Can-do?
Calpine has acquired a near-mythical status as a bellwether for hot
power markets. Its acquisition of interests in two Canadian
generation facilities from Westcoast Energy has, therefore,
refocused attention on the deregulating markets of Canada. Much
like the various states in the US, Canada is deregulating one
province at a time. And whilst Alberta, the first province to
deregulate, has seen some changes in asset ownership, populous
Ontario is set to be the most active market over the next few
years.
But this increase in interest in the power industry has been overshadowed by developments in the oil and gas industry. Duke Energy has inked an $8.5 billion takeover deal with Westcoast, and has said that its main interests are in Westcoast's pipeline assets, which compliment its eastern presence. By the same token, Calpine recently bought out oil and gas producer Encal, largely to avail itself of Encal's sizeable gas reserves.
Export potential
Indeed, pipeline projects are still the most favoured Canadian assets, partly because shipping contracts offer more stable revenue streams than generation assets, but also because their cross-border nature ensures access to some US dollar funding. In April 2001 the Alliance Pipeline filed a $1.2 million shelf registration to refinance project debt on a corporate basis, and has used Canadian and US dollar denominated private placements to reduce debt still further.
Current US energy thinking makes further such projects likely, since Canadian and Alaskan gas reserves remain the closest sources of energy security for the hungry American market. Whilst the recent terrorist attacks may have pushed the question of drilling in the Arctic wildlife reserve to the back of the congressional agenda, the domestic case for drilling has increased palpably. Uncertainty over the choice of operators and a long permitting process make an imminent mandate unlikely, however.
Canada's present inclination to export its natural gas to the US is highlighted by El Paso Corporation's present plan to build a $1.6 billion pipeline from Nova Scotia to New York and New Jersey. The 750-mile system would have a capacity of 1 billion cubic feet of gas per day and would open up the Nova Scotia reserves to increased exploitation. The plan mirrors the Neptune interconnect project, sponsored by Atlantic Energy Partners, which would bring electricity along a similar route.
The Ontario market
A willingness to examine energy export schemes is perhaps understandable after an examination of the Ontario power market. Even with a population growing at a healthy rate, the province is not under great threat of shortages, largely because of a strong, low cost, base load generation mix. Ontario has come through deregulation with around 70% of generation assets still held by state-owned Ontario Power Generation (OPG). There are as yet no plans to privatize OPG, and the province has taken a number of steps to mitigate its market power.
The first of these is the rebate process, which hands revenue above an average annual price threshold of 3.8% back to customers. The second, more promising, measure is the principle of decontrol. This states that all generation capacity above 35% of the market must be removed from OPG's control over the next ten years. Decontrol means the relinquishing of operational control, and at the moment is understood to mean either an outright sale of power generation facilities or a straightforward lease.
The most prominent asset transfer so far has been OPG's lease of Bruce Power to British Energy. Bruce has 3000MW of nuclear capacity and has been leased for 17 years for an upfront payment of C$625m, which breaks down into an initial lease payment of C$540m and the acquisition of stocks and other assets for C$85m. The deal also features yearly lease payments that will vary according to future conditions. The deal was concluded on 11 July, but will not feature any external funding, aside from that available to British Energy through its corporate bank facilities.
Next up will be the 310MW Thunder Bay Station, the 215MW Atikokan Station in north-western Ontario, and the 490MW combined output of the four Mississagi River Generating Stations (Aubrey Falls, George W. Rayner, Red Rock Falls and Wells) near Sault Ste. Marie. Merrill Lynch and Scotia Capital have bagged the advisory mandate for the sales, which should be complete by the middle of 2002. OPG is also examining decontrol options for its coal-fired Lakeview and oil and coal-fuelled Lennox facilities.
The start of open markets in Ontario is set for May 2002, when residential customers can start choosing their suppliers. Transmission has now been spun off into a ?wires? business known as Hydro One. Direct Energy, a centric subsidiary, now has 400-500,000 customers. The Independent Electricity Market Operator (IMO) is responsible for monitoring and controlling dispatch. The wholesale market will operate on a spot market, although this will be a relatively small given the market power potential of OPG.
Potential for gas-fired generation, then, lies in the construction of peaker plants. This option will be especially attractive to those players ? particularly Enron ? who are looking to start up trading operations in the province. The likelihood of these emerging from any parent's corporate balance sheet is slim. And, as Ron Lepin from PricewaterhouseCoopers Securities in Ontario points out, ?a big question that has to be answered before building peaking capacity is whether the nuclear capacity that has been off recently will come back on. There is a lot of cheap baseload capacity and a demand/supply profile that says there will be sufficient supply. This is a very tough environment for financing?. Bruce Power, for instance, has 1500MW currently offline.
