康菲 (COP) 2013 Q4 法說會逐字稿

Welcome to the fourth-quarter 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 of Investor Relations and Communications.

You may begin.

Thanks, Christine, and welcome, everybody.

Our executive speakers for the day are Ryan Lance, our Chairman and CEO; Jeff Sheets, our Executive Vice President and CFO; and Matt Fox, our Executive Vice President of Exploration and Production.

They'll make some prepared remarks, and then of course we'll take your questions.

We will ask folks to stick to a question and one follow-up today just so we can move through the queue.

A couple of quick reminders, today's materials are available on our website, and we'll post a transcript of this call there soon.

I also wanted to remind you we've previously announced that we'll host our 2014 Analyst Meeting in New York City on April 10, so look out for some additional logistical details on that.

And then finally our Safe Harbor statement is shown on page 2 of today's presentation deck.

We will make some forward-looking statements during today's webcast.

The statement, as well as our periodic filings with the SEC, outline some of the uncertainties and risks in our future performance.

Now, I will turn the call over to Ryan.

Thank you, Ellen, and hello, everyone.

Thank you for joining us today.

We just finished our first full year as an independent E&P company and all of us here at ConocoPhillips are pretty proud of what we've accomplished.

2013 was a year in which we had to achieve several strategic and operational goals to position the company for 3% to 5% volume and margin growth in 2014 and beyond, and that's what we did.

If you turn to slide 3, let me describe some of the highlights from this important year.

Operationally, we met our production goals for the year.

As importantly, we grew our reserves to fuel our future growth.

As you saw in our announcement today, we achieved 179% reserve replacement ratio and grew our reserves about 3%.

It's pretty strong results for a company of our size, and it certainly speaks to the quality of our asset base and our investment programs.

Our 3% to 5% growth will come from major projects and development drilling programs across our operations.

In 2013, we achieved startups in several major projects, and we continue to ramp up our unconventional programs in the Lower 48.

These activities will ramp up during 2014 as well and also provide strong momentum into 2015.

In looking longer-term, our exploration program which is key for sustaining our future growth, we had another successful year in 2013.

We announced three deepwater Gulf of Mexico successes.

We advanced our North American unconventional exploration programs, and accessed additional opportunities around the globe.

Operationally, we hit the milestones we set for ourselves in 2013, and we have positioned the company for growth.

2013 was also a strong financial year.

On a full-year adjusted earnings, we were at $7.1 billion, up 5% compared to 2012's adjusted earnings.

This translates to $5.70 per share for the year.

Cash from operations grew year-over-year, and we ended up 2013 with $6.5 billion of cash and short-term investments on the balance sheet.

Our cash margins grew 11% compared to 2012.

This reflects a fundamental shift toward liquids in our portfolio and certainly a key aspect of our value proposition.

Strategically, it was an active year for ConocoPhillips as well.

We closed over $10 billion of non-core asset dispositions including Kashagan and Algeria, and these are certainly important steps toward high-grading our portfolio.

Nigeria is really the only remaining announced asset sale to complete, and we hope to have that done relatively soon.

During 2013 we maintained our commitment to pay a compelling dividend.

We increased our dividend by about 4.5% at midyear and remain committed to increases over time.

So in summary, 2013 was a very successful year for the company operationally, financially and strategically.

We accomplished what we set out to do, to high-grade our portfolio, to position ourselves for volume and margin growth, to access and build opportunities for future growth, to maintain our financial strength, and finally, deliver strong shareholder return.

Let me now turn over the call to both Jeff and Matt for some additional comments on 2013 and a look into 2014.

Thanks, Ryan.

First, a recap of the fourth-quarter results on slide 4. Fourth-quarter 2013 adjusted earnings were $1.74 billion or $1.40 a share.

Adjusted earnings were essentially flat to last year's fourth quarter and down slightly sequentially despite lower realizations.

Some of the drivers in this quarter's performance aren't obvious, so I have some detail on those items.

Embedded in this quarter's earnings are weaker liquids realizations in North America, reflecting wide differentials to WTI and WCS.

For example, in our Lower 48 segment our realized price for crude oil averaged 90% of WTI in Q4 2013, compared to 101% WTI in Q4 2012.

Bitumen prices were also particularly weak this quarter.

Volumes for the quarter were negatively impacted by unusual weather in the Lower 48 and the North Sea, which we pre-announced.

We also had continued curtailment in Libya and a planned turnaround in Qatar.

Finally, the quarter benefited from lower tax expenses.

Our tax expenses were lower both because of increased proportion of production in areas with more favorable fiscal terms, as well as an approximately $100 million benefit related to changes in tax estimates from several regions, and an $85 million tax benefit related to the strengthening of the US dollar against the Australian dollar.

Our fourth-quarter segment earnings are shown in the lower right hand corner side of this chart.

We provided additional details on our operating and corporate segments in the backup materials.

Next I'll cover full-year 2013 financials on slide 5. As Ryan mentioned, full-year 2013 adjusted earnings were $7.1 billion or $5.70 a share.

Adjusted earnings were up about 5% from the full-year 2012.

