Good afternoon. My name is Paige and I will be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation Fourth Quarter and Full-year 2016 Results 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. I would now like to turn the call over to Mr. Gary Clark, Vice President, Investor Relations. Sir, the floor is yours.

Good afternoon, and thank you for joining us on Apache Corporation's fourth quarter and full-year of 2016 financial and operational results conference call. Speakers making prepared remarks on today's call will be Apache's CEO and President, John Christmann; Executive Vice President of Operations Support, Tim Sullivan; and Executive Vice President and CFO, Steve Riney. In conjunction with this morning's press release, I hope you have had the opportunity to review our fourth quarter financial and operational supplement, which can be found on our Investor Relations website at investor.apachecorp.com. I would like to note that the supplement posted this morning includes expanded production and financial guidance for 2017. Production numbers cited in today's call have been adjusted to exclude our non-controlling interest in Egypt and Egypt tax barrels. Please also note that we are now providing guidance for our Egypt-based operations that includes non-controlling interest and tax barrels such that analysts can reconcile their estimates to Apache's reported production numbers. I would also call your attention to the updated production guidance we are providing for North America. We are now providing specific production guidance for the Midland and Delaware Basins, combined which represents Apache's primary growth engines. Another minor change we have made for 2017 is that we are now including the Gulf of Mexico in our North American guidance. We're also providing more comprehensive capital guidance, which now includes all oil and gas capital investment, leasehold acquisition, capitalized interest and capitalized G&A, and we are continuing to exclude Egypt non-controlling interest capital from our guidance. Finally, I'd like to remind everyone that today's discussions will contain forward-looking statements and assumptions based on our current views and 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. I will now turn the call over to John.

Good afternoon and thank you for joining us. On today's call, I will review our 2016 accomplishments, outline our 2017 strategic and operational objectives, discuss our capital spending plans and production outlook for the next two years, and I will conclude with an update of our Alpine High play. First, I'd like to step back and take stock of the last two years and how we have repositioned Apache. The collapse in commodity prices which began in 2014 required a strategic response to improve the company's financial standing and our operational capabilities and to position Apache to thrive as prices recovered. We have accomplished all that and more. The cornerstone of our approach has been strict capital discipline and cost structure rationalization, both of which have significantly improved the quality and economics of our underlying inventory as well as our ability to access and exploit its value for the future. We accomplished this through a rigorous and more centralized process for capital allocation, a more detailed long-term planning process, and through significant cost reductions in our operations and in our overhead structure. For example, we significantly reduced activity Onshore North America where costs were not aligned with lower commodity prices, dropping from 91 rigs in the third quarter of 2014 to eight rigs at year-end 2016. And since 2014, we drove down average onshore well costs by 30% to 40% across key plays in North America. Our LOE per BOE is down 24% and we have reduced our gross overhead cost structure by more than $300 million. As a result of these efforts, we were able to preserve our dividend, avoid issuing equity and maintain our investment-grade rating. We are now well prepared for a more constructive, albeit lower price environment, than prior to the downturn. With the proven quality…

Good afternoon. My remarks today will focus on 2016 production, expected activity in each of our regions during 2017, and a perspective on supply and service costs that we're seeing, particularly Onshore North America. Turning first to production; our fourth quarter results reflect the impact of reduced CapEx and development activity throughout 2016. During the fourth quarter, North America Onshore production averaged 252,000 barrels of oil equivalent per day, a 7% decrease from the third quarter. Our Permian operations produced an average of 149,000 BOE per day, down 6% from the third quarter. As John noted, we expect overall North American production will continue to decline into the second quarter before shifting to a strong growth trend. Most of this decline will occur outside the Permian in regions where we have made relatively little capital investments over the past four quarters. In the North Sea, our production in the fourth quarter returned to more normalized levels at approximately 70,000 BOE per day, a 12% increase compared to the third quarter, which was impacted by extended facility turnaround issues. We are in initial planning stages for development of the store discovery that we announced on the last conference call. Our high-risk Canord (21:29) exploration well reached TD in the fourth quarter and did not encounter commercial quantities of hydrocarbons. We have drilled three successful exploration wells and only one dry hole since acquiring our 3-D seismic survey over Beryl in 2013. Our gross production in Egypt during the fourth quarter declined approximately 2% on a sequential quarterