康菲 (COP) 2018 Q4 法說會逐字稿

Welcome to the Fourth Quarter 2018 ConocoPhillips Earnings Conference Call.

My name is Paulette, 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, Vice President, Investor Relations and Communications.

You may begin.

Thanks, Paulette, and thanks to our listeners for joining us today.

Our speakers will be Ryan Lance, our Chairman and CEO; Don Wallette, our Executive Vice President and CFO; and Matt Fox, our Executive Vice President and Chief Operating Officer.

Ryan will deliver some brief remarks and then today we are going to go straight to Q&A to make time for your questions.

Our cautionary statement is shown on Page 2 of today's presentation material.

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

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

And then finally, we'll refer to some non-GAAP financial measures today and that's to facilitate comparisons across periods and with our peers.

We've provided reconciliations of non-GAAP measures to the nearest corresponding GAAP measure in our press release this morning and also on our website.

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

Thanks, Ellen, and welcome, everyone, to today's call.

In a moment, I'll recap our 2018 highlights.

But before I do, I first want to put those results and in fact our results of 2017 in context.

We're on a path to manage this company for the business we're in, one that's mature, capital intensive and cyclical.

We've embraced this view of the business with a value proposition that we believe should be the new order for E&P companies.

Now what do we mean by the new order?

We mean a value proposition that competes on returns and doesn't change cycles up or down.

The market has clearly spoken that it expects behaviors in this business to change, and we have led the E&P industry in a approach that can and we believe will attract investors back to the sector.

Our value proposition, now more than 2 years old, is fundamentally structured to offer this.

Over this period, we've driven our sustaining price lower and made our balance sheet stronger.

We've simultaneously grown our resource base, while lowering its overall cost of supply.

We've achieved competitive per share growth, not chasing absolute growth, and we've returned a distinctive payout of cash flows to shareholders, kept our cost in check and generated among the most competitive financial returns in the business.

We're encouraged that our value proposition is clearly resonating with the market.

For us, the value proposition is a mindset and a commitment that began in late '16, worked in 2017, and worked again in 2018.

So with that, let me summarize our 2018 results on Slide 4. Starting with the strategy column on the left, we held firm on our priorities.

During this year, Brent prices touched $80 but also $50 a barrel.

But our priorities didn't change.

And this consistent approach allowed us to generate a return on capital employed of 12.6%, that's nearly a 20% improvement over our ROCE when Brent was $109 per barrel just a few years ago.

We increased our dividend, we accelerated our debt reductions to achieve our $15 billion target 18 months ahead of plan and we repurchased $3 billion shares.

We've executed just over $6 billion of buybacks since our program began in late 2016, with about $9 billion remaining on our existing authorization.

Including our dividends and buybacks, we returned about 35% of our CFO to our owners.

All this was funded organically from free cash flow.

We have $5.3 billion of adjusted earnings, $12.3 billion in cash from operations and $5.5 billion of free cash flow.

We ended the year with $6.4 billion in cash and short-term investments on the balance sheet.

We view cash is an effective means to ensure that we can execute our consistent programs, both our buybacks and CapEx, through the cycle.

Our financial position is very strong, and we exited 2018 A rated by all 3 major credit rating agencies.

And we achieved a settlement agreement in our ICC proceedings with PDVSA to fully recover an arbitration award of about $2 billion of which we recognized over $400 million in 2018.

Operationally, I'm proud of the way our organization performed.

We safely executed our capital program and achieved underlying production growth of 18% on a per debt-adjusted share basis.

We got help from strong performance on our Lower 48 business and from project start-ups across our regions.

Finally, we made great progress on our continuing efforts to add to our low cost of supply resource base and optimize our asset portfolio.

We completed high-value asset acquisitions and achieved significant exploration success in Alaska.

We progressed our Montney appraisal program in Canada and began exploring on our new Louisiana Austin Chalk play.

Our portfolio high-grading continued in 2018.

We generated about $1.1 billion of disposition proceeds, and we grew preliminary year-end reserves to 5.3 billion barrels of oil equivalent.

The total reserve replacement rate was 147%, and our organic reserve replacement rate was 109%.

Our year-end resource base now contains roughly 16 billion barrels of oil equivalent with an average cost of supply less than $30 a barrel.

This is the fuel for our continued success in our approach to the business.

So in summary, 2018 was another exceptional year for ConocoPhillips.

But again, 2018 is behind us, what matters now is what's next, and that's a great segue into 2019.

So in December, we laid out an operating plan that we believe can and will sustain our success.

It's a plan that's resilient to lower prices, while offering investors virtually uncapped upside to higher prices.

This is an intentional and sometimes overlooked aspect of how we've positioned ConocoPhillips.

We play both ends of the field, offense and defense.

Our 2019 operating plan is summarized on the next slide.

