康菲 (COP) 2019 Q2 法說會逐字稿

Hello, and welcome to the ConocoPhillips earnings conference call.

My name is Sanera, and I'll be the 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, Senior Vice President, Corporate Relations.

Ellen, you may begin.

Hello everyone, and welcome to our second-quarter earnings call.

Today's prepared remarks will be delivered by Don Wallette, our EVP and Chief Financial Officer; and Matt Fox, our EVP and Chief Operating Officer.

In addition, our three region presidents are on the call today.

They are Bill Bullock, our President of the Asia Pacific, Middle East region; Michael Hatfield, our President of the Alaska, Canada and European regions; and Dominic Macklon, President of our Lower 48 region.

Page 2 of today's presentation deck shows our cautionary statement.

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

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

We'll also refer to some non-GAAP financial measures this morning, and reconciliations of non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and on our website.

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

Thanks, Ellen.

Good morning, all.

I'll cover the second-quarter highlights on Slide 4. Starting on the left with our financial performance, we realized adjusted earnings of $1.1 billion in the quarter or $1.01 per share.

Our production outperformance in the quarter didn't fully translate to the bottom line, as sales lagged production with inventories building by roughly 25,000 barrels a day, which represents about $0.03 a share.

We generated $3.4 billion of cash from operations, resulting in free cash flow of $1.7 billion in the quarter and $3 billion year-to-date.

This quarter represents our seventh consecutive quarter of free cash flow generation across a broad range of prices, underscoring our commitment to capital discipline.

And importantly, over this 7-quarter time frame, cash from operations has more than covered all capital, dividends and share repurchases.

We ended the quarter with $6.9 billion of cash and short-term investments.

And our strong financial returns continued.

On a trailing 12-month basis, our return on capital employed was 12.4%.

Moving to the middle column, operationally in the quarter, we produced 1.29 million barrels of oil equivalent per day, up 6% on an underlying per net-adjusted-share basis compared with the year-ago quarter.

Sequentially, seasonal turnaround impacts were mitigated by growth from the Lower 48 Big 3.

Touching on the final bullet in the operational column, in the second quarter we closed several small bolt-on transactions in the Lower 48 Big 3 for about $100 million.

We consistently monitor the market for these kinds of low cost of supply additions in and around our core areas, and we were able to complete a few royalty interest and acreage deals this quarter at attractive terms.

Shifting to the far right strategic column, we've increased this year's planned share repurchase program by $500 million to a total of $3.5 billion.

In the second quarter, we repurchased $1.25 billion of shares.

We expect to purchase $1.5 billion of shares in the second half of the year.

Combined with our second-quarter dividend, we returned 47% of cash from operations to shareholders in the quarter.

So returning capital to shareholders remains a priority.

In the second quarter, we realized $600 million in disposition proceeds, and the U.K. disposition continues to progress toward closing in the second half of the year.

We expect to recognize a gain of approximately $2 billion before tax and after tax when the sale closes.

Also, at closing, we'll see a significant balance sheet improvement, with net cash proceeds expected to be about $2 billion while liabilities associated with asset retirement obligations will decrease by about $2 billion.

If you turn to Slide 5, I'll wrap up with a look at cash flows during the quarter.

We began the second quarter with cash and short-term investments of $6.7 billion.

Moving to the right, cash from operations was $3.4 billion, which included roughly $320 million in APLNG distributions and about $90 million collected through the ICC settlement agreement with PDVSA.

To date, we've received $665 million related to the $2 billion settlement.

I'll also mention that we continued to receive contingent value payments from Cenovus during the quarter.

To date, we've received or accrued a little over $180 million in contingency payments from this 2017 transaction.

Moving on, working capital was a $600 million use of cash during the quarter.

We recognized $600 million in proceeds from dispositions, and we had $1.7 billion of capital expenditures in the quarter, which was exactly half of cash from operations excluding working capital, leaving $1.7 billion of free cash flow.

For the first half, free cash flow was $3 billion, representing a 9% free cash flow yield on an annualized basis.

Looking to the last two bricks on the right, the roughly $350 million in dividends and $1.25 billion of share repurchases represented a return of capital to shareholders of $1.6 billion, or 47% of CFO.

Total shareholder yield based on planned buybacks and our current dividend is running a little over 7%.

And you see the ending cash on the far right with a slight build from the first quarter despite choosing to increase buybacks in the quarter by $500 million compared to recent quarters.

So to briefly recap, this past quarter builds on our trend of consistent, strong operational and financial performance.

The quarter reemphasizes our commitment to financial returns, capital discipline, free cash flow generation and returning cash from operations to shareholders.

