康菲 (COP) 2012 Q2 法說會逐字稿

Welcome to the Q2 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 Ms. Ellen DeSanctis, Vice President, Investor Relations and Communications.

Ms. DeSanctis, you may begin.

Thank you, Kim, and good morning to everybody.

Again, thank you for joining us on this ConocoPhillips second quarter earnings call.

I'm in the room today with Ryan Lance, our Chairman and CEO; and Jeff Sheets, our EVP and Chief Financial Officer.

And before I turn the conference over to those two gentlemen, let them make a few administrative comments.

First of all, you'll notice we have provided a lot of new information with today's disclosure; and, of course, that is to help you understand the business better.

We've provided segment data on each of our regions in addition to some data on our corporate segment.

And I just want to let people know Vladimir and I will be available after the call to help you sort through those details as needed.

In addition I want to remind you that our presentation materials for the call today can be found on our website, and a transcript of this call will be posted again to our website, hopefully by no later than tomorrow morning.

And then finally, if you advance to slide 2, you'll note our cautionary statement.

We will make some forward-looking statements during today's webcast and actual results could differ materially from the expectations we share today.

The factors that could cause these results to differ are listed in this cautionary statement as well as in our periodic filings with the SEC.

And now, it is my pleasure to turn the call over to Ryan Lance.

Thank you, Ellen, and thank you all for joining the call today.

So I reflect back.

In mid-April we laid out our plans for the newly independent ConocoPhillips, and today represents our first quarterly call to update you on those plans.

So I am looking forward to your questions at the end as well.

So I will begin my comments on slide 3, and cover some of our key second quarter highlights.

Strategically, the second quarter was certainly an eventful one.

Less than 100 days ago we completed the spinoff of our Phillips 66 Company; and while we were prepared for the event, it's really hard to know until that event actually shows up, how things go.

But I'm pleased to say that I think we hit the ground running and I certainly couldn't be prouder of our employees.

They certainly stepped up in a pretty big way.

So in addition to completing the Phillips 66 spinoff, we continue to make progress on our divestiture program.

This is a strategic program that is important for completing the repositioning of the ConocoPhillips and adding financial flexibility to the Company.

In the quarter we generated about $0.5 billion of proceeds from asset sales in the North Sea and we continue to advance our progress on other assets.

We still estimate that our announced program will be complete by mid-2013.

I also include a point about our unconventional and our conventional exploration program as a strategic highlight.

We made progress in the quarter on these important activities, with more to come in the year.

And I will speak about our exploration activities in more detail in a moment, because this is an important part of our plans for the future and we have a lot going on in this area.

Operationally, the Business ran well in the quarter.

We achieved the high end of our estimated production range for the quarter at 1.54 million barrels equivalent per day.

Key production highlights include our ongoing strong performance from unconventional assets in the Lower 48, led by our Eagle Ford development; and from our oil sands in Canada.

Our major projects have progressed, notably our APLNG; and in the second quarter we advanced at Train 2 towards FID, and recently announced that milestone.

Both Jeff and I will cover some additional details about our operational performance in later comments.

Moving to the financial themes, clearly our strong operational quarter was overshadowed by weaker commodity prices.

This translated into lower income and cash flow for the quarter compared to prior periods.

It's important to note that our diversified portfolio helped buffer some of the impact of weaker North American commodity prices.

This allowed us to generate $1.5 billion of adjusted earnings, or $1.22 of adjusted earnings per share.

Excluding working capital, we achieved $3 billion in cash from operations.

What is important to note is that this cash flow number reflects the fact that we had a number of high-margin production off-line due to planned turnarounds this quarter.

In other words, the $3 billion should not be considered ratable.

And finally, we purchased $3.1 billion of ConocoPhillips shares in the quarter, representing a total of about 52 million shares.

And through six months, we have delivered on our goal of repurchasing $5 billion worth of shares.

So in summary, we had a strong quarter, strategically and operationally, delivering on several important fronts.

While commodity prices softened, we stayed focused and delivered on things we can control to meet our commitment for growth, financial returns, and yield over the long terms.

So if you would turn to slide number 4, I would like to address the state of the business and put some perspective around the focus areas and the priorities for the rest of the year and beyond.

As I already mentioned, the businesses running well and that is absolutely key.

We are focused on delivering our programs and plans safely, on time, and on budget.

Our major growth projects are on track and these included our Lower 48 unconventional resource plays as well as our major growth projects in the Canadian oil sands, the North Sea projects in the UK and Norway, APLNG, and our Malaysian deep water projects.

These are the major projects that will underpin our long-term goal to deliver 3% to 5% with margin expansion at flat prices.

Aside from the major times major projects, the base businesses also running well.

As you know, second and third quarters are typically high season for maintenance downtime, but we have those activities well in hand.

Finally, we continue to starve dry gas drilling and divert capital to the liquids-rich plays.

As I mentioned a minute ago, our exploration program continues to gain momentum.

This is an aspect of the business that we are reemphasizing in the new ConocoPhillips, and I would like to give you some highlights of that.

First, I should note that, when I talk about exploration, I talk about it through two lenses -- a conventional lens and an unconventional lens.

And we have a lot of activity in both our unconventional and conventional programs throughout the year and in this second quarter.

In the unconventional plays we continue to test liquid-rich opportunities in North America.

We have pilot programs actively underway, and in plays like the Niobrara, the Wolfcamp, the Duvernay and the Avalon.

We are also evaluating several other opportunities, some of which are associated with ConocoPhillips' massive land position in the Lower 48 and Western Canada.

With approximately 21 million net acres, much of it held by production, we have access to some potentially impactful unconventional plays.

One example that I would like to share with you this morning is the Mancos Shale in the San Juan Basin.

We are the largest leaseholder in the San Juan Basin today, with 900,000 acres held by production.

We have been actively reviewing our extensive data across the Mancos in the gas, the liquids-rich and the oil window, and plan to test the play later in the year.

