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Window on LNG: Australia’s Gas Age Is Upon Us

Feature Stories | May 28 2014

This story features SANTOS LIMITED, and other companies. For more info SHARE ANALYSIS: STO

– Woodside's dilemma
– PNG off and running
– East coast gas price increase
– Energy stocks evaluated
– Oil price risks

By Greg Peel

Woodside Petroleum ((WPL)) is an energy company with a dilemma. While dwarfed in market cap by Australia’s two big diversified mining and mining/energy companies, Rio Tinto and BHP Billiton, Woodside is still Australia’s largest standalone energy producer by some measure and over the past year has been forced to make a similar decision to those of its heavyweight resource sector peers – growth for growth’s sake is not a sensible strategy in a world of slower economic growth.

But while this decision for BHP and Rio has meant shelving some of the companies’ more grandiose plans, both are still pursuing existing growth projects in iron ore and other commodities, including shale gas for BHP. For Woodside, the decision to be selective with regard to growth options has now left the company with a development portfolio consisting of just one single growth asset – the Browse floating LNG project.

Like the miners, Woodside generates significant free cash flow through its existing operations, being its one-sixth share in the five-train North West Shelf facility (first gas produced 1989) and leading share in the one-train Pluto facility (2012), both in Western Australia. Like the miners, Woodside has been able to improve the value proposition for shareholders in redirecting earnings no longer to be used for growth investment into capital management. This has left the stock with a current dividend yield more akin to a bank than a resource company, but without a suite of growth options, the sustainability of that yield comes into question over the longer term.

This month Woodside was forced to make the frustrating decision to reduce its suite from two to one. For eighteen months the company had been negotiating a joint venture partnership to develop the Leviathan project in Israel, which offers the potential for both LNG and pipeline export. What initially appeared to be a potentially valuable investment slowly lost its appeal over time as the Israeli government vacillated and continually moved the goal posts. Not only did the prospective internal rate of return on Woodside’s investment drop below what analysts considered viable, the recent deadline on taking the deal beyond the level of memorandum of understanding with the Israelis passed without a murmur.

So management cut and ran. Analysts breathed a sigh of relief. The market prematurely sold off Woodside on the news until it realised the withdrawal meant all those funds the company had on hold for Leviathan would have to be directed elsewhere. Given there was no “elsewhere”, the strong possibility was that Woodside would hand it back to shareholders, on top of what they were already enjoying. The shares quickly rallied.

In the wake of the Leviathan withdrawal, Woodside last week held an investor briefing – its first in two years. All analysts attending the briefing walked away with a common conclusion. They had just sat through a presentation from a value-focused, experienced and pragmatic management team which is determined not to chase growth for growth’s sake and is highly disciplined in its investment strategy. Leviathan underscored this discipline.

Of course, having lost Leviathan as an option, Woodside could always pursue some M&A option to maintain its growth suite. Some media reports had the company making a play for smaller peer Oil Search ((OSH)) but brokers quickly dismissed this as fanciful. Management has by no means dismissed the M&A option, and indeed would no doubt dearly love if one were to fall conveniently from the sky, but a prospective internal rate of return of at least 15% would be required for the company even to be interested. Such is management’s self-imposed discipline. And the skies are very clear.

That leaves Browse FLNG. Here, too, management has proved itself disciplined in electing to farm-out stakes of its investment to reduce risk and in abandoning the original plan to build an onshore LNG facility. Not only was the WA government concerned about strong environmental protest, analysts deemed the onshore option as too expensive. FLNG is newish technology and thus riskier, but offers greater value. While Woodside is looking towards reaching a final investment decision (FID) on Browse (based on a three train proposal) next year, first gas is realistically achievable no earlier than next decade.

There’s also exploration, which Woodside continues to pursue. But exploration is what it is – despite expertise and technology, a lucky dip. And a very long term pursuit.

As impressed as FNArena database brokers were by the Woodside briefing, two elected to downgrade their recommendations thereafter. The market, salivating over immediate yield potential, has pushed the Woodside share price to above the consensus database price target, which is based on a wider balance of yield versus growth, or lack thereof. While the database now shows four Hold, three Sell and no Buy (or equivalent) ratings, brokers generally agree the stock offers little in the way of downside risk given the capital management potential which underpins market sentiment.
 


 

For the aforementioned Oil Search, life is very different. In what might be a case of “They said you’d never make it,” it was over a decade ago the explorer/developer first set its sights on the prospects of significant gas in Papua New Guinea. Building a large-scale LNG export facility in the wilds of PNG was always going to be an ambitious dream, particularly throughout the ups and downs of oil price volatility and global financial crashes in the interim. There were many sceptics, but now even the most optimistic of analysts has been forced to admit to being flabbergasted. PNG LNG has already produced its first gas.

