Alberta's oil sands have made Canada into an influential producer of oil and gas. By 2025 Dominion Bond Ratings Service predicts that Canada could be the world's third or fourth largest oil producing country, and over $100 billion could be invested in its oil sands over the next 10 years. On 2 October, for instance, ConocoPhillips announced a 50/50 partnership with EnCana Corporation to create an integrated North American oil business. The upstream partnership will consist of EnCana's Forest Creek and Christina Lake projects in Alberta's Athabasca oil sands.

The market is either hot or already overheated, depending on which participant is canvassed. In either case the market's pace of activity is causing problems for developers as each competes with the next for labour, materials, resources and technology. The threat of scarcity of these vital components is leading to cost overruns and delays, and threatens lower and later returns to investors in already expensive projects. In the circumstances developers, much like their counterparts in US power, are looking to B loan structures as the flexible friends in getting their projects up and running.

B is for bitumen

The term B market has been the popular option for recent oil sands project financings. In April, MEG Energy closed a $750 million term B financing of its Christina Lake oil sands project through Lehman Brothers and Credit Suisse. It was able to gain blended pricing of 150bp over Libor over two facilities split equally between drawn and undrawn facilities, and rated at Ba3 by Moody's.

Then on 17 May OPTI Canada closed a seven-year, $450 million B loan financing that retired an existing bridge loan for its Long Lake project and provided it with some funding for future oil sands development. Lead arranger on that deal was RBC Capital Markets, while the syndicate included Toronto-Dominion Bank, Royal Bank of Scotland, Bank of Nova Scotia and BNP Paribas. That deal gained ratings of BB+/Ba3 (S&P/Moody's), and priced at 175bp over Libor.

And new kid on the block, Connacher Oil and Sands, is currently finalising a $180 million term B financing to aid development of phase 1 of its Great Divide project through BNP Paribas. Connacher is looking for a term loan maturing in 2013 and an additional $15 million working capital facility due 2011, and has gained a BB-/B1 (S&P/Moody's) rating on the debt

Robert Mason, a managing director at TD Securities, says that "this year we've seen the US term loan market opening up significantly. It's willing to be more aggressive than the project bank market is, and especially when it comes to funding non-integrated projects, that is, those without an upgrader". Upgraders use an expensive and energy intensive process to turn bitumen, the raw product of an oil sands project, and turn these into light synthetic crude.

OPTI, an integrated producer, took its Long Lake deal to market at a good time. It was, according too one observer, "well positioned on the yield curve was and appetite for term loan Bs at the time was high – there wasn't that much B-loan activity in the market." B loan investor interest was at a peak, and projects benefited from press coverage in the US, which stressed the size of the Canadian reserves and the relative friendliness of their owners. Likewise, MEG went to market at 225bp over Libor, and then decreased its pricing to 200bp over Libor, again because of demand.

It will be difficult to replicate these margins, because the B-loan market has cooled off in recent months – the result of a larger number of more projects approaching it and less B-loan money sitting on the sidelines. Moreover, the financial press has been flooded with poor news from the sector of cost overruns. According to the observer, "oil isn't at $70 any more. A little bit of the bloom has come off the rose but there are still some good opportunities for B loans". So still the borrowers keep coming.

Richard Borden, a partner at MacLeod Dixon, considers their attraction to stem from the B loan's flexibility. "The product's structure is attractive because it means longer term money at attractive rates for sub-investment grade companies," he says. "You also don't have the problems associated with fixed-rate financings, where debt can't be repaid without a large whole premium. Seven years is a long time and things change, so if a developer needs to go back and make changes to a fixed-rate placement it's difficult to do so without getting his cheque book out, since these investors do not generally want to have to deal with amendments, and know these types of loans are hard to repay because of make-whole premiums associated with them." Term loan Bs are floating rate with generally minimal or no prepayment penalties attached.

Oil sands producers' access to finance markets depends on them securing adequate ratings from the ratings agencies – Dominion Bond Ratings Service, Moody's and Standard & Poor's. They have usually been able to oblige, based on fact that even in a low commodity environment there is little material risk of loss in the event of default. Says Esther Mui, senior vice president at DBRS, "Given the huge recoverable resource base, existing projects have seen full recovery of capital costs even in low-pricing environments".

