康菲 (COP) 2014 Q3 法說會逐字稿

Welcome to the third-quarter 2014 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, and thanks to all of our listeners for joining us today.

With me in the room are Ryan Lance, our Chairman and CEO, Jeff Sheets, our EVP of Finance and our Chief Financial Officer, and Matt Fox, our EVP of Exploration and Production.

A couple quick administrative matters.

Of course, we'll make some forward-looking statements this morning, the risks in our future performance are described on page 2 in today's presentation, also in our periodic filings with the SEC.

All this information, as well as our GAAP to non-GAAP reconciliations and our supplemental data, can be found on our website.

And finally, I just wanted to mention that we announced this morning that ConocoPhillips will be hosting an analyst meeting on April 8 in 2015, so hope you'll save the date for that.

We'll of course provide some additional details very shortly, and with that I'm going to turn the call over to Ryan.

Thank you, Ellen, and thanks to all our listeners for your participation this morning.

I'll begin our call this morning with some remarks about the current environment.

Let me just say that while the recent oil price downturn seems sudden, we are well-positioned as a company to respond without impacting our strategic objectives of 3% to 5% volume and margin growth.

This is key, and it's the result of a significant repositioning we've achieved as a company in the past two years.

We've cored up the portfolio, lowered the overall cost of supply, and significantly increased our degree of capital flexibility.

And to put this last point in a bit of perspective, in 2014, our committed capital from major projects and maintenance represents about 50% of our capital, and this declines to approximately 30% by 2016.

I'll come back and highlight that again in a couple of minutes.

Another thing we want to emphasize is that events like the recent price downturn underscore the importance of staying focused on the fundamentals.

We know this is a cyclical business and we've been here before, and certainly the old adages apply: full-cycle low-cost wins, asset quality matters, and financial strength is an asset.

We intend to make prudent adjustments at this time, while continuing to monitor the environment.

So please turn to the next slide, and I'll outline the reasons why we believe we are in a unique position today.

This slide summarizes what we want you to take away from our comments today.

The headline and the chart on the right really say it all.

We have the flexibility and the resiliency to weather lower prices, and we'll exercise that flexibility as appropriate.

Importantly, at this time, we do not see any major impediment to our ability to deliver on our stated goals for the next few years, and those are 3% to 5% volume and margin growth with a competitive dividend.

We still believe this is a winning formula for our shareholders, and we have a plan to deliver it.

We have momentum in our volume growth due to the start-up of several major projects this year, in places like Europe, Malaysia, the oil sands, and APLNG, and we have stated growth coming from our North American unconventionals.

And it goes without saying, we will continue to stay focused on margins and returns.

On a price normalized basis, we expect to achieve our margin targets.

This is driven by growing liquids production in areas with favorable fiscals.

In addition, the major project startups in 2015 will generate steady cash flows for years to come.

Importantly, at current commodity prices our capital investments generate attractive returns.

And in the unconventionals, we have a multi-year inventory of projects that have a cost of supply that is lower than the prices we are seeing today.

So we are well positioned to adjust to the current environment without affecting our overall performance targets, and here's the key reasons why.

During the past few years, we spent a significant amount of capital on the major projects that I just mentioned.

In fact, 2014 was the peak year of capital spending at Surmont and APLNG.

So beginning in 2015, capital in our major projects begins to taper off.

As shown on the right-hand chart, with growing development capital spend, we have significantly more flexibility to ramp up or down our capital as circumstances dictate.

This is flexibility we have not had for many years, but is what we set out to create when we established the independent ConocoPhillips over two years ago.

As we think about capital levels going into 2015, we first consider all of our priorities for investment.

As we have said, consistency -- consistently since the spin, our top priority is the dividend.

This is an important part of our investment thesis: the dividend provides discipline in our capital allocation process, and we believe it is important in a mature business.

So, no change to the outlook on the dividend.

The next consideration is affordability of capital and cash flow neutrality.

Since the spin, we have been consistent about targeting late 2016 to 2017 for cash flow neutrality, and achieving cash flow neutrality is still a priority.

We are currently in the process of setting our 2015 capital budget and will announce that later in December.

What you should expect is that we will increase -- we will exercise the flexibility we have, and announce a range of capital spending that is not only lower than 2015, but lower than our stated target of $16 billion per year.

Across the Lower 48, we can throttle back on our less mature unconventional plays, while continuing to invest in our highest margin, short cash cycle projects in the Eagle Ford and the Bakken.

These are the best returns in our portfolio, and give us the confidence that we need to meet our volume target of 3% to 5%, even with a bit lower capital next year.

Finally, we have a very healthy balance sheet, including cash on hand.

We think of our financial strength as a competitive advantage.

So in summary, we are well positioned for the current environment.

We're coming out of a significant transformation as a company, at a time when asset quality, capital flexibility, and financial strength matter.

We're going to act prudently, but our plan is on track, we are focused on executing that plan, and we don't anticipate any significant change to delivering our stated goals to our shareholders.

Hopefully, these opening comments can provide a bit of insight and context to how we are thinking about the current environment; but so now back to our regularly scheduled program, stepping through the quarterly results.

So please turn to the next slide, here's a summary of our overall achievements for the third quarter.

Of course, this is our company level said/did chart that we show every quarter.

I won't cover all the points here in detail, I'll leave that for both Jeff and Matt, but the key takeaway here is the business is on track.

We delivered our targeted volume and margin growth for the quarter, we increased our dividend to the shareholders, and we exited the quarter in a very strong financial position with almost $6 billion of cash and short-term investments on hand.

So now let me turn the call over to Jeff and Matt, and they'll go over the results of the quarter in a bit more detail, and I'll come back at the end of the call with some concluding remarks and field your questions.

Thanks, Ryan.

My comments this morning will be brief, reflecting the straightforward nature of our third-quarter results.

Slide 7 presents our adjusted earnings.

Sequentially and year-over-year, adjusted earnings reflect lower commodity prices.

