康菲 (COP) 2017 Q2 法說會逐字稿

Welcome to the Q2 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.

Good morning to our participants.

Welcome to this quarter's earnings call.

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 described in our periodic SEC filings.

In addition, we will refer to some non-GAAP financial measures in today's call.

These measures help facilitate comparisons across periods and with our peers.

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

Now I'll turn the call over to Don.

Thank you, Ellen, and good morning.

I'll start on Slide 4, which summarizes the progress we've made during the second quarter on our key strategic, financial and operational objectives.

These highlights underscore the magnitude of the transformation we've made as a company in a short period of time.

Starting on the left side of the chart.

The key catalyst that has accelerated our transformation is the success of our asset sales program this year.

During the second quarter, we closed the previously announced Canadian transaction and announced the sales of our San Juan Basin and Barnett shale assets.

We're on track to close these transactions in the third quarter.

Earlier this week, we also entered into an agreement for the sale of our Panhandle assets.

And we're progressing the sale of our Anadarko position.

In total, we expect to achieve asset sales of over $16 billion this year.

Earlier this year, we described plans to use most of the proceeds from these asset sales to enhance and accelerate, both our debt reduction plans and shareholder distributions.

During the second quarter, we reduced debt by $3 billion.

And we expect the balance sheet debt to be under $20 billion by year-end.

We also announced the doubling of our 3-year share buyback program.

We expect to repurchase $3 billion of shares in 2017 and another $3 billion over the course of 2018 and 2019.

We repurchased $1 billion of shares during the second quarter, a pace that we expect to maintain through the remainder of the year.

Moving to the middle column.

Our second quarter financial results were also notable.

On an adjusted basis, we realized profit of $178 million or $0.14 per share, and that's at Brent prices of about $50 a barrel.

We also generated over $1.6 billion operating cash flow, right in line with our published sensitivities.

This was the fourth consecutive quarter where operating cash flow more than covered our capital spending and dividend.

We've consistently demonstrated that we're able to generate free cash flow at oil prices in the $45 to $50 a barrel range.

And we continue to focus on further reducing our cash flow breakeven point.

To be clear, when we talk about free cash flow, we're including only operational cash flows.

We're not relying on an assist from asset sales.

This provides the clearest view of the sustainability of our spending and our resilience to commodity price movements.

Moving to operations.

We continued to run well during the quarter.

Production exceeded the high end of our guidance, and we achieved 3% year-over-year underlying growth when adjusted for Libya and the impact of closed and contracted dispositions.

Given strong year-to-date performance, we're increasing our 2017 underlying production guidance by 25,000 barrels a day.

We now expect our underlying full year production growth rate to be 2% to 4%.

At the midpoint of the updated production guidance, that would be about 8% growth on a per-share basis.

Finally, while we're increasing our production outlook, we're also lowering capital spending guidance to $4.8 billion.

Let me recap the rapid progress we've made on executing our strategy.

We've exceeded our asset sale, debt reduction and share repurchase targets.

We've demonstrated the ability to generate both free cash flow and profits at $50 Brent.

We've improved our outlook for high-margin per-share growth and we're doing it for less capital.

We're exceeding every expectation that was communicated at last year's November Investor Day.

And we believe we're strongly positioned to continue executing this differential strategy, one that is focused on discipline through the cycles, financial strength, free cash flow generation and high-return per-share growth.

If you turn to Slide 5, I'll review the quarter financials in more detail.

With Brent averaging just under $50 a barrel and Henry Hub about $3.20 an Mcf, our realized price was around $36 a barrel equivalent.

Strong operational performance drove positive earnings of $178 million.

Compared to the prior quarter, adjusted earnings improved about $350 million, with most of the improvement coming from lower depreciation and lower exploration expenses.

Compared to the year-ago quarter, adjusted earnings improved by about $1.2 billion, with the improvement being driven by higher commodity prices and lower depreciation and exploration expenses.

I should note that we are lowering our guidance on depreciation expense by $1 billion, which reflects the impact of the asset sales as well as price- and performance-related reserves increases.

Al will cover each of our guidance changes later.

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

4 of the 5 producing segments were profitable this quarter.

The supplemental data on our website provides additional segment financial detail.

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

We began the quarter with $3.4 billion of cash and short-term investments.

We generated $1.64 billion of cash from operations, which exceeded spending on capital and dividends by about $300 million.

We received cash proceeds from the sale of assets of $10.7 billion.

We used $3.2 billion to retire debt, bringing our debt balance to $23.5 billion.

You can see from the ending cash figure of $10.3 billion that net debt at quarter's end was down to about $13 billion.

I'll also note that after the quarter closed, we paid off our 2019 term loan and issued notice for additional bond redemptions.

As a result, we expect to record a further $2.5 billion reduction in debt during the third quarter.

Our balance sheet debt will stand at less than $20 billion by year-end.

The combination of dividend payments and share buybacks represented a return of capital to the shareholders of $1.3 billion during the quarter.

And we ended the second quarter with $10.3 billion in cash and short-term investments.

