A Petroleum Tanker of a Different Color: Obstacles to an LNG-based Global Gas Spot Market Dr. Jeff D. Makholm NERA Economic Consulting firstname.lastname@example.org +1 617 927 4540 Dr. Laura T. W. Olive NERA Economic Consulting email@example.com +1 617 927 4588 2 Abstract The production of unconventional gas has driven North American gas prices down to a fraction of those in the EU for more than six years. Will a spot market trade in oceangoing liquefied natural gas (LNG) serve to balance those price differences in a global gas market, as oceangoing crude oil trade does for oil markets? This is highly unlikely, for two reasons. First, maritime LNG transport is far more costly and capital intensive than for crude oil. Second, the high gas prices evident in the EU do not reflect the actions of supply and demand in a competitive market (as in North America), but rather result from the barriers to competitive entry inherent in EU gas industry regulation. Those EU regulatory barriers to competitive entry effectively exclude both spot-market LNG and unconventional gas production. Even were those barriers to competitive entry to fall, it will be hard for maritime LNG shipments to compete with less capital-intensive local unconventional gas production. Thus, given its high cost and the uncertainties in reliably gaining competitive access to customers outside of North America, LNG trade will remain dominated by long-term contracts instead of the commodity spot markets that typify world oil markets. Keywords: Liquefied Natural Gas; Oil; Institutions; Asset Specificity; Transactions Costs 3 Contents Abstract 2 Introduction 4 The Oceangoing Trade in LNG vs. Crude Oil 5 Oil and Gas Prices in World Markets 7 The Cost of Martime Transport of Oil and Gas 13 Reaching Producers and Consumers at the Ends of the LNG Journey 17 Entry Competition for LNG from Unconventional Gas 19 Conclusion 20 Acknowledgements 22 References 23 4 Introduction Natural gas is widely considered to be the bridge fuel to a lower carbon planet.1 The fuel— methane (CH4) with only one carbon atom per molecule—has the lowest per-unit carbon emissions of any fossil fuel. But while it is clean as a fossil fuel and highly useful in particular applications (like home heating, petrochemicals, and efficient power generation with modern combined-cycle power technology), it is inconvenient to transport. Gas ties up expensive and immobile pipeline capital equipment to link producing regions to consumers. Barges, rail cars, and road-based oil tankers that move much of the world’s liquid petroleum, particularly in the last stage of transport to consumers, do not work for gas. Gas requires either dedicated pipelines or, if moving liquefied natural gas (LNG) over the oceans in about 1/600th the volume of its gaseous state, highly capital-intensive liquefaction, specialized shipping, and regasification equipment. The lack of practical non-pipeline transport for gas, combined with the high capital cost of LNG, means that the kind of competitive worldwide spot markets that exist for oil (or for other bulk commodities, such as coal and grain) have not formed for gas. Worldwide crude oil prices indexes tend to follow each other, and each is a center for both spot and robust forward crude oil markets—indicating the willingness of financial markets to trade in the price risk associated with future crude oil deliveries. There is no such worldwide price of gas—quite the contrary. Over the past six years, apart from transport, Europeans have paid roughly three times what North Americans paid for their gas—amounting to almost $500 billion (more than the 2015 Greek debt sovereign debt that is troubling the EU and the world financial markets). Such lasting price differences, coupled with the impending entry of the United States and Canada as a major exporters of LNG from unconventional gas production, invites the question of whether new global LNG trade can balance supply and demand to produce worldwide competitive spot prices, 1 See the Symposium “Prospects for Natural Gas in a Low-Carbon Context” in the winter 2015 issue of Review of Environmental Economics and Policy, including Neumann, A. and von Hirschhausen, C.; Holz, F., Richter, P.M., and Egging, R., and Makholm, J. D. 5 separated only by the cost of shipping. There are two reasons to be doubtful that it can. First, LNG suppliers do not have competitive access to gas consumers outside of North America, as they have competitive access to consumers at home. Because of the way that pipelines are regulated outside of North America, inland gas consumers cannot access competitive gas supplies that might arrive by LNG tanker on the coast and existing gas suppliers do not see LNG as a competitive threat to their dominance over essentially captive gas customers. Second, even if transport barriers fall, evidence is that LNG will find it hard to compete with less costly local unconventional gas production. The Oceangoing Trade in LNG vs. Crude Oil LNG has an important role in the global supply of gas. In 2013, worldwide LNG trade amounted to 325 billion cubic meters as shown in Figure 1. Locales with scarce fuel resources, such as Japan and Korea, or underdeveloped internal resources, such as China and India, rely heavily on imports from resource-rich (but low population) regions such as Trinidad & Tobago, Qatar, and the Australian North West Shelf. 