WASHINGTON–The North American natural gas industry is in the midst of profound transformation. The successful development of the Barnett Shale has spurred a succession of shale gas plays, beginning with the Woodford and Fayetteville, and then expanding to the Haynesville, Marcellus, Horn River and Eagle Ford–many of which are more prolific than the Barnett and also have significantly lower cost structures in core areas.

Production from shale is growing explosively, and already is having a major impact on prices. This unprecedented growth from formations that still are at an early stage of development has far-reaching implications for the long-term forward delivery price curve for natural gas and the allocation of capital among other supply sources, and requires every company in the industry to rethink its strategic plans–from industry giants to smaller independents. It already has caused major international players to start pouring funds into the United States and could result in permanent changes in the composition of the industry.

The U.S. Energy Information Administration’s revised monthly production data released April 29 drive home the pivotal impact shale is having on the market. EIA’s report applied a revised methodology for estimating gross withdrawals. EIA used this methodology to report production for February 2010 (the most recent month covered by the report) and adjusted its previous estimates from January 2009 using the same methods.

EIA’s report stunned the market.

Many observers had expected the agency to sharply cut its earlier estimates of U.S. production, possibly by as much as 2.0 billion cubic feet a day, in support of the widespread belief that domestic production had dropped much lower than year-ago levels as a result of the steep rig count declines that began in the fall of 2008. While the rig count began to climb rapidly last fall, most of this rebound has occurred too recently to have a major impact on February production. Notably, the rig count this spring has still been more than 40 percent below its 2008 peak.

If EIA’s April report had confirmed these beliefs, the market might have rallied significantly, especially since price support near $4.00 an MMBtu seemed to be rock solid for most of April. Prior to the release of the report, the May 2010 contract (at the time, the front month) started to head up and went off the board the day before EIA issued its production report at a final settlement price of $4.27 an MMBtu–above the front-month contract closing price on 29 of the previous 30 trading days. A rapid return to prices in the mid-to-high $4.00 range seemed possible, with corresponding increases in the 12-month strip.

EIA’s production report dashed these hopes, at least for now. While the April report adjusted EIA’s earlier estimates downward, the reductions generally were in the range of 300 million-500 million cubic feet a day, which were too low to drive the market back up. The greatest shock, however, was the report for February. EIA estimated gross withdrawals for the lower-48 states of 63.85 Bcf/d, which was an all-time high and 1.0 Bcf/d above January. This increase, combined with a very bearish storage report issued the same day, sent the market tumbling. For the day, the June 2010 contract (which rolled over to become the front-month contract the same day the report was released) lost $0.37/MMBtu–its largest loss in many months.

Stunning Increases

Near term, EIA’s February production estimate is likely to have a greater impact than the adjustments for earlier months. The February estimate may be reduced modestly when EIA releases its May report, but the primary reasons for the February increase ring true: stunning increases in the Haynesville and Marcellus shales (and to a lesser degree, the Granite Wash play), recovery from freeze-offs in December and January, and increased pipeline send-out capacity.

The February data indicate that growth in production from the emerging shale plays and other sources entirely offset declines elsewhere by early this year. This growth, coupled with the increases in the rig count late in 2009 and during the first three months of 2010, suggests the potential for continued significant increases for at least the next three months.

Weather forecasts suggest that weather-driven demand for natural gas could fall far below normal by June. Furthermore, now that the $4.00/MMBtu barrier has been broken, traders who are shorting the market could become even more aggressive. At least for the next 30 days, therefore, natural gas is likely to remain under significant downward pressure. Despite the strong support for the front-month contract shown during most of April, a rapid drop to the mid-$3.50/MMBtu range would not be surprising.

Prices are unlikely to fall as sharply as last year though, when the front-month contract briefly fell below $2.50/MMBtu in order to induce sufficient substitution of natural gas for coal for the market to reach equilibrium.

There is no shortage of factors that are likely to create continued downward pressure. Decisions regarding the level of drilling during the past year have been less closely tied to the cash market price than in the past. This is partly the result of significantly increased hedging, which allowed many producers to lock in prices in 2009 and early in 2010 that were much higher than current levels. This creates incentives to continue drilling wells in 2010 that are not cost-justified at current price levels. Hedges by publicly traded producers are at an all-time high, with an average of 49 percent. While less data are available for privately held companies, many small and medium-sized producers also have hedged their production for this year.

Moreover, the investments made in shale plays over the past 24 months increase the risk that production will not fall significantly until the third or even fourth quarters of this year. Industry insiders estimate that more than 50 percent of the drilling that is occurring in the emerging shale plays is being done to maintain leasehold interests that might otherwise be forfeited, and is not price sensitive. This need to continue drilling to retain acreage often acquired at high costs could continue for many years.

