Ellen DeSanctis – Vice President Investor Relations and Communications Ryan M. Lance – Chairman and Chief Executive Officer Jeff Sheets – Executive Vice President, Finance, and Chief Financial Officer Matt Fox – Executive Vice President, Exploration and Production

Faisel Khan – Citigroup Doug Leggate – Bank of America Merrill Lynch Doug Terreson – ISI Group Paul Sankey – Deutsche Bank Edward Westlake – Credit Suisse Kate Minyard – JPMorgan John Herrlin – Societe Generale Paul Cheng – Barclays Capital

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 will 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 to this call will be also posted later today, we hope not by tomorrow. And then in the final reminder on Page 2 of our presentation deck, you will find our Safe Harbor statements. 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 statements and in our periodic filings with the SEC. With that out of the way, I’ll turn the call over to Ryan Lance. Ryan M. Lance: Thank you, Ellen, and good afternoon everyone, and thank you for joining us today. Let me kick off the meeting today with a review of our key 2012 highlights and accomplishments. And certainly the strategic highlight of the year was the spin-off our downstream business, Phillips 66, which occurred in May. And following that transaction, we emerged as North America’s largest independent E&P Company. And we set out to combine our world-class assets, technology, financial strength and workforce with an intense focus on the E&P business. 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 or identified growth programs, but on executing a major divestiture program to high-grade asset base. And 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. And a key part of our ongoing value proposition is to maintain a 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 are on track to deliver the plans we laid out in April of last year. We recognize that 2013 would be a low point in production and we expect growth in the fourth quarter due to major project start-ups 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 grow 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 in 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 workforce. Despite the 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. So 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 four. 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 from an Asian 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 interest in the Kashagan Field and the Algeria and Nigeria business units, we accreted 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 the 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, our adjusted earnings were down by 14%, primarily due to lower liquids prices, higher DD&A expense, which was offset primarily by higher volumes. Our 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 plant maintenance. The year-over-year average realized prices for the quarter were down about $3 a barrel, but up about $1 in the third quarter compared to fourth quarter. Our bitumen and NGL prices declined during the year and remained weak. In the fourth quarter, bitumen represented about 7% of our production in North American NGL has also represented about 7% of world wide production. Clearly, it’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 cost 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, production from continuing operations and from discontinued operations, and I’ll step through the key items here, and Matt is 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 expectation. So starting at the left of the chart, 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 Statjford and Alba fields in the North Sea, some Western Canadian assets and NMG, a joint venture in Russia. : 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 developments. Improved drilling programs 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 the 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. So this represents a 6% growth overall. And additionally, liquids as a percent of our portfolio from continuing operation increased between the two periods. So if you turn to slide 6, we’ll cover some production guidance for 2013. On the left of this chart is our 2011 total production of 1.578 million BOE per day. I want to take you to 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 the 51,000 BOEs per today to discontinued operations, which again is the assets in Algeria and Nigeria. Next, we removed 70,000 BOE everyday 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 our final 13,000 BOE per day, which represents production from this asset during 2012. So the resulting 2012 production of 1.497 million BOE per day represents the normalized year 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 a range of 1.475 million BOE to 1.525 million BOE per day. On the first quarter, we expect to still have Algeria, Nigeria, and Cedar Creek in our portfolio. Therefore, we provided you with the all in first quarter production outlook of 1.582 million BOE to 1.6 million BOE per day, which includes about 40,000per day for discontinued operations. The second and third quarters of 2013 will be negatively impacted by both normal seasonality and planned maintenance. But additionally, with some new projects coming on later in the year, we’ll have downtime associated with projects high-end. And 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 the prior guidance that we given around hitting our 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 of a prior period as we continue 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 2011. We reached a significant milestone during the quarter in the Eagle Ford. Production exceeded a 100,000 BOE per day on a peak daily basis and averaged 89,000 BOE per day. In addition to the Eagle Ford, the 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 of 2011, the weakness in crude and NGL prices drove earnings lower year-over-year and fourth quarter adjusted earnings were $157 million. Next, we 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 the 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 and lower year-over-year earnings. We expect bitumen prices to remain weak for another quarter or so, until additional heavy refining capacity comes on line. 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 on just due to normal field decline. Sequentially, higher production resulted in a higher sales volume and this earnings benefit was partially offset by higher production related cost, including our petroleum production taxes and DD&A. Segment adjusted earnings for the quarter were $595 million. So 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 represent quarterly sales compared to quarterly production. So this should help illustrate of these timing differences. All these timing differences net out over time that 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 result in lower earnings relative to the production level, and then we have the opposite effect in the third quarter of 2012, when sales exceeded production and that contributed positive to earnings. I’ll turn now to slide 10 and talk about the Asia-Pacific and Middle East segment. Asia-Pacific and Middle East continue 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, where we also had new production for Gumusut project in Malaysia and 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 for the first quarter 2013 earnings from the reversely timing affects 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 Cocktail or JCC prices. And these prices impact were partially offset by the benefits of higher sales volumes. Europe is the next segment and 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 Aquitaine C 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 start ups that are underway. These projects will mitigate declines and bring attractive margins with the growth. And 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 this segment. So the assets that are now in this segment includes 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 and this increase was driven primarily by Libya coming back on line which more than offset the impact on NMG 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 and we used the proceeds from dispositions to pay down commercial paper and other maturing debt. So 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 result of lower prices, particularly for North American natural gas and NGLs and Canadian bitumen. And also, we are impacted by lower production levels, which were primarily result 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 a lower share count due to the $5 million of shares repurchased in 2012. Our return on capital employed or ROCE numbers trended lower along with adjusted earnings and capital employed growing slightly from 2011 to 2012 as we are making significant investments to generate future production and margin growth. Cash contribution for BOE and income for 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 in the average of our current portfolio. And next, I’ll step through the company’s 2012 cash flow on slide 15. So just a quick comment about this waterfall that’s shown is just Algeria, 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 to $15.2 billion, excluding working capital changes in 2012, which were a $1.3 billion use of cash. We also generated $2.1 billion in proceeds from asset disposition. 