Over the past few years, natural-gas prices have skyrocketed, causing concern across many industries over supply shortages and the long-term viability of this important fuel. Record prices also have fueled interest in new coal, nuclear, and renewable power generation projects, just as the gas-fired merchant building frenzy has subsided, leaving many power markets with excess capacity.
On the natural-gas supply side, analysts and consumers are worried that conventional sources are tapped out. Furthermore, Canadian exports have decreased from their peak, despite the high prices.
All of these factors point to a fundamental change that is now underway, with only a few possible solutions to today’s high prices: Conserve, drill more, build new liquefied natural-gas (LNG) terminals, bring in new frontier sources, or get used to high prices.
During the 1990s, when prices and volatility were low, growth in U.S. demand was matched by increases in natural-gas imports from Canada. Figure 1 shows how the growth trend stalled and then reversed sharply in 2003. This was due in part to growing exports to Mexico, but also from blowing off the natural-gas supply bubble that existed for many years in Canada. The figure also shows how LNG has made up much of the shortfall in net pipeline supply. Since 1995, U.S. annual LNG imports have grown from 18 Bcf to an all-time high of 652 Bcf in 2004. In 2005, LNG imports declined by 93 Bcf, due in part to higher natural-gas prices in Europe relative to the United States and in part to the unavailability of cryogenic storage for spot cargoes. This caused some redirection of LNG cargoes originally intended for the United States.
The expected increase in gas consumption for electric generation and high commodity prices has fueled a renewed interest in developing more LNG and other non-conventional resources (coal-bed methane, tight sands and shales, Arctic gas). According to Global Energy’s long-term gas price forecast, all of these supply sources are likely to be economical on a full-cycle basis (including recovery of total project costs) at current market prices. But developing billion-dollar projects with long lead times will require some faith that project economics will remain favorable once the project is complete.
Over the next several years, including the existing LNG re-gas terminals, expansion projects, and greenfield projects under construction, total regasification capacity is expected to increase to well over 12 Bcf/d at maximum send-out rate. Although these numbers sound impressive, there is no certainty that LNG projects will operate at full capacity. By comparison, in 2005, LNG plants operated below 50 percent of their maximum rate.
Furthermore, during the winter season of 2005-2006, several LNG cargoes were priced away from the North American receiving terminals to Europe. The new international competition, as anticipated by Global Energy, led to a slight decline of LNG imports in 2005. Whether prices will be high enough to attract more shipments next year remains an uncertainty.
Offsetting this global competition for LNG is, in part, the amount of undedicated liquefaction and shipping capacity (currently approximately 10 percent of total capacity), limitations on redestination flexibility (none to 10 percent of annual contract quantity for base-load supply), and restrictions on compositional interchangeability.
One thing is certain right now: Developers have big plans to build even more LNG re-gas capacity. Plans for at least another 20 Bcf/d are in the works, but this is unrealistic because upstream constraints in liquefaction capacity building, LNG tanker construction, global spot cargo competition, and resistance in many communities will limit or slow the pace of growth.
Worldwide LNG liquefaction capacity (including current, under construction, and proposed) is shown in Figure 2. Between 2005 and 2011, capacity could double if all projects are built, but this is well below current proposed re-gas terminal projects worldwide.
Worldwide liquefaction growth specifically dedicated to the U.S. market is the key limiting element in LNG supply to the United States. Traditionally, global LNG trade was based on long-term contracts with dedicated supply sources and regasification terminals. This arrangement was critical for the development of the industry, especially in Japan and South Korea. Uncertainty surrounds the viability of signing similar long-term or even short-term fixed-price contracts in light of North America’s deregulated gas-market environment.
Local gas distribution companies (LDCs) might be unwilling (or unable) to accept the risk of regulatory disallowance if market prices move below negotiated contract rates. Global Energy is aware of several instances where LNG prices at then favorable terms were rejected simply for NYMEX plus or minus basis. Recent imports of LNG have been for meeting seasonal swing supply, based on NYMEX prices. So questions may remain as to how North America’s deregulated gas market fits into this global marketplace for long-term base-load supply, and its potential linkage to short-term domestic spot-market prices.
