康菲 (COP) 2013 Q1 法說會逐字稿

Welcome to the Q1 2013 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.

Later, we will conduct a question-and-answer session.

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.

Thank you, Christine and thank you to all of our listeners for joining this earnings call today.

As usual we'll review the results for the past quarter and we'll provide quite a bit of outlook for the coming quarters this year.

It's a big year, as I think you all know and appreciate.

With me for today's call are Jeff Sheets our Executive Vice President of Finance and our Chief Financial Officer; and Matt Fox, our Executive Vice President of Exploration and Production.

Before I turn the call over to Jeff let me make just a few administrative points here.

As a reminder, in late February we hosted our first ever analyst meeting as an independent Company.

And at that meeting we presented a lot of detail about our future plans and our milestones.

We had a great response to the event, which we appreciate.

And today you'll hear that our performance and our plans are tracking the expectations we laid out there overall.

The material for that meeting, including a transcript of that call is still available from our website and that's also where you'll find the materials for today's presentation.

One other quick administrative matter, except as noted, today's comments as we go through the presentation will address the Company's performance on a continuing operations basis.

And that is net of the results for the several properties that we've previously reported as discontinued operations.

So just listen for that.

We know the models have a mix of conventions and so we want to be clear about the convention we plan to follow today.

If you'll turn to page 2 you'll find our Safe Harbor slide.

We will make some forward-looking statements today, and of course our actual results could differ.

The risks in our future performance have been outlined and described on the Safe Harbor statement and in our periodic filings with the SEC including our recently filed Form 10-K.

And with that it's my pleasure to turn the call over to Jeff.

Jeff?

All right.

Thank you, Ellen, and good afternoon, everyone and thanks for taking the time to join us on our call today.

I'll begin my comments on slide 3, and cover some of the key first quarter highlights.

Strategically we continue to make good progress on our announced asset sales.

In the first quarter we closed the Cedar Creek Anticline transaction and some small asset sales which generated total proceeds of about $1.1 billion.

We are also making progress in our sales of our Algeria and Nigeria and Kashagan assets and anticipate closing those in 2013.

At the same time as we work to monetize these non-core non-strategic assets in our portfolio, we continue to add assets which will allow us to sustain our long-term growth.

We added acreage in our deepwater Gulf of Mexico position and continue to make selected entries into new exploration plays globally.

Matt's going to provide more information about our investment programs during his comments later in the call.

Operationally the business ran well and we achieved the high end of our estimated production range for the quarter.

We produced $1.596 million BOE per day on a total Company basis and 1.55 million per day on a continuing operations basis.

We announced two significant deepwater Gulf of Mexico discoveries in first quarter at Shenandoah and Coronado.

And these are important milestones in our emerging deepwater Gulf of Mexico program.

Moving to financial results adjusted earnings were $1.8 billion or that's $1.42 a share.

Special items this quarter were $387 million which were primarily related to gains on asset sales.

Excluding a $1 billion net working capital gain, benefit we generated $3.6 billion in cash from operations and ended the quarter with $5.4 billion of cash on hand.

Our debt level was unchanged from year end.

So overall we had a strong quarter strategically, operationally and financially.

And if you turn to the next slide I'll discuss our earnings for the quarter.

It was a straight-forward quarter with adjusted earnings relatively flat with comparative periods.

This quarter's adjusted earnings were down about 2% compared to last year's first quarter primarily driven by lower benchmark prices and higher DD&A expense, which were partially offset by our shift to higher-value liquids in our portfolio and lower corporate expenses.

Adjusted earnings per share was up 3%, which reflects the share repurchases in the first half of 2012.

Sequentially adjusted earnings were essentially flat, slightly lower total Company volumes were offset by somewhat higher product prices with the notable exception of bitumen pricing which remained weak in the first quarter.

As I mentioned production, volumes hit the high end of our guidance range and operating costs were as expected so there are no surprises there.

Next I'll cover our production performance for the quarter so if you'll turn to the next slide.

As I mentioned a moment ago, our all-in production this year's first quarter was 1.596 million BOE per day.

And these results included about 40,000 BOE per day from discontinued operations.

So this slide 5 shows how production compares to the first quarter of 2012.

First quarter 2012 production from continuing operations was 1.58 million BOE per day.

And if you adjust that for the 45,000 of production from assets that were sold during 2012, normalized production from continued operations was 1.536 in the first quarter of last year.

So if you compare that to the first quarter of 2013, our down time from continuing operations was 30,000 BOE per day higher in the first quarter 2013 than the first quarter 2012.

This downtime is primarily due to weather-related issues in the San Juan basin and downtime at the East Irish Sea Rivers acid plant.

Production growth of 219,000 BOE per day more than offset decline of 170,000 BOE per day.

The majority of this growth came from the Lower 48 shale plays and our Oil Sands assets and we had some production increases year over year from Libya and China.

So normalized for 2012 dispositions our production from continuing operations increased from 1.536 to 1.555 million BOE per day year over year, and that represents about a 1% growth in total.

