Welcome to the first quarter 2018 ConocoPhillips earnings conference call. My name is Christine, 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. Good morning, everybody, welcome to our first quarter earnings call. Our speakers for today will be Don Wallette, our EVP of Finance, Commercial, and our Chief Financial Officer, Al Hirshberg, our EVP of Production, Drilling, and Projects. Our cautionary statement is shown on page two of today's presentation. We will make some forward-looking statements during today's call that refer to estimates or plans, of course, actual results could differ due to the factors that are described on this slide, as well as in our periodic SEC filings. We'll also refer to some non-GAAP financial measures today, that's for purposes of facilitating comparisons across periods and with our peers. Reconciliations to non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release again also on our website.
During this morning's Q&A, we're going to try to limit questions to one that's so we can get to all of our callers. If you have additional questions, obviously please feel free to jump back into the queue. Now I'm going to turn the call over to Don.
Thank you, Ellen. Good morning. I'll start on slide four. We've gotten off to a good start this year by demonstrating another quarter of strong execution. Starting on the left side of the chart with strategy, we again delivered on all our strategic priorities. We increased the quarterly dividend by 7.5%. We paid down $2.7 billion of debt, bringing our total debt to $17 billion at the end of the first quarter. As you know, at our AIM meeting in November, we set out a target to reduce debt to $15 billion before the end of 2019. Given the improved outlook for the business and our current cash balances, we intend to accelerate our debt reduction by an additional $2 billion this year, thus achieving our leverage target a year early.
This is consistent with our priorities, and we believe it sends another strong signal about our commitment to discipline. With respect to buybacks, we repurchased $500 million of shares this quarter, and we're on track for a total buyback of $2 billion in 2018. This is another return of capital to shareholders that was increased during the quarter, this time by 33% from the target announced in November. Since our buyback program began in late 2016, we've repurchased about 75 million shares or 6% of our share count at an average price of about $48 a share. One of our stated priorities is to return 20%-30% of operating cash flow to shareholders. This quarter, we again exceeded that, returning 34% of CFO to shareholders through dividends and buybacks. Strategically, we continue to hit on all priorities.
We're maintaining our discipline and following our game plan. Moving to our financial performance in the middle column, adjusted earnings were $1.1 billion for the quarter or $0.96 a share. We generated $2.5 billion of cash from operations excluding working capital, and that exceeded our capital spending by $1 billion. Free cash flow more than funded the dividend and share repurchases for the quarter. Finally, we ended the quarter with $5.5 billion of cash on hand. Moving to our operational results on the right, we've also had a strong start to the year. Production for the quarter, excluding Libya, was over 1.2 million BOE a day. Adjusting for dispositions, our underlying production grew 4% compared to the first quarter of last year and was up 26% on a per-debt adjusted share basis.
We announced the acquisitions of unconventional acreage in the Louisiana Austin Chalk play and the liquids-rich Montney, as well as the bolt-on acquisition of Anadarko's position in the Western North Slope of Alaska. We also completed an active and successful exploration program in Alaska. To recap, this quarter's performance again reinforces our commitment to keeping our discipline while delivering our plan. If you turn to slide five, I'll walk through the first quarter financial results. With WTI averaging about $63 a barrel and Henry Hub about $3 in MMBtu, our average realized price was around $50 a BOE. As you can see in the bar graph on the left, compared to the prior quarter, adjusted earnings improved almost $600 million due to higher commodity prices, lower depreciation expense, and reduced operating costs.
Compared to the year-ago quarter, adjusted earnings improved by over $1.3 billion, driven by a 40% improvement in realizations and about a 30% reduction in depreciation expense. The table on the bottom right shows a comparison of year-over-year adjusted earnings by segment for the first quarter. I would draw your attention to the Lower 48, where only two years ago, we had an earnings breakeven above $70 a barrel. We're seeing the earnings power of our unconventional engine driving the bottom-line results. With our Lower 48 earnings breakeven now at less than $45 a barrel. If you turn to slide six, I'll put the significant improvement in our earnings and cash flow expansion into perspective. The chart on the left illustrates the product mix shift in our portfolio since the first quarter of 2017.
Through strategic dispositions and targeted investments in high-margin production, we've increased our exposure to higher value products such as crude oil and international gas, including LNG. At the same time, we've significantly reduced our exposure to lower value products such as Canadian and U.S. natural gas and bitumen. The chart on the right shows that our improved earnings and cash flow are not driven by price increases alone. Here we show the improvement in realizations compared to the first quarter of 2017, from about $36 to $50 a BOE. The green boxes indicate how much of that realization gain came from product mix improvements and how much came from price increases. Over 40% came from mix improvement. Our product slate is now capturing over 75% of the Brent price, a further indication of how leveraged we are to rising Brent prices.