Not only has this milestone been achieved well ahead of earlier timeline expectations, it has beaten the most recent of assumptions by four months. What’s more, LNG from the second train is expected in only a few weeks. “First gas” is not official yet, but this is expected to be ticked off in coming weeks when the first revenue-generating cargoes are shipped. At this rate, suggests Bell Potter, peak two-train production could be reached by the December quarter, if not before, meaning the project could go “non-recourse” to the joint venture partners by year-end.

This would mean cash generated from early sales and held in escrow by the banks can be released. Oil Search has to date targeted late in the March quarter 2015 for this to occur. Once the partners have the cash at their disposal, the next step for Oil Search is to consider exactly when, and to what extent, shareholders will begin to share in the spoils.

Santos ((STO)) is also a JV partner in PNG LNG, albeit junior to Oil Search. Santos’ major LNG project, of which it is leading partner, is the Gladstone project in Queensland (GLNG). First gas is expected from GLNG in 2015, on the tails of both PNG LNG and BG Group’s Queensland Curtis LNG project, which is also targeting first gas this year. Joining GLNG in the “2015 club” are Origin Energy’s ((ORG)) Asia Pacific LNG project in Queensland and Chevron’s Gorgon project in WA.
 


 

No doubt the achievement of first production in PNG will inspire confidence the Queensland-based projects can also stick to their targeted timelines. Recent updates suggest projects are on (revised) schedule and on budget despite all suffering from earlier delays and cost blow-outs at some point throughout their construction. Morgan Stanley’s research indicates the chance of material capex overruns diminishes in the last 12-18 months of an LNG project’s ramp-up phase.

The problem now for Queensland LNG, however, is gas. It’s one thing to successfully complete the long and costly process of building an LNG export facility, but it’s another to feed it, and recent suggestions are that sufficient local supplies may prove difficult to secure. Not helping the energy companies’ cause is strong public protest against coal seams gas (CSG) exploration and development in agricultural/urban areas which is forcing politicians to tread carefully and limit exploration access.

The loser in the lack-of-gas takes will not be the LNG producers, nevertheless. It will be the consumer. Santos, for example, can source gas from its own legacy Cooper Basin operations to feed GLNG and, if needs be, rival projects. Such supply would be redirected away from domestic east coast consumption which, when taken to its conclusion, implies households in Sydney will be forced to pay whatever the Chinese are prepared to pay for their own energy security.

Australia is almost the only energy producing nation in the world that does not quarantine some proportion of production for domestic use at government-controlled pricing.

This puts Santos in a position to benefit, in effect, twice from its gas production – once through LNG exports at healthy prices and again through hefty prices rises for domestic sales. Gas price rises will also have an impact on electricity prices.

In the US, natural gas has become so plentiful (through advancements in shale gas recovery) and prices so comparatively cheap that power companies can choose to switch away from coal-fired electricity generation and onto gas-fired generation at will, based on pricing. And in so doing also satisfy increasing “green” obligations. US gas will remain cheap because despite the first US LNG export facilities having been approved for development, energy in the US will always be heavily quarantined via strict export limitation.

For a long time Australians have been keen to switch from electricity to gas for heating and cooking given the relative cost, but as prices rise, that relationship has diminished. On projection, it will soon be a lot more expensive to choose gas, but then it will also be a lot more expensive for electricity utilities to choose gas for electricity generation. That is, unless utilities stick with coal-fired generation, from which they have been trying to move away (although the political landscape has become uncertain re carbon pricing).

Whatever the outcome, Citi suggests Origin Energy will be a winner. With a foot in both the upstream (production) and downstream (distribution) camps, Origin will be in the position to send its gas to whichever end-user is prepared to pay most at any given time – the gas-fired electricity generators or the domestic gas consumers.

Either way, Citi sees the LNG producers falling short of sufficient CSG, which means gas being directed away from any form of domestic consumption (electricity or gas) and onto export. That’s where Origin’s APLNG export facility kicks in.

Aforementioned tight government control over US energy supplies means that while one day the US may threaten to undermine a booming Australian gas export industry through competition, that day is some time off, and not that great a concern given growing demand from Australia’s Asian neighbours. And the US does not have a monopoly on shale. (See: Can Australia Sell Its Gas At A Reasonable Price?)

Goldman Sachs estimates the amount of oil/gas production added from the development of new shale extraction technology since 2008 is more than two times that added by old-fashioned exploration of the past 15 years. The US is the epicentre of shale “fracking” and lateral drilling development, but not the only global source of shale. Indeed, shale is abundant across the globe, found in multiple locations including Australia, and even jewel-in-the-crown gas export customer China. Indeed, China is now developing its first shale gas project, the aptly named Fuling.

The days of the geological breakthroughs that opened up US shale resources seemingly overnight are now behind us, Goldman suggests, such that ongoing technological improvements and resource-life enhancing developments are now more incremental. The dominance of shale has pushed higher cost energy options into irrelevance, although shale production itself is more costly than conventional and even deepwater production, sitting at around US$80-85/bbl Brent equivalent on the cost curve (current Brent spot US$110/bbl). But given new conventional sources have become very thin on the ground (and underwater), Goldman sees only shale and “ultra-deepwater” as providing ongoing double-digit production growth.

