Welcome to
the BP Presentation to the Financial Community Webcast and Conference Call. I now hand over to Jessica Mitchell, Head of Investor Relations. Hello and welcome to BP's 4th quarter and full year 2012 results webcast and conference call. I'm Jessica Mitchell, BP's Head of Investor Relations. And joining me today are Bob Dudley, our Group Chief Executive and Brian Gilvari, our Chief Financial Officer.
Before we start, I'd like to draw your attention to our cautionary statement. During today's presentation, we will make forward looking statements that refer to our estimates, plans and expectations. Actual results and outcomes could differ materially due to factors that we note on this slide and in our U. K. And SEC filings.
Please refer to our annual report, stock exchange announcement and SEC filings for more details. These documents are available on our website. Thank you. And now over to Bob.
Thank you, Jess, and good afternoon or good morning, everyone, depending on where you are in the world. As you all know, the last few weeks have been a very traumatic time for us following the atrocity at the Intermenus joint venture in Algeria. It has also been a terrible blow for our partners in the joint venture Statoil and Sonitrack and for the contracting companies involved. Of the people who lost their lives, 4 BP employees and 5 Statoil employees Stata employees lost their lives along with contractors and partners, many of them close colleagues and friends. BP is a large, but tightly knit company.
People were murdered on what should have been an ordinary day at work and we feel the loss deeply. The shock waves have been felt not only within the companies involved, but around the industry as a whole. The event was a painful and tragic reminder of the importance of what we do. Our industry has a high profile. We operate in many different countries and cultures.
We work in challenging physical environments and we deal with multiple hazards. This event has highlighted the risks that we face from time to time and as an industry we must learn from it. I would like to thank governments and companies for the close cooperation during the incident. BP is a company that has been tested to the utmost, but we have resilient committed people. I believe we are equal to the task we face and this event will simply underscore our determination to run our operations that are safe, secure and able to deliver energy for customers and value for shareholders.
I think today's presentation will show some of the drivers at work in our business to achieve this outcome. So turning to our full year results. Today, you will see that 2012 was what we said it would be, a year of milestones in which a great deal was accomplished at BP. We are entering 2013 as a more focused oil and gas company with a smaller but stronger portfolio that provides a platform for growth, a set of distinctive capabilities, a disciplined financial framework and a clear strategic direction for the long term. Together, these building blocks create a solid foundation from which to grow long term sustainable free cash flow for shareholders.
In 2013, we'll continue to see the impact of the reshaping work in our reported results from the divestment of non strategic assets and the repositioning of our Russian interests as well as some early results from improved underlying performance. By 2014, I expect underlying financial momentum to be strongly evident. I am confident that we have the right strategy and that BP is well positioned for the world we're heading into. Today, we'll start with a summary of our full year 2012 financial results, a look at the key milestones we have met over the past 12 months and a brief overview of the macroeconomic environment. Brian will then take you through our results for the Q4 in more detail.
Then I want to update you on the big important areas of our business: our progress on safety and operational risk, the U. S. Legal process, our expected investment in Rosneft and our strategic agenda in the upstream and downstream. And then we'll take your questions. So let's begin with an overview of our full year 2012 results.
Underlying replacement cost profit was $17,600,000,000 post tax operating cash flow was $20,400,000,000 Our organic capital expenditure was $23,100,000,000 and we divested $11,400,000,000 of non core assets during the year. Total 2012 dividends paid were $0.33 per share up, 18% in dollars and up 20% in sterling compared to 2011. This means we distributed $5,300,000,000 in cash to shareholders. And our gearing at the end of the year is 18.7 percent, which is within our target band of 10% to 20%. That summarizes the outputs in financial terms.
But as I said earlier, 2012 was really about a year of strong progress on the drivers that will show up in future results. So looking at the key milestones. In Russia, we have an exciting and promising new future now that we have announced the sale of BP's 50% share in TNKBP to Rosneft. We expect the deal to close in the first half of this year. In the U.
S, we continue to work through the legal proceedings. During 2012, we reached landmark settlements with the plaintiff steering committee and we resolved federal criminal charges with the Department of Justice and the SEC. Also in the Q4, we completed the final payment into the 20,000,000,000 trust fund. This is a major milestone for the direction of operating cash flow. We continue to deliver our 10 point plan.
We are playing to our strengths and we now have a much more focused portfolio, having effectively reached our $38,000,000,000 divestment target a year earlier than planned. This will have a marked impact on reported earnings and operating cash flow in 2013, but it paves the way for future value creation by establishing a high quality platform for growth. During 2012, BP started up 5 major projects Galapagos in the U. S. Gulf of Mexico, Devanik in the U.
K. North Sea, PSVM in Angola and SCARVE in the Norwegian Sea, all of which we operate and Caucus Mavacola in Angola in which we have an interest. I'll come back to talk about 2 of these PSVM and SCARVE in more detail in a short while. Both are projects of considerable scope and scale and are real markers of operational progress. With these projects online, we remain on track to complete our program of 15 major project startups between 2011 the end of 2014.
At our Upstream Investor Day last December, we provided a detailed outline of the upstream platform for growth beyond 2014 and I'll summarize that again later. In the downstream, the major upgrade of our Whiting refinery is now 84% complete at year end and is on track to start up in the second half of this year. Looking even further ahead, we have reloaded our exploration portfolio by gaining access to a range of promising new leases. We've acquired new acreage in Brazil, Canada, Namibia, Trinidad and Tobago, Uruguay and the U. S.
Since 2010, we have been awarded new license exploration areas that cover a combined area roughly twice the size of the U. K. Or about the size of the state of California. That's more than twice as much acreage as we acquired over all of the previous 9 years. Now before we move on, let's briefly review the likely course of future energy demand.
This slide shows some of the main projections from the BP Energy Outlook 2,030, which we compile each year. The headlines are that we expect global energy demand to grow rapidly adding around 36% to global consumption by 2,030. And nearly all of that increase in demand over 90% is coming from emerging economies. Oil, gas and coal will supply 80% of these needs with gas showing the fastest growth at around 2% per year. However, the pattern of supply continues to shift and we expect unconventional oil and gas to play an increasing role in meeting demand.
The U. S. Is now expected to become almost self sufficient in energy by 2,030, while China and India become increasingly import dependent. We can see from the outlook that BP's strategy and portfolio is aligned with the opportunities presented by these trends. We plan to play a leading role in the supply of oil by applying what I believe are our distinctive capabilities in exploration, managing giant fields and enhanced oil recovery.
We are investing in unconventional oil and gas from shale operations in the U. S. To tight gas in the Middle East and heavy oil in Canada. But we're also investing in the capacity to process heavy oil, most notably through the major modernization of the Whiting Refinery. And our downstream businesses are supporting progress in energy efficiency.
For example, with fuels and advanced lubricants for transport that help improve fuel economy and lower emissions as well as leading petrochemical technologies that minimize energy use, cost and emissions. Turning from the long term to the current environment. The oil price has remained above $100 a barrel for the majority of the past year, albeit with some continued dislocations between crude markers in the U. S. Clearly, this is sensitive to the balance between global demand affected by the recovering global economy and the supply tensions from geopolitical risks.
Henry Hub gas prices have continued to remain in historically low trends with reductions in drilling activity offset by only modest demand growth, which has not been sufficient for a recovery in the price. And finally, in the Downstream, refining margins increased on average for the 3rd consecutive year in 2012 as demand for global oil products mainly in the non OECD markets continued to grow and supply was reduced by refinery closures and operational issues. So this is the global environment we've been operating in. Let's now hand you over to Brian to talk you through our financial performance
for the Q4. Thank you, Bob. I will start with an overview of the 4th quarter financial performance. BP's 4th quarter underlying replacement cost profit was $4,000,000,000 down 20% on the same period a year ago and 23% lower than the 3rd quarter. Compared to the Q4 of 2011, the result reflected lower production due to divestments, production sharing agreement impacts and natural field decline partly offset by major project delivery.
A lower contribution from TNKBP as it became an asset held for sale following the agreement with Rosneft meaning only 21 days of underlying income was recognized. A $430,000,000 negative consolidation adjustment to eliminate unrealized profit in inventory, partly offset by the positive impact of stronger refining margins. As a reminder, the consolidation adjustment relates to the unrealized profit from upstream equity crude that is held in our refinery inventories with the volumes held in the 4th quarter increasing significantly compared to the 3rd quarter. 4th quarter operating cash flow was $6,300,000,000 which included the final payment of $860,000,000 into the Gulf of Mexico Trust Fund. And as Bob mentioned a moment ago, full year 2012 underlying replacement cost profit was $17,600,000,000 down 19% on 2011.
This included a record contribution from the downstream of $6,400,000,000 pretax with another year of underlying profit growth from that business. The 4th quarter dividend payable in the Q1 of 2013 is €0.09 per ordinary share, an increase of 12.5% year on year. Turning to the highlights at a segment level. For the upstream, the underlying 4th quarter replacement cost profit before interest and tax was $4,400,000,000 compared with $5,900,000,000 a year ago and $4,400,000,000 in the 3rd quarter. The result versus a year ago largely reflects a decrease in production of around 7%, primarily due to divestments and entitlement impacts in our production sharing agreements and natural field declines.