You will see in the upper right that we're sticking with the core elements of our value proposition, discipline, a focus on free cash flow generation, investing to grow cash flows and distinctive returns to shareholders.

We've already announced the 2019 capital budget of $6.1 billion, planned production growth of 5% to 10% on per debt-adjusted share basis and planned buybacks of $3 billion for third year in a row.

This is consistent with our dollar cost average approach to repurchases.

Our 2019 capital plans include activity and some potentially impactful operating milestones, several of which are shown on this page.

I'll make a quick review of items starting with Alaska.

In 2019, we'll advance construction at GMT-2 and conduct another season of exploration and appraisal drilling.

In December, even before our Ice Road campaign began, we drilled 2 exploration wells from existing pad.

Our Montney 14-well pad program is in full swing in Canada.

In the Lower 48 Big 3, we expect to grow production by about 19%.

We're focusing our activities in the early part of the year on testing potential resource-enhancing programs such as multi-well pilots of our Vintage 5 completion technique, EOR pilot and refracs.

During these activities, we expect volumes in the Big 3 to be relatively flat in the first half and ramp in the second half of the year.

In the Louisiana Austin Chalk, we've already started our four-well exploration program and expect to have results later this year.

And we expect to advance discussions and decisions on a few major projects in Asia, including Bohai Phase 4 in China and the North Field expansion in Qatar and Barossa in Australia.

The items on this page represent opportunities to add low cost of supply resource, strengthen our portfolio and create optionality for the future.

Importantly, as we see results on these opportunities, we'll retain flexibility on how and when we invest in most of these projects.

You should expect us to prioritize and phase these investments in a way that's aligned with our value proposition.

As the year plays out, we'll update you on our results across each of these fronts, and we anticipate providing a comprehensive multi-year update to the market in November.

We're excited to get another year underway.

We believe our 2019 operating plan reflects what you currently expect from us.

It's consistent with our priorities, focused on growing long-term value and underpinned by our commitment to strong execution.

This is our formula for delivering superior returns to shareholders through the cycle and for many years.

It's a formula we believe works, and we're sticking to it.

So with that, let me turn the call over to your questions.

(Operator Instructions) And our first question comes from Paul Cheng from Barclays.

Ryan, just curious that it seems like that you still have running room in Eagle Ford and probably a little bit less in, let's say, in Bakken, I presume.

Based on what you see today on the business, I don't know whether you can actually say that, oh, this is what I plan, is the pedal one way going to be on those 2 basins and once you get there -- and how fast you can get there, and once you get there, what kind of rig program you need to sustain you and how long that you can sustain at that peak production?

And second question is a real short one, whether you receive any payment from APLNG?

Let me -- I think Matt could probably add a little bit of color, Paul, and Don can cover the APLNG question as well.

Yes, I would just say at a high level, we continue to find new technologies and new approaches.

We talked a little bit about testing our Vintage 5 completions in the Eagle Ford.

What we see is continuing lowering cost of supply and opportunities to continue to grow that opportunity.

In fact, Bakken had an outstanding year in 2018.

We reached some plateau and it suggested that to the marketplace that we outperformed in 2018 and we see some similar opportunities there as we go forward.

Matt can maybe provide a little bit extra color for you there.

Yes, Paul, we're running 6 rigs in the Eagle Ford just now.

We actually dropped a rig at the beginning of the year in Eagle Ford to optimize the ratio of our rigs to completion crews.

And we're running 3 in the Bakken and 2 in the Permian.

At those sort of rig levels, we would be continuing to grow in the Eagle Ford.

But if we run those rigs continuously, we'd ultimately reach a plateau and we'd be able to hold that plateau for well over a decade, maybe 2 decades.

In the Bakken, we -- as Ryan said, we felt we were at plateau, but we had some improved results from drilling in completions there and we had more partner-operated activity.

And so we're now at a higher rate than we anticipated and that can probably be sustained close to that rate for a decade or more.

And then, of course, on the Permian, we're very early in the life cycle there.

So that's several years of growth ahead of it before it reaches plateau.

Matt, do you have a number in mind that on Eagle Ford that with the plateau maybe for you guys and also that, if you guys don't mind, give me the production number for the Big 3 in the quarter?

Yes.

No we don't have a number that we'd -- that we're ready to share on the plateau rig as a function of the number of rigs that we run over the long term.

So that -- what we're trying to do of course in all of these places is optimize the rig count so that we optimize the infrastructure costs, and so it's all about maximizing the NPV as we learn more about our new completion designs, for example, in the Eagle Ford, that may change how we view that.

So it's premature to go there.

In terms of the rates for the Big 3 in the fourth quarter, I can give you the list.

We -- I don't have them off the top of my head here just now, but we can get those to you.

