康菲 (COP) 2013 Q3 法說會逐字稿

Welcome to the Q3 2013 ConocoPhillips earnings conference call.

My name is Christine and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded.

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

You may begin.

Thanks, Christine.

Thanks to all of our participants and a big welcome to our third-quarter earnings call.

Joining me today in the room are Jeff Sheets, our EVP of Finance and our Chief Financial Officer, and Matt Fox, our EVP of Exploration and Production.

We'll begin our prepared remarks in a moment.

But I wanted to make sure that all of you saw the announcement this morning that we completed the sale of our Kashagan business for about $5.4 billion.

Just a quick mechanical point, we sent the earnings release and the Kashagan releases separately.

That was because we had to queue up the earnings release last night and we weren't entirely certain about that timing of the Kashagan close.

So apologies there for a little bit of possible confusion.

But this is obviously a huge milestone for the business, and wanted to get the news out to the marketplace this morning.

I also wanted to make sure that all of you saw in our release this morning that we expect to announce our 2014 capital and production budget in early December.

And that in 2014 we will be hosting our Analyst Meeting on April 10 in New York.

Obviously details to follow.

If you'll turn to page 2, you'll note our Safe Harbor statement, and that describes the risks and uncertainties in our future performance.

These are also described in our periodic filings with the SEC.

With those details out of the way, I'm going to turn the call over to Jeff.

Jeff?

Thanks, Ellen.

Hello, everyone, and thank you for joining us today.

I'm going to jump right into the material beginning on slide 3. This slide shows some of the key highlights for the quarter.

Once again, the theme of today's call is pretty simple.

We're successfully executing on our business plan.

Operationally, we delivered our expected volumes.

We produced 1.514 million BOE per day, which is in line with guidance despite the curtailment of Libyan production for most of the quarter.

From continuing operations we produced 1.47 million BOE per day.

Without the disruption in Libya we would have exceeded the high end of our production guidance.

As we've stated for quite some time, we expected this quarter to be the low point on volumes, and we're positioned to grow from here.

The third quarter was an active period for seasonal planned maintenance.

We executed these key turnarounds on schedule, and most of that work is complete for the year.

Our major growth projects are progressing.

Christina Lake Phase E and Ekofisk South are now producing, and others are nearing first oil.

We have several near-term milestones that Matt will discuss in a minute.

So, operationally we executed our plan.

Moving to the financial results, reported earnings were $2.5 billion, or $2 per diluted share.

Adjusted earnings were $1.8 billion, or $1.47 per share.

This is a 7% increase year over year.

We were also up 4% sequentially despite this being the low point for volumes.

And excluding working capital we generated $3.8 billion in cash from continuing operations.

And we ended the quarter with $3.9 billion in cash.

Cash margins grew 13% compared to last year's third quarter, reflecting the impact of higher prices, production mix and location.

Normalized for changes in prices cash margins grew 3% year over year.

This is an important part of growing cash flows to internally fund our investment programs and dividends over time.

In the quarter we continued to prune our portfolio and closed on two nonstrategic asset sales.

Our Clyden undeveloped oil sands leasehold in Canada and our interest in the Phoenix Park midstream assets in Trinidad and Tobago.

And as Ellen mentioned at the start of the call, importantly, we achieved a big milestone earlier today with the closing and the receipt of funds for the $5.4 billion Kashagan transaction.

And we continue to make progress on closing our other announced asset sales.

We're continuing to add to and test our conventional and unconventional exploration inventory globally.

And these programs are running at a high level of activity.

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

In early July we increased our dividend by 4.5%.

And we remain committed to increasing the dividend over time.

In summary, we delivered on our plan for the quarter, we achieved the operational performance we expected, and generated strong financial results.

We're positioned for an exciting phase of growth and margin expansion, which is the essence of our strategic plan.

So please turn to slide 4 and we'll cover the financial review for the quarter.

Again, this quarter's adjusted earnings were $1.8 billion, or $1.47 per share.

And this was slightly above consensus.

The 7% year-over-year increase in adjusted earnings was primarily driven by higher margins.

The higher margins reflect strong liquids pricing in the quarter and a continued shift to higher-value liquids in the portfolio.

Average realizations were up 6% year over year and 4% sequentially.

Production from continuing operations was in line with expectations, but down sequentially and flat compared to the third quarter of 2012, largely reflecting the curtailments in Libya.

We've shown a table of segment earnings for the quarter in the lower right corner of the slide.

Our usual segment charts can be found in the appendix of this deck.

And I don't plan to review these on the call but wanted to make a few key points here.

Alaska income was down sequentially due to planned maintenance, but in line with our expectations.

Lower 48 adjusted earnings were up sequentially, reflecting strong liquids prices and the mix shift.

Canada generated significantly higher adjusted earnings sequentially, as well.

Although natural gas prices were weaker than last quarter, bitumen prices were particularly strong, reflecting higher WTI prices, favorable diluent prices, lower crude differentials, and lower seasonal blending requirements.

Sort of a perfect set of conditions for the oil sands.

At this point we would not expect fourth-quarter realizations for bitumen to be as strong.

Europe and the Asia Pacific and Middle East segments were also in line with expectations.

Our corporate segment adjusted losses were about $40 million higher than in the second quarter of 2013 due to the absence of licensing revenues in the third quarter.

This was about the same level we would expect for the fourth quarter, as well.

So there's no change to our full-year guidance of $750 million for this segment.

Next I'll step through our production performance for the quarter on slide 5. Total company production in the second quarter was 1.514 million BOE per day.

And this includes 44,000 BOE per day from discontinued operations.

This chart shows continuing operations compared to the third quarter of 2012.

In the third quarter of 2012 production from continuing operations was 1.47 million BOE per day.

