Ellen DeSanctis - VP, IR and Communications Ryan Lance - Chairman and CEO Jeff Sheets - Executive Vice President and CFO Matt Fox - Executive Vice President, Exploration and Production

Doug Terreson - ISI Group Ed Westlake - Credit Suisse Jim Sullivan - Alembic Global Advisors Paul Cheng - Barclays Blake Fernandez - Howard Weil Doug Leggate - Bank of America Merrill Lynch Faisel Khan - Citigroup Roger Read - Wells Fargo

Welcome to the Fourth Quarter 2013 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.

Thanks Christine and welcome everybody. Our executive speakers for today are Ryan Lance, our Chairman and CEO; Jeff Sheets, our Executive Vice President and CFO and Matt Fox, our Executive Vice President of Exploration and Production. They will make some prepared remarks and then of course, will take your questions. We will have folks to stick a question and one follow up today just so we can move through the queue. A couple of quick reminders. Today’s materials are available on our website and we will post the transcript of this call there soon. I also wanted to remind you we’ve previously announced that we will host our 2014 analyst meeting in New York on April 10. So look out for some additional logistical details on that. And then finally, our safe harbor statement is shown on Page 2 of today’s presentation that we will make some forward looking statements during today’s website. The statement as well as our periodic filings with the SEC outline some of the uncertainties and risks in our future performance. Now I’ll turn the call over to Ryan.

Thank you, Ellen and hello everyone and thank you for joining us today. So we just finished our first full year of an independent E&P company and all of us here at ConocoPhillips are pretty proud of what we have accomplished. 2013 was a year in which we had to achieve several strategic and operational goals to position the company for 3% to 5% volume and margin growth in 2014 and beyond. And that’s what we did. So if you turn to Slide 3, let me describe some of the highlights from this important year. Operationally, we met our production goals for the year. As importantly, we grew our reserves to fuel our future growth. As we saw it in announcement today, we achieved 179% reserve replacement ratio and grew reserves about 3%. Pretty strong results for a company of our size and certainly speaks to the quality of our asset base and our investment programs. Our 3% to 5% growth will come from major projects and development drilling programs across our operations. In 2013, we achieved start-ups in several major projects and we continued to ramp up our unconventional programs in the Lower 48. These activities will ramp up during 2014 as well and also provide strong momentum into 2015. In looking longer term, our exploration program, which is key for sustaining our future growth, we had another successful year in 2013. We announced three Deepwater Gulf of Mexico successes. We advanced our North American unconventional exploration programs and accessed additional opportunities around the growth goal. So operationally, we hit the milestones we set for ourselves in 2013 and we have positioned the company for growth. 2013 was also a strong financial year. On a full year adjusted earnings, we were at $7.1 billion, up 5% compared to 2012’s adjusted earnings. This translates to $5.70 per share for the year. Cash from operations grew year over year and we ended up 2013 with $6.5 billion of cash and short term investments on the balance sheet. Our cash margins grew 11% compared to 2012 and this reflects the fundamental shift toward liquids in our portfolio and certainly a key aspect of our value proposition. Strategically it was an active year for ConocoPhillips as well. We closed over $10 billion of non-core asset dispositions, including Kashagan and Algeria and these are certainly important steps toward high-grading our portfolio and Nigeria is really the only remaining announced asset sale to complete we hope to have that done relatively soon. During ’13, we maintained our commitment t to pay a compelling dividend. We increased our dividend by about 4.5% at midyear and remained committed to increases overtime. So in summary, ‘13 was a very successful year for the company operationally, financially and strategically. We accomplished what we set out to do, to high-grade our portfolio, to position ourselves for volume and margin growth, to access and build opportunities for future growth, maintain our financial strength and finally, deliver strong shareholder return. So let me now turn over the call to Jeff and Matt for some additional comments on 2013 and a look into 2014.

