Welcome to the BP presentation to the financial community webcast and conference call. I now hand over to Jessica Mitchell, Head of Investor Relations.
Hello, welcome. This is BP's first quarter 2014 results webcast and conference call. I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary. Before we start, I need to draw your attention to our cautionary statement. During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations. Actual results and outcomes could differ materially due to factors 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, now over to Bob.
Thank you, Jess, welcome to everyone who's joined us today, wherever you are in the world. The first quarter has been a very productive three months for us. In the upstream, we've made new exploration discoveries and started up new projects. In the downstream, the newly modernized Whiting Refinery continued to ramp up, along with progress across our fuels, lubricants, and petrochemical businesses. We continued our focus on safe and reliable operations across the whole of the group. In March, we affirmed BP's proposition to shareholders out to 2018. Just to remind you of what we said, we are committed to growing sustainable free cash flow through a combination of growing operating cash and capital discipline with the intention of growing distributions to shareholders.
As you can see from today's results, we've delivered a solid start to the year, which puts us firmly on course to deliver our 2014 goal of delivering $30 billion-$31 billion of operating cash flow at $100 oil. Turning to the agenda, Brian will start by taking us through the results for the first quarter in detail, along with a reminder of our financial framework and guidance. I will then talk briefly about ongoing legal proceedings in the U.S. before sharing some of the first quarter highlights in our operations and at Rosneft. Finally, there will be time for Brian and I to take your questions. Let me now hand over to Brian to take you through the numbers.
Thanks, Bob. BP's first quarter underlying replacement cost profit was $3.2 billion, down 23% on the same period a year ago and 15% higher than the fourth quarter of 2013. Compared to a year ago, the result reflects higher costs, predominantly non-cash, in the upstream business, a significantly weaker refining environment, and lower production, partly offset by the return of the largest crude unit at our Whiting Refinery. Compared to the previous quarter, the result reflects lower costs and a stronger contribution from supply and trading in both upstream and downstream, partly offset by a significant reduction in our share of earnings from Rosneft due to the recent weakness of the ruble and the absence of the one-off benefit to BP's share of Rosneft net income in the fourth quarter. Operating cash flow was $8.2 billion for the quarter.
We have announced an 8.3% year-on-year increase in the first quarter dividend to $0.0975 per ordinary share, payable in June. In upstream, the underlying first quarter replacement cost profit before interest and tax of $4.4 billion compares with $5.7 billion a year ago and $3.9 billion in the fourth quarter of 2013. Compared to the first quarter of 2013, the result reflects higher costs, predominantly exploration write-offs and DD&A, and lower production and lower liquids realizations, partly offset by strong gas marketing and trading results and higher gas realizations. Following our decision to create a separate business around our U.S. Lower 48 onshore oil and gas activities, and as a consequence of disappointing appraisal results, we have decided not to proceed with development plans in the Utica Shale. As a result, we have taken a $520 million exploration write-off relating to Utica acreage in the quarter.
Excluding Russia, first quarter reported production versus a year ago was 8.5% lower, primarily due to the Abu Dhabi onshore concession expiry in January and the impact of divestments. After adjusting for these factors and entitlement impacts, underlying production was slightly lower. With new major project volumes in the North Sea, Angola, and the Gulf of Mexico, we have grown our total underlying production in higher margin areas. Compared to the fourth quarter, the result reflects lower costs, higher gas realizations, and stronger gas marketing and trading results, partly offset by the absence of the one-off benefit to production taxes in the fourth quarter and lower liquids realizations. Looking ahead, we expect second quarter 2014 reported production to be lower than the first quarter. This is driven by planned major turnaround activity in the higher margin North Sea and Gulf of Mexico regions.
We expect the turnaround impact on production to be slightly less than the impact experienced in the second quarter of 2013. Rosneft is expected to announce first quarter results tomorrow. Based on preliminary information, we expect BP's underlying net income related to our Rosneft shareholding to be $270 million for the first quarter. This compares to BP's share of Rosneft net income in the first quarter of last year of $90 million, which included only 11 days of earnings. Compared to the previous quarter, underlying net income is expected to be $820 million lower. The first quarter was adversely impacted by the devaluation of the ruble and the absence of adjustments made in the fourth quarter to finalize BP's equity accounting for 2013. BP's share of Rosneft production for the first quarter is estimated at one million barrels of oil equivalent per day.
We expect to receive our next dividend from Rosneft in the third quarter of 2014. In the Downstream, the first quarter underlying replacement cost profit before interest and tax was $1 billion, compared with $1.6 billion in the first quarter last year and $70 million in the fourth quarter. The fuels business reported an underlying replacement cost profit before interest and tax of $700 million in the first quarter, compared with a $1.2 billion profit in the same quarter last year. The decrease reflects a significantly weaker refining environment, partly offset by the return of the largest crude unit at our Whiting Refinery, which had a planned outage in the same period of 2013, and the progressive increase in heavy crude processing throughout the quarter. This quarter, the fuels business also had a strong supply and trading contribution, similar to the first quarter of 2013.
Heavy crude processing continued to increase at Whiting, reaching about 200,000 barrels per day at the end of the quarter. It is expected to reach around 280,000 barrels per day during the second quarter, optimizing to market conditions. The lubricants business reported an underlying replacement cost profit before interest and tax of $310 million, compared with $350 million in the same quarter last year. The difference is primarily due to exchange rate effects on the Indian rupee, the British pound, and the South African rand. Beyond this, the result reflects continued delivery of our strategy focused on premium lubricants, leading brands, and high growth markets. The petrochemicals business reported a break-even result. Our major complex near Shanghai has been down for a site turnaround since early March. The environment for this business continues to be challenging, with strong product demand growth more than offset by excess supply.
In other business and corporate, we reported a pre-tax underlying replacement cost charge of $490 million for the first quarter in line with guidance. Guidance for 2014 remains unchanged, with the average underlying quarterly charge in the range of $400 million to $500 million per quarter. The underlying effective tax rate for the first quarter was 33%, compared to 39% in the first quarter of 2013. The rate is lower than a year ago, mainly due to foreign exchange effects and a higher level of equity income from Rosneft, which is reported net of tax. Guidance for the full year effective tax rate remains around 35%. The charge for the Gulf of Mexico oil spill was $40 million in the first quarter, primarily reflecting the ongoing cost of running the Gulf Coast Restoration Organization. The total cumulative pre-tax charge for the incident to date is now $42.7 billion.
