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Executives

Robert Peter Wilson - Non Executive Chairman, Chairman of Nominations Committee, Chairman of Chairmans Committee, Chairman of Finance Committee, Member of Remuneration Committee and Member of Sustainability Committee

Frank J. Chapman - Chief Executive, Executive Director, Chairman of Exploration & Appraisal Committee, Chairman of Group Executive Committee, Member of Chairmans Committee, Member of Portfolio Development Committee, Member of Sustainability Committee, Member of Finance Committee and Member of Investment Committee

Fabio De Oliveira Barbosa - Chief Financial Officer, Executive Director, Member of Group Executive Committee, Member of Chairmans Committee and Member of Finance Committee

Martin Houston - Chief Operating Officer, Head of Liquefied Natural Gas Unit, Executive Vice President - Atlantic Europe and Mediterranean Basin, Managing Director of Americas & Global Lng, Executive Director, Member of Group Executive Committee, Member of Group Performance Committee and Member of Sustainability Committee

Chris Lloyd - Head of Investor Relations

Analysts

Irene Himona - Societe Generale Cross Asset Research

Jason Gammel - Macquarie Research

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Jon Rigby - UBS Investment Bank, Research Division

Brendan Warn - Jefferies & Company, Inc., Research Division

Gordon M. Gray - Collins Stewart plc, Research Division

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

Lucy Haskins - Barclays Capital, Research Division

Michael J. Alsford - Citigroup Inc, Research Division

Unknown Analyst

Martijn Rats - Morgan Stanley, Research Division

Anish Kapadia - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Colin Smith

Hootan Yazhari - BofA Merrill Lynch, Research Division

Paul G. Spedding - HSBC, Research Division

BG Group plc (OTCQX:BRGYY) Q4 2011 Earnings Call February 9, 2012 9:00 AM ET

Robert Peter Wilson

Ladies and gentlemen, good afternoon. I'm Robert Wilson, Chairman of BG. It's very good to see you here again for our 2012 Strategy Presentation. I'd just like to say 1 or 2 things before getting the presentations underway.

The presentation this year is a little bit different from the format you've seen in previous years. There's not going to be a lot of time going over the 2012 results -- 2011 results, 2012 will be a bit optimistic. And we're not going to spend a lot of time on 2011 results, because you've already spent quite a lot of time on this, I know. And I'm not intending by that incidentally to preclude questions in the Q&A session on 2011 results. But we do want to spend a little bit more time on discussing the strategy update.

There's 1 particular aspect, which is going to be a little bit different, too, in that because over the years, we've noticed that our LNG business, which you all know has actually given us some astonishingly good results, but there has been, and there still is an element of the investor community, which rather dismisses these results as low-quality, short-term earnings, a sort of one-off break. I think by now that it's clear that we have a much solider business than that, and one that we can look forward to the future with great optimism. And what you're going to hear is actually a little bit of further explanation, more information about the LNG business, which will enable you to build models on the future profitability of this business rather than the systematic short-term indications of profitability, which we've relied on in the past. As it happens, I know that some of you have already developed models that are very close to the reality. So it's not going to come as a big surprise to some of you. So that is one thing, though, that is going to be a little bit different about the presentation this year.

I should say, too, that after 8.5 years, I'm just about to stand down as Chairman of BG. It's been a hugely exhilarating period for me. I must say I thoroughly enjoyed it. And I've been very lucky, too, in having a highly successful Chief Executive to work with throughout that period. I can tell you, it's a lot easier being a Chairman if you've got a successful CEO than if you've got a business that's struggling.

So I'm now pleased to be able to hand on my role to Andrew Gould, who is known of, if not known to, all of you in his capacity as -- or his past capacity as Chairman and Chief Executive of Schlumberger. Schlumberger is a great company, the most successful company in the oil field services sector. Andrew's knowledge of this industry is profound. And very interestingly, and I think very valuably, his seeing the industry from a slightly different perspective than the traditional IOC managers and leadership would've done, I think that's going to be a great help to us, as will Andrew's very strong connections with the national oil companies because, of course, he's been a service supplier to them rather than a sort of a rival.

I'd like to ask Andrew just to come up so that those of you that haven't seen or met him before at least get a chance to recognize him. And this is the man. If anything goes wrong in the future, it'll be Andrew or Frank.

And with that, I'd like to hand the meeting over to Frank to get started. Thank you.

Frank J. Chapman

Well, Bob, I'd like to also say thank you to you enormously. You've been a tremendous support and a terrific mentor, guiding us with your vast experience of international extractive industries. It has been a huge pleasure to work with you, and I look forward, of course, to the transition to Andrew and this new knowledge and skills that he will bring. But once again, thank you very much, Bob, for all of you've done for me and for the company.

So ladies and gentlemen, as I walk around this, good afternoon, and welcome to BG Group's 2012 Annual Strategy Presentation. I know you're getting very good at this. I want to draw your attention to our legal notice, which I'm going to leave you to read later.

Now today's presentation is structured around market knowledge and commercial agility, exploration performance and fast-track development of economic projects. These are distinctive capabilities at the very heart of BG and key to the continued delivery of shareholder value.

Now before we get into this, Fabio will kick off, summarizing our financial performance and our funding plans. Then we'll get on to strategy, beginning with the outlook for global gas and LNG markets. We'll then look at prospects for our global LNG business and the latest chapter, U.S. LNG exports. We'll review strong exploration and appraisal performance and further increases in our resources. We'll look at the fast-track development of economic projects, focusing on Australia and Brazil, and finally, to the outlook for production. And as you're going to see, we are making good progress with delivering our plans.

The key messages that I want to convey are the outlook for gas and LNG demand is strong with markets important to BG Group generally remaining tight. Our LNG business is set fair with the prospect of excellent profit momentum for many years, 10 years of industry-leading exploration that added another billion barrels oil equivalent of resources in 2011. We're on track in Australia for first LNG in 2014. We're on track in Brazil to deliver 2.3 million BOE per day of capacity by 2017. The combination of these and other named projects, underpinned by discovered resources, will deliver growth to 1.4 million BOE per day by 2020.

You'll recognize our strategy remains unchanged. It's founded on a deep understanding of our target markets and customers. We couple this with skills to connect to those markets' long-life, competitively priced resources. And while we retain our distinctive gas capability, we've adapted our approach to oil and secured a material increase in our exposure to oil prices. The combination of a clear and stable strategy and our distinctive capabilities has, over some 15 years now, driven strong profit growth of 28% per annum. Our presentation will show that this trend of value creation is set to continue as a suite of new E&P and LNG projects are brought on-stream.

But before we come to all of this, Fabio will summarize 2011 results and comment on our funding plans. Fabio?

Fabio De Oliveira Barbosa

Thank you, Frank. Good afternoon, ladies and gentlemen. Very briefly on the results. In 2011, E&P operating profits rose by 37%, benefiting from higher realized prices but held back by production shortfalls, primarily in the UK North Sea assets. LNG profits were at 5% with a strong demand and price in Asia being offset by the impact of our hedging program. Underlying T&D performances in Brazil and India were strong, and despite the results being down 39% due to timing of gas cost recovery at Comgás. Overall, our operating profit rose 19%, mirrored by strong cash generation from operations, up 17% at $9.8 billion.

Earnings were up 11%, reflecting the higher operating profits, offset by the increase in North Sea tax announced in March. Without this additional tax, earnings would have grown by 21%. We have recommended a final dividend of $ 0.1296 taking the full year to $0.2376, an increase of 10% in 2011.

Let's now turn to CapEx. Last year, we invested $10.6 billion, very much in line with our plan. Going forward, we intend to present our CapEx on a cash basis rather than on an accrual basis as the differences become material over the next few years. We will disclose, of course, the noncash items which are predominantly finance basis. Over 2012 and '13, we expect to spend $22 billion on a cash basis. Noncash items will amount to $2.3 billion. As I shall explain in a moment, we continue to pursue the rationalization of our portfolio. And in this connection, the CapEx forecast for 2012 and '13 takes into account the reduction in spend assuming the accomplishment of our main goals.

Now let's look at our view of 2012 CapEx. Updating our previous number, for new reference, conditions adds $1.2 billion, mainly due to changed exchange rate assumptions. There are $400 million of other items, encompassing some carryover from 2011, reduced CapEx in the U.S. and a number of program scope changes elsewhere in the portfolio. The execution of our portfolio rationalization brings about savings of $1.4 billion. Finally, adjusting for noncash items, 2012 CapEx on a cash basis is expected to be $10.6 billion, the same as in 2011.