This was partly offset by major project delivery, underlying 4Q volumes excluding TNKBP and after adjusting for divestments and entitlement effects decreased by around 1% year on year. The price environment was basically flat with small improvements in Brent offset by movements in local oil price differentials and Henry Hub traded slightly lower than a year ago. Costs increased year on year including higher DD and A and higher cash costs. Compared to the Q3, the Q4 result is flat with the benefits of higher gas prices including Henry Hub being offset by higher cash costs. For the full year, underlying production in 2012 was broadly flat compared to 2011 in line with previous guidance.
Looking ahead, we expect 1st quarter reported production to be slightly up relative to the 4th quarter with the ramp up of production from our major project start ups offset by the ongoing impact of divestments. Turning to Russia. As you're aware, following the agreement in principle with Rosneft on the 22nd October, we announced that equity accounting of our share of TNKBP earnings would cease and that TNKBP would be treated as an asset held for sale. So our result for the Q4 only reflects 21 days of TNKBP net income. As a consequence, BP's share of TNKBP underlying net income was $220,000,000 in the 4th quarter compared to $1,300,000,000 in the previous quarter and $1,000,000,000 a year ago.
We also received dividend income from TNKBP of $700,000,000 in the 4th quarter. As an asset held for sale under IFRS, this is accounted for within revenue and has been treated as a non operating gain. The dividend will also reduce the cash proceeds from the sale of our TNKBP shareholding and the associated non operating gain by an equivalent amount. We continue to expect to complete the deal with Rosneft during the first half of this year. So until that point, we will not be booking any earnings more activities and interests in Russia.
We will however continue to report our share of TNKBP's production and reserves until the transaction closes. In the Downstream, the 4th quarter underlying replacement cost profit was $1,400,000,000 compared with $800,000,000 a year ago and $3,000,000,000 in the 3rd quarter. The fuels business delivered an underlying replacement cost profit of $1,000,000,000 in the 4th quarter compared with $400,000,000 in the same quarter last year. The continued benefit of strong operations enabled the capture of high refining margins partly offset by the impact of the planned outage of the largest crude unit at our Whiting refinery, which began in November. Compared with the 3rd quarter, the fuels result was impacted by significantly lower refining margins, the absence of gains from the prior month pricing of barrels into our U.
S. Refining system and the planned crude unit outage at Whiting. This outage is scheduled to continue until the Q2 enabling the start up of the Whiting Refinery Modernization Project in the second half of the year. In addition, we expect the financial impact of refinery turnarounds in the Q1 will be similar to the Q4 of 2012 and lower than the full year 2013 than for 2012. The lubricants business delivered an underlying replacement cost profit of $330,000,000 in the 4th quarter and $1,300,000,000 for the full year.
This reflects continued robust performance in the quarter contributing to year on year growth in underlying profit despite challenging demand levels throughout 2012. The petrochemicals business delivered an underlying replacement cost profit of $50,000,000 compared with a profit of around $100,000,000 in the same period last year. Despite seeing a slight recovery in margins in the Q4, we expect margins to remain under pressure during 2013. In Other Business and Corporate, we reported a pretax underlying replacement cost charge of $450,000,000 for the 4th quarter, an improvement of $170,000,000 on the same period a year ago. The full year charge of $2,000,000,000 was in line with our February 2012 guidance.
And in 2013, we expect the average underlying quarterly charge for other business and corporate to remain around $500,000,000 per quarter, although this will remain volatile between individual quarters. The effective tax rate on underlying replacement cost profit for the 4th quarter was 16%. This was mainly due to deferred tax adjustments relating to divestments and foreign exchange movements and adjustments to provisions. The full year effective tax rate on an underlying replacement cost profit basis was 30%. In the 4th quarter, we also recognized a $4,100,000,000 charge, primarily reflecting the settlement with the United States Department of Justice to resolve all federal criminal charges.
This brings the full year total charge to $5,000,000,000 The total cumulative net charge for the incident to date is $42,200,000,000 The pre tax cash outflow related to oil spill costs for the year was $6,200,000,000 And during the Q4, we completed funding of the $20,000,000,000 trust fund. At the end of the year, the cash balances in the trust and the qualified settlement funds amount to $10,500,000,000 with $20,000,000,000 contributed in and $9,500,000,000 paid out. As indicated in previous quarters, we continue to strongly believe that BP was not grossly negligent and we have taken a charge against income on that basis. Since the end of the Q3, we have announced over $4,000,000,000 of further asset sales including our Texas City refinery in the United States together with some related logistics and marketing assets, a transaction which closed on the 1st February. Interests in a number of North Sea oil and gas fields and our interest in the Yachang gas field in the South China Sea.
As Bob said, we have now effectively reached our $38,000,000,000 divestment target a year earlier than planned. Of the $38,000,000,000 announced divestment since 2010, we have received over $31,000,000,000 in proceeds by the end of December 20 12 and expect to receive the majority of the remaining proceeds in 2013. The impacts will be increasingly evident as we move through 2013. For example, the 2013 reported production relative to 2012 is expected to be around 150,000 barrels of oil equivalent per day lower. For the upstream, the divestment program accounts for almost 500,000 barrels of oil equivalent per day or 16% of our 20 10 reported production excluding TNKBP.
For the group as a whole, assets divested since 2010 would equate to around $5,000,000,000 of pretax earnings and $5,000,000,000 of post tax operating cash flow. Looking at our full year cash flow movements, this slide compares our sources and uses of cash in 20112012. Operating cash flow for 2012 was $20,400,000,000 which includes $6,200,000,000 of Gulf of Mexico pre tax oil spill related expenditures. Excluding these oil spill related outgoings underlying cash flow was $26,600,000,000 We received $11,400,000,000 of divestment proceeds during the year with $6,800,000,000 received in the 4th quarter. Full year organic capital expenditure was $23,100,000,000 with $6,600,000,000 in the 4th quarter.
Our year end net debt reduced to $27,500,000,000 and our gearing ratio fell to 18.7% bringing it within our target range. With the completion of payments into the trust fund, as we receive the outstanding proceeds from the divestment program, we expect gearing to reduce further. We will continue to target gearing in the 10% to 20% range, while uncertainties remain. Turning now to guidance for 2013. We expect underlying production in 2013 to grow, mainly driven by the ramp up of major projects in high margin areas and reduced maintenance outages.
Full year 2013 reported volumes are expected to be lower than 2012 due to the divestment of around 150,000 barrels of oil equivalent per day, the majority of which relates to high margin areas in the Gulf of Mexico and the North Sea. The actual reported outcome will depend on the exact timing of divestments, OPEC quotas and the impact of oil price on production sharing agreements. Organic capital expenditure in 2012 was $23,100,000,000 In 2013, we expect capital expenditure to be around $24,000,000,000 to $25,000,000,000 as we invest to grow in the upstream. Our DD and A charge was $12,500,000,000 in 20.12 and in 2013 we expect this to be around $500,000,000 to $1,000,000,000 higher. The increase reflects the expected ramp up from high margin upstream assets and the planned commissioning of the Whiting upgrade in the second half of the year.
As already mentioned, other business and corporate charges are expected to be around $500,000,000 per quarter. Moving to tax. Our effective tax rate is expected to be higher in 2013 within the range of 36% to 38%, mainly due to a lower level of equity accounted income mostly TNKBP which is reported net of tax. There are also some accounting changes that will impact earnings in 2013. With effect from the 1st January 2013, we will be adopting new accounting standards including IAS 19 employee benefits and IFRS 11 joint arrangements.
We will provide information around the expected impact of these standards on our 2013 financial statements in due course. And we will also restate our results accordingly for the last 5 years. However, at this time, we expect the new reporting standard for pensions accounting to have the largest effect reducing 20.13 earnings by approximately $260,000,000 per quarter. In effect, we will now be using a rate for the return on plan assets that matches the rates used to discount our pension liabilities. However, this will have no impact on cash flow.
And finally, as a result of our major portfolio rationalization, we will also be updating our rules of thumb this week as published on our website bp.com. Looking out to 2014 and our operating cash flow objectives, we continue to expect to see operating cash flow of $30,000,000,000 to $31,000,000,000 As highlighted at our Upstream Investor Day in December, this represents more than 50% growth in operating cash flow versus 2011 including the impacts of payments in respect of the settlement of all criminal and securities claims with the United States Department of Justice and the SEC. We are increasingly confident in the drivers that underpin this growth, primarily driven by the start up of 15 major projects over the period and the planned commissioning of the Whiting upgrade in the second half of this year. With our current portfolio, expect to manage gross organic capital expenditure from the group in the range of $24,000,000,000 to $27,000,000,000 per annum from 2014 through to the end of the decade and to divest an average of $2,000,000,000 to $3,000,000,000 per annum on an ongoing basis. Growth in group operating cash flows to 2014 and beyond creates the platform to increase reinvestment and grow distributions in line with the improving circumstances of the firm.
And we will continue to maintain a progressive dividend policy. We will provide details on how the cash proceeds from the proposed TNKBP transaction will be used at the time the deal completes. However, at a minimum, our intention remains to use part of the cash proceeds to offset any dilution to earnings per share. Now let me hand you back to Bob.
