Ellen R. DeSanctis – Vice President-Investor Relations and Communications Ryan Michael Lance – Chairman and Chief Executive Officer Jeffrey W. Sheets – Executive Vice President- Finance and Chief Financial Officer Matthew J. Fox – Executive Vice President-Exploration and Production Janet Langford Kelly – Senior Vice President-Legal, General Counsel, Corporate Secretary

Faisel Khan – Citigroup Inc. John P. Herrlin Jr. – Societe Generale Scott Hanold – RBC Capital Markets LLC Ed G. Westlake – Credit Suisse Paul Cheng – Barclays Capital, Inc. Doug Leggate – Bank of America Merrill Lynch Paul B. Sankey – Deutsche Bank Securities, Inc. Katherine L. Minyard – JPMorgan

Welcome to the Q2 2013 ConocoPhillips' Earnings Conference Call. My name is Sheri, 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. Ellen, you may begin. Ellen R. DeSanctis: Thank you so much, Sherry and of course thank you to our listeners for joining this second quarter earnings call. I’m joined in the room today by Ryan Lance, our Chairman and CEO; Jeff Sheets, our EVP of Finance and CFO; and Matt Fox, our EVP of Exploration and Production. It’s a very busy day for earnings activity. I know all of you are pressed for time. So we’re going to jump right into the material today really quickly before we get started. If you would please turn to Page 2 you will see our Safe Harbor statement. That of course described the risks and uncertainties in our future performance. Those are also described in our periodic filings with the SEC. I’m going to turn the call over to Ryan now.

