Castlen Kennedy – Manager, IR Steve Farris – Chairman and CEO Alfonso Leon – EVP and CFO John Christmann – EVP and COO, North America.

Pearce Hammond – Simmons & Co.

John Freeman – Raymond James Charles Meade – Johnson Rice Michael Roe – PPH John Malone – Mizuho Securities Arun Jayaram – Credit Suisse Eric Otto – CLSA Americas John Herrlin – Societe Generale Michael Hall – Heikkinen Energy Jeffrey Campbell – Tuohy Brothers James Sullivan – Alembic Leo Mariani – RBC Capital Markets Richard Tullis – Capital One Doug Leggate – BofA Merrill Lynch Harry Mateer – Barclays Capital.

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 Apache Corporation First Quarter 2014 Earnings 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 conference over to Mr. Brady Parish, Vice President of Investor Relations. Sir, please go ahead..

Thank you, Jennifer. Good afternoon, everyone. And thank you for joining us for Apache Corporation’s first 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, Chief Executive Officer and President; followed by Alfonso Leon, our Executive Vice President and Chief Financial Officer.

In addition, joining us for the question-and-answer session are John Christmann, Executive Vice President and Chief Operating Officer of North America; and Tom Voytovich, Executive Vice President, Chief Operating Officer of International.

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, or cash flow from operations.

In addition, we have prepared an operations supplement which summarizes our activities and includes detailed well highlights across the various Apache operating regions. These can both be found on our website at www.apachecorp.com/financialinfo.

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 first quarter 2014 earnings from continuing operations of $753 million or $1.90 per diluted share. Adjusted earnings, which excludes certain items that impact the comparability of results totaled $707 million or $1.78 per diluted share.

Cash flow from operations before changes in working capital totaled $2.2 billion during the quarter. During the first quarter, total reported net production averaged approximately 640,000 boe per day with liquids production constituting 58% of the total.

Production during the first quarter was impacted by the sale of our operations in Argentina which closed March flow and were shown as discontinued operations on the income statement. Including discontinued operations from Argentina, our total production for the quarter was 672,000 boe per day. With that, I’ll turn the call over to Steve..

Good afternoon everyone and thank all of you for joining this afternoon. As you know, Apache has taken some significant steps to rebalance our portfolio and to focus our strategy on predictable production growth among North American onshore assets which are fuelled by our substantial cash flow that we generate from our international operation.

As we reshape our portfolio for the last four years, we’ve now shifted our focus to execution which has been a long core strength of Apache for a number of years.

As Castlen pointed out, today we announced strong first quarter results generating $707 million of adjusted earnings, and $2.2 billion of cash flow from operation before changes in working capital.

During the quarter, as Castlen pointed out, we experienced weather impacts in the North Sea as well as our central region where weather not only impacted our production but it also impacted our delay in our drilling schedule. Despite these significant disruptions, our first quarter production numbers were ahead of our internal plan.

We remain on track to deliver within our previously stated production guidance for the year at 15% to 18% North American onshore liquids growth, and 5% to 8% global boe growth on our pro forma 2013 production of 537,000 barrels per day.

During the quarter, our operational focus in our [indiscernible] acreage position across the number of hydrocarbon rich basins, allowed us to drive production growth in North American onshore liquids where we averaged 198,484 barrels per day which is up 6% or 11,600 barrels per day over the fourth quarter.

North America onshore liquids represented 53% of our total worldwide liquids and 31% of our total overall production. You can read a number of details in our operational performance and the quarterly operations supplement. I am going to go over a few of the highlights.

In the Permian, we got off to a strong start to the year, with production increasing nearly 15,000 barrels of oil equivalent a day or 12% quarter over quarter. This growth was a result of our continued strong performance relative to our tight curve and the ability to move some of our well forward.

We continued to have exceptional results on the Wolfcamp where we drilled an additional $43 horizontal wells during the quarter and further delineating our potential in the southern Midland basin where we averaged 7 rigs .We also saw significant results in our Bone Springs play in the Delaware basin.

In our Gulf Coast region we saw some very encouraging results from our Eagle Ford acreage. Earlier this year at our investor day we outlined our 400,000 gross acreage position in the northern part of this play.

We’re continuing to progress on stranding [ph] of the area despite nine additional wells during the quarter, our most recently completed well was McCullough-Wineman in Brazos county which 30- day IP averaged 1,455 barrels of oil equivalent a day well above our initial type curve.

Based on this recent well result, and our overall understanding of the play, we plan to increase our rig count from four currently to eight by midyear. In the division we’re driving costs down in the play and are currently working to reconfigure our wells to further enhance our returns.

In Canada, quarter-over-quarter we grew liquids production by 10%. We experienced strong growing results in our new liquids rich area of the Duvernay and Montney. We have 3D wells with encouraging results but we don’t plan to disclose further details at this time.

Earlier this week we disclosed two recent field discoveries in Egypt, including a well in Matruh basin and Khalda Offset Concession which encountered pay in five separate formations and tested at combined rate of 49 million a day and 7,700 barrels of condensates per day.

As you know we rigorously review our opportunity set and allocation of capital on a quarterly basis. Based on the strong results we’ve seen in the Permian so far and the Eagle Ford and our Gulf Coast regions we are evaluating the programs with an eye towards reallocating capital for those regions.

Looking ahead to production for the rest of the year, we anticipate strong second half growth as projects come on line in Australia and North Sea, a bit recovery from a very difficult winter. Let’s turn now from operations to our continuing efforts to fine tune our overall portfolio.

During the quarter we announced several additional divestments, in March we closed our previously announced sale of our operations in Argentina. In addition we announced the sale of non-core assets in Canada from Noel, Wapiti, and Ojay which did close on April 30.

I am sure you saw this morning we announced the sale of our deepwater projects Lucius and Heidelberg and 11 primary term exploration blocks to Freeport-McMoRan for $1.4 million. We have retained all current production in deepwater as well as the 147 deepwater primary blocks.

Based on the operator’s current timeline for the estimated production contribution for Lucius, we’re foregoing about 0.4% or approximately 2000 barrels of oil per day at gross for the year – both of this transaction. As I previously mentioned we remain confident in achieving our 2014 growth guidance.

I also want to provide an update on the progress related to our two LNG projects Wheatstone and Kitimat. We are in advanced discussions and on track to decide on the most appropriate financing options in the near future and at Kitimat we have been working with our partner to reduce our 2014 capital spend given where we are in the project lifetime.

Currently we anticipate reducing the budget by approximately 40% to around $600 million net as you recall that’s down from an initial budget net (indiscernible). Also at Kitimat, we are currently in discussion with several interested parties as we look to right size the overall investment in this project.

This is an ongoing process and one that we are focused on getting done in this calendar year. Finally I want to provide an update on our buyback program.

Utilizing proceeds primarily from divestments during the quarter as we bought back an additional $485 million of stock, this brings our total, since the launch of the buyback program to the end of the first quarter to nearly $1.5 billion or 17 million shares.

As a reminder our board authorized 30 million shares buyback program in early 2013 and we’re continuing to believe that Apache shares are a compelling investment at this price.

But on the first quarter conference call last year that we initially outlined our plans to redefine our global portfolio and bring greater focus to our expanded North American onshore asset base. We’ve made significant progress over this past year. We emerged a leaner, a more North American onshore physical company.

We believe our current portfolio gives Apache a tremendous foundation with sustained, predictable, repeatable and profitable growth for the foreseeable future. I would like to turn it over to Alfonso Leon..

Thanks, Steve. I am going to cover three areas today. Our balance sheet, reporting matters and earnings performance. As Steve indicated we continue to take important steps in pushing our portfolio for profitable growth.

Within the first four months of the year we announced and completed the sale of our entire operation in Argentina and certain dry gas properties in Canada.

Today’s announcement of the monetization of our development stage projects at Lucius and Heidelberg represents yet another step forward in focusing us in our growth area while crystallizing value for shareholders. We continue to actively repurchase Apache’s common shares.

During the first quarter we bought back $485 million in stock bringing our total re-purchase in initiating our $2 billion buyback program last year to $1.5 billion through the end of the first quarter. We continue to view our shares as one of the most attractive options to capture cash flow, reserve value and portfolio debt.

We recently allocated an additional $300 million of cash availability through incremental buybacks and now has a further near term optionality on this front with funds from Lucius and Heidelberg transactions. Of course, our balance sheet remains very strong and supports our deep opportunities for organic value growth.

We ended the first quarter with $1.6 billion of cash and debt unchanged at $9.7 billion which puts us at 22% debt to cap. We have approximately $1.8 billion in new proceeds from our Canada and deepwater transactions coming our way now and we expect our E&P capital expenditure to be within our cash flow for the year.

So our financial position is really very strong. Now, there are two balance sheet items in front of us. First is managing our interest in two integrated LNG projects for maximum shareholder value growth. Steve discussed this briefly but given the importance of this issue I want to touch on them as well.

We have identified competitive alternatives to finance our remaining investment in Wheatstone LNG outside of our cash flow and expect to announce our decision over the next few months.

In regard to Kitimat LNG, since our analyst day in February we have been working with our partner to reduce the proposed investment in 2014 by 40% to $600 million net to Apache. In addition we are in discussions with other potential partners to right size Apache’s percentage interest in the project.

Kitimat is one of the most strategic projects underway in the global energy industry. It will open Canada’s gas exports to Asia.

Kitimat has real pipeline solution in place, is backed by an unprecedented 100 TCFs of supply in the highest quality gas shale in Bakken in North America and can be delivered from the Art Well Pass [ph] producing up to 1 TCF each with minimal environmental impact. It’s a good project.

