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

Ed Westlake – Credit Suisse Doug Terreson – ISI Group Paul Sankey – Deutsche Bank Paul Cheng – Barclays Capital Scott Hanold – RBC Capital Markets Doug Leggate – Bank of America Merrill Lynch Faisel Khan – Citigroup Inc. John Herrlin – Societe Generale Roger Reid – Wells Fargo Katherine L. Minyard – JPMorgan Brandon Mei – Tudor Pickering Holt Blake Fernandez – Howard Weil, Inc.

Welcome to Q3 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, the Vice President, Investor Relations and Communications. You may being.

Thanks Christine. Thanks to all of our participants and a big welcome to our third quarter earnings call. Joining me today in the room are Jeff Sheets, our EVP of Finance and Chief Financial Officer and Matt Fox, our EVP of Exploration and Production. We will begin our prepared remarks in a moment. But I wanted to make sure that all of you saw the announcements this morning that we completed the sale of our Kashagan business for about $5.4 billion. Just a quick mechanical point, we sent the earnings release and the Kashagan releases separately, that was because we had to queue up the earnings release last night and weren’t entirely certain about the timing of the Kashagan close. So, apologizes there for a little bit of possible confusion; but this is obviously a huge milestone for the business and wanted to get the news out to the marketplace this morning. Also wanted to make sure that all of who saw in our release this morning that we expect to announce our 2014 capital and production budget in early December and then in 2014 we will be hosting our Analyst Meeting on the 10th of April in New York, obviously details to follow. If you’ll turn to page two, you’ll note our Safe Harbor statement and that describes the risks and uncertainties and our future performance, these are also described in our periodic filings with the SEC. With those details out of the way, I am going to turn the call over to Jeff. Jeff?

Thanks, Ellen. Hello, everyone. And thank you for joining us today. I am going to jump right into material beginning on the slide three, this slide shows some of the key highlights for the quarter. Once again the theme of today’s call is pretty simple, we are successfully executing on our business plan. Operationally, we delivered our expected volumes. We produced 1.514 million BOE per day which is in line with guidance despite the curtailment of Libyan production for most of the quarter. From continuing operations, we produced 1.47 million BOE per day. Without the disruptions in Libya, we would exceeded the high end of our production guidance. As we’ve stated for quite some time, we expected this quarter to be the low point of volumes and we are positioned to grow from here. The third quarter was an active period of seasonal planned maintenance. We executed this key turnarounds on schedule and most of that work is complete for the year. Our major growth projects are progressing Christina Lake Phase E and Ekofisk South are now producing and others are nearing first oil. We have several near-term milestones that Matt will discuss in a minute so operationally we executed our plan. Moving to the financial results reported earnings were $2.5 billion or $2 per diluted share. Adjusted earnings were $1.8 billion or $1.47 per share. This is 7% increase year-over-year. We were also up 4% sequentially despite this being the low point for volumes. And excluding working capital, we generated $3.8 billion in cash from continuing operations and we ended the quarter with $3.9 billion in cash. Cash margins grew 13% compared to last year’s third quarter reflecting the impact of higher prices, production mix and location. Normalized for changes in prices cash margins grew 3% year-over-year. This is an important part of growing cash flows to internally fund our investment programs and dividends over time. In the quarter, we continued to prune our portfolio and closed on two non-strategic asset sales our Clyden undeveloped oil sands leasehold in Canada and our interest in the Phoenix Park midstream asset in Trinidad and Tobago. And as Ellen mentioned at the start of the call, importantly, we achieved a big milestone earlier today with the closing and receipt of funds for the $5.4 billion Kashagan transaction. And we continue to make progress on closing our other announced assets sales. We are continuing to add to and test our conventional and unconventional exploration inventory globally and these programs are running at a high level of activity. Finally, we are committed to returning capital to our shareholders. In early July we increased our dividend by 4.5% and we remain committed to increasing the dividend overtime. In summary, we delivered our plan for the quarter. We achieve the operational performance we expected and generated the strong financial results. We are positioned for an exciting phase of growth and margin expansion, which is the essence of our strategic plan. So please turn to slide four, and we’ll cover the financial review for the quarter. Again, this quarter’s adjusted earnings were 1.8 billion or $1.47 per share and this was slightly above consensus. The 7% year-over-year increase in adjusted earnings was primarily driven by higher margins. The higher margins reflect strong liquids pricing in the quarter and a continued shift to higher value liquids in the portfolio. Average realizations were up 6% year-over-year and 4% sequentially. Production from continuing operations was in line with expectations, but down sequentially and flat compared to the third quarter of 2012, largely reflecting the curtailments in Libya. We have shown a table of segment earnings for the quarter in the lower right corner of the slide, our usual segment charts can be found in the appendix of this deck and we don’t plan to review these on the call but wanted to make a few key points there. Alaska income was down sequentially due to planned maintenance but in line with our expectations. Lower 48 adjusted earnings were up sequentially, reflecting strong liquids prices and the mix shift. Canada generated significantly higher adjusted earnings sequentially as well. Although natural gas prices were weaker than last quarter, bitumen prices were particularly strong, reflecting higher WTI prices, favorable diluent prices, lower crude differentials and lower seasonal blending requirements, sort of a perfect set of conditions for the oil sands. At this point, we would not expect fourth quarter realizations for bitumen to be as strong. Europe and the Asia Pacific and Middle East segments were also in line with expectations. Our Corporate segment adjusted losses were about $40 million higher than in the second quarter of 2013 due to the absence of licensing revenues in the third quarter. This was about the same level we would expect for the fourth quarter as well. So, there is no change to our full year guidance of $750 million for this segment. Next I’ll step through our production performance for the quarter on Slide 5. Total company production in the second quarter was 1.514 million BOE per day and this includes 44,000 BOE per day from discontinued operations. This chart shows continuing operations compared to the third quarter of 2012; and in the third quarter 2012 production from continuing operations was 1.47 million BOE per day. Adjusting for dispositions of 12,000 BOE per day normalized production from continuing operations was 1.548 million in last year’s third quarter and that’s the middle blue bar in the chart. And I’ll talk about growth from there. The Libya downtime accounted for 28,000 barrels per day reduction compared to last year’s third quarter, but that was partially offset by lower downtime in the rest of our operations around 11,000 per day in this year’s third quarter. The key is the next two bars. You can see that growth of 215,000 barrels per day more than offset declines of 186,000 barrels per day, this represents net organic growth of 29,000 per day or about 2% adjusted for dispositions and downtime. The majority of the growth came from our development projects in the Lower 48 shale plays, growth in our oil sands asset from China. And as I mentioned before this should be the low point on continuing operations volume that we’ve been predicting for a while and we are now positioned for an upward trend. If you turn to Slide 6, I’ll make a few comments about the improving margin trend we also have underway. This slide shows how our third quarter growth and changing mix drove cash margin improvement compared to last year’s third quarter. The chart shows the change in this quarter’s volumes by region and product compared to last year’s third quarter. The growth shown in green is all from liquids. In addition, it’s coming in areas with more favorable fiscal terms in the company average notably the Lower 48, Canada and the Asia-Pacific and the Middle East segments. Normal field declines in Alaska and Europe and lower natural gas North American natural gas production somewhat offset the growth. Slide 7, shows the impact of our growth, mix shift and fiscals on our margin performance. This slide shows sequential and year-over-year cash margins both on a reported basis and on price normalized basis. Compared to last year’s third quarter, cash margins grew 13%, sequentially cash margins grew 6% and realized prices improved compared to both periods, but that’s not the whole story. On the right side of the page using our public sensitivity as we price normalized margins with last year’s third quarter as the base line, as you can see cash margins improved 3% on a price normalized basis compared to last year. This metric will tend to be volatile on a quarter-by-quarter basis, but we expect the trend to continue to improve as we shift production towards higher value products and places with more favorable fiscal terms. And we will continue to track and report this metric. I’ll wrap up my comments with our cash flow waterfall and quarter financial position on slide eight. I am going to talk you through our cash flow and this does not include the proceeds from Kashagan, which we announced this morning and virtually our fourth quarter item. Through the third quarter of 2013, we generated $11.8 billion of cash from continuing operations and our working capital was about $100 million source of cash. Through the end of September, we’ve generated $3.2 billion in asset sales proceeds from the sale of Cedar Creek Anticline asset, the Clyden asset, the Phoenix Park and some smaller asset packages. If you include Kashagan, and this increases to $8.6 billion. So, far this year, we’ve funded $11.9 billion capital program for continuing operations and paid out $2.5 billion in dividends. Debt and other, which includes the capital, associated with discontinued operations accounts for $1.2 billion use of cash in 2013. So, we had $3.9 billion of cash on hand as of September 30, essentially flat to where we started the year. Our balance sheet and financial situation are very strong and just got stronger today with the closing and receipt of the proceeds from the Kashagan disposition. We are in a great position to execute our investment programs and deliver value through a combination of organic growth, improving margins and a compelling dividend. That concludes the review of the financial overview and now I’m going to turn the call over to Matt for an update on our operations which begins on Slide 9.