However, we saw strong operational performance this quarter, and we successfully executed several major turnarounds.

Volumes reflected a dip sequentially for these planned maintenance activities.

Third-quarter adjusted earnings were $1.6 billion or $1.29 a share.

Segment breakdown of those earnings is shown on the lower right of this chart and further segment details can be found in the supplemental data, which is available on our website.

If you turn to slide 8, I'll quickly summarize our production results for the quarter.

As you know, our convention for production is continuing operations, excluding Libya.

On this basis, our third-quarter volumes averaged 1.473 million BOE per day, which is slightly above the midpoint of our guidance.

We anticipated a significant level of turnaround activity in the third quarter.

As you can see, we had 37,000 BOE per day of additional downtime compared to last year, with 35 of that coming from our planned maintenance work.

Normalizing for those impacts, we achieved 62,000 BOE per day of underlying growth.

This represents a 4% increase year-over-year, and keeps us on track to deliver our 3% to 5% growth in 2014.

On the same basis, this represents a 7% liquids growth year-over-year.

This high-value liquids increase is really making a difference in our margin, which I'll cover on the next slide.

This is our typical slide showing year-over-year sequential cash margins, the left chart reflects margins at actual prices during the period and the right chart is price normalized.

On a price normalized basis, third-quarter margins improved 8% year-over-year.

Of that growth, about 2% is from FX-related tax items and reduced Libya volumes.

So underlying cash margin growth was about 6%, and this despite higher costs associated with the significant turnaround activity in the quarter.

This metric will be volatile on a quarter-by-quarter basis, but like our volume target, we are on track to achieve our 3% to 5% growth target for margins for the year.

And finally, I will review our year-to-date cash flow waterfall on the next slide.

Again this is straightforward, we began the year with $6.5 billion in cash and short-term investments.

Year-to-date, we generated $12.5 billion of cash from operating activities, and added $1.3 billion from the FCCL distribution earlier this year.

Over this period, we've had about a $200 million improvement in working capital, and added $1 billion of net proceeds from dispositions.

Year-to-date, we have funded a $12.7 billion capital program, with $4.6 billion of those expenditures coming in the third quarter.

The third quarter will be the peak capital spending quarter for 2014, and we are still on track for the $16.7 billion of capital for 2014 that we announced in December last year.

After funding our capital program and dividend, we ended the quarter with $5.8 billion in cash and short-term investments.

As a reminder, we need about $1 billion to run our business, so the remainder will be available to fund our capital programs.

This concludes the review of our financial performance.

Now I'll turn the call over to Matt for an update on operations.

Thanks, Jeff.

The key operational message is that execution is on track across our global portfolio.

It was a very busy quarter for turnarounds in our base operations, and we completed these activities on schedule and on budget.

We also achieved some important milestones and startups in our major projects, continued to deliver strong performance from our North American unconventionals, and progressed our exploration activities, including the discovery of a new oil play, offshore Senegal.

So let's jump into a review of our segment performance, starting with the Lower 48 and Canada on slide 12.

In the Lower 48, third-quarter production averaged 343,000 BOE per day.

That's a 9% overall increase from the third quarter of last year, and represents a 25% increase in crude oil production over the same period.

Leading this growth were our liquids-rich Eagle Ford and Bakken assets, which averaged a combined 212,000 BOE per day, a 33% increase from the third quarter last year.

Sequentially, Eagle Ford production is relatively flat, in line with our guidance.

As you recall last quarter, we indicated growth would be flatter through the end of the year, as we continue to shift to pad drilling and bring new wells online in batches.

We remain on track for continued growth into 2015 and beyond.

The Eagle Ford averaged 157,000 BOE per day in the third quarter.

This represents a 31,000 BOE per day or a 25% increase from the same quarter last year.

We continue to execute and evaluate pilot tests in the Eagle Ford, including single horizontal well tests in the upper Eagle Ford.

These tests have been encouraging, and we'll soon begin testing a three-layer development concept by placing a layer of wells in the upper Eagle Ford and two layers of wells in the lower Eagle Ford.

The wells will be drilled 660 feet apart in each layer.

We call this an 80-acre triple stack.

The Bakken averaged 55,000 BOE per day over the quarter, up 21,000 BOE per day from the third quarter last year, a 62% increase.

We continue to pilot test 160-acre downspacing in the Bakken.

But based on the results we've seen to date, it's too early to make a decision about our ultimate spacing there.

We've also made good progress on our Permian and Niobrara appraisal activities in 2014.

In the Permian, we're currently focused on appraising the multiple stacked horizons in the Delaware Basin, and then in the Niobrara, we're testing several alternative well configurations and completion techniques.

In both areas, we continue to see encouraging results.

Before I leave the unconventionals, I want to highlight the chart on the bottom left.

This chart represents third-party data that shows ConocoPhillips has the lowest cost of supply unconventional portfolio, compared to our peers.

This means we're the best positioned to withstand lower prices, and remember that not all unconventionals are created equal, and being in the sweet spot matters now more than ever.

We'll provide a more complete update on our unconventional reservoir appraisal and pilot test activities at our Analyst Meeting next year.

In addition to our unconventional activities in the Lower 48, we continue to be active in the deepwater Gulf of Mexico.

After further evaluation at Coronado, we have decided not to continue with appraisal of that discovery, and we took our initial wildcat costs to dry hole this quarter.

However, we continue to be very active this year appraising our three significant discoveries at Shenandoah, Tiber and Gila.

So, stay tuned for more information on those.

In addition, we have a rig coming in early 2015 that will allow us to start evaluating our operated portfolio.

So our Lower 48 segment continues to deliver strong performance.

Our Canadian business also performed well during the quarter.

We produced 276,000 BOE per day, which includes a 9% increase in liquids production year-over-year.

At Surmont 1, we completed a significant turnaround, and are now back at full production rates as planned.