And this growth would have been higher were it not for the increased downtime we had in the first quarter.

So while we experienced a slight year-on-year production growth from our continuing operations, the composition of that production shifted, leading to improved cash margins, and the next slide discusses those cash margins.

As you can see cash margins are growing.

Despite a 3% drop in realized prices compared to last year's first quarter, our cash margins grew by 6%.

One of the biggest drivers in this margin improvement is the shift to higher-value liquids in our portfolio.

So liquids production from crude, from NGL and bitumen increased to 57% of production compared to 55% a year ago.

So this metric's likely to be volatile on a quarter-by-quarter basis but the long-term trend should be one of increasing cash margins as we shift our production towards higher value products.

And we will continue to focus on this metrics as it's one of the key aspects of our value proposition.

So next I'll turn to the segment slide beginning with the Lower 48 on slide 7. Production in this segment was 475,000 BOE per day.

That's up 5% compared to last year's first quarter, as we continue to successfully ramp up production in the Lower 48 shale plays.

Total liquids production in this segment increased 17% over the same period a year ago while natural gas production decreased by 4%.

Sequentially, production was flat for the segment reflecting the unplanned downtime in the San Juan Basin related to winter weather conditions.

So with the 17% growth from liquids production, liquids now represent approximately 50% of the production mix in this segment, up from 45% a year ago, and we expect our liquids production percentage to continue to grow.

During the quarter Eagle Ford production averaged 101,000 BOE per day.

Permian production averaged 52,000.

Bakken production averaged 29,000 BOE per day.

So total production from these three areas was 182,000 BOE per day and that's up 42% compared to the same period last year.

In terms of earnings, realized prices tell most of the story on earnings variability.

Sequentially in this year's first quarter volumes were flat but earnings benefited from stronger crude prices.

So next we'll move to the Canada segment on slide 8. Canadian production was 283,000 BOE per day in first quarter.

That's up 6% year over year, driven by the ramp-up of production in our Oil Sands assets.

Liquids production increased 22% year over year while gas production declined 7%.

And this shift should show up in improved margins over time with recovering bitumen prices.

Canada reported negative adjusted earnings this quarter, reflecting weak bitumen prices that carried over from late last year.

As a reminder, our realizations embed a one-month lag in WCS spot prices.

So our first quarter results essentially reflect pricing in December, January and February.

Since we already know that March and April prices for bitumen are higher, we expect second quarter realizations to improve compared to the first quarter.

So let's move onto the Alaska segment on slide 9. Production in Alaska was 218,000 BOE per day this quarter, that's down sequentially but in line with our expectations.

Compared to the first quarter of 2012 production was down about 18,000 BOE per day, reflecting normal field decline.

In the first quarter, lift timing had an adverse impact to earnings of about $50 million, and adjusted earnings were $543 million for the segment.

As most of you know, the Alaska Legislature passed SB 21 representing some reform to the existing fiscal regime.

We are currently analyzing the possible impact to our business including where we could, or would, increase investment in Alaska and we expect to provide more details on our future plans over time.

So I'll turn to slide 10 and talk about our Asia-Pacific and Middle East segment.

Production in this segment was 318,000 BOE per day during the first quarter and that's up 5% compared to a year ago, and about flat sequentially.

One milestone to note is, we achieved our first sale of a cargo of oil from the Gumusut Field in Malaysia in January.

Adjusted earnings this quarter were favorably impacted by about $20 million related to lift timings and they benefited from continued strong pricing sequentially.

Europe is the next segment and it's found on slide 11.

Production for Europe was 207,000 BOE per day during the quarter, a sequential decrease of 9,000 BOE per day.

Natural field declines, asset dispositions and continued downtime primarily at the East Irish Sea facility, continued to lower production volumes compared to the first quarter of last year.

The adjusted earnings of $348 million for this segment did not include any significant timing differences this quarter.

So we don't have an Other International segment or a Corporate slide in our presentation this quarter as there wasn't much news.

As a reminder, most of what was previously in the International segment is now reported in our discontinued operations.

Our Corporate segment adjusted earnings were negative $173 million, that's in line with our fourth quarter performance but ahead of our quarterly guidance.

And we're going to provide an update on our full-year outlook for corporate expenses at the second quarter call in mid-year.

Further information on this segment is provided in the supplemental information that's provided with the earnings release.

So if you turn to slide 12, I'll cover our first-quarter cash flow.

We generated $3.6 billion in cash from operations this quarter, excluding working capital.

And working capital was the source of $1 billion in cash.

We also generated $1.1 billion in proceeds from the sale of the Cedar Creek Anticline asset and some other small assets.

So you'll notice that the working capital change this quarter is large and the biggest single component of this change relates to the impact of the Cedar Creek Anticline asset sale.

But in the nature of accounting for asset sales, is that the pretax value of asset sales proceeds shows up on the cash flow statement in the cash from investing activities, but the tax impacts from asset sales end up in the cash from operations portion of the cash flow statement.