I'll come back to you in a moment.

Don, you want to answer the...

Paul, with respect to APLNG payments, I'm sure you're referring to the distributions.

So in 2018, we had total of $480 million of distributions from APLNG, and you will recall we had 200 in the first half.

I believe that I had probably guided that the second half would look similar to the first half and we ended up with a larger dividend distribution payment in the fourth quarter of $280 million and that's really a reflection of a number of things, but probably mostly the high realizations, you know that the LNG pricings on a 3-month lag.

So fourth-quarter LNG pricing or realizations really reflect third quarter oil prices.

So we saw really good revenues at APLNG and, of course, they made good progress on reducing cost both on the operating side and on refinancing opportunities on the project financing.

While I'm here, I know you'd be curious about expectations for 2019 looking forward, and I would say that you've got to pick a price point because it's going to be very much influenced by actual realizations during the year, of course, but at around, say, $65 Brent, I'd probably expect distributions to be in the $500 million to $550 million range.

And Paul, I have the fourth quarter average rates for the Big 3, it was 200 in Eagle Ford, 101 in the Bakken and 34 in the Permian.

And the next question comes from Doug Terreson from Evercore ISI.

I have a financial and a strategic question today.

First, return on capital appears to be rising even after normalizing for changes in oil and gas prices, especially in the U.S. business.

And on this point, I want to say, if you guys could provide some color on the drivers of this demand, meaning is it gains in capital efficiency, is it technology, is it cost or is it something else driving these improvements.

So just some color on this improvement in this area?

Well, Doug, this is Don, and I would say, yes, all of the above if you look at the transformation that we have undergone in the last 2 to 3 years, certainly more capital efficient, more disciplined, our greater focus on returns.

That's the priority now, of course.

And so you can go back to a lot of the portfolio changes that we've done to lower our cost of supply and our sustaining price.

I think all of these things are reducing the debt and our operating cost, I think, are from like $10 billion to $6 billion, taking capital down from $17 billion, I believe, in 2014, down to the current level around $6 billion, so just efficiency on all fronts.

Okay.

And then also strategically, Ryan, you reiterated your pledge to your new order value proposition, which has obviously served shareholders in that COP has been the best stock in the S&P Energy since you implemented the plan 2 years ago.

Simultaneously, companies with high success in this industry often mission drift and that often results in strategic activity.

So while most E&P acquisitions were done at about half of acquirer or capital cost over the past couple of years and they were therefore viewed pretty negatively in the market, valuations have fallen further and I want to see how you guys are thinking about strategic activity these days?

And if there are areas of interest, why and what are they?

Yes, Doug, we do get quite a lot of questions.

I appreciate, it gives us a chance to sort of articulate our views a little bit about the M&A side.

Really for us, it's about strategic portfolio choices, and we've been pretty deliberate in that space over the last couple of years.

And since the spin of the company, it's mostly been on the disposition side with $30 billion, and I would also remind everybody half of that went to the shareholders and half went to reduce the debt on balance sheet.

While we have been involved in some more strategic and smaller scale acquisitions like adding acreage opportunities in the Montney and the Austin Chalk, where we think we have a clear competitive advantage like the asset deals we did last year up in Alaska.

So when we think about that, we consider asset quality, diversity, resource, debt and operating cost.

So we think about it, do we add in and add in those 4 categories around the portfolio.

But I'll point out our 2019 portfolio is in pretty good shape, 16 billion barrels of low cost of supply resource base that's Brent-weighted, it's diverse, it's deep, it's material.

So we're not feeling any pressure to do anything.

It just has to be value adding and substitutive in the portfolio.

That's kind of where we stand as a company.

Now broadly within the sector, consolidation should result in more disciplined capital allocation, slower growth and ultimately strengthening oil prices and help investors back into our sectors.

When you consider, I think that on a sector basis, you have to consider things like the value that you pointed out, synergies, the timing, the market reaction to it and what we find it's tough from a valuation perspective, if you're going to implement a disciplined capital allocation program like we have in place, you need to slow down the growth rate for any acquisition target that you look at.

But that growth rate is built into the evaluation and then you usually have to pay a premium on top of it, that makes it extremely difficult.

Synergies, tough to realize with some of the pure play from the private equity companies that are out there.

Unless you have adjacent acreage and infrastructure, there's just typically not many synergies, timing is tough, the low point of the cycle, board rooms are reluctant to sell and obviously tough to issue shares to go to do something.

And then you touched on as well, what's the market reaction?

It's not been good.

So people have been punished because they seem to be overpaying.

So we pay attention to it, we look at it, we watch it.

We see all the opportunities, got to be competitive in the portfolio.

We understand what we like and what might fit, but it takes a real special deal to where we feel like it's a good use of shareholder capital.

Our next question comes from Phil Gresh from JPMorgan.