What we must do is right size Apache’s participation and states the investment to build long term value while supporting our competitive per share performance today. The second balance sheet item to keep in mind is that most of our current cash is overseas and cannot come back to United States without tax consequences.

This is the common issue for global corporations like Apace and yet one more reason why our monetization step announced today with Lucius and Heidelberg is important. This is U.S cash for Apache. Moving to financial reporting.

In our first quarter earnings, our former business in Argentina is reported as discontinued operations under accounting rules for current and historical period. This is the only component of our nearly $10 billion of recent portfolio focusing steps that you will see reflected as discontinued operation and that is strictly a function of GAAP rule.

[indiscernible] is based on continuing operation on the total I stated. A financial supplement posted on our website provides additional details regarding Argentina operation. I am now going to turn to results.

Our performance for the quarter was driven by strong production and price realization and resulted in reported earnings from continuing operations of $753 million or $1.90 per share. Our results included a couple of non-cash items, including an unrealized after tax gain on our derivatives of $49 million and some deferred tax impact.

When we remove these non-cash items for comparability purposes, our adjusted earnings were $707 million from continuing operations or $1.78 per share, up from $610 million or $1.52 in the fourth quarter.

Operating cash flow was strong driven by the performance of our North American onshore base, we generated $2.2 billion of cash flow from operations before working capital items, up from $2 billion in the fourth quarter. Now I would like to provide a bit of line by line color on our financial expectations through the end of the year.

Let me start with production. In February, we outlined 2013 performance production of 537,000 barrels equivalent per day. These represent before a gas production for 2013 minus all the divested properties, the each of non-controlling interest in Egypt tax barrels [ph]. This 2013 number provides the baseline for comparability.

As outlined in detail in Page 4 of our operations supplement, the equivalent underlying production in the first quarter of 2014 was 548,000 barrels equivalent per day.

We performed ahead of our expectations through the first quarter and remain on track to achieve our guidance for the year and in spite of the loss of production growth from Lucius and the weather impact in our central and northeast regions in the first quarter.

Turning to realization, oil realizations averaged approximately $101 per barrel for the first quarter.

Based on the current market outlook for differentials, we see our first quarter North American realization discount to WTI of $4.60 widening in the second quarter by approximately $2 or $3 and then falling back to first quarter levels by the end of the year.

We see international oil and North America gas realizations at about the first quarter discount to benchmarks for remainder of the year. On NGLs, we currently expect to realize about 30% of WTI through 2014. Going to the expense side, LOE per boe was up a bit quarter over quarter to $10.37.

We expect this for boe cost to increase 10% driven by general increases in labor and power costs and our divestments of dry gas properties for the rest of the year.

DD&A per boe is expected to rise by as much as $2 by the end of the year driven by our capital focus in liquids projects, although this is subject to significant variability spending on timing of reserve bookings. We broadly see other per unit cost metrics relatively stable through the rest of the year from the first quarter levels.

On income taxes, our first quarter effective tax rate was 40.4%. Going forward we expect our effective tax rate for the rest of the year to be in the range of 40% to 44%. Our deferred tax percentage in the first quarter was 28% in line with what we would expect for the remainder of 2014 absent nonrecurring items.

Finally, through the end of the first quarter, our E&P capital is on track with our planning for the year. Overall and despite significant weather events it was a very strong quarter for Apache and we reported strong production results, earnings and cash flow. This concludes our prepared remarks. And I think we are now ready for any questions..

(Operator Instructions) And our first question comes from the line of Pearce Hammond with Simmons & Co..

Regarding capital allocation within the portfolio, does it make sense to dial back activity a little bit in the central region and redirect those dollars to higher rate of return plays like the Permian or Canada et cetera? I'm not sure if you were kind of touching on that a little bit in your prepared remarks at all, Steve..

Yes, we haven’t made a final decision but I would suspect with the results that we’ve gotten out of the Eagle Ford, and some of the really better results in our type curve in the Permian basin, you could see us allocate capital a little differently than we did going into the year..

And would that the a decision that's more made at midyear?.

Probably a decision will be made in the next couple of weeks, I would say..

And then my follow-up is, given your tremendous success in growing volumes in the Permian, are you getting close to reaching a max operational limit for Apache and the region as it pertains to people, rig availability, procuring need of services, et cetera?.

With respect to services and rigs, we’re in very good shape, frankly. One good thing about having [indiscernible] rigs running that we have is we can’t get rigs and frac those. Certainly I made this analogy before, it’s a little bit like when you have a four month for 16 [ph], and you can add one more – it’s 16, you’ve got to add another 4.

We can go up some, but we are not going to be able to go up some the way we’re going at from 2011 to 2012 and from 2012 to 2013. But we have made [ph] in that account..

