康菲 (COP) 2009 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2009 ConocoPhillips earnings conference call.

At this time, all participants are in listen-only mode.

We will conduct a question-and-answer session towards the end of this conference, at which time you may participate (Operator Instructions).

I would now like to turn the call over to Mr.

Clayton Reasor, Vice President of Corporate Affairs.

Please proceed, sir.

Thanks, Antoine.

Good morning, and welcome to ConocoPhillips' fourth-quarter 2009 earnings conference call.

Today, I will be focusing on the Company's results for the quarter, using material you can find on the web.

And during the presentation, I will refer to adjusted earnings, which are -- reconciliation to adjusted earnings can be found in the appendix of our presentation material.

Before we get started, I would like to refer you to our Safe Harbor statement, which is on page two, which is a reminder that I will be making forward-looking statements as part of the presentation and the Q&A and that actual results may be materially different.

So I'm going to move to slide three, which provides a summary of our fourth-quarter results and business highlights.

Adjusted earnings for the quarter were $1.7 billion, or $1.16 per share, generating cash from operations of $5.1 billion.

We ended the quarter with debt of $28.7 billion, resulting in debt-to-cap ratio of 31%, down 2% versus last quarter.

Total production, including our 20% share of LUKOIL, was 2.26 million BOE per day in the fourth quarter.

It was a challenging period for R&M, with an overall loss in net income, driven by depressed refining margins, which were particularly low in the US.

Global refining utilization was only 76%, reflecting economic run cuts made in this difficult environment, as well as increased turnaround activity.

On the cost side, we achieved a normalized full-year reduction of 12%, or around $1.7 billion pretax for the year.

This compares to our original target of $1.4 billion.

And I will provide more detail on the sources of these cost reductions later in the presentation.

During the quarter, we recognized non-cash asset impairments of almost $575 million after-tax, primarily related to the impairment of our equity stake in Naryanmarneftegaz joint venture in Russia and mature Western Canada gas properties, as well as miscellaneous impairments in our E&P and R&M segments.

At Naryanmarneftegaz, equity accounting rules for impairment testing resulted in a writedown for this quarter.

While the current producing field, YK, has met our expectations, our view of probable resources has declined as a result of additional data and drilling activities around some of the flank areas of the reservoir.

In Western Canada, the impaired properties were impacted in varying degrees by a combination of lower prices, royalty rate increases, the strengthening of the Canadian relative to the US dollar and operating performance.

These Canadian impairments represent a small portion of our total capital employed in that region.

Turning now to slide four, you can see total adjusted earnings for the fourth quarter were up sequentially, but down by about 10% compared to last year.

This slide shows changes by segment.

Our E&P business increased earnings by more than 20%, due primarily to the improvement in oil price, which more than offset lower gas prices.

As I mentioned, R&M had a loss for the quarter due to significantly lower realized margins and utilization rates.

LUKOIL adjusted earnings were higher in the fourth quarter of 2008, reflecting -- or higher than the fourth quarter of 2008, reflecting our estimate of fourth-quarter 2009 results.

Slide five shows the progress we've made on reducing controllable cost.

We started 2009 with a goal of reducing cost by 10% or $1.4 billion.

For the full year, we achieved nearly $2 billion all-in savings.

And if you exclude one-time severance accruals, the normalized reduction was around $1.7 billion.

Nearly 40% of these savings were related to base operational expenditures, while the remainder resulted from market factors such as currency movements and lower utility costs.

We also saw significant savings in the equity affiliate operations, such as CPChem and DCP, which are not included in this amount.

Slide six outlines our cash flow performance.

In the fourth quarter, we generated $5.1 billion from cash from operations.

We have capital spend of $3.1 billion and dividends of $750 million.

Total debt was reduced by $1.8 billion.

Our 2009 full-year cash flow detail is shown on the pie charts on slide seven.

As you can see on the left, we generated $12.5 billion in cash from operations.

Asset sales, including the disposition of our interest in Keystone Pipeline, along with other changes provided $1.1 billion of additional cash.

The uses of cash are provided on the right-hand side of the slide and show our 2009 capital program of $12 billion, which was slightly below plan due to the timing of expenditures on major projects.

