康菲 (COP) 2012 Q3 法說會逐字稿

Welcome to the Q3 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 afternoon everybody.

Welcome to the ConocoPhillips Third Quarter Earnings Call.

Today you are going to hear from three of our senior executives.

Ryan Lance, our Chairman and CEO, will cover the third quarter highlights and provide an update on our strategic goals and priorities.

Jeff Sheets, our Executive Vice President and CFO, will review the third quarter financial results including our segment financials.

And we also have Matt Fox on today's call.

Matt is our Executive Vice President of Exploration and Production, and he's going to review the E&P activities in each of our segments.

Please note today's presentation materials can be found on our website, and a transcript of this call should be posted by no later than tomorrow morning.

And finally, we will be making some forward-looking statements during today's webcast.

Our results may differ materially from the expectations we share today, but we've outlined these uncertainties and risks to our future performance in the Safe Harbor Statement shown on page 2 in the slide deck that you should have access to at this time.

And also in our periodic filings with the SEC.

Now it's my pleasure to turn our call over to Ryan.

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

I'll begin my comments on slide three and cover some of our key third quarter highlights.

This quarter marked an exciting milestone in our first full quarter as an independent E&P Company.

As you saw from this morning's release, we posted strong performance this quarter, and hitting our numbers is critical to achieving the goals we have set for ourselves.

Really, a special thanks to our employees who continue to step up and deliver.

We continue to make progress on our divestiture program.

Completing this program will improve our portfolio, reset our base for future growth, and add financial flexibility to the Company.

In the third quarter, we generated about $0.5 billion of proceeds from asset sales including our interest in NaryanMarNefteGaz.

And we continue to advance our progress on other assets.

Year-to-date, we have generated $2.1 billion in proceeds from asset dispositions.

A key part of our strategy is to grow organically.

Our exploration program continues to build momentum both on the unconventional and conventional sides of the business.

And Matt will talk more about these programs shortly.

But I'm pleased to see these programs gaining speed.

Operationally, we achieved the high end of our estimated production range for the quarter at 1.525 million barrels equivalent per day.

This performance represents an important milestone for ConocoPhillips.

We achieved 3% year-on-year volume growth when adjusted for dispositions.

Key production highlights include ongoing strong performance from unconventional assets in the lower 48, especially the Eagle Ford and from our Oil Sands in Canada.

In addition, compared to a year ago this quarter benefited from the resumption of production at Peng Lai and in Libya.

Our major projects are also progressing as planned, and Matt will provide additional color on these in his comments.

As I move to the financial themes, we generated $1.8 billion of adjusted earnings or $1.44 per share.

Our diversified product mix and geographic mix continues to buffer us somewhat from ongoing weaker North American natural gas and NGL prices.

Excluding working capital, we achieved $3.9 billion in cash from operations.

And finally, we improved our balance sheet this quarter in lowering the debt-to-cap ratio to 31% from 33%.

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

We stayed focused and delivered on the aspects of the business that we can control.

Now if you turn to slide 4, I'll quickly address the state of the business and highlight our focus areas and priorities for the rest of the year and into 2013.

First and foremost, the business is running well.

We completed our worldwide seasonal turnaround activities on time and on budget.

Our major projects and drilling programs are on track to deliver volume and margin growth.

These include our Lower 48 and 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 underpin our long-term goal to deliver 3% to 5% production growth and margin expansion at flat prices.

And as I mentioned a minute ago, our exploration program is continuing to gain momentum.

We are currently testing several unconventional and conventional opportunities, and are advancing others quickly to the drill-ready stage.

Earlier this week, it was announced that we had acquired slots in a sixth generation rig to begin executing on our operated deep-water Gulf of Mexico program by 2014.

Again, we are focused on completing our strategic asset disposition program.

We have several packages on the market, and expect some of these assets will take a little bit of time to divest.

But we're being patient, and we will remain committed to getting the program done at acceptable prices.

We believe we're on track to deliver the $8 billion to $10 billion of proceeds by the end of 2013.

So with a quarter to go on the year, we now believe our capital spending will come in between $15.5 billion to $16 billion.

A bit lower than we guided to in the second quarter.

Where we end up in this range depends on whether or not we find attractive opportunities to add unconventional acreage between now and year-end.

We continue to be opportunistic in the market for acreage that fits well in our portfolio.

Maintaining our balance sheet strength is essential.

We continue to keep a close eye on our financial position to ensure that we have the flexibility and the capacity to execute our plan.

And finally, we remain committed to our stated strategic goals of profitable growth, and sector leading returns.

And I believe this gives a good quarter and gives a good evidence that we are executing on the parts of the business that we control, and have projects and programs in hand to support these goals.

So now, let me turn over the call over to Jeff for a financial review.

Thank you Ryan, and good afternoon everyone.

I'll start out the review of our third quarter results with slide 5, which shows our total adjusted earnings and realized prices.

We'll go through the detail on each of our segments and subsequent slides and I'll defer the operational detail and updates to Matt.

Total adjusted earnings were $1.8 billion this quarter, compared to $1.5 billion in the prior period, and $1.9 billion in the third quarter of 2011.

Third quarter 2012 adjusted earnings excludes special items related to net gains on asset dispositions, changes to tax laws in the UK, pension and settlement expenses and some other items.

Details of these special items can be found in the supplemental data provided with our earnings release.

Our production came in at the high end of the estimate we provided last quarter.

Total sales volumes for the quarter were in excess of production, resulting in a favorable impact to earnings of approximately $80 million.

And we will discuss these details as we go through the segments.