If you turn to slide seven, I'll wrap up with a look at our cash sources and uses during the quarter. First, looking at the sources of cash shown in green, the combination of cash from operations and dispositions was $2.7 billion. In red, we used $2.9 billion to retire debt, and we spent $1.5 billion of capital, which includes about $120 million for the Montney acreage acquisition in Canada. We paid $300 million of dividends and repurchased $500 million of shares, returning 34% of cash from operations back to shareholders in the first quarter. In the red box labeled Other, we included our bolt-on transaction in Alaska for $400 million, which will be moved to capital once we receive final regulatory approval.
As I said before, and it is worth emphasizing, this was all done while generating $1 billion of free cash flow in the quarter, which more than funded our dividend and repurchases. Again, a strong financial start to the year. I'll hand the call over to Al to cover operations.
Thanks, Don. I'll provide a brief overview of our first quarter operating highlights and our outlook for the rest of the year. Please turn to slide nine. Overall, as Don mentioned, production excluding Libya, averaged 1,224,000 barrels oil equivalent per day, beating the top end of our quarterly production guidance range. As you'll remember, our prior guidance reflected an assumption of a full quarter shut-in of KBB export production in Malaysia due to a third-party pipeline outage. Our production improvements were driven by the power of our diverse portfolio with contributions from the U.K., Alaska, and Indonesia. But the majority came from improved performance and completions timing in our Eagle Ford asset. We had a strong operational quarter in our Big Three unconventional assets. Production for the Eagle Ford was 163,000 barrels equivalent per day.
Bakken produced 68,000 barrels per day, and the Delaware produced 19,000 barrels per day. That adds to 250,000 barrels per day for the Big Three, representing a 20% increase in production year-on-year. In addition to the ongoing development operations in the Lower 48, during the first quarter, we announced the acquisition of early lifecycle unconventional acreage in the Austin Chalk of Central Louisiana. We're currently in the process of permitting exploration wells and expect to begin drilling in the position later this year. In Canada, we took steps to mitigate the impacts of the weak WCS differential in the first quarter by piloting the use of condensate as an alternate to synthetic crude diluent at Surmont. We're encouraged by the results so far and believe this unique capability will improve net backs and provide us a valuable diluent flexibility going forward.
In Canada, as Don mentioned, we announced our bolt-on in the liquids-rich Montney of 35,000 net acres, where we're currently appraising our position. During the quarter, we also made good progress on many conventional projects in Alaska, Asia Pacific, and Europe. I'll talk about those further on the next slide. In Alaska, we completed our exploration and appraisal drilling program after announcing the acquisition of Anadarko's acreage interest earlier in the quarter. We drilled six wells. Increased drilling efficiency allowed us to add an additional appraisal well to the original five-well exploration scope. This was our largest exploration program in Alaska since 2002, and a successful one. So far, we've tested four of the Willow discovery and appraisal wells, and the results are in line with our expectations. We confirmed that Willow has a recoverable resource potential of more than 300 million barrels.
We also drilled three exploration wells, West Willow, Putu, and Stony Hill, all of which were new discoveries, confirming that we have additional running room on the Western North Slope. I'll discuss the operations outlook as we move into the second quarter on slide 10. Our $5.5 billion capital guidance is unchanged. As you know, this excludes the capital for the previously announced Alaska bolt-on and the Montney acreage acquisitions. We continue to execute the $5.5 billion scope we outlined last November, and we're working to mitigate the pressures on our program from inflation, foreign exchange fluctuations, and increased partner-operated activity. For full year, we're increasing our production guidance to 1,200 to 1,240 thousand barrels per day to reflect our strong performance in the first quarter and adjusting for disposition assumptions. This increase comes despite now assuming that the KBB export volumes will be down for the entire year.
In other words, we're confident that due to the strong performance we're seeing around the world, and especially in the U.S., our diverse portfolio will more than offset the expected roughly 20,000 barrel a day production loss from KBB. Based on guidance, we expect to deliver 5% production growth, 7% production growth per share, and about 14% production growth per debt adjusted share. Although that latter number is based on ending the year at $17 billion of debt. Based on the $15 billion year-end debt number that Don mentioned earlier, our production growth per debt adjusted share would increase to about 16%. Our second quarter production guidance is 1,170 to 1,210 thousand barrels per day. This assumes our typical 2Q/3Q turnaround season in APME, Europe, and Alaska. In the Lower 48, we'll continue to deliver high-margin production growth in the Big Three throughout the remainder of the year.