Cogen ? the merchant beachhead
Elsewhere in Canada sponsors are coming up with novel financing solutions that exploit an anchor power purchase agreement, either with an industrial offtaker or a municipally-owned power company. In provinces that have deregulated, municipal power authorities have been encouraged either to sell out to private utilities or incorporate. Where this has not yet occurred, the provincial credit behind these offtakers makes projects subject to them attractive assets.
ATCO Power has been at the forefront of new single asset financings, most recently with the Cory Cogen deal. Cory is a joint venture with Saskatchewan municipal SaskPower, and sells its steam to the Saskatchewan Potash Corporation. The C$118 million financing took the form of a bond issue led by RBC Dominion Securities and BMO Nesbitt Burns. Such periodic raids on the institutional market are the best that sponsors can hope for given the intense conservatism that afflicts the Canadian dollar bank market.
ATCO's previous milestone was the Joffre transaction, rightly hailed as a template but as yet attracting few imitators. Joffre, which signed in June 1999, used a mixture of 12-year bank debt from RBC and WestLB of C$158.7 million and a 20-year institutional tranche from John Hancock of C$100 million. Joffre and Cory also used an unincorporated joint venture structure, largely because of the tax benefits. This Canadian legal structure avoids trapping the speedy depreciation available to cogeneration plants at the project level.
Joffre's other sponsors, Nova Chemicals and EPCOR, took the steam and electricity, respectively, from the plant, but around 53% of the electricity is either sold on the spot market in Alberta, where Joffre is located, or sold under bilateral contracts, which are permitted under the new rules. Alberta's market is dominated by ATCO, EPCOR and Transalta, the last of whom has moved out of the regulated business altogether and is looking for US growth. Transalta has sold its utility business to Utilicorp and its transmission business to the SNC Lavalin-led Altalink consortium. Its last link to the regulated market in Alberta is the transitional PPA that it has with the utility business.
ATCO wants to follow suit in creating a generation company, although it will not yet exit the other corners of the business in which it is engaged. It is currently looking at arranging a portfolio facility to cover a portfolio of five small plants, some of which are already in operation, with an installed capacity of 300MW. The move would be a bold one, and the question for ATCO is whether it can persuade the domestic banks to bite. Questions of geographical and fuel diversity (ATCO's plants are understood to be a combination of hydro and thermal assets located in various parts of the country) are less important to lenders than how comfortable they can get with a meaningful tenor and the risk of operating in a deregulating market.
Calpine's new assets are also cogeneration plants. One is the 250MW Island facility located near Campbell River, British Columbia on Vancouver Island. This is near to completion and will deliver electricity to BC Hydro under a 20-year PPA and steam to Norske Skog for industrial processing under a 15-year contract. The other is the 50MW Whitby Cogeneration facility. The offtaker here is Ontario Energy Financial Corporation (formerly Ontario Hydro) and steam is sold to Atlantic Packaging.
Lepin at PwC is more positive about the long-term prospects for export-driven financings and increased intertie capacity. Manitoba and Quebec, in particular, are seriously looking at hydro-electric projects to serve markets such as upstate New York, Ohio and Michigan. Such deals would exploit comparative cost advantages and a healthier supply/demand situation imbalance, as well as access US dollar revenue streams that make facilities more financeable. This is a scenario that many analyses of the Nepool and ECAR power markets have stressed ? that there may exist enough capacity in Canada to drive down prices in the north-eastern US to such an extent that it would actually drive several thermal generators out of business.
Oil Sands
August saw major movements on the financing front for the two main operators of oil sands projects. The two major players, established Syncrude and upstart Athabasca, both received financing commitments through minority stakeholders. After the gradual exhaustion of crude reserves, oil sands projects ? where bitumen mixed with sand and water are essentially mined and then upgraded ? are now receiving the majority of new investment in Canada. The syncrude that results from the process could account for almost 50% of output in the sector by the end of the decade.
This qurter's funding activity has been limited to the independent and project specific members of the two consortia. Western Oil Sands (WOS), made up of former BHP management stranded by BHP's withdrawal, is a 20% partner in Athabasca, along with Shell Canada (60%) and Chevron (20%). WOS, without an extensive balance sheet at its disposal, has had to find one fifth of the estimated C$5.9 billion project costs. C$1.3 billion of the costs will be funded separately, however, including a lease on a hydrogen plant that is integral to the project.
