康菲 (COP) 2018 Q2 法說會逐字稿

Welcome to the Second 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, and thanks to our participants for joining our second-quarter earnings call today.

Our presenters will be Don Wallette, 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 deck.

During the call, we will make some forward-looking projections, and results could differ due to the factors noted here and also in our periodic filings with the SEC.

One more final administrative point.

We may also refer to some non-GAAP financial measures today, and that's really to help facilitate comparisons across periods and with peers.

For any non-GAAP measures we use, a reconciliation to the nearest corresponding GAAP measure can be found on our website.

And with that, I'll turn the call over to Don.

Thanks, Ellen.

Good morning all.

I'll start on Slide 4. I'm going to go quickly through this but want to add some color to a few of the points on the slide.

Starting on the left, solid operating performance and higher oil prices have allowed us to continue advancing our strategic priorities.

During the quarter, we completed our debt reduction program and achieved our $15 billion debt target.

We've reduced balance sheet debt by nearly half since 2016.

We're in a strong financial position now and we're happy with our balance sheet, so we don't plan to reduce debt any further.

Achieving the debt target allowed us to consider additional shareholder distributions, and you've seen our recent announcement where we plan to increase our buybacks this year to $3 billion.

And going into 2019, we'll have a remaining authorization to repurchase up to $9 billion of shares over the coming years.

This highlights our expectation that buybacks will continue to be an important component in addition to dividends of our shareholder distribution philosophy.

Moving to the financial column.

Our adjusted earnings were $1.3 billion, the ninth consecutive quarter of adjusted earnings growth.

But I want to draw your attention to cash flow.

Cash from operations in the quarter was $3.2 billion.

Cash flow has been running high relative to the sensitivities we provided last November.

The main reasons are that production is higher than we projected, and the increases in production are coming mainly from high-margin unconventionals that currently have no cash tax.

Also, interest expense is lower as a result of the accelerated reduction in debt.

So last November, I gave you a reference point for 2018 that at $50 WTI, we'd generate CFO of about $7 billion, which at $65 WTI translates to a bit higher than $10 billion.

That's turned out to be too low so we've recalibrated in light of our current outlook.

The new reference point I'd give you is that at $65 WTI, we'd expect to generate CFO between $11.5 billion and $12 billion, depending on differentials.

The cash flow sensitivities in the appendix remain unchanged based on this new reference point.

And if you apply these sensitivities based on forward prices using that reference point, then you'll see that it implies a CFO estimate for 2018 of over $12 billion.

I think that the market hasn't yet fully appreciated the cash-generating capability of our assets.

So we wanted to provide an update that better reflects the company's performance and considers the higher price environment.

And by the way, just to refer back to our financial strength, based on these estimates, our net debt to CFO leverage ratio would be a little under 1.

Moving now to the far right column, you'll see a number of our operational milestones achieved during the quarter.

Al is going to cover these when we get to the operational review and also take you through the adjustments we're making to the guidance items.

Let's go to Slide 5 and I'll touch on the quarter's earnings.

Sequentially, earnings were up almost 15 percent, driven by realized prices and partially offset by higher operating costs associated with seasonal turnarounds and maintenance activity.

Compared to the year-ago quarter, adjusted earnings improved by over $1.1 billion, primarily driven by a 50 percent improvement in realizations.

The table on the bottom-right side of the slide shows a comparison of year-over-year adjusted earnings by segment.

The table demonstrates not only the strong benefit of our Brent-linked portfolio, but also the benefit from having a large diversified portfolio, which mitigates the corporate impact of operational disruptions and regional market dislocations.

If you turn to Slide 6, I'll wrap up with a look at cash flows during the quarter.

We began the quarter with cash and short-term investments of $5.5 billion.

We've talked about the strong second-quarter cash from operations.

So moving to the right, the first red brick shows $2 billion of capital.

And this includes the $400 million Alaska Western North Slope bolt-on acquisition.

Next, we used $2.1 billion to retire debt, which achieved our debt target of $15 billion.

We paid $300 million of dividends and repurchased $600 million of shares, and ended the quarter with over $4 billion of cash and short-term investments.

The bottom line, cash from operations exceeded Capex by $1.2 billion.

This free cash flow more than funded the dividend and share repurchases, which together represented a return of capital to shareholders of about 30 percent.

Now I'll hand the call over to Al to cover operations.

Thanks, Don.

I'll provide a brief overview of our secondquarter operations highlights and discuss our outlook for the remainder of the year.

Please turn to Slide 8.

Total production for the second quarter, excluding Libya, averaged 1,211 thousand barrel oil equivalent per day.

This result was just above the high end of the second-quarter guidance range, primarily driven by Eagle Ford and Bakken outperformance, but also benefiting from an additional 5,000 barrels per day from the Western North Slope acquisition.

Underlying production grew 5 percent on an absolute basis and 34 percent on a per debt-adjusted share basis.

We had a good quarter in our Big 3 unconventionals.

On a combined basis, they averaged 292,000 barrels equivalent per day, resulting in 37 percent growth year-on-year, and we exited the quarter at over 300,000 barrels a day from the Big 3, achieving this milestone well ahead of plan.