We're confident in our Big Three growth plan. As I said on the last call, growth may be lumpy quarter to quarter, but we expect to exit the year at above 300,000 barrels equivalent per day from the Big Three. We're executing well on our Big Three unconventional programs, but we're also executing strongly in the conventional business as well. Before the end of 2018, we expect to achieve first production from several projects, including Bohai Phase 3 in China, Clair Ridge in the U.K., Aasta Hansteen in Norway, GMT 1 in Alaska, and the final phase of Bayu-Undan Development Drilling, which will continue feeding the Darwin LNG plant in Australia. We'll be continuing our appraisal work in the Montney and beginning our Central Louisiana Austin Chalk Appraisal Program. We'll also continue to gear up for our 2019 Alaska Winter Exploration and Appraisal Program.
We had a strong operational quarter, which translated to a strong financial quarter, where we executed our plans with capital discipline while generating $1 billion of free cash flow. I'll turn the call over for Q&A.
Thank you. Ladies and gentlemen, if you have a question, please press star then 1 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 1 on your phone now. Our first question is from Doug Leggate of Bank of America. Please go ahead.
Doug, thank you. Good afternoon, everybody. Al, I wonder if I could start on your CapEx comments that you just alluded to there, I guess. Obviously, inflation pressures have been talked about backwards and forwards, but I think the increase in third-party activity, I wonder if you could just give us a little bit more color as to what you're seeing there. Is this really more of a question of it's probably too early still to revisit the spending program? Is this more something you'd likely revisit, let's say, mid-year? If I can risk a third piece to that question, you're lining up a lot of opportunities longer term. How do you see, since the Analyst Day, your opportunity set impacting the CapEx outlook that you guided toward back in November? I've got a quick follow-up on buybacks, please.
Okay.
Oh, Doug, I don't know.
Let's see.
Just the CapEx question
Yeah, CapEx. Okay. Well, I think as I mentioned, we're still at our $5.5 billion CapEx guidance. We do see pressure, as I mentioned, in three different areas, inflation, Forex, and OBO. You asked specifically about the partner-operated side. We are seeing considerably above what we had expected of ballots from our partners in various areas, dominated in Lower 48. Of course, that will bring volumes with it as well. Although a lot of those volumes don't come till next year. For us, the choice when we receive those ballots is if it looks like economic work, which it typically does, we either have to elect in and spend that money or we get into a penalty situation, or we lose the rights to those reserves.
As that comes in, we're going to elect to do those, and that does put some upward pressure on the CapEx. We're continuing to work to offset those upward pressures with increased efficiencies. We're seeing significant increased efficiencies in our work. It's really too early to tell how all that's going to add up at the end of the day. With respect to scope going forward, we're still on the plan that we talked about in November at the Analyst & Investor Meeting, where we expect to average around this $5.5 billion over that three-year period that we laid out 2018, 2019, and 2020. There are some things on the horizon that potentially could be incremental opportunities for us down the road. You've heard us talk about the Qatar expansion. We're in the running for that and hoping to be able to win a piece of that business.
That was not in our plan that we showed you in November. Obviously that would be upside. If we're able to win that's something that investors are going to want us to invest in. You've also seen the exploration success in Alaska. That's another area where that wasn't reflected in our November plans that could be upside. These are not things that are going to affect 2018 and 2019 CapEx in a big way. It's 2020 and out beyond that.
I appreciate you indulging the question, Ellen. Thanks for not cutting them off. My follow-up is really a quick one. The buybacks, we all know what the cash flow outlook is, but you've still got your Cenovus shares, and now you've got this interesting situation last night that you announced on PDVSA. I'm just wondering if you could elaborate as to, maybe on the PDVSA piece specifically, what are your options there? Is that something that could ultimately result in another kind of step change in buybacks similar to the CVE shareholding that you still have? I'll leave it there. Thank you.
Well, Doug, this is Don. Yeah, on the PDVSA question, of course, that's a nice award from the ICC tribunal as a result of our arbitration, and we have another one coming later this year, probably from ICSID as well. We'll see what the total of all of that is. That's not something we're going to be able to book a receivable on anytime soon. I don't think that's going to require some enforcement action on our part, and we intend to be aggressive and persistent in that. It's something that's going to take time to recover the value that we lost when they expropriated our assets there. I think it's a little too early to start thinking about that in terms of uses of cash. You mentioned Cenovus as well.
Of course, we've got somewhere around $2 billion worth of Cenovus equity. Really, the story hasn't changed there. We're not a strategic investor, don't intend to be there for the long term. We're also not an anxious seller as well. We'll wait until we think that the value is right. Right now, we think the company is undervalued. Someday we'll be able to liquidate that and put that money to work elsewhere.
Thanks for indulging my questions, guys. I appreciate it. Thank you.
Thanks, Doug.
Thank you. Our next question is from Philip Gresh of J.P. Morgan. Please go ahead.
