Gas Crisis Forum: Prices Pointing Skyward!

Deck: 
Gas prices are likely to remain high in the near term.
Fortnightly Magazine - August 2003


Gas prices are likely to remain high in the near term.

There are many possible new sources of supply that could dampen the high-priced natural gas environment in the long-term, but most signs point to a high-price environment in the near-term. One could argue that changes in storage in the production area between years has the potential to start heading north soon, because domestic production capacity between July and the end of 2003 will be larger than last year.1 This will put downward pressure on prices. But other sources of supply don't look as good. When one looks at Canadian imports, Mexican exports, liquefied natural gas (LNG), the Rockies, and overall demand for gas, the outlook for much lower gas prices by the end of the year is pessimistic.

Canadian Imports and Mexican Exports: How Will They Offset Each Other?

Natural gas imports from Canada were, until the last several years, a major source of new supplies, and often the stopgap source of supplies in the depth of winter. For example, Canadian imports were 21 percent of domestic natural gas production in December 2000, when the average price of gas was near $9.00/MMBtu. Between November and December of 2000, imports rose by 1 billion cubic feet (Bcf) a day.2 Without the 1 Bcf increase in Canadian imports, the price would have been still higher.

Yet, Canadian imports will most likely not increase and not be a stopgap source of supplies this year.

Some Canadian companies and consumers believe our recent policies on Canadian exports of agriculture, lumber and other commodities to the United States amount to economic warfare. Moreover, the export/import pipe capacity between the United States and Canada has increased hardly at all in the last two years, and last winter much of this pipe space was near or above capacity limits.

There are reasons not to push this capacity to the limit. The chance of operational problems increases at these times. Demand for natural gas also continues to grow in Canada.3 Accordingly, Canadian companies may be unwilling or unable to supply incremental gas to the United States. This may even work to their advantage. If cold weather occurs and domestic supplies become tight, price levels will soar. When a necessity such as natural gas is perceived to be in short supply, prices can double from already high levels. Hence, a reduction in natural gas export volumes from Canada may be more than offset by an increase in price, and Canadian export revenues could grow, not decline, from lowered Canadian export volumes.

Although Canada is not expected to contribute to additional supplies this year, future years look brighter. There are six new export pipeline expansion proposals into the northeastern United States through 2005, representing 2.1 Bcf/day of capacity.4 The natural gas for these planned pipe builds would be shipped from fields offshore the Maritime Provinces in Canada. This is a relatively new source of natural gas developed during the 1990s. But gas imports to the United States from Canada may be offset by U.S. gas exports to Mexico. Mexico has a sizeable natural gas resource base. Yet, exports to Mexico, while not large, have increased significantly from 100 Bcf in 2000 to an annualized rate of 250 Bcf today. Increased goodwill between Mexico and the United States and cooperation between energy agencies in both countries could result in a changed picture for export/import markets between the United States, Canada and Mexico. Yet, the Federal Energy Regulatory Commission has approved 729 MMcf/day of additional export pipe capacity to Mexico for installation in 2003. Despite tight supplies in the United States, exports to Mexico in 2003 are likely to grow from their level in 2002.

LNG: Not Yet a Contender

Canadian imports currently amount to between 10 to 11 Bcf/day. In contrast, LNG is contributing about 700 MMcf/day to our domestic markets and is expected to contribute several hundred cubic feet more this year.5

There are now four active import marine terminals in the United States. They all have plans for expansions of capacity and deliverability by 2005. There are also proposals for about 20 new LNG import facilities that could serve the United States.

The largest existing facility is the Lake Charles terminal in the heart of the natural gas-producing area of the United States. It has a capacity of 6.3 Bcf, with additional capacity of 3 Bcf planned by 2005 and peak sendout deliverability of 1 Bcf/day. Additional deliverability of 570 MMcf/day is planned by 2005.

Yet, despite impressive import facilities, LNG capability is difficult to estimate. For the major marine terminal facilities, full capability involves the coordination of the choice between spot or fixed-price forward contracts, the arrangement of international transport by ship, regasification, and delivery by pipe on domestic shores. Deutsche Bank estimated in its May 2, 2003, report on LNG that full-year baseload capacity for LNG by 2002 represented potentially 4.4 percent of U.S. gas demand.

If existing capacity is more fully utilized and additional shipments of LNG are possible, this may put some downward pressure on price this year. Going forward, LNG's contribution to domestic supplies bears watching.

Rockies: Late to the Game

According to Energy Information Administration statistics, Wyoming dry natural gas proved reserves were 10.88 trillion cubic feet (Tcf) at the end of 1994 and 18.4 Tcf at the end of 2001, the most recent data available.6 Moreover, a recent study by the Department of Interior found that 63 percent of the natural gas resource base in the major basins of the Rockies is accessible under current lease arrangements.7

The price of natural gas in the Rockies is often several dollars less than the cost of natural gas in Louisiana and Texas, the major sources of domestic natural gas supplies. In short, robust supplies in that part of the country are seeking a market.