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 shore show in the waterfall is discontinued operations related to the spin-up of Phillips 66, which includes the special distribution and all the other cash flows related to Phillips 66. Moving to the right on the waterfall, we repurchased 5.1 billion of our shares and paid $3.3 billion in dividend, so over $8 billion in total distribution to shareholders in 2012. Debt and other of $600 million include some deposits we received from our recently announced asset disposition. So summing across, we ended up 2012 with $4.4 billion of cash and restricted cash. And also just to note on the slide on the upper right, inside the box, our year-end debt was $21.7 billion, which represents 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 operation 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 reserve replacement rate of 156%. Our total reserve additions 497 million barrels came from Canada, as a result of project sanctions in the oil sands. Lower 48 was the second largest source of organic reserve additions with 293 million barrels and these are 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 reserve replacement rate was 142% and this takes into account the impact of dispositions completely during the year that reduced reserves by 83 million BOE. We’ll provide more detail on the reserve performance, including the costs in current and the forthcoming 10-K. We’re sufficed it to say that we are really pleased with these results and we believe that our 40 plus billion barrel resource base hold 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 we 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 the milestone of over 100,000 BOE per day of peak daily rates in the fourth quarter. This is a tremendous accomplishment and credit to the entire Eagle Ford team. During 2012, we adopted 17 rigs drilling the play. Late in the year, we began to reduce the rig count due to improved drilling efficiencies and the growing backlog of uncompleted wells, and we exited the year with a 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 are waiting tie in. Completing and connecting this backlog of wells is a key focus in 2013 along with achievement held by production status. We expect to complete the drilling phase of Acreage Capture by mid 2013 and we will reach field held by production status by year end. During the year, we’ll gradually phase into a 100% pad drilling in the play with full pad drilling expected in 2014. On the infrastructure side of the business, we currently chuck 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 are 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 and 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 reduce over the coming months. Moving to the Bakken, we produced 24,000 BOE per day in the fourth quarter and we exited the year with 9 rigs operating in the play. In 2012, we completed a total of a 187 operated and non-operated wells. We have 34 operated wells waiting in 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 position. 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 the 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. So we have now built over 130,000 net acres and what we believe is a sweet spot compatible to the [war-torn] area about half of this acreage was added in the fourth quarter. And as shown in the map, it’s a contiguous position that provides scale benefits and development flexibility going forward. We’ve 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 be encouraging and that 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 deepwater position there. During the quarter, we were awarded 20,800 acres in the central Gulf of Mexico lease sale, and we were also a pattern high bidder for 348,000 acres in the western Gulf of Mexico lease sale. These additions bring our current deepwater position to over 1.9 million acres making us the sixth largest acreage holder in the Gulf. I’m not sure everyone recognizes just as substantial our position we have developed here. Currently, we’re drilling two partner operated wells in the deepwater Coronado and Shenandoah. Hummer a low-cost fireman was declared the dry hole in fourth quarter. We expect this quarter 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 is an opportunity to divest the decline in 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 will talk about the Canada segment. The 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 us the second-largest SAGD producer in the oil sands. Currently, we’re executing seven major projects across our FCCO joint venture and Surmont. We recently sanctioned Narrows Lake Phase A and Christina Lake Phase F. We are 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 are running 16 rigs drilling on our held by production acreage that are focused on liquids proven place such as the Montney, Glauconite and Cardium. We’re also testing other unconventional exploration opportunities within and outside our core areas in Western Canada. For example, we’re currently drilling in the Duvernay play where we have a 112,000 net acres. We drilled and completed one horizontal well recently and are currently drilling a second well with three additional wells planned for this year. We also have drilling underway in our 120,000 net acre position in the (inaudible) 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 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 segments 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 is 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 the first ever Octo-lateral CTD well. That’s a well with 8 different horizontal sections that was guided using a high-quality 4D seismic survey. In the fourth quarter, we sanctioned the Alpine West CD5 Project and expect production to startup in 2016. As we 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 cost 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 are 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 and production storage in our floating facility at the Katy 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 Malikai project, where we expect first production in 2017, and development activities also underway in Siakap North-Petai and KBB projects. Also in Malaysia, we recently executed the production sharing contract for exploration Block SB311 offshore Sabah. This block covers about 250,000 acres and we are the operator with a 40% working interest. The PSC has a three-year exploration period with the 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 8,000 BOE per day between now and 2014 as we drill additional wells from Britannia platforms, and this new production is expected to more than offset decline to Panyu. Also in China, we recently announced the joint study agreement with Sinopec to access shale gas opportunities in Qi Jiang Block in the Sichuan province. The block covers an area of approximately 1 million acres, and the study will be carried 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 Zephyros-1 well, the second of the five-well appraisal program at Poseidon and in the Canning Basin, we are drilling a second exploration well to test as a 11 million acre position. So this is a very active segment for us just now and we are 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 are 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 off-line in the fourth quarter. The East Irish Sea is still shut in, but we think once your facility is upgraded, it 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. The Ekofisk South, the topside structural sections are being completed and first production is expected at the end of this year. Eldfisk II is also on track to production startup 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 operated on a three Baltic were western concessions. Just a note, we have significant downtime in 2013 within this segment as we tie in 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 will cover is other international on slide 22. There was a lot of activity in this segment 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 this slide, we’ve shown 2012 average production rates and year end 2012 results for these assets. During the fourth quarter, Nigeria was severely impacted by flooding in the Niger Delta and 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 plants to drill four exploration wells starting in 2014. The seismic results in our Angola blocks are really encouraging and we look forward to getting underway on drilling in this significant new exploration opportunity. I will conclude my prepared remarks by reiterating the things you 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 will turn the call over to Ryan for some closing comments. Ryan M. Lance: Thank you, Matt. So 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 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. And these proceeds will largely be directed toward executing our drilling programs and our major growth projects. As we have told you throughout the year, we have identified projects in hand and underway that will materially change the growth trajectory of our company over the next few years, and it’s important that we execute on these activity. 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. That meeting will 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.