In the second quarter, by play, Eagle Ford averaged 182,000 barrels per day; Bakken 82,000 barrels per day; and the Delaware averaged 28,000 barrels per day.

As you know, we have seasonal turnarounds in the second and third quarters each year.

Our second-quarter shutdowns were completed safely, on budget and on time.

Our third-quarter turnarounds are underway and also going according to plan.

In Canada, an outage of third-party synthetic diluent resulted in a production curtailment late in the quarter and continuing into July.

We're actively working to mitigate the impact of these kinds of third-party outages by implementing the capability to run condensate as an alternative to synthetic crude oil diluent.

This capability will not only reduce the amount of diluent required but also improve our ongoing flexibility and our netbacks.

During the quarter, we made good progress on multiple conventional projects in Alaska, Asia Pacific and Europe.

We also announced the completion of the Western North Slope bolt-on.

And in July, we announced the Greater Kuparuk and Clair transactions.

Once we receive regulatory approval, these transactions will further core up our Alaska business to give us flexibility to manage the pace, level and timing of our future investments there.

And last week, we announced that our 2018 winter drilling season in Alaska confirmed gross discovered resources of between 0.5 billion and 1.1 billion barrels oil equivalent with significant upside -- undrilled upside remaining.

We also announced that we now expect to develop Willow as a stand-alone hub.

Detailed work is underway to evaluate development options and to plan the 2019 exploration and appraisal drilling program.

So another quarter of strong execution.

Now I'll discuss the operations outlook for the remainder of the year on Slide 9.

We're adjusting our 2018 operating plan to account for our higher production performance and the significantly higher prices we're continuing to see compared to our reference price of $50 a barrel WTI at budget time.

Our capital guidance for the year is being adjusted to $6 billion, excluding acquisitions.

We've continued to maintain our discipline with no net increases in our operated drilling and project scope.

The roughly 10 percent capital increase is driven by three reasons, all in the Lower 48: 1) increased partner-operated activity; 2) increased efficiency at operated assets, leading to more completions with the same number of rigs; and 3) inflation.

The partner-operated increase reflects a business decision to participate in strong-return projects and comes with increased production.

The increased operated efficiency leading to additional completions and additional wells online is a contributor to our operated production coming in above expectations.

The inflation impact is actually less than we would have predicted based on a $15 to $20 move above our assumed $50 oil price, but that's because we continue to offset some of the pressure in the Lower 48, both with our supply chain strategy and from other parts of the business.

With wider differentials in Midland, we're taking advantage of our flexibility and stronger LLS pricing in the Gulf Coast to shift an unconventional rig in the Delaware Basin to the Eagle Ford.

And we're also laying down our one conventional rig in the Permian Basin.

Our adjusted capital plan is also bringing incremental production with it.

Since the beginning of the year, we've increased our full-year production guidance by 25,000 barrels a day at the midpoint.

Our new full year production guidance is 1,225 thousand to 1,255 thousand barrels equivalent per day.

These are all good-margin barrels and they'll contribute to strong momentum going into 2019.

Based on this updated guidance, we expect to deliver 6 percent underlying production growth in 2018.

Including our upsized share repurchases and our debt repayment, that translates to 9 percent production growth per share and about 20 percent production growth per debt-adjusted share.

Our third-quarter production guidance is 1,215 thousand to 1,255 thousand barrels per day, reflecting the continuation of our turnaround season.

The guidance range also accounts for a partial quarter of continued third-party outage in Canada, which is offset by additional high-margin growth from the Big 3 unconventional plays.

We have some catalysts coming before year-end that will also provide good momentum going into 2019.

Before the end of the year, we expect to achieve first production from GMT-1 in Alaska, Aasta Hansteen in Norway, Bohai Phase 3 in China, Clair Ridge in the U.K. where we still retain a 7.5 percent interest, and the final phase of Bayu-Undan development in Australia.

On the exploration front, we're continuing our appraisal work in the Montney, and we expect to spud the first of a four-well Louisiana Austin Chalk program in the third quarter.

Finally, planning is underway for the 2019 Alaska exploration season.

Our priority will be on further appraising and testing the Greater Willow Area in order to advance our development plans.

We had a strong first half of the year, and our entire team is focused on successfully executing the second half of our 2018 operating plan.

Now I'll turn the call over for Q&A.

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

First question is for Al.

Maybe you could just elaborate a little bit more on the unconventional side of things.

Obviously, you've hit your target here two quarters early.

So if you could maybe refresh that for us at a high level.

And then maybe also just give us some color because you are shifting some rigs around.

So to the extent Eagle Ford's taking away from the Permian a little bit, and I guess, more broadly how this fits in with the 2020 plan you outlined back in November.

Okay.

Thanks, Phil.

I guess, we -- as you mentioned, we did -- I guess, back in January on the 4Q call, I indicated that we thought the Big 3 unconventionals and Lower 48 would hit an exit rate above 300 by the end of the year.

And then on the last call, I foreshadowed that it looked like, based on our latest vintages of completions and the efficiencies we were seeing, that we were going to hit 300 considerably earlier in the year.

And then what ended up happening is we actually had our first day over 300 was back in mid-May.

So we -- both May and June were above 300.

