康菲 (COP) 2015 Q1 法說會逐字稿

Welcome to the ConocoPhillips first-quarter 2015 earnings conference call.

My name is Adrienne and I will be your operator for today's call.

(Operator Instructions).

Please note this conference is being recorded.

I will now turn the call over to Ellen DeSanctis, VP of Investor Relations and Communications, ConocoPhillips.

Please go ahead.

Thanks, Adrienne, and welcome to all of our call participants today.

I am 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, and 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 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 risks and uncertainties in our future performance.

Again thank you for participating and now I will 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 to 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 in 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 are going to describe a quarter with strong production growth and good cost control, but one where weak commodity prices overshadowed strong operational performance.

If you will turn to slide 4 I will 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 Eldfisk II, Bayu Undan Phase III and the Brodgar H3 subsea tie-back.

We also advanced five major projects towards startup by the end of the year, and that includes our two megaprojects 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 and we are already moving the needle.

We've made significant progress on capturing deflationary capital benefits in our capital program, which we also outlined at our analyst meeting.

Strategically announced our new three-year operating plan that provides predictable growth for about $11.5 billion of capital per year.

We are 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 will turn to slide 5 for more of a discussion on our earnings.

Production came in at the high end of guidance.

We also saw improvement in our opening costs which, as we discussed at the Analyst Meeting, includes production and operating cost, SG&A, and exploration expenses excluding dry holes and leasehold impairment.

Those cost 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 cost.

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 on the lower right side 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 Omosi-1 dry hole in Angola.

If you will turn to slide 6 I will summarize our production results for the quarter.

Our production 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 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.

And of the 82, 61 of the improvement comes from liquids, that is mostly from oil sands in Canada, unconventionals in the Lower 48 and Gumusut in Malaysia.

Gas was up 21 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 and 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.

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 will 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 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 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 will 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 are 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 production 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 as we continue to work on lowering costs.

We could see further improvement in our cost guidance for the year, especially if the US dollar stays strong, but we are holding to the current guideline for now.

We expect cost to be higher in the second and third quarters as we go into heavy turnaround season.

We will 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 looked a little low on run rate, but we expect to end the year at about $9 billion.

This reflects mix shift changes in 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 are focused on executing a prudent plan and we're delivering on our operational commitment.

Now I will 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.

So 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 is 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 but, as we 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 deepwater Gulf of Mexico.

We currently have appraisal wells drilling at Gila and Tiber.

Unfortunately, Harrier was a dry hole.

Next I will 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, Falher 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 are seeing strong performance from Christina Lake and Foster Creek with production continuing to ramp up at Foster Creek Phase F. And 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 will 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 is already commenced and we are 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.

And 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 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 on line and the Brodgar H3 subsea tie-back well achieved first gas in March.

Enochdhu is also progressing on schedule and should start in the second -- in the third quarter.

Now let's review our Asia Pacific and Middle East segment 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 for 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 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 towards startup in the third quarter.

In our Other International segment we are continuing to focus on our exploration and appraisal programs.

In Angola we spudded the Vali well this month and we will 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.

Finally, in Libya our production remains shut in due to ongoing unrest and it remains out of our production guidance for the year.

I will wrap up my prepared remarks on slide 13 with some key activities to watch in 2015.

As Jeff mentioned, we are on track to deliver 2% to 3% production growth this year.

For the second quarter we expect to produce 1.555 million to 1.595 million BOE per day.

The key driver is the typical turnaround activity that you see in 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, so we will 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 and we expect to run 12 rigs through the second half of the year.

Moving to major projects -- we have five startups expected before the end of the year at Surmont 2, 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 spudded 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.

And 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 will continue to appraise our existing discoveries in the Gulf of Mexico.

So that is a quick review of the segments.

We gave you a lot of information at the recent Analyst and Investor Meeting, so there is 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.

So this ends our prepared remarks, now I will turn the call back to the operator for Q&A.

(Operator Instructions).

Douglas Terreson, Evercore ISI.

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.

And 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 if we could just get some color on what to expect on capital spending declines.

Yes, so, 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.

So it is pretty much in line still with what we discussed at Analyst Day and what we have been expecting for some time.

As we move from 2015 into 2016 we will see about a $2 billion reduction in capital associated with those projects.

But that won't be seen from startup immediately because we still have capital being spent on both of those projects through the end of the year.

But between 2015 and 2016 it is about a $2 billion reduction.

Okay, great, thanks a lot.

Doug Leggate, Bank of America.

Matt, one of the things that has changed since the Analyst Day, unfortunately you had a couple of dry holes from a sizable write off.

And I guess I am mindful that you had a lot of obligations on drilling this year in exploration.

But when you consider $1.5 billion on exploration relative to let's say M&A opportunities whether it 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?

And I've got a follow-up, please.

Clearly we are disappointed in the results we have 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 is 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.

And there, as we said, we've proven two different play types in the basin.

We are looking forward to getting back there.

Of course as you know, that is the nature of exploration.

In terms of the sort of longer-term role for exploration, I mean we see exploration's role to supplement the resource portfolio with additional opportunities to sustain long-term growth.

And we are exploring plays where we think we can do that at a competitive cost of supply.

And over the last five years or so exploration has delivered a lot of success.

Remember the Eagle Ford was an exploration success for us.

And during that time we have been building the deepwater portfolio, focused initially in the Gulf of Mexico.

And we already have significant discoveries there too, three discoveries in the Gulf of Mexico in addition to Senegal.

So 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.

But we see that as good discipline to make sure that we are only committing to exploration opportunities that we think we can compete against that and 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 will stick with this one.

But I am 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.

So where would you expect that to move towards let's say in a lower oil price environment should this continue?

And I will leave it there, thanks.

Okay, thanks, Doug.

Well, in the operating plan that we laid out a few weeks ago we are anticipating a level of about $1.5 billion this year, next year and in 2017.

We can revisit that to some extent, but that is our expectation as a sort of an average over the next three years.

All right, thanks very much.

Paul Sankey, Wolfe Research.

A couple of quickies.

You mentioned on Libya that you are shut in.

Is that for sure shut in or could someone else be producing those volumes?

And the follow-up, which is also fairly quick I think, is could you talk a little bit more about the Kenai sales?

I am not sure who is buying that or how you are selling it.

And then I have a longer-term follow-up.

So, Libya, yes, the production is shut in and we are confident that that is shut in in the Waha concession, so nobody else is producing it.

The Kenai, we started operations up this month.

We will sell their cargoes starting next month.

We are going to sell five or six cargoes and they are 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 the next catalyst in terms of news flow on those pilots?

Thanks.

Yes, thanks, Paul.

So we are running several different pilots in the Eagle Ford, in particular in the Upper Eagle Ford we are running I think it is seven different pilots across different parts of the Eagle Ford to test the triple stack concept that we talked about.

And just to understand what parts of our geographic extent of the Eagle Ford is going to be amenable to the triple stack development.

So those pilots are going to be drilled as we go through this year.

And we will start to see results as we head into next year.

So I don't expect it to draw any definitive conclusions on just how much of our aerial 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 and you don't see that early in the well's life.

And of course we are still running the stimulated rock volume pilot that we talked about.

And 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 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 we're anticipating, if I'm not wrong.

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 basically showed the production was the same as the Lower Eagle Ford.

And but we haven't tested yet is when those are drilled in the context of a pattern of wells do we see interference.

And that is what we are testing with these seven pilots that we are running now.

So there was actually a number I think that is 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 are confined with other wells.

We didn't actually make any real prediction about what we expect to find.

We would rather do that after we have seen the pilot test results.

Okay, and as you said, this is something that is going to take a bit of time to really -- maybe by next Analyst Meeting I guess?

Yes, it is possible but it may take even longer than that.