The charge does not include any provision for business economic loss claims that are yet to be received, processed, and paid. Bob will provide an update on the legal process shortly. As we have previously advised, it is still not possible to reliably estimate the remaining liability for business economic loss claims. We will continue to revisit this each quarter. The pre-tax cash outflow on costs related to the oil spill for the first quarter was $700 million. The cumulative amount estimated to be paid from the trust fund remains at $19.3 billion, leaving unallocated headroom available in the trust for further expenditures of around $700 million. In the event that the headroom is fully utilized, subsequent additional costs will be charged to the income statement as they arise.
At the end of the quarter, the aggregate remaining cash balances in the trust and qualified settlement funds were $6.6 billion, with $20 billion paid in and $13.4 billion paid out. As indicated in previous quarters, we continue to believe that BP was not grossly negligent and have taken a charge against income on that basis. Turning now to divestments. In 2013, we completed our $38 billion divestment program and the sale of our share of TNK-BP to Rosneft for $27.5 billion. We continue to actively manage our portfolio, and in October, announced plans to divest a further $10 billion of assets by the end of 2015. So far, we have signed deals worth over $3 billion against this commitment. This includes the recently announced sale of a package of assets in the Alaskan North Slope for $1.25 billion.
This slide compares our sources and uses of cash in the first quarter of 2013 and 2014. Operating cash flow was $8.2 billion in the first quarter of 2014, compared to $4 billion a year ago. Excluding oil spill related outgoings, underlying cash flow was $8.9 billion compared to $4.5 billion a year ago. In both cases, the increase is largely due to continued robust cash delivery from our businesses and the absence of the building of working capital reported in the first quarter of 2013. Our organic capital expenditure in the first quarter was $5.4 billion. Inorganic capital expenditure in the quarter was $680 million and included the purchase of additional equity in Shah Deniz and the South Caucasus Pipeline in Azerbaijan. We received investment proceeds of $1 billion during the first quarter, and $2 billion of shares were also repurchased in the quarter.
At the end of the first quarter, net debt was $25.3 billion with gearing at 16.2%. Previously stated, our intention remains to keep gearing in a target band of 10%-20% while uncertainties remain. Already noted, today we announced an increase in our quarterly dividend to $0.0975 per ordinary share, 8.3% higher than a year ago. This reflects our confidence in our ability to grow sustainable free cash over the medium to longer term and the delivery of the 10-point plan. As previously announced, the board will continue to review the dividend with the first and third quarter results each year. Since the 1st of January this year, we have bought back $2.1 billion of our own shares, bringing the cumulative total since early 2013 to $7.6 billion.
Our $8 billion share buyback program from the proceed of the sale of our interest in TNK-BP is now approaching completion. We intend to use the post-tax proceeds from our current $10 billion investment program predominantly for shareholder distributions with a bias to share buybacks. This will support a continuation of buybacks beyond the current program. Looking further out to 2018 and the financial outlook we showed for the year in March. We remain confident of delivering operating cash flow of $30 billion-$31 billion in 2014 at $100 a barrel, an increase of more than 50% over 2011. Relative to 2013, this reflects the higher expected contribution from major projects in the upstream, the continuing ramp-up at the Whiting Refinery, and some reverse of the working capital build seen in 2012 and 2013.
In 2015, we expect operating cash flow to be broadly similar to 2014, before then growing out to 2018. We also intend to keep capital expenditure in a range of $24 billion-$26 billion per annum over the same period. This will provide the platform for us to continue to grow shareholder distributions. Firstly, by growing dividend per share progressively in accordance with expected growth in sustainable underlying operating cash flow. Secondly, we will then look to bias surplus cash over and above capital requirements and dividend payments to further distributions through buybacks or other mechanisms. Now let me hand you back to Bob.
Thank you, Brian. Next, let me give you a brief update on the status of certain Gulf of Mexico related legal proceedings in the United States. As you probably know, the first and second phases of the MDL 2179 trial in New Orleans are now complete, with the court yet to rule on either. The penalty phase, in which the court will hear evidence regarding the penalty factors set out in the Clean Water Act, has been scheduled to begin on January 20th next year. Separately, BP continues to contest the payment of business economic loss claims, which we believe to be unfounded. Last month, the Fifth Circuit denied BP's request for a permanent injunction to prevent the payment of business economic loss claims not traceable to the oil spill.
We disagree with this decision and have requested an en banc hearing review by all of the active Fifth Circuit judges. We've also asked the court to consider this petition at the same time as it considers our petition in the appeal related to the final improvement of the settlement. Importantly, the court issued a fair and reasonable ruling regarding the matching of revenues and expenses in calculating business economic loss claims, and a new matching policy has been submitted to the district court for approval. BP has indicated its support for the policy, while the plaintiffs' steering committee have objected. In the meantime, the temporary stay of all business economic loss claim payments remains in place until the appellate court issues its mandate.
Also, last month, BP entered into an administrative agreement with the United States Environmental Protection Agency on behalf of the federal government, resolving all matters related to the suspension, debarment, and statutory disqualification of BP following the Deepwater Horizon accident and oil spill. As a result of this agreement, BP is once again eligible to enter into contracts with the U.S. government, including new deepwater drilling leases in the Gulf of Mexico and fuel supply contracts. I'll come back to this in a moment. We are determined to pursue fair outcomes in all legal proceedings for our millions of large and small shareholders. We continue to compartmentalize the management of these activities to avoid distraction, and BP's operating teams remain firmly focused on delivering our business objectives.
Turning to the upstream, we announced last week a deal to sell interest in a number of our Alaskan assets to Hilcorp for $1.25 billion, plus a development carry for the Liberty field of up to $250 million. This deal will concentrate our operating footprint, and we expect it to drive higher activity into the basin. This enables us to focus more intensely on maximizing production from Prudhoe Bay, North America's largest oil field, as well as progressing the Alaska LNG opportunity. In exploration, following last year's success, we intend to complete at least 15 exploration wells in 2014. Eight wells have already been completed, resulting in two new discoveries at Orca in Angola and Notus in Egypt. Both of these wells were tests of newly acquired acreage and give us further encouragement in the plays we are testing.
We continue to access new acreage, as our recent result in the Gulf of Mexico lease sale shows. BP was the highest bidder on 24 out of 31 blocks, with final award subject to regulatory approval. This was made possible by the lifting of BP's debarment by the USEPA in March and demonstrates our continued commitment to the Gulf of Mexico. Turning to projects, the first quarter of 2014 saw three major project startups: Na Kika Phase 3 and Mars B in the Gulf of Mexico, and the Chirag oil project in Azerbaijan. I'm pleased to say that the Atlantis North Expansion Phase 2 project in the Gulf of Mexico started up earlier this month. This milestone represents the first of our four new production wells in this development. We continue to make progress on three further startups planned for 2014.