Yes. Hi, good morning. First question, just on, you talked about the balance sheet a bit with where prices are now, and it sounds like capital spending, you're looking to try to offset the inflation and maintain the capital spending budget. How do you think about the excess uses of cash, Don? Is there any chance you might put a bit more on the balance sheet just for a rainy day? Even, obviously, you've done a great job of buying the stock back at what now looks like great prices, but how do you think about that issue on a go forward?
Good questions, Phil. With our plan to accelerate the debt reduction and reach our target sometime this year, $15 billion. As you say, we're going to continue to constrain capital and work hard to live within our budget there. We've pretty much eliminated two pretty key uses of cash. The options are getting narrower. What we've said is, we just increased our buybacks, what, two months ago from $1.5 billion to $2 billion. We increased our dividends a couple of months ago, 7.5%. I can't steer you one way or the other today on that. We've said that our distributions to shareholders will continue to grow as our cash flow grows.
I guess-
What was the second part of your question again, Phil? On the stock price and the buybacks?
Yes, exactly.
Well, I tell you what, some of the key factors that we take a look at, obviously, the CAGRs on our production growth on a debt-adjusted share basis. If you look at our cash flow, cash margin expansions in this sort of environment, we think our stock is well undervalued and has a lot of upside to it.
Okay, fair enough. Thanks. I'll turn it over.
Thanks, Phil.
Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead.
Good morning, guys. The first question I had was around APLNG. Am I right to say in the first quarter, in the cash flow, that there was no dividend recorded from APLNG and that came in in April? If so, can you quantify what the cash flow associated with that dividend was?
Yes, Neil, that's correct. We did not receive a dividend in the first quarter from APLNG, that's not reflected in the cash flows for the quarter. A dividend was declared in the first quarter, it was paid in April this month. We did receive a dividend from APLNG, the amount was $105 million to ConocoPhillips.
That's great. The follow-up question is just the Big Three production profile for the balance of the year. Can you just talk about where do you see it going from here, and a little bit by basin as well? Thank you.
Okay. I talked earlier in the prepared remarks about the Big Three hitting 250. That was up 6% quarter-to-quarter and 20% year-over-year, first quarter of 2018 versus first quarter of 2017. I frankly don't expect you to be too impressed by that 20% number. We said in November we were going to grow the Big T hree 22%, we keep improving all the time, the latest well results we've seen have been very impressive. I certainly expect our operating teams to beat that 22%. I'm going to expect you to be impressed with 20, I expect it to be better as we go forward in the year. I think that it will be lumpy, as I said. Some of the lumpiness smoothed out a little bit.
We had some Eagle Ford completions that we thought we wouldn't get till the second quarter that sneaked their way into the first quarter. I think you will see strong numbers as we go through the year. Just to put a finer point on that, if I can say it without Ellen kicking me under the table, maybe. Last call, you may remember I said I thought we'd have an exit rate that would be above 300 for the Big Three. I think if you look at the latest well performance and how things are going for us, it's clear to me now that that 300 that I was kind of calling an exit rate at the last call is going to happen quite a bit earlier in the year.
Great. Congrats on a good quarter, guys.
Thanks, Neil.
Thank you. Our next question is from John Herrlin of Societe Generale. Please go ahead.
Yeah. Hi, just some quick upstream ones for Al. With Alaska, given the success that you've had, what kind of cycle time should we expect in terms of you actually bringing on incremental production on the North Slope? Also with the Austin Chalk, when will you start talking about that? Will that be third quarter or fourth quarter?
Yeah. On Alaska, of course, we have a pretty nice pipeline of projects, mid-size sort of projects we're bringing on. GMT1 is the one we expect to start up by the end of this year, GMT2 will be next. We hope to take FID on next year. That would start up in sort of the 2021 timeframe. We've got production still coming up at CD5 and at 1H NEWS. A lot of different projects that are in the pipeline there. In terms of the new discoveries, which I think is what you're really asking about.
Yes, I am.
Willow. Yeah. Also Putu and Stony Hill. What I said about a year ago on this call when we first announced the Willow discovery was that in the best case scenario where we got all our approvals, particularly the federal approvals that have been difficult to get in the past timely, the earliest we could start up would be 2023. I think that's still the case, but that's a bit of a theoretical timing that would require more rapid federal permitting than we've experienced in the past. That is possible within the rules. You should sort of think of that as an earliest timeframe, I think, for Willow. One of the questions we've had is Willow going to be a tieback or is it going to justify a standalone facility?