And your next question comes from the line of John Freeman with Raymond James..

Alfonso, just following up on what you said about Wheatstone where you're looking at these competitive financing alternatives.

I mean can you just kind of give us some ideas of what those alternatives are?.

We need to get some decisions going our side but the basic principle is this is not going to come out of our cash flow, this is not going to come out of our existing assets. Where this is a project that is contracted and a project that can finance itself, so that we don’t have to make any incremental investment in this project.

And it can also be something that we’re obviously looking Q4 value, we’re going to do whatever adds in those value for our shareholders –.

And then other question, shifting gears on the central region when you discussed that the weather not only impacted your production, but also the drilling and completion schedule. Just for context, you drilled 44 net wells during the quarter.

How many did you originally budget that you were going to drill and complete in the central region?.

John Christmann who runs our North American company you got --.

Yes, we had originally planned and kind of outlined at the February analyst day 418 plus which is about 100 wells a quarter. So it’s a significant reduction in terms of what we were able to get on..

That is really a result of jut the backup testing when you have – we had two different weather at those and it really weathers the production as much as being able to get wells down and frac and volume production..

And your next question is from the line of Charles Meade of Johnson Rice..

I wanted to ask the other press release -- the other news that you guys have been talking about today is the sell or the sale rather of Lucius and Heidelberg. And I wondered if you can -- you made reference in that press release that you're continuing to pursue the sale of other prospects I believe was the word.

So I wondered if you could just give a bit of the narrative back story on how the sale came about.

Whether it was someone who came and knocked on your door, whether you guys had the for sale sign on those for a while given the mark that Anadarko put on them?.

Well if you recall back in the beginning of 2013 even our yearend earnings call, we started unveiling what really had been planned for sometime but unveiling our goal to rebalance our North American portfolio make it a bigger chunk of it and we identified a number of assets internally that we were going to be on that risk, actually the deepwater was on that list at that time.

The one thing I would tell you is that we made the conscious decision we would not sell any properties that we didn’t think that we got a fair value for. So that probably answers that question. It hasn’t been actively marketed but it has been in the market for sometime..

That does. And I wonder if I could turn to the Permian here. When I look at your operations report and I see that you look like you've had some of the best results you guys have had in the Wolfcamp. In northern Reagan and in Upton County I know that's a little bit different from where the bulk of your area -- bulk of your activity was in 2013.

So maybe this is best for John, is that a fair read on the quarterly results out in the Permian? And what's got you excited now?.

I mean I think we continue to see improvement on all our wells, driven by completions, the things we are doing but we did run six rigs in the Mariam county, we may not track there, and continue to have outstanding results there.

We have added 5 horizontal rigs that we started adding late last year and kind of started to hit our strides in most other counties, Midland, Upton and Reagan, so we’ve got 5 rigs running there, two verticals, you will start to see some of those kick in.

The thing about Wolfcamp is you’ve got multiple beaches and we’re still early in understanding exactly how many wells we can drill per section, how many laterals and that sort of thing. So I am excited about all of it – our whole portfolio in the Permian is we’re having great results not just in Wolfcamp. So it’s not about the whole but –.

I might add, when John mentioned the number of wells per section, that number is not going to go down, that number is going to go up because we have identified that we may be able to downspace more than we are currently and we may have more batch of horizontals being able to go out, so the reverse per section certainly in that Wolfcamp area is not just in Barnett, but all through that play, we could see significant upwards..

Your next question comes from the line of Michael Roe with PPH..

I was just wondering you mentioned earlier in your prepared comments that you're seeing on the LOE side a 10% increase in general increase in labor and power costs, for the rest of the year.

Just wondering if you could provide a little bit more color around that please?.

If you look across the industry and even if you look at the variance on our first quarter versus fourth quarter LOE per boe, those are the driving factors in terms of forward experience with the level of activity out there. Those are the two biggest drivers of our variance on a going forward basis within this year..

And then I guess just my follow-up question would be it sounds like you're planning on using the cash from the deepwater Gulf of Mexico sale for additional share buybacks. I'm just wondering is there anything else you were contemplating for that or just how you're thinking about allocating that cash flow infusion. Thank you..

We are going to a board meeting next week and that’s the discussion that we still need to have internally. Just announced the transaction today, so we have to go through that. But we are very conscious obviously the value of opportunities that we are crystallizing right now through our buybacks in front of us..

And your next question comes from the line of John Malone with Mizuho Securities..

Just looking at Kitimat. Clearly it's been a drawn out process getting a partner. You've seen some potential partners go with competing projects.

Is there anything you can say Steve about any differences in perception that you might have of potential partners, since it's late and just a longer process? Maybe on pricing or cost or environmental question in BC and can you talk just a little bit about the landscape in Asia LNG in general?.

In terms of our partner strategy, we brought Chevron into the project just last year and that was in ’13.