Our dividends were $2.8 billion, which included the quarterly increase we announced in October.

As a result, total debt increased $1.2 billion for the year.

Slide eight shows the history of our debt-to-cap ratio over the last several quarters versus our target of 20% to 25%.

As you can see, while we are currently above our goal, we've made progress at reducing debt-to-cap this year.

And as we go forward, we expect the proceeds from our two-year, $10 billion asset disposal program and cash flow from operations to move us back within our targeted range.

Now I would like to take a couple minutes to review our segment performance, starting with total Company production for the fourth quarter you can find on slide nine.

Overall E&P production was down 2%, or 39,000 BOE a day, versus the fourth quarter of 2008.

Market factors decreased production by 16,000 BOE a day, reflecting reduced gas production in North America, driven by economic conditions, as well as PSC-related, price-related reductions and international OPEC curtailments.

As we discussed in our third-quarter conference call, voluntary gas curtailments began in late August and continued into the fourth quarter.

And during the fourth quarter, total curtailment was around 145 million cubic feet per day.

Moving to the right side of the slide, you can see that changes to the portfolio reduced production by 12,000 BOE per day, primarily reflecting the sale of our Netherlands assets and expropriation of our interests in Ecuador.

These declines were partially offset by a benefit from improved volumes due to the absence of hurricane impacts in 2009.

In the operations category, we saw significant benefit from new production, but was not able to offset normal field decline.

Although the fourth quarter was down compared to last year, our full-year production was up around 3% to 1.85 million BOE per day versus the 1.79 million in 2008, as shown on slide 10.

Excluding market-related improvements of 17,000 BOE per day, we were up over 2%.

This was driven by nearly 140,000 BOE per day of production from new major projects and oilsands expansions.

We were also helped by strong operational -- we had a strong operational year and had lower impacts from external events, such as hurricanes.

So now turning to slide 11, you can see total E&P adjusted earnings for the fourth quarter were $1.7 billion, up from $1.4 billion last year.

The main drivers of the improvement were higher oil prices and lower operating costs, which more than offset lower gas prices, sales volumes and other costs.

You can see that on the right-hand side of the table at the bottom of the slide, our realized oil and NGL prices went up by 36% compared to last year, while global realized gas prices decreased by about 25%.

Although North America gas prices were challenged for the majority of the year, our fourth-quarter performance in lower 48 benefited from somewhat better gas prices and continued cost reduction programs.

The chart shows a breakdown of the major variances.

In total, prices and other factors, such as production taxes, increased earnings by $500 million.

Lower sales volumes decreased earnings by about $160 million.

This decrease reflects lower gas sales, due in part to voluntary reductions, which were partially offset by higher liquid sales.

Operating costs were improved by a little less than $100 million after-tax.

Unlike previous quarters, when market factors comprised the majority of savings, cost reductions this quarter relate to underlying operations, as market factors worked against us.

The other bar primarily reflects foreign-currency loss compared to a gain last year, and we also had higher DD&A expense this quarter due to project startups and some specific field dismantlement accruals.

The R&M adjusted earnings variance is shown on slide 12.

R&M lost money during the quarter, driven by low global refining margins and compressed crude differentials.

As shown on the table at the bottom of the slide, US adjusted earnings fell by nearly $700 million, due in large part to a nearly 60% decline in integrated margins.

Although the US refining 3-2-1 crack spread was virtually unchanged versus the fourth quarter of 2008, our realized margins decreased significantly, and this was caused by several key factors.

First, light/heavy and sweet/sour crude differentials were significantly lower this quarter compared to last year.

Our US refineries are configured to run around 55% advantage crudes, such as WTS, Canadian sour and South American heavies.

On these advantaged crude, every dollar decrease in differential creates between $15 million and $20 million decrease in quarterly earnings.

And compared to last year's quarter, the Maya differentials decreased by nearly $7.00 a barrel.

We also saw negative impacts from the decrease in distillate spreads.

Although the market 3-2-1 crack spread was flat, distillate margins decreased by over $11 a barrel, while gasoline spreads increased.

Because our production and configuration is more biased toward diesel, with an average yield in the mid to high 30% range, we were adversely impacted by the distillate spread.

