ConocoPhillips (COP) Q1 2012 Earnings Report, Transcript and Summary

Welcome to the Q1 2012 ConocoPhillips Earnings Conference Call. My name is Kim, 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 Mr. Clayton Reasor, Vice President of Corporate and Investor Relations. Mr. Reasor, you may begin.

Thank you, Kim. Well, good morning, and welcome to ConocoPhillips' First Quarter 2012 Earnings Conference Call, our final conference call as an integrated company. Today, we'll focus on key financial and operating results for the first quarter, as well as our outlook for the remainder of 2012. I'm joined by Jeff Sheets, Senior Vice President and Chief Financial Officer. As in the past, you can find our presentation material on the Investor Relations section of the ConocoPhillips website. And in addition, you can also find some presentation material that we've recently put out on each of the stand-alone companies, ConocoPhillips and Phillips 66. Please read the Safe Harbor statement on the bottom of this slide. It's a reminder that we will be making forward-looking statements during the presentation and during the question-and-answer session. Actual results may differ materially from what we expect today. And factors that could cause actual results to differ are included here, as well as in our filings with the SEC. So that said, I'll turn the call over to Jeff to take you through our first quarter results.

Thanks, Clayton. I'll start with some highlights for the first quarter. During the quarter, we had adjusted earnings of $2.6 billion. That's $2.02 a share. This is flat with the prior quarter and up from $1.82 per share in the first quarter of 2011. If you look back, in the first quarter of 2011, we had the same level of earnings that we did in the last quarter, but we saw a $0.20 per share improvement, and that reflects the impact of our ongoing share repurchase program. Our annualized return on capital employed was 12%. We generated $4.2 billion in cash from operations. That's $3.23 a share. In E&P, our production was $1.64 million BOE per day, which is 3% higher than the fourth quarter of 2011. And if you compare that to the first quarter of 2011, our production per share increased by 9%. So we had seasonally strong refining utilization of 91% globally. And during the quarter, we closed the sale of our interest in Vietnam, and we funded $1.9 billion in share repurchases, and that brings the total of share repurchases since we started the program in 2010 to around $17 billion. And as of today, we're about a week away from the distribution of the Phillips 66 shares to our shareholders, and we're executing the remaining steps of this transaction this week and right on target to complete on the 1st of May. So let's turn to Slide 3 and look at our earnings in more detail. Reported earnings for the quarter were $2.9 billion. This includes gains on asset sales of $987 million, offset by $562 million of impairments and $95 million of repositioning costs. The gains were mostly related to the sale of Vietnam business, and the impairments were primarily related to the Mackenzie Gas Project and the associated leaseholds. Adjusted earnings of $2.6 billion were flat with the first quarter last year. But as I mentioned, they were 10% higher on a per share basis as a result of our share repurchase program. E&P adjusted earnings were $2.1 billion and R&M adjusted earnings were $444 million during the first quarter, and our other segments, together, provided an additional $32 million of earnings. But Chemicals had a record quarter, and we're going to provide more details about that later in the presentation. So next, we'll look at some more detail on our segment earnings, and we'll start with E&P production, which is on Slide 4. Our first quarter production was 1.64 million BOE per day. That's down 65,000 BOE per day from the first quarter last year. If you exclude the impacts of dispositions and the suspension of our operations at the Peng Lai Field in Bohai Bay, production would have been 9,000 BOE per day more than a year ago. Our growth opportunities are performing well, and we continue to execute on our plans to exploit the unconventional resources in the Eagle Ford, Bakken, Permian and oil sands. Our unconventional plays have contributed 85,000 BOE per day compared to a year ago. These growth opportunities are part of the 47,000 BOE increase shown on the slide. We also had less downtime and a slightly increased production from Libya, which improved production. And these improvements more than offset our normal field declines. The suspended operations at Peng Lai, combined with asset dispositions and the decline in our Russia and Naryanmarneftegaz production, reduced production by about 94,000 BOE per day. And on the natural gas side, compared to the first quarter of 2011, North American natural gas production was 18,000 BOE per day lower, with about half of that coming from curtailments. Now I'll turn to the E&P earnings on Slide 5. E&P results benefited from strong crude prices. However, the strength in crude prices was offset by weakness in North American natural gas markets, and as well as NGL prices and a widening spread between crude oil and bitumen prices. Our E&P adjusted earnings for the quarter were $2.1 billion, slightly lower than the first quarter last year. As this Slide 5 illustrates $156 million of after-tax impact. We had that due to higher prices and other market factors, and that was offset by about $225 million decrease associated with lower volumes. In the U.S., earnings in the first quarter of 2012 were $158 million higher than a year ago. This reflects the improvement in domestic crude prices, but this was offset by significantly lower Henry Hub gas prices. Henry Hub averaged $2.72 this quarter, which is 34% lower than it was a year ago. Year-over-year, we saw reduced earnings in our international business. International was impacted this quarter by lower crude sales volumes and, again, significantly lower gas prices in Canada. ACO prices averaged $2.15 per million Btu this quarter, which is 44% lower than a year ago. So let's move to Slide 6, and I'll talk about some of our E&P unit metrics. As we just discussed on the previous slide, we saw strong crude prices, but this was offset by weakness in North American natural gas, NGL prices and the widening bitumen differentials. We produced around 110,000 barrels per day of NGLs in North America in the first quarter, and margins on this production were impacted by the fact that NGL prices did not move up as crude prices moved up. In addition, our first quarter results were adversely impacted by about $85 million after tax from differences between production and sales volumes and some other timing impacts. So year-over-year, these timing impacts and the weakness in natural gas and the relative weakness of NGLs and bitumen prices, along with some higher taxes, kept per barrel margins flat with the same quarter a year ago. So although we saw this disconnect between NGL and bitumen prices and crude prices in the recent quarter, this doesn't change our long-term view about our ability to grow cash margins as we shift capital towards higher margin production. As we've mentioned