This makes a point that underlying performance is improving.

Realizations are about flat, but margins are growing due to increases in liquids production from places with better fiscals, which is consistent with our strategy.

Despite volatile pricing and basis differentials throughout the year, all of our significant operating segments were profitable.

We continue to believe that our diversified product and geographic splits are key to providing consistent performance over time.

That was a quick review of our reported earnings results.

Again, there is additional information in our backup and supplemental materials.

Now turn to slide 6 for some specific comments on production.

Total production for 2013 was 1.518 million BOE per day which included 1.473 million BOE per day from continuing ops, and 45,000 per day from discontinued operations.

This chart shows the drivers of the change in production from continuing operations, compared to the fourth quarter of 2012.

Fourth-quarter 2012 production from continuing operations was 1.566 million BOE per day.

Adjusting for dispositions and Libya, which were 10,000 and 43,000 BOE per day, respectively, normalized production from continuing operations was 1.513 million BOE per day in last year's fourth quarter, and that's the middle blue bar on the chart.

Moving to the right, we show the variance in downtime this quarter, driven by unusual weather impacts and a month-long turnaround in Qatar.

Finally, you'll see that growth just about offset decline.

I should note that there wasn't much of a contribution from the major project startups since they came on late in the quarter.

But they will start making a visible difference in our future production.

The majority of our growth came from our development in major projects in the Lower 48 shale plays and the Oil Sands and Asia.

The full-year volume story is more telling, so please turn to page 7. This chart shows the same convention as the previous chart, adjusted for downtime, Libya and dispositions, we grew production about 2%.

Growth of 207,000 BOE per day was 30,000 per day higher than decline of 177,000 per day.

This reflects underlying production growth in the Lower 48, the Oil Sands and in Asia.

Again, the contribution from our recent major projects was negligible given the late year timing.

One note, in 2013, Libya contributed 30,000 BOE per day of production and absent those volumes 2013 total production was 1.472 million BOE per day, and we intend to exclude Libya in our future production outlooks.

So, we now think of this 1.472 million BOE per day as the base on which we're going to grow 3% to 5% in 2014 and beyond.

That growth is bringing stronger margins and slide 8 and 9 put our growth and margin trends in perspective.

The chart on page 8 shows the 30,000 barrel a day production change from the previous slide, sliced by segment and product in order of year-over-year change.

At the top of the chart, is our growth from liquids focused assets especially the Lower 48 unconventionals, the Oil Sands in Canada, and higher-margin production from the Asia-Pacific segment.

We're growing in the places and in the products that have higher margins and declining in some of the lower-margin streams like North American natural gas.

During 2013, liquids production from continuing operations increased to 56% of total production and should continue to improve in 2014 and beyond.

The impact of this mix shift on cash margins can be seen on slide 9. This slide shows year-over-year cash margins both on a reported basis on the left side of the chart and a price normalized basis on the right side of the chart.

As you can see from the left chart, 2013 cash margins grew 11% on an absolute basis despite flat realized prices compared to 2012, reflecting the impact of production mix and location.

On the right side of the page, we price normalized the margins with 2012 as the baseline, and margins grew 9% on this basis.

We have provided a reconciliation of this chart in our backup materials.

We expect this metric to continue to improve, and we'll continue to track it since it's a key aspect of our value proposition.

I will conclude my prepared remarks with our cash flow waterfall, which is another good story.

If you'll turn to slide 10.

This shows our cash flow performance for 2013.

We began the year with about $4.5 billion of cash on the balance sheet.

For the year, we generated about $16 billion of cash from operations and over $10 billion from asset sales.

Our continuing operations capital program was about $16 billion.

We paid about $3.3 billion in dividends.

As we announced in December we prepaid $2.8 billion of future obligations to our 50% owned joint venture interest at FCCL, and the remaining cash flow items such as debt repayment and capital associated with discontinued operations were a $1.5 billion use of cash.

This leaves us in a very strong financial position at the end of 2013 with about $6.5 billion in cash and short-term investments on hand and a positive outlook for margin improvement that can grow cash from operations.

As we start 2014, we're well positioned to execute on our investment programs for the company.

That concludes the review of our financial performance.

I will turn the call over to Matt for an update on our operations, beginning on slide 11.

Thanks, Jeff.

I'll kick off the operations section with some comments on our 2013 reserve replacement performance.

We achieved very strong results for the year.

We ended 2013 with 8.9 billion BOE of reserves, up 3% compared to last year.

Importantly, we added over 1 billion barrels of reserves organically, resulting in our organic reserves replacement ratio of 179%.

Including last year, we've now averaged over 165% organic reserve replacement as an independent E&P company.

Our all-in reserve replacement ratio was 147%.

This takes into account the impact of dispositions completed during the year, primarily at Kashagan, Algeria and the Cedar Creek Anticline, which reduced reserves by 188 million BOE.

Some of the key additions came from the Eagle Ford and Bakken.

Most of the additions in these two plays were a result of higher confidence and performance and offset bookings.

However, we've only booked less than 30% of identified resources in Eagle Ford and Bakken.

