康菲 (COP) 2018 Q3 法說會逐字稿

Welcome to the Third Quarter 2018 ConocoPhillips Earnings Conference Call.

My name is Christine, and I will be your operator for today's call.

(Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Ellen DeSanctis, VP, Investor Relations and Communications.

You may begin.

Thanks, Christine.

Hello, everybody, and welcome to our third quarter earnings call.

Joining me today are Ryan Lance, our Chairman and CEO; Don Wallette, our EVP of Finance, Commercial and our Chief Financial Officer; Al Hirshberg, our EVP of Production, Drilling and Projects; and Matt Fox, our EVP of Strategy, Exploration and Technology.

Our agenda today -- for today's call is to have Ryan review our key milestones from the third quarter from the year-to-date and then some of our focus areas for the remainder of the year.

I want to note that all of our usual financial and operational highlight slides are included in today's deck and back-up for your information.

They're very straightforward.

So after Ryan's remarks, our plan today is to go directly to Q&A.

Our cautionary statement is shown on Page 2 of today's deck.

We will make some forward-looking statements during the call that refer to future estimates or plans.

Actual results could differ due to the factors described on this slide and in our periodic filings with the SEC.

And then finally, we'll also refer to some non-GAAP financial measures today, and that's to facilitate comparisons across periods and with our peers.

Reconciliations to those non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and also on our website.

And now I'll turn the call over to Ryan.

Thanks, Ellen, and welcome, everyone, to today's call.

2018 has been another exceptional year for ConocoPhillips.

Slide 4 summarizes our achievements from the third quarter and the first 9 months of the year.

Our value proposition is all about returns.

We're laser-focused on disciplined free cash flow generation and strong execution.

Discipline means we're not chasing higher prices by ramping up activity.

By staying disciplined, we generate strong free cash flow, which we then allocate in a shareholder-friendly way.

And underpinning our discipline and cash flow allocation is predictable, consistent execution quarter-in and quarter-out.

Our commitment to these elements has driven strong results across the business in the third quarter and throughout this year.

Starting with our strategic milestones on the left, earlier this month, we announced a 7% increase in our quarterly dividend rate.

In July, we increased our 2018 buyback target to $3 billion.

That's the pace we're on for the year.

At the same time, our board increased the total authorization to $15 billion, representing about 20% of our shares since the buyback program began.

This sends a strong signal to the market that we have confidence in our plans for continued shareholder value creation.

The combination of our dividend and buybacks represents a return to shareholders of about 35% of CFO, well in excess of our 20% to 30% target.

Importantly and distinctively, these distributions were funded organically.

We're delivering on all our strategic priorities and that means focusing on all aspects of value capture.

For example, there's been a lot of interest in our ICC proceedings with PDVSA.

We announced in August that we had reached a settlement agreement to fully recover the arbitration award of about $2 billion.

This was a major milestone in this effort.

This quarter, we recognized $345 million of that settlement, so we are collecting.

Finally, we continue to optimize our portfolio and have announced about $600 million of additional dispositions over the past few months.

Our financial performance has improved consistently throughout the year.

Stronger prices helped but we're also benefiting on a relative basis due to our Brent-weighted mix and from ongoing efforts to mitigate inflation risks and keep a lid on costs.

In the third quarter, we generated $1.6 billion or $1.36 per share of adjusted earnings.

And here's some interesting perspective.

The last time ConocoPhillips generated quarterly adjusted earnings of $1.6 billion from continuing operations was in the third quarter of 2014.

Brent was over $100 per barrel, and our production was almost 1.5 million barrels of equivalent oil per day.

So we're as profitable today as we were then despite prices being 25% lower and volumes being 20% lower.

So bigger isn't always better.

That's why we're focused on per-share growth and value, not absolute volume growth.

Our portfolio and efficiency efforts have boosted the underlying strength of our company and driven what we believe is peer-leading sustaining price of less than $40 WTI.

We've significantly improved our resilience to low prices without capping upside for investors, and that's the key to outperformance through the cycles.

Cash from operations in the third quarter was $3.5 billion and CapEx was $1.6 billion.

So we generated almost $2 billion of free cash flow, which more than funded our dividend and buybacks.

Year-to-date cash from operations is $9.1 billion.

This exceeded CapEx by $4 billion.

Of this free cash flow, over $3 billion has been returned to our owners.

We also further reduced debt while keeping our CapEx in check and maintaining strong liquidity.

At the end of the quarter, we had about $4.8 billion of cash and short-term investments on hand.

Our balance sheet is in great shape.

Our debt reduction target was achieved 18 months ahead of schedule.

The credit rating agencies have noticed, and they've responded with recent upgrades.

We are now Single A-rated by all 3 of the agencies.

Importantly, since our value proposition is all about returns, let me be -- give you a current snapshot.

Our 12-month trailing return on capital employed is now in double digits, and our cash return on capital employed is over 20% and those returns should continue to improve.

Strong financial performance is possible because of consistent, predictable execution on the operating side of the business, and the organization again delivered this quarter like they have done all year.

Third quarter production, excluding Libya, was 1.224 million barrels of oil equivalent.

That's underlying year-over-year growth of 6% on an absolute basis and 28% on a per debt-adjusted share basis.

Our disciplined plan remains very much on track and we expect to close out 2018 on a strong note.

Our key annual turnarounds were completed safely and our operations are running smoothly.

We recently started up conventional projects in Alaska and Asia Pacific with 2 additional startups expected in Europe this quarter.

