英國石油 (BP) 2013 Q4 法說會逐字稿

Welcome to the BP presentation to the financial community webcast and conference call.

I now hand over to Jessica Mitchell, Head of Investor Relations.

Hello, and welcome, everyone.

This is BP's fourth-quarter and full-year 2013 results webcast and conference call.

I'm Jessica Mitchell, BP's Head of Investor Relations.

I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary.

Before we start, I need to draw your attention to our cautionary statement.

During today's presentation, we will make forward-looking statements that refer to our estimates, plans, and expectations.

Actual results and outcomes could differ materially due to factors that we note on this slide, and in our UK and SEC filings.

Please refer to our annual report, stock exchange announcement, and SEC filings for more details.

These documents are available on our website.

Thank you, and now over to Bob.

Thank you, Jess, and welcome, everyone, wherever you are in the world.

Thanks for joining us today.

We're here to look back at 2013.

It was a busy year, and also a successful one.

We accomplished a number of important things.

We improved our safety record.

We had a very good year for exploration; in fact, our best in 10 years.

We started up a series of major new projects, both in the upstream and the downstream.

In Russia, we created a new future for BP.

And at the same time, we released some of the considerable value we generated with our former joint venture, TNK-BP.

A large part of that is currently used for buybacks; a good outcome all around.

We also announced some significant new investments for the future that we believe will create value for BP for decades to come.

In particular, these included the huge Shah Deniz 2 natural gas project in Azerbaijan, with the associated pipeline stretching well into Europe, and also the giant Khazzan project in Oman.

We also increased the dividend by 11% in dollars compared to 2012.

We are not complacent, but we are pleased with the progress.

These are all important milestones on the way to delivering our 10-point plan, and these will all contribute to sustainable growth and free cash flow in the years ahead.

What you can see now is a company that has a more focused and stronger portfolio, leading positions in exploration, deepwater, and giant fields, and a quality downstream business.

And we will continue to play to these strengths.

We will do this through disciplined capital investment in a high-quality upstream project pipeline, and a downstream that is a strong generator of cash for the Group.

And we will do all this while maintaining a relentless focus on safety, and reducing operational risk.

So, turning to today's agenda, we'll start with a summary of our full-year results, and then look at progress against the 10-point plan.

Brian will take you through the details of our results for the fourth quarter.

Then I will update you on our safety performance, Rosneft's progress, legal proceedings in the US, and our ongoing work in the upstream and downstream.

And then we will take your questions.

So, let's begin with an overview of our full-year 2013 results.

Our underlying replacement cost profit was $13.4 billion.

Post-tax operating cash flow was $21.1 billion.

Our organic capital expenditure was $24.6 billion, in line with our guidance, and we divested $17.1 billion of assets during the year.

Our gearing at the end of the year was 16.2%, which is within our target band of 10% to 20%.

We distributed $5.4 billion in cash to shareholders through dividends, and we also bought back $5.5 billion of our own shares.

These results reflect a number of different factors.

Among them are the restructuring of our portfolio through divestments, a weaker environment in the downstream, large working capital build, and the increased exploration write-offs which have accompanied our ramp-up in exploration drilling.

That said, it has also been a year of strong results in our underlying operations, which I will come back to in a short while.

We are confident that the full financial momentum from this progress will become clearly evident in 2014 and beyond.

To reinforce that point, let me give you another figure.

Our reserves replacement ratio for 2013 was 129%, excluding the impact of acquisitions and divestments.

If we include the net reserves growth as a result of the repositioning in Russia, the reserves replacement ratio was 199%.

I believe this result is a strong indicator of the growing short-term and long-term momentum in our Business as we pull through the drivers of long-term growth.

Let me update you a little more on some important milestones.

As many of you will recall, our 10-point plan consisted of things you could expect, and things you could measure.

And 2013 has set us up well to deliver.

The first commitment was to continue to make safety the top priority, and we're seeing positive results, as you can see in a moment.

We also said we'd build a stronger portfolio and simplify the Company while playing to our strengths, from exploration to high-quality downstream businesses.

And we have delivered on that commitment.

We have completed the $38-billion divestment program outlined to you in 2011, and we are now a smaller but much more focused Company.

The divestments have removed complexity, strengthened the balance sheet, and left us with a more distinctive set of assets.

And with our third-quarter results, we announced our intention to divest a further $10 billion of assets before the end of 2015.

This will further focus the portfolio, and provide additional free cash flow from which we plan to increase distributions to shareholders, primarily through buybacks.

The successful completion of the transactions associated with TNK-BP and Rosneft demonstrated our ability to turn a major challenge into a unique opportunity.

It also makes us a 3.2-million-barrel-per-day oil company, when adding our interests in Rosneft to BP's own production.

While reshaping the portfolio, we also continue to deliver some significant milestones in our businesses.

For example, in the upstream, we have continued to reload the exploration portfolio, and also made seven potentially commercial discoveries in 2013, in Angola, Brazil, Egypt, the Gulf of Mexico, and India.

We also saw a series of high-value upstream projects come online.

During 2013, three more projects started up, following the five we started up in 2012.

These included the first phase of the BP-operated Atlantis North Expansion in the Gulf of Mexico, and two more partner-operated assets, the Angola LNG plant, and North Rankin 2 in Australia.

I'm pleased to be able to tell you today that the Chirag oil project in Azerbaijan came online last week, and Mars B in the Gulf of Mexico, another oil project, has come online today.

In the downstream, we announced last month that all the major units associated with the Whiting refinery modernization project have been brought on stream.

We continue to expect the reconfigured refinery to deliver an incremental $1 billion of operating cash flow per year, depending on the environment.

So, as we end the year, the track record of delivery continues to build.

We have a much stronger balance sheet, and we are confident of delivering our important goal for 2014, to increase operating cash flow by 50% between 2011 and 2014, assuming $100 oil.

It is this confidence that enabled us to increase our dividend with our third-quarter results in line with our progressive dividend policy.

On the 4th of March, we will tell you more about our future plans.

We will show you how we plan to continue playing to our strengths to drive material growth in operating cash flow.

Coupled with our focus on capital discipline, we expect this to drive continued growth in free cash flow, enhancing our ability to increase distributions to shareholders.

Let me now hand over to Brian to take you through the results for the fourth quarter.

Thanks, Bob.

BP's fourth-quarter underlying replacement cost profit was $2.8 billion, down 27% on the same period a year ago, and 24% lower than the third quarter.

Compared to the fourth quarter of 2012, the result reflected higher non-cash costs, including exploration write-offs and DD&A, a significantly weaker refining environment, and significant divestment impacts, partly offset by improved underlying upstream production in high-margin regions and stronger earnings from Rosneft compared to TNK-BP in the same period in 2012.

Fourth-quarter operating cash flow was $5.4 billion.

The fourth-quarter dividend, payable in the first quarter of 2014, is $0.095 per ordinary share, up 5.6% compared to the same period last year.

Turning to the highlights at a segment level, the upstream underlying fourth-quarter replacement cost profit before interest and tax of $3.9 billion compares with $4.4 billion a year ago, and $4.4 billion in the third quarter of 2013.

Compared to the fourth quarter of 2012, the result reflects higher non-cash costs including exploration write-offs associated with increased exploration activity and higher DD&A, along with some sector inflation; lower production due to previously announced divestments, primarily in the North Sea and the Gulf of Mexico; and lower liquids realizations, partly offset by improved underlying volumes in high-margin regions, a one-off benefit to production taxes, stronger gas marketing and trading results, and higher gas realizations.

Fourth-quarter reported production, excluding Russia, was 1.9% lower than a year ago, primarily due to the impacts of divestments.

On an underlying basis, after adjusting for divestments and entitlement effects, production increased by 3.7%, partly reflecting new major project volumes in the North Sea, Angola, and the Gulf of Mexico.

Compared to the third quarter, the result reflects higher costs partly due to the exploration write-offs, absence of the one-off benefit in the third quarter related to the trans-Alaska pipeline system, and lower liquids realizations, partly offset by improved underlying volumes in high-margin regions, a one-off benefit to production taxes, and higher gas realizations outside of North America.

Looking ahead to the outlook for the first quarter, we expect reported first-quarter production to be lower than the fourth quarter of last year, reflecting the impact of divestments and the expiry in January of the Abu Dhabi onshore concession.

Turning to Russia, this slide shows our share of earnings from Rosneft, and historically from TNK-BP.

BP's underlying net income related to its Rosneft shareholding was $1.1 billion in the fourth quarter.

This compares to BP's share of TNK-BP net income in the fourth quarter of last year of $220 million, which included only 21 days of earnings.

Compared to the third quarter, underlying net income was up $270 million.

The fourth quarter was favorably impacted by the finalization of BP's equity accounting for the year, and includes certain adjustments to net income in respect to prior quarters.

These effects are partially offset by adverse foreign exchange and duty-like effects, and by lower realizations.

BP's share of Rosneft production in the fourth quarter was 985,000 barrels of oil equivalent per day; 20,000 barrels per day higher than the previous quarter.

In the downstream, the fourth-quarter underlying replacement cost profit before interest and tax was $70 million compared with $1.4 billion a year ago, and $720 million in the third quarter.

The results included a loss of $200 million in the fuels business, compared with a $1-billion profit in the same quarter of last year.

This reflected a significantly weaker refining environment, the absence of earnings from divested Texas City and Carson refineries, and a weak result from our supply and trading activity, and additional depreciation and start-up costs as a result of the Whiting refinery modernization project.

This was partly offset by strong refining availability and lower turnaround activity.

The lubricants business reported an underlying replacement cost profit before interest and tax of $230 million compared with $330 million in the same quarter last year.

This reflects restructuring charges, as we seek to improve the competitiveness of our mature European businesses.

The petrochemicals business reported an underlying replacement cost profit before interest and tax of $40 million, broadly flat compared to the same period last year.

Results were impacted by the environment, which continues to be challenging, with excess supply in Asia and the United States, partly offset by lower turnaround activity.

Looking forward to 2014, we expect refining margins to improve from the levels seen in the fourth quarter, but in general, we expect the fuels and petrochemicals environments to remain challenging.

We also expect an increased exposure to heavy crude differentials in the United States, as we ramp up heavy crude processing at the Whiting refinery.

In other business and corporate, the pre-tax underlying replacement cost charge was $610 million for the fourth quarter, an increase of $170 million on the same period a year ago.

The fourth-quarter results included certain one-off charges compared to one-off benefits that occurred in the same period a year ago.

The full-year charge of $1.9 billion was within guidance levels, and $100 million lower than the previous year due to lower corporate and functional costs.

The effective tax rate on underlying replacement cost profit for the fourth quarter was 24.3%.

This is lower than the third quarter, reflecting higher income from Rosneft, which are reported net of tax, and a number of one-off favorable fiscal settlements in several jurisdictions related to previous years.

The full-year effective tax rate on underlying replacement cost profit was 35.4%, slightly below our guidance range for 2013.

The charge for the Gulf of Mexico oil spill was $190 million in the fourth quarter, primarily reflecting an increase in the provision for legal costs, plus the ongoing cost of running the Gulf Coast Restoration Organization.

This brings the full-year charge to $470 million.

The total cumulative net charge for the incident to date is now $42.7 billion.

The charge does not include any provision for business economic loss claims that are yet to be paid.

Bob will provide an update on the legal process shortly, but as he had advised at the third quarter, it is still not possible to reliably estimate the remaining liability for business economic loss claims.

We will continue to revisit this each quarter.

The pre-tax cash outflow on costs related to the oil spill for the full year was $1.4 billion.

The cumulative amount estimated to be paid from the trust fund remained at $19.3 billion, leaving unallocated headroom available in the trust for further expenditures of around $700 million.

In the event that the headroom is fully utilized, subsequent additional costs will be charged to the income statement.

At the end of the year, the aggregate remaining cash balances in the trust and qualified settlement funds were $6.7 billion, with $20 billion paid in, and $13.3 billion paid out.

And, as indicated in previous quarters, we continue to believe that BP was not grossly negligent, and have taken the charge against income on that basis.

Now, turning to divestments, our $38-billion divestment program is now complete, and in the first quarter, we also completed the sale of our share of TNK-BP to Rosneft for $27.5 billion.

Following the receipt of cash proceeds of around $12 billion from the TNK-BP transaction, we also announced the share buyback program of up to $8 billion.

To date, $6.8 billion of shares have been repurchased for cancellation, of which $5.5 billion were repurchased in 2013.

In October, we announced plans to divest an additional $10 billion of assets by the end of 2015, and to use the post-tax proceeds predominantly for shareholder distributions, with a bias to share buybacks.

So far, we have agreed around $1.7 billion of additional divestments.

Now, looking at our full-year cash flow movements, this slide compares our sources and uses of cash in 2012 and 2013.

Operating cash flow for 2013 was $21.1 billion, which includes $1.4 billion of pre-tax expenditure related to the Gulf of Mexico oil spill.

Excluding these costs, underlying cash flows of $22.5 billion were also impacted by a net working capital build of around $5 billion.

Compared to 2012, a higher working capital build and the impacts of divestments offset the benefits of strong underlying volume growth from the ramp-up of major projects and improved operating efficiency in the upstream business.

In the fourth quarter, we received $400 million of divestment proceeds, bringing the total for the year to $17.1 billion, including the net cash received from the divestments of our share in TNK-BP.

Full-year organic capital expenditure was $24.6 billion, of which $7.1 billion was in the fourth quarter.

Net debt at year end was $25.2 billion, with gearing of 16.2% compared to 18.7% a year ago.

Our intention remains to keep gearing at a target band of 10% to 20%, while uncertainties remain.

Turning to our forward-looking guidance for 2014.

The Abu Dhabi onshore concession expiry has an impact on production of around 140,000 barrels of oil equivalent per day.

Adjusting for this and the impacts of divestments, we expect full-year underlying production in 2014 to increase compared with 2013, with reported production being lower due to these effects.

The actual reported outcome will depend on the exact timing of project start-ups, divestments, OPEC quotas, and entitlement impacts.

Organic capital expenditure in 2013 was $24.6 billion, and as previously indicated, we expect 2014 capital expenditure to be between $24 billion and $25 billion.

The DD&A charge was $13.5 billion in 2013, and is expected to be around $1 billion higher in 2014 as production on new projects ramp up.

In other business and corporate, the average underlying quarterly charge is expected to be in the range of $400 million to $500 million, although this may fluctuate between individual quarters.

The effective tax rate for 2014 is expected to be around 35%.

We will provide updated rules of thumb for 2014 on our website later this month.

Before I hand you back to Bob, I'd like to summarize our overall financial framework.

We expect the combination of continued operating cash flow growth and capital discipline to enable us to grow sustainable free cash flow, underpinning progressive dividend growth into the future.

We expect to deliver operating cash flow of $30 billion to $31 billion in 2014, with continued material growth thereafter.

2014 capital expenditure is expected to remain at a similar level to 2013, between $24 billion and $25 billion.

Beyond 2014, we expect annual capital expenditure to be in the range of $24 billion to $27 billion through to the end of the decade.

We will continue to actively manage our portfolio.

As previously announced, we plan to divest a further $10 billion of assets before the end of 2015, using post-tax proceeds predominantly for distributions with a bias to share buybacks.

And finally, we intend to keep gearing within the 10% to 20% band whilst uncertainties remain.

Now let me hand you back to Bob.

Thank you, Brian.

So, now I want to walk you through some of the important details of our 2013 performance, and I'll start with safety.

These charts show an encouraging trend, one that I believe reflects the disciplined approach we're taking to our operations around the globe.

Looking first at losses of primary containment, which records even very small releases, 2013 showed a 4% reduction in 2012 when adjusted for divestments, continuing a multi-year improvement.

We also track process safety events, the American Petroleum Institute-recommended industry metric.

In 2013 we saw a 47% reduction in the most serious incidents, known as tier 1 events, versus 2012, again, adjusted for divestments.

We also continue to focus on personal safety, and our recordable injury frequency rate remains at levels comparable to, or better than, industry benchmarks.

Safety is at the heart of BP, and it is good business.

We are pleased with this progress, but by no means do we take it for granted.

Let's move on to our investment in Russia.

Rosneft has now completed the initial integration of TNK-BP, and laid out its strategy for the enlarged company, identifying significant synergies and benefits.

Momentum continues to build across Rosneft generally.

