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Executives

Chris Finlayson - Chief Executive Officer, Executive Director, Chairman of Governance Committee, Chairman of Investment Committee, Chairman of Exploration & Appraisal Committee, Member of Chairmans Committee, Member of Sustainability Committee and Member of Finance Committee

Simon Jonathan Lowth - Chief Financial Officer and Executive Director

Analysts

Peter Hutton - RBC Capital Markets, LLC, Research Division

Jon Rigby - UBS Investment Bank, Research Division

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

Frederick Lucas - JP Morgan Chase & Co, Research Division

Alejandro Demichelis - Exane BNP Paribas, Research Division

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

Martijn Rats - Morgan Stanley, Research Division

Michael Ridley - Mizuho International plc

Neill Morton - Investec Securities (UK), Research Division

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Lydia Rainforth - Barclays Capital, Research Division

BG Group (OTCQX:BRGYY) Q4 2013 Earnings Call February 4, 2014 7:00 AM ET

Chris Finlayson

Thank you very much, indeed, ladies and gentlemen. We do realize that there are competing attractions today, so the intention is that we will do our Q&A until around 1:30 for those who need to get back to their offices. But we will be around downstairs for those who want to stay around and ask further questions.

So good afternoon, and welcome to our fourth quarter and full year presentation. For those who haven't yet had the opportunity to meet him, I'd like to introduce Simon Lowth, our new CFO. Please, can I draw your attention to our legal notice, which I'll leave you to read later on?

We continue to pursue the strategy we laid out in May, and our long-term growth story remains in place. BG must be a company that delivers on its commitments each and every year. I've talked to investors and analysts since we updated our 2014 and 2015 outlooks last week.

I understand that, indeed, I share the frustration and disappointment that you feel. We have made progress in 2013, delivering our key project milestones and growth projects. But in 2014, we have significant challenges in Egypt, which has led us to declare force majeure; and in the U.S., where the gas forward curve does not yet support higher levels of drilling activity. Despite this, I am disappointed in our lower production outlook for 2014 and 2015 and its impact on unit costs.

Today, we are giving very clear guidance for 2014 on production, unit E&P costs and LNG Shipping & Marketing total operating profit. We will keep the investor community fully informed of our progress. My top priority is to execute our plans consistently and effectively, especially the commissioning of QCLNG in Australia later this year. I am pushing change through the organization, and we are clear what we need to do.

But first, safety has always been my highest priority and will continue to be so. We have made progress in this area and beat our group total recordable case frequency target in 2013. But the major achievement is clearly in Australia. What is most impressive is that this improvement was during a period of intense construction activity. On the asset integrity side, I'm pleased also to say we had no Tier 1 hydrocarbon releases. These achievements show what can be done when the right level of management attention is applied to safety. But safety gains can be ephemeral and can be lost. And sadly, we have suffered 1 fatality in December, a contractor employee making an unauthorized motorbike journey. A stark reminder to all of us, but nothing is worth doing, if it can't be done safely.

I'll now hand over to Simon, who will take you through our 2013 results. And then I will describe our 2014 outlook and milestones.

Simon Jonathan Lowth

Chris, thanks very much indeed. And good afternoon to all of you.

So I'm going to start with a brief summary of our financial results for the fourth quarter and the full year 2013 and a description of the key drivers of the profit movements in both the Upstream and the LNG segments. I'll then review the progress of our portfolio management strategy before summarizing our cash generation and deployment for the year. And finally, I'll describe the development of our reserves and our resources' position during 2013.

So let me start with the financial results for the fourth quarter. Business performance operating profit was up 4% to $1.9 billion. Upstream operating profit fell 4% to $1.1 billion. Operating profit in the LNG Shipping & Marketing rose 18% to $778 million. Net operational cash flow rose 27% to $2.1 billion due to the higher cash profits in the quarter. Business performance earnings per share were up 10% year-on-year to $0.333, reflecting the higher operating profit and the lower tax charge. Reported earnings per share, however, were negative $0.313, due mainly to the U.S. and Egypt impairments recognized in the quarter. And I will describe these in more detail shortly.

For the full year, business performance operating profit was down 5% to $7.6 billion. Upstream operating profit fell 9% to just under $5 billion. LNG Shipping & Marketing operating profit increased by 3% to $2.6 billion. Net operational cash flow was down slightly at $7.8 billion. Business performance earnings per share, flat year-on-year at $1.286 with a lower tax rate of 41% offsetting the operating profit decline.

As we announced last week, we expect our 2014 effective tax rate to be around 41%. Reported earnings per share were 33%, down at $0.648, reflecting the fourth quarter impairments. As we announced last week, our reported results for 2013 include 2 asset impairments totaling $2.4 billion posttax. We've reported a posttax impairment of $1.3 billion in relation to the group's Upstream assets in Egypt. This reflects reserves revisions and revised expectations of the value of our Egyptian operations given the deterioration and the continued uncertainty in the business environment in the country.

The revised pooling arrangements for 2013 have not been honored. And as a result, we've been unable to meet in full our obligations to deliver gas to Egyptian LNG. So given this and the continued uncertainty around the level of future diversions, we've declared force majeure under our LNG agreements.

Now the position on domestic receivables improved during 2013. Year-end receivables balance was $1.2 billion, that's $0.1 billion lower than at the start of the year.

Now moving to the U.S. We have recorded a posttax impairment charge of $1.1 billion. This is a result of lower production expectations based on well performance and a continued low rig count combined with lower forward gas market prices.

So let me now turn to the drivers of the movement in Upstream profits, and I'm going to start it with volumes.

Total E&P production in 2013 declined by 4% to 633,000 barrels of oil equivalent a day. Contribution from our base assets declined by 6% to 569,000 barrels of oil equivalent per day, driven principally by reductions in the U.S. and Egypt.

Now the base asset decline was only partially offset by the production contribution from new developments coming onstream. These included Everest East and Jasmine in the U.K., Bongkot in Thailand; the new phases, such as Margarita and Itau in Bolivia. Of course, in Brazil, production grew driven by the 2 new FPSOs.

Upstream operating profit declined by 9% to just under $5 billion. Here, the improving mix, including a higher proportion of oil, increased revenues by $744 million compared with 2012. However, this mix benefit was offset by the impact of the year-on-year production declines and increase at E&P costs and higher exploration and business development charges.