The third source of year-over-year earnings decline not reflected in the 3-2-1 market crack is the impact of higher crude prices on secondary product margins.

We sell certain refined products on a fixed-price basis, which makes their margins vulnerable to crude costs moving quickly higher.

On the international side, the variance is more straightforward.

The table shows that international earnings fell by 70%, and that is generally consistent with the international refining 3-1-2 spread decrease.

In total, global realized margins reduced earnings by more than $800 million, as shown on the graph.

Utilization rates and sales volumes were also down, caused primarily by economically-driven run cuts.

Lower operating costs did help adjusted earnings by about $50 million, despite the higher turnaround activity.

And all other impacts, such as currency movements, decreased adjusted earnings by about $30 million.

I will now move to slide 13, which shows the variances for all of the segments.

In Midstream, we experienced higher results due to higher NGL prices.

Compared to last year, index price for DCP were up around 40%.

And our share of CPChem results were $60 million higher due to improved specialties, aromatics and styrenics margins and lower controllable costs, partly offset by lower olefins and polyolefin margins.

Earnings from our Emerging Businesses segment decreased primarily due to lower spark spreads in international power.

LUKOIL earnings were $388 million for the quarter compared to an adjusted value of zero for the fourth quarter of 2008.

Corporate expenses were in line at $311 million after-tax for the quarter compared to $354 million of adjusted expenses last year.

This decrease is due to the absence of foreign currency losses and lower staff costs, partially offset by higher net interest expense.

So that completes my review of our fourth-quarter results.

I will wrap up with some summary comments on slide 14.

We performed well in 2009 despite difficult global economic conditions that severely impacted the energy industry.

In 2009, we initially expected our E&P production to be flat versus 2008.

Excluding market factors, we delivered slightly more than 2% growth, driven by improvements in operating efficiency and lack of any external events, such as hurricanes.

Looking at 2010, we expect to return to the more normalized production we achieved in 2008, in large part to having a full-year impact of reduced North America drilling, as well as lower production growth from new projects.

While we do have a good portfolio of major projects, such as QG3, Canadian Oil, Jasmine, Gumusut and others, they will contribute growth as these developments are continued, but we do plan to reduce our capital spending in some of our more mature assets, which are significant contributors to near-term production.

We are intentionally reducing our spending levels in support of our stated effort to improve our return on capital employed and increase our per-barrel cash flow and earnings in our upstream business.

In addition to delivering production results, improving safety performance and having a good environmental stewardship year, we took steps to reduce our cost structure through capturing market opportunities and driving reductions in our underlying business.

While we can't predict how market factors such as currency and utilities will impact us in 2010, we are committed to holding on to the operational savings we achieved this year from procurement initiatives, controllable cost reductions and portfolio changes.

In 2009, we also began to see results from our commitment to exploration, with discoveries in the Browse Basin of Australia and lower tertiary trend in the Gulf of Mexico.

We also added several prospects in some exciting new areas.

And spending on exploration will remain relatively flat in order to strengthen our portfolio for future organic reserve replacement.

Late in the year, we announced plans to enhance returns and strengthen our financial position.

Consistent with these objectives, we announced our 2010 capital budget of $11.2 billion and initiated our asset disposition plans.

We've started the sales process for our Syncrude interest, and are seeing quite a bit of interest on this asset.

And we've identified other targets and are very confident we'll reach our $10 billion target over the next two years.

Finally, we are taking appropriate steps to manage our downstream business in the face of prolonged margin pressure.

We do not expect the magnitude of losses to continue in this business, given the specific actions we are taking.

Our strategy is constant and starts with operating excellence; we must run safely and reliably.

Next, we focus on controlling our costs, and we have a good track record in this area.

In addition to running well and keeping costs in check, we focus on optimizing the plants and capturing the highest margin available on any given day.

This not only includes making economic run reductions, as we did in the fourth quarter, but also changing operations in response to market movements.

Lastly, we have adjusted our capital plans for this business with the objective of ensuring that it is cash positive.

You can see this in the deferral of the upgrade project at Wilhelmshaven and the reduction of discretionary capital.