Thank you, Jeff. As Jeff mentioned the main theme of this quarter’s operational performance has been on plan, in fact that’s been the theme over the past several quarters. I’m going to cover the operations material by our capital categories. As a reminder those are high qualify based assets, our lower risk development drilling programs, our major projects, and our exploration program. So I’ll begin with a quick review of our base asset performance. Most importantly this quarter’s major turnaround and tie-in activity went according to plan. And this essentially completes the majority of a major turnaround activity for this year. I’ll run through a few of these key activities quickly. Alaska experienced high seasonal turnaround activity at Kuparuk and Prudhoe, and the Lower 48 we had planned downtime of the Lost Cabin Gas Plant. In the UK, the Britannia Area and Southern North Sea turnarounds were completed and planned maintenance was also recently completed at the Foster Creek in the oil sands. The shutdown activity that began in Norway’s Greater Ekofisk complex in June was completed early in the third quarter and included the brownfield work necessary for the new Ekofisk South and Eldfisk II projects. As the chart on the lower left shows, most of our planned turnaround activity is complete for the year. Fourth quarter turnarounds are nearing completion at Clear and Qatargas 3. The restart of the assets after the recent turnaround should deliver strong volume momentum in the fourth quarter. So will the expected production startup in the East Irish Sea following about a year long shutdown there to replace the asset gas plant. So you can see our base assets performed well. Now let’s move on to our development programs on Slide 10. These development programs consist of lower risk drilling led activities around the world that mitigate our base decline and generate higher margins and attractive returns and these programs remain on track to deliver about 600,000 BOE per day of production by 2017 as shown on the top left graphic. In the Kuparuk Field in Alaska, our core chipping drilling sidetracks continued in the third quarter. Since changes are made to Alaska’s fiscal with the more Alaska production act, we added a rig in Kuparuk at the end of May. We are planning to add another rig for development drilling at Kuparuk in January and we continue to work with partners and improve to identify additional opportunities to increase activity there. A big milestone for the quarter was reaching 500,000 BOE per day in the Lower 48. Of course, this is largely due to performance from the unconventionals in the Eagle Ford’s and the Bakken, but continuing good performance from the Permian conventional program. A couple of highlights from these place Bakken production averaged 334,000 BOE per day in the year’s third quarter, up 31% compared to the same quarter last year and up 13% sequentially. Our focus during the third quarter was in the time from drilling a layout to bringing in on production. This continues to be a focus and will become even more important as we shift the pad drilling. At the end of the third quarter we had 11 operated rigs running in the Bakken, nine of which were pad drilling. The Eagle Ford also continued to deliver strong performance. Third quarter production averaged to 126,000 BOE per day, up 66% compared to the third quarter of last year. Sequentially the Eagle Ford grew 4%, a bit lower than the first half of 2013’s growth because this quarter was impacted by the commissioning of further stages of the Helena and Sugarloaf stabilization facilities and maintenance of third-party facilities to increase meter sizes resulting in a slight increase in downtime versus the second quarter. At the end of the third quarter, we had a backlog of 77 wells waiting on facilities on various stages of completion. This represents a 38% reduction in our inventory compared to year end 2012. So we are gaining on the backlog. The Eagle Ford exited the third quarter over a 130,000 BOE a day. And for the fourth quarter, we will continue to run 11 rigs in the play and expect to bring on between 50 and 60 operated wells. As we head into 2014, we are in full transition to multi-well pad drilling are more than 1,800 remaining identified well locations assuming in 80-acre well spacing. Right now six out of the 11 rigs running in the Eagle Ford are pad drilling. And we expect to see more variability in the quarterly production levels as we move to pad drilling, but we anticipate continued growth in this asset next year. In Western Canada, we continue to see good results from margin enhancing drilling programs in the liquid-rich plays, here our development drilling activity continues to focus on the Glauconite, Montney, Lower Cretaceous and Tri Asset place. Activity levels are expected to ramp up in the fourth quarter as we prepare for and execute our winter drilling program. Finally, our legacy field development programs are also on track through all of our operating areas. Now, let’s discuss our major projects on slide 11, we were approaching some very important milestones. Our projects that are very high levels of activity and remain on track to deliver about 400,000 BOE per day of production by 2017, as shown on the top left graph. Virtually, all business segments are contributing to our growth from major projects. In Alaska, our CD5 project construction is progressing on schedule and preparations are underway for the winter construction season when the ice roads are in place. We continue to pursue engineering work and additional satellite projects for sanctioning in 2014. For example work is underway at Shark Tooth and Greater Moose’s Tooth 1. We will make a decision on these projects late next year. You also probably saw a recent announcement about the site selection for a possible Alaskan LNG project which we now refer to as AKLNG. Along with our co-venturers we are performing studies now to determine the feasibility of that project. Our oil sands project are performing as planned, the combined oil sands project averaged a 107,000 BOE per day during the quarter, up 16% year-over-year. Christina Lake Phase E started up in mid-July and this should add about 20,000 BOE net over the next several months. At our operative Surmont 2 project, we remain on plan for first team in the first half of 2015. You may have seen the announcement that we achieved first oil at Ekofisk South last week, a couple of months ahead of schedule. This is an exciting milestone for the company. Over the next few years, we’ll ramp up volumes as we drill 35 producing wells and eight injection wells. And