Welcome to the third quarter 2017 ConocoPhillips earnings conference call. My name is Christine, and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Ellen DeSanctis, VP, Investor Relations and Communications. You may begin.
Thanks, Christine. Welcome to all of our call participants this morning. Today's presenters will be Don Wallette, our EVP of Finance, Commercial, and our Chief Financial Officer, and Al Hirshberg, our EVP of Production, Drilling, and Projects. Our cautionary statement is shown on page two of today's presentation deck. We will make some forward-looking statements during today's call that refer to estimates and plans. Actual results could differ due to the factors noted on this slide and also described in our periodic SEC filings. We will also refer to some non-GAAP financial measures in today's call. The purpose of these is to help facilitate comparisons across periods and between peers. Reconciliations of non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and again on our website. Finally, this morning, we're going to limit during Q&A your questions to one and a follow-up.
With that, I'm going to turn the meeting over to Don.
Thank you, Ellen, and good morning. I'll start on slide four with our key strategic, financial, and operational highlights for the third quarter. Starting on the left side of the chart with strategy, this quarter was another impactful one for our company. We've executed a number of transformational decisions to accelerate our differentiated, disciplined, and returns-focused strategy. During the quarter, we closed the sales of our San Juan Basin and Panhandle assets. We also continued progressing several other sales that should close in the fourth quarter or early next year. We expect to deliver greater than $16 billion of asset sales during 2017. In the third quarter, we paid down another $2.4 billion of debt, bringing our balance sheet debt to $21 billion. In the quarter, we received a credit rating upgrade. We are on track for the year-end debt balance to be under our target of $20 billion.
We repurchased $1 billion of our shares during the quarter, which takes us to over $2 billion repurchased for the year, representing about a 3.5% reduction in outstanding shares year-to-date. We expect to buy back another $1 billion of shares in the fourth quarter. Between our dividend and the expected share buybacks, capital return to shareholders would represent the equivalent of 60%-70% of our operating cash flow in 2017. Moving to the middle column, our third quarter financial results extended the momentum we've built over the past year to achieve profitability and maintain cash flow neutrality in a $50 price environment. On an adjusted earnings basis, we were profitable for the second successive quarter, realizing a profit of about $200 million or $0.16 a share. We generated $1.1 billion of cash from operations, excluding working capital.
I want to point out that operating cash flows this quarter were impacted by a choice we made to use a portion of our cash balances to accelerate funding of future pension obligations with a $600 million cash infusion. I'll cover this item in more detail in a few slides. Excluding the pension item, cash flow was right in line with our expectations and consistent with our published sensitivities. On a year-to-date basis, cash from operations is $4.5 billion, which exceeds CapEx and dividends by over $400 million, despite the $600 million CFO reduction I just mentioned. As we've shown for more than a year now, our cash flows have more than covered our CapEx and dividends. We don't require a pathway or market help to get to cash neutrality. Adjusted operating costs were 15% lower year-on-year as we continue to lower our break-even price across the portfolio.
Moving to our operational results on the right, we're meeting or exceeding all of our operational targets. Production excluding Libya for the quarter was 1.2 million BOE a day. Adjusting for dispositions, our underlying production on a per debt adjusted share basis grew by 19% compared to the third quarter of last year. We successfully completed the last lenders test at Australia Pacific LNG, which allowed us to release the final project financing loan guarantee. We continue to execute our 2017 capital program scope at lower cost. As Al will cover in more detail, we're lowering our capital guidance for the year to $4.5 billion. That's a reduction of $500 million or 10% compared to our initial 2017 guidance. To recap, this quarter's performance again reinforces the transformation we've made as a company. We're delivering on our priorities and continuing to build momentum.
While the outlook for commodity prices has improved recently, we remain committed to our disciplined, returns-focused strategy that creates shareholder value. If you turn to slide five, I'll walk through the third quarter financial results. With WTI averaging about $48 a barrel and Henry Hub about $3 an Mcf, our average realized price was around $39 per BOE. Compared to the prior quarter, adjusted earnings improved slightly because of higher realizations and equity earnings, partly offset by disposition impacts. Compared to the year-ago quarter, adjusted earnings improved by over $1 billion, with the improvement driven by higher commodity prices, lower depreciation and exploration expenses, and the impact of dispositions. Third quarter adjusted earnings by segment are shown on the lower right. The supplemental data on our website provides additional financial detail. If you turn to slide six, I'll cover our cash flows during the quarter.
