Chicken Little has cornered the market on gas price doom and gloom, but the data is inconsistent on whether high gas prices are here to stay.
A near-universal consensus of alarm appears to be emerging concerning North American gas supply adequacy. The steady march upward of spot gas prices and NYMEX futures over the past year confirms this coalescence of market sentiment. Way back in June 2002, you could still buy Rocky Mountain wellhead production for about $1.25/MMBtu, although Eastern U.S. markets had already exceeded $3.00/MMBtu.
Today, that Rocky Mountain gas supply would cost you about $5.00/MMBtu, while Eastern supplies sell for well over $6.00/MMBtu. Storage inventories were blown down to record levels during the past heating season, gas producers continue to issue dire warnings about their ability to replace dwindling deliverability, and private and public prognosticators predict many years of supply curtailment and concomitant high prices. Both investment banking firms and brokerage houses are thumping their drums in unison on the latest hot sector as regulators and politicians notice and begin to address the reported problem in their individual, often heavy-handed ways.
My problem with all this brouhaha is the tiresome familiarity of the increasingly strident alarms coming primarily from the upstream gas industry as echoed and amplified by my fellow energy sector consultants and pundits.1 Crisis makes for good business to an interesting assortment of players, and I wouldn't want to spoil the party but for my concern that an overblown and transitory economic threat often leads to unnecessary and untimely legislative and regulatory intercession, typically yielding unintended and disruptive results. We need only think back fondly to the National Energy Act of 1978 and all its misguided particulars for (non)crisis management, or the current attempts at state and federal levels to fix the 2000-2001 "California crisis," itself the result of hype, botched legislation and regulation, and finally, direct political intervention, wreaking havoc in what was an otherwise sustained market response to anticipated shortfalls in wholesale power supply.
There are perhaps five observed gas industry features and trends that are used to support the argument for a serious and persistent gas supply/demand crisis:
- Prevailing futures prices and forward curves;
- Gas demand growth expectations;
- The near exhaustion of storage inventories over the past winter;
- Rapid deliverability decline rates from recently drilled gas wells; and
- The inability to muster a timely industry response, in part reflected in the weekly rig count data.
In what follows, I would like to address each of these subjects, highlighting certain mitigating factors that have not been given much attention. I then propose an alternative view of what is happening right now in gas markets and what will happen in coming months-where we find ourselves in the continuing interplay of cyclical business behavior and resource depletion and substitution-and therefore, what if any extraordinary market interventions are required now to accelerate supply augmentation and moderate absolute price levels and price volatility.
To begin, let us bear in mind that commodity price levels are not set or changed by rational and exhaustive analysis of supply/demand fundamentals. As in any market, incessant reports of problems, real or imaginary, raise anxieties and move market sentiment. For utility planners and large gas consumers, the news has not been good during the spring and early summer. Spot and futures prices continued upward, and the need to secure flowing gas supplies is pressing. As will be discussed further below, there is very little accurate current information on the state of the gas market other than prices and the weekly storage inventory figures from the U.S. Department of Energy's Energy Information Administration (a report that, in my estimation, has assumed inordinate importance to market participants simply by virtue of the fact that it is the only piece of current non-price market information available).
While it is true that commodity prices are primarily the result of market expectations (however uninformed), not the cause, technical analysis of recent gas price behavior also influences price expectations and thereby affects transactional activity and portfolio management decisions. If the factual assumptions that created the expectations are flawed but unchallenged, any technical analysis of price behavior only exacerbates the underlying error. Therefore, I would ask you to suspend belief for a moment, and examine the fundamentals on which the price run-up is based.
Last year saw a significant increase in gas demand due primarily to new gas-fired generation and a cold (actually, normal) winter. Presumably, new gas-fired capacity scheduled to come on line in 2003 will only exacerbate the gas deliverability problem. Demand destruction in the industrial sector would appear to be insufficient to counterbalance this increasing power sector demand. This argument, however, ignores the fact that power sector gas demand, like industrial demand, is price-sensitive. Last year, with gas prices in the $3.00/MMBtu range, combined-cycle gas turbo-generators (CCGTs) generally were baseloaded. Meanwhile, most coal-fired steam plants were being deeply cycled during off-peak hours. Gas consumption may have been up, but coal consumption was down.2 With $3.00 gas, it is cheaper to run the CCGT off-peak (and avoid accelerated maintenance costs and start-up heat rate penalties) than to shut it down. However, the break-even point on overnight CCGT operation is in the $4-$5/MMBtu range, depending on other associated costs and off-peak power prices.
