康菲 (COP) 2017 Q3 法說會逐字稿

Welcome to the Third Quarter 2017 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, and welcome to all of our call participants this morning.

Today's presenters will be Don Wallette, our EVP of Finance, Commercial and our Chief Financial Officer; and Al Hirshberg, our EVP of Production, Drilling and Projects.

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

We will make some forward-looking statements during today's call that refer to estimates and plans.

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

We will also refer to some non-GAAP financial measures in today's call.

The purpose of these is to help facilitate comparisons across periods and between peers.

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

Finally, this morning we're going to limit during Q&A your questions to one and a followup.

And with that, I'm going to turn the meeting over to Don.

Thank you, Ellen, and good morning.

I'll start on Slide 4 with our key strategic, financial and operational highlights for the third quarter.

Starting on the left side of the chart, with strategy.

This quarter was another impactful one for our company.

We've executed a number of transformational decisions to accelerate our differentiated, disciplined and returns-focused strategy.

During the quarter, we closed the sales of our San Juan Basin and Panhandle assets.

We also continued progressing several other sales that should close in the fourth quarter or early next year.

We expect to deliver greater than $16 billion of asset sales during 2017.

In the third quarter, we paid down another $2.4 billion of debt, bringing our balance sheet debt to $21 billion.

In the quarter, we received a credit rating upgrade, and we are on track for the year-end debt balance to be under our target of $20 billion.

We repurchased $1 billion of our shares during the quarter, which takes us to over $2 billion repurchased for the year, representing about a 3.5% reduction in outstanding shares year-to-date.

We expect to buy back another $1 billion of shares in the fourth quarter.

Between our dividend and expected share buybacks, capital return to shareholders would represent the equivalent of 60% to 70% of our operating cash flow in 2017.

Moving to the middle column.

Our third quarter financial results extended the momentum we've built over the past year to achieve profitability and maintain cash flow neutrality in a $50 price environment.

On an adjusted earnings basis, we were profitable for the second successive quarter, realizing a profit of about $200 million or $0.16 a share.

We generated $1.1 billion of cash from operations, excluding working capital.

I want to point out that operating cash flows this quarter were impacted by a choice we made to use a portion of our cash balances to accelerate funding of future pension obligations, with a $600 million cash infusion.

I'll cover this item in more detail in a few slides.

Excluding the pension item, cash flow was right in line with our expectations and consistent with our published sensitivities.

On a year-to-date basis, cash from operations is $4.5 billion, which exceeds CapEx and dividends by over $400 million, despite the $600 million CFO reduction I just mentioned.

As we've shown for more than a year now, our cash flows have more than covered our CapEx and dividends.

We don't require a pathway or market help to get to cash neutrality.

Adjusted operating costs were 15% lower year-on-year as we continue to lower our breakeven price across the portfolio.

Moving to our operational results on the right, we're meeting or exceeding all of our operational targets.

Production, excluding Libya for the quarter, was 1.2 million BOE a day.

Adjusting for dispositions, our underlying production on a per debt-adjusted share basis grew by 19% compared to the third quarter of last year.

We successfully completed the last lenders' test at APLNG, which allowed us to release the final project financing loan guarantee.

And we continue to execute our 2017 capital program scope at lower cost.

As Al will cover in more detail, we're lowering our capital guidance for the year to $4.5 billion.

That's a reduction of $500 million or 10% compared to our initial 2017 guidance.

So to recap, this quarter's performance again reinforces the transformation we've made as a company.

We're delivering on our priorities and continuing to build momentum.

And while the outlook for commodity prices has improved recently, we remain committed to our disciplined returns-focused strategy that creates shareholder value.

If you turn to Slide 5, I'll walk through the third quarter financial results.

With WTI averaging about $48 a barrel and Henry Hub about $3 an Mcf, our average realized price was around $39 per BOE.

Compared to the prior quarter, adjusted earnings improved slightly because of higher realizations and equity earnings, partly offset by disposition impacts.

Compared to the year-ago quarter, adjusted earnings improved by over $1 billion, with the improvement driven by higher commodity prices, lower depreciation and exploration expenses, and the impact of dispositions.

Third quarter adjusted earnings by segment are shown on the lower right.

The supplemental data on our website provides additional financial detail.

If you turn to Slide 6, I'll cover our cash flows during the quarter.

First, looking at the sources of cash shown in green, cash from operations was $1.1 billion, which as I mentioned, was impacted by our decision to make a $600 million cash contribution to our U.S. pension fund.

As we continue to strengthen our financial position, we look across the balance sheet for opportunities to reduce long-term obligations.

This payment represents an economic acceleration of future contributions, which will also serve to reduce cash flow volatility and increase flexibility going forward.