Looking at the sources of cash shown in green, cash from operations was $1.1 billion, which, as I mentioned, was impacted by our decision to make a $600 million cash contribution to our U.S. pension fund. As we continue to strengthen our financial position, we look across the balance sheet for opportunities to reduce long-term obligations. This payment represents an economic acceleration of future contributions, which will also serve to reduce cash flow volatility and increase flexibility going forward. The other major source of cash during the quarter was asset sales, which generated $3 billion. The uses of cash shown in red were in line with expectations we provided during our last earnings call. We used $2.5 billion to retire debt and distributed $1.3 billion to shareholders through dividends and share buybacks. We ended the quarter with $9.6 billion of cash and short-term investments.
If you turn to slide seven, I'll wrap up by covering year-to-date cash flows to emphasize our focus on free cash flow generation. This slide illustrates the disciplined approach we take to running the company. Starting with the first set of bars on the left, as I just said, year-to-date operating cash flows have more than exceeded spending on capital investments and dividend distributions. The second set of bars shows how cash proceeds from dispositions are pre-funding our debt reduction and share repurchases. In addition to the roughly $14 billion of cash proceeds shown here, we also have $2 billion of equity in Cenovus, which will be converted to cash proceeds over time. In summary, the business continues to run well. Let me turn it over to Al to give you some color on the operations.
Thanks, Don. I'll provide a brief overview of our third quarter operating highlights and our outlook for the rest of the year, including our updated capital guidance. Operationally, we had another strong quarter, despite some tough weather challenges here in Texas. As Don mentioned, production excluding Libya averaged 1.2 million barrels per day. Despite a 15,000 barrel per day reduction in the quarter due to Hurricane Harvey, better performance from our global portfolio allowed us to offset this loss and still exceed the midpoint of guidance by 12,000 barrels per day. Year-on-year, this represents an increase in underlying production of 1.4%. During the quarter, we ran 12 operated rigs in the Lower 48 Big 3 unconventional assets, six in the Eagle Ford, four in the Bakken, and two in the Delaware Basin.
Our Big 3 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 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 3 unconventionals would have been about 6% higher sequentially. In Canada, Surmont achieved a record daily production of 141,000 barrels a day gross during the quarter. The project continues to ramp up toward full capacity. In Australia, APLNG ran at 110% of nameplate and demonstrated 98% uptime. We've shipped 92 cargoes through the end of the third quarter. In Alaska and Europe, we safely executed significant turnaround activities, which now completes our major turnarounds for 2017. Finally, across the portfolio, we're making great progress on our conventional projects.
In Alaska, we spud the first wells at 1H NEWS, with first oil expected before year-end. Meanwhile, GMT-1 is still on track for first oil by the end of 2018, with costs running well under budget. The Aasta Hansteen topsides left port in South Korea headed for Norway, and this project is also on track for first production by late 2018. Work also continues on Clair Ridge and Bohai Phase 3, both of which are on track for first production in 2018. Moving on to slide 10, I'll provide an update on our 2017 outlook. We're lowering our full-year 2017 capital guidance for the second time this year. We now expect to spend $4.5 billion. We continue to do more for less. The updated capital guidance represents a 10% reduction from our original budget. Despite this CapEx reduction, we expect to exceed our original production guidance.
This year, we now expect to deliver 3% underlying production growth, and that's 17% on a debt-adjusted share basis. On the left side of the slide, we list key fourth quarter and full year guidance metrics. Below the capital, you can see our fourth quarter production guidance is 1,195-1,235 thousand barrels per day, and we've tightened the previous full year production range to between 1,350 and 1,360 thousand barrels per day. Our remaining drivers are tracking closely with our guidance. That's a quick recap of the quarter. As Don said, business is running well. We continue to look forward to providing an update of our future plans at our analyst and investor meeting on November 8th. I'll turn the call over now to Q&A.
Thank you. Ladies and gentlemen, if you have a question, please press star, then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star, then one on your phone now. Our first question is from Doug Leggate of Bank of America. Please go ahead.