WOS' new financing is a $465 million seven-year senior note issue and a four year C$175 million priority senior secured bank facility that will largely be used to cover possible cost overruns. The other partners have first call on WOS assets in the event of default, followed by the banks and then the noteholders. Moody's Investors Service rated the notes at Ba2 and the bank deal at Ba1. The main rationale behind this rating was the lack of completion guarantees, but Moody's stresses that an operational project would probably be investment grade.
The proposed C$465 million note issue, however, has been pulled from the market for the time being following the September 11 attacks and continuing uncertainty in the Canadian high-yield market.
The project involves the exploitation of one of the highest quality oil sands deposits in Alberta. At the Muskeg River site, bitumen-rich sands are extracted, the bitumen is separated and diluted and then piped 444km down to Shell's Scotford Refinery for upgrade. Shell is the main offtaker, and is looking at properties with reserves that might exceed Muskeg River's 1.7 billion barrel reserves.
The latest Syncrude project involves the $4.1 billion expansion of an existing operation and has a much more complicated ownership structure. Syncrude, in operation since the seventies, is owned by a consortium which includes AEC, Conoco, Petro-Canada, Murphy and Imperial Oil Resources. It also features a single purpose investor, Canadian Oil Sands Limited (COS), which recently merged with another partner, Athabasca Oil Sands Investments. Rivalry between the two, which were set up, respectively, by PanCanadian and Gulf, prevented a merger until common investors prodded the two to merge in the interests of efficiency. Between them, the two are responsible for 21.74% of the project's funding.
Citibank/Salomon Smith Barney won the mandate to run a bond issue for COS' share of expansion costs, beating out strong competition from the banks working on the merger, which included Merrill Lynch, RBC and CIBC. The $250 million deal was launched in the 144A market, because syncrude produces a US dollar revenue stream, and liquidity in the Canadian market was not up to the burden. The twenty-year senior unsecured issue came in with a coupon of 7.9%.
The notes were rated BBB+ and Baa2, higher than the greenfield and currently speculative grade Western Oil Sands issue. Big issues for the ratings agencies were completion risk (oil sands projects have a long history of cost overruns) and the leverage of the project. Until recently COS' debt/equity ratio was roughly 10%, and management wished to increase distributions to shareholders during the expansion. Nevertheless, COS has stated that it wants to keep gearing at or below 40%, roughly sufficient for an investment grade rating.
There are other considerations for operators, including crude prices, which can only be mitigated by making sure that upgraders focus on the lighter crudes, which can often be used to dilute other loads. Moreover, activity in the region has expanded, both contributing to a possible regional glut and also increasing labour costs. The addition of a second train at the Aurora mine, the focus of the Syncrude expansion, should create efficiencies, however.
But this increase in interest in the power industry has been overshadowed by developments in the oil and gas industry. Duke Energy has inked an $8.5 billion takeover deal with Westcoast, and has said that its main interests are in Westcoast's pipeline assets, which compliment its eastern presence. By the same token, Calpine recently bought out oil and gas producer Encal, largely to avail itself of Encal's sizeable gas reserves.
Export potential
Indeed, pipeline projects are still the most favoured Canadian assets, partly because shipping contracts offer more stable revenue streams than generation assets, but also because their cross-border nature ensures access to some US dollar funding. In April 2001 the Alliance Pipeline filed a $1.2 million shelf registration to refinance project debt on a corporate basis, and has used Canadian and US dollar denominated private placements to reduce debt still further.
Current US energy thinking makes further such projects likely, since Canadian and Alaskan gas reserves remain the closest sources of energy security for the hungry American market. Whilst the recent terrorist attacks may have pushed the question of drilling in the Arctic wildlife reserve to the back of the congressional agenda, the domestic case for drilling has increased palpably. Uncertainty over the choice of operators and a long permitting process make an imminent mandate unlikely, however.
Canada's present inclination to export its natural gas to the US is highlighted by El Paso Corporation's present plan to build a $1.6 billion pipeline from Nova Scotia to New York and New Jersey. The 750-mile system would have a capacity of 1 billion cubic feet of gas per day and would open up the Nova Scotia reserves to increased exploitation. The plan mirrors the Neptune interconnect project, sponsored by Atlantic Energy Partners, which would bring electricity along a similar route.
The Ontario market
A willingness to examine energy export schemes is perhaps understandable after an examination of the Ontario power market. Even with a population growing at a healthy rate, the province is not under great threat of shortages, largely because of a strong, low cost, base load generation mix. Ontario has come through deregulation with around 70% of generation assets still held by state-owned Ontario Power Generation (OPG). There are as yet no plans to privatize OPG, and the province has taken a number of steps to mitigate its market power.
