康菲 (COP) 2012 Q4 法說會逐字稿

Welcome to the Q4 2012 ConocoPhillips earnings conference call.

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

At this time, all participants are in a listen-only mode.

Later, we will conduct a question and answer session.

Please note that this conference is being recorded.

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

You may begin.

Thank you, Christine, and good morning to all our participants today.

Welcome to our fourth quarter and full year 2012 conference call.

Today, you will be hearing from three of our executives.

Ryan Lance, our Chairman and CEO, will make some brief opening and closing comments to cover the full year 2012 results and some priorities for 2013.

Jeff Sheets, our EVP and CFO, will review the fourth quarter and the full year financial results, including our segment financials, and he'll be followed by Matt Fox, our EVP of Exploration and Production.

Matt will review our year-end reserves performance and provide some color on E&P activities for the fourth quarter in each of our segments.

Please note that today's presentation materials can be found on our website.

A transcript of this call will be also posted later today, we hope, if not by tomorrow.

As a final reminder, on Page 2 of our presentation deck, you'll find our Safe Harbor Statement.

We will be making some forward-looking statements this morning.

Results could differ materially from the expectations we share today, and we've described those uncertainties and risks to our future performance in our Safe Harbor Statement and in our periodic filings with the SEC.

With that out of the way, I'll turn the call over to Ryan Lance.

Thank you, Ellen.

Good morning, everyone.

Thank you for joining us today.

Let me kickoff the meeting today with a review of our key 2012 highlights and accomplishments.

Certainly the strategic highlight of the year was the spinoff of our downstream business, Phillips 66, which occurred in May.

Following that transaction, we emerged as North America's largest independent E&P Company.

We set out to combine our world class assets, technology, financial strength, and work force with an intense focus on the E&P business, and we laid out an ambitious goal to achieve both growth and returns while offering a compelling dividend, and we remain committed to that goal.

Achieving this goal depends not only on executing our identified growth programs, but on executing a major divestiture program to high grade our asset base.

During 2012, we made significant progress on this program.

We completed asset sales of $2.1 billion and recently announced agreements for an additional $9.6 billion of dispositions.

These proceeds will give us the flexibility to fund our significant growth programs over the next few years.

The key part of our ongoing value proposition is to a maintain focus on our shareholders.

We achieved strong shareholder returns during 2012, especially combining the performance of ConocoPhillips and Phillips 66.

That strategic performance was matched with strong operational results.

We met our volume targets in 2012, achieving a total annual production rate of 1.578 million BOE per day, with growth on a continuing operations basis.

And we're on track to deliver the plans we laid out in April of last year.

We recognized that 2013 would be a low point in production, and we expect growth in the fourth quarter due to major project startups and continued ramp-up in our North American drilling programs.

And this sets us up for our long-term 3% to 5% growth objective.

We grew our reserve base to 8.6 billion BOEs, and organic conditions this year were 942 million BOE, and that represents a 150% reserve replacement rate, a significant achievement for a company our size.

Throughout the year, the business ran well.

Our major projects and drilling programs performed as expected, and importantly, we built momentum in both our conventional and unconventional exploration programs, and these are key to creating long-term value in this business.

For the full year, we generated $6.7 billion of adjusted earnings, or $5.37 per share from continuing operations, and we generated $14.7 billion of cash from continuing operations excluding working capital.

We returned over $8 billion to our shareholders, $5.1 billion of share repurchases and $3.3 billion in ordinary dividends.

Our per share performance for the year reflects roughly a 10% reduction in share count compared to 2011.

Before I turn the call over to Jeff, let me take a moment to acknowledge the hard work and the dedication of our ConocoPhillips work force.

Despite a year of major change, they maintained their focus on the business, and they delivered on all fronts.

And I'm very proud of their performance and their commitment to our strong start as an independent company.

So I'll come back with some concluding remarks.

Let me now turn it over to Jeff for the financial review.

Thank you Ryan, and good morning, everyone.

I'll start with a review of our fourth quarter financial results on Slide 4. We reported adjusted earnings of $1.76 billion, or $1.43 a share for the fourth quarter 2012.

The special items this quarter that we excluded from our reported earnings in the determination of adjusted earnings included some asset impairments, certain tax items and legal settlements, as well as adjustments for discontinued operations.

These adjustments totaled $329 million, and the details can be found in the supplemental data that we provided with the earnings release.

As a result of the announced agreements to sell our interests in the Kashagan field and the Algeria and Nigeria business units, we've treated earnings and production associated with these assets as discontinued operations for the current quarter, as well as previous quarters.

Adjusted earnings in the fourth quarter from these assets would have been $27 million during the quarter or $0.02 a share, and our adjusted earnings per share would have been $1.45 without this change.

The earnings chart and realized price data on this slide now reflect continuing operations for all periods and except where we specifically noted, this is going to be our convention as we go through today's call.

Compared to the fourth quarter of 2011, adjusted earnings were down by 14%, primarily due to lower liquids prices and higher DD&A expense, which was offset primarily by higher volumes.

Per share earnings in this year's fourth quarter benefited from a 7% reduction in share count compared to last year's fourth quarter.

Compared to the third quarter, adjusted fourth quarter earnings were up 3% due to higher volumes and a slight improvement in realized prices.

Production volumes for the quarter met our targets.

We achieved solid performance across most of the portfolio and resumed production in several segments following the third quarter planned maintenance.

Year-over-year, averaged realized prices for the quarter were down about $3 a barrel, but up about $1 third quarter compared to fourth quarter.

Bitumen and NGL prices declined during the year and remained weak.

In the third fourth quarter, bitumen represented about 7% of our production, and North American NGLs also represented about 7% of our worldwide production.

Clearly, there's been a significant amount of volatility and price markers through the year, but if you look across our overall portfolio, realizations were relatively stable.

Finally, operating costs came in about as we expected them for the year.

Now, turn to Slide 5 and I'll review fourth quarter production performance.

This waterfall takes you through the changes in production from the fourth quarter of 2011 compared to the current quarter.

You can see the split here of production from continuing operations and from discontinued operations, and I'll step through the key items here, and Matt's going to provide some additional details in his material.

Total production from continuing and discontinuing operations was 1.607 million BOE per day in this year's fourth quarter, which was in line with our expectations.

So starting at the left of the chart and stepping through the waterfall, dispositions reduced production by 55,000 BOE per day compared to the fourth quarter last year.

And those 2012 dispositions included Vietnam, the Stafford and all the fields in the North Sea, some western Canadian assets, and the NMNG joint venture in Russia.

Downtime accounted for 40,000 BOE per day of lower production compared to the downtime experienced in last year's fourth quarter.