Thank you. (Operator Instructions) And our first question is from Faisel Khan of Citigroup. Please go ahead. Faisel Khan – Citigroup: Hi, good morning. 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 and North American production. So can you just clarify what’s going 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 have 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 at this point. 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 as part of our portfolio long term. So we’re trying to layout 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 have – what some people have had – probably have in their models for the amount of production that’s going out on dispositions as well. Faisel Khan – Citigroup: Okay. Go ahead.

Faisel, let me jump in here quickly, this is Ellen. I appreciate again the question. If you look at what we had in April for 2012 and what we had in April for 2013 and you kind of averaged it over the couple of years, it ends up being that we were – that the timing of divestitures actually ends up slipping from 2012 a little bit to 2013. And so if you look at it on a couple of 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 just provided is sort of 1510, they had the noise out of this quarter compared to the fourth quarter to get to this guidance we provided. It will be very significant growth in quarter-over-quarter 2013 to 2012. We’ll provide all of these updates at the Analyst Meeting, but I 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. Ryan M. Lance: Yeah. So I think as an important point is that, we are going to start seeing production growth in 2013 particularly late in the year or we have startups happening in the North Sea and the continued ramp up in oil sands continue to ramp up in the oil shale and right and plus the startup of projects in Malaysia. Faisel Khan - Citigroup: Okay. Great. And just one other question, on the capital program, it looks like (inaudible) in – on slide 15 that are roughly $800 million in capital was associated with the asset divestitures in 2012. Is that roughly the same number in 2013?

