As the first shipments of LNG from the United State to Europe, South America, or Asia loom, the salient question is not the “volume question” (i.e., how many Btus or Bcf will be outward bound to an overseas destination) but rather the “basis question:” Will first shipments be profitable? Will any future shipments be profitable? If not, can we bid adieu to United States LNG exports? Will there be minuscule or zero volumes if intercontinental basis cannot support them?

Is it possible that all the links in the supply chain garner positive margin (i.e., make money) on these first shipments? Any shipment? In particular, will participating suppliers, gatherers and processors, pipes to liquefaction, liquefaction, shippers, regasification, pipes to market, and consumers that comprise the supply chain all make money? Will there be one or more links in the chain obliged to lose money? Will the ultimate end user be contractually forced to take gas at an “out-of-the-money” price, above fair market value? Taking gas at an “out-of-the-money” price above fair market value is an economic loss, whether or not a “take” price may be prescribed in a contract. (“Out-of-the-money” contracts are losses, and they can often find themselves quickly renegotiated or vitiated.)

If one or more of the parties along the way fails to make money or loses money, what would we expect that party to do in future transactions? Continue to move gas in spite of the loss? Continue to pay for gas at “out-of-the-money” prices governed by “out-of-the-money” contracts? Continue to honor a purchase contract notwithstanding losses? In recent years, we have seen LNG customers vitiating or renegotiating out-of-the-money contracts in favor of mark-to-market, gas-on-gas prices. Is that just an anomaly, never to rear its head again, or are current and future contracts imperiled? Are gas and LNG the only commodity in the world that require contracts in order to be viable? Are contracts intrinsic to that business?

Profitability is the criterion driving LNG flows and decision making. LNG doesn’t flow from a low-demand region to a high-demand region; it flows from a low-price region to a high-price region. Price, not demand, dictates flows. And profitability cannot possibly occur unless the basis differential from the source to the destination is more than enough to pay for all the pipe-to-liquefaction, all the liquefaction, all the shipping, all the regasification, and all the pipe-to-market cost. Hopefully there is also a bit of return, because if not, no new capacity will be built.

Using NBP as an example, the price at NBP is totally independent of the transportation cost (including losses) from Sabine Pass to NBP. Market prices and basis differentials do not magically line up so that the Sabine-to-NBP route is intrinsically profitable. Quite the contrary, the price at Sabine is set by gas-on-gas competition in the United States, and the price at NBP is set by gas-on-gas competition in England and Europe. The hope of any LNG vendor is that his cost to deliver is lower than the gas-on-gas price in England minus the gas-on-gas price at Sabine. If so, he sells. If not, he doesn’t.

We answer the salient questions using the ArrowHead Global Gas Model, an extensively detailed, multi-regional, world-scope supply-transportation-demand model summarized in Figure 1. There are myriad sources of natural gas emerging around the world, and they are likely to have an effect on myriad regional markets around the world interconnected by myriad pipes and ships. The answer from this model for a robust supply case appears in Figure 2. If we observe March 2016 prices in those two markets, they differ by approximately $2.19/MMBtu (reported by cmegroup.com on March 22, 2016). If we look at the longer term, those basis differentials promise to head toward $3/Mcf but no higher. The reality is that $3/Mcf is not enough to pay the total of the costs for pipe to the liquefaction point plus liquefaction plus shipping plus regasification plus pipe to the liquid market, much less any return on any of those assets. In our robust supply case, basis differentials are not going to be sufficient to support LNG export at full cost. Exacerbating the chronically narrow basis differential is the plethora of LNG routes to each destination that emanate from lower cost supply coupled with lower transportation cost (closer proximity), routes that compete favorably with United States routes.

Picture1The basis differentials in Figure 2 are not likely to pay the full supply chain costs from the United States. There must be other considerations in world gas markets that render such volumes economic. Those considerations must reduce the cost of:

  • Pipe from the liquidity point (Henry Hub) to the liquefaction point at Sabine Pass
  • Liquefaction
  • Shipping to the receiving regasification terminal in England
  • Regasification in England
  • Pipe from the regasification point to the NBP liquidity point in England

Alternatively, they must portend paucity of upstream supply, paucity of competing supply, or acceleration of downstream demand. Our model identifies and quantifies such forces.

Picture2As it appears today, flows outward bound from the United States appear to be at some risk. (Our models can calculate a probability distribution over future price.) We have seen recent articles that question growth of LNG exports from the United States. Some have generally reached the right answer, but they incorrectly attribute the reason to shrinking demand in key target markets. It is not demand but rather price and price differentials that drive LNG. It is not shrinking demand that is driving down gas price and basis to target markets. In a forthcoming article, I will carefully address what is driving price and basis in world natural gas markets, how we have accurately analyzed it, and why it is important.

