In the energy sector, price forecasts are generally every bit as good at predicting the recent past as they are spectacularly bad at predicting the future. This is especially true in the case of natural gas in the United States. Over the past several years, the industry consensus on the outlook for natural gas swung from one extreme to the other, and then back again. Forecasters of all types—from government, to Wall Street, to the gas and power industries—exhibited the classic bias of placing excessive weight on recent history. Forecasters into the mid 1980s continued to project a return to the higher prices of the late 1970s, resulting in consistently overestimated price forecasts. By the next decade, the opposite tendency was in evidence, with the actually realized lower gas prices projected indefinitely into the future. Predictably, this led to some substantial underestimates of prices, as well as some rather shrill contrarian warnings of extremely high prices and domestic shortages to come. Neither was correct. Finally, over the past few years, industry and forecaster views apparently capitulated to the recent years’ high gas prices, and started projecting higher prices into the future, similar to the forecasts from two decades ago. Each forecast era shared similar traits—historical bias, static analysis and a limited fact base. Any which way it’s cut, price forecasts, particularly market forwards, have been widely unreliable in predicting gas prices (see Figure 1).
These gyrating price forecasts, however, did serve a purpose. They provided signposts for counter shifts (inflections) in industry structure and dynamics. Since the start of this decade, conventional wisdom on gas has shifted from one of unconstrained (conventional) domestic gas supply to one where prices would be set by international imports of liquefied natural gas (LNG), with U.S. prices reflecting the global LNG and oil market. Now, a new era of domestic abundance is being proclaimed by many on the assumption of abundant unconventional gas.1 Throughout this period, we note the growing importance of trends in the U.S. natural gas sector for both the U.S. power sector, as well as the evolution of the global natural gas industry. This trend only will grow in significance.
There is an evolving debate around the prospects for U.S. gas supply and prices. But what does the latest, emerging consensus on the U.S. gas sector—namely, a massive upward revision in the size of economically accessible unconventional gas supplies—mean for the gas market, including implications for power and the global gas market? We’ll attempt to resist the temptation to get tricked by the static, extrapolation bias. Instead, it is important to focus on fundamentals by identifying which factors likely will define the next gas ‘era’ in North America (see Figure 2).
The lack of success in forecasting gas prices doesn’t make the attempt any less necessary. Correctly anticipating future gas-price trends has immense consequences, not just for the gas industry, but for power generators and energy-intensive industrial sectors as well. The long period of abundant conventional natural gas production throughout the late 1980s and 1990s, combined with breakthroughs in gas-turbine efficiency and the prospect of comprehensive electricity liberalization, were key factors behind the boom in gas-fired generation construction in the later 1990s, as well as the messy aftermath that followed. The prospects for cheap gas led to an over-reliance on new gas capacity. Companies who bet on a sustained period of abundant and cheap domestic natural gas were sorely disappointed as gas-generation capacity factors sank—victims of overbuild and diminished relative economics. On the other hand, investors in domestic natural gas production, and the midstream assets required to get the new production to market have seen periods of impressive performance.
Over the past five years or so, a new consensus has been emerging around the future direction of the U.S. gas market. Over this period, in part due to the demand growth from the gas-generation sector, the North American gas market tightened dramatically. This consumption growth was coupled with accelerating decline rates and diminishing yields of conventional natural gas production in the United States with little additional supply coming on-line despite historically high gas prices and extraordinary levels of exploration activity. Gas-price spiking became evident as supply/demand became imbalanced. The market began to anticipate long-term higher prices—and the embrace of the LNG solution tightened (see Figure 3).
Given growing gas demand, especially from power, and the prospects of dwindling supply, gas imports increasing appeared inevitable. The obvious consequence would be the convergence of the world’s heretofore regional natural gas markets, and as a result, the convergence of gas and crude oil prices. In practical terms, this implied an era of historically high natural gas prices. The economic argument was straightforward. North America would be obliged to meet its growing needs for natural gas via increased LNG imports. Given the tightness of current LNG-liquefaction capacity and the massive and rapidly escalating capital expenditures needed to bring additional LNG trains on line, it seemed likely that suppliers would be able to impose the same contractual terms for LNG exports long established in the North Asian and European markets. Specifically, LNG cargoes would be secured under long-term contracts, explicitly linked to oil prices. And given most analysts’ view of the prospects for a new era of oil prices in the $60/barrel and above range, this implied a future with natural gas prices in the $8 to $12/MMBtu range through the next decade. The lack of new liquefaction capacity coming on line over the past few years has accentuated concerns about tightness of global LNG, a major concern for gas buyers (and owners of re-gasification capacity in lower-cost markets like the United States) around the world.