It’s probably a little lower than that in 2013. But it really much depends on when assets actually end up leaving the portfolio. So it will be all through the year. We kind of need to be giving updates on how we see the capital program playing out this year. Faisel Khan - Citigroup: Okay. The last question from 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?

I think there applies a little bit of long term, there will be moves to faint alternative markets for bitumen from the Canadian oil sands. I think that’s a strategic comparative of the Canadian government, not just the bay oil companies’ work in the oil sands, so we will see that happening over time. Of course, this is a short-term issue that we’re facing just now, very much associated with refining constrains like BP is fighting refinery. So don’t expect these daily rate differentials to be sustained for more than in the next few months. In the long term, other markets will be developed. Faisel Khan – Citigroup: Okay, fair enough. Thanks guys.

Thanks, Faisel. Ryan M. Lance: Thanks, Faisel.

Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch: Thanks. Good morning everybody.

Hi, Doug. Doug Leggate – Bank of America Merrill Lynch: I have a couple of quick ones please. Jeff, could you – 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 with those assets. Can you help us with the operating cash flow impact? And if you could clarify whether or not the 15.7, 15.6, 15.7 target for this year for spending assumes the asset sales are out for the whole year, or if not number – not just higher a (inaudible) 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 a good outcome of Kazakhstan during 2012 – the number that was in 2012, I think that was probably the half of two-thirds of the number that was in – on the $800 million. As far as what’s in for 2013, we are pursing a lot of different capital projects with fairly heavy spend. And there is going to be several things that could impact what our capital program ultimately been, ends up being at the – 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 kind of continually updating that as we see the year develop. Doug Leggate – Bank of America Merrill Lynch: Thanks, Jeff. I guess my follow-up is a – I guess relates to the exploration program, just to put some context around this, German had spent the last decades, trying to secure resources and build up very large drilling inventory I guess. And obviously, there is a lot of spending to achieve that, but now you are in a position where you are still underfunded relative to your CapEx and your dividends that you are 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, and I’ll leave it there? Thanks. Ryan M. Lance: Yeah, Doug, this is Ryan. I think as we look out and think about the future opportunity, I think with this unconventional revolution that we are seeing in North America right now, and some of the technology advances in the deepwater arenas that are becoming pretty perspective. It’s kind of in my view turn from a bid of resource scarcity that was leading to a lot of merger synergies over the last 10 or 12 years and resource capture into a view now. But the resources aren’t so scares, and there is a bit more abandon, 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 technologies done on the deepwater side. And we just think that growing organically, there is the opportunity set to go do that and the option value associated with growing organically is, we thought better in our portfolio then 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. Doug Leggate – Bank of America Merrill Lynch: I appreciate the answer, Ryan. Thanks.

Thanks, Doug.

Thank you. Our next question is from Doug Terreson of ISI. Please go ahead. Doug Terreson – ISI Group: Good morning, everybody. Ryan M. Lance: Good morning, Doug.

Good morning, Doug. Doug Terreson – ISI Group: My question is one the mix shift that appears to be underway, the company meaning, but the size – there are profitability in the United States, it appears that there is going to be some positive mix effects overseas too. And on this point, my questions is, whether the earning from the discontinued operations, which I think we’re listed is close to zero for 2011 and 2012, or 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? I mean what I’m trying to get to is, what is the approximate earnings loss and return for the $10 billion of pre-tax proceeds that you likely to receive? Ryan M. Lance: Well, the fourth quarter was a challenging, again (inaudible) is Algeria, Nigeria and Kashagan assets, which of course not in operation yet, income or cash flow from these assets. So the adjusted earnings as we mentioned from these assets were $0.02 a share or $27 million during the fourth quarter. That was probably a particularly low number though because of the impact that Matt talked about in the flooding in Nigeria impacted 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. Doug Terreson – ISI Group: And Jeff do you have any insight for us on the tax implications of these divestitures. You highlighted $10 billion of sales proceeds and doing out the cash proceeds might be?

