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Executives

Andrew F. J. Gould - Chairman, Chairman of Chairmans Committee, Chairman of Finance Committee, Chairman of Nominations Committee, Member of Remuneration Committee and Member of Sustainability Committee

Chris Finlayson - Chief Executive Officer, Executive Director, Chairman of Reserves Committee, Member of Governance Committee, Member of Investment Committee, Member of Risk Management Committee, Member of Exploration & Appraisal Committee and Managing Director of BG Advance

Den Jones - Interim Chief Financial Officer and Financial Controller

Malcolm Brown - Executive Vice President of Exploration

Martin J. Houston - Chief Operating Officer, Executive Director, Member of Sustainability Committee and Member of Risk Management Committee

Analysts

Jason Gammel - Macquarie Research

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

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

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

Michael J. Alsford - Citigroup Inc, Research Division

Jon Rigby - UBS Investment Bank, Research Division

Rahim Karim - Barclays Capital, Research Division

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

Lucas Herrmann - Deutsche Bank AG, Research Division

Irene Himona - Societe Generale Cross Asset Research

Peter Hutton - RBC Capital Markets, LLC, Research Division

BG Group (OTCQX:BRGYY) Q4 2012 Earnings Call February 5, 2013 7:00 AM ET

Andrew F. J. Gould

Good afternoon, ladies and gentlemen, and welcome to our fourth quarter and full year result presentation. Let me begin by congratulating Chris on his appointment as Chief Executive of the BG Group. I've known Chris personally for many years and I have great respect for what he achieved at Shell, particularly in Russia and Nigeria.

With his extensive broad industry experience, Chris is ideally placed to deliver the next phase of our strategy. Chris is aware of where we need to place our immediate focus. We all know that in the immediate future, our focus must be on delivering improvements in the performance of our existing production on our 2 mega projects in Brazil and Australia. Having been here for just over 2 years, he also knows the BG Group well. As the inside outsider, which means that in this critical delivery phase, he can hit the ground running. We should not forget in this, the underlying strengths that underpin BG's unique model, namely the incredibly successful exploration record and the unique LNG trading model. These are the hallmarks that underpin BG success, and I know Chris will continue to give his full support to these efforts.

Before we start, let me briefly update you on Fabio. His course of treatment in Brazil has now finished, and we hope that to be making an announcement in the near future. My role as Chairman is to ensure that we have the smoothest succession as possible and to assist the new CEO and the management in implementation of strategy. I'm very pleased to be able to do this, because I have no doubt that BG Group has a very bright future in front of it. Now as you know, as a consequence of the Chief Executive transition, the group strategy update will be held on May 14. And let me now hand it over to Chris Finlayson.

Chris Finlayson

Thank you, Andrew. Good morning, ladies and gentlemen, and welcome to our 2012 results presentation. I draw your attention to our legal notice, which I'll leave you to read later.

Now I'm really excited and honored to have been entrusted to lead BG Group in the next phase of its development. Most of the comments in the market have been around our short-term challenges, but we continue to have an unparalleled set of long-term assets to develop. Today, I hope to build your confidence in how we plan to address the short term and on the progress of our long-term developments. Over the next few months, I'll be engaging with investors, with stakeholders and with our key assets, reviewing the business in detail, and in May, I'll update you on our strategy and the outlook for our business beyond 2013. However, I do think it is appropriate to share with you now some of -- preliminary comments about my strategic intent.

As Andrew said, we're a company with deep commercial and technical expertise. Our strategy will continue to build on our distinctive strengths, which we believe differentiate us from the majors in the industry and that is world-class exploration, a unique LNG model and our commercial agility. We'll maintain a focused portfolio, as we've done in 2012, and we will continue to keep our portfolio under active management and review. We aim to deliver industry-leading growth in shareholder value. We expect to see significant volume and cash flow growth from Australia and Brazil in 2014 and 2015.

Right now, I understand that we need to rebuild trust, particularly in our ability to execute. And for that reason, my immediate focus and the focus today is on 2013. We have much to do this year and significant milestones to deliver.

Let me outline my priorities. First and foremost, a relentless focus on safety, and that's both personal safety and major accident hazards. Secondly, production delivery in our base assets and, in particular, in Egypt and the U.K. Thirdly, the delivery of key projects with clear quarterly milestones, including in Brazil, having a third producing FPSO onstream in Q2; and in Australia, having first gas to start commissioning the LNG plant around the end of the year.

In total, we will have 7 major projects onstream around the group in 2013. A key priority is continued emphasis on exploration, and I've increased our exploration budget for this year to $1.6 billion. I will push for the continued tight management of cost and the completion of our current portfolio rationalization program. Those are my priorities for 2013. I'll come back in a few minutes and talk about them in more detail. But first, I'm going to hand over to Den Jones, who's going to take us through our 2012 results.

Den Jones

Thank you, Chris, and good afternoon, ladies and gentlemen. As you will have seen from the release following the disposal of the majority of our Transmission and Distribution assets, the T&D segment has been discontinued. We have also taken the opportunity to move our Liquefaction businesses to the new Upstream segment to reflect the way these businesses are managed. The LNG segment now comprises the LNG Shipping & Marketing activities only.

Let's now look at the financial highlights. Against the backdrop of very strong set of results in the fourth quarter of 2011, our total operating profit in the quarter fell by 12% to $1.8 billion. Upstream is also a 12% lower as a result of a 2% decrease in production, principally due to shutdowns at Elgin/Franklin and Buzzard and higher operating and depreciation costs. LNG results were 16% lower in the quarter as a result of fewer cargoes, deliveries and lower Asian spot prices.

Cash generated from operations decreased by 15%, in line with the drop in operating profits. Lower operating profit, together with the impact of a one-off $277 million tax credit booked in 2011, resulted in a 29% drop in Q4 earnings. Excluding this credit, underlying earnings were some 13% lower, in line with the drop in total operating profit.

Moving now to the full year results. Overall, total operating profit in 2012 increased by 4% to $8 billion. The Upstream business result was in line with 2011. Our LNG business continued its robust performance and was up 13%. This was mirrored by strong cash generation from operations up 10% at $10.7 billion. Earnings were $4.4 billion, up 3%, reflecting the higher operating profits, partially offset by slightly higher effective tax rate of 44.5%, in line with our earlier guidance. The board has recommended a final dividend of $0.1426, taking the full year to $0.2614. This is an increase of 10% on last year.