So it did come quite a bit earlier and really driven by all the things you hear us talking about in terms of improved efficiency and effectiveness of our completions.

So I also said last quarter when we were -- in the first quarter, we were up 20 percent year-over-year on Big 3 production.

And I told you, I didn't expect you to be impressed by that and it really wasn't a number we were proud of because we had promised 22 percent or better.

So now we're at 37 percent.

Second quarter, we were up year-over-year 37 percent on production in the Big 3. And I think that is a number I'm proud of.

That number is more like what you should expect for a full year kind of number.

I think we're going to beat the 22 percent by that much.

So 22 percent to 37 percent, an extra 15 percentage points of growth from the Big 3 in 2018 is pretty significant progress, I would say.

And I guess, maybe if you could just -- if you have any color on this, how you would tie this into the outlook you had going out to 2020 from the Analyst Day for your unconventional business.

Obviously, it's huge growth plan in terms of the Permian but you're slowing a little, but Eagle Ford as well ahead of your expectations.

Yes.

So with the one rig that we're shifting, so we had six rigs.

The plan that we laid out at the Analyst Meeting for activity in the Big 3 was an 11-rig program.

And that plan was six rigs in the Eagle Ford and three rigs in the Delaware and two rigs in the Bakken.

And so now what we're doing is shifting one of those three Delaware rigs to the Eagle Ford, so we'll have seven in the Eagle Ford and two in the Delaware.

And so that will shift volumes a little bit as well obviously, particularly as we go into next year.

And we expect that the wide Midland differentials are going to last through next year.

And so I expect that this shifting of that rig, still totaling 11, will carry into next year and will impact our volumes.

And we'll update on that when we set our plans for 2019.

But obviously, with this considerably higher growth rate we've had, even just running the 11 rigs -- you remember, our decoder ring from the Analyst Meeting is obviously getting ready to change again.

We've had another year of increased efficiency, and so that is allowing us to do more with the same number of rigs.

And so I think you can expect that you're going to see a continued improving story there.

I guess, one more thing I might add that's a piece of this story is that you -- we've talked about our different vintages of completions at the Eagle Ford.

And when we laid our plan out at the Analyst Day last November, that was based on what we called Vintage 4 completion in the Eagle Ford.

And -- but we had just started using Vintage 4 in the third quarter of last year, and we can see it was quite a bit better than Vintage 3. But by Analyst Day, we hadn't had enough runtime to see just how good it was.

So I think that is one of the key things that's allowing Eagle Ford to outperform is that the Vintage 4 completions are giving us better performance than what we had assumed at the time of the Analyst Day.

Of course, we're now testing Vintage 5 so we'll see where that takes us next.

When would you expect those results?

We drilled a couple of -- we've completed a couple of Vintage 5 wells, and the first one is going to come on production here in the next few weeks, so we don't have any production data yet.

But it's coming soon.

Our next question is from Neil Mehta of Goldman Sachs.

I want to start on the cash flow sensitivity because I thought that was incremental.

Could you rattle through those numbers again of what you moved, the old -- the baseline to and from -- and the anatomy of what changed in that cash flow sensitivity?

How much of the higher baseline that we should be anchoring to is a result of production versus cost versus price realizations.

Helping us break down that framework would be helpful.

This is Don.

I just want to address your first question on the math that I went through in the opening section.

But I think in November, what I was referring to, as I told you, that based on our outlook of $50 WTI, we would expect $7 billion of cash from operations.

And so the new baseline I was giving you moving the price up to $65 WTI.

Now we're seeing that at between $11.5 billion and $12 billion, where as if you had used the November reference point and applied the cash flow sensitivities that we've published, you would have only come up with about $10 billion.

And so we've noticed that every analyst has been running low, and we think it's because we've given you some guidance that's out of date and that's why we wanted to update that.

So the new reference point, the new baseline, $65 WTI, we should be in the $11.5 billion to $12 billion of cash flow.

This is for 2018 that I'm talking about, right?

And so that range is there because it's going to depend on the Brent-WTI differential.

So -- and as far as the anatomy, I mean, the company has been changing at a very rapid pace.

Obviously a lot of dynamics here.

But I'd point to production consistently running above guidance and to the point where we had to update guidance today, added another 20,000 midpoint to midpoint.

So that's one reason that's driving the higher cash flows.

The other is where we're getting that extra production.

And these are the high-margin unconventional wells.

They're the low cost, the high netback.

But also importantly, for the time being and for the next few years, it's no cash taxes.

So tremendous contribution to operating cash flows.

And then the other area that's contributing is that we paid the debt down a lot earlier than we expected, 1.5 years early.

And so our interest rate has come down quite a bit and that wasn't built into -- that acceleration wouldn't have been built into the previous reference point or sensitivities.

I appreciate the color on that, Don.

And then just another item where I think we've gotten some questions this morning on the $500 million increase in Capex, and this call you've done a good job of breaking it down to three buckets: completion, inflation and partner-operated volumes.

And you said cost inflation was a relatively small piece of that $500 million increase.

Can you kind of help us frame out the different buckets here?

And then what does this portend for 2019 and the go-forward Capex?

Okay.

Sure, Neil, I'll take that one.