Adjusting for dispositions of 12,000 BOE per day, normalized production from continuing operations was 1.548 million in last year's third quarter.

And that's the middle blue bar on the chart.

And I'll talk about growth from there.

The Libya downtime accounted for 28,000 barrels per day reduction compared to last year's third quarter.

But that was partially offset by lower downtime in the rest of our operations of around 11,000 per day in this year's third quarter.

The key is the next two bars.

You can see that growth of 215,000 barrels per day more than offset declines of 186,000 barrels per day.

This represents net organic growth of 29,000 per day, or about 2%, adjusted for dispositions and downtime.

The majority of the growth came from our development projects in the Lower 48 shale play plays, growth in our oil sands assets, and from China.

And as I mentioned before, this should be the low point on continuing operations volume that we've been predicting for a while.

And we are now positioned for an upward trend.

If you'll turn to slide 6 I'll make a few comments about the improving margin trend we also have underway.

This slide shows how our third-quarter growth and changing mix drove cash margin improvement compared to last year's third quarter.

The tornado chart shows the change in this quarter's volumes by region and product compared to last year's third quarter.

The growth, shown in green, is all from liquids.

In addition, it's coming in areas with more favorable fiscal terms than the company average, notably the Lower 48, Canada and the Asia-Pacific and Middle East segments.

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

Slide 7 shows the impact of our growth mix shift and fiscals on our margin performance.

This slide shows sequential and year-over-year cash margins, both on a reported basis and a price normalized basis.

Compared to last year's third quarter, cash margins grew 13%.

Sequentially cash margins grew 6%.

And realized prices improved compared to both periods.

But that's not the whole story.

On the right side of the page using our published sensitivities, we priced normalized margins with last year's third quarter as the baseline.

As you can see, cash margins improved 3% on a price normalized basis compared to last year.

This metric will tend to be volatile on a quarter-by-quarter basis but we expect the trend to continue to improve as we shift production towards higher-value products and places with more favorable fiscal terms.

And we'll continue to track and report this metric.

I'll wrap up my comments with our cash flow waterfall and quarter end financial position on slide 8. I'm going to talk you through our cash flow.

And this does not include the proceeds from Kashagan, which we announced this morning, which will be a fourth-quarter item.

Through the third quarter of 2013 we've generated $11.8 billion of cash from continuing operations.

And our working capital was about $100 million source of cash.

Through the end of September we've generated $3.2 billion in asset sales proceeds from the sale of the Cedar Creek Anticline asset, the Clyden assets, Phoenix Park, and some other smaller asset packages.

If you include Kashagan in, this increases to $8.6 billion.

So far this year we've funded an $11.9 billion capital program for continuing operations, and paid out $2.5 billion in dividends.

Debt and other, which includes the capital associated with discontinued operations, accounts for a $1.2 billion use of cash in 2013.

So we had $3.9 billion of cash on hand as of September 30, essentially flat to where we started the year.

Our balance sheet and financial situation are very strong, and just got stronger today with the closing and receipt of the proceeds from the Kashagan disposition.

We're in a great position to execute our investment programs and deliver value through a combination of organic growth, improving margins, and a compelling dividend.

That concludes the review of the financial overview.

And now I'm going to turn the call over to Matt for an update on our operations, which begins on slide 9.

Thank you, Jeff.

As Jeff mentioned, the main theme of this quarter's operational performance is we're on plan.

In fact, that's been the theme for the past several quarters.

I'm going to cover the operations material by our capital categories.

As a reminder, those are our high-quality base assets, our lower-risk development drilling programs, our major projects and our exploration program.

So I'll begin with a quick review of our base asset performance.

Most importantly, this quarter's major turnaround and tie-in activity went according to plan.

And this essentially completes the majority of our major turnaround activity for this year.

I'll run through a few of these key activities quickly.

Alaska experienced high seasonal turnaround activity at Kuparuk and Prudhoe.

In the Lower 48 we had planned downtime at the Lost Cabin gas plant.

In the U.K., the Britannia Area and southern North Sea turnarounds were completed.

And planned maintenance was also recently completed at Foster Creek in the oil sands.

The shutdown activity that began at Norway's Greater Ekofisk complex in June was completed early in the third quarter.

And included the brownfield work necessary for the new Ekofisk South and Eldfisk II projects.

As the chart on the lower left shows, most of our planned turnaround activity is complete for the year.

Fourth-quarter turnarounds are nearing completion at Clair and Qatargas 3. The restart of our assets after the recent turnarounds should deliver strong volume momentum in the fourth quarter.

So will the expected production startup in the East Irish Sea following about a year-long shutdown there to replace the acid gas plant.

So, as you can see our base assets performed well.

Now let's move on to our development programs on slide 10.

These development programs consist of lower-risk drilling-led activities around the world that mitigate our base decline and generate higher margins and attractive returns.

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

In the Kuparuk Field in Alaska, our coiled tubing drilling sidetracks continued in the third quarter.

Since changes were made to Alaska's fiscals with the More Alaska Production Act, we added a rig at Kuparuk at the end of May.

We are planning to add another rig for development drilling in Kuparuk in January.

And we continue to work with partners on Prudhoe to identify additional opportunities to increase activity there.

A big milestone for the quarter was reaching 500,000 BOE per day in the Lower 48.

Of course, this is largely due to performance from the unconventionals in the Eagle Ford and the Bakken, with continuing good performance from the Permian conventional program.

A couple of highlights from these plays, Bakken production averaged 34,000 BOE per day in the year's third quarter, up 31% compared to the same quarter last year, and up 13% sequentially.

Our focus during the third quarter was on reducing the time from drilling a well to bringing it on production.

This continues to be our focus and will become even more important as we shift to pad drilling.

At the end of the third quarter we had 11 operated rigs running in the Bakken, nine of which were pad drilling.

