BP p.l.c.
Q3 2015 Earnings Call Transcript

Published: 28 Oct 2015

Operator:

Welcome to the BP Presentation to the Financial Community Webcast and Conference Call. I now hand over to Jessica Mitchell, Head of Investor Relations.
Jessica Mitchell:

Hello and welcome. This is BP's Third Quarter 2015 Results Webcast and Conference call. I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary. Also with us for the Q&A is the Chief Executive of our Upstream, Lamar McKay, and Tufan Erginbilgic, Chief Executive of our Downstream. Before we start, I need to draw your attention to our Cautionary Statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors we note on this slide and in our U.K. and SEC filings. Please refer to our Annual Report, stock exchange announcement and SEC filings for more details. These documents are available on our website. Thank you. And now over to Bob.
Robert W. Dudley:

Thank you, Jess. Today we are reporting our third quarter results in what has been another consistent quarter of operational delivery for BP. It is also a quarter where we have all seen continued volatility in the environment and our industry remains under pressure as it undergoes a major transformation, so it feels like a good time to update you on the direction we're taking at BP and why I remain confident about the future. Our agenda will start with Brian taking you through the results of the quarter. I would then like to take you through the enduring principles that form the foundation of our strategy to grow value for shareholders. This section is in response to your request, as shareholder feedback, to have more visibility on our direction, our portfolio and growth prospects. It is slightly longer than usual and we trust you will find it useful. I'll then hand back to Brian to address more specifics on our financial framework out to 2017. Then after summarizing, there will be time for your questions. So first over to Brian for the results of the third quarter.
Brian Gilvary:

Thanks, Bob. Starting with the environment. Brent oil has averaged around $50 per barrel this quarter, down from $62 a barrel in the second quarter. Although global demand has been stronger and U.S. production has begun to decline, OPEC production is running higher than the 2014 average and inventories continue to increase. As we have mentioned before, there is also the prospect of Iranian production coming onto the market in 2016. Henry Hub gas prices averaged $2.77 per million British thermal units in the third quarter, slightly higher than the second quarter, as United States gas power generation expanded and year-on-year production growth slowed. European and Asian spot prices have remained weak throughout the year. The global Refining Marker Margin averaged $20 per barrel in the third quarter, the highest level for three years, as margins continued to be supported by strong gasoline demand. Meanwhile, light/heavy U.S. Canadian crude spreads recovered from the six-year low of $8.29 per barrel in the second quarter to $14.52 per barrel in the third quarter. We expect the usual seasonal decline in refining margins in the fourth quarter. Turning now to the results. BP's underlying replacement cost profit in the third quarter was $1.8 billion, down 40% on the same period a year ago and 39% higher than the second quarter of 2015. Compared to a year ago, the result reflects significantly lower upstream realizations partly offset by lower cash costs across the group and strong performance in the downstream. Compared to the previous quarter, the result reflects lower cash and non-cash costs partly offset by the lower upstream realizations. Third quarter operating cash flow was $5.2 billion. We have also taken a further $151 million non-operating restructuring charge in today's result, bringing the cumulative charge closer to $1.1 billion since the fourth quarter of 2014. The third quarter dividend, payable in the fourth quarter, remains unchanged at $0.10 per ordinary share. Turning to the highlights at a segment level. In the Upstream, the underlying third quarter replacement cost profit before interest and tax of $820 million compares with $3.9 billion a year ago and $490 million in the second quarter of 2015. Compared to the third quarter last year, the result reflects significantly lower liquids and gas realizations partly offset by lower costs, including benefits from simplification and efficiency activities and strong gas marketing and trading results. Excluding Russia, third quarter reported production versus a year ago was 4.4% higher. After adjusting for entitlement and portfolio impacts, underlying production decreased by 2.2%, mainly due to higher seasonal turnaround activity. Compared to the second quarter, the result reflects lower exploration write-offs, lower costs from simplification and efficiency and strong gas marketing and trading results partly offset by lower liquids realizations. Third quarter production benefited from the absence of seasonal adverse weather in the Gulf of Mexico. We expect fourth quarter reported production to be slightly higher than the third quarter, mainly reflecting recovery from planned seasonal turnaround activity. In the Downstream, the third quarter underlying replacement cost profit before interest and tax was $2.3 billion, compared with $1.5 billion in the third quarter last year and $1.9 billion in the second quarter. The fuels business reported an underlying replacement cost profit before interest and tax of $1.9 billion compared with $1.1 billion in the same quarter last year and $1.4 billion in the second quarter. Compared to a year ago, this reflects improved refining margins and strong refining operations, cost benefits from simplification and efficiency programs and strong fuels marketing delivery reflecting retail volume and margin growth. Compared to the second quarter, the result reflects strong fuels marketing performance and reduced turnaround activity. The lubricants business delivered an underlying replacement cost profit of $350 million in the third quarter compared with $340 million in the same quarter last year and $400 million in the second quarter of 2015. The Petrochemicals business reported an underlying replacement cost profit of $40 million in the third quarter. Looking forward to the fourth quarter, we expect reduced refining margins and lower seasonal demand to adversely impact fuels margins and volumes compared to the third quarter. Turning to Rosneft. Based on preliminary information, we have recognized $380 million as our estimate of BP's share of Rosneft's underlying net income compared to $110 million a year ago and $510 million in the second quarter. Our estimate of BP's share of Rosneft's production for the third quarter is just over 1 million barrels of oil equivalent per day, broadly similar compared with a year ago and 1.4% lower than the previous quarter. In July, we received our share of Rosneft's 2014 dividend, which amounted to $271 million after all taxes. In other business and corporate, we reported a pre-tax underlying replacement cost charge of $230 million for the third quarter compared to $290 million a year ago and $400 million in the second quarter. The average quarterly charge for the first nine months of 2015 is $300 million. This is lower than our guidance and reflects benefits from our simplification programs and improved performance in our other businesses. The underlying effective tax rate for the third quarter was 39% compared with 41% a year ago and 35% in the second quarter. Compared to the second quarter the rate is higher, mainly due to the effect on deferred tax balances of the strengthening U.S. dollar. Turning to Gulf of Mexico oil spill costs and provisions. As previously announced, BP Exploration & Production reached agreements in principle with the United States government and five Gulf Coast states to settle all federal and state claims arising from the Deepwater Horizon oil spill. The settlement provides for principal payments of up to $18.7 billion over a period of 18 years as fully set out in our announcements in July. During the third quarter, we have continued to move forward with these agreements in principle. The vast majority of local government entities elected to participate in the settlement, signed releases and were paid from funds previously provided and within the trust fund. Early this month, the United States government filed a proposed Consent Decree with the court which began a 60-day public comment period, and the court has scheduled a hearing for the final Consent Decree on the 23rd of March 2016. We also signed a definitive economic settlement agreement with the five Gulf Coast states, which is conditional upon the court's approval of the proposed Consent Decree. The settlements do not include claims relating to the 2012 class action settlement with the Plaintiffs' Steering Committee, including business economic loss claims not provided for, private claims not included within the class action settlement, or private security litigation in MDL 2185. The charge taken for the accident for the third quarter was $430 million, which takes the total cumulative pre-tax charge to $55.0 billion. This reflects around $460 million related business economic loss claims not provided for, credits to other provisions and the ongoing costs of the Gulf Coast Restoration Organization. It is still not possible to reliably estimate the remaining liability for business economic loss claims and we continue to review this each quarter. Of the $20 billion paid into the trust fund, $17.8 billion has now been paid out. Costs not provided for are being charged to the income statement as they arise each quarter. The pre-tax cash outflow on costs related to the oil spill for the third quarter was $210 million. Moving to cash flow. This slide compares our sources and uses of cash in the first nine months of 2014 and 2015. Operating cash flow in the first nine months was $13.3 billion, of which $5.2 billion was generated in the third quarter. This compares with $25.5 billion in the first nine months of 2014 and $9.4 billion in the third quarter of 2014. Excluding oil spill related outgoings, underlying cash flow in the first nine months was $14.3 billion. This reflects the impact of lower oil prices on earnings as well as a build in working capital of $1.8 billion, which we expect to mostly unwind in the fourth quarter. Organic capital expenditure was $13.2 billion in the first nine months and $4.3 billion in the third quarter. We received divestment proceeds of $2.6 billion in the first nine months of this year, including $290 million in the third quarter. I'll now hand you back to Bob.
Robert W. Dudley:

Thanks, Brian. And I think that is a good set of results. Obviously, the landscape has changed for everyone, but I think the numbers show that BP is competing well in the current environment. I will come back to the reasons for that and to our future plans, but let me start by taking a step back and looking at how we got to where we are today. Late last year, we moved quickly and decisively to reset BP for what we expected could be a sustained period of low oil prices. Not everyone shared our view at the time. Earlier this year, the forward price strip for Brent oil pointed to prices of almost $80 before the end of the decade. Some even speculated that prices might rebound quickly to previous levels. The market is now pricing in a much flatter trend for the oil price to 2020 and beyond. This is driven mainly by the expectation that supply will continue to be strong and there is a more cautious outlook on Chinese demand growth. This reinforces the need for a business model that can withstand a longer period of lower oil prices, and we've been resolved to that for some time. More importantly, we believe we are well positioned in our industry to take advantage of the opportunity this brings. This new environment has provided a much-needed catalyst to rebase our industry and instill greater efficiency right across our sector, and there are advantages for those who are most adaptable. The ability to adopt a more efficient business model will become a point of differentiation. It's an environment that encourages companies, both producers and the service sector, to work closely together and innovate in the way we work with each other and with resource holders. And it calls on resource holders to do more to incentivize investment in their regions, all of which will help re-establish better long-range returns in our sector, in turn, better supporting the dividend model for those that invest. If there is one thing we have shown you over the years, it is that BP has the ability to adapt to changing circumstances and navigate through uncertain times. It is part of who we are. It's a legacy that has come from the learnings of decades and our more recent troubled past, and it comes from how we think about and engage with the world during both good times and trying times. Our history has given us a strong desire to be pioneering and to be good at business, always looking to see and capture the opportunity in any situation. But we are very clear that, before we do anything else, we need to be a strong operator
Brian Gilvary:

Thanks, Bob. Now that you have the overall perspective Bob presented, I'll start by outlining the key elements of our financial outlook for the next few years as we continue to recalibrate to the current price environment. Our principal objective over the medium term is to re-establish a balance in our financial framework, where operating cash flow covers capital expenditure and the dividend. As Bob laid out, we aim to do this while maintaining safe and reliable operations, preserving core growth activities and sustaining the dividend. This reflects a belief that our dividend is set at a level consistent with the long-range cash generating capability of our underlying businesses. With the steep fall in oil prices late last year, as Bob highlighted, we acted quickly to reset the company for a period of sustained lower prices, a transition we expected to take about two years. We are making strong progress on resetting both the capital and cash cost base of the group. We now expect organic capital expenditure to be in the range of $17 billion to $19 billion per annum through to 2017. Group controllable cash costs are expected to reduce by over $6 billion by 2017 compared to 2014. With these plans in place and continued strong operating performance across our businesses, we expect to rebalance organic sources and uses of cash by 2017 at an average Brent oil price of around $60 per barrel. Organic free cash flow is expected to grow thereafter at constant prices. This underpins our ongoing commitment to sustaining the dividend as the first priority within our financial framework and restoring growth in distributions to shareholders over the long term. On divestments, as Bob noted, we are approaching completion of our $10 billion divestment program by the end of 2015 and expect to announce a further $3 billion to $5 billion of divestments in 2016. In 2017, we expect divestments to average the historical norm of around $2 billion to $3 billion per annum. We will continue to manage gearing with some flexibility around the 20% level. Turning to these points in more detail and starting with capital expenditure. As mentioned, we now expect organic capital expenditure to be in the range of $17 billion to $19 billion through 2017, although closer to $19 billion this year. For 2015, this compared to our original guidance of $24 billion to $26 billion for the year, subsequently revised at the mid-year to below $20 billion. The reduction in 2015 spend largely reflects the re-phasing and optimization of activity in the Upstream. In exploration, we have focused activity into high-value, near-field opportunities with less frontier exploration. We have shelved some marginal projects and reprioritized activity in the base. At the same time, as Bob described, there are examples of strong deflation in the sector. We will continue to pace the timing of our investment decisions to best realize the deflationary opportunity while actively driving capital efficiency into the way we build and operate projects. So we will continue to take final investment decisions on projects, but only when we think the timing is right for each project. In our Downstream and other businesses, we're only advancing very carefully selected projects that complement our strategy. As we lock-in deflation over the next few years, this structurally lower capital frame still supports a level of activity we consider optimal to grow value for shareholders from our portfolio of options over the longer term. Turning to cash costs. We continue to make strong progress on right-sizing the group's cash cost base while seeing the benefit of the investment we have made in improving asset integrity. Our intensified efforts across the whole of the group to structurally reset the cost base in response to the low price environment have also taken hold and are increasingly evident in our results. Non-operating restructuring charges are now expected to approach $2.5 billion in total by the end of 2016 as we continue with these efforts. This compares to the $1 billion of restructuring charges we initially announced in December of last year for the period to the end of 2015. Total group controllable cash costs for the nine months year-to-date are $3 billion lower than the same period last year. As you have seen, the actions we continue to take are wide-ranging across both the Upstream and Downstream and we remain very focused on further simplification within our functional and corporate activities. This rapid progress in part builds on initiatives already started in 2013 and where we now benefit from having made a head start. Looking ahead, we still see a material opportunity to further reduce the cost base. By 2017, we expect total group cash costs to reduce by over $6 billion compared to 2014, with nearly half of this already captured. Looking at free cash flow beyond 2017. By 2017, we expect to be working off a reset and structurally more efficient platform, both Upstream and Downstream, with sources and uses of cash for the group balancing organically at oil prices of around $60 per barrel. In this environment and based on our planning assumptions, we would expect free cash flow growth from 2018 restoring our capacity to grow distributions to shareholders. In the Upstream, growth in operating cash flow will be driven by continuous organic growth from the start-up of our next tranche of major projects and the ongoing efficient management of our base at the same time as maintaining our strong focus on capital and cost discipline. Any recovery in the price environment would offer further upside, as illustrated on this chart. Equally, if events or prices are below this level, more deflationary correction will be required than currently built into our plans. At the same time, continued strong performance from our Downstream through delivery of further efficiencies and marketing growth brings a degree of resilience to this outlook. Turning to divestments. Total divestments since 2010, as Bob described, are now approaching $50 billion, or nearly $75 billion including the sale of our interest in TNK-BP. To-date, we have agreed $7.8 billion of our $10 billion program for the 2014 to 2015 period and expect the cumulative total to approach $10 billion by the end of the year. As already noted, we expect $3 billion to $5 billion of divestments in 2016 and ongoing divestments averaging around $2 billion to $3 billion per annum thereafter. The divestments we made over the last five years initially included the necessary steps we took in the aftermath of the oil spill, but went on to divest non-strategic assets, capturing prices commensurate with $100 per barrel oil price. In the current environment, we continue to pursue divestments as part of our ongoing strategy to actively manage our portfolio, as Bob described. In addition to this strategic objective, the cash proceeds provide flexibility for the balance sheet to manage continued oil price volatility and to meet our Deepwater Horizon payment commitments to the United States. Lastly, just a few words on gearing. At the end of the third quarter, gearing stands at 20%, including the impact of the Consent Decree and agreements with the Gulf States. This compares to the 10% to 20% target boundary we established in 2010 to allow greater flexibility for uncertainties, of which Deepwater Horizon was the most significant. As mentioned, with the recent filings in the United States, we have moved a step closer to finalizing these agreements, which provide for payments over an extended period. With that context, we will manage gearing going forward, allowing some flexibility around a 20% level while volatile market conditions remain. I'll now hand you back to Bob.
Robert W. Dudley:

Thanks, Brian. To sum up, we believe we are navigating through the current challenges in a way that is characteristic for BP. I am confident we will adapt to this new world and do so with competitive advantages. We've worked hard to build a track record of delivery. In 2011, we laid out a 10-point plan and you saw it delivered in 2014. In February, we laid out a set of priorities to respond to lower oil prices, and you can see us delivering on those priorities in our results today. And we are very energized about our plans for the future. With our recent agreements on the largest remaining legal exposures in the Gulf of Mexico moving towards closure, we are able to focus fully on this future. Our strategy is built around maximizing the potential of a strong and well balanced portfolio. I remain convinced of the potential of this portfolio in any environment. Together with our ongoing focus on capital and cost discipline, this gives us confidence in being able to grow free cash flow and distributions over the long term. Near term, it is a challenging time for our industry, but we are making the sustainable changes that are needed without compromising our longer-term goals. Our financial framework shows us rebalancing organic sources and uses of cash by 2017 in a $60 world. This supports our commitment to sustaining the dividend and it remains a strong priority. So I believe we have set a clear course. It's based on a set of enduring principles that reflects our proven ability both to innovate and find new ways of working as well as to deliver as an operator day by day. It's often said in business that it is the most adaptable who survive and succeed. BP has adapted many times in its history
Jessica Mitchell:

Hello, everybody. Welcome back. Thank you for holding on, to those who have been on the phone for some time. I believe some folk may be having problems with the telephone lines, in which case, please do submit questions also via the web. In the meantime, we'll take the first question from Oswald Clint of Sanford Bernstein. Are you there, Oswald? Okay, I'm not hearing anything from Oswald. So moving to Gordon Gray of HSBC. Are you there, Gordon? No. Okay, sorry. We seem to be having some technical difficulties and we have no questions working at the moment. Perhaps we could just pause for a moment and we'll get back to you as soon as we can. Okay, so we do have one question coming through on the web from Richard Griffith of Canaccord and that is, what oil price is required to balance sources and uses of cash if Deepwater Horizon payments are dropped?
Brian Gilvary:

Thanks, Richard. It's Brian Gilvary. It's a pretty simple calculation. From 2017 onwards, the payment schedule looks like about $1 billion dollars a year over the 18 years in terms of the settlement. So that's the difference. In terms of the additional revenue you'd need, there's $1 dollar per barrel you could put on that. But actually, the way we're thinking about this is that the key is we need to ensure that the dividend and CapEx is covered by operating cash flow. And that's the commitment in terms of 2017 at $60 a barrel, and choosing $60 as the number that's currently in the forward strip. And that any commitments associated with Deepwater Horizon settlements will come from ongoing divestment proceeds. And we've said there's $2 billion to $3 billion of churn going forward, so they will be accommodated by that, but that's not the way we're thinking about it in terms of oil price.
Jessica Mitchell:

Okay, thank you. We have another question. What is the expected timeline for Whiting to return to the heavy sour slate it was running before the recent corrosion issues? And that question comes from Jack Hogan. Thank you, Jack.
Tufan Erginbilgic:

Thanks, Jack. I think that outage was only for 15 days. After that, we actually went back to normal levels of running, which is Whiting is capable of running more than 400,000 barrels per day total production and also capable of 280,000 to 300,000 barrel per day heavy as part of that. So it was only for 15 days. We actually went back to our normal levels.
Jessica Mitchell:

Okay. And another question from [Barack Salmon]. Thank you. It's a question on refining margin outlook. Can you give us some color on your refining margin projections for 4Q 2015 and 2016?
Tufan Erginbilgic:

Okay. I think 4Q 2015 is, as we highlighted in our presentation, margins effectively went back to seasonal levels that you should expect. Because in 2Q and 3Q, what has been driving the margins, refining margins, was mostly gasoline cracks. In this season, obviously gasoline demand goes down, but also gasoline pool, you can actually put other things into gasoline pool because of the spec requirements. So it is expected that 4Q margins will be lower and we already see that at this point in time. When it comes to 2016, I think the way you may want to think about, we expect refining capacity increase next year around 1 million barrel per day. And right now, the consensus demand increase for the next year is around 1.3 million barrels per day, but that includes some biofuels and NGL as well. So you should take out 0.2 million barrels, 0.3 million barrels of that. As a result, I think this demand will continue to suffer refining margins through 2016, but surplus refining capacity will be higher than 2015. That is how you should keep the refining margins in your mind, I suggest.
Jessica Mitchell:

And thanks, Tufan. And we'll stick with the web questions for the moment while we're sorting out the phones. Thank you for your patience. So I have two questions here from Biraj Borkhataria of RBC. The first one being, regarding new projects' $60 per barrel breakeven for the majority, then what would it take for you to sanction them today?
H. Lamar McKay:

Hi. This is Lamar, Biraj. The graph that we showed you shows breakeven for a range of prices. And the point was that about 80% of our projects break even below $60 a barrel. A significant majority of those are quite below $60. So some of those are going to get sanctioned, as Bob said, as they get worked and they're understood as to the optimum approach to the market, the optimum timing and are we ready to go and do they compete in the portfolio. But the majority of those are going to work through the system based on their current breakeven prices. However, I will reiterate one thing Bob said. That graph is moving downward still. We're still pretty early in the deflationary cycle on these major projects, so that graph is still dropping. So we'll see improvement over that whole spread. And some of those are going to be ready for FID this year, next year and on beyond.
Jessica Mitchell:

Okay. And a second question from Biraj. Looking for an update on Oman. Would you like to go with that again, Lamar?
H. Lamar McKay:

Yeah. And the editorial point of Biraj's question is it's a big source of cash flow in 2017, 2018 plus. Oman's going well. We're drilling wells. We're having good well results. We're on schedule. We're on time. The facility's being built. It will be on, as Biraj has mentioned, 2017, 2018. It is a good and solid source of cash. We're pleased with our progress on the project. So like many of our projects that are in execute right now, these major mega projects that are on schedule, if not ahead of schedule, and on plan as far as their resource development as well as their costs.
Jessica Mitchell:

Next question from Theepan Jothilingam of Nomura. He's asking a question about the cash costs being driven down by another $3 billion. And he's looking to understand if we can split that between what is variable to price and what is sustainable for the future and also what is related to lower activity levels.
Brian Gilvary:

Okay. Thanks, Theepan. And the bulk of the cash costs we're talking about are cash fixed costs, so, therefore, they are sustainable on a go-forward basis. In terms of the breakdown, it's pretty much across the piece. Upstream, the bulk of it is in the Upstream. Pretty close to half of the $6 billion is coming from the Upstream. But a very big proportion is coming out of Downstream and out of the corporate and functions restructuring that we put in place back in 2013. So in terms of its next phase, more than 50% will be coming out of the Upstream, 30% to 35% out of the Downstream and the balance out of corporate and functions, given that we've taken quite a big chunk out of that area already. In terms of the types of activity, it's across the piece. But maybe Lamar can give just a couple of examples in the Upstream in terms of what's happening versus people, deflation and so on.
H. Lamar McKay:

Yeah, our progress on cost has been strong and. As Brian said, a majority of that is going to be Upstream. If you want to dimension roughly where it's coming from, 35% to 40% of that is third-party spend, 35% to 40% is head count and probably about 25% is operated by others costs all going down. We've seen reduction in everything from very, very small items to very large items. And as I said earlier, we're a bit early in this deflationary cycle, I think, and we expect to see more deflation not only in the CapEx side but also in the operating side. And we are seeing people work very hard to get more efficient, minimize duplication and maximize standardization. Theepan, you have a second question about what's the average margin of your new barrels versus the current base E&P portfolio at $60 a barrel. Well, of course, this is a moving piece, as prices are changing and our projections of cost are changing. But in effect, the oil projects will have higher margin than the current segment average at $60, and the gas projects will have lower margins. The average in the aggregate is about right at the segment average. And it will vary project by project, year by year. So I think we can't say that the new projects going forward are double the cash margin of the segment average, as we were a few years ago with some projects that came through, but we do have very solid projects both on the oil side and on the gas side coming through.
Jessica Mitchell:

Okay. Great. We'll take the next question here from Blake Fernandez on the web. He's looking for some direction on DD&A for 2016.
Brian Gilvary:

Yeah, so, Blake, in terms of DD&A, we typically give guidance as we get into the fourth quarter results in terms of outlook for next year, and we'll do the same again in February. But the basic assumption you should assume is it's flattening right now given that the CapEx has come down quite significantly. But we still have the depreciation that we're working off and the previous investments, so we still have a big chunk of projects in train that Bob described. That DD&A will flow through the system, but I think it's a fairly reasonable assumption it flattens off in the future, but we'll give you some more guidance around that in February with the 4Q results.
Jessica Mitchell:

Okay. And a second question from Blake regarding the recent LNG contracts in China. Looking for some color on S-curves being included and the terms in relation to existing contracts.
Brian Gilvary:

Yeah, Blake, so the deal that you saw announced last week was a 20-year supply deal into China. We don't normally share the contractual arrangements around those deals, but they sit as part of our global LNG portfolio and they'll be managed as part of that and sourced from different options that we have within the portfolio.
Jessica Mitchell:

Moving on now to Martijn Rats from Morgan Stanley. He has a question related to the sources and uses of cash. He's asking, with a dividend of around $7.5 billion and the CapEx guidance that we've provided, whether we are effectively guiding for operating cash flow of around $25 billion to $26 billion? And he'd like to know how that splits between Upstream, Downstream and Rosneft and what the underlying assumption for refining margins is in our plans.
Brian Gilvary:

Thanks, Martijn. And, yes, your math is absolutely correct. So that's exactly the way to look at it. So you're in the right range in terms of balancing things up. And we have never given a sub-split of cash flow by segment and we wouldn't plan to start now. But of course, it looks very different at $50 or $60 a barrel than it looked at $100 a barrel. But, no, we don't really give the breakdown in terms of sub-segmentation of cash.
Jessica Mitchell:

So thanks for those questions, Martijn. And turning now to Oswald Clint from Sanford Bernstein, who'd like to know what we need to do to get U.S. [arc] back up to profitability and whether that's continued production cost reduction or gas price and NGL prices that need to rise?
H. Lamar McKay:

Let me take that, Jess. This is Lamar. Oswald, I take it by your question you probably mean Lower 48 rather than all of U.S., Alaska, Gulf of Mexico refineries, et cetera, so I'll talk about Lower 48. We want to get that business where it is profitable at basically about $3 an Mcf. Now we're below that, quite a bit below it as of today, and get that free cash flow positive around $3. Now, that's not the easiest thing in the world, but that's what we've given the team to shoot for. And they have made massive progress on cost, where I think we're basically competitive in each basin that we operate. And they are making fast progress on capital, as Bob showed you on the slide. And those green dots, by the way, on that slide that you saw basically go top to bottom sequentially. So we're making good progress. Yeah, $2.10 is not going to be great, but the business I guess will adjust to that over time. But really, we're thinking something more towards $3 to have a really viable business there and have a chance to develop the assets that we have.
Jessica Mitchell:

So just sticking with Oswald's questions for the moment. He has one asking whether sustainably embedding the cost savings is realistic. Given that the industry is terrible for witnessing re-inflation when prices rise, what is BP doing to ensure that inflation doesn't filter through BP again?
H. Lamar McKay:

Well, Oswald, that is a great question. We're doing several things. One is the approach we're taking, and I hope our contractors would back me up on this, is that we're not trying to just slash and burn everything and beat people to a pulp to get rates down. We're trying to work with our contractors to, in effect, acknowledge that we're in business together, that we've got to do something that is sustainable, whichever way prices go. So we're trying to work constructively with terms, with lengths of contracts, with flexibility for ourselves and contractors to do this the right way. We're also doing some things that they may sound kind of small, but I think they're important, as we consolidate footprints and consolidate building spaces around the world, which by the way in Houston we're doing, Southern U.K. we're doing quite aggressively. We plan on sticking with that and not expanding that footprint into the future. We are working our plans on cost much harder than we have in the past. And we see that as a line item to manage at the same intensity going forward as we do production or anything else. So there have been some changes and we talk about this quite a bit. There's no silver bullet, of course, and we're not immune to any pressures that may occur. But we will do everything we possibly can to make sure that we hang onto the margin the best way we can if these things turn around in any way in terms of prices. Tufan, do you want to say something?
Tufan Erginbilgic:

Yeah, let me add to that from Downstream perspective. First of all, so far our costs are 15% lower. And third-party costs as well as internal costs, similar reduction we achieved. And none of that actually has anything to do with deflation because we don't actually experience any deflation in Downstream. What we are doing is, in addition to third-party reductions I mentioned, internally we are simplifying our business model. And actually we took one layer out; we eliminated significant activity in the Downstream head office. Therefore, we expect 40% lower costs in the Downstream head office costs. And then in the businesses, we are eliminating duplication. And effectively all the businesses, fuels, lubricants and petrochemicals, we are making them simpler, no duplication and actually leaner models. So they are all sustainable because of that.
Jessica Mitchell:

Thank you. So just to give an update, we are still having technical difficulties with the telephone lines, but we are successfully getting questions through on the web. So could we please ask that for the time being, you continue with your web questions and we will keep you updated. So we have a question here from Guy Baber of Simmons. He's asking about the level of capital guidance. And he's looking for confirmation as to whether this level of spend needs to be accompanied by some level of inorganic activity to 100% replace reserves and grow through the cycle. And he's asking because he sees the implicit F&D cost of that framework as being further below where it has been recently trending and what deflation might imply.
H. Lamar McKay:

Guy, yeah, let me address that. The range of CapEx we've described, we believe that we can grow the company moderately, as we've said. Now, if you look at reserve replacement, obviously that's going to be weak right now. We do think, as Bob said, he mentioned an approach to renewing the company. And if I just repeat that in a little bit different words, we do have an organic exploration that we will continue. We are not sizing that organic exploration to 100% replace reserves because we're also working on discovered resources we have as well as resources within the portfolio that we think technology and deflation will unlock. And then we are also very active in accessing unconventional resources, such as Oman, such as the Chinese deal that we talked about earlier or you've seen earlier this week. And there may be places, as Bob said, for deepening in other acquisitions. So I think the way we're looking at renewal is organic exploration, pull through of resources we already have, new unconventional access and the potential for acquisition. And those are all viable. And, of course, they'll be lumpy year to year, but those are all viable sources of renewal.
Jessica Mitchell:

All right. Next question from Lydia Rainforth of Bar Cap. And her first one is on cost. She says, I think Bob mentioned adding additional organizational controls. Can you outline further what they are and how they help the cost reduction program? And also, related to that, does 2017 represent the perfect BP from a cost perspective, or is this still a multi-year process?
Robert W. Dudley:

Thanks, Lydia. I'm not sure there is a perfect BP. But what I can say on the costs, what we have done, if you go back to the divestment programs, we had divested over $50 billion. I've said it before, our overhead did not properly adjust to that big reduction in assets. So we were already in action and have been in action really since late 2013 adjusting our cost base. Since then, a group of senior executives have met consistently and frequently and looked at a whole series of changes. And all that work has accelerated now. We've looked at hiring. We looked at projects. We've looked at sponsorships. We've looked at consulting spending. And those decisions have now been pulled in with a group of people who work very closely together at the highest levels of the company. And that's how we're able to I think help drive these reductions in costs through the company, because we've been working on it before this drop in the oil prices. I think I could talk about that for quite a bit, but I think I'll stop there. On the dividend, talk about how you see the scrip program evolving in 2017 and beyond, Brian.
Brian Gilvary:

Yeah, Lydia. I mean, I think the scrip take-up, scrip is something we introduced in 2010 and was heavily supported the investors at the time when it was introduced. We also recognize there will be a degree of dilution, although the scrip take-up for the last four quarters has only been around 5% or 6%. We've offset that dilution in the past with the buyback program that we had post the TNK Rosneft transaction. And we are very cognizant of the fact that in offering a scrip which is taken up by our shareholders, that we need to think about the consequences of dilution going forward. Hence this balancing in 2017 includes the scrip in part of that balance to ensure that actually we can cover the cost of that scrip and reduce the share counts accordingly.
Jessica Mitchell:

All right. So now Kumar Choudhary of Old Mutual Global Investors would like to know what drove the strong gas marketing results this quarter.
Brian Gilvary:

Thank you for that question. It was mostly out of our international LNG operation, although we had a very solid set of results out of our base gas marketing trading out of North America and globally. But the difference versus typical quarters, it's above our average quarter for gas trading. We typically have each year an above-average quarter for both oil trading and gas trading. And in this quarter, it was for the gas trading. And it was certainly a couple hundred million dollars above what we had the previous quarter. But it came mostly out of our international LNG optimization.
Jessica Mitchell:

And Jason Gammel from Jefferies would like to know whether we can identify how much of the controllable cost reductions are in the corporate center and how much arise in the operating segments. Are you sacrificing any organizational capabilities to achieve these cost savings?
Robert W. Dudley:

Jason, hi. This is Bob. Well, first off, every part of the company is being reviewed. And we are, in fact, simplifying the corporate center as well. A lot of the complexity built up after 2010 moved into the company and a lot of it in the corporate center. We question all the things in the work that we drive. We realize we're driving a lot of the complexity in the company ourselves. So there has been and will be changes in the corporate center. In the operating segments there's, of course, a lot of change in the operating segments as well. We know the breakdown between them. We're probably not – we're not talking about that so much publicly. But maybe, Lamar and Tufan, you can talk about the reductions broadly in your segments.
H. Lamar McKay:

Yes, maybe I'll go first. As you said, Bob, it's happening everywhere. So we are obviously already pretty far into this, so we can see where results are occurring. And they're occurring in every single region in the Upstream, every single function. Everybody is at work. We're, of course, trying to involve the whole organization in this so that we can get thousands of small ideas as well as pretty big ideas. I'm pleased with the way this is working. And, of course, we're concentrating as well on staying safe and reliable as we do this. And so it's across every single category of costs in the company and I think people have taken to this and are pretty proud of the progress they're making.
Tufan Erginbilgic:

Just to add to that, I think, again, our 15% reduction on the total costs is coming from everywhere. We are restructuring every business as we go along. Obviously some businesses, especially head office, we can actually restructure more quickly. Some European businesses take more time. But within the timeframe we are taking about, we expect those savings to come in. But it is everywhere. One thing I would say, also manufacturing efficiency we are actually driving as well. But one point on capabilities. The way we are doing this, in line with our strategy, we are actually adding some capability in some places. We have an example for you. We have a reliability program to improve the availability of our refining. We are bringing world-class experts to build the capability there in line with our strategy. So this is definitely not taking the capability out.
Jessica Mitchell:

Right. So now Alastair Syme from Citi has a question about the portfolio. He'd like to know how we think about renewal and, as we look into the next decade, whether we think the exploration program is enough to renew the hopper, or whether we need to look at supplementing this in some way.
Robert W. Dudley:

Thanks, Alastair. Well, we do have more than enough investment options in front of us that we know we're going to have to prioritize. There's no question about that. And that's a good place to be. A decade or 15 years ago, it was harder. Do we have enough? We're certainly going to re-pace the rate of exploration. We have enough exploration acreage acquired over the last three years is more than we had in the nine years before that. We have a number of exploration appraisal activities going on today that could lead to projects not on that list that will reprioritize those options going forward, and some of those will certainly take us into the next decade. Is the exploration program enough to renew the hopper? Do you need to look at supplementing it? I think the kinds of projects we've done, for example, in Oman over years, the kinds of things that we're actually doing in Russia today are the other kinds of things that we can supplement renewal of the resource base, reserve base, rather than just pure exploration. Would you expect to see an increase in spending – you moved here. You also asked me about things that are not on our list, for example, KGD6, which is discoveries we've had underneath the D6 field in India. At the moment, they're not in our list of projects. They're out there as possible options. Today, the conditions in terms of gas pricing are not economic to do that, but we remain hopeful. But the capital can't really flow into there until it's much clearer. Lamar, do you want to talk about the other questions in the Gulf? Paleogene, I think.
H. Lamar McKay:

Yeah, I just wanted to comment, Bob, that there are 50 or so major projects that we have out there. We didn't list every one. I do expect some to rotate in that are not on that list. We're working them hard and I think they, for various reasons, deflation, scope, contracts, those kind of things, terms, I do expect some of those to rotate in. So this list will evolve. I think the basic point is I think between the resources we have in the company plus our resized exploration plus access to unconventionals, I think that is enough to renew the hopper. And as I mentioned, we'll look for opportunistic things to do if there are some that we can deepen in our portfolio through acquisition.
Jessica Mitchell:

All right. Moving on now to Bertrand Hodée from Raymond James. He has a first question. Looking for an update on Mad Dog South. What our latest cost estimates are relative to the around $10 billion back in July and whether we expect the costs to still go down further and also whether we are confident on FID of those late in 2015 or in 2016?
H. Lamar McKay:

Let me take that, Jess. Mad Dog, we're still working. It is improving. It is more than likely – very, very likely to be below $10 billion. We're trying to understand exactly when the optimum timing for that is. We're working with our partners and I do have confidence that we will get to sanction here probably in early 2016. We'll see. We'll see where we and our partners get to. But I do feel good about that. And I feel like, back to Bob's point earlier about returns on new projects, I do think that will put Mad Dog in a competitive return window and structurally lock in those costs going forward to build a very, very important Miocene project in Gulf of Mexico.
Jessica Mitchell:

And a second question from Bertrand. When looking at the breakeven at $60 a barrel, what is our weighed average cost of capital?
Brian Gilvary:

We don't disclose that, I believe, in the Annual Report in accounts, we don't actually give out our weighted cost of capital. And it's stayed pretty stable actually over the last five years. There was a slight uptick post-Macondo, but it's back to sort of where it was in pre-Macondo levels.
Jessica Mitchell:

Okay. Turning now to Gordon Gray from HSBC. Gordon would like to know whether the new CapEx guidance, which represents a near 30% fall from the old guidance, whether this spending level is driven by the financial framework as opposed to other factors? In other words, he says, what's the confidence level that you can give us that this level of spend is enough to sustain growth post-2017 and post-2020? And would we expect to see an increase in spending in an outcome of crude prices above the $60 per barrel scenario in the medium or long term?
H. Lamar McKay:

Let me take it from an Upstream perspective. I think from what we can tell, the activity level that we would set for the Upstream within that frame represents what we would like to do. Portfolio is quality enough that we think we can grow it moderately. Now, if prices go up and we get some inflation, as I said earlier, we'll do everything we can to maintain the capital efficiency, eat inflation, if at all possible. And the implication is not here that if prices go up a little bit, we explode CapEx. We have a very, very, I think, quality portfolio that we're going to work hard to stay within this frame and do everything we can to not have inflation eat us up. So we're not choking back activity to fit a frame, if that's what you mean. Obviously, on the margins, we've got some things we're sliding around and re-phasing and re-scoping, but it's not a big choke-back on capital that we would explode if the prices went back up.
Jessica Mitchell:

All right. And Chris Kuplent of Bank of America is looking for some guidance on depreciation, other business and corporate and the underlying effective tax rate in 2015 and beyond.
Brian Gilvary:

Thanks, Chris. I think we said earlier that we expect DD&A to continue to flatten. So it's around $15 billion, which is where we came in guidance this year. And I would expect to see that trend going forward, so expect it sort of flat. On other corporate, we are trending about $100 million a quarter below the guidance that we had for this year. That's because we're seeing some of the cost simplifications coming through, but also some positive results out of our other businesses that we hold under the corporate line. And then in terms of underlying effective tax rate for 2015, the last five-year range has been in the range of 30% to 36%. I think we guided you at the start of this year below last year, which was, from memory, 35% or 36%. And I think it will be in that range of 30% to 36% going forward. I think that's a pretty good range.
Jessica Mitchell:

Moving on. Iain Armstrong of Brewin Dolphin would like to know whether the resetting of BP to a $60 environment is going to be back-end loaded in 2017 or will it be a smooth progression.
Robert W. Dudley:

Iain, hi. This is Bob. We started to see the results come through in the second and the third quarter this year fairly rapidly. In fact, I think we're going to go into 2016 with lots of momentum. I think it will not be back-end loaded. I think part of the question is, how fast with our suppliers will the deflation come through for part of it and then the other question is around labor flexibility. Different geographies you can move faster in terms of reduction of cost. That's why some of those will be well out into 2017, but there'll be a lot of activity in 2016. I think it's going to be a smooth progression.
Jessica Mitchell:

And so now Aneek Haq of Exane has a question to put to Lamar. He'd like to know whether, given the reset in project costs that we are currently experiencing, whether we can comment on areas of our portfolio where we are incrementally more positive than where we were a year ago. And on the offset, those where we are seeing less cost deflation on a relative basis.
H. Lamar McKay:

Aneek, two big areas where I feel much more positive than I did a year ago. One, I knew that Lower 48 would react fast. There was zero doubt in my mind about that. What I didn't know and didn't realize is actually the rest of the world is reacting pretty fast in terms of deflation and minimizing duplication and getting more and more efficient. So incrementally more positive that this is broader and more significant in terms of the speed of deflation than what I thought a year ago. Second dimension is that it's not only CapEx, it's operating costs as well. And partly is that that's our own efforts within BP, but also the efforts of our contractors in our producing areas. So I do feel more positive overall about the rate of progression here. There are areas that obviously they're more aggressive than others where rigs and things like that, seismic, pretty aggressive. Other things may be a bit slower. But I feel more positive about how this is deflating than I did a year ago.
Jessica Mitchell:

And then Aneek also had a question for Bob. Can you talk us through the latest thoughts on buy versus development of production?
Robert W. Dudley:

Aneek, right. Certainly any developments we're going to do have to meet these hurdles that Lamar described and we described in the presentation. We think those are good investments. I think the first thing in terms of buy is when people approach us about deepening in our existing projects and fields in production, some of that's starting to happen now. But I think what I think I don't want to signal is we're going to be out looking for acquisitions. They have to be very good deals; they need to tailor fit our portfolio. And that's probably the best thing to say right now.
Jessica Mitchell:

Turning now to Neill Morton. Neill would like to know whether the reduction in capital expenditure from the $24 billion to $26 billion original guidance down to the $17 billion, $19 billion, whether we can give a rough split of that between lower activity and lower costs or deflation.
H. Lamar McKay:

I'll give you an Upstream perspective first. Obviously, I don't have a number on this and I don't want to give a percentage, but I would say the majority of it, if not the vast majority of it, is lower costs and deflation. There is attenuation of activity of some lower return activity and the re-phasing of things. But it's mostly lower costs and deflation and how we're optimizing the scope and standards by which we do things. So we were already at work at much of this, which is a good thing, and I think the deflation has been a wind at our back to help us get some of this done.
Jessica Mitchell:

And Neill is also asking for the Refining Marker Margin assumption behind the 2017 cash neutrality position.
Brian Gilvary:

Yeah, Neill, it's Brian. I'll pass you over to Tufan. But I think you'll see it on the slides, we have it there. It's $15 is the assumption that we've used out in 2017 along with $3 Henry Hub and $60 a barrel oil. But remember, the Marker Margin is just the marker; it doesn't actually tell you what's going on in the real refineries. I'm sure Tufan can give you a lot more detail behind it.
Tufan Erginbilgic:

Thanks, Brian. Just, Neill, I think how you may want to think about this, $15 is obviously lower than this year's margin environment. Earlier on I talk about 1.3 million barrels increase in the demand for 2016. Current assumptions for 2017, similar demand increase are expected. If those increases happen, I think we expect that refining margins will continue to be supported, not at the current 2015 level, but around the levels that Brian mentioned.
Jessica Mitchell:

Okay. Next question from Irene Himona of Soc Gén. Irene would like to know what industry cost deflation assumption we factor in behind the reduction in CapEx and the over $6 billion cash cost saving.
Robert W. Dudley:

Given that the Upstream spend is about 85% of the capital, Lamar?
H. Lamar McKay:

Okay. Thanks, Bob. Irene, there's not, as you can imagine, there's not one assumption on industry cost deflation. We've looked at all of our major spending categories. We've talked to our contractors. And we've also looked at our activity set going forward and have come up with some pretty detailed plans about how we're going to accomplish the cash cost savings as well as the CapEx programs. So it varies. We normally see a lag of one to three years in terms of all of the deflation filtering through. And we've thought about that and worked that. And we have multiple assumptions on every line of types of services that we get. So I'm not going to give you one factor, but we see things 15% to 30% reductions over a three-year period in most every service. And then we've obviously got activity re-phasing and re-scoping that we talked about, which adds to the savings. So we're working in a very, very granular manner rather than sort of a gross assumption basis.
Jessica Mitchell:

So, Irene is also annualizing the nine-month year-to-date operating cash flow of 2014 to get to a number of $19 billion annualized with Brent at $55. She'd like to know what Henry Hub price we anticipate in 2017 and what other sources of improvement in operating cash flow we expect out to 2017.
Brian Gilvary:

Thanks, Irene. So we're assuming, I think as mentioned earlier, a similar Henry Hub price to what we've seen to-date as the year-to-date average. I would assume $3 for 2017 as a planning assumption. In terms of the sources of the cash improvement, the bulk of it is from the costs that we can see coming through in terms of what we've already had this year. Remember that next year you get a full-year impact of those cost savings without the restructuring charges associated with them as well as cash payments this year. So you get an extra kick in 2017 and 2016, hence Bob's earlier answer to Iain's question around the loading of it. It will be quite continuous through 2016 and 2017, so this is absolutely not back-end loaded. And also then from the new projects coming on stream and the revenues associated with that and then all the various pieces that both Tufan and Lamar have explained in earlier answers to questions around the sources of improvement. But it's basically all coming from what I'd call the top line in terms of the overall improvement out to 2017.
Robert W. Dudley:

And Irene asked about the annualization of cash flows. And I know at the second quarter, we said you can't annualize the cash flows based on the quarterly earnings. I know we're three quarters of the way through the year, but we still probably can't and shouldn't answer that.
Brian Gilvary:

Yeah, thanks, Bob. I forgot about that part. We do have a working capital bill this year of $1.8 billion already year-to-date, which you'd expect the bulk of it to unwind. So you're not a million miles away from where the absolute number may come out, but there's a lot that can still happen between now and the end of the year. But you're right. It's year-to-date about $14 billion, some working capital reversals to come through and then some more benefits on the costs to come through in 4Q.
Jessica Mitchell:

All right. Some questions now from Jon Rigby of UBS. And we'll start with a couple for the Downstream. The first is, is the existing $1.6 billion cost improvement in the downstream included in the new cash cost reduction guidance of $6 billion? And also, while we're on the Downstream, he's asking a question about petrochemicals, saying, your portfolio has meant you have missed the pet chem top of cycle. BP's pet chem is well below recent years' profitability. Is that re-achievable and what needs to happen?
Tufan Erginbilgic:

Okay. Thanks, Jon. On the first question, I think short answer is, yes, it is included in the $6 billion. And we actually – I talk about 15% reduction. That represents a good acceleration of that $1.6 billion cost efficiencies. I think, in addition, now we see further opportunities which is also part of $6 billion. Coming to petrochemicals question. Let me remind you first of all why we have narrow portfolio such as aromatics. These two businesses actually grow higher than normal bulk of the petrochemicals business, around 5% to 7% growth between them you actually see. And we have technology and, therefore, cost advantage versus competition. So coming to your question. What has been happening in the industry, especially in China PTA between 2011, 2015, industry actually built up more than 20 million tons capacity. And as a result of that, margins went down – up. What we see going forward, we still see 6%, 7% growth in PTA China, so it's still continued strong growth, which was the case this year as well. And now we have better visibility in 2016 and 2017 additional capacity coming in to PTA China. And I can tell you, given additional capacity, we don't actually foresee loss of capacity to come in in 2016 and 2017. As a result, we expect utilization to start to go up in 2016, 2017 in China PTA, and also one should expect margins to go up in line with that. But let me tell you what we are doing. We set our agenda at a constant margin, we are going to expand the earnings potential of the business. This is exactly what we are doing. If you look at this year's numbers, nine months, you have these numbers – nine months' improvement in petrochemicals is around $150 million. And environment versus last year, more or less the same. So similar environment, $150 million better performance. It is all coming from efficiency, operating improvements and portfolio restructuring. And we will continue on this agenda and you should expect more improvements to come as a result of that.
Jessica Mitchell:

Thanks, Tufan. John would also like to know whether, when we look at increasing shareholder distributions, whether we would focus on buybacks?
Robert W. Dudley:

John, hi. This is Bob. We'll keep all of these things in our toolkit, most certainly. I'd say focus on buybacks is probably not right. We've had many of the discussions about UK shareholders generally having a bias towards dividends, U.S. shareholders having a bias towards buybacks. We balance that. But I think for the moment, we're just absolutely priority is to maintain the dividend through this period, make sure we balance the sources and uses of funds and then we'll have all options open to us. Because I think you'll see that we'll see a growth in free cash flow out towards the end of the decade and that'll give us lots of choices.
Jessica Mitchell:

And I have a couple of questions now coming in from Fred Lucas of JPMorgan. The first would be, he's looking for a real and material example of standardization in Upstream operations or projects.
H. Lamar McKay:

Hi, Fred. This is Lamar. Several things going on here. Over the past several years when prices went up above $100 and stayed there – and I don't think we're that much different than other majors at least, where there was a lot of up-specking and bespoke systems and equipment used for new projects, and I mean that all the way from valves to trees to compressor packages, everything. We have kind of regrouped and decided that on most of the things we do, not everything, but most of the things we do, it's probably been built before and we should be able to get something that someone else has built and get another version of that built or to make sure we use industry-standard equipment. And I'll give you specific examples, like valves, like subsea trees, like compressor packages, use industry standard, which, by the way, the contractors know very well. And if we don't want to use a industry standard for something, there has to be a conscious reason and justification and logic for doing that. So we've kind of flipped the DNA hopefully a little bit here where we use what's worked and we go outside that industry standard if we really need to. And that will cover things like trees, valves, metallurgy, hull design, compressor packages. Those are lower cost, they're easier to do because they've been done before and can be replicated and at a lower risk on delivery. Now, those are probably going to affect projects that are in the new projects in the Gulf of Mexico, big and small, Egypt, Trinidad, and potentially Angola. And it'll bleed into the operational front as we continue to standardize where we'll have an easier time to maintain things as we get the same types of valves, the same types of compressors around the patch.
Jessica Mitchell:

A second question from Fred. Does the goal of sustaining the dividend make BP more pro-cyclical and less able to capture low-cycle opportunities either to invest or buy more and be more tactical?
Robert W. Dudley:

Yeah, Jess, and then I'll ask Brian to comment as well. I mean, the uncomfortable reality here is after five years, only this year can we begin to plan the company with a reasonable sense of certainty after the events in the Gulf of Mexico. And I say that a sense of certainty at least, uncertainty at the same level as the rest of the industry now. So I think it's good for all seasons to make ourselves very fit, very lean, a more focused company that's got a portfolio after divesting well over $50 billion. We like the portfolio that we have and we want to build a company that is fast and quick and very, very competitive. So I think all that's good for all seasons. When and if a really good opportunity unfolds, I think we'll also have the flexibility to deal with that. But, Brian?
Brian Gilvary:

Yeah, and actually not a lot to add to that, Bob. And I think don't forget we have quite a strong balance sheet. We now have clarity on those uncertainties that Bob described going forward. So you have to remember, last year we were surplus cash, Fred, quite significantly surplus cash and our net debt came down accordingly. We're way into this transition phase now having sort of got out ahead of the eight ball quite early in terms of what we could see happening with the price. I think it puts us in a very strong position. And if they provide things that are accretive, which I think is important for our shareholders, and they fit strategic options for us in terms of the portfolio, absolutely we'll look at them. But without them in terms of the balance sheet and where we are, we're in a pretty strong position.
Jessica Mitchell:

Lastly from Fred, when does BP expect the Upstream deflationary cycle to bottom out?
H. Lamar McKay:

Fred, we've looked at history here, and it generally says one to three years is – if things stay relatively stable on a price basis, one to three years is when the cycle kind of finds its stability. So I think I don't see any real reason to think it's different this time. But this, as I said earlier, feels like this is a pretty progressive and aggressive deflating period right now it feels to me. So perhaps it doesn't take quite as long. But that's been the history, with several different examples, really one to three years.
Jessica Mitchell:

Next question now from Thomas Adolff of Credit Suisse. Firstly, what are you doing differently with front-end loading on major projects?
H. Lamar McKay:

Thomas, we're doing all the things we have been doing, plus I think the major change we've made, which relates to what Fred was asking, is how do we approach a major project. And we spend a lot more time as an executive team with the functional heads now before, let's say, we have a discovery or a new access, we get together very, very early on and determine what this project ought to look like. We give some help to the teams in terms of what we would expect in terms of the scope and scale of the project based on the best information we can gather. And we do it less sequentially than we used to. That has offered some opportunities – this is what I mean by rotating some projects in, it's offered some opportunities that I think are going to accelerate some things. And we will do those at industry standard and do those faster than we've done before. So the difference for us is kind of changing our attitude towards how do we do things in major projects. And I think it is really making – it will really make a difference.
Jessica Mitchell:

And a second question from Thomas related to the point of 80% of pre-FID projects breaking even below $60 a barrel. Thomas is looking to know if we are referring to the 33 billion barrels of oil equivalent in contingent resources and how much of that resource base is linked to Henry Hub..
H. Lamar McKay:

Thomas, the 80% pre-FID below $60 represents some of the 33 billion barrels in contingent resources, certainly not all of that. But they're all the projects in the project hopper that Bob mentioned. The resource base that's directly linked to Henry Hub is 7.5 billion barrels, which is the Lower 48 resource base. So other things, you could argue, are related in some way to Henry Hub through baskets and other things, price weighting. But directly, it's 7.5 billion barrels.
Jessica Mitchell:

Right. And Guy Baber back in again from Simmons with a couple of questions on the Lower 48. Really looking for us to expand on the points about reinvigorating underworked acreage and selected inorganic activity, as well as discussing capital allocation in the context of the broader portfolio returns metrics that we highlighted in the prepared commentary.
H. Lamar McKay:

Yeah, Guy. Good questions. The fact is our acreage has been underworked over the last several years. We were down to two company-operated rigs in 2014. We've got 5.5 million acres, about 1 million acres – or over 1 million acres of mineral interest. It's just not been worked very hard over the last 10 years. We're going to work it hard. And what we've asked the team to do and effectively what we're demanding of the team is to get your costs competitive basin by basin. That's pretty much there. And then show us that you can do capital execution and efficiency to a degree such as you can have returns that are competitive with the rest of the Upstream portfolio. We've been relatively lenient in capital this year. That's tightening up as we go forward. And their returns, I'm happy to say, on their incremental activity have been good. And they're using new technologies and obviously looking at what's going on around us. And I feel pretty good. And capital allocation will be a normal allocation process with the Lower 48 and it will be competitive. So the return thresholds will be the same for the Lower 48. As I said, we've been a bit lenient this year. And I'm happy to say that in effect we're in experimentation phase with the new leadership team and they're doing a bang-up job. So I feel good about where that's going.
Jessica Mitchell:

Great. Thanks, Lamar. Turning now to Rob West of Redburn. A first question. What investment hurdle would you have for any potential inorganic uses of capital?
Brian Gilvary:

Thanks, Rob. Like any investment, we'd look at the usual economic indicators in terms of our existing portfolio. But any capital that we'd look to put into those potential acquisitions would have to stack up with the alternative uses of that cash. And as Bob described earlier, we have a very flexible financial frame that it may be better to actually buy back stock versus buying assets. I think providing it's accretive and it hits our economic indicators versus organic investment, then those options will stack up. And ultimately they have to lead back to strategy in terms of being supported by the strategy where we're heading.
Jessica Mitchell:

And a second question from Rob. Can you allay the potential fear that re-phasing spending tacitly means deferring maintenance? Have all of your turnarounds occurred at the same scope as they were originally designed for or have any been slimmed down?
H. Lamar McKay:

Rob, yeah, this is something we talk about a lot. And I think I have a webcast with about 2,000 senior-level leaders this week to talk partly about this. We do not intend to and are trying everything we can to make sure no one in the company delays any spending that's required, appropriate, necessary for safety and reliability and maintenance. And the first priority when I go through in terms of my checklist in terms of our capital program is staying safe and staying reliable and spending appropriate money on the base. I will repeat that and repeat that and repeat that. Have all of the turnarounds occurred at the same scope as they were originally designed? Yes, pretty much. If they haven't, if they've been slimmed down, and some have been slimmed down, they've been slimmed down for a reason and through the operations function, not by a dictate from me or anybody else in St. James's or Houston or anywhere else. So obviously what we do want to do is when we do turnarounds or we do any sort of spending, including safety, is we spend every single dollar the best possible way it can be spent to get the best possible results. And we are seeing savings in that area as well. We're 24% ahead of schedule on our turnarounds this year, but they've been delivered within scope and ahead of time and within cost. So it's something that we concentrate on. You cannot imagine how dedicated I am to not go backwards in terms of safety and reliability.
Robert W. Dudley:

And, Rob, if I could add from our standpoint, actually it's almost become such second nature to us and we should put it in the presentation when we talk about it. This is absolutely the number one thing that we talk about when we review our capital budgets and our spending, whether that's the Downstream or the Upstream. We're not going to sacrifice safety. We're not going to defer things to fit a financial framework in this area. We've been really clear. We're not going to reduce or stop any kind of safety critical training of our employees. There's no company that's more aware of this I think than we have become. And I would note that this year alone in 2015, we had double the number of turnarounds than we did in 2014.
H. Lamar McKay:

That's what I was going say.
Jessica Mitchell:

Rob is lastly asking about us relinquishing 100% stakes in three ultra-deepwater blocks off Uruguay, what drove this decision and whether it was due to gas proneness in the basin.
H. Lamar McKay:

Well, Rob, I'm not going to comment on individual blocks and individual prospectivity. But you can assume that if we drop anything, it's because it wouldn't fit into the portfolio at the prospective returns that we want to get out of it. So that's all I'll say on that.
Jessica Mitchell:

Right. Jason Kenney from Santander is looking for some underlying tax guidance for 2016.
Brian Gilvary:

Sorry, Jason. You're probably going to be disappointed, but I'll refer back to my earlier answer, but it's the range of the last five years of 30% to 36% is still pretty good. We're trending below 36% this year. We'll give you guidance in February next year. But something in that range would be a reasonable assumption going forward.
Jessica Mitchell:

Thanks. And I think we've got Chris Kuplent coming in again from Bank of America asking what business segment do we expect the 2016 and 2017 disposals to come from. And on the assets you have earmarked for disposal, what would have been the expected contribution to CapEx, cash flow, earnings and any other operational metric as we look at it?
Brian Gilvary:

Thanks, Chris. It's a very different portfolio that we're looking at going forward than the ones that we did during the big divestment phase where we sold out of big countries and big producing hubs. And if we just look at the sort of nature of the disposals this year, a big chunk of those will actually come out of the Downstream, a mix of terminals, assets. We'll continue to look at also disposal of early life assets that aren't generating cash today. And you saw that with the Paleogene early this year that we did. So it's a mix and we wouldn't normally give you guidance by segment. The bulk of them this year have come out of the Downstream. It will be a mix going forward. And there's a whole chunk of options that are in the portfolio. In terms of effect on CapEx and cash, that's all been built into that financial frame we've given you for 2017.
Jessica Mitchell:

And Iain Armstrong of Brewin Dolphin is asking whether we expect to take a writedown on both base and probable reserves in view of the lower for longer assumption on oil prices.
Brian Gilvary:

Iain, too early to say at this point. We don't know what our long-run assumptions will be on oil prices. We're still in $80 for the long, long term, and we will go through the whole reserves calculation through the fourth quarter. No early indications at this stage. We went through a whole series of tests in the third quarter looking at the asset base. We have similar plans in place for 4Q. We didn't take any major impairments at the end of 3Q, but you have to wait for 4Q results.
Jessica Mitchell:

Turning now to Lucas Herrmann from Deutsche Bank, who is putting a question to Brian. Does dividend cover on an accounting basis mean anything to BP? And, if so, what level of cover would the company like to move towards and over what timeline?
Brian Gilvary:

That's a trick question from an accountant, Lucas. But I think you and I both know that ultimately you have to have the earnings to justify your distribution of dividends. So, absolutely, that's one of the things that we take into account, but we don't target a specific number. Historically, it's been around 25% of earnings at the $100 a barrel, or somewhere in that range of something in terms of retained earnings. So clearly, as we've moved to $50 a barrel, we're still in the process of transitioning. But absolutely on a point forward basis, it's something we'd look at.
Jessica Mitchell:

And then Lucas would also like to put to Tufan two questions. Firstly, at Whiting, have the facilities stabilized or simplistically what is the further non-market related opportunity for performance uplift from here? And secondly, are you seeing any benefit in lubricants as yet from base oil price falls, or is that to come?
Tufan Erginbilgic:

Thanks, Lucas. First, Whiting question. I think, as you rightly said, the first task is to stabilize. And Whiting is very reliable. Then I think two more opportunities we see on the Whiting performance. One is this is a new kit. And once it is stable, i.e., reliable operations, we are doing some work on optimizing the new kit. You can actually unlock some limitations, and we believe that's going to unlock some value. And the second thing is once it is stable, we are going to be able to drive some efficiencies in Whiting that we haven't been able to do so far. So those are two opportunities which are not market related. And on lubricants, yes, we have seen base oil price falls this year, definitely. But I think here is how you should think about our lubricants business. Base oil price falls are there. On the opposite direction, though, a couple of things going on. Because of the base oil price falls, you get price pressures in the market. So that is one thing. Second thing is most of our lubricants business is outside United States. And given stronger dollar, two significant negative hits we had in lubricants business this year. One is transaction ForEx impact when the ForEx depreciated against dollar in most of the countries. And then the second thing is translation impact, obviously which is self-explanatory. So our performance improvement this year is actually coming from growth markets. We are achieving improvement there, improvement definitely, and it is coming from efficiencies. And we are actually improving our premium ratio, which has a much better margin profile. So that is where it is coming from.
Jessica Mitchell:

Turning back to Richard Griffith of Canaccord. How much harder and how long would it take to rebalance sources and uses of cash if you used $50 a barrel instead of $60 a barrel?
Brian Gilvary:

Thanks, Richard. I think first of all, let me clarify because we got some questions earlier this morning. We have not chosen $60 because we believe it will be $60 in 2017. We just simply took what was in the forward strip as a point in time in 2017 as we transition through to rebalancing the company at a lower oil price environment. So I think that's the first point of clarification. And in terms of this year, we laid plans out at $50 a barrel is what we assumed when we looked at our sources and uses as part of this transition. So that's what we set the plan for this year. We're in the same process in terms of next year. And I don't think any of us are expecting a major uptick in oil prices from where we see today. The supply and demand outlook still, I think, is a bearish one in terms of where the oil price will stay absolutely in the short to medium term through the first half of next year and probably into the second half. In terms of 2017, if it transpires in the back half of next year that we're at $50 or some lower price, of course we'll expect further deflation to come into the system. And I think Bob alluded to that in his presentation. So $60 is not a point in time that we're banking everything on for 2017. It's just simply what the forward curve is saying and we've looked at our sources and uses for that year. So to the degree the price is higher than $60, that will lead to a position obviously where we have surplus cash. To the degree it's below $60, our rules of thumb would tell you a $10 a barrel drop, that would be over $2 billion of cash we'd need to make up, and we would expect to see further deflation come through in the back end of next year. So I think it's just important that we're not locking into a specific price because a lot of things can happen between now and 2017.
Jessica Mitchell:

Okay. And we now have another question from Anish Kapadia. Outside of the U.S., where do you expect liquids growth to come from to the end of the decade and beyond?
H. Lamar McKay:

Anish, hi. Lamar. Well, where our major projects will be in terms of oil developments will of course include Gulf of Mexico, but also Angola. The North Sea we have some big projects coming on over the next few years and there are other projects after that. We believe Azerbaijan will have more oil opportunity as we go forward. And then we've got exploration plays in Brazil, in Nova Scotia and in Egypt that we think and believe could be oil. And of course we've got our Canadian heavy positions that could, at the right point in time, be major projects as well. So we have several places that oil could come from and those will be worked into the project schedule as they compete and get developed.
Jessica Mitchell:

And in Angola, where would you expect production to fall to by the end of the decade?
H. Lamar McKay:

Yeah, Anish, I don't have any direct prediction on where Angola's production is going to be. We don't normally talk about a piece of our portfolio like that, nor an individual country. So I don't have a production prediction for you there.
Jessica Mitchell:

Thank you. And we now have a couple of questions from Fadel Gheit at Oppenheimer. The first one is, do you expect the recent gas discovery by Eni to have to have any impact on BP West Nile Delta gas development?
H. Lamar McKay:

Fadel, no, I don't. That project is underway and the terms are clear and I don't see that having any effect on West Nile Delta.
Jessica Mitchell:

And also from Fadel, does BP need to keep the $32 billion cash balance while having $50 billion of debt?
Brian Gilvary:

Yeah, thank you, Fadel. Of course, that $32 billion includes various standby lines that we put in place after Macondo of the tune of $6 billion to $7 billion. So, no, we would expect to see some of that debt roll off over its natural course over this year, which it has already this year, and through to next year. But we certainly don't need to keep that level of cash balance going forward.
Jessica Mitchell:

Turning now to Jean-Pierre Dmirdjian of Liberum. And he's referring to slide 23 and 45% of the expected Upstream CapEx from 2015 relating to projects. And can we please let him know how much of this is committed in 2015?
H. Lamar McKay:

Jean-Pierre, obviously all of the 2015 spending is committed. And then 2016, I would say most of it and then it starts tapering from there. So there are more options and flexibility as you get further out in time. I don't have an exact profile to give you today, but it frees up as you go along in terms of time.
Jessica Mitchell:

And we'll take the last questions from Dennis Coleman of Bank of America. Can you please update how BP is positioned with the credit rating agencies, given the updated financial framework?
Brian Gilvary:

In terms of the current financial framework, we are A with both rating agencies. And in terms of outlook, like the sector, I think the whole sector is on negative outlook as a result of the oil price across the whole piece. But we are today A is our credit rating. And in terms of what we've laid out today for 2017, I think it's premature to say what impact that may have from a ratings perspective.
Jessica Mitchell:

And the second part of the question...
Brian Gilvary:

Sorry. To be clear, I wouldn't expect it to have, I think in terms of where we've got to now in terms of rebalancing at this lower oil price, I would not expect that to have any impact.
Jessica Mitchell:

And a second part of the question is whether the Macondo payments are included as a payment due obligation in the gearing calculation?
Brian Gilvary:

I think we laid this out on the 2nd of July with the Agreements in Principle. But effectively it's a long-term contractual commitment is the way it's treated. It's an overall impact of 1% on the gearing of the company.
Jessica Mitchell:

Well, thank you, everybody. I'm sorry that the telephone lines let us down today, but thank you for keeping the web questions coming. And I'll now just hand back to Bob to close the call.
Robert W. Dudley:

Well, thank you, Jess. And thank you, everyone, if you're on the line. It's been about 2 hours and 20 minutes, so thank you very much for your patience. Sometimes when you're caught and something isn't working, it's good to let you know we did receive word that the external telecommunications carrier's bridge that supported this telecom has crashed. It sounds all very dramatic. I don't think anyone was hurt. I do know those of you who dialed in could listen, you just couldn't speak. And so thank you all for those many people who shifted over to the web. And we could see the numbers. It was probably the largest call we've had. So thank you for that. The length of this call is actually in response to shareholders, many of you on the line, in fact, who we know well who have given us the feedback to go into a little bit more detail on this quarter. I think you'll see a consistent quarter of operational delivery now, the operational reliability. It is that virtuous circle of safety, reliability feeding through to financial results that we've been working so hard on. I think they do come through again this quarter. It allows us to compete well. Probably the big thing that we're starting to see now is that we can again now plan the company for the longer term. Having progressed the Deepwater Horizon Spill Agreements in Principle is actually a big thing for shareholders. Again, that reestablishing the financial framework, get the operating cash flow to be able to cover the capital expenditures and the dividends is our objective. Our dividend is going to be set at a level that's consistent with the long-term cash generation that we see the underlying businesses have that capability. We've gone through all the numbers there. And supporting all that – and we are trying to make very sustainable changes in our cost structure, we want to support that commitment we've made to sustaining the dividend. And that remains the strong priority for us right now without sacrificing the future growth of the firm. And I think with that, thank you all very much for your patience. And we'll be out and around seeing many of you. Thanks.

BP p.l.c. Q3 2015 Earnings Call Transcript

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BP p.l.c.
Q3 2015 Earnings Call Transcript