Hello, and welcome to BP's First Quarter 2013 Results Webcast and Conference Call. I'm Jessica Mitchell, BP's Head of Investor Relations. And joining me today are Bob Dudley, our Group Chief Executive and Brian Gilvari, our Chief Financial Officer. Before we start, I'd like 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 that 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.
Thank you, Jess, and good afternoon or good morning, everyone, depending on where you are in the world. Thank you for joining us. Today's presentation is mainly designed to take you through our Q1 results, but we also take the opportunity to briefly update you on some important areas of activity. In short, we're reporting a strong set of results that reflects the work we're doing to rebuild BP and make it a company that can grow value safely and sustainably over the years. So as usual, we'll start with Brian taking you through our financial results in detail.
I will then review progress in the legal proceedings in the U. S, including the civil trial in New Orleans. We'll touch on the completion of the Rosneft transaction, where we are now and the opportunity that lies ahead. And we'll give you a brief update on progress in the upstream and downstream. The record shows we are very much on track to deliver the objectives we set out back in late 2011 in our 10 point plan.
And finally, there will be time to respond to your questions. But first over to Brian.
Thanks, Bob. I'll start with an overview of the Q1 financial performance. 1st quarter underlying replacement cost profit was $4,200,000,000 down 9% on the same period a year ago, but 9% higher than the Q4 of 2012. Compared to a year ago, the result reflected the absence of any contribution from Russia prior to completion of the Rosneft transactions on the 21st March as TNKBP was treated as an asset held for sale. Lower upstream production due to the impact of divestments and natural field decline, partly offset by major project delivery and improved downstream results due to a strong quarter in supply and trading and better operational performance within a more favorable refining environment, a positive consolidation adjustment to eliminate unrealized profit on lower volumes of equity crude in inventory at the end
of the
quarter. Around $170,000,000 of this is now permanently unwound due to the divestment of the Texas City Refinery and will not be reversed in future quarters. First quarter operating cash flow was $4,000,000,000 and the underlying effective tax rate for the Q1 was 39% compared to 33% in the Q1 of 2012. Turning to highlights at a segment level. For the upstream, the underlying first quarter replacement cost profit before interest and tax was $5,700,000,000 compared with $6,300,000,000 a year ago and $4,400,000,000 in the 4th quarter.
The lower result versus a year ago largely reflects lower reported production and lower liquids realizations, partly offset by stronger gas marketing and trading activities. Reported production decreased by around 5% compared to the same period last year, primarily due to divestments. Underlying volumes in the Q1 after adjusting for divestments and entitlement effects increased by around 2%. This reflects the ramp up of major project delivery in Angola, the Gulf of Mexico and the North Sea and improved performance in Trinidad, partly offset by natural field decline. Compared to the Q4, the first quarter result reflects stronger gas marketing and trading activities coupled with the benefits of high realizations, lower costs due to seasonal phasing and increased volume in higher margin areas driven by the continued ramp up of the PSVM and Scarf projects.
These improvements were partly offset by the impact of divestments. Looking ahead, we expect Q2 2013 reported production to be lower than the Q1. This is similar to the reduction we saw between the same periods last year and is primarily a result of planned major turnaround activity concentrated on higher margin assets in the Gulf of Mexico and the North Sea and the continuing impact of our divestment program mainly in the North Sea. We also expect costs to be higher in the Q2 compared to the Q1 due to seasonal factors. Turning to Russia.
On the 21st March, we announced the completion of the divestment of our 50% interest in TNKBP for a total consideration of $27,500,000,000 in cash and Rosneft shares. As a result of this transaction, the gain on disposal was $15,500,000,000 of which $12,500,000,000 was recognized and reported as a non operating item in the Q1 with the balance of $3,000,000,000 deferred and released to the income statement over time. This is required by accounting rules as we effectively retained circa 20% of TNKBP through our ownership of Rosneft Shirts. Net cash received from the transaction was $12,500,000,000 including the $700,000,000 TNKBP dividend received in the Q4 of 2012. We also received shares representing an aggregate 18.5% stake in Rosneft, which together with our existing 1.25% shareholding in the company brings BP's total interest in Rosneft to 19.75%.
For the Q1 of 2013, we have recognized $85,000,000 of income from our new shareholding in Rosneft based on 11 days of net income as estimated by BP. By comparison, the Q1 of 2012 included underlying profit of $1,200,000,000 for a full quarter of TNKBP net income and the 4th quarter included $224,000,000 based on 21 days of TNKBP net income. Looking forward, we intend to equity account our share of Brosneft as we did with TNKBP and we report it as a separate segment, so that you'll be able to see the performance and contribution separately. As with TNKBP, the results of our investment in Rosneft are subject to similar volatilities, especially the impact of Russian export duty lag in periods of rapid oil price changes. In the Downstream, the 1st quarter underlying replacement cost profit was $1,600,000,000 compared with $900,000,000 a year ago and $1,400,000,000 in the Q4 of 2012.
The fuels business delivered an underlying replacement cost profit of $1,200,000,000 in the first quarter, compared with $500,000,000 in the same quarter last year. This reflects a stronger supply and trading contribution, continued strong operational performance in a more favorable refining environment, particularly in the U. S. Midwest, where heavy Canadian crudes were significantly discounted during the quarter. These benefits were partly offset by the planned outage of the largest crude unit at our Whiting Refinery.
The new crude unit remains on track to start up in the Q2 of 2013, enabling the commissioning of the Whiting Refinery Modernization Project in the second half of this year. During the quarter, fuels demand was weak resulting in both lower volumes and unit margins compared to the 4th quarter. The lubricants business realized an underlying replacement cost profit of $345,000,000 compared with $325,000,000 in the same quarter last year. This reflects continued robust performance supported by growth in the share of sales of our premium cash flow brands and strong profitability from growth markets. The petrochemicals business delivered an underlying replacement cost profit of $59,000,000 compared with a profit of $112,000,000 in the same period last year as margins continue to be under pressure, which also led us to lower our production particularly in Asia.
In the Q2 to date, margins have been lower relative to the levels seen in the Q1. In other business and corporate, we reported a pretax underlying replacement cost charge of $460,000,000 for the Q1 in line with guidance. Guidance for 2013 remains unchanged from that given in February with underlying quarterly charges volatile and expected to average around $500,000,000 per quarter. The underlying effective tax rate for the Q1 was 39% compared to 33% in the Q1 of 2012. The increase in the rate is mainly due to a lower level of equity accounted income mostly TNKBP, which is reported net of tax.
Guidance for the full year effective tax rate remains in the range of 36% to 38%. Turning to Gulf of Mexico provision. The total cumulative net charge for the incident to date remains unchanged to $42,200,000,000 The pre tax BP cash outflow related to oil spill costs for the quarter was $500,000,000 At the end of the Q1, the cash balances in the trust and the qualified settlement funds amounted to $9,400,000,000 with $20,000,000,000 contributed in and $10,600,000,000 paid out. As we indicated in previous quarters, we continue to believe that BP was not grossly negligent and we have taken the charge against income on that basis. Moving now to cash flow.
This slide compares our sources and uses of cash in the Q1 of 20122013. Operating cash flow was $4,000,000,000 in the Q1 of 2013 compared to $3,400,000,000 a year ago. Excluding oil spill related outgoings, underlying cash flow was lower reflecting the absence of a dividend from TNKBP. As seen in 2012, the Q1 includes a large seasonal buildup of working capital, which amounted to around $4,000,000,000 After adjusting for the purchase of Rosneft shares, we received $13,400,000,000 of divestment proceeds during the quarter, including a net $11,800,000,000 of cash for TNKBP and $1,500,000,000 for Texas City Refinery. Our organic capital expenditure in the Q1 was $5,700,000,000 The completion of the sale of our interests in TNKBP has reduced gearing to the lower half of our targeted band of 10% to 20%.
At the end of the first quarter, net debt was $17,700,000,000 and gearing was down to 11.9%. At the time of the completion of the transactions, we announced an intention to use up to $8,000,000,000 of the proceeds for a share buyback program, which we expect to complete over the next 12 to 18 months. The balance of the cash received from the TNKBP transaction will be used to reduce net debt. As of last Friday, we have bought back $834,000,000 worth of shares. Our intention remains to keep Deering in a targeted band of 10% to 20%, while uncertainties remain.
Looking out to 2014 and our operating cash flow objectives, we continue to expect operating cash flow of $30,000,000,000 to $31,000,000,000 representing more than 50% growth in operating cash flow versus 2011. Bob will illustrate the progress we are making with the operational drivers of this growth. We also continue to expect full year gross capital spend for the group to be in the range of $24,000,000,000 to $25,000,000,000 for 20.13 and to be in the range of $24,000,000,000 to $27,000,000,000 per annum from 2014 through to the end of the decade. Divestments are expected to be $2,000,000,000 to $3,000,000,000 per annum on average on an ongoing basis. The sale of our interest in TNKBP has considerably strengthened our balance sheet in the near term and increases the flexibility of our financial framework going forward.
