康菲 (COP) 2014 Q1 法說會逐字稿

Welcome to the Q1 2014 ConocoPhillips earnings conference call.

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

At this time, all participants are in a listen-only mode.

(Operator Instructions)

Please note that this conference is being recorded.

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

You may begin.

Thanks, Christine, and good morning to everybody.

With me here today are Jeff Sheets, our EVP of Finance and our Chief Financial Officer; and Matt Fox, our EVP of Exploration and Production.

Jeff will cover the quarter's financial highlights and then Matt will take us through the quarter's operational highlights and provide some color on what to watch out for or what to pay attention to for the remainder of the year.

Then, we'll have Q&A, and we'll ask during Q&A if you would to limit your questions to two and of course jump back into the queue if necessary.

We will make some forward-looking statements this morning and the risks and uncertainties in our future performance are described on Page 2 of this morning's presentation materials, also in our periodic filings with the SEC.

This information as well as our GAAP to non-GAAP reconciliations and additional supplemental information can be found on our website.

Now, I'll turn the call over to Jeff.

Thank you, Ellen.

Hello, everyone and thank you for joining us today.

As you know, we just recently held our 2014 Analyst Meeting in New York where we reaffirmed our plans to deliver double-digit returns annually to our shareholders.

We outlined our production and margin growth plans for the next few years and hopefully gave you increased confidence in our ability to deliver on those plans.

We have an exciting year ahead and, as we reported this morning, we're off to a strong start.

So, Slide 4 lists our key highlights for the first quarter.

Operationally, we had a very good quarter.

We produced 1.53 million BOE per day from continuing operations, excluding Libya.

Adjusted for dispositions and downtime, this is up about 3% compared to last year's first quarter, so we're seeing growth.

We also made progress on key activities that will continue to drive organic growth.

We delivered on key milestones around our major projects and continued our strong performance in the unconventionals.

Exploration and appraisal activities continue during the quarter in the North American unconventionals, the Gulf of Mexico deepwater, Australia, and elsewhere.

These activities are key to our reserve and production growth beyond 2017.

Financially, this was also a very strong quarter.

We achieved adjusted earnings of $2.3 billion or $1.81 per diluted share.

This was quite a bit higher than expectations and I'll address some of the drivers of this stronger-than-expected performance on the next slide.

During the recent quarter we generated $4.4 billion in cash from our operating activities alone.

We also had positive working capital change of about $600 million and a distribution of $1.3 billion from FCCL, so total cash from operations was $6.3 billion.

And our balance sheet remains very healthy with over $7.7 billion in cash and short-term investments on hand as of the end of the quarter.

Strategically, we delivered on both production and margin growth this quarter.

We continue to expand our inventory of organic growth opportunities to support our growth goals and, importantly, we remain committed to delivering double-digit returns to our shareholders annually, including a compelling dividend.

So, all-in-all the first quarter was very strong operationally, financially and strategically.

So, now I'm going to turn to Slide 5 for a discussion on earnings.

First-quarter adjusted earnings of $2.3 billion were up 29% compared to last year's first quarter and up 30% sequentially.

Adjusted EPS of $1.81 was higher than consensus.

About a dime of the difference, or roughly $100 million, was due to North America natural gas price realizations that were stronger than the realizations indicated by changes in market prices.

Another dime or about another $100 million was due to gains from marketing third party natural gas during the quarter.

As a reminder, we have a strong commercial gas marketing organization that markets both equity and third-party gas in North America.

Given the high volatility in first-quarter gas prices, our commercial team was able to capture some benefit by supplying both equity and third-party gas into premium markets.

This benefit from our third-party activities is not necessarily repeatable, but it speaks to our strong marketing capability.

First-quarter segment earnings are shown in the lower right side of this chart.

The financial details for each segment can be found in the supplemental data that accompanied this morning's release, but let me address a couple items about the segments.

The Lower 48 earnings included the marketing gain I just talked about as well as strong realizations for natural gas.

Canada segment earnings were very strong, again reflecting stronger bitumen prices and gas realizations.

Gas realizations for the quarter were $5.81, reflecting both strong AECO pricing and the placement of some volumes in premium markets during the quarter.

Canada segment earnings also included an approximately $60 million benefit from foreign exchange, which was offset mostly by foreign exchange losses across other parts of the portfolio.

Alaska was pretty straightforward with nothing unusual to highlight in the quarter.

Europe operations performed well in the quarter with growth coming from several major projects, and if you'll look over the past several quarters we're starting to see the benefit of volume growth in this segment.

Our Asia Pacific and Middle East segment was impacted by lift timing differences in China and western Australia, but otherwise was in line with expectations.

And, finally, our corporate segment was in line with our previous guidance.

So if you'll turn to Slide 6, I'll cover our production results for the quarter.

As you know, our convention for production is continuing operations less Libya.

On this basis, our first quarter averaged 1.53 million BOE per day.

Normalized for dispositions, this compares to 1.495 million per day in the first quarter of 2013.

The waterfall shows that over the period we had 6,000 BOE per day more of planned and unplanned downtime than in the first quarter of 2013 and net growth of 41,000 BOE per day.

That represents a 3% increase compared to a year ago.

The box on this page illustrates the composition of this 41,000 BOE per day of growth.

