英國石油 (BP) 2012 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 to BP's fourth-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 Gilvary, 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 UK and SEC filings.

Please refer to our annual report, stock exchange announcements 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 In Amenas joint venture in Algeria.

It has also been a terrible blow for our partners in the venture, Statoil and Sonatrach, and for the contracting companies involved.

Of the people who lost their lives, four BP employees and five Statoil 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 tasks 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 interest, 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 fourth quarter 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 US 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 $17.6 billion.

Post tax operating cash flow was $20.4 billion.

Our organic capital expenditure was $23.1 billion.

And we divested $11.4 billion 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 $5.3 billion in cash to shareholders.

And our gearing at the end of the year is 18.7%, which is within our target band of 10% to 20%.

That summarizes the outputs and 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 TNK-BP to Rosneft.

We expect the deal to close in the first half of this year.

In the US, we continue to work through the legal proceedings.

During 2012, we reached landmark settlements with the plaintiffs' steering committee.

And we resolved federal criminal charges with the Department of Justice and the SEC.

Also in the fourth quarter, we completed the final payment into the $20 billion Trust Fund.

This is a major milestone for the direction of operating cash flow.

We continued 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 billion 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 five major projects.

Galapagos in the US Gulf of Mexico.

Devenick in the UK North Sea.

PSVM in Angola.

And Skarv in the Norwegian sea.

all of which we operate.

And [Klockes Navicula] in Angola in which we have an interest.

I'll come back to talk about two of these, PSVM and Skarv, 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 start-ups between 2011 and 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.

It 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 US.

Since 2010, we have been awarded new license exploration areas that cover a combined area roughly twice the size of the UK, 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 nine years.

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 2030, which we compile each year.

The headlines are that we expect global energy demand to grow rapidly, adding around 36% to global consumption by 2030.

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 US is now expected to become almost self-sufficient in energy by 2030.

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 US, 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 US.

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 at historically low trends.

With reductions in drilling activity offset by only modest demand growth, which has not been sufficient for recovery in the price.

And, finally, in the downstream, refining margins increased, on average, for the third 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 fourth quarter.

Thank you, Bob.

I will start with an overview of the fourth-quarter financial performance.

BP's fourth quarter underlying replacement cost profit was $4 billion, down 20% on the same period a year ago, and 23% lower than the third quarter.

Compared to the fourth quarter 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 TNK-BP as it became an asset held for sale, following the agreement with Rosneft.

Meaning only 21 days of underlying income was recognized.

A $430 million 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 fourth quarter increasing significantly compared to the third quarter.

Fourth-quarter operating cash flow was $6.3 billion, which included the final payment of $860 million into the Gulf of Mexico Trust Fund.

And as Bob mentioned a moment ago, full-year 2012 underlying replacement cost profit was $17.6 billion, down 19% on 2011.

This included a record contribution from the downstream of $6.4 billion pretax, with another year of underlying profit growth from that business.

The fourth-quarter dividend payable in the first quarter of 2013 is $0.09 per ordinary share, an increase of 12.5% year on year.

Turning the highlights at a segment level.

For the upstream, the underlying fourth-quarter replacement cost profit before interest and tax was $4.4 billion, compared with $5.9 billion a year ago, and $4.4 billion in the third 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 is partly offset by major project delivery, underlying 4Q volumes excluding TNK-BP.

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&A and higher cash costs.

Compared to the third quarter, the fourth-quarter 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 first-quarter reported production to be slightly up relative to fourth 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 agreements in principle with Rosneft on the 22nd of October, we announced that equity accounting of our share of TNK-BP earnings would cease.

And that TNK-BP would be treated as an asset held for sale.

So our result for the fourth quarter only reflects 21 days of TNK-BP net income.

As a consequence, BP's share of TNK-BP underlying net income was $220 million in the fourth quarter, compared to $1.3 billion in the previous quarter, and $1 billion a year ago.

We also received dividend income from TNK-BP of $700 million in the fourth quarter.