As I said, the $500 million increase to Capex is all in the Lower 48.

But it's not a sign that we're ramping up our drilling activity and our Capex to take advantage of higher prices.

I certainly wouldn't characterize it that way.

We've maintained discipline on our operated activities, and we really are exactly following the plan that we laid out at the Analyst Meeting in November.

As our partner-operated ballots have almost tripled versus last year, and as we've had more completions and more wells online due to our increased efficiency and our faster drilling times, and as inflation due to higher prices have kicked in, we could have reduced our activity to offset and restrain Capex and keep it at the $5.5 billion.

But given that, as Don was just talking about, these are very good high-margin volume adds this work, and because we've been beating all of our targets for all our priorities, increasing the dividend, reducing our debt early, above target on shareholder distributions, we're above target on improving our ROCE and our CROCE as we talked about at the Analyst Meeting, and finally, given that our supply chain strategy has allowed us to continue to access our contracted services at acceptable prices.

For all those reasons, we've chosen not to try to offset or reduce activity, and we've allowed this 10 percent increase in the budget.

So let me give you the pieces.

The operated-by-others piece is $0.2 billion.

And that's primarily in the Bakken is the biggest area where we're seeing that.

The increased efficiency and increased completions in wells online is also about $0.2 billion.

And that is something we're seeing that I would characterize that as about 2/3 in the Eagle Ford, 1/3 in the Bakken.

And then inflation, the last piece, is only about 1/10 where, as I said earlier, seeing offsets both from our supply chain strategy and also from our international business that are keeping that number quite a bit smaller than you might expect.

Earlier in the year, we said that in a $10 higher, a $60 world, we would expect an extra $200 million to $300 million of Capex due to increased inflation.

And of course, we're in an even higher price world than that.

But we've managed to keep it down to more like $100 million.

And so it's actually, inflation is lower than what we would have projected with our models for this price environment.

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

Al, this is kind of a wildcard question, I guess, given the changing activity in Delaware.

But I'm just curious, what happens to the production rate in the Delaware with the lower activity?

And would you still consider, given everything else in the portfolio, that Delaware is still core to ConocoPhillips?

Yes, I think the Delaware -- obviously, we still haven't gotten to a full manufacturing mode there and it's relatively early days for us.

We don't see these big efficiencies going across time like we have in the places where we're in manufacturing mode like the Eagle Ford and the Bakken.

But we view the price situation, the differentials there as a temporary situation obviously.

And so we have flexibility and we should exercise it.

We are -- there's no reason to try and spend money to grow production hard into that kind of headwind when you have the flexibility that we do.

And when adding an extra rig in the Eagle Ford instead, moving that rig to the Eagle Ford is that is prime acreage we'll be drilling with that rig.

And remember, that's less than $2 a barrel lifting costs and super high margin so just makes easy sense for us.

The reason that we're keeping two rigs in the Delaware, frankly, is that we do have drilling that we still need to do to maintain our leases there.

And we need two rigs really to do it efficiently, to continue to drill quad pads and still maintain our lease obligations.

We really need to run two rigs.

I mentioned earlier also that we have taken a fourth Permian rig.

It's not Delaware, but we had one Permian conventional rig and have laid it down at this point and won't run any rigs in the Permian conventional for the rest of the year.

So just to be clear, is Delaware still a core part of the ConocoPhillips portfolio?

Yes, absolutely.

We just -- and I think we'll still roughly hit our -- even with one less rig, I think we'll still roughly hit our production number for 2018.

Obviously, it will impact 2019.

We'll have the Eagle Ford volumes in 2019 will be higher and Delaware volumes lower than what we have in the -- at the time of the Analyst Meeting.

My follow-up if I may is, first of all, as Andy will tell you, I'm going to take exception with Don's comment about every analyst and the cash flow.

My numbers no longer look stupid, so thank you for that.

But I do want to ask a question, Don, about use of cash because clearly, at that run rate, you're generating a ton of cash beyond even your buyback plan.

And I guess, what's embedded in my commentary is the Venezuela situation, the CVE equity plus the strong cash flow.

What do you think is a good run rate and the potential -- maybe an update on Venezuela potentially from a -- potential for you to get proceeds from that and redeploy them to the buyback as well.

How should we think about that going forward?

Well, the -- were you talking about the run rate on the buybacks, Doug?

Yes.

It's really because you've got organic cash flow, but then you've got the Cenovus stock and then you've got potentially settlements in Venezuela.

And then obviously, it looks like there's a wall of cash potentially over the next two or three years if oil prices stay at these levels.

So should we look at a $3 billion annual run rate?

Well, I can't give you guidance on the run rate.

But you know that basically what our philosophy is, which is 1) we're making sure that we meet or exceed our targets on shareholder distribution, as you know, as a percentage of CFO.

You know that we want to be competitive with the majors on distribution yield and we want to be distinctive to the E&P peers.

And you know the philosophy on dollar-cost average and we try not to time the market.

We want to be in the market at a reasonably steady rate over time.

We bought back $3 billion of shares last year.

We're going to buy back $3 billion of shares this year.

But it really doesn't suggest anything as far as 2019.

And we'll just have to see what the environment is.

