Welcome to the ConocoPhillips first quarter 2015 earnings conference call. My name is Adrienne, and I'll be your operator for today's call. At this time, all participants are in a listen only mode. Later, we'll conduct a question and answer session. Please note this conference is being recorded. I'll now turn the call over to Ellen DeSantis, VP of Investor Relations and Communications, ConocoPhillips. Please go ahead.
Thanks, Adrienne. Welcome to all of our call participants today. I'm joined this morning by Jeff Sheets, our EVP of Finance and our Chief Financial Officer, and Matt Fox, our EVP of Exploration and Production. On this morning's call, Jeff will cover the first quarter financial results, as well as our guidance items for the rest of the year. Matt will review the operational highlights for both the quarter and the rest of the year upcoming. During Q&A, please, we'd ask that you limit your questions to one plus a follow-up. Page two contains our safe harbor statement. We'll make some forward-looking statements this morning. As always, we'd ask you to refer to our periodic filings with the SEC for a description of the risks and uncertainties in our future performance. Again, thank you for participating. Now I'll turn the call over to Jeff.
Thanks, Ellen. Hello, everyone. Thanks for joining us today. As you know, we recently held our 2015 analyst and investor meeting in New York, where we launched our new three-year operating plan and provided details on our long-term growth opportunities from our large, low cost of supply resource base. We outlined our capital and production plans for the next few years and how we would achieve cash flow neutrality in 2017 at a range of commodity prices. We also reaffirmed our commitment to a compelling dividend. In the first quarter results we will discuss this morning, we're going to describe a quarter with strong production growth and good cost control, one where weak commodity prices overshadowed strong operational performance. If you'll turn to slide four, I'll cover our key highlights for the first quarter.
We produced 1.61 million BOE per day, which is growth of 5% compared to the same period last year, adjusted for Libya dispositions and downtime. We achieved first production at Ekofisk II, Bayu-Undan Phase 3, and the Brodgar H3 subsea tieback. We also advanced five major projects towards startup by the end of the year, and that includes our two mega projects at Surmont 2 and APLNG. Financially, our earnings were materially impacted by low prices. We had a $222 million loss, or $0.18 a share, after adjusting out special items. We generated $2.1 billion in cash from operations, excluding impacts from working capital, and ended the quarter with $2.7 billion in cash. Costs are a big focus this year. At our analyst and investor meeting, we announced the goal to reduce operating costs by $1 billion in 2016 versus 2014. We're already moving the needle.
We've made significant progress on capturing deflationary benefits on our capital program, which we also outlined at our analyst meeting. Strategically, we announced our new three-year operating plan that provides predictable growth for about $11.5 billion of capital per year. We're making good progress on implementing that plan this year, as we ramp down activity across the portfolio. We still grow high margin volumes at this CapEx level, and in 2015, we plan to deliver production growth from continuing operations without Libya of 2%-3% compared to 2014. I'll turn to slide five for more of a discussion on our earnings. Production came in at the high end of guidance. We also saw improvement in our operating costs, which, as we discussed at the analyst meeting, includes production and operating costs, SG&A, and exploration expenses, excluding dry holes and leasehold impairment.
Those costs improved 7% compared to the first quarter last year. When you adjust out the restructuring charges, which were a special item for the quarter, you see a 12% improvement in our costs. However, sharply lower prices overwhelmed that performance. Realized prices were down 30% compared to last quarter and down 48% compared to the first quarter of 2014. That contributed to the first quarter adjusted loss of $222 million or the $0.18 a share. First quarter segment adjusted earnings are shown in the lower right side of this chart. The financial details for each segment can be found in the supplemental data on our website. Segment earnings are roughly in line with our sensitivities, except for the Lower 48, where adjusted earnings were differentially impacted by lower realizations, both in absolute terms and relative to markers.
This impact wasn't just from crude, but also from NGLs and natural gas. Lower 48 earnings also reflected the previously announced dry hole expense from Harrier. The other international segment adjusted earnings were driven by the Omosi-1 dry hole in Angola. If you'll turn to slide six, I'll summarize our production results for the quarter. Our projections slide follows our usual convention of continuing operations excluding Libya. Our first quarter production averaged 1.61 million BOE per day, compared to 1.53 million BOE per day in the first quarter of 2014. The waterfall shows downtime and dispositions were essentially flat year-over-year. That leaves net growth of 82,000 BOE per day, or 5% growth compared to last year. Of the 82, 61 of the improvement comes from liquids. That's mostly from oil sands in Canada, unconventionals in the Lower 48, and Gumusut in Malaysia.