in our recent investor updates, we expect cash margins to grow 3% to 5% per year over the next 5 years in a flat price environment. So that completes our E&P segment results. Now let's take a look at our R&M segment results, which are on Slide 7. First quarter R&M adjusted earnings were -- of $444 million were $36 million less than the same period a year ago. And in comparing the periods, R&M earnings were negatively impacted, primarily by lower refining margins and some higher turnaround expenses. This was offset by higher earnings from volumes and improved marketing margins in the U.S. And we ran higher volumes at some of our Mid-Continent refineries where the margins were the strongest. So overall, despite improved market crack spreads, refining margins decreased, primarily due to less favorable crude differentials in Europe and the Gulf, East and West Coast regions and some lower secondary product margins. But turnaround expenses were $176 million pretax, and that's in line with our expectations. So we can move to the next slide and look at the R&M per barrel metrics. First quarter 2012 income per barrel was $1.80, and the cash contribution was $2.62. The per barrel metrics for R&M were similar to a year ago and up compared to the fourth quarter of 2011. Compared to the fourth quarter of '11, R&M benefited from both a more favorable crude differentials and improved market crack spreads, which, together, drove significantly improved refining margins and higher adjusted earnings. So we continue to look for ways to improve our margins in this space through capturing more advantaged crudes and increasing clean product yield. Our clean product yield of 84% was flat with the prior quarter and 1% improved compared to the same period a year ago. Wood River drove about 40% of this improvement in the clean product yield post the core implementation in the fourth quarter 2011. Next, we'll take a look at some of the results from our other operating segments on Slide 9. Adjusted earnings increased in both our Chemicals and Midstream segments. Chemicals' earnings were $218 million during the quarter. This record quarter reflects a very strong margin environment. Industry margins for ethylene during the first quarter were among the highest recorded in 20 years. With domestic ethylene utilization rates north of 100%, CPChem was able to capture these margins. Compared to the first quarter of 2011, Chemicals' earnings improved by $25 million, due primarily to higher olefins and polyolefins margins and volumes, which were partially offset by lower margins in volumes and specialties, aromatics and styrenics. Midstream earnings of $93 million were more than 25% over a year ago, primarily due to higher gathering and processing volumes. In the first quarter of 2011, we had significant reductions due to severe weather, which we didn't see in the first quarter of 2012. Adjusted corporate expenses were $265 million for the first quarter of 2012. That's $39 million improved compared to a year ago, primarily due to lower net interest expense and benefit-related expenses. Excluded from these adjusted corporate expenses are about $95 million in repositioning costs. Let's go to Slide 10 and look at our cash flow for the first quarter. We generated $4.2 billion in cash from operations during the quarter and closed the sale of our Vietnam business unit, resulting in proceeds of a little over $1 billion. During the first quarter, we funded a $4.4 billion capital program. $4.2 billion of that was directed to E&P and around $200 million to R&M. And E&P capital for the quarter included over $500 million in exploration in Gulf of Mexico leaseholds. I want to explain an impact on our cash flow having to do with how we account for assets that we will be selling later in the year and that we've moved to a held-for-sale category during the second quarter. The impact of that is that in our -- when you look at the other line in our other cash -- in the cash flow from operation segment, you'll see a negative. And $450 million of this negative was reflected -- was as a result of moving assets to a held-for-sale category. This was offset by a $450 million positive that is in the working capital line. So were it not for these changes, you would have seen a working capital for the quarter that was negative by about that amount. If you look across all the segments, almost all the cash from operations -- really, all of the cash from operations this quarter came from our E&P operations. R&M cash from operations were consumed by working capital changes. In our Chemicals joint venture, the -- CPChem has begun retaining cash in order to fund a complete retirement of their debt balances later this year. We also paid $2.7 billion in shareholder distributions. That's split between the $1.9 billion of share repurchases and $843 million in dividends, and these share repurchases accounted for $25 million shares during the quarter. We ended the quarter with $4.2 billion in cash and short-term investments. And related to the repositioning, we issued $5.8 billion in senior notes at Phillips 66. These notes bear a weighted average pretax cost of 4.1%. Associated with this issuance, we are currently holding a restricted cash balance of $6.1 billion in addition to the $4.2 billion in cash and short-term investments. As part of the separation, the notes will transfer to Phillips 66, and ConocoPhillips will receive a cash distribution from Phillips 66 of approximately $6 billion. Turning to Slide 11, we'll talk about our capital structure. At the end of the first quarter, our equity balance was $67 billion, up $1 billion from year-end 2011. With income largely offsetting distributions, the equity increase is primarily related to foreign exchange impacts. Our debt balance increased reflecting the Phillips 66 debt I just discussed. And if you adjust that out, our debt to cap is 25% for the quarter. I'll move to Slide 12 and talk about some capital efficiency metrics. First quarter 2012 annualized returns on capital were 12%, which is flat from a year ago. If you break this down by segment, first quarter returns were 14 -- ROCEs were 14% in E&P, 9% in R&M, 50% in Midstream and 31% in Chemicals. This is a metric we're going to continue to focus on as we invest in higher margin assets across our portfolio, and they'll be a key initiatives for both companies going forward. So I will wrap up with some outlook comments and then we'll open the line for questions. So we're going to give guidance, first, for ConocoPhillips and then for Phillips 66. So starting with ConocoPhillips, our annual production guidance for 2012 remains unchanged at 1.55 million to 1.6 million BOE per day, and that depends on the timing of dispositions. Sequentially, in the second quarter, production will be down from the first quarter. Second quarter production will include turnaround and maintenance activity of 50,000 to 60,000 BOE per day, primarily in Australia, the U.K., Alaska and our Foster Creek, Christina Lake joint venture in Canada. And production in the second quarter will also be negatively impacted by 20,000 to 30,000 BOE per day related to dispositions, including the recent Vietnam disposal. In the Peng Lai Field in Bohai