Gas, Carbon and Credit

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By Greg Peel

What is LNG?

Natural gas is an energy source for an environmentally challenged world because it is the cleanest of all fossil fuels, having the lowest CO2 emissions per unit of energy. It is also as abundant as coal. Oil provides the world with two problems: firstly, it is a heavy carbon emitter and secondly its remaining availability is questionable. Coal’s abundance creates its own problems, as while it is the cheapest form of fossil fuel it is also the dirtiest. Natural gas seems like an obvious solution, and it is ideally suited to fuel both vehicles and power stations.

Except for one problem.

Gas, by its nature, is difficult to transport and store. Pipelines can be used to take natural gas directly from the source to a point of usage but for greater distances and any storage time another solution is needed. That solution is liquefication. LNG takes up 600 times less of the volume of natural gas and as an added bonus is not explosive and cannot burn.

But liquefication is not a simple process. It requires taking the gas down to cryogenic levels of cooling over several stages. Commercial LNG is 90% methane with small amounts of ethane, propane and butane. Raw natural gas contains a number of other substances including carbon dioxide, hydrogen sulphide and water, all of which freeze at temperatures above which methane liquefies. Thus the cooling process requires several steps to allow removal of impurities at different levels of temperature. To achieve commercial LNG, natural gas flows down a line through the plant, stopping at different stations for each cooling step. Hence such a plant is known as a “train”.

Once liquefied, huge volumes of natural gas can be stored in cryogenic tanks or piped onto cryogenic tankers for export overseas. This is the upside. The downside is that the whole process of liquefying natural gas is itself an energy intensive one. The resultant fuel is thus a 20-40% greater net carbon emitter than its natural gas source. Nevertheless, LNG is still ultimately cleaner than either coal or oil.

The energy intensity of LNG production, along with the complex installation which is an LNG “train”, ensures there are significant costs involved in LNG export. Natural gas may be abundant and easy enough to get out of the ground, but from that point expenses build up. One might compare uranium, which is also relatively abundant and easily recovered, and also “clean” as an energy source, but a nuclear power plant is very expensive and takes over ten years to bring on-line.

Which – inevitably – leads us back once more to coal. Not only is coal abundant in the ground but burning it to drive a power station is a straightforward process. Coal is cheap on both counts. But coal is the dirtiest of all power sources. Oil is also dirty, and becoming scarce. Renewable energy sources such as solar and wind require a big jump in economies of scale to be commercially viable and cannot guarantee baseload power – a continuous, reliable power source for a city. Nuclear energy requires significant investment and comes with its own unique public policy problems.

Natural gas must also not be confused with “town gas”, which is gas created by burning coal or oil, or LPG, which is liquefied petroleum. Coal seam methane (CSM) is, however, a form of natural gas suitable for conversion into LNG. CSM was once considered a annoying waste product trapped in coal mines to be “flared” off into the atmosphere by burning. Natural gas trapped in oil wells was once similarly dealt with.

For more on CSM, see Classical Gas.

As the world continues down a path of recognising the need to reduce carbon emissions dramatically, even in the face of economic hardship, clearly LNG has a role to play. It is not for no good reason that the giant oil and gas companies across the globe have begun to shoulder each other aside to acquire or secure natural gas reserves.

Natural Gas Pricing

Over the longer term the price of natural gas has tended to follow the price of oil, as one might expect, but without a lot of the volatility. Natural gas has been more of a behind-the-scenes player, failing to fall as low as oil and failing to rise as high. However in the last couple of years that has changed given emerging appreciation of the capacity for natural gas to be a cleaner substitution for dwindling oil. And because the speculators have become involved.

It costs different amounts to produce LNG at different locations across the globe and then different costs are incurred by importing LNG from different locations. In other words, natural gas prices are not homogenous. Oil has the same disparities of price for the same reasons and for the different grades of oil (eg light and sweet, heavy and sour) that are found at different locations. Nevertheless, the world’s benchmark oil price is West Texas Intermediate crude and the benchmark for trade in WTI is the New York Mercantile Exchange futures contract price. It is a lot easier to trade oil on paper than it is to try to ship it back and forth in tankers.

Similarly the world’s benchmark natural gas price has its own Nymex futures contract, which reflects the Henry Hub price and is traded in millions of British thermal units, or MMBtu.

The price of oil is determined for futures contract settlement as the delivery price of WTI at to Cushing, Oklahoma. Natural gas futures are settled at the price determined as delivery to the Henry Hub in Erath, Louisiana – a point where nine US interstate gas pipelines and four intrastate pipelines intersect.

The following chart is a comparison of the oil (blue) and gas (red) futures prices over the last two years, and clearly indicates that gas has been swept along in the great speculative oil bubble and bust. (if you are reading this story on a third party distribution channel it is possible you won’t see any chart – our apologies for this).

