康菲 (COP) 2019 Q3 法說會逐字稿

Hello, everyone, and welcome to our third quarter earnings call.

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

Our three region presidents are also in the room with us today.

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

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

We will make some forward-looking statements during today's call.

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

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

One final comment before I turn the call over to Don.

Given that our November analyst and investor meeting is only a few weeks away, we're going to limit questions to one per person and ask that questions address today's earnings release or recent announcements.

And with that, I'll turn the call over to Don.

Thanks, Ellen, and good morning, all.

I'll begin with third quarter highlights on Slide 4. Starting on the left, with our financial performance, we realized adjusted earnings of $0.9 billion or $0.82 a share.

Higher LNG realizations and higher production volumes combined with lower overall cost to mitigate the impacts of reduced market prices.

Cash from operations was $2.6 billion, resulting in free cash flow of $1 billion in the quarter and $4 billion year-to-date.

We ended the quarter with $8.4 billion of cash and short-term investments.

And our strong financial returns continued with the return on capital employed at just under 11% on a trailing 12-month basis.

Moving to the middle column, operationally in the quarter, we produced 1.32 million barrels of oil equivalent a day, up 7% on an underlying basis compared with the year-ago quarter, and up 12% on a per share basis.

Matt will cover the rest of the operations highlights in a moment.

On the strategic side, earlier this month, we announced a 38% increase to our quarterly dividend, which reflects the company's improved underlying financial strength as well as our commitment to peer leading capital returns to shareholders.

In addition, we repurchased $750 million of shares in the quarter and announced our plan to buy back $3 billion of shares in 2020.

In both the third quarter and year-to-date, we've returned over 40% of CFO to our shareholders.

We closed the sale of our E&P assets in the U.K. in September, which generated $2.2 billion in proceeds.

And as recently announced, we entered into definitive agreements for the sale of our Australia-West business.

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

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

Moving to the right, cash from operations was $2.6 billion.

There were a couple of items impacting cash from operations in the quarter that are noted here.

First, in conjunction with the U.K. sale, we made a one-time top up contribution to the pension plan such that it is now fully funded and essentially self-sufficient.

That $320 million can be viewed as an acceleration of future pension contributions.

And second, as we do each quarter, we note the cash received during the quarter associated with the PDVSA settlement.

To date, we received over $750 million related to the $2 billion settlement agreement reached in the third quarter of last year.

Working capital was at $300 million use of cash.

And as mentioned, we recognized $2.2 billion in proceeds from closing of the U.K. disposition.

Capital spending was $1.7 billion, resulting in free cash flow of $1 billion in the quarter.

And we distributed $1.1 billion or 41% of CFO to shareholders during the quarter through dividends and share buybacks, ending the quarter with a cash balance of $8.4 billion.

So as you can see, this past quarter once again continued our trend of consistent, strong operational and financial performance.

It also demonstrates our unwavering commitment to financial returns, capital discipline, free cash flow generation and returning capital to shareholders.

We firmly believe that ours is a sustainable, distinctive and compelling value proposition, one that is highly competitive not only within the energy sector, but also across the broader market.

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

Thanks, Don.

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

Please turn to Slide 7.

Across the portfolio, we continue to advance the operational milestones we highlighted at the end of last year.

Starting in Alaska, we safely completed our third quarter turnarounds of Prudhoe, the Western North Slope and Kuparuk and closed the Nuna discovered resource acquisition.

We also continued to progress appraisal of our Willow and Narwhal discoveries.

Earlier this month, we spud another horizontal well from an existing outline drill site into the Narwhal trend.

The well was designed to provide offset injection to the horizontal producer we drilled earlier in the year and help us optimize future development planning.

We're also gearing up for the winter exploration, appraisal and project execution season.

Moving to Canada, we completed commissioning of our Montney gas plant this quarter.

Due to delays in the third-party pipeline, we now expect that project to be online in early 2020.

At Surmont, our alternative diluent project is on track for start-up in the fourth quarter, as planned.

In fact, we're actively transitioning today to start condensate blending for dilbit sales beginning on November 1.

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

In the Lower 48, Big 3 third-quarter production by asset was: Eagle Ford at 226,000 barrels equivalent per day; Bakken at 102,000; and Delaware at 51,000, for a total of 379,000.