As noted, it took a while for many to accept the notion that U.S. natural gas prices could equilibrate at these historically high levels, rather than near earlier estimates of LNG imports’ long-run marginal cost of $4.50 or lower. But more daring players were willing to place bets on this new vision of a global (and pricey) natural gas market. This included aggressive investment in re-gasification capacity—and the political battles such an effort entails—as well as strategies focused on optimizing the mix of midstream assets, including processing, pipelines, and storage, to accommodate a new series of gas flows and product characteristics. This perspective also created a focus on coal, renewables, and nuclear generation assets among players in the U.S. power sector. All would benefit from the high marginal electricity price umbrella supported by expensive natural gas.
This bullish outlook for natural gas also implied a higher cost for establishing mandatory global greenhouse gas (GHG) regulations in the United States under the various cap-and-trade regimes being debated. Seeing this relationship requires a bit of insight into the likely power industry sources of CO2 and its equivalents in the U.S. electricity sector. Given the range of electricity sector CO2 reductions in much of the legislation under consideration, the price of CO2 would need to be high enough to induce replacement of base-load coal capacity with new gas-fired combined-cycle capacity. Thus the price of CO2 and the price of natural gas would be linked. Furthermore, a view premised on high-cost domestic natural gas and a constrained—economically and/or politically—supply of LNG from foreign sources implies that cost and security issues would preclude the United States from relying on natural gas as a bridge to a lower carbon electricity sector, leaving renewables and conservation as the only near-term options for new generation in a carbon-constrained and tightening U.S. power-generation sector. At the higher level of gas prices implied by the new orthodoxy, an even moderately aggressive, pure cap-and-trade GHG policy began to look politically challenging (see Figure 4.)
The reality of historically high gas prices, and the prospect of sustained high prices in the new convergence era, had important consequences for the natural gas sector, beyond spurring strategies focused on investing in a globalized gas infrastructure. First, demand destruction in the industrial sector and all-electric residential supply penetration in rapidly developing regions of the United States (i.e., the South) accelerated. Second, and more significant, investment in unconventional domestic natural gas took off. Accompanied by little noticed breakthroughs in the art of exploiting shale, tight sands and coal-bed methane (CBM) reserves by numerous independent upstream producers and their service firms, production began to take off in the 1990s. The technology improved and became increasingly available using new work processes and techniques, resulting in a decline in production costs and buoyed investments in new unconventional production. The novelty of these developments, and perhaps because they were led by heretofore lower profile firms, resulted in a significant underestimation of natural gas production by the U.S. Department of Energy’s forecasting arm, the Energy Information Agency (EIA). For example, actual production in 2006 was more than double what the EIA forecasted in its 1998 and 2000 Annual Energy Outlook reports (approximately 4 Tcf short each year). Indeed, every forecast since 1998 has required significant upward adjustments. As the unconventional market has begun to emerge from the development stage, a new conventional wisdom on natural gas and its role in the overall U.S. energy sector is being born and being heralded by a well funded advertising campaign that promises a gas ‘panacea’ (see Figure 5).
What will this new outlook on the U.S. natural gas resource base mean for the gas and power markets? To begin to address this, we offer a few hypotheses, more to stimulate thought than to offer definitive (and inevitably embarrassing) predictions. In doing so, we start with a pretty heroic assumption, namely that the most recent set of forecasts around unconventional natural gas reserves and costs are roughly correct. Given that, we see the future rolling out in three basic phases.
• Phase 1: The Return of Autarky: In the near term, U.S. demand will be met with domestic (unconventional) supply, with little need for additional LNG imports, and thus lead to the de-linking of U.S. gas from global gas—or oil—prices.