The buyback program should not only offset any earnings dilution from the transaction, but also reduces the equity base consistent with the reduction in BP's asset base following our major $38,000,000,000 divestment program over the past 3 years. As we look further out, growth in operating cash flows beyond 2014 provide the means to increase reinvestment as we have outlined and to continue to maintain a progressive dividend policy in line with the improving circumstances of the firm. Now let me hand you back to Bob.
Thank you, Brian. And if I can summarize the messages from those numbers, I think they are very positive ones. We're seeing strong operational performance from a portfolio that has been strengthened by divesting assets that are non strategic and investing in those that can generate the most value. We've made a new start in Russia, turning a challenge into an opportunity and positioning ourselves for a great future in the world's most prolific oil and gas region. We are making progress in the U.
S, no longer paying into the trust fund, making our case in court and meeting our commitments in the Gulf of Mexico region. We're maintaining a strong financial framework, keeping gearing within responsible limits, generating sufficient cash to increase our capital investment, while growing distributions, including the $8,000,000,000 share buyback program. And we are firmly on track to meet our 2014 objectives as well as continuing to strengthen our portfolio and deepen our capability, so we can grow over the rest of the decade and beyond. So turning to the detail. Let's look first at the status of legal proceedings in the U.
S. The first phase of the MDL-two thousand one hundred and seventy nine civil trial began on the 25th February in New Orleans. It was focused on the causes of the accident and the allocation of fault among the defendants. BP completed the presentation of its defense on the 17th April, marking the end of the first phase of the trial. For Judge Barbier's order, all parties will complete and submit their post trial conclusions and briefings for Phase 1 by the 12th July.
It is not known when the court will rule on the issue presented in Phase 1 of the trial. While the final decision rests with the court, we believe that the evidence and the testimony presented at trial confirmed that BP was not grossly negligent and moreover that the accident was a result of multiple causes involving multiple parties. We are continuing to prepare for the 2nd phase of the trial, which is scheduled to begin in September. This phase will consider the issues of source control efforts and the volume of oil spilled as a result of the accident. We're also continuing to pursue all available legal options to challenge the claims administrator's interpretation of the settlement agreement with the plaintiff steering committee.
BP believes that the claims agreement in a way that results in awards that have no merit being made to many business claimants based on losses that we believe are in fact non existent. We see that in many cases, there is a mismatching of expenses of businesses without the corresponding revenues, which results in very, very strange results. This can't be what was intended by the parties. Legitimate losses, yes, but not what is happening in many cases. We consider what is happening now to be at odds with the parties stated intent in reaching the settlement last year.
You will be aware that this has been the subject of several court filings over the last few weeks. BP has filed appeals of motions. These have been denied by the District Court in Louisiana and they are now progressing through the United States Court of Appeals for the 5th Circuit also in New Orleans. While we continue to act to protect our rights in this matter, BP remains committed to compensating those who have legitimate claims as a result of the accident. From the outset, we've stepped up, acknowledged our role in the accident and worked to meet our commitment to help economic and environmental restoration efforts in the Gulf.
Now as Brian outlined earlier, during March, we completed the transaction to sell our share of TNKBP to Rosneft for cash and shares. Rosneft also purchased AAR share of TNKBP, so now owns 100% of the company and its assets. This transaction gives us a new future in Russia, allowing us to build upon the experience we have built up there over the past 20 years. By selling our share of TNKBP, we have monetized 10 years of success delivering both cash and a unique opportunity to remain a key player in Russia. We have a lot to contribute as an investor, an advisor and a partner.
Initially, we will be sharing what we've learned from our own experiences of integrating large businesses. Igor Sechin and I are both members of the integration committee established to oversee this process and maximize the operational efficiencies that began by bringing the 2 companies' large set of assets together. Several work streams have now been set up to look at the integration of key areas such as the upstream, finance, refining, marketing and logistics. I am very happy to have been also nominated to join the RossNet Board, which I hope to do towards the middle of the year as the first of the 2 Board seats BP will take up. It is worth reflecting for a moment on BP's position in Russia following these transactions.
Russia is the world's largest producer of oil and gas combined. It also has the largest reserves of oil and gas combined and Rosneft is now the world's largest listed oil company in terms of production. BP holds 19.75 percent of Rosneft. It gives us a major stake in a company which possesses great scale in a country with huge potential and it enhances our own scale and reach. It means BP's production as a group is now over 3,000,000 barrels of oil equivalent per day and our proved reserves are over 17,000,000,000 barrels of oil equivalent.
As with TNK BP, you should also expect to see a significant contribution to BP's earnings. This transaction creates a unique position for BP. The deal provides us not only with a near 20% share in all that Rossneft undertakes, but a close relationship that allows us to actively discuss opportunities where BP and Rossneft may be able to work together outside of the shareholding. It's early days and there's still much to do, but we're proud of our track record in Russia and we look forward to working with Rosneft, building a bright long term future together. Now moving on, let me update you on progress and milestones in our upstream.
With much of the reshaping work behind us, our main focus is on executing what we said we would do within our current operations to deliver our 2014 targets and grow operating cash flow for the long term. However, we're also investing for growth. In exploration, we plan to complete 15 to 25 wells by the end of the year, 8 of which are currently in progress, including wells in Egypt, India, Jordan, the Gulf of Mexico and Indonesia. These are pure exploration wells and I'm not counting appraisal wells and some of those are significant. We continue to appraise existing discoveries in the Gulf of Mexico Paleogene and our oil sands properties in Canada.
Operations have also begun to appraise our Utica Shale portfolio in the U. S. And in Brazil, we have just announced a successful flow test at Itaipu. Our projects team has a strong pipeline of around 45 major projects to progress through the end of the decade with around half of those in our high margin regions. We remain on track to start up 4 of these in 2013.
And we expect to take a further 5 final investment decisions or FIDs during the year. On Chate Denis Phase 2, we also expect to make a European pipeline selection. Good progress is also being made on our 2014 project start ups, although the timing of work on our Inaminas and Insala projects in Algeria is being reassessed following the tragic incident at Inaminas in January. Other projects though may come on stream in 2014. We are continuing to ramp up our global rig fleet, increasing mobile offshore drilling units to around 20 by year end.
In the Gulf of Mexico, we expect to have 8 rigs operating once we start up the Mad Dog platform rig later this year. And in our operations, we're also continuing to carry out our scheduled turnaround program. This is a systematic program designed to improve both safety and reliability across our portfolio. In 2013, the activity for turnarounds will be focused on the Gulf of Mexico and the North Sea. We've already completed the turnaround of the Atlantis facility in the Gulf of Mexico and we expect to complete the majority of the remaining program in the second and third quarters.
I want to spend a few minutes on the progress we're making in our high margin areas. As you know, the ability to grow unit operating cash margins is central to our 10 Point Plan and its objective of increasing operating cash flow. In the Gulf of Mexico, as I mentioned, we now have 7 rigs operating, 5 engaged on production activity and 2 performing exploration and appraisal work. Furthermore, this will increase to 8 once we start up the Dog platform rig later this year. The idle iron work of the last 3 years is now substantially complete.
In April, we started up the Atlantis North expansion, the first of 7 wells as we further developed a field to fill the facility. We have also decided in collaboration with co owners not to move forward with the current plan for the Mad Dog Phase 2 project in the Deepwater Gulf of Mexico as it is no longer as attractive as previously modeled due largely to market conditions and industry inflation. This decision is in keeping with our commitment to shareholders to maintain capital discipline and ensure we only develop projects, which meet suitably competitive benchmarks. We fully intend to develop this resource following a review of existing plans and other options in evaluating how to progress the project. In Angola, we've recently started up our 3rd operating rig, the DS-six, which is 10,000,000 barrels from PSVM and will continue to ramp up to a plateau rate of 150,000 barrels of oil equivalent per day as we bring on additional wells.
In the North Sea and Norwegian Sea area, we've seen a strong ramp up in production during the Q1, driven by the startup of the SCARVE major project and improved overall production uptime in the area. SCARVE is now producing around 50,000 barrels of oil equivalent per day and is expected to reach a maximum rate of 165,000 barrels of oil equivalent per day. And we've started up new facilities at Valhall. These will give the field a further 40 years of life and production is expected to continue to grow into the second half of twenty thirteen. The Canoe major project continues to progress towards a 2014 startup with all engineering work now complete.
And we have just agreed with our partners to proceed with a 2 year appraisal program to evaluate a potential third phase of the Giant Clare Field, an initial appraisal investment of more than $500,000,000 In Azerbaijan, we have seen stable production in the quarter as new wells have been brought into operation and these offset natural decline. We continue to benefit from improved plant efficiency of the giant ACG development. On the Chirag oil major project, the jacket and export pipelines are being installed ahead of startup later this year. So when you add us all up, you can see a lot of progress. We're well on track towards the goals that we set for ourselves in the stream to deliver our 10 point plan.
We are back to exploring. We're bringing on high margin projects. Our rig fleets are ramping up and all of this gives us growing confidence in our plans for 2014 and beyond. In the Downstream, we are making strong progress too. As Brian explained, we had another strong results in this business.
