign Exchange Risk (S&P 2001)
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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.
Electricity Case Studies
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200
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
Electricity Case Studies
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201
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.
Projected and Actual Revenues for Iridium
9,000,000
Actual
Salomon Smith
Barney
Credit Suisse/First
Boston
Lehman Brothers
8,000,000
“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…’”
7,000,000
Merrill Lynch
6,000,000
CIBC Oppenheimer
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
0
1998
Electricity Case Studies
1999
2000
2001
2002
2003
2004
2005
2006
March 16
2007
2008
203
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.
Electricity Case Studies
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Resources and Contacts
•
My contacts
 Ed Bodmer
 Phone: +001-630-886-2754
 E-mail: edbodmer@aol.com
•
Other Sources
 Financial Library – project finance case studies including
Eurotunnel and Dabhol
 Financial Library – Monte Carlo simulation analysis
Electricity Case Studies
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