But I agree with you, Doug.

I mean, at these current prices, we're generating a ton of cash flow, and we've got these other things out there like you mentioned, the Cenovus stock that we're not going to hang on to forever.

So yes, there's going to be a lot of choices and a lot of opportunities going forward.

You asked about the Venezuela situation.

There's not really much...

Yes, I don't want to hog the call but obviously, there's been some obviously, a lot of news around this and more to come probably.

I don't know if there's any realistic chance you get any get cash from that in the near term but your perspective would be -- your perspective would be appreciated.

Well, like I said before, we intend to recover what's owed to us fully.

And we're -- as you've seen, we've been fairly aggressive and will be persistent in that.

And I can confirm what the head of PDVSA and the energy minister said a few weeks ago publicly, that PDVSA and ConocoPhillips are in discussions and that's accurate.

We are in discussions.

But I really don't have anything further to add to that.

Our next question is from Doug Terreson of Evercore ISI.

Al, just wanted to clarify the point that you made on spending a minute ago, meaning while you guys are only spending about 30 percent or maybe even less than 30 percent of what you were spending a few years ago and still a disciplined plan, I just kind of wanted to get your perspective on how the three factors that you talked about that drove the increase in spending are trending, meaning are they becoming more onerous, less onerous or about the same?

Or put differently, Al, do you consider them to be manageable depending on the economics of the wells, meaning, are the economics so positive that this is spending that you want to do and the factors really aren't something that you can't offset somewhere else anyway.

Yes, I mean, I've -- the word onerous doesn't come to mind for me because I -- I mean, we have flexibility.

This is money that is really bringing big benefits with it.

And so we think shareholders want us to spend this money.

Let me -- maybe it would help if I talked about our 2018 volumes beat and how that relates to the Capex and kind of tie those two together.

We've -- since the -- since our original guidance during the 4Q call back in January for the year, we've increased 25,000 barrels a day on midpoint, so our midpoint's moved from 1,215 thousand to 1,240 thousand barrels per day.

And there's just a few big pieces that kind of drive that.

The -- you know about the negative 20 that we have at KBB from the third-party pipeline outage.

That negative 20 is -- there's a lot of 2s and 3s and 4s but leaving those aside, the big numbers is roughly offset by plus 10 in Europe that you've heard me talk about before where we're having a good year in Europe on our base production there and our uptime, and about plus 10 from acquisition, A&D kind of activity.

That offsets that 20.

So then that takes you back to 0. The plus 25 is all coming from the Big 3, really from the Big 2. It's plus 15 in Eagle Ford and plus 10 in the Bakken.

And so you can do the math and see that we get a lot of cash flow from that extra 25 from those very high-margin barrels.

So where does that 25 come from?

It's roughly 1/3, 1/3, 1/3, matching up with some of the same reasons that drive our Capex.

One-third of that extra 25 is coming from partner-operated primarily in the Bakken.

Actually the number is -- we're getting about an extra 7, we think, in 2018, from the higher OBO spend.

And that number is held down by partial-year effects.

You're spending the money during calendar 2018 so you get 7. But we would expect to get about twice that amount of increased volume in '19 from this extra $200 million of OBO spend so it's very effective money.

It varies, but generally speaking, these ballots, these partner ballots are typically 30 percent IRR at $50 WTI or better, and so it's that kind of investment.

And then the next third is on wells online on the operated side.

So this is the higher efficiency.

It's about 2/3 Eagle Ford, 1/3 Bakken.

We're getting about a plus 9 there from that extra $200 million that we're spending on completions.

And we could -- when we see we're more efficient, we're drilling more wells with the 11 rigs, we could build DUCs.

We could lay down a rig or two.

But we are -- we don't think that's smart.

We drill a well, we think you should complete the well.

These are great wells.

And so that's an extra 9 there.

And then the last 9 or so that makes the 25, the last third, is really [free].

It's from the thing I was talking about earlier of the Vintage 4 completions in the Eagle Ford outperforming.

All of that 9 is really coming from the Eagle Ford.

So that's how you get the plus 15 in the Eagle Ford, the plus 10 in the Bakken, it's those kind of three effects.

Okay, that's very helpful, Al.

And then also on Greater Sunrise, there was an agreement recently about maritime boundaries which suggests that we're having progress on the next phase of that project but there's a lot of crosscurrents, too.

So I wanted to see if you can give us an update on the status of that project and specifically, what ConocoPhillips needs to see for this project to progress over the next several years.

I'm sorry.

I missed the very beginning.

You're talking about Sunrise project?

I was, yes.

Yes, yes.

Okay, well, there was progress on maritime boundaries.

That part's true.

And -- but in order for Sunrise to move forward, the governments involved -- there's really two governments involved in Sunrise still even with the new boundaries, have to reach an agreement to some kind of reasonable development plan that will be economic.

And there -- it is one of the potential competitors to backfill Darwin.

But one of the two governments isn't interested in that option right now.

And so Barossa has moved ahead, entered FEED about a quarter ago, and is in the lead position for that Darwin backfill.

And that's going to make it difficult for Sunrise to move into development anytime in the near future.

It's the way the government wants to develop it makes it an uneconomic project.

