Many market participants view liquefied natural gas (LNG) as a wave of supply analogous to the famous Banzai Pipeline on Oahu in the Hawaiian Islands. Some believe it will swamp the U.S. market and crash prices to levels under $4 per MMBtu indefinitely. We hold a different viewpoint on LNG’s likely contribution to the North American supply/demand equation.
We believe LNG will act more like the ocean tides rising and falling on a reasonably predictable cycle with occasional “spring” tides that are noticeably higher than the normal level. It will have a complex impact on price in North America; sometimes it will act like baseload supply, and sometimes it will behave like a true marginal supply source.
We think a significant number of the proposed LNG regasification facilities will be constructed and that they will be situated mostly along the Gulf of Mexico with a couple in the Canadian Atlantic provinces and along Baja, Mexico. Unfortunately, siting difficulties are likely to deter most of the proposed projects along the East and West coasts. Successful regasification facility siting and increased LNG imports into those areas could relieve pipeline-congestion points and defer pipeline and storage upgrades as demand grows.
how much LNG and when?
Ultimately, we believe as much as 20 Bcf/day of physical regasification capacity will be available to the market by 2020. The key questions are: How much LNG will be delivered and when?
The chart provides an illustration of how we believe the annual supply demand balance in the United States will stack up between 2010 and 2015. Greater LNG deliveries will occur in the spring, summer and fall and diminished deliveries will be the norm in winter.
Driving the pattern is the degree of storage capacity in the U.S. relative to other countries.
This pattern is driven by our country’s degree of storage capacity relative to other countries. Many countries that are large LNG importers have little or no underground storage and rely on storing LNG in its liquid form plus an assured stream of tanker deliveries. They can be slightly more flexible in receiving LNG in the non-winter months when heating demand is lower. The United States needs to create price incentives to encourage sufficient summer LNG deliveries to match the degree of storage withdrawal depicted by the area under the curve during high-demand winter months. Lower-48 production and Canadian imports will no longer be sufficient to meet demand and refill storage.
The simple reality is that North American supply and demand will react to LNG influence as greater volumes are imported into the pipeline grid. Prices will fluctuate in new and potentially unpredictable ways as gas goes the way of oil and becomes linked to a global market. Overall, North American price levels and locational basis prices will be impacted by the ultimate location and activity of LNG regasification facilities. The attractiveness of natural gas as a fuel for industrial applications and as a fuel for power generation will depend both on price and on perceptions of reliability. Reliability will be viewed through the prism of both physical security and price volatility. LNG may become the key determinant in the market’s perception of natural gas both short and long term, but we still doubt that its marginal delivered cost will become the North American marginal price for any sustained time period. We concur with most industry analysts that most successfully sited regasification facilities will be along the Gulf of Mexico corridor, so generic price discussion of LNG landed into the U.S. remains anchored to a Henry Hub price view.
it’s a supply, not a demand, problem
Lack of growth in supply has caused U.S. natural gas consumption to remain relatively static for the past six years despite strong GDP growth, increases in gas home heating, and the introduction of more than 2,000 individual gas-consuming turbines representing more than 200,000 MW of new electric generating capacity. Market forces, through higher prices, have been working to ration demand to match our static gas supply. Otherwise, supply growth would have been met by the increased consumptive capability of the nation’s end users. This demonstrates that we do not have a demand problem in the United States, we have a supply problem.
Whenever natural gas falls below $5 per MMBtu it will begin to displace coal in the power generation market segment due to today’s higher coal prices, SOx and NOx allowance prices, and the impending impact of mercury rules. The introduction of large amounts of gas-fired capacity creates a large potential demand waiting to enter the market during any periods of lower prices. However, these markets are interrelated and also will respond to changes in demand at the margins of the industry. The other source of additional electric power demand on natural gas remains the competitive interplay of residual oil-based generation and gas-fired capacity. During periods of higher priced crude oil and residual fuel oil, a noticeable amount of generation will switch to natural gas, creating demand on the margins of the market.
Industrial demand also has pent-up consumptive capability that can reemerge in an environment of lower natural gas prices, particularly if world oil prices and naphtha-based petrochemicals remain relatively high-priced. This is not a suggestion that the methanol- and ammonia gas-intensive industries will reopen shuttered operations, but a belief that the petrochemical complex in general has latent North American capacity that could ramp up and result in greater gas consumption.
Since the price decisions of both of these demand sources regarding natural gas potentially involve very large capital investments, LNG’s impact on long-term prices and perceptions is as important as the actual impact upon short-term price movements.
The demand side of the equation still sees an “elephant in the room” regarding the LNG’s viability as a major supply source. The question remains how good is the interchangeability between LNG and the historical, delivered natural gas quality delivered in different regions around North America. FERC, the Natural Gas Council and industry participants have expended enormous amounts of effort and advocacy in the attempt to resolve key questions regarding whether quality/interchangeability limits need to be imposed on LNG imports, and if so, what limits make sense from an economic, safety and reliability standpoint. This is a particularly important issue to the power generation community since the push toward lower emission standards and higher efficiencies has resulted in technology changes to combustion turbines. These design changes make combustion turbines much more sensitive to fluctuations in natural gas composition, particularly over short time periods. If interchangeability standards are too loose, end-use equipment will suffer, and, conversely, interchangeability standards that are too tight will make some LNG sources difficult and expensive to deliver into the U.S. market.
Delivered LNG will also impact the production side of North America’s supply. There is a positive correlation between the forward NYMEX 12-month strip and drilling activity. At prices near $5 per MMBtu, marginal drilling prospects will be deferred and production will quickly decline. Ample data for production response is available from the prior periods of short-term drilling declines. With even higher decline rates in today’s mix of production sources, declines in drilling activity should continue to show up in production data with a very short lag period. These declines in production will need to be made up by more LNG imports or a rebound in drilling from the higher prices that result from tightening the supply/demand balance. Basis differentials will be as critical in the future as they are today in determining whether producers commit risk capital for drilling. Lower wellhead prices for producers in south Texas, the Mid-continent and Rocky Mountains will drive their investment behavior consistent with the past few years. Discussions of $5 natural gas in the Gulf Coast will translate as $3 to $4 gas in the Rockies. Will these prices be sufficient to drive high investments into unconventional resources and the associated pipeline infrastructure?
unlocking Alaska’s natural gas
The other remaining question for long-term North American supply is the unlocking of Alaska natural gas via the Alaskan pipeline. The magnitude, siting difficulty and construction risk of this pipeline investment stagger the imagination. The producers who hold title to the majority of stranded natural gas in Alaska are also primary participants in the LNG investment chain trying to bring natural gas to North America. Their price views will be the major determinant that decides how much investment is appropriate for a given price outlook. If LNG has pushed Gulf Coast prices to levels under $5 per MMBtu when the 4+ Bcf/d of Alaska natural gas is slated to hit the market, netback realizations in Alaska are likely to be inadequate to handle royalty, tax and profit expectations.
The logic utilized in this article suggests that $5 per MMBtu will serve as a relatively hard price floor, broken through only during “spring” tide periods when weather and economic activity have created an imbalance between supply and demand. Consequently, our longer-term price outlook is closer to $6 per MMBtu at the Henry Hub on a cash basis.
Keith Barnett is managing director, fundamental analysis and economic forecasting, at AEP. He has served in a variety of operational, transactional, and analytic roles during a 25-year career in the natural gas and electric power industries. Karl Bletzacker is staff natural gas analyst at AEP. He previously served as the COO of National Gas and Oil Company, an Ohio natural gas and power distribution utility.