In terms of funding program, an active treasury program last year raised $5.6 billion from the bond market, securing attractive interest rates and extending our average debt maturity to over 10 years. We also increased our undrawn committed facilities to $4.5 billion and extended their maturities up to 2016. In addition, we signed a memorandum of understanding with the Bank of China for up to $1.5 billion of funding support. We worked on diversifying source of long-term credit through establishing strategic alliances with export credit agencies worldwide. We expect to reach our first agreement in 2012. Three rating agencies confirmed our mid-A credit rating and gearing was 27%, unchanged from the third quarter.

As you know, BG Group is in the middle of the heaviest investment phase in its history. Project investment funded predominantly from our own cash flows will fundamentally transform the business. We expect production to reach over 1 million barrels of oil equivalent per day by 2015, with annual revenues growing to more than $35 billion at current prices.

To maintain a robust financial structure, 3 things we'll continue to feature. Firstly, we are a top-quartile cost performer and we are determined to remain so by maintaining focus on operating costs. Secondly, in an opportunity-rich portfolio, we will continue to prioritize projects with the highest capital efficiency, deferring less efficient ones. Thirdly, we'll continue with the execution of our portfolio rationalization program, planning to release over the next 1 to 2 years some $5 billion from, for example, power plants, T&D and Brazilification [ph] assets. These measures, alongside continuing work to diversify and extend funding sources are part of a solid and coherent plan to fund the execution of our large investment program. Economic and financial assumptions can change, and we'll therefore preserve all generic funding options, including, for example, different capital efficiency measures and possibly a wider divestment program. But at present, we are making good progress with our funding plan.

Thank you. And now back to Frank.

Frank J. Chapman

Thank you, Fabio. So strength in the U.S. and emerging markets, especially China, means that global economic growth is expected to exceed 3% in 2012, with emerging markets growing by nearly 6%. In the U.S., we're already seeing signs of an economy turning around and indications of an industrial renaissance, fueled by low-cost synergy from shale gas. In China and other emerging economies, structural drivers, such as urbanization, population growth, rising income and increasing consumption should lead to strong economic growth and even stronger growth in energy and gas demand. In China alone, each 1% increasing GDP growth rate increases the rate of gas demand by 2.3%.

So despite the financial and economic uncertainties, we remain optimistic about the outlook for those economies that matter most to BG Group. Over the next 10 years, despite modest demand growth in Europe, the overall outlook is strong. We expect significant growth in North America as the emergence of shale gas keeps gas prices well below oil parity, increasing demand in the power, industrial and the transportation sectors. Expectations have increased for emerging markets such as South America and the Middle East, and we think Asia will continue to grow particularly robustly once again, especially in China.

One view unchanged from last year is that strong underlying demand will generate immense supply challenges. By 2020, production decline from existing fields will amount to 1,500 billion cubic meters per annum. At the same time, we expect demand to increase by more than 900 bcma, generating a 2,400 bcma requirement for new supply in just 9 years. Supply will need to grow at over 9% per annum, requiring investment of some $2 trillion. All major regions will require significant new supply, driven by high decline rates of unconventional production in North America, domestic decline in Europe and very strong underlying demand growth in the emerging markets.

Meeting this demand will require enormous technical, commercial and funding challenges to be overcome. Many countries will need new imports resulting in significant changes in the league table of LNG importers. By 2025, China will be the second largest importer after Japan, and these forecasts already assume production from successful shale gas development amounts to some 15 bcma. We expect India to lie third with LNG imports reaching almost 50 million tonnes per annum by 2025, a sixfold increase. India is a market we understand well. Our agreement to sell 2 million tonnes per annum to GSPC is an important first step in a planned transition from gas distributor to major LNG importer. And India's location fits well with both existing supplies and is ideal for prospective LNG exports from Tanzania.

Significant new LNG capacity has been commissioned over recent years. But at the same time, future supply has been actually falling. In fact, we've seen a 17% reduction in prospective LNG supply by 2020. So we see increasing LNG demand at a time when future possible supply appears to be diminishing. And these diverging supply-demand trends create a tight LNG market. Outlook, they point to firm long-term contract prices and the need for new LNG supply projects, in fact, just like the ones now taking shape in the U.S.

We see 4 key factors driving this proposition. First, the U.S. has a large low-cost shale gas resource sufficient to meet domestic demands for many generations. Second, we believe that Henry Hub will remain significantly discounted to oil for some considerable time. Third, there will be a shorter shipping route to Asia once the widening of the Panama Canal is complete in 2014. And fourth, and most important, are the existing and underutilized Gulf of Mexico import terminals. These provide brownfield sites, advantaged by up to 50% lower capital costs and shorter development lead times. This leads to a robust U.S. export margins at Henry Hub prices considerably higher than industry forecasts. Now only 4 such Gulf brownfield sites are credible near-term projects. And quite uniquely, BG Group has a 34% stake in either the offtake or the capacity of these 4 advantaged terminals, giving us a material, early-mover advantage in U.S. export volumes. Presently, we see up to 45 million tonnes of export by 2020 from these brownfield sites, adding a modest 10% to U.S. gas demand, an increment unlikely in our view to have a significant impact on U.S. gas prices. So with the combination of these 4 key factors, U.S. LNG exports to Asia become practicable and competitive.

BG Group has moved quickly to establish U.S. LNG export business. The first stage is built around 2 tranches of supply from Sabine Pass. Sabine will deliver 3.5 million tonnes per annum from the first train in 2015 and a further 2 million tonnes from subsequent trains. Sabine Pass exports can be sold to all U.S. trading partners. And so these new volumes will form an integral part of BG Group's flexible global LNG supply. Cheniere has signed an EPC contract with Bechtel, and we expect the construction to start in 2012. And I should point out, we're not contributing capital to this project and our liquefaction charges commence only on delivery of the first contracted volumes.

In addition to Sabine Pass, development plans for export from Lake Charles are at the design and permitting stage. A 15 million tonne export authorization for FTA countries was granted in July last year, facilitating a Lake Charles supply to our customers in Chile, in Korea and in Singapore. We expect a decision on our application for non-FTA countries by the end of this year. With Sabine Pass, our total LNG supply is set to exceed our 2015 target of 20 million tonnes. Moreover, the goal of 30 million tonnes by 2020, introduced to shareholders just last year, is now within our reach and we’ll follow from some combination of Lake Charles QCLNG Train 3 and potentially Tanzania. In the success case, these projects could, in fact, take us well beyond 30 million tonnes per annum.

So future profits momentum will be strongly driven by underlying volume growth as material new supply comes on-stream from Australia and from Sabine Pass over the period 2014 to 2018. In the meantime, LNG profit momentum will be sustained by a continuation of a tight market, plus the expected positive effects of reducing LNG hedges, which materially held back 2011 LNG results. Accordingly, we are increasing 2012 profit guidance by over 30% to between $2.6 billion and $2.8 billion. From 2013, we will be substantially unhedged.

To aid the modeling of profits from 2013, we're presenting today more information on the cost and the value of our LNG portfolio. Let's first look at the source and cost of LNG supply. Existing Atlantic Basin supply largely purchased at a discount to Henry Hub will continue at around 12 million to 13 million tonnes. Over the period to 2015 or the period from 2015 to 2018, Sabine Pass will add 5.5 million tonnes, also purchased on a Henry Hub basis. From 2014, QCLNG will provide new equity LNG supply with the cost based on a netback from oil-indexed sales. From this global portfolio, we sell to customers in 23 countries. And in terms of revenue, some 3 million tonnes is committed to market with Henry Hub pricing, which includes, as previously indicated, the change in our Chile contract to Henry Hub pricing from 2013. The rest of the portfolio targets high-value markets with oil-indexed sales into Asia, our main focus. We'll maintain portfolio flexibility, sufficient to respond to market opportunities and to build new market-led LNG propositions.

Turning now to our U.S. E&P business. In the Haynesville, we built a large, high-quality, low-cost shale gas resource of some 5 trillion cubic feet and are presently developing the core DeSoto area. The Marcellus, with its 3 tcf of resources, is less mature. In 2011, appraisal revealed 2 new high-quality areas with cost and productivity comparable to our better Haynesville areas. The independent data shown in this slide, gathered from 126 of our wells, shows that the results were achieved and compare very favorably with competitors.

The big questions, of course, are all about price. Forecasters have undoubtedly over the last year lowered their outlook for long-run U.S. gas prices, now projecting $4 to $6 per million BTUs. Our price expectations lie towards the lower end of their range. Right now, there are factors on both the supply and the demand side, so they're keeping prices particularly low, a situation we expect to continue for the present. Given current weak prices, we are substantially reducing our 2012 program, rig count is expected to fall from 35 to around 8. And accordingly, our forward plans currently assume about 80,000 BOE per day production from U.S. shale gas in 2015, some 110,000 BOE less than last year's plan.