Bay, current gross production is 40,000 BOE per day and should continue at this level through the second quarter. We also expect continued gas shut-ins in North America of around 9,000 BOE per day due to low gas prices, and we continue to evaluate this for a further shut-in. And our full year capital guidance for the E&P is approximately $15 billion. So I'll shift now and talk about exploration. We expect exploration expenses to be in line with our previous guidance of $1.2 billion for the year, as we continue to progress our exploration portfolio in several core areas. In Australia, we indicated last quarter that we plan to commence a 5- to 7-well appraisal program around our Poseidon discovery. The Boreas 1 well spud on April 4, which is the first well in that appraisal drilling. In Angola, our seismic program has commenced and recent discoveries in the area confirmed the exploration potential. We expect drilling to start in 2013 or later. In Bangladesh, Blocks 10 and 11, we completed seismic activity in the first quarter this year, and we're analyzing the data. We have 1.4 million acres and 100% working interest in this opportunity. In the Gulf of Mexico, we expect to spud an exploration well in the second or third quarter this year to test the Coronado prospect, and the operators at Shenandoah and Tiber are anticipating appraisal wells in 2012. In our international shale plays, we exercised the co-option for a 70% operating interest in a 5,000-acre position in the Western Baltic Basin of Poland. We have a co-option this year on the remaining 572,000-acre position. We drilled 2 horizontal wells and continue -- in 2011, and we will continue our pilot program in 2012. We plan to start up the first phase of our program in the frontier shale play in the Canning Basin in Australia, and we should commence 3 vertical wells in mid-2012. In North America, we've initiated 7 pilot programs in some of our new emerging plays in the Niobrara, Wolfcamp, Avalon, Canol and Duvernay plays. And we continue to pursue high-quality, liquids-rich unconventional opportunities globally. Now some updates on our major growth projects around the world. Efforts continue to drill our liquids-rich shale plays in North America in the Eagle Ford, the Bakken, the Permian and the Cardium plays. At Eagle Ford, we expect to maintain a 16-rig average and drill about 180 wells in 2012. First quarter production averaged 54,000 BOE per day, and current production capacity is around 60,000. It will be our priority to stay ahead of condensate takeaway capacity to reduce any further curtailments. And system constraints are now primarily related to gas takeaway capacity in construction and some other infrastructure. In the Permian and Bakken, we are running a total of 13 rigs today, 5 more rigs than last -- this time last year. We expect to average 16 rigs during 2012. First quarter production at Permian and Bakken averaged 51,000 and 24,000 BOE per day, respectively. Our SAGD projects continue to grow production. As you've seen, bitumen production from SCCL increased 11,000 BOE per day from the first quarter of last year. And we're exploring further opportunities to achieve better netback pricing, such as improving the blend ratio, alternatives to synthetic and condensate distilluants [ph] and application of new technologies. We expect to sanction the second train of APLNG during the second quarter and are currently on track to deliver our first cargo in mid-2015. And we are in the Phase 1 development of the Jasmine projects in the U.K., and 2 of the 8 project wells were drilled. And so far, subsurface results are exceeding our expectations. Jasmine production should start in 2013. And finally, for ConocoPhillips, we are targeting $8 billion to $10 billion in asset dispositions over the next 12 months. We expect to repurchase 5 billion of shares in the first half of 2012, and the timing of additional share repurchases will depend on the timing of the dispositions. So now I'll turn and give some outlook on some items for Phillips 66 going forward. In R&M, we expect turnaround activity in the second quarter to be approximately $140 million pretax and global refining capacity utilization is anticipated to be in the low 90s. The majority of the turnaround activity is expected to be in our international operations next quarter. And we reiterate our full year guidance of around $450 million pretax for turnaround expenses. With the Wood River CORE project online, we're seeing a 5% increase in clean product yields at the refinery. And if you look at our WRB joint venture with Synovis, realized over $200 million gross profit uplift from the core project during the first quarter of 2012. Next, I'll turn to a discussion of some of the growth projects in the Phillips 66 Midstream and Chemicals businesses. In Midstream, DCP has several growth projects underway. These include developments in the Niobrara, Permian, Eagle Ford, Bakken and Granite Wash plays, along with logistic opportunities in the Mid-Continent region. DCP recently announced an agreement to construct a new NGL pipeline that will originate in the Denver-Julesburg Basin in Weld County, Colorado and extend approximately 435 miles to Skellytown, Texas in Carson County. The new front-range pipeline with connections to the Mid-America pipeline system and the recently announced Texas Eastern pipeline will help producers in the DJ Basin maximize the value of their NGL production by providing takeaway capacity and market access to the Gulf Coast. In addition, DCP is also building a Sand Hills NGL pipeline to provide additional NGL takeaway capacity in the Permian and Eagle Ford. In Chemicals, CPChem announced additional fractionation capacity of 30,000 to 40,000 BOE per day -- barrels per day at Sweeny. CPChem is progressing with one of its affiliates in Saudi Arabia to build a manufacturing facility that will produce olefins, polyolefins and alpha olefins. Production is expected to begin in the second quarter of this year, and CPChem has a 35% interest in this JV. CPChem also plans to construct a 1-hexene plant on the U.S. Gulf Coast with a capacity of 440 million pounds per year. Start-up is expected in 2014. CPChem continues to progress plans for construction of a $5 billion worldscale ethylene cracker at Cedar Bayou, Texas. A final investment decision is expected either later this year or early in 2013, and that facility would take about 4 years to construct following a final investment decision. We have -- and then finally, for Phillips 66, we have 2 of our refineries on the market. Due to the increased -- due to interest from potential buyers, we're extending the timing for our trainer disposition to late May, and we also continue to market the Alliance refinery. So that concludes our remarks on ConocoPhillips and Phillips 66. As I mentioned earlier, the company's on target to complete its repositioning in the 2 independent leading energy companies on the 1st of May. We’d like to direct you to look at our Investor Relations website for the recent presentations given by Ryan Lance for ConocoPhillips and Greg Garland for Phillips 66. So that concludes the prepared remarks, and we're ready to open up the line for questions.

