1. The possibility that LNG might play an important role in meeting U.S. energy needs has arisen only recently. As recently as 36 months ago, for example, the U.S. Energy Information Administration (EIA) indicated that LNG imports were “not expected to become a major source of U.S. [energy] supply.” Annual Energy Outlook 2002 at page 82.
EIA’s most recent forecast, however, Annual Energy Outlook 2005, assumes a compound annual growth rate for imports of LNG, beginning in 2008, of 12.2% per year -- more than 5 X the expected growth rate for imported oil. See AEO 2005, Supplemental Table 104.
2. Unlike the global oil industry or the North American natural gas industry, the global LNG market still is at a comparatively early stage in its development. The current size of the global market, for example, is less than 1/5th of the size of the North American market for natural gas. It is designed predominantly to serve just three countries: Japan, South Korea and Taiwan. Collectively, these countries account for more than 2/3rd’s of the current world market.
Further, the output of most existing LNG projects and all but a small share of the output from the limited number of projects that currently are under construction in various parts of the world already is committed to other purchasers on a long-term basis.
Virtually all of the incremental LNG supplies EIA assumes will be available to the U.S. market in future years, therefore – even as soon as 2008 -- must be obtained from projects that have not yet been built and shipped using specialized tankers that have yet been constructed.
In addition, even though the lead time for building new LNG projects generally is estimated to be at least 4 to 5 years, even meeting EIA’s projected deliveries for 2008 will require obtaining substantial production from projects that have not yet even broken ground -- or in some instances, even signed binding commercial agreements or begun to seek financing.
Further, even though the U.S. has become critically dependent upon meeting the import levels assumed in EIA’s estimates in order to be able to satisfy the basic energy needs of the U.S. economy, EIA has not identified the specific projects on which its estimates are based – even during the 2008 through 2010 time frame.
Nor has it identified major milestones that must be met for these increased import levels to be achieved.
It also is not attempting to report publicly on a current basis on the status of pending projects.
Instead, as it so often does, it has merely published a set of estimates of total imports and said, in effect “trust us” -- at least until next year, when its estimates presumably might once again be radically revised.
3. Longer term, there still is a great deal of uncertainty regarding how many new LNG projects actually will be constructed during the next decade. Despite the intense interest in LNG, few if any new projects actually started construction anywhere in the world in 2004.
Further, neither EIA nor any other federal or state Agency appears to have ever undertaken any rigorous assessment of how many new projects actually are likely to be built over the next 20 years. No assessment appears to have been made, for example, of whether the host companies are likely to develop a significant percentage of their reserves within a relatively compressed time frame (which many estimates implicitly assume) or instead potentially decide to phase the development of the finite reserves each country controls over a period of several decades (as prudence would appear to dictate) -- in which case it is possible that only a limited number of projects will be initiated in the next few years beyond those already under way and the price of LNG could prove to be significantly higher than EIA assumes.
Instead, EIA appears to have simply accepted at face value broad-brush assertions regarding the potential amount of new LNG production that conceivably might be developed on a world-wide scale in a relatively short period of time assuming that both the host companies and the super-major international oil companies attempt to build new supply projects on an extremely aggressive schedule, without considering whether it is necessarily in their economic best interests to do so (which it almost certainly is not).
(Note, in this regard, that the government of Qatar, one of three countries – along with Iran and Russia – generally considered to have the greatest potential to develop new capacity -- recently announced a moratorium of unspecified length on new projects, at a time when a high percentage of the output from projects already under way in Qatar is committed to other countries. At close to the same time it announced its moratorium, it also abruptly cut by almost 40 % ExxonMobil’s expected share of the 2nd train at Qatargas II, which ExxonMobil has been including in its development plans for almost 4 years. This share was awarded instead to the French firm, Total. Neither ExxonMobil nor Total have yet made any public commitment to ship any portion of the output of Qatargas II to the U.S. market, even though it is one of the last projects expected to be built in Qatar which is not subject to the moratorium.)
4. Further, even if a significant number of new projects are successfully completed over the next several years, competition for the output from these projects is likely to be intense.
Like the U.S., much of the world is currently planning to turn increasingly to the use of natural gas for space heating, rather than heating oil and planning to rely on gas-fired generation to meet nearly all of its incremental demand for electricity.
As a result, world-wide demand for natural gas is expected to grow at a rapid rate.
