Gary Clark - Vice President, Investor Relations Steve Farris - Chairman, President and CEO Anthony Lannie - Executive Vice President and CFO John Christmann - Executive Vice President and COO, North America Tom Voytovich - Executive Vice President and COO, International

David Tameron - Wells Fargo Doug Leggate - Bank of America John Freeman - Raymond James Brian Singer - Goldman Sachs Joe Allman - JPMorgan Michael Rowe - TPH John Herrlin - Societe Generale Charles Meade - Johnson Rice Michael Hall - Heikkinen Energy Advisors Jeffrey Campbell - Tuohy Brothers Investment Research Richard Tullis - Capital One Leo Mariani - RBC

Good afternoon. My name is Jennifer, and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2014 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. (Operator Instructions) Thank you. And I would now like to turn the conference over to Mr. Gary Clark, Vice President of Investor Relations. Sir, you may begin.

Thank you, Jennifer. Good afternoon, everybody. And thank you for joining us for Apache’s third quarter 2014 earnings conference call. On today’s call, we will have three speakers making prepared remarks prior to taking questions. I will start by giving a brief summary of results and then we will hear from Steve Farris, our Chairman, CEO and President; followed by Anthony Lannie, our Executive Vice President and CFO. Also joining us for the question-and-answer session are John Christmann, Executive Vice President and COO of North America; and Tom Voytovich, Executive Vice President and COO of International. Please note that we have streamlined our supplemental earnings disclosures this quarter. We are replacing our financial supplement and our operation supplement with a single quarterly earnings supplement. Most of the financial disclosures previously found in the financial supplement can now be found in the tables attached to our earnings release, as well as the 10-Q. Our new streamlined earnings supplement will continue to summarize our operational activities for the quarter and include well heights across various Apache operating regions. The supplement also includes information on E&P capital expenditures and the visual graphic to illustrate cash sources and uses that reconcile changes in net debt quarter-over-quarter. Our earnings release accompanying the financial tables and non-GAAP reconciliations, and our new quarterly supplement can all be found on our website at apachecorp.com/financialdata. Today’s discussion will contain forward-looking estimates and assumptions based on our current views and most reasonable expectations. However, a number of factors could cause actual results to differ materially from what we discussed today. A full disclaimer is located with the supplemental data on our website. This morning we reported a third quarter 2014 loss of $1.3 billion or $3.50 per diluted share, adjusted earnings, which excludes certain items that impact the comparability of results totaled $528 million or $1.38 per diluted share. Cash flow from operations before changes in working capital totaled $2.1 billion during the quarter. Worldwide reported net production averaged 637,000 barrels of oil equivalent per day, with liquids production constituting 60% of that total. On a pro forma basis, adjusting for recent assets sales and excluding the non-controlling interest and tax bills from Egypt, our second quarter worldwide production was 562,000 barrels of oil equivalent per day. This represents a 2% increase from the second quarter and a 6% increase from the same period a year ago. I will now call -- turn the call over to Steve.