Although pipeline expansions out of the Rockies continue to be announced, the time from filing to completion is several years. Additional Rockies gas will not be available this year to reduce any tightness of supplies east of the Rockies. It appears that the industry or the government needs to determine why accessible Rockies gas is not getting to market. Even the lowering of the interest rate to levels not seen in 45 years is not boosting investments in this business.

Nonmanufacturing Demand Continues to Increase

Although the shutdown of fertilizer plants as a consequence of high natural gas prices is important, there is no surprise here. In 1998, fertilizer exports were double fertilizer imports. Today fertilizer imports are greater than exports. The importance of fertilizer production to the economy has been on the decline. As fertilizer and other chemical plants continue to shut down, this will reduce demand for natural gas and increase overall supplies, but the impact on price and on the economy will probably be modest.

Yet natural gas is the fuel of choice for new investments in power generation, and natural gas demand is expected to grow, though modestly and despite high prices, because of very efficient combined-cycle gas units.

Natural gas also is used to heat a majority of homes and commercial establishments in the United States. In the heating season months from November to March, volumes of natural gas sold and household bills can easily increase east of the Rockies fivefold from their level prior to the heating season. But that is only part of the picture.

Residential and commercial business customers are going to be greeted not only with continued high prices for the commodity but also increases in their cost of service from uncollectable bills and cost adjustments from past winters when prices soared. These costs will continue to surface in bills into the next year.

Moreover, it is not just the price customers pay for the commodity and for gas service that has increased significantly over the last several years, but the size of the housing market. The purchase of new, larger homes and the building of additions on existing homes means that costs of home heating would have increased for many consumers even without the large price increase for the commodity and standard gas service.

A clear view of the situation surfaced this past winter, when residential use of natural gas from November 2002 through January 2003 grew by almost 25 percent over the previous year. This increase was greater than expected and is a break from much of the past, when high prices inspired conservation and a reduction in consumer demand.

Heating season 2001/2002 was exceptionally mild. Hence volatile natural gas prices fell significantly and inventories of natural gas remained high relative to year-earlier levels. These inventories continued to build throughout the nonheating season in 2002. Accordingly, inventory supplies in November 2002 were very similar to levels in the previous year when they were quite high, and prices subsequently fell.

Plentiful supplies in storage in November 2002 should have caused some decline in price, so why didn't prices decline? Because there had been a fundamental increase in demand. The recent reported EIA consumption statistics for November 2002 through January 2003 indicate this.8 Unless the weather turns out to be extraordinarily mild, with a cool summer and a warm fall and winter, consumers will need to cut back expenditures on other items as expenditures on natural gas continue at elevated levels. The chance that this could move the economy back into recession is very real indeed.

Wholesale Markets: Volatility in the Mix

Another notable change in the energy business in the last two years is that Enron, Dynegy, and other major energy companies have exited the short-term contract wholesale part of the business. Short-term markets have gotten thinner, which tends to increase price volatility and perhaps price.

Increasingly, producers are no longer using wholesalers to help them sell their natural gas. On June 24, 2003, it was reported that Apache with 1 Bcf/day of North American production had, after five years, ended a 10-year agreement with a marketer.9 It would not be surprising if many of Apache's target customers are major utilities. Utilities are increasingly signing longer-term contracts for natural gas with producers and not relying on intermediaries.10 The problem is that some utilities often have little incentive for effectively negotiating the price down since they often pass this cost onto consumers. High costs supply them with large cash flows and long-term contracts supply them with a steady long-term cash flow.


