英國石油 (BP) 2016 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.

This is BP's fourth quarter and full year 2016 results webcast and conference call.

I'm Jess Mitchell, BP's Head of Investor Relations, and I'm here with our Group Chief Executive, Bob Dudley, and our Chief Financial Officer, Brian Gilvary.

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

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

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

Please refer to our annual report, Stock Exchange announcement and SEC filings for more details.

These documents are available on our website.

Thank you and now over to Bob.

Thanks Jess.

Welcome everybody and thank you for joining us.

We're reporting on another challenging quarter today and another challenging year for the industry.

But for BP it's been a very eventful quarter and one where we've continued to make good progress on many fronts.

We certainly had a busy end to 2016, and I'll spend some time in a moment on that and our other actions to get back to growth.

As usual, Brian will take you through the detail of our fourth quarter numbers and provide an update on our guidance for 2017.

I'll come back to briefly update you on the progress in our upstream and downstream businesses, and at the end Brian, Jess and I will take any questions you have.

But first, I'd like to take a look at the environment.

By the end of last year we were seeing Brent oil prices around where they are today, in the mid $50s, but in 2016 the average oil price was $44 per barrel, the lowest for 12 years.

Henry Hub gas prices were also weak in 2016, averaging $2.50 for MMBtu for the year, and a Refining Marker Margin at $11.80 per barrel was the lowest since 2010.

As we stand today, Brent oil prices have risen by around $10 per barrel since the OPEC deal was announced.

We still expect oil demand growth to be strong this year at 1.3 million barrels per day with modest growth of non-OPEC supply, which means the timing and extent of market rebalancing depends heavily on OPEC behavior.

The physical market has begun to tighten with inventories falling a little faster than seasonal norms.

However, OECD inventories at the end of 2016 were still close to 3 billion barrels, significantly higher than their recent historic average.

We expect much of the historical inventory overhang to be eroded by the end of 2017 if OPEC and non-OPEC producers deliver on their promised production cuts.

Any shortfall could delay this process and does still pose some downside risk to prices in the near term.

So while we remain optimistic about the market continuing to rebalance in 2017, we recognize that this could take some time.

In short, the road to a more balanced position still has uncertainties.

We are very aware of these uncertainties, but as you'll hear today, we are confident in our resilience to the environment, and we're continuing to build momentum in our businesses.

Turning to our results.

The slide you are seeing now is a summary of our full year 2016 results for the Group as a whole.

Our underlying replacement cost profit was $2.6 billion for the year.

Our underlying operating cash flow, excluding oil spill related payments, was $17.8 billion for the year.

This was 12% lower than last year but represents strong performance in these tough market conditions.

Organic capital expenditure in 2016 was $16.0 billion, excluding the consideration for our recently announced renewal of 10% of the Abu Dhabi ADCO concession.

Proceeds during the year from divestments totaled $3.2 billion.

Gearing at the end of the year was just under 27%.

We distributed $4.6 billion in cash to shareholders through dividends, and finally our reserve replacement ratio for 2016 is estimated at 109%, including the impact of the Abu Dhabi concession renewal.

Putting these numbers in perspective, we finished the year ahead of where we expected to be at this point in rebalancing our organic financial frame, supported by the significant and rapid structural changes we've made to our cost base.

Our organic capital of $16 billion was well below our original guidance of $17 billion to $19 billion for the year.

As well, we reached our controllable cash cost reduction target of $7 billion versus 2014 a year early.

So looking over the course of the year, we're pleased with our underlying financial progress, despite the very weak environment.

And Brian will give you some more details on this in a minute.

More broadly, we've had a very busy and eventful year.

We've clarified the remaining material uncertainties around our Deepwater Horizon liabilities.

This has allowed us to put more of our energies into shaping a strong future for the Group.

In the upstream, progress is visible, with six major project start-ups completed in 2016, including the early start-up of the Thunder Horse South expansion in the Gulf of Mexico.

This supports our aim to drive material growth of free cash flow from this business over the medium term.

In the downstream, we rolled out our biggest fuels launch in a decade.

The new Ultimate fuels range is just one example of the differentiated customer offers helping to underpin material and reliable earnings growth in our marketing businesses.

And most significantly, we have made big strides in creating a stronger platform for growth.

We've moved forward a number of the high-quality development options you are already familiar with, and we have deepened our incumbent interest in some specific areas we consider to be very strategic.

And we've added to our portfolio with some creative new partnerships and some exciting new opportunities.

This slide pulls together some of our key activities last year, many of which came in a busy final quarter for announcements.

Earlier in the year we completed the merger of our Norwegian North Sea portfolio with Det norske to form Aker BP.

The new company is now well established and we believe it has the potential to grow its production to around a quarter of a million barrels a day by the early 2020s.

More recently, we were awarded a 10% interest in Abu Dhabi's ADCO concession, which provides us with material long-term onshore oil reserves, low cost oil production and cash flows.

These are resources that we already understand well, which will add resilience and production to our upstream portfolio out to 2055.

You may have also seen that we agreed to acquire world class working interests in discoveries in Mauritania and Senegal, giving us a leadership position in these emerging low cost gas basins, which we know can be produced competitively.

And in the Gulf of Mexico, we gave Mad Dog 2 the go-ahead after three years of work to bring costs down to $9 billion, which is around 60% lower than the original figure.

We expect this to add around 140,000 barrels a day gross of oil equivalent capacity, supporting our post 2020 returns focused growth.

We're also expanding other incumbent positions where we see opportunities for greater growth.

Our purchase of a 10% share in the giant offshore gas field, Zohr, is an example of this, as it complements our existing large gas portfolio in Egypt.

We also reached agreement with the Government of Oman for phase two of the Khazzan gas project, and in Azerbaijan we will continue to build on the success of the Azeri-Chirag Guneshli oilfield following the signing of a letter of intent to extend development out to 2050.

In the downstream, we announced a new strategic partnership with Woolworths, one of Australia's largest supermarket retailers.

Subject to regulatory approvals, this will see us acquiring and operating over 500 fuel and convenience sites as well as establishing a new convenience retail partnership.

You may have also seen the partnership we entered into with Fulcrum BioEnergy, a pioneer in the development of low carbon jet fuel.

Taken together, all of these opportunities are building the resilience, competitiveness and balance of our global portfolio.

They're helping shape the future of the Group and getting us back to growth.

So we've been busy, but our commitment to keeping our people and operations safe has remained our top priority.

This slide shows our progress at the Group level.

Overall the data suggests we have maintained the progress made in previous years and are seeing improvements in some key measures.

Tier one and tier two Process Safety Events, our industry standard process safety metrics.

In 2016 we had 20% fewer tier one events than in 2015, while the total number of tier two events was broadly flat with 2015.

Turning to Losses of Primary Containment, or LOPCs, these refer to releases of any hazardous material from primary containment, including very small ones.

LOPCs increased in our Lower 48 business, partly due to difficult winter operating conditions, but were broadly flat elsewhere.

Looking at personal safety, our recordable injury frequency rate has reduced in 2016.

This continues a pattern of improvement in this area over a number of years.

As I will never tire of saying, safety is at the heart of all we do.

We're not going to be satisfied while we're having any accidents or harming our people.

We know there's always more to do.

With that, I'll hand over to Brian to take you through the numbers.

Thanks Bob.

Looking more specifically at the oil price for the fourth quarter, Brent crude averaged $49 per barrel in the fourth quarter, up from $46 per barrel in the third quarter.

Following the production cut announced by OPEC and non-OPEC producers at the end of November, the oil price showed strong momentum, and is now comfortably above $50 per barrel.

United States gas prices rallied in the fourth quarter, due to sustained falls in production and continued growth in demand.

Henry Hub averaged $3 per million British thermal units, up from $2.30 a year ago and $2.80 in the third quarter.

The fourth quarter global refining marker margin remained weak at $11.40 per barrel compared to $11.60 per barrel in the third quarter and $13.20 a barrel a year ago.

Looking ahead, we expect the stronger outlook for both oil and gas prices to support improved realizations in our upstream business this year.

Although refinery utilization is likely to remain weak, we expect margins to recover slightly in 2017, due to lower product stocks, but to still be well below the very high margins of 2015.

Turning now to the results.

BP's fourth quarter underlying replacement cost profit was $400 million compared with $200 million a year ago and $930 million in the third quarter of 2016.

Compared to a year ago, the result reflects lower cash and non-cash costs across the Group and higher upstream liquids realizations, partly offset by weaker refining margins and a higher level of turnaround activity.

Compared to the previous quarter, the result reflects the absence of the one-off UK tax benefit reported in the third quarter, a weaker supply and trading result and higher turnaround activity, partly offset by higher upstream oil and gas realizations.

Fourth quarter underlying operating cash flow, which excludes Gulf of Mexico oil payments, was $4.5 billion.

The fourth quarter dividend, payable in the first quarter of 2017, remains unchanged at $0.10 per ordinary share.

In upstream, the fourth quarter underlying replacement cost profit before interest and tax of $400 million compares with a loss of $730 million a year ago and a loss of $220 million in the third quarter of 2016.

Compared to the fourth quarter of 2015, the result mainly reflects lower costs, including the benefits of simplification and efficiency activities, lower exploration write-offs and higher liquids realizations.

Excluding Rosneft, fourth quarter reported production versus a year ago was 5.5% lower.

After adjusting for entitlement and portfolio impacts, underlying production increased by 1.8%, largely reflecting major project ramp-ups.

Compared to the third quarter, the result mainly reflects higher liquids and gas realizations and lower rig cancellation and one-off charges.

