Welcome to the third quarter 2018 ConocoPhillips earnings conference call. My name is Christine and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. 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. Hello, everybody, and welcome to our third quarter earnings call. Joining me today are Ryan Lance, our Chairman and CEO, Don Wallette, our EVP of Finance, Commercial, and our Chief Financial Officer, Al Hirshberg, our EVP of Production, Drilling, and Projects, and Matt Fox, our EVP of Strategy, Exploration, and Technology. Our agenda for today's call is to have Ryan review our key milestones from the third quarter, from the year-to-date, and then some of our focus areas for the remainder of the year. I want to note that all of our usual financial and operational highlight slides are included in today's deck in backup for your information. They're very straightforward. After Ryan's remarks, our plan today is to go directly to Q&A. Our cautionary statement is shown on page two of today's deck.
We will make some forward-looking statements during the call that refer to future estimates or plans. Actual results could differ due to the factors described on this slide and in our periodic filings with the SEC. Finally, we'll also refer to some non-GAAP financial measures today, and that's to facilitate comparisons across periods and with our peers. Reconciliations to those non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and also on our website. Now I'll turn the call over to Ryan.
Thanks, Ellen, welcome everyone to today's call. 2018 has been another exceptional year for ConocoPhillips. Slide four summarizes our achievements from the third quarter and the first nine months of the year. Our value proposition is all about returns. We're laser-focused on disciplined free cash flow generation and strong execution. Discipline means we're not chasing higher prices by ramping up activity. By staying disciplined, we generate strong free cash flow, which we then allocate in a shareholder-friendly way. Underpinning our discipline and cash flow allocation is predictable, consistent execution quarter in and quarter out. Our commitment to these elements has driven strong results across the business in the third quarter and throughout this year. Starting with our strategic milestones on the left. Earlier this month, we announced a 7% increase in our quarterly dividend rate. In July, we increased our 2018 buyback target to $3 billion.
That's the pace we're on for the year. At the same time, our board increased the total authorization to $15 billion, representing about 20% of our shares since the buyback program began. This sent a strong signal to the market that we have confidence in our plans for continued shareholder value creation. The combination of our dividend and buybacks represents a return to shareholders of about 35% of CFO, well in excess of our 20%-30% target. Importantly and distinctively, these distributions were funded organically. We're delivering on all our strategic priorities. That means focusing on all aspects of value capture. For example, there's been a lot of interest in our ICC proceedings with PDVSA. We announced in August that we had reached a settlement agreement to fully recover the arbitration award of about $2 billion. This was a major milestone in this effort.
This quarter, we recognized $345 million of that settlement. We are collecting. Finally, we continue to optimize our portfolio and have announced about $600 million of additional dispositions over the past few months. Our financial performance has improved consistently throughout the year. Stronger prices help, but we're also benefiting on a relative basis due to our Brent-weighted mix and from ongoing efforts to mitigate inflation risks and keep a lid on costs. In the third quarter, we generated $1.6 billion or $1.36 per share of adjusted earnings. Here's some interesting perspective. The last time ConocoPhillips generated quarterly adjusted earnings of $1.6 billion from continuing operations was in the third quarter of 2014. Brent was over $100 per barrel, and our production was almost one and a half million barrels of equivalent oil per day.
We're as profitable today as we were then, despite prices being 25% lower and volumes being 20% lower. Bigger isn't always better. That's why we're focused on per-share growth and value, not absolute volume growth. Our portfolio and efficiency efforts have boosted the underlying strength of our company and driven what we believe is peer-leading sustaining price of less than $40 WTI. We've significantly improved our resilience to low prices without capping upside for investors. That's the key to outperformance through the cycles. Cash from operations in the third quarter was $3.5 billion, and CapEx was $1.6 billion. We generated almost $2 billion of free cash flow, which more than funded our dividend and buybacks. Year-to-date cash from operations is $9.1 billion. This exceeded CapEx by $4 billion.
Of this free cash flow, over $3 billion has been returned to our owners. We also further reduced debt while keeping our CapEx in check and maintaining strong liquidity. At the end of the quarter, we had about $4.8 billion of cash and short-term investments on hand. Our balance sheet is in great shape. Our debt reduction target was achieved 18 months ahead of schedule. The credit rating agencies have noticed. They've responded with recent upgrades. We are now single A-rated by all three of the agencies. Importantly, since our value proposition is all about returns, let me give you a current snapshot. Our 12-month trailing return on capital employed is now in double digits, and our cash return on capital employed is over 20%. Those returns should continue to improve.
Strong financial performance is possible because of consistent, predictable execution on the operating side of the business, the organization again delivered this quarter like they have done all year. Third quarter production, excluding Libya, was 1.224 million barrels of oil equivalent. That's underlying year-over-year growth of 6% on an absolute basis and 28% on a per debt adjusted share basis. Our disciplined plan remains very much on track, and we expect to close out 2018 on a strong note. Our key annual turnarounds were completed safely, and our operations are running smoothly. We recently started up conventional projects in Alaska and Asia Pacific, with two additional startups expected in Europe this quarter. We recently sanctioned GMT II in Alaska and spud our first exploration well in the Louisiana Austin Chalk. We're building good momentum heading into 2019. In December, we'll announce our 2019 operational plan.