And so something is going to have to change there before it's going to move forward.

Our next question is from Paul Cheng of Barclays.

Al, you talked earlier in talking about the KBB.

Is there any update or are we still expecting by year-end that could respond or that being put out further now?

Yes, at KBB, in the new -- volumes guidance we gave a little while ago, we're assuming that KBB is essentially down for the rest of the year and that we don't get those volumes back.

There could be -- there has been steady progress on the repair work, and so there could be, say in the fourth quarter this year, some volumes for testing the line once they're ready to get back into some kind of operating mode where they have a test mode for a while.

But we're certainly not counting on that.

Right now we're just assuming that we don't get any significant uptime out of that line between now and the end of the year.

I'm actually -- I think the other way, that was the risk that they won't even restart by year-end and (inaudible).

Oh I see.

Well, yes, there is a risk of that.

But do you think it's a big one?

I mean, when we're looking at the next year, should we assume that KBB is back up?

Yes.

I mean, I think we'll address that as we get further in the year and get ready to put out late this year what our numbers are for 2019 so it's a little early.

But I think the signs that I see, of course, it's third party.

We have no ownership and no control or direct knowledge really.

We're just providing some technical assistance and so we get some insights.

It looks to me like it is progressing well on schedule to be back up by the first of next year.

So I don't think it's a big risk but there could still be surprises and so it certainly is a risk.

And in your latest full-year production guidance comparing to last quarter, you're up about 15,000 barrels per day.

Is that billion any of the gain from the recent asset swap deal like BP or that purchased from Anadarko?

Yes, it's actually up 20,000, Paul, versus the midpoint to midpoint from last quarter.

And no, we're not including anything.

The BP deal would actually be about a plus 30,000 on a full year if you included it.

But that's waiting on regulatory approval, which we are not assuming any volumes from that in these numbers.

Okay.

So this morning, this organic is not related to M&A activity?

Well, there is the WNS deal, which one quarter ago, had not gotten regulatory approval yet.

We got regulatory approval in May.

And so we have -- so we have included those volumes now in the year-end number and that's about a 7.

Okay.

So now of] the 15 -- now of the 20 is 7 is that.

Yes.

And the next two is probably for Don.

Don, on the cash return and you guys gave 20 percent to 30 percent target payout, that's probably based on a much lower price range that you guys using.

And with the price range, for argument's sake, if we're going to such thing as 70 to 80 should we assume that, that range will be changed also, would be higher?

Well, no, I don't think necessarily so, Paul.

I think the 20 percent to 30 percent is still good but we still kind of consider that 20 percent to 30 percent to be sort of a minimum target.

We exceeded that by a great amount last year, and there's a good chance that we'll exceed that this year.

I kind of hope not because it means our cash flow is even stronger than what I had suggested earlier.

Our next question is from John Herrlin of Societe Generale.

Just some quick ones for Al since so much has been asked.

With the Eagle Ford, is all the activity new drills or are you doing any re-completions?

That's number one.

Number two, with the Austin Chalk, is that a first-quarter postmortem, more or less, given the third-quarter start?

Okay.

On the first question, I mean, the Eagle Ford is really -- the numbers are driven by new drills, but we are doing some rig re-completions, particularly in situations where we do what we call defensive refracs, where we have an area, where we have a pressure-depleted zone and we want -- and we're drilling a new child well next to a parent well, that sort of thing.

But that's not a key driver in the volume speed, but there is some of that activity going on.

And then on the Louisiana Austin Chalk, we have a four-well -- one-rig four-well plan for appraisal.

And the first well, we expect to spud probably in September.

So yes, I think it'll be well into next year, maybe the first quarter or maybe -- might even not be by then before we have an assessment -- have drilled and completed and assessed all four of those wells and have a report back from you -- for you.

Okay.

Last one for me, Al.

You mentioned your vintages of completions with the Eagle Ford.

Clearly, you're getting more recovery.

What about the IP decline rates?

Is it flattening at all for you or is it still the same?

Yes, I mean, we are getting higher IPs and when you get higher IPs, you typically get a higher decline rate early on also.

But we're -- but part of what we've learned from those wells that we didn't know back at Analyst Meeting time when we only had a few months of runtime with them is that we are getting a better overall profile as well.

And so that's helping us with our production.

That's the kind of thing that's driving that extra 9,000 barrels a day from the Eagle Ford.

Our next question is from Alastair Syme of Citi.

I just have a very quick question for Don.

On the clarification around the cash tax.

Did you say you think probably two years will be a good estimate for using up the tax position in North America?

Alastair, that is really hard to try to forecast.

A lot of moving parts in especially prices.

So I think the way that we're looking at it now, if you assume constant prices, like 2018 prices continue going forward, then it's probably 2020 or beyond, maybe '21, '22, somewhere in that range.

Our next question is from Roger Read of Wells Fargo.

I guess, a lot of it has been hit here.

But I was curious, APLNG, no real discussion here of that.

Maybe how that fits into the cash flow sensitivity, maybe remind us how the dividends get paid out there.

And does the joint venture have any debt it needs to pay down before maybe cash flow could even get better out of there?

Yes, Roger.

So we ended up having the two dividend payments during the second quarter.