In addition to LNG supply, two competing pipeline proposals also are advancing to bring frontier gas resources from Alaska and Canada’s Mackenzie Delta. The timetable for either project is still uncertain. In mid-September, the Mackenzie pipeline consortium began spelling out shipper requirements to obtain capacity on the 840-mile line. The project’s initial capacity is expected to be 1.2 Bcf/d and could be on line as early as 2010.
A broad consortium of industry and most aboriginal people who have a stake in the project recently provided funding and participation agreements to regulators. The consortium now has filed for regulatory approval. A decision to proceed will be based on market conditions and any conditions set out by the regulators. However, in the fall of 2005, Imperial Oil threatened to walk away from the project if a finalized agreement could not be reached with all aboriginal groups.
The delay facing the project centers on the intransigence of the Deh Cho First Nation, representing 13 communities and 4,500 residents, whose lands cover approximately 44 percent of the proposed Mackenzie Valley pipeline route. The other three aboriginal communities have ratified general land access and benefits agreements with the project, and have formed the Aboriginal Pipeline Group (APG), which hopes to gain a 30 percent equity interest in the pipeline, supported by governmental and producer funding.
The Deh Cho First Nation wants to link approval to ownership of mineral rights still subject to an existing land claim. The Canadian government also has rejected their claim to collect property taxes from the pipeline.
Further complicating matters, Northwest Territories is pursuing its decades-old bid to collect its own resource royalties rather than have them transferred through the federal government, and to gain greater control over resource development. The federal government has offered C$500 million in socio-economic funds to aboriginal communities along the planned pipeline route, but its allocation to aboriginal communities is still undefined. It will take a lot of work to remove the 1977 moratorium.
A second and much larger pipeline could deliver natural-gas supplies first, if a deal is not reached on the Mackenzie pipeline soon. Completion of the Alaskan natural-gas pipeline project could potentially supply 4.5 Bcf/d. It would be a mammoth project, with an estimated price tag in the $20 billion range. To achieve financing, the sponsors received in October 2004 government support in the form of loan guarantees and tax incentives. The Energy Policy Act of 2005 gave no support to this pipeline project. However, it does state that the Federal Energy Regulatory Commission is responsible for any future studies to be carried out for this project (in the United States), rate design, and impact on the environment. The current agreement before the legislature for approval involves the state of Alaska converting its royalty interest in gas production into a 20 percent equity interest in the pipeline, with linkage to a new 20 percent tax rate on oil production and a 20 percent credit rate on exploration and production spending.
The online date also could be affected by progress on the Mackenzie pipeline project, and the timing of incremental LNG regasification capacity, as well as its total marginal cost upstream of the takeaway pipelines. Currently, the estimates and projections for the LNG are that it would come in at a lower total into pipeline cost than the Alaskan gas delivered to either AECO or Joliet, and that LNG (including liquefaction capacity) has a shorter construction period than the 8 to 10 years estimated for the Alaskan pipeline. Also, controversy surrounds future producer access to the pipeline, other than the key sponsors (BP, ConocoPhillips, and Exxon/Mobil) who will build the Canadian portion of the system (TransCanada or Enbridge) and intra-Alaskan shipments using lateral lines. Also, in February 2006, the governor of Alaska introduced a bill affecting the fiscal rules for the three major sponsors of this project.
The bill would replace the state’s production-based tax on oil with a tax tied to producer profits. Producers would pay a 20 percent tax rate and receive a 20 percent tradable tax credit. Tax revenues would be lower when initial capital investments would be made and, consequently, higher as production increases. Once the oil tax changes are approved, the governor, in a separate bill, would ask legislators to approve of the new oil tax terms to be incorporated into a gas pipeline project during a special session to be called for this spring or early summer if the tax bill is passed. The sponsors are encouraged to see that the fiscal aspects of the project, and their long-term stability are moving in a positive direction.
Only time will tell if either arctic pipeline gets built and how they compete with each other at their final delivery points, and with LNG. And LNG developers have their own set of issues: competition for liquefaction capacity, NIMBYism, and contracting. But for better or worse, the industry has staked its future on gas supplies from more exotic sources than in the past.