Thanks, Ryan. Well, first to recap the fourth quarter results on slide four. Fourth quarter 2013 adjusted earnings were $1.74 billion or $1.40 a share. Adjusted earnings were essentially flat to last year’s fourth and down slightly sequentially despite lower realizations. Some of the drivers in this quarter’s performance aren’t obvious, so I have the detail on those items. Embedded in this quarter earnings are weaker liquids realization in North America, reflecting wide differentials to WTI and WCS. For example, in our Lower 48 segment, our realized price for crude oil averaged 90% of WTI in Q4 2013, compared to 101% of WTI in Q4 2012. Bitumen prices were also particularly weak this quarter. Volumes for the quarter were negatively impacted by unusual weather in the Lower 48 and the North Sea which we pre-announced. We also had continued curtailment in Libya and a plan to turnaround in Qatar. And finally, the quarter benefited from lower tax expenses. Our tax expenses were lower both because of increased proportion of production in areas more favorable fiscal term, as well as an approximately $100 million benefit related to changes in tax estimates from several regions and an $85 million tax benefit related to the strengthening of the U.S. dollar against the Australian dollar. Our fourth quarter segment earnings are shown in the lower right hand side of this chart. We have provided additional details on our operating and corporate segments in the backup materials. Next I will cover full year 2013 financials on slide five. As Ryan mentioned, full year 2013 adjusted earnings were $7.1 billion or $5.70 a share and adjusted earnings were up about 5% from the full year of 2012. And this makes the point that underlying performance is improving, realizations are about flat but margins are growing due to increases in liquids production -- liquids production from places of better fiscals which was consistent with our strategy. Despite volatile pricing and basis differentials throughout the year all of our significant operating segments were profitable. We continue to believe that our diversified product and geographic splits are key to providing consistent performance overtime. That was a quick review of our reported earnings results, again there is additional information in our backup and supplemental materials. Now I’ll turn to slide six for some specific comment on production. Total production in the fourth quarter 2013 was 1.518 million BOE per day, which included 1.473 million BOE per day from continuing ops and 45,000 per day from discontinued operations. This chart shows the drivers of the change in production from continuing operations compared to the fourth quarter of 2012. Fourth quarter of 2012 production from continuing operations was 1.566 million BOE per day, adjusting for dispositions in Libya, which were 10,000 and 43,000 BOE per day, respectively. Normalized production from continuing operations was 1.513 million BOE per day in last year’s fourth quarter and that’s the middle blue bar on the chart. Moving to the right, we show the variance in downtime this quarter driven by unusual weather impacts and a month long turnaround in Qatar. Finally, you will see that growth just about offset decline. I should note that there wasn’t much of a contribution from major project startups since they came on late in the quarter, but they will start making a visible difference in our future production. The majority of our growth came from our development and major projects in the Lower 48 shale plays and the oil sands in Asia. The full year volume story is more telling, so please turn to page seven. This chart shows the same convention of the previous chart, adjusted for downtime Libya and dispositions we grew product about 2%. Growth of 207,000 BOE per day was 30,000 per day higher than decline of 177,000 per day. This reflects underlying production growth in the Lower 48, the Oil Sands, Indonesia. Again the contribution from our recent major projects was negligible given the late year timing. And one note in 2013, Libya contributed 30,000 boe per day of production and at those volumes 2014 total production was 1.472 million boe per day. And we intend to exclude Libya in our future production outlook. So we now think of this 1.472 million boe per day as the base on which we are going to grow 3% to 5% in 2014 and beyond. And that growth is bringing stronger margins, and Slide 8, 9 put our growth in margin trends in perspective. The chart on Page 8 shows the 30,000 barrel a day production change from the previous slide – sliced by segment and product in order of year-over-year change. At the top of the chart is our growth from liquids focused assets, especially the Lower 48 unconventionals, the oil sands in Canada and higher margin production from the Asia Pacific segment. We are growing in the places and in the products that have higher margins and declining in some of the lower margin streams like North America natural gas. During 2013, liquids production from continuing operations increased to 56% of total production and should continue to improve in 2014 and beyond. The impact of this mix shift on cash margins can be seen on Slide 9. This slows year-over-year cash margins both on a reported basis on the left side of the chart and price normalized basis on the right side of the chart. As you can see from the left chart, 2013 cash margins grew 11% on an absolute basis despite flat realized prices compared to 2012, just like in the impact of production mix and location. On the right side of the page, we priced normalize the margins with 2012 as the baseline and margins grew 9% on this basis. We provided a reconciliation of this chart in our backup materials. We expect this metric to continue to improve and we will continue to track it since it’s a key aspect of our value proposition. I will conclude my prepared remarks with our cash flow waterfall, which is another good story. So if you turn to Slide 10, this shows our cash flow performance for 2013. We began the year with about $4.5 billion of cash on the balance sheet. For the year we generated about $16 billion of cash from operations and over $10 billion from asset sales. Our continuing operations capital program was about $16 billion. We paid about $3.3 billion in dividends. As we announced in December, we prepaid $2.8 billion of future obligations to our 50% owned joint venture interest at FCCL and the remaining cash flow items such as debt repayments and cash flow associated with discontinued operations were a $1.5 billion use of cash. This leaves us in a very strong financial position at the end of the 2013 with about $6.5 billion of cash and short term investments on hand and a positive outlook for margin improvement that can grow cash from operations. So as we start 2014, we are well positioned to execute on our investment programs for the company. That concludes [inaudible] … on Slide 11.