[Operator Instructions] And at this time, we have a question from Doug Terreson from ISI.

So you guys have covered a lot the past few Mondays, but in E&P, and specifically in exploration, Jeff, you mentioned Poland and Bangladesh along with a host of others. And so I just wanted to see what the drilling plan was for those 2 countries during the next 12 months or so. It seems like there's momentum there. And also, any commentary that you may have on recent exploration development activities in China.

In Bangladesh, it's too early for us. We're just in the seismic phase right now, so we don't have -- too early for us to really give any thoughts around drilling programs there. In Poland, we're going to continue at kind of the pace we are at and to try to further delineate that play. But it will be relatively low levels of expenditure there going forward. On Bohai Bay, we are in the process of going through a ramp-up of production to the levels that have been approved by the authorities. We're still in the process of working through the long-term development plan for the field. That's going to take us up to around 40,000 BOE per day. It's about 19,000 or so, net to ConocoPhillips at Bohai Bay.

Our next question comes from Faisel Khan from Citigroup.

I have a number of kind of small questions. On the bitumen pricing for upstream, it looked like your equity affiliates pricing was much lower than your consolidated operations. And I guess historically, that number has always been much higher. I suspect that's because of the joint venture with Synovis. If you could just elaborate a little bit on what's going on there. Why has the pricing shifted now to a discount versus your consolidated operations?

I think you probably see those move back and forth over time, and I wouldn't assume that there's going to be a discount on all of them going forward. There was a particularly wide WTI, WCS differential in the first quarter, which we've seen close somewhat in the first month of the second quarter. We're getting an increased production from Christina Lake, which is also has a little bit higher transportation differences as well. But as I said, I think you will see -- we don't expect to see differentials as wide as what we saw this quarter. Or I think you can also expect that over time, you'll see similar realizations from both the consolidated and the nonconsolidated.

Okay, that's fair. And then on Alaska, too, it seemed like given the production and pricing in Alaska that your earnings in Alaska were clearly higher than it's been in the past. Could you also give us a little bit more color on what's driving that? Sorry to bog you down with small questions.

Yes. That may be one way. We might have to circle back. But …

Yes, I mean generally in Alaska, there's a couple of factors which can affect kind of quarter-to-quarter. There's a bit of a pricing lag on some of the crude. So in a rising market, that can have a difference. And then of course, the tax regime in Alaska when you get up to these kinds of oil prices, that takes as a very high marginal take to you -- take. But I guess, as Clayton says, we can get back to you again with that.