Thank you, Gary, and good afternoon, everyone, and thank everybody for joining us. During the third quarter, Apache continued to make progress on our transition to becoming a premier North American resource company, delivering another quarter of strong production growth. Our North American drilling program delivered on-shore liquids production growth of 5% sequentially and 15% year-over-year, when adjusted for our asset divestitures. We had strong performance in the Permian and it continues to drive North American results. I want to go back, if you recall during our February 2014 Investor Day, we provided guidance for our Permian production growth from 12% to 15% for the year. Through the nine months ending September 30, our production increased 25%, nearly doubling our February guidance. This increase growth is a result of mix shift to more horizontal drilling. For example, our horizontal well count is up 50% and our vertical count is down 40% through the first nine months of this year compared to same period last year. The biggest drivers of growth in the Permian were our Wolfcamp horizontals in the Southern Midland Basin, our Yeso program in the Northwest shelf and our horizontal Bone Springs wells in the Delaware Basin. A particular note, our Pecos Bend area in Reeves County completed four very strong Bone Springs wells during the quarter. The average 30-day IP of these new wells was over a 1,000 barrels equivalent per day. In our Eagle Ford play, we’ve ramped up activity throughout the year and we are now running 10 rigs there. Strong results coupled with our relentless focus on lowering well costs are allowing this play to compete very well for capital within Apache’s capital program. During the quarter, we spud 29 wells, including wells on four separate pads and brought on our first two pads online in the Reveille area Williston County with an average 30-day IP of 609 barrels of oil equivalent a day. The success of our Eagle Ford program to-date coupled with our expectations for lower well costs and higher rates of return have prompted us to allocate more capital to this play in 2014 than we originally budgeted. Turning to the central region, we have retooled the organization, we have significantly reduced our rig count, we have made numerous process improvements and reprioritized our focus following our challenging first half 2014. We are scaling back our traditional Granite Wash and Tonkawa plays in the Anadarko Basin and we are focusing more on our drilling program in the Canyon Lime play in Oldham and Potter County in Texas Panhandle. As of this morning, we had 16 rigs running in the Anadarko Basin and four in the promising Canyon Lime. In our Duverney and Montney plays in Canada, we ran three rigs total and spud initial wells at the Duverney seventh well pad and drilled the first well at our Montney two well pad. The Duverney and the Montney offer some of the best reservoir rock in North America and we are looking forward to these plays driving our strong production growth once we have optimized our well costs and our completions. We are continuing to high-grade our North American asset base through the addition of leasehold in key growth areas and the sale of non-core acreage. During the quarter, we invested $520 million primarily in leasehold in the sweet spots of our key growth areas. This opportunistic investment was the big driver of the capital cost increase you see in our financial table. We plan to fund our increased investment primarily through the sale of non-core North American assets which we currently have in the market. We’re looking forward to sharing these details in our acreage purchases as well as providing an update on perspective asset sales on November 20th. Looking ahead, we’re confident that our 2014 North American liquids production growth will come in at the higher end of our 15% to 18% guidance range which led predominantly by better-than-expected production out of our Permian region. To sum it up, we are encouraged by the progress we're making in North America, both in our ability to drive cost out of the system as well as improve our well performance. And we are looking forward to providing a lot more detail in the next few weeks when we visit New York City. Turning to our international operations, all three of our regions, North Sea, Egypt and Australia delivered profitable production growth and remain on track to generate significant free cash flow per year. As a result, third quarter worldwide volumes came in slightly above the second quarter at 637,000 barrel equivalent per day, which is right in line with our internal expectations. In the North Sea, we completed our annual third quarter maintenance turnaround with no material delays. Production losses from scheduled downtime was partially offset by strong drilling results at Forties in our first well from The Forties Alpha Satellite Platform. In Egypt, we executed on a very active exploration and development program. During the quarter, we drilled eight new well discoveries in a call to concession. One of the most notable of which was Meghar-08 which IPed at nearly 3200 barrels oil equivalent a day. And yesterday, we tested our [Matruh] (ph) number one exploration well on Western Shushan Basin for over 7000 barrels of oil per day. Operations and production in Egypt continued with no material disruptions during the quarter. And finally in Australia, we made headway on several projects. Our Balnaves’ FPSO came online at the end of August and is currently producing at 18,000 barrels of oil per day net to our interest. We continue to progress our Coniston oil development and remain on track for first oil during the first half of 2015. In closing, I want to reemphasize the strategic direction we laid out on our second quarter earnings call. We remain committed to exiting our two LNG projects, Wheatstone and Kitimat. And we are continuing to evaluate the separation of our international assets through either strategic transactions or the capital markets. And with that, I’d like to turn it over to Anthony Lannie.