The majority of this cash is earmarked for future debt reduction and share repurchases.

We consider that the success we've had with the disposition program has prefunded these strategic priorities.

Now let me turn it over to Al to review the quarter's operations in more detail.

Thanks, Don.

Well, we've had another strong operational quarter.

If you turn to Slide 8, I'll cover the highlights.

For the quarter, production excluding Libya was 1.43 million barrels oil equivalent per day.

That exceeded the high end of guidance and beat the midpoint by 40,000 barrels per day.

Once you adjust for the impact of closed and signed asset sales, we had underlying production growth of 3% compared to our second-quarter production last year.

We accomplished this production increase, while continuing to maintain our discipline on capital and operating costs.

We completed all our planned second-quarter turnarounds safely on or ahead of schedule.

Lower 48 unconventional production averaged 226,000 barrels per day for the quarter.

Eagle Ford was at 128,000, Bakken at 69,000 and Permian at 16,000 barrels per day, with the balance in Barnett and Niobrara.

As I forecast last quarter, the low point for unconventional production was the first quarter, so the inflection point is now behind us as production increased 2% quarter-over-quarter.

During the quarter, we ran 12 development rigs, 5 in Eagle Ford, 4 in Bakken and 3 in the Permian, with one of these Permian rigs drilling conventional zones.

We've recently added a sixth rig in the Eagle Ford, taking us to 13 development rigs.

This was an opportunistic addition based on attractive contracting terms.

We expect to average about 12 rigs in the big 3 plays for 2017.

In Alaska, through the winter construction season, the key infrastructure components at Greater Mooses Tooth 1 were completed, so this keeps us on track for first oil by the end of 2018.

The 1H NEWS drill site facilities are also complete, and first oil is expected by the end of this year.

Excellent execution performance has led to lower cost on both of these Alaskan projects, and that increased efficiency is contributing to the lower capital spending that we've announced.

If you'll turn to Slide 9, I'll cover some operational highlights from the rest of the portfolio.

In Australia, the APLNG plant continues to perform well above expectations,and 60 LNG cargoes were loaded from APLNG during the first half.

We just concluded the 90-day operational phase of the 2-Train Lenders' Test in July, with the LNG plant operating at more than 10% above nameplate capacity and running with very high thermal efficiency and minimal downtime.

We expect the remainder of the completion certification process to be finalized in the third quarter, which will release the remaining $1.3 billion of our loan guarantees for the project financing.

In Western Australia, the Barossa-6 appraisal well was completed.

The well tested at a robust rate of 55 million cubic feet per day, even though it was choked back due to facility constraints.

The results from the Barossa-5 and 6 appraisal wells confirm the commerciality of the project, allowing us to progress our plans to develop Barossa as the backfill for the Darwin LNG plant.

In Malaysia, Malikai continues to deliver strong performance from the initial wells.

Drilling operations for the second batch at Malikai wells began in June.

This followed the successful shutdown of the KBB and Malikai fields for maintenance work.

In Norway, the Aasta Hansteen spar arrived in June and has been floated.

The project is on track, and first production is expected by the end of 2018.

So those were just a few of the operational highlights from the first quarter.

Now let's move to Slide 10 to discuss the remainder of the year.

On the left side of the slide, you can see our updated guidance.

Bottom line, our strong performance continues across the company.

We're increasing full year underlying production guidance by 25,000 barrels a day, and at midpoint, adjusted for dispositions, that's 3% production growth and 8% per share production growth.

We've also reduced capital guidance by $200 million to $4.8 billion.

Even with lower capital, we were able to opportunistically add a sixth rig to Eagle Ford and extend attractive terms for 2 rigs in the Permian.

This activity will allow us to expand cash flows, while maintaining our investment discipline.

Several slides in the appendix give more granularity on all the guidance updates.

And then finally, as a reminder, please save the date for our 2017 Analyst and Investor Meeting.

This year's meeting will be held in New York on November 8. You can expect to hear about our strategy and action, a deeper dive into the portfolio and a path to a lower breakeven and higher returns.

So now I'll turn the call over to Q&A.

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

First question I wanted to ask about was this production outlook, the 2% to 4% growth on an underlying basis on $4.8 billion of capital spending.

I guess, what I'm wondering is if I go back to last year's Analyst Day in the $4.5 billion of sustaining CapEx at the time and adjusted for all these divestitures, et cetera, I mean, how do you think about that sustaining capital number moving forward given the growth you're able to achieve?

Okay, Phil, I'll take that one.

I think that's a good question that, obviously, at the analyst meeting we'll dive into a fairly detailed analysis comparing to that $4.5 billion that we quoted before.

But I think you can make some observations from our performance, so far.

So what we said at last year's analyst meeting was $4.5 billion is about what it would take to hold us flat to maybe a little small amount of growth.

And what you can observe happening this year is that, that number did not include exploration.

So that we add another $0.5 billion or so to get to the $5 billion that was in our budget.

So if you look at our $4.8 billion number that we're using for CapEx this year, about $0.6 billion of that, we think, will be exploration.