Looking ahead, we expect first quarter 2017 reported production to be higher than the fourth quarter of 2016, reflecting the impact of the Abu Dhabi concession renewal.

Now turning to downstream, the fourth quarter underlying replacement cost profit before interest and tax was $880 million compared with $1.2 billion a year ago and $1.4 billion in the third quarter.

The fuels business reported an underlying replacement cost profit before interest and tax of $420 million in the fourth quarter, compared with $890 million in the same quarter last year and $980 million in the third quarter.

Compared to a year ago, this reflects a significantly weaker refining environment and a particularly large turnaround at our Whiting refinery, which had a significant impact in the quarter.

These adverse effects were partly offset by higher refining margin captured in our operations, increased fuels marketing performance, driven by retail growth, and lower costs, reflecting the benefits from our simplification and efficiency programs.

Compared to the third quarter, the result reflects a significantly weaker supply and trading performance and the impact of the Whiting turnaround, which I previously mentioned.

The lubricants business reported an underlying replacement cost profit of $360 million in the fourth quarter compared with $290 million a year ago and $370 million in the third quarter.

This result brings our full year pre-tax earnings to a record $1.5 billion.

The petrochemicals business reported an underlying replacement cost profit of $100 million in the fourth quarter.

This brings our full year pre-tax earnings to $380 million compared with $170 million in 2015.

Looking to the first quarter of 2017, we expect a similar level of refining margins and lower turnaround activity compared with the fourth quarter.

Based on preliminary estimates, we have recognized $135 million as BP's share of Rosneft's underlying net income for the fourth quarter, compared with $120 million last quarter.

This reflects higher Urals prices and duty lag benefits, partially offset by higher expected tax impacts.

Our estimate of BP's share of Rosneft's production for the fourth quarter was 1.2 million barrels of oil equivalent per day, an increase of 12% compared with a year ago and an increase of 12% compared with the previous quarter.

The increase reflects the completion of the acquisition of Bashneft and Rosneft's increased stake in Petromonagas joint venture.

Further details will be available when Rosneft report their fourth quarter results.

In other business and corporate, the pre-tax underlying replacement cost charge was $420 million for the fourth quarter, an increase of $120 million on the same period a year ago, reflecting adverse foreign exchange impacts.

The average quarterly charge during 2016 was $310 million, in line with guidance.

The adjusted effective tax rate for the fourth quarter was 10% compared with 37% last quarter.

This mainly reflects the reassessment of deferred tax asset positions, partly offset by foreign exchange impacts.

The adjusted effective tax rate for 2016 was 23% compared to 31% for 2015, excluding the impact of the North Sea tax changes in both years.

Turning to the Gulf of Mexico oil spill costs and provisions.

The total cumulative pre-tax charge for the incident is $62.6 billion or $44.1 billion after tax.

The charge taken for fourth quarter was $800 million pre-tax or $530 million after tax.

This reflects our latest estimate for claims, including business economic loss claims and other costs, and the ongoing unwind of discounting effects on the provision, which have no impact on cash.

Significant progress has been made in the fourth quarter and we are moving towards completion of the process for resolving business economic loss claims.

Amounts to resolve the remaining claims are expected to be substantially paid this year.

We have revised our provision for these claims to reflect our best estimate of the cost of the remaining claims.

The pre-tax cash outflow on costs related to the oil spill for the full year 2016 was $7.1 billion.

Looking next at cash flow, this slide compares our sources and uses of cash in 2015 and 2016.

Underlying operating cash flow, which excludes pre-tax oil spill related outgoings, was $17.8 billion in 2016, of which $4.5 billion was generated in the fourth quarter.

This includes a working capital release of $3.2 billion for the year, with $2 billion in the fourth quarter.

Organic capital expenditure for the full year of $16 billion included $4.5 billion for the fourth quarter.

Divestment proceeds totaled $470 million in the fourth quarter and $3.2 billion for the year, including $570 million from the partial sale of the Group's shareholding in Castrol India.

Gulf of Mexico oil spill payments were $2 billion in the fourth quarter, bringing full year 2016 cash payments to $7.1 billion.

We estimate that the cash impact of non-operating restructuring charges was around $1 billion in 2016, with around $2 billion since the fourth quarter of 2014.

As Bob noted, cash flow delivery from our operations was robust, despite the much weaker environment, supported by delivering our $7 billion cash cost reduction target a year ahead of plan.

As well, organic capital expenditure for the year was well below our original guidance.

So we ended the year ahead of where we expected to be on rebalancing organic sources and uses of cash.

This helped mitigate the net inorganic outflow that arose due to the rephrasing of divestment proceeds previously expected in 2016 into 2017, and Deepwater Horizon cash payments that were higher than we anticipated for 2016, mainly due to the faster resolution of claims.

Net debt at year end was $35.5 billion and gearing was at 27%, comfortably within our 20% to 30% target band.

In 2017 we see a number of factors impacting our financial framework.

In addition to what we anticipate will be a stronger environment compared to 2016, we expect Group operating cash flow to reflect the full cumulative effect of having already reached our $7 billion cash cost reduction target.

It will also reflect the ongoing focus on continuous efficiency improvements across the Group.

With our portfolio now growing, this will show up in future, mostly in the unit cost matrix of our businesses.

Non-operating restructuring charges are expected to continue into 2017, although we expect the cash flow impact to be lower than last year.

We now expect 2017 organic capital expenditure to be between $16 billion to $17 billion, including the estimated operational capital spend for our portfolio additions.

This compares to previous guidance towards the lower half of $15 billion to $17 billion range for the old portfolio.

In addition, we expect some $700 million of inorganic cash outflow in 2017, related to these already announced transactions.

Compared to 2016, we expect divestment proceeds to be higher in 2017, in the range of $4.5 billion to $5.5 billion for the year, and then reducing from 2018 to a more typical $2 billion to $3 billion per annum.

At the same time, we estimate Deepwater Horizon cash payments to be lower than last year, also in the range of $4.5 billion to $5.5 billion.

As already noted, we expect the remaining business economic loss claims to be substantially paid this year.

We therefore expect the total Deepwater Horizon cash payments to fall sharply to around $2 billion in 2018 and to then step down to a little over $1 billion per annum from 2019 onwards.

So, putting all of this into context, we remain firmly focused on re-establishing a balance in our financial framework where operating cash flow covers capital expenditure and the current dividend at the prevailing oil price.

The strong progress we have made to date in structurally rebalancing our financial frame is allowing us to maintain our dividend and underpins our confidence in pursuing the inorganic transactions already noted by Bob.

This is consistent with our aim to retain the dividend at a level we believe is supported by the long-term cash generating potential of our businesses, while balancing investment to ensure we can grow free cash flow over the longer term.

As already discussed, we expect the environment to remain uncertain for a while yet, and we have the usual seasonal trends in our business to navigate.

Our recently announced portfolio additions are accretive to cash flow over the longer term but create additional cash outflow in the early years.

So current oil prices notwithstanding, we anticipate rebalancing at the prevailing oil price towards the back end of the year.

This also coincides with the mostly second-half start-up of our extensive program of new upstream major projects.

Including the impacts of our announced portfolio additions, this translates to balancing organically by the end of the year at a Brent oil price of around $60 per barrel.

Our balance sheet has the flexibility to deal with near-term fluctuations.

For this year we will retain the option of a scrip as an undiscounted alternative to our cash dividend.

We continue to target gearing within a 20% to 30% band going forward, monitoring our cash inflows and outflows closely.

Over the near term we will explore further funding mechanisms or divestments if required to enhance cover and retain flexibility to take further advantage of growth-enhancing opportunities.

Looking further out, and based on our new portfolio, we expect organic free cash flow to start to grow at around the same price level.

We expect this to be supported strongly over the medium term by the ramp-up of our new slate of upstream project start-ups, strong marketing growth and from the accretive effects of our enhanced portfolio.

As noted in October, once rebalancing is achieved we would love to address the dilution that arises from the scrip dividend alternative.

We will then aim to ensure the right balance between disciplined investment for even stronger growth and growing distributions to shareholders over the longer term.

This slide summarizes our remaining guidance for 2017.

We expect full year underlying production in 2017 to be higher than 2016, primarily due to our major project start-ups.

We also expect actual reported production to be materially higher, as this will include the renewal of the Abu Dhabi concession, although the actual outcome will also depend on divestments, OPEC quotas and entitlement impacts.

In 2017 we expect DD&A to be higher than the 2016 charge of $14.5 billion, mainly reflecting the impact of the Abu Dhabi concession renewal.

In other business and corporate, the average underlying quarterly charge is expected to be around $350 million, although this may fluctuate between individual quarters.

From the first quarter of 2017 we will recognize our 10% share of the Abu Dhabi concession on a pre-tax basis within the upstream.

We expect this will have a material impact on upstream pre-tax underlying replacement cost profit, but will also reflect a higher effective tax rate for the Group.

In the current environment, we expect the effective tax rate to be in the region of 40% in 2017, mainly reflecting the inclusion of the Abu Dhabi concession.

We will publish our updated rules of thumb on our website later this quarter.

I'll now hand you back to Bob.

Thanks Brian.

I'd now like to take a closer look at how our upstream and downstream businesses are contributing to the picture of growing resilience that Brian has set out.

Looking first at the upstream, we achieved a lot in 2016 in a challenging price environment, and continue to become a more resilient business.

You can see this in improvements in our operating performance, the actions we've taken to reduce cost and capital spend through our active portfolio management.

We continue to see strong operating performance in 2016 with plant reliability for operated assets at around 95%.

All 11 turnarounds in 2016 were completed on or ahead of schedule.

