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, and welcome, everyone. This is BP's 4th quarter and full year 2013 results webcast and conference call. I'm Jessica Mitchell, BP's Head of Investor Relations. I'm here with our Group Chief Executive, Bob Dudley and our Chief Financial Officer, Brian Gilberry. 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. And now over to Bob.
Thank you, Jess, and welcome everyone wherever you are in the world. Thanks for joining us today. We're here to look back at 2013. It was a busy year and also a successful one. We accomplished a number of important things.
We improved our safety record. We had a very good year for exploration, in fact our best in 10 years. We started up a series of major new projects, both in the upstream and the downstream. In Russia, we created a new future for BP and at the same time we released some of the considerable value we generated with our former joint venture TNKBP. A large part of that is currently used for buybacks, a good outcome all around.
And we also announced some significant new investments for the future that we believe will create value for BP for decades to come. In particular, these included the huge Chardanese II natural gas project in Azerbaijan with the associated pipelines stretching well into Europe and also the giant Kazan project in Oman. We also increased the dividend by 11% in dollars compared to 2012. We are not complacent, but we are pleased with the progress. These are all important milestones on the way to delivering our 10 point plan and these will all contribute to sustainable growth and free cash flow in the years ahead.
What you can see now is a company that has a more focused and stronger portfolio, leading positions in exploration, deepwater and Giant Fields and a quality downstream business. And we will continue to play to these strengths. We will do this through disciplined capital investment in a high quality upstream project pipeline and a downstream that is a strong generator of cash for the group. And we will do all this while maintaining a relentless focus on safety and reducing operational risk. So turning to today's agenda, we'll start with a summary of our full year results and then look at progress against the 10 Point Plan.
Brian will take you through the details of our results for the Q4. Then I will update you on our safety performance, Ross Neff's progress, legal proceedings in the U. S. And our ongoing work in the upstream and downstream. And then we will take your questions.
So let's begin with an overview of our full year 2013 results. Our underlying replacement cost profit was $13,400,000,000 Post tax operating cash flow was $21,100,000,000 Our organic capital expenditure was $24,600,000,000 in line with our guidance and we divested $17,100,000,000 of assets during the year. Our gearing at the end of the year was 16.2%, which is within our target band of 10% to 20%. We distributed $5,400,000,000 in cash to shareholders through dividends and we also bought back $5,500,000,000 of our own shares. These results reflect a number of different factors.
Among them are the restructuring of our portfolio through divestments, a weaker environment in the downstream, large working capital bills and the increased exploration write offs, which have accompanied our ramp up in exploration drilling. That said, it has also been a year of strong results in our underlying operations, which I will come back to in a short while. We are confident that the full financial momentum from this progress will become clearly evident in 2014 and beyond. To reinforce that point, let me give you another figure. Our reserves replacement ratio for 2013 was 129%, excluding the impact of acquisitions and divestments.
If we include the net reserves growth as a result of the repositioning in Russia, the reserves replacement ratio was 199%. I believe this result is a strong indicator of the growing short term and long term momentum in our business as we pull through the drivers of long term growth. Let me update you a little more on some important milestones. As many of you will recall, our 10 point plan consisted of things you could expect and things you could measure and 2013 has set us up well to deliver. The first commitment was to continue to make safety the top priority and we're seeing positive results as you can see in a moment.
We also said we'd build a stronger portfolio and simplify the company while playing to our strengths from exploration to high quality downstream businesses. And we have delivered on that commitment. We have completed the $38,000,000,000 divestment program outlined to you in 2011 and we are now a smaller but much more focused company. The divestments have removed complexity, strengthened the balance sheet and left us with more distinctive set of assets. And with our 3rd quarter results, we announced our intention to divest a further $10,000,000,000 of assets before the end of 2015.
This will further focus the portfolio and provide additional free cash flow from which we plan to increase distributions to shareholders, primarily through buybacks. The successful completion of the transactions associated with TNKBP and Rosneft demonstrated our ability to turn a major challenge into a unique opportunity. It also makes us a 3,200,000 barrel per day oil company when adding our interest in Rossnap to BP zone production. While reshaping the portfolio, we also continue to deliver some significant portfolio and also made 7 potentially commercial discoveries in 2013 in Angola, Brazil, Egypt, the Gulf of Mexico and India. We also saw a series of high value upstream projects come online.
During 2013, 3 more projects started up following the 5 we started up in 2012. These included the first phase of the BP operated Atlantis North expansion in the Gulf of Mexico and 2 more partner operated assets, the Angola LNG plant and North Rankin II in Australia. And I'm pleased to be able to tell you today that the Sharag oil project in Azerbaijan came online last week and Mars B in the Gulf of Mexico, another oil project has come online today. In the downstream, we announced last month that all the major units associated with the Whiting Refinery Modernization Project have been brought on stream. We continue to expect the reconfigured refinery to deliver an incremental $1,000,000,000 of operating cash flow per year depending on the environment.
So as we end the year, the track record of delivery continues to build. We have a much stronger balance sheet and we are confident of delivering our important goal for 2014, to increase operating cash flow by 50% between 2011 2014 assuming $100 oil. It is this confidence that enabled us to increase our dividend with our 3rd quarter results in line with our progressive dividend policy. On the 4th March, we will tell you more about our future plans. We will show you how we plan to continue playing to our strengths to drive material growth in operating cash flow, coupled with our focus on capital discipline.
We expect this to drive continued growth in free cash flow, enhancing our ability to increase distributions to shareholders. Let me now hand over to Brian to take you through the results for the Q4.
Thanks, Bob. BP's 4th quarter underlying replacement cost profit was $2,800,000,000 down 27% on the same period a year ago and 24% lower than the 3rd quarter. Compared to the Q4 of 2012, the result reflected higher non cash costs, including exploration write offs and DD and A, a significantly weaker refining environment and significant divestment impacts, partly offset by improved underlying upstream production in high margin regions and stronger earnings from Rosneft compared to TNKBP in the same period in 2012. 4th quarter operating cash flow was $5,400,000,000 The 4th quarter dividend payable in the Q1 of 2014 is $0.095 per ordinary share, up 5.6% compared to the same period last year. Turning to the highlights at a segment level.
The upstream underlying 4th quarter replacement cost profit before interest and tax of $3,900,000,000 compares with $4,400,000,000 a year ago and $4,400,000,000 in the Q3 of 2013. Compared to the Q4 of 2012, the result reflects higher non cash costs, including exploration write offs associated with increased exploration activity and higher DD and A along with some sector inflation. Lower production due to previously announced divestments, primarily in the North Sea and the Gulf of Mexico and lower liquids realizations, partly offset by improved underlying volumes in high margin regions, a one off benefit to production taxes, stronger gas marketing and trading results and higher gas realizations. 4th quarter reported production excluding Russia was 1.9% lower than a year ago, primarily due to the impacts of divestments. On an underlying basis, after adjusting for divestments and entitlement effects, production increased by 3.7%, partly reflecting new major project volumes in the North Sea, Angola and the Gulf of Mexico.
Compared to the Q3, the result reflects higher costs, partly due to the exploration write offs, absence of the one off benefit in the Q3 related to the TransAlaska pipeline system and lower liquids realizations, partly offset by improved underlying volumes in high margin regions, a one off benefit to production taxes and higher gas realizations outside of North America. Looking ahead to the outlook for the Q1, we expect reported Q1 production to be lower than the Q4 of last year, reflecting the impact of divestments and the expiry in January of the Abu Dhabi onshore concession. Turning to Russia. This slide shows our share of earnings from Rosneft and historically from TNK BP. BP's underlying net income related to its Rosneft shareholding was $1,100,000,000 in the 4th quarter.
This compares to BP's share of TNKBP net income in the Q4 of last year of $220,000,000 which included only 21 days of earnings. Compared to the Q3, underlying net income was up $270,000,000 The 4th quarter was favorably impacted by the finalization of BP's equity accounting for the year and include certain adjustments to net income in respect of prior quarters. These effects are partially offset by adverse foreign exchange and duty lag effects and by lower realizations. BP's share of Rosneft production in the Q4 was 985,000 barrels of oil equivalent per day, 20,000 barrels per day higher than the previous quarter. In the Downstream, the 4th quarter underlying replacement cost profit before interest and tax was $17,000,000 compared with $1,400,000,000 a year ago and $720,000,000 in the 3rd quarter.