We believe this is a sustainable and compelling value proposition for our industry.

With that, I'll turn the call over to Matt.

Thanks, Don.

I'll provide a brief overview of our year-to-date operational highlights and discuss our outlook for the remainder of the year.

So please turn to Slide 7.

Across the portfolio, we continue to make progress toward the key milestones we highlighted at the end of last year.

Starting in Alaska, we wrapped up a winter appraisal season in the Greater Willow Area and Narwhal in the second quarter.

During the first half of the year, we drilled seven successful appraisal wells and conducted a series of horizontal production well, injectivity and interference tests.

The results have been encouraging for both Willow and the Narwhal trend.

Based on these positive results, we're also taking the opportunity to drill an additional unbudgeted horizontal well from an existing Alpine drill site into the Narwhal trend later this year.

Also in the second quarter, we announced a high-value bolt-on to our Alaska position.

We acquired discovered resource acreage called Nuna directly adjacent to our Kuparuk Field and we expect that transaction to close in the third quarter.

Finally in June, planned maintenance was completed at Prudhoe Bay, and turnarounds will continue in the third quarter at Prudhoe, the West and North Slope and Kuparuk.

Moving to Canada, we safely completed the first turnaround of our Surmont 2 Central Processing Facility, which in addition to the maintenance scope, also paved way for the alternative diluent project.

This capability will not only reduce the amount of diluent we'd require but provide diluent flexibility and improve our netbacks.

We expect to have it fully operational by the end of the year as planned.

In June, Surmont was brought back online, but continues to be subject to mandatory curtailment, impacting planned production by about 5,000 barrels a day for the rest of the year.

In Montney, we continued completion activities on the 14-well pad and construction of the associated infrastructure with start-up still on track for the fourth quarter.

In the Lower 48, Big 3 second-quarter production by asset was: Eagle Ford at 221,000 barrels equivalent per day; Bakken at 98,000 and Delaware at 48,000.

This represents a 41,000 barrel a day increase from the first quarter to 367,000 due to strong execution performance and improved operational efficiency.

We now expect Big 3 production in 2019 to average 360,000 barrels a day, up from our initial expectation of 350,000.

This represents a growth rate of about 21% from 2018 to 2019 and an increase of over 60,000 barrels a day for the year.

As Don mentioned, during the quarter, we made several royalty-interest and acreage acquisitions across the Big 3. Lastly, we continue to evaluate our results in the Louisiana Austin Chalk play.

So far, although we flowed oil from the first three wells, they produced higher water cuts than we were hoping to see, so the results to date are disappointing.

Although the Austin Chalk is the primary target, we're also evaluating opportunities in other formations within the acreage.

Moving over to Europe, as Don said, the U.K. disposition continues to progress towards closing.

We also began a planned turnaround in the J-Area that was completed in July.

In Norway, we completed the Greater Ekofisk Area turnaround during the second quarter and sanctioned the Tor II Field redevelopment project.

This is a subsea production system tied back to Ekofisk that we expect to come on at the end of 2020.

In the third quarter, there'll be more turnaround activity in Norway at our partner-operated assets.

In Qatar, we remain very interested in participating in the North Field expansion project.

Moving to Malaysia, production ramp-up at KBB continued when flow through the Sabah Sarawak gas pipeline recommenced, but we don't expect full ramp-up in production to be achieved until late in the year.

Also in the quarter, KBB began delivering gas to a third-party floating LNG facility.

This will serve as a supplementary offtake to help mitigate potential production disruptions through the pipeline.

Finally, in Indonesia, the Ministry of Energy and Mineral Resources announced earlier this month that ConocoPhillips has been awarded a 20-year extension of our participation in the Corridor Block beyond the current contract expiry in December of 2023.

So, we've had another quarter of strong execution as well as significant progress across the portfolio.

So now let me discuss the outlook for the remainder of the year on Slide 8. As we progress through 2019, we're continuing our disciplined capital approach, and we're also making decisions to optimize the value of our high-margin assets.

We're adjusting our full-year operating plan capital guidance from $6.1 billion to $6.3 billion, excluding acquisitions, for two unbudgeted activities.

In Alaska, we'll spend about half of the incremental capital to conduct additional scope in our appraisal program, including a long-term test of the Putu horizontal appraisal well and the additional Narwhal appraisal well I mentioned earlier, as well as additional long-lead items for the 2020 exploration and appraisal season.

In the Eagle Ford, we've just added a rig in order to optimize rig count as we ramp toward the plateau phase of our development plans over the next few years, and we'll describe the basis of this optimization in more detail in November.

