Silver linings
Uncertainty, sometimes to the level of chaos, prevails in the power
sector worldwide. Whether there is oversupply, under-supply, bad
weather, or political upheaval, the result is that sponsors of, and
investors in, power projects face numerous challenges unforseen
when liberalization and privatization were set in motion.
Market participants anticipated a somewhat orderly process of building or buying power plants, running them efficiently, and earning an economic rent that would meet shareholder expectations. Classic project finance techniques were widely used to finance these investments, and investors faced familiar risks including economic, fuel, contract and operational risks. However, with the relative pricing and political instability that exists in power markets around the world, developers and project sponsors are getting more creative in order to mitigate the risks resulting from the ?growing pains' in these relatively new markets.
As electricity markets around the world have evolved, the project finance market has become more complex. Investors now face risks associated with changing market dynamics, and regulatory and legal instability in addition to the classic questions of operational, fuel, contract, sovereign and structural risks. No longer limited to a single asset, contract based, highly structured financing category, project finance analytical techniques are used on a broader range of bank and bond offerings. While not always strictly project financings in the sense of being non-recourse, single asset, contracted power projects, the larger picture of how the power markets are developing makes the analytic techniques used to rate project financings adaptable to corporate level financings for generation companies as well.
In Project Finance's June, 2001 Latin Report, we outlined our approach to evaluating the risks inherent in project finance, with a special focus on developing markets. In this article, we focus on the US, Europe and Australia. Our view is that opportunities abound in the power sector around the world, but that the level of certainty for investors has deteriorated as the markets lurch their way through reform. In both articles, we state our belief that the economics underlying any project or generation company financing are critical. Structure cannot save an otherwise flawed project financing.
United States
In the ?land of plenty?, the questions are endless
Is there an energy crisis or not? Are there enough plants being built around the US to avert another California-like situation? Will there be enough natural gas infrastructure built to support the construction of all these power plants? Is there enough skilled labour to construct these plants? How will the electric transmission grid operate in the future? Are we constructing too many plants? What regulator will run the show ? state or federal? Will the environment impact energy policy? Has California permanently derailed electric deregulation and how might that impact the strategies of the newly formed high flying merchant generators? And if that were not enough things to consider, can all of these considerations be financed in a way that is not detrimental to bondholders?
As we continue to learn from the painful California experience, the fragmentation and potential dislocations in the US power industry become more apparent and questions like these emerge. Nearly nine years after the Energy Policy Act of 1992 passed and after billions of dollars of stranded cost bonds were issued, the transition has barely begun, the strategies continue to evolve, and the questions abound with few definitive answers in sight.
To understand how we got here, it is instructive to first understand the past. The US electric utility industry, faced with the potential to write off multiple billions of capital understandably spent the past decade wrestling with stranded cost recovery and spent little time, if any, building power plants or any form of power infrastructure.
Add to that a state- by- state based deregulation plan that moves sporadically and unevenly through each statehouse. It establishes standards for a commodity that is traded in regional markets that know no state boundaries and receives prices that change more dramatically in one hour than most commodities change in their lifetime.
Overlaying these many moving parts is an economy that has experienced unprecedented growth since the early 1990's, spurred by technological advances which increase the use of electricity.
However, the industry has indeed responded. According to NERC, between 1997 and 2000, 35,000 megawatts of new capacity have either been built or are under construction. According to RDI, approximately 300,000 megawatts of capacity are under consideration for completion by 2005. Most of the new construction is natural gas fired, although a number of coal plants are indeed part of the mix. In fact, even nuclear has made a comeback as the fate of the national fleet benefits from unprecedented operating performance and transitional stranded cost recovery, which transformed nuclear power from an obsolete dinosaur into a very attractive and, because it emits no air pollutants, an ?environmentally friendly' source of supply.
New generating companies that were not even operating five years ago have been formed to take advantage of these perceived opportunities. Some are new ventures, some are spin-offs from the utility and some are created through asset transfers of previously regulated assets. All are considered the growth vehicles for the power industry.