So it's about $4.2 billion that we plan to spend this year and grow, at the midpoint, around 3%.

So from that, it's obvious that the new number, the new stay-flat CapEx is lower than $4.5 billion.

And we're in some analysis right now, and we'll talk about that more in detail at the analyst meeting.

Okay, got it.

My second question would be given there's been so many moving pieces in the portfolio, off of this new base that you talk about in the appendix, as we look ahead to 2018, could you just remind us where you feel you are with the ramp of certain projects to how much growth do you see in '18 just coming from projects that are already underway?

And maybe if you could just elaborate generally on the portfolio how you're thinking about it right now.

Yes.

Projects is becoming a smaller piece of our growth as we move forward from the past few years where we've been into 2018.

And we're -- that's another item that we're going to cover in the Analyst Day and get to show you all the detail from those smaller projects.

We do have -- as we've finished the 2 mega-projects that we were working on, Surmont 2 and APLNG, what we now have in front of us is a pretty significant stable of smaller to medium-sized projects that have more flexibility to them.

And so we'll be laying all that out in some detail, including the volumes that we'll expect from 2018.

But really, if you look at what's driving our volume momentum going forward, 2017 into '18 and '19, it really comes from our unconventional resource plays.

Our next question is from Doug Terreson of Evercore ISI.

So ConocoPhillips and the super-majors, too, have increased their investment in U.S. shale over the last several years.

There's understanding that the subsurface has grown, which seems pretty prudent to me.

But in contrast, there are a lot of public and private E&P companies that seem to be determined to drill many of their best prospects, even at low commodity prices, which seems kind of curious given the NPV profile of these wells.

So I have 3 questions.

The first for Al.

Do you agree with this broad characterization?

And second, where do you think we are in the subsurface learning process?

You guys talked about that a lot in the past.

And then also maybe for Don.

When you think about acquisitions, has -- do you think that some entities have effectively disqualified themselves from strategic action due to operating or financial practices?

Or is this theme not really relevant to the decision-making progress -- process?

So first 2 questions for Al.

Third question for Don.

Okay.

Do you remember all that, Al?

I'm not sure I remember all.

The first part -- obviously, the first one was do I agree with your characterization that a lot of E&Ps are drilling too -- are over-drilling, I guess, and -- yes, and that's the second question.

So on the first question, I think you already know the answer.

Our views on that is that yes, we think that you can drill too fast in these unconventional plays.

And we like to make sure that we progress efficiently in our technical understanding and down the learning curve before we go into full manufacturing mode and really drill things up.

And we think we get ultimately better -- much better recoveries and avoid causing damage to an area that you can't go back and fix very easily once you've changed the subsurface pressures.

And so we think that has stood us in good stead and allows us to maximize the value that we get from our acreage.

Second, with regard to where we are in the learning curve, I -- so far, despite reports sometimes of early demise, I haven't seen any slowdown in the pace of improvement in our unconventional.

So it still feels to me like we're in relatively early innings.

Maybe we've advanced to getting toward the halftime, but -- to mix metaphors between different sports.

But I haven't seen any slowdown.

I've seen the tools that we've used to continue to make progress have shifted over time.

But the kind of pace of progress has stayed pretty consistent.

I haven't seen a slowdown.

So we still got -- I still think we have a long ways to go.

Okay.

Don, you remember your question?

I think I do, Doug, yes.

And yes, I think I would agree that financial weakness or operational capability limitations should disqualify companies from being acquirers.

That should be the strong buying the weak rather than the weak buying the strong.

But in practice, I'm not sure that they do serve as limitations.

And I guess I would throw in to your mix there of strategic shortsightedness as well.

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

So guys, one of the comments in your earnings release was on inflation or the lack thereof, as one of the reasons you were able to keep lowering operating costs and, I guess, come in under spending.

Kind of curious if you could elaborate on which parts of your business you're seeing that and why you think it's not coming through and, I guess, how sustainable you think that might be.

And I've got a follow-up, please.

Okay.

Well, Doug, I -- I'll address the inflation question, but I should just mention on the front end that some of our lower spending on both the CapEx and OPEX side is not just due to the deflation capture we've had.

There's been other savings that are driven by more efficient operations.

So that's certainly a significant piece of the puzzle as well.

But on deflation, we are still seeing net deflation as a company worldwide, 2017 versus 2016.

I would say, for every dollar of inflation we've seen in certain areas of the Lower 48 related to the unconventional side, we've seen $2 to $3 of deflation elsewhere in the U.S. or around the world.

To give you some examples of some of the places where we're still seeing deflation year-over-year, Lower 48 chemicals and some of our construction work in Lower 48, OCTG, internationally, not in Lower 48, but outside Lower 48 OCTG.

Alaska, construction costs in Alaska; subsea, cost for subsea equipment in the North Sea, those are all down year-over-year.

Another area you see people talking about in the U.S. is sand.

We've seen a pretty stable sand cost this year, so sand really hasn't been a big issue for us.

I was looking at some data the other day comparing with some of the inflation we've seen in some of the areas in the Lower 48 normalizing our costs.