That's based on our current well spacings of 80 acres in the Eagle Ford, and 320 acres in the Bakken.

Resource upside potential still exists in these plays, as we get results from our spacing pilots.

Canada contributed about a quarter of the additions, predominantly from the Oil Sands.

We also added reserves to APLNG as we continued to drill our acreage there and with some contributions from both the U.K. and Norwegian sectors of the North Sea.

We'll provide more details on our reserve booking including costs incurred in our 10K that will be filed in February.

Again, we're really pleased with these results, and we believe they're differential for a company of our size.

The bottom line is that these reserve additions give us confidence in our ability to deliver sustained growth and value creation from our capital programs.

Next I'll review our operating segments.

In each segment, I will address key results from the fourth quarter and overall highlights from 2013, and I will give you some color around activities to watch out for this year.

I'll start with the Alaska segment on page 12, starting from the lower left with highlights from the fourth quarter.

We applied for a two-year export license for a Kenai LNG plant.

You may remember we placed this facility in cold storage about a year ago to retain the option to restart if conditions changed.

With increasing gas production in the Cook Inlet we can now take advantage of that LNG capacity.

At CD5, we began critical ice road construction that will allow us to move materials for roads and bridges that are key to accessing and preparing this project site.

Moving to the top right, 2013 was a big year for our Alaska business.

Probably the most significant highlight was the passage of SB21, or the More Alaska Production Act.

These changes have made the investment climate in Alaska more attractive.

As a result, we'll execute a much higher budget for 2014, $600 million more than in 2013.

And this capital increase is focused on adding production.

For example, in addition to CD5, we'll continue our major project work at Drill Site 2S and Greater Moose's Tooth, and these three projects alone could add over 40,000 barrels a day gross by 2018 to offset declines through TAPS.

We continue to make progress on the Alaska LNG project.

This month we executed a Heads of Agreement with ExxonMobil, BP, TransCanada and the State of Alaska that defines the path forward for the commencement of pre-FEED.

If all goes well, Pre-pEED work could start as early as the second quarter this year.

So I'd say we're making progress on all fronts in Alaska.

Let's move on to slide 13 to cover the Lower 48 segment.

As Jeff already mentioned, like many other operators, we had adverse production impacts due to weather in the fourth quarter in this segment.

Despite the weather, we achieved some significant progress in the Eagle Ford and the Bakken in particular.

In the Eagle Ford, our operated program reached a milestone of more than 500 total wells online, production averaged 126,000 BOE a day in the fourth quarter, representing 42% growth versus the same period for the previous year.

We reached a peak rate of 141,000 BOE per day in late December.

In the Bakken, we achieved a peak rate of 43,000 barrels a day, and averaged 39,000 a day for the fourth quarter.

That's a 63% increase compared to the same period last year.

In the fourth quarter, we also made progress on our emerging deepwater business.

We announced the discovery of Gila, conducted appraisal activities at Tiber and Coronado, and continued exploration drilling at Deep Nansen in the Western Gulf of Mexico.

Moving to the full-year highlights, Lower 48 production was up 34,000 BOE per day, representing 7% growth versus 2012, but more importantly behind this overall growth, our oil production grew 24% year-on-year delivering the mix shift we're targeting as we execute our strategy.

In fact, for the full-year 2013 the Eagle Ford and Bakken grew 60% on a combined basis compared to 2012.

During 2013 we also matured our appraisal programs in the Delaware and Midland basins and in the Niobrara.

We continue to test various horizons, completion designs and lateral lengths in these plays with encouraging results to date.

We'll give you an update on what we're learning at our Analyst Day in April, so the goal of these appraisal programs is to have a clearer view of the development plans for these plays by the end of this year.

In our emerging Gulf of Mexico deepwater program we announced significant results at Shenandoah and Coronado in the first quarter and a discovery of Gila in the fourth quarter.

These are important milestones and establish strong momentum for exploration and appraisal activities for 2014 and beyond.

Our Lower 48 business is a very unique and high-value segment.

We have peer-leading positions in several of the best Lower 48 unconventional plays, where we're growing production and continuing to identify upside.

Also, we have an enviable position in the deepwater Gulf of Mexico that's delivered early success and provides future growth and significant value for the company.

Please go to slide 14 and we'll talk about the Canada segment.

Operationally, our Canada business performed very well in the fourth quarter.

Volumes continue to ramp up at Christina Lake Phase E, and our Western Canada winter drilling program got underway, where we're focused on drilling our liquids-rich inventory.

We continue to drill and evaluate unconventional plays in the Duvernay and Montney, and we've spudded the first horizontal well in the Canol play, where wee hope to drill two horizontal wells this season.

Overall, 2013 was a very important year for the segment.

Like the Lower 48 we advanced a very substantial yet diverse set of opportunities.

For the year, production was up 1% and we achieved a 13% increase in liquids production compared to 2012, mostly from the Oil Sands.

Our Oil Sands business performed extremely well operationally.

Volumes grew 17% and by year end the Surmont 2 project had achieved over 60% completion.

This positions us very well for first steam in mid-2015 as we planned.