Sequentially, prices weren't a huge driver in earnings.

North American gas and bitumen prices increased while domestic crude and NGL prices decreased.

Slight increases this quarter, North American natural gas prices remained challenged.

We continue to offset this impact by shifting our investments towards liquids production.

Operating costs were consistent with our expectations.

Let's turn to slide 6, and talk about our total production.

Production of 1.525 million BOE per day was in line with our expectations.

Stepping through the waterfall, dispositions reduced production by 53,000 BOE per day compared to the third quarter of last year.

The dispositions included Vietnam, Statfjord Alba and some Western Canadian gas assets as well as the NaryanMarNefteGaz joint venture.

Downtime was heavier than normal this quarter, reducing production by 49,000 BOE per day compared to the same quarter last year.

We had major turnarounds this quarter in Alaska and in the UK.

Growth more than offset base decline, accounting for 256,000 BOE per day of new production.

With the majority of the growth coming from the Lower 48 shale plays and our Oil Sands assets.

We also had considerable production increases over these periods from Libya and China.

In summary, volumes were up 3% adjusted for dispositions.

But importantly, the 3% growth was largely driven by a 7% increase in liquids production as shown on the dark blue bars on the slide.

As we announced this morning we now expect our full-year 2012 production volumes to average between 1.57 million to 1.58 million BOE per day.

Now I'll turn to the segment slides, beginning with the Lower 48 and Latin America on slide 7. Production in this segment was 462,000 BOE per day this quarter, an increase over prior periods as we continue to successfully ramp-up production in our Lower 48 shale plays.

Total liquids production in the segment increased 21% over the same period a year ago, while natural gas production decreased 3%.

A year ago, liquids represented 40% of our production in the segment.

And in the third quarter 2012, liquids increased to approximately 46%.

We expect this liquids percentage to continue to grow and drive our margin expansion over time.

During the quarter, production was 76,000 per day at Eagle Ford with 79% liquids and 26,000 BOE per day at Bakken with 88% liquids.

Total production of 102,000 BOE per day from these two plays has doubled compared to the same period last year.

Compared to the second quarter, the increased liquids production along with the 26% increase in realized gas prices contributed positively to earnings in this segment, while continued declines in NGL prices negatively impacted earnings.

Despite the sequential increase in natural gas prices, the segment earnings continue to be impacted by generally weak natural gas prices.

Next we'll move to the Canada segment on slide 8. Canadian production was 277,000 per day in the third quarter, with the growth over prior periods being driven by the ramp-up at our Oil Sands assets.

Liquids production increased 30% year-over-year, while gas price decreased by 6%.

And this shift will show up as improved margins over time.

Canada reported negative adjusted earnings this quarter, largely reflecting ongoing weak natural gas prices.

However, earnings were improved compared to the second quarter as natural gas and bitumen prices improved quarter-over-quarter.

We also saw the WTI-WCS differential improve late in the quarter, and the price of diluent decrease, and this resulted in an overall improvement in bitumen netbacks.

And it should be noted that despite the negative earnings, the Canada segment continues to generate strong cash flow.

Now let's move to the Alaska segment on slide 9. Production in Alaska was 176,000 BOE per day this quarter, down 39,000 per day but in line with our expectations.

This production decline was largely due to major turnaround activity all across our assets and on the North Slope.

The impact of lower production on earnings was offset by sales from inventory this quarter, and these sales from inventories contributed approximately $120 million to the Alaska segments earnings.

As a result, adjusted earnings of $535 million were roughly equivalent to the prior quarter and improved from a year ago.

I'll now turn to slide 10, and talk about the Asia Pacific and Middle East segment.

Asia Pacific and Middle East continued to be a strong performer for ConocoPhillips, and provides important diversification to our portfolio.

Production in the segment was 306,000 BOE per day during the third quarter.

Both the Bay-Undan Field and the Darwin LNG plant were fully online this quarter after being down in the second quarter for planned maintenance.

Production continued to ramp up at Peng Lai increasing 20,000 BOE per day over the prior quarter.

We exited the quarter with net production of 45,000 BOE per day, and we expect to maintain this level of production during the fourth quarter.

Now where we had a gain in Alaska on the last slide from sales out of inventory, Asia Pacific and Middle East earnings were adversely impacted by about $60 million related to lift timings.

Europe is our next segment, and we'll cover that on slide 11.

Production from the Europe segment was 191,000 per day during the quarter, a sequential decrease of 45,000 per day.

Natural field declines, downtime, and asset dispositions contributed to the lower production in this quarter.

Downtime resulted in 28,000 BOE per day impact, primarily from planned maintenance at the Judy, East Irish Sea, and Britannia platforms.

The majority of production that was offline during the third quarter due to downtime should be back online during the fourth quarter.

The disposition impact was about 8,000 per day from Statfjord and Alba.

So adjusted earnings of $299 million declined versus the prior quarter, primarily due to this slower production.

It's important to note, that we benefit in a portfolio sense from having exposure to the stronger pricing in this segment.

Now I'll cover our next final geographic segment, the other international on slide 12.

So I remind you that this segment includes our assets in Russia, the Caspian and in Africa.

Production was 113,000 BOE per day, basically maintaining the same level of production that we've seen over the past couple quarters since Libya came back on line.

Adjusted earnings of $124 million this quarter were helped by favorable settlements of certain tax items.

Prior quarter earnings were negatively impacted by higher taxes, exploration expense, and adverse foreign-exchange impacts.

Earnings are also impacted by the sale of NMNG in mid August.

