康菲 (COP) 2012 Q1 法說會逐字稿

Welcome to the Q1 2012 ConocoPhillips earnings conference call.

My name is Kim, and I will be your Operator for today's call.

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

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

Please note that this conference is being recorded.

I will now turn the call over to 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's first-quarter 2012 earnings conference call -- our final conference call as an integrated Company.

Today, we will focus on key financial and operating results for the first quarter, as well as our outlook for the remainder of 2012.

I am 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 have recently put out on each of the standalone 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 will turn the call over to Jeff to take you through our first-quarter results.

Thanks, Clayton.

I will start with some highlights for the first quarter.

During the quarter, we had adjusted earnings of $2.6 billion -- that is $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 on 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 is $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%.

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 are about a week away from the distribution of the Phillips 66 shares to our shareholders, and we are executing the remaining steps of this transaction this week, and right on target to complete on May 1.

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 the Vietnam business, and the impairments were primarily related the Mackenzie Gas Project and the associated leaseholds.

Adjusted earnings of $2.6 billion were flat with the first quarter last year.

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 are going to provide more details about that later in the presentation.

So, next, we will look at some more detail on our segment earnings, and we will start with E&P production, which is on Slide 4.

Our first-quarter production was 1.64 million BOE per day.

-- that is 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 down time 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 will 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 the NGL prices and a widening spread between crude oil and bitumen prices.

Our E&P adjusted earnings for the quarter were $2.1 billion; that was 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, a decrease associated with lower volumes.

In the US, earnings in the first quarter 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.

AECO 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 will 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 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 of 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 does not change our long-term view about our ability to grow cash margins as we shift capital towards higher-margin production.

As we have mentioned in our recent investor updates, we expect cash margins to grow 3% to 5% per year over the next five 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 of $444 million were $36 million less than the same period a year ago.

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 US.

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 is 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 the 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 of 2011.

Next, we will 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 the 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 and volumes in specialities, 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 did not see in the first quarter of 2012.

Adjusted corporate expenses were $265 million for the first quarter of 2012 -- that is $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 were 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 and 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 that we have 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 Operations segment, you will 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 of 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.

And 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 is 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 will 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 increase reflected in the Phillips 66 debt I just discussed -- and if you adjust that out, our debt to cap is 25% for the quarter.

I will 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 are going to continue to focus on as we invest in higher-margin assets across our portfolio, and it will be a key initiatives for both companies going forward.

So, I will wrap up with some outlook comments, and then we will open the line for questions.

So, we are going to give guidance, first for ConocoPhillips and then for Phillips 66.

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 UK, Alaska, and our Foster Creek/Christina Lake joint venture in Canada.

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 further shut-in.

And our full year capital guidance for the E&P is approximately $15 billion.

So, I will 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 five- to seven-well appraisal program around our Poseidon discovery.

The Boreas One 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 confirm 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 are 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 call option for a 70% operating interest in a [500,000-acre] (corrected by company after the call) position in the Western Baltic Basin of Poland.

We have a call option this year on the remaining 572,000-acre position.

We drilled two 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.

We should commence three vertical wells in mid-2012.

In North America, we have initiated seven 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 grow in our liquids-rich shale plays in North America and 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 and construction and some other infrastructure.

In the Permian and Bakken, we are running a total of 13 rigs today, five 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 have seen, bitumen production from FCCL increased to 11,000 BOE per day from the first quarter of last year.

And we are exploring further opportunities to achieve better netback pricing, such as improving the blend ratio, alternatives to synthetic and condensate as diluents, 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 a Phase I development of the Jasmine project in the UK, and two of the eight 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 will 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 are seeing a 5% increase in clean product yields at the refinery.

And if you look at our WRB joint venture with Cenovus, realized over $200 million gross profit uplift from the CORE Project during the first quarter of 2012.

Next, I will 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 US Gulf Coast that will have capacity of 440 million pounds per year.

Start-up is expected in 2014.

CPChem continues to progress plans for construction of a $5 billion, world-scale 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 four years to construct, following a final investment decision.

We have -- and then, finally, for Phillips 66, we have two of our refineries on the market.

Due to the increased -- due to interest from potential buyers, we are 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 is on target to complete its repositioning into two independent leading energy companies on May 1.