Thank you, Brian. Turning to Safety and Risk Management, some say we are now too attentive to this. But let me be clear, this is good business both for the near term and the years ahead. Our approach brings together our operating management system or OMS and our BP values of safety, respect, excellence, courage and one team. The first defines what we do through a set of global standards that we expect across all of our operations.
And the second set defines how we do it. Together, they are the way we work in every BP operation around the world. We then look to 3 specific principles to guide us. The first is strong leadership. Individuals within our businesses and operations who shape and grow a safe operating culture and who are supported by a highly capable workforce.
The second is to insist upon globally consistent use of our OMS. This involves applying safety and operating procedures and rigorously assessing and managing risks. And it means always seeking to strengthen the safety and reliability of our operations through the improvement of plant, people and process. And finally, we have strong self and independent assurance to confirm that we are compliant with our systems and processes. So that's the approach.
But how does this show up in our safety performance? These charts show some of our safety statistics. Of course, the trends shown here are only one lens of safety performance and we know there's always more to do. However, I do take some encouragement from these metrics. The first is losses of primary containment shown on the right slide.
This records losses down to very small releases. 2012 showed a 19% reduction on 2011 continuing a multi year improvement. Also on the right slide, we track process safety events. The American Petroleum Institute or API recommended industry metric. Our 2012 outcome was a 42% reduction in Tier 1 events versus 2011.
The focusing of our portfolio has also had a positive impact in terms of safety and risk management. For example, our divestment program in the upstream will remove around 50% of our installations, 50% of our pipeline length and reduced the number of wells by a third, while only reducing our reserves by around 10%. Alongside process safety, we continue to focus on personal safety, maintaining our recordable injury frequency rate at levels comparable or better than industry benchmarks. This is shown on the left chart. There is always more to do, but I believe what we are seeing is the emergence of the safer and stronger BP that we're creating and our focus remains resolute.
And we are also clear this is good business. I want to just focus for a moment on one of the most important things we're doing to embed safety and risk management in BP. Since the Deepwater Horizon accident, we have been determined to share the lessons to help prevent an accident of this magnitude happening again and to help advance global oil spill response capabilities. Our experience has been built across the key capability areas of prevention and drilling safety, well capping and containment, relief wells, spill response and crisis management. This has been a significant journey of learning for BP and we've been asked to share our experiences with many others in the industry and among regulators and governments worldwide.
We've conducted more than 200 briefings and presentations with such groups in the past 2 years in at least 30 countries. As you know, we carried out a thorough investigation, which made 26 recommendations. We are now implementing those recommendations through a worldwide program with a dedicated team. It involves multiple actions to ensure each recommendation is fully implemented in every operation. This involves creating a new standardized risk identification and action plans.
At the same time, we're adopting a more systematic approach. We've introduced enhanced well control and other drilling safety standards, practices and capabilities. In Houston, we built a state of the art facility that displays live well information about our rigs in the Gulf of Mexico. Operating 20 fourseven, experts of the facility provide an additional level of assurance to their colleagues located at each offshore drilling rig in the Gulf of Mexico. Are also ensuring we are better prepared to respond to an accident should one occur.
And that has involved building new equipment such as a capping stack, which is located in Houston and creating new response plans. So let's move on to the legal landscape in the U. S. Where we have made progress in reducing the legal risks facing the company. We reached a significant milestone with completion of the $20,000,000,000 payments into the trust fund, the final payment being made in the 4th quarter.
This removes a call on the operating cash flows of the group of some $5,000,000,000 per year. The fairness hearing to determine whether to grant final approval of the settlements with the plaintiff steering committee was held in November and the settlements were subsequently approved by the court in December January. Payments associated with these settlements are expected to be made from the trust fund. We also announced in November that we've reached an agreement with and the Securities Exchange Commission to resolve all federal criminal charges and SEC securities claims against BP stemming from the accident, the oil spill and response. The settlement resulted in an increase to the overall charge of $3,850,000,000 in the 4th quarter, with the payment schedule stretching out to early 2018.
We believe the cash payments are manageable within our current financial framework. As this increase relates to fines and penalties, it will not be tax deductible. Last week, the court accepted BP's plea resolving all federal criminal charges against the company stemming from the Deepwater Horizon accident, oil spill in response and sentenced the company in accordance with the terms of the plea agreement. BP continues to work with the EPA in preparing an administrative agreement that will resolve suspension and debarment issues. By reaching this settlement with the U.
S. Government, we have removed another significant legal uncertainty and can now focus fully on defending the company against the remaining civil claims. We remain prepared to settle the remaining civil claims, but only on reasonable terms. Throughout, we have been preparing for the trial scheduled for later this month and we will be ready to thoroughly and factually present our case in court. In Russia, we've made significant progress towards the completion of our deal with Rosneft announced in October to sell our share in TNK BP for cash and an 18.5% stake in Russia's leading oil company.
As a result of the transaction, you will recall that BP will receive $12,300,000,000 in cash and hold a total of 19.75 percent of Rosneft when combined with the existing 1.25 percent of Rosneft which we already own. In November, BP and Rosneft signed final binding agreements for the transaction and the Russian government approved BP's acquisition of a further 5.66 percent of Rosneft. Also on the 12th December, Rosneft and Alpha Access and Renova signed agreements so that Rosneft will acquire 100% of TNKBP. The completion of the transaction is subject to regulatory approvals and this process is well underway. We anticipate the closing of the transaction in the first half of twenty thirteen.
BP and Let's now look at the potential Let's now look at the potential for value creation as a result of the investment we are making. Our proposed holding of nearly 20% gives us a great opportunity to contribute to Ross Neff's strategy and potential for value growth. This slide illustrates the areas of potential value growth for Ross Neff following its planned acquisition of TNKBP. On the left side of the slide are areas where short term synergies can be achieved through the process of integrating TNKBP into Rossneft. The right side of the slide shows the longer term potential.
BP has very relevant experience here in improving performance in Russian and oil and gas businesses and in large scale corporate mergers. This can directly benefit Rosneft and its efforts to define and capture these synergies. Like Ross Neff, we see numerous opportunities for optimization of the upstream and downstream businesses and the gas and gas liquids value chains. We also see opportunities in supply chain management, corporate synergies and portfolio optimization. Longer term, we see potential to increase both reserves and production through the application of leading edge technology and the powerful partnership between BP and the Russian oil and gas professionals that brought such impressive results in T&KBP.
We are very much looking forward to the prospect of working together with Rossneft to identify and develop standalone projects both inside Russia and internationally. Given all that Rossneft and Russia have to offer to the oil and gas industry, we believe there is enormous potential in the enlarged company to create value for Russia, Ross Neft and its shareholders and by direct consequence for BP shareholders as well. Turning to the progress and outlook for the upstream. We continue to improve on safety and risk management in the upstream last year. The number of Tier 1 process safety events fell by 55% between 2011 2012.
Additionally, we completed implementation of 14 of the 26 recommendations of the Bligh Report, which is our investigation into the Deepwater Horizon accident and we've made continued progress towards closure of the remaining 12. In Exploration and Access, as I indicated earlier, we have significantly reloaded the portfolio. In the last year alone, we added Atlantic positions including Uruguay, Brazil, Nova Scotia and Canada and Namibia to complement our leading positions in Angola and the Gulf of Mexico. We also established a significant unconventionals position in the emerging Utica shale in Ohio and we've now started drilling out that inventory. We started 5 major projects PSVM, SCARVE, Claucus Mavicola, Devonik and Galapagos all as you know are in our high margin areas.
We significantly increased our rig fleet, increasing mobile offshore drilling units from 15 to 19 and we now have 7 operational rigs in the Gulf of Mexico working on a combination of production and exploration activities. Overall plant efficiency has improved by around 1% across the portfolio and by almost 10% in our top four high margin regions. In 2012, we also completed 70% of our turnarounds on or ahead of schedule, which is twice as good as our historical rate of efficiency on these critical activities. Both are good examples of how the new operating model is enabling us to more systematically and consistently across BP with further benefits to come in the future. Looking to the portfolio, we've used a combination of divestment and investment to create a strong platform for future growth.
We have reached our $38,000,000,000 target of disposals significantly increasing the quality of the upstream portfolio, while reducing its age, complexity and the risks which come with that. Given the high quality nature the portfolio, we have decided to direct more of our capital investment towards the upstream, up to 80% over the next decade. In general, the features of this portfolio are a more focused footprint with strengthened incumbent positions, a reloaded exploration prospect inventory, a strong pipeline of high margin projects and a focus on our distinctive strengths to deepwater, high quality gas value chains, giant field management and a deep hopper of unconventional resources. Over the past few years, we have transformed our exploration portfolio and materially increased our unconventional inventory. The map shows the positions we have added since 2007 focused on deepwater, unconventionals in North America and the Middle East.
We are now early in the process of exploring the acreage. Right now, we're acquiring and interpreting seismic data and ramping up to 15 to 25 new exploration wells per year. This does not count appraisal wells. By testing at least 10 new material conventional and unconventional opportunities every decade, we aim to add 2 new provinces each with multibillion barrel potential like we have done in Angola, Azerbaijan and the Gulf of Mexico over the past decade. Turning to projects.