So in summary, the outlook for gas and LNG demand is strong with markets important to BG Group generally remaining tight. We have a new U.S. LNG export business. It's economically robust at prices well above present Henry Hub forecasts. We also have a high-quality domestic shale gas business, where the intensity of investment can be modulated in response to price. The combination of these 2 businesses will allow BG Group to extract value from the success of U.S. shale gas over a wide range of Henry Hub prices. In LNG, we'll meet our 2015 target of 20 million tonnes of supply and have identified clearly the route to 30 million tonnes or more by 2020. Identified short-term profit drivers and strong underlying volume growth from 2014 mean our LNG business is set fair with the prospect of excellent profit momentum for many years to come.

Let's turn now to the second distinctive capability I referred to earlier, our exploration performance. A recent Wood Mackenzie study once again recognized the BG Group's exploration performance sustained over the last decade, which places our company ahead of the majors in terms of value creation at $25 billion over the last 10 years, return on exploration investment at 24% and reserves replacement averaging more than 300% per annum. And this analysis doesn't include our unconventional exploration success or our recent resource upgrades in Brazil. Nonetheless, the relative performance paints a clear picture of BG Group delivering top-quartile performance for over a decade, confirming BG Group's capability as one of the industry's leading explorers.

In 2011, exploration and appraisal activity added 1 billion BOE to our resource base, bringing resource additions over the last 10 years to 10 billion BOE, 9 billion of that coming from the drill bit. We've achieved this at a low organic finding cost just $1 per BOE of resource. Our inventory has grown annually by around 12% over the last 10 years to reach today's 3.8 billion BOE. And as you can see, we have a good diversity of play types and importantly, a high level of control over the program execution, with 75% of this operated by BG Group. The gross unrisked resources within this portfolio amount to some 40 billion BOE.

Now in 2011, the exploration highlights included: appraisal drilling on the big 5 Santos fields in Brazil, leading to material resources upgrades; another discovery in Tanzania and a large acreage acquisition in Kenya; discoveries in both the U.K. and Norway, adding high-value barrels. In 2012, we'll invest $1.5 billion across 7 countries, with focus beginning to shift away from Brazil appraisal and towards new frontier plays.

Let's take a look at 2012 exploration in 4 countries beginning with a new opportunity identified in Egypt. Our high equity-operated positions in Egypt include new potential in the established Pliocene play, as well as a very exciting new Oligocene play in the El Burg and El Manzala concessions. The new Oligocene play has been proven by what BG Group believes is a high success rate from 8 adjacent wells. The Oligocene potential in our blocks amounts to over 17 tcf, and we'll be testing this play in 2012 with a Notus well.

East Africa is emerging as a major new gas province. Offshore Tanzania and Kenya, we have some 30,000 square kilometers of acreage, equivalent to over 150 U.K. blocks. Our first campaign in Tanzania yielded 3 tertiary gas discoveries in high-quality reservoirs, with estimated resources of over 3 tcf. In Tanzania, we are looking at a variety of perspective multi-tcf plays situated in 2 delta systems, the Rufiji in the north end, the Ruvuma there down in the south. We'll drill 3 to 4 wells in 2012 across the Blocks 1, 3 and 4, aimed at adding further tertiary resources and testing the deeper Cretaceous potential. We also plan to shoot 2,500 square kilometers of 3D seismic, which includes the potential extension of the Ruvuma play proven in Mozambique. Screening workers begun prospectively to identify a potential site for an onshore LNG plant.

In Australia, QGC is pursuing 4 resource plays. First, exploration and appraisal to increase coal seam gas resources in the Surat, an additional 1.2 tcf has been identified. Second, we are exploring for CSG in the Bowen, where 4.7 tcf has been identified. We drilled 14 wells in 2011, with encouraging results. In 2012, we plan further production testing and possibly, a pilot production program. Third, 700 kilometers away, we're exploring shale gas opportunities and potential in the Cooper Basin, where existing pipelines could connect gas to QCLNG. Finally, we're exploring a deep gas sands play with 2.3 tcf of potential. And this is in the south of the Bowen Basin, where it underlies the Surat. Last year, we drilled 2 exploration wells, which encountered gas, and are currently under evaluation. A third well is now drilling with a fourth to follow later this year. All 4 of these plays represent potential new supply sources for expansion of QCLNG. In Australia, resources have increased from around 5 tcf in 2008, when we acquired our interest in QGC, to more than 25 tcf today, plus 1 tcf of contracted third-party gas.

In Brazil, we drilled 11 exploration and appraisal wells in 2011 and completed 2 extended well tests. Resources were upgraded to some 6 billion BOE, with an upside of 8 billion BOE net to BG Group. These upgrades were based on improving reservoir delineation, well deliverability and reservoir connectivity, all of this derived from appraisal drilling and well testing results. More than 95 -- 95% of these resources are in the big 5 Santos fields, Lula, Cernambi, Sapinho, Iara and Carioca. In 2012, we'll drill further 8 appraisal wells and an exploration well on Sagittario in BM-S-50, the last of the presently envisaged high-potential presalt prospects. So 4 material exploration and appraisal plays for the future.

Let's now turn to reserves replacement and the resources stack. In 2011, our proved reserves replacement ratio was 251% and 212% averaged over 3 years. This is a robust performance and an important precursor to strongly rising future production. We expect to maintain a top-quartile performance on these measures. Here, the left-hand chart shows the rolling 3-year F&D costs, again, in the top quartile, where it's been for 8 of the last 9 years. Again, this is a sound indicator of economic developments being progressed towards production. The right-hand side of this slide shows our unit OpEx. Here, too, BG Group is a top-quartile performer.

During 2011, reserves and resources increased 1 billion BOE bringing the total to 17.1 billion or 73 years of production at 2011 levels. Reserves and resources have grown 7 billion BOE over the last 4 years.

[Audio Gap]

BG Group has delivered 10 years of industry leading exploration that added another 1 billion BOE of resources in 2011.

Continuing robust proved reserves replacement reflects BG Group's third distinctive capability. The fast track development of economic projects currently being demonstrated in Australia and in Brazil. In Australia, we sanctioned the QCLNG project in October 2010, only 34 months after entering the country. Since then, we've invested more than $5 billion, and we're on track to deliver our first LNG from Queensland in 2014, just 6 years after arriving. QCLNG represents the integration of 4 parallel projects: an upstream development with initially 2000 wells and gas and water treatment facilities, 540 kilometers of main pipelines connecting the gas fields up to Curtis Island, a 2-train LNG plant with capacity of 8.5 million tonnes in the first phase and market development. That has so far secured 10 million tonnes per annum of LNG sales to high-value Asia-Pacific markets. Now to show you what's happening on the ground, 15 months on from FID, we sent a camera crew down to Queensland.

[Presentation]

So as you can see, we're making good progress on the ground. Drilling is being ramped up significantly to 11 rigs nearly 150 kilometers.

[Audio Gap]

Welded and at Curtis Island, the site is being prepared -- has been prepared and foundations are being constructed with work ongoing in Thailand on the modules and steel work. This is a project that's going to deliver attractive economics underpinned by 15 TCF of gross resource to supply the LNG plants and domestic contracts, plant annual throughput of 8 million tonnes and competitive costs, both in the upstream and the LNG plant.

QCLNG's competitive unit costs and mainly oil indexed revenues result in strong capital efficiency and economic returns. Gross revenues of more than some $5 billion per annum FOB are expected at an oil price of $90 per barrel.

So we're on our way to realizing net plateau production of 215,000 BOE per day from this, the first phase. In parallel, pre-sanction and appraisal work continues for Train 3, cost efficiency favors a sequential build following on from Train 2. However, resource maturation across all QGC supply options could require a somewhat later build. And these considerations will, in the course of 2012, determine sanction timing. Meanwhile, LNG supply momentum is being strongly driven by our new U.S. exports business. So this is a picture in Australia.

Let me now move to Brazil. You know so much has occurred in the last 5 years. It's perhaps too easy to lose perspective on the sheer scale and quality of our big 5 Santos fields. By 2020, these fields alone will be producing over 2 million barrels of oil per day, nearly as much as the entire U.K. North Sea at the same stage in its life. Effectively, it's like BG Group having around 25% of the entire North Sea oil output at that point in its development. And this production -- you liked that, didn't you? And this production comes from just 5 fields compared to 30 in the U.K. North Sea at that same stage, and from 1/7 of the number of wells. Also, the proximity and similarity of the fields allows a flexible modular development approach and the sharing of infrastructure of combination that yields exceptional capital efficiency and robust economics.