At the time of the sale, NMNG was producing about 11,000 BOE per day and was dilutive to earnings.

The final reporting segment I'll cover quickly is our corporate and other segment on slide 13.

Adjusted corporate expense during the quarter was $139 million.

This is lower corporate expense than we expect to see going forward as the quarter benefited from licensing revenue as well as some favorable foreign-exchange impacts.

But for the Company overall, total foreign-exchange was not a factor in the total quarter's earnings.

For the year, we estimate this segment's expense on an adjusted basis to be about $850 million.

We repaid $2 billion of debt during the quarter, bringing the total debt outstanding to $21.1 billion at the end of the quarter.

And total debt-to-cap was 31%, and our long-term target remains to be in the 25% to 30% range.

If you turn to slide 14, I'll cover our operating segment margins and returns.

This four pack of charts on this slide summarizes our key financial metrics for the quarter.

On a year-over-year basis, all four metrics were negatively impacted by lower North American prices as well as our overall realized price declined by about $5 per BOE compared to the third quarter of last year.

Our income and cash contribution per BOE were helped this quarter by the inventory sales in Alaska, but also reflected the operational and portfolio improvements that we're starting to make as a Company.

And over time, we expect these metrics to improve as we deliver on our growth programs, our margin expansions and our continued focus on returns.

So I'll wrap up my remarks on slide 15, which is our third quarter Company cash flow.

As Ryan mentioned in his opening comments, we generated $3.9 billion in cash from operations this quarter excluding working capital.

And working capital was a $412 million use of cash.

We also generated $522 million in proceeds from asset dispositions.

We funded a $3.7 billion capital program, bringing our year-to-date capital program to $11.9 billion.

We paid out roughly $800 million in dividends, and reduced debt by about $2 billion.

During the quarter, excluding working capital our cash from operations and proceeds from dispositions funded our dividend payments and our capital program.

And we used our restricted cash to pay down debt.

We ended the quarter with $3.7 billion in cash equivalents and restricted cash.

So our balance sheet and financial situation remains strong.

We are well-positioned to execute on our program.

Importantly, we have capacity and flexibility to fund the programs that will generate volume and margin growth going forward.

That concludes the review of our financial results, and I'll now turn the call over to Matt for an update on our operations.

Thanks Jeff.

I'll take us back through our operating segments and provide some detail on our drilling programs, growth projects, and both our conventional and unconventional exploration activities.

I'll cover some highlights from the third quarter, but I'll also update you on current activities and provide some color on what to expect in the near future.

I'll start with a Lower 48 and Latin America segment on slide 16.

First I'll focus on two key areas, the Eagle Ford and the Bakken.

In the Eagle Ford, we have about 230,000 net acres.

And our acreage is largely located in the condensate fairway, which the industry recognizes as the best part of the play.

And we have 14 rigs running in the play today.

In the third quarter, our production averaged 76,000 BOE per day.

And we achieved a peak production rate of 86,000 BOE per day.

In the fourth quarter, we expect to achieve a peak rate of 100,000 a day as we continue to drill and pick up wells.

And we are actively adding infrastructure in the play to create value.

For example, we're adding stabilization facilities like the one shown on thtop left.

To remove light ends, maximize our light crude sales at pipeline spec, and to maximize our captured NGLs.

We should have an entire Eagle Ford acreage position held by production by the middle of 2013, and that's important because it allows us flexibility to apply new technologies and thoughtfully determine the most capital efficient way to develop our overall acreage position.

Switching now to the Bakken, we have more than 620,000 acres in this liquids rich play that's all held by production.

We exited the quarter with a production rate of 26,000 BOE per day.

And as a result of instrumental takeaway capacity from new real facilities, we've ramped up from five to eight rigs and will see the benefits of this increased activity in the fourth quarter and in 2013.

We also have significant exploration activity underway and other unconventional plays in the Lower 48 including the Wolfcamp in the Delaware and Midland bases.

The Avalon shale, the Lewis shale in Wyoming, Niobrara, and the Mancos in the San Juan basin.

We expect to have results for discussing these plays by early next year.

And I should note that these are just a few of the opportunities we're evaluating in our vast Lower 48 land possession.

And we continue to identify other potential plays where we can acquire unconventional acreage at low entry prices.

Moving on to conventional exploration; we have some significant activities underway in the Gulf of Mexico deepwater and continue to build a portfolio of future opportunities there.

Just for some context, we have 1.5 million deepwater acres in the Gulf, making ConocoPhillips the sixth largest deep-water acreage holder there.

Our initial strategy for this area has been to participate in non-operated wells, while building a COP operated portfolio.

Currently we're drilling two non operated wells, the Coronado Prospect and the Shenandoah Appraisal well.

We're also just about to spud a third well Hummer, a surprising exploration well.

And we anticipate four additional exploration wells spudding in 2013, along with the Tiber appraisal well.

And the potential for additional appraisal wells exists if we have success with our exploration wells.

So we're really excited about our 2013 program in the Gulf of Mexico.

Our long-term strategy is to build an attractive operated lease possession that will allow us to drill 3 to 6 wells a year.

And to advance our operated program that was announced on Tuesday that we've secured access to a new deepwater drill ship to use across our operated portfolio starting in 2014.

So please go to slide 17, and we'll talk about the Canada segment.

Our Oil Sands assets in Canada are a big part of our growth story.

In fact, we are currently the second largest SAGD producer in Canada with 23% of total SAGD production.

And our assets continue to perform well.

Christina Lake Phase D reached first production in July, three months ahead of schedule.