Thanks, Jeff. I will kick off the operation section with some comments on our 2013 reserve replacement performance. We achieved very strong results for the year. We ended 2013 with 8.9 billion boe of reserves, up 3% compared to last year. Importantly, we added over 1 billion barrels of reserves organically, resulting in our organic reserve replacement ratio of 179%. Including last year, we averaged over 165% organic reserve replacement as an independent E&P company. Our all-in reserve replacement ratio was 147%. This takes into account the impact of dispositions completed during the year primarily at Kashagan, Algeria and Cedar Creek Anticline which produces [ph] 588 million boe. Some of the key additions came from the Eagle Ford and Bakken. Most of the additions in these two plays were a result of higher competence in performance and offset bookings [ph]. However we have only booked less than 30% of identified resource in Eagle Ford and Bakken and that’s based on our current well pacings at 80 acres in the Eagle Ford and 320 acres on the Bakken. So those subside potential still exists in these place as we get results from a spacing pilots. Canada contributed about a quarter of the additions predominantly from the oil sands. We also added reserves to APLNGs. We continue to drill our acreage there and with some contributions from both the U.K. and Norwegian sectors of the North Sea. We’ll provide more details on our reserve bookings including costs incurred in our 10-K that will be filed in February. Again we are really pleased with these results and we believe the differential for a company of our size. And the bottomline is that these reserve additions give us confidence in our ability to deliver sustained growth and value accretion from our capital programs. So next I will review our operating segments. In each segment, I will address key results from the fourth quarter and overall highlights from 2013 and I will give you some color around the activities to watch out for this year. I’ll start with the Alaska segment on Page 12, starting from the lower left with highlights from the fourth quarter. We applied for a two-year export license for our Kenai LNG plant. You may remember we base this facility in cold storage about a year ago to retain the option to restart but conditions changed with increase in gas production that could -- that cannot take advantage of that LNG capacity. At CD5, we began critical ice road constructions that lead us to new materials for roads and bridges, a key to accessing and preparing this project site. Moving to the top right. 2013 was a big year for our Alaska business, probably the most significant highlight was the passage of SB21 of the More Alaska Production Act. These changes have made the investment climate in Alaska more attractive and as a result, we’ll execute much higher budget for 2014, $600 million more than in 2013. And this capital increase is focused on adding production. For example, in addition to CD5, we continue our major project, work at Drill Site 2S and Greater Moose’s Tooth. And these three projects alone could add over 40,000 barrels a day growth by 2018 to offset the claims through tax. And we continue to make progress on the Alaska LNG project. This month we executed the heads of agreement with ExxonMobil, BP, TransCanada and the State of Alaska that defines a path forward for the commencement of precede and if all goes well, precede what at the start of early in the second quarter of this year. So I’d say we’re making progress in all fronts in Alaska. Let’s move onto Slide 13 to cover the Lower 48 segment. As Jeff already mentioned, like many other operators, we had adverse production impact due to weather in the fourth quarter in this segment. But despite the weather, we achieved some significant progress in the Eagle Ford and the Bakken in particular. In Eagle Ford, their operated program reached a milestone of more than 500 total wells on line. Production average 126,000 BOE a day in the fourth quarter, representing 42% growth versus the same period previous year. And we reached a peak rate of 141,000 BOE a day in late December. In the Bakken, we achieved a peak rate of 43,000 barrels a day and average 39,000 for the fourth quarter and that’s a 63% increase compared to the same period last year. In the fourth quarter, we also made progress in our emerging deepwater business. We announced the discovery at Gila, conducted appraisal activities at Tiber and Coronado and continue the exploration drilling at Deep Nansen in the Western Gulf of Mexico. Moving to the full year highlights, Lower 48 production was up 34,000 BOE per day representing 7% growth versus 2012. But more importantly behind this overall growth, our oil production grew 24% year-on-year delivering the mix shift we’re targeting as we execute our strategy. In fact for the full year 2013, the Eagle Ford and Bakken grew 60% on a combined basis compared to 2012. During 2013, we also matured our appraisal programs in the Delaware and Midland basins and the Niobrara. We continue to test various horizons, completion designs on natural wins in these plays with encouraging results to date. We’ll give you an update on what we’re learning in our Analyst Day in April. So the goal of these appraisal programs is they have clearer view of development plans for these plays by the end of this year. And we are managing Gulf of Mexico deepwater program, we announced significant results at Shenandoah and Coronado in the first quarter and the discovery at Gila in the fourth quarter. These were important milestones and established strong momentum for acceleration in appraisal activities for 2014 and beyond. Our Lower 48 business is a very unique and high value segment. We have few leading positions in several of the best Lower 48 unconventional plays where we are growing production and continuing to identify upside. Also, we have an enviable position in the deepwater Gulf of Mexico that’s delivered early success and provides future growth and significant value for the company. Please go to Slide 14 and we will talk about the Canada segment. Operationally, our Canada business performed very well in the fourth quarter. Volumes continued to ramp up at Christina Lake Phase E and the Western Canada winter drilling program got underway. We were focused on drilling a liquids rich inventory. We continue to drill and evaluate on conventional appraisal and driven in Monterey and we spudded the first horizontal well in the channel play – we drilled two horizontal wells this season. And overall 2013 was a very important year for the segment, like the Lower 48, we advanced very substantial yet divested of opportunities. For the year, production was up 1% and we achieved a 13% increase in liquids production compared to 2012 mostly from the oil sands. And oil sands business performed extremely well. Operational volumes grew 17% and by year end the Surmont 2 had achieved over 60% completion. And this positions us very well for ’15 [ph], next 2015 as we plan. The theme for 2014 in Canada is continuous investment in growth. Our conventional liquids rich plays – our unconventional plays and our oil sands assets will all be active with some significant milestones on the horizon. So let’s move on to our Europe segment on Slide 15. Like the Lower 48, this segment experienced some very challenging, weather impacted fourth quarter production. However the big news on the fourth quarter was the start of production Ekofisk South in Norway and Jasmine in the UK. Ekofisk South production started in late October from the first of four pre-drilled wells, three months ahead of schedule. Ekofisk South is designed for 35 production wells that will grow production as we build over the next five years. At Jasmine first production was achieved in November. Production is currently constrained by the half of platform capacity until we fill the connection with J-Area [ph] platform which should occur during this quarter. Clearly the major projects dominated the operational themes for 2013 but extensive [indiscernible] in large part, project startups were key activity in the middle of the year and were executed very well. In addition to the two major projects I just discussed, work advanced on additional projects at Eldfisk 2, Britannia Long-Term Compression and Clair Ridge. We enter 2014 focused on ramping up and optimizing our major projects at Ekofisk South and Jasmine, and establishing production through our new East Irish Sea asset plant. In addition, the Britannia long-term compression project is preparing for startup in the third quarter of this year, and pre-drilling is underway at Eldfisk 2 in anticipation of startup in early 2015. On exploration front, in this segment, we expect to see results from our unconventional appraisal in Poland; two verticals wells and one horizontal well are planned. We've also begun exploratory drilling in the Barents Sea. So, our Europe segment had a pivotal year in 2013 after several years in project mode. We're positioned for growth from high value production that will extend the life of our legacy positions in Europe. We have a lot of work to do to ramp up and optimize our operations in 2014, but these positions – these activities will position us for a strong future in that segment. Finally, I'll cover our Asia Pacific and Middle East segment on Slide 16. Key fourth quarter highlights in this segment included the completion of the QG3 plant planned turnaround in Qatar and continued progress and access on future exploration options. We obtained operatorship and 100% working interest in the Palangkaraya PSC in Indonesia and we completed our seismic work in the Qijiang Block of China. These are both examples of relatively low cost, early stage exploration options. I'm pleased with the potential for materiality. Highlights for all of 2013 included progress on major projects that will make a step-function contribution to future production levels in this segment. During 2013, our partners progressed towards major project start-ups in Malaysia. We are now anticipating a first quarter start-up at Siakap North-Petai and a second quarter start-up at Gumusut. Our APLNG project is on schedule for first LNG by mid-2015, the Niobrara project stands at about 60% complete. On the exploration front, we announced the Proteus gas discovery in the Browse Basin, which was an untested structure to the Southeast of the Poseidon discovery. The big catalyst for 2014 of the Malaysian start-ups at SNP, (inaudible) and Kebabangan. And we have an important year ahead at APLNG, as we approach start-up in 2015 and we expect to provide a full update of these projects at our April Analyst Meeting in New York. Our appraisal programs offshore Australia will continue in 2014 with two wells each, plans in the Poseidon area and the Caldita/Barossa and the punch line in this segment is very straightforward. Significant production ramp up over the next couple of years from high margin volumes and upside from a drilling exploration condensate. I don’t have a slide in our other international segment. The main focus last year was on executing the divestitures that Ryan mentioned. In 2014, the key segment activity will be of exploration in Senegal and Angola, which should get underway by midyear. I will conclude my prepared remarks with some comments on our production outlook for the first quarter. We are on track to deliver 3% to 5% growth in 2014 from the projects and activities I just described. Excluding Libya, we expect to achieve approximately 1.5 million barrels a day this year. As Jeff mentioned, we’ll exclude Libya from future production outlook since we are not optimistic that production will resume from the eastern field anytime soon. In the first quarter, we estimate the volumes from continued operations excluding Libya could range from 14.90 to 15.30 and those in BOE per day. This range reflects short-term uncertainty around the ramp up of recent and pending start-ups, and includes a 15,000 barrel a day impact from a turnaround of the second chain in Qatar that will occur in March. Now, I will turn the call back to Ryan for a brief recap and summary of the key things for 2014 on slide 17.