E&P costs increased year-on-year by $683 million to $6.3 billion. Now before explaining the detailed drivers of the cost movements, let me just start by emphasizing 2 points. I mean, firstly, the increase in costs is primarily, but not wholly, a byproduct of strategic choices that we have made to invest in growth assets. Secondly, the higher costs will be more than offset by higher unit revenues as these growth assets ramp up to full production.

So now let me turn to the individual costs. Lifting costs increased year-on-year by $175 million, driven by the cost of new developments coming onstream, most notably in Brazil, and the investment that we're making in the enhanced asset integrity program in the North Sea. Royalties and other operating costs, well, they rose by $169 million due to the growing revenue contribution from royalty paying assets, such as primarily Brazil and Bolivia.

Now Brazil, we pay a 10% royalty and special participation tax. And that's charged from a sliding scale, but rates up to 40% on revenues less allowable costs. In Bolivia, we pay a royalty fee, which equates to around 50% of turnover.

Now other E&P costs, well this includes production costs not directly incurred in the fields that, that might include cost of shipping, our [ph] Brazilian oil and third-party gas supplies in Australia. So those, together with preproduction costs and corporate overheads, attributable to the E&P activities sit in other E&P costs. Now these costs declined by $92 million in 2013, but we expect them to trend upwards in the midterm as oil shipping costs increase on the back of production growth in Brazil and the cost of third-party gas supplies rise during the ramp-up in QCLNG. DD&A, that increased by $431 million due to the combination of new developments coming onstream, notably Brazil, and then reserves revisions, particularly in Egypt and the North Sea.

So I'll now explain how these movements in absolute costs could have impacted our unit costs. And then given realized prices, how they impacted cash and profit margins. I can assure that development of unit costs for the period 2011 to '13 to draw out the trends for you.

Now unit lifting costs have increased by about $1.40 per barrel of oil equivalent over the past couple of years. And this reflects the cost of new developments and our asset integrity program, but also combined with some production declines in our base assets. The upward pressure on lifting costs will reduce as the new growth assets ramp up to full production. The unit cost of royalties and other OpEx, they've increased by about $2 a barrel as a result of the growing contribution from royalty-bearing fields in our portfolio, notably, Brazil and Bolivia. Unit royalty costs, well, they'll continue to trend upwards as Brazil grows. But clearly, they will be matched by the higher realized prices on the Brazil production.

Other E&P costs have declined by about $0.40 per barrel over this period. Unit DD&A charges, they've increased about $3.60 a barrel since 2011 due to the combined impact of new developments coming onstream and the reserve revisions. The upward pressure on DD&A costs should also reduce as new growth assets ramp up to full production.

Now while unit costs have increased, this has been largely offset by an improved revenue mix, including the increased proportion of oil in our production portfolio. We see average unit revenues increased by about $5.40 a barrel, resulting in an improvement of around $2.40 per barrel in our EBITDA margin, but a decline of around $1.20 per barrel in our EBIT margin over this period. Looking ahead, we continue to expect margins per barrel to improve over time through the combination of an increasing proportion of higher-margin assets in our portfolio, longer-term production growth to leverage fully that fixed cost base and a clear focus on cost efficiency and productivity.

Moving now to the LNG segment. Operating profit in the LNG Shipping & Marketing business increased by 3% to around $2.6 billion in the year. Increased sales to high valuation markets and lower hedging losses offset a reduction in the number of cargoes. And overall, we delivered 19 fewer cargoes in 2013 than in 2012, with the reduction principally from Egypt and Nigeria.

Active portfolio management. Well, it's an important component of our strategy. And in 2013, we completed 4 major transactions that, along with some smaller deals, released almost $4.8 billion of capital, of which about $200 million is deferred consideration. When combined with our 2012 activity, total capital to be released from our divestment program in 2012 and 2013 amounts to $8.5 billion.

Turning to cash flow. So net cash flow from operations decreased just slightly to $7.8 billion due to the lower cash profit and higher working capital outflows, the latter mainly the result of lower cash margin core inflows on our hedged LNG contracts, cash outflow and investing activities, including our cash capital expenditure of $11.2 billion, partially offset by dividends, loans repayment from JVs and associates.

Net interest was up slightly at $560 million, leaving a net-free cash flow of $3.6 million outflow. Cash proceeds from disposals totaled $4.6 billion in the year. And this, combined with additional net borrowings of $1.7 billion, increased our cash and cash equivalents by $1.7 billion after paying dividends just over $900 million. At year end, we held $6.2 billion in cash and cash equivalents. And our net debt and gearing flat year-on-year at $10.6 billion and 24.8%.

Now reserves and resources decreased in 2013 by 790 million barrels on an SEC basis. We monetized more than 1 billion barrels during the year, 231 million barrels through production and another 860 million barrels through disposals, principally the QCLNG sell-down to CNOOC. We had another good year in exploration in 2013. We added 157 million barrels to our perspective resources. In Tanzania, we continue to make good progress, increasing total gross recoverable resources by 50% from last year to around 15 tcf. Our organic reserves replacement ratio on SEC management was 115% on a 1 year basis and 179% on a 3 year basis.

Now from 2013, we're adopting for [ph] reserves reporting the internationally recognized Petroleum Resources Management System published by the Society Petroleum Engineers in line with the European securities and market authority recommendations. Change in definition has had little impact on our total reserves.

So in summary for 2013, we held our business performance, EPS and our net debt flat year-on-year, with an improved revenue mix and lower tax rate, largely offsetting lower volumes and the impact of increased operating and capital expenditures that will drive future growth and value. Taking account of the outlook for earnings, cash flow and the balance sheet position, the board has recommended a final dividend of $0.1568. And this takes the full year dividend for 2013 to $0.2875, that's an increase of 10% on last year.

So thank you very much indeed for your attention. I'll now turn it back to Chris.

Chris Finlayson

Thank you very much, Simon. When I set out our long-term strategy in May to build on our strengths in exploration in LNG, I also talked about some of the things that we needed to do differently.