The downtime primarily occurred in Nigeria, the UK, and some in the Lower 48.

Natural field declines were about 152,000 BOE per day, and finally, shown on the green wedge on the chart is a growth wedge of 257,000 BOE per day of incremental production compared to the fourth quarter of last year.

The largest component of this growth wedge is new production from our Lower 48, Eagle Ford and Bakken plays and new production from our Canadian Oil Sands development.

Improved drilling programs across -- and performance across our portfolio, the resumption of full production in Libya, and some incremental volumes from the Peng Lai field in China also contributed to growth in production.

On a continuing operations basis, production for this year's fourth quarter was 1.566 million BOE per day compared to 1.483 million BOE per day in last year's fourth quarter when you adjust that quarter for dispositions.

This represents a 6% growth overall.

Additionally, liquids as a percent of our portfolio from continuing operations increased between the two periods.

So if you'll turn to Slide 6, we'll cover some production guidance for 2013.

On the left of this chart is our 2012 total production of 1.578 million BOE per day.

I wanted to take you through some of the adjustments that will result in a normalized 2012 production number, reflecting production from only the assets that we expect to be in our portfolio for the entirety of 2013.

First, we back out 51,000 BOE per day for discontinued operations, which, again, is the assets in Algeria and Nigeria.

Next, we remove 17,000 BOE every day, which is the 2012 production generated by the dispositions that were closed during 2012.

And earlier this month, we also announced the sale of our Cedar Creek Anticline assets, which we expect to close late in the first quarter 2013.

So our analysis we back out a final 13,000 BOE per day, which represents the production from this asset during 2012.

So the resulting 2012 production of 1.497 million BOE per day represents the normalized view of the production performance of our go-forward assets.

So our 2013 outlook for production from these assets that will remain in our portfolio is the range of 1.475 million to 1.525 million BOE per day.

Now, in the first quarter, we expect to still have Algeria, Nigeria and Cedar Creek in our portfolio.

Therefore, we provided you with an all-in first quarter production outlook of 1.58 to 1.6 million BOE per day, which includes about 40,000 per day for discontinued operations.

The second and third quarters of 2013 will be negatively impacted by both normal maintenance and planned -- normal seasonality and planned maintenance, but additionally, with some new projects coming on later in the year, we will have downtime associated with project tie-in.

Then we expect fourth quarter 2013 production to return to levels near the first quarter total production, as new projects coming online make up for the removal of production from discontinued operations.

And this is consistent with prior guidance that we have given around hitting a production low point in the second or third quarter of 2013.

Now, I'll turn to the segment slides and begin with the Lower 48 and Latin America, which is on Slide 7. Production in this segment was 475,000 BOE per day this quarter, an increase over prior periods, as we continued to ramp up production in our Lower 48 shale plays.

Segment production increased 13,000 BOE per day, or 3% sequentially, and 31,000 or 7% compared to the same period a year ago.

More importantly, liquids production grew 20% versus the fourth quarter of 2011.

We reached a significant milestone during the quarter in the Eagle Ford.

Production exceeded 100,000 BOE per day on a peak daily basis and averaged 89,000 BOE per day.

In addition to the Eagle Ford, year-over-year growth was achieved from unconventional drilling in the Bakken, new wells in the Permian, and improved well performance and optimization in the San Juan Basin.

While natural gas prices have recovered to levels closer to those in the fourth quarter 2011, the weakness in crude and NGL prices drove earnings lower year-over-year, and fourth quarter adjusted earnings were $157 million.

Next, we'll move to the Canada segment on Slide 8. In the Canada segment during the fourth quarter, production was 281,000 BOE per day, up 1% sequentially.

And production was up 6% compared to the fourth quarter of 2011, and this reflects five consecutive quarters of growth from our oil sands assets.

Compared to the fourth quarter 2011, liquids in this segment increased 23%, and natural gas production declined 7%.

And overall, the portfolio mix shifted to 51% liquids from 44% liquids a year ago.

This segment generated positive earnings of $32 million during the fourth quarter.

Earnings benefited from both higher production and stronger natural gas prices.

And these factors more than offset the impact of lower bitumen prices when compared to the third quarter.

Weaker bitumen prices were the key driver in lower year-over-year earnings.

We expect bitumen prices to remain weak for another quarter or so until additional heavy refining capacity comes online.

So now let's move to the Alaska segment on Slide 9. Production in Alaska was 222,000 BOE per day, up 46,000 compared to the third quarter.

And this increase was primarily due to production coming back online following the completion of major turnarounds in the third quarter.

Production volumes were down about 6% from the fourth quarter of 2011 to 2012, primarily just due to normal field decline.

Sequentially, higher production resulted in higher sales volumes, and this earnings benefit was partially offset by higher production-related costs, including petroleum production taxes and DD&A.

Segment adjusted earnings for the quarter were $595 million.

For segments like Alaska that are subject to lift timing differences between sales and production in any given quarter, we've now added a red line on these charts, which represents quarterly sales compared to quarterly production.

So this should help illustrate these timing differences.

While these timing differences net out over time, they do create quarterly earnings volatility.

So in this quarter, there was virtually no impact, no timing impact for lift timing in Alaska.

But prior quarters have been impacted.

So for example, if you look back in the fourth quarter of 2011, sales were nearly 40,000 BOE per day less than production, which resulted in lower earnings relative to the production level.

Then we had the opposite effect in the third quarter of 2012, when sales exceeded production and that contributed positively to earnings.

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

Asia-Pacific and Middle East continued to perform well during the quarter, providing important diversification to our portfolio.

Production in the segment was 322,000 BOE per day, up 16,000 per day or 5% sequentially, and up 32,000 or 11% compared to the fourth quarter of 2011.

The increase was primarily due to the resumption of Peng Lai production, but we also had new production from the Gumusut project in Malaysia and the Panyu growth project in China.

As you can see from the production chart, production exceeded sales this quarter.

This impacted segment earnings, as earnings reflect sales volumes rather than production.

We should also see a positive impact to the first quarter 2013 earnings from the reversal of these timing effects, all other things being equal.

Sequentially and year-over-year, earnings reflect the impact of lower realized LNG prices, which are linked to the Japanese Crude [Cocktailer] JCC prices.

And these price impacts were partially offset by the benefits of higher sales volumes.

Europe is the next segment found on Slide 11.

Production from the Europe segment was 216,000 BOE per day, an increase of 25,000.

This increase primarily reflects the resumption of production following planned downtime at Brittania and J-Block during the third quarter.

This quarter's volumes were negatively impacted by unusually high unplanned downtime in the southern North Sea and the east Irish Sea during the fourth quarter.