Gas is up 21, and some of that's from domestic gas sales at APLNG. That'll turn to LNG over time. If you turn to the next slide, I'll review our cash flow waterfall. We started the year with $5.1 billion in cash. During the quarter, we generated $2.1 billion from operating activities. This reflects an environment where Brent was at $54, WTI was at $48.50, and as you know, current prices in the strip are higher than these numbers. Moving through the chart, we saw a negative impact of about $300 million from working capital. For the quarter, we spent $3.3 billion in capital expenditures and investments. As you would expect, capital is front-end loaded and tapers off through the year as we complete our major projects and ramp down our activity in unconventionals. That number is not ratable.
After paying our dividend, we ended the quarter with $2.7 billion of cash on the balance sheet. Before I leave this slide, let me mention an item that you'll notice on the cash flow statement in our supplemental information regarding deferred taxes. In the quarter, we had a $555 million benefit to earnings as a result of a change in tax laws in the U.K. This is a special item and not included in our adjusted earnings. This income benefit did not create an immediate cash flow benefit. On the cash flow statement, the income benefit is reversed out on the deferred tax line, which is why the deferred tax line on the cash flow statement shows a large negative this quarter. Without this tax law change, deferred taxes would have been about an $85 million use of cash in the quarter.
I'll wrap up my comments on the next slide with some guidance for the rest of the year. We provided guidance at our analyst and investor meeting earlier this month. We're not making any changes to the guidance, I do want to walk through some of the trends and profiles as we go through the year, since most of our first quarter metrics aren't ratable. We remain on track to achieve our 2%-3% production growth this year. Our second quarter production guidance is 1.555 million-1.595 million BOE per day. This reduction from our first quarter mostly reflects the start of our seasonal major turnaround activity. As I just mentioned, we expect capital to decrease throughout the year, and we remain on track for $11.5 billion of capital this year. Our operating cost guidance of $9.2 billion remains unchanged.
We did better on a run rate basis in the first quarter, as we continue to work on lowering costs. We could see further improvement in our cost guidance for the year, especially if the U.S. dollar stays strong, we're holding to the current guideline for now. We expect costs to be higher in the second and third quarters as we go into heavy turnaround season. We'll also see some higher costs in the fourth quarter associated with our major project startup. There's no change to our exploration dry hole and impairment guidance of $800 million for the year. We were higher than that rate in this quarter, and we'll keep you updated throughout the year. DD&A looked a little low on run rate, we expect to end the year at about $9 billion. This reflects mix shift changes and major projects coming online through the year.
Finally, our corporate segment is in line with guidance. That concludes the review of our financial performance and guidance. The theme you should be hearing is that we're focused on executing a prudent plan, and we're delivering on our operational commitments. Now I'll turn the call over to Matt for an update on our operations.
Thanks, Jeff. Good morning, everyone. To begin, I'll quickly go through our segment results for the quarter and then conclude with a preview of some key activities to look out for in 2015. As Jeff mentioned, we had a strong quarter operationally, achieving the high end of our production guidance, and we did that while reducing capital and operating costs and maintaining a relentless focus on safety. Let's jump into a review of the segment performance, starting with the Lower 48 and Canada on slide 10. In the Lower 48, first quarter production averaged 542,000 BOE per day. That's a 7% overall increase from the first quarter of last year and represents a 16% increase in crude oil production. Production grew in the unconventionals. As we have previously announced, growth will begin to slow as we see the impact of reducing the number of rigs in operation.
Overall, in Lower 48, we had 15 operated rigs running at the end of April, which is more than a 50% reduction from the end of 2014. As a result of fewer rigs, we expect production growth to slow in the second quarter and begin a slight decline in the second half of the year. At our recent analyst and investor meeting, we gave you a lot of detail on pilot tests, and we're continuing to run those tests across the segment. In addition to our unconventional activities in the Lower 48, exploration and appraisal activity continues in the Deep Water Gulf of Mexico. We currently have appraisal wells drilling at Gila and Tiber, and unfortunately Harrier was a dry hole. Next, I'll cover Canada. We saw strong growth from our Canadian business segment during the quarter. We produced 318,000 BOE per day, a 14% year-over-year increase.
This growth came primarily from our oil sands assets, with bitumen production increasing 26% compared to the first quarter of 2014. In Western Canada, we successfully completed our winter drilling program, with activity focused primarily in the Clearwater, Clair and Montney areas. This activity will reduce as we ramp down our rigs from a high of 10 in the quarter to two for the remainder of the year. In the oil sands, we're seeing strong performance from Christina Lake and Foster Creek, with production continuing to ramp up at Foster Creek Phase F. At Surmont 2, construction is more than 93% complete, and final preparations are underway in anticipation of first steam by the middle of the year. Next, I'll cover off our Alaska and Europe segments on slide 11. Alaska's average production was 186,000 BOE per day, and activity this quarter was focused on several major projects.
CD5, a new development on the west side of Alpine, is more than 75% complete. Drilling has already commenced, and we're moving ahead with pipeline and module installation. At Kuparuk Drill Site 2S, facility construction is on schedule, and drilling will commence in the second quarter. Both CD5 and 2S are on schedule for startup in the fourth quarter of this year. We sanctioned the first phase of the Northeast West Sak development, the 1H NEWS project in Kuparuk in March, and we expect to see first production in 2017. In addition to progress on these projects, we've resumed operations at the Kenai LNG plant, with exports expected to recommence in May. Moving on to Europe, first quarter production averaged 209,000 BOE per day. We saw two startups this quarter at Eldfisk II and Brodgar.
Eldfisk II production will continue to ramp through the year as we bring additional wells online, the Brodgar H3 subsea tieback well achieved first gas in March. Enoch 2 is also progressing on schedule and should start in the third quarter. Let's review our Asia Pacific and Middle East segments and other international segment on slide 12. In APME, we produced 351,000 BOE per day in the first quarter. This is a 10% increase compared to the first quarter of last year, primarily as a result of new production from major project startups at Gumusut and SNP in Malaysia. The Gumusut floating production system is continuing to ramp up, with full field production currently exceeding 150,000 BOE per day on a gross basis. At KBB, production remains constrained, awaiting third-party pipeline repairs.
We achieved first gas from our Bayu-Undan Phase 3 program in March, production is continuing to ramp up. The APLNG project was more than 90% complete at the end of March. We achieved first fire from one of our gas turbine generators in April, we're progressing towards startup in the third quarter. In our other international segment, we're continuing to focus on our exploration and appraisal programs. In Angola, we spudded the Vale well this month, we'll update you on our progress there next quarter. We announced a dry hole at Omosi, where we encountered a gas column and subsequently plugged the well. In Senegal, planning continues for an appraisal program in the fourth quarter. In Libya, our production remains shut in due to ongoing unrest, it remains out of our production guidance for the year.
I'll wrap up my prepared remarks on slide 13 with some key activities to watch in 2015. As Jeff mentioned, we're on track to deliver 2%-3% production growth this year. For the second quarter, we expect to produce 1.555 million-1.595 million BOE per day. The key driver is the typical turnaround activity that you see on the upper right chart. Our major turnaround activity for the year is scheduled in Alaska, Europe, and APME in the second and third quarters. These large turnarounds start in June, we'll see an impact on production in the second quarter, with a more significant impact in the third quarter. In the Lower 48, we expect production to begin to decline in the second half of the year, reflecting our reduced rig count.
As I just mentioned, we ended April with 15 rigs, we expect to run 12 rigs through the second half of the year. Moving to major projects, with five startups expected before the end of the year at Surmont 2, APLNG, Enoch 2, CD5, and Drill Site 2S. Production from these five projects will be minimal in 2015 but will provide momentum going into 2016. We also have exploration and appraisal activity underway. As I said earlier, we spudded the Vale well in Angola this month. We plan to start drilling the Vernaccia and Melmar wells in the Gulf of Mexico in the second and fourth quarters, respectively. We expect to spud the Cheshire well and Nova Scotia in the fourth quarter.
In Senegal, we plan to start appraisal work before the end of the year, and we'll continue to appraise our existing discoveries in the Gulf of Mexico. Non-GAAP measures. We gave you a lot of information at the recent analyst and investor meeting, there's not a lot new to add. We are paying close attention to the things we can control by safely executing our operating plan, capturing capital and operating cost improvements, and creating value for shareholders. This ends our prepared remarks. Now I'll turn the call back to the operator for Q&A.
Thank you. We'll now begin the question and answer session. If you have a question, please press star then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you're 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 touchtone phone. We have Douglas Terreson from Evercore ISI online with a question. Please go ahead.
Good morning, everybody.
Good morning, Doug.
A key element of the path to cash flow neutrality that you guys talked about at the analyst meeting for the next few years is the shift in spending away from the capital-intensive projects in the oil sands and also in LNG and towards unconventionals. On this point, I wanted to see if we could get an update on when you expect Surmont and APLNG to commence operations, and therefore, for spending to be significantly curtailed. Second, is a $2 billion reduction in spending, which is about 20% of the budget, a reasonable order of magnitude type reduction for these two projects, or is that too high? If we could just get some color on what to expect on capital spending declines.
Doug, on Surmont 2, we expect to have first steam sometime relatively soon, certainly by the middle of the year. APLNG, we expect to start up there in the third quarter. It's pretty much in line still with what we discussed at analyst day and what we've been expecting for some time. As we move from 2015 into 2016, we'll see about a $2 billion reduction in capital associated with those projects. That won't be seen from startup immediately because we'll still have capital being spent on both of those projects through the end of the year. Between 2015 and 2016, it's about a $2 billion reduction.
Okay, great. Thanks a lot.
Thank you, Doug.
Our next question comes from Doug Leggate from Bank of America. Please go ahead.
Thanks. Good morning, everybody.
Hey, Doug.
Matt, one of the things that has changed since the analyst days, unfortunately, you had a couple of dry holes from a sizable write-off. I guess I'm mindful that you had a lot of obligations on drilling this year and exploration. When you consider $1.5 billion on exploration relative to, let's say, M&A opportunities, so that it'd be bolt-on working interest on the onshore or something like that, how does your exploration appetite look post 2015 once those obligations have rolled off? I've got a follow-up, please.
Clearly, we're disappointed in the results we've had from Angola so far. We, and the whole industry, in fact, expected that that pre-salt play in the Kwanza Basin should have similar characteristics to the pre-salt play in Brazil, but it's not panning out that way so far. On the other hand, we were really pleased with the results that we had in Senegal, which on the face of it was a more risky play. There, as we said, we've proven two different play types in the basin. We're looking forward to getting back there. Of course, as you know, that's the nature of exploration. In terms of a sort of longer-term role for exploration, we see exploration's role to supplement the resource portfolio with additional opportunities to sustain long-term growth. We're exploring plays where we think we can do that at competitive cost of supply.
Over the last five years or so, exploration has delivered a lot of success. Remember, the Eagle Ford was an exploration success for us. During that time, we've been building the deep water portfolio, focused initially in the Gulf of Mexico. We already have significant discoveries there too, three discoveries in the Gulf of Mexico in addition to Senegal. We're continuing to test the portfolio, but clearly, exploration has to compete for capital in what is a very competitive investment portfolio, as we outlined when we described the resource base and the cost of supply of that resource base a few weeks ago. We see that as good discipline, to make sure that we're only committing to exploration opportunities that we think we can compete against that resource base.
I guess, kind of a related question. I was going to have another follow-up, but I don't want to take up too much time, so maybe I'll stick with this one. I'm thinking really more, Matt, about the scale of the discretionary capital, because $1.5 billion is still a decent chunk of your spending this year. Where would you expect that to move towards, let's say, in a lower oil price environment, should this continue? I will leave it there. Thanks.
Okay. Thanks, Doug. Well, in the operating plan that we laid out a few weeks ago, we're anticipating a level of about $1.5 billion this year, next year, and in 2017. We can revisit that to some extent, but that's our expectation as a sort of an average over the next three years.
All right. Thanks very much.
Thank you.
The next question comes from Paul Sankey from Wolfe Research. Please go ahead.
Good afternoon, everybody.
Hello, Paul.
A couple of quickies. You mentioned on Libya that you're shut in. Is that for sure shut in, or could someone else be producing those volumes? The follow-up, which is also fairly quick, I think, is could you talk a little more about the Kenai sales? I'm not sure who's buying that or how you're selling it. Then I have a longer-term follow-up.
Libya, yeah, the production shut in, and we're confident of that shut-in in the Waha concession. Nobody else is producing it. The Kenai, yeah, we started operations up this month. We'll sell their cargoes starting next month. We're going to sell five or six cargoes, and they're going to Japan.
Is that kind of spot sales, Matt?
Yes.
Got it. Matt, one of the things that people have been talking about since your analyst meeting is your comments on the pilot that you ran and pilots that you're continuing to run in the Eagle Ford. Could you just expand and talk about what could be next catalysts in terms of news flow on those pilots? Thanks.
Yeah. Thanks, Paul. Yeah, we're running several different pilots in the Eagle Ford, in particular in the Upper Eagle Ford. We're running, I think it's seven different pilots across different parts of the Eagle Ford to test the triple stack concept that we talked about, just to understand what parts of our geographic extent of the Eagle Ford is going to be amenable to the triple stack development. Those pilots are going to be drilled as we go through this year, we'll start to see results as we head into next year. I don't expect to draw any definitive conclusions on just how much of our areal extent will be developed that way until maybe the later part of next year, frankly, because a lot of this is understanding, do the wells begin to interfere with each other?
You don't see that early in the well's life. Of course, we're still running the stimulated rock volume pilot that we talked about, we're going to get a lot of new information from that this year that will be important from a longer-term basis in terms of optimizing the Eagle Ford as a whole, other unconventional plays that we have in the portfolio.