We remain on track to deliver 15 major project startups between 2012 2014. In 2012, we delivered 5 projects including PSVM and Scarf, each a significant achievement and key operational milestone in its own right. PSVM in Angola and Block 31 represents one of the largest subsea developments in the world and the first in the Angolan Ultra Deepwater. The field started up in December with production averaging just over 60,000 barrels per day. Production will continue to ramp up as we bring on stream further wells and it is expected to build towards plateau rates of 150,000 barrels per day over the coming year.
In December, we also started up SCARVE in the Norwegian Sea. The field development includes a new highly advanced FPSO purpose built for harsh waters with 5 subsea drilling templates. Production will continue to ramp up through the year and is expected to reach a maximum rate of 165,000 barrels per day by year end. There are 2 short videos currently on our website, which show the scope and scale of these 2 major projects. I hope you take a moment to see them.
Looking further ahead, we have a very strong pipeline of projects as we showed you in December. We expect a further 4 upstream major projects to come on stream toward the end of 2013 North Rankin II, Angola LNG, Nikika III and the Sherag Oil Project with the remaining 6 startups in 2014. In total, we have around 50 major projects progressed through the decade. Of these, 11 are what we call mega projects, which are greater than $10,000,000,000 in gross spend. We made final investment decisions or FIDs on 3 projects in 2012: Juniper, the Kazamba Satellites 2 and Point Thompson.
And we expect to FID a further 5 in 2013. To deliver these projects, we're planning a gradual ramp up of our rig fleet. It will increasingly be made up of newer high quality rigs with higher reliability and with key suppliers very much aligned to our focus on safety and risk management. The strength of this pipeline lies in quality. As we look at the projects that will be delivered out to 2017 where we have the most definition, the average operating cash margin will be roughly twice that of the 2011 Upstream segment average.
That provides us with the opportunity to grow cash margins through the decade. Of course, we may not progress all of these ourselves realizing value earlier in the process and some may get deferred. But this is a powerful platform for future growth and it does not include any further exploration success. So what does all of this mean? We remain on track to deliver the upstream contribution to our 50% increase in operating cash flow out to 2014 supported by restoration of production in our high margin regions and growth from our 15 new major projects.
Looking longer term with the capital frame Brian outlined earlier, there are 3 things that give me confidence we can see continuous growth in operating cash flow out to 2020 from the upstream. 70% of our production will come from fields already producing. This shows the youth of our reservoirs and gives me confidence that we can count on them. 2nd, about 85% of our production will come from oil fields or gas fields with prices linked to oil. I believe this is distinctive and offers us more oil price leverage in a world where oil is more scarce than natural gas.
And third, you can see that we will continue to generate about half of our operating cash from our existing major profit centers: Angola, Azerbaijan, the Gulf of Mexico and the North Sea. We have a very high quality set of assets to work with and I'm certain that the strength of our new organization together with the focus of our portfolio will enable sustainable value growth for our shareholders, while we continue to explore and create value beyond the current portfolio. Now let's look at BP's Downstream business and what you can expect in the future. Turning to the Downstream. 2012 has been a success in many areas.
It was a year of sustained safety and operational improvements, strategic progress and record levels of underlying earnings, despite a weak environment in both petrochemicals and oil trading. As we have previously explained, our approach is based on the principle that a world class downstream business requires focus on the right assets with the right scale, location and configuration, complemented by leading technology and brands. But first and foremost, to deliver an asset's full potential, we must operate safely and reliably. As this slide shows, during 2012, we delivered sustained process safety and refinery availability improvements through targeted investments and capability building. In terms of safety in particular, losses of primary containment more than halved between 2,008 2012.
And improving the safety and reliability of our operations, we are realizing stronger financial performance today. As we announced on February 1, we have successfully concluded the divestment of the Texas City Refinery with the announced divestment of our Carson Refinery and U. S. Southwest value chain remaining on track for completion towards the middle of 2013. The Whiting Refinery Modernization Project is on track for operations to begin in the second half of twenty thirteen with construction 84% complete at year end.
Once operational, we expect this project to deliver an incremental $1,000,000,000 of operating cash flow per year depending on the environment. And we are delivering all of this within a disciplined financial framework with a consistent focus on maintaining quality positions with material and growing cash flow generation capability. Looking to the future, our focus is to keep up this momentum, embedding the sustained progress in safe and reliable operations of recent years and expanding the cash margin generating capability of our businesses through the emphasis on quality, thereby delivering material and growing free cash flow. Within the Fuels business, we will complete our divestment program, bring the Whiting Refinery Modernization Project on stream and focus future investments and efficiency programs on expansion of cash margin capability. Within lubricants, we will use our advantage exposure to growth markets to drive further business expansion and we'll continue to invest in brand, technology and customer relationships.
And finally, within petrochemicals, we will continue to invest through the cycle with a focus on expanding our Asian positions and further developing the commercialization of proprietary technologies. In summary, the Downstream is delivering strong and competitive results through a high quality portfolio that is capable of sustaining this level of performance across all of its businesses. Our Downstream is a material contributor to the group's cash flows today and remains an essential element in our plans for growing operating cash flow into the future. So to summarize the group perspective, we have repositioned BP over the last 2 years for sustainable growth into the future. We have significantly refocused the portfolio.
We have addressed head on safety and reliability through a wide ranging change program. We've reshaped BP's upstream and focused our refining. We said 2012 would be a year of milestones. It was and we remain on track to deliver the 10 point plan, including our commitment to growth and operating cash flow by 2014. We will be a focused oil and gas company that creates value by growing long term sustainable free cash flow through safe and reliable operations, a disciplined and prudent financial framework and a portfolio rich in high margin opportunities.
We plan to deliver this through increased upstream reinvestment to drive growth in higher margin areas and to sustain the pace of our increased exploration and access activity. And finally, it is our intention to grow distributions over time in line with the improved circumstances of the firm and to maintain a progressive dividend policy. We are making BP safer and stronger and there are no shortcuts. We're doing what needs to be done and are becoming a better company as a result. That concludes my remarks.
And now Brian, Jess and I will be happy to take your questions.
Good afternoon or good morning everyone. The first question comes from Houtan Yazari from Bank of America. Go ahead, Houtan. Okay.
We might be on mute. We'll come back.
All right. No answer from Hutang. Can we try a question from Alejandro Demicales from Exane?
Yes. Good afternoon, gentlemen and just a couple of questions if I may. Bob, you've said that you remain prepared to settle the civil claims under reasonable terms. So I wanted to know if the discussions are still ongoing or if you're just waiting for the start of the trial at this point? The second question is on the pension situation maybe to Brian.
With the €260,000,000 impact on a quarterly basis over the course of a year, would you be able to bridge the gap between the liabilities of the assets? Or do you need to think that we need to extend that into 2014 as well?
Thanks, Alejandro. On your question about the trial, which is starting, it's really 20 days away right now. So our teams are working very hard to prepare for the trial. And I think that's probably all I can say right now. I think we've had numerous settlements over the last 2 years with our partners with the plaintiff's attorney steering committee and the Department of Justice and the SEC in December.
And I think we're now heading right down to the trial for the civil proceedings and our team is very, very prepared.
Yes. So Andrew on the question you're asking, I presume this is around the IAS 19 which is a new accounting standard that we'll be adopting through 2013. It won't impact our funding plans. We'll continue to invest in the funds at roundabout $1,300,000,000 per annum. What it does effectively reduce the discount rate.
It is a classic example of where the accounting treatment has come in to use a discount rate rather than return on equities based on a bond rate. And on that basis, we'll be discounting something like 4.4% for the U. K. Scheme 3.2% for the U. S.
Scheme. It does have an impact in terms of how we report earnings. It has no impact in terms of how we fund the plans. And I think the key here is it's a classic accounting rule that has no economic sense or semblance of sense. But nevertheless we are introducing that as one of your accounting standards.
But it will have no cash impact. And I think given the company is very much focused on cash, this will have no impact on cash going forward.
That's very clear. Thank you.
Right. The next question is from Doug Terreson from ISI. Go ahead Doug.
Good afternoon, everybody and congratulations on your results.
Thank you, Doug.
Bob, you have extensive experience in the integration process on major strategic activities in this industry. And obviously, the record of value creation at TNKBP speaks for itself. And so while you highlighted the path forward for Rosneft, my question regards the level of involvement that yourself and some of the other senior leaders of BP are likely to have in the areas that will drive the growth and returns profile at the new Russian company?
Yes, Doug. Thanks. So we are in the approval processes right now. They're working their way through a couple of government approvals. So but all those seem to be on track right now.
I have been asked to be part of an integration steering committee with Rosneft along with Igor Sechin and there'll be some others joining it. I have no doubt that there will be a number of very well known consulting firms that also have experience in merger integration are beginning to work on pieces of this. There'll be there's work underway on the downstream, there's work underway on the upstream. And I think right now the emphasis on the integration is to get the companies ready for day 1, which means being able to merge the books, close the books, control the assets and then build an organizational structure. So while a lot of that is quietly going on, of course, it's very much going on.