Thanks Steve. As mentioned earlier, we believe our North American onshore resource base is capable of driving strong growth and returns over the foreseeable future. And we continue to take important steps in that direction and allocate resources accordingly. In tandem with our strategic shift towards our North American onshore assets, we took the following two steps during the quarter. We determined that the undistributed earnings in our Australia, Egypt and North Sea regions should no longer be considered permanently reinvested in our foreign operations. This change in policy results in a non-cash charge to U.S. deferred income tax expense of $814 million on those regions for undistributed earnings. In addition, we repatriated $1.9 billion of cash from our Egypt region during the third quarter for which we recognized an associated non-cash U.S. tax expense of $249 million. Bringing this cash back to the U.S. will provide us additional balance sheet flexibility and liquidity as we delineate several promising onshore plays and expand our acreage holdings while at the same time repurchasing Apache’s stock. Turning to the income statement. As Gary noted at the outset, we reported a quarterly loss of $1.3 billion or $3.50 per share, which was driven by two significant items. The first is the $1.1 billion of income tax related charges that I just mentioned, in which reflect the change in our permanent reinvestment policy and repatriation of foreign earnings to the U.S. The second item is an approximate $1 billion after-tax non-cash ceiling test write down primarily related to lower oil and NGL price realizations and the impact of unamortized deepwater costs that remained in our full cost pool following the sale of our Lucius and Heidelberg projects at the end of the second quarter. When excluding these items, along with other more typical non-cash items such as mark-to-market derivatives and foreign currency exchanges, our adjusted earnings were $528 million or $1.38 per share, down from $644 million or $1.67 per share in the second quarter. Operating cash flow remains strong, driven by performance of our North American onshore base. We generated $2.1 billion of cash flow from operations before working capital items, which was down slightly from $2.2 billion in each of the first two quarters of 2014. Despite strong production numbers, our bottom line results were impacted by lower commodity prices. In North America, our oil price realizations averaged $94.69 per barrel in the third quarter, down 9%, compared to the second quarter. Gas price realizations averaged $3.88 per Mcf, down 7% from the second quarter, but still 9% higher than the comparable 2013 period. We ended the third quarter with just over $1 billion of restricted and unrestricted cash on our balance sheet, bringing our total -- our net debt to $9.9 billion. Year-to-date, we have invested $7.5 billion in our drilling programs, of which approximately $626 million is related to opportunistic acreage and leasehold acquisitions onshore North America. Our strong free cash flow from foreign operations and low debt-to-cap ratio of 25% provides Apache the liquidity to support both our North American growth and share repurchase program. On the expense side, LOE per Boe was up 5% quarter-over-quarter to $11.13. This is in line with the expectations we set on the first quarter call. The increase is driven by general increases in labor and power costs and our divestment of lower-cost dry gas properties. Turning to income taxes, our third quarter effective tax rate reflects the impact of the aforementioned change in our foreign earnings reinvestment policy, along with the full cost ceiling test write downs as well as other non-recurring items. Absent these items, our adjusted effective tax rate would have been 43.5%, which is in line with previous guidance. Our adjusted earnings and adjusted effective tax rate recalculations can be found in our supplemental financial information attached to this morning's press release. This concludes our prepared remarks. We are now ready for questions.

(Operator Instructions) And our first question comes from the line of David Tameron with Wells Fargo. David Tameron - Wells Fargo: Good morning. I guess it’s good afternoon. Lot of moving pieces, but can you talk about where Canada fits in big picture going forward?

What I think you’ve seen from 2014 -- I mean, 2013 and 2014, we’ve really high-graded our portfolio up there. We basically have two real major plays up there, which is the Duvernay and the Montney. Right now that is going to be our growth drivers for going forward. David Tameron - Wells Fargo: Okay. I don’t what you say ahead of the North American update? But if I think about the Permian, production -- can you just talk about how you see production? It look like it’s slowed a little bit in the quarter but I mean, that could just be noise and timing or completion, et cetera. But can you talk about that growth trajectory over the next 12 to 18 months? John Christmann : I mean, the first key is we are having a great year. When you look at the well count over the first three quarters of last year, our horizantals were up 50%, as we kind of shifted our program. We are currently running 41 rigs. You’ve seen us dropping the verticals as well. So actually, we are working quite a bit ahead where you had guided to 12 to 15% and we are looking at year-end numbers. We are going to put you twice the lower end. So we feel really strong about that. I think going into next year, we'll get into that on the November 20th, but a lot of that will depend on the commodity price forecast and how much cash we want to invest there. The big deal is, I think we feel good about the projects and we have a lot of flexibility with the rig count. So we are in a good spot going into next year.