So the cost per pound of proppant pumped, which is one way to normalize our costs over time since the jobs have gotten bigger.

And compared to the peak that we were seeing, say, back in 2014, we're still down about 2/3rds in our cost per pound of pumped proppant from where we were at the peak, where we stand today, even with some of the increases we've seen.

That's true.

I guess, the proportion of your spend U.S. versus international, I'm guessing that on an aggregate basis, you're still seeing deflation across your portfolio, Al.

Yes, yes, that's what I'm saying, that when you add it all up, it's substantially still deflation for us, overall.

And it's a mix of the same kinds of things that we've been talking about.

The -- some of it is resistance to the Lower 48 inflation because we've got some contracts that we're locking things in.

But really, it's that inflation, so more than half our spending being international and yet -- still seeing deflation there.

Don, my follow-up is for you, hopefully.

The -- so obviously, tremendous progress on the debt now that you've locked down those debt reductions.

I think you had suggested previously that you might want to get down at about $15 billion.

I guess, where I'm going with my question is your cash breakeven continues to drop.

Oil prices appear to have kind of stabilized somewhat.

So how do you see the balance between buybacks, even though you're early in the process versus your continued commitment to drop that debt level.

Is $15 billion still the right number?

And I'll leave it there.

Yes.

Thanks, Doug.

Well, we fully intend to do both, continue with the debt reduction beyond 2017 and to continue with our buyback programs.

The question is to whether $15 billion is the right number.

And you point out that the cash flows from the company are very strong and we continue to look at that.

And of course, our plan is to expand cash flow as we go forward, we'll factor into our thinking.

But right now, $15 billion is our target, and we'll stay on that course.

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

I wanted to -- the first question is really just clarity on the buyback commentary for $3 billion over '18 and '19.

I just wanted to make sure I understood.

Is that supposed to be $1.5 billion per year?

Or is that actually $3 billion per year?

No, that's $3 billion over a 2-year period.

Got it, okay.

And then secondly, I think in the past, you had addressed deferred taxes.

And the commentary, I believe, was something around $60 a barrel at that point.

You would really start to see kind of a reversal or a benefit of what has been a drag on cash flow over time.

Is that still a good number?

Or are there any changes if kind of your efficiencies and costs are coming down?

No.

Yes, that's a great question.

It continues to evolve.

I don't think it's a good number anymore.

If you look at this quarter, of course, we had a large use of deferred taxes and that was driven by a lot of the inorganic stuff, the dispositions.

If we normalize out for that and a few other minor discrete items, we would have had deferred taxes probably as maybe a couple hundred million use of cash, which signifies that we're pretty darn close.

And that's in the $50 environment.

And so yes, a year ago, we would have said we needed $60 or better prices to break even.

Today, it's -- we're really breaking even right around $50 on profit breakeven, not cash breakeven.

So I think that flip point, Blake, is probably closer to $50 today rather than the previous $60.

Our next question is from Paul Sankey of Wolfe Research.

Two for me, please.

Al, you guys differentiated yourselves initially in the Eagle Ford and subsequently have pursued growth there quite specifically to avoid cost inflation in the Permian.

Can you update us on where those costs are as regards -- how the strategy is playing out, how you see the differentiation between cost inflation in the Permian versus the Eagle Ford, please?

And my second follow-up is for Don.

Don, could you just address -- this is a bit of a modeling question, I apologize, but could you just address the issue of shareholders' equity that's moving quite fast?

I just wondered if you could talk a little bit about the dynamics of what's changing it.

Okay.

On the first question, I -- we do continue to see ourselves advantaged in the Eagle Ford.

You notice that when we had an opportunity to add another rig here a few weeks ago, we chose to add it in the Eagle Ford, where we had a good opportunity to add at an attractive contract cost.

We -- remember, also for us, that the Eagle Ford is also where we have our infrastructure already fully developed and can add rigs and add production there without a significant infrastructure bill, unlike in the Permian where we have to make additional significant commitments to infrastructure in order to expand there.

So those are kind of the things that are driving us there.

We still have a long list of good, very low cost of supply opportunities in the Eagle Ford, so you'll see us continuing to have that be our sort of favorite area to invest in the U.S.

I guess you're going to hold the Permian position then fallow?

No.

I also mentioned that we are running 3 rigs there in the Permian now, 2 in the unconventional, 1 in the conventional.

And one of the scope adds that I mentioned in my prepared remarks is that we not only added an additional rig in the Eagle Ford here a few weeks ago, but we've also taken the decision to -- you heard me talk about our Permian rigs being a little bit up and down as the year moving across to Niobrara, et cetera.

We've decided on those 3 rigs to extend the contracts all the way through the end of the year.

So that's going to effectively add about another 6 rig months of drilling to the Permian this year versus what our original $5 billion budget had been based on.

So we are putting a little more money into the Permian than our original plan, not a little more money, a little more scope activity.

It's actually costing us less money.

Got it.

So from your point of view, the cost inflation is not dramatically worse, if at all, in the Permian than the Eagle Ford.