First question, I guess, would be for Don.

You're at your $15 billion gross debt target, but you have over $6 billion of cash, so your net debt is now below $9 billion.

Wondering how you're thinking about that today, in terms of willingness to take the gross debt down more or obviously, provides you a lot of flexibility in a downside price case, but in an upside price case, you would be building even more cash.

So how are you thinking about what you want to do with that?

Yes.

I think, Phil, we're still at the same place we were as far as capital structure of the company and as far as gross debt.

So we are really not contemplating anything to further reduce the balance sheet debt.

I think this is more of a cash utilization type question and the reasons why we would maintain levels of cash -- high levels of cash in a positive price environment.

And that's going to speak to a number of things, but obviously being able to withstand volatile price cycles and being able to run steady programs and keep our strategy on pace on all fronts as far as buybacks, as far as the base capital program and so forth, gives us the opportunity to take advantage of strategic opportunities, investments that come around that are kind of one-time deals and may be the potential Qatar expansion is part of that.

So it can help kind of pre-fund some of those potential opportunities going forward.

I'd say Phil, really it's not burning a hole in our pocket and remind everybody less than a month ago, people were panicking with $40 crude prices.

So we're not doing that.

We're staying with our program.

As Don said, it allows consistency through the cycles on both the buybacks and the capital investment and follow our priorities.

That makes a lot of sense.

And I guess, the follow-up is to your last comment there, Don.

I feel like one of the most frequently asked questions I have been getting about ConocoPhillips is the level of capital spending that might be moving forward, you could include Qatar in there, you could include Barrosa or Willow.

So how do you guys think about levels of capital spending that might be needed moving forward?

I realize you're not going to have an Analyst Day for a while, but any color you might be able to give I think would be helpful.

Yes, so let me take that one on as I know we've gotten a fair number of questions about that, and I appreciate you're asking about it.

We probably are not going to provide the clarity that you may want in terms of absolute numbers going forward, we'll update the market as some of this resolves.

But I think we have been pretty transparent about the opportunities, you mentioned new field -- or the North Field expansion in Qatar.

So we tried to show those beyond our base programs, I just reviewed in my prepared remarks some of the higher impact activities we have underway in 2019.

We expect to resolve a lot of the uncertainties in most, if not all, of those projects as we go through the course of the year.

Then we'll take stock of what, when and how we might invest in those opportunities, but I'll tell you I think from our past activity and reputation, we've been intentional about retaining flexibility in many of the projects.

And we really have the discretion to phase the capital investments over time.

We've also had a pretty successful track record of divesting assets that don't compete in the portfolio, to high graded and that provides another means of flexibility as well.

So our goal really is to create the highest returns to our shareholders, while preserving our value proposition that we're committed to, including a focus on free cash flow.

So that means we'll be setting and be thoughtful about setting our future plans according to those kinds of premises.

So then again, we'll lay that out in a lot more detail for you later in November, but we're not going to lose our way about ourselves.

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

Ryan, you guys have set the bar pretty high for the industry in terms of capital discipline.

So I think questions around the longer-term CapEx are obviously relevant, but I think in the confines of how you have allocated capital, I am curious, however, if you see a kind of upside limit on the level of reinvestment as a percentage of cash flow to kind of put it simplistically, I realize you might talk about this a bit more in November, but when you look at the list of opportunities, if you did get Qatar or Barrosa or Bohai sanctioned this year, would your aim be to hold the CapEx within a range or do you see some upside risk to the longer-term CapEx?

Well, again, as I tried to say, we'll see what the commodity price for the market is at.

I think first and foremost, we are committed to giving a high percentage of our cash flow back to the shareholders.

So we start by, as you've all sort of noticed, that 30% is kind of our floor.

We're committed to giving 30% of the cash back to the shareholders.

So we'll run the company and will allocate capital to the programs with the remaining amount of cash that we have in the business.

But we're going to look at it annually and make sure that we still continue to deliver free cash flow from the business.

And as we think about the opportunities that you mentioned, the North Field expansion, Barossa and some of the other things, we'll manage that.

We've got control over pace, we've got control of over timing, we've got control over what our interest level is and we've got other ways to control the capital program and we'll do that and we'll take that into account as we do.

We've got a rich set of opportunities coming our way.

We've got capacity and we've got cash in the balance sheet, but we also know any given year, we're committed to our value proposition, and we're going to stay the course.

Perhaps just a quick follow-up to that, Ryan.

There has been some speculation in the press that you are pursuing a North Sea sale and that sale may not be going forward.

I wonder if you could offer any color on just that specific issue, but also the general portfolio management in terms of non-core assets as they stand today, I'm guessing that would also factor into the flywheel for your ability to return cash?

And I'll leave it there.

Yes.