The amount of unconventional natural gas in the lower 48 now deemed economically recoverable is impressive, both in its absolute size, but even more so from the fact that it somehow previously was overlooked by the sector’s experts. In any case, based on recent forecasts of the likely range of natural gas demand, we believe the latest forecast of U.S. natural gas supply looks adequate to meet domestic needs for at least the next few decades. As an illustration, the lack of LNG cargoes drawn to U.S. shores in the current price environment has led Cheniere Energy (a leading developer of merchant LNG re-gasification terminals) to seek out producers such as QatarGas and even sign marketing agreements with middle-market players such as JPMorgan to extend contracts that would fill some of the excess U.S. re-gasification capacity. But what about increased gas demand resulting from a lower price environment? We already have noted the potential for demand destruction in large segments of the U.S. gas market, so why can’t these price-sensitive segments (traditionally viewed as composing over 30 percent of the market) create demand under lower prices?
We don’t believe that near-term demand growth from lower prices will be enough to make a real dent, at least in the short run. First, much of the industrial demand destruction that occurred over the past several years of higher gas prices is irreversible. Indeed, many gas-intensive industries, such as building materials and petrochemicals, have relocated not just to access lower-cost gas supplies, but also to get closer to the much more rapidly growing markets for their products in the Middle East, Asia, and Latin America. Second, the trend of increased penetration of all electric residential services has more to do with the basic economics of home access in the faster-growing, lower-heating-demand regions, than with the relative gas commodity price. As a result, lower prices are unlikely to result in a significant medium-term increase in residential demand, consistent with the famously low demand elasticity seen in gas consumption in the non-industrial end-use sectors. Third, and most obviously, the current recession significantly will dampen gas-demand growth in the industrial, residential, and commercial sectors. That leaves the power-generation segment, which has doubled its share of total U.S. gas consumption to 30 percent over the past two decades. While there remains significant unused (combined-cycle and steam) gas-generation capacity across the country, we don’t foresee that gas prices even in the $5-$6/MMBtu range will lead to a massive increase in gas demand from existing units, particularly given the prospects of minimal or negative power demand growth in a recession, combined with plummeting coal prices.
Given the above, U.S. gas prices will remain de-linked from global LNG and thus crude oil prices. The netbacks for U.S. LNG imports need to match or exceed those for European or North Asian destinations in order to attract the marginal shipment of LNG. In regions of the world like Japan, where petroleum products based on >$70 crude oil are the next best option for generating an incremental Btu of heat or light, LNG landed at under $12/MMBtu representing an economically superior alternative for them. But with domestic unconventional natural gas available at $6/MMBtu or less, LNG prices would cease to pose a realistic option for the United States, and import parity pricing for U.S. natural gas would cease to hold. U.S. gas prices once again would march to the beat of their own drummer, as they have during earlier periods of gas-on-gas competition. Another potential impact of more abundant unconventional gas may be the effective diversion of natural gas in Alaska and Canada that long has been expected to flow south to the lower 48, to move instead to more lucrative markets overseas via LNG. The logic is the same as described above, in which the abundance of unconventional gas lowers netbacks of exports into the continental United States below those of Asian or European markets.
• Phase 2: LNG Redefined: The unexpected abundance of unconventional gas in North America, and possibly around the world, leads to a surplus of liquefaction capacity and thus the development of a significant spot market for LNG.
The discovery of massive unconventional natural gas reserves is not limited to North America. Australia, China, India, Southeast Asia, as well as parts Europe (UK, Poland, Italy, etc.) all have anywhere from significant to massive unconventional reserves. Excluding Australia, significant production is several years out, and often blocked by murky rules around resource access and inadequate gas infrastructure to get the gas to market. What impact will all this new gas have on the LNG market? Very simply, one must wonder if the combined impacts on LNG supply and demand has the potential to push global liquefaction into surplus by some point in the next decade? The potential for additional volume from markets like Indonesia (Kalimantan and Sumatra) and Australia (Queensland), combined with decreased demand for LNG from gas-hungry and unconventional-rich countries—above all the United States, but importantly China and India as well— has the potential to strand a significant fraction of planned and existing liquefaction capacity.