This was accompanied by a strong drilling performance, with drilling and completion non-productive time reduced to around 20% compared to 26% in 2015.

I've already mentioned we had six start-ups last year, which makes 2016 a big year for major projects, with another big year to come.

The first of the 2016 start-ups was in February with the start-up of the In Salah southern fields in Algeria.

Then came Point Thomson in Alaska in April, the recent restart of Angolan LNG and Thunder Horse water injection in the Gulf of Mexico, both in May, and in December the In Amenas compression project in Algeria.

Last on the list is the Thunder Horse South expansion in the Gulf, which started 11 months ahead of schedule and $150 million under budget.

We also made final investment decisions or FIDs on five major projects this year, including most recently the Mad Dog 2 expansion in the US Gulf.

Last month we completed installation of the jacket and topsides for the Juniper project in Trinidad, marking a significant milestone for the project.

This organic growth keeps us on track for the planned 800,000 barrels of oil equivalent per day of new production from major projects by 2020 and contributes to growth beyond this.

In addition to the 2016 exploration discoveries previously announced in Egypt and Angola, we've made significant progress in enhancing our portfolio with significant new access through our agreements with Kosmos Energy in Mauritania and Senegal, again a 10% of the Zohr field in Egypt, two new deepwater exploration blocks in the Salina Basin in Mexico, and our previously announced new access in China, and Newfoundland, Canada.

So 2016 was a busy year for the upstream.

With our recent announcements we now have a stronger and more diversified upstream portfolio that lays the foundations for future growth.

In the downstream, the execution of strategy has delivered another year of material underlying performance improvement.

Full year pre-tax earnings of $5.6 billion are more than 25% higher than 2014, despite the refining environment being significantly weaker than 2014 and one of the weakest in the last 10 years.

This includes $3 billion of underlying performance improvement at constant margins since 2014, $1.2 billion of which was delivered in 2016.

This demonstrates that we continue to expand the earnings potential of our business.

Our refining operational performance was strong, with Solomon availability increasing to 95.3% for the full year.

In the fourth quarter, we also completed the dissolution of our German joint operation with Rosneft.

This will greatly simplify and refocus our refining business in the heart of Europe.

In our fuels marketing and lubricants businesses, we saw continued growth in pre-tax earnings, up more than 15% versus last year, reflecting underlying performance improvement and benefits from continued investment.

Across our retail business, which is the most material element of our fuels marketing operations, volumes increased by 3%, supported by the success of our new Ultimate fuels with ACTIVE technology and the expansion of our convenience partnerships with leading retailers.

As I mentioned earlier, our recently announced strategic partnership with Woolworths in Australia demonstrates our strategy of growing our advantage marketing businesses in important global markets.

Once completed, it will provide additional earnings and operating cash flows to the downstream.

In lubricants, this year we had a record pre-tax earnings.

We had good growth across all of our growth markets and premium brands, such as Castrol.

And through technology, we continue to develop new offers and lower carbon products for our customers.

In addition to Ultimate fuels, we also launched new products in lubricants and petrochemicals.

Finally, total cash costs in the downstream are now $3 billion lower than in 2014, their lowest level in more than 10 years.

This reflects the benefits, mainly from our simplification and efficiency programs, along with some foreign exchange impacts.

In summary, 2016 has been another year of delivery from our downstream business.

It has continued to grow underlying earnings, is more resilient to the environment and has built a great platform for further exciting growth opportunities.

Now it's time we moved on to take some questions, but let me briefly sum up what you've heard from us.

First and foremost, our strong focus on safety and reliability is underpinning a track record of continually improving operational performance.

Second, we've been working systematically to a plan to rebase our capital and cash spend.

As Brian laid out, the Group is moving steadily towards rebalancing our financial framework organically by the end of 2017 at around $60 per barrel oil prices, which includes the operational impacts of our many recent portfolio announcements.

Our balance sheet is sufficiently strong to deal with near-term volatility, while also being flexible.

That's why we have been able to be creative with our portfolio to step in and capture a set of strategic opportunities that will add value and enhance future earnings and cash flow for many, many years to come.

Third, we are increasingly resilient to all conditions, with that resilience coming from the progress we're making in focusing and simplifying both our upstream and downstream businesses.

Fourth, both upstream and downstream have been building capacity to deliver material and growing free cash flow for the Group over the medium term, even if the environment stays much where it is today.

Our confidence in this outlook allows us to continue to sustain our dividend.

Looking further out, our primary objective remains to grow sustainable free cash flow and distributions to shareholders.

We are looking forward to showing you more of the detail in our strategy update on February 28.

We aim to show you how we are building an even stronger platform for growth, how we are retaining a focus on returns, and how we are shaping our longer-term future in what we all know is a rapidly changing world.

So thank you very much for listening and we'll now open it up for your questions.

(Operator Instructions).

Okay, well welcome again everybody.

We'll take the first question today from Alastair Syme of Citi.

Are you there Alastair?

Good morning everyone.

Brian, can you just clarify in fourth quarter on the cash statement around the timing of dividends received from associates?

There seems to be quite a big swing from previous quarters.

And I have a follow-up question on Egypt as well please.

Thanks Alastair.

Sorry, specifically in terms of related company income?

Exactly.

I think there will have been a cash inflow off the back of a bond in Argentina will have come through in the fourth quarter, and I can't remember the exact amount but that would have been part of the delta.

Okay, so there's not an unusual mismatch on dividends received this quarter from associates?

No.

Okay.

My follow-up question is on Egypt.

Can you -- strategically can you talk around the overall exposure to Egypt on a risk-adjusted basis?

Are there any synergies on being in Zohr versus your existing West Nile Delta business?

Well I think I'll let Bob talk about the attractivity in terms of Zohr and how it sits within the portfolio.

In terms of risk exposure, if anything with Egypt I think the risk is significantly reduced from where we were four or five years ago in terms of both the portfolio we have, because now being part of Zohr of course balances out some of that risk.

It also enables us to deploy, and we have deployed over the last three or four years, Egyptian pounds paid locally into local contracts.

And therefore, if you think about our long, long history of being in Egypt, over 60 years, the receivable that was coming under some stress post the various changes three years ago after the Arab Spring.

That is now vastly reduced from where we are, and so from a risk perspective, Egypt is actually now in terms of our radar screen is much reduced from where we were.

Of course, as you pointed out, Zohr helps in terms of further investment across our portfolio, but from a risk perspective financially, Egypt is reduced from where we were.

Yes Alastair, the Zohr purchase for BP -- of course BP and Eni work together all across Egypt in many places and we've got our own very large projects in Egypt, a very large one, the West Nile Delta project, which will come on towards the summer here.

For us Egypt is very strategic.

As Brian said, we've worked there for 50 years without an interruption at all.

We think it's got great potentials as a gas market, and as the West Nile Delta and Zohr come on this year, we think Egypt as a country's position of potentially moving to a gas exporting country is in very good shape.

So I know it's overlooked by a lot of people but we're very pleased with that project, as well as the other ones we've got.

We've got other discoveries there that we're moving towards development as well.

Thank you very much.

Thanks Alastair.

We'll take the next question from Thomas Adolff of Credit Suisse.

Good morning.

I've got two questions around the CapEx please.

The easy one I guess is I wonder what the share of CapEx today is that can generate cash flow within the next two years.

I just wanted to better understand the cash flow cycle and financial risk associated to your CapEx.

The other question on CapEx I have is the longer-term sustaining CapEx.

Last year in Baku, when you hosted the field trip, you talked about the portfolio quality in depth, you were very happy with what you had and that the sustaining CapEx would be at around $15 billion to $17 billion for the Company as a whole.

Obviously since then you've made a number of acquisitions, presumably to strengthen your portfolio, as you've highlighted, and that is also leading to a slightly higher CapEx range in the near term to $16 billion to $17 billion per annum.

But I wondered whether this enhanced portfolio also now allows you to sell more in 2017, because I'm assuming that -- so the question I really have around that is, can the longer-term CapEx range in the say world of $60 to $65 revert back to the $15 billion to $17 billion range?

Or is the disposal plan merely a function of matching Macondo liabilities?

Thank you.

So Thomas, let me just pick up the first part of the question, which I think is about capital in service and capital not in service.

I don't have the precise figures for you, but obviously, given the number of big projects we've got coming on stream this year, there is a significant amount of the upstream capital will be in projects.

So I'm guessing somewhere close to 40%, 45% of the CapEx we're spending in the upstream this year will be in the major project wedge for 2017.

And we can come back to you with the specifics around that, but we don't normally give guidance around what's in service and what's not in service in terms of build.

In terms of the disposal program, we've said many times, we've sold off close to -- actually over $55 billion of upstream assets over the last two or three years at $100 a barrel of those higher prices.

The next phase of divestments, and if you look at the divestments that we slated through 2016, the majority of those were midstream and downstream.

Actually quite a few corporate assets we had around the place have been sold off.

The target we've set for next year has some upstream in there, but none of it that's going to have a significant impact in terms of the future capital program.

So I think we gave you guidance at 3Q around $15 billion to $17 billion of capital for this year.

We've closed those extra transactions that Bob talked about in terms of creating optionality for the future, and therefore we've moved the capital frame up to $16 billion to $17 billion, which we think is good for this year and will see us through into 2018.

And then we'll see whether other opportunities arise this year.

The ones that we talked about, they all came together at the same time.

You wouldn't normally have that many converge in that short a space of time, but there may be other opportunities for us this year as well.

So I think the key is everything has to come back to the balance of the financial frame and making sure that we can cover organic CapEx and the full dividend with the operating cash flow.

That gets more sustainable from here as we start to see the ramp-up in projects and the new builds coming on.