The theme for 2014 in Canada is continued investment and growth.

Our conventional liquid-rich plays, our unconventional plays and our Oil Sands assets will all be active with some significant milestones on the horizon.

Let's move on to our Europe segment on slide 15.

Like the Lower 48, this segment experienced some very challenging weather that impacted fourth-quarter production, however, the big news in the fourth quarter was the start of production in Ekofisk South in Norway and Jasmine in the U.K. Ekofisk South production started in late October from the first of four pre-drilled wells, two months ahead of schedule.

Ekofisk South is designed for 35 production wells that will grow production as they're drilled over the next five years.

At Jasmine, first production was achieved in November.

Production is currently constrained at about half of platform capacity until we fully commission the Judy riser platform, which should occur during this quarter.

Clearly the major projects dominated the operational themes for 2013.

But extensive turnarounds, in large part to (inaudible) prepare for project startups, were a key activity in the middle of the year and were executed very well.

In addition to the two major projects I just discussed, work advanced on additional projects at Eldfisk II, Britannia Long-Term Compression and Clair Ridge.

We enter 2014 focused on ramping up and optimizing the major projects at Ekofisk South and Jasmine and establishing production through a new East Irish Sea acid plant.

In addition, the Britannia Long-Term Compression project is preparing for startup in the third quarter of this year, and pre-drilling is underway at Eldfisk II in anticipation of start-up in early 2015.

On the exploration front in this segment we expect to see results from our unconventional appraisal in Poland.

Two vertical wells and one horizontal well are planned.

We'll also begin exploratory drilling in the Barents Sea.

Our Europe segment had a pivotal year in 2013 after several years in project mode.

We're positioned for growth from high-value production that will extend the life of our legacy positions in Europe.

We have a lot of work to do to ramp up and optimize our operations in 2014, but these activities will position us for a strong future in this segment.

Finally, I'll cover our Asia Pacific Middle East segment on slide 16.

Key fourth-quarter highlights in this segment included the completion of the QG3 planned turnaround in Qatar and continued progress on accessing future exploration options.

We obtained operatorship and 100% working interest in the Palangkaraya PSC in Indonesia, and we completed our seismic work in the Qijiang block of China.

These are both examples of relatively low-cost early stage exploration options and plays with the potential for materiality.

Highlights for all of 2013 include the progress on major projects that will make a step function contribution to future production levels in this segment.

During 2013, our partners progressed towards major project start-ups in Malaysia.

We are now anticipating a first-quarter startup at Siakap North-Petai, and a second-quarter start -at Gumusut.

Our APLNG project is on schedule for first LNG by mid-2015, and overall the project stands at about 60% complete.

On the exploration front, we announced the Proteus gas discovery in the Browse Basin, which was an untested structure to the Southeast of the Poseidon discovery.

The big catalysts for 2014 are the Malaysia startups at SNP, Gumusut, and Kebabangan, and we have an important year ahead at APLNG as we approach startup in 2015.

We expect to provide a full update of these projects at our April Analyst Meeting in New York.

Our appraisal programs offshore Australia will continue in 2014 with two wells each planned in the Poseidon area and at Caldita Barossa, and the punch line in this segment is very straightforward, significant production ramp up over the next couple of years from high-margin volumes and upside from a growing exploration inventory.

I don't have a slide on our Other International segment.

The main focus last year was on executing the divestitures that Ryan mentioned.

In 2014 the key segment activity will be our exploration in Senegal and Angola.

We should get underway by mid-year.

I'll conclude my prepared remarks with some comments on our production outlook for the first quarter.

We are on track to deliver 3 to 5% growth in 2014 from the projects and activities I just described.

Excluding Libya, we expect to achieve approximately 1.5 million barrels a day this year.

As Jeff mentioned, we'll exclude Libya from future production outlooks since we are not optimistic that production will resume from the Eastern fields anytime soon.

In the first quarter, we estimate that volumes from continuing operations, excluding Libya, could range from 1,490 to 1,530 thousand BOE per day.

This range reflects short-term uncertainty around the ramp-up of recent and pending start-ups and includes a 15,000 barrel per day impact from a turnaround of the second train in Qatar that will occur in March.

Now, I'll turn the call back to Ryan for a brief recap and summary of the key themes for 2014 on slide 17.

Thank you, Matt.

I hope there's no doubt that 2013 was a successful year for the company.

We delivered on our commitments but perhaps more importantly we positioned the company for a strong 2014.

Operationally, we're at a significant inflection point for the company.

We expect to continue ramping up our unconventional drilling programs and progressing our major growth projects.

As Matt mentioned, we expect to grow in almost all of our business segments this year, while progressing the major projects that will continue our growth into 2015 and beyond.

Meanwhile, it's a big year for our exploration programs, and our conventional program will be drilling in the Gulf of Mexico, Angola, Senegal, the Barents Sea and Australia.

In our unconventional program, we'll have an active year in the Lower 48 Permian andNiobrara plays, as well as Poland and Canada.

We should see ongoing improvement in underlying margins as we bring on new volumes and we'll maintain our focus on improving returns, while staying committed to returning capital to our shareholders.