During the Q1, we completed the divestment of our Texas City Refinery. We brought into operation the catalytic reforming project at our Toledo refinery with our partners Husky and we confirmed our first formal lubricants partnership agreement with the passenger cars division of China's Shanghai Automobile and Industrial Corporation. We also continued to make progress on the Whiting Refinery Modernization Project. This is now over 90% complete. We remain on track to bring the new operations on stream during the second half of twenty thirteen.
The divestment of the Carson Refinery and associated assets is expected to complete by mid-twenty 13 subject to regulatory approval. And our clean diesel project at our Cherry Point refinery is on schedule for operations in the mid year. We've maintained our focus on safe and reliable operations, while also sustaining high refining availability through the quarter, building upon the strong performance last year. All of this supports our longer term strategy to expand the cash generating capability of our downstream business, so it can continue to deliver material and growing free cash flow for the group. So to summarize, the year is off to a good start.
We've completed our repositioning in Russia. It is a result that is good for BP, for Rosneft, Russia and all the TNKBP partners. The trial in the U. S. Has completed its first phase and we remain resolute in our intention to defend ourselves fully, while also ensuring we meet our obligations in the Gulf.
And we continue to show strong progress in executing the operational milestones that support the delivery of our 10 Point Plan, including our commitment to growth in operating cash flow by 2014. Longer term, our direction is very clear. We aim to be a focused oil and gas company that grows long term sustainable free cash flow. We will do this through safe and reliable operations and through disciplined capital investment biased towards a growing portfolio of high margin projects in the upstream supported by a strong and increasingly cash generative downstream. It is a simple model, a safer and stronger BP grounded in systematic operations and delivering sustainable growth.
Our aim is to operate that model and to continuously improve it in all aspects. With the completion of the sale of TNKBP, we have commenced a share buyback program to return up to $8,000,000,000 of the proceeds to shareholders. This sits alongside the strong and flexible financial base from which we intend to grow distributions over time, in line with the improving circumstances of the firm and to maintain a progressive dividend policy. With that, that concludes my remarks. And now Brian, Jess and I will be happy to take your questions.
Right. Hello, everybody. We'll take the first question from Alejandro Demichela, CFAXANE.
Yes. Good afternoon, gentlemen. Yes, a couple of questions from my side. In terms of the cost on the upstream that we have seen in the Q1, how we should be thinking about sustainability of this new cost base going forward? And the second question is regarding Mad Dog 2.
Clearly, you have postponed that because the returns were not no longer attractive to you. But it seems that you no longer have a mega project in the Gulf of Mexico in the period 2016 2020. So how we should be thinking about the development of Gulf of Mexico post 2020?
Alejandro, hi. Thanks. It's Bob. As we look at the Q1, you all will know that the pattern of our costs in the Q1 tends to be lower because we're heading into the turnaround season in the second and the third quarters. In the past, we've had roughly 47 turnarounds in 2011 dropping to around 30.
And this year it will go down to 21. And out of those 21 turnarounds in the second and third for the year, 17 of those will be in the second and the third quarter. So we'll see some of that. Sector inflation, we see overall still running 5% to 10%, but we're also seeing some sustained cost containment reduction coming because just the more efficient use of our rigs now that we've got a rhythm quite frankly of getting our safety and operational risk in order. So we do see sustained cost reductions coming through in our operations, but it's also the seasonality of the Q1 going forward.
On the Gulf of Mexico and the Mad Dog, I think we're doing exactly what you would want us to do as shareholders is to make sure we manage our capital. It's not that unlike what's happening with the big Browse project in Australia, which we also have an interest of stepping back and looking again. To say we don't have a mega project there, I think is not correct. But I think restructuring that project and looking at it differently is absolutely the right thing to do. So I think we will have a project there.
We definitely will develop those resources. The 4 big hubs for us in Thunder Horse, we continue in the near term to work on the water flooding projects near term activity in the North Field Expansion Phase 1, Phase 2 and then the South infill after that. In Nikita, we've got 2 wells and the topsides in 2013 ongoing. We also have the appraisal of the Cascquita well and we've also got the Gila exploration well on the way down now. So way too early to say that after 2020 we won't have mega projects there.
But I think the one that's captured the headlines is Mad Dog. Actually I think the organization is doing exactly the right thing to reassess that.
That's very clear. Thank you.
Okay. Thanks, Alejandro.
Right. We'll take the next question from Jason Kenney at Santander. Go ahead, Jason.
Hi, there. And congratulations on the positive start for the countdown to lift off. Good to see that again.
Thanks, Jason.
So I appreciate your answer on the question from Alejandro and the seasonality of upstream costs. But the latest kind of cost data we really have is the FASB data for full year 2012. And you've obviously got a very different portfolio in the upstream now. And it's going to be a long time to wait for FASB data 2013. So if we were to think year on year, how should we think about upstream unit costs?
I mean, maybe just in percentage terms or high level reduction terms on that slimmed down portfolio, which is obviously focused on higher margin positions. And then maybe secondly on the Downstream business, should we be assuming a fallback in margins through the mid part of this year? Obviously, there's a lot of operational things happening this year. But was that kind of a one off uptick in the Q1? And maybe if I could just squeeze a third one in at all.
Again, I appreciate the tax guidance in your earlier commentary for 2013. When we get Whiting up and running in 2014, where do you think that tax charge might fall to in 2014?
Okay. Jason, thank you. Brian and I will take a couple of those things. Well, first some sense of cash cost per barrel for us. If you look at the Q1 of 2012 and the Q1 of 2013, they're almost identical.
They were $13.96 a year ago for the quarter. They're $13.91 now. They've come down in the 4th of the Q1 from over $16 back to the $13.80 number. So it is a long time before that comes out, but it depends on prices. We do see the sector inflation continuing at 5 plus percent per year for both CapEx and operating costs.
And for us, you'll see an uptick in exploration for us investment. It depends on the results of that. You'll also see an increase in activity in well work for us. But we're going to just continue to maintain that competitive focus on selecting the right activity and making the procurement efficient and effective. Brian, what would you like to add?
Yes. I mean, I think on cost, Jason, it's kind of we're seeing them slightly lower on a unit basis 1Q, 1Q. But we're going to have to wait till we get through this year till you really get a look at the new portfolio. So I think it's a bit premature to give you any guidance around where the costs are heading. We'll have a very new portfolio on stream by the end of this year, the 5 projects from last year, the 4 projects this year and the $38,000,000,000 of assets out of the portfolio.
So I think it's just a bit premature yet. But in terms of on a unit basis what we're seeing today 1Q, 1Q is slightly down as Bob described.
And I think towards the end of the year as we get the turnarounds done in the second and third quarters actually the comment about margin degradation I don't see that. I see the opposite happening by the Q4. Tax question on what?
Yes. On the tax, I mean, it's a bit again, that's a bit premature, Jason. But I think the guidance for this year is still 36% to 38%. The slightly higher figure of 1Q just reflects the fact that we don't have that much RELCO income there. The RELCO income typically TNKBP and our ROSNIF comes through on a post tax basis.
But we do see that coming back to 36% to 38%. We haven't gone as far ahead modeled it out to sort of 2014. 14. We do have an assumption in there around the targets we put out there, which is around this range of 36% to 38%. It's really again going to be a function where the portfolio stabilizes at the end of the year where we are around existing tax issues historically.
So it's impossible to give you guidance. But I think 36% to 38% is probably a good solid number for the next couple of years.
Okay. I mean, as long as you realize we're all thinking about that, because it's going to come around quickly as to how we can model 2014, 2015, 2016 and just how good that might be?
Yes. I mean, I think for 14, it's that stick around the range we've just given you around 36 to 38. Beyond 2014, the intention would be at some point probably this year to come out with some more guidance around what the portfolio looks like beyond 2014. But really the focus this year is really about underpinning the 2014 targets.
All right. Thanks very much.
Yes. And I'll just add a footnote to that that as you think about Whiting, the differentials in the U. S. Have just recently reached its record levels and they're not necessarily the guide of the future. It's been very, very volatile, very complex infrastructure supply dynamics there.
But we do think that the refinery there is quite uniquely advantaged structurally for processing Canadian heavy crudes and midcontinent crudes and even Gulf Coast crudes. So we're all looking at that, but it's just too early to say whether those conditions will stay.
Moving on to John Rigby from UBS.
Yes. Hi. Thanks for taking the questions. 2 please. On the results themselves, can you characterize a little better the comments you make about trading both in the upstream and the downstream?
I take the point that you don't like to put a number on them, but I'm aware that you commented last year at 1Q that I think oil trading was somewhere below where you'd expect it. So maybe what I'm trying to say is when you say that there's been an uptick or the better, have you returned to something more like what you would expect to get on a normal basis? Or was the quarter somewhat better than you would have expected? And then the second question is just to come back to Mad Dog. As I understand it, you have single hurdle rates for FIDs.
And I just really wanted to ask the question, did Mad Dog fail on the hurdle rates you're applying? Or did it just look wrong in terms of the rate of return you're getting in that previously you would have expected a large Gulf project to be very high up in pecking order of projects and this one wasn't. So a view that perhaps you could do better even though it actually was making your rate of return hurdle? Thanks.
