Natural-gas fell to the lowest ever inflation-adjusted price in its history of NYMEX trading on Wednesday as extremely warm weather continues to limit demand. As we recently explained, the glut in nattie is worse than that facing the crude complex, and while the glut in oil is expected to continue for the next year or so before balancing in late 2016, the pain for liquefied natural gas (LNG) could be just beginning. As one trader warned "this market is in real trouble...just wait for the bankruptcies."
As The Wall Street Journal reports, gas prices have been falling precipitously in recent weeks because of the combination of record-high stockpiles and a December that could be the worst for heating demand in history.
Prices have fallen 25% in just one month and have dropped 39% from their high in August. Wednesday settlement put gas below the inflation-adjusted low of $1.801 that had been in place since January 1992.
Gas did make a move up to small gains in after-hours trading, but many traders and brokers had little explanation for that rebound. The trader Marc Kerrest said he noticed prices and spreads moving higher for months far away, a sign front-month prices could follow. He closed out some of his bearish bets before settlement, he said.
“But in no way would I consider going [bullish on] gas just because of what it’s done,” in recent weeks, said Mr. Kerrest, who manages his own gas-focused fund, Cornice Trading LLC.
Warm weather in the U.S. caused by the El Niño weather phenomenon has sharply limited demand for the heating fuel this year. The natural-gas market is oversupplied, and some traders and analysts say the industry could run out of storage space for gas by mid-2016.
Production was so high and demand was so soft that storage levels likely shrank by just 41 billion cubic feet last week, according to the average forecast of 17 analysts, brokers and traders surveyed by The Wall Street Journal. That is only a third of their five-year average drawdown for the week. If the forecast is correct, stockpiles on Dec. 11 would have been 16% above levels from a year ago and 8.9% above the five-year average for the same week.
With weather so warm and prices already so low, there may be no lower price to which gas can fall to draw more demand, said Scott Shelton, broker at ICAP PLC. That means prices have to fall so far that producers stop working.
But many have been caught in a cycle of debt, forced to keep producing even at a loss just to bring new revenue in the door that they can use to pay the debt bills that piled up from using loans to fuel their growth during the drilling boom. It isn’t clear how far prices would have to fall to get them to stop, Mr. Shelton said.
“This market is in real trouble,” Mr. Shelton said. “Just wait for the bankruptcies.”
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Finally, as we detailed in October, JPMorgan sees a buyer's market in NG 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% 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 demandgrowth, with some nuclear facilities expected to restart that will initially lead to fuel switching away from burning oilproducts, 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 beingcheaper and could seea 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 relatedto 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% this year at 184bcm in 2015, rising to 300bcm in 2020 (implying 10% 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).
#3: LNG still at a cost disadvantage vs alternative fuels
Long-term demand from fuel switching remains a potentialoption, 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 next1-3 years. In Japan, one smaller customer is actually still investing ina new coal power plant. However, the companyacknowledged that this would likely be the last coal facility that itwould 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 75mptaFY14-17on its way, mostly from Australia and the US–which is over 3x the equivalent capacitygrowth FY11-14. Customers in Japan andKorea 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 established to be a more globally competitive powergen and gas business, stated it would only sign LNG agreements from 2020+ as existing contracts expire (eg Qatar). However, there was a desirefrom Asia buyersto exercise destination flexibility clauses where possibleand 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 hashigh confidence in the project as well. KOGAS isfinding it difficult to findbuyers 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.
#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 US and Qatar could increasingly look to the European market as anoutlet valve, given geographic proximityand gas storage availability. While European gas prices have already been weak (UK National Balancing Point (NBP) index down 22% y/y), the economics of sending Henry Hublinked gas to Europe (Henry Hub * 115% + transport) remainsattractive and suggeststhat 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. JERAexpects to increase the portion of non-JCC linked contracts. By 2020, JERAexpects10mtpa 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(eg 50% JCC/50% Henry hubmix). JAPEX has also noticed a change in customer pricing toward a mixed/hybrid structure.
#8: Eco-ships taking time
NYK seeslimited recovery in spot dayrates for LNG vessels in the next 1-2years, but as liquidity increases and more projects eventually get sanctioned there should be more opportunitiesin 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 notalways available tofill 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 shippingfuel, the pace of natural gas substitution has been slowed a little with lower oil prices.
#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 surpriseto us. KOGAS stated that if the oil price remains at $50/bl (using a 6% discount rate) the companyis not likely to take impairment on its Australian LNG projects (GLNG, Prelude). KOGAS see its Australia GLNG returns at c6% and Prelude at 7-8% at current oil prices (both previously around 9% in a higher oil outlook). INPEX guided only anIRR decrease by 1% from previous 1010% IRR at $70-100/bl for Ichthys. The company also stated anIRR at $60/bl would be below 9%, 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 producerse.g. Eni for Mozambique. DSME know the costs for FLNG from Petronas FLNG (and know thelessons learnt, e.g higher than expected working volume, i.e man hours). However, DSME expects60 months from contract signing to delivery for FLNG (Eni or Anadarko Mozambique) and itsyard 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...