Again, to show the progress we're making there on the ground, we also sent a film crew down to Brazil.

[Presentation]

So as you can see, we're also making rapid progress in Brazil.

You know, it is quite remarkable that 1 billion BOE will be produced from the FPSO 1 location. And this, of course, is due to the quite exceptional reservoir characteristics confirmed by appraisal and testing results and production to date of some 30 million BOE.

We're on track to deliver the 2.3 million BOE per day of FPSO capacity by 2017. Moreover, unit costs are competitive and falling. Let me say something more about costs and infrastructure. About half the development CapEx will be spent on drilling. Time to TD is down from 141 days taken on the Lula discovery well to an average now of some 66 days. Our best composite well took just 34 days and we're working to get our average down to that level. We're building up to more than 40 wells a year, and plan to adopt a new deepwater assembly line approach to accelerate performance improvement by using specialist rigs and crews on different sections of the well. The JV has secured some 80% of the rigs needed for the next 2 years at rates 20% lower than in 2009.

In 2011, the first phase of BG Group's independent oil export development became operational, lifting 2 cargoes from Lula by dynamically positioned shuttle. Seven cargoes are planned in 2012. Four further DP shuttle tankers are being contracted for 2013 and 2014, coinciding with the buildup of production. We also completed the concept selection for BG Group's in-shore oil transshipment facility to be sanctioned this year. We expect to sell our oil to international markets, at a net back of some $4 below Brent. Gas sales commenced in 2011 through the new Lula-Mexilhão pipeline. It has capacity of 350 million standard cubic feet per day, sufficient for the first 3 FPSOs. The first Cabiúnas gas pipeline to be sanctioned in 2012 will have export capacity sufficient for a further 3 to 4 FPSOs. The JV is currently evaluating further export options including pipelines and floating LNG.

Since 2008, estimates of average recovery per well have almost doubled for our big 5 fields, driving reserves and production upgrades. Again this year, we're increasing our net production forecast for 2020 from 550,000 to over 600,000 BOE per day. And all of this progress, I think, provides a much firmer basis for confidence about Brazil, the future program and, of course, its value.

So in summary, we are on track in Australia for first LNG in 2014. We're on track in Brazil to deliver the 2.3 million BOE per day by 2017. And these are examples of what I meant by BG Group's distinctive capability to fast track economic projects.

So let's now turn to production. Now before considering our production outlook, let me first touch on the 2011 story, which has 2 parts. In aggregate, the international assets grew by some 5% in line with expectations. The effects of political change in North Africa and the severe flooding in Australia were successfully recovered or offset. This performance however, was masked by the impact of shutdowns and infrastructure restrictions primarily in the U.K. North Sea, which resulted in the deferral of some 12 million BOE.

Now as you'll know, our fields currently on stream show essentially no decline before 2015, in our industry, a picture you don't often see. What's more, this decline is delayed until 2017, when one takes into account the new developments in these countries, such as Bongkot South, Jasmine, Knarr, West Delta Deep. And production from these base countries in 2015 will be above 600,000 BOE per day, in fact, more than in 2010.

The production growth equation is therefore, a simple one. Combining this solid base with the contributions from Australia and from Brazil, plus the reduced U.S. plan delivers production of more than 1 million BOE per day by 2015 and around 1.4 million by 2020, importantly, underpinned by already discovered resources and named projects.

1.4 million BOE per day represents the midpoint of our long-term 6% to 8% growth range established back in 2005. Further, we expect risk resources from our exploration portfolio to allow the top end of the range also to be achieved in 2020.

In terms of 2012, we start the year with a production run rate of some 650,000 BOE per day, and we expect to exit the year with a rate of some 750,000. The key factors will be improved production from the U.K., alongside 6 new projects coming onstream progressively through the year.

Let me, therefore, conclude by summarizing the key messages I set out earlier. The outlook for gas and LNG demand is strong, with markets important to BG Group, generally remaining tight. Our LNG business is set fair with the prospect of excellent profit momentum for many years. 10 years of industry-leading exploration that added another 1 billion BOE of resources in 2011. We're on track in Australia for first LNG in 2014. We're on track in Brazil to deliver 2.3 million BOE per day of capacity by 2017. And the combination of these and other named projects, underpinned by discovered resources, will deliver growth to 1.4 million BOE per day by 2020. So as I hope you've seen, we are making good progress with delivering our plans.

And that brings me to the conclusion of this presentation. And now, Fabio and I will be happy to take your questions. Thank you.

Question-and-Answer Session

Irene Himona - Societe Generale Cross Asset Research

It's Irene Himona at Société Générale. I had 3 questions please. First, are you prepared to say what LNG EBIT would have been last year in the absence of the hedges? Secondly, the 5 billion of planned asset disposals, could that include Australia and Brazil? And thirdly, you mentioned the 6 new startups in 2012. Could you give us a sense of the pace of ramping up? Is it weighted in the latter half of the year, for example?

Frank J. Chapman

Well, on the 6 startups, we've got Bongkot South in the Far East, in Thailand, which is about to start up in the next month or 2. In fact, it's scheduled to start in April. We have Margarita Phase I, which again is a project which will start in the first -- the second quarter this year. We have Gaupe in Norway, which will start up in the first half. We have West Delta Deep Marine Phase 7 and 8B. 8B is quite a significant project. That will be loaded towards the second half of the year. And we have Jasmine, which is right at the end of 2012. So some of the larger projects are weighted into the second half of the year. Fabio, do you want to talk about LNG EBIT and $5 billion?

Fabio De Oliveira Barbosa

Well, I think we should consider the issue of hedging in a long-term perspective involving offshore, the situation that we face in the past, by 2008, when we noticed or we expected a major supply overhang in the market that would undermine our ability to execute on investment program, if we haven't protected our cash flow. So in this perspective, as the plan was fully effective and we believe that despite the fact that, of course, our results were held back by the strike price that we have agreed for 2011. We have a very positive assessment of the results. In order to help you to understand the business moving forward, we are providing you with more granularity on the cost of supply, and also the markets that we are selling our LNG cargoes. At the same time, we are indicating that in 2012, we substantially hedged and being the opposite in 2013, when we are going to be substantially unhedged. I think this will give you plenty of information to understand where are we headed in terms of our future LNG business. As for the $5 billion, we indicated the assets that we are considering, some of them, particularly the power assets is a long-standing program. We have divested most of our product lines at this stage and have a few remaining. That will continue to pursue the final sale. We also have a process going on in India, as you know, regarding our T&D asset. And finally, the reclassification assets that we also included in this program, as well as some infrastructure assets in the U.S. as we may have seen recently. We have a lot of options in our portfolio. But at this stage, I don't think it will be appropriate to comment further in order to preserve our commercialbility to continue our discussions.

Jason Gammel - Macquarie Research

Jason Gammel from Macquarie. I had a few question around the LNG business. First, related to Sabine Pass, you did reference that you don't have any capital committed to that program but it does appear that anyone has capital committed to that program. So I was wondering, how that's going to actually move forward? Second of all, related to U.S. pricing, is your policy moving forward now that you have essentially all your fundings secure going to be to just not hedge Henry Hub and to take that pricing risk?

Frank J. Chapman

Yes. I mean, Martin maybe and you'll take the question on pricing and the hedging policy. On Sabine, I mean, essentially, our view is that when you've sold as much LNG as Sabine has sold, given the current powerful underlying economics of these ventures and the commitment of companies such as BG, who have the capability to pay for these very substantial contracts, this will alleviate massively Sabine Pass Liquefaction, LLC's capability to raise capital. I mean essentially, it's BG's balance sheet and the balance sheet of all of the other big players who are taking off that is going to support the ability to finance that project. So that's our view there. Martin, do you want to say something about pricing and the hedging?

Martin Houston

Yes. I mean, just on Sabine. I guess, we expect it will be, [indiscernible] where the question came from. Thanks. Look, we expect it will get funded and we're pretty confident about that. But on hedging, I mean, our position now is we're not going to put any hedges in place. I mean, we're going to stay open to the market. And if we look at the price expectations, I mean Frank talked about the consensus range of 4 to 6, we tend to be of the lower half of that range as we look forward in our own screening values. Right now, we've got prices which I would say abnormally low, driven by factors on both the supply side, which we're well aware of to do with drills to hold, carry and so on. And on the demand side, we've had, I think, 20%. We're at currently at the warmest winter for some time and quite a substantial reduction in actually, commercial and industrial demand in the U.S. But to answer your question straightforwardly, no.

Frank J. Chapman

The microphone is somewhere in the middle here. Somebody? Is it? No? All right. Just around...