You can expect our capital to be roughly in line with this year's capital, excluding acquisitions. I think this is a clear indication that we're not straying from our strategy, no surprises there. This quarter marks the second year of our anniversary of when we launched our disciplined return-focused value proposition. At that time, we established a leadership role in executing what we believe is the right strategy for this cyclical business. We're committed to maintaining consistency and discipline through price swings. This is fundamental. Our sustaining price of less than $40 gives us a distinct advantage at lower prices, and we offer investors unhedged exposure to higher prices. As we head into 2019, you can count on us to remain disciplined, focused on free cash flow generation, and strong execution of the business. That's our formula for delivering superior returns to shareholders through the cycles.
We know it's a formula that works, we're sticking to it. Let me turn the call over to Q&A.
Thank you. Ladies and gentlemen, if you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your phone now. Our first question is from Phil Gresh of J.P. Morgan. Please go ahead.
Good morning, and thanks for the call, Ryan. I guess I'll ask a question on the capital number that you referenced for 2019 since you're willing to give that. It sounds like obviously you're not looking to ramp up spending. You do have, I think, some roll-off spending from some projects that are ramping here in the fourth quarter. Do you expect any activity increase, say, in lower 48 in 2019? If not, is there a scenario where you would consider it? Obviously we have a lot higher price now than we did before.
Yeah, Phil, thanks. As I said, I think we're staying pretty committed to our discipline plan. Wanted to give a signal to y'all about where we see 2019 headed. I'll let Al chime in on a bit more detail about that. We expect our capital to be roughly in line with where we're at today, all things being equal. There are some moving parts within the portfolio that are important, and I think Al can provide you a little bit of color on that.
Yeah. Phil, we obviously haven't set our exact capital number for 2019 yet. We'll do that in December and announce it to the market then. Ryan's already given you a pretty strong hint at how it's going to turn out. Really, consistent with where we've been all year. We don't plan to make any significant changes to our activity level in the Big Three in the lower 48. We do have some new projects that will be attracting CapEx in 2019 higher versus 2018. We also have the acquisitions in Alaska this year. Let me mention a few numbers there. We've got GMT II in Alaska, Barossa that is progressing, and we're starting to spend more CapEx. Also the Montney, it's really still in the appraisal phase, but we are building processing capability and water capability that'll be adding to our CapEx next year.
In addition, we have our increased working interest at Kuparuk, assuming that we close there on that deal, and in the Western North Slope. When you add all that up, about $500 million ± of increased CapEx in 2019 versus 2018 for those things. We also have some significant roll-off of major projects that are finishing up
You've got Aasta Hansteen, Clair Ridge, Bohai at phase 3, and the Bayu-Undan infill wells. When you add all that up, that roll-off, it's also about $500 million. Those roughly offset each other. That's how we get to a plan that is roughly what Ryan was describing, where the major project roll-on and roll-off are roughly offsetting and we're staying similar in our Lower 48 activity levels.
Okay. That's very helpful. Thanks. I guess the second question, Al, for you would be some of the topics of the day here just on takeaway. There's been a lot of talk about frac commitments for NGLs as well as Bakken takeaway. Maybe you could just elaborate how Conoco is positioned on these issues.
Phil, this is Don, maybe I'll take that one. As far as fractionation capacity overall for NGLs in the Lower 48, we're in pretty good shape. We're not seeing any takeaway constraints relative to the Bakken. Certainly within the basin, everybody can see that processing capacity is starting to get pinched there with the growth in the Bakken production, about 150,000 barrels a day year-over-year, and additional competition from the Canadian imports as well. We're not seeing takeaway problems on the gas or the processing or the NGL side up in the Bakken, and we don't anticipate any. The midstream companies that we work with have expansion plans that we expect to be in place toward the end of 2019.
Yeah, Don, just to be clear, on the Bakken, I was talking more on the crude side. I was just trying to understand how much do you put on DAPL versus do rail, and any color on those dynamics?
Yeah, I'd be happy to, Phil. I don't know that I want to get into specific pipelines, but generally the way that I think or we think about the Bakken, kind of three different market centers there. You've got the Rockies refining center that's sort of the local market, and then we have access through pipe commitments to the Midcontinent so kind of the Chicago area, Patoka, Clearbrook. And then the third is Cushing, and we go in all three different directions. I would say that lately, we have flexibility, so it shifts from one quarter to the other how much is going into each location. In the third quarter, I believe a good estimate would be about 50% is sold within the Rockies. That gives you an indication of our exposure to, say, Guernsey type pricing. Probably 30% to Cushing and maybe 20% to the MidCon.
And we're not-
Okay, great. Thanks.
We're not seeing takeaway constraints there.
Okay. Thanks. I'll turn it over.
Thank you. Our next question is from Doug Terreson of Evercore ISI. Please go ahead.
Good morning, everybody.
Morning, Doug.
Good morning.
On Venezuela, Ryan, you mentioned the $345 million payment from PDVSA in the quarter. I think that another $500 million is expected by year-end, and you guys get the remainder over four and a half years. My question is: Is this the correct profile for those cash payments? Is that the right way to think about it? Second, given the uncertainty in Venezuela, is there any recourse that you have if PDVSA doesn't pay on schedule? How are you guys thinking about those two things?