We recently sanctioned GMT2 in Alaska and spud our first exploration well in the Louisiana Austin Chalk.

So we're building good momentum heading into 2019.

Now in December, we're going to announce our 2019 operational plan, you can expect our capital to be roughly in line with this year's capital, excluding acquisitions.

I think this is a clear indication that we're not straying from our strategies, so no surprises there.

This quarter marks the second year of our anniversary of when we launched our disciplined, return-focused value proposition.

At that time, we established a leadership role in executing what we believe is the right strategy for this cyclical business.

We're committed to maintaining consistency and discipline through price swings.

This is fundamental.

Our sustaining price of less than $40 gives us a distinct advantage at lower prices, and we offer investors unhedged exposure to higher prices.

Now as we head into 2019, you can count on us to remain disciplined, focused on free cash flow generation and strong execution of the business.

That's our formula for delivering superior returns to shareholders through the cycles.

We know it's a formula that works, and we're sticking to it.

So let me turn the call over to Q&A.

(Operator Instructions) Our first question is from Phil Gresh of JPMorgan.

I guess I'll just -- I'll ask a question on the capital number that you referenced for 2019 since you're willing to give that.

It sounds like, obviously, you're not looking to ramp up spending.

You do have, I think, some roll-off spending from some projects that are ramping here in the fourth quarter.

But do you expect any activity increase, say, in Lower 48 in 2019?

And if not, is there a scenario where you would consider it?

Because obviously, we have a lot higher price now than we did before.

Yes, Phil, thanks.

As I said, I think we're staying pretty committed to our disciplined plan.

Wanted to give a signal to you all about kind of where we see 2019 headed.

I'll let Al kind of chime in on some of the -- a bit more detail about that, but we expect our capital to be roughly in line with kind of where we're at today, all things being equal.

But there are some moving parts within the portfolio that are important.

And I think Al can provide you a little bit of color on that.

Yes.

So Phil, we obviously haven't set our exact capital number for 2019 yet.

We'll do that in December and announce it to the market then, but Ryan's already given you a pretty strong hint at how it's going to turn out.

Really consistent with where we've been all year, we don't plan to make any significant changes to our activity level in the Big 3 in the Lower 48.

We do have some new projects that are -- that will be attracting CapEx in '19 higher versus '18, and we also have the acquisitions in Alaska this year.

Let me mention a few numbers there.

We've got GMT2 in Alaska, Barossa, that is progressing, and we start to spend more CapEx.

And also, the Montney where we've got -- it's really still in the appraisal phase but we are building processing capability and water capability that will be adding to our CapEx next year.

And in addition, we have our increased working interest at Kuparuk, assuming that we close there on that deal, and the Western North Slope.

And we add all that up, about $500 million, plus or minus, of increased CapEx in '19 versus '18 for those things.

But we also have some significant roll-off of projects that are -- major projects that are finishing up.

So you've got Aasta Hansteen, Clair Ridge, Bohai Phase 3 and the Bayu-Undan in-fill wells.

When you add all that up, that roll-off, it's also about $500 million.

So those roughly offset each other.

And so the -- that's how we get to a plan that is roughly what Ryan was describing, where the major project roll-on, roll-off are roughly offsetting and we're staying similar in our Lower 48 activity levels.

Okay, that's very helpful.

And then I guess, the second question, Al, for you would be some of the topics of the day here just on takeaway.

There's been a lot of talk about frac commitments for NGLs as well as Bakken takeaway.

Maybe you could just elaborate how Conoco is positioned on these issues.

Phil, this is Don.

Maybe I'll take that one.

As far as fractionation capacity overall for NGLs in the Lower 48, we're in pretty good shape.

We're not seeing any takeaway constraints.

Relative to the Bakken, certainly within the basin, everybody can see that processing capacity is starting to get pinched there with the growth in the Bakken production of about 150,000 barrels a day year-over-year and additional competition from the Canadian imports as well.

So we're not seeing takeaway problems on the gas or the processing or the NGL side up in the Bakken.

And we don't anticipate any -- the midstream companies that we work with have expansion plans that we expect to be in place toward the end of 2019.

Don, just to be clear on the Bakken, I was talking more on the crude side.

I was just trying to understand how much do you put on DAPL versus do you rail?

And any color on those dynamics?

Yes, I'd be happy to, Phil.

I don't know that I want to get into specific pipelines.

But generally, the way that I think or we think about the Bakken, kind of 3 different market centers there.

We've got the Rockies refining center.

That's sort of the local market.

And then we have access through pipe commitments to the Mid-Continent, so kind of the Chicago area, Patoka, Clearbrook.

And then the third is Cushing.

And we go in all 3 different directions.

I would say that lately -- we have flexibility so it shifts from 1 quarter to the other how much is going into each location.

But in the third quarter, I believe a good estimate would be about 50% is sold within the Rockies.

That gives you an indication of our exposure to, say, currency-type pricing.

Probably 30% to Cushing and maybe 20% to the MidCon.

And we're not seeing takeaway constraints there.

Our next question is from Doug Terreson of Evercore ISI.

On Venezuela, Ryan, you mentioned the $345 million of payment from PDVSA in the quarter.

And I think that another $500 million is expected by year-end, and you got to get the remainder over 4.5 years.

So my question is, is this the correct profile for those cash payments?

Is that the right way to think about it?

And second, given the uncertainty in Venezuela, is there any recourse that you have if PDVSA doesn't pay on schedule?

So how are you guys thinking about those 2 things?

