Prepared by Prudential Securities, Inc.

Crude Oil | Heating Oil | Natural Gas

Overview

In the third quarter, a tight demand/supply balance propelled natural gas futures and cash prices to levels not seen since January. The sharp rise in both cash and futures prices has perplexed many, but the gains appear justified. Several factors on both sides of the demand/supply equation are behind the market's strength. Moreover, the gradual and almost uninterrupted rise in natural gas prices from the year's lows recorded in February to the current level of more $3.00 per million Btu reinforces the lasting power of the rally. More often, rallies in the natural gas futures are very short term in nature, resulting in price spikes rather than slow sustained advances. However, speculators (i.e., commodity funds) may have exaggerated the rally.

Natural gas futures prices rose sharply in the third quarter, with nearby futures at the New York Mercantile Exchange (NYMEX) gaining nearly 29% to average $2.44 versus $2.14 in the second quarter; second-quarter gains had been 11%. However, nearby futures at the Kansas City Board of Trade (KCBT) continued to outpace NYMEX, rising more than 31% in the third quarter on top of 15% gains in the second quarter, thus further tightening the New York/Kansas City spread. The nearby KCBT contract averaged $2.35 in the third quarter versus $2.00 in the second.

Because the heating season has not yet begun in earnest, we can only wonder how high prices will rise as temperatures fall. Residential, industrial and commercial consumers can already be heard murmuring “something smells rotten in the state of the Gulf Coast.”

Supply/Usage

The natural gas market's supply/usage balance has tightened because of lower-than-expected U.S. production. Consumers are fortunate that lackluster production gains have been partially mitigated by a rise in net imports. Still, total supply (production and net imports) in 1997 may be surpassed by total usage (industrial, residential, commercial and utility demand) if fourth-quarter weather conditions spur heating demand beyond normal levels. On an annual basis, we now expect that supply and demand will both converge toward 22.1 trillion cubic feet (TCF), suggesting the balance is indeed tight.

For the first eight months of 1997, U.S. natural gas production fell 0.3% versus the comparable year-earlier output. Moreover, monthly production statistics from the Energy Information Administration (EIA) have been revised lower repeatedly this year. The drop in production (albeit marginal) is confounding, especially considering that the number of active rigs looking for natural gas continues to rise; currently more than 600 rigs are in use. Nevertheless, actual output has not grown this year. Had net imports not increased through August by nearly 5% relative to last year's levels (due mainly to Canadian supplies), the U.S. market would have been considerably tighter. On a combined basis, U.S. production and imports are up 0.3% in the first eight months of 1997 versus the same time in 1996.

The tight supply picture looks likely to be tested later in 1997 unless output and imports expand or demand contracts. Mild weather in the first quarter alleviated some demand pressure and reduced the draw on storage, resulting in a decline of 2.8% in total usage for the period. Second-quarter demand stabilized, posting only a 0.4% decline versus the year-earlier level. Thus, even though demand dropped 1.0% in the first eight months of 1997 relative to 1996, the higher price environment still appears justified given the rising trend in demand seen in the third quarter. Higher electric utility consumption (particularly in the Western United States where summer temperatures were about 7.5% warmer than normal), as well as increased industrial and commercial usage are apparently behind the recent increases. Numerous plant outages and heavier-than-normal nuclear plant maintenance schedules were the primary factors behind the increase in utility demand, while robust economic growth contributed to the rise in commercial and industrial consumption. The recent stepped-up level of storage injections is also adding to demand pressures.

Utility consumption gains in the West typically do not significantly support NYMEX futures prices because of the contract's focus on markets in the Midwest and Northeast. Indeed. the NYMEX Permian Basin futures contract and the KCBT Western natural gas futures contract were developed to address the basis risk between the Eastern and Western markets. Usually, Western markets (e.g., California) get supplies from Canada, the Rockies and the constrained (but improving) San Juan Basin. However, these three supply regions also ship gas into the Midwest. Thus, as Western demand increases there is less supply available to the Midwest market, which may partly explain some of the physical market's apparent tightness and the rally in New York futures. Furthermore, the price spread between the two futures contracts indicates that Western demand was stronger than normal this summer. Consequently, it appears Western consumption was pulling supplies away from the East, thereby also supporting NYMEX prices.

Given the first-half results as reported by the EIA, we expect total 1997 demand will advance 1.0% over year-ago levels. However, a large boost will be needed in second-half demand to offset the warmer-than-normal winter that sent residential consumption down 7.5% during January and February while commercial usage fell 4.0%. As a result, first- quarter demand fell 2.7%. However, we believe the recovery in second-quarter total demand, aided by the ongoing strength in the U.S. economy, suggests that the second half will continue the strong consumption pattern. We forecast a 4.3% year-over-year rise in demand occurred in the third quarter and expect a 4.5% increase in the final quarter.