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Theepan from Nomura. I just -- I do want to come back just to the concept of hedging on the LNG business. In the sense that essentially, an overview here is the spread between the oil price and Henry Hub. And going forward, when you look at '13 and '14, it seems strange in some ways that you want to be significantly unhedged, unless you assume that the spread is going to widen. So I just wanted some thoughts on how you thought that spread in particular may move. Secondly, just coming back to the financial framework, just wondering how you saw gearing progress over the next couple of years, and how important the A rating is to you. And therefore, how important it is to deliver that $5 billion of, let's say, disposals. And then lastly, looking forward to Tanzania. Thank you for the updated chart on risk exploration. Just sort of -- I haven't got a protractor but it looks like sort of on a risk basis, Tanzania is sort of 500 million barrels. I was just wondering, so on a derisk basis in terms of resource for the drilling program this year, how much do you think you can derisk if Tanzania was a 3 to 4 wells?

Frank J. Chapman

Just on Tanzania, we're not going to try to derisk that for you. It's in our portfolio, our risking in the past has tended to be a little on the conservative side. That is the track record of the company. But I'm not going to give you prospect sizes and the amount of resource that we're targeting in the year. I don't think that's appropriate to sort of stoke expectations in that way. As I said, we are pursuing multi-TCF play in a variety of multi-TCF plays, in a variety of play styles. And we won't have to wait too long before we've drilled out our 3 wells and there'll be a pause and then there'll be another well a bit later on. You're going to deal with this credit rating. But let me just say on the hedging, very simply, you know that the origin of this, when we stood up in 2008 and said, we'd hedge all these stuff out starting in 2007, people thought it was a really good idea. Actually, the market turned a little shorter, a little earlier than we expected and therefore, we had hedges in place that we rather wished that they had come off. But on the whole, these hedges have done the trick. They have given the stability when everyone's earnings were going like this. In 2009, we had this terrific platform of earnings coming through and people just said, wow, look at this business go. And of course, the business has gone on from that. And as we move out to 2020, '15 and '20 with 20 million to 30 million tonnes of supply, you're going to see a massive central gravity. Not -- central gravity be a massive amount of potential coming out of this business. Now in terms of the guidance we're giving, the hedge part of the portfolio, when we've got the hedges in place, we're telling you what we think the performance is going to be. That can go to one side. Now we get to 2013, no hedges in place, substantially unhedged, plus the fact that you're getting more skilled on understanding how were doing this. With the data we've given today, you will be able to estimate with some accuracy the picture going forward. So hedges are in the past, we're going to a position where we're going to be unhedged and we're giving you this information, so that we can stop the guidance and you can calculate.

Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division

Frank, I understand that, but why wouldn't you want to -- given the environment you're in, why wouldn't you want to actually hedge out some of that spread today? I mean, are you taking a more optimistic view than where we are today? That was my question. I understand you're not going to give the number on it.

Frank J. Chapman

Yes, yes. I mean, the whole way that we have made money in this business over the years. I mean, It is true that we've shifted where we've taken money and we've taken commercial positions in different points in the cycle. We made money off our ships, and then we transferred them into making money out of terminals and then we transferred that into making money out of new supply and then building customer base in the Atlantic and then building customer base in the Pacific, and then having an a third party -- an equity LNG supply over there in the Asia-Pacific and so on and so forth. So the game rolls on. So we will take these positions from time to time, like we'll take positions on the quantity of LNG that we don't want to sell, that we want to keep liquid. And all of this overall picture, I just put in a box which says, commercially sensitive. The way we move this business around, the way we mature it, the way we try to keep ahead of the competition, change the paradigm, I put all of that in a box. And I say, I'm not telling you what we think. Okay? Sorry. So I think it's fair. Sort of like I'd be a bit secretive every now and then.

Fabio De Oliveira Barbosa

Well, on the rating. We'll, we are happy with our mid-A rating and we believe that it's a good place to be, considering our investment program. We have a solid and coherent plan as we explained. We believe that this plan is consistent with this target of keeping and ensuring our mid-A rating. As for gearing, as you know, we, of course, in a period of investment right now, but as we indicated in 2015, our revenues, considering the current oil prices, would be over $35 billion, if we apply production to the current prevailing environment. So it's a very sound position in the long term. And of course, the disposals are important and an integral part of our plan. We are very happy with the developments that we had so far. We are very much on track, and we believe that we'll be able to deliver as we expect. And so keep our mid-A rating in our balance sheet.

Jon Rigby - UBS Investment Bank, Research Division

It's Jon Rigby from UBS. Two questions, one of which has 2 parts. The first one is on the U.S. and LNG. Firstly, I mean, it occurs to me you're shutting in gas production whilst still importing LNG into the U.S. I think, you see you got some commitments there. Is there no smart way that you can add a bit of capital somewhere logistically and get rid of that, what looks like an anomaly? Second is, you looked at export options, but just looked at the U.S., is there something around Canada at the moment that might be of interest to BG longer term? And then -- that was my first question. The second question is, again, around your disposal program and linking it back to Brazil. As you look at Brazil, is the way that you see generating value out of Brazil, holding those assets through to startup and through production? Is that the way do you think BG will deliver MPV or are there other options around those assets that you can deliver MPV with?

Frank J. Chapman

Well, we're not going to -- this is another attempt to getting us to speculate. Now I've got a Brazilian next to me you see, I'm not allowed to sell anything Brazilian. But I don't think it's right to speculate at the time on what we will and won't do about Brazil. I can tell you, we are really, really delighted with what's happening in Brazil. Let me give you something, right? Because I know you like all these sort of numbers. We stood up at the end of 2010, and we talked about the 3 best developments that we had in all of this resource. And we talked about the first 3 FPSOs. And we said at that time, the economics are fantastic. Each of these FPSOs will produce 750,000 -- 750 million barrels. They'll have, on a lease basis, a unit cost, CapEx cost of $5 a BOE of production. And we talked about including the lease costing $9 a BOE for the OpEx. I was asked the question at the time that said, what about if they're owned, the future ones and the answer was, well, the CapEx will go up a bit from $5 to $6.50 and the OpEx, I expect, will come down by $4 from $9 to $5. And both of these metrics, whichever way you cut it, give fantastically robust economics. Now what about if I said to you today, let's recut those numbers, what do they look like today? And I would say to you today, well, the CapEx number when we own this has gone up, not to $6.50 but to $7. And I would say the OpEx has gone up -- has gone down not to $5, but to $6, right? But guess what, now I'm talking about the entire 6 billion to 8 billion barrels of resource, okay? So before we were talking about the attractive sweet spots, the 3 first FPSOs. Now, I'm talking about 8 billion barrels of resource for BG net, with those sorts of unit costs. Now if you want to think about where we want to put our CapEx, that delivers most efficiently, strong economic returns for our company, and given the fantastic progress we're making with Petrobras and the partnership, I mean, you'd have to make sure you got good value to sell assets like these. You'd never want to sell asset like this undervalue. The trend is so strongly upwards. You better not get that equation wrong. Anyway, you were going to say something else about U.S. Anyway, I just want to say something about it because I know you'd be embarrassed to say because I'm Brazilian, we're going to keep those assets. But you were talking, Martin, will you take the question about applying capital to get rid of this idiosyncrasy?

Martin Houston

Well, I mean, there's been a substantial reduction in the amount of LNG we brought into Elba Island. That's the sticky market we have in the U.S. If you look at the numbers at Calgary in 2010 versus 2011, substantially, we have spent a lot of money through our partner, El Paso, on the receiving side. As you know, those are quite isolated markets. So it's been quite difficult. We put only one cargo into Lake Charles to keep it cool last year. So that's been reduced. Then of course, if there are any other exposure to hub markets we have, as Frank has said, is the conversion from an oil-based index to a hub-based index in Chile going forward in 2013.

Frank J. Chapman

Which was always part of the agreement.

Martin Houston

Indeed, yes.

Jon Rigby - UBS Investment Bank, Research Division

And Canada?

Frank J. Chapman

Canada, yes. Okay. well, we made -- there was a very small article in the press as you probably saw yesterday, suggesting that we had some interest in some land on Prince Rupert Island, which is true. It's an option. It's a very low-cost option. You heard, I think, quite powerfully in the presentation, for mid-decade with $35 million of revenues, we're going to be looking for some new projects. This is one of a number of things that we're looking at. There's 1,000 TCF or more sitting in the mud and the whole river. This is a very exciting opportunity. But it's very, very early stages, and I would describe it as a sort of very feasible at the moment.