Yes, Doug, let me just clarify.

And then Don's been on point for us, he can chime in, too, as well.

But the -- yes, we recognized $345 million of revenue in the third quarter from the settlement, and that's part of a total of $500 million that we should receive this year.

And we should get the remaining part between the $345 million and the $500 million in the next month or so.

Then we start a monthly -- or a quarterly amount that we get until the full $2 billion is paid in full to ConocoPhillips.

And we have provisions if they miss payments to go back after some of the assets, and I'll maybe let Don elaborate on that a little bit.

Maybe just to drill down into a few more facts around that, Doug.

On the -- as Ryan mentioned, our settlement agreement called for $500 million of early payments -- or we refer to them as initial payments as part of the $2 billion collection from the ICC award.

And that $500 million was comprised of 2 components really.

You'll probably recall that we seized crude inventories as part of our enforcement actions.

That was about 4 million barrels of oil that had a notional value of around $300 million, so that was the commodities element of that.

And we've been marketing that oil, and most of it has been lifted.

We still have some to go.

The other component were 2 cash payments of $100 million each.

And the first cash payment was due the first week of October.

PDVSA provided that the last week of September actually.

The second payment is due in November.

And so that sums up the total $500 million that we anticipate that we'll collect during 2018.

And then as Ryan mentioned, then we go into a quarterly payment schedule of around $85 million a quarter for, I believe, it's the next 18 quarters or however long it takes to recover the full $2 billion.

Okay, okay.

And then also, Ryan, you mentioned that your financial performance is the best it's been since, I think, second or third quarter of 2014 when Brent was above $100.

And then going forward, obviously, if this performance -- if performance continues to be strong and spending's not rising much, which I think you implied, debt reduction program's mostly complete, then the question becomes, what are the plans for -- or priorities for surplus funds going forward?

Meaning, would you allow cash to build on the balance sheet, increase share repurchases?

What are some of the parameters around the thinking in that area?

Yes.

Thanks, Doug.

We've kind of said we're holding our activity level.

We like to execute a constant level of activity kind of through the cycle.

And so that does kind of say what -- as we generate the cash flow that we see, the ability to generate what do we do with that.

And I'd say at this point in time, we feel comfortable with the averaging that we're -- the constant level of buybacks that we're executing.

We'll watch the market, see how that's going.

But I think you should expect to see cash probably rise on the balance sheet.

And we'll also address that in a bit more detail in December.

But right now, that's where, heading out, we see our net debt fall a little bit.

Our next question is from Paul Cheng of Barclays.

I don't know, maybe this is for Al.

Al, have you guys shut in any production in Surmont given the price that it must be pre-, post or if not, below your cash variable cost there?

Yes.

We have had -- we've talked about the -- some of the shut-in production or curtailed production that we had back in the third quarter.

I talked about on the last call that was really driven by the Syncrude outage.

But in the fourth quarter, we also do have some small curtailments that are driven by netbacks and trying to just maximize our cash there.

But right -- it'll be in the round-off in terms of our production volumes in terms of the numbers.

Do you guys have any intention to sign the rail deal we need to do Surmont production?

Rail?

Paul, yes, we have a good bit of Surmont blend going on, on rail right now.

I think in the third quarter, we had maybe something like 45% coming to the U.S., maybe 55% sold into the Edmonton trade center.

These are kind of rough numbers.

And then of the amount going to the U.S., it was pretty evenly split between pipe and rail, maybe a little bit more on rail than pipe.

And Don, do you have any intention to increase that given that some fee at that situation could get far worse before you get better?

No, that's exactly right.

And even in the fourth quarter, we're going to see -- I mentioned, what, 45% going to the U.S. in the third quarter.

That's going to rise above 60% in the fourth quarter.

And almost all that increment is on rail, so we are expanding our rail capacity.

Okay.

And those are long-term minimum volume contracts?

Or are these all based on spot?

No, these are term contracts.

I don't know -- they're not as long as the 5-year deals that you hear about that the rails are insisting.

We got in and got these contracts before the terms got that onerous.

So the intention is to bridge us over to the next major pipeline expansion, so a few years.

All right.

And then the benefit is showing up in your price realization, right, already or that is showing up somewhere else?

Say it again, Paul.

I didn't understand, Paul.

No, the benefit.

I mean, given that if you're looking at the cost to rail it is much less than what the discounter (inaudible).

So I assume that once you rail it down, you get the (inaudible) price.

And so that your price realization comparing to the Edmonton if you sell it there would be much higher.

So I guess, my question is that in those volume, the benefit that you receive, is this showing up just simply on the price realization is higher than you report?

Or is there someplace else that we should look for?

No, it will show up in the realizations, and that is going to vary from one quarter to the next.

Currently, pipe is going to give, by far, the highest realizations, at least it does under our arrangements, and then followed by rail.

And -- because rail cost into, say, Cushing or to the Gulf Coast is generally in the -- it's not in the high teens.

It's more in the low teens.

Okay.

A final one for me.

Ryan, there's some concern from -- in the industry that as we free up Permian, we're just going to shift the bottleneck in the middle of the country into the Gulf Coast because the import capability may not be sufficient by early 2020.

Where do you stand in that debate?

And whether you guys will try to be more active trying to accelerate the [bureau] on the export capability?

Yes, I'll let Don chime in as well, Paul.

But yes, we see the same thing as most of the industry's been looking at is the bottleneck gets eliminated from pipe in the Permian and moves to the Gulf Coast.