Source: eSignal (www.esignal.com)

Yet it is only on the Atlantic side of the world that natural gas is traded enthusiastically in spot price terms. The Pacific side is all about long term contracts. Only 13% of global natural gas trade in 2007 was transacted at spot prices.

Australians have recently been watching with despair as the spot prices of iron ore and coal have tumbled in the economic crisis. Yet both only trade at spot prices to make up shortfalls when immediate supply is close to hand. The great proportion of both is traded on a one-year contract basis, rendering spot prices an overly volatile and non-specific indicator of real demand/supply fundamentals.  Each week two global uranium consultants publish a spot price, but again the amount of uranium changing hands globally at spot prices is minimal. The real producers and consumers of uranium trade on long term contracts of five or more years duration.

Hence in the above cases, fluctuations in contract prices tend to follow a much smoother path through the middle of volatile spot price graphs. When spot prices are too high, consumers back off. When they are too low, producers back off. Indeed, the “real” trade of many of the world’s hard commodities involves price-smoothing agreements between both sides that see producers giving up profits via discounts when prices are high and consumers providing more profits via equivalent premiums when prices are low. This is known as a “cap and floor” pricing system and ensures that neither demand nor supply is “destroyed” at either end of the scale.

In the Asia-Pacific region, 95% of natural gas is traded on long term contracts of 10-20 years duration. This makes LNG less “spot” than any of iron ore, coal or even uranium. What’s more, nearly all those contracts work on a “take or pay” basis. This means that if a buyer decides mid-contract it doesn’t need another shipment, the buyer still has to pay for it.

So when it comes to Australian LNG, the above Nymex natural gas futures chart is not a hard and fast indicator of pricing. Obviously spot prices are an indicator of economic conditions and presently those have become rather lousy across the globe, leading to much lower commodity prices. But for an Australian natural gas producer selling to Japan, for example, the difference will only be felt in new contracts, not in existing ones. Indeed, Australia sold only eight LNG cargoes at spot prices in 2007 and only one in 2006. It has sold none in 2008 to date. This leads Citigroup’s global analysts to declare Australian LNG as a “defensive play”.

Indeed Citigroup sees contract natural gas prices only falling at half the rate of oil prices.

Natural Gas in Australia

Town gas was used to power Australian city lights in the nineteenth century before the electric light bulb became fashionable, but when a crew were drilling for underground water in Roma, Queensland, in 1900, they inadvertently discovered natural gas. It is now legend that at the time the crew foreman was said to have uttered the immortal words, “Was that you?”.

Thrilled by the discovery, the town of Roma hooked up all its lights to the wonderful new source only to have them fade out ten days later when the source was depleted.

But they came back in 1969 and connected the old Roma power station to natural gas to thus establish the first commercial use in Australia. Sources quickly reached Brisbane, and Melbourne and Adelaide also hooked up to their own natural gas sources in 1969. Poor old Sydney, devoid of such riches, had to wait until 1976 for a pipeline to arrive. Nothing changes.

In the early 1970s, vast amounts of natural gas were discovered about 130km off the north west coast of Western Australia. North West Shelf Gas today remains Australia’s largest resource project. When Australia’s last truly socialist government came to power in 1972 it was the intention of the then Minister for Primary Industry, Rex Connor, to nationalise Australia’s now obviously vast natural resources for the benefit of all Australians. Part of the plan included gas pipelines across the length and breadth of the continent. Unfortunately Australia had neither the funds nor the credit rating to raise the more than a billion dollars required at the time (a sum so vast no Australian could truly contemplate it) so Connor turned to a Pakistani by the name of Khemlani – supposedly a well-connected broker in the fledgling merchant bank and money markets.

Khemlani turned out to be a crook and strung Connor along to the point of heart attack. Having lied to parliament about where he was sourcing the funds, Connor was forced to resign in disgrace and the Whitlam government was sacked shortly thereafter. To this day the North West Shelf is a private operation with US, British, Dutch, Japanese and Australian interests.

Australia has only limited oil reserves on a global scale but an abundance of natural gas. Unfortunately it’s all about as far away from the concentration of Australia’s population as it could be, being off the north-west coast of WA and north of Darwin the Timor Sea. However Australia’s gas is much cheaper to access than a similar abundance in the US for that very reason – it’s out in the middle of nowhere. There is very stiff resistance, for example, to building heavy carbon emitting LNG trains in the middle of populous areas of California. US gas is also priced off fluctuations at the Henry Hub, rendering it more expensive than the contract-based Australian deals.