The term loan B market and its ratings are more focused on oil sands producers' likelihood of default, and less on the volatility that non-integrated projects can have in terms of cash flows. Non-integrated projects are subject to the volatility of differentials between the price of bitumen and heavy oil or natural gas prices. Says Mason, "Depending on how each of the various commodity prices and exchanges rates are performing, non-integrated projects sometimes make lots of money and sometimes less, or even find themselves cash-flow negative for brief periods, as we have seen in the past few years. This has historically kept the project bank market away from non-integrated projects. With higher oil prices in the past few years, and the position that rating agencies have taken regarding the low risk of loss on default, given the huge resource backing these projects typically have, the bank market is now probably more willing to look at non-integrated projects than it has done historically, but it's not yet as aggressive as the B loan market".

Small but perfectly formed?

Connacher Oil and Gas is the latest and smallest developer to opt for the term B market. BNP Paribas was due to close this $180 million facility as Project Finance went to press, and will use the proceeds to repay $51 million in debt associated with its March acquisition of Montana refining assets and also finance the development of its Great Divide oil sands project in Fort McMurray.

Richard Gusella, president and CEO Connacher, is thankful the company "Acquired most of our acreage in 2004 before the thundering herd came in." Looking to hedge itself from several angles, Connacher acquired the Montana refinery and a natural gas company to aid its operations and notes that "being in the refining business all of a sudden isn't quite the dog it used to be. Morgan Stanley just called the present the 'golden age of refining'". A B-loan structure was a favourable choice for Connacher since, "the most important part of this debt is that it has term to it. We do have covenants to comply with but I'm not looking at the gun to my head like you would be with short-term bank debt. And we do have a 25-year asset here, with the potential to expand".

While it is a smaller developer, Connacher can still raise cost-effective financing, as long as it can persuade lenders and agencies that its credit rating is reviewed differently. "There's probably a better chance of us paying back debt as a small developer if we got into difficulty in the oil sands business than a big guy who will back away from it. Great Divide is important to us as it is our biggest asset – there's an implied guarantee if not an overt or real guarantee". Similarly Connacher has mitigated some risk by virtue of its location. "We didn't run a pilot – this is small-scale commercial. But we're not building anything but the tanks onsite. There's a highway running through our site so we mitigated some cost overrun risk – we can get what we need there easily and can build anywhere so we avoid McMurray madness".

Nevertheless, Connacher's debt facility has been rated B1 by Moody's, slightly lower than its peers, and its pricing will likely be around 300bp+, thinks Gusella, possibly reaching 325bp, but not any higher. But Gusella sees this deal as a little different from the rest: "This transaction is a little variation on a project financing, in that the assets that are collateralised are oil sands projects and our refinery, which is an active business kicking out current cashflow at a fairly attractive rate. We have been able to expand the refinery's capacity. We've drawn a ring around the collateralised assets, which provides the lenders with security, and we have a provision to expand our envelope by $150 million as well".

Gusella says that Connacher is comfortable as a smaller player. "We're not 100,000 barrel per day guy. We have 10,000 barrels per day projects; we've scaled up from 5,000 barrels and we're comfortable with that. If you come into the business trying to do 100,000 up to 500,000 barrels you're going to leave a little blood on the table". But there are risks associated with being a smaller producer: "There are three or four major risks the little guy in the oil sands has. The first is differential risk, which is why we bought the refinery, the second is the operating cost risk associated with natural gas costs which is why we bought the LUKE gas company, the third is balance sheet risk, and that's where a small guy can't afford to wait a long period of time. But we have a lot of equity and I believe you can never be over-capitalised in the oil business".

Nevertheless, having a smaller balance sheet requires a business strategy that is a little more diverse than some of its peers. "Connacher can't afford to go through periods of low or no cash flow. We're not Nexen or Petro-Canada, we're a $800 million company and we can't afford to be exposed to all the risks that are associated with being an oil sands company, and then face receiving low or no cash-flow after we have converted assets into production. We bought a refinery in Montana, closest in US to the oil sands, and if we want to we can move our oil to that; this mitigates differential risk. We also bought a gas producer because gas is the single most important component of our operating costs – our operating costs are $8-$10 per barrel, but 80% of that is natural gas, and while we may never refine a single barrel of our production we're physically hedged, and we may never burn a single molecule of our gas, but we are least selling equal or greater amounts of natural gas into the market place the same time as we're buying it. So we have a physical hedge".