The Eagle Ford also continued to deliver strong performance.

Third-quarter production averaged 126,000 BOE per day, up 66% compared with the third quarter of last year.

Sequentially, the Eagle Ford grew 4%, a bit lower than the first half of 2013's growth rate because this quarter was impacted by the commissioning of further stages of the Helena and Sugarloaf stabilization facilities and maintenance at third-party facilities to increase meter sizes, resulting in a slight increase in downtime versus the second quarter.

At the end of the third quarter we had a backlog of 77 wells waiting on facilities in various stages of completion.

This represents a 38% reduction in our inventory compared to year end 2012.

So we're gaining on the backlog.

The Eagle Ford exited the third quarter at over 130,000 BOE a day.

And for the fourth quarter we will continue to run 11 rigs in the play and expect to bring on between 50 and 60 operated wells.

As we head into 2014 we're in full transition to multi-well pad drilling on more than 1,800 remaining identified well locations, assuming an 80-acre well spacing.

Right now 6 out of the 11 rigs running in the Eagle Ford are pad drilling.

And we expect to see more variability in our quarterly production levels as we move to pad drilling.

But we anticipate continued growth in this asset next year.

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

Here our development drilling activity continues to focus on the Glauconite, Montney, Lower Cretaceous, and Triassic plays.

Activity levels are expected to ramp up in the fourth quarter as we prepare for and execute our winter drilling program.

Finally, our legacy field development programs are also on track through all of our operating areas.

Now let's discuss our major projects on slide 11 where we're approaching some very important milestones.

Our projects are at very high levels of activity, and remain on track to deliver about 400,000 BOE per day of production by 2017, as shown on the top left graph.

Virtually all business segments are contributing to our growth for major projects.

In Alaska, our CD5 project, construction is progressing on schedule, and preparations are underway for the winter construction season when the ice roads are in place.

We continue to pursue engineering work and additional satellite projects for sanctioning in 2014.

For example, work is underway at Shark Tooth and Greater Moose's Tooth 1. We'll make a decision on these projects late next year.

You also probably saw our recent announcement about the site selection for a possible Alaskan LNG project, which we now refer to as AKLNG.

Along with our co-venturers, we're performing studies now to determine the feasibility of that project.

Our oil sands projects are performing as planned.

The combined oil sands project averaged 107,000 BOE per day during the quarter, up 16% year over year.

Christina Lake Phase E started up in mid-July.

And this should add about 20,000 BOE net over the next several months.

At our operated Surmont 2 project we remain on plan for first steam in the first half of 2015.

You may have seen the announcement that we achieved first oil at Ekofisk South last week, a couple of months ahead of schedule.

This was an exciting milestone for the Company.

Over the next few years we'll ramp up volumes as we drill 35 producing wells and 8 injection wells.

And by early 2015 we will also start first production at Eldfisk IIII.

So we're positioning ourselves to achieve significant growth in Norway and extend field life for decades to come.

At Jasmine in the U.K., we're in the final stages of our commissioning and startup preparations before initiating first oil.

Offshore hookup is progressing as planned and four wells have been perforated and are ready for first production.

Jasmine should start up later in this quarter, which would provide good exit rate momentum going into 2014.

At Curtis Island we continue to progress our APLNG project.

Train 1 is still on schedule for first LNG by mid-2015, and critical milestones have been achieved on the project.

We've got a lot going on in Malaysia.

We're close to achieving major project startups in two non-operated projects, Gumusut and Siakap North Petai.

At Gumusut, offshore commissioning continues.

The tenth and final riser was installed in early September and flow line installations are complete.

They operator estimates that full field startup will be in early 1Q '14.

The Siakap North-Petai development is continuing hookup and pre-commissioning.

Umbilical installations are complete and flow line installation is underway.

And the operator estimates that startup will occur right at the end of this year.

Elsewhere in Malaysia, the Kebabangan development is also progressing.

Topside fabrication is running ahead of schedule and drilling commenced in August.

The overall project remains on track for first production in the fourth quarter of 2014.

So you can tell we're at a very exciting yet critical time in many of our major projects.

And they'll be a key driver in our volume growth over the next few years.

So, now I want to briefly cover our exploration program on slide 12.

Our exploration efforts continue on several fronts.

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

We're drilling several non-operated prospects currently.

And we're advancing our operated prospects to the drill-ready stage.

We currently have three conventional prospects drilling in the Deepwater Gulf of Mexico program.

We have an interest in the Gila and Deep Nansen wildcat prospects.

In addition, we have an interest in a Tiber appraisal well.

So we are participating in some big, important Lower Tertiary wells.

We're also currently progressing our plans for our operated drilling program in the Gulf for 2014.

In the Browse Basin of Australia we drilled the Proteus-1 discovery during the recent quarter.

This was an untested structure to the southeast of the Poseidon discovery.

In Indonesia, we obtained government approval for the Palangkaraya farm-in agreement, onshore Kalimantan.

This clears the way to begin drilling next year.

In Malaysia we completed our seismic activity in Block SB 311.

In the Kwanza Basin in Angola we completed our 3D seismic program earlier in the year.

We've identified and ranked several prospects and expect to be drilling there by mid next year.

And we're just as busy in several unconventional plays, especially in North America.

In the Permian Basin, we're testing prospective zones across our leasehold in the Delaware and Midland Basins.

In the Niobrara, we currently have one rig in the field executing an appraisal program.

It's too early to discuss results in the Permian or the Niobrara, but we're encouraged by our preliminary results.

In Canada, we continue to drill and appraise the Duvernay and Montney plays.

And we're also gearing up for a second season of winter drilling in the Mackenzie Valley Canol play.

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

And the key takeaways are these.

The operations are running well.

The development programs are delivering.

