Hello, everyone, and welcome to BP's 2011 Investor Update. We are very pleased to have you with us whether in person, over the phone or on the web where I understand there's a large group. For those here in London, you will have seen behind me our safety evacuation guidelines. We are not planning to test the alarm system today, so if you hear it, please proceed as advised and further details can be found on the handouts on your chair. I'm pleased to be joined on stage by Byron Groat, our CFO and Ian Khan.
And with us in the audience we have our Chairman, Karl Hendrik Svanberg, as well as the BP executive team who I will come back to and introduce in a short while. And we also welcome Maxime Barsky who's just walked in, as perfect timing as CEO Designate of TNKBP. And our long standing and successful joint venture in Russia and our guests from Rosneft, including Edouard Houdinotov, Rosneft's President, CEO Pavel Fedorov, First Vice President and CFO of Rosneft and the CEO and General Counsel, CEO's General Counsel, Larissa Kalanda. As you know, we have recently forged a significant new global and Arctic strategic alliance with Rosneft. So we are pleased to have them with us here today as well as Maxime from TNKBP, an important venture for BP.
Now let me begin with our usual cautionary statement. During our presentation, we'll be making forward looking statements. Actual results may differ from these plans and forecast for a number of reasons such as those noted on this slide and also in our SEC filings. Please refer to our Annual Report of Accounts and 4th Quarter Stock Exchange announcement for the details and both of these documents can be found on our website. Our agenda today is a full one, and I will start with a brief overview of 2010 and an outline of how we are moving the Q4 and the full year of 2010, and then we'll move into a detailed look at progress and future plans in each of our businesses before taking your questions.
We had a difficult year in 2010. It was dominated by the Gulf of Mexico in which 11 people lost their lives. We remain deeply sorry for what happened and its effect on the families and the communities that were involved. We know nothing can restore the loss of these 11 men. Often the response to a tragedy defines the character of an organization and I am determined that we will emerge from this episode as a company that is safer, stronger and more sustainable, more trusted and also more valuable.
I believe that BP has a responsibility to meet its commitments in the US, which it will, and also has a responsibility to take our learnings deeply to the fabric of our organization. It means changing the way we manage our operations and concentrating on the things that drive long term value. Safety, capability, technology, portfolio choices and relationships. We are taking the opportunity to reshape our portfolio and our operating model as well as working in new ways with National Oil Companies and many partners. So let's look more specifically at the events of 2010 and our response.
Following the accident, we acted rapidly to fulfill our commitments as a responsible party, stop the oil flow, clean up the water and the short response was of unprecedented dimensions. At its peak, it had 48,000 people, 650 vessels and 125 aircraft. And we've acted in many other ways to do so. We suspended the payment of a dividend for 3 quarters of 2010. We know this had a major impact on our shareholders.
We committed to pay $20,000,000,000 over 3.5 year period into a trust fund, out of which we were meeting our legitimate claims. We initiated $30,000,000,000 asset divestment program. We fully cooperated with the U. S. Federal Government and the States.
And we have made organizational changes including setting up a new safety and operational risk function, and we've restructured the upstream segment of BP. We have introduced a new performance management system across BP. We are fundamentally reviewing the way we manage contractors, And we're sharing and implementing our learnings globally. Now beyond the Gulf of Mexico, global operations performed well. 2010 was a year of good financial performance with strong underlying earnings and cash flows.
In the Upstream, we continue to move forward on many fronts. We're today reporting reserve replacements of 106%. This is the 18th consecutive year above 100% for BP and we replaced 4 70% of our resources. It was a very good year for new access with many new opportunities added to the portfolio. That trend was continued with the new access to deepwater blocks in Australia, in Angola and the BP Rosneft Arctic Alliance.
15 projects were progressed through Final Investment Decision or FID and we achieved a very important milestone approved production target in Iraq in December. In Refining and Marketing, we delivered $900,000,000 of underlying performance improvement, mainly driven by improved U. S. Refining operations and our international businesses. And we made good progress on our divestment program and have significantly exceeded the book value on these sales.
Byron will prove 2010 results in a moment. But before we do that, I would like to say a few words about how we see the future of our industry and BP's role going forward. 2 weeks ago, we shared our outlook for energy demand and supply through to 2,030. By 2,030, based on our judgment of the likely path of global markets and energy demand, we estimate that the world could be consuming around 40% more energy than today. As this charteredy will be from many different sources.
We expect continued reliance on oil, but with new growth met increasingly by gas and renewables. With many of the world's mature basins in decline, the industry will need to increasingly look to frontiers and new technology deep waters, the Arctic as well as unconventional sources. One of our roles as a company is to help the world meet this increasing demand for secure, affordable and sustainable energy. Our license to operate depends on us delivering it in a safe and responsible way. Trains to build on, we have scale and reach that spans the globe and a leading track record of exploring and opening up new frontiers.
Our portfolio of assets, I believe, is among the very best in the industry. This portfolio combined with the capability of our people and with our relationships built over the course of decades, alongside our strong focus on technology, I believe positions us to play a key role in meeting that challenge. We expect the growth in energy demand will be driven primarily by the non OEC world. Today, China's demand for energy is already larger than that of the EU and is about the same size as the U. S.
As you can see here, it is expected to nearly double in the next 20 years, while demand growth in the U. S. And the EU looks set to be much flatter. This picture requires us to think differently from the past, increasingly looking to the East to invest while rationalizing our positions in the more mature OECD markets as appropriate. And you will have already heard of our decision about U.
S. Refining. Of course, this is an evolution that will take some time, but you can already start to see how these trends are influencing BP's decisions. This brings me to the key part of our agenda today, BP's priorities moving forward. 2010 was an inflection point challenging us to think about what changes we need to make to our business.
So moving forward, we have set ourselves 3 clear priorities. The first is setting safety and operational risk management at the heart of and how we operate, how we partner with governments and contractors and how we reward performance. This will fundamentally reshape the way we work. Secondly, we recognize that building trust is central to our continued license to operate. In the first instance, we need to meet our commitments in the United States.
We also need to ensure that lessons are implemented across all of our operations globally. Beyond this, we need to play an active role in sharing the lessons with partners and governments to ensure such an accident can never happen again in our industry. And importantly, our 3rd priority is to deliver value growth for shareholders. We've made a number of announcements this morning and you can start to see some of the choices we are making to realize our value. We are resuming payment of a quarterly dividend with the intention to grow the dividend level in line with the improving circumstances of the company.
We are divesting non core assets in the upstream, unlocking hidden value while creating a portfolio with potentially stronger growth from a smaller base. We are adjusting half of our U. S. Refining capacity, retaining those positions with the greatest competitive advantage so as to improve returns. We're creating long term value by investing in strategic projects.
Our upstream portfolio is very rich in growth of 32 project startups planned by the end of 2016. And we're increasing our investment in exploration. It's one of our distinctive strengths and the beans by which we turn prospects into value. We're evolving the nature of our strategic partnerships with national oil companies and major resource holders going beyond the traditional IOC model, such as our alliance with Rosneft and our joint venture with TNKBP. We're focusing on long term value by investing in the key inputs, namely safety, capability, technology and relationships.
All in all, we intend to focus on continuous reduction in risk, value as much as volume, and quality over quantity. It's about choices for the future rather than legacies of the past. And as to the immediate future of 2011, it will be a year of consolidation for BP as we focus on completing our $30,000,000,000 divestment program, meeting our commitments in the U. S. And bringing new rigor to the way that we manage risk.
These actions may increase some costs and reduce volumes in the very short term, but we believe they are absolutely essential to growing value for shareholders for the longer term. With the new direction we're putting in place at BP come a number of new faces. So before I hand over to Byron, I'd like to take a moment to briefly introduce the BP team. This chart shows much of the leadership team, highlighting those of you that you some of you will get to meet, at least some of you over the next few weeks on our annual investor roadshow. So here in London today with me, we have Ian and Byron, who I've already introduced, who will be presenting shortly.
Representing Upstream, we have Mike Daley. He's responsible for exploration Bernard Looney, who heads up developments Bob Fryer, heads up production Andy Hopwood with overall responsibility for upstream strategy and integration. Mark Bly heads the new Safety and Operational Risk Organization. Lamar McKay here has joined us from BP America. David Petey from BP in Russia.
I think he's out right now. We also have with us Brian Gilvari, our Deputy CFO. Some of you will know these people well Steve Westwell, Head of Strategy and Integration for the group Sally Bodd, our Head of HR Peter Henshaw is the new Head of Group Communications. There's Peter. And a face all of you know well, Fergus MacLeod, who's Head of Investor Relations.
After the presentation, you'll have an opportunity to questions to all of us during the Q and A session. Let me hand it over to Byron to take the Q4 and full year results.
Thank you, Bob, and good day to all. I'll begin my review with a summary of the trading environment. The table shows the percentage year on year changes in BP's average upstream realizations and refining indicator margin for both the Q4 and the full year. Our liquids realizations increased to $79 per barrel in the 4th quarter, up 12% on 3Q and 16% higher than a year ago. Our gas realizations increased slightly to $3.98 per 1,000 cubic feet, 2% higher than 3Q and 8% higher than a year ago.
Taking both oil and gas together, average hydrocarbon realization was up 10% compared to the Q4 of 2,009. Our refining indicator margin of $4.64 per barrel was slightly higher than the previous quarter, but around 3 times higher, the very weak margins seen a year ago. From the Q1 of 2011, we'll be using new refining indicator margin, which we'll call the refining marker margin or RMM. The refining marker margin uses regional crack spreads to calculate the margin indicator. It is not in submittal costs and other variable costs.
It's similar to the approach used by many of our competitors. Full details and historical comparisons, including an updated rule of thumb are available through Investor Relations and onbp.com. Turning to the financials, adjusted for gains of $250,000,000 for non operating items and fair value accounting effects, Our 4th quarter underlying replacement cost profit was $4,400,000,000 the same as 4Q. The quarter's result benefited from a stronger environment, but was adversely affected by lower production and a significantly higher tax charge. 4th quarter operating cash flow was an outflow of $180,000,000 Excluding Gulf of Mexico oil spill expenditures of $5,400,000,000 underlying operating cash flow was $5,200,000,000 down 28% compared with last year.
The lower operating cash flow was primarily driven by temporary working capital effects. Next, I'll provide you with an update on the costs and the provisions associated with the Gulf of Mexico oil spill. In the Q4, we've taken an additional pre tax charge of $1,000,000,000 primarily reflecting an increase in projected response and administration costs. The provision carried forward in the balance sheet at the end of 4Q represents our current best estimate of those future costs for which a provision can be made at this time, subject to all the exclusions and uncertainties that we've described in the stock exchange announcement. And we've taken the provision on that basis.