We would 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 are ready to open up the line for questions.

(Operator Instructions) Doug Terreson, ISI.

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, just wanted to see what the drilling plan was for those two countries during the next 12 months or so?

It seems like there is momentum there.

And also, any commentary that you may have on recent exploration and development activities in China?

In Bangladesh, we are still -- it's too early for us.

We are just in the seismic phase right now.

Okay.

So, we do not have -- too early for us to really give any thoughts around drilling programs there.

In Poland, we are going to continue at kind of the pace we are at, 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 are still in the process of working through the long-term development plan for the field.

That is 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.

Okay, great.

Thanks a lot.

Faisel Khan, Citigroup.

Have a number of kind of small questions.

On the bitumen pricing for upstream, it looked like your equity affiliate's pricing was much lower than your consolidated operations.

And I guess historically, that number has always been much higher.

I suspect that was -- that is because of the joint venture with Cenovus.

If you could just elaborate a little bit of what is going on there?

Why is 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 would not assume there is 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 have seen close somewhat in the first month of the second quarter.

We are getting increased production from Christina Lake, which also has a little bit higher transportation differentials, as well.

But as I said, I think you will see -- we do not expect to see differentials as wide as what we saw this quarter, or -- I think you can also expect that over time, you will see similar realizations from both the consolidated and the nonconsolidated.

Okay.

That is fair.

And then, on Alaska too, it seemed like, given the production and pricing in Alaska, that your earnings was -- your earnings in Alaska were materially higher than it has been in the past.

Could you also give us a little bit more color on what is driving that?

Sorry to bog you down with small questions.

Yes, that may be one we might have to circle back with.

Yes.

Generally, in Alaska, there is a couple factors which can affect kind of quarter-to-quarter.

There is 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, has a very high marginal take.

But as Clayton said, we can get back to you with more detail on that.

Okay.

And the last question, I think you mentioned in your prepared remarks that CPChem is investing more capital in its operations this year, so they are retaining more of their distribut -- more of their cash flows that was allocated towards distributions.

Is that the same for DCP?

If you could give a little more color how those distributions from CPChem and DCP would be for the year?

Let me clarify; 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 that will be coming out of both of those joint ventures, they could more than fund their capital programs with cash flows.

What is unique at CPChem currently is that we are -- we have made the decision to essentially deleverage 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 will 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.

But their cash flows are --

My understanding, Faisel, is that the funding for DCP expansion, about two-thirds of that financing comes from dropping assets down into the MLP inside of DCP, DPM.

And about one-third of the funding of their expansion comes from either non-cash expenses, like D&A, or from about -- let's say 10% of their net income or any cash they have on the balance sheet.

So, they are expecting to continue to dividend out cash, as well as fund their expansion programs.

Okay, great.

Thanks for the detail.

I appreciate it.

Ed Westlake, Credit Suisse.

I guess some clarifications, and then a question on CapEx in SAGD.

Firstly, just on that $450 million in the Held for Sale category -- if we were trying to think of a cash flow before working capital, would $4.6 billion be close to the right number to use?

That is right.

So, were it not for that, we would have seen about -- when you look at our supplemental information, you will 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.

Okay.

If you are looking at cash flow before working capital changes, what you said is correct.

And then, on CapEx, obviously, if we take in the upstream, the $4.15 billion, take out $500 million for leaseholds, multiply it by four, add back the leaseholds, you get to about $15.1 billion.

And normally, CapEx in the upstream companies tends 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 is different this year is it's not back-end loaded.

We had, as 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 are running a pretty consistent spin through our unconventional developments like the Eagle Ford.

So, you will not see the same level of back-end loading in our capital program this year.

Okay.

And then, the final question on SAGD CapEx.

The presentation that Lance gave last week, it was $2.3 billion spend in SAGD.

As we focus in a little bit more granularly on some of these assets, could you maybe just talk through what the run rate of spend you would have on the SAGD would be, going forward?

If there is any lumpiness to it, or trends?

Yes.

So, I need to break that into a couple pieces there, Ed.

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 FCCL joint venture of -- it's around $800 million or $900 million for the year, every year for what will be 10 years.

We are about five or six years into that right now.

And Cenovus is doing the same thing on the WRB side.

So, between the contribution that we make and the cash flows that are generated inside the joint venture, that funds FCCL CapEx for us.