We have seen some things being tighter in the Permian versus the Eagle Ford just because there's a bigger frenzy there.

We're still down dramatically.

We still only have about 1/3 of the number of rigs running in the Eagle Ford as there were at the peak.

And so it is an easier place to work.

But our Permian acreage is attractive also.

And we're continuing to pursue that development as well.

And Paul, yes, this is Don.

On your question regarding shareholder equity, of course, we've seen some reductions over the last few years for a number of reasons.

Part of that is related to some rather large impairments that we've taken.

You always hope that a lot of that is behind you.

Of course, we exited the deepwater program, so we feel like our exposure is essentially eliminated from that area.

You saw the recent write-down of APLNG as well.

Of course, shareholders' equity has been reduced as we've taken the portfolio actions that we have through our asset sales over an extended period of time.

But we believe that we've created value from those asset sales.

So that's not at all troubling to us.

And then our buyback program, we think, is a good use of cash, which is also bringing shareholder equity down as we use that cash, but that's a good use of cash.

I think -- and then, of course, we've been in this period of low prices for a number of years, which has resulted in losses of -- losses to earnings.

As we look forward, we can see equity growing as we become profitable going forward.

Yes.

Would that be write-backs as well?

Or would you need little higher prices?

Write-backs?

Yes.

I mean, for the write-downs.

We're not European, so we don't get to do that under U.S. laws.

Okay.

So the dynamic would be retained earnings and buyback, I guess.

Right.

Our next question is from Paul Cheng of Barclays.

Two questions.

I think first is for Al.

The second one maybe either Al or for Don.

Al, for Permian, the 2 unconventional rigs, I think you are still doing ad hoc and not yet manufacturing commercial development.

So the question is that if -- do you have a timeline when that you guys are ready to do it?

Or that -- what would be the criteria before you reach that timeline?

Really, I mean, it's crystal clear to us that the cost of supply that we need to have it compete in our portfolio to move into manufacturing mode is definitely there.

And so really, what we're doing right now is just phasing our way into the offtake commitments and the infrastructure commitments that we need to make and the time it takes to build those that is really driving the timing of how fast we start to drill up that acreage and move more into manufacturing mode across our acreage in the Permian unconventional.

Any kind of timeline?

Well, I think you'll see it happening steadily over the next couple of years.

It -- you can't move to manufacturing mode until you have the infrastructure and the takeaway capacity to allow you to do it.

And so we've already contracted for the first phases of that infrastructure and it's moving forward to be built.

But a lot of it won't be online until 2019.

Okay.

So we should assume 2019 or 2020 then.

Yes.

I mean, I think in 2019, you'll see something that will probably look -- start to look to you like manufacturing mode as that infrastructure becomes available to us.

Okay.

The second question is for Don.

Don, APLNG in the second quarter, are they positive free cash flow by now?

Or that they are still just paying off the project financing?

And also the -- in the $1.6 billion of the cash flow this quarter, what is the cash flow associated with that asset to be sold or that you already sold?

Let's see, Paul, on APLNG, they had good production through the second quarter, as they were conducting their performance tests for the part of the lenders' test.

Their cash flow breakeven is somewhere between $45 and $50 Brent, so they would have been probably generating some free cash flow and building cash balances within the joint venture.

As far as what part of the $1.6 billion was associated with divestitures, I'm not sure I have that figure at hand.

We may have to get back with you on that.

Of course, we had FCCL, those -- cash flow associated with that would have been whatever we anticipated for distribution.

They wouldn't have had any in the second quarter, so that would have been a zero.

We had about half of a quarter of Western Canada that contributed to second quarter, and that's a very small number of maybe $30 million or $40 million.

So it's a pretty -- and San Juan is in the second quarter, and that's about $200 million a year, so $50 million a quarter, something like that.

So we should say, call it, somewhere on a pro forma basis that $50 is more like in $1.45 billion, $1.5 billion in the cash flow.

No, I wouldn't do that.

And the reason I wouldn't do that is because a couple of reasons, but one thing that you need to keep in mind is that a lot of these proceeds that were used are going to retire debt.

And so our interest expense is coming down, and that's serving to offset a good portion of that lost operating cash flow.

So I don't think that we're going to see a significant -- at $50 oil, I'm not anticipating that we're going to see a significant degradation of our operating cash flow.

As you know, previously, I've talked to you guys about-- at $50, the company is able to generate about $6.5 billion.

You've heard me talk about that before.

I think when all these dispositions are said and done, we might have lost $100 million or $200 million out of that, but it's really not a significant amount at $50.

Of course, the cash flow impacts will increase as oil price increases.

You go to $60, it's going to be more material.

But at $50, it's just not -- it's not a big loss.

Our next question is from Ryan Todd of Deutsche Bank.

Maybe one, I know the oil price certainly feels a bit more stable now, but if we were to see a lower -- potentially lower oil price into 2018, how should we think about the response of ConocoPhillips?

How much flexibility is there in that kind of $4.8 billion run rate into 2018?

And what type of environment would prompt you to reduce the activity levels from the 12 rigs you're currently running in the U.S.?