Thank you, Matt. So, I hope there is no doubt that 2013 was a successful year for the company. We delivered on our commitments but perhaps more importantly, we positioned the company for a strong 2014. Operationally, we had a significant inflection point for the company. We expect to continue ramping up our unconventional drilling programs and progressing on our major growth project. And as Matt mentioned, we expect to grow on almost all of our business segments this year, while progressing the major projects that will continue our growth into 2015 and beyond. Meanwhile, it’s a big year for our exploration programs. In our conventional program, we will be drilling in the Gulf of Mexico, Angola, Senegal, the Barents Sea in Australia. In our unconventional program, it was an active year in the Lower 48 Permian, the Niobrara plays as well as Poland and Canada. We should see ongoing improvement in underlying margins as we bring on new volumes and we will maintain our focus on improving returns while staying committed to returning capital to our shareholders. On the strategic front, we are moving beyond the positioning phase of our journey as an independent E&P company. So now we are focused on executing our current plans to deliver growth in volumes, in margins, while positioning the company for long-term success. Our goal here is to have a deep inventory of choices and options for investment and to be the best capital allocators in the business. We think our diversified approach to this business will service well over the long-term. We are not dependent on any single product, play type or geography and this allows us to consistently execute our programs through the cycles. Bottom line, we are positioned to deliver 3% to 5% growth in both production and margins with a compelling dividend. That’s our value proposition that we set out and we are committed to delivering on it. So, I hope, Jeff, Matt and I have given you confidence that our plans are on track for delivering key milestones in 2014. It should be exciting year and I look forward to seeing you at the Analyst Meeting in April in New York. And I would mention -- I think Matt mentioned 2014 production of 1.55 million BOE per day. So, now let me take all your questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) Our first question is from Doug Terreson of ISI Group. Doug Terreson - ISI Group: In Lower 48 and also in International E&P, cash margin seemed to have been significantly stronger versus the year ago period, despite the [indiscernible] from realization, which I think one of Jeff's slide indicated. On this point, I want to see if we could get some color on the improved performance in those two areas, and specifically where you are seeing the improvement regionally in both Lower 48 and International E&P?