So, the $800 million or $900 million that I talked about is the FCCL CapEx, and the rest of it is the development of the Surmont project, our 50/50 joint venture with Total.

That is a very helpful reminder.

Thanks very much.

Doug Leggate, Bank of America.

Couple of things from 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 in the -- I guess at the end of the fourth quarter, can you give us some thoughts as to whether the portfolio is -- that you have still producing to date is resilient at current gas prices, or if you are 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 will 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 two-thirds to 70% of it, the economics of gas production are driven by liquids prices.

So, you do not see much -- there is no real reason to be shutting in that gas production that still has strong economics.

Of the 30% to one-third that is left of that, we operate about half of that production.

Generally, our partners have not wanted to shut in production.

We will continue to monitor the balance of what we operate where the gas is more dry gas, for potential additional shut-ins.

But right now, we would not expect it to be markedly different than what we saw in the first quarter.

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.

You know, it probably varies from place to place.

I think for the most part we are actually shutting them in.

You know, and royalty could be --

Okay, great.

Things we look at in evaluating whether or not we shut in.

Got it.

My follow-up is really on -- very simple one, hopefully, on share buybacks.

Whatever shares you have repurchased by the end of this month, does that still impact the share count for PSX?

And can you help maybe quantify what the number would be?

Yes.

So, yes, it would impact the share count for PSX, and we have 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 --

About $1 billion (multiple speakers)

-- how much would be allocated wholly to -- $1 billion in April?

Okay, great, that answers the question.

Yes, right.

Close enough to that for -- around that.

Got it.

Okay.

Thank you.

Arjun Murti, Goldman Sachs.

Just wanted to confirm, when you all talk about $5 billion to $10 billion of asset sales, you are not counting the Phillips 66 dividend within that?

(laughter) And then, a related point is, when you have talked about using asset sales for stock buyback, does that dividend also count as potential proceeds to supplement your stock buyback?

Thank you.

No -- well, okay, no.

So, what we are saying on the ConocoPhillips side is that we would anticipate over the next year that we are 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 will probably have about $3 billion of that done by the time of the spin.

Then we will do another $2 billion, probably in the balance of the second quarter.

And then, after that, it will -- the pace of share repurchase will sync up with the pace of further asset sales.

So, when we talk about asset sales, we are not trying to -- we are not counting the dividend, we are not counting the Phillips 66 shares.

It's just a straight asset sale.

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 would do future stock buybacks, beyond what you just talked about for the second quarter?

Yes, I think we would -- of course, we are going to be evaluating everything going forward, just -- where are we in cash from operations?

What does the investment opportunities in the portfolio look like?

Are we where we want to be on the debt balance?

There will be a lot of things that go into the mix.

But if you go back to the kind of -- 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 is the same kind of guidance we would give.

Yes, that is great.

And then, just one E&P follow-up -- you mentioned some of the work you are doing in the Niobrara.

Where is that program for you guys?

How many wells have you drilled?

Where are you in terms of being encouraged, in terms of your position?

And where do you think it can go over time?

I do not have those details right in front of me.

We may have to get back to you on --

I would say we are early days.

Yes, it's still pretty early days.

And I'm not exactly sure how much we are talking quite yet about the Niobrara.

That is 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.

That is Bakken.

Okay, thank you.

Robert Kessler, Tudor, Pickering and Holt.

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?

Obviously, there is opportunity cost.

We can guess at that.

But there is adjustment we have to do for the fiscal regime there, the cleanup effort directly announced with the settlement.

Do you have a total figure that we could use to cross-check our own math?

Not that we really want to -- no, we do not, really.

And we are 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.

Can you give any more clarity on the fiscal take there and what -- your production volumes, as reported for ConocoPhillips, are already net of the 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 I think about the government take of your net share of production?

The production number we talked about was our net share of production, which includes the effects, the PSC effects.

I mean, other than -- I do not think we would really want to provide exact what the kind of fiscal regime is, applicable to those barrels.

It is high-quality production, with good margins.

It's above-average production.

It's above-average margin for us.

And any estimate on overall dollars spent for the cleanup efforts?

Not speaking to any kind of settlement or ongoing negotiation, but actual cash outlay to resolve the incident?

I do not have that figure in front of me, Robert.