by early 2015, we’ll also start first production at Eldfisk 2, so we are positioning ourselves to achieve significant growth in Norway and extend field life for decades to come. Adjustment in the UK, we’re in the final stages of our commissioning and start our preparations before initiating first oil, offshore rooftop is progressing as planned and four wells have been perforated under ready for first production. Jasmine has started of later in this quarter, which would provide good exit rate momentum going into 2014. At Curtis Island, we continue to progress our APLNG project, 311 is still on schedule for first LNG by mid-215 and critical milestones have been achieved on the project. We’ve got lot going on in Malaysia, we’re close to achieving major projects, stackups and two non-operated projects Gumusut and Siakap North-Petai. Gumusut offshore commissioning continues the 10 and final rise that was installed in early September and flow line installations are complete, they operate rest of them is the full fuel starts-up will be in early Q1, 2014. The Siakap North-Petai development is continuing hookup from pre-commissioning. Umbilical installations are complete and Flowline installation is underway and they operate rest of them is to start Umbilical right at the end of this year. Malaysia the Kapampangan development is also progressing, top side fabrication is running ahead of schedule and drilling commenced in August. The overall project remains on track for first production in the fourth quarter of 2014. So you can tell what are very exciting is critical time in many of our major products and they will be a key driver in our volume growth over the next few years. So now I want to briefly recover our exploration program on slide 12. Our exploration efforts continue on several fronts, we are building an inventory of both conventional and unconventional opportunities. We are drilling several non-operative prospects currently and we are advancing our operating prospects to the drill-ready stage. We currently have three conventional prospects drilling in the Deepwater Gulf of Mexico program. We have an interest in the Gila and Deep Nansen wildcat prospects. In addition, we have interest in the Tiber appraisal well. So we are participating in some big important lower tertiary wells. We are also currently progressing our plans for our operating drilling program in the Gulf for 2014. And the Browse Basin of Australia, we have drilled a Proteus-1 discovery during the recent quarter. This was an untested structure to the Southeast of the Poseidon discovery. In Indonesia, we obtained government approval for the Palangkaraya farm-in agreement, onshore Kalimantan. This creates the way to begin drilling next year. In Malaysia, we completed our seismic activity in block SB-311. In the Kwanza Basin in Angola, we completed our 3D seismic program earlier in the year. We identified and ranked several prospects and expect to be drilling nearby mid next year. And we’re just discussing several unconventional plays, especially in North America. In the Permian Basin, we’re testing prospective zones across our leaseholds in the Delaware and Midland basins. In the Niobrara, we currently have one rig in the field executing an appraisal program. It’s too early to discuss results in the Permian and Niobrara, but we’re encouraged by the preliminary results. In Canada, we continue to drill and appraise that differently in Montney plays and we’re also gearing up for our second season of winter drilling in the Mackenzie Valley Canal play. It sounds a pretty quick overview of our operations in exploration activity and the key takeaways of these, the operations are running well. The development programs are delivering. Stocked up of several growth projects are underway or eminent and we’ve got high level of exploration activity. If you turn to Slide 13, I’ll quickly cover all this, all adds up to our production outlook for this year. The table in the bottom of the slide provides actual volumes for the first three quarters of the year and our expected range for the fourth quarter. The data is provided for both continuing and discontinued operations. Our overall volume guidance for the year is unchanged except in the fourth quarter, we’re now removing 50,000 BOE from Libya as a result of the ongoing disruptions there. What’s important to know is that the fourth volumes are expected to ramp up from the third quarter due to lower turnaround activity, ramp up in our unconventional programs and the major projects startups. The range in fourth quarter volumes reflects statistical variability in major projects startup timing. We’ll announce our 2014 production target with a capital release in December. In the meantime, we’re positioned to deliver such strong activity in 2013 and now provide strong momentum towards achieving our organic growth goals next year. Now please turn to Slide 14 for our summary comments. Operationally, we’ve arrived at very important inflection point for the Company. We have several key milestones to achieve this quarter and we should have volume growth momentum out of 2013. So in 2014, you should expect to see increased production from our major projects at Ekofisk South, Jasmine, Britannia long-term compression, Gumusut, Siakap North-Petai, Kebabangan, Christina Lake Phase E, Foster Creek Phase F and Lower 48 unconventional programs at Eagle Ford, Bakken and Permian. All these projects have contributed to 3% to 5% production growth as we detailed in our analyst meeting earlier in the year. And as always, we expect to deliver our operational performance safely and efficiently. We’re committing to maintaining a strong balance sheet that can provide financial flexibility. We’re seeing the early stages of cash margin expansion, which should improve as our volumes grow. We’re focused on improving the tons and that’s a driver behind continuing to rebalance our portfolio and allocate capital prudently. We’re delivering on our value proposition. We continue to progress on our earnings asset divestitures and this will provide a financial flexibilities to fund our investment programs and our dividend, which remains a top priority; so I hope Jeff and I have given you confidence that our plans are on track for delivering key milestones this year, and positioning ConocoPhillips for an exciting 2014. And now we’re pleased to take your questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) And our first question is from Ed Westlake of Credit Suisse. Please go ahead. Ed Westlake – Credit Suisse: Hi, good afternoon and congrats on the delivery so far this year against your plan.