In Angola, the CLOV FPSO is now moored on site, with hookup, well cleanup, and other pre-commissioning activities now in progress. In the North Sea, the Kinnoull project offshore construction and commissioning ramp-up are on track. Finally, in Canada, all wells have been drilled on the Sunrise Phase 1 oil sands project. The wells facilities are also complete and construction of the central processing facilities is in progress. In our operations, we have started our 2014 turnaround program, with our first in Angola completed ahead of schedule. The majority of seasonal turnaround activities will occur in the second and third quarters. Having invested heavily over the past few years, our 2014 program represents a lower level of activity compared to prior years. We continue to see an improvement in our operations, with first quarter BP-operated plant efficiency more than 1% higher than the 2013 average.
This is driven by our investment in maintenance and reliability, as well as the benefits being delivered by our functional organizational model. Finally, in our global wells organization, we expect to deliver our highest operated production from new wells and well work for four years. Our top 15 wells for 2014 will deliver two-thirds of total new well production this year. 45% of these wells have come online in the first quarter. With regard to Russia, let me first update you on some organizational changes. We recently announced the appointment of David Campbell as BP's new head of Russia, based in Moscow and reporting directly to myself. David brings 30 years of commercial experience, technical and operational leadership roles across a wide range of locations, including the Alaskan Arctic, the North Sea, Mexico, and Iraq, as well as within TNK-BP.
This move combines the head of Russia and regional president roles, simplifying and focusing how we manage our unique position in Russia. Turning to Rosneft's progress during the quarter, recent events have created some volatility in the Russian financial markets, and as you have seen, the weaker ruble has affected current quarter earnings. However, Rosneft continues to make strong progress. In the quarter, this included an asset sale of over $1 billion to Sibur, with whom Rosneft also concluded a significant long-term associated gas sales agreement. Rosneft are also focusing on improvements in the efficiency of their operations and also continue to progress the execution of their major projects and their ongoing refinery modernization program. Our commitment to Rosneft is a long-term one. Our relationship continues to grow, and we believe that it will have significant benefits for both Rosneft and BP.
In the downstream, the quality of our portfolio continues to improve, and we are maintaining focus on safe, reliable operations. That's reflected in our high Solomon availability, which remains strong at 95% in the first quarter. This quarter, we continue to increase heavy crude processing at the Whiting Refinery. Throughput reached about 200,000 barrels per day at the end of March, and in April has achieved over 210,000 barrels per day. Whiting is expected to reach heavy throughput of 280,000 barrels per day during the second quarter. We continue to focus on the overall quality of our downstream portfolio, having announced earlier this month that we will be ceasing refining operations at the Bulwer Island Refinery in Australia by mid-2015. This has been driven by commercial pressures experienced by small scale refineries in the region.
In petrochemicals, we acquired the remaining 50% joint venture interest in our PTA plant in Indonesia as we consolidate our footprint around advantage locations. In lubricants, we've launched a new product, Castrol EDGE, which is boosted with Fluid TITANIUM Technology, which is a unique polymer, and continues our strategic focus on technology and quality lubricants to further develop our premium brands. Let me now sum things up. The BP proposition out to 2018 is to deliver value for shareholders in the form of sustainable growth and free cash flow in support of growing distributions. We plan to do this through material growth and operating cash flow, coupled with strong capital discipline. I think we can now fairly claim to be a company that is achieving real business momentum and turning words into action.
As you can see, we are actively managing our portfolio, both unlocking value today and allowing us to focus on value over volume into the future. Our recent announcement to divest a package of assets in Alaska is a good example of this. In exploration, we have participated in two new discoveries and eight exploration wells year to date. In the upstream, we've already started up four major projects this year, all in high margin areas. In the downstream, the upgraded Whiting Refinery is ramping up steadily. This is all helping us steer a course towards material growth and operating cash flow. At the same time, we are maintaining capital discipline and intend to stay strictly within the limits we've set ourselves. I am confident we are making strong progress, and you can see this reflected in the dividend increase we've announced today.
Thank you for listening, and now we will be happy to take your questions.
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Well, welcome all to the Q&A session. It's Jess speaking again, and we will take the first question today from Jason Gammel from Jefferies. Go ahead, Jason.
Thanks very much, thank you for the update on the situation with Rosneft. I realize it hasn't been a large amount of time since incremental sanctions were imposed on Mr. Sechin. Would you be able to provide your understanding of how this potentially restricts your participation in the financial results of Rosneft, or indeed in participating in any board meetings or board decisions?
Jason, yes. Hi, thanks. Well, a couple of things. You're right, it's only been about 24 hours. We will, of course, comply with any of the relevant sanctions, and we'll monitor the situation very closely. Rosneft itself has not been sanctioned, so we will continue to work in whatever the appropriate manner is with Rosneft, primarily as a shareholder, but also as a partner. Of course, BP is not alone in being a big energy investor in Russia and a partner of Rosneft. Jason, we are committed to our investment in Rosneft. We intend to remain a successful long-term investor in Russia. Yes, I will be able to continue to participate on the board of directors of Rosneft itself. I think Let me see, what can I add to that from your questions?
We will be able to exercise our shareholder vote at the Rosneft AGM. Maybe Brian, maybe Jason, if you're interested, you can comment on the accounting impact if any.
Yeah, Jason, in terms of your question, participating in their earnings, nothing has changed in the last 24 hours. In terms of the accounting standards, in terms of equity accounting, as a starting point, equity accounting starts on the assumption that you're somewhere north of 15%. We have something close to 20%. The accounting standard also requires that you can evidence in any one of five ways, either through representation on the board of directors, which clearly we have through Bob, participation in policy making processes through that board seat, interchange of managerial personnel or provision of essential technical information or any material transactions between the two parties. I think we tick four of those five boxes in terms of equity accounting. We review that on a quarterly basis with the audit committee, and nothing has changed in the last 24 hours that would affect that.
Okay. Appreciate the comments. I know there's a lot of uncertainty still around the whole situation.
Yeah. We will, of course, comply with all the relevant sanctions. We're just going to continue to monitor it. Thanks, Jason.
Okay, thank you. Next question from Irene Himona at Société Générale.
Thank you, Jess. Good afternoon. I had a couple of questions for you. Firstly, you had spoken last year, I think, about a potential reversal of the large negative working capital that we had seen in 2013. It wasn't in Q1. Can we still expect that reversal over the rest of this year and next year? Secondly, Bob, you mentioned Angola. I wonder if you could briefly update us on the pre-salt drilling plans for this year. Thank you.
