Berkshire Oct 30, 2015 (Thomson StreetEvents) -- Edited Transcript of BG Group PLC earnings conference call or presentation Friday, October 30, 2015 at 11:00:00am GMT
TEXT version of Transcript
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Corporate Participants
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* Mark Lidiard
BG Group plc - Head of IR
* Helge Lund
BG Group plc - Chief Executive
* Simon Lowth
BG Group plc - CFO & Executive Director
* Sami Iskander
BG Group plc - COO
* Steve Hill
BG Group plc - President Global Energy Marketing & Shipping
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Conference Call Participants
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* Oswald Clint
Sanford Bernstein - Analyst
* Anish Kapadia
Tudor Pickering & Co. Sec - Analyst
* Brendan Warn
BMO Capital Markets - Analyst
* Irene Himona
Societe Generale - Analyst
* Theepan Jothilingam
Nomura - Analyst
* Lydia Rainforth
Barclays - Analyst
* Fred Lucas
JPMorgan - Analyst
* Michael Alsford
Citi - Analyst
* Thomas Adolff
Credit Suisse - Analyst
* Biraj Borkhataria
RBC Capital Markets - Analyst
* Rob West
Redburn Partners - Analyst
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Presentation
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Operator [1]
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Good morning, ladies and gentlemen, and welcome to the BG Group's third quarter conference call. My name is Rhiannon, and I'll be your coordinator for today's conference. (Operator Instructions).
I am now handing you over to Mark Lidiard to begin today's conference. Thank you.
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Mark Lidiard, BG Group plc - Head of IR [2]
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Thank you, Rhiannon. Good morning, everyone, and welcome to the call today. Our Chief Executive, Helge Lund, and our Chief Financial Officer, Simon Lowth, will take you through the quarter's key business and financial highlights. They will then answer your questions, together with our Chief Operating Officer, Sami Iskander, and President of our Global Energy Marketing and Shipping Business, Steve Hill.
During the call, we will focus on our business performance results as highlighted in our results statement. We will also be making various forward-looking statements, including in relation to the proposed combination with Royal Dutch Shell.
By their nature, forward-looking statements involve uncertainty and no assurance can be given in relation to these statements. The combination with Shell is subject to a number of conditions and there are a number of factors that could cause our actual results to differ materially from the results we currently expect, including those set out in detail in the principal risks and uncertainties section of our 2014 Annual Report and accounts, and our half-year results statement published in July.
We have around 60 minutes for the call and I'll now hand over to Helge.
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Helge Lund, BG Group plc - Chief Executive [3]
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Thank you, Mark. Good morning, and thank you for calling in, everyone. I would like to start with a few words on the proposed transaction with Shell.
We are making good progress on the deal and have received unconditional antitrust approvals in Brazil and in the EU which, as you know, are both pre-conditions to the transaction, as well as approvals in a number of other jurisdictions.
We continue to work with Shell towards the satisfaction of the remaining pre-conditions in Australia and China and, based on progress to date, the transaction is still expected to complete in early 2016.
We are also working with Shell on integration planning and this continues to progress well. The current phase is focused on ensuring a smooth handover of activities, post completion, and also establishing the best possible basis for maximizing value from the combination.
While I'm clearly taking a keen interest in how the deal is progressing, my primary focus remains on safety and the operational and financial performance of the Company to ensure we deliver on our 2015 commitment, and continue to develop BG as an efficient and high-performing Company.
This will be the focus on what we talk about today, and I'm pleased to report that we are currently on track to meet, or indeed exceed, our operational targets.
Despite the turbulent industry environment, and activity driven by the proposed Shell deal, our teams delivered another strong quarter of progress against our project and operational milestones. Our connected and flexible organization, combined with the high quality of our people, has allowed us to react positively and quickly to the current circumstances.
The operational results show real momentum and reflect the growing stability and derisking of our business. As well as delivering our growth projects in Brazil and Australia, we have largely stabilized the performance of our base assets and have a strong drive to improve costs and efficiency. We are on track to exceed our cost savings target for this year.
