Description

Suncor (SU) is the largest and most liquid pure play on the Canadian oil sands. As an integrated oil and gas company, the company is also engaged in the exploration and production of natural gas and refines and markets petroleum products. In 2002, 83% of capital employed and 89% of net earnings came from oil sands, with 8% and 4% coming from natural gas, and 9% and 7% coming from refining and marketing. SU controls a vast resource base in Alberta’s oil sands, which potentially contain more reserves than even Saudi Arabia.

SU represents one of the few oil and gas producers (outside the majors) that has consistently achieved returns on capital above its cost of capital (14.6%, 17.8%, and 16.6% in 02, 01, and 00, respectively). Book value per share has grown over 10% in the 9 years ended 2002. In addition, the company has clear and achievable plans to continue growing average daily production (from 205,800 bpd in 02 to 330,000 bpd in 2007, to 500-550,000 bpd in 2010-12), another feather in its cap relative to the peer group. Lastly, the integrated nature of the company (gas production and refining/marketing beyond just its oil sands production) sets it apart from other oil sands producers.

Valuation

Given SU’s returns on capital and ability to achieve with some visibility its growth plan in the coming years, the question becomes what should one pay for such an asset. SU deserves a premium to the majors and the peer group of independent producers because of its high visibility and lack of need to explore for new replacements of resources. And, in fact, it does already get such a premium. On a P/E basis SU trades at 13.6x ‘03 and 15.9x ‘04. Exxon, widely regarded as the premier player in oil, trades above this at 15.3x and 17.8x though has achieved similar ROCE this year and last. On the other hand, RD and BP trade on average at 12.5x 03 and 14.6x 04 P/E. Thus, on this metric, assuming similar economics in the future, one might say that SU is fairly valued.
However, this does not take into account the difference in growth profiles of these companies. 10% annual growth in production for SU looks readily achievable, while the majors struggle to get much beyond 3%. SU should get credit for that. Perhaps a better way to account for the growth – a result of SU’s unique asset base - is to look at reserves per market value. As one analyst recently pointed out, SU is at 5.5 bbl of oil per $100 in market cap vs XOM at 8.5 bbl per $100…but this only counts proven reserves. By the nature of SU’s assets, the vast majority of its reserves are classified as probable, and there is good reason to believe that much of the probable reserves will be proved up once SU decides it needs to undergo the extensive assessment activity necessary for that (understandably, they haven’t seen the need for that yet). The majors do not have such a luxury. If one were to include probable as well as proven reserves, SU improves to 41 bbl per $100 in market cap. This provides a sense to the upside in this long-lived asset.

I believe the persistent fear that oil will crater to $20 has kept a lid on this stock....as SU continues to execute, and oil remains above that price, the stock should get revalued.

Positives

1. Long reserve life with little/no exploration necessary.
SU has booked proved plus probable reserves of over 2.4bn barrels at its Steepbank/Millennium mine, resulting in over 30 years of production. Firebag has over 2bn barrels of probable reserves booked, with a 22-year life assuming a sustainable production rate of 250Mbpd. The company also has additional estimated recoverable reserves of 7.6bn barrels (not yet booked), leading to a total reserve life of over 50 years – amongst, if not the highest, of any public oil company, and multiples of the average producer’s reserve life.

2. Natural hedge due to natural gas production.
Natural gas is a critical component of oil sands production. For perspective, Firebag will use 0.75Mcf of gas for each barrel produced using the in-situ process (a relatively new process - contrast with open-pit mining). In 2002, the company used 90Mcf/d in oil sands and another 20Mcf/d in downstream operations, versus total production of 180Mcf/d. Thus, the company has excess production, which allows it to profit in a high gas price environment even though oil sands production costs suffer. This excess should remain the case for the next 10 years as per management.

3. Continuous improvements in technology are driving production costs downwards.
The company is targeting per barrel costs being reduced to C$10-11 by the end of this year, and actually beat this goal in Q3 ($9.85). This compares to C$20/bbl in 1990 and C$13/bbl in 2002. Part of the reduction stems from scale efficiencies while further technological and process improvements will continue the trend. The critical next step involves in-situ recovery, which uses horizontal wells to reach the ore, heat it and bring the recoverable matter to the surface for processing. In the short-term, this process may lift costs somewhat, but as the company gains experience, we would expect a reversion to the trend.

4. Proximity to US and necessary infrastructure provides ready access to market.
Alberta’s oil and gas basins benefit from strong infrastructure links to the rest of Canada as well as to the all-important US market. SU also has a network of more than 300 Sunoco-branded retail sites (mostly in Ontario) that give it an in-house distribution channel. The company recently strengthened its footprint with the US$150mm purchase of a 62Mbpd refinery in Denver along with 43 retail gas stations and a pipeline and storage system that connects the refinery to the Platte/Express pipeline. SU management has indicated that it would continue to look at further expansion of its downstream operations to maximize the value chain.

5. Strong cash flow has materially improved the balance sheet.
SU generated C$1.4bn in CFFO versus capex of C$877mm in 2002. Its debt-to-cap stood at 44% at YE 2002 (vs 53% in 2001), but more importantly, net debt was only 2x CFFO last year. The company’s goal is to maintain debt at 2x CFFO at a WTI price of US$20. Delevering has continued in 2003 and should not deteriorate significantly when higher capex is spent in 2004 and beyond (and to the extent oil prices remain high, SU becomes a cash cow).