Irene, I'll just pick up the first question. You've clearly looked very closely at the balance sheet. We saw a release of around GBP 400 million of working capital in the first quarter results. That's typically a quarter where quite often you may see a build, but there are no operational issues in terms of that would drive that. There has been a modest release of about GBP 400 million this quarter. Nothing has changed from what we've said previously, I think at the end of 3Q, that we expected roughly two-thirds of the GBP 5 billion to release or unwind itself through this year. All things being equal and nothing changing in terms of pricings. Of course, pricing would have an effect. You're right, it's a relatively modest release in 1Q, and we'd expect to see some more of that release as the year progresses.
Okay. Thank you.
Yeah, Irene, on Angola, it's actually been a pretty good period here in terms of drilling. We're evaluating what we think is a breakthrough discovery made offshore Angola in the pre-salt, which is that for those of you, that layer that lies beneath those big thick layers of salt. It's operated by Cobalt. The first well was Lontra number 1, which is on Block 20. Cobalt announced a discovery on a well called Orca, in the deep water pre-salt, also in Block 20. That one, estimated resources appear to be between 400 and 700 million barrels of a large light oil structure. We're going to continue to test that Orca further. We've got additional wells that will be drilled this year. I'm just flipping through to look and see which well. We've got a well that we'll be drilling. Yeah.
I have a note here that says that we shouldn't really talk about the exact wells. We're going to have a well, and it has a name. I think we're going to be splitting that well in Block 19. Cobalt themselves will begin to drill an appraisal well as well in Block 20. That's probably all I should say right now.
Yeah.
We're very enthused about the region.
Okay, thanks so much.
Okay. Thank you. All right, the next question, we'll move over to the U.S. Doug Terreson from ISI. Are you there, Doug?
I am. Good morning, everybody. In E&P, production has been pretty resilient on a comparable basis, and it seems that profitability is likely to be resilient, too, given the growth from the higher-margin startups that were highlighted in the release today. My question is whether, besides the seasonal turnarounds and the loss of Abu Dhabi that Brian mentioned, are there any other major mix effects that are going to affect E&P profitability in 2014? Should this be a year of higher profitability in E&P for the company?
Yeah, Doug, it is. There's nothing major that's going to throw that. We've started up four projects this year. We've got three more to start up, as mentioned earlier.
Right.
You're right, the turnarounds which have gone, I think in 2011, we did 47 turnarounds, then in 2012, we did 30, and in 2013, we did 20. This year, we're down to 10. You will see that drop in turnarounds, of which four will be in the second quarter and four will be in the third quarter. There's nothing that I can look at that would see a major change. Underlying production
Okay
should grow as these new projects come on, most certainly. Year-over-year underlying, there will be some growth in 2014.
Okay. Also, Bob, a few minutes ago, you spent a minute on the BEL settlement, where I think you mentioned that payments are on hold, and appropriately so, in my opinion. Because the figures associated with this item are so meaningful, my question is what outcomes would need to unfold to trigger a change in the provision in this area? Meaning, is the recent decision that you indicated the PSC disagrees likely to represent some type of binding judgment in this area, or could this portion also face an extended legal path? Just any color on this process in this area, which is pretty meaningful, would be appreciated.
Yeah. Doug, there's a lot of moving pieces of this, and Brian sat down earlier with our legal team and lawyers.
Maybe just Doug on the specifics of the matching policy, which is still sitting with the judge, has been recommended forward by the fund in terms of how the new matching policy should now be enforced post the Fifth Circuit ruling. We'll have to wait for that to effectively come into force. Once that's in force and in action, and we get a period of time of where we start to see new determinations, and indeed, no doubt the revision of older determinations inside the fund, and we get some flow in terms of understanding what sort of claims are then being processed. After a period of time, we'll try and come back and do some sort of actuarial calculations. Right now it's indeterminable. On that basis.
Okay
We will simply take provisions as they arise in each quarter. As you say, effectively those payments have been suspended for 12 months. We will now wait until that determination comes through. Sorry, over the last six months. We'll wait till that determination comes through, and then we'll be able to try and do an estimate. It really will require some pattern of claims threats would enable the actuaries to do that.
Okay. Thanks for the clarification, Brian.
Doug, I just want to say that, while there's been some things that we've been less than satisfied about, I think the court's ruling on the matching is fair and reasonable.
Well, rightfully so, I'm less than satisfied.
Thank you. Next in the U.K., Theepan Jothilingam from Nomura.
Yes. Thank you, Jess. Good afternoon. I just wanted to focus on the Gulf of Mexico and also the Lower 48. Perhaps firstly, could you sort of just update in terms of the trajectory in the GOM? I know you've talked about maintenance, but how does that compare to sort of the increased activity levels with the number of rigs and the producer wells you've talked about? Could you discuss, in that context, Thunder Horse? In terms of the new model in the Lower 48, I know it's early days since your announcement in March, but perhaps you could talk about what's been implemented so far, what type of E&A activity you expect, and how much capital employed you have in that business. Thank you.
Okay. A lot of questions there, Theepan. Thank you. Well, the Gulf of Mexico, we've got 11 rigs running now in the Gulf, four exploration, two appraisal wells. Production will continue to increase in 2014. Fourth quarter production was up about seven over the third quarter of 2013. I won't give you the numbers today, but we are bringing on a series of new wells. We're well over 200,000 barrels a day in the first quarter. We expect to continue a trajectory out in time, 2018 or so, out towards 300,000 barrels a day. We feel like we're on track for that. We're gonna have happening right now a major project ramp-up at Na Kika Phase 3. The Shell-operated Mars B project is ramping up as well. We had, in middle of April, the North Atlantis Phase 2 project start up, the first of four wells.
Thunder Horse and Atlantis, we've got new wells coming on. The well work delivery at Thunder Horse is happening. We will have two minor turnarounds in 2014 on Thunder Horse, and then later out, 2015 to 2020, really the growth that we see in our hubs will be driven by Thunder Horse and Atlantis 2B. We still have only around 20% of the Gulf of Mexico resources around those four hubs have been produced to date. While the trajectory won't be a straight line, Theepan, it's definitely on track for what we told you before.
Theepan, in terms of Lower 48, it's a little premature at this point since it was only a month ago that we announced it. We are clearly, in terms of Lamar and the team, are in action around what the new governance model looks like. All of the various internal announcements, what that means in terms of sizing the organization, are pretty well advanced. What I would say in terms of the first quarter, it was certainly probably one of the strongest quarters we've seen in over three years, as you'd expect with the run-up in gas prices in the United States. Both a strong earnings quarter for that business relative to the history and from operating cash flow delivery perspective.