BP continues to believe that it has a contractual right to recover the partner shares of costs incurred. And whilst no amounts have been recognized in our financial statements at this time, as of the 20 January, $6,000,000,000 had been billed to our joint venture partners. We'll continue to review the provisions quarterly and we'll be adjusting it as new information becomes available. Total cash payments of $5,800,000,000 were made in the 4th quarter, which included the second payment of $2,000,000,000 into the trust fund as well as direct oil costs. Full year cash expenditures related to the incident totaled $17,700,000,000 In exploration and production, after adjusting for a gain of $1,300,000,000 for non operating items and fair value accounting effects, we reported a pre tax underlying replacement cost profit of $6,700,000,000 Relative to a year ago, the result was impacted by lower production volumes and a loss from our gas trading and marketing operations that benefited from higher prices and lower depreciation.
Production was 3,670,000 barrels of oil equivalent per day, 9% lower than a year ago and 6% lower after adjusting for the effects of acquisitions and divestments of around 85,000 barrels per day, plus 40,000 barrels per day of entitlement effects on our production sharing agreements. This reduction reflects a higher level of turnaround activity than in the Q4 of 2,009, particularly in the North Sea and Angola and the continued impact of the Gulf of Mexico drilling moratorium. It also reflects the absence of the 40,000 barrels per day benefit in the 4th 2019 related to the makeup of a prior period under lift, which we talked about a year ago. After adjusting for entitlement impacts on our production sharing agreements and the impacts of acquisitions and divestments, full year production was 2% lower, largely due to the impact on Gulf of Mexico production. Looking ahead, we expect 1st quarter production to reflect the continued impact from disposals, the continued lack of drilling activity in the Gulf of Mexico, the impact from the shutdown of the Trans Alaska pipeline system in January and entitlement impacts on our production sharing agreements if prices remain at current levels, partially offset by our first production from Iraq.
BP's share of TNA BP Knitting was $850,000,000 for the quarter. We received a dividend of $790,000,000 In Refining and Marketing, after adjusting for non operating items and fair value accounting effects of $220,000,000 we reported a pre tax underlying replacement cost profit of $740,000,000 for the this is an increase of $130,000,000 compared with the Q4 of 2009, principally due to stronger refining margins, stronger operational performance in the fuels value chains, continued momentum in the international businesses and continued cost efficiencies, partially offset by a loss from supply and trading activities. The results were also impacted by certain one off items. Our operational performance in the fuels value chains continue to be strong with some availability and refining throughput up 120,000 barrels per day versus the Q4 of 2,009, partly due to lower turnaround activities. The international businesses continued to perform well with petrochemicals maintaining high production levels and our lubricants business continuing to deliver earnings growth.
Underlying performance in the U. S. Was a breakeven for the Q4 compared with a loss of over $600,000,000 in the same quarter of 2,009. Looking ahead, we expect Q1 refining margins to be similar to the 4th quarter and the petrochemicals environment to remain robust. BP's refinery turnaround activities are expected to be slightly higher than in the 4th quarter.
As I mentioned earlier, we incurred loss in the 4th quarter in our supply and treaties in the Upstream and Downstream segments. It's worth noting that over the past few years, the contribution from supply and trading has been volatile, both on a quarterly and on an annual basis with 2,008 and 2,009 being particularly strong, 2010 being unusually weak. In light of the 2010 performance, we've made a number of structural changes aimed at reinforcing our ability to efficiently capture available market opportunities. The long term returns have been attractive to BP and we continue to view supply and trading as a business activity within the Group. In other businesses and corporate, after adjusting operating items, we ordered a pre tax underlying replacement cost charge of $480,000,000 for the 4th quarter, an increase of $60,000,000 versus the charge a year ago, primarily reflecting adverse foreign exchange effect.
Turning to cash flow, this slide compares our sources in 2,0092010. Operating cash flow excluding post tax Gulf of Mexico oil spill expenditures was $29,600,000,000 7% higher than a year ago, mainly reflecting the benefits of a stronger environment, partially offset by lower production. We received $6,200,000,000 of disposal proceeds for deals completed in 4Q, bringing the total to the year to $10,800,000,000 In addition to this, we held $6,200,000,000 in deposits for deal which are expected to complete in 2011. Total capital at the end of the year was over $18,000,000,000 Our net debt at the end of 2010 was $25,900,000,000 and our net debt ratio was 21%, 1% higher than a year ago. The $6,200,000,000 of deposits for deals to be completed post year end was reported to short term debt.
As these deals close, net debt will reduce accordingly. Consistent with maintaining a prudent and flexible financial framework for the group, we intend to target gearing within a lower range of 10% to 20% in the future. The reduction of net debt to $10,000,000,000 $15,000,000,000 over time as we stated in June is distant with the lower end of this range. I'll now turn to guidance for 2011. First, we expect our organic capital expenditure to increase to around $20,000,000,000 as we invest to grow.
We received $17,000,000,000 of proceeds for completed disposals plus disposal deposits. In 2011, we currently expect around a further $13,000,000,000 from disposal proceeds the 2 year total $1,000,000,000 Next, I remind you that under the terms of the Deepwater Horizon Oil Spill Trust, BP is committed to pay $5,000,000,000 of cash into the fund in 2011, 2012 and 2013 as well as continued response costs. DD and A is expected to be around $500,000,000 higher than in 2010, due to the recognition of production in Iraq and increased production from fields with higher depreciation rates, partially offset by the impact from divested assets. We've made significant progress in reducing our cash cost base over the past several years. In 2011, we expect to see a slight increase while we refocus our activities as Bob has described.
The average underlying quarterly term business rate in 2011 is expected to be around $400,000,000 As in previous years, this is likely to be volatile on an individual quarterly basis. And finally, the effective tax rate is expected to be in the range of 32.4%, slightly higher than in 2010. Bob will provide production guidance for 2011 in his remarks. In closing, I'd like to outline the medium term financial framework for the Group. We've resumed distributions to shareholders while we increase investment to grow the firm.
This resumption of the dividend is supported by our continued success in the disposal program and by the improving business environment, but balanced by the need to retain a significant level of financial flexibility at this time. To provide that financial flexibility, we intend to maintain a significant cash liquidity buffer as we have over the past 6 months and reduce the gearing ratio range of 10% to 20%, as I mentioned a moment ago. A quarterly dividend of $0.07 per ordinary share was announced for the Q4, which will be paid in March. As you would expect, the Board's prudent in setting the new quarterly dividend level, recognizing the continuing obligation to pay $5,000,000,000 per annum into the Deepwater Horizon oil spill cost and the uncertainties that we still face. The intention is to grow the dividend level over time in line with the improving circumstances of the company.
The scrip program approved by shareholders at last year's Annual General Meeting will be available for 4Q dividend recipients. That concludes my remarks. Now back to Bob.
Well, thank you, Brent. Let me now update you on progress in safety and risk management in BP. It is a focus for us. Last year, as you all know, 11 contractors lost their lives on April 20th. Sadly, we also had 3 other contractor fatalities across our operations elsewhere in the world, making a total of 14.
The top chart here shows recordable injury frequency, which includes fatalities and lost time incidents. This shows that the total number of recordable injuries increased last year. This was mainly due to the impact of the people involved in the Gulf of Mexico response. The increase occurred primarily during boom deployment and beach cleanup. Overall, we've had a knee injury trend for 10 years and performed in line with industry benchmarks.
As well as personal safety, we've taken a lot of steps in recent years to improve performance in process safety. Two measures shown here. The first is process safety related major incidents. In 2,009, we recorded no such incidents, but in 2010, we had 3, including the Gulf of Mexico explosion. The losses of primary containment on the right here are unplanned and uncontrolled releases of process material.
The trends for all of the metrics here show some progress, but there is much to do and we know that. So what are we doing to put safe, reliable operations at the heart of BP? We have clear priorities and a program of the main priorities to strengthen process safety and reduce operating risks. This requires the alignment of our organization from top to bottom with a consistent set of standards and behaviors. The primary mechanism consistency is our operating management system or OMS, We are continuing to embed this across the organization as a single system to be respected and followed by every operation.
And in human terms, we continue to focus on ensuring that we have a highly competent organization and a deep safety culture where everyone speaks up and takes act necessary. We are rebasing our approach to performance and reward to ensure every person in BP follows these priorities. As I mentioned earlier, we also created a more powerful operational rich organization, which we call S and OR. S and OR will strengthen our standards and processes and has personnel embedded in BP's operating divisions. And they'll be working alongside the line management to guide, advise, scrutinize and if necessary intervene.
The S and O team is confirming implementation of the 26 recommendations from the Bligh Report, approving critical personnel, reviewing risk mitigation plans and overseeing decisions acting operational safety. Let me give you a little more detail by looking at what this means in the upstream specifically. Within the developments division, we've established a centralized global wells team to make sure our wells are safe and compliant. They are working closely with S and OR to advance standards and ensure they are applied consistently. We fired from the incident which we are advancing.
These are prevention, containment, relief wells, spill response and crisis management. We are committing to share what we've learned and we're bringing our capability and knowledge in some cases equipment to groups including the new marine well containment U. S. And we're also cooperating with investigations and supporting initiatives to bring about necessary regulatory change. Now let me turn back to the Gulf of Mexico.
Our Gulf Coast restoration organization is completing its response activities and working towards the longer term restoration of affected areas. BP assumes day to day management of further activities from the and the natural resources investment process is underway. We continue to have a local presence through our offices and staff, and we have supported initiatives such as tourism and seafood testing and marketing to help rebuild the Gulf Coast reputation. And we have voluntarily contributed significantly to independent research and assistance initiatives. This includes investing $500,000,000 in the Gulf of Mexico Research Initiative, as well as other payments and grants.
While this activity continues, you will know that we are cooperating with a series of investigations, inquiries and hearings. And I believe it would be helpful to note some of those activities and the likely timeline. We expect the Presidential Commission will have completed their investigations and published their findings by the end of March, while publication of the final report from the Marine Board is scheduled for later this spring and the Naval Academy of India's report is for the end of the year. Less clear is the timing of the ongoing Department of Justice Investigations which are still expected to take some time to complete. There are currently many active lawsuits against PEA parties and these have been consolidated into 2 litigation proceedings, with most of the cases being consolidated under Judge Barbier in the Eastern District of Louisiana.
Discovery in this case in these cases is ongoing and the Oil Pollution Act test trials may be scheduled for later this year. The limitation and liability trial is currently early 2012. So while there are still uncertainties as to how all of this regressed, we have to be clear on the implications as we move into 2012. As you have seen thus far taken a charge of some $41,000,000,000 against income in expectation of potential liabilities such as those I outlined a moment ago. There are a few key points I'd like to make to investors about this.
Firstly, we believe that the $20,000,000,000 trust fund within the provision provides a substantive facility to cover claims brought by individuals and businesses, government claims, as well as the cost of the natural resource damages claims. Should the $20,000,000,000 turn out to exceed requirements, the balance of the fund will return to BP. Secondly, our estimate of the potential claims under the Clean Water Act, which we expect to be the major category of fine, is also included in the $41,000,000,000 charge as well as response and cleanup costs. Further, as already noted by Byron, we continue to believe that BP is not grossly negligent and have taken the charge on that basis. We would expect to be able to recover a portion of costs from partners, which is not reflected in our provisions.
