康菲 (COP) 2013 Q2 法說會逐字稿

Welcome to the Q2 2013 ConocoPhillips earnings call.

My name is Sheri, and I'll be your operator for today's call.

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

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

Please note that this conference is being recorded.

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

Ellen, you may begin.

Thank you so much, Sheri, and of course, thank you to our listeners for joining the second-quarter earnings call.

I'm joined in the room today by Ryan Lance, our Chairman and CEO, Jeff Sheets, our EVP of Finance and CFO, and Matt Fox, our EVP of Exploration and Production.

It's a very busy day for earnings activity.

I know all of you are pressed for time, so we're going to jump right into the material today.

Really quickly before we get started, if you would please, turn to page 2, you'll see our Safe Harbor statement.

That of course describes the risks and uncertainties in our future performance.

Those are all described in our periodic filings with the SEC.

I'm going to turn the call over to Ryan now.

Thank you, Ellen, and good afternoon everybody, and thank you for joining us today.

Well, it's been just over a year since we launched the independent ConocoPhillips as a new class of investment.

We've laid out a plan that would deliver growth in volumes and margins with a compelling yield.

I think as you'll hear and see today, the key pieces of our strategy are falling into place.

For the second quarter in a row, organic volumes, net of dispositions, and planned downtime are growing.

Margins are improving.

We're maintaining our commitment to a compelling dividend, reflecting our confidence in our plans, and our financial position remains strong.

So the theme of today's call is pretty simple.

We're successfully executing on our business plan.

We're doing what we said we would do.

We continue to keep our eye on the ball and the top priority for all of us at ConocoPhillips is to operate safely and execute our plans and programs.

So let's get started on slide 4. Operationally, our business performed very well this quarter.

We produced 1.552 million BOE per day on a total Company basis and 1.51 million BOE per day on a continuing operations basis.

Adjusted for dispositions and planned downtime, this represents 4% organic growth compared to a year ago.

Last quarter, we grew 2% on the same basis.

So the organic growth is showing up in our performance.

This quarter's volume performance exceeded the high end of our guidance range, and this was primarily due to two things, better than expected performance at Eagle Ford and in our Europe and Asia-Pacific regions, and our seasonal maintenance and planned downtime was executed ahead of plan.

Based on this quarter's stronger than expected volume performance, we're raising our third quarter and full year volume guidance, which Matt will cover in more detail.

As you know, the second quarter was a very active period for planned maintenance and we successfully executed key turnarounds.

That's essential to protecting our base assets.

In addition, our development activities also performed well this quarter, and remember, these are our lower risk programs, with years of inventory that completely mitigate our base decline.

Of these, the Eagle Ford stood out in the second quarter.

Production averaged more than 120,000 BOE per day, almost double last year's second quarter rate, and up 20% sequentially.

Our major growth projects are also on track.

These are projects that will generate step function growth during the next several quarters and years, and we have several near-term startups that Matt will also describe in detail.

So operationally, we're hitting the milestones we set for ourselves.

Now moving to the financial results, adjusted earnings were about $1.8 billion, or $1.41 per diluted share.

Adjusted earnings were up 17% year over year.

Excluding working capital, we generated $4.4 billion in cash from continuing operations, and ended the quarter with $4 billion of cash in short-term investments.

On a year-to-date basis, our cash from continuing operations, plus our proceeds from asset sales have covered our dividend and capital programs.

Cash margins grew compared to last year's second quarter, reflecting the impact of product mix, prices and location.

And strategically, this is one of the keys to achieving our value proposition, is high grading our portfolio by selling non-strategic assets and redeploying those proceeds into organic investments that will drive future growth.

And we're making good progress on our announced divesture program.

Since the beginning of this year we've received approximately $1.7 billion in proceeds from asset sales, and we expect to close Algeria, Nigeria and Kashagan by year-end.

These would add approximately $9 billion of additional proceeds in 2013.

As we previously discussed, our portfolio efforts will now shift toward pruning and rebalancing the asset base.

We'll take opportunities to [divest] smaller non-strategic assets such, as the Southwest Louisiana conventional assets that we sold in the second quarter, and we'll also look for ways to rebalance our interest in assets like the oil sands.

These are great assets, but one where we believe we're a bit overweighted in our portfolio today.

At the same time we're monetizing assets, we're also adding to our conventional and unconventional exploration inventory globally, and we're running this program at a high level of activity.

Exploration success like we've recently seen at Coronado and Shenandoah is key to sustaining organic growth longer term.

Despite this high level of activity, our 2013 capital outlook is relatively unchanged.

We expect to spend about $15.9 billion on a continuing operations, and $600 million on discontinued operations.

That's a total of $16.5 billion, which is an increase of about 4% compared to our announced total company budget.

Of this 4% increase, about half reflects our updated expectations around completing the sales of Algeria, Nigeria and Kashagan.

So this is capital that will come back to us as adjustments at closing.

The remainder of the increase, or about 2% reflects various adjustments across our asset base, including high quality additions to our exploration portfolio.

Finally, we remain committed to returning capital to our shareholders.

Right after the quarter ended, we increased our dividend by 4.5%, reflecting confidence in our growth plans, and we remain committed to consistent dividend increases over time.

So in summary, we have a strong quarter operationally, financially and strategically.

So next, you'll hear from Jeff and Matt, who will give you all the details.

So if you please turn to slide 5, and let Jeff begin his comments on our financial performance.

Thank you, Ryan.