Can I just follow up on the last point you made?

You said that there may be more opportunities this year and next.

Presumably you're referring to further acquisitions, and obviously the focus also has to be on balance sheet.

So would you fund further acquisition via the balance sheet or further equity issuance or more disposals?

Thank you.

I think what we'll continue to stay focused on for our shareholders is deals which are accretive.

And anything which is accretive, we will look at.

But please don't let me send the signal out that we're out there on a shopping spree right now, because we're not.

But if opportunities arise -- take Aker BP as an example for last year, which is a great example of a late life asset that now has a huge growth opportunity through a creative innovative structure that we put in place.

I could argue the same thing about Abu Dhabi, about Mauritania and Senegal.

Each time you see us step into the marketplace, it's really about creating optionality for the future.

But everything comes back to what are we trying to do for our shareholders.

So I think if you see -- if accretive opportunities arise, then they're the ones that we'll look at, but of course it will all be bound up within the financial frame.

Perfect.

Thank you.

Thanks Thomas.

Turning now to Martijn Rats at Morgan Stanley.

Go ahead Martijn.

Yes, good morning.

I wanted to ask you two questions.

So the CapEx has of course come down a fair amount during the course of this year, but the CapEx commitments you've entered into are quite significant and stand out relative to some of your peers.

So I guess that reflects how you see the cycle unfolding, as in it suggests that you think this is the right time to do projects.

I'm just wondering if that is indeed the right interpretation of that observation?

The second thing I wanted to ask you about is the following.

So on the 3Q conference call there was a comment -- and I'll read it out.

It said in upstream growth is imminent and visible until the end of the next decade.

And on this call we're talking about the large number of transactions you've done over the last two months and the comment in the press release is that we've laid the foundations for BP to be back to growth.

And I have to say, I struggle a little bit to make these things consistent with each other.

Can you talk about that?

Well Martijn, a couple of things.

One, I don't think our CapEx has ramped up very much.

We said $16 billion -- $17 billion to $19 billion this year, we came in at $16 billion.

We're probably looking at $1 billion more roughly this year, so I don't see that as a massive boost.

In terms of the growth going out, we've got six big projects coming on in 2017, in addition to the six that came on in 2016, the ones in Algeria, the Thunder Horse West, water injection, Point Thomson, Angola LNG and Amenas and Thunder Horse South expansion that's came on in 2016.

We've got the big Quad 204 project coming on in the North Sea; we've got Trinidad onshore; we've got the compression project; we've got Juniper in Trinidad; we've got the giant Oman Khazzan phase one, Persephone coming on in Australia, West Nile Delta, very large project coming on in 2017.

You keep going on into 2018 and you see the big Clair Ridge projects in the UK, Culzean in the North Sea, the big Shah Deniz project coming out of Azerbaijan and Atoll in Egypt.

The list goes on and on.

We see guidance out there with some other FIDs this year as well for that 800,000 barrels a day additional production from new projects.

And I haven't mentioned them all.

Mad Dog phase two is another one.

So I think if you lay out the upstream major project summary, the ones that we've brought on, the ones that will come on this year, the ones planned in 2018 and 2019 and the FIDs you'll see, that's what is meant by the future growth.

Okay.

Thank you.

Thanks Martijn.

Next question from Oswald Clint at Sanford Bernstein.

Yes.

Good morning.

Sorry to labor a point, but I actually had a similar question to the last few.

It's really going back to the Baku trip, when we hear about the 45 billion barrel resource base and 8 billion barrels that would have to be extracted over the next 13, 14, 15 years to continue growth.

Maybe another question.

Is there anything in that 8 billion barrel number that was supposed to be the development hopper that just isn't looking so attractive today that you had to make these deals in the last two months of last year or these deals were just so attractive you had to move on them?

That's the first question.

And maybe one -- Brian, I'm just want to look at the cash flow numbers again, the $18 billion last year.

And we had to step up I guess to $24 billion, $25 billion this year to cover that CapEx and dividend.

So I can see getting half of that $6 billion delta uplift from a commodity price, but is the other half coming from upstream volumes or is there a decent contribution from Whiting or I guess some of these Australian -- the acquisition in Australian retail in December?

Thank you.

Yes.

Oswald, I'm actually going to pick up the first part of the question first and then Bob might want to sweep on it.

But just to say, just from the financial frame perspective, I think Bob's just laid out a list of projects that I think underpins Martin's question that says, call me old fashioned, but with that level of projects coming through and the nature of the gas and oil mix, that gives us significant growth.

So actually we didn't need to do any of the deals in terms of the future health of the Company last year.

And one of the things that actually really gave us confidence to execute on those, there are two things.

One was being able to bound the liabilities around Macondo in terms of understanding now that we're in the final stages of that process around the liabilities and understanding what the future commitments are.

But the second piece was also around recognizing that by the end of last year we'd managed to get the portfolio back at balance at around $55 a barrel in terms of the portfolio we had at the end of last year.

And we're giving ourselves eight quarters to do that.

Now, if you remember, back in February 2015, the lower -- someone reminded me on call this morning about the lower-for-longer tag that we had that at the time people pushed back and said, no, no, oil prices will come back.

We were very bearish and ensured that we got after a series of things around cost and capital to get the portfolio back to balance at $55.

The great thing about being able to do that is that creates optionality.

And these deals were deals that my dear friends on my left, Bob, have been working for a number -- over a long period of time and they came together at the right time.

And I'll come back to the cash flow number, but I don't know if, Bob, you want to add anything around the deal structure we put through at the end of 4Q.

Well, I think, as you said, those deals were not essential for us.

We've been working on them for a while.

They had to be accretive.

Some obvious ones in Abu Dhabi.

The terms there came together and they were very attractive and they lengthened the Company's life out, 2055.

Azerbaijan, another natural one that you see us doing, is looking for an extension there on the ACG concession, which will go out to 2050.

The Zohr project, strategically, just works really well for us and with our partnerships there with Eni.

The little bolt-on acquisition in Tangguh, no additional overhead whatsoever, accelerates that project, helped get it approved.

These were things that were not essential, as Brian said, but just strategically make sense for us.

Even the Australian one, which does require the regulator's approval, probably get done sometime next year, in 2018.

You'll know in the UK we've got a great model with Marks and Spencer's in our retail growth, in revenue growth.

And we've got a chance to replicate that very successful strategy in Australia.

These were things that I think are all going to help build where we're going.

That, along with a very, very solid organic set of projects that we've got in the pipeline.

And we'll go through this in more detail with you on February 28.

We'll have a strategy update.

In fact, we're looking forward to that.

And then, Oswald, in terms of operating cash, I'm going to try and help you a little bit in terms of what we can see coming through this year that gives us confidence around the balance point.

So we exit 2016 at around about $17.8 billion.

Back out the working capital release that came through the results through the backend of last year, so take another $3 billion out of that.

If the oil prices stay where they are today -- and of course, there's a lot of environmental movements that you can't see beyond the rule of thumb around like, for example, non-Henry Hub gas and what's happening with local refining margins.

But let's just assume the environment helps at where today's oil prices are, around $4 billion, so that's positive $4 billion, maybe more than that if we get up towards $60, which we're not anticipating at the moment.

I think something around $50/$55 is a good planning assumption for this year.

You've then got the Abu Dhabi piece comes in, and that's cash accretive for this year.

We also have rationalization expenditure of $0.5 billion to $1 billion of cash that went out last year that won't go out this year.

There will be some going out this year, but the delta's somewhere from $0.5 billion to $1 billion.

We've got volume and margin improvements coming through in both upstream and downstream -- it's about 50/50 -- of about $1.5 billion to $2 billion.

And then some other movements get you to a cash figure this year of somewhere around $21 billion to $22 billion at today's price set, which means that the CapEx and dividend, cash dividend, is covered with an imbalance of about $1 billion.

Now, of course we actually want to cover the full scrip part of the dividend, which we'll be able to do as we get into 2018, delayed only by a year because of course we've now got the new options around the new transactions, which will require an extra $1 billion of CapEx or thereabouts for this year, as Bob said.

So actually everything box balances for this year, and then we've got the momentum through into 2018 with the ramp up of the projects, which says we start to see free cash flow growth from there.

So it's nice to have the scrip.

We'd like to offset that scrip, and we will offset the scrip at the first opportunity we get.

But in terms of cash balancing, that's how you get from 2016 to 2017.

And of course, there may be some upside on the oil price.

And a footnote, Oswald.

You mentioned are there any hubs that aren't coming through that we felt like we needed to fill?

The answer's no on that.

You might be thinking of India, but those are coming forward.

The economics look very attractive given the new gas price in India as well.

Maybe that's the one you were thinking of, but we don't have any gaps really.

And, Oswald, just to be clear, in my little balancing I've done here I'm assuming CapEx at around about $16 billion.

Excellent.

Thank you very much.

Yes.

Oswald, it's probably also worth noting that the $16 billion to $17 billion CapEx guidance for this year, although it's a little bit higher in terms of specific guidance for 2017 that's still within that overall $15 billion to $17 billion frame we showed you in Baku.

Okay.

We'll take the next question now from Gordon Gray of HSBC.

Thanks, and hello, everyone.

Two quick ones if I can, firstly on the M&A side of things.

I think it's fairly obvious that this could be a good point in the cycle to be building the upstream positions, but to some people I guess the downstream acquisition, the Woolworths acquisition, was a little bit less obvious.

Maybe you can just give us a little bit more rationale around that one.

And secondly, if you could give us a little bit of insight into the reserve replacement outlook or position excluding the Abu Dhabi acquisition.

Thanks.

