The Hope for LNG
The desire to build new LNG receiving terminals is understandable. There’s been a persistent 2:1 price differential, roughly, over the last few years between spot prices for natural gas in US markets and the contract price for delivered LNG. In that period, importing LNG has been highly profitable for the companies involved. However, its scope has been limited by an acute shortage of capacity to receive LNG shipments in the US. Although 2004 was a record year for it, LNG still supplied only 2.9% of the US natural gas market. The hope of many in the utility business is that new terminals will enable LNG to be imported at a rate that will finally ease the protracted crisis in natural gas supplies that has been forcing up prices over the last few years. If prices come down, then investments made in gas-fired generating capacity from the waning Clinton administration years might at long last begin to pay off.
Two recent articles in this forum, make it clear that the utilities’ hopes for cheaper natural gas are most likely in vain—at least over the next few years. The problem, as both Murray Duffin and Andrew Weissman have pointed out, is that current supplies of LNG, as well as the tanker capacity to carry it, are fully committed in service to existing markets. There’s no spare LNG production capacity sitting around, looking for new markets to supply. We can build all the receiving terminals we want, but LNG tankers will not simply come, like baseball players in a scene from “Field of Dreams”.
If we are to import substantially more LNG, then two other things must happen. First, the fleet of LNG tankers must be greatly expanded, and second, producers will have to build new gas liquefaction plants and loading terminals. There is some activity on both those fronts, and nobody doubts that LNG imports will indeed be rising over the coming years. But it is not happening at the rate at which it would need to happen in order to meet the EIA’s optimistic forecasts for LNG imports. And with the U.S. coming into the market, competition for available supplies is bound to raise prices considerably.
Economics to the Rescue?
There’s a saying in economics that “the cure for higher prices is higher prices.” In theory, a period of high LNG prices should stimulate investment in new production facilities, which will eventually bring prices back in line to something more consistent with real production costs. Production costs for LNG should be low, since the source gas is most often a byproduct of oil production. Worldwide, there is still a great deal of co-produced natural gas that is simply flared, for lack of infrastructure for getting it to market. Does that mean that we can eventually hope to see a return to lower natural gas prices, once investments in facilities for gas liquefaction and shipping have picked up? It may not be happening as fast as the EIA has predicted, but isn’t that where market economics should eventually take us?
Don’t count on it.
The Pesky Alternative: GTL
The problem is that cryogenic liquefaction of natural gas for export as LNG is not the only way to make use of so-called “stranded” natural gas. Nor is it always the best way, from a producer’s point of view.
An alternative is to process natural gas to first make what’s known as “synthesis gas”—a mixture of hydrogen and carbon monoxide—and then use Fischer-Tropsch synthesis and downstream processing to produce premium sulfur-free diesel and jet fuels. If the price of LNG is low relative to diesel, it is more profitable for producers to employ this gas-to-liquids technology (GTL) to make diesel and jet fuel, rather than exporting the gas in the form of LNG.
The tradeoff between the two options is not simple and straightforward. In both cases, the capital investment in facilities is large. Lead times for construction can be several years. LNG has the advantage that, relative to the input gas volume, the capital cost for LNG facilities is much lower than for GTL. But the facilities must normally be sited near a deep-water port; its cryogenic temperature prevents sending LNG any distance by pipeline. Insulated storage facilities at the shipping port are costly and hazardous. GTL output, by contrast, is easy to store, and can be shipped by barge, rail, or truck, if needed. It commands a market premium for its high quality. It also involves the producer in a larger piece of the “value chain” of refinery products and petrochemicals. That often accords with a producer’s long-term economic plans.
Ultimately, the choice of whether to invest in LNG or GTL production will depend on the price that LNG commands relative middle distillates from the GTL process. Or, from a different perspective, the availability of the two investment options defines a long-term relationship between the price of LNG and the price of middle distillates. If LNG prices are not high enough, producers will find it more profitable to invest in new GTL facilities, rather than LNG. So the obvious question becomes, what is “high enough” to encourage increases in LNG production over GTL?
Parity for NG vs. Diesel
There is enough information publicly available to allow a rough estimation of what the natural parity between LNG and diesel prices would be, based on the current state of the technologies involved. The answer, unfortunately, is bad news for anyone hoping for the return of cheap natural gas.
According to a recent report from SRI, the cost breakdown for GTL product from the proven Shell process is $7.00 for capital and depreciation, $3.00 for catalysts and utilities, and $4.00 for labor, taxes, and plant overhead. That’s $14.00 per barrel of output, exclusive of the gas input. In newer plants, it appears to require about 10 MMBtu of gas to produce one barrel of GTL product. If a barrel of GTL product is valued at $80, the effective return to the producer on 10 MMBtu of gas is $66.