As an asset held for sale under IFRS, this is accounted for within revenue and is being treated as a nonoperating gain.

The dividend will also reduce the cash proceeds from the sale of our TNK-BP shareholding and the associated nonoperating 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 from our activities and interest in Russia.

We will, however, continue to report our share of TNK-BP's production and reserves until the transaction closes.

In the downstream, the fourth-quarter underlying replacement cost profit was $1.4 billion, compared with $800 million a year ago, and $3 billion in the third quarter.

The fuels business delivered an underlying replacement cost profit of $1 billion in the fourth quarter, compared with $400 million in the same quarter last year.

The continued benefit of strong operations enabled the capture of higher 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 third quarter, the fuels result was impacted by significantly lower refining margins, the absence of gains from the [priment] pricing of barrels into our US refining system.

And the planned crude unit outage at Whiting.

This outage is scheduled to continue until the second quarter, 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 first quarter will be similar to the fourth quarter of 2012.

And lower than the full year 2013 than for 2012.

The lubricants business delivered an underlying replacement cost profit of $330 million in the fourth quarter, and $1.3 billion 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 million compared with a profit of around $100 million in the same period last year.

Despite seeing a slight recovery in margins in the fourth quarter, we expect margins to remain under pressure during 2013.

In other business and corporate, we reported a pretax underlying replacement cost charge of $450 million for the fourth quarter, an improvement of $170 million on the same period a year ago.

The full-year charge of $2 billion 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 million per quarter, although this will remain volatile between individual quarters.

The effective tax rate on underlying replacement cost profit for the fourth quarter was 16%.

This is 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 fourth quarter, we also recognized a $4.1 billion 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 billion.

The total cumulative net charge for the incident to date is $42.2 billion.

The pretax cash outflow related to oil spill costs for the year was $6.2 billion.

And during the fourth quarter we completed funding of the $20 billion Trust Fund.

At the end of the year, the cash balances in the Trust and the qualified settlement funds amount to $10.5 billion, with $20 billion contributed in and $9.5 billion 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 third quarter, we have announced over $4 billion 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 first of February.

Interests in a number of North Sea oil and gas fields.

And our interest in the Yacheng gas field in the South China Sea.

As Bob said, we have now effectively reached our $38 billion divestment target a year earlier than planned.

Of the $38 billion announced divestments since 2010, we have received over $31 billion in proceeds by the end of December 2012.

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 2010 reported production, excluding TNK-BP.

For the group as a whole, assets divested since 2010 would equate to around $5 billion of pretax earnings and $5 billion of post-tax operating cash flow.

Looking at our full-year cash flow movements, this slide compares our sources and uses of cash in 2011 and 2012.

Operating cash flow for 2012 was $20.4 billion, which includes $6.2 billion of Gulf of Mexico pretax oil spill-related expenditures.

Excluding these oil spill-related outgoings, underlying cash flow was $26.6 billion.

We received $11.4 billion of divestment proceeds during the year, with $6.8 billion received in the fourth quarter.

Full-year organic capital expenditure was $23.1 billion, with $6.6 billion in the fourth quarter.

Our year-end net debt reduced to $27.5 billion, 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 relate to the high-margin areas in the Gulf of Mexico and the North Sea.

The actual reported outcome will depend on exact timing of divestments, OPEC quotas, and the impact of oil price on production-sharing agreements.

Organic capital expenditure in 2012 was $23.1 billion.

In 2013, we expect capital expenditure to be around $24 billion to $25 billion, as we invest to grow in the upstream.

Our DD&A charge was $12.5 billion in 2012.

And in 2013 we expect this to be around $500 million to $1 billion higher.

The increase reflects the expected ramp-up of production 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 million per quarter.

Moving to tax.

Our effective tax rate is expected to be higher in 2013, within a range of 36% to 38%.

Mainly due to a lower level of equity accounted income, mostly TNK-BP, which is reported net of tax.

There are also some accounting changes that will impact earnings in 2013.