Upstream operating profit after exploration expense was some $5.5 billion, in line with 2011. E&P production increased by some 3%, consistent with the guidance given at Q3. As I previously mentioned, Upstream now includes the group's LNG liquefaction activities. The group's average realized oil prices were broadly flat but realized gas prices increased by 8%, reflecting generally higher market prices and the change in the production mix. This was offset by higher unit operating costs, mainly due to higher royalties. Depreciation charges also increased as a result of the new fields coming onstream.

In 2012, our E&P unit operating cost at $10.25 per barrel of oil equivalent was in line with the guidance given at Q3, and we expect to remain top quartile when peer data becomes available in -- for 2012.

In 2013, our reference conditions, we expect our unit operating cost to be in the range of $11 to $11.50 per BOE. Our unit depreciation charge increased to $9.05 per BOE, which we also expect to be top quartile. We expect this cost to continue to increase as new projects come onstream. In 2013, we expect our unit DD&A to be in the range of $10.50 to $11 per BOE.

Turning now to reserves. Our proved reserve replacement ratio over 1 and 3 years were 176% and 217%, respectively. The chart on the right shows that the group continues to sustain a highly competitive performance.

Now moving to the group's LNG Shipping & Marketing businesses where once again we posted another year of improved results. Operating profit in 2012 now excluding liquefaction, increased by 13% to $2.6 billion. This strong performance was delivered due to higher margins from increased deliveries in Asia, offset by the associated higher shipping costs. If we add back liquefaction profits to align with the old LNG segment, operating profit for the year was $2.9 billion, exceeding the upper end of our guidance range.

LNG volumes in 2012 were 12.7 million tonnes, some 0.7 million tonnes lower than 2011, due mainly to reduction in third-party spot purchases. Supply from our long-term contracts was 11.6 million tonnes, slightly down on 2011.

Throughout the year, Asia, principally Japan, where demand remains strong due to the nuclear shutdowns, continue to be the destination of choice, offering the highest margins. In light of these conditions, the group successfully increased sales to the Asian markets by 13%, whereas sales to the fall-back destinations of Europe and the U.S. were 45% lower than 2011.

In 2013, we expect our long-term contracts to supply around 11.3 million tonnes, a reduction of 0.3 million tonnes on last year. This fall in long-term contracted volumes is principally due to lower supply from Egypt. And given current market tightness, we expect minimal spot volumes this year.

LNG sales to Singapore market where BG is the LNG aggregator, are targeted to commence in the second quarter of 2013, following the completion of the terminal facilities. As we have previously stated, the portfolio is substantially unhedged for 2013. And in Chile, the pricing has been switched to a predominantly Henry Hub-linked basis.

Overall, we expect LNG operating profit in 2013 to be in the range $2.5 billion to $2.7 billion on the new basis and at current market conditions. This is equivalent to $2.9 billion to $3.1 billion on the old basis, slightly ahead of 2012 results.

The group's net cash inflow last year was $0.9 billion. Excluding net additional borrowings of $1.2 billion, the group had a net cash outflow of $0.3 billion. The group's extensive investment program continued, with capital investment on a cash basis of $10.4 billion. During the year, 94% of the group's cash disbursements were self-funded. This was through a combination of our strong operating cash flows, together with $2.9 billion generated through the sale of non-core businesses.

Our CapEx in 2012 was slightly lower than the $11.5 billion guidance, principally due to deferred spend in Australia, which importantly doesn't impact the project schedule. The growth assets in Australia and Brazil accounted for over 60% of cash CapEx. And some 2/3 of the $2.7 billion invested in our base assets was spent in the U.K. and Egypt.

Our outlook for 2013 spend remains unchanged at around $12 billion. As with last year, spend in Australia and Brazil will account for 2/3 of the total and is expected to be around $8.2 billion.

We made excellent progress with our portfolio rationalization program in 2012. This program is refocusing our portfolio on our core strengths in E&P and LNG. We have now signed deals that will release an expected $8.1 billion of capital by the end of 2013. This will significantly exceed our 2-year $5 billion target. The highlight was deepening our partnership with CNOOC by signing a Heads of Agreement for the sale of certain interests in QCLNG, an additional LNG supply to China. We expect to close this deal around the middle of the year.

And finally, we continue to maintain a robust financial structure. This chart demonstrates our success in reducing gearing from 27% in 2011 to 24% at the end of last year, whilst at the same time, increasing our cash balance to $4.4 billion. We're also diversifying and extending our funding sources. We have increased our average maturity of debt to 17 years and have cash plus undrawn committed bank facilities totaling around $9.6 billion. Thank you very much for your attention and now back to Chris.

Chris Finlayson

Thank you, Den. Now as I said, I'd like to take us back and focus on the priorities for 2013 first.

And firstly our focus on safety. Safety is my first priority. I believe passionately that every accident and every incident is avoidable. Sadly, last year, 2 people died working for BG Group, 1 in an incident involving a supply vessel in Aberdeen Bay and the second in a vehicle accident in our Pennsylvania operations. Both incidents were thoroughly investigated and the lessons learned have been shared around the group. In Australia, we had too many minor injuries as hours worked ramped up over the year. This increased the group's overall total recordable case frequency to 2.26, well above our target of 1.35. In Australia, Queensland Gas Company has an extensive action plan to address this, including ensuring better contractor management and personnel on-boarding, and it's targeting a 50% improvement this year.

Excluding QGC, the group met its safety target in 2012 and, in aggregate, was in the top quartile in the industry. As well, though, as focusing on personal safety we're also -- in line with industry best practice -- extremely focused on our process safety and asset integrity performance. In 2012, we made good progress and had only 3 significant hydrocarbon releases recorded in our Upstream and Midstream businesses over the course of the year.

I'd like now to address concerns about the production performance in our base assets. As this chart shows, excluding Egypt and the U.K., the majority of our base assets delivered volumes in 2012 close to our budget expectations. And over the last 4 years, these assets have produced 550 million barrels of oil equivalent, and they've delivered 89% production efficiency, and after investment, have had no production decline. However, if we now add to this picture Egypt and the U.K., you can see that these assets were the major driver of our production shortfall in 2012. The reasons for this are very different.

