HOUSTON, Jan. 31 -- For more than 6 months, near-month natural gas futures contracts on the New York Mercantile Exchange generally have traded at lower prices, adjusted for daily differences in the rate exchange, than comparable gas futures positions on the International Petroleum Exchange in London.
That's a complete reversal of the historic norm since the mid-1990s when near-month futures contracts on the NYMEX always exceeded those on the IPE, usually by several dollars per thousand cubic feet.
Last year, however, futures prices for North American gas fell sharply in the New York market while European gas futures prices inched up in London.
On Aug. 28, the NYMEX gas position dropped 29¢ to $2.42/Mcf, undercutting the comparable IPE near-month gas contract in London that also lost 10.2¢ to the equivalent of $2.50/Mcf. Except for two brief periods, the equivalent IPE natural gas price has remained higher than the NYMEX price ever since.
"I suspect that a large part of the difference with the US (gas futures market) lies in how the back end of the (price) curve behaves," said Paul Horsnell, head of energy research for London-based JP Morgan Chase & Co. "The US market can set its own curve, whereas in Europe there is a dominant effect from oil, given that contract prices are linked to oil prices that are normally lagged 6 months. That can throw up a few oddities if oil prices move very sharply within that 6-month period, which is what has happened."
Patrick Heren, Managing director, PH Energy Analysis Ltd. of London, said, "The simple answer is that European natural gas prices reflect the oil price through direct contractual links. Thus with the oil price relatively high, and the US gas price relatively weak, European gas prices are necessarily at a premium to US gas prices. However, answers are never simple."
He said, "There are two gas markets in Europe. One is largely but not exclusively in Britain, and the other largely on the continent. The British market, with outliers at Zeebrugge in Belgium and at Bunde on the Dutch-German border, is a free, OTC-based market similar to the kind of thing you have in North America. The biggest volume is traded at the British National Balancing Point (NBP), a notional delivery point, and the
IPE futures contract is for NBP gas."
"The British market got going in 1994-95 and was isolated until late 1998 when the Interconnector pipeline to Zeebrugge brought the British market into direct contact with the continent's," Heren said.
"While Britain had been progressively liberalizing its gas and power markets since the late 1980s, the continent had remained monopolistic, with no third-party access rights. There was no spot market. Gas prices were linked to oil prices, through contractual formulae of varying complexity," he said.
Arrival of the Interconnector pipeline coincided with the introduction of limited and imperfect third-party access agreements on the continent, as required by various European Union directives, said Heren. A spot market began at Zeebrugge that largely reflected natural gas prices on the British market.
"It so happened that when the Interconnector opened, oil prices were very low and so were European gas contract prices, while British spot gas prices were at their winter highs," Heren said. "European companies sold small volumes into the UK out of their portfolios. At this stage it was still possible to say that British spot gas prices had an entirely independent existence."
Later, he said, oil prices rose, and with them the European gas contract prices.
"In early 2000, British spot prices were roughly 10 pence per therm (p/th), or about $1.50/MMbtu," said Heren. "But with European contract prices climbing to over 20 p/th or $3 equivalent, the spot price naturally followed them up. That has been the situation more or less ever since. The general level of spot prices is set by the long term contract price, which in turn is set by the oil price. However, spot prices fluctuate around that level, with winter peaks fairly pronounced."
Horsnell said the rise of European gas prices "is a good issue to look at. It's been causing the gas companies in the UK no end of trouble in terms of passing it on the customer.
"(European natural gas) prices were bid up on the back of a few unexpected North Sea field outages, the expectation of colder than usual weather, and then the appearance of really cold weather," he said.
"The NBP day ahead market -- the very short term end of the market -- worked its way above 30 p/th, and I heard rumors that some deals were done above 40 p/th," Horsnell told OGJ Online.
"I wonder also whether there was a Enron effect adding to the volatility. The liquidity of trade in spot, rather than futures, gas did seem to go down a lot prior to Christmas before recovering," he said.
