Gary T. Clark - Vice President-Investor Relations John J. Christmann - President, Chief Executive Officer & Director Stephen J. Riney - Chief Financial Officer & Executive Vice President Thomas E. Voytovich - EVP-International & Offshore Region Timothy J. Sullivan - Senior Vice President-Operations Support

David R. Tameron - Wells Fargo Securities LLC Leo Mariani - RBC Capital Markets LLC Brian A. Singer - Goldman Sachs & Co. John A. Freeman - Raymond James & Associates, Inc. John P. Herrlin - SG Americas Securities LLC Doug Leggate - Bank of America Merrill Lynch Pearce Wheless Hammond - Simmons & Company International Bob A. Brackett - Sanford C. Bernstein & Co. LLC Michael Anthony Hall - Heikkinen Energy Advisors Charles A. Meade - Johnson Rice & Co. LLC Michael Kelly, CFA - Global Hunter Securities James Sullivan - Alembic Global Advisors LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc. Richard M. Tullis - Capital One Securities, Inc. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.

Good afternoon. My name is Suzy, and I will be your conference operator today. At this time, I would like to welcome, everyone, to the Apache Corporation 2015 Second Quarter 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. Thank you. I would now like to turn the call over to Gary Clark, Vice President of Investor Relations. Mr. Clark, you may begin your conference. Gary T. Clark - Vice President-Investor Relations: Good afternoon, everyone, and thank you for joining us on Apache Corporation's second quarter 2015 earnings conference call. Speakers making prepared remarks on today's call will be Apache's CEO and President, John Christmann; and CFO, Steve Riney. Also joining us in the room is Tom Voytovich, Executive Vice President of International and Offshore; as well as Tim Sullivan, Senior Vice President of Operations. In conjunction with this morning's press release, I hope you have had the opportunity to review our quarterly earnings supplement, which summarizes our operational activities and well highlights across various Apache operating regions. The supplement also includes information on our revised full-year guidance, capital expenditures for the quarter, as well as a chart that illustrates cash sources and uses and reconciles Apache's change in net debt during the second quarter of 2015. Our earnings release, the accompanying financial tables, and non-GAAP reconciliations, and our quarterly earnings supplement can all be found on our website at www.apachecorp.com. I'd like to remind, everyone, that today's discussions 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 on our website. And I would now like to turn the call over to John. John J. Christmann - President, Chief Executive Officer & Director: Thank you, Gary. Good afternoon, and thank you all for joining us today. I'm very pleased with our second quarter results and the tremendous amount of progress we have made refocusing our asset base, strengthening our balance sheet, and restructuring our operational organization. Importantly, we are continuing to deliver on our cost initiatives, and we are exceeding our previously established production goals. During the quarter, we closed on the sales of our LNG business and remaining oil and gas assets in Australia, which served to more strategically align our portfolio with our core competencies. In doing so, we greatly enhanced our balance sheet strength and liquidity position. Additionally, we reduced our drilling and completion activities and overall spending to a level that is more in line with the current commodity price environment. We also realigned our management and regional operating structure to drive greater efficiencies, and we implemented meaningful new initiatives to reduce overall G&A costs. Finally, we delivered strong production both domestically and internationally, which is prompting us to raise our 2015 production guidance. Looking ahead, we anticipate having strong production momentum as we exit 2015 and believe that we will have the flexibility to live within 2016 cash flow, while maintaining relatively stable year-over-year production levels. Now I'd like to review our operational results in greater detail. During the second quarter, onshore North American production averaged 317,000 BOEs per day and once again came in ahead of our expectations. This was driven by strong operational performance across the entire portfolio and in particular from new well contributions in the Permian and the Eagle Ford. Our performance internationally was also impressive. Excluding Australia, pro forma production from international and Gulf of Mexico was 172,000 barrels of oil equivalent per day. Egypt was a significant driver during the quarter as delineation of the Ptah and Berenice oil fields continued to drive gross production sequentially higher. In the North Sea, our production declined modestly from the first quarter as a result of two seasonal platform maintenance turnarounds, but was still above internal expectations due to production efficiencies. We have also had recent drilling success in the North Sea, which I will discuss in a few minutes. Our performance on the capital side, during the quarter, was in line with our expectations. Expenditures on continuing operations before leasehold acquisitions, capitalized interest, and non-controlling interest were $857 million, which was down 28% from the first quarter. In addition to realizing service cost reductions, Apache is delivering solid drilling and completion efficiency gains, which is critical in this low oil price environment. At the beginning of the year, we took aggressive steps to address our cost structure and established a plan to reduce drilling and completion costs by at least (5:30) levels. Year-to-date we have already achieved the 15% reduction and are on a run rate for an approximate 25% reduction for the remainder of the year. We now believe that there are potentially even more cost savings over and above the 25% if oil prices remain at current levels. Our lease operating expenditures per BOE were down 13% year-over-year in the second quarter, and our G&A run rate is following quickly as a result of the overhead initiatives that we are pursuing on multiple fronts. Steve Riney will provide some more details in a few minutes on those items, as well as some forward-looking guidance. As noted in our press release this morning, we raised our full-year 2015 onshore North American production guidance to between 305,000 BOE to 308,000 BOEs per day, the midpoint of which is up approximately 5,000 BOEs per day from our prior implied guidance. We are also effectively raising our international guidance, as we now see production in Egypt and the North Sea up 5% to 8% this year on a pro forma basis, which is a notable increase from our previous guidance of up slightly. Looking at our onshore North American production profile for the remainder of the year, we expect third quarter production will be down sequentially from the second quarter. This is due primarily to monthly well completion timing, planned downtime associated with offset fracing operations, and planned facility and plant maintenance in the Permian. In the fourth quarter, however, we expect a strong production rebound and project that December will be our highest production month in the fourth quarter, absent any adverse weather events. Overall, we feel very good about our performance to date and our projected production momentum as we enter 2016. It is important to note that we are in the process of developing our initial 2016 plan, as well as our five-year plan. This will put us in a better position to provide more thoughts around next year's production and capital outlook on our third quarter call. I'd like to now discuss some of our key operational areas and activity plans for the remainder of the year. During the second quarter, we operated an average of 34 rigs company-wide with 15 rigs in North America, 12 rigs in Egypt, and 7 rigs in the North Sea. In North America, we completed 63 gross operated wells during the quarter, which was a 51% decrease from the first quarter. Despite the significant drop in completion activity, our onshore North American production grew by 9300 barrels of oil equivalent per day sequentially. The majority of this increase was driven by the Permian Basin where we delivered strong new well results and experienced a bounce back from the tough first quarter weather conditions and shut-ins. We consider our Permian Basin to be advantaged in this current environment due to a relatively low base decline rate of approximately 22%. This is aided by our Central Basin Platform and North West Shelf assets, which represent approximately half of our gross production from the Permian and have a decline rate of roughly 14%. We have several production enhancement initiatives under way, including various water flood activities, and ESP installations that serve to protect our base decline rate at a fairly low capital cost. In the Delaware Basin, we saw a strong oil performance in the Pecos Bend area and generated positive results from our delineation and target testing. Drilling at our 7-well Osprey pad confirmed good performance from 660 foot down-spaced wells and also helped to confirm an additional landing zone in the third Bone Spring formation, which appears to be performing as well as our primary target in the third Bone Spring. In the Waha area, we placed our first two wells online during the last week of June. Initial results look encouraging, and we will update you on this area next quarter. At our North American update on November 20 of last year, we shared an average well cost for the Delaware Basin of $8 million. Today, we are drilling those wells in the mid to upper $5 million range, and our target is to get down closer to $5 million, which would represent an approximate 35% reduction from November 20. In the Midland Basin, we ran three rigs during the second quarter, with one in our Wildfire area, one in Powell-Miller, and one at Azalea. Our first four wells at Wildfire in Midland County showed strong 30-day average IP rates of 1,090 BOEs per day in the middle Wolfcamp. We plan to complete an additional eight wells in this area during the second half of the year, three of which will be drilled to the lower Spraberry. During the second half of the year, we will be completing 11 wells in the Powell-Miller and Azalea areas, which we anticipate will contribute solid results. Lastly, at Barnhart, we brought on four wells during the quarter, which exhibited some of the strongest results we have seen to-date across the field. In the Central Basin Platform and North West Shelf, we see numerous opportunities across our acreage position to continue drilling wells with high rates of return. We are currently focusing on areas such as the Cedar Lake Yeso play and the Seth Campbell Clearfork play, which are highlighted in our quarterly supplement. These plays offer relatively inexpensive drilling and completion cost, thus yielding very attractive rates of return in today's low commodity price environment. Turning to the Eagle Ford. During the second quarter, we made important progress in optimizing our completion techniques and significantly improving flow rates on the four new wells we brought online. Our current focus in the Eagle Ford has primarily been in Area A at Ferguson Crossing in Brazos County. During the second quarter, we brought online four key wells, two on our Walker pad and two on our Rae pad. The 30-day average IP of the two Walker wells was 1,935 barrels of oil equivalent per day, which significantly exceeds Apache's Area A type curve and represents our highest flow rates in the Eagle Ford play to-date. Based on these results, we plan to add a rig back into the Eagle Ford at Ferguson Crossing, during the second half of 2015, which will help us continue optimization and delineation of this highly prospective area. In the Midcontinent, which was formerly our Central region, production was down 7% sequentially from the first quarter, as a result of natural declines and reduced activity. During the second quarter, we completed only six wells compared to 24 wells during the first quarter. Apache's primary focus in the Midcontinent is delineating our Woodford/SCOOP acreage and continued testing of the Canyon Lime play. In the Woodford, we have one rig drilling and delineating our 50,000 plus net acres, primarily in Grady County, and we plan to add another rig in the fourth quarter of 2015. We recently brought online our first Woodford well of 2015, with very good initial results. The Truman 28-6-6 #1H, a 16-stage 4,400 foot lateral, tested at a peak rate of 392 barrels of oil and 6.9 million cubic feet of gas per day on a 20/64-inch choke. We plan to complete at least three more Woodford wells this year, including a two-well pad that is waiting on completion and another well which is currently drilling. In Canada, we had very little drilling and completion activity during the quarter. However, our production declined less than expected due to minimal