Ellen DeSanctis – VP, IR Ryan Lance – Chairman and CEO Jeffrey Sheets – EVP, Finance and CFO Matt Fox – EVP, Exploration and Production

Ed Westlake – Credit Suisse Doug Terreson – ISI John Herrlin – Societe Generale Paul Sankey – Deutsche Bank Faisel Khan – Citigroup Blake Fernandez – Howard Weil Paul Cheng – Barclays Pavel Molchanov

Welcome to the Q3 2012 ConocoPhillips Earnings Conference Call. My name is Dan and I will be your operator for today’s call. (Operator Instructions) 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 Ms. Ellen DeSanctis, Vice President Investor Relations and Communications. Ms. DeSanctis, you may begin.

Thank you, Kim, and good afternoon, everybody. Welcome to the ConocoPhillips Third Quarter Earnings Call. Today you’re going to hear from three of our senior executives: Ryan Lance, our Chairman and CEO, will cover the third quarter highlights and provide an update on our strategic goals and priorities; Jeff Sheets, our Executive Vice President and CFO, will review the third quarter financial results, including our segment financials; and we also have Matt on today’s call. Matt is our Executive Vice President of Exploration and Production, and he’s going to review the E&P activities in each of our segments. Please note today’s presentation materials can be found on our website and a transcript of this call should be posted by no later than tomorrow morning. And finally, we will be making some forward-looking statements during today’s webcast. Our results may differ materially from the expectations we share today, but we’ve outlined these uncertainties and risks to our future performance in the Safe Harbor Statement shown on Page 2 in the slide deck that you should have access to at this time, and also in our periodic filings with the SEC. Now it’s my pleasure to turn our call over to Ryan.

Thank you, Ellen, and good afternoon, everyone. Thank you for joining us today. I’ll begin my comments on Slide 3 and cover some of our key third quarter highlights. This quarter marked an exciting milestone and our first full quarter as an independent E&P company. As you saw from this morning’s release, we posted strong performance this quarter and hitting our numbers is critical to achieving the goals we set for ourselves. Really a special thanks to our employees will continue to step up and deliver. We continue to make progress on our divestiture program. Completing this program will improve our portfolio, reset our base for future growth and add financial flexibility to the company. In the third quarter we generated about $0.5 billion of proceeds from asset sales, including our interest in (inaudible). And we continue to advance our progress on other assets. Year-to-date we have generated $2.1 billion in proceeds from asset dispositions. A key part of our strategy is to grow organically. Our exploration program continues to build momentum both on the unconventional and conventional sides of the business, and Matt will talk more about these program shortly, but I’m pleased to see these for grabs gaining speed. Operationally, we achieved the high end are estimated production range for the quarter at 1.525 million barrels equivalent per day. This performance represents an important milestone for ConocoPhillips. We achieved 3% year-on-year volume growth when adjusted for dispositions. Key production highlights include ongoing strong performance from unconventional assets in the lower 48, especially the Eagle Ford and lower oil Sands in Canada. In addition, compared to year ago this quarter benefited from the resumption of production at Peng Lai and in Libya. Our major projects are also progressing as planned, and Matt will provide additional color on these in his comments. As I move to the financial themes, we generated $1.8 billion of adjusted earnings or $1.44 per share. Our diversified product mix and geographic mix continues to buffer us somewhat from ongoing weaker North American natural gas and NGL prices. Excluding working capital we achieved $3.9 billion in cash from operations. And finally we improved our balance sheet this quarter, lowering the debt-to-cap ratio to 31% from 33%. So in summary, we had a strong quarter strategically, operationally and financially. We stayed focused and delivered on the aspects of the business that we can control. Now if you turn to Slide 4, I’ll quickly address the state of the business and how that our focus areas and priorities for the rest of the year and into 2013. First and foremost, the business is running well. We completed our worldwide seasonal turnaround activities on time and on budget. Our major projects and drilling programs are on track to deliver volume and margin growth. These include our lower 48 and unconventional resource plays as well as our major growth projects in the Canadian oil Sands the North Sea projects in the U.K. and Norway, APLNG and our Malaysian deepwater prospects. These are the major prospects that underpin our long-term goal is to deliver 3% to 5% production growth and margin expansion at flat prices. As I mentioned a minute ago, our exploration program is continuing to gain momentum. We’re currently testing several unconventional and conventional opportunities and are advancing others quickly to the drill-ready stage. Earlier this week it was announced that we acquired slots in a sixth generation rig to begin executing on our operated deepwater Gulf of Mexico program by 2014. Again, we are focused on completing our strategic asset disposition program. We have several packages on the market and expects some of these assets will take a little bit of time to divest, but we’re being patient, and we remain committed to getting the program done at acceptable prices. We believe we’re on track to deliver the $8 billion $10 billion of proceeds by the end of 2013. So with a quarter to go in the year, we now believe our capital spending will come between $15.5 billion and $16 billion a bit lower than we guided to in the second quarter. Where we end up in this range depends on whether or not we find attractive opportunities to add unconventional acreage between now and year end. We continue to be opportunistic in the market for acreage that fits well in our portfolio. Maintaining our balance sheet strength is essential. We continue to keep a close eye on our financial position to ensure that we have the flexibility and the capacity to execute our plan. And finally, we remain committed to our stated strategic goals of profitable growth and sector-leading returns. I believe this gives a good quarter and gives good evidence that we’re executing on the parts of the business that we control and have projects and programs in hand to support these goals. So now let me turn over the call to Jeff for a financial review.