We have been pursuing a very deliberate one step at the time of pros that brings value to this project – bringing Chevron in last year in 2013 was the very value added for us, it’s a downstream operator to complement our upstream expertise at Apache.

At this point as this project gathers further momentum, we have decided it is the right time to bring in additional partner into our group, if anything the momentum of the project had accelerated beyond our expectations, the pipeline is in very good stage, the facility is in a very good stage and Chevron is very keen and start to head with this project.

So it’s just the right time for Apache now to bring in another partner as we think about how much we had, and what project within our portfolio to maintain our balance..

And just Alfonso, just one analogy as well some housekeeping.

You haven't spent anything from a general cash flow in Wheatstone to date? Is that correct?.

We have incurred capital expenditure year to date in the Wheatstone project. We have not affected our financing decision as it fits very welded and up until the date, within this year and which we implement that in anything transaction, we will be funding that capital expenditure either by all means..

And one last one for me just on the North Sea, can you give me a sense of what you think the run rate could be there, net of any weather affects? I know you've got new wells coming on in hopefully the 40s in barrel how will that compare to or offset the natural declines?.

Well, as you are well aware, our strategy going into the year was that we were going to have growth regions and cash flow, so we measured the investment in the North Sea essentially deep flat.

So we expect to meet that end of the year, I think that catch up from the weather event in the first quarter was already underway, and I would look for you to see that the production rate stabilized, where it was probably about in the fourth quarter..

And your next question comes from the line of Arun Jayaram of Credit Suisse..

John, maybe starting with you.

I was wanting to see if you could comment on how some of your initial well results have been doing on the horizontal side and the Delaware Basin?.

We’ve got 3 rigs running over that whole area, and we have been very pleased, I mean we are predominantly growing in Bone Springs, and in Wolfcamp. And I think there is a couple volumes to be listed in the ops report and we are very pleased over there.

We do have some acreage to the south that we are evaluating, and later in the year we will be looking at some of those areas but if I am looking the page 1, 1H and number 02H, both net, they’re still playing on the 30 day IP, they came out over a thousand boe per day. And over 12 rigs and high pressures..

John, if you're going to put some incremental capital as it stands today, would you be looking more on the Midland side or the Delaware side?.

Right now we are probably running two-thirds of rigs running in Midland, that’s the easiest place to add, and that’s driven based on just where we can put in immediately. I think the economics are very comparable in both basin though – as the year unfolds, mostly it’s getting more active in the Delaware..

My second question is, Steve, you reiterated your North American onshore liquids guidance. Obviously the Permian is ahead of plan as we stand today.

Do you expect the central region to be able to make up some of the weather induced downtime they had in the first quarter?.

I think it will make it up, some of it, I also think that we have opportunity set for day in the Eagle Ford and starting off the year based on what we have learned over the – really the last four months, we have an opportunity to ramp that up.

I think I mentioned in my prepared remarks, we’re going to go to from four rigs to by the middle of the year to 8 rigs there – plenty of upside [ph] on that to be able to do that..

And my final question is for Alfonso. The CapEx number in the quarter came in a little bit of above, at least what I was modeling. Just wanted to see if you could give us a sense of -- your full-year CapEx at the analyst day for your E&P was I believe a $8.5 billion, how you're trending relative to that target..

We’re exactly on plan, it’s actually slightly under in some regions but all in all on plan for that target.

When you look at the table in our supplemental financial disclosures I think there might be a bit confusion out there, when people are looking at those numbers and thinking about the 8.5, the numbers on that table include LNG CapEx within the relevant countries, that’s something that we are going to look at for us coming quarters except – to provide better clarity so the people can actually see how we find those to the 8.5.

You also have Argentina in there and you also have to keep in mind that, that table includes Egypt on a 100% basis, so it does now have our two-third interest economics interest in Egypt [indiscernible] in the 8.5. So we’re going to work to make that a little bit clear for the next quarter but we are on plan with our CapEx..

I want to reiterate what Alfonso said, you have a 100% capital – in that line you have 100% capital for Egypt, and our equity interest is two thirds. So it takes a little work to get to the net numbers. So overall --.

And your next question is from the line of Eric Otto with CLSA Americas..

Just a follow-up on Kitimat.

Can you give us an update or color on discussions with customers? And related to that does your partner still require oil link pricing for them to move forward with FID?.

I think starting with customers, the one thing I would say is that it’s a very active marketing group right now. We are – we have had discussions with most everyone you would expect that you would market LNG to and those discussions we are ongoing.

With respect to oil price, I think as a group, has been our partner, pretty good realization that it really doesn’t matter how you make up that basket but you really have to bear – at a price at the end of the pipe that will make up an economic project with the project, and I think we are both on the same page there..

And your next question comes from the line of John Herrlin with Societe Generale..