Our average cash operating cost across the portfolio remained low, at around $18 per barrel year to date, in a period where our revenue has averaged around $35 per barrel. This means we have strong and positive operating cash margins, even in the current oil price environment, and this will allow our business to remain resilient during the current downturn.
We are also reducing CapEx and expect this to fall by around 30% to $6.5 billion this year, and Simon will talk more about cost and CapEx later.
Moving on to safety; the safety of our people is the highest priority for everyone at BG. And year-to-date performance against the industry standard measure, or total recordable case frequency, was 1.14, which is an improvement on last year's outturn of 1.38 and on our performance at the half-year.
We put a lot of emphasis on asset integrity, risk management and the development of a strong safety culture. It is really important that we do not lose focus on safety as we deal with the current industry challenges, and the upcoming changes driven by the combination with Shell.
Moving to our E&P business; production of 716,000 barrels of oil equivalent a day was up 26% on last year. This was driven by significant growth in Australia and Brazil, along with the ramp-up at Knarr.
We also reduced and re-phased some maintenance shutdowns while achieving better up time and efficiency across a number of assets. Offsetting this was continued declines in Egypt.
Reflecting this strong performance, we are increasing our production guidance range for the year to 680,000 to 700,000 barrels per day.
Now to Australia, where we continue to see positive momentum. As you know, we took operational control of Train 1 in May and this train is now operating at plateau. Train 2 produced first LNG in July and we expect to take full control of the plant later this year. To date, we have produced 62 cargoes from QCLNG, or some 4.1 million tonnes.
In the upstream in Australia, E&P performance has been in line with expectations and this month we achieved the highest daily production level of 118,000 barrels per day. We remain on track to reach plateau production in May 2016.
The project in Australia has been a real challenge for BG of many years, and I am pleased with the way our people, over the last 12 to 18 months, have been able to complete the project and ramp up production in a safe and efficient manner. Indeed, since Train 1 was handed over to BG in May of this year, plant availability has been excellent, around 96%.
In Brazil, underlying operational delivery remained strong. At the end of July, we started up FPSO 6 at Iracema North, and we now expect FPSO 4 and 5 to reach plateau in fourth quarter.
Daily production during October in Brazil has reached 175,000 barrels net to BG. FPSOs 7, 8 and 9, the last three leased FPSOs, are all progressing well and are on track to be on stream, as planned, in 2016.
On the replicant FPSOs, we continue to monitor developments and, as we have said before, we are prepared to implement contingency plans, if necessary, to minimize the risk of any further delays caused by the Lava Jato investigation.
Petrobras focus on the pre-sold and operational delivery remained strong, despite all of the challenges we are seeing in the region. We continue to work with and support Petrobras in all aspects of the development.
In our base assets, production was ahead of expectations during the quarter as we had lower than expected maintenance shutdowns and improved operating efficiency in certain assets.
Overall, I'm pleased with progress in the upstream business, where we continue to deliver growth, improve safety and reliability and have a real drive to improve costs and productivity. Our upstream team sees further areas of improvement across our value chain and will continue to capture those as we move forward.
In the LNG segment, delivered volumes were 76% higher than the same period last year at 75 cargoes, or 4.8 million tonnes. This was primarily due to new supply from QCLNG and six additional spot cargoes. Volumes from our other long-term supply sources were flat on the same period last year.
Deliveries year to date in Asia increased on last year to 72% of the total, primarily as a result of the startup of QCLNG which is fully underpinned by long-term contracts to Asian customers.
While LNG market conditions are becoming more challenging with increasing supply and weaker than expected demand in certain markets, BG's flexible business model has allowed us to respond to these changes with increased spot purchases, additional optimization activities, and sales into new markets, including Egypt and Pakistan.
We will continue to use our market expertise to optimize returns from our portfolio and keep open longer-term options for our LNG business. We believe that LNG will continue to be a high-growth segment of natural gas which, in turn, will have an increasingly important role in the energy mix.