In 2013, they signed a number of binding agreements for joint ventures and projects with IOC partners.

These included unconventional development projects and also Arctic exploration.

JV operating companies were established, and significant quantities of 2D and 3D seismic were acquired.

Rosneft also continued its program of modernization in its downstream business, including upgrades at a number of refineries enabling them to produce premium-grade fuels.

Rosneft continued to deliver on their gas strategy, as Russia's regulatory and fiscal landscape evolves.

This has included the removal of Gazprom's official monopoly on LNG exports.

In this area, Rosneft made a number of acquisitions, and also finalized a number of long-term LNG supply agreements.

The changes to the fiscal terms in Russia have also increased the attractiveness of other opportunities within Rosneft's portfolio.

So, in summary, it was a significant year for BP in Russia, and also for Rosneft.

Our unique position in Russia not only makes BP a 3.2-million-barrel-a-day business, it also adds an additional 840 million barrels of oil equivalent to our proved reserve base, and opens the way for us to benefit from all of the achievements and progress that Rosneft delivers.

More widely, the relationship we have with Rosneft is growing, and we believe it will have significant long-term benefits for both Rosneft and BP.

Now, let me give you an update on the status of certain Gulf of Mexico-related legal proceedings in the United States.

The first phase of the MDL 2179 trial in New Orleans focused on the causes of the accident, and the allocation of fault among the defendants.

The second phase covered source control, and the quantity of oil spilled.

Both phases are now complete, with the court yet to rule on either.

While the final decision rests with the court, we continue to believe that the evidence in Phase I showed that the accident was a result of multiple causes involving multiple parties, and that BP was not grossly negligent.

We believe that phase II of the trial demonstrated that BP mounted an extraordinary response, and we believe it showed BP was neither negligent nor grossly negligent in its efforts, and the government's flow rate estimates are substantially overstated.

The penalty phase, in which the court will hear evidence regarding the penalty factors set out in the Clean Water Act, has not yet been scheduled for trial.

The US government, BP, and Anadarko will be parties in this phase.

Turning to the settlement with the Plaintiffs' Steering Committee, and the issues involving business economic loss, or BEL, claims.

As you know, we have been contesting the payment of claims which we believe to be unfounded.

BP has been successful in challenging the claims administrators' interpretation of the BEL framework with a panel of the US Fifth Circuit Court.

The panel reversed the interpretation and the District Court subsequently agreed that revenues and expenses must be properly matched, but failed to correct the practice of issuing awards to claimants whose losses are not traceable to the spill.

BP has again appealed to the same panel, requesting a permanent injunction to prevent such improper awards.

This panel has agreed to consider these causation issues on an expedited basis.

In the meantime, a temporary injunction remains in place for all BEL claims.

In a related development, on the 10th of January, a different panel of judges from the Fifth Circuit upheld the validity of the settlement as written.

However, it left to the BEL panel the question of how to interpret the agreement, including the meaning of the causation requirements I just mentioned.

BP has filed a petition for rehearing on the decision.

Separately, former federal judge Louis Freeh's independent investigation of the claims facility continues, and we recently received his second written report that describes some of the behavior at the claims program that led to the resignations of senior staff members.

We continue to hope that Judge Freeh's investigation will lead to steps that ensure public confidence in the integrity of the claims process.

And while we continue to pursue litigation challenging the EPA's suspension and debarment decisions, we are also continuing to work towards an administrative agreement to resolve these issues.

And finally, I should mention another case, MDL 2185.

This is a coordinated proceeding pending in federal court in Texas, and includes a purported class action on behalf of the American Depository Shares, or ADS, purchasers under US federal securities law.

Plaintiffs have filed a renewed motion following the court's initial rejection of a motion to certify a class; a jury trial on this action is scheduled to begin in October 2014.

In summary, we remain determined to pursue fair outcomes in all these proceedings.

Importantly, we continue to compartmentalize these activities to avoid distraction, and BP's operating teams remain clearly focused on delivering our strategy.

Moving on, let me update you on what we've done in our upstream.

It was an outstanding year for exploration, one which really showed the impact of playing to our strengths.

In total, we participated in seven potentially commercial discoveries across India, Egypt, Angola, Brazil, and the Gulf of Mexico, making 2013 the most successful year for exploration drilling for almost a decade.

This reflected the increased investment we have made in finding oil and gas, with 17 exploration wells being completed around the world in 2013, and between 15 and 20 planned for 2014.

The Lontra oil and gas discovery in the pre-salt layer in offshore Angola, announced by our partners, Cobalt, in October, was followed by a successful drill stem test in December, demonstrating the excellent quality of the reservoir.

The Petrobras-operated Pitu well was confirmed as a discovery in December.

This is a successful test of a new play in Brazil's frontier deepwater.

And also in December, we announced a discovery at the BP-operated Gila well in the deepwater Gulf of Mexico.

The Gila discovery was drilled in approximately 4,900 feet of water at a total depth of over 29,000 feet, and is BP's third operated discovery in the Paleogene.

Moving on to new operations, three projects were brought online in 2013: the Angola LNG project, the first phase of the Atlantis North Expansion, and the North Rankin phase II project.

And I've already mentioned the start-up of the Chirag oil project in Azerbaijan, and the Mars B project in the Gulf of Mexico, both of which came online in the last week.

We are also on track to deliver four further major project start-ups in 2014: the Na Kika phase III in the Gulf of Mexico, Kinnoull in the North Sea, CLOV in Angola, and Sunrise phase I in Canada.

Across the portfolio, we continue to maintain our focus on the safe, reliable execution of activities.

In 2013, we achieved a BP-operated plant efficiency of 88%, which was a significant improvement over 2012, and we expect this improving trend to continue as we move through 2014.

We successfully completed 20 planned turnarounds, including 12 in our key assets.

This represents a reduced level of activity compared to 2011 and 2012.

Looking forward, we intend to continue to invest in the reliability of our assets with a steady-state multi-year program, which we expect to require continued lower level of turnaround activity than in recent years.

At the start of the year, we identified 15 wells in key locations as the top wells for production delivery.

All of these were successfully drilled by the end of the year, with two remaining to be completed by the end of this month.

Delivery of production from new wells in 2013 increased compared to 2012, particularly from some of our key regions such as Azerbaijan and the North Sea.

We expect to continue this trend of improving well delivery, with production from new wells in 2014 forecast to be higher than in 2013.

Now, let me update you in more detail on our major projects.

Our recent key start-ups continue to ramp up their production.

For example, PSVM in Angola, which started at the end of 2012, reached plateau production of 150,000 barrels of oil per day.

In delivering this, our Angola team has started up all four fields that make up the asset, and achieved a first-year plant efficiency of 91%.

The Chirag oil and Mars B projects that started up this year represent major new infrastructure developments in significant established oil fields in two of our key regions.

Facilities completion on the next four start-ups in 2014 now exceed 75%.

During the fourth quarter, we reached several key milestones towards the delivery of these projects.

On Na Kika phase III in the Gulf of Mexico, we completed the subsea construction, and drilled two wells, with completion now under way, and expect well start-up in the first quarter.

We also began commissioning of Kinnoull in the North Sea, while on Sunrise phase I in Canada the initial 55 well pairs were completed ahead of schedule.

Most recently, the CLOV FPSO left the Paenal shipyard in Angola on the 20th of January to start the offshore hook-up and commissioning campaign.

Our 2012 to 2014 start-ups bring high-margin production online, and will, on average, deliver twice the operating cash margin of the upstream portfolio that we held in 2011.

Looking to our next wave of developments, we sanctioned two significant projects in the fourth quarter of 2013, which we expect to deliver value for BP for decades to come.

Shah Deniz stage 2 and its associated southern corridor pipelines will develop the next phase of this gas field in the Caspian, connecting it directly to European markets.

16 billion cubic meters per year of natural gas will be carried some 3,500 kilometers to Georgia, Turkey, Greece, Bulgaria, and Italy, while condensate production will increase from 55,000 to 120,000 barrels per day.

Meanwhile, our Khazzan project in Oman will see some 300 wells drilled over 15 years, delivering 10 BCMA of gas, which is equivalent to around a third of Oman's total daily gas supply, ensuring continued stable supplies from domestic sources.

So, in summary, this has been a significant year of building momentum in the upstream.