As we discussed at our recent analyst meeting, we are growing in the highest margin portions of our portfolio and this growth of high-margin production is driving growth in the company's cash margins and we'll discuss that margin growth on the next slide, which is Slide 7.

This slide shows changes in our cash margins from the first-quarter 2013 to the first quarter of 2014 and also on a sequential basis.

On the left side of the chart are the margins on an as-reported basis, which were up over 20% year-over-year on strong natural gas prices and on the right are the margins on a price normalized basis.

So, on a price normalized basis margins increased 13% year-over-year.

Of this improvement, over one-third, or 5%, is due to our underlying liquids growth, especially in areas with more favorable fiscals.

The remaining 8% margin improvement was due to the benefits related to equity and third-party gas marketing activities that we just discussed as well as Libya being down.

So, we are delivering on our commitment to improved margins as we grow, not just generating growth for growth sake.

I'll conclude my prepared remarks with our cash flow waterfall, which is another good story, so I'll move that now to Slide 8. This shows our cash flow performance for the first quarter.

We began the quarter with $6.5 billion of cash and short-term investments on the balance sheet.

You can see we generated $4.4 billion of cash from operating activities, had a $1.3 billion FCCL distribution, and a working capital benefit of $600 million.

We had capital expenditures and investments of $3.9 billion, and after paying our dividends and retiring debt of about $500 million, we ended the quarter with $7.7 billion of cash and short-term investments on the balance sheet.

We've reduced our debt-to-cap ratio to 28% from 29% at the end of the year, so we're in great financial shape and well positioned to execute our investment programs for the company.

That concludes the review of our financial performance.

Now, I'll turn the call over to Matt for an update on our operations.

Thanks, Jeff.

Good morning, everyone.

So to begin, I'll provide a first-quarter operations update for each of our business segments, then I'll go over our production outlook for the remainder of the year, and I'll conclude with a preview of some key activities to watch out for, for the rest of 2014.

As we talk about each segment you'll hear a common thread throughout the presentation and that's growth.

As we progress through 2014 and into 2015, we expect to see growth in almost every segment of our business and we're not just growing volumes, we're growing margins.

Virtually all of our growing production will be at margins higher than our average margins today.

So, let's go to Slide 10, our Lower 48 and Latin America segment, which continues to lead the way on strong growth for the company.

First-quarter production averaged 507,000 BOE per day for this segment, which is a 7% increase from the first quarter of 2013 but, more importantly, our crude production increased 16% over the same period.

The biggest contributor to this growth was the Eagle Ford where we produced an average of 140,000 BOE per day during the quarter.

Our daily peak rate for the quarter was 163,000 barrels a day, so we achieved good momentum after the weather problems earlier in the quarter.

We currently have 12 operated rigs running in the Eagle Ford and we brought 48 wells online in the first quarter.

We're transitioning to the 80-acre high/low development spacing we outlined at our Analyst Meeting a few weeks ago, and we have additional pilots and progress testing further down spacing.

In the Bakken, we averaged 43,000 BOE per day and achieved a peak daily rate of 54,000 barrels a day in the first quarter.

We're also performing pilot tests in the Bakken to optimize our drilling and development programs.

Unconventional drilling and testing continues in the Delaware and Midland Basins in the Permian as well as in the Niobrara.

It's still early days, but as we said at the Analyst Meeting, we remain optimistic about these emerging plays.

In addition to our unconventional activities, appraisal drilling in the deepwater Gulf of Mexico continues at Tiber and Coronado, and exploration drilling continues at Deep Nansen.

On Slide 11 we'll give you some highlights from our Canada segment.

Operationally, our Canada business performed very well in the first quarter.

We produced 280,000 BOE per day, which includes a 9% increase in liquids production from the first quarter of 2013.

Surmont 1 debottlenecking is progressing and our major project at Surmont 2 remains on schedule for first steam in the middle of next year.

At the end of the quarter, the project was 68% complete.

Christina Lake Phase E is approaching full capacity and Foster Creek Phase F remains on track for first production in the third quarter of this year.

As part of our western Canada winter drilling programs, we successfully drilled 25 horizontal wells in the liquid rich plays across our significant acreage position.

This program continues to deliver good returns and holds a lot of drilling inventory, and we achieved a big milestone in the first quarter by drilling the longest horizontal well ever drilled in Canada, over 13,000 feet.

This is an impressive operational and technological accomplishment and it shows how we are continuing to optimize our programs.

We also continue to explore and appraise our unconventional plays in the Duvernay and Montney where we are seeing encouraging early results.

I'll now cover the Alaska segment on the next slide, Slide 12.

Alaska production was about flat sequentially at 200,000 BOE per day.

We remain encouraged by the improved fiscal terms brought about by the passage of the More Alaska Production Act last year.

And, of note, we plan to spend more capital in Alaska in 2014 than we spent there in the past three decades.

This increased investment will mitigate declines in legacy fields and provide growth from new satellite fields into the future.

We're making good progress at Drill Site 2S Project at Kuparuk, the Greater Mooses Tooth 1 Project in the Western North Slope, and the 1H North East West Sak Project.

That 1H NEWS Project is the third new project that has been initiated by the company since the passage of the More Alaska Production Act last spring.

We have had a good winter construction season at CD5, and we remain on track for startup in late 2015.