Thank you. Ed Westlake – Credit Suisse: I guess in the slides Jeff you’ve outlined $6 billion of incremental cash flow from the production growth between sort of 2013 and 2017 in a flat macro type, which is going to obviously increase your financial flexibility of the top line. But I’ve got a question on CapEx, you’re still investing in – and you’re still investing in some LNG. Is there a year as you look out in the sort of the CapEx profile where as you sort of finalize some of those longer lived assets, you got a bit more flexibility in terms of how you could allocate sort of CapEx in the Upstream business?

Yeah, that’s certainly going to be the case Ed, and really we’ll detail this more in December like we indicated on our early in the call as far as 2014 capital will be. But the effect we’re pointing out is probably going to be fairly pronounced in 2014, where APLNG capital will hit a peak, Surmont 2 capital will hit a peak and we will be continuing to fund the expansions in the new oil sands of Foster Creek and Christina Lake. And as we go through time will see some of those projects tail off and which will give us more flexibility to handle increase flows stemmed from the unconventionals? Ed Westlake – Credit Suisse: Great. And then in terms of obviously the longer we go through time and with Kashagan receipts in and the balance sheet looking a little bit more robust and clearly oil price hasn’t collapsed in anyway; I mean what are your thoughts about maybe re-instituting a buyback program?

Right. So at the end of this year assuming we continue to progress the rest of our asset sales program. We’re going to have significant cash balances. At the end of the year, we could be approaching nearly $10 billion – in that neighborhood of $10 billion of cash in our balance sheet. As we think through 2014 and 2015, we’re going to be increasing our cash flow, but still at the point where cash from operations is not going to completely cover capital and dividends. In terms of a buyback, I think that is something we’re going to be thinking more about as we get to the point where cash from operations, funds capital and dividends on a go forward basis. Near-term I think we feel like it is important to maintain a significant level of financial flexibility to adequately invest in our capital program and fund our dividend. Ed Westlake – Credit Suisse: Okay. That’s very helpful. Thanks so much, Jeff.

Thanks Ed.

Thank you. Our next question is from Doug Terreson of ISI. Please go ahead. Doug Terreson – ISI Group: Congratulations on your results everybody.

Thanks Doug. Doug Terreson – ISI Group: U.S. production growth has obviously been a major success story for the company and I think out by another 40% this quarter from Eagle Ford, Bakken and Permian, yet it seems like the potential from the Eagle Ford continues to improve as more as known about the Company’s position. So my first question is whether Matt would agree, and second whether there will be any additional color on the position in Eagle Ford related activity, efficiency or financial performance that is stronger versus the original expectations, what has really changed here because it seems like you are much more enthusiastic on this position?

Yeah Doug. We are still very excited and I would say getting more excited about Eagle Ford position and we continue to run a consistent program there, we are running 11 rigs. Our intention is essentially to continue that and we’ll continue to see production growth because of that. What we’ve indicated as we’ve got them remaining about 1800 well locations in the Eagle ford to drill and that’s all based on the assumption that we continue to drill the 80 acre spacing and we have pilot tests underway to determine if that is the right spacing that may ultimately tighten up and there will be more drilling locations. We are also looking other levels in the Eagle Ford and for potential too. So we are still very excited about the Eagle Ford position and then we’re going to see significant growth and very high margin growth from the Eagle Ford for several years to come. Doug Terreson – ISI Group: Thanks Matt. And secondly in Alaska, it appears that passage of SB21 will impact activity in the state and because you guys are largest producers in acreage order seems that you’ll be the leading beneficiary. But at the same time your portfolio of how return opportunities is strong as it’s been in several years. So, the question is twofold. :

Yes, so the first part is SB21, the that’s not probably more or less Alaska Production Act that was a significant change as a result of that we will spend more capital in Alaska. There are opportunities for investment – with the change to the fiscal regime competitive and our international portfolio. So we will be doing that. We’ve enhanced a few of those I mentioned few on the call. So we definitely see potential and you’re right we are very well positioned in Alaska to as the largest producer. On the ANs and sales and so we do have the flexibility if we want to exercise to take ANs cargos to Asia and we do have the right to do that. And that will depend on the differential that we’re seeing to Asian prices versus West Coast prices obviously. But it is good to have that flexibility and then as time evolves we will see if this flexibility we need to exercise. Doug Terreson – ISI Group: Great. Thanks a lot everybody.

Thanks a lot.

Thank you. Our next question is from Paul Sankey of Deutsche Bank. Please go ahead. Paul Sankey – Deutsche Bank: Hi. Good afternoon everyone. I want to squall the analyst meeting party too much if I can just clarify that the page 13, volume guidance for the full year of 2013 in Q4 is consistent, I obviously seem it is with the Slide nine outlook that you have there on the high quality legacy base production. I’m basically trying to get to 2014, 2015 volume number for you guys.