In Egypt, the issue has been reservoir performance. In the U.K., it's been about the performance of our production facilities, and I'd like to now talk about these individually. Firstly, to Egypt where we have 2 major producing assets, Rosetta and West Delta Deep. Rosetta has been producing to plan. And as you can see from the chart, achieved good production -- as you can see from the chart, West Delta Deep achieved good production efficiency of over 90%, but we've seen production decline in recent years due to wells experiencing water breakthrough. In 2012, we drilled 9 new wells and completed the Phase 7B compression project in West Delta Deep. This added production and arrested the production decline. The wells performed, on average, close to expectation, but unfortunately, the compression project led to higher water production and lower gas volumes than planned from existing wells.

We now have a four-point recovery plan. Firstly, we're improving the predictability of our field performance, gathering more reservoir data to improve our subsurface understanding and developing a new dynamic production system model. Secondly, we are focusing on increasing production from our existing well stock, with a series of workovers and acid stimulations. Thirdly, we have sanctioned, subject to partner approval, the next phase of development of West Delta Deep. Drilling is due to start in the second quarter of this year, with the first wells onstream in 2014. This is part of our plan for 18 new wells to develop an additional 2 Tcf of gas. Finally, we are targeting near-field exploration, drilling 2 wells this year, which, if successful, can be rapidly connected to existing infrastructure.

Despite these actions, production will now decline in Egypt until the new development wells come onstream in 2014. This has been factored into our 2013 production and our long-term LNG outlook. The long-term development of BG Group's business in Egypt depends on the evolving political and business environment. We continue to monitor the situation closely and are in close contact with the Egyptian authorities.

Now as I explained, the U.K. was the other major driver of our production shortfall in 2012. The U.K. assets have continued to create significant value for BG Group. Over the last 5 years, they have delivered $12 billion of operating profit, and we've added around 200 million barrels of discovered reserves and resources to the portfolio. 2/3 of our U.K. production is non-operated and 2/3 of our 2012 production shortfall was from these non-operated assets. As you are aware, well integrity programs caused the gas leak and the shut-in of the Total-operated Elgin/Franklin production complex. This alone accounted for 45% of our total U.K. shortfall. Buzzard, too, suffered from a shutdown extended from 30 to 65 days, due to scope growth and problems with start-up.

On our operated assets, limited accommodation has meant that beyond carrying out safety-critical maintenance, we have been unable to complete all the maintenance improvements necessary to recover our production efficiency. We have been successful at addressing these issues on Armada, where we've made a step change in our maintenance program. And the improvements have been impressive. We've increased production efficiency to 82% over the last 4 years. We're now applying this knowledge to our other operated assets. We're planning large maintenance campaigns on Everest and Lomond in 2014 and 2015, using flotels to provide additional accommodation. These fields have significant remaining reserves and development potential, in line with our hub strategy.

We're also working closely with Nexen to improve production efficiency on Buzzard. With production restored from Elgin/Franklin and new production from Jasmine, we expect our U.K. production to be higher in 2013 than in 2012.

Now as I've said, we have 7 projects coming onstream and ramping up over this year. In fact, the second FPSO in Brazil has already started up. As you can see, we've provided you with the quarterly milestone guide to show you when these projects commissioned and when our major maintenance shutdowns will occur. Some projects are not within our control, most significantly the timing of the restart of Elgin/Franklin. The operator is working to a restart in Q1, and we have incorporated that assumption into our plans, but the exact timing and, perhaps more importantly, the number of wells online remain a key uncertainty.

Project contributions this year will be offset by our strategic decision to further reduce rig count in the United States, natural decline in Egypt that I've talked about, a major maintenance campaign in Karachaganak and reduced equity following the sell-down to CNOOC in Australia. On balance, I believe a range of 630,000 to 660,000 barrels a day, excluding any further disposals, reflects fairly the risks and opportunities we face in 2013. However, internally, we will continue to drive for a target of 660,000 barrels a day.

We expect production to be slightly down in the first half, lower in Q3 when we perform most of our maintenance and then grow strongly in the fourth quarter, driven by the ramp up of 2 FPSOs in Brazil and significant volumes from Jasmine and Margarita Phase 2 in Bolivia.

Given this starting point in 2013 and adjusting for the impact of the CNOOC deal, despite very strong volume and cash flow growth from Australia and Brazil in 2014 and 2015, it's clear to me that our 1 million-barrel a day target will not be reached in 2015.

My third priority for 2013 is the delivery of the key projects, and I want to focus now on Brazil and on Australia. In Australia, we made extremely good progress on the QCLNG project in 2012. In the Upstream, the fourth quarter was our best ever quarter for drilling, with 148 wells drilled, bringing the total to 1,160. The 2 new field compressor stations are now operating and 6 more are under construction. All aspects of the gas infrastructure construction are progressing well. The gas collection header mainline welding is complete and we have almost half of the gas export pipeline in the ground. The key narrows crossing to the island is also on schedule with dredging now completed.

At the LNG plant on Curtis Island, we now have 24 modules on the island and 25 in transit. We are continuing to monitor the impact of the recent flooding in Queensland. Our preliminary assessment is that our systems have worked well and the impact is limited.

Looking forward, you can see the key milestones in Australia for 2013 and 2014. In the Upstream, we expect to drill an average of 150 wells per quarter giving us a well stock of over 1,700 wells by the end of the year and more than 2,000 wells by 2014. We expect to complete the first of the 2 major water facilities in the third quarter and the first of the new central processing facilities in the fourth quarter. We expect the gas collection header and narrows crossing to be delivered in the third quarter and the export pipeline to be ready for commissioning in the fourth quarter.

At the LNG plant, all the remaining modules for the 2 Train plant are scheduled to be delivered in 2013 and all the Train 1 equipment to be installed by the end of the year. We expect to have first gas in the LNG plant around the end of 2013. This will enable commissioning to start, initially focused on the power systems. This means that we are well on track for LNG sales to start in the second half of 2014.

We've completed over half the 2 Train project and more than 60% of the scope required to fill the first Train. 94% of the project is now covered by contracts and other agreements. And consequently with significant remaining contingency and a project that is on schedule, we remain confident we will deliver within our budget of $20.4 billion.

