US LNG capacity utilization: Lower prices challenge US exports

Theodore Michael's picture
Theodore Michael, LNG Analyst, Genscape
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Opposite Directions:  While oil prices rally, LNG makes new lows - Exxon and other major players are sticking to their script.  By 2020, rising demand will be in line with production. Oil prices will rise and LNG indexed to oil will simply follow.  However, global supply for LNG will rise by 120 mtpa in next three years.  While oil supplies may remain unchanged, we can see the divergence between spot LNG and indexed terms already.  Brent crude oil has rallied 50% since its January lows placing 16% oil-indexed LNG in the $6 range.  Spot LNG prices are currently breaking $4.00 in the Asian basin and NBP the Atlantic Basin marker, is trading closer to $3.50 for June delivery.

Should the spread between spot and oil-indexed contracts widen, pressure will build on take or pay holders to lift less than minimum requirements. Spot volume will increase and new entrants will force term sellers to accommodate.  In a world of narrowing energy margins, buyers of term may be asked to pay a 50% or greater premium to spot markets, a commercially untenable situation.  Especially with deregulated markets pricing off marginal costs.

US LNG export capacity:  How low can LNG prices go? US LNG construction is on schedule to export 65 mtpa (8.5 bcf/d) with the next 3 years. On top of 55 mtpa from Australia. The current global demand of 250 mtpa will see approximately 40 mtpa online this year alone.

While the Atlantic Basin has been a swing supply for Asia in the past, that role is reversing, with Australia coming online in 2017 before US capacity.  However, as we move into 2018, US export capacity will be entering full production mode, driving Atlantic Basin prices down to MC of supply.

The order of merit:  Dispatch at lowest marginal cost - LNG markets are asking the question; how much of capacity under construction will dispatch, and how much will shut in.  Liquefaction capacity charges are sunk costs so are term charters for shipping and regas terminal agreements.  The marginal cost of dispatch, therefore, only includes fuel where LNG capacity holders own the entire supply chain.

In the US export market, capacity holders without regas terminal access will be the first to shut in.  For exporters with their own shipping and regas; marginal dispatch will be feed gas, plus losses during liquefaction and ship fuel.  Using NBP as a proxy for EU and Atlantic Basin LNG prices, and Cheniere’s feed gas charge of 115% of HH for losses and acquisition costs. We add 10% more for ship fuel and create a quick capacity marginal dispatch formula.

Lowest cost dispatch =  NBP -  125% Henry Hub

Integrated major players with access to prices behind EU regas terminals and utilities with a dedicated customer base will, therefore, be the last to shut in.

Assets in supply chain are sunk costs - At the low end of the marginal cost scale is the fully integrated major players like Shell/BG or integrated utility companies such as Iberdola, E.ON and Gas Natural Fenosa.  Ownership of the full supply chain means sunk costs across the board.

We may also rank the marginal cost LNG producer in order of lowest cost feed gas access.  Lower cost basis than Henry Hub include:

  • Dominion Cove’s Leidy line direct access to the Marcellus/Utica
  • Cameron LNG access to low-cost Haynesville shale
  • Corpus Christi and Freeport access to the Eagle Ford

Cheniere marketing alone will have 9 mtpa of DES capacity with 3 ships under long-term charter but no regas capacity.  Similarly, the Soga Shosha buyers have shipping but no regas in Atlantic basin (Mitsui, Mitsubishi, Sumitomo). At the high marginal cost end of the supply stack are the Japanese utility hedges with no shipping and no regas access.

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