ConocoPhillips (COP) Q1 2013 Earnings Report, Transcript and Summary

Welcome to the Q1 2013 ConocoPhillips Earnings Conference Call. My name is Christine, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Ellen DeSanctis, 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 here 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 kind of 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 settled 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're also making progress in our sales of our Algeria, Nigeria and Kashagan assets and anticipate closing those in 2013. At the same time, as we work to monetize these non-core nonstrategic 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 selective entries in the new exploration plays globally. But Matt is 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 2 significant deepwater Gulf of Mexico discoveries in the 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, it'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. So it was a straightforward 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 million BOE in the first quarter of last year. So if you compare that to the first quarter 2013, our downtime from continuing operations was 30,000 BOE per day higher in the first quarter 2013 than in the first quarter of 2012. This downtime is primarily due to weather-related issues in the San Juan Basin and downtime at the East Irish Sea Rivers asset 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 million 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 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 from bitumen increased to 57% of production compared to 55% a year ago. So this metric is likely to evolve, though, 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 metric since 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 from the -- for the segment, reflecting the unplanned downtime in the San Juan Basin related to winter weather conditions. So with the 17% growth in 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 3 areas was 182,000 BOE per day, and for -- 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 benefit 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 the first quarter. That's up 6% year-over-year, driven by the ramp-up in -- of production in our oil sands assets. Liquids production increased 22% year-over-year, while gas price -- 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 1-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 on to 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 reforms 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 of -- 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 our cargo 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 continuing -- 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. Now 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's adjusted earnings were a 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 midyear. So -- and 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 a source of $1 billion in cash. We also generated $1.1 billion in proceeds from the sale of 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 sales -- asset sale. The -- and the nature of accounting for asset sales is that the pretax value of the asset sale's 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 impacts from the CCA disposition has impacted both the fourth quarter of 2012 and the first quarter of 2013 cash from operations -- cash from operating activities. So absent 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 the financials situation remain strong. We continue to be well positioned to execute on our -- 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 over call over to Matt for an update on operations.