Thank you, Ellen, and good afternoon, everybody, and thank you for joining us today. Well, it’s been just over a year since we launched the independent ConocoPhillips as a new class of investment. We’ve laid out a plan that would deliver growth and volumes and margins with a compelling yield. I think as you’re all hear and see today the key pieces of our strategy are falling into place. For the second quarter in a row, organic volumes net of dispositions and planned downtime are growing. Margins are improving. We’re maintaining our commitment to a compelling dividend reflecting our confidence in our plans and our financial position remained strong. So the theme of today’s call is pretty simple. We are successfully executing on our business plan. We’re doing what we said we would do. We continue to keep our eye on the ball and the top priority for of all of us at ConocoPhillips is to operate safely and execute our plans and programs. So let’s get started on Slide 4. Operationally our business performed very well this quarter. We produced 1.552 million BOE per day on a total company basis and 1.51 million BOE per day on a continuing operations basis. Adjusted for dispositions and planned downtime, this represents 4% organic growth compared to a year ago. Last quarter we grew 2% on the same basis. So the organic growth is showing up in our performance. This quarter’s volume performance exceeded the high end of our guidance range and this is primarily due to two things; better than expected performance at Eagle Ford in our Europe and Asia Pacific regions and our seasonal maintenance and planned downtime was executed ahead of plan. Based on this quarter’s stronger than expected volume performance we’re raising our third quarter and full year volume guidance, which Matt will cover in more detail. As you know, the second quarter was a very active period for planned maintenance and we successfully executed key turnarounds. That’s essential to projecting our base assets. In addition, our development activities also have performed well this quarter. And remember, these are lower risk programs with years of inventory that completely mitigate our base decline. Of these, the Eagle Ford stood out in the second quarter. Production averaged more than 120,000 BOE per day, almost double last year’s second quarter rate and up 20% sequentially. Our major growth projects are also on track. These are projects that will generate step-function growth during the next several quarters and years and we have several near-term startups that Matt will also describe in detail. So operationally, we are hitting the milestones we set for ourselves. Now moving to the financial results, adjusted earnings were about $1.8 billion or $1.41 per diluted share. Adjusted earnings were up 17% year-over-year. Excluding working capital, we generated $4.4 billion in cash from continuing operations and ended the quarter with $4 billion of cash in short-term investments. On a year-to-date basis, our cash from continuing operations plus our proceeds from asset sales have covered our dividend and capital programs. Cash margins grew compared to last year’s second quarter, reflecting the impact of product mix, prices and location and strategically this is one of the keys to achieving our value proposition is high-grading our portfolio by selling non-strategic assets and redeploying those proceeds into organic investments that will drive future growth and we’re making good progress on our announced divestiture program. Since the beginning of this year, we’ve received approximately $1.7 billion in proceeds from asset sales and we expect to close Algeria, Nigeria and Kashagan by year-end. These would add approximately $9 billion of additional proceeds in 2013. As we previously discussed, our portfolio efforts will now shift to improving and rebalancing the asset base. We’ll take opportunities to divest the smaller non-strategic assets such as southwest Louisiana conventional assets that we sold in the second quarter. And we’ll also look for ways to rebalance our interest and assets like the oil sands. These are great assets, but one where we believe we’re bit overweighted in our portfolio today. At the same time, we’re monetizing assets. We’re also adding to our conventional and unconventional exploration inventory globally and we’re running this program at a high level of activity. Exploration success like we’ve recently seen at Coronado and Shenandoah is key to sustain any organic growth longer terms. Despite this high level of activity, our 2013 capital outlook is relatively unchanged. We expect to spend about $15.9 billion on continuing operations and $600 million in discontinued operations. That’s a total of $16.5 billion which is an increase of about 4% compared to our announced total company budget. Of this 4% increase, about half reflects our updated expectations around completing the sales of Algeria, Nigeria and Kashagan. So this is capital that will come back to us as adjustments at closing. The remainder of the increase are about 2%, reflects various adjustments across our asset base including high quality additions to our exploration portfolio. Finally, we remain committed to returning capital to our shareholders. Right after the quarter ended, we increased our dividend by 4.5%, reflecting confidence in our growth plans and we have remained committed to consistent dividend increases over time. So in summary, we have a strong quarter operationally, financially and strategically. So next you’ll hear from Jeff and Matt who will give you all the details. So if you please turn to Slide 5 and let Jeff begin his comments on our financial performance. Jeffrey W. Sheets: Thank you, Ryan. This quarter’s adjusted earnings were $1.75 billion or $1.41 per diluted share. This was above consensus, driven primarily by the higher than expected volumes that Ryan just mentioned. Second quarter adjusted earnings were up 17% compared to last year’s second quarter and on an earnings per share basis, adjusted earnings were up 19%, reflecting the impact of our 2012 share repurchases. The year-over-year increase in adjusted earnings was primarily driven by higher margins. The higher margins reflect the continued shift to higher-value liquids in the portfolio as well as the shift to more favorable fiscal machines. Average realized prices were flat and total company volumes were up modestly. Now I’ll cover our production performance for the quarter. So if you’ll turn to Slide 6. Total company production in the second quarter was 1.552 million BOE per day. These results included 42,000 BOE per day from discontinued operations. This chart shows the change in both continuing and discontinued operations compared to the second quarter 2012, but I’ll focus on the continuing operations. Second quarter 2012 production from continuing operations was 1.48 9 million BOE per day. Adjusting for dispositions of 33,000 BOE per day, normalized production from continuing operations was 1.456 million BOE per day in last year’s second quarter and that’s the middle blue bar on the chart. During the second quarter of 2013, planned downtime was 10,000 BOE per day higher than last year’s second quarter, which was mostly due to downtime in the North Sea. Growth of 219,000 Boe per day more than offset decline of 155,000 Boe per day. So normalized for 2012 dispositions and planned downtime, our production from continuing operations increased by 64,000 Boe per day, which I will explain more in the next slide. Year-over-year this represents a 4% organic growth and the second consecutive quarter on this upward trend. So let me take a moment and talk about cash margin trends on slide 7 and 8, starting with contributions from our production growth. So this chart on slide 7 is a new one, it shows how our second quarter growth and changing mix drove cash margin improvement compared to last year. As I just mentioned, volumes from our continuing operations were up 64,000 Boe per day year-over-year, adjusted for dispositions and planned downtime. This chart shows the change in this quarters volumes by segment and product compared to last year’s second quarter. : Normal fuel declines in Alaska, Europe and North America natural gas somewhat offset the growth. The impact of the shift on our cash margins can be seen on the next slide, slide 8. This slide shows sequential and year-over-year cash margins both on a reported basis and a price normalized basis. As you can see on the chart on the left cash margins grew on a reported basis, despite flat overall realized prices compared to the last year’s second quarter. In terms of prices we generally saw North America natural gas prices being offset by decreases in Brent crude prices. So the chart on the left reflects the impact of product mix, prices in location, and you can see this from the chart the cash margins grew both sequentially and year-over-year. But the right side of this chart shows, this is an estimate of what our cash margins would have been, if we had the same pricing in all quarters and we have used the second quarter of 2012 at the baselines, that’s pricing $93 at WTI, $108 Brent, and $2.20 Henry Hub. You can see that on this price normalized basis, the cash margins grew significantly year-over-year and also grew sequentially. So this metric will tend to be volatile on a quarter-by-quarter basis. However, we expect this trend to continue as we shift our production towards higher value products in places with more favorable fiscal terms. We will continue to periodically track and report this metric as growing both production and margins is a key aspect of our value proposition. So now I will turn to the segment slide, beginning with Lower 48 on slide 9. Production in this segment was 491,000 BOE per day, that’s up 11% compared to last year’s second quarter and up 3% sequentially. We saw this improvement despite the sale of the Cedar Creek Anticline assets in the first quarter of 2013. Total liquids production in the segment increased 20% compared to the same period a year ago and now represents 48% of the total mix for the segment and we expect our liquids percentage to continue to grow. During the quarter, combined production from the Eagle Ford, Bakken and Permian Basin averaged 203,000 BOE per day and that’s up 47% from a year ago. These assets made up less than 9% of our total company production a year ago and today these assets comprise 13% of our total company production and we expect they will continue to grow. Segment adjusted earnings this quarter generally reflects higher realized prices compared to the same period a year-ago, but they also include the foreign dry hole costs and leasehold impairment of approximately $70 million after-tax. Excluding that charge, segment adjusted earnings would have been almost $250 million as you can see the leverage and earnings due to the growth and the shift to liquids. Now, let’s cover the Canada segment on Slide 10. Production in this segment is $271,000 BOE per day, roughly flat compared to last year’s second quarter. Liquids grew 12% year-over-year while gas production declined 9%. The shift has increased segment margins, which continue to improve margins overtime. Production was impacted in the second quarter by 9,000 BOE per day as a result of planned downtime at Christina Lake. Canada’s adjusted earnings of $5 million this quarter reflects stronger product pricing compared to last year and sequentially. And as a reminder, the WCS prices in our supplemental information represents one month lag, which better reflects our pricing for Bitumen. Now, let’s move to the Alaska segment on Slide 11. Production in Alaska was 197,000 BOE per day, this quarter, this was down sequentially due to planned downtime at Kuparuk and Prudhoe and normal field decline. But despite lower sequential volumes, adjusted earnings were $585 million this quarter, which is up compared to last quarter. Differences between the timing of production and sales explain much of the variance; the first quarter of this year included an adverse impact earnings of approximately $50 million from these lift timing impacts while this quarter included the benefit of about $25 million, a positive swing of $75 million. We continue to analyze the impact to our business related to the recent passage of Senate Bill 21 and we expect to pursue additional opportunities for investment over time. I'll turn now to Slide 12 and talk about our Asia-Pacific and Middle East segment. Production in this segment was 324,000 BOE per day during the second quarter, up 20% compared to year ago and up 2% sequentially. Key drivers of year-over-year performance were the resumption of normal production and growth at Bohai Bay, growth at the Panyu project in China, and early production from Gumusut in Malaysia, which started late last year. Adjusted earnings this quarter were unfavorably impacted by weaker prices and impacts from lift timing are minimal this quarter. Europe, the