But at some point, every good party will come to an end. While Moody's believes that the genco party will continue and the demand for new power plants will remain strong over the next few years, pockets of over-capacity are likely to emerge. Already regions such as Texas and New England face an overbuild, while in California concerns over the possibility of regular rolling blackouts resulted in the California Department of Water Resources signing what has turned out to be contracts at higher than current prices because prices have fallen rapidly since May 2001. Add to the story a federal government that wants to utilize its power to open up the electric transmission system which should, theoretically, lead to lower electric generating prices in the future. While this scenario may actually satisfy federal and state regulators, since it could lead to lower prices and greater choices for consumers, it may mean lean times for generators operating a power plant in a merchant environment without a contract.
All of which brings us back to the most important question; ?How do you finance this growth and protect the interests of bondholders?? Many companies, including highly rated Duke Energy, have used their balance sheets to weather the uncertainties of the merchant generating environment. Other companies, like Calpine, have largely financed their capital requirements on a corporate basis while taking maximum advantage of their high stock price to utilize common equity as a currency to finance their growth. Others like AES Corporation have entered into a number of one-off tolling arrangements with trading and marketing companies to utilize the cash flow predictability of a fifteen year tolling arrangement to arrange capital markets financing. A final approach is the bank market. Syndicates have been arranged for construction financing on an asset or a group of assets. These bank deals usually mature within five to seven years covering construction and the early years of operating in a merchant environment. Typically, long-term off-take contracts have not been executed and the bankers' expectation is that permanent financing will be arranged when the power market's roadmap is clearer. Today's bank financings are likely to be refinanced in the 2005 through 2007 timeframe, a period when soft power markets could exist throughout certain parts of the country if a number of the aforementioned scenarios play out. Indeed, while Moody's appreciates the desire among bank lenders to provide shorter-term financing, Moody's also believes that refinancing risk may become more acute when the genco party ends and the merchant generator is left standing without a contract in an overbuilt market.
Europe
Though most advanced, still in transition
Most developed and many lesser developed countries are reforming electricity trading arrangements with the general aim of liberalizing the market and introducing competition.
There are many different forms of electricity trading arrangements across the world, although some variation on the pool mechanism exists from Australasia to the Americas and Europe. Notwithstanding the replacement of the UK pool by NETA (New Electricity Trading Arrangements) and the failings of the California pool, the number of pool systems is increasing in mainland Europe. Nordpool has been in operation for many years in Scandinavia, and is widely held to be a success. The Spanish pool has been operating since 1998, the Amsterdam Power Exchange (?APX?) since 1999, the Polish pool since 2000, and the Italian pool is now scheduled to operate from 2002.
No single set of electricity trading arrangements can be regarded as the best. However, a key measure of the success of any trading arrangements is the provision of appropriate pricing signals to increase generation capacity to meet rising demand, and the broad public acceptance of these pricing signals. This may include periods of low capacity margins and very high prices that compensate for periods of excess capacity and low prices. A good test is the ability of new entrants to project finance single power plants (IPPs) without having the broader resources of large utilities.
Whist the economic climate in Europe is positive for the construction of IPPs ? little or no currency risk, rising demand in strong economies, established legal frameworks ? there are certain basic risks related to the electricity pools that need consideration. Confidence is required regarding the competitive dynamics of the market and the risk of exposure to merchant prices; and there is the issue of potential mismatch between fuel and generation prices.
Defining the market
The first task is to define the European marketplace. Despite transmission restrictions and lack of consistent third party access terms across Europe, exports and trading are already a feature in European electricity. Certain markets are already well connected e.g. Germany and Austria, whilst others may be so more in the future e.g. Spain and Portugal may form an Iberian market; the APX may merge with the German exchanges; and Nordpool is likely to integrate further with Central Europe. The changing nature of these markets means that current capacity margins may be less relevant in the future. Other markets such as the Italian one may remain relatively isolated despite considerable imports as the scope for increased interconnection is limited.