With effect from the first of January 2013, we will be adopting new accounting standards, including IS-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 five years.

However, at this time, we expect the new reporting standard for pension accounting to have the largest effect, reducing 2013 earnings by approximately $260 million 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 the results 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 billion to $31 billion.

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, we expect to manage gross organic capital expenditure from the group in the range of $24 billion to $27 billion per annum, from 2014 through to the end of the decade.

And to divest an average of $2 billion to $3 billion per annum on an ongoing basis.

Growth in group operating cash flows for 2014 and beyond creates the platform to increase reinvestments 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 TNK-BP 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.

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 -- safety, respect, excellence, courage in 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 three 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.

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 reduce the number of wells by one-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 have conducted more than 200 briefings and presentations with such groups in the past two 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 24/7, experts at the facility provide an additional level of assurance to their colleagues located at each offshore drilling rig in the Gulf of Mexico.

We're also ensuring we are better prepared to respond to an accident, should one occur.

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 US, where we have made progress in reducing the legal risks facing the Company.

We reached a significant milestone with completion of the $20 billion payments into the Trust Fund.

The final payment being made in the fourth quarter.

This removes a call on the operating cash flows of the group of some $5 billion per year.

The fairness hearing to determine whether to grant final approval of the settlements of the plaintiffs' steering committee was held in November.

And the settlements were subsequently approved by the court in December and 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 the US Department of Justice and the Securities and 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 $3.85 billion in the fourth 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 and 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 US government, we he have removed another significant legal uncertainty.

And can now focus more 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 at an 18.5% stake in Russia's leading oil company.

As a result of the transaction, you will recall that BP will receive $12.3 billion in cash, and hold a total of 19.75% of Rosneft when combined with the existing 1.25% 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% of Rosneft.

Also on the 12th of December, Rosneft and Alfa Access and Renova signed agreements so that Rosneft will acquire 100% of TNK-BP.

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 2013.

BP and AAR have also reached agreement on the settlement of all outstanding legal disputes between them, bringing an end to all ongoing litigation.

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 Rosneft's strategy and potential for value growth.

This slide illustrates the areas of potential value growth for Rosneft following its planned acquisition of TNK-BP.

On the left side of the slide are areas where short-term synergies can be achieved through the process of integrating TNK-BP into Rosneft.

The right side of the slide shows the longer-term potential.

BP has very relevant experience here in improving performance in Russian oil and gas businesses, and in large-scale corporate mergers.

This can directly benefit Rosneft in its efforts to define and capture these synergies.

Like Rosneft, 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 TNK-BP.

We are very much looking forward to the prospect of working together with Rosneft to identify and develop standalone projects, both inside Russia and internationally.

Given all that Rosneft 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, Rosneft and its shareholders.

And by direct consequence, for BP shareholders as well.

Turning to the progress and outlook for the upstream.

We continued 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 and 2012.

Additionally, we completed implementation of 14 of the 26 recommendations of the Bly 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 five major projects -- PSVM, Skarv, Klockes Navicula Devenick 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 work 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 billion 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 of 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 -- 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 two new provinces, each with multi-billion 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 start-ups between 2012 and 2014.

In 2012, we delivered five projects, including PSVM and Skarv, each a significant achievement and key operational milestone in its own right.

PSVM in Angola, 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 Skarv in the Norwegian Sea.

The field development includes a new, highly advanced FDSO, purpose-built for harsh waters, with five 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 two short videos currently on our website which show the scope and scale of these two 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 four upstream major projects to come onstream toward the end of 2013 -- North Rankin 2, Angolan LNG, Na Kika 3, and the Chirag oil project.

With the remaining six start-ups in 2014.

In total we have around 50 major projects to progress through the decade.

Of these, 11 are what we call mega projects, which are greater than $10 billion in gross spend.

We made final investment decisions, or FIDs, on three projects in 2012 -- Juniper, the Kizomba Satellites 2, and Point Thomson.