Incremental rate associated with this rig won't show up until 2020.

Our 2019 operating capital guidance excludes acquisitions.

To date, we've closed or announced about $300 million of transactions, including the Lower 48 and Nuna deals we've already mentioned and a low-cost entry into the Vaca Muerta shale play in Argentina.

These all represent opportunistic low cost of supply additions to our resource base.

On the production side, we expect the third quarter to average between 1.29 million and 1.33 million barrels equivalent per day.

You'll notice on the right side of this chart that we're narrowing the range on our full-year outlook because half the year is behind us now, but maintaining the midpoint in our previous guidance of 1.325 million barrels a day.

Now this might look conservative considering our very strong first-half performance.

However, at this time, we're not adjusting our full-year midpoint guidance for two reasons.

The first is because we accelerated production versus our plan from the second half of the year into the first half of the year, especially in the second quarter and especially in the Lower 48 Big 3. And finally, as I said earlier, we expect the Big 3 overall growth rate to be higher than plan for 2019.

We expect production levels for the remainder of the year to be flat to mostly growing -- to modestly growing from the increased rate we saw in the second quarter.

The second factor is lower-than-expected performance in two areas: Surmont due to the mandated curtailments that we now expect to continue through the year; and Alaska where one of the four production wells of the GMT-1 project is performing below expectations.

The increased production from the Lower 48 Big 3 in the first half of the year essentially offsets these factors through the year.

This is another great example of the value of diversification in our portfolio.

We have a busy second half of the year with several turnarounds and the ramp-up of KBB production, so we don't think it's prudent to change full-year guidance at this time.

But to be clear, the original $6.1 billion operating plan capital is still delivering our planned 5% underlying production growth.

And with our planned buybacks, we expect to deliver 8% per debt adjusted share growth.

Also bear in mind that we are carrying the U.K. in all of these numbers.

We'll update production and other relevant guidance items at the close of the U.K. disposition.

Finally, we're looking forward to our Analyst & Investor Meeting on Nov.

19 in Houston.

We'll show a decade-long disciplined capital plan that delivers free cash flow and strong shareholder returns across a range of prices, and we'll provide a deep dive into the assets across our diverse portfolio.

Our strong performance in the first half of the year highlights the strength of our portfolio diversity and our ability to generate free cash flow to support distinctive returns to shareholders.

Our entire ConocoPhillips team is focused on successfully executing the second half of our 2019 plan and sharing our long-term plans with you in November.

Now I'll open it up for Q&A.

(Operator Instructions) Our first question comes from Neil Mehta from Goldman Sachs.

Congrats on a good quarter here.

I guess the first question is you had really strong cash flow generation.

Part of it was led by the dividend payment out of APLNG and then the ability to pull cash from Venezuela.

Can you talk about both of those line items?

They're independently difficult to model, the sizing and timing, and how we should think about them going forward.

Neil, this is Don.

I'll take that one.

So yes, cash flow was strong and you point to a couple of items that helped that.

We did have strong distributions from APLNG, $320 million in the quarter.

And in the first quarter, I think it was $73 million.

So for the first half, about $400 million.

I think previously, maybe it was in the last call, maybe it was the fourth-quarter call, I gave guidance of -- to expect APLNG distributions of about $550 million to $600 million for the year.

I need to probably bump that up a little bit, but I wouldn't take two times the $400 million.

It won't be quite that high.

But I think the new expectation on distributions for 2019, I would say, is going to be in the range of $650 million to $700 million.

Now I've cautioned folks on this before but I'll just do it again is that these aren't ratable across the quarters.

The odd quarters, the first and the third quarter are always going to be low because that's when financing payments and tax payments come up.

And then the even quarters, the second and fourth, are going to be relatively high.

So as you're thinking quarter-to-quarter, you should expect third quarter to be kind of low-ish and fourth quarter to be high-ish.

With respect to PDVSA, I think that's a very difficult one to give you guidance on for modeling because we don't build that into our cash forecast either.

We only recognize the earnings and the cash as we receive it, and I think that's probably the appropriate way to view it considering the situation and the counter-party.

That's helpful.

And then look, it's a small adjustment on CapEx from $6.1 billion to $6.3 billion, but certainly received some attention this morning.

So can you just talk a little bit about -- give us a little more color about what drove the $200 million?

And when you think about the incremental rig in the Eagle Ford and the incremental spend in Alaska, why those are good incremental rate of return projects that helped to lower the cost of supply of the company?

Yes, I'll take that.

So the Alaska, the -- so we've completed the off-ice appraisal season in Alaska this winter, and the results we've seen at Willow and Narwhal are both very encouraging.