You bet -- I think Matt has been kind of managing the U.K. process for us.

I'll let him kind of provide a little bit of color on that for you.

Yes, Doug, the process to market the U.K. assets continues, but we're no longer under an exclusive arrangement to do that.

So we have broadened the process to include several parties.

And there really has been very strong interest in the properties.

I don't want to comment any further on that unless there is a material change to report down the line.

But we're actively marketing those assets.

In terms of other assets that we may market, we've expressed consistently and consistently executed on the fact that we will look at the lower end of the portfolio and dispose of assets as the -- when the timing is right.

We did $1.1 billion this year, so you should expect to see us continuing to work on the assets now.

We'd say that the major portfolio restructuring is essentially behind this.

But that's not to say that there aren't other changes that we would make to the portfolio.

And just to be clear, I think you maybe say the North Sea assets, the assets that we're marketing are the U.K. assets.

So I think that's the best we could describe what the state of play is on the disposition front.

And our next question comes from John Herrlin from Societe Generale.

I've got a question on reserve replacement in the U.S. You had asset sales this year, you've changed the way you allocate capital reserves decline.

What should we think about in terms of your reserve replacement in the U.S. on kind of a going-forward basis, just low nominal growth?

(inaudible) we'll start maybe by explaining what happen to our overall reserve base.

There is a slide in the appendix that we posted, I think Slide 9, that describes the overall sources of reserve replacements.

So we started the year with 5.38 billion and ended with 5.263 billion, that's a lot of decimal places.

We produced 483 million barrels.

We added 474 through extensions and discoveries, another 52 through revisions and improved recovery.

So that's where we get to the 109% organic reserve replacement ratio that Ryan mentioned.

And then as you look at the acquisitions and dispositions, the net effect of that was 182 million barrels.

We added close to 300 in Alaska through the acquisitions and that was offset by 38 million reduction in the Clair disposition and 68 million from Lower 48.

So if we add all that together, the net effect is we get the 147 million -- 147% total reserve replacement.

No that's I was referring to the Lower 48, Matt.

Yes, the Lower 48, I think the best way to think about that is to think about in the context of the resource base because the Lower 48 obviously, the booking schedule there is based on SEC rules is limited to what you are anticipating in your 5-year drilling schedule.

So when we look at the Eagle Ford, for example, we booked about 500 million barrels of the 2.5 billion barrels that's in our resource base.

And if you look at the other plays, we're about 50% booked in the Bakken, 20% in the Eagle Ford, less than 15% booked in the Permian and less than 1% booked in the Montney.

So there is a long period ahead of us of continuing to add SEC reserves as we work through this resource base.

So they -- we tend to focus on frankly rather than the reserves is that resource base.

And if you look at that from -- for this year, we went from 15 billion barrels last year with a cost of supply of less than $50 to 16 billion barrels this year with a cost of supply of less than $40.

So because we've produced about half-a-billion barrels, that's a resource replacement ratio of 300% and that's what we are -- that's what we really focus on, and I think both from a reserves and a resource perspective, we're in a really good shape.

And specifically to your question, we're in really good shape in the Lower 48 because of the way those reserves will be booked over time.

Great.

My next one is regarding some of the larger projects that could be approved for FID, and I guess, this is more towards Ryan.

Are you at all worried about E&C capacity in terms of delivery?

I mean, obviously, the industry doesn't have the frenzied activity that it did in past cycles, but are you at all concerned about the industry being able to deliver as you commit to these kinds of projects?

Not necessarily, John.

I think when you look at the location, you look at Barossa, we're out for competitive bid on FPSOs and the market is pretty light right now in Asia Pacific.

So the opportunities out there, not too worried about them.

The subsea equipment associated with them is highly competitive and not real stressed out in the system today.

Qatar is going through a large expansion in Qatar at Ras Laffan, that will probably have its challenges, but I think they have managed it well in the past and we'd expect them to manage it well going forward.

So while it's always a risk, I think we've got the team in place, we've got the capability.

It's a large company like we are and functional excellence around managing the projects, we haven't lost that as a company, so we'll bring all that excellence to bear on all these major projects going forward.

And our next question comes from Roger Read from Wells Fargo.

I guess maybe come back around one of the -- and Don, you talked about it a little bit, the decline in OpEx if the companies have been able to achieve, kind of broader productivity and efficiencies.

Wrapping what you can do going forward on that front?

And maybe if you would or if you can disclose the underlying decline rate?

Just kind of want to understand maybe some of the more, I guess, I describe as increasing challenges on being able to deliver continued improvement just from internal things as opposed to maybe some of these future projects everybody has been more focused on, on the call?

Maybe I'll take that one, Roger, this is Matt.

If you look at our OpEx, we're still completely committed to the discipline in our OpEx.