Doug, let me just clarify. Don's been on point for us. He can chime in too as well. We recognized $345 million of revenue in the third quarter from the settlement. That's part of a total of $500 million that we should receive this year. We should get
Got it
The remaining part between the $345 and the $500 in the next month or so.
Okay.
We start a monthly or a quarterly amount that we get till the full $2 billion is paid full to ConocoPhillips. We have provisions if they miss payments to go back after some of the assets. Maybe let Don elaborate on that a little bit.
Maybe just to drill down into a few more facts around that, Doug. As Ryan mentioned, our settlement agreement called for $500 million of early payments, or we refer to them as initial payments, as part of the $2 billion collection from the ICC award. That $500 million was comprised of two components, really. You'll probably recall that we seized crude inventories as part of our enforcement actions. That was about 4 million barrels of oil that had a notional value of around $300 million. That was the commodities element of that. We've been marketing that oil, and most of it has been lifted. We still have some to go. The other component were two cash payments of $100 million each, and the first cash payment was due the first week of October. PDVSA provided that the last week of September, actually.
The second payment is due in November, that sums up the total $500 million that we anticipate that we'll collect during 2018. As Ryan mentioned, we go into a quarterly payment schedule of around $85 million a quarter for, I believe it's the next 18 quarters or however long it takes to recover the full $2 billion.
Okay. Also, Ryan, you mentioned that your financial performance is the best it's been since, I think, second or third quarter of 2014, when Brent was above $100. Going forward, obviously, if this performance continues to be strong and spending's not rising much, which I think you implied, debt reduction program's mostly complete, the question becomes: What are the plans for, or priorities for surplus funds going forward? Meaning, would you allow cash to build on the balance sheet, increase share repurchases? What are some of the parameters around the thinking in that area?
Thanks, Doug. We've said we're holding our activity level. We like to execute a constant level of activity through the cycle. That does say as we generate the cash flow that we see the ability to generate, what do we do with that? I'd say at this point in time, we feel comfortable with the averaging, the constant level of buybacks that we're executing. We'll watch the market, see how that's going. I think you should expect to see cash probably rise on the balance sheet.
Okay.
We'll also address that in a bit more detail in December. Right now that's where we're headed. You ought to see our net debt fall a little bit.
Great. Thanks a lot.
Thanks, Doug.
Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead.
Hey, guys. Good morning.
Good morning, Paul.
I don't know, maybe this is for Al. Al, have you guys shut in any production in Surmont, given the price that it must be pretty close to, if not below your cash variable cost there?
Yeah. We've talked about some of the shut-in production or curtailed production that we had back in the third quarter. I talked about it on the last call. In the fourth quarter, we also do have some small curtailments that are driven by netbacks and trying to just maximize our cash there. It'll be in the round off in terms of our production volumes, in terms of the numbers.
Do you guys have any intention to sign any well deal related to Surmont production?
Oh, Paul. Yeah, we have a good bit of Surmont blend going on rail right now. I think in the third quarter, we had maybe something like 45% coming to the U.S., maybe 55% sold into the Edmonton Trade Hub. These are kind of rough numbers. Of the amount going to the U.S., it was pretty evenly split between pipe and rail, maybe a little bit more on rail than pipe.
Don, do you have any intention to increase that given that there's some fear that the situation could get far worse before you get better?
No, that's exactly right. Even in the fourth quarter, we're going to see, I mentioned, what, 45% going to the U.S. in the third quarter. That's going to rise above 60% in the fourth quarter, and almost all that increment is on rail. We are expanding our rail capacity.
Okay. Those are long-term minimum volume contract, or these are all based on spot?
No, these are term contracts. I don't know. They're not as long as the five-year deals that you hear about, the rails are insisting. We got in and got these contracts before the terms got that onerous. The intention is to bridge us over to the next major pipeline expansion. A few years.
Right. The benefit is showing up in your price realization already, or they are showing up somewhere else?
Say it again, Paul?
I didn't understand, Paul.
No, the benefit. Given that if you're looking at the cost to rail it is much less than what the discount currently will imply. I assume that once you value it down, you get the Magellan price, and so that your price realization comparing to the Edmonton, if you sell it there, will be much higher. I guess my question is that in those volume, the benefit that you will see, is it showing up just simply on the price realization is higher than you report, or there's something else that we should look for?
No, it will show up in the realizations. That is going to vary from one quarter to the next. Currently, pipe is going to give by far the highest realizations, at least it does under our arrangements, followed by rail. Because our rail cost into, say, Cushing or to the Gulf Coast is generally not in the high teens. It's more in the low teens.
Okay. A final one for me. Ryan, there's some concern in the industry that as we clear up Permian, we're just going to shift the bottleneck in the middle of the country into the Gulf Coast because the export capability may not be sufficient by early 2020. Where you stand in that debate, whether you guys will try to be more active, trying to accelerate the build-out on the export capability?
I'll let Don chime in as well, Paul. We see the same thing as most industries been looking at, is the bottleneck gets eliminated from pipe in the Permian and moves to the Gulf Coast. We'll be exporting a lot more crude. I can let Don comment on how we're thinking about that more specifically.