Startup of several growth projects are underway or imminent.

And we've got high level of exploration activity.

If you turn to slide 13 I'll quickly cover how this all adds up to our production outlook for this year.

The table on the bottom of the slide provides actual volumes for the first three quarters of the year and our expected range for the fourth quarter.

The data is provided for both continuing and discontinued operations.

Our overall volume guidance for the year is unchanged, except that in the fourth quarter we are now removing 50,000 BOE from Libya as a result of the ongoing disruptions there.

What's important to note is that the fourth quarter volumes are expected to ramp up from the third quarter due to lower turnaround activity, ramp up in our unconventional programs, and the major project startups.

The range in fourth quarter volumes reflects typical variability in major projects startup timing.

We'll announce our 2014 production target with our capital release in December.

In the meantime, we're positioned to deliver a strong exit rate in 2013 and that will provide strong momentum towards achieving our organic growth goals next year.

Now please turn to slide 14 for our summary comments.

Operationally we've arrived at a very important inflection point for the Company.

We have several key milestones to achieve this quarter.

And we should have volume growth momentum coming out of 2013.

So in 2014, you should expect to see increased production from our major projects at Ekofisk South, Jasmine, Britannia Long-Term Compression, Gumusut, Siakap North Petai, Kebabangan, Christina Lake Phase E, Foster Creek Phase F, and the Lower 48 unconventional programs at Eagle Ford, Bakken and Permian.

All these projects helped contribute to our 3-5% production growth as we detailed at our analyst meeting earlier in the year.

And as always, we expect to deliver our operational performance safely and efficiently.

We're committed to maintaining a strong balance sheet that can provide financial flexibility.

We're seeing the early stages of cash margin expansion, which should improve as our volumes grow.

We're focused on improving returns.

And that's a driver behind continuing to rebalance our portfolio and allocate capital prudently.

We're delivering on our value proposition.

We continue to progress our announced asset divestitures.

And this will provide the financial flexibility to fund our investment programs and our dividend, which remains a top priority.

So I hope Jeff and I have given you confidence that our plans are on track for delivering key milestones this year, and positioning ConocoPhillips for an exciting 2014.

And now we're pleased to take your questions.

(Operator Instructions)

Ed Westlake, Credit Suisse.

Congrats on the delivery so far this year against your plan.

In the slides, Jeff, you've outlined $6 billion of incremental cash flow from the production growth between 2013 and 2017 in a flat macro tape which is going to obviously increase your financial flexibility at the top line.

But I've got a question on CapEx.

You're still investing in SAGD and you're still investing in some LNG.

Is there a year as you look out in the CapEx profile where, as you finalize some of those longer-lived assets you get a bit more flexibility in terms of how you could allocate CapEx in the upstream business?

That's certainly going to be the case, Ed.

And really we'll detail this more in December, like we indicated earlier in the call, as far as what 2014 capital will be.

But the effect you're pointing out is probably going to be fairly pronounced in 2014 where APLNG capital will hit a peak, Surmont 2 capital will hit a peak, and we'll be continuing to fund the expansions in the oil sands at Foster Creek and Christina Lake.

And as you go through time, we'll see some of those projects tail off, which will give us more flexibility to handle increased levels of spend in the unconventionals.

Great.

And then in terms of, obviously the longer we go through time, and with Kashagan receipts in, and the balance sheet looking a little bit more robust, and clearly the oil price hasn't collapsed in any way, what are your thoughts about maybe reinstituting a buyback program?

At the end of this year, assuming we continue to progress the rest of our asset sales program we're going to have significant cash balances at the end of the year.

We could be approaching in the neighborhood of $10 billion of cash on our balance sheet.

As we think through 2014 and 2015, we're going to be increasing our cash flow but still at the point where cash from operations is not going to completely cover capital and dividends.

In terms of a buyback, I think that's something we're going to be thinking more about as we get to the point where cash from operations funds capital and dividends on a go-forward basis.

Near term I think we feel like it's important to maintain a significant level of financial flexibility to adequately invest in our capital program and fund our dividend.

Okay.

That's very helpful.

Thanks very much, Jeff.

Doug Terreson, ISI.

Congratulations on your results, everybody.

U.S. production growth has obviously been a major success story for the Company.

And I think output was higher by another 40% this quarter from Eagle Ford, Bakken and Permian, yet it seems like the potential from the Eagle Ford continues to improve as more is known about the Company's position.

So, my first question is whether Matt would agree.

And, second, whether there's any additional color on the position in the Eagle Ford as it relates to activity, efficiency or financial performance that is stronger versus the original expectations?

Meaning, what's really changed here because it seems like you're much more enthusiastic on this position.

Doug, we are still very excited and I would say getting more excited about our Eagle Ford position.

We continue to run a consistent program there for now.

We're running 11 rigs.

Our intention is essentially to continue that.

And we'll continue to see production growth because of that.

What we've indicated is that we've got remaining about 1,800 well locations in the Eagle Ford to drill.

And that's all based on the assumption that we continue to drill at 80-acre spacing.

And we have pilot tests underway to determine if that's the right spacing.

That may ultimately tighten up and there may be more drilling locations.

We're also looking at other levels in the Eagle Ford for potential, too.

So, we're still very excited about the Eagle Ford position and we're going to see significant growth and very high margin growth from the Eagle Ford for several years to come.

Thanks, Matt.

And, second, in Alaska it appears that passage of SB21 will impact activity in the state.

But because you guys are the largest producer and acreage holder it seems that you will be a leading beneficiary.

But at the same time, your portfolio of high-return opportunities is as strong as it's been in several years.

So the question is twofold.

First, how meaningful are the legislative changes as it relates to your desire to invest in the state when you consider the opportunity set that you have elsewhere?