6 Figure 1: Major Gas Trade Movements, 2013 (billion cubic meters) Figure 2 depicts the trend in the proportion of ocean shipments of LNG and crude oil in their respective markets since 2009. Global gas consumption is about 72% that of oil (3,020 million tons of gas versus 4,185 million tons of oil in 2013—in oil equivalent, measured by heating value). Yet ocean transport constitutes less than 10% of global gas consumption (carried by 357 vessels) versus roughly two-thirds for crude oil (carried by 9,033 vessels) (IGU, 2014; UNCTAD, 2015). Furthermore, whereas the entire trade in oil occurs at worldwide spot or forward prices, less than 30% of LNG cargoes are spot or short-term (delivered under contracts of four years or less), representing only 3% of worldwide gas consumption (GIIGNL, 2015). 7 Figure 2: Annual Worldwide Consumption and Ocean Transport of Oil and Gas, 2009-2013 Oil and Gas Prices in World Markets Despite such evidence of a very minor (3%) maritime spot trade in gas, some of the world’s top economists are confident that gas is traded in global markets. For example, the Initiative on Global Markets (IGM) Forum, sponsored by the Booth School of Business at the University of Chicago, regularly surveys its panel members (all senior economics faculty at the most elite US research universities) on public policy matters. Since 2012, the group has surveyed its IGM Panel twice on the issue of the economic consequences of US unconventional gas production with the following proposition: “New technology for fracking natural gas, by lowering energy costs in the United States, will make US industrial firms more cost competitive and thus significantly stimulate the growth of US merchandise exports.” 8 While lower energy costs may well stimulate growth of US merchandise exports, some of the responses (from leading economists at Princeton, Stanford, Berkeley, and Yale) demonstrate that many are under the errant impression that gas prices move together around the world: “US energy prices are driven by world supply and demand, so the effect on US growth is realized only if global prices are moderated.” “In a global market, natural gas prices would fall worldwide helping foreign economies too.” “A silly gotcha q! Fracking may lower gas prices but it’s traded on world mkt so it won’t make any country’s exports more cost competitive. Duh” “Energy costs are set largely in the world market.” “At best a short-run and insignificant effect; prices are set in a global marketplace.” “Fuel prices are largely set on a world market so the supply in any one country does not reduce its producers’ input costs markedly.” “In a global market for energy, US and foreign manufacturing firms will ultimately face the same energy costs.” These economists assume that gas markets work like oil markets, which is not the case. Spot price indexes for Brent (named after the Brent oil field in the North Sea), West Texas Intermediate (WTI), defined as the major US hub in Cushing, Oklahoma, and DME Oman (traded on the Dubai Mercantile Exchange since July 2007) move together, as shown in Figure 3. Except for local constraints, the three international spot indexes move in lock step.2 2 Local constraints include the temporary pipeline bottleneck in moving WTI-priced oil south toward the US Gulf Coast as new oil sand production in Alberta and in North Dakota changed the decades-old direction of oil movements. 9 Figure 3: World Oil Benchmark Prices, 2000-2015 This is not the case for gas. Several “hubs” exist that report gas prices, although their growth and function—and the reported prices—are distinctly different. The Henry Hub facilities, in Erath, Louisiana, owned by Sabine Pipeline, connect to nine interstate and four intrastate gas pipelines. The Hub is the physical pricing point for natural gas futures traded on the New York Mercantile Exchange (NYMEX). NYMEX created the Henry Hub to satisfy the US financial markets’ demand for a standardized physical point at which to define futures contracts given the regulatory successes in the United States regarding the open-access gas transport on the interstate pipeline system. In contrast, European hubs such as the National Balancing Point (NBP) in the United Kingdom and the Dutch Title Transfer Facility (TTF) in the Netherlands are not physical points, but rather 10 “notional” hubs, reflecting a regulatory requirement for the separation of gas commodity sales from the UK or Dutch pipeline systems.3 The European notional hubs arose to meet government demands for separate wholesale gas sales in the pipeline systems controlled by Member State gas companies. They were not formed by financial markets to trade in gas commodity price risk but as a consequence of entry/exit tariff design mandated by the EU. The American system encourages competitive entry