And I think we do have experience in that. We know the TNKBP company and assets. So we'll have a, I would say, a small, but very experienced group of people that are working on this now. And then as we go forward after the closing and depending on the structures of where the assets are grouped, I have no doubt that some of that experience of being able to identify where the real talent in TNKBP is on things like water flooding, artificial lift work and sort of a focused exploration program will happen. And I think I would just Doug to say everyone stay tuned.
Okay, good. And then also Brian highlighted around $5,000,000,000 of lost profits related to the upstream divestitures. And on this point, I wanted to see whether you have a similar figure for the downstream and specifically any insight on the profit reduction from the divestitures in U. S. Downstream last year?
Yes, Doug. I mean, I think it's that of course is always a function of what the refining margin environment looked like. It was quite attractive at least for a quarter in the Q3. And the $5,000,000,000 figure that we gave you is really a group figure. It's not specific to the upstream.
We talked about volumes. But at the end of the day, I think it's good to get these 2 refineries behind us. We wouldn't have seen them as strategic assets to invest in. And actually in terms of Texas City the cash flow out of there was negligible for the year. So I think this is a good thing to have behind us in terms of where the disposals and the proceeds came in last week.
So $5,000,000,000 did include downstream?
It did. That's correct.
Okay. Thanks a lot.
All right.
The next question comes from Jason Gammel of Macquarie.
Yes. Thank you, everyone. My question comes back to the expectations for the cash flow accretion over the next 2 years and how that will actually affect the shareholder. Bob, you referenced with the dividend raise that was announced last year rewarding what have been very patient shareholders. When you look at the cash flow growth, how do you now expect to divide that up between increased capital investment, which you've provided some detail on today?
And what cash actually goes back to the shareholders versus strengthening the balance sheet?
Brian and I were just going through this. I'm going to ask Brian to tackle that and then I'll come back at the end with a few points.
Yes. Thanks, Jason. I mean the background to this is when we laid the targets out in the 10 point plan in October of 2011, We started with a base of $22,000,000,000 of operating cash and we said that that would grow by 50%. So it takes you up to $33,000,000,000 in the original 10 Point Plan. And we said 50% of that would go into capital and we've held that number at roundabout $24,000,000,000 $25,000,000,000 The base on capital was $19,000,000,000 so that would increase by 50%.
And we said the remaining $5,000,000,000 to $5,500,000,000 would be available for other purposes. Now since that was out there, the revised figures are now $30,000,000,000 to $31,000,000,000 So that still says that there is still cash available for other purposes, which will underpin the dividend in terms of the future and progress the dividend policy. The difference from the $33,000,000 to the $31,000,000 or the $30,000,000 to $31,000,000 The difference from the 33 to the 31 or the 30 to 31 is basically the fact that we swapped dividend Aletti and KDP for dividend in Rosneft. Effectively, we've accelerated 6 to 7 to 8 years' worth of dividends out of TNKBP as part of that transaction, which is the $12,300,000,000 of cash we will receive on the closure of that transaction. And also there's flexibility inside those numbers around Henry Hub natural gas prices.
And so the figure now says that actually there's still surplus cash available for growth in other purposes or distribution. And also of course we've had since then the criminal settlement with the DOJ and that has a payment schedule over the next 5 years that sits inside that $30,000,000,000 to $31,000,000,000
And Jason, I would just add that what we we have more projects than we can do over the next 15 years. And so what we have signaled with our levels of capital investment, we do need to reinvest in the upstream most certainly, but we want to signal and lay out a disciplined framework there that paces that capital spending so that we can be sure that we do have incremental free cash flow for our shareholders. The other thing that will be part of this in terms of shareholders that we've said that after the closing of the Rosneft transaction that we will ensure that the shareholders have not been diluted by the transaction. And after the closing, we'll lay out steps that we'll take, which should be certainly before the middle of the year.
And if I could just follow-up very quickly then outside of the potentially anti dilutive measures related to the TNK transaction Would the dividend be the primary focus for returning cash to the shareholders? Or would you be considering repurchases at this point?
Well, I think we're considering both actually. And I think a special dividend is unlikely given the progress nature we want to manage the cash, but I think you would see us considering both.
Very clear. Thanks.
Okay. Jason, good job on CNBC today. I saw you talking about the industry.
Right. The next question comes from Oswald Kuntz of Sanford Bernstein.
Good afternoon. Thank you. Could I maybe just focus on the reserve replacement number? I know it's a point in time, but just wanting to know if that's mostly a low number on the back of low U. S.
Gas this year? And but also maybe thinking about this year, if you're starting to drill out your Utica position in terms of drilling inventory, would you expect to be able to book any of that at the end of 2013? And then secondly, maybe just a question on down in Iraq with some of the recent news articles etcetera talking about various companies thinking about their projections and targets. Is there anything we should be aware of in terms of your project there? Thank you.
Okay. Thank you, Oswald. Let me start from the back and move up. With Iraq, we continue to move the production up of the Rameela field. It's between 1.4000000 and 1 5,500,000 barrels a day today.
As other companies have, we have been in discussions with the Iraqi federal authorities about we've given them as many as 4 different options in terms of plateau rates and the enhanced development of the field. And those talks are ongoing in a assets in the country and what they're capable of debottlenecking in time. And that's probably what's happening all across the South there. On reserve replacements this year, we've said that we will announce the details of that with our annual report our 20 F to be published in early March. We expect our reserve replacement ratio to be in the range of 75% to 80%, 85% excluding acquisitions and divestments.
We'll do that we're going to look at that on a combined basis of all the subsidiaries and equity accounting entities. We think that the number will be below 100% most likely. Main reason for that is in 2012, we FID'd only 3 projects. And we expect to on average over the last 5 we've FID ed about 8 projects. During 2013, we should be up to the 5 to 6 range.
The 3 that we did this year were not what we would call mega projects. So that's been an impact for us in 2012. We've had a reserve replacement ratio of over 100% for the last 10 years, actually 20 years. And so this is a trend of we'll expect to get back to our trend here in 2013 and beyond. And on the Utica, we do have about 86,000 square Acres in Utica.
We are appraising it right now. And I think it's possible we might be able to book some of the Utica shale gas or shale liquids reserves in 2013, But that will be in time. We'll see how the year goes.
That's great, Bob. Thank you.
Okay. Thanks, Oswald.
Over to the U. S, Robert Kessler from Tudor Pickering. Do you want to go ahead, Robert?
Yes, sure. I just wanted to go back to follow-up on the cash balances for 2014 and make sure I've got the numbers right. As I look at your cash flow guidance, I've got to take the high end of the range there at 31 and the low end of your CapEx guidance at 24 just to get to the current dividend payment. And I know you've got a big slug cash coming of course with team KBP and some other ongoing asset sale proceeds of $2,000,000,000 to $3,000,000,000 a year. But are we to assume that you're going to use that to support the dividend growth?
And if so, where do you see your new target? I mean, I know you've got the band of 10% to 20%, but are we likely to see you hover at the higher end of that gearing range going forward to support this distribution strategy?
Yes. So I think Bob I think I'll take that. So I think the key is first of all cash breakeven that we are cash breakeven in the $80 to $100 a barrel fully loaded with the disposal proceeds going forward over this period of time. So the dividend is more than covered by the cash flow within the existing financial frame. I think what we have here is flexibility around what we do with cash in 2014.
And I think really we need to give you a clear picture of what happens beyond 2014 in terms of free cash flow generation. But after 2014, existing dividend is underpinned. We can be progressive with that going forward, but that's really a matter for the board and with the context of the environment that we're in at the time. So that's something which is considered by the Board around the results. And so I think the key is as you said yourself there's $2,000,000,000 to $3,000,000,000 of disposal proceeds.
We have a scrip dividend which is typically around about a 20% take up. So the cash dividend is about 80% of what we actually declare as a dividend. And I think there is still flexibility out in 2014 around surplus cash. And I think Bob has said already that we'll have the issue in the first half of this year around the cash proceeds that come with the TNK transaction will be an opportunity for us to look at the options that Bob's described around progressive dividend and potentially shrinking the share base which thereby of course also impacts the overall cash dividend at the company.
And thoughts on whether you might be at the high end of the gearing band in 2014?
Right now based on where the oil price is in terms of our plan assumptions, we will continue to see the gearing drift down probably towards the top end of the lower half of the range. So it will be in the top end of the 10% to 15% range within the existing plans that we have today.
I'm sorry what oil price are you using for that?
$100 a barrel.
Okay. Thank you.
And longer term, we'll continue to reassess that gearing range of $10 to 20. Have in time when we go through this period of transition we might move that up.
I'm going to come back and try Hu Tan again. I think he's back on the line. Hu Tan, are you there?
Hello?
Hello.
Hi. Am I coming through or not?
Yes, you are coming through. Go ahead.
Good. All
right. Sorry about that phone issues, but here we go. Just coming back to disposals, your $2,000,000,000 to $3,000,000,000 run rate as guided going forward from here, it's sort of you're also indicating that you might have too much on your plate in terms of investing. What sort of scope is there for that €2,000,000,000 to €3,000,000,000 run rate to increase in the coming years, especially given the very attractive realizations you've made on asset disposals? And then going back to the civil case, which is coming up on the 25th February, I just wanted to see in terms of underlying negotiations, whether we could see some sort of a split negotiation going on such that you would reach a resolution on the Clean Water Act separately from what's going on with the natural resources stuff and the respective states that you're going to court with?