[Indiscernible] more detail on that.

Okay. And then last question, to me, I think you mentioned in your prepared remarks that CPChem is investing more capital on its operations this year. So they're retaining more of their cash flows that was allocated for distributions? Is that the same for DCP? So if you can just give a little more color how those distributions from CPChem and DCP would be for the year.

So, yes, I think maybe I'll -- let me clarify and make sure that I was clear on what we said about CPChem. You are correct in that both of them have good opportunities to invest capital. But generally, we would think that distributions will be coming out of both of those joint ventures, they can more than fund their capital programs with cash flows. What's unique at CPChem currently is that we are -- we've made the decision to essentially delever CPChem and pay off their debt balances post the spin happening. So CPChem is not making any distributions to either of the partners currently. So the record earnings that they saw in the first quarter were all retained at CPChem. That'll put CPChem in a position later this year where they have a cash balance sufficient to pay off the debt at CPChem and then, I think, we would start to see some distributions from that joint venture.

Okay, understood. And is it the same thing with DCP or what? Can you give us more detail on that, too?

No. I think we actually -- we continue to see distributions out of DCP, the cash flow there.

My understanding, Faisel, is that the funding for DCP expansion, about 2/3 of that financing comes from dropping assets down into the MLP inside of DCP, DPM. And about 1/3 of the funding of their expansion comes from either noncash expenses like DNA or from about, let's say, 10% of their net income or any cash they have on the balance sheet. So they're expecting to continue to dividend out cash, as well as fund their expansion programs.

Our next question comes from Ed Westlake from Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: I guess some clarifications, then a question on CapEx in SAGD. Firstly, just on that $450 million in the held-for-sale category. So if we were trying to think of sort of cash flow before working capital, would $4.6 billion be closer to the right number to use?

That's right. So were it not for that, we would have seen about -- when you look at our supplemental information, you'll see that working capital is basically a push for the quarter. So were it not for that reclassification, you would have had about a $500 million use of cash from working capital. But if you're looking at cash flow before the working capital changes, what you said is correct. Edward Westlake - Crédit Suisse AG, Research Division: And then on CapEx, obviously, if we take in the upstream the sort of $4.15 billion, take out $500 million for leaseholds, multiply it by 4, rack [ph] back the leaseholds, you get to about $15.1 million. And normally, CapEx in the upstream companies tends to be a bit back-end weighted. So just trying to see what might be different this year in terms of being able to hit the $15 billion of guidance.

I think what's different this year is, it's not back-end loaded. We had, as many of you mentioned, the large leasehold acquisitions. We also had a fairly high spend level at the APLNG project in the first quarter as well. And we're running a pretty consistent spin through our unconventional developments like the Eagle Ford. So you won't see the same level of back-end loading in our capital program this year. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And then the final question on SAGD CapEx, the presentation that Lance gave last week, it was a $2.3 billion spend in SAGD. As we focus in a little bit more granularly on some of these assets, can you maybe just talk through what the sort of run rate or spends you'd have on the SAGD would be going forward, if there's any lumpiness to it or trends?

Yes, so I need to break that into a couple of pieces there, Ed. So if you look at how we fund the Foster Creek, Christina Lake joint venture, it goes back to how the venture was set up to start with, where we are making payments into the SCCL joint venture of -- it's around $800 million or $900 million a year, every year for what will be 10 years. We're about 5 or 6 years into that right now. And Synovis is doing the same thing on the WRB side. So between that contribution that we make and the cash flows that are generated inside the joint venture, that funds SCCL CapEx for us. So the $800 million or $900 million that I talked about is the SCCL CapEx, and the rest of it is the development of the Surmont project or 50-50 joint venture with Total.

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

A couple of things for me, hopefully, both relatively housekeeping. The first one is on your comments, Jeff, on shutting in gas. Can you just give us an idea, what would it take for you to bring your gas production back online? And given that prices have deteriorated somewhat since you made the decision, I guess, at the end of the fourth quarter, can you just give us some thoughts as to whether the portfolio is -- that you are still producing to date, is resilient at current gas prices? Or is it likely to get a little bit more aggressive there? My follow-up is on share buybacks, please.

Yes, Doug, I'm not sure that we'll see much change from where we are right now. Again, maybe to reiterate some comments that we made when we talked about this previously. If you look at our gas production across the Lower 48 and Canada, North American natural gas production, probably 2/3 to 70% of it, the economics of gas production are driven by liquids prices. So you don't see much -- there's no real reason to be shutting in that gas production. It still has strong economics. Of the 30% to 1/3 that's left of that, we operate about 1/2 of that production. Generally, our partners have not wanted to shut in production. Then we'll continue to monitor the balance of what we operate that isn't where -- the gas is more dry gas for potential additional shut-ins. But right now, we wouldn't expect it to be markedly different than what we saw in the first quarter.

So, Jeff, when you say shut-in gas, are you actually shutting in wells, or are you choking them back? I'm thinking about shut-in royalty commitments that you might have.