Kitimat, is it easier having FID to seek partners or does it matter at all in terms of bringing someone in?.

John, I don’t – I think Alfonso put a pretty good focus on – we are moving the project forward and we have a lot of momentum right now, I think that’s being hopefully recognized on the market side and in terms of FID, we would expect – we still have – final to do on the downstream, on the upstream it’s not just about – all about just drilling wells, we got an awful of facilities with takeaways planned success – we are in pipelines that we have put in there.

So we are involved in that FID right now, that FID should be done – upstream should be done by the middle of 2015 and likewise in terms of where Chevron is on the other side. But they are not contingent on each other let me put it that way..

One for John Christmann. We're hearing a lot more about changing well designs and multiple launch for unconventional plays. Also the use of more ceramics.

Are you changing your well completions designs at all in the Permian?.

We showed a slide at analyst day that showed early results relative to the new changes we have made. I think as we get in and drill more of these wells, and better understand the source that we are dealing in, and the spacing and the – we are getting better and you are seeing more sands, more stages, more zones, and finding ways to place it properly.

So it’s a combination of a lot of things..

And your next question comes from the line of Michael Hall with Heikkinen Energy..

I'm just curious on the good result you've been seeing there in the Eagle Ford, what are the hydrocarbon mix splits on those wells? And do you think you're stimulating the chalk at all with those? And what are the cost running on them?.

With respect to the mix, that well I mentioned made about 730 barrels for condensate for the rest of the year. So it’s about 60:40 liquids to gas. With respect to cost, I don’t know – well costs, -- we’ve just redesigned our Eagle Ford wells, we think we can take about $1.2 million off the well design that we’ve got right now.

I am hopeful we can take more than that out of it. As you go into pad drilling and you go into manufacturing mode, you can really bring your cost down, we have shown that at Bernhard [ph] area, we’ve seen that honestly – we start off drilling wells $16 million and today they are under 7. So we expect those costs to come down significantly..

And then you highlighted in the commentary or on the balance sheet all the cash that's sitting in the international arena.

Any plans to do -- what are your plans to do with that cash I guess? And how should we think about that?.

As we go through the next few months in terms of getting to the way forward in our LNG projects, we have to get – good decisions where it did not represent any type of cost, in our cash flow and we have – lot of exposure to Kitimat.

Once we have complete clarity [indiscernible] it is our objective to have over the next few months and we have some more at that, clearly at this very moment, we cannot bring that international cash to the United States without tax consequences. But that is something that we will have to continually looking at and figure out what we do about it.

We do generate NOLs in the United States as we go along as that can give us path – as we find our way to bring that cash back..

And one more if I could sneak it in on -- just total capital cost, just kind of the outlook you're seeing, particularly in the Permian, as you rollover contracts for the end of the year and into 2015.

Any commentary around any cost increases you're seeing on drilling or pumping?.

No, we just recently refrac tender and actually had a pumping services come down amazingly.

So we see things pretty well, I mean there is pressure on the bigger rigs, 1500 horsepower rigs with top drives, there is more demand, for those will be just up a little bit, I think the big deal is with the efficiencies, the things we have been able to do, we have been able to maintain or lower our oil costs..

And your next question comes from the line of Jeffrey Campbell with Tuohy Brothers..

The first question I wanted to ask you was as I survey the Permian, the industry is moving towards stacked lateral moment on TAD.

And when we see Apache horizontal success with the less than households name zones, Penn Shale [ph], Wichita, Albany, Strawn do those zones or that acreage have multi zone horizontal stag development potential?.

That just varies, I think what they show you is the diversity of our asset base. So we got acreage in place, so not everybody is, and so we’ve got – and that’s the nice thing about our portfolio.

While there are some areas in there where you could put multiple laterals, if you get over to the edge though in the Heady count, but some of those are really low zone targets but the nice thing about the Permian is that you got other stack zones that are – the strata that work as well.

So that you are seeing horizontal drilling really grape hold in the central platform, the wells in Delaware and Midland basins..

Going back to the Eagle Ford McCullough-Wineman well. Is that going to get more drilling near the Brazos-Burleson border or maybe push more into Burleson County? At the investment day, it looked like most of the drilling was taking place to the West.

And I guess overall I'm asking what do you think is the direction of Eagle Ford delineation over the next several quarters?.

I think McCullough-Wineman well, that is running very high on, it’s built in some things up and you will see us get very active in that area, Steve mentioned with Heady rigs, towards mid-year, as far as direction of where it goes, that’s not something we comment on at this point. We are excited about it on our acreage..

And if I could sneak one quick one in on the use of cash.

If the Montney and the Duvernay continue to create some excitement over time, could those programs become home for some of the international cash later on?.

We didn’t announce our results but I would say they were – we drilled two Montney wells now, we drilled two Duvernay wells, both of them are stellar walls. And we have quite a bit of acreage both in Montney and the Duvernay.

