As ramped-up global production places long-term deflationary pressure on natural gas prices, leading importers in Asia are growing increasingly frustrated with the persistence of oil-indexation in LNG contracts. Since 2006, regional gas prices have decoupled (Exhibit 1, BP Statistical Review of World Energy 2013) and Asian nations have seen their prices spike. Historically, Asian LNG is linked to the average monthly price of a basket of imported crudes known as the Japanese Crude Cocktail, or JCC. The pricing of these contracts generally reflects the fact that one thousand cubic feet of natural gas contains one-sixth (16.67%) the energy content of a barrel of oil - a relationship often referred to as "oil parity."
In simplified terms, the pricing formula for Asian LNG imports can thus be thought of as a linear relationship: Y = (0.1667 x JCC) + premium. Typically, the contract slope will also be S-shaped with caps and collars to protect buyers and sellers from exceptionally high or low oil prices. If oil prices fall outside a certain pre-agreed band, the slope is generally flattened on the upside (to 0.05 x JCC, for example) to lessen the burden on the price-taker. To offer downside protection to suppliers when oil prices fall, the premium component of the equation is often adjusted upward.
Under this formula, a Brent price of $100/barrel would yield an LNG import price of $16.67 + premium, a rough proxy of what Asian markets are paying today. With Henry Hub currently trading in the $4-5/MMBtu range, LNG prices in the Far East are approximately four times higher. The economic impact on the region has been noticeable. Japan - traditionally a net exporter - has recorded 17 straight months of trade deficits, largely due to rising energy costs after the Fukushima disaster. Unhappy with these developments and emboldened by the growing prospect of natural gas exports from North America, prominent Asian buyers led by Japan and India have sensed the opportunity and formed a consortium to aggressively lobby for lower LNG prices.
The supply-demand dynamic of LNG markets has thus grown increasingly complex. Under normal market conditions, Japan and South Korea would hold significant negotiating leverage as the largest importers in an increasingly gas-saturated world. A lack of hydrocarbon resources and a shift away from nuclear energy post-Fukushima, though, have partially offset this advantage. Suppliers are well aware of the increasing reliance of Asian economies on natural gas imports, as illustrated in the graph below (Exhibit 2).
Source: Barclays Cross Asset Research - Global Energy Outlook (9/4/2013)*
For producers, then, the question of how to price their long-term contracts with Asian buyers becomes a delicate one. Simultaneous increases in both supply and demand - market forces with diametrically opposite impacts on price - have resulted in a tense tug-of-war. On the one hand, nations like Japan and South Korea remain heavily dependent on a reliable stream of LNG imports and should theoretically display inelasticity to high prices. China's growing appetite for liquefied natural gas (Exhibit 3) will also bolster Asian demand for years to come. On the other hand, as shale discoveries increase and more LNG projects come on-stream across the globe, producers fear being undercut by their competitors. Adding further pressure, most projects cannot be financed until the pre-contracting of future output is securely in place.
Source: Deutsche Bank Markets Research - Gorgon and the Global LNG Monster (9/17/12)*
The looming possibility of cheap U.S. exports flooding the market has clearly unnerved producers and temporarily tipped negotiating power back to Asian importers. The dramatic rate of increase in U.S. shale gas production (38.8% CAGR since 2007, Exhibit 4) has accelerated the timeline for U.S. exports. Previously-constructed LNG import facilities along the U.S. Gulf and East Coasts are rapidly adding liquefaction capabilities at relatively low cost. BG Group (OTCQX:BRGYY) has estimated that the cost savings from re-tooling an existing regasification facility could be as high as 50%. Placed head-to-head in the market, foreign greenfield LNG projects will therefore have great difficulty competing on price against their brownfield U.S. counterparts. Chevron's massive Gorgon LNG project in Northwest Australia, for instance, has seen its capital expenditures balloon to over $50bn, causing Deutsche Bank (DB) analysts to dub it "one of the largest private projects ever undertaken in global history."
This brownfield advantage is reflected in the data. Most U.S. unconventional gas plays enjoy commercial breakevens of under $5/Mcf, with the Marcellus formation estimated at $3.8/Mcf. By contrast, Mozambique's large offshore gas finds in the Rovuma Basin and Australia's massive LNG projects have anticipated break-evens of $12-13/Mcf and $14-17/Mcf, respectively (Source: Goldman Sachs - 380 Projects to Change the World, 4/12/13)*. Asian buyers are also likely to favor secure supply sources in the United States over projects in more politically-volatile regions like East Africa. Argentina's renationalization of YPF in 2012 served as a stark reminder of the great risk of frontier markets.