And we expect to FID a further five 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 three 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.

Second, 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 50% 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, loss is a primary containment more than half between 2008 and 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 previously-announced divestment of our Carson refinery and US 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 2013, with construction 84% complete at year end.

Once operational, we expect this project to deliver an incremental $1 billion 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 onstream, 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 will continue to invest in brand, technology and customer relationships.

And, finally, within petrochemicals, we will continue to invest through the cycle with the focus on expanding our Asian positions.

And further developing the commercialization and 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 two 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 short cuts.

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 would be happy to take your questions.

(Operator Instructions)

Hootan Yazhari, Bank of America.

No answer from Hootan.

Alejandro Demichelis from Exane.

Couple of questions, if I may.

Bob, you said that you remain prepared to settle the civil claims under reasonable terms.

I wanted to know if 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 million impact on a quarterly basis, over the course of a year would you be able to bridge the gap between the level of the assets?

Or do you mean 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 two 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 prepared.

Yes, so Alejandro, on the question you're asking, I presume this is around IS-19 which is the new accounting standard we will be adopting through 2013.

It won't impact our funding plans.

We'll continue to invest in the funds at roundabout $1.3 billion per annum.

What it does is 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 will be discounted something like 4.4% for the UK scheme, 3.2% for the US 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 the accounting standards.

But it will have no cash impact.

I think, given the Company's very much focused on cash, this will have no impact on cash going forward.

That's very clear.

Thank you.

Doug Terreson from ISI.

Congratulations on your results.

Bob, you have extensive experience in the integration process on major strategic activities in this industry.

And obviously the record of value creation at TNK-BP 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 in 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.

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 will be some others joining in.

I have no doubt that there will be a number of very well-known consulting firms that also have experience in merger integration and are beginning to work on pieces of this.

There is 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 one.

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 TNK-BP 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, 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 TNK-BP is on things like waterflooding, artificial lift work, and a focused exploration program will happen.

And I think I would, Doug, just say, everyone stay tuned.

Okay.

Good.

And then also, Brian highlighted around $5 billion 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 US downstream last year.

Yes, Doug, I think, 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 third quarter.

And the $5 billion 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 two 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 the disposals, and the proceeds came in last week.

So $5 billion did include downstream?

It did.

That's correct.

Okay, thanks a lot.

Jason Gammel of Macquarie.

My question comes back to the expectations for the cash flow accretion over the next two 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 provided us with detail on today, and what cash actually goes back to the shareholders versus strengthening of 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.

The background to this is when we laid the targets out in a 10-point plan in October of 2011, we started with a base of $22 billion of operating cash.

And we said that that would grow by 50%.

So it takes you up to $33 billion 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 billion to $25 billion.

The base in capital is $19 billion, so that would increase by 50%.

And we said the remaining $5 billion to $5.5 billion would be available for other purposes.

Now, since that was out there, the revised figures are now $30 billion to $31 billion.

That still says there is still cash available for other purposes, which will underpin the dividend in terms of the future in progressive dividend policy.

The difference from the $33 billion to the $31 billion, or the $30 billion to $31 billion, is basically the fact that we swapped dividend out of TNK-BP for dividend in Rosneft.

Effectively we've accelerated six to seven to eight years worth of dividends out of TNK-BP as part of that transaction, which is a $12.3 billion 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 five years that fits inside that $30 billion to $31 billion.

And, Jason, I would just add that 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 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 is 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?

I think we're considering both, actually.

And I think a special dividend is unlikely, given the progressive nature.

We want to manage the cash.

But I think you would see us consider both.

Very clear.

Thanks.

Jason, good job on CNBC today.

I saw you talking about the industry.

Oswald Clint of Sanford Bernstein.

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 US gas this year.

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, et cetera, 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 Ramayla field.

It's between 1.4 million and 1.5 million 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 four different options in terms of plateau rates and the enhanced development of the field.

And those talks are ongoing in a very sensible way.

So I wouldn't expect any news right away on that.