We can probably get back to you on that one.

Okay.

Thanks very much.

Blake Fernandez, 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 is at the upstream.

That is at ConocoPhillips -- that is ConocoPhillips guidance, right.

Okay.

So, at post split, it will just continue on the upstream.

Right.

Got it.

And then, on your production guidance -- obviously, we have some gas shut in.

I know you had contemplated a return of Libya.

I'm not exactly sure what level.

But obviously, Libya has come back fairly quickly.

In your assumptions, can you talk about what is embedded in there?

In other words, are the shut-ins in natural gas already in that 1.55 million to 1.6 million number?

Yes.

It's part of the reason why we give ranges on production guidance, is that 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[,000] a day, which is about [6,000] higher than it was in the first quarter of 2011.

And I do not really -- based on our forecast, we do not see that going higher than that for the year.

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 are looking at FID potentially in the second quarter.

My understanding is the real incremental return from that project were going to come from trains three and four.

Do you have any clue when we may be evaluating those?

I think we are going to just have to see how things develop, whether ultimately there is a trains three or four, whether it makes sense to take our -- any additional resource we find to lengthen the life of the first two trains, or we do not know whether there may actually be capacity in other's trains that could make sense to use longer term.

So, it's really too early for us to try to make an estimate on when -- whether or not there will be additional trains there.

There will just be a lot of options for what we think is still a very high-quality resource.

Okay, thank you very much.

Iain Reid, Jefferies.

I'm sorry; I'm going to come back to the buybacks and asset sales again.

Given the fact that you are forecasting $5 billion by the end of second quarter, and you are 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 will have sold $5 billion of the $8 billion to $10 billion you are talking about?

And what sort of production impact is that going to be?

No, I think when we think of the asset -- the share repurchase program we are currently doing in the first half of the year, we are more looking backwards at the asset sales that we have done in the previous -- both early -- first part of this year and the latter part of last year.

So, we are not -- I would not carry that link across to things being done in the second quarter.

Okay.

And can I ask a couple of questions on what you talk about as far as a -- (multiple speakers)

And as far as a -- well, on the production, again, I guess Vietnam is in there, right?

So, the impact of production on second quarter from asset sales, I think Jeff said were --

Is 20,000 to 30,000 BOE, the biggest chunk of that is Vietnam.

We have some things in the North Sea and some smaller assets in North America that could close in the second quarter.

Right.

Relatively small amounts there.

Okay.

So, 20,000 to 30,000 BOE is really already done.

Yes, a lot of that was Vietnam, correct.

Okay.

And just a couple questions about -- you mentioned taxes and also an under lift as being fairly significant negatives in the first quarter.

Is taxes kind of the continuation of the North Sea effect and Alaska?

Or is it something else that -- which we do not know about?

It's primarily the North Sea effect, the UK tax increase that happened last year.

Second quarter, I guess, so --

Yes.

-- impact the first quarter.

Right.

And then, Alaska again, it's a pretty progressive tax regime at current price environments.

And the under lift, what about that?

Those things are a fairly substantial number for an under lift.

It was fairly substantial.

We see numbers of about that size.

Well, really -- no, it is a fairly high number for an under lift.

It's not completely unprecedented.

It just has to do with timings of when cargoes get lifted.

And unfortunately, the ones that it affects were international, that had relatively higher margins.

Okay.

So, we are talking about Australia or the UK, something like that?

Yes, you --

Above-average margins.

Right.

Okay, guys, thanks very much.

Paul Cheng, Barclays.

Just wanted to make sure I understand.

You are saying that the under lift is primarily related to Australia, or that it's not related to Libya?

I thought the under lift would be primarily related to Libya.

No, the under lift is primarily -- you have under lifts and over lifts all throughout the portfolio.

So, it's a netting effect that this quarter netted to that kind of number.

So, we were over lifted some places, we were under lifted others.

It just -- the balance this time ended up with a number that we felt was significant enough we should mention it.

Yes.

And Jeff, maybe I must be missing something, maybe you can help me.

I was looking at, 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 under lift of $85 million, your net income per BOE is still about $15, versus in the fourth quarter is about $16.

Your production is actually somewhat up.

So, and you are saying that -- is that the reason why that the unit margin is down?