As we indicated last quarter, we expect Big 3 production to remain relatively flat for the remainder of the year, and we're on target to achieve a full-year growth rate of about 21%.

Lastly, in the Lower 48, we now have three Vintage 5 multi-well pilot pads online in Eagle Ford, and you'll hear more about that in a few weeks.

Moving over to Europe, the U.K. disposition closed and we successfully transitioned operatorship.

In Norway, partner-operated turnarounds were safely completed in the third quarter.

In Qatar, we've been invited to submit a bid for the North Field expansion project.

And in Malaysia, production ramp up at KBB continued through the quarter, and we expect to reach full throughput by year-end.

In addition, Gumusut Phase 2 came online in August.

And finally, in Australia, we announced the divestiture of our Australia-West assets for $1.4 billion, which we expect to close in the first quarter of 2020.

Meanwhile, we continue to progress Barossa and remain on schedule for FID by early next year.

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

Now I'll discuss the outlook for the remainder of the year on Slide 8.

As we enter the last quarter of 2019, we're continuing our focus on execution while maintaining capital discipline.

Our full year operating planned capital guidance remains unchanged at $6.3 billion, excluding about $300 million of opportunistic, low cost of supply resource additions that we discussed last quarter.

On the production side, full year guidance also remains unchanged, except for updating for the close of our U.K. asset divestiture.

With that in mind, we now expect the fourth quarter to average between 1.265 million and 1.305 million barrels equivalent per day, with the full year guidance between 1.3 million and 1.31 million barrels a day.

So, we remain on track to deliver 5% underlying full year production growth, and combined with our buyback program, that results in 10% production growth per share.

Finally, we're looking forward to our Analyst & Investor Meeting on November 19 in Houston.

We'll show a decade-long disciplined plan that delivers free cash flow and strong returns.

And of course, we'll provide a deep dive into the assets across our diverse portfolio.

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

Our entire ConocoPhillips team is focused on successfully executing the remainder of our 2019 plan, and we look forward to sharing our longer-term plans with you in November.

Now we will open up for questions on the quarter.

(Operator Instructions) And our first question comes from Phil Gresh from JPMorgan.

First question here, just as you said on the quarter.

As you look ahead here to the fourth quarter guidance, it looks like from your prepared remarks, the production outlook was just meant to be an adjustment for the closing of the U.K. transaction.

Just wanted to confirm that if there are any other moving pieces we might want to be thinking about for the quarter.

Thanks.

Yes.

Phil, the, ah, it really is just an adjustment for the U.K. change.

It's a bit less of an increase from the third to the fourth quarter than we usually see, but that's mostly because we've had front-end loaded production in the Lower 48 and Qatar.

And it's also influenced to some extent by the fact that Montney startup has slipped into the first quarter because of this delay in the third-party pipeline.

But really, primarily just reflecting the change in the U.K.

Okay.

Got it.

And then just one for Don.

On the cash flow, you've had a decent working capital headwind year-to-date.

And I was just wondering if there are any transitory dynamics there that could reverse some of that in the fourth quarter.

And then obviously, I think we're going to get a step up in the APLNG distributions as well.

Correct?

Yes, Phil.

On the APLNG distributions, yes, we do expect the even quarters to be high, the odd quarters to be low.

So, we'll continue that trend.

We had $60 million distributed in the third quarter.

I would expect that number to grow to about $300 million in the fourth quarter.

So still pretty consistent with what I guided to last time, which I think was $750 million for the year on APLNG.

On working capital, we had a $300 million use in the quarter.

And there, we saw an increase in accounts receivable due to some sales timings on liftings in Norway and Malaysia both, and a decrease in the accounts payable of about the same, about $150 million.

And that's just normal payment timing.

So, there's really not a lot going on there.

I wouldn't suggest that we're -- we have a trend line that we're following.

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

I wonder again, trying to stick to the quarter, I guess, with also one of the things you included in your slide today, Matt.

Your decision to exit Barossa in the middle of the quarter, but yet prepared to still consider investment in Qatar.

I just wonder if you could walk us through your thinking in terms of LNG market outlook, why exiting one and still being involved in another might make sense for you guys.

And maybe if you -- if I can, a part B to that.

Just it looks like international gas prices were a bit better this time.

I'm just wondering if you're seeing any improvement or is that just a lag effect on pricing.

