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ConocoPhillips (ticker: COP), the world’s largest independent E&P company, reported its Q3 financial results yesterday.

Q3 2017 Summary

  • Achieved Q3 production excluding Libya of 1,202 MBOED; 1.4 percent year-over-year underlying production growth excluding the impact of closed or signed dispositions; underlying production grew 19 percent on a production per debt-adjusted share basis
  • Lowering full-year 2017 expected capital expenditures to $4.5 billion, a 10 percent reduction from initial guidance
  • Maintaining full-year production guidance despite impacts from Hurricane Harvey, which were offset by increased volumes from our globally diverse portfolio
  • Reduced year-over-year production and operating expenses by 20 percent and adjusted operating costs by 15 percent
  • Closed San Juan and Panhandle dispositions. Expect over $16 billion of dispositions during 2017
  • Repurchased $1.0 billion in shares, which reduced ending share count by 2 percent from the end of Q2. On track for $3 billion in share repurchases in 2017
  • Reduced balance sheet debt by $2.4 billion and received credit rating upgrade. On track for less than $20 billion of debt by year-end
  • Released final project financing loan guarantee for APLNG in Australia after successful two-train lenders’ test

ConocoPhillips (ticker: COP) reported Q3 2017 earnings this week, with earnings of $0.4 billion, or $0.34 per share, compared with a Q3 2016 loss of $1.0 billion, or ($0.84) per share. Excluding special items, third-quarter 2017 adjusted earnings were $0.2 billion, or $0.16 per share, compared with a third-quarter 2016 adjusted loss of $0.8 billion, or ($0.66) per share.

Operations and production

ConocoPhillips Executive VP of Production, Drilling and Projects Alan J. Hirshberg said: “During the quarter, we ran 12 operated rigs in the Lower 48 Big Three unconventional assets, six in the Eagle Ford, four in the Bakken and two in the Delaware Basin.

Our Big Three unconventional production was 211,000 barrels per day with 123,000 per day from Eagle Ford, 66,000 per day from the Bakken and 22,000 per day from the Delaware. This was about flat to the second quarter of 2017 but included the impact of Hurricane Harvey. Excluding this impact, production from the Big Three unconventionals would have been about 6% higher sequentially.”

  • Canada’s Surmont project reached a record daily production of 141,000 barrels a day gross during Q3. The project has not yet reached full capacity yet
  • Australia’s APLNG ran at 110% of nameplate and maintained 98% uptime. 92 cargos were shipped through the end of Q3
  • Alaska spud the first wells at 1H NEWS, with first oil expected before the year’s end
  • GMT1 remains on track for first oil by the end of 2018 and costs should run under budget
  • Aasta Hansteen topsides left port in South Korea is headed for Norway, this project is on track for first production by late 2018
  • Work continues on Clair Ridge and Bohai phase 3, both are on track for first production in 2018

The company said fourth quarter production guidance is 1.195 million to 1.235 million barrels per day, and full year production range is between 1.350 million and 1.360 million barrels per day.

Liquefied Natural Gas Plant, Australia

Liquefied Natural Gas Plant, Australia

Conference call Q&A

Q: My quarterly question is a simple one. The U.S. is exporting this week again close to 2 million barrels a day of oil. It seems to us that we’re now starting to see some real linkage between certain parts of the Lower 48 and Brent pricing, so more of a Brent minus than a WTI plus kind of number. Is that what you’re seeing? Do you think it’s sustainable, and if so, maybe you could help us with how you think that would impact the relative investment decisions for the Eagle Ford as we go forward?

ConocoPhillips Executive VP, Finance, Commercial, and CFO Donald E. Wallette, Jr.: When you look at our U.S. production in total, we’re pretty heavily weighted towards the Brent side and not so much exposed to WTI, and a large part of that is because our Alaska North Slope, which is the largest portion of our U.S. really trades similar to Brent.