weather-related downtime. The next significant activity scheduled is the completion of our seven-well Duvernay pad in the fourth quarter of this year. Turning to our international operations. In Egypt, Apache's continued exploration and development success is driving better-than-expected production volumes year-to-date. As noted in our press release, we experienced positive results during the quarter at our Ptah and Berenice oil fields in the Faghur Basin. We now have nine wells online at these new fields producing a combined gross rate of more than 23,000 barrels of oil equivalent per day. During the second quarter, the Ptah-5X exploration well appraised the northeast flank of the Ptah field and is flowing at a restricted rate of 3,000 barrels of oil per day. We also drilled and completed our first development well, which flowed at a 30-day average IP rate of more than 3,000 barrels of oil per day. Apache has five wells drilled in the Ptah field, all of which are currently producing. In the Berenice field, Apache drilled an additional development well during the quarter that logged 93 feet of pay and is now online. This marks the fifth well drilled to-date in the Berenice field, four of which are currently producing. Our current 2P reserve estimate for the Ptah and Berenice fields is approximately 50 million barrels, which we believe will require a total of 20 wells to 25 wells to fully develop. During the quarter, Apache achieved an exploration success rate in Egypt of 78%, which is significantly above the company's historical average. In the North Sea, two seasonal platform maintenance turnarounds reduced output by approximately 3,300 barrels of oil equivalent per day, but production still exceeded our internal plan. We anticipate a strong second half of the year, which has minimal scheduled maintenance downtime. As a result, we now project that pro forma North Sea production will be flat year-over-year, compared to our previous expectation of down slightly. In the Beryl field area, we made a significant exploration discovery with the 9/19 B/K well, which we refer to as the K prospect. The well encountered 235 feet of net pay in two Jurassic-age sandstone reservoirs. Apache's pre-drill mean unrisked reserve estimate for the K prospect was approximately 7 million barrels of oil equivalent and, given our initial test results, we believe recoverable reserves are likely to significantly exceed this estimate. The field will be developed as a subsea tie-back into existing infrastructure. The K prospect well was our first exploration well and only our tenth well drilled in the Beryl area since acquiring the field in 2011. We look forward to demonstrating the future reserve and production growth potential at Beryl. Also in the Beryl area, Apache brought its first subsea development well on production at the Nevis Central field. The S67 well encountered 114 feet of net pay and achieved an initial production rate of approximately 11,500 barrels of oil equivalent per day. Egypt and the North Sea continued to provide excellent diversification to the Apache portfolio and reduced the overall volatility of our cash flow profile in this low oil price environment. Returns at $50 oil in these regions are very economic. And we plan to provide more detail around the portfolio depth and quality of these two businesses in the future. At the beginning of 2015, we established a conservative budget that assumed a $50 WTI and $53 Brent oil prices. Although prices came in above these levels in the first half of the year, the recent retreat in oil prices underscores the importance of our conservative budget and capital spending approach. As we enter the back half of 2015, Apache is achieving efficiency gains and cost reductions that are enabling us to increase our planned drilling and completion activities. In North America, we are now planning to run an average of 16 rigs in the second half of the year, 13 rigs of which will be in the Permian Basin, one will be in the Eagle Ford, and two will be drilling in the Woodford/SCOOP play. We now expect to reach total depth on approximately 40 wells to 50 more wells than our original 2015 plan, and to complete approximately 30 wells to 35 more wells than originally planned. Internationally, we plan to average 17 rigs in the second half of the year, which is down slightly from second quarter levels. However, we plan to complete approximately 15 wells to 20 more wells than previously planned, most of which are in Egypt. This incremental activity will positively impact our production trajectory as we enter 2016, while having only a minimal impact on our full-year 2015 production volumes. In conjunction with this activity increase, we are tightening our capital expenditure guidance range to between $3.6 billion and $3.9 billion. Apache is staying within our dramatically reduced capital spending budget, while at the same time exceeding our production goals for the year. Our strategy in this low oil and gas price environment is to continue working on our cost structure, continue investing in acreage and 3D seismic, and continue key play delineation and target testing such that when it is time to ramp up our drilling program, we will be doing so in the most efficient manner possible, which will maximize program rates of return and net present value. To sum up, we made very good progress in the second quarter. We completed our major asset sales and put our balance sheet in excellent shape. We reduced our drilling and completion program to levels that are appropriately aligned with the current commodity price environment. We realigned our regional operation structure to drive greater efficiency and technical collaboration. We made significant reductions in our run rate G&A and overhead costs. And we delivered strong production both domestically and internationally, which resulted in an increase to our 2015 guidance. And with that, I would like to turn the call over to Steve Riney. Stephen J. Riney - Chief Financial Officer & Executive Vice President: Thank you, John, and good afternoon. As John said, we had a very good first half 2015 and we are very well positioned, even if the current low oil price environment persists. I would like to take some time to highlight the financial positioning of Apache and what we have accomplished in terms of driving down our cost structure consistent with the current price environment, utilizing divestment proceeds to reduce debt and to improve near-term liquidity, extending our credit facility to ensure liquidity through to June 2020, and aggressively adjusting our activity level to live within our means on an ongoing cash flow basis. But first, let me highlight the second quarter financial results. As noted in this morning's press release, Apache reported a GAAP loss of $5.6 billion or $14.83 per common share. This includes after-tax charges for a ceiling-test impairment of $3.7 billion, as well as $1.9 billion of other items, mostly after-tax losses and tax expense associated with the company's assets sold during the quarter. Our earnings for the quarter adjusted for these items were $82 million or $0.22 per share. As in the prior two quarters, we experienced a ceiling-test impairment in second quarter resulting from the continuing low price environment. Under full cost accounting, our upstream assets are carried at historical costs. Each quarter we compare this cost basis to a PV-10 value, calculated using trailing 12-month average oil and gas prices, held flat into perpetuity. To the extent the net book value exceeds the PV-10 valuation, the result is a ceiling-test write-down. We expect further ceiling-test impairments in the second half of 2015. As outlined in more detail in our 10-Q, based on June 30, 2015 forward strip prices. For the remainder of this year, we would expect to incur an additional $3.5 billion post-tax impairment. One notable impact of the ceiling-test impairments on our financial results going forward will be a reduction to our unit DD&A rate. For example, our DD&A per BOE during the second quarter was 20% lower than it otherwise would have been as a result of impairments taken in 4Q 2014 and 1Q 2015. Forward-looking impacts are uncertain as they will depend on many factors beyond just ongoing impairments. Let me now turn to costs. The following oil price environment and subsequent activity reduction across the industry has resulted in significant downward pressure on service costs, and we are generally seeing lower trends in most major cost categories. More specifically for Apache, much of the improvement in our cost structure is being driven by our belief that we should prepare ourselves for an extended period of lower prices. Accordingly, we have put considerable effort into poring over every aspect of our cost structure. Since the end of 2014, we have reduced head count by approximately 20%, consolidated certain regional offices, and streamlined the organizational structure. These actions are generating significant savings in our overhead cost structure. The measurement of overhead costs can be complex from an accounting perspective. A good proxy for our overhead cost structure is the gross cash spend for everything above the field. At the end of 2014, these costs were running approximately $1 billion annually. The combined effect of our portfolio changes and extensive efficiency efforts across the organization will bring our current run rate to below $750 million. Our goal is to enter 2016 at a run rate around $700 million. These overhead cost show up in our financial statements in various places. On average, about 20% typically appears in lease operating expense, 45% in expensed G&A, and 35% in capitalized G&A. Thus, these savings will manifest in many different ways. The bottom line, though, is it represents cash savings of about $300 million per year, which can now be better utilized to create shareholder value. On the lease operating expense side, our second quarter LOE was just over $9 per BOE, which is 13% lower than second quarter 2014. As John indicated, we believe in this price environment there will be continued downward pressure on all costs, and this includes lease operating expenses. Next, I would like to make a few comments regarding our balance sheet position and liquidity. While we've certainly accomplished a lot in terms of focusing our portfolio, we have also improved our overall financial strength. In particular, we have reduced debt levels, extended our credit facilities and we are now eliminating certain nearer-term debt maturities. Our proceeds from divestments enabled us to pay off $2.7 billion of short-term debt in the second quarter. We ended the quarter with long-term debt of $9.7 billion, and nearly $3 billion of cash, and have recently initiated steps to pay off $900 million of outstanding 2017 bonds. Following this, we will have no long-term debt maturing prior to 2018. As mentioned in our 1Q call, the sale of our foreign assets and the repatriation of the proceeds triggered a U.S. income tax payable of $560 million. Actual cash payment of this liability will occur in the second half of 2015, so I would like to point out that our current net debt of $6.7 billion should be considered as being closer to $7.3 billion. As of June 30, 2015, Apache held access to an undrawn commercial paper program backed by our $3.5 billion credit facility, which was recently extended through to June 2020. Combined with our current cash position and the maturity profile of our long-term debt, our liquidity is in very good shape. Having established this position, we are also working hard to protect it. As John has indicated many times, we are aggressively working to live within our means on a cash-flow basis. Obviously that was a difficult task for the first half of the year as prices declined rapidly and activity took time to ramp down. John spoke previously about our activity level for the second half of 2015. We are positioning our second half exploration and development activity at a pace that, if continued, would target cash flow neutrality for 2016. Our goal has been and continues to be to live within our means on a cash-flow basis. We have taken significant actions to achieve this and it has proven to be the prudent course. However, we want to balance these efforts with continued investment in an inventory of high quality opportunities that still work in this price environment. We have made great strides to position the company to be successful in a low-commodity-price environment. We knew that if we could be successful at $50 oil, we would certainly be successful at higher prices. The company is in a solid foundation with a healthy balance sheet, substantial liquidity and improving cost structure commensurate with the price environment, and a capital activity plan to live within our means as we enter 2016. We will remain opportunistic, but highly disciplined in the manner that we allocate capital in this challenging environment. I look forward to a successful second half of the year. And we'll now turn the call over to the operator for Q&A.