Yeah, as we had indicated in the beginning of the year Paul that we would be intending to exit the year essentially at the same level as we come into the year and so that growth you see on Slide nine and the exit that we’re moving towards in the fourth quarter here they’re both consistent. Now, there is the complication of exactly what’s going to happen in Libya I mean that’s 50,000 barrels a day of production, it’s not going anywhere and it is still going to be there to produce but it’s really uncertain as to how that will play out over the next several months. But yeah there is both internally consistent yes… Paul Sankey – Deutsche Bank: I would have thought there Libya thinking about the Slide 9 was seems to be flat. I mean was neither declining nor growing I guess?

Yeah there was some slight growth actually coming in Libya as we increased our ability to process and sell gas there and the overall scheme of things that was 15,000, 16,000 barrels a day. And that of course is in the base on Slide nine. That’s grey base on the graphic in the top of top left hand side of Slide nine. Paul Sankey – Deutsche Bank: Yeah. Again I don’t want to kind of spoil – talking too much at the analyst meeting. But I guess what I’m trying to push towards is this Slide nine outlook is broadly unchanged even allowing for Libya and can be considered to be your outlook for volumes basically.

Just to be precise Paul the Slide nine outlook as Libya included in it Libya just really had to predict what’s... Paul Sankey – Deutsche Bank: In anyway you basically outperforming your expectations given that you’ve kept the same number but you’ve lost Libya basically, right?

Well we have lowered our fourth quarter numbers to reflect the assumption that Libya will just be off in the fourth quarter but we have not changed our go forward 2013 and beyond numbers and those all still include Libya. Paul Sankey – Deutsche Bank: Yeah I have got you. Not wanting to be – on page 13 the Libya numbers are just completely excluded from 4Q because I’m thinking continuing with this, it is not in either of those.

For the full quarter that’s right. So we show them on that slide, we show them as a light blue color at the top just to give perspective or scale. But we’re assuming in the guidance that we’re giving now for the fourth quarter that Libya won’t come back, it may come back in the fourth quarter but we’re assuming for this guidance that it doesn’t. Paul Sankey – Deutsche Bank: No I understand, yeah I do. And then again, from analyst meeting your previous guidance on CapEx going forward, I think was about $15.5 billion to $16 billion a year. Is that correct?

I think we’ve been seeing as around 16 as basically the guidance we gave at Analyst Day. Paul Sankey – Deutsche Bank: That’s the last sort of forward guidance you gave to work on this annual around 16.

Yeah. Paul Sankey – Deutsche Bank: And then I guess just a follow up simply the old questions further to Doug, which is, why don’t you accelerate in the Eagle Ford. Thanks.

Well the flexibility exist to do that in the Eagle Ford, we focused on a few different things here to establish with a optimum array of development is first thing as we want to make sure that we’re operating efficiently and safely so that that comes in as an important factor and we want to move towards Pad drilling and we want to make sure we don’t get in front of infrastructure constraints. And the Eagle Ford, we want to make sure that we are taking advantage of the learning curve because we’re continuing to see learning curve improvements and want to take advantage of that before we ramp up and we want to get results from the many pilot tests we are running in the Eagle Ford too. So we are making sure whether our investment in capital is efficiently as it can. And these opportunities are not going away so, so we want to – we think that our strategy is the right strategy for us in the Eagle Ford.

Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead. Paul Cheng – Barclays Capital: Hi, guys. Simple quick question hopefully. Jeff I was looking at your result in the Lower 48, it looked like your [indiscernible] sequentially from the second to the third quarter up by about 1.50 per barrel, is there any particular reason why there is such a big jump?

I don’t know the details of that fall. Generally as we’re bringing on some of these unconventional production, our reserve bookings are still being down on a fairly conservative basis. So you’re finding fairly – you are finding higher DD&A rates on some of the unconventional properties and we will probably see longer term that’s probably the biggest single driver that’s going on there. Paul Cheng – Barclays Capital: I hear you but I mean from the first to the second quarter do you also see production increase but your unit DD&A is pretty flat, you are just there from the second to third then all of a sudden you jump by $1.50 so that seems very high so maybe that if you can some one to get back to me.

Yeah we will definitely get back on that detail, Paul. Paul Cheng – Barclays Capital: Okay. And in your – you indicate that on Alaska have a negative impact from the lifting I presume you have underneath. Can you quantify how big is that?

The lift timing in general for this quarter were not big factors. So, we didn’t highlight them in the earnings release, the second quarter of Alaska had a favorable impact and the third quarter was relatively small I believe negative impact it was in order of $10 million to $15 million in Alaska where the positive impact in the second quarter I know we mentioned that on our second quarter call that was a much larger number. Paul Cheng – Barclays Capital: And then the company as a whole doesn’t have a lot because when I’m looking at your supplemental slide, you indicate that in the third quarter the total company had a overleap of 19,000 barrel per day.

Yeah, that’s right Paul. So in general the overall company impact from timing was relatively small this quarter we had slight negatives in Alaska and some slight positives in other regions but none of them were large enough that we felt like it made since the highlight on this quarter. Paul Cheng – Barclays Capital: And then a final one on I think probably for Matt, Matt in Permian it look like that in the third quarter based on the data that you gave back in that will be about 54,000 barrel per day. Are those all conventional oil production or that some of them is actually already in the oil production?

The vast majority is from the conventional production 4,000 or 5,000 barrels a day production from the unconventional just now in the Permian really in the exploration and appraisal phase in the unconventionals. So the vast majority is from our conventional program. And that program is doing great that’s a very high return programs of lots of running room there. So in the unconventional we’re continuing to evaluate the position that we have and we’re feeling good about that too. Paul Cheng – Barclays Capital: Matt if you’re looking out over the next two or three years and – Permian between unconventional and conventional component. What is the growth projection that you expect for both sides?