That's part of what we're after in this appraisal program, is making sure we understand the subsurface well enough to make the right decision for what's the highest value. I think we can see from the appraisal work in Willow that it's looking more and more like it'll be able to justify a standalone facility. Then you can have things like West Willow, which is our new discovery further out to the west, tying back to that. That's not a decision we've taken yet, but certainly the appraisal program strength points us in that direction.
Okay. Then what about talking about the Chalk? When will you-
Yeah. On the Austin Chalk position, we're up to I think it's about 211,000 acres now across a pretty wide area. We're in the process of permitting the first exploration wells, which we'll be able to spud depending on the permit timing later this year. Might be late third quarter, early fourth quarter, somewhere in that timeframe. I expect it'll be into 2019 by the time we actually have results from that program that we'll be able to start to characterize what we think we have there.
Okay, great. Thanks, Al.
Thank you. Our next question is from Doug Terreson of Evercore ISI. Please go ahead.
Good morning, everybody. Congratulations on your strong results.
Thanks, Doug.
Thanks, Doug.
Yep. During the quarter, your like-for-like production grew by 4% year-over-year, even with the outage that you guys talked about in Malaysia. I wanted to see if you could comment on the driver of the gains and also the resiliency that you're seeing in the portfolio outside of the Big Three, meaning in areas such as Alaska or Indonesia or really any of the other areas that seem to be exceeding expectations. It certainly appears to be fairly resilient in many areas.
Okay, sure. I think it's a particularly good question. A lot of the outperformance we're seeing in the first quarter is part of what's given us the confidence to increase our full-year number. We were 24,000 barrels a day above the midpoint of the range we had given in the first quarter. That was, you're correct, about 4% growth versus that quarter in the prior year. Of course, that's with the loss of 2% from KBB, it would've been six if we'd had that. If you look at where that +24 comes from, about 11 of it was from the Lower 48, as you kind of alluded to. We did have strength in a number of other areas.
We continue to outperform with the base in Europe and in both the U.K. and Norway, as we were about a +7 to expectation from better uptime and better base performance in Europe. You've heard me talk about before, in Alaska, our project and our well performance has been strong there. We got about three more than we expected. In Indonesia, we had higher demand for our gas because of some third-party coal-fired power plants that had unplanned downtime. We picked up a +3 there. We also had better uptime in Qatar and got about +3 there. The only real negative we had in the quarter was at Surmont. We were about two short of where we had expected at Surmont, really due to diluent supply shortages and other market factors. You add all that up, that's the +24 or so.
Okay. Also for Don, on Venezuela, your point's taken on recoverability from PDVSA given the circumstances. While we're on this topic, I wanted to see if you could give us somewhat of a status update there, damages you're seeking, and the next steps for the ICSID proceeding, which I think you alluded to is going to have a next step later in the year. Could you just kind of remind us where we are with that proceeding?
Yeah. Maybe just give you a brief recap as well, because it is kind of complex because we have multiple proceedings going on there. Of course, the one concluded yesterday with ICC. The important thing about the ICC award that was about $2 billion, of course, that doesn't come anywhere close to compensating us for our full losses of value in Venezuela, but it never was expected to. I'll try to explain that a little bit. That was a contractual matter between ourselves and PDVSA that had to do with the indemnity that they provided to us for discriminatory actions that the Venezuelans took when they expropriated our assets.
The limitation on that indemnity was spelled out in the contract in a formula, basically, and that formula had caps on it. We knew that that award was always going to be capped and really only would represent a partial compensation for our total losses. Now we move to the other claim that we have, which is not against PDVSA but against the government of Venezuela.
Right.
That's the one that's being heard at ICSID. That process, there is no cap involved in there, and we expect that that result, which we hope to receive notice of an award later this year, that that will represent a full compensation for our value loss.
Right. Okay, great. Thanks a lot, guys.
Thanks, Doug.
Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead.
Hey, guys. Good morning.
Hey, Paul.
Good morning, Paul.
For Don, a quick two, one. First is for Don, a quick one. For the APLNG, the $105 million that you're going to receive in the first quarter, is that represent the full cash flow in excess of the internal usage, such as the project financing and also the payback of the project financing and also the CapEx? Or that you actually, even with that, you're already building cash?
You did mention first quarter. That was received actually in the second quarter, Paul.
Right. Understood
I just wanted to correct that.
I'm just saying that if we're looking at a $67 Brent, if that means that the APLNG, if you assume that you already feel comfortable for the joint venture cash balance going forward, is that $105 million is a reasonable estimate or that that should actually be a higher number?
I have a hard time saying whether that's a reasonable estimate. It all depends on what the price is and what the net cash flow within the joint venture is. We can just say that it was $105 in April. I can tell you that we are.
Let me ask in another way, Don. If you take our $105 million from the cash balance by the end of the first quarter, is that balance higher than year end with year end the joint venture?