Ryan, I'll take that.

We'll talk more obviously in November about our outlooks and our plans for 2018.

And I think we'll be in a better position to talk about how we would react to different potential outcomes and scenarios in 2018.

But I think it's important to note how resilient the company has become to lower oil prices.

Our cash breakeven has continued to decline.

Our profit breakeven has continued to decline.

We've pretty much preloaded on the balance sheet with $10 billion.

We've got more assets to close as we go forward in the third quarter.

We -- like I've said, we've basically prefunded our plans for the next couple of years there.

So you'd have to get down to some pretty low scenarios before we thought about significant changes to our strategy.

And with regard to our flexibility, if you did get into that kind of scenario, we haven't set our 2018 capital plans yet, obviously.

We'll be talking about that later in the year.

But I expect that on the order of half of our CapEx plans for '18, we'll be fairly flexible and the sort of thing that you could ramp down if you needed to in a very low-price scenario.

Great.

And then maybe, I guess, just one very specific one.

I mean, you mentioned the additional asset disposal, the Panhandle asset agreement in the release today.

What's the -- could you give any details in terms of how much production associated with that asset and maybe what the potential proceeds would be?

Yes, I can do that, Ryan.

We're -- I think the sales price on that is right around $200 million.

And let me just check my facts here.

But we're looking at 2017 pro forma, so for the full year, a rate of 8,000-barrel equivalent a day.

That's mostly gas.

Our next question is from Roger Read of Wells Fargo.

I guess, maybe just real quick on Alaska given that things are going well up there and on the cost side.

But there's been some movements inside the state there to raise taxes more so on idle than active projects.

But I'm just wondering if you could give us sort of an update on the kind of political tax outlook in that area.

Well, if you look at what's happened so far, the tax changes that have made -- been made really don't have any significant impact on us and so haven't had an impact on our plans in Alaska with what's happened so far.

Any prospects for -- anything we need to keep our eye on?

Or anything you're watching there?

Well, I mean, there's -- I think the tax and spending situation in Alaska is still difficult in today's environment.

And so we continue to watch it closely to see what happens.

We're -- in terms of our level of investment activity in Alaska, we're pretty sensitive to the fiscal regime up there.

So in the handful of years since SB 21 was passed that made things more attractive for investment, we've been able to increase our production there.

We've been spending about $1 billion a year of capital, so -- on the order of 20% of the whole company's CapEx going into Alaska.

And if the tax regime changes, we would, of course, have to reevaluate that.

We have forward projects where we have control of the pace.

Okay.

I appreciate that.

And then if I missed it in your discussions earlier, I apologize for asking this question.

But the improvement on the depreciation, I understand a portion of it related to asset sales, but the part related to production performance, kind of where is that and maybe the magnitude of that in the $1 billion?

Yes, I think it's about $0.3 billion out of that $1 billion is from performance.

And it's really driven by -- the biggest line item is the Lower 48 and some in Alaska as well, so really kind of U.S. driven.

In the Lower 48, we have a lot of restrictions on the way we book our reserves there.

But as we've gotten more and more experience and more time and more confidence in our type curves there, you're able to book more of the EUR that you're expecting to get in the base case.

You can actually book and so that improves your unit depreciation rate.

Well, you've always said you were conservative on your initial booking, so I guess that's pretty consistent.

Yes.

And we -- and I think we still are, but we're catching up a little bit on that, and that's helping.

Our next question is from Neil Mehta of Goldman Sachs.

Just want to connect with you guys.

On second quarter production, you exceeded the top end production guidance.

And relative to your expectations, where did you see that outperformance?

Just relative to our forecast, it was Norway, Malaysia and we felt like a little bit in Alaska, but curious where you saw that outperformance.

Okay, Neil, I'll give you the rundown of that and kind of some of the reasons behind it.

So we beat the midpoint by 40,000 barrels a day.

14,000 of that was actually in Alaska, that was the single biggest place, and that was really driven by better uptime and some better well performance.

We were plus 10,000 in Malaysia.

That was driven by the -- a shorter turnaround time for the KBB turnaround and also better-than-expected Malikai well performance.

Norway was plus 7,000.

Again, we had better uptime and well performance, but also some increased gas offtake in the summer.

Australia was plus 5,000.

We had better performance at both APLNG and Darwin LNG.

And the U.K. was plus 5,000.

We had better uptime in the J-Block area and some better well performance.

So when you look at all those, you wonder, how can that be?

You add all those pluses all at the same time, and I guess, the observation I would make from my travels around the world visiting our operating groups is it seems to me that in this period where we've been spending less CapEx, our operating groups who got -- had more time to focus on our base operations.

And so what's really driving this is better-than-expected performance out of our base.

It's a -- so that brings me to my follow-up, which is just how do you think about that decline rate on the base, both mitigated and unmitigated?

And then tying it to a bigger picture question, I know you guys built the business to be sustainable in any type of oil price environment, but you do as good at modeling on oil macros as anyone we've seen.