I'll leave it there.

Thanks, Doug.

Yes, we decided to exit ABU-West not because we're concerned about the cost of supply there.

We actually think that as a competitor project.

But the -- we concluded that the -- we should monetize those assets and redirect the capital to higher returning projects across the rest of our portfolio.

So, it was a pretty straightforward allocation of capital decision for us, to make the decision that we did with ABU-West.

We are still interested in the Qatar North Field expansion.

We think that will also be a very competitive cost of supply LNG project.

And we will continue to progress those discussions with Qatar as we go through the rest of the year and into next year.

Doug, you had a question about LNG realizations in the third quarter, so I just wanted to address that.

And you're right, it is the lag effect in pricing the way these long-term contracts work.

So for example, in the quarter, Brent, as you know, was down about $7 from the previous quarter, but JCC pricing was up $8.

So, what you're seeing is just the lag effect on LNG realizations.

Our next question comes from Neil Mehta from Goldman Sachs.

The first question I had was around Qatar.

Can you remind us again, Matt, just around the mechanics of production?

To the extent that you have it, heavy first half weighted production run in Qatar.

Does that come up against any caps or restrictions on volumes as you get into the fourth quarter?

Yes.

The -- so we've already talked, as we've gone through the year, about the front-end loaded nature of the Lower 48.

In Qatar, there's an annual limit to total production that we can produce there in Qatar.

And we had very strong performance through the first three quarters.

So that means that we choke back in the fourth quarter to meet our limit.

That's something that's been in place from the beginning of Qatar, but it's been -- it's a bit more pronounced this year because performance has been so strong in the first three quarters.

And then drilling down at the Lower 48, can you just walk us through each of the three regions and what you're seeing from a volume perspective as we go into the fourth quarter, anything notable that you would call out in terms of how the performance is play by play?

Yes.

Thank, Neil.

It's Dominic here.

I mean I think in terms of Q4 outlook on the Big 3, all pretty flat.

I think Eagle Ford pretty flat from Q3 into Q4.

Bakken had a good strong quarter in Q3.

It's probably relatively flat into Q4.

We may see some weather impacts in December up there, in North Dakota of course.

We will see a little bit of growth in the Delaware.

But overall, our guidance is relatively flat Q4 for the Big 3 versus Q3.

We will see continued growth in 2020 in the Big 3, and we look forward to talking about that in November.

Our next question comes from Doug Terreson from Evercore ISI.

So my question is about the implications of divestitures in the North Sea and Western Australia on your total corporate retirement obligations, and specifically, how you expect those to change once those asset sales close.

Yes, Doug.

This is Don.

Yes, I can give you some guidance around the asset retirement obligations.

In the U.K. I think we've already published that, but that's $1.8 billion of reduction in ARO.

And then in, let's say, Australia-West, assuming that, that completes in the first quarter next year, we would expect that ARO reduction to be about $650 million.

So, combined between the two major asset sales, we'd see a $2.5 billion reduction, that's about 30% of our balance.

Our next question comes from Roger Read from Wells Fargo.

I was just curious, given that the winter program is already pretty set, just kind of curious about an update there, what we may look for in the coming months.

Yes.

Roger, this is Michael.

We're gearing up for our winter drilling program now.

In fact, this upcoming winter program will be our largest ever.

We'll drill wells at Willow, at Narwhal and Harpoon, and we're looking forward to sharing the details of that program at our meeting in November.

There's really nothing further to share at this point.

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

I was curious that on Monday, I think you guys are targeting on the condensate window.

What's the API you're targeting, because one of the pushback we heard from people is that the update that people actually want to have a higher API condensate so that they use lesser of the pipeline space when they branded with the bitumen.

So from that standpoint, I mean that why that you guys think that your condensate, if you get from there, you mean there's a lower API, you will have a good market?

Thanks, Paul.

This is Michael again.

The -- our liquids in Montney is about half of our product mix and about 2/3 of our revenue mix.

About over half of that is condensate and it's a fairly light condensate, it's about 40 degrees.

It's not linked physically with our Surmont asset.

We'll sell the condensate into the market.

And in fact, we're in the process of just waiting on a third-party pipeline to start up our gas plant probably early next year.

And so we'll start to see production results from this first pad that we'll bring online at that time.