So we’re going to see growth in both the rate of growth obviously in the unconventionals will be a lot faster because we are starting from a lower base. But we’re going to see significant growth over the next five years on both the conventional and the unconventional and… Paul Cheng – Barclays Capital: Any number you can share say are we talking about over the next five years on the conventional side going by say 50,000 barrel per day; unconventional side going by say 30,000 barrel per day or any kind of number you can share?

Well actually we gave an indication of this, our expectations on the analyst day. So if you go back to the analyst day presentation we had a specific slide on the expectations for growth in the conventionals and the unconventionals in the Permian. So and our view hasn’t changed since then. And we’ll update our view of that in our next analyst day in April. That’s a good go back from that Paul.

Thank you. Our next question is from Scott Hanold of RBC Capital Markets. Please go ahead. Scott Hanold – RBC Capital Markets: Yeah. Thanks. Since, we are sort of on this unconventional conversation with the Permian I just want to dive in a little bit more on that I mean when do you all think you will feel more comfortable with looking at plays like the Niobrara in the Permian or any of these other unconventional plays you’re testing today to actually get to the decision to put more capital and get somewhat of a development program going. Is that something that is a more of a later 2015 event or could we see that sooner than that

So for the Niobrara for example with the one rig running there, we feel 11 wells with the 51 production. And we’re very well – I think very well through appraisal program. This is going to run through the end of the 2014. And the end of 2014, we really know the scale and the scope of our Niobrara development and that’s when we’ll make the development decision where the characteristics of that will be. The same really applies in the Permian as well. We’ll go through our test in our portfolio there. Making sure that we understand which of the different perspective horizons, the Avalon, the Bone Springs, the various Wolfcamp horizons are for the right – the potential and the right place to start that development. So let’s see that’s probably on about the same timeline by the end of 2014 we’ll have a really good sense of that’s going to develop and in both of those we’ll give some more guidance in the analyst meet in April. Scott Hanold - RBC Capital Markets: Okay. And are your acreage positions in like each of those places specifically, large enough for the – probably the size of Conoco?

I would say so. And I think that we have got 130,000 acres in the Niobrara, and we’ve got about 150,000 acres in the Delaware Basin and about 90,000 acres in the Midland Basin and with multiple horizons that exist in those plays, yes, it’s a pretty significant position even for a company of our size. Scott Hanold – RBC Capital Markets: Okay. And then one last question, on the concept of Alaska LNG project, APLNG as you all call it. Can you give me a little more thoughts on what the views in terms of getting a project, when could we expect to see those ought potentially pushing forward that and how that kind of reflects other projects coming on in the global market?

Okay so the status of APLNG is that we’ve selected a concept and spoke about that as you might remember Scott spoke about that maybe on the last call. The concept we’ve selected. We’ve announced in this quarter of the site location that we’re favoring for the location of the LNG plant in the Kinai area and so Central Alaska. We’re moving towards the stage of getting into Prescott fleet so the early stages of engineering and we’re in conversations with the co-venturers and with the state of Alaska on the timing of that. We did quite an extensive summer field work season on the pipeline, but this is premature to put in a timeline as to claim first production would be because there is a – there is a lot of a water to flow under the bridge. But we’re focused on it, we and the co-venturers and state the focus on that making sure that we fully understand the viability of that project. Scott Hanold – RBC Capital Markets: So maybe ask the question in a different way than to make this viable. What kind of size of this project needs to be for you guys?

It’s going to be a very large scale project because in each of the resource base there. And we think this could be a competitive project with other sources of supply otherwise we wouldn’t be pursuing it. So it’s going to be of pricing of scale I mean it is somewhere between $45 billion and $60 billion of capital. It’s what we expect it is going to cost.

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. I have a couple if I may. Jeff on the deferred tax with the start up of Norway and obviously I’m not quite sure how other major projects are going to be treated like this, but can you give us some ideas to whether or not you will have a touch you’re building as some of these major projects come on stream.

I am not sure I understand your question, just let me try and answer if that’s not what you are asking. Doug Leggate – Bank of America Merrill Lynch: Let me try and help a little bit so Ekofisk in Norway you get to uplift your capital if you’ve spent on the development. So I’m curious just to know are you going to be paying cash taxes on some of these which are the projects and Norway in particular I guess and will you see an uptick in your deferred tax line I am just thinking about the cash flow as we move forward.

Yeah, there is lot of moving pieces on deferred taxes. And if you think about how things are treated tax wise around the world. Norway you get a relatively quick recovery of your capital. In the UK, you get a very quick recovery of capital. In the Lower 48 we are spending a quite a bit of capital to the extent you have IDCs we get a quick recovery of capital there as well. So what you’ll see in this year and what you’ll see probably on into next year. And then it gets harder to model as you go into subsequent years, is that the deferred taxes in general you can think of has been a source of cash for us on the cash flow statement. So far this year it’s been about a $1 billion source of cash, whether keeps running at exactly the rate we have seen for the last few quarters it’s hard to predict but it’s going to certainly, it’s going to be a positive number. So you could consider that a source of cash for both 2013 and 2014. Doug Leggate – Bank of America Merrill Lynch: Thanks. And as a signal, I am sure you are aware of this, but – your pure play E&P peers gets some guidance on how much is expected to be – something you might consider which should be – would be really helpful if you would. A couple of quick follow ups please. I guess is related to some of the questions of how to raise that the Eagle Ford, I would like to turn it to the Bakken place. Number of your peers have talked abtour resetting your development plans based on Q4 success and down spacing success. I am just curious about the new acreage of – going on. I am just curious as that how you’re thinking about that going forward?

Thanks. As I am sure you aware of this but what your pure play E&P peers give some guidance on how much is expected to be current and deferred on all times something you might consider it would be very helpful if you would. A couple of quick follow ups please I guess this is related to some of the questions at -- but the Eagle Ford I would like to turn to the Bakken please Matt numbers of your peers have talked about resetting their development plans based on Three Fork success and down spacing success. I am just curious about I mean your acreage is right in the heart of where all of that stuff going on. I am just curious as that how you are thinking about that going forward?