Through all these steps, we feel confident in our ability to manage through this challenging environment.

So Antoine, that concludes my prepared remarks, and now I will open the call for your questions.

(Operator Instructions) Paul Sankey, Deutsche Bank.

Hi, Clayton.

You've talked about upgrading the portfolio and general actions over the course of the year.

Can you just give us some more detail on any more specific progress, how we will be looking by the Analyst Meeting on March 24, for example?

Any further comments on LUKOIL and so on?

Thanks.

Okay.

So I guess the questions that are out there are around status on the asset sale program.

And when we announced this in the fourth quarter, we said it was a two-year program, because we knew it was going to take a little bit of time to get the level of interest that we wanted in certain assets and define where we wanted to invest and also measure the market response.

So -- and nothing has really changed -- or I can't give you any more color on the assets as far as where we are with the bottom 10% of our North American assets or Syncrude or the REX Pipeline or the southern North Sea.

So those are all still being worked.

I can say we don't have any reason to believe we are not going to be able to generate the $10 billion that we've stated.

As far as LUKOIL, again, I can't really say anything that -- but repeat what Jim had said, which was we've got a really good relationship with LUKOIL and the Russian authorities.

We recognize what has taken place there, and we are aware of the situation.

And it's really appropriate -- the comment that we would like to make, is we just intend to maintain the strategic relationship we have with LUKOIL.

And I don't know if there was anything else that you wanted to ask.

Yes, you generated enough cash to pay down debt this past Q4.

Assuming -- given what you said about the expected disposal proceeds being in line with what you had previously thought, what would be the next phase for the additional cash that is implicit, beyond what you want to do in terms of paying down debt?

Some of this is going to depend upon what the market does.

But when we see this free cash flow coming, you think about $10 billion of asset sales, and you think about some of the other things we are considering, you think about free cash flow, we certainly would like to have annual dividend increases.

And we want to keep our CapEx at the $11 billion range; maybe a couple hundred million higher, but not much more.

We don't see it going back up into the $13 billion or $14 billion range.

But once we get our debt down, cover the $11 billion or so CapEx, raise our dividends, I think we've got to consider share repurchase.

I've got you.

And then finally for me, Clayton, I didn't quite understand what you said about volumes for the year.

Did you say that '08 was normalized, in which case, what would you call the normalized number for '08?

Because we have got it sort of down quite sharply basically '08 over '07.

Okay.

So what we had -- when we started the year 2009, the guidance we were providing, we were going to stay flat over the next couple of years from that level.

And so that is -- the guidance we are really giving for 2010 is going to be in line with 2008 volumes.

Okay.

I understand.

All right, I'll leave it there.

Thanks a lot.

Doug Terreson, ISI.

Good morning, Clayton.

I have a question on E&P, as well.

Your production rose by a full 4% in 2009, and that is obviously impressive for a company your size, and it's higher than I think the Company thought a year ago.

And so the press release talks about reliability in PSCs in some of the regions that drove the performance.

But it appears that they were broad-based.

So my question is whether or not there are strategies or processes that you guys have in place that are leading to this positive performance ahead of expectations.

That is, is there a common theme amongst the commentary that you made in the press release today that are driving these positive results in E&P?

And if so, if you could just comment on what they might be, it would be appreciated.

Okay, so I guess, Doug, are you looking at fourth quarter versus fourth quarter or year on year?

Full-year.

Full-year.

So I guess there is the up -- we ran very well in 2009.

Our uptime and reliability was higher.

I think the things that I would look at, you know, you had some major project startups around the BritSats, Bohai Bay.

Canadian heavy oil projects increased a bit, as well as YK field.

And that offset the declines that we saw in North Sea.

Also, I would say the North America decline was less than expected with the lower activity.

So I would say those are the big parts of it.

We just ran very well this year.

Sure.

Let me ask you one more question about the debt reduction plan.

You guys have talked about lowering debt to total capitalization from 31% to 20% to 25%.

Although if consensus estimates are in the ballpark in '10 and '11, then you should be able to attain that target just from growth in equity alone by the middle of 2011.

And so my question is, how do you guys plan to manage this part of the program, meaning is there an absolute level of debt that you're more comfortable with?