In Brazil, we are also making good progress. We continue to see excellent reservoir performance, now underpinned by more than 65 million barrels of oil produced and the certification of BG Group's reserves and resources, which has confirmed the mid-case of 6 billion barrels oil equivalent and an upside of 8 billion barrels.

Last year, the partnership added 2 further FPSOs to its plants, meaning that 15 FPSOs with a total capacity of some 2.5 million barrels of oil equivalent per day will be in place by 2018. Drilling activity ramped up further in 2012, with 18 wells drilled and 21 well tests completed. Up to 12 rigs have been drilling simultaneously on wells in which BG Group has an interest.

Commercial production started in January this year from the Sapinhoá Field using FPSO 2. This was both on-time and on budget. FPSO 3 is on schedule to start production on Lula Northeast in the second quarter of this year. The buoyancy supported risers will be installed later in 2013, enabling full ramp up of FPSO 2 and FPSO 3. And importantly, costs remain on track with budget and a further $14.3 billion of gross CapEx was committed in 2012.

Production from FPSO 1 on the Lula Field exceeded our expectations last year. And the partnership has now produced almost 50 million barrels gross through this facility. The field has been onstream for more than 2 years and we're seeing sustained exceptional well deliverability. A single well has already produced over 20 million barrels of oil and the field is currently producing over 100,000 barrels of oil equivalent per day from just 4 wells. Our first horizontal producer well will be brought onstream next quarter. Now I have to say that compared to the best analogues that I have seen around the world, these reservoirs are truly exceptional.

The first water alternating gas injector wells started water injection into the field in October last year, and we could already see it providing pressure support to neighboring wells. And that confirms the excellent reservoir quality and the connectivity in the fields. The well will be switched to gas injection later this quarter.

The large number of FPSOs and wells in the Santos Basin will allow Petrobras and BG Group to continuously improve project execution, as processes are repeated. Wells are half the total CapEx in this development, and we have seen around a 25% reduction in drill times in 2012, as rigs and crews have gained experience. And this highlights to me the continuing potential for further cost reduction in this area. To address the previously announced delays in Christmas trees, the partnership has now contracted over 100 from international and local suppliers, which will give us sufficient stocks well into 2015.

FPSOs represent about 20% of the CapEx. The operators continue to show flexibility to source additional FPSOs to secure the schedule and to expand the development scope. These improvements give us increasing confidence in delivering these projects on schedule and on budget.

Let's now turn to exploration. My first decision, as CEO, was to appoint Malcolm Brown, our Head of Exploration, to the group executive committee, reporting directly to me. As I've already mentioned, we have increased our exploration budget to $1.6 billion in 2013. We had continued exploration success in 2012. 18 out of 19 E&A wells were successful, and that delivered a further 800 million barrels of discovered resources and, importantly, we also matured 350 million barrels of resources to reserves through our appraisal efforts.

In Q4, we completed 1 successful exploration well and the successful appraisal well around the Jodari discovery in Tanzania. This has confirmed previously disclosed volumes and given us increased confidence in our estimate of nearly 10 Tcf gross in Tanzania, with extensive further potential to be explored in our remaining prospects.

In Brazil, we drilled our third successful well on Iara, confirming our previous estimates that this field has similar volumes in place to Lula.

In Australia, we successfully tested both the Bowen coal seam gas and deep gas sand plays. Evaluation is ongoing. We grew our prospect inventory by over 20% to some 4.6 billion barrels of oil equivalent, with new licenses acquired in Uruguay, Trinidad and Tobago, India and Egypt.

So now turning to 2013. We plan to drill key exploration wells in Egypt, Brazil and the U.K. and, importantly, we expect to spud our first well in Kenya around the end of the year. We're continuing appraisal programs in Australia and Tanzania where we are currently commencing the first of 2 drill stem tests.

In Brazil on the outer field, we're currently drilling a fourth well, and plan to drill a further well in 2013 to test well designs for the development of this field. We have major seismic programs in Uruguay, Kenya, Tanzania and Egypt and, indeed, the Uruguay seismic program commenced only 6 weeks after we had signed the license. Finally, we aim to sign new licenses in Honduras, in Bolivia, Norway and the U.K.

During 2012, reserves and resources increased by 1.4 billion barrels of oil equivalent, bringing the total to 18.5 billion. Reserves and resources have grown by over 8 billion BOE over the last 5 years. That's a compound rate of 13% per annum.

So in summary, we have much to do this year in 2013, and we have many significant milestones to deliver, both in our major growth assets and in our base assets. Our mega projects in Australia and Brazil are on budget and on schedule, and we expect to see significant volume and cash flow growth in 2014 and 2015, driven by these assets. Exploration remains core to our strategy. We have significant exploration and appraisal programs in 8 countries this year against a raised exploration budget. I look forward to talking to you on the 14th of May about our strategy and our longer-term outlook. Now we're happy to take your questions. Den will join me on the stage, and we also have Martin in the audience and Malcolm in the audience for any specific exploration questions. So thank you.

Question-and-Answer Session

Jason Gammel - Macquarie Research

Jason Gammel, Macquarie. I wanted to ask, first of all, a question about the LNG volume guidance and second about how gas flows in Egypt work between the domestic market and LNG. So first on the overall guidance, 11.3 million tonnes per annum relative to 13 million tonnes per annum of contracted capacity that you have. Can you help me to understand what the difference between those 2 numbers is? And then second of all, how much of that is Egypt, and how much of it is a prioritization of the domestic market over the LNG facilities?

Chris Finlayson

Okay. The major decline over the last 2 years in total managed LNG volumes comes from the reduced amount of spot cargoes being traded. And the spot cargoes, by their very nature, have a much lower margin than those within our long-term portfolio. So in terms of the longer term, the long-term values, I think, we showed on the viewgraph there that volumes declined about 0.2 million tonnes between '11 and '12 and will decline 0.3 million tonnes between '12 and '13. The '12 to '13 movement is almost entirely driven by a decline -- a natural decline in Egypt. In terms of the split, there is a cap on the domestic take, and we are looking at negotiating improvements on that as part of our final investment decision for Phase 8a, but I can't go into more detail -- 9a, sorry.

