康菲 (COP) 2018 Q1 法說會逐字稿

Welcome to the First Quarter 2018 ConocoPhillips Earnings Conference Call.

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

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

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

You may begin.

Thanks, Christine.

Good morning, everybody, and welcome to our first-quarter earnings call.

Our speakers for today 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.

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

And of course, actual results could differ due to the factors that are described on this slide as well as in our periodic SEC filings.

We'll also refer to some non-GAAP financial measures today, and that's for purposes of facilitating comparisons across periods and with our peers.

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

(Operator Instructions)

And now I'm going to turn the call over to Don.

Thank you, Ellen, and good morning.

I'll start on Slide 4. We've gotten off to a good start this year by demonstrating another quarter of strong execution.

Starting on the left side of the chart with strategy, we again delivered on all our strategic priorities.

We increased the quarterly dividend by 7.5 percent.

We paid down $2.7 billion of debt, bringing our total debt to $17 billion at the end of the first quarter.

As you know, at our AIM meeting in November, we set out a target to reduce debt to $15 billion before the end of 2019.

Given the improved outlook for the business and our current cash balances, we intend to accelerate our debt reduction by an additional $2 billion this year, thus achieving our leverage target a year early.

This is consistent with our priorities, and we believe it sends another strong signal about our commitment to discipline.

With respect to buybacks, we repurchased $500 million of shares this quarter, and we're on track for a total buyback of $2 billion in 2018.

This is another return of capital to shareholders that was increased during the year -- during the quarter, this time by 33 percent from the target announced in November.

Since our buyback program began in late 2016, we've repurchased about 75 million shares, or 6 percent of our share count, at an average price of about $48 a share.

One of our stated priorities is to return 20 to 30 percent of operating cash flow to shareholders.

This quarter, we again exceeded that, returning 34 percent of CFO to shareholders through dividends and buybacks.

So strategically, we continue to hit on all priorities.

We're maintaining our discipline and following our game plan.

Moving to our financial performance in the middle column.

Adjusted earnings were $1.1 billion for the quarter or $0.96 a share.

We generated $2.5 billion of cash from operations, excluding working capital, and that exceeded our capital spending by $1 billion.

Free cash flow more than funded the dividend and share repurchases for the quarter.

Finally, we ended the quarter with $5.5 billion of cash on hand.

Moving to our operational results on the right.

We've also had a strong start to the year.

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

Adjusting for dispositions, our underlying production grew 4 percent compared to the first quarter of last year and was up 26 percent on a per debt-adjusted share basis.

We announced the acquisitions of unconventional acreage in the Louisiana Austin Chalk play and the liquids-rich Montney, as well as the bolt-on acquisition of Anadarko's position in the Western North Slope of Alaska.

We also completed an active and successful exploration program in Alaska.

So to recap, this quarter's performance, again, reinforces our commitment to keeping our discipline while delivering our plan.

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

With WTI averaging about $63 a barrel and Henry Hub about $3 an MMBtu, our average realized price was around $50 a BOE.

As you can see in the bar graph on the left, compared to the prior quarter, adjusted earnings improved almost $600 million due to higher commodity prices, lower depreciation expense and reduced operating cost.

Compared to the year-ago quarter, adjusted earnings improved by over $1.3 billion, driven by a 40 percent improvement in realizations and about a 30 percent reduction in depreciation expense.

The table on the bottom right shows a comparison of year-over-year adjusted earnings by segment for the first quarter.

I would draw your attention to the Lower 48, where only two years ago, we had an earnings breakeven above $70 a barrel.

We're seeing the earnings power of our unconventional engine driving the bottom line results, with our Lower 48 earnings breakeven now at less than $45 a barrel.

If you turn to Slide 6, I'll put the significant improvement in our earnings and cash flow expansion into perspective.

The chart on the left illustrates the product mix shift in our portfolio since the first quarter of 2017.

Through strategic dispositions and targeted investments in high-margin production, we've increased our exposure to higher-value products such as crude oil and international gas, including LNG.

At the same time, we've significantly reduced our exposure to lower-value products such as Canadian and U.S. natural gas and bitumen.

The chart on the right shows that our improved earnings and cash flow are not driven by price increases alone.

Here, we show the improvement in realizations compared to the first quarter of 2017, from about $36 to $50 a BOE.

The green boxes indicate how much of that realization gain came from product mix improvements and how much came from price increases.

Over 40 percent came from mix improvement.

Our product slate is now capturing over 75 percent of the Brent price, a further indication of how leveraged we are to rising Brent prices.

If you turn to Slide 7, I'll wrap up with a look at our cash sources and uses during the quarter.

First, looking at the sources of cash shown in green, the combination of cash from operations and dispositions was $2.7 billion.