I will now hand over to Simon to take you through the financials. Simon.
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Simon Lowth, BG Group plc - CFO & Executive Director [4]
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Well, thank you, Helge, and good morning to everyone on the call. I'm going to start with a brief summary of the overall financial results and, as usual, my comments will relate to business performance results for the third quarter, unless otherwise stated.
EBITDA was 37% lower at $1.2 billion, mainly reflecting the impact of the significant drop in realized sales prices, which was only partially offset by a higher upstream and LNG volumes, together with a positive contribution from our liquefaction business in Australia.
Earnings per share were 63% lower at $0.082, reflecting this lower EBITDA, together with higher upstream depreciation charges, partially offset by a lower tax charge. Total results reported a loss per share of $0.03. This reflected non-cash foreign exchange-related tax charges.
I'll now turn to the segment-specific highlights and I'll start with the upstream. E&P production was up 26% on last year. Despite this increase, and a favorable mix effect from increased oil production in Brazil and the North Sea, E&P revenues fell 18%, primarily due to lower commodity prices.
The Group's average realized prices for both oil and liquids fell by almost 50%. Our realized gas prices fell 34%. E&P operating costs were 3% higher than last year. This increase was driven by the ramp-up of production in both Australia and Brazil, together with the startup of Knarr.
This was largely offset by lower royalties linked to the fall in commodity prices and by the impact of our cost savings and efficiencies. Other E&P costs increased 18%, reflecting higher Brazil oil shipping costs and foreign exchange losses from the revaluation of certain working capital items in Brazil. Overall, E&P EBITDA of $900 million was 34% lower.
Liquefaction EBITDA increased by $156 million to $184 million, with QCLNG profits now reflecting a full quarter of commercial operations at Train 1 and the common facilities, allowing a full tariff to be charged to E&P business and partners. This was partially offset by a small loss, as expected, at Train 2 whilst it is in the commissioning phase.
Elsewhere in liquefactions, the Group's share of post-tax results were lower with no cargoes at Egyptian LNG and lower volumes in realized prices at Atlantic LNG.
Upstream depreciation was [$166 million] higher with E&P DD&A up $124 million, principally reflecting the increase in production and the impact of reserve revisions in Trinidad and Tobago, partly offset by a favorable change in the mix of fields.
Liquefaction DD&A of $51 million relates to QCLNG. Overall, upstream EBIT of $253 million was down 65%.
In the LNG segment, delivered volumes were 76% higher with 25 cargoes from QCLNG and six additional spot purchases. Total cargoes from the Group's Atlantic Basin contracts remain unchanged.
LNG revenues of $2 billion were 11% higher, reflecting the increase in volumes, partially offset by the commodity price impact on realized LNG sales prices. However, LNG EBITDA of $213 million was 65% lower, due to the lower margins earned as a result of the fall in realized LNG sales prices.
DD&A was 19% lower, following the sale and leaseback of a number of LNG vessels. And then LNG shipping and marketing EBIT of $187 million was 68% lower, largely mirroring the fall in EBITDA.
Based on forward commodity price curves in mid-October, the Group's full-year LNG shipping and marketing EBITDA guidance remains $1.3 billion to $1.5 billion with an expected outturn around the middle of that range.
Supply volumes are still expected to be slightly lower than the 150 cargoes in 2014, if we exclude both the spot and the QCLNG cargoes.
A $56 million loss was reported in the other activities segment. This relates mainly to the elimination of profit recognized in the upstream segment on equity LNG cargoes that are in transit at the end of the quarter. These cargoes have increased principally as a result of the ramp up of operations at QCLNG.
Net finance costs were $55 million in the quarter. Excluding foreign exchange gains, underlying net finance costs increased by $65 million to $103 million. This reflects the reduction in the amount of interest on borrowings capitalized following the startup of QCLNG.
Tax charge for the quarter, excluding the Group's share of joint ventures and associates, reduced to $49 million. This reflects both the lower profit before tax and a further reduction in the Group's estimated full-year effective tax rate to 32%. In the current low commodity price environment, the full-year tax rate remains sensitive to movements in the Group's profit mix, but is expected currently to outturn in the range of 30% to 35%.
