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Address to APPEA Conference, Perth

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Thank you for the invitation to again address APPEA.

I acknowledge the welcome to country by Dr Richard Walley OAM, and I pay my respects to the traditional custodians of the land on which we meet, the Noongar People, and to their elders past and present.

I want to acknowledge two individuals, in particular, for their contributions to this industry.

Martin Ferguson, my predecessor as the Minister for Resources and Energy, and Ann Pickard, the former head of Shell Australia.

Martin and Ann have moved on to other endeavours, yet their decisions as industry leaders will be felt for many years to come.

Ann’s decision - to facilitate development of floating LNG-FLNG in Australia - now raises an important opportunity for this country.

I want you all to imagine in the none-to-distant future a world where revenue to the Commonwealth and to the States of Australia from LNG production is greater than the revenue from iron ore or coal mining.

Already LNG has surpassed coal.

LNG revenue will fund roads, schools, hospitals and pensions - building our nation, monetising current resources for future generations.

To achieve this we need a step change in LNG productivity.

Floating LNG production is that step change and it has been gifted to Australia to pioneer.

But like all opportunities, its genesis is in the challenges of the industry.

That is the nature of innovation.

And today, I am going to talk about a critical challenge for Australia’s LNG industry: dealing with downward pressure on LNG prices.

The dynamic of world oil and gas has always been volatile, powered by geopolitics, global economics, technology, and, of course, the weather.

In our generation, the Middle East has dominated this dynamic, primarily because of the reliance on Middle East oil by the United States, the world’s biggest economy.

It wasn’t until the 1970s that the North Americans attached an intrinsic value to gas.[i]

This was long after North Africa had begun exporting LNG to Europe in the 1960s[ii] and after Japan began importing LNG in 1969.[iii]

For 50 years, the world LNG trade has been relatively stable with prices set by reference to oil and through long-term contracts supporting long-term investments.

It has meant countries with lots of gas have sold it to countries with not much at all, and the price has been based on what the buying country would have to pay should it have opted for oil.

This has worked well for buyer and seller and risks have been shared.

Countries with few fossil fuel resources, such as Japan, have diversified their energy supply risk so they are not too reliant on any one fuel or any one source of energy.

But times are changing.

The LNG industry - and that means Australia and our now-significant role in it - is facing new risks that threaten the historically comfortable buyer-seller relationship.

It means Australia needs to spread its own risk as a world-leading supplier, or face the real possibility of having our vast but remote gas resources stranded.

Price has become a more nagging issue, particularly for LNG importing countries in our region: Japan and Korea in particular; the world’s largest buyers of LNG.

Price is also a first-order issue in India, the most important emerging market.

In late 2013, these countries called on sellers to reduce LNG prices and the premium they had to pay against gas prices in North America and Europe.[iv]

Asian buyers have increasingly called for an end to the linkage of LNG prices to oil, and for more gas to be sold at US domestic-plus - or Henry Hub-plus - prices.

In some cases, they have succeeded with producers such as BP, Cheniere, BG Group, and Sempra among those who have linked LNG contract prices to Henry Hub over the past couple of years.[v]

While a few gas contracts do not make a sea-change, the public debate about LNG prices in a business that has been historically muted, polite, and comfortably stable, suggests - as one reporter put it - that some kind of genie has escaped its bottle.[vi]

Others suggest as much also, with Ernst and Young believing that persistently high oil prices and a growing surplus of gas are creating a situation where LNG prices may not always be tied to oil prices.[vii]

Other genies are escaping bottles elsewhere in the world that will put downward pressure on LNG prices.

Let me give you a few examples.

Late last year, the Mexican Government turned back 75 years of resource nationalism to allow private companies to once again explore for oil and gas in Mexico.

This may not seem significant to us, but this most dramatic reform was needed to rescue Mexico’s hydrocarbon industry, which today is said to need many billions a year, to stop the decline in its domestic production.[viii]

Foreign firms now are now lining up to tap Mexico’s hydrocarbons and they will succeed in great geology and with the best technology.

This will most likely result in more oil and gas being available in the North American market.