Thank you, Ryan, and good afternoon, everyone. I’ll start out the review of our third quarter results with Slide 5 which shows our total adjusted earnings and prices. Will go through the detail in each of our segments in subsequent slides and I’ll defer the operational detail and updates to Matt. Total adjusted earnings were $1.8 billion this quarter compared to $1.5 billion in the prior period and $1.9 billion in the third quarter of 2011. Third quarter 2012 adjusted earnings excludes special items related to net gains on asset dispositions, changes to tax laws in the U.K., pension settlement expenses and some other items. Details of these special items can be found in the supplemental data provided with our earnings release. Our production came at the high end of the estimate we provided last quarter. Total sales volumes for the quarter were in excess of production resulting in a favorable impact to earnings of approximately $80 million, and we’ll discuss these details as we go through the segments. Sequentially prices weren’t a huge driver in earnings. North American gas and bitumen prices increased while domestic crude and NGL prices decreased. Despite increases this quarter, North American natural gas prices remained challenged and this impact – we continue to offset this impacted by shifting our investment towards liquids production. Operating costs were consistent with our expectations. Let’s turn to Slide 6 and talk about our total production. Production of 1.525 million BOE per day was in line with our expectations. Stepping to the waterfall, dispositions reduced production by 53,000 BOE per day compared to the third quarter of last year. The dispositions included Vietnam, step here at Alba and some Western Canadian gas assets that as the Naryanmarneftegaz joint venture. Down time was heavier than normal this reducing production by 49,000 BOE per day compared to the same quarter last year. We had major turnarounds this quarter in Alaska and in the U.K. Growth more than offset base decline, accounting for 256,000 BOE per day of new production with the majority of the growth coming from the lower 48 shale plays and our oil sands assets. We also had considerable production increases over these periods from Libya and China. In summary, volumes were up 3% adjusted for dispositions, but importantly the 3% growth was largely driven by a 7% increase in liquids production as shown on the dark blue bars on the slide. As we announced though this morning, we now expect our full year 2012 production volumes to average between 1.57 million and 1.58 million BOE per day. Now I’ll turn to the segment slides beginning with the lower 48 and Latin America on Slide 7. Production in this segment was 462,000 BOE per day this quarter, an increase over prior periods as we continue to successfully ramp up production in our lower 48 shale plays. Total liquids production in the segment increased 21% over the same period a year ago while natural gas production decreased 3%. A year ago liquids represented 40% of our production in this segment. In the third quarter 2012 liquids increased to approximately 46%. We expect this liquids percentage to continue to grow and drive our margin expansion over time. During the quarter production was 76,000 per day it Eagle Ford with 79% liquids and 29,000 BOE per day in the Bakken with 88% liquids. Total production of 102,000 BOE per day from these two plays has doubled compared to the same period last year. Compared to the second quarter the increased liquids production along with the 26% increase in realized gas prices contributed positively to earnings in this segment while continued declines in NGL prices negatively impacted earnings. Despite the sequential increase in natural gas prices, the segment earnings continued be impacted by generally weak natural gas prices. Next we moved to the Canada segment on Slide 8. Canadian production was 277,000 per day in the third quarter with the growth over prior periods being driven by the ramp-up at our oil-sands assets. Liquids production increased 30% year-over-year, while gas price decreased by 6%. And this shift will show up as improved margins over time. Canada reported negative adjusted earnings this quarter, largely reflecting ongoing weak natural gas prices. However, earnings were improved compared to the second quarter as natural gas and bitumen prices improved quarter-over-quarter. We also saw the WTI, WCS differential improve late in the quarter and the price of diluan decrease and this resulted in an overall improvement in pitchman netbacks. And it should be noted that despite the negative earnings the Canada segment continues to generate strong cash flow. Now let’s move to the Alaska segment on Slide 9. Production in Alaska was 176,000 BOE per day this quarter, down 39,000 per day but in line with our expectations. This production decline was largely due to major turnaround activity all across our assets on the north slope. The impact of lower production on earnings was offset by sales from inventory this quarter and these sales from inventories contributed approximately $120 million to the Alaska segment’s earnings. As a result, adjusted earnings of $535 million were roughly equivalent to the prior quarter and improved from a year ago. I’ll now turn Slide 10 and talk about the Asia Pacific and the Middle East segment. Asia Pacific and Middle East continue to be a strong performer for ConocoPhillips and provides important diversification to our portfolio. Production in the segment was 306,000 BOE per day during the third quarter. Both the Vilumunden field and they Darwin Allen Value plant were fully online this quarter after being down in the second quarter for planned maintenance. Production continue to ramp up at Peng Lai, increasing 20,000 BOE per day over the prior quarter. We exited the quarter with net production of 45,000 BOE per day and we expect to maintain this level of production during the fourth quarter. However, we had again in Alaska on the left side from sales of inventory. Asia Pacific and Middle East earnings were adversely impacted by about $60 million related to lift timings. Europe’s our next segment and we’ll just cover that on Slide 11. Production from the Europe segment was 191,000 per day during the quarter, a sequential decrease of 45,000 per day. Natural-field declines, down-time, and asset dispositions contributed to the lower production this quarter. Down-time resulted in 28,000 BOE per day impacts, primarily from planned maintenance at the Duty, east IVC, and Britannia platforms. The majority of production that was off-line during the third quarter due to down-time should be back online during the fourth quarter. The disposition impact was about 8,000 per day from Startured and Alba. So adjusted earnings of $299 million declined versus the prior quarter, primarily due to the slower production. It’s important to note that we benefit in the portfolio sense from having exposure to the stronger pricing in this segment. Now I’ll cover our next and final geographic segment, the Other International on Slide 12. So I’ll remind you that this segment includes our assets in Russia, the Caspian and Africa. Production was 113,000 BOE per day, basically maintaining the same level of production that we’ve seen over the past couple of quarters since Libya came back online. Adjusted earnings of $124 million this quarter were helped by favorable settlements of certain tax items. Prior-quarter earnings were negatively impacted by higher taxes, exploration expense, and adverse foreign-exchange impacts. The earnings were also impacted by the sale of NMNG in mid-August. So at the time of the sale, NMNG was producing about 11,000 BOE per day and was diluted to earnings. The final reporting segment I’ll cover quickly is our Corporate and Other segment on Slide 13. Adjusted corporate expense during the quarter was $139 million. This is lower corporate expense then we expect to see going forward as the quarter benefited from licensing revenue as well as some favorable foreign-exchange impacts. For the company overall, total foreign exchange was not a factor in the total quarter’s earnings. For the year, we estimate this segment’s expense on an adjusted basis to be about $850 million. We repaid $2 billion of debt during the quarter bring the total debt outstanding to $21.1 billion. At the end of the quarter, total debt-to-cap was 31%, and our long-term target remains to be 25% to 30% range. If you turn to Slide 14 I’ll cover our operating segment margins and returns. Charts on this slide summarizes our key financial metrics for the quarter. On a year-over-year basis all four metrics were negatively impacted by lower North American prices as well as our overall realize price declined by about $5 per BOE compared to the third quarter of last year. Our income and cash contribution per BOE were helped this quarter by the inventory sales in Alaska, but also reflected the operational and portfolio improvements that we’re starting to make as a company, and over time we expect these metrics to improve as we deliver on our growth programs, our margin expansions and our continued focus on returns. So I’ll wrap up my remarks on Slide 15, which is our third quarter company cash flow. As Ryan mentioned in his opening comments, we generated $3.9 billion in cash from operations is quarter excluding working capital. Working capital was a $412 million use of cash. We also generated $522 million proceeds from asset dispositions. We funded a $3.7 billion capital program bringing our year-to-date capital program to $11.9 billion. We paid out roughly $800 million of dividends and reduced debt by about $2 billion. During the quarter excluding working capital our cash from operations and proceeds from dispositions funded our dividend payments our capital program, and we used our restricted cash to pay down debt. We ended the quarter with $3.7 billion of cash equivalents and restricted cash. Our balance sheet and financial situation remains strong. We’re well-positioned execute on our program. Importantly we have capacity and flexibility to fund the programs that will generate volume and margin growth going forward. That concludes the review of our financial results, and I’ll now turn the call over to Matt for an update on our operations.