Yes, John thanks. Well, first just an overall reflection on the Q1 earnings and the drivers. I would say there's really 3 parts of it. Really a third of it is better margin mix. A third of it is the costs that came through.
And a third of it I'd say is oil and gas trading. And Brian why don't you comment on the trading?
Yes. John you're right. Historically we don't typically talk about the trading numbers unless we have a very strong quarter which is what you've seen in the Q1. So the way I would characterize the trading result and we've talked about this historically on a sort of average basis, where we compare it to an average quarter then the trading result is around about circa $500,000,000 higher than an average quarter. If you look at the last 5 years average quarters, it's round about $500,000,000 higher and it's split roughly evenly in terms of the upstream and the downstream.
So in terms of gas trading in the upstream and oil trading in the downstream, it's split pretty evenly across the 2.
But just to follow-up on that, I think you commented I think, in the Q4 that 2012 itself right across the year was not a great year for oil trading. So if you were to look back historically presumably you're comparing it against a base that's not actually all that good?
No. Because actually if you think actually 2012 was a tough year for them, 2011 was an okay year, 10% was good and 9% was very strong, 8% was very strong. So you can sort of if you go back to last 5 years, the average this is about $500,000,000 above an average quarter for the trading results. So if you look this thing evens out over time over many, many quarters as I'm sure you're familiar.
And on Mad Dog?
John on Mad Dog, Mad Dog 2 Phase 2, it's a really very much of a world class resource and we very much intend to develop that resource with our partners which are BHP and Chevron. The current plan when we looked at it and one of the things that all companies with these capital projects need to do is not just keep going down the road because that's what you've laid out to do and go through the stage gate process. And we looked at it and we said this project is not as attractive as we had previously modeled it, mainly due to some of the market conditions and industry inflation in steel and yards. So we stopped at the stage gate and said we think there are other things that we need to return to look at improving the economics. And it could be a phased development that actually brings production earlier than we thought, but at lower rates and stages it over time or not.
So we just need to take another look at the engineering we work and try to optimize that. So I wouldn't say it failed, but you're right these are high margin projects in the Gulf and this didn't have the margins that we had been looking at. There's no real read across of this to other projects that we have now Then there's no immediate impact on the reserves of the field. And I'm most certain we will develop these resources out in time. I think this is a very healthy recycling.
That makes sense. Thank you.
Turning to the U. S, Doug Terreson from ISI. Go ahead, Doug.
Congratulations on your strong results everybody.
Thanks Doug. Thanks Doug.
I have
a couple of questions on the downstream too. First there seem to have been very positive mix effects in the downstream in the period. And so my question is whether you could provide insight into these factors exclusive of those leg to trading that Brian just highlighted? And also, whether there are any geographical effects worthy of mention as it relates to mix?
Doug, I think I'll take that question. So if you look at what's happened 4Q into 1Q, there is benefits coming through in terms of the trading result we talked about. There's also seasonally lower cash costs. So you're seeing benefits of both of those roughly evenly actually in terms of the difference. You've also got the Whiting outage there.
We took the crude unit down in December. So of course you haven't got the benefit of Whiting through the Q1. And we have seen some pressure on both unit margins and volumes in the fuels business. So it's a sort of there's sort of 4 components to it strong results in global oil trading, seizing lower cash costs. But to the negative side, we've got the Whiting units out, which will be starting up this quarter and some of the margin effects in terms of fuels, volumes and margins.
Okay. And Brian, I think both you and Bob talked about commissioning at Whiting in the second quarter and then start up in the second half of twenty thirteen. So just for clarification, is it just as simple as to mean that feedstock will be processed starting this quarter and that we'll have full run rates in the second half of twenty thirteen. Is that the correct interpretation?
No. So what we've got is the units come back on stream in the second quarter They're the crude units we took down in December. Okay. We'll need those back on stream to then start commissioning the coker through the second half of the year. So you will start to see the run rates come back up through the Q2 and then we'll begin the commissioning process through the second half of the year.
Okay. Okay. I'll follow. Thank you.
Okay. I'll just add to what Brian said. In terms of our Solomon availability of our refinery system, overall was 95% in the 4th quarter and 95.1% in the 1st quarter. So we've actually kept our units running globally in both the quarters which also has helped these results.
Okay, Zach.
Thanks, Doug.
A question now from Houtan Yazari of Bank of America Merrill Lynch.
Hi, there gentlemen. Two questions please. Let's start with Rosneft. I just wanted to get a clear picture of how you're getting involved in the integration process. Obviously BP has a lot of experience with the integration process given your the acquisitions you've made in the past.
I just want to see how you're applying that to the Rosneft transaction. And then secondly, moving on to your balance sheet, obviously, very strong sub-twelve percent gearing. I just wanted to get a feeling of how you're looking at the dividend and potential increases in forthcoming quarters? Thank you.
Hooten, I'll take the question on Ross Neft and then Brian will take the point on the gearing and dividend outlook. The integration process, I think everybody on this call has been involved to one degree or another in some major integration. You know that they're fast paced and they're moving quickly. On this particular one given that the close was accelerated from June as it was into March, the integration has moved very rapidly. So on day 1, the main thing was make sure there is complete internal controls that the company has the ability to pull together its earnings.
And in addition, a structure was put in place, which was organized not on geographic lines, but it was the offshore, it was the onshore and the upstream, the refining and the supply and trading logistics as these are different segments or blocks of the business that they're called as well as putting in place a common economic evaluation methodology for all the decisions that have to be made. There has been a there was a popular rumor that no one from TNKBP was going to move into Rossneft and it would be just an acquisition and then there would be a full scale whole hundreds of professionals from T and K now that are now part of Ross Neft. And we've had formal integration meetings and we've had informal integration meetings as these decisions are made pretty quickly. So I think as integrations of large companies go, this one is moving very, very, very fast. Then of course the main thing overall is to make sure that the synergies are defined and developed which are starting to be listed and it will be up for Ross Neff to describe those to the market.
And it will be making sure that many of what I think are some state of the art world scale technologies around corrosion, inhibition, water flooding, reservoir modeling and the use of technology are brought together in the Rosneft to do what I think it's going to do, which is become a model. I think most people would say that TNK VP on most benchmarks had evolved into the most efficient Russian oil company. And it's openly talked about at Rosten, how do they make sure that they follow down that path. So I don't know if that gets at the specifics of your question Houtan. It's a subject obviously we talk a lot about.
But does that hit the primary point?
I'm just trying to get a feeling of how much of the best practice in TNK BP would be transferred to Rosneft And indeed how much of BP's best practices would be injected into that mix?
Yes. So this has been a company that's been merged now within a month. Certainly, the assets are still a substantial amount of the TNK assets which are now part TNKBP assets are now part of Rosneft itself. So that technology is not going to go away. And I'm always struck by if you look at a map of Russia and you see the location the TNKBP properties exploration and producing properties with Rossniffs, they're all very, very close to each other out there.
And I just can't help think that this is going to start flowing through substantially. And as people have moved around with those experiences from one field to another field and the pipes get hooked up between them, there's going to be just a tremendous amount of best practices. And I think about water flooding corrosion inhibition, artificial lift is going to happen. I'm not worried about that. And the first thing I was worried about in the 1st month was are the internal controls in place?
Is the company going to be able to pull its books together? Is the company going to be able to forecast and project, so that it's a larger car with the steering wheels working? And then that's all gone very well in the 1st month. So I'm just just give it some time here. There's no doubt that the best practices aren't going to be lost.
Let's talk to your question about gearing and the dividend.
Yeah. Thanks, Houtan. So you're right the balance sheet is in a much stronger position now post the Rosneft transaction. What we've said previously is the Board is clearly committed to progressive dividend policy. You saw us move the dividend up twice last year 0 point 0 $1 on each occasion representing an overall 28% increase since the level we set we reset the dividend at 0 point 0 $7 And of course, the growth in operating cash flows out to 2014 and beyond will be able to enable us to underpin that sustainable dividend growth into future around the progressive dividend.
It will be a function of being able to deliver sustainable free cash flow, which I think is one of the things that we talked about in December last year off the back of the new projects and tight capital discipline that will create the space to for progressive dividend policy beyond. So that's something which the Board will review each quarter And certainly that will get reviewed at some point through this year, for the normal course of course review of results.
Thank you very much.
We'll take the next question from Irene Himona at SocGen.
Good afternoon. I had three questions please. Firstly, on India, is it possible to update us on where you are in terms of gas price discussions with the government? And what would you need to match your expectations of Project Economics at the time of that acquisition? Secondly, on the dispute with the claims administrator, could you provide a sense of the magnitude of the extra cost that would be involved in a scenario where he's simply allowed to continue to follow that methodology?
And then thirdly, Whiting. In the past, you had mentioned a $1,000,000,000 cash contribution, obviously, at a much lower level for light heavy differentials. In the Q1 environment, should we simply double our expected cash contribution because the margins were the differentials were twice as high? Thank you.
So Irene, thank you. We're just sure about doubling. I'll let Brian answer that. First on India, I think we've made quite a bit of progress here in India. I've just been out there and spoke to the Prime Minister and every main minister here, the energy ministers.