Is it because sequentially we have a higher unit cost, or is there something that we are missing?

No, it's primarily driven by things like the timing on the under lift, like we mentioned.

It's driven by the fact that natural gas prices were lower in the first quarter than they were in the fourth quarter of last year.

NGL prices were lower in the first quarter than in the fourth quarter last year.

Bitumen prices were lower in the fourth -- in the -- lower as well.

Crude prices were up.

The mix of all those things, plus --

But Jeff, I'm sorry -- but what I did is that I did look at what you report as your crude price, 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'm -- seems like I'm at a loss.

Okay.

Well, we will have to work with you on that one.

I'm not sure how you are -- what your calculations have been.

We will have to take that one offline.

Okay, I will do that.

If I could, at Clayton, do you have a actual fully diluted share count 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.

We can get that to you.

It will be on the face of the 10-Q that we file next week.

Right.

But I mean, if you guys have that, can you send me a quick e-mail?

I would really appreciate it.

Yes, we can do that.

And the reposition costs -- Jeff, do you guys have an estimate of what that total is going to be?

So, it was $95 million in the first quarter.

It has been $120 million, if you look across the fourth quarter and the first quarter.

It's going to be -- you will see it.

It will be hard to track after this, because it's going to be reported in two separate companies.

But most -- probably the majority of the repositioning costs are behind us now.

Okay.

And then, on a going-forward basis, on sustainable basis, what is the estimated increase in your higher G&A costs at the two separate companies?

Do have you a number that you can share?

It will split evenly between the companies.

And for both companies, I think we are saying it will be around $75 million to $100 million.

Right.

Per year.

Per year, right.

Pretax or aftertax, this is?

That is an aftertax number.

Aftertax?

Okay.

Right.

And in Poland, Jeff, is there some drilling result you can share with us so far?

There is not drilling results that we are sharing yet.

Okay.

Final two questions.

In Bakken, Permian Basin, and Eagle Ford, do you have a breakdown?

What is your production as percentage of fracked oil, condensate, and NGL?

I think we do.

Yes.

Eagle Ford is 60% crude or condensate.

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

No, I do not.

But those two 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 have it -- 53% -- or 50% to 55% crude, 10% to 15% NGLs, and the balance would be gas.

That is of our current Permian production.

So, if you look at the things we are bringing on there, I'm not -- I think that is probably a higher weighting to the liquids side.

And it seems that refineries do not we need condensate per se, so that is why I want to see a breakdown between the condensate and fracked oil.

As of today, I do not think that is such a big difference, in terms of the pricing.

But is it possible that over the next two or three year, as we continue to ramp up the condensate and with no readily available local market for that, we would start to see a big differences between the condensate pricing and the fracked oil pricing?

That is something I do not have a view on right now, Paul.

I guess you are saying that our refineries are not going to be interested in running very light liquids production and --

Well, I mean you -- (multiple speakers)

You find a home outside the US.

You are going to max out on your distillation [power] on the very light end.

So, there is really not much you can run, especially if you are going to see more of the WCS coming down than 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.

I see.

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

Thank you.

We have some follow-up to do with you, Paul.

Thank you.

(Operator Instructions) Pavel Molchanov, Raymond James.

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-a-vis the investment base.

It's obviously not a typical, not a commonplace model for independents.

So, just your thoughts on that.

That is a great question, because that is really kind of a fundamental difference of ConocoPhillips and much else that is 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.

In many ways, we have the assets of a major.

We are going to try to have the nimbleness and culture of an independent.

But from a distribution point of view, we feel like we are 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 have talked about that being 20% to 25% of our cash flow.

And that ends up giving us a dividend that is like what the integrated Company has today.

And we recognize that that is going to give us a pretty high yield going out of the box.

But we think that is an issue not with the dividend, but with the share price, and that that is 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.

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 are 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 are 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 is fairly consistent across the years.

We do not want to be moving that up and down.

We want to have a dividend that is, like I just discussed, that the level -- that is at the level it is today and grows over time.

We have 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 will look and adjust.

But in the near term, you 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 are 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 will be using proceeds from asset sales to fund share repurchases.

All right.

Appreciate it.

Thank you.

This concludes our question-and-answer session, due to time constraints.

I will now turn the conference back to Mr.

Reasor for closing remarks.

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 will find the 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.