I think it was a good quarter, but I think it's a bit premature yet to talk about where we are, and we'll certainly have a lot more information at the second quarter around where Lamar's got to with the reorganization of that business.
Great. Thank you.
The next question comes from Oswald Clint at Bernstein.
Thank you very much, Jess. Actually a question just around what Brian was talking about. I was curious on the Lower 48 business if, just looking at your Henry Hub sensitivities, if that business was able to capture that type of sensitivity. I think it might have implied about $300 million of kind of RCOP from the first quarter versus first quarter last year. I just want to get a sense of if it was able to capture that level of profitability. Also just linking into that on the Lower 48 business, and given what happened to your assets in Utica, how confident or how good an asset do you think your Eagle Ford position is at this point? Thank you.
Oswald, on the first question, yes, it has been a good quarter, and we've been able to capture the upside. Notwithstanding that, of course, the Utica write-off sits in the Lower 48 books. There's no question we were able to capture the upside in the gas prices for the first quarter and in terms of cash flow for that quarter as well. Yes, is the answer to the first part. Bob, you want to talk about Eagle Ford?
The Eagle Ford is producing between just under 40,000 barrels a day oil equivalent, of which 34% is liquid. We like our Eagle Ford position. We like the relationship we have with our partner there, where they do a lot of the surface operations, and we do a lot of the subsurface work, Lewis. It's actually been a very good model for us. Yes. I'm happy with it.
Okay, great. Thank you.
Thanks, Oswald. Over in the U.S., Stephen Simko from Morningstar Research. Go ahead, Stephen.
Hi, good afternoon, everybody. Building on the last question excuse me, related to the Eagle Ford and your opinion of that. I was wondering, when you guys talked about the onshore reporting and changes that are gonna happen with your Lower 48 assets, you showed a map of your different gas acreage. I was wondering If and when the time comes where you decide to deploy capital a little bit more into that business going forward, how would you stack up the plays and the producing assets that you have? Put another way, where would the first dry gas rigs be deployed to in that acreage? Thanks.
Yeah. Part of your question has to do with scale of operations in the various areas. Certainly places with scale, like we have in San Juan, produces high rates of production, but it's pretty dry gas. Obviously, the first thing we're interested in are liquids, because that's where most of the value is. In our production areas of Wamsutter, which have a reasonable amount of liquids as well, 40% liquids, we've got three rigs running there. We don't have that many rigs running in North America, but three in Wamsutter. We've got two running in the Haynesville, which is only about 20% liquids. We've got to restructure that business and get the cost, let the business itself look through the Wamsutter, the San Juan, Anadarko, Woodford, et cetera.
Very helpful. Thanks.
Yeah, sure.
Okay, thank you. Next question from Alejandro Demichelis at Exane. Can you go ahead, Alejandro?
Yes, thank you, Jess. Coming back to the onshore business in the U.S., and the write-down there you have made here on Utica. If that's the case, when do you think that that could happen? The rest of the acreage, are you still going to go through and analyze what you feel the fair value of those assets are? The second question is, in the overall group, how do you see the cost evolving, let's say over the next 12 months?
Alejandro, if I maybe pick up the first part. In terms of Utica, we've taken the write-off of the assets where we've made the appraisal wells. It's premature to say what we'll do with the remaining parts of that asset base. I think we've made it very clear that we don't intend to proceed with where we are today. That is really commercial information that we wouldn't normally release on a call.
I'd say in terms of costs. I assume, Alejandro, you're asking about upstream costs, which are again, different in different basins around the world. For the entire group, we are continuing to simplify. We're seeing lower lifting really across all the regions, pretty much. We are reducing our seismic activity, which will be part of our cost reduction as well. We've finished a lot of seismic. Our total cash costs for the upstream, we expect it to be down about 1% from last year through this year, mainly due to better efficiency and a lot of these reorganizations that we've been talking about.
That's very helpful. Thank you.
Thank you.
Right. The next question comes from Jon Rigby at UBS.
Hi. Yeah, hi. Thanks, Jess. Can I just pick up on the comments you've made on trading? I think you had a good trading quarter, both in gas and in the downstream as well. I remember a couple of years ago, we were all worrying a little bit about the increase in competition with banks hiring large commodity teams, et cetera, there seems to be a process of exit there, which I guess has implications for competition, but also for liquidity in the market. There's obviously increased regulatory scrutiny. I'm also sort of looking at the way your disposal program is going and I think some of the gas processing plants in the upstream, and clearly refinery capacity in the downstream is changing.
I wonder whether you can just indicate where you see in the sort of medium term, looking back historically, where trading earnings have gone. Are they remaining consistent? Could we expect or should we expect any changes in the contribution to the business going forward?
Thanks, Jon. I think the way I'd character it is there's an awful lot of information you've put out there in terms of the question. You've sort of laid out the landscape of what we see around commodities in the energy space. From BP's perspective, you have to remember the reason why we're there in the first place is because we have big major flows of oil and gas, and therefore, the first role of our trading business is to make sure they get balanced and ensure that our refineries get the best prices for their crude inputs and our upstream gets the best price for disposal of its production. That's the kind of primacy of why we have the business.
Of course, it does at time to time take on positions, entrepreneurial positions, that allow us to be able to benefit in the marketplace through positions that we have. Of course, this quarter's been a strong quarter. I think if you look at the volatility of the earnings over the last two or three years, a lot of that has been driven by the volatility of the absolute price itself. We don't trade outright flat price. We tend to trade a commodity versus another commodity because we'll have a point of view on that. I think what you've seen is there's been a lot of change in the space itself in terms of people entering and exiting the market. We've seen a number of new entrants, which is good for liquidity reasons.
I think, at the end of the day, it's been a strong quarter, both in the oil and the gas piece. Compared to the first quarter last year, that was also a strong quarter. The delta 1Q isn't that large, this quarter versus the same quarter last year, because we also had a good set of results from the trading business there. It's something we continue to invest in going forward. In terms of linking it back to our asset positions, we can also, of course, replicate some of those through leasing our own storage, which that business does, in both oil and gas. It doesn't absolutely rely on having the own asset base in place.
Just as a follow-up. How does it rank in terms of- I mean, you're an unusual beast in that you look at return on capital. I guess a lot of your competitors don't. Does it use up a lot of capital to put on trading positions?
No, Jon. Well, you will know better than anybody that return on capital is a kind of interesting measure, but it depends on the sort of nature of the business and how long you've been in the business and the continuity of that business, i.e, if you have lots of portfolio changes inside it. We look to ensure that its returns that we get from the business are accretive to the group. If you look at where the group is, normally, given some of the risk, so you'd normally look at a risk-adjusted return, typically, in this space. You'd be wanting that to be significantly higher than the average returns for the group on a risk-weighted basis.
