康菲 (COP) 2017 Q1 法說會逐字稿

Welcome to the first-quarter 2017 ConocoPhillips earnings conference call.

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

(Operator Instructions) Please note that this conference is being recorded.

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

You may begin.

Thanks, Christine.

Hello, everybody, and welcome to our first-quarter earnings call.

Our speakers for today will be Don Wallette, our EVP of Finance and Commercial and our Chief Financial Officer; and Al Hirshberg, our EVP of Production, Drilling and Projects.

Our cautionary statement is shown on page 2 of the presentation materials we've provided.

We will make some forward-looking statements during today's call that refer to estimates or plans.

Actual results could differ due to the factors described on this slide and also described in our periodic SEC filings.

We will also refer to some non-GAAP financial measures today to facilitate comparisons across periods and with our peers.

Reconciliations to non-GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and also on our website.

Finally, during this morning's Q&A we will limit questions to one and a follow up.

And now I will turn the call over to Don.

Thank you, Ellen.

I'll start by covering a few highlights from the first quarter.

Then Al will close with more on our operational results and what to watch for the remainder of the year.

I'll begin on slide 4 with a summary of the first quarter.

2017 is off to a good start for the company.

We continued to deliver strong underlying performance, both operationally and financially, but the biggest news of this quarter was the progress we've made strategically.

So let me start there with the left side of the chart.

Consistent with our cash allocation priorities, we grew the dividend 6%, we paid off $800 million of debt, and we repurchased 2.2 million shares.

In total, we've announced over $16 billion of dispositions, along with our intent to use a significant portion of the cash proceeds for debt reduction and share buybacks.

These strategic actions mean we've not only accelerated the 3-year plan we laid out in November into less than 1 year, but greatly exceeded it.

We are on track to close the Canada transaction this quarter and the San Juan Basin transaction in the third quarter, so we are making rapid progress on our transformation.

Moving to the middle column.

Financially, we had an adjusted loss of $19 million.

Our first-quarter results included dry hole expense of $101 million, which accounts for the slight variance to consensus.

This quarter, we generated $1.8 billion in cash from operations, excluding working capital.

This exceeded capital and dividends by over $0.5 billion.

Our adjusted operating costs were 6% improved compared to the first quarter of 2016.

Finally, both S&P and Moody's improved their rating outlooks on the company after our announced dispositions.

In terms of day-to-day execution, our operations are running well.

We exceeded the high end of our first-quarter production guidance, delivering 2% underlying production growth year-over-year.

In the Lower 48, we are executing our drilling program in line with our plans, and we expect to average 11 to 12 rigs for the year.

Bottom line, we remain on track to meet our 2017 operational targets, which Al will cover in a few minutes.

If you turn to slide 5, I'll review the quarter financials in more detail.

This quarter, Brent averaged about $54 a barrel and Henry Hub averaged about $3.30 an Mcf.

This resulted in an average overall realized price of about $36 a barrel.

We reported an adjusted loss of $19 million or $0.02 a share.

Year-over-year, adjusted earnings improved nearly $1.2 billion.

The biggest driver was a 58% improvement in realized prices, but we also benefited from the actions we've been taking to improve our cost structure.

Sequentially, adjusted earnings improved about $300 million.

The benefit came primarily from improved realizations and lower cost.

One way to think about this quarter is that with $54 Brent on an adjusted basis, we were very close to being profitable.

A year or so ago, we would have needed oil prices in the mid-$60s.

That's how much improvement we've made, and those improvements also drive cash flow.

First-quarter adjusted earnings by segment are shown on the lower right.

3 of the 5 producing segments were again profitable this quarter.

Both Canada and Lower 48 showed significant improvement on the path to profitability.

The supplemental data on our website provides additional segment financial detail.

If you turn to slide 6, I'll cover our cash flow waterfall for the first quarter.

Here's our typical cash flow waterfall, which you are familiar with, so I won't go through each element, but I do want to add some color to a couple of items.

While we generated $1.8 billion of operational cash flow, ex working capital, we had 2 items in the quarter that I would not expect to factor into future quarters.

First, we had a hedged cross-currency swap contract from British pounds to Canadian dollars that was put in place pre-Brexit but matured this March.

So at the termination of the contract, we realized about a $200 million currency loss due to the sterling devaluation over that period, which adversely impacted cash flow.

Second, our cash flows in the quarter benefited from the recapture of tax loss carryforwards in Libya when crude oil exports resumed in late 2016.

We had 4 liftings during the first quarter, and cash flow benefited by about $100 million due to the tax recoupment.

So those items netted to an overall adverse impact on operating cash flow, ex working capital, of about $100 million.

Also of note, we paid down $800 million of debt and made distribution to shareholders of $400 million between dividends and share repurchases.

I should point out that we suspended our buyback program during the quarter as we worked to progress the transaction with Cenovus.

Shortly after the public announcement of the deal, we resumed repurchasing shares.

And as we've previously announced, we plan to complete the $3 billion of buybacks this year.

As you see, we ended the quarter with $3.4 billion in cash and short-term investments.

In summary, our focus on free cash flow generation and the lowering of our breakeven price is showing up in our financial performance for the third straight quarter.

We're delivering on our cash allocation priorities, and the business continues to run well.

I'll hand over now to Al to review the quarter's operations in more detail.

Thanks, Don.

Well, we've had another good operational quarter with strong performance on production, capital and operating costs.

If you'll turn to slide 8, I'll cover some operational highlights from our Lower 48 and Alaska segments.

For the quarter, production, excluding Libya, increased to 1.58 million oil equivalent barrels per day.

That exceeded the high end of guidance and beat the midpoint by 24,000 barrels per day.

As Don said, once you adjust for 2016 asset sales and downtime, it was an underlying increase of 2% compared to our first quarter production last year.

We accomplished this production increase while maintaining our discipline on capital and operating costs throughout the company.

Lower 48 unconventional production averaged 221,000 barrels per day for the quarter with the Eagle Ford at 133,000, the Bakken at 59,000 and the Permian at 17,000 barrels per day with the balance in Barnett and Niobrara.

This result is a 2% decline versus the same period last year.

On the last call, I mentioned the low point for unconventional production was expected to be in the second quarter of this year.

We now see the inflection point behind us in the first quarter.

In April, we reached 12 rigs in the Lower 48 as planned.

We're currently running 5 in the Eagle Ford, 4 in the Bakken and 3 in the Permian.

In Alaska, production increased 3% compared to the first quarter of 2016 when adjusted for asset sales.

Through the winter construction season, the Greater Mooses Tooth 1 ice roads and associated key infrastructure components of the project were completed.

This keeps us on track for first oil by the end of 2018 at GMT1.

The 1H NEWS drill site facilities are complete, and first oil is expected by the end of this year.

Following our 2016 exploration discoveries and success at the December lease sales, we completed shooting 3-D seismic in the GMT unit, which includes our Willow discovery.

If you turn to slide 9, I'll cover some operational highlights from the remainder of the portfolio.

At our Surmont operations in Canada, we reached a record production rate of 128,000 barrels per day gross, just before a disruption of third-party diluent supply forced curtailment of the field.

We're currently operating at about 2/3 of the pre-disruption volumes, but we expect to return to our planned ramp this month.

At this time, we do not anticipate this disruption to have a material impact on full year Canada volumes, although it negatively impacted first quarter volumes by around 5,000 barrels per day.

In the U.K., commissioning began for the Clair Ridge production platform.

This is another important step for this project as we move toward first production in early 2018.

In April, the Aasta Hansteen spar left port in Korea en route to Norway.

The project is on track, and first production is expected by the end of 2018.

Moving to Australia.

APLNG continues to operate well, and the first turnaround at Train 1 was successfully completed in April.

27 LNG cargoes were loaded in the first quarter.

We're continuing to hone in on the range of resource for the promising Barossa development to backfill the Darwin LNG plant.

The successful Barossa-5 appraisal well increased the estimate of gas in place and significantly reduced the downside uncertainty.

The Barossa-6 well is currently drilling.

And finally, in Malaysia, after full commissioning of both gas trains, the Malikai development continues to deliver better-than-expected production rates.

The project will continue to ramp after the planned KBB-Malikai turnaround currently underway.

So those were just a few operational highlights from the quarter.

Now let's move to slide 10 to discuss the remainder of the year.

As we move forward in 2017, we're on track to deliver on continued strong operational performance.

In the Lower 48, we expect our unconventional production to increase throughout the year with an exit rate of around 250,000 barrels per day while maintaining the average of rigs at around 11 to 12.

In the next two quarters, we have planned turnarounds in Alaska, Europe and the APME segments that will impact production.

The table on the left provides some perspective on how key operational metrics will be affected for our two announced asset sales.

Given that we don't know the exact dates of closing for the sales transactions, the table shows the metrics both with and without these sales.

On the left are the numbers excluding any impact from dispositions.

The numbers on the right are pro forma guidance numbers, assuming both the Canadian and the San Juan dispositions had closed on January 1, 2017.

As Don said, we expect Canada to close sometime in the second quarter and San Juan in the third quarter.

We will update guidance during the year as those transactions close.

In the appendix, we provide additional guidance on each of the two dispositions.

But the bottom line is this: underlying performance is on track to meet or exceed our budgeted plans.

And finally, please save the date for our 2017 Analyst and Investor Meeting.

This year's meeting will be held on November 8 in New York.

We're on a fast track to transform ConocoPhillips into a company that thrives at today's oil prices.

We look forward to updating you on strategic progress and providing a deep dive into our unique portfolio.

Now I'll turn the call over for Q&A.

(Operator Instructions) And our first question is from Phil Gresh of JPMorgan.

My first question is just on the second-quarter production guidance.

I just wanted to make sure I understood it on an apples-to-apples basis.

I understand that you don't have the asset sales in there that have been announced, but I just want to go back to the 2Q16 to make sure I understood those numbers, because you did have some asset sales in 2016 as well that you were talking about when you discussed the 1Q performance.

So is the right base from 2Q16 1.546 million, so the midpoint would be down 2% year-over-year?

Or am I looking at that the wrong way?

Hang on, Phil.

We're looking here.

Yes, 1.546 million is the actual from Q2 last year.

So because 1Q you were up 2% year-over-year.

So I was just trying to tie that to the midpoint being about down 2%.

I think you mentioned that there's some maintenance in the second quarter of this year.

I'm just hoping to understand a little bit better some of the moving pieces there.

Yes, the 1.546 million, though, does not have adjustments in it for sales that have happened since then, like Block B, yes.

So I don't think it's right to take that number and then compare it directly to 2Q.

This -- you would -- that would be missing the adjustments for sales since then.

We can take that offline, Phil.

But our 2Q off this quarter does include the delta between its dispositions, and it does include the delta on planned downtime as well.

Yes.

In the 2Q number, there's a significant turnaround downtime built in, but that's not so different from last year either, so...

Okay.

And then second question, maybe just to follow up on the buyback commentary.

So you obviously were blacked out for a period of time there.

But it sounds like you're committed to the $3 billion number for the full year, which would imply you're going to go from like a $100 million run rate in the first quarter to something closer to $1 billion for the next three quarters?

Is that the right way to think about that?

Yes, Phil, I think that's a reasonable assumption.

Our philosophy is to dollar cost average mostly, so it'll be pretty consistent over the quarters.

Our next question is from Ryan Todd of Deutsche Bank.

Great.

Maybe to start out with one on capex.

The capex run rate in the quarter was certainly well below kind of the full-year guidance on a quarterly basis.

Can you talk about what was driving that and some of the moving pieces that will drive the trajectory of quarterly capex throughout the year?

Sure.

The -- yes, the quarterly came in at about $950 million.

So if you take the run rate times 4, you get like a $3.8 billion kind of number.

We do still expect to spend $5 billion on the year.

It's interesting, though, that we were able to continue to grow volumes even at that lower capex rate.

I think -- so partly it does reflect our continuing capital discipline and our success in resisting some of the inflationary forces that are out there.

But we did have in the quarter some more roll-off in project activity, particularly in our APME region.

Malaysia, Indonesia, some lower project activity.

Our exploration capex was lower, a bit of a timing thing in the first quarter.

Our capex in places where we are ramping projects like Alaska and places like L48 where we were coming up on rigs was increased.

But just to give you perspective around the Lower 48, where we have our biggest ramp going on, we came into the quarter at 8 rigs, and we exited the quarter at 11 rigs.

We're now at 12.

And of course, the majority of the costs associated with that rig is associated with the completions and the completion work comes along behind that.

And so that's still ramping.

And so I think that will be a key driver that will push our quarterly capex numbers up going forward through the rest of the year.

And I expect that we will spend that $5 billion, even though you don't see it in the first quarter pace.

That's helpful.

And then maybe just want to follow up on your -- on the U.S. onshore.

Can you talk a little bit -- I mean, you -- the comments that you had previously that you expected a trough in 2Q, it looks like you're going to trough in 1Q now.

You were able to hold production relatively flat quarter-on-quarter versus 4Q16.

Can you talk about some of the things that drove the better-than-expected production?

The exit rate looks like it's a little bit above the kind of 5% to 10% exit rate increase that you had talked about on a previous call.

So can you run through some of the things?

Maybe is it earlier activity?

Is it better well performance?

What's driving the better-than-expected production out of the Lower 48?

Yes.

No, Ryan, I think you're right.

We are continuing to see better-than-expected numbers there.

Our first-quarter production out of this piece of our business was up 2%, 3% over what we were predicting, say, a quarter ago.

And it's the continuing drumbeat of improvements from technology and other efficiency drivers, things like data analytics, that are helping us continue to get more and more efficient in the results that we get there.

So we -- I think that -- last quarter, I said I thought that on a full-year basis that 2017 would be 5% to 10%, somewhere in that range, lower than 2016.

I think it's clear, just from the progress we've already made so far this year, that we'll be at the low end of that decline range, if you will.

So we'll do better.

Instead of declining 5% to 10%, we'll be closer to the 5%.

If you look at it 4Q to 4Q, I said on the last call I thought we would be up 5% to 10% 4Q of '16 to 4Q of '17.

I think you're right.

It's already clear that we're at the very high end of that guidance now, that we'll be at the top end, just based on what we see so far.

And it's consistent with this idea that at 11 to 12 rigs we said we would grow 10% to 15% based on that chart we showed you back at the Analyst Meeting.

And I think it's clear from the progress we made so far that we're on the upper end of that kind of range, if not beating it also.

And is it safe to assume that your estimates here are based on the fact that in the current environment that you pause here at 12 rigs and the rig ramp doesn't go any further beyond that?

In -- yes, that's right.

In 2017, as we've said before, we don't plan to go above this kind of 11 to 12 rigs for 2017.

And so all those numbers are based on continuing with that same scope that we've laid out in the past; no increase.

Our next question is from Paul Sankey of Wolfe Research.

You said that you'd bottomed sooner than expected in the Lower 48.

Is the rig count that you've got there, the 12, what's the progression now anticipated, if it's changed at all?

And could you break that down by -- between Eagle Ford, Bakken and Permian, please?

Well, like we said a minute ago, the rigs are 5 in the Eagle Ford, 4 in the Bakken, 3 in the Permian.

The Permian there's -- 2 of those are in the unconventional, and 1 is in the Permian conventional.

I apologize because I did completely miss them.

Go ahead.

Yes.

And so we do plan to do some work in the Niobrara this year.

And so some of these rigs may bounce up and down a little bit, but I expect to be in the 11 to 12 kind of range all year.

Where would you think that goes next year, Al?

Well, it's -- that's a 2018 capex question.

It's just too early to say.

We'll obviously be watching the macro environment as we go through the year, and that includes where the cost and inflationary environment is going as well to sort of see how we judge that.

But it's just too early to say.

I imagine we'll be talking about that at our Analyst Meeting come November, about what our plans are for '18.

Great.

I just have a follow-up.

And apologies if that previous question was somewhat already asked.

When you look at the proceeds that you've got from these big disposals, and I'm also thinking back to conversations you and I have had about Kashagan in the past, you're getting really outstanding valuations relative to where your stock trades.

Is there not a strong temptation to re-up the disposal program, Al?

To re-up?

I mean, I guess -- I mean, we talked at the Analyst Day just not too long ago, last November, about $5 billion to $8 billion over 2 years, 2017 and '18.

And we've already announced, what is it, $16 billion?

Over.

Over $16 billion and have said we still -- we're still going to continue with the rest of our program and get probably another $1 billion to $2 billion as we...

Yes, I guess it's the upside to the $1 billion to $2 billion is what I'm driving at.

Couldn't you add another leg to this when the valuations are so attractive to you?

We don't have any plans to do that right now.

I mean, that -- we identified from a strategic standpoint the kind of assets that we wanted to sell.

And part of the consideration there was which types of assets did we think we could get good value for in today's market.

And so that's how we put that list together.

And I haven't seen any fundamental change in the market that would make me want to change that right now.

Our next question is from Paul Cheng of Barclays.

I think the first question is for maybe both for Don and Al.

Have you guys received any dividend payment from the APLNG at $54 Brent?

And also that, Al, can you talk about Queensland LNG export quota, what kind of timeline and decision-making process we should be able to monitor to understand that -- how that process?

Okay.

I can comment on both of those, I guess.

The -- I mean, we're in the -- we have not received any distributions so far this year from APLNG.

Of course, that cash sort of builds inside the joint venture, and then the joint venture decides when to make distributions.

But we are in that kind of range where we're -- as we move in the kind of $50s that -- and ramp up -- and as we ramp up our volumes that you would expect to start getting some distributions.

With regard to the export licensing, the government of Australia has announced some key principles around that just here recently and have said they'd like to put it into effect by July 1. With regard to that, we're, of course, very engaged with the government and the details around how we're going to -- how this regulatory -- how these regulations are going to roll out.

And we can see that APLNG is very well positioned relative to what the government is trying to do here.

Their focus is on wanting the LNG export projects to be net domestic gas contributors, is what they call it, which just simply means that of all the production that we control and it's -- and a portion of which goes through our LNG plant, that we also are a net provider to the domestic market.

So we may be buying gas on the domestic market, selling gas, but we need to net provide gas.

And APLNG has always done that and has a firm plan to continue to do that.

In fact, APLNG provides about 20% of the domestic gas on the East Coast market in Australia.

So because of that and the way they've laid the rules out, we don't expect that there'll be any impact on APLNG exports from these new rules as they come into detailed regulations.

Okay.

Second question I think is for Don and maybe also for Al.

Don, how much is the debt you may be able to buy back or pay down without any penalty over the next two years?

And in terms of the dry hole, do we still see a lot of exposure for the remaining of the year or that those are behind us by now, after the first quarter dry hole?

Well, maybe the second question first, Paul.

As far as dry holes, we had about $100 million dry hole expense in the first quarter.

And I think our guidance on that for the year was $200 million.

So we've taken a look at that.

We haven't changed our guidance.

We're pretty comfortable that we'll be somewhere around the $200 million range when we look at the program and the way that the risk is distributed across the quarter.

So no change to the $200 million guidance.

As far as debt repayment, we've said that we want to reduce our balance sheet debt down to $20 billion this year, which is nearly $7.5 billion of reduction.

Your question was around how much can you reduce without a penalty.

What we're doing in this first phase, if you will, to get down to $20 billion is basically focused on near-term maturities and the term loan that we have out there in 2019.

The term loan has no penalties associated with it.

The balance of these -- of the debt that's going to be retired this year will be retired through make-whole provisions.

I don't know if you consider that a penalty, but we will pay a premium over the par value on the bonds.

But since they're such near-term maturities, the penalty is fairly modest, or the make-whole premium is fairly modest.

And so what I'm looking at is cash efficiency.

And we believe we can retire that $7.5 billion of debt.

We'd spend about $1.04 roughly to retire each $1 of debt.

So that's pretty efficient.

Our next question is from Ed Westlake of Credit Suisse.

A question just on inflation and deflation.

I mean, obviously your program is spread across the Eagle Ford, Bakken and Permian.

The Permian is where people think inflation is the most severe.

But maybe any comments of what you're seeing in the other basins.

And then you did touch on it, that some of it's timing on capex, but maybe just some -- any comments on deflation in the non-shale spend of the $5 billion program that you're seeing?

Okay.

I would say, at a high level, there's really been no big changes in my views about inflation for this year versus the comments I made on the last quarter call.

If I look at our spending year-to-date, where we track this every month, we are still net deflation year-to-date as a company.

So we would certainly experience more deflation in our costs year -- after the first quarter in '17 versus '16.

And there's a mix there.

As you correctly point out, I think the Permian is hotter than some of the other Lower 48 unconventional areas.

But all of the Lower 48 unconventional is experiencing some pressure, although actually only in certain business lines.

I mean, it is variable.

We're experiencing inflation in the Lower 48 in pressure pumping, proppant, cement, tubulars; those kind of categories.

But we're actually still experiencing deflation on some of our labor costs, oil field chemical costs.

Some of our fabrication costs in the Lower 48 are lower than they were last year.

And so we -- there is some mix there, but overall, because we are still experiencing significant deflation internationally, that, plus the little bit of help we're getting from some of our fixed contract pricing in the Lower 48, is more than offsetting that and allowing us to be net deflating so far this year.

That's very helpful.

And switching it around geographically, I mean, Alaska seems to be a real progress area.

Obviously, you gave guidance on the production potential out to 2021 at the Analyst Day last year, which included some of these projects that you're starting up.

Is there anything that you can do to drive production harder before 2021?

I know you -- on the last call you mentioned that the Willow discovery was maybe 100,000 barrels a day, but that was 2023.

I'm just trying to get a sense of the levers to lean into Alaska as you get more confident in the resource space and maybe oil picks up.

Yes, I think we have a lot of continuous coil tubing drilling work there, rotary drilling work there, so we have a fairly continuous program that's -- a lot of which is driven by different kinds of new technology that allow you to see where to drill.

And so you do have some ability to change the pace of that work.

And also, our -- as we continue to march out GMT1, GMT2, our next projects, you maybe have some control over the pace of those.

But -- and recall on Willow, when I said 2023, I think I said that the most important thing driving timing there was the permitting process and that, based on experience from the past, 2023 would be the earliest.

That would be if we had a cooperative federal permitting process.

Our next question is from Doug Terreson of Evercore.

I have a few questions that I think are probably for Don.

First, can you provide some specificity on the deferred tax item in the quarter in that it was fairly high and also any insight as to how it may trend in the future?

Sure, Doug.

Yes, the deferred tax use in the first quarter was very high at $1.2 billion.

It does stand out, so I'm not surprised you're asking about it.

But that was mainly driven by that large financial tax benefit that we had on the Canadian transaction that we booked during the first quarter.

If you remember, that was like $1 billion or so.

So when you remove that and a few other special items, nonrecurring type items, you would -- we would get down to about $100 million use of cash for the quarter, which is right on line with what we would expect and probably more in line with what you would expect.

Okay, okay.

And then second, just to clarify, and getting to your debt reduction target of $15 billion in 2019, it looks like you're assuming Brent prices of only $55.

So number one, to clarify that figure; two, ask what divestiture proceeds are included in that outcome; and then three, is it correct to assume that debt to total cap -- or net debt to total cap in that scenario is less than 10% in your scenario by that point in 2019?

Is that about right, Don?

Oh.

Well, as far as the planning scenario, I think what we've shown is around $50 Brent plan over the next few years.

That's what we're planning for.

And as far as what mix, what dispositions contribute to the debt reduction, it's a little -- it gets pretty fungible pretty quick.

I would say, based on these two transactions we've announced closing, that's $16 billion of proceeds.

You can look at our current cash balance.

If you use current strip going forward, we're going to end the year with a pretty large cash balance.

But we still have a bit to do in '17 and '18.

We've pretty much earmarked another $5 billion for debt reduction over those years and another $3 billion in share buybacks.

So that's $8 billion that's going to have to be funded from the combination of our cash balances, which are the result of the dispositions, as well as free cash flow that we're able to generate.

I don't know if that answers your question.

Doug, on net debt to total cap, I don't have that statistic handy right now.

But based on my projections as far as, say, CFO to net debt, I'm looking at a leverage ratio somewhere around 1.5, closer to 1.5 than the 2 that I've -- we've talked about previously.

Our next question is from Doug Leggate of Bank of America Merrill Lynch.

A lot of the detailed ones have been asked, I guess.

But I wonder if I could, a little prematurely, I guess, talk about major capital project spending and your thoughts beyond the current year.

And what was at the back of my mind was your comment on Barossa and some speculation that ConocoPhillips might consider an expansion of Darwin.

So just sort of big-picture comments on where you see major capital project commitments, on Darwin specifically.

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

Well, I think, consistent with what we've said in the past, I expect that we're not eager to get into any inflexible super major projects like -- things like APLNG and Surmont 2 anytime soon.

But we do have this nice pathway of semi-flexible midsized projects that we can modify the timing of that extend well out in time.

And so we'll be managing that as we figure out how much of our capital do we want to allocate to things that are flexible on the month and things that are flexible over a period of years.

And so we have a lot of optionality there and keep adding new things into the hopper, things like Willow up in Alaska.

But with regard to Barossa, I mean, we have Bayu Undan supplying the Darwin plant now, and it's coming toward the end of its life.

And so we know that we need to backfill with some new development, and Barossa is what's in our plans.

And Barossa fits into the current Darwin plant as it is.

We don't need to expand it.

There has been interest from many other parties in the area who have -- there's a lot of discovered gas off the coast there.

And so there's been interest from a lot of other parties in whether we would consider expanding the plant.

And so they've been willing to put up money to do some engineering study work to see what it might cost to do that, and so we've been supporting that effort.

But that's not in our current plans, to expand the plant.

But that possibility is being studied, primarily to see whether you could accommodate some of the other gas that's been discovered in the area.

You don't need it for Barossa.

Okay.

That's very helpful.

And I guess my follow-up is also for you, Al.

It really goes back to an earlier question about the pace of growth in the Lower 48.

I mean, obviously given the environment we're in right now and oil kind of struggling to break $50 on a sustainable basis, what's the governor for your growth targets for the Lower 48?

It's obviously not cash flow or cash, given the amount of cash you're going to have on the balance sheet.

But what's the right rate of growth as you think about the 12-rig program looking beyond 2017?

And I'll leave it there.

Well, I think for us you really have to go back to the priorities, those five priorities that we laid out back at the Analyst Meeting, where we've got this high return, disciplined growth capex that we have available as an option.

But it's competing with how we spend our cash on share buybacks and net debt reduction that Don was talking about a minute ago.

We don't plan to chase production growth into the cycle.

We're quite pleased with the amount of growth we've been able to get in the unconventional space just with -- at the rig levels that we're at now.

If you look at our -- if you look at entry to exit in 2017, even as we've been increasing our rig counts and really haven't gotten to steady state till here in April, you'll see on the order of about a 20% entry to exit growth rate for us in our Lower 48 unconventional.

So we'll be considering those trade-offs between how to use that cash as we work through our plans and establish, working with our Board of Directors, what's our 2018 capex level going to be and be talking more about that as we move back into the later part of the year and into the November Analyst Meeting.

Our next question is from Roger Read of Wells Fargo.

I guess coming back to the Eagle Ford shale and your guidance or your indication that you may perform at the top end of the guidance range, if you're not spending any more money, I presume that means it's the same well count but the wells themselves are more efficient or they're getting completed more quickly?

Maybe just a little enlightenment there, please.

Yes.

Well, Roger, it's some of both.

It's this continuing improvement year after year that really hasn't slowed down for us in the Lower 48 unconventional space, where we're getting better production, better recoveries and continuing to drill and complete faster quarter-over-quarter, year-over-year.

And so that's really what drives it.

We build some of that into our forecast when we lay it out.

But we've had a pretty good history here quarter after quarter of having it perform even better than the level of improvement that we've forecast.

Any particular item you'd single out or call out?

Well, I would say we haven't -- there hasn't been anything involved here that I would call a step change, so it's -- we're working on some step change items that -- for the future.

But I wouldn't say there's been a particular step change item that's driven this.

If I had to call out one thing that's really gained steam over the last couple years and is paying significant dividends for us now, it would be, just generically, data analytics, big data, where we've been able -- we've been working hard on that for quite a few years, but we've been able to standardize and drive it through more and more of our operations and have it much more handily helping us make day-to-day decisions on how to develop as a stronger force.

And I think that's probably -- if I had to pick one thing that threads through all of this, that's probably what I would say is the biggest trend driver.

All right.

I'm sensing a theme for November 8. And then switching gears a little bit over to you, Don.

Production out of Libya, and I recognize there are a lot of things moving around, but are there any prospects for cash flow from Libya in 2017?

Well, we had some pretty good cash flow from Libya in the first quarter, Roger.

I tried to explain that, that was -- a lot of that was due to tax loss carryforwards that had been built up during the couple of years that operations had been suspended, and when they resumed, that's the first money we get back.

So we're getting the lion's share of the cargoes that are -- or the proceeds of the cargoes that are sold.

We sold four cargoes, I believe, in the first quarter.

We're continuing to sell into the second quarter.

But the majority of that tax loss carryforward has been exhausted.

And we would expect, if production continues uninterrupted in Libya, that we would fully exhaust that carryforward during the second quarter, so...

Okay.

Sorry.

I should have been more specific.

Like after the loss carryforwards is there a -- does the business underlying generate cash flow or is it simply a recapture of the tax loss carryforward?

Yes, I would call it pretty modest cash flow.

Our next question is from Blake Fernandez of Scotia Howard Weil.

Question on the Lower 48 profitability.

It looks like a loss of about $170 million or so this quarter with oil averaging over $50.

Al had mentioned the inflationary pressures being experienced there.

I know we get some volume growth.

But is there anything that you can think of that would meaningfully change the profitability of the business?

In other words, at $50 to $55, should we just think that this is going to continue to be a net income negative business or is that a step change, also acknowledging, of course, the gas sales may impact some things?

Well, I'll try that one, Blake.

Of course, some of the things that we're doing on the portfolio we expect to be accretive to income going forward and profitability.

Obviously, we've taken a lot of measures over the last two years to reduce our cost structure.

Those efforts continue in the Lower 48, commensurate with the dispositions and other programs that we have underway.

So yes, on the first quarter pretax, I think that loss was around $260 million.

If you look back over the last, say, five quarters, at the pretax losses versus different prices, you'll see that it's about $500 million of profit improvement for every $10 increase in oil price.

Of course, there's a lot of gas price improvement going along with that.

So we're getting pretty close on the commodity side, but we've still got a ways to go.

I would say one other area of improvement, Blake, in that arena is our DD&A rates.

We have been seeing larger bookings across the unconventional as we get more time with that, and that has been driving down some very high DD&A rates.

And I expect that to continue as we get more experience and are able to book more proved reserves.

We really have pretty small bookings relative to what we know is there, and so that should continue to help our earnings.

I guess there's also the dry hole money that's built into those numbers as well.

Yes.

Over the last few years, of course, we had been active in the deepwater in the Gulf of Mexico and we'd incurred quite a few dry hole expenses.

In this quarter, we saw some dry hole cost there as well.

So we would expect that, that trend would abate with time.

That will improve our earnings.

That's helpful.

The only other question I had, and you may not have these numbers at your fingertips, but on your kind of post-transaction guidance of 1.145 million to 1.175 million of production, do you happen to have a comparable number of what that -- what those numbers were in '16?

Blake, I don't have those numbers.

We don't have those handy.

Can we come back to you on that?

Yes, absolutely.

No worries.

It won't be hard to do.

I don't have it handy.

Our next question is from Guy Baber of Simmons & Company.

Al, on the topic of big data and data analytics and the impact that has had on operational performance, it seemed as if your comments primarily applied to your U.S. unconventional operations.

Is that an accurate observation?

And then the question would be to what extent can those learnings and processes be applied globally across the product portfolio?

Where you might -- where might you be in that process or assessing that?

Yes.

No, that's actually not an accurate way to think about it.

Our data analytics work actually started outside the U.S. It's one of the things that we actually first started doing that work in the North Sea, and it made its way around the world from there.

And so it's been a powerful force for us.

I would say where the U.S. has led that effort is the early days of data analytics for us were really focused on operational efficiency, operating your rotating equipment better, that sort of thing.

And in the Lower 48 unconventional where you're drilling so many wells all the time, then data analytics was very helpful at helping to drive up our URs, make our completions more efficient our drilling more efficient.

And you get a lot of opportunities to practice, and so it has a quicker impact on your results.

And we also use it in the U.S. for -- to drive our uptime efficiency, to manage our equipment and to help our multiskilled operators in the field to be the most efficient they can be in terms of "What well do I work on next" and those sorts of things.

So it's really got universal use across the company globally and has moved from being an aboveground kind of thing that we use on equipment to being something that helps drive the work we're doing belowground as well.

That's helpful, Al.

And then I wanted to talk a little bit more about the key major project ramp-ups this year, the longer-cycle projects.

You mentioned that Malikai was exceeding expectations.

Can you speak to that a little bit, what might be driving that, where we are in terms of production versus peak capacity?

And then can you give us an update on the KBB gas project in Malaysia, how that ramp might be progressing towards full capacity?

Yes.

The Malikai project, we've just -- we've had better well performance, better reservoir performance than we expected.

We're still ramping there, so we're going to continue to get more benefits from that.

KBB has continued to be constrained by third-party pipelines downstream of it, and so there's been a lot of progress made on that.

During -- there's some additional work being done on those facilities while we're in shutdown right now.

We have an extended shutdown that we're on in KBB right now that -- and since Malikai gas flows through KBB also, it's got both of those shut in while we complete this turnaround.

And as we come up from that, we'll be doing some testing downstream of KBB to try and verify what gas capacity we have now through these third-party facilities.

And that should allow us to ramp KBB some more as we move back through the back part of the year.

And of course Malikai will be ramping as well.

Our next question is from Pavel Molchanov of Raymond James.

You've spelled out 5 Eagle Ford, 4 Bakken and 3 Permian rigs.

And recognizing that you do not have any near-term plans to add rigs, if you had the choice to add 1 additional or 2 additional ones, which of those 3 plays would be your first call on capital?

It's pretty clear that the next place we would add a rig would be the Eagle Ford.

The Eagle Ford is mature enough and has the infrastructure capacity that you could add a rig there and wouldn't have to spend any additional money on takeaway, etc.

And with all the pressure in other places like the Permian, the Eagle Ford has been a good place to operate with less pressure on inflation and better netbacks for the barrels that you're sending out.

So for us, all of the -- and we still have a lot of very high-quality acreage to be drilled, great drilling locations in the Eagle Ford.

So it's a pretty straightforward answer for us.

Okay.

And I just -- quick follow-up on Alaska.

You've mentioned that you are in the process of trying to sell the Kenai LNG plant.

Do you have any involvement at the moment in the Alaska LNG project?

Yes.

The Kenai LNG plant started up in the late '60s and really has just -- the area has sort of run out of gas to feed it.

And so it -- we've been marketing it, thinking it might have more value to others and have had some interest in it.

So that's something that's in progress.

The Alaska LNG project is a megaproject that's been -- that we've -- has had a lot of engineering work go into it, trying to find the most economic way to develop all the gas that's being recycled right now up at Prudhoe Bay.

The current embodiment of that project is that the state has taken over the engineering commercial work to drive that project forward, hoping to do it in a more tax-efficient way.

And we're supporting the state in those efforts.

And our last question is from Michael Hall of Heikkinen Energy.

Maybe kind of one in the weeds and one higher up, higher level question.

I guess first on the detailed one.

You just mentioned a difference in netbacks for your crude in the Eagle Ford relative to the Permian.

Are you seeing any differences in the way -- in the sort of pricing you're getting for your crude in the Delaware relative to the Eagle Ford as it relates to gravity discounts or anything along those lines at this point?

Well, I don't know about gravity discounts, but the Eagle Ford market has improved significantly over the last several years.

It's become a lot more competitive.

I guess a couple things are probably contributing to that.

One is the decline of supply in the Eagle Ford.

The other is the crude oil exports last year, which opened up new markets for the Eagle Ford.

So we are seeing netback improvements year-on-year at equivalent pricing of several dollars.

So it's become very competitive there.

So it sounds like maybe less about the Permian degrading, more about the Eagle Ford improving.

Is that a fair way to think about it?

Yes, that's probably fair.

Okay.

And then I guess the big-picture question, we've kind of hit on it a little bit, just trying to think about the non-shale or, let's say, non-U.

S. business, you guys have a pretty unique perspective as relates to kind of the deflationary impacts of improving productivity and efficiency outside of the U.S. I'm just curious if you can kind of compare and contrast how meaningful, how impactful that's been in terms of reducing stay-flat capital now versus expectations a year ago and how you think that might continue to progress in the years ahead, just big picture.

Well, I think it's been a not insignificant factor in driving down our -- particularly our capital but also somewhat on our operating costs as a company overall.

And we're -- in the first quarter, we continued to see some pretty strong deflation outside the U.S. as we were rolling to new contracts and maybe even a little more deflationary than we would have predicted in the first quarter.

And so that's been a continuation of a trend over the last couple of years.

It's certainly not the key thing that's been driving down our costs and driving down that sort of breakeven capex that we've talked about.

That's been driven more by other factors.

But inflation has been one of the significant piece -- deflation has been one of the significant pieces.

Our model predicts that we will continue to see deflationary forces throughout this year outside the U.S. internationally but that they'll be becoming smaller and smaller and that by the time you get to next year that you would stop seeing significant deflation even outside the U.S. and that would start to even up.

And so if we continue to see inflation in the Lower 48, I would expect, as we go from '17 to '18, that we'll start to have a net inflationary environment.

Thanks, Michael.

Christine, you want to wrap it up here?

Thank you.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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