This quarter's adjusted earnings were $1.75 billion, or $1.41 per diluted share.

This was above consensus, driven primarily by the higher than expected volumes that Ryan just mentioned.

Second-quarter adjusted earnings were up 17% compared to last year's second quarter, and on an earnings per share basis, adjusted earnings were up 19%, reflecting the impact of our 2012 share repurchases.

The year-over-year increase in adjusted earnings was primarily driven by higher margins.

The higher margins reflect a continued shift to higher value liquids in the portfolio, as well as a shift to more favorable fiscal regimes.

Average realized prices were flat and total Company volumes were up modestly.

Now I'll cover our production performance for the quarter, so if you'll turn to slide 6, total Company production in the second quarter was 1.552 million BOE per day.

These results included 42,000 BOE per day from discontinued operations.

This chart shows the change in both continuing and discontinued operations, compared to the second quarter of 2012, but I'll focus on the continuing operations.

Second-quarter 2012 production from continuing operations was 1.489 million BOE per day.

Adjusting for dispositions of 33,000 per day, normalized production from continuing operations was 1.456 million per day in last year's second quarter, and that's the middle blue bar on the chart.

During the second quarter of 2013, planned downtime was 10,000 per day higher than last year's second quarter, which was mostly due to downtime in the North Sea.

Growth of 219,000 BOE per day more than offset decline of 155,000 per day.

So normalized for 2012 dispositions and planned downtime, our production from continuing operations increased by 64,000 BOE per day, which I'll explain more in the next slide.

Year over year, this represents a 4% organic growth and the second consecutive quarter on this upward trend.

So let me take a moment and talk about cash margin trends on slides 7 and 8, starting with contributions from our production growth.

So this chart on slide 7 is a new one.

It shows how our second-quarter growth and changing mix drove cash margin improvement compared to last year.

As I just mentioned, volumes from our continuing operations were up 64,000 BOE per day year-over-year adjusted for dispositions and planned downtime.

This chart shows the change in this quarter's volumes by segment and product compared to last year's second quarter.

So as you can see, the relative growth which is shown in the green bars, is primarily from higher value liquids.

In addition, it's occurring in areas with more favorable fiscal terms than the Company average, and this isn't by accident as we're focused on shifting our portfolio and our investments to places with higher margins and better returns.

Normal field declines in Alaska, Europe and North America natural gas somewhat offset the growth.

The impact of this shift on our cash margins can be seen on the next slide, slide 8. This slide shows sequential and year-over-year cash margins, both on a reported basis and a price normalized basis.

As you can see on the chart on the left, cash margins grew on a reported basis despite flat overall realized prices, compared to last year's second quarter.

In terms of prices, we generally saw North America natural gas prices being offset by decreases in Brent crude prices.

So the chart on the left reflects the impact of product mix, prices, and location, and you can see from the chart that cash margins grew both sequentially and year over year.

What the right side of this chart shows is an estimate of what our cash margins would have been if we had the same pricing in all quarters, and we've used the second quarter of 2012 as a baseline, so that's pricing of $93 WTI, $108 Brent and $2.20 Henry Hub.

You can see on this price normalized basis, the cash margins grew significantly year over-over- year and also grew sequentially.

So this metric will tend to be volatile on a quarter-by-quarter basis.

However, we expect this trend to continue as we shift our production towards higher value products in places with more favorable fiscal terms.

We'll continue to periodically track and report this metric, as growing both production and margins is a key aspect of our value proposition.

So now I'll turn to the segment slide, beginning with Lower 48 on slide 9. Production in this segment was 491,000 BOE per day.

That's up 11% compared to last year's second quarter and up 3% sequentially.

We saw this improvement despite the sale of the Cedar Creek Anticline assets in the first quarter of 2013.

Total liquids production in the segment increased 20% compared to the same period a year ago, and now represents 48% of the total mix for this segment, and we expect our liquids percentage to continue to grow.

During the quarter, combined production from the Eagle Ford Bakken and Permian Basin averaged 203,000 BOE per day.

That's up 47% from a year ago.

These assets made up less than 9% of our total Company production a year ago and today these assets comprise 13% of our total Company production, and we expect they'll continue to grow.

Segment adjusted earnings this quarter generally reflect higher realized prices compared to the same period a year ago, but they also include the Thorn dry hole cost and leasehold impairment of approximately $70 million after tax.

Excluding that charge, segment adjusted earnings would have been almost $250 million.

So you can see the leverage in earnings due to the growth and the shift to liquids.

Now let's cover the Canada segment on slide 10.

Production in this segment was 271,000 BOE per day, roughly flat compared to last year's second quarter.

Liquids grew 12% year-over-year, while gas production declined 9%.

This shift has increased segment margins and should continue to improve margins over time.

Production was impacted in the second quarter by 9,000 BOE per day as a result of planned downtime at Christina Lake.

Canada's adjusted earnings of $5 million this quarter reflect stronger product pricing compared to last year and sequentially.

As a reminder, the WCS prices in our supplemental information represent a one-month lag, which better reflects our pricing for bitumen.

Now let's move to the Alaska segment on slide 11.

Production in Alaska was 197,000 BOE per day this quarter.

This was down sequentially due to planned downtime at Kuparuk and Prudhoe Bay, and the normal field decline.

Despite lower sequential volumes, adjusted earnings were $585 million this quarter, which is up compared to last quarter.

Differences between the timing of production and sales explain much of the variance.