The other major source of cash during the quarter was asset sales, which generated $3 billion.

The uses of cash shown in red were in line with expectations we provided during our last earnings call.

We used $2.5 billion to retire debt and distributed $1.3 billion to shareholders through dividends and share buybacks.

We ended the quarter with $9.6 billion of cash and short-term investments.

If you turn to Slide 7, I'll wrap up by covering year-to-date cash flows to emphasize our focus on free cash flow generation.

This slide illustrates the disciplined approach we take to running the company.

Starting with the first set of bars on the left, as I just said, year-to-date operating cash flows have more than exceeded spending on capital investments and dividend distributions.

The second set of bars shows how cash proceeds from dispositions are prefunding our debt reduction and share repurchases.

In addition to the roughly $14 billion of cash proceeds shown here, we also have $2 billion of equity in Cenovus, which will be converted to cash proceeds over time.

So in summary, the business continues to run well.

Now let me turn to it over to Al to give you some color on the operations.

Thanks, Don.

I'll provide a brief overview of our third quarter operating highlights and our outlook for the rest of the year, including our updated capital guidance.

Operationally, we had another strong quarter, despite some tough weather challenges here in Texas.

As Don mentioned, production, excluding Libya, averaged 1.2 million barrels per day.

Despite a 15,000-barrel per day reduction in the quarter due to Hurricane Harvey, better performance from our global portfolio allowed us to offset this loss and still exceed the midpoint of guidance by 12,000 barrels per day.

Year-on-year, this represents an increase in underlying production of 1.4%.

During the quarter, we ran 12 operated rigs in the Lower 48 Big 3 unconventional assets: 6 in the Eagle Ford, 4 in the Bakken, and 2 in the Delaware basin.

Our Big 3 unconventional production was 211,000 barrels per day, with 123,000 per day from Eagle Ford, 66,000 per day from the Bakken, and 22,000 per day from Delaware.

This was about flat to the second quarter of 2017, but included the impact of Hurricane Harvey.

Excluding this impact, production from the Big 3 unconventionals would have been about 6% higher sequentially.

In Canada, Surmont achieved a record daily production of 141,000 barrels a day gross during the quarter.

The project continues to ramp up toward full capacity.

In Australia, APLNG ran at 110% of nameplate and demonstrated 98% uptime.

We've shipped 92 cargoes through the end of the third quarter.

In Alaska and Europe, we safely executed significant turnaround activities, which now completes our major turnarounds for 2017.

And finally, across the portfolio, we're making great progress on our conventional projects.

In Alaska, we spud the first wells at 1H NEWS with first oil expected before year-end.

Meanwhile, GMT1 is still on track for first oil by the end of 2018, with costs running well under budget.

The Aasta Hansteen topsides left port in South Korea, headed for Norway and this project is also on track for first production by late 2018.

Work also continues on Clair Ridge and Bohai Phase 3, both of which are on track for first production in 2018.

Now moving on to Slide 10.

I'll provide an update on our 2017 outlook.

We're lowering our full year 2017 capital guidance for the second time this year.

We now expect to spend $4.5 billion.

We continue to do more for less.

The updated capital guidance represents a 10% reduction from our original budget.

Despite this CapEx reduction, we expect to exceed our original production guidance.

This year, we now expect to deliver 3% underlying production growth and that's 17% on a debt-adjusted share basis.

On the left side of the slide, we list key fourth quarter and full year guidance metrics.

Below the capital, you can see our fourth quarter production guidance is 1,195,000 to 1,235,000 barrels per day, and we've tightened the previous full year production range to between 1,350,000 and 1,360,000 barrels per day.

Our remaining drivers are tracking closely with our guidance.

So that's a quick recap of the quarter.

As Don said, business is running well.

We continue to look forward to providing an update of our future plans at our Analyst and Investor Meeting on November 8. So I'll turn the call over now to Q&A.

(Operator Instructions) And our first question is from Doug Leggate of Bank of America.

So I'm not optimistic on getting too many forward-looking questions answered today, but I might give it a go.

So just one forward-looking and one about the quarter if I may.

$55 Brent all the way out in the strip from what we can tell now.

You guys are obviously fairly levered to that.

So it kind of changes the narrative a little bit about where your cash breakeven and sort of portfolio and your choice between sustaining the buyback program perhaps beyond the disposal proceeds that you've brought in versus reinvesting in the company.

So I know you're going to get into this in a couple of weeks, but can you just frame for us what a $55 world was?

What does Conoco think about by way of growth versus continued debt-adjusted per share growth?

Well, Doug, that almost sounds like you've written a title of one of our slides for the week after next for our analyst meeting.

So I think you've teed it up perfectly and we're going to answer it then as you predicted.