Yeah, the cash proceeds are going to be close to the numbers that we’ve highlighted. These transactions [currently] may be very tax efficient. Doug Terreson – ISI Group: Great. You’re a great value. And also I have a question for Ryan, Ryan you’ve spent a lot of time in Alaska and it seems like there is moment on the new fiscal regimen up there. So my question is, whether or not you feel that just most recent movement is real and if so whether or not the investment opportunity could be meaningful for the company. Ryan M. Lance: Yeah, I do. I think Fed 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 understands the lack of competitiveness and the fact that the current taxing system really takes away a lot of competitiveness instead of other Alaskan opportunities out there. So I think he is serious about trying to push something through the legislature. I think he has proposed some fiscal on the oil side, he has put a proposal out there. I don’t think – it’s going to be a tough hall through the legislature, but I also think that the – 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 the changing fiscal system in Alaska. Part of that side I think to the work that we are doing on ANS Gas as well and progressing the work on a potential LNG project. So part of that’s tied into some of these as well, but I’m probably slightly encouraged, but it’s a long way till May when the session ends. Doug Terreson – ISI Group: Great. Thanks a lot. Ryan M. Lance: Thank you.

Thanks, Doug.

Thank you. Our next question is from Paul Sankey of Deutsche Bank. Please go ahead. Paul Sankey – Deutsche Bank: Hi, good morning, everyone.

Good morning. Ryan M. Lance: Good morning. Paul Sankey – Deutsche Bank: I’m sorry to be confused about this, but if I look at the slide 6 and you may well have explained this and I apologize, but the normalized 2012 is 1,497?

Right. Paul Sankey – Deutsche Bank: And then the outlook is 1,475 to 1,525. 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 it? I think the point is that the idea was to – in order to balance cash against dividend and then 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 is the 3% growth?

I think we’ve been – we try to be clear in all the presentations that we’ve given. The 3% to 5% is a multi-year target and the 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. Paul Sankey – Deutsche Bank: Okay. So I guess the point that you previously made is that, I shouldn’t be thinking about 2013 growth, why shouldn’t I have been thinking about 2013 growth, yeah.

Three to five we always kind of characterize as of a low point.

So you will begin to see evidence of production growth as we are rolling towards the end of 2013. Paul Sankey – Deutsche Bank: Yeah. And that’s the high margin Malaysian barrels that will begin to road towards the cash in, cash out balance?

It’s there. It’s also start up of the Jasmine project in the UK and then startup of projects in Norway as well, combined with the continued ramp up in the Lower 48 and the oil sands. Paul Sankey – Deutsche Bank: Just to change tax lightly and you may want to wait for the Analyst Meeting to talk more about this, but there is an open question right now about business models amongst big oils and whether or not your global deepwater type operations and activity really fit well with U.S. unconventional. Could you give your perspective on the business mix, particularly business mix at this scale which is so differentiated in terms of its sheer size against any of the EMP? Thanks.

Yeah, it’s a good question. I think as we look at our portfolio, we’ve been doing this for quite sometime. As a company, we’ve got large project capacity and capability. So we have got the capacity to make and execute these large projects globally around the world. And we’ve also got a business model that really at – 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 manufacturing model. So when I look at the organization, Paul, I look at a group, or we can compare ourselves to the smaller independents weather it’s 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, deepwater projects, Al Sabo or in the Gulf of Mexico here at home. So I think it had the diversity, the diversification, the global part of the portfolio just adds a lot of capacity and something that we are interested in. So we like the mix of high deliverability and scalable recourse and that’s what we’re building in the company. Paul Sankey – Deutsche Bank: Okay. Thanks very much.

Thanks, Paul.

Thank you. Our next question is from Ed Westlake of Credit Suisse. Please go ahead. Edward Westlake – Credit Suisse: Yes, good morning, everyone. Just coming back to the longer-term growth, I mean, I guess this 1.8 billion barrels a day in the longer-term is still intact as the shale and the international projects come on stream in 2016? Ryan M. Lance: That’s correct.

That’s correct. Edward Westlake – Credit Suisse: Yeah. And then how many rigs you got running in the Permian for this year?

In the Permian, I’m not sure how many we have run in the Permian. But right now we are focused on the Permian on two things conventional developments, with a significant amount of activity going on in conventional, and we have one or two rigs drilling up the testing the unconventional plays in the Midland and Delaware basin. The exact rig count is, now I don’t have it on top of my head in the Permian. Edward Westlake – Credit Suisse: Okay.