We are drilling up right now to look at – when we talk about capital allocation because we are in the sober [ph] month in Canada, we will have a plan going in for our winter drilling starting at about August September that will probably look a little stronger in the Duvernay and Montney..

And your next question is from the line of James Sullivan with Alembic..

Just wanted to go back to the East Eagle Ford for a second. And you guys talked about the McCullough-Wineman well was a nice result. But I think you had a couple of wells drilling in the Reveille -- at least next to where you had the well -- the older well that you guys had talked about the 8, 9, and 10.

Did you guys have results on that yet?.

We do not at this point, we [indiscernible] well there and so we are stacking some things up, that will be completed in the near future..

And then could you -- obviously you guys are sounding pretty high on the play based on the McCullough-Wineman results and that was over on the other side of the county there.

But can you talk just a little bit about the geology there? I mean obviously you've discussed the launch at the analyst day, but I mean is it -- are you guys feeling it's quite repeatable across the acreage in terms of how continuous the section is and all that?.

It’s very practical as you go across, I think the thing we have seen in the area is the QRs go up little bit which is helping you, so little higher gas rate with it, which is a good thing. So we’re very encouraged – got more energy in the system –.

If I could just switch over for a second to the Permian. I -- and let's see if I can express this question in a way that makes sense. But obviously you guys have an enormous vertical program that's transitioning over now into horizontal program.

So in a sense the ramp in horizontal activity -- it's not coming in, in a vacuum you've got human capacity there for the vertical program and in logistics and so forth. Can you just characterize -- I mean actually you guys went down up by four vertical rigs and up by one in the horizontal.

Is that, I know it's a little crude to think of it that way, but is that not a bad sense of scale in terms of how -- what you take from one program to give to the other in terms of capacity? If that makes sense?.

It’s a good question. That is not how we think about it. I mean we look at the baseline, we really look at how the plays work on an economic basis and we have been shifting as we have been building the horizontals, you will see a little bit of continued trend as we add rigs, there will be likely to be horizontals.

I think we’ve got a baseload program out there, really high graded projected with the verticals that we like to keep, I mean the nice thing about the verticals is we get on quick, the competitive rates of return and you don’t have to wait on pads and those things, so you will see us run a baseload of vertical rigs and then continue to grow the horizontal rig count..

When you are setting your base, sort of when you confirm a vertical wells, I don’t decline likely horizontal wells, you kind of match vertical wells and get the base going up..

And our next question is from the line of Leo Mariani with RBC..

Hey guys. Can you speak a little bit to how much acreage you have in the Permian and Upton and Reagan County's? It looks like you just start getting after that with some strong results there..

In terms of the acreage there, I mean we’ve got – we showed that at the analyst day those 3 counties I think couple hundreds, hundred thousand acreage, I need to check that exact number. Just a second..

While you're checking on the, you guys just mention the ability to sort of keep the vertical rig count consistent and add horizontal rigs over time.

Could you give us a sense of where you think that number could go to? What is the current horizontal rig count today in the Permian? And I'm sure you guys have a plan over the next couple of years to ramp that up, could you maybe put some numbers around that?.

Your first question, we got 292,000 acres in those 3 counties and 232,000 net.

You got significant Wolfcamp exposure in and – when we look at our plan for the year, we plan on 39 rigs – total rigs, we plan on 26 horizontals and 13 verticals, so almost 2 in 1 horizontal and vertical ratio, that’s probably a pretty good ratio for where we are today, right now there is capacity growth – to put couple in there but as Steve alluded to, it’s about just people and execution..

I guess just talking to about asset sales here, I guess obviously you guys just announced the deepwater. I guess I thought it was a bit surprising. On previous calls you said there weren't a lot of big deals left in terms of selling assets.

So I guess anything else we should expect on the asset sales side later this year?.

Well I tried to answer that earlier, when – the year end analyst call last year, we talked about portfolio of baskets that we were going to sell and we identified a number of candidates and quite frankly the deepwater was more of those candidates.

The other thing we had decided is we went from stalled properties to something less than we thought the value to look for, so that assets it’s been on the list for over a year.

We are going to make sure we got what we call we get value for that asset and it’s really – from our standpoint it wasn’t a surprise, we talked about order of magnitude, we have always indicated that we were moving out the deepwater, we still have about 900,000 barrels, 95,00 barrels today in the deepwater, we continue to reduce that.

We are not going to sell it unless we find someone is willing to pay what we think is, and I mean what is worth, but in terms of our, really in the deepwater we will have done that..

Your next question comes from the line of Richard Tullis with Capital One..

Steve, in today's press release announcing the sale of the deepwater, it sounds like the Company's planning to get a decent amount more active among the Gulf Coast.

Could you give a little more detail there and maybe what activity could look like over the next year or two?.