Thanks, Jeff. I’ll take us back through our operating segments and provide some detail on our drilling programs, growth projects and both our conventional and unconventional exploration activities. I’ll cover some highlights from the third quarter, but also update you on current activities and provide some color of what expect in the near future. I’ll start with the lower 48 and Latin America segment on Slide 16. First, I’ll focus on two key areas, the Eagle Ford and the Bakken. In the Eagle Ford we have about 230,000 net acreages, and our acreage is largely located in the Condensate Fairway, which the industry recognizes as the best part of the play. We have 14 rigs running in the play today. In the third quarter our production averaged 76,000 BOE per day, and we achieved a peak production rate and 86,000 BOE per day. In the fourth quarter we expect to achieve the peak rate of 100,000 a day as we continue to drill and pick up wells. And we are actively adding infrastructure in the play to create value. For example, we’re adding stabilization facilities, like the ones shown on the top left, to remove light ends, maximize our light crude sales at pipeline spec and to maximize or capture of NGLs. We should have an entire Eagle Ford possession held by production by the end of 2013, and that’s important because it allows us flexibility to find new technologies and thoughtfully determine the most capital efficient way. Switching now to the Bakken, we have more than 620,000 acres in this liquids rich play that’s all held by production. We exited the quarter with the production rate of 26,000 BOE per day, and as a result of incremental takeaway capacity from new rail facilities, we’ve ramped up from five to eight rigs, and we’ll see the benefit of this increased activity in the fourth quarter and in 2013. We also have significant exploration activity underway in other unconventional plays in the lower 48, including the Wolfcamp and the Delaware and Midland Basins, the Avalon Shale, the Louis Shale in Wyoming, the Niobrara and the Mancos in the San Juan Basin. We expect our results in these place by early next year. And I should note that these are just a few of the opportunities we’re evaluating in our vast lower 48 land possession. We continue to identify other potential plays where we can acquire unconventional acreage at the low entry prices. Moving onto Conventional Exploration, we have some significant activities underway in the Gulf of Mexico Deepwater and continue to build a portfolio of future opportunities there. Just for some context, we have 1.5 million Deepwater acres in the Gulf making ConocoPhillips the sixth largest Deepwater acreage holder there. Our initial strategy for this area has been to participate in non-operated wells by building a COP operated portfolio. Currently we’re building two non-operated wells, the Coronado prospect and the Shenandoah appraisal well. We’re also just about to spud a third well, Humber. It’s a supply and exploration well. And we anticipate four additional exploration wells spudding in 2013 along with the Tyber appraisal well. And the potential for additional appraisal wells exist if we have success with our exploration wells. So we’re really excited about our 2013 program in the Gulf of Mexico. Our long-term strategy is to build an attractive operated lease position that will allow us to drill three to six wells a year. And to advance our operating program that was announced on Tuesday that we’ve secured access to a new Deepwater drillship to use across our operated portfolio starting in 2014. Please go to Slide 17 and we’ll talk about the Canada segment. Our oil sands assets in Canada are a big part of our growth story. In fact, we are currently the second largest SAGD producer in Canada with 23% of total SAGD production. And our assets continue to perform well. Christina Lake, Phase D reached first production in July, three months ahead of schedule. Foster Creek is performing well. And Surmont Phase I achieved record production in September. As a result, third quarter bitumen production was 92,000 barrels per day net, after royalty. And we expect production to average over 100,000 barrels a day in the fourth quarter. Continued expansion in FCCL is ongoing and construction of Surmont Phase II is progressing towards first production in 2015. Surmont is a large-scale development. When it’s ramped up to full production the project will produce at a gross annual average rate of 110,000 BOE per day, equivalent to about 3 typical FCCL phases. And we continue to expand. For example, the sanction the Narrows Lake Phase A and Christina Lake Phase F are anticipated by year-end. The application of new technology is critical to the development of SAGD because it can add significant value due to the size of our resource base there. So we’re starting an enhanced SAGD pilot in November. And we’re actively testing several other technologies that will increase rates and reduce steam/oil ratio. Moving to our Western Canada business unit, here our drilling program is focused on liquids rich and light oil opportunities in our portfolio. And we’re also drilling or planning exploration wells in several of our unconventional plays in Canada including the Duvernay, Montney and Horn River. In addition to that, we’re preparing for a winter exploration program in the Canol oil play in the Northwest Territories where we hold more than 200,000 net acres. And like the lower 48, we hold a significant amount of land throughout Western Canada that’s held by production. And we believe some of this acreage could be prospective for additional tight oil and share liquid plays. So let’s finish out North America with Alaska on Slide 18. Major turnarounds were successfully completed at Kuparuk, Britto and Alpine this quarter. In fact, Kuparuk was completed 14 days ahead of schedule. In October the ConocoPhillips Board approved the North Slope’s Alpine West project also known as CD5. The project is now pending patent approval, which we expect in November and production will start from Alpine West in 2016. As you may seen in the press, we’re working with the other producers in Alaska to evaluate LNG exports from the North Slope. The Producer group has been focusing on narrowing down development