Brendan Warn - Jefferies & Company, Inc., Research Division

It's Brendan Warn from Jefferies. Just a couple of questions. Just one on relating to LNG. I guess, shipping capacity, just your view on sort of number of vessels or capacity required going forward that you don't already have contract, and perhaps one of the missing pieces is the average, call it, lease or contracted day rate for those types of vessels. And just second, I guess, back on Jason's question related to your couple of partners in the U.S. Both the U.S. onshore shale producer and your partner that's looking to construct the liquefaction. Just any sort of tangible contractual contingencies, either rights under the agreements that you have in place going forward. Obviously, these are strengths important to you guys now.

Frank J. Chapman

Yes. Martin, I'll just answer the question on the EXCO and Sabine. But maybe you would take the day rate issue and the shipping strategy. Look, any self-respecting company and the agreements they put into place will cater for a range of outcomes and a range of circumstances to protect the parties to the agreement. So, of course, we will put into place things that we feel are appropriate to protect ourselves. I mean, the ultimate protection with Sabine is if the project doesn't happen, we don't pay anything. Of course, we want it to happen because this is a great business opportunity, where we have a first mover advantage. With EXCO, there, we're in the process of reaching an agreement to bring the rigs down to around about 8, and half of those at least will be continuing to work on exploration appraisal work. It takes a lot of work to do there still, which is a program we believe EXCO is fully capable of supporting. So that's the situation with EXCO. Martin, do you want to say something about shipping strategy?

Martin Houston

Yes. Our shipping right now, we have -- there's certainly 31 December

[Audio Gap]

Market and industry. We sought review [ph] very, very early last year that we were going to be moving more east. I can tell you the first thing we did after the tsunami in Japan, apart from doing what we could with our customers in sending our condolences was to locked in ships. We've dropped in early last year. I think we’ve got a -- we're at the midpoint of, I think, of the price cycle last year and I think we're positioned well. So our average cost is well below the high watermark in the industry today.

Gordon M. Gray - Collins Stewart plc, Research Division

Gordon Gray from Collins Stewart. I had a question about your 2015 volume target if I could. A year ago, you were talking about guidance of 14% compound to 2015, which if I'm right, represents a number of over 1.2 million barrels a day. Today, you're talking about over 1 million. Obviously, the U.S. gas position is one big thing that's changed. Can you talk about any other moving parts between...

Frank J. Chapman

Yes. I would do that. I mean, actually, our plan carries more than 1 million. I've rounded it down to, say, 1 million barrels. The plan actually carries more. When you add in 110,000 barrels a day, that will be short in 2015, where we'd be producing 80,000 instead of 190,000, there's 110 difference. When you add that to the actual plan, you get pretty close to 1.2 million. So I mean, it's a little bit at the margin, a few differences. But substantially, it's the U.S.

We've got a question down here. We have somebody just over here, please. You have a microphone? I'm trying to line them up, you see.

Go ahead.

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

Oswald Clint, Sanford Bernstein. Yes, just on the shale gas actually, could I confirm that the 80,000 barrels per day is going to be constant and still works at your reference conditions, which go out to $5.05 in 2015, if we're at, hypothetically, $2.5 in 2015, is that still a good number? And even on the upside, what causes you to go back into those shale plays again? Second one, just on Brazil again and confidence over the numbers. I just note that there's a lot of comments about, it's not the consortium, not the operator's view on some of the data you gave us. Can you give us any indication of when Petrobras and Gallup might come to align with all of your views? Is that something could be forthcoming? And then just a very quick one, on the exploration, can you say if we should expect you to bid in the Lebanon and Cypress license runs this year?

Frank J. Chapman

I'm not going to speculate at all on Lebanon and Cypress. We're going to leave that. We don't want people bidding, jacking it up. So how do we get back into an investment cycle in the U.S? What we simply done at this stage is to say, nobody really knows what's going to happen with prices in the long term. We are very positive, along with quite a few others about the growing demand. We're seeing industrial demand at 3.5% up already this year. It's only the seasonality. This really caught us out with the warm winter. LNG demand transportation, a new power demand and so on and so forth. So we're very positive on that. The great attribute about this business with very shortly lead times between when you put the first dollar in and when you get your first dollar of revenue is very short, 3 months. So it is a business that lends itself to modulating the intensity of investment in response to the market. So the current plan says, right, we're going to be economically rational here, we're going to turn down the wick in the coming years. We don't know how long this present thing is going to go on, we don't expect it to be over soon. So we turned down the wick. In our plan, we've assumed that prices enter the lower part of the band that we referred to earlier on, and at $4 a 1 million BTU, $4.50, this sort of range, we've got a lot of resource that is economic. So you would really, at that level, we would really be jacking up our business plan, of course, just makes an assumption. The set of reference conditions and makes a set of internally-consistent assumptions about the buildup of that profile out for the rest of the year. The important thing to remember is that we have a combination of 2 businesses now. An LNG business that can be profitable, very much higher LNG, Henry Hub prices and very good quality rocks, which means we can be profitable with our shale gas business at quite low prices and we can even turn it off. And a combination of these 2 things means that we will extract value from U.S. shale gas over a very wide range of Henry Hub prices. So that's really a little bit of an insight. Now your 2 other questions, one was about exploration, which I said wouldn't answer. The middle one was about the...

Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division

Just about the alignment of views across the consortium in Brazil?

Frank J. Chapman

Well, look, it is quite normal actually for companies to carry their own field development models, their own reserves estimating. This is quite normal. You don't sit in a room and do it altogether. You have your own technologies, your own approach, your own standards. And therefore, all of the companies will have their own stuff. We get into the room together with our different views and we negotiate. Actually, we made fantastic progress. I mean, 4 years, from 2006 to 2010, 4 years only from first discovery to first 100,000 barrel unit in service. Only 5 years between first discovery and committing $40 billion of capital investment to 2.3 million barrels of capacity, there is a massive, massive commitment. Now we've got all that under our belt. There's no disagreement between the partners in terms of these are great fields, we're going to get off here. I mean, it's enormously rapid progress. And now we've got that under our belt. We've got some nutty issues to deal with: How are we going to optimize gas evacuation, How are we going to sell crude. So we're doing our own scheme, for example, on. How are we going to shape Phase 2. So these things, we're in the process of -- and some of these things are going to take 2 to 3 years before we expect to settle. But you shouldn't be surprised about all this. We've got plenty of time to do this. In the meantime, we believe it's important that we tell our shareholders what we believe will happen, what we believe it's worth. And we make it very clear that it's not a partnership view, it's our view. But enormous commitment from the partnership, fantastic. It really is working. We had another question down here.

Lucy Haskins - Barclays Capital, Research Division

Lucy Haskins, Barclays Capital. Can I ask about contingency within your estimates for 2012, both on LNG and production? So do we have about the same volumetric hedges in place for this year? And can we expect the same kind of uplift in terms of the outcome in terms of LNG profitability as we had relative to the guidance last year? And on the exit volumes for this year, at 750,000 barrels a day. What are the assumptions in terms of the shale gas? And also, have you got incrementals for the contingencies in for North Sea downtime? Because as you said, that was the big sort of miss during the course of 2011 .

Frank J. Chapman

Yes. I mean, on North Sea production, I mean it was a hell of a year. We had the elective shutdowns because we simply said we want to improve the asset integrity and the longer term, the performance of Everest and Lomond in particular and brings down Erskine with it. We had third-party infrastructure. Second world war ordnance floating alongside pipeline, this sort of stuff. We had the extraordinary weather. I don't know if anybody noticed, but we had several 100-year waves in 1 year. It was extraordinary extreme weather in the North Sea, which did cause damage towards the end of the year to Lomond. So there are a theory’s -- and we also had the commissioning issues with Buzzard. That was a real issue with our friends over there. It wasn't a great process. Now some of those things are not going to happen this year. Certainly, the commissioning, we don't expect the same sort of infrastructure issues. We have assumed quite a lot of production, therefore, returns. But we have not brought the fields up to the level that we were carrying in last year's plan because we intend to do more asset integrity work on Everest and Lomond, particularly we have Everest down at the moment doing maintenance work and long-term asset integrity work because that, we believe, will be part of the solution to a higher production efficiency in the future. So as I said in my remarks earlier on, we're going to get better production from the U.K. North Sea. I haven't put everything back in that plan and there are going to be 16 projects coming on. Two of the big ones towards the back end of the year. So that's should give you some idea. Now you're asking something else about how much we got in the back pocket on LNG guidance, we're not going to tell you that.

Lucy Haskins - Barclays Capital, Research Division

And what's the volumetric hedges this year, is this akin to where we were last year which, I think, was about 80%?

Fabio De Oliveira Barbosa

We are substantially...