When we originally made the acquisition, we dollars in place until April of 2014 and then we made an assumption of going to $7. Since that time, I have to say and I I've told officials in India that it's been hard. There has been a real slowdown in government decision making for some time not just in our industry but every industry. They have they recognize that their gas price is uncompetitive. I've explained that it's not doesn't make sense for BP to develop natural gas in Australia and ship it into India and that's more economic for us than developed there in the country.
And they've had a Ranjiram, it's called the Ranjiraran Committee, which has made a recommendation to the government to move the price to $8 an Mcf to somewhere between $8 $8.50 per Mcf at $100 LNG parity which will be about 12 dollars What we've said is that that's a step in the right direction. We can support that. But we also would like a market path to market pricing after that. And our Board is heading out to India later in May. We have no more meetings with the officials.
I'm very, very encouraged with the meetings that I've had. And we've got something called the R Series development plans have now been submitted. Seabed surveys are underway. We've got further satellites around D6 and something called the NEC-twenty five areas. So I think it's coming together.
We've got an exploration well right now that's down and coring. So I think I would look at the government's decision on that commission as the first next milestone on India. Is that clear Irene?
Yes. Thank you.
Okay. And then so with the claims and with Whiting Brine?
Yes. So in terms of the claims process Irene, the issue that we have with the agreement is around business economic loss claims. And for us to be able to do an estimate of what those claims look like going forward, we need 2 things. The first thing is a ruling in terms of the Court of Appeal. And then having established that ruling in the Court of Appeal either way, we would then need a pattern of future claims to be able to do an actuarial calculation.
So at this point, it's actually impossible to estimate, since we don't have that pattern, we don't have the decision. What I can say is that when we did the settlement initially, we took a provision of $7,800,000,000 within the $20,000,000,000 trust fund. We progressively moved that up that by the end of the Q4 of 2012 that number was sitting at $8,500,000,000 When we had this issue arise with the court and contesting some of the claims that Bob talked about as going through which appear quite fictitious to us and not really the people that the money should be getting to. We backed out the future economic loss claims at that point in our provision of $800,000,000 which at the annual report and accounts filing took us to $7,700,000 This quarter we've booked we'll now book economic loss claims as they now come through. So you will see that the provisions now moved up to $8,200,000,000 So we've taken $500,000,000 this quarter.
And we still have within the trust fund headroom of around about $1,700,000,000 that has not yet been allocated and could be used for these purposes. But really at this point it's premature in terms of trying to make any estimate around what those claims look like in the future.
Okay.
And finally on the Whiting
Sorry on the Whiting question. It's premature. Of course, we've seen the spreads blow out to something like $27 versus WTI, Canadian heavy versus TI. And of course, TI is blown out to Brent to the tune of $18 in the Q1. So you've sort of got a $45 Brent to Canadian crude differential that Whiting will be able to capture.
Now of course part of that's being driven by the fact that the Whiting unit was down. And so therefore that's that in itself with that volume not being able to get anywhere that exacerbates the spread. So that's come back in line now. The current spot spread is somewhere around about $17 to WTI in terms of Canadian heavy. That's where it is as of yesterday.
Now clearly to the degree that we see moments where the light heavy spread opens up and widens to the numbers we saw in the Q1, we'd be able to capture those benefits through Whiting. And effectively those benefits move between our upstream position with Sunrise in Canada down to the Whiting refinery. So I think the short answer to your question is, if we see these sort of spreads, there is clearly significant upside over and above the $1,000,000,000 of cash that we've talked about around Whiting Refinery. We're not going to quantify what that number looks like, but clearly the upside. And that of course comes into the overall 2014 targets of $30,000,000,000 to $31,000,000,000 of operating cash.
We've risked in assumptions across the portfolio. So to the degree Whiting may be higher in those numbers there may be balance somewhere else.
Thanks very much. Very clear.
Back to the U. S. Brandon May from Tudor Pickering.
Yes. On the natural gas realization in the Rest of World, it looks like you had a nice increase relative to benchmarks. So just wanted to get your thoughts and color on what caused it and maybe what's going on looking forward?
Well, we have because of the North American prices. I mean the LNG prices globally have gone up and
they've Yes.
So I think it's actually sorry Bob. If the LNG pricing was attractive for us Q1 as some diversions and also the benefit of the Trudadian volumes having additional cargoes available to us. That was I think that was one of the big drivers in the Q1.
Sorry Bob. Yes.
Could you maybe quantify some of those numbers?
Typically we don't other than the fact it comes through the gas trading result that we talked about earlier. That for the total trading it was $500,000,000 above an average quarter split evenly across the gas and the oil trading businesses.
Got it. Thanks.
We'll take the next question from Tipan Jossylingham at Nomura.
Yes. Hi, good afternoon. Thanks for taking the questions. 3 please. Firstly, just looking at cash generation, I know quarterly numbers are volatile, but I wanted to see you can make any comments on how to extrapolate Q1 to your sort of 2014 operating cash flow target.
Ideally, I'd sort of had to get a feel for what the run rate is, as the 2014 reference conditions. I'm wondering wanting to know whether you think you're ahead in line or below that sort of Secondly, just on exploration, if you could give some color on the 8 wells drilling what countries or place you're testing That would be great. And thirdly, just to cross check that your guidance on disposal impacts year on year is unchanged? Thank you.
Okay. So, Brian on the cash, I'll talk about exploration and we'll then come back to the disposal point in a moment.
Yes. Tee Pan on the operating cash flow, remember for the Q1 typically as you saw the Q1 of last year, we did have a seasonal build in working capital. So on an underlying basis the actual the $4,000,000,000 of operating cash, there's also a $4,000,000,000 build in working capital through the first quarter, which is typical as we build products for the summer season. That will unwind as the year progresses. So I think the short answer is 2014 with the projects that came on stream last year, the projects this year where we are around the commissioning of Whiting, the target of $30,000,000,000 to $31,000,000,000 of operating cash in 2014 is well underpinned.
And in terms of the Q1, it's always a difficult quarter to get to the kind of what you're looking for in terms of run rate. But on an underlying basis, if you take the working capital build out, it's something like $8,000,000,000 of operating cash coming through the Q1.
Yes. Brian, I was just wondering do you I mean the question I'm thinking is do you feel confident I mean it sounds like you're very confident around €30,000,000 to €31,000,000 And you've talked about sort of risk assumptions. You also sort of mentioned that the CFA target could be greater than 50%. I'm just wondering what the upside case could be sort of a reference $100 oil?
Yes. Sorry, it's $100 a barrel and it's $5 per MMBtu of Henry Hub remember? Of course the Henry Hub price has come back this year. We've seen it back over $4 now. So it's sort of it's moving towards that trajectory for 2014.
But no, I'd say it's well underpinned into next year. There may be some upside. There may be some downside. But we're fairly confident that $30,000,000 to $31,000,000 is well underpinned for 2014.
Okay, great.
Tien, hi, this is Bob. On exploration, we're currently testing this reloaded portfolio. Up to now, we've been drilling wells that were prior obligation wells. And as we move forward, we're now really getting into the new acreage positions we've picked up over the last few years. So we're currently drilling 8 wells.
Around 5 of them are testing new plays, real completely new plays. Those would be in Brazil, Egypt and Jordan. We've got wells scheduled in the U. K. Indonesia and India as well for the year and in the Gulf of Mexico of course the Gila well.
So those wells are going down right now. I think it's just something to see what the results are coming through. We don't really have anything new to announce today, but we've got some promising things that are happening out there. And that's probably all I can say right now about it.
Okay. Perfect. And then just on disposals please?
Yes. Yes.
What was the sorry, Chi Pem what was the specific question? Just
the impact of disposals for the year on year, are you sticking to that sort of 1% year?
Yeah. It's around 5%. Yeah. That's correct.
Okay. No change there.
All right.
Very clear. Thank you.
Yes. We have received the proceeds now in on 32 point 7,000,000,000 of the €38,000,000,000 of the disposals. Yes.
There's €5,000,000,000 more to come through this year and there'll probably be some other disposals over and above that, but it's basically underpinned.
Yes. And most of the impact on the disposals are in some high margin areas, the Central North Sea being one of them as well.
Right. Next question from Oswald Clint of Bernstein.
Yes. Hi, good evening. Two questions. First one, can I ask if you can talk about the earnings contribution from some of those new fields starting up this quarter like SCARVE and Volhall if possible? Then secondly, I'd like
to go back to Rosneft
and just get your thoughts on their recent strategy. You spoke about the earnings growth potential from this investment. Yet I got the sense looking at their strategy that there is limited kind of upstream growth here for the next couple of years. There was a lot of downstream investment. Synergies seem to be more heavily weighted to 20 16 onwards.
There are also a lot of natural gas growth in the domestic market. So it seems like it might be a bigger earnings growth potential post 2016. I just want to get your thoughts if you think that's fair or you think it could be much more accretive over the next couple of years? Thank you.
Yes, sure. Well, first on the new projects that have come on. Certainly, the Block 31 PSVM and Angola has come on. We're projecting roughly production another 24,000 barrels a day. It's a very high margin area for us.