next segment is found on Slide 13. Production for the Europe segment was 173,000 BOE per day during the quarter, a decrease of 34,000 BOE per day sequentially. This was driven by significant downtime in Greater Ekofisk area in Norway and the J-Area in the UK. Compared to a year ago lower production is driven by higher planned and unplanned downtime, normal field declines, and dispositions. Second quarter adjusted earnings for the segment were $261 million, and segment performance should improve when major projects startup occur in the UK and Norway. Before I wrap up, the financial section of today's call, with the discussion of cash flow, let me provide an update on our corporate segment. Our corporate segment adjusted earnings were negative $164 million in the quarter. We are updating our annual guidance for this segment to be $750 million after-tax, that's an $150 million improvement compared to our prior guidance. Additional information for the corporate segment and the other international segments are included in the supplemental information that we provided with the earnings release. We turn to Slide 14, I'll cover our year-to-date company cash flow waterfall. Through the first half of 2013 we’ve generated $8 billion in cash from continuing operations excluding working capital. Through June working capital was a better wash for the year. Year-to-date we’ve generated $1.7 billion in proceeds from dispositions primarily from the sale of the Cedar Creek Anticline assets and partial working interest in the Browse and Canning Basin. So far we’ve funded $7.5 billion capital program for continuing operations and paid out $1.6 billion in dividends. Note that cash flow from operations and proceeds from dispositions have covered our dividend and capital program. The $1.3 billion in debt and other reflects the repayment of approximately $900 million of debt at maturity during the quarter, as well as capital associated with the discontinued operations. Now something to note, although we paid down $900 million in debt during the quarter, our debt balance was unchanged as we recorded $900 million capital lease obligation for the Gumusut Floating Production System. We have $4 billion in cash and short-term investments on hand, which is just slightly lower than where we started the year. So in summary, our balance sheet and financial position remains strong and we believe are well positioned to execute our investment programs and our value proposition for the company. I will now turn the call over to Matt for an update on operations beginning on Slide 15. Matthew J. Fox: Thank you, Jeff. As both Ryan and Jeff mentioned, the main theme of this quarter’s operational performance is that we are on plan just like last quarter. So I am going to cover the operations material by our capital categories beginning with our high-quality base assets. And as a reminder, our base assets refer to the assets that we’re producing at the end of last year. In June, the second quarter these base assets performed very well across all of our operations and with minimal unplanned downtime. So that means on average everything ran back better than expected because in our forecast we actually assume some unplanned downtime. We protect the operating integrality of our base assets through plant maintenance. As we discussed in the previous quarter call we have significant plant maintenance and tie-in scheduled for the second and third quarters of this year. And our operated assets (inaudible) minority the downtime of 30% higher than our five year historical average. The chart in the lower left shows the major planned events for 2013 and their duration. As you can see many projects commenced later in the second quarter and a couple of these are still underway and others are scheduled to start in the third and fourth quarters. And now a few highlights; in the North Sea turnarounds were successfully completed ahead of schedule at Ekofisk, Eldfisk in the J-Area. These activities included tie-ins for the major projects Ekofisk South, Eldfisk II and Jasmine. Turnarounds in the Lower 48 were successfully completed as well as the planned maintenance at Christina Lake. We have additional planned downtime scheduled during the third and fourth quarters in Alaska, the UK, Foster Creek and Qatar. So our base operations are running well and our turnarounds are on or ahead of schedule. Moving on to our development programs on page 16, these development programs consists of lower risk drilling lead activities around the world, that completely mitigate our base declines in generally higher margins and attractive returns. These programs remain on track to deliver about 600,000 Boe per day of production by 2017 as shown in the top left graphic. Our legacy conventional field development programs are on track. For example, in places like the Kuparuk field in Alaska, coiled tubing drilling sidetracks continued in the second quarter. In Western Canada, we continue to see good results from margin enhancing drilling programs and the liquids rich plays we are focusing on. Results across our Lower 48 development programs are very strong. They produce 491,000 BOE per day in the second quarter and a high level of drilling activity continues. A couple of highlights; Bakken produced an average of 30,000 boe per day, up 15% compared to the first quarter last year and up 3% sequentially. Heavy rains and flooding in the area impacted our second quarter activity, but we are getting back on track with 11 rigs running. The Eagle Ford exceeded our expectations in the second quarter. Production averaged 121,000 boe per day, almost double the same period last year and up 20% sequentially. During the second quarter, we brought on 65 operated wells including catching up on some of the well backlog we have. And we continue to believe that our Eagle Ford position is truly best-in-class. The charts on the lower left of this slide shows third-party data on our well performance compared to the top competitors in the fleet. We are one of the top producers overall and we are producing higher oil volumes per well; more than 50% higher than the competitor average, so clearly we’d identified the sweet spot when we established our position for only $300 an acre. We are currently running 11 rigs in the fleet. We are on track to complete the drilling Phase of acreage capture this year and we are transitioning to multi-well pad drilling for our more than 1900 remaining identified locations. Now I would like to discuss our major projects on slide 17. Our major projects remain on track to deliver about 400,000 boe per day of production by 217, as shown on the top left graph. Our oil sands assets are performing as planned. The combined oil sands properties averaged 100,000 BOE per day during the quarter, up 14% year-over-year. Currently, we have seven major oil sands projects in execution and these projects are progressing on schedule. Christina Lake Phase E started up in mid-July slightly ahead of schedule, and we should ramp to about 20,000 BOE per day net from Christina E within six to nine months. Our (inaudible) project is about 40% complete by the end of July and is on track to start up in the early 2015. In Alaska, our CD5 project is on track and we are progressing engineering work and additional satellite projects for sanction in 2014. The passage of SB21 in Alaska, we believe some of our Alaska projects and (inaudible) viable and we expect to invest more capital in Alaska over time. In Asia-Pacific and Middle East segment, our major projects are also on plan. Performance from our pioneer growth project is running ahead of expectations. We have 23 wells on line at the end of June, versus 19 planned. And these wells contributed about 7,000 BOE per day net and second quarter. In Malaysia, key load outs and less were achieved during the quarter. The floating production system from Gumusut is now in place, Siakap North-Petai project is on track, and we expect production from both projects to begin ramping up at year-end. At Curtis Island, module installations continue to APLNG during the second quarter. In June, we raised the width of our first tank, a big milestone for the project. We're still on schedule for first LNG in 2015. Activity at both the UK and the region sectors of the North Sea is very high. At Ekofisk, so we installed a new project topside facilities during the second quarter and the project is on track to achieve cost reduction by the end of 2013. Also during the quarter, we installed the jackets and bridges at Eldfisk II in preparation for first oil late next year. At Jasmine, key installations were completed in the second quarter and offshore hook-up and commissioning market is fully underway. Cost reduction from Jasmine is expected early in the fourth quarter. The graphic on the lower left shows the expected production start-ups during the third and fourth quarter of this year and as you can see the projects we have been talking about for a while are now coming to fruition and we have more projects scheduled to startup next year including Eldfisk II in the North Sea, Kakap in Malaysia, additional phases of the oil sands, Britannia long-term compression and (inaudible) project in Indonesia. So the delivery of new production from major projects will start later this year and continue through 2014 and beyond. Next I want to briefly cover our exploration programs starting in slide 18. Our exploration momentum continues on several fronts. We are building inventory of both conventional and unconventional opportunities. We are advancing several opportunities to the drill ready stage and we are currently drilling several operated and non-operated prospects. There is a very high level of activity in the deepwater Gulf of Mexico program. The lower (inaudible) is currently drilling. We have 30% interest in this well. During the quarter, we acquired 20% working interest in the (inaudible)` prospect and the six plus heal at JOE. This is a very large prospect that’s also currently drilling and should reach TV this quarter and we have additional 100% ConocoPhillips leases within the healer structure, so this is an important well for us. The Deep Nansen wildcat and Tiber appraisal wells are expected to spud this quarter and we have a 25% and 18% working interest in these wells respectively. In the Browse Basin of Australia we are currently drilling the Proteus wildcat on an untested structure to the Southeast of the Poseidon discovery and we expect to reach TD soon. We completed our sale of partial interest in the Browse and Canning Basin in June as well. Recall, this was part of a deal to gain access to potential shale opportunities in the Sichuan Basin in China. In Europe we were awarded one operatorship and three partnership licenses in Norway’s 22 licensing round in the Bering sea and this represents attractive future conventional inventory in a legacy area for the company and we expect to start testing our acreage in the Bering’s in 2014. In the Kwanza Basin in Angola, we completed our 2013 3D seismic acquisition program in early April. Also, we recently acquired an additional 20% working interest in Block 36 bringing our equity to 50%. We also have 30% interest in Block 37 and we’re still planning more to begin drilling early next year. In addition, we’ve completed a fireman to three offshore blocks in Senegal. These blocks provide attractive acreage to test the West African (inaudible) play and drilling on these blocks will start next year too. Globally we have activities under way in several unconventional plays. We expect to be drilling in Poland and Colombia by year-end. We also continue to drill on plays, the Duvernay and Montney plays in Canada and we continue to test plays in the Permian and Niobrara in the Lower 48. That was a pretty quick overview of our operations and exploration activity. The key takeaways are less. The operations are running well, the development programs are delivering, the startups of several growth projects are eminent and we’ve got level of exploration activity. I’ll wrap up my comments on Slide 19 with a quick review of our 2013 production outlook. As Ryan mentioned in his opening comments, we are raising our production outlook for 2013. This slide shows our actual 1Q and 2Q volumes and our forecast volumes for the rest of the year on both the continuing and discontinued operations basis. The bottom line, we are tightening our ranges in 3Q and 4Q and we are bringing up the midpoint of a full year range by about 20,000 BOE per day just over 1%. As you can see, we expect third quarter volumes to be lower than second quarter, driven again by significant turnaround in maintenance activities, in this case dominated by Alaska and the UK. Fourth quarter volume should ramp up from there as our planned downtime (inaudible) and our major projects ramped up and we should see a strong exit rate going into 2014. Now please come to Slide 20 for Ryan’s summary comments.