Other factors, including Wall Street’s interest in companies poised to become dominant shale players, also could push shale production higher for most of this year. Over the past 24 months, since the magnitude of the Haynesville’s potential became public, most large U.S. producers have “picked up stakes” to a significant degree, allocating large shares of available capital to developing shale formations that were not even on the industry’s radar when 2008 began.

The inflow of capital from other sources has been even more impressive. ExxonMobil’s acquisition of XTO Energy Inc. in late 2009 made the biggest splash, but a long list of other investors has bet tens of billions of dollars on shale in a remarkably short time, including BP, Shell, British Gas, Statoil, Total, major Japanese companies, and an increasing number of overseas players–many of whom have not previously played a significant role in the U.S. market. Many of these companies are committed strategically to becoming major players in shale development, which requires huge commitments of capital and is expected to offer major economies of scale. Given their strategic commitments, these companies are not likely to cut back quickly on their efforts to become industry leaders in shale.

The factors that may tend to push production higher, however, should not be exaggerated. As hedges fall off, cutbacks in drilling are likely to accelerate. Furthermore, the market is much closer to equilibrium than it was at this time last year. Our models indicate that, in a normal weather scenario, even after taking into account the implications of EIA’s report for production during the remainder of the injection season, the amount of natural gas available for injection into storage at current price levels is on a trajectory to reach end-of-season storage of approximately 4.0 trillion cubic feet. Last year, this would have resulted in a major overflow condition, with gas available for injection into storage far exceeding usable storage capacity unless prices fell to $2.50/MMBtu or lower for an extended period.

Storage And Price Outlook

This year, as a result of new storage capacity, storage operators can accommodate 4.0 Tcf of and possibly even 4.05 Tcf-4.10 Tcf unless weather-driven demand is exceptionally weak. Therefore, no storage squeeze is likely to occur, and it will not be necessary to induce nearly as much substitution of natural gas for coal as was required last year. Even if prices fall to the $3.00-$3.50 an MMBtu range, they should rebound to $4.00/MMBtu months before the end of the injection season, as the lower need for coal displacement becomes clear.

Current price levels will inevitably lead to further cutbacks in drilling. As U.S. production begins leveling and demand continues to increase, prices are likely to move back above $4.00/MMBtu, and in all likelihood, reach $4.50 or even $5.00 an MMBtu before the end of this year.

By adding vast new reserves in both the United States and Canada, and by bringing large new production volumes to market, shale plays have permanently changed the supply side of the natural gas equation. And while the supply-side revolution is still at an early stage, already it is abundantly clear that decade-long concerns about the adequacy of North American supplies were obliterated in 2008 when initial test drilling awakened sleeping shale gas giants in the Haynesville and Marcellus.

Operators have unlocked a tremendous new supply resource in shale basins. If it is used wisely, it could fundamentally alter U.S. energy and environmental policy for decades to come and greatly strengthen the U.S. economy. Fundamental change already is sweeping through the industry that is developing this resource. Stunning technological improvements, sharp reductions in development costs, and the immense reserves locked in gas shales have resulted in one of the most rapid redeployments of massive assets ever experienced in any industry.

However, the April EIA production report underscores the potential to increase production from shale plays far more rapidly than was imaginable only 12-18 months ago. Many large producers have concluded that there are compelling strategic reasons to become major shale players so that they do not get left behind their competitors. This is resulting in more rapid growth in shale production than the market needs.

Longer-Term Implications

The longer-term implications of the emerging shale formations are clear: Shale is here to stay and is resulting in a fundamental restructuring of the U.S. market. Huge amounts of capital are committed to shale development. The costs for shale development vary considerably, based on the formation being developed and the quality of the particular site, and are typically much lower in core areas of a play.

In addition, the skill level differs significantly, in part, because some producers already are far down the learning curve while others only recently have made major investments in shale. In the aggregate, however, the industry already has gained enough experience to be confident that huge increases in shale production can be achieved at a break-even Henry Hub equivalent price of $4.00/MMBtu. However, efficiencies continue to improve in shale plays, and like most manufacturing processes, production costs are likely to continue to decline. In five years, the break-even price for developing core reserves could be significantly lower than today.

Looking forward, as horizontal drilling and hydraulic fracturing technologies continue to improve, a new generation of gas shales and tight gas sands are likely to be developed. If these efforts are successful, the implications are staggering. The potential increase in North American supplies, coupled with energy efficiency, could be sufficient to eliminate the need to rely heavily on coal-fired electric generating units. Carbon dioxide emissions from power plants could be quickly reduced by almost half, at much lower cost than under the major climate change proposals pending before Congress or the cost of a carbon tax. At the same time, emissions of mercury and other dangerous pollutants could be reduced considerably. Additionally, oil imports could be cut sharply at no additional cost, significantly improving the U.S. trade balance.