concepts and assessing the cost of the major project components. In the Chukchi Sea we’re targeting drilling the Devil’s Four prospect in 2014. Now this prospect is in the 155 feet of water. So it can be drilled with a jack-up break with service BOPs and a prepositioned capping device on the seafloor. We continue to invest around $1 billion a year of net capital such as Alpine West and infill drilling programs across the North Slope. Significant additional oil development and opportunities exist contingent upon more competitive state fiscal counts. So let’s move to Slide 19, the Asia Pacific & Middle East segment. We produce more than 300,000 barrels per day from this region and it’s an area of significant growth for us over the next five years. We continue to make progress with the Australia Pacific LNG project. The project remains on track with premise, scope and cost and is on schedule for the mid-2015 start up of train one and 2016 start of train two. Now we track project progress in three main categories here: upstream, midstream and downstream. In upstream all major contracts for gas processing and water treatment plants and associated gathering systems are fully executed and module fabrication and drilling are progressing. In midstream the main pipeline work is in progress with right-of-way clearing, grading and pipeline streaming proceeding as planned. The downstream development of the LNG at Crackus Island is also proceeding as planned with engineering progress ahead of schedule and all construction access, dredging and mainland facilities completed in third quarter. At Poseidon Boreas-1 was a successful appraisal well reaching target depth on September 18 with encouraging results. The well was drill stem-tested at just over 30 million cubic feet a date against a flowing tubing head pressure of 3,300 psi. Drilling operations will now begin on the second well of the program in November, and this is part of five-well appraisal program that we will conduct over the next two years. In the Canning Basin we drilled and cored our first well. The well was drilled to about 12,000 feet, and 1,400 feet of core was collected. This is the first of a three-well program that will be completed by mid 2013. In China our net production at Peng Lai reach 45,000 BOE per day at the end of the third quarter, and production should remain fairly steady at that level for the remainder of the year. The first well at our Panyu Growth project came on in late September. Current Panyu production is about 8,000 barrels of oil per day net, and this project will add another 8,000 barrels per day between now and 2014 as we drill additional wells from the two new platforms. We now have four major projects in execution in Malaysia: Gumusut; Seacap, North Bohai; KBB in Malikai which were recently approved. First oil is expected from an early production system at Gumusut in the fourth quarter of this year. SNP in Gumusut full production will start in late 2013. The start up of the others will be staggered between 2014 and 2017. We’re also working on several other project developments in Malaysia and we have the potential to significantly grow this business over the next five to 10 years. Due to recently renegotiated gas sales contracts in Indonesia we will see significant increases to our realized gas prices for both on the Tennessee Block B, sales to Malaysia and of Corridor block sales to the Indonesian domestic market. Now these price improvements positively impact the value of both assets and increase the attractiveness of additional investment in these PSEs. Finally in this segment, conventional exploration in Bangladesh. There we’ve completed shifting seismic and we expect to complete the processing this year. Please turn to Slide 20 and I’ll provide an update on our Europe segment. We are focused on progressing our major projects in Europe. In the U.K. we completed a major turnaround at Judy that included preparing for the tie-in of the Jasmine project, and we installed the associated pipeline and jackets. Development drilling results at Jasmine are exceeding expectations and we expect first oil in the second half 2013. In the U.K. we’re also planning a five-well exploration and appraisal program at Greater Clair. In Norway we installed jackets, bridges and bridge support for the Ekofisk South project and commenced pre-drilling activities this quarter. We’ve also progressed modifications to existing facilities on Ekofisk and Eldfisk in preparation for tie-in of the new facilities. First production for Ekofisk and Eldfisk II are expected in late 2013 and late 2014 respectively. In Poland we exercised our option to acquire a 70% interest in Lane Energy and assumed operatorship of three Western Baltic Basin concessions for an additional exploration well that’s currently being drilled. The final segment I’ll cover Other International on Slide 21. As we mentioned earlier, we completed the sale of our 30% interest in NMNG. Our Libya production returned to pre-conflict levels. The third quarter average was 47,000 barrels per day. Additionally the fire and gas seals agreement was executed in early September, and this will result in a production increase of about 4,000 BOE per day for the rest of 2012 and going forward. In Kazakhstan, Caspian production is expected to be online in the first half of 2013. We completed our seismic on Angola blocks 36 and 37. Air blocks are immediately outboard of the Camia discovery in block 21, and we’re encouraged by what we’ve already seen in the seismic. Drilling is expected to start in 2014. I’ll conclude my prepared remarks by reiterating the things you’ve heard consistently today. Operationally the team is staying focused on executing the base business while successfully funding our emerging growth programs. We’re also seeing the payoff from the past few years of opportunity catcher, both in our unconventional drilling programs and our conventional major projects. Our expiration team is done a great job, not only building up our opportunity set, but advancing our current inventory to a drill-ready stage. So I echo Ryan’s early comments about how much there is to look forward to over the next few quarters and beyond. Now I’ll turn the call back over to Ryan for some closing comments.