On the latter one, we'll come back on the reserves replacement ratio when we file our ARA, Annual Report and Accounts in 20-F, so we'll come back to the split of that.

And you'll also see what the Rosneft piece looks like underneath all of that in terms of reserves replacement.

Bob, Woolworths.

Yes.

Gordon, on Woolworths, this is really very consistent with strategy.

Our UK retailing has done extremely well.

We don't lay out all the details of that, but by acquiring and re-branded the operating Woolworths' stations in Australia, a brand that unless you're familiar with Australia you won't realize how strong the Woolworths' brand is in Australia, we'd acquire 527 fuel and convenience sites.

And again, subject to the approvals there, probably completed in early 2018.

It's accretive to earnings.

It's operating cash flow with returns that are competitive with the rest of our downstream portfolio.

It's a somewhat unusual opportunity.

It's very consistent with the strategy we have in the downstream, which is develop these high-quality, differentiated fuels and convenience offers in the downstream.

And again, it works really well here with Marks and Spencer in the UK, and REWE in Germany also is another model for us.

So this one was -- we feel is very attractive for us.

And on reserve --

Thanks.

We have reserve replacement of 109%.

Again, Brian said we'll break those out later, but it's really a renewal of the concession that we had before.

We've had healthy reserve replacements across the rest of the Company as well.

Great.

Thank you.

Thank you.

Next question now from Anish Kapadia of TPH.

A couple of questions from me.

The first one was on your net working capital position.

If I look back to 2013, the end of 2013, your net working capital position was over $20 billion, I calculate, obviously in a much higher oil price environment.

I think now, at the end of 2016, it was close to zero.

I was wondering, I'm guessing oil price is a big portion of that, but if you could explain if there are any other impacts in there and how you'd expect that to trend, especially in a rising oil price scenario.

And the second one was related to your planned disposal program for this year of about $5 billion.

Just what's your estimate in terms of the cash flow that you'll be selling alongside that, that $5 billion and any idea of the split, upstream versus downstream?

Thanks.

Okay.

On the net working capital piece, as you can imagine, as you move from -- you're absolutely right.

As the oil prices go higher, working capital builds.

And therefore, we have assume some working capital build into 2018.

And at $55 a barrel, we're assuming it's neutral.

Actually, it will be neutral for this year.

Obviously as you go through the big correction with being around the oil price, costs, working capital, capital, all sources of cash are worked through.

And we've been systematically reducing our working capital uses in both the downstream, but also in the upstream around inventory management.

So it's part of parcel of everything we've been doing around costs and CapEx.

Hence why you've seen the working capital balances come down so significantly.

For 2015, we're assuming it's neutral.

So there isn't any assumption that there's any working capital release nor build.

But as prices -- if prices move up in 2018, we would expect a modest increase in working capital.

And that's built into a forward cash flow projections.

In terms of disposal proceeds for 2017, the bulk of what we're looking at is -- in terms of the cash flow impact, they've already been built into our projections for this year.

So they sit inside all of our portfolio adjustments.

The big cash accretive pieces were really sold off in the last big series of transactions we did over 2013, 2014, 2012.

They won't have anything like the same impact.

They -- yes, a lot of the assets are actually more in the utility-type returns, if you look at midstream and some of the terminals that we're looking at.

And actually, some of the examples I could give you for this year were some of the offices that we sold off that we hold.

Obviously there's no cash associated with those.

There's a small increase in costs in terms of the lease, but from an IRR perspective they're very good returns for us.

And you will have seen some of the transactions we've got away.

So nothing that causes any concern in terms of being cash accretive or dilutive.

If anything, they tend to be on the lower end of the cash return.

Thank you.

Thanks, Anish.

Turning now to Guy Baber in the US.

Thank you for joining us, Guy.

We realize it's quite early in the morning there, so very glad to have you on the call.

Will you go ahead with your question?

Thank you very much.

You guys reached the $7 billion cash target for cash cost reductions early.

Can you just talk about that a little bit and now what the expectations are from a cash cost perspective going forward?

Are there opportunities for continued reductions and where may you see those?

And are you beginning to see any inflation anywhere in your business that you operate?

If you could just help us understand that, that would be great.

And then I had one follow-up.

Yes, Guy, a very good morning, early morning to you.

Some color here on our cash cost reductions.

We did hit the $7 billion reduction in cash cost versus 2014 a year earlier than planned, took them down from $27.2 billion to $20.2 billion.

The split on that is around $3.7 billion has been in the upstream, $3 billion in the downstream and about another third, or third of a billion on other operating -- other corporate businesses.

Two-thirds of that is roughly from self-help, driving cost reduction, simplification in.

A third of that is from deflation of cost.

And that self-help really is how we work more efficiently, with the activity optimization, simplifying how we do things.

The organizational size has come down, so staffing costs have come down.

Getting into more of the details, the kinds of things that we drive is with BP headcount and reduction of the expatriates.

Agency staff has come down quite a bit, headcounts and rates for agency staff.

We've had a lot of third-party spend come down just by more competitive bidding.

We've got a real drive to eliminate waste.

Common sense at scale we call it.

Inventory control, operated by others.

We're working hard on those where we're not the operator to push them as well.

And for BP, we're pushing, as our partners do with us, to improve cost recovery over time.

Brian, you want to add anything?

Yes.

I think it's across the piece.

And I think the only other comment I'd add is that of course we started in 2012 in the corporate space in terms of trying to take out significant costs.

And those corporate and functional costs, we've stripped out about 40% since that date, which the high-water mark was around 2012, if you think about all the redundancy we've built into the system after then events of 2010.

And then in terms of upstream, as Bob said, going forward, 75% of the reductions that we've driven through here we believe are sustainable.

25% will be exposed to inflation, but I don't think we see any of that coming any time soon.

That's very helpful.

And then my follow-up was I was hoping you all could touch on the Lower 48 onshore business a bit, but can you discuss the appetite now to increase spending there in light of the strides you've made operationally and maybe what the implicit range of spending is for that business within the overall CapEx range?

And where does the Lower 48 fit in terms of your appetite for perhaps some incremental acquisitions?

If you could just discuss maybe what you might be looking to add there, that would be helpful.

Well, I think our team there have really -- their capability now in driving the rigs and the rig work and getting results has really, really come through.

Production in the quarter was over 300,000 barrels a day now, which is the highest fourth quarter since we've had -- since 2011.

So Dave Lawler and that team have been doing a great job.

We've got our highest quarterly operating cash flow from there as well.

So we like what the team is doing.

We will look at ways to incrementally see how we can take the capability and expand it.

We'll do it creatively.

There's a lot of -- there are a lot of targets, I would say, that are out there on offer.

They seem highly priced to us, so we're going to use a lot of discipline here before we take it up.

We got -- you'll remember a few years ago we had about 2 rigs running.

Now we've got 13 rigs running in the fourth quarter.

Sorry, we've reduced our rigs down.

We've got 5 rigs running in the fourth quarter compared to 13 in the fourth quarter of 2015.

But what we're getting out of those rigs is quite astounding.

Of course, there's some weather issues right now.

But, Brian, you want to make any comments?

Yes.

No.

The only other thing I'd say is what the team have done, which I think is really important, is get the cash breakeven of that business right down to therefore justify the capital spend going forward.

And I think Bernard and the team will look at opportunities with Dave Lawler in terms of where will we take that business going forward.

And you'll know from the external data we publish, it is in a markedly better position than it was when Dave and the team came in.

And our cash breakeven number has come down significantly from where we were by the time we got to the fourth quarter.

And our liquids production is up to about 15% of that total as well, 1.5 Bcf a day.

But we've got about 15% liquid, so that's giving it a boost as well.

Guy, thank you.

Thank you very much.

Thanks, Guy.

We'll take a question now from Theepan Jothilingam of Exane.

Yes.

Hi.

Good morning, all.

Thanks, Jess.

A couple of questions actually, firstly just on Macondo.

Could you talk about particularly the BEL payments and how you see that phasing in, in 2017?

Will that also be frontend loaded?

And perhaps just give a little bit of color in terms of the process and what's remaining in terms of the claims to -- that BP needs to run through.

Second question, just in terms of major turnarounds.

We saw one in Q4 with Whiting.

I just wanted to ask if there were major turnarounds in the BP portfolio, either in the upstream or the downstream, for 2017.

Thank you.

So, Theepan, on the first piece, the BEL payments have been significantly accelerated through the back half of last year through various processes we did under the court supervision.

But effectively, now we're left with the final piece of the claims facility.

But I'll just give you some data.

We started with about 149,000 total claims in the BEL process.

Half of those were closed with no payment and 65,000 of them have now been finalized, with 15,000 being resolved in the fourth quarter, hence why you've seen the reassessment now in terms of the provision.

We've been able to work through a big number of claims through a process aligned with the court supervised settlement program, which leaves about 9,000 claims now to be resolved.

So we will expect to see all of those, the majority of those get worked out through here.

There will be some appeals, so actually in today's provision, anything which is of a significant nature where we believe that actually the payment is not a representation of the actual loss, we will appeal those through to the fifth circuit.

So you will see some of those come through and they will take some time to get resolved.

But generally, we would expect, and as we've said in our press release today, to get a -- the major resolution of what's left in terms of the overall claims, not just business economic loss claims, but the big chunk of business economic loss claims have now effectively been resolved through the fourth quarter, with 9,000 left to be processed this year.

Yes.

Thanks, Brian.

And on turnarounds, we did complete 11 of them in 2016 ahead of schedule.

You're right, we had a Whiting turnaround.

That's in the upstream.

We had a Whiting turnaround and it -- right near the end of the year.

There will be turnarounds in 2017.