So, the condensate and other products will all be sold into the market in Canada, which is actually a pretty strong market in terms of condensate.

Michael, I'm sorry, you say what is the API for your condensate?

Yes, it's around -- it's in the 40-degree range, plus or minus.

40?

Okay.

Yes.

That seems pretty low.

Okay.

Our next question comes from Paul Sankey from Mizuho Securities USA.

We had a question about the maintenance capital levels that will be ongoing off to the disposals you made, Matt.

We wanted just to know what the impact is on spending on an ongoing basis from the disposals.

And if I could follow up on the M&A theme, could you talk a little bit about the $300 million of opportunistic add-ons, I think you call them?

What are the parameters for those deals?

And do we assume that the parameters that you're using there would be similarly applied to a bigger deal, if you made one?

The -- thanks, Paul.

The maintenance capital, assuming you're referring to the sustaining capital number that we...

Yes, exactly.

Sustaining is what I should have said.

Yes.

No, that's the thing.

They're sort of interchangeable.

But the -- that's around $3.8 billion, and that continues here.

In fact, it continues through the next decade, when we talk about some in a few weeks.

And so there's no significant change there.

There are some puts and takes with the acquisitions and growth in the unconventionals, but it stays around $3.8 billion.

And that keeps our sustaining price, which is what we're really focused on, well below $40 per barrel.

The -- on the M&A front, the -- was really, you referred to the $300 million we spent this year on acquisition capital.

So, those were adding possessions in Alaska at the Nuna trend is now closed.

In the Lower 48 adding, for the most part, royalty acreage in our existing operated possessions.

Some smaller additions in the Montney continue crawling up there.

And then entrance into the Vaca Muerta play in Argentina.

There's nothing new in this quarter from -- in that respect.

But the -- you ask for the sort of decision criteria from the -- what we're thinking about those.

Basically, we're focused, as we are, on all of our capital investments on the cost of supply, so we have to be able to see the acquisition price plus the development cost of supply in aggregate being compared with other sources of resource additions.

And again, that's something that we'll talk about -- more about in November, just the -- philosophically how we think about all of that in the context of asset or corporate acquisitions.

Our next question comes from Jeanine Wai from Barclays.

In terms of Alaska, and I think this question qualifies because it's on recent news.

Do you see anything changing from an operating perspective now that you have a new partner with BP exiting?

And have you had maybe any early conversations and could there be some upside there?

And I guess what we're getting at also is because we've noticed that you spent almost all of the full year budget in Alaska already.

Yes, Jeanine.

This is Michael again.

So, with the transition from Hilcorp -- sorry, from BP to Hilcorp, it's still early stages.

So the -- we're still pending the successful close of that transaction.

But Hilcorp does have a track record in Alaska of rejuvenating mature fields.

They've reduced lifting costs, they've increased development activity and increased production in these other fields.

And so we expect to see a reduction in operating costs and a renewed focus on investment.

Now any capital plans for Prudhoe Bay require the approval of Hilcorp, Exxon and ConocoPhillips.

And so, while we work very closely today with BP as the operator, we'll continue to work closely with Hilcorp as they come in and Exxon to maximize the value of this legacy asset.

So, we're excited for this transaction.

We see opportunity to unlock more value at Prudhoe Bay.

Our next question comes from Bob Brackett from Bernstein Research.

Another Alaska-related question.

If we think about the Fair Share Act ballot initiative, can you talk about that and perhaps put in the context of the longer-term ebb and flow of tax policy up on the North Slope?

Yes.

Thanks, Bob.

This is Michael again.

It's a situation that we're monitoring very closely.

I'd say this initiative is not in the best long-term interest of the Alaskan citizens.

We believe the Alaskan citizens will see the benefit that the North Slope exploration renaissance has already brought to the state and to its citizens.

If you look at the positive changes that have occurred since SB 21 went into effect in 2013, ConocoPhillips and others have announced several additional discoveries and projects.

It could add significant incremental production and revenue to the state.

And so, we believe that continuing those investments is good for employment.

It's good for the Alaskan economy, and it's good for the Alaskan citizens.

And so that's for both now and over the long term.

And so we feel like it's also worth noting that this sort of initiative has come up in the past and we've successfully informed voters of the negative consequences of jobs, production and long-term revenue, the impact of those sort of initiatives have on the benefits that the citizens would see.

