NEGATIVE LNG PRICES IN OUR FUTURE?
May 14, 2020 § 3 Comments
The combination of Covid 19 driven demand loss and the Russia/Saudi spat sent oil into negative pricing for a day in late April 2020. This was largely an anomaly driven by futures trader missteps. Now, there is the real, although still unlikely, scenario unfolding for negatively priced Liquefied Natural Gas (LNG). Spot pricing in Europe and Asia is at historic lows, approaching USD 2 per MM BTU, and dipping below that on one occasion. At that price it is tantamount to being negative because it is less than the cost to produce and deliver for most.
The cost of landed LNG anywhere may be broken down into two parts: liquefaction and transportation. Post landing, there is a re-gas cost. The first step is the costliest and is broken into capital cost amortization and operating cost. The capital component is the higher of the two. While location specific variants exist, very roughly speaking, liquefaction costs USD 2 – 3, transportation 0.4 – 1.1 (sometimes double that in times of scarcity of vessels) and re-gas O.4. The transportation costs are distance driven. Add to that the cost of the feed gas, which can be lower than the regional price due to long term contracts. Nevertheless, even if a low cost of USD 1.0 is ascribed to it, a useful total figure for the US would be USD 4. This makes the landed cost still higher than the spot pricing in evidence today.
LNG is the methane part of natural gas cooled to -161 oC. Most natural gas contains up to 10% larger molecules than methane. These are primarily ethane, propane, and butane. These must be removed prior to liquefaction. In the liquid state methane is 600 times denser than the gas from which it was derived. This property makes it amenable for long distance transport across oceans. But it must be kept at -161 oC. The most economical way to accomplish this is to allow some of it to evaporate, which cools the bulk liquid. An everyday example is the cooling action of sweat evaporating from one’s skin in a breeze. The gas is collected and used in the vessel engine or to make steam, which conserves it and prevents a greenhouse gas emission, but still constitutes loss of a saleable good.
As in the case of oil, when the demand is suddenly depressed, LNG gets stored. Limited capacity at the land locations leads to storage in the idled vessels. This week Qatar reportedly has 17 tankers idling off their coast. Each tanker carries up to 3 billion cubic feet of gas. Unlike in the case of oil, this storage has a cost beyond the lease of the vessel: the boil off gas has no use in a stationary vessel. It must be released from the tanks and will likely have to be flared.
Most LNG contracts have pricing pegged to the price of oil. The plummet in the price of oil in the last couple of months took with it the LNG price. In net importing nations, LNG sourced gas is the marginal cubic foot. Domestically sourced gas is used first. In India, for example, in normal times, the controlled price for domestically produced gas was complex, but around USD 4 per MM BTU. The LNG import price was around USD 11. Now things are different. After the Covid 19 depressed demand is met with regional gas, LNG demand is low, thus driving down the spot price. Incidentally, Indian renewable electricity has increased as a percentage of the total during the last few months.
LNG is to Qatar what oil is to Saudi Arabia: the primary source of income for the nation. It does not have the luxury of a cartel to control prices. Qatar, together with Russia and Iran, did attempt to form the Organization of Gas Exporting Countries (OGEC) in 2008. This was about the time that US shale gas was hitting its stride. Within a few years, US shale gas throttled the formation of the cartel because it was producing some of the lowest cost gas natural gas in the world, and lots of it. In very short order, the US went from plans to be a major importer of LNG (and therefore a client for the OGEC aspirants) to an exporter. Cheniere Energy, the US leader in LNG was forced to dump development plans for re-gas plants and to shift gears to become exporters. This reinvention did give them a cost advantage over competitors who joined the trend to take advantage of plentiful low-cost gas: existing facilities. The docking stations for the vessels and the shore storage existed and comprised nearly half of the cost, and half the time to commission, of that in greenfield operations.
Green field LNG liquefaction facilities and associated marine berths and storage cost about USD 4 billion, give or take some depending on details. 40-60% of this is labor, one reason why local governments find such plants attractive. But the high cost means long amortization periods. Add to that the fact that from start to finish they take up to 10 years to build. Uncertainty in pricing, the practice in this industry of long-term contracting notwithstanding, is daunting. That is precisely what Covid 19 has accomplished: created significant uncertainty in demand. Predictably, investors are balking. Worldwide, USD 50 billion worth of plants have been canceled or delayed.
Qatar faces the quandary of not being able to control prices, and yet needing a high market share: exactly what the Saudis faced with oil a couple of months ago and responded by offering discounts to get share increases. If Qatar were to do this, LNG price could briefly dive into negative territory. The US producers are likely to curtail production because it is unprofitable. Russia and Norway already are throttling back on gas sales. Qatar will most likely also drop production, no matter the fiscal pain, and spare us the drama of negative price lightning striking again *.
*”Lightning is striking again” in Lightnin’ Strikes, performed by Lou Christy (1966), written by Lou Christie and Twyla Herbert
Most appreciated this snapshot of the current LNG market. Thank you.
Very interesting and thought provoking. I am interested in the efficiency and costs of energy/fuel transport. You mention that capital costs for LNG are higher than operating costs. Is there a breakdown of capital vs. energy cost for the two big ones: liquifaction and regassing? And is a fraction of the gas is lost to evaporation and flaring (as opposed to conversion to transportation fuel)?
Here are some rough numbers. Assuming the total compression plant costs to be USD 2.5 per MMBTU. Of this the operating cost is largely the gas used for the compressors. In the US, especially today, that could be as little as USD 0.2 per MMBTU of LNG produced. In Australia that would be at least USD 0.7; lots of reasons. But the overall number is higher than the USD 2.5.
Regas is very cheap on operating cost. Evaporation releases energy.
Your last question: LNG can be stored only by using evaporative cooling. The gas is usually utilized in some way if feasible, such as ship engines. I imagine the gas from shore storage at a compression plant is used in the compression. I am not sure what happens in LNG trucks on the road. They likely release it.