In red, we used $2.9 billion to retire debt, and we spent $1.5 billion of capital, which includes about $120 million for the Montney acreage acquisition in Canada.

We paid $300 million of dividends and repurchased $500 million of shares, returning 34 percent of cash from operations back to shareholders in the first quarter.

In the red box labeled Other, we included our bolt-on transaction in Alaska for $400 million, which will be moved to capital once we receive final regulatory approval.

As I said before, and it is worth emphasizing, this was all done while generating $1 billion of free cash flow in the quarter, which more than funded our dividend and repurchases.

Again, a strong financial start to the year.

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

Thanks, Don.

I'll provide a brief overview of our first-quarter operating highlights and our outlook for the rest of the year.

So please turn to Slide 9.

Overall, as Don mentioned, production, excluding Libya, averaged 1,224 thousand barrels of oil equivalent per day, beating the top end of our quarterly production guidance range.

Now as you'll remember, our prior guidance reflected an assumption of a fourth quarter -- of a full quarter, not fourth -- full quarter shut-in of KBB export production in Malaysia due to a third-party pipeline outage.

Our production improvements were driven by the power of our diverse portfolio, with contributions from the U.K., Alaska and Indonesia, but the majority came from improved performance and completions timing in our Eagle Ford asset.

We had a strong operational quarter in our Big 3 unconventional assets.

Production for the Eagle Ford was 163,000 barrels equivalent per day.

Bakken produced 68,000 barrels per day, and the Delaware produced 19,000 barrels per day.

That adds to 250,000 barrels per day for the Big 3, representing a 20 percent increase in production year-on-year.

In addition to the ongoing development operations in the Lower 48, during the first quarter we announced the acquisition of early life-cycle unconventional acreage in the Austin Chalk of central Louisiana.

We're currently in the process of permitting exploration wells and expect to begin drilling in the position later this year.

In Canada, we took steps to mitigate the impacts of the weak WCS differential in the first quarter by piloting the use of condensate as an alternate to synthetic crude diluent at Surmont.

We're encouraged by the results so far and believe this unique capability will improve netbacks and provide us a valuable diluent flexibility going forward.

Also in Canada, as Don mentioned, we announced our bolt-on in the liquids-rich Montney of 35,000 net acres, where we're currently appraising our position.

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

I'll talk about those further on the next slide.

In Alaska, we completed our exploration and appraisal drilling program after announcing the acquisition of Anadarko's acreage earlier -- acreage interest earlier in the quarter.

We drilled six wells.

Increased drilling efficiency allowed us to add an additional appraisal well to the original five-well exploration scope.

This was our largest exploration program in Alaska since 2002, and a successful one.

So far, we've tested four of the Willow discovery and appraisal wells, and the results are in line with our expectations.

We confirmed that Willow has a recoverable resource potential of more than 300 million barrels.

We also drilled three exploration wells, West Willow, Putu and Stony Hill, all of which were new discoveries, confirming that we have additional running room on the Western North Slope.

Now I'll discuss the operations outlook as we move into the second quarter on Slide 10.

Our $5.5 billion capital guidance is unchanged.

As you know, this excludes the capital for the previously announced Alaska bolt-on and the Montney acreage acquisitions.

We continue to execute the $5.5 billion scope we outlined last November, and we're working to mitigate the pressures on our program from inflation, foreign exchange fluctuations and increased partner-operated activity.

For full year, we're increasing our production guidance to 1,200 to 1,240 thousand barrels per day to reflect our strong performance in the first quarter and adjusting for disposition assumptions.

This increase comes despite now assuming that the KBB export volumes will be down for the entire year.

In other words, we're confident that due to the strong performance we've seen around the world, and especially in the U.S., our diverse portfolio will more than offset the expected roughly 20,000-barrel-a-day production loss from KBB.

So based on guidance, we expect to deliver 5 percent production growth, 7 percent production growth per share, and about 14 percent production growth per debt-adjusted share.

Although that latter number is based on ending the year at $17 billion of debt, based on the $15 billion year-end debt number that Don mentioned earlier, our production growth per debt-adjusted share would increase to about 16 percent.

Our second-quarter production guidance is 1,170 to 1,210 thousand barrels per day.

This assumes our typical 2Q, 3Q turnaround season in APME, Europe and Alaska.

In the Lower 48, we'll continue to deliver high-margin production growth in the Big 3 throughout the remainder of the year.

We're confident in our Big 3 growth plan, and as I said on the last call, growth may be lumpy quarter-to-quarter but we expect to exit the year at above 300,000 barrels equivalent per day from the Big 3.

So we're executing well on our Big 3 unconventional programs, but we're also executing strongly in the conventional business as well.

