As oil investors liquidate their…
Asian oil demand is providing…
With LNG supply set to increase meaningfully over the next few years, JPMorgan sees a buyer's market until 2020 with limited new long term contracts being signed and renewal of existing contracts post expiry likely to have more price diversification (i.e. more Henry hub component) and offtake/diversion flexibility. A recent trip to Asia identified 10 key themes reinforcing their bearish outlook on the LNG market for the rest of the decade.
Excess capacity forecast to grow to 20 percent by 2018...
#1: Asia LNG demand slowdown confirmed
All participants shared a cautious view on near-term demand trends, with Japan and South Korea likely flat to down and China gas demand growth having slowed this year. In Japan, population and economic trends are the main driver of lower electricity demand growth, with some nuclear facilities expected to restart that will initially lead to fuel switching away from burning oil products, then eventually coal and LNG, if enough reactors start back up (Tepco guided 1GW nuclear plant reduces LNG demand by 1.2mtpa). KOGAS believes LNG imports will decrease in South Korea next year owing to coal and other commodities being cheaper and could see a stagnant demand period from FY17.
#2: Lower FY15 gas demand growth in China – potentially a one-off
Many participants in the Chinese natural gas market saw the collapse in gas demand growth this year as "an anomaly", partly related to market uncertainty on pricing and frequency of change. Many industry contacts see mid to high single digit gas demand growth in the long term, especially if the government is serious about environmental measures and penetration of gas into China's energy mix – China has already been shutting coal power plants which were only commissioned in 2008. PetroChina sees gas demand growth at 2.6 percent this year at 184bcm in 2015, rising to 300bcm in 2020 (implying 10 percent pa). (Note: 1H15 PetroChina still makes a loss on pipeline gas of Rmb0.38/cm3 or c$2/mbtu vs a loss for LNG of Rmb1.8/cm3 or c$10/mbtu).
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#3: LNG still at a cost disadvantage vs alternative fuels
Long-term demand from fuel switching remains a potential option, but cost competitiveness is still key for now. When it comes to the potential for fuel switching to natural gas, we came away feeling that this is likely to be a positive long term driver, although it may not happen as quickly, more likely the next 1-3 years. In Japan, one smaller customer is actually still investing in a new coal power plant. However, the company acknowledged that this would likely be the last coal facility that it would consider, as future regulatory changes could add to the cost. For now, coal remains highly competitive.
#4: Lack of customer desire for new contracts
On the supply side, there is a wall of new capacity of 75mpta FY14-17 on its way, mostly from Australia and the U.S. –which is over 3x the equivalent capacity growth FY11-14. Customers in Japan and Korea were still committed to signing agreements, noting the importance of long-term supply security with reliable suppliers. KOGAS does not plan to take on any new long-term contracts until 2020 and will re-negotiate some of its Qatar/Oman contracts which expire in early 2020s. JERA, a 50/50 Tepco/Chubu JV, established to be a more globally competitive power gen and gas business, stated it would only sign LNG agreements from 2020+ as existing contracts expire (e.g. Qatar). However, there was a desire from Asia buyers to exercise destination flexibility clauses, where possible, and should supply/demand balances change in the coming years.
#5: Large projects still expected to FID
Despite the near-term supply/demand and pricing situation, some suppliers appear to have not thrown in the towel on sanctioning new projects for the 2020+. JGC expects orders for large LNG projects e.g. Mozambique (floating/onshore); Tanzania with selection of contractors this year; Tangguh expansion with FEED being conducted with selection of EPC by year end as well as Lake Charles and is “strongly hoping” Shell/BG will go ahead with LNG Canada. Chiyoda is also not only doing FEED, but also EPC and has high confidence in the project as well. KOGAS is finding it difficult to find buyers for Mozambique, but re-iterated FID by year end or early 2016for the project. If these projects (eg West Coast Canada LNG) are sanctioned and approved by local governments (also still uncertain), this may delay the longer cycle recovery potential.
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#6: Europe – the market of last resort
With near-term excess LNG supply, the question remains where spot cargoes will land. We believe that the U.S. and Qatar could increasingly look to the European market as an outlet valve, given geographic proximity and gas storage availability. While European gas prices have already been weak (UK National Balancing Point (NBP) index down 22 percent y/y), the economics of sending Henry Hub linked gas to Europe (Henry Hub * 115 percent + transport) remains attractive and suggests that future upside to European spot prices could be capped and, at worst, more downside may be ahead with the risks that Gazprom responds to maintain market share.
#7: Increasing LNG pricing diversification
Asia LNG buyers clearly want to obtain more pricing flexibility within their LNG portfolios and most buyers suggested a gradual move away from JCC (Japanese Crude Cocktail) pricing. JERA expects to increase the portion of non-JCC linked contracts. By 2020, JERA expects 10mtpa procured based on Henry hub for long term contracts (vs 25mtpa procured today with a third spot/short term). JERA also will select producers based on: 1. Offtake volume, 2. Destination flexibility; 3. Supply availability, not only price. KOGAS also said its pricing strategy will take a flexible approach on existing contract expiry (e.g. 50 percent JCC/50 percent Henry hub mix). JAPEX has also noticed a change in customer pricing toward a mixed/hybrid structure.
#8: Eco-ships taking time
NYK sees limited recovery in spot day rates for LNG vessels in the next 1-2 years but, as liquidity increases and more projects eventually get sanctioned, there should be more opportunities in LNG shipping (the company expects to expand its 69 LNG fleet to 100+ by 2019). Most of the company’s current vessels are steam turbine. Under current technology, NYK suggested it is not easy to replace vessels to natural gas as infrastructure is not always available to fill up at ports, hence NYK will soon have its own LNG bunkering vessel in Europe. The company believes that while the eco-ship theme remains structural with more environmental measures being put in place for shipping fuel, the pace of natural gas substitution has been slowed a little with lower oil prices.
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#9: Australian LNG projects around mid- to single-digit IRRs at current oil price
Despite most Australian LNG projects being at the upper end of the cost curve, many companies were guiding mid- to single-digit returns for these projects at current oil prices, which was a surprise to us. KOGAS stated that if the oil price remains at $50/bl (using a 6 percent discount rate) the company is not likely to take impairment on its Australian LNG projects (GLNG, Prelude). KOGAS see its Australia GLNG returns at c6 percent and Prelude at 7-8 percent at current oil prices (both previously around 9 percent in a higher oil outlook). INPEX guided only an IRR decrease by 1 percent from previous 1010 percent IRR at $70-100/bl for Ichthys. The company also stated an IRR at $60/bl would be below 9 percent, although project breakeven point is around $30-40/bl.
#10: Wait and see approach for FLNG and LNG FSRU
There was a cautious view on the outlook for FLNG and LNG FSRU with the market waiting to see if Petronas demonstrates FLNG works, then more projects will start to be sanctioned and more small-cap players may join the market i.e. small LNG solutions vs mega projects. Shipbuilders such as DSME remain in “tough” negotiations with producers e.g. Eni for Mozambique. DSME know the costs for FLNG from Petronas FLNG (and know the lessons learnt, e.g. higher than expected working volume, i.e. man hours). However, DSME expects 60 months from contract signing to delivery for FLNG (Eni or Anadarko Mozambique) and its yard could cope with signing two contracts for two FLNG vessels. Keppel, which is half way through a conversion for Golar, is still talking to other producers about new contracts and believes vessel conversion is still economic at current oil prices. However, some E&C companies believe NOC’s do not like FLNG and prefer onshore LNG as there is no ownership if FLNG.
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And to nail the coffin shut one more time, they add, Coal is still consistently cheaper than natural gas or oil products...
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