Other companies are actively testing the play now, which means we are effectively de-risking the play with other people's money.

If the play is successful, we have years and years of drilling activity ahead.

It's opportunities like these -- in our backyard, adjacent to where we have operating infrastructure and experience and already held by production -- they are what create long-term running room for the Company in this unconventional space.

Internationally, we are currently getting ready to pilot test our 11 million-acre unconventional shale position in Australia's Canning Basin.

Now let me move to the conventional side.

We made significant progress here this quarter as well.

During the quarter we spud three non-operated wells in the deepwater Gulf of Mexico; an appraisal well was spud on the Shenandoah prospect; and two wildcat wells were started at the Bioko and Coronado prospects.

We continue to build our deepwater prospect inventory in the Gulf of Mexico, largely focused on the Paleogene play.

We added a significant chunk of acreage late last year, and as well, we now hold more than 325 blocks in the Gulf of Mexico.

Finally, earlier this year, we added significant conventional acreage positions in Angola and in Bangladesh, and we're undertaking seismic activities in both those areas right now.

So we are busy in the exploration area and we think this is an important part of the business where we are very effectively positioning for future growth in taking advantage of good opportunities as they arise.

This, combined with our 43 billion-barrel resource space is providing optionality to our growth.

On the business development side, we are very focused on completing our announced asset sale program.

We have targeted selling $8 billion to $10 billion of assets by mid-2013.

We have several packages on the market today.

When we started this divestiture program we understood some of the assets would take some time to sell, but overall, I'm pretty pleased with the progress that we're making.

This year to date, we've sold about $1.6 billion of assets, with several more currently in the process.

We are being patient, but we remain committed to getting the program completed; but will do that at acceptable prices.

With the year half over and the spinoff complete, we have scrubbed our capital outlook for 2012.

We now believe we have good visibility on the rest of the year and estimate 2012 capital spending to be about $16 billion.

This includes the impact of pushing out the expected timing of asset sales, some of which have quite a lot of capital spending associated with them.

It also includes the impact of some incremental exploration spending I just mentioned, as well as some incremental investments for infrastructure in the Eagle Ford area to ensure that we are not constrained in that development.

Although commodity prices have weakened for all of industry, we continue to believe that our growth projects are robust enough to justify our planned investment at a range of prices.

These are projects that will generate growth, margin improvement, and returns for the longer term.

For this reason we do not think it is prudent to reduce our capital at this time, given that we are investing for a long-term value creation.

So some of the questions we get I hope this next slide starts to address, and it looks at our funding sources and the use of issues in a bit more detail.

So this slide lays out our current thinking on our investment priorities and the actions we will take to fund our growth programs and maintain financial flexibility over the course of 2012 and 2013.

It summarizes our sources of cash on the left and our uses of cash, by priority, on the right.

On the sources side, we have cash on hand of roughly $6 billion today plus incoming cash from operations.

And of course, cash from operations will vary according to price, but we expect to generate cash proceeds from asset sales of between $8 billion and $10 billion over the course of the next year and we have balance sheet capacity if needed.

At consensus views of cash from operations, the sum of this column for 2012 and 2013 combined could be as much as $40 billion without going to the balance sheet.

On the right-hand side of this chart we have the uses for the cash listed by priority.

Our top priority for spending is to fund our dividend.

We believe that a company our size should distribute about 20% to 25% of our annual cash flows through the cycles, back to our shareholders.

Our next priority is to fund our capital program at roughly $15 billion annual level.

Over the next two years, the sum of our expected dividends and annual capital program is roughly $36 billion.

So in the current environment, we have sufficient sources from cash, cash flows, and asset sales to cover our highest priority uses, funding our dividends and investing in our capital programs, and modestly reducing our debt levels.

We think this allocation makes sense and creates long term value for shareholders.

Higher levels of asset sales proceeds or higher cash from improved commodity prices would give us the opportunity to consider additional share repurchases.

On the other hand, if prices were to cycle down for an extended period of time, we would adjust our capital program and use the balance sheet capacity as needed.

So now, let me turn over the call to Jeff, and he'll cover our financial and our segment reviews.

Thank you, Ryan, and good morning, everyone.

Thought I would start this portion of the call with a list of some of the key drivers that underpin our financial and operating performance for the quarter.

These are drivers that either affected our segments across the board, or represents some noteworthy impact to our financial.

The first is no surprise -- North American crude, bitumen and natural gas and NGL prices continue to trend lower and we'll have more detail on that on the next slide.

In terms of production, our volumes came in as planned, with solid performance across our portfolio.

Ryan stepped through a few of these, but as a reminder, our Lower 48 shale and Canadian oil sands achieved production increases which were somewhat offset by unusually heavy planned maintenance efforts and the impact of dispositions.

Generally, operating costs were as expected and dispositions also had some impact on our financials.

And we will cover that as we go through the segments.

I'd also note that the format of the slides we're using this morning are quite different from our previous earnings calls, with a lot more information being presented about each of our geographic operating segments.

What is also different is that we will be providing outlook information as we go through the presentation instead of all at once at the end of the presentation, as we've done in previous earnings calls.

So if you move to slide 7, we will start the discussion with a discussion of our realized prices.

About 55% of our production consists of liquids and about 45% consists of natural gas.

Of the 55% that is liquids, about 30% is tied to Brent or international prices, which were strong early in the quarter and began to decline later in the quarter.

The remaining 20% of liquids is tied to North American crude markers, NGL or bitumen prices; and this production continues to be adversely impacted by wide crude differentials.

On the natural gas side about 45% of our portfolio, roughly 20% consists of international gas -- that is gas outside of North America -- or LNG, which actually enjoyed relatively strong pricing this quarter.

And the remainder of gas consists of North American natural gas, which of course, continues to be challenged.

On the right side of this chart we presented the second quarter price realizations compared to prior periods.