What would this entail? Such an environment would not just spell disappointing performance for the owners of the liquefaction capacity, but also create the conditions for the emergence of a significant spot market in LNG. Today, the spot market only represents 10 percent to 15 percent of total LNG sales. However, a back-of-the envelope calculation comparing planned capacity and potential changes in net demand based on the unconventional-gas story above suggests the spot share of the market could grow significantly. There was a similar phenomenon in the U.S. petroleum refining and marketing market in the 1980s, when excess refinery capacity led both to unhealthy spreads, as well as the emergence of a spot market. Given existing excess capacity, owners of liquefaction would be hard pressed to pass up the opportunity to sell excess product on the market at a price at, or above, their marginal cost, rather than insisting on long-term contracts tied to the price of petroleum. In this scenario, we’re back to the simple world of potential LNG prices of ~$5 to $6/MMBtu delivered to the United States. These prices would reflect the long-run marginal price of the LNG, rather than the much higher price of the substitute for natural gas, crude products. Note that one could get to the same delivered LNG price even in a world without excess liquefaction capacity, but only with crude oil around $35/barrel—laughably low a few months ago—but close to many of the majors’ longstanding planning assumptions just a few years back.
Finally, if the reader struggles to believe the world will overshoot its liquefaction capacity additions, or fail to rapidly exploit the potential of unconventional gas outside the United States, or see oil under $40/barrel, there’s one more variant of this scenario that gets us back to LNG at its long-run marginal cost in North America. That is the situation in which the recent period of historically high petroleum prices leads China and others with significant oil and diesel-fired generation to replace it with something else, be it natural gas or coal or a lower carbon alternative. In this case, should the electricity sector remain the marginal consumer of natural gas in China, the price of natural gas would need to remain in equilibrium with the cost of coal generation, perhaps including a global CO2 price at some point in the not too distant future. Something quite similar happened in the United States and Western Europe after the oil embargoes of the 1970s, when petroleum’s share of electricity generation fell from 19 percent to 12 percent over 5 years. And as occurred in the United States, this would cut the direct link of substitution between natural gas and crude oil. This variant also is consistent with less-expensive LNG prices. As an illustration, if we assume a $30/ton price for CO2, and coal prices of around $1.50/MMBtu, the marginal price of landed LNG imports into China would need to be under ~$6 to compete for their share of the electricity generation market.
• Phase 3: Calpine’s Revenge: A few more years out, natural gas will capture a significant share of new generation capacity additions, leading to a belated need for LNG to meet demand.
“Ahh,” objects the gas bull out there. In a world of abundant, low-priced domestic natural gas, won’t demand from the power sector take off, particularly in the form of building relatively low GHG-emitting natural gas combined-cycle generation capacity? In the United States, the combination of increased utilization of the current fleet, plus the choice of combined-cycle units as the preferred option for new base load (assuming the threat or reality of carbon constraints) could result in an incremental annual gas demand of 2 to 3 TCF or more within the next several years. At the very least, wouldn’t this unprecedented level of gas demand require tapping some of the higher-cost unconventional resources? At that point, LNG imports pretty well may look compelling, especially given the scenario painted above in which the price of LNG settles near long-term marginal cost through one mechanism or another. And thus once again we’re back to a global gas market, albeit delayed by several years and at a lower gas price than recently forecasted.
Or are we? The continued growth of wind and other renewables has the potential to significantly mitigate the impact of this gas generation-friendly environment on gas demand. For argument’s sake, take a fairly aggressive scenario around renewables penetration of 20 percent in 2015 or 2020 (versus under 5 percent, excluding conventional hydropower, today). This is estimated to displace up to 3 TCF or so of gas per year. While this reduction likely would be offset partially by increased gas consumption for simple-cycle turbines for firming capacity, a substantial share of this could in turn be offset by non-gas capacity from various types of storage and demand-response programs.
Nonetheless, even this rather green scenario merely would postpone a re-bound of gas-demand growth from the generation sector by a few years. The bigger question is how steep the supply curve of unconventional natural gas really will be, especially in light of issues around water disposal in sensitive regions, as well as the still rather limited visibility into the real nature of the resource base’s economics. Some leading oil and gas independents’ recent statements about backing off earlier production growth commitments in light of gas prices falling under $8/MMBtu leads one to wonder.
For example, Chesapeake Energy has stated regularly that the industry requires $9-$10 gas to support the number of current rigs, with a credit crunch accelerating a reduction in rigs. While the quantities and affordability of domestic unconventional gas appear impressive, only time will tell.