The result included a loss of $200,000,000 in the fuels business compared with $1,000,000,000 profit in the same quarter of last year. This reflected a significantly weaker refining environment, the absence of earnings from divested Texas City and Carson Refineries and the weak result from our supply and trading activity, and additional depreciation and start up costs as a result of the Whiting Refinery Modernization Project. This was partly offset by strong refining availability and lower turnaround activity. The lubricants business reported an underlying replacement cost profit before interest and tax of $230,000,000 compared with $330,000,000 in the same quarter last year. This reflects restructuring charges as we seek to improve the competitiveness of our mature European businesses.
The petrochemicals business reported an underlying replacement cost profit before interest and tax of $40,000,000 broadly flat compared to the same period last year. Results were impacted by the environment, which continues to be challenging with excess supply in Asia and the United States, partly offset by lower turnaround activity. Looking forward to 2014, we expect refining margins to improve from the levels seen in the 4th quarter. But in general we expect the fuels and petrochemicals environments to remain challenging. We also expect an increased exposure to heavy crude differentials in the United States as we ramp up heavy crude processing at the Whiting refinery.
In other business and corporate, the pretax underlying replacement cost charge was $610,000,000 for the 4th quarter, an increase of $170,000,000 on the same period a year ago. The 4th quarter results included certain one off charges compared to one off benefits that occurred in the same period a year ago. The full year charge of $1,900,000,000 was within guidance levels and $100,000,000 lower than the previous year due to lower corporate and functional costs. The effective tax rate on underlying replacement cost profit for the 4th quarter was 24.3%. This is lower than the 3rd quarter reflecting higher income from Rosneft, which is reported net of tax and a number of one off favorable fiscal settlements in several jurisdictions related to previous years.
The full year effective tax rate on an underlying replacement cost profit was 35.4%, slightly below our guidance range for 2013. The charge for the Gulf of Mexico oil spill was $190,000,000 in the 4th quarter, primarily reflecting an increase in the provision for legal costs plus the ongoing cost of running the Gulf Coast restoration organization. This brings the full year charge to $470,000,000 The total cumulative net charge for the incident to date is now $42,700,000,000 The charge does not include any provision for business economic loss claims that are yet to be paid. Bob will provide an update on the legal process shortly, but as we advised at the Q3, 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 pretax cash outflow on costs related to the oil spill for the full year was $1,400,000,000 The cumulative amount estimated to be paid from the trust fund remained at $19,300,000,000 leaving unallocated headroom available in the trust for further expenditures of around $700,000,000 In the event that the headroom is fully utilized, subsequent additional costs will be charged to the income statement. At the end of the year, the aggregate remaining cash balances in the trust and qualified settlement funds was $6,700,000,000 with $20,000,000,000 paid in and $13,300,000,000 paid out. And as indicated in previous quarters, we continue to believe that BP was not grossly negligent and have taken the charge against income on that basis. Now turning to divestments. Our $38,000,000,000 divestment program is now complete.
And in the Q1, we also completed the sale of our share of TNKB Peter Rosneft for $27,500,000,000 Following the receipt of cash proceeds of around $12,000,000,000 from the TNKBP transaction, we also announced the share buyback program of up to $8,000,000,000 To date, dollars 6,800,000,000 of shares have been repurchased for cancellation, of which $5,500,000,000 were repurchased in 2013. In October, we announced plans to divest an additional $10,000,000,000 of assets by the end of 2015 and to use the post tax proceeds predominantly for shareholder distributions with a bias to share buybacks. So far, we have agreed around $1,700,000,000 of additional divestments. Now looking at our full year cash flow movements, this slide compares our sources and uses of cash in 20122013. Operating cash flow for 2013 was $21,100,000,000 which includes $1,400,000,000 of pre tax expenditure related to the Gulf of Mexico oil spill.
Excluding these costs, underlying cash flows of $22,500,000,000 were also impacted by a net working capital build of around $5,000,000,000 Compared to 2012, a higher working capital build and the impacts of divestments offset the benefits of strong underlying volume growth from the ramp up of major projects and improved operating efficiency in the upstream business. In the Q4, we received $400,000,000 of divestment proceeds, bringing the total for the year to $17,100,000,000 including the net cash received from the divestment of our share in TNKBP. Full year organic capital expenditure was $24,600,000,000 of which $7,100,000,000 was in the 4th quarter. Net debt at year end was $25,200,000,000 with gearing of 16.2% compared to 18.7% a year ago. Our intention remains to keep gearing in a target band of 10% to 20%, while uncertainties remain.
Turning to our forward looking guidance for 2014. The Abu Dhabi onshore concession expiry has an impact on production of around 140,000 barrels of oil equivalent per day. Adjusting for this and the impacts of divestments, we expect full year underlying production in 2014 to increase compared with 2013 with reported production being lower due to these effects. The actual reported outcome will depend on the exact timing of project start ups, divestments, OPEC quotas and entitlement impacts. Organic capital expenditure in 2013 was $24,600,000,000 and as previously indicated, we expect 2014 capital expenditure to be between $24,000,000,000 $25,000,000,000 The DD and A charge was $13,500,000,000 in 20.13 and is expected to be around $1,000,000,000 higher in 2014 as production on new projects ramp up.
In other business and corporate, the average underlying quarterly charge is expected to be in the range of $400,000,000 to $500,000,000 although this may fluctuate between individual quarters. The effective tax rate for 2014 is expected to be around 35%. We will provide updated rules of thumb for 2014 on our website later this month. Before I hand you back to Bob, I'd like to summarize our overall financial framework. We expect the combination of continued operating cash flow growth and capital discipline to enable us to grow sustainable free cash flow underpinning progressive dividend growth into the future.
We expect to deliver operating cash flow of $30,000,000,000 to $31,000,000,000 in 2014 with continued material growth thereafter. 2014 capital expenditure is expected to remain at a similar level to 2013 between $24,000,000,000 $25,000,000,000 Beyond 2014, we expect annual capital expenditure to be in the range of $24,000,000,000 to $27,000,000,000 through to the end of the decade. We will continue to actively manage our portfolio. As previously announced, we plan to divest a further $10,000,000,000 of assets before the end of 2015 using post tax proceeds predominantly for distributions with a bias to share buybacks. And finally, we intend to keep gearing within the 10% to 20% band whilst uncertainties remain.
Now let me hand you back to Bob.
Thank you, Brian. So now I want to walk you through some of the important details of our 2013 performance and I'll start with safety. These charts show an encouraging trend, what I believe reflects the disciplined approach we're taking to our operations around the globe. Looking first at losses of primary containment, which records even very small releases, in 2012 when adjusted for divestments continuing a multi year improvement. We also track process safety events.
The American Petroleum Institute recommended industry metric. In 2013, we saw a 47% reduction in the most serious incidents known as Tier 1 events versus 2012, again adjusted for divestments. We also continue to focus on personal safety and our recordable injury frequency rate remains at levels comparable to or better than industry benchmarks. Safety is at the heart of BP and it is good business. We are pleased with this progress, but by no means do we take it for granted.
Let's move on to our investment in Russia. Rosneft has now completed the initial integration of TNKBP and laid out its strategy for the enlarged company identifying significant synergies and benefits. Momentum continues to build across Rossnath generally. In 2013, they signed a number of binding agreements for joint ventures and projects with IOC Partners. These included unconventional development projects and also Arctic exploration.
JV operating companies were established and significant quantities of 2 d and 3 d seismic were acquired. Ross Neff also continued its program of modernization in its downstream business, including upgrades at a number of refineries enabling them to produce premium grade fuels. Ross Neff continued to deliver on their gas strategy as Russia's and fiscal landscape evolves. This has included the removal of Gazprom's official monopoly on LNG exports. In this area, Rosneft made a number of acquisitions and also finalized a number of long term LNG supply agreements.
The changes to the fiscal terms in Russia have also increased the attractiveness of other opportunities within Rosneft's portfolio. So in summary, it was a significant year for BP in Russia and also for Rossneft. Our unique in Russia not only makes BP a 3,200,000 barrel a day business, it also adds an additional 840,000,000 barrels of oil equivalent to our proved reserve base and opens the way for us to benefit from to our proved reserve base and opens the way for us to benefit from all of the achievements and progress that Rosneft delivers. More widely, the relationship we have with Rossnept is growing and we believe it will have significant long term benefits for both Rossnept and BP. Now let me give you an update on the status of certain Gulf of Mexico related legal proceedings in the United States.