And then second, with ANS trading inexpensively to global markers in recent periods, my question is whether the strategy for sales to new market is changing.

Or, put another way, how is the company thinking about optimizing realizations on future output from Alaska?

Yes.

So, the first part, the SB21, that's now called the More Alaska Production Act.

That was a significant change.

And as a result of that, we will spend more capital in Alaska.

There are opportunities for investment there now, that with the change to the fiscal regime, are competitive in our international portfolio.

So, we will be doing that.

And we've announced a few of those, and I mentioned a few on the call.

So we definitely see potential there.

And, you're right, we're very well-positioned in Alaska as the largest producer there just now.

On the ANS sales, we do have the flexibility if we want to exercise it to take ANS cargoes to Asia.

We do have the right to do that.

And that will depend on the differential that we're seeing to Asian prices versus West Coast prices, obviously.

But it's good to have that flexibility.

And as time evolves, we'll see if that's the flexibility we need to exercise.

Great.

Thanks a lot, everybody.

Paul Sankey, Deutsche Bank.

I don't want to spoil the analyst meeting party too much, but if I could just clarify that the page 13 volume guidance for the full year '13 and Q4, is consistent.

I obviously assume it is with the slide 9 outlook that you have there on the high-quality legacy-based production.

I'm basically trying to get to a 2014-2015 volume number for you guys.

Yes.

As we indicated at the beginning of the year, Paul, that we would be intending to exit the year essentially the same level as we came into the year.

So that growth that you see on slide nine and the exit that we are moving toward in the fourth quarter here, they're both consistent.

Now, there is the complication of exactly what's going to happen in Libya.

That's 50,000 barrels a day of production.

It's not going anywhere.

It's still going to be there to produce, but it's really uncertain as to how that will play out over the next several months.

But, yes, they're both internally consistent, yes.

I would have thought that Libya, thinking about the slide 9 chart, would assumed to be flat.

It was neither declining nor growing.

There was a slight growth, actually, coming in Libya, as we increased our ability to process and sell gas there.

In the overall scheme of things it was between 50,000 and 60,000 barrels a day.

And that, of course, is in the base on slide 9. That's the gray base on the graphic in the top left-hand side of slide 9.

Yes.

Again, I don't want to spoil the party too much for the analyst meeting but what I'm trying to push toward is that this slide 9 outlook is broadly unchanged, even allowing for Libya.

And can be considered to be your outlook for volumes basically.

Just to be precise, Paul, the slide 9 outlook has Libya included in it.

But Libya is just really hard to predict.

And any way you're basically outperforming your expectations, given that you've kept the same number but you've lost Libya basically.

Right?

We've lowered our fourth-quarter numbers to reflect the assumption that Libya will just be off in the fourth quarter.

But we've not changed our go-forward 2013 and beyond numbers, and those all still include Libya.

Yes, I've got you.

Just without wanting to be too pedantic, on page 13, the Libya numbers are just completely excluded from 4Q, because I'm thinking continuing or discontinued.

It's not in either of those, right?

For the fourth quarter, that's right.

So, we show them on that slide, we show them as a light blue color at the top, just to give prospective or scale.

But we're assuming in the guidance that we're giving now for the fourth quarter that Libya won't come back.

It may come back in the fourth quarter but we're assuming for this guidance that it doesn't.

I understand.

I do.

And then, again without front-running the analyst meeting too much, your previous guidance on CapEx going forward I think was about $15.5 billion to $16 billion a year.

Is that correct?

I think what we've been saying is around $16 billion, is basically the guidance we gave at analyst day.

That's the last forward guidance you gave to work on, is annual around $16 billion?

I've got you.

And then just a follow-up would be simply the old question for the [inaudible], which is, why don't you accelerate in the Eagle Ford?

Thanks.

The flexibility exists to do that in the Eagle Ford.

We're focused on a few different things there to establish what the optimum rate of development is.

The first thing is we want to make sure that we are operating efficiently and safely.

So that comes in as an important factor.

We want to move toward pad drilling.

We want to make sure we don't get out in front of infrastructure constraints in the Eagle Ford.

We want to make sure that we're taking advantage of the learning curve, because we're continuing to see learning curve improvements and we want to take advantage of that before we ramp up.

And we want to get results from the many pilot tests we're running in the Eagle Ford, too, so that we're making sure that we're investing the capital as efficiently as we can.

And these opportunities are not going away so we think that our strategy is the right strategy for us in the Eagle Ford.

Paul Cheng, Barclays.

Several quick questions, hopefully.

Jeff, I was looking at your results in the Lower 48.

It looked like your units DD&A sequentially from the second to the third quarter up by about $1.50 per barrel.

Is there any particular reason why that was such a big jump?

I don't know the details of that, Paul.

Generally, as we're bringing on some of these unconventional production, our reserve bookings are still being done on a fairly conservative basis.

So you're finding higher DD&A rates on some of the unconventional properties than we will probably see longer term.

I think that's probably the biggest single driver.

I hear you, but from the first to the second quarter, you also see production increase but your unit DD&A is pretty flat.

You adjust that from the second to third that all of a sudden you jump by $1.50.

So that seems very high.

So maybe that you can have someone to get back to me off-line?

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

Okay.

In your slide, you indicated that Alaska has a negative impact from the lifting.

I presume you have it underneath.

Now can you quantify, how big is that?

Lift timings in general for this quarter were not big factors.

So we didn't highlight them in the earnings release.

The second quarter of Alaska had a favorable impact.

And the third quarter was relatively small.

I believe it would be a negative impact.

It was on the order of $10 million to $15 million in Alaska, with a positive impact in the second quarter.

I know we mentioned that on our second-quarter call, was a much larger number.

And then the company as a whole doesn't have a lot.

Because I looking at your supplemental slide, you indicate that in the third quarter the total company had an over lift of 19,000 barrels per day.