And if so, what is that level or that range?

So if you could just talk about how that part of the plan is likely to be managed, that would be great.

Yes, and that might be something that would be better talked about in March (multiple speakers).

But there is no specific number that we are targeting.

I think part of it will depend upon what is happening in the market, what kind of opportunities we see.

But I think we like the idea of being back in the 20% to 25% debt-to-capital ratio, but don't see a real big benefit in going much below that level.

Okay, great.

Thanks a lot, Clayton.

Mark Gilman, Benchmark.

Clayton, good morning.

A couple things.

Can you comment on the cash that changed hands with respect to the recently announced Statoil swap?

Not really.

I mean, we try to keep those asset swaps -- the commercial terms confidential.

So I can't really say anything about that.

Okay, let me try one or two more, if I could.

Implicit in your comment regarding 2010 production is how much in the way of voluntary gas curtailment?

I don't think we are making any assumption around voluntary gas curtailment.

So we've got around 140 -- for the quarter, we were down what -- 140 Mcf a day, and we are all back on now.

So essentially, we don't make any assumption that there is going to be gas curtailed in 2010.

Okay.

There is a comment in the press release, Clayton, regarding Bohai production, and number about 45 KBD.

I don't know what that number is.

Is it fourth quarter, is it full year, is Phases 1 and 2 or just Phase 2?

Is it an entitlement number?

Can you help?

I think that is a net year-end number.

For --?

For everything inside of Bohai.

I mean, that is our production [net] at Bohai.

And it's an entitlement number?

Yes -- well, I'm not sure I know enough not to agree with you.

But if it is not an entitlement number, I will call you back.

Okay.

I mean, your net share under the applicable production sharing contract?

Correct, that's right.

Okay.

Just one or two other quick Upstream things.

Can you give us any kind of color on the kinds of results you're seeing in the Eagle Ford program at this point?

Not a lot.

I mean, we've had good success there.

What has been encouraging are the existence of some condensates and other liquids.

I would say the drilling program is being developed now for 2010.

But I don't think we want to get into any specific production or well results.

Okay.

There has been some confusion in the trades and in the media regarding the Poseidon appraisal.

Could you set the record straight on exactly what happened with that well?

Was it a well where we really didn't see any meaningful results because of mechanical considerations?

Or did the well in fact not confirm what you saw in the initial discovery?

Are you talking about Poseidon, the most recent well or the --?

That's correct, Poseidon 2.

There were some technical issues that didn't allow us to test the well the way we wanted to.

So we are waiting for technical results.

There's nothing conclusive we've gotten from that well testing now.

Okay, I have just one more, a little arithmetic-related.

Looking at the waterfall charts for the segment earnings, okay, I have $95 million in cost reduction in E&P in the fourth quarter.

I've got $47 million in R&M in the fourth quarter.

If I put it together and multiply it by 4, gross it up on a pre-tax basis, I am looking at a number that is perhaps in the $1.1 billion range.

That is nowhere near the kind of numbers that you talk about as having achieved.

What am I missing?

So are you -- well, this may be something we want to take off-line, but I don't know if you are looking at the market-related impacts or you're just looking at the --

I'm just looking at what you are defining as cost savings in those two slides.

Okay?

These are your numbers, and on a fourth-quarter basis versus year ago, frankly, the run rate ought to be a lot higher.

And therefore, if anything, I ought to be exceeding the number that you are talking about.

You can't look at the fourth quarter -- fourth quarter can't be annualized because the market factors of natural gas and foreign exchange went against us.

Okay.

In the other quarters we actually had helps from FX and nat gas.

This quarter, all the savings came from internally-generated, and actually we gave some back on the market-related ones.

But I'm happy to walk through the -- we feel pretty good that we delivered on this $2 billion in savings, $1.7 billion, if you exclude the severance accruals.

And I would be happy to walk through that with you.

Okay, will do.

Thanks very much.

Robert Kessler, Simmons & Company.

Thanks.

Good morning, Clayton.

I wanted to revisit the Upstream impairments a bit and see if there was any associated reserve impact for those.

It sounded like for the Russian affiliate, it was -- you were fairly explicit in saying those were unproven or probable reserves, and that there was, by implication, I'm assuming no 1P effect.