So we've really taken the opportunity to extend some of the appraisal from our existing drill sites at Alpine.

For example, we've decided to do an extended well test on a horizontal appraisal well that we drilled into the Narwhal trend.

The results of that well are very encouraging and we thought, let's see if we can get a long-term test and understand the long-term deliverability.

So that's part of the increase.

We also can drill an offset injection well to this producer from the same drill site.

So we're going to take the opportunity to do that as well and that will give us further information on the Narwhal trend.

But it's really driven by encouragement on what we saw in the initial well in the Narwhal, the Putu appraisal we call that.

So we're feeling good about that.

We're also firming up our plans for 2020 and we're going to have another quite aggressive appraisal and exploration season in 2020.

This year, we really focused just on appraisal and so there's some long-lead items to do that.

So the -- once we get to November, we'll give you some details on exactly what we've concluded from the appraisal program this year, but they -- it's encouraging and that's what's led to trying to accelerate some of this learning.

Now Lower 48, we're always looking to optimize the value from our unconventional programs, and we've been working specifically this year in more detail on establishing the optimum plateau rate for the -- for our unconventionals.

And that has led us to conclude that we should add a rig or two over time to the Eagle Ford and we're taking the opportunity to add a seventh rig this year and maybe an eighth rig next year.

So that's what's behind that.

Of course, we don't expect the seventh rig to contribute any production until next year, but it's all part of this sort of rational approach to establishing the correct plateau rate at the unconventional plays.

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

Thanks, good morning everybody.

(technical difficulty) On your last call, I seem to recall Ryan talking about trying to find out a way to bring investors back to the sector and more than 30% of your cash flow to be now returned to shareholders.

You obviously exceeded that this quarter.

My question really is, the share price clearly continues to languish along with the rest of the sector.

What are you thinking in terms of how you differentiate your cash return?

I think the expression that Matt just used was how do you differentiate that?

And I'm thinking specifically about the prospect of a variable distribution, particularly in times when oil prices are elevated relative to what the market might think is sustainable.

So to the extent to which you can share any thoughts on how you might manage around that and I've got a follow-up, please.

Doug, this is Don.

Let me take that one.

Yes, I think we are trying to distinguish ourselves with our return of capital to shareholders.

You saw the figures for the second quarter.

And if you look at our $1.4 billion dividend and $3.5 billion of planned buybacks this year, that's $4.9 billion.

And let's just say that you see maybe something around $12 billion of CFOs, something in that neighborhood, that's approaching -- that's right around 40% return of cash, return of capital to shareholders in the year.

So we're trying to compete with the best capital returners in the business and certainly distinguish ourselves from the other E&P companies out there.

Now you mentioned the variable dividends, and I'd just say that we're always thinking about the best ways to return capital to shareholders.

And so we talk with the investment community to get feedback on their thoughts.

We do think our current model of a meaningful common dividend and a significant level of ratable buybacks that really go on indefinitely is a very attractive capital return model.

But we're always testing other ideas.

And so we'll talk more about this in some depth in November.

Yes.

This -- I want this to be my second question but just a very quick follow-up comment on that, is that the cash return is terrific as we all know but your relative yield is where the pushback comes, Don.

So I'm just curious if that -- I mean, obviously, you never want to put yourself back in a position with a high ordinary dividend.

But the buyback is essentially the delta between what your prior dividend was and what your current dividend is.

And as a consequence, you have that challenge, I guess, that your current yield is no longer competitive with companies with similar free cash flow capabilities.

So just an observation, I'd be curious if you want to add any follow-up as to whether that's a consideration, and I do have a very quick follow-up.

Yes.

Those are always considerations, Doug.

So yes, we continuously think about the level of our distributions.

We think about the mix of our distributions between buybacks and cash return in the form of dividends.

And we also think about how best to distribute during periods of pro cyclicality.

So these are the things that the management team continues to challenge and ask ourselves, and we are looking forward to talking more about this in November.

Okay.

My follow-up, I expect this to be very quick one.

Matt, you mentioned you're still interested in Qatar LNG.

I understand that things are like in a confidential stage for the industry right now.

But I'm just curious, in a success case, is that included in the sub-$7 billion multi-year capital plan or would something like the potential liquidation of Cenovus be a source of alternative funding if you were successful?

That is not included in the sub-$7 billion average capital.

The only thing we've included in there are things that we've already captured and we don't want to be presumptuous on whether or not we'll actually take a position in Qatar LNG.