The first quarter of this year included an adverse impact to earnings of approximately $50 million from these lift timing impacts, while this quarter included a benefit of about $25 million, a positive swing of $75 million.

We continue to analyze the impact to our business related to the recent passage of Senate Bill 21, and we expect to pursue additional opportunities for investments over time.

I'll turn now to slide 12 and talk about our Asia-Pacific and Middle East segment.

Production in this segment was 324,000 BOE per day during the second quarter, up 20% compared to a year ago, and up 2% sequentially.

Key drivers of year-over-year performance were the resumption of normal production and growth at Bohai Bay, growth at the Panyu project in China, and early production from Gumusut in Malaysia, which started late last year.

Adjusted earnings this quarter were unfavorably impacted by weaker prices, and impacts from lift timing were minimal this quarter.

Europe, the next segment is found on slide 13.

Production for the Europe segment was 173,000 BOE per day during the quarter, a decrease of 34,000 BOE per day sequentially.

This was driven by significant downtime in the Greater Ekofisk Area in Norway, and the J-Area in the UK.

Compared to a year ago, lower production is driven by higher planned and unplanned downtime, normal field declines and dispositions.

Second-quarter adjusted earnings for the segment were $261 million.

Segment performance should improve when major projects startup occur in the UK and Norway.

Before I wrap up the financial section of today's call with a discussion of cash flow let me provide an update on our corporate segment.

Our corporate segment adjusted earnings were negative $164 million in the quarter.

We are updating our annual guidance for this segment to be $750 million after tax.

That's a $150 million improvement compared to our prior guidance.

Additional information for the corporate segment and the Other International segments are included in the supplemental information that we provided with the earnings release.

If you turn to slide 14, I'll cover our year-to-date Company cash flow waterfall.

Through the first half of 2013, we've generated $8 billion in cash from continuing operations, excluding working capital.

Through June, working capital was about a wash for the year.

Year-to-date we've generated $1.7 billion in proceeds from dispositions, primarily from the sale of the Cedar Creek Anticline assets and partial working interest in the Browse and Canning basin.

So far we've funded a $7.5 billion capital program for continuing operations and paid out $1.6 billion in dividends.

Note that cash flow from operations and proceeds from dispositions have covered our dividend and capital program.

The $1.3 billion in debt and other reflects the repayment of approximately $900 million of debt at maturity during the quarter, as well as capital associated with the discontinued operations.

Something to note, although we paid down $900 million in debt during the quarter, our debt balance was unchanged, as we recorded a $900 million capital lease obligation for the Gumusut floating production system.

We have $4 billion in cash and short term investments on hand, which is just slightly lower than where we started the year.

So in summary, our balance sheet and financial position remain strong and we believe we're well positioned to execute our investment programs and our value proposition for the company.

I'll now turn the call over to Matt for an update on our operations, beginning on slide 15.

Thank you, Jeff.

As both Ryan and Jeff mentioned, the main theme of this quarter's operational performance is that we are on plan, just like last quarter.

So I'm going to cover the operations material by our capital categories, beginning with our high quality base assets, and as a reminder, our base assets refer to the assets that were producing at the end of last year.

During the second quarter, these base assets performed very well across all of our operations, and with minimal unplanned downtime.

So that means on average, everything ran better than expected because in our forecasts, we actually assume some unplanned downtime.

We protect the operating integrity of our base assets through planned maintenance.

As we discussed in the previous quarter call, we had significant planned maintenance and tie-ins scheduled for the second and third quarters of this year, In our operated assets alone we noted a downtime would be 30% higher than our five year historical average.

The chart in the lower left shows the major planned events for 2013 and their duration.

As you can see, many projects commenced later in the second quarter and a couple of these are still underway.

Others are scheduled to start in the third and fourth quarters.

I'll note a few highlights, in the North Sea, turnarounds were successfully completed ahead of schedule at Ekofisk, Eldfisk, and the J-Area.

These activities, including tie-ins for the major project start-ups, Ekofisk South, Eldfisk II and Jasmine.

Turnarounds in the lower 48 were successfully completed, as was the planned maintenance at Christina lake.

We have additional planned downtime scheduled during the third and fourth quarters in Alaska, the UK, Foster Creek and Qatar.

So our base operations are running well and our turnarounds are on or ahead of schedule.

Moving on to our development programs on page 16, these development programs consist of lower risk drilling-led activities around the world that completely mitigate our base declines, and generate higher margins and attractive returns.

These programs remain on track to deliver about 600,000 BOE per day of production by 2017, as shown in the top left graphic.

Our legacy conventional fuel development programs are on track.

For example, in places like the Kuparuk field in Alaska, ourcoiled-tubing drilling side tracks continued in the second quarter.

In Western Canada, we continue to see good results from margin-enhancing drilling programs in the liquids rich plays we're focusing on.

Results across our Lower 48 development programs are very strong.

We produced 491,000 BOE per day in the second quarter and our high level of drilling activity continues.

A couple of highlights, Bakken produced an average of 30,000 BOE per day, up 15% compared to the first quarter last year, and up 3% sequentially.

Heavy rains and flooding in the area impacted our second-quarter activity, but we're getting back on track with 11 rigs running.

The Eagle Ford exceeded our expectations in the second quarter.

Production averaged 121,000 BOE per day, almost double the same period last year, and up 20% sequentially.

During the second quarter we brought on 65 operated wells, including catching up on some of the well backlog we have.

We continue to believe that our Eagle Ford position is truly best in class.

The chart on the lower left of this slide shows third-party data on our well performance compared to the top competitors in the play.

We're one of the top producers overall, and we're producing higher oil volumes per well, more than 50% higher than the competitor average.

So clearly we have identified the sweet spot when we established our position for only $300 an acre.

We're currently running 11 rigs in the play.

We're on track to complete the drilling phase of acreage capture this year, and we're transitioning to multi-well pad drilling for our more than 1,900 remaining identified locations.

Now let's discuss our major projects on slide 17.

Our major projects remain on track to deliver about 400,000 BOE per day of production by 2017, as shown in the top left graph.

Our oil sands assets are performing as planned.

The combined oil sands properties averaged 100,000 BOE per day during the quarter, up 14% year over year.

Currently we have seven major oil sands projects in execution, and these projects are progressing on schedule.

Christina Lake phase E started up in mid-July, slightly ahead of schedule, and we should ramp to about 20,000 BOE per day net from Christina E within six to nine months.

Our Surmont 2 project is about 40% complete at the end of July, and is on track for start-up in early 2015.

In Alaska, our CD5 project is on track, and we're progressing engineering work on additional satellite projects for sanction in 2014.

With the passage of SB 21 in Alaska, we believe some of our Alaska projects are now more commercially viable, and we expect to invest more capital in Alaska over time.

In the Asia-Pacific and Middle East segment, our major projects are also on plan.

Performance from our Panyu growth project is running ahead of expectations.

We had 23 wells online at the end of June, versus 19 planned, and these wells contributed about 7,000 BOE per day net in the second quarter.

In Malaysia, key loadouts and lifts were achieved during the second quarter.

The floating production system from Gumusut is now in place.

The Siakap North-Petai project is on track, and we expect production from both projects to begin ramping up at year-end.

At Curtis Island, module installation continued at APLNG during the second quarter.

In June, we raised the roof of our first tank, a big milestone for the project.

We're still on schedule for first LNG in 2015.

Activity at both the UK and Norwegian sectors of the North Sea is very high.

At Ekofisk South we installed a new project topside facilities during the second quarter, and the project is on track to achieve first production by the end of 2013.

Also during the quarter, we installed the jackets and bridges at Eldfisk II in preparation for first oil late next year.

At Jasmine, key installations were completed in the second quarter, and offshore hook-up and commissioning work is fully underway.

First production from Jasmine is expected early in the fourth quarter.

The graphic on the lower left shows the expected production start-ups during the third and fourth quarter of this year, and as you can see, the projects we've been talking about for a while are now coming to fruition.

And with more projects scheduled to start up next year including Eldfisk II in the North Sea, Kebabangan in Malaysia, additional phases of the oil sands, Britannia long term compression, and the South Belut project in Indonesia.

So the delivery of new production from major projects will start later this year and continue through 2014 and beyond.

Next I want to briefly cover our exploration program, starting on slide 18.

Our exploration momentum continues on several fronts.

We're building inventory of both conventional and unconventional opportunities.

We're advancing several opportunities to the drill ready stage and we're currently drilling several operated and non-operated prospects.

There's a very high level of activity in the deepwater Gulf of Mexico program.

The lower tertiary Ardennes well is currently drilling.

We have a 30% interest in this well.

During the quarter, we acquired a 20% working interest in the Gila prospect in the six-block Gila JOA.

This is a very large prospect that's also currently drilling and should reach TD this quarter, and we have additional 100% ConocoPhillips leases within the Gila structure.

So this is an important well for us.

The Deep Nansen wildcats and Tiber appraisal wells are expected to spud this quarter and we have a 25% and 18% working interest in these wells respectively.

In the Browse Basin in Australia, we're currently drilling the Proteus wildcat on an untested structure to the southeast of the Poseidon discovery.

We expect to reach TD soon.

We completed our sale of our partial interests in the Browse and Canning Basins in June as well.

Recall this was part of a deal to gain access to potential shale opportunities in the Sichuan basin in China.

In Europe, we were awarded one operator-ship and three partnership licenses in Norway's 22nd licensing round in the Barents Sea and this represents attractive future conventional inventory in a legacy area for the Company, and we expect to start testing our acreage in the Barents in 2014.

In the Kwanza Basin in Angola we completed our 2013 3-D seismic acquisition program in early April.

Also, we recently acquired an additional 20% working interest in Block 36, bringing our equity to 50%.

We also have a 30% interest in Block 37, and we are in full planning more to begin drilling early next year.

In addition, we've completed a farm-in agreement for three offshore blocks in Senegal.

These blocks provide attractive acreage to test the West African Cretaceous pinch-out play and drilling in these blocks will start next year, too.

Globally, we have activities underway in several unconventional plays.

We expect to be drilling in Poland and Colombia by year-end.

We also continue to drill and appraise the Duvernay and Montney plays in Canada, and we continue to test plays in the Permian and the Niobrara in the Lower 48.

So that was a pretty quick overview of our operations and exploration activity.

But the key take-aways are this.

The operations are running well.

The development programs are delivering.

The start-ups of several growth projects are imminent and we've got a high level of exploration activity.

I'll wrap up my comments on slide 19 with a quick review of our 2013 production outlook.

As Ryan mentioned in his opening comments, we're raising our production outlook for 2013.

This slide shows our actual 1Q and 2Q volumes and our forecast volumes for the rest of the year, on both a continuing and discontinued operations basis.