Thank you, Matt. Well, we’re at the halfway mark for 2013, but more importantly we are in [the home stretch] of a multi-year effort to transform ConocoPhillips into a unique compelling independent E&P company. So let me also summarize the key takeaways from this call. Operationally, we are approaching a very significant inflection point for the company. We have several important milestones to achieve in the next two quarters and we should see good momentum coming out of 2013. We are building our inventory and delivering visible results from our conventional and unconventional exploration programs that will sustain our growth well into the future. Importantly, we expect to deliver our operational performance safely and efficiently. Financially, we’re committed to maintaining a strong balance sheet and that can provide our financial flexibility. We’re seeing the early stages of cash margin improvement, which should continue as our volumes grow and as always, we’ll maintain our focus on improving returns. Strategically we are delivering on our value proposition. We expect to complete our announced asset divestitures in 2013 and this will provide the financial flexibility to fund our investment programs, which we are on track to deliver volume and margin growth and our dividend remains a top priority. The bottom line, we’re committed to creating long-term value by delivering 3% to 5% growth in both production and margins with a compelling dividend. So I hope Jeff, Matt and myself have given you confidence that our plans are on track for delivering key milestones in 2013 and they will certainly position the company for very strong finish to the year and an exciting 2014. So now with that, let’s turn it back to the moderator and take your questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) Our first question is from Faisel Khan. Faisel Khan – Citigroup Inc.: Good afternoon. Faisel with Citi.