So they -- and as you say, if it does transpire that we have a position there, then we have ways of funding that incremental capital but we didn't want to include that until it's captured.

And our next question comes from Phil Gresh from JPMorgan.

I guess the first question here would be a follow-up for Matt.

You're making the comments about trying to align the rig count in the Big 3 with an optimal long-term production plateau.

And I was just wondering if you could elaborate on that a bit as to how you're thinking about the three assets today?

I know Bakken's been a flattish asset for some time.

Now you're adding to the Eagle Ford.

So I'd be very interested if you have updated thoughts in the Eagle Ford and even if you have any on the Permian.

Yes, yes.

I'm going to give you more on this in November.

But the way we see the three -- the Big 3 assets in quite different stages of the life cycle just now.

Bakken is essentially at plateau.

Now depending on the timing of completions, that's going to bounce around a bit but we would expect that to be in the 80,000 to 90,000 barrel a day range for a long time to come but we don't really intend to have incremental growth there.

The Eagle Ford is on what we would characterize as late-stage growth.

Within the next few years, we'll reach plateau there.

And this addition of the rig is in service of reaching that optimum plateau and holding that for the optimum duration.

The Permian for us is much earlier in the life cycle.

So that has a significant growth ahead of it, and it will be several years before we reach plateau there.

But we do still have what we regard as a pretty rigorous approach to this, and it's too difficult to explain on the phone call but it's something that we will elaborate on in November.

And just to clarify in the Eagle Ford, is there a specific target you're thinking of that you could share or would you rather save that?

I think it's better to wait to get the context for the whole thing, but it's fair to say that we're a few years yet from the plateau.

So it certainly is going to plateau at a higher rate than where it is just now but we'll share more of that in November.

Okay.

And then just my follow-up is on the buyback.

Don, maybe you could just maybe clarify a little bit.

There's obviously a $500 million raise in the full year, which you fully accomplished in the second quarter.

So maybe just a little clarity around how you're thinking about the back half.

Is it just more about kind of what happens with prices?

Is there some degree of conservatism there?

Or maybe intentionally stepped up in the second quarter, just any thoughts you have about the progression you took.

Yes.

Phil, no, I think you can expect us to revert back to the $750 million a quarter that we've kind of historically run the last couple of years.

As far as the bump-up in the second quarter by $500 million, well, we knew we wanted to increase the buybacks for the year to $3.5 billion and we certainly had the cash on hand to be able to do that.

And of course, we noticed a pretty significant dislocation in our share price/Brent price correlation, or at least the historical correlation, and we felt like that was selling at a large discount to our intrinsic value.

We felt that, that was a good opportunity and why not just go ahead and spend that increment during the second quarter?

But the run rate, we expect to go to $750 million a quarter over the next two quarters, and then we'll talk about 2020 and beyond what our plans are as far as distributions in November.

Our next question comes from Doug Terreson from Evercore ISI.

So this is probably for Don but consensus expectations are for declining returns on capital and production growth for most E&P companies next year, which appears to be unfavorably affecting valuation and share prices in E&P.

And while you guys have differentiated yourselves with credible plans to sustain high returns and grow shareholder distributions, and you've delivered too for several years, the message seems to be that lower spending and portfolio restructuring may be the ultimate way to preserve value and share prices, especially if the sector is maturing.

So my question is that when you consider this theme but also the quality of your investment opportunity set, does it change the way that you think about future capital management, especially given your historic emphasis on returns on capital and trying to increase them as well?

Well, I don't think it changes our thinking.

I think, Doug, you know our strategy that we came out with in late 2016 was very much focused on capital discipline and a good balance between investing for growth and continued cash flow growth in the business as well as a high level of returns of capital back to the shareholders.

So we've -- I think we've seen good success on that strategy and it's one that we have a lot of conviction on going forward.

Our next question comes from Paul Sankey from Mizuho Group.

The decision to increase CapEx this quarter could presumably been avoided if you were concerned about the optics of doing that.

I just wondered why you couldn't find a couple of hundred million dollars elsewhere, Matt, and stick to budget.

Yes.

I mean, obviously, we did consider that, Paul, that the -- but we really feel as if the scope -- the original scope that we laid out for the assets was we should be delivering that, and then these opportunities to sort of modestly increase the capital were going to be value adding on top of that.

So we didn't feel as if just to stick to the capital program for the sake of doing that without recognizing the extra value that we could add here.

We didn't think that would be appropriate.

So we made the decision to do -- I mean, it's a 3% increase in capital.

It's not that significant but it's -- we believe that both of those uses in Alaska and in the Eagle Ford are something that the shareholders would want us to do.