Paul, we think that the Gulf Coast is going to require expansion. There are plans in place in both Corpus, Ingleside, and Houston to expand the export capability, we think those plans are proceeding along at a good pace. Just to give you some numbers on ConocoPhillips, we've sold probably something about around 10 million barrels over the docks this year. It's going to vary a lot from month to month or quarter to quarter, depending on whether the ARB's open or not. On average for the year, that would be about 35,000 barrels a day, or in other terms, it represents about 30% of our Eagle Ford sales. Currently, we don't have transportation to the Gulf from Permian, so that's all Eagle Ford. Those exports have helped our realizations. That's one of the reasons why our realizations are so strong.
In the third quarter, our waterborne barrels averaged WTI plus about $3 net back to the Eagle Ford lease. Really good performance there. Just generally from an industry, you're asking about more the industry capability and the wave of Permian production coming into the Gulf. Right now, we think the Corpus-Ingleside area has about 800,000 barrels a day of export capacity. Recently in August, they exported about 400,000, so right now, 50% of their capability. If you move up to Houston, we estimate about 1.6 million barrels a day of export capacity at the Port of Houston. In August exports were 400,000 barrels a day. A lot of surplus capacity in Houston. Corpus has active plans to dredging and adding buoys and things like that that are going to grow export capacity over 2 million barrels a day by 2022, late 2021.
I think a lot of this is going to depend on, obviously, the pace of Permian production. Just looking at the pipeline schedules, the new pipes being built out of the Permian to the Gulf Coast, it looks like those pointed toward Corpus are probably going to go in first. We'll probably see a little bit of bottleneck at Corpus initially. Once the pipes going from the Permian to the Port of Houston, the ship channel come on, then that should alleviate the bottleneck. As we look at it and back up, we think, yeah, there's probably going to be some tightness, particularly at Corpus, probably in late 2019 when these pipes start up. We're probably talking about bottlenecks in terms of months rather than years. We don't think this is going to be a significant problem.
I mentioned our export capacity. I will confirm that we are, and have been actively discussing expanding our capability in that regard. We think that's going to be important over the next few years.
Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Thanks, Doug. Good morning, everybody. Thanks for getting me on. Can I start with a fairly asinine housekeeping question, if I may? I just noticed that in the non-recurring charges, you're still rolling through some restructuring and impairment charges on the P&L in the third quarter. Are you guys done with your cost-cutting initiatives, or is it still going on? Just so you could frame, is that legacy or is it something new?
We're chuckling to ourselves, Doug. Yeah, go ahead.
Yeah, I can talk about that one. Well, no, we're not done, and we're never done. Despite the higher volumes, the increase 25,000 barrels a day that we've had to our guidance since the start of the year, we're still planning to hit our original OpEx target, $5.7 billion. We've done that by shaving about $0.25 a barrel off our unit operating cost. As an example of one of the kinds of things we've been doing as we continue to focus on our costs, even as oil prices have come back up, we recently had a reorganization in our Houston center and our Lower 48 organization, the increased productivity and organizational effectiveness that we've had there has allowed us to reduce our Houston staffing by about 10% this year, including sort of open jobs that we didn't fill.
We have some severance costs that are associated with that. We expect that effort alone will allow us to decrease our Lower 48 G&A cost by about $0.30 a barrel next year. We're continuing to work away on it even for us, it's not higher prices are back, so we can quit focusing on that. We're continuing to work, that's what that's associated with.
I appreciate the answer. Just to be clear again, Al, there's a bit of an asinine part to that. The $5.7 billion, that includes transport, right? Transportation's in and out OpEx?
Yeah. It's what we call our kind of controllable cost. It includes transportation.
It's got lifting costs in it, including transportation, but it also has G&A in it, other costs.
The Alaska piece, like TAPS and so on, that's in there as well, or no?
What was that? The TAPS? Yeah.
Yeah.
It's in there as well.
That's in there as well. Okay, great. Thank you. My follow-up is really, hopefully, a relatively quick one. Obviously, Ryan, you guys have set the bar pretty high, as it relates to capital discipline. You've got a lot of stuff still coming online, which is obviously helping the momentum on the tailwind on production. My question is, as the balance of these project spending rolls off, as you get through the stuff that Al mentioned, there's also a lot of things out there that you guys appear to have been competing for example, Qatar LNG, as well as the ramp up in Barossa that you talked about already. I'm just curious, what do you think happens to the longer-term capitals plan beyond 2020?
If you could maybe give us a refresh on where you see the sustaining capital today, given the inflationary environment, I'd appreciate that as well. Basically, two parts to that, the longer-term CapEx, assuming you won some of those projects, and what's the sustaining capital look like in today's environment? I'll leave it there. Thanks.
Thanks, Doug. Maybe Matt can chime in on the sustaining capital. He's pretty close to that. I would say, we're pretty disciplined in trying to make sure we generate the free cash flow. You're right, we have some very good projects that we're competing for, and hopefully, we'll be successful in the North Field expansion in Qatar. We need to backfill our LNG facility in Darwin, Northern Territory. Then ultimately, hopefully, we'll have more exploration discoveries coming in Alaska. We've got things on the plate. With that said, we have projects that are rolling off, and we continue to look at the portfolio, and we continue to make adjustments in the portfolio to account for what we see coming in as capital. We'll talk some more about that.