We'll be exporting a lot more crude.

I can let Don comment on how we're thinking about that more specifically.

Yes.

Paul, we think the Gulf Coast is going to require expansion.

There are plans in place in both Corpus, Ingleside and Houston to expand the export capability, and we think those plans are proceeding along at a good pace.

Just to give you some numbers on ConocoPhillips, we've sold probably something about -- around 10 million barrels over the docks this year.

So it's going to vary a lot from month to month or quarter-to-quarter depending on whether the arbs open or not.

But on average, for the year, that would be about 35,000 barrels a day.

Or in other terms, it represents about 30% of our Eagle Ford sales.

Currently, we're not -- we don't have transportation to the Gulf from Permian, so that's all Eagle Ford.

And those exports have helped our realizations.

That's one of the reasons why our realizations are so strong.

In the third quarter, our waterborne barrels average WTI plus about $3 netback to the Eagle Ford lease.

So really good performance there.

But just generally from an industry, you're asking about more the industry capability and the wave of Permian production coming into the Gulf.

Right now, we think the Corpus, Ingleside area has about 800,000 barrels a day of export capacity.

And recently in August, they exported about 400,000.

So right now, 50% of their capability.

If you move up to Houston, we estimate about 1.6 million barrels a day of export capacity at the Port of Houston.

And August exports were 400,000 barrels a day, so a lot of surplus capacity in Houston.

Now Corpus has active plans to dredging and adding buoys and things like that, that are going to grow export capacity over to 2 million barrels a day by 2022, late 2021.

So I think a lot of this is going to depend on, obviously, the pace of Permian production.

Just looking at the pipeline schedules, the new pipes being built out of the Permian to the Gulf Coast, it looks like those pointed toward Corpus are probably going to go in first.

And so we'll probably see a little bit of bottleneck at Corpus initially.

But then once the pipes go in from the Permian to the Port of Houston, the ship channel come on, then that should alleviate the bottlenecks.

So as we look at it and back up, we think, yes, there's probably going to be some tightness, particularly at Corpus, probably in late '19 when these pipes start up.

But that probably -- we're probably talking about bottlenecks in months -- in terms of months rather than years.

So we don't think this is going to be a significant problem.

Now I mentioned our export capacity.

I will confirm that we are and have been actively discussing expanding our capability in that regard.

We think that's going to be important over the next few years.

Our next question is from Doug Leggate of Bank of America Merrill Lynch.

Can I start with a fairly asinine housekeeping question, if I may?

And it's really the -- I just noticed in the nonrecurring charges, you're still rolling through some restructuring and impairment charges on the P&L in the third quarter.

Are you guys done with your cost-cutting initiatives?

Or is it still going on?

If you could frame what's -- is that legacy or is it something new?

We're chuckling to ourselves, Doug.

Al's got -- yes, go ahead.

Yes.

I mean, I can talk about that one.

Well, no, we're not done and we're never done.

We -- despite the higher volumes that we've -- the increased 25,000 barrels a day that we've added to our guidance since the start of the year, we're still planning to hit our original OpEx target of $5.7 billion.

And so we've done that by shaving about $0.25 a barrel off our unit operating cost.

But we -- as an example of one of the kinds of things we've been doing as we continue to focus on our costs even as oil prices have come back up, we had -- we recently had a reorganization in our Houston center in our Lower 48 organization.

And the increased productivity and organizational effectiveness that we've had there has allowed us to reduce our Houston staffing by about 10% this year, including sort of open jobs that we didn't fill.

And so we have some severance costs that are associated with that.

But we expect that, that effort alone will allow us to lower our -- decrease our Lower 48 G&A cost by about $0.30 a barrel next year.

So it's just -- we're continuing to work away on it even, for us, it's not higher prices are back so we can quit focusing on that.

We're continuing to work and so that's what that's associated with.

I appreciate the answer.

Just to be clear again, I'll ask a bit of an asinine part to that.

The $5.7 billion, that includes transport, right, transportations and not OpEx?

Yes.

It's what we call our kind of controllable cost.

It includes transportation.

So it's got lifting costs and it include transportation, but it also has G&A in it and other cost.

So the Alaska piece like TAPS and so on, that's in there as well or not?

The -- what was that, the TAPS?

Yes.

That's in there as well.

That's in there as well.

Okay, great.

My follow-up is really, hopefully, a relatively quick one.

It's -- obviously, Ryan, you guys have set the bar pretty high as it relates to capital discipline.

You've got a lot of stuff still coming online, which is obviously helping the momentum on the tailwind on production.

My question is, as the balance of this project spending rolls off, as you get through the stuff that Al mentioned, there's also a lot of things out there that you guys appear to have been competing for.

For example, Qatar LNG as well as the ramp-up in (inaudible) that you talked about already.

So I'm just kind of curious, what do you think happens to the longer-term capital plan beyond 2020?

And if you could maybe give us a refresh on where you see the sustaining capital today given the inflationary environment, I'd appreciate that as well.

So basically, 2 parts to that.

The longer-term CapEx, assuming you won some of those projects, and what's the sustaining capital like in today's environment?

I'll leave it there.

Yes.

Thanks, Doug.

I can -- maybe Matt can chime in on the sustaining capital.

He's pretty close to that.

Yes, I'd say we're pretty disciplined in trying to make sure we generate the free cash flow.

But you're right, we have some very good projects that we're competing for and hopefully, we'll be successful in the North Field expansion in Qatar.