Yeah, Ed, we’ve got on the conventional, we’ve got – we exited the year with four rigs running and then we’ve got – 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. Edward Westlake – Credit Suisse: And when I look at the 1.8, I mean 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 are testing this year?

We’ll go through all that Ed at the Analyst Meeting. We’ve shown you throughout the year our multi-year production levels from all our segments and we’ll provide that as well as bit of a deeper dive into our sub play production outlooks as well. So if you can hold on for that, would appreciate it. Edward Westlake – Credit Suisse: Yeah, I’m just trying to gage when I look at that 1.8, how much additional shale upside there is beyond the 1.8, like I still have to wait for that until the Analyst Day.

There is 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 a steady ramp in these and so what remains is how quickly do we go at these programs. Ryan M. Lance: We’ll feed you more in February Ed. Edward Westlake – Credit Suisse: Right. And then on the disposal side, I mean, obviously, great execution so far and I guess with the cash proceeds 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.

Thanks, Ed. We now still continue to look for options to diluted APLNG and 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 a 100%. So now we’re still looking at those options, but haven’t obviously announced anything yet. Edward Westlake – Credit Suisse: Okay, thanks very much. Ryan M. Lance: Thank you.

Thank you. Our next question is from Kate Minyard of JPMorgan. Please go ahead. Kate Minyard – JPMorgan: Hi, good morning, everyone. 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 downtime in 2Q and 3Q, and also you have indicated that, you’ll give some more clarity around the 2013 production guidance at the late February Analyst Meeting. But can you just talk a little bit about in terms of modeling the quarters out correctly, maybe to the extent of the downtime in some of the regions in 2Q and 3Q? I mean are there any countries where we will be looking at assets being off-line for an entire of either of these quarters. Can you give us a sense as to kind of the magnitude of the difference in some other regions?

Yeah, the area where we had a segment, where we have the biggest differential downtime compared to normal activities is in Europe. And this associated with tying in the new growth projects at Ekofisk, Eldfisk, and Jasmine. So, for example, in Ekofisk, we’re going to see about 70% more downtime than we usually see, so maybe 28 days of downtime Ekofisk. In Eldfisk, we’ll see close to two months of downtime for the Brownfield activities and use to go on to tie-in Eldfisk II. And then a G Block where we are tying in the Jasmine project, and we’re going to have over a months of downtime there, whereas typical downtime would be about 14 days at G Block. So the differential downtime is mostly in Europe and associated with these tie-ins. Is that helpful, Kate? Kate Minyard – JPMorgan: Yeah. No, 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 per BOE basis that declined about I guess almost 10% or so from 2011 to 2012. I know 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 improvements, 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 dropped by some of the commodity price shift, and what we will be looking for in 2013 as we look for an uptick in cash margins.

Cash margin growth very much is going to follow production growth. Because you think about what we’re doing in our portfolio is, we’re adding new production in areas where the margins are higher than our current production. So 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 startup LNG projects, as we startup the Malaysia projects, as we startup 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’ve just correctly summarized, we did see the 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. So when we always talk about margin growth, we talk about margin growth if you – whatever prices (inaudible) the same prices are constant across time that we would see per barrel margins growing in this 3% to 5% and that’s again is over a multiyear time period as we bring on these growth projects. Kate Minyard – JP Morgan: 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 with there. Thanks.

So 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. So may be we’d rather just give that guidance in February. Kate Minyard – JP Morgan: Sure. Okay, thank you very much.

Thanks, Kate.

Thank you. Our next question is from Roger Reed of Wells Fargo. Please go ahead. Ryan M. Lance: Morning, Roger.

Roger, if you are on mute, can you un-mute your phone? Okay, we will move on. The next question is from John Herrlin of Societe Generale. Please go ahead. John Herrlin – Societe Generale: Good morning. Three quick ones. In 2011, you ended with about 29% of your proven reserves – Conoco’s proving reserves being PUDs. You booked a lot of unconventionals this year. Can you say approximately how high your PUD count will rise because historically Conoco has been very under booked these years?

So with our – the booking that we announced today, PUD percentage is about 35%. John Herrlin – Societe Generale: Okay. So you’re still under that line?

Yeah. And this is actually dominated by the oil sands. John Herrlin – Societe Generale: Sure.