Hi, Faisel. Ellen R. DeSanctis: Hi, Faisel. Faisel Khan – Citigroup Inc.: Hi. Just going to some of your comments on the transactions that you plan to close for the end of the year, can you just give us an update on kind of when you expect, precisely when those transactions will close in Nigeria and Algeria and Kashagan versus kind of what guys had expected when you announced those transactions earlier on.

Yeah, thanks, Faisel. So when we set up our plants last year we were thinking towards the latter half of the year, mid year for some of the transactions may be a little bit later. It looks now to us that we will probably; we will complete all those transactions by the end of the year. There are complex full country exits with respect to Algeria, Nigeria, and Kashagan, so you can probably appreciate the complexity that's their. But we are on track to finish those by the end of the year, which is what we have said all along. In terms of planning, we were thinking maybe a few of them would be done by mid-year, but they will stretch into, a little bit into the third and fourth quarters. Faisel Khan – Citigroup Inc.: Okay, is that influencing at all the guidance, the change in guidance at all and will continue and discontinue off spaces?

So on the capital that we have talked about, it is impacting the discontinued operations. About half of the capital that we have talked about $600 million, roughly half, $300 million of that is due to those extending the dispositions, and but we’ll get that back through post closing adjustments on each one of the transactions. Faisel Khan – Citigroup Inc.: Okay, understood. Just one last question for me. In the Eagle Ford, lot of sort of industry publications on talking about lower condensate pricing and sort of lower realizations because of kind of the its inability to kind of move all that condensate to market or the consumer to market. Any issues, can you talk, elaborate a little bit more and how you're seeing the pricing of Eagle Ford crude versus some of the industry publications are talking about in terms of discounts and some of those lighter grades.

We don't sell our Eagle Ford crude as condensate type. It is a black oil that we are selling, so we are others maybe giving those sort of discounts we are not. Matthew J. Fox: So, just to add on that a little bit. So back when there was more of a spread between WTI, Brent and LLS, our Eagle Ford oil tended to price between WTI and LLS, as that as compressed, it’s trading more towards the WTI type number, but still as Matt saying a full oil price for that product. Faisel Khan – Citigroup Inc.: I got it, thanks guys, I appreciate the time. Ellen R. DeSanctis: Thanks.

Thank you.

Thank you. Our next question is from John Herrlin of Societe Generale. John P. Herrlin Jr. – Societe Generale: Yes, hi.

Hi, John. John P. Herrlin Jr. – Societe Generale: Three quick ones, Ryan you mentioned rebalancing your oil sands exposure, should we expect this to happen over the next few years or are you going to monetize, try to swap or what are you going to do?

Yeah, thanks John. Well, we’ve got a very large position. We’ve got 100% acreage, we’ve got joint ventures, it’s Surmont with FCCL. We are looking at a number of different ways to rebalance that portfolio. I wouldn’t get specific on any one way, we are trying to do what’s best for our shareholders, what’s best for our company. We want to maintain some exposure to the oil sands, but rebalance what we do have. I would say over the next this year, you want to see some efforts along those lines, but that will continue probably well into next year as well. John P. Herrlin Jr. – Societe Generale: Okay thanks. With respect to the Bakken and Eagle Ford Matt, are you comfortable with the degree of activity or should we expect further acceleration in terms of your exploitation efforts? Matthew J. Fox: John, we are quite comfortable with the strategy that we have just now, which is a 11 rigs running in both the Bakken and the Eagle Ford, and we are running that in a pretty efficient way, just now we are well laying out to do that, that we are continuing to learn from pilot tests for example, in the Eagle Ford, and we are at keeping pace with the infrastructure development, so I think we are going to keep on that sort of pace for sometime to come yet. John P. Herrlin Jr. – Societe Generale: Okay. Last one from me in terms of virgin new players or newer players, Permian and Niobrara, should we expect to see acceleration there in activity. Matthew J. Fox: Well, we have actually increased our activity this year. We’ll get three rigs running in the Permian just now, testing of that place in the Delaware basin and in the Midland basin, and we’re getting encouraging results there, but one rig running in the Niobrara, just now and we’re continuing to could test that fully across about pretty expensive acreage that we have so, we’re pretty active in both the Niobrara and in the Permian. John P. Herrlin Jr. – Societe Generale: Thanks I was just wondering if that could be incremental towards what that’s all. Thanks.

Thanks, John. Ellen R. DeSanctis: Thanks, John.

Thank you. Our next question is from Scott Hanold from RBC. Scott Hanold – RBC Capital Markets LLC: Thanks, good afternoon.

Good afternoon, Scott. Scott Hanold – RBC Capital Markets LLC: In the Eagle Ford it sounds like you said you’d tied-in 65 wells that you’ve drilled in the quarter, and then you had some backlog you put online. How many wells, do you get online during the quarter and you had a pretty nice production bump. Was there any infrastructure that was added, once we began the quarter that also added the increase? Jeffrey W. Sheets: So, it was 65 in total that we put on in the quarter, but plenty of those were from the backlog and the backlog reduction. Scott Hanold – RBC Capital Markets LLC: Okay. Where did your backlog right now… Jeffrey W. Sheets: It’s about 85. Scott Hanold – RBC Capital Markets LLC: 85, would you, as running 11 rig, what is sort of a normal backlog you’d expect to carry, and is there anymore opportunity to trim off that in the coming quarters? Jeffrey W. Sheets: Yeah, we’re going to adjust that backlog as we work through the year, there is always our backlog almost by definition takes time to come by the end of the year, we’ll probably have 50 or 60 wells, they are drilled but not tied-in. Scott Hanold – RBC Capital Markets LLC: Okay, got it. And then your 1,900 locations that you have talked about drilling at in the Eagle Ford remind me, what is the space that you assume there, any thoughts on where that can go?

That assumes 80 acre spacing and we have pilot test running, testing of (inaudible) business down to 40 acres, but we don’t have a conclusive result yet as to what the optimum spacing might be, so those 1900 continues to be based on 80 acre spacing. Scott Hanold – RBC Capital Markets LLC: Okay. How long will it, when should we hear about the more conclusive result that day and do you think is that more 2014?

That’s more a 2014 really before we, I mean the information continues to come in, before we would draw any definitive conclusions is probably something next year. Scott Hanold – RBC Capital Markets LLC: Okay. Any early thoughts that it is pretty encouraging so far?