Thank you.
Okay. Hutan, thank you. We were worried about you for a while there. On the disposal the $2,000,000,000 to $3,000,000,000 I mean that's not an insignificant set of disposals going forward. We'll continue to work through that in time.
Right now, we do have a lot on our plate, but we also think we have paced them out and separated them out. And there are things out later in the decade that I think we could consider. But we're right now not I don't think we have too much on our plate. I think we have balanced it well with capability and the projects identified. But we may divest projects at different points in their lifecycle coming up, but they're not in our plans right now.
On the trial on the 25th February, obviously, it's nothing we could talk about in terms of settlement discussions at all. I just note that there are 20 days to go and that's not very long and our efforts are really focused on getting ready for the trial. So I think anything is possible, but I can't give you any real sufficient light on your question as you would expect right now. But thanks, Sutan.
Understood. Thank you.
Right. Turning now to John Rigby from UBS.
Yes. Hi. Two questions, please. The first one just going back to I think one of the first questions around TNKBP and Rosneft. Correct me if I'm wrong, but it seems to me that the great sort of distinguishing feature of TNKBP within Russia was the people and the processes that were taking place there.
I mean you always spoke about how that organization kept motoring on even when the management problems were happening. And I'm just wondering as you step back from it how you ensure that those good people and good processes continue into the combined Rosneft group? Because it would seem a shame, I guess, to lose that. And also, I would have thought that applying those people and processes to the combined base would be where you get a vast proportion of your merger synergies from. And I think of that in the context of your relationship with AAR, who of course are leaving completely.
The second question just as a a confirmation. You talk about the $1,000,000,000 of cash flow benefit from the Whiting modernization project. Can you just remind me what macro assumptions you're making around the spreads between crude oil prices for the basis of that $1,000,000,000 Thanks.
So John, thanks. Both good questions. And I'll let Brian answer the one on the Whiting Refinery. You're spot on. TNKBP, when you benchmark the Russian oil industry and I've had lots of discussions with Rosneft about that, T and KVDP benchmarks very well in terms of efficiency and what it's been able to do in terms of bringing out additional reserve additions to the oil fields in Russia as well as very tight controlled centralized exploration processes and accounting processes that allowed the venture really to keep up and close IFRS books at the same pace as with BP.
So being able to retain both the business processes and the people who know how to run them is very important. And clearly in a time of a merger as with any company and probably most of you all know this in times of merger, there's a lot of uncertainty. But there's a lot of discussion about just exactly what you described. How do we maintain some of the business processes that drive a lot of efficiency and be able to make a merger happen simply. And then secondly, identifying good people, the best people to be able to work in a new organization, so that the assets suddenly are just not left alone.
And I'm confident that that's not going to happen and that many of those really world class as good as any business processes will remain. But like in any merger there'll be lots of stories and lots of headlines I suspect. But actually it's been the approach path has been remarkably smooth so far. And Brian on Whiting. Yes.
On Whiting, John, we've never actually put macro data out there in terms of the light heavy spread assumptions. I would simply say that at various points through last year as the light heavies blew out, we were way above the $1,000,000,000 on an annual run rate basis. But I would describe knowing what the number is. It's relatively conservative in terms of what we've built into that $1,000,000,000 So actually if you saw anything like the blowouts that we saw in the light heavy spreads last year in addition to of course the benefits you get from the WTI differential to Brent, because not only do you have a cheap light source to price the heavy off, it's actually it's discounted again versus Brent. So I would say the $1,000,000,000 is very underpinned at the current prices we've seen in recent years.
Is it worth just looking back at the sort of historical trends at or around the point at which you FID the project in the first place as a guide to the kind of background that you're looking at?
Yes. We've done that because actually the assumption we made is that the pipelines would be built and therefore that light heavy spread would narrow over time. So we're confident that the $1,000,000,000 will be there based on the historicals that we've looked at and then aimed off that number. And I'd actually also say it's probably worth counting of course with a heavy oil position in Canada effectively between the two positions we pretty much now have a hedge or if you like the value can now move between the two assets as that light heavy moves out and comes back in again.
Thanks.
The next question comes from Teepan Jockey Lingam from Nomura. Go ahead, Teepan.
Yeah. Thanks, Jess. Good afternoon. Couple of questions. Firstly, Bob, could I come back to that point on gearing?
To be clear, are you saying that sort of beyond let's say the cash in for Russia a potential settlement in the U. S. Then you sort of anticipate that gearing level moving back sort of towards the high end of the 10% to 20%. And then if that's the case, is that a mix of higher organic spend, potential use of M and A to bolster up the portfolio? Or is that cash return back to investors?
The second question sort of linked to that I guess is the position in the U. S. And unconventionals. Could you talk about how much investment BP would be willing to put into that business? What sort of growth we expect both sort of for 2013 and then over the next few years?
And whether you need to add on the liquid acreage side? Thank you.
Tien, I'll give you I'll just give you a quick introduction on the gearing and then Brian follow it up and then I'll come back on the unconventionals. But I say on the gearing, my comment was many of our shareholders have said as you move through a period of transition is 10% to 20% the most efficient range you should be in and would you be open to increasing that range of 10% to 20% to 30%. And what we have said is that for now 10 to 20 is the range. But as we move through this period, which I would say is through 2014, then we reconsider that range, because I think it's a question about is that the most effective efficient range for us. So Brian?
Yes. I mean, I think, Tapan, the context here is historically the range that we always operated within Financial Frame for the best part of a decade prior to the Q1 of 2010 was a gearing range of 20% to 30%. And we redirectionally moved up to 10% to 20% while we have major uncertainties around cash outflows in the United States. Of course, a lot of those uncertainties have now been resolved notwithstanding the court case which is due to start on 25th February. So I think what Bob is alerting you to is that once we get all uncertainties resolved, there is a far more useful use of cash.
Gearing is net debt and net debt is a way to do that. So I wouldn't read too much into that. In terms of the existing plans we have today post the closure of Rosneft the gearing will track naturally down by 2014 in the 10% to 15% range. And of course that just means that we have a very strong balance sheet, which gives us a huge amount of flexibility going forward. And I think with the economic outlook that we see today that's actually a very good thing to have in your armory.
And T Pain on unconventionals in the U. S, we it's interesting to note that Q2 last year gas prices were $1.90 roughly and now they're up to $3.30 But for BP which has a very large gas position in North America, we have reduced the number of operating rigs that we've had from 24 in 2010 down to 12 in 2011. And at the year end of 2012, now we're only down to the 5 rigs. We have reduced our activity to 0 rigs in the dry gas basins. And we have changed our portfolio by moving out of the mature basins.
Some of them are Hugoton, the Jonah and the Anadarko gas plants for example and we've been moving into the liquid rich areas of the Eagle Ford in Texas and Utica in Ohio. And we'll further continue to shift our investments to the liquid rich areas. We'll retain the optionality on the dry gas And I think for BP right now, it's a question mark. What will happen is a lot of gas in the U. S.
It's still a question mark. I think the U. S. Will to a limited degree export it. But we're adjusting both the portfolio and the investment levels to suit what we see there.
The gas markets now are very regional around the world. Deepan is that
Yes. That's helpful, Bob. I was
just wondering on the I mean, do you have any
sort of hard numbers in
terms of what you're thinking of the production for this year and then beyond that?
Well, we've been careful not to give specific basin production. I think overall you're talking about for the overall or the unconventionals?
Yes. Just unconventionals on the U. S. Liquid side in the U. S.
Just trying to get a sense
of
what it may contribute to underlying growth this year and beyond?
Yes. It's not significant in the Utica most certainly. In the Eagle Ford, we've got a healthy production there. But I don't have the exact figure with me right now and maybe Jess can, but we have we've got to be careful about giving out the base numbers. But in terms of a significant boost in underlying increase in production for us in the U.
S. And the unconventionals, it's not really material.
Okay. Thanks. I'll follow-up with Jeff.
Yeah. Thanks, Chi Pang. Can we turn now to Lydia Rainforth at Barclays?
Thanks, Jess, and good afternoon. A couple of questions, if I could, please. Firstly, can you just talk about the outlook for the Gulf of Mexico for the next year and what you're seeing there? And then secondly and partly related to that on the cost side, it does appear that certainly the cost per barrel have risen throughout the last couple of years, but there has been a lot of maintenance going on. Can you just talk through how much of that increase you think is related to maintenance and how much is actually BP doing things differently?
Thank you.
Well, on an underlying basis, we're going to be flat in 2012 to 2013 in terms of our Gulf of Mexico production. We have divested roughly 50,000 barrels a day in 2012 in the Gulf of Mexico and then we expect the production to begin to rise consistently up off of 2013 into 2014, 2015 2016. Our increase in spending is going to be driven by what is now last year, a year ago we had 5 rigs running. Now we're going to have 7. We're going to be moving into development drilling wells in Thunder Horse and Atlantis water injection at Thunder Horse.