Compared to the fourth quarter of a year ago, production declined due to normal field decline, unplanned downtime and dispositions.

Sequentially, adjusted earnings of $388 million benefited from improved sales volumes and continued strong pricing in the segment.

As a reminder, like the Asia-Pacific segment, this segment provides important pricing diversification in our portfolio, and future earnings should benefit significantly from major project startups that are under way.

These projects will mitigate declines and bring attractive margins with the growth.

I'll cover our final geographic segment, the Other International segment, on Slide 12.

This segment is presented on a continuing operations basis, so it excludes Kashagan, Algeria and Nigeria, which were previously reported in the segment.

So the assets that are now in this segment include Libya, Russia, and our activities in Angola.

Fourth quarter 2012 production from continuing operations was 50,000 BOE per day, up 26,000 for the same period last year.

This increase is driven primarily by Libya coming back online, which more than offset the impact of the NMNG divestiture.

Final reporting segment I'll cover is Corporate and Other, which is on Slide 13.

Adjusted corporate expense during this year's fourth quarter was $177 million, resulting in a full-year adjusted corporate expense of $813 million.

The full-year performance was a little better than our expectations.

As you recall from our update last quarter, the third quarter benefited from licensing revenue, as well as some favorable FX impacts.

During the fourth quarter, we issued $2 billion of debt at attractive interest rates.

We used the proceeds from this issuance to pay down commercial paper and other maturing debt.

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

The previous charts have discussed segment results on a quarterly basis, and on this slide, we show annual results for some key financial metrics.

Adjusted earnings declined from $8 billion in 2011 to $6.7 billion in 2012, primarily a result of lower prices, particularly for North American natural gas and NGLs and Canadian bitumen and also were impacted by lower production levels, which were primarily results of our ongoing asset sales program.

On a per share basis, adjusted earnings declined to a lesser extent from $5.75 to $5.37, as a result of the lower share count due to the $5 billion of shares repurchased in 2012.

On our return on capital employed, our ROC numbers trended lower along with adjusted earnings, with capital employed growing slightly from 2011 to 2012, as we make significant investments to generate future production and margin growth.

Cash contribution per BOE and income per BOE were also impacted primarily by changes in commodity prices, and we expect to see these cash contributions per BOE numbers to grow significantly over the next several years as we add production from assets with higher cash margins than the average of our current portfolio.

And next, I'll step through the Company 2012 cash flow on Slide 15.

Just a quick comment about this water fall.

It's shown as if Algeria and Nigeria and Kashagan were part of continuing operations to provide some better comparability to analyst cash flows and our CapEx guidance.

On this basis, we generated cash from operations of $15.2 billion, excluding working capital changes in 2012, which were a $1.3 billion use of cash.

We also generated $2.1 billion of proceeds from asset dispositions.

We funded a $15.7 billion capital program, and about $800 million of that was capital associated with Nigeria, Algeria, and Kashagan.

The $5.5 billion source shown on the water fall is discontinued operations related to the spin of Phillips 66, which includes a special distribution and all the other cash flows related to Phillips 66.

Moving to the right on the water fall, we've repurchased $5.1 billion of our shares and paid $$3.3 billion in dividends, so over $8 billion in total distributions to shareholders in 2012.

Debt and other of $600 million includes some deposits we received from our recently announced asset dispositions.

So to sum it across, we ended up with -- 2012 with $4.4 billion of cash and restricted cash, and also just to note on the slide on the upper right, inset box, our year-end debt was $21.7 billion, which represented a debt to capital of 31%.

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

Thank you, Jeff.

Good morning, everyone.

I'll begin the operations section with the Company's 2012 reserve replacement performance.

We ended 2012 with just over 8.6 billion BOE of reserves, up 3% overall compared to 2011.

Importantly, we added 942 million net BOE of reserves organically, resulting in an organic reserves replacement rate of 156%.

Of our total reserve additions, 497 million barrels came from Canada as a result of projects sanctions in the oil sands.

Lower 48 was the second largest source of organic reserve additions, with 293 million barrels, and these were principally added from our Eagle Ford and Bakken unconventional programs and our Permian conventional programs.

Over 100 million barrels were also added across the Asia-Pacific segment.

Our all-in reserves replacement rate was 142%, and this takes into account the impact of dispositions completed during the year that reduced reserves by 83 million BOE.

We'll provide more detail on the reserve performance, including the costs incurred in the forthcoming 10-K.

But suffice it to say, we're really pleased with these results and we believe that our 40 billion plus barrel resource base holds significant future potential to be converted from resource to reserves over the coming years.

Now, I'll review our operating segments and provide some detail on our drilling programs, growth projects, and conventional and unconventional exploration activities.

I'll cover some highlights from the fourth quarter and also update you on current activities and what to expect in the near future.

Overall, our plans remain on track, and the business continues to run well.

So please turn to Slide 17 for a review of the Lower 48 and Latin America segment.

Performance in this segment is dominated by our ongoing success in the unconventional plays, especially the Eagle Ford.

In 2012, the Eagle Ford achieved 70,000 BOE per day of annual average production and averaged 89,000 BOE per day in the fourth quarter.

As Ryan and Jeff already mentioned, we also achieved a milestone of over 100,000 BOE per day of peak daily rate in the fourth quarter.

This is a tremendous accomplishment and a credit to our entire Eagle Ford team.

During 2012, we had up to 17 rigs drilling the play.

Late in the year, we began to reduce the rig count due to improved drilling efficiencies and a growing backlog of uncompleted wells, and we exited the year with 11 operated rigs.

We drilled 211 operated wells in 2012, and we now have a total of 313 wells online.

In addition, we have 87 wells drilled, waiting on completion, and 40 wells completed and awaiting tie-in.

Completing and connecting this backlog of wells is a key focus in 2013, along with achieving held-by production status.

We expect to complete the drilling phase of acreage capture by mid 2013, and we will reach full held-by production status by year end.

During the year, we'll gradually phase into 100% pad drilling in the play, with full pad drilling expected in 2014.

On the infrastructure side of the business, we currently truck virtually all of our light crude barrels from Eagle Ford, but we are working diligently to access connections to pipelines for direct sales.

In addition, we're actively adding infrastructure such as stabilization facilities that will remove light ends, allowing us to get our light crude barrels to pipeline spec and maximizing our capture of NGLs.

Recently in the Eagle Ford, we in the industry have been experiencing inconsistent and higher than normal back pressures in the gas gathering systems, which have created variability in our daily production rates.

We expect these constraints to be significantly reduced over the coming months.

Moving to the Bakken, we've produced 24,000 BOE per day in the fourth quarter, and we exited the year with nine rigs operating in the play.