I've invested a lot of my personal time in this over this past year. I've taken action to simplify the organization, established consistent processes across the group and embed a culture of clearer personal accountability. But I recognize that we have more to do to embed this change throughout the organization. I and Simon are determined to improve the cost and capital efficiency of our base assets and have increased the pre-sanction challenge and the scrutiny of all projects. Furthermore, a rigorous challenge to the later years of our business plan took place with my personal involvement as part of our 2014 process. We have a robust set of numbers, not only for 2014, but also for 2015.

Let's now look at our 2014 production outlook. In 2014, BG Group's production volumes are expected to be in the range of 590,000 to 630,000 barrels of oil equivalent per day. Base assets will contribute in the range of 480,000 to 520,000 barrels a day, excluding any portfolio changes. Brazil and Australia will deliver strong year-on-year growth, which will be offset by declines in Egypt until Phase 9a comes onstream in Q3 2014. Additionally, the continued low rig count in the U.S. will result in a volume decline similar to that of 2013. Overall, the volumes from our other base assets are expected to be broadly flat. Production will grow in the U.K. as Jasmine ramps up to capacity over Q1, but this growth will be offset by declines to the rest of the base.

Importantly, gross production in Trinidad and Tobago will remain on plateau, but we expect our entitlement under the PSC to fall due to higher realized prices in 2013. There's a marked seasonal profile through the year, with maintenance planned to be in the second and third quarters and a strong ramp-up in Q4 as a number of new assets come onstream.

Looking ahead, based on the production volume range for 2014, we now expect the 2015 to be in the range of 710,000 to 750,000 barrels of oil equivalent per day, again, excluding any portfolio changes. And we have an increased confidence in this 2015 range following our rigorous multiyear planning challenge. The rebound in volumes in 2015 will be led by growth from Brazil and Australia.

Earlier, Simon took you through the drivers of E&P costs and margins in 2013. I will now provide our E&P cost guidance for 2014.

We expect our unit OpEx cost to rise to between $15.50 and $16.25 per barrel at referenced conditions. Unit lifting costs are expected to rise as a result of our enhanced asset integrity program in the U.K. and continued build-out of capacity in Australia and Brazil, combined with lower production volumes in our base assets. Other unit OpEx costs, principally royalties, will rise as a result of the growing proportion of royalty-bearing revenues, principally in Brazil and Bolivia as Simon has explained. We expect unit DD&A to increase between $12.25 and $13 as we bring new developments onstream, notably in Australia and Brazil, and with Jasmine and Knarr in the North Sea.

As we described in September, the outlook for the global LNG market remains tight. New projects across the industry continue to be delayed or deferred. And demand, particularly from Asia, will continue to increase.

Turning to our own portfolio, there is considerable uncertainty over the number of LNG cargoes that the Egyptian LNG will produce in 2014. But we expect there to be lower supply volumes from Egypt, and our reference conditions are lower than realized prices in 2013. However, we believe that we have sufficient flexibility in our portfolio to honor all of our customer obligations. Due to the reduced numbers of cargoes from Egypt, we expect our operating profit to be in the range of $2.1 billion to $2.4 billion at reference conditions, and we will be fully unhedged after Q1. As a reminder, the majority of the profits that accrue in Australia will be reported in the Upstream segment.

Turning to our 2014 priorities. Our relentless focus on safety will, of course, continue. But our key deliverables this year are: to commission QCLNG, and we remain on track to deliver first LNG in the fourth quarter of this year; to grow Brazil volumes, which will mean more high-margin oil in our mix; to deliver our other key project milestones; to continue our extensive exploration program and advance our new LNG supply options. We will do all of this with a slightly less capital than we used in 2013. And the group has now passed its peak year for CapEx, and I now expect it to trend downwards. These priorities will enable us to deliver our significant growth plans next year, and we remain on track to be cash flow positive in 2015.

Let me now take you through the start-up process for our critical QCLNG project on a quarter-by-quarter basis. Firstly, in the Upstream, drilling is ahead of schedule. Then throughout the year, as you can see from the chart, we will start up a series of Field Compressor Stations and central processing plants at Ruby Jo and Bellevue.

At the liquefaction plant on Curtis Island, construction is now in its final stages. In Q1, we will complete the first LNG tank hydro test. In Q2, we will start commissioning the gas turbine generators. And we'll then begin commissioning Train 1, leading to the first commercial cargo in Q4; and Train 2, about 6 months later. So we will ramp up QCLNG to plateau over the period of 2014 to 2015.

One challenge with coal seam gas is that you have to dewater the wells with 6 to 12 months before they reach peak gas production. In order to optimize our Upstream production profile and maximize value during this ramp up, we have contracted gas from third-party suppliers during the commissioning phase. Between 2014 to 2016, we expect third-party gas to make up some 10% to 20% of supply to the plant. And we have commercial arrangements in place at attractive prices. At plateau, we expect third-party gas to comprise only some 5% of supply.

Let's now look at Brazil in 2014. We plan to add substantial new capacity this year, starting with well hookups for FPSOs 2 and 3. After a period of weather delays, the buoyancy supported riser on FPSO 2 at Sapinhoá is now fully installed, 2 wells are connected by steel catenary risers. And the first umbilical jumper was finished over the weekend. The operator expects the first well via BSR to be producing later this month. And we anticipate that FPSO 2 will reach plateau by midyear. The BSR on FPSO 3 on Lula Northeast was fully tethered over the weekend. We'll begin adding new wells in the coming months and expect to reach plateau with 5 or 6 producing wells.

FPSOs 4 and 5 are due to be deployed on Sapinhoá and Iracema. They are on budget and around 88% and 80% complete, respectively. Both are now in Brazil for top sites integration. And the operator expects to install these facilities on schedule in the second half of this year.

Meantime, we continue to focus on reducing drilling times. In 2013, our drilling time for development wells was reduced to 56 days from 69 days in 2012. There is considerable drilling in advance of FPSO installations. And so far, 44 development wells have already been drilled that will service FPSOs 1 to 6.

On this slide, you will see our other 2014 key project milestones. Clearly, it's weighted towards Australia and Brazil, but also shows you the milestones on a quarter-by-quarter basis. You will be able to track our progress against these as last year over the year. As I mentioned earlier, a number of new projects are due for starting up in Q4.

Now turning to 2014 exploration. We have a lot of important exploration and appraisal activities planned this year in new basins and existing hubs. Much of it will be advancing new prospects, particularly in Uruguay, the Barinas Basin in Brazil and Honduras. Additionally, in January, we acquired a 30% equity interest in Gujarat offshore for third -- 3 blocks offshore Colombia and 3D seismic is planned there this year. We anticipate this activity to provide high-impact drilling opportunities in 2015 and beyond.