We've got project startups on Nikika Phase 3 and Atlantis a project called Atlantis 2A. And then beyond 2015, our spending will really be driven by the Thunder Horse expansion and then we've got project startups after that Atlantis 2B and the 2nd phase of Mad Dog. We see oil field inflation, sector inflation running 5% to 10% broadly around the world, but very, very different depending on where you are. And I think the cost increases in the Gulf of Mexico are clearly at the higher end and in some categories even higher than that. We have been doing a period of plug and abandonment work.
It's called idle iron projects in the Gulf of Mexico. We'll be moving now into right now where it's our spending is in development and injection work, injector wells and then appraisal exploration and appraisal work going forward. I think that we have passed the high point, low point, but now you look at it in terms of our maintenance spending in the U. S. Number of turnarounds are going down next year.
I could give you some there may be too much over the call, but some of the activity of what we're doing in terms of Atlantis Med Dog and Akika and Thunder Horse going forward. But I think what I would just say is that those are our 4 big hubs. We've got work to do on all of them that will continue to drive production up starting in 2014 over above 2013. Still very optimistic about the Gulf of Mexico what we need to do. I will say that broadly I know this is not just BP, but the more rigs you have running the more time and care is being taken in our industry and blowout preventers around the world.
And the downtime not just for BP, but every operator I talk to is quite significant still in terms of blowout testing and the time taken to drill wells. And we've got to go through a period here where that where the industry goes through that phase. And that's obviously affecting us in terms of rig days, but it's not just us. And I could go into specifics, but probably not on the call. Does that get at your question Lydia?
Yes. Thank you.
Yes. Okay.
All right. Thank you. Can we go now to Alastair Syme at Citi? Go ahead Alastair.
My question is actually very similar to the second part of Lidya's. It was about the production cost about the trend you're seeing in cash costs on the upstream side in 2012 in terms of year on year inflation and how you think that plays out in 2013 as you have greater efficiency for the producing asset?
Well, our yes, it's very, very similar. 5% to 10% depending on which basin you're in is clearly is driving costs up for all the companies. In our case, as we get back to work and we are moving up to the 15 to 25 range of number of exploration wells that we're drilling. The building of technical and engineering capability work towards these 15 major projects now has been an increase in scope for us. And everyone in the industry knows that the skilled labor continues to be a key driver of industry cost and inflation.
Our turnover of personnel is down. We hired 2,000 people last year of experienced upstream people. I think we're past that period now. So we do expect to remain competitive in performance through the work that we do selecting the right activities, planning it well, having effective procurement and then executing it efficiently. And our eyes on that now solidly and has been now for the last year as we moved out of the basically the response on safety and reliability as the top priority.
And now we're doing both that and the execution of projects. So I see our costs as being competitive going forward.
And can I just clarify the 31,000,000,000 dollars target in 2014,000,000 it still works with an inflation in production costs? It doesn't imply a reduced cost base as efficiency improves?
Well, we have some we have cost efficiencies built into that target. We also we base that $30 to $31 based on $100 oil. So we think that is very much on track for 2014 at $100 oil and we're not going to rebase the target. And if the costs are up because of higher oil prices, we still think we will be able to normalize back to that target at
$100 Okay. Thank you.
Right. Moving now to Irene Himona at SocGen. Go ahead, Irene.
Yes. Good afternoon. Thank you. I had three questions, please. So first, can you remind us of the asset disposals that you have announced excluding T and K BP, how much cash remains to be received in 2013?
Secondly, on the U. S. Unconventionals, could you give us a sense of the size of that business, either in your balance sheet or production please? And then finally on the EPA debarment, Do we is it possible to discuss some of the conditions that actually need to be fulfilled for that to be lifted? Thank you.
Yes. So Brian on first.
Yes. Rene on the first question, the disposal proceeds still yet to be received this year. And of course, City we had the proceeds come in last week. But for this year in total we still have about $5,000,000,000 of proceeds to come in from what we announced last year, of which $1,500,000,000 arrived last Friday from Texas City.
Okay. Irene, your second question was on U. S. Unconventionals and it cut out for a minute on the balance sheet.
The size of the business, I was saying either on your balance sheet or in terms of current production?
Yes. We'll get back to you on U. S. Production. I don't know whether we put that out separately.
But on the size of the balance sheet, what I would say is that under IFRS, we have continually adjusted our and impaired the assets down with the oil price. And we did that in the Q2 of last year. And then I would say if we were to look at the oil prices today we would some of that might come back on. But I think our balance sheet is sort of been continually adjusted under the IFRS rules. On the EPA debarment and the conditions, it has to do with sort of the technicalities of the plea agreement that was reached that I think has been made public.
I'm going to be careful just in case it hasn't, but certainly outline of the plea agreement. But it has something to things to do with ensuring safety monitoring of our operations. And beyond that, it's a very, very complicated legal process that we're involved in. And I can't tell you exactly what the conditions would be for that. But we're going to meet our obligations.
We're going to work with the EPA which is sort of a focal point for lots of different agencies in the U. S. And I can't tell you how long it takes. I just know it's a very complicated process. And as I mentioned earlier, it doesn't affect our existing operations permitting processes in the Gulf of Mexico.
It primarily has to do with future lease sales or sales of fuel to the U. S. Government.
Okay. Thank you very much.
Right. The next question comes from Martin Ratz of Morgan Stanley.
Hi. Hello. I wanted to ask you about 2 things. In the beginning, you referenced the BP Energy Outlook 2,030, which calls for quite a structural energy demand over the next 20 to 30 years. But over the short to medium term, it actually calls for a rather rapid build in spare capacity and a rather large reduction in the coal and OPEC.
And looking at oil markets over the last couple of weeks, clearly, there's no sort of concern visible in the oil price. But on in the scenario where that happens and oil comes down, what's the scope for BP to respond? And I was wondering if this scenario is slowly but surely also making its way into your strategic planning around CapEx and things like that? The second question I wanted to ask revolves around legal spending besides the sort of settlements that you've announced over the last 12 months. I can imagine that also actually the cost of running the process has been rather large.
And I was hoping if you could sort of give a sort of indication of the order of magnitude of that in case that sort of unwinds over the next year or 2?
Martin, all good questions. I'll take the first bit and then Brian can comment here. I would say that the energy outlook to 2,030, I mean there's the fundamentals of what's in storage today and the possibility of potential production and surplus of demand. I note that Saudi Arabia has reduced itself its production by about 1,000,000 barrels a day in the last quarter. And I think OPEC does continue to adjust based on these this outlook that they see as well.
We do evaluate our projects on $80 a barrel. I'll let Brian comment on the strength of the company should the oil price fall, which we obviously do always brace ourselves for that and always have. So once you comment on that and then we'll come back to the legal costs.
Yes, Martin, in terms of stress testing, we do run stress tests. And one of the stress tests we run is a prolonged 2 year period at $80 a barrel. And we have various scenarios in place for how we would manage that around being able to make sure we could fund the balance sheet and manage the financial framework. I'd also comment that that's far more comfortable from where we sit today with our gearing today is the lowest it's been certainly since pre Macondo. So actually the balance sheet has strengthened up over the last 2 or 3 years even with all the outgoings that we've seen.
So we're in a far more robust position today to withstand $80 a barrel, but we do have various scenarios we run and we do have a whole activity plan that we'd have in place that would see us be able to withstand that for a period of 2 years.
Yes or more and including the dividend absolutely.
Sorry, no, when you say underpinning the dividend those prices?
It's very hard to quantify, but I think the world continues to see sort of underlying geopolitical tensions and uncertainties. And that's clearly hard to measure in the oil price, but it also seems to be a bit chronic. The other thing I would add to your question around the legal cost, I'd just say they're very high. It's a very expensive system to work within to meet the obligations that we have to work through the processes. It's very complicated.
It's very expensive. I'm looking here to see if we can say anything about it at all. Yes, so Jess has reminded me we do have legal costs in the provisions are there. The settlements that we've done with the plaintiff's attorneys have a very large legal administrative fee that goes along with those. And I would hope that in time that we could begin to see those things unwind in time as we move through the process.
Certainly, I think I should stop there.
I would go to. Well, actually Martin I would comment that of course we do have the criminal and SEC settlements behind us and now agreed. So of course all of the external accounts that we're using in that particular space has clearly been closed down and there's no run rate associated with those.
All right. Okay. Thanks very much.
Okay, Martin. We do have a very high quality legal team that are helping us through this process. I will say that for sure. Okay, Martin. Thanks.
Okay. Lukas Herman from Deutsche. Are you there Lukas?
Yes. Jess, thanks very much. Gentlemen, can you hear me?
Perfectly, Lucas.
2 or 3 if I might. I just wanted to start with and forgive my ignorance. The operating cash flow guidance €30,000,000,000 to €31,000,000,000 How do you or within that, how do you think about the provisions that are still sitting on balance sheet and potentially may flow associated with the Deepwater Horizon trial? In short, if you were to reach an agreement and it was within the amount you provided, are those sums included in 3,031 or would they be additional? Secondly,
just whether
you can give us some idea of what the contribution from divested activities was in the Q4, I. E. What the profit from the U. K. And U.
S. Businesses was that will not be ongoing in Q1? And thirdly, if I might, if you could just walk through the Whiting process and the steps associated with actually bringing that facility on in the second half. I don't mean huge detail. I just mean how much capacity in essence is out and when will full margin when will you be in a position to capture full margin?