And tax impact from the CCA dispositions impacted both the fourth quarter 2012 and the first quarter 2013 cash from operating activities.

So as of the impacts from this transaction, cash flow from operations before working capital would have been approximately $4 billion in both the fourth quarter of 2012 and the first quarter of 2013.

And the working capital change in the first quarter of 2013 would have been closer to $600 million.

Moving to capital, we funded a $3.6 billion capital program for continuing operations in the quarter.

And we expect that capital expenditures will be higher in the subsequent quarters of 2013.

So finishing up the cash flow statement we paid out roughly $800 million in our recent quarterly dividend, and this left us with a strong cash position at quarter end of around $5.4 billion.

So our balance sheet and financial situation remains strong.

We continue to be well-positioned to execute on the programs that are going to generate the volume and margin growth for the Company.

So that concludes the financial overview.

And now I'll turn the call over to Matt for an update on operations.

Thanks, Jeff.

As both Ellen and Jeff mentioned, really the theme of this quarter's operational performance is that we're on plan.

Jeff covered the financials results by segment, but I'm going to cover the operations material by the capital buckets we reviewed at the analyst meeting in February.

So these are our high quality base, our relatively low-risk development programs that completely mitigate base declines, our major projects, and our exploration programs.

And we think of these buckets as distinct parts of our strategy that when aggregated will drive growth in volumes, margins and returns over time.

So let's start with a base asset discussion on page 14.

Just as a reminder, our base refers to the assets we were producing at the end of last year, which comprised about 1.5 million BOE per day of continuing operations.

During the first quarter of this year, our base production performed essentially as expected.

Around the business we had some winter related downtime in the San Juan Basin that Jeff talked about, the majority of which has been restored.

In addition, as we discussed last quarter our Calder Field in East Irish Sea is down pending completion of a new asset plant.

As we discussed in the fourth quarter call and at the analyst meeting, I want to remind you that we have some significant downtime planned during the next two quarters.

And our operating assets of when we expect downtime are going to be about 30% higher than our five-year historic average.

And much of this higher downtime is related to what needs to be performed to tie in new production in many of our operations.

And we also expect higher than average downtime at several of our key nonoperating assets this year.

So I thought it be worthwhile taking a moment to give you some highlights that are listed on this slide.

First, the Greater Ekofisk Complex schedules a major shutdown every three years during the summer.

This year's plant shutdown will be the largest ever in the Greater Ekofisk area, and in fact they will be the largest shutdown in ConocoPhillips' history.

So it's a big deal and our planning's going well.

The shutdown at Ekofisk itself will start in early June and last about a month.

In addition to planned maintenance we'll be completing ground field work for Ekofisk South production beginning later this year.

Also Eldfisk is planned to shut down in late May for a period of about 70 days and this work will include preparations for the tie-in and start-up of the Eldfisk II in late 2014.

Likewise in the UK we have a significant J-Area shutdown planned also for June, coinciding with Greater Ekofisk shut down.

And similar to the Norway work, a key goal of this planned event is to make preparations for the Jasmine Field tie-in and start-up later in the year.

We also have significant turnarounds planned in Alaska, the Oil Sands and Indonesia and the Lower 48 so this really is a big year for planned shutdowns.

Before I leave this slide I want to make a key point.

Our 2013 production guidance hasn't changed, except we've narrowed the range for the full year and have slight increase to the midpoint.

We've provided quarterly detail for 2013 production outlook in the appendix section of today's presentation.

And we've presented this information for both continuing operations and discontinued operations for the rest of this year.

And we're showing both conventions because we know there's a mix in the analyst models out there, and we want to make sure there's no confusion.

And let me give you a little more color specifically on the Lower 48 second quarter volume expectations.

The sale of the Cedar Creek Anticline properties will reduce our base production by about 11,000 BOE per day compared to the first quarter.

That combined with the second quarter planned downtime and underlying decline should be completely offset by production growth from our development programs, so as a result we expect second quarter production from the Lower 48 to be about the same as first quarter production.

So moving on to development programs on slide 15, these are the low-risk drilling lead programs around the world that completely mitigate our decline with high margins and high returns.

These programs remain on track across the globe to deliver the 600,000 BOE per day of production by 2017 that you can see on the top left graphic.

Among our Legacy fields, in Alaska, Kuparuk coiled tubing drilling sidetracks continued.

In Western Canada we got high-octane due to mild weather and good results from this year's winter drilling program.

Results across the Lower 48 development programs are also strong.

So beginning in Eagle Ford, first quarter production averaged 101,000 BOE per day, with a peak net production of 110,000 BOE per day.

So volumes were up 13% sequentially compared to 89,000 BOE per day in the fourth quarter of last year.

We expect to complete the drilling phase of acreage captured in the Eagle Ford by mid-this year, and then be fully held by production by the end of the year.

And as we approach this milestone we're focused on planning for full-field development.

Moving to the Bakken, production averaged 29,000 BOE a day, an increase of 5,000 versus the fourth quarter or about a 21% increase.

In both the Eagle Ford and the Bakken plays we continue to evaluate and implement infrastructure and marketing solutions to improve our margins.