The first of these is the rebate process, which hands revenue above an average annual price threshold of 3.8% back to customers. The second, more promising, measure is the principle of decontrol. This states that all generation capacity above 35% of the market must be removed from OPG's control over the next ten years. Decontrol means the relinquishing of operational control, and at the moment is understood to mean either an outright sale of power generation facilities or a straightforward lease.
The most prominent asset transfer so far has been OPG's lease of Bruce Power to British Energy. Bruce has 3000MW of nuclear capacity and has been leased for 17 years for an upfront payment of C$625m, which breaks down into an initial lease payment of C$540m and the acquisition of stocks and other assets for C$85m. The deal also features yearly lease payments that will vary according to future conditions. The deal was concluded on 11 July, but will not feature any external funding, aside from that available to British Energy through its corporate bank facilities.
Next up will be the 310MW Thunder Bay Station, the 215MW Atikokan Station in north-western Ontario, and the 490MW combined output of the four Mississagi River Generating Stations (Aubrey Falls, George W. Rayner, Red Rock Falls and Wells) near Sault Ste. Marie. Merrill Lynch and Scotia Capital have bagged the advisory mandate for the sales, which should be complete by the middle of 2002. OPG is also examining decontrol options for its coal-fired Lakeview and oil and coal-fuelled Lennox facilities.
The start of open markets in Ontario is set for May 2002, when residential customers can start choosing their suppliers. Transmission has now been spun off into a ?wires? business known as Hydro One. Direct Energy, a centric subsidiary, now has 400-500,000 customers. The Independent Electricity Market Operator (IMO) is responsible for monitoring and controlling dispatch. The wholesale market will operate on a spot market, although this will be a relatively small given the market power potential of OPG.
Potential for gas-fired generation, then, lies in the construction of peaker plants. This option will be especially attractive to those players ? particularly Enron ? who are looking to start up trading operations in the province. The likelihood of these emerging from any parent's corporate balance sheet is slim. And, as Ron Lepin from PricewaterhouseCoopers Securities in Ontario points out, ?a big question that has to be answered before building peaking capacity is whether the nuclear capacity that has been off recently will come back on. There is a lot of cheap baseload capacity and a demand/supply profile that says there will be sufficient supply. This is a very tough environment for financing?. Bruce Power, for instance, has 1500MW currently offline.
Cogen ? the merchant beachhead
Elsewhere in Canada sponsors are coming up with novel financing solutions that exploit an anchor power purchase agreement, either with an industrial offtaker or a municipally-owned power company. In provinces that have deregulated, municipal power authorities have been encouraged either to sell out to private utilities or incorporate. Where this has not yet occurred, the provincial credit behind these offtakers makes projects subject to them attractive assets.
ATCO Power has been at the forefront of new single asset financings, most recently with the Cory Cogen deal. Cory is a joint venture with Saskatchewan municipal SaskPower, and sells its steam to the Saskatchewan Potash Corporation. The C$118 million financing took the form of a bond issue led by RBC Dominion Securities and BMO Nesbitt Burns. Such periodic raids on the institutional market are the best that sponsors can hope for given the intense conservatism that afflicts the Canadian dollar bank market.
ATCO's previous milestone was the Joffre transaction, rightly hailed as a template but as yet attracting few imitators. Joffre, which signed in June 1999, used a mixture of 12-year bank debt from RBC and WestLB of C$158.7 million and a 20-year institutional tranche from John Hancock of C$100 million. Joffre and Cory also used an unincorporated joint venture structure, largely because of the tax benefits. This Canadian legal structure avoids trapping the speedy depreciation available to cogeneration plants at the project level.
Joffre's other sponsors, Nova Chemicals and EPCOR, took the steam and electricity, respectively, from the plant, but around 53% of the electricity is either sold on the spot market in Alberta, where Joffre is located, or sold under bilateral contracts, which are permitted under the new rules. Alberta's market is dominated by ATCO, EPCOR and Transalta, the last of whom has moved out of the regulated business altogether and is looking for US growth. Transalta has sold its utility business to Utilicorp and its transmission business to the SNC Lavalin-led Altalink consortium. Its last link to the regulated market in Alberta is the transitional PPA that it has with the utility business.
ATCO wants to follow suit in creating a generation company, although it will not yet exit the other corners of the business in which it is engaged. It is currently looking at arranging a portfolio facility to cover a portfolio of five small plants, some of which are already in operation, with an installed capacity of 300MW. The move would be a bold one, and the question for ATCO is whether it can persuade the domestic banks to bite. Questions of geographical and fuel diversity (ATCO's plants are understood to be a combination of hydro and thermal assets located in various parts of the country) are less important to lenders than how comfortable they can get with a meaningful tenor and the risk of operating in a deregulating market.