Also like the U.S., however, most major natural-gas consuming countries are not currently expected to be self-sufficient in future years (including countries, such as Great Britain, that currently are meeting all of their own needs).
As a result, the U.S. is likely to face stiff competition for the limited new supplies of LNG that become available on the world market from China, India, the United Kingdom, Spain, France, South Korea, Japan, Mexico and many other countries, further limiting the potential new supplies that are likely to become available to the U.S. market.
5. Despite the overall strength of the U.S. economy, the U.S. could be at a significant disadvantage in competing for these supplies.
We are running the largest trade deficit in U.S. history – and the largest trade deficit of any country in the world. In part as a direct result, the value of the dollar is expected to continue to decline sharply over the next several years.
Further, because of our location, for every current producer other than Trinidad, the amount of time a tanker must travel in order to complete a delivery to the U.S. and therefore the cost of shipping LNG to the U.S. market is significantly greater than for any other potential customer except Mexico. With tankers potentially costing up to $ 250 million each, this is a significant disincentive to sell into the U.S. market.
It also means that, by definition, a U.S. manufacturer using LNG will be at a competitive disadvantage to almost every other manufacturer worldwide, since (due to the shipping cost differential) the cost of LNG delivered to the U.S. market inevitably will be higher than in any other market in the world.
6. In addition, neither EIA nor industry representatives appear to have given adequate consideration to the potential consequences of the supply disruptions that are virtually certain to occur periodically if the U.S. shifts to a strategy in which it will be relying upon supplies from a few large LNG mega-projects potentially located thousands of miles from the U.S. rather than tens of thousands of discrete natural gas wells, even the largest of which accounts for only a tiny fraction of 1 % of total U.S. supply.
In a global LNG market, with supplies being shipped half across the world and the stability of the host government not always a given, periodic interruptions in supply in all likelihood are inevitable.
As the International Energy Agency (IEA) has observed with respect to the global oil market, supply disruptions can arise due to any of a variety of causes, including “accidents, unplanned or unannounced maintenance, technical problems, labor strikes, political unrest, guerilla activity, wars and weather-related supply losses.” See IEA Monthly Oil Report for February, 2005 at page 12.
Every one of these factors is potentially just as applicable to a large LNG mega-supply project located half way around the world as it is to the international oil market.
Further, at least some of the expected sources of supply (particularly Nigeria, but also Venezuela and to some degree Statoil in Norway) have been among the most prone to political or labor-related strikes (or in the case of Nigeria, political unrest) of any producers in the world.
If we rely heavily on LNG imports from West Africa or the Middle East, therefore, and the government in a host country is overthrown, a strike temporarily shuts down production or, in the case of a Middle East producer, shipments through the Strait of Hormuz are temporarily blocked, there may be a very real risk that we’ll not be able to keep homes warm in the middle of the winter or that the lights will go out in the summer.
Even if shortages never occur, however, from a pricing standpoint, the potential consequences of a supply disruption in the LNG market, even for a short period, could also be severe – even if it involves only a single major LNG project supplying the U.S. market.
This is in part due to differences in the feasibility and cost of storing oil and the cost and feasibility of storing natural gas, the resulting differences in the amount of oil and natural gas that are maintained in storage, and the increased risk of severe price spikes this creates in the U.S. market for natural gas.
Oil, as a liquid, can be stored relatively inexpensively. In part as a result, industry and government have developed huge reserves. Total U.S. reserves of crude oil, for example, including both commercial reserves and the Strategic Petroleum Reserve maintained by the U.S. government, are sufficient to offset a total cut-off of oil from the Middle East for over 12 months.
At least to a significant degree, this reduces the severity of the price shocks that occur when temporary supply disruptions occur -- such as the strikes and guerilla-war related supply interruptions that have occurred frequently in recent years in Nigeria.
By contrast, the cost of storing natural gas is far greater – either as a gas or as LNG.
As a result, just barely enough storage capacity exists in the U.S. to meet expected peak period needs during the winter.
While the natural gas industry in the U.S. is seldom described in this way, because of the high costs associated with natural gas storage (both to build storage facilities and to keep them stocked) the natural gas market in the U.S. is designed to operate with essentially zero spare capacity over the course of any given annual 12-month cycle.