Total results earnings were impacted by a net $344 million non-cash tax charge, primarily related to changes in tax balances arising from the retranslation of the Group's tax bases, especially in Brazil and Australia. This was due to the devaluation of these currencies against the US dollar. The Group's total results for future periods remains sensitive to further foreign exchange movements.
Net cash flow from operating activities fell to $844 million, primarily reflecting the impact of lower realized sales prices. However, cash CapEx reduced by over 30%, more than offsetting the decline in operating cash flow. As a result, free cash flow performance improved by $224 million to a $705 million outflow in the quarter.
At the end of the quarter net debt was $9.6 billion; gearing was 24.5%.
We continue to drive operational and cost efficiencies right across the business and we're on track to deliver on our operating and capital cost savings for 2015. These actions clearly will help mitigate the impact of lower commodity prices on our financial results.
As Helge mentioned, our cash capital expenditure has reduced as major projects complete and as our cost and efficiency programs deliver. This has been most notable in Australia, where CapEx in the nine months is around $1.8 billion lower than last year, and in Brazil, where we have seen improved drilling productivity. We now expect CapEx for the full year to come in at around $6.5 billion, so that's 30% lower than last year.
We're on track to deliver at least the $300 million target cost savings for 2015, which equates to around 10% to 15% of our lifting and organization costs. We're pursuing cost savings in three key areas.
We're reducing organizational costs through streamlining and efficiencies; we're capturing near-term procurement savings in weaker supply markets; and we're driving sustained and structural cost improvement through the optimization of our developments, standardization in design, supply chains and improving our operating processes.
The actions that we're taking to improve cash cost, and to tightly manage capital investment, will ensure that BG is resilient to any prolonged downturn in oil prices and is well placed for any recovery.
So thanks very much for your attention. We'll now be happy to take your questions. As normal, please could you limit these to two per person so that we can cover as many people as possible on the call in the allotted time. Operator, over to you to open the line for questions.
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Questions and Answers
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Operator [1]
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(Operator Instructions). Oswald Clint, Sanford Bernstein.
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Oswald Clint, Sanford Bernstein - Analyst [2]
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Could I ask a question about Trinidad and the reserve revision you made today? Just really curious about what's going on there. Or also what's the prospect inventory you might have within that block for future tie-ins, or if there is any chemical treatments or any mitigation actions you can take there in terms of that particular block?
And then secondly, maybe over to East Africa; I noticed some of the other companies involved in Tanzania were successful in the Mozambique license round. I wonder, did BG bid, or potentially why not, in terms of that license round in offshore Mozambique? Thank you.
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Helge Lund, BG Group plc - Chief Executive [3]
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Thank you, Oswald. I suggest that Sami goes directly into Trinidad. Sami?
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Sami Iskander, BG Group plc - COO [4]
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Okay. Good morning, Oswald. I think, to describe Trinidad, there are really two parts to it. First, I'll talk a few words on Starfish then Dolphin, then really the prospects as you asked.
So on Starfish, Starfish was a new field we're drilling in the east coast area, so kind of very, very close to Dolphin, and there we've encountered quite a long expanding shale section. So some formation that we had not seen and we've drilled some 17 or so wells in the Dolphin area, so this was something new.
The current completion we run in that ECMA area is an open-hole gravel pack, not really well suited to expanding shales which cause instabilities in the wells. So in a three well, the long and short of it, a three well program became a one well program because we lost two wells.
So in the short term, clearly the production that we expected from the Dolphin area has not come on line; we have one instead of three. We may come back to this program again; clearly, we need to do some more engineering work and see how we can successfully drill out Starfish. So that's Starfish.
On Dolphin itself, two effects here. We've seen some sand production from some of our wells, which really has pushed us to maybe take a closer look at the reservoir model and adjust it slightly. And that is part of the impact of the reserves you saw.