That was the available cash. That represents the cash that was available to be distributed.
Okay. All right. Maybe I will take it off now. The second one, Al, for the Surmont. Any takeaway issue because of the problem over there that need you to change the way that how you operate?
We don't have a takeaway issue per se, in terms of being able to move our barrels to market. The takeaway issue is really the constraints that have been in place for a number of months now that have widened out the WCS differential and really hurt our netbacks. Our netbacks were doing pretty well. We had some pretty decent cash margins at Surmont in the second half of last year. As there were a few operational issues that other folks had on pipelines, it did create some backup. One of the things I also mentioned that we've been using synthetic crude oil as our diluent. That's how the plant was set up, and there'd been some supply issues there, a number of repeating supply issues over the past year and a half.
We're moving forward to make what are really some fairly minor facilities changes there that will allow us, by the third quarter of 2019, to be able to run any mix of condensate or synthetic crude oil that we want to as diluent. We can create a dilbit by running all condensate, we can create a synbit by running all synthetic crude oil, or we can create a syndilbit by running a mix. We're in a process of piloting those sorts of things now. As we look back at the volatility of the various factors involved here in the market, we think having the flexibility to go back and forth is going to be a really valuable and unique attribute to the Surmont plant.
Al, do you guys have any committed pipeline volume at the existing pipeline from Alberta down to the Gulf Coast? Or that you are selling all those that in the local market?
Let me tell you what our current situation there on the marketing side is, Paul. We're currently on a blend basis. We're at, like, 150,000 barrels a day of Surmont blend that we're moving to market. Probably on a rough cut basis, the best way to think about that is we have probably around 100,000 of that 150,000 is going into the local Edmonton trade market. We've got about 25,000 barrels going to the U.S. by rail. That would be into Cushing and some into the Gulf Coast as well. We have the balance of that 25,000 barrels a day is on pipe being exported into the U.S., into the Midwest, and the Gulf Coast.
Okay, perfect. Thank you.
Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.
Yeah, good morning.
Hello.
Nice quarter there. Al, you've been talking and bragging about the 250, which certainly is good. We did hear a lot about weather in the quarter as restricting some of the production. I was just curious, was your 250 affected by that somewhat? Which means your sort of higher growth rate is more achievable as the year goes along, or are we looking at that as a pretty clean number?
Yeah, we were impacted by weather. We don't like to whine about weather. We were hit about 14,000 barrels a day back in January in a number of our different areas. Divide by three to get a sort of four or five-ish impact on the quarter. Not too big, but we were able to more than offset that with our performance, and so we don't really need it in the math.
No, I appreciate that. Just trying to get a feel for the exit rate versus maybe the average there.
Look for the timing on that 300. That is going to be the interesting thing.
All right. Appreciate that. We will be watching it. My second question is, you looked at the decision to make the acquisitions both in the Montney and Louisiana. You are talking about the CapEx pressures elsewhere. Help us to understand maybe what the return thought process is there of moving into, I do not want to call them frontier-ish, but I mean, certainly not frontline opportunities for production growth and cash flow. You have got the share repo, you have got your other undeveloped reserves, you are making some additional acquisitions. I am just curious how that all flowed together.
Yeah. Well, you could think about it from a number of different perspectives. I mean, for one thing, the money that we spent on some of these bolt-on type opportunities, including in the Western North Slope, really was funded by our Ecuador legal settlement, $337 million of cash that came in. Plus, in the last few quarters, we have had about $250 million of cash come in from the smaller asset sales we have been doing. That $600 million or so has largely funded some of the smaller bolt-on kind of things we have been doing. Of course, the bolt-on in Alaska is once we get the regulatory approval, that is immediate. These other things you are asking about, remember, these are sort of $1,000 an acre or less kind of longer-term things that are for the 2020s.
They're not going to bring us volumes this decade, but they're not costing us much money right now. They fit within, they're a part of our natural exploration budget. They'll displace other things in the exploration budget that we had already laid out that was part of our math during the Analyst Meeting in November. They are an opportunity to be very competitive, total cycle, full cycle cost of supply with the other things that are in our resource base. That's why we like them.
Okay, great. Thanks. If I could sneak one in just to follow Paul on the APLNG on his dividend question. The run rate that generated that was based on what crude price, and then how should we think about the fact the crude price has moved up certainly from Q4, Q1 to now, how that flows through into maybe the expectation for dividend payments?
Well, the $105 million was based on the crude prices that they recognized during the first quarter, but also the beginning cash balances as they entered into the year. They had been building some cash up, not a great amount, during the fourth quarter. I think one thing you have to factor if you're trying to forecast this precisely is that there is, on the LNG sales into Asia, there's always the three-month lag, so you've got to lag your prices on that.