Merchant IPPs can be project financed, as witnessed in the UK in the past decade. Investors need confidence that such plant can earn an economic return whilst continuing to maintain debt service. The plant typically needs to be low cost and have high thermal efficiency to ensure long term competitiveness. In the UK, investors also believed they understood the commercial dynamics of the system and trusted the pool structure. Some were ultimately sorry they did.
Even if market prices are less managed than they were in the UK, merchant IPPs can be project financed as long as the electricity market is liquid and there is confidence that commercial aspects of supply, demand and cost competitiveness will prevail. Recent allegations of manipulation on the APX illustrate the need to fully understand the operational rules of a pool and the overall competitive forces. The direction of regulation is also an uncertainty in such situations ? the UK provides a good example of progressively tightening regulation leading to a considerably altered marketplace.
In some European countries, there is still uncertainty as to how competition will develop. In particular the market power of incumbents is changing but the final destination is uncertain. In Italy and Spain there is an ongoing asset sale programme. Issues such as the mechanisms for stranded cost recovery also increase the uncertainty on pool price direction and levels. The rate of change of prices can be particularly hard to predict in these situations, especially when, as in Italy, prices are considered to be significantly above new entrant levels.
Liquidity of any pool is important, as higher liquidity provides a truer market price. The UK pool was extremely liquid as virtually all volume sold went through it; NETA has a balancing mechanism with very little liquidity. Although liquidity is growing in the Spanish pool and the APX, their output prices may not yet accurately reflect overall system supply and demand. In Poland, liquidity is very low due to the existence of long term PPAs which are not included in pool volumes, and prices are currently artificially low; at the same time, offtakers appear reluctant to sign new PPAs for fear of them soon becoming out of the market.
Confidence in the working of a pool also encompasses issues such as credit quality, systems and settlement procedures needed to ensure smooth operation. A longer track record of successful operation may be necessary in certain countries if the perception is that less effort has been expended in such areas.
Relative economics indicates that the majority of new plant to be built in Europe, as in the UK, will be combined cycle gas turbine (CCGT) burning natural gas. A positive development in the UK was the fact that the gas market was deregulated in parallel with the electricity market. This together with an oversupply of gas led to gas on gas competition and eventually some delinkage of gas prices form oil indexation. Certain gas suppliers were prepared to partially index their prices to electricity, which allowed IPPs to manage their price risks much more effectively. Gas was also priced in the same currency as electricity.
The situation in Europe is somewhat different. There are a number of gas regulators with different agendas, and few suppliers. These suppliers generally have in place long-term gas supply contracts with oil indexation (priced in US $, as opposed to electricity prices in Euros). There is generally insufficient correlation between gas and electricity prices to consider a natural hedge, and the number of electricity purchasers willing to accept pass-through of this indexation is limited (possible exceptions being in Italy, where oil prices already have a significant impact on prices). Although numerous LNG schemes are advocated to increase the supply of gas, these will continue to show substantial oil-price linkage. It may be that increased European gas liberalization including the provision of regulated third party access is necessary to introduce gas on gas competition.
Touching on Nordpool, this has (for Europe) the unique aspect that the principal factor determining prices in any year is hydrological conditions. This can mask underlying demand growth and reduction in capacity margin for many years. The forward price curve may also be too short and too influenced by yearly hydrology to be used as the basis of project financing IPPs and it has yet to be seen whether this can be achieved.
Australia
A more hospitable environment for power project finance? Pricing signals finally begin to work but it's a close run thing
If you had been sitting in an Adelaide or Melbourne restaurant in recent years, you would probably have cursed the name of electricity deregulation. On those days there were rolling power blackouts in those two cities due to lack of supply. Sitting in the heat with no air-conditioning was not a pleasant experience (as a team of Moody's analysts discovered!). Each occasion was short lived and had its own specific reasons but each highlighted the declining reserve margin in the two Australian states in which those cities are located. Fears were raised that more extensive power shortages were on the horizon.
Fast forward to August 2001 and there is evidence that the wholesale market is sending clear pricing signals for more capacity that are being acted on. Pulse Energy (a retail energy supplier) has entered into an agreement with Edison Mission Energy to buy power from a new 300MW gas fired peaking plant to be built by the first quarter 2002. AGL (rated A2, negative outlook), another energy retailer, has likewise commenced building new peaking plants in Victoria and South Australia that it expects to be operational in early 2002.