We'll describe that in more detail here coming forward, the 2019 plan in December, and how we're thinking about that, then ultimately how we're thinking about the long term as well. We won't lose our discipline. We'll keep a steady scope in what we're doing in the Lower 48 unconventionals. We're starting our exploration results in the Austin Chalk. As Al mentioned earlier, we have a stacking and spacing pilot going on in the Montney. We're going to manage all that within the portfolio and make sure that we keep our discipline on the capital side. Specific to sustaining capital, I can let Matt chime in there.
Doug, you may remember, I think you asked me a similar question last year at the analyst meeting about what would happen to sustaining capital over time.
Right.
I said that we would see increases in sustaining capital, but what we were actually focused on was maintaining the low sustaining price. What we'd anticipate moving ahead is that the sustaining capital that we talked about last year was $3.5 billion or so. We'd expect that to move through next year into 2020 to $3.8 billion. That's about the same amount of increase in sustaining capital as the increase in production. But the sustaining price is not increasing. The sustaining price is still well below $40 a barrel. As we're anticipating, we're getting some modest increases in sustaining capital over time as the production's increasing, but we're not seeing any increase in sustaining price at all.
Matt, just to be clear, on the last call, you ticked up your CapEx for this year on inflation. Has there been any inflationary impacts on that 3.8?
Yeah. I can talk about the inflation effects on 2018 if you like. That's not a key thing that's driving that. It's really just having a higher level of production. Like Matt said, your production goes up 10%, your sustaining cost is going to go up 10%.
Yeah. Reflecting things like the acquisitions in Canada and so on. It's not inflation-driven.
Got it. All right. Thanks a lot, guys.
Alaska, sorry. Yeah.
Thank you. Our next question is from Alastair Syme of Citi. Please go ahead.
Thanks. Matt, this first question might follow on a little bit from that. As you look at the inventory on your cost to supply, presumably you've updated this through the summer. Is the shale piece still expanding at a lower cost point? You certainly get a sense in the market that some people are saying shale has been pushed up the cost curve. Interested in your observation on that.
No, we have been updating our supply curve. Maybe later in the year or early next year, we'll be finished with that work, and we can talk more about it. What we are seeing is an increase in the unconventional resource from our existing land positions, and actually still a decrease in the cost of supply associated with that. We're not seeing either a reduction in the resource or an increase in the cost of supply. Quite the reverse.
Okay. Sorry, Matt, is that spread across the shale portfolio, or is it specifically the Eagle Ford? Or is there any way?
It's spread across the shale portfolio as a whole, basically reflecting efficiencies and changes in completion designs that are increasing recovery and so on. It's across the whole portfolio.
Thank you. My follow-up is just on your scenario analysis. You look at all the factors as a global demand and supply. How's the scenario analysis shaping up? It sounds as if you still believe in unrelenting shale. Is there anything on the demand side you see?
Yeah, the scenario that we're in just now would be on the supply side, the unrelenting unconventionals. That's still happening. Right now we're in a place of relatively high demand for our scenarios. We're in a place where we've got supply increasing, but demand matching it. We haven't really seen any change. We go through a scenario monitoring process every year and try and reassess the probabilities of those scenarios as we look out in time. Really, we haven't seen any significant change this year in how we see those playing out.
Great. Thanks for that. Thanks very much.
Thank you. Our next question is from Bob Brackett of Bernstein Research. Please go ahead.
I had a follow-up on the PDVSA arbitration. Could you talk about what that means for the other ongoing arbitrations? I'm thinking with Venezuela specifically.
Yeah, Bob, this is Don. We have two other arbitrations related to Venezuela. The biggest by far is the ICSID arbitration, which is a claim against the Republic of Venezuela for expropriation. I think previously we had indicated that we expected the results of that damage award to be made public in the fourth quarter of this year, and we've been since informed that that's slid, and we're being told now that those results will be announced in the first quarter of next year, 2019. The other is a smaller potential award related to an offshore development, not a heavy oil project, that was called Corocoro, and that's an ICC award or arbitration.
I'm sure there's an interest in how all these different arbitration actions relate to each other. What we've said is that if ICSID, for example, comes up with a higher award, which is what we would expect, than what ICC came up with this past spring, then we wouldn't be looking for dual recovery. To the extent that they address the similar issues, there would be an offset. One would offset the other, and we'll just have to go through the final result from ICSID to determine what additional compensation Venezuela might owe us.
You're saying that if the ICSID number was higher, you'd sort of offset that against the already claimed ICC award?
Yeah, to the extent that they addressed the same issues. There will probably be instances where they're dealing with different components that the ICC didn't address, and in that case, it wouldn't be overlapping. Yeah, there's a potential for a significant amount of overlap between the awards.
Yeah. That's clear. Thank you very much.
Thanks, Bob.
Thank you. Our next question is from John Herrlin of Societe Generale. Please go ahead.
Yeah, thanks. Getting back to the CapEx question, fair to say that on a mixed basis, you're going to be still 60% plus sustaining, 20% plus short cycle, the rest long cycle?
Well, the sustaining will be in the $3.8 range.
Yeah
6.1. I don't know what that ratio is, but it's roughly a bit less than two-thirds sustaining.
Okay. Thanks, Matt.
We would expect that to stay similar, John.
Okay, thanks. With the Montney, when will the gas processing and water be in place so you're going beyond the testing mode?