Okay. Lucas, good questions. I'm going to Brian on the operating cash flow guidance and contribution of the divestments.
Yes. So on the first question Lucas clearly in the $30,000,000,000 to $31,000,000,000 that's already net of anything that we've laid in place. So the payment schedule around the DOJ and the SEC payments are already inside that number. And of course that number still has if you go back to this 50% of additional cash versus 2011 of which half is for capital half for other purposes. I think we had this on the call that we talked about the 3Q that of course those other purposes can be set aside for that.
And there's about $3,000,000,000 available that would look to be able to cover any range of uncertainties out there including progressive dividend and other things from where we are today. So everything which is inside the number out in 2014 includes anything which we've settled already. Of course the existing outgoings associated with the trial in place of course is not inside that number today.
Okay. So just to be absolutely clear, if you were to agree something the €3,500,000,000 provision for example example you've got sitting on balance sheet for clean water and that were to be expensed over 3 years starting 2014 that would eat into that €30,000,000,000 to €31,000,000,000
That's a hypothetical question. But I think what you'd say is there is not so let me be really absolutely clear. Inside the €30,000,000,000 to €31,000,000,000 there is no cash outflow associated with Clean Water Act fines and penalties.
Lovely. Thank you.
Lucas your contribution of the divestments in the U. S.
Yes. Sorry, Lucas. The biggest piece of course is TNKBP that we only have 21 days of earnings. It's a bit too lumpy to give you the exact figures because of course the assets went out at different points during the Q4. We can come back to you with a sort of broad figure on what that looks like in terms of earnings.
But it's the Gulf of Mexico went out from memory halfway through the quarter. The North Sea assets went out towards back end of the quarter. So it'd be pretty difficult to actually give you a point in time estimate for Q4. Okay.
But Lucas the 4th quarter production impact. So in the Q4 over 2011 was 116,000 barrels a day, so it's significant overall. On the Whiting project, so this is a project again just this is a structurally advantaged project to process the Canadian heavy crudes with a lot of flexibility there. The site construction as of this week, so it's 84% complete at the end of the year. It now continues to move through and so well above 85% complete.
The commissioning is on schedule second half of the year. And the major crude unit outage started on schedule in early November and that will continue to be out until the middle of 2013. And I think for us the whole commissioning process will take roughly 6 to 9 months with 3 of the major units starting up in the sequence there. So we do anticipate that 2014 will be the 1st year that we get the full benefits of as these operations continue on in the middle of the year. I think around the middle of the year that's when you'll see us start getting very precise about as these units come up and on.
Okay. Gentlemen, thanks very much.
Okay. Thanks, Lucas.
Next question from Bertrand Hodee at Raymond James.
Yes. Thank you, Jessica. Two questions, if I may. Can we expect in 2013 BP to launch or to sanction some major projects? You only sanctioned 3 projects in 2012.
You mentioned a possible 5 in 2013. And can we expect the likes of Chardanese or your also I would say big opportunities to be sanctioned in 2013? And the second question is how critical would it be to BP exploration portfolio in the Gulf of Mexico if BP would not be able to participate in next March round lease in the central part of the Gulf of Mexico? Thank you.
Thanks Bertrand. You're right. We had 3 sanctions this year, none of which were mega projects. We do see 5 sanctions in our FIDs during 2013. We normally don't lay out the FID points themselves.
And I would note that some of our partners don't necessarily consider an FID as the defined gate. But we've got our eye on 5 projects of which 4 of those are very large. I will name the ones that we are clearly have been talking about externally. 1 is the Tengu Train 3 in Tengu. The Tengu expansion is a big one.
Shock Denise, we're working through now the economics of those complicated pipelines that are so critical to the economics of that project. We're looking at Angola Greater Plutonium Phase 3. We're looking forward to and we'll know more about India here in about a month or so. So we've got a good healthy list that I think will get us back in terms of looking at reserve additions as well as we go forward. In terms of exploration in the Gulf of Mexico, today we are the largest leaseholder in the Gulf somewhere between 70750 leases.
It is a lot on our plate. So it's so we haven't made a decision and we haven't actually been told we cannot bid on the March lease sales. But if we don't, it's okay.
Okay. Thank you. Okay.
Next question from Peter Hatton at RBC.
Good afternoon and thanks for all the details this afternoon. I was actually following on from a similar question on FID 3 that you took in 2012, sort of lower than trend rate. What put ENGIE doing more? Was it just a kink in the pipeline of future projects? Or is it that BPCs itself is fully loaded and enough on its plate?
And the second one is thanks for guidance on the gearing and 10% to 20% moving to 20% to 30%. There's prospective significant shareholders in Rosneft with 20% where would BP in that division see an appropriate gearing level for them given their risk and obligations?
Yes. Peter, first, I do think it was a kink in the pipeline. If you look historically, we have sanctioned 5 to 8 projects a year for a decade. I think if I look back and we have been looking back very carefully at our exploration record and our exploration spending. And 2,009, 2010 even going back a little bit before that, the amount of acreage that we were adding and the amount of exploration drilling we did really did dip down and there's always a consequence of that.
And I think that's what we were beginning to see with the kink in the pipeline, which I think is a good way to describe it. It's not a sustained kink. We've got I'm looking at 5 plus sanctions in 2013 and even more in 2014. So that's not a and there's no assumptions in there at all for exploration success as well. Gearing level, I would say it's not guidance.
It's just it's something we have been talking with shareholders about and there's no I don't mean to give guidance, but we will as it's possible.
Yes. The third question I think around Rosneft and what a suitable gearing is for that business is really a question for the Finance Director of Rosneft. That's not really one for us to approach here.
But as 20% holders would you presumably you would have a view, but you've expressed that directly to Rosneft not through to all our analysts?
Yes, that's right. I mean, we haven't we don't have the insight into the Rosneft processes yet and their Board. And it wouldn't be appropriate for us to comment on that. Obviously, they have are taking on everyone knows they're taking on debt for the TNKBP transaction, but I also know these oil prices they are capable of generating cash flow to certainly handle that in a healthy way. They're also using other means of raising debt such as crude oil trade sales, which is another way of doing it.
So it's way too early for us to comment on that.
Okay. Thank you.
Okay. And the final question then from Jason Kenney in Santander.
Thank you very much. Sorry, I was a bit late to the call. So I can only apologize if you've answered a couple of these points. And you probably won't answer my first one anyway, so but I'll give it a shot.
Settlement, right?
Yes. So you've got a view of what a reasonable settlement figure for the U. S. Litigation would probably be. I'm just wondering if you've undertaken a straw poll of what investors in BP might think a reasonable figure is.
And I know you're not going to tell me either number, but are you at least able to say if those two numbers are in the same ballpark or not? And the second question, a bit more traditional, I suppose, on North Africa. And again, I can only apologize if you said something earlier on this, but what is the impact of the Algeria outage? And do you see any pressure for your activities in North Africa particularly Libya near term?
Jason, so that I can satisfy your question, because I won't start with the settlements and the numbers. I'll talk about North Africa and we'll come back on the settlement in a minute. North Africa, in Namenas was around 17,000 barrels a day for us. So you think about that with a 2,300,000 barrels a day company, it was a good return project for us, but not significant in terms of volume terms. We do remain committed to Algeria.
We're working in Ansala as well. These are good projects for us. We are going to be very, very careful. We're going to work closely with Sunitrac and the government along with Statoil and our contractors to make sure the conditions are right for when we go back to work in Algeria. In Libya, we have no production.
We have no facilities there. We have 2 exploration acreages 1 offshore where our planning work continues. And then onshore, we're down in the Godamas Basin near the Algerian border, not too far away from where Enemias was. So certainly for the time being, I would say it's in hibernation. But we also remain committed to doing business in Libya.
And as an oil company, we frequently and often take on projects as does our industry in tough places around the world. And I think it's I've been cautioning some in the media just not to overreact too quickly and draw conclusions after an event like that. I think that's the mode we're in certainly on high alert and looking at all of our facilities. We have had a healthy number of questions on settlements and numbers earlier in the call Jason. And I think we're probably going to give you about as much satisfaction as we gave everyone else, which is really something we can't talk about.
But I would note with the trial coming up in 20 days, we're sort of in the chute to get ready for the trial.
Okay. Many thanks.
Yes. Well, thank you everybody. I
think that is the last set of questions. I think as BP began 2013, it began to feel like we were back to a normal corporate rhythm of getting ready for the year, starting up 2 projects in December, getting the redevelopment of Auhall going in January. These are all important milestones for us. We're laying out our plans. We did get a bit of a jolt with what's happened in Algeria.
The company itself as I've said is a very tight knit company. It's a big company, but it's very tight knit and people knew many of the people impacted on it. But as we move that we will go on. We'll keep going on. We've got some many exciting things happening this year in terms of new projects.
The Rosneft transaction is moving along. I think that's been a problem turned into an opportunity for BP. And of course the legal processes in the U. S. Are quite mind boggling and it's for us to say exactly where that heads.
But it just feels very different than it did in 2011. It feels better than it did in 2012. I think the company continues to move through the transition. And thank you all for your