For example, we continue to install stabilizers in the Eagle Ford to allow us to more effectively ship our light crude production.

In the Permian Basin we are increasing activity in both the conventional and the unconventional plays where we hold 1.1 million net acres.

We are currently testing several unconventional plays in both the Delaware and Midland basin.

For example, we're seeing good results from early tests of Avalon wells in the Delaware basin where about 60% of the production stream is liquids.

We hope to have more results here to share soon.

In the Permian conventional development program, we now have four operated rigs running.

Our current plan assumes will bring on about 135 wells this year and an increase of 40% compared to 2012.

So these efforts will protect our base production against generating strong margin and returns.

So we've got lots of good things going on in our development programs and we will have for the remainder of year.

Now let's turn to our major projects on slide 16.

Our major projects remain on track to deliver the 400,000 BOE per day of production by 2017 that you can see in the top left graph.

Our Oil Sands properties continue to perform on plan and currently we have seven major projects in execution there.

The combined Oil Sands properties averaged 109,000 BOE per day during the quarter, up 3% sequentially.

Christina Lake Phase E is on track to start up in the third quarter of this year, which will contribute to the continuing ramp up of production.

In the Asia-Pacific region, an additional eight Panyu growth wells were brought online in the first quarter, bringing the total new well count to 17 wells and these wells contributed more than 6,000 BOE per day net by the end of the quarter.

In Malaysia the floating production system from Gumusut and the Siakap North-Petai projects are both on track for fourth quarter start-up.

At Curtis Island, module installations are underway at APLNG this quarter.

This is a big milestone for the project and it shows that we're still on schedule for first LNG in 2015.

Activity in both the UK and the region sectors of the North Sea is high.

The picture shown on the bottom left here is of a Jasmine topside installation that began in March and was completed earlier this month.

The offshore hookup and commissioning work has now commenced with first production still expected in the fourth quarter.

At Ekofisk South the project is progressing well, we're on track for sail away in June.

We expect to set the top side this summer and achieve first oil production by the end of this year.

So as you can tell, it's a very busy year for major projects in ConocoPhillips.

We've got a lot of exciting things underway in terms of growth and margin catalysts.

For example, the four major projects we're bringing on this year, Jasmine, Ekofisk South Gumusut and SNP, will have a total average production of about 80,000 BOE per day in 2014.

But this is actually only half of the total production that we'll be adding from all of our major projects in 2014.

We'll also add production from projects at FCCL, increasing production at APLNG for domestic sales and several other smaller projects around the Company.

And of course that's the incremental production in 2014, is in addition to the production that we'll be adding from a development programs which essentially maintain base production flat.

The next two quarters are really important.

I know our people are up to the task of safely executing our plans.

Next I want to briefly cover our exploration programs starting with the Gulf of Mexico on slide 17.

As most of you know, we announced two significant Gulf of Mexico deepwater discoveries this quarter, Shenandoah and Coronado.

Shenandoah was the first appraisal well following a 2009 discovery and we have 30% equity.

This first appraisal well exceeded pre-drill expectations, with over 1,000 feet of net pay it looks to have good reservoir quality and good oil quality.

And importantly we drilled down dip of the discovery well but we didn't find a water column.

At Coronado we announced the discovery of a large three-way closure sub salt.

This well discovered more than 400 feet of net pay with good quality reservoir.

And we have 35% of this discovery.

And the operator's now back on location drilling an appraisal sidetrack from the discovery well.

During the quarter we continued to build our leasehold position in the deepwater Gulf of Mexico through our participation in the recent March lease sale.

The chart in the lower left shows our growing acreage position, much of which is still in primary term, and the flexibility this provides is a real advantage.

And then finally in the Gulf of Mexico we've got a very active drilling program under way or planned for the remainder of the year.

Currently we're drilling at the Ardennes well, a lower tertiary wildcat, and we have 30% interest in the well.

We expect to spud the COP operated Thorn well any day now, which is an upper tertiary wildcat where we have 65% working interest.

Also coming up in the second quarter, a Tiber appraisal well is expected to spud where we have an 18% interest.

And then later in the year, the Deep Nansen wildcat well will spud which is a lower tertiary prospect where we have a 25% interest.

So 2013 is clearly a very big year for our deepwater Gulf of Mexico program, we're really excited about this and we hope that we have other meaningful results to share with you as the year progresses.

Moving to slide 18, and here I just want to take a minute to update you on our other unconventional and conventional exploration programs outside the Gulf of Mexico.

In Canada we drilled, logged and cored two wells in the Canol play.

This is a Devonian Shale that we believe is in the oil window on trend with the prolific Horn River gas play.

We are planning to go back to this area next winter for a multi-well program, including a horizontal well production test.

In the Niobrara play we drilled three wells in the first quarter.

Currently our pace is somewhat limited by gathering and infrastructure build-out here.

Our rail results are encouraging but it's still early days.

In the second quarter we expect to drill our first well in Columbia on the Middle Magdalena Basin in the La Luna Shale play.