In 2012, we completed a total of 187 operated and non operated wells.

We have 34 operated wells waiting on completion and 14 wells ready to tie in, and we continue to be excited about the future of this play.

In the Permian, we hold a really strong legacy conventional possession.

In 2012, we averaged 50,000 BOE per day of production from our conventional assets, and we added 98 operated wells and 50 non operated wells to production.

In the Permian, we are also testing several unconventional plays in the Midland and Delaware Basins.

Notably in 2012, we drilled nine wells in the Wolfcamp with encouraging results.

We also completed a 3D seismic survey across our Midland basin acreage, and we expect to continue drilling and testing Permian unconventional plays in 2013.

We haven't talked much about our activity in the Niobrara unconventional play, but we now hold about 130,000 net acres in what we believe is a sweet spot comparable to the Wattenberg area.

About half of this acreage was added in the fourth quarter.

And as shown on the map, it's a contiguous position that provides scale benefits and development flexibility going forward.

We drilled six Niobrara wells in 2012 and recently completed a new 3D seismic survey across our existing acreage.

This is a developing play, and production results to date are encouraging, and it will be an important part of our exploration and development program going forward.

We'll provide more detail at our analyst meeting in February.

Moving to the Gulf of Mexico, we continue to grow our deep water position there.

During the quarter, we were awarded 28,800 acres in the central Gulf of Mexico lease sale, and we were also an apparent high bidder for 348,000 acres in the western Gulf of Mexico lease sale.

These additions bring our current deep water possession to over 1.9 million acres, making us the sixth largest acreage holder in the gulf.

I'm not sure everyone recognizes just how substantial a possession we have developed here.

Currently, we're drilling two partner operated wells in the deep water, Coronado and Shenandoah.

Hummer, a low cost farm-in, was declared a dry hole in the fourth quarter.

We expect to spud our first operated well in 2013, the Thorn Prospect, which will be an exciting milestone for the Company.

Finally, we announced the sale of our Cedar Creek Anticline asset for over $1 billion.

This was an opportunity to divest a declining conventional asset that didn't compete for capital in our portfolio.

We expect this transaction to close in the first quarter.

So please go to Slide 18, and we'll talk about the Canada segment.

Our Canadian oil sands assets continue to operate extremely well.

Weaker bitumen pricing this quarter has impacted margins, but operationally, these assets are delivering strong volume growth.

Our oil sands production exceeded 100,000 BOE per day in the fourth quarter of 2012, making it the second largest SAGD producer in the oil sands.

Currently, we're executing seven major projects across our FCCL joint venture and Surmont.

We recently sanctioned Narrows Lake Phase A and Christina Lake Phase F, while progressing construction on the large scale development of Surmont Phase II.

Moving to our Western Canada business unit, we continue to focus our drilling activities on the liquids rich and light oil plays in our portfolio.

Currently, we're running 16 rigs, drilling on our held-by production acreage that are focused on liquids-prone plays such as the Montney, Glauconite and Cardium.

We're also testing other unconventional exploration opportunities within and outside of core areas in Western Canada.

For example, we're currently drilling in the Duvernay play, where we have 112,000 net acres.

We've drilled and completed one horizontal well recently and are currently drilling a second well.

We have three additional wells planned for this year.

We also have drilling under way in 120,000 net acre position in the Muskwa play in the Horn River area.

Finally, in the Canol play in the central Mackenzie Valley, we have 216,000 net acres.

We plan to drill two vertical wells early this year to test the significant potential of this oil shale play, and we have two additional horizontal wells identified for drilling next year.

In summary, our Canada segment continues to operate extremely well.

So let's finish out the North American segment with Alaska on Slide 19.

Full Alaska production resumed in the fourth quarter following successful third quarter turnarounds.

And this segment continues to generate steady performance for the Company, and it's benefiting from development innovations using coiled tubing drilling, or CTD and 4D seismic, that are helping to offset natural field declines.

For example, in the fourth quarter, we drilled what we believe is a first-ever octolateral CTD well.

That's a well with eight different horizontal sections that was guided using high quality 4D seismic survey.

In the fourth quarter, we sanctioned the Alpine West CD5 project and expect production to start up in 2016.

As we've mentioned before and you've seen in the press, we are working with other producers in Alaska to evaluate LNG exports from the north slope.

The producer group has been evaluating development concepts and assessing the costs of major project components for various alternatives, and completion of this phase of work is targeted for the first quarter.

We continue to invest around $1 billion a year of net capital for maintenance activities and infield exploitation programs across the north slope.

And we could make other significant investments in Alaska, but they will require more competitive state fiscal terms.

Let's move to Slide 20, the Asia-Pacific and Middle East segment.

Our Asia-Pacific and Middle East operations are running well, and we're progressing several major projects in this segment.

This is an area of significant growth for us over the next five years, with most of the growth coming from Malaysia and APLNG.

In Malaysia, we achieved first oil from Gumusut in November, utilizing an existing floating production storage and off-loading facility at the Kikeh field.

This facility will be used until our dedicated floating production system is completed later this year.

We expect to reach peak production from Gumusut in 2014.

In early October, we also sanctioned the Malakai project, where we expect first production in 2017 and development activities also under way in the Siakap North-Petai and KBB projects.

Also in Malaysia, we recently executed a production sharing contract for exploration block SB-311, offshore Sabah.

This block covers about 250,000 acres, and we are the operator with the 40% working interest.

The PSC has a three-year exploration period with a work program of seismic and two exploration wells.

In China, Peng Lai averaged 43,000 BOE per day of net production during this quarter, and at Panyu, we brought on nine growth wells in the fourth quarter.

The growth development remains ahead of schedule, and we expect to add about 8000 BOE per day between now and 2014 as we drill additional wells from the two new platforms.

And this new production is expected to more than offset declines at Panyu.

Also in China, we recently announced the joint study agreement with Sinopec to assess shale gas opportunities in the Qi Jiang block in the Sichuan province.

The block covers an area of approximately 1 million acres, and the study will be carried out over two years, including seismic and drilling obligations.

In Qatar, we secured new long-term LNG sales commitments in the fourth quarter, and we now have about 80% of QG3 LNG production linked to crude prices under long-term agreements.

In Australia, our APLNG project remains on schedule, and we intend to provide a more fulsome update on the development of the APLNG at the February analyst meeting.

On the exploration front, drilling continues in Australia.

In November, we spudded the [Zephyrs 1] well, the second of a five-well appraisal program at Poseidon, and in the Canning Basin, we're drilling our second exploration well to test this 11 million-acre position.