Yes.

I thought I'd give it a go, but anyway, it sounds optimistic.

My quarterly question is really a real simple one.

The U.S. is exporting this week again close to 2 million barrels a day of oil.

It seems to us that we're now starting to see some real linkage, I guess, between certain parts of the Lower 48 on Brent pricing, somewhat of a Brent minus than a WTI plus kind of number.

So I'm just curious, is that what you're seeing?

Do you think it's sustainable?

And if so, maybe you could help us with how you think that would impact the relative investment decisions with the Eagle Ford as we go forward?

I'll leave it there.

Yes, Doug.

This is Don.

I can comment a little bit on that.

When you look at our U.S. production in total, we're pretty heavily weighted toward the Brent side and not so much exposed to WTI.

And a large part of that is because our Alaska North Slope, which is the largest portion of our U.S., is -- really trades similar to Brent.

Probably what's not recognized well enough is our Eagle Ford production that you alluded to.

About half of that production is marketed on an LLS component basis.

And as you know, LLS and Brent have had a pretty strong relationship.

So we're not seeing the same impacts of the widening differentials that you might expect there.

I do expect, going forward, that those relationships, they have maintained in the past, so I don't see why they would break down in the future.

As far as exports themselves, we've been pretty active in the export, I'd say, in the first and second quarters this year and going back to last year.

But we're seeing demand pretty strong domestically now.

And so I think in the third quarter, I don't believe we had any waterborne cargoes going outside the country.

We did have some going inland or within the country.

But we're seeing markets improve here in the U.S., and as I mentioned, we're pretty exposed to Brent relative to WTI.

Just to be clear, Don, so if export capacity is obviously up, can you envisage 100% of the Eagle Ford being marketed on a Brent basis or not?

Well, I think 100% would be an awful lot.

I don't know what dynamic would have to cause that.

Today and in the third quarter, we didn't see the advantage, the arbitrage advantage in exporting relative to the strength that we were seeing domestically.

I think there'll be times when you see -- if you go back last year, we had a good bit going outside the country and -- but 100% is probably something that we wouldn't be expecting.

Our next question is from Paul Cheng of Barclays.

Don, just curious then.

For APLNG, I presume where now you're in a positive cash flow position.

And I believe you must be building a cash cushion in the joint venture.

So if the price stays here, when do you think the partner will start to receive the cash dividend payout from that?

I mean, in some way then, your cash flow from operations in this quarter not only impact by the $600 million of the pension contribution, but also impacted by the not distributing the cash from the APLNG.

Is that correct?

Well, we do have -- I mean, you're right, Paul.

We do have cash that's building up in APLNG.

As we said before, the cash -- the net cash flow breakeven there, in fact, is somewhere in the $45 to $50 Brent range.

And so yes, we have been building cash within the joint venture.

And if prices stay where they are for the rest of the year, it's quite possible that we could see a fourth quarter distribution from APLNG.

And then, we would expect that to correspond to prices next year as well.

Yes.

So that's an active area of discussion in the joint venture right now, Paul.

And we, of course, want to make sure we maintain enough cash build going into next year to cover loan payments as they schedule out next year.

But even with that, at these kind of prices, you're absolutely right, that we're building excess cash and will be in a discussion about distribution timing.

But no decision has been taken on that at this point.

And Al, since that I have you here, the $4.5 billion of the revised CapEx for this year, that would suggest the fourth quarter would jump to $1.4 billion.

You've been doing about $1 billion a quarter.

What may be the factor behind why that we see that jump by 40%?

Yes.

So we did $1.1 billion this quarter...

And also, that you can also talk about that, whether $4.5 billion is really what you consider is now your new sustainable CapEx requirement.

That latter question, we'll cover in 2 weeks.

But the -- $1.1 billion this past quarter and we're forecasting between $1.3 billion and $1.4 billion in the fourth quarter to get to that $4.5 billion number.

And the key drivers to that increase, we have been on a fairly steady increase through the year in the Lower 48 on overall activity.

And so there is still some more build in actual CapEx spend, and that's 3Q to 4Q in the Lower 48 and that's actually exacerbated a little bit by the Harvey effect because there was some money that didn't get spent in the third quarter due to Harvey and just some work that you weren't doing because we were down to that for a period of time.

But we also have increases quarter-to-quarter in Bohai Bay.

As that Phase 3 project, as that continues to ramp, we expect those -- that spending to be up.

And also drilling, our drilling programs in Alaska and Europe, are both going to be up, we expect third quarter to fourth quarter.

And so those are the key pieces.

Our next question is from Phil Gresh of JPMorgan.

So first question is just on kind of a follow-up on the CapEx question.