Moving on to our conventional programs, in Alaska we drilled a wildcat discovery at the Cassin prospect and the onshore NPRA.

In the Kwanza Basin in Angola we completed the second Phase of our 3-D seismic program in early April and we are in full planning mode to begin drilling early next year.

And finally, in the Browse Basin of Australia we are currently drilling the Proteus wildcat on an untested structure to the south east of the Poseidon discovery, and we expect to reach TD in late May.

So there's been a lot of expiration activity in the first quarter and that continues into the second quarter.

So that was a pretty quick overview of our operations which are running well, very high level of activity and generating visible results.

So now please return to slide 19 and I'll wrap up with some summary comments.

I think the most important take away from today's call was that the business is running well.

I hope Jeff and I have given you confidence that our plans are on track for delivering key milestones in 2013, that will position us for a very strong 2014.

Our value proposition remains intact.

We expect to make progress in our announced asset divestitures in 2013 which will provide financial flexibility for funding our growth programs, and our dividend remains our top priority.

Operationally we're approaching a very significant inflection point for the Company.

The momentum coming out of 2013 should be strong.

We're delivering visible results from our conventional and unconventional exploration programs that will sustain our growth into the future and very importantly, we're delivering our operational performance safely and efficiently.

Finally, we've committed to maintaining a strong balance sheet that can provide financial flexibility.

We're seeing the early stages of cash margin expansion, which should improve as our volumes grow and as always, we'll maintain our focus on improving returns.

The bottom line is that we are committed to creating long-term value by delivering 3% to 5% growth in production and margins with a compelling dividend.

We're executing on this strategy and we're committed to keeping you updated on our progress.

So now we're pleased to take your questions and Christine, I'll hand it back to you.

Thank you.

(Operator Instructions)

Faisel Khan, Citigroup.

Thanks, good afternoon.

I was wondering if you could give us an exit rate in the quarter for the Eagle Ford?

The exit rate was about 110,000 BOE per day.

And we're continuing to grow production.

I think we had new peak production on Monday of 116,000 BOE per day in the Eagle Ford.

Okay.

Where do you see this going towards the end of the year?

Right now in Eagle Ford we're on a pretty linear growth trend and we see that continuing essentially as we go through the year.

Okay.

Understood.

And then on the recent change in the legislation in Alaska, on the progress of tax, you said you are going to add a rig to Alaska.

What's the current thinking now with the new tax regime in place?

So we've been encouraged by the changes to the regime, we've been advocating this for some time.

And then the change will encourage additional investment in Alaska.

So we're looking at that, we've got a long list of projects that we are evaluating now.

And we did announce that we were immediately starting to increase with this new rig that we are bringing in, that rig is going to provide focus on working over existing wells and adding production that way, but we do have quite a few capital projects that we're now evaluating the impacts of fiscal regime on.

Okay.

And in Alaska, you guys laid out a production decline in Alaska over the course of this year.

Does this rig and the new activity mitigate that decline rate?

And by how much?

You won't really see any significant change in the short-term, but the issue is that the government new fiscal regime our incremental capital investments are now competitive and we think they will be but we're taking that through our overall planning process this year and we'll be more equipped talk about that later in the year.

Okay.

Great.

Thanks for the time.

I appreciate it.

Thanks, Faisel.

Doug Terreson, ISI.

Good morning, everybody.

Good morning, Doug.

In March at the analyst meeting the Company provided a pretty detailed outlook for production and cash margins, and on this point I think US production from liquids-rich plays rose by over 40% versus the year-ago period which is obviously a pretty strong result.

But my question is on profitability and specifically whether cash margins in these plays are strengthening as you thought that they might.

And also whether there are any other performance related factors that are worth mentioning in the Eagle Ford,the Bakken and the Permian development that you have underway?

Yes.

Pretty much as Matt mentioned the production is happening pretty much as we expected from all three plays, Eagle Ford, the Bakken and the Permian.

And production from these is all -- Eagle Ford is 60% oil and 20% NGLs and 20% gas, so that's really strong cash margins.

And Bakken, of course, is mostly oil.

And the Permian is yet a very favorable mix as well.

So cash margins from all these assets are really much higher than the average of our current portfolio.

So as you see the portfolio, you're starting to see that show up now finally in Lower 48 cash margins, as that portfolio has moved now to where it's kind of about half liquids to where it was 45% a year ago.

So you're starting to see that all across the portfolio.

Cash margins have been a little bit hurt in Canada because of the real recent weakness in bitumen prices but we think that's going to start recovering as well.

So overall, as Matt was summarizing, we see the trajectory of the growth in production happening as we thought it was going to.

And it's that trajectory of growing production that's going to cause growing the production, that higher margin that's going to cause cash margin to increase over time.

So production growth is on plan and margin growth is on plan as well.

Okay.

Jeff, I think that you mentioned your efforts on optimization and higher net-backs, is I think the way you talked about it, and on this point I want to see if you could highlight some of the specifics that are being undertaken to improve the net-backs to the Company on production.