North of the border, the United States is on the verge of becoming a net exporter of energy for the first time since the 1940s, solely on the back of technological advances that have allowed explorers and producers to extract oil and gas from shales.[ix]

Texas, for example, is expected to produce more than three million barrels of oil a day this year, moving it ahead of Kuwait and Mexico to be the world’s ninth-largest oil producer.[x]

The US shale boom is unprecedented and bigger than even the oil booms of the 1900s and 1930s that made Texas the world’s largest oil producer of the day.[xi]

Moving further north, Canada - the largest supplier of hydrocarbons in North America - is responding to the rise in US domestic oil and gas production by seeking alternative markets and has turned its attention to exporting its large gas resource as LNG.[xii]

Canada is considering 13 LNG export proposals and North America as a whole has more than 40 proposals totalling about 250 million tonnes a year on the books.[xiii]

While nobody expects all of these to come off, they alone account for more than all of world LNG exports in 2013.[xiv]

Let’s move south.

In South America, the newly widened Panama Canal will open in 2015, and will be able to provide passage for an estimated 12 million tonnes of LNG a year, a thought nobody had when planning the canal upgrade six years ago.

This tonnage would equal about 5% of world LNG trade, based on 2012 figures, and estimates suggest the shorter route would reduce by a quarter the cost of shipping LNG from the US to Asia.

With the US predicted to become the world’s third largest LNG exporter by 2020 behind Australia and Qatar[xv], some industry analysts predict its entry to the LNG supply market could cut marginal costs for new LNG contracts by as much as 25% over the next decade.[xvi]

These are ominous challenges to Australian LNG pricing.

Another reality facing the super majors - Exxon, Shell, BP, Chevron and Total - the companies that have capacity to invest in LNG projects, is the growing demand from their investors to constrain capital spending and focus on projects with the highest returns.[xvii]

Over the past couple of years, some have been investing more than they earn and have had to sell assets or borrow to cover their capital and shareholder dividend demands, or they have had to jettison projects with poor returns.

Around the world, capital costs for LNG projects since the early 2000s have risen everywhere except the Middle East, with the increases greatest in our part of the world, the Pacific Basin.

Indeed, we could build an onshore plant a decade ago for about US$225 a tonne of annual production.

Over the next five years, analysts predict it will cost us up to US$2000, or more, a tonne.[xviii]

I cannot recall the last LNG project that came in on the budget that its proponent first published and all of Australia’s onshore greenfield LNG projects in recent years have cost more than first forecast.

In the new world of the super major mantra of ‘value over volume’, investors are wary of LNG projects that may not bring the returns they promised.[xix]

Equally, expansions that were suggested in the early days of project development - such as Gorgon here in Western Australia and Queensland Curtis LNG - appear increasingly unlikely as both projects wrestle with costs, productivity and price wary markets.

Add to that the difficulty of some projects - particularly in Queensland, New South Wales and Victoria - in dealing with regulation inspired by activist groups, actually getting gas out of the ground quickly enough is proving a challenge and discouraging further investment.

Activism is adding another layer of risk to land-based LNG projects to such an extent that I sometimes wonder whether our political system can find a spot on the coast of Australia’s largest state that the activists would find suitable for another LNG project.

For all of these reasons - Asian agitation for a better deal on price; developments in the Americas to produce more gas and move it more cheaply, capital constraints on big LNG investors, and regulatory pressure on land-based projects - lead me to conclude that Australia needs to mitigate these risks by being innovative in continuing to supply LNG.

So I re-state my long-held position that we need to embrace floating LNG and the innovation that comes with our maritime engineering excellence, just as we embraced floating oil production in the Timor Sea in the 1980s.

I lived in Darwin in the 1980s, and like me, some of you may remember that BHP Petroleum pioneered floating production, storage and offloading technology with the Jabiru Venture in the Timor Sea in 1986,[xx] a decade after Shell first used the technique in Spain.[xxi]

Jabiru tapped an oil field that otherwise would not have been developed and led to the development of many more remote oil fields off Australia’s north-west and gave birth to a vibrant on-shore service industry for these vessels from Perth to Darwin.

Today, more than 200 of these vessels are deployed worldwide.[xxii]

Shell’s Prelude LNG Project off Western Australia - the world’s largest floating platform[xxiii] - provides Australia with a golden opportunity to use innovation to drive productivity so we can continue to compete for market share.

Floating LNG could be cheaper to build than conventional plants and it could get built up to a year faster than its conventional cousins.[xxiv]

Cheaper to build, faster to market; FLNG obviates the need for costly and lengthy pipelines, the construction and eventual decommissioning of on-shore plant and associated harbour facilities.