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

Theepan from Nomura. Few questions, please. Firstly, just on Brazil, I think, last year, you talked about one of the keys for further hookups in the wells being buoyancy vessels from China. So I was just wondering where we are in terms of progress on delivery of that. Then, coming back to Egypt, I think you made a point about natural field decline. I was just wondering what assumptions you'd made for 2013 for Egypt. In terms of the payment mechanism as well, I think you've disclosed receivables of about $1.3 billion and $600 million in -- that are overdue. How does that trend through 2013? And lastly, just on exploration, the Notus well has been drilling for some time, I was just wondering when we may get a result.

Chris Finlayson

Okay. I think we can start with the last one first because it's a very -- it's a 6,000-meter well. Somebody showed the day before yesterday, we only have 3 kilometers to go. So no results for Notus yet, and it won't be for several more months. Because of the nature of the reservoir and the nature of the very small margin between overburden pressure and pore pressure, you require an awful lot of casings to get down there, as the other operators drilling in this Oligocene play have also seen. But we're on -- it's going well, but it's a long well to drill. Coming back to your question about domestic supplies in Egypt, clearly, we have -- sorry, decline in Egypt. We have built in the -- a modeled decline into our availability models for this year, so we take full account of that, both in terms of the availability of gas and also the LNG processing capacity. Now on Brazil, you talked about the buoyancy supported risers, the BSRs, and as I mentioned in the presentation, those are currently being loaded on to vessels for shipping from China. They were hoping to get them away before the Chinese New Year holiday. I haven't had an update in the last 2 or 3 days, but they're essentially on route to Brazil. When they arrive, there will then be a hookup period as we connect the steel catenary risers, which come up to the buoyancy supported -- BSRs and then the flexible links into the vessel beyond that. What perhaps is important, and I'm not sure whether this came out in the previous presentation, is that concerns about potential delays in the BSR were driven by BG's analysis of the -- of this work and led Petrobras' operator to contract for flexible risers to be installed in advance of the BSRs' arrival. That's what's allowed us to bring these -- the FPSO 2 and indeed, FPSO 3 on ahead of schedule rather than behind schedule. It's just a very good example of where we have had real influence with the operator in changing and improving plans, leading to a significant improvement in delivery.

Den Jones

On receivables that you're talking about there, we actually received more in 2012 than we actually did in 2011. So despite the political situation in Egypt, the business environment, we continue to be paid for our ongoing work there. So looking forward, we expect that to continue.

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

I'd like to come back to -- is it right to assume that [indiscernible].

Chris Finlayson

The group decline rate that was talked about last year was an overall decline rate, including investment. And as we showed you for 9 or 10 of those assets in practice when you put reinvestment in, the actual decline rate has been essentially close to 0. So yes, clearly the decline rate in Egypt is higher than the average in all of our assets. It's of the nature of these turbiditic [ph] slope sands where you get relatively rapid pressure decline within there, and you need to keep drilling to fill that on. So that's sort of, of itself is not -- is neither a surprise or a shock.

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

And then just coming back to your comment on Brazil. Let's say there may be a delay in the BSRs, would the net pushouts [ph] for FPSO 2 and 3 possibly use [indiscernible] risers?

Chris Finlayson

We are looking in that potential. There is the potential of hacking -- of hooking up additional wells using flexible risers, if that proves to be the best course to follow, yes.

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

Oswald Clint, Sanford Bernstein. I'm just curious on your comments on the distinctive strengths of BG being the LNG, the exploration and the commercial agility. What about -- you didn't mention development, and I wonder is that something -- a distinctive strength you think BG has? Or if it hasn't -- how do you intend to address that given what is to come? And the second question on Australia, please, half of your CapEx at the moment, getting close, and you did a good update today. Can we -- how comfortable can we get here that in '14, '15, '16 that we really see that chunk of CapEx actually dropping out of the group CapEx? Other larger peers aren't really showing that. I just want to get a sense of how comfortable you guys are.

Chris Finlayson

Okay. In Australia, we are very comfortable, as we've said there, that we are on schedule and we're on budget for the first 2 trains of LNG coming onstream. I think that and we -- one of the reasons we've put such a degree of detail in there was a feeling coming from the market that people expected that we had more bad news that we hadn't declared on Australia and we haven't. I think it's possibly because when we did declare our cost increases nearly a year ago now, a lot of other people have followed us after that, and I think people have possibly forgotten that we did actually talk about the cost picture early. If we look at what drives our cost in Australia, in these onshore gas sands, gas coal -- CSG sands in the east of Australia, we're as much in competition with the mining industry as we are with the oil and gas industry. And of course, mining has fallen off a cliff in Australia in terms of investments. And what we're actually seeing is quite a significant reduction in cost pressure as we -- as local contractors, civil contractors and the like have much less work to look at. So that's what gives us confidence, together with remaining headroom contingency that we already -- that we continue to have in that project. In terms of what we do with the money thereafter, you're right that Australia very rapidly comes from being a major capital absorber into a major generator of cash. And how we address that will be a key strand of the strategy work that we're doing now, which we'll be coming back to talk on in May.

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

And sorry, the first question, just on the development distinctive strengths of BG?

Chris Finlayson

Yes, I mean, I said, I think we have 3 distinctive strengths. I would argue that's 3 more than an awful lot of E&P companies had. It's -- I don't think we have a particular distinctive strength in development. If you look at our benchmarking, we are certainly better. We're in the top -- maybe top second quartile, bottom first quartile, so not in any sort of bad position. But I do think we need to do more work to strengthen there to make sure that all our projects are regularly in top quartile. So I think we're not badly positioned, but I think to be able to say that we think we have 3 distinctive strengths is a pretty good position to be in and ones where we can benchmark it in terms of times to commercialization, in terms of our overall exploration performance and the results of our LNG business.

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

Brendan Warn from Jefferies. Just 2 questions, if I can. Just firstly on -- back on exploration, there's a slight increase in the exploration budget for 2013. How much of that is a carryover from last year, from 2012? And just in terms of your risk perspective resource or risk exploration, you call it, the step-up from 3.7 billion to 4.5 billion BOE, what's the breakdown and what's the split towards, say, Australia gas and U.S. gas? And that it was around 50% of your 3.7 billion. And if you can just give us an idea -- and I'd appreciate it's a beyond 2013 -- but really there's only, what, 1 or 2 wells this year drilling that are, call it, frontier or new, your thoughts going forward for exploration?