Natural gas is injected into storage during a 7-month injection season. At the end of the injection season (in late October), if the industry has met its targets, a large amount of natural gas will temporarily be contained in underground storage facilities (viz., approximately 3,250 to 3,350 BCf).
This creates the near-universal impression (even within the industry) that the natural gas market always maintains a substantial reserve.
In fact, however, if supply and demand are more or less balanced for the year as a whole and weather over the course of the year matches historical norms, all or virtually all of the natural gas injected into storage during the storage Refill Season is likely to be needed to meet winter needs.
While there still may be a few hundred BCf of natural gas left in storage at the end of the winter heating season, as we saw three winters ago when the amount of natural gas in storage was reduced to 730 BCf, much of that amount is needed simply to maintain operating pressure in the pipelines.
Further, at least some amount always must be held back to guard against the possibility of one more wave of “cold weather.”
As a practical matter, therefore, there ordinarily isn’t any meaningful amount available as a reserve to protect against a significant interruption of supply.
In the natural gas industry, therefore, there is no natural gas “Strategic Reserve” comparable to the Strategic Petroleum Reserve.” Nor is there a “natural gas stockpile” comparable to a coal stockpile.
Instead, largely because it would be prohibitively expensive to construct the required storage facilities and fill them with natural gas held in reserve strictly to protect against disruptions in supply or other emergency use, the industry effectively operates with near-zero reserves over the course of any given 12-month cycle.
As a result, in the natural gas market, even minor swings in expected supply or demand routinely cause significant swings in the market price of natural gas.
We saw vividly last fall, for example, the impact on the market price of natural gas of the temporary loss of approximately 2.2 BCf per day of production from the Gulf of Mexico due to Hurricane Ivan. At its peak, the cash market price for natural gas jumped by as much as 60 % and the price for natural gas futures traded on NYMEX sky-rocketed to as high as $ 10.00 per MMBTU.
No other event affecting the natural gas market in the U.S. has ever caused a temporary loss of supply even close to the magnitude of the loss of production caused by Hurricane Ivan; instead, from a domestic supply standpoint, the temporary loss of production that resulted from Hurricane Ivan was a classic “1 in a 100 year” event.
By contrast, however, the production temporarily lost due to the storm – i.e., at its peak, 2.2 BCf per day -- is the same scale size as each one of the largest LNG supply projects targeting the U.S. market.
The temporary loss of supply from a single LNG project, therefore, potentially could have an impact on the U.S. market similar to the extreme strikes that resulted from Hurricane Ivan.
No one has yet proposed that we create a Strategic Reserve for natural gas – presumably in part because the cost to construct and maintain a storage facility of the requisite size would be many times greater than the cost for constructing a storage facility of comparable size for oil.
Further, if the cost of constructing such a facility and maintaining a reserve adequate to protect against potential temporary interruptions of supplies of LNG were included as a “tax” on the cost of importing LNG, it might make it prohibitively expense to import LNG into the U.S. market.
Absent a reserve or some other form of reliable back-up supply, however, an interruption of deliveries from any one of these projects, for any reason, or the unavailability of one or more U.S. re-gasification facilities for an extended period could expose the U.S. natural gas market to price shocks just as severe as we experienced last fall after Hurricane Ivan struck the Gulf.
In a market which already exceeds 60 BCf a day, even if such an interruption only lasted 2 or 3 months, it could easily add $ 10 billion or more to the costs incurred by U.S. consumers of natural gas each time such a disruption is supplies occurs.
It is not entirely clear, therefore, whether a massive increase in U.S. dependence upon imports of LNG should even be allowed without determining before new import permits are granted who will bear the costs when such supply interruptions occur – as almost certainly periodically will be the case.
7. Finally, a heavily LNG-dependent strategy raises far-reaching issues regarding the potential increased exposure of the U.S. natural gas and electricity markets to frequent and extreme price shocks that might result from increased dependence upon LNG even in instances in which no supply disruption has occurred.
At least to date, these issues do not appear to have been adequately addressed – or, for that matter, even considered – by regulators at either the federal or state level.
This omission in some respects surprising, since the potential problem that arises closely parallels an issue that has become the central focus of much of the Federal Energy Regulatory Commission’s (FERC’s) efforts to regulate the wholesale power markets – viz., the potential ability of a so called “pivotal supplier” in the market for electric generation to raise prices at will.
In electricity markets, a pivotal supplier is any supplier whose market share exceeds the amount of excess capacity available to serve a particular market.
