Conoco Phillips (COP) — Q1 2015 Earnings Call Transcript

Thanks, Adrian, and welcome to all of the 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 & 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, and Matt will review the operational highlights for both the quarter and the upcoming year. During Q&A, we would appreciate it if you would limit your questions to one, plus a follow-up. Our page 2 contains our SAFE HARBOR statement; we will make some forward-looking statements this morning and as always we would ask you to refer to our periodic filings with the SEC for a description of the risk and uncertainties in our future performance. Again, thank you for participating, and now I'll turn the call over to Jeff.

Thanks, Ellen, hello everyone and 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 supply resource base. We outlined our capital and production plans for next year and how we will achieve cash flow neutrality in 2017 in relation to commodity prices. We also reaffirmed our commitment to a compelling dividend. In the first quarter results we will discuss this morning, we are 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 4, I'll cover our key highlights for the first quarter. We produced 1.61 million BOE per day, which is a growth of 5% compared to the same period last year, adjusted for Libya dispositions and downtime. We achieved first production at Eldfisk II by an indent Phase 3 and the Brodgar H3 subsea tie-back. We also advanced five major projects toward startup by the end of the year, including our two major projects with Surmont II and APLNG. Financially, our earnings were materially impacted by low prices— we had a $222 million loss, or $0.18 per 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 our big focus this year. At our analyst and investor meeting, we announced the goal of reducing operating costs by $1 billion in 2016 versus 2014, and we are already starting to see progress. We’ve made significant strides in capturing deflationary capital benefits on our capital program as we 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% to 3% compared to 2014. Now I'll turn to Slide 5 for further discussion on earnings. Production came in at the high end of guidance; we also saw improvement in our costs, which as we discussed in 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 of last year. When you adjust 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. We 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 $0.18 per share. First quarter segment adjusted earnings were shown in a lower right part of this chart. The financial details for each segment can be found in the supplemental data on our website, and 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, and the other international segment adjusted earnings were driven by the MOC 1 dry hole in Angola. If you’ll turn to Slide 6, I’ll summarize our production results for the quarter. Our projections slide follows our usual convention and 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, which leaves net growth of 82,000 BOE per day or 5% growth compared to last year. Of the 82,000, 61,000 of the improvements came from liquids, mostly from oil plants in Canada and conventional in the Lower 48 and Gumusut, Malaysia. Gas was up 21,000, and some of that is from domestic gas sales at APLNG that will turn to LNG over time. Now, if you turn to the next slide, I will 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 and WTI was at $48.50, and as you know, current prices in the strip are higher than these numbers. Moving to 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, the capital is front-end loaded and tapers off through the year as we complete our major projects and ramp down our activity in unconventionals, so 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 UK. This was a special item and not included in our adjusted earnings. This income benefit did not create an immediate cash flow benefit, so on the cash flow statement the income benefit is reversed out on the deferred tax line, which is why the deferred tax line on cash flow 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, but 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% to 3% production growth this year. Our second quarter projection guidance is 1.555 to 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, and 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, but 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 turnaround season. We’ll also see some higher costs in the fourth quarter associated with our major project startups. There is 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 look a little low on run rate, but 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 the 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 operational quarter, achieving the high end of our production guidance, and we did that while reducing capital and operating costs and maintaining our relentless focus on safety. So, let’s jump into the review of the segment performance starting with the Lower 48 in 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 drilling in the conventionals but as we’ve previously announced began to slow as we see the impact of reducing the number of rigs in operation. Overall in the 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. In our recent Analyst and Investor Meeting, we gave you a lot of details 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 deepwater Gulf of Mexico. We currently have appraisal wells drilling at Gila and Tiber; unfortunately, Harrier was a dry hole. Next, we’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, Blair, and Montney areas. This activity will reduce as we ramp down our rigs from a high of 10 in the quarter to 2 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, and at Surmont II, construction is over 93% complete and final preparations are underway in anticipation of first steam by the middle of the year. Next, I will cover our Alaska and Europe segments from Slide 11. Alaska's average production was 186,000 BOE per day and activity this quarter was focused on several major projects. CD5 and 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 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 also sanctioned the first phase of the northeast-west act development; the 1H NEWS project in March, and we expect to see first production in 2017. In addition to progress on these projects, we 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 throughout the year as we bring additional wells online, and the Brodgar H3 subsea tie-back well achieved first gas in March. Enochdhu is also progressing on schedule and should start in the third quarter. Now let's review Asia Pacific and Middle East segments along with other international segments on Slide 12. In APME, we produced 351,000 BOE per day in the first quarter, which 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 S&P in Malaysia. The Gumusut 2014 production system is continuing to ramp up, with full fuel 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 the Bayu Undan Phase III program in March, and 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, and we’re progressing toward startup in the third quarter. In our other international segment, we’re continuing to focus on our exploration and appraisal programs; in Angola, we spud the Vali well this month and will update you on the progress there next quarter. We announced the 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. Finally, in Libya, our production remains shut in due to ongoing unrest, and 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% to 3% production growth this year. For the second quarter, we expect to produce 1.555 to 1.595 million BOE per day. The key driver is typical turnaround activity which you see in the upper right chart. Our major turnaround activities for the year are scheduled in Alaska, Europe, and APME, in the second and third quarters. These large turnarounds starting in June will impact 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 and we expect to run 12 rigs through the second half of the year. Moving to major projects, there are five startups expected before the end of the year: Surmont II, APLNG, Enochdhu, 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 spud the Vali 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 in 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. So that’s a quick review of the segments. We provided you with a lot of information at the recent Analyst and Investor Meeting, so 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.

A key element of the path to cash flow neutrality that you 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? And second, is a $2 billion reduction in spending, which is about 20% of the budget, kind of a reasonable order of magnitude type reduction for these two projects, or is that too high? So, could you just provide some color on what to expect on capital spending declines?

So Doug, on Surmont II, we expect to have first steam sometime relatively soon, certainly by the middle of the year. APLNG we expect to start up in the third quarter. So, it’s pretty much in line with still 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, but that won’t be noticed immediately because we still have capital being spent in both of those projects through the end of the year. From 2015 to 2016, it’s about a $2 billion reduction.

Matt, one of the things that has changed since the Analyst Day is, unfortunately, you had a couple of dry holes resulting in sizable write-offs. I guess I’m mindful that you had a lot of obligations on drilling this year in exploration. When you consider $1.5 billion in exploration relative to M&A opportunities, how does your exploration appetite look post-2015 once those obligations are rolled off? And I’ve got a follow-up.

Clearly, we’re disappointed in the results we’ve had from Angola so far. The whole industry expected that the pre-salt clay in the Kwanza Basin showed similar characteristics as the pre-salt clay in Brazil, but it’s not planning out that way so far. On the other hand, we’re really pleased with the results from Senegal, which was a more risky play, and we were prudent with two different clay types in the basin; we’re looking forward to getting back there. As you know, that’s the nature of exploration. In terms of the long-term role for exploration, we see exploration’s role as supplementing the resource portfolio with additional opportunities to sustain long-term growth and exploring in plays where we think we can do that at a competitive cost of supply. Over the last five years, 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 and focused initially in the Gulf of Mexico, and we already have significant discoveries there too, with 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 this very competitive investment portfolio. As we outlined our resource base and the cost of supply a few weeks ago, we see that as good discipline to ensure that we’re only committing to exploration opportunities that we think we can compete against our resource base.

I guess like 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. But I’m thinking really more about the scale of discretionary capital because $1.5 billion is still a decent chunk of your spending this year. So, where would you expect that to move towards, let’s say, in a lowered oil price environment should this continue? I’ll leave it there. Thanks.

Thanks, Doug. 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 sort of expectation is planned as an average over the next few years.

Good afternoon, everybody. A couple of quick questions. You mentioned on Libya that you are shut in; is that full shore shut in, or can someone else be producing those volumes? And the follow-up, which is also a fairly quick and clean, could you talk a little bit more about the Kenai sales? I'm not sure who is buying that—Ohio is selling it, and then I have a longer-term follow-up.

So Libya, yes, that production is shut in, and we are confident that is shut in at the Waha concession, so nobody else is producing it. The Kenai— we started operations this month; we will sell our cargos starting next month. We have grown our sales to five or six cargos, and they are going to Japan.

Is that kind of spot sales, Matt?

Yes.

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 the next catalyst in terms of news flow on those pilots? Thanks.

Yes, thanks, Paul. We are running several different pilots in the Eagle Ford, particularly in the upper Eagle Ford. We are running, I think, seven different pilots across different parts of Eagle Ford to test the triple-stack concept, that we talked about before, and just to understand which parts of the geographic extent of the Eagle Ford is going to be meaningful to the triple stack development. So, those pilots are going to be drilled as we go through this year, and we’ll start to see results as we head into next year. I don't expect us to drill any definitive conclusions on just how much of the aerial extent will be developed that way until maybe the latter part of next year because a lot of this is understanding how the wells began to interfere with each other, and you don't see that early in a well's life. Of course, we’re still running this stimulated growth volume pilot that we talked about, and we're going to receive a lot of new information from this year that, from a longer-term basis, will help with optimizing the Eagle Ford as a whole and other unconventional plays that we have in the portfolio.

Yes, Matt, just remind us what the uplift is in terms of performance that you I think were anticipating. I can't remember if you've seen initial results or whether you anticipate.

Yes. The initial results from single well pilots in the upper Eagle Ford have basically shown the production was the same as the lower Eagle Ford. We haven’t tested yet in the context of a pattern of wells; do we see interference? That's what we’re testing with these seven pilots.

So, there was actually a number I think 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, and how they perform when they’re confined with other wells. We didn’t actually make any predictions 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?

Yes, it's possible, but it may take longer than that. We don't want to jump the gun, and we're definitely encouraged, as we said a few weeks ago, but we want to ensure that we’re calibrating properly before we make any claims on what incremental reserves will be, for example.

Hi, Guys. Two quick questions. Matt, can you share what EAPLNG's cash operating cost and the tax regime are?

We’re not in the operating phase yet for EAPLNG, 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 royalties at the Queensland level and taxes at the federal level.

So, it’s typical like 10% on the royalty and 30% PPT or TIP?

Yes. This is actually not fully resolved yet; there is some discussion still underway with the Queensland government on how their oil could be calculated, so I can’t really give you a definitive answer on that yet, Paul.

I'll add a little bit to what Matt said on the tax side. The taxes are actually paid down at the ATLNT at kind of corporate level, and there’s going to be, as you can imagine, with a big capital investment project like that from a cash flow perspective, a fairly robust tax shale due to depreciation on the investment, particularly in the early years of the project.

So, Jeff, does that mean that during the first five years, we should assume there's not really much tax that EAPLNG needs to pay?

I don’t know, but I can't give you that precisely, as that depends on price levels as well. But if we had current kind of prices, that’s probably not a bad assumption.

Okay. And then, Matt, can you — maybe I missed it; can you tell me what the Eagle Ford, Bakken, and Permian production figures were in the first quarter? And if you have any numbers you can share in terms of the exit rate for this year.

Yes, the Eagle Ford was around 175,000 BOE in the first quarter, the Bakken was around 55,000 barrels a day in the first quarter, and Permian was less than 10,000. On the unconventional side, we also have significant conventional production, but on the shale side, it was less than 10,000. So what we expect to happen forward is the aggregate production from the unconventionals will grow a little bit into the second quarter and then it's going to gradually decline as we exit the year, so the fourth quarter exit rate is going to be quite similar to the first quarter rate in aggregate for the shale plays.

And do you plan to start increasing the rig count next year again? I think that’s the current trend, so should we assume that they will resume growth, or will the increase in rig count for next year be only sufficient to hold it flat?

It depends a bit on the pace of the build of 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 through the drilling, completion, and hooking up and bringing them into production, we’re actually going to continue to see a decline in production from those plays into the early part of 2016 and then start to increase towards the end of 2016. Based on our current assessment on how we’ll put rigs back to work, they’re probably going to be relatively flat from an average of 15 to an average of 6.

So, a couple of questions on the — there have been several recent news stories around some of your M&A efforts regarding potential assets that you might consider selling. Any additional commentary that you might have regarding potential M&A programs—are these bringing people approaching you, or are these assets that you are marketing? Are we still looking at kind of smaller $500 million to $1 billion sized deals? Any thoughts around that?

We’re always in portfolio management, looking at how to optimize our assets. As we go forward, we're not going to announce that we're marketing particular assets. You're likely to hear stories in the marketplace that we’re assessing values on that, and that’s an ongoing process. As we’ve said, I think it’s prudent to think in terms of a company of our size doing something with its asset portfolio every year; $1 billion a year is probably a good guideline. It really depends on whether we’re getting full value for the assets. It’s always about whether we can sell the assets or at least what we think we could receive if we kept them in our portfolio.

And maybe shifting gears a little bit, in Alaska at the Analyst Meeting, you provided guidance on Alaska production, and you have a couple of projects turning up later this year. I guess, can you talk a little about your production expectations in Alaska and maybe that of the industry with these differentials bouncing around quite a bit? If you look out one or two years, what’s the direction that you would expect regarding 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. We have a reasonably good representation of the overall Alaska production because we manage the big production areas; we look to drill Kuparuk and Alpine, so I think if you look at us, our macro view of Alaska would be a basis to consider. In terms of realizations, I think current realizations for the E&S crude are both $2 or $3 below Brent, and 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.

I know Conoco remains focused on bridging your cash flow to neutrality; how would you respond to a commodity recovery, meaning when you seek to increase cash cushion and balance sheet repair, just some level which might dictate or delay any potential reacceleration?

I think our first reaction to an increase in prices is going to be to reduce the amount of cash we use and the amount of debt we might borrow, particularly as we think about the activity levels in 2015 and 2016.

Any idea in terms of kind of levels or price signals that you need to see to reaccelerate?

I think in the near term, I’m not sure we see a price level that would cause us to reaccelerate, and we are going to want to see what if there is some acceleration in prices and it has a more lasting effect as well. We are taking everything into account regarding our capital program as Matt mentioned earlier; we have a couple of billion dollars rolling off from APLNG. We are planning to accelerate capital spending in places like North America and unconventionals as we go into 2016.

Right, 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?

It’s a bit of a—I don’t think I can actually quantify that because the rating agencies won't tell you exactly what number that is. But I think we would characterize it the same way we characterized it on our call last time. We think the amount that we do borrow could cause us to see a one notch downgrade from what’s currently A1 at Moody’s and A in the middle single A with Standard & Poor’s and with Fitch. All the agencies currently have our credit rating outlook on a negative, anticipating that. If that were to happen, we are comfortable that there is plenty of space to meet whatever borrowing needs we might have in 2015 and 2016 as we head towards cash flow neutrality in 2017.

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 are doing differently this year?

We’re continuing to work through our optimizations, Ed, that I discussed a few weeks ago, including optimizing the completion design, well length, well placement, and so on. I wouldn’t say there is anything fundamentally different going on, but we are moving towards more pad drilling; 90% of the wells have become pad drilling, but there is not a fundamental change there; the teams are just executing well.

And then on the shale program—obviously a massive cut in rigs, and you do modeling on volumes probably to a far greater degree than we do from the outside. But are there any risks that you might undershoot on volumes, or do you feel pretty comfortable about the trajectory you just outlined?

I feel pretty comfortable, although for obvious reasons—the answer I gave earlier on our expectations for Eagle Ford, Bakken, and Permian production for this year and into next year. Assuming we do increase our rigs in the way that we intend to next year. We expect activities to continue with the projects coming online, particularly with the major projects we have. APLNG and Surmont II's peak operational cash flows will be in 2017.

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, but I think three full-time and four if we occasionally need them, so that's our total spread to support those rigs.

Okay, great. And at Global, you had a passing comment about being disappointed with the geology. Can you elaborate a little bit more on that?

Okay. We’ve had two dry holes in that campaign; the first at Kamoxi was basically the reservoir wasn't developed. These cabinet reservoirs are quite difficult to predict across the development and in the case of porosity, it just wasn't developed there. For Omosi, the porosity was developed; we did see good reservoir faces, but it was gas filled. So the fetch area feeding into Omosi was overcooked. So, two different reasons for the failures on those wells, and that basin as a whole is a bit less predictable than we were talking going in. There is a valley well that we’re drilling, which is actually testing a different play than the Omosi and Kamoxi wells were, so we’ll see how that goes.

Hi, folks. Good morning. Jeff, back on the balance sheet discussion previously, I am just curious; can you remind me if Libya?

No, we’ve not impaired Libya. For us, we would have to see if there is 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 kind of capital employed or anything on that asset?

You know, I don’t know that number off the top of my head; it’s on the order of $0.5 billion, but I wouldn’t— I'm not sure exactly what that number is.

No worries, that's fine. The second question: there has been a lot of discussion around the recent rise in commodity prices with some of the E&Ps layering in hedges. I know historically that has not been something that Conoco has enacted. But I didn't know if there was any new internal debate on the potential benefits of doing that, specifically for your Lower 48 activity?

No, we take the portfolio approach to thinking about our cash flows. So we wouldn’t really think about doing it for one particular part of our portfolio. Generally, our philosophy hasn’t changed; we feel like hedging is by definition kind of a zero-sum game in terms of value, and it’s one of the reasons we keep a strong balance sheet to handle fluctuations in commodity prices.

So, there has been a lot of talk, sticking with the Lower 48; at what price signal does U.S. shale production start reaccelerating? And 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 a range of outcomes. How quickly can the industry bring back that production, and what potential bottlenecks exist to bring that supply back online?

I can’t speak for the industry regarding what price signal they might be looking for. A cash flow would certainly have a big impact on that as well. In our plans, we are planning modest increases in 2016, but we’re going to increase as we move into 2016 based on anticipated continued price recovery. In terms of capacity, clearly, we’ve laid down quite a bit of rig and completion capacity. That can be brought back relatively quickly. There's flexibility in the industry in the Lower 48, so exactly how quickly people bring these back on will depend on the cash they want to invest and how efficiently they can bring the rigs and completion crews back to work. So, I don’t think I answered your question satisfactorily, but that’s the best I’ve got.

You got me there philosophically. And then, Matt, I should've asked you this question at the Analyst Day. But 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?

Our intention is to make that commodity agnostic; for the most part, we’re looking to get sustainable cost reductions through this effort. Now we’re going to get some fluctuations associated with exchange rates and changes in the deflationary environment, but our focus is on getting structural cost reductions that we can sustain through the cycles.

I’d like to ask about the price realization. It seemed 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 perhaps some of the differentials we have seen, or a mix of production, like oil, condensate, NGLs, et cetera, working its way through? And the final part of the question, as prices have been recovering, does that help in realizations as we think about Q2 and Q3 potentially?

In the first quarter, realizations were probably weaker than what people were expecting, primarily in the Lower 48. For example, our Lower 48 crude oil realization was closer to $40, where WTI was like $48.50 for the quarter. What we’re seeing is a tough quarter for realizations; there’s a lost supply in the marketplace. The differentials we saw in the first quarter were not that different from the 50 price environment compared to when we were at much higher price environments, but they were tough across all commodities for us in the Lower 48, including tough differentials on NGLs, oil, and natural gas.

I was just wondering; was that a function of any more lighter crude that you are selling or condensate barrels? Or just it is what it is?

It's just the market conditions in the first quarter; nothing fundamentally changed in our product mix or the quality of our products that we are selling that would lead to that kind of differential.

Your guidance for exploration in the dry hole of $800 million for the year—you said it is unchanged. But it looked like Q1 was well above your annual run rate. So does that imply that there is going to be significant reduction in that expense line item as the year progresses?

Yes, it does, and by its nature, dry hole costs are going to be pretty lumpy. We happened to have both the Harrier well and the Omosi well hit in the first quarter. You could have quarters where the numbers are really low; no well actually gets to TD during that quarter, and it could be lumpy again later in the year. But as we look at the overall balance of the year, we think the guidance we gave at the Analyst Meeting still makes sense.

Okay. And then, you've talked about some of the areas where you are 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?

What we’re seeing is a more rapid response in the Lower 48 and parts of the company; we expect to see some deflation kicking in. We’re already seeing some in our international business, but it’s coming more slowly there. It’s what we have anticipated. We do expect to see those reductions coming internationally over the next several months.

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 are seeing? Second, within your portfolio where do you see the most relevance? If you could frame that on a risk-reward context, please.

Yes. We have been running some refracs in our portfolio using diverter-type technology, some just basically straight-up pumping new fracs with existing pairs and somewhat new paths, so we’ll be testing a few. The area where 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, particularly in wells that were drilled a few years ago and more recently drilled wells, so we are continuing to evaluate that; there’s certainly some upside potential.

That's terrific. We appreciate everybody's questions and comments. Feel free to reach out to us if you didn't get your questions answered. But 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.