It probably varies from place to place. I think, for the most part, we're actually shutting them in. And royalty commitments and things like that are things we look at and evaluating whether or not we shut in.

Got it. My follow-up is really a very simple one, hopefully, on share buybacks. Whatever shares you've repurchased by the end of this month, does that still impact the share count for PSX? And can you help maybe quantify what that number would be?

Yes. So, yes, it would impact the share count for PSX. And we've talked about doing $5 billion by the end of the second quarter. We did $2 billion, basically, in the first quarter, and it's a pretty ratable purchase across the quarter.

So just to be clear then, if you did, let's say, $3 billion in the balance of the second quarter, I'm trying to understand how much -- I know it's a very small point, really, but how much would be allocated wholly to -- $1 billion in April? Okay, great. That answers the question.

Close enough to that, but for -- around that.

Our next question comes from Arjun Murti from Goldman Sachs.

I just wanted to confirm when you all talk about $5 billion to $10 billion of asset sales, you're not counting the Phillips 66 dividend within that. And then I guess, a related point is, when you talk about using asset sales for stock buyback, does that dividend also count as potential proceeds to supplement your stock buyback?

No. Okay, no. So what we are saying on the ConocoPhillips side, is that we would anticipate over the next year that we're going to have between $8 billion and $10 billion of asset sales. And then ConocoPhillips is going to have about $5 billion of share repurchases by the end of the second quarter. And as I just mentioned, we'll probably have about $3 billion of that done by the time of the spin. Then we'll do another $2 billion probably in the balance of the second quarter. And then after that, the pace of share repurchase will sync up with the pace of further asset sales. So when we talk about asset sales, we're not trying to -- we're not counting the dividend, we're not counting the Phillips 66 shares. It's just the straight asset sales.

I think I got it then. So if you do sell $8 billion or $10 billion or some other number, that would be the ballpark by which you’d do future stock buybacks beyond what you just talked about for the second quarter?

Yes. I think we would -- of course, we're going to be evaluating everything going forward, just where we earn cash from operations, what the investment opportunities in the portfolio look like and where we want to be on the debt balance. There'll be a lot of things that go into the mix. But if you go back to the -- really, what Jim Mulva said back in his presentation in March, where he said $5 billion by the end of the second quarter, and we hope to be around $10 billion depending on the pace of asset sales, that's the same kind of guidance we would give.

Yes, that's great. And then just one E&P follow-up. You mentioned some of the work you did in the Niobrara. Where is that program for you guys? How many wells have you drilled? Where are you in terms of being sort of encouraged in terms of your position and where do you think it can go over time?

I don't have those details right in front of me. What -- we may have to get back to you on...

I'd say we're early days.

Yes, it's still pretty early days. And I'm not exactly sure how much we're talking quite yet about the Niobrara.

That's great. And I'm sorry, just one very quick final one. The 24,000 barrels a day you said for the Bakken, is that Williston Basin or is that actually Bakken?

It's Bakken.

Our next question comes from Robert Kessler from Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I wanted to see if you had done any kind of -- I'm sure you have, done a look back on Bohai Bay and determined the overall financial impact as a result of the incident, and obviously, there's opportunity cost we can get with that. But there's some adjustment we have to do for the fiscal regime there, the cleanup effort directly and also the settlement. Do you have a total figure that we could use to cross-check around that?

Not that we really want to -- no, we don't, really. And we're still in the middle of discussions on Bohai Bay with the authorities there. It probably would be better for us to get everything resolved and then talk about that. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Can you give any more clarity on the fiscal take there and what -- I mean, your production volumes as reported for ConocoPhillips are already net of the sort of PSC effect. And then I guess on top of that, we need to apply an income tax, any sort of incremental excise tax or how do we think about the government take of your net share of production?

Well, the production number we talked about was our net share of production, which includes the effects, the PSC effects. I mean, other -- I don't think we would really want to provide exact kind of what the fiscal regime is absolute to those barrels. I mean, it is high-quality production with good margins. It's above average production. It's above average margin for us. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: And any estimate on overall dollars spent for the cleanup efforts? I mean not just -- not speaking to any kind of settlement or ongoing negotiation, but just actual cash outlay to resolve the incident?

I don't have that figure in front of me, Robert. We can probably get back to you on that one.

Our next question comes from Blake Fernandez from Howard Weil.

I hate to belabor the share buyback question, but if I can just confirm, the $2 billion post split in the second quarter, are we to think about that as being solely at the upstream? Or is that a combination of both upstream and downstream?

That's at the upstream. That's a ConocoPhillips guidance. Right.

Okay. So at post split, it'll just continue on the upstream?

Correct.

And then on your production guidance, obviously, we have some gas shut-in. I know you had contemplated the return of Libya. I'm not exactly sure at what level, but obviously, Libya has come back fairly quickly. In your assumptions, can you talk about what's embedded in there? In other words, are the shut-ins in natural gas already in that 1.55 to 1.6 number?

Yes, I mean it's part of the reason why we give ranges on production and guidance is that, yes, that is -- we have our uncertainties of exactly what rate Bohai will ramp back up with and just other things in our portfolio. Just as far as Libya is concerned, Libya production, I believe, in the quarter, was around 36 a day, which is about 6 higher than it was in the first quarter of 2011.