And I think that relates to the export 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 a range of 75% to 80%.

85% excluding acquisitions and divestments.

We're going to look at that on a combined basis of all the subsidiaries in equity accounting entities.

We think that the number will be below 100%, most likely.

The main reason for that is in 2012 we FIDed only three projects.

And we expect to, on average, over the last five years we've FIDed about eight projects.

During 2013 we should be up to the five to six range.

The three that we did this year were not what we would call mega projects.

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.

We 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 the 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.

Robert Kessler from Tudor, Pickering.

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 billion and the low end of your CapEx guidance at $24 billion, just to get to the current dividend payment.

I know you've got a big slug of cash coming, of course, with TNK-BP and some other ongoing asset sale proceeds of $2 billion to $3 billion 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 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?

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 out to 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.

That's something which is considered by the Board around the results.

And so I think the key is, as you said yourself, the $2 billion to $3 billion of disposal proceeds.

We have a script dividend, which is typically around about a 20% take-up.

So the cash dividend is about 80% of what we actually flow 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-BP 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 of 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%.

Out in time, when we go through this period of transition, we might move that up.

I'm going to try Hootan again.

Just coming back to disposals, your $2 billion to $3 billion run rate, as guided going forward from here, 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 billion to $3 billion 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 of February, I just wanted to see in terms of underlying negotiations whether we could see some sort of a split, 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 in the respective states that you're going to court with.

Thank you.

Okay.

Hootan, thank you.

We were worried about you for a while there.

On the disposal, the $2 billion to $3 billion, 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 life cycle coming up.

But they're not in our plans right now.

On the trial on the 25th of February, obviously it's nothing we can 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's possible but I can't give you any real sufficient light on your question, as you would expect, right now.

But thanks, Hootan.

Understood.

Thank you.

Jon Rigby from UBS.

Two questions, please.

The first one, just going back to, I think one of the first questions, around TNK-BP and Rosneft.

Correct me if I'm wrong but it seems to me that the great distinguishing feature of TNK-BP within Russia was the people and the processes that were taking place there.

You always spoke about how that organization kept motoring on, even when the management problems were happening.

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 to lose that.

And also I would have thought that applying those people and processes to the combined base would be where you get the vast portion of your merger synergies from.

I think of that in the context of your relationship with AAR who, of course are leaving completely.

The second question just is a confirmation.

You talk about the $1 billion 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 and the basis of that $1 billion?

Thanks.

Jon, thanks, both good questions.

I'll let Brian answer the one on the Whiting refinery.

You're spot on.

TNK-BP, when you benchmark the Russian oil industry, and I've had lots of discussions with Rosneft about that, TNK-BP benchmarks very well in terms of efficiency and what it's been able to do in terms of wringing out additional reserve additions to the oilfields 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 the 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 will be lots of stories and lots of headlines, I suspect.

But actually, the approach path has been remarkably smooth so far.

Brian, on Whiting?

Yes, on Whiting, Jon, 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 billion on an annual run rate basis.

But I would describe what the number is.

It's relatively conservative in terms of what we've built into that $1 billion.

So, actually, if you saw anything like the blow-outs that we saw in the light-heavy spreads last year, in addition to, of course, the benefit 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 discounted again versus Brent.

I would say the $1 billion is very independent to the current prices we've seen in recent years.

Is it worth just looking back at the historical trends at or around the points at which you FIDed 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 will be built, and therefore that light-heavy spread would narrow over time.

So we're confident that the $1 billion will be there based on the historicals that we've looked at and aimed off that number.

And I'd actually also say it's probably worth counting, of course, with the 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.

Okay, thanks.

Theepan Jothilingam from Nomura.

Couple of questions.

Firstly, Bob, could I come back to that point on gearing?

To be clear, are you saying that beyond, let's say, the cash-in for Russia, a potential settlement in the US, then you anticipate that gearing level moving back towards the high end of the 10% to 20%?