But I'm wondering if the Canada reserves may have had an associated write-off of barrels in addition to the write-down of assets.

I'll start with Canada.

There were several things that drove the Canadian impairments.

One was royalty rate reduction -- well, there was royalty rate reduction for a good portion of Canadian production.

But in some specific wells and fields, including some of the deep wells, royalty rates actually increased.

Impairments in Canada were isolated to a few fields.

Some of them did see negative impacts from royalty rate changes, but there was no impact on reserves -- or very little on reserves.

As far as Naryanmarneftegaz, the biggest driver on that was our view of the probable reserves around the JV area and the fact that we see those reserves as less than we had.

There were some other things around cost and currency that impacted the valuation.

But also in Russia, you have to keep in mind the equity impairment rules are different where you use a discounted cash flow against book, which is more stringent than you use for consolidated.

Sure.

I just would have thought that year-end 2009 would have been more benign than the year-end 2008 test in terms of market factors there, but --.

That's true.

I think that's right.

I think around Russia, it was just our assessment of the resource after we had gotten additional information.

So it sounds like YK itself has done reasonably well, but the surrounding areas have changed in terms of your perception.

How do you view overall net production from the JV now for Conoco going forward the next several years?

I don't think our position has changed on that.

I think YK is operating as we expected.

I don't really -- I don't view this as having an impact on our overall assessment of Russian operations (multiple speakers).

Okay.

Thanks, Clayton.

Blake Fernandez, Howard Weil.

Good morning, Clayton.

A question for you -- I wanted to clarify.

The 2010 production guidance, does that contemplate any divestitures?

No, it does not.

So it is -- we are not assuming impact of the divestiture in [2000].

I mean, obviously there could be divestitures that have an impact on production, but we are not including it in the guidance.

Okay, thanks.

And then moving on to the lower tertiary, obviously, the transaction with Statoil moves you more levered to the lower tertiary.

And as I understand it, it's somewhat early days, with not a lot of production history or data points from the play from industry.

And I'm just curious, do you have enough tangible data points to kind of have a good understanding of the economics out there, or how much of this is kind of betting on the [com]?

No, I think the people that we have in exploration understand lower tertiary pretty well.

They've gotten us into Tiber and some other things that have been successful.

The thinking behind this is that we just are looking to balance the portfolio between the different exploration opportunities that we have.

And Chukchi is highly prospective.

But we wanted -- and the deal with Statoil allows us to manage some of those costs and risks, while we are maintaining control and are exposing ourselves to material prospects that have running room and that are early in the lower tertiary position, we think does that for us.

So it is going to be another area of emphasis for us in our exploration program.

Okay, great.

And then the last one I have for you, you mentioned kind of the net earnings impact as a result of crude differentials, which are clearly compressed.

I'm just curious if there is any outlook from you guys going forward as maybe more OPEC barrels coming to market, potentially a ramp-up of Canadian oilsands development.

Do you have any sense that differential environment is going to materially improve over the coming year?

Well, some people believe that heavy/light differentials will move with improvements in general economic activity.

So if overall demand for crude oil increases, then you will see additional heavy sour barrels coming out of the Middle East.

You know, the Canadian production is going to take some time to materialize.

The new capacity that we've seen in Asia and also some of the capital spending that US refiners have done have been pointed towards coking and other heavy oil handling investments.

And so that kind of puts more demand for heavy oil.

So I don't think we expect it to go back to where it was, let's say, in the middle part of the decade, 2005, 2006 there.

I don't think we're expecting $20 heavy/light diffs, but maybe a little bit wider than it is now.

The only other comment on refining -- I know this isn't really to your point, but we do expect the West Coast to get better than it has been.

The West Coast margins have really gotten creamed over the fourth quarter, and that was part of what contributed to our results in that we have three refineries on the West Coast.

Right.

Well, thanks so much, Clayton.

Appreciate it.

Arjun Murti, Goldman Sachs.

Thanks.

Clayton, just a question on the Surmont announcement from this week.

Do you have a CapEx number to go with the production increase you talk about in the release?

Well, we are not sharing it.