Foster Creek is performing well, and Surmont Phase 1 achieved record production in September.

As a result, third quarter bitumen production was 92,000 barrels per day net after royalty, and we expect production to average over 100,000 barrels a day in the fourth quarter.

Continued expansion at FCCL is ongoing and construction of Surmont Phase 2 is progressing towards first production in 2015.

Surmont 2 is a large-scale development.

When it's ramped up to full production, the project will produce a gross annual average rate of 110,000 BOE per day equivalent to about three typical FCCL phases.

And we continue to expand.

For example, the sanction of Narrows Lake Phase A and Christina Lake phase F are anticipated by year-end.

Now the application of new technology is critical to the development of SAGD because it can add significant value due to the size of our resource base there.

So we're stacking an enhanced SAGD pilot in November, and we're actively testing several other technologies that will increase rate and reduce steam oil ratio.

Moving to our Western Canada business unit, here our drilling program is focused on liquids rich and light oil opportunities in our portfolio.

And we're also drilling or planning exploration wells in several of our unconventional plays in Canada including the Duvernay, Montney, and Horn River.

In addition to that, we're preparing for a winter exploration program in the Canol oil play in the Northwest Territories, where we hold more than 200,000 net acres.

And like the Lower 48, we hold a significant amount of land throughout Western Canada that's held by production, and we believe some of this acreage could be perspective for additional type oil and shale liquid plays.

So let's finish out North America with Alaska on slide 18.

Major turnarounds were successfully completed at Kuparuk, Prudhoe and Alpine this quarter.

In fact Kuparuk was completed 14 days ahead of schedule.

In October, the ConocoPhillips Board approved the North Slope's Alpine West project also known as CD5.

The project is now pending partner approval, which we expect in November and production will start from Alpine West in 2016.

As you may have seen in the press, we're working with the other producers in Alaska to evaluate the LNG exports from the North Slope.

The producer group has been focusing on narrowing down development concepts and assessing the cost of the major project components.

In the Chukchi Sea, we're targeting drilling at Devils Paw prospect in 2014.

Now this prospect is in 135 feet of water, so it can be drilled with a jack up rig with surface BOPs and a pre positioned capping device on the sea floor.

As we continue to invest around $1 billion a year of net capital such as Alpine West and infield drilling programs across the North Slope, significant additional oil development opportunities exist contingent upon more competitive state fiscal terms.

So let's move to slide 19 the Asia Pacific and Middle East segment.

We purchased more than 300,000 barrels per day from this region, and it's an area of significant growth for us over the next five years.

We continue to make progress with the Australia Pacific LNG project, the project remains on track with premise scope and cost and is on schedule for the mid 2015 of train one, and 2016 start up of train two.

So we tracked project progress in three main categories here; upstream, midstream, and downstream.

In upstream all major contracts for gas processing and water treatment plants and associated gathering systems are fully executed and module fabrication and drilling are progressing.

In midstream, the main pipeline work is in progress with right-of-way clearing, grading and pipeline straining proceeding as planned.

The downstream development of the LNG site at Curtis Island is also proceeding as planned with engineering progress ahead of schedule and all construction access, dredging and mainland facilities completed in the third quarter.

At Poseidon, Boreas-1 was a successful appraisal well.

Reaching target depth on September 18th with encouraging results.

The well was drill stem tested at just over 30 million cubic feet a day against the flowing and tubing head pressure of 3300 PSI.

Drilling operations will now begin on the second well of the program in November, and this is part of a five well appraisal program that we will conduct over the next two years.

In the Canning Basin, we've drilled and cored our first well.

The well was drilled to about 12,000 feet, and 1400 feet of core was collected.

This is the first of a three well program that will be completed by mid- 2013.

In China, our net production at Peng Lai reached 45,000 BOE per day at the end of the third quarter, and production should remain fairly steady at that level for the remainder of the year.

The first well at our Panyu growth project came on in late September.

Current Panyu production was about 8000 barrels of oil per day net, and this project will add another 8000 barrels per day between now and 2014 as we drill additional wells from the two new platforms.

We now have four major projects in execution in Malaysia.

Gumusut North-Petai, KBB, and Malikai which was recently approved.

First oil is expected from an early production system at Gumusut in the fourth quarter of this year.

SNP and Gumusut full production will start in late 2013.

The start up of the others will be staggered between 2014 and 2017.

We're also working on several other project developments in Malaysia, and we have the potential to significantly grow this business over the next five to ten years.

Due to recently renegotiated gas sales contracts in Indonesia, we will see significant increases to our realized gas prices for both our Natuna Sea Block B, sales to Malaysia, and the Corridor Block sales to the Indonesian domestic market.

Now these price improvements positively impact the value of both assets and increase the attractiveness of additional investment in these PSCs.

Finally in this segment, conventional exploration in Bangladesh.

There we've completed shooting seismic and we expect to complete the processing this year.

Please turn to slide 20, and I'll provide an update on our Europe segment.

We are focused on progressing our major projects in Europe.

In the UK, we completed a major turnaround at Judy that included preparing for the tie in of the Jasmine project and we installed the associated pipeline and jackets.

Development drilling results at Jasmine are exceeding expectations, and we expect first oil in the second half of 2013.

[The following statement redacted by Company following the call] - (In the UK, we're also planning a five well exploration and appraisal program at Greater Clair.]

In Norway, we installed jackets, bridges, and bridge supports for the Ekofisk South project and commenced the predrilling activities this quarter.

We've also progressed modifications to existing facilities in Ekofisk and Eldfisk II in preparation for tie in of the new facilities.