Thanks, Jeff. As both Ellen and Jeff mentioned, general theme of this quarter's operational performance is that we are 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 decline, 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 our base asset discussion on Page 14. Just as a reminder, our base refers to the assets that we're 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 were 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 2 quarters. In our operated assets alone, we expect downtime to be about 30% higher than our 5-year historic average, and much of this higher downtime is related to what then needs to be performed to tie in new production in many of our operations. And we also expect higher-than-average downtime in several of our key non-operated assets this year. So I thought it would be worthwhile taking a moment to give you some highlights listed on this slide. First, the Greater Ekofisk complex schedules a major shutdown every 3 years during the summer. This year's planned shutdown will be the largest ever in the Greater Ekofisk area, and in fact, it will be the largest shutdown in ConocoPhillips' history. So this is a big deal, and our planning is going well. The shutdown at Ekofisk itself will start in early June and last about a month. In addition to planned maintenance, we will be completing ground fieldwork 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, this work will include preparations for the tie-in and startup of Eldfisk 2 in late 2014. Likewise, in U.K., we have a significant J-Area shutdown planned also for June coinciding with the Greater Ekofisk shutdown. And similar to the Norway work, a key goal of this planned event is to make preparations for the Jasmine field tie-in and startup later in the year. We also have significant turnarounds planned in Alaska, the oil sands, Indonesia and the Lower 48. So this really is a big year for planned shutdowns. But 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 provided quarterly detail for our 2013 production outlook in the Appendix section of today's presentation, and we presented this information for both continuing operations and discontinued operations for the rest of this year. And we've shown both conventions because we know there's a mix in the analyst modules out there. We want to make sure there's no confusion. Now 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 the development programs, on Slide 15. These are the low-risk drilling-led programs around the world that completely mitigate a 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 in the top left graphic. Among our legacy fields, in Alaska, Kaparuk coiled tubing drilling sidetracks continued; and Western Canada, with its high uptime 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 each acreage capture 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 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're increasing activity in both the conventional and the unconventional plays where we hold 1.1 million net acres. We're 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. And we hope to have more results here to share soon. In the Permian conventional development program, we now have our 4-operated rigs running. Our current plan assumes we'll bring on about 135 wells this year, an increase of 48% compared to 2012. So these efforts will protect our base production against generating strong margin and returns. So we've got a lot of good things going on in our development programs and we will have for the remainder of the 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 7 major projects in execution there. The combined oil sand 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 8 Panyu Growth wells are 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 a fourth quarter startup. At Curtis Island, module installation got 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 U.K. and Norwegian sectors of the North Sea is high. The picture shown in the bottom left here is of the 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 plan for selling [ph] in June. We expect the set the topside 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 4 major projects we're bringing on this year, Jasmine, Ekofisk South Gumusut and SNP, hold a total average production of about 80,000 BOE per day in 2014. But this is actually only half of the total production that will be added 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, there's the incremental production in 2014 that is an addition to the production that we'll be adding from our development programs, which essentially maintain base production flat. Now the next 2 quarters are really important, but I know our people are up to the task of safely executing our plans. So 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 2 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 of over 1,000 feet of net pay. And it looks to have good reservoir quality and good oil quality. And unfortunately, we drilled down depth of the discovery well but we didn't find a water column. At Coronado, we announced the discovery of a large 3-way closure, subsalt. This well discovered more than 400 feet of net pay, with good-quality reservoir. And we have 35% of this discovery. And the operators is now on location drilling an appraisal sidetrack from the discovery well. During the quarter, we continued to build a 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 as a real advantage. Then finally, in the Gulf of Mexico, we've got a very active drilling program underway 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, the Tiber appraisal well is expected to spud, where 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 2 wells in the Canol play. This is a Devonian shale that we believe is in the oil window on Train, with a prolific Horn River gas play. We're 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 3 wells in the first quarter. Currently, our pace is somewhat limited by gathering and infrastructure build-out here. Our well results are encouraging, but it's still early days. In the second quarter, we expect to drill our first well in Colombia in 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 in the onshore NPR-A. In Kwanza Basin in Angola we completed the second phase of our 3D seismic program in early April, and we're in full planning mode to begin drilling early next year. And finally, in the Browse Basin of Australia, we're currently drilling a Proteus wildcat in an untested structure to the southeast of the Poseidon discovery, and we expect to reach TD in late May. So there've been a lot exploration 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 takeaway from today's call is 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 on our announced asset divestitures in 2013, which will provide financial flexibility for funding our growth programs, and our dividend remains a 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 are 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 are pleased to take your questions. And Christine, I'll hand it back to you.

[Operator Instructions] And our first question is from Faisel Khan of Citigroup.

I was just 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 for -- and we're continuing to grow production. I think we had a new peak production on Monday of 116,000 BOE per day in Eagle Ford.

Okay. So -- and where do you kind of see this going towards the end of the year at?

Right now, in the Eagle Ford, we're in a pretty linear growth trend. And we will 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 progressive tax, what do you mean? You said you're 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 -- and we were looking at that. We've got a long list of projects that we are evaluating now. And we did announce that we're immediate starting to increase with this new rig that we're bringing in and that rig is going to be very focused 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 the fiscal regime on.

Okay. And this is still in terms of Alaska. So the -- you guys laid out, I guess, a production sort of decline in Alaska over the course of this year. Does this rig and the new activities sort of mitigate that decline rate, and by how much?

You won't really see any significant change in the short term. But the -- but the issue is given the new fiscal regime, our incremental capital investments worth 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 to talk about that later in the year.

Our next question is from Doug Terreson of ISI.

In March, at the Analyst Meeting, the company provided a pretty detailed outlook for production and cash margins. And on this point, I think U.S. production from liquid-rich play 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 developments that you have underway?