Foster Creek F achieved first production in September and is expected to ramp up over the next 12 to 18 months.

Our major project at Surmont 2 is making good progress, and remains on schedule for first steam in mid-2015.

This is an important, large-scale oil sands project that will provide steady production and cash flow in the future.

The chart on the bottom right shows the steam-oil ratios for several oil sands projects.

Our three projects, Surmont, Christina Lake and Foster Creek had the lowest SORs compared to our competitors last year.

Low SORs are the key to low-cost of supply, and just like the unconventionals it really matters to be in the best geology in the oil sands.

On the exploration front, we're continuing to explore and appraise our unconventional plays with some very encouraging results from the Montney and Duvernay.

Again, we expect to provide more detail at the Analyst Meeting.

Next, I'll cover Alaska and Europe segments on slide 13.

Alaska average production was 155,000 BOE per day, reflecting higher planned maintenance downtime at Prudhoe Bay.

At CD5, the Alpine central facilities tie-in work is progressing on schedule.

The project is more than 50% complete and on track for startup in late 2015.

We've sanctioned the Drill Site 2S project, and assuming acceptable federal permits, we plan to sanction the Greater Mooses Tooth project in the first quarter of 2015.

We are also progressing the 1H NEWS project, this is the third new project we've initiated since the passage of the More Alaska Production Act.

And in addition to the progress on these projects, we've also signed a contract to build a new rotary drilling rig for Kuparak.

We're also making progress on the Alaska LNG project.

We have FERC approval to start the pre-file process for the project.

This milestone sets the stage for the environmental review required for the siting, design, and construction permitting of the project.

An export application has also been filed with the DOE and the federal register.

So we are making progress on the preliminary work to move this project forward.

Moving on to Europe, third-quarter production averaged 194,000 BOE per day.

This is up 10% year-over-year, reflecting new production from the startups at Jasmine, the new East Irish Sea facility, and Ekofisk South, partly offset by normal field decline.

The Britannia Long-Term Compression Project started up in the third quarter, and Eldfisk II hook up and commissioning activities continue on schedule for early 2015 startup.

Now let's review our Asia Pacific and Middle East segments, and Other International segment on slide 14.

In the APME segment, we produced 301,000 BOE per day in the third quarter.

This reflects major turnaround work at Bayu-Undan and Darwin LNG.

At Bayu-Undan, we also initiated Phase 3 drilling during the quarter.

We were pleased to report that Gumusut achieved first production in early October.

The new floating production system is running well and we expect to ramp up production in this high-margin field over the next few months.

This project is one of the key drivers of production and margin growth going into 2015.

The KBB project is ready for startup.

We expect first gas in November, but our rate will be significantly constrained, pending repairs on a third-party pipeline.

We expect to be at full rate in this project by mid-2015.

On a combined downstream and upstream basis, the APLNG project is now about 84% complete and remains on schedule for a mid-2015 startup.

This is another project that will provide stable production and cash flow for many years to come.

In exploration, we spudded the Barossa-3 well in October and completed the second phase of our appraisal program in the Greater Poseidon Area.

These fields represent possible options for Darwin LNG backfill in the future.

In our Other International segment, we announced that oil was discovered in Cretaceous sandstones offshore Senegal with our FAN-1 well.

We're encouraged by the presence of a working petroleum system in this frontier basin, and we are now evaluating further work to enhance our understanding of the play and its commerciality.

We are currently drilling an additional well, SNE-1, testing a different play in the area.

This is the second of a two well commitment on this block.

By the way, if Senegal advances as a development project, ConocoPhillips has the option to take over operatorship, so more to come on Senegal.

We continued drilling our Kamoxi well in Block 36 in Angola, and we expect to have some initial results in this well soon.

In Poland, we are continuing to test the Lublewo well after a large fracture stimulation.

As you know, we were exploring for gas, but the results of the well indicate that we are in a more liquids-rich window.

We are studying the data and evaluating next steps, and we'll update the market once our evaluation is complete.

In Colombia, we recently spudded the Picoplata well in the La Luna Shale trend.

Finally, the Es Sider Terminal in Libya opened in late August.

We completed our first lift in early September and had two additional liftings this month.

We are currently producing about 25,000 BOE per day net.

We continue to monitor the situation in Libya, but it will remain out of our production guidance, given the ongoing uncertainty.

I'll wrap up my prepared remarks with the volume outlook on slide 15.

This is our typical chart of quarterly volume guidance for continuing operations, excluding Libya.

The first three quarters represent actuals.

We expect a significant ramp up in volumes going from the third quarter to the fourth quarter.

Key drivers of this production increase are the completion of our major turnaround season, and ramp up of Gumusut and Britannia Long-Term Compression.

We now expect fourth-quarter volumes to be in the range of 1,545 to 1,575 thousand BOE per day, which is lower than the previous guidance for the quarter, but still achieves the full-year targets we laid out earlier in the year.

The fourth quarter adjustments reflect three main drivers.

First, we don't expect to be providing ramp gas to a third-party LNG project in Australia during the quarter.

This was always viewed as a short-term production option.

Second, as mentioned earlier, we expect a delay of full ramp up at KBB due to third-party pipeline repairs.

And finally, at current prices we expect to reject ethane in our San Juan Basin operations.

This is strictly a value play; what we give up on rate, we'll gain on margins.

Despite these changes to the fourth-quarter expectations, we've had a very strong year, and we are on track to grow production by 4% compared to 2013.

Again, this is exactly in line with the guidance we provided at the start of the year.

And we are well positioned to deliver our longer-term growth targets with strong momentum going into 2015.

This momentum comes from a continued ramp from recent startups at FCCL, Malaysia, the UK, and Norway, and ongoing strong production from our unconventionals.

In addition, in 2015 we've growth coming from major project startups at Eldfisk II, APLNG, Surmont 2, and Foster Creek Phase G.

The bottom line is, we continue to execute safely and efficiently, and we are well positioned to deliver our strategic objectives.

