2000: Year The Market Showed Off Its Muscles

Calling 2000 a watershed year for the natural gas market is somewhat akin to saying 1776 was an important time in U.S. history. With only a couple of exceptions, last year began with all spot price indexes between $2 and $3. It ended with January 2001 indexes ranging from $8.56 (Questar) to $18.81 (Transco Zone 6-NYC).

Along the way, NGI's previous spot price record of $39 at the Chicago citygate, set in early February 1996, was shattered several times. The new record stands at $69 at the Southern California border, established in Dec. 11 trading. That same day all other West Coast points (PG&E citygate, Malin, Sumas, Stanfield and Kingsgate) registered highs that beat the old Chicago record.

Prices have seen spikes in previous years at certain points or in specific regions due to severely hot or cold temperatures, transportation constraints, a hurricane or whatever. But those spikes were short-lived and seemed larger because they contrasted with a base market at $2-3 or so. The key difference in 2000 was that except for minor retrenchment here and there, high prices showed no signs of subsiding and were built on a base of $8-10 or more toward the end of the year.

The cash increases were based mostly on weather, storage and other supply-demand fundamentals, but they also got plenty of support from futures. Gas futures contracts kept notching new highs, especially towards the end of 2000. The climax came Dec. 27 when the January 2001 contract briefly surpassed $10 and settled at the all-time high of $9.98. Other parts of the energy complex at Nymex also contributed. Although crude oil was below $30/bbl at the end of the year, it spent some time earlier in the vicinity of $37. And heating oil futures were very strong as worries of a winter shortage increased.

There was no indication of a monster market in the making through the early part of the year. May indexes were still relatively tame on either side of $3. But a hint of what was to come appeared when nearly all June indexes rose by a dollar or more. Then two conditions combined to get the 2000 price rampage launched: more gas-fired air conditioning load than the market had ever seen before, and concerns throughout the summer and fall that the routine refill of storage facilities was going more slowly than usual and might prove inadequate for heating season needs.

As storage injectors competed with power generators for the same molecules of gas, the impact of a drilling slowdown spawned by low prices in the late 1990s began to be felt more acutely. Although there was enough supply to go around, buyers had to ante up more and more money to get their share. The result was monthly indexes that kept reaching new heights in the latter half of the year except for retreats in the August and November bidweeks. And though October was a major exception in which aftermarket prices fell 50-60 cents or so below indexes, in other months day trading quotes spent most of their time in index-plus territory.

The hypervolatility of 2000 produced some unprecedented market distortions. Even when Chicago was hitting $39 in February 1996, it still averaged just under $18.50 that day, only about $4 above Henry Hub. Contrast that with Sumas and Northwest-domestic, two points that under normal market conditions trade at near parity, in Dec. 8, 2000 business. Thanks to a long series of OFOs and entitlements for the northern half of the system by Northwest Pipeline along with cold Pacific Northwest weather, Sumas commanded a premium of nearly $40 over the domestic product that day. The Northwest actions also had Stanfield and Kingsgate setting point-specific records during December.

Toward the end of the year there was an explosion of basis at some points. As California continued to struggle with power problems, gas traders gasped in amazement as September basis at the border averaged just under plus 250. But that was just for starters, even though October and November basis averages slipped back to less than plus 50. In the December bidweek border basis peaked at plus 780 and averaged a little more than plus 651. For January 2001, quotes got only as high as plus 715, but there were more large reports to push the average to plus 663.50.

However, the California border's peak of plus 780 didn't last long as the all-time basis record. The opposite corner of the U.S. was getting into the super-basis act in the January 2001 bidweek as quotes for Texas Eastern M-3 and Transco's New York City and non-NYC pools in Zone 6 topped off at plus 500, 700 and 850 respectively. But although Zone 6 (NYC) now holds the basis record, its average in that bidweek was only plus 579, well short of the Cal border average.

An interesting phenomenon in indexed contracts developed late in 2000. Normally traders report a deal at index plus or minus a few cents. For December, however, some sources said they bought Southern California border gas at the NGI index plus a dollar or more. As it turned out, those proved to be wise decisions as border prices immediately skyrocketed in the aftermarket and stayed much more than a dollar above the $14.08 index throughout the month.