The first phase of the MDL-two thousand one hundred and seventy nine trial in New Orleans focused on the causes of the accident and the allocation of fault among the defendants. The second phase covered source control and the quantity of oil spilled. Both phases are now complete with the court yet to rule on either. While the final decision rests with the court, we continue to believe that the evidence in Phase 1 show that the accident was a result of multiple causes involving multiple parties and that BP was not grossly negligent. We believe that Phase 2 of the trial demonstrated that BP substantially overstated.
The penalty phase in which the court will hear evidence regarding the penalty factors set out in the Clean Water Act has not yet been scheduled for trial. The U. S. Government, BP and Anadarko will be parties in this phase. Turning to the settlement with the plaintiff steering committee and the issues involving business economic loss or BEL claims.
As you know, we have been contesting the payment of claims, which we believe to be unfounded. BP has been successful in challenging administrator's interpretation of the BEL framework with a panel of the U. S. 5th Circuit Court. The panel reversed the interpretation.
The district court subsequently agreed that revenues and expenses must be properly matched, but failed to correct the practice of issuing awards to claimants whose losses are not traceable to the spill. BP has again appealed to the same panel requesting a permanent injunction to prevent such improper awards. This panel has agreed to consider these causation issues on an expedited basis. In the meantime, a temporary injunction remains in place for all BEL claims. In a related development, on the 10th January, a different panel of judges from the 5th Circuit upheld the validity of the settlement as written.
However, it left to the BEL panel the question of how to interpret the agreement, including the meaning of the causation requirements I just mentioned. BP has filed a petition for rehearing of the decision. Separately, former federal Judge Louis Freeh's independent investigation of the claims facility continues and we recently received his second written report that describes some of the behavior at the claims program that led to the resignations of senior staff members. We continue to hope that Judge Free's investigation will lead to steps that ensure public confidence in the integrity of the claims process. And while we continue to pursue litigation challenging the EPA suspension and debarment decisions, we are also continuing to work towards an administrative agreement to resolve these issues.
And finally, I should mention another case, MDL-two thousand one hundred and eighty five. This is a coordinated proceeding pending in federal court in Texas and includes a purported class action on behalf of the American Depository Shares or ADS purchasers under U. S. Federal Securities Law. Following the court's initial rejection of a motion to certify a class.
A jury trial on this action is scheduled to begin in October 2014. In summary, we remain determined to pursue fair outcomes in all these proceedings. Importantly, we continue to compartmentalize these activities to avoid distraction and BP's operating teams remain clearly focused on delivering our strategy. Moving on, let me update you on what we've done in our upstream. It was an outstanding year for exploration, one which really showed the impact of playing to our strengths.
In total, we participated in 7 potentially commercial discoveries across India, Egypt, Angola, Brazil and the Gulf of Mexico, making 2013 the most successful year for exploration drilling for almost a decade. This reflected the increased investment we have made in finding oil and gas, with 17 exploration wells being completed around the world in 2013 and between 201520 planned for 2014. The Elantra oil and gas discovery in the presalt layer in offshore Angola announced by our partners Cobalt in October was followed by a successful drill stem test in December, demonstrating the excellent quality of the reservoir. The Petrobras operated pitu well was confirmed as a discovery in December. This is a successful test of a new play in Brazil's frontier deepwater.
And also in December, we announced the discovery of the BP operated Gila well in the Deepwater Gulf of Mexico. The Gila discovery was drilled in approximately 4,900 feet of water at a total depth of over 29,000 feet and is BP's 3rd operated discovery in the Paleogene. Moving on to new operations, 3 projects were brought online in 2013: the Angola LNG project, the first phase of the Atlantis North expansion and the North Rankin Phase 2 project. And I've already mentioned the start of the Sharag oil project in Azerbaijan and the Mars B project in the Gulf of Mexico both of which came online in the last week. We are also on track to deliver 4 further major project startups in 2014: the Nikita Phase 3 in the Gulf of Mexico, Canoole in the North Sea, CLOV in Angola and Sunrise Phase 1 in Canada.
Across the portfolio, we continue to maintain on the safe, reliable execution of activities. In 2013, we achieved a BP operated plant efficiency of 88%, which was a significant improvement over 2012 and we expect this improving trend to continue as we move through 2014. We successfully completed 20 planned turnarounds, including 12 in our key assets. This represents a reduced level of activity compared to 2011 2012. Looking forward, we intend to continue to invest in the reliability of our assets with a steady state multiyear program, which we expect to require a continued lower level of turnaround activity than in recent years.
At the start of the year, we identified 15 wells in key locations as the top wells for production delivery. All of these were successfully drilled by the end of the year with 2 remaining to be completed by the end of this month. Delivery of production from new wells in 2013 increased compared to 2012, particularly from some of our key regions such as Azerbaijan and the North Sea. We expect to continue this trend of improving well delivery with production from new wells in 2014 forecast to be higher than in 2013. Now let me update you in more detail on our major projects.
Our recent key startups continue to ramp up their production. For example, PSVM in Angola, which started at the end of 2012, reached plateau production of 150,000 barrels of oil per day. In delivering this, our Angola team has started up all four fields that make up the asset and achieved a 1st year plant efficiency of 91%. The Chirag Oil and Mars B projects that started up this year represent major new infrastructure developments in significant established oil fields in 2 of our key regions. Facilities completion on the next four start ups in 2014 now exceeds 75%.
During the Q4, we reached several key milestones towards the delivery of these projects. On the Quica Phase 3 in the Gulf of Mexico, we completed the subsea construction and drilled 2 wells with completion now underway and expect well start up in the Q1. We also began commissioning of Canoole in the North Sea. While on Sunrise Phase 1 in Canada, the initial 55 well pairs were completed ahead of schedule. Most recently, the Clove FPSO left the Pinal Shipyard in Angola on the 20th January to start the offshore hookup and commissioning campaign.
Our 2012 to 2014 startups bring high margin production online and will on average deliver twice the operating cash margin of the upstream portfolio that we held in 2011. Looking to our next wave of developments, we sanctioned 2 significant projects in the Q4 of 2013, which we expect to deliver value for BP for decades to come. Chardanese Stage 2 and its associated southern corridor pipelines will develop the next phase of this gas field in the Caspian, connecting it directly to European markets. 16,000,000,000 cubic meters per year of natural gas will be carried some 3,500 kilometers to Georgia, Turkey, Greece, Bulgaria and Italy, while condensate production will increase from 55,000 to 120,000 barrels per day. Meanwhile, our Kazan project in Oman will see some 300 wells drilled over 15 years delivering 10 BCMA of gas, which is equivalent to around of a third of Oman's total daily gas supply, ensuring continued stable supplies from domestic sources.
So in summary, this has been a significant year of building momentum in the upstream. We continue to deliver results across access and exploration, projects, wells and operations. We have after adjusting for divestments delivered underlying production growth in every quarter of 2013 when compared to 2012. This has been driven by improving execution of activity through our functional model and a relentless focus on safe and reliable delivery. Now turning to the downstream.
In 2013, there were continuing improvements in safety and reliability as well as delivering several significant milestones. The number of Tier 1 safety events decreased and the business achieved a steady decrease in losses of primary containment and recordable injury frequency. Solomon refining availability was 95.6 for the 4th quarter, which is the highest level for BP since 2004. In 2013, we met several important milestones, primarily focused on the repositioning of our U. S.
Fuels business. We completed the commissioning of all major units for the Whiting Refinery Monetization Project, finalized the sales of the Texas City and Carson refineries and started up new units at the Toledo and Cherry Point refineries. We expect these changes to enhance the safety, margin capture and operating efficiency of our U. S. Fuels business and in turn to provide significant cash generation for the group.
Our lubricants business continues to be an important source of revenue growth and returns for the group as it implements its strategy of investment in technology, exposure to growth markets, distinctive global brands and targeted marketing programs. We're also beginning to implement a program of transformation to improve competitiveness across our mature European businesses. In January, we announced our decision to sell our Specialist Global Aviation Turbine Oils business. After a careful review of our portfolio, we decided the business would offer more opportunities for other companies wanting to invest in this particular sector. In petrochemicals, we continued construction of a third PTA plant at Zhuhai in the Guangdong province of China, which is on track for completion in late 2014.