This highlights the commodities that were weaker versus stronger in those periods, and our overall price declined about $6 from a year ago and about $5 from the first quarter.

The key takeaway from this slide is that we benefit somewhat from a diversified global portfolio; and about 55% of our mix was not affected by weaker North America pricing.

As our major projects come online our production mix shifts more to liquids and international gas, and this will help improve our margins and cash flow growth in the future.

Let's move to slide 8 and talk about the total Company production.

As Ryan mentioned, our production was 1.54 million BOE per day, on target with our expectations.

This was down 97,000 BOE per day from the same period last year.

At a high level you can see that this decrease can be bucketed roughly a third to dispositions, which Vietnam, Statfjord and Alba; about a third to down time in Australia, Alaska and Canadian oil sands; and about a third to natural gas decline to North America, driven by decreased activities and curtailments.

However, what is also shown is that our growth offset base declined, accounting for over 110,000 BOE per day compared to last year, the bulk of the growth coming from the Eagle Ford, Bakken, Permian and oil sands assets.

In a moment I'll provide more detail on production by segment.

Let me first give you some guidance for production estimates for the rest of the year.

We expect third quarter production to be between 1.475 million and 1.525 million BOE per day.

Most of the expected drop from the second quarter to the third quarter is due to planned downtime in Alaska and the UK.

Our full-year production estimate is now expected to be between 1.565 million and 1.585 million BOE per day, and this includes the impact of dispositions.

Now I'll turn to our adjusted earnings on slide 9. This slide shows the seven new reporting segments for our Company.

We will go through detail on each of these segments in subsequent slides, and there is also additional information, along with historical data, in the supplemental tables included in the press release.

Although we operated well, our results compared to prior quarters were adversely impacted by the combination of lower commodity prices and lower production, as we discussed on the previous slide.

Lower 48 and Canada were affected by natural gas prices that were down more than 50%, NGL prices down more than 20%, and Canadian bitumen prices down more than 20%.

The biggest volume-related impacts to earnings for the asset dispositions in Europe, lower production in China, and the turnarounds in Australia.

Our second quarter adjusted earnings were $1.535 billion versus $2.31 billion a year ago.

Now I'll turn to the segment slides, beginning with Alaska on slide 10.

Our legacy asset in Alaska continues to operate well and provide strong earnings in production performance.

Production was 215,000 BOE per day, down from year ago.

The lower production was driven by natural gas field decline, partially offset by improved drilling performance and lower unplanned downtime.

In the quarter, we completed a major turnaround at Kuparuk on schedule and on budget.

Adjusted net income for the segment was $551 million, roughly equivalent to a year ago.

In the third quarter we have additional turnarounds planned, which we estimate will lower sequential production by 40,000 to 50,000 BOE per day.

Looking forward, Alaska's segment where we have opportunities to mitigate decline from incremental exploitation opportunities, and we retain the option for some longer term projects such as LNG exporting and ANS gas.

However, future developments from Alaska are contingent upon some improved physical terms.

So next we'll move to the Lower 48 and Latin America segments, which is on slide 11.

In this segment we continue to advance several high-margin growth projects across our asset base.

Total production for the quarter was 441,000 BOE per day, approximately 16,000 BOE per day higher than last year.

The growth of our last year was driven by our liquids-rich plays in the Eagle Ford, Bakken and Permian; and this growth was partially offset by natural gas declines across the portfolio.

Eagle Ford, Bakken and Permian average production in the second quarter this year was 61,000, 25,000 and 51,000 BOE per day, respectively.

Our total production of 137,000 BOE per day from these three plays was 54,000 BOE per day higher than a year ago.

So looking more broadly across the Lower 48 portfolio, liquids production was up 24% and natural gas production declined 8%.

This reflects our shift in capital to liquids plays and away from dry gas drilling.

Although we saw year-over-year production growth in the Lower 48, the net income results from the second quarter were lower due to a 50% drop in natural gas prices and a 23% drop in NGL prices.

This reduced net income $119 million for this segment.

In the second quarter we had a total of 31 drilling rigs, comprised of 17 at the Eagle Ford, 8 in the Bakken and 6 in the Permian; and we expect to maintain a total of 27 rigs through the end of this year.

A majority of the acreage in the Bakken and the Permian is held by production and we expect to have the Eagle Ford acreage held by mid- 2013.

And based on the positive results we are seeing to date on these liquids-rich shale plays, we expect that we've identified extensive development potential over the next several years.

As Ryan mentioned earlier, we are resuming high impact deepwater Gulf of Mexico exploration and appraisal activities.

We would expect to have some results by late this year or early next year.

So next we'll move to our Canadian segment on slide 12.

Canadian production was 268,000 BOE per day in the second quarter, up 6,000 BOE per day versus the same period last year, driven by a ramp-up in oil sands production.

New production growth of 22,000 BOE per day was offset by natural gas asset dispositions, natural gas curtailments from lower well performance as a result of restricted capital investment in our natural gas fields.

So you can see on the production charts, liquids as a proportion of our total segment production increased compared to last year.

Liquids volumes were up year-over-year 19%, while natural gas declined 9%.

Again, like the Lower 48 segment, this shift should start to show up as improved margins over time.

So even though our Canadian business operated well, segment earnings reflected significantly lower bitumen prices, increased WTI-WCS spreads, and lower natural gas and NGL prices.

As a result of these factors, and given that 62% of our total production in Canada is attributable to natural gas and NGLs, adjusted net income was a negative $94 million for the quarter compared to a positive $82 million in the second quarter of 2011.

It's important to note that this segment has generated positive operating cash flow year-to-date, so even with gas prices at recent lows, cash flows from this segment are important sources of cash for redeploying into our growth programs.

The Company's oil sands project continue to perform well, with production growth from Christina Lake Phase III and Surmont Phase I. This resulted in an increase bitumen production of 20,000 BOE per day compared to the second quarter of 2011.