We look forward to providing an operational update at our Analyst Meeting in April.

Now, I'll turn the call back to Ryan for closing remarks.

Thank you, Matt.

So let me recap a bit of what you've heard today.

First, we are on track to deliver our goals of 3% to 5% volume and margin growth, with an attractive dividend, and we are well positioned for the current price environment.

We are laser focused on executing our plans, while using our capital flexibility to respond to short-term factors.

We have good production momentum going into 2015, and we'll expect to announce the 2015 capital program that reflects the priority on achieving cash flow neutrality, without impacting our ability to deliver on our growth targets.

So we are following the plan and the path we laid out two years ago, and it's working.

As Matt said, we look forward to providing you a more detailed company update at our Analyst Meeting in April.

So with that, let me turn it over to everyone on the phone, and back to the operator for some Q&A.

(Operator Instructions)

Edward Westlake, Credit Suisse.

Yes.

So I think if I heard you correctly, obviously oil prices have been lower, you've said similar volume outlook for less CapEx.

Obviously correct me if I misheard that, but I was just wondering how much, when you look at the overall program going forward of that saving on CapEx, is well performance, shale outperforming to enable you to hit your growth for lower amounts of dollar spend?

How much is deferral -- you mentioned deffering some early phase shale, it would be interesting to know how much you spend on that in 2014, and how much is perhaps cost reduction?

Yes.

Thanks Ed.

Mostly our thinking right now, it's mostly I would say deferral from the less mature of the unconventional plays that we have in the portfolio.

Again, we are focused on our low cost of supply that we have in the Eagle Ford, the core areas that we're drilling in the Eagle Ford, the Bakken, those are going to remain a big part of what we're doing going forward, but it is a deferral out of some of those less mature plays.

What we don't know going into the year is how the costs are going to develop.

Is this -- depending on your view or how bullish or bearish you are on commodity prices over the next couple of years, what I don't know is how much scope we are going to get done for the capital that we've said, that's something that we're going to watch pretty closely as -- depending on where the prices level out and how long it stays there, what that cost structure's going to look like.

Things will correct if it stays at $80, we know that.

And then a question on APLNG: obviously you're saying first production around the middle of next year.

When do you reckon you would get the first commercial cargo in terms of us starting to model the cash flow contribution from that project?

Obviously we still hear about delays with the main contractors out in the Queensland gas area.

And then any comments on this reversion reclaim by Tristar?

Will that disrupt your ability to hit those goals?

So Ed, we'd expect the first cargo would be sometime late in the third quarter or early in the fourth quarter from APLNG.

And we are on track to deliver that.

We don't think that our production or our resource position is going to be influenced by this Tristar issue.

Yes.

I'm just -- I'm not as familiar with Aussie law, but if they win and secure an access to the project, would you need to buy third-party gas from others, or presumably you could buy from them?

I just don't know how sunk costs would be treated?

So we don't anticipate that that's going to be an issue Ed.

We don't think that that claim has merit.

Okay.

Thank you.

Thanks Ed.

Doug Terreson, ISI.

Good morning everybody.

Good morning Doug.

Ryan, it seems like based on your comments and I think the way that you answered Ed's question, that you are probably going to be as focused as ever on your capital expenditure and your operating cost control in the current budgeting round at least as much as ever.

But the second part was about sustainable cost opportunities, what was your point that it wasn't clear how significant they were and also where they might be, whether or not they are in the supply chain or the whole service areas or what have you?

And so I guess the question is first kind of a clarification on that point, and also are you doing anything different in the current budgeting round to try and locate some of these cost opportunities and possibly capture them?

Yes.

Thanks Doug.

No.

We sent our procurement group out to scour the world in terms of making sure that we are getting the best deal we can for all those services that we are providing.

My comment is related to last -- the last downturn we saw in this business, the cost came down a fair amount as well.

They've risen over the last 4 years to 5 years, but if we stay at this $80-ish world for a year or two, then we would expect some of the costs to start coming down and we're trying to capture those as fast and as quickly as we can.

So again, a lot of our contracts, whether they're drilling rig or pumping services, they're relatively short term so the reductions that should come, we ought to be able to capture them very quickly and that's our intention, but yes.

We're laser focused on both the capital that we are spending to make sure we get as much scope as we can out of it and the cost that we're spending across the whole enterprise.

Okay.

I understand.

And then also on Venezuela, you filed for arbitration recently.

So just wanted to see if we could get an update on the next steps there, the timing, and how you're thinking about that situation.

Yes.

So we have two sets of arbitration that are going on.

The recent arbitration that we filed is a contractual arbitration relative to the joint operating agreements we had for both the Hamaca and the Petrozuata projects in the Orinoco belt, and so that's different and separate from the arbitration that we filed a few years back that's working its way through the system.

So that -- the phase of that arbitration is we are both submitting our damages claim to the tribunal.

Both ConocoPhillips and the Venezuelans, are submitting that to the tribunal and the tribunal will rule on the amount of the damages.

This contractual arbitration is something distinct and separate from that that will progress through the courts just like the other arbitration has.

Okay.

Thanks a lot everybody.

Thanks Doug.

Scott Hanold, RBC Capital Markets.

Great.

Thanks.

If I may kind of go into the CapEx sort of discussion again.

When you look at -- obviously a lower price oil environment and moderating spending a little bit to bring more of that balance.

How many -- I guess years of that could you do before -- when you look into 2017 and beyond, that becomes more of a question whether or not you can support that 3% to 5% growth beyond that period.

Yes.

You know, that's exactly what we're looking -- we have a lot of flexibility in the portfolio so we can -- we've created that over the last couple of years as these major projects have ramped down and we are spending more on the development drilling side so we can ramp that down or ramp that up based on the market that we see.

And to your point, if we stay at the lower capital levels than what we've described since the spin, and we do that for a prolonged period, two or three years, it starts to potentially impact some of the growth.

