15 November 2004 00:01 [Source: ICB Americas]
While crude oil prices dipped below the $50-per-barrel mark last week on strengthening of US inventories, the near-term energy outlook shows continued upward pricing pressure from both crude oil and natural gas. Crude-oil pricing will stay in the upper end of the $40-per-barrel range next year, while natural gas pricing will remain above $5 per mmbtu for the next several years, energy analysts project. With increased pressure on energy sources, finding ways to manage energy volatility is becoming increasingly important for chemical companies.
US spot prices for crude oil (West Texas Intermediate (WTI) have ranged from under $49 per barrel to over $56 per barrel over the last several weeks, according to the US Energy Information Administration (EIA). The projected average WTI price for the fourth quarter of 2004 is just over $51 per barrel, about $20 per barrel higher than the price in the fourth quarter of 2003 and about $5 per barrel above the EIA’s earlier projection for the fourth quarter.
WTI prices moved up sharply in October in part because of production losses in the Gulf of Mexico resulting from Hurricane Ivan. In early October, about 500,000 barrels per day of Gulf oil output was shut in; this situation improved to about 200,000 barrels per day in early November, says the EIA. “Considering the strong demand growth seen this year and expected in 2005, US oil inventories and inventories in the other industrialized countries remain relatively low compared to historical standards,” says the EIA.
“Given this, together with limited prospects for large increases in production from outside the Organization of Petroleum Exporting Countries (OPEC) in the near term, oil prices are expected to remain elevated in the mid- to high-$40s range through 2005, even though OPEC crude oil production remains high at about 30 million barrels per day,” says the EIA. OPEC production capacity remains about 0.5 million to 1.0 million barrels per day above current output levels, an implied global utilization rate of about 99 percent.
World petroleum demand growth for 2004 is projected at 2.8 million barrels per day over 2003 levels, reflecting 3.5 percent growth over 2003. Global oil demand growth is expected to slow to 2.4 percent in 2005 as global economic growth slows toward more sustainable rates, influenced in part by high world oil prices. US petroleum demand is projected to average 20.4 million barrels per day this year, up 2.0 percent from last year. In 2005, demand growth is projected to slow to 1.0 percent as a result of moderation in economic growth and continued high energy prices, says the EIA.
On the natural gas front, energy analysts point to continued upward pricing pressures. “It is clear that, without measures to boost supplies or temper demand, the market is locked in a strong price environment,” says Daniel Yergin, chairman of Cambridge Energy Research Associates (CERA). “Natural gas prices today have spiked to triple the average of the 1990s, and that is signaling what is ahead.
“The challenge lies between now and the arrival of substantial new volumes of LNG [liquefied natural gas] on North American shores,” Mr. Yergin says. CERA projects that a tightening of the balance between supply and demand could lead to even higher and more volatile prices for North America. “An event as simple as an abnormally hot summer or cold winter could push prices well above recent levels, to the $6.50 to $8 per mmbtu range in the summer, and above $10 per mmbtu during a particularly cold winter,” he says. “This is exactly what Hurricane Ivan has done.”
He points to four key areas that would enable the US to manage natural gas demand and exposure to price volatility during the bridge period of 2004 to 2009, including:
• Effective customer education and flexible gas procurement mechanisms by utilities;
• Fuel flexibility for new and existing electric power capacity;
• Resolution of the mismatch between the short-term contracting bias of consumers and the need for longer-term commitments to underpin new natural gas infrastructure, such as Arctic and LNG supplies; and
• Acceleration of gas production in the near term by streamlining permitting for activity and applying flexibility.
“The challenge is before the industry and regulators and policymakers and indeed the nation—to manage a difficult market environment over the next several years while new supply arrangements can be made,” says Mr. Yergin.
“Comparison of the US natural gas demand imperative with the supply out-look creates a stark picture,” accord-ing to Mr. Yergin. Demand is set to con-tinue to outstrip continental supply, and the gap is on track to widen.
“The reason we are in a crisis is not that demand has surged, it is that supplies are stagnant,” Mr. Yergin notes. “In the lower 49 US, we have not been able to increase gas production for a decade.” Productive capacity peaked at 55 billion cubic feet (Bcf) per day in 1994, and has been creeping steadily downward, presently to 50 Bcf per day, notes CERA. In recent years, Canada has become a major source of natural gas, supplying 16 percent of current US consumption. However, Canadian production has flattened in recent years, and CERA expects only modest growth in Canadian production over the next several years which, combined with growing Canadian demand, translates into declining exports to the US.
“There is strong evidence that simply adding more drilling rigs will not solve the problem, as it has in previous decades,” Mr. Yergin says. He points to the experience of 2001 when the gas industry responded to wintertime price spikes by putting over 1,000 rigs to work, compared with 700 rigs the previous year. This led to a surge in activity yielding less than a 4 percent increase in US production, which eroded the following year. In 2004, onshore drilling has returned to record levels, but CERA expects US gas productive capacity to fall from 2003 levels. “North American natural gas productive capacity is not expected to grow meaningfully, and US gas productive capacity, like oil, is now in permanent decline,” he says. At the same time, demand for natural gas is expected to increase as a result of higher consumption by electric power plants. In recent years, almost 200,000 megawatts of gas-fired power plants has been installed, equal to one-fourth of the country’s total capacity in 2000. With these plants in place, demand for natural gas will grow steadily as economic growth inevitably pushes usage up. “With supplies unable to grow in the near term, power demand is squeezing price-sensitive industrial demand out of the market, with negative consequences for competition and employment in gas-intensive industries in the US and Canada,” Mr. Yergin says.
