Good morning and welcome to the ConocoPhillips Third Quarter 2019 Earnings Conference Call. My name is Senera and I'll be the operator for today's call. At this time all participants are in a listen only mode. Later we will conduct a question answer session. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Ms. Ellen DeSanctis. Ellen, you may now begin.

Thanks Senera. 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 reconciliations 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 the 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 costs to mitigate the impacts of reduced marker 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 a 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 UK 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…

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 at Prudhoe, the Western North Slope and Kuparuk and closed the Nuna discovered resource acquisition. We also continue to progress appraisal of our Willow and Narwhal discoveries. Earlier this month we spud another horizontal well from an existing Alpine drill site into the Narwhal trend. The well is 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 the Montney gas plant this quarter. Due to delays in the third-party pipeline, we now expect that project to be online in early 2020. As Surmont our alternative diluent project is on track for start-up in the fourth quarter as planned. In fact, we are actively transitioning today 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. And the Lower 48 Big 3 third quarter production by asset was Eagle Ford at 226,000 barrels equivalent per day, Vulcan a 102 and Delaware at 51 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 3 vintage…

Thank you. [Operator Instructions] And our first question comes from Phil Gresh from JP Morgan. Please go ahead, your line is open.

Yes. Hi, good morning. First question here, just as you said on the quarter. As we 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 UK transaction. Just wanted to confirm that. And if there are any other moving pieces we might want to be thinking about for the quarter? Thanks.

Yeah. Phil. Yeah, it really is just an adjustment for the UK 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 start-up has slipped into the first quarter because of this delay in the third-party pipeline, but really primarily just reflecting the change in the UK.

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?

Yeah, Phil, on the APLNG distributions, yeah, we do expect the even quarters to be high and 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 $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 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 have a trend line that we're following.

Thank you. Our next question comes from Doug Leggate from Bank of America Merrill Lynch. Please go ahead, your line is open.

Thank you. Good morning, everybody. 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 investing in Qatar. I just wondered 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 I you get out, can I add a Part B to that. Just it was like international gas prices were a little 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. Thank you.

Thanks, Doug. We decided to exit the ABUs not because we're concerned about the cost of supply there. We actually think that as a competitive project, but the -- we concluded that the we should monetize those assets and redirect 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 with the ABUs. We are still interested in the Qatar North Field expansion and the -- 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.

Thank you. Our next question...

Excuse me, Senera, we'll complete the answer to Doug's second part of the questions.

Yeah. 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 it 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.

Go ahead, Senera, we'll take our next question.

Thank you. And I apologize about that. Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead, your line is open.

Good morning, team. The first question I had was around Qatar. Can you remind us again, Matt, just around the mechanics of production, to extent do you have a heavy first half weighted production run in Qatar, does that come -- did you come up against any caps or restrictions on volumes as you get into the fourth quarter?

Yeah. 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 is an annual limits 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. And that's something that's been in place from the beginning of Qatar, but it's been a bit more pronounced this year because performance has been so strong in the first three quarters.

Thanks, and then you're drilling down into the Lower 48. Can you just walk us through each of the 3 regions and what you're seeing from a volume perspective as we go into the fourth quarter and anything notable that you would call out in terms of how the performance is play-by-play?

Yeah. Thanks, Neil. It's Dominic here. I mean I think in terms of Q4 outlook here 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 the 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.

Thank you. Our next question comes from Doug Terreson from Evercore ISI. Please go ahead, your line is open.

Hi, everybody. 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?

Yeah. Doug. This is Don. Yeah, I can give you some guidance around the asset retirement obligations. In the UK , 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 completes in the first quarter of 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.

Oh wow. Okay. Okay, that's all I had. Thank you.

Thank you. Our next question comes from Roger Read from Wells Fargo. Please go ahead, your line is open.

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

Yeah. Hi, 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 that 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.

All right, I'll leave it there. Thanks.

Thank you. Our next question comes from Paul Cheng from Scotia Howard Weil. Please go ahead, your line is open.

Hey guys. Good morning. Matt, Just curious that on Montney, I think you guys are targeting on the condensate window. What's the API you're targeting because one of the push back we heard from people is that the update that people actually want to have a higher API condensate, so that the used lesser of the pipeline space, and when they blend it with the bitumen. So from that standpoint, I mean why that you guys think that you're condensate if you get from there, even if it is a lower API you will have a good market?

Yes, thanks Paul. This is Michael again. Our liquids in Montney is about half of our product mix and about two-thirds of our revenue mix. About over half of that is condensate, and it's a fairly wide 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 the 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 will 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.

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

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

40? Okay, that seems pretty low. Okay, thank you.

Thank you. Our next question comes from Paul Sankey from Mizuho Securities USA. Please go ahead, your line is open.

Thank you. Hi, all. We had question about the maintenance capital levels that will be ongoing after the disposals you made, Matt. So 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? Thank you.

Okay. Yeah Thanks, Paul. The maintenance capital. I assume you're referring to the sustaining capital number that we are...