Australia has built Rex’s pipelines, but it is the vast export markets of the nearby Asian region which offer burgeoning export potential for the Australian LNG market. The rush for cleaner, cheaper fuel sources has meant an explosion of new projects, and an explosion of interest from global oil and gas companies. Over the next decade, suggest the UBS global analysts, Australia is a key growing global LNG supplier set to match the natural gas powerhouses of Qatar and Nigeria.

The vast majority of Australia’s gas reserves lie offshore in a series of fields stretching offshore from the coast of north-west WA through to the Timor Sea off Darwin. This area provides the greatest export potential. It contains, among others, the significant developments projects of North West Shelf, Greater Gorgon, Pluto, Browse, Scarborough and Greater Sunrise.

On the other side of the country, central Queensland is the centre of CSM to LNG development which has sparked so much interest recently from international oil and gas players.

Closer to civilisation, the Gippsland, Otway and Bass basins located of the southern coast of Victoria are also areas of enthusiastic gas development for local supply, and the New South Wales coal fields also offer the potential for future CSM development.

Then there is Papua New Guinea. For a long time now Australian interests have been anticipating the development of the extensive PNG gas reserves to provide long awaited PNG LNG for the export market. In assessing Australia’s place in the global gas sector, analysts count PNG under the same umbrella. The PNG gas fields extend from the Gulf of Papua, north of Cape York, into the PNG mainland.

The original plan was to build a natural gas pipeline from PNG to the Australian mainland to meet existing LNG and port facilities but that project was finally shelved in February this year. Withe the help of interested international parties, the plan is to now make PNG LNG a stand-alone operation.

The Credit Crisis

As the global economy boomed up to 2007, LNG development projects were little affected by the cost or availability of financing. Credit was plentiful, and a skyrocketing oil price amid climate change concerns ensured natural gas was being enthusiastically endorsed.

However the boom also meant booming costs – for the equipment and energy required to drill for gas and build and operate LNG trains, and for the manpower (both professional and labour) required to run them. Nevertheless, with the oil price assumed to be heading for US$200/bbl various gas projects were been pursued even at the high end of the cost curve. These include African deepwater reserves and the infamous Canadian tar sands.

Now that the credit crisis has hit and transformed into a global economic crisis, the situation is much changed. Commodity prices have collapsed in one direction and credit costs have skyrocketed in the other. And while the cost of credit is one thing, the sheer availability of credit is now merely a dream for marginal, high risk projects.

The good news is that input costs have thus fallen, although so far the cost of labour and equipment remains high due to the number of global resource projects still under way for the time being. However on a net basis, Australia looks better placed than others in the world to continue pursuing and ultimately benefiting from LNG development.

Citi notes that while the credit crisis will render some global energy projects uncommercial, it should also bring about a rash of merger and acquisition activity as the energy market consolidates. The cashed-up majors are in a particularly good position. ExxonMobil has US$40bn in cash on its balance sheet and Shell has US$9bn. Companies with more pressing debt concerns have the option to sell-down asset exposures. We have already seen such activity in Australian CSM as BG, ConocoPhillips and Petronas have all moved in to secure lucrative deals with Australian gas companies.

Beyond credit markets and asset sales there exist specific export credit agencies, and while feeling a bit once bitten and twice shy at present, sovereign wealth funds are not an exhausted resource for equity. Simple equity raising is always an option, but as the market has sold down all listed resource stocks heavily – often reflecting discounts to asset values – it is not enticing to dilute capital bases at this level.

On the other side of the coin, those gas supplies lying further up the cost curve are now at risk of being shelved. At the highest end of cost is tar sands, and then we fall back through deepwater projects to CSM and more accessible projects. PNG LNG lies at the bottom end of the cost curve below CSM, while offshore projects lie either side of CSM. Already tar sands projects – which also have the largest carbon footprint for production – are being curtailed.

As global supply projects give way to high costs and low prices, the market is more open to those at the lower end of the cost curve. UBS nevertheless suggests that even Australia will suffer from project delays as financing becomes more restrained and the need to prove up reserves and secure sales contracts more pressing.

There will be some respite from the cost side in Australia. Citi suggests there is a growing case for downward cost pressure on the equipment, service and labour front given the fall in global commodity demand and the aforementioned likelihood of projects being shelved.

As the commodity market boomed, so too did the mining and drilling services market. Share prices of service companies soared along with those of commodity producers. Now that the game has changed, project developers will not be as beholden to service companies who were previously able to name their own prices. The boot will be on the other foot as service companies compete for access to a fewer number of projects. And the same goes for labour. The Western Australian unemployment rate had fallen as low as 2.6% given the state’s booming resource industry, but as the supply side slows down that number will begin to grow noticeably.