Additionally, the Surmont Phase II development and further FCCL expansion phases are underway and should lead to further production growth over the next several years.

In May, we received approval from the Alberta government to proceed with the Narrows Lake oil sands project, and the project is anticipated to have gross production capacity of 130,000 BOE per day to be developed in three phases starting in 2017.

So next we'll move to the Europe segment on slide 13.

Second quarter production in Europe decreased by 42,000 BOE per day to 236,000 BOE per day.

This was primarily driven by natural field decline in Britannia, Ekofisk, in J-Block; downtime in the Statfjord and the Alba asset dispositions.

Net income in Europe was $414 million, down $119 million from last year.

Commodity prices held up in this segment relatively well compared to the North American markets, and positive FX impacts slightly improved income this quarter.

In the near term we expect volumes in this segment to decline.

Volumes will begin to increase when the Jasmine project comes online in 2013 and when the additional North Sea projects of Clair, Ekofisk South and Elkfisk 2 start up.

And one additional point I'll remind you is that the UK recently enacted legislation which restricts corporate tax relief on decommissioning costs to the 50% tax rate retroactive back to March of 2012.

And we anticipate in the third quarter 2012 that our earnings would be reduced by approximately $175 million due to the remeasurement of these deferred tax liabilities.

So I'll turn to slide 14 and talk about our Asia Pacific and Middle East segments.

Production in this segment was 270,000 BOE per day, down approximately 85,000 per day from the second quarter of 2011.

This reduction was driven by the curtailment of the Peng Lai production, the disposition of Vietnam business unit, and by the safe completion of a 41-day turnaround at the Darwin LNG project.

At the end of the second quarter, Peng Lai was producing 30,000 BOE per day, net.

We are seeking approval for final operating and development plan but continue to ramp up production under an interim production resumption plan.

Compared to the same period last year, adjusted net income decreased by $167 million to $789 million.

This decrease was driven by 24% lower volumes, slightly offset by improved LNG prices and lower DD&A.

The second production train at APLNG was sanctioned in July and project -- financing agreements were signed during the second quarter.

The project is on track for first deliveries of LNG in 2015.

Concurrent with project sanctions, ConocoPhillips further reduced its working interest in the project to 37.5%.

In Malaysia, development continues on several projects, including the deepwater Gumusut oil field off the coast of Sabah, the natural gas Kebabangan field, and the oil field at Malikai and Siakap North-Petai.

Finally, we anticipate beginning our pilot program in the Canning Basin that Ryan mentioned, in the third quarter.

So I'll move to our international segment on slide 15.

This segment includes our assets in Russia, Caspian, and Africa.

Production was 112,000 BOE per day, up from 88,000 BOE per day a year ago.

This increase was primarily due to the restart of our operations in Libya, partially offset by declines in Russia.

Net income was a negative $19 million, driven by lower crude prices, high taxes, and foreign exchange impacts.

And for the Company overall, the FX losses on this segment generally offset the FX gains that I talked about in Europe.

As we've indicated in the past, we are actively marketing some of these assets in this segment as part of our $8 billion to $10 billion divestiture program.

So the final reporting segment I'll talk about is on slide 20 (sic--see slide 16), our Corporate and Other segment.

Since this is essentially a cost segment, adjusted earnings were a negative $225 million this quarter.

Costs contained in this segment include net interest expense, corporate G&A, environmental costs, some FX impacts, and our Emerging Businesses cost.

A portion of the former Emerging Business segment that you will recall from the integrated ConocoPhillips is now included as part of this Corporate and Other segment.

For guidance purposes, I would suggest using $1 billion annually for this Corporate segment, so roughly another $500 million for the second half of this year.

So next, we'll turn to slide 17 and talk about our operating segment margins and returns.

The four-pack of slides on this page summarize our key financial metrics for the quarter.

In the short run, prices overshadow the operational and portfolio improvement successes we've had as a Company.

Looking year-over-year at the second quarter, the drop in income per BOE is primarily driven by the $6 drop in realized prices we discussed earlier, and our cash contributions and our return on capital and cash return on capital metrics follow this same trend.

And before turning the call back to Ryan to close up, I'll go through our year-to-date Company cash flow on slide 18.

To date we've generated $7 billion of cash from continuing operations, which excludes an increase in working capital of about $600 million.

We've also generated $1.6 billion from asset sales.

To date we've spent $8.2 billion in capital, which includes approximately $500 million of deepwater Angola exploration and Gulf of Mexico leasehold.

It also includes heavier spending on the APLNG project than we expect in the balance of 2012.

We paid $1.7 billion in dividends, continuing the same dividend rate as the pre-spinoff integrated ConocoPhillips.

Related to the repositioning, the net impact -- cash flow impact -- of the spinoff of Phillips 66 is $5.7 billion.

This was a combination of all of the operating, investing, and spin-related transactions for the operations of what the assets that are now in Phillips 66.

During the first two quarters of the year we also repurchased $4.9 billion of our shares, and that left us with $6 billion in total cash at the end of June, including $5 billion in restricted cash and $1 billion in cash and cash equivalents.

During the third quarter this year we expect to begin using some of these cash balances to reduce our debt balance.

So with that, I'll turn it back to Ryan for some closing comments.

Thanks, Jeff.

And if you can turn to slide 19, I'll try to wrap up a little bit.

I think the takeaway that we'd like to have for you all for today's call is that the business is running well and our plans are on track.

The spinoff of Phillips 66 was a big milestone for the Company, and it successfully launched ConocoPhillips as an independent E&P Company.

Operationally, we had a strong quarter and that part of the Business is delivering on our expectations.

Certainly our focus will remain on returning value to the shareholders through our dividends and by executing on our major projects, our exploration programs, and our asset sales.

The asset sales are important because they generate proceeds that help fund our high-return growth projects.

And we certainly will keep a close watch on the macro environment and we believe the investments that we're making today are going to position the Company to deliver on our long-term value proposition of 3% to 5% growth in production and margins, with improving absolute financial returns and combining a sector-leading yield.