I don't have the exact schedule in front of me.

But the industry, the refining industry itself is slated in North America for a heavy set of turnarounds later in the spring.

And we'll have some of their -- of ours there as well.

But it's not an overly burdensome set of upstream turnarounds in 2017.

And you can check in with our IR team at another time.

Thank you.

Thank you.

Brian, I was just wondering, just on the actual payments for the BEL claims through 2017, is that going to be -- if we're trying to model the quarter and watch BP's gearing, is that going to be frontend loaded or --?

It will absolutely be frontend loaded, which is -- and Theepan, maybe just to decode some of this, one of the reasons why we're frontend loading and accelerating is that the administration comes down and that facility, under Pat Juneau's excellent supervision, will start to wind down as we get towards the end of this year.

Of course, all under supervision of the court.

Okay.

That's clear.

Thank you.

Thank you.

We'll take a question now from Jon Rigby of UBS.

Go ahead, Jon.

Thanks, Jess.

Yes, I've got two questions.

The first is on trading.

This 4Q pattern of reduced or negligible contribution to trading seems to recur, and I just wondered whether you could talk about what drives that.

Is it risk?

Is it opportunity?

I'm conscious that your upstream business runs 24 hours a day, 365 days a year.

I'm curious why your trading business only runs for three quarters.

The second question is just on your tax guidance.

Obviously you're taking the ADCO tax below the line as corporate tax, so I just wondered whether you were able to give us some sort of indication of what an apples-to-apples tax rate would be, i.e.

what the underlying tax rate would be without the ADCO impact that takes it to 40%.

Thanks.

So, Jon, on the first question, I can tell you from personal experience.

But I asked the same questions of the Chief Executive of IST, Paul Reid, who's done a great job over the last six years and is stepping down this year.

Actually, this fourth -- every fourth quarter is different, but generally, what happened this fourth quarter, this was not -- and it's oil trading.

It's not gas trading.

Gas trading actually had a good result in the fourth quarter.

But in terms of the oil books, I think, generally, coming into the fourth quarter, given all the uncertainty around what OPEC was going to do and just the sensitivities around supply/demand balances, this was not a quarter to try and take big positions.

And therefore, I think there was a natural inclination to flatten up all of the books.

There was also an adverse court ruling against us, which was actually a $70 million hit that was in the public domain that made the actual fourth quarter a loss.

Otherwise it'd have been just above breakeven.

But I think it's more a reflection.

This fourth quarter is different to the last time we had a fourth quarter where there was an either breakeven or small loss.

And I've actually looked out over the last 20 quarters.

Something like 12 or 13 of those or at least close to 50% of those are above average.

There's about 25% significantly above average and then there's about four or five quarters where it's breakeven or just a slight loss of just on plan.

So just to caveat this, the oil trading books actually were above plan for 2016, as they were in 2015.

But 4Q was really not a quarter where you'd want to be taking significant risk given all of the uncertainties around what was happening around supply and demand balances.

So that explains I think 4Q oil.

And then on the tax rate, I'm sorry, I apologize, it's a messy quarter in terms of trying to give guidance around the effective tax rate.

Effective tax rate for last year is about 23%.

If you add Abu Dhabi it moves it up significantly.

But there's also a change in the mix of profits around gas and oil and where those profits sit, so that also has an impact to take the effective rate up to around 40%.

If you look at 2017 without Abu Dhabi, the effective tax rate would be somewhere around 30% and a cash tax rate of 23%.

And I think just an important point, Jon, just in terms of using our rules of thumb, because of course we've gone through all the various back-of-envelope calculations, the marginal tax rate you should use on the rule of thumb and our new rule of thumb will be about $340 million for every dollar a barrel, if you include Abu Dhabi.

The marginal tax rate you should use on that piece is somewhere between 10% to 20%, so 15% is probably a good marginal cash tax rate to use as you start to think about deltas year-on-year.

Okay.

Super.

Thank you.

Okay.

Going now to Lydia Rainforth from Barclays.

Thanks, Jess, and good morning, everybody.

Two questions if I could.

The first one, just to come back to the acquisitions and perhaps if you could give us the average return on those, when you talk about them adding value, that we could have a look at.

But just within that and just going back to something Brian said on the -- once the rebalancing is achieved, then you'll look to offset the dilution from the scrip I think at the first opportunity.

What confidence can you give us that in a year's time that we're not sat here thinking that it's going to be delayed for another year because there's been other attractive options that have come into the portfolio that you want to take advantage of?

And then the second one was actually just back on the cost question that Guy asked.

Are you actually looking at whether you can do more into 2017 on the cost targets that you've given or is it just a case of, given the oil price increase, that we're basically looking at locking that into the year?

Thanks.

Well, Lydia, on the acquisitions, we've obviously been competitive in our capital ranking process.

And Abu Dhabi, I shouldn't actually say the terms are different than they were, but Abu Dhabi themselves and ADNOC themselves are still negotiating with potential people to join the partnership.

So I shouldn't comment on that.

Certainly with Tangguh it's just straight bolt-on to a project that we know is healthy and economic.

The same with Zohr.

The economics of that project we think are good with lots of optionality.

And there's lots of optionality in all three of these projects that I mentioned.

And again, the Woolworths' deal, if approved, will be accretive as well.

So these were -- and the extension, which the commercial terms were worked out before the holidays in Azerbaijan, are certainly very economic and healthy with our returns as, again, they're just an addition onto what we're already doing.

So I think that's probably all I should say about the specific economics of the projects.

Yes, and on the cost front, Lydia, actually if you go back to the high-water mark we talked about, 2012, our cash cost base has reduced by about 50%, which is quite significant from where we were back at 2012.

So that's an important data point.

I think what you will now start to see going forward is our unit efficiency operating cost start to improve.

So we'll look to hold cost flat here, notwithstanding the earlier comment about, in the upstream, 75% of the costs we believe are sustainable, 25% will be exposed to inflation.

So we'll look to hold the unit -- the absolute costs flat where they are, even though we have a huge amount of projects coming on with investment, both in upstream and downstream.

So we've got -- there's a natural increasing cost pressure in the system and inflation that we'll look to hold flat.

And what you'll start to see is our unit operating costs and those unit metrics, in terms of the operations, in terms of upstream, it'll be around operating costs and production costs.

And in terms of downstream, it'll be the amount of costs that are going into generating margin, which is the way that really the marketing businesses look at this in terms of costs over a gross margin measure.

Okay.

Thanks, Lydia.

Next question from Rob West of Redburn.

Are you there, Rob?

I'm here, yes.

Thanks very much.

I guess the first question I'd like to ask is on CapEx.

Brian and Bob, to the extent that you have the breakdown at a more project level than the headline level you've given us, are there any projects you know about within your split where there's been a significant change versus how you see it now versus how you would have seen it maybe six months ago or when we were all in Baku?

Within that, I'd like to ask about Oman specifically.

I think Guy asked you about the drilling productivity improvements in the US, and I know Oman is another area of unconventional drilling activity.

And I was wondering, those recent wells that have come in just over the last three to six months, how are they comparing on a drilling productivity basis versus where you would have seen them?

And then the final one I wanted to ask you is just on the downstream business and contango impact there.

So, a year ago it was maybe $10 a barrel per year, looking at the contango.

And I think I remember back to 2015 you talked about filling your boots in that contango-ed environment.

Is there any change in that business now that we're at a more flattened, forward curve, either in terms of inventories coming out or in terms of maybe profitability booked on the contango that we should be aware of maybe not recurring?

If you could talk about that a little bit, that would be interesting to me.

Thanks.

Rob, yes, good questions.

I'll take the first one and then Brian on the contango and he can explain that technical term, filling your boots, for all of us.

I think on the CapEx, we've continued to see, with projects that are even in midstream now, with the costs coming down.

The Shah Deniz project, the one that's working its way in the pipelines across Turkey, the steel costs have come down significantly in that.

The Mad Dog sanctioning, the one where it went from $20 billion down to $9 billion, it gives you some idea of the reduction, both in scope.

We re-engineer these things, take a fresh look at it and look at how we would do it, and that took a lot out of the scope.

And then of course drilling costs have come down significantly.

The Thunder Horse South expansion that just came on stream near the end of December, again, 10% under budget is probably $150 million savings and 11 months earlier.

So things are happening faster.

They're happening at lower cost.

So there isn't a project out there that I would say we're worried about.

The ones that'll come on stream this year have been moving along the West Nile Delta, the big, big project in Egypt.

We have 83% of that.

That's also -- the drilling is much reduced cost and much faster.

So that project, hopefully, will come on early rather than the summer or the fall, which we'd originally planned on.

On Oman, we've got a number of breakthroughs there in the southern part of Oman and we've signed an agreement that will expand the acreage there by another 50%.

We're getting well rates out of there that are even straight wells that we had not expected that I think are going to lead us to be able to do the original project and the 50% expansion for around the same price as the original FID for the first phase.

We're using new techniques and new data so that every time a well is drilled we automatically rework the entire development plan to optimize where the next well moves to, things that were never actually seen in our history before in terms of being able to use new technology.

We've got 45 development wells drilled to date and they're completed, and definitely potential production levels above plan.

And the liquid production levels that we're testing are higher than planned.

So we like that project a lot, so keep an eye on that.

That'll be on stream before the end of the year.

I don't know if that helps, Rob.

Yes, that does.

Thanks.

And then, Rob, on the question around contango, I'm fairly confident fill your boots never came off this call, but it may be some other company you've been dealing with, unless it was a very private session.

It's been a long time since I last used that phrase, probably about 20 years ago when I was on the trading floor.

No.