Yeah. Matt, just remind us what the uplift is in terms of performance that you, I think, were anticipating, if I'm not wrong. I can't remember if you'd seen initial results or whether you anticipate.
The initial results from single well pilots in the Upper Eagle Ford basically showed that the production was the same as the Lower Eagle Ford. What we haven't tested yet is when those are drilled in the context of a pattern of wells, do we see interference? That's what we're testing with these seven pilots that we're running now.
There was actually a number, I think, that's associated with what you might get in terms of improved performance.
No, I don't think we went into that yet, Paul, because we really need to understand the nature of these pilots, how they perform when they're confined with other wells. We didn't actually make any real prediction about what we expect to find. We'd rather do that after we've seen the pilot test results.
Okay. As you said, this is something that's going to take a bit of time to really Maybe by next analyst meeting, I guess.
Yeah. It's possible, but it may take even longer than that. We don't want to jump the gun on it. We're definitely encouraged, as we said a few weeks ago, but we want to make sure that we're calibrating properly before we make any claims about what the incremental reserves will be, for example.
Got it. Thanks, Matt. Thank you all.
Thanks, Paul.
Your next question comes from Paul Cheng from Barclays. Please go ahead.
Hey, guys.
Hi, Paul.
Two quick question. Matt, can you share what is APLNG, the cash operating cost, and the tax regime?
We're not in the operating phase yet for APLNG, so I don't have the operating cost number off the top of my head. The tax regime is a tax and royalty regime with the royalties at the Queensland level and taxes at the federal level.
It's a typical 10% on the royalty and 30% PPT or PRT?
Yeah. It's actually not fully resolved yet. There's some discussions still underway with the Queensland Government on the nature of how the royalty will be calculated. I can't really give you a definitive answer on that yet, Paul.
Most of the-
I'll add a little bit to what Matt said on the tax side. The taxes are actually paid down at the APLNG corporate level. There's going to be, as you can imagine, with a big capital investment project like that from a cash flow perspective, a fair bit of tax shield from depreciation on the investment, particularly in the early years of the project.
Jeff, that means that during the first five years that we should assume there's not really the tax that APLNG need to pay?
I don't know that I could give you that precisely the number. That depends upon price levels as well. If we had current kind of prices there, that's probably not a bad assumption.
Okay. Matt, maybe I missed it. Can you tell me what is the Eagle Ford, Bakken, and Permian production in the first quarter? If you have any number you can share in terms of the exit rate for this year?
Yeah. The Eagle Ford was around 175,000 barrels a day in the first quarter, and the Bakken was around 55,000 barrels a day in the first quarter. The Permian was less than 10 on the unconventional side. We also have a significant conventional production, but on the shale side, it was less than 10. What we expect to happen, Paul, is the aggregate production from the unconventionals is going to grow a little bit into the second quarter, and then it's going to gradually decline as we exit the year. The fourth quarter exit rate is going to be quite similar to the first quarter rate on aggregate for the shale plays.
That you will start increasing the rig count next year again? I think that's the current plan. We should assume that they will resume the growth or that the increase in rig count for next year will be only sufficient to hold it flat?
It depends a bit on the pace that we build the rigs back up. You should really assume that it's going to hold it flat because by the time we get the wells back and running again, go through the drilling and completion and hook up and bring them on to production, we're actually going to see the declining production from those plays continue into the early part of 2016.
Start to increase towards the end of 2016. Based on our current assessment of how we'll put rigs back to work there, we'll probably be relatively flat from the average of 15 to the average of '16 .
Thank you.
Thanks, Paul. Our next question comes from Ryan Todd from Deutsche Bank. Please go ahead.
Great. Thanks. Good morning, everybody.
Hey, Ryan.
Hey, Ryan.
Oh, sorry. Hey, can you hear me better?
Yes.
Sorry. A couple of questions. There's been several recent news stories around some of your M&A efforts of potential assets you might consider selling. Any additional commentary that you might add regarding potential M&A programs? Are these programs people approaching you? Are these assets that you're marketing? Are we still looking at kind of smaller, $500 to $1 billion size deals? Any thoughts around that?
Yeah. We're always in, with a portfolio of our size, looking at what can we do in the way of portfolio optimization. As we go forward, we're not going to be pre-announcing that we're marketing particular assets. You'll hear stories probably out in the marketplace that we're testing values on that. That's what we'll always be doing as part of a kind of prudent optimization of the portfolio. As we've said, I think it's prudent to think in terms of a company our size will do something with its asset portfolio every year. We've talked about it, whether that's $1 billion or so a year is probably a good go by. It really just depends on whether we're getting full value for the assets.