FLNG can be built in low-cost shipyards, and can be moved and possibly used time and again.

It can be suitable for remote, smaller gas fields that otherwise would not be developed, and has a much smaller environmental footprint than onshore development.

While floating LNG will not be the right solution in all cases, it has an important role in developing Australia’s gas resources right now.

We face the realistic choice of production with floating technology, or not at all.

And, as can be seen by the Prelude example, it comes with far less regulatory risk.

By way of illustration, compare any of the Queensland onshore LNG projects that have many thousands of conditions as part of their approval[xxv] with the 13 that were attached to Prelude.[xxvi]

We must not forget that Australia has a competitive advantage in environmental regulation - something that has been strengthened even further in the offshore petroleum sector.

At last year’s APPEA conference, I was delighted as the then Federal Minister for Resources and Energy to announce that I had reached agreement with then Environment Minister Tony Burke and his Secretary Paul Grimes, and Blair Comley, the Secretary of my Department, that the National Offshore Petroleum Safety and Environmental Management Authority would become the sole regulatory body for offshore oil and gas exploration.

I thank Blair and Paul but especially Jane Cutler at NOPSEMA; Jane was the driving force for this change. Jane is the third significant contributor of this past year that I would like to thank.

A year ago, NOPSEMA had been operating for 18 months, and had proved to be a competent and diligent regulator that engages internationally to draw on and develop the world's best practice.

I am now pleased that my successor, Ian Macfarlane, has completed these changes. They will streamline regulation and reduce duplication between the Offshore Petroleum and Greenhouse Gas Storage Act and the Environment Protection and Biodiversity Conservation Act.

I offer my support to extend this now to the near shore environment.

With bipartisan support, the Federal Parliament has improved regulatory frameworks and ensured that we can have a policy regime that supports investment decisions.

While floating LNG has capital cost advantages, particularly over remote, onshore projects, I accept that some have doubts about its operating cost.

However, oil and gas companies are superb managers of operating expenditure.

Indeed, operating cost drives innovation and productivity in the oil and gas industry and I know from my experience as a former oil and gas executive that focus on cost must be unrelenting and is the defining skill for successful managers in this sector.

Here in West Australia much has been made of jobs that are foregone to other countries in the relatively short five-year offshore construction phase of floating LNG.[xxvii]

But too little is made of the investment in creating jobs and skills in the relatively long, 25-year-plus operating phase.

It begs the obvious question: who would prefer the boom-bust uncertainty of a five-year job over the steady-state certainty of a 25-year job?

Shell will face many challenges over Prelude’s 25-year production phase in servicing this mammoth facility, safely moving people and equipment, training and feeding workers, and maintaining plant and production.[xxviii]

Prelude will involve capital investment of about US$12 billion and is a sizeable chunk of the estimated US$64 billion that analysts expect to be invested in floating LNG over the next six years.[xxix]

This is tremendously exciting because it puts Australia in a leading position to make the most of this new technology even though our competition has already arrived.

Several other floating LNG projects are already in development, including two in Malaysia, one of which is scheduled to begin production in 2015, two years before Prelude.[xxx]

In Israel, Indonesia, Brazil, Canada, Mozambique and the US, engineering is at various stages on 16 floating LNG projects,[xxxi] and nearly every briefing I get from gas companies has reference to the technology as a development option.

Just as energy-poor markets such as Japan, Korea, Taiwan and China have diversified their energy mix and the source of supply within each sector of that mix, so must we as producers diversify even further our mix of gas production technologies.

It would be a mistake, in my view, to obstinately prosecute the case for on-shore LNG production while the prospect of any new, onshore LNG project in Australia looks increasingly remote.

Floating LNG production is a step change that has been gifted to Australia to pioneer at scale.

This industry has showed time and again its capacity - indeed brilliance - to engineer and operate the most wonderfully complex technology to keep us warm, keep us cool, keep us fed and keep the lights on.

Floating LNG is another opportunity for us - Australian industrial designers, scientists, operators, mechanics, petroleum engineers, clerks and marine engineers - to shine.

Those companies that have an LNG future need to move fast, to seize the moment, to embrace the future.

We would be foolish not to embrace the future, if we do not, the future will not be kind to Australia.

Our industry has benefitted from the work of great champions, I’ve named some today - there are many more.