  1. Production capacity is based on the lagged relationship between rigs and development wells and actual production. There is about a six- to nine-month lag between rigs and actual production, and it is the average relationship of number of rigs over time that matters. The relationship between production and production capacity has been determined using statistical analysis. Hence by the end of June of a year we have estimates of production capacity for the rest of the year and can compare this to production capacity in the previous year.
  2. Since imports/day were about 11.5 Trillion MMBtu and the average price was $9.00/MMBtu, these imports amounted to about 100 million dollars. Since trade back and forth across the border is about 1 billion dollars/day the natural gas trade was a significant portion of overall trade at the time. In January 2001, Canadian imports reached their highest level ever of about 11.7 Trillion MMBtu.
  3. Nonetheless, Canadian production may increase this coming winter as rigs have been running 50 percent and more above year-earlier levels. Yet an item to watch this year, along with increased demand for gas in Canada, is the exchange rate between the U.S. and the Canadian dollar, which changed significantly in the last year. This may have implications for investments. If a Canadian producer received American dollars for shipments of natural gas, the producer would have received in February 2000 $1.60 in Canadian dollars when the U.S. dollar was exchanged for the Canadian dollar to purchase additional production equipment in Canada. On June 24, 2003, the same producer would have received $1.36 for the same dollar according to the exchange rate published in the . Luckily, the large rise in the price of natural gas between last year and this year has swamped the decline in the exchange rate, but this is something to continue to watch.
  4. Jim Tobin, Expansion and Change on the U.S. Natural Gas Pipeline Network - 2002, May 2003. This is the authoritative reference for the natural gas and related industries.
  5. New LNG capacity at Cove Point, Md., could soon push this total above 1 Bcf/day. The LNG facility at Cove Point already has a deliverability of 1 Bcf/day. Most recent price information available from the EIA indicates that LNG has been about 8 percent cheaper than the Henry Hub price. However, whether the cost of LNG will remain below the HH price is hard to tell, since there is an active spot and long-term contract market for LNG. Moreover, because of the large size of each LNG capacity addition relative to the existing market, each new addition can significantly change the price and the complexion of the market. Nonetheless, some longer -term contracts for LNG could serve as a physical hedge for utilities, much like conventional storage reservoirs, while short-term spot contracts could help to satisfy peak demand. For recent studies and summaries of the recent hot topic of LNG markets see Damien Gaul, "U.S. LNG Markets and Uses," January 2003, Energy Information Administration, U.S. Department of Energy. Paul Sanket, Caroline Cook and J.J. Traynor, "LNG … going… going … Gone Global," Deutsche Bank AG, May 2, 2003. Carol Crowfoot, "U.S. Natural Gas Supply Dilemma: Is LNG the Answer?" Canadian Natural Gas Focus, GLJ Energy Publications Inc., Calgary, Alberta, Canada, May 2003. In addition to analysis the latter monthly publication also contains extensive information on Canadian/U.S. markets, such as export pipeline utilization.
  6. This is only 920 million cubic feet less than total lower-48 domestic production in 2001 of 19.32 Tcf. Energy Information Administration, U. S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves, 2001 Annual Report, November 2002. The 1994 Reserves Report contains information for 1994.
  7. U.S. Department of Interior, Agriculture and Energy, Scientific Inventory of Onshore Federal Lands' Oil and Gas Resources and Reserves and the Extent and Nature of Restrictions or Impediments to their Development, the Paradox - San Juan- Uinta/Piceance, Greater Green River and Powder River Basins and the Montana Thrust Belt, January 2003.
  8. One reason for relying heavily on the initial EIA estimates of residential consumption is that they are more reliable than many of their other initial estimates. Unreliability contributes to price uncertainty.
  9. Reuters, "Apache to market its own U.S. natural gas," June 24, 2003.
  10. It is telling that Steve Ewing of DTE Energy and chair of the AGA Task Force on Gas Supply at the National Petroleum Councils Natural Gas Summit was quoted in an AGA press release on June 26 as stating, "State public utility commissions should pre-authorize utility requests to purchase certain volumes of natural gas at set prices under long-term contracts."


The Makings of a Supply Crisis?

Outlining the fundamental factors that are keeping natural gas supplies tight.

  • Price volatility remains high, although there is a chance due to uncertain weather and other factors1 that prices could move below $3.00 by end of year. Yet, expected price levels under normal conditions are most likely to remain high for the rest of the year.
  • Storage in consuming areas both east and west will get filled at a heady pace, and this demand will put upward pressure on prices until the heating season.
  • Residential and small business demand will continue to increase unless consumers start spending money on conservation, not increasing the size of their homes, and regulators, government, and businesses start publicizing the ins and outs of conservation.
  • The use of natural gas for power generation most likely will continue to increase. Imports from Canada will not increase and will not be a stopgap source of gas in the depth of winter, thus increasing the chance of price spikes.
  • An increased productive capacity will increase domestic production, but it probably won't be enough to significantly reduce prices.
  • Increases in LNG supplies and exports to Mexico will tend to offset one another.
  • Utilities will continue to sign longer-term contracts with producers at a price that is higher than what an aggressive wholesaler would pay.

Down the road, increased natural gas will flow into the Northeast from the Maritime Provinces, and the domestic pipe/utility companies that own the LNG import facilities will make fuller use of the capacity available to them. Conservation initiatives will kick in as a response to continued high bills, especially if the economy is in recession, and additional amounts of gas will flow from the accessible area of the Rockies eastward. -J.H.H.

  1. One of the other uncertain factors not considered directly is the price of oil in particular residual fuel oil. The reasons for this are several. Changes have taken place in manufacturing that have apparently reduced the importance of oil. In power generation, efficient combined-cycle generators are substituting for oil or fuel switching generators, and available oil price information for estimation purposes is of poor quality. Such considerations motivate treating oil prices as just another source of uncertainty in natural gas prices.

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