in both pipeline transport and gas supply within a well-defined system of physical contract paths—North America’s definition of gas market “liquidity”—while the European regime effectively bars competitive entry, while advancing the European Union’s definition of gas market “liquidity” that abstracts from the pipelines themselves. The difference is important—while the Henry Hub reflects a genuinely competitive commodity market with unrestricted competitive entry, the other “hub” prices generally only reflect gas sales between European gas companies at prices linked to roughly oil equivalents in long-term supply contracts. Nevertheless, each “hub” (American or European) displays a price index as a basis for comparison. Until early 2009, oil and gas prices moved together fairly consistently, tied—in a somewhat rough but discernable way—to movements in the price of oil. In particular, both gas and oil markets reflected the wild price movements in 2008-2009. But in 2009, a split occurred in the United States that reflected the application of new technology in unconventional gas production (hydraulic fracturing, or “fracking”). This split has persisted since—shown in Figure 4. A similar split occurred at the same time for the NBP; however, that split reflected the onset of the global financial crisis, which did not persist (Alterman, 2012). 3 TransCanada’s NOVA System in Alberta, Canada, with its NOVA Inventory Transfer (NIT) pricing hub, is the only place in North America where natural gas trades on a notional gas grid like that in the United Kingdom. The Canadian gas regulator, the National Energy Board (NEB), has blocked the spread of this system beyond its traditional boundaries in Alberta three times in the last five years, citing anticompetitive effects of entry/exit as a main factor in its decisions. 11 Figure 4: Henry Hub, UK National Balancing Point, and Brent Prices, 2007-2015 The differential between resulting commodity gas bills in the United States and Europe are staggering. Table 1shows that, apart from transport, over the past six years European gas consumers have paid an estimated $492 billion more for gas than their US counterparts.4 The differences continue into 2015, as the month-ahead futures for the first week of February 2015 show US Henry Hub gas prices averaging $2.60 while this at the UK NBP (toward the lower end of EU prices indexes) average $7.24 (or about $243 million per day additional gas cost for those indexes in the UK) (Platts, 2015a; 2015b). 4 For comparison, $492 billion is more than the 2015 Greek sovereign debt of roughly $408 billion (which equals 170% of Greek GDP of about $240 billion). 12 Table 1: Cost of Gas in Europe vs. the United States Average Price* per MMBtu European Consumption** Cost Differential Cumulative (Since 2009) Year Europe U.S. (Billion MMBtu) (Billion US$) (Billion US$)     =(-)*  2009 $4.92 $4.25 19.58 $13.04 $13.04 2010 $6.31 $4.35 21.09 $41.44 $54.47 2011 $9.48 $4.13 19.77 $105.80 $160.27 2012 $9.37 $2.79 19.22 $126.49 $286.76 2013 $10.56 $3.72 19.10 $130.77 $417.53 2014 $8.28 $4.35 19.10 $75.15 $492.68 *For Europe, average annual price at UK NBP; for the United States, annual average price at Henry Hub **2013 and 2014 EIA estimated European gas consumption Sources: EIA, Bloomberg L.P. Why isn’t US LNG flowing to Europe to arbitrage the persistent price differences shown in Figure 4? Part of the reason is that the prices shown in Figure 4 for US and European hubs are not truly comparable. The Henry Hub index prices in Figure 4 reflect a liquid and competitive market with recognizable spot and forward trading. US LNG exporters can buy at those Henry Hub prices, adjusted for reliable and competitive pipeline transport to the port of export—even years in advance with forward contracts linked to those Henry Hub prices. The European index prices, however, do not reflect what LNG importers could access—as there is no reliable and competitive means to access consumers at those notional hub prices, and there is generally no forward contracting ability to permit the financial markets to assist the transaction. Table 2 further illustrates why the Henry Hub and European gas hubs are not truly comparable. It shows the amount of natural gas futures traded in the United States and Europe alongside Brent crude oil and US corn (for an example of a different bulk commodity).5 The lack of competitive pipeline access to consumers and physical points at which the financial industry can settle its contracts effectively excludes gas futures trading in Europe. Without a competitive market for transport, a liquid market for gas cannot 5 We compare the consumption of the commodity, or production where it serves as a more appropriate measure, per day to the volume of the commodity traded in futures per day. 13 exist and the financial industry cannot enter in order to manage price risk as it does so vigorously in other commodity markets. Table 2: Volume of Commodities Consumed and Traded in Futures Market Unit Consumption Futures Volume Traded Ratio of Futures Volume Traded to Consumption European Gas MMcf/d 