On the strategic front we're moving beyond the positioning phase of our journey as an independent E&P company, so now we're focused on executing our current plans to deliver growth in volumes and margins, while positioning the company for long-term success.

Our goal here is to have a deep inventory of choices and options for investment and be the best capital allocators in the business.

We think our diversified approach to this business will serve us well over the long term.

We are not dependent on any single product, play type or geography.

This allows us to consistently execute our programs through the cycles.

Bottom line, we're positioned to deliver 3% to 5% growth in both production and margins with a compelling dividend.

That's our value proposition that we set out and we're committed to delivering on it.

I hope Jeff, Matt, and I have given you confidence that our plans are on track for delivering key milestones in 2014.

It should be an exciting year and I look forward to seeing you at the Analyst Meeting in April in New York.

I would mention I think Matt mentioned 2014 production at 1.5.

It's a 1.55 million BOE per day.

Oops.

Now, let me take all your questions.

(Operator Instructions)

Doug Terreson, ISI.

Good afternoon, everybody.

Good afternoon, Doug.

In the Lower 48, and also internationally, the cash margins seemed to have been significantly stronger versus the year-ago period despite the absence of help from realizations, which I think one of Jeff's slides indicated.

On this point, I wanted to see if we can get some color on the improved performance in those two areas, and specifically where you're seeing the improvement regionally in both Lower 48 and international E&P.

Doug, I think it primarily comes back to changes in mix, when you look at cash margins within that segment.

That's what we were trying to highlight with the slide.

It just shows the year-over-year changes in production.

You just saw a fairly large shift in liquids production that we talked about increases of a very significant percentage related primarily to Eagle Ford and Bakken.

I think the biggest driver of that change.

And internationally, Jeff, could it be the loss of some lower-margin production as well?

Well, yes.

I think that's the overall mix.

Appropriately, there's a flag there, Doug.

If you look year-over-year we basically have the same overall realized price.

But the shift of production within different jurisdictions, which is highlighted on that one slide we have, shows production going up in the Lower 48, up in Canada, up in Asia, down in Alaska, down in Norway, down in the U.K.; so up in lower-tax areas, and down in highertax areas.

That has a lot to do with helping drive the cash margin, that and just the shift overall to liquids production over gas production.

Doug, that's what we said.

That's going to continue because that's the direction, that's the strategy.

That's how we are allocating our capital, and that's how we're thinking about how we grow the margins and grow our cash flows as the production growth.

Right.

Then quickly on capital expenditures, I think slide 10 indicated that the company prepaid almost $3 billion of its Oil Sands commitment.

I wanted to see if you could spend a minute on that item specifically, why the company chose to do so, whether or not there were any interest or tax benefit that were meaningful, and also how it affects the spending profile on that project going forward.

Yes.

As we mentioned, we prepaid a $2.8 billion obligation that we had, and that was something we incurred when we set up the joint venture back many years ago.

The key for us is that was an interest-bearing obligation.

It had about a 5% interest on it.

You can really think of that as being equivalent to debt.

It was an obligation that we needed to pay over the next several years.

When we had as much cash as we have in our balance sheet just from a balance sheet management point of view, it makes sense to prepay that obligation and save the 5% interest, as opposed to leaving that's on your balance sheet and earning little return on the cash.

The other thing we want to make sure we point out on that is that's cash that is moving into a 50% joint venture.

While it's a $2.8 billion outflow for us that means we essentially still own about half of that $2.8 billion, so it's more of a $1.4 billion net outflow.

That does reduce capital that we'll have in the subsequent years, but we did that primarily just from a balance sheet management point of view of getting rid of an interest-bearing obligation, and taking advantage of the fact that you would otherwise just have cash on your balance sheet not making a very good return.

Right.

Okay.

Thanks a lot, guys.

Thanks, Doug.

Ed Westlake, Credit Suisse.

Good afternoon, and good progress on the cash margin story.

Just thinking about one of the components of that is obviously your shale portfolio, and you gave good guidance back on the Investor Day last year.

Still some growth in the Eagle Ford, although you seem to be ahead of plan, in the Bakken and Permian, then accelerate.

What's the constraint on perhaps even driving a little bit harder in terms of shale?

Is it the amount of money that you have to still spend on some of these longer-life pancake type assets, SAGD, APLNG?

Or is it that the shale itself is not yet delineated enough for you to put more capital to work?

Thanks.

Ed, this is Matt.

It's really neither of those things actually.

Really what it is we're focused just now on running a safe and efficient operation.

We don't want this economy of scale.

We don't want to get too far ahead of infrastructure.

The real reason is that we're still benefiting from our cost learning curve and the drilling and completions, and that's going to improve even further as we move toward pad drilling for most of our wells.

It's a cost learning curve and then there's a huge technology learning curve ahead of us in the unconventionals that's going to improve the overall efficiency of these developments in the years to come.

We're staying consistent, for example, in the Eagle Ford with an 11-rig program, but we do have the flexibility as you point out, to change that if we think that's the right value proposition.

And most of the acreage HBP so there is no pressure as well.

Just a follow-up on shale then, Matt.