The larger producers can present themselves in a more straightforward fashion to ratings agencies. According to Esther Mui, a senior vice president at Dominion Bond Rating Service, "In the case of Nexen, which already has existing production, we would look at the impact of the oil sands project on the rest of its operations. Regarding projects such as OPTI, we would assess the project itself – how much proven reserves are in the ground, and the project economics, including capital cost, financing structure and ongoing operating costs versus the price of oil. If the cost of the project is too high, there isn't much room for debt repayment. The percentage of financing based on debt to capital is a key consideration. Generally we would prefer more capital than debt for a more favourable rating as this would reduce the burden of debt-servicing. Regarding reserves, we usually don't attach much value to recoverables as these are not considered as commercially viable. We focus on the proven reserves, which are commercially viable to extract, based on current technology. In addition the experience of the management team is a key consideration."

Escalating cost overruns – par for the course?

But the single biggest issue for Canada's oil sands developers is the potential for cost overruns. With development taking place in one single concentrated area of Alberta, competition is fierce, delays are frequent and prices are increasing. Says one banker active in the market, "Western Oil Sands ran into overruns with its base project; the original number two years ago was $4 billion, 6 or 8 months ago it was $8 or $9 billion and now that has increased to $11 billion. Costs are going up by the moment, caused by international and local issues; raw material costs globally and the superheated market in Alberta – costs are going up for everyone, especially in Fort McMurray. Labour costs are high – there are so many projects and only so many people to work on them; it's more or less a worker's market in terms of what he or she can charge".

Connacher's Gusella has also experienced some cost increases, but is undaunted. "Since we first estimated, our costs have gone up around 15%. We've seen a creep of 1-1.25% per month, but that's mainly in the drilling sector, we fixed our prices in other areas."

This phenomenon is good for ancillary businesses located nearby, but simultaneously creates problems for the oil sands companies that then have to figure out how to pay suppliers. Says Borden "even if you've arranged a certain amount of financing, you still need to make sure you can then arrange more financing. Typically companies want to avoid diluting themselves by raising additional equity. Financing structures have to have the flexibility to allow playing around with more types of debt". Here, in particular, MEG's delayed draw structure offered tangible benefits.

Cost overrun can be mitigated, since investors are now well able to understand it. For instance, financings are usually structured with generous, if expensive, cost overrun buffers, and investors ask that developers maintain this buffer throughout the life of the project, providing certain coverages until project completion. In some cases developers over-fund equity or, as in OPTI's case, raise contingent equity. OPTI could not raise a commitment from its large institutional shareholders that they would fund additional equity for cost overruns if and when needed and if OPTI can't raise the equity in the public market. Nevertheless, some projects have been put on hold because of concerns about spiralling costs. This is frustrating, but as Borden stoically points out, "the resources aren't going anywhere".

And Mason does not believe the cost overruns have the potential to affect the industry substantially. "Interest isn't cooling. The cost overrun risk is factored into credit analysis and structuring of the deals now."

Living at lower levels

If cost overruns have not deterred development at present, though, recent price declines may. Mui notes there are three limiting factors to the attractiveness of oil sands projects "cost pressure, overcrowding and if oil prices go down". Oil has edged below $60 per barrel after nearing $70 in recent months. The prices are still well above the levels required for producers to break even, and some projects were active even as the price of crude hovered around $20.

But these issues are a concern for developers big or small. Gusella notes, "Our operating costs are 20% to 30%, depending on where oil prices are, and gas prices move in conjunction. The worst of all worlds would be very low oil prices, very wide differentials so you get a low price for your bitumen, and very high natural gas prices – that's the perfect storm that can do you in if it is protracted".

On the upside, the royalty structure remains attractive in Alberta. A minimal royalty is charged until such time as capital costs have been recovered, after which it is increased to around 25%. Originally this scheme was put in place to encourage resource development, and this goal has undoubtedly been successful. But the oil sands industry is so active that the pace of development has led some politicians to question the present structure of the royalty regime. Several have suggested that it should be revised. The market is waiting to see whether the revised regime would be applied only to new leases, or also to existing leases. The second scenario is unlikely, say market participants, but the debate is only the latest sign of an industry plainly a victim of its own success.

But still the new entrants come. North American Oil Sands, owned by Paramount Resources, ARC Financial and the Ontario Teachers' Pension Plan Board, is planning a C$7.5 billion ($6.7 billion) oil sands project and upgrading plant in the province. It has recently had to shake off the suggestion that it might find it difficult to compete with merchant upgrading projects, and aims to reach a capacity of 160,000 barrels per day by 2015, by using the steam-assisted gravity drainage process. It will settle on a site for the upgrader shortly.