And we're going to -- we need to backfill our LNG facility in Darwin, Northern Territories.

And then, ultimately, we will have more exploration discoveries coming in Alaska.

So we've got things on the plate.

But that said, we have projects that are rolling off, and we continue to look at the portfolio.

And we continue to make adjustments in the portfolio to account for what we see coming in as capital.

And we'll talk some more about that.

We'll describe that in more detail here in the -- coming forward in the '19 plan in December and how we're thinking about that and then ultimately, how we're thinking about the long term as well.

But we won't lose our discipline.

We won't -- we'll keep a steady scope in what we're doing in the Lower 48 unconventionals.

We've got some -- we're starting our exploration results in the Austin Chalk.

And as Al mentioned earlier, we have a stacking and spacing pilot going on in the Montney.

And -- but we're going to manage all that within the portfolio and make sure that we keep our discipline on the capital side.

Specific to sustaining capital, I can let Matt chime in there.

Yes, Doug.

You may remember, I think you asked a similar question last year at the Analyst Meeting about what would happen to sustaining capital over time.

And I said that we would see increases in sustaining capital, but what we're actually focused on was maintaining the lower sustaining price.

So what we'd anticipate moving ahead is that the sustaining capital that we talked about last year was $3.5 billion or so.

We'd expect that to move through next year and 2020 to $3.8 billion.

So that's about the same amount of increase in sustaining capital as the increase in production, but the sustaining price is not increasing.

The sustaining price is still well below $40 a barrel.

So as we anticipate and we're getting some modest increases in sustaining capital over time as the production's increasing, but we're not seeing any increase in sustaining price at all.

So Matt, just to be clear, on the last call, you ticked up your CapEx for this year on inflation.

Has there been any inflationary impact on that $3.8 billion?

Yes.

No, the -- I can talk about the inflation effects on 2018, if you like.

But it -- that's not a key thing that's driving that.

It's really just having a higher level of production.

Like Matt said, your production goes up 10%, your sustaining cost is going to go up 10%.

Yes, so things like the acquisitions in Canada and so on.

So it's not really -- it's not inflation-driven.

Our next question is from Alastair Syme of Citi.

This first question might follow on a little bit from that.

As you look at the inventory on your cost of supply, assuming you've updated this through the summer, is the shale piece still expanding at a lower cost point?

You certainly get a sense in the market that some people are saying shale has been pushed up the cost curve.

So I'm interested in your observation on that.

No, we have been updating our supply curve.

And maybe later in the year or early next year, we'll be finished with that work and we can talk more about it.

But what we have seen is an increase in the unconventional resource from our existing land possessions and actually still a decrease in the cost of supply associated with that.

So we are not seeing either a reduction in the resource or an increase in the cost of supply.

Quite the reverse.

Okay.

And is that -- sorry, is that split across the shale portfolio?

Or it is specifically the Eagle Ford or (inaudible)?

It's split across the shale portfolio as a whole and basically reflecting efficiencies and the changes in completion designs that are increasing recovery and so on.

So it's across the whole portfolio.

My follow-up is just on your scenario analysis.

You look at all the factors as sort of global demand and supply.

How's the scenario analysis shaping up?

It sounds like you still believe in unrelenting shale.

Is there anything on the demand side, do you think?

I mean -- so yes, the scenario that we're in just now will be on the supply side, the unrelenting unconventionals.

I mean, that's still happening.

The -- and right now, we're in a place of relatively high demand for our scenarios.

So we're in a place where we've got supply increasing but demand matching it, so we haven't really seen any change.

We go through a scenario monitoring process every year and try and reassess the probabilities of those scenarios as we look out in time and really haven't seen any significant change this year and how we see those playing out.

Our next question is from Bob Brackett of Bernstein Research.

I had a follow-up on the PDVSA arbitration.

Could you talk about what that means for the other ongoing arbitrations?

I'm thinking with the Venezuela specifically.

Yes, Bob, this is Don.

So we have two other arbitrations related to Venezuela.

The biggest, by far, is the ICSID arbitration, which is a claim against the Republic of Venezuela for expropriation.

I think previously, we had indicated that we expected the results of that damage award to be made public in the fourth quarter of this year.

And we've been since informed that, that's slid, and we're being told now that those results will be announced in the first quarter of next year 2019.

The other is a smaller potential award related to an offshore development, not a heavy oil project that was called Corocoro, and that's an ICC award or arbitration.

So I'm sure there's interest in how all these different arbitration actions relate to each other.

So what we've -- what we've said is that if ICSID, for example, comes up with a higher award, which is what we would expect than what ICC came up with this past spring, then this -- we wouldn't be looking for dual recovery to the extent that they address the similar issues.

There would be an offset.

So one would offset the other.

And we'll just have to go through the final result from ICSID to determine what additional compensation Venezuela might owe us.

So you're saying that if the ICSID number was higher, you'd sort of offset that against the already claimed ICC award?

Yes.

To the extent that they address the same issues.

Now there's potential -- there will probably be instances where they're dealing with different components that the ICC didn't address.

In that case, it wouldn't be overlapping.

But yes, there's a potential for a significant amount of overlap between the awards.

Our next question is from John Herrlin of Societe Generale.

Getting back to the CapEx question.

Fair to say that on a mix basis, you're going to be still 60% plus sustaining, 20% plus short cycle, the rest is long cycle?

Well, I mean, the sustaining will be in the $3.8 billion range.

This year, it's at $6.1 billion, so I don't know what that ratio is.