Given the new playing field, UBS determines that there are 13 credible LNG development proposals remaining downunder (down from 15 at the last assessment in April which was also prior to the explosion of interest in CSM). Eight of those projects are located in offshore WA-northern Australia, one in PNG, and the remaining four are Queensland CSM projects. The UBS analysts favour projects sponsored by leading companies with quality partners that have an established track record of delivering major LNG project developments.

The Players

The undisputed leader of the Australian LNG market is Woodside Petroleum ((WPL)), operator and one-sixth owner of the existing North West Shelf and owner of the next door Pluto project. Pluto is under development and has the capacity to become Australia’s second largest resource project. Woodside also lays claim to the Browse and Greater Sunrise projects which have longer term potential. All up, Citi estimates Woodside could increase its LNG production by 230% by 2011. The company brought its fifth North West Shelf LNG train on line earlier this year.

The Citi analysts recommend Woodside as a Buy for the longer term and note the current share price suggests zero premium for growth. The analysts were previously concerned with the company’s capacity to grow beyond 2011 given the current cost constraints but with no optionality in the share price for Pluto, that is not currently a concern. Citi suggests Woodside could be debt free by 2012.

UBS also has a Buy rating on Woodside and considers the stock one of two preferred picks in the LNG space. Despite Citi’s concerns, UBS notes Woodside has enough potential projects to keep in growing through 2018 if the circumstances allow.

The other UBS top pick is Oil Search ((OSH)), one of two owners of the PNG LNG project operated by Exxon. All analysts agree that PNG LNG will be a “company making” project for Oil Search. A final investment decision (FID) is expected on the project in the second half of 2009. Oil Search has a very good relationship with the PNG government, which itself retains an investment in the LNG project. The PNG government recently announced it would sell its stake in Oil Search stock to an Abu Dhabi government fund for what amounted to a price 40% above Oil Search’s trading price at the time.

As an explorer/developer rather than a producer, Oil Search is sitting ready to be fully taken over, although Citi suggests this is unlikely to happen before FID is achieved. Citi also rates Oil Search as a Buy.

Santos ((STO)) is the other partner in PNG LNG and is also 60% owner of the Gladstone CSM LNG project in Queensland. Santos surprised the market earlier this year when it sold 40% of the Gladstone project to Malaysian oil giant Petronas for a handsome sum. Both UBS and Citi have a Buy rating on Santos.

Citi suggests Santos is a likely takeover target as soon as government share register restrictions are lifted – not for the quality of its underlying oil business but for the leveraged LNG growth portfolio it is building. UBS does, however, see financing risk for Santos, particularly in developing the first ever CSM to LNG project. So far this is an unknown quantity.

Until February this year, Origin Energy ((ORG)), with its disparate collection of resource and utility interests in Queensland and elsewhere, was paid little heed by analysts. That is until British gas giant BG shocked the market with an out-of-the-blue takeover offer. The offer ultimately failed, but it suddenly put CSM and its potential on the global map.

Origin later signed a deal with ConocoPhillips for CSM development and BG was sent on its way, only to re-emerge and form a partnership with Queensland Gas ((QGC)) – the other Gladstone LNG player – instead. UBS thus describes Origin Energy as a crucial player which could draw upon its pioneering CSM knowledge and feed into either the QGC or Santos CSM projects.

UBS rates both Origin and QGC a Buy while Citi rates origin a Buy but does not cover QGC.

The FNArena database shows that on a 6-12 month horizon, five out of ten brokers rate Woodside a Buy. Oil Search scores a nine and Santos a seven. Origin scores a perfect ten while QGC rates three Buys out of three brokers.

Carbon Trading

The Australian government is due to release its draft legislation on emission reduction targets and industry penalties and exemptions this month.

LNG is in a difficult position. On a stand-alone basis, natural gas is a fossil fuel the burning of which generates greenhouse gases. The process of converting natural gas to LNG increases the carbon footprint of the industry. Thus on a stand-alone basis, the LNG industry is likely to require the purchase of carbon credits in order to meet emission reduction targets, thus adding to the cost of Australian LNG.

The renewable energy industry stands to be a major beneficiary of carbon trading, being the source of carbon credits granted for lack of emissions. Australia intends the system to encourage development away from traditional coal-burning power sources and onto cleaner, alternative sources. However LNG, too, is a cleaner power source than coal, and a cleaner transport fuel than oil. Taking that as a basis, the case can be argued that LNG should be generating carbon credits, not having to purchase them.

And indeed industry participants – particularly Woodside – have already been quite vocal on this anomaly. It is now down to the Australian government to weigh up the argument carefully.

On that note however, the Citi analysts note their modelling suggests a carbon trading scheme would make certain LNG projects sub-economic (such as Browse), it would not threaten the international competitiveness of the overall Australian LNG industry.

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