But that occurs well beyond 2017.

So that's why we have a range of 3% to 5% production growth.

We'll monitor the market, we'll watch it and make sure we do the right thing for the company and the shareholders and -- but the impact would be longer-term.

So what we're doing now with the major projects rolling off the production that we are delivering, is why we've got confidence between now and 2017 and the plans that we've laid out that we'll deliver on the 3% to 5% volume growth.

So when -- you made a comment on some of the more new venture type of unconventionals could take a bit of a backseat for now.

Where does exploration sort of rank on that sort of pecking order list?

Well, it's at a similar bucket as the less mature unconventionals, because that's investments we are making today for the long-term growth and development of the company.

So yes.

We look at our commitments that we have on the exploration side and some of the new opportunities that might present themselves.

We're taking a bit of a pause and slowing some of that down, as well.

Okay.

Thanks, and then if I could quickly ask on the Coronado, can you give us a little bit of color on your thoughts on -- I guess it doesn't look like you guys are going to participate or be involved in any activity there anymore.

Can you give a little color on that?

Yes.

I mean the original discovery well was very encouraging but the first appraisal well that we drilled was intended to establish what the overall size was and it was disappointing.

So rather than continue to appraise that we feel as if we'd be better to direct our exploration and appraisal dollars elsewhere, so that's why we decided not to continue pursuing Coronado.

But it doesn't have any implications for our overall deepwater Gulf of Mexico exploration program.

We've got very strong position there; over 2 million net acres that we like a lot.

We've got the three big discoveries already that we're appraising.

And so, that doesn't have any long-term implications for our Gulf of Mexico exploration program.

Okay.

Thank you.

Guy Baber, Simmons.

Thanks for taking my questions.

The overall production this year you expect to basically come in line with your expectations, and we can see the growth projects expected to come on the next few years which are significant, as well as the uplift you'll get from the US unconventional piece, but my question is around your underlying and more mature base of production.

How have you felt about that base this year?

How it's performed: Are there any trends you would highlight or areas where you have seen improvement or you see potential for improvement going forward?

Just trying to get a better sense of how base production might evolve over the next couple of years and how -- and what you're seeing on that front.

No.

Base performance is virtually identical to what we thought it would be.

We have good predictive capability on all of our major legacy assets and we understand the decline on our base projects.

So, there are no surprises at all across the portfolio in our base production.

Okay.

Great.

And then upstream results in Canada have been especially impressive this year.

Especially in light of where some of that profitability has been the last couple of years, despite relatively consistent pricing and production, so I was just hoping you could comment a bit more, in a little bit more detail on the evolving profitability of that business unit.

Have you made significant strides there in improving the underlying cost structure and the profitability of that business?

Just wanting to better understand that strength and the sustainability of that going forward.

I think that's probably more of a factor of just market conditions that we've seen in different quarters.

The third quarter was a pretty strong quarter for us for bitumen realizations, seasonal blending requirements, diluent prices.

All those things worked pretty well in the third quarter.

So we had strong bitumen realizations, I think you saw marker prices go down by $6 or so quarter-to-quarter.

But you saw bitumen prices only go down by maybe half of that, and a lot of that has to do with all of the things that go into bitumen realizations.

And the other thing that's helping the business is we're operating extremely well; the operating efficiency in our oil sands asset is tremendous.

Surmont, for example, is producing consistently well above the design capacity.

Our Western Canada business unit had a tremendous focus on cost management and capital efficiency for the development programs, so we are executing well.

And we have -- as well as seen some benefit from the WCS sort of differentials.

Thanks for the comments.

Thanks Guy.

Doug Leggate, Bank of America Merrill Lynch.

Thank you, everybody.

Hi.

Good afternoon.

Hello.

Ryan, I wondered if I could try one for you and then one to Matt.

And to you I'm really just curious on your perspective on what's happened to the commodity here.

And I know it's a big picture question, but one of the hangovers of being a big oil company is longer-term planning.

So I'm not expecting Conoco to have any knee-jerk reactions, but I just wondered if you could give us your perspectives?

And specifically around Libya, given that you are an operating company there, how sustainable you think Libya is?

And then I've got a follow-up, more specifically on the assets.

Thanks.

Yes.

Thanks Doug -- on the macro picture, probably a lot of what you hear, surprising how quickly the Libyans came back from zero to what we're seeing today, 600,000, 700,000 barrels a day gross production.

But we don't have any people on the ground in Libya, but we do have some national employees that are a part of our company that are there in Tripoli and the situation is very tenuous.

The one faction that took over the NOC offices, and in fact bombed the NOC offices in Tripoli, so I think the whole Libya thing is hanging on right now.

There is tenuous supply out there that I think is a bit at risk, which we'll have to just see over the course of the next few months.

But I think the demand side has been a little bit surprising out of some of the non-OECD countries in the Far East, and, obviously, China, trying to figure out how much -- where their demand is going to come out and how much of the growth is happening in the country.

So definitely a well-supplied market right now, and we can all speculate what the Saudis are going to go do.

But I think they're a little upset with some of their customer base being taken away by some of the other countries.

So it is a bit of a mixed bag of things that are out there.

But I think for us it's a global diversified company.

That's what we're trying to do.

We run scenarios.

We think about -- we don't think about point estimates and oil price around different scenarios, and we try to anticipate what we would do in capital investment, what the company, the portfolio would look like under these various scenarios, so I think we are well-positioned for where we find the market today.

I appreciate that.

I guess my other question is to Matt.

It really bridges between the discretionary spending in the portfolio, Matt, relative to, obviously, the very competitive economics you have had.

So, what I am looking at is 15% of your spending budget was laid out as exploration or defined as exploration, which would have no impact on the short-term production.

So as you look at a lower price environment and you think about the plan, not to get into too many specifics, because you haven't given us a number yet, obviously, but how do you think about where you would cut capital first and what the -- if there was an area in the Lower 48 portfolio that might be challenged in the current environment where -- how you would you rank worst through best, if you like?