“Unfortunately, CERA expects that natural gas demand growth in the power sector will come at the expense of more constrained industrial sector consumption—what is described as ‘demand destruction.’ Indeed, industrial consumers are already examining off-shore locations for new plants,” Mr. Yergin adds. This compounds a problem already existing in industrial markets hard hit by higher natural gas prices such as the ammonia-based fertilizer industry, petrochemical industry, pulp and paper industry as well as primary metals such as steel.
“By contrast, many parts of the world are awash with gas,” he says. “Outside North America, global natural gas reserves are growing. Projects are now underway to bring these new global resources to North America in the form of liquefied natural gas. And there are huge quantities of stranded gas in Alaska, and gas as well in the Canadian Arctic.”
CERA projects that the bulk of North American supplies in the next decade and a half will come from continued exploration and production in North America, with LNG playing an important role as the third major supply source after the US and Canada. LNG provides roughly 3 percent of US supplies. By the year 2020, that share could be 25 percent to 30 percent, he says.
However, the soonest LNG could provide significant price relief is 2008, with 2009 a more likely date, based on the long lead times in developing natural gas and supplies from the Arctic. In addition, gas from the Canadian Arctic could reach the market by 2010, and Alaskan gas will not arrive until well into the next decade.
CERA projects that upward pricing pressure for natural gas will remain, with prices over the next three to four years to exceed $5.00 per mmbtu. “With upward pressure from demand, prices are performing their essential function—signaling the change in conditions to both producers and consumers. Prices for the next three to four years are expected by CERA to exceed $5.00 per mmbtu, more than double the levels of just a few years ago. These prices are adding to the burdens of consumers and shifting the competitiveness of key industries that depend on natural gas. Yet it is important to understand that producers have limited ability to significantly increase gas production in the near term without access to new sources and new areas,” says Mr. Yergin.
For chemical companies, strategies to manage energy volatility are becoming increasingly important. “The cost structure has changed in recent years and is unlikely to return to a more positive environment in the near term,” says David Traylor, principal with Deloitte & Touche LLP’s global energy markets practice, who spoke last month at the Strategic Sourcing Summit & Showcase sponsored by the Supply Management Committee of the Drug, Chemical and Asso-ciated Technologies Association (DCAT) and the Chemical Group and Pharma Forum of the Institute of Supply Management. “Recent significant changes in the process/chemical industry present new challenges and opportunities for the process industry, such as increased US and global energy consumption, changing regulatory environments, the demise of larger energy trading shops, new energy market participants and existing players with evolving structures.”
Companies in a short energy position have two goals for their cost management program: volatility management and least cost. “Managing volatility seeks to smooth, over time, the costs associated with commodity procurement, and implies a lower risk-tolerance since budgets can be more accurately forecasted,” explains Mr. Traylor. “Un-der a least-cost principle, there is an acceptance of price volatility in an effort to procure energy at the least cost available in the market for a given period of time. This strategy implies a higher risk-tolerance since volatility is likely to be greater,” he explains.
“The pursuit of volatility management or least-cost strategies is accomplished through three methods: hedging, arbitrage and floating with the market,” says Mr. Traylor. Each option has degrees of risk and complexity (Figure 1, p. 22). The lowest-risk approach is hedging, the complexity of which varies, depending upon the instruments and strategies chosen. “The least complex hedging involves physical and simple financial instruments,” explains Mr. Traylor. “For example, exchange-trade futures may be used if long-term physical supply contracts are not economically available. Swaps, which convert existing floating-price contracts to fixed-price transaction by swapping floating-cash flows for fixed with a third party, can be used to accommodate changing market bias.” If the correlation between finished product price and energy commodity cost is high, simple hedging may be achieved without further hedging transactions, he notes.
Advanced hedging is used when a more customized approach is required. “Unlike simple forward purchasing, the use of more advanced financial instruments allows for the flexibility to fine-tune to specific strategies and cost management within a band of acceptable prices,” says Mr. Traylor. The instruments that can be used are combinations of physical forwards, futures, swaps and options that allow for more customization while introducing infrastructure requirements to properly control transacting activities.
Another tool, arbitrage, relies on having value extracted from owned or contracted assets and/or market knowledge. “Arbitrage opportunities exist in markets when all participants do not have the same information and/or access to market value assets at the same time,” says Mr. Traylor. An example is natural gas storage optimization, where the value of the storage asset may have significantly more value than just a means of physical delivery.
Whatever route is taken, in order to maximize program effectiveness for energy procurement, all energy-related financial risk factors affecting the company must first be identified, and then a business plan must be drawn up that supports the necessary investments for an energy procurement plan. “But the key,” says Mr. Traylor, “is to remain objective in your approach. Avoid becoming enamored of an approach that is unresponsive, and avoid decisions based on short-term events. It is important to remain properly aligned with risk tolerances. For example, a more risk-averse approach may mean that you will not always achieve the lowest price, but if mitigating risk is the top priority, that is the result that you know and plan for.”
For the latest chemical news, data and analysis that directly impacts your business sign up for a free trial to ICIS news - the breaking online news service for the global chemical industry.
Get the facts and analysis behind the headlines from our market leading weekly magazine: sign up to a free trial to ICIS Chemical Business.
Asian Chemical Connections