Doug, I think it primarily comes back to changes in mix, when you look at cash margins within that segment, and that's what we are trying to highlight with the slide. It just kind of shows year-over-year changes in production. You just saw a fairly large shift in liquids production that we talked about increases in very significant percentage related primarily to Eagle Ford and the Bakken, the biggest driver of that change. Doug Terreson - ISI Group: And Internationally, Jeff, could it be the loss of some lower margin production as well?

Yes, I think that's the overall mix. As you would have properly flagged there Doug, if you look year-over-year we basically had the same overall realized price. But the shift of production within different jurisdictions, which is kind of highlighted on that one slide we have, shows production going up in the Lower 48, up in Canada, up in Asia, down in Alaska, down in Norway, down in the U.K. So, up in kind of lower tax areas and down in higher tax areas. That has a lot to do with helping drive the cash margin – that and just the shift overall to liquids production over gas production.

Doug, that's what we said. That's going to continue because that's the direction, that's the strategy, that's how we're allocating our capital, and that's how we're thinking about how we grow the margins and grow our cash flows as the production grows. Doug Terreson - ISI Group: And then just quickly on capital expenditures. I think Slide 10 indicated that the company prepaid almost $3 billion of its oil sands commitment. And so I want to see if you could spend a minute on that item specifically why the company chose to do so? Was not there any interest or tax benefits that were meaningful, and also how it affects the spending profile on that project going forward?

As we mentioned we prepaid a $2.8 billion obligation that we had and that was something that we incurred when we set up the joint venture back many years ago. The key for us is that was an interest-bearing obligation, it had about a 5% interest on it. You can really think of that being equivalent to debt. It was an obligation that we needed to pay over the next several years, and when we had as much cash as we have on our balance sheet just from a balance sheet management point of view that makes sense to prepay that obligation and save the 5% interest as opposed to leaving that cash on your balance sheet and variable return on the cash. But the other thing we want to make sure we point out on that is cash that's moving into a 50% joint venture. So while it's a $2.8 billion outflow for us, that means that we essentially still own about half of that $2.8 billion. So it's more of a $1.4 billion net of outflow. So that does reduce capital that we'll have in the subsequent years. We did that primarily just from kind of a balance sheet management point of view of getting rid of an interest-bearing obligation and taking advantage of the fact that you would otherwise have cash on your balance sheet, not making a very good return.

Our next question is from Ed Westlake of Credit Suisse. Ed Westlake - Credit Suisse: Just thinking about one of the components of that is obviously your shale portfolio and you gave good guidance back at the investor day last year. Still some growth in the Eagle Ford where you seem to be a bit ahead of plan in the Bakken and Permian, then accelerate. So what's the constraints on perhaps even driving a little bit harder in terms of shale? Is it the amount of money that you have to still spend on some of these longer life pancake type assets, , SAGD, APLNG or is it that the shale itself has not yet delineated enough for you to put more capital to work?

Well, Ed, this is Matt. It's really neither of those things actually, really what is the -- we’re focused just now on running a safe and efficient operation. We do want this economy to scale, we do want to get too far ahead of infrastructure. But the real reason is that that we’re benefiting from -- still benefiting from our cost learning curve and are drilling in the completions and that’s going to improve even further as we move towards spud drilling for most of our wells. So the cost learning curve and then there’s a huge technology learning curve ahead of us in the unconventionals. This going to improve the overall efficiency of these developments and -- in the years to come. So we see consistent redeem in the Eagle Ford with an 11 rig program and we do have the flexibility as you point out to change that everything that’s a right value proposition. Ed Westlake - Credit Suisse: Right. And most of the rigs which is HPP so there’s no pressure as well. And then just a follow-up on shale and Matt, what are you most excited about that you feel that you can talk about last year when you think about the North American shale, clearly not just and maybe include Colombia as well but not just in the U.S.?

Sure. I mean, I think, we’re making progress on all of the shale plays, clearly the Eagle Ford and Bakken are now in development mode, but we’re still seeing upside there and associated with pilot test that we’re running for looking at decrease in well space and I sort of alluded to that in my prepared remarks. And we’re getting encouraging results in the Permian, both in the Delaware and the Midland Basin and encouraging results in the Niobrara. And then, again, in Canada we have -- we’re still getting good results from our unconventional program out there. And we’re going to give you a lot more detail on this when we get to the Analyst Meeting in April, because we think we will give you sort of update on what we’re learning in all these plays and that I’ll take a bit of time and we’ll do that in April.

I would add Ed that, we continue to believe and I think our results are proving out that we’re in best positions in the best plays and can we get any surprises we get usually to the upside and we’ve got more resource and more opportunity as we think about our capital program and our allocation of capital is -- some of the big projects starting to wind down. Ed Westlake - Credit Suisse: Great. Very helpful. Very clear. Thanks.

Thanks, Ed.