Yes.

That's right, Paul.

In general, the overall company impact from timing was relatively small this quarter.

We had slight negatives in Alaska and some slight positives in other regions.

But none of them were large enough that we felt like it made sense to highlight them this quarter.

And then a final one, I think -- probably for Matt -- Matt, in Permian, it looked like that in the third quarter based on the data that you gave back in would be about 54,000 barrels per day.

Are those all conventional oil production or that some of them is actually already in the tight oil production?

The vast majority is from the conventional production.

It's 4,000 or 5,000 barrels a day of production from the unconventionals just now in the Permian.

We're really in the exploration and appraisal phase in the unconventionals.

So, the vast majority is from our conventional program.

And that program is doing great.

That's a very high return program with lots of running room there.

But in the unconventional we're continuing to evaluate the position that we have, and we're feeling good about that too.

Matt, if you're looking out over the next two or three years, and separate out in Permian between unconventional and the conventional component, what is the growth projection that you expect for both sides?

So we're going to see growth in both.

The rate of growth, obviously, in the unconventionals will be a lot faster because we're starting from a lower base.

But we're going to see significant growth over the next five years on both the conventional and the unconventional.

Any number you can share, say?

Are we talking about over the next five years on the conventional side growing by, say, 50,000 barrels per day, unconventional side growing by, say, 30,000 barrels per day?

Or any kind of number you can share?

Actually, we gave an indication of this, of our expeditions, on the analyst day.

So if you go back to the analyst day presentation, we had a specific slide on our expectations for growth in the conventionals and the unconventionals in the Permian.

And our view hasn't changed since then.

And we'll update our view of that in our next analyst day in April.

But that's a good go by for now, Paul.

Scott Hanold, RBC Capital Markets.

Since we're on this unconventional conversation with the Permian, I just want to delve in a little bit more on that.

When do you all think you'll feel more comfortable with looking at plays like the Niobrara and the Permian, or any of these other unconventional plays you're testing today to actually get to the decision to put more capital and get somewhat of a development program going?

Is that something that is more of a later 2014-2015 event?

Or do we see that sooner than that?

For the Niobrara, for example, we've got one rig running there, we've drilled 11 wells, we've got 5 on production.

And we've got, I think a very well thought through appraisal program that's going to run through the end of 2014.

At the end of 2014 we will really know the scale and the scope of our Niobrara development and that's when we'll make the development decision and what the characteristics of that will be.

The same really applies in the Permian, as well.

We're testing our portfolio there, making sure that we understand which of the different prospective horizons, the Avalon, the Bone Springs, the various Wolfcamp horizons offer the best potential and are the right place to start that development.

So I'd say that's probably on about the same time line.

By the end of '14 we'll have a really good sense of how that's going to develop.

And in both of those we'll give some more guidance at the analyst meeting in April.

Okay.

And are your acreage positions, in each of those plays specifically, large enough for the size of Conoco?

I would say so.

I think we've got 130,000 acres in the Niobrara.

And we've got about 150,000 acres in the Delaware Basin and about 90,000 acres in the Midland Basin.

And with the multiple horizons that exist in those plays, yes, it's a significant position, even for a company of our size.

Okay.

And then one last question, on the concept of Alaska LNG project, that AKLNG, as you all call it, can give me a little more thoughts on what the view is in terms of getting a project?

When could we expect to see the thought of potentially pushing forward with that?

And how that reflects other projects coming on in the global market.

Okay.

The status of AKLNG is that we've selected a concept.

And I spoke about that, as you might remember, Scott, I spoke about that maybe on the last call, the concept that we've selected.

We announced in this quarter the site location that we're favoring for the location of the LNG plant and the Kenai area in south-central Alaska.

We are moving towards the stage of getting into what's called pre-FEED.

So, the early stages of engineering.

And we're in conversations with our co-venturers and with the state of Alaska on the timing of that.

We did quite an extensive summer fieldwork season on the pipeline route.

But it's premature to put any timeline out there as to when first production would be because there's a lot of water to flow under the bridge.

But we are focused on it.

We and the co-venturers and the state are focused on making sure that we fully understand the viability of that project.

So, maybe to ask the question a different way, then, to make this viable what size does this project need to be for you guys?

It's going to be a very large-scale project because of the nature of the resource base there.

And we think it could be a competitive project without other sources of supply, otherwise we wouldn't be pursuing it.

So, it's going to be of a quite significant scale.

It's somewhere between $45 billion and $60 billion of capital, is what we expect it's going to cost.

Doug Leggate, Bank of America Merrill Lynch.

I've got a couple, if I may.

Jeff, on the deferred tax with the startup of Norway, and obviously I'm not quite sure how other major projects have been treated like this, but can you give us some idea as to whether or not you will have a tax shield build in as some of these major projects come onstream?

Not sure I understand your question, Doug.

Let me try and answer and if that's not what you're asking --.

Let me try and help a little bit.

Ekofisk in Norway, you get to uplift your capital that you've spent on the development.

So I'm curious as to know, are you going to be paying cash taxes on some of these?

Which of the projects, and Norway in particular.

And will you see an uptick in your deferred tax line?

I'm just thinking about the cash flow as we move forward.

Yes.

There's a lot of moving pieces on the deferred taxes.

And if you think about how things are treated tax-wise around the world, Norway, you get a relatively quick recovery of your capital.

In the U.K. you get a very quick recovery of capital.

In the Lower 48 where we're spending quite a bit of capital, to the extent you have IDCs we get a quick recovery of capital there, as well.

So what you'll see in this year and what you'll see probably on into next year, and then it gets harder to model as you go on into subsequent years, is that deferred taxes in general you can think of as being a source of cash for us on the cash flow statement.