As far as the impact on the cash requirement of the group is concerned, our commitment to the trust fund is spread over 3.5 years ending in the Q4 of 2013. After we take the amount of cash, we'll be able to provide a balance sheet for other uses. So now, ladies and gentlemen, let me turn the lines of business and I will start with a focus on our up stream business and then Ian will overview refining and marketing. As Byron has noted, 2010 was in fact a year of strong financial performance aside from the Gulf of Mexico oil spill and lower production. However, we realize we have to realize that the Gulf of Mexico oil spill was a pivotal moment for BP and nowhere has this been felt more strongly than in the upstream.
We will be a different kind of company in the stream going forward. With the fundamental restructuring into divisions, the embedding of the new S and OR organization, redefining our performance setting and reward processes, and the systematic implementation of the lessons from the BLY report through our operating management system. We are also taking this moment to make broad strategic change. Our strategy remains to invest for growth, but our emphasis will be on value growth. Going forward, we will deliver this in a number of ways.
We will continuously reduce risk. We will evolve the nature of our relationships with National Oil Companies. There will be increased spend in our high highly value leveraging activity of exploration. We will actively manage our portfolio looking to divest or sell down a portion of our assets. They are more valuable to others than to BD or to acquire where Beattie can create significant value.
And finally, we'll be investing in building our technology and our human growth, it will be deemphasized favor of value. So in this section, I'm going to look at progress in 2010 with an update on the divestment program, a look at the makeup of the portfolio and the picture reserves. Then I'll look ahead to 2011 including our increased program of turnarounds and the outlook for activity in the Gulf of Mexico. And then production and CapEx guidance for 2011. And I'll finish by looking more broadly at the business explaining our framework for growing value and using examples to demonstrate our confidence in the future of our upstream business.
So first, our divestments. I want to be clear on the criteria used in selecting assets for divestment. It was to refocus our own portfolio growth. And second, where assets would be worth more to others than to ourselves, thereby unlocking value for shareholders. This latter point has clearly been demonstrated, I think, as our divestments have attracted disposal proceeds greater than ex valuations and more than twice their book value.
The divestments represent around 15% of BP's current market value and yet a much smaller portion of reserves, around 9%, and ex underlying replacement cost profit of around 7%. In 5 countries, we divested all of our upstream interests, simplifying the portfolio considerably. This means that our management can concentrate on regions where we believe we can grow value in a distinctive way. But we divested none of our inventory of future major projects. So our long term growth potential remains intact.
This slide shows the overall distribution of the asset value in our upstream business. It excludes our shareholding in TNKBP, which I'll talk about later, and it also excludes the Gulf of Mexico, where significant uncertainty for the industry remains. Again, I'll come back and talk about that. There are several important observations on this slide. First, it shows just how much more focused our portfolio has become through the divestment program.
A feature of our value growth story will be to continue to divest where it is clear BP cannot add unique value. We will aggressively pursue the front end of value creation, but we'll be prepared to divest when others can create greater value. 2nd, the chart shows the inherent scale, strength and breadth of portfolio. We have many material multi $1,000,000,000 businesses. 3rd, it also shows us that we have currently smaller positions with significant potential as we invest over the decade.
These include North Africa, the Middle East, Brazil and Canada. And finally, we will be exploring our new basins with the intent of moving them onto this chart in the future. For example, our work in Australia or with Rosneft in the Arctic. A primary driver of value growth is how we manage the flow of resources from access to production. So let's show how resources have progressed to reserves and then to production during 2010.
Year on year, our total resource base grew from 64,000,000,000 to 68,000,000,000 barrels of oil equivalent and our inventory life has been extended from 43 to 48 years. Resource additions resulted in a total resources replacement ratio of 4.8 percent. Proved reserves were down slightly from 18.3000000000 to 18.1000000000 barrels of oil equivalent, but that is after divestments. Excluding acquisitions and divestments, additions ceded production for the 8th consecutive year. Now this chart shows how the resource base and reserves are now distributed.
One point to note is that the portfolio has a bias towards oil with around 65% of oil and 35% gas. We need that oil to capture and maintain our leverage to higher oil prices. And we want to complement that with a sizable share of gas to capture with growth. The quality of our resource base in our subsidiaries is also continuing to improve. Over the last 5 years, we have increased the reserve additions from higher margin areas such as Azerbaijan, Angola, the North Sea and the Gulf of Mexico.
I want to look in more detail at our access success during 2010. We deepened in our existing positions in North Sea, in the Baha field and in the recent U. K. Licensing round, shale gas in North America and Canadian heavy oil. We deepened in Azerbaijan through the Shafaq Azimane production sharing agreement and intend to do so in Angola through 4 new blocks in the Kwanzaa and Benguela Basins.
And we completed our access in Jordan with ratification of the Rishuk concession and access the North Arafura block in Papua province, Indonesia. Importantly, we moved into 4 major new basins. First, Brazil. It had represented a gap in our deepwater portfolio for further growth opportunities there. In the South China Sea, we access new acreage in the deepwater.
In the Arctic, we have just announced our future work in the South Cara Sea with Rosneft. And in Australia, we are pleased to enter the new frontier Sedona Basin. And we had a significant discovery with the Hadua well in the West Nile Delta Concession. Now let me summarize the progress we made in our major projects. All of this activity is now managed by our global projects organization within the developments division, which has created this year to improve the quality of our project execution.
That organization has been our ability. It has also used BP scale to sign 7 new long term global supply agreements. During 2010, we made final investment decisions on 15 projects. A large number of the projects are in the North Sea, Angola, Azan and the Gulf of Mexico. As a result, over 2,000,000,000 barrels of oil equivalent BP net resources are expected to be developed with an expected total capital investment of $20,000,000,000 to bring them on stream.
I'll turn to 2011, provide you with some guidance on volume output or investment. One practical effort of our focus on safety and risk management will be an increase of almost 50% in key areas such as Alaska, the North Sea, Angola and Iraq. All of this is expected to have some short term production impact, around 200,000 barrels of oil equivalent per day during 2011. This is roughly 50% more than in 2010. I have no doubt that this activity will have long term benefits in terms of reliability and is part of getting the foundation right, long term growth.
You will know one of the key uncertainties we face in 2011 is the pace of which activity and getting back work will be restored in the Gulf of Mexico. We are not unique. The industry faces a similar uncertainty. Production in 2010 was affected by the drilling moratorium and will carry over into 2011 as natural reward declines take effect. In 2011, our focus is on restoring rig activity safely.
We have clear restart criteria, which includes meeting all new regulatory requirements, addressing each of the recommendations of our investigations under Mark Bly and compliance with our own standards, ensuring we have the right capability in place along with appropriate contractor management. Exploration rig resuming activity this year, although there is industry wide uncertainty around the exact timing. We also have stakes in activities that are operated by others in the Gulf including the Mars, Ursa, Tubular Bells, Galapagos and Great White fields as well as appraisal focusing on Freedom and Mad Dog North. This uncertainty will clearly affect Gulf of Mexico production overall. And in 2011 we anticipate a further decline before returning to growth in 2012.
But this will depend on the timing of the restart. However, the key point for future value creation is BP's resource base is unchanged and we remain committed to its development. So recapping on what I've covered here. Production values are expected to be lower in 2011 than 2010. That's as a result of divestments, lower production from the Gulf of Mexico, increased Taranak to that is required to improve the long term reliability of the assets.
As a result, these factors reported production in 2011 is expected to be around 3,400,000 barrels of oil equivalent per day. Now of course, the actual outcome will clearly depend on the exact timing of the divestments and the pace of getting back to work in the Gulf of Mexico, OPEC quotas and the impact of oil price on production sharing agreements. The actions we're taking in 2011 will set the foundation for longer term growth. We're increasing our investment and plan a total of 32 project starts by the end of 2016. These will contribute an expected 1,000,000 barrels of oil per day equivalent per day, which will more than offset natural declines.
The scope for accelerated growth from this now smaller base is clear, but our team's focus in the near term is getting the inputs right. We will not compromise the ongoing reduction in risk, reliability, systemic excellently going to be the primary drivers of value. Now to support that growth, we're increasing our investment in 2011 and we expect organic investment in the upstream to be around $15,000,000,000 Our share of investment in TNKBP will be about $2,000,000,000 capital budgets. Now ladies and gentlemen, at this stage, I want to take a step back and explain more about what I mean when I say we're making broad strategic changes to grow value for the long term. I've talked earlier about changes in safety, risk management, the restructuring of the upstream organization and the alignment of priorities and rewards.
We're also evolving the model at what an international oil oil company does. Clearly project scale and complexity requiring access to sensing technology and capability continue to enable our industry's challenges. Deepwater projects are a prime example. We remain deeply committed to this important resource. We are also pursuing new kinds of relationships with National Oil, a major resource.
We don't only competitors, but increasingly as partners when our capabilities are suited to their needs. And those partnerships will take different forms, according to the particular opportunities. BP and Rosneft is just the latest example of a new kind of relationship and I see that as mutual benefit action. This agreement typifies the way that we're following the global trends. Growth in energy demand and economic activity is coming almost entirely from the emerging economies, especially the so called BRICS, Brazil, Russia, India and China.
The other way the model is evolving for us in emphasis from volume to value. Of course, production numbers matter, of course. But we need to see our assets in terms of value and understand how we as a company can best create and realize value in those assets. The focus in value also means that we will actively manage the portfolio and may not always participate in every stage of the life cycle of every project. And so let me show you how this value based approach has worked in one of our key areas, namely in Azerbaijan.
It's an example for many points here, but value can be created at every phase through the exploration, appraisal, development and production of the resources. Our experience in Azerbaijan shows that successive waves of exploration, development, production build on each other, repeating this several times in each basin. Incorporating learnings will enable us to unlock new opportunities and create unique value. There are different points as the value is created where you have options to sell down, partner in other ways that could happen. And arguably the most value creating part of an asset cycle as you saw in previous chart is exploration.
BP is an explorer by instinct and tradition and I think we're good at it. This chart shows our history. We've consistently found more than 600,000,000 barrels of oil equivalent per year through the exploration drill bit throughout the last opening up new plays in Angola, Trinidad, the Gulf of Mexico, some of our key producing areas today. We've also made significant progress in rebuilding our inventory of new plays. And I think this access momentum will continue to build.
We believe it will give us the potential to double our REX spend over the next few years with discipline. There is a choice to preserve the quality of our prospects, which can create the new producing areas for the next decade. We may not choose to take every success through to production and we may use success to bring new strategic partners to join us. And I think that's value creation through exploration. Let me review where we will focus our exploration activity.