In terms of frontier exploration, we spotted our first well in Kenya, and we are currently drilling. In Egypt, we have discovered a number of gas zones that we're evaluating at the Notus well. If commerciality is established, we'll consider development in the context of the overall investment climate in Egypt. We continue to pursue exploration and appraisal opportunities in Tanzania. And while we have discovered resource sufficient to support 2 LNG trains, we want to optimize the field development plan further.

In Australia, we are pursuing independent exploration plays to extend and potentially expand our coal seam gas projects. We're targeting shale gas in the Cooper Basin, deep gas sands in the Bowen and coal seam gas in the Surat Basin.

Sabine Pass is our next source of supply after Australia. Construction is on track, and the plant is scheduled to go into service in early 2016. This will, over time, add 5.5 million tonnes of LNG supply to our portfolio as the project ramps up.

I'd now like to take you through our future LNG options. At Lake Charles, we achieved a key milestone with U.S. Department of Energy approval to export to non-FDA countries. We've now entered into a project development agreement with a terminal owner, Energy Transfer, and will develop and operate the plant on the U.S. Gulf Coast.

As with Sabine Pass, we will not contribute upfront capital to this project. We expect to make our Federal and Energy Regulatory Commission submission in 2014. In Tanzania, in addition to adding significant gas resources for the project, we have submitted, together with the partners in Block 2, a proposal for an LNG site to the government. In Canada, the Energy Board gave a favorable decision on the approval for the Prince Rupert project to export LNG. We're progressing pipeline permitting and exploring partnering opportunities. I would remind you that while we are currently advancing these 3 LNG projects, we will not take them all to sanction at current equity levels.

Now turning to more active portfolio management, which is the key element of our future strategy. As we've said, we aim to monetize through production or disposal up to 50% of our discovered resources in the next 10 years and create a focused portfolio of 10 to 15 high quality and material assets. We made a good start in 2013 and have monetized around 6% of our resource base. We'll monetize assets at different stages in their life cycle, bringing in partners to accelerate delivery. And we'll recycle capital into new high return early-stage growth, and of course, return cash to shareholders.

We've clearly demonstrated in the last 2 years that we have the capability to actively manage our portfolio. Our divestment program is ongoing, and we continue to explore options to reduce our capital employed. For example, we're pursuing the sale and leaseback of some of our LNG ships. And in Australia, we're looking at the further sale of infrastructure, such as pipelines and water treatment plants. However, we will make disposals at the optimum time to capture the best value.

2014 planned capital expenditure on a cash basis is expected to be slightly lower than 2013, with around 70% of our CapEx committed to Australia and Brazil. The group's CapEx is expected to fall to between $8 billion to $10 billion in 2015 and 2016, with Brazil averaging around $3 billion per year through to 2018. We therefore anticipate that we have passed our peak year for CapEx.

So in summary, 2014 will be a key year for BG. The delivery of QCLNG on time is critical. Our priority remains delivery. We have clear key project milestones and are committed to remaining on track, not just in 2014, but also in 2015. We'll continue to pursue our value strategy and active portfolio management, looking for more opportunities to generate value and to simplify the company. The long-term growth story for the company remains in place. Our growth projects in Brazil and Australia continue to make good progress. And we expect to be free cash flow positive in 2015.

Now, Simon and I are happy to take your questions. Thank you.

Question-and-Answer Session

Peter Hutton - RBC Capital Markets, LLC, Research Division

Peter Hutton from RBC. Given that you, as you say, wanting to provide clearer milestones for 2014, just a couple of couple of follow-up questions. On Page 26, you're giving, you give the next phases of the next wells on FPSO and 2 and 3. I think you mentioned in your comments when the wells after that and when they would be -- that you expect them to reach plateau. Could you just clarify that one because I'm not sure I or everybody got that? And the second question is on QCLNG where you mentioned that in 2016, the third-party gas would contribute 10% to 20% of the supply into the plant. And that plateau, that will be 5%. So is it too obvious to assume that by 2016, you're running -- you put -- read across those 2 and you see that the plateau is still quite some way -- the production is still quite some way to go to plateau?

Chris Finlayson

Well, no is the answer to the last question. Coming back to the Brazil milestones. So second well on FPSO 2 by the end of February. The third well should follow shortly thereafter. I mentioned that with 2 steel catenary risers already installed, so they have to go back and install a second umbilical jumper across the vessel. And then there will be a gap of, I think, 2 or 3 months before a fourth well is completed. So we are saying that FPSO 2 on plateau by around the middle of the year. FPSO 3, a difference of slightly less productive areas, so probably an extra 1 or 2 wells to connect. But again, we're making good progress. The BSR fully installed, and we will be -- the next stage being after we have finished finally de-ballasting the BSR. We will then start connecting up wells to that as well. So 5 or 6 wells to go, you're probably looking towards the end of the year.

Peter Hutton - RBC Capital Markets, LLC, Research Division

[indiscernible]

Chris Finlayson

Yes. Then turning to QCLNG, I mean there has been a lot of comment about our third-party reliance or not coming in from this. And I try to give a lot more color as to what this means for this. Just perhaps to give a little more background, we'll have the wells stock that we said we would have before we started producing. And the average deliverability of the type curves on those wells are in line with what we anticipated. The challenge is that for these wells, you have a fairly extended build-up period as the wells dewater. And over that time, you have an opportunity, whilst your own capacity builds up, to actually take additional gas in if people have dewatered wells or wells, or gas from other sources that they can bring in there.

That gives us an opportunity to get more gas more rapidly through the plants. So that's an opportunity we are taking. We have gas from a number of sources. We have prices for that which are very attractive for us to do so. And I think the key point is the one that you raised at the end there that as you look out into 2016, when we anticipate to be reaching plateau on the -- on QCLNG. We only expect the contribution at plateau at the moment to be around 5%. The rest will come from our own resources.