In addition to Zhuhai, we are also retrofitting our existing facilities with our latest PTA technology to improve cost efficiency. We also announced 2 new breakthrough petrochemical technologies in 2013, SABRE and Hummingbird, which we expect to radically improve the cost of manufacturing the petrochemical feedstocks of acetic acid and the conversion of ethanol to ethylene respectively. Looking to the future, our focus in the downstream is to leverage our newly upgraded assets, customer relationships and leading technologies to generate material and growing free cash flow for the group. In 2014, our capital investments are focused on safety, efficiency and growth markets and aimed at enhancing our advantaged portfolio of assets. So I would like to close by summarizing what we've achieved and looked at 2014 and beyond.
We have talked today about the milestones passed in 2013. These and other recent achievements form the foundations for delivering value into the long term. Our aim is to grow sustainable free cash flow as we continue to build and operate a high quality portfolio in which we prioritize value over volume. And I think that value is very much the goal to focus on in today's environment. It doesn't look like an easy sector right now, but I believe that you can succeed if you do the right things well.
It means continuously reloading our pipeline of opportunities through exploration success. It means making the right investment choices. It means sticking to the capital limits we have set, and it means excellent execution of only the best projects. At the same time, we will continue to actively manage our portfolio to ensure we are playing to our strengths and divesting assets, which are not core to delivering long term value. And we will always make safety and reliability the top priority in all we do.
We are confident that our hard work this year keeps us on track to deliver our commitment to growth and operating cash flow in 2014 and beyond. We are strongly committed to our progressive dividend policy and we look to use surplus cash to enhance distribution to shareholders. We look forward to telling you more about what the journey ahead looks like on the 4th March. That's the end of our remarks. And now Brian, Jess and I will be happy to take your questions.
Right. The first question then comes from Oswald Clint at Sanford Bernstein. Go ahead, Oswald. Hello, Oswald, are you there?
Yes. Thank you. Sorry. Thank you very much. First question, Bob, I was looking at the U.
S. ARCO per barrel and how it has stepped up the past two quarters sort of into the mid teens per barrel. Obviously, it's a business that's had quite a range of ARCCOP per barrel. So I wanted to get some thoughts on where you think that number might actually get to over the next 12 months and obviously the next couple of years please? And then secondly, I was interested in your comments on the most successful exploration year in a decade.
Is there anything you can point to that may have helped deliver that success? And is it possible to give any sense of materiality or some volumes around the discoveries you had last year? Thank you.
Oswald, great. Thank you. I'll comment on the U. S. ARCOK per barrel numbers and then Brian can add a little bit more to it and then some comments on exploration.
Clearly, it's getting back to work in the Gulf of Mexico for us with 10 rigs running. We're not giving the exact figures, but we did produce more than 200,000 barrels a day during the quarter and an exit rate as well at 200,000 in the 4th quarter. So we've got that. We've got an improved natural gas prices as well that have affected the industry and both would be a mix. You want to add?
Yes. No, I think that's the big part of it Bob. And it's actually to run the balance of Gulf Mexico barrels coming in with the Lantus major project coming online and turnaround around Thunder Horse and it's actually lower oil realizations versus high gas realizations. So they were the big drivers. And as more gone barrels come on with the lower production taxes, hence that you'll start to set number trajectory up.
Yes. We expect that out of these 4 big hubs out into the decade. On exploration success, I think it has been a really good year. The 3 wells there just at the very end of the year, the Loncher well in Angola did a drill stem test in December. A lot of these we can't really comment on materiality or size because we have partners and governments and regulators that we need to work through.
But I'm very encouraged about Angola. And we're drilling another well in the block. In fact, it's going down now. And in India, I think the size of those India is a country that needs every molecule of gas it can get. 1 of the discoveries was underneath the D6 field down deep.
That looks sizable facilities there. So that's good. And then in Brazil, I think the most significant thing in the pitu well in Brazil is it's proved up the equatorial margin a whole new basin in area. So that's got some really good significance. And Gila discovery in the Gulf of Mexico, that's another one in the Paleogene formation.
It looks very, very promising. It's in 4,900 feet of water and drilled to 29,000 feet, one of our deepest wells. And then Egypt as well is a country who has been exporting gas needs all the gas it can get. And the Salomat well, which is 100% BP is 1 that looks promising. And then we've drilled drilling another one now at BG that looks promising.
So I could I can't give you the numbers. I know you like the figures, but there's just some color around
That's helpful. Thank you very much.
Right. Next question from Alejandro Demicalis, Exane.
Yes. Good afternoon, gentlemen and Jessica. A couple of questions from my side. In terms of the new start up for 2014, plastic whitening and refinery, how much cash flow do you think you can generate from those new projects in order to get you to the $30,000,000,000 $31,000,000,000 target on cash flow? That's the first question.
2nd question is, Bob, you mentioned the Gulf of Mexico having a very good exit rate for this year. What do you think you can get over the next couple of years in the Gulf of Mexico?
Okay. Alejandro, I'll start with the last one first. I mean, over time, we expect to get over 3 100,000 barrels a day in the Gulf of Mexico. In terms of sort of where it's going to be this year, next year, depends on the state of turnarounds and we do have some turnarounds coming up. We've got 3 of them in the Gulf.
So but I'm very optimistic about where we're heading in the Gulf with those 4 big hubs. And roughly 80% of our reserve base that we have in the resource base around in the Gulf is around those 4 big hubs. So it's obviously a great area of focus for us. On the amount of cash flow contributed by the 4 startups in 2014, we're not going to give you a number on that, but the confidence should come with the fact that we've started out 4 major projects in 2013. So we'll get the run rates through into 2014 on that and we've got 2 projects that started up this week with the Chirag oil platform and the Mars B oil project in the Gulf of Mexico and oil really is the high margin commodity here that we have more and more of coming on.
So Brian, do you want to add anything?
Yes. No, I mean I think Bob that's the bulk of it. And then there's obviously the mix of barrels as we move more high margin barrels in the base come through that will also help support the $30,000,000,000 to $31,000,000,000 this year.
And in terms of widening?
Yes. Whiting right now all the units commissioned and we're ramping up. So we'll continue to ramp up. I mean it's a lot. If you think at its peak, it can run up to 380,000 barrels a day of heavy crude.
That's going to take some time to ramp up as we bring all of those units on. So we'll give you more updates on that as the year progresses.
Perfect. Thank you.
Thanks Alejandro.
Okay. Over to the U. S, we'll take a question from Blake Fernandez at Howard Weil.
Hi, folks. Good afternoon. I had two questions for you. For 1 on the Downstream, the results were a little below what we would have thought. And I know you mentioned higher DD and A and you give us guidance of an incremental $1,000,000,000 of DD and A in the $14,000,000 I was hoping maybe you could give us some color around how much of that is associated with the upstream and the downstream?
And then the second question is back on Lantra. I know the fiscal terms do not accommodate for gas sales. And from what I understand, there is a gas component to that discovery. I was hoping you could maybe give us an update of negotiations with the government to renegotiate the terms there. Thanks.
Okay. Brian, maybe you can comment on the DD and A and I'll come back to it, Elantra.
Yes. Hal, we don't normally give details on DD and A by the segments. Whiting will be a modest increase in DD and A as we look to depreciate that asset over time now it's being commissioned. I think the depreciation schedule is something like 30 years is what we've agreed. So it won't have a huge impact.
But nevertheless, it does impact 4Q as we've commissioned the asset. Some of the costs that came through in 4Q in the downstream were also around some restructuring charges, rat ex effectively which comes through as a normal charge, specifically in the lubricants businesses and more broadly. And also we had a weak supply and trading quarter. Although we had a good supply and trading year both in oil and gas for 2013, it was actually weak 4Q for the oil trading and supply business. So that was probably what they were the biggest components of the mix.
And the upstream DD and A is also due to the new projects that are coming on stream. We've had a number of the big ones come on in 2013. And on Elantra, our partners there are Cobalt. So really they are discussing and negotiating with the country. I'll just note.