If you look at what's happening from last year to this year, for example, last year our operating cost was $5.8 billion.

But if you put that in a pro forma basis, reflecting the acquisitions and dispositions, most notably the Kuparuk and Clair transactions, our OpEx would have been $6 billion on a pro forma basis.

This year, we're moving to $6.1 billion, but when you look at the underlying production growth, our OpEx for barrel has gone up from 12.6, it's 12.6 rather, that's 20 cents less than last year.

So the absolute number is a bit higher than 2018, but the unit cost is lower and that's pretty impressive when you consider that the acquisition in Alaska, relatively high-cost barrels, of course, they're very high-value barrels because it's all oil and it sells at Brent.

And so the fact that we added those higher-cost barrels and still see a reduction in operating cost per barrel, and it's the same, we certainly haven't lost the discipline on the cost front.

And we can see that, that focus is going to remain in the company over the next several years, and we're going to continue to make sure that we're driving our unit cost down over time.

That's actually very helpful.

Anything on the underlying decline rate?

I can't remember if you talked about that or not, just wanted to ask?

The underlying decline on aggregate is about 10%.

Unmitigated.

Yes, that's unmitigated, without -- that takes all the wells that were online at the end of last year and what would they be producing at the end of next year.

So, of course, because we have the production in LNG and oil sands, which is essentially zero decline and a very large conventional base that has a modest decline, when you put together that with our unconventionals, which, of course, declined more quickly, the aggregate effect is about 10% decline.

Our next question comes from Neil Mehta from Goldman Sachs.

The first one for you is just on Venezuela.

Obviously, very fluid situation out there.

And just your thoughts on the ability to collect the capital that's owed to the company and just some thoughts on the ground of how that plays out from here?

Yes, Neil, this is Don, and I will address that question.

With respect to the recent events in Venezuela, a couple of things, I guess, one on the Venezuela side and one on the -- with respect to the U.S. sanctions, the new U.S. sanctions.

I mean, as far as PDVSA, today, they have fully complied with the settlement agreement that we entered into late last summer as far as making cash payments and providing the inventories that what we obtain title to.

We're in very regular contact with the officials at PDVSA and they continue to assure us that their intention is to continue to comply with the obligations under the settlement agreement.

And I think that their actions over the past 7 or 8 months have indicated that ConocoPhillips is clearly high on their priority list of creditors.

So we expect that they will continue to comply.

Of course, we don't know -- nobody knows how things are going to change in Venezuela and what that may entail.

Their next -- they are now on a quarterly payment schedule for the recovery of the ICC settlement and the next quarterly installment is due next month.

And we expect to receive it and it appears that they are making plans to satisfy that obligation.

The other part of it is on the U.S. side, related to U.S. government's recent actions, and we're operating under a license from OFAC, the Office of Foreign Assets Control, that we obtained before we entered into the settlement agreement.

We have been in contact with OFAC officials as recently as earlier this week and they have assured us that our license is valid, that we are strictly complying with that license, and they've given us a very good guidance on how to go forward.

They don't anticipate any issues related to our settlement agreement, and so we don't see any complications on that front.

And then the follow-up question is just on Qatar LNG.

The timing of that sounds like it's going to be mid-2019, we expect to get a decision about the project partners.

How do you see ConocoPhillips position for a potential project win there?

Any thoughts on the latest in terms of returns?

And I guess, one of the market concerns around Qatar LNG has been around financing the capital spend.

It strikes us that you guys have a substantial amount of free cash flow coming up over the next couple of years that should allay market concerns even after the dividend and the buyback, but any comments about how you think about financing that capital outlay if the project materializes would be great.

Yes, Neil, I'll take that one.

The time line, just as you laid out, we expect decisions to be made by the middle of this year and the underlying process to achieve that is sort of underway.

We think we're very well positioned competitively to participate in the project.

And in terms of financing it, yes, we have cash available to finance it.

We have very high free cash flows recognized.

Even this year, we generate free cash flow, at any price above $40 a barrel WTI.

And so we're not concerned about our ability to finance it.

So we are fully engaged in the process with Qatar Petroleum, and we'll see how it plays out as we go through the year.

And our next question comes from Blake Fernandez from Simmons Energy.

Matt, on that last point, could you just remind me when -- if you did go forward with Qatar, when we could expect first production roughly?

I think the timeline would be first production between 2024 and 2025 is when the expectations are.

Engineering design is already underway, and has not been slowed down for the waiting for the final participants to be agreed.

So it will be sometime late '24 or early '25 is when we'd expect that to come to market.

That's great.

The second question, I suspect you guys aren't as exposed to this, but the feedback we're getting from our E&P team that's covering some of the smaller companies in the space and maybe some of the privates.