A valuation of $80 for a barrel of GTL product is certainly high by past standards for middle distillates. However, the past standard for crude oil was not $55 / bbl. In the world going forward, $80 / bbl is probably not unrealistic for the refinery price for premium diesel and jet fuels that are free of sulfur and PAH compounds.
A long-term LNG price of $6.60 / MMBtu (“plus shipping and handling”) would be disappointing, but not a total disaster. We’ve been living with natural gas at roughly that level for a couple of years now. It would mean that LNG imports would not bring the hoped for price relief, but at least they should allow demand for gas to be met and thereby prevent prices from rising still higher.
Unfortunately, the simple derivation that led to that $6.60 figure is not the whole story.
The Larger Story
The GTL process is not, by itself, terribly efficient. Figures for carbon efficiency and energy efficiency vary depending on the particular process and reporting source. Quotes for carbon efficiency range from 55 – 70%. That means that from 55 – 70% of the carbon molecules in the natural gas feedstock end up in the liquid product. Energy efficiency is more consistently cited at about 65%. I.e., the energy content of the GTL product represents only 65% of what was contained in the input gas.
On the face of it, that sounds pretty bad. However, another little saying is that “it’s only waste if it’s wasted”. As it happens, the waste heat and chemical byproducts of GTL synthesis are valuable products in their own right.
Most of the carbon loss in GTL processes comes from the partial combustion of some of the input gas to provide high temperature heat for the steam reforming step. That step produces synthesis gas for the subsequent FT synthesis step, and is endothermic. So while as much as 45% of the original carbon may be oxidized to CO2 in the reforming phase, the loss of chemical potential energy is much less. Much of the heat released in partial combustion of carbon ends up adding to the chemical potential energy in the reformed gasses. Also, the CO2 byproduct of partial combustion has its own market value. It’s fairly easy to separate from the other reforming gases, and it can be sold for injection into aging oil fields for enhanced oil recovery (EOR). According to an article in the July 2005 Scientific American, oil producers with access to CO2 have been paying from $10 – 20 per ton to use it in EOR operations. For perspective, $15 per ton of CO2 would equate to a “rebate” of roughly $1.00 / MCF of natural gas, for the CO2 byproduct of its combustion.
In contrast to the carbon loss in the reforming step, most of the energy loss in GTL processes occurs in the subsequent FT synthesis phase. FT synthesis is exothermic; the reaction vessels must be actively cooled to keep them at optimal temperature for the reaction. However, only a part of the difference in chemical potential energy between the input natural gas and the FT liquids is lost as heat. Much of it goes into chemical potential energy in the principle “waste” product of FT synthesis—which is hydrogen gas.
Since the ratio of hydrogen to carbon in natural gas is nearly double what it is in the heavier hydrocarbons of the GTL output, it should not be surprising that the GTL process produces hydrogen as a major byproduct stream. In fact, it produces almost half as much hydrogen as would be produced if the same amount of natural gas were processed by steam reforming to produce only hydrogen. So if a hypothetical Middle East producer happened to have, say, large reserves of heavy sour crude that required a lot of hydrogen to refine, a GTL facility could supply that hydrogen at no cost. Or, since it’s only a matter of internal accounting, the GTL output could be charged for only 60% of its NG input, with the other 40% charged to hydrogen production for the refinery. That would boost the accounted productivity of the GTL process by 66%.
Hydrogen and CO2 are not the only useful byproduct streams from the GTL process. The heat energy released in F-T synthesis is not at a high enough temperature to drive the production of synthesis gas, but at 200 – 350 degrees C it is adequate for power generation and for water desalination.
Back to the Future
When the efficiencies of integrating GTL with refining of heavy crude, enhanced oil recovery, power generation, and water desalination are all considered, the price needed to favor LNG production over GTL is upped considerably. If crude remains in the vicinity of $55 a barrel, it’s likely that LNG will need to fetch $10 / MMBtu or more to justify investments in LNG production over GTL. Producers will no doubt want to hedge their bets by building some of both, but a quick boom in LNG at today’s prices appears most unlikely.
That leaves utilities stuck with uneconomical gas-fired generating capacity with only one good option: the once and future technology of coal gasification. Tomorrow’s coal gasification plants will be a far cry from the dirty, smelly “town gas” plants from the turn of the last century. Hopefully, they will follow the lead of the Dakota Gasification Company in producing a pure CO2 waste stream that can be sold to nearby oil outfits for enhanced oil recovery. But however they’re built, it’s time to get moving on them. Anyone waiting for natural gas prices to return to historical levels will, I fear, be waiting for a very long time.
End Notes and Links
 A claim equivalent to just 8 MMBtu per barrel is asserted for Conoco’s GTL process, but that is out of line with most other data. It could be the result of different accounting methods. E.g., it might exclude that portion of the natural gas input that produces hydrogen that is not consumed in the synthesis step.
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