The bottom line, we're tightening our ranges in 3Q and 4Q, and we're bringing up the midpoint of our full year range by about 20,000 BOE per day, or just over 1%.

As you can see, we expect third-quarter volumes to be lower than second quarter, driven again by significant turnaround and maintenance activities.

In this case, dominated by Alaska and the UK.

Fourth-quarter volumes should ramp up from there as our planned downtime reduces and our major projects start up, and we should see a strong exit rate going into 2014.

Now please turn to slide 20 for Ryan's summary comments.

Thank you, Matt.

We're at the halfway mark for 2013, but more importantly, we're in the homestretch of a multi-year effort to transform ConocoPhillips into a unique compelling independent E&P company.

So let me also summarize the key take-aways from this call.

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

We have several important milestones to achieve in the next two quarters, and we should see good momentum coming out of 2013.

We're building our inventory and delivering visible results from our conventional and unconventional exploration programs, that will sustain our growth well into the future.

Importantly, we expect to deliver our performance safely and efficiently.

Financially, we're committed to maintaining a strong balance sheet, and that can provide our financial flexibility.

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

Strategically, we're delivering on our value proposition.

We expect to complete our announced asset divestitures in 2013, and this will provide the financial flexibility to fund our investment programs, which are on track to deliver volume and margin growth, and our dividend remains a top priority.

The bottom line?

We're committed to creating long-term value by delivering 3% to 5% growth in both production and margins with a compelling dividend.

So I hope Jeff, Matt and myself have given you confidence that our plans are on track for delivering key milestones in 2013, and it will certainly position the Company for a very strong finish to the year and an exciting 2014.

So now with that, let's turn it back to the moderator and take your questions.

(Operator Instructions)

Our first question is from Faisel Khan.

Faisel with Citi.

Going to some of your comments on the transactions that you plan to close before the end of the year, can you just give us an update on when you expect precisely when those transactions will close in Nigeria and Algeria and Kashagan, versus kind of what you guys had expected when you announced those transactions earlier on?

Yes, thanks, Faisel.

When we set up our plans last year, we were thinking towards the latter half of the year, mid-year for some of the transactions, maybe a little bit later.

It looks now to us that we'll probably -- we'll complete all those transactions by the end of the year.

They're complex, full-country exits with respect to Algeria, Nigeria and Kashagan.

So you can probably appreciate the complexity that's there.

But we're on track to finish those by the end of the year, which is what we've said all along.

In terms of planning, we were thinking maybe a few of them would be done by mid-year, but they'll stretch into -- a little bit into the third and fourth quarters.

Okay.

Is that influencing at all the guidance -- the change in guidance at all on both continued and discontinued ops basis?

Yes.

On the capital that we talked about, it is impacting the discontinued operations.

About 50% of the capital that we've talked about, the $600 million, roughly 50%, $300 million of that is due to those extending the dispositions.

But we get that back through post-closing adjustments on each one of the transactions.

Okay.

Understood.

Just one last question for me -- in the Eagle Ford, a lot of industry publications on talking about lower condensate pricing and lower realizations because of the, I guess, inability to move all that condensate to market, or to consume it in market.

Any issues -- can you elaborate a little bit more on how you're seeing the pricing of your Eagle Ford crude versus some of these industry publications are talking about, in terms of discounts on those lighter grades?

We don't sell our Eagle Ford crude as condensate, Faisel.

It's a black oil that we're selling, so others may be experiencing those discounts.

We are not.

Just to add on that a little bit -- back when there was more of a spread between WTI and Brent and LLS, our Eagle Ford oil tended to price between WTI and LLS as compressed.

It's trading more towards a WTI-type number, but still, as Matt's saying, a full price, full oil price for that product.

Okay, got it.

Thanks.

Appreciate the time.

Thank you.

Our next question is from John Herrlin of Societe Generale.

Three quick ones.

Ryan, you mentioned rebalancing your oil sands exposure.

Should we expect this to happen over the next few years?

Are you going to monetize, try to swap?

What are you going to do?

Thanks, John.

We've got a very large position.

We've got 100% acreage.

We've got joint ventures in Surmont and with our -- at FCCL, we're looking at a number of different ways to rebalance that portfolio.

I wouldn't get specific on any one way.

We're trying to do what's best for our shareholder -- what's best for our Company.

We want to maintain some exposure to the oil sands, but rebalance what we do have.

I would say over the next -- this year, you ought to see some efforts along those lines, but that will continue probably well into next year as well.

Okay, thanks.

With respect to the Bakken and Eagle Ford, Matt, are you comfortable with the degree of activity, or should we expect further acceleration in terms of your exploitation efforts?

John, we're quite comfortable with the strategy that we have just now, which is 11 rigs running in both the Bakken and the Eagle Ford.

We're running that in a pretty efficient way just now.

We're well lined out to do that.

We're continuing to learn from pilot tests, for example, in the Eagle Ford, and we're keeping pace with the infrastructure development.

So I think we're going to keep on that pace for some time to come yet.

Okay.

Last one for me -- in terms of burgeoning plays or newer plays, Permian and Niobrara -- should we expect to see acceleration there in activity?

We have actually increased our activity there in this year.

We've got three rigs running in the Permian just now, and testing plays in the Delaware Basin and the [Midland] basin, and we're getting encouraging results there.

We've got one rig running in the Niobrara just now, and we're continuing to test that play across that pretty extensive acreage that we have.

So we're pretty active in both the Niobrara and in the Permian.