That represents about 60% of our PUDs, but we think more detail will become – before coming on that. John Herrlin – Societe Generale: No, that’s fine, you’re still under. Regarding benchmarking, that Ryan mentioned in the unconventional plays, could you be a little bit more specific on how you are doing inside the Eagle Ford and Bakken vis-à-vis a lot of the smaller entities. Ryan M. Lance: Again, that’s something that we are going to get more in-depth analysis on the end of next month in the Analyst Meeting. It may be a bit too much detail for the call, but we will get more detail at that time. John Herrlin – Societe Generale: Okay, well, it’s worth of shot. Last one from me is Angola, you said you ran seismic, you’ve processed some of the seismic, how fixed its out there for the pre-salt plays, I’m just curious.

On the top of my head, I don’t know the thickness. They clearly is – it’s got similarities to the Brazilian side. I mean, they were together, they were paying all those, this was the positive. So the number on top of my head, I don’t know. The seismic though is looking very encouraging. I think you are aware of this, just issues and 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 perform the play on the Brazilian side of the margin. So we are encouraged and we are looking forward to getting drilling there. John Herrlin – Societe Generale: Okay, great. That’s it from me. Thank you. Ryan M. Lance: Thanks, John.

Thanks, John.

Thank you.

We’ll take one more question operator. We’re running a little long here, but let’s take one more.

Our last question is from all Paul Cheng of Barclays. Please go ahead. Paul Cheng – Barclays Capital: Hey, guys. Thanks for taking my questions, several quick one. Ryan, in addition to you guys still looking at oil sand and APLNG maybe diluting the interest on, is there any other major offset that you guys still considering or there is pretty much that the other sales program would be largely done at this point? Ryan M. Lance: Well, Paul, we’re 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 its things like see Cedar Creek Anticline, there was an opportunity that presented itself or we got for value. We looked at the future investments in that particular asset. They 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 have talked about, it was an opportunity where we got – where we feel like we got full value and got to redeploy the – we will redeploy those proceeds into 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 asset size would be premature to say anything about that. Paul Cheng – Barclays Capital: Along that line, one of your smaller competitor in activeness that has some firework recently, and I think one of the suggestion from the activeness is that maybe that is better off that you put up the company between the share volume which we will be having a much higher multiple in comparing to the rest of the company. And one may argue that, that could potentially also apply to ConocoPhillips that the oil sand and the shale oil will be higher multiple. I suppose that based on the way you answered previous question, this is not an option that you guys believe is attractive to you; just want to make sure that we understand.

Paul, we’ve – 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 they have compelling dividend back to the shareholders. That’s what we’re focused on as executing our plan. We think we’re on the front end of that plan. We delivered in 2012. I think the shareholders should be pretty happy with what we did in 2012. We realized we’ll reach a lower point in our production in 2013. We set that all along, because we 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 talked about today. Those are compelling investments that are high return. They’ll move our margins, they’ll move our growth. And then we’re doing some exciting things on the exploration side. So we think there is exciting future. We think diversification globally and amongst all these different resource types and asset types is an important for our company our size. Paul Cheng – Barclays Capital: Okay. Final one from me, I guess for Matt, Matt, if I look at this year, 2012 reserve replacement, excluding oil sand for the rest of the portfolio, I guess we are facing about 82%. Any idea that over the next couple of years, should we assume some of 400 million to 500 million fell a year of the reserve addition from oil sand? Is it a reasonable one way or that 2012 is somewhat unique and we’re going to see a slowdown on that addition way?

So the bookings in the oil sands essentially flow of the project sanctions. And so as we – and that seems to be lumpy dependent on how we go – as we go through the project development thesis. So we wouldn’t expect the – to be consistent at all over the next several years, there will be lumpy as we go through the project sanction fees. We do have a significant remaining resource plays in oil sands that hasn’t been converted to reserve shale. But we don’t expect a consistent booking from year-to-year, because has to follow the project sanction. Paul Cheng – Barclays Capital: Sure, and based on the project backlog that do you think the next couple of years that the reserved booking maybe substantially less or above the same or just going to be higher?

I mean we expect to replace more than a 100% of reserves, and as we go forward, as we develop the oil sands, the unconventionals and the other projects we have in our portfolio that is not going to be consistent from year-to-year. But over the long run, we’re going to place in more than 100% of reserves for the next five years. Paul Cheng – Barclays Capital: Thank you.

Thanks, Paul. 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. Ryan and I are available for any further follow-up questions that you might have and appreciative your time. Operator, we are ready to winded up here.

Thank you. And thank you ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.