So this is a very active segment for us just now, and we're excited about the development and exploration opportunities here over the next several years.

Please turn to Slide 21, and I'll provide an update on our Europe segment.

In Europe, we're focused on progressing our major projects in the UK and Norway.

Operationally, the UK had a challenging quarter, due to unplanned downtime in the east Irish Sea, southern North Sea, Britannia and Clair.

This downtime accounted for an average of 23,000 BOE per day that was offline in the fourth quarter.

The east Irish Sea is still shut in, awaiting onshore facilities upgrades that should be completed in the second quarter.

On a positive note, our Katy field development in the southern North Sea was completed in December, and gas production came online in January.

We expect peak rate production of about 5,000 BOE a day from this field.

In addition, in the UK, the Jasmine and Clair Ridge developments are in execution with first production at Jasmine expected in the second half of this year.

First production at Clair Ridge is targeted for the second half of 2016.

Moving to Norway, the Ekofisk South and Eldfisk II projects are progressing as planned.

At Ekofisk South, the topside structural deck sections are being completed, and first production is expected at the end of this year.

Eldfisk II is also on track for production start up at the end of 2014 or early 2015.

These projects are running smoothly, and our base operations in Norway continue to perform well.

Finally, in Poland, we are continuing our exploration drilling program in 2013, as operator in our three peri-Baltic western concessions.

Just to note, we have significant downtime in 2013 within the segment, as we tie in our new projects to the Ekofisk and J-Block production platforms.

However, we expect to exit the year with very strong growth from these developments.

The final segment I'll cover is Other International on Slide 22.

There was a lot of activity in this segment, too, during the fourth quarter.

We announced sales agreements for Kashagan, Nigeria and Algeria.

We expect these transactions to close in the middle of this year.

On the slide, we've shown 2012 average production rates and year-end 2012 reserves for these assets.

During the fourth quarter, Nigeria was severely impacted by flooding in the Niger Delta, as you can see in this lower picture.

The flooding began in late October, and fourth quarter production was impacted by about 13,000 BOE per day, and first quarter production will also be impacted by this flood-related downtime.

In Angola, we secured a rig for our plans to drill four exploration wells starting in 2014.

The seismic results in our Angola blocks are really encouraging, and we look forward to getting under way in drilling in this significant and new exploration opportunity.

I'll conclude my prepared remarks by reiterating the themes you've heard consistently this morning.

We are focused on safely executing our base business while successfully funding our growth program.

We are seeing the benefits of our conventional and unconventional exploration programs, and we continue to progress on major projects across the globe.

Now, I'll turn the call over to Ryan for some closing comments.

Thank you, Matt.

Please turn to Slide 23 for some summary comments.

I'll conclude today's remarks with a quick review of our 2013 priorities.

These are not going to be a big surprise, as they are a continuation of the priorities we set for ourselves during last year.

Our highest priority is to focus on safety and operations excellence.

And this is an imperative, and it's a priority we take to heart at ConocoPhillips and throughout the Company.

We made significant progress on our strategic divestiture program in 2012, but we still have work to do.

Importantly, we have to complete and close these divestitures, which are expected to generate about $9.6 billion of proceeds.

These proceeds will largely be directed toward executing our drilling programs and our major growth projects.

As we've told you throughout the year, we have identified projects in hand and under way that will materially change the growth trajectory of our company over the next few years.

And it's important that we execute on these activities.

It's also important that we advance our exploration activities globally in both our conventional and unconventional portfolios.

2013 and 2014 are important years for testing the opportunities that we've captured.

And certainly last, but not least, we'll maintain our commitment to shareholders by continuing to offer a unique value proposition that delivers growth, margins, and a compelling dividend.

Finally, a reminder, we'll have our first analyst meeting as an independent E&P company in New York on February 28.

At that meeting, we'll provide more detail on our Company's plans for the future and our long-term priorities for value creation.

So thank you for listening.

We'll turn the call now back to our operator to begin the Q&A process.

Thank you, Christine, and thank you, participants.

We will now begin the question and answer session.

(Operator Instructions)

Faisel Khan, Citigroup.

I was wondering if you could clarify the 2013 production guidance, it looks like it is going to be relatively flat and certainly the market seems a little bit disappointed today in that number.

But going back to your previous slides from last year, you did show a dip in expected production in 2013 internationally and growth in the Lower 48 in North American production.

So could you just clarify what's going on with production and how you see it, this being a bottom in the year?

And I have a follow-up after that.

Thanks for the question, Faisel.

I think the production guidance is really pretty similar to what we've given in the past.

We knew that 2013 would be the low point in our production for the year.

So I'm not sure what additional guidance we can have other than what we've given on the call this morning.

We tried -- what we're trying to do is just make it clear, now that the asset disposition program has become a little bit more into focus than it has been in the past.

Just what the production levels are going to be from the assets, long-term -- going to be part of our portfolio long-term.

And that's what we're trying to lay out with this production guidance this morning.

I think part of the -- we've been -- we anticipate being pretty successful in our asset disposition program.

So we're probably at the high end of what we've -- of what some people have probably had in their models for the amount of production that's going out on dispositions as well.

Okay.

Faisel, let me jump in here quickly.

This is Ellen.

Appreciate again the question.

If you look at what we had in April for '12 and what we had in April for '13 and you kind of average it over a couple of years, it ends up being that we were -- that the timing of divestitures actually ends up slipping from '12 a little bit to '13.

So if you look at it on a couple year basis, it ends up being really right on guidance.

I think a way to think about this is exit rate to exit rate, think about 4Q this year.

The number Jeff provided is sort of [15-10] that had the noise out of this quarter compared to the fourth quarter to get to the guidance we've provided.

It will be very significant growth in quarter over quarter 2013 to '12.

We'll provide all these updates at the analyst meeting, but I think of it as -- or think of it as the divestitures stayed in the portfolio in 2012 a little bit longer, and exit rate to exit rate is going to be higher because of the timing startups.

The project startups.

Yes.

So I think that's an important point, is that we are going to start seeing production growth in 2013, particularly late in the year, where we have startups happening in the North Sea and the continued ramp up in oil sands and continued ramp up in the oil shales.

And right, plus the startup of projects in Malaysia.

Okay, great.

One other question, on the capital program, it looks like -- fine print on Slide 15, that roughly $800 million in capital is associated with the asset divestitures of 2012.

Is that roughly the same number in '13?

It's probably a little lower than that in '13, but really much depends on when assets actually end up leaving the portfolio.

So we'll be -- all through the year, we'll need to be giving updates on how we see the capital program playing out this year.

Okay, and last question for me, bitumen prices were extremely low in the fourth quarter.