So this, it's really an opportunity to exercise flexibility.

And where we would anticipate that we would ramp more slowly than the previous plans would be in our less mature plays.

So we don't need to ramp as quickly in the Permian as we had previously thought.

So we could take some scope there.

And the same applies to the Niobrara and to some of our plays in Western Canada.

So those are the primary areas where we can take a look at some flexibility without having any significant impact on our rate between now and 2017.

So those are the main areas.

We'll also choke back a little bit in exploration, but we are still committed to exploration as an engine for organic growth for the company in the long-term.

So we need to be balancing a long-term view of the company's growth potential with the short-term conditions that we find ourselves in.

Is it fair to describe, Matt, $2 billion of exploration, I mean that's a big cushion.

Would that be the first place if things got worse, let's assume, is that the first place you would look to cut while maintaining rate?

I'm just trying to understand this -- it just seems you got a lot more flexibility than some of your peers and I'll leave it there.

Yes.

I mean that's one of the areas we would look.

But as I said, I mean, it's a balancing act for the short-term and the long-term.

We've got a lot of flexibility in our Lower 48 and Canada portfolio, to manage our capital over this period without having a big impact on growth, so we are certainly not going to gut our exploration program.

We need to maintain exploration for the long-term organic growth of the company and we're going to do that

Very clear.

Thanks fellas.

John Herrlin, Societe Generale.

Yes.

Thanks.

I've got some quick ones for Matt.

Can you say anything else about the well in Angola, the pre-salt well?

Were you seeing anything on the way down because you're going to TD that soon, and then also with Poland, can you talk at all about the test results in the shale?

It's too early to say anything about the Kamoxi well, John.

I mean, we expect to have that done sometime in the next couple of weeks.

And we'll make some announcement once we've actually got some results to talk about, it's too early, really, to talk about that.

On the Poland well, yes, we have had some tests in Poland in a more downdip location than this well that were gas wells, and we drilled this well in this location anticipating we'd find the same fluids and we essentially found what's really an oil well.

So, we're scratching our head a bit to understand what's going on, there's some sort of thermal maturity change that we were not anticipating and we are at the stage of essentially conducting a long-term flow test, doing some pressure buildups.

And then we'll have a better understanding of what the implications of this are in the next few months.

Okay.

Great.

Thanks Matt and then one other one for me.

Given the fact that we've had prices breakdown, ultimately there may be more properties available in the market for the companies that don't go public.

Will you at all look to supplement your acreage positions in the unconventional plays by buying additional assets or acreage, be opportunistic?

Yes.

We're out there -- screening land all the time in both North America and internationally, so if opportunities come up that would meet with our portfolio well and at a decent price early in the lifecycle.

Then we would be ready to take advantage of that if those opportunities came up.

I think the early in the lifecycle comment that Matt made is key there.

Because we do have a lot of organic growth opportunities in the existing portfolio that we are funding currently.

Okay.

Thanks Jeff.

Thanks John.

Paul Cheng, Barclays.

Hello.

Good afternoon.

Hello Paul.

Maybe this is for Matt or for Ryan.

First question, from a portfolio management standpoint, if we're looking at today Bakken, Eagle Ford and SAGD account for 20%, 22% 23% of your production.

So from a portfolio management standpoint, Matt and Ryan, is there a level that you feel uncomfortable in saying that, okay, this is too much concentration?

Or then what is the desirable optimum percentage of your asset mix should be in the North American onshore unconventional oil portfolio?

Yes.

I guess, Paul, that kind of thinking about it -- along those lines or trying to get an optimum sort of percentage.

I'll take low cost of supply, which the Bakken and the Eagle Ford represent, and then balance that with the SAGD, which is these longer-term 40-year, 50-year projects that provide an incredible base amount of cash flow with high-margin productions.

They're a little bit different, so really not targeting a percentage, just making sure they fit the returns profile and they're competitive with the rest of the investments we have -- the opportunities we have in the portfolio, and they do compete.

And obviously Bakken and Eagle Ford are at a very low cost of supply, very high returns.

So from that standpoint I mean risks come also with opportunity.

And so, if indeed that commodity price let's say, stay at this $80 or even lower for one year or two years, will you be willing then to use your balance sheet or perhaps to stretch your balance sheet to make some acquisition, to even further beef up what you consider that maybe is an advantage position to be even bigger?

(multiple speakers)

Or that you would be too concerned about the balance sheet and that's not something that you would like to do?

You know, that really just depends on the quality of the opportunity that we see out there, as we've talked about before, we do have balance sheet capacity.

We ended up the quarter with $6 billion in cash.

We are going to use some of that as we go through just funding our programming until we get to the point of cash flow neutrality.

But as Matt said, we are always going out there looking for opportunities.

If they make sense, we shouldn't be afraid to use our balance sheet.

But we do have a pretty strong inventory of existing opportunities in the portfolio today.

Two final quick ones.

One, Matt, any rough range you can provide for 2015 production?

And second, for Ryan, it looked like that is somewhat of a status quo for your CapEx program that today implies, you may trim here and there.

But is there a level of the commodity prices that once you reach there for a extended period of time whatever you define that then and you start to be visiting your overall program and maybe consider that time had changed?

So on the production question, I mean, the best guidance I can give, Paul, is we expect to deliver 3% to 5% production growth moving from 2014 into 2015, just as we have from 2013 into 2014, and then keep that going through 2016 into 2017.

So the best guidance is the 3% to 5% production growth.

And on the second part there, Paul, there's nothing status quo about what's happening today in the market.

So we are -- we'll look at that as we got a lot of flexibility, we've got flexibility in our capital program, we got cash on the balance sheet.

We've got balance sheet flexibility.

We'll monitor the system and I'm pretty focused on cash flow neutrality.

I think we have to have a plan that gets us there, and so that's a stake that we've put in the ground.