Our first question comes from the line of Dave Tameron of Wells Fargo. David R. Tameron - Wells Fargo Securities LLC: Hi. Congrats on a good quarter. John, how do you think about the price level here when you're at $45, versus $50, versus $40? And at what level would you see yourselves going the other way and pulling back a little bit? John J. Christmann - President, Chief Executive Officer & Director: Well, Dave, I mean, I think the first thing is we took a more conservative approach earlier in the year when we kind of carved out a $50 budget back in February. So it's put us in a position where we've been counting the – trying to get our heads around what $50 means and working hard on our cost structure. You know, I think clearly with the – when you look at the activity increase, while we're adding back three rigs in North America, it's really going to be just one rig increase over what we ran in the second quarter. So we're trying to kind of streamline our activity with where we envision things would be in that price range, as you mentioned. I think the good news is we've got flexibility and as we're working on our plans for 2016 right now, we'll work on it even harder, but we've got flexibility to move up or down from this point. So the first thing was, was to kind of synchronize to this price environment and we'll maintain flexibility that we could ratchet down or ratchet up a little bit if necessary. David R. Tameron - Wells Fargo Securities LLC: Okay. And then just as a follow-up circling back to 2016, you mentioned within cash flow, you could show some, I think you said modest growth or you keep your production level, I guess, where it's at. Are you assuming the current strip? And then kind of, what framework, what metrics should we think about for 2016? Is it going to be within cash flow? Is that the driver there? Can you just talk more about that? John J. Christmann - President, Chief Executive Officer & Director: Yeah, I think that first of all, we've got a deep inventory, projects that work at low prices, so we feel good about the inventory. I think the key is, we do and we've said from the get-go this year we had a heavy outspend Q1. I think we did an excellent job of getting in line in Q2. So as we start to think about 2016, we do want to be in line within cash flow and kind of living within our means. We're working through our planning process right now in great detail, and as that becomes a little bit more clear and we think about it, as we work through it, we'll be able to give a little bit more color on the next call. But in general, I think the important thing is, we've proven what we can do this year on a much lower decreased CapEx budget. We've proven that our costs – our dollars are going further. And I think with the initiatives we have and the way the cost structure, the G&A, we're going to be able to do more with even less capital in 2016 if necessary. David R. Tameron - Wells Fargo Securities LLC: All right. Thank you.