The expertise developed by U.S.-based producers is also starting to be applied to major global shale formations, where the resource potential has barely been scratched. Within three or four years, the natural gas available to Europe and Asia could begin to mushroom, reducing the risk of price spikes in the global liquefied natural gas market that could spill over into the U.S. market. Developing new sources of supply also could weaken Russia’s strategic influence over Western Europe. Russia has increasingly used its chokehold on delivering pipeline supplies to Europe to exert leverage on European governments, reducing U.S. influence on a number of important geopolitical issues.

If the United States acts quickly and sets a strong example, expanded use of natural gas can significantly reduce global demand for crude oil–both in the transportation and manufacturing sectors–which would significantly reduce dependence on oil imported from the Middle East, West Africa or Venezuela in the near term, and potentially eliminate it almost entirely over the longer term. No comparable “game-changing” event in global energy supply has occurred for many decades.

Technology Play

Fundamentally, shale development is a technology play made possible by applying industrial manufacturing techniques to produce natural gas in ways that have not previously occurred on any significant scale. The first horizontal well was drilled in the Barnett Shale in 2003, and within a matter of months, drilling was almost exclusively horizontal, with wells completed using multistage hydraulic fracturing. As Barnett operators gained experience, horizontal drilling and multistage fracturing have been improved continually, creating a virtuous circle. As more wells were drilled, costs continued to fall. Fit-for-purpose rigs drove major drilling efficiency improvements, cutting-edge modeling systems allowed continuous adjustment of the angle at which laterals were drilled, and microseismic monitoring tools provided real-time feedback to optimize stimulation treatments.

Increasing the numbers and lengths of laterals to 16 per well, with each lateral extending almost a mile through the pay zone, dramatically increased the area from which gas could be drained from a single bore hole. The learning-curve benefits from stimulating thousands of horizontal wells have been, if anything, even more dramatic. Barnett wells that had only a couple frac stages as recently as three years ago now are routinely fractured in 12-16 stage treatments.

The result of all the innovations and “lessons learned” over the past seven years in the Barnett is a fundamental paradigm shift in gas production and its potential role in the U.S. and global economies. In 2003 and 2004, Barnett Shale production barely moved the needle nationally. By 2008, however, it had reached 4 Bcf a day, becoming the fastest growing domestic source of natural gas and accounting for almost half of total U.S. onshore supply.

However, the incredible growth of the Barnett Shale has barely scratched the surface of potential production from lower-48 shale formations, and the same story is now playing out in other plays across the country. Silicon Valley and the information technology revolution have transformed much of the U.S. economy over the past three decades. But its greatest impact on natural gas production is occurring right now.

Strategic Planning

This is a unique time for the industry. Much has changed, and the change has come swiftly. It is essential, therefore, for every natural gas producing company–from the smallest mom-and-pop organization to the largest of the industry giants–to comprehensively review its strategic plan and reassess how to best deploy its resources.

Although shale production is the fastest growing source of U.S. natural gas supply, conventional reservoirs are expected to remain the largest supply source over the next decade. That said, however, both horizontal and vertical drilling technologies should continue to evolve rapidly. As shale’s market share continues to grow, the amount of gas needed from conventional reserves is likely to decline commensurately, eliminating the need to develop the most expensive tier of reserves that were needed to balance the market in 2007-08. As a result, for the foreseeable future, prices are likely to remain lower than they were in 2007-08. Margins also are likely to remain smaller, even for prospects that remain cost effective to develop.

During this time of continued rapid change over the next 10 years, it will be more important than ever to correctly predict future price trajectories. It also will be critical to concentrate control of reserves and drilling programs on prospects where margins are likely to remain attractive, even if the forward delivery price curve remains at the $4.00/MMBtu level.

Producers would be wise to heed Wayne Gretzky’s counsel to “skate to where the puck is going,” and not to where it already is. To maximize future success, producers must keep abreast of the rapid changes as they occur in the industry, and develop an accurate vision of where the market is likely to head next.

In addition to the challenges inherent in managing rapid market shifts, the industry’s composition also is changing quickly, largely because of the belief that gas produced from shale is likely to grow explosively, with continued efficiency improvements and major economies of scale. This is especially true for large producers experienced at developing gas shales. ExxonMobil’s acquisition of XTO is widely seen as heralding far-reaching industry consolidation. Attention is focused primarily on large U.S. independents, which many market observers see as prime acquisition targets for supermajors seeking to expand their gas shale positions.