We continue to deliver results across access and exploration, projects, wells, and operations.

We have, after adjusting for divestments, delivered underlying production growth in every quarter of 2013 when compared to 2012.

This has been driven by improving execution of activity through our functional model, and a relentless focus on safe and reliable delivery.

Now, turning to the downstream, in 2013 there were continuing improvements in safety and reliability, as well as delivering several significant milestones.

The number of tier 1 safety events decreased, and the business achieved a steady decrease in losses of primary containment and recordable injury frequency.

Solomon refining availability was 95.6% for the fourth quarter, which was the highest level for BP since 2004.

In 2013, we met several important milestones, primarily focused on the repositioning of our US fuels business.

We completed the commissioning of all major units for the Whiting refinery modernization project, finalized the sales of the Texas City and Carson refineries, and started up new units at the Toledo and Cherry Point refineries.

We expect these changes to enhance the safety, margin capture, and operating efficiency of our US fuels business, and in turn, to provide significant cash generation for the Group.

Our lubricants business continues to be an important source of revenue growth and returns for the Group as it implements its strategy of investment in technology, exposure to growth markets, distinctive global brands, and targeted marketing programs.

We're also beginning to implement a program of transformation to improve competitiveness across our mature European businesses.

In January, we announced our decision to sell our specialist global Aviation Turbine Oils business.

After a careful review of our portfolio, we decided the business would offer more opportunities for other companies wanting to invest in this particular sector.

In petrochemicals, we continued construction of a third PTA plant at Zhuhai in the Guangdong province of China, which is on track for completion in late 2014.

In addition to Zhuhai, we are also retrofitting our existing facilities with our latest PTA technology to improve cost efficiency.

We also announced two new breakthrough petrochemical technologies in 2013: SaaBre and Hummingbird, which we expect to radically improve the cost of manufacturing the petrochemical feedstocks of acetic acid and the conversion of ethanol to ethylene, respectively.

Looking to the future, our focus in the downstream is to leverage our newly upgraded assets, customer relationships, and leading technologies to generate material and growing free cash flow for the Group.

In 2014, our capital investments are focused on safety, efficiency, and growth markets, and aimed at enhancing our advantage portfolio of assets.

So, I would like to close by summarizing what we've achieved, and look to 2014 and beyond.

We have talked today about the milestones passed in 2013.

These and other recent achievements form the foundations for delivering value into the long term.

Our aim is to grow sustainable free cash flow as we continue to build and operate a high-quality portfolio in which we prioritize value over volume.

And I think that value is very much the goal to focus on in today's environment.

It doesn't look like an easy sector right now, but I believe that you can succeed if you do the right things well.

It means continuously reloading our pipeline of opportunities through exploration success.

It means making the right investment choices.

It means sticking to the capital limits we have set.

And it means excellent execution of only the best projects.

At the same time, we will continue to actively manage our portfolio to ensure we are playing to our strengths, and divesting assets which are not core to delivering long-term value.

And we will always make safety and reliability the top priority in all we do.

We are confident that our hard work this year keeps us on track to deliver our commitment to growth in operating cash flow in 2014 and beyond.

We are strongly committed to our progressive dividend policy, and we look to use surplus cash to enhance distribution to shareholders.

We look forward to telling you more about what the journey ahead looks like on the 4th of March.

That's the end of our remarks.

And now Brian, Jess, and I will be happy to take your questions.

(Operator Instructions)

Oswald Clint, Sanford Bernstein.

The first question, Bob, I was looking at the US RCOP per barrel and how it has stepped up the past two quarters.

Into the mid-teens per barrel.

Obviously it's a business that's had quite a range of RCOP per barrel so I wanted to get some thoughts on where you think that number might actually get to over the next 12 months, and obviously the next couple of years, please.

Secondly I was interested in your comments on the most successful exploration year in a decade.

Is there anything you can point to that may have helped deliver that success, and is it possible to give any sense of materiality or some volumes around the discoveries you had last year?

I'll comment on the US RCOP per barrel numbers and then Brian can add a little bit more to it, and then some comments on exploration.

Clearly it's getting back to work in the Gulf of Mexico for us with 10 rigs running.

We're not giving the exact figures but we did produce more than 200,000 barrels a day during the quarter and an exit rate as well, 200,000 in the fourth quarter.

So we've got that, we've got improved natural gas prices as well that have affected the industry and both would be a mix.

You want to add anything?

I think that's the big part of it, Bob.

It's actually around the balance of Gulf of Mexico barrels coming in with Atlantis major project coming online, and turnaround around Thunderhorse, and it's actually lower oil realizations versus higher gas realizations.

So they were the big drivers, and as more GOM barrels come on with the lower production taxes, hence that [you'll start setting your own trajectory up].

Yes, we expect that out of these four big hubs out into the decade.

On exploration success, I think it has been a really good year; the three wells there just at the very end of the year, the Lontra well in Angola did a drill stem test in December.

A lot of these, we can't really comment on materiality or size because we have partners and governments and regulators that we need to work through but I'm very encouraged about Angola.

We're drilling another well in the block.

In fact, it's going down now.

And in India, I think the size of those -- India is a country that needs every molecule of gas it can get.

One of the discoveries was underneath a D6 field down deep, that looks sizable, facilities there.

So that's good.

And then in Brazil, I think the most significant thing in the Pitu well in Brazil is that it's proved out the equatorial margin, a whole new base in an area.

So that's got some really good significance.

And the Gila discovery in the Gulf of Mexico, that's another one in the Paleogene formation, looks very, very promising; it's in 4,900 feet of water and drilled to 29,000 feet, one of our deepest wells.

And then Egypt as well, is a country who has been exporting gas, needs all the gas it can get.

And the Salamat well, which is 100% BP, is one that looks promising, and then we're drilling another one now with BG that looks promising.

So I can't give you the numbers.

I know you like the figures, but there's just some color around that.

Alejandro Demichelis, Exane.

Couple of questions from my side.

In terms of the new start-ups for 2014, plus the Whiting refinery, how much cash flow do you think you can generate from those new projects that you get?

[Did you see] $30 billion, $31 billion target on cash flow for the first question?

Second question is, Bob, you mentioned the Gulf of Mexico having a very good exit rate for this year.

What do you think you can get over the next couple of years in the Gulf of Mexico?

Okay, Alejandro, I'll start with the last one first.

Over time, we expect to get over 300,000 barrels a day in Gulf of Mexico.

In terms of where it's going to be this year, next year, depends on the state of turnarounds.

We do have some turnarounds coming up.

We've got three of them in the Gulf.

So very optimistic about where we're heading in the Gulf with those four big hubs.

Roughly 80% of our reserve base that we have in the resource base around in the Gulf, is around those four big hubs.

So it's obviously great area of focus for us.

On the amount of cash flow contributed by the four start-ups in 2014, we're not going to give you a number on that but the confidence should come with the fact that we've started up four major projects in 2013, so we'll get the run rates through into 2014 on that and we've got two projects that started up this week with the Chirag oil platform and the Mars B oil project in the Gulf of Mexico and oil really is the high-margin commodity here that we have more and more of coming on.

I think, Bob, that's the bulk of it.

And then there's -- they obviously mix the barrels, as we move more high-margin barrels in the base, come through, that will also help support the $30 billion to $31 billion this year.

And in terms of Whiting?

Whiting, right now, all the units are commissioned and we're ramping up.

So we'll continue to ramp up.

I mean, it's a lot.

If you think at its peak it can run up to 380,000 barrels a day of heavy crude, that's going to take some time to ramp up as we bring all of those units on.

So we'll give you more updates on that as the year progresses.

Blake Fernandez, Howard Weil.

I have two questions for you.

For one, on the downstream, the results were a little below what we would have thought.

I know you mentioned higher DD&A, and you give us guidance of an incremental $1 billion of DD&A into 2014.

I was hoping, maybe, you could give us color around how much of that is associated with the upstream and the downstream.

And then the second question is back on Lontra.

I know the fiscal terms do not accommodate for gas sales, and from what I understand there is a gas component to that discovery.

I was hoping could you maybe give us an update of negotiations with the government to renegotiate the terms there.

Thanks.

Okay.

Brian, maybe you can comment on the DD&A, and I'll come back to Lontra.

Howard, we don't normally give details on DD&A by the segments.