Chris Finlayson

Okay, I'm going to ask Malcolm to answer your detailed points on that. My comment -- you say, the market forgets very quickly. I mean, Tanzania is an incredibly rapidly developing story. We've drilled, I think, 8 or 10 wells already, and we can be coming back for more later. And now people say, "What comes next?" Well, what comes next for us is actually Kenya. But we'll also be going back to Tanzania, but I'll leave it to Malcolm to answer the detailed questions.

Malcolm Brown

I think on the prospective resource inventory, it's a continually moving target. So at times, we sort of bring in some new acreage, we add some resources, we drill some things out, and there are some things we don't like anymore. So at the moment, probably the difference between 2011 to '12 was actually working up a lot of Australia -- acreage we had acquired in the previous year, but also bringing in things like Uruguay. So Uruguay is a huge acreage spread, so a lot of risk resources came in from that, also Kenya. So actually it's a continually moving mixture of things. But overall, it's a decent size increase because we've actually just gone out and picked up quite a lot of acreage, and we plan to continue doing that in the next couple of years, just refilling the hopper. The second question was?

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

Actually, I didn't ask the second question. The 1.6 versus 1.5 last year is that a carryover or is it true increase?

Malcolm Brown

It's a true increase. There's always a phasing between year-ends because it happens when it happens. So no, it's a true increase and yes, we'll be doing more things than we planned to do before, so yes.

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

And then the second question actually relates -- related to your base business in the U.K. North Sea, obviously, very non-operated. What portion of the base CapEx is North Sea demand this year? And again, I apologize, it's a May question. How do you see the U.K. North Sea core or non-core? And I appreciate it's been a good cash-generative business for you.

Chris Finlayson

Well, I think the simple answer to the second question is I would never look at it in terms of the U.K. North Sea. You have to look at it on an asset-by-asset basis and plot a way forward on that basis, and they are very different assets at very different stages of their life cycle. And we have one clear aim, which is to make sure that we maximize value in each of our assets. And as I said at the start, we will -- we don't have any untouchables. We'll make sure that we treat those in the best way possible for our shareholders. In terms of the CapEx spend, I think we say in the release the percentage of the spend on core assets is about 2/3 that we spend on the U.K. and on Egypt. And the majority of the U.K. spend this year is on the ongoing Jasmine development, which will come onstream in the third quarter.

Michael J. Alsford - Citigroup Inc, Research Division

It's Mike Alsford from Citi. Just the first question, can I -- on Brazil and I guess, the upstream portfolio more broadly. On our numbers, we get to Brazil being about 50% of upstream cash flows by 2020. I guess your initial impression is on that position. Is that -- would you see that as a high risk in terms of too much exposure to one country? How do you think about that in the context of maybe portfolio management? And perhaps, how actively do you see perhaps derisking that growth profile in the nearer future? And then, just secondly, back on to exploration, on the 4.6 billion barrels of risked resources, how much is sort of -- will be targeted with wells in '13 and maybe into '14? That will be great.

Chris Finlayson

Okay. Well, I'll let Malcolm think about that one, while I answer the first one. What we try to bring out for you in Brazil is how much we are derisking and adding value to this portfolio by our cost management activities, our appraisal activities, our well testing activities, and simply proving what an exceptional set of resources these are. So whilst I would absolutely not say that this is a "never say never" in terms of portfolio management, I'm very clear that at the moment, we are adding far more value by pursuing an effective development there than we would be by trying to show a value through a partial divestment at this time. We've looked at the other deals that have been done in the Santos Basin. And we don't think that, in any way, they reflect the inherent value that we see in our assets in that field. So we certainly have no short-term plans for portfolio management within Brazil. The other comment I would make, we're trying to bring out here how much we think that we are, in a sense, a privileged partner of Petrobras. We're their largest foreign partner, and we have numerous examples of where we have genuinely influenced the direction they're taking in terms of the development to, we think, the benefit of all parties in there. If we go down to a smaller position at this stage, we undoubtedly become less influential and more of a portfolio player. So we are convinced that for -- at this stage of development, the right thing to do is to stay there as we are and show the value of these fields, which we think will only grow. Malcolm?

Malcolm Brown

I think the -- I mean the answer on the PRI, how much we tested this year, would depend a bit on the final program because, as we just said, we've increased the budget by 200, and we're trying to bring some things forward. And at the same time, I mean, things we're going to drill this year coming, we're just getting the seismic in now. So somewhere in the order of 400 million to 600 million barrels or thereabouts, but that may grow depending on what we actually drill.

Jon Rigby - UBS Investment Bank, Research Division

It's Jon Rigby from UBS. Two questions, please, if I could. The first, just coming back onto the answer you made just now on Brazil. I don't know whether you agree or not, but I would say that common consent in this room would be that the share price is materially below any calculation of what your net asset value is. And I take the point that you'll come back to strategy in May, but is that a good starting point to think about how you're thinking about this, that in some way, shape or form, strategy has to be adjusted in order to get full value for shareholders from that asset base -- or reflect that asset base better and presumably some sort of sale process or derisking of what is currently in development would be one way of doing that. The second is just on LNG. When we think about the way that the hedges were put on in 2009 and the forward curves that existed around that time, and then we look at the current structure, both oil price and gas price that exist, it looks like a very small increase. I just wondered whether there was anything else we needed to understand about the way the margin development moves from a hedged position to an unhedged position sort of 2009 to 2013.

Chris Finlayson

Thanks. I mean, I'll answer the first question, and then Martin will answer the second question about LNG guidance. Clearly, our strategy has to be directed towards reducing what, I would completely agree with you, is a large discount to the net asset value that we see. I'm not going to commit at the moment to how we intend to do that, but we have completely aligned with you that, that's what we need to do and that's what we'll be talking about in the May presentation. And Martin, LNG?