We have it, but we are not going to share it.

I'm glad you have one.

That's at least good.

So can you provide any color of how you kind of see that versus Foster Creek?

Christina Lake, I guess, is part of the question as well.

Sure.

And you know we don't provide project level CapEx.

But I would say it is competitive within our portfolio.

I say I think it is in line with where we see FCCL CapEx or requirements.

We also -- we want to stage these things at different times.

Surmont will begin construction this year.

This is a build-on from an earlier phase, and I think peak production from Phase 2, we're expecting in 2017.

I guess Foster Creek/Christina Lake seems to clearly be an excellent project.

And no disrespect to Surmont; it has been viewed as obviously difficult to measure up to Foster Creek/Christina Lake.

But it sounds like you all have had some encouragement as you've run the pilot that the economics are actually quite competitive.

That's right.

And this way this -- this in no way crowds out investment into Foster Creek or Christina Lake.

That is terrific.

That's it, Clayton.

Thanks a lot.

Jason Gammel, Macquarie.

Hi, Clayton.

You kind of preempted my question on refining.

But on the West Coast, we've been looking at margins that were probably not covering cash operating expenses, which I believe were confirmed by another report today.

Could you confirm if you are seeing something similar?

And also, if so, does it help you to reduce run rates or are your costs fixed such that you would probably still run at a high utilization even if you are burning cash?

No, I think when you're making these decisions around run rates, you have to take a prospective view on where you think cracks are going to be.

And for us, we always say you have to cover your variable cost.

So you've got to be positive cash.

The rates that we saw in California, the crack spreads were so low, they are just not sustainable.

Refineries will take additional run cuts or shut down.

But we don't want to burn cash.

When we're making those kinds of decisions, we are making a forward look on what we expect those cracks to be, what we expect the differentials to be on heavy/light, what we expect movements in crude to impact our secondary products.

But if we are not covering our variable costs, we have to take steps to curtail production.

Okay, thanks for that.

Also, if I could just clarify on the gas curtailments, the 145 million a day that you mentioned in the fourth quarter, is that US only or is that total North America?

Total North America.

And I've got production down sequentially about 320 a day versus the third quarter.

So is the incremental effect simply a decline effect as a result of a lower level of drilling activity?

That's correct.

Okay, and then finally if I could, there has been quite a few heads of agreement or purchase sale agreements signed in the Pacific basin over the last six months.

Is that affecting how you are marketing ALNG, and can you talk about any progress that has been made on the marketing front for that project?

We are still active.

We've announced some things over the last month around mostly Upstream awards of engineering and project awards.

We haven't said anything about our marketing activity, given that these things are fairly sensitive and you don't want to tip your hand on commercial negotiations.

So all I can tell you is we are actively pursuing the marketing of two trains of LNG out of Queensland.

And there is a lot of interest.

And we expect to announce something before the end of the year.

Thanks very much, Clayton.

Doug Leggate, Merrill Lynch.

Morning, Clayton.

Clayton, I wanted to jump back to the production guidance.

Can you give any sense of what the magnitude of disposals might look like and how that might impact the production for the year?

What is behind my question is your debt targeting.

Because I guess your cash flow -- your assumed cash power of the portfolio has a production capacity in mind when you do that.

So if you could give us some help as to around how you are thinking about that, that would be great.

We really haven't tried to give order of magnitude on what the impact of asset sales is going to be.

Syncrude is around 25,000 a day, but that depends on when the asset would be sold.

Right?

So the 2010 guidance really isn't factoring in any impact from asset sales.

Okay.

I guess we'll get more color on that on the strategy day.

Okay.

The only other one I have is I wanted to jump back to CapEx.

What exactly is the pacing of the CapEx coming out of ALNG?

How much is in for this year?

Because that was expected to ramp up.

But my understanding is you managed to negotiate some much better, I guess, E&C contracts and so on, and maybe those CapEx numbers are coming down.

So some idea of that would be appreciated.

And I may have to -- I don't have that, and I would assume that we didn't -- again, we don't give project-related CapEx guidance.

I don't know if we had provided it in our 2010 capital press release.

We may have done it for the region or for the country.

It is early days in APLNG.