Yes, the -- pretty much. As Matt mentioned, the production is happening pretty much as we expected from all 3 plays, the Eagle Ford, the Bakken and the Permian. And production from these is all -- well, 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 a -- got a very favorable mix as well. So cash margins from all these assets are really much higher than our -- than the average of our current portfolio. So as you see, the portfolio, the whole -- you're starting to see that show up now finally in Lower 48 cash margins as that portfolio has moved now towards kind of about half liquids to where it was only 45% a year ago. So you're getting to -- you're starting to see that all across the portfolio. Cash margins have been a little bit hurt in Canada because of the recent weakness in bitumen prices, but we see that that's going to start recovering as well. So overall, the -- it's kind of 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 is going to cause -- growing the production at higher margins is going to cause cash margin to increase over time. So production growth is on plan and margin growth is on plan as well.

Okay. And Jeff, I think that you mentioned your efforts on optimization and how higher net backs, as I think the way you talked about it. And on this point, I wanted to see if you could highlight some of the specifics that are being undertaken to improve the netbacks 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 it's not going to be talking about [ph] marketing in Eagle Ford, for example. Matt, maybe you want to talk some about what we're doing there?

Yes. So our goal here, Doug, is to have as much optionality as we can because, as you know, there's a lot of volatility and various markers in the production itself in all 3 of those basins. So we're -- so for example, in the Eagle Ford, just now, the way that we're set up for our sales, we're realizing WTI plus about $5 from Eagle Ford, and that's a mixture of production that's going by pipeline. A lot of production is still going by truck. And some of our production is priced off LLS, some of it's priced off WTI. And our liquids, the non-NGL liquids, are sold as a light sweet crude. And because they've got very high-value metal distillate, that makes them good refinery products, so they're not going being sold as condensate. And so we're -- and we feel good about the liquid and the gas takeaway capacity just now in the Eagle Ford. In the Bakken, we're actually realizing WTI minus about $5 on average in the Bakken. And we've got a mixture of offtake as well: About 30% is by pipeline just now, about 25% we're selling to rails -- to railers to bring it south to capture the WTI-Brent spread. And so we're managing that, I think, very well. And we're developing a lot of optionality to make sure that we have flexibility to maximize our realizations.

Our next question is from Ed Westlake of Crédit Suisse. Rakesh Advani - Crédit Suisse AG, Research Division: This is actually Rakesh for Ed. Quick question on your -- if you can give any updates on your Canadian asset disposals, where we are in the process over there.

Yes. 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, and -- but we're not in a hurry. This is an important strategic transaction for the company so we're still thinking through the -- which of these alternatives we want to pursue.

The next question is from Paul Cheng of Barclays.

This is real quick. Matt, I think, in Eagle Ford, that you're primarily frac oil. And do you have any rough estimate in terms of the spread between frac oil, condensate, NGL and gas for your position in the Niobrara, Wolfcamp and Canol Shale?

It's still very early days from the -- in all of those. And they -- we do see -- have a higher liquids yield in the Niobrara, for example. And the wells we've tested there all have a high crude oil yield. The -- in 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 had -- we just tried -- drilled and cored and logged to those wells, so we don't have an estimate of that yet.

And Matt, when you say crude oil, you're really referring is frac oil, it's not condensate and NGL, right, when you say 60% in the Wolfcamp?

That's correct. That's right.

Okay. And that in the Colombia, when you drilled the first well, the vertical well, are you going to also frac it? Are you just going to, say, get some core sample?

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

And maybe this is for Jeff, that any update about the Canadian oil sand sales, where we -- where are we in the process?

I think, as Matt mentioned, I think, on -- previously, we're still evaluating the options that we have in the Canadian oil sands process. And 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 this is going to have a final decision made by company within this year.

Yes, I think that'll be fair. It's a transaction we're going to be working on throughout this year and could potentially be in the next year as well.