It's always about whether we can sell the assets for at least what we think we could receive from in value if we kept them in our portfolio. We don't know what that number's going to be, there'll be some level of asset sale.
Okay. Thanks. Maybe shifting gears a little bit. In Alaska, I know at the analyst meeting, you guys have given guidance on Alaska production, and you have a couple projects starting up later this year. I guess, can you talk a little bit about your production expectation in Alaska and maybe that of the industry? We've seen differentials kind of bounce around quite a bit. Maybe as you look out one or two years, what's the direction that you would expect in terms of crude realizations and activity levels in general in Alaska?
We expect with the major projects that we're doing and the development drilling that we're doing in Alaska, that we're likely to hold production relatively flat for the next three years and beyond that, actually. We are a reasonably good representation of the overall Alaska production because we are in all three of the big production areas there of Prudhoe, Kuparuk, and Alpine. I think if you're looking at a sort of macro view of Alaska, that wouldn't be a bad basis to think about that. In terms of realizations, I think currently realizations for ANS crude are about $2 or $3 below Brent. We have taken one cargo this year to Asia and one last year, and we always have that option if that's what we choose to do.
Our next question is from Evan Calio from Morgan Stanley. Please go ahead.
Hey. Good afternoon, guys.
Good afternoon.
I know Conoco remains focused on your yield, bridging to cash flow neutrality. How would you respond to a commodity recovery? Meaning, will you seek to increase cash cushion, balance sheet repair to some level which might kind of dictate or delay any potential re-acceleration?
I think our first reaction to an increase in prices is going to be to reduce the amount of cash we use or the amount of debt we might borrow, particularly as we think about the activity levels in 2015 and 2016.
Any idea in terms of levels or price signal that you'd need to see to re-accelerate?
I think in the near term, I'm not sure we see a price level that would cause us to re-accelerate.
We're going to want to see that if there is some acceleration in prices, that it's got a more lasting effect as well. If you think about what's going on with our capital program-
as Matt mentioned earlier, we have a couple billion dollars rolling off from Surmont and APLNG, and we are in our plans already accelerating capital spending in places like North America and reinvestments as we go into 2016.
Right. No, I understood that. Maybe to the other side, could you quantify or provide a range of how much more you could borrow and still maintain your A rating?
I don't think I can actually quantify that because the rating agencies won't tell you exactly what number that is. I think we would characterize it the same way we characterized it on our call last time, that we think the amount that we do borrow, it could be enough that would cause us to see a one-notch downgrade from what's currently A1 at Moody's and the middle single A with Standard & Poor's and with Fitch. As you've seen, all the agencies do have our credit rating outlook on a negative, so they're anticipating that. If that were to happen, that would move us into a range where we're comfortable that there's plenty of space there to meet whatever borrowing needs we might have in 2015 and 2016 as we head towards cash flow neutrality in 2017. Great. Fair enough. Thanks, guys.
Thanks, Evan.
Our next question comes from Ed Westlake from Credit Suisse. Please go ahead.
Yeah, I just wanted to dive a little bit into shale again. I've seen some very strong performance from you guys this year, even stronger in the Bakken. Is there anything you're doing differently this year?
We're continuing to work through our optimizations, Ed, that we discussed a little bit a few weeks ago. We're optimizing the completion design and the well length, the well placement and so on. I wouldn't say that there's anything fundamentally different going on there. We are moving towards more pad drilling. 90% of our wells will be from pad drilling. There's not a fundamental change there. The guys are just executing well.
On the Shale program, obviously a massive cut in rigs. Obviously you do modeling on volumes, probably to a far greater degree than we do from the outside. Are there any risks that you undershoot on volumes, or you feel pretty comfortable about the trajectory you just outlined?
I feel pretty comfortable about the answer I gave earlier on what we expect of our Eagle Ford and the Permian and Bakken production to do this year and into next year, assuming that we do increase our rigs the way that we intend to next year.
Coming back to Doug's question on obviously people are going to focus a lot on cash flow margins and you've got these big projects coming up. When do you reckon that APLNG, Surmont will hit what you think is a peak operational cash flow? Obviously, whatever the macro gives at that point is a separate discussion.
Yeah. Peak on both of them really for different reasons. Peak operational cash flow is in 2017. For Surmont too, it's because it takes a while, as you know, to build the steam chambers and ramp up production in the SAGD projects. In the case of APLNG, we'll bring the first train on this year. It'll be next year before we bring the second train on. The first year that we'll have both trains running will be 2017. In both cases, it'll be 2017 before they're fully contributing at their plateau rate. Of course, that rate will continue on both projects for decades.