Is there any plans for you guys to try to evacuate that production by other means and pipelines to get a higher realization?

Faisel, over the long-term, there will be moves to find alternative markets for bitumen from the Canadian Oil Sands.

I think that's a strategic imperative of the Canadian government, not just the oil companies working on the oil sands.

So we will see that happening over time.

Of course the short-term issue that we're facing just now is very much associated with refining constraints, like at BP's Whiting refinery.

We don't expect these very wide differentials to be sustained for more than the next few months.

In the long-term, other markets will be developed.

Okay.

Fair enough.

Thanks, guys.

Doug Leggate, Bank of America Merrill Lynch.

I have a couple of quick ones.

Jeff, you gave us the earnings numbers associated with the discontinued ops.

But I guess to Faisel's point, looks like there was over $800 million of spending associated to those assets.

Can you help us with the operating cash flow impact, and if you could clarify whether or not the $15.6 billion, $15.7 billion target for this year for spending assumes the asset sales are out for the whole year, or is that number much higher if you basically delay these sales to the end of the year?

And I have a quick follow-up, please.

So the operating cash flow numbers, again -- so the discontinued operations are Algeria and Nigeria, and I don't think we have -- we're not going to be disclosing particular operating cash flow numbers for each of those segments.

The capital is mostly development of Kazakhstan during -- the number that was in 2012.

I think that was probably the half to two thirds of the number that was in on the $800 million.

As far as what's in for 2013, we are pursuing a lot of different capital projects with fairly heavy spend, and there's going to be several things that could impact what our capital program ultimately ends up being at in 2013 as we execute on those projects, and timing of dispositions is really just one of those items.

So we've assumed certain timings, but as I said on the answer to the last question, we're just going to need to be continually updating that as we see the year develop.

Thanks, Jeff.

I guess my follow-up is I guess relates to the exploration program.

Just to fit some context around this, [Jim] had spent the last decade trying to secure resources and build up a very large drilling inventory at gas.

Obviously there was a lot of spending to achieve that, but now you're in the position where you're still underfunded relative to your CapEx and your dividends, but you're spending $2 billion to $3 billion in exploration.

Can you help us with the logic of why that's the right thing at this point, given the $1.5 billion write-off in 2012, why that's the right strategy at this point, given that you should have theoretically had a lot of resource?

I'll leave it there.

Thanks.

Yes, Doug, this is Ryan.

I think as we look out and think about the future opportunity, I think with this unconventional revolution that we're seeing in North America right now, and some of the technology advances in the deep water arenas that are becoming pretty prospective, it's in my view turned from a bit of resource scarcity that was leading to a lot of merger synergies over the last 10 or 12 years and resource capture and into a view now that the resources aren't so scarce and there's a bit more abundance, certainly on the unconventional side in North America, what the technology is doing to improve the oil sands performance in Canada, and then what innovation and technology has done on the deep water side.

We think growing organically, there's the opportunity set to go do that and the option value associated with growing organically is -- we found better in our portfolio than trying to do that through an M&A channel or some resource access that way.

So we think it's important for the long-term growth.

What the last 10 years did for this company is created a 40 billion plus barrel resource base.

And we're investing in that resource base right now as we look forward into the future over the next 10 years, we see the exploration and the organic growth being more a driver to our other growth and development of the company.

All right.

Appreciate the answer.

Thanks.

Thank you.

Doug Terreson, ISI.

My question is on the mix shift that appears to be underway at the Company.

Besides better profitability in the United States, it appears that there are going to be some positive mix effects overseas, too.

And on this point, my question is whether the earnings from the discontinued operations, which I think were listed as close to $0 for '11 and '12, were the actual clean operating numbers.

And also, do we have any updated information on the tax implications of the $10 billion of proceeds from those sales, meaning what I'm trying to get to is what is the approximate earnings loss in return for the $10 billion of pretax proceeds that you're likely to receive?

Well, the fourth quarter was a challenging -- again, so disk ops is Algeria, Nigeria and the Kashagan asset which of course is not in operation yet, so there's not income or cash flow from these assets.

So the adjusted earnings, as we mentioned, from these assets were $0.02 a share, $27 million during the fourth quarter.

That was probably a particularly low number, though, because of the impact that Matt talked about on the flooding in Nigeria that impacted the Nigerian operations.

But they weren't significantly higher than that in the previous quarters, in the year also.

We generate cash flow a little bit higher than income in those, but we are also reinvesting capital as well.

A long way of saying, Doug, that we don't really anticipate that moving those assets out of our portfolio would change our cash flow from operations very significantly.

Okay.

And, Jeff, do you have any insight for us on the tax implications of these divestitures, meaning you highlighted $10 billion of sales proceeds and, do we know what the cash proceeds might be?

Yes, the cash proceeds are going to be close to the numbers that we've highlighted.

These transactions are generally going to be very tax efficient.

Great.

Easy way to create value.

And also, I have a question for Ryan.

Ryan, you spent a lot of time in Alaska.

Seems like there's movement on a new fiscal regime up there.

So my question is whether or not you feel this most recent movement is real and if so, whether or not the investment opportunity could be meaningful for the Company.

Yes, I do.

I think I've had conversations with Governor Parnell over the course of last year and leading up to the session that started in January here in Alaska.

And he's -- he understands the lack of competitiveness and the fact that the current taxing system really takes away a lot of competitiveness out of the Alaskan opportunities up there.

So I think he's serious about trying to push something through the legislature.

I think he has proposed some fiscals on the oil side.

He's put a proposal out there.

I don't think -- it's going to be a tough haul through the legislature, but I also think people are noticing.

And we've said as a company that we would be prepared to ramp up our investment if it got more competitive with a changing fiscal system in Alaska.

Part of that's tied I think to the work that we're doing on ANS gas as well and progressing the work on a potential LNG project.

So part of that's tied into some of this as well.

But I'm probably slightly encouraged, Doug, but it's a long way till May when the session ends.

Great.

Thanks a lot.

Paul Sankey, Deutsche Bank.

I'm sorry to be confused about this, but if I look at Slide 6, and you may well have explained this and I apologize, but the normalized 2012 is 1497.

Right.

Then the outlook is 1475 to 1525.

Is that the comparable number that we should think about when we are trying to get to your 3% volume target that we were looking from?

I think the point is the idea was in order to balance cash against dividend and CapEx, cash-in against dividend and CapEx, you would be growing volumes and margins at around, I think it was 3% per year each.

Shouldn't I just be looking at that normalized number and then looking at the outlook and wondering where's the 3% growth?

I think we've been -- we've tried to be clear in all the presentations that we've given, that the 3% to 5% is a multi-year target and that 2013 would probably be the low point in our production going forward.