Thanks.

I was just wondering if this could be incremental to where you were.

That's all.

Thanks.

Thank you.

Our next question is from Scott Hanold from RBC.

In the Eagle Ford, it sounded like you said you had tied in 65 wells that you drilled during the quarter, and then you had some backlog you put online.

How many wells did you get online during the quarter?

And you had a pretty nice production bump.

Was there any infrastructure that was added specifically in the quarter that also aided the increase?

So it was 65 in total that we put on in the quarter.

About 20 of those were from the backlog and the backlog reduction.

Okay.

What is your backlog right now -- right around now?

About 85.

(multiple speakers)

Running 11 rigs, what is a normal backlog you'd expect to carry?

And so is there any more opportunity to trim off that in the coming quarters?

Yes.

We're going to reduce that backlog as we work through the year, but of course there's always a backlog almost by definition.

It takes time to hook up, but by the end of the year, we'll probably have 50 or 60 wells that are drilled and not tied in.

Okay.

Got it.

And then, your 1,900 locations that you talked about drilling yet in the Eagle Ford, remind me -- what is the spacing that you assume there?

And what are your current thoughts on where that can go?

That assumes 80-acre spacing, and we have pilot tests running, testing alternative spacings down to 40 acres, but we don't have conclusive results yet as to what the optimum spacing might be.

So those 1,900 continues to be based on 80-acre spacing.

Okay.

How long, or when should we hear about the more conclusive result?

Is that an end-of-year thing?

Is that more 2014?

That's more 2014 really before we -- I mean, information continues to come in.

But before we would draw any definitive conclusions, it's probably sometime next year.

Okay.

Any early thoughts though?

Is it pretty encouraging so far?

Really, it's just too early to say, Scott.

There's -- I don't see us increasing our spacing from 80, but we continue to look to see if there's value optimization in reducing that spacing.

Okay.

One other thing on the oil sands plays -- you talked about rebalancing that.

And can you remind me -- so, within your guidance for 2013, is there any effect of this rebalancing effort for the oil sands yet?

No, there's not, Scott.

Okay.

Thank you.

Thank you.

Our next question is from Ed Westlake of Credit Suisse.

Yes.

I guess, continuing on the theme just around the shale portfolio, I mean, it feels like obviously the Eagle Ford has been great for some of the companies who have been there, including yourselves.

Do you feel that your shale production, particularly in the liquids, will slow a little bit in 2014, and reaccelerate as you add activity to these other plays?

I mean, maybe give us some color about how you see the evolution of that.

Well, we expect to see production to continue to grow in the Eagle Ford, Bakken and the Permian over the next few years.

The Permian from an unconventional perspective, and we've seen a lot of potential there.

We're seeing probably at least two producing intervals in the Avalon, two or three in the Wolf camp.

So we continue to be encouraged by the unconventionals in the Permian.

So time will tell just how much that contributes to growth in the long term, but we do expect to see growth in the Eagle Ford, the Permian and the Bakken for several years to come, frankly.

And then a question for Jeff -- diving into the weeds on the cash flow statement, two line items -- this will be fun -- two line items that are difficult for us to forecast.

One is deferred taxes, and then there is a category you have, which is other.

Obviously, as we focus on cash margins at the E&P level, obviously it has to translate into cash flow for the Group.

So, on deferred taxes, is that predominantly US, or is there some international component in there in the 2013 numbers so far?

Yes, there is.

It is -- a big part of it is US, but also Norway and the UK are pretty substantial contributors as well.

If you think about what deferred taxes is, is just where you're able to take more rapid tax depreciation than financial depreciation, and the UK and Norway both have fairly accelerated tax depreciation.

Of course, the US has some IDC benefit as well.

And then, on the other line, it was a $500-million swing first quarter to second quarter.

Can you just talk -- what is in that other line?

Thanks.

That is a difficult one, because there are a lot of things that go into the other line.

Maybe just a little bit of -- if you think about how to think about all the things that go into the cash flow statement for us overall.

When we talk about cash margins, we took a very simplified approach, and have net income plus DD&A, and talk about that as our cash margin.

But for us going forward, deferred tax is probably a pretty substantial positive for us this year and probably on into next year.

A lot of the other items on the cash flow statement are going to generally offset each other.

You'll see that cash flow from operations other line.

It's going to fluctuate from quarter to quarter, probably for the year, that's probably a $200-million negative typically.

In particular, though, if you looked at the first quarter of this year and the fourth quarter of last year, those were unusually negative numbers.

And those were both results of some special items which had positive effects to income but were non-cash impacts, where the offset to that is in the cash flow from other line.

So I would say the fourth quarter and first quarter were pretty anomalous numbers for that line item.

And you should think of that line item as being more of a few hundred million dollar negative for the year for most years.

That's very helpful.

Thanks, Jeff.

Thank you.

Our next question is from Paul Cheng of Barclays.

Matt, on Eagle Ford, you're saying that you're going to move into the pad drilling.

How many rig is actually already in the pad drilling at this point?

We've got four or five that are currently pad drilling in the Eagle Ford.

And so as we move -- I presume that by mid of next year or second quarter or so you're going to be 100% in pad drilling.

And at that point, when is your best guess in terms of your unit costs will change -- 10%, 15% of the improvement, or you think that you may be able to drive better than that?

Well, time will tell.

We know that we'll see improved efficiencies from the pad drilling with fewer rig moves, and all the other benefits that come from pad drilling, but I think it's too early, Paul, to put a number out there.