So it's roughly about less than 2/3 sustaining, and we would expect that to stay similar, John.

Okay.

With the Montney, when will the gas processing and water be in place so you're going beyond the testing mode?

Yes.

So on the Montney, we've talked in the past about the 12-well pad that we're putting in right now.

That's really a spacing and stacking pilot.

We're drilling Well #9 right now of the 12.

And in fact, Well 8 has already been drilled.

We've put in our proprietary fiber-optic diagnostic system.

So we're using this opportunity in appraisal mode to also collect a lot of extra data to help map out the future development of our entire acreage there.

But construction is currently underway on the processing plants, the flow lines, the water handling systems.

So all that is in progress.

We've also made additional takeaway commitments on both the liquids and gas side there to support the next phase of appraisal and all the production that comes from that.

So you'll see all that starting to come online next year.

Latter half, Al?

Yes, yes.

It will be in the back half of next year.

And of course, (inaudible).

Okay.

Last one for me is on dispositions.

Still little things to come out like the Barnett or -- can you give us a sense of how much you're going to do a year, ballpark?

Yes, we announced the Barnett, the $230 million, and the Sunrise around $350 million.

So those are the ones that we've announced recently.

Yes, we would expect to continue to be taking action on the portfolio over time.

And I mean, it could be lumpy, but what we sort of indicated in the past is that we could be looking at dispositions in the $1 billion to $2 billion on average over time and we -- but it'll come in a sort of lumpy nature.

But we are still looking at that aspect of the strategy to make sure that the portfolio is as strong as it can be.

Our next question is from Roger Read of Wells Fargo.

I guess let's keep with the Canada theme here for a bit.

So big LNG project you had announced for Kitimat.

Would we -- should we anticipate that's ultimately where a lot of the Montney gas development that you're doing would be able to go?

Or should we think about it as dependent on another exit route?

Yes.

I mean, our current work that we're doing on Montney gas export so far is not going to Kitimat.

It's going to more traditional routes and coming south, yes.

And what's your identified pipeline routes for that and are -- or other alternatives maybe locally?

Yes.

I mean, there are pipelines that come reasonably near past our acreage, some of which are getting full and new ones being built.

We're not really in the mode of talking about which pipelines we're talking to right now.

But over time, we'll have to take on quite a bit of pipeline capacity to meet our full plans over a period of time.

Okay.

And then just a question coming back to the kind of CapEx versus production growth expectations.

You walked through earlier kind of the shift to $500 million from one to another in terms of completed projects and new projects.

But as we think about the base spending yet the ability to deliver growth, is the efficiency you're seeing, whether that's straight up productivity gains or just the change in well lateral lengths and so forth, is that going to then be equivalent with the rate of growth we should expect production-wise?

Well, we certainly -- you've seen with another quarter's worth of data that we're continuing to do better than the 22% CAGR that we had laid out in our Analyst Day, and we'll be -- we've indicated more like a 35% is what you'd expect this year.

And that has largely been driven by some of the outperformance that you referenced.

But of course, that also gives us a higher level of production in -- this year that makes it harder to keep growing it.

So I'm not -- with what we have right now, you wouldn't expect you would keep maintaining that same kind of 35% CAGR without yet some new breakthrough that comes along that allows you to continue to have these large improvements that we've seen this year.

And so we'll see how that plays out over time.

But we don't see any signs that we're at the end of the road on new ideas on the technology side and continuing to improve and continuing to get more efficient on the drilling, which has led us to more wells online this year than we had in our plan.

I talked about that last quarter that that's one of the things that increased our CapEx on this year was we've drilled more wells with the same number of rigs, so we got more wells to complete, more production.

But it does increase -- has increased our -- one thing that's increased our CapEx this year.

So we're working on all of that from next year.

And that's part of what we'll be talking with you about in December is the details around the CapEx plan and the production volumes that we expect.

Our next question is from Neil Mehta of Goldman Sachs.

So the Big 3, up 48% year-over-year, certainly a surprise relative to our model.

I was curious how those numbers were tracking relative to your own expectations.

And any thoughts in terms of which of the basins is sort of surprising?

And then some -- any early thoughts in terms of growth levels for the Lower 48 going into next year given your views on activity?

Yes.

So Paul was onto some of the things I was just talking about.

We -- if you look at the -- well, the Big 3 is at 313,000 for the third quarter.

That's up over 100,000 barrels a day from the same quarter last year.

So that's the 48% growth that you're referencing.

I should start out by saying that about 10 points of that is kind of a Harvey effect.

So really, to really get a more proper year-to-year look since we lost about 15,000 barrels a day in the third quarter last year due to Harvey, it's really more of a 38% year-over-year growth third quarter to third quarter once you adjust for the Harvey effect.

So I -- that's consistent with -- last quarter, we talked about that same number was 37%.

It was lower in the first quarter, down around 20%.

But we've -- that's what's -- continues to support this idea that we're going to have about 35% growth year-over-year from the Big 3 this year even at the kind of capital levels we're at.

And that has been led by the Eagle Ford.

The Eagle Ford is 75 of that 100 year-over-year in terms of increase.

The Eagle Ford's up 61% versus the same quarter last year, 44 once you adjust for Harvey.

So I think that we have gotten some extra benefit this year.

Some of this is outperformance from what I've talked about in the past, the Vintage 4 completions doing better than we -- even better than we had expected.

But it's also more wells, more wells online because we've been more efficient with our drilling.

And so as we lay out our plan for next year, we'll see what kind of numbers that produces.