I'll give you color rather than specifics on this. You are right. The gas is under the contracts in Angola are property of the government. However, this is a very promising oil gas condensate field that is not too far from the shore and Angola needs done. And the discussions are related to increasing power because a lot of the power in Angola is I think burned more by fuel oil.
So this is quite significant for the country. And but I think you'd be best asking Cobalt about it, but I'm encouraged.
Thank you very much.
Sure.
Next question from Thomas Adolff at CSFB. Go ahead Thomas.
Hi. Good afternoon. Thanks for taking my questions. I've got 2 please, one on India and one on U. S.
Downstream. Firstly, on India, the price hike looks to be a given now from April. How should we think about production and development in the near to medium term of your asset base there? And secondly, on the U. S.
Downstream, I believe you're still net longed RINs. So I was wondering if you can quantify the net benefits from RINs during 2013 and how we should think about it going into 2014? Thank you.
Okay. Thomas, I'll comment on India and we'll test Brian on RINs. So you're right. The government confirmed that after the Q1 in April, the gas price would go up on a formula. It's a positive step.
The estimated new gas price is around $8 an Mcf. It will be adjusted quarterly depending on benchmark prices. This is very good. This is what we've always said that we expected to happen. It has taken longer over the past 2 years to get certain approvals on some of the other things.
But the R Series field development plan has been submitted for approval. We think that the gross resource base recoverable there is about 1.3 Tcf likely to start up in 2017. The D6 satellites and something called NEC25 developing plans for that that's about a 1.5 to 2 Tcf resource potential. Managing the declines out of the D1, D4 base, till new compression comes online in early 2015, will be a challenge. And then this discovery we've had the MJ1 which is a Jurassic reservoir below the D6 fields.
I think it's been given a name of D55. We think that's significant. And so that will take some time to develop, but it's right underneath the facility. So that's great news. And then in exploration further out in the Kaveri Basin down towards Sri Lanka, we've had another discovery.
I think it's called D56. So in terms of specifics and production, we're not going to lay that out just yet. But I think all the pieces are finally coming together after what has been a there was a delay there. I think everybody knows it in kind of getting decisions made not just for us, but India. And I can sort of feel that logjam breaking in energy.
On the RINs question, you're right that we're long RINs since our marketing volumes now exceed our refinery throughput with the repositioning in the U. S. Of our 2 refineries. The what that means in terms of overall results for last year is pretty modest. It's not a huge number in terms of the financials that came through.
While it gives an apparent expansion in our refining market margin, you lose a lot of that around the cost of compliance with the standards. So it doesn't have a huge impact on the overall financials and it's somewhat modest. So but we don't normally give that number out to the market.
Okay. Thank you very much.
Next question from Jon Rigby at UBS.
Yeah. Thanks, Geoff. Three questions actually very quickly.
Hopefully, you can do with these. The first is on Whiting. Can you just tell me how much, if any, heavy crude you were processing in the Q4? I'm just trying to get an idea about where it was operational versus where the potential is as it ramps up through the first half of this year? The second is just on the Macondo.
What does the cash within the PSC unpaid, I think you referenced $6,000,000,000 or so. What does that relate to? It's obviously allocated but not yet paid. Can you just sort of run through what that is? And then very quickly, just lastly, on the gearing, the range, I guess, is you see is appropriate given the uncertainties around Macondo.
What is your attitude to that? Is that 10%
to 20% something that is probably suitable for the long term and you'd go out of it, let's say, to extinguish the liabilities? Or would you, as that risk falls away, look to see gearing for the corporate start to rise somewhat higher than that range that you've got now? Thanks.
Well, on Whiting, John, I think we're probably not going to give those figures out there sort of trading sensitive information. But we were running some heavy crude during the end of the year there, minimal amounts as we were commissioning them. And now we're working through that sort of post startup vessel testing set of activities that are going on now.
So would it be fair to say that there's very little benefit in the Q4 for the work that's being done on that
year. Yes. If anything, John, there's probably a minor disbenefit as we were operationally bringing the unit on. So I think so there was certainly no upside coming through in 4Q. Okay.
Yes. And there was some of that really severe cold weather.
Yes.
Yes, it's a little bit down as well. But that ramp up in vessel testing activities and switching over is occurring now On Macondo?
Yes. Sorry, John, the specific Macondo question. Of the CHF 20,000,000,000 fund we've got CHF 13,300,000,000 in cash is being paid out balance of CHF 6,700,000,000 There's £1,200,000,000 frozen at the moment around the fisheries fund. If you recall the fisheries was a cap number of £2,300,000,000 of which from memory €1,100,000,000 was paid out. There's €1,200,000,000 sitting in the fund, but that given the issues that we have now risen and the litigation we've initiated on the civil side around the WAFS claims on the fisheries side that is now as I understand it suspended in terms of payment on the balance.
But right now there's still €6,700,000,000 within the fund that can be distributed for various things like natural resource damages, plaintiff steering committee settlements, state economic claims and so
on. And on the gearing levels, if you recall, it was March this year when we completed the Ross Neff transaction, the gearing levels dropped from over 20% down to 11% and the Board has discussed what's the right gearing band. For now, we're doing the share buyback program, which has lifted it up to 15%, 16% now. For the moment time being, we like a gearing band. We think it's prudent 10% to 20%.
The Board continues to review it and discuss it. But I think for the foreseeable future, we like being right in the middle and around this. We've got plenty of capacity to go up to 20%. So no real change, John.
Okay. Thank you.
Back to the U. S. And Robert Kessler at Tudor Pickering.
Hi. I'm hoping you can help me kind of bridge your cash flows from the actual in the Q4 to your outlook for 2014. Of course, there are a number of moving parts that you've talked about in bits and pieces. I mean, Whiting is a big one. Working capital swinging the other way is a big one.
The extra margins from the upstream is another one. But now that you've got a bigger asset sale program, I'm wondering if some of that kind of carves out of the cash flow for next year. Just see if you can just provide some kind of waterfall with some bigger numbers we can think through to go from 4Q to next year.
Yes. So Robert, I think that you've highlighted all the big moving parts. So you've got the kind of underlying improvements we're seeing come through in the mix of the upstream barrels. And we saw underlying growth year on year of about 3.7% 4Q, 4Q. So that's the first sort of dynamic and you'll see that continue to come through and the higher margin barrels coming through.
You've got the new projects in Whiting that Bob talked about. You've also got a working capital build that we saw through the end of 3Q and we said that we expect to further that to reverse out. We did see a chunk of it reverse out in the last quarter, but you didn't see it come through the numbers because at the end of each year we have this around $2,000,000,000 of working capital goes out the door for the German FISC. It's called mineral oil tax that comes back in. It started to come back in already through the 1st 6 weeks of the year.
So if you look at the €5,400,000,000 and you take account of that €2,000,000,000 that goes out, it gets you to something more looking like a run rate that you can start to sort of see a bridge through million. So maybe that will help a little bit with some working capital that we built last year in various across various pieces around some operational components. So as all those things get smoothed out through this year then I think we are still comfortable that the $30,000,000,000 to $31,000,000,000 target is achievable.
As far as the incremental cash flow from the upstream, you of course gave us some outlook for production. You gave us some outlook for Gulf of Mexico margins and U. S. Margins. But what about total upstream unit cash flow?
Can you give us some kind of guidance for rate of improvement relative to say Brent prices?
Yes. Robert, what we've shared with you before is, if you remember way back October 2011, we talked about all the new barrels coming on stream having double the margin of the average portfolio. And we're seeing those barrels come through actually on an EBITDA basis. You can see those in 3Q. You start to see those ratios models into models into your sort of forward projections that would see those big margin barrels kicking in.
And you saw that in the Q4 with Gulf of Mexico now getting back above 200,000 barrels a day. And you see that those the margin of those barrels is significantly impacts the overall portfolio. So you'll see more of those things ramp up with the projects.
Thanks. And last one for me. A couple
of just
small items. The one offs you mentioned in the upstream the benefit of lower production taxes with the recovery of past costs and then the stronger gas market and trading referenced in the results?
That's correct. Yes. Both those things came to in 4Q production taxes in the U. S. And a good quarter for the gas trading and the gas realizations outside the United States and actually inside the United States.
Any quantification of those two factors?
