The issue of an appropriate price benchmark for LNG continues to attract widespread debate. Perhaps the question should be who looks for what in a price benchmark? Business relevance and transparency are key criteria. Liquidity should also give confidence the price is representative of market fundamentals. Clearly, to the extent that the benchmark can be used in contracts.
The development of LNG trade often involved displacing oil as a fuel in power generation. As such, use of oil indexation was deemed appropriate – and can be varied across a range of prices, thus protecting sellers from low, or buyers from high prices. Historically, indexation levels have varied widely, reflecting the balance of seller-buyer power and individual traits when contracts were negotiated.
Nonetheless, LNG projects have been sanctioned against gas price benchmarks (e.g. Henry Hub or NBP). In this case, demand constraints, even in markets like Japan, allowed sellers to mitigate volume risk by having the option to deliver LNG into Europe or the USA, in return for accepting gas price risk.
Today, oil based fuels continue to be substituted by natural gas – be it Malaysia, where domestic gas shortfalls resulted in distillate being used for power generation (prior to LNG imports), or Pakistan, were furnace oil is often the competing fuel. Thus, at one level, competition between gas and oil continues.
While oil demand is dominated by transportation, in some cases, natural gas vehicles compete. For example, the potential for LNG as a marine bunker fuel has been estimated at 25 mt by 2025. Natural gas use (CNG or LNG) for vehicle fleets is currently niche, but found in many countries (e.g. China, Canada etc.).
The largest, and most competitive area for gas is power. Incrementally, LNG often no longer competes with coal, but renewables – which accounted for over 60 percent of global capacity additions in 2016, pushing out legacy conventional fuels in high-growth economies. That is the real marginal competition for LNG.
There are challenges in integrating renewables. However, it is widely believed distributed power will become more important; and intermittency can be mitigated by battery storage and demand-side management.
Where the resource potential exists, the economic competitiveness of solar and wind cannot be overlooked, even against baseload CCGT. Taken together with climate change commitments the role of gas as a transition fuel must importantly be shaped from a competitive pricing perspective.
Take Your Pick
It may seem ironic when oil and gas prices are down around 60 percent from their 2013 highs, that there seems to be such a strong focus on price competitiveness. Yet, that is also a function of market deregulation, and no more so than in Asia. Nonetheless, with a swathe of US projects effectively offering Henry Hub linked pricing it is difficult to see what the fuss is all about. Or is it?
Henry Hub or oil based pricing, what is the problem? The answer is at times one may prove more expensive than the other, hence buyers always want the best of both worlds.
With long project lead times, the issue for LNG lies in assuring security of supply and the need to committing to an obligation to take (or pay).
US export projects can deliver LNG to Asia for US$8 per MMBtu (US$3 feed gas; US$3 for liquefaction; and US$1.60 for shipping). Few greenfield projects can match a US$3.50 per MMBtu upstream development, nor beat US liquefaction costs (when logistics and manpower are considered), even though shipping for projects proximate to Asian buyers could be US$1 per MMBtu less than their US counterparts. Russia may be the one real competitor, with 50 mt of proposed new capacity (which would add to Sakhalin and Yamal LNG).
LNG delivered to Japan at US$8 per MMBtu (basis Henry Hub) is equivalent to around US$50 per bbl for oil-indexed cargoes from Australia (assuming a 13 percent slope; and a straight line). Some deals have been reported around 11 percent (close to European gas prices). But, if oil prices recover to US$70 per bbl, LNG prices would increase US$2 to around US$10 per MMBtu. Higher oil prices are a more likely scenario than Henry Hub moving back to the US$5 per MMBtu level on a sustained basis.
Renewables (solar and wind) are all about high up-front capital costs and small variable costs. LNG has severe trouble competing with that marginally, and can in many new markets only find its proper place and pricing basis in a full-cost investment setting, co-jointly with renewables. Long-term marginal LNG valuation is therefore quite conventional, and buyers should appreciate that.
It’s About Money
Projects need buyers. US LNG developers offer a compelling argument – price risk off a long flat supply curve, fixed liquefaction costs, destination flexibility, and little risk of slippage in project schedules. Recently, price certainty has extended to a reported five-year fixed cost delivered price offer to Japan from 2023. For a large buyer with a portfolio of supply that may prove too attractive to ignore.
However, this also says something about US projects. Unless the feed gas cost is hedged, the price risk is fully reflective of the US gas market. Markets tend to do what people least expect – and nobody is expecting a significant increase in US gas prices. But historically gas prices in the long-term exhibit greater volatility than oil prices do, and New-England winter gas prices are more than twice Henry Hub. It comes down to your stomach for risk, your willingness to use your alternative fuels, or outright accept curtailments.
“Conventional” LNG projects with integrated upstream development carry fixed costs. But, once that cost is covered (perhaps through a price floor), the upside potential is considerable, if oil indexation prevails. That gives conventional sellers an opportunity US counterparts do not have – “hybrid” pricing. This means a buyer can be offered the “lower of” Henry Hub or oil-linked prices (subject to a likely price floor to finance the project). US developers clearly still face tough competition.
In a tightening market, many buyers will again find themselves struggling with their inability to think long-term earlier. Others will have a clearer crystal ball and the will to act on it.
Putting Theory into Practice
Recently, several MoUs have been signed, e.g. JERA, KOGAS and CNOOC; JERA and DUSUP; Centrica and Tokyo Gas; and Total and Pavilion Energy (LNG bunkering). But, aligning stakeholder interests is easier said than done, as evidenced in conventional projects trying to structure deals across the LNG value chain. Nothing is likely to be done quickly, and certainly when an MoU is of a general cooperative nature.
The real scope for collaboration lies in asset optimisation – which is understandable given the constraints in today’s LNG market by way of access to infrastructure and the continued push to lower costs. Key areas to watch would be in storage, transportation, and cargo swaps. Putting in place framework agreements that help increase operational flexibility could yield significant benefits.