South Australia’s Cooper Basin is one of few locations still offering up fresh conventional reserves as well as a new boom in unconventional (shale) development, despite previous assumptions production from the Basin would sooner rather than later decline to a natural death. Gas was first discovered in the Cooper in 1963 by South Australia Northern Territory Oil Search (think of is as an acronym). But it’s amazing what new markets, new technologies and the promise of healthy profits can inspire.

The Cooper Basin remains Australia’s premier onshore hydrocarbon province, Macquarie notes, with expenditure now having passed the A$13bn mark. With another A$3-5bn expected to be spent on infrastructure and development drilling over the next 10 years, on top of exploration (both conventional and unconventional), the Cooper still has a long future ahead of it, Macquarie suggests. And it’s all due to the promise of higher east coast gas prices.

While Santos may have been first to develop the Cooper, independent producers exploring in the Basin’s Western Flank have discovered four times the level of oil reserves as has Santos in the past four years. Cooper crude production is back to levels not seen since the 1990s and Australian mid-cap energy companies have quickly found themselves among the country’s largest onshore producers. The Cooper is also the country’s most active unconventional gas province.

Indeed, Santos has become the laggard in the region, Macquarie notes, missing out on the Western Flank and returning mixed unconventional drilling results to date. For Santos, upside lies in price increases (notwithstanding the company’s LNG interests elsewhere) and the advantage of its legacy operatorship of the original Moomba facility.

Origin Energy is connected to the Cooper via its transaction with Senex Energy ((SXY)), providing Origin with greater upstream resources and the potential to build its forward gas book. Senex itself does not offer as strong a growth profile as mid-cap peers but does boast a large acreage and a steady ramp-up in production. Drillsearch Energy ((DLS)) trades at a premium that requires success from up to 19 conventional wells anticipated over the next 12 months.

Beach Energy ((BPT)) offers the broadest exposure to Cooper development, Macquarie suggests, with interests in the Santos-operated gas infill program, the Western Flank and the vast Nappamerri Trough unconventional project.

Australia’s listed mid-cap energy sector, operating either in or outside Australia or both, still offers value on average, Macquarie suggests, despite recent outperformance. Many stocks no longer offer the same value they did six months ago but Macquarie calculates an average 50% discount to net asset value on current trading prices. For those with oil exposure, working backwards suggests the sector is discounting an oil price of only US$67/bbl compared to the broker’s long-run Brent price forecast of US$107/bbl.

Many stocks in the sector offer value, Macquarie suggests, but the broker’s preferred exposures are AWE ((AWE)), Horizon Oil ((HZN)) and Senex Energy.

Critical to the success of Australia’s energy sector is the oil price. Relevance flows through to the LNG space given long term gas offtake agreements are priced on an indexation basis to the oil price.

After several years of wild volatility, oil prices have traded in a relatively narrow margin for the past three years. Since the start of 2011, notes Deutsche Bank, Brent crude has traded in the US$100-120/bbl range 85% of the time. This stability likely reflects several counterbalancing forces, Deutsche suggests.

On the one hand, US shale oil production has grown rapidly but on the other, there has been a significant increase in OPEC supply disruptions. On the one hand, an improving US economy has served to increase North American demand while on the other, demand has declined in a slower Chinese economy.

There is downside risk to prices from the supply-side, dependent on certain developments. Iranian exports continue to be constrained as negotiations with the West over Iran’s nuclear program drag on. In theory the new Iranian prime minister is more open to curbing the country’s nuclear ambitions in order to alleviate the economic deadweight of lost petrodollars, and were Iranian supply to be freed up once more, there’d be a lot more oil back on the market. Ditto Libya, where supply has been constantly hampered by export terminal blockades by disgruntled workers. Just when it looks like Libyan oil might hit the oceans again it doesn’t, but the day may one day come.

On the other hand, Nigeria has always suffered its share of supply setbacks through oil theft and pipeline sabotage, but the growing menace that is Boko Haram suggests the potential for much greater disruption. Supply disruptions have also now developed in Sudan and Venezuela, and then there’s the Ukraine/Russia situation, the outcome of which it is impossible to predict.

Oil prices have already built in somewhat of a Ukraine risk premium, but a near-term resolution to tensions between Russia and the West looks unlikely, suggests Citi. The two sides are locked into a relationship of what Citi calls Mutually Assured Destitution given Russia’s unmatched energy superpower status. Russia exports as much oil as Saudi Arabia and 50% more gas than Qatar, and if coal is included, Russia's total energy exports are equivalent to number two energy exporter Saudi Arabia and number three Qatar combined.

Which is why sanctions imposed by the West to date have been more symbolic than effective, and while Europe is reluctant to upset its premier energy supplier. Meanwhile, Russia has not yet invaded Ukraine and seems unlikely to do so given the West may yet be forced to impose energy export sanctions, in which case Russia’s economy would nose-dive.

The situation is no less MAD than the decades-long Cold War.

Technical limitations

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