No, we don't give any I'm sorry, Robert. We don't give specific guidance on the specific numbers.
Okay. Thanks anyway.
Thank you. Next, Alastair Syme from Citi.
Yeah. Good afternoon. Three quick questions, I think. Just picking up on Robert's point about the cash flow target. Can I confirm that the sort of the pre working capital cash flow is also going to be up within that range?
I was sort of a little bit confused about the point you're making on working capital moves. Secondly, it's I guess since we last spoke you've sanctioned Chatezanese and Kazan. I wonder if you could just talk about sort of the relative economics of those projects within the portfolio. And lastly, you've had ramp up you have ramp ups from Atlantis North and North Rankin 2 this year. Just a bit confused about whether you would class those as projects within the base.
Do in other words, do we still consider there's a 3% base decline ex those projects or including those projects? Thank you.
So Alastair maybe when I take the first question.
Which one should I do?
No, no, on underlying operating cash flow. Sorry, probably just picks up from where Howard was asking. We'll see through the portfolio mix and through the new projects and so for example PSVM is now up on full plateau you'll start to see the underlying operating cash flow from the effectively from the earnings of those assets will also come through in 2014. So that's obviously all part of bridging to $30,000,000,000 to $31,000,000,000 of operating cash I. E.
Excluding all the working capital effects.
Yeah. And the 2 big projects you mentioned Chardonnayce, the 2nd phase of Chateaunez, this is the largest gas condensate field that BP has found and has the highest rate wells in our portfolio today from it. 2nd stage expansion 16 BCMA taking it into Turkey and then later on into up into Europe over to Italy with 125,000 barrels a day of condensate with it. We're not going to give out the exact production agreements. 6 BCMA will be sold to Turkey.
The economics on this project are long lived and they're attractive. And we who manage what I think is the largest single offshore complex in the world with ACG and then the Chokines projects you really do need to look at it as a system for us and the economics are attractive. On Kazan, we've signed what is one of the longest life projects I've ever seen. We're going to drill 300 wells over time to produce gas in Oman, which is becoming a gas short region. The economics on that are attractive for us.
And we won't give you the exact numbers on here. But the gas price, which is also not a public number may not be as high as what people might look at and draw a conclusion from it. But I'll note that in that project the gas gathering facilities and the central processing plants are being built by the government itself. We have a 60% stake in that and Oman Oil has a 40% stake in that. I'm very enthusiastic about that.
We've signed a memorandum of understanding to use our SABR technology that can use the gas and get to potentially acetic acid in what could be a revolutionary process there as well, which of course we did not include that in the economics of the decision on Kazan. So I think it's got additional phases for development as well down the road and it's also got some condensate. So 300 wells over the 1st 15 years and many more years after that I believe. So Alistair does that answer your question?
That's fair. It's just the one remaining on Atlantis and Northland and North American sort of about whether this is growth or base?
Brian and I are looking at you there quizzically because it's a fair question. I'm not sure. And let's see if Jess can find something. Tell you what, let's come back Alistair and we'll see if we can find the date out of that because it's a fairly detailed question. And let's see.
So they are both growth, both of them from 2013 into 2014.
Yes. We don't give the specific numbers by project as you know Alastair, but they are both I would say in the growth category.
Yes. Definitely looking at the numbers.
Okay. Thank you.
Good. Thank you. We'll take the next question from Irene Himona at SocGen.
Good afternoon. Thank you. I had two questions, please. So firstly, you indicated the current €9,200,000,000 provision for the claims is at least €1,000,000,000 too low and probably more given unsettled claims sort of going through the system? There used to be a deadline, and I believe it was April 14, for filing such claims for economic losses.
Is that deadline still legally valid? My second question going back to Whiting, if I may ask, when do you actually expect the unit to be fully up and running, sort of ramp up to plateau as it were? And is it at that point that the EUR 1,000,000,000 cash flow contribution becomes relevant? And is that likely to happen this year basically? Thank you.
So Brian on the claims?
Yeah. On the claims, Irene, basically where we started with the PSC settlement was that we originally did various calculations of what we believed the costs would be and then provision for those costs and that was the $7,800,000,000 You'll probably recall that that number then went to €9,600,000,000 around the Q4 of last year and then we reversed that out down to €9,200,000,000 So lots of moving parts. There isn't I think what we've said is there were 2 substantive issues that we raised a year ago around the way in which the agreement was being interpreted by the court and we appealed those decisions one of which we received a favorable ruling on from the 5th Circuit Court of Appeal on the matching of revenues and expenses. So that one was resolved and now the court is looking to how that gets applied around those matching of revenues and expenses. And there's still a separate issue which is sitting with the 5th Circuit around causation.
That is to say that we put the agreement in place to ensure those people damaged by the spill were compensated. However, it appeared that there'd been a delinking of causation in the interpretation of the agreement. That one is still out there. So until that issue gets resolved and we have a framework for matching of revenues and expenses, we can't determine what the future provision might be around business economic loss claims. So I certainly can't say at this point that we're under provided by €1,000,000,000 as you've just suggested.
I think there is a $1,000,000,000 of determinations this is hitting inside the fund. They may well the majority of which may well need to be redetermined through either the matching process or depending on what happens around causation.
And the April deadline?
Oh, the April deadline. So the deadline is actually set as the earlier later of it would have been April 14, which is the sunset clause. It's actually 12 months after the date at which the furnace appeal has ruled on the furnace of the settlement agreement when that was the ruling that we had a couple of weeks ago. We're still working through what that actually means, but typically it would be 12 months after that after all the final claims to come in.
And Irene on Whiting, we are ramping it up now. And yes, we are projecting the $1,000,000,000 in incremental cash flow this year for the year. Obviously, there's some environmental assumptions around that, but the current environmental the current environment $1,000,000,000 forecast. We're going to progressively ramp it up. We can't be specific on the pace, because we're going to fine tune it as we go.
And of course, it's a trading sensitive number. So we're not going to comment on the pace of fine tuning the ramp up.
I think Irene Bob makes a really important point. To the degree the light heavy spread stays out where it is today which is $19 there's clearly upside in those numbers as you get to a full year ramp. So there'll be to the degree it ramps up early, the light heavy spread is low compensates for it taking a little bit longer, but we don't know and a light heavy spread which is bigger. So right now at $19 the 1,000,000,000 dollars is comfortably underpinned at $19 spread.
Thank you.
Thank you, Irene. Next from Doug Terreson at IASI.
Good morning and congratulations on positive execution everybody.
Thanks Doug.
Bob, returns on capital were under pressure for the super majors during the past few years. And on this point, both your and Brian's comments underscored the company's commitment to capital discipline today and the spending profile is supportive too. So my question is, and I have two questions, is first, given the more challenging environment for returns, but also the desire for growth, how does BP ensure that it sustains its discipline through its corporate planning process given the recent replenishment of the portfolio that you talked about, but also the more challenging environment for returns? And then second, some of your competitors are increasing emphasis on returns on capital. So I want to see if we can get an update on the measures that you guys deem most important whether they're changing and specifically how ROCE plays into the thinking?
Yes, Doug. I think this is kind of the heart of the sector which is sort of out of favor to a degree. And I think what I'd say is return on capital employed. My experience yours too I'm sure. Go through history and when it suits companies talking about return on capital employed they do.
And then when it doesn't sometimes they don't. But I and I'm going to fall back at it a little bit on BP in the sense that we divested $40,000,000,000 of assets which had more than 50% return on their capital employed. So by definition, our overall capital employed is going to take a notch down. We think that was absolutely the right thing to do. But the kinds of things that we will give us a little patience Doug, we are on the 4th March going to go in and talk about this quite a bit more.
But I do believe here's the sort of fundamentals. We've said $24,000,000,000 to $27,000,000,000 for the rest of the decade. We're going to have that discipline. We're going to invest in carefully in what we think are good margin projects. We will pace those in time so that we can make sure we can generate sufficient operating cash flow to have some distributions back to shareholders, make sure we can have a sustainable dividend policy through the decade.
And there are differences in the portfolios of different companies. And you've heard us say many times, we have a bias to oil. We like oil. It's a higher margin product and then selectively in gas. So that's kind of it in a nutshell.
But remember that $40,000,000,000 out at 50% returns has kind of shaped some of the fundamentals of the company.
