Good afternoon. My name is Rachel, and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter Earnings -- 2013 Earnings Release 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. I would now like to turn the call over to Mr. Brady Parish, Vice President of Investor Relations. Sir, you may begin your conference.

Thank you, Rachel. Good afternoon everyone, and thank you for joining us for Apache Corporation’s third quarter 2013 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 the third quarter results, and then we will hear from Steve Farris, our Chairman and Chief Executive Officer, followed by Tom Chambers, our Chief Financial Officer. In addition, joining us for the question and answer session which will follow the prepared remarks are Roger Plank, President and Chief Corporate Officer; Rod Eichler, President and Chief Operating Officer; Tom Voytovich, Executive Vice President for International Operations and John Christmann, Region Vice President for our Permian region. We prepared our quarterly financial supplemental data package for your use, which also includes the reconciliation of any non-GAAP numbers that we discuss, such as adjusted earnings, cash flow from operations, pre-tax margins or cash margins. In addition, we have prepared an operations supplement which summarizes our activities, includes detailed well highlights across the various Apache operating regions. These can both be found on our website at www.apachecorp.com/financialinformation or financial info. 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 discuss today. A full disclaimer is located with the supplemental data package on our website. This morning we reported third quarter 2013 earnings of $300 million or $0.75 per diluted share, cash flow from operations before changes in working capital totaled over $2.7 billion. Adjusted earnings, which excludes certain items that impact the comparability of results, totaled $932 million or $2.32 per diluted share. During the third quarter, total net production averaged approximately 784,000 boe per day with liquids production constituting 54% of the total. This represents an increase over the 771,000 boe per day reported in the third quarter of 2012 and a decrease from the 790,000 boe per day reported in the second quarter of 2013. Production in the third quarter of 2013 was negatively impacted by a decrease in North Sea production 6,100 boe per day predominantly due to a planned turnaround at 40s as well as natural field declines in the offshore Gulf of Mexico and Australia, all of which we guided to on our second quarter earnings call. With that, I’ll turn the call over to Steve.

Thank you, Brady, and good afternoon, everyone. And thank you everybody for joining us. As Brady mentioned, we’re delighted to have Tom Voytovich and John Christmann, join Roger and Rod and Tom Chambers and me on the call. And although Tom and John are not officially assuming their new Co-COO positions until the beginning of 2014, in typical Apache fashion they’re burning the candle at both ends rapidly getting up to speed with respect to their new responsibilities. As Brady pointed out, Apache reported another solid quarter generating $932 million of adjusted earnings and $2.7 billion of cash flow from operations before changes in working capital. On the operational results I’d highlight one number, Apache’s North America onshore liquids production grew by 49,000 barrels of oil a day or 35% from the third quarter of 2012 reaching nearly 190,000 barrels. Our North American onshore oil production grew by 26% during the same period to 129,000 barrels a day. During this time those regions made no acquisitions, so this is a 100% drill bit generated growth and it puts Apache in the top-tier of North America onshore liquids growth generators among all our peers. Apache continued to be most active US onshore driller in the third quarter running an average of 77 rigs and completing 306 gross wells. Importantly, we coupled our production growth with a relentless focus on operation and cost efficiency to ensure that our wells are not only increasing production but doing so at attractive returns. In all our onshore regions, we continue to drive down drilling and completion costs. And I’ll give you a couple of examples. Year-to-date we reduced our drilling and completions costs by $1.5 million per well in Tonkawa play in the Anadarko Basin and over $1 million per well in the Wolfcamp and…