First production for Ekofisk South and Eldfisk II are expected in late 2013 and 2014 respectively.

In Poland, we exercised our option to acquire a 70% interest in Lane Energy, and assumed operatorship of three Western Baltic Basin concessions where an additional exploration well is currently being drilled.

The final segment I'll cover is Other International on slide 21.

As we mentioned earlier, we completed the sale of our 30% interest in NMNG.

Our Libya production returned to pre-conflict levels.

The third quarter average was 47,000 barrels per day.

Additionally, the Faregh and gas sales agreement was executed in early September, and this will result in a production increase of about 4000 BOE per day for the rest of 2012 and going forward.

In Kazakhstan, Kashagan production is expected be online in the first half of 2013.

We completed our seismic on Angola blocks 36 and 37.

Our blocks are immediately out board of the Cameia discovery in Block 21 and we're encouraged by what we've already seen on the seismic.

Drilling is expected to start in 2014.

I'll conclude my prepared remarks by reiterating the things you've heard consistently today.

Operationally the team is staying focused on executing the base business while successfully funding our emerging growth programs.

But also seeing the payoff from the past few years of opportunity captured, both in our unconventional drilling programs and our conventional major projects.

And our exploration team has done a great job not only building up our opportunity set, but advancing our current inventory to a drill-ready stage.

So I echo Ryan's earlier comments about how much there is to look forward to over the next few quarters and beyond.

So now I'll turn the call back over to Ryan for some closing comments.

Thanks Matt, and if I could get you all to turn to slide 22 for some summary comments.

The most important take away I think from today's call is that the businesses running well and that our plans are on track.

And I'm pleased with our performance in our first full quarter as an independent E&P Company.

We remain highly focused on executing our major projects and our drilling programs.

And we're also building and testing our conventional and unconventional exploration portfolio.

I think Matt's overview should give you confidence that we're making strong progress on these activities.

We're also executing on the strategic asset disposition program.

When complete, these asset sales will improve our portfolio and create financial flexibility.

This flexibility is core to our strategy, and you've heard from Jeff that maintaining a strong balance sheet is and remains a top priority.

The bottom line, our long-term value proposition remains unchanged.

We believe we have the portfolio and the programs to deliver 3% to 5% growth in production and margins with improving absolute financial returns and a sector leading yield.

This is our commitment and we're on track to deliver it.

We're also committed to keeping you updated on our progress.

We expect to announce our 2013 capital budget in December, and our year-end reserves and financial results early next year.

And finally, I'd like to encourage all of you to save the date for our first analyst meeting as an independent E&P Company.

We'll host our meeting in New York on February 28th, and we'll provide a detailed update of our strategic plans for growth and value creation.

So thank you for your interest and participation this afternoon, and we look forward to your questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions)

Ed Westlake from Credit Suisse.

Hello everyone, congratulations on the results.

And it certainly feels that confidence in 2016 growth in that margin improvement is building.

I guess I have a question just looking beyond 2016.

As you look across the portfolio, do think non conventional shale is enough or what should we focus most on, do you think, in the pre drill potential of the offshore portfolio?

Well, thanks Ed.

Appreciative the comments.

I think as we look out beyond 2016, that's the work that Matt alluded to in the operating update is we're working both on the conventional and the unconventional side of the Exploration business.

So I think you'll watch both those spaces globally in the Gulf of Mexico deep-water and in North America, and we hope globally in the unconventional space, as well.

We're working that pretty hard right now to load up the inventory for the latter half of this decade.

And then a more specific question, just coming in on the Eagle Ford.

Obviously, you've got some good production performance there.

Can you just remind us what acre spacing your planning your production, and any IP rate targets that are behind that target?

Because it feels like if you're already up at 100,000, and you've got 110,000 barrels a day guidance for 2013, that the well performance, or the efficiency, or something is changing that means you're ahead.

So, we have 230,000 acres in total, and we're currently thinking that the ultimate spacing will be about 80 acres.

So that's what we're planning for, and that results in about 1.8 billion BOE associated with the play.

But we have pilot tests going on, several pilot tests going on in Eagle Ford, where we're testing different technologies and different spacing.

So, that might change over time as we learn more.

Our IPs continue to be of the order of 1200 plus barrels a day.

And we're seeing strong IPs compared to the industry average.

We think our completions are working well there.

And just to confirm those IPs, what time period?

Those will be 30 days.

Right, yes that would be pretty good.

Okay, thanks very much.

Doug Terrison from ISI.

Good afternoon everybody, and also congratulations on your results.

Ryan, you mentioned a minute ago that underlying production growth was 3% in Q3, and it looks like we're going to have another 3% again in Q4.

So, the first question is whether or not that's your expectation for Q4, as well?

And then second, obviously higher production is important, but your profitability and returns were near the highest level of the year during the third quarter, as well.

So I wanted to see if you could specify some of the functional and/or geographical drivers behind the improvement in the returns, as well.

Well thanks Doug.

Yes, we gave you a range for the full-year and expect us to come in that range pretty well, so you can see the growth that's coming in the fourth quarter.

And I think as we look across the portfolio, we came out of the turnaround season pretty well.

We've added rate in China and Libya in the Canadian business unit and in the ramp-up in the unconventionals in the US are providing a lot of the production growth that we're seeing in the third and the fourth quarter.

And those areas are also, as we see prices bouncing around differentials, bouncing around as well.

Those same areas have largely led to the income and the margin improvements that we're seeing, as well.