I mean, $4.5 billion of CapEx, 3% production growth.

I certainly don't think anyone expected that at the beginning of this year.

Al, maybe you can just provide a little color about how you feel like the company's been able to accomplish this.

And then, whether you think that you can continue to grow at these types of rates at this level of spend.

It's obviously a choice, but how do you think about that?

Yes, I think, Phil, we've really accomplished this -- I mean, you're right that we have done better than we expected, the plan we laid out for ourselves this time last year as we were looking into 2017, and we've continued to do a really good job of driving efficiency.

That's been a key part of our capital discipline that's allowed us to lower our capital costs.

We've been successful at resisting inflation, to a large extent, in the Lower 48.

And our production performance has really come out on the high side in a number of different places.

And those things have kind of added together to give that outperformance.

And as I look at it, I made some comments last -- on the last quarterly call that as I travel around and see this outperformance and try to really understand what's driving it, as I said last quarter, I think, in our organization, operationally, as we've reduced the amount of money that we were spending on big projects, the growth money, the $17 billion we used to spend in this company back in '14, we -- our organization has been able to spend a lot more focus on the base.

And our base production is really a big part of what's been outperforming.

And I do expect that to continue.

So that -- without front-running our story in 2 weeks, I think you can expect that we'll show you our latest calculations on that.

But this is not a one-trick deal this year, it's going to continue, I think.

Okay.

Very clear.

Second question, I guess, for Don.

This one would be, again, don't want to front run the Analyst Day, but some of the key tenets that you've talked about over the past several quarters has been 20% to 30% of CFO back to the shareholder and $3 billion of buybacks between 2018 and 2020.

And those were not in the slides today.

I just want to ensure that there's no real change to kind of that commitment on a go-forward basis.

Obviously, you're going to have a bigger update more broadly.

No.

Right, Phil.

We'll be laying all that out here in a couple of weeks for you.

But absolutely, no backtracking from any of those commitments.

So you'll see that again here in a few weeks.

Our next question is from Scott Hanold of RBC Capital.

If I could ask another question on the capital spending budget coming down quite a bit just sequentially quarter-to-quarter.

Al, could you provide a little color on that?

Are you seeing some -- was that a change in your service cost expectations?

Was that part related to less activity related to hurricane, and just a little bit of color on specifically what that reduction was for?

Sure, let me talk a little more about that.

I mean, at a high level, it is, as I was talking about a minute ago, just reflecting our continued capital discipline.

But there is this resisting inflation part.

I think since a little over a quarter ago, when the industry in the Lower 48 had a bit of the tapping on the brakes that people have talked about, that has really halted Lower 48 inflation in its tracks for the most part.

And so some of our assumed inflation that we felt we would see earlier in the year in the second half, we aren't seeing.

That little bit of slowdown reduction in rigs that we've seen and slowdown in activity has been enough to give us an absence of inflation that we had been assuming.

But we also are continuing to see increases in efficiency across the Lower 48 and across the world.

We've also had a, as I mentioned in my prepared remarks, GMT1, one of our major projects that we have going in Alaska, has continued to really perform well on the project side and is under-spending relative to the budget.

And so that's a savings.

And then you mentioned Harvey.

There is a little bit of Harvey delay where there's some work that we weren't doing or paying for during the time we were down for Harvey that is a little tiny piece of this reduction.

Okay.

So the bulk of it, it's actually organic stuff happening, right?

So that's...

That's right.

And so -- and I should also -- there's one other thing.

There's a -- we've also seen some reduction on the operated by other side.

So a little less AFEs coming in from some of our partners where they're operating than we would have forecast as they've slowed down a bit from what -- the plans we were expecting from them.

Okay.

That's great color.

And maybe this one's for Don.

You gave some brief comments in your prepared remarks on the Cenovus ownership, obviously, the lockup's expiring here soon.

Could you provide a little more detail on big picture kind of how you look at that ownership?

And what you kind of want to see as you go down the path of how and when you monetize it?

Sure, Scott.

A little bit at least.

The standstill, as you mentioned, that's coming up pretty soon.

It expires 17th of November, so we'll be free to market the equity anytime after that.

The market value right now is right around $2 billion, I believe.

This equity was really transactional currency, as you know, so we're not natural long-term owners, not strategic owners, so we'll be reducing our position over time.

I think you should expect that given our financial position, we'll be patient.

We can afford to be patient, and so our approach is going to be value-driven.

Our next question is from Ryan Todd of Deutsche Bank.

Maybe one first on the U.S. onshore.

I know you averaged 12 rigs in the quarter.

What's the current rig count in the U.S. onshore?

And how should we think about that trajectory into 2018?

Well, of course, we'll cover 2018 in a week after next.