And our next question comes from the line of Leo Mariani of RBC. Leo Mariani - RBC Capital Markets LLC: Hey, guys. Just, I wanted to see if I can get some comments on the current kind of M&A market. I know you guys had talked previously in the year about trying to grab more acreage and looking at acquisition opportunities. John J. Christmann - President, Chief Executive Officer & Director: Leo, two things. Number one, I think when you look at the acreage market out there, there's stuff off the beaten path that I think we'd be interested in. And we don't budget for that, but we're clearly always looking for things that work in low price environment. I think when you step back and look at the bigger picture M&A market right now, some of the price decks that have been used to justify some of those transactions I think have been relatively high. And I think if you go back to our portfolio, at $80 we've got a lot of inventory that works. And so from my standpoint, we would look at things incrementally. The good news is we've taken the steps to put our balance sheet in great shape, so we've got capacity, we've got a credit facility in place and we've aligned our cost structure and our activity levels to current so we've got lots of flexibility. And I think the key is, is we've got a good portfolio and it would have to be something that made sense incrementally to what we have in terms of what we could add. So I think in general, the market's been a little pricey. These last transactions have been using a higher deck than I think what's bearing out right now. Leo Mariani - RBC Capital Markets LLC: Okay. And I guess just thinking about your most resilient assets and where you have the deeper inventory in the low oil price environment here, should we continue to think Egypt and Permian get the lion's share of capital as you work your way into 2016? John J. Christmann - President, Chief Executive Officer & Director: As we look at the back half of the year, we'll run approximately 16 rigs in North America. 13 rigs of those will be in the Permian. We'll have five in the Delaware, like we maintained all year. You'll have the other eight in our Midland Basin and Central Basin Platform/Northwest Shelf. You'll see us sprinkle a few more rigs into the Midland Basin second half of the year. You'll also see one rigs to two rigs from us in the Woodford, which is working quite well in the low price environment. And with the results that we mentioned on our Walker wells in the Eagle Ford, we're pretty excited about that as well. So when I look at North America, you'll see most of the work being in the Permian. Internationally, quite frankly, both Egypt and the North Sea compete very well and have great rates of return in terms of those projects. So we've scaled back there this year like we did in all the other areas, but we've got good inventory there. Look at what we're doing with Ptah and Berenice. I mean, we've now got 10 wells on, producing more than 23,000 barrels a day and that's constrained with facilities, there's room for that number to go higher and it's going higher as we speak. So I think we've got a lot of inventory at low prices that's going to keep us busy for a long time. Leo Mariani - RBC Capital Markets LLC: Okay. Thanks, guys.

And our next question comes from the line of Brian Singer of Goldman Sachs. Brian A. Singer - Goldman Sachs & Co.: Thank you. Good afternoon. I wanted to focus on the Eagle Ford that you've spoken in the past about, some geologic complexities in this part of the Eagle Ford. With the results that you're reporting in Area A, do you feel like you've cracked a code there? Is there a code to be cracked? Can you talk to the well costs and where this play stands and ranks relative to some of your other opportunities? John J. Christmann - President, Chief Executive Officer & Director: Yeah, Brian. I mean, it is a little more complex. You've got, as I've mentioned in the past, your geologic setting is critical as well as your fluid. I mean, you've got everything from a dry gas to a black oil. You've got a wet gas, a volatile oil in there. There is higher clay content. It's a little thinner. So I think one of the key areas we have been able to make some progress on our completion procedures. And the latest four wells we brought on, the two Walkers and the two Raes, I think if you look at the two Walker wells, those wells in a little over three months have produced 83,000 barrels and 80,000 barrels of just oil alone. So we're pretty excited about those results. Well costs are in the low $7 million range and we feel really good about the economics. So, I mean, I think we've definitely made some progress. We're still working spacing. We will put a rig back to work there and continue to highlight the fairway there. But a big breakthrough for us technically on the fracking side. Brian A. Singer - Goldman Sachs & Co.: Great. Thanks. And then I wanted to shift to the Midland Basin and the Wildfire area in Midland County is an area you reported some good results. Can you talk about the running room there at Wildfire? And then if we look outside Barnhart at your Midland position, is this the area that has the greatest running room that you're most excited about, or would you highlight other parts of the portfolio within the Midland Basin? John J. Christmann - President, Chief Executive Officer & Director: If you go back, the best place to go back and look at our portfolio there would be our November 20 update. We kind of circled the four counties. We showed around 200,000 acres as I recall. In addition to Wildfire, we've got our Powell-Miller area, we've got our Azalea area. We've got a lot of running room in there. We've really just had a rig or two working. So we're very encouraged. It's an area we've got room to add. If you go back to our November update, we were planning to run eight to ten rigs. We'll probably have two to four or five rigs in there roughly this back half of this year. So we've got a lot of running room and we're very encouraged by the results. We're also taking a pretty measured approach on our flow backs. We've been experimenting with the frac procedures. We've taken some of those up to 3,000 pounds per foot. So we're making headway in there and feel good about the inventory. Brian A. Singer - Goldman Sachs & Co.: Great.