We still feel like the 3% to 5% production growth long-term is the right measure for us.

Sov--

Okay.

So I guess the point you've previously made is that I shouldn't be thinking about 2013 growth.

I shouldn't have been thinking about the 2013 growth.

3% to 5%, we always kind of characterize as off the low point.

You'll begin to see evidence of production growth as we roll in towards the end of 2013.

Yes, and that's the higher margin Malaysian barrels that will begin growth towards the cash, cash in/cash out balance.

It's that.

It's also startup of the Jasmine project in the UK and startup of projects in Norway as well, combined with the continued ramp up in the Lower 48 and the oil sands.

Just to change [text] slightly, and you may want to wait for the analyst meeting to talk more about this.

But there's an open question right now about business models among big oils and whether or not global water type operations and activity really sit well with US unconventional.

Could you give your perspective on a business mix, particularly a business mix of this scale, which is so differentiated in terms of its sheer size against any other E&P?

Thanks.

Yes, it's a good question.

I think as we look at our portfolio, we've been doing this for quite some time as a Company.

We've got large project capacity and ability, so we've got the capacity to make and execute these large projects globally around the world, and we've also got a business model that really as its basis is multifunctional, integrated teams.

And we've had a separate Lower 48 organization for the last number of years that has demonstrated its ability to run and execute an exploitation model or a manufacturing model.

So when I look at the organization, Paul, I look at a group where we can compare ourselves to the smaller independents, whether it's the Eagle Ford or Permian or Bakken, we look across the fence line and we're competing, and we're in a low quartile position relative to how those folks are executing their plans.

And then we have the capacity to build very large projects around the world, whether it's LNG, oil sands, deep water projects off Saba or in the Gulf of Mexico, here at home.

So I think it adds the diversity, the diversification, the global part of the portfolio just adds a lot of capacity and something that we're interested in.

So it's -- we like a mix of high deliverability and scalable resource, and that's what we're building in the Company.

Okay.

Thanks very much.

Ed Westlake, Credit Suisse.

Just coming back to the longer-term growth, I guess this 1.8 million barrels a day in the longer term is still intact as the shale and the international projects come on stream in 2016?

That's correct.

That's correct.

Yes, and then how many rigs have you got running in the Permian for this year?

Permian, I'm not sure how many we have running in the Permian.

Right now, we're focused on the Permian on our, two things, our conventional developments.

We've got a significant amount of activity going on in conventional.

And we have one or two rigs drilling up the test in the unconventional plays in the Midland and Delaware Basin.

The exact rig count, I don't have off the top of my head in the Permian.

That's all right.

I've got it here.

On the conventional, we exited the year with four rigs running, and we've announced, we've got rigs running, testing some of the unconventionals as well.

But that would be -- we ran -- that's about our run rate for the year, four to five.

When I look at the 1.8 million, how much roughly in volume terms are you including, say, from the Permian, from this Niobrara sweet spot or from the Canada non conventional plays that you're testing this year?

We'll go through all of that, Ed, at the analyst meeting.

We've shown you throughout the year our production, our multi-year production levels from all our segments, and we'll provide that, as well as a bit of a deeper dive into our sub play production outlooks as well.

If you can hold on for that, we would appreciate it.

Yes, I'm just trying to gauge, when I look at that 1.8 million, how much additional shale upside there is beyond the 1.8 million.

I guess I'll have to wait for that until the analyst day.

There's a lot of upside, depending on the pace of the program is the way to think about it.

What we have in here right now, what we've had since April is actually, we've laid it out pretty carefully.

It assumes a capital, it assumes kind of a steady ramp in these, and so what remains is how quickly we go at these programs.

We'll feed you more in February, Ed.

Great.

And then on the disposal side, obviously great execution so far.

And I guess with the cash receipts coming in, there's no pressure to be aggressive on some of the Canadian Oil Sands or further equity in APLNG.

But I just wondered if there was any update on the timing of those potential sales, whether they were still in your thought process.

Well, thanks Ed, no.

We still continue to look for options to diluted APLNG and probably reduce some of our Canadian Oil Sands exposure.

We have a very large position up there that we know we won't move forward developing some of that 100%.

So no, we're still looking at those options, but haven't obviously announced anything yet.

Okay.

Thanks very much.

Kate Minyard, JPMorgan.

Just a couple of questions.

The first one, just for clarification in terms of just modeling the year going forward, I know you talked about the down time in 2Q and 3Q and also have indicated that you'll give some more clarity around the 2013 production guidance at the late February analyst meeting.

But can you talk a little bit about just in terms of modeling the quarters out correctly, the -- maybe the extent of the downtime in some of the regions in 2Q and 3Q?

Are there any countries where we'll be looking at assets being offline for an entire of either of those quarters, or can you give us a sense as to kind of the magnitude of the dip in some of the regions?

Yes, the, the area where we have, the segment where we have the biggest differential downtime compared to normal activities is in Europe.

And it's associated with tying in the new growth projects, Ekofisk, Eldfisk and Jasmine.

So, for example, at Ekofisk, we're going to see about 30% more downtime than we usually see, so maybe 28 days of downtime at Ekofisk.

And at Eldfisk, we'll see close to two months of downtime for the [burn field] activity that needs to go on to tie in Eldfisk II.

And then at J-Block, where we're tying in the Jasmine project and we're going to have over a month of downtime there, whereas a typical downtime would be about 14 days at J-Block.

So they -- the differential downtime is mostly in Europe and associated with these tie-ins.

Is that helpful, Kate?

Yes, that's very helpful.

Thanks very much.

And then just looking at, just kind of some of the margin growth going forward, you've talked about margin improvement across the portfolio coming from factors such as mix shift and controllable costs.

We also saw a cash margin contribution on a per BOE basis that declined about, I guess almost 10% or so from 2011 to 2012.

I know a lot of that's related to lower natural gas pricing, lower NGLs and lower bitumen in North America.

But can you talk about the factors that would be driving the further cash margin improvement?

How much of those factors actually manifested what you were able to control as we move from 2011 to 2012 that may have just been robbed by some of the commodity price shifts and what we'll be looking for in 2013 as we look for an uptick in cash margins?

So cash margin growth very much is going to follow production growth.

If you think about what we're doing in our portfolios, we're adding new production in areas where the margins are higher than our current production.

You haven't really, you haven't seen margin growth yet because you haven't really seen production growth yet.

So as we continue to add production in the Lower 48, as we add, as we start up LNG projects, as we start up the Malaysia projects, as we start up these projects we were just talking about in the North Sea, and you see increased production, that's when you really are going to have noticeable margin growth as well.