Oh, hi. Good morning, everybody. Excuse me, I needed to clear my throat. Hi, everyone. I'm not optimistic on getting too many forward-looking questions answered today.
Come on.
I might give it a go. Just one forward-looking and one about the quarter, if I may. $55 Brent all the way out in the strip from what we can tell now. You guys are obviously fairly levered to that, it kind of changes the narrative a little bit about where your cash breakeven is for the portfolio and your choice between sustaining the buyback program, perhaps, beyond the disposal proceeds that you brought in versus reinvesting in the company. I know you're going to get into this in a couple of weeks, but can you just frame for us what a $55 world, what does Conoco think about by way of growth versus continued debt-adjusted per share growth?
Well, Doug, that almost sounds like you've written the title of one of our slides for the week after next for our analyst meeting. I think you've teed it up perfectly, and we're going to answer it then, as you predicted.
Yeah, I thought I'd give it a go, but anyway, it sounds optimistic, thank you for that. My quarterly question is really a real simple one. The U.S. is exporting this week again closer to 2 million barrels a day of oil. It seems to us that we're now starting to see some real linkage, I guess, between certain parts of the Lower 48 and Brent pricing, more of a Brent minus than a WTI plus kind of number. I'm just curious, is that what you're seeing? Do you think it's sustainable? 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. I'll leave it there. Thank you.
Yeah, Doug, this is Don. I can comment a little bit on that. When you look at our U.S. production in total, we're pretty heavily weighted toward 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. As you know, LLS and Brent have had a pretty strong relationship. 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. 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. We're seeing demand pretty strong domestically now. I think in the third quarter, I don't believe we had any waterborne cargoes going outside the country. We did have some going inland or within the country. We're seeing markets improve here in the U.S., and as I mentioned, we're pretty exposed to Brent relative to WTI.
Just to be clear, Don, if export capacity is obviously up, can you envisage 100% of the Eagle Ford being marketed on a Brent basis or no?
Well, I think 100% would be an awful lot. I don't know what dynamic would have to cause that. Today and in the third quarter, we didn't see the arbitrage advantage in exporting relative to the strength that we were seeing domestically. I think there'll be times when if you go back last year, we had a good bit going outside the country. 100% is probably something that we wouldn't be expecting.
Okay. I appreciate the answers, guys. We'll see you in a couple of weeks. Thank you.
Thanks, Doug.
Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead.
Hey, guys. Good morning.
Good morning, Paul.
Don, just curious, then, for APLNG, I presume right now you are in a positive cash flow position. I believe you must be building cash cushion in the joint venture. If the price stays here, when you think the partner will start to receive the cash dividend payout from that? In some way, then, your cash flow from operation in this quarter not only impact by the $600 million of the pension contribution, but also impacted by the not distributing the cash from the APLNG. Is that correct?
Well, you're right, Paul. We do have cash that's building up in APLNG. As we said before, the net cash flow breakeven there, in fact, is somewhere in the $45-$50 Brent range. Yeah, we have been building cash within the joint venture. 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, we would expect that to correspond to prices next year as well.
Yeah. That's an active area of discussion in the joint venture right now, Paul, 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. Even with that, at these kind of prices, you're absolutely right that we're building excess cash, we'll be in a discussion about distribution timing, no decision's been taken on that yet at this point.
Mm-hmm. Al, since that I have you here. The $4.5 billion of the revised CapEx for this year, that would suggest the fourth quarter will jump to $1.4 billion. You've been doing about $1 billion a quarter. What may be the factor behind why that we see that jump by 40%?
Yeah. We did $1.1 billion this quarter.
You can also talk about that whether $4.5 billion is what you consider is now your new sustainable CapEx requirement.
That latter question we'll cover in two weeks, it was $1.1 billion this past quarter, we're forecasting between $1.3 billion and $1.4 billion in the fourth quarter to get to that four and a half number. The key drivers to that increase, we have been on a fairly steady increase through the year in the Lower 48 on overall activity. There is still some more build and actual CapEx spend, that's 3Q to 4Q in the Lower 48 . 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 for that for a period of time. We also have increases quarter to quarter in Bohai Bay as that phase 3 project, as that continues to ramp.
We expect that spending to be up. Also our drilling programs in Alaska and Europe are both going to be up, we expect, third quarter to fourth quarter. So those are the key pieces.