Yes.

I think we talked about how a lot of, in particular what we're trying to make sure is that, we're talking about marketing in Eagle Ford, for example, Matt, maybe you want to talk some about what we're doing there.

So a growth year, Doug is to have as much optionality as we can because as you know, there's a lot of volatility in the various markers and in the production itself, in all three of those basins.

So for example in Eagle Ford, just now the way we're set up for our sales we're realizing WTI plus about $5 from the Eagle Ford.

And that's a mixture of production that's going by pipeline, a lot of production is still going by truck.

Some of our production is priced off LLS, some of it's priced off WTI.

Our liquids, the non-NGL liquids are sold as a light sweet crude.

Because they've got very high-value middle-distillate that makes them a good refinery product so they're not being sold as condensate.

And we feel about good about the liquid and gas takeaway capacity just now in the Eagle Ford.

In the Bakken, we are actually realizing WTI minus about $5 on average in the Bakken.

And we've got a mixture of off-take there as well, about 30% is by pipeline just now.

About 25% we're selling to railers to bring it south to capture the WTI grants spread.

So we're managing, I think, very well and we're developing a lot of optionality to make sure that we have flexibility to maximize our realizations.

Okay.

Great.

Thanks a lot.

Ed Westlake, Credit Suisse.

This is actually Rakesh for Ed.

Question on, if you can give any updates on your Canadian asset disposals?

Where we are in the process over there?

We're still evaluating our options for diluting our position in the Canadian Oil Sands.

We've got quite a few alternatives that we're considering, quite a lot of interest in those assets.

But we're not in a hurry.

This is an important strategic transaction for the Company so we're still thinking through which of these alternatives we want to pursue.

Thank you.

That's all I had.

Thanks, Rakesh.

Paul Cheng, Barclays.

Matt, I think in Eagle Ford that your primary black oil.

Do you have any rough estimate in terms of the spread between Black oil condensate, NGL and gas for your position in the Niobrara, Wolfcamp and Canol shale?

It's still very early days in all of those.

We do see high liquids yield in the Niobrara, for example.

The well that we've tested they're all have a high crude oil yield.

And the Permian, I think the most recent stuff I saw from our Avalon wells was 60% crude oil percentage.

And then I think you mentioned the Canol.

We don't have a well test in the Canol yet.

We just drilled and cored and logged those wells so we don't have an estimate of that yet.

And, Matt, when you say crude oil, you're really referring to black oil, it's not condensate and NGL, right?

When you say 60% in Wolfcamp?

That's right.

Okay.

And then in Columbia, when you drilled the first well, the vertical well, are you going to also frack it or are you just going to, say, get some core samples?

I think the first well we're just going to get core samples and some dynamic fracture testing but I don't think we plan to run a full frack on the first well.

And maybe this is for Jeff, any update about the Canadian Oil Sands sales, we are we in the process?

I think as Matt mentioned, I think, previously, we're still evaluating the options that we have in the Canadian Oil Sands.

Process in -- that's something that we're going to be taking our time doing because there are a lot of different potential routes we could go with that transaction.

So we should not necessarily assume that it's going to have a final decision made by Company within this year?

Yes.

I think that would be fair.

It's a transaction we're going to be working on throughout this year and could potentially be next year as well.

Okay.

Matt, on the Shenandoah, that is a monster well.

Given that it's so great news in terms of the size, should we assume from a timeline standpoint on the development you may actually need to at least another two years for additional appraisal well, and then after that do two years of the feed and then four years the actual construction of the platform?

So are we talking about more like in the 2020, 2021 kind of timeline?

We are still working that, Paul.

It's a good question and we're in the middle of working out the timeline and the appraisal request for that well.

And so it's too early to give you a timeline for that.

I see.

Okay.

Thank you.

Thanks, Paul.

Doug Leggate, Bank of America.

Good afternoon, guys.

Good afternoon.

I've got a couple of questions please.

Matt, on the Eagle Ford, there's a number of companies now starting to chatter about the Pearsall and the Austin Chalk underneath their acreage.

I'm just wondering if you are moving in that direction, if there's anything you can share with us in terms of how it might augment the existing program.

Yes.

We know that that potential exists on our acreage.

So we really are regarding right that now as upside relative the Eagle Ford shale itself but you're right, that potential could be quite significant.

Nothing in terms of expiration activity or appraisal activity at this point?

Not right now.

Not right now.

Okay.

Thanks.

Jeff, my follow-up, is on the cash margin comment.

I'm looking for a bit of help here, really, this is probably the key to, or one of the keys to the investment case, I guess, is the growth in the margin expansion you spent a fair amount of time talking about it.

Your liquids production was up 57% versus 55% as a proportion, but every liquids realization year over year was down quite materially.

And the only realization that was up was gas.

So I'm trying to understand, how does the cash margin grow in that environment?

By my numbers, it's not growing and I'm trying to understand how you're getting to these numbers.

Are you normalizing for the base portfolio after asset sales?

Or is there something else going on there?