It really is too early to see. I don’t see it is increasing the spacing permit, but we continue to look to see if there is value optimization and reducing that space. Scott Hanold – RBC Capital Markets LLC: Okay. And then one of the things on the oil sand plays, you talked about rebalancing that, can you remind me so, within your guidance for 2013, is there any effective just sort of rebalancing effort for the oil sands yet? Jeffrey W. Sheets: No, there is not Scott. Scott Hanold – RBC Capital Markets LLC: Okay, thank you.

Thank you.

Thank you. Our next question is from Ed Westlake of Credit Suisse. Ed G. Westlake – Credit Suisse: Yeah. I guess continuing on the same just around the shale portfolio, I mean it feels like obviously the Eagle Ford has been great for some of the companies who have been now including yourselves, do you sort of feel that your sort of shale production and particularly in the liquids all sort of slowed a little bit in 2014, and then reaccelerate as you add activity to these other plays, I mean maybe give us some color about how you see the evolution of that? Matthew J. Fox: We expect to see production to continue to grow in the Eagle Ford, the Bakken and the Permian over the next few years. The Permian from an unconventional perspective, and we’ve seen a lot of potential there. We are seeing probably at least two producing wells in the Avalon, two or three in the Wolfcamp. So we continue to be encouraged by the unconventionals in the Permian. And so time will tell how much that contributes to growth in the long-term, but we do expect to see growth in the Eagle Ford, the Permian and the Bakken for several years to come frankly. Ed G. Westlake – Credit Suisse: And then a question for Jeff, diving into the weeds on the cash flow statement, two line items. This will be fun. Two line items that are difficult for us to forecast, one is deferred taxes and then there is the catch you have, which is other. Obviously as we focus on cash margins at the E&P level, obviously it has to translate into cash flow for the group. So on deferred taxes, is that predominantly U.S. or is there some international component in the 2013 numbers so far? Jeffrey W. Sheets: Yes, there is. A big part of it’s U.S., but also Norway and the UK are pretty substantial contributors to this as well. If you think about the tax, what deferred tax is, it’s just where you’re able to take more rapid tax depreciation and financial depreciation and UK and Norway, both have fairly accelerated tax depreciation. Of course the U.S. has some IDC benefit as well. Ed G. Westlake – Credit Suisse: And then on the other line, which is sort of a $500 million swing first quarter to second quarter, can you just talk what is in the other line [next]? Jeffrey W. Sheets: That is a difficult one because there are a lot of things that go into the other line. Maybe just a little bit of, kind of if you think about how to think about all the things that go into the cash flow statement for us overall. When we talk about cash margins we took a very simplified approach and just have net income plus DD&A and talk about that as our cash margin. But for us going forward deferred tax is probably a pretty substantial positive for us this year and probably us this year and probably on into next year. A lot of the other items on the cash flow statement are going to generally offset each other. You will see that cash flow from operations other line, it’s going to fluctuate from quarter-to-quarter, probably for the year, that’s probably couple of hundred million dollar negative typically. In particular though, if you looked at the first quarter of this year and the fourth quarter of last year, those are unusually negative numbers and those were both results of some special items, which had positive effects to income, but with non-cash impacts, where the offset to that is in the cash flow from other lines. So I would say the fourth quarter and first quarter were pretty [unanimous] numbers for that line item and you should think about line items being more of a kind of few hundred million dollar negative for most years. Ed G. Westlake – Credit Suisse: Thanks very helpful. Thanks Jeff.

Thanks Ed.

Thank you. Our next question is from Paul Cheng of Barclays. Paul Cheng – Barclays Capital, Inc.: Hey guys.

Hi, Paul. Matthew J. Fox: Hi, Paul. Paul Cheng – Barclays Capital, Inc.: Hi, Matt, in Eagle Ford you are saying that you are going to move into the pad drilling. How many rig is actually ready in the pad tubing at this point? Matthew J. Fox: We have got four or five there are currently pad drilling in the Eagle Ford. Paul Cheng – Barclays Capital, Inc.: And so as we move, I presume that by mid of next year that second quarter or so you are going to be 100% in pad tubing and at that point, what is your best guess in terms of your unit cost will change 10% to 15% of the improvement or do you think that you may be able to drive better than that? Matthew J. Fox: Well, time will tell. We know that we are seeing improved efficiencies in the pad drilling with a fewer rig moves and all the other benefits that come from pad drilling, but I think it’s too early Paul to put a number out there, just probably – we know we will see efficiencies, I wouldn’t put a number on it just now. Paul Cheng – Barclays Capital, Inc.: And I am not sure that, maybe I missed it, I have to apologize if that’s the case, that you guys have to like coming now with maybe of the longer term production or we saw target for Eagle Ford and Bakken, let’s say by 2017, how much do you think that those two area will be able to produce that? Matthew J. Fox: We haven’t come out with any updated view of that yet. Ellen R. DeSanctis: But we have got it in the Analyst Meeting material, both for Bakken and actually for all the Lower 48 plays in the Analyst Meeting material. Matthew J. Fox: That we put out last year, so Paul… Ellen R. DeSanctis: February. Paul Cheng – Barclays Capital, Inc.: So any kind of update? Matthew J. Fox: No, we are really kind of working through that process now. The great part of that getting to the position now where we got the Eagle Ford acreage primarily held by production is, we got a lot of flexibility to step back and ask ourselves, what is the optimal rate to develop that field and wet got a lot of work going on to do that right now. Paul Cheng – Barclays Capital, Inc.: Right. And Jeff, along that line, I mean that paying up very lousy picture in terms of all the opportunity. So some of the Cap expense on, are you guys still looking at around in the $16 billion year over the next several year or that is also start to material see some adjustment? Jeffrey W. Sheets: No, Paul, we’re targeting that $16 billion annual number. So, we see some changes in the mix as we go forward over the next five years. We’ve got some major projects that start ramping down and we see some opportunities in our base plans as Alan described, to ramp up some of the unconventional North American stuff. But, no, we still think $16 billion is the right number to use. Paul Cheng – Barclays Capital, Inc.: Ryan, since that you guys are sort of up this year for reduction target a bit, how about next year? Is there any change?