We're looking at CapEx budgets being ratcheted back and rig count potentially coming down and all of a sudden now we're hearing commentary regarding potential cost deflation in the Lower 48.

I know it's early days into '19, but I just didn't know if you're beginning to witness anything or if you think there is potentially some downward pressure on spending based on kind of peers cutting activity levels?

Yes, I think, last year, we saw about $100 million of escalation in the Lower 48, but we are seeing some deflationary pressures, for example, the frack fleet activity in the Lower 48 is down about 10% just in the last couple of months.

So our view is that the frack fleet is about 65% utilization just now.

And if you put that together with big reductions in sand prices because of new mining sites opening, we're actually seeing quite a healthy reduction in our completion costs from '18 to '19, and we built that into our budget, those were contracts that we renewed towards the end of the year.

So we are seeing some cost reductions on completions.

On the high-spec rig on the rig side of it, we're at higher utilizations, about 92% on rigs, and we have options on our rigs through the end of 2019.

So I think there could be some deflation going to show up in 2019, and we already saw some of that showing up towards the end of '18.

Our next question comes from Scott Hanold from RBC Capital Markets.

I had a couple of quick ones.

First, you all have somewhere around $7 billion of cash right now and obviously positioned well to generate more free cash flow.

But considering the opportunities that you have in front of you that was discussed quite a bit today and obviously your buyback program that's in force right now as well, is there an optimal amount of cash you guys would like to have the cushion?

And so where I'm going with this is, if a number of these large projects do come to fruition, is there a chance you guys could look at saying adding debt to the portfolio to help fund those projects?

Or is that where you come back and say that's where you look at monetization opportunities and other things?

Scott, yes, I think we've been pretty clear that we're not looking to either raise or lower debt from its current level, and I don't know if there is an optimal -- there is not an optimal point of cash balance that we're aiming for on the balance sheet.

There's a pretty wide range given the volatile business that we're in and the host of opportunities that we hope to have that are investable in the future.

So, no, there is really not -- there is not an optimal level of cash.

Yes, I think -- I would add to that, Scott, that again, we follow our priorities, we feel comfortable with the capital that we are investing right now will grow the company, grow margins, grow cash flows for the company at the kind of level that we're funding today given where the portfolio stands.

We're going to fully fund our $3 billion of share repurchases and above that, to the extent we have additional cash there, we're okay putting it on the balance sheet for now because we see opportunities that might present themselves in a down market, and also we ask ourselves what the future holds for us?

What are commodity prices going to do?

And that gives us the level of comfort when we have that cash on the balance sheet to know that we can fund the opportunities that we have and we can stand the downturns if we see them.

Okay, appreciate, understood.

And as a follow-up, touching base on sort of the Big 3 unconventionals in the Lower 48, is there an appetite to look at some point to put those in more on, hey, we've hit the plateau, they're going more on maintenance mode.

Are we near that point for those, say, the Eagle Ford and Bakken?

Or are you still kind of building up to that?

And then as you look at the Permian Basin with your position in the Delaware, what do you see as sort of the optimal kind of pace that you guys can develop that at?

I'd say, Scott, in the Bakken, we're essentially at plateau, I mean, clearly (inaudible).

But it's not our ambition to grow Bakken further.

We can sustain a level around where we are just now for a long time, but we don't -- we're usually running 2 or 3 rigs and we are comfortable with that in the Bakken.

In Eagle Ford, we're still growing.

This year, we are running 6 rigs and we'll continue to see growth from that and, as Ryan said, testing some new technology in the completion designs there, what we call Vintage 5. Once we understand how those new completion design works, we might revisit what the right pace and what the right plateau rate is and so on.

But there's a few more years of growth for sure left in the Eagle Ford before we get to plateau.

And then the Permian is a long way from plateau.

We're running 2 rigs.

Just now.

you remember last year, we took a rig out of the Permian as the differentials blew out.

I suspect some time over the next year or 2 we'll put the third rig back to work again there.

But that will continue to grow for several years before it reaches plateau.

You're asking a good fundamental question here for the industry as a whole, is how do we -- how does the industry think about where the optimum plateau is?

And the optimum plateau is certainly not just a year or two.

You know you're overbuilding infrastructure if you go there.

And the optimum plateau isn't 30 years because your time value of money certainly.

But we think of this very carefully as we consider the rig -- the pace of rig activity and the pace of infrastructure build and the pace of technology change.

So I think we have a good handle on how we should be managing these assets to optimize the value from a plateau perspective and rig count perspective.

And our next question comes from Jeoffrey Lambujon from Tudor, Pickering, Holt.

First one is on the Op side for the Lower 48.

I was just hoping you could talk a bit more about the Vintage 5 testing that you mentioned a few times now that's going on in the Eagle Ford in terms of both variables that you may be tweaking and then also just the time line for when we may see some data around it all?