Index premiums got even heftier for this month when one source reported several Transco Zone 6 (NYC) purchases at index plus $1.50-2.00. However, that strategy is backfiring compared to the California case a month earlier. For last Friday's flow, Zone 6 (NYC) numbers averaged $10, nearly nine dollars under the $18.81 index.

Consumers started getting warnings of sharply higher winter natural gas and heating oil prices in early fall, and the barrage of utility advisories, disseminated primarily through local news media, kept accelerating as the heating season approached. In an election year, that naturally created a political football as lawmakers and other officials promised investigations and other actions to keep the fuel costs in check.

California spent much of the last half of 2000 in a power crisis that drove two major utilities to the brink of bankruptcy. That was exacerbated by record-setting gas prices that made California the most expensive market of 2000 and the fact that much of the state's power generation is gas-fired. Price caps on electricity made it impossible for a gas-using plant to sell its output within the state without losing money while daily border, PG&E citygate and Malin prices were averaging in the $40s and $50s during part of December.

An explosion on El Paso's South Mainline in New Mexico in August killed 12 people, put a crimp in gas deliveries to California and east-of-California markets and made the case for building much-needed new pipeline infrastructure in other regions a much harder sell to regulators, politicians and residents.

The extremely bullish market has taken a toll on midstream operators. A number of processing plants, primarily in the Gulf Coast, have suspended or greatly reduced activity in recent months for economic reasons. The Btu content of liquids made them worth more left in the gas stream than taken out as separate products.

However, the processing cutbacks have led in turn to problems with gas failing to meet pipeline quality specifications. A number of pipes in late 2000 issued OFOs (or warned of their possibility) or took other action to guard against gas streams with excessive liquids that could threaten operational integrity or cause downstream safety concerns.

A producer noted that he has a processing plant in Texas that's been shut down since November, but luckily the gas stream it served was lean enough to continue meeting pipeline quality specifications. However, he has been forced to shut in some HIOS gas because of an ANR OFO against unprocessed production with excessive Btus. It's almost impossible for a processor to make any money under current conditions, he said, but it's quite likely that producers may be offering extra processing fees to get their gas into a pipeline rather than shutting in. The producer was sure that "there's a lot of renegotiation of processing contracts going on."

The high prices that soured economic operations for many processors produced a corollary development when some industrial firms for whom gas is a major commodity cost, such as chemical or fertilizer makers, found they could make more profits by at least temporarily abandoning their normal business and re-selling their gas contracts (in either physical or futures form). There was another side of that coin, however. Some businesses such as flower growers or agricultural firms, especially in California, said they faced financial ruin from not being able to afford gas to heat greenhouses or dry food products.

One of the most remarkable aspects of the super-bullishness of the last half of the year was that it occurred during a benign hurricane season. Although the 2000 Atlantic season was, as predicted, an active one with 14 named storms including eight hurricanes (three of them considered major), there were no significant disruptions of Gulf of Mexico production.

So what can we expect in 2001? Few sources see any chance of sustaining the incredible heights of last year, but they believe prices will continue to reign at loftier levels than during the 1990s.

Analysts at Raymond James & Associates, Salomon Smith Barney, WEFA Inc., Petrie Parkman & Co. and UBS Warburg and bean counters at the Energy Information Administration (EIA) all predict gas storage levels will end the winter at a record low, which should keep prices high throughout the year. EIA expects wellhead prices to average $5.20/Mcf in 2001 compared to an estimated $3.70 in 2000 (72% higher than in 1999) and about $4.50 projected for 2002. EIA said gas storage levels at the end of December were lower by 10% than the previous record low for that month set in 1976. Many observers agree that storage could be completely depleted or reduced to the lowest level possible by April 1.

EIA expects gas demand to grow by 2.9% in 2001 and by 2.7% in 2002, compared with estimated demand growth of 4.5% in 2000. However, gas demand from non-utility electricity generation in 2001 is expected to be up by a solid 9%.

Meanwhile, a record high rig count (886 U.S. gas rigs drilling as of Friday compared to 638 a year earlier) is expected to pay off eventually in higher gas production, but opinions are mixed on how fast production will grow. Analysts at Salomon Smith Barney and EIA expect North America gas production to grow by between 5% and 6% this year; while others observers, most notably the producers at Independent Petroleum Association of America, say the growth will be less than half that much because mature fields are yielding less gas. The latter scenario surely would mean the wild ride that lasted through 2000 is only the beginning of a very difficult trip ahead.

Roger Tanner, Houston

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