So that wraps up our summary that we had today, and look forward to questions from the audience.

(Operator Instructions) We have a question from Faisel Khan from Citi.

Thanks.

Good morning.

On slide 5 I think you mentioned in your prepared remarks the amount of cash flow you expect to generate from operations under consensus estimates.

I just want to clarify that.

Was that $40 billion did you say in '12 and '13?

No.

The consensus cash from operations is not the $40 billion.

We think per year it's in the $12 billion to $14 billion range.

$12 billion to $14 billion -- okay.

Yes.

You add the $6 billion of cash on hand plus what we expect to get from asset dispositions is what adds up to the $40 billion, Faisel.

Okay.

And then on Penglai, what -- assuming you can get up to full operatable capacity, what is that potential number over the long term, assuming you can get your -- all the permits in place and be able to get back to producing in all those fields?

Yes, I think you ought to think in terms of 110,000 to 120,000 barrels a day gross.

So net back to us is in the 40,000 to 50,000 BOE per day level.

And that compares to around 60 before the events.

Okay understood.

And then at APLNG, given your reduced working interest now in the facility and given also the project financing that you have in place, what kind of spend -- or what kind of equity contributions will you have to -- will you be obligated make to APLNG over the next sort of year or two?

What we will find is that over the second half of 2012, that the project financing and the fact that the additional interest at Sinopec is going to acquire as part of the final investment decision on the second train will find most of our capital requirements for the balance of the year.

And then we will see lower capital requirements on APLNG as primarily related to project financing next year as well.

Okay.

Great.

Perfect.

Thanks for the time, guys.

Paul Sankey from Deutsche Bank.

Hi, guys.

Good morning.

I would very much like what you -- your continued clarity and also really truly appreciate your level of disclosure that you give us is admirable.

Thank you.

On the basic question of cash flows, just one point -- you didn't say anything about growing the dividend but I assume that's your aim.

Yes.

Certainly I think our strategic intent we talked about is delivering 20% to 25% of our cash flows back to the shareholder primarily through the dividend channel.

And so as we grow our production, grow our earnings, grow our cash flows that 20% to 25% is intended to grow as well.

Okay.

I understand.

It's actually also a very interesting target.

I was going to move on to that -- the idea that you would give back around a quarter of your cash flows, I guess what we are all struggling with is you mentioned that the consensus cash flows right now are $12 billion to $14 billion annually, which even arguably, I think, is on a relatively aggressive oil price forecast.

So that is why it's helpful to see the uses of cash by priority.

I guess what we are struggling with is the extent to which over time you're going to have to cut back that capital program.

Could you just talk more about the sensitivity of the program and how much you could potentially cut that back to balance your cash flows over the longer term?

A couple comments there, Paul, first, as we talked about -- the Company is going through some fairly significant production growth and the growth that's occurring at a fairly high margins.

So if you think about us going from a production level of 1.5 to 1.6, up to the 1.8, 1.9 kind if level over several years, that adds significant cash flow.

And then as we've talked before that regardless of the price environment we're in, by virtue of moving the portfolio more to liquids and, as well, moving it more to jurisdictions which have lower taxes, we're going to see margin improvement.

So as we look out over the next several years the difference between what we're generating in terms of cash and capital and dividends of course shrinks over time.

What we're trying to lay out for you this morning is that in this interim time period where it may not be covered, then we have other sources of cash to balance that gap and we think it makes sense to continue to invest in the capital that we have.

Ryan, I don't know if you want comment on where we might cut capital if we're in a really lower price environment?

Yes.

Certainly if -- so we've seen some drop off here from Brent 120 down to arguably $100 reductions over the last -- through this last quarter.

We still think Brent in the $90-ish, $100 range is probably reasonable over the short term, but if we saw some cycling down of prices and we felt like they were going to be here for two or three years we would make adjustments to our capital program.

We are doing some of that through our disposition process and we've identified some high capital requiring assets that we would like to dispose of.

We've got capability to throttle back on some of our exploitation spend across all of North America, really, across the whole global portfolio and we would look at that as well.

We want to continue some of our -- what we think are the high-quality, high-margin, high-return major projects we are not going to whipsaw some of those right now being some of our ones in the North Sea in Norway, the UK, Malaysia -- some of those we'd like to continue going.

But we've got some optionality in the portfolio.

If we saw lower prices were going persist for a year or two.

I think we've experienced over time too is that as prices come down and activities levels come down across the industry you'll get the same amount of scope done for a lesser amount of money as well.

If I think about the relationship you have between the asset sales and the share repurchases and the commitments you made essentially to buy back shares through the first half of the year, where are we sitting now on buybacks for the rest of 2012 and into the first half of 2013 and knowing what you're saying about asset sales and share repurchases?

Because it feels like you might be in the position to actually pretty much stop the buyback now.

We completed the $5 billion that we said we would fund through the first half of the year.

Our priorities have shifted with some of reductions in commodity prices that we've seen over the last quarter or so.

As we look out ahead, the asset sales and dispositions will be used to help fund our capital program.

If we end up getting an increase in dispositions above what we are forecasting or if commodity prices ramp back up a little bit then that would leave room for us to consider more share repurchase.

Is that saying that basically the share repurchase has stopped now?

Yes, they have stopped.

Got you.

Okay.

Alright, guys, I've asked you plenty of questions.

Thanks a lot.

Ed Westlake from Credit Suisse.

Good morning, everyone.

You've laid out how cash flow margins are going to rise and therefore cash is going to expand over time.

Just still running through these cash balance numbers -- do you have a number, I mean a rough range -- obviously we don't need to get into what you're going to sell -- but for the CapEx that is associated with the disposals?

If you look at -- had we disposed of -- a rough range, yes.

If we were to dispose of everything that was on our -- that they were complicating as asset dispositions as of the beginning of this year -- probably would have taken $1 billion to $1.5 billion of capital out of this year's program.