Yes, I guess that's kind of the point, which is that it's such a minor amount.

It's almost just -- not such a minor amount but it's a relatively minor amount.

I just thought that maybe the optics could've been better if you managed to stick with the number.

Part of the reason for saying that is simply that you're running ahead of growth while you're running strongly on growth, which again would suggest that maybe you could actually work towards pulling back a bit on spending.

Is that a fair assessment, on growth, I mean?

Certainly, we're ahead of our growth schedule for the year because of a significant outperformance in the second quarter, really driven by the Big 3. But for the full year, we still feel as if it was prudent for us to hold the same long full-year outlook because as I said in my prepared remarks, there was quite a significant amount of acceleration in the second quarter numbers.

So although yes, we appear to be heading -- we appear to be ahead of that, there's no real change for the full year.

Understood.

If I could ask just a quick one that you might not want to answer and then a bigger one.

Firstly, is there any timing on Qatar, best guess?

And secondly, where do you go from here on disposals after North Sea?

No, we don't really have anything new to add to the timing expectations for Qatar.

The -- it's clear that Qatargas is making progress in developing the project, but we don't really have any additional insights that we can offer on the timing of when they'll select partners at this time.

In terms of dispositions, we -- yes, we have the U.K. disposition to close and then that's proceeding well.

We have a few smaller dispositions that are in the works around the portfolio.

But if there's anything significant to report on that front, we'll do it when we have something to report.

And our next question comes from Alastair Syme from Citi.

A couple of questions.

In the past, I think both of you actually have mentioned that Permian M&A doesn't really compete on a cost of supply basis versus the portfolio.

Just interested if you're seeing any change in seller expectations given the sort of the recent weakness in equity values.

And my follow-up, I'll just give it to you now, but on Corridor, the Indonesian PSC, I think you've mentioned sort of in previous discussions that it was probably going to be quite challenging to renew.

So I wanted, what sort of changes have happened and how does that match up on the cost of supply?

Okay, Alastair.

I think I'll take the first question and I'll pass on to Bill for the details on the Corridor PSC extension.

So you're asking, do we -- have we seen a change in Permian seller expectations.

We're not really in that market asking sellers what their expectations are.

So I would say no, we're not seeing a change from that perspective.

The -- we still believe that there's a mismatch between what people expect for their assets and what would compete as a use of capital for our capital and that may change over time.

So that's why we're focused on the sort of really -- the relatively small but very high-value additions to the portfolio through acquisition that we announced over the past few months.

So no significant change in expectations there.

On Corridor, I think, Bill?

Sure.

Alastair, it's Bill.

Happy to discuss the Corridor extension.

We were really pleased that the Minister of Energy and Mineral Resources announced that we've been awarded a 20-year PSC for the Corridor Block and that we're going to be continuing our 45-year presence in Indonesia.

That PSC is going to begin on Dec.

20, 2023.

That's immediately following the expiry of the existing PSC.

We'll have a 46% working interest, that's prior to a 10% dilution for local governments that's required by the government regulations.

It is a new gross split PSC, term PSC and it's got a signature bonus of $115 million net to ConocoPhillips.

And we expect we'd make that payment upon completion of definitive documentation.

You also see that it's got a commitment of about $100 million net firm work commitment, but that's during the first five years of new PSC, so it really doesn't start until 2024.

It is a robust low cost of supply extension and we're pleased that we've been granted that.

Can I ask, will the entitlement -- net-net, will the entitlement production be lower going forward versus what you have today?

Sure.

The production will be a bit lower.

Obviously, the working interest is down about 13% and then it's on gross split terms.

Our next question comes from Paul Cheng from Scotia Howard Weil.

Two questions.

One, maybe I think both of them should be Matt.

In Permian, when -- do you think that now is the time or that do you have a time line when you will become more aggressive in pushing the activities there?

And second, I think you made some comment about Austin Chalk.

So is that at this point based on what you see which should significantly downscale the potential over there?

Are there opportunities there?

Okay.

Thanks, Paul.

Yes, we will be, over time, increasing our activity in the Permian as we move from the mode that we're in just now, which is essentially making sure that we're optimizing the well spacing and stacking and the order of which we tackle the various zones that exist within our Permian acreage.

Once we've got that completed, then we'll increase to more sustainable rig count there to build towards plateau.

And we are going to talk in more detail about that in November, for sure, so that you can understand the question.

But we want to put that in the context of this overall work on optimizing the plateau.

So more to come on that.

But yes, you were asking, will we ultimately become more aggressive in the development of our Permian resource position?

Yes, we will.

On the Austin Chalk...