Sure. Sure. Okay. Thanks a lot.
Tapan Jochel Ingram at Nomura.
Yeah. Afternoon. Thanks, Jess. A few questions, please. Just firstly, Bob, you mentioned Russia in your remarks.
I was just wondering, are there any specific milestones that we should look for over the next 12 months? In particular, how much more can BP sort of contribute on the integration steps? Secondly, Brian, just come back to modeling in the Upstream. I think you've talked about the margin mix at length. I just wanted to clarify just on unit OpEx on the base portfolio for this year.
Do you see it going up flat or down and sort of the latter being that you're benefiting off more barrels off the fixed cost? And then just lastly on the Palajun and Anguilla, how much further prospectivity do you see there in the Palajun? And sort of what are the next steps in terms of appraisal and drilling? Thank you.
Okay. On Russia, so taking these 2 large oil companies Rosneft and T and K BP merged them together. And I would say that integration moved pretty fast about 800 of the top 1100 in T and K BP people came across into Ross Neft and you really do have a mixture of business processes. And I can see it in the pace at which many things are happening there. Both companies have got a lot of professionals.
The milestones I would expect you to see from BP in addition to the kinds of things that we push at the Board processes in terms of governance and annual planning processes and capital allocation. But I would expect you to see and hear about expertise and experts from BP going and working in and with Rossnacht on specific issues, problems, projects, water flooding, artificial lift, seismic interpretation, corrosion expertise, pipelines, environmental work. That would be one thing that we think is important. So I would look for that. We I believe a lot of the really good Arctic acreage is taken.
That's fine, because we effectively own nearly 20% of it and carry it at exploration. So we like that. So I look at the exploration results coming forward as milestones of success of the company itself Ross Neft. And then for us, I know we have expertise and we're looking for carefully selected opportunities onshore. It might be unconventionals in oil.
It might be some of the heavier, tougher oil developments that we can work on together in joint ventures. There's no rush. This is going to be a multi decade relationship, but those are the sort of things I would look at in the next year. And then, T Pen, on the Paleogene, we're going to continue the appraisals of Tiber, Cascquita, the Chevron operated Moccasin projects, which were in there together. We know there are further opportunities out there.
We have a large acreage position. And so we're going to selectively look at what we either want to drill for exploration. It's a large province. We might do things with other companies as well. And then of course in December the big Gila discovery just further reinforced the importance.
And it's a longer term province, HeLa. We'll look for technology that can keep up. So we're not going to rush and get out in front of the technology, the 20 ks technology we're working on with Quesquita right now. It's going to be a big play. And I think don't know what the potential is for it to go down into Mexico as well, but there's other things in the Gulf by the way in Mexico that the industry will certainly be interested in.
But this is a play for the next decade. That's I think is a fair comment.
Tee Pan. And then on the cost question, the internal performance metric we look at around cash costs in the Upstream decreased 13% versus 2012 primarily due to divestments as we take some assets out. On a unit production cost basis, it increased by about 5% and that again reflects the volumes that we've divested. So it's pretty hard to sort of see through in terms of what's going on on an underlying basis. And if you look over the last 5 years, unit production costs for the sector have grown about 6% to 15% over that time period and we're kind of in the pack of that.
And we did see some increase on a unit basis. But going forward, we'd expect to remain competitive within the sector. And of course, we're also ramping up exploration activity and all the new projects are coming on stream as well. So you'll start to see this sort of smooth out over time. But it's something that you have to look at on a long run of quarters not in any specific 1 quarter or 1 year.
Okay. So there's no particular sort of leverage to let's say the gone barrels coming back this year against a fixed cost just on a unit basis?
It'll be hard for you to see it. You'll see all the new gone barrels and new projects come on stream, but equally you'll see the Abu Dhabi concession volumes come out. So it's going to be hard for you to sort of see through that, but we'll try and give you as much guidance as we can as the year progresses.
Great. Thanks, Brian.
We'll take the next question from Lydia Rainforth at Barclays.
Thanks. And good afternoon. Just one question for me please. You've made a considerable effort in the last couple of years to improve the efficiency and the availability of assets in the upstream. And I was just wondering if you can give us an indication of where we stand now on that almost reliability and availability index compared to where we were 2 years ago?
And how much you would want to see that improve going forward? And what the optimal level would be? Thanks.
Yes. Good question and a really important point. I mean, we've got our upstream availability now running 88% reliability, which is this has continually improved over time. Each 1% reliability is worth between $150,000,000 $200,000,000 a year. This has been a very good year.
The number of turnarounds are down. And of course, if we can keep this reliability up, that's how the operating cash flow stays up. And this sort of is this virtuous circle of safe reliable operations is good business because the assets stay running. And having made a considerable investment in turnarounds now, this is part of the story of why we've seen improvements this year and we'll see more improvements next year. We've had those increased operating efficiencies in this year in the Gulf of Mexico most certainly Alaska's new well work.
The North Sea still has some improvements that yet need to be, but they're coming as well. But this is a really important point. And that's why we've highlighted that 88% operational efficiency this time in our numbers.
Thank you. Question now from Martin Ratz at Morgan Stanley.
I have 2. I'll try to keep it short. Just first of all, as a matter of detail, in this $30,000,000,000 to $31,000,000,000 for next year in terms of operating cash flow, what is the assumption embedded in there for Gulf of Mexico oil spill related payments? And secondly, I wanted to ask you about this point that you just made about the bias towards oil. Because if I listen to Christoph Ruhl and when he presented your energy outlook 2,035, I thought he made a very strong case for the opportunities that consist in gas and also looking at some of the biggest project announcements you made last year, the Hassan project and Chaldanese.
And I mean they have a gas bias, it looks lately. And I was wondering when the underlying perhaps this bias towards oil might be softening a little. I was wondering if you could comment on that.
Yes. Well, first, Brian on the assumption on the Gulf of Mexico.
Martin, the only thing we can let you know about is the things which are in the public domain. So that would be the you recall the criminal settlement that we had last year around actually 2000 late 20 12 around the DOJ and the SEC. So there'll be payments going out associated with those this year. That was a schedule that was set up over 5 years in the case of the DOJ criminal settlement and 3 years for the SEC settlement. So that will go out this year.
They're part of the plan. And then there's ongoing litigation costs, which are built in the plans and then the ongoing cost of what is now a much smaller organization associated around the Gulf Coast Restoration Organization. So there'd be any of the things out there, but they're layered into the plans. So it's a good way that we can see what we think those costs are going to look like they're layered in already.
Okay.
Okay. And Martin, a really interesting point about gas and oil. And for those of you who haven't had a chance to look at it, I think everybody might find it interesting this energy outlook to 2,035 which you can download off our website. And gas is a growing share of the market going forward, but all of them are growing. So while the share of coal may come down natural gas will go up.
We sort of think by 2,035 about I mean I call it the rule of 27, so I can remember it. But 27% of the market share of energy will be oil, 27% natural gas, 27% coal by 2,035. But to get to that, you're going to need if this is this forecast turns out to be right another 19,000,000 barrels of oil per day to get there by 2,030 5 even though its market share is lower because the demand for energy just keeps growing, which is the equivalent of another United States and another Saudi Arabia all coming out there in terms of being able to supply that. So oil, we think is going to be continually valuable 90% of transport fuel in 2,035 will be oil based or liquids based. So gas is different.
It's regional. So you've got a price of gas in North America. It's 3 times that much in Europe and it's 5 times that much in Asia. So we want to be very selective about where we develop gas. And there's good economics probably all through all three of those.
But those two projects you mentioned are very economic, but they're not in North America.
All right. Thank you.
Thanks, Martin.
Moving now to Stephen Simcoe of Morningstar in the U. S.
Hi. Good afternoon, everybody. I have two quick questions and the first one would be highlighting this regional gas comments you just made Bob. In terms of North American dry gas, is there anything from here that can be done in the portfolio beyond investments in terms of just getting costs down or improving the performance? I know Q1 is obviously going to be the best quarter in some time, but just some commentary there on what can be done to improve the results.
And then I don't think this has been touched on, but in terms of Gulf of Mexico pricing, and the idea of just kind of the light crude glut in the Gulf Coast that might develop in the near term. As far as Gulf of Mexico production, what is Beefy's exposure to lights versus medium output from the Gulf of Mexico? That's it for me. Thanks.