Yeah that we are thinking about that Doug and we’ve got some pilot test underway. Right now we are developing on a cost effectively 320 acres space and we’re developing both the Middle Bakken and the Three Forks it’s quite possible that we ultimately will want to tighten up that space. And so we have pilot test underway to try and give us a good sense of possibly optimum spacing and what level of communication exist between the Middle Bakken and the Three Forks that for the frac that we have delivered doing just now. So yeah, we are pursuing the potential for down spacing in the Bakken. Doug Leggate – Bank of America Merrill Lynch: Normal price increase the rig count any time soon?

No I don’t think so my comments on that are sort of very similar to the Eagle Ford. I think we’re running 11 rigs in the Bakken and I think that that’s the right level for now. But one of the beauties of these unconventional plays is that you do have flexibility and it is just a question of making sure that we’re exercising that flexibility at the right time and moving over the right information. Doug Leggate – Bank of America Merrill Lynch: Thanks and just one final one if I can just squeeze it in. Jeff I don’t want to like – I am try and front on the Analyst Day, but I just want to pick up in your comments about APLNG and CapEx peaking. I just wanted to be clear were you talking specifically about 2014, should we be, directionally can you give us any kind of feel is the how the spending should go 2014 over 2013 and 2015 over 2014? I’ll leave it that, thank you.

I think we would, it’s going to be a fairly short period of time from now where we can talk a lot more precisely about that with you know. We’re in the middle of wrapping up our capital outlook for next. And as Ellen mentioned at the top of the call, we’ll be back to you with that in fairly early December.

Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead. Faisel Khan – Citigroup Inc.: Hi, thank you. Good afternoon.

Hi, Faisel. Faisel Khan – Citigroup Inc.: Hi. Just looking at the project startups you guys have Ekofisk, Eldfisk, Gumusut, Jasmine. I mean what’s the I’m looking at your at that I think its page seven sort of cash margin per barrel. What do you say that these projects collectively sort of have in terms of the cash margins per barrel? I’m just trying to get a sense of sort of what the margin uplift is going to be. I know you guys talk about it but these are three or four big projects that could have a material impact to cash flows?

Generally what we’ve looked at; when we think about everything that we’re adding to our portfolio over kind of between now and 2017 that kind of mix has generally low 40s kind of cash margin to it. And it is when you mix that kind of cash margin with what’s really a high-20s is kind of cash market for us right now that you get that kind of growth. I think our views on this really aren’t any different than what we had in the analyst presentation where we actually, if you recall we had a chart there that kind of plotted cash margins and production growth and it kind of pointed to kind of that same what I just said kind of low-40s type number overall. Some things like Malaysia where you get capital recovery for the terms of the TSC in the early parts of the year, you end with some even higher than cash margins as you are giving capital recovery. Faisel Khan – Citigroup Inc.: Okay. And in terms of Eldfisk and Ekofisk those in that same $40 sort of ballpark numbers?

They’re probably a little bit, they’re probably a bit lower than that because of where the taxes are in Norway, they’re probably a little bit, they’re more in the 30s than they are in the 40s. Faisel Khan – Citigroup Inc.: Okay, okay understood. And then just in terms of the Eagle Ford, can you give us some little more color on a well cost and I know those numbers have been trending down for you in the last quarter. But can you let us know kind of where you are today and how we can compare that to rest of the periods in the industry?

We’re continuing to see improvements Faisel across the boards and our drilling cost in particular. We have recently increased the size of our frac jobs, starting in September we’ve increased the size of our frac job significantly so completion cost are going up, but for good reason. And what will do the analyst day as we will give you a good breakdown of how that learning curve is being preceding and the overall cost at that time? Faisel Khan – Citigroup Inc.: Okay, okay fair enough. And then in terms of APLNG just any update on labor productivity and how that’s trending with both the downstream build out and also any updates on the upstream, any upstream issues or things to note on it, any changes from last time when the cost sort of built up a little bit because of the upstream sort of part of the business?

No. The project is going well, we are about 50% complete on the upstream part of the project, about 54% complete on the downstream. And we’re tracking really against the milestones that we have outlined for both the downstream and the upstream project and we’re very focused now on getting ready for first production. So we’re staffing up our operating and staff for that but obviously the project is going well again and April will give an update on the status of that but the projects on track and we are pretty happy with where things are going there.

Thank you. Our next question is from John Herrlin of Societe Generale. Please go ahead. John Herrlin – Societe Generale: Yeah, hi, John is on for Matt on the unconventionals not to be the dead horse we know you have the in fill potential with the Eagle Ford and the Bakken . In the past you’ve talked about thinking of in terms of field kind of plateau levels would you rather extend the plateau or increase the rate for the given intervals you expect to peak production or place like the Bakken and the Eagle Ford or is that still to be determined?

So the answer is sort of easy both and I would like to increase the plateau size and increase the duration and the opportunity said they exist in our Eagle Ford , Permian and Bakken acreages just going to give us the opportunity to do that. And that is another thing that we’re going to get more guidance on but it potentially exists to do both in those plays. John Herrlin – SG Securities: Okay. That’s fair. With some of the newer plays that are kind of in the germinal stages, do you have any acreage retention issues like in the Permian and Niobrara?

No acreage retention issues that we are not able to manage. So we are not going to run in to any issues of losing acreage that we think is prospective, that’s one of the thing, the end points, that is how we organize our drilling schedule in these plays. John Herrlin – SG Securities: Okay. That’s fair. In Canada with plays like the Duvernay, some of your peers have had pretty high costs and I know it’s early days are the costs more prohibitive in terms of getting more aggressive up in Canada for unconventionals at the U.S.?

Yeah no I wouldn’t say, no. I mean in fact our development drilling programs and explorations programs in Canada have been reducing costs that they have we actually seen capital efficiency there so and I wouldn’t say that we are seeing that sort of pressure at all in the Duvernay or Montney while the other plays are pursuing up there.. John Herrlin – SG Securities: Okay. Last one from me as more oriented towards Jeff I guess. You’ve made some very large chunky asset sales and in the future should we see more smaller type byte size sales rather than large turnkey assets.