And again, you'll go back to a bit of guidance that I provided in the call here, which says next year I'm looking at a capital amount that's lower than this year, and in fact lower than kind of the $16 billion guidance that we threw out there when we put our plan in place for the company's 3% to 5% growth.

Thank you.

Thanks Paul.

Roger Read, Wells Fargo.

Hi.

Good morning depending on where you are, or good afternoon.

Thanks Roger.

Just a couple other things, thinking about the whole cash flow, balance sheet approach, you all went through a very large, I guess, part -- the shrink part of the shrink to grow approach here over the last couple years.

If you're looking for ways to potentially plug an opening in the cash flow CapEx front over the next year or two years, if crude stays where it is, what -- are there other assets identified for sale -- if I remember correctly you had a larger portfolio of potential sales than were actually executed, so presumably there's still some noncore assets out there.

The approach we have on asset sales going forward is just to point people to the fact that we've got a large portfolio of assets.

When you look at a company of our size, roughly $100 billion of assets out there, but you can always expect that there'll be some level of asset sales that'll be happening.

And so is there $1 billion or so, maybe $2 billion of asset sales a year?

That's probably not an unreasonable expectation.

Going for -- unlike what we've done in the past, where we've identified particular assets that we're going to be marketing, we don't anticipate we'd be doing that going forward.

So you'd just likely hear about things as they happen.

We are going to be disciplined about portfolio management going forward, but there's nothing in particular that we would identify today that we want to talk about as an asset sale.

Okay.

Thanks.

And then the other question, on the OpEx side, we talked a lot about capital allocation and so forth, and you mentioned earlier contracts with the service companies, but rather than necessarily drilling a new well, what opportunities do you have on the operating side to lower costs, if any?

Or what should we think of to watch maybe as an independent factor for thinking about lower cost?

Yes.

So we are going through a budgeting phase just now, and we are asking all of our operating units and our staff groups to take a very close look at operating costs for next year to look for opportunities to reduce our overall operating cost structure.

So it's just part of our ongoing disciplined approach to managing our cost structure and we certainly have focused on that.

But we are always focused on that.

Right.

So I guess is there anything -- you know we should think about?

Well workovers or something like that you can always defer some of that work or are there ways -- I'm just trying to think expendable cost, something like that that you can manage down?

Yes.

There are opportunities, probably the last place we would go is through just well work and workover activity, that's very value adding operating costs, but we are asking all of our operating units to take a hard look at their operating costs for next year.

But that's no different from what we usually do, frankly.

Okay.

Thank you.

Thanks Roger.

Paul Sankey, Wolfe Research.

Good afternoon all.

Thanks for being so clear at what is a difficult time of year, I know, to talk about this stuff.

I think, just to clarify a comment you made to be very clear, Ryan, I think you said quite specifically that CapEx next year would be lower and below your $16 billion guidance, is that your opening statement?

That's correct.

That's great.

Thanks.

That makes that clear.

If we were to think of what you thought of as an attractive dividend, we would assume that that would be rising over time in order -- otherwise it wouldn't be attractive.

Right?

Yes.

We've said over time we expect to be increasing the dividend, so yes.

That -- it'll remain attractive.

And by the way I'm not setting out here to trick you in any way.

I'm just making quite sure we're clear here.

So what you've nowsaid is that you are locked into the major project spending obviously, and that's a very important part of you meeting your volume guidance.

But you have an increasing amount of essentially discretionary CapEx over the coming years which would allow you, should the environment stay tough, to cut back fairly easily on your spending in order to balance your budget.

Yes.

I think that's right, Paul.

You know it's a place where we haven't been as a company that we set out to create more flexibility, lower cost of supply across the portfolio.

So as I mentioned in my opening remarks, today, through 2014, about 50% of our capital is what you described, the major projects that are going to deliver the -- help deliver the 3% to 5% growth.

The discretion and flexibility that we're creating in the company is a lot more of that capital going to the development drilling programs, both the mature low-cost supply Eagle Ford, Bakken, and the less mature things that we are doing in the Permian and Niobrara, and up in Canada, Montney, Duvernay and what we are doing internationally.

So that represents in the next couple years over 70% of our capital.

So that capital is flexible and we'll manage the capital level based on the commodity price environment that we see, the opportunities that's in front of us, and the cash flows we have coming in as a company.

Yes.

And it feels like even if you were, let's say, to cut in the way that you're describing, already, in fact CapEx next year, the volume impact because of the fact these are more frontier type developments, the volume impact's actually going to be fairly limited within the 2017 timeframe is that correct -- very limited.

Yes.

That's exactly right, Paul.

Our volume growth target is execution on the plans that we've had over the last couple of years, it's the investments we've made over the last two years, it's the projects that we've been investing in for the last five years or six years.

Those are coming to fruition now, this year and into next year, so what we do, whether it's 2015 or goes beyond 2015, has very little impact on our plans and our production growth targets through 2017 that we outlined and described to the market over the last couple years.

Right.

So if I could just round it all off, one thing I think is very small but I'll just highlight, is that in the past you talked about running with $2 billion, I think, of cash as a working need?

But you today said $1 billion.

And secondly one thing that (multiple speakers) you did.

Is that what you just said, sorry?

Yes.

$1 billion is the -- would be the correct number.

The one thing that did worry me, Ryan, was that you said that you would meet your targets in a normalized price environment.

Could you specify that, because obviously that could mean an awful lot of different things?

I think the point we were trying to make there, Paul, is when you look at cash margins, those obviously are changing as commodity prices change.

So as we look at the shift that's happening within our portfolio, if you just pick one price environment no matter what price environment it was, and stuck with that, you'd see increasing cash margins.

So we're trying to be very transparent on that, Paul, we are showing you what each quarter is in terms of the actual, but we're trying to also ground back to when we described and launched the independent company, described how we were going to grow both margins and volumes, and we are trying to report back to that basis.