But I -- I mean, I think that, certainly, I can, without terribly front running things, say that you can expect to see from us, for Lower 48 for 2018, a very disciplined program.

You're not going to see anything crazy in 2 weeks, and you're going to see these same general kind of activity levels.

And we may have rigs of opportunity that we add or subtract here and there as we have certain situations.

But I think we're at a pretty comfortable rig level at that kind of number that you mentioned.

Okay.

And then, maybe, on the project side.

I mean, you've mentioned Alaska a couple of times on the ongoing projects.

The Willow discovery as well as discoveries by others in the region of Alaska have mostly kind of flown under the radar up to this point.

Can you talk a little bit about what activity you may have planned in Alaska in that area over the next 12-plus months?

And what role it could play in either driving modest growth or maintaining volumes in the region?

Well, we have this pipeline of projects in Alaska.

A lot of good news there on things that have been going well, everything from CD5 to GMT1 to 1H NEWS that are all going well.

Just take CD5 for an example for a moment.

When we took FID on CD5, we were projecting plateau volumes of 16,000 barrels a day gross and we're now at 26,000 barrels a day.

So projects like that have allowed us to continue to extend, maintaining our production.

And we -- we've already said that we plan to drill 5 exploration wells in Alaska this winter.

In addition to that, we -- that 3 of those wells, by the way, are appraisal wells for Willow and 2 that are new wildcats, along the lines of what you were hinting at there, that some of the other opportunities out to the west.

And we also have submitted permits for new seismic on those state leases that we picked up late last year.

Remember, we picked up about 740,000 acres gross in December of last year.

And so we're starting to plan our seismic work around that.

And so we see additional opportunity out to the west, but also have a nice pipeline of projects that we're working on today.

And we hope to get GMT2 over the line to FID next.

Our next question is from Paul Sankey of Wolfe Research.

Given the upcoming analyst meeting, I'll ask you just a couple of modeling ones and more specific questions.

First on the pension, do we consider that very much a one-off?

Or is that going to be a future payment?

Secondly along cash flow lines, you talked about the $4.5 billion, the potential for lower -- for increased efficiencies going forward.

Should we push $4.5 billion as your spending into our long-term modeling?

And then, I have a separate follow-up.

Paul, this is Don.

I'll address the pension question that you had.

I think you should view this as a unique opportunity that we had to make a fairly substantial discretionary contribution to the pension fund.

You see a lot of companies doing that these days for a variety of reasons.

I explained our reasons.

But to answer your question, our plan doesn't include significant contributions going forward next few years.

And I guess on the CapEx, obviously, we'll be talking about the forward CapEx here in a couple of weeks.

Don't forget that we have been ramping through 2017 in our Lower 48 rig program and from the low levels we were at last year.

And so that spending has been increasing quarter-over-quarter to get to the kind of levels that we're at today.

Got it.

There's been some press out on Australia domestic gas issues.

Could you talk a little bit about that?

Yes, we've talked about that on the last few calls where the government's been working on considering export restrictions and using this basis of making sure everybody is a net dom gas contributor, particularly out in the east.

And the decision they've taken recently that you would have seen in the press is they've decided not to restrict exports in 2018.

And what facilitated that decision by the government is that the 3 Curtis Island operators in Queensland that all have these similar coal seam projects have agreed that we will offer to the domestic market any spot cargoes that we have planned next year.

We'll offer that gas to the domestic market at an equivalent netback price before we go to spot LNG sales.

And so for us, from an economic standpoint, of course, that's -- we're indifferent to things that bring us the same netback.

There's been some noise in the press about LNG operators selling spot cargoes at netbacks that are less than domestic prices.

And obviously, you know us well enough to know we wouldn't do that.

We're not in the business of selling our gas for less than whatever the best is in the marketplace.

But what you have also seen just here today in the press where we announced our latest domestic gas sales.

So this is an example of where we had some gas that could have gone spot and 20, 21 petajoules of gas that we've just agreed to sell into the domestic market that would have gone to spot LNG because we were able to sort of achieve those netback objectives.

So with that sale being added on, we now are north of 180 petajoules of domestic gas that APLNG will be selling into the market next year.

So in 2017, APLNG is supplying about 20% of the dom gas market in eastern Australia.

And next year, with this latest sale, we'll be just shy -- we're already, just with what we've done so far, almost up to 30%.

That's interesting.

The -- I don't know if this is public or not, but can you talk about how you calculate the netback comparability?

Well, I mean, it's reasonably straightforward.

You know what all the pieces are.

The piece some people sometimes miss when they just look at sales prices is there are significant transportation costs in Australia to get from the tailgate of our -- to get from where we're producing the gas to the market to our individual customers.