But I don't expect that we can continue to run the similar number of rigs that we talked about in the Analyst Meeting and generate a 35% CAGR over time.

The math doesn't work that way.

You're not going to get that kind of performance even with the outperformance that we've had.

And of course, as we talked about in the last quarter call, some of this increased volume is due to the little bit higher spending on OBO, the operated by others, in Lower 48.

I mentioned about a plus 7 on the last call in 2018 is from some of the increased OBO spending.

That's not a huge piece, but that is part of the Lower 48 Big 3 outperformance on production.

That's helpful, Al.

The follow-up is what's the team's message around M&A?

It seems like you got a nice organic opportunity set here with Alaska and Willow and Qatar and obviously, the runway that you're just talking about in the Big 3. But how do you think about Conoco's role of consolidation?

Or is the most -- is the P50 case still that you prosecute those organic opportunities?

Well, we're pretty happy, Neil, with the organic opportunity set.

And you're probably getting tired of me saying this, but I -- we kind of think about M&A in 3 buckets again.

And we've been executing the first 2 buckets over the course of the last couple of years as we've kind of got the company back on its front foot a little bit.

That's acreage buying, the -- what we did up at the Montney, what we did in the Louisiana Austin Chalk.

We're doing some of that each year, every year, year in, year out.

And now we were afforded the opportunity to do a little bit of asset-level work, which is kind of how I think about Alaska with respect to the Western North Slope, the agreement that we're trying to close on Kuparuk.

And we look for those opportunities.

We're patient.

We're persistent.

We won't -- we'll only pay the right price when we have an extra opportunity to improve the portfolio.

And we think we did, in that particular case, quite a lot with some good adds and getting control of our development piece over that part of the area.

Now I think you're probably referring to the large M&A, and that's kind of tough hurdle in the company because it needs to be substituted, it needs to be competitive on a cost of supply basis.

And with the current prices, they're pretty -- still pretty frothy for large companies or small companies and some of the bigger deals that are going on right now.

But we watch them.

We look at them all, and we know what we like.

And we're patient, we're persistent.

We believe that this business is going to go through cycles.

And we'll be -- we'll always look at it and have an opportunity when another down cycle occurs.

Our next question is from Devin McDermott of Morgan Stanley.

I just had a quick follow-up on the Lower 48 activity plans.

Last quarter, you talked about shifting a rig out of the Delaware to the Eagle Ford.

And I was just wondering, as you're going through the planning for 2019 and even longer term, what would you need to see to be -- to reallocate more investment or more activity to the Delaware, particularly given the improvement we've seen in realizations locally there?

Yes.

So we did execute on that shift of one rig from the Delaware to the Eagle Ford that we talked about on the last call.

And we also did lay down a conventional rig in the Permian that we talked about on the last call.

So we have done those things that we talked about.

I don't see us moving a rig back to the Delaware.

I don't expect that, that will be in our plan for 2019.

We will -- I think it'll be most advantageous to do that once we see the takeaway capacity issues in the Permian getting settled out.

And we really -- with the flexibility that we have and all the great opportunities we have in the Eagle Ford, we're not in a hurry to do that.

And so I think we'll use our flexibility and take our time, just like we talked about on the last call, and decide when to move back.

And I don't expect that it's going to be anytime in the immediate future.

Got it.

Makes sense.

And the second question I had is really a higher level one around the philosophy on dividend growth given the bump we saw recently.

How should we think about, given the strong free cash flow profile that you guys have right now, the low overall cost structure, what you view as a sustainable dividend level?

And I was thinking about the cadence of growth there over the next few years or even longer term.

Well, Devin, we wanted to kind of move to a fourth quarter dividend.

It fits better with the cadence on the company and how we review our plans with the board strategy, set our plans for the upcoming years.

So fourth quarter, it feels like a better cadence for us going forward.

I think as you think about the dividend, I think it ought to be predictable, consistent and reliable, and you ought to count on increases on an annual basis.

And so I think what we've tried to describe, what we've done over the past couple of increases should be a fairly good predictor going forward.

Our next question is from Blake Fernandez of Simmons & Company.

Production-sharing contracts have become more topical as of late, and I've never really viewed Conoco as overly exposed there.

But I just wanted to confirm there are no lingering hand grenades out there, I guess, that we need to address imminently.

Yes, let me cover that one.

If you look out, say, 10-plus years and our list of PSCs, we've got three that expire in the next 10-plus years or so.

And they've all been disclosed previously in our fact sheets, so it is really no news there.

But the nearest term one is in China, Panyu, which was originally set to expire this year.

We recently, not too long ago, negotiated a 1-year extension, but it expires in September next year.

That's about 5,000 barrels a day net to us, so not a big volume item.

Then, of course, there's Bayu-Undan that supplies the Darwin plant.

We've been talking about that for a long time that we're going to be out of gas in that field out in the '22, 2023timeframe.

So basically the production there goes to something approximating zero about the same time that the license ends.

And then we have Corridor in Indonesia, which we recently applied for.

That PSC expires in 2023.

Production will be down quite a bit from where it is now by the time you get out to 2023.

It'd be relatively low.

But we have applied just recently for an extension to the Indonesian government for that license.

And we haven't have it -- we've been in a dialogue with them, but we don't have an answer there yet.

But it's -- those are the three for us in the next 10-plus years that are on the queue for expiration.

But all in all, I'd say they're all either low production or they're going to be low production by the time we get to the expiry date, so it's kind of a nonevent for ConocoPhillips, as you suspected.