We have -- actually we don't let -- and our trading floor would let you know this.

We actually keep quite a discipline on the amount of oil that we would use in contango plays, when those opportunities arise.

And I will give you another phrase, which is flat as a pancake, which is exactly where the Brent market is right now.

So I don't think there's much carry that we see in Brent, certainly not on a [CAL] basis, if you look at the forward curve right now.

There is some carry in gasoline and I think we'll always allow our traders to take advantage of that when that arises in terms of using the storage facilities we have and the working capital that we can deploy towards that activity.

But we do actually limit it and we do have a very strict resource allocation group within trading that looks to allocate the scarce working capital we allow in terms of that activity to make sure that we're getting the highest returns in the ones that we look at.

There are some people that'd be comfortable investing in cost of capital.

We'd look to want to get significant returns way above cost of capital before we'd look to deploy our working capital into that sort of space.

So we will do contango when it arises.

Right now, the only opportunity you can see are in gasoline and we have some of those positions on for this year.

But right now in crude there's really nothing there.

All right then.

Sorry for the false attribution of that comment.

No.

I think I know where it came from, but you need to talk to somebody else.

Don't worry, Rob.

I don't think your memory's that bad.

Okay.

Moving on now to [Christian Manock] of JPMorgan.

Hi.

Thanks, Jess, and thanks for taking my questions.

Good morning.

Just two questions, starting with oil prices.

You talked -- you were justifiably bearish early last year and that reflected itself in terms of discipline around CapEx.

What is your view at this point?

OPEC's done a deal and therefore you're more constructive, but I can't help associating that move high in oil prices with how you've done more deals.

And so the first question, if oil price was still in its $40s, would you have done those deals?

The second question links back to strategy around CapEx versus cash flow.

Can you just remind us as to what exactly is the priority around cash flow breakeven?

If that was the true priority, as much as it's tempting to do deals that are accretive and deliver long-term production, wouldn't you have resisted to get that cash flow breakeven lower, particularly given oil is so volatile.

Just two questions, please.

Can I just --?

Sorry, Bob.

No, go ahead.

No, can I just pick up the frontend of the question?

I think if the oil prices stayed at $40, would we looked to have done this?

I think, if you go back to one of the earlier questions, it was the confidence we have was that we could get back to breakeven at $55.

And I think while we said lower for longer two years ago, I think my partner here said lower for longer, but not forever a year ago.

And I think, structurally, we can start to see the overhang in the crude supplies start to work their way through this year.

It's taken longer than was anticipated because I think actually some of the supply last year wasn't anticipated that came on, particularly Libya coming back in terms of production there.

So I think if the oil price had stayed at $40 -- you have to remember a lot of the transactions we looked at are either low-cost oil and therefore are good for the long term in terms of strategy, or gas, in terms of those transactions that you saw at the backend of last year.

So even at $40 a barrel they would definitely be within the suite of options that we might have looked at.

Yes.

Let me just add to that.

That's exactly right.

Tangguh, gas prices, generally fixed.

Zohr, gas prices are fixed.

The -- Mauritania is just such a large, low-cost gas source there.

Low-cost oil, Abu Dhabi, that one, I'm not sure.

But it was the flexibility of ADNOC and the government of Abu Dhabi to take our shares that made that one different.

I think it's -- I think, as I've said to them, we would not have done that deal even last year if that had required the cash.

So I think that had some characteristics, flexibility and some creativity around it.

But we certainly would have been -- you're right, Christian.

We would have been nervous at $40.

We would have continued to think very, very carefully about all of these deals here.

On what our view is on OPEC, all of us in the Company travel a lot.

We spend time in various countries.

We do talk to the views of various ministers.

Obviously we operate in Russia and Azerbaijan, which are part of the non-OPEC producers of these agreements.

And I have to say that the confidence and the steely resolve that they speak about is reflected in country after country after country.

So we'll see.

There's risk to it, but it does feel like this is holding with resolve by these many countries.

If I could just follow up, not to wish low oil prices on anybody, but if we do go back into the mid-$40s, is it safe to say that you would be willing to lower your CapEx or is $16 billion a hard floor?

No, no, no.

We would absolutely lower the CapEx and we would probably re-pace things.

Some of the economics of projects would change.

The big ones that we're halfway across the stream on we'd obviously continue to go forward with.

We would look at all the discretionary base and wedge drilling activities, so you have to make sure that the returns, which are generally very high on those, happen.

But you would see us slow down some of the FIDs I'm sure.

Right.

Thank you very much.

Moving on now to Chris Copeland of Bank of America.

Thank you, Jess.

Good morning, everyone.

Just two questions, the first one on CapEx.

Could you comment a little bit about your new CapEx commitments on the back of acquisitions, whether it's Zohr or whether it's ADCO, et cetera?

Should we think about that as displacing previously unsanctioned projects in your resource base or is that one reason why you've gone to the higher end and slightly upgraded your 2017 CapEx number?

And the second question is really asking you for a little bit more detail about your cash flow outlook.

You previously gave us more or less the same CapEx guidance, the same Henry Hub guidance, refining margin guidance, and guided us to a 2017 breakeven of $50 to $55.

Now it's $60.

So I just wondered whether you could let us know a little bit more in detail where those I guess $1.5 billion, $2 billion have gone.

Thank you.

Actually, Chris, it's the same answer to both questions.

If you remember at the end of Q3 we talked about CapEx -- on the Q&A session we talked about CapEx in the range of $15 billion to $17 billion.

But for next year, this year, at $50 to $55, we were guiding our CapEx in the range at the lower end of that range, so somewhere around $15 billion, $15.5 billion.

The new acquisitions and projects have brought with them an additional $1 billion.

Hence why I say assume CapEx of around $16 billion or just north of $16 billion for this year.

That's the $1 billion.

And that $1 billion actually bridges you from $55 to $60 a barrel on a post-tax basis in terms of rebalancing.

So it's $1 billion out in terms of organic balancing for this year.

Hence, $55 to $60.

Great.

Thank you, Brian.

Thanks, Chris.

Irene Himona of Soc Gen.

Go ahead, Irene.

Thank you.

Good morning.

I had two questions, and apologies if they have been discussed before.

Firstly, on the downstream, where for the full year your lubricants' profit is up 10%.

Chemicals is up 2.5 times.

And together, those two sub-divisions generated about three times more than your upstream, but a lot of the cash cost reduction has been delivered in the downstream businesses.

So I wonder how we should be thinking about further upside on these businesses from here on, if there's any guidance.

And then secondly, on the upstream and the 500,000-barrel-a-day startups by year end, your own organic growth, obviously these don't ramp up immediately to plateau and initially costs will be higher to start with.

And there is a risk of initially perhaps overestimating the cash contribution of the organic growth.

Is there any guidance you can give us on how we should think about the, let's say, cash contribution of those 500,000 barrels in the first year of production in 2018?

Thank you.

So, Irene, if I just take the downstream question, I think it's also worth pointing out that, just on the straight rules of thumb, the environmental impact that (inaudible) and the team had to deal with last year was about $2 billion around the (inaudible) margin, margin, and actually bigger than that if you build in the local margin differences.

So actually it's quite significant, and hence why it was important that extra value was generated elsewhere inside the business, both in terms of actually fuels as well as lubricants, as well as chemicals.

I think outlook for lubes, it was a record year last year for them.

Whether they can repeat that this year, but I think you should assume flat to growth going forward for lubricants.

On chemicals, we've come out of, and still not fully out of, what has been a three to four-year very suppressed period for our chemical margins in terms of that activity.

You may see some recovery this year, but we're not assuming there's any major uptick in chemicals through this year.

And I think what you'll see in terms of downstream is a continued focus on efficiency.

It's where the costs go in terms of generating margin, and fuels' growth, where we've seen significant fuels' growth across the piece.

And, Irene, I think on the upstream projects, the biggest indicators rather than -- I think it's more you've got to see us bring these projects on for us to be able to prove what we've been saying.

We do have these six more, seven if you count the one that started in December at Thunder Horse.

I would gage whether they're on time or ahead of schedule or on budget or under budget.

The Thunder Horse South one certainly has come on like that.

I think keep it on your radar screens over the next three or four months.

The West Nile Delta project towards Libra coming on, and Quad 204.

These are probably the first two that will come on, large projects.

All of these, you're right, are a ramp up to 500,000 barrels a day and so it doesn't happen overnight.

It's 500,000 barrels of capacity that will be put in place and of course then we'll continue to drill and drill out some of these well into 2018.

But I think it's -- are we bringing projects on time and under budget.

And I'd just ask you to wait and we'll go into a little bit more detail on this in -- on February 28.

Okay.

Thank you.

Thanks, Irene.

Turning now to [Birej Orkataria] of RBC.

Hi.

Thanks for taking my questions.

Just going back to Macondo, you mentioned the drivers for the increase in guidance was more to do with phasing.

But the 2016 number is -- was higher than the top end of guidance, the 2017 number has increased, and 2018 and 2019 are unchanged.

So I'm wondering, is this really a phasing issue, or are the payments just higher than you were expecting maybe six months ago?

And the second question is, just could you clarify the scrip uptake assumption in that $60 per barrel breakeven target?

It looks like the 2016 uptake was a bit higher than it has been over the previous few years, so just clarity on that will be good.

On the last one, the last question's straight -- well, they're both pretty straightforward, actually, but the last question is we've assumed 20% is the longer average on the scrip uptake.

Last year it was significantly higher and above that, but in terms of our cash balancing we're assuming about a 20% uptake on scrip.

And then in terms of Macondo, you're right to point out that actually the payments are higher in 4Q than anticipated for this year because what has happened is if you look at where we last reassessed the -- each quarter we look at the overall provision.