And I don't really -- based on our forecast, we don't see that going higher than that for the year. I mean, it's pretty flat looking out through the remainder of 2012.

Okay, great. The last one, if I could ask one on APLNG. I know it may be early days on this, but you're looking at FID, potentially, in the second quarter. My understanding is the real, I guess, incremental returns from that project were going to come from trains 3 and 4. Do you have any clue when we may be evaluating those?

I think we're going to just have to see how things develop, whether ultimately, there's a train 3 or 4 or whether it makes sense to take any additional resource we find to lengthen the life of the first 2 trains or we don't know whether there may actually be capacity in others' trains that could make sense to use longer term. So it's really too early for us to try to make an estimate on whether or not there will be additional trains there. There just be a lot of options, but what we think is still a very high quality resource.

Our next question comes from Iain Reid from Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: I'm sorry, I want to come back to the buybacks on asset sales again. Given the fact that you're forecasting $5 billion by the end of the second quarter, and you're now linking pretty closely your share buybacks to your asset sales, is it a fair assumption to say that by the end of the first half, you’ll have sold $5 billion of the $8 billion to $10 billion you're talking about? And what sort of production impact is that going to be?

No. I think when we think of the share repurchase program we're currently doing in the first half of the year, we're more looking backwards at the asset sales that we have done in the previous -- first part of this year and the latter part of last year. So we're not -- I wouldn't carry that link across to things being done in the second quarter. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. And can I ask a couple of questions on where you talked about as far as ...

While on the production, Iain, I guess Vietnam is in there, right? So impact of production on second quarter from asset sales, I think, Jeff said were...

It's 20,000 to 30,000. The biggest chunk of that is Vietnam. We've got some things in the North Sea and some smaller assets in North America that could close in the second quarter, relatively small amounts there. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. So 20,000 to 30,000 is really already done?

Yes, a lot of that was Vietnam. Correct. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. Okay, and just a couple of questions about -- you mentioned taxes and also an underlift as being fairly significant negatives in the first quarter. Is taxes kind of become the continuation of the North Sea effect in Alaska? Or is there something else there which we don't know about?

It's primarily the North Sea effect. The U.K. tax increase that happened last year.

The second quarter, I guess, so it impacted the first quarter.

Yes, right. And then Alaska, again, it's a pretty progressive tax regime at the current price environments. Iain Reid - Jefferies & Company, Inc., Research Division: And the underlift, what about that? That seems like a fairly substantial number for an underlift?

Yes, it was fairly substantial. We see numbers of about that size. Well, really -- no, it is a fairly high number for an underlift. It's not completely unprecedented. It just has to do with timings of when cargoes get lifted.

And unfortunately, the ones that did affect it were international that had relatively higher margins. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. So we're talking about Australia or the U.K., something like that?

Yes, above average margins.

Right.

Our next question comes from Paul Cheng from Barclays.

Clayton, I just want to make sure I understand, you're saying that the underlift is primarily relate to Australia or that it's not related to Libya. I thought the underlift would be primarily related to Libya?

No. The underlift is -- you have underlifts and overlifts all throughout the portfolio, so it's a netting effect that this quarter netted to that kind of number. So we were overlifted in some places, we're underlifted in others. It's just the balance this time ended up with a number that we felt was significant enough we should mention it.

And, Jeff, maybe that I must be missing something, maybe you can help me. I was looking in the first quarter, your oil and gas realization is roughly about $66.7 per BOE. It's about $2 higher than the fourth quarter. Even after I take into consideration of the underlift of $85 million, your net income for the whole year is still about $15 versus in the fourth quarter, it's about $16. Your production is actually somewhat up. So -- and you're saying that -- is that the reason why the unit cost out there -- unit margin is down? You said because, sequentially, we have a higher unit cost or is there something that we're missing?

No, it's primarily driven by things like the timing on the underlift, like we've mentioned. It's driven by the fact that natural gas prices were lower in the first quarter than they were in the fourth quarter last year. NGL prices were lower in the first quarter than in the fourth quarter last year. Bitumen prices were lower in the fourth -- lower as well. Crude prices were up. And the mix of all those things...

But, Jeff, I'm sorry, but what I did is that I did look at what you report as your crude oil price and your bitumen price and your natural gas price. I did a calculation based on what you report. Your average realization per BOE net of all those what you mentioned actually sequentially is up about $2 per barrel. That is what I am -- seems I am at a loss.

Okay, we'll have to work with you on that one. I'm not sure how your -- what your calculation is. We'll have to take that one off-line.

Okay, I will do that, if I could. Clayton, do you have an actual fully diluted share cost [ph] at the end of the quarter, March 31?

We probably do. Do you have that, Jeff?

No, I just have the average in front of me. No, I don't. We can get that to you. I mean it will be on the face of the 10-Q that we file next week.

So I mean you guys have it, that you can show me a complete [indiscernible] per share?

Yes, we can do that.