Thank you.
Thank you. Our next question is from Phil Gresh of JPMorgan. Please go ahead.
Yeah. Good morning. First question is just on kind of a follow-up on the CapEx question. I mean, $4.5 billion of CapEx, 3% production growth, I certainly don't think anyone expected that at the beginning of this year. Al, maybe you could just provide a little color about how you feel like the company's 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 spend. It's obviously a choice, but how do you think about that?
Yeah. I think, Phil, we really accomplished this. You're right that we have done better than we expected, the plan we laid out for ourselves 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 that'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. As I look at it, I made some comments on the last quarterly call that as I travel around and see this outperformance and try to really understand what's driving it.
As I said last quarter, 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. Our base production is really a big part of what's been outperforming, and I do expect that to continue. Without front-running our story in two weeks, I think you can expect that we'll show you our latest calculations on that. This is not a one-trick deal this year. It's going to continue, I think.
Yeah. Okay. Very clear. Second question, I guess, for Don, this one would be, again, don't want to front-run the Analyst Day, but some of the key tenets that you've talked about over the past several quarters has been 20%-30% of CFO back to the shareholder and $3 billion of buybacks between 2018 and 2020. Those were not in the slides today. I just wanted to ensure that there's no real change to that commitment on a go-forward basis. Obviously, you're going to have a bigger update more broadly.
No. Right, Phil. Yeah, we'll be laying all that out here in a couple of weeks for you. Absolutely no backtracking from any of those commitments. You'll see that again here in a few weeks.
Okay, thanks.
Thank you. Our next question is from Scott Hanold of RBC Capital. Please go ahead.
Thanks. If I could ask another question on the capital spending budget coming down quite a bit just sequentially quarter to quarter. Al, could you provide a little color on that? Was that a change in your service cost expectations? Was that part related to less activity related to hurricane? Just a little bit of color on specifically what that reduction was for.
Sure. Let me talk a little more about that. At a high level, it is, as I was talking about a minute ago, just reflecting our continued capital discipline. There is this resisting inflation part. I think since a little over a quarter ago, when the industry in the Lower 48 had a bit of the tapping on the brakes that people have talked about, that has really halted Lower 48 inflation in its tracks for the most part. Some of our assumed inflation that we thought we would see earlier in the year in the second half, we aren't seeing. That little bit of slowdown and reduction in rigs that we've seen and slowdown in activity has been enough to give us an absence of inflation that we had been assuming.
We also are continuing to see increases in efficiency across the Lower 48 and across the world. We've also had, as I mentioned in my prepared remarks, GMT-1, one of our major projects that we have going in Alaska, has continued to really perform well on the project side and is underspending relative to budget. That's a savings. Then you mentioned Harvey. There is a little bit of Harvey delay where there's some work that we weren't doing or paying for during the time we were down for Harvey. That is a little tiny piece of this reduction.
Okay. The bulk of it is actually organic stuff happening, right?
That's right. I should also mention, there's one other thing is we've also seen some reduction on the operated by other side. A little less AFEs coming in from some of our partners where they're operating than we would have forecast as they've slowed down a bit from the plans we were expecting from them.
Okay. That's great color. Maybe this one's for Don. You gave some brief comments in your prepared remarks on the Cenovus ownership. Obviously, the lockup's expiring here soon. Could you provide a little more detail on big picture, kind of how you look at that ownership and what you kind of want to see as you go down the path of how and when you monetize it?
Sure, Scott. A little bit at least. The standstill, as you mentioned, that's coming up pretty soon. It expires the 17th of November, so we'll be free to market the equity anytime after that. The market value right now is right around $2 billion, I believe. This equity was really transactional currency, as you know. We're not natural long-term owners, not strategic owners. We'll be reducing our position over time. I think you should expect that given our financial position, we'll be patient. We can afford to be patient. Our approach is going to be value-driven.
Okay. Appreciate that. Thanks.
Thank you. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead.
Great. Thanks. Maybe one first on the U.S. onshore. I know you averaged 12 rigs in the quarter. What's the current rig count in the U.S. onshore, and how should we think about that trajectory into 2018?