We drilled two exploration wells in the Western North Slope this winter, Rendezvous 3 and Flat Top 1, and we're in the process of evaluating those results.

We will resume LNG exports such as Kenai Plant with a contract signed to deliver six cargoes in 2014 with the first shipment this month.

In April, enabling legislation was passed by the state legislature to allow the State of Alaska's equity participation in the AKLNG Project, and this is a positive step forward for the project, but there is still a lot of feasibility work to do and we hope to move into pre-feed in the near future.

Alaska's become an attractive area for investment.

We've got a lot of activity underway that we expect will provide additional growth opportunities for this segment in the future.

I'll next cover our Europe segment on Slide 13.

Like the Lower 48, this segment recovered well from some very challenging weather conditions late last year and early in the quarter.

Production for the quarter averaged 220,000 barrels a day, which was about 12% higher sequentially.

Our last quarterly call we discussed the startup of Ekofisk South in Jasmine.

Eko South we're ramping up volumes in conjunction with drilling activity.

At Jasmine, we recovered from some minor startup delays and averaged 25,000 BOE per day for the quarter, and we brought a fifth well online at Jasmine in March.

We also commissioned and started up our new sour gas plant at the East Irish Sea.

Onshore construction activities are nearing completion at Eldfisk II for early 2015 start up and offshore commissioning is ramping up at the Britannia Long-Term Compression Project for startup in the third quarter of this year.

In Poland, we continue exploring in the Baltic Basin just to the west of Gdansk.

We completed two vertical wells and sidetracked one of them horizontally during the first quarter.

We're currently completing the horizontal section with an Eagle Ford style frac, and we intend to conduct an extended flow test later this year.

As you can see in the bottom left of the chart there's a heavy turnaround activity planned in the U.K. during the second and third quarters, which I'll discuss in a bit more detail on a later slide.

So, our Europe segment is positioned for growth from high-margin production this year.

Finally, let's look at our Asia Pacific and Middle East segment on Slide 14.

In this segment we produced 319,000 BOE a day, 9% higher than the fourth quarter, and over this period we also saw a 20% increase in high-margin liquids for this segment.

Our 1Q planned turnaround at Train 7 in Qatar was completed ahead of schedule.

In Indonesia we achieved first gas at the South Belut project in April, which is the fifth phase of Block B's oil and gas development.

We also achieved first oil in February at Siakap North-Petai, and our non-operated Gumusut project is progressing toward start up in the third quarter of this year.

At Kebabangan, our top sides are scheduled for sail away in the second quarter and we're on track for first production by the end of this year.

In exploration, we've drilled a successful appraisal well in Malaysia at Limbayong-2, and we remain encouraged by our findings there so there's clearly more growth potential in our Malaysia business.

APLNG also remains on track for a mid-2015 start up.

On a combined downstream and upstream basis we were 67% complete at the end of the first quarter.

Our appraisal programs continue in Australia at the Browse Basin and at the Barossa Field where wells spud in March and April, respectively.

Both of these wells should TD later in the second quarter.

We expect this segment to provide significant production growth over the next couple of years.

Before I move to the next slide, let me briefly touch on our other international segment.

The key activity in this segment is exploration related.

In Senegal we spudded the first well two weeks ago and in Angola our rig is now on transit to Block 36, and we expect to spud the Kamoxi well late this quarter or early in the third quarter.

I'll cover our production outlook now on Slide 15.

We showed this slide at our Analyst Meeting last month.

We slightly exceeded our guidance for first-quarter volumes, but otherwise our expectations are unchanged.

As you can see, we expect production to drop during the second and third quarters due to seasonal maintenance activities across our operations.

And on the left side of the chart is a list of the key turnarounds and tie-in activities for the next two quarters.

This activity will start late in the second quarter beginning in the U.K., but the majority of our turnaround activity will occur in the third quarter, and these turnarounds impact almost all of our segments.

The key activities in the third quarter will be in Alaska, Canada, the U.K. and the Bayu-Undan Field in the Asia Pacific region.

Bayu-Undan is particularly noteworthy as this is a 36-day shutdown that includes brownfield activity for the tie-in of two new subsea wells.

By the fourth quarter, our seasonal maintenance should be complete and additional projects should be coming online, and we expect to exit the year at or above 1.6 million BOE a day.

Full-year production guidance for continued operations is 1.51 to 1.55 million BOE a day excluding Libya, and this is unchanged from our prior guidance and in line with our 3% to 5% production growth target.

At this point, the biggest uncertainty in the range is the startup of our non-operated Gumusut project in Malaysia.

I'll now wrap up my comments with what to watch for in 2014.

With several activities underway to drive growth, major project startups are expected at Gumusut, Foster Creek Phase F, Kebabangan and our Britannia Long-Term Compression project.

These are important activities that should impact our 2014 exit rates and drive 2015 performance.

We also expect to continue growth both in the Eagle Ford and the Bakken.

We laid out some development program details at the recent Analyst Meeting and raised expectations for these plays over the next few years.

We'll continue our North American unconventional exploration and appraisal programs with a focus on the Permian and Niobrara.

We'll also test our unconventional play in Poland with the extended production test I spoke about.

The company also farmed into three additional blocks in Colombia last year where exploration will commence in the second half of 2014 to test the prospectivity of the La Luna shale.