No. Not at this point. Paul Cheng – Barclays Capital, Inc.: Not at this point. And then finally, Matt, in Eagle Ford I’m wondering you’re not going to rig in Bakken, you’re also wondering – you’re not going to rig – but it does look like that you have a stronger position in the Eagle Ford. Is there any reason that why we’re running that similar amount of rig, I presume that the CapEx, I’m not sure that if you (inaudible) 11 rig, that the CapEx program under two base and at this point are dramatically different for this year. Is there any particular reason why you haven’t shift more of your effort into the Eagle Ford? Matthew J. Fox: We’re managing the pace of activity to make sure that we don’t go ahead of infrastructure, to make sure that we’re able to run safely and efficiently and the reason you don’t see so much production appearing in the Bakken from the 11 rigs outrun we don’t look probably as we’re talking interest in the book and there is 50% or less and if it was in Eagle Ford this in high 80% to 90%. So that’s why you’re not seeing the same in the bottom line and then the underlying rates from the Eagle Ford and Bakken as well, but it’s really try and make sure that we are managing and running an efficient, safe program with these rates. Paul Cheng – Barclays Capital, Inc.: So we should assume that the 11 rig for each base, this year to stay for the next one or two years? Jeffrey W. Sheets: Yeah, certainly their intention is to stay around that level for the next year or so. Yeah, and we’ll learn as we go. We’ll learn from our pilot tests and we may adjust that, but right now yes it’s for modeling purposes, that’s what I would assume. Paul Cheng – Barclays Capital, Inc.: Thank you.

Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Doug Leggate – Bank of America Merrill Lynch: Thank you, guys. I appreciate you taking my questions. Hi, guys, I got a couple of quick ones please. So you have mentioned that you might consider having move to Alaska in terms of perhaps incremental investment. You both have got interest in what is a growing suite of exploration success, and in terms of long-term capital planning. How should we think about balancing those two items. Does the CapEx go up to accommodate these incremental projects or does it get reallocated away from different areas. If could you kind help us with that and I’ve got a follow-up please? Jeffrey W. Sheets: The $16 billion number includes assumptions of both major capital programs that will come for example from an exploration program, and any increase that we see in Alaska is also included in opportunities that we are modeling within the $16 billion overall program. And so you shouldn’t see an increase from the $16 billion to accommodate those? Doug Leggate – Bank of America Merrill Lynch: Okay now those major capital projects have they also included in your production outlook? Jeffrey W. Sheets: Yes, they are, yeah. Matthew J. Fox: Well, production outlook. Jeffrey W. Sheets: Yes, they are, yeah. Matthew J. Fox: Well, just to be clear, that’s not in – when we talked about our production outlook for 2016 and 2017 at the Analyst Presentation, we don’t have anything for the Gulf of Mexico discoveries in that production outlook, but we’d have some assumptions that, as we get towards the end of that period we are going to start spending capital there and you will see that production probably show up outside of the time period we talked about where we’ve kind of talked about the production guidance. Doug Leggate – Bank of America Merrill Lynch: So there is no capital guidance? Matthew J. Fox: So the capital going into those projects in the Gulf of Mexico for example with no production, in Alaska, we were not assuming in our plans last year that we will see incremental production in Alaska; that incremental production will be tied to activity associated with SB-21, but we do have the capital flexibility to accommodate. Doug Leggate – Bank of America Merrill Lynch: My follow up Matt is maybe just on some of the well results you have recently on both the Bakken and the Eagle Ford. We are monitoring this doc and that looks like just in the last couple of months you have some pretty stellar well results. I am just wondering if you can confirm you’re seeing that in your production trends and if you can maybe help us understand if something is changed, are you drilling that particular area, are you changing well design, what’s going on in there now? Thank you. Matthew J. Fox: Yeah, we’re continuing to vote for example a fact design in places like Eagle Ford, the number of stages that we pump, the volume of [propane] that we pump and we are doing that as learn from our pilot pits and what we are learning is that the more stages and more profit makes a difference. So going forward we’re going to be continuing to optimize that. Doug Leggate – Bank of America Merrill Lynch: So you’re seeing your 2013 vintage wells delivering better than let’s say 2012 Panyu growth wells? Matthew J. Fox: Yeah, on an average that was going on here. Doug Leggate – Bank of America Merrill Lynch: Okay, great. I’ll leave it there. Thanks. Matthew J. Fox: Thanks, Doug Ellen R. DeSanctis: Thanks, Doug

Thank you. Our next question is from Paul Sankey of Deutsche Bank Paul B. Sankey – Deutsche Bank Securities, Inc.: Hi, good afternoon guys. Just clarify on the disposal program. I think you said you expected this to complete by 2013. I think you’re referring Nigeria and Algeria. Could you just repeat? Excuse me if I missed it what you said about Canada as well. I know that things changed there a bit versus your expectations. I wanted to just understand how you’re thinking about that going forward. Thanks.

Yeah, thank you, Paul. In terms of Canada, we’re continuing to look at the opportunities we may see a little bit before the end of the year, but most of what we’re trying to do in Canada will stretch well into 2014. I’ll be referring to cash again. You’ve probably seen the news. We were notified in early July by the Kazakhstan Government that they’ve elected to preempt on the arrangement that we had with OVM and we’re in conversations and discussions right now with the amount of Purchase/Sale Agreement and those are going quite well. So that’s progressing along. Paul B. Sankey – Deutsche Bank Securities, Inc.: Okay. I guess my understanding was that kind of in the likely order of events that would be first Algeria, then Kazakhstan and Nigeria was difficult to that I can guess. In terms of, it sounds like great – seem that’s fairly straightforward now they pay the same price that was [of the ONGC].