Well, of course, we'll cover 2018 in a week after next, but I think that certainly I can, without terribly front-running things, say that you can expect to see from us for the Lower 48 for 2018, a very disciplined program. You're not going to see anything crazy in two weeks, and you're going to see these same general kind of activity levels. We may have rigs of opportunity that we add or subtract here and there as we have certain situations, but I think we're at a pretty comfortable rig level at that kind of number that you mentioned.
Okay. Thanks. Then maybe on the project side, you've mentioned Alaska a couple times on the ongoing projects. The Willow discovery as well as discoveries by others in the region Alaska have mostly kind of flown under the radar up to this point. Can you talk a little about what activity you may have 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?
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 GMT-1 to 1H NEWS that are all going well. Just take CD5 for an example for a moment. 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. We've already said that we plan to drill five exploration wells in Alaska this winter. In addition to that, three of those wells, by the way, 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.
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. 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 GMT-2 over the line to FID next.
All right. Thanks, Al.
Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead.
Good afternoon. Al, given the upcoming analyst meeting, I'll ask you just a couple of modeling ones and more specific questions. First, on the pension, do we consider that very much a one-off or is that going to be a future payment? Secondly, along cash flow lines, you talked about the $4.5 billion, the potential for increased efficiencies going forward. Should we push $4.5 billion as you're spending into our long-term modeling? Then I have a separate follow-up. Thanks.
Paul, this is Don. I'll address.
Hi, Don
The pension question that you had. I think you should view this as a unique opportunity that we had to make a fairly substantial discretionary contribution to the pension fund. You see a lot of companies doing that these days for a variety of reasons. I explained our reasons. To answer your question, our plan doesn't include significant contributions going forward in the next few years.
Thanks.
I guess on the CapEx, obviously, we'll be talking about the forward CapEx here in a couple of weeks. Don't forget that we have been ramping through 2017 in our Lower 48 rig program and from the low levels we were at last year. That spending has been increasing quarter-over-quarter to get to the kind of levels that we're at today.
Got it. There's been some press out on Australia domestic gas issues. Could you talk a little bit about that? Thanks.
Yeah. We've talked about that on the last few calls, where the government's been working on considering export restrictions and using this basis of making sure everybody is a net dom gas contributor, particularly out in the East. The decision they've taken recently that you would have seen in the press is they've decided not to restrict exports in 2018. 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 cargoes that we have planned next year. We'll offer that gas to the domestic market at an equivalent netback price before we go to spot LNG sales. For us, from an economic standpoint, of course, we're indifferent to things that bring us the same netback.
There's been some noise in the press about LNG operators selling spot cargoes at netbacks that are less than domestic prices. 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. You have also seen just here today in the press where we announced our latest domestic gas sale. This is an example of where we had some gas that could have gone spot, and 21 petajoules of gas that we've just agreed to sell into the domestic market that would have gone to spot LNG because we were able to sort of achieve those netback objectives. 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.
In 2017, APLNG is supplying about 20% of the dom gas market in Eastern Australia. Next year, with this latest sale, we're already, just with what we've done so far, almost up to 30%.
That's interesting. I don't know if this is public or not, but can you talk about how you calculate the netback comparability?
Well, it's reasonably straightforward. You know what all the pieces are. The piece some people sometimes miss when they just look at sales prices is there are significant transportation costs in Australia to get from where we're producing the gas to the market, to our individual customers. There's significant transportation distribution costs. Of course, you have the same thing on LNG where you're paying to liquefy and to ship. It's just getting to the equivalent netback for us all the way back to the wellhead, is the way we think about it.
Thank you. Our next question is from Blake Fernandez of Scotiabank Howard Weil. Please go ahead.
Folks, good morning. Al, I wanted to go back to the capital commentary that you provided. Last quarter, I thought it was interesting. I think you said for every dollar of inflation you were seeing in the Lower 48, you were seeing $2 to $3 of deflation globally. It sounds like that Lower 48 increase has kind of begun to plateau or flatten out. I'm just curious on the international front, are you still seeing that deflationary trend that you were witnessing, or has that begun to change at all?