Before the end of 2018, we expect to achieve first production from several projects, including Bohai Phase 3 in China, Clair Ridge in the U.K., Aasta Hansteen in Norway, GMT-1 in Alaska, and the final phase of Bayu-Undan development drilling, which will continue feeding the Darwin LNG plant in Australia.

We'll be continuing our appraisal work in the Montney and beginning our central Louisiana Austin Chalk appraisal program.

We'll also continue to gear up for our 2019 Alaska winter exploration and appraisal program.

So we had a strong operational quarter, which translated to a strong financial quarter, where we executed our plans with capital discipline, while generating $1 billion of free cash flow.

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

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

Al, I wonder if I could start on your Capex comments that you just alluded to there, I guess.

Obviously, inflation pressures have been talked about backwards and forwards, but I think the increase in third-party activity, I wonder if you could just give us a little bit more color as to what you're seeing there.

And just really more of a question of it's probably (inaudible) to revisit the spending program.

Is this more something you'll likely revisit, let's say, midyear?

And if I can risk a third piece to that question, you're lining up a lot of opportunities longer term.

So how do you see, since the Analyst Day, your opportunity set impact from the Capex outlook that you guided toward back in November?

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

Okay...

Oh, Doug, I don't know...

Let's see, which...

Just a Capex question.

Yes.

Capex, okay.

Well, I think, as I mentioned, we're still at our $5.5 billion Capex guidance.

We do see pressure, as I mentioned, in three different areas: inflation, ForEx and OBO.

You asked specifically about the partner-operated side.

We are seeing considerably above what we had expected ballots from our partners in various areas, dominated in Lower 48.

And so of course, that will bring volumes with it as well, although a lot of those volumes don't come until next year.

But for us, the choice when we receive those ballots is, if it looks like economic work, which it typically does, we either have to elect in and spend that money or we get into a penalty situation or we lose the rights to those reserves.

So as that comes in, we're going to elect to do those and that does put some upward pressure on the Capex.

But we're continuing to work to offset those upward pressures with increased efficiencies we're seeing, significant increased efficiencies in our work.

And so it's really too early to tell how all that's going to add up at the end of the day.

With respect to scope going forward, we're still on the plan that we talked about in November at the Analyst Meeting, where we expect to average around this $5.5 billion over that three-year period we laid out '18, '19 and '20.

I mean, there are some things on the horizon that potentially could be incremental opportunities for us down the road.

You've heard us talk about the Qatar expansion.

We're in the running for that and hoping to be able to win a piece of that business.

That was not in our plan that we showed you in November, so obviously that would be upside.

But if we're able to win that, that's something that investors are going to want us to invest in.

You've also seen the exploration success in Alaska.

That's another area where -- that wasn't reflected in our November plans that could be upside.

But these are not things that are going to affect 2018 and '19 Capex in a big way.

It's sort of 2020 and out beyond that.

I appreciate you indulging the question, Al.

My follow-up is really a quick one.

The buybacks, we all know what the cash flow outlook is, but you've still got your Cenovus shares.

And now you've got this interesting situation last night that you're now in all of a sudden, PDVSA.

I'm just wondering if you could elaborate as to maybe on the PDVSA piece, specifically, what are your options there?

Is that something that could ultimately result in another kind of step change in buybacks similar to the CVE shareholding that you still have?

And I'll leave it there.

Well, Doug, this is Don.

Yes, on the PDVSA question, of course, that's a nice award from the ICC tribunal as a result of our arbitration.

We have another one coming later this year, probably from ICSID as well, so we'll see what the total of all of that is.

But that's not something we're going to be able to book a receivable on any time soon.

So I don't think that, that's going to require some enforcement action on our part.

And we intend to be aggressive and persistent in that but it's something that's going to take time to recover our -- the value that we lost when they expropriated our assets there.

So I think it's a little too early to start thinking about that in terms of uses of cash.

And then, you mentioned Cenovus as well.

Of course, yes, we've got somewhere around $2 billion worth of Cenovus equity.

And really, the story hasn't changed there.

We're not a strategic investor, don't intend to be there for the long term, but we're also not an anxious seller as well.

So we'll wait until we think that the value is right.

Right now, we think the value -- the company is undervalued.

So someday, we'll be able to liquidate that and put that money to work elsewhere.

Our next question is from Phil Gresh of JPMorgan.

First question just on -- you talked about the balance sheet a bit with where prices are now, and it sounds like capital spending is going to -- you're looking to try to offset the inflation and maintain the capital spending budget.

So how do you think about the excess uses of cash, Don?

Is there any chance you might put a bit more on the balance sheet just for a rainy day, or even -- obviously, you've done a great job of buying the stock back at what now looks like great prices.

But how do you think about that issue on a go-forward?

Good questions, Phil.