At least one or two more “mega-acquisitions” are likely to occur within the next two years, but the number of large acquisitions may be smaller than many expect for a couple reasons. First, the supermajors tend to be cautious. Until they see clear evidence that gas prices have stabilized, many potential purchasers may prefer to expand their stakes in the U.S. market incrementally, by providing capital to develop specific reserves and acquiring partial ownership positions in those reserves.

Moreover, shale development is very capital intensive. If prices remain weak, large independent producers may need to hoard capital, reducing the number of acquisitions of medium-sized producers. The roll-up of small- or medium-sized companies could grow, however, during a period in which the most financially robust producers focus on steps to improve their competitive positions in a shifting market.

Structural Changes

Concurrent with the onset of this nascent consolidation and the flood of new players into the U.S. natural gas industry, far-reaching structural changes are happening to the way the U.S. and global natural gas markets function. These changes deserve more attention than they often receive. They already have been a major influence on the long-term forward delivery price curve, which has fallen faster and further than anyone in the industry had reason to expect two or three years ago, and could permanently change the industry’s economic model.

During the past 12-18 months, the U.S. market has become far more physically integrated, creating broader interregional competition and quickly reducing interregional spreads. This rapid decline in spreads is primarily the result of:

• The completion of the Rockies Express Pipeline, which integrated the Rockies with markets in the Midwest and the Northeast for the first time;
• A rapid production ramp-up in the Haynesville and the Marcellus shales, which still are at early stages of development; and
• A major new source of imports into the Northeast as a result of operations at the Canaport LNG terminal in New Brunswick, Canada.

As a result of these major changes in supply sources, basis differentials frequently have plunged to only a few pennies over much of the United States. They are likely to permanently shrink spreads between the Rockies and the East Coast, and on many days, sharply cut the premium for delivery points in the Northeast. Over the next few years, the impact on prices in New York and the Northeast and Midwest regions could intensify.

These same structural developments are likely to result in a steep decline in the amount of gas sourced from the Gulf region into the Northeast, the Mid-Atlantic region and the Midwest. This could have a major impact on Henry Hub prices, since production from Haynesville, Eagle Ford, Fayetteville and other emerging shale formations is likely to be growing simultaneously at a tremendous clip. This could drive down the price of the Henry Hub NYMEX futures contract significantly in comparison to prices at other hubs.

At the same time, the completion of liquefaction projects in Qatar and other gas-rich areas around the world that were started many years ago is causing a huge increase in global LNG capacity that will not begin to plateau until next year. Increased LNG supplies over the past 18 months already are integrating the global market in unforeseen ways, and are resulting in a much closer correlation between prices at Henry Hub and key delivery points for the European market.

While U.S. LNG deliveries have not yet started to grow, LNG deliveries to U.S. terminals can no longer be viewed in isolation from the other major North American terminals in New Brunswick and Mexico. Significant amounts of LNG have started to flow into the United States through Canaport. Increases in spot market deliveries at the two Mexican terminals also have been reducing net exports from the United States into Mexico, creating a more fully-integrated North American LNG market. This already has been a major factor increasing the link between European prices and the Henry Hub spot market price, which could intensify within the next few months, with U.S. LNG deliveries expected to increase. Since the U.S. market is becoming far more integrated, a highly integrated global market may develop faster than is anticipated generally.

Expanded Storage Capacity

The single most important component of restructuring in the North American market, however, is the huge increases occurring in the amount of U.S. underground storage and simultaneous increases in LNG storage at Canaport and Gulf Coast terminals. By next year, the amount of usable storage capacity available to the U.S. market will be almost 1 Tcf greater than it was only a few years ago. This incremental storage capacity is sufficient to cover nearly half of the total amount of gas withdrawn from storage nationally during most withdrawal seasons. This unprecedented increase in storage capacity is a major factor driving the integration of the U.S. and global markets.

But just as significantly, it could permanently mitigate U.S. price volatility, sharply reducing both the frequency and severity of price spikes. The potential for dramatically reduced price volatility is further enhanced by growing supplies from gas shales. As has been definitively demonstrated in the Haynesville and other plays, the industry has the ability to increase production at an unprecedented rate, adding several billion cubic feet a day in supply in less than one year. As development continues to extend into new shale plays, this capability is likely to continue to grow. The ability to quickly increase or decrease the rate at which wells can be refractured also provides the industry with new-found flexibility to rapidly adjust production as demand dictates.

The downside for producers is that reducing the risk of price spikes undercuts the potential upside, and could reign in the forward delivery price curve for years as the scope and efficiency of shale production continue to expand and the break-even price in shale plays drops even further. The options for expanding supply will increase further if horizontal drilling and multistage fracturing can significantly reduce costs for developing tight gas sands, but increases in the forward delivery price curve could be even more limited.