And SCARVE 22,000 more than 20 this year. That will Block 31 will go up for net to BP above 30,000 barrels a day as Will Scarves. So those are 2 high margin contributions for us most certainly. And we've completed the redevelopment of Valhall field in January as well, which we haven't really highlighted as a major project, but it will effectively extend the life of Valhall for another 40 years. So these are some of the good things that have just come on you see in the results and that obviously does affect the volume mix that we've seen in the 1Q numbers.
On RossNet, strategically RossNet has some plans to modernize refineries. I think actually there's a big question mark yet on how much of their capital they will put into refinery modernizations and how much will be into looking at what are many, many opportunities across the existing onshore fields. I think their focus is going to be significantly on the upstream. I know it is. And I think that their projections are where we our projections and their projections separately show underlying growth throughout the decade in Ross Net in the upstream.
I think the there is enormous amounts of associated gas production in Russia that you can see the market beginning to open up and liberalize for those companies who have the potential for monetizing that projections right now. So I wouldn't describe it as back end loaded. I think it's going to be steady progress. And I think just like BP, our message to them is capital discipline is really very important and be very, very selective on those big projects that you take on including refining modernizations.
Okay. And sorry just a follow-up Bob. In terms of the potential international opportunities with Rosneft, would you be contemplating letting Rosneft into your Gulf of Mexico portfolio?
Portfolio? Well, we haven't talked to them specifically. Of course, we have a very large Gulf of Mexico portfolio. I think they have their hands full focusing on the integration right now. But I would say that nothing's off the table with us as we talk with them around the world as well as projects onshore in Russia and even the Arctic.
So I think we have the relationships. We have the access. If there's something that's interesting, we'll be happy to take it on. We look at this partnership with Rosneft as one of multiple decades. So it's still early.
And just like for BP and just like for Rosneft any decisions to enter in and do things together have to look good economically from both sides. But I'm I don't think we're restricted. I don't think they feel restricted about anything. But no specific plans in the Gulf.
Okay. That's great. Thank you. Sure.
Next question from Fred Lucas of JPMorgan.
Thanks, Jess. A question on numbers perhaps for Brian. Can you tell me remind me the total cost BP incurred to exit the solar business and whether you expect to be able to exit wind without any costs? And when you exit the wind sector, how might that affect your guidance for the OBC segment? And then a question for Bob.
Bob, I've been reading some of the summary reports following the Ula incident in September 2012, the report from Norway's Petroleum Safety Authority. And I mean they describe it as an accident that had an incident that had the potential to become a major accident and a potential near miss. I just wondered how you felt about that given that that occurred 2.5 years after Macondo?
Okay. Well, Fred, let me take that last one the Ulla incident. You're right. The Norwegian authorities we've been working with them for since 2011 on that. It was a I believe I don't have the facts and figures.
I'm going to do this from memory, but I believe there was a 6 barrel of oil discharge to the sea. The rest was contained in a sump and there was a gas discharge. This was an unmanned platform. There was no one on the platform. And yes, any time you have just as has happened here in the U.
K. For example, you have an uncontrolled gas leak for a period of time. There's a potential of course for ignition. And that's what that report is about and we're working with the authorities there. And I think the authorities have obviously and rightly said, this had the potential for an accident.
And that they have also said that we have all the capability of improving and continue to improve our systems there. So I'm not going to say it obviously didn't happen, but it was not an accident. It had high potential. We call it a high potential incident. And I think that's probably all I need to say about that right now.
And on solar
Bob, they were very critical of BP's approach to maintenance. And I was just astonished that so long after Macondo that your maintenance processes on an offshore platform could still be criticized in such a way?
Well, Fred, you read the report. I think everybody can read that report. We had a maintenance of a kind of set of bolts on that report led to a discharge on an unmanned platform. The safety systems did work. The automated safety systems did work.
There was a minimal discharge to the sea. And regulators at any time there is any kind of an incident anywhere whether that's upstream or downstream or for any company I would expect regulators will write that kind of report.
Yes. Fred in terms of solar and the read across to wind there really isn't one. Solar was a business that we announced the intention to wind down and exit in 2011. We've been in that business for 40 years. It's a business that went through an enormous market change that made it very difficult to make money in that business and that's why we chose to exit it.
In the case of wind, it's a good business. We've got 16 wind farms in the United States, 3 that we recently constructed across 9 states. We finished 3 wind farms last year in Kansas, Pennsylvania and Hawaii. We think that will be when we take that business to market, we think it will be very competitively bid. So I don't think there's any read across what you saw in terms of the exit costs out of solar and some of the things that we had to put in place around warranties around the solar panels and some of the impairments that we took around that business.
I would not read any of that across to wind. Wind is a very viable business. The tax credits were extended. So it's a good business in terms of marketing. It simply doesn't fit the portfolio going forward which is why we chose to exit.
And so therefore, there is no read across from what you saw in solar.
Thanks, Brian. That's very clear. Can you just clarify? I mean, I assume the business profitable. So when it's sold, will that deepen the quarterly charge for the OPC segment?
You should no actually. So the way it works is wind works on the basis of tax credits. So therefore on a post tax basis, it's accretive. But of course you have to have revenues some revenue streams somewhere to take advantage of those tax credits. So from a post tax basis, there'll be a you'll see the charge from that.
But we never report O B and C on a post tax basis. You'd only see it on pre tax. So you shouldn't see any major changes in O B and C.
Got it. Thanks.
All right. Thank you. Next question from Michele Dellavenir from Goldman Sachs.
Hi. Thank you for
the presentation. I was just wondering in view of your comments on capital discipline and inflationary pressure, if there are FIDs that you will feel comfortable taking over the next 12 months or if you prefer taking time to get to a better cost environment?
Kayley, hi. We do have in fact, we're projecting we had a light year last year FIDs. We had 3. We're looking at as many as 5 this year. And 3 of those would be mega projects, I would say.
And we have even more that we could decide from. So, no, I think because in light of our capital discipline, we're going look at any project that needs to be refined and it will go through its normal stage gates. But we would expect to see 5 this year and I would say more than 5 as well in 2014.
Thank you.
Right. Rahim Karim from Barcap.
Thanks, Jess. Two questions, if I may, around the buyback program. First might be more for clarification, but just wanted to check what environment or what circumstances would see you not reach that $8,000,000,000 that you've talked about? So you talked about up to $8,000,000,000 So just wanted to check that. And then the second was just around the scrip dividend.
Clearly, it's currently dilutive given you're not buying that back. Should we expect once that €8,000,000,000 is done and dusted that you should continue to do an ongoing kind of buyback program to offset that dividend given the gearing now is back at towards the bottom end of your range? Thank you.
Yes. Thanks. So in terms of the Lazapar that question, we have a mandate which goes before every AGM on an annual basis that allows us to buy back up 10% of our market capitalization. So that's kind of those authorities are in place. And that's something that we typically look at on a routine basis as part of the financial frame.
So that there is a mandate in place to enable us to do that. The $8,000,000,000 you should assume that provided oil prices stay where they are, the balance sheet stays where it is, There is flexibility, but our assumption certainly assumption to the Board is that we'll go ahead and do the full $8,000,000,000 buyback. We think it will take 12 to 18 months. As of last night, we're up to $850,000,000 now over and above the $834,000,000 that we talked about in the script in terms of what we just talked about. So the assumption is we'll complete that.
But of course depending on what happens in the environment it creates great flexibility. We make sure that we can run the balance sheet of the firm at $80 a barrel for 2 years. And we have stress tests in place to enable us to do that. So there's nothing really an environmental perspective I think that would get in the way of the full $8,000,000,000 buyback. Then in terms of the scrip dividend, the scrip dividend is good for our shareholders.
There are benefits for our shareholders around the issuing of scrip and that's really for their choices whether they choose to take the scrip or take cash and we'll continue to offer that. We haven't put any commitments in place in terms of non dilution of that and buying that scrip back. And so therefore, there's certainly no policy we're about to make on the HOOPHIA today. So no, I mean, we'll continue to offer a script for our shareholders while they request that. And then in terms of buyback of stock generally that sits within the existing financial frame.
Perfect. Thank you. If I may just have a follow-up question just around more generally around the strategy and the update. I mean, I guess, you've been a little bit constrained on what's going on in terms of the court case in the U. S.
Given that seems to be progressing, should we expect greater disclosure around the strategy at some stage? I mean, you mentioned in December perhaps that once the court case developed and we were into it that you might be in a better position to talk about the longer term?
Raheem, hi, this is Bob. So in December when we laid it out, we basically laid out a company that is focused on upstream high margin projects out to the end of the decade with a capital discipline around it with projects that focused on higher margin upstream projects and emanating out of the 4 big hubs that we have, which is Angola, the North Sea, Azerbaijan and the Gulf of Mexico. And further focusing down on some of the older assets and decisions that you now see like what we have said that at least at the moment our intention is with wind for example. So the strategy I think is clear around focus on oil and gas a bias towards liquids not in all cases because there are regional differences on gas capital discipline and downstream assets which generate cash for the company high quality assets that generate cash. And I think with that, we should put ourselves into an ability to be a cash Now that I think is essentially what we laid out in Now that I think is essentially what we laid out in December.