Primarily China coming back and the growth in both North American unconventionals and the Canadian oil Sands.

Okay.

And then also administratively the exit rate for NMNG was 20,000 to 25,000 barrels per day is that about right?

No, the exit rate was probably closer to 11.

Okay great, thanks a lot.

John Herrlin from Societe Generale.

Yes, hello.

Just some quick ones.

With the Eagle Ford, how long are the laterals and how many drilled but unfracked wells do have currently inventoried?

The laterals are typically 5000 feet, and I don't know off the top of my head how many we have drilled and then not hooked up yet.

But we have quite a few that we are waiting to hook up over the next quarter in Q1.

Okay, that's great.

In terms of your expenditures, if you're going to split it between conventional and unconventional is 40% a good estimate for unconventional CapEx exposure?

Yes, that's a reasonable estimate of where we'll be going on our unconventionals and our planning.

Okay last one for me is Poland and shale.

You've had other companies exit.

Why are you optimistic?

We still see potential in that Poland Baltic region of pull where we're drilling just now.

But time will tell, and we're testing a different part of the play moving a bit further north towards the Baltic with the well that we're drilling just now.

And so, we'll see how that works out.

Thanks Matt.

Paul Sankey from Deutsche Bank.

Hello, everyone.

Just right at the end there you said something that I just wanted to clarify, which was that you're targeting a sector leading yield.

Could you just run through that?

Because it's not actually on the slides that I see.

Well, I think as we think about it Paul, today we're yielding 4.5% or so, given where our stock price is.

And as we think about our peer group as a mix between independents and the major integrates, we think the yield that the dividend will underpin for the stock will be at the upper end of all that peer group.

Now some of the European integrates will be a little higher, but where we are relative to a mix of peers in the integrated an the independent side we think it's one that falls at the top end.

And its an important part of our value proposition, and we're committed to maintaining the kind of a dividend.

So, you're committed to maintaining the yield at the higher end of the range?

Well, the yield will -- we expect the stock price to grow, so the yield will probably come down a little bit.

We're committed to maintaining the dividend that we've announced and where we are at today.

Okay, I think well -- if you guys got an analyst meeting next February right?

So I'm just not quite sure about the dividend policy.

Because I think you've got dividend as your top cash priority, and you have said that you want to grow the dividend.

I'm not sure exactly what you said on the percentage aim for that, if anything.

And then the yield is not, with all due respect, not quite what you meant.

Because, obviously, would be a different thing if you were targeting a best in class or upper range yields.

Let me -- so Paul, what we're talking about is, what we have said is we'll allocate 20% to 25% of our cash flows on an ongoing basis back to the shareholder, and we'll do that primarily through the ordinary dividend.

And we expect over time as our production grows and our margins grow, that our cash flows are going to grow, as well.

So, I think what we say as we ought to expect modest increases in the dividend as we go forward over the next five years, and deliver on the program that we've outlined to the market.

It probably won't grow as fast as what the dividend has grown over the last ten years in the integrated Company.

But as we look forward over the next five, as our cash flows grow and our margins grow, so shall our cash flows grow and our commitment to the shareholders remains the same.

We're going to distribute that percentage of our cash back to them.

Yes that's great.

I understand now.

And the yield will be -- hopefully share price will increase and the yield might come down a little bit.

Sorry, I was just picking you up on that.

But it wasn't actually written down so I couldn't be sure.

I understand now.

Just my second follow-up, back to the Australia LNG.

You started down the road of explaining where we were on costs and progress.

Could you just remind us what the total project cost is expected to be?

When the critical moments are for activity?

If I give you an example, Chevron's goal on project will have its peak activity level next Q2, 2013.

Could you talk about where, if you like, the back some level of risk lies on the timeframe going forward?

And where you see the overall project costs?

And you began to break that down between your three segments of where the costs lie.

Can you talk a bit more around those?

I think you talked about the extent to which you were contracted, but I wondered if you could go through some completions levels, and so on.

Thanks.

Yes, I'll let Matt jump in, as well.

We're still at a two-train $20 billion project for APLNG.

That's upstream, downstream, midstream all combined up.

We haven't seen any indication.

That's without FX considerations, which might move around a little bit over the course of the next four to five years as we complete the scope.

I'd say we're ramping up to peak rates.

I think we probably hit there in the '13 and into 2014, is when we start with our peak manpower both on Curtis Island and in what we're doing on the upstream side of the project, as well.

The project is on track in terms of the progress, the critical path is intact.

And we're quite comfortable with the way things are working just now in APLNG.

And when is the -- given the critical path, when would be the maximum points of risk over the next coming quarters or whenever?

As you go through the critical path, for example one of the things on the critical path for an LNG project is typically the LNG tanks themselves.

And they are ahead of plan.

Basically, as we work through the critical path, there's always these individual milestones that you want to meet.

But we are comfortable that we're on track to do that.

And if we'd rolled that up into a project completion number so far, were would we be?

I think you might have said that actually.

Sorry.

Project completion number, as in the capital cost?

Yes, exactly.

What percentage is done?

Percent complete just now for the project is about 20% I think.

20% to 25%.

Maybe it's 22%.

But it's that order of magnitude.

Kim?

Faisel Khan from Citi Group.

Thanks.

Good afternoon.

When we look at what's going on in North America today, there seems to be a lot of asset transactions taking place.

I just want to get your update on acquisitions.

I know you're divestiture plan is fairly straightforward, but just want to get your update on how you're thinking about also acquisitions given all the transactions we have seen of late.

And I have a follow-up after that.

Yes, thanks Faisel.