Yes. Hey, Blake. The international deflationary trend has begun to flatten out as we've gone through the year. We're not seeing as strong a deflation percentages in the third quarter as we were, say, in the first half. There's a little bit of it. Also at the same time, as I said, it's flattened out in the U.S., those two are offsetting each other a bit. We still expect as a corporation to be net deflationary in 2017 versus what we saw in 2016. Internationally, we are still seeing deflation on subsea equipment, seismic costs, offshore rigs, support vessels, even software. Software is another area where we've continued to see some deflation this year. In the U.S., as I said a minute ago, with the industry slowing down a bit, we've seen a flattening.
We've actually, on some of our contracts in the U.S., even seen downticks versus where we were earlier in the year.
Okay, that's helpful. Thank you. The second question, I'm sorry if this is a little bit detailed, but I'm kind of having trouble getting to some of the 4Q guidance on production. If this is something you guys need to follow up with after, that's perfectly fine. I'm just trying to kind of think about the moving pieces. You've yet to close Barnett, so that's a net negative. Then obviously San Juan and the Panhandle probably come out from a full quarter contribution, but then somewhat offsetting that is an increase of 15,000 barrels a day of the Eagle Ford. Am I kind of addressing all of the right moving pieces there?
Yeah. That's right. Those are all appropriate moving pieces.
Okay. I think that kind of covers what I need, thank you.
Yeah. I think, when you look at those numbers and compare the underlying, after you adjust for asset sales and look at kind of midpoint of our 4Q number, you'll see about 4% growth versus the fourth quarter of last year. Year-over-year, fourth quarter 2016 to fourth quarter 2017. You should get about a 4% number.
Got it. Okay. Thank you.
Blake, there's a chart in the appendix, if you haven't seen it, that takes you from midpoint to midpoint on a same-store sales basis.
Okay. Thank you, Ellen.
You bet.
Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead.
Good morning, team.
Morning.
The first question I had was just on Libya. I know 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 any thoughts and the sustainability of it in what's obviously a very volatile region.
Okay. Yeah, 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 in the third quarter, and we're currently north of 30. If you look at sort of what our current production rate is, that's all on a net basis. That's over 200 on a gross basis, current production. We lifted three cargoes from Libya in the third quarter, that's 10 that we lifted in the first three quarters of the year. 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. It's getting to be a more significant number, I guess, particularly year-over-year in our bottom line production.
Yep. No, that makes sense. The follow-up is, I recognize you guys make very clear that you're price takers that plan for a lower for longer crude price environment. Where do you think we are in terms of the crude rebalancing? We obviously have seen products clean up and OPEC compliance has been good and some of the hyper-U.S. growth expectations have been moderated, curious in terms of how you guys are thinking about the market evolving here.
Yeah. We're seeing the same numbers you are of watching things tighten, also, it's not hard to predict with the rollover in U.S. rigs that that's going to give a different U.S. production profile than I think people were expecting a quarter ago. That's also going to tighten things up. There's also such large wild cards With things like the Libya that we were just talking about, the latest things going on in Kurdistan, et cetera. You have a long list of things you can name there.
For us, you'll see at our Analyst Day here in a few weeks that we're just very focused on not counting on anything good happening for us there on prices, really keeping our company structured, keeping things tight and disciplined to where we continue to give the results you've seen out of us in the last four or five quarters, where we can get good financial results at prices below where we are right now.
Congrats on a good quarter.
Thanks, Neil.
Thank you.
Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.
Yeah, thanks and good morning.
Morning.
Since it's still morning here in the Central Time Zone. Just trying to stick with the let's not talk too much forward, look a little bit back. You mentioned APLNG running 110%, the breakevens in that, I think, $45-$50 range. I was curious, though, if you can run at those kind of levels, and it seems typical in these LNG projects to sort of have a base assumption and then exceed it. Does that lower the breakeven by a material amount? I mean, in other words, can APLNG get more competitive as we go forward?
Well, I think the kind of break-evens we've been talking about are based on the performance that we have been achieving for a while now. The 110% performance is not news. That's baked into our numbers, really.
As good as it gets? No, I do not answer that, I'm just
Yeah, no, I wouldn't say that. I would hate to leave that impression. We actually have a lot of work going on to continue to drive down our operating costs and our sustaining capital costs on the upstream side of the project. We in the joint venture have significant plans to continue to improve it. I was really just trying to comment on what you asked about, though, the extra 10% throughput. That's something we've been doing for a while now and is built into our plans. It's one of the things that pushes you. It does push your breakeven down some. You shouldn't expect a dramatic change just from that effect.