With our plan to accelerate the debt reduction and reach our target sometime this year, $15 billion, and then, as you say, we're going to continue to constrain capital and work hard to live within our budget there.

We've pretty much eliminated two pretty key uses of cash.

So the options are getting narrower.

So what we've said is -- I mean, we just increased our buybacks, what, two months ago, from $1.5 billion to $2 billion.

We increased our dividends a couple of months ago, 7.5 percent.

So I can't steer you one way or the other today on that.

But we've said that our distributions to shareholders will continue to grow as our cash flow grows.

What was the second part of your question again, Phil?

Oh, on the stock price in the buybacks?

Yes.

Exactly.

Well, I'll tell you what, if you -- some of the key factors that we take a look at, obviously, the CAGRs on our production growth on a debt-adjusted share basis.

And if you look at our cash flow -- cash margin expansions in this sort of environment, then we think our stock is well undervalued and has a lot of upside to it.

Our next question is from Neil Mehta of Goldman Sachs.

The first question I had was around APLNG.

Am I right to say in the first quarter in the cash flow that there was no dividend recorded from APLNG that came in, in April?

And if so, can you quantify what the cash flow associated with that dividend was?

Yes, Neil, that's correct.

We did not receive a dividend in the first quarter from APLNG, so that's not reflected in the cash flows for the quarter.

A dividend was declared in the first quarter but it was paid in April, this month, so we did receive a dividend from APLNG and the amount was $105 million to ConocoPhillips.

That's great.

And the follow-up question is just the Big 3 production profile for the balance of the year.

Can you just talk about where you see it going from here and a little bit by basin as well?

Okay.

Yes, I talked earlier in the prepared remarks about the Big 3 hitting 250,000, so that was up 6 percent quarter-to-quarter and 20 percent year-over-year first quarter of '18 versus first quarter of '17.

And I frankly don't expect you to be too impressed by that 20 percent number.

We said in November, we were going to grow the Big 3 22 percent, and we keep improving all the time and the latest well results we've seen have been very impressive.

So I certainly expect our operating teams to beat that 22 percent.

So I'm not expecting you to be impressed with 20 percent, and I expect it to be better as we go forward in the year.

I think that it will be lumpy as I said.

And some of the lumpiness smoothed out a little bit.

We had some Eagle Ford completions that we thought we wouldn't get until the second quarter that sneaked their way into the first quarter.

But I think you will see strong numbers as we go through the year.

And just to put a finer point on that, if I can say it without Ellen kicking me under the table, maybe, but last call, you may remember I said I thought we would exit -- we'd have an exit rate that would be above 300,000 for the Big 3. I think if you look at the latest well performance and how things are going for us, it's clear to me now that, that 300,000 that I was kind of calling an exit rate at the last call is going to happen quite a bit earlier in the year.

Our next question is from John Herrlin of Societe Generale.

Just some quick upstream ones for Al.

With Alaska, given the success that you've had, what kind of cycle times should we expect in terms of you actually bringing on incremental production on the North Slope?

And then also with the Austin Chalk, when will you start talking about that?

Will that be third quarter or fourth quarter?

Yes.

So on Alaska, of course, we have a lot of -- a pretty nice pipeline of projects, midsize sort of projects we're bringing on, GMT-1 is the one we expect to start up by the end of this year, and then, GMT-2 will be next.

We hope to take FID on next year, that would start up in sort of the 2021 time frame.

We've got production still coming up at CD5 and at 1H NEWS, so a lot of different projects that are in the pipeline there.

In terms of the new discoveries, which is what I think you're really asking about, Willow, and also Putu and Stony Hill, what I said about a year ago on this call when we first announced the Willow discovery, was that in the best case scenario where we got all our approvals, particularly the federal approvals that have been difficult to get in the past timely, the earliest we could start up would be 2023.

I think that's still the case, but that's a bit of a theoretical timing that would require more rapid federal permitting than we've experienced in the past.

But that is possible within the rules.

So you should sort of think of that as an earliest time frame, I think, for Willow.

And as one of the questions we've had is, is Willow going to be a tieback or is it going to justify a standalone facility?

And so that's part of what we're after in this appraisal program is making sure we understand the subsurface well enough to make the right decision for what's the highest value.

And we -- I think we can see from the appraisal work in Willow that it's looking more and more like it will be able to justify a standalone facility.

And then, you can have things like West Willow, which is our new discovery further out to the west, tying back to that.

So that's not a decision we've taken yet, but certainly, the appraisal program strength points us in that direction.

Okay.

And then, what about Austin Chalk, when will you...

Yes.

So on the Austin Chalk position, so we're up to, I think it's about 211,000 acres now across a pretty wide area.