Because of the long lead time required to add new electric generating capacity, at least in theory, in a de-regulated market, during some hours of the year, a pivotal supplier can raise the market clearing price for electricity in the wholesale market to whatever level it chooses simply by withholding from the market sufficient capacity so that there are not enough other sources of supply available for the local service provider to be able to serve total electricity demand in its service territory without purchasing some or all of the pivotal supplier’s remaining output at whatever price the pivotal supplier chooses to demand.
Since the California crisis in 2000, the FERC has devoted a great deal of time and effort to addressing this potential problem – not just as it potentially applied to the 2000 crisis in California, but as a major issue potentially affecting wholesale power markets nationwide.
One of the primary allegations made in connection with the California crisis is that during the height of the crisis, “pivotal generators” in California with “market power” decided to deliberately withhold from the market a portion of the capacity that was available to serve the California market in order to artificially raise the spot market price of electricity. (This allegation has been vigorously disputed by the generators who are alleged to have engaged in this conduct.)
Petitioners in proceedings relating to the California crisis have alleged that deliberate withholding of capacity by pivotal suppliers led to billions of dollars in increased costs for electricity in California alone in a period of just a few months.
Whether or not the specific allegations that have been made in connection with the California crisis are factually true, electricity markets are thought to be particularly vulnerable to this form of price manipulation, since often only a limited number of generators are in a position to serve a particular geographic market – not just in California but in many other parts of the U.S.
While many of the claims relating to the California crisis have been settled, in the electricity context, the FERC has taken the problem of the pivotal supplier very seriously, recognizing that the only solution might be to re-impose price restrictions on pivot suppliers during any portion of any year in which a pivotal supplier might have the ability to exercise market power.
The domestic natural gas industry as it is currently structured, however, generally has been thought to be immune from the problem of the pivotal supplier.
This is largely because there are literally hundreds of producers, no one of whom has more than a small share of total production. In addition, there are a large number of individual wells (currently, over 320,000 in the U.S. and another 40,000 + in Canada), with more than 22,000 new wells added this year in the U.S. alone.
While the largest U.S. natural gas producer (currently BP Amoco) in theory might be able to withhold sufficient production to increase the market clearing price of natural gas slightly for a brief period, in all likelihood it could do so it could only do so by cutting its own production drastically.
As a result, even if a very large producer chose to pursue such a strategy, its own profits almost certainly would decrease (since its market share would be cut significantly) and it would not be likely to profit from pursuing such a strategy.
Further, since the lead time for drilling new on-shore wells in the U.S. is relatively short (i.e., less than a year), the general expectation has been that, even if a large producer chose to engage in such conduct, other producers would quickly move in to fill the gap by increasing the number of new wells that they drilled – increasing their market share and potentially causing the larger company’s market share to permanently decline.
As a practical matter, therefore, most economists have concluded that it is difficult to conceive of a circumstance in which a domestic producer of natural gas in the U.S. market as currently structured would have any incentive to attempt to cut-back on its production in order to increase prices in the U.S. market.
Indeed, it is precisely for this reason that de-regulation of wellhead prices originally was thought to be appropriate in the U.S. market and why many believe it has been such a success.
If the U.S. moves to a heavily LNG-dependent strategy, however, as it applies to the natural gas industry, the problem of the “pivotal supplier” would be likely to change radically. Further, this change will occur even assuming – as the author of this paper does – that no LNG supplier ever deliberately withholds a single molecule of supplies from the U.S. market for the specific purpose of raising prices in the U.S. market.
The problem in a nutshell is this:
If EIA’s estimates prove to be accurate, beginning as soon as 2008, the total amount of LNG imported into the U.S. -- which already has increased by 419 BCf over the past over the past two years -- will begin to increase at an even more rapid rate.
By 2010, for example, EIA projects that LNG imports will increase from 2004 levels of 649.1 BCf per year (i.e., an average of just over 1.75 BCf/day) to 2.50 TCf per year (or almost 7 BCf/day).
By 2015, this figure is expected to increase to an astounding 4.33 TCf (i.e., almost 12 BCf/day) – at which point it would account for over 15 % of total U.S. supplies of natural gas (more than 5 X the current market share of 2.9 %):
By 2025, this figure would increase to 6.37 TCf (i.e., just under 17.5 BCf/day) – which equates to 21.7 % of expected total U.S. natural gas consumption in that year.