Firstly, we'll continue to explore where we have been successful in the last decade in Angola, in Egypt, Azerbaijan and the Gulf of Mexico. 2nd, we will test 5 new provinces in the next few years. These will be Libya, Jordan, Brazil, the South China Sea and in Australia. We see the potential prospectivity of these provinces as a balance between oil and gas. And then thirdly, for the longer term, we'll test the exciting potential of the Arctic continental shelf in the Canadian Beaufort Sea and now also in the Russian South Carouse Sea.
And finally, the Gulf of Mexico. We remain the leading leaseholder and we have a very strong prospect inventory. We hold a leading position in the emerging Paleogene play with 2 significant discoveries in the Cascada and Tiber and a strong prospect inventory to drill out. When I look at the global opportunity set, I'm excited about the big wells that we're ahead of us as we test and drill out this strong portfolio. So moving on from exploration to developments.
We have a deep portfolio of high quality projects. We have made the final investment decisions on 24 projects and a further 10 are expected to reach FID in the next 2 years. We also have seen additional projects which are under appraisal. Let's look specifically at a few of the deepwater and the gas projects. BP does remain committed to the deepwater.
We are the largest deepwater producer amongst the major international and are determined to take the lessons of last year around the world with us and build on our know how and capability. I think we have a responsibility to do this. There are 4 focus areas for our developments organization. 1st, investing in the capability of our people. 2nd, developing new technology.
3rd, developing new arrangements with our contractors. And finally, developing new engineering and operating standards. We're currently progressing 19 deepwater projects in the Gulf of Mexico and Angola with an expected total investment of over $40,000,000,000 and we expect to shortly confirm Brazil in that portfolio. Though oil forms the majority of the portfolio, natural gas is set to be the fastest growing fossil fuel in the next 2 decades and I'd like to highlight 4 particularly exciting projects. In Azerbaijan, the second phase of the gas development projects in the world with the potential to open up new sources of supply to the European gas markets.
In Oman, we are appraising Block 61 using our expertise in tight gas reservoirs. In Egypt, the West Nile Delta project reached a significant milestone in 2010 with the signing of a new concession. And in Indonesia, we continue to explore and appraise potential resources to expand our existing Tengu LNG facility with a 3rd train now underpinned and work underway to identify resources for a potential 4th train. So pulling all this together, here's an overview of the planned start ups by the end of 2016. We plan to start up 32 projects which have the potential as mentioned before to contribute around 1,000,000 barrels a day of production equivalent.
As I said earlier though, there may also be opportunities to create value at this stage of the project's cycle. Turning to the 3rd division of upstream production. We're focusing on 3 areas. 1st, advertising safe, reliable facilities by continuing to invest in integrity and reliability. 2nd, we're pursuing excellence in reservoir management.
And 3rd, we're working on improving the recovery factors from our reservoirs. Our operations in Iraq, I think are a very good example of all of this. The learnings we've gained in giant reservoirs in the U. S, in Russia and the North Sea are now being transferred to the largest field in Iraq, the giant Rameela field. The Rameela operating organization recently met a major milestone by safely achieving its improved production target.
This was achieved through the ramp up in activity that began only in July 2010. Some 10,000 people are now working on Rameela over double the number at the beginning of 2010. In 2011, we plan to continue ramp up activity including a water infrastructure upgrade and engineering for a full field development. And we grew production target means we now start recovering cost and earning remuneration fees. This milestone is good for Iraq and it significantly changes this profile of our Invena.
Now let's take a look at our business in Russia. The relationship between BP and Russia has been forged over 20 years and it is a relationship we intend to build upon. Already we have the largest position of any international oil company in Russia. We have a unique growth oriented position in Russia through our distinctive partnership in TNKBP and the long standing partnership with Rosneft. Let me first provide an update on TNKBP.
Maxime is here, questions later, TNKBP has a very strong onshore production base of which around 70% come West Siberia. This includes the giant Semilore field where we have been applying technology to sustain production for several years. The transition to new greenfield projects began with the start ups of the Verknechand, Uva and Kamenoya fields in 2010. These projects will and in 2010 production growth was up over 2%, greater than the national average. Looking ahead, TNKBP expects to see investment growing at a growth rate of 11% over the next 5 years and production 2%.
Longer term growth will come from the development of new provinces near the Yamal Peninsula. TNKBP is core and Let me now turn to the recently announced alliance with Rosneft. This is a further important step for BP, for the industry, for Russia and for global energy over the long term. This is a long term activity. The agreement to seek a form of joint venture to explore and if successful develop 3 license blocks of Russian Arctic Continental Shelf offers a new opportunity to access a world class basin.
It utilizes BP's exploration skills and leading position in the Arctic region, which includes our 40 year track record in Alaska and drilling off in Russia with Rosneft. The licenses were awarded to Rosneft in 2010 and cover approximately 125,000,000 cubic feet of the sea. This is an area roughly equivalent in size and between a national oil company and an international oil company. And following completion of this agreement, Rosneft will hold 5% of BP's ordinary voting shares in approximately 9% to 10.8%. We have also agreed to establish an Arctic Technology Center in Russia and we've agreed to continue our joint technology studies with Rosneft in the Russian Arctic and we'll seek additional opportunities as we have with TNKB for international collaboration with Rosneft beyond our fifty-fifty joint venture partnership in rural in Germany.
So as we come to the end of the Upstream section, I want to take a moment to highlight the role of technology. It's a common theme running through all the upstream. We continue to exert discipline in selecting the technologies we pursue through our flagship programs. Clearly, technology would be a key input to unlocking long term value. I believe we are an I believe we are an industry leader in seismic both as acquisition and imaging as well as in sand control.
And we've made dramatic breakthroughs in the development of waterflood technology and enhanced oil recovery. These are just a few examples. To sum it up, our upstream business is going through some change as it refocuses to drive safety improvements and operational risk reduction in everything that we do. Our divestment program has created a portfolio which is substantially refocused. We are shifting the emphasis from volume to long term value growth for shareholders.
I think we're good at finding oil and gas and we will take advantage of our growing world class exploration inventory to double exploration investment over the next few years. We have high quality projects capable of delivering around 1,000,000 barrels of new oil equivalent per day by the end of 2016. We will continue to make choices about where we invest and we'll divest if others can add more value than we can. And we will continue to evolve our relationships with large resource holders and national oil companies and we will invest in technology and the capability of our people. Ladies and gentlemen, that concludes my remarks on the Upstream.
So now let me hand over to Ian who's going to talk about our Downstream businesses.
Thank you, Bob, and good afternoon. It's a pleasure to update you on progress and prospects for Refining and Marketing. Given today's announcements, my presentation is divided in 3 sections: firstly, an update on R and M's performance in 2010 in the context of the goals I set a year ago. Secondly, an in-depth description of our portfolio strategy, including further detail on the announcements we made this morning regarding our U. S.
Fuel value chain portfolio and finally, some indication of what you should expect from R and M in the future. So let me begin by covering the R and M turnaround in our press in 2010. Our focus since 2007 has been on turning around R and M with an agenda upon the 5 priorities outlined on this slide. These are unchanged. Safety remains our top priority, and the events of 2010 only serve to underscore this.
Bob outlined the agenda for our safety and operational risk function, and we're in the process of implementing that agenda within R and M. During 2010, R&M's safety performance was stable versus a very good 2,009. Personal safety was slightly worse than 'nine, and Process Safety was better with a 25% reduction in our severity weighted Process Safety incident index, and all of R&M's major operations are now on our operating management system. Organizationally, we continue to invest for the future, both in capability and core processes as we consolidate the operating model. Most of my presentation today relates to the last three priorities, the implementing's momentification and our efforts to improve our efficiency.
I'd like to begin with 2010, starting with performance. Used for 4 years now, the chart on the left shows our post tax ROCE versus the superannuation of the year estimated on a consistent basis. Having closed the gap in 2,009, we estimate BP has remained near the top of the competitor set and absolute levels are improving. BP's ROCE in 2010 on this measure was over 8%, a significant improvement in 2018 and an improvement of 2 percentage points versus 2,009. On the right, for 2 years, BP's Downstream has outperformed in terms of net income per barrel of refining capacity.
As I said last year, we are not focused on being the largest player in our businesses but have hold the highest quality portfolio and operating it well. I believe this is beginning to show through in our results. Turning now to earnings momentum. This chart shows 2010 pretax underlying RCP of €4,900,000,000 versus €3,600,000,000 in 2,009. M since 2006, but in a considerably worse environment.
By our estimates, the margin environment was slightly better than 2,009, giving €500,000,000 of the improvement, with the other €900,000,000 coming from underlying performance. This improvement is about half of the goal to improve pretax profit by over €2,000,000,000 a year by 2012, which I set out last year, indicating that we're making good progress. You can also see that the total underlying pretax improvement since 'seven is now approaching $6,000,000,000 per annum. So how have the different parts of the portfolio performed? This is a usual breakdown of profits and operating capital employed between fuels value chains and the international businesses, including history back to 2,007.
In the fuel value chains overall, profit has improved by $500,000,000 In fuels marketing and supply, earnings were down 1,400,000,000 driven in large part by very poor oil trading performance and also the marketing impacts in the U. S. In the aftermath of the Gulf of Mexico oil spill incident. Refining posted a profit for the first time since 2007 and improved by $1,900,000,000 year on year. This was mainly due to the timing of the refining solomon availability was 95% in 2010, the best level since 2004.
Throughputs were up 140,000 barrels a day and utilization rates declined and significantly above industry averages. Refining returning to profit in 2010 means we've achieved another important milestone of refining becoming breakeven in an environment similar to that of 2,009. In the international businesses, earnings improved by $800,000,000 The largest contribution to this was in petrochemicals. Even though margins were only slightly up versus 2,009, demand recovery and new BP capacity coming on stream drove a 23% improvement in production, and total costs were maintained at 2,008 levels. Lubricants and Cool Fuels also had another good year with further expansion of growth in and good cost discipline driving double digit earnings growth.
Returning then to the segment level and looking at 2010 through the three themes of improvement I outlined last year, which underpin the €2,000,000,000 per annum goal. Starting at the bottom with growing margin share. We delivered considerable growth in the international businesses, offset by oil trading, so we actually went backwards on this measure in 2010. We made significant progress in both repositioning cost efficiency and from portfolio quality and integration in the fuel value chains through better operations, higher utilization and better optimization of the integrated margin. We're ahead of our plans on both these dimensions.
The cost efficiency improvements were from across the portfolio with large contributions from refining efficiency gains, business continuous provision. Last year, I described our goals to improve refining efficiency without compromising our investment safety and plant integrity. This is an updated chart showing our goal for 2012 in Orange and the progress we've made in 2010. We remain on track with our plans for refining efficiency. The efficiencies have come largely from improved planning and execution of all types of work, improved contractor management and sourcing of goods and services.
Looking now at cost efficiency overall, the green bars show costs indexed to 2,004 levels with turnaround costs split out at the top. The yellow dot indicates costs normalized via ForEx and turnaround levels, and as we're now growing volumes, additional manufacturing variable costs. As you can see, we've now reached our goal of 2,004 cost levels on a broadly like for like basis. We're looking to drive to improve unit cost efficiency, but as we've now planned large portfolio changes, comparing absolute costs with a 2,004 portfolio will no longer be useful. Looking forward, our turnaround costs are expected slightly higher than Ridge in 2011 and 'twelve.