There's significant transportation distribution costs.

So that's a big -- and then, of course, you have the same thing on LNG, where you're paying to liquefy and to ship.

And so it's just getting to the equivalent netback for us all the way back to the wellhead, is the way we think about it.

Our next question is from Blake Fernandez of Scotia Howard Weil.

Al, I wanted to go back to the capital commentary that you provided.

Last quarter, I thought it was interesting.

I think you said for every $1 of inflation you were seeing in the Lower 48, you were seeing $2 to $3 of deflation globally.

It sounds like that Lower 48 increase has kind of began to plateau or flatten out.

I'm just curious on the international front, are you still seeing that deflationary trend that you're witnessing?

Or has that begun to change at all?

Yes.

The international deflationary trend has begun to flatten out as we've gone through the year.

We're not seeing as strong a deflation percentages in the third quarter as we were, say, in the first half.

So there's a little bit of an offset at the same time as I said, it's flattened out in the U.S. So those 2 are offsetting each other a bit.

We still expect, as a corporation, to be net deflationary in '17 versus what we saw in '16.

And internationally, we are still seeing deflation on subsea equipment, seismic costs, offshore rigs, support vessels, even software.

Software is another area where we continue to see some deflation this year.

And in the U.S., as I said a minute ago, with the industry slowing down a bit, we've seen a flattening.

We've actually, on some of our contracts in the U.S., even seen downticks versus where we were earlier in the year.

That's helpful.

The second question -- I'm sorry if this is a little bit detailed, but I'm kind of having trouble getting to some the 4Q guidance on production, and if this is something you guys need to follow up with after, that's perfectly fine.

But I'm just trying to kind of think about the moving pieces.

You've yet to close Barnett, so that's a net negative.

And then, obviously, San Juan and the Panhandle probably come out from a full quarter contribution, but then somewhat offsetting that is an increase of 15,000 barrels a day of the Eagle Ford.

Am I kind of addressing all of the right moving pieces there?

Yes.

Yes.

That's right.

Those are all appropriate moving pieces.

Okay.

That -- I think that kind of covers what I need.

Yes.

And so I think when you look at those numbers and compare the underlying after you adjust for asset sales and look at kind of midpoint of our 4Q number, you'll see about 4% growth versus the fourth quarter of last year.

So year-over-year fourth quarter '16 to fourth quarter '17.

You should get about a 4% number.

Blake, there's a chart in the appendix, if you haven't seen it, that takes you from midpoint to midpoint on a same-store sales basis.

Our next question is from Neil Mehta of Goldman Sachs.

The question -- first question I had was just on Libya.

I know we often think about production, excluding Libya, but it did stick its head up here in the quarter.

So I was curious what you're seeing out there and any thoughts in the sustainability of it in what's obviously a very volatile region.

Okay.

Libya is an interesting case because if you look back to last year, we averaged 2,000 barrels a day for the year from Libya, and we just did 24,000 barrels in the third quarter.

And we're currently north of 30,000 if you look at sort of what our current production rate is.

That's all on a net basis.

So that's over 200,000 on a gross basis current production.

We lifted 3 cargoes from Libya in the third quarter, so that's 10 that we lifted in the first 3 quarters of the year.

And in fact, we're lifting another one here just recently, so we're up to 11.

We've got 6 workover rigs active in Libya that's helping drive some of this production increase.

So it's getting to be a more significant number, I guess, particularly year-over-year in our bottom line production.

Yes, that makes sense.

And then, the follow-up is, I recognize you guys make very clear that you're price takers that plan for a lower for longer crude price environment.

But where do you think we are in terms of the crude rebalancing?

We obviously have seen products cleanup and OPEC compliance has been good, and some of the hyper U.S. growth expectations have been moderated, but curious in terms of how you guys are thinking about the market evolving here.

Yes.

I mean, we're seeing the same numbers you are of watching things tighten.

And also, it's not hard to predict with the rollover in U.S. rigs that, that's going to give a different U.S. production profile than I think people were expecting a quarter ago.

That's also going to tighten things up.

But there's also such large wildcards with things like the Libya that we're just talking about, the latest things going on in Kurdistan, et cetera, et cetera.

There's a long list of things you can name there.

So for us, you'll see at our Analyst Day here in a few weeks that we're just very focused on not counting on anything good happening for us there on prices, but really, keeping our company structure, keeping things tight and disciplined to where we continue to get the results you've seen out of us in the last 4, 5 quarters where we can get good financial results at prices below where we are right now.

Our next question is from Roger Read of Wells Fargo.

Just trying to stick with the let's not talk too much forward look a little bit back.

You mentioned APLNG running 110%, the breakeven is in that, I think, $45 to $50 range.