I think on the acquisition side, we're mostly focused on acreage acquisitions, and have been over the last year so.

I think we've added a bit over 700,000 net acres to the portfolio in the last year.

So, what we're focused on is trying to identify these unconventional plays early, so we can be a very early mover and get in more of a ground floor type of opportunity, rather than getting in after pilots have been done, and the resource has been derisked and drilling has started to occur to develop it.

The price goes up pretty dramatically when you reach that stage.

So, our effort has really been focused on the organic side and capturing our opportunities early.

And in the Gulf of Mexico, are you pretty satisfied with your position or if assets were for sale would you take a look at them?

Well I don't think we're ever satisfied with our position.

We continually look for opportunities to improve it or consolidate our positions, and bulk up what we like and farm out what we don't like.

Okay, understood.

Although I'm looking at the Eagle Ford and the Bakken positions.

In your prepared remarks thing you talked about how you're developing some infrastructure.

What is that infrastructure spend exactly?

And when is that going come to an end over the next -- I guess in the future?

So, this year we're spending around $600 million to $700 million on infrastructure.

I'm not exactly sure what our numbers are for next year, but it's mostly 2012/2013 expenditure to build the backbone through our acreage as we develop that whole acreage position.

Okay, and then if I'm just thinking about the projects that have been sanctioned, and I'm thinking about reserve bookings, it seems like you've got some additional sanctioning in Canada.

You've got the, I think, Alpine West, you said, and then you also went forward with the second train of APLNG.

Are those three big things that I'm thinking about?

And how would I also think about the Eagle Ford, where you have 1.8 billion barrels of oil equivalent in place?

So, we'll see reserve bookings at the end of the year associated with the ones that you listed.

Plus we expect to see our proved preserves in Eagle Ford increase.

And we also sanctioned the Malikai project in Malaysia, so we'll see reserves increase there.

And they'll be some puts and takes in various other assets, but those are the major reserve additions that we expect.

Okay, got it.

Great, thanks for the time guys, appreciate it.

Blake Fernandez from Howard Weil.

Folks, good afternoon.

Congratulations on the results.

I had a couple for you.

One is a little bit more detailed.

But another is the Lower 48 natural gas production increased fairly sizably, and I'm trying to determine, I know there were some gas that was previously shut in.

Can you say whether that was a result of that gas coming back on line?

Or maybe you could just answer were you stand today with regard to shut-in gas?

So we don't have any significant volume shut in at all now.

Some of that increase is gas coming back on line, but the majority of it is increases in associated gas production with our liquids rich plays.

For example, Eagle Ford.

Okay.

Second question is on Oil Sands in general.

There's been an awful lot of press reports on assets being marketed from you guys up there, and I know you probably are unwilling to share too much.

But I'm just curious if you could talk in general how the Oil Sands fits into the portfolio?

Yes, I think the Oil Sands are important in our portfolio.

The important growth.

The margins are good, and they have a different profile, obviously, relative to some of the other assets, but important in complimenting and large portfolio like ConocoPhillips has.

You have heard we have gone out looking at marketing some of our Oil Sands positions, primarily some of our Surmont and some of our 100% acreage we have outside of the area.

We got a lot of interest in it, and in fact, we got enough so that we got proposed a number of different structures.

So, we're taking -- stepping back for a minute and taking a look at what might work best for ConocoPhillips as we think about our options that we have with our position in Canada.

Okay Ryan, but just to be clear we shouldn't view that as a potentially a full exit out of Oil Sands right?

No.

Okay.

And sorry, I'll sneak in one last one.

I know you're in I guess in the conceptual phase of ANS Gas LNG out of Alaska.

Obviously you have a fairly decent position up in Western Canada, as well.

I'm just curious, are you exploring options for LNG exports out of Western Canada, or are you just really focused on Alaska at this point?

Thanks.

I'd say we're mostly focused on Alaska, Blake.

Okay.

Thank you very much.

Iain Reid from Jefferies.

Yes.

Hello gentlemen.

Sorry, and lady.

Just a couple of questions, please.

I think you talked about natural gas price improvements coming in Indonesia and Libya, and you can see that your Libyan -- realized that it's picked up substantially.

So, just interested in why that is.

And also on the Indonesian side, is that something we've got to look forward to, or is that something which has already happened?

On Indonesia, it's really something that we have to look forward to.

On both the Malaysia contracts and the domestic Indonesia contracts.

You should start to see those coming through in the fourth quarter.

And is that something structural, or is it an oil price effect, or what is it?

Renegotiation of the gas contracts from Malaysia, because Petronas has wanted to secure more gas, and because the Indonesian government wants to incentivize more development of domestic gas production in Indonesia.

So, they're moving towards more market-based pricing.

So, those are really the drivers.

Okay, and what happened in Libya?

You mean we have the Faregh gas contract that isn't going to happen until September.

So, we had a little bit of that in the third quarter which is the -- if you're looking at the realized price per MCF in Libya, we started to sell gas under that contract.

Okay.

Second question is just wondering how you feel about your UK North Sea portfolio.

You've obviously have a couple of developments there.

But, you're also I think going to sell some assets over time with the tax increases et cetera.

Are you a kind of net seller now of the UK or are you -- after to this disposal, which is in the works?

Or is there something else coming?

Well, no.

I think we've been pretty pleased, so the North Sea and the UK sector you've got to divide that into three areas, the Central Gravin, the stuff we have up west of Shetlands with our Clair interest and the East Irish Sea and then the Southern North Sea that we have.