I'd now like to turn briefly to refining margins. Byron has described our intention to move to a new refining marker margin or RMM. Details are on the BP website. Our expectation continues to be for margins to remain in a range more reflective of pre-two thousand and four levels. Taken with the recent realities of 2,009 and then, our forward plans are currently based on an RMM range of $8 to $12 a barrel.
As with GIM, there's a good correlation between this new marker margin and R and M's pretax RC profit as indicated by the dark green line. The Jan over €2,000,000,000 per annum improvement goal by 2012, and I've plotted 2010 on the same basis, showing the €900,000,000 of improvement in the 1st year. Finally, a word on investment levels. The black line indicates CapEx. The green bar is net investment with the dotted blue line depreciation.
In 2010, CapEx was $4,000,000,000 and proceeds from divestments of about 1,800,000,000 leading to net investment of 2,200,000,000 and in line with depreciation. On average, for the last 5 years, we have also net invested in line with depreciation. With strong operating performance and investment discipline, R and M delivered material net cash flow back to BP in 2010. For 2011, with the current portfolio, you can expect CapEx to be slightly higher than in 2010 with a slightly lower level of proceeds for investments. The chart excludes any proceeds from the U.
S. Divestments we announced today. So I'd now like to summarize the financial results of the portfolio to 20 10, which provides the context for the portfolio decisions we've made. This slide shows profit and return on employed, both pretax for the major constituent parts of NEM. For each asset class, both 2,008 2010 are shown.
Capital employed is reflected in the size of the bubble. The chart is not adjusted for environment, and refining margins fell from an RMM of nearly $16 a barrel in 2,008 to about $10 a barrel in 2010. You can clearly see the quality of the international businesses in Orange, with absolute profit increasing by $2,000,000,000 over the last years and pretax return on operating capital in the 19% to 33% range. These businesses are also capable of material growth. Indicated in yellow, the earnings in the Eastern Hemisphere fuel value chains have fallen back by $1,300,000,000 due to lower oil trading contribution and lower refining margins, materially offset by underlying improvements, delivering profit in 2010 of nearly $2,000,000,000 and returns of over 10%.
We have plans in place to further improve their performance. Facing these same factors, U. S. Fuel value chains in green made very significant progress, improving by $1,900,000,000 and moving into a breakeven situation. This is a considerable achievement and has been done while delivering materially improved safety performance.
This represents the huge efforts of a very dedicated however, the reality is that in a 2010 environment, the U. S. Fuel value chains remained breakeven. I therefore like to turn to the second part of my presentation on strategy and portfolio. The backdrop to our strategic choices is one of flat to decline demand for fuel in the U.
S. And Europe, with decline of fossil fuel demand accelerated by the penetration of biofuel. It's also in the context of significant growth for fuel, lubricants and petrochemicals in the emerging economies. For the last 18 months, we've been considering the future performance potential of the whole portfolio in both relative and absolute terms. In addition to meeting strategic hurdles such as configuration and market location, integration and growth potential, we also expect our fuel value chain businesses to reach returns above cost of capital at the bottom of cycle conditions and to make a material contribution to BP over time.
Although we've concrete plans to improve further all parts of the U. S. Fuel value chain portfolio, parts of it fail the strategic hurdles and current performance does not meet these financial goals. This is the backdrop to the decisions we've announced this morning. Our portfolio strategy in R and M is now to reposition the U.
S. Fuel value chains, halving U. S. Refining capacity improve the fuel value chains in other geographies and access associated growth and continue to grow the high quality international businesses. As indicated here, there are many active elements underpinning this strategy.
In the U. S, we've reached some major decisions. As announced, we intend to exit the Texas City Refinery and exit the Southern West Coast fuel value chain, including the Carson Refinery. We will continue with our plans for the rest of the U. S.
Fuel value chain portfolio. Our plans for both the Eastern Hemisphere value chains and for the international businesses are unchanged, and I'll provide that in a moment. Starting with the U. S. And with Texas City.
The Texas City Refinery is a very large scale asset with a highly complex gasoline oriented configuration. It's the 3rd largest refinery in the United States capable of producing about 3% of U. S. Gasoline production. It's improved its performance in safety and operations significantly and financially by some $2,500,000,000 per annum over the last 3 years.
This has been achieved under the most intense scrutiny, and I want to thank and congratulate the team most warmly for that achievement. However, Texas is not strongly integrated into BP's marketing assets and so fails the hurdle of integration and has limited logistics and tankage flexibility. BP would need to increase the footprint around Texas City to improve this. Strategically, we therefore have concluded that it should sell Texas City and exit before 2012, subject to legal and regulatory approvals, including satisfying the authorities regarding the future fulfillment of our obligations at the site. We have received a number of inquiries from CANT operators relating to Texas City.
Turning now to the West Coast. In reality, the West Coast has 2 value chains with a limited degree of overlap between them. In the South, BP has a fuel value chain with Carson Refinery at its core and high marketing shares in Southern California and related marketing VADA and A. However, the refinery has littered feedstock flexibility, is gasoline buying and will require investment in logistics and or configuration to improve this. While this business has material potential for improvement, which we are pursuing, it will also require investment to take it to a new level of capability in a highly competitive market.
Given our plans elsewhere in the U. S, we've therefore decided to exit the Southern Fuels value chain and intend to complete this transaction also by the end of 2012, again subject to relevant approvals. Again, I wish to thank the team for their considerable efforts and achievements in safety and the operational and financial performance improvement to date. Our Northern position, by comparison, has the relatively modern 1970s Cherry Point refinery at its core, which is jet fuel and diesel fuel biased and into which we're making further investments to ensure it remains the leading refinery in the Pacific West. The refinery is better located and more feedstock flexible, being both pipeline connected to Canada and also closer to A and S Supplies.
The financial performance and integrated margin are further than the south and will meet our criteria. As a result, we intend to retain the northern part of the West Coast as part of a U. S. Fuel value chain strategy, which focuses on feedstock advantaged, product flexible, highly upgraded, well located refineries integrated into advantaged logistics and marketing. The West Coast will halve BP's U.
S. Refining capacity and significantly improve the current financial performance of the U. S. Fuel value chain portfolio. We're also investing to improve the Toledo refinery with our Pusqui and continuing to transform Whiting Refinery.
The Whiting project shown here is making good progress. As the chart shows, this is a very large and complex project, and it's now about 60% complete with all major lifts of key units completed in 2010. The project start up has now been deferred slightly from late 2012 to mid-twenty 13. This chart is a version of 1 I used last year, showing indexed pretax profit per barrel in the Midwest against refining margins on the new RMM basis. The yellow dot shows end 2010 conditions, indicating that even at relatively low margins, this project is expected to deliver approximately a threefold improvement in profitability and will contribute materially to improvement in our U.
S. Fuel value chain position overall. This comes from an increased ability to run heavy crudes, improved product yields and location advantage relative to the Gulf Coast for Canadian crude.
So where
do these major portfolio changes leave us in the U. S? Post-twenty 13, we'll have half the refining capacity of today, more diesel capable than BP's current portfolio. All of them have access to advantaged focused logistics and are integrated with marketing operations to support high utilization rates. Our import led terminals and marketing on the structurally Short East Coast are also very well positioned.
Although smaller, we believe this portfolio will be competitively very advantaged in the United States. I'd now briefly like to turn to the Eastern Hemisphere fuel value chains. This portfolio focused mainly around the Rhine, Iberia, Southern Africa and Australasia is comprised of well located integrated refining, which is generally of a high competitive quality and strong marketing positions. We've been with the exits in France, planned exits of marketing in 5 Sub Saharan countries and the sale of non core terminals and marketing assets. This portfolio has material potential for improvement and growth, either through market growth, margin growth or new access.
In terms of market growth, we're seeing continued profitable fuels volume and gross margin growth in China, Australasia, Turkey, South Africa, Poland and Iberia and opportunities to grow convenience retail in the Rhine geography, Australasia and the U. K. Unit margin growth is expected largely to come from configuration improvements to our refineries and from some structural efficiency programs. The configuration of Rotterdam, which will be BP's largest capacity refinery post exit of Texas City, has scope for upgrading, and we are currently evaluating options, including investment in a hydrocracker. Gelsenkirchen also has an projects being evaluated to improve an already excellent refining position.
Finally, in terms of new access, we continue to progress options to build on our other positions in Asia. To complete the fuels value chain picture, where will we be positionatively in refining after the changes we've announced and outlined today? This shows the Nelson complexity and average scale of BP's global refining portfolio post-twenty 13 relative to the current position. Post divestment of the two positions in the U. S.
And the transformation of Whiting, our average scale and complexity are both slightly lower than today, but still in the pack with our leading competitors. This is before any further upgrading of Rotterdam. Perhaps the biggest implications of the announced moves will be simply that BP will be the smallest refiner of the 2 supermajors at just under 2,000,000 barrels a day of capacity. And the proportion of BP's capacity in the U. S.
Market will fall from 50% of the portfolio today to just over onethree. That concludes my remarks on the fuels value chains. I'd now like to turn to the international businesses. Our Lubricants business has been growing rapidly and also delivering excellent returns for a number of years. I want to explain sources of growth and why we're confident it will continue into the future.
On the right hand side of the chart, you can see that the profit from our land based lubricants activities has grown significantly since 2,007, with an annual growth rate of well over 20% per annum. The proportion coming from non OECD geographies is about half of the total or approaching half of the total, providing a long term engine for volumetric expansion of the business. Together with delivery of structural cost efficiencies, this has helped drive particularly high growth rates recently, but we do expect to continue to see something approaching double digit profit growth well into the future from volume expansion and mix improvement underpinned by a strong technology pipeline and powerful brands. In terms of margin, a healthy product pipeline and the right product mix are key. And you can see on the bar chart underneath that the proportion of higher margin synthetic and premium sales is materially higher than the market average.
Finally, the rapid expansion of the business has not been at the expense of returns. While delivering material growth, over the last few years, lubricants returns have risen to levels in line with smaller but high quality competitors, reaching top quartile return on sales compared to the consumer goods sector in general. Our strategy is to leverage technology and know how, the Castrol brand and strong marketing capabilities to access new market growth while also enhancing the margin mix of our product portfolio. The lubricants business is a great success story for BP and a major contributor to expected overall growth rates. Turning now to Petrochemicals.
This slide shows the geographic locations of our main plants. As you know, our focus is on aromatics, being PTA and paraxylene, acetic acid and olefins and derivatives in China. Beyond delivering safe, reliable and compliant operations are our pillars: accessing growth in Asia leveraging our superior manufacturing technology and efficiency to contract for further sales volumes, ensuring our plants in the U. S. And Europe operate at high utilization rates thirdly, managing fixed costs to ensure industry leading returns by continuing to invest in technology and capability for the future.