No, I know. With all the drilling activity, more volume typically, little better unit cost structure, I would imagine.
Yeah.
Follow-up question. Since, I presume, earlier when you were talking about the cost inflation, deflation was more on the CapEx front. Can you give us any sort of how the OpEx side? I know you give the OpEx guidance number, but what are you seeing in terms of cost inflation on the OpEx side? Is any of that a function of the non-operated part of your portfolio as well?
Yeah. On OpEx side, let me just mention some of the numbers. Our third quarter OpEx number that we just published this morning is down 15% on the adjusted OpEx that we focus on, down 15% versus the same quarter in 2016. Obviously there's asset sales that are built into that. If you look at the same store sales basis and take out all that, the asset sales confusion from that, basically, we're right on our original budget guidance. We're doing that with a couple % higher volume. Our budget was originally based on a midpoint 1% volume increase. It's at 0-2 range, midpoint one, and we're accomplishing three. Basically, we've been able to eat all the extra OpEx, transportation, et cetera, that comes with those extra barrels and still meet our guidance.
As I look forward into what we're doing there, we're certainly not done on our OpEx work in the corporation. We have a lot of focus on it around the world, and I expect that we'll continue to see additional improvement there. From the inflation side, the story is pretty similar to what I was talking about on CapEx, that it's a little bit to the benefit to us in 2017 versus 2016 so far.
Okay, great. We'll see you in about a week and a half.
Okay.
Thanks, Roger.
Thank you. Our next question is from Jason Gammel of Jefferies. Please go ahead.
Thanks very much. If I could just maybe follow up on the pension contribution. Don, can you talk about what made that discretionary payment more attractive than, let's say, accelerating some further debt repayment? Maybe also address the level of funding relative to the obligation?
Yeah, Jason. I think the way we looked at it is that this was a really good way to put a portion of our large cash balance to work. Essentially what we're doing is moving cash from short-term, low-return investments on the balance sheet to the pension fund that can invest in much longer-term, higher yield type return in investments. It's an arbitrage there. We compared it incrementally to reducing the next best bond retirement opportunity that we had.
It had advantage to economics with respect to that. Your other question was around the level of funding of the plan, I believe. With this contribution, and this was to the U.S. qualified plan, it would bring our funding level up to right around 85%. If I remember correctly, that'll be about the highest level of funding that we've had since before the spin of the company in 2012. The liability for that U.S. pension fund would be down from a little over $1 billion, I believe $1.1 billion before this contribution to bring it down to about half a billion dollars.
Great. Very clear. I almost hesitate to ask this follow-up question, given that I'm sure we'll hear a lot about your premium Eagle Ford position in a couple of weeks. Another operator did take a pretty big write-down in the Eagle Ford today and talk about how they had significantly down spaced further than what their acreage would actually produce that optimally. Al, I was hoping maybe you could just address at a very high level, what distinguishes your position from some of the other operators there?
Yes, obviously, I can't comment on any of the details of the other operators' results, but clearly it doesn't apply to us. We've been very deliberate in our development plans there in the Eagle Ford. We're very tailored to the specific reservoir characteristics in the different areas. You know that we're right in the sweet spot. We've got a lot of running room. You remember that map that we showed at last year's Analyst Day? Ellen tells me it's page 48 of last year's deck that showed.
Please show your last year's material.
Yeah, showed how much running room we have there. We really have no concerns, anything like that. Our Eagle Ford continues to make us proud and outperform and even took a beating from Hurricane Harvey and came back pretty quickly, right back up to full production.
Yeah, I appreciate that. I think it's just useful to distinguish you from some of the other operators. Appreciate that.
Yep.
Thank you. Our next question is from Guy Baber of Simmons. Please go ahead.
Thank you for taking the question. Al, on the production side, you did a good job highlighting the outperformance of your base portfolio. Can you speak to the performance year-to-date from the major projects that have been ramping up? You gave some color on Surmont, it looks like that's getting closer to max rates, maybe where that is right now. Malikai as well, maybe specifically, has that fully ramped up? Where are we on the Kebabangan gas ramp up?