So just where do you guys think we are in terms of the oil market rebalancing right now.

I would say no significant changes.

To move the decline rate at the corporate level takes big shifts.

So -- but I still think we're in that kind of 8% to 10% range over time that we've talked about.

If we continue to have the sustained improved performance out of our base, we may have to do some more analysis on that.

It could be that there's a shift there over time.

As far as the macro goes, I mean, I think what's interesting for us is that the weak -- the recent weakness that we've had in a little bit of kind of -- has not been a surprise for us.

I mean, I think the macro environment we found ourselves in is the exact one you've heard us talking about since last year's analyst meeting and the one that we've prepared ourselves for.

We've said that we're going to be prepared to have free cash flow that covers our CapEx and dividends in this $45 to $50 environment.

And that we're going to be ready to thrive in that environment over an indefinite period of time.

So this matches up well with the way we prepared ourselves.

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

Al, if I could just follow up on that question on the quarterly production outperformances.

You guys forecasted, obviously, higher production by, on average, 25,000 a day this year.

That implies still a pretty healthy increase in 3Q, 4Q.

And in your second quarter commentary there, you used the word uptime a lot as far as the outperformance.

What is really driving the higher production outlook?

And my number looks about 30,000 BOE per day in the back half of the year.

Yes, I'm not sure what your 30,000 is.

Are you saying 30,000 up from 3Q to 4Q?

Well, yes.

So if you're increasing your full year number by 25,000, and you outperformed by 40,000 in -- yes, yes.

Yes.

I mean, the only problem with that math, you've got to be careful with that math about same-store sales and taking out the dispositions because if you look at our underlying growth, same-store sales, 3Q to 4Q, it's in the 7% to 8% range what we expect to grow from the third quarter this year to the fourth quarter this year once you take out the dispositions, and between 4% and 5% year-over-year.

So if you compare this -- what we expect this year's fourth quarter with last year's fourth quarter, same-store sales 4% to 5% range.

And so part of that is our normal bathtub shape that we get every year because we tend to have our turnarounds in the second and third quarter.

And we do have some very significant turnaround load planned in the third quarter.

But also with the timing of some of our rig additions in the Lower 48 unconventional and then the completions coming in behind that and the time you get the completion crews out there, you are -- we'll have a -- we're expecting to have pretty strong production in the fourth quarter from our Lower 48 unconventional.

Got it.

That's helpful.

Also there's been some, I guess, news that Tokyo Gas is looking to renegotiate some of its LNG pricing agreements.

And obviously, you discussed the write-down at APLNG due to weaker pricing.

Can you give us a sense of what that market looks like and what kind of conversations you are having with some of your counterparties?

Yes.

This is Don.

Our APLNG is really sold out under 20-year long-term contracts, both to Sinopec and Kansai in Japan.

So I'm not familiar with what you're reporting with respect to Tokyo Gas.

We do sell gas from our Darwin LNG to Tokyo Gas.

I'm not aware of any discussions we've had about renegotiating contracts.

Okay, okay.

There was something else in the news within the last week, so I can follow up with that.

Okay.

Our next question is from Pavel Molchanov of Raymond James.

Once the asset sales wrap up, you'll be one of the few North American companies to have about as high gas exposure in Europe as you are in North America.

So I would ask, given the magnitude of your European gas portfolio, is that something that you would expect to grow over time?

Or is it a noncore asset that you would be potentially looking to monetize as you've done in North America?

Well, I'll try to take that one.

Yes, I mean, you're pointing to the comparability of our European gas sales to our North American, but I'd have to remind you that after the asset sales in North America, North America gas represents less than 10% of our total portfolio.

So these aren't the largest positions that we've got from a commodity perspective.

With respect to the strategic nature of our European gas sales, that's coming primarily from Norway and -- as well as the U.K. But yes, I think that we consider the North Sea assets, which are primarily oil-producing assets, to be strategic to the company.

Okay.

Let me ask a quick one on exploration expense.

Less than $100 million in Q2, the lowest, I think, on record.

Is that a run rate that can be sustained given your CapEx plans?

Or was that a bit of an outlier?

Well, I mean, the exploration expense tends to be a bit lumpy with specific events that occur, things like lease acquisition that will happen at one time.

We did have, in the first quarter, the last vestiges of some of our deepwater drilling cost and exploration that are completely done now.

And so I wouldn't call $100 million a run rate necessarily, but that's not too far off.

I think we're expecting to be around $600 million for the year this year.

But $100 million a quarter is not too far off.

Our next question is from Jason Gammel of Jefferies.

I just have a 2-parter on APLNG.

First of all, can you make any comments about what the domestic gas situation on the East Coast of Australia is potentially going to have on the operations of APLNG, especially given that it appears to be the project that is producing the most feedstock gas at the current time?

And then I guess, the second question is given that you're very close to achieving completion and getting certification from the lenders and lifting of the loan guarantees gives you quite a bit more flexibility in the role of that asset in the portfolio.

So I guess, the question really is would you still consider APLNG a core asset that you want to hold for the long term?