And we plan -- we're in the process of permitting the first exploration wells, which we'll be able to spud depending on the permit timing later this year, might be late third quarter, early fourth quarter, somewhere in that time frame.

So I expect it'll be into 2019 by the time we actually have results from that program or be able to start to characterize what we think we have there.

Our next question is from Doug Terreson of Evercore ISI.

During the quarter, your like-for-like production grew by 4 percent year-over-year, even with the outage that you guys talked about in Malaysia.

So I want to see if you could comment on the driver of the gains and also the resiliency that you're seeing in the portfolio outside of the Big 3, meaning in areas such as Alaska or Indonesia or really any of the other areas that seem to be exceeding expectations, because it certainly appears to be fairly resilient in many areas.

Okay.

Sure, Doug.

I think it's a particularly good question because a lot of the outperformance we're seeing in the first quarter is part of what's given us the confidence to increase our full-year number.

We were 24,000 barrels a day above the midpoint of the range we had given in the first quarter.

And that was -- you're correct, about 4 percent growth versus that quarter in the prior year.

Of course, that's with the loss of 2 percent from KBB so it would have been 6 percent if we had that.

But if you look at where that plus 24,000 comes from, about 11,000 of it was from the Lower 48, as you've kind of alluded to, but we did have strength in a number of other areas.

We continue to outperform with the base in Europe and both the U.K. and Norway as we were about a plus [7] to expectation from better uptime and better base performance in Europe.

As you've heard me talk about before in Alaska, our project and our well performance has been strong there.

We got about [3] more than we expected.

In Indonesia, we had higher demand for our gas because of some third-party coal-fired power plants that had unplanned downtime.

We picked up a plus [3] there.

We also had better uptime in cutter and got about plus [3] there.

The only real negative we had in the quarter was at Surmont.

We were about [2] short of where we had expected at Surmont, really due to diluent supply shortages and other market factors.

So that's kind of -- you add all that up, that's the plus 24,000 total.

Okay.

And then, also, for Don, on Venezuela, your point's taken on recoverability from PDVSA given the circumstances.

But while we're on this topic, I wanted to see if you could give us somewhat of a status update there, damages you're seeking and the next steps for the ICSID proceeding, which I think you alluded to, is going to have a next step later in the year.

So could you just kind of remind us where we are with that proceeding?

Yes.

Maybe just give you a brief recap as well because it is kind of complex because we have multiple proceedings going on there.

Of course, one concluded yesterday with ICC.

The important thing about the ICC award that was about $2 billion.

Of course, that doesn't come anywhere close to compensating us for our full losses of value in Venezuela, but it never was expected to.

And so I'll try to explain that a little bit.

That was a contractual matter between ourselves and PDVSA, and it had to do with indemnity that they provided to us for discriminatory actions that the Venezuelans took when they expropriated our assets.

And so that -- the limitation on that indemnity was spelled out in the contract in a formula, basically.

And that formula had caps on it.

So we knew that that award was always going to be capped and really, only would represent a partial compensation for our total losses.

Now we move to the other claim that we have, which is not against PDVSA, but against the government of Venezuela, and that's the one that's being heard at ICSID.

And that process -- there is no cap involved in there, and we expect that that result, which we hope to receive a notice of an award later this year, that, that will represent a full compensation for our value loss.

Our next question is from Paul Cheng of Barclays.

For Don, a quick -- a key one.

First is for Don, and a quick one.

For the APLNG, the $105 million that you're going to receive in the first quarter, is that represent a full cash flow in excess of the internal usage, such as the project financing, and also, the payback of the project financing, and also the Capex?

Or that you actually, even with that, you're already building cash?

You did mention first quarter.

That was received, actually, in the second quarter, Paul.

So I just wanted to correct that.

Right.

Understand.

I'm just saying that if we're looking at a $67 Brent, that means that the APLNG, if you assume that you already feel comfortable for the joint venture cash balance going forward, is that $105 million is the -- a reasonable estimate?

Or that, that should actually be a higher number?

I have a hard time saying whether that's a reasonable estimate.

It all depends on what the price is and what the net cash flow within the joint venture is.

I mean, we can just say that it was $105 million in April.

Now I can tell you that...

Let me ask it another way, Don.

If you take out $105 million from the cash balance by the end of the third -- by the end of the first quarter, is that balance higher than year-end, within the joint venture?

That was the available cash.

That was the cash -- that represents the cash that was available to be distributed.

Okay.

All right.

Maybe I will take it offline.

The second one, Al, for the Surmont.

Any takeaway issue that you -- because of the problem over there that made you to change the way to how you operate?

Well, we don't have a takeaway issue per se in terms of being able to move our barrels to market.

The takeaway issue is really the constraints that have been in place for a number of months now that have widened out the WCS differential and really hurt our netbacks.