So far this year it's been about $1 billion source of cash.

Whether it keeps running at exactly the rate we've seen for the last few quarters it's hard to predict.

But certainly it's going to be a positive number.

So, you could consider that a source of cash for both 2013 and 2014.

Thanks.

I'm not sure you're aware of this, about whether you're pure play E&P peers give some guidance on how much is expected to be current and deferred.

I don't know if that's something you might consider, which would be really helpful if you would.

A couple of quick follow-ups, please.

It's related to some of the questions about the Eagle Ford.

But I'd like to turn it to the Bakken, please, Matt.

A number of your peers have talked about resetting their development plans based on Three Forks success and down spacing success.

I'm just curious about, your acreage is right in the heart of where all that stuff's going on.

Just curious as to how you're thinking about that going forward.

Yes.

We are thinking about that, Doug, and we've got some pilot tests underway.

Right now we're developing what's effectively 320-acre spacing.

And we're developing both the Middle Bakken and the Three Forks.

It's quite possible that ultimately we will want to tighten up that spacing, so we have pilot tests underway to try and give us a good sense of what's the optimum spacing and what level of communication exists between the Middle Bakken and the Three Forks for the fracs that we're doing just now.

So, yes, we are pursuing the potential for down spacing in the Bakken.

But no plans to increase the rig count anytime soon, Matt?

No.

I don't think so.

My comments on that are very similar to the Eagle Ford.

I think we are running 11 rigs in the Bakken.

And I think that that's the right level for now.

But one of the beauties of these unconventional plays is that you do have flexibility.

It's just a question of making sure that we are exercising that flexibility at the right time and with the right information.

Thanks.

And just one final one, if I can squeeze it in.

Jeff, like Paul, I don't want to try and front run the analyst day, but I just wanted to pick up on your comments about APLNG and Surmont CapEx peaking.

I just wanted to be clear.

Were you talking specifically about 2014?

Should we be -- directionally can you give us any feel as to how spending should go '14 over '13 and '15 over '14?

And I'll leave it at that.

Thank you.

It's going to be a fairly short period of time from now when we can talk a lot more precisely about that with you.

We are in the middle of wrapping up our capital outlook for next year.

And as Ellen mentioned at the top of the call, we will be back to you with that in fairly early December.

Faisel Khan, Citigroup.

Just looking at the project startups you guys have, Ekofisk, Eldfisk, Gumusut, Jasmine, I'm looking at, I think, it's the page 7 cash margin per barrel, what would you say that these projects collectively have in terms of a cash margin per barrel?

I'm just trying to get a sense of what the margin uplift is going to be.

I know you guys talked about it but these are three or four big projects that could have a material impact to cash flows.

Generally, what we've looked at, when we think about everything that we're adding to our portfolio over between now and 2017, that kind of mix has generally a low 40s cash margin to it.

And it's when you mix that kind of cash margin with what's really a high 20s kind of cash margin for us right now that you get that kind of growth.

I think our views on this really aren't any different than what we had in the analyst presentation where we actually, if you recall we had a chart there that plotted cash margins and production growth.

And it pointed to that same, what I just said, a low 40s type number overall.

Some things like Malaysia, where you get capital recovery for the terms of the PSC in the early parts of the year, you end up with some even higher than that cash margins as you're getting capital recovery.

Okay.

And in terms of Eldfisk and Ekofisk, are those in that same $40 ballpark numbers?

They're probably a bit lower than that because of where the taxes are in Norway.

They are more in the 30s than they are in the 40s.

Okay.

Understood.

And then just in terms of the Eagle Ford, can you give us a little more color on well costs?

I know those numbers have been trending down for you in the last quarter, but can you let us know where you are today and how we could compare that to the rest of the peers in the industry?

We're continuing to see improvements, Faisal across the board in our drilling costs in particular.

We have recently increased the size of our frac jobs.

Starting in September we've increased the size of our frac jobs significantly.

So our completion costs are going up but for good reason.

And what we'll do at the analyst day is we will give you a good breakdown of both how that learning curve has been proceeding and the overall costs at that time.

Okay.

Fair enough.

And then in terms of APLNG, just any update on labor productivity, and how that's trending with both the downstream buildout and, also, any updates on the upstream, any upstream issues or things to note?

Any changes from last time when the costs built up a little bit because of the upstream part of the business?

No, the project is going well.

We are about 50% complete on the upstream part of the project.

About 54% complete on the downstream.

And we're tracking well against the milestones that we have outlined for both the downstream and upstream project.

We are very focused now on getting ready for first production.

So we're staffing up our operating staff for that.

But obviously the project's going well.

Again, in April we'll give an update on the status of that.

But the project's on track and we're pretty happy with the way things are going there.

John Herrlin, Societe Generale.

I've got something for Matt on the unconventionals.

Not to beat a dead horse, we know you have infill potential with the Eagle Ford and the Bakken.

In the past you've talked about thinking in terms of field plateau levels.

Would you rather extend the plateau or increase the rate for the given intervals you expect at peak production for plays like the Bakken and the Eagle Ford?

Or is that still to be determined?

The answer is sort of easy -- both.

I would like to increase the plateau size and increase the duration.

And the opportunity set that exists in our Eagle Ford, Permian and Bakken acreage is going to give us the opportunity to do that.

And that's another thing that we are going to get more guidance on.

But the potential exists to do both in those plays.

Okay.

That's fair.

With some of the newer plays that are in the germinal stages, do you have any acreage retention issues, like in the Permian or Niobrara?

No.

No acreage retention issues that we're not able to manage.

So, no, we're not going to run into any issues of losing acreage that we think has perspective.

That's one of the things that influences how we organize our drilling schedule in these plays.

Okay.

That's fair.

In Canada, with plays like the Duvernay, some of your peers have had pretty high costs.