I got you, but what worries me is when you did that the oil -- and your planning assumption, I think was $110 Brent, if I remember rightly.

It was way higher than we are today.

No.

That -- we were quoted as saying that.

That's not our planning assumption; it is not $110 Brent.

Back when we threw that out, we were using current prices to demonstrate here's where the margin is today, and if you track our performance relative to that, you'll see what the margin growth is doing.

So my point is the underlying margin growth is there, the absolute number's going to fluctuate and be a bit volatile quarter to quarter based on the absolute level of commodity prices, but we're trying to show that the volume growth is coming, and it's at a higher margin than the base part of the portfolio, so the margin growth is coming and it'll turn to cash flow.

That's great.

Thank you.

Thanks Paul.

Blake Fernandez, Howard Weil.

Thanks.

I recognize it's late in the call so I'll try to be fairly brief.

I'm sorry to flog the CapEx piece, but I was wondering if you could define the absolute amount of spending that's actually rolling over on a dollar basis from the major projects year-to-year, and then secondly, I didn't know if you could maybe define a level or price point where you would actually curtail spending on some of the more mature unconventional plays.

Well, I'm not sure -- we'll have to get back with you on the capital that's rolling over from this year to next year, but the price has to go pretty low before we start impacting the mature plays that we have in our unconventionals.

Okay.

The second question for you is on some of the issues on production in 4Q.

I think you referenced three of them: infrastructure in Malaysia, ethane rejection, and APLNG.

Just trying to get a sense of how transitory those are, in other words, should those be behind us into 1Q?

I'm thinking maybe the ethane rejection piece is the only wild card?

So based on current prices, we would expect to be continuing to reject ethane through 2016, the way things stand just now, and that's about 1/3 of the variance that we talked about.

On APLNG that was -- we were prepared to take the opportunity to sell ramp gas to one of the other venturers on Curtis Island.

Their project hasn't come in as quickly as they had anticipated so we don't -- we were unlikely to be selling ramp gas to them.

And then on the KBB project -- we're ready -- we're going to start sometime in November, but there's a pipeline that runs from -- once the gas gets onshore, there's a pipeline that runs from Sabah to Sarawak to take that gas to the Malaysia LNG plants, and that pipeline has had some issues that need to be repaired, and we are not sure how long that's going to take.

We certainly don't expect it to be repaired before the end of the year, and we are assuming that it may be as late as the middle of 2015 before we actually get that pipeline fully repaired and into full operation, so that one will linger for a while into 2015.

Okay.

Perfect.

Thank you very much.

Thank you Blake.

Ryan Todd, Deutsche Bank.

Great.

Thanks gentlemen.

A couple quick questions, again, one's a follow-up and maybe this is too specific on CapEx, but I believe that your prior targets to reach cash flow neutrality were based around $100 Brent, $90 WTI longer-term.

When we think about the amount of relative CapEx that might need to be to come out of the 2015 budget, is there -- should we think about a mark-to-market on the commodity price, and then we'll try to bridge that gap on a year-by-year basis from here?

No.

We are not talking about trying to get to cash flow neutrality in 2015.

So as we go forward from 2015 -- 2014 to 2015, you're going to see cash flow growing as production grows from these major projects that we have starting up, so you're going to see that cash flow growth.

Even in a lower commodity price environment that we're seeing today, the comment that Ryan was making, is we still feel like we're going to get to a cash flow neutrality number by 2016, 2017, and before we were at the higher prices that you talked about, we were at a point where we were actually beyond cash flow neutrality, so we still feel like that's a very doable thing for us to be doing.

We don't have a number today that we can tell you that it's going to be this amount of cash -- capital expenditures in 2016 or 2017 to get to that kind of cash flow neutrality.

Okay.

And this -- I wasn't implying cash flow neutrality in 2015.

I was implying relative to the -- plugging the gap relative to the prior plan to keep on pace for the 2017 time period but (multiple speakers)--

But yes.

I think you are -- if you think about a $20 change in price, basically which is what we've had, that's about a $3 billion change in our cash flow.

Part of that is going to come from the fact that we are beyond cash flow neutrality and part of it would come from lower CapEx.

Okay.

One other question on a totally different issue; in Alaska there's obviously been -- we hear it a lot on the refining side from west coast refineries about increasing competition as you see Bakken volumes or rail volumes reaching the West Coast and the impact on Alaskan crude pricing, in terms of your outlook on Alaskan crude pricing going forward, what is the outlook?

What are the opportunities that you have?

I know you've done one cargo at least in terms of exporting that crude, and what sort of price differential would you need, or bottlenecks in the system are there in terms of exporting more of that crude to Asia?

Well, I think yes, what we're trying to show is that we've got a lot of flexibility, so right now the market on the west coast is -- needs the ANS crude and we hear a lot about the Bakken railing there.

But we've got a lot of flexibility.

We demonstrated that by taking the cargo to Asia.

We have the ability and the capability to go do that, obviously there's a bit more transportation costs associated with that, so if ANS starts trading well below where it's historically traded relative to either WTI or Brent, then we can exercise the optionality we have of exporting that crude.

Okay.

Great.

Thanks for the help.

We are past the hour, so we'll take one final question, if you don't mind, operator.

Pavel Molchanov, Raymond James.

Thanks for squeezing me in.

Just one from me.

As we wait for APLNG to start up, and obviously watching LNG prices fall along with crude, can you just remind us on what the off take arrangements are for the plant, and any color on that would be helpful.

Yes.

So all of the gas from Train 1 and 2 is contracted at -- based on the Japanese crude cocktail prices so it's all contracted.

There'll be a few spot cargoes as we are ramping up production, but once we get into full production it's fully contracted to China and Japan.

Okay.

Perfect.

That's all I needed.

Thank you.

Thanks and thanks operator, we'll go ahead and shut it off here.

Thank you so much everybody for joining us today.

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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This transcript contains forward-looking statements.

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