I think portfolio of our size you probably expect there’ll always be a little bit of assets sales that are happening that could be smaller assets sales I think that it’s still out there that we talked about on previous calls as whether we choose to do something to do lower our concentration in oil sands and that could be just because of the nature of how large of an asset that is for us even a relatively small change and that could be a fairly significant number. But other than I think the larger asset sales are behind us now and you will see things these be smaller.

Thank you. Our next question is from Roger Reid of Wells Fargo. Please go ahead. Roger Reid – Wells Fargo: Good afternoon.

Hello Roger. Roger Reid – Wells Fargo: I guess but kind of melding the Eagle Ford question with the cash flow questions. I would imagine where you are on your drilling compared to some other companies your not cash flow positive in the Eagle Ford if that’s correct I’d appreciate the correction but maybe a timing on when you could be free cash positive?

So we are today. Roger Reid – Wells Fargo: You are free cash flow positive today.

Yeah, we’re right above free cash flow positive today. Roger Reid – Wells Fargo: Okay and all right. So that’s question one the other one was, as we look at the decline rate that you’ve highlighted on one of the early charts. I think I calculated at about 13% roughly 186, I think it was 1000 barrels a day of decline. What as you go forward and add some of the big projects that you’re adding, some of the ones obviously that you started up are pretty traditional, but thinking maybe more like APLNG and so forth, do we get a slower decline rate going forward and is that part of the production growth uptick we would expect to see kind of let’s say exit rate for 2014 into 2016.

So our overall decline rate in our base production is about 10% in a year and over the next five years. And then as the production mix changes over those years for example we drill an oil sands and we add APLNG and then the base decline that would tend to mitigate the underlying base decline. In the other hand we are also growing there by drilling unconventional which on the higher end overall decline so our expectation is that 10% underlying base decline rate is probably good buying for the next five years. Roger Reid – Wells Fargo: Okay, well that was a two things, I wanted to hear. Appreciate it. Thank you.

Thank you. Ellen R. DeSanctis: Thank you, Roger.

Thank you. Our next question is from Kate Minyard of JPMorgan. Please go ahead. Katherine L. Minyard – JPMorgan: Hi, good afternoon everyone.

Hi Kate. Katherine L. Minyard – JPMorgan: Hi, I was wondering, I would like to go back to the ANs question or the ANs topic if I could, you talked about having the option to send ANs volumes over to Asia. Is that just an option that there is a one that you really diligently explored and I guess if I ask it another way, if you look out two years, how likely do you think it is that Alaskan volumes are leaving the U.S. versus remaining domestic?

So what would cause us to really focus on that as an option is if we saw ANs gas traded some significant ANs oil excuse me traded some significant discount, brent prices which we saw for a short period of time back when WTI brent spreads were very wide and those of course have collapsed quite a bit. Now ANs is back to trading pretty much flat with brent prices. It’s an option that we know it’s out there I can’t say that we’ve thoroughly investigating or are trying to make it happen, we know that we could if that were the case whether or not it happens in the next couple of years it will depend a lot on where ANs pricing sits relative to other periods. Katherine L. Minyard – JPMorgan: And have you guys looked at what the shipping differential is between Asia and the West Coast for ANs or have not gotten to that point yet?

Well I think you will have to see that ANs pricing was probably $5 or so below Brent pricing for it to make sense for us to be thinking of doing that. Katherine L. Minyard – JPMorgan: Okay. That’s helpful. Thank you very much. Ellen R. DeSanctis: Thanks Kate.

Thank you. Our next question is from Brandon Mei of Tudor Pickering Holt. Please go ahead. Brandon Mei – Tudor Pickering Holt: Thanks. Two questions for me. First one is on I just want to get your thoughts on pricing in Canada moving forward here in the next year or so.

Okay I mean it’s hard to tell. I mean this is going to remain regulatory, I mean weak and maybe Brandon that your assessment is as good as our assessment. Brandon Mei – Tudor Pickering Holt: Okay. And the second question is on the Venezuela ruling What are the next steps in that process and then how should we think about the timing in the amount of the award, because I think at the amount of time of expropriation the PV10 was around $10 billion.

Yeah, I don’t think we can comment on any expectations of amount but just as far as process goes we have the initial award which sets out some of the parameters upon which the award is going to be, which the financial award is going to be calculated, we now move – are moving into the more detailed assessment of what exactly what that award is and that’s going to be a process that will take a couple of years to evolve and that’s just something what we are going to continue to update as we can, but it’s a process that we continue to work through.

Thank you. Our last question is from Blake Fernandez of Howard Weil. Please go ahead. Blake Fernandez – Howard Weil, Inc.: Folks I had pumped in late in the call. I’ll just limit it to one question. I was just curious where you think we are in the life cycle of a developing technology to economically develop the lower tertiary. I guess when I look at your portfolio, you’ve got several discoveries, you’re drilling the appraisal well at Tiber and talking with peers, such as BP, developing 20K and what not. Is it like the technology isn’t quite there just yet, what kind of confidence do you have that we’re going to get there and when do you think we can reasonably expect our production from the play? Thanks.

So as I’m sure you know Blake that the not all of the Lower Tertiary is at the same pressure and then the same depth. But you’re right that the several paths of the Lower Tertiary are going to require a 20K trees. And that development of those trees is underway and that will come over the next over the next few years. From where – discovery so far, I don’t expect we’ll see production from the Lower Tertiary discoveries and hitting us until the late part of this decade, but the development market this required to make sure that we have the technology in place. But that’s all in hand, then it’s – I mean the development in 20K trees isn’t like the man on the moon, we know how the trees work is a question of just making sure that we’ve built them and getting them certified that we are confident on their deployment, but we will certainly get that done. Blake Fernandez – Howard Weil, Inc.: Okay. Thank you very much.

Thanks Blake.

Thank you.

Back to you operator, we’ll wrap up the call here.

Okay. We have no further questions. I will now turn it back to Ellen DeSanctis.

I have no further comments either. Just appreciate all your time and attention. You’re welcome to call us for any follow-ups and again, thanks for your participation, and enjoy the rest of the day.

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