Thanks, Steve. This morning we reported third quarter earnings of $300 million or $0.75 per share, adjusted earnings of $932 million or $2.32 per share. 784,000 barrels of equivalent of net daily production and over $2.7 billion of cash flow from operations before working capital items. Overall, our bottom-line results reflect another solid financial performance for this quarter. Oil and gas revenues totaled $4.4 billion, a $300 million increase over the second quarter driven primarily by higher oil prices with oil comprising 80% of total revenues despite only accounting for 46% of our total production on a boe basis. Including the impact of hedging, third quarter oil prices averaged $107.50 per barrel, up $9.57 per barrel from the second quarter, while gas prices averaged $3.49 per mcf down $0.38 from the second quarter. For the quarter, oil continued to sell for more than 30 times the price of North American natural gas. Our total cash operating expenses were down slightly for the quarter to $17.53 per barrel of oil equivalent, primarily as a result of lower lifting cost and G&A expenses as we continue to focus on reducing costs. As a result of our commodity mix and reduced cash operating costs, Apache’s cash margin increased by over 7% versus the second quarter to a healthy $42.74 per boe. Turning to earnings, we had several adjustments which impacted our results. Earnings for the quarter were negatively impacted by $478 million after-tax adjustment for non-cash property write-downs, including one in the US, predominantly related to our restructuring efforts, one in Argentina, relating to expiring concessions and one in Kenya, following our decision to exit the country. These were offset somewhat by $28 million deferred tax benefit for foreign currency fluctuations and other deferred tax benefits totaling $31 million. In addition, we recorded…

Thanks, Tom. Operator, we are now ready to open the call for questions.

(Operator Instructions) And your first question comes from the line of Arun Jayaram [Credit Suisse]. Arun Jayaram – Credit Suisse: Steve, I wanted to get your comments around international. I think in the press release you talked about how going forward these regions will primarily be a source of excess cash flows, and I assume that the incremental cash flows would be reinvested in North America. But how should we think about international growth going forward?

Well, we would like to be able to at least keep it flat – that regions that we keep we would like to be able to either keep flat or grow a little bit. For sure we’d also like them to be able to generate significant cash flow with our capital program for the year. For Egypt, for example, I think generated about $900 million of cash flow in the first three quarters. So – and it has – and basically stayed flat. Arun Jayaram – Credit Suisse: But Steve, by this comment, essentially you are communicating that relative to maybe Apache a year ago that you’re going to be investing more of your cash flows in North America versus internationally? Is that fair?

You bet. When ‘13 ends, you will see that in 2013 and certainly 2014 – a much stronger than that. Arun Jayaram – Credit Suisse: And my second question is for Tom. You produced 784,000 barrels for this quarter, your pro forma run rate that you show on page four of the supplement, is that 625 which is – with all the asset sales gone. So my question as we think about the fourth quarter, it would just reflect, I assume, for the fourth quarter just the Gulf of Mexico Shelf and Canadian assets and then going forward as we think about the first quarter of ’14, that’s when we start thinking about 625 and maybe some growth on top of that, as that being kind of what you do next year; is that fair, Tom?

That’s fair. That’s exactly right. Go ahead. Arun Jayaram – Credit Suisse: And can you just quantify -- overall I know you have done several transactions in Canada, what the impact will be in terms of the fourth quarter?

Depending on we still have some pending transactions it should be around 22,000 barrels a day, or thereabout equivalent a day, predominantly gas.

And your next question comes from the line of Pearce Hammond [Simmons & Co.] Pearce Hammond – Simmons & Co.: Steve, in your prepared remarks, you were talking about Canada and the ability to maybe have that asset compete with the Anadarko basin and the Permian basin assets for capital. Are you referring to your Duvernay and Montney assets and is this a foreshadow in that we should see an increased amount of CapEx for this region next year?

Duvernay, Montney, also we have Bluesky and also some of our Viking stuff that we are doing, all of it going horizontal, I think we will have by the end of November we should have 12 rigs running out there, all 12 will be sideways. We will spud our first Duvernay well. We’ve got an acreage position right in the heart of the play. So we will spud our first Duvernay well this winter. The rocks looks very similar to what they look like in the Anadarko basin there, they are called something different but that whole – western sedimentary basin looks an awful lot like the Anadarko basin. Pearce Hammond – Simmons & Co.: Do you think the economics could compete because of the – it seems like with the differentials being a little wider up there, it might make a disadvantage?

Well, I would tell you North American capital is going to have to compete with each other, so our program up there is going to have to compete with the Permian and Anadarko Basin in order to get funding. Pearce Hammond – Simmons & Co.: Great. And then my follow-up question is when you look back at the BP transaction from a few years ago where you bought some assets in the Permian and Canada and Egypt, but specifically in Permian, sort of, an after-action review on that particular acquisition. What do you feel like you picked up and how has it helped your asset base and especially in light of all the de-risking that’s going on in the Permian right now, how does that transaction look a couple of years on?