Jon Rigby - UBS Investment Bank, Research Division

It's Jon Rigby from UBS. Can I ask some -- 2 questions on -- just clarification and one to Chris, please? Just on Egypt, can you clarify, is the party impairment the actual LNG plant, as well as E&P activities offshore? And then second, you seem to imply that special participation tax was in the EBIT line i.e., with royalties. Is that true? Wouldn't that be different to your treatment of PRT, for instance, in the U.K? So I just wanted to clarify that. And then on -- for Chris, you mentioned that you did a lot of work on the sort of I know you got comfortable with 2013 and delivered most of 2013, you looked at 2014, and also into 2015. But I think you talked about getting comfortable with the longer term planning process. Can you just sort of confirm that you look out longer term that the broad trajectory of the business is as you expected it and as has been set out historically in the past?

Simon Jonathan Lowth

Yes, so to your 2 questions. Yes, SPT is in the OpEx line, so to be absolutely clear on that. And secondly, yes, the LNG is part of the solicit part of the impairment.

Chris Finlayson

So to the question about the process, what we did last year was we had the data that allowed us to do a statistical analysis on our 1-year out production. We didn't at that stage have the data available to allow us to extend that into the latter years. Over the course of this year and into 2014 planning process, we have extended that to all assets and into the out years of the plan. That's what gives me more confidence or what gives me confidence in the projections that we're making later on. And whilst we're not giving quantified targets for the out years, I am convinced that the growth story of continued significant growth remains completely intact.

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

Theepan from Nomura. And just a couple of questions. Just coming back to Egypt, just from a mechanical process. Do you envisage a scenario where you have one of the trains down? Or I mean, how do we view modeling sort of utilization on the trains? Secondly, just in terms of CapEx for this year. I imagine there is a decline in Australia, but I was just wondering whether you could talk about CapEx on the base? And I think, Simon, you talked very much about -- in the call last week about meeting or attaining free cash flow neutrality over a range of scenarios, so could just talk about where the deltas are in the $8 billion to $10 billion of CapEx for 2015?

Chris Finlayson

Thanks, Theepan. So I'll just answer the train utilization question. It is tricky for your modeling this year because you're going to see very significant changes we think in utilization over the course of the year. At the moment, utilization is low. That's clear because we have declining production and we have this build up to maximum domestic offtake, which we highlighted in the release. How that develops over the next few months, we are frankly unclear. It will depend on to what degree of the government decides that it is going to scale back and abide by the pooling agreement. What is clear is that when Phase 9a comes on stream, the 9 additional wells that we have there in Q3 and through into Q4, that will give significant additional capacity which will mean that utilization of QCLNG should ramp up significantly. But as we said in our financial projections, in our operational projections, we are allowing for a range of different outcomes in Egypt.

Simon Jonathan Lowth

And to your questions on, I mean, capital, I mean, I think we guided to capital in '14 being a little lower than in '13. Chris also mentioned that about 70% of the program will be in Brazil and Australia, so can see there'll be some a bit of movement down in the base assets, you can sort of see that from those 2 pieces of guidance around '14. If you look into '15, where does the flexibility lie? This is about decisions that we take primarily to reinvest to -- for future growth, future projects, whether it'd be an exploration or advancing some of the projects of scale which we have done, some of the projects that Chris described. And we clearly have discretion around that and will be guided by the sort of prospective returns that we see in light of the importance of delivering that cash flow objective. I would also say that I think there's an opportunity to bring fresh perspective to the capital program to really look at our capital efficiencies and capital discipline, and that's another area that we'll be looking out at over the coming sort of 12 to 24 months.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Fred Lucas, JPMorgan. Could you quantify the reserve write-downs in Egypt in the U.S.? And also, explain why there's been a further reserve write-down in Egypt? And it'll be helpful also if you don't just quantify the write-down? But you give us what reserves you carry for both countries at year end 2013? And going back to the question on capital, capital discipline. You've guided to 12, last year, you spent 11.2. The guidance for 2014 was 12, and now it's going to be below 11.2. Where are these savings coming from? Is it genuine efficiency savings or is this just switching of capital obligation into a lease obligation on FPSOs and things like that?

Chris Finlayson

I think to the last question, a part of it is looking at capital to lease, that is true. Other areas, it is actually addressing the overall capital efficiency. We are coming in significantly cheaper in some of the Brazil operations. Our drilling costs, we talked about that before, we say drilling is 50% of the total cost of the project. And our drilling times have increased -- have improved rather by 50% to 60%, so that's genuine saving, as well, we anticipate that to continue as we go forward.

Frederick Lucas - JP Morgan Chase & Co, Research Division

In terms of the reserves?

Chris Finlayson

In terms of the reserves, I think, Fred, we'd have to get back with the exact figures that go with that.

Frederick Lucas - JP Morgan Chase & Co, Research Division

Can you explain why this is like that [indiscernible]?

Chris Finlayson

There was a write-down in Egypt around 2 wells, which we anticipated as having SEC-proven reserves and where we now believe we can only carry these as contingent resources.

Alejandro Demichelis - Exane BNP Paribas, Research Division

Alejandro Demichelis from Exane BNP Paribas. A couple of questions. Coming back to QCLNG, you have been talking about third-party gas and so on. Some of the nearby projects seem to be put on hold or canceled. Is there any kind of K for you to launch further trains on QCLNG, if you can get advantage of those? First question. Second question is, you've given us quite a lot of detail in terms of the cost evolution. How we should be thinking about cost evolving once you get through the ramp-up phase of both Brazil and QCLNG? Or this -- is there any kind of range that we should be thinking about?

Chris Finlayson

I think we are 100% focused at getting our 2 existing trains full and keeping them full on the most capital-efficient way. That's why one of the reasons we're putting significant effort into exploration not because we haven't gotten gas available to go in there, but we think there may be opportunities to get more cost-effective gas for the longer term. We have debottlenecking opportunities at relatively low-cost on the 2 trains that we have there. And quite clearly, the most capital-efficient thing that we can do is to carry through that debottlenecking, fill those trains and make sure that they're kept full for longer. If we are very successful in our exploration, if there are other third-party opportunities, clearly, we're not saying we would not consider those opportunities. But at the moment, I would not anticipate us taking a decision on that in the near future. Our focus is on delivering what we have.