North American gas prices languished last year after failing to recoup much, if any, of the US power market that it lost to residual oil when gas prices peaked in 2000.
US natural gas futures were trading above $9/Mcf on the New York Mercantile Exchange during early January 2001 but had dropped to $6.10/Mcf on Jan. 31. On the IPE in London, gas futures were trading in a tighter range of prices equivalent to $3.76-$4.22/Mcf, peaking near the end of January when NYMEX prices were already in a sharp decline.
By mid-February, the near-month gas futures contract was priced well below $6/Mcf on the NYMEX, while the comparable IPE position was fairly constant in the equivalent price range of $3.70-$3.85/Mcf. When NYMEX dropped below the $5 level to $4.98/Mcf on Apr. 25, the near-month IPE position was still trading at the equivalent of $3.32/Mcf.
On May 22, the IPE gas contract for June delivery slipped below the $3 barrier to the price equivalent of $2.95/Mcf. The IPE near-month position was still at the same price exactly a week later when the NYMEX gas contract for July fell through the previous $4 floor to $3.74/Mcf.
Gas futures prices continued to fluctuate while following general downward trends in both markets. On July 19, the August gas contract lost 15¢ to $2.94/Mcf, marking the first time in 16 months that a near-month gas position had closed below $3/Mcf on the NYMEX (OGJ Online, July 20, 2001).
A generally normal US summer without excessively warm temperatures in the US had prevented any run up in demand for gas at that point. US gas storage levels exceeded 2 tcf at the time and were up 239 bcf from storage levels in the same period the previous year.
That same day, the IPE natural gas contract for August delivery jumped 17.5¢ to the equivalent of $2.84/Mcf, temporarily reducing the gap between the two contracts to a mere 10¢.
Within a week, the NYMEX gas position had rebounded back above $3/Mcf and continued, with few exceptions, to fluctuate above that price for some weeks. By the last week of August, however, the NYMEX price for the near-month gas contract was well established below $3.
After falling below the IPE price level in late August, near-month NYMEX gas positions continued to trade primarily below $2.50/Mcf over the next 5 weeks, with the October contract bottoming out at $1.83/Mcf on Sept. 26 during its final day of trade. The IPE near-month positions, however, had moved above $3/Mcf in early September and were still trending upward with fluctuations.
By the last week of October, near-month NYMEX gas positions had again overtaken the slumping IPE gas prices by a few cents and were kicking at the $3/Mcf ceiling. The December gas contract finally broke through that barrier Oct. 29, gaining 8¢ to $3.04/bbl.
However, on Nov. 5, that contract plummeted 32.6¢ to $2.92/Mcf on the NYMEX, below the equivalent price of $3.25/Mcf for December gas on the IPE. Near-month IPE gas futures prices have retained that lead to date, rising above $4/Mcf price equivalent for brief periods in late December and early January while NYMEX prices remained mired well below $3/Mcf, dipping to just barely above $2/Mcf in recent days.
On Monday, the February natural gas position dipped to $1.91/Mcf on the NYMEX, while the IPE gas contract was trading at the equivalent of $3.16/Mcf.
As time goes by, long term natural gas contracts are likely to adapt to the new market realities, with some decoupling from oil, said Heren. "However, there are two factors that militate against it," he said.
Third party access and market liberalization in general are not developing quickly or evenly across the EU countries. "And the incumbents, who are also the principal buyers of long term gas, are not in any hurry to help," Heren said.
Also, he said, "Unlike the US where there are thousands of gas producers, Europe as a whole has very few gas producers. Most gas comes from four sources: Algeria (Sonatrach); Netherlands (Gasunie, which means Exxon/Shell); Norway (mainly Statoil ASA, but also 25 others); and Russia (Gazprom).
"Most of the gas travels very long distances, and most of the supply contracts are very high load factor. Flexibility services are developing slowly, in harness with the OTC markets," Heren said.
Contact Sam Fletcher at firstname.lastname@example.org