This summer should see much higher off-peak coal plant utilization and a symmetrical reduction in gas consumption unless gas prices drop significantly. This price-induced demand destruction can be added to the other causes of reduced gas demand, including the closure of industrial facilities using natural gas as a feedstock, and the inordinately mild weather experienced in much of the country this spring.
As noted above, the EIA storage report has become, for better or probably worse, a major weekly event in the North American gas market.3 The news over the past winter was of a rapid and continuing inventory drawdown as cold weather in the eastern United States persisted. The obvious explanation was that available production was inadequate to meet its usual share of winter demand, necessitating depletion of storage inventories.
There were other factors afoot, however. The merchant energy financial crisis of 2002-2003 and the more pervasive liquidity crunch of all gas market participants played a little-noticed role in determining storage inventory levels. Merchant gas traders and other distressed market participants held large storage inventories to meet their supply obligations. Sales of storage inventories, purchased at around $3.00, were often the only quick source of cash over the winter in a $6.00 market, providing critical liquidity and operating profit to corporate parents but critically exacerbating inventory depletion. Recent record fill rates would suggest-but not prove-that the working industry hypothesis on inadequate wellhead deliverability was simplistic and overstated.
Deliverability Declines in New Gas Wells
For the past 20-odd years since de facto wellhead price deregulation, gas exploration and production (E&P) has been a sucker's game in North America. Industry-average returns on investment have hovered in the same range as passbook savings accounts, with periodic price boomlets to bolster those returns and to rebuild confidence and enthusiasm to continue the hunt.
Cumulative improvements in seismic data processing and interpretation, hydraulic fracturing of gas-bearing but impermeable rock, drill bit directional control (permitting, among other things, horizontal drilling through gas-bearing strata from a vertical wellbore) and other technological advances have allowed E&P companies to not only chase hydrocarbon "elephants" in extreme environments but also to target and profitably extract gas from previously uneconomic formations onshore and smaller geological structures on the shallow continental shelf of the Gulf of Mexico. Relaxed state regulations on well spacing allowed in-fill drilling in older gas fields to recover more gas-in-place. These techniques could be applied relatively quickly to a company's producing properties and previously evaluated onshore and offshore acreage under a mineral lease.
Because such wells are drilled in and around producing gas fields with established midstream infrastructure,4 the time from capital authorization to marketable production can be three to six months, although systematic exploitation of a given technique in geographically extensive gas-bearing formations can take many years.
It is these prospects that are first brought on-stream as a result of a multi-month price spike, such as the 2000-2001 gas price excursion during the California power crisis. As Henry Hub gas prices rose from below $3.00 in the spring of 2000 to a peak of over $9.00 in January 2001, the drilling rig count exhibited its typical lagged response. The U.S. gas well rig count rose from 600 rigs in the spring of 2000 to 880 rigs in January 2001 and only crested at over 1,000 rigs later that summer, six months after prices started to tank, reaching about $2.25 by September and languishing below $3.00 through the warm winter of 2001-2002.5
The new crop of gas wells resulting from this drilling boomlet was predominantly composed of field extensions and other low-risk/low-reward targets. Industry analysts who claim that the rapid decline in average wellhead deliverability from wells of this vintage is indicative of a major decline in North American prospect quality miss the point: Most of these wells were drilled on familiar territory to capture a short-term opportunity. Frontier exploration for large and expensive prospects continued apace, but represented a small percentage of the total wells drilled, with production lagging discovery by many years in remote areas.
Timely Industry Response
In both Canada and the United States, cheap and quick drilling prospects are declining after 20 years of steady exploitation. There is still money to be made on such plays, but the overall prospect mix is shifting to larger, deeper, more remote locations requiring greater per-well expenditures, potential delays in infrastructure access and, therefore, greater financial risk. This escalation in cost and requisite remuneration is a secular trend, not a cyclical phenomenon, requiring higher price expectations to justify investment.
Supply response does not consist solely of drilling activity, however. Demand growth also has highlighted constraints in the existing gas transmission infrastructure, attracting capital to capture the large price differentials that develop when too much gas deliverability is chasing too little pipeline capacity, such as in the Rocky Mountains, the San Juan Basin and, until recently, the Western Canadian Sedimentary Basin. A persistent transmission bottleneck out of Alberta was eliminated in the late 1990s with the opening of Alliance Pipeline and the numerous expansions of existing pipelines.