Gulf of Mexico deepwater drilling continues at Tiber, Coronado, and Deep Nansen.

And we're also preparing to begin our operated drilling program late this year or early next year.

Finally, as I mentioned earlier, we'll begin exploration drilling in Senegal and Angola this year and, if successful, these programs would be catalysts for growth into the next decade.

So, here is what I hope you heard from our comments today.

2014 is off to a good start.

We fully recovered from some weather and startup delays early in the first quarter and exited the quarter in a strong position to deliver on our volume expectations for the year.

Our unconventional programs are performing very well and our major projects are ramping up or progressing towards startup.

We have another year of significant second and third quarter turnaround activity, but we are optimistic about achieving a 3% to 5% production growth in the year and the momentum will be able to continue that growth into 2015 and beyond.

Our exploration activities focused on drilling and testing a high quality set of conventional and unconventional prospects, and we should have a lot to update you on the coming months.

So, this ends our prepared remarks and we'll turn it over for questions.

Thank you.

(Operator Instructions)

Our first question is from Paul Cheng of Barclays.

Hi, guys.

Good morning.

Good morning, Paul.

Matt, on Foster Creek seems like it has been facing some operating issue, steam-oil ratio has been up and the cost has been quite high.

Can you give us an update?

What's the game plan and how confident you are that you can return that operation into say a couple years ago kind of operating cost structure?

These are short-term issues that we anticipated would happen as the steam chambers coalesced and you expect to see steam-oil ratios increase under those circumstances, but the operator has a good plan in place to regain the steam-oil ratios that Foster Creek used to exhibit, and as we add Foster Creek Phase F and move steam from some of the more well-developed steam chambers to new steam, so we feel pretty confident that Foster Creek will return to the high performance that we've seen in the past there.

Jeff, can you give us an update or any update at all related to the other sales plan in Canada or for the oil sands?

We've said on several occasions that we'll continue to look for opportunities to lighten our position in the oil sands, but that is just something that we're going to continue to watch.

There's no update on that process, Paul, and there's nothing that's in our plans for 2014 in that regard.

Can I just sneak a real quick one for Matt?

Okay, go ahead.

Matt, from an M&A standpoint, if you're looking at your portfolio in the upstream, is there any particular location that you'd think you may want to be more aggressive in acquiring additional acres?

Paul, of course we're always looking to add opportunities to our portfolio.

We're focused on doing that organically and our exploration teams are out there all the time looking for high-quality acreage that we can add early in the life cycle so, yes, of course we always want to take opportunities to strengthen the portfolio but it's all about organic life growth for us.

So, there's not really any particular region or area that you think that you really have a hole and you want to be -- substantially step up the land acquisitions strategies?

There's no region where we think with any particular hole and I wouldn't want to go into any specifics of the areas that we're looking at.

It wouldn't be wise to do that.

Thank you.

Thanks, Paul.

Our next question is from James Sullivan of Alembic Global Advisors.

I just wanted to hear if you guys have had any plans on reporting results?

I know during the analyst day you talked about ongoing spacing test in the Bakken, testing, I think, down to maybe four middle Bakken wells per spacing unit out there.

Is that an ongoing test and do you have a timeframe where you might have results on that?

James, we have.

I think it's about eight different operated pilot tests going on in the Bakken in particular and we have some of our partner-operated areas in the Bakken are testing different well spacings and different horizons.

The timeframe, it takes a bit of time to really get results that you would feel confident about, so I would say over the next year or more before we get really definitive results that would drive conclusions on the well density.

Okay.

That's great.

And then I just had two kind of housekeeping type ones on your costs.

Obviously you guys had a pretty good performance this quarter on production and then other areas, but two really jumped out at me were the SG&A and the net interest numbers.

I was a little confused on the interest number.

I know you guys paid down a bit of debt, but I've been under the impression that the capitalized interest number was going to come down with Kashagan out of the portfolio, yet the net number was pretty low, and then just the SG&A number.

Is there anything driving those?

And are those sustainable running rates?

James, we're looking at a couple things here, hang on a second.

The net interest number is higher than it was, I'm not sure what your question is.

We do expect interest expense to be higher because of the fact we're no longer capitalizing interest and you see that in the first quarter, so I'm not sure if I'm following your question there, James.

I think I was just looking at the -- kind of sequentially at the numbers, yes, it was up over Q1 2013.

Yes, I think Q4 it's roughly the same number and you can just have slight variations during the quarter.

Okay, great.

And then on the G&A number?

G&A can also be a little bit lumpy as well quarter-over-quarter.

I think we don't try to give any guidance separate for production and operating costs and for G&A.

What we said back at our analyst presentation as you'll recall is that we see the combination of those two being $8.5 billion for this year, which is a little bit higher than last year, it's just ramping up with growth.

Okay, great, thanks guys.

Thanks, James.

Thank you.

Our next question is from Doug Terreson of ISI.

Good morning, everybody.

Good morning, Doug.

Profitability in margins were very high in the quarter and maybe even at a record level even after normalizing for price as I think Jeff demonstrated, and on this point I wanted to see if you'd comment on a couple of things.

First, the trend in cost across the global portfolio, what are you seeing there?

Two, your lifting status in the most recent period.