Well, I’ll give you a broad overview. I mean, honestly it’s been a home run but John Christmann is sitting here, who runs our Permian and is getting ready to run all our North American onshore. So, John, do you want to comment?

I mean, I think when you look at – there is really two transactions, you can’t just talk about, you know, BP without talking about Mariner, both those transactions really help change our whole program, I mean, you now look we’ve got over 1.1 million acres in the Midland Basin, you know, we’ve been in a transition out there, really an evolution into – in fact, in this quarter we now have, you know, across, we’ve got more horizontal rigs running than vertical rigs and we’ve got a lot of acreage contributed from, both, BP and Mariner. So I think it’s really helped the region put it where it is today.

And your next question comes from the line of John Herrlin. John Herrlin – Societe Generale: Yeah. Hi. Steve, you mentioned that you had well cost savings. How much of it was hedge related and how much of it was well completion, onshore?

How much is what now, John. John Herrlin – Societe Generale: You mentioned that you hedge for wells, so just wondering –

Yeah, the Tonkawa is really not been too affected by pad drilling right now because we’re just not going to that, frankly. The biggest cost savings in Tonkawa is number of days drilled and the completion cost. And the completion cost because we’re self-sourcing all our chemicals, all our sand and our horsepower now. John Herrlin – Societe Generale: Okay. And didn’t you also mention that Permian as well or was it just the Tonkawa?

No, I also mentioned the Cline. It’s many of the same thing. That is pad drilling. Certainly in the Wolfcamp in our Barnhart area. It also is associated with self-sourcing all our services. John Herrlin – Societe Generale: Okay. Next one for me is in the Permian you built a very large organization quickly. How automated are you going to make your operations just given the fact that infrastructure is so critical?

John, do you want to –

Yeah, I mean, I would say we have, you know, in a matter of three years, we’ve now got over 330 folks in Midland and I would stack that organization up against any. I think the thing we’ve got with the mid-40, 44 rigs running right now, when we are – you know, as I mentioned we’ve now got more horizontals than verticals, the beauty that we’ve got is, we’ve got multiple plays and that we’ve got the ability to kind of time these where we can work around our infrastructure both on the processing side as well as having facilities built for water handling, you know, the pads built and the sourcing for the fracs. So, I think it actually puts us in a position where we’ve got the ability to plan. We’ve been working on getting further ahead so we can do an even better job doing that. But I think that’s why you see such strong performance from the Permian in the third quarter and it looks good going forward.

Your next question comes from the line of John Freeman. John Freeman – Raymond James: Good afternoon. Have you all made a decision yet on when you do get those Egyptian proceeds whether or not you’re going to lead it offshore versus you lead in places like Wheatstone next year or if you bring it back and try to use your inner wells to kind of shield your tax hit?

Well, you’ve pretty well outlined the alternative. Certainly, we are looking at it, you know, we’ve made some commitments to pay down debt and to buy shares back which we expect. One of the things that I said – I think I said on the last call is is that we have so more producing assets than the $4 billion which means we’re going to have to pay down the debt than the $2 billion that we paid down so far. And we also have repurchased 8 million shares, which we intend to continue. John Freeman – Raymond James: And then my other question – looking at Australia in Australia, if I am looking at this rate, the current production there that is at is 56 million a day, which is about 60% higher than what you all said, you thought the net daily production was going to be last quarter, I was just wondering if you could add any color.

This is Tom Voytovich. I think that we are pushing more gas through Macedon earlier than we thought we did and it’s a nameplate gas plant of 200 million, we are up to around 225 million. So arithmetic I think is fairly self-explanatory.

Your next question comes from the line of Charles Meade [Johnson Rice]. Charles Meade – Johnson Rice: I recognize that, that if you are all ready to give guidance and talk about 2014, volume growth you would have come out and done that. But I was wondering if I could get you to talk a little bit more about how you are internally thinking about what 2014 would look like, this year. Doing some of the same math that Arun did earlier, it looks like to me that you have been having kind of year-over-year growth of around 2% and just the denominator effect from the sold volumes will get you more like 2.5%. But I think there will also be some effect from the fact that the Gulf of Mexico Shelf was declining and that might add a bit more to your growth. So is there any discussions or thoughts that you have had internally that you can share?

