Ontario’s push into renewables is part of an effort to squeeze out coal-fired production and boost its industrial sector. The province has been the site for a respectable string of gas-fired projects, but lenders’ greatest interest is in wind and solar deals, following the province’s new tariff regime and energy legislation. Deals have contended with teething troubles such as domestic content requirements, but these look set to be overcome in the next few months.

In 2009 Ontario’s Liberal party-led administration rolled out new renewable tariff legislation and an energy act, which has fostered considerable interest from sponsors. The province’s manufacturing sector has not escaped the economic downturn, and the current government is under pressure to show it is capable of creating jobs. As such, the province hopes its feed-in tariffs, combined with streamlined permitting procedures, can accelerate investment, boost employment and shrink Ontario’s carbon footprint.

But the effort is also dedicated towards a more immediate goal – Ontario has a moratorium on coal plants and plans to end coal-fired power production by 2014. A combination of gas, wind and solar capacity is meant to fill the void.

FIT for purpose

The feed-in tariffs cover all small-scale renewables, including biomass and landfill gas, but solar and wind tariffs are likely to be the source of most sponsor and lender activity. Under the scheme, solar projects are limited to a capacity of 10MW per connection, but projects can be bundled together for financing. Ground mounted projects over 10kW receive C$0.443 per kWh and rooftop projects over 500kW get C$0.539 per kWh.

Under the older renewables incentive regime, the Renewable Energy Standard Offer Programme (RESOP), projects were offered a PPA if they met renewables criteria, but there were no price distinctions according to the size of the project. Under FIT, onshore wind projects get a tariff of C$0.135 per kWh, with the rate for offshore projects set at C$0.19 per kWh, though offshore is likely to be a longer-term prospect.

The Ontario government also brought in energy legislation around the time FIT was launched, which streamlined the permitting process. “Under the RESOP, local municipalities played a very central role in permitting,” says Michael Barrett, partner at Bennett Jones. “Under the FIT program, the government now provides a province-wide renewable energy approval (REA) that is intended to be a one-stop shop approach to getting your project permitted. There still remains some local municipality involvement (i.e. building permits and some other local permits) but the process has drastically reduced the public consultation role,” Barrett says.

Under RESOP, wind projects were limited to 10MW in size. With no cap on projects under the new tariffs, the province should see sharp growth.

“The only way to build a sizeable windfarm was to bid into a request for proposals, until this new FIT programme came along,” says one banker. The RESOP contracts typically involved selling power for 20 years to the Ontario Power Authority (OPA), a state-owned entity rated Aa1/A High (Moody’s/DBRS). These contracts tended to be extremely attractive to bankers, and Canadian solar and wind was noticeably quick to recover from the crunch.

One example was Kruger Energy’s 101.2MW Chatham wind deal, which closed in May 2010. The project sells power to the OPA under a RES III power purchase agreement. Kruger closed a three-year (construction plus two years) C$220 million mini-perm loan with Scotia, as lead arranger, Deutsche, Rabobank, SMBC, and CIBC as arrangers, and AIB as lender. The pricing on the loan is roughly 325bp. Since then, the market has eased below 300bp, sources say.

Why wait to get FIT?

The market is confident the FIT terms will make for tempting financing opportunities. Teething troubles remain, however, and optimism over the FIT rates is yet to transform into a steady flow of deal signings.

The biggest challenge for developers and lenders under the FIT programme comes from new domestic content requirements, which require renewables projects to use locally-made components for a certain portion of the plant. Domestic content requirements are not new to Canada, but Ontario’s rules have caused much head-scratching.

Projects effectively gain points for each domestically-sourced component, up to a certain minimum percentage, which means that developers must choose which pieces must be produced locally. But there is only a small number of in-province manufacturing sources for certain components, and these will have to be sourced from abroad until new factories are set up.

For example there is, as yet, a dearth of local solar panel production. Instead, solar project developers are looking to source domestically distribution and transmission equipment, as well as superstructure components like frames and mounts, says Paul Astolfi, partner at Mayer Brown. “Solar panels are more commonly manufactured outside of Canada ... so basically people focus on the rest of the project and try to drive up the domestic content in those areas,” he says.

Wind projects are moving faster than solar deals, as the threshold for domestic content is lower in the early period.

Designed to foster the growth of a renewable energy equipment manufacturing industry in Ontario, the domestic content requirements ratchet up over time, with early mover wind projects requiring 25% of total equipment, moving up to 50% for projects from the start of 2012.

Whether wind or solar, foreign manufacturers have to decide whether or not they want to set up operations to compete for the business. “We’re talking about solar vendors, module and inverter manufacturers, making investment decisions to locate in Ontario. I have two meetings later today with manufacturers interested in locating in Ontario,” said Jon Kieran, head of EDF Energies Nouvelles’ Canadian solar development arm.

Canadian developer Pristine Power has several development-stage wind projects on its books. Geoff Krause, the company’s chief financial officer, says the responsibility for meeting domestic content requirements needs to be pushed towards the supplier. “You‘ve got to require guarantees on the local content side...but it does narrow the playing field,” he says. “A lot of the foreign major suppliers in the turbine supply space are keenly aware of the domestic content rules and are looking to address that,” he adds.