And that the reposition cost, Jeff, do you guys have an estimate on what that total is going to be?

So it was $95 million in the first quarter. It's been $120 million if you look at across the fourth quarter and the first quarter. It's going to be -- you'll see it. It'll be hard to track after this because it's going to be reported in 2 separate companies. But most -- probably the majority of the repositioning costs are behind us now.

Okay. And then on a going-forward basis, on a sustainable basis, what is the estimated increase in your higher G&A costs at the 2 separate companies? Do you have a number that you can share?

It'll split evenly between the companies, and for both companies, I think we're saying it'll be around $75 million to $100 million.

Per year?

Per year, right.

Pretax or after-tax basis?

That's an after-tax number.

After-tax. Okay. And in Poland, Jeff, is there some drilling result you can share with us so far?

There's not drilling results that we are sharing yet.

Okay. The final 2 questions. In Bakken, Permian Basin and Eagle Ford, do you have a breakdown of what is your production as a percentage of frac oil, condensate and NGL?

Yes, so Eagle Ford is 60% crude or condensate.

Do you have a further breakdown between crude oil and condensate?

No, I don't, because those 2 price very similarly.

About 20% NGLs.

About 20% NGLs and about 20% natural gas. The Bakken is basically 90% crude and 5%, say, NGLs and 5% gas. Permian is...

I got it. 53% -- or 50% to 55% crude; 10% to 15% NGLs; and the balance would be gas.

That's of our current Permian production. So if you look at the things we're bringing on there, I think there's probably a higher weighting to the liquids side.

And it seems that, I mean, the refinery, don't we need one condensate per se? So that's why I wanted to see a breakdown between the condensate and frac oil. I mean, as of today, I don't think there's such a big difference in terms of the pricing. But is it possible that over the next 2 or 3 years, as we continue to ramp up the condensate and with no readily available local market for that, we would start to see big differences between the condensate pricing and the frac oil pricing?

That's something I don't have a view on right now, Paul.

Yes, I mean I guess, you're saying that our refineries aren't going to be interested in running very light liquids production [indiscernible] find a home outside the U.S.

Well, I mean, you're going to max out on your distillation tower on the very late end. So I mean, there’s really not much you can run, especially if you're going to see more of the WCS coming down, then they will occupy some of the light barrel, light column already.

Yes, I'm sure we will see some short-term dislocations in the market as we build out these plays in the next few years. But longer term, when you think about products like propanes, butanes, condensates, those are something that you can export. So that will also help any differentials that might be there.

Clayton, is there any possibility if you can, say, maybe help us there by giving us the breakdown between your condensate and your frac oil mix in those areas? That would be really appreciated.

Yes, we've got some follow-up to do with you, Paul.

[Operator Instructions] At this time, we have a question from Pavel Molchanov from Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Kind of a big picture one about the dividend. You will have unquestionably the highest dividend yield of any independent oil and gas company. And I'm just curious, your thoughts on how that positions you vis-à-vis the investment days. It's obviously not a typical, not a commonplace model for independence. So just your thoughts on that.

That's a great question because that is really kind of a fundamental difference of ConocoPhillips and much else that's out there in the marketplace today. And you can see that when we put out our investor update, we titled it as a new class of investment, kind of pointing out that difference. I mean, in many ways, we've got the assets of a major. We're going to try to have the nimbleness and culture of an independent. But from a distribution point of view, we feel like we're of a size and of a maturity, and in an industry where shareholders should be expecting that a significant portion of cash flow comes back to them in the form of a dividend. And we've talked about that being 20% to 25% of our cash flow. And that ends up giving us a dividend that's like what the integrated company has today. And we recognize that, that's going to give us a pretty high yield going out of the box. But we think that's an issue, not with the dividend, but with the share price, and that that's going to be something that will change over time. We still would be looking to maintain that kind of payout ratio longer term and also to see increases in the dividend as our earnings and our cash flow grows over time. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. And then just a quick follow-up on that same point, is there an oil price level where you would begin to be concerned about maintaining share buyback at the rate that you're currently doing, especially given that, I think as you indicated, your asset sale program may not extend that much into 2013?

Well, as prices change, we're always looking at the whole mix of things that we use our cash flow for. Though, basically, we want to maintain a capital program that's fairly consistent across the years, we don't want to be moving that up and down. We want to have a dividend that's, like I just discussed, that's at the level it is today and grows over time. We've got a lot of capacity on our balance sheet to handle short-term swings in prices. So if we get a big change in prices, we'll look and adjust. But in the near term, it probably would not see large adjustments on the upside or the downside as prices moved either up or down to the size of our capital program. And on share repurchases, we're always going to be evaluating what the best use of our proceeds are. As we look out today, we think it's reasonable guidance to say that we'll be using proceeds from asset sales to fund share repurchases.

This concludes our question-and-answer session due to time constraints. I will now turn the conference back to Mr. Reasor for closing remarks.

Well, thank you, and thank you for the interest in ConocoPhillips, as well as the individual entities going forward. We look forward to further discussions in the future. Again, you'll find a transcript of this call and the presentation material on the ConocoPhillips website. Thank you.

Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.