Probably what’s not recognized well enough is our Eagle Ford production that you alluded to, about half of that production is marketed on an LLS component basis and as you know, LLS and Brent have had a pretty strong relationship. So we’re not seeing the same impacts of the widening differentials that you might expect there. I do expect going forward that those relationships, they have maintained in the past, so I don’t see why they would break down in the future.

As far as exports themselves, we’ve been pretty active in the export, I’d say, in the first and second quarters this year and going back to last year, but we’re seeing demand pretty strong domestically now. And so I think in the third quarter, I don’t believe we had any waterborne cargos going outside the country. We did have some going inland or within the country. But we’re seeing markets improve here in the U.S., and as I mentioned, we’re pretty exposed to Brent relative to WTI.

Q: You’ve mentioned Alaska a couple times, such as the Willow discovery as well as discoveries by others in the region. Alaska has mostly flown under the radar up to this point. What potential activity is planned in Alaska, in that area, over the next 12-plus months, and what role it could play in either driving modest growth or maintaining volumes in the region?

ConocoPhillips Executive VP of Production, Drilling and Projects Alan J. Hirshberg: Well, we have this pipeline of projects in Alaska, a lot of good news there on things that have been going well, everything from CD5 to GMT1 to 1H NEWS that are all going well. Just take CD5 for an example. When we took FID on CD5, we were projecting plateau volumes of 16,000 barrels a day gross and we’re now at 26,000 barrels a day.

Projects like that have allowed us to continue to extend maintaining our production and we’ve already said that we plan to drill five exploration wells in Alaska this winter. In addition to that, three of those wells are appraisal wells for Willow and two that are new wildcats along the lines of what you were hinting at there, that some of the other opportunities out to the west.

And we also have submitted permits for new seismic on those state leases that we picked up late last year. Remember, we picked up about 740,000 acres gross in December of last year and so we’re starting to plan our seismic work around that. We see additional opportunity out to the west, but also have a nice pipeline of projects that we’re working on today. We hope to get GMT2 over the line to FID next.

Q: In regard to APLNG, I presume we’re now in a positive cash flow position, and I believe you must be building a cash cushion in the joint venture. So if the price stays here, when do you think the partner will start to receive the cash dividend payout from that? In some way, your cash flow from operations in this quarter, not only the impact by the $600 million of the pension contribution, but also the impact by not distributing the cash from the APLNG. Is that correct?

CFO Wallette, Jr.: We do have cash that’s building up in APLNG, as we’ve said before, the cash, the net cash flow breakeven, there in fact is somewhere in the $45 to $50 Brent range. We have been building cash within the joint venture. And if prices stay where they are for the rest of the year, it’s quite possible that we could see a fourth quarter distribution from APLNG, and then we would expect that to correspond to prices next year as well.

Executive VP Hirshberg: Yes. So that’s an active area of discussion in the joint venture right now, Paul. And we of course want to make sure we maintain enough cash build going into next year to cover loan payments as they schedule out next year. But even with that, at these kind of prices, you’re absolutely right that we’re building excess cash and we’ll be in a discussion about distribution timing. But no decision has been taken on that yet at this point.

Q: Can you talk a little bit about Australia and their domestic gas issues?

Executive VP Hirshberg: Yes, we’ve talked about that on the last few calls where the government has been working on considering export restrictions, and using this basis of making sure everybody is a net domestic gas contributor, particularly out in the east. And the decision they’ve taken recently, that you would have seen in the press, is they’ve decided not to restrict exports in 2018.

And what facilitated that decision by the government is that the three Curtis Island operators in Queensland, that all have these similar coal seam projects, have agreed that we will offer to the domestic market any spot cargos that we have planned next year, we’ll offer that gas to the domestic market at an equivalent net-back price before we go to spot LNG sales. And so for us, from an economic standpoint of course, that’s we’re indifferent to things that bring us the same net back.