What were you most excited about that you feel that you can talk about last year, when you think about the North American shale play portfolio, maybe include Columbia as well but not just in the U.S.?

We're making progress on all of our shale plays.

Clearly the Eagle Ford and the Bakken are now in development mode, but we're still seeing upside there associated with pilot tests that we're running for, looking at decreasing well spacing.

I alluded to that in my prepared remarks.

We're getting encouraging results in the Permian, both in the Delaware and Midland basin, and encouraging results in the Niobrara.

In Canada, we're still getting good results from our unconventional program up there.

We're going to give you a lot more detail on this when we get to the Analyst Meeting in April because we think we owe you an update on what we're learning in all of these plays, but that will take a bit of time and we'll do that in April.

I would add, Ed, that we continue to believe, and I think our results are proving out that we're in the best positions in the best plays.

Any surprises we get are usually to the upside, and we've got more resource and more opportunity as we think about capital program and our allocation of capital as some of the big projects start to wind down.

Very helpful.

Very clear, thanks.

Jim Sullivan, Alembic Global Advisors.

Good afternoon guys.

I just wanted to look a little bit ahead on this margin story.

Obviously the passage of SB21, the Alaska Production Act, has you guys thinking a little bit differently about Alaska, and we obviously appreciate the details on Moose's Tooth and so forth, with the reservation that I'm sure that you guys are going to want to talk about this in more detail at the Analyst Day.

Can you just comment a bit on how you see that affecting the margin profile going forward?

Obviously, you have an array of tax benefits in that bill.

Can you have a comparison to the base production, and is it along the lines of Lower 48, or how should we think of it?

It's not as strong as the Lower 48 because there is still, even with the tax improvements in Alaska, higher tax regime in Alaska than there is in the Lower 48.

Alaska production is all oil, which helps on cash margin side as well, where you think about something like Eagle Ford is 60% oil, and 20% NGLs and 20% natural gas.

Alaska is going to also contribute to helping with cash margins because it continues to help with the oil production, probably not as much as increased Lower 48 production helps.

Okay.

That is all I have.

Paul Cheng, Barclays.

Hi, guys.

I have two questions.

One maybe on the overall picture.

Ryan, one of your competitors Shell, the new CEO is essentially saying that the elephant hunt is risky and wanted to scale back.

Obviously, for the company of your size you can't just always go for the single, it won't work.

Just to correlate that, you have what internally considered by the top allocation of capital, how much is your percent of your capital you want to chase those really high-risk big elephant, or how much is it that you go for to say the lower risk and smaller one?

And also whether it is capital or production profile.

Is there anything you can share on that thinking?

Yes.

What I would say, Paul, is broadly at the higher level in terms of allocation, we think about spending about 15% of our capital on the exploration, and we would like to do that through the cycles now.

If we get success and, we start to appraise, we've got a decision that we face about increasing that percentage for appraisal and keeping an exploration program going.

But I'd say broadly speaking, we're spending about 15% of our capital on exploration, and we are really value based as we think about it.

I don't go into it trying to overload either unconventional or conventional.

Today, our program is pretty balanced.

It's about 50-50 conventional and unconventional.

Everything has to compete, so whether it's a new unconventional play that we might be looking at in another country, or here in the U.S., or in North America, it has got to complete on a cost-to-supply basis and an expected rate of return.

If we're doing our risking appropriately, doing our technical work appropriately, everything has got to play.

I don't really look at it and say I'm not going yo go elephant hunting or anything like that.

We're just trying to do the best technical work we can, risk it the best way we can, and then every dollar competes.

If I can clarify myself, when I say elephant hunt, it's not just for the exploration.

For example, when you go to the Alaskan LNG, if indeed that project ended up being economically viable, it's going to be extremely expensive and even with a partner, your share is going to be huge.

It's a huge big block and if anything has happened, it's going to be a huge negative impact on the company, and so those are the kind of projects.

I am wondering that if there's internally a percentage of the capital or the production you want to be in those big projects?

We still look at returns and cost of supply and try to ask ourselves is it competitive in the portfolio.

We know that big resource, long-dated projects like Alaska LNG that you referred to, or similar to what we're executing in Queensland, or what we're doing in the Oil Sands of Canada, those have a different profile, different return profile than unconventionals in North America.

But again, this is the part where we think a diversified large, global E&P company with the balance sheet like we have is important.

There's a place in the portfolio for some of those projects to balance it out over time.

They reduce capital intensity, and they have a place in the portfolio.

But we have to be careful.

We have to look at the other alternative investments and other options and choices we have in the portfolio.

We haven't made that decision on Alaska gas because we're still studying it.

We're still trying to understand what that cost is going to look like, what the economics, how it competes in the global market place for LNG, and how it competes in our portfolio.

The second question is for Matt.

Matt, on Eagle Ford based on your previous production chart from this point on that the growth is going to slow down, I guess my question to that is if that's just being ultra conservative or indeed you think that is the most likely base case scenario?

Should we be more aggressively trying to shift and increase the activities in either the Bakken or the Permian?

Yes.