Yeah. Very clear. Thanks very much.
Thanks. Ed.
Our next question comes from John Herrlin from Societe Generale. Please go ahead.
Yeah. Hi. Two quick ones. You cut your lower 48 rigs by over half. How many frac spreads are you running, Matt?
Let's see. I would say overall, we're probably running three or four. It varies a little bit, but I think three full-time and four if we occasionally do. That's our total spread to support those rigs.
Okay, great. In Angola, you had a passing comment about you being disappointed with the geology. Can you elaborate a little bit more on that? That's it for me.
Okay. Yeah. We've had two dry holes there in the campaign. The first at Kamoxi was basically the reservoir wasn't developed there. As you know better than most, these carbonate reservoirs are quite difficult to predict the porosity development. In the case of Kamoxi, the porosity just wasn't developed there. For Omosi, the porosity was developed. We did see good reservoir facies , but it was gas-filled. The fetch area that was feeding into Omosi was overcooked. Two different reasons for the failures on those wells. That basin as a whole is a bit less predictable than we had hoped going in.
Thank you.
The Vale well that we're drilling is actually testing a different play than the Omosi and Kamoxi wells were. We'll see how that goes.
Thanks.
Thanks, John.
Our next question comes from Blake Fernandez from Howard Weil. Please go ahead.
Hey, folks. Good morning. Jeff, back on the balance sheet discussion previously. I'm just curious, can you remind me if Libya
No, we've not impaired Libya. For us, we would have to see that there was some kind of view that there was a permanent loss of that concession before we really need to do an impairment.
Okay. Offhand, do you remember what capital employed or anything on that asset?
I don't know that I know that number off the top of my head. It's on the order of a half a billion dollars, but I'm not sure exactly what that number is.
No worries. That's fine. The second question, there's been a lot of discussion with the recent rise in commodity prices here with some of the E&Ps potentially layering in hedges. I know historically that's not been something that Conoco has enacted, but I didn't know if there was any new internal debate as to the potential benefits of doing that specifically for your lower 48 activity.
No, we take a portfolio approach to thinking about our cash flows. We wouldn't really think about doing it for one particular part of our portfolio. Generally, our philosophy that we've talked about before hasn't changed. That we feel like hedging is, by definition, a kind of zero-sum game in terms of value. One of the reasons we keep a strong balance sheet is to be able to handle the fluctuations in commodity prices.
Fair enough. Thank you.
Thanks, Blake.
Our next question comes from Neil Mehta from Goldman Sachs. Please go ahead.
Good morning. Good afternoon.
Good morning, Neil.
There's been a lot of talk, sticking with the Lower 48. At what price signal does U.S. shale production start re-accelerating? As a major U.S. player, not speaking specific to your portfolio, just wanted to get your perspective at what level that might occur, whether it's $60 WTI or $65 WTI, or the range of outcomes. How quickly can the industry bring back that production, and what potential bottlenecks to bring that supply back online are?
You know, Neil, I can't speak for the industry as to what price signal they might be looking for. Certainly, cash flow will have a big impact on that as well. In our plans, we are planning the increases within 2016. Modestly, but we're going to increase as we move into 2016, and that's in the anticipation that there'll be some continued recovery in prices. In terms of the capacity, clearly we've laid down quite a bit of rig and completion capacity, and that can be brought back relatively quickly. It is a flexible industry that we have in the Lower 48. Exactly how quickly people bring these back on will be a function of the cash that they want to put back in and what they see as being an efficient and safe way to bring the rigs and the completion crews back to work.
I don't think I answered your question very satisfactorily, but that's about the best I've got.
No, you got me there philosophically. I should have asked you this question at the analyst day. The $1 billion of the cost reduction program, that operating cost reduction target, how sensitive is that to the commodity price, or do you think that is commodity agnostic?
No, our intention is to make that commodity agnostic for the most part, where we're looking to get sustainable cost reductions through this effort. Now we're going to get some fluctuations associated with exchange rates and with changes in the deflationary environment. Our focus is on getting structural cost reductions that we can sustain through the cycles.
Thank you very much.
Thanks, Neil.
Our next question comes from Roger Read from Wells Fargo. Please go ahead.
Yeah, thank you. Good morning, or good afternoon.
Hey, Roger.
as the case may be. I guess I'd like to ask about the price realization. Seemed a little bit, well, at least relative to our expectations, a little weak in the first quarter, both on oil and gas. I was wondering how much of that may just be a function of timing, how much of that is maybe some of the differentials we've seen for a mix of production, oil condensate, NGLs, et cetera, working its way through. The final part of that question, as prices have been recovering, does that help on realizations as we think about Q2 and Q3 centrally?