Our production has been growing by about 3% per annum since 2004, as you can see from the bar chart at the bottom of the slide. This growth has almost exclusively been principally in Mainland China. Our Asian production has nearly doubled over this period and in 2010 was about equal to that of the U. S. And Europe combined.
We've many projects under evaluation for further growth in China, the Middle East and in India. Profit growth has also been material, with the majority now coming from As indicated in the pie chart, you can see at the bottom right of the slide. Once again, this growth has not been at the expense of returns. The chart on the left shows the high level of BP's return on sales versus the competition. The petrochemicals business is a core operating portfolio and a key component of future growth and returns.
So in the final part of my presentation, let's now turn to what you should be able to expect from R and M post 2013 when we should have completed the changes to the portfolio I outlined earlier. Returning to the earlier format, but now looking at post-twenty 12 performance for a range of refining margins similar to an RMM of $8 to $12 a barrel. You can see that the fuel value chains in both the U. S. And the Eastern Hemisphere are expected to be of a solidity, delivering 10% to 20% pretax return on operating capital, but with the U.
S. Portfolio smaller than that of the Eastern Hemisphere. The international businesses are expected to continue to grow and to deliver pretax returns in the 20% to 35% range through the cycle. Taken together, this means that from 2013, all asset classes should be delivering absolute returns, which are attractive, while also being material. That deals with returns and materiality.
Finally, it's about growth. This slide shows in the green bars the pretax earnings of R and M normalized to a 2,009 refining margin environment. The earnings growth has not surprisingly been very high at over 50% CAGR during the recovery period from 'seven-'nine and is projected to be about 15% to 20% per annum during the quarter. This represents a material source of earnings growth for BP over that period. Longer term, with the investments in Whiting, planned enhancements to margin capture and some growth in fuels value chains and the strong growth potential from the international businesses, we would expect the whole portfolio to be able to deliver sustainable and attractive long term growth to BP.
The red line on the chart shows the recent improvement in returns. Longer term, with the improvements I've outlined, we would also expect the portfolio to be able to deliver attractive pretax returns well above the cost of capital. So to summarize, R and M has had another successful year. Safety has been and will always remain absolutely the top priority. We can deliver over $2 per annum of pretax RCP improvement by the end of 2012, and we had a good start in 2010.
Like for like costs have returned to 2,004 levels, and refining achieved its goal of becoming breakeven in a similar environment to 2,009. In terms of portfolio, our goal remains quality before quantity. We have announced some major changes today. In the U. S, we'll exit Texas City and the southern part of the West Coast while continuing to invest in Whiting and the other refineries.
This will halve our U. S. Refining capacity and reposition the portfolio. Globally, BP will become the smallest refiner of the traditional supermajors. In the rest of the fuels value chains, we'll continue to enhance margin capture capability and access available growth.
And in the international businesses, we'll continue to see material and sustainable earnings growth and the delivery of highly competitive returns. Taken overall, in the type of environment I've described, you can expect R and M post-twenty 13 to be capable of delivering sustainable growth to BP with attractive returns well above cost of capital and material earnings and cash flow to the group. Thank you for listening, and let me now hand you back to Bob.
So thank you, Ian. Now before closing and summarizing, let's take a look at the highlights of our alternative energy business. You saw earlier our view on the demand for energy to 2,030. Renewable energy will be the most rapidly growing category. BP has developed a very focused portfolio of assets in this rapidly growing low carbon energy market with a total investment of more than $5,000,000,000 since 1,005.
And due respect to invest a further $1,000,000,000 in 20.11, as we believe that as a leading energy company, we must participate in this future growth. Our biofuels business will continue to be a strategic priority for BP. It is a rapidly growing sector with the potential to supply 5% to 10% of all oil transportation fuels by 2020. We plan to expand our Brazilian operations. Our advantaged Brazilian sugarcane production compares well against all other non conventional supply sources.
The supply costs of this are around $50 per barrel of oil equivalent. We're also developing a position in the Southern or southeastern U. S. For the production of lignocellulosic ethanol. And U.
S. Regulatory support for this new fuel remains strong and we expect to sanction our 1st commercial facility in the next 12 months. Additionally, we're advancing technology for biobutanol production through our joint venture with DuPont. Our other areas of focus is low carbon power. We now have 10 operating wind farms of scale in the U.
S. With a gross capacity of 1.3 gigawatts. It's business cash positive and other wind farms will follow. In summary, we are maintaining progress across our focused alternative energy portfolio and we will continue to build out our asset base in step with this rapidly growing market. Now stepping way back.
In summary today, I hope you see that BP is a changing company as a result of what happened in 2010. I believe the changes will be for the better. These are not just words. You can see that from our actions which are highlighting on this slide. We will meet our commitments.
We are investing for the future. More investment in safety and risk management, more investment in the emerging economies and more investment in our core strength of exploration, more investment in new projects and investment in strategic partnerships, more investment of the drivers of long term value. And yet at the same time, we are not afraid to divest non strategic assets, both upstream and downstream, if that's the best path. And we believe we can prudently restore a dividend stream to our shareholders. We're a company building on its strength and addressing its weaknesses.
It's a safer BP, an agile BP, a stronger BP, a company that is committed to rebuilding value and trust for the long term and doing it well. Ladies and gentlemen, that brings our presentation to an end. Thank you for listening so very patiently. We'd now be pleased to take questions from you here as well as we have quite a number of people on the web and on the telephone and we may go back and forth between them. So let me start, this gentleman right here on the end and then this lady's second.
Thank you. Good afternoon, gentlemen. Tapan from Morgan Stanley. Could you talk a little bit about capital intensity? It seems capital intensity is on the rise.
I was wondering if you could sort of maybe help reconcile the split between the increasing costs around safety, the assumptions you're making in terms of cost inflation for the industry in 2011. And then you know how much emphasis there is in terms of growth CapEx? And I guess you know the follow-up question there is where in terms of a new BP resetting the portfolio, I think you've talked about upstream value growth. Where do you see capital intensity for BP going, particularly in the context of the peers?
Well, clearly this is a year of consolidation for BP. This is a year for us to get back on our feet, complete the divestments that we have. You'll see that we are not divesting any of the 32 major projects that we have coming forward. Some of the timing on the capital intensity will depend on the restarts in the Gulf of Mexico. But you've seen major capital programs in the North Sea, Angola, further on in Azerbaijan.
And I think part of this year is for us to pace the divestments, pace the startup of the projects. And this is one of the things that we're we've had a lot of strategic debate inside the company about whether we set volume targets and the pace of course those volume targets. And of course, capital intensity and the capital that we progress in these projects depends on some of the decisions that we might have on whether or not we sell down parts of that development chain that we have. So it's hard to give a number today. This is the 1st year I think of BP coming out of the crisis year in 2012 and resetting.
And we'll have more guidance for you in the future on that.
Thank you. It's Irene Himon at Societe Generale. I had two questions, please. So first, Bob, you're shifting emphasis from volume to value. Can you give us a sense of the metrics that you would like us to use as outsiders to measure that value?
Is it margin per barrel? Is it return on capital? In which case, are there some explicit targets on those metrics? My second question on the issue of safety. Obviously, your predecessor had spent his 3 years in the position overhauling safety.
Having turned it upside down yourself, can you give us a sense of how big the gap is between BP on that issue and perhaps the best in class that you're striving to reach? And how long it might take to get there? Thank you.
Well, I knew people would ask about the exact metrics of volume to value because of course, the oil industry has very often set volume targets out there and that's a simple metric. And what we're saying portfolio projects that are coming on stream that we think can add 1,000,000 barrels a day equivalent by 2016, which will more than offset natural declines. But we're also signaling and we're not going to give a figure of that yet because it depends again on the restart times in the Gulf of Mexico for us and many in the industry. But what you'll see over time is maybe some decisions to take steps where the volume won't be important. We may be able to unlock parts of that chain.
So I think to be honest, the long term what we're going to do is create value by both combination of returning value to ships could be through dividends, could have if depending on the improving fortunes of the company down the road, it could be share buybacks or it could be divestments. It will be a mix of these things and that will all manifest itself in time in the value of the company. In terms of how big the gap is on safety, we know that we've learned many things in the last year and we know that the industry needs to learn many things from these events in the Gulf of Mexico. We have made significant changes in our organization that are now being moved all the way down through the organization. We take some of our best operating people that now work in the safety and Operational Risk Organization.
You saw the charts on the trends of BP's results on safety over a decade. The broad general trends track industry benchmarks over the decade. But we're we should not sit here today and make any comments really about the future with safety. We're going to have to prove that by the way we operate our assets And we're putting in place all of the organizational structure, the techniques, we're bringing in expertise from the nuclear industry, the hazardous chemicals industry into the company to help us make sure we've looked at things right. I think these are the things that you should expect us to do, but we'd actually rather speak with our lack of actions in terms of incidents rather than words going forward.
And this will take time. We've got to rebuild trust and faith in the company, we know that. One here, this gentleman. And then I'll take a couple of questions from the web.
Hi, it's Ian Reid from Jefferies. Bob, if you look at this presentation, you've moved the production growth numbers back a year based on a pretty similar set of new start ups. How confident are you that you're really going to be able to get back to work in the Gulf of Mexico on the time frame, which seems to be just a year, if you like, in terms of total delay? And how confident are you that BP won't be, if you like, singled out for perhaps slightly more restrictive actions when it comes to approving your project?
Well, Steve, the Gulf of Mexico is just one area that we have in terms of this portfolio of major projects. So that part of our portfolio in the industry has been pushed back. We've got a very, very large pipeline of projects there as you saw. I do not believe that BP will be singled out for special treatment in the Gulf of Mexico. We are cooperating today daily with the regulators in the United States.
Lamar McKay who is here is in contact daily with them in multiples. I don't have the sense that BP is going to be singled out. We of course are going to hold ourselves to a high standard and not go back to work until we are clear that we are ready to go back and ready to go back drilling with our own standards as well as the regulatory standards. I think that the investigations and multiple investigations have come out and said that this is an accident, highly, highly low probability accident that 7 barriers failed, very low probability that involved multiple companies. And the industry has a lot to learn about that.
It's going to change the way we do business. We already know it's changing the way many oil companies are looking at these operations. But I remain confident. BP is committed to doing business in the U. S.
We're committed to our resource base in the Gulf of Mexico. It's a very high quality resource base. Jason, and then in behind, Jason.
So it's Jason Kenney from ING. I've got a kind of conceptual question really just to better understand your renewed focus on value. If we could pretend that Macondo had never happened, could you have envisaged AXA 5 18 months, which is what you're doing, in order to unlock value for shareholders? Or would you have not seen that pressure unless Macondo had happened? I'm just trying to understand the drivers behind why you can see value now, whereas you didn't try this process maybe 2 years ago when there was the beginning of a seller's market?