We don't want to jump the gun on it.

We are definitely encouraged, as we said a few weeks ago.

But we want to make sure that we are calibrating properly before we make any claims about what the incremental reserves will be, for example.

Got it.

Thank you all.

Paul Cheng, Barclays.

Two quick questions.

Matt, can you share what is APLNG, the cash operating cost and the tax regime?

We are 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.

So it's a typical like 10% on the royalty and 30% PPT -- or PRT?

This is actually not fully resolved yet.

There are some discussions still underway with the Queensland government on the nature of how the royalty will be calculated.

So I can't really give you a definitive answer on that yet, Paul.

(Multiple speakers) I will add a little bit to what Matt said on the tax side.

The taxes are actually paid down at the APLNG kind of corporate level.

And there is 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.

So, Jeff, does that mean that during the first five years that we should assume there's -- not really have the tax that APLNG need to pay?

I don't know that I could give you precisely of a number, that depends upon price levels as well.

But if we had current kind of prices that is probably not a bad assumption.

Okay.

And then, Matt, can you -- maybe I missed it.

Can you tell me what is the Eagle Ford, Bakken and Permian production in the first quarter and if you have any number you can share in terms of the exit rate for this year?

Yes, 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 significant conventional production, but on the shale side it was less than 10.

So what we expect to happen, Paul, is we -- 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.

So the fourth-quarter exit rate is going to be quite similar to the first-quarter rate on aggregate for the shale plays.

Okay.

And you start increasing the rig count next year again?

I think that is the current trend.

So we should assume that they will resume the growth or that the increase in rig count for next year will be only sufficient that you hold it flat.

It depends a bit on the pace of the build of the rigs back up.

But you should really assume that it is going to hold it flat.

Because by the time we get the wells back and running again we're through the drilling and completion and hook up and bringing them onto production.

We're actually going to see the declining production from those plays continue into the early part of 2016 and then start to increase towards the end of 2016.

And based on our current assessment of how we will put rigs back to work there, we'll probably be relatively flat from the average of 15 to the average of 16.

Thank you.

Ryan Todd, Deutsche Bank.

A couple questions.

There have been several recent new 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 -- were these other people approaching you?

Are these assets that you are marketing?

Are we still looking at kind of smaller $500 million to $1 billion size deals?

Any thoughts around that?

Yes, we are always with a portfolio of our size looking at what can we do in the way of portfolio optimization.

As we go forward we are not going to be pre-announcing that we are marketing particular assets.

You will hear stories probably out in the marketplace that we are testing values on that and that is what we will always be doing as part of a prudent optimization of the portfolio.

As we have said, I think it is prudent to think in terms of a company our size will do something with its asset portfolio every year.

And we talked about it, whether that is $1 billion or so a year is probably a good go by.

It really just depends on whether we are getting full value for the assets.

It is always about whether we can sell the assets for at least what we think we could receive for them in value if we kept them in our portfolio.

And we don't know what that number is going to be.

But there will be some level of asset sale.

Okay.

Thanks.

And 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 is the direction that you would expect in terms of crude realizations and activity levels in general in Alaska?

So we expect with the major projects that we are doing and the development drilling that we are doing in Alaska that we are likely to hold production relatively flat for the next three years and beyond that actually.

And we have a reasonably good representation of the overall Alaska production because we are in all three of the big production areas there, Prudhoe, Kuparuk and Alpine.

So I think if you are looking at sort of a 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.

We always have that option if that is what we choose to do.

Evan Calio, Morgan Stanley.

I know Conoco remains focused on your yield, bridging the cash flow neutrality, yet 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 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 activity levels in 2015 and 2016.

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

I think in the near term I am not sure we see a price level that would cause us to reaccelerate.

We are going to want to see what -- that if there is some acceleration of prices that it has got a more lasting effect as well.

I mean we are taking -- as you think about what is 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 AmericaN 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 is 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.