Simon Jonathan Lowth

And in terms of cost evolution, we've tried to lay out for you the separate components of E&P costs and the drivers of them, I think in -- and explained also, the trends in those unit costs into '14. As we look beyond '14, I indicated that as we see the production ramping up through Brazil and Australia, we can expect to see the pressures on lifting cost component, obviously, abate because we're going to get utilization as we come through the plateau from that fixed cost base. And same applies actually on the DD&A, where quite a step-up in DD&A has been bringing new developments on stream. So again, as we get utilization rising and up to production plateau, we can expect to see pressures on DD&A abating. I think the only other point I'd say at this stage is we, again, I indicated in my remarks, we've seen improvements in unit revenues as a function of the improving mix and the combination of that continuing as the growth assets come onstream, combined with these abating pressures on the unit lifting and DD&A costs, we continue to see cash margins expanding over time. I think we sort of shared the growth shape of that with you in the past and that's -- we still see that as a development of the cash margin in the overall portfolio.

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

Oswald Clint at Sanford Bernstein. Chris, maybe can I just get you to just focus on the U.K., please, the 100,000 barrels per day there with your more robust modeling, and the issues the industry has in terms of the U.K. Buzzard obviously having a few dying days recently so far in 2014, so maybe a bit of discussion around U.K.? And secondly, back to QCLNG. And the chart that I liked most last year was your EBITDA progression. I just wonder, is the 10% to 20% third-party purchasing, is it up for the next 2 years? Is that included in that EBITDA progression chart that you showed last year?

Chris Finlayson

Thank you. So the U.K., U.K. remains clearly an important and a very profitable area for us going forward and will do for a number of years yet. Buzzard having had a very difficult 2012 as we brought the Sour Gas Processing platform onstream. It actually delivered really high availability in 2013. And although we've had a couple of trips in -- at the start of the year, overall, we're still ahead of plan for the year with Buzzard. What you will see during the course of 2014 is that there are a number of infrastructure-driven outages coming up this year. There's a Forties pipeline system shutdown, there's a Frigg system shutdown, and there's a CATS terminal shutdown. And those will essentially drive our shutdown program over the course of 2014. And wherever possible, we will shelter the shutdowns that we plan on the platforms or our operators where we're not the operator within those pipeline or infrastructure-driven shutdowns. Clearly, Jasmine is very important. So I mean, Jasmine will ramp up to around 30,000 barrels a day BG share. We had challenges in December and January around 2 things. Firstly, the cooling medium problems that ConocoPhillips experiences. And latterly, the commissioning of the flash gas compressor. That I haven't seen the final figures but that's underway as we speak, and that should then allow us to ramp up to full capacities. We'll be about a month behind where we expected but we still expect to be able to recover those volumes over the year.

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

The second -- sort of second one?

Simon Jonathan Lowth

EBITDA? Yes, sorry, the role for third-party gas and its importance in the portfolio during the ramp up is obviously something that's been an integral part of QCLNG planning, and it's been built into our forward view. You -- may have caught when I went through my description of cost base, you will find that in the other E&P costs line, so it sits outside the OpEx costs so that's the place to track it as you see during the course of 2014.

Chris Finlayson

And the margin per barrel is an equity margin per barrel.

Simon Jonathan Lowth

That's right.

Unknown Analyst

James Lynn [ph] from Aberdeen Asset Management. Just quick -- 2 questions, one on the receivables which you talked about an improvement in. Is collection improving quite a lot and what does it primarily relate to? Is that Egypt? And then the second one, obviously, U.S.A., another impairment. And could you just highlight a bit more detail on that? Is it just the assets aren't as good qualities as they were or is it primarily a price issue?

Chris Finlayson

Do you want to do the first one and I'll do the second?

Simon Jonathan Lowth

Thanks. Yes, I mean, certainly, on receivables. I mean, the situation as I mentioned in Egypt, which has been the area where we've had seen the greatest extent of over dues. We did see some improvement in that situation during the course of 2013, both through the regular cash payments, but also, we received a lump sum before the end of the year. And as I mentioned, the receivable balance dropped during the course of 2013. That's probably the only main development I would call out on receivables in '13. Chris?

Chris Finlayson

Yes. We said perhaps is willing to add this sort of feeling about so did you get much money out of Egypt. Overall, before we start reinvesting, we got nearly $1 billion of cash out of Egypt through the various routes. So yes, we still have a significant outstanding balance, but the balance did reduce over the course of the year. On your -- sorry, I forgot your second question?

Unknown Analyst

Sorry. It was on U.S. impairment.

Chris Finlayson

Thank you. Yes, so the U.S. impairment is essentially composed of 3 elements. Firstly, we had some exploration acreage in the Marcellus in the Northeast where the exploration results have been disappointing and we're writing down that value. Secondly, again, in the Marcellus acreage, we see a significant discount of gas prices, the Henry Hub, which has emerged in the last half of the year caused by infrastructure bottlenecks to the northeast, which do not look like they're going to be solved anytime soon, so that has caused us to write down the volume -- the value rather of the assets that we have there. And then, in East Texas, West Louisiana, whilst we have not written down volumes there, I would stress what we have seen is in the best areas of the fields that we have there, we have seen a deterioration in type curve, which has led us to increase our future well spacing, which does have an impact on production and reserves going forward.

Unknown Analyst

[indiscernible] given this is a [indiscernible]

Chris Finlayson

Yes, no, I think...

Unknown Analyst

[indiscernible] have asset integrities improve...

Chris Finlayson

There is no issue with assets integrity.

Unknown Analyst

[indiscernible]

Chris Finlayson

Yes. No, I think that we have a very solid position now in the U.S., absolutely.

Simon Jonathan Lowth

So probably, Chris, just to finish in what you're saying, the majority of the remaining carrying value is in the Texas, Louisiana, which is less exposed obviously to the discounted pricing that Chris described. That's where the majority of the remaining carrying value is held.

Martijn Rats - Morgan Stanley, Research Division

It's Martijn Rats, Morgan Stanley. I just want to ask you about 2 things. First of all, the sort of intention to moletize [ph] about 25% of the acid base over asset base over the next 10 years through disposals. A lot of companies doing a lot of disposals these days. And the market is reasonably flooded with assets. I was wondering from where you are sitting, whether this is starting to have an impact or whether you're actually saying, no, look, we can still do the disposal. We wanted to ask you your perspective on that? And secondly, very briefly, but Chris, you started off the presentation by saying, we're pushing change throughout the organization, and listening to the plan as you presented. This is a very sort of gradual development compared to last year. I was wondering whether were there any specific changes that you were referring to when you made that comment?