And your next question comes from the line of Doug Leggate with Bank of America. Doug Leggate - Bank of America: Thank you. Good afternoon everybody. Steve, the step-up in the East Eagle Ford, obviously that’s a newer play for you. I guess, we are going to hear more about that at the end of the month. But I’m just kind of curios, if you could help right for us in this oil price environment, how that play would stack up against your Wolfcamp assets and in particular, how would you allocate capital or prioritize your allocation of capital towards the central areas and more gassy areas in the portfolio and I have a follow-up, please?

Yeah. Thank you. Honestly, we are tremendously pleased and excited about the future of the Eagle Ford and I don’t want to steal our guys thunder for November 20th. But we’ve seen our latest wells continue to get better and we are driving quite a bit of cost out of the system. Our view is that’s going to be a major play for us going forward, especially in 2015, 2016 and beyond. And some of that acreage that we talk about and we will show you this more on November 20th. We’ve increased -- basically that acreage is made up of two parts. One is we’ve increased the acreage in our interest and our existing acreage by buying some of our partners out and the other one is aggregating acreage right around what we think the sweet spot is. So, John, you might want to comment?

I mean, I think, directionally, when you look at where we are, we dropped our rig count in the Anadarko. Steve mentioned, we are down to 20 rigs now. So you see that drop in conjunction with the Eagle Ford ramp-up and that will continue going into next year. So that directionally tells you where they are and we’re looking at the portfolio, things that migrate to the top quick, they are going to be the Eagle Ford, the Canyon Lime and the Permian and lots of plays there. So it’s going to compete very, very well. Doug Leggate - Bank of America: I appreciate. My follow-up is really more about -- I guess you don't talk too much about the restructuring, but the issue around -- the subtlety of the issue around the international cash or free cash flow, which I guess is previously accelerating the drilling program to some extent in the Lower 48. With the separation of the international business and the lower oil price, how does that impact your -- I guess your willingness to spend outside of cash flow to bring forward the volumes to some of these newer plays? So I guess I am really trying to understand is operating cost flow, is that still a limiter for spending in the Lower 48 or the standalone company? Or should be expected to use the balance sheet and I will leave it there? Thank you.

Yeah. I might make a general comment. I think we -- over the last two months we’ve seen a $20 move in oil prices. I think all of us have to look at that. We certainly are looking at it in terms of making sure we’re prudent and what our capital program is going forward. I will tell you from an investment opportunity standpoint, we are better off right now and we have been in Lower 48 over the last two or three years. We have tremendous inventory right now, good inventory. I doubt if you see us until we understand where this price is going be really bullish on overspending our cash flow going forward.

Your next question comes from line of John Freeman with Raymond James. John Freeman - Raymond James: Good afternoon. The Canyon Lime is the one area in the central region that you all are increasing activity on and it seems like each quarter the commentary is more bullish. I think now you are kind of ranking as one of your three best North American areas since that Bivens well that you had. And I just want to make sure that I’ve got on the right numbers. When you entered the year that was about 100,000 net acres that was prospective for either the Canyon Wash or the Canyon Lime, is that still a good number to use? I mean, you’ve obviously been busy buying acreage across North America.

We are going to show a lot more of that on November 20. We have more acreage than -- we have more acreage today than we have in the past. John Freeman - Raymond James: Okay. I want still (indiscernible). I will wait on that. And then just my follow-up question. On Egypt you mentioned that there was the sequential production decline was due primarily to some technical challenges as well as some partial shutdowns on a shale operated gas plant. Can you just kind of give maybe an update on that status?