Unlike current North American production, however, this 17.5 BCf/day is not expected to be obtained from hundreds of different suppliers, each of whom is expected to have a relatively small market share.
Instead, it is expected to be obtained from a small number of huge “mega-projects,” much of the output will be controlled by a small number of large suppliers. Further:
This combination of circumstances -- none of which assumes any wrongful conduct by any of these companies – potentially poses a unique set of risks to the U.S. market, which to date appear to have been entirely ignored in the public debate regarding LNG.
These risks arise precisely because these companies are legally obligated to – and presumably should and will – act in a manner that serves the best interests of their shareholders, as long as it conforms to applicable laws.
As a result, they presumably will generally sell the output under their control wherever it can fetch the highest price; indeed, in a free market system, that’s precisely what we want them to do in order for the market as a whole to function as efficiently as possible (i.e., in this instance, the new “global” market for LNG).
A significant portion of this output could well be sold under long-term contracts. To the extent this occurs, if the contracts are binding and enforceable and lock the supplier into delivering the LNG into the U.S. market on a long-term basis, at least a portion of the output from these projects presumably will be certain to reach the U.S. market (i.e., it will not be subject to being withheld by the supplier, at least without penalties for breach of contract, even though the supplier might otherwise arguably satisfy the conditions necessary to qualify as a “pivotal supplier” with the potential ability to exercise “market power” by withholding needed supplies from the U.S. market).
It is quite possible, however, that even those contracts which lock-in delivery into the U.S. market will not set a fixed priced for the sale. If so, the purchaser may still be vulnerable to steep price increases, if other LNG supplies under the control of the same LNG supplier or any other LNG supplier serving the U.S. market are diverted to another market.
More importantly, however, at least the way the LNG industry currently appears to be evolving, there appears to be a substantial likelihood that that the delivery point for a significant portion of the output from many of the major projects will be left flexible.
Specifically, for a significant portion of the output of each major project, the LNG supplier who signs the initial contract with the producing country (e.g., Royal Dutch Shell, Tractabel, BP, ExxonMobil, etc.), will have discretion as to the market or markets to which that supply will be delivered.
At various points in time, some of that discretion subsequently might be negotiated away by contract, as a result of suppliers making binding contractual commitments of varying durations (e.g., one month, 1 year, 10 years) to specific customers in specific markets.
But some of it may not (i.e., control over the delivery point may be retained for short-term sales).
Further, at least under current law, neither the Federal Energy Regulatory Commission nor any state Public Utility Commission will necessarily have any direct jurisdiction over how shipments of LNG are allocated between countries or priced.
Nor, given the international nature of the LNG business, is it clear that there is any basis by which either FERC or any state PUC even could be given such authority -- unless suppliers voluntarily agree to be regulated by the U.S. government or some not-yet-created international Agency.
To the extent suppliers remain free to re-allocate LNG to different markets on a short-term basis, however – as they presumably will remain free to do – this could greatly magnify the risk of severe price spikes in the natural gas market in the U.S. – price spikes that could quickly spill over into electricity markets as well.
As a result, the $ 125 billion + U.S. natural gas market and the $ 300 billion + electricity market (two of the largest segments of our economy), could become exposed to severe new price risks that have never previously existed in the U.S. market.
This is because, unlike a domestic producer (whose only alternatives are to sell into the U.S. market or not sell its gas at all), to the extent an LNG supplier reserves a portion of its output for short term sales it will not necessarily be required to sell this output into the U.S. market at all.
Instead, if it can fetch a higher price, it presumably can – and will – sell its LNG to a purchaser in China, or India, or Japan or Great Britain or Spain or the Netherlands or anywhere else in the world where it believes it can obtain a higher price than it can obtain in the U.S.
Unlike a domestic producer, therefore, it is not faced with a “Hobson’s choice,” where if it withholds production from the U.S. market, its profits and revenues potentially will suffer since it has no other way to make a sale.
Instead, in order to maximize its profits, it has every incentive to divert cargoes that might ordinarily have been delivered to the U.S. to any market anywhere in the world in which it can obtain a higher price – and presumably will do just that.
The potential impact that this is likely to have on the volatility of natural gas prices in the U.S. market should not be underestimated.