About the Author:

Dr. Dale Nesbitt is a noted national and international energy, resource, microeconomics, modeling, and risk analysis expert. He is president of Arrowhead Economics and the inventor and manager of the ArrowHead Global Oil Model and ArrowHead Global Gas Model and prior to 2011 oil, gas, and power models by Altos, MarketPoint, and Decision Focus. Dr. Nesbitt has been in energy market decision support, analysis, and modeling continuously since 1974. He holds a PhD in Engineering-Economic Systems from Stanford University and teaches there.

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Why is it that oil and gas “experts” invariably attribute soft prices to “demand that didn’t materialize” rather than “low-cost supply that did materialize?” Producers in the oil and gas industry are intimately familiar with their own (and competitors’) supply endeavors and the cost to pursue them. They get the idea that “supply is expensive.” That is just not true and is even less likely to be true into the future. They tend to attribute changes in the market to “demand,” with which they are less familiar. That simply is not the case with world and regional oil markets and prices. Prices are low today, and the reason is abundance of supply and not waning demand. At 90 plus mmbbl/day and 115 plus Tcf/year, how could that be happening?

Let’s start with a look at historical real crude and gas price in Figure 1. The real price of oil today (~$7/MMBtu) is not particularly low by historical standards. (The average real price of oil since 1973 has been approximately $9/MMBtu, with substantial volatility year to year.) The average real price of natural gas since 1973 has been ~$4/MMBtu; today’s Henry price of $2/MMBtu is markedly lower. Wouldn’t such a low price be expected with the colossal technological change and resource augmentation that has beset the gas business?

Picture1There has been considerable interest in the crude oil to natural gas price ratio, which we have plotted in Figure 2. Today’s ratio of 3.5 is slightly above the long run historical average 2.9.

Picture2(Arguments that oil indexed gas contracts don’t matter in 2016 because oil price is so low are “off the wall.”  Gas producers would eagerly accept oil price any day of the week!)  The quantity of gold it takes to buy one unit of crude or one unit of natural gas, sort of a “currency neutral” notion of the price of gold and crude, is revealing. In 2016, the ratio of ounces of gold per MMBtu of crude or oil gas is significantly lower than has occurred for many years as depicted in Figure 3. What is the reason for the dramatic change in these two ratios this year? Is this a short-term phenomenon or will it persist long-term? What should we expect for prices in the future?

Picture3The ArrowHead Global Oil Model (AGOM), Figure 4, an integrated, multiregional, multi-crude-type, worldwide model of crude supply, gathering, shipping, refining, intermediate product shipping, refinery upgrading, finished product shipping and consumption, provides answers. As a supply-curve/demand-curve model, it calculates price endogenously, as contrasted with the ubiquitous procedure of guessing oil price and putting it in from the outside. The AGOM balances supply and demand everywhere in the world at every point in time from source rock to burner tip. (Herein, we have assumed that OPEC continues the present ceiling on production but increases slightly at approximately 2 percent per year. We have also assumed that product demand grows at recent historical rates, with a slight slowing in China and India relative to previously highly aggressive assumptions.)

Picture4We have assembled a world scope collection of supply curves that portends that a significant fraction (but not all) of the light and unconventional supply worldwide is and will be available to producers, who will produce it when and if profitable. The massive and increasing volumes of light crudes recently estimated by EIA and others in places such as South America, North Africa, Russia, the Middle East, China, Australia, North America, and perhaps elsewhere are assumed to be available to producers, whether investor owned or NOCs, as are all the emerging and mature supplies of conventional crude around the world. (It doesn’t really matter to the market who produces the oil as long as it is in fact produced.)

The prices projected using these and other assumptions appear in Figure 5. The price (in constant dollars) begins at about $57/bbl ($9.80/MMBtu) and rises rather gradually to $80 in 2048. ($57/bbl is our estimate of today’s long run marginal cost, toward which we expect crude prices to rather quickly rise before long.)

Picture5People who argue that soft demand is what is eroding oil price are likely wrong. The legitimate range of uncertainty in supply and resource dwarfs the legitimate range of uncertainty in demand, and supply estimates have been trending upward at a rapid pace in recent years. Supply is the primary driver of oil (and also natural gas) price. The projected trillion barrels in the Orinoco, the 1.8 trillion barrels in the Canadian oil sands, untold trillions of barrels in the Bazhenov, Australia, North Africa, Gulf of Mexico, Permian, Eagle Ford, Bakken, etc. are available to compete in our base case, and compete they do! It is necessary to understand supply if one is to understand oil price. (We are quick to emphasize that robust supply is not the only scenario possible in the AGOM. Alternative views of supply and demand lead to alternative prices and quantities.)  The notion of chronically strong supply has gained ground with the industry and us.