With the feed-in tariff for wind at C$135 per MWh compared with the RESOP’s rate of C$125 per MWh, projected returns have moved up into double-digit territory, Krause says. The higher feed-in tariff, coupled with a strong Canadian dollar and increased competition between turbine suppliers, has made the market more attractive, in Pristine’s eyes, he says. “The combination has opened the door for us to enter into that space.”

But any developer wanting a feed-in tariff must overcome a timing problem with meeting the domestic content test, which lenders and sponsors highlight as a serious obstacle to financial close. Under the FIT Contract, the OPA does not declare whether a project fulfils the domestic content requirements until after the date of commercial operations. However, lenders want to know that the project meets the domestic content threshold before providing any project funding.

Market participants are putting pressure on the OPA to resolve this difficulty. Project teams are developing legal documents to get over this hurdle, says Jonathan Weisz, partner at Torys: “It’s a binding letter from the OPA issued at the notice to proceed stage, which confirms that if the developer complies with its domestic content plan which has been reviewed by the OPA, it will be deemed to have met the domestic content test at COD.” Produced on a project-by-project basis as the OPA scrutinises proposals, the letters should give lenders more comfort over the timing issue for the domestic content test.

Foreign developers and foreign lenders

That space is becoming more crowded, with Asian companies Samsung and Korea Electric Power Corporation (KEPCO) entering the fray. The government of Ontario signed an agreement in January with Samsung’s trading and construction arm Samsung C&T and KEPCO, to build 2,000MW of wind power and 500MW of solar power in the province by 2016. Clusters of projects are to be built throughout the province, and in the first stage, a 500MW bundle, comprising 400MW of wind and 100MW solar, is to be built by the first quarter of 2013 in the Chatham-Kent and Haldimand County regions.

Up until then, Samsung was not a major power developer in Canada, and the deal confirms the province’s intent to get industry infrastructure in place, though the size of the deal, and the way in which the Korean firms bypassed the existing development channels, caused some grumbling from other developers. But for Ontario, new manufacturing bases, and new jobs, trump these concerns. Samsung and KEPCO are to support the development of manufacturing bases, and Samsung will take care of project management, whilst KEPCO will be responsible for putting in place the transmission and distribution system. The government is to secure the land.

“Ontario has some gaps in transmission, so by knowing that there are going to be projects of material size established in certain areas, that helps Ontario allocate transmission construction budgets and focus on which lines need to be built,” says one market participant. Samsung is said to be recruiting local expertise and some developers with respectable pipelines may benefit from an inside track.

Some European banks are lending to renewables projects with tenors as long as 15 or 18 years, giving their loans a small tail before the expiration of their 20-year contracts with the Ontario Power Authority. Canadian banks are not yet comfortable with long tenors. As is the case for conventional power projects, Canadian banks look towards a miniperm structure with a view to a post-construction refinancing with institutional lenders. Life companies, however, are involved in some of the first wind deals under the FIT programme, and some of them are comfortable with construction risk. Using typical tenors of construction plus 20 years, the life companies, lending at a fixed rate, tend to group together, and European banks cannot quite match these maturities.

“We do have a strong syndicate. We typically lend around C$100 million to a project ourselves. We can probably raise up to C$300-350 million in the institutional market, without going to the banks,” says William Sutherland, head of Manulife’s Canadian project finance group. “It’s very difficult to do a dual tranche. Banks don’t really want to go out beyond 7 or 10 years,” he adds.

With the gap between tenors, banks want the life company to defer repayment for the first 10 years or so, while the bank is paid off, he says. “We won’t do that. We want to have some amortisation over the period the banks are getting amortised. And we’re not finding the banks with sufficient capacity willing to go out 15 years,” Sutherland says.

Developers in Ontario will be competing with other provinces, such as Quebec, for lenders’ resources. RES Americas (30%) and EDF EN (70%), through joint venture St Laurent Energy, won the contract to build 954MW of wind capacity in Quebec and the developer is out to market on the first of five projects which will come on line through 2015. The projects will be financed on a single asset basis.

EDF EN is the O&M operator, whilst RES is the construction contractor. “We are looking to finance perhaps half of the portfolio by the middle of next year,” says Richard Ashby, CFO of RES Americas, adding that the developer will consider all financing options. “We will potentially look at export credit agency financing as well,” he says. Germany’s RE Power is the turbine vendor, but the projects will have to fulfil Quebec’s domestic content requirements. Still, the province’s rules are clearer than those in Ontario, and have undergone more testing, following their use in a previous procurement round, Ashby says.

Gas capacity – the winners and losers

Even as Ontario’s renewables capacity competes for lender attention, a series of large gas plants also requires debt commitments. Ontario needs new gas-fired capacity to replace its coal fleet while its renewables market grows to maturity, but not all gas projects have sailed through the market. Late last month, the York gas-fired project reached close, while a B loan financing for the troubled Greenfield South project was pulled from the market.