Or would this potentially be another candidate for divestiture and then you could potentially redeploy the proceeds elsewhere?

Okay.

I'll start on the export licensing.

You've seen some material in the press lately where the government is starting their process for 2018 to think about what they want to do there.

But remember that the key to the regulations, the way they've been written is that the test is whether you're a net domestic gas contributor or not.

And so APLNG has always been in our plans, going all the way as far as you can see into the future, are for us to always be a significant domestic gas contributor, which just means that as we buy and sell in the domestic market, we're selling much more of our own production into the domestic market than we're buying.

And so we're a very significant supplier.

We supply about 20% of the domestic gas in the East Coast market in Australia as APLNG.

So given that that's the case, we -- there's -- we don't expect any impact on APLNG's operations from the export licensing process that's ongoing.

With regard to our view of how APLNG sits in our portfolio, I guess, I could say that we don't have any plans to market or sell APLNG.

It sits -- we've got the -- all the CapEx behind us and -- are now in the flat production mode.

As Don mentioned earlier, when you include the debt service, we do need $45 to $50 to get to breakeven.

But if you exclude the debt service, just to give you an idea of where the operation sits, it's $30 to $35.

You need $30 to $35 Brent to break even cash, excluding the debt service.

So at the kind of levels we're at today, we're able to cover that debt service as well.

And we're very pleased with the way that the facility has operated.

It's really been better than expected and continues to get better.

We had 72 cargoes that we shipped all last year from APLNG, and we've already done 60 in the first half of this year.

Our last question is from Michael Hall of Heikkinen Energy.

A quick one on my end.

Just curious kind of on a similar front to some of the questions earlier around maybe if you've seen any varying inflation pressures across the different Lower 48 focus areas.

But taking that on the learning curve side, you mentioned you're still seeing a lot of progress on that front.

Just curious how, if any, those learning curves differ across the different -- Eagle Ford, Williston and Permian.

And then on a related angle, have you had any success to kind of bringing technologies from the offshore and other conventional areas into your onshore unconventional projects?

Okay.

There was a number of different questions there.

I mean, I guess, I would say that I -- we don't see any huge differences in terms of learning curve from our different areas.

There's some difference with maturity.

But even in the Eagle Ford, where we're the most mature, we still continue to get very significant improvement in both recoveries and in how many days it takes to drill and complete our wells from year to year.

So even where we're mature, we're still continuing to see a significant pace of improvement.

The bigger differences for us come around infrastructure and how that impacts our ability to get things done and have good netbacks.

So I think that, that's really -- and you also asked about the knowledge transfer from the offshore to the onshore.

I talked about this in the last quarter call that the big thing for us has really been around data analytics and our integrated operations, which really started many years ago in the North Sea, for us, in Norway and then spread across the company and served as the foundation years ago for our data analytics effort in places like the unconventional.

That's a good example of some of the offshore coming to the onshore.

So I think that's a good place for us to wrap up, and that's a good topic that I'm sure we'll be talking more about at the Analyst Day that we have coming up in November, so we hope to see everybody there.

Thanks, folks.

Christine, we'll go ahead and wrap it up.

Obviously, if anybody has any follow-up questions, feel free to ring IR.

We'll be glad to help you out.

Thank you for your interest and participation.

Thanks.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This document contains forward-looking statements.

Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results.

In many cases you can identify forward-looking statements by terminology such as "anticipate," "estimate," "believe," "continue," "could," "intend," "may," "plan," "potential," "predict," "should," "will," "expect," "objective," "projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and other similar words.

However, the absence of these words does not mean that the statements are not forward-looking.

Where, in any forward-looking statement, the company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis.

However, there can be no assurance that such expectation or belief will result or be achieved.

The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, our ability to liquidate the common stock issued to us by Cenovus Energy Inc.

as part of our sale of assets in western Canada at prices we deem acceptable, or at all; our ability to complete the sale of our announced dispositions (the Sale Transactions) on the timeline currently anticipated, if at all; the possibility that regulatory approvals for the Sale Transactions will not be received on a timely basis, if at all, or that such approvals may require modification to the terms of the Sale Transactions or our remaining business; business disruptions during or following the Sale Transactions, including the diversion of management time and attention; the ability to deploy net proceeds from the Sale Transactions in the manner and timeframe we currently anticipate, if at all; changes in commodity prices; changes in expected levels of oil and gas reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; difficulties in developing new products and manufacturing processes; unexpected cost increases; international monetary conditions; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business.

Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission.

Unless legally required, ConocoPhillips undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Cautionary Note to U.S. Investors - The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves.

We use the term "resource" in this document that the SEC's guidelines prohibit us from including in filings with the SEC.

U.S. investors are urged to consider closely the oil and gas disclosures in our Form 10-K and other reports and filings with the SEC.

Copies are available from the SEC and from the ConocoPhillips website.

Use of Non-GAAP Financial Information - This document includes non-GAAP financial measures.

These terms are included to help facilitate comparisons of company operating performance across periods and with peer companies.

A non-GAAP reconciliation is available at www.conocophillips.com/nongaap.