Furthermore, the one major cost advantage Australian and East African projects hold over American exports - geographic proximity to key Asian markets - will soon be lessened. With a widened Panama Canal set to open in the coming years (contingent on the resolution of current cost disputes), the shipping distance from the USGC to Asia for large LNG tankers will drop from 16,000 to 9,000 miles. Subsequently, the current freight cost to Japan should fall from around $2.50 to $1.40, though this is variable depending on the new toll fees.
Consequently, a growing sense of urgency is enveloping LNG producers outside the United States. The race is on to sign contracts, construct facilities and bring projects online before U.S. exports cut into their already-thin margins or render them commercially unviable. In 2013 alone, the Department of Energy has granted non-FTA export approval to three U.S. LNG projects, almost three years after Sabine Pass received the same permission. As of late January 2013, the DOE had approved 41.05 Bcf/d of natural gas exports - 34.68 Bcf/d to FTA countries and 6.37 Bcf/d to non-FTA nations. Some further 23 applications are currently under review for non-FTA exports totaling 35.11 Bcf/d. A summary of the non-FTA approved projects is seen below. [Note: DOE approval of Cameron LNG project occurred during article review and publication and is therefore omitted from analysis]
With the DOE seemingly on board, the greatest threat to the twenty-three U.S. projects currently awaiting approval is grass-roots backlash. Domestic manufacturers and private citizens, both beneficiaries of low energy costs, are openly challenging the decision to permit gas exports. In November, Dow Chemical (DOW) released a statement arguing that the approvals would "raise consumer energy prices, discourage manufacturing investment, and impede economic growth and job creation." Through an appeal to energy independence and patriotism, the argument could prove politically compelling in Washington, DC. Present momentum strongly suggests, however, that the United States is moving ahead with natural gas exports.
The possibility of exports from Canada's west coast, although less imminent, has granted Asian buyers further bargaining power. Located in northeast British Columbia, the Horn River Basin is estimated to hold up to 75tcf of recoverable gas reserves, nearly as much as Mozambique's more celebrated offshore finds. With Alberta's AECO C natural gas benchmark hovering in the $2-$3 range, Horn River's estimated breakeven of $4/Mcf may not be low enough to merit commercial development for the moment. Just south of the Horn River play, the Montney shale - with an additional 50tcf - faces a similar breakeven constraint. A lack of pipeline infrastructure and environmental concerns may also prove problematic. Already, a proposed 750km pipeline - the Prince Rupert Gas Transmission Project - is in jeopardy because it would cut through the Khutzeymateen grizzly bear sanctuary (Source: Global LNG Monitor - Issue 286, 9/12/13)*. These fields will eventually come on-stream, though, and their size and relative proximity to the Asian markets will have an immediate impact on the market.
Using the North American production boom to promote the idea of a sustainable "global gas glut", Asian importers have successfully managed to chip away at the longstanding oil-linked pricing mechanism for LNG contracting. Contracts signed by U.S. export terminals reflect this.
In November 2012, Japanese power utility Kansai Electric signed a 15-year import contract with BP (BP) Singapore with Henry Hub as the basis. The agreement marked Japan's first-ever long-term LNG import contract to be fully linked to a gas benchmark. In January 2012, Cheniere Energy (LNG) signed a 20-year agreement with Korea Gas Corporation (KOGAS) to supply 3.5 million tonnes per annum (MMtpa) of LNG from its Sabine Pass facility for a $3/MMBtu liquefaction fee plus 115% of the current Henry Hub price. More recently in 2013, Freeport LNG in Texas signed 20-year tolling agreements with Asian industrials Toshiba (Japan) and SK (Korea) for a premium of $7/MMBtu over Henry Hub. Dominion Resources' (D) Cove Point, Maryland project has also signed Henry Hub linked contracts.
In conclusion, rising competition between LNG suppliers to secure long-term contracts and the imminent threat of U.S. exports has provided Asian buyers with greater power to negotiate contracts based on the U.S. benchmark. A variety of factors (Exhibit 6) are converging to place net downward pressure on LNG prices over the medium-term (5-year horizon). Oil-indexation in LNG contracting will certainly not disappear overnight, but the shale revolution temporarily has enabled Asian importers to make significant inroads and secure more favorable procurement pricing.
* Asterisk denotes sources that are not publicly available. As such, links cannot be provided.