Thank you. And our next question is from Jim Sullivan of Alembic Global Advisors. Please go ahead. Jim Sullivan - Alembic Global Advisors: Hi. Good afternoon, guys.

Good afternoon, Jim. Jim Sullivan - Alembic Global Advisors: Just wanted to look a little bit ahead on this margin story, obviously the passage of SB21, the last production act as you guys thinking a little bit differently about Alaska. And we obviously appreciate the details on Moose’s Tooth and so forth. And I -- with the reservation that I’m sure you guys are working on -- I want to talk about this in more detail at the analyst day. But you guys just comment a bit on how you see that affecting the margin profile going forward. I mean, obviously, you have an array of tax benefits in that bill. And so just, can you, sort of how to -- how it compares to the base production and is it kind of along the lines of Lower 48 or how should we think of that?

Well, it’s not as strong the Lower 48 because there’s still even with the tax improvements in Alaska, higher taxation in Alaska than in the Lower 48. The Alaska production is all oil. Which helps us on the cash margin side as well, where you think about something like Eagle Ford is kind of 60 oil and 20 NGLs and 20 natural gas. So Alaska is going to also contribute to helping with cash margin because the continues to help with the oil production, probably not as much as increased Lower 48 production wells. Jim Sullivan - Alembic Global Advisors: Okay. Great. That’s all I had.

Thanks, Jim.

Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead. Paul Cheng - Barclays: Hey, guys. Good afternoon.

Hi, Paul.

Good afternoon, Paul

Hi, Paul. Paul Cheng - Barclays: I have two questions, one maybe is a little bit overall picture, Ryan, one of your competitors Shell the new CEO is essentially saying that had it been a hunch, it’s risky and want to scale back. Obviously that for the company and from your side you can’t just always go for the single, it won’t work? So that’s basically that you have what internally considered by the proper allocation of capital, how much is your percent of your capital, you want to chase those really high-risk big (inaudible) or that how much is that you for that’s a lower risk and smaller one? And also that whether it’s capital or production profile I mean is there anything you can share on that thinking?

Yeah. What I’d say Paul is that we’re broadly at the higher level in terms of allocation. We think about spending about 15% of our capital on the exploration. We like to do that through the cycles. Now if we get success and we start to appraise, we’ve got a decision that we face about increasing that percentage for appraisal and keeping an exploration program going. But I’d say, broadly speaking, we’re spending about 15% of our capital on exploration. We’re really kind of value based as we think about it. I don’t go into it trying to overload either unconventional or conventional. Today our program is pretty balanced. It’s about 50-50 conventional and unconventional. But everything has to compete. So whether it’s a new unconventional play that we might be looking at in other country or here in the U.S. or in North America, it’s got to compete on a cost to supply basis and an expected rate of return. So for doing our risking appropriately, doing our technical work appropriately everything has got to play. So I don’t really look at it and say, I’m not going to go elephant hunting or anything like that, we’re just trying to do the best technical work we can, risk it the best way we can and then every dollar competes. So we’re not… Paul Cheng - Barclays: I guess, I mean Ryan, if I could clarify myself. When I say elephant hunting, it’s not just for the exploration. So for example when you go with Alaskan LNG, if indeed that the project trying not to be economically viable is going to be extremely expensive? And even the partner that your share is going to be huge. So there is huge big block and if anything happened there, it is going to be a huge negative impact on the company. So, those are kind of projects. So I’m wondering that if they internally sell off my -- a percentage of the capital or the production you want to be in those big projects?

I think we look at -- we still look at returns and cost of supply and try to ask ourselves is it competitive in the portfolio. We know that big resource, long-dated projects like Alaska LNG that you referred to are similar to what we’re executing in Queensland or what we’re doing in the oil sands of Canada. Both have a different profile, different return profile than unconventionals in North America but again this is the part where we think a diversified large global E&P company with the balance sheet like we have is important because there is a place in the portfolio for some of those projects to balance it out. Over time they reduce capital intensity and they have a place in the portfolio. But we have to be careful. We have to look at the other alternative investments and the other options and choices we have in the portfolio. And we haven’t made that decision on the Alaska gas because we’re still studying it and we’re still trying to understand what that cost is going to look like, what the economics, how it competes in the global marketplace for LNG and how it competes in our portfolio. Paul Cheng - Barclays: And the second question is for Matt. Matt, on Eagle Ford, based on your previous production chart from this point on that growth is really going to slow down. But I guess my question is, is that just being out of conservative or indeed you think that is the most likely base case scenario. Should we be more aggressively trying to shift and increase the activity in either Bakken or in the Permian?

Yeah. So we’re going to give you an update on that Paul, as we may get together in the April for the Analyst Day. That was a view of how production would be likely to move in the Eagle Ford. Our view has been changed. We were going to show you something that’s a bit more optimistic than that in April. Paul Cheng - Barclays: Okay. Thank you.

Thanks Paul.

Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead. Blake Fernandez - Howard Weil: Folks, good afternoon. I’m sorry to ask you to repeat the guidance. But I just wanted to make sure, be a 100% clear. I thought I heard the first quarter guidance number and then a full year. And I was hoping you could just repeat that if you don’t mind?