Right.

And so that will free up that CapEx plus maybe once APLNG is gone through to invest more aggressively in shale?

Yes, I think as we look forward over the next -- right now we would think that our capital expenditures in 2013 are going to be in the range of $15 billion and that includes, as you mentioned, a continuation of the aggressive investment levels we are doing in the Lower 48 in the resource plays.

And then, obviously, as you look through divisional disclosure, Canada is suffering.

Maybe you could say Bakken and Permian is suffering from low realizations.

Apart from others building pipes to help you get to higher realizations on the production you're getting there -- can you talk through your strategy to try and maximize realization for those onshore assets?

We talked a little bit about that in terms of the 2012 capital that we see clarity on for the rest of the year and a part of that is spending a fair amount of infrastructure to help our realizations and make sure we can move the product where it is getting bottle necked and make sure we can get it sold.

We are doing a fair amount of that where it makes sense, whether it is competition and where we can get to third parties for a reasonable cost we will do that.

We are also focused on spending our own capital if we need to, build our own infrastructure to make sure that we are maximizing the realizations.

A final one for me -- you mentioned the Mancos, any results you can share from them?

And I do see you're permitting down in your acreage down in southern Louisiana.

Any results or targets that you are probing there?

Well none that we would -- that I think we can disclose today.

Still a pretty competitive position.

We wanted to talk a little bit about the Mancos because obviously we have got a lot of that acreage held by productions so we are still studying that and hope to have results later this year.

Thanks very much.

Arjun Murti from Goldman Sachs.

Thank you.

Just wanted to clarify the stock buyback commentary.

I think we've always thought that future asset sales -- those proceeds would be used to buy back shares.

It sounds like it's not probably as direct going forward.

It will be a function of what cash you have available.

Is that accurate?

Yes, I think that is fair, Arjun.

That's great.

So you're going to spend $16 billion in capital this year.

You have the $15 billion-ish number for next year and long term, does that contemplate the $8 billion to $10 billion of asset sales or would that $15 billion-ish come down once you're finished with your asset sales?

No.

We think that's a -- as we look at the portfolio and look at the opportunities -- look what we have added in the North American unconventionals, we look out over time and $15 billion feels like a pretty reasonable capital figure.

If commodity prices hang in at kind of today's level or even a bit softer.

That's great.

That makes sense.

And then just last one for me -- some of the peer companies in Australia LNG has had some budget increases.

My understanding is you all had more of a contingency built into your budget, but just wondering if you could comment on what you are seeing down there and how good you do you feel about the current budget.

Thank you.

Yes.

I know we've -- we have seen some announcements.

When we came out we felt like all along, Arjun, that a one-train project or two-train project on Curtis Islands was about $20 billion.

That was our estimate a couple of years ago and we haven't seen anything to think that would be any different.

I think the other projects are just now realizing what it's going to cost on Curtis Island.

Great.

Thank you so much.

Jason Gammel from Macquarie.

Yes.

Thank you.

I had a few more on APLNG if I could please.

First of all, on the upstream program, I believe you are actually a fair bit ahead of the other projects that are going forward in Queensland, but can you talk about what type of a forward drilling program that you need to have to match the upstream with the downstream requirements, in terms of number of wells to be drilled and then also in terms of rigs that you need to run?

Yes.

I might have to get back with you on the specifics with that but I think we are running today a three, four-rig program and feel like we've got -- with the efficiencies that we are gaining and the number of wells we are drilling on a daily and a monthly basis we are ramping up the well count in front of the startup of the first train.

So when the first train is ready to come online in 2015, we'll have the supply ready to go.

And then we are continuing to drill because six to nine months later the second train will come online so we continue to drill and have the upstream capacity available for that.

Sure.

And then I suppose the logistics are obviously fairly difficult trying to match that number of wells with the requirement that you have.

So do you feel like the arrangements that you have commercially with the domestic market and some of the other projects give you more flexibility in how you manage that upstream process?

Yes.

I think we are probably uniquely positioned there because we're selling over $200 million a day to the domestic market today and we've got the ability to de-water wells and throw wells into the domestic market and not.

So we've got a lot more flexibility to be able to manage our available capacity on the front end to make sure when the plant's ready to go that we can deliver the gas to the plant.

And then one more on APLNG if I could please -- you mentioned that you have project financing in place.

Can you talk about, just in rough numbers, what percentage of the overall capital requirements will come from the project financing facility?

Yes.

The project financing that was completed with -- the agreements were signed back in the second quarter is an $8.5 billion project financing.

So it's roughly 40% of the requirements.

Great.

And, Jeff, how much cumulative cash flow would you need to generate to repay whatever principle you have to do first and fund any contingency accounts before APLNG could start dividending cash back to you?

Well the repayment of the financing happens over a long period of time, so as soon as APLNG starts up it will start paying out a dividend.

Okay.

So you would have any contingency account funding that would have to come in front of dividend payments to the partner group?

No.

It's going to be part of what gets funded over all with the project.

So when we start up we will begin to make distribution.

Okay.

Thanks very much.

Blake Fernandez from Howard Weil.

Thanks.

Good morning.

If I could just tack on to the APLNG questions -- I'm just curious, you've sanctioned the second train, obviously that helps with scalability and efficiency and should improve overall returns.

I'm just curious, given the second quarter return on capital employed for the entire Company at around 11%, do you think this project will be accretive to overall returns?

I think APLNG will be accretive to overall on returns in the long term but it'll be a challenge to our overall returns in the near term.

And that is pretty consistent with all long-life projects where you end up putting a lot of capital on the books up front and then you get that back over a long period of time.

So it is probably not accretive in the short term; will be accretive in the long term.

But the issue there is the reason you have seen us dilute from our -- willing to sell equity to a marketing entity to purchase a portion of the project and our willingness to be able to do that.