Then, if that's the case, is that a mix of higher organic spend, potential use of M&A to bolster up the portfolio, or is that cash returned back to investors?

The second question linked to that is the position in the US 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 for 2013, but then over the next few years?

And whether you need to add on the liquid acreage side.

Thank you.

Theepan, I'll just give you a quick introduction on the gearing, and then Brian to follow it up.

And then I'll come back on the unconventionals.

But I will 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 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'd reconsider that range.

Because I think it's a question about is that the most effective, efficient range for us.

Brian?

I think, Theepan, that the context here, of course, is historically the range that we always operated within our financial frame for the best part of a decade, prior to the first quarter 2010, was a gearing range of 20% to 30%.

And we redirectionally moved that 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 core case that is due to start on the 25th of 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.

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 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, Theepan, on unconventionals in the US, it's interesting to note that in the second quarter 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 zero 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 liquids-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 acreage.

And I think for BP right now, it's a question mark, what will happen.

There's a lot of gas in the US.

It's still a question mark.

I think the US 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.

Yes, that's helpful, Bob.

I was just wondering, do you have any hard numbers in terms of what you're thinking of for production for this year and then beyond that?

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 US liquids side in the US.

Just trying to get a sense of what it may contribute to underlying growth this year and beyond.

It's not significant in the Utica, most certainly.

In the Eagle Ford, we've got healthy production there.

But I don't have the exact figure with me right now.

Maybe Jess can.

But we've got to be careful about giving out the basin numbers.

But in terms of a significant boost in underlying increase in production for us in the US in the unconventionals, it's not really material.

Okay.

Thanks.

I'll follow up with Jess.

Lydia Rainforth at Barclays.

Thanks, Jess.

Good afternoon.

A couple of questions, if I could, please.

Firstly, Bob, 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, on the cost side, it does appear that the costs 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.

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 '14, '15 and '16.

Our increase in spending is going to be driven by what is now -- last year, a year ago, we had five rigs running, now we're going to have seven.

We're going to be moving into development drilling wells in Thunder Horse and Atlantis.

Water injection at Thunder Horse.

We've got project start-ups on Na Kika, 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 start-ups after that, Atlantis 2B and the second phase of Mad Dog.

We see oilfield inflation, sector inflation, running 5% to 10% broadly around the world.

But 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 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, our spending's in development and injection work, injector wells and then appraisal, exploration appraisal work going forward.

We have passed the high point -- low point, depending how you look at it -- in terms of our maintenance spending in the US.

The number of turnarounds are going down next year.

I could give you some -- it may be too much over the call but some of the activity of what we're doing in terms of Atlantis, Mad Dog and Na Kika and Thunder Horse going forward.

But I think what I would just say is that those are our four 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 blow-out preventers around the world.

And the down time, not just for BP, but every operator I talk to, is quite significant still in terms of blow-out testing, and the time taken to drill wells.

And we've got to go through a period here where the industry goes through that phase, and that's obviously affecting us in terms of rig days.

But it's not just us.

I could go into specifics but probably not on the call.

Does that get at your question, Lydia?

Yes, thank you.

Alastair Syme at Citi.

My questions are actually very similar to the second part of Lydia's.

It was about the production cost, about the trend you're seeing in cash costs and the upstream side in 2012 in terms of year-on-year inflation.

And how you think that plays out in '13 as you have greater efficiency from the producing assets.

Yes, it's very similar.

5% to 10%, depending on which basin you're in, 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 capabilities, we work toward 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, 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 eye is 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.

I see our costs as being competitive going forward.

Could I just clarify.

The $31 billion target in '14, it still works with inflation in production costs?

it doesn't imply a reduced cost base as efficiency improves?

We have cost efficiencies built into that target.

We also base that $30 billion to $31 billion based on $100 oil.

So we think that is very much on track for 2014, at $100 oil.

We're not going to re-base 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.

Irene Himona, Soc-Gen.

I had three questions, please.