The first quarter guidance Blake was 1,490,000 to 1,530,000 barrels a day for the first quarter and that’s really -- there is quite a wide range of uncertainty there because of the ramp-up of new projects that are going to be happening in that quarter. And this also would be affected by the downtime and the one of the Qatar LNG trends. So that was that the first quarter. And our full year guidance is basically unchanged from what we’ve been seeing at 1.55 million barrels a day for the year. And all of those numbers I just gave you exclude Libya. Blake Fernandez - Howard Weil: Okay. Matt, just to be clear. Now you had some weather-related impacts on Lower 48 in 4Q, obviously we’ve seen some pretty rough weather this past week. Does that contemplate anything you may be witnessing currently for 1Q?

That range includes some uncertainty and any weather impacts that we’ll see for the remainder of the quarter. Blake Fernandez - Howard Weil: Okay, great. The second question I had for you, this maybe a bit premature but on pre-salt Angola, I know you will begin drilling this year. Some of your peers who had success and ended up having some gas, basically the fiscal terms from what I understand didn’t really contemplate monetizing gas. Are you trying to proactively get ahead of maybe kind of reevaluating your contracts with the government or you just taking a wait-and-see approach there?

We don’t have gas right, within those two blocks, blocks 36 and 37. And the way that we model the petroleum system there, we don’t expect to find gas, the way we model the maturity of the (inaudible) expectation is that we will find oil, if we find anything, it’s still exploration in next program. So they -- we are still hopeful for that. We had blocks. It’s a quite fix section above the structures and the effect of that is that it fills the [Soshok] which means the [Soshok] less material, not to get too technical on your business. But nonetheless we expect that that’s going to be an orderly petroleum system prospect. Blake Fernandez - Howard Weil: Okay. Good to hear. Thank you.

Thanks, Blakse.

Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Doug Leggate - Bank of America Merrill Lynch: Thanks. Good afternoon everybody.

Hey Doug.

Hey Doug. Doug Leggate - Bank of America Merrill Lynch: I am not sure who wants to take this one but if you go to Slide 7 in your book. I am wondering if you could give us a little bit of help with its puts and takes on how you see 2014. So 1.55 , guidance, I’m looking at last two bars of decline in the growth because what I’m really trying to get to is the composition over the decline in terms of gas in particular, obviously that’s when you look at your realized margin, I am guessing that would be a big help because there is a lot of gas in there. So if you could help me with the puts and takes and I got a follow-up?

Doug, this is Ellen here. We love to take this kind of offline with you. We’ve got the data that could help you but I don’t have it at my finger tips. Obviously in the 177, quite a bit of -- our North American gas is declining of course and now we see in the 207, excuse me, the growth we show on that page, that our liquids ramped in the unconventional.

Doug, your question is probably more looking forward to 2014, right? Doug Leggate - Bank of America Merrill Lynch: Yeah, yeah, its pretty much for 2014. I am trying to get a feel for the underlying decline on the mix and underlying decline.

Yeah. I don’t think that data we got really at our finger tip right now. Directionally we are going to see the same type of things. We are going to continuing to grow more liquids production than gas production as we ramp up oil production in Malaysia as we continue to grow the unconventional that the oil sands continue to grow. So you will see lot of the same things in 2014. We probably have to -- I am not sure if we tap that information , that’s something we can probably give you more detail on…

Analyst Meeting here.

…when we do the Analyst Meeting. Doug Leggate - Bank of America Merrill Lynch: Yeah, that’s great. I will pick it offline. My follow up really is kind of related, I guess, but hopefully you can help me with this one Jeff, but if I look at the next several projects coming on line, it looks to us at least that that there is a fair number of them, we’ll not incur cash taxes at least from the early years of production. I am just wondering if you could help offer some color and particularly things like basically you came in all feedstock, I’m guessing, you won’t be paying cash taxes in early years. I’m just wondering if you could confirm that and may be press numbers around that. Thank you.

Yeah, I may add a few things and will see that quite helps. So if you think about where our capitals going in the Lower 48, lot of it’s going into drilling, lot of that capital is IDCs and which of course get very rapid depreciation. In Norway, you get rapid depreciation, in U.K. you get essentially almost immediate depreciation on new capital. So directionally you are right on all of those. The way that manifests itself in kind of our results is just what you see under deferred tax line on the cash flow statement. You’ve seen that that was a pretty significant source of positive cash in 2013, little bit less so in the fourth quarter than in the other quarters but there were some impacts that how the impairments in the fourth quarter roll through the cash flow statement, ebbs and flows impacts. You would have seen the similar number in the fourth quarter which you saw in the previous quarter. So it was a pretty substantial impact, positive to cash that will probably continue on in the 2014. But I don’t have the number that I can give you that you know exactly what that impacts are going to be. But that’s where it shows up for us, it’s – how much of it add back to your deferred tax and new cash flow statement. Doug Leggate - Bank of America Merrill Lynch: That’s embedded in your report cash margins, Jeff?

No. It’s not. The way we do a cash margin calculation is just simply a adjusted net income plus your amortizations, plus your DD&A and your dryhole cost and your leasehold amortization. So we don’t factor in deferred tax into that. So, if we take rather kind of simplified approach to cash margins and we do that because that’s the kind of metric we can have a comparison against other companies with. Doug Leggate - Bank of America Merrill Lynch: Got it. Really helpful. Thanks guys.