Thanks, Matt. If I could get you up to turn to Slide 22 for some summary comments. The most important takeaway I think from today’s call is that the business is running well and that our plans are on track, and I’m pleased with our performance in our first full quarter as an independent E&P company. We remain highly focused on executing our major projects and our drilling programs, and we’re also building and testing our conventional and unconventional exploration portfolio. I think Matt’s overview should give you confidence that we’re making strong progress on these activities. We’re also executing on the strategic asset disposition program. When complete, these asset sales will improve our portfolio and create financial flexibility. This flexibility is core to our strategy, and you’ve heard from Jeff that maintaining a strong balance sheet is and remains a top priority. The bottom line, our long-term value proposition remains unchanged. We believe we have the portfolio and the programs to deliver 3% to 5% growth in production and margins with improving absolute financial returns and a sector leading yield. This is our commitment, and we’re on track to deliver it. We’re also committed to keep you updated on our progress. We expect to announce our 2013 capital budget in December and our year-end reserves and financial results early next year. And finally I’d like to encourage all of you to save the date for our first Analyst Meeting as an independent E&P company. We’ll host our meeting in New York on February 28 and will provide a detailed update of our strategic plans for growth and value creation. So thank you for your interest and participation this afternoon, and we look forward to your questions.

Thank you. We will now begin the question-and-answer session. (Operator Instructions) At this time we have a question from Ed Westlake from Credit Suisse. Please go ahead. Ed Westlake – Credit Suisse: Hey, everyone. Congratulations on the results. It certainly feels that confidence in 2016 growth and that margin improvement is building. I guess I have a question just looking beyond 2016. I mean as you look across the portfolio, do think nonconventional shale is enough? Or what should we focus most on do you think in this sort of pre-drill potential of the offshore portfolio?

Thanks, Ed. I appreciate the comments. I think as we look out beyond 2016, that’s the work that we’re alluded to in the operating update is working both on the conventional and in conventional side of the Expiration business. So I think you watch both those spaces globally, in the Gulf of Mexico deepwater and in North America, and we hope globally in the unconventional space as well. We’re working that pretty hard right now to load up the inventory for the latter half of this decade. Ed Westlake – Credit Suisse: And then a sort of more specific question just coming in on that Eagle Ford, obviously you’ve got some good production performance there. Can you just remind us what acre spacing you’re planning your production on? And any IP targets that are behind that target? Because it feels like if you’re already about 100 about 110,000 barrels a day guidance on 2013 that the well performance or the efficiency or something is changing that means you’re ahead.

So we have that 230,000 acres in total and we’re currently thinking that the ultimate spacing will be about 80 acres, so that’s what we’re planning for. And that results in about 1.8 billion BOE associated with the play. But we have pilot tests going on, several pilot tests going on in Eagle Ford where we’re testing different technologies and different spacing. So that might change over time as we learn more. Our IPs have continued to be in the order of 1200 plus barrels a day. And we’re seeing strong IPs compared to the industry average. We think the completions are working well there. Ed Westlake – Credit Suisse: And just to confirm those IPs, what time period?

30 days. Ed Westlake – Credit Suisse: Right. Yeah, they would be pretty good. Okay. Thanks very much.

Thank you, Ed.

Thanks, Ed.

Thank you. Our next question comes from Doug Terreson from ISI. Please go ahead. Doug Terreson – ISI: Good afternoon, everybody, and congratulations on your results.

Thank you, Doug. Doug Terreson – ISI: Ryan, you mentioned a minute ago that the underlying production growth was 3% in Q3. And it looks like we’re going to have another 3% gain in Q4. So the first question is whether or not that’s your expectation for Q4 as well? And then second, obviously higher production is important. But your profitability and returns were near the highest level of the year during the third quarter as well. So I wanted to see if you could specify some of the functional and/or geographical drivers behind the improvement in the returns as well?

Well, thanks, Doug. Yeah, we gave you kind of a range for the full year and expect us to come kind of in that range pretty well. So you can see the growth is coming in the fourth quarter. And I think as we look across the portfolio, we came out of the turnaround season pretty well. We’ve added rigs in China and Libya, in the Canadian business unit and then the ramp-up in the unconventionals in the U.S. are providing a lot of the production growth that we’re seeing in the third and the fourth quarter. And then those areas are also as we see prices bouncing around, differentials bouncing around as well, those areas have largely led to the income and the margin improvements that we’re seeing as well. Primarily China coming back in the growth and both North American unconventionals and the Canadian oil sands. Doug Terreson – ISI: Okay. And then also, administratively, the exit rate for NMNG was 20,000, 25,000 barrels per day. Is that about right?

No, the exit rate was probably closer to 11,000 for us. Doug Terreson – ISI: Oh, okay.

So, yeah. Doug Terreson – ISI: Okay. Great. Thanks a lot.

Thank you, Doug.

Thanks, Doug.

Thank you. Our next question comes from John P. Herrlin from Societe Generale. Please go ahead. John Herrlin – Societe Generale: Yes, hi. Just some quick ones. With the Eagle Ford, how long are the laterals? And how many drilled but unfracked wells do you have currently but inventoried?