The reason for this sudden spurt is clear ? a declining reserve margin, increasing pool and forward contract prices and the fear of being short on electricity when prices are at their most volatile in the Australian summer. Indeed, National Gas Corporation of New Zealand (a subsidiary of AGL), has just learnt to its cost the risks of being short of electricity when supply is tight. A hydro-dominated market, New Zealand is experiencing a drought and wholesale prices have skyrocketed. This might sound familiar to those on the West Coast of the US. NGC was unable to appropriately hedge this exposure with the result that it has announced an abnormal hit to profit and has sold its retail customer base to exit that market altogether.
It is too early to be complacent however. None of the new peaking plants are yet operational. If they are delayed (and recent industrial action threatens just that) then the projected reserve margin is estimated to be approximately 4.3% (or 510 MW) as Victoria and South Australia head into their summers and the air conditioners crank up.1 To put that in context each of the four units at Loy Yang Power's plant in Victoria has a nominal capacity of 500MW. If one of those were to shut down that would be the end of the reserve margin. No wonder the electricity retailers are scrambling to build new capacity!
Why has the reserve margin fallen so low? There are undoubtedly a number of factors at play but two probably stand out: uncertainty about transmission upgrades and low pool prices during 1999 and earlier. There is surplus generating capacity in New South Wales and Queensland but limited transmission interconnection between those states and New South Wales. Whilst a number of projects are under consideration none will be built in time for the summer of 2002. However the fact that they might have been built has, arguably, delayed investment decisions for peaking plant. Only when it became clear they would not be built in time have some retailers been forced to act. The reason for the low pool prices prior to 2000 is itself a source of controversy with many market participants blaming others' behaviour. What is incontrovertible is that pool prices were low and so were encouraging anyone to build new plant. Only as pool prices increased during 2000 and prices became more volatile were pricing signals clearer.
Many would argue that this is the market working at its most efficient ? maybe. It's certainly going to be a close run thing this (southern) summer.
1 Source ? National Electricity Market Management Company (Australia) press release of 28 June 2001.
Market participants anticipated a somewhat orderly process of building or buying power plants, running them efficiently, and earning an economic rent that would meet shareholder expectations. Classic project finance techniques were widely used to finance these investments, and investors faced familiar risks including economic, fuel, contract and operational risks. However, with the relative pricing and political instability that exists in power markets around the world, developers and project sponsors are getting more creative in order to mitigate the risks resulting from the ?growing pains' in these relatively new markets.
As electricity markets around the world have evolved, the project finance market has become more complex. Investors now face risks associated with changing market dynamics, and regulatory and legal instability in addition to the classic questions of operational, fuel, contract, sovereign and structural risks. No longer limited to a single asset, contract based, highly structured financing category, project finance analytical techniques are used on a broader range of bank and bond offerings. While not always strictly project financings in the sense of being non-recourse, single asset, contracted power projects, the larger picture of how the power markets are developing makes the analytic techniques used to rate project financings adaptable to corporate level financings for generation companies as well.
In Project Finance's June, 2001 Latin Report, we outlined our approach to evaluating the risks inherent in project finance, with a special focus on developing markets. In this article, we focus on the US, Europe and Australia. Our view is that opportunities abound in the power sector around the world, but that the level of certainty for investors has deteriorated as the markets lurch their way through reform. In both articles, we state our belief that the economics underlying any project or generation company financing are critical. Structure cannot save an otherwise flawed project financing.
United States
In the ?land of plenty?, the questions are endless
Is there an energy crisis or not? Are there enough plants being built around the US to avert another California-like situation? Will there be enough natural gas infrastructure built to support the construction of all these power plants? Is there enough skilled labour to construct these plants? How will the electric transmission grid operate in the future? Are we constructing too many plants? What regulator will run the show ? state or federal? Will the environment impact energy policy? Has California permanently derailed electric deregulation and how might that impact the strategies of the newly formed high flying merchant generators? And if that were not enough things to consider, can all of these considerations be financed in a way that is not detrimental to bondholders?