I was curious though if you can run at those kind of levels, and it seems typical in these LNG projects, to sort of have a base assumption and then exceed it.

Does that lower the breakeven by a material amount?

I mean, in other words, can APLNG get more competitive as we go forward?

Well, I mean, I think the kind of breakevens we've been talking about are based on the performance that we are -- have been achieving for a while now.

So the 110% performance is not news.

And so that's baked into our numbers, really.

So as good as it gets?

No, you don't have to answer that.

I'm just...

I wouldn't say that.

I'd hate to leave that impression.

We actually have a lot of work going on to continue to drive down our operating costs and our sustaining capital cost on the upstream side of the project.

And so we and the joint venture have significant plans to continue to improve it.

I was really just trying to comment on what you asked about the extra 10% throughput.

That's something we've been doing for a while now and is built into our plans.

It's one of the things that pushes you.

It does push your breakeven down some, but you shouldn't expect a dramatic change just from that effect.

No.

I know.

With all the drilling activity, I was just -- more volume typically, a little better unit cost structure, I would imagine.

Yes.

Follow-up question.

Since I presume earlier when you were talking about the cost inflation, deflation was more on the CapEx front.

Can you give us any sort of how the OpEx side -- I know you gave the OpEx guidance number, but what are you seeing in terms of cost inflation on the OpEx side?

And is any of that a function of the non-operated part of your portfolio as well?

Yes, on OpEx side, let me just mention some of the numbers.

Our third quarter OpEx number that we just published this morning is down 15% on the adjusted OpEx that we focus on, down 15% versus the same quarter in '16.

And obviously, there's asset sales that are built into that.

If you look at the same-store sales basis and take out all that -- the asset sales confusion from that, basically, we're right on our original budget guidance, and -- but we're doing that with a couple of percent higher volumes.

So we -- our budget was originally based on a midpoint 1% volume increase.

It's at 0 to 2% range, midpoint of 1% and we're accomplishing 3%.

And so we're -- basically, we've been able to eat all the extra OpEx transportation, et cetera, that comes with those extra barrels and still meet our guidance.

So we're -- as I look forward into what we're doing there, we have -- we're certainly not done on our OpEx work in the corporation.

We have a lot of focus on it around the world.

And I expect that we will continue to see additional improvement there.

From the inflation side, the story is pretty similar to what I was talking about on CapEx, that it's a little bit to the benefit to us in '17 versus '16 so far.

Our next question is from Jason Gammel of Jefferies.

If I could just maybe follow up on the pension contribution.

Don, can you talk about what made that discretionary payment more attractive than, let's say, accelerating some further debt repayment?

And maybe, also, address the level of funding relative to the obligation?

Yes, Jason.

So I think what we're looking -- the way we looked at it is, that this was a really good way to put a portion of our large cash balance to work.

So essentially, what we're doing is moving cash from short-term low-return investments on the balance sheet to the pension fund that can invest in much longer-term, higher-yield-type returning investments.

And so it's an arbitrage there.

We compared it to -- incrementally, to reducing the next best bond retirement opportunity that we had.

And it had advantaged economics with respect to that.

And then, your other question was around the level of funding of the plan, I believe.

So with this contribution and this was to the U.S. qualified plan, it would bring our funding level up to right around 85%.

And that will be, if I remember correctly, that will be about the highest level of funding that we've had since before the spin of the company in 2012.

The liability for that U.S. pension fund would be down from a little over $1 billion, I believe, $1.1 billion before this contribution to bring it down to about $0.5 billion.

Great, very clear.

And I almost hesitate to ask this follow-up question, given that I'm sure we'll hear a lot about your premium Eagle Ford position in a couple of weeks.

But another operator did take a pretty big write-down in the Eagle Ford today and talked about how they had significantly down-spaced further than what their acreage would actually produce optimally.

So Al, I was hoping maybe you could just address it at a very high level what distinguishes your position from some of the other operators there.

Yes, obviously, I can't comment into details of the other operator's results.

But clearly, it doesn't apply to us.

We're -- we've been very deliberate in our development plans there in the Eagle Ford.

We're very tailored to the specific reservoir characteristics in the different areas.

You know that we're right in the sweet spot.

We've got a lot of running room.

You remember that map that we showed at last year's Analyst Day.

Ellen tells me it's Page 48 of last year's deck that showed...

Let me show you last year's material.

Yes.

It showed how much running room we have there.

So we really have no concerns or anything like that.

Our Eagle Ford continues to make us proud and outperform and even took a beating from Hurricane Harvey and came back pretty quickly right back up to full production.

Yes.

I appreciate that.

I think it's just useful to distinguish you from some of the other operators.

Appreciate that.

Our next question is from Guy Baber of Simmons.