And our next question comes from the line of John Freeman of Raymond James. John A. Freeman - Raymond James & Associates, Inc.: Good afternoon. Just some questions on the backlog that you all laid out. You said at the end of the year you'd have roughly 80 to 100 drilled uncompleted wells. I think you ended last year around 200 wells. And I'm just trying to get a sense, would you consider kind of a normal backlog at somewhere around two wells to three wells per rig? John J. Christmann - President, Chief Executive Officer & Director: That would be a little high. What we'd say a normal backlog. You know, when we were blowing and going, we were down to maybe 1.5 wells per rig. Some of the pads, you'll get a few more. If you go back to, we actually came into 2015 with 216 wells in backlog, and I think about 45 wells of those were verticals. So when you look at our horizontal backlog, it was in the 160 to 170 range. I think the number was 166 wells. We've kind of guided to 80 to 100. And that number may creep up, but we feel good about that range. So it's going to be a little higher, and that's just a function of still keeping an eye on prices and keeping a handle on our CapEx spend in this low price environment. John A. Freeman - Raymond James & Associates, Inc.: Okay. And then just my one follow up along those same lines. I was a little surprised in the Permian that uncompleted backlog on the horizontal wells, it basically stayed flat despite going from 15 rigs to 10 rigs. Is there anything unusual that maybe caused that? John J. Christmann - President, Chief Executive Officer & Director: No, when we backed off for the first part of the year, the completion costs hadn't come down yet. And right now we've currently got two frac crews in the northern portion of that and we've got two in the south, and we're just going at it very methodically. And so there's clearly room to accelerate, but we don't see any reason. And obviously in hindsight, with this recent drop in prices, we've been prudent not to do that. John A. Freeman - Raymond James & Associates, Inc.: Great. Thanks, John. Good quarter. John J. Christmann - President, Chief Executive Officer & Director: Thank you.

Our next question comes from the line of John Herrlin of Société Générale. John P. Herrlin - SG Americas Securities LLC: Yeah, hey, John. In your ops report regarding the Delaware, you talked about doing different completions at Pecos Bend and Waha to eliminate water. What are you doing and how much could that save you on a cost basis going forward? John J. Christmann - President, Chief Executive Officer & Director: Well, John, one of the things that's not talked about a lot, we hear about the oil rates, we hear about the gas rates in the Delaware, we don't get a lot from other companies on the water rates. These wells are high pressure. The Delaware is characterized by very high pressure and you will get some very, very high water rates. And so we've been going in and really understanding our geology, using our 3D seismic, trying to understand how we want to complete these and buffer around areas where we can eliminate some of the water production. If we can take those water cuts down just a few percentage points, it makes a big difference, one on your cost, your LOE, because you're having to handle the water, not to mention your ultimate recoveries and that sort of thing. So we're trying to move the needle and produce these wells at higher ultimate oil cuts, and we're really trying to understand the geologic system and the framework to how to complete them. John P. Herrlin - SG Americas Securities LLC: Great. Then in terms of restructuring your organization, where are your technical operational centers is based? I mean, you have one obviously in San Antonio, but where else? John J. Christmann - President, Chief Executive Officer & Director: Well, we've got an unconventional center in San Antonio. We've got our regions now. We've maintained a really three super regions as we have called them. Permian we have a big presence out there, which is handling our Midland Basin and Central Basin Platform/North West Shelf, our San Antonio has our Delaware Basin and our unconventional technology center. In the Houston region now, we've consolidated by closing Tulsa and collapsed our central region properties in with our Gulf Coast and actually Canada now reports into that. And we also have a technology center here in Houston that does a lot of support around the world on kind of our EP technology. So not to mention our Corporate Reservoir Engineering Group here, our enhanced recovery, and some other things. So really Houston, San Antonio, and then our regional offices. And then our international, we still maintain our presence in Cairo for Egypt and Aberdeen for the North Sea. John P. Herrlin - SG Americas Securities LLC: Great. Thanks. John J. Christmann - President, Chief Executive Officer & Director: Thank you

Our next question comes from the line of Doug Leggate of Bank of America. Doug Leggate - Bank of America Merrill Lynch: Hi, John. John J. Christmann - President, Chief Executive Officer & Director: Hi, Doug. Doug Leggate - Bank of America Merrill Lynch: We'll go with something more exotic than normal, but that's fine. A couple questions, if I may. First of all, if I could jump back to the Eagle Ford, the wells results continue to be pretty strong there. I just wonder if you could help us understand the relative attractiveness of pulling wells or pulling rigs out of the Eagle Ford in favor of some of the other areas as opposed to continuing with Eagle Ford activity. And in your answer maybe you could hit the HBP question as well, if you've got any issues there. And I've got a follow-up, please. John J. Christmann - President, Chief Executive Officer & Director: Well, I mean I think the important thing there is we had to really focus in on the completion procedures and the geologic settings. And so actually backing down those rigs was a blessing for us. It's let us really spend some time. We've had a frac crew out there and we've done some work, and like I said, the last four wells we reported, we've made some significant progress in understanding the complexities geologically and what's going on in the Eagle Ford. When we start to look at the numbers today, it competes extremely well, which is why we're going to put a rig back in there. But we have got Woodford that competes very well as well as Permian, as well as some of our other areas. So we've got a deep inventory and a lot of areas competing for capital. And we're glad to be able to put it back to work in the Eagle Ford. Doug Leggate - Bank of America Merrill Lynch: Are there any HBP issues in the Eagle Ford, John, that we should be aware of? John J. Christmann - President, Chief Executive Officer & Director: I would say the acreage that we want HBP, will have HBP. So clearly the fair way there is we're understanding that. I mentioned that it is not a blanket fluid system, and so it's important to understand your system. But the acreage, we're not worried about losing acreage that we'd want to hang onto. Doug Leggate - Bank of America Merrill Lynch: Okay. Thank you. My follow up is on (43:43).