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 is going to be -- it could be enough that it would cause us to see a one notch downgrade from what is currently A1 at Moody's and A -- the middle single A with Standard & Poor's and with Fitch.

And as you have seen, all the agencies do have our credit rating outlook on a negative so they are anticipating that.

But once -- if that were to happen that would move us into a range where we are comfortable that there is 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.

Ed Westlake, Credit Suisse.

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 are continuing to work through our optimizations, Ed, that we discussed a little bit a few weeks ago, optimizing the completion design and the well end, the well placement and so on.

I wouldn't say there is anything fundamentally different going on there.

But we are moving towards more pad drilling, 90% of our wells will be from pad drilling.

But there is not a fundamental change there, the guys are just executing well.

And then on the shale program and obviously a massive cut in rigs, and obviously you do modeling on volumes probably to a far greater degree than we do from the outside.

But are there any risks that you under shoot on volumes or you feel pretty comfortable about the trajectory you just outlined?

I feel pretty comfortable about the -- the answer I gave earlier on what we expect of our Eagle Ford and 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.

And then coming back to Doug's question on do you know if 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 sort of hit what you think is sort of a peak operational cash flow?

Obviously whatever the macro gives at that point is a separate discussion.

So peak -- on both of them really for different reasons, peak operational cash flows in 2017.

For Surmont 2 it is because it takes a while, as you know, to build the steam chambers and ramp up production in the SAGD project.

And in the case of APLNG we will bring the first train on this year; it will be next year before we bring the second train on.

So the first year that will have both trains running will be 2017.

So in both cases it will be 2017 before they are fully contribute in their plateau rate and of course that rate will continue in both projects for decades.

Very clear.

Thanks very much.

John Herrlin, Societe Generale.

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 we are probably -- overall we are probably running three or four.

It varies a little bit, but I think three full-time and four if we -- occasionally.

So that is 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 is it for me.

Okay.

Yes, so we have had two dry holes there in the campaign, the first at Kamoxi, basically the reservoir wasn't developed there.

As you know better than most, these carbonate reservoirs are quite difficult to predict the porosity development and in the case of Kamoxi the porosity 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 that was feeding into Omosi was overcooked.

So two different reasons for the failures in those wells.

And that basin as a whole is a bit less predictable than we had hoped going in.

Okay, thank you.

The Vali well that we are drilling is actually testing a different play than the Omosi and Kamoxi wells were, so we will see how that goes.

Thanks.

Blake Fernandez, Howard Weil.

Jeff, back on the balance sheet discussion previously, I am just curious, can you remind me if Libya (technical difficulty)?

No, we have 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 would really need to do an impairment.

Okay.

Offhand do you remember what kind of capital employed or anything on that asset?

I don't know that I know that number off the top of my head.

It is on the order of $0.5 billion.

But I wouldn't -- I am not sure exactly what that number is.

No worries, that's fine.

The second question, there has 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 has 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.

So we wouldn't really think about doing it for one particular part of our portfolio.

Generally our philosophy that we have talked about before hasn't changed.

But we feel like hedging is by definition a kind of zero sum game in terms of value and one of the reasons we keep a strong balance sheet is being able to handle the fluctuations in commodity prices.

Fair enough.

Thank you.

Neil Mehta, Goldman Sachs.

So there has been a lot of talk, sticking with the Lower 48, at what price signal does US shale production start re-accelerating?

And as a major US 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.

And how quickly can the industry bring back that production and what potential bottlenecks to bring that supply back online are?

Neil, I can't speak for the industry as to what price signal they might be looking for and the same would be cash flow will have a big impact on that as well.

But in our plans we are planning the increases in 2016 modestly but we are going to increase as we move into 2016.

And that is in the anticipation that there will be some continued recovery in prices.

In terms of the capacity, clearly we have laid down quite a bit of rig and completion capacity.

And that can be brought -- that can be brought back relatively quickly as a flexible industry that we had in the Lower 48.