Yes, I can’t quite – depending on how you calculate the math, the way that we look at 2014 is 2013 based on a pro forma, we should be able to increase our production growth rate for 2014. We’ve got a lot of moving parts in 2013; to peg a number it’s pretty difficult right now other than looking at it on a pro forma basis. Charles Meade – Johnson Rice: And is there a pro forma number that you have in mind, Steve?

No, we are going to have analyst day in February and we will come out with a 2014 production growth and capital plans for 2014. Charles Meade – Johnson Rice: That will be great. I can wait till then. And then if I could follow up on the Permian, I notice that I have asked about this horizontal on the Central Basin platform you guys a few times. It seems like you are the only operator that’s really doing it. And when I look at your operations report, if I am interpreting correctly, I think you’ve got a few more in there, horizontal Wichita Albany, and horizontal Australia I think it was. And so those are quite impressive wells and they look like they have had great economics. And am I right in that and how does this stack up with some of the more industry wide plays that are happening in the Midland basin?

I would say you are exactly right and those are, three of our wells right now are some of the best economics we’ve got in the region for sure. The beauty we’ve got is having a big position on the Central basin platform, we’ve got a lot of assets, we’ve got areas where we can go in and target and use horizontal drilling, and we’ve done it quite successfully. And we have been doing that since 2010 in the Grayburg, Squire 4 [ph], [indiscernible] and obviously Wichita Albany has been a big story for us this year. So I think the beauty of it there is you’ve got your areas where you come off of main units, you’ve got on the flanks, you’ve had units performed on paycuts and parameters that were little better than what you are drilling horizontally and it makes for really, really economic wells. But the big deal is you’ve got to have the assets in the acreage and positions in those deals and the infrastructure to drill. They are very good economics.

Your next question is from the line of David Tameron [Wells Fargo Securities]. David Tameron – Wells Fargo Securities: Hi, just back to the Permian. Can you give us a breakdown – you have -- I think it’s 45 operated rigs running, can you just ballpark that for Central, Midland and Delaware?

We’ve got roughly 3 in the Mexico, handful of them in Central basin platform. If you look at the Wolfcamp alone right now, we’ve got about 9 horizontal wells running in the Wolfcamp, I have got another 3 or 4 in other plays down in the central – or in the Midland basin. So you’ve got over half of the rigs indefinitely in the Midland Basin and that over half of the rigs are horizontals. We’ve got a couple down in the Delaware and they’ve kind of scattered out in some other areas. David Tameron – Wells Fargo Securities: Okay. John. And if we think about, just a year ago or year-and-a-half ago when you guys had your Analyst Day you kind of rolled out what your plans were for the Permian and what you knew at that time. Looking back, any areas you’re more excited about, less excited about, kind of what’s changed, I know there’s been a lot going on the last year-and-a-half, but kind of what’s changed in the last year-and-a-half that you could summarize that for us.

Well, I mean, I think, you know now the – obviously there’s a lot of momentum, you’re seeing a lot of these plays are real. They’re getting more legs underneath. If you look back at what we guided to it was kind of 13% growth, I think with where we’ve been the last two years, we’ve well exceeded that. So, I think we’re very excited about what’s in front of us. I think you’re seeing the cost come down significantly as we alluded to, you know, with the use of pad drilling and the completion side and starting to go that direction you’re seeing multiple landing zones, so there’s more to be excited about today as we see that it’s starting to really prove out and we’re being able to deliver on what we said we’ll do to you back in June of 2012.

And your next question is from the line of Matt Portillo. Matt Portillo – Tudor Pickering & Co.: Good afternoon.