At 2Q we had about 34,000 BEL claims to still be processed.

We're now down to 9,000, so of course, we've got two quarters worth of BEL claims have now been processed.

Some of those have come through at higher rates, hence why we've re-evaluated the provision, but we're now in a more confident position than we would have been.

And given that we're down to 9,000 claims left, hence why the provision has come up.

So it's a combination of both.

One, the provision's moved up and it's about $625 million around the claims piece for this quarter.

And then we have the forward view in terms of now we're down to the last 9,000, having accelerated 15,000 claims through the fourth quarter.

Puts us in a better position in terms of assessing what the provision looks like, going forward.

Very clear.

Thanks.

Thanks Birej.

And turning now to Brendan Warn of BMO.

Go ahead, Brendan.

Yes, thanks, Jess.

Look, a lot of questions have been asked and answered, but I'll just follow up, and just in terms of any expectations for FIDs or sanctions this year?

Just referring to your Baku trip.

You talked about 40-odd projects in work.

Just any thoughts on what we may see this year, or is it another year of hiatus for FIDs from BP?

Yes, we generally don't lay out the FIDs directly, because we have to do it sometimes with our partners.

I mean, we've had five FIDs in 2016, which I'll -- those were the Atoll phase 1 project in Egypt, which is an early production scheme.

It's 100% BP.

The Tango expansion project, which we're not up to 40% in, has been FID.

We FIDed a Trinidad onshore compression, which will drive higher production in Trinidad into the LNG plants.

That's another 100% one.

You've read about the Mad Dog phase 2 one.

We've FIDed it and we've got partners Chevron and BHP that are looking at it now.

So those -- and another operated by others in the Gulf of Mexico.

It was previously called Hopkins, it's now Constellation.

We've got a 67%.

So those are done.

We have deferred a couple of FIDs.

We have deferred one in Australia, a big LNG project, and another one in Canada that we think that's the right thing to do for both strategy and where the estimates are.

And then, I think keep an eye on us with some other things that we may do in Trinidad.

In Oman, as I mentioned earlier, there's more potential there.

India, with the new gas price there, we have some very, very good-looking prospects there as well.

And there's a couple of others that are rather operated by others, so I think I'd rather wait before I mention those.

But those are some, and yes, we've got a pipeline of things out there as well.

There are some other higher -- lower probability ones on the list as well, but not worth mentioning yet.

And just in follow-up, just can you talk about the base declines?

You were talking that you're keeping that above your -- or better than your target rate of 3% to 5%.

When can we see -- start to see the impact of lower maintenance CapEx coming through on the base decline, please?

Well, we've got our base decline at around 3% now.

We've held that for some time, versus the historical average 3%, 3% to 5%.

So, you'll see that coming through, in one, the reliability numbers in the plant and the upstream are now up to 95%.

You'll see that in lower turnarounds.

I know the question was asked earlier.

We had 11 turnarounds in the upstream last year.

I think we'll probably have about five this year.

So you should see it all around in small pieces everywhere.

Yes, thanks for that.

Thanks, Brendan.

Next question from Jason Gammel of Jefferies.

Thanks very much, everyone.

I actually had two questions.

The first one, coming back to Abu Dhabi, I was hoping you might be able to address your desire to use equity in that particular transaction.

I recognize the long-dated nature of the asset, but your equity is relatively expensive right now, given the dividend yield.

And Brian also mentioned that it was a cash flow accretive project.

Can you confirm that that's the case on a per share basis and also covers the incremental dividend payment?

And the second question I had was on the potential for a US border tax adjustment.

Have you given any preliminary -- do you have any preliminary comments on what that can mean for your refining business, given the heavy [slated] Canadian crude that you use a lot in.

I'll take the first part of that question while Bob thinks about import in the US.

It's -- Abu Dhabi was a -- yes, it was really straightforward, I think, and I think most of our investors -- the majority of our investors, if not all of them, came back to us very positive about it, which was -- it's immediately cash accretive.

The cash that comes from it covers the dividend for the shares that were an issue.

And it's earnings accretive.

So I think this was a good use of equity.

And was unique.

And of course the sovereign country wanted access to BP shares.

I mean, that was part of this whole transaction was their desire to actually own.

And we've been talking to them over a number of years about the potential for them stepping into a position in BP.

This was just the perfect opportunity that came together in a relatively small window, to allow us to actually go forward on the renewal of that license.

Yes, and I think I'm really happy about that transaction, Jason, with the supply there, working with Abu Dhabi and crude supplies and the implications it has on our trading organization out to 2055.

Those don't happen very often.

On the border tax, well, I was watching -- you asked about Canada specifically, but there's also issues around Mexico and just imports and exports in general.

And I'm going to take the position of the Canadian government, because I watched and listened to them last night, and they more or less just said, hmm, we're going to scratch our heads and we're going to think about what this means, and not comment.

And I think I should probably do the same thing.

Fair enough.

Thanks, Jason.

And we'll take the last question from Lucas Herrmann.

Are you there, Lucas?

Yes, Jess, thank you very much.

Gentlemen, good morning.

Just some points of clarity, if I could.

Firstly, Brian, just going back to the answer you gave -- I think it was to Theepan around balance or Oswald around balance.

And you mentioned price driving an improvement in cash flow of an estimated $4 billion this year.

I assume that's the movement in refining marker back to your average level, gas prices to your average level and as well as oil prices to your average level.

Lucas, let me pick that one up straight away.

Actually, the hit in 2017 -- in 2016 versus 2015 was close to $8 billion of environmental impacts across the two.

You can get to about $5.5 billion of that through the rules of thumb.

There's also about $2.5 billion from non-rule of thumb type activities, like non-Henry Hub gas.

So, in terms of the assumption for this year, it's a modest improvement to refining margins, certainly not back to the long run average that we've been assuming previously.

It's a modest improvement in the Henry Hub gas price.

And its oil price is around close to $55 a barrel.

Okay.

And Brian, can we just go back to the sensitivity comment you made as well?

Same thing, really.

$3.4 billion move, I think you said, for a $10 move in the price.

Then you talk about a marginal rate of tax of 10% to 20%, which seems remarkably low on incremental price driven cash flow.

Not when -- well, actually, if you go back and look at the size of our portfolio and the mix of upstream and downstream on the corporate tax rate, actually it's not that low.

If you look at the cash tax rate for those upstream barrels, it is lower than the corporate tax rate.

Okay.

And sorry, final point of clarity, just to be absolutely clear, ADCO, the operating cash contribution that you expect in 2017 from that concession will outweigh the capital spend.

And the reason I ask, simply is that -- I appreciate the CapEx goes up as you take things on.

I just -- ADCO looks as though it should be a decent contributor, though.

It's hard to see quite where the negative $1 billion overall is coming from.

Oh, well, you've got the CapEx that needs to go into Zohr this year.

You have the CapEx that will go into Mauritania and Senegal.

You've got some CapEx going into Abu Dhabi.

The cash coming out of Abu Dhabi more than covers the dividend associated with the shares that are put into issue.

So no, Abu Dhabi's cash --

And the CapEx Brian?

I'd need to come back and look at the free cash flow figure.

I haven't actually got the CapEx to hand, but it will be pretty close, if not accretive.

Okay.

All right.

That's great.

Thank you.

Thanks, Lucas.

We do have a question on the web from Jason Kenney.

Jason is asking about returns to the end of the decade.

Jason, we are going to talk at some length to returns on February 28, so if you don't mind, I think we'll hold that question until then, unless -- oh, no but Brian's looking at me and he says he really wants to comment.

No, we should never duck a question, Jess.

I think I can even remember the fill your boots quote now as well.

That's just suddenly come back.

Oh, spoil my -- our presentation for the 28th.

All I would say, Jason -- Jason's raised this point about where do you see ROACE?

It's on the web, but for BP for end 2017, and also at the end of the decade, and can you get ROACE ahead of your weighted average cost of capital in the next two years?

I'll pick up the latter part of that question.

I mean, you'll know the history.

You know that we sold of $55 billion of assets.

The average returns of those assets was in excess of 50%, post tax.

And therefore -- and we've gone through the massive period of oil price adjustments, so we have a lot of capital that was laid in at $100 a barrel -- it now needs to work its way through the system and our returns are down below weighted average cost of capital.

We would be disappointed if we can't get our returns back up in the next 12 months to two years, back up above the weighted average cost of capital for the corporation.

And this is also a big focus for the Board, in terms of the long-term plans.

And so I just segue what Jess will lay out for us at the end of February, to say, we'd be disappointed not to get there in the next 12 months to two years.

We would expect to be above the weighted average cost of capital by this time next year.

And then we'll be able to show you the trajectory of what returns look like, going forward, in terms of getting us back to where we should be, in terms of where we were historically over the last 50 years or 60 years.

Sorry, Jess.

No, that's great.

Thank you Brian.

And thank you, everybody.

Bob, do you have any closing remarks?

I'll just keep it very brief.

First, a big thank you very much to everyone.

Very good questions, as always.

A few thoughts, again.

You're going to see us focusing on safety and reliability that makes our assets run more reliably, which creates the reliable cash flows from the Company.

Again, big focus right there.

And then, as Brian laid out, rebasing our capital and cash spending, going forward rebalancing the Company.

We have a good sense of confidence about doing that, not only from our existing assets, but the new things that are coming on.

Keep an eye on these projects that are coming on.

And then, just remembering, for the long term, it really is our primary objective to remain to grow our sustainable free cash flow distributions to you all, our shareholders.

And we look forward to seeing you on February 28.

Thank you very much.