And our next question comes from the line of Pearce Hammond of Simmons & Company. Pearce Wheless Hammond - Simmons & Company International: Good afternoon, John. Thank you for taking my questions. John J. Christmann - President, Chief Executive Officer & Director: You're welcome, Pearce. Pearce Wheless Hammond - Simmons & Company International: The first question is looking at your portfolio, I know this is hard to answer, but what do you think your base decline percentage is as kind of a whole company? And what do you think the maintenance CapEx is for the company to keep production flat? John J. Christmann - President, Chief Executive Officer & Director: Well, I mean, if you look at our overall portfolio decline, we're in the 25% range. I mean, we highlighted in my prepared remarks today our Permian is around 22%. It's helped by our Central Basin Platform/North West Shelf. We're working through our planning process right now. And the one thing I would say is that if you look at 2015 relative to 2014, we now are going to show growth in North America on a significantly reduced CapEx program, but we're not in a position to give you guidance in terms of what would be "maintenance" in terms of – if you're asking maintaining flat production or that sort of thing. Pearce Wheless Hammond - Simmons & Company International: Okay. Thank you. And then my follow-up: service costs, you've done a great job of bringing those down. Looking at the Ford strip, it sounds like your expectation as service costs move lower, but a lot of the service companies right now negative cash margin. Do you think that service costs continuing to come down is realistic at this point? John J. Christmann - President, Chief Executive Officer & Director: Well, I mean, I think there's two things. Number one, we were probably the earliest out there on the service side, and if you look at our savings today to the 25%, there's probably more than half of that is operational things and logistics and things we've done to get better. My conversations with the service companies have moved to, this has never been about margin, we're just asking them, they've got to make the margin to have a healthy business. It's been, though, we've got to sit down and figure out how to work together and how they get smarter, and how we can take costs out of the system that don't need to be passed through. So bottom-line on, it is in a low price environment, it doesn't matter if you're operating at negative margin, you're going to have to find a way to get more creative and get your cost structure down. And I think it's a matter of us rolling up our sleeves, working with them, and finding creative ways to take costs out of the system, which is what we do and that's what's we'll – that's what's happening right now across the industry, and that's what we'll continue to do in the future. I mean, when you look at the numbers second quarter, the market had pretty well baked in recovery into the mid-$60s on oil price back half of the year. And clearly that's not – it doesn't look like that's the case, and so as a result, the cost side's going to have to come down and we're going to have to work together and get in the trenches and figure out how to lower them. Pearce Wheless Hammond - Simmons & Company International: Thank you.

And our next question comes from the line of Bob Brackett of Sanford Bernstein. Bob A. Brackett - Sanford C. Bernstein & Co. LLC: Yeah, a question on your realizations in the international assets. North Sea and Egypt looked pretty strong. Is that a seasonal effect, or what's driving that? John J. Christmann - President, Chief Executive Officer & Director: Well, I don't know if Steve, wants to add something. I think it's just a function of having Brent pricing and predominantly oil-driven revenues. And Tom Voytovich has another comment too. Thomas E. Voytovich - EVP-International & Offshore Region: We get a pretty good gas price in the North Sea too, and our gas rates are up this year, so that's contributing to it as well. Bob A. Brackett - Sanford C. Bernstein & Co. LLC: Okay. Great. And another would be, what's your exit rate for December 31 of this year? Do you have a sense of what that might be? John J. Christmann - President, Chief Executive Officer & Director: Well, what we said is, if you look at our fourth quarter, December's going to be our highest month. So we're not in a position to give that number at this point. If you take our North American guidance, we gave numbers in terms of we got actuals first quarter, second quarter, 307,000 BOEs, 317,000 BOEs, gets you to 312,000 BOEs for the first half average. Our midpoint of our guidance range would be 307,000 BOE for the year, which means you average 302,000 BOE the back half. We've said third quarter is going to be under that and fourth quarter we're going to see a nice rebound, so and I think there's room in those numbers. So with that, it's about all I'll say at this point. And we guided to kind of 164,000 BOE to 168,000 BOE on our international. And it's going to be probably relatively flat.

Our next question comes from the line of Michael Hall of Heikkinen Energy. Michael Anthony Hall - Heikkinen Energy Advisors: Thanks. Good morning. I guess I wanted to follow-up a little bit on your comment about keeping production relatively stable within cash flow for 2016. Is that intended to mean stable year-on-year 2015 – or 2016 versus 2015, or stable from the exit rate in 2015? John J. Christmann - President, Chief Executive Officer & Director: I mean that clearly we're not giving full color. I think what we've looked at and if you look at how we've been able to stretch capital this year, with where our cost structures are and the quality of our inventory, we feel like we can be relatively stable, and it would be more year-over-year. But we'll come out with something more definitive at the appropriate time. Michael Anthony Hall - Heikkinen Energy Advisors: Okay. Great. And then as a follow-up, you've done some great jobs on the overhead cost reductions. I appreciate all that extra granularity. Just curious, as you guys are looking at 2016 and beyond, you had a much larger rig count obviously, and activity level in 2015 – or sorry, 2014. What sort of activity level are you gearing the company for, or sizing the company for from an overhead perspective? I don't know if you put that in terms of rigs or what, but I'm just kind of trying to think through if there are more overhead reductions to come in 2016, or is it kind of already been done, and at what sort of activity level can it support? John J. Christmann - President, Chief Executive Officer & Director: Well, we've been gearing our cost structure to a $50 price environment. The thing I would say though is, with the efficiencies and things we're doing today, it will not take the number of rigs in the future in a higher price environment, so I mean, I think we've got – we've set this thing up to where it's kind of an accordion that can take on a lot more activity, but we tried to gear it towards the low price environment because what I can't do is be wasting dollars in terms of G&A that I should be putting in the ground that can be generating results. And so we've tried to get real frugal on where we need to be, and then in typical Apache fashion, we feel pretty good. We've got a footprint in place that will expand fairly significantly because I think what we've done this year has been really healthy. We needed – as Apache and quite frankly as an industry – to look at our overall cost structure, even in a high-price environment. And we feel real good about where we are and how we've geared it and that we're definitely prepared for lower prices.