So 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.

So I don't think I answered your question very satisfactorily, but that is about the best I have 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?

No, our intention is to make that commodity agnostic for the most part where we are looking to get sustainable cost reductions through this effort.

We are going to get some fluctuations associated with exchange rates and with changes in the deflationary environment.

But our focus is on getting structural cost reductions that we can sustain through the cycles.

Thank you very much.

Roger Read, Wells Fargo.

I guess I would like to ask about the price realization.

It seemed a little bit -- well, at least relative to our expectations -- a little weak in the first quarter both on oil and gas.

And 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 have seen or a mix of production kind of oil, condensate, NGLs, etc., working its way through.

And the final part of the question, as prices have been recovering does that help on realizations as we think about Q2 and Q3 potentially?

So, 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 or so for the quarter.

What we are seeing is just a tough quarter for realizations, a lot of supply in the marketplace.

Kind of the differentials that we are seeing are not that different -- 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 a much higher price environment, it is still kind of that same level of differentials.

I think we would expect to see kind of differentials improve in terms of kind of percent of marker realized and maybe some slight improvement in kind of absolute levels of differentials as well.

Okay.

The differentials were tough because they were kind of tough across all commodities for us in the Lower 48 as well.

It was tough on NGLs, oil and natural gas.

Yes, I was just wondering was there any -- I don't remember all the exact moving parts here, but I am just saying was that a function of any more -- either a lighter crude that you are selling or a condensate barrel or just it just is what it is?

I am just trying to understand.

Yes, it is a little bit just that is just what the market was in the first quarter.

There is nothing really that fundamentally changed in our product mix or the quality of any of the products that we are selling that would lead to that kind of differential.

Okay thanks.

And then an unrelated follow-up.

The change in taxes in the UK, give us an idea of maybe how you characterize that.

Is it that really helped?

It is 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 on a post-2017 environment?

Yes, Roger, I mean it helps, the UK sector needs as much help as it can get.

So the help on the tax rates was welcome.

The simplification and broadening of the uplift on capital is going to help us as well.

It is about a 12% uplift now on capital when you go through the math.

So we will build that into our thinking as we are thinking about our overall investment portfolio over the next few years.

But it certainly was a move in the right direction by the UK government.

Okay, thank you.

Pavel Molchanov, Raymond James.

Your guidance for exploration in dry hole $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 a significant reduction in that expense line item as the year progresses?

Yes, it does.

By its nature the dry hole cost is going to be pretty lumpy.

And 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 is really low if 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 kind of balance of the year we think the guidance that we gave at the analyst presentation 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 are not seeing the savings that perhaps you would have anticipated by this point?

Are you talking about operating cost, Pavel, or capital costs?

I guess more on the capex side.

Yes, so what we are 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 actually have seen some in our international business, but it is coming more slowly, which is what we would anticipate.

It's coming more slowly from the International business, but it has come very rapidly in the Lower 48.

But we are building -- we've built that sort of trend as we anticipated into our expectations of deflation.

And we do expect to see those reductions coming in the international over the next several months.

Okay.

Appreciate it.

Asit Sen, Cowen and Company.

Matt, just wanted to get your views on the recent industry debate on refracking in the unconventional.

And 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?

And second, within your portfolio where do you see the most relevance?

And if you could frame that on a risk/reward context, please.

So we have been running some re-fracs in our portfolio, some using the (inaudible) technology, some just basically straight pump and new fracs with existing perfs and some with new perfs.

So we've been testing a few.

The area that we are seeing the best uplift is, as you would expect, are older wells where we pumped smaller jobs with wider spacing.

So we see some potential there in this, particularly in wells that were drilled a few years ago.

Not in more recently drilled wells.

So we are continuing to evaluate that.

But there is some -- there is certainly some upside potential.

Okay, thank you.

I will now turn the call over to Ellen DeSanctis for final comments.

That is 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.

But we are 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.

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