Even Energy Companies Feel the Pinch
Consumers aren't the only ones sweating higher energy prices. The escalation is also weighing on the operations and finances of companies in the exploration and production (E&P) and refining categories. While it's likely oil prices will remain volatile, rising and falling on each day's headlines, Standard & Poor's Ratings Services believes they are cycling around a rising trend. That's because global demand for oil continues to climb, but its supply is rising only slowly.
As a result, even some E&P companies face a sometimes difficult balancing act. For example, companies that extract crude from Canada's oil sands are rapidly expanding development to take advantage of the higher oil prices, but they also face fast-rising capital spending requirements and increasing competition for equipment and skilled labor.
For refiners, dependence on oil as their primary feedstock has meant that the pricier oil gets, the thinner the margins on their refined products. Part of the margin problem results from a slowing U.S. economy that's keeping refiners from passing on their higher costs to consumers. Adding to the squeeze on refiners is the large amount of ethanol in the fuel supply and high natural gas prices.
Still, strategies exist in both camps to make the best of a tough situation. Suncor Energy (SU; S&P credit rating, A-) and others in the Canadian oil sands sector are trying to increase cash flow to cope with rampant development cost inflation. And Valero Energy (VLO; BBB) is one refiner that has fared better than many of its competitors because it has been able to more efficiently make end products from cheaper, lower-quality grades of crude and shift more output to higher-margin fuels such as diesel. It's also employing initiatives that reduce capacity, further improve operating efficiency, and conserve liquidity.
Exploration & Production
In Canada, rising crude oil prices have had several effects on companies' development plans and government regulation of the industry. Nowhere is this more evident than in the Athabasca oil sands region. The Alberta government's April 2008 estimate of oil sands projects either recently completed or in progress is now about C$163 billion—up from just under C$68 billion in 2005.
The accelerating development, both from longtime oil sands operators and new entrants, is directly linked to the runup in crude oil prices. These capital-intensive megaprojects still provide attractive returns, despite rising development costs. The Canadian oil and gas companies sponsoring these projects say they can satisfy their internal investment hurdles, despite rampant cost inflation and increasing labor productivity issues. Furthermore, even the Alberta government's 2007 decision to adjust its oil and gas royalty framework to more closely align royalties with current prices and the changing production mix have not slowed oil sands development plans.
Despite the strong credit attributes associated with the oil sands' massive resource base and steady long-term production profile, two factors, capital costs and labor productivity, are adversely affecting near-term credit quality. Increasing activity in Alberta's oil sands region is resulting in higher project development costs, which ultimately could put pressure on ratings. The breakeven crude oil price (including required investment returns) has risen to between US$60 and $80 a barrel today, up from about $35 a few years ago. As the fully levered breakeven price increases, the risk of credit profile deterioration during project construction also increases.
Oil Sands Assets
Given the accelerated development of oil sands projects, capital costs are rising as companies compete more strenuously for scarce materials and labor, and manage the increasingly complex logistics associated with building these projects in Alberta's remote Athabasca region. As a result, cost estimates for integrated oil sands projects (including the upgrading complex, which acts as a partial refinery and converts bitumen into a synthetic light crude oil) are now almost three times the cost of earlier projects (developed less than 10 years ago). For example, the cost estimate for Suncor's Voyageur project, announced at the end of January 200, is C$20.6 billion. To see how much costs have inflated, just compare the current Voyageur estimate to Suncor's actual final capital cost for the 1999-2001 Millennium expansion project of C$3.4 billion.
Faced with accelerating cost inflation, yet reluctant to abandon their strategic oil sands growth initiatives, Suncor and other participants have brought much of the engineering and procurement capabilities in-house, and are increasingly looking outside of Alberta and Canada for labor. Nevertheless, the increasing number of oil sands projects now means longer lead times between ordering equipment and delivery. In addition, the sector's new and less experienced labor force has lower productivity and higher labor costs, which can account for almost half of the total project cost.
Although oil sands participants are realizing record cash flows from the continued strength in crude oil prices, those elevated flows do not entirely offset the risks associated with developing an oil sands complex. As a result, Standard & Poor's recently revised its outlook on Suncor to negative, following our review of Voyageur's effect on the company's credit profile during the construction period. We had taken similar rating actions on other oil and gas companies (for example, Canadian Oil Sands (COS_U) and Canadian Natural Resources (CNQ), based on the heightened risk of financial profile deterioration as they developed their oil sands assets.
While we acknowledge Suncor's recent track record at keeping its development costs at budgeted levels, Voyageur's size and scale heighten the company's exposure to capital cost increases. If these costs remain at current estimates, crude oil prices will have to stay fairly high during the Voyageur construction to temper balance-sheet deterioration. Our decision to revise the outlook reflects our view that the near-term risks of cost overruns or weakening crude oil prices outweigh the long-term benefits associated with the oil sands' large resource base and robust cash-flow profile.