We did try to market our Southern North Sea position a little better earlier in the year, but that got hung up with a bunch of changes that were occurring in the government in the UK side with taxes and abandonment liability and some of those issues so.

But the core area that we still like and remain, think there are still opportunity there.

Things like Jasmine developments that tie into our existing infrastructure.

So, we see additional opportunity off the Britannia platform bringing more wells and additional satellites into production in the Britannia area, and we're currently exploring in the area for more Jasmine look-alikes.

Okay.

Did you pick up any licenses today, Lance, in the license round?

I don't know if we did, I haven't been informed if we have are not.

Okay.

All right guys, thanks very much.

Paul Cheng from Barclays.

Hello.

Good afternoon.

I have a number of soft questions hopefully they're soft.

Matt or Jeff, for the APLNG, the $20 billion, what's the percentage that is Australian dollar-based, and what FX rate that you used in the budget?

If you can remind me.

It's somewhere between 50% and 60% Australian dollar, and I don't know that we have a particular FX rate that we're going to quote in the budget.

I see.

Matt, how many wells are you are ready drilling in Poland?

And is there any results that you can share from those wells?

We have drilled a total of four wells.

Three in the Poland Baltic region, and we've got one more that we're drilling just now.

But we're not really ready to talk about the results that we've had in those wells yet.

I see.

Ryan I know that you've going to give the budget in December.

If you're looking at right now, do you expect the budget will be pretty similar to this year, or that it's going to be higher or lower?

I'd say it's in the range of where we're at this year.

Okay.

Jeff, on the corporate expense, do have a guidance that for 2013, 2014, of a quarterly run rate that a normal quarter may look like?

Yes, maybe just a couple words about our corporate segment.

So when we -- with this spin and the way we realigned our segment, some of the things that didn't used to be in corporate are in corporate now.

So particularly some of the technology operations.

So, that's going to introduce a little bit of volatility to corporate numbers.

But if you think about core corporate which is made up of primarily net interest expense and corporate G&A, that's going to be around, I would say $220 million a quarter more or less.

But there's going to be probably more volatility in the corporate number than you might have been used to seeing in the past.

Jeff, that's an after-tax number, right?

$220 million?

Yes that's an after tax income number, right Paul.

And Matt, I'm just curious, is there any quality difference between your consolidated bitumen output and your equity bitumen output?

So in other words, that when we're looking at estimating the pricing on the implied bitumen pricing, is there any quality differences that we should assume that there would be differences?

Well you can think about it in three different areas, Surmont that produces a SYN-bit.

So it explains the bitumen is blended with a synthetic.

And the FCCL assets both blend with a condensate.

So, as condensate prices and synthetic prices move around that effects the net backs.

Within the FCCL, Christina Lake has a higher tan content than Foster Creek.

So as a result, it sees a bit of a discount to the blend it sells.

But roughly speaking, the current prices the net back at Surmont and at Foster Creek are about the some.

And the net back at Christina Lake is a bit less because of this high tan content.

Matt, have you guys received a final approval to restart fully on Peng Lai from the Chinese?

We've submitted an EIA application and overall development -- revised overall development plan.

We expect the approval shortly for both of those.

I see.

A final one, Jeff from a inventory standpoint at the end of the third quarter, are you guys still underneath [over deep] or should we assume that it's pretty much that you're catch-up by now?

When you have an operation the size of ours, and you've got a lot of liftings happening -- oil liftings happening in places like Europe and Alaska and in Asia, every quarter you're going to have a little bit of fluctuation between the amount that you sell in the amount that you produce.

And it's going to go plus and minus.

Generally we're in a balanced position.

But we talked in the first quarter that we had about an $80 million negative impact from timing.

We've come out this quarter, we said, about an $80 million positive impact from timing.

We're likely to see that order of magnitude types of swings can happen.

Just because -- through normal operations of timing of when --

Sure.

Fully understand.

But from a inventory standpoint you are pretty balanced at the end of the third quarter?

Right.

But again, we'll have pluses and minuses, and particularly when you look at particular segments you can have pluses and minuses just as part of your normal operations.

Very good, thank you.

Pavel Molchanov.

Hello guys.

I want to go back to one of the earlier questions about the dividend.

Your long-term growth target of 3% to 5% and your simultaneous target of having one of the highest dividends in the industry.

If you discover that both cannot be done at the same time, which do you choose?

Well, we've set our priority on our funding is with the dividend.

So, what's the minimum acceptable level for organic growth?

In other words, would you be willing to take that down to 2% to 4%, 1% to 3% or is it the dividend unambiguously what you would choose regardless?

So, we would like to be here in ten years saying we've had steady dividend increases every year over an extended period of time.

How fast we grow the dividend is going to function of how fast cash flows actually grow.

We sit today at one of the higher dividends, and we've had some very strong dividend growth over the past decade.

I think what we're saying is we expect to have dividend growth going forward.

It won't be at the same pace that it's been in the past.

But that's a key part of our delivering to the shareholders, and we really can't sit here today and tell you exactly what the dividend growth rate is going to be going forward.

It's an important part of what we offer the shareholders.

Okay.

Appreciate it guys.

Thank you that concludes the time that we have for the question-and-answer session.

I'll now turn the call back to Ellen DeSanctis for closing remarks.

Thank you Kim, and thank you everybody.

If there were folks in the queue we didn't get to, Vlad and I are obviously more than happy to cover off your questions off-line.

Thank you very much for your interest, and we look forward to ongoing communications in December and certainly in the early part of the year.

Thank you.

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 press release contains forward-looking statements.

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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.

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