Sure. On Surmont, we'll be fully ramped basically end of the year. Early next year, we'll be at our full rate. We're right toward the end of that. Malikai, we are still ramping and won't hit the plateau there till next year in 2018. KBB has been kind of an odd story because we've had gas availability from our side for a long time, for several years, and have been limited by non-owned third-party infrastructure that has had some pretty significant maintenance issues, which have slowly been getting lined out. We are seeing higher volumes from KBB, in recent weeks, actually, and expect it to be part of what allows us to grow volumes a bit into the fourth quarter, as we've been basically allocated a higher rate from KBB into MLNG.
I think that year-over-year, we'll see higher rates again in 2018 versus 2017 for KBB because of that effect.
Yep, that's helpful. My follow-up is on the capital spending side. You highlighted some of the variables that might contribute to a bit higher CapEx going into 4Q with Lower 48 activity, partial driver there. Are there any specific offsets you would call out into next year? I'm thinking specifically about if there's any noteworthy major project, longer cycle spend, maybe associated with Surmont or other projects that set to fall off on a year-over-year basis, or if lower CapEx going forward is just going to be a function of you guys continuing to get more efficient and capture deflation where you can.
Yeah. There's a lot of moving parts there to answer that question. We're going to have a segment in two weeks at the analyst meeting where we give you some fairly detailed plots and charts that show you how all those pieces add up from both a capital perspective and a production volume perspective. I think that's probably the best way to answer that.
Fair enough.
wait for those charts.
Thank you.
Thanks, Guy. Thank you. Our next question is from Pavel Molchanov of Raymond James. Please go ahead.
Thanks for taking the question. Just two quick kind of housekeeping items. As we watch spot LNG prices in Asia picking up, can you remind what portion of your APLNG exports are fixed price versus what's being sold in spot market?
Well, yeah. This is Don. From APLNG, 100% of the gas from APLNG that's not dedicated to the domestic market is contracted under long-term contracts to customers in China and Japan. Those customers have a right to reduce their obligation by up to 10% in any particular year, and so that can make as much as 10% of the capacity available for the spot market.
Got it. On Libya-
I can add to that. In fact, our customers have taken that downward quantity tolerance for 2018, and that's what's made these spot cargos available in 2018 that we've been in this discussion with the government about making those available as domestic gas.
Right. Understood. On Libya, you're up to 24,000 BPD. If you were to get back to pre-revolution, pre-2011 normalized levels, how much higher would that number get, all else being equal?
Yeah. If you go back, we were in the 40 to 50 range net. If you can ever define normal there again, that's the kind of rate we were at.
Perfect. Appreciate it.
Thank you. Our final question is from Michael Hall of Heikkinen. Please go ahead.
Thanks very much. A lot of mine have been addressed, but I guess quickly on Surmont, following up on that from the prior question, do you have what that averaged during the third quarter in terms of contribution from Surmont?
In terms of the volumes?
Correct.
Yeah. 63,000 barrels a day was the 3 Q number from Surmont.
Okay. As you think about kind of maintenance capital levels for Canada coming out of the year after Surmont's effectively ramped up, how should we think about that? If you could provide it.
You're thinking about the maintenance CapEx, you mean?
Correct. Yeah.
Yeah. I mean, it's down to a pretty low level. Not sure I've got a number handy, but with the point that we've gotten to now, and particularly with some of the technology work we've been doing to improve things, the need to spend CapEx that are sustaining is down to a pretty low level. We're going to show you at our analyst meeting in a couple of weeks some other kind of margin improvement projects that we have planned there that are low-dollar. We'll show you kind of how that adds up. There is still some work to be done there at Surmont, given current market conditions on the diluent side, et cetera, to allow us to improve our margins there, and we'll talk about that a little bit in a couple of weeks.
Okay, great. As I think about, I guess, fourth quarter capital spending levels, is there anything kind of one-off or one-time within that spending level that we should not think about as recurring?
No. I'm not expecting any big lumps, like a dry hole expense or any of those kind of things in the fourth quarter. I can't think of any lumpy one-off type stuff.
Okay. That's helpful. Thanks so much.
Thanks, Michael. Christine, thank you very much. If you would close this out. We look forward to seeing everybody in a couple of weeks. Thanks for your time today.
Thank you. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.