We believe natural gas consumption by utilities rose sharply in the third quarter (actual data is unavailable at the current time) due to plant outages (both nuclear and non-nuclear) and warmer Western U.S. weather conditions. Additionally, it appears that industrial and commercial usage also expanded, continuing a trend that likely will last well into 1998. Growth in the third quarter and early in the fourth quarter also was aided by stepped-up storage injections. For the year, we expect a 3.3% decrease in residential usage, a 4.7% surge in electric utility consumption, a 2.6% gain from the industrial component and a 0.7% jump in the commercial segment. Thus, total demand is expected to rise to about 22.1 TCF, up 1.0% versus 1996 levels, assuming a normal start to the upcoming winter.

Total production should have a better showing in the second half than in the first, especially in light of the high-price environment. In addition, we have confidence that the number of rigs detailed by the Baker Hughes rig count eventually will produce output gains. We look for 1997 production to rise to 19.1 TCF, up 0.4% versus last year. Given the slight production increase in the second quarter, we expect a 1.1% gain in the third quarter, followed by growth of 1.7% in the fourth quarter. On the import side, the 4.7% increase in net imports through August (as well as the higher U.S. price environment) should translate into an annual jump of about 7%, lifting net imports to about 3.0 TCF for the year. An increase in 1998 net imports will be limited by pipeline capacity constraints between the United States and Canada.

With supply and demand both forecast at 22.1 TCF to 22.2 TCF, the importance of winter weather is heightened, especially if it proves to be colder than normal. As always, the key to accurate natural gas demand forecasts is the weather. Due to this year's El Nino (and its loose association with warmer-than-normal winters in the Midwest and Northeast), expectations for natural gas demand that are founded on “normal” weather assumptions must be viewed skeptically.

A colder-than-normal winter would raise other concerns, mainly regarding deliverability (i.e., pipeline constraints). Capacity limitations are a key consideration because little has been done to alleviate the constraint points, especially those that feed the major consuming markets in the Northeast and Midwest. Periods of sustained cold weather in these markets could cause significant price increases on NYMEX while physical markets not well-connected to the Eastern pipeline system may lag in price due to inability to ship gas to areas of high demand. Such a development would also be reflected by an increase in the NYMEX/KCBT futures spread. Additionally, capacity out of the Gulf also warrants attention.

Many of the significant pipeline additions and expansions that have been announced (e.g., Northern Border, Alliance Pipeline, Alberta Pipeline and Sable Island) will not play a role in market fundamentals this year because the facilities will not be ready until at least the 1998/99 winter season. Finally, keep in mind that winter weather will affect not only the winter contracts but also the summer months because this winter's storage drawdown will impact the following injection season.

Storage

We believe the industry will enter the winter with storage at 2,800 billion cubic feet (BCF). Last year, the industry entered the heating season with 2,725 BCF (86% of capacity) relative to 2,958 BCF (93%) and 3,099 BCF (97%) in 1995 and 1994, respectively, based on American Gas Association (AGA) statistics. The slow start to this year's refill season resulted in stepped-up injections beginning in September and continuing well into October. This related demand is a component behind the recent market tightness.

In addition to following winter temperatures and heating degree days, monitoring storage withdrawals will provide insight in gauging demand. Our assessment of the averages suggests that weekly storage withdrawals in excess of 55 BCF in November, 95 BCF in December, 160 BCF in January and 110 BCF in February would support higher prices.

Weather

Over the next three months, natural gas futures will be influenced most by U.S. weather conditions. Typically, natural gas price forecasts (as well as demand and supply estimates) are founded on the assumption that normal temperatures (i.e., the 30-year average) will prevail and produce a normal number of heating degree days. While this approach is rational and prudent, the increasing strength of the current El Nino weather phenomenon suggests U.S. weather may be anything but normal. Given the sensitivity of some forms of natural gas consumption to weather (e.g., consumption peaks in January due to space heating needs), abnormal conditions can play havoc with demand, and therefore, prices. An El Nino's impact on U.S. weather is far from exact. During an El Nino, the subtropical jet stream shifts north to such a degree that it dominates its northern counterpart that usually brings Canadian arctic blasts to the Midwest and Northeast. As a result, past El Ninos have caused warmer-than-normal temperatures in the Western and North Central portions of the United States. More importantly, the impact during some El Nino years has rippled into the Midwest and the Northeast, creating warmer winters. Cooler-than-normal winter temperatures have been seen in the Plains, Rockies and from Texas through Florida under an El Nino, partly due to heavier rainfall and related cloud coverage. Other areas that experience higher moisture include the West and Southwest. However, the biggest concern is the impact that El Nino will have on the Midwest and Northeast, given the large role those markets play in terms of heating usage. A warmer-than-normal winter in those markets would more than likely be a significant price depressant.