Frank J. Chapman

We're substantially hedged.

Fabio De Oliveira Barbosa

Substantially hedged, yes.

Lucy Haskins - Barclays Capital, Research Division

So is the same levels?

Frank J. Chapman

Substantially hedged. Over here, please. Thank you. We've got 2 questions over here we’re going to take. Thank you.

Michael J. Alsford - Citigroup Inc, Research Division

I've got 2 questions, Michael Alsford from Citigroup. Just firstly, on QCLNG, you talked about the weighing out between sort of cost efficiency for Train 3 and resource maturation. Could you maybe give us an indication of what reserves you feel comfortable with in order to go and sanction the third train? And whether, I guess, the E&A program in Australia in 2012 is sort of, I guess, material enough to meet that target. And then just a second quick question on guidance. Obviously, unit OpEx in the upstream is quite high this year versus -- given the U.K. production downtime. Could you maybe give a guidance on whether what the OpEx might be for 2012?

Frank J. Chapman

Yes, we've got guidance.

Fabio De Oliveira Barbosa

OpEx 2012 between $9.20 and $9.60. This range.

Frank J. Chapman

Yes. Efficiency maturation, I mean, the issue here is not one of do we have enough risk resource. We have plenty of risk resource to sanction the project right away. But what is important, of course, is that amongst all of these resource you do isolate those parts of the resource base, which are going to be the most economic and make sure you do that first. And that takes quite a bit of maturation work, quite a bit of appraisal work. And then it comes down to once you've identified, that means how much you want to achieve in terms of 2P and proved reserves before you press the button. So there's no question that if you want to do a really good job on the resource maturation, be sure you get it right, then you take a little bit of a longer time to do this. The CapEx efficiencies are really supporting, just carrying on. And we need to figure that out, and we are investing substantial effort in the coming year in looking at some of these plays. I think Cooper Basin will be out of this time frame. But the other 3 plays, we're drilling right now, the exploration appraisal wells. So that's the balance. I did say and it's important to remember, that the momentum in LNG supply is coming from -- it's coming from the existing 2 trains that have been sanctioned and Sabine, that will really drive very powerfully the volume equation and the underlying volume growth in the LNG segment and the supply equation. So I'm not concerned. I don't feel in a hurry to get this thing out of the trucks because of that. And I do want to make sure that we get the right resources mature. But you can see a massive progress, a fivefold increase in reserves and resources since we started in just 2008. Good progress. There's a whole group of people -- I must have said something that is going git -- all the lights have come on over there.

Unknown Analyst

Christine Vesey [ph] from RBC Capital Markets. You mentioned that you are building the pipeline in Australia out of steel from China, and I just wondered how you deal with the quality-control issues around that. I know -- I come from an oil and gas background in Calgary, and we have definitely had trouble with steel over there. Also, you mentioned that the brownfield sites in the U.S. are 50% lower CapEx cost. What kind of sites are they? Are they currently exporting LNG sites or importing LNG and you're transferring them to exporting sites?

Frank J. Chapman

On the steel, I don't know, Chris, you want to talk about the steel?

Chris Lloyd

Yes, I can do that. We are indeed sourcing from China for the pipeline. It is gone through all the normal quality checks. We are extremely confident with the quality of the steel that we're getting from there. We don't see it as an issue.

Frank J. Chapman

Martin?

Martin Houston

Yes. On the question on brownfield. It was, indeed, they are the 4 projects or the 4 terminals that Frank talks about. Lake Charles, Freeport, Sabine Pass and Cameron, which are all in the same sort of area in the Gulf of Mexico. They're all import projects. Some of them are new, some of them are not new. But the CapEx for one train is about 50% of the capital we would deploy for a greenfield project. So it's hugely capital efficient. And of course, these are built in places where there's lots of land available. And so, what you're doing is taking a very small amount of that land and just putting liquefaction trains alongside the existing facilities, tanks, process equipment, jetties and utilities. So it's a pretty simple process.

Martijn Rats - Morgan Stanley, Research Division

It's Martijn Rats from Morgan Stanley. A lot of questions have already been asked about the LNG business looking forward. But I had one sort of slightly looking back at the fourth quarter. Can the fourth quarter earnings in LNG accelerate it quite remarkably? Yet the guidance for 2012 suggests that the quarterly run rate is going to slowdown again, which suggest that the fourth quarter was, well, perhaps then maybe a bit of a blip. I was wondering, if you could comment either on what was that temporary factor driving up 4Q? If there was none, what is the factor that's going to drive it down again going forward?

Frank J. Chapman

You're not going to get there. I'm sorry, you're not going to get there. How we do this, how we make our arrangements, the commercial arrangements we have, we're keeping all of that inside, sorry. I think we've given good, clear guidance on LNG for the year, absolutely clear. 2.6 billion to 2.8 billion is 30% more than the guidance we gave for last year, that's it. Sorry. We got some questions over the back here. We've got one more in here somewhere, I think. No? We're going to go over this side, please.

Anish Kapadia - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

It's Anish Kapadia from Tudor, Pickering, Holt. I had 3 questions please. The first one is looking actually at your LNG liquefaction business. You've got a large amount of caps employed in that business at present and that's ever-growing. It just -- it strikes me with that business, you could quite easily take a long-term offtake agreement, supply your own equity LNG, but have no interest in the actual plant, monetize that at much higher multiples than the market's willing to give you. Is that something that you've considered with your existing plants, if so, why not? And also, potentially for the Australia plant, which is in an easier location to do it. And second question is just on your exploration expenditure, it fell in, 2010 looks -- sorry, 2010 into 2011. It's falling again in 2012 as the company's been growing. Could you just comment on your kind of focus on exploration as you grow and you focus more on developments? And then the final question, going back to LNG again. In a success case in Tanzania at the end of this year, if you prove up enough LNG for enough gas for, say, a 2-train LNG plant, how will that compete with the Queensland third train in terms of your capital allocation?

Frank J. Chapman

Yes. The exploration expenditure in general and we look at the metrics for our company per production unit is quite high anyway. We're putting the money that we're seeing to good use, but it is quite a high number. And in fact, the exploration expenditure that we are planning in 2012 is higher than we have planned in 2012 last year. So when you look to the CapEx in last year's plan and the CapEx in this plan this year, it's a more exploration expenditure, not less, okay?

Fabio De Oliveira Barbosa

[indiscernible]

Frank J. Chapman

Exactly. Yes, we have to take the acquisition out. So actually, our exploration spend is going up relative to last year's plan. LNG in Tanzania, look, we just got a large number of opportunities. There are many other opportunities that were working on in the portfolio. These things are all running along. We're resourcing them and developing them. And as they mature, we have to stack them up and say, well, what have we got? We can't answer the question on Tanzania. We don't know where the site is going to be, we don't know what logistical issues around that, what community relations issues, social performance issues relate to that. We don't know what the reservoir productivity is, where -- how far away the discoveries is going to be, whether the cretaceous is going to work well. A whole bunch of issues. And so therefore, we're going to mature these things in parallel. And periodically, we're going to pause and say, now, which one's next out-of-the-box? So that's just how it works. So I can't speculate on whether this one's going to be first or second and how the economics will stack up. We're going to do the most economic thing first. When we get to 2015, as you've already said twice, I think, there will be quite a lot of need for new capital-intensive projects. Liquefaction capacity, you are -- it depends how the whole deal is being structured in the partnership. So in recent times, we have started to structure things such as all of the elements in our projects are compartmentalized, such that pieces that have a fixed income style about the assets could, at a time when the project is mature and the thing's being developed, you haven't got any large expansion sort of decisions or things, which impair a securitization, if you like, of that sort of fixed income element of the project. So we've gone away to -- a way along the road to compartmentalize elements of the projects. Say, in Australia, a large number of elements in this project have been put in their own compartments. But it's not something you can do before you've matured this thing to a point where it's in the stable operation and before you've made certain key decisions regarding expansion rights and who controls those and so on. So it's a very good point, it's something that we are definitely thinking about. But I wouldn't say anymore at this stage.

Unknown Analyst

Just in terms of your existing plans, you haven't got the right structure in place to be able to do that, say, in Egypt and Trinidad, et cetera.

Frank J. Chapman

Partly, in Egypt. In Trinidad, I think not, Martin. The way it's ranging in Trinidad is very much more traditional arrangement in Egypt will come part of the way because we have the so-called utilities and common facilities, Topco, where all of these things are organized and yet individual train co. In Australia, we've gone the whole way, with every company that -- we have an operating company, we have an aggregation company, we have a pipeline company, with all these different companies. It's a possibility. But it's not right now. We're not right now doing it. I've got a whole raft of people in the middle here. Please, in the middle?