Whiting will be a modest increase in DD&A, as we'll have to depreciate that asset over time now.

It's been commissioned, I think the depreciation schedule is something like, 30 years is what we've agreed, so it won't have a huge impact.

Nevertheless it does impact 4Q as we've commissioned the asset.

Some of the costs that came through in 4Q (inaudible) and are also around some restructuring charges, [Ratex,] effectively, which comes through as a normal charge, specifically in the lubricants businesses, and more broadly, and also we had a weak supply and trading quarter, although we had a good supply and trading year both in oil and gas for 2013, it was actually a weak 4Q for the oil trading and supply business.

They were the biggest components of the miss.

And the upstream DD&A is also due to the new projects that are coming on stream.

We've had a number of the big ones come on in 2013.

On Lontra, our partners there are Cobalt, so really, they are discussing and negotiating with the country.

I'll just note, I'll give you color rather than specifics on this.

You are right, the gas is -- under the contracts in Angola are property of the government.

However, this is a very promising oil-gas condensate field that is not too far from the shore and Angola needs power.

They need electric power.

And there are discussions about, for this field to be economically viable, the government, I believe, wants this done, and the discussions are related to increasing power because a lot of the power in Angola is burned more by fuel oil.

So this quite significant for the country, and -- but I think you would be best asking Cobalt about it, but I'm encouraged.

Thomas Adolff, CSFB.

Thanks for taking my questions.

I've got two, please.

One on India and one on US downstream.

Firstly on India, the price hike looks to be a given now from April.

How should we think about production and development in the near- to medium-term for your asset base there?

Secondly on the US downstream, I believe you are still net long to RINs.

So I was wondering if you can quantify the net benefits from RINs during 2013 and how we should think about it going into 2014.

Thomas, I'll comment on India, and we'll test Brian on RINs.

So you're right, the government confirmed that after the first quarter in April, the gas price would go up on a formula.

It's a positive step.

The estimated new gas price is around $8 in MCF.

It will be adjusted quarterly depending on the benchmark prices.

This is very good.

This is what we've always said that we expected to happen.

It has taken longer over the past two years to get certain approvals on some of the other things, but the R-series field development plan has been submitted for approval.

We think that the gross resource base recoverable there is about 1.3 tcf, likely to start up in 2017.

The D6 satellites and something called NEC-25, developing plans for that, that's about a 1.5 tcf to 2 tcf resource potential.

Managing the declines out of the D1, D4 base until new compression comes online in early 2015, that will be a challenge.

And then this discovery we've had, the MJ1, which is a Jurassic reservoir below the D6 fields, I think it's been given a name of D55, we think that's significant.

And so that will take some time to develop, but it's right underneath the facility so that's great news.

And then an exploration further out in the Cauvery basin down towards Sri Lanka, we've had another discovery, I think it's called D56.

So in terms of specifics and production, we're not going to lay that out just yet but I think all the pieces are finally coming together after what has been -- there was delay there, I think everybody knows it, in kind of getting decisions made, not just for us but India, and I can sort of feel that logjam breaking in energy.

On the RINs question, you're right that we're long RINs since our marketing volumes now exceed our refinery throughput with the repositioning in the US of our two refineries.

What that means in terms of overall results for last year is pretty modest.

It's not a huge number in terms of the financials that came through.

While it gives an apparent expansion in our refining market margin, you lose a lot of that around the cost of compliance with the standards.

So it doesn't have a huge impact on the overall financials and is somewhat modest but we don't normally give that number out to the market.

Jon Rigby, UBS.

Three questions, actually, very quickly, hopefully you can do.

The first is on Whiting.

Can you just tell me how much, if any, heavy crude you were processing in the fourth quarter?

I'm just trying to get an idea about where it was operational versus where the potential is as it ramps up through the first half of this year.

The second is, just on the Macondo, what does the cash within the PSC unpaid?

I think you referenced $6 billion or so.

What does that relate to?

It's obviously allocated but not yet paid.

Can you just run through what that is?

Very quickly, lastly, on the gearing, the range, I guess, is, you see is appropriate, given the uncertainties around Macondo.

What is your attitude to that?

Is that 10% to 20% something that is probably suitable for the long term when you go out of it, let's say to extinguish liabilities, or would you, as that risk falls away, look to see gearing for the corporate start to rise somewhat higher than that range that you've got now?

On Whiting, Jon, we're probably not going to give those figures out.

They're sort of trading-sensitive information.

But we were running some heavy crude during the end of the year there.

Minimal amounts as we were commissioning them.

Now we're working through that post-start up vessel testing set of activities that are going on now.

So would it be fair to say that there's very little benefit in the fourth quarter for the work that's being done on that?

If anything, Jon, there's probably a minor disbenefit as we were operationally bringing the unit on, so I think, there was certainly no upside coming through in 4Q.

And there was some of that really severe cold weather.

Slowed it down as well.

But that ramp-up and vessel testing activities and switching over is occurring now.

On Macondo.

The specific Macondo question, of the $20 billion fund, we've got $13.3 billion in cash has been paid out, balance of $6.7 billion.

There's $1.2 billion frozen at the moment around the fisheries fund.

If you recall, the fisheries was a cap number of $2.3 billion, of which, from memory, $1.1 billion was paid out.

There's $1.2 billion sitting in the fund, but that -- given the issues that we have now risen, and the litigation we've initiated on the civil side around the Watts claims on the fisheries side, that is now, as I understand it, suspended in terms of payment on the balance.

But right now there's still $6.7 billion within the fund that can be distributed for various things like natural resource damages, Plaintiffs' Steering Committee settlements, state economic claims and so on.

And on the gearing levels, if you recall, it was March this year when we completed the Rosneft transaction.

The gearing levels dropped from over 20% down to 11%.

The Board has discussed what's the right gearing band for now.

We're doing the share buyback program which has lifted it up to 15%, 16% now.

For the moment, time being, we like a gearing band.

We think it's prudent, 10% to 20%.

The Board continues to review it and discuss it.

But I think for the foreseeable future we like being right in the middle and around this.

We've got plenty of capacity to go up to 20%.

So no real change, Jon.

Robert Kessler, Tudor Pickering.

I was hoping could you help me kind of bridge your cash flows from the actual in the fourth quarter to your outlook for 2014.

Of course there are a number of moving parts you've talked about in bits and pieces, Whiting is a big one.

Working capital swinging the other way is a big one.

The extra margins from the upstream is another one.

But now that you've got a bigger asset sale program I'm wondering if some of that carves out of the cash flow for next year.

Just see if you can just provide some kind of waterfall, some bigger numbers we can think through to go from 4Q to next year.

Yes, so Robert, I think that you've highlighted all the big moving parts.

You've got the kind of underlying improvements we're seeing come through in the mix of the upstream barrels.

We saw underlying growth year on year of 3.7%, 4Q - 4Q.

So that's the first sort of dynamic and you'll see that continue to come through and the higher-margin barrels coming through.

You've got new projects and Whiting that Bob talked about.

You've also got a working capital bill that we saw through the end of 3Q and we said that we expected two thirds of that to reverse out.

We did see a chunk of it reverse out in the last quarter, but you didn't see it come through the numbers because at the end of each year, we have this -- around $2 billion of working capital goes out the door for the German [Fisk], it's called mineral oil tax that comes back in.

It's started to come back in already through the first six weeks of the year.

So if you look at the $5.4 billion and you take account of that $2 billion that goes out it gets you to something more looking like a run rate that you can start to sort of see a bridge through to $30 billion so maybe that will help a little bit with some working capital that we built last year in various -- across various pieces around some operational components.

So as all things get smoothed out through this year, then I think we are still comfortable that the $30 billion to $31 billion target is achievable.

As far as the incremental cash flow from the upstream, you of course gave us some outlook for production, you gave us some outlook for Gulf of Mexico margins and US margins, but what about total upstream unit cash flow?

Can you give us some kind of guidance for rate of improvement relative to, say, Brent prices?

Yes, Robert, what we've shared with you before is, remember way back to October 2011 we talked about all the new barrels coming on stream having double the margin of the average portfolio.

And we're seeing those barrels come through actually on an EBITDA basis.

You can see those in 3Q.

You start to see those ratios on the portfolio come through.

So we have never given a specific trajectory, but you can build various models into your full projections that would see those big margin barrels kicking in.