Our netbacks were doing pretty well.

We had some pretty decent cash margins at Surmont in the second half of last year.

And then, as there were a few operational issues at other -- that other folks havd on pipelines, it did create some backup.

And so one of the things I also mentioned that we've had some -- we've been using synthetic crude oil as our diluent, that's how the plant was set up and there've been some supply issues there, a number of repeating supply issues over the past year, 1.5 years.

And so we're moving forward to make what are really some minor -- fairly minor facilities changes there that will allow us, by the third quarter of 2019, to be able to run any mix of condensate or synthetic crude oil that we want to as diluent.

We can create a Dilbit by running all condensate.

We can create a Synbit by running all synthetic crude oil or we can create a Syndilbit by running a mix.

And we're in a process of piloting those sorts of things now.

And as we look back at the volatility of the various factors involved here in the market, we think having the flexibility to go back and forth is going to be a really valuable and unique attribute to the Surmont plant.

Do you guys have any committed pipeline volume at the existing pipeline from Alberta, down to the Gulf Coast?

Or that you are selling all those down in the local market?

Let me tell you what our current situation there on the marketing side is, Paul.

We're currently, on a blend basis, we're at like 150,000 barrels a day of Surmont blend that we're moving to market.

And so, probably, on a rough-cut basis, the best way to think about that is we have probably around 100,000 of that 150,000 is going into the local Edmonton trade market, and then, we've got about 25,000 barrels going to the U.S. by rail.

So the -- and to Cushing and some into the Gulf Coast as well.

And then we have the balance of that 25,000 barrels a day is on pipe being exported into the U.S., into the Midwest and the Gulf Coast.

Our next question is from Roger Read of Wells Fargo.

Just -- Al, you've been talking and bragging about the 250,000 which certainly is good.

We did hear a lot about weather in the quarter as restricting some of the production.

So I was just curious, was your 250,000 affected by that somewhat, which means your sort of higher growth rate is more achievable as the year goes along?

Or are we looking at that as a pretty clean number?

Yes.

We were impacted by weather.

We don't like to whine about weather.

But we have -- we were hit about 14,000 barrels a day back in January in a number of our different areas.

So divide it by [3] to get a sort of [4] or [5-ish] impact on the quarter.

Not too big.

But we were able to more than offset that with our performance.

And so you don't really need it in the math.

No.

I appreciate that.

Just trying to get a feel for the exit rate versus maybe the average there.

And then...

Look for the timing on that 300,000.

That's going to be the interesting thing.

All right.

I appreciate that.

We will be watching it.

And then, my second question is, you look at the decision to make the acquisitions, both in the Montney and Louisiana.

You're talking about the Capex pressures elsewhere.

Kind of help us to understand maybe what the kind of the return thought process is there of moving into, I don't want to call them frontier-ish, but I mean, certainly, not frontline opportunities for production growth and cash flow.

So like, you got the share repo.

You've got your other undeveloped reserves, and then, you're making some additional acquisitions.

I was curious how that all kind of flowed together.

Yes.

Well, you can think about it from a number of different perspectives.

I mean, for one thing, the money that we've spent on some of these bolt-on-type opportunities, including in the Western North Slope, really was funded by -- we got our Ecuador legal settlement, $337 million of cash that came in, plus in the last few quarters, we've had about $250 million of cash come in from the smaller asset sales we've been doing.

And so that $600 million or so has largely funded some of the smaller bolt-on kind of things we've been doing.

Of course, the bolt-on in Alaska is -- once we get the regulatory approval, that's immediate.

These other things you're asking about, remember, these are sort of dollar -- $1,000 an acre or less kind of longer-term things that are for the 2020s.

They're not going to bring us volumes this decade.

But they're not costing us much money right now.

They fit within--they're a part of our natural exploration budget.

So they'll displace other things in the exploration budget that we had already laid out that was part of our math during the Analyst Meeting in November.

And they are an opportunity to be very competitive, total cycle, full cycle cost of supply with the other things that are in our resource base.

That's why we like them.

Okay.

Great.

And then, if I could sneak one in just to follow Paul on the APLNG, on his dividend question.

The run rate that generated that was based on kind of what crude price?

And then, how should we think about the fact that crude price has moved up, certainly, from Q4, Q1, to now, how that flows through and to maybe the expectation for dividend payments?

Well, the $105 million was based on the crude prices that they recognized during the first quarter, but also the beginning cash balances as they entered into the year.

They had been building some cash up, not a great amount, during the fourth quarter.

And I think one thing you had to factor if you're trying to forecast this precisely is that there is, on the LNG sales in Asia, there's always the three-month lag so you've got to lag your prices.

I think another factor may be that may be causes some difficulty here is the lumpiness of the loan payments.