And what we are now considering doing is a business review later this summer just to give you a little more color past from 2015 on to the end of the decade. But it won't be a fundamental redirection.
That's helpful. Thank you very much.
Next question from Lucas Hermann from Deutsche.
Yes, thanks, gentlemen. Good afternoon. A couple if I may. Bob, can I get you to talk through some of the developments of what's going to be happening in the short term in the Gulf of Mexico in particular? I think you talked about an objective or a desire to fill the Atlantis platform, which from memory is 200,000 barrels a day of capacity.
And that's relative to I think you're producing something near 70,000 at the moment. And also where we are on Thunder Horse, You talked about an objective of moving production back to 125,000 a day. You've been working on maintaining pressure, etcetera, etcetera. But what should we or what are you anticipating or planning through the Q2? I'll leave it there for the moment.
Okay. Thanks, Lucas. You've mentioned 2 of the big hubs we have in the Gulf of Mexico and Atlantis. So the near term activities for us in Atlantis, by the way, we want to show volume growth from 2013. It's around 50,000 up to around 75,000 by 2020.
But the near term activity is the Northfield expansion which is Phase 1 which has a total of 3 wells and plus the subsea facilities that go along with that. And then another Northfield expansion Phase 2, which has a total of 4 wells along with the subsea facilities. And then the South infill which will be a total of 4 producers of which 3 are water plus 3 water injection wells. So quite a bit of activity. And we will have a turnaround in the Q2 that's a significant one in Atlantis.
So we have about a 45 day turnaround there to tie in Thunder Horse. So sorry that the turnaround is in Thunder Horse. So Atlantis we've got new wells coming on lots of activity there. Now Thunder Horse near term activity there, we've got well work on 6 wells going on right now. We've got an infill phase Phase 1 which will be 9 wells.
We'll have a water injection phase which will change the topsides plus have 3 water injection wells as well. We'll have a 3rd rig on Thunder Horse in January 2014, which we're going to at the moment are planning to contract for 3.5 years on that. But we will see Thunder Horse come down in the second quarter with a 45 day turnaround. And we'll see Thunderhorse decline 2013 to about 25,000 barrels a day. But we expect then to see it grow through 2020 back up, I'm just going to say 100,000 barrels a day.
It could be higher than that, but 100,000.
Sorry through 2020, so over the next 7 years the ambition is
to move Thunder Horse back towards?
Yes, over $100,000
Over $100,000 sorry, net Bob or
That's net. Yes. That's net. That's our 75% net.
Sorry in terms of Atlantis and just production where you expect capacity to move to and just some pinpoints around time as you bring the different phases on? What should we be thinking about? I'm confused I guess if these are huge facilities.
That's right. These are yes, the work I outlined sort of goes out all the way out through 2020 that I've listed there. I think for us to give you specific wells and what we're going to be doing on each of the wells, Let me see what I can tell you here. I mean we will have Atlantis 2A starting up. I think what's best because there's a lot of detail there and I don't want to do anything selectively right now is anyone can phone Jess and her team there to go in what we're doing sort of quarter by quarter, if we can even do that for you.
All right. But Bob, I
mean from everything you've seen all the work you've done with the Gulf so far, the guidance that you put out in December around anticipated production you clearly feel is robust?
That's right. Yes, absolutely. I mean, we're we'll be underlying flat this year and then we'll see those numbers continue to move up through 2016 substantially, so year by year by year in the Gulf. And I'll you remember that we had probably in 2012, we were around 210,000 barrels a day in the Gulf. We've divested about 46,000 barrels out of the Gulf.
So sort of net of that will be flat. And then each year confidence is absolutely there to keep growing.
Okay. And finally one other if I might. Just on the 2014 guidance. I mean Brian, you're indicating that you feel that everything is already in place to deliver the €30,000,000,000 to €31,000,000,000 of operating cash flow. Or are there particular pinch points or particular events that need to happen start up of Whiting aside?
Yes. Lucas, I mean just so clearly that's a risk number. So therefore there are things that can go in our favor, things that can go against us. So I think from a risk perspective things are on track, but many things can happen between now and the end of next year, OPEC quotas, hurricane season. I wouldn't say it's complete.
They're not assuming it's in the bank, but all the things that we need to do to underpin it are in place. And as on a risk basis, there may be some upsides and downsides across each one of the projects. So I wouldn't put it in the bank at this point, but we do feel things are underpinned. I'm sure Bob
will do.
Yes. I'd just add some of the things that had to happen were the 5 major project startups that happened in 2012. The Galapagos from the Gulf of Mexico, the Clocos Mavacola in Angola, PSVM down there as well, Scarve and Devonik those things had to happen. In 2013, we've got the Angolan LNG projects that's got to come on. We've got the Sheerag Oil project that's got to come on in Azerbaijan later.
There's a number of these projects that have to happen and you know what the road map is. We don't take any of that for granted. But I would say they're on track now.
Okay. I'm sorry final question. Where does CapEx on refining in the U. S. Move to post the completion of WRMP?
Lower.
Okay. Let me so look we've got 2 refineries have gone although we haven't we're actually capitalizing those since we announced them for sale. Clearly the CapEx going into Whiting will be reduced as we bring the coker on. So, yes CapEx overall will be lower into the future. We haven't given any specific guidance at what level.
Right. But there are no other expansion plans
We have no major expansion plans across any major I. E. Of a Whiting like expansion that you should expect across any of our refineries.
And we just that's one thing we didn't mention. We actually have just completed an upgrade at Toledo. It's just now finished.
Gentlemen, Jess, thank you very much.
Okay. Folks, time is moving on and we still have quite a few people polling for questions. So if they're very detailed IR is of course always available to help you afterwards. But let's move on to the next question from Ian Rhee from Jefferies.
Hi. Yes, thanks very much. Bob, a couple of questions about Rosneft again. Just wondering about the opportunities you're talking with about Arctic exploration because it seems to me that a lot of the acreage which Rosneft had available has now gone through Exxon. And anything that's left is pretty remote and maybe not particularly prospective.
So I just wonder whether you could comment on that. And maybe what you're looking at with Rosneft now? Is it onshore tight oil? Is it gas? Because offshore Arctic seems to be kind of moved out of your grasp now, at least from my perspective.
And also on the dividends, the 25% payout ratio that Rosneft has promised is that an aspiration or something which is absolutely fixed? And are they going to move to a quarterly payout? I suppose you should know this now you're a member of the Board.
Well, I haven't actually I stepped onto the Board upon election in June. But I obviously know quite a bit about this. First on the Arctic, one, the Arctic is very large and there are definitely still areas in the Arctic which are prospective including a fair number that Rosneft still has licenses on, plus there's unlicensed areas in the Arctic. So Rosneft now has partnerships with some great companies. So Exxon, Statoil and Eni have a series of licenses offshore.
I think there's some others that are being considered. From our standpoint, from BP, we're very pleased to see great companies like that exploring, because effectively we own 20% and are carried in that exploration. So that's a good thing for us. And then so we'll continue to talk with them about ideas in the Arctic, but we're very pleased that Rossneft has been so aggressive leasing up that acreage. And then onshore, yes, we are talking with them across a variety of things from our experience in TNKBP.
But for us the success of having done the transaction with Rosneft is now less dependent on individual projects onshore or offshore, because we're sort of sharing all those together. And each BP and they will look very carefully at things that have economic promise. So I feel fine about that. And then in terms of the 25% dividend, the Russian government is a major shareholder who is considering a variety of different privatizations or whatever. But even as much as yesterday, the commitment has been made by Rosneft Neft of 25 percent dividend.
And the even the President referred to it this last week as something that's been in place. It's I haven't seen a document which says it's the policy, but of course you can see over the last year how often that's been referenced as being important to the government. I doubt that the company would go to a quarterly dividend, but they might. I don't know of that happening. I think there are certain times of the year related to the government budgeting when dividends are paid.
So I would stay tuned on that. But I don't think it will be quarterly.
Okay. Thanks very much.
Thanks, Ian. Let me Alastair Syme with Citi maybe?
Yes. Go ahead Alastair.
Yes. Thanks, Jess. Hi, Bob and Brian. Can I just quickly for Brian clarify the P and L accounting treatment of Rosneft? Is it just simply 20% of Rosneft IFRS accounts?
Or is there something else on there?
It is. But it will be simply 19.75 percent of the IFRS numbers. We may the only issue for us will be the way in which we look at our underlying earnings. It will be how they Rosneft treat NOIs. So we'll just need to make sure that's consistent with how we would treat NOIs.
But effectively yes it's 19.75 percent of the IFS earnings.
Brilliant. Thank you. And one for Bob. Can I ask sort of a very general question about profitability? Because you used the word strong multiple times through this call and it just strikes me when you look at the return on capital employed, you're not a 1000000 miles away from the cost of capital in this business in an environment north of $100 barrel oil.
So I just wonder is that a metric you think about much And how you think that moves going forward?