On the Montney, we've talked in the past about the 12-well pad that we're putting in right now. That's really a spacing and stacking pilot. We're drilling well number 9 right now of the 12. In fact, well 8 that has already been drilled, we put in our proprietary fiber optic diagnostic system. We're using this opportunity in appraisal mode to also collect a lot of extra data to help map out the future development of our entire acreage there. Construction is currently underway on the processing plants, the flow lines, the water handling systems. All that is in progress. We've also made additional takeaway commitments on both the liquids and gas side there to support the next phase of appraisal on all the production that comes from that. You'll see all that starting to come online next year.
Latter half, Al?
Yeah. It'll be in the back half of next year.
Okay, thanks.
Of course-
Last one for me is on dispositions.
Sorry.
Last one for me is on dispositions. Still little things to come out, like the Barnett? Can you give a sense of how much you're going to do a year, ballpark?
Yeah. We announced the Barnett, the $230, and the Sunrise at around $350. Those are the ones that we've announced recently. Yeah, we would expect to continue to be taking action on the portfolio over time. It could be lumpy. What we indicated in the past is that we could be looking at dispositions in the $1 billion-$2 billion on average over time. We
They all come in a sort of lumpy nature. We are still looking at that aspect of the strategy to make sure that the portfolio is as strong as it can be.
Thanks, Matt.
Yep.
Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.
Yeah, thanks. Good morning.
Morning.
Morning.
I guess let's keep with the Canada theme here for a bit. Big LNG project got announced for Kitimat. Should we anticipate that's ultimately where a lot of the Montney gas development that you're doing would be able to go? Or should we think about it as dependent on another exit route?
Yeah. Our current work that we're doing on Montney gas exports so far is not going to Kitimat. It's going to more traditional routes and coming south, yeah.
What's your identified pipeline routes for that then? Other alternatives, maybe locally?
Yeah. There are pipelines that come reasonably near past our acreage, some of which are getting full and new ones being built. We're not really in the mode of talking about which pipelines we're talking to right now. Over time, we'll have to take on quite a bit of pipeline capacity to meet our full plans over a period of time.
Okay, thanks. Just a question coming back to the kind of the CapEx versus production growth expectations. You walked through earlier kind of the shift of $500 million from one to another in terms of completed projects and new projects. As we think about the base spending, yet the ability to deliver growth, is the efficiency you're seeing, whether that's straight up productivity gains or just a change in well lateral lengths and so forth, is that going to be equivalent with the rate of growth we should expect production-wise?
Well, certainly, you've seen with another quarter's worth of data that we're continuing to do better than the 22% CAGR that we had laid out in our Analyst Day, we've indicated more like a 35% is what you'd expect this year. That has largely been driven by some of the outperformance that you referenced. Of course, that also gives us a higher level of production this year that makes it harder to keep growing it. With what we have right now, you wouldn't expect you would keep maintaining that same kind of 35% CAGR without yet some new breakthrough that comes along that allows you to continue to have these large improvements that we've seen this year. We'll see how that plays out over time.
We don't see any signs that we're at the end of the road on new ideas on the technology side and continuing to improve and continuing to get more efficient on the drilling, which has led us to more wells online this year than we had in our plan. I talked about that last quarter. That's one of the things that increased our CapEx some this year was we've drilled more wells with the same number of rigs. We got more wells to complete, more production, it has increased our one of the things that's increased our CapEx some this year. We're working on all of that for next year, that's part of what we'll be talking with you about in December is the details around the CapEx plan and the production volumes that we expect.
Great. Thank you.
Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead.
Thanks very much. I appreciate the opportunity to ask a question here. The Big Three up 48% year-over-year, certainly a surprise relative to our model. I was curious how those numbers were tracking relative to your own expectations, and any thoughts in terms of which of the basins were surprising, and then any early thoughts in terms of growth levels for the Lower 48 going into next year given your views on activity?
Yeah. It follows on to some of the things I was just talking about. If you look at with the Big Three is at 313,000 for the third quarter, that's up over 100,000 barrels a day from this same quarter last year. That's the 48% growth that you're referencing. I should start out by saying that about 10 points of that is kind of a Harvey effect. To really get a more proper year-to-year look since we lost about 15,000 barrels a day in the third quarter last year due to Harvey, it's really more of a 38% year-over-year growth, third quarter to third quarter, once you adjust for the Harvey effect. That's consistent with last quarter we talked about that same number was 37%.
It was lower in the first quarter, down around 20, that's what continues to support this idea that we're going to have about 35% growth year-over-year from the Big Three this year even at the kind of capital levels we're at. That has been led by the Eagle Ford. The Eagle Ford is 75 of that 100 year-over-year in terms of increase. The Eagle Ford's up 61% versus the same quarter last year, 44 once you adjust for Harvey. I think that we have gotten some extra benefit this year. Some of this is outperformance from what I've talked about in the past, the Vintage 4 completion is doing even better than we had expected. It's also more wells. More wells online because we've been more efficient with our drilling.
As we lay out our plan for next year, we'll see what kind of numbers that produces. I don't expect that we can continue to run the similar number of rigs that we talked about in the analyst meeting and generate a 35% CAGR over time. The math doesn't work that way. You're not going to get that kind of performance even with the outperformance that we've had. Of course, as we talked about on the last quarter call, some of this increased volume is due to the little bit higher spending on OBO, the operated by others in the Lower 48. I mentioned about a plus seven on the last call in 2018 is from some of the increased OBO spending. That's not a huge piece, but that is part of the Lower 48 Big 3 outperformance on production.