We don't have a loan payment every quarter.

It's twice a year.

It's twice a year.

And so we build up cash to make the next loan payment.

So it's may be not as ratable as people are thinking.

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

Don, I was hoping to go back to Phil's question on uses of cash flow.

I just wanted to kind of confirm, is the $15 billion debt target subject to being revisited?

Or is that pretty much a hard number, and we can just think once that's accomplished, the rest is just going to simply be distributed?

That's a hard number.

Okay.

The second piece, Al, you kind of talked quite a bit about the Canadian, I guess, discounts and takeaway capacity, et cetera.

I'm also curious, obviously, this past quarter, we've seen a lot of discounts in the Permian crude differentials.

And I was hoping you could talk a little bit about what kind of takeaway capacity you have there?

How exposed are you to the actual Midland pricing as opposed to getting that down to the coast and realizing something more like LLS?

Maybe I can talk about that a little bit.

Right now, our -- we don't have export -- any significant export capacity out of the basin in the Permian.

So we're fully exposed to the Midland Cushing differential.

Of course, in the first quarter, the realizations in the Permian were actually quite high.

I think we got around 98 percent of WTI, but we're going to see the impacts of that, it looks like, in the second quarter.

Now looking longer term, a number of the midstream companies are entertaining open seasons on long-haul transport into the Gulf Coast.

And we are active in that.

But that sort of shipping capacity wouldn't be available until the second half of 2019 at the earliest.

Our next question is from Ryan Todd of Deutsche Bank.

Maybe -- and ask a specific one in the Eagle Ford.

I mean, you've talked around the issue on how your performance seems to be exceeding expectations there.

Can you give any additional color on what you're seeing today in the Eagle Ford versus your original expectations?

Is it better per well productivity, drilling efficiencies?

Any thoughts on cost there?

And then, I've got one asset-related follow-up.

Well, it's yes, yes, and yes.

By the way, you win the prize for best title this morning on your note.

I think in the Eagle Ford, we are seeing better per well performance.

Our latest generation of completion design, and we have a new generation that we're getting ready to test next that may give us yet even better results.

You can go into the public databases and just look at the last four years and look at the different vintages of wells, and you'll see the pretty dramatic improvements that we've had.

We also are continuing to drive down our costs.

We're getting quicker drilling times per well, lower well costs, and also, continuing to optimize our completion costs.

Data analytics is a very powerful force in the Eagle Ford.

That was really the first place in the company where we built a comprehensive data warehouse.

And that has -- it's -- I think in the last few years, we've doubled the number of wells that can be handled by each multiskilled operator out in the field because of all the tools that we've given them.

And we've been able to drive our lifting costs there down well below $2 a barrel.

It's very efficient.

So we get great margins out of the Eagle Ford.

It's not just a matter of the volumes; we've had improving margins.

And while everyone else has been banging away in the Permian, a lot of people left the Eagle Ford to do that, and there's just been less competition for goods and services in the Eagle Ford and better netbacks because there've been less people trying to jam their barrels down the same takeaway capacity.

So everything about the Eagle Ford is really hitting on all cylinders for us.

I think that continues to be a real bright spot for us and I think will.

So it's not just volume.

I think we are going to see really good volumes out of the Eagle Ford this year, but there's a lot more to the story than that.

Great.

That's helpful.

And then, maybe, on Darwin LNG, I think you're -- based on your partner's comments, you've seen a recent peak in terms of LNG production there.

It seems like there's moving closer to a potential FID at the Barossa backfill option.

Any thoughts on what you see the potential timeline there, general thoughts on the asset going forward and maybe insights on potential LNG contracting there?

Sure.

The Darwin LNG plant is a great asset.

It's a jewel for us that has performed great.

We've been able to increase the capacity of that plant significantly over the years since we've built it, and it's really performed well.

We want to keep it full.

So I've seen some things in the press where they said that ConocoPhillips has been accelerating Barossa or moving faster.

That's really not the case.

We've been on the same schedule for several years.

It's been apparent to us when Bayu-Undan is going to run out of gas and it coincides with when the PSC expires as well, and also, when our current LNG sales contracts expire.

All that happens in 2023.

So we've known for a long time, we've got to have something else ready to flow gas to Darwin in 2023.

I mentioned in my prepared remarks that we're now -- we just spud a few weeks ago.

We're in the last phase of development drilling at Bayu-Undan.

So this will be the last handful of wells that allow us to drain all the gas from Bayu-Undan by 2023.

And then Barossa has been on a steady schedule.

I said on the last call that I thought by this call, we'd be at or near entering FEED, and that did happen as you saw on the news earlier this week.

So we're right on schedule there.

And we expect to take FID in late 2019 if everything continues to move down the tracks.