Well, Jason, you're right in one sense. The Macondo incident created a liquidity issue for BP that caused us to respond. And we responded and Byron's team responded incredibly quickly to go out and divest assets that achieve prices that quite frankly surprised us to a degree in terms of the competition for buyers. And I think that market is still out there. We've got $8,000,000,000 worth of upstream divestments that we have we're still we've identified and we'll be working on.
We haven't had nothing around that. And events like 2010 are inflection points in the sense that they do change what you have to respond. It's a response to the challenges of 2010 that has led us to do things that has made us realize that there are different ways of unlocking value for the portfolio. Same thing I think may apply to the decision that we've made with Ian and our downstream businesses to consider divesting significant footprint of our American refineries.
Jason, if I could just add to that. A lot of these assets were being held in order to shore up the underlying production volumes of the group and maintain production levels close to 4,000,000 barrels a day. There was nothing inherently wrong with these assets except that they were mature. They were they didn't have the longer term growth prospects that the assets we've retained do. And they added a lot of complexity because of their size and their geographic breadth.
We're exposing of them and into a very lucrative sellers market
at the current time. Question behind and then I'm going to turn to the U. S. With some phone questions.
Yes. Thanks, Bob. It's Lucas Hermann at Deutsche. Just following on from with value, I just want to better understand what value through exploration means for you because every year we're shown the hopper and the hopper gets larger, but the production barrels haven't. And it's not struck me that you're an organization with excess capacity and that you're not actually using your engineers to the extent you wouldn't.
So does value through exploration and putting more money into exploration also tie back to that comment of effectively churning the opportunities more aggressively and more frequently, high grading your own opportunities, exiting other opportunities that you may discover with the drill bit. Basically, quite what does it mean because you look at the funnel and if anything, value is bringing barrels through more rapidly and that simply hasn't happened in this company and many others in the industry. That observation is not directed at BP alone.
Well, as many say, you look at the independent oil companies, many of the smaller independents, they create a lot of value through exploration, easing and finding something, appraising it or sometimes selling after a discovery or sometimes after appraisal. That's the sort of thing that we haven't done before as a company. So being able to step in and consider at least the potential creation of valuation value exploration drill bit. The other thing I think that a portfolio like that gives us in terms of creating value is we have a wide set of assets exploration developments and the opportunity now to partner with national oil companies and other resource holders to open up new strategic options for us in other ways that are different. Using that, for example, in Germany with rural, for example, we could have sold that asset.
Instead, we joined with Rosneft in partnership in Germany, which is I think helped create an alliance that has now opened up other opportunities for us. The divestments that we've done in Venezuela and Vietnam with TNKBP, they will be able to add more value to those assets through our divestments. These I think are strategic steps we've made to unlock value that we wouldn't have otherwise had and created value for TNKBP. I think we're good explorers. I think Mike and his team and the prospects that we have and the continued attention we've had from governments around the world who now would like us to work with them because they believe that we have learned a hard lesson in the Gulf of Mexico.
They'd like to have us bring our expertise, advise them on regulation and what you can term prevent and spill response is actually opening up opportunities for us now. And you have seen in some of the things that have happened in the last 3 months, that's been a factor in it.
Do you have the prospect inventory to double your exploration spend at this time and sensibly double that spend rather than spend twice the amount because you can't.
Well, you're absolutely right. You hit on a key point of discipline in exploration spending, and this is not going to be an overnight increase in exploration spending. I mean, Mike and his team have a very disciplined approach to exploration. But I think we have constrained that for some time. So we will migrate up to a doubling in exploration spending and certainly not overnight.
But there's a very good inventory of exploration prospects. And we're not going to start drilling any of those until we are ready in terms of the rig capability and are working with the contractors to our satisfaction anywhere. Yes, let me I have a question here from Joseph Tovey from Tovey and Company. Are we hooked up to be able to take that question?
I hope so.
We can hear you loud and
unfortunately. But we're enjoying the snow and I hope that results in good sales. I did want to say that by starting my comments that I very much appreciate the clarity and the specificity that's been provided. It's very helpful indeed. I was just had several questions.
The disposition of or the planned disposition of the California refinery, the Carson refinery, is that also a comment on long term view with respect to the California economy and the regulatory?
Scene? Well, I'll just give a simple answer, which is no, but then I'm going to let Ian expand on that.
Sorry, Jim. I was expecting a list there. So I mean, as Bob says, it's not to do with that. There's a combination of things. As we outlined, the fundamentals are changing.
And I believe in the U. S, our industry is going to have to make choices, and there are going to be winners and losers. And for people to win in the integrated business, they're going to have to run integrated businesses built around highly upgraded refineries and that they need to be well located and flexible. For most refiners, they're going to have to upgrade them still further to achieve that, and they're going to have to invest in the logistics and marketing to do that. We are already investing significantly into Whiting and the East of the Rockies, into Toledo with our partner Husky and into Cherry Point.
And as we balance all the various pressures and when we look at fundamentals and the economic performance of the businesses today, we've concluded that we will not be able to spread ourselves so thinly as to invest in all of the assets to upgrade them, and we are choosing to do so in the ones that are most strategically advantaged. So it's a strategic decision to do with the Californian economy or the regulatory issues.
Moving right along, if I just might, is it your anticipation that the biofuel issues are going to impact upon gasoline marketing and the gas and the refinery situation with respect to gasoline more than it will affect diesel and other motor fuels?
So yes, clearly, we predict longer run biofuel penetration of 5% to 10% of the worldwide gasoline pool, probably the whole fuel pool eventually, think that bio penetration will have a pact on demand growth for fossil fuel, which again says you got to focus on quality. And in certain regions, I think it will impact it more. And that does play into why we want to build out the Cherry Point refinery for diesel and jet capability and why we're choosing to invest elsewhere and divest the southern part of the value chain.
And the last question, if I just might. I noticed that you're expanding Rotterdam at a time when there seems to be at least a 15% overcapacity in North Atlantic refinery capacity. Is am I missing something obvious?
Well, you are slightly in that I can't actually decide to expand it yet. That's exploring what we might do to improve it. It isn't expanding the capacity, and I think this is a really important point. This is not a quantity game anymore in Europe and the U. S.
It's a quality game. So what we're looking after here is Rotterdam is exceptionally well positioned. It's tied into our integrated business through the Rhine line, And it's about upgrading the margins and not increasing the and looking at increasing more diesel and less gasoline. And I think that's the right approach.
Thank you very much. Appreciate the help.
Thank you, Joseph. Let me ask John in the back. I'll go back to the web. We have a lot of questions.
Yes, thanks Bob. I've got 3 questions if I run through all 3 and maybe you can choose how much order to answer them. The first is just on the trading. Look, referencing your comment about $4,000,000,000 down on trading and also retail that maybe trading in 2010 was down $1,000,000,000 or more. How much of that would you expect to come back or are there some structural changes in the market that you think won't all come back?
The second is on buybacks. I mean, you've talked about value and clearly decisions will be the value of your shares. And in the past, and I think some of your competitors talk about share buybacks as a flywheel, essentially it's almost like a blind buyback that references the spare cash that sits on the balance sheet. Are you going to be a bit more nimbler about the decision between reaspying back your stock? And the third one is, I'm conscious I sit here.
I'm looking at one of the UK's largest companies with only 3 executive directors facing me. And that's quite unusual even by historic standards at BP. Is there a prospect that the Board, certainly the executive side of the Board will be increased over time?
Thanks. Byron, you want to comment on the trading and buybacks? I'll comment
on the third question. John, as I said in my remarks, it's the long term performance from the supply and trading organizations whether it was on in the year. And we wouldn't expect that the sort of outturn we saw in 2010 would be something that would be would pursue into 2011. I also pointed out 2,008 and 2,009 were particularly good years. So you're kind of seeing from the top end of things down to relatively weak performance and one needs to calibrate in line with both of those dimensions.
So, the we'll continue to describe the trading performance whenever it's a material deviation from the norm on a quarter by quarter basis. And as I said, we're taking steps to ensure that the cost structure is right and the focus is aimed at, these will add value to the firm. As far as buybacks go, since I've overseen the majority of those buybacks during my tenure as CFO, I think it's premature for us to be talking about how we would go about it given that we just restored the dividend as of today. If we find ourselves in a situation where the appropriate thing to do to add shareholder value is to distribute some of the cash via share buyback program. We'll certainly be cognizant of some of the errors that have made by firms in the past.
And I think I would add on the buyback point is that the company with its dividend level had moved itself where it was somewhat dependent on the high price of oil to maintain. And then during the commodity price cycles, it had there was a period there where they had to borrow to pay the dividend. We really don't want to get back in that sort of range again. And there's an opportunity to both increase the dividend depending on the changing fortunes of the company or consider buybacks. We do have a period of time to continue for the trust fund in the U.
S. So as Byron said, it's a little early to talk about buybacks. On the Executive Director role, there's 3. I don't think that's actually that unusual. But our Chairman is here.
You may want to comment Karl Henrik, but I think it isn't that unusual in companies in the UK in terms of the number of Executive Directors, but that is clearly a decision for the Board to make. Do you care to no? Okay. Thanks, John. Let me ask Pavel, well, Johnoff is on the phone with Raymond James in the U.
S.
Thanks very much. Two questions if I may. First on the refinery sales, you mentioned that 2010 was actually the 1st year of profitability in number of years for your refining business. And yet now is the time that you're looking to sell it. I guess, what is it right now that inclines you to sell it into what is really more of buyer's market, finding assets, waiting for improvement in the business?
Well, thanks Pavel. I mean, I think but basically, we've come to the conclusion that the outlook for refining margin is going to be similar to pre-two thousand and four levels rather than the brief period during 'five to 'eight when we thought that it was Christmas, this business is oversupplied. And therefore, it's, again, I repeat, a quality game. So this isn't about just suddenly deciding to get out. It's we're going to stay in the business, but it's about quality.
The reason we've decided now is because we've concluded what we think the outlook looks like. But also, very importantly, as I outlined before, we've concluded that we have to focus, and we have to focus in the most advantaged positions. And having got Texas City and the West Coast back into a place where they can be profitable in this type of environment, they are now very saleable ongoing concerns, and it seems they're right.
Sean, 10 ks, clearly, there is some disagreement between you and your partners regarding whether the Ross Neft alliance is consistent with your contractual obligation under 10 ks. Just looking to get some color for you, on this
issue. Yes, I think well, in fact, as I'm sitting here, we just received some news, good news. I think it's there was an arbitration hearing about a few hours ago on TNK and the Ross Neft transaction. And the court has ruled that we should move to an expedited tribunal process to be resolved by February 25. This is good.
I think that this is something that will be resolved in a very reasonable business between the line. Maxine Barsky is here today from TNKBP. Edouard, who did not talk to the team or here from Rosneft. I think I would watch again. I wouldn't read headlines, I just watch and see what happens.
And I think this will be resolved.
One more quick one on 10 ks if I may. Are you still looking to move to an IPO of the company in the next few years?