A year ago, a combination of tight capacity, strong demand, and periodic disruptions created what some industry observers called the golden age of petroleum refining. Few would describe current conditions so favorably. Refiners, which use oil as their primary feedstock, have been hit hard by the rising cost of crude. Prices for refined products such as gasoline and diesel tend to be sticky, meaning that go up and down more slowly than the price of oil, resulting in margin contraction for refiners when prices are rising.
The magnitude of the rise in oil and the softness of the U.S. economy have combined to reduce fuel consumption, making it especially difficult for refiners to pass along the full effect of expensive oil to their customers. Margins for gasoline and residual products, such as asphalt, have been especially poor this year, while diesel and other distillates have been relative bright spots. The price of oil rose more than 100% during the past year, but gasoline is up less than 50%, with refiners absorbing the difference in the form of lower margins. The addition of ethanol into the fuel supply has contributed to weak gasoline margins. Mandated ethanol use in the U.S. is now almost 600,000 barrels per day (bpd), which is about 6% of gasoline demand or the equivalent of about six large refineries' gasoline output. High natural gas prices are another factor lowering profitability, since it is a large contributor to operating costs.
Valero Is Faring Well
Valero, which accounts for about 15% of total U.S. refining capacity, has so far fared better than many of its competitors. The company's earnings fell by 77% compared to a year earlier in the first quarter, to $261 million, in contrast to a number of peers that posted losses. Margin contraction accounted for most of the decline. Benchmark gross margins fell by 25% in the U.S. in the first quarter of 2008 because of poor market dynamics for gasoline and residual products. In addition to lower profitability, the increase in crude prices means greater working capital demands. Valero, which buys nearly 3 million bpd of oil, posted $1.6 billion worth of letters of credit at the end of the first quarter, double the amount at the end of 2007. Companies rated below investment grade face tighter credit terms and, in some cases, must prepay for crude.
As one of the largest and most sophisticated refiners, Valero has a number of advantages over other companies in the sector that are losing money. It operates primarily large, high-conversion facilities with logistical advantages that can produce high proportions of clean fuels from low-quality crudes, such as heavy or high-sulfur grades, that trade at discounted prices. Other refiners with smaller, less-efficient and -sophisticated plants produce larger amounts of residual products that sell at low prices, and have less flexibility to switch products and feedstocks. A large component of Valero's output is ultra-low-sulfur diesel, which has been one of the few healthy areas of profitability this year. Growing demand from Europe, which is undergoing a shift from gasoline vehicles to a diesel-fueled passenger fleet, is supporting very strong diesel margins that partially offset the weakness in gasoline and other products.
Valero is adjusting both its operating and financial behavior in response to poor market conditions. The company cut back on gasoline production in the first quarter because of thin margins and is maximizing diesel production, shifting about 100,000 bpd of output from gasoline to diesel. Valero is also accelerating maintenance that requires equipment downtime, taking capacity off-line now to be ready in case margins improve.
Longer term, Valero has shifted away from capacity expansion and toward improving operating efficiency. A five-year plan targets $1 billion of operating profit improvement per year, derived from gains in equipment reliability and lower energy use. Less unplanned downtime contributes $550 million of the improvement and energy efficiency another $250 million.
In a departure from its history as the most aggressive consolidator in the industry, Valero sold two refineries in the past 12 months, and is considering selling several more. The divestitures will likely improve the company's overall operating performance and eliminate the need to make expensive investments to upgrade the facilities.
On the financial side, Valero is conserving liquidity in response to reduced cash flow and increased working capital needs, but it remains committed to share repurchases. The company ended the first quarter with ample liquidity, including an undrawn $2.5 billion credit facility and $1.4 billion in cash. A further runup in crude prices, however, would result in an additional increase in working capital. The business is also generating less cash to fund ambitious investment plans.
In response, Valero is deferring spending on major projects, reducing its capital expenditure budget for 2008 to $4.2 billion from $4.5 billion. Without margin improvement, planned capital spending and dividends of about $300 million will likely exceed cash flow in 2008. The company reduced its level of share repurchases but still bought back about $500 million of stock in the first quarter.
The Bottom Line
Clearly, escalating energy prices aren't necessarily a huge windfall for everyone in the oil and gas industry. In E&P, the winners will more likely be the ones that can manage their budgets and labor costs to keep rising expenses from wiping out their higher cash flows. At the same time, refiners that are nimble enough to switch away from lower-margin fuels and capacity expansion will likely reap greater rewards when market conditions improve. Still, continued market volatility and economic stresses could weigh further on these companies and their ratings.