So let me take that and short-term and long-term impact.

So --

I'm looking Q1 over Q1.

Yes.

Which I would call a short-term impacts.

The cash margins, there's always going to be a lot of things that go into cash margins that would create a lot of noise when you look quarter over quarter.

Even somewhat year over year.

So it depends not just on what price levels happen what went on with price levels which moved a little bit, in this year-over-year time period, as we showed our realized price overall went down by about 3% overall the cash margins went up.

So it's what is making up, it's the tax rates at which that production is happening as well, that makes a lot of difference.

And as you point out we did have some improvement in natural gas prices in that timeframe which helped margins.

So what we showed in the call today was just what happened to actual cash margins year over year, including the impact of prices.

Now, what we think is important, though, is what's happened in the cash margins over the long-term, in a flat price environment and that's what we really tend to talk more about, like what we spent a lot of time talking about in the analyst presentation.

And as you go long-term, it's the impact of adding oil production, LNG production, Oil Sands production and changing the mix in the portfolio as well as the geographies in which you add them.

And that's just saying, we pointed out on today's call that you could observe year-over-year cash margins increases and there's going to be noise around that as we go forward.

And I won't say that every quarter we'll see an increase, but over time, as we move our portfolio to higher liquids percentages and change the geographies, that you're going to see an improvement in that cash margin.

Let me just be clear then.

I'm looking at first quarter '13 over first quarter '12 your saying it is up 6%.

How much of that was the gas price improvement?

I don't know.

I don't think, we haven't dissected to that, to try to allocate it out to different components.

All right.

Thanks.

I'll leave it there.

Thank you.

All right, thank you.

Blake Fernandez, Howard Weil.

Folks, good afternoon.

I had a question for you on the Gulf of Mexico.

You talked about Shenandoah and as I understand it you've got about 180,000 acres in, primarily, in the Green Canyon area where you have 100%, and I believe the plans are to start drilling in that in 2014.

I'm just curious if, how we should think about farmed on potential there, do you maybe have increased appetite to keep a higher working interest given the success in the area?

Thanks, Blake.

I think it's more likely that we would start drilling there in maybe 2015 than 2014.

We've got some new high-quality seismic across that whole acreage position that you're referring to.

And we expect to see some very good-looking prospects there.

And until we get to the stage where we are ready to get them on the drilling program, that's when we'll think about, do we want to bring someone in before we drill the well to farm in?

So we haven't got to a stage of making that decision yet but we really are quite excited about that zip code, it's definitely looking very good.

Okay.

Great.

Secondly, I guess it's on the natural gas side, I always view Conoco as having probably more leverage than peers do, US Natural Gas, and certainly that creates some optionality.

Obviously we haven't heard anything on increased activity just yet, but is there a certain price that we should ear-mark as say, $5 in MCF where maybe you would begin to increase activity there?

We do have a lot of potential there, to invest.

But we're really focused in on investment now on the liquids-rich assets and of course we get associated gas with that so we benefit from the gas price there.

I would say that I wouldn't see us redirecting any capital towards gas assets until it's significantly north of the current prices.

On a sustained basis, yes.

Yes.

That's point too, is we'd have to get comfortable that prices have made some kind of move, that is sustainable to a higher level.

Jeff, saying that, I'm assuming, given your history, you're not the type to hedge, so I'm assuming that's not something you'd be looking to do?

That's correct.

You'd be unlikely to see us hedge.

Okay.

I'll leave it there.

Thanks, folks.

Thanks, Blake.

Brandon Mei, Tudor Pickering.

Hi, thanks.

On the Gulf of Mexico exploration plans, obviously you've got a lot going on there, but just wanted to get some color on how you see the new prospects and how they differ from what you've learned on Shenandoah and Coronado?

And then secondly, I think you have one rig, operated rig, for Thorn, just wanted to see if there's opportunity to increase that.

Yes.

So across our Gulf of Mexico portfolio we've got a mixture of Pliocene and Miocene and the lower tertiary.

The majority of the acreage that we've been picking up has been focused on the local lower tertiary but we do have some balance in the portfolio there.

We have this operated one single slot to drill the Thorn well.

And then we have, we're picking up a long-term rig contract with a new build that's coming in 2014, the beginning of 2014, and we're sharing that 50-50 with another operator.

And we're currently evaluating our needs for more rig capability in the Gulf of Mexico and the deepwater rig capability in general so we expect to be adding to our operator capacity here over the next couple of years.

Thanks.

Thanks, Brandon.

Roger Read, Wells Fargo.

Hi, good afternoon.

Good afternoon, Roger.

Maybe just to beat the cash margin horse a little bit more, as you're looking at it as we think over the next, let's say, certainly the next couple quarters where were going to see the downtime issues, plus the asset sales actually get completed.

I know you maybe haven't broken it down by all the segments, as you said, between the prices and all.

But as we think about those projects that you're selling dropping away, a resurgence in activity off the downtime as we look at say, the fourth quarter, and then on into '14 what would you expect to see on the cash margin side?