Yes, that’s correct. Paul B. Sankey – Deutsche Bank Securities, Inc.: Right. So that should go pretty quickly. And then, obviously the other two, I guess that you’re finding that these [devils] are highly accretive to you, right?

Yes, you’re absolutely right. Paul B. Sankey – Deutsche Bank Securities, Inc.: So, would be logical to consider further disposals for next year to continue the accretion?

Well, I think as I try to explain, I think when we get down with the three that we have described here today, we have got some rebalancing we want to do in the old sense that we talked about and then I think it’s healthy and prudent to continue to improving the portfolio on the low end. So there is some modest level of divestitures that we see out overtime in the portfolio in $1 billion to $2 billion range or something like that, but we don’t have any large ones that we have talked about other than, looking at trying to rebalance in our oilsands position. Paul B. Sankey – Deutsche Bank Securities, Inc.: Yeah, I understand. And then obviously with 3% to 5% double target that you have got, I think Paul Cheng highlighted, it’s basically unchanged by today’s better outlook for this year’s volumes? Jeffrey W. Sheets: Yeah, no, we are sticking to the 3% to 5%. Again we pin that back when we came out year and a half ago. So you do the math and do different numbers depending on when you pick your starting point and ending point, but I am anchored back to when we came out as an independent company in May of last year and that’s our commitment over the next four to five years as you will see that kind of growth in both volume and margins for the company. Paul B. Sankey – Deutsche Bank Securities, Inc.: And just as completely reiterate, what speaks up before, you’re basically saying that at that point, you would be covering the dividend and the CapEx annually based on I think of $110 right by 2017? Jeffrey W. Sheets: Well, it’s prior little bit lower, oil price we don’t assume $110 or we’re buying more or like $90 to $100 kinds of prices in the middle of $3 Henry Hub prices. And yeah, we start fully covering our CapEx and dividend in the next couple of years, but that deficit start shrinking pretty quickly over the next couple of years, so it’s very manageable with the proceeds that we estimate will have by the end of this year, the cash will have on the balance sheet, that’s the plan and we can cover it very easily at that point. Paul B. Sankey – Deutsche Bank Securities, Inc.: Okay, great. I understand that. Sorry again I apologize if I missed this. Was there a specific update on the progress in Australia and where your projects down relative to the other two major projects going on down there?

The APLNG is in good shape. The project just now is about 45% complete and we are making good progress. We are still on track for starting up in 2015. Paul B. Sankey – Deutsche Bank Securities, Inc.: And there was a cost review I believe which came through with Needham.

And we reviewed that to the analysts the results of that to the analyst earlier in the year, and there is no change from what we described then. Matthew J. Fox: Other than seeing some fairly significant strengthening of the U.S. dollar versus the Australian Dollar which is probably mitigated some of the cost increases we thought we were seeing on in U.S. dollar terms. Jeffrey W. Sheets: Yeah, I think what we had said is like 7% increase in the underlying cost and the spent currency and that was looking like a 20% increase in U.S. dollars depending on how the FX goes and may not the 20% increase in the U.S. dollar basis? Paul B. Sankey – Deutsche Bank Securities, Inc.: Great, thanks guys. That’s helpful, thank you.

Thanks Paul.

Thank you. And the final question we have time for is from Kate Minyard of JPMorgan. Katherine L. Minyard – JPMorgan: Hi, good afternoon thanks for taking my questions.

Hi, Kate. Jeffrey W. Sheets: Hi, Kate. Katherine L. Minyard – JPMorgan: Hi, just a quick question for Jeff, thanks for providing the color on slide 7 and 8, can you talk about the cash margin improvement that might be stemming from a difference in cash taxes between 2012 and 2013, just as you’ve changed some of the geographic distribution of production. Is there any impact there that you can help us extract? Jeffrey W. Sheets: In kind of the question was the deferred taxes a part of that, is that? Katherine L. Minyard – JPMorgan: Why it is different? Why just different cash tax rates between the regimes exactly? Jeffrey W. Sheets: Yeah, so really the benefit comes from just pretty much the cash margin benefit comes from where we’ve added production. And we’ve added production primarily in Canada, in the Lower 48 and in Asia, and those are all tax rates, which are less than our current average tax rate. When we do this cash margin calculation, we do a simple calculation, so we can have some comparability to other companies. So we just take net income plus DD&A, and call that our cash margin, so deferred taxes don’t come into, but we talked about, when we talk about cash margins. Katherine L. Minyard – JPMorgan: Okay.

And as I mentioned, as you’re thinking about cash flow model and things like that, you should think of deferred tax as being like you’ve seen in the first couple of quarters of this year, that kind of it’s going to continue on because of it, where we are spending our capital dollars. Katherine L. Minyard – JPMorgan: Okay. All right, thanks. And then maybe just another question on Alaska, as you guys look at evaluating additional investment opportunity, you specifically talk about the evaluation in light of SB21. How are you taking into account potential marketability of the crudes as well and what specific type of crude are you with your investments be targeting? Is it light or is it heavy and how does marketability play a factor? Jeffrey W. Sheets: I mean the opportunities that we are looking at predominantly light oil opportunities with production similar to EPI to what we have just now. We also see opportunities in the heavy oil in Alaska, but that would be a bit further out and before we would see a significant increase in that. Katherine L. Minyard – JPMorgan: Okay. And no long-term concerns around marketability? Jeffrey W. Sheets: No, no. Katherine L. Minyard – JPMorgan: Okay. All right, great. Thanks very much. Jeffrey W. Sheets: Thanks Kate.

Thanks Kate. Ellen R. DeSanctis: Why don’t we go ahead and wrap it up here, we’re little passed the hour and again we really appreciate everybody’s time and attention on such a busy day. We will have a replay of this call on our website shortly and of course you’re always welcome to call anyone on the investor relations team for further color. Thanks so much have a great afternoon. Sheri?

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