But another and equally significant part is, we have taken a view on future projects in the ECMA area, so whether it's the compression project, or drilling projects like [Grenadier], or 5C or the rest, where those have been pushed out in time.
And I guess the question here is why. Fundamentally, these projects in the current pricing environment would require us to work, together with our partners, to optimize them further, that's on one side, and really work with the government to see if we can explore better fiscal terms that will move them up the funnel, if you wish.
So two impacts; one is the current Dolphin reservoir, and clearly some mitigation measures can we do. But equally important is the funnel of projects, as I think you referred to it, where these projects would require further optimization and, potentially, better terms.
In terms of their impact on the overall delivery, clearly today we are delivering our annual committed quantities. As we project forward it would really depend when these projects get sanctions and become online. But it's important probably to highlight we will see a further decline year on year at some of these projects in Trinidad, which will reflect a little bit within obviously our domestic contracts, and our export contracts.
It's important, maybe, to say that it's a small impact, a relatively small impact on our rather expanding LNG portfolio, but nonetheless a little bit of an impact.
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Helge Lund, BG Group plc - Chief Executive [5]
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On the exploration side also, as you know, we are building and maturing the inventory opportunities, Canada, Honduras, Myanmar, Mongolia, and Brazil, a couple of other places. So we have not been active beyond Tanzania recently in East Africa.
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Oswald Clint, Sanford Bernstein - Analyst [6]
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Okay. Very clear, thank you.
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Operator [7]
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Anish Kapadia, TPH.
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Anish Kapadia, Tudor Pickering & Co. Sec - Analyst [8]
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A couple of questions from me. Firstly on QCLNG, I think you've provided quite a lot of detail on modeling out QCLNG, but I think the market seems to have made a bit of a hash of modeling out the liquefaction EBITDA this quarter.
When I look at it, kind of taking this quarter and the additional earnings you're going to get from next train, would a good estimate for the EBITDA for liquefaction, at full capacity for QCLNG, be around $1.5 billion?
And just kind of thinking about that, given the value you've got for selling down the common facilities, and these are quite ratable assets, would you think that the market value of the liquefaction in common facilities is around that same kind of multiple, that $15 billion to $20 billion type value?
And then the second question, going back to the Trinidad issue again, I was just wondering, is there some kind of fundamental issue with the BG's reservoir characterization and appraisal process of some of your fields, because it feels like you've had a raft of issues with reservoirs underperforming, or underestimating production, other things I can think of are Jasmine, Gaupe, Egypt? So just wondering, is that a fundamental issue and what are you doing to address that? Thank you.
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Helge Lund, BG Group plc - Chief Executive [9]
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Perhaps, Sami, you want to take Trinidad again, so we can complete that? And then perhaps Simon, you address the liquefaction? Shall we take Trinidad first?
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Sami Iskander, BG Group plc - COO [10]
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Yes, very short, I think first, I appreciate the question, however I do not believe there is any fundamental issue, and if there were any fundamental issues we'd have dealt with them probably two or more years ago.
So no, the issues between Egypt, certainly Gaupe and some of the rest, and the ones in Dolphin are quite distinct, quite different. I could go into the geological difference between the reservoirs, but suffice to say they are quite different, and I think we're addressing this and the future.
And the point I made to Oswald a little bit earlier, yes, one part of it is reserve, but then equally important part is the pace of taking projects forward. And clearly, we're [not] taking projects, economic projects forward in a much more rigorous way in this pricing environment.
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Helge Lund, BG Group plc - Chief Executive [11]
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On the economic modeling of the liquefaction, Simon?
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Simon Lowth, BG Group plc - CFO & Executive Director [12]
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Yes, so thanks for the question and we did, indeed, provide quite a detailed factsheet. We do recognize that this is quite challenging to model for all of you, particularly as we ramp up because we're not in a steady state and, therefore, we're not yet operating at the steady state economics that you can get to from all of the information that we've provided. So we can understand the challenge.
We think that will improve as we get into 2016, and we're operating then at plateau and in more of an equilibrium.