43,853 822 0.02 US gas MMcf/d 93,120 2,494,349 26.79 Brent Crude Oil Barrels/d 2,700,000 587,924,864 217.75 US Corn Metric Tons/d 8,955,000 27,808,604 2.74 Sources: Bloomberg, L.P., International Energy Agency, United States Department of Agriculture. * Futures contract volumes are measured using Generic 1st futures or 1-month base futures. Europe natural gas futures include data for Gaspool, NCG, and the Dutch TTF. The financial industry evidently has no interest in participating in European gas markets. The hubs were not created by the financial industry, nor are those European hubs physical points (like the Henry Hub) that themselves are connected by physical means to gas producers and consumers. Entry/exit regimes play a destructive role in pipeline competition by obscuring market signals for investors, thereby barring entry into pipeline capacity markets and thus raising prices for gas consumers. As such, it is unsurprising that the financial industry avoids the EU gas market. The Cost of Martime Transport of Oil and Gas Maritime oil transport includes the relatively minor costs of terminal loading and unloading and the lease cost for the tanker and associated fuel. Those costs are approximately $2.05 per barrel of oil (or $0.37 per MMBtu) (OPEC, 2013). The cost of transporting LNG by tanker is much higher. There are three steps required for maritime LNG transport: liquefaction, ocean shipping, and regasification, where liquefaction and regasification require large capital expenditures. Those US export facilities soon to be in-service (with completion dates in 2017 and 2018) tend to be at the lower end of the capital cost spectrum as they are “brownfield” projects—built at existing regasification terminals—whereas “greenfield” projects—constructed in locations without any existing infrastructure—are significantly more expensive (Maugeri, 2014). Evidence of the current cost of 14 liquefaction is available from public sources for US export facilities soon to be in-service, shown in Table 3 below. Table 3: Capital Costs of Liquefaction Facility Name Location Capital Cost (US$M) Capacity (Mt/yr) US$/MMBtu Sempra – Cameron LNG Hackberry, LA $9,500 12.74 $2.76 Freeport LNG Freeport, TX $14,000 13.49 $3.68 Dominion – Cove Point LNG Cove Point, MD $3,600 6.15 $2.26 Cheniere - Corpus Christi LNG Corpus Christi, TX $11,750 16.04 $2.72 Southern LNG Company Elba Island, GA $1,250 2.62 $1.91 Sources: Cheniere, FERC, and Hydrocarbons Technology. *Calculated with straight-line 20-year amortization and 10%t nominal return. Transportation of LNG via ocean tanker requires highly specialized ships that are equipped to carry the product at the appropriate temperature for the natural gas to remain in its liquid form, and also allow the ship to use some of that LNG as fuel. Total transport via tanker costs are shown in Table 4 below for an average journey of 4,500 miles from the US to Europe. Table 4: Cost of Shipping Units Charter Rate US$/Day $50,000 Tanker Capacity tons 66,000 Tanker Cost for 4,500-Mile Trip US$ $1,058,603 Fuel Cost for 4,500-Mile Trip US$ $452,435 Boil-Off Cost for 4,500-Mile Trip US$ $369,900 Sources: Platts, Searates. 15 Representative regasification facility costs are shown in Table 5 below. Table 5: Capital Cost of Regasification Facility Name Capital Cost (US$M) Capacity (bcm/ yr) US$/MMBtu Bahia de Bizkaia Regasification Plant, Bilbao $411.31 7.00 $0.43 Dragon LNG Terminal, UK $480.05 7.60 $0.77 Dunkerque LNG Terminal, France $1,044.49 11.50 $1.47 Sources: Hydrocarbons Technology, GIE. *Calculated with straight-line 20-year amortization and 10%nominal return. **Cost for Dunkerque LNG corresponds to an in-service date of 2014 for the first phase of the Project, thus no depreciation is included. In-service dates for Bahia de Bizkaia and Dragon LNG are 2003 and 2009, respectively. Total transport from the United States to European consumers averages about $4.15 per MMBtu: Table 6: Average Cost of Maritime Transport of Gas US$/MMBtu Liquefaction (Average of Five Projects) $2.66 Shipping (4,500-Mile Trip) $0.59 Regasification (Average of Three Projects) $0.89 Total $4.15 The proportion of the cost of maritime shipping to the unit value of oil and gas, for a 4,500-mile haul, is shown in Figure 5. What is useful to note about the comparison is that the costs for maritime oil transport are predominantly related to fuel and the daily lease charges for the tanker, which are variable costs. In contrast, the majority of the cost for maritime LNG shipments is tied up in the liquefaction and regasification capital facilities requiring long amortization periods (20 years) to pull the unit cost down to the maritime shipping line shown in Figure 5. 16 Figure 5: Relative Cost of Maritime Shipping for Oil and Gas Sources: Bloomberg, L.P., OPEC. Sources: Bloomberg, L.P., Cheniere, FERC, GIE, Hydrocarbons Technology, Platts, and Searates. 