I think another factor maybe that may be causing some difficulty here is the lumpiness of the loan payments. We don't have a loan payment every quarter.
It's twice a year.
Twice a year. We build up cash to make the next loan payment. It's maybe not as ratable as-
No, that's right
people are thinking.
Thank you. Our next question is from Blake Fernandez of Scotiabank Howard Weil. Please go ahead.
Thanks. Good morning. Don, I was hoping to go back to Phil's question on uses of cash flow. I just wanted to kind of confirm, is the $15 billion debt target subject to being revisited, or is that pretty much a hard number and we can just think once that's accomplished, the rest is just going to simply be distributed?
That's a hard number.
Okay. The second piece, Al, you kind of talked quite a bit about the Canadian discounts and takeaway capacity, et cetera. I'm also curious, obviously this past quarter, we've seen a lot of discounts in the Permian crude differentials, and I was hoping you could talk a little bit about what kind of takeaway capacity you have there. How exposed are you to the actual Midland pricing as opposed to getting that down to the coast and realizing something more like LLS?
Maybe I can talk about that a little bit. Right now, we don't have any significant export capacity out of the basin in the Permian, so we're fully exposed to the Midland Cushing differential. Of course, in the first quarter, the realizations in the Permian were actually quite high. I think we got around 98% of WTI. We're going to see the impacts of that, it looks like, in the second quarter. Now looking longer term, a number of the midstream companies are entertaining open seasons on long-haul transport into the Gulf Coast, and we are active in that. That sort of shipping capacity wouldn't be available until the second half of 2019 at the earliest.
Got it. Okay. Thank you very much.
Thanks, Blake.
Thank you. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead.
Great. Thanks. Maybe an asset-specific one in the Eagle Ford. You've talked around the issue on how your performance seems to be exceeding expectations there. Can you give any additional color on what you're seeing today in the Eagle Ford versus original expectations? Is it better per well productivity, drilling efficiencies? Any thoughts on cost there? Then I've got one asset-related follow-up.
Well, it's yes, and yes. By the way, you win the prize for best title this morning on your note.
Thank you.
I think in the Eagle Ford we are seeing better per well performance with our latest generation of completion design, and we have a new generation that we're getting ready to test next that may give us yet even better results. You can go into the public databases and just look at the last four years and look at the different vintages of wells, and you'll see the pretty dramatic improvements that we've had. We also are continuing to drive down our costs. We're getting quicker drilling times per well, lower well costs, and also continuing to optimize our completion costs. Data analytics is a very powerful force in the Eagle Ford. That was really the first place in the company where we built a comprehensive data warehouse.
I think in the last few years, we've doubled the number of wells that can be handled by each multi-skilled operator out in the field because of all the tools that we've given them. We've been able to drive our lifting costs there down well below $2 a barrel. It is very efficient. We get great margins out of the Eagle Ford. It is not just a matter of the volumes. We've had improving margins. While everyone else has been banging away in the Permian. A lot of people left the Eagle Ford to do that, and there's just been less competition for goods and services in the Eagle Ford and better net backs because there've been less people trying to jam their barrels down the same takeaway capacity. Everything about the Eagle Ford is really hitting on all cylinders for us.
I think that continues to be a real bright spot for us. I think we are going to see really good volumes out of the Eagle Ford this year, but there's a lot more to the story than that.
Great. Thanks. That's helpful. Maybe on Darwin LNG, I think, based on your partner's comments, you've seen a recent peak in terms of LNG production there. It seems like there's moving closer to a potential FID, the Barossa backfill option. Any thoughts on what you see as potential timeline there? General thoughts on the asset going forward and maybe insights on potential LNG contracting there?
Sure. The Darwin LNG plant is a great asset. It is a jewel for us that has performed great. We've been able to increase the capacity of that plant significantly over the years since we built it, and it's really performed well. We want to keep it full. I've seen some things in the press where they've said that ConocoPhillips has been accelerating Barossa or moving faster. That's really not the case. We've been on the same schedule for several years. It's been apparent to us when Bayu-Undan is going to run out of gas, and it coincides with when the PSC expires as well, and also when our current LNG sales contracts expire. All that happens in 2023. We've known for a long time we've got to have something else ready to flow gas to Darwin in 2023.
I mentioned in my prepared remarks that we just spud a few weeks ago. We're in the last phase of development drilling at Bayu-Undan. This will be the last handful of wells that allow us to drain all the gas from Bayu-Undan by 2023. Then Barossa has been on a steady schedule. I said on the last call that I thought by this call we'd be at or near entering FEED, and that did happen, as you saw in the news earlier this week. We're right on schedule there. We expect to take FID in late 2019, if everything continues to move down the tracks. We've already gotten our regulatory approval from NOPSEMA, that's a difficult thing to get. We've got that in hand. We had unanimous vote from the partners this week to move forward into FEED on all the different pieces.