Great. Thank you.
Thanks, Jon. To Martijn Rats of Morgan Stanley.
Hi. Hello. I had a question about the U.K. operations. The 20F, over the last couple of years, has shown, well, of course, quite a deterioration in volumes, but also quite a sort of upswing in production cost per barrel. Over the last three years, they've gone from GBP 12 to GBP 21 to GBP 25, and last year to GBP 31 a barrel. There must be something sort of underlying that I don't quite capture. I was wondering if you could comment a bit on where you see the U.K. operations going in terms of both volumes as well as production costs.
Martijn, I'll have a go at it, but I can't give you a precise answer.
No.
My good feel, and we'll come back to you specifically, would be that as reliability in the North Sea has been an issue for the whole industry over the last couple of years. Clearly, the denominator has been affected for everybody in the North Sea, and that's one of our biggest pieces that you'll see this year. We've certainly seen it in the first quarter, is improvements in reliability in our operations there is one of the primacy of the things that we're trying to do. I would suspect that's one of the biggest drivers of what you've seen in terms of costs and the number of turnarounds that we've had in place there. Of course, our North Sea business has gone through a fairly major restructuring over the last two or three years.
Maybe we'll come back on a future call to give you something specific on that around the North Sea.
Yeah. Given that that, for many, seems to be going through a bit of a sort of inflection point, if there's any indication of how much of the loss could be regained, that'd be very interesting.
I think you'll see some of that come back as you start to see reliability improve in the North Sea for sure, and that's part of the future projections that we've laid out there around improving reliability. North Sea is certainly a part of that.
Okay. Thank you.
Yeah. The Kinnoull will start up. That'll be later this year. Yeah.
Thanks, Martijn. Ian Reid from BMO. Go ahead, Ian.
Yeah. Hi. Thanks a lot. Just coming back on the Rosneft question, Bob, if I can. I was wondering. You've undoubtedly done some analysis of what might happen if Rosneft, the company itself, is sanctioned. I wonder what that means in terms of your interactions with them, and is there any kind of worst-case scenario where you'd be forced to actually dispose of the stake? Second question is in the downstream. Obviously, a big increase in profitability in the U.S. I'm just wondering how much of that was purely due to Whiting versus your other assets there. Thanks a lot.
Yeah. Ian, hi. I think projecting the price of oil, I'd be about as good at that as projecting sanctions. I think trying to speculate on what would happen or could happen really isn't helpful. As I said before, we'll respond appropriately to any sanctions and abide by them. Speculating on worst cases is like projecting what happens if the price of oil falls to $10. I'm not thinking that that's going to happen. Go ahead.
Yeah. On the second question around downstream first quarter versus the previous quarter, it's obviously the recovery to somewhat recovery in refining margins and a stronger trading result versus a very poor low result that we had in the fourth quarter. 1Q versus 1Q, there is certainly a benefit of Whiting since we took Whiting out of service, if you recall, in the first quarter of last year. Whiting being back on stream this year versus last year being taken out of service, getting ready for the upgrade, is certainly part of the first quarter versus first quarter results.
You can't qualify that a bit more, Bob?
Nope.
Okay. Thank you.
Okay. Thanks, Ian. Next from Chris Kuplent at Merrill's. Are you there?
Hello there. Thanks, Jess. Just a quick question on the operating cash flow recovery. I noticed that very little of that, whether it's quarter-on-quarter or year-on-year, has anything to do with what happened in the last quarter on working capital. I know you're going to warn us not to annualize this number into the full year, but can you confirm that you see that trend continuing and maybe update us on what you found out in terms of the Whiting ramp-up impacting the working capital for this year? Second question, more broad. I guess I just wanted to know whether you expect any additional, whether it's political or regulatory headwinds following the headlines surrounding the Lake Michigan spill. Thank you.
Let me just take the first part of that question, which is that we would expect. First of all, don't take 8.2 and times it by four. Clearly, that would not be a sensible thing to do, especially since we'll see at the end of this year the mineral oil tax , GBP 2 billion will flow out again. That is predictable every year around that sort of order of magnitude. You can assume that there will be, as I said earlier, some more working capital release, but the biggest driver, 4Q into 1Q from last quarter to this quarter is really around the underlying cash earnings coming from the businesses Across the whole suite of different areas, slightly lower tax paid, and some other lower payments.
I think the way I'd couch the first quarter is, this is a good solid start for the year, and there will be more to follow quarter-by-quarter.
Yeah. Chris, on Whiting, for those of you who don't know, back in March, we had a process upset in one of our Whiting crude distillation units that resulted in a discharge of oil into the cooling water outfall into Lake Michigan. That cleanup was done immediately, not only with booms but vacuuming off the lake, managed, collecting all that to reach the shore. The effort was not just managed by BP, but with members of the U.S. Coast Guard and the U.S. EPA. The estimate to the EPA and the U.S. Coast Guard was somewhere between 15 and 39 barrels of oil. The representatives were from the Coast Guard. They inspected the area, gosh, first week of April and determined that there was no further cleanup work needed. There haven't been any known impacts to wildlife or human health.
The exact cause, we're still investigating it, but there were no impacts to the refinery production or supply. I think that incident has been put aside.
Sorry, Chris, you also asked about the working capital with Whiting, that there is no major effect this year. I mean, to the degree that Whiting was down last year, we had to go and purchase stocks. The degree Whiting's up, we're actually running crude so there's no major impact around that.
Great. Thank you.
We'll take a question now from Lydia Rainforth at Barclays.
Thanks, Jess, good afternoon. Two questions, if I could. Firstly, on the Mad Dog project. It was about a year ago that you said you didn't want to continue with the project as it was being developed. Can you give us an update on where we are with that project now and where you're looking to save money? Secondly, if I could just ask a question for Brian on the downstream side and the charge that you took for the Bulwer Refinery. I understand that will be a triggering event, does it make you want to or have to go back to the rest of the refining assets that you have and want to look at what book value you're carrying for those assets? Thank you.
Let me take the second one.
Yeah, go ahead.
Sorry, Bob.
Yeah, go ahead.
The Bulwer one was, I think we're now down to about 12 operated refineries from. I've not looked closely at the, but if I think in my head, about 12 that we've got left and having sold 13 over the last 13 years. Bulwer was a simple question of on the East Coast, the over capacity of refining there, we'd looked to it from a commercial perspective. We'd done various work and decided actually the best option for that refinery was effectively to close it down and convert it to an import terminal for jet fuel. That doesn't have any triggers anywhere else inside the portfolio. I'd actually say we're pretty comfortable now with the refining portfolio we have, two and a half refineries. If you think about the Toledo joint venture in the northern tier of North America, across from the West Coast through to the Midwest.