As we continue to learn from the painful California experience, the fragmentation and potential dislocations in the US power industry become more apparent and questions like these emerge. Nearly nine years after the Energy Policy Act of 1992 passed and after billions of dollars of stranded cost bonds were issued, the transition has barely begun, the strategies continue to evolve, and the questions abound with few definitive answers in sight.
To understand how we got here, it is instructive to first understand the past. The US electric utility industry, faced with the potential to write off multiple billions of capital understandably spent the past decade wrestling with stranded cost recovery and spent little time, if any, building power plants or any form of power infrastructure.
Add to that a state- by- state based deregulation plan that moves sporadically and unevenly through each statehouse. It establishes standards for a commodity that is traded in regional markets that know no state boundaries and receives prices that change more dramatically in one hour than most commodities change in their lifetime.
Overlaying these many moving parts is an economy that has experienced unprecedented growth since the early 1990's, spurred by technological advances which increase the use of electricity.
However, the industry has indeed responded. According to NERC, between 1997 and 2000, 35,000 megawatts of new capacity have either been built or are under construction. According to RDI, approximately 300,000 megawatts of capacity are under consideration for completion by 2005. Most of the new construction is natural gas fired, although a number of coal plants are indeed part of the mix. In fact, even nuclear has made a comeback as the fate of the national fleet benefits from unprecedented operating performance and transitional stranded cost recovery, which transformed nuclear power from an obsolete dinosaur into a very attractive and, because it emits no air pollutants, an ?environmentally friendly' source of supply.
New generating companies that were not even operating five years ago have been formed to take advantage of these perceived opportunities. Some are new ventures, some are spin-offs from the utility and some are created through asset transfers of previously regulated assets. All are considered the growth vehicles for the power industry.
But at some point, every good party will come to an end. While Moody's believes that the genco party will continue and the demand for new power plants will remain strong over the next few years, pockets of over-capacity are likely to emerge. Already regions such as Texas and New England face an overbuild, while in California concerns over the possibility of regular rolling blackouts resulted in the California Department of Water Resources signing what has turned out to be contracts at higher than current prices because prices have fallen rapidly since May 2001. Add to the story a federal government that wants to utilize its power to open up the electric transmission system which should, theoretically, lead to lower electric generating prices in the future. While this scenario may actually satisfy federal and state regulators, since it could lead to lower prices and greater choices for consumers, it may mean lean times for generators operating a power plant in a merchant environment without a contract.
All of which brings us back to the most important question; ?How do you finance this growth and protect the interests of bondholders?? Many companies, including highly rated Duke Energy, have used their balance sheets to weather the uncertainties of the merchant generating environment. Other companies, like Calpine, have largely financed their capital requirements on a corporate basis while taking maximum advantage of their high stock price to utilize common equity as a currency to finance their growth. Others like AES Corporation have entered into a number of one-off tolling arrangements with trading and marketing companies to utilize the cash flow predictability of a fifteen year tolling arrangement to arrange capital markets financing. A final approach is the bank market. Syndicates have been arranged for construction financing on an asset or a group of assets. These bank deals usually mature within five to seven years covering construction and the early years of operating in a merchant environment. Typically, long-term off-take contracts have not been executed and the bankers' expectation is that permanent financing will be arranged when the power market's roadmap is clearer. Today's bank financings are likely to be refinanced in the 2005 through 2007 timeframe, a period when soft power markets could exist throughout certain parts of the country if a number of the aforementioned scenarios play out. Indeed, while Moody's appreciates the desire among bank lenders to provide shorter-term financing, Moody's also believes that refinancing risk may become more acute when the genco party ends and the merchant generator is left standing without a contract in an overbuilt market.
Europe
Though most advanced, still in transition
Most developed and many lesser developed countries are reforming electricity trading arrangements with the general aim of liberalizing the market and introducing competition.