Yeah exactly, sustaining is what I should have said.

Yeah. No, that's same. It's sort of interchangeable. But the so 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. So, there is no significant change there. There's some puts and takes with the acquisitions and growth in the unconventionals but it stays around $3.8 billion and that keeps or sustaining price, which is what we're really focused on well below $40 a barrel. The -- on the M&A front, it's really -- you referred to the $300 million the spend this year on acquisition capital. So those were adding positions in Alaska at the Nuna trend that's now closed in the Lower 48 adding for the most part royalty acreage within our coexisting operated positions. Some smaller additions in the Montney continue to calling up there and then the entrance into the Vaca Muerta play in Argentina and there's nothing new in this quarter from in that respect. But the -- yes, they sort of decision criteria, when we are thinking about those it's basically we're focused as we are in 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 competitive with other sources of resource additions. And again, that's something that we'll talk about -- more about in November, just philosophically how we think about all event and in the context of asset or corporate acquisitions.

Thank you. Our next question comes from Jeanine Wai from Barclays. Please go ahead, your line is open.

Hi. Good afternoon, everyone. Hi, hello. 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 we're still pending the successful close of that transaction, with Hilcorp does have a track record in Alaska 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 investments. 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.

Okay. And just saying we'll stay tuned. Thank you very much.

Thank you. Our next question comes from Bob Brackett from Bernstein Research. Please go ahead, your line is open.

Another Alaska related question. If we think about the fair share Act ballot initiative. Can you talk about that and perhaps put it in the context of the longer-term ebb and flow of tax policy up on the North Slope?

Yeah. Thanks, Bob. This is Michael, again. It's a situation that we are 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 that 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 of -- the benefits that the citizens would see. So we do have a long history of engagement with the public. We feel that there is 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.

Great. Thanks for that.

Thank you. Our next question comes from Jeoffrey Lambujon from Tudor Pickering Holt. Please go ahead, your line is open.

Good morning. My question is just on capital allocation for the remainder of this year, just thinking about the unchanged budget, would have stopped there may have been some downside potential and spend just given that UK closed. So just looking for any color on where that unspent CapEx might be allocated to instead for the remainder of the year?

Yeah. This is Matt, Jeoffrey, so far this year run rate has been about $1.6 billion in the quarter, that's going to drop $500 million in the 4th quarter. Part of it because of the UK disposition, but also just general phasing primarily associated with completions, and refracs and exploration timing there and it's just that those modest sort of planned changes that causes to go from a run rate of $1.6 billion to $1.5 billion

Thank you. Our next question comes from Michael Hall from Heikkinen Energy. Please go ahead, your line is open.

Thank you. Good morning. I appreciate the time. I guess maybe going back up to Canada or to Alaska -- sorry, can you guys provide an exit rate on what Alaska production look like after the turnarounds?

Yeah. 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 and to you?

Yeah, the capacity is about 100 million cubic feet a day. One of the benefits that we have of 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 stairsteps of production levels we'll be able to clone this plant multiple times over.

Thank you. Our next question comes from Pavel Molchanov from Raymond James Please Please go ahead, your line is open.

Thanks for taking the question. First, just a quick one, about gas pricing, you mentioned the lag effect benefiting LNG in the quarter by -- in your European gas pricing, it was the lowest number as far as I can remember on record, lower than in 2016 even. I'm curious why North Sea gas was so depressed in the September quarter?

Hey Pavel. This is Don. Yeah, all of the markers, were down during the third quarter from Brent to WTI and Henry Hub, of course, here in the US AECO, International Gas in Europe. LNG, of course, is quite different and it's priced differently. That's why we saw the increased realizations in the third quarter. But now that's just supply and demand factor in Europe, there is a weakness in the market or there was in the third quarter and 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?

And this is Matt, Pavel. No, this was focused on the cash flow characteristics in ABUs and the nature of that asset, the stage of the lifecycle. And we didn't consider an exit of Australia in its entirety.

Thank you. We have a question from Doug Leggate from Bank of America Merrill Lynch. Please go ahead, your line is open.

I know I ask my one question already. I think that's a mistake. I can ask another one, if you like.

Feel free Doug.

Well, I have you guys I actually didn't line up from other question. 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 because the costs -- well they've been running a bit light this year I'm just wondering if there is anything that we should read into that, are you doing a lot better on both operating costs. And I guess DD&A's a bit low as well but pretty much from the cash costs. But I'm guessing that's something you will address in a couple of weeks, but any comments you can share? But -- and I'll extend my gratitude to the operator for giving me the second shot. Thanks.

Doug, thanks for your second question. No the operating costs continue to hold the line. In fact, in third quarter, I think our production, and 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 litigation thing that we settled. So we see operating costs remaining essentially flat for this year. And so we're not adjusting the full-year production and operating cost guidance at this time. I mean, 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.

Thank you. And at this time we have no further questions. I would like to turn the call back to Ellen.

Thank you, Senera. 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.