Our next question comes from the line of Charles Meade of Johnson Rice. Charles A. Meade - Johnson Rice & Co. LLC: Yes. Good afternoon, John, to you, and your team there. If I could go back to a question that you touched on before, in your operations report, you mentioned that you had 70 horizontal wells in the Permian drilled and completed here at mid-year. Does that – how does that interact? Or how does that drilled and completed count progress as we go through the back half of the year? I guess what I'm really after is, are you really planning on working that down in late 3Q, early 4Q. And that's why we're going to see the bump-up? John J. Christmann - President, Chief Executive Officer & Director: I'm going to let Tim Sullivan, who I have not let him handle a question yet. But I'll let Tim, jump in and talk through those numbers a little bit for you. Timothy J. Sullivan - Senior Vice President-Operations Support: Okay. For the Permian Basin, for our drilled and uncompleted wells, we're at about 40 right now. And as we work through the back half of the year and with our rig activity, we're going to exit the year at down to about 25 to 30 throughout the year, at the end of the year. Charles A. Meade - Johnson Rice & Co. LLC: Got it. And you said you're 40 – you're at 40 right now, you said? Timothy J. Sullivan - Senior Vice President-Operations Support: In the Permian Basin... John J. Christmann - President, Chief Executive Officer & Director: About 45. We're at 45. Timothy J. Sullivan - Senior Vice President-Operations Support: We're at 45, right now. Charles A. Meade - Johnson Rice & Co. LLC: Okay. Got it. All right. Thank you for that, Tim. And then if I could go back to some of Steve's comments... John J. Christmann - President, Chief Executive Officer & Director: Let me back up there. We're at, like, 70 right now. We'll end the year at about 45 with total Permian. Charles A. Meade - Johnson Rice & Co. LLC: Got it. And so that includes – when you say total Permian, that's vertical and horizontal? Or what's the distinction there? John J. Christmann - President, Chief Executive Officer & Director: Yes. Charles A. Meade - Johnson Rice & Co. LLC: Okay. Okay. John J. Christmann - President, Chief Executive Officer & Director: 43 – it's going to be 50. We're roughly – we're projecting about 52, if you add verticals and horizontals for combined Permian. Charles A. Meade - Johnson Rice & Co. LLC: Okay. Thank you. Thank you, John. And then shifting over to more of balance sheet philosophy sort of question, and this might be for Steve, Steve, I appreciate you giving us the forecast of what's going to happen with the balance sheet here in the back half of the year, and I know that all of you guys there have worked really hard to put the balance sheet in the good shape it's in right now. But philosophically as you – you talked about – you're working on a – you're working in a $50 world, philosophically, what kind of constraints do you want to keep on your balance sheet, whether it's in terms of debt-to-EBITDA or some other relevant metric? And what are the circumstances that you'd have to see that would make either one lever up? Or use your balance sheet for a transaction? Stephen J. Riney - Chief Financial Officer & Executive Vice President: Yeah, Charles. I think at this point and in this environment as of today, I think that the balance sheet in the shape that we've got it right now is probably pretty good. And I'd prefer – my philosophy would be, at this point in time we just keep it where it is. We may look at paying down some further debt. We'll look at that as we go through the second half, look at what the price environment is doing. And we get a really solid view of 2016 as we round out the planning. But right now I think the best thing to do is for us to sit on the balance sheet that we have. It's a good strong one. It's highly liquid and it's one that would allow us to be opportunistic if we felt like the compelling opportunity came along. I think John hit the nail on the head a few minutes ago, and that is that the opportunities that we've seen and we've seen some other people jump at, we wouldn't have put those under the column called, compelling, at this point in time. And it's just not something that we would be willing to sacrifice the balance sheet for in any material way.

And our next question comes from the line of Mike Kelly of Global Hunter Securities. Michael Kelly, CFA - Global Hunter Securities: Hi, guys. I was hoping you could maybe give us a bit of a preview of what's to come with this capital allocation review that you're going to unveil next quarter. And I'm really trying to get a sense of whether we should expect potential major strategy shift with this, the portfolio get shaken up quite a bit? Or is this more modest alterations around the edges? Thanks. John J. Christmann - President, Chief Executive Officer & Director: Well, I would say in general, if you look at where we are today, you look at the rig count we're running and you look at the price environment, I don't have a crystal ball out there what's going to look like in a couple of months, but it's probably pretty similar, I mean we've done a good job this year. We're really drilling the things we want to drill. We don't have an area where we are in what I'd call development mode, with the exception of maybe our Ptah and Berenice area in Egypt. So as you start to think about going forward, I think capital is going to go to the best places, but we've got it in those projects that are working the best right now. And as you think about the incremental capital back half of the year, we're putting a little bit back to work in the Eagle Ford. We're putting a little bit back to work in the Woodford and obviously in the Permian in conjunction with our international. Michael Kelly, CFA - Global Hunter Securities: Okay. Great. If I go over to the Permian and the Delaware. It was good to hear that the Delaware well cost down 35%. If you go back to that November 20 presentation, you guys had 100% IRRs out there but a much higher oil price. Just wondering if you could talk about kind of mark-to-market today, lower costs, lower oil price, what project return you could be looking at right now? And then just the scale of the inventory there, the opportunity set that's really core Delaware. Thanks. John J. Christmann - President, Chief Executive Officer & Director: I'll let Tim Sullivan jump in on this one. Timothy J. Sullivan - Senior Vice President-Operations Support: Yeah, with the well costs we're seeing out there, about $5.8 million. And the IPs that we're currently seeing, we're well above our type curves. And even at the $50 oil price, we're seeing above 40% rate of returns out of the Pecos Bend area.

And our next question comes from the line of James Sullivan of Alembic Global Advisors. James Sullivan - Alembic Global Advisors LLC: Hey, guys. Good afternoon. Just sticking with the Permian for a second. There was a comment in the prepared remarks about a second landing zone in the third Bone Spring. Is that an option for stack development? And can you speak to how prevalent that appears to be? It may be early days on it, but any detail you might have. John J. Christmann - President, Chief Executive Officer & Director: Right now we're looking at them as individual zones, just another well that can be drilled from the pads. And the good news is we've got a full pad in and they're pretty compelling. And we're not in communication. And the second zone is performing really in line with the primary zone. James Sullivan - Alembic Global Advisors LLC: Okay. Sounds great. So just maybe pulling back a little bit on the question of science work. And I did notice you guys pulled the rig out of Canyon. That might have been part of the plan that you guys were working on. But just in terms of high-grading the portfolio, how do you guys manage the balance between trying to allocate capital to areas that are going to be sure bets in terms of delivering program rate of return cash flows and doing more experimental work like in the Canyon and elsewhere, where you've got stuff you don't know yet and maybe costs that needs to come down, just philosophically? John J. Christmann - President, Chief Executive Officer & Director: Well, you've got to look at the areas where you think you've got the most impact or running room. And the real driver is you can't lower costs if you don't put a rig in there. And a lot of what we're doing this year is strategic testing, like the second landing zone in the third Bone Spring. We've just got to look at those and see how they stack up and see how many and then we'll go to work on that. But very few places right now in North America are we parking rigs on pads and trying to develop things. I think it's a function of right now setting up opportunities and really continuing to line our cost structure and get our returns at the levels we want before we'd go back to work with major development programs.