Our position inside Europe with the German hinterland, Germany and the hinterland, and our refinery in Castellón, and a small part ownership of a South Africa refinery in Kwinana on the West Coast. That's a pretty good advantage portfolio from our perspective. I don't think this will lead to any other further triggers elsewhere inside the portfolio.
With Mad Dog, you're right. That's one of the projects that we looked at that said just wasn't going to compete, wasn't going to cross the hurdle rates for capital in the company. We took a complete white sheet of paper to it again and looked at the economics very creatively and the development concepts for phase 2. We did step back with our partners. It's a spar today with us having just over 60%. Our partners are Chevron and BHP. We all agreed to stop, look at it again. We've been actively engineering it. Our teams, I think, are coming up and looking at some very, very good options. We're going to continue to review that. At the right point, we'll bring it forward as a project. I have no doubt that there's a good economic project there.
I am very pleased that we stopped when we did to look at it again. We're doing that, of course, with all our projects around the world.
That's great. Thank you.
Now Lucas Herrmann from Deutsche.
Jess, thanks very much. Good afternoon, gentlemen. Just two, if I might. Firstly, Brian, can you give us any idea what the cash flow ceded from, or the free cash flow I should say, ceded from the divestments you've announced to date is likely to be, i.e., from the GBP 3 billion of divestment proceeds? Secondly, it's great to see the exploration success, particularly last year. The hopper looks to be improving all the time. Clearly, you can't proceed with everything. Where are you in the context of realizing value or trying to accelerate the realization of value from exploration success and resource that sits there and that may take you quite some time to monetize, if at all? When do we start to see the realization of some of that development or exploration resource?
On that first question, Lucas, no specific guidance in terms of numbers, but nothing like as cash accretive as the GBP 5 billion that was a free cash flow that was sold off. I'm sorry, of operating cash flow that was sold off as part of a GBP 38 billion program. We're talking the hundreds of millions of GBP, not in the billions of GBP in terms of the GBP 3 billion that's been done so far. It's a real mix of different assets. If you recall what we've said about the next tranche, the GBP 10 billion over and above the GBP 38 billion, that some of that will be early life, not cash-accretive assets. You'll start to see some of those probably appear in the portfolio of divestments going forward. It's in the hundreds of millions of GBP, not in the billions of GBP.
Okay. Thanks.
Lucas, on the exploration, you're right. We're sort of now moving into the heartland of the acreage that we've sort of picked up in the new basins over the last several years and still working our way through some earlier exploration obligations. We've had some good success. We'll be participating in 15-20 wells this year. We have discussions often with various companies about the potential of them joining us. Some of it's farming down, some of it's farming in, or carries. That in terms of where they are, I think you'd probably be best to look at where we have exposure on at 100% positions.
Yeah.
I think, we'll just constantly optimize this. I think this is going to be a great source of value for the company.
Okay. Watch this space, in effect?
Yeah. Mm-hmm.
Can I ask one final or one further question, may I? Just going back to Martijn's question. North Sea and specifically the U.K., where is uptime relative to capacity at the present time? I mean, one's impression looking at the numbers, as Martijn alluded to, and I know it's true of the industry, but it seems very true of yourselves, is that your production relative to potential has been, should we just say, very modest over at least the last three or so quarters, if not beyond.
Well, you're absolutely right. I mean, this has been an issue that the North Sea and the operators talk about and the contractors talk about. Uptime is not a whole lot above 50%, not only for the entire industry, we're in that pack as well. We've got some turnarounds this year. I fully expect us to move out of that going forward. Part of the issue is, as turnarounds come around in the industry, the facilities that have been built don't have enough bed space for people to get out there to do some of the maintenance, which affects some of this uptime. It's part of a characteristic of a late-life oil and gas province. I think we're moving through this with our turnarounds, Schiehallion will be reworked. Kinnoull will come on stream.
I can just tell you, this is an area that we spend a lot of time on and a lot of focus on, along with other operators and partners on. It's an issue in the U.K.
Okay.
Yeah.
Well, thank you. Brian, thank you. Jess, thanks.
Thanks, Lucas.
Okay. Thank you. Well now, we've got Jason Kenney on the web with a question. His question is, you have mentioned a GBP 1 billion increase for DD&A between 2013 and 2014 at the group level. Will there be a larger DD&A figure again in 2015? Can you give us an expected delta or trajectory for DD&A in 2015 over 2014?
Jason, I can imagine your dulcet tones reciting there had you been on a phone from Edinburgh. I'll take it as a web one, which is new, I think, for you. I think what we said back in March was we've seen a ramp-up in DD&A as we've looked at investing in some of these high-margin areas. One example is Angola, where you have higher DD&A, but higher margins that come with it. As we now start to get to a more stable level of investment going forward in the upstream with the new projects that we have coming on stream, I think we've already flagged in March that we wouldn't expect to see a similar sort of ramp-up into the future, that we'll start to see some of the DD&A stabilize out from where we are now.
The biggest drivers of that have been the investments, the higher capital against those high-margin investments that return with them higher cash as well.
Okay. Thank you, Brian.
The great thing about an internet question is you don't get a comeback from Jason unless he's very, very fast on the keys.
Back to the telephone lines. We have Thomas Adolff from Credit Suisse. Are you there, Thomas?
I am. Thanks. Two questions, please. Firstly, on FIDs. I think on the last call, you said you expect to take FID on five projects in 2014, one of them in Southeast Asia, and I'm assuming this is the Tangguh expansion. I wondered whether you're confident on the progress you're making there, in particular related to firming up the DMO. At the time, there's a bit of a turmoil at the SKK Migas, and we're also in a presidential elections there. Just one more question, just small ones. You said you made a discovery on Notus. It's an HPHT well. I wondered whether this is in excess of 15,000 PSI. Just a final one on Brazil. You've got the Itaipu and Wahoo discovery. It's been slow. We haven't heard anything. What's going on? Thank you.
Great, Thomas. Thank you. Well, you're right. We've made very good progress on the Tangguh expansion, particularly with signing the gas contracts. I think we're getting the conditions in place for that project on FID. I think we've said five in the past. I'm not sure that that one will be done this year. It may be. I would say there's going to be one in India, one in Angola, Australia, and maybe a Thunder Horse South expansion. As four FIDs is the way I'm thinking right now. We'll see. It's possible. We actually really like that Tangguh expansion. I'm very pleased about the gas agreements. On the Notus well, you're right. It is the deepest well drilled in Egypt. We farmed into it during the drilling with BG as the operator. It's down, it looks very promising. I think it's significant.