Historically, the El Nino's peak impact on the United States has been felt from December through February, overlapping the peak consumption period for natural gas and an often volatile period for natural gas futures prices. Granted, there were other factors that affected futures prices during the two most recent El Nino occurrences, but this is how natural gas futures reacted in those years:

–The last El Nino (considered relatively short and mild) spanned November and December 1994. Natural gas futures were severally depressed, partly due to warmer-than-normal weather conditions.

–Another El Nino occurred from November 1991 to May 1992, longer in duration but still considered mild. Still, natural gas prices that year also experienced weakness.

The association between El Nino and warmer winter weather (even though it is loose) warrants caution because this year's El Nino is the strongest in this century. The existing El Nino began developing last spring. Sea surface temperatures in the equatorial Pacific, especially along the Peruvian coast, have risen to levels above normal that surpass the reigning champ of 1982/83. Indeed, on a recent trip to San Diego, we witnessed surfers, sans their traditional wet suits, enjoying the above- normal water temperatures. Moreover, tropical fish are being caught with regularity as far north as Washington state.

El Ninos also are associated with below-normal precipitation in the Caribbean and increased westerly winds, both of which work against the formation of tropical storms and hurricanes. The strong winds can shear emerging storm systems, thereby often impeding their organizational efforts. Less frequent and less severe hurricanes lower the risk of unplanned natural gas production curtailments, and thus, the related bullish impact on the futures market. Still, the risk of hurricanes cannot be ruled out because the storms do form under El Ninos. Hurricane season runs through November.

To date, the 1997 hurricane season has been quiet; whether a coincident or the result of the El Nino episode is uncertain. “Danny” provided the futures market with a brief scare in late July, but bought more barks than bites from traders. “Erika” lifted prices ahead of the Labor Day weekend, but she was taken out to sea (eastward into the Atlantic) away from the Caribbean Islands and the U.S. coast before Americans were back to work the following Tuesday.

Although warm winter weather in key U.S. energy markets and fewer hurricanes often occur during the El Nino, these developments are far from assured. Indeed, El Ninos have created both blizzard conditions and warm weather. The last severe El Nino began in June 1982 and lasted into August 1983. Nevertheless, the 1982/83 winter brought blizzard conditions that blanketed the Northeast with several feet of snow. The latest measures indicate that the current El Nino is stronger than that previous record- holder.

Price Outlook

Given disappointing domestic production and an anticipated pick up in demand, we expect the supply/usage balance to tighten further. As a result, we are raising our price forecast for the remainder of the year and for the first quarter of 1998. Indeed, the steady increase in NYMEX values from the $1.80 level reaffirms our belief that recent price levels are justified and sustainable. (It is more typical for this market to make advances in numerous exaggerated and often short- lived price spikes.)

Specifically, we believe prices will average about $3.25 in the fourth quarter and $3.00 in the first quarter of 1998, assuming a normal winter. Using our estimated price level for the fourth quarter, natural gas prices will average more than $2.50 on an annual basis. Our latest quarterly price forecast is listed in Table 3.

We believe that many natural gas producers (and other natural longs such as some marketers), will not aggressively use the futures market this winter, and this should be considered in one's trading strategy. This assumption appears rational, given the following factors: (1) widely reported cases in which producers experienced large hedging losses (primarily due to basis risk); (2) the natural desire of some producers not to forego upside potential; and (3) their recognition of delivery constraints within the U.S. market. Indeed, many risk management firms have been advising natural longs to lighten their hedge positions during the winter months. If our assumption is correct, then the futures market will experience less selling pressure (resistance) than might otherwise be expected, and price rallies may be exaggerated by the influence of commodity funds and other speculators. Given that managed funds contributed to the sharp increase in open interest for the NYMEX contract during the third quarter and the related price increase, one must respect their influence on prices.

Trading Strategy

We have a favorable opinion of the natural gas futures market, assuming normal winter weather lies ahead. Prices appear poised to rally sharply if normal or colder-than-normal weather conditions prevail, especially if a period of sustained cold weather arrives early. However, given current price levels, significant downside price risk exists. Indeed, with the current El Nino phenomenon the most severe on record, our “normal” winter weather assumption may prove too bullish. Still, we believe that stance is prudent, especially in light of the low correlation between the El Nino and its impact on U.S. weather conditions, particularly in the Northeast and Midwest.

We recommend buying the January contract on dips below $3.40. An “ideal” point of entry would be in the $2.90-$3.10 zone, or better. Under normal winter weather conditions, we believe prices could flirt with $4.00, while the record $4.60 high is possible if an early period of sustained cold weather (7 to 14 days) emerges by late November or early December in the Midwest and Northeast. If warmer-than-normal conditions linger into December, we would have to change our tune and expect a return to the $2.25-$2.50 level.

October 23, 1997 Richard Redash and Jim Ritterbusch

Prudential Securities, Inc.

One New York Plaza, New York, New York

Consensus National Futures and Financial On Line Index

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