There’s been some noise in the press about LNG operators selling spot cargos at net backs that are less than domestic prices. And obviously, you know us well enough to know we wouldn’t do that. We’re not in the business of selling our gas for less than whatever the best is in the marketplace. But we have also seen just here today in the press, where we announced our latest domestic gas sales, so this is an example of where we had some gas that could’ve gone spot and 21 petajoules of gas that we’ve just agreed to sell into the domestic market that would’ve gone to spot LNG, because we were able to sort of achieve those net-back objectives.

So with that sale being added on, we now are north of 180 petajoules of domestic gas that APLNG will be selling into the market next year. So in 2017, APLNG is supplying about 20% of the domestic gas market in eastern Australia. And next year, with this latest sale, we’ll be just shy. We’re already just with what we’ve done so far almost up to 30%.

Q: What was the average volume produced from the Canadian Surmont project?

Executive VP Hirshberg: 63,000 barrels a day was the Q3 number for Surmont.

Q: We often think about production excluding Libya, but it did stick its head up here in the quarter. I was curious what you’re seeing out there and if you have any thoughts about the sustainability of it, in what’s obviously a very volatile region.

Executive VP Hirshberg: Libya is an interesting case because if you look back to last year, we averaged 2,000 barrels a day for the year from Libya, and we just did 24,000 in the third quarter. We’re currently north of 30,000 if you look at sort of what our current production rate is. That’s all on a net basis. So it’s over 200,000 on a gross basis, current production.

We lifted three cargos from Libya in the third quarter, so that’s 10 that we lifted in the first three quarters of the year and in fact, we’re lifting another one here just recently, so we’re up to 11. We’ve got six workover rigs active in Libya that’s helping drive some of this production increase. So it’s getting to be a more significant number, I guess, particularly year-over-year in our bottom-line production.

Q: What about the $4.5 billion of the revised CapEx for this year? That would suggest that fourth quarter would jump to $1.4 billion. You’ve been doing about $1 billion a quarter. What may be the effect behind why we that see that jump by 40%?

Executive VP Hirshberg: Yes. We did $1.1 billion this quarter.

Q (continued): Can you talk about that, whether $4.5 billion is what you consider your new sustainable capital expenditure requirement?

Executive VP Hirshberg (continued): Well, that latter question we’ll cover in two weeks. But it was $1.1 billion this past quarter, and we’re forecasting between $1.3 billion and $1.4 billion in the fourth quarter to get to that $4.5 billion number. And the key drivers to that increase, we have been on a fairly steady increase through the year in the Lower 48 on overall activity, and so there is still some more build in actual CapEx spend, and that’s 3Q to 4Q in the Lower 48.

And that’s actually exacerbated a little bit by the Harvey effect, because there was some money that didn’t get spent in the third quarter due to Harvey and just some work that you weren’t doing because we were down to that for a period of time. But we also have increases quarter to quarter in Bohai Bay as that phase 3 project continues to ramp. We expect that spending to be up. And also, our drilling programs in Alaska and Europe are both going to be up, we expect third quarter to fourth quarter. And so those are the key pieces.

Q: Following up on the CapEx question… $4.5 billion of CapEx, 3% production growth, I certainly don’t think anyone expected that at the beginning of this year. Could you maybe provide a little color about how you feel like the company has been able to accomplish this, and then whether you think that you can continue to grow at these types of rates at this level of spending. It’s obviously a choice, but what do you think about that?

Executive VP Hirshberg: Yes. I think we really accomplished this. I mean, you’re right that we have done better than we expected, the plan we laid out for ourselves at this time last year as we were looking into 2017, and we’ve continued to do a really good job of driving efficiency. That’s been a key part of our capital discipline. It’s allowed us to lower our capital costs. We’ve been successful at resisting inflation to a large extent in the Lower 48, and our production performance has really come out on the high side in a number of different places, and those things have kind of added together to give that outperformance.

While I travel around and see this outperformance, I try to really understand what’s driving it. I think in our organization, operationally as we’ve reduced the amount of money that we were spending on big projects, the growth money, the $17 billion we used to spend in this company back in 2014, our organization has been able to spend a lot more focus on the base. And our base production is really a big part of what’s been outperforming, and I do expect that to continue.


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