First, can you remind us of the asset disposals that you have announced, excluding TNK-BP, how much cash remains to be received in 2013?

Secondly, on the US 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, is it possible to discuss some of the conditions that actually need to be fulfilled for that to be lifted?

Thank you.

Yes.

Brian, on the first one.

On the first question, the disposal proceeds still yet to be received this year.

And, of course, Texas City we had the proceeds come in last week.

But for this year in total we still have about $5 billion of proceeds to come in from what we announced last year, of which $1.5 billion arrived last Friday from Texas City.

Okay.

Irene, your second question was on US unconventionals and -- it cut out for a minute -- on the balance sheet.

Just the size of the business, I was saying, either on your balance sheet or in terms of current production.

We'll get back to you on US 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 second quarter of last year.

And then I would say, if we were to look at the oil prices today, some of that might come back on.

But I think our balance sheet has been continually adjusted under the IFRS rules.

On the EPA debarment and the conditions, it has to do with 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 outlined in the plea agreement.

It has things to do with ensuring safety monitoring of our operations.

And beyond that, it's a 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 a focal point for lots of different agencies in the US.

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 US government.

Okay.

Thank you very much.

Martijn Rats at Morgan Stanley.

I wanted to ask you about two things.

In the beginning, you referenced the BP Energy outlook 2030, which calls for 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 call on OPEC.

Looking at oil markets over the last couple of weeks, clearly it's no concern visible in the oil price.

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 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 give an indication of the order of magnitude of that in case that unwinds over the next year or two.

Martijn, all good questions.

I'll take the first bit and then Brian can comment here.

I would say that the energy outlook to 2030, there's the fundamentals of what's in storage today and the possibility of potential production and surplus of demand.

I'd note that Saudi Arabia has reduced itself production by about 1 million barrels a day in the last quarter.

And I think OPEC does continue to adjust based on 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 why don't you comment on that and then we'll come back to the legal costs.

Yes, Martijn, in terms of stress testing, we do run stress tests.

And one of the stress tests we run is a prolonged two-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 can 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, the lowest it's been certainly since pre-Macondo.

So, actually, the balance sheet has strengthened up over the last two or three 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 we'd be able to withstand that for a period of two years.

Or more.

And including the dividend, absolutely.

When you say underpinning the dividend -- at those prices.

It's very hard to quantify, but I think the world continues to see 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 legal costs, 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.

Jess has reminded me we do have legal costs in the provisions that are there.

The settlements that we've done with the plaintiffs' 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.

Martijn, I would comment that, of course, we do have the criminal and SEC settlements behind us and now agreed.

So, of course, all the external counsel we're using in that particular space has clearly been closed down and there's no run rates associated with those.

Great.

Thanks very much.

Okay, Martijn.

We do have a very high quality legal team that are helping us through this process.

I will say that for sure.

Okay, Martijn, thanks.

Lucas Herrmann from Deutsche.

Jess, thanks very much.

Two or three, if I might.

I just want to start with, and forgive my ignorance, the operating cash flow guidance, $30 billion to $31 billion, 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 $30 billion to $31 billion, or would they be additional?

Secondly, just whether you can give us some idea of what the contribution from divested activities was in the fourth quarter, i.e., what the profit from the UK and US 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 you be in a position to capture full margin?

Okay.

Lucas, good questions.

Brian, on the operating cash flow guidance and contribution of the divestments.

On the first questions, Lucas, clearly in the $30 billion to $31 billion, 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 50% is for capital, 50% 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 billion 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.

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 $3.5 billion provision, for example, that you've got sitting on balance sheet for clean water, and that were to be expensed over three years starting 2014, that would eat into that $30 billion to $31 billion?

That's a hypothetical question.

It's a hypothetical question.

But there is not -- so let me be really absolutely clear.

Inside the $30 billion to $31 billion, there is no cash outflow associated with clean water fines and penalties.

Lovely.

Thank you.

Lucas, your contribution to the divestments in the US.

Lucas, the biggest piece, of course, is TNK-BP.