Al, on the production side, you did a good job highlighting the outperformance of your base portfolio.

Can you speak to the performance year-to-date from the major projects that have been ramping up?

You gave some color on Surmont so it looks like that's getting closer to max rates.

Maybe where that is right now.

But then, Malikai as well, maybe, specifically.

Has that fully ramped up?

And then, where are we on the KBB gas ramp-up?

Sure.

The -- on Surmont, we're -- we'll be fully ramped, basically, end of the year, early next year, we'll be at our full rate.

So we're right toward the end of that.

Malikai, we are still ramping and won't hit the plateau there until next year in 2018.

And KBB has been kind of an odd story because we've had gas availability from our side for a long time, for several years, and have been limited by non-owned third-party infrastructure that has had some pretty significant maintenance issues and which have slowly been getting lined down.

And so we are seeing higher volumes from KBB in recent weeks actually and expect it to be part of what allows us to grow volumes a bit into the fourth quarter as we've been basically allocated a higher rate from KBB into MLNG.

And so I think that year-over-year, we'll see higher rates again in '18 versus '17 for KBB because of that effect.

Yes, that's helpful.

And then, my follow-up is on the capital spending side, you highlighted some of the variables that might contribute to a bit higher CapEx going into 4Q, with higher Lower 48 activity a partial driver there.

Are there any specific offsets you would call out into next year?

And I'm thinking specifically about if there's any noteworthy major project longer-cycle spend, maybe associated with Surmont or other projects that's set to fall off on a year-over-year basis?

Or if lower CapEx going forward is just going to be a function of you guys continuing to get more efficient and capture deflation where you can.

Yes, it's -- there's a lot of moving parts there to answer that question.

And so we're going to have a segment, in 2 weeks at the analyst meeting, where we give you some fairly detailed plots and charts that show you how all those pieces add up from both a capital perspective and a production volume perspective.

So I think that's probably the best way to answer that, is to wait for those charts.

Our next question is from Pavel Molchanov of Raymond James.

Just 2 quick kind of housekeeping items.

As we watch spot LNG prices in Asia picking up, can you remind what portion of your APLNG exports are fixed-price versus what's being sold in spot market?

Well -- yes, this is Don.

From APLNG, 100% of the gas from APLNG that's not dedicated to the domestic market is contracted under long-term contracts to customers in China and Japan.

Now those customers have a right to reduce their obligation by up to 10% in any particular year.

And so that can make as much as 10% of the capacity available for the spot market.

Got it.

And then, on Libya...

And I can add to that.

In fact, we -- our customers have taken that downward quantity tolerance for 2018, and that's what's made sort of these spot cargoes available in '18 that we've been in this discussion with the government about making those available as domestic gas.

Right.

Understood.

And then on Libya, so you're up to 24,000 BPD.

If you were to get back to pre-revolution, pre-2011 normalized levels, how much higher would that number get, all else being equal?

Yes.

If you go back, we were in the 40,000 to 50,000 range net back when -- if you can ever define normal there again, that's the kind of rate we were at.

And our final question is from Michael Hall of Heikkinen.

A lot of mine have been addressed.

But I guess, quickly, on Surmont, following up on that from a prior question.

Do you have what that averaged during the third quarter, in terms of contribution from Surmont?

In terms of the volumes?

Correct.

Yes, 63,000 barrels a day was the 3Q number from Surmont.

Okay.

And as we think about kind of maintenance capital levels for Canada coming out of the year after Surmont's effectively ramped up, how should we think about that, if you could provide it.

You're thinking about the maintenance CapEx, you mean?

Correct.

Yes.

Yes.

So I mean, it's down to a pretty low level.

I'm not sure I've got a number handy, but it's -- the point that we've gotten to now and particularly with some of the technology work we've been doing to improve things, the need to spend CapEx that are sustaining is down to a pretty low level.

We're going to show you at our analyst meeting in a couple of weeks some other kind of margin improvement projects that we have planned there that are low dollar.

But we'll show you kind of how that adds up.

So there is still some work to be done there at Surmont, given current market conditions on the diluent side, et cetera, to allow us to improve our margins there.

And we'll talk about that a little bit in a couple of weeks.

Okay.

Great.

And then, as I think about, I guess, fourth quarter capital spending levels, is there anything kind of one-off or one-time within that spending level that we should not think about as recurring?

No, I'm not expecting any big lumps, like a dry hole expense or any of those kind of things in the fourth quarter.

I think that it's -- I can't think of any lumpy one-off type stuff.

Thanks, Michael.

And Christine, thank you very much.

If you would close this out, we look forward to seeing everybody in a couple of weeks.

Thanks for your time today.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

Forward-Looking Statements

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