Understanding that the next two quarters maybe a little bit obscured in terms of what you're actually achieving?

And maybe how much of it is an improvement of dropping off the projects you're exiting?

There's always going to be a fair bit of volatility based on what's going on with prices, so you almost have to set that aside to start with.

So you think about what we said at our analyst presentation, we're going from a mid-20s kind of cash margin today over the next several years, where price has stayed the same, that's low 30s type number.

And that's being driven by new production coming online that's different.

And the new production has happened on a fairly ratable basis, between now and 2017.

You really start to see that happening for us in the fourth quarter of this year as new projects start up.

And then also ramping up on some of the Lower 48 assets as well.

So it's going to be, prices didn't change, then you'd see a fairly steady increase in our cash margins over that timeframe.

But I can't really tell you how it's going to be in the second quarter or the third quarter.

I think you're asking a question of how about the impact of things dropping out of our portfolio?

And you kind of are already seeing that already, because we've started reporting Algeria and Nigeria, Kashagan didn't have any production right now but reporting those assets as discontinued operations so actually having those sold, probably not going to change much from the presentation that you see today.

Okay.

So I guess that was part of my question, so the $26.53 in Q1 is the right run rate going forward?

Yes.

Okay, that's helpful.

And then, as you think about Alaska, what would be the time-frame in which you'd be able to reevaluate your existing projects, or let's call it your inventory of projects, and actually make a decision going forward, that we would maybe begin to think about Alaska as something other than a declining production province and something could actually grow?

So, Roger, we'll be doing that as we go through our planning process this summer.

And into the fall.

And looking at how this change in the fiscal regime influences the competitiveness of the incremental projects that we can see there.

And we'll put that in the mix, and then I certainly expect to see us want to increase investment in Alaska, based on this change.

Okay.

But if we think about budgeting this fall, given the time to get equipment up there and all, you'd really be looking at probably the winter of '14, '15 to get more active?

Yes.

And in some areas we can ramp up that quickly, that's pretty fast for somewhere like the North Slope but of course if it's major projects, adding new phases of West Sak development or adding new drill sites Kuparuk or in the NPRA, these things take quite a bit longer than that, to get moving.

Okay.

That's helpful.

Thank you.

Thanks, Roger.

Iain Reid, Jefferies.

Hi, good afternoon, everyone.

Hi, Iain.

Couple of things.

A couple of questions about Australia to begin with, if you don't mind.

On Poseidon, you've drilled several wells there now and also farmed it down.

I wonder if you can say how close you are now to get into say, feed, and what you're thinking about in terms of the potential development, is it going to be a stand-alone development or maybe tied back to something else?

Obviously Woodside have recently put their Browse thing a little bit back now.

So that was the first thing.

And the second thing is on APLNG, you've been trying to farm this out for a while, trying to farm down further than your current interest.

Is there any progress on that?

Or is the appetite of people for Australian coalseam gas diminished a little bit compared to where we were a couple of years ago?

So that was the first --

Okay.

So let's take Poseidon first.

So to answer the questions that you are asking, what's the right development plan, where should we take the gas.

That's the whole purpose of the appraisal program that's underway just now.

And we anticipate the appraisal program will be somewhere between five and eight wells.

So we'll be appraising all the way through this year and probably into early next year.

And the whole purpose of the appraisal program is to get us the data that we need to optimize the development plan.

So that's what we're about in Poseidon.

On APLNG, we have said that we would be interested at the right value to dilute a bit further in APLNG and that's not likely to happen this year.

So that's sort of on the back burner for the time being.

Okay.

Last one was on the Chukchi, you've had to put that on hold for regulatory issues.

What exactly are these issues?

Is it a kind of knock on from what happens to shale up there?

And once you get drilling there how do you rank that region compared to other areas where you've been pretty successful recently say, the Gulf of Mexico?

So in the Chukchi, the reason that we decided not to go out in 2014 was that we were on the cusp of having to make some very significant commitments for rigs, for vessels and so on.

And we just felt as if there wasn't enough stability in the way that the regulatory framework was shaping up for us to be able to do that with confidence, knowing that we'd be able to get the permits and get out there and actually drill when the rigs turned up.

So we just felt that the prudent thing to do was to take a pause there and let things evolve a little bit before we decide to drill those wells.

As far as the prospectivity is concerned, we still like the prospectivity in the Chukchi, there's a lot of potential out there, so we haven't given up on drilling in the Chukchi we just said we're not going to go out there in 2014.

So you're looking at a 2015 program, then?

Is that the kind of way to think about it?

Potentially.

Really what we have to understand is, make sure that we fully understand the regulatory framework so that we know what were getting ready for, and make sure that we can be ready for that.

Okay.

Thanks for that.

Thank you, Iain.

Christine, we're right at the top of the hour.

I want to respect everybody's time.

We're happy to take, Vlad and I, happy to take any additional questions you might have.

I want to thank all of you for your participation and enjoy the rest of the day.

Thank you, everybody.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

And thank you for participating.

You may now disconnect.

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