Well, that's up for the Board of TNKBP to talk about. It's been discussed for a number of years. Maxime, if you want to comment, you're welcome to. But I think this is something that the Board from has been considering. But as far as I know, and I'm not on the CNKBP, this is not an immediate agenda item for the company.
Is that fair? Maxime is here and saying that's correct. But anything is possible.
Oswald Clint, Sam for Bernstein. Just a question actually back on Russia. For our TNKBP did quite well last year in terms of production growth. I think you were targeting 1% to 2% this time last year and it came in at 2.4%. Percent.
Could you talk about what's underlying that? Do you think it could do better than the 2% you're talking about over the next couple of years there? Secondly, just on Canada, it was one of your smaller NPV bars, but you talked about it having the potential for significant growth and the integration with the refinery. How could you get that growth? Is that focused on the oil sands and how can you lift that materiality?
Maybe just a quick one actually. Just on the medium barrels per day of extra production by 2016, it does seem to imply from today's production levels really a 4% or 5% decline rate maybe at the 4% level just to get to office declines by 2016. Is that your underlying assumption there? Are you confident that you can work to those types of base decline rates? Thank you.
Well, we have divested the assets we've divested have been declining assets. So we have always said our decline rates between 3% 5%. The fact that we've divested assets with a decline rate, you could see that our decline rates are probably going to be at the lower end of that range. But we're not going to give you an exact number. On TKBP, we've had the new startups in Wirtan, Chanskoa, the Suzune, Tagool, yet to come.
Uvat and Kamanoya fields have resulted in the greenfields, the transition from the brownfield stage is now into some green production production that's coming on and there's more. I think a 2% estimate over the next 5 years is a good estimate based on what we know about the waterflood declines and the new greenfield projects coming on. And on Canada, we have a position in the Canadian heavy oils. It is not Canadian, it's mining, it's SAGD. There are some of our projects that we can develop forward.
It's part of linking the value chain of heavy oil into the Midwestern refining. The margins of that will move between the trending and the upstream and that's why we see the integration value of those refineries going forward. We haven't made decisions yet. Husky, they're a joint venture with Husky. They've made a decision to start developing up there and we've got another one in our inventory to decide yet whether we take it on or not.
Let me turn to Lucy Haskins, who's on the phone here in the U. K. From Barclays.
Many thanks for the presentation. Could I ask in terms of your assumptions for 2011 and the 2016 sort of projections, how much will Iraq contribute? And also how do you expect to actually book the profitability from those barrels?
Well, production is rising and rapidly now in Iraq. It's a very complicated question to ask how we're going to book the profit from those. And I'd actually suggest you phone into Fergus's office. But
Yes. Lucy, we'll treat it as we would other production sharing contracts. It's going to have a significant level of DD and A and that was referenced in my earlier remarks. But as Bob said, it's a complicated structure. It's the first structure of the sort.
So first one, we've spent a lot of time thinking about the accounting related aspects of it, believe that we have it right and it will come through in a way that is not materially dissimilar to production sharing contracts, but will of course be its own contractual structure.
And so are we talking about say 70,000 barrels a day for this year?
I think we're looking at 50,000 barrels a day for 2011 and beyond that growth.
And so and I guess beyond that it's sort of contingent in terms of the spend you're putting in place effectively. I mean, have you got a feel for what kind of CapEx you wish to commission each year to that part of the world?
You're asking us to look ahead about decisions we'll be making on an ongoing base. But the production stream will be linked with the amount of capital that we're investing. And as Bob said earlier, the fact that we've now gotten through the new production level requirements, we're recovering the capital we put in earlier in 2010. So this is a project around which the risk factors are well mitigated by the structure of the contract.
Sure. And where are you the resource numbers you took in 2010 years have taken part of the equation before you start to think about reflecting those barrels in your reserve and resource basis?
We'll save discussion about the specific contributions to reserves when we report under our annual report and accounts in a month's time, Lucy.
Thanks very much.
Thanks, Lucy. Question, Alejandro?
Hi, from Merrill Lynch. A couple of questions here. The first one is on the ideal size of the new BP. Barrick have been talking about some of the assets you disposed was because you were trying to prop up some of the production levels. Is there an ideal level of production that you see the company going forward?
And when you're looking at this value creation, is it that you target that kind of level of production then the value creation will surround that?
I don't think there's I don't think we're going to say that there's an ideal level of production. I think what we've got is a set of portfolio projects coming through that can add significant volumes by 2016 that will offset natural declines in the portfolio. And then we'll look at how to use that portfolio for other things if we decide to do that. But I think you're I know everyone would like to hear an action target from us, essentially. And we're just not at this year.
This is a year of consolidation for us of building the foundations for going forward. It will be clearer as we move through the year, but it's just not the right year for us to give a production forecast due to the timing of divestments. Some of which have yet to be announced, as well as the start up and getting back to work in the Gulf of Mexico for the entire industry. OPEC quotas, the high oil prices that are happening right now are impacting production levels for companies with PSAs. All of these variables make that not simple to forecast now.
We'd rather not that. And if I could, with your question, we have one on the web, which I think is relevant to your question, what gives you confidence in the U. S. Government will not act to limit your role in the Gulf. I think the fact that we have responded the way we have, we have consistently said we'll meet our concern of the relationships that we have daily with the regulators at all levels in the U.
S. Government. I do not believe that the U. S. Government will take steps to limit BP's activities in the Gulf.
The pace of startup for us and the entire industry is a big issue. Right here and after this question, I'll ask Paul Spedding from HSBC and then after that Mark Gillman from Benchmark who are on the line.
Peter Hutton from RBC. In the past, we've tended to hear quite a lot more about U. S. Gas and the opportunities there. And the fact that you said it's been breakeven at $3 to $5 a barrel.
We've not heard very much on that today. Is that because it didn't break even at 3 to 5? Or is that because it maybe falls the wrong side of the volume versus value criteria?
Well, we've rebased our business in gas in the U. S. So that it is returns and cost of capital for dollars in Mcf. So we haven't spoken about it today because we've had a lot to talk about. Actually there would have been a lot of other things we could talk about today that are but there clearly is the dynamics of the international oil business have been affected greatly by the discovery of the resource base in North America, which has brought down margins sort of broadly in gas in North America, has had a knock on effect in terms of Europe.
And the flows of LNG into Europe have been diverted into Europe. And so this has had an impact all across the globe. So we have a very sizable North American gas business that we need to resize for this reality of gas pricing. And we've done other people here would just ask a bit of a question. Okay.
Paul left. Let me Mark Gillman from Benchmark in New York, I believe.
Thank you, Bob. Can you hear me all right?
I hear you loud and clear, Mark.
Just three quick questions. One for you, one for Byron and one for Ian. Bob, I respect your confidence regarding BP not being singled out with respect to the Gulf of Mexico. But should you feel that that would be a possibility? Would you be willing to cede operatorship or perhaps bring in a partner that might not be tainted by the recent history?
Byron, can you give me under what circumstances and over what timeframe, if my assumption is correct that you would be willing to take the company more toward its historical and conventional gearing structure. And then finally for Ian, Ian, I guess I'm a little bit surprised that as part of an asset oriented review of the global refining system that Rotterdam and your Australian units wind up being considered somewhat disadvantaged given both market location and configure. You could help me understand that.
Thank you.
So Mark, our confidence in the U. S, I don't believe we are being singled out. So it'd be sort of hypothetical to talk about if we were singled out what we would do. We've got great operating capability in the Gulf offshore experience there with a wide ranging number of fields, some of which we operate. We're involved in projects where others operate.
But we don't have any plans to shift the operatorship of those assets.
With respect to your question about debt and carrying I said that we're transitioning from a range of 20% to 30% down to a gearing range of 10% to 20%. We want to transition into the lower end of that range because you're at the lower end then you've got the flexibility to deal with uncertainties as they appear. And we'd expect to get down there over the course of the next couple of years.
And Mark, if scale and Nelson complexity were the only criteria for choosing what to hold and what not to hold, then you'd be absolutely right. We've just announced the sale of 2 of our largest and most complex refineries. And the reason for this is that our strategic review is not just focusing on scale and complexity because, in our view, that won't be good enough long run. It's also got to be right place with flexibility in feedstock and production, Incheon into an integrated chain that allows you to lock in high utilization rates and the ability to optimize the situation. Now we could have built that further around Carson and Texas City, but it would have meant further investment.
If you take the other 2, Rotterdam is brilliantly located in the right sale, but it doesn't have the right configuration yet. You're absolutely right, but it's integrated in our business. And in the case of Australia, our Australian business is doing extremely well, and it's being pulled on by demand growth from China and other places. And we will look at whether we should upgrade those further, but they're in the right place. So in simple terms, size and configuration size and complexity, sorry, are not the criteria.
Okay. Thanks, Guy.
Okay. I've got a question here on the web. Can you please give us an update on your expectations on the authorizations from the Brazilian authorities for the acquisition of the It's a good question. We were down there in Brazil in November and met the authorities that asked us for additional information, primarily around spill response activities and BP's commitment to investing in the country beyond just the offshore. We provided that information and we believe the next time that the commission who makes the decision to meet is in March.
So I believe that that is the next time it will review in its normal cycle of reviews. Ed Westlake from Credit Suisse in the U. S.
Yes. Good afternoon in London. Two questions if I may. Just coming back to the Gulf. Obviously, in Conkul commentary over here, people have learned perhaps about some of the permit requirements, particularly the containment requirements of NTL-ten.
Do you think the industry and yourselves are ready today? If not, when will you be ready and what would we need to see? That's the first question. The second question is really around asset integrity. Obviously, on the North Sea, it's still a meaningful portion of your NAV.
What reviews have you done? How confident are you in the integrity of the assets and broadly your overall portfolio? Specifically, do we think that 20122013 we're going to see another period of high upstream turnarounds?
Well, on the U. S, the signals that have come from the U. S. That companies are not ready to go out and drill in the deepwater based on comments that have been made later. The Marine Well Containment Company has been formed just recently and we've just joined that along with Exxon, Chevron, Conoco and Shell.
And as part of that of an inventory of equipment and caps and materials that were developed for the oil and gas bill in Macondo that are now being brought into that. So it will have long term research to develop new tools and techniques and we're bringing what we have out of the warehouses to join that. And it will be up for the regulators to see as sufficient. That along with plans and having rigs available to begin relief wells or something like that ever and again a very low probability that ever happens again. So I think it's a decision for the regulators.
It's a good question. But you've got the best R and D and engineering capability in the industry has come together and recognize the need to be able to respond with that. That's one way. There's also a second company led by Helix and 16 independent operators who joined forces to be able to be ready for response. But I think that debate on for some time as it's not unexpected.
But do feel that the U. S. Will not get back to work in the Gulf of Mexico. I find that highly, highly unlikely given the economic contribution that the oil and gas industry brings to the United States and the roughly 4,000 jobs that had been identified for that industry. I just would be very surprised following thorough review of the U.
S. That the industry does not get back to work. On