And then in the Permian, specifically, I was hoping you could talk a bit about capital allocation within an asset for you all just towards getting a sense of operational objectives there in the near term?

Yes.

I mean, the Vintage 5, basically they're designed to intensify the stimulated rock volume to improve recovery factor.

That's the essence behind the Vintage 5 design.

We haven't really disclosed that design, but that's the underlying parameter that we're trying to improve is the recovery factor by improving the intensity and regularity of the stimulated rock volume.

So we completed a single-well pilot last year, and we got really encouraging results there.

So what we're doing now is we're going to do 3 multi-well pilots at different locations and at different spacings within Eagle Ford in 2019 and then 2 more we have planned for 2020.

So we'll get initial results from that late this year and more results into 2020.

We're also advancing a multi-well pilot and Vintage 5 test in the Delaware too.

That will be later this year, so results there won't come until 2020.

So it's a very interesting technology angle to be pursuing here, and we're going forward pursuing those results.

In terms of the Permian, capital allocation specifically really is driven, of course, by the rig count, the 2 this year and some time over the next year growing to 3 rigs.

Great.

And then my second one is on acquisitions and maybe this is a bit nuanced and maybe possibly a rounding error.

But I saw in the disclosure with earnings today $0.6 billion for acquisitions for the year last year, which compares to $0.5 billion for Q3 earnings.

I know the bolt-ons in Alaska and Montney had been listed pretty consistently throughout the year.

So just wondering if there is any color you can give there on the nature of that incremental $100 million or so that might be implied just for Q4's activity?

Yes, so the acquisition in the Western North Slope is 400, the Montney acquisition was 120, the balance of that is really some additional smaller acquisitions to core up in places like the Louisiana Austin Chalk.

So it is a, I don't point to a big one that makes up the difference there except for smaller-scale acquisitions around the portfolio that takes us to the 600.

Thanks, Paulette, we're getting close to the top of the hour.

So we'll take our last question, please.

And our last question comes from Michael Hall from Heikkinen Energy Advisors.

I guess, you kind of alluded to one in the last question, but just curious in the context of kind of the Vintage 5 completions in the Eagle Ford.

If you look at your prior disclosures, you had pretty big step changes all along the way as you moved up the Vintage cycle, I guess.

Do you still see that sort of potential rate of change, I guess, as you move from Vintage 4 to Vintage 5?

Or is this something that's more on the margin?

And then where would you say you're at in terms of vintaging in the other places, the Williston and Permian?

Yes, so Vintage 5 really isn't focused on trying to improve IP.

It's really focused on trying to improve recovery factor.

So the big increases in an initial production that we've disclosed from Vintage 1 through Vintage 4 is really not what we are targeting here.

This is a more fundamental improvement in the EUR across any given drain drop volume, so that's what Vintage 5 is about.

That's why it's going to take several months after these wells are brought online to really understand how the type curve is evolving and how interference with other wells is behaving.

And so it will have a different characteristic of improvement than Vintage 1 through Vintage 4. So far across the rest of our plays, Bakken, Permian and Montney, we're really implementing completion techniques similar to Vintage 4 just now.

We're testing Vintage 5 in the Eagle Ford and as I said, we'll test in the Permian also.

And we'll then -- we're pretty good at transferring these learnings across the organization quickly.

So we don't have to pilot test everything everywhere before we can put it to work in other plays.

Great.

That's very helpful.

I guess, last on my end would just be -- just curious if you'd be willing to possibly provide exit rate thoughts for the Big 3 in aggregate or individually for 2019?

No.

I mean, I gave the exit rates earlier for the Big 3 individually for the fourth-quarter average rates, which is really in my view the best way to think about the exit rate because of the movement here.

Probably what we've said we're going to do in 2019 as we're going to produce 350,000 on average through 2019.

So that's about 20% growth from '18, and that's going to come through over the first quarter or so and I think Ryan mentioned this in his prepared remarks.

The first half is going to be relatively flat.

We had really quite exceptional outperformance in 2018 as we went through the -- in particular towards the end of the year, we had -- you know how these programs work, you have -- you drill multi-well pads so you get lumpiness within each of the individual plays.

Towards the end of 2018, we had multi-well pads coming on essentially simultaneously across the Big 3. So we saw a big jump there.

And so now we'll be moving towards more of a momentum and we'll be experimenting with these Vintage 5 completions, which take a little bit longer to pump.

So that's why expect them to be flat through the first half of the year and then we'll jump up in the second half of the year as we increase the number of completions.

Thanks.

I think that's going to wrap it up for the day everybody.

We really appreciate your interest.

By all means, call us back if you have any other follow-ups and thanks again for joining us.

Thank you.

Ladies and gentlemen, this concludes today's conference.

Thank you for participating and you may now disconnect.