We're going to give you an update on that, Paul, when we get together in April for the Analyst Meeting.

That was our view of how production would be likely move in the Eagle Ford.

Our view has changed.

We are going to show you something that is a bit more optimistic than that in April.

Okay.

Thank you.

Blake Fernandez, Howard Weil.

Good afternoon.

I'm sorry to ask you to repeat the guidance, but I wanted to make sure, and be 100% clear.

I thought I heard a first quarter guidance, and then a full year, and I was hoping you could just repeat that if you don't mind.

The first-quarter guidance Blake was 1,490 to 1,530 thousand barrels a day for the first quarter.

That's quite a wide range of the uncertainty there because of the ramp up of new projects that are going to be happening in that quarter.

This also will be affected by the downtime in one of the Qatar LNG trains, and so that was the first quarter.

Our full-year guidance is basically unchanged from what we've been saying, the 1.55 million barrels a day for the year, and all of those numbers I just gave you exclude Libya.

Matt, just to be clear.

I know you had some weather-related impacts in the Lower 48 in 4Q.

Obviously, we've seen some pretty rough weather this past week.

Does that contemplate anything you may be witnessing currently?

That range includes some uncertainty and any weather impacts that we'll see for the remainder of the quarter.

Okay.

Great.

The second question I had for you, this may be a bit premature but on pre-salt Angola, I know you'll begin drilling this year.

Some of your peers who have had success and ended up having some gas, basically in the fiscal terms from what I understand, didn't really contemplate monetizing gas.

Are you trying to proactively get ahead of maybe reevaluating your contracts with the government?

Or are you just taking a wait-and-see approach there?

We don't have gas rights, in those two blocks, blocks 36 and 37.

The way that we model the petroleum system there, we don't expect to find gas.

The way we model the maturity of the source rock our expectation is that we'll find oil, if we find anything.

It's still exploration in this program, so we're still hopeful for that.

Where our blocks are, there's quite a thick salt section above the structures and the effect of that is that it cools the source rock, which means the source rock is less mature.

Not to get too technical on you, but nonetheless we expect that that's going to be an oily petroleum system where our prospects are.

Okay.

Good to hear.

Thank you.

Doug Leggate, Bank of America Merrill Lynch.

Good afternoon, everybody.

Hello, Doug.

I'm not sure who wants to take this one, but if you go to slide 7 in your book, I am wondering if you could give us a little bit help with the puts and takes on how you see 2014.

The 1.55 guidance, I'm literally looking at the last two bars in the decline and the growth because what I'm really trying to get to is the composition of the decline in terms of gas in particular.

Obviously, when you look at your realized margin, I am guessing that would be a big help if there's a lot of gas in there.

So if you could help with the puts and takes?

And I've got a follow-up, please.

Doug, this is Ellen here.

We'd love to take this offline with you.

We've got the data that could help here, but I do not have it at my fingertips.

Obviously, in the 177 MBOED our North American gas is declining, of course.

Obviously in the 207 MBOED, the growth we saw on that page, that's the liquids ramp and the unconventional.

I think, Doug, your question is probably looking more toward 2014?

It's very much about 2014.

I'm trying to get a feel for the underlying decline in the mix.

I don't think that's data we've at our fingertips.

Directionally, we're going to see the same type of thing.

We're going to be continuing to grow more liquids production than gas production, as we ramp up oil production in Malaysia, as we continue to grow the unconventionals as the Oil Sands continue to grow.

You'll see a lot of the same things in 2014.

I'm not sure if we've got that information or if that's something we can probably give you more detail on in April.

At the Analyst Meeting.

Yes, when we do the Analyst Meeting.

That's great.

I'll take it offline.

My follow-up is kind of related I guess, but hopefully you can help me with this one, Jeff.

If I look at the mix of the projects coming online, it looks to us at least that there's a fair number of them that will not incur cash taxes, at least in the early years of production.

I am just wondering if you can help offer some color, and particularly things like Ekofisk, basically U.K. and North Sea, I am guessing you won't be paying cash taxes in the early years.

I'm just wondering if you can confirm that, and maybe put some numbers around it.

I'll leave it at that.

Thank you.

Let me just mention a few things, and we'll see if that helps.

If you think about where our capital is going in the Lower 48, a lot of it's going into drilling.

A lot of that capital is IDCs, which of course get very rapid depreciation.

Norway you get rapid depreciation.

U.K., you get essentially almost immediate depreciation on your capital.

Directionally, you're right on all of those.

The way that manifests itself in our results is just what you see on the deferred tax line on the cash flow statement.

You've seen that that was a pretty significant source of positive cash in 2013, a little bit less so in the fourth quarter than in the other quarters.

But there were some impacts of how the impairmentsthat we took in the fourth quarter roll through the cash flow statement that adds up those impacts, you would've see a similar number in the fourth quarter to what you saw in the previous quarter.

It's a pretty substantial impact positive to cash.

That'll probably continue on into 2014, but I don't have a number that I can give you that's exactly what that impact is going to be, but that's where it shows up for us.

How much of an add-back do you have for deferred tax on your cash flow statement.