Calpine's new assets are also cogeneration plants. One is the 250MW Island facility located near Campbell River, British Columbia on Vancouver Island. This is near to completion and will deliver electricity to BC Hydro under a 20-year PPA and steam to Norske Skog for industrial processing under a 15-year contract. The other is the 50MW Whitby Cogeneration facility. The offtaker here is Ontario Energy Financial Corporation (formerly Ontario Hydro) and steam is sold to Atlantic Packaging.
Lepin at PwC is more positive about the long-term prospects for export-driven financings and increased intertie capacity. Manitoba and Quebec, in particular, are seriously looking at hydro-electric projects to serve markets such as upstate New York, Ohio and Michigan. Such deals would exploit comparative cost advantages and a healthier supply/demand situation imbalance, as well as access US dollar revenue streams that make facilities more financeable. This is a scenario that many analyses of the Nepool and ECAR power markets have stressed ? that there may exist enough capacity in Canada to drive down prices in the north-eastern US to such an extent that it would actually drive several thermal generators out of business.
Oil Sands
August saw major movements on the financing front for the two main operators of oil sands projects. The two major players, established Syncrude and upstart Athabasca, both received financing commitments through minority stakeholders. After the gradual exhaustion of crude reserves, oil sands projects ? where bitumen mixed with sand and water are essentially mined and then upgraded ? are now receiving the majority of new investment in Canada. The syncrude that results from the process could account for almost 50% of output in the sector by the end of the decade.
This qurter's funding activity has been limited to the independent and project specific members of the two consortia. Western Oil Sands (WOS), made up of former BHP management stranded by BHP's withdrawal, is a 20% partner in Athabasca, along with Shell Canada (60%) and Chevron (20%). WOS, without an extensive balance sheet at its disposal, has had to find one fifth of the estimated C$5.9 billion project costs. C$1.3 billion of the costs will be funded separately, however, including a lease on a hydrogen plant that is integral to the project.
WOS' new financing is a $465 million seven-year senior note issue and a four year C$175 million priority senior secured bank facility that will largely be used to cover possible cost overruns. The other partners have first call on WOS assets in the event of default, followed by the banks and then the noteholders. Moody's Investors Service rated the notes at Ba2 and the bank deal at Ba1. The main rationale behind this rating was the lack of completion guarantees, but Moody's stresses that an operational project would probably be investment grade.
The proposed C$465 million note issue, however, has been pulled from the market for the time being following the September 11 attacks and continuing uncertainty in the Canadian high-yield market.
The project involves the exploitation of one of the highest quality oil sands deposits in Alberta. At the Muskeg River site, bitumen-rich sands are extracted, the bitumen is separated and diluted and then piped 444km down to Shell's Scotford Refinery for upgrade. Shell is the main offtaker, and is looking at properties with reserves that might exceed Muskeg River's 1.7 billion barrel reserves.
The latest Syncrude project involves the $4.1 billion expansion of an existing operation and has a much more complicated ownership structure. Syncrude, in operation since the seventies, is owned by a consortium which includes AEC, Conoco, Petro-Canada, Murphy and Imperial Oil Resources. It also features a single purpose investor, Canadian Oil Sands Limited (COS), which recently merged with another partner, Athabasca Oil Sands Investments. Rivalry between the two, which were set up, respectively, by PanCanadian and Gulf, prevented a merger until common investors prodded the two to merge in the interests of efficiency. Between them, the two are responsible for 21.74% of the project's funding.
Citibank/Salomon Smith Barney won the mandate to run a bond issue for COS' share of expansion costs, beating out strong competition from the banks working on the merger, which included Merrill Lynch, RBC and CIBC. The $250 million deal was launched in the 144A market, because syncrude produces a US dollar revenue stream, and liquidity in the Canadian market was not up to the burden. The twenty-year senior unsecured issue came in with a coupon of 7.9%.
The notes were rated BBB+ and Baa2, higher than the greenfield and currently speculative grade Western Oil Sands issue. Big issues for the ratings agencies were completion risk (oil sands projects have a long history of cost overruns) and the leverage of the project. Until recently COS' debt/equity ratio was roughly 10%, and management wished to increase distributions to shareholders during the expansion. Nevertheless, COS has stated that it wants to keep gearing at or below 40%, roughly sufficient for an investment grade rating.
There are other considerations for operators, including crude prices, which can only be mitigated by making sure that upgraders focus on the lighter crudes, which can often be used to dilute other loads. Moreover, activity in the region has expanded, both contributing to a possible regional glut and also increasing labour costs. The addition of a second train at the Aurora mine, the focus of the Syncrude expansion, should create efficiencies, however.
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