The other key question is how the global LNG market actually will look at this point. Will it remain tied to high-priced oil, or will part of that equation—either high-priced oil or LNG’s ties to oil—sufficiently be altered to bring LNG prices significantly lower than today’s, and thus a viable competitor for U.S. gas demand? As seen of late, the price and structure of the global LNG market also will be tied to broader global macroeconomic factors, such as global commodity prices, engineering, procurement and construction (EPC) prices and availability, and the value of the dollar. Regardless, it’s likely that LNG indeed will matter for the U.S. gas market at this point, either as a participant or as a potential entrant, setting a price ceiling. At the extreme, should U.S. unconventional supplies really prove to be available at the levels and low incremental production costs suggested by some recent analyses, then conditions may exist for investment in U.S. gas exports at some point in the next decade. While this may sound fanciful today, the point is that even in this scenario, U.S. gas prices could be linked to global prices, though in this case at export rather than import parity. And this linkage is likely even without an actual molecule of natural gas ever being shipped to (or from) U.S. shores.
Bringing the various threads of this story together, we arrive back approximately where we started. That is, with a view that in the medium term, LNG imports are likely to play the pivotal role in determining U.S. natural gas supplies and prices. Corollaries to this view include a linkage of U.S. gas prices to those of the rest of the world (though not necessarily those of oil), and the likelihood of the United States serving as the swing consumer and storage depot for the global LNG market. The changes to the U.S. midstream sketched above once again would require attention, including reconfiguring pipelines, storage, and processing capacity to accommodate altered product flows and specifications. However, much is different about this emerging view of the future of the gas market. The equilibrium price of gas implied by this perspective is probably higher than the ~$4.00/MMBtu levels predicted a few years back, thanks to increases in liquefaction construction costs, but is well beneath the current levels of LNG prices. And this convergence would occur several years after earlier predictions had anticipated, perhaps not until well into the next decade rather than in 2009 or so as previously envisaged. Above all, the potential impact of unconventional gas production on the U.S. could be immense, both for the U.S. gas sector—including sweeping implications for the midstream to support new unconventional supplies—but also for the U.S. power sector, carbon policy, and the global natural gas industry.
As is obvious from the scenario sketched above, we believe analysts of the U.S. gas market have fallen victim to the inherent rigidities in the market. Supply in this market tends to over- and undershoot demand, thanks to lags in major capital projects and predictable biases in planner’s forecasts (i.e., placing excessive weight on recent experience). As a result, taking bets on some view of the correct fundamental equilibrium price of natural gas appears risky. Instead, the question revolves more around getting the timing of different developments right, rather than predicting the right price. More practically, our perspective points to several nearer-term imperatives for participants in the gas and power market.
Many analysts have characterized the availability of LNG imports as a safety net, ensuring the U.S. market will have access to adequate gas supplies even as the domestic supply-demand balance tightens. However, LNG imports at recent global prices also provided a very attractively elevated price umbrella for domestic natural gas prices, along with all those assets dependent on gas prices. Going forward, in light of the new outlook on the abundance of domestic U.S. resources, participants in the up- and midstream gas industry will need to learn to invest and operate in a lower price environment. This will have immediate impact on some unconventional producers’ capital plans. In addition, accelerated maturation of operating practices—i.e., industrializing and standardizing production, streamlining basic business processes, etc.—among unconventional players will be critical. Consolidation also seems likely, particularly as capital constraints become more binding throughout the industry given the current global financial environment.
At the same time, quick turn-around for LNG terminals is not likely. This will lead to consolidation as well as deferred and cancelled projects in the near-term. A trend towards vertical integration of LNG assets is a potential strategic move by the majors as they gain the greatest value from the North American market option and have the capital to weather the current market.
As a result, the prospects of several years (at least) of moderate gas prices suggests that gas-fired generation once again may be the most attractive option for mid-merit and base-load power generation, particularly in the light of expensive capital and rapidly-approaching carbon constraints. Conversely, the economics of coal, nuclear and renewable generation all will appear that much less attractive in the future sketched above.
But then again, we all know how dangerous it can be to try to predict gas prices.
1. The term “unconventional” used throughout this article refers to natural gas produced from shale, tight sands, and coal-bed methane geological formations.