In a tight U.S. market, there already was evidence this past summer that the ability of Japanese buyers to outbid the U.S. for a small number of LNG cargoes originally expected to be delivered into the U.S. market but ultimately diverted to Japan (including at least one cargo from Trinidad reportedly shipped halfway around the world to satisfy demand this summer in the Japanese market) was sufficient to significantly affect the price of natural gas futures traded on NYMEX – possibly by as much as 50 cents per MMBTU.
Further, even though LNG still accounts for less than 3 % of U.S. supplies, in a recent research report, Goldman Sachs suggests that the need to compete with other countries for spot market cargoes of LNG could become one of the dominant factors driving natural gas prices in the U.S. this coming winter. This in turn potentially could become a powerful factor driving natural gas prices in the U.S. market towards parity with oil at a time when oil prices may be reaching a new all-time high.
If the U.S. continues to pursue a heavily LNG-dependent strategy, in another 5 to 7 years, up to several BCf per day of expected U.S. natural gas supply may be vulnerable to being diverted at any time to any of a number of other major markets around the world.
The sudden shut of nuclear units in Japan, for example, or the rupture of a major natural gas pipeline in Europe, and the subsequent diversion of LNG originally expected to be delivered to the U.S. to those markets, might suddenly reduce the natural gas supply available to the U.S. market not just by a few cargoes but by 3, 4 or even 5 BCf a day – at least unless U.S. purchasers were willing to engage in a bidding war in which they outbid every other purchaser in the world for limited available supplies of LNG.
This in turn could result in unprecedented increases in the spot market price of natural gas in the U.S. – increases that would apply not just to purchasers of LNG, but to every purchaser of natural gas in the U.S. market from any source who is obligated to pay the spot market price for natural gas at the time the event occurs.
The economic consequences of a major diversion of LNG supplies away from the U.S. market, therefore, could be truly staggering – i.e., potentially several times greater than the impact of the loss of production caused by Hurricane Ivan last fall. Indeed, just the potential for such a loss of supply could add significantly to the price volatility of natural gas in the U.S. market.
If a major shift in supply to other markets were to occur during the hottest period of the summer, for example, or during the heart of the winter heating season, and last for an extended time period, increases in the total costs incurred by purchasers of natural gas on the order of $ 5 to 10 billion in the natural gas market alone are not by any means out of the question.
If the shift occurred in the summer, and the impact then rippled through the electricity market, the total cost to U.S. energy users easily could be 2 to 3 times this amount.
Further, even if U.S. purchasers ultimately outbid other competitors for the available supplies and the cargoes originally expected to be delivered to the U.S. market remained here, the need to potentially outbid other competitors all over the world, in natural gas markets that like the U.S. market essentially are operating with zero reserves, could create just as severe an increase in the spot market price of natural gas. It is also possible that, in some years, disruptive events of this nature could occur several times in one year.
There are, of course, solutions that potentially could be crafted to avoid some of these problems.
At least in theory, for example, if suppliers were so inclined, they could make binding commitments to deliver whatever portion of their output they plan to deliver into the U.S. market on a firm basis 100 % of the time whenever their facilities are operating and never divert these shipments to other markets.
If commitments of this nature were made, then from a functional standpoint, at least in some respects, LNG would become more similar to a domestic source of supply (although there still would be a greater risk of supply interruptions of the type discussed in item # 6 above).
Given the obvious risks involved with a heavily LNG-dependent strategy, however, absent such a commitment, the vulnerability of the U.S. market to severe price spikes is likely to be unprecedented.
In all likelihood therefore, if we continue along our current path, it will only be a matter of time until we begin experiencing a new generation of crises in the natural gas markets in the U.S., in which U.S. prices suddenly spike to unprecedented levels not because of events here but because of events in other markets beyond our control (e.g., most recently, just in the last few weeks, poor hydro availability in Spain – which apparently was made up for almost entirely by increased imports of LNG into Spain, a significant portion of which apparently consisted of cargoes diverted from the U.S. market).
Further, given the close link between natural gas prices and the wholesale price of electricity, particularly in the summer months, it may be inevitable that these crises will spill over into Regional electricity markets as well, with consequences that may ripple through much of the U.S. economy.
These losses in turn could wipe out in a heartbeat any benefits that might have been obtained by a decision to massively increase imports of LNG.
Please note: This is Part 2 in a 3 Part series. Part 3 will be published tomorrow, May 19th.
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