And that has caused us to go from the 50% down to the 37.5% and we are looking for probably some opportunities for some for further dilution at APLNG.

Okay.

Great.

Thank you.

The second question was on the exploration front.

Ryan, I now you gave us a few impact wells going down in the Gulf of Mexico, I was just curious, is there anything else globally that we should be aware that could be high impact?

And then I know you mentioned Angola seismic -- could you give us an idea of when we may slip the first well there?

I think we are looking in Angola the end of 2013, early 2014, for a well.

We're in the middle of capturing 3-D seismic.

I think we pretty much completed our initial program in Bangladesh and we will get that data in.

So that well is probably pushed out.

The other one I would probably point out in terms of impact is we are kind of at the front end of our Poseidon appraisal program in the Browse Basin of Australia.

But that will be probably a year-long, five or six well program.

Okay.

Thank you very much.

Doug Leggate, B of A Merrill Lynch.

Thanks.

Good morning, everybody.

A couple of things from me.

When you did the separation, Ryan, you projected -- or you laid out at least projections which looked like we're assuming $120 Brent at time -- the margin improvement assumption of 3% to 5%, had that as a backdrop.

If you had to reset, I'm guessing -- why haven't you reset your assumptions what the future curve looks like right now and would that change the margin improvement, is my first question?

I know we continue to get some of those questions, Doug.

I just remind everybody when we came out in April and we described that a little bit we were trying to describe what current prices were and how the margin would improvement.

The important part is, as we look at the portfolio and we look at where we are investing the money, whether you pick $120, $100 or $90 oil or $80 oil, our margin is going to improve on a flat price basis.

And we believe that 3% to 5% is coming at a flat price.

So it is not reliant on $120.

As we look at our plans today, and we look at the investments that we are making relative to the existing portfolio, our margins are going to be improving over the next three to five years.

And we -- the absolute production growth in the margin growth is coming and we are investing in things that are changing the mix in the portfolio and are changing the tax burden on the Company as well.

Got it.

I have just got a couple other quick ones if I may.

I guess this is where my confusion comes in, because it is related to that issue of mix.

So when we look up Australia LNG, that's a very large part of your incremental organic growth.

I assume you had discussions with the team about this, but the implied -- the IRR you presented on Australia LNG was showing 8% to 10%.

You didn't count on assumptions.

Can you share how those assumptions differ from your cash flow assumptions?

In other words $120 oil.

Because what I'm trying to figure out is in the world oil price assumption with so much of your growth coming from APLNG, how does that then jive with the incremental improvement in cash margin?

8% to 10% IRR --

So maybe a couple of clarifications there, Doug, so the 8% to 10% IRR is not what you have at $120 oil pricing.

You'd be doing much better than that at a $120 oil price.

So when we talk about margins, we're talking about cash margins.

When APLNG starts up, you're getting a significant return of -- or getting a return on your capital, you're getting your capital back as well.

The cash margins are going to be pretty robust on that project, regardless of what price environment that we're in.

So that will be a significant source of cash for us upon start up.

What I'm trying to figure out, Jeff, is can you share with us what commodity assumption does equate to 8% to 10%.

That was more on a $90 type price environment.

So $90 per barrel -- would that still be accretive to cash margins?

Yes.

Okay, second one for me is on the disposals -- the $8 billion to $10 billion.

Can you give us some scale of production and cash flow associated with those?

And I'll leave it at that.

Thanks.

From a production standpoint, like we said before, it will depend upon the mix because in that $8 billion to $10 billion there's a mix of assets that are currently producing and currently not producing.

So impacts on current productions are probably in the 50,000 barrel-a-day type range.

And depending upon the mix, it could vary plus or minus 25,000 barrels a day on either side of that.

Then cash flows -- I don't think I have a number that we can throw out to you on that.

All right.

I'll leave it there.

Thanks.

Iain Reid, Jefferies.

Good morning, guys.

Jeff, could I just go back to your comments on the UK part of the business.

And you were talking about the impact of the tax change on abandonments.

And you mentioned a number which is going to affect I think you said third quarter earnings -- could you just confirm what that is and whether it is a one-time charge and what the ongoing affect on DD&A could be?

It's a one -- that is a one-time charge of around $165 -- $175 million and that just really reflects the fact that when the UK increased tax rates earlier -- it was last year -- up to around 62% range, they said they might be coming out later with some restrictions on how much you could deduct on abandonment obligations.

They have done that now and said that you only get 50% tax relief on abandonment obligations.

That mark of our deferred tax liability down to reflect that change is what the $175 million would be.

So it would be a one-time special item type event in the third quarter.

And there won't be any kind of ongoing affect to your DD&A per barrel rate?

There could be some -- no.

No, there isn't.

Because it is just -- that's a before tax item.

Okay.

And secondly, on NGL pricing there is going to be a fair amount of investments in infrastructure, et cetera.

Just wondering when you look at these very depressed prices you are getting in the Lower 48, how long you expect those to have such a big margin to oil prices going forward and whether you've thought about any sort of hedging program for that?

Obviously it's not a great time to hedge now but whether that is something which you might want to look to protect the future?

NGLs, as we pointed out, are around, globally, about 9% of our production and the Lower 48 and Canadian portion of that is like 6% or 7% of our production.

As we look across over time, if you roll the clock forward several years, our NGL production we would anticipate to be relatively flat and with our growth is going to be coming from crude oil production.

So we don't have increasing exposure to NGLs going forward.

I think we see that the market is going to be fairly soft, particularly for ethane, in the near-term, which is what's really driving down the overall price of NGLs and -- but that will get solved with all the capacity expansions that you're hearing talked about in the chemicals side of the business right now.

So we don't think it's a long term phenomenon but that kind of low NGL prices is going to attract additional investment.

Okay.

And my last one -- I'm going to come back to APLNG, I'm afraid.

The other guys have announced big increases, mostly talked about the translational effects of the Australian dollar, and I presume when you launch this project you are looking at a much lower level of the Australian dollar versus the US dollar.