Martin J. Houston

Yes, look, the -- you've seen that we've had a reduction in -- where's Jon? Sorry. You've seen we've had a reduction in volume, not only in Egypt -- it's very small amounts actually -- but also in spot volumes. But we've also had the Chile price switch, and I think if you just think about that for a minute, a switch from a pure oil index to sale to one, which is absolutely Henry Hub-linked. And if you think about where the Henry Hub price is today, that has been a significant impact on the portfolio. And you've seen, of course, through news reports that we have been active in trying to renegotiate some of those contracts. We have 3 offtakers in Chile, actually. The reality is that the impact of those changes against the impact of the changes with the hedges rolling off and being almost unhedged in 2013 is almost a wash, although you have seen, from the guidance that Chris has given, that we do have an uptick for 2013. So I'm afraid it's no more complicated than that.

Rahim Karim - Barclays Capital, Research Division

Rahim Karim from Barclays. Two questions. The first actually to follow up on the LNG guidance. I was wondering if you could possibly give us a little bit more color in terms of the reference conditions you are assuming for this year. Spot prices have been very strong in January, so far. Perhaps we could see some sensitivity around those numbers, so where we could look out if we were to price in $19 in Asia? And the second question was just looking at Tanzania. Obviously been a great success for the company over the last couple of years. There is a review, as I understand, around gas contracts and gas situations undergoing at the moment in the country. I was just wondering your view on that, how you think that might progress. And also, if any of the current disruptions in Towara [ph] Bay, the political and civil issues having any impact on your activities out there.

Chris Finlayson

Okay. Martin, do you want start on the gas?

Den Jones

I'll take that. Just on the guidance, the reference conditions we use the Brent's is around 110, and the Henry Hub is $3.30, so they're the kind of current reference conditions that we've used for the guidance. We're not going to give a range around different prices. You've got the ranges...

Chris Finlayson

But obviously, I mean, the second part of your question was on sensitivity to diversion to Asia and so [indiscernible]...

Martin J. Houston

I mean, look, you said this in your own question. In the summer, we saw very weak spot prices, unusually. Again, I'm sorry, what was the question? Right, we've seen prices run up to just shy of 20 in fact, so -- on a spot basis right now. So we had a big cycle throughout the year, 18 down to about 12 and back up to almost 20 again, and those are the prices we ride. But the guidance is against the reference conditions that Den has given you.

Chris Finlayson

Okay. Now with regards to Tanzania, I think, yes, I mean, we're very pleased with the speed at which we've been able to take this through from acreage acquisition, drilling and maturation into a credible resource base for a significant LNG project. I think the challenge that exists is we're working in a country which has got a very undeveloped infrastructure and a very undeveloped civic capacity to absorb major investments. What we're sure is that we do not want to get ourselves into another African country suffering from a resource curse and the issues that go along with that. And so we want to make sure we do this really well. Now to do that, it means engaging not just the current government, it means engaging civic society, the opposition, NGOs, to make sure that you build a consensus for your project. This takes time in a situation like that, particularly with things like elections upcoming. But that's what we are committed to do, because if you're going to get in a society and environment like that, a sustainable project, it has to be a project that your stakeholders in-country believe is going to give benefit to the country in the longer term. It takes more time to get it sorted out, but in the end, you end up with a project which will stick. And that's what we're trying to achieve.

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

Anish Kapadia from Tudor, Pickering, Holt. First question just on personnel issues, over the last few years, it seems like BG has transitioned certainly from market ties [ph] to more of a large-scale integrated from a smaller E&P in the past. I'm just wondering how that's changed in terms of the eyes of your employees. So in the past, you were able to attract talent from the larger integrateds. Wondering if you're seeing now somewhat of a talent drain into some of the independents and even back into the integrateds and how you're looking to address that? And then the second question is on exploration in Tanzania. We've seen from your partner, Ophir, there's some quite large prospectivity outboard in Tanzania. Just wondering in terms of your intention of going after that kind of multi-Tcf outboard potential, whether that's a short-term objective or a longer-term objective.

Chris Finlayson

Okay. Malcolm will answer the question about that productivity, the extension of the -- potential extension of the Mozambique play coming across. In terms of personnel, I think it's an interesting and a good question. Yes, the company has changed. Clearly, we are no longer a small E&P company, and of course, we've all benefited from that transition. We're also now a company where a single exploration well result doesn't significantly move the dial. We have to look at the bigger scale projects and that, of course, is what we have done. Does that mean that we have defocused on exploration? I hope we've shown you that, that is absolutely not the case. So I think that for the explorers, we can still offer a very attractive opportunity to make a difference in a short period of time, and that, if you like, has been our traditional value proposition for people on pulling on them from the majors. The fact that they can come in and have their well identified and drilled in a much shorter period of time than they perhaps could with one of the big integrateds. So I think that value proposition stays in place. But in a hot market, so, yes, we've been certainly lost people that we would've preferred not to lose. We've also managed to attract people that we wanted to attract. So that's a challenge, but I think one we can address. As coming back to a previous question, I think on the development side, yes, we do need to attract more development talent, particularly in the front-end engineering side to the company, and that's very much a focus that we have at the present time. And now Malcolm, Tanzania exploration.

Malcolm Brown

Yes, in Tanzania, as we've said, things have been moving very quickly. We only got in there in June 2010. We drilled 9 wells, 7 discoveries, 2 appraisals. We're currently doing 2 tests, and we shot 3 3Ds. So at the moment, there's an awful lot of work going on in deciding what to do next in terms of the remaining slots on the program. So we're going to test Jodari. We're going to test Mzia, as in DSTs, flow tests, and then we've got a couple of slots at the end, which we're just debating what to drill with those 2 slots on the rig. So at the moment, it's work in progress, analyzing a whole lot of data. And we haven't decided what to do next, and I think our partners are also going through the same process of actually just absorbing the data we have. So we'll finish up with this rig in June, and that's what we expect to do because we need a break to catch up on the seismic, and then we'll come back and do some more drilling after that.

Lucas Herrmann - Deutsche Bank AG, Research Division

Lucas Herrmann at Deutsche. 2 or 3, if I might. The first is -- I mean, you've got interesting experience on LNG. You've lived through Sakhalin. You've now lived through Australia. Maybe this is a question for Martin, but how important is it for you to have involvement in upstream to be able to capture the market opportunity or the trading opportunity, which is where the excellent returns you're achieving are being made? Do you need a presence? Do you need to put capital in? Or do you feel that your business is now of a scale and you've got sufficient market clout to capture opportunity without?