There are many different forms of electricity trading arrangements across the world, although some variation on the pool mechanism exists from Australasia to the Americas and Europe. Notwithstanding the replacement of the UK pool by NETA (New Electricity Trading Arrangements) and the failings of the California pool, the number of pool systems is increasing in mainland Europe. Nordpool has been in operation for many years in Scandinavia, and is widely held to be a success. The Spanish pool has been operating since 1998, the Amsterdam Power Exchange (?APX?) since 1999, the Polish pool since 2000, and the Italian pool is now scheduled to operate from 2002.
No single set of electricity trading arrangements can be regarded as the best. However, a key measure of the success of any trading arrangements is the provision of appropriate pricing signals to increase generation capacity to meet rising demand, and the broad public acceptance of these pricing signals. This may include periods of low capacity margins and very high prices that compensate for periods of excess capacity and low prices. A good test is the ability of new entrants to project finance single power plants (IPPs) without having the broader resources of large utilities.
Whist the economic climate in Europe is positive for the construction of IPPs ? little or no currency risk, rising demand in strong economies, established legal frameworks ? there are certain basic risks related to the electricity pools that need consideration. Confidence is required regarding the competitive dynamics of the market and the risk of exposure to merchant prices; and there is the issue of potential mismatch between fuel and generation prices.
Defining the market
The first task is to define the European marketplace. Despite transmission restrictions and lack of consistent third party access terms across Europe, exports and trading are already a feature in European electricity. Certain markets are already well connected e.g. Germany and Austria, whilst others may be so more in the future e.g. Spain and Portugal may form an Iberian market; the APX may merge with the German exchanges; and Nordpool is likely to integrate further with Central Europe. The changing nature of these markets means that current capacity margins may be less relevant in the future. Other markets such as the Italian one may remain relatively isolated despite considerable imports as the scope for increased interconnection is limited.
Merchant IPPs can be project financed, as witnessed in the UK in the past decade. Investors need confidence that such plant can earn an economic return whilst continuing to maintain debt service. The plant typically needs to be low cost and have high thermal efficiency to ensure long term competitiveness. In the UK, investors also believed they understood the commercial dynamics of the system and trusted the pool structure. Some were ultimately sorry they did.
Even if market prices are less managed than they were in the UK, merchant IPPs can be project financed as long as the electricity market is liquid and there is confidence that commercial aspects of supply, demand and cost competitiveness will prevail. Recent allegations of manipulation on the APX illustrate the need to fully understand the operational rules of a pool and the overall competitive forces. The direction of regulation is also an uncertainty in such situations ? the UK provides a good example of progressively tightening regulation leading to a considerably altered marketplace.
In some European countries, there is still uncertainty as to how competition will develop. In particular the market power of incumbents is changing but the final destination is uncertain. In Italy and Spain there is an ongoing asset sale programme. Issues such as the mechanisms for stranded cost recovery also increase the uncertainty on pool price direction and levels. The rate of change of prices can be particularly hard to predict in these situations, especially when, as in Italy, prices are considered to be significantly above new entrant levels.
Liquidity of any pool is important, as higher liquidity provides a truer market price. The UK pool was extremely liquid as virtually all volume sold went through it; NETA has a balancing mechanism with very little liquidity. Although liquidity is growing in the Spanish pool and the APX, their output prices may not yet accurately reflect overall system supply and demand. In Poland, liquidity is very low due to the existence of long term PPAs which are not included in pool volumes, and prices are currently artificially low; at the same time, offtakers appear reluctant to sign new PPAs for fear of them soon becoming out of the market.
Confidence in the working of a pool also encompasses issues such as credit quality, systems and settlement procedures needed to ensure smooth operation. A longer track record of successful operation may be necessary in certain countries if the perception is that less effort has been expended in such areas.
Relative economics indicates that the majority of new plant to be built in Europe, as in the UK, will be combined cycle gas turbine (CCGT) burning natural gas. A positive development in the UK was the fact that the gas market was deregulated in parallel with the electricity market. This together with an oversupply of gas led to gas on gas competition and eventually some delinkage of gas prices form oil indexation. Certain gas suppliers were prepared to partially index their prices to electricity, which allowed IPPs to manage their price risks much more effectively. Gas was also priced in the same currency as electricity.