Picture6What might natural gas be doing in this scenario? The answer, from the ArrowHead Global Gas Model (AGGM), which has the structure in Figure 6, appears in Figure 7. We see Henry Hub price evolving (as it moves forward in time) from approximately $3/MMBtu rising very gradually over the next four decades. This assuredly reflects the copious availability of low cost gas throughout North America and in fact throughout the world.

Picture7What does this portend for the relationship between oil price and natural gas price?  It portends that there is likely no relationship whatsoever, any relationship emerging only serendipitously from parties signing an oil-indexed contract for natural gas. The need for oil indexed contracts is low and diminishing, likely a relic of the past. In March 2016, the real world price of natural gas at NBP (U.K.) was under $4/MMBtu and crude was at $42/bbl or $7.25/MMBtu. With such abundance of supply, why would people sign indexed contracts for natural gas, agreeing to buy it at an “out-of-the-money” price? Robust supply (intrinsic in this case) suggests that they needn’t.

The model run suggests that natural gas will become more of a regional/continental business with diminishing need for ultra-long haul infrastructure. If there is plenty of gas in North Africa, Russia, and the Middle East, such gas will be competitive in Europe. Gas supplies are abundant and competitive in North America, China, Kazakhstan-Turkmenistan, Africa, South America, etc. A forthcoming article will have more to say about Caspian and Russian gas.

The projected oil to natural gas price ratio into the future appears in Figure 8. The oil to gas price ratio remains surprisingly constant at 3.0, not far from its historical level. The value of a liquid Btu is about three times that of a gaseous Btu because of the high “form value” of liquid Btus.

Picture8Strong supply, a linchpin of this case, is a juggernaut in energy markets, keeping prices moderate for a long time into the future (ignoring volatilities that emanate from short term, transient phenomena). When it comes to estimating price, there is no substitute for understanding and quantifying the resource base region by region worldwide.

About the Author

Dr. Dale Nesbitt is a noted national and international energy, resource, microeconomics, modeling, and risk analysis expert. He is president of Arrowhead Economics and the inventor and manager of the ArrowHead Global Oil Model and ArrowHead Global Gas Model and prior to 2011 oil, gas, and power models by Altos, MarketPoint, and Decision Focus. Dr. Nesbitt has been in energy market decision support, analysis, and modeling continuously since 1974. He holds a PhD in Engineering-Economic Systems from Stanford University and teaches there.

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Russian gas has been shrouded in misconceptions, and its real nature can only be understood with an integrated world natural gas model that has significant detail in and around Russia. Energy experts have defaulted to assuming that Russia is an originator and source of natural gas exports to Europe. After all, it is assumed there is so much gas there that Russia can and will export to Europe (and possibly China too) and garner for themselves the revenue they desire. This is naïve, missing the vast expanse of Russia, the high cost of incremental infrastructure that would be needed to increase Russian exports beyond current levels, and the ferocity of gas-on-gas competition looming in China and Europe.

What has paid for and thereby propped up Russian exports to Europe in the past two decades? Very high prices in Europe, buoyed by growth in European gas markets and slow infrastructure addition. High prices in Europe portend to end, and the historically high prices in Europe will no longer be there to support costly infrastructure. North African gas and LNG can flood Europe with dramatically lower cost than some of the Russian infrastructure projects which have long been taken for granted.

Imports into Russia. There is very significant inbound gas pipeline capacity at the Kazakhstan-Russia border (at Alexandrov Gay and Astrakhan). Upstream from that in Kazakhstan and the Caspian, lies a tremendous volume of low-cost, marketless gas. Russian border capacity here is on the order of 4 Tcf/yr or 10.5 Bcf/d, and its fixed costs are sunk. (EIA lists “more than 3.5 Bcf/d.”) That capacity is an artifact of the old Soviet Union, in which the Caspian was an integral part. The Russian gas system and markets utilize that gas, as our model (depicted in Figure 7 below) continues to project. We see 4 Tcf/yr continuing to be imported at Alexandrov Gay and Astrakhan (Brotherhood and Soyuz), with expansions delayed by the market to the 2027 time frame. (Such expansions require pipeline capital and operating costs, which are not economic until then. It is 2332 km from Alexandrov Gay to Uzhhorod, the gateway to Europe, which means development will entail a significant pipeline cost, even if by displacement.)