Sorry, Matt.

Does that mean that that's not next year or that maybe it's more like in the 2021 or 2022 before you begin more aggressive on the manufacturing?

Yes, it'll be a few years out before we get to the rig count that will ultimately take to plateau, yes.

On the Austin Chalk, yes, we've tested three of the four wells that we had to test the Austin Chalk play there.

And it's just that as we brought those wells on, the petroleum system isn't working as effectively as we hoped it would.

The Chalk hasn't dewatered to the extent that this requires to get high enough production rates.

I mean, unconventional wells produce high water cuts in other plays, in the Delaware Basin, for example.

So that by itself is not a disqualifier.

But here, the water cut that we've seen is being -- it's been a bit over 90%, the oil rates have been about 100 barrels a day.

It's just unlikely to be enough to justify development in that part of the play.

Though there are targets in the Wilcox and there are targets in the Tuscaloosa Marine Shale, so the acreage is not condemned but that primary target in the Austin Chalk doesn't look encouraging just now.

Okay.

Can I just sneak in a final real quick one?

On the Eagle Ford for the second half of the year, is your target is just being conservative or that you are slowing down the activity from the second-quarter level?

Paul, it's Dominic here.

No, I think basically, what we've seen on Eagle Ford this year is an acceleration of our wells online into the second quarter.

So if I look at the total wells online count we expect this year, it's the same.

So the character of the growth profile is basically an acceleration of the ramp and then relatively flat for Eagle Ford for the remainder of the year.

Our next question comes from Bob Brackett from Bernstein.

A question on Alaska.

I'm kind of curious around the timing of development or sort of pre-FID developments.

Mentally, we sort of thought about Willow being 2021 FID and then maybe Narwhal and West Willow.

Does that still make sense?

And where does Nuna fit into that development pipeline?

Bob, this is Michael Hatfield.

Thanks for the question.

You're right as far as the timing of Willow with the results that Matt was talking about from an exploration and appraisal perspective, we're very encouraged by that.

We're actually sizing facilities now and expect to get to FID here in 2021.

We do see first oil from Willow probably in the 2025-2026 timeframe.

It's around about the time that we had talked with you all about when you were up in Alaska last year.

At Nuna, I'll just provide a little bit of color on that.

It's a discovered resource on 21,000 acres that's in our backyard.

It's immediately adjacent to Kuparuk.

It's a very low cost of supply, in the low $30s.

It's $100 million for 100 million barrels.

It's something we're very pleased about.

It will be developed from pads both that exist at Kuparuk and a pad at Nuna where there's already gravel and a road to that pad in place.

The remaining facilities at Nuna can be built in a single ice-road season.

So we'll have appraisal over the next couple of years and target first oil in the 2022 time frame.

The development will be using existing drilling and completion technology and then the development itself will be incorporated as part of our Kuparuk program, so it won't be incremental to that.

So we're very excited about this low cost of supply bolt-on acquisition.

Great.

And then what about the 2020 exploration program?

What's the focus?

Yes.

We're actually putting the plans together for that now.

We're going to be drilling in Willow, and the primary focus is on understanding the extent of Willow so that we can fully size the facilities.

We're also going to be drilling a prospect to the southwest called Harpoon.

We'll drill several wells in Harpoon, at least that's the current plans.

We'll talk to you more about that in November.

Our next question comes from Devin McDermott from Morgan Stanley.

So my first question I wanted to ask about some of the opportunistic bolt-on acquisitions and specifically on Argentina.

Just the opportunity set that you see there longer term and how that fits into the strategy and perhaps from a cost of supply or return standpoint, how it competes with other shale in your portfolio?

Yes, I'll take that, Devin.

This is Matt.

The -- yes, so we've picked up this about 25,000-acre position in the Vaca Muerta.

Of course, the shale is very like the Eagle Ford but it has some characteristics of the Permian in that there are multiple stack pays within there.

It's in the oil leg and the -- it looks to be in a very good geography.

There could be north of 5 layers within the play across this acreage.

Our expectations on a success basis here would be certainly north of half-a-billion barrels of potential on the acreage that we picked up.

So we see the Vaca Muerta as probably the best international play, the best unconventional play outside North America, and this represented a really good low cost of supply entry into the basin for us.

There aren't any significant work commitments, there are work commitments but they're not significant, and we will be able to manage them within our exploration budget over the next several years.

Got it.

That's helpful.

And my second question is on Alaska.

You mentioned in your prepared remarks some issues at one of the wells on the GMT development.

I was just wondering if you could quantify the impact a bit more what you're seeing there and then talk about whether there's an opportunity to remediate that or offset that either later this year or maybe down the road in 2020 or beyond?