Risks

1. While production costs are coming down, they do have the tendency to surprise on the wrong side.
Oil sands producers, and SU is no exception, have tended to unfavorable surprises most often with productions costs being higher than anticipated (but also with respect to project cost overruns). In recent months, the excess has been a result of high gas prices (offset by SU’s own production). Going forward, given the adoption of the new in-situ recovery process, it would not be too surprising to witness evidence of growing pains through production costs that fall slower than we currently assume.

2. The company has exposure to R&M margins, which in the short term can be independent of crude/gas fundamentals.
While over the longer term upstream and downstream margins tend to move in opposite directions with changes in crude oil prices, we have witnessed volatile short-term movements in prices/margins that are driven more by regional forces such as storage and refinery capacity. SU has exposure to this volatility, however it is relatively small relative to the actual oil sands operations.

3. High capex requirements to bring expansion online in coming years.
SU has announced plans that detail their anticipated expansion. With Firebag Stage 1, the company has completed 80% of a C$600mm project, and for the second part of that stage, the vacuum tower, construction is estimated to be 20-25% complete (of C$400mm). First production should add 35Mbpd of production capacity (vs 206Mbpd produced in 2002) in late 2004. Voyageur Phase 1 is the next major project and will likely entail C$3bn in expenditure over the 2004-07 timeframe (split into two components). This will likely take the company to 330Mbpd, with the company’s ultimate goal being 500-550Mbpd by 2010-2012.
In 2004, the company will spend $1.7bn in total capital expenditures (oil sands, natural gas, and downstream).
As intimated above, capital cost overruns are unfortunately common in oil sands development (eg as in SU’s recent Millennium project). That said, SU has done well with other recent projects.

4. Risk that falling crude prices could hurt margins.
As a result of SU’s relatively fixed cost basis, the company obviously enjoys higher rents the higher crude prices are. To the extent prices fall, SU stands to be hurt proportionally more than other traditional producers, most who have the wherewithal to scale back projects or take advantage of likely lower service provider costs. That being said, the company takes a smart approach to hedging, with a goal of selling 30% of its production at US$21 or better to ensure annual cash flow of C$1bn to fund growth initiatives.

5. Canada’s adoption of the Kyoto protocol may also hurt costs in the future.
The company currently estimates cost of compliance at $0.20-0.27 per barrel. While not a material amount, this is a very preliminary estimate, and the government’s decision has to date generated much debate regarding its long-term effects on Alberta’s oil patch (anywhere from little to disastrous).

Some further color based on a recent visit to the oils sands facilities with management:

The hedge provided by the company's natural gas production is important to this story and sets SU apart from other producers. It turns out, though, that SU does not use any of its own production at its oil sands operation or refineries (it actually sells it into CA and Chicago). Because of locational differences, ie eastern vs western Alberta, there is sometimes a very small differential. While immaterial today, this could in time actually be a positive for SU to the extent the Mackenzie Delta pipeline comes on in a reasonable timeframe, ie more supply in the region could create a differential that is favorable for their oil sands production.

Currently, the company's production is all open-pit (ie they mine the sands), while the upcoming Firebag expansion is SU's first in-situ project (ie utilizing horizontal pipes to draw the oil out of the ground - typically used when the overburden in too much). The technology they intend to use is called steam-assisted gravity drainage (SAGD) and requires more natural gas than traditional mining projects. At a $3.50 NYMEX gas price, the cash operating costs of the two techniques are the same, but for each $1 increase, cash costs of SAGD go up 50c (higher than mining's sensitivity). One mitigating feature at Firebag though is that its new steam units will have dual-fuel capability (ie natural gas AND low-sulfur resid) providing important flexibility.

Step changes in technology are one approach to improving the cost structure of oil sands production. For example, the move to truck and shovel from bucket-wheel extraction saved C$4/bbl. Two different approaches can further reduce cash operating costs. The first, for open-pit, entails moving the extraction system (ie the machines that separate the oil from the sand) to the mine-face, especially as continuous production moves the oil sands farther away from the processing facilities (causing amongst other things longer trips for the massive trucks they use). The second, for in-situ, involves the use of chemical solvents to reduce their dependence on steam, resulting in less nat gas usage. The company continues to reearch both of these.

SU has been forthright in saying that they intend to purchase more refining : SU wants 50% cover on the eventual 500-550,000 bbls/d it intends to produce, ie refining capacity of 250,000 bbld/d. Given that they are at ~132,000 bbld/d today, we would expect at least one more acquisition over the next 5-8 years. [Bitumen, which is extracted from the sands, costs about $7 to transport the upgrader, and would only receive about half of the WTI crude price. Upgrading costs ~$2.50, and the resulting product receives a similar price to WTI. This math drives SU's strategy in going downstream.]

With respect to marketing (ie gas stations), mgmt does not really like the business, but they run the stations to ensure their refiners remain at capacity. The returns on capital are much lower in this business, and they would in fact sell the stations if they could find another way to ensure the refineries were full. While they have yet to see any pressure from the WMTs of the world who are starting to use gas stations as a loss-leader (a problem for the US players, not yet an issue in Canada), the flip-side to such a competitor is that their presence would drive more business at the refiner level (offsetting some of the loss at the actual stations).

Catalyst