Good afternoon. Matt Portillo – Tudor Pickering & Co.: Just two quick questions for me. The first in regards to the Permian. I know that you guys have really focused a lot of your drilling activity, initially, around the Barnhart area for the Wolfcamp but you do have a very big footprint in Reagan and [indiscernible] and Upton in Midland County. And I was curious, as we think about the program progressing forward, especially given some industry results we’ve seen in all the various areas, how should we think about the expansion of your Wolfcamp program in the Midland Basin. And I guess, alongside that I did see that you had a very good Wolfcamp well, Loving, and I was curious how you guys are thinking about the Wolfcamp drilling program in the Delaware Basin?

Well, you got, you know, three different areas we’re talking about there. You know, we’re running six rigs in the Barnhart area, which is Irion County. You know, I think one of the legs up we’ve got on industry right now is we’ve probably drilled more concentrated wells in an area. So, we’re probably further ahead in terms of understanding spacing lateral lengths and really moving into development mode. So, we’ve been working hard there to understand that and actually doing a lot of field test to help us optimize wells. So, we’re excited about Barnhart, I think you’ll see us run a similar number of rigs as we start the plan for next year in that area. The one thing we’ve done this year is we’ve picked up two rigs, now we’ve got three rigs actually in Reagan and Upton. We’ve got two wells here, the Miller that are in the ops report that both are very strong wells. You know, I think an early look EURs will be north of our type curve that we put out in June of last year. And I think as you see us going into next year that will be an area where we will expand the rigs going forward as we get into those areas. The other area you allude to is in the Delaware, that actually is a third Bone Springs well, a horizontal, but it’s really close to the Wolfcamp which is why we tagged it that way. Very, very good well, you know, we’ve got some room to drill some more over there as we just kind of start to understand our Delaware position. The big difference in the Delaware and the Midland is you’ve got higher pressure, you’ve got little more water volumes to deal with over in the Delaware but right now all three programs look very, very compelling. Matt Portillo – Tudor Pickering & Co.: Okay.

And your next question comes from the line of Leo Mariani. Leo Mariani – RBC Capital Markets: Hey, guys, just wanted to follow-up on a comment you made regarding asset sales. It sounds like there could be some more coming from you folks, just wanted to get a sense, I mean, do you think there is anything really large are we kind of talking about small pieces of portfolio to clean up?

Well, I think we’ve done the lion’s share. I think I said in my prepared remarks, we’ve done the lion’s share. We do have some other assets that we’re looking at as part of our review. And I think it’s important to note that if we can’t get good value from at this point that we probably won’t sell them but we are actively pursuing some of those. Leo Mariani – RBC Capital Markets: Alright. I guess in terms of cost, you guys obviously talked about a concentrated effort to reduce LOE and G&A, certainly showed up in the numbers this quarter. You know any sense of continued improvement, any kind of magnets that you can give us, I mean, could we see another 5% to 10% per boe come at a cost going forward and how should we think about that.

Well, I think certainly that if you look at our operating costs on the shelf, our fourth quarter operating costs are going to go down, because if you put in that much production at $21 a barrel and average that over the rest of our property base, your operating costs are going to come down. Certainly on the G&A side, obviously we’ve gone down quite a bit on the product side and also – mentioned that when we talk about our sales in Canada, that’s about 52% of our well count up there. So it wasn’t just about getting rid of the dry gas, it’s also getting rid of well count. So overall our G&A ought to continue to come down also.

Your next question is from the line of Jeffrey Campbell [Tuohy Brothers Investment Research]. Jeffrey Campbell – Tuohy Brothers Investment Research: I noticed in your operations supplement that you mentioned that drilling fewer wells per section is 18, to better find well performing, I was wondering if you could provide some updated spacing for acre and will this be continued throughout your Cline areas?

Well, I mean one thing about these shales is they are homogenous. So different areas, you got to attack them different ways but we have found in the class, especially in Glassglow [ph], we are right now kind of looking at four wells per section, we are seeing better results, so it’s all a function of within that area but as you move into other areas, it changes. But I think that’s one of the advantages we’ve got as getting into some areas where we have got in the pads and drilling more laterals and get more wells down, we are going to have more data we can understand how to optimize this.

On a broader scale, one thing I think that – and not just for Apache, I mean truthfully with the number of zones and the amount of oil in place in the Permian basin, we just scratched the surface. I mean I truly believe that. I think the Permian is going to have years of surprises in it, most of them are going to be good.