The laterals are typically 5,000 feet. I don’t know how many off the top of my head how many we have drilled and then not hooked up yet. But we have quite a few that we’re waiting to hook up over the next quarter and at the end of Q1. John Herrlin – Societe Generale: Okay. That’s great. In terms of your expenditures, if you’re going to split it between conventional and unconventional, is 40% a good estimate for unconventional? It’s CapEx exposure?

Yeah, that’s a reasonable next move if we were going under unconventionals in our planning. John Herrlin – Societe Generale: Okay. Last one for me is Poland shale. You’ve had other companies exit. Why are you optimistic?

Well, we still see potential in that sort of pari-Baltic region of Poland where we’re drilling just now. The time will tell. We’re testing a different part of the play, moving a bit farther north towards the Baltic with the oil that we’re drilling just now. And so we’ll see how that works out. John Herrlin – Societe Generale: Thanks, Matt.

Thanks, John.

Thank you. Our next question comes from Paul Sankey from Deutsche Bank. Please go ahead. Paul Sankey – Deutsche Bank: Hi, everyone. Just right at the end you said something I just wanted to clarify which was that you’re targeting a sector-leading yield? Can you just kind of run through that? Because it’s not actually on the slides that I see.

Well, I think as we think about it, Paul, today we’re yielding 4.5% or so, given where our stock price is. And as we think about our peer group as a mix between independents and the major integrates, we think the yield that the dividend will underpin for the stock will be at the upper end of all that peer group. Now some of that European integrates will be a little bit higher, but we are relative to a mix of peers in the integrated and the independent side, we think it’s one that falls at the top end. And it’s an important part of our value proposition. We’re committed to maintaining that kind of a dividend. Paul Sankey – Deutsche Bank: So you’re committed to maintaining the yield at the higher end of the range?

Well, I mean the yield will – we expect the stock price to grow, so the yield will probably come down a little bit. We’re committed to maintaining the dividend that we’ve announced and where we’re at today. Paul Sankey – Deutsche Bank: You guys have got an Analysts Meeting next Feb, right? I’m just not quite sure about the dividend policy, because I think you’ve got dividend as your top cash priority, and you have said that you want to grow the dividend, I’m not sure exactly what you said on the percentage aim for that if anything? Then I guess the yield is not, with all due respect, not quite what you meant. Because obviously it would be a different thing if you were targeting a better class or upper range yields.

Yeah, so Paul, what we’re talking about is, what we said, is we’ll allocate 20% to 25% of our cash flows on an ongoing basis back to the shareholder and we’ll do that primarily through the ordinary dividend. And we expect over time as our production grows and our margins grow, that our cash flows are going to grow as well, so I think what we say is we ought to expect modest increases in the dividend as we go forward over the next five years and deliver on the program that we’ve outlined to the market. We probably won’t grow as fast as what the dividend has grown over the last ten years in the integrated company, but as we look forward over the next five as our cash flows grow and our margins grows, so shall our cash flows grow. And our commitment to our shareholders remains the same. We’re going to distribute that percentage of our cash back to them. Paul Sankey – Deutsche Bank: Yeah, that’s great. I understand now.

And the yield will be, hopefully the share price will increase and the yield might come down a little bit. Paul Sankey – Deutsche Bank: Sorry, I was just picking you up on that. But it wasn’t actually written down so I couldn’t be sure. I understand now. Just my second follow-up. Back to the Australia LNG, you kind of started down the road of explaining where we were on costs and progress. Could you just remind us what the total project cost is expected to be, when the critical moments are for activity? If I give you an example, Chevron’s global project will have its peak activity level next Q2 2013? Could you talk about where, if you’d like, where the level of risk lies on the timeframe going forward and where you see the overall project costs? And you began to break that down between your three segments of where the costs lie. Can you talk a bit more around those and I think you talked about the extent to which you were contracted but I was wondering if you could go through some completion levels and so on. Thanks.

I’ll let Matt jump in as well. We’re still at a two-train $20 billion project for APL and GMX. That’s upstream, downstream, midstream all combined up. We haven’t seen any indication. That’s with without FX considerations which might move around a little bit over the course of the next four of five years as we complete the scope. I’d say we’re ramping up to peak kind of rates. I think we probably hit there into 2013 and into 2014 is when we start with our peak manpower both on Curtis Island and what we’re doing on the upstream side of the project as well.

The project is on track in terms of the progress. The critical path’s intact and we’re quite comfortable with the way things are working just now on the APLNG. Paul Sankey – Deutsche Bank: And given the critical path, when will be the maximum points of risk over the next coming quarters or whatever?

As we go through the critical path for example, one of the things on the critical path there any LNG project is typically the LNG tanks themselves and they’re ahead of plan. We basically were to the critical path, there’s always the sort of individual milestones that you want to meet, but we’re comfortable that we’re on track to do that. Paul Sankey – Deutsche Bank: And if we roll that up into the completion numbers so far, where would we’d be? I think you might’ve said that actually, sorry.

Project completion number as in the capital cost? Paul Sankey – Deutsche Bank: Yes. Exactly. What percentage is kind of done?

Percent complete just now for the total project is about 20% I think.

20% to 25%.

Yeah, maybe it’s 22%. But it’s that order of magnitude.

Jim?

Thank you. Our next question comes from Faisel Khan from Citigroup. Please go ahead. Faisel Khan – Citigroup: Thanks. Good afternoon.

Hello, Faisel. Faisel Khan – Citigroup: Hi. When we look at what’s going on in North America today, there seems to be a lot of asset transactions taking place. I just want to get your guys’ update on acquisitions? I know you’re divestiture plan is fairly straightforward, but I just want to get your update on how you’re thinking about? Also acquisitions, given all the transactions we’ve seen of late? And then I have a follow-up after that.