You saw that in the fourth quarter, with the Gulf of Mexico now getting back above 200,000 barrels a day.

And you see that those -- the margin of those barrels is, significantly impacts the overall portfolio.

So you'll see more of those things ramp up with the projects.

Last one from me.

A couple of just, small items, the one-offs you mentioned in the upstream, the benefit of lower production taxes with the recovery of past costs.

Then the stronger gas marketing and trading referenced in the results.

That's correct.

Both those things came through in 4Q.

Production taxes in the US, and a good quarter for the gas trading, and the gas realizations outside the United States and actually inside the United States.

Any quantification of those two factors?

No, we don't give any.

I'm sorry, Robert, we don't give specific guidance on the specific numbers.

Alastair Syme, Citi.

Three quick questions, I think.

To just pick up on Robert's point about the cash flow target, can I confirm that the sort of the pre-working capital cash flow is also going to be out within that range?

Sort of a wee bit confused about the point you were making on working capital moves.

Secondly, since we last spoke you have sanctioned Shah Deniz and Khazzan.

I wonder if you could just talk about sort of the relative economics of those projects within the portfolio.

Lastly, you've had ramp-ups from Atlantis North and North Rankin 2 this year.

Just a bit confused about whether you would class those as projects within the base.

In other words, do we still consider there's a 3% base decline ex those projects or including those projects?

Thank you.

So Alastair maybe I'll take the first question.

(Multiple speakers) operating cash flow.

Sorry, Robert, it just picks up from where Howard was asking.

We'll see through the portfolio mix and through the new projects, so for example, PSVM is now [up on full] plateau, you will start to see the underlying operating cash flow from the -- effectively from the earnings of those assets will also come through in 2014.

So that's obviously all part of bridging the $30 billion to $31 billion of operating cash.

Excluding all the working capital effects.

The two big projects you mentioned, Shah Deniz, the second phase of Shah Deniz, this is the largest gas condensate field that BP has found and has the highest-rate wells in our portfolio today from it.

Second stage expansion, 16 BCMA, taking it into Turkey, and then later on into -- up into Europe, over to Italy with 125,000 barrels a day of condensate with it, we're not going to give out the exact production agreements.

6 BCMA will be sold to Turkey.

The economics on this project are long-lifed and they're attractive, and we who manage what I think is the largest single offshore complex in the world with ACG, and then the Shah Deniz projects, you really do need to look at it as a system for us, and the economics are attractive.

On Khazzan, we've signed what is one of the longest-lifed projects I've ever seen.

We're going to drill 300 wells over time to produce gas in Oman, which is becoming a gas-short region.

The economics on that are attractive for us.

I won't give you the exact numbers on here but the gas price, which is also not a public number, may not be as high as what people might look at and draw a conclusion from it, but I will note in that project the gas-gathering facilities and the central processing plants are being built by the government itself.

We have 60% stake in that, and Oman Oil has a 40% stake in that.

I'm very enthusiastic about that.

We've signed a memorandum understanding to use our SaaBre technology that can use the gas and get to potentially acetic acid in what could be a revolutionary process there as well, which of course, we did not include that in the economics of the decision on Khazzan.

So I think it's got additional phases for development as well down the road, and it's also got some condensate.

So 300 wells over the first 15 years, many more years after that, I believe.

So Alistair does, that answer your question?

There's just the one remaining on Atlantis, North Rankin, about whether this is growth or base.

Brian and I are looking at each other quizzically, because it's a fair question.

I'm not sure.

Let's see if Jess can find something.

Tell what you, let's come back, Alistair, and we'll see if we can find the data out of that because it's a fairly detailed question.

Let's see.

So they are both growth, both of them, from 2013 into 2014.

We don't give the specific numbers by project as you know, Alistair, but they are both, I would say, in the growth category.

Definitely, looking at the numbers.

Irene Himona, Societe Generale

Two questions please.

Firstly, you indicate that the current $9.2 billion provision for the claims is at least $1 billion too low and probably more given unsettled claims sort of going through the system.

There used to be a deadline, and I believe it was April 14, for filing such claims for economic losses.

Is that deadline still legally valid?

My second question, going back to Whiting, if I may ask, when do you actually expect the unit to be fully up and running, to ramp up to plateau as it were.

And is it at that point that the $1 billion cash contribution becomes relevant?

And is that likely to happen this year basically?

Thank you.

So, Brian, on the claims.

On the claims, Irene, basically where we started with the PSC settlement was that we originally did various calculations of what we believed the cost would be and then provision for those costs, and that was the $7.8 billion.

You'll probably recall that number then went to $9.6 billion around the fourth quarter of last year, and then we reversed that out, down to $9.2 billion.

So lots of moving parts.

There isn't -- I think what we've said is there were two substantive issues that we raised a year ago, around the way in which the agreement was being interpreted by the court, and we appealed those decisions, one of which we received a favorable ruling on, from the Fifth Circuit Court of Appeals, on the matching of revenues and expenses.

So that one was resolved, and now the court is looking to how that gets applied around those matching of revenues and expenses.

And there's still a separate issue which is sitting with the Fifth Circuit around causation.

That is to say that we put the agreement in place to ensure those people damaged by the spill were compensated.

However, it appeared that there had been a de-linking of causation in the interpretation of the agreement.

That one is still out there.

So until that issue gets resolved, and we have a framework for matching of revenues and expenses, we can't determine what the future provision might be around business economic loss claims so I certainly can't say at this point that we're underprovided by $1 billion as you've just suggested.

I think there's $1 billion dollars of determination sitting inside the fund.

They may well -- the majority of which may well need to be redetermined through either the matching process or depending on what happens around causation.

And the April deadline?

So the deadline is actually set, as the earlier -- later of, it would have been April 14, which is the sunset clause.

It's actually 12 months after the date at which the fairness appeal has ruled on the fairness of the settlement agreement.

That was the ruling we had a couple weeks ago.

We're still working through what that actually means but typically it would be 12 months after that for all the final claims to come in.

And Irene, on Whiting, we are ramping it up now, and, yes, we are projecting the $1 billion of incremental cash flow this year for the year.

Obviously there's some environmental assumptions around that but the current environmental -- the current environment supports that $1 billion forecast, we're going progressively ramp it up.

We can't be specific on the pace, because we're going to fine-tune it as we go.

Of course, it's a trading-sensitive number so we're not going to comment on the pace of fine-tuning the ramp-up.

I think, Irene, Bob makes a really important point.

To the degree the light/heavy spread stays out where it is today, which is $19.00, there's clearly upside in those numbers as you get to the full-year ramp.

So to the degree it ramps up early, the light/heavy spread is low.

Compensates for it taking a little bit longer but we don't know.

And a light/heavy spread which is bigger.

So right now $19.00.

The $1 billion is comfortably underpinned at $19.00 spread.

Doug Terreson, ISI.

Bob, returns on capital were under pressure for the super majors during the past few years and on this point both your and Brian's comments underscore the company's commitment to capital discipline today and the spending profile is supported, too.

So my question is, and I have two questions, is first, given the more challenging environment for returns, but also the desire for growth, how does BP ensure that it sustains its discipline through its corporate planning process given the recent replenishment of the portfolio that you talked about but also the more challenging environment for returns?

And then second, some of your competitors are increasing emphasis on returns on capital so I wanted to see if we could get an update on the measures that you guys deem most important, whether they're changing, and specifically how ROC plays into the thinking.

Yes, Doug, I think this is kind of the heart of the sector, which is sort of out of favor to a degree, and I think, what I'd say is, return on capital employed; my experience, yours too, I'm sure, go through history, and when it suits companies to talk about return on capital employed they do, and then when it doesn't, sometimes they don't.

But I'm going to fall back a little bit on BP in the sense that we divested $40 billion of assets which had more than 50% return on their capital employed.

So by definition, our overall capital employed is going to take a notch down.

We think that was absolutely the right thing to do.

But the kinds of things that we will -- give us a little patience, Doug.

We are, on the 4th of March, going to talk about this quite a bit more, but I do believe -- here's the fundamentals.

We've said $24 billion to $27 billion for the rest of the decade.

We're going to have that discipline.

We're going to invest in -- carefully, in what we think our good margin projects.