Kind of follow up on that, if you take the Wolfcamp down and Barnett, we have tested four different zones in there, we’ve now placed two in the upper some would call the Wolfcamp but we’ve got a buffer, the lower portion of the upper are an upper. So there’s going to be more laterals stack in all these fields. So they will walk in on just how many per section for sure. Jeffrey Campbell – Tuohy Brothers Investment Research: Let me ask one further question, regarding the inherent risk of all exploration wells, maybe it’s too early but I was just wondering having gotten to a 100 feet pace, that’s efficient to commercialize the well, your announcement of the follow up drill kind of on the hill, it’s very positive.

Right, I think you can presume that we reached total depth on that well and we are about waiting selection options or evaluating options to conduction some appraisal drilling, so I think that will happen before the end of the year.

Your next question comes from the line of Michael Hall [Heikkinen Energy Advisors]. Michael Hall – Heikkinen Energy Advisors: I guess circle back on few things, number one, on the international production front, trying to little bit better understand that commentary about holding things flat, would that be from kind of current and or 2013 exit rate levels or should we think about that more as a flat year on year average?

I think it’s important that we articulate that plant – Egypt, we made that transaction for a number of reasons. Obviously validate the value of it. But the other thing, it also gives us an opportunity to grow that region because it won’t be as big as part of our portfolio. So we can – it truly still have tremendous upside, we are drilling our first horizontal, actually we are going to drill seven horizontal wells this year but our first one is just about completed. And in the North Sea that is a matter of how much capital and how much cash you want to take out. In terms of our profile for 2014 versus 2013 more like an exit rate of 2013 than it is at average for the year. Michael Hall – Heikkinen Energy Advisors: And I guess the other from my end is on the spending side, I am just trying to think about – what in the current, let’s say quarterly spending rate would be non-recurring, if you will or should we – you know, why would though you do not think about just taking the roughly $3 billion spent this quarter and kind of annualizing that next year?

Oh, you mean your capital – annualizing capital, I’m sorry I didn’t quite. Michael Hall – Heikkinen Energy Advisors: Yeah.

You know, we haven’t allocated capital for 2014 yet. Certainly we’re very active in the Permian, the Anadarko right now but I think we got to be careful about just annualizing the third quarter’s capital numbers, that’s probably a little strong. Michael Hall – Heikkinen Energy Advisors: Okay. Thanks.

Your next question comes from the line of Doug Leggate. Doug Leggate – Bank of America/Merrill Lynch: Thanks and good afternoon, everybody. So, you guys gave us a pro forma production number for the quarter, I’m just trying to think in light of the strength of your balance sheet with the disposals coming in, can you give us a pro forma cash flow and CapEx number for the quarter? And maybe opine a little bit as to whether you expect to start out spending cash flow given that you’re going to have basically $6 billion of cash in your balance sheet when all disposals are done? And I’ve got a follow-up, please.

Brady, you –

Well, I don’t think – I think it would be premature to put out a pro forma cash flow and CapEx number for the quarter. You know we did breakdown capital by region within the financial supplement. Obviously you know the two major items that we've sold which is really the source of the pro forma number that we have in the operation supplement. So, you can assume even though ultimately we're going to – we’ll record 100% of Egypt on a non-controlling interest for the third that we don't own as the way we’ll account for it, but if you assumed a third of the capital for Egypt is not ours, we’re spinning two-thirds there and if you assume the Shelf obviously is not in those numbers, that would give you a sense for what our capital reduction would have been for the quarter. As far as cash flow, you know, Egypt is pretty easy to figure out what our cash flow is, when you look at historical financials you get a good sense for what kind of cash flow we generate there, even on a quarterly basis. And with respect to the Shelf, the one guidance we had given around the date of the divestiture when it was announced is that we were roughly going to get about $500 million of excess cash flow out of the Shelf with about $900 million of capital, so that obviously implies about $1.4 billion per year at least for 2013 that we thought we might do this year. Doug Leggate – Bank of America/Merrill Lynch: So, that’s helpful, Brady. Thanks. I guess what I’m really trying to figure out is you guys have got enormous opportunities there, obviously in the Permian. And I know you don't want to talk about 2014 guidance but historically, Steve, you’ve always talked about Apache will spend its cash flow but that was before you had potentially $6 billion on the balance sheet. So I’m just wondering should we anticipate some of those disposal proceeds accelerating some of that value? And I'll leave it at that, thank you.