I will let Tom Voytovich who really got the details on that to answer that question.

Well to directly answer the technical challenges, there is a gas plant, the old biogas plant which has been rife with problems with the Benfield system and they have shale operated gas plant. It’s the only outside operated plant that we participate in. And as a result of that, out takes have gone down materially 30 million to 50 million cubic feet a day and that really accelerated here in the latter part of the third quarter. We think that this is going to continue through the rest of the year, but we will be making up for it in other ways.

Now the only caveat I would give that is, is in the Egypt 88% of our revenues come from our oil. Gases is percentage wise a bigger chunk of our production on a Boe basis, but 88% of our revenues come from the oil side.

And your next question comes from the line of Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs: Thank you. Good afternoon. Following up on the earlier question on free cash flow. In a lower oil price environment, if you are committed for Apache to stay within cash flow, is there any change to how you're thinking about the strategic nature of some of your free cash generative businesses like the North Sea and Egypt? Is there a case that perhaps you keep that as part of Apache for longer and use that free cash flow? If not, do you see yourself potentially having to cut back on activities in areas that you may rank in your top 3 plays like the Eagle Ford, Canyon Lime or Permian?

Brian, I think the statement that we made in our second quarter earnings call and I reiterated today, we are committed to exiting the LNG facilities and truthfully we are -- we’ve got lots of people working on those projects to do just that. In terms of evaluating our international assets for possible transactions or spends, that’s an ongoing process and we continue to look at it everyday. Certainly I think our -- truthfully I think our North American business today and I probably wouldn’t have said this a year ago or year and half ago is very capable of standing on its own. I mean, I think we’ve got the inventory and I think what you’re going to see in November 20 is we now have the capabilities and the leadership in the regions to be able to do that.

And your next question comes from the line of Joe Allman with JPMorgan. Joe Allman - JPMorgan: Thank you, Operator. Hi, everybody. Steve, could you just clarify your strategic direction? So we understand that you plan on exiting the LNG business. But, do you plan to exit the international business? And has there been any even nuisance change just based on data or thinking more deeply about things, about whether to exit the international business?

No, I don’t think so. I think, our plan, our strategic vision is to separate our North American form our international business. I mean, no -- nobody else, I mean when I say think, it’s just -- we have the same thinking today that we have in the past. Joe Allman - JPMorgan: Okay. That’s helpful. And then onshore North America activity, on a net basis are you in the process of ramping up the North America drilling activity and spending, or are you keeping things flat or you actually on the net basis reducing activity and spending over the next several months?

Well, I think, I guess I will reiterate the answer I gave a little early or the fact of the matter is, we’ve had by anybody’s calculations we’ve got a real sea change in oil prices. I think we’re all going to have a look at how we run businesses at $80 oil in North America and without blowing out your balance sheet. So depending on what happens to oil prices, we’re running a number of different cases, but we’re going to -- our capital program is going to be somewhere around what our cash flow is going into 2015.

Your next question comes from the line of Michael Rowe from TPH. Michael Rowe - TPH: Yes. I have a quick question on the Anadarko. So I guess you’re down to 20 rigs now versus 30 or so that we’re averaging Q3 and you specifically highlighted the Granite Wash and Tonkawa two intervals that you are hitting activity. I was wondering is that purely driven by tribal economics given where commodities prices are. Or was there I guess something else unique going on there operationally that cause those two specific targets to see less drilling?