Chris Finlayson

So first question around disposals. I mean, it is a valid point. There are some parts of the market where it's easy people to say, you should sort of perhaps churn this portfolio, but we're very clear, we're not going to churn portfolio to get rotten prices for it. And if we can't get a good price, then we'll hang on, but I think you can see that from the transactions that we have achieved, we have significantly simplified the company. We've got completely out of the power segment. We've got completely out of the downstream gas segment. We have managed some quite significant E&P disposals as well. We have our eye on what that next stage could be like, but I think, you're right. We -- you have to be -- you have to convince yourself that there is a market there and that there is real value there before you move out and start causing all the disruption that you do internally if you don't think actually you're going to be successful as you move forward. So that is a part of the decision process where you move, but it's not a reason not to go out and try. And as we said, we keep everything under review all the time, and we do expect to be able to make significant traditional moves in this space. In terms of process and what has changed, I think the key thing I would emphasize for now, you can go through a watch list on this, but really, to me the key thing is that we have now got in place a multiyear fully statistical model for our production, which allows us to make sure that as we review the inputs coming from all of the assets, we can take a robust long-term view on that. And that is now there and working and that's why I have much more confidence in the 2015 output, as well as my confidence in the 2014 output.

Michael Ridley - Mizuho International plc

Michael Ridley from Mizuho International. So 3 questions if I may. Currently, Brazil and Australia are responsible for 6% and 4% of your overall production in 2013. Do you have sort of guide medium-term what percentages that would rise to? Secondly, your leverage net debt to EBITDA still been rising. I'm just wondering, which is the peak year for that and have you got an estimate of what that would be. Finally, your -- although you're free cash flow negative, you've got a lot of liquidity at the moment. So in the bond markets, would you not be looking to come back this year or next year, and when would you like to come back into the bond markets?

Chris Finlayson

Okay, well, I'll give all the second set of questions to Simon. Clearly, it depends on how you define as medium term. Our production -- Australia essentially moves over a period to 2016 to plateau. And plateau in terms of equity production is about 200,000, 210,000 barrels of oil equivalent a day. In Brazil, that grows throughout the decade right through to 2020. And by the time you get there, you will be talking, as we've said before, volumes which are north of 500,000 barrels a day. So you can work that out, but clearly, the 2 against our -- the rest of our existing portfolio will form the majority of production.

Simon Jonathan Lowth

And to your question on, I mean, funding, and questions I think principally focused on the sort of short-stem [ph] funding but probably we're setting that in context, which is just a few thoughts on overall capital allocation and financing. As we've stressed, real priority is to deliver improving net cash flow from our operations, delivery on production goals, bringing a real focus on cost productivity and tight management of the capital program comments we made earlier. Chris said we've also got an active portfolio management program underway. The aim obviously is in realizing value, accelerating value, but also, liberating capital. We said before that we are committed to retain a mid-single A rating, that remains the case. And against that backdrop over time, that we can assess the allocation of residual capital, whether that's around quality reinvestment of the business or indeed over time, additional distributions to shareholders. So as that as backdrop coming to the question of sort of shorter-term, funding. When we entered 2014 with a strong liquidity position, I mentioned about $6.2 billion in cash, gearing just under 25%. We do expect 2014 to be a year where there's going to be a continued pressure on cash flow because, as Chris described, production sort of trends down. We've got CapEx. Yes, it's lower than in 2013, but it's not falling to levels we anticipated in '15, so there will be some pressure on gearing during the course of 2014, albeit from that position of very strong liquidity. In terms of specific approaches to funding, we've got access to the debt capital markets. We've got CP lines undrawn, and we will look at that actively during the course of this year to ensure we secure the best mix of funding for the business during '14. And then looking into 2015 where we expect to see us moving back into cash flow positive and then the pressures on gearing starting to abate. So that gives you a sense of the dynamics on financing.

Chris Finlayson

Not to mention USX?

Simon Jonathan Lowth

Sorry. Yes, I mean, there is a range of committed undrawn facilities both in terms of bank funding, but also as you probably know, we've again noted in our report today, we have a developed export credit financing USX. And that's available subject to the documentation as another source of funding for the business.

Neill Morton - Investec Securities (UK), Research Division

It's Neill Morton, Investec. Two questions, please. One each I think. First, Chris, it's a bit of a touchy-feely question, but you mentioned that you changed the long-term planning process, made it more rigorous. But it's not uncommon with the hard-driving organization with ambitious growth targets that bad news sometimes tends not to percolate up to the top of the management structure. Can you perhaps just talk a little bit more about the softer side, the change in management style? You'd mentioned in a recent interview about perhaps being a little more autocratic than the past. And then just secondly for Simon, a very quick question. In which year does Upstream unit DD&A peak?

Chris Finlayson

Okay. Well, Neill, it's always a pleasure to have somebody from the investor community asking about the softer side of the business. It doesn't often come, but it's a very good question. I think what we've tried to do and now continue to do is to shorten lines of communication, make sure that we are running this as a team, which is not in any way diluting my ultimate responsibility for making sure that my colleagues are completely engaged in this process and that we have a real build of information through to the top. So you are right. It's about improving information flows. It's about making sure that people recognize that all news surfaces, but of course, it is not about in anyway lessening the focus on delivering on targets once they are agreed. This takes time. I think we are making real progress. I'm not saying we are everywhere in everything where we need to go, but I would reemphasize that I am confident around these planning parameters that we've talked about today.

Simon Jonathan Lowth

In terms of your question on unit DD&A. I think the drivers of that in the short term if you're going to '14 are very clear that we are bringing new developments onstream. We've also got the impact of reserve revisions that flow into DD&A. I think as we ramp up, continue to see ramp up, particularly in Australia, but equally in Brazil, some of those pressures will remain perhaps into '15. But certainly, as we look beyond that, I'd expect to see us beginning to move into plateau and full ramp up in Australia, began to see get better leverage out of Brazil given the timetable that Chris described. So I think the pressure start to ease beyond that. Of course, exactly what the unit DD&A will be is also going to be a function of the progress in our reserves during that period, so I'm not going to give you a pinpoint date when it changes. But I think you can see the pressures that have impacted us in '13 and '14, those definitely start to abate over the course of the next 24 months.