What we saw in the first quarter was that realizations were probably weaker than what people were expecting, primarily in the Lower 48. For example, I think our Lower 48 crude oil realization was closer to $40, where WTI was like at $48.50 for the quarter. What we're seeing was just a tough quarter for realizations, a lot of supply in the marketplace. The differentials that we saw in the first quarter are not that different when we were in a $50 price environment than they were when we were in much higher price environments. They're still that same level of differentials. I think we would expect to see differentials improve in terms of % of marker realized, and maybe some slight improvement in absolute levels of differentials as well.
Okay.
The differentials were tough because they were tough across all commodities for us in the Lower 48 as well, just it was tough on NGLs, oil, and natural gas.
Yeah, I was just wondering, I don't remember all the exact moving parts right here, but I'm just thinking, was that a function of any more either a lighter crude that you're selling or a condensate barrel, or it just is what it is? I'm just trying to understand.
Yeah. That's just what the market was in the first quarter. There's nothing really that fundamentally changed in our product mix or the quality of any of the products that we're selling that would lead to that kind of differential.
Okay, thanks. Unrelated follow-up, the change in taxes in the U.K., can you give us an idea of maybe how you'd characterize that? Is it a, "That really helped. It's a nice first step, but we need to see more"? Does it change anything in terms of how you think about investing over the next, say, two years, which seems pretty well locked down in terms of expectations on the CapEx side, but it could help in a post 2017 environment?
Roger, it helps. The U.K. sector needs as much help as it can get. The help on the tax rates was welcomed. The simplification and broadening of the uplift on capital is going to help as well. It's about a 12% uplift now on capital when you go through the math. We'll build that into our thinking as we're thinking about our overall investment portfolio over the next few years. It certainly was a move in the right direction by the U.K. government.
Thank you.
Thanks, Roger.
Thanks, Roger. Our next question comes from Pavel Molchanov from Raymond James. Please go ahead.
Thanks for taking the question. Your guidance for exploration and dry hole, $800 million for the year, you said is unchanged. It looked like Q1 was well above your annual run rate. Does that imply that there's going to be a significant reduction in that expense line item as the year progresses?
Yes, it does. By its nature, dry hole cost is going to be pretty lumpy. We happen to have both the Harrier well and the Omosi well in Angola hit in the first quarter. You could have quarters where the number's really low if no well actually gets to TD during that quarter, and it could be lumpy again later in the year. As we look at the overall balance of the year, we think the guidance that we gave at the analyst presentation still makes sense.
Okay. You've talked about some of the areas where you're seeing cost savings that look pretty encouraging. Are there any operating areas where, on the other hand, costs have been surprisingly sticky? Where you're not seeing the savings that perhaps you would have anticipated by this point?
Are you talking about operating costs, Pavel, or capital costs?
I guess more on the CapEx side.
Yeah. What we're seeing is a more rapid response in the Lower 48 than in other parts of the company. We expect to see some deflation kicking in, and we already are seeing some in our international business, but it's coming more slowly, which is what we would anticipate. It's coming more slowly from the international business, but it's come very rapidly in the Lower 48. We've built that sort of trend as we anticipated it into our expectations of deflation, and we do expect to see those reductions coming in the international over the next several months.
Okay. I appreciate it.
Thank you.
Thanks, Pavel.
We have a question from Asit Sen from Cowen and Company. Please go ahead.
Thanks. Good morning. Matt, just wanted to get your views on the recent industry debate on refracking in the unconventional. If I could ask two questions on that. First, from Conoco's vantage point, what is new in the technology offering that you're seeing? Second, within your portfolio, where do you see the most relevance? If you could frame that on a risk-reward context, please.
We have been running some refracs in our portfolio. Some using the diverter sort of technology, some just basically straight pumping new fracs on existing perfs, and some with new perfs. We've been testing a few. The area that we're seeing the best uplift is, as you'd expect, our older wells, where we pumped smaller jobs with wider spacing. We see some potential there, and it's particularly in wells that were drilled a few years ago, and not in more recently drilled wells. We're continuing to evaluate that, but there is certainly some upside potential.
Okay, thank you.
Thank you.
Okay, sorry, go ahead, Operator.
Oh, I was just going to turn the call around to make his final comments.
That's terrific. Really, we appreciate everybody's questions and comments. Obviously, feel free to come back to us if you didn't get your questions answered. We're going to give you back a little bit of time here. Again, thank you for participating, and we look forward to staying in touch with all of you. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating, and you may now disconnect. I can't turn the