Well, Alastair, it's a good observation, but what has to come with it is the $38,000,000,000 of divestments. What we've made of very high return projects so that were highly depreciated assets. So by almost by definition our return on capital employed has come down dramatically quickly because we have divested so many high return assets and gotten very good prices for it. So I think for us, all the major oil companies in their life cycle sometimes grab on to return on capital employed when it sort of fits. Obviously, it wouldn't be the right one.
Now return on capital employed going forward absolutely improving that is what we intend to do. But we have so many big major projects coming on right now where we've got capital that is going to be fructified that I think you I mean Brian I think we're sort of at the bottom of this now. Now it's going to move up overall. Maybe I'll just leave it at that.
No, I think that's right, Bob. That's exactly right.
And I'll so Alistair so I'll go back to the previous question on Ross Neff, because I just was flipping through here notes and just sort of want to say on the dividends in the past at Ross Neff, they typically pay the dividend 60 days after the annual meeting, which is held in June. So you should probably be expecting something September timeframe I'm thinking. And last year was the 1st year they actually made 2 dividend payments in a year. So it does sound like it's going to be not easy to predict.
Right. Next question from Peter Hatton of RBC.
Thanks very much. I was going
to ask on the Gulf
of Mexico, but maybe thanks. You've covered that to Lucas' question. So really just a follow-up on the share buyback and the timing of that one. You're talking about up to €8,000,000,000 over the next 12 to 18 months. Can I just ask this is sort of directly linked to the return of the amount of cash originally invested in Rosneft being repaid?
Is that sort of a timetable of that totally independent to whatever happens on the court case and the appeal relating to Macondo? Or is there likely to be some preference to keep a lower gearing until that is clarified later this
year? We've made no linkage to anything happening with the legal cases to what we've done. We said that we would not our shareholders would not be diluted by the transaction in Rosneft which was roughly $4,000,000,000 So and then we have shrunken our asset base over the last year. And the decision by the Board was to be more aggressive with that and put that out there as an $8,000,000,000 buyback which we've started sort of consistently already is in place. So our thinking is that we've made that commitment to shareholders independent of any kind of a court case.
Thanks. Right. Next Colin Smith from VTV.
Thank you, gentlemen. A question on Jacques Denis. Just the wording in the report, I think makes it sound a little bit as though a decision might be slipping post 30th June, which is my understanding of when that decision was supposed to be made. I wonder if you could comment on that? And more broadly, could you just talk a little bit around what's actually going on with Shaktani?
Some idea of what the involvement is expected to be both in the pipeline sections across Turkey and whichever choice you make into Europe and whether you are selling the gas direct or what's going on with all of that contracting and the costs? Thank you.
Okay. So I just had a Chate Denis review that took a day. So let me see if I could summarize your very good question. For those of you who don't know what Chant Denise is, it's a very large gas field in the Caspian that will assuming it's economic and the decisions are made, I have to qualify that of course. But the pipeline would come out through and across Turkey that has an option of going to the north up through to Austria or could take straight across Turkey and head over through Greece to Albania into Italy.
And there's quite a bit of difference in the distance of those pipelines. And at least for the beginning, that pipeline needs a choice of which direction because the project can bear both pipelines being built. And so there has been quite a bit of work done by the TAP pipeline which is this other one to Italy and Nabucco which goes up to Austria. And we have said as a company in the Chach Denise consortium which is BP, Stettoel, Total and others that that is to it needs to be a decision that's based on economics and rather than politics. So those projects will be submitting their more or less bids that can determine the tariff structures across that that will allow us then to make a decision on Chateaunees on the upstream project later this year.
So the pipeline selection is heading towards resolution of that in June. And then based on only then can we make a decision on a final investment decision heading towards later in the year for the upstream decision. All of that is on track right now. There's a lot of politics involved in it. But we remain committed to an economic solution there.
And I can tell you that the Shantanuise field itself is doing great. The Phase 1 field is producing very well. There now is an indication of what's to come. And I can just tell you there's a lot of work going on, a lot of evaluation, a lot of pencil sharpening going on in the 2 different pipelines, which are effectively competing with each other. Colin that's probably a day's boiled down.
Okay. I don't know what else you would want specifically.
Okay. I think moving on then to Bertrand Haddie at Raymond James.
Yes. Thank you, Jess, for taking the question. I've got two questions, if I may. One is a follow-up on Mad Dog, SaaS. What kind of development cost reduction would you need on Mad Dog to get to final investment decision?
Is it planned 15%, 20% And then on a follow-up also on your FID for 2013. Bob mentioned 3 mega projects. You just talked about Chardanese. Can you give us an update on your on the progress being made on Oman and Tengu expansion?
Yes. Well, the sort of A number for FIDing Mad Dog Phase 2, II. I would just say it's not that simple because some of the options we're looking at is possibly bringing on some resources early and phasing it out over time versus a mega project all at once project. And so I think for us it's got to be competitive with other projects we have around the world. We think we will get it there, but not as not in the current form that we have it.
So I would just say don't worry. It'll be a good return project when we finally redo and refine the development concept and not out of line with other projects that we make. On the Tengu expansion, which would be Train 3, good progress has been made. We've certainly underpinned all the resources there for our 3rd train and we're actually very close to underpinning resources for our 4th train. So we're and we're actually beginning engineering in fact for the 4th train as well.
But that's just moving through the normal approval processes this year. I don't see any problems with that. It will be back end loaded this year. And then in Oman, we're in discussions now with the government in Oman. They're sensitive.
So I probably can't say very much more about Oman in particular. But some of the others that we're looking at the hot field in Norway, we've got other we've got the R Series in India which we're moving ahead. So we've got a number of things out there that we continue to work on. And as we go forward, we've got another at least 5 in 2014. So it's hard to say exactly which ones we see coming on.
I just don't want to list them all out, because obviously we're in some sensitive discussions with some groups.
And just a final question on Mad Dog. What is the available, I would say, capacity on the existing Mad Dog spa for potential tiebacks?
I think that's something you might want to check-in with Jess. I can't tell you what the tieback for them. But there is some volume in there and we're going to have another develop we're going to have the rig up and running working on it. Those of you who remember in 2,008 during the Ike hurricane that rig was badly damaged and that rig will be back up and working. But I think we've got capacity with Mad Dog.
And there's also new options and new facilities that we could consider as well for Phase 2.
Okay. Thank you.
Okay. Turning to Stephen Simcoe from Morningstar. Go ahead Stephen.
Hi. How are you guys doing?
Good. How are you doing Stephen?
Good. Thanks. I'll just ask one brief question and that would be on Volal. Both you and Hess have given guidance for this year and then you both talked about just the potential for the fields being very long lived and the capacity of platform being far above what 2013 guidance would be even at the implied end of the year run rate. And I'm just wondering, is this a project that's going to see continued growth in the next 1, 2, 3 years?
Is this going to be something that's going to have some sort of starts and stops as these incremental wells are drilled? And what would be the best way to think about the volumes from that post 2013? Thanks.
Yes. I mean, it's your point about stopping and starting that I'm not quite sure how to answer.
I guess it's more just is this effectively I'm just trying to ask is there any sort of planned date when this platform would be reaching full capacity?
Yes. It is premature. I mean, we've got we've done a lot of work on Volhall. It is a very unusual reservoir. It has porosity is greater than 33%, which is almost physically impossible to do, because it's got that chalk that diatomaceous earth in there.
And so every well is a bit of an adventure when you drill it in terms of the results and how it's going to hang on there in terms of production. So we've got the facilities back, so they'll last a very, very long time. And this is a field that has always surprised. It's been around since 1970s or late 70s early 80s and it just continues to surprise the way that reservoir works in terms of the original projections of oil reserves and oil in place. So I don't know how to exactly answer you there.
We're enthusiastic about it, but we haven't laid out specifics.
Helpful. Thank you.
Okay. Thank you. And the last question from Neil Morton Investec. Go ahead Neil.
Thank you. Just two quick numbers questions left please. Just firstly on the financial charges. You saw an uptick in Q1 with the new pension law coming in. But on the cash side at the end of the quarter, you got a lot of cash coming in.
So I just wondered if you're going to give some guidance on a reasonable quarterly run rate from here on? And just secondly, with regard to the cash flow target next year and cash tax rates, I think historically you've guided to 1, 2 percentage points below the income statement tax rate. Is that still applicable? Thank you.
So let me take that question Neil. We said originally I think with our 4Q results we talked about the new IAS 19 tax rules that came through that would result in an additional charge of about $1,000,000,000 to earnings for the year. So it's about $250,000,000 a quarter. It is cash 0. I mean this is something that's been forced on us by using the discount rates that we typically use against the liabilities rather than what you'd expect from return on equities.
So it is actually cash neutral. It doesn't actually impact the cash position in any of the quarters. And then sorry your second question was around the tax rate?
It was just the cash tax rate versus the income? Yes.
It is typically going to be around a couple of percentage points below where the income the underlying effective tax rate is. That's right.
Great. Thank you.
Thanks, Neil.
All right. Well, thank you, everybody. I think that's the last of the questions. And we look forward to talking to you again next quarter.
Yes. I'd just like to thank everyone for your many detailed questions. And we're already 1 third away through the Q2. So it won't be that long before we'll be back and see you again. Thank you.