Thanks, Doug. Welcome back to you.

Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead. Faisel Khan - Citigroup: Thanks. Good afternoon. I appreciate the guidance on margin growth and production growth. I was also wondering, whether you guys have sort of goals on return on capital employed and what those looks like underneath so the assumptions you have for 2014 and for that matter going forward?

So our return on capital employed for 2013 is pretty similar to what we saw in 2012 and it will be, will be a bit challenge to improve return on capital employed in a very near term. A lot of that has to do with the fact we got large capital going into projects that are not really producing much right now, if you think about APNLG, some of the oil sands assets and also due to the fact that, as Matt mentioned in his remarks, we were relatively conservatively booked on a lot of the unconventionals, which leads to some pretty high DD&A rates on the unconventionals and all those things kind of impact net income, which of course impacts return on capital employed. You see a better picture for us once APLNG starts up, when the Surmont starts up and once we get a little bit more fully booked on the unconventional. So, we do see that we will be improving returns on capital employed plus prices can affect that metric as they change but those improvements are probably more in a 2016, 2017 kind of timeframe. Faisel Khan - Citigroup: Okay. Fair enough. And just on Alaska, so I understand it’s kind of early to figure out what the cost this project would be, but what type of capital are you spending right now on it and what are the -- what’s sort of the critical sort of timelines or sort of time post in order for this to sort of move forward or even gain some traction?

I assume you’re talking about APLNG? Faisel Khan - Citigroup: Yeah.

Yeah. So as you know we’ve selected the concept -- we’ve selected to say. We just announced an [HOA] with the first structure in place for the project and we’re hopeful we’ll start pre-FEED in the second quarter. Right now, it looks like a project that will be somewhere between $45 billion and $65 billion, and that’s because of some movement, different scope and so on, but that’s our scale. And it will be something around the 17 million tons per annum since three chains there. And the timeline that we’re working with just now is that we would make a final investment decision in 2016 or 2017. There is quite a bit FEED required for project of this scale and between the pre-FEED and the FEED that will be 2016 or ‘17 before we make a final investment decision and first gas would be 2022 to 2025. So, that’s the sort of range that we’re thinking about just now for the project. Faisel Khan - Citigroup: Okay. Appreciate it. Thanks guys.

Okay. Thanks, Faisel.

Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead. Roger Read - Wells Fargo: Hi. Good afternoon.

Hi, Roger.

Hey, Roger. Roger Read - Wells Fargo: Well, I guess, main thing I’d like to focus on here is just trying to understand the, I know how you reiterated the 3% to 5% volume growth, 3% to 5% margin expansion. Could we walk through here what the margin expansion should be from at least my growth assumption more of second half ‘14 of that but just I wanted to hear what your take is on that?

I think that’s probably a fair assumption. As Matt mentioned earlier, as we think about volumes overall for 2014, the impact of timing on start-ups at some of these key major projects is going to be a question. I mean, we do -- I think like some of the previous questions that I have gotten too. The same kind of things that drove margin growth this year are going to be the things, the drivers next year as we continue to ramp up oil sands production ramp up, Lower 48 production and get to a full production in Gumusut, which because of the way the production recovery works there, had some really strong cash part and so you will see those all same, three drivers. North America natural gas probably won’t grow in our portfolio going forward. We could see a slowing of decline in Alaska, but overall that’s probably not going to cause margins to move significantly. So it’s really back to the same primary drivers that we’ve had this year, going to be drivers in 2014 as well.

With the same reductions in the gas side, so Europe, Lower 48, some of the lower margin gas, it’s not getting capital investment, Roger, it starts to decline since that mix that Jeff described in his remarks. Roger Read - Wells Fargo: Okay. So it is safe to assume that margin is sort of a full year event in the production. Like, you said, I don’t know want to put words in your mouth. But at least in my assumption on projects start-ups more of a second half event, does it get right away?

Yeah. And really with cash metric like that, we try to warn every quarter that that can swing up and down because incoming DD&A can be less than, I would say ratable through the year for different reasons. So we think it’s important as we go forward that we talked about just kind of how we’re progressing on more longer-term measures and just looking at it quarter-to-quarter. Roger Read - Wells Fargo: Okay. And well, I know you don’t give quarterly production. The last question I had was last year, especially in the summer months, a lot of turnaround activity had a pretty significant impact on production volumes. Can you kind of characterize for us this year when we would be anticipating in terms of maintenance and turnarounds?

Yes. In 2014, we’re expecting about 20% more planned downtimes than we have in 2013. And we’ve got downtime I mentioned in the QG3 between seven in the first quarter. We have turnarounds in Prudhoe Bay in the second and third quarter, turnarounds in the U.K. in the second and third quarter. And a big turnaround to the Bayu-Undan field in Australia in the third quarter. So we are expecting the overall planned at 10 times to be above 20% more than it was in 2012.

2013.

In 2013, sorry. Roger Read - Wells Fargo: Thank you.

Thank, Roger. Thank you. We have no further questions. I will now turn the call back over to Ellen DeSanctis.

Thank you, Christine and thank you everybody. Of course, feel free to call us back. If you have any lingering questions then we certainly look forward to seeing you in April. Thank you for your time.

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