We will pace those in time, so that we can make sure we can generate sufficient operating cash flow to have some distributions back to shareholders, make sure we can have a sustainable dividend policy through the decade.

And there are differences in the portfolios of different companies.

You've heard us say many times we have a bias to oil, we like oil, it's a higher-margin product, and then selectively in gas.

That's kind of it in a nutshell.

But remember that $40 billion out at 50% returns has kind of shaped some of the fundamentals of the company.

Theepan Jothilingam, Nomura.

Two questions, please.

Just firstly, Bob, you mentioned Russia in your remarks.

I was just wondering, are there any specific milestones we should look for over the next 12 months?

In particular how much more can BP contribute on integration steps?

Secondly, Brian, just coming back to modeling in the upstream, I think you've talked about the margin mix at length.

I just want to clarify, just on unit OPEX on the base portfolio for this year, do you see it going up, flat, or down, and sort of the latter being that you're benefiting off more barrels off the fixed cost?

And then just lastly, on the Paleogene and Gila, how much further prospectivity do you see there in the Paleogene, and sort of, what are the next steps in terms of appraisal and drilling?

Okay, on Russia, so taking these two large oil companies, Rosneft and TNK-BP, merge them together, and I would say that integration moved pretty fast, about 800 of the top 1,100 in TNK-BP people came across into Rosneft, and you really do have a mixture of business processes, and I can see it in the pace at which many things are happening there.

Both companies have got a lot of professionals.

The milestones I would expect you to see from BP, in addition to the kinds of things that we push at the Board, processes in terms of governance and annual planning processes and capital allocation.

But I would expect you to see and hear about expertise and experts from BP going and working with Rosneft on specific issues, problems, projects, water flooding, artificial lift, seismic interpretation, corrosion expertise, pipelines, environmental work.

That would be one thing that we think is important.

So I would look for that.

We -- I believe a lot of the really good Arctic acreage is taken.

That's fine, because we effectively own nearly 20% of it in carried exploration so we like that.

So I'd look at the exploration results coming forward as milestones of success of the company itself, Rosneft.

And then for us, I know we have expertise, and we're looking for carefully selected opportunities onshore.

It might be unconventionals in oil.

It might be some of the heavier, tougher oil developments that we can work on together in joint ventures.

There's no rush.

This is going to be a multidecade relationship but those are the sort of things I would look at in the next year.

And then, Theepan, on the Paleogene we are going to continue the appraisals of Tiber, Kaskida, the Chevron-operated Moccasin projects, which we're in there together, we know there are further opportunities out there.

We have a large acreage position, and so we're going to selectively look at what we either want to drill for exploration.

It's a large province.

We might do things with other companies as well.

And then, of course, in December the big Gila discovery just further reinforced the importance.

And it's a longer-term province, Gila.

We'll look for technology that can keep up.

So we're not going to rush and get out in front of the technology, the 20K technology we're working on with Kaskida right now.

It's going to be a big play.

And I think -- I don't know if the potential is for it to go down into Mexico as well, but there's other things in the Gulf, by the way, in Mexico that the industry will certainly be interested in.

But this is a play for the next decade.

That, I think is a fair comment.

Theepan, and then on the cost question, the internal performance metric we look at around cash costs in the upstream decreased 2013 versus 2012, primarily due to the divestments as we take some assets out.

On a unit production cost basis it increased by 5% and that again reflects the volumes that we've divested so it's pretty hard to sort of see through in terms of what's going on in the line basis.

And if you look over the last five years, unit production costs for the sector have grown about 6% to 15% over that time period, and we're kind of in the pack of that.

And we did see some increase on a unit basis, but going forward we'd expect to remain competitive within the sector.

And, of course, we're also ramping up exploration activity in all the new projects that are coming on stream as well.

So you'll start to see this sort of smooth out over time.

But it's something that you have to look at on a long run of quarters, not in any specific one quarter or one year.

Okay, so there's no particular sort of leverage to, let's say, the GOM barrels coming back this year against the fixed costs, just on a unit basis?

It will be hard for you to see it.

You will see all the new GOM barrels and new projects come on stream, but you'll see the Abu Dhabi concession volumes come out.

So it's going to be hard for you to sort of see through that but we'll try and give you as much guidance as we can as the year progresses.

Lydia Rainforth, Barclays.

Just one question from me, please.

You made a considerable effort in the last couple years to improve the efficiency and the favorability of assets in the upstream.

I was just wondering if you can give some indication of where we stand now on the reliability and availability index compared to where we were two years ago and how much would you want to see that improve going forward and what the optimal level would be?

Thanks.

Yes.

Good question.

And a really important point.

We've got our upstream availability now running 88% reliability, which is -- this has continually improved over time.

Each 1% reliability is worth between $150 million and $200 million a year.

This has been a very good year.

The number of turnarounds are down, and, of course, if we can keep this reliability up, that's how the operating cash flow stays up.

And this virtuous circle of safe, reliable operations is good business because the assets stay running, and having made a considerable investment in turnarounds now, this is part of the story of why we've seen improvements this year and we'll see more improvements next year.

We've had those increased operating efficiencies, and this year in the Gulf of Mexico, most certainly Alaska's new well work.

The North Sea still has some improvements that yet need to be, but they're coming as well.

But this is a really important point.

And that's why we've highlighted that 88% operational efficiency this time in our numbers.

Martijn Rats at Morgan Stanley.

I have two.

I'll try to keep it short.

First of all, as a matter of detail, in the $30 billion to $31 billion for next year in terms of operating cash flow, what is the assumption embedded in there for Gulf of Mexico oil spill-related payments?

And secondly I wanted to ask you about this point that you just made about the bias towards oil.

Because if I listen to Christof Ruhl, when he presented your Energy Outlook 2035, I thought he made a very strong case for the opportunities that consist in gas and also looking at some of the biggest project announcements that you have made last year, the Khazzan project, and Shah Deniz, they have a gas bias, it looks like.

And I was wondering whether underlying, perhaps, this bias towards oil might be softening a little.

I was wondering if you could comment on that.

Yes.

Well, first, Brian, on the assumption on the Gulf of Mexico, then I'll come back to this.

Yes, Martijn, the only thing we can let you know about is the things which are in public domain.

So that would be the -- if you recall the criminal settlement that we had last year around -- actually, late 2012, around the DOJ and the SEC.

So there will be payments going out associated with those this year.

That was a schedule set up over five years in the case of the DOJ criminal settlement, and three years for the SEC settlements.

They'll go out this year.

They're part of a plan.

And then there's ongoing litigation costs which were built into the plans.

And then the ongoing cost of what is now a much smaller organization associated around the Gulf Coast Restoration Organization.

So they would be the only other things out there but they're laid in for the plans.

So to the degree that we can see what we think those costs are going to look like they're laid in already.

Okay, and Martijn, really interesting point about gas and oil.

And for those of you who haven't had a chance to look at it, I think everybody might find it interesting, this Energy Outlook to 2035, which you can download off our website.

And gas is a growing share of the market going forward.

But all of them are growing.

So while the share of coal may come down, natural gas will go up, we sort of think by 2035 about -- I call it the rule of 27 so I can remember it, but 27% of the market share of energy will be oil, 27% natural gas, 27% coal by 2035.

But to get to that, you are going to need, if this forecast turns out to be right, another 19 million barrels of oil per day to get there by 2035, even though its market share is lower because the demand for energy just keeps growing, which is the equivalent of another United States and another Saudi Arabia all coming out there in terms of being able to supply that.

So oil, we think is going to be continually valuable; 90% of transport fuel in 2035 will be oil-based or liquids-based.

So gas is different.

It's regional.

So you've got the price of gas in North America.

It's three times that much in Europe and it's five times that much in Asia.

So we want to be very selective about where we develop gas.

And there's good economics, probably through all three of those, but those two projects you mentioned are very economic but they're not in North America.

Stephen Simko, Morningstar.

I have two quick questions, and the first one will be highlighting the regional gas comments you just made, Bob.

In terms of North American dry gas, is there anything from here that can be done in the portfolio beyond divestments in terms of just getting costs down or improving the performance?

I know Q1 is obviously going to be the best quarter in some time, but just some commentary there on what can be done to improve the results.

And then I don't think this has been touched on, but in terms of Gulf of Mexico pricing, any idea of just, kind of, the light crude glut in the Gulf Coast that might develop in the near term?