We think it certainly can be developed. It's a feasible reservoir in terms of temperature and pressure. We're still evaluating the results, or the operator is, and we're contributing it. It's probably best to speak directly with BG about that. About Itaipu, it is located in the deep water of the Campos in Brazil. We have completed three wells on it. We've got an ongoing evaluation. It's right near another development that appears to be part of the Petrobras area as well. In Wahoo, we're continuing to evaluate that.
What I would expect down the road here is that there will be some sort of economic unitization of that area, with some of the activities of Petrobras, we're still evaluating, looking at it, as everyone knows, unitization and knowing how much is on one side of a line versus another is going to take a little bit of while. We can't really comment on it.
Okay. Can I just quickly go back to Tangguh again? Can I just clarify that you firmed up the DMOs, and if so, how much of the volumes do you need to sell to the domestic market? I was under the impression that's the uncertainty still.
Well, I think we've made commitments of 40% into the domestic market. I think we've got sort of all but one of the gas contracts in place. Because those discussions are going on, I probably shouldn't comment on it further.
Okay. Thank you.
Great. Thank you, Thomas. A question now from Michele Della Vigna at Goldman Sachs.
Good afternoon. Thank you for taking my question. You've now pretty much completed the $8 billion buyback, and you did it at a rate of more or less $2 billion per quarter. I was thinking, as you now enter the kind of stage 2 for the buyback, whether we should expect it to be at a slower pace or perhaps a bit more lumpy as you wait for the proceeds from disposals to come in before doing the buybacks.
Thanks, Michele. We haven't really given any indication. All we've said so far is that we will look to use the bulk of the $10 billion of post-tax proceeds predominantly for shareholder distributions or predominantly buybacks. That's really a commercial decision that we'll take internally in terms of as those cash proceeds arrive. It sits within the financial frame. It looks at how the capital flows out. You should assume that we will attempt to try and keep the continuity of the buyback program, so you don't see a sudden stop to it. That's why you are seeing it phase down more recently. We'll also look at the round of the general environmental outlook in the marketplace as to how we go ahead and reduce that equity base.
The basic premise is that we've shrunk our equity in terms of the amount of assets we've sold off, therefore, it's commensurate that we should look to shrink the share base. We'll look to do that. I think what we've said is over 2014 and 2015, you should expect to see that share base come down by a commensurate amount.
Thank you.
We'll take a question next from Bertrand Hodée of Raymond James.
Yes. Hello. I have two questions. First one is a follow-up on Bob's comment in terms of upstream cash costs being down, probably down 1% in 2014 compared to 2013. Do you refer to total cash costs or unit cash costs? Because if it's total cash costs down 1%, I suppose that unit cash costs should be down more than 1%, given that probably your underlying group production is going to be higher in 2014 compared to 2013. The second question is, in Angola, you are targeting one FID this year. Is it going to be Block 31 or Block 18?
Bertrand, I'll take the first question on cash cost. It's total cash costs. Of course, in terms of unitary cash costs, you'd also have to allow for the change around the Abu Dhabi concession in your volumes, the disposal volumes. It's actually a box balance question that we've not given that to the level of disclosure. In terms of total cash cost terms, you should expect those to be down.
Yeah. Can I follow up on that? Abu Dhabi was equity accounted, so I guess it is not included in the calculation?
Well, it depends how you do the calculation. In terms of the volumes, the Abu Dhabi volumes would have been there last year for you to unitize. You would have carried those volumes inside the unitization. All I'm saying is there's lots of moving parts, but on a total basis, they'll trend down.
Okay.
Bertrand, on your question about Angola, I'm going to be a little cryptic, and I'm going to say it's not Block 18 or 31, but it's a Total project.
Okay.
Okay. Mm-hmm.
Thank you.
Thanks, Bertrand. Last but not least, Fred Lucas from JPMorgan .
Thanks, Jess. The exploration performance in Angola is going very well, the performance of your LNG asset there is not. Could you just give us an update on what the problems are with that asset? I appreciate you don't operate it. Second question on gas prices in India, could you give an update on the situation there given the deferral to the gas price increase that was tabled? Thank you.
Fred. I think all the partners and the government of Angola had higher hopes for the LNG project there. We don't operate it. I think this has been a constant set of ironing out the cold end and the hot end of the LNG plant there, and that they continue to understand the engineering and get that plant going. We anticipate that this will be back on and up and running within a couple of quarters here. I can't really give you too much more of the details around what exactly the engineering issue is there.
It's out for a couple of quarters, is it, Bob?
It started up, then it was back down again. You should actually speak to the operator about what the date is. That's always better to do than talking to partners. I think if I could refer you to the operator. Then on India, we have not got large volumes included in our projections this year in terms of volumes from it. In terms of India, there was, I think, a positive step towards a market-determined gas price estimated around GBP 8 an Mcf, that was to be adjusted quarterly. It has been deferred pending the outcome of the election in India, which is the largest and longest democratic election in the world. 750 or 850 million people vote over a period of weeks, which will be completed on the 16th of May.
The decision by the government was, don't change that price in the middle of the elections because it, and a number of things, didn't want to turn it into an issue that could become political. We do remain confident that the new gas price formula will be implemented. All indications are that it will be set retrospectively from the 1st of April 2014. I believe the energy minister has said that contracts that are being signed and gas volumes that have gone out since April are being written and designed so that the price will retroactively be effective on the 1st of April. Those elections are going to go on. They're going to go on for another two and a half weeks. Let's just not interfere in any way.
Thank you, Bob.
If I may just slip in a third one. BG's looking for a new CEO. Do you have any interest in extending your remit?
I'll answer that question on Bob's behalf. We're very happy with him as the CEO of BP. Thanks very much, Fred.
Thank you.
BG.
Yeah, I have enough to do. Thank you.
Okay. Well, thank you everybody. It was good to have you on the call. I know it's a busy week for you.
Yes. Thank you, everyone. Your questions, as always, are very good and broad. Some of them detailed and some of them very big picture. I hope what we're showing you is we're pursuing and have been pursuing the value over volume point. The objective, continue to grow sustainable free cash flow, continue on the operating cash flow targets we have this year, so that we can continue to grow our distributions to the shareholders. You'll see us continue to actively manage the portfolio, have the discipline on our capital spending, and I think the team is doing a very good job of executing safely and reliably, and our efficiency has really come up since 2011. Thank you all very much for your attention today.