That's helpful, Al. The follow-up is, what's the team's message around M&A? It seems like you got a nice organic opportunity set here with Alaska and Willow and Qatar, and obviously the runway that you were just talking about in the Big 3. How do you think about Conoco's role in consolidation, or is the P50 case still that you prosecute those organic opportunities?
We're pretty happy, Neil, with the organic opportunity set. You probably get tired of me saying this, but we think of M&A in three buckets again. We've been executing the first two buckets over the course of the last couple of years as we've got the company back on its front foot a little bit. That's acreage buying, what we did up at the Montney, what we did in Louisiana Austin Chalk. We're doing some of that each year, every year in, year out. Now we were afforded the opportunity to do a little bit of asset level work, which is how I think about Alaska with respect to the Western North Slope, the agreement that we're trying to close on Kuparuk. We look for those opportunities. We're patient, we're persistent.
We'll only pay the right price when we have an extra opportunity to improve the portfolio than we think we did in that particular case quite a lot with some good adds and getting control of our development pace over in that part of the area. I think you're probably referring to the large M&A, and that's got a tough hurdle in the company because it needs to be substitutive, it needs to be competitive on a cost of supply basis. With the current prices, though they're still pretty frothy for large companies or small companies and some of the bigger deals that are going on right now. We watch them, we look at them all, and we know what we like, and we're patient, we're persistent.
We believe that this business is going to go through cycles, and we'll always look at it and have an opportunity when another down cycle occurs.
Thanks, Ryan.
Thank you. Our next question is from Devin McDermott of Morgan Stanley. Please go ahead.
Good morning. Thanks for taking the question.
Good morning.
I just had a quick follow-up on the Lower 48 activity plans. Last quarter, you talked about shifting a rig out of the Delaware to the Eagle Ford. I was just wondering, as you're going through the planning for 2019 and even longer term, what would you need to see to begin to reallocate more investment or more activity to the Delaware, particularly given the improvement we've seen in realizations locally there?
Yeah. We did execute on that rig shift of one rig from the Delaware to the Eagle Ford that we talked about on the last call. We also did lay down a conventional rig in the Permian that we talked about on the last call. We have done those things that we talked about. I don't see us moving a rig back to the Delaware. I don't expect that that'll be in our plan for 2019. I think it'll be most advantageous to do that once we see the takeaway capacity issue in the Permian getting settled out. We really, with the flexibility that we have and all the great opportunities we have in the Eagle Ford, we're not in a hurry to do that.
I think we'll use our flexibility and take our time, just like we talked about on the last call, in deciding when to move back. I don't expect that it's going to be any time in the immediate future.
Got it. Makes sense. The second question I had is really a higher level one around the philosophy on dividend growth, given the bump we saw recently. How should we think about, given the strong free cash flow profile you guys have right now, the low overall cost structure, what you view as a sustainable dividend level, and how we should think about the cadence of growth there over the next few years or even longer term?
Well, Devin, we wanted to move to a fourth quarter dividend. It fits better with the cadence in the company and how we review our plans with the board strategy, set our plans for the upcoming years. Fourth quarter, it feels like a better cadence for us going forward. I think as you think about the dividend, I think it ought to be predictable, consistent, and reliable. You ought to count on increases on an annual basis.
I think what we try to describe what we've done over the past couple of increases should be a fairly good predictor of going forward.
That makes sense. I'll leave it there. Thanks so much.
Thank you. Our next question is from Blake Fernandez of Simmons & Company. Please go ahead.
Hey, folks. Good morning. Thanks for the question.
Morning.
Production sharing contracts have become more topical as of late. I've never really viewed Conoco as overly exposed there. I just wanted to confirm there are no lingering hand grenades out there, I guess that we need to address imminently?
Yeah, let me cover that one. If you look out, say, 10-plus years in our list of PSCs, we've got three that expire in the next 10-plus years or so. They've all been disclosed previously in our fact sheet. There's really no news there. The nearest term one is in China, Panyu, which was originally set to expire this year. We recently, not too long ago, negotiated a one-year extension. It expires in September next year. That's about 5,000 barrels a day net to us. Not a big volume item. Of course, there's Bayu-Undan that supplies the Darwin plant. We've been talking about that for a long time, that we're going to be out of gas in that field out in the 2022, 2023 timeframe. Basically, the production there goes to something approximating zero about the same time that the license ends.
We have Corridor in Indonesia, which we recently applied for. That PSC expires in 2023. Production will be down quite a bit from where it is now by the time you get out to 2023. It'll be relatively low. We have applied just recently for an extension to the Indonesian government for that license, and we've been in a dialogue with them, but we don't have an answer there yet. Those are the three for us in the next 10-plus years that are on the queue for exploration. All in all, I'd say they're all either low production or they're going to be low production by the time we get to the expiry date. It's kind of a non-event for ConocoPhillips as you suspected.