We know we'll see efficiencies, but I wouldn't put a number on it just now.

I'm not sure -- maybe I missed it.

I have to apologize if that's the case.

Do you guys ever coming out with a little bit of the longer-term production or resource target for Eagle Ford and Bakken, let's say, by 2017, how much do you think that those two areas would be able to produce at?

We haven't come out with any updated view of that yet.

But we've got it in the analyst meeting material, both for Bakken and actually for all the Lower-48 plays in the analyst meeting material.

That we put out last year, so, Paul --

February.

Any kind of update?

No, we're really kind of working through that process now.

But the great part about getting to the position now where we've got the Eagle Ford acreage primarily held by production is we've got a lot of flexibility to step back and ask ourselves -- what is the optimal way to develop that field?

And we've got a lot of work going on to do that right now.

Right.

And Jeff along that line Matt painted a pretty rosy picture in terms of all the opportunity.

So from a CapEx standpoint, are you still looking at running around the $16 billion a year over the next several years, or that is also start to may need to see some adjustment?

No, Paul.

We're targeting that $16 billion annual number.

So we see some changes in the mix as we go forward over the next five years.

We've got some major projects that start ramping down.

And we see some opportunities in our base plans, as Ellen described, that ramp up some of the unconventional North American stuff.

But no, we still think $16 billion is the right number to use.

Ryan, seems like you upped this year's production target update.

How about next year -- is there any change?

No, not at this point.

Not at this point.

And then finally, Matt, in Eagle Ford, you are running 11 rigs; in Bakken, you're also running 11 rigs, but it does look like you have a stronger position in Eagle Ford.

Is there any reason why we are running the similar amount of rigs?

I presume that the CapEx -- I'm not sure if you run both of them 11 rig, that the CapEx program on the two basins at this point are dramatically different this year.

Is there any particular reason why you haven't shift more of your effort into the Eagle Ford?

We're managing the pace of activity to make sure that we don't get ahead of infrastructure, to make sure that we're able to run safely and efficiently.

And the reason you don't see so much production appearing in the Bakken from the 11 rigs we have running is we've got probably our average working interest in the Bakken is 50% or less, and whereas in the Eagle Ford it's in the high-80% to 90%.

That's why you're not seeing the same in the bottom line.

And the underlying rates from the Eagle Ford are better than the Bakken as well.

But we're really trying to make sure that we're managing and running an efficient, safe program with these rigs.

So we should assume that the 11 rigs for each basin is at least here to stay for the next one or two years?

Certainly our intention is to stay around that level for the next year or so, and we'll learn as we go.

We'll learn from our pilot tests, and we may adjust that, but right now, yes, for modeling purposes that's what I would assume.

Thank you.

Thank you.

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

I've got a couple of quick ones, please.

So you've mentioned that you might consider having a look at Alaska, in terms of perhaps incremental investment.

You've also got interests in what is a growing suite of exploration success in terms of long-term capital planning.

How should we think about balancing those two items?

Does the CapEx go up to accommodate those incremental projects, or does it get reallocated away from different areas?

If you could help us with that, and I've got a follow-up, please.

So the $16-billion number includes assumptions about major capital projects that will come, for example, from an exploration program.

And any increase that we see in Alaska is also included in opportunities that we are modeling within the $16-billion overall program.

And so you shouldn't see an increase from the $16 billion to accommodate those.

Okay.

Those major capital projects, have they also included in your production outlook, Matt?

Yes, they are.

Just to be clear, not in -- when we talk about our production outlook out through 2016 and 2017 at the analyst presentation -- those are not -- we don't have anything for the Gulf of Mexico discoveries in that production outlook.

But we have had some assumptions that as we get towards the end of that period, we are going to start spending capital there.

And you'll see that production probably show up outside of the time period that we've talked about where we've kind of talked about the production guidance.

So there's no -- (multiple speakers)

That makes sense.

So there's capital going into those projects in the Gulf of Mexico, for example, but no production.

In Alaska, we were not assuming in our plans last year that we would -- that we'd see incremental production in Alaska.

That incremental production will be tied to activity associated with SB 21, but we do have the capital flexibility to accommodate that.

Got it.

My follow-up, Matt, is maybe just on some of the well results you've had recently on both the Bakken and the Eagle Ford.

We're monitoring this stuff, and it looks like just in the last couple months you've had some pretty stellar well results.

I'm just wondering if you can confirm you're seeing that in your production trends, and if you could maybe help us understand if something's changed?

Are you drilling a particular area?

Are you changing well design?

What's going on there, now we got [a pump]?

Thank you.

We're continuing to evolve, for example, our frac design in places like the Eagle Ford.

The number of stages that we pump, the volume of proppant that we pump, and we're doing that as we learn from our pilot test.

And what we're learning is that more stages and more proppant makes a difference.

So going forward, we're going to continue to optimize that.

So you're seeing your 2013 vintage wells delivering better than, let's say, 2012, 2011 wells?

Yes.

On average, that's what's going on, yes.

Okay, great.

I'll leave it there, thanks.

Thank you.

Our next question is from Paul Sankey of Deutsche Bank.

Can I clarify on the [disposal] program?

I think you said you expected it to be complete by 2013.

I seem to be referring to Nigeria and Algeria.

Could you just repeat, excuse me if I missed it, what you said about Canada as well?

I know that things changed there a bit versus your expectations.

I wanted to understand how you're thinking about that going forward.