Thomas Yoichi Adolff - Crédit Suisse AG, Research Division

Thomas Adolff, Crédit Suisse. Two questions, please. Firstly on your base, you said you have a better grip on DP 10p, 50p, 90 4 [ph] asset performance and production at least for the next few years. If I go back to your guidance back in May 2013 around the base CapEx of between $2 billion to $3 billion per annum. If you continued to invest at the lower end of the range, if you will, how does the base production evolve to the end of the decade? On the second question, I guess on QCLNG. Once you reach plateau production, I was wondering whether you can share your internal assumption for cash costs [indiscernible] terms of OpEx and maintenance CapEx.

Chris Finlayson

Okay. Well, for the second one, we would have to get back to you. I haven't got that figure in front of me at the moment. In terms of our investment strategy and the base assets, I think as Simon made clear, this will depend on the quality of the investment opportunities that come forward. And so that clearly links to them what in the longer term is the likely outturn. So we're not going to commit to a particular level. We will be driven by value as we've said, that is the key of the strategy. We will do things that create real value for our shareholders and not to maintain a particular metric as a production metric as we go forward.

Lydia Rainforth - Barclays Capital, Research Division

Lydia Rainforth from Barclays. Two questions. Firstly, you've both talked about driving productivity, cost efficiency, capital efficiency and additional scrutiny on the cost side. Is there a particular area within the BG cost base that you would like to [indiscernible] or is it like an industry-wide issue that you are thinking of? And then secondly, just to clarify, on the reserve base, in the change on the SCE to SPE side, there was an increase of the improve reserve base there. Is that one particular region or is that across the portfolio? And just to clarify on that, are you using the SPE base on a DD&A guidance?

Chris Finlayson

Okay. Well, let me take the first question. Sorry, the second question on the resource base. And that is -- why have we made the change? We've made the change because the SEC base only actually covers proved plus probable, so we always use the PRMS system for the resources. This allows us to combine the 2 into a single and effective program. That is the recommended system for the -- by the regulator. We tried to show that this was not something that gave us a sort of a significant increase in resource or decrease in resource. It does give a small movement between P1 and P2, proved and probable resource. That is in essence driven by pricing assumptions where you take -- where under SEC, you're taking the annual average of the past year and under PRMS, you're taking your assumed pricing deck going forward, which, of course, we have in the release said what our base assumptions are, so that's what's drives that small change. But as you can see, the total stack is essentially identical under both.

Simon Jonathan Lowth

On the costs, let me offer my perspective, I'm starting my eighth week in the role, I think. And haven't yet had the opportunity to go out and visit our assets, our operations and really get to know the people at the frontline, so naturally, my perspective is somewhat conditioned by that time and limited vantage point. I mean, I think that from what I have observed, bringing a fresh perspective, particularly one that's informed by a number of different operating context. There are always ways in which a company can look at managing its overall cost and resource base more effectively. And I can see opportunities in multiple different parts both at the, let me call it, the infrastructure G&A overhead sort of base. In discussions with colleagues, I think we all acknowledged that -- and I suspect this is a wider industry issue, we need to look quite hard at our cost structure and start to really tackle and ask ourselves how much of the cost base is genuinely fixed, can we make it more variable, bring more flexibility to it because that's having quite a pronounced effect on unit cost at this period as we go through some declines in some of our assets. So -- and of course, from industry I came from, that was a very, very similar issue, highly cyclical revenue shape. And we made huge strides in variablizing more of our cost base. I suspect that's another opportunity to look at. But I said, it's initial thoughts conditioned by a relatively brief time period. But I look forward -- it's going to be a huge priority for me over the course of the next 12 months.

Unknown Analyst

Brendan Mourn [ph] from Bank of Montréal. Just obviously, significant commissioning risks in Australia where pretty bad reputation of delivering projects on time in the commissioning phase. Just what's BG doing differently? And just secondly, on any label contractual arrangements, any of those up for renewal in 2014? And then just second question, we've all become comfortable with a north of $100 oil price, but what would be BG be doing differently in an $80 oil price environment in 2014?

Chris Finlayson

Okay. So the simplest question, is the labor agreement up for renegotiation? Yes, there is across all the contracts on Curtis Island, so Bechtel of course is the constructive for all 3, and that is due to be renewed in the middle of the year. So that's clearly a risk that is out there. But at the same time, we understand they are making reasonable progress with the unions with that. In terms of commissioning, what are we doing differently? It's interesting you say that because I've got a call with them after this to get the finalization of the agreement. But in essence, we will take most of our operations staff and succumb them into Bechtel because we have a lot of staff there who commissioned actually 3 LNG plants already of similar designs. And we will put them 100% into Bechtel's team. We need to do that, because it's a lump sum contract to deliver and that will make sure that they have the best talent available to them to deliver effective commissioning. If you look back at our history, Egyptian LNG came onstream very, very smoothly, so did Trinidad, and we have some of the same people working in Australia that we had working on those projects. So that's my reply to you as to what we're going to do hopefully well, and perhaps differently than you've seen in some other projects.

Simon Jonathan Lowth

$80 oil.

Chris Finlayson

$80 oil, I think it will depend -- you will clearly need to respond. I mean, that's an obvious answer to that. Do I believe that $80 oil for a sustained period of time is likely to come? My view is no, I don't, but I think that a downward excursion is certainly a possibility and we review our robustness against that. We test. We do our going concerns, and we would clearly be looking at where we have capital that we could defer out of the year to take account of that.

Unknown Analyst

[indiscernible] cash [indiscernible] positive in 2015 at all?

Simon Jonathan Lowth

I mean, we made clear I think that cash flow positive reference conditions -- clearly, if you see -- I mean, the main risk as you've correctly identified to that is the hydrocarbon prices. I think it's fair to say that it'd be challenging to be cash flow positive at $80 oil in 2015.

Chris Finlayson

I think that's all the questions that we have, Simon. So I would like to thank you all for joining us today, and we look forward to hearing you on the call for our Q1 results and I think in first of May. So thank you, all, very much indeed. Now Simon and I will be downstairs if anybody wants to catch up with us. Thank you.

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Source: BG Group Management Discusses Q4 2013 Results - Earnings Call Transcript
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