Other transmission projects are coming to fruition, and more are on the way. The Kern River Gas Transmission expansion project, in service May 1 of this year, is a case in point. The Kern River expansion, designed to bring incremental supplies of Rockies gas reserves to new power generation markets in Nevada and California, can now deliver enough fuel to generate about 5,500 MW of wholesale power supply. This new pipeline capacity (900 MMcf/d) immediately caused the Rockies basis differential (versus the Henry Hub) to fall from over $2.00 in April to about $1.00 as of mid-June, with producers pocketing the difference.
Meanwhile, the rig count continues to climb, with the overall U.S. oil and gas rig count at 1,071 as of mid-June (85 percent gas-oriented and up from 842 a year earlier) while the Canadian rig count has climbed to 344 from 222 over the same period. Higher gas price expectations have pushed many marginal high risk/high reward projects to the front burner as E&P companies review and pursue their prospect inventories. The North American resource base, variously estimated at 1,500 to 2,000 Tcf, indicates a domestic industry entering the decline mode some 20-30 years in the future, not today.
One final source of supply augmentation receiving much press these days is LNG imports. The immediate opportunity resides in the four existing import terminals (Lake Charles, La.; Elba Island, Ga.; Everett, Mass.; and Cove Point, Md.). In the short term, expanded LNG manufacturing capacity in Trinidad and Nigeria will find homes in the newly reopened Cove Point and Elba Island terminals. Cove Point alone will add 1 Bcf/d of incremental deliverability directly into the Mid-Atlantic region (enough to heat 3.5 million homes or fuel 6+ GW of CCGT capacity) later this year, bypassing upstream pipeline bottlenecks. Elba Island is ramping up production toward a sustainable 450 MMcf/d, to be expanded to 800 MMcf/d in late 2005. Other plant expansions are in the works elsewhere and many new North American import projects are advancing rapidly. Worldwide LNG production capacity continues to grow rapidly along with the specialized tanker fleet needed to transport product to market, stimulated not only by demand but also by significant improvements in liquefaction process and tanker construction costs. With some moderation in the historical veto power of not-in-my-backyard resistance, environmentally and economically sound import projects should come to fruition. With its inherent ability to immediately ramp output up or down in response to price signals, a dispersed network of LNG import terminals would provide the additional benefit of damping price volatility-not a popular idea with commodity traders but a real benefit to the U.S. economy.
In conclusion, the North American upstream natural gas industry, as currently configured, is in a period of transition, not irrevocable decline. The solutions to currently perceived supply shortfalls lie in incremental, market-based capital investment, not new government programs designed to accelerate deployment of politically favored technologies and energy supplies. The industry alarmists would have us believe that $6.00+ gas prices are with us for the indefinite future. The politicians have responded with calls for drastic federal intervention, with the promise of all the insight and benefits such intervention has provided in the past. I say the market is already well down the road to providing a solution to the current supply/demand imbalance and should be allowed to find its own way. Barring some truly extreme and pervasive weather patterns, we should know by next spring whether I'm right or wrong. A $3.50/MMBtu gas market is all it would take to spur a combination of accelerated exploration and development of available North American gas resources and investment in an LNG supply network to better integrate our market with the vast pool of un- and under-developed gas discoveries around the world. Let's keep our eyes on that prize and send Chicken Little packing.
- Two noteworthy contrarians have come to my attention to date: Judith Warrick, in an April 3, 2003, Morgan Stanley industry analysis (), and Vinod Dar, in a commentary appearing in the June 6, 2003, issue of ("There Is Tightness in the Gas Market, but Surely no Crisis"). I recommend them both to your attention.
- Special thanks to my colleague Jerry Eyster for his ongoing analysis of this issue.
- In a recent example of this obsession, the June 12, 2003, report indicated an increase of 125 Bcf nationwide. August NYMEX futures immediately fell 10 percent, despite the fact that inventories were still well below normal at this time and no fundamental information about the overall supply/demand situation had changed.
- Gas gathering, processing, compression, and transmission.
- Note that the drilling rig count, in itself, is a poor indicator of future incremental gas reserves and deliverability. Industry commentators point to the 4,000+ rigs at work in 1980-81 in contrast to the current figure of around 1,000. Forgotten are the billions of dollars of speculative capital that was wasted on highly dubious prospects. In a low-price environment, prospect quality must be high to justify the expenditure of risk capital; in flush times, shelved ideas come out of the closet as companies boost drilling budgets and passive capital becomes easier to attract. Predictably, average reserve additions per new well drop.
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