And, three, whether there any other regional profitability mix factors either on the oil or the gas side outside of Jeff's comments on Lower 48 that stood out in the period?

I would say we've made some comments about the obvious things.

Prices, of course as you pointed out, were a big driver this quarter, in particular natural gas prices.

But underlying the margin growth is still this same thing we've been talking about, the movement of our portfolio to more liquids and to more production in areas where tax rates are generally lower and that's the underlying effect, which we said was still around 5% this quarter.

Not having Libya volumes in the portfolio does make a 2% or 3% difference in cash margins year over year for us this year and, of course, the fact that we are able to sell gas at strong prices and have marketing gains helped this time as well.

In terms of other impacts, we mentioned that there were some minor impacts on lift timing this year -- this quarter.

Overall lift timing was a negative on earnings mostly in the Asia Pacific area, it probably impacted Asia Pacific earnings by the order of $40 million to $45 million in terms of lift timing, and with relatively smaller impacts across the other segments.

But other than those things, there wasn't really anything very anomalous in the numbers.

You asked about kind of trends on costs, kind of like on the previous question.

What we are seeing is costs are going up as production is going up, but all that is covered by the fact that we're producing higher-value products, so overall cash margins are going up like we've been talking about.

Sure.

And then, Matt, you talked about Alaska where you guys are obviously one of the leaders up in the state.

And while it might be early, my question is whether or not the improvement in your opportunity set appears likely to be significant enough to be able to stabilize your output up there.

What I'm trying to gauge is whether or not Alaska can end up being significant enough to represent another layer of growth for the company over a reasonable period of time?

Yes, we are the biggest producer up there, as you know, Doug, and this change in the fiscal regime has opened up opportunities to stabilize the decline from our overall asset base.

Our asset base up there declines at about 7.5% a year, so the development activity that we have going on just in-field development drilling and then the major projects that we're kicking off the engineering for and moving towards sanction, we're hopeful that it should, we could stabilize Alaska production.

And depending on how things play out as we put these development plans together, there's a possibility that we could see growth in Alaska, but even just stabilizing production on an asset of that size and that maturity would be a pretty good accomplishment and I think that's achievable over the long run.

Okay, great.

Thanks a lot.

Thanks, Doug.

Thank you.

Our next question is from Paul Sankey of Wolfe Research.

Hi, good morning; good afternoon, everyone.

Matt, thanks for your comments.

I had kind of a high-level question about your acceleration in the Eagle Ford and maybe the Bakken, too.

How representative do you think you are of the wider competition that you have in those areas?

I guess what I'm driving at is to an extent you were slower to ramp up than some of your competitors but now have at the Analyst Meeting put through a significant increase in your outlook for these areas.

Do you feel like that's representative of what everyone is seeing or that you're going to be acting and moving much faster than your competition?

And I guess I'm also thinking of any geologic implications you think about where you're located and what you're seeing against what would be the wider trend in the play?

Thanks.

That's a good question, Paul.

As you know, there's quite a lot of geologic, even though these things are essentially shales, there's quite a lot of variability geologically as you move across the Bakken and as you move across the Eagle Ford.

We think that the acreage that we have in the Eagle Ford and the Bakken is right in the sweet spot and the Nesson Anticline in the Bakken is pretty clearly the sweet spot.

The area where we have the thermal maturity and thickness and pressure and geologic characteristics of our Eagle Ford position is strong, so I wouldn't expect our results to be the same as everyone else's.

I would expect over the -- as we continue this development, our returns will be higher than the average returns because of the position in the sweet spot, so you're right.

We didn't ramp up the pace as fast as some others did, we did that very intentionally.

We'd rather do it right than do it fast and focus on maximizing value, and I think that the strategy that we've adopted in both of those plays is going to prove out to be the best long-term strategy.

Which I guess would imply that your volume growth in these plays will outpace the volume growth in the wider play?

I mean, it is very dependent on how many rigs people choose to run, so I couldn't say if that's going to be the case for sure, but we are going to see significant continued growth in both of those plays as we showed a couple weeks ago.

I understand you can't say for sure, but what's your feeling about how others are behaving as regards in competition with you?

It's really hard to say, Paul, because it depends on how quickly they've been growing so far and what they intend to do with the rig counts and I don't have insight into that.

But we are in the middle of the sweet spot of both plays and really clear, consistent strategy on how we want to execute that and we're continuing to see upside in both of those plays that we'll exploit over the next few years.

That's good.

And then just to close off, the follow-up is how are costs and particularly in the Eagle Ford but also in the Bakken as regards to the activity of your undertaking, how do we look at that?

Thanks a lot.

So was that operating costs or capital costs, Paul?

Both, please, but really I was thinking more operating.

So our operating costs in both plays are really low.

We're below $5 a barrel in operating costs, very low operating costs.

That's one of the things that contributes to the high margins, of course, along with the high liquids yield in both plays.

And on our capital cost basis, for the sort of wells that we have drilled, the costs we are seeing are pretty much in line with the rest of the industry is seeing up there, so I'll say competitive on operating costs and the capital costs in both plays.

Great.

I'll leave it there.

Thanks, Matt.

Thank you.

Our next question is from Ed Westlake of Credit Suisse.

Please go ahead.

Yes, two questions probably for Matt.