So, we do have a long history of engagement with the public.

We feel that there's a mutually beneficial relationship with the stakeholders and in short, so it's very much on our radar and something we're monitoring quite closely.

And we do expect, in fact, we're gearing up now to make our case to the citizens about the benefits of continuing under the fiscal regime that we currently have.

Our next question comes from Jeffrey Lambujon from Tudor, Pickering, Holt.

My question is just on capital allocation for the remainder of this year, just thinking about the unchanged budget.

I would have thought there may have been some downside potential in spending just given the U.K. close.

So just looking for any color on where that unspent capex might be allocated to and set for the remainder of the year.

Yes.

This is Matt, Jeffrey.

So, so far this year, our run rate has been about $1.6 billion a quarter.

That's going to drop by about $100 million into the fourth quarter.

Part of it because of the U.K. disposition, but also just general phasing and primarily associated with completions and refracs and exploration timing.

The -- and it's just that those modest sort of plan changes that cause us to go from a run rate of $1.6 billion to $1.5 billion.

Our next question comes from Michael Hall from Heikkinen Energy.

Just maybe going back up to Alaska, sorry.

Can you guys provide an exit rate on what Alaska production looked like after the turnaround?

Yes, we're producing around the 210,000 to 220,000 barrels a day at this point.

Great.

That's helpful.

And then on the Canadian gas plant, can you just remind me what the net capacity on that is to those operations to you?

Yes.

The capacity is about 100 million cubic feet a day.

One of the benefits that we have with the plant that we've designed here is we can design one and build many.

So, as we're in this appraisal mode and we ramp up to different stair steps of production levels, we'll be able to clone this plant multiple times over.

Our next question comes from Pavel Molchanov from Raymond James.

First, just a quick one about gas pricing.

You mentioned the lag effect benefiting LNG in the quarter.

But in your European gas pricing, it was the lowest number, as far as I can remember, on record, lower than in 2016 even.

Curious why North Sea gas was so depressed in the September quarter.

Pavel, this is Don.

Yes, all of the markers were down during the third quarter from Brent to WTI and Henry Hub, of course, here in the U.S., AECO International Gas in Europe.

LNG, of course, is quite different, is priced differently.

That's why we saw the increased realizations in the third quarter.

But now, there's just a supply and demand factor in Europe.

There's a weakness in the market -- or there was in the third quarter.

It continues in the fourth.

Okay.

Understood.

My follow-up, a little more thematic, if I may.

In your sale of Australia-West, did you consider including APLNG as part of the same transaction to simply exit Australia altogether?

This is Matt, Pavel.

No.

This was focused on the cash flow characteristics in ABU-West and the nature of that asset, the stage of the life cycle.

And it wasn't that we didn't consider an exit of Australia in this entirety.

We have a question from Doug Leggate from Bank of America Merrill Lynch.

No I asked my one question already.

I think that's a mistake.

I can ask another one, if you like.

It's okay, Doug.

While I have you guys, I actually didn't line up for another, I feel quite embarrassed, but I had another one written down.

Just on your cost guidance, I'm expecting this will come up next week, but the costs have been running about light this year.

I'm just wondering if there's anything that we should read into that.

Are you doing a lot better on both operating costs?

And I guess DD&A is about low as well, but pretty much from the cash cost.

But I'm guessing that's something you'll address in a couple of weeks.

Any comments you can share?

But -- and I'll extend my gratitude to the operator for giving a second shot.

Thanks for your second question.

No, the operating costs continue to hold the line.

In fact, in the third quarter, I think our production operating costs and SG&A were down about 6% or so from the previous quarter.

I wouldn't read a whole lot of that into that.

Some of it was we had a bit higher cost in the second quarter because of the turnaround activity, and we had I think a settlement of litigation thing that we settled.

So, we see operating costs remain essentially flat for this year.

And so, we're not adjusting the full year production operating cost guidance at this time.

And we can talk more about how we see that outlook going forward next month, but we continue to be aggressive on trying to keep a very efficient operating structure.

And at this time, we have no further questions.

I would like to turn the call back to Ellen.

Thank you to our listeners today.

We look forward to seeing you in a few weeks.

Appreciate your time and interest in ConocoPhillips.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.