We've already gotten our regulatory approval from NOPSEMA, which was -- that's a difficult thing to get.

We've got that in hand.

We had unanimous vote from the partners this week to move forward into FEED on all the different pieces.

So I think everything is working well there.

We are very, very focused on this project on capital efficiency.

Everything we're doing in the way, the FEED is set up, including a design competition for the FPSO, is all designed to really drive forward capital efficiency on that project.

Our next question is from Guy Baber of Simmons & Company.

I wanted to go back to cash flow, but in light of the fact that you guys did not receive a dividend from APLNG, the cash generation this quarter seemed especially strong relative to the sensitivities.

So I'm wondering if your simplified cash flow sensitivities actually are conservative now because of some of the margin enhancements you all have highlighted, and because we're now north of $65 barrel Brent, which was the upper end of the band of the sensitivities, I think, that you provided.

And just as one example, it seems that your Lower 48 realizations in particular are really strong relative to WTI and Brent and have improved quite a bit perhaps due to Eagle Ford, as you mentioned.

But anything more specific you would call out on those Lower 48 realizations or in the Eagle Ford, specifically?

No.

I think, Guy, just overall, since we introduced those cash flow sensitivities back in, I think it was November '16, we've been tracking, what, seven or eight quarters -- six or seven quarters, maybe, and they've really done well.

I mean, they've been very precise in their predictive capacity, I would say.

And even in the first quarter, they also came pretty close to what our actual cash flow, ex working capital was.

But maybe for some of the wrong reasons, because we had the low realizations in Canada, but then, we had stronger realizations in the Lower 48.

So I think you're right.

The cash flow generating ability of the company may be understated somewhat by the sensitivities that we updated just this past November.

So we are looking at it.

And as you say, we are at the upper end of the range pricewise of what we've said those sensitivities are good for.

We did take a look at it here in the last couple of weeks and we think it's still okay, but we're going to continue monitoring it.

And if we feel like it's no longer has its predictive capability, then we will provide new guidance.

Our next question is from Michael Hall of Heikkinen.

I guess, first, I wanted to just ask on the KBB pipe, to get into a little more detail on what exactly is creating the delays on bringing that back on.

Are there any issues with the metallurgy there?

What sort of costs might be associated with repair and/or replacement of the pipe?

And is that all factored into Capex at the moment?

Yes.

So the KBB pipe, there's no issue around metallurgy.

We have no ownership in the pipe and so there's no impact on cost to us.

It's just strictly a third-party arrangement.

And so really what -- the cost is not a factor for us.

They had a weld failure that was really caused by a mudslide.

So this is a remote area with some pretty difficult terrain and heavy rains and sort of the earth moved and caused excess strain on the pipe.

So the problem is it's a very difficult area for them to get to, and there's a number of these potential mudslide areas.

And so they have a lot of -- a very comprehensive plan of repair for the pipeline.

And we expect -- we don't really know when the pipeline's going to be up, and we're not really in the middle of it because we have no ownership.

And so we're just assuming -- we're assuming at this point, it will be down for the whole year.

We don't really know that for sure.

Okay.

Appreciate you clearing that up.

And then, just curious, as a follow-up on the Permian.

You noted, obviously, things are looking tough on the differentials on the forwards.

If things get bad enough in the Permian from a price realization standpoint starts to weigh on valuations in the basin, is that an area you guys would consider being opportunistic in on a longer date basis?

Or was that not really on the agenda?

Yes.

I mean, it -- we never say never.

We're always looking at everything but, that's not -- I don't really see that.

You look at the pricing on recent things that have happened.

And on a full-cycle basis, we struggle to see how that would compete in our existing portfolio that we've showed you, the cost of supply of our existing portfolio, and it's -- you just do the math on the prices being paid and it's hard to see how that works.

But things could change, you never know.

And our last question is from Pavel Molchanov of Raymond James.

Just one more question about the Permian, from a gas perspective.

Obviously, a lot of conversation about constraints in gas takeaway capacity and the possibility of flaring later this year or next year.

Are you experiencing any pressures of that sort in terms of your gas volumes in the Delaware?

No.

We're really not and we don't expect to either.

ConocoPhillips is one of the largest gas marketers in the United States, and we're -- the U.S. Southwest, including the Permian area all the way out to the SoCal border, is an area that we're very large and very active.

So we transport a lot of third-party gas out of that basin and across the U.S., and so we have plenty of capacity available for our equity gas.

And if we ever got in a bind, we can back out third-party gas.

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

Thank you, everybody.

Thank you, Christine, I appreciate it.

And obviously, if we left any questions unanswered, feel free to call us anytime over the next day or so.

Appreciate your interest, everyone.

Thanks.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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