I appreciate that.

The second question, this may be more of a Don question, but I guess, it's more modeling-oriented, really kind of two-fold: one, can you discuss the over lift in the quarter?

Specifically, where that was and how should we think about kind of that going forward?

And then secondly, just on the tax rate, the adjusted tax rate has been moving down progressively each quarter.

I suspect that's because of U.S. growing.

But I just -- any thoughts on how we should think about that moving forward?

Yes.

Blake, as far as the over lift on the quarter, it's about 13,000 barrels a day.

Most of that was in Alaska.

And yes, it's coming from an under lift position in Alaska in the second quarter.

And as far as going forward, I would say on the year-to-date, we're pretty well balanced, actually a little bit under lifted on the year.

So as you think about the fourth quarter, I can't really give you any guidance.

I can't think of a reason why anybody would project an over lift or an under lift.

So as far as we're concerned, our expectation today is that sales and production would be pretty evenly matched.

Of course, things can change late in the year as far as cargo liftings, but we're not in an over lifted position on the year.

And on the effective tax rate, you noted that our effective tax rate has gone down a couple points.

I think it's -- it was 39% on an adjusted basis and maybe a little bit lower, 36% or so, on a reported basis.

I think that -- we did have a higher pretax income in our low tax jurisdictions and in our equity affiliates, which clear their tax at the affiliate level, than we did in the higher tax jurisdictions during the third quarter.

So that really kind of brought it down.

39% is within the range of my expectations.

I think when we look at our jurisdiction mix and our product -- production mix, generally kind of expect it to be in that 38% to 42% most quarters.

So not really a surprise there.

And as far as the reported being lower than the adjusted ETR, that was mainly driven by the Venezuela settlement.

So that $345 million or so has very low tax consequences to it.

And so since we reported that as a special item, that brought that ETR down to 36%.

Our next question is from Scott Hanold of RBC Capital Markets.

I think this question's for Al.

You stated, obviously, you've seen some good results in the Eagle Ford.

I think you're probably, what, producing around 200,000 per day net in that basin.

As you look forward, I mean, what do you think -- and this is an all-time record, if I'm not mistaken, for you.

What is your capacity to continue to grow there?

Where do you think it could get to?

And is there a point at which you guys are going to be more of a sustenance mode there?

Or is that quite a ways out?

Yes, you're right, Scott.

We are at about 200,000.

In the third quarter, we made 198,000 in the Eagle Ford.

And it -- we have recently signed up for additional stabilization and takeaway capacity there because the Eagle Ford has grown faster this year than we had originally projected.

We've had to sign up for it earlier.

But I think I mentioned this on a previous call, that third-party capacity was readily available in the Eagle Ford given all the shift of others to the Delaware.

And so we found that we can continue to grow without having to spend much money on infrastructure because it was overbuilt by others.

So I -- there's still more room for us to run there and more room for us to grow.

I'm not going to predict an exact number.

But we certainly -- we're not in the flattening out mode like we have talked about in the Bakken, where we were looking to kind of hold steady.

The Eagle Ford is going to continue to grow for quite some period of time.

It's not -- the flat spot on it is not in sight, not something that's going to happen next year.

Okay, understood.

And one question on the Cenovus ownership.

What are sort of the current thoughts?

Anything changed on that?

And I know you all are patient in the way you look at things, but can you frame for us how you think about that right now?

Well, Scott, yes, I mean, there's really nothing new.

We talk about this every quarter, but we do have a value expectation on Cenovus.

We've said before, I think, that we felt like it was undervalued.

I think looking at the price today, we think it's even more undervalued.

So fortunately, our liquidity position, our cash balances afford us the opportunity to be patient.

We think Cenovus is on the right track.

Obviously, we got some headwinds with the transportation takeaway issues up there.

But we think they're doing the right things, and we think the market will eventually reward them.

Our last question is from Pavel Molchanov of Raymond James.

A quick one about the LNG in Australia.

With Brent close to 4-year highs, what has been the response in LNG pricing in the spot market?

And how, just as a reminder, is your offtake agreement structured vis-à-vis the slope versus Brent?

Good try, Pavel.

I'll try to take that one, but we don't provide information on the slopes and exact pricing.

I mean, I think the furthest that we'll go is to confirm that all of our LNG contracts, Australia and elsewhere, are Brent-linked.

And so we're not going to get into the details of that.

As far as the commitments that we have in Australia, our customers are in both China and Japan.

They're long-term contracts.

Again, they're Brent-linked contracts.

Generally speaking, the buyers have some flexibility in how much they take in any one year so they may, in any particular year, vary their commitment down by 10% or up to 10%.

LNG demand, as you know, is quite strong.

So our largest buyers are -- in China are looking at taking their full commitments as we go forward.

So what the long-term commitment off takers don't take, we do sell into the spot market, and we've been pretty pleased with the spot prices that we received so far this year.

Yes, we -- I can add, Pavel, that we've had about -- we've been averaging about two cargoes a quarter of spot cargoes.

And like Don said, we've been quite pleased with the pricing we've been getting on those the last few quarters.

And what percentage is that of the LNG volume?

Well, we've -- we had 29 cargoes in the third quarter, 87 year-to-date after three quarters.

So it's less than 10%.

Thanks, Pavel, and thanks, everybody, for joining the call today.

By all means, reach back to us if you have any questions, and enjoy the rest of the day.

Thank you, and thank you, Christine.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

19