There is -- contracts are being awarded, but I don't see a lot of capital going into that project right now.

I think generally on projects like this, you need to get certain things in place before you ramp up on capital spending.

So I would say the bulk of the capital going to APLNG is going to be later in the decade.

I guess just one final one, if I can squeeze it in, a kind of related question.

There was some noise on the wires a few weeks back about what was going on with Shah.

And I know that Jim has been very clear that that was not in the 2011 -- sorry, 2010 budget.

So are we basically -- are you basically going to be sort of pulling out of that project altogether?

Or any update would be appreciated.

I think I could just give the same answer Jim has been giving, and that is we continue to work the project and no decision has been made.

When we get to the point where we are going forward or not going forward, then we will share that with you.

I don't think -- I think when we look at Shah or look at other projects, all these things have got to compete for capital and have got to generate high returns.

And that is how we look at it and other major projects like it.

All right.

Terrific.

Thanks, Clayton.

Ryan Todd, Morgan Stanley.

I just had a quick question on US refining.

Is it safe to say from your comments that other than maybe some efforts at cost control, that you are not considering anything else in the ways of rationalizations or sales or JVs or anything else to handle the situation -- that is just cost control and then riding out the environment?

Well, I don't think we are just sitting on our hands.

I think that we are going to look at run cuts in certain areas that -- where the refineries aren't covering their variable costs.

You are probably familiar that we had Wilhelmshaven down for most of the fourth quarter.

I think there are other -- so yes, you can cut costs.

You can constrain capital that would be going into projects or expansion type projects.

As part of our design to improve our returns over time, we've said that we want to have a smaller downstream business, 15% to 20% of our total portfolio being downstream, instead of the 20% to 25% where we are now.

But that is going to take some time, given the environment for refineries.

So I guess I would say it a little bit differently.

There may not be a lot that we can do from a portfolio perspective in 2010 in terms of finding creative ways to generate higher returns out of that business.

But over the next several years, as we go forward in this, you could expect us to look at creative ways of reducing our exposure to the downstream.

Is that fair?

Yes, that is.

So earlier, you had said that you would expect that in terms of asset divestiture, it would be more likely that we would see refining divestitures a couple of years down on the line, and --.

And I think that's a function of the market.

And that would still assume to -- that would still be the position?

I think that's right.

That is probably a good question for Willie or Jim at the end of March at the Analyst Meeting.

And on the West Coast, you mentioned obviously there has been tremendous weakness in West Coast margins.

And what do you think -- from your perspective out there, what has been driving the weakness?

Is it just a blowdown of winter grade gasoline?

And you expect -- you commented that you expected it to get better.

Any comments on why the weakness and why you would expect it to get better in the near term?

Well, I think you've already seen it improve a little bit here in the last week or so.

But I think it is imports and demand levels on the West Coast have been very low.

But I can't give you specifics to why the West Coast has done so poorly.

But it is at a level -- or it was at a level that it was operating below variable costs, and at that point, you start seeing refineries curtail and you start seeing imports -- or you start seeing waterborne [clean] products go to different markets.

So it has a tendency to clean itself up.

But we hadn't seen crack spreads at that level, I don't think -- it's a historic low.

That is what was behind that comment.

Okay.

And on a different note, you mentioned the Origin JV and the Australian LNG project.

But can you give us any, as we look towards 2010, an idea of potentially what project sanctions you might have in store or potential project sanctions for the year?

That would be one of them.

We've got to make a call one way or another on Shah.

I think there are -- obviously, QG3 is going forward.

You've got the Jasmine project in the North Sea.

Let's see -- I think I've got a project slide here somewhere.

There are -- I think the Alpine West has been pushed out.

Gumusut is in production.

Let me come back to you on -- as far as specific project sanctions.

And this is going to be something we will talk about, as well, in March.

Okay.

Great.

I appreciate the help.

Thanks.

Mr.

Reasor, there are no further questions at this time.

Great.

Well, I just want to thank everybody for their participation in the call, and the information is available on our website.

We are certainly available to follow up if you've got any additional questions.

Thank you.

Thank you for your participation in today's conference call.

This concludes the presentation.

You may now disconnect.

Good day.

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