Canadian developer Pristine Power and Harbert Power, a subsidiary of US-based hedge fund manager Harbert Management Corporation, were joint equity providers for the 400MW York Energy Centre peaking plant project. Each company contributed C$26.1 million in equity, and the project raised C$270 million in term debt from arrangers Union Bank, ING, and Royal Bank of Canada, and participants Bank of Nova Scotia, Siemens Financial, National Bank of Canada, Canadian Western bank, and Allied Irish Banks.

The banks are also providing a C$60 million letter of credit facility and C$3 million operating working capital facility, which provides performance security for the contract with the OPA, as well as transportation and equipment supplier contracts. The debt to equity ratio is 80/20, and the mini-perm debt has a tenor of construction plus 5 years. The expectation is to refinance the plant after completion with a private placement in the bond market.

Commercial operations at York, located a little north of Toronto, are to start in second quarter of 2012 and the project holds a 20-year contract to provide peaking power with the OPA. The developer purchased turbines and generator sets from Siemens, while the balance of the plant construction benefits from a turnkey contract with US firm Lill & Difazio Constructors.

The project came up against local permitting troubles, when the township did not want to approve its site plan, a required step before the release of building permits. As it studied the issue, the municipality passed an interim control bylaw, which prevented activity on the site for one year, extendable to a maximum of two years. “We appealed to the Ontario Municipal board for approval of the site plan and for repeal of the interim control bylaw, which can be a lengthy process. Instead, the Ontario Provincial government specifically exempted the project from the Ontario Planning Act,” says Pristine’s Krause. “As a result, the project can now move forward under the Building Codes Act to apply and receive the necessary building permits,” Krause says.

Eastern Power’s Greenfield South project, in Ontario, has found it more difficult to secure financing. Credit Suisse and Morgan Stanley’s $335 million B loan financing for the plant was withdrawn late in August, due to limited market appetite. If successful, it would have been the first Canadian power plant to be financed in the US dollar B loan market. The facility featured high leverage and the construction package had no full fixed-price turnkey arrangement.

The sponsor had hoped to use a B loan to bridge the deal to completion, at which point a longer-dated refinancing with a less onerous debt service schedule might have been possible. B loan lenders, however, wanted pricing that the project could not support without a lower debt/equity ratio.

The project has a 20-year PPA with the OPA, denominated in Canadian dollars. The arrangers were set to mitigate foreign exchange with a cross-currency swap, but the project B loan market is unfamiliar with the feature.

Eastern Power was providing C$69.7 million ($66.5 million) in equity, comprised of C$35.9 million in cash and C$33.8 million in in-kind contributions such as services. The financing was launched with pricing of 500bp over Libor. The sponsor, says one lender familiar with the project, has tried to keep hold of all of the project’s equity, by driving down construction costs and reaching for B loan market levels of leverage. “It would probably help if the developer was willing to accept some dilution by turning to a deep-pocketed equity investor,” he adds.

Eastern’s difficulties aside, debt pricing on renewables projects is still hovering above pricing for gas plants, says one banker. This phenomenon is evident despite the higher coverages that the higher FIT rates produce, at least for wind, although this does not fully recognise wind’s intermittency. “There’s still a premium to renewables,” he says. Gas projects might obtain debt at around 250bp, while renewables would be closer to 300bp, he says.

In late August, Northland Power Income Fund completed financial closure of its 260MW North Battleford combined-cycle gas turbine project, in Saskatchewan Province. The group of lenders is a more global affair than York’s group. A large international syndicate of 15 banks is lending to the C$680 million project, led by Canadian Imperial Bank of Commerce and the Bank of Montreal, and US-based Union Bank. The debt-to-equity is 80/20. The pricing on the loan starts at around 250bp over CDOR. The pricing ratchets up after completion to incentivise refinancing, to over 300bp over time.

The mini perm debt structure consists of a C$542 million non-recourse construction loan, which converts to a seven-year amortising loan after plant start-up, as well as letter of credit facilities for an additional C$38 million to support the project’s other obligations, which includes security under the PPA. The project is expected to refinance post completion. Making up the bank syndicate were Allied Irish Banks, National Bank of Canada, Scotia, Mizuho, Siemens Financial, Societe Generale, SMBC, TD, Bayerische, Canada Western Bank, Helaba, and Natixis.

All the banks are lending in Canadian dollars, and lending according to Canadian Deposit Offered Rate (CDOR). CDOR has been used instead of Canadian Libor as the base rate, as the borrower wanted to swap the floating interest rate exposure to fixed for the 20 years of the PPA term. “There isn’t a swap market for Canadian Libor, but there is for CDOR. So they swap in CDOR, they borrow in CDOR,” says one banker close to the deal. The choice of benchmark indicates that a growing number of foreign banks are happy to lend off the local benchmark, after a period in which the mismatch between CLibor and CDOR dislocated the project finance market, notably for PPP deals.

The PPA on Battleford stipulates that an indexed gas price, paid by the project, is passed on to the project’s offtaker, state-owned SaskPower. The EPC contractor is Kiewit, and the project will use a GE 7FA gas turbine. Construction began in May, and commercial operations are expected to start in the summer of 2013.