I talked about the first one during the last -- during the first-quarter call because we didn't record it in the first quarter but it had been declared.

And so it's going to be a subsequent event, so I felt like I needed to talk about that since it was going to be a disclosure.

So we had $105 million and then we just had the $85 million later in the quarter.

So a little bit under $200 million.

I think -- let me talk about the timing of the dividends too, because they are designed around some of the financing obligations, the payments that we make, which tend to occur -- they do occur in the first and third quarters.

So that, combined with when we're making tax payments, really point us toward the second quarter being a dividend distribution period from APLNG and then the fourth quarter.

So I think it's important when you guys start looking at the quarterly cash flows, you're going to see that $200 million or you've seen the $200 million in the second quarter, we won't see that at all in the third quarter.

So that you need to adjust your cash flows for that.

And then they come back in the fourth quarter.

And I mean, if prices stay where they are today, then we would expect similar distributions in the fourth quarter to what we've seen in the second quarter.

Now going forward, I do expect distributions to increase in 2019 even at constant prices.

And the reason for that is that the joint venture has been pretty aggressive on the upstream side, in particular this year in reducing operating costs, having a pretty significant impact there.

So next year, we'll have the full-year benefit of that plus we won't be offsetting some of that as we are this year with severance costs that are associated with the reductions.

And then the other item is that we see the potential for having -- being able to reduce the interest expense at APLNG as part of the project financing.

And so don't know how much more the distributions would be under constant pricing in '19, but they will be higher.

Our next question is from Scott Hanold of RBC Capital.

Could -- Al, could you talk a little bit about the Bakken and maybe some context on the Eagle Ford as well?

Both areas are at or near, I guess, peak net production levels for you guys.

And obviously, in the Eagle Ford, you talked about the improved generation of completions.

Are you seeing a similar type of improvement in recent completion technology in the Bakken as well?

Or is it just from that higher non-op activity level, you saw the sharp ramp there?

And a question then for both basins.

Is there -- obviously, with production at the highest level that you guys have really seen to this point, any kind of constraints there or is there plenty of capacity in those areas?

Sure.

Okay, well, we start with the Bakken.

Last quarter, remember back at our Analyst Meeting, we told you, of the Big 3, the Bakken was the one we were going to run two rigs and try to hold it roughly flat at 70,000 barrels a day.

And yet last quarter, we came in at 82,000 barrels a day.

So obviously, it is outperforming.

That's up 19 percent year-over-year for the Bakken production.

And yes, definitely, a part of that is improved completion performance and faster drilling times.

We've also made some progress here just recently on our well designs to significantly -- another kind of step change down on the cost of our wells.

And so the Bakken, that outperformance, 82,000 versus 70,000, is on the order of half of it might be coming from the OBO and maybe the other half is coming from the kind of outperformance.

And some of that OBO is from OBO outperformance as well.

In the Eagle Ford, we're up 42 percent year-over-year on the quarter.

So it's really that Vintage 4 that I talked about having a significant impact for us.

We're also continuing to drive greater efficiency there and are having more wells drilled.

And so that's a key part of that Eagle Ford outperformance as well.

It -- the Vintage 5 will -- could take us the next step up.

We'll just have to see how that turns out.

But all of this has given us strong momentum into 2019.

With the extra 15 points of growth that we're seeing here in the Big 3, you can see how that's going to give us a really strong exit rate and carry us strongly into 2019.

In terms of the constraints, I -- we're not seeing anything with what we're doing because we're in kind of steady-state mode.

And we even had a little bit of catch-up to do on completions work in the first half and will actually have less frac crews running in the second half than we did in the first half.

So we're not running at any kind of constraints in terms of our services.

And certainly, on the takeaway-type constraints, we don't have enough production in the Permian for it to matter to us really.

We're not seeing a problem in the Bakken.

In the Eagle Ford, the issue we're getting into is that our production is growing so much faster than we expected.

We have had to sign up for some additional export capacity but there's plenty of third party available.

We've been out in the market continuing to get great prices for that.

And so we are having to add some additional commitments for takeaway in the Eagle Ford, given the higher production.

Our next question is from Devin McDermott of Morgan Stanley.

I just had a quick follow-up on some of the earlier questions on Capex.

I think the additional guidance and color on 2018 is very helpful.

I was just thinking about it in the context of the multiyear plan you laid out at the Analyst Day, which referred to roughly $5.5 billion per year as the targeted spend level.

How should we think about that in the context of the $6 billion for this year?

Is this a good new run rate number based on the current pricing environment?

How should we think about carrying that forward?

And I know I'm asking for a bit of forward guidance but any color you can provide would be helpful on that front.

Yes, let me make some high-level comments and maybe talk about the pieces as well.

But certainly, there's been no change to the philosophy that we laid out at the Analyst Meeting.

Although the Capex plan we laid out there, we clearly said was for a $50 world.

So we are going to -- we have been and are going to continue to see some inflation pressure, including the steel tariffs in the U.S., which is turning out to be a fairly significant item for us.

We spend, in the U.S. Lower 48 plus Alaska, about $300 million a year on OCTG and pipes and valves and fittings, all that kind of stuff that's made out of steel.