Yes. Okay, Stephen. Both good questions. I mean, we're running our gas business in the U. S.
Try to make it breakeven around $4 an Mcf. So right now, of course, with the cold weather prices are up closer to $5 But dry gas is very challenged in the U. S. And so we're not running any rigs in dry gas. We could hold all our production resources there.
So we're focusing on liquids rich gas as much as possible. And that I think is what you'd find most people's strategy to be. I think for BP going into things like gas to liquids, if you're thinking that far out, I think that requires a lot of capital, a lot of infrastructure. And I don't think we're focusing on that. So we want to run a tight efficient gas business in North America and we've got a lot of work going on to further improve that efficiency.
In a way the Gulf of Mexico turning to that for a minute that crude extra crude that we do see in the Gulf of Mexico trading for a while. Yes. I mean, I don't have worked and run trading for a while. Yes.
I mean, I don't have to hand the actual mix of the light versus the medium in terms of Gulf of Mexico. But you will have seen that grades like Mars have been discounted quite heavily to Brent and actually they're de linked from the Brent price now as you've seen the domestic crude rebalance in the United States. So there is some impact on realizations and you'll see that come through in future quarters. But the market will ultimately determine what those barrels price at. I think the last time I looked, Mars has discounted at around about $14 to Brent, which follows the pattern that we've seen with WTI given the oversupply of crude oil as the oil shale has grown in the United States.
And I think with these lower realizations, I think it's worth noting for us the cash impact for us on 2014 is positive. It's not anyway because of the increase in production more than offsetting that lower realization. Is that okay, Stephen?
Yes. Very helpful. Thank you very much.
Next question comes from Colin Smythe of BTB.
Yeah. Hi. Thanks for taking my question. Just a follow-up on realizations one. As you noted, Brian, realizations or rather market prices fell quite a lot for Gulf of Mexico crudes, but that wasn't really visible in your realizations, which held up very well for the U.
S. And I just wondered if you could comment about that. And the second thing was you noted that the trading performance in Downstream had been pretty weak. And I just wonder if that was in any way connected with anything to do with MiFID or EMEA or what you think those issues might mean for you in terms of the ongoing profit from that business? Thank you.
So specifically the question around supply and trading is a 4Q issue in terms of being weak in the Q4. The actual year result for supply and trading both in oil and gas was a good year. So we did have a very good start to the year. So I mean the first half of the year the 4Q was a weak quarter for the supply and trading business for the ore side. It was actually driven by some positions that actually do link back to domestic position in the United States.
But frankly I wouldn't we don't normally typically go into the specifics of those. And then in terms of realizations, a lot of our barrels do price off Brent. They're Brent related prices you see come through. To the degree Gulf of Mexico barrels stay disconnected and delinked from Brent, we may start to have some impact on realizations going forward. But as Bob said, we are comfortably seeing production growth in the Gulf of Mexico is more than offsetting that.
The U. S. Realizations quite a bit
of that is actually linked
to Brent. Is that right?
Well, typically Gulf of Mexico barrels are priced off Brent. So because ultimately there were international trade for them. What you've seen happen in the last quarter and last 6 months is a de linking now of that link back to Brent. So actually no those barrels are now pricing off local prices which look a little more like WTI.
Right. But you didn't really see that in the 4Q to 3Q change in realizations for your U. S. Barrels? That was really question.
Yes. I think you've got a whole you have a whole mix of things going on with the gas realizations being stronger than liquids realizations coming through in the Q4 as well. So I think you'll see some of these things clean out as the year progresses this year.
Okay. And MiFID and EMEA?
No. Absolutely. We've done everything we needed to have in place around the new MiFID regulations and indeed the Dodd Frank regulations. So we're comfortable. We have structured things as we need them to be able to continue to participate in the markets, but none of those had any impact on 4Q.
Thank you very much.
We'll take the last question from Fred Lucas at JPMorgan. Go ahead Fred.
Thanks, Jeff. Thanks, guys. A few questions. Firstly, which upstream projects do you think is operating your sanction in 2014? My second question is, it was a great year for exploration, but it was also a burdensome year for exploration expenses.
I wonder going forward do the 2 go hand in hand? And my third question is around portfolio positioning in the Middle East, North Africa region. BPs clearly had a breakthrough in Iran and looks like you've had some exploration success in Egypt. But you've also lost the concession in Abu Dhabi. You've exited Jordan.
The unconventional play there hasn't worked. There's got to be a question mark over what happens going forward in Libya. So I just wondered if you could share some comments about BP's portfolio positioning in the MENA region and perhaps where next And if Iran is on your radar screen? Thanks.
Okay. Thanks, Fred. First on 2014, right now we're expecting around 5 FIDs to occur in a variety of different geographies in the U. S. And Africa and South Asia.
So we've got a list of 5. We're not going to lay those out just yet. We've got partners that we need to get approvals with. You asked a second question there, while I was looking up something on MENA. But what was your second question?
Yes. It's around sorry, Fred. So yes, you're right Fred. To the degree that we ramp up the exploration spend, assuming you have the similar success rates that you had previously, clearly the more dry holes leads to more write downs. So yes, the 2 things do go hand in hand.
But as Bob said, it was our most successful year in quite a long time and certainly over a decade last year in terms of the exploration and the commercial viability of some of the fines. But yes, last year those we did get a lot of exploration write offs coming through in the 4Q. That is linked to the higher exploration spend.
Yes. And I think that exploration write off is not steady. It's lumpy depending on individual wells. 4Q seemed higher than what I would expect going forward. On MENA, MENA is interesting because it is an important area of the world for us.
You're right. Jordan, we tried the unconventional gas. It wasn't there. We gave a good effort at it. It's unfortunate because Jordan is a country that has no energy really and needs it, but that one we'll step away from.
Iraq where we manage a 1,400,000 barrel a day oil field with called Rumaile lettuce one of the largest 2nd largest field now in the world operating. It provides probably half the money from energy into the treasury of the country of Iraq. I think that's going extremely well. In Algeria, we continue to work and operate in the Inaminas and Insala concessions. And we're back to work now in Algeria particularly in Insala now.
There's more work on both of those projects for expansions probably in 2015 now. We do have large exploration areas in Libya. I would describe it as being in hibernation. And I am glad we don't have production today. But the prospects still remain there both offshore and onshore Libya.
And offshore is of course most prospective for us. Abu Dhabi, the concession was not renewed for anyone. The big we still operate there on the marine concession, which is still a very significant concession. But we and I think Total Shell and Exxon each step down 140,000 barrels a day on the offshore along with the one Portuguese company. And they'll make a decision at some point down the road here.
We still have offices in the Emirates where we manage a number of our Middle East activities. And of course, Oman is a very, very big action. So in Egypt, we've been operating in Egypt since the 1960s. We've had no disruptions on the oil production in the Gulf of Suez and the gas production minimal maybe, but primarily the gas production has continued in the North. We remain committed to working in Egypt.
And so I think we have actually a fairly sizable MENA position with the potential to grow.
What are you thinking about Iran both?
Iran, we have not had meetings on Iran with government. Somebody said I had a meeting with the government of Iran. Well, the head of the Iranian President came to Davos and spoke to a lot of people. So that's the only meeting we've had, which is I wouldn't count as a meeting. Until laws are clear and sanctions are clear, we're not going to drift out of anything around those laws until we have a clear signal that that's an appropriate thing to do.
Got it. Thank you very much.
So if I could ask you thank you very much for everyone really, really good questions every one of them. As we head towards 2014 and beyond, we look forward to seeing you on the 4th March. We'll do that as a webcast. It will be Brian and myself, Head of the Upstream, Head of the Downstream and then we'll have some teams that travel after that. It will be live.
It won't be a recorded webcast, so you'd be able to participate. And again, if I could just say, the kinds of things you're going to hear is about the capital discipline we put in place. We realize we work for our shareholders. We want to be shareholder friendly. We don't want to fall into the trap of generating a lot of cash and then putting it back into projects and not returning some of those distributions to shareholders.
We treat our portfolio as it is something to manage. We've lost some of the emotional hold on assets through this difficult 3 years. And we look forward to telling you more about it in early March. So with that, again, Happy Chinese New Year to everyone on the line and we look forward to being in touch.