This year, I think as you have correctly summarized, we did see degradation in cash margins over 2011 to 2012, but that really is driven primarily by the significant drops we saw in natural gas prices and NGL prices and bitumen prices.

When we always talk about margin growth, we talk about margin growth as if whatever price assumption you have, if you just assume that prices are constant across time, that we would see per barrel margins growing in this 3% to 5%.

And that, again, is over a multi-year time period as we bring on these growth projects.

Okay.

All right.

And then just one final question, I know you talked about the F&D estimate potentially coming later, but can you give us a sense as to how it might compare with 2012 -- excuse me, with 2011 directionally, or how it also might compare with the cash contribution per BOE that we saw in 2012?

And I'll leave it there.

Thanks.

That's another item that I think we would just say that we will give you some updates in February.

You also see some of this as we file our 10-K in late February as well.

We're kind of working through those numbers now.

I think we would rather just give that guidance in February.

Sure.

Okay.

Thank you very much.

Roger Read, Wells Fargo.

Roger, if you are on mute, can you unmute your phone?

Okay.

We will move on.

John Herrlin, Societe Generale.

Three quick ones.

In 2011, you ended with about 29% of your proven reserves, Conoco's proven reserves being PUDs.

You booked a lot of unconventionals this year.

How -- can you say approximately how high your PUD count will rise?

Because historically Conoco's been very underbooked vis-a-vis peers.

So with the booking we announced today, our PUD percentage is about 35%.

Okay.

So you're still under.

That's fine.

Yes, and it's actually dominated by the oil sands.

Sure.

That represents about 60% of our PUDs.

More detail will be forthcoming on that.

No, that's fine.

You're still way under.

Regarding benchmarking that Ryan mentioned in the unconventional plays, could you be a little bit more specific on how you're doing on, say, the Eagle Ford and Bakken vis-a-vis a lot of the other smaller E&Ps?

That's something that we're going to give more in depth analysis on at the end of next month at the analyst meeting.

It's maybe a bit too much detail for the call.

But we will get more detail at that time.

Okay.

Well, it was worth a shot.

Last one for me is Angola.

You said you ran seismic, you processed some of the seismic.

How thick's the salt there for the presalt plays?

Just curious.

Well off the top of my head, I don't know the thickness.

There clearly is -- it's got similarities to the Brazilian side.

You just -- they were together at the time all this was deposited, so they -- but the number off the top of my head, I don't know.

But the seismic is looking very encouraging.

I think you're aware of this, just initials on the graphic on that slide, we're just outboard of the Cameia discovery.

So we know we have a working petroleum system.

The seismic looks encouraging from the potential of identifying these carbonate buildups that form the play on the Brazilian side of the margin.

So we are encouraged and we are looking forward to getting drilling there.

Great.

That's it for me.

Thank you.

We'll take one more question, operator.

We're running a little long here, but let's take one more.

Paul Cheng, Barclays.

Several quick ones.

Ryan, in addition to you guys looking at oil sand and APLNG maybe diluting the interest, is there any other major asset that you guys still considering or that, pretty much that the asset sales program would be largely done at this point?

Well, Paul, we are always looking at the portfolio and making sure that the assets that we have in the future investments that are in those assets compete in the portfolio.

So, it's things like Cedar Creek Anticline that was an opportunity that presented itself, where we got full value.

We looked at the future investments in that particular asset that made more sense to the purchaser than they did to us, didn't compete in our portfolio.

So even though it wasn't one that was identified and we had talked about, it was an opportunity where we got, where we felt like we got full value and got to redeploy those proceeds and capital opportunities that are higher returns for us going forward.

So we've talked about wanting to reduce our oil sands footprint a little bit and some further dilution at APLNG.

We're still working on those, but any other specific assets, it would be premature to say anything about that.

Well, along that line, one of your smaller competitors and an activist that has some [firework] recently, and I think one of the suggestion from the activist is that maybe it's better off that you break up the company between the shale Oil, which will be having a much higher multiple compared to the rest of the company.

One may argue that that could potentially also apply to ConocoPhillips, that the oil sand and the shale oil would be high multiple.

I suppose that based on how you answered the previous question, that this is not an option that you guys believe is attractive to you.

Just wanted to make sure that we understand.

Yes, Paul, you know, we've -- yes, I appreciate it.

We all read the papers these days and see what's going on.

I think as we came out as an independent company, we laid out our plans.

We told the shareholders what we're trying to do to grow this company and improve the returns and still pay a compelling dividend back to the shareholders.

That's what we're focused on, is executing our plan.

We think we're on the front end of that plan.

We delivered in 2012.

I think shareholders should be pretty happy with what we did in 2012.

We realized we reached a lower point in our production in 2013.

We've said that all along, because we've said we're going to core up the portfolio and sell some assets.

We look at our future.

We look at the investments that we're making in the growth projects that we've talked about today.

Those are compelling investments that are high return.

They will move our margins.

They will move our growth.

And then we're doing some exciting things on the exploration side.

So we think there's an exciting future.

We think diversification globally and amongst all these different resource types and asset types is important for a company our size.

Okay.

A final one for me just for Matt.

If I look at this year, 2012 we sort of [repaid].

Excluding oil sand for the rest of the portfolio as we are pacing about 82%, any idea that over the next couple of years, should we assume some of the 400 million to 500 million barrel a year of the reserve addition from oil sand is a reasonable run rate, or that 2012 is somewhat unique and we are going to see a slowdown on that addition rate.

So the bookings in the oil sand essentially follow the project sanctions.

So as we -- that tends to be lumpy, depending on how we go through the development phases.

I wouldn't expect it to be consistent at all over the next several years.

It will be lumpy as we go through the project sanction fees.

We do have a significant remaining resource base on oil sands that hasn't been converted to reserves yet.

But we don't expect a consistent booking from year to year because it has to follow the project sanctions.

Sure.

And based on the project backlog that you think the next couple of years that the [recircle] can be maybe substantially less or about the same or it's going to be higher?

We continue to expect to replace more than 100% of our reserves on a -- as we go forward, as we develop the oil sands, the unconventionals and the other projects we have in our portfolio.

But it's not going to be consistent from year to year.

Over the long run, we will be replacing more than 100% of our reserves for the next five years.

Thank you.

Let's go ahead and wrap it up here.

I appreciate everybody sticking around a little bit.

As a reminder, we will be in New York on February 28, and we look forward to seeing you there.

Vlad and I are available for any further follow-up questions that you might have and appreciate your time.

Operator, we're ready to wind it up here.

Thank you, and thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.

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

This news release contains forward-looking statements.

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

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