Thanks.

Thank you, Paul.

In terms of Canada, we're continuing to look at the opportunities.

We may see a little bit before the end of the year, but most of what we're trying to do in Canada will stretch well into 2014.

If you're referring to Kashagan, you've probably seen the news.

We were notified in early July by the Kazakhstan government that they've elected to preempt on the arrangement that we had with OMV, and we're in conversations and discussions right now with them on a purchase-sale agreement, and those are going quite well.

So that's progressing along.

Okay.

My understanding was that kind of in the likely order of events, it would be first Algeria, then Kazakhstan, and Nigeria was difficult to second guess.

In terms of the Kazakh agreement, I would assume that's fairly straightforward, that they pay the same price that was offered by ONGC?

Yes, that's correct.

Right.

So that should go pretty quickly, and then obviously the other two.

I guess that you're finding that these deals are highly accretive to you, right?

Yes.

No, you're absolutely right.

So it would be logical to consider further disposals for next year to continue the accretion?

Well, I think, as I tried to explain, when we get done with the three that we've described here today, we've got some rebalancing we want to do in the oil sands that we talked about.

And I think it's healthy and prudent to continue to prune the portfolio on the low end.

So there's some modest level of divestitures that we see out over time in the portfolio, in the $1 billion to $2 billion range or something like that.

But we don't have any large ones that we've talked about, other than looking at trying to rebalance in our oil sands position.

Yes, I understand.

And then, obviously the 3% to 5% double target that you've got is -- as I think Paul Cheng highlighted this -- is basically unchanged by today's better outlook for this year's volumes?

Yes, we're sticking to the 3% to 5%.

Again, we pinned that back when we came out 1.5 years ago.

You can do the math and do different numbers, depending on when you pick your starting point and ending point.

But I'm anchored back to when we came out as an independent company in May of last year, and that's our commitment over the next four to five years is you'll see that growth in both volume and margins for the Company.

Just to completely reiterate what's been said before, you're basically saying that at that point, you would be covering the dividend and the CapEx annually, based on, I think it was a $110 oil, is that right, by 2017?

Well, it's probably a little bit lower oil price -- we don't assume $110 oil.

We're probably more like $90 to $100 kinds of prices, and middle-$3 Henry Hub prices.

We start fully covering our CapEx and dividend in the next couple years, but that deficit starts shrinking pretty quickly over the next couple years.

So it's very manageable with the proceeds that we estimate we'll have by the end of this year -- the cash we'll have on the balance sheet -- that's the plan, and we can cover it very easily at that point.

Okay, great.

I understand.

And sorry, again, I apologize if I missed this, but was there a specific update on the progress in Australia, and where your project stands relative to the other two venture projects going on down there?

The AP LNG is in good shape.

The project is now about 45% complete, and we are making good progress.

We're still on track for starting up in 2015.

And there was a cost review I believe, which came through with some new numbers?

Yes.

We reviewed that at the analyst -- the results of that at the analysts meeting earlier in the year, and there's no change from what we described then.

Other than we've seen some fairly significant strengthening of the US dollar versus the Australian dollar, which has probably mitigated some of the cost increases we thought we were seeing in US dollar terms.

I think what we said was like a 7% increase in the underlying cost, in the as-spent currency, and that was looking like a 20% increase in US dollars.

Depends on how FX goes -- it might not be quite 20% increase on the US dollar basis now.

Great.

Thanks, that's helpful.

Thank you.

Thank you.

And the final question we have time for is from Kate Minyard of JPMorgan.

Just a quick question for Jeff.

Thanks for providing the color on slides 7 and 8. Can you talk about the cash margin improvement that might be stemming from a difference in cash taxes between 2012 and 2013, just as you've changed some of the geographic distribution of production.

Is there any impact there that you can help us extract?

Kind of the question of whether deferred taxes are part of that, is that --?

Right.

Just different cash tax rates between the regimes, exactly.

Yes.

The benefit comes from -- just pretty much the cash margin benefit comes from where we've added production.

And we've added production primarily in Canada and the Lower 48 and in Asia, and those are all tax rates which are less than our current average tax rate.

When we do this cash margin calculation, we do a simple calculation, so we can have some comparability to other companies, where we just take net income plus DD&A and call that our cash margin.

So deferred taxes don't come into what we talk about when we talk about cash margins.

As I mentioned, as you're thinking about cash flow models and things like that, you should think of deferred taxes as being like you've seen in the first couple quarters of this year, but that kind of is going to continue on because of where we're spending our capital dollars.

Okay, all right.

Thanks.

And then maybe just another question on Alaska.

As you guys look at evaluating additional investment opportunity, you said that we would talk about the evaluation in light of SB 21.

How are you taking into account potential marketability of the crudes as well, and what specific type of crude would your investments be targeting?

Is it light or is it heavy, and how does marketability play a factor?

The opportunities that we're looking at are predominantly light oil opportunities with production similar to the -- similar API to what we have just now.

We also see opportunities in the heavy oil in Alaska.

That would be a bit further out, and before we would see a significant increase in that.

Okay.

And no long-term concerns around marketability?

No, no.

Okay.

All right, great.

Thanks very much.

Why don't we go ahead and wrap it up here.

We're a little past the hour, and again, we really appreciate everybody's time and attention on such a busy day.

We will have a replay of this call on our website shortly, and of course, you're always welcome to call anyone on the investor relations team for further color.

Thanks so much.

Have a great afternoon.

Sheri?

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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