And that's embedded in your reported cash margins, Jeff?

No.

It's not.

The way we do a cash margin calculation is simply an adjusted net income, plus your amortization, plus your DD&A, and your dry hole costs and leasehold amortization.

We don't factor deferred tax into that.

We take a simplified approach to cash margins, and we do that because that's the kind of metric we can have a comparison against other companies with.

Got it.

Really helpful, thanks, guys.

Faisel Khan, Citigroup.

Thanks.

Good afternoon.

I appreciate the guidance on margin growth and production growth.

I was also wondering whether you guys have goals on the return on capital employed, and what those look like underneath, the assumptions you have for 2014, and for that matter, even going forward?

Our return on capital employed for 2013 is pretty similar to what we saw in 2012.

We'll be a bit challenged to improve return on capital employed in the very near term, and a lot of that has to do with the fact that we've got large capital going into projects that are not really producing much right now, if you think about APLNG, some of the Oil Sands assets.

It's also due to the fact that, as Matt mentioned in his remarks, we're relatively conservatively booked on a lot of the unconventionals, which leads to some pretty high DD&A rates on the unconventionals.

All of those things impact net income, which of course impacts return on capital employed.

You'll see a better picture for us once APLNG starts up, once Surmont starts up, and once we get a little bit more fully booked on the unconventionals.

We do see that we'll be improving returns on capital employed, but of course prices can affect that metric as they change but those improvements are probably more in a 2016/2017 timeframe.

Okay.

Fair enough.

Just on Alaska, so I understand it's early to figure out what the cost of this project would be, but what type of capital are you spending right now on it?

And what are the critical timelines or time posts in order for this to move forward or even gain some traction?

I assume you're talking about AKLNG?

Yes.

As you know, we've selected the concept.

We've selected the site.

We just announced an HOA that puts the structure in place for the project, and we are hopeful to start Pre-FEED in the second quarter.

Right now, it looks like a project that will be somewhere between $45 billion and $65 billion.

That's got some movement of different scope in it, and so on, but it's that our scale.

It'll be something around the 17 million tons per annum and through three trains there.

The timeline that we're working with just now is that we would make that final investment decision in 2016 or 2017.

There's quite a bit of feed required for a project of this scale and between the Pre-FEED and the FEED, it'll be 2016 or 2017 before we make a final investment decision.

First guess would be 2022 to 2025.

That's the range that we're thinking about just now for the project.

Okay.

I appreciate it.

Thanks, guys.

Roger Read, Wells Fargo.

Good afternoon.

Hello, Roger.

I guess the main thing I'd like to focus on here is just trying to understand, I know you reiterated the 3% to 5% volume growth, the 3% to 5% margin expansion.

Can we walk through here where the margin expansion should be, for at least my growth assumptions, more of the second-half 2014 event.

But I just wanted to hear what your take is on that.

I think that is probably a fair assumption.

As Matt mentioned earlier, as we think about volumes overall for 2014, the impact of timing on start-ups on some of these key major projects is going to be a question.

I think some of the previous questions that we've gotten to, the same kind of things that drove margin growth this year are the things that drive us next year, as we continue to ramp up Oil Sands production, ramp up Lower 48 production, and get to a full production in Gumusut, which because of the way the production recovery works there had some really strong cash margins.

You'll see those same three drivers.

North American natural gas probably won't grow in our portfolio going forward.

We could see a slowing of decline in Alaska, but overall that's probably not going to cause margins to move significantly.

It's really back to the same primary drivers that we've had this year and driversin 2014 as well.

With the same reductions in the gas side.

Europe, Lower 48, some of the lower-margin gas that's not getting capital investment starts to decline, so the mix that Jeff described in his remarks.

Okay.

It's safe to assume that margin is a full-year event in the production?

Like I said, I don't want to put words in your mouth, but at least in my assumption on projects startups, more of a second half event is a good way to look at it?

Yes.

With cash margin metrics like that we try to warn every quarter that that can swing up and down because incoming DD&A can be less than perfectly ratable through the year for different reasons.

We think it's important as we go forward that we talk about how we're progressing on more longer-term measures than just looking at it quarter to quarter.

Okay.

I know you don't give quarterly production.

The last question I had was last year, especially in the summer months, a lot of turnaround activity had a pretty significant impact on production volumes.

Can you characterize for us this year what we would be anticipating in terms of maintenance and turnarounds?

Yes.

In 2014, we are expecting about 20% more planned downtime than we had in 2013.

We've got the downtime, I mentioned in QG3 Train 7 in the first quarter.

We have turnarounds inPrudhoe Bay in the second and third quarter, turnarounds in the U.K. in the second and third quarter, and a big turnaround at the Bayu-Undan Field in Australia in the third quarter.

We're expecting the overall planned downtime to be about 20% more than it was in 2012.

2013.

2013.

Sorry.

Thanks, Roger.

We have no further questions.

I will now turn the call back over to Ellen DeSanctis.

Thank you, Christine, and thank you, everybody.

Of course feel free to call us back if you have any lingering questions, and we certainly look forward to seeing you in April.

Thank you for your time.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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