Thank you, Al. I appreciate that. The second question, this may be more of a Don question, but I guess it's more modeling-oriented, really twofold. One, can you discuss the overlift in the quarter, specifically where that was, and how should we think about that going forward? Secondly, just on the tax rate, the adjusted tax rate has been moving down progressively each quarter. I suspect that's because of U.S. growing. Just any thoughts on how we should think about that moving forward?
Yeah, Blake, as far as the overlift on the quarter, it was about 13,000 barrels a day. Most of that was in Alaska, and that's coming from an under-lift position in Alaska the second quarter. As far as going forward, I would say on the year to date, we're pretty well balanced. Actually a little bit under-lifted on the year. As you think about the fourth quarter, I can't really give you any guidance. I can't think of a reason why anybody would project an overlift or an under-lift. As far as we're concerned our expectation to date is that sales and production would be pretty evenly matched. Of course, things can change late in the year as far as cargo liftings. We're not in an overlifted position on the year.
Okay.
On the effective tax rate, you noted that our effective tax rate has gone down a couple points. I think it was 39% on an adjusted basis and maybe a little bit lower, 36 or so on a reported basis. I think that we did have higher pre-tax income in our low-tax jurisdictions and in our equity affiliates which clearly are taxed at the affiliate level than we did in the higher tax jurisdictions during the third quarter. That really brought it down. 39% is within the range of my expectations. I think when we look at our jurisdiction mix and our production mix, generally expect it to be in that 38%-42% most quarters. Not really a surprise there. As far as the reported being lower than the adjusted ETR, that was mainly driven by the Venezuela settlement.
That $345 million or so has very low tax consequences to it. Since we reported that as a special item, that brought that ETR down to 36.
Helpful. Thank you very much. Appreciate it.
Thanks, Blake. Thank you. Our next question is from Scott Hanold of RBC Capital Markets. Please go ahead.
Thanks. I think this question's for Al. You stated obviously you've seen some good results in the Eagle Ford. I think you're probably what, producing around 200 a day net in that basin. As you look forward, what do you think, and this is an all-time record if I'm not mistaken for you, what is your capacity to continue to grow there? Where do you think it could get to? Is there a point at which you guys are going to be more of a sustenance mode there? Is that quite a ways out?
Yeah. You're right, Scott. We are at about 200. In the third quarter, we made 198 in the Eagle Ford. We have recently signed up for additional stabilization and takeaway capacity there because the Eagle Ford has grown faster this year than we had originally projected. We've had to sign up for it earlier. I think I mentioned this on a previous call, that third-party capacity was readily available in the Eagle Ford, given all the shift of others to the Delaware Basin. We've found that we can continue to grow without having to spend much money on infrastructure because it was overbuilt by others. There's still more room for us to run there and more room for us to grow. I'm not going to predict an exact number.
We're not in the flattening-out mode like we have talked about in the Bakken, where we were looking to kind of hold steady. The Eagle Ford's going to continue to grow for quite some period of time. The flat spud on it is not in sight, not something that's going to happen next year.
Okay, understood. Thanks. One question on Cenovus ownership. What are sort of the current thoughts? Anything change on that? I know you all are patient in the way you look at things, can you frame for us how you think about that right now?
Well, Scott, yeah, there's really nothing new. We've talked about this every quarter. We do have a value expectation on Cenovus. We've said before, I think, that we felt like it was undervalued. I think looking at the price today, we think it's even more undervalued. Fortunately, our liquidity position, our cash balances afford us the opportunity to be patient. We think Cenovus is on the right track. Obviously, they've got some headwinds with the transportation takeaway issues up there. We think they're doing the right things, and we think the market will eventually reward them.
Understood. Appreciate it. Thanks.
Thanks, Scott. Christine, this is Ellen. We'll take our last question now, if you don't mind, so we respect people's time.
Thank you. Our last question is from Pavel Molchanov of Raymond James. Please go ahead.
Thanks for squeezing me in. A quick one about the LNG in Australia. With Brent close to four-year highs, what has been the response in LNG pricing in the spot market and how, just as a reminder, is your offtake agreement structured vis-a-vis the slope versus Brent?
Good try, Pavel. I'll try to take that one. We don't provide information on slopes and exact pricing. I think the furthest that we'll go is to confirm that all of our LNG contracts, Australia and elsewhere, are Brent-linked. We're not going to get into the details of that. As far as the commitments that we have in Australia, our customers are in both China and Japan. They're long-term contracts. Again, they're Brent-linked contracts. Generally speaking, the buyers have some flexibility in how much they take in any one year, so they may, in any particular year, vary their commitment down by 10% or up to 10%. LNG demand, as you know, is quite strong, so our largest buyers in China are looking at taking their full commitments as we go forward.
What the long-term commitment offtakers don't take, we do sell into the spot market, and we've been pretty pleased with the spot prices that we received so far this year.
I can add, Pavel, that we've been averaging about two cargoes a quarter of spot cargoes, and like Don said, we've been quite pleased with the pricing we've been getting on those the last few quarters.
What percentage is that of the LNG volume?
Well, we had 29 cargoes in the third quarter, 87 year to date after three quarters. It's less than 10%.
Okay. Clear enough. Appreciate it, guys.
Thanks, Pavel, thanks, everybody, for joining the call today. By all means, reach back to us if you have any questions, and enjoy the rest of the day. Thank you, thank you, Christine.
Thank you. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.