Yes, Devin.

This is Michael.

We've had underperformance at GMT-1.

The development was brought online last year and ramped up to the plateau rate.

It's a smaller development.

There's only four producers that are in this development.

So any one producer that underperforms ends up significantly impacting the overall development, and that's been the case here.

I should mention that despite this underperformance, with the capital reductions that we had while we were executing the project, we actually delivered the project for what we had expected in terms of cost of supply.

We don't see remediating this at this point, but we are continuing with our GMT-2 plans where we've taken the learnings from GMT-1 and applied those to this different reservoir at GMT-2.

Our next question comes from Scott Hanold from RBC.

On Canada, Matt, you talked about obviously using the alternative diluent and it was going to improve the netbacks going forward.

Can you kind of quantify what that means in terms of how much incremental income or revenue you'll see from that?

Yes.

This is Michael again.

With the all-diluent project, we would -- so it will depend on the season.

But in general, as we think about a year-on-year improvement, it would be say, $1 to $2 a barrel or so.

When we look at the total improvement from a blend ratio perspective, we'll be reducing about -- actually improving about 35% from a total blend perspective and that's upward of a couple of dollars a barrel.

One of the big advantages there, Scott, is that the flexibility because as Michael was saying, it could be $1 or $2, it could be quite a bit more than that sometimes because the market moves, the price of condensate versus the price of synthetic, the value of the drill bit versus the value of a synbit, and we have the flexibility here to run all synthetic, all condensate, some blend of the 2 and we can batch it as well.

So this will be perhaps the only plant with a truly active optionality in the what we choose to blend with the bitumen and that's going to unlock a lot of value over time.

Okay, that's great color.

And then one really quick one.

I think the last quarter, you talked about having some excess firm -- gas firm in the Permian region.

Were you all able to take advantage of some of the weak pricing and be able to monetize that this quarter?

And can you give us a sense of like how much capacity you've got there and any kind of terms you have out there?

Yes, Scott, this is Don.

Yes, some of the things you're asking are fairly commercially sensitive so probably can't give you a whole lot on that.

I would just maybe say that our offtake out of the Permian is multiples of what our equity production requires.

And yes, we continue to be able to take advantage commercially of the low Waha prices.

I think they averaged in the second quarter minus $0.01 and so we do purchase in the Permian.

We take it to points west and capture margin on that.

Second quarter was -- probably wasn't quite as active for us as the first quarter, but that's going to continue until some of the new pipelines like Gulf Coast Express and others come on later this year.

Our next question comes from Pavel Molchanov from Raymond James.

One more following up on a previous one regarding the gas situation.

What's the latest that you're seeing as it relates to flaring, particularly in the Permian, given some of the capacity constraints?

So this is Dominic here.

Thanks for the question.

I think in terms of our own situation, we don't have a particular problem because we have very good offtake, as Don has just talked about.

I think that's really a question of when this new gas export capacity is going to come on and we see that, as Don said, there's some significant pipelines coming on at the end of this year and we see quite a lot coming thereafter.

So I think this is something that's going to get resolved in pretty short order.

Okay.

And I'm sorry if you addressed this earlier but income tax in Q2, 22%, the lowest I think in about 8 quarters.

Were there any special moving parts that explain why it was so low?

Yes, Pavel, this is Don.

Yes, our reported effective tax rate was 22% during the quarter so we did have a number of special items.

So we provide in our supplemental information our reported ATRs as well as our adjusted.

And so I think you saw our adjusted ATRs was about 40%, which is typically where we are or would expect to be.

So the difference between those 2 are going to be the special items where we either pay no tax on those items or we're paying very low tax.

And so those get -- that's what drives down the reported ATR.

So in the quarter, for example, we have -- we had a pretty large tax benefit associated with our U.K. sale.

And of course, being a tax benefit, it has no tax on it.

So that's a zero tax rate.

We had something similar on the Sunrise disposition.

And then you look at the earnings that we get from our equity affiliates.

Now the taxes on equity affiliates are paid at the equity affiliate level, so that it won't get reported in our corporate level.

So those earnings are effectively zero from an effective tax rate standpoint.

So in the quarter, we had a large number of special items with that either no tax or low tax type treatment.

Sanera, this is Ellen.

I -- It sounds like we're out of questions.

That is correct.

We have no further questions at this time.

Okay, everybody.

Well, thank you very much for joining us today and by all means, if you have any follow-up questions after the call, feel free to reach out to us.

Thank you for your ongoing interest in ConocoPhillips.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.