Firstly on the Bakken, you said a couple more years before you get definitive results to think about well density and appreciate Nesson Anticline natural fractures and probably some of the areas may be slightly off that.

Just on what is it that you're trying to see?

Is it the sort of the year two and year three declines to try and get a sense of the economics of some of these wells?

And obviously we have data from some of these wells for about a year so far.

That's right, Ed.

When you tighten up the well spacing, you sort of would expect the early period of production to look similar on wells that have tighter spacing and wider spacing, so it's not until you've got a sense of the decline characteristics that you can really get a full understanding if the wells are interfering with each other and competing for the same oil or if they're not.

And so you're right, you need a few years to get confidence in the overall type curve characteristics as you tighten up.

You've got to be careful not to allow the pilot test to flatter or to deceive because in the early days you do expect to see similar performance from wells on tighter spacing, so that's why I was saying that we need some time to make sure that we are actually developing incremental reserves and adding incremental value as we tighten well spacing up.

So a little bit premature to have EURs that we can have confidence in?

I think so.

And then on the Permian, I mean, one of the debates I'm obviously -- in the refining space is this super light crudes that are coming out of the shales, obviously you have some of that in the Eagle Ford with the condensates.

You're doing tests in the Delaware Basin and also in the Midland Basin, so I'm just wondering if there's any differences in terms of the -- obviously people quote crude, NGLs, and gas, but they probably don't speak enough about the quality of the crudes coming out.

Can you give us some color on what you're seeing in terms of those tests because obviously it will affect the infrastructure that's required and also the pricing of the molecules?

Yes, this might not be very a satisfactory answer, Ed, because as you go through this 4,500 feet of stacked opportunity that exists in the Delaware Basin in particular, you get a very significant variation from -- in some areas it's gas with a high-liquids yield and some areas it's a relatively low API oil and other areas you've got a strong condensate yield.

It's going to be very variable, but it's clear that over the long run there's going to be quite a bit of gas, NGLs, condensate and crude that's going to grow in production in the Permian Basin as a whole.

And as our understanding and the industry's understanding of that matures, that will have implications for what sort of offtake and infrastructure requirements that are to fully evacuate all of these products from the Permian area.

And that's more on the Delaware than the Permian?

(Multiple speakers), but even in the Midland Basin, too, there's going to be some significant variation there but I think my sense is a wider variation in the Permian than the Delaware, but time will tell.

Thank you.

Our next question is from Blake Fernandez of Howard Weil.

Please go ahead.

Hi, folks.

Thanks for taking the question.

Back at the analyst day you kind of outlined the production profile where the U.S. unconventionals were increasing and it seemed like you were decreasing Europe and western Canada if I'm not mistaken, to kind of accommodate to where overall things remained pretty much in line with your previous guidance.

My question is what happens to those European and western Canadian projects?

Is that simply being deferred, and I guess what I'm wondering is do we have potential into 2015 for there to be an opportunity to maybe go toward the upper end of the 3% to 5% range on production?

Yes, we're very careful that if we are going to reduce capital in any area that it's deferring.

We are not going to lose opportunities so the western Canada we have a huge inventory of opportunities there with the high-liquid yields and the European projects that we spoke about are deferrals and both areas are retaining opportunities to add growth in the later part of 2017 and beyond, so I think that we're making pretty judicious capital allocation decisions to balance the short- and the long-term growth potential in the portfolio.

Okay, so that's outer year, not necessarily next year then it sounds like?

Probably, but every year we re-look at the portfolio.

One of the beauties of our portfolio is the level of flexibility that we have and the level of optionality that exists.

But in general the ones that we're talking about are probably more than opportunities to continue growth beyond 2017, but we'll see.

Okay.

Thanks for that, Matt.

The second one, I apologize if this is a little bit detailed, but I just want to make sure we understand from a modeling standpoint the Kenai, Alaska LNG.

From a reporting standpoint I'm assuming obviously the earnings from that will simply drop into Alaska, but are there corresponding volumes associated with that?

I guess I'm trying to understand if there's simply margin expansion or if there will be both production and earnings increases?

So, there will be both but the production growth is relatively small, so each of those LNG tankers that we load in Kenai contain about 2.75 BCF of gas and their expectation is that about 40% of that or so will be equity gas, ConocoPhillips equity gas, and then there will be third-party gas that we're moving through those tankers as well, so there will be some production growth but annualized over the year is relatively modest, 4,000 barrels a day or something like that over the year.

But we do get very good margins, good value from that business.

Okay, thank you.

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

Hi, guys.

Thanks for getting me on.

Jeff, could I start with the DD&A guidance for the year?

Is that really going to be back-end loaded compared to what you did in Q1?

I think in your analyst day you said Gumusut and one or two others might be responsible for that, but what should we think about as a unit DD&A as run rate, say, at the end of the year when the production is online?

So, we gave guidance, Doug, of 8.5 billion for DD&A for the year and, like you've seen, we came in like 1.9 or so in the first quarter.

It is going to be back-end loaded and really a few things drive that.

One is Jasmine started ramping up in the first quarter.

That's one of the things causing increases in DD&A.

We're going to continue to see increases in unconventional production in the Lower 48 as we go through the year.

That will cause DD&A to increase.