As far as Gulf of Mexico production, what is BP's exposure to lights versus medium output from the Gulf of Mexico?

That's it for me.

Thanks.

Okay, Stephen.

Both good questions.

We're running our gas business in the US, try to make it break even around $4.00 an mcf.

So right now, of course, with the cold weather prices are up closer to $5.00.

But dry gas is very challenged in the US.

So we're not running any rigs in dry gas.

We, of course, hold all our production resources there.

So we're focusing on liquids-rich gas as much as possible.

And that, I think, is what would you'd find most people's strategy to be.

I think for BP going into things like gas to liquids, if you're thinking that far out, I think that requires a lot of capital, a lot of infrastructure.

I don't think we're focusing on that.

So we want to run a tight, efficient gas business in North America, and we've got a lot of work going on to further improve that efficiency.

In a way, the Gulf of Mexico, turning to that for a minute, that crude -- extra crude that we do see in the Gulf of Mexico in some ways is almost a natural hedge between that and Whiting for us.

But in terms of the specifics, Brian, you've worked and run trading for awhile.

Yes, they don't have to hand the actual mix of the light versus the medium in terms of Gulf of Mexico but you will have seen that grades like Mars have been discounted quite heavily to Brent and actually they've de-linked from the Brent price now, as you've seen the domestic crude rebalance in the United States.

So there is some impact on realizations, and you'll see that come through in future quarters.

But the market will ultimately determine what those barrels price at.

And I think the last time I looked Mars was discounted and ran about $14.00 to Brent, which follows the pattern that we've seen with WTI given the oversupply of crude oil as the oil shale has grown in the United States.

And I think with these lower realizations I think it's worth noting for us, the cash impact for us on 2014 is positive, it's not anyway because the increase in production more than offsetting that lower realization.

Colin Smith, VTB.

Just a follow-up on the realizations one.

As you noted, Brian, realizations, or rather, market prices fell quite a lot for Gulf of Mexico crudes but that wasn't really visible in your realizations which held up very well for the US.

I just wondered if you would comment about that.

The second thing was, you noted that the trading performance in downstream had been pretty weak.

And I just wonder if that was in any way connected with anything to do with MiFID or EMIR or what you think those issues might mean for you in terms of the ongoing profit from that business.

Thank you.

So specifically the question around supply and trading is a 4Q issue in terms of being weak in the fourth quarter.

The actual year result for supply and trading, both in oil and gas was a good year.

So we do have a very good start to the year.

So the first half of the year, the 4Q was a weak quarter for the supply and trading business for the oil side.

It was actually driven by some positions that actually do link back to the domestic position in the United States but frankly we don't normally typically going into specifics of those.

In terms of realizations, a lot of our barrels do price off Brent, they're Brent-related prices you see come through.

To the degree Gulf of Mexico barrels, stay disconnected and de-linked from Brent, we may start to have some impact on realizations going forward, but as Bob said, we are comfortably seeing production growth in the Gulf of Mexico where it was more than offsetting that.

The US realizations, quite a bit of that is actually linked to Brent, is that right?

Typically Gulf of Mexico barrels are priced off Brent, so, because ultimately there were the international trade for them.

What you've seen happen in the last quarter, and last six months is a de-linking now of that link back to Brent, so actually there's barrels in our pricing off local prices which looked a little more like WTI.

Right.

But you didn't really see in that 4Q to 3Q change in realizations for your US barrels.

That was really my question.

Yes, I think you have a whole mix of things going on with the gas realizations being stronger than liquids realizations coming through in the fourth quarter as well, so I think you'll see some of these things clean house as the year progresses this year.

Okay, and MiFID and EMIR?

No, we've done everything we need to have in place around the new MiFID regulations, and indeed the Dodd-Frank regulations, so we're comfortable we have structured things as we need them to be able to continue to participate in the markets, but none of those had any impact on 4Q.

Fred Lucas, JPMorgan.

A few questions.

Firstly, which upstream projects do you think is operating, your sanction in 2014?

My second question is, it was a great year for exploration but it was also a burdensome year for exploration expenses.

I wonder, going forward, do the two go hand in hand?

My third question is around portfolio positioning in the Middle East, North Africa region.

BP's clearly had a breakthrough in Oman.

Looks like you've had some exploration success in Egypt but you've also lost a concession in Abu Dhabi, you've exited Jordan, the unconventional play there hasn't worked.

There's got to be a question mark over what happens going forward in Libya.

Just wondered if you could share some comments about BP's portfolio positioning in the MENA region and perhaps where next.

And if Iran is on your radar screen?

Thanks.

Okay, thanks, Fred.

First on 2014, right now we're expecting around five FIDs to occur in a variety of different geographies, in the US and Africa and South Asia.

So we've got a list of five.

We're not going to lay those out just yet.

We've got partners that we need to get approvals with.

You asked a second question there, while I was looking up something on MENA, but what was your second question?

It was around -- you're right, Fred, to the degree that we ramp up the exploration spend, assuming you have the similar success rates that you had previously, clearly the more dry holes leads to more write-downs.

So the two things do go hand in hand.

But as Bob said, it was our most successful year in quite a long time, in certainly over a decade last year, in terms of the exploration and the commercial viability of some of the finds.

But, yes, last year we did get a lot of exploration write-offs coming through the 4Q, that is linked to the higher exploration spend.

Yes, and I think that exploration write-off is not steady.

It's lumpy, depending on individual wells.

4Q seemed higher than what I would expect going forward.

On MENA, MENA's interesting because it is an important area of the world for us.

You are right, Jordan, we tried the unconventional gas.

It wasn't there.

We gave a good effort at it.

It's unfortunate because Jordan is a country that has no energy, really, and needs it, but that one we'll step away from.

Iraq, where we manage a 1.4 million barrel a day oil field with -- called Rumaila, it's the second largest field, now, in the world operating.

It provides probably half the money from energy into the treasury of the country of Iraq.

I think that's going extremely well.

In Algeria we continue to work and operate in the In Amenas and In Salah concessions, and we're back to work now in Algeria, particularly In Salah now, there's more work on both of those projects for expansions, probably in 2015 now.

We do have large exploration areas in Libya, I would describe it as being in hibernation.

And I am glad we don't have production today.

But the prospects still remain there, both offshore and onshore, Libya, and offshore is, of course, most perspective for us.

Abu Dhabi, the concession was not renewed for anyone.

The big -- we still operate there on the marine concession, which is still a very significant concession.

But we, and I think, Total, Shell, and Exxon each stepped down 140,000 barrels a day on the offshore, along with one Portuguese company.

And they'll make a decision at some point down the road here.

We still have offices in the Emirates, where we manage a number of our Middle East activities, and of course, Oman is a very, very big action.

So in Egypt, we've been operating in Egypt since the 1960s, we've had no disruptions of the oil production in the Gulf of Suez or the gas production, minimal, maybe.

But primarily gas production has continued in the north.

We remain committed to working in Egypt, and so I think we have, actually, a fairly sizable MENA position with the potential to grow.

What are you thinking the about Iran, Bob?

Iran, we have not had meetings on Iran with government.

Somebody said I had a meeting with the government of Iran.

The head of -- the Iranian president came to Davos and spoke to a lot of people, so that's the only meeting we've had, which I wouldn't count as a meeting.

Until laws are clear and sanctions are clear we're not going to drift out of anything around those laws until we have a clear signal that that's an appropriate thing to do.

So if I could ask you, thank you very much, everyone, really good questions, every one of them.

As we head towards 2014 and beyond, we look forward to seeing you on the 4th of March.

We'll do that as a webcast.

It will be Brian, myself, head of the upstream, head of the downstream, and then we'll have some teams that travel after that.

It will be live.

It won't be a recorded webcast.

So you'll be able to participate.

Again, if I could just say, the kinds of things you are going to hear is about the capital discipline we've put in place.

We realize we work for our shareholders.

We want to be shareholder-friendly.

We don't want to fall into the trap of generating a lot of cash, and then putting it back into projects and not returning some of those distributions to shareholders.

We treat our portfolio as it is something to manage.

We've lost some of the emotional hold on assets through this difficult three years and we look forward to telling you more about it in early March.

So with that, again, happy Chinese New Year to everyone on the line, and we look forward to being in touch.

Thank you.