Does that $20 billion budget you have -- do you cover this kind of big increase in the Australian dollar exchange rates?

Because I believe that is a very substantial portion of the overall CapEx is denominated in local currency?

It is.

That reflects our current estimates with where the market looks now on the Australian dollar.

But that continues to be -- like with the other projects -- that continues to be one of the larger exposures we have on the project is if there is a further weakening of the US dollar relative to the Australian dollar.

So is if fair to say that you probably used up all the contingency you had initially on a project?

No.

I wouldn't say that.

I'd say that we feel like the numbers that we had out there now still have contingency in them.

Okay.

Alright.

Thanks a lot, guys.

Paul Cheng, Barclays Capital.

Hi, guys.

Good morning.

First I want to echo the earlier comment that I want to thank you for the expanded disclosure.

Very helpful and I appreciate.

But just one possible request that seems that you're going to break out the earning by different regions.

Can you also breakout your exploration expense in the future by the corresponding region?

That would be helpful in the modeling.

And, Ryan, in your presentation that you give production and the margin improvement talk -- do you have a proven reserve growth target?

Yes.

Certainly, Paul, we expect over time to be more than replacing the production.

So we haven't come out and said exactly what it is, but it clearly targets over 100%.

It will be lumpy and there will be years when it probably dramatically exceeds it and years when it could be right at it.

Should we assume that you were trying to hold your R/P ratio flat or that is not really a target?

I don't think about, Paul, trying to hold R/P flat, in fact, as we shift our investment in some of these higher margins -- the profiles of some of these investments, I actually expect our R/P will go down a little bit over time.

Not a lot, but will trend down versus trying to trend flat.

Okay and, Jeff, on the office sale, just wanted to clarify that.

$8 billion to $10 billion for 2012 and 2013, does it already include the $1.6 billion year-to-date and also the expense of farm down on the APLNG?

So we do include -- we think about that number as a 2012 and 2013 number.

The farm down on APLNG ends up being a contribution into the joint venture so it is not an asset sale.

So APLNG is not included, but the $1.6 billion year-to-date is included?

That is correct.

And since I got you, Jeff, I think you guys have an over lift in the second quarter, around 29,000 barrels per day, what region does that come from?

And also, as of the end of June 30, are you guys balanced or still net over weight -- over lift?

Paul, we'll have to get back to you on that.

I don't have that right in from of me.

Alright.

Thank you.

Jeff Dietert, Simmons & Company.

This is (inaudible) in here for Jeff.

Thanks for taking my call.

I was hoping you guys could talk a little bit more about current and planned activity levels and what you're seeing in the Permian Basin and specifically wondering if you had any update with respect to pilot programs in the Avalon and the Wolfcamp.

Any comments there would be appreciated.

Well we've got quite a bit of activity going on, as Jeff described earlier.

We have six, seven rigs running in the Permian Basin and those are all targeting some of the existing conventional opportunities that we have but largely focused on the unconventional.

It is mostly liquid investments in all of the Permian so we are active in piloting and drilling both the Wolfcamp and some of the other plays in the Permian Basin.

So, yes, we are pretty active there right now.

Okay thanks.

And then I also had a strategic portfolio management type of question.

Ryan, as you look at the existing portfolio, are there any gaps or areas where you are lacking exposure now that you would like to enhance your position in?

And then relatedly, internationally the focuses has largely been OECD geographically to limit risk and that's worked well for you all.

Now should we assume that remains the case going forward?

And would that preclude you from potentially entering some of these international plays that may offer significant long-term resource potential but do carry a higher risk profile?

And I'm thinking of some plays like East Africa, for one, or even Kurdistan region of Iraq?

Any comments there would be appreciated.

As I look at the portfolio, I'd say we're more after low cost to supply opportunities, whether that is gas or oil, where we can make a competitive rate of return within our portfolio.

As I look at that today, you see our heavy focus on unconventionals in North America because we see a lot of opportunity that are working well.

We've got a great position and so a large part our investments are going there.

But internationally, I'd say we've -- as you see from our exploration, we are growing our deep water position and that is not only in the Gulf of Mexico but also Angola and the sub salt opportunity there, Bangladesh, we're offshore Sabah Island in Malaysia.

So you'll see some things that we are doing in the deep water.

We think the liquids-focus deep water investments make a lot of sense.

So I think as we think about it going around -- it's really opportunity for opportunity but looking for a good low cost of supply and looking for areas.

So even playing the Barents Sea in Norway make sense to us right and you've seen us capture some acreage positions up there.

So in terms of holes, I don't think we have a hole that we are really trying to plug, we're really focused on value and focused on returns and making sure that what we do go after and capture competes well within our existing portfolio.

As you said, we're largely OECD today so we can take on a little bit more risk in terms of political risk in something like that if we think the returns are going to be competitive.

Okay.

Great.

Thanks for the comments.

Thank you ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This transcript contains forward-looking statements.

Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results.

In many cases you can identify forward-looking statements by terminology such as "anticipate," "estimate," "believe," "continue," "could," "intend," "may," "plan," "potential," "predict," "should," "will," "expect," "objective," "projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and other similar words.

However, the absence of these words does not mean that the statements are not forward-looking.

Where, in any forward-looking statement, the company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis.

However, there can be no assurance that such expectation or belief will result or be achieved.

The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, changes in commodity prices; changes in expected levels of oil and gas reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; difficulties in developing new products and manufacturing processes; unexpected cost increases; international monetary conditions; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business.

Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission.

Unless legally required, ConocoPhillips undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Use of Non-GAAP Financial Information - This transcript includes the terms adjusted earnings and adjusted earnings per share.

These are non-GAAP financial measures.

Adjusted earnings and adjusted earnings per share are included to help facilitate comparisons of company operating performance across periods.

References to earnings refer to net income attributable to ConocoPhillips.