Well, I think, a little bit you’re seeing that this year. We're going to make the best capital decisions we can. And certainly we would like to have a growth profile for 2014 that’s stronger than 2013.

Your next question is from the line of Richard Powest [ph].

Hey, good afternoon, everyone. Steve, just going back to the sub-salt play on the Gulf of Mexico shelf, with the success at the Heron well, do you have a reserve estimate on that well at this point and well cost?

You know we've got one well down. So, it's a little premature to talk about reserves. In terms of – the one thing I will say about that is, it is probably the next big play that’s going to come on the shelf. I mean all you're doing is taking that same rock and coming up on the shelf and looking for the same things you were looking in Deepwater, the only difference is we've got infrastructure across the Gulf because of our relationship, our negotiations with Fieldwood, we have rights to go through platforms on all those wells we drilled, including Main Pass 295. So, you should expect us to drill quite a few sub-salt wells, exploration wells, next year. And I think it has tremendous room.

Are you currently drilling any additional sub-salt wells?

There are two additional rigs that are running on the shelf right now. And we will continue program at that pace probably.

Your next question is from the line of Joe Magner [Macquarie Research]. Joe Magner – Macquarie Research: I was wondering if you could provide us with an updated production number for the Barnhart area.it looks like you added 10 more wells from the last update that was provided a couple of months ago and just kind of curious what the trajectory looks like there?

We have not come out on with anything external yet but we continue to run on active program out there. We were well above 8000 oil and gas has gone up nicely as well too. So I mean I think you will see more of that in February of next year when we walk through the analyst stuff. Joe Magner – Macquarie Research: Just I wondered if you could give us an update on, I think the length of the well being drilled up there has moved around a little bit, just current economics and costs and well performance.

I think we are pretty all in line with type curves that we disclosed back in June of ’12. We have drilled some longer laterals as long as 9300 feet, where it makes sense with the land we seem to be – drill a mile and half, so we’re just kind of setting that up right now. Our well costs have come down significantly as Steve alluded to. We are well under $7 million, the mid to high 6s right now. And so – and that’s for the 7500 foot laterals.

Your next question is from the line of John Malone [Global Hunter Securities]. John Malone – Global Hunter Securities: I’ve just two quick questions about BC, any update you can give us on status of Kitimat and then on Liard basin, you talked about these 10 new wells, can you give us some idea of what the production capacity of those Liard wells are?

So for Kitimat, things are progressing on a number of fronts there. From the regulatory standpoint, we are currently working with BC government to work out their desire for their LNG tax scheme. We are moving forward on the environmental approvements in areas that are concerning our pipeline occurrence right away. Of course, the downstream portion is operated by Chevron, in the upstream area we are completing our conceptual engineering for the placement of facilities that will support the rental drilling program. As far as the second part of your question on the yard, the one well that we have which is a premier well which is outlined is the D-34-K well which we think is one of the most productive shale gas wells drilled to date in North America, if not the world, that well probably may cost 20 Bcf, it’s been in production now for over year and a half, it’s the current – exactly as we forecasted at the analyst day last year.

The number of fracs are slight compared to what we will do on a development plan.

Exactly that particular well we only had six frac stages applied to at a very limited lateral compared to the design fracs for the wells going forward with the development plan which will be much longer laterals at a many frac stages we apply at it in Permian and Anadarko area. The 10-year program itself beginning in 2010 as we will mention more detail in February at our analyst day, is principally to hold acreage and less sulphur production, only a few of those wells like to see production in 2014 and 2014.

(Operator Instructions) There are no further questions at this time.

Okay, thank you Rachel. Thank you everyone for participating on the call. We obviously greatly appreciate your interest in Apache. If you have any additional questions, please reach out to the IR department and will be happy to help you out. Thank you. Have a great day.

Ladies and gentlemen this does conclude today’s conference call. You may now disconnect.