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 fourth quarter.

We can come back to you with a broad figure on what that looks like in terms of earnings.

The Gulf of Mexico went out, from memory, halfway through the quarter.

The North Sea assets went out towards the back end of the quarter.

So it would be pretty difficult to actually give you a point in time estimate for the fourth quarter.

Okay.

Lucas, the fourth quarter production impact, so in the fourth quarter over 2011, was 116,000 barrels a day.

So it was significant overall.

On the Whiting project, this is a project -- again, 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 is 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 six to nine months, with three of the major units starting up in the sequence there.

So we do anticipate that 2014 will be the first year that we get the full benefits of it, 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 it as these units come up and on.

Okay.

Gentlemen, thanks very much.

Bertrand Hodee, Raymond James.

Two questions, if I may.

Can we expect in 2013 BP to launch or to sanction some major projects?

You only sanctioned three projects in 2012.

You mentioned a possible five in 2013.

And can we expect the likes of Shah Deniz or other 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.

You're right, we had three sanctions this year, none of which were mega projects.

We do see five sanctions or 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 five projects, of which four of those are very large.

I will name the ones that we clearly have been talking about externally.

One is the Tangguh Train 3 in Tangguh.

The Tangguh expansion is a big one.

Shah Deniz, 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 Plutonio 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 of the Gulf of Mexico today, we are the largest leaseholder in the Gulf, somewhere between 700 and 750 leases.

It is a lot on our plate.

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.

Peter Hutton at RBC.

Thanks for all the details this afternoon.

It was actually following on from a similar question on FID.

The three that you took in 2012.

So it was lower than trend rate.

What prevents you from doing more?

Was it just the kink in the pipeline of future projects?

Or is that BP sees itself as fully loaded and enough on its plate?

And the second one is, thanks for the guidance on the gearing.

And 10% to 20% moving to 20% to 30%.

As 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 five to eight projects a year for a decade.

If I look back, and we have been looking back very carefully at our exploration record and our exploration spending, and 2009, 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.

There's always a consequence of that.

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 five-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.

The gearing level, I would say, it's not guidance.

It's just something we have been talking with shareholders about.

And there's no -- I don't mean to give guidance.

We will, if possible.

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, presumably you would have a view.

But you'd express that directly through Rosneft, not through to all the analysts.

Yes, that's right.

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 are taking on -- everyone knows they're taking on debt for the TNK-BP transaction.

But I also know, at these oil prices, that they're 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.

Jason Kenney in Santander.

Sorry I was a bit late to the call so I can only apologize if you've answered a couple of these points.

You probably won't answer my first one anyway but I'll give it a shot.

Settlement, right?

Yes.

You've got a view of what a reasonable settlement figure for the US 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.

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?

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 then we'll come back on the settlement in a minute.

North Africa, In Amenas was around 17,000 barrels a day for us.

So you think about that, with a 2.3 million barrels a day company, it was a good return.

A good return project for us but not significant in terms of volume terms.

We do remain committed to Algeria.

We're working in In Salah, as well.

These are good projects for us.

We are going to be very careful.

We're going to work closely with Sonatrach and the government, along with Statoil and our contractors to make sure 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 two exploration acreages, one offshore, where our planning work continues.

And then onshore, we're down in the Ghadames basin near the Algerian border.

Not too far away from where In Amenas was.

So certainly for the time being I would say it's in hibernation.

But we also remain committed to doing business in Libya.

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'm cautioning some in the media just not to over-react 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 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, it's really something we can't talk about.

But I would note, with the trial coming up in 20 days, we're in the chute to get ready for the trial.

Okay.

Many thanks.

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 two projects in December, getting the redevelopment of Valhall 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 that's very tight-knit and people knew many of the people impacted on it.

But as we move that, we'll go on.

We'll keep going on.

We've got so 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 US are quite mind boggling, and it's hard 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.

And I think the Company continues to move through the transition.

And thank you all for your attention and questions.