As we mentioned or Steve mentioned in the script, I mean, we retooled and even on the last call we’ve changed out our entire leadership in our central region. So we’ve addressed the region VP as well as the Op. So the good news is in all of our plays, we still got good wells and good things there. We have shifted the rig count a little bit. We pared back as Steve said in the script and the talk on the Granite Wash. We’ve got a few more running in the Cleveland and the Cottage Grove, where we’re having some good results. And we’re also shifting to the Canyon Lime. But I think when you look at that portfolio and the mix, you’ll see a shift towards the Eagle Ford and the Permian and the Canyon Lime as we look at next year. Michael Rowe - TPH: Okay, great. And then just lastly on the $520 million spend for leasehold and property acquisitions in Q3. Is this part of a broader effort to I guess increase M&A activity relative to drilling given where commodity prices are now, just curious to see, if you are all thinking about easing capital for M&A has been changed versus prior expectations?

Gary, do you want on the Rockies then I handle.

Yeah. I mean, we have really seen an opportunistic -- opportunity this year to add some exceptional acreage in our key growth areas and so we’ve taken advantage of that. I wouldn’t say that it’s necessarily a sea change and how we view acreage acquisition and M&A, but the reality is we need to high-grade the portfolio. And as we’ve matured our key plays and demonstrated a lot of confidence and what we can accomplish there, we have seen a interesting opportunity to beep up in the sweet spots of those key plays. And at the same, we will divest and are divesting some of our areas where that are not going to attract capital and that are not on the growth track and they have lower rates of return. So what you all seen is our spending in the third quarter, what’s pending is the divestitures that will cover a lot of that spending.

Your next question comes from the line of John Herrlin with Societe Generale. John Herrlin - Societe Generale: Yeah. Hi. Three quick ones. With respect to the asset packages, can you give us a ballpark on associated volumes with them?

Well, we’re going to do that November 20th. We have got a -- I will say, we’ve got a package related to that we’re keen on. We’ve got a package in South Louisiana, our South Louisiana stuff its legacy, we’ve had for sometime. And we’ve also got some properties in central region that are gassy and we’re not spending money on. So you’ll see what that looks like in -- on November 20th. John Herrlin - Societe Generale: Okay. Thanks, Steve. How much does your typical Eagle Ford well run on a complete well cost basis?

John, we’ll get into that on November 20th, but they’re going to come in under $8 million Eagle Ford well cost.

We told you $8.3 in February and we’re doing better than that now and we’ve got our site set lower but we’ll share more on the 20th.

Your next question comes from the line of Charles Meade with Johnson Rice. Charles Meade - Johnson Rice: Yes. Good afternoon, everybody. Steve, if I could go back to maybe try to tie two questions together. As we look at or as I look at your debt trajectory, you had been on a trajectory down with debt, not every quarter, but generally over the last six quarters. But you have had tick up this quarter. And I’m wondering if perhaps that might be tied into a view that you are more likely to actually have an outright sale of some assets, whether it would be Wheatstone or maybe some of your conventional, all assets in Australia and that might be a source of funds to get that debt back down or alternatively if you're comfortable with debt in that $10 million to $11 million range going forward?

Well, I think the absolute debt is not as important as what we consider what our debt structure should be overall. In terms of our debt going up a little bit this year, I mean, this quarter, I think Gary has pointed out and I think, I pointed out earlier. We made some strategic buys of undeveloped acreage and what you’re seeing is you got a timing difference between we’re selling non-core assets, which should come in the fourth quarter. And the acreage acquisitions that we’ve seen in the third quarter, so those two should balance out over the year.

Your next question is from the line of Michael Hall with Heikkinen Energy Advisors. Michael Hall - Heikkinen Energy Advisors: Thanks. Well, one of my have been addressed. I guess, just one on East Texas, I’m just curious on those wells and maybe, I might have to wait but I figure I’ll ask. What the hydrocarbon splits look like on those wells, on average and then maybe high and low case splits?

I mean, we’ll get into that in detail when we -- we’ll show some data on November 20th but they really -- I mean, we mentioned the first couple pads have come on in the Reveille of average 690 Boes a day and that’s in a lower GOR area. One thing across our acreage that GOR does move, so it just depends on the area but we’ll go through that in detail on November 20th. Michael Hall - Heikkinen Energy Advisors: Okay. Steve. Thank you.