Okay. Matt, on the -- on Shenandoah, that is a monster well. Given that it's so great in terms of the size, should we assume from a time line standpoint, the development, you may actually need to -- at least another 2 year for additional appraisal well and then, after that, 2 year of the same [ph] and then maybe 4 year of the actual construction of the platform and all that? So were you talking about more like in the 2020, 2021 kind of time line?

So we're still working that, Paul. It's a good question. And we're in the middle of working out the time line and the appraisal requirements for that well. And so it's too early to give you a time line for that.

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

I've got a couple of questions, please. Matt, on the Eagle Ford, there's -- a number of companies now have started to chatter about the Pearsall and the [indiscernible] on their recent acreage. I'm just wondering if you are moving that -- in that direction and if there's anything you can share with us in terms of how it might augment the existing program.

Yes, yes, we know that, that potential exists on our acreage. And so that's -- we're really regarding that right now as upside relative to the Eagle Ford shale itself. But you're right, that potential could be quite significant.

But nothing in terms of exploration activity or appraisal activity at this point.

Not right now. No, not right now.

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 and 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 pretty 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? But my numbers is 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 kind of take that in kind of short-term and long-term impact. So...

I'm looking Q1 over Q1...

Yes. It's what I would call short-term impacts. Cash margins, there's -- always, there are going to be a lot of things that go into cash margins that would create a lot of noise when you look kind of quarter-over-quarter or even somewhat year-over-year. So it depends not just on what price levels happened -- or 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 it 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 those -- that production is happening, as well, makes a lot of difference. And as you point out, we did have some improvement in natural gas prices in that time frame, which helped margins. So what we showed in the call today which is what happened to actual cash margins year-over-year, including the impact of prices. Now what we think is important, though, is what happened in the cash margins over the long term kind of in a flat price environment, and that's what we really tend to talk more about, like that we spend a lot of time talking about it 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 the same way 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.

Well, only just to be clear, then. I'm looking at first quarter '13 over first quarter '12, you're saying it's up 6%. How much of that was the gas price improvement?

Gee, I don't know. I don't think I've -- we haven't dissected to that and try to allocate it out to different components.

Our next question is from Blake Fernandez of Howard Weil.

I had a question for you, in the Gulf of Mexico. You talked about Shenandoah. And as I understand that you've got about 180,000 acres in -- primarily in the Green Canyon area where you have 100% and, I believe, the plants are to start drilling in that in 2014. I'm just curious if -- how we should think about farm-down potential there. Do you maybe have increased appetite to keep a higher working interest given the success in the area?

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 high and -- good-looking prospects there. And until we get to the stage where we're ready to get them on the drilling program, that's when we'll think about if we went to bring someone in before we drill, to farm-in. So we haven't got to the stage of making that decision yet, but we really are quite excited about that zip code. This is 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 to U.S. natural gas. And certainly, that creates some optionality. I -- obviously, we haven't heard anything on increased activity just yet, but is there a certain price that we should kind of earmark as -- say, $5 in Mcf, where maybe you would begin to increase in activity there?

We did have a lot of potential there transactionally. We're really focusing our investment just now on the liquids-rich assets. And of course, we get associated gas with that, so we benefit from the gas price there. And I would say that -- I wouldn't see us redirecting any capital towards gas assets until we're seeing it significantly north of the current prices, the...

On a sustained basis.

Yes. And I think that's the point to it: We'd have to get comfortable the prices have made some kind of move that is sustainable to a higher level.

And Jeff, saying that, I'm assuming -- I mean, 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 -- you don't likely to see us hedge.

Our next question is from Brandon Mei of Tudor, Pickering.

Just 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, operator rig, for Thorn. Just wanted to see if there's opportunity to increase that.

Yes. So we -- across our Gulf of Mexico portfolio, we've got a mixture of pliocene, miocene and then the lower tertiary. The majority of the increase we've been picking up has been focused on the lower tertiary. And then we do have some balance in the portfolio there. We have this operated wide single slot to drill the Thorn well, and then we have -- we're picking up a long-term rig contract with a new-build first coming in, 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.