Well, as you are ware, a year or so ago, we went into effect the strategy to reposition ourselves in the Gulf of Mexico to become to be able to generate meaningful organic production growth on the shale.

Now as the shale of course is when we had interest in about 500 blocks, 125 of those operated and most of which have never experienced any deep exploration.

So it’s also where we transition our very experienced technical team out of deepwater with your advanced techniques for deepwater to similar geology on the shale and basically we are focusing on exactly the same horizons on the shale that we have been in deepwater for years. This is something that hasn’t experienced a lot of activity in the past.

There is lot of advances to be in over the shelf, there is a lot of room for liquids rich and oil growth, there is a much shorter concept to realization times and when compared to the deepwater, and we can certainly leverage existing infrastructure to cut the time and the cost on this process.

So it’s where – prospects can also better compete with the risk of our pretty robust global portfolio and that’s something that really for the last couple of years the deepwater has been able to do.

So in short, we are going to move our technical talent, out of the deepwater and merge that with a much more sensible resources that are available on the shale. You may want to think about this as especially 2014 is a year of inventory builds, and we would expect to come out of the blocks in 2015 with a nice drilling line.

I think we will hear our first real prospects and [rig count generated] realized in 2015..

And just as a follow-up, does your partner Fieldwood have any activity currently along -- that you're involved in along the coast? Well results that we should look for near-term?.

The only well that – really is the easing out with 136 which is put out in the first quarter, I think about 6 million a day and a few hundred barrels oil, I mean 300 barrels of oil, other than that, I don’t see any additional activity in the near term..

And your next question is from the line of Doug Leggate with BofA Merrill Lynch..

Thanks good afternoon guys thanks for taking my questions.

Steve in the Gulf of Mexico there the sale of Lucius and Heidelberg, what does that mean for the remaining interest you have in the deepwater in terms of your commitment to that area? In other words could they be for sale at some point?.

Let me answer that, I think maybe you didn’t hear me or maybe you can’t hear, I understand, maybe [indiscernible]. We still have about 96,00 barrels a day in the deepwater, it would have been nice to be part of a package that we sell.

As I mentioned earlier, we made a decision about a year and a half ago that we weren’t going to sell anything under a value that we thought it was worth.

So we are going to continue to operate those, we have 147 deepwater blocks, but you will see us migrate out of the deepwater either through producing that out and then abandoning it or if someone was interested in it, we certainly think it was worth for [ph].

But we have moved, that team – we moved that team to the shale where we have a significant acreage and I think the real opportunity to have more organic growth there..

Sorry I wasn't reading between the lines.

So I'm guessing you originally had tried to sell that together with Lucius and Heidelberg and decided not to -- is that how we should think about it?.

Sorry, I didn’t quite catch up you..

Sorry, so just reading between the lines, should we assume that you tried to sell the entire package and decided against it -- decided to hang onto those assets? So they were for sale in other words?.

You bet..

Thanks for that. My follow-up is onshore and hopefully it's not too convoluted. But just comparing the operating report to last operating report, there seems to be a fair amount of movement in your acreage positions. And the one that jumps out is the Marmaton. It's dropped from 512,000 to 395,000 net acres.

So I'm just wondering what's going on there? Is there active sort of high grading process going on or is this acreage expiry or what's causing the moving parts? And I'll leave it there. Thanks..

I can’t comment.

John?.

We got two rigs in the Marmaton in the first quarter, 26 we have working in the Anadarko basin..

Yeah one other things -- we’re completely, we got an upper Marmaton and we’ve got a lower Marmaton. And I don’t know what’s in that book but it depends on if you are in that lower Marmaton, which is more gassy but it comes on like gangbusters for the upper Marmaton. So we need to reconcile that.

I don’t know what those numbers, but I am sure as the total both upper and lower is probably the same number, I think we probably set up a lower Marmaton, we’ve got listed in there which is just subset of the total Marmaton..

And your next question is from the line of Harry Mateer with Barclays..

Hi guys. Just a question for me on the balance sheet.

Can you just give us an update on where you think the debt balance should be? Are you happy with your debt levels now or should we anticipate potential use of proceeds going forward to be further debt reduction?.

Clearly the strong position we don’t have any immediate need for any debt run up or debt reduction, we are in a very comfortable position and the most important question is what do we do with the cash coming out our way and what do we do once we complete will be pursuing on our LGN projects..

Okay.

It’s fair to say it sounds like investing in the business and potential returns to shareholders are going to take priority over debt reduction at this point?.

I think what he said is, we don’t feel we need to pay down any debt. We just need to make sure we will be able to cover the things that we are liable for, and we are going to look at obviously certainly share buybacks at our current pledge or on the table..

And we have no further questions at this time. I would like to turn the conference back over to our presenters..

Great, that concludes our call for today. Once again we want to thank you for joining us and if you have any additional questions, feel free to reach out to investor relations. Thank you..

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