But I commit that I will work with Ian MacFarlane to deliver the best possible regulatory environment to allow for the speedy approval of the next generation of FLNG projects.

We need these projects - they are our energy bridge to the future. They will underpin our envied position as an energy super power. Strong in coal. Strong in uranium. Dominant in LNG.

Thank you.




[i] ‘The role of LNG in North American natural gas supply and demand’, Centre for Energy Economics, September 2004 - d_Final.pdf [ii]

Gas in Focus, ~2009; [iii] A History of Japanese Trade and Industry Policy, by Mikio Sumiya, Oxford University Press, 2004 [iv]

‘Japan and India call for end to unfair ‘Asian premium’ on LNG prices’, Economy Watch, 11 September 2013 - [v] Oil and Gas Reality Check 2013 - A look at the top issues facing the oil and gas sector -; ‘Toho lands Henry Hub-linked LNG deal’, Energy News Bulletin, 31 January 2014 -;; [vi]

‘No such thing as cheap, long-term gas - Woodside’, Gas Tech News, 25 October 2013 - [vii] ‘Global LNG: Will new demand and new supply mean new pricing?’, Ernst and Young, 2013 -$FILE/Global_LNG_New_p ricing_ahead_DW0240.pdf [viii]

CBS News, 12 December 2013 - [ix] ‘US was net oil exporter for first time since 1949’, Bloomberg, 1 Mar 2012 - [x]

Top 10 largest oil producers in the world, 2014’ - [xi] ‘Oil! Texans gushing over new riches’, USA Today, 16 January 2014 - [xii] [xiii] ‘North American Natural Gas Seeks Markets Overseas’, National Geographic Daily News, 20 March 2014 - [xiv]

Average project capex by basin, 2000-2019, World LNG Report - 2013 Edition, pp 8, 22 International Gas Union -; Global LNG Market Overview, March 2014, BG Group - [xv]

‘Panama Canal’s LNG surprise to redefine trade in fuel: freight’ - Bloomberg, 5 November 2013 - [xvi]

‘US LNG Exports: Impacts on Energy Markets and the Economy’, pp 66, ICF International, 15 May 2013 - [xvii] ‘Oil majors trapped in cycle of spending more but finding less’, Financial Times, 11 August 2013 - [xviii]

Average project capex by basin, 2000-2019, World LNG Report - 2013 Edition, International Gas Union, pp 20 -; ‘LNG Plant Cost Escalation’, Brian Songhurst, February 2014, Oxford Institute for Energy Studies -; ‘Corpus Christi Liquefaction, LLC - competitive with other recent liquefaction projects’, October 2013, Cheniere Energy - 3D1&ei=EFwtU-7OKI3trQfytoGoDQ&usg=AFQjCNHW02kILRPFCydDRGTzaXXkS6S8rQ [xix]

‘BP ups asset sales, dividend as big oil Q3 kicks off’, Reuters, 29 October 2013 -

[xx] ‘PTTP moving to complete Jabiru, Challis abandonments’, Oil and Gas Journal, 3 November 2011 - [xxi]

‘A floating production, storage and offloading vessel: History’ - [xxii] Ibid.

[xxiii] ‘Floating liquefied natural gas’, Shell - [xxiv] ‘FLNG technology shows promise for stranded gas fields’, Offshore, 11 January 2009 - [xxv]

Approvals: Queensland Curtis LNG Project, Queensland (EPBC 2008/4398, 4399, 4401, 4402, 4405; 22 October 2010); Australia Pacific LNG Project, Queensland (EPBC 2009/4974, 4976, 4977; 21 February 2011) - [xxvi]

Approval: Prelude Floating Liquefied Natural Gas Facility, Browse Basin, offshore Western Australia (EPBC 2008/4146), 12 November 2010 - [xxvii]

‘Prelude FLNG - an overview’, [xxviii] ‘1000 FLNG jobs in Australia through Shell’, iMinco - [xxix]

‘Floating LNG market poised for increased investment and activity’, World LNG Market Forecast 2014-2020, Douglas-Westwood - [xxx]

‘New opportunities for floating LNG production’,, 24 January 2014 -; ‘Petronas decides on FLNG2 project’, OE Press, 13 February 2014 - [xxxi]

‘LNG: Will it float?’, MZine, MJM Energy, November 2013 -; World LNG Report - 2013 Edition, International Gas Union, pp 19 -; Shell, pers. comm, 20 March 2014