17 Reaching Producers and Consumers at the Ends of the LNG Journey The US gas market is freely competitive because it successfully restructured its federally regulated interstate pipeline system to remove pipeline interests as a barrier to the competitive trade in gas (Makholm, 2012). America’s pipeline sector exhibits a brilliant irony, for while every interstate pipeline has been subject to the skillful regulation of the Federal Energy Regulation Commission (the FERC) for more than 75 years, a genuinely competitive and unregulated market exists in the well-defined FERClicensed physical capacity in those pipelines. Using concepts that gave the late Ronald Coase his 1991 Nobel Prize in Economics, the FERC worked successfully during the 1990s to create such a market in highly specific physical capacity rights. Using the unregulated “sub-let” market in well-defined physical capacity rights, gas producers can physically reach any buyer on the interstate pipeline system simply by buying the rights from customers with existing contracts at the going price. If the gas market wants new capacity on existing pipelines, or a pipeline in a new location, pipeline companies (along with customers willing to pay) simply ask the FERC to license the addition, which then adds to the wider competitive pipeline capacity market. The system works, with little active participation by the FERC beyond licensing and cost-based tariff setting. In addition, it is precisely the transparently physical configuration of gas transport that invited the participation of the financial markets around the distinctly physical Henry Hub. There is nothing like such a market for gas transport in Europe, for two reasons. First, the institutional and political endowments that facilitated competitive pipeline transport in the US (e.g., a strong federal regulator, a history of investor participation in interstate pipeline construction, and powerful independent state-regulated gas utilities) have never been shared by the EU or its member states. Second, the regulatory initiatives adopted by the EU since the 1990s have been both highly protectionist of the EU’s member state gas companies and, as a result, damaging to the prospects for competitive entry either of new pipeline or new gas supplies.6 In other words, while the EU started with a bad hand in 6 For a description of the particular legislative actions heightening the protectionism of member-state gas companies, see Makholm, J.D. (2015), 17-19 and Makholm, J.D. (2012), 60-62 and 167-171. 18 pursuit of competitive gas supply to its 115 million consumers, the EU has made the situation worse through recent regulation—moving gas markets in the EU further away from the competition that has spurred new gas development and pipeline construction in North America. Existing EU legislation, known as the Third Legislative Package of 2009, was ostensibly created to promote an EU-wide competitive market in gas based on the principles of the EU’s competitive electricity markets (EU, 2009). It has had the opposite effect for a number of reasons. The Third Package outlaws point-to-point gas transport in the Member States and directs each state to create a regime of “entry/exit” transport tariffs to and from notional hubs where gas changes hands from sellers to buyers. Whereas the competitive gas transport market in the US ties tightly to the physical operation of its pipelines, the Third Package rejects such a physical basis for gas transport contracts and pricing for its Gas Target Model, preferring to adopt the types of markets that it pursues for its electricity grids. As a result, member state gas companies face no bypass threats to either their pipelines or to gas imported under contracts indexed to oil prices. The Third Package forbids the customer the ability to contract for, and trade in, point-to-point transport capacity on long-distance pipelines, irrespective of national borders (Noël, 2013). Europe’s highly developed gas industry is thus effectively immune to the threat of both supply rivalry among the major suppliers from lower-priced LNG imports, and from the development of unconventional shale gas supplies (which are apparently plentiful below the ground in the EU) (EIA, 2013b). In February 2015, the EC published an outline of its plan to develop a resilient Energy Union in which the Commission indicates its wish “to remove obstacles to LNG imports.” The EC, almost in passing, notes its LNG strategy will include an examination of transport infrastructure to connect LNG access points with the internal EU market—but provides no indication that changes in the entry-deterring regulation of inland transport will take place (EC, 2015). 