And coil, hot-rolled steel prices in the U.S. since the first of the year are up 26 percent even though the input cost to the manufacturers of this steel haven't changed.

And so there's been a significant move in the market.

We've been somewhat insulated from that from our supply chain position, but that is going to continue to grow on us going into next year.

So that is one piece.

We obviously haven't set our capital budget for next year.

It's too early.

And you can expect that we'll announce it in December.

But there is going to be that continued inflation pressure as we're in the higher price world.

In terms of the operated-by-others pressure, we -- I mentioned earlier that we're looking at almost triple the spending this year on these ballots versus last year.

We get the ballots in, if they look like good economics, we approve them.

That's what you'd want us to do.

In the first half of this year, we've already spent, in capital, 50 percent more than we spent all of last year on Lower 48 non-operated activity.

And so it is a significant effect.

So there's been a big shift year-to-year.

In terms of this year and the next year, I don't know that I would expect the same.

I think we'll see some -- a number of those ballots have been in the Permian area.

I expect those will probably cool off some.

And so there could be some effects the other way.

In terms of the greater efficiency and some more well completion costs, one option we would have would be to run less rigs.

We could accomplish the kind of volume with the shift in the decoder ring, we could accomplish the kind of volume goals that we laid out at Analyst Meeting that we said would take 11 rigs.

We obviously could meet those volumes now with less rigs.

And so that's an option that we'll be considering as well.

So we're working on all that and we'll have an announcement in December on what our capital plan is for next year, but that's a little bit of color anyhow on the current thinking.

Our next question is from Paul Sankey of Mizuho Securities.

Thank you very much for the Alaska trip.

It was very informative and differentiated.

Al, there's been a few moving parts.

Can you update us on the Capex outlook at a high level?

There's a couple of things.

One would be whether or not Willow is incremental.

And then also, Qatar, would that be incremental?

And then perhaps after that, if oil goes up a lot, let's say, through $100 a barrel, how would your Capex change, firstly obviously regarding how you would anticipate costs changing, but also assume that it wouldn't change your strategy?

Yes, okay.

I'm trying to keep track of the four different questions that were embedded in there, that's why.

It's Capex outlook.

Yes, so with regard to things like Willow and Qatar expansion, I mean, Willow is really outside the period.

We talked about at the Analyst Meeting, which was '18, '19, '20.

So Willow, we're anticipating a 2021 FID and that's when you would start to see significant spending.

And so that's really outside the period we've laid out.

We'll deal with that as we move forward on future-period strategies.

Qatar expansion, on the other hand, we've been told by the Qataris that they expect to pick who their partners are going to be around the end of this year or early next year.

And so if we are fortunate enough to get selected as one of the companies that participates in that, then I would expect some increased spending in this '18 to '20 period, so in '19 and in '20.

And so that would be additive to the plan that we laid out last November in the period.

And you can imagine, it's just hard to predict what those numbers would be.

It depends on what kind of work and interest we might get in the deal and that's really unknown to us now.

As far as $300 a barrel and all that...

I never said $300, hang on a second.

Can we just go back to the Capex thing?

So basically, is Qatar and Willow, I know it's outside the plan, is there anything else incremental?

I mean, for example, acquisitions, you've done some stuff, would you do more?

Well, I mean, we've had these couple of very special opportunities that I think at both Western North Slope and Kuparuk where we were able to really had a special situation with a partner that viewed the values differently than we did.

And so we could get what we thought was an advantaged deal.

And so if we can find deals like that, that are that good, we'll take them.

But they are few and far between has been our experience.

So no, I wouldn't project any more of those coming per se.

Let's see, was that -- what was the rest of that question?

We were at the $300 a barrel.

Yes.

I mean, at high prices, you're right in what you said.

Our basic philosophy won't change.

The way we think about it is the higher the oil price goes in the near term, the more likely it is that it's going to come crashing back down soon enough.

And so we do not plan to chase that sort of thing by running out and splashing out more rigs.

That's not what we're staffed to do.

It's not what we plan to do.

Our last question is from Pavel Molchanov of Raymond James.

Just one from me.

What would it take for you to add back the one Permian conventional rig that you took off?

Is it a matter of Midland pricing getting back to more normalized levels?

Or are there other dynamics you'll be watching in that regard?

Well, Pavel, actually our -- in our budget for this year, we had only planned about a half year of work in the Permian conventional.

And we had that rig running at the beginning of the year, and we've completed the pads that we were planning for it.

We had -- it was going well and the economics have been good, even with the big disconnect on prices, so we could have kept running it.

But just as part of our disciplined approach and with Capex running hot as it is, we went ahead and followed the plan that we had and laid that rig down at roughly the mid-year timing.

And so it's not a plus or minus to our capital or to our volumes one way or the other.

We do have some significant additional attractive work to do there and could put a rig back to work there next year if we choose to.

But it doesn't seem like great timing.

As long as the -- that acreage is all held by production, and as long as we have the blowout in diffs, it doesn't seem like a particularly opportune time to go do that.

We'll probably exercise our flexibility and maximize our value by putting a rig like that back to work when the takeaway problem has been solved.

Thank you.

And Christine, we'll wrap things up.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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