Yeah, thanks, Faisel. I think of the acquisition side we’re mostly focused on acreage acquisitions and have been over the last year so. I think we added a bit over 700,000 net acres to the portfolio in the last year. So what we’re focused on is trying to identify these unconventional plays early so we can be a very early mover and get into more of the ground floor type of opportunity rather than getting in after pilots have been done and the resource then derisked and drilling has started to occur to develop it. The price goes up pretty dramatically when you reach that stage. So our effort has really been focused on the organic side and capturing our opportunities early. Faisel Khan – Citigroup: And in the Gulf of Mexico, are you pretty satisfied with your position? If assets were for sale, would you take a look at them?

I don’t think we’re ever satisfied with our position. We continually look for opportunities to improve it or consolidate our positions and bulk up what we like and farm out what we don’t like. Faisel Khan – Citigroup: Okay. Understood. And looking at the Eagle Ford and the Bakken positions in your prepared remarks you talked about how you’re developing some infrastructure. What is that infrastructure spend exactly? And when is that going to come to an end over the next, I guess in the future?

So this year we’re spending around $600 million or $700 million on infrastructure, I’m not exactly sure what the numbers are for next year, but it’s mostly a 2012-2013 expenditure to kind of build the backbone through our acreage as we develop that whole acreage position. Faisel Khan – Citigroup: Okay. If I’m just thinking about the projects that have been sanctioned – I’m thinking about reserve bookings, it seems like you’ve got some additional sanctioning in Canada. You’ve got the Alpine West you said. And then you also went forward with the second train of APLNG. Are those kind of the big things I’m thinking about? And how would I also think that the Eagle Ford where you have 1.8 billion barrels of oil equivalent in place?

So we’ll see reserve bookings at the end of the year associated with the ones that you listed, plus we expect to see our proved preserves in Eagle Ford increase. We also sanctioned the Malikai project in Malaysia, so we’ll see reserves increase there. And there’ll be some puts and takes on various other assets, but those are the major reserve additions that we expect. Faisel Khan – Citigroup: Okay. Got it. Thanks for the time. I appreciate it.

Thanks, Faisel.

Thank you. Our next question comes from Blake Fernandez from Howard Weil. Please go ahead. Blake Fernandez – Howard Weil: Folks, good afternoon. Congratulations on the results. I have a couple for you, one is a little bit more detail, but I noticed the lower 48 natural gas production increased fairly sizably. I’m trying to determine, I know there was gas that was previously shut in. Can you say whether that was a result of that gas coming back on line? Or maybe you could just answer where you stand today with regard to shut-in gas?

So we don’t have any significant volume showing at all now. So some of that increase is gas coming back on line, but the majority of it is increases in associated gas production with our liquids-rich plays, for example Eagle Ford. Blake Fernandez – Howard Weil: Okay. Second question is on oil sands in general. There’s been an awful lot of press reports on assets being marketed from you guys up there, and I know you are probably unwilling to share too much. But I’m just curious if you could talk in general how the oil sands fits into the portfolio?

Yeah, I think the oil sands are important in our portfolio. The important growth of the margins are good and they have a different profile, obviously relative to some of the other assets, but important in complimenting a large portfolio like ConocoPhillips has. We have gone out looking at marketing some of our oil sand positions primarily some of our Surmont. And it’s over 100% acreage we have outside of the area. We’ve got a lot of interest in it. And in fact, we’ve got enough so that we got proposed a number of different structures. So we’re stepping back for a minute and taking a look at what might work best for ConocoPhillips as we think about our options that we have with our position in Canada. Blake Fernandez – Howard Weil: Okay, Ryan. But just to be clear we shouldn’t view that as potentially a full exit out of oil sands, right?

No. Blake Fernandez – Howard Weil: Okay. So I’ll slip in one last one, I know you’re in the conceptual phase of ANF gas LNG out of Alaska. Obviously you have a very decent position up in Western Canada there as well. I’m just curious, are you exploring options for LNG exports out of Western Canada? Or are you just really focused on Alaska at this point? Thanks.

I’d say we’re mostly focus on Alaska, Mike. Blake Fernandez – Howard Weil: Okay. Thank you very much.

Thank you. Our next question comes from Iain Reid from Jefferies. Please go ahead.

Yeah, hi, gentlemen. Sorry, (inaudible) Just a couple questions please, I think you talked about natural gas price improvements coming in Indonesia and Libya. And you can see that your Libyan realization has picked up substantially. So just interested in why that is. And also on the Indonesian side, is that something we’ve got to look forward to? Or is that something which has already happened?

On Indonesia it’s really something we have to look forward to and both the Malaysia contracts and the domestic Indonesia contracts, you should start to see those coming through the fourth quarter.

Is that something structural or was it an oil price affect? Or what is that?

It’s a renegotiation of the gas contract from Malaysia because Petronas wanted to secure more gas and because the Indonesian government wants to incentivize more development of the domestic production in Indonesia. So they’re moving towards a more market-based pricing. So those are really the drivers.

Okay. And what happened and Libya?

You mean the fera gas contract, but that didn’t happen until September.

We had a little bit of that in the third quarter but if you are looking at the realized price per (inaudible) in Libya we started to sell gas under that contract.

Okay. Second question is I’m just wondering how you feel about your U.K. North Sea portfolio. You’ve obviously got a couple of developments there. But you’re also I think going to sell some assets with the tax increases, et cetera. Are you kind of net seller now of the U.K. or are you after this disposal, which is in the works? Or is there something else coming?

Well, no, I think we’ve been pretty pleased. So the North Sea and the U.K. sector, you’ve got to divide that into three areas, the Central Graven, the stuff we have up west of Shetlands with our Claire interest in the East Ireland Sea and the southern North Sea that we have. We did try to market our southern North Sea position a little bit earlier in the year, but that got hung up with a bunch of changes that were occurring in the government in the U.K. side with taxes and abandonment liability and some of those issues. But the core area that we still like and remain to think there’s still opportunity there, things like Jasmine developments that tie into our existing infrastructure, so we see additional opportunity off the Brittania platform bringing more wells and additional satellites into production in the Brittania area. And we’re currently exploring in the area for more Jasmine look-alikes.