Chris Finlayson

I think, if you look at our forward portfolio, you can see how we're trying and I think succeeding in playing in both areas of that. We have a traditional Australia integrated project right through to the market. And then, the Cheniere venture in the U.S., followed by Lake Charles will both be capital-light entries while we will be a major offtaker of LNG. But we will purchase on the market -- on Henry Hub in the States. I think that's an exciting capital-light way in which we'll able to significantly expand our LNG business. So I think both is the answer to your question.

Lucas Herrmann - Deutsche Bank AG, Research Division

Okay. Secondly, in the U.K., can you just talk a little bit more about the outlook for your operated assets? I mean, I can see very clearly the issues with Buzzard or the issues with J-Block, et cetera. It's much harder for me to get a perception at the present time of what's actually happening with Everest/Lomond, greater Armada and how you see those moving forward. So just some indication of how you expect production to progress '13, and I'm going to ask you to go slightly beyond but...

Chris Finlayson

Well, the picture is different between the different assets. If you look at Everest, the east Everest expansion project is one of our major projects to come onstream, should be coming on during the first quarter. And that will essentially fill the facility for the next couple of years. Both Everest and Lomond still have remaining very significant hub potential, new fields that can be taken through there. We're still moving forward with the Lomond bridge-linked platform project to tie third party and our own volumes into that platform. So in both of those fields, I see significant potential for continuing to execute our hub strategy. Armada, we have a high-efficiency operating platform. There is less scope around that platform and we will -- that will clearly be something we need to take account of moving forward.

Lucas Herrmann - Deutsche Bank AG, Research Division

And is that scope undermined further by what's happening with Gaupe and the delivery of production from that field?

Chris Finlayson

Not necessarily undermined by Gaupe, simply by the geology of what we see in terms of other fields around them.

Lucas Herrmann - Deutsche Bank AG, Research Division

Okay. And sorry, finally, just to clear up, LNG reference conditions, your reference condition is 100. But in terms of the LNG forecast, you've been using 110. Is that correct understanding?

Chris Finlayson

That's right.

Irene Himona - Societe Generale Cross Asset Research

Irene Himona, Societe Generale. I had 2 questions, please. First of all, if you could possibly update us on the U.S. situation in terms of shale gas drilling. Is the JV drilling at all or what's happening there? Secondly, you highlighted an ongoing active review of the portfolio, but is there a specific asset disposal target for 2013, following the $8 billion you've already completed?

Chris Finlayson

Okay. I mean, I think to answer -- the second one can be answered very briefly. At the moment, our target is to complete the $8 billion that we've targeted. I sometimes feel that, that has got slight -- the scale of that has got slightly lost in the other noise that's been going on for the last few months. I mean, that is a very significant number of transactions. It is about 14% of our asset base, which we will have turned over in a period of less than 2 years. So I think it is quite an achievement by our M&A department on its own. We have not yet defined any targets beyond that, and that will be a part of the work leading up to the May strategy. I'm sorry, your second question was?

Irene Himona - Societe Generale Cross Asset Research

U.S. shale gas.

Chris Finlayson

U.S. shale gas. Well, we've always said with U.S. shale that this was an asset where we had the opportunity to turn up or turn down activity based on the prices that we saw in a short term. Now clearly, prices fell further than we had anticipated was going to be likely, and that led us to making the write-down in the first quarter. But where we are now is with an asset where we do have at the moment, 3 to 4 rigs drilling, so we have some of the best areas of the Haynesville we're still drilling on, and we're still carrying out some delineation and appraisal activities in the Marcellus to prepare ourselves for what we still anticipate to be an upturn in U.S. gas prices, which will allow us to move to a stronger level of development activity there. We do believe we are well placed with the acreage we hold, in that we are in the best areas of the Haynesville and have -- also have access to some of the best areas in the Marcellus. So provided the price comes to a sustainable level, we will -- we should be able to move on drilling early. But we're treating it as we said we'd treat it, as a resource we can turn up and turn down.

Peter Hutton - RBC Capital Markets, LLC, Research Division

Peter Hutton from RBC. You've taken the opportunity to write down the production target for 2013 to 630,000, 660,000. First question, is there -- other than the timing of Elgin/Franklin, is there anything operationally that you see now that you couldn't have seen at the end of Q3 when it was 660,000 to 670,000? Or is there just a correct element of caution introduced? And the second one is there's no -- you haven't taken an opportunity to write down some of the assets in the fourth quarter, particularly, and yet, for example, your partners in Gaupe have done that. Is that because you've looked through and you're very comfortable in the quality of those? Or is there something that we might still expect to come?

Den Jones

Gaupe, we have written down. Look at the release, it says in the release, we have written it down. To say we haven't is not correct -- we have written it down.

Chris Finlayson

That's what I thought. But to your first question, I think that when we looked at the 660,000 that we had in -- at Q3, and we said -- well, actually, we didn't say 660,000. We said broadly flat, so that implied some form of a range around 660,000. We wanted to give a good range that we believe we could deliver in. We looked at the number of variables that we had. We've tried to show you what the extensive number of variables we have in terms of new project delivery, as well as the timing of Elgin/Franklin. Elgin/Franklin is indeed the single largest uncertainty on there in terms of straight volumes. But also, for instance, in Jasmine, an outcome where the top side sailed around the North Sea for 2 months because of this bad weather versus one where we get it on within a couple of days gives you a pretty significant change in outturn as well. And the rate at which we get the connections made to the FPSO 2 and FPSO 3 in Brazil, because they're very big wells, an individual well can actually have a significant impact on our outcome as well. So we've done statistical analysis. We've looked at event-based analysis. We've tried to share with you what those main events are. Our belief is that a proper range within which we should be able to deliver is this 630,000 to 660,000. Now as I've said, in turn, in terms of target setting, everything we continue to set within the company, people to deliver -- set to deliver volumes that meet that 660,000. But we think that, in terms of guidance, it's much more appropriate to give the range.

I think we are questioned out, so thank you, all, very much indeed for coming. And I look forward to meeting with you again after the strategy presentation -- or at the strategy presentation, I should say, in May. So thank you, all, very much indeed.

Den Jones

Thank you.

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