And I know it's early days.

Are the costs more prohibitive in terms of getting more aggressive up in Canada for unconventionals than the US?

I wouldn't say so, no.

In fact, our development drilling programs and exploration programs in Canada have been reducing costs.

We've actually been seeing quite a bit of capital efficiency there.

So I wouldn't say that we're seeing that sort of pressure at all in the Duvernay or the Montney or the other plays that we're pursuing up there.

Okay.

Last one for me is more oriented toward Jeff, I guess.

You've made some very large chunky asset sales.

In the future should we see more smaller type bite-sized sales rather than large chunky assets?

I think in a portfolio our size you probably expect there will always be a little bit of asset sales that are happening that could be smaller asset sales.

I think the thing that is still out there that we've talked about on previous calls is whether we choose to do something to lower our concentration in oil sands.

And that could be just because of the nature of how large of an asset that is for us.

Even a relatively small change in that could be a fairly significant number.

But other than that, I think the larger asset sales are behind us now and you will see things be smaller.

Roger Read, Wells Fargo.

A lot of stuff's been hit, but melding the Eagle Ford questions with the cash flow questions, I would imagine where you are on your drilling compared to some other companies, you're not cash flow positive in the Eagle Ford.

If that's incorrect, I'd appreciate a correction.

But maybe a timing on when you could be free cash positive.

We are today.

You are free cash flow positive today?

Yes.

We are right above free cash flow positive today.

Okay.

So that's question one.

The other one was, as we look at the decline rate that you highlighted on one of the early charts, I think I calculated it at about 13%, roughly 186,000, I think it was, barrels a day of decline.

What, as you go forward and add some of the big projects that you're adding-- some of the ones obviously that just started up are pretty traditional but thinking maybe more like APLNG and so forth -- do we get a slower decline rate going forward?

And is that part of the production growth uptick we would expect to see, let's say, exit rate for '14 into '16?

Our overall decline rate in our base production is about 10% a year over the next five years.

And as the production mix changes over those years, for example we grow our oil sands and we add APLNG, then the base decline, that would tend to mitigate the underlying base decline.

But on the other hand, we're also growing there by drilling unconventionals, which have a higher overall decline.

So our expectation is that that 10% underlying base decline rate is probably a good go by for the next five years.

Okay.

That was the two things I wanted to hit.

I appreciate it.

Thank you.

Kate Minyard, JPMorgan.

I'd like to go back to the ANS question or the ANS topic, if I could.

You talked about having the option to send ANS volumes over to Asia.

Is that just an option that's there or is it one that you've really diligently explored?

And if I ask it another way, if you look out two years, how likely do you think it is that Alaskan volumes are leaving the US versus remaining domestic?

What would cause us to really focus on that as an option is if we saw ANS oil trade at some significant discount to Brent prices.

Which we saw for a short period of time back when WTI Brent spreads were very wide.

Those, of course, have collapsed quite a bit.

And now ANS is back to trading pretty much flat with Brent prices.

It's an option that we know that's out there.

I can't say that we've thoroughly investigated or tried to make it happen yet.

We know that we could if that were the case.

Whether or not it happens in the next couple of years will depend a lot on where ANS pricing sits relative to other crudes.

And have you guys looked at what the shipping differential is between Asia and the West Coast for ANS?

Or have you not gotten to that point yet?

I think we would have to see that ANS pricing was probably $5 or so below Brent pricing for it to make sense for us to be thinking of doing that.

Okay.

That's helpful.

Thank you very much.

Brandon Mei, Tudor, Pickering, Holt.

Two questions for me.

The first one is on, I just wanted to get your thoughts on AECO pricing in Canada moving forward here in the next year or so.

It's hard to tell.

It's going to remain, likely to remain weak.

But it might be, Brandon, that your assessment of that is as good as our assessment.

Okay.

And second question is on the Venezuela ruling.

What are the next steps in that process?

And then how should we think about the timing and the amount of the award?

Because I think that the amount at the time of expropriation, the PV10 was around $10 billion.

I don't think we can comment on any expectations of amounts.

But just as far as process goes, we've had the initial award which sets out some of the parameters upon which the award is going to be -- the financial award is going to be calculated.

We now are moving into the more detailed assessment of what exactly what that award is.

And that's going to be a process that will take a couple years to evolve.

And that's just something where we're going to continue to update as we can.

But it's a process that we continue to work through.

Blake Fernandez, Howard Weil.

Folks, sorry to prompt in late in the call.

I'll just limit it to one question.

I was just curious where you think we are in the life cycle of developing technology to economically develop the Lower Tertiary.

When I look at your portfolio you've got several discoveries.

You're drilling the appraisal well at Tiber.

And in talking with peers, such as BP, developing 20K and whatnot, it seems like the technology isn't quite there just yet.

What kind of confidence do you have that we are going to get there?

And when do you think we can reasonably expect production from the play?

Thanks.

As I'm sure you know, Blake, not all of the Lower Tertiary is at the same pressure and the same depth.

But you're right, there are several parts of the Lower Tertiary are going to require 20K trees.

And the development of those trees is underway, and that will come over the next few years.

From our own discoveries so far, I don't expect we'll see production from the Lower Tertiary discoveries hitting us until the late part of this decade.

But the development work that this requires to make sure that we have the technology in place, that's all in hand.

Developing 20K trees isn't like putting a man on the moon.

We know how trees work, it's a question of just making sure that we're building them and getting them certified in a way that we're confident on their deployment.

But we will certainly get that done.

Okay.

Thank you very much.

We have no further questions.

I will now turn it back to Ellen DeSanctis.

I have no further comments either.

Just appreciate all your time and attention.

You're welcome to call us for any follow-ups.

And again, thanks for your participation.

Enjoy the rest of the day.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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