Our next question comes from the line of Edward Westlake of Credit Suisse. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker): Thanks for squeezing me in at the top of the hour here. Just on the last comment you made about getting into development mode. No one has focused on this today, but say the oil price does go back up to the sort of $65 range that I think you referenced on the last call for some of the plays. How aggressive could you be in terms of the number of rigs that you could add over the next two years to three years? That's my first question and I have a quick follow-up. John J. Christmann - President, Chief Executive Officer & Director: Well, in terms of the number of rigs, I think we could add as many as we wanted to. We were running 93 last fall. So that's not hard. It will all come down to cash flow and economics and where's the cost structure. So what will be the driver – and we've been real consistent on that theme all year, is it takes the cash flow from our operations to be able to drive our programs. Over the long haul, we can go to the balance sheet from time to time if we felt like there was an opportunity. But in general, we want to be balanced and living within our means. And so it will be a function of the cash flow that we have to reinvest versus what other opportunities are out there. Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker): And then follow on is on the international CapEx. I mean, it's still running something like $650 million in Egypt on an annual basis, if I just annualize your first half and $800 million in the North Sea. Any opportunity to get some deflation or activity cycling as you go forward to get some savings there in the CapEx program? John J. Christmann - President, Chief Executive Officer & Director: We are seeing savings there. The one thing in Egypt, you really never had the run up from 2009 on the rigs that you had in the service side in North America. So dollars go further, which is why we've been running a number of rigs in Egypt. When you look at the North Sea, we've had a lot of success. The one thing we haven't talked about is we sanctioned a project that's pretty critical to us. It's Aviat. It's a $200 million project over two years. It's in the numbers now this year. We're going to spend about $100 million. But the big deal on that is we're going to convert the field to field gas from diesel. And it's a very economic project, it makes great rate of return. But the big deal is is it's going to be safer, it's going to be environmentally friendly and it's going to give us field gas supply where we're not having to bunker diesel to well into a 2030 timeframe. So it's an important project. It's about $100 million. That's part of what's in that North Sea number this year.

Our next question comes from the line of Michael Rowe of Tudor, Pickering, Holt. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc.: Yes. Good afternoon. You mentioned earlier a balanced CapEx program. Do you think the capital spent on North America onshore versus international offshore this year, which is roughly 60/40, is that balanced enough? And does that really change depending on what part of the commodity cycle we're in? John J. Christmann - President, Chief Executive Officer & Director: Well, clearly we look at the opportunities, we look at the running room and we look at the economics of the projects. And the good news is we've got a great inventory in general. The international portfolio is less sensitive to the drop in prices, so it's a little more buffered on the returns. And then on the North America side, you can generate in some areas a little bit more NPV. So it's a balanced approach. We like where our mix is right now. We're generating cash, cash out of both Egypt and the North Sea. And that's kind of directionally where we want to stay. But right now we like that mix, and think it's serving us very well. Michael J. Rowe - Tudor, Pickering, Holt & Co. Securities, Inc.: Okay. And then just a quick question on the Mid-continent program. You're spending some capital in the Woodford/SCOOP area, but not much in the context of the whole portfolio. So I was just wondering if you can comment on the 50,000 net acres you've got there today, and just maybe provide some context around how sustainable you think that is for a company of Apache's size. Thanks. John J. Christmann - President, Chief Executive Officer & Director: Well, number one it's, we've got about 50,000 net acres that's predominantly Grady County. We've got a rig in there, we're going to put another one in, the economics work very well. Yeah, it's material, and it's material to that portion of our portfolio. Most of the acreage has been purchased in there, but we've got some nice positions that are clearly very economic at low prices, and clearly, we've got a lot of running room to develop on that acreage position. So it's not something we're looking to scale up necessarily, just because most of it has already been gotten, but we've got really economic projects in there and it can make an impact.

Our next question comes from the line of Doug Leggate of Bank of America. Doug Leggate - Bank of America Merrill Lynch: I just wanted to hear it one more time. Sorry. Guys, I had a follow-up that I don't think – I think that your operator thought that my follow-up was a clarification point. Anyway, Egypt, John. Obviously at the beginning of the year, you decided that this was going to be a core part of the portfolio. So I'm just kind of trying to understand this step-up in exploration activities. Is that something that has been a deliberate change in reallocating capital? I'm thinking with the PSC, you get the money back fairly quickly. And if so, what is the exploration or drilling backlog look like for Egypt on the go-forward plan? John J. Christmann - President, Chief Executive Officer & Director: Well, Doug, it's really more driven off of technology. I mean, we've got the seismic 3D interpretations and so forth. Our success rate, we're drilling fewer wells than we drilled last year, but we announced a 78% success rate and it's really just a function of the quality, the technical work we're undoing in unlocking the basin, and a lot of these stratigraphic areas and traps with the 3D seismic, we're just getting better, and we've got a better handle on the system. Doug Leggate - Bank of America Merrill Lynch: And so is Egypt cash flow positive in the current environment? John J. Christmann - President, Chief Executive Officer & Director: Absolutely. Doug Leggate - Bank of America Merrill Lynch: Great stuff. Thanks very much.

Our next question comes from the line of Richard Tullis of Capital One Securities. Richard M. Tullis - Capital One Securities, Inc.: Hi. Thanks. Good afternoon, John. Quick question: looking at the Delaware Basin, I noticed the Bone Spring completions during the second quarter. While it's solid, it looked to be a little bit lower in oil cut and productivity per lateral foot than those Condor wells that you reported in the first quarter. Anything done differently drilling those Condor wells, or was it just a particularly sweet spot? John J. Christmann - President, Chief Executive Officer & Director: Yeah, I mean, I think it's going to be spacing and just the area that you're in within that Bone Spring. They're completed very similarly. So it's just a function of the area where you are. Richard M. Tullis - Capital One Securities, Inc.: And how much acreage does Apache have in that Pecos Bend area? John J. Christmann - President, Chief Executive Officer & Director: Pecos Bend is actually pretty small. I mean, you'd have to go back and look at our ops report. I think we're in the 7,000 acres to 8,000 acres in there. It's not a very big area, but it shows you how many landing zones we've got in a really nice little development area right there. Richard M. Tullis - Capital One Securities, Inc.: All right. That's it for me. Thank you.

And our next question and our last question, I should say, comes from the line of Jeffrey Campbell of Tuohy Brothers. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.: Good afternoon. My fist question is just broadly looking throughout the various plays, your Permian 30 day rates look pretty strong. I was just wondering, are you practicing any rate restriction in any of the portions of the Permian? John J. Christmann - President, Chief Executive Officer & Director: Actually, Jeff, we are. I mean, we have gone to some managed chokes and we're doing some things there right now that are helping us. And we have also been very focused on our completions and sand concentrations and so forth. Jeffrey L. Campbell - Tuohy Brothers Investment Research, Inc.: Okay. Great. Thank you. And then kind of taking Tom's remarks about the UK gas market in mind, the high rate S67 well, is that predominantly a nat-gas well and does it de-risk other potential similar locations? John J. Christmann - President, Chief Executive Officer & Director: Tom? Thomas E. Voytovich - EVP-International & Offshore Region: Indeed it does. It is a high rate gas well. In fact it's making about $50 million a day right now which is at the gas price we're getting, that's pretty much parity with oil right now on a BOE basis. There are other opportunities out there. We're just now getting started with our exploitation and exploration program of the recent 3D seismic, but there are more opportunities just like this in the field pays. These are individual fault blocks that were heretofore unseen or untouched at least.

And there are no further questions in the queue. Gary T. Clark - Vice President-Investor Relations: Okay. Well, thank you, everybody. We look forward to speaking with you all on the next quarter conference call.

Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.