19 Entry Competition for LNG from Unconventional Gas It is hard to overstate the wider importance of unconventional gas production for energy markets in the US and Canada since 2008. Unconventional gas supplies have spurred local employment, encouraged the displacement of higher-carbon fossil fuels, and helped to drive down competitive electricity prices (which itself has put economic pressure on the cost of some forms of renewable power generation) (EIA, 2013a). Unconventional supplies have revitalized the continent’s petrochemical industries (including fertilizer and plastics) and driven down the competitive price of power. The experience with unconventional gas, which has caused gas production to shift to regions that are closer to population centers than are the Gulf of Mexico or Northern Alberta, has also led to the conversion of gas pipelines so that they can transport new crude oil reserves to existing refineries (such as transporting Alberta oil sands crude oil to the continent’s largest refining complex on the Texas Gulf Coast). The continuing prospects for unconventional gas supplies, including the production cost and available future supply, are the subject of intense study in North America (Ikonnikova, et al., 2015a). Some of the most recent work on the break-even price for unconventional wells of various depths indicated that the average shallow zone wells requires a price of $2.74/MMBtu (generating an international rate of return of 10%) and $3.30 on average for a well from deep zones. Various estimates of North American unconventional gas put breakeven costs as low as $2 per MMBtu to just over $5 per MMBtu, depending on the play (Ikonnikova, et al., 2015b). The studies of US unconventional gas production are highly encouraging, both with respect to current break-even estimates and the still-developing experience and technology applied in a diverse range of geological circumstances. Recent studies show that recoverable shale resources are not simply a North American phenomenon (EIA, 2013b). There is no particular reason, however, to be encouraged about the near-term ability to exploit the US unconventional gas experience elsewhere. Various important institutional barriers particular applicable to unconventional gas production stand in the way, including the lack of private sub-surface mineral rights ownership, less developed petroleum service industries, and 20 lower public support for unconventional gas supplies as a political matter. Additional market barriers apply to any gas entry, whether for unconventional gas supply or LNG. These include a more highly concentrated oil and gas sector (usually controlled by state companies) and the difficulty in accessing the infrastructure that producers would need to reach customers (represented by the substantial competitive access in pipeline transport described in the last section). Conclusion It is attractive to think of the maritime LNG trade as having the capability to synchronize world gas markets around the global supply and demand for that fuel, as oil markets do with the maritime trade in crude oil. Indeed, as evidenced by surveys of top economists, much of the world believes that a world gas market already exists. A slightly closer examination of the trade in the two fuels, however, shows that this is not the case. Oil moves around the world easily—two-thirds of the world’s oil consumption moves by sea for some part of the journey from producers to consumers; all of that at spot market prices. Barely 10% of the world’s gas supply moves that way, with less than a third of that delivered at spot prices. Why is there such a small reaction to a world where, in six years, Europeans have paid almost $500 billion more for their gas than their American counterparts? The gas trade cannot exist without pipelines or expensive containers to hold it. Pipelines provide a ready-made ability to withhold access and undermine competitive entry. Only North America has developed regulatory regimes that consign pipelines to serve only the role of “transporters for hire”— permitting producers and consumers to deal directly with each other without pipeline interests or regulators getting in the way. This is not the case in the EU, where local pipeline monopolies and their own regulatory authorities control all gas transport and trade within a regime that deprives gas sellers and buyers of the physical means to deal directly. Even if producers and consumers are able to deal directly and physically (over defined pipeline links) with each other, gas is just too light a fuel to transport over the oceans without reducing its volume 21 by 1/600th into a liquid. The cost of that LNG transformation is vastly greater than the comparable relative cost of crude oil transport. The cost of LNG is even comparable, if not greater, than the cost of using modern technology to produce marketable gas from unconventional sources. Faced with high costs and regulatory difficulties in dealing with pipeline transport outside of North America, the market for LNG is inherently limited to a commodity trade between regions of abundance and scarcity, relative to local demand. Given the capital costs involved and the volatile nature of gas prices, investors will seek, as they have done in the past, relationship contracts to tie such regions together long enough to amortize those LNG investments. To mimic the global spot market trade in crude oil, gas would need both a vastly reduced maritime cost and a way of getting to consumers without being captive to pipeline monopolies. The former is a physical impossibility, and the latter, outside North America, may well be an institutional impossibility. 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