Conoco Phillips (COP) — Q3 2019 Earnings Call Transcript

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 mitigated 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. 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 operational 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 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 UK 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. Second, as we do each quarter, we note the cash received during the quarter associated with the PDVSA settlement. To date, we've received over $750 million related to the $2 billion settlement agreement reached in the third quarter of last year. Working capital was a $300 million use of cash and as mentioned, we recognized $2.2 billion in proceeds from closing the UK disposition. Capital spending was $1.7 billion, resulting in free cash flow of $1 billion in the quarter. 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 will 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 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. Our Surmont alternative diluent project is on track for start-up in the fourth quarter as planned. In fact, we are 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, Vulcan at 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 5 multi-well pilot pads online in the Eagle Ford, and you'll hear more about that in a few weeks. Moving over to Europe, the UK 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. 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 II came online in August. 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 plan capital guidance remains unchanged at $6.3 billion, excluding about $300 million of opportunistic low-cost of supply resource positions that we discussed last quarter. On the production side, full-year guidance also remains unchanged, except for updating it for the close of our UK 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, but 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 and Investor Meeting on November 19 in Houston. We'll show a decade-long disciplined plan that delivers free cash flow and strong returns. 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'll open up for questions on the quarter.

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. 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?

We do expect the distributions from APLNG in even quarters to be high and in odd quarters to be low, continuing that trend. We distributed $60 million in the third quarter, and I anticipate that will increase to about $300 million in the fourth quarter. This aligns with my previous guidance of approximately $750 million for the year regarding APLNG. On working capital, we saw a $300 million use in the quarter, driven by an increase in accounts receivable due to the timing of sales in Norway and Malaysia, along with a decrease in accounts payable of around $150 million, which is just typical payment timing. There isn't much to indicate any significant trend here.

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.

Thank you, Doug. We chose to exit the ABUs not due to concerns about supply costs there, as we believe it is a competitive project. However, we determined that it would be wiser to monetize those assets and redirect capital to projects with higher returns throughout our portfolio. Thus, this was a clear capital allocation decision regarding the ABUs. We remain interested in the Qatar North Field expansion, which we also regard as a competitively priced LNG project, and we plan to advance discussions with Qatar as we progress through this year and into the next.

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, 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.

Good morning, team. My first question is about Qatar. Matt, could you remind us about the production mechanics? Considering you have a production run in Qatar that is heavily weighted towards the first half of the year, will you face any caps or restrictions on volumes as we enter the fourth quarter?

We've previously discussed the front-end loaded nature of the Lower 48. In Qatar, there are annual production limits we must adhere to, and we've seen strong performance in the first three quarters. Consequently, we need to reduce production in the fourth quarter to comply with these limits. This restriction has always been part of our operations in Qatar, but it has been more noticeable this year due to the strong performance earlier in the year.

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. 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 in North Dakota, of course, we will see a little bit of growth in the Delaware. 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.

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. I can give you some guidance around the asset retirement obligations. In the UK, I think we've already published that, but that's a $1.8 billion reduction in ARO. Then in 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.

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 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.

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 they use less of the pipeline space, and when they blend it with the bitumen. So from that standpoint, I mean why do you guys think that your 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 are about half of our product mix and about two-thirds of our revenue mix. 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. 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 40 degrees, plus or minus.

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

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.

Yes, that's interchangeable. It’s around $3.8 billion and will continue over the next decade. There are no significant changes to note, even with the acquisitions and growth in unconventional resources, as it remains around $3.8 billion, which keeps our sustaining price well below $40 a barrel. Regarding mergers and acquisitions, we are spending $300 million this year on capital for acquisitions. This includes expanding positions in Alaska at the Nuna trend, which is now closed, as well as acquiring mostly royalty acreage within our operated positions in the Lower 48. We are also making small additions in the Montney area and entering the Vaca Muerta play in Argentina, though there is nothing new to report this quarter. Our decision criteria focus on the cost of supply; we need to see the acquisition price and development costs being competitive with other resource sources. We will discuss this further in November, particularly regarding our approach to asset or corporate acquisitions.

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. With the transition from BP to Hilcorp, it's still in the early stages. We're waiting for the successful completion of that transaction. Hilcorp has a proven history in Alaska of revitalizing mature fields. They have managed to lower lifting costs, boost development efforts, and ramp up production in other areas. We anticipate a decrease in operating costs and a renewed emphasis on investments. Any capital projects for Prudhoe Bay will require approval from Hilcorp, Exxon, and ConocoPhillips. While we currently collaborate closely with BP as the operator, we will continue to work closely with Hilcorp as they take over and with Exxon to enhance the value of this legacy asset. We are enthusiastic about this transaction and believe there is potential to unlock more value at Prudhoe Bay.

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

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. 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. 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. 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.

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, the 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, 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. Good morning. I appreciate the time. Can you provide an exit rate on what Alaska production will 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.

Thanks for your question. First, I want to touch on gas pricing. You mentioned the lag effect that benefited LNG this quarter, and in your European gas pricing, it was the lowest I can recall, even lower than in 2016. I'm wondering why North Sea gas was so low 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 factors 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. We didn't consider an exit of Australia in its entirety.

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

Feel free, Doug.

I didn't plan to ask another question, and I feel a bit embarrassed for doing so. I had another question regarding your cost guidance, which I expect will be discussed next week. Since costs have been lower this year, I'm curious if there's anything we should take away from that. Are you seeing improvements in operating costs? Additionally, DD&A appears to be low, but I'm mostly interested in cash costs. I assume you'll cover this in a couple of weeks, but any insights you can provide would be appreciated. Also, I want to thank the operator for giving me this opportunity to speak again.

Doug, I appreciate your second question. The operating costs are stable. In fact, in the third quarter, our production, operating costs, and SG&A decreased by about 6% compared to the previous quarter. I wouldn't overanalyze that as we had higher costs in the second quarter due to turnaround activities and a legal settlement. We expect operating costs to remain fairly flat for the rest of the year. We can discuss our outlook in more detail next month. We're committed to maintaining an efficient operating structure.

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.