I think everything's working well there. We are very focused on this project on capital efficiency. Everything we're doing in the way the FEED is set up, including a design competition for the FPSO, is all designed to really drive forward capital efficiency on that project.
Thank you.
Thank you. Our next question is from Guy Baber of Simmons & Company. Please go ahead.
Thanks very much for taking the question. In light of the fact that you guys did not receive a dividend from APLNG, the cash generation this quarter seemed especially strong relative to the sensitivities. I'm wondering if your simplified cash flow sensitivities actually are conservative now because of some of the margin enhancements you all have highlighted, and because we're now north of $65 a barrel Brent, which was the upper end of the band of the sensitivities, I think, that you provided. Just as one example, it seems that your Lower 48 realizations in particular are really strong relative to WTI and Brent and have improved quite a bit, perhaps due to Eagle Ford, as you mentioned. Anything more specific you would call out on those Lower 48 realizations or in the Eagle Ford specifically?
No, I think, Guy, just overall, since we introduced those cash flow sensitivities back in, I think it was November 2016, we've been tracking, what, seven or eight quarters, six or seven quarters maybe, and they've really done well. They've been very precise in their predictive capacity, I would say. Even in the first quarter, they also came pretty close to what our actual cash flow ex working capital was. Maybe for some of the wrong reasons, because we had the low realizations in Canada, then we had stronger realizations in the Lower 48. I think you're right. The cash flow generating ability of the company may be understated somewhat by the sensitivities that we updated just this past November.
We are looking at it, as you say, we are at the upper end of the range price-wise of what we've said those sensitivities are good for. We did take a look at it here in the last couple of weeks, and we think it's still okay. We're going to continue monitoring it, if we feel like it no longer has its predictive capability, we will provide new guidance.
Thanks very much.
Thanks, Guy.
Thank you. Our next question is from Mike Hall of Heikkinen. Please go ahead.
Hi. Good morning.
Morning.
I guess first I wanted to just ask on the KBB pipe to get into a little more detail on what exactly is creating the delays on bringing that back on. Are there any issues with the metallurgy there? What sort of costs might be associated with repair and/or replacement of the pipe, and is that all factored into CapEx at the moment?
Yeah. The KBB pipe, there's no issue around metallurgy. We have no ownership in the pipe, there's no impact on cost to us. It's just strictly a third-party arrangement. Really, the cost is not a factor for us. They had a weld failure that was really caused by a mudslide. This is a remote area with some pretty difficult terrain and heavy rains, the earth moved and caused excess strain on the pipe. The problem is, it's a very difficult area for them to get to. There's a number of these potential mudslide areas, they have a very comprehensive plan of repair for the pipeline. We don't really know when the pipeline's going to be up, we're not really in the middle of it because we have no ownership.
We're just assuming at this point it'll be down for the whole year. We don't really know that for sure.
Okay. Appreciate clearing that up. I was just curious as a follow-up on the Permian. Noted, obviously, things are looking tough on the differentials front on the forwards. If things get bad enough in the Permian, from a price realization standpoint, starts to weigh on valuations in the basin, is that an area you guys would consider being opportunistic in on a longer data basis? Or is that not really on the agenda?
Yeah. We never say never. We're always looking at everything. I don't really see that. You look at the pricing on recent things that have happened, on a full-cycle basis, we struggle to see how that would compete in our existing portfolio. We've showed you the cost of supply of our existing portfolio, you just do the math on the prices being paid, it's hard to see how that works. Things could change. You never know.
Thank you. Our last question is from Pavel Molchanov of Raymond James. Please go ahead.
Thanks for squeezing me in. Just one more question about the Permian from a gas perspective. Obviously, a lot of conversation about constraints in gas takeaway capacity and the possibility of flaring later this year or next year. Are you experiencing any pressures of that sort in terms of your gas volumes in the Delaware?
No, we're really not, we don't expect to either. ConocoPhillips is one of the largest gas marketers in the United States, and the U.S. Southwest, including the Permian area all the way out to the SoCal border, is an area that we're very large and very active. We transport a lot of third-party gas out of that basin and across the U.S. We have plenty of capacity available for our equity gas. If we ever got in a bind, we can back out third-party gas.
Thank you. I will now turn the call back over to Ellen DeSanctis, VP, Investor Relations and Communications, for closing remarks.
Thank you, everybody. Thank you, Christine. I appreciate it. Obviously, if we left any questions unanswered, feel free to call us anytime over the next day or so. Appreciate your interest, everyone. Thanks.
Thank you.
Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.