And your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research. Jeffrey Campbell - Tuohy Brothers Investment Research: Good afternoon. A little while go you called out the Montney and the Duvernay, but I found it interesting that you have three rigs devoted to the Bluesky formations in the Kaybob. And could you provide a little color here? Is it vertical or is it horizontal, is it developmental or expiration? Why is Bluesky attracting this rig?

Jeff, they’re just economics, they’re good wells, they are all horizontals and the economics are fantastic on them. So we can get the rigs in there and we’ve got three elements there. They’re cheaper, they are not as expensive and they help the program so. But the economics are very compelling. Jeffrey Campbell - Tuohy Brothers Investment Research: Okay. Kind of staying on this sort of theme. We’ve had earlier discussions of the pan shale as more of a standalone horizontal target. But this quarter you showed us three highlight vertical wells that featured the 10 combination with the Strawn and the Wolfcamp. Were these expirations wells preparing for later horizontal drilling, or does this vertical drilling have legs of its own?

No, that’s another area. I mean, you’ve got to look across the counties and we’ve got some areas where we are drilling horizontally in the Pan and the Strawn and we will show little bit of that on November 20th. In this particular area, we highlighted some wells that are North of Odessa and the [Gustav Bay] (ph) area and some vertical wells that we can stack those and they are also very compelling. We saw fantastic rates from those so. It shows you the variety in the Permian and you’ve got lots of zones, lots of area and different plays but they are very economic.

And your next question comes from the line of Richard Tullis of Capital One. Richard Tullis - Capital One: Hey, thanks. Good afternoon. Steve, I don’t think this area has been touched on. How does the remaining Gulf of Mexico shelf assets fit into your strategy going forward in this lower oil price environment. I know in the past you’ve mentioned that you expect it to perhaps begin drilling some of the deeper shelf targets in 2015?

Yeah. Right now, we are building inventory. I might point for those listening we have --we kept half of the deep rights when we sold our shelf. And we have about 500 blocks of deep rights under our existing shelf acreage that we sold. And truthfully that’s -- if we have a very good idea there, we’ll fund it otherwise that we will continue to build inventory. Richard Tullis - Capital One: Okay. And just as a follow up, what sort of price is required to -- oil price to generate expectable rate of return in the shelf for the type of well as you anticipate drilling?

Actually the shelf rates of return are very, very strong. And especially if you are drilling them, the reason we kept the deep rights is we sold 700 platforms. And so most of the deep rights are in and around the existing infrastructure. So you time back quicker and you can get them on quicker. And you don’t have the infrastructure cost that you do when you are under deepwater going out and doing expiration.

Your next question is from the line of John Herrlin of Societe Generale. John Herrlin - Societe Generale: Yeah. Hi last one for me. With the ceiling test, how much of it was the unamortized deepwater cost and was that all a U.S. pull or was there some Canada in there as well?

It was about 50-50. And it was all in the U.S. John Herrlin - Societe Generale: Thank you.

Your next question is from the line of Leo Mariani with RBC. Leo Mariani - RBC: Hey, with respect to your 2015 budget, trying to get a sense of when we would get a look at that? And I guess would we get a sense of spending on November 20th in terms of your North American on throughput?

Yeah. We are going to roll out what our 2015 and then our forward plan is, what our outlook is over the next several years. And our capital budget for 2015 will be part of that. Leo Mariani - RBC: All right, that’s helpful. And I guess just in terms of the international sales. I guess, it’s an ongoing process here. Clearly, I guess, we are in position now where oil prices have come in. Just trying to gauge your apatite in terms of spinning things off versus sales here?

I think they are both viable. I will tell you the one thing we’ve said and I think we’ve constantly done, we are not going to sell something just to get rid of it. And ultimately the separation will partly be, I am sure a span of some of our assets.

And we have no further question in queue at this time.

That concludes the call. Thank you all for joining us and we’ll talk to you on November 20th.

Thank you. This does conclude today’s conference call and you may now disconnect.