The situation in Europe is somewhat different. There are a number of gas regulators with different agendas, and few suppliers. These suppliers generally have in place long-term gas supply contracts with oil indexation (priced in US $, as opposed to electricity prices in Euros). There is generally insufficient correlation between gas and electricity prices to consider a natural hedge, and the number of electricity purchasers willing to accept pass-through of this indexation is limited (possible exceptions being in Italy, where oil prices already have a significant impact on prices). Although numerous LNG schemes are advocated to increase the supply of gas, these will continue to show substantial oil-price linkage. It may be that increased European gas liberalization including the provision of regulated third party access is necessary to introduce gas on gas competition.
Touching on Nordpool, this has (for Europe) the unique aspect that the principal factor determining prices in any year is hydrological conditions. This can mask underlying demand growth and reduction in capacity margin for many years. The forward price curve may also be too short and too influenced by yearly hydrology to be used as the basis of project financing IPPs and it has yet to be seen whether this can be achieved.
Australia
A more hospitable environment for power project finance? Pricing signals finally begin to work but it's a close run thing
If you had been sitting in an Adelaide or Melbourne restaurant in recent years, you would probably have cursed the name of electricity deregulation. On those days there were rolling power blackouts in those two cities due to lack of supply. Sitting in the heat with no air-conditioning was not a pleasant experience (as a team of Moody's analysts discovered!). Each occasion was short lived and had its own specific reasons but each highlighted the declining reserve margin in the two Australian states in which those cities are located. Fears were raised that more extensive power shortages were on the horizon.
Fast forward to August 2001 and there is evidence that the wholesale market is sending clear pricing signals for more capacity that are being acted on. Pulse Energy (a retail energy supplier) has entered into an agreement with Edison Mission Energy to buy power from a new 300MW gas fired peaking plant to be built by the first quarter 2002. AGL (rated A2, negative outlook), another energy retailer, has likewise commenced building new peaking plants in Victoria and South Australia that it expects to be operational in early 2002.
The reason for this sudden spurt is clear ? a declining reserve margin, increasing pool and forward contract prices and the fear of being short on electricity when prices are at their most volatile in the Australian summer. Indeed, National Gas Corporation of New Zealand (a subsidiary of AGL), has just learnt to its cost the risks of being short of electricity when supply is tight. A hydro-dominated market, New Zealand is experiencing a drought and wholesale prices have skyrocketed. This might sound familiar to those on the West Coast of the US. NGC was unable to appropriately hedge this exposure with the result that it has announced an abnormal hit to profit and has sold its retail customer base to exit that market altogether.
It is too early to be complacent however. None of the new peaking plants are yet operational. If they are delayed (and recent industrial action threatens just that) then the projected reserve margin is estimated to be approximately 4.3% (or 510 MW) as Victoria and South Australia head into their summers and the air conditioners crank up.1 To put that in context each of the four units at Loy Yang Power's plant in Victoria has a nominal capacity of 500MW. If one of those were to shut down that would be the end of the reserve margin. No wonder the electricity retailers are scrambling to build new capacity!
Why has the reserve margin fallen so low? There are undoubtedly a number of factors at play but two probably stand out: uncertainty about transmission upgrades and low pool prices during 1999 and earlier. There is surplus generating capacity in New South Wales and Queensland but limited transmission interconnection between those states and New South Wales. Whilst a number of projects are under consideration none will be built in time for the summer of 2002. However the fact that they might have been built has, arguably, delayed investment decisions for peaking plant. Only when it became clear they would not be built in time have some retailers been forced to act. The reason for the low pool prices prior to 2000 is itself a source of controversy with many market participants blaming others' behaviour. What is incontrovertible is that pool prices were low and so were encouraging anyone to build new plant. Only as pool prices increased during 2000 and prices became more volatile were pricing signals clearer.
Many would argue that this is the market working at its most efficient ? maybe. It's certainly going to be a close run thing this (southern) summer.
1 Source ? National Electricity Market Management Company (Australia) press release of 28 June 2001.
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