Colin Smith

Colin Smith from BTB Capital. Just back on Sabine Pass, I think, the issue is not obviously you can provide a lot of confidence to Cheniere's bankers that you will be there with the revenue side of things. And the issues is more, whether or not they can get the project done at the kind of capital cost they are talking about, which I think was about $600 a tonne. If you look at current, recently sanctioned LNG projects, 50% of that would be pushing $1,500 or $1,800 a ton. And I think $2.25 to $3 as a throughput fee probably finances $600 with a decent return. But it doesn't finance $1,000 a tonne or north of that. So I guess my question is, if they're not able to get that project because there simply isn't enough in it for them to be able to make a return on it, would you come back and review the throughput fee that you're offering or perhaps think about other ways of financing it? And the second question I have is just to wonder if you make sure your thoughts about what you think BG's interest in non-conventional gas outside of Australia and the United States might be or perhaps I should say outside of North America and Australia might be?

Frank J. Chapman

I don't really want to speculate on renegotiations, you can just play this out, Colin. Sabine is sitting out there on the website and their hearing the Chief Executive saying if they get frustrated with their development program, we're going to pay them more. Of course, we're not going to pay them anymore. We signed a contract, they expected to deliver the contract. So that's what these guys expected to do. And by the way, we would've entered into a contract that we don't think is technically feasible. It's going to be built by Bechtel. We have a fantastic relationship with Bechtel. They've done a huge amount of work for us and we happen to believe that this is absolutely feasible. It is remarkable. You noticed some of the $1,500 a tonne at greenfield sites, in environmentally difficult place as you know is thinking about Pluto or something like that, extremely difficult. Some places you bits of the upstream rolled into it, you can identify this. This place is connected already to the network. It's got none of the gas supply issues. It's got utilities, it's got export, it's got tanks, it's got loads, it's got to have a train Co built. A Train Co is a small part actually of the overall development. So when I say, up to 50% lower CapEx, that is the case. And it might be more when you compare it with a completely greenfield like Pluto-type of arrangement. Martin, you want to say something more?

Martin Houston

I'll would just say things to that, Colin. One, 600 a tonne for a brownfield, remember, Sabine is brand new. I mean, I'm not even sure how many -- whether it has reached double-digit cargoes in terms of imports. So it's a brand-new facility. It's tons of land. I mean 600 I think is a bit toppy to be truthful. And secondly, we've got an EPC wrapped around it from Bechtel. So actually, it's quite a lot price protection within us already and I feel pretty confident it's going to be done actually. Bechtel, as you well know, build the import facility as well. So they come back into their own sites.

Frank J. Chapman

I have to say by the way, we're not paying $1,500 a tonne for our plants, nowhere near. Excuse me, microphone here please.

Hootan Yazhari - BofA Merrill Lynch, Research Division

It's Hootan Yazhari from Bank of America Merrill Lynch. Just a couple of things. You've been talking quite a bit about ramping up LNG capacity. Your aspirations in one of the slides you present seem to suggest upwards of 40 million tonnes of LNG sales by 2020. I just wanted to see what sort of focus is currently being put on marketing that gas in order to be able to achieve those sales? We've talked a lot about actually capacity out there, but do you feel that you have a huge market out there with lots of buying interest with oil-linked pricing out there continuing unabated or are you seeing some resistance there? And the second question I had was regarding Lake Charles and ultimately, taking it down the same path as Sabine Pass. Just wanted to see how far you have got with that, what are the key permitting issues, how likely you think that's to happen. So any guidance there would be very helpful.

Martin Houston

Second one first, Lake Charles, we're in pre-FEED -- sorry, my apologies. Pre-FEED in the permitting process. We're getting ready for the third filing. As you know, Southern Union has been acquired by Energy Transfer. So we've had a bit of a hiatus as that ownership transfer has taken place. But I think we expect it would hopefully be permitted by the end of the year, is what I would say. We're waiting as you know for the FERC clearance for the non-FCA countries. On the ramp up of capacity and the marketing. I mean, Frank's presentation has firmly addresses that point. We see a market in which we have a lack of supply to meet the ever-growing demand caused both by growth in market, particularly the Asian markets. But also the falloff in current supply. And if you look at that chart that Frank showed, the 2007 to 2011 with Mackenzie, what was predicted in 2007 and what is predicted now and the supplies that have rolled off, Iran, Venezuela, West Africa, Scotland and the list goes on. This is what's come back on to the list, which is a much lower, smaller number of projects. That gap is wide and it needs filling. And I think the projects we're talking about, solid projects, I mean, expansions of Queensland, East Africa if we're fortunate enough with the drill bit and the United States, robust solid projects. And of course, the great advantage we have as we're selling these stuff, is we're selling it through a portfolio where we are able as we have done many times before to create, it's a pre-wire markets through the portfolio. So we are able to offer what our competitors cannot do, which is certainty of delivery on the day. You will get this LNG today because that's when we -- because we can pull it from the portfolio. So we can give a very, very different proposition to our customers. And of course, the other thing is and the final point is that we have sold to just about everybody. I mean, out of the, I think, it's 20.

Frank J. Chapman

It's not cheap by the way.

Martin Houston

I'll come and [indiscernible] if you want. I mean, my answer to that is it’s here to stay and we're seeing no breaking and why would we, when essentially the markets are short and extremely tight at the moment. So we sold to 23 out of the 25 LNG purchasing countries. And that number, we track it all the time. So there's lots of reasons why we're confident about this. Now we're not getting ahead of ourselves selling LNG we don't have. But you can be quite sure that with the 5.5 million tonnes from Sabine, that we're well on the road to deciding what we're going to do with that. But the markets are offering us a great opportunity right now.

Frank J. Chapman

I think it's very important to point we make about pre-wiring markets, having the flexible supply. Not only can we say, don't have to worry about it coming. We can say to people, do you want it the year before the plant's finished. And then what profile do you want. Do you want 120% year 1? Do you want 50%, 100%, 75%, and they can have any profile they like basically, and we will tailor that for them. So that is a pretty unique thing, and the proof of the pudding is, have we done this? Well, in the last 3 years, we sold 10 million tonnes of LNG. 200 million tonnes actually, 10 times 20, 200 million tonnes of LNG we sold in the last 2 years, 2.5 years. So it's an example of the progress we're making. We got more questions here. Yes, please?

Paul G. Spedding - HSBC, Research Division

Paul Spedding from HSBC. You give us some details about your rig coverage in Brazil for the next 2 years. I wondered if you can go a little longer term than that, and perhaps discuss with what number of rigs you might need for 2014 onwards. And also, the degree to which Brazil rigs might feature in that. And perhaps as a follow-on, if you could comment or give us an end of term report on Brazilian yards ability to produce those rigs.

Frank J. Chapman

Yes. I mean, let me just point out to you that the program going forward does not currently include a lot of ultra-deep water, latest generation drilling rigs coming out of Brazil. For the very reason that we're trying through the development of our technology to deploy lower-cost rigs or more straightforward sections of the well. And we're also trying to develop tools that will enable us to deploy casing drilling, to deploy riserless drilling, which of course means that the weight of these long lower marine riser package does not hang under the rig and you go down from a very, very large latest generation massive rig like some of the pictures we've shown you in Tanzania, down to something -- in fact, there's one up there now. Down to something which is relatively small. You take away that 2.5 kilometers of marine riser package. You take well all the weight. This rig gets a lot smaller. So if you can get down to riserless drilling and wireline retrievable bits and drilling the casing. These sort of technologies, which we're developing tools for this, this is all being done. But now, it's a question of doing it in the water and these surfaces. We're going to get to a better place. And of course, when you have a rig that's going to drill the top hole, it's going to set the conductors. It's going to drill a bit of top hole. You have another rig that comes in that's all set up to drill the salt, and put that casing in and then it's going to go somewhere else. Somebody else is going to come in and drill the reservoir. You're going to have tailored rig. So we have to be careful that we don't over commit long term to a kit that isn't going to help us bring the cost down at some point in the future. So it's a slowly, slowly, incremental type of approach as we keep a careful eye on the technological progress we're making. Petrobras, very good, we're really holding hands on this. We've got -- if they're listening, they won't mind me saying, we push very hard on our own ideas in this area, and they have taken some of these ideas, added their own thoughts and we've come up together with a very good program. So and of course, hats off to them. They're doing a brilliant job on the drilling.

Right. I think we are pretty much there. Thank you very much indeed for your presence today, for your interest in oil, for your interesting questions. And we look forward to seeing you either on the road or in May for Q1 results. Thank you very much.

Fabio De Oliveira Barbosa

Thank you.

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