Okay. Did you pick up any licenses today, Luc, in the license room?

I don’t know if we did. I haven’t been informed if we have or not.

Okay. All right, guys. Thanks very much.

Thanks, Iain.

Thank you. Our next question comes from Paul Cheng from Barclays. Please go ahead. Paul Cheng – Barclays: Hey, guys. Good afternoon. I have a number of soft questions, hopefully. Matt or Jeff, for the APLNG on the $20 billion, what is the percentage that is the Australian dollar-based and what FX rate are you using in the budget, if you can remind me?

It somewhere between 50% and 60% Australian dollar, and I don’t know that we have a particular FX rate that we’re going to quote in the budget. Paul Cheng – Barclays: I see. Matt, how many Matt wells you already drilled in Poland? And is there any result that you can share from those wells?

We’ve drilled a total of four wells, three in the pari-Baltic region and then we’ve got one more that we’re drilling just now, but I’m not really ready to talk about the results at the time on those wells yet. Paul Cheng – Barclays: I see. Ryan, I know that you don’t give the budget in December. If you’re looking at right now did you expect the budget would be pretty similar to this year? Or that is going to be higher or lower?

I’d say it’s in the range of where we’re at this year. Paul Cheng – Barclays: Okay. Jeff, on the corporate expense do you have a guidance that for 2013, 2014, what type of run rate that normal quarter may look like?

Yeah, maybe just a couple words about our corporate segment. So with the spine and the way we realigned our segments some of those things that didn’t used to be in corporate are in corporate now, particularly some of the technology operations, so that’s going to introduce a little bit of volatility to corporate numbers. When you think about kind of core corporate, which is made up primarily of net interest expense and kind of corporate G&A, that’s going to be around I would say $220 million a quarter more or less, but there’s going to be probably more volatility in the corporate number than you might have been used to seeing in the past. Paul Cheng – Barclays: Jeff, that’s an after-tax number, right?

Yeah, that’s an after-tax income number. Right, Paul. Paul Cheng – Barclays: And, Matt, I’m just curious. Is there any core key difference between your consolidate bitumen output and your equity of (inaudible) bitumen output? So in other words, when we’re looking at estimating the pricing, the implied bitumen pricing, is there any core key differences that we should assume that there would be differences?

Well, basically you can think of three different areas. Some ore produces a synbit, so the bitumen is blended with the synthetic. The FCCL assets both blend with the condensate. So as condensate prices and synthetic prices move around that affects the net (inaudible). Within the FCCL, Christina Lake has a higher TAN content Foster Creek. so as a result it sees a bit of a discount to the blend it sells. But roughly speaking at current prices the net mark at Surmont and Foster Creek are about the same, and the net mark at Christina Lake is a bit less because of this high TAN content. Paul Cheng – Barclays: Matt, have you guys received a final approval to restart fully on Peng Lai from the Chinese?

We have submitted an EIA application and overall development plan, revised the overall development plan. We expect the approval shortly from both of those. Paul Cheng – Barclays: Thank you. A final on. Jeff, on the inventory standpoint at the end of the third quarter, are you guys still under it, over it? Or should we assume pretty much that you catch up by now?

Yeah, when you have an operation the size of ours, and you’ve got a lot of liftings happening, oil liftings happening in places like Europe and Alaska and in Asia, every quarter you’re going to have a little bit of fluctuation between the amount that you sell and the amount that you produce and it’s going to go plus and minus. I mean generally we’re in a balanced position, but we talked in the first quarter that we had about an $80 million negative impact from timing. We’ve come out this quarter we said about an $80 million positive impact from timing. We’re likely to see that order of magnitude. Types of swings can happen just because – through normal operations of timing of when... Paul Cheng – Barclays: Sure. Fully understand that. From an inventory standpoint your are pretty balanced at end of the third quarter?

Right. Again, we’ll have pluses and minuses. Particularly when you look at particular segments you can have pluses and minuses just as part of your normal operations. Paul Cheng – Barclays: Very good. Thank you.

Thanks, Paul.

Thank you. Our next question comes from Pavel Molchanov. Please go ahead.

Hey, guys. I want to go back to one of the earlier questions about the dividend. Your long-term growth target of 3% to 5% and your simultaneous target of having one of the highest dividends in the industry, if you discover that both cannot be done at the same time, which do you choose?

Well, we set our priority on our funding is with the dividend.

So I guess what’s the minimum acceptable level for organic growth? In other words, would be willing to take that down to 2% to 4%? 1% to 3%? Or is the dividend unambiguously what you would choose regardless?

We would like to be here in 10 years saying we’ve had steady dividend raises every year over an extended period of time. How fast we grow the dividend is going to be a function of how fast cash flows actually grow. We sit today at one of the higher dividends, and we’ve had some very strong dividend growth over the past decade. I think what we’re saying is we expect to have dividend growth going forward. It won’t be at the same pace that has been the past, but that’s a key part of our delivering to the shareholders. And we really can’t sit here today and tell you exactly what the dividend growth rate is going to be going forward. It’s an important part of what we offer the shareholders.

Okay. I appreciate, guys.

Thanks.

Thank you. That concludes the time that we have a question-and-answer session. I’ll now turn the call back to Ellen DeSanctis for closing remarks.

Thank you, Kim, and thank you, everybody. If there were folks in the queue that we didn’t get to, Ryan and I are obviously more than happy to cover up the questions off line. Thank you very much for your interest, and we look forward to ongoing communications in December and certainly in the early part of the year. Thank you.

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