Exports from Russia. Russian gas continues to use its current infrastructure, but Russian markets need the Kazakhstan/Caspian gas illustrated in Figure 1. If Caspian gas weren’t there, Russians would consume their own gas and there wouldn’t be much to export.

Picture1Referring to Figure 2, we notice continued but non-growing exports into the European market via the Ukraine and Belarus (the traditional routes) with a modest volume through Northstream (which is too expensive to expand). The current capacity for gas exports, approximately 5 Tcf per year, will not grow materially until about 2035. The increase at that time flows through the Ukraine, Uzhhorod, and into Austria and Germany. Expansion does not happen earlier because European prices will not be high enough until then to sustain profitable infrastructure expansion. Europe will be getting inexpensive gas from North Africa and LNG until then, gas that will box high cost Russian expansion out. It is notable that Russian gas will not export to Asia. It is far too costly to build the infrastructure, and Asian markets can get gas cheaper in their local markets and from the Caspian, Kazakhstan, and Turkmenistan, which are lower in cost than Russia to get to Asia.

Picture2Indigenous Demand. Domestic consumption in Russia is large, and growing, as projected in Figure 3. Russia is not a minuscule consumer; it is a very large and cold country with a very large population. Russia consumes a lot of natural gas, and they will continue to do so. Their own production capability is sized to their own demand (a fact not sufficiently recognized). Russians produce for Russians. Russians import Caspian gas to sell to Europeans (by displacement). Russians don’t produce that much for Europeans. That situation may change 20 years from now, but probably not before.

Picture3Russian Supply. Supply in Russia has been sized to the pipe, which has been sized to meet Russian demand, not surprisingly. Everyone knows that low-cost Russian supply is colossally large. Everyone also knows that key supplies in Urengoy lie 5181 km from Uzhhorod, and expansion of that capacity is tremendously expensive. It won’t happen unless European gas price is high enough to pay for it, and that won’t occur for 20 years. Known gas reserves and resources in Urengoy, the Barents, and Yamal are staggering, but alas the infrastructure cost to bring them to market is also staggering, too high to be monetized by chronically low European prices that will occur. As shown in Figure 4, the more westerly Russian resources are declining and are not competitive.

Picture4Any notion that Russia will dramatically expand supply to serve Europe overlooks the massive cost of such expansion and the fact that European price is just going to be too low to support it. Low European price borne of gas-on-gas competition from LNG, North Africa, North Sea, and the Middle East will suppress new Russian export infrastructure for a couple of decades. Russian infrastructure will increasingly support Russian needs.

Figure 5 plots net exports from Russia, i.e., exports minus imports (Figure 2 minus Figure 1). For 20 years, Russia is not a classic exporter. Rather, Gazprom is a conduit from the Caspian to Europe, with Russian gas used to meet Russian demand. Caspian gas is a crucial piece of that puzzle. This situation might change some 20 years hence, but the present situation promises to persist until then.

Picture5Russia is neither a classic import economy nor a classic export economy with respect to gas, as our model indicates in Figure 6. Russia imports gas from Kazakhstan and the Caspian in just under the same volumes that they export to Europe. That promises to persist for 20 years or so, during which time Russia is not intrinsically a “mega” exporter but rather a displacement transporter to Europe from the Caspian using existing infrastructure, a transporter with huge indigenous demand that it serves economically with its own domestic resource. If the currently large Russian demand grows, that will take an increasing piece of Russian supply.

Picture6Game changers in Russia center on gas price in Europe (which our model projects endogenously). If supply entering Europe were restricted, European price would rise and Russian infrastructure could become competitive in Europe. We have analyzed such cases in our model, and the insights are invaluable. By contrast, if supply entering Europe were more abundant (e.g., massive LNG exports from the U.S., Middle East, or Africa), European price would remain low and Russian gas would be held out even longer.  Russian gas is not necessarily “inframarginal” in Europe. Russian gas through existing, sunk-cost infrastructure may be inframarginal, but Russian gas through new infrastructure is a whole different ballgame.

Picture7About the Author

Dr. Dale Nesbitt is a noted national and international energy, resource, microeconomics, modeling, and risk analysis expert. He is president of Arrowhead Economics and the inventor and manager of the ArrowHead Global Oil Model and ArrowHead Global Gas Model and prior to 2011 oil, gas, and power models by Altos, MarketPoint, and Decision Focus. Dr. Nesbitt has been in energy market decision support, analysis, and modeling continuously since 1974. He holds a PhD in Engineering-Economic Systems from Stanford University and teaches there.

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