But probably the largest single item is the Gumusut startup, which is more of a third quarter item for us, which causes that DD&A to be back-end loaded.

In terms of unit rates, you'll see that go a little bit higher.

I don't have those just right off the top of my head here, but we still think the 8.5 number is the right number for the year and that you'll see that back-end loaded.

A little bit higher numbers in the fourth quarter than the second and third quarter.

Just to poke a wee bit on that, Jeff, so Q1 was about $13 and change and the average would be about $15 and change, so should we think something like a $16 to $17 kind of number in Q4 order of magnitude?

Kind of order of magnitude, I think the way I'd tend to think about it more is that the DD&A doesn't apply to all of our production since you've got equity barrels as well.

So you've got in our portfolio about 200,000 barrels a day of equity accounting barrels, which don't have DD&A associated with them.

So, I'd say our DD&A is probably more like 15, 15.5 right now and you may see that drift up a little bit as you go into the third and fourth quarters.

Okay, thanks for that.

We are going to be adding significant volumes in the fourth quarter in particular.

Got it.

Second one, my follow up, if I may, is just a quick one for Matt.

Matt, over the years there's been a debate between operators and the Eagle Ford and how you choke your wells.

We've seen obviously EOG with some very, very strong rates and obviously in a lower pressure part of the reservoir whereas others like Pioneer, which are a little bit south of you and in that same neighborhood as you guys are, are big advocates of kind of choking back to retain reservoir quality and so on.

I'm just wondering if you could share with us how are you approaching that in terms of how you think about the well rates that you're getting at?

Are you choking back?

Are you trying to manage towards that longer-term recovery or how do you think about it?

And I'll leave it there.

Thanks.

Yes, so we're more in the latter camp of managing the early rates and that's driven by a few different things.

We don't build our single-well facilities so that they can handle very high peak rates, that you're only going to have for a few weeks or a few months even, and so that's a reason for doing it.

We want to make sure that we keep all of the profit in the hole.

We don't want to be having such a high drawdown that we're damaging our completions, and so we do choke back quite significantly.

In the early month we can have tubing head pressures over 7,000 PSI choked back and so we manage it to make sure that we aren't oversizing the facilities and to make sure that we're not damaging the completion.

And there's some evidence that that's the right long term thing to do as well, not only to be -- prudent from an operations perspective, so that's the approach that we take.

Is that significant in terms of the up-front decline rate, Matt?

Does it slow you down quite a bit for a meaningful period or is it not really that material?

I'm just trying to get a feel for what your decline curves might look like on those wells.

So, we can -- on some of our wells we will be maintaining essentially flat production for several months and so over those months you're choking the reservoir back, so it has implications for the first year average rate and then so that does have implications for the observed decline rate.

I think that's what you're getting at.

Yes.

That's exactly right.

Okay.

That's helpful.

Thanks a lot.

Thanks, Doug.

Our next question is from Faisel Khan of Citigroup.

Please go ahead.

Thanks, good afternoon.

Good afternoon, Faisel.

Just going back to your comments on the Alaska LNG project, you talked about sort of enabling legislation passed in April.

Is there any change from the comments you guys made at your Analyst Meeting in terms of the type of spend pattern you would see for this project over the next few years even with this enabling legislation having been passed?

No, we were anticipating that the legislature would support the governor's approach to this, so our view of the spend profile for AKLNG hasn't really changed.

We're hopeful that we'll get to move into pre-feed.

We've already selected the high-level concept and I think I've discussed that on previous calls, but we need to get into pre-feed, hopefully in the second quarter here, and that will last 12 or 18 months and then we'll move into feed program which will take two or three years.

So really the sanction of the project we're probably looking out to 2017 or 2018 before we would actually sanction the full-scale project.

It takes a bit of time to go through the engineering as something of this sort of scale, as you can imagine.

Okay, got it.

And then just want to see if there's any sort of read- through for your guys' drilling program in Angola with sort of the recent results by Cobalt on this ORCA DST.

Is there anything in that data that changes your outlook for the prospects you have for the end of this year?

Not really.

The way we've been encouraged by the results that other operators have had in the area, we picked up the acreage before the play had been tested, but the results that we've had to have seen other operators announce have given us encouragement that we're in the right part of the play and we'll know that before we get to the end of this year.

We'll have the first well done hopefully before the end of the year, but no change in our views really as to what the materiality and prospectivity is in our Angola position.

Last question for me.

On APLNG, you've given some detail on that at the Analyst Meeting but in terms of the progress on that facility, it is still -- are all of the major sort of components for that facility sort of coming online and are the producing wells sort of also ramping up the way you anticipate?

I just want to make sure there's no risk here that the project lifts like we've seen with a few others in that part of the world.

No, we're still pretty confident we're hitting our milestones.

The actual LNG plant itself on Curtis Island.

I'm not sure if we shipped all of the modules already, but if we haven't it's pretty much all of the modules so we're on track.

We built these plants before, so we feel pretty confident that we're on schedule there and the upstream part of the project -- we still have a lot of work to do there.

We've got a lot of rigs running, we're commissioning our gas plants, our water handling facilities, but we're still confident that the middle of 2015 we should have the LNG plant itself, the first train ready, and we should have that the first gas we need to get that fully commissioned, so I would say that we feel that the project's on track.

Understood.

Thank you for the time, appreciate it.

Thanks, Faisel.

Our next question is from Roger Read of Wells Fargo.

Good morning or good afternoon, as the case may be.

Good morning.

Jeff, a question for you.

A look at Q1 results, and obviously we can strip out the payment from Canada; we can strip out the working capital advantage here in the quarter, yet even after you do that free cash flow is essentially breakeven which, given how you structured the company for the next several years, that's a real positive sign.

As you look at the projects that are coming online kind of a mid-point of the 3% to 5% volume growth and 3% to 5% margin, does a quarter like this indicate any sort of maybe you get there sooner in terms of the free cash flow matching or -- I should say free cash flow -- cash flow out matching cash flow in and getting to sort of a neutral or slightly positive free cash flow situation?

Yes, in that we had a quarter with very strong pricing.

We had Brent near 110 still and WTI about 100 and very strong North American natural gas prices, of course, which helps our cash flow numbers.

I think the way we like to think about it, though, is we've got the growth in production and margins happening, which are going to get us to that neutrality point across a wide range of prices.

And how quick we get there can be influenced by prices but by - as we talked about in the analyst presentation, by 2017 we've added considerable production at high margins and are going to have the size of cash flows that are going to cross a pretty wide range of commodity prices are going to get us to that neutrality point.

Yes, that could back up to 2016 if prices were higher, but we don't count on having prices like we saw in the first quarter long term in order to -- as the basis for our plans.

Okay.

That's helpful.

And then from a strictly operational standpoint, heavy turnarounds last year in the summer in the North Sea again this year.

Maybe, Matt, the question is for you.

Is that going to be typical for your North Sea production over the next year, couple of years, or are you getting past sort of a pig in the python moment here, two big years of maintenance in the North Sea in the summertime?

It's more the pig in the python thing for the North Sea.

We had a huge turnaround last year in Norway, the biggest we've ever had.

There's no significant turnaround going on in Norway this year or next year because we have Norway in a three-year cycle.

There will be some short downtime at Eldfisk to tie in for the new Eldfisk II project, but it's a handful of days from that.

This year's turnaround is a little bit less than last year's, I think it's about 3% less than overall turnaround activity.

But you're right, these have been two relatively big years in turnarounds and they're somewhat anomalous from that perspective.

Okay, that's helpful.

Thank you.

Thanks, Roger.

Our next question is from Pavel Molchanov of Raymond James.

Thanks for taking my question.

In your exploration section, you have a pretty extensive set of upcoming catalysts.

And I know that historically you've talked about shifting away from high impact wildcatting.

Is 2014 somewhat of an exception or do you think you'll continue this exploration run rate, especially deepwater, going forward?

No, I think we'll continue it.

There are some really interesting wells that we're drilling there this year, but, no -- we've built an exploration portfolio that has a good mix of unconventional and conventional opportunities for the -- as a portfolio that allows us to do this, so significant testing this year, but continuing that over the next several years in the Gulf of Mexico and elsewhere.

We're continuing to add to the exploration portfolio, so I'm hopeful that we'll have 2015 and the years beyond that we'll still have an exciting exploration and appraisal program to exploit.

So in the context of kind of flattish CapEx in total, do you anticipate that your offshore spending just globally will be up year over year in 2014?

No.

Well, on average we've said it's about 15% of our overall capital, about $2.5 billion a year and some years will be a bit higher.

This year will be about $2.1 billion, for example.

So it will fluctuate from year to year but it's going to average, I think, around that $2.5 billion for the E&A program overall.

And of course the split between conventional, unconventional, deepwater and shallower water, that's clearly going to fluctuate as the prospects mature and we get to the drilling phase of the life cycle, but on average about $2.5 billion a year.

Okay, thanks very much.

Thanks, Pavel.

We'll take one more question if there is one and then cut it off here.

Our last question is from Asit Sen of Cowen & Company.

Please go ahead.

Thanks, good afternoon, guys.

Good afternoon.

So, I have a question on Malaysia.

And Malaysia is a decent part of the growth equation over the next 12 to 18 months driven by Gumusut and KBB.

How much Malaysian volume is embedded in the 2014 production guidance and could you provide what is the incremental contribution from Malaysia expected in 2015?

Off the top of my head, I'm not 100% sure of what the component -- what the 2014 -- I would say it's around 20,000 barrels a day for 2014.

And that would be higher but I can't remember how much higher in 2015, maybe another 20 by the time we get to 2015.

So as a significant part of the growth and it's high-margin growth it's -- but how much we produce this year in Malaysia is very dependent upon when Gumusut starts up, but it's a significant part of the growth and it's good high-margin growth.

And so we have SNP on production, we have the Gumusut early production system on just now.

We'll bring on the full floating production system for Gumusut hopefully in the third quarter here, we'll bring on Kebabangan late in the fourth quarter, we still have the Malikai project in execution just now.

And we've got four or five other discoveries in the area that we're moving forward through the appraisal and engineering stage.

So, it's a good piece of business for us and it's going to contribute to both our production and margin growth over the next few years.

Thanks.

Thanks, Asit.

Appreciate it.

And why don't we call it good there.

By all means, call IR if you have any follow-up questions.

Thank you so much for joining us, everybody.

And thank you, Christine.

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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