Our next question is from Roger Read of Wells Fargo.

I guess maybe just to beat the cash margin horse a little bit more. As you're looking at it, as we think over next, let's say, certainly the next couple of quarters where we're 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 kind of look at, say, the fourth quarter and then on into '14, what would you expect to see on the cash margin side, I mean, understanding that the next 2 quarters may be 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?

Yes, so there's always so much -- there's always going to be a fair bit of volatility just based on what's going on with prices. So do you step -- you almost have to set that aside to start with. So if you think about what we said at our analyst presentation, we're kind of going from a mid-20s kind of cash margin today over the next several years where prices stay the same, that's kind of a low-30s type number. And that's being driven by new production coming online that's different. And new production has kind of happened on a favorably ratable basis over the next -- between now and 2017. You'll really start to see that happening for us kind of in the fourth quarter of this year as new projects start up and then also you're kind of ramping up on some of the Lower 48 assets as well. So it's going to be, if prices didn't change, then you'd see a fairly steady increase on our cash margins over that time frame, but I can't really tell you even how it's going to be in the second quarter or the third quarter. I think you were asking a question of, well, "How about the impact of things dropping out of our portfolio?" And you kind of are already -- seeing that already because we started reporting Algeria, Nigeria -- well, Kashagan didn't have any production right now, but we started 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, that -- so the $26.53 in Q1 is the right sort of run rate going forward?

Yes, yes. Right.

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 say -- call, your inventory of projects and actually make it a decision going forward that we would maybe begin to think about Alaska as something other than a declining production province and something that could actually grow?

So Roger, we'll be doing that as we go through our planning process this summer and into the fall, in 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 I certainly expect to see us a onetime increase on investment in Alaska based of 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, I guess, '14, '15 to get more active?

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 and adding new phases of well site development or adding new drill sites and product or an NPR-A, these things take quite about longer than that and -- to get moving.

Our next question is from Iain Reid of Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: 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 getting into, say, feed and what you're thinking about in terms of a potential development. Is it going to be a stand-alone development, or maybe tied back to something else? Obviously, Woodside recently pushed their browsing back a little bit 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 did the -- or the appetite of people for Australian coal seam gas kind of diminished a little bit compared to where we were a couple of years ago? That was the first 2.

So -- okay, so let's take Poseidon first. So to answer the questions, you were asking, what's the right development plan there, 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 5 and 8 wells. So we'll be appraising all the way through this year and probably into early year. And the whole purpose of the appraisal program is to get us the data that we need to optimize the development plan. So yes, that's what we're about in Poseidon. On APLNG, we have said that we would be interested in -- at the right value to dilute a bit further in APLNG. That's not likely to happen this year. So we're -- that's sort of in the back burner for the time being. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. Okay, last one is on the Chukchi. You've had to put that on hold for regulatory issues. What exactly are these issues? Isn't it knock on from what happened to Shell up there? And once you get drilling there, how do you kind of 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 there in 2014 was that we were in 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 then go out there and actually drill when the rigs turned up. So we just felt that the prudent thing to do is to take a pause there and see how things -- see -- let things evolve a little bit before we decide to drill those wells. As far as the prospectivity is concerned, I mean, 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 Chukchi. We just looked -- we said that we're not going to go out there in 2014. Iain Reid - Jefferies & Company, Inc., Research Division: So you're looking at a 2015 program, then. Is that the kind of way to think about it?

Yes, potentially. We've been -- really, what we have to understand is what the -- is make sure that we fully understand the regulatory framework and so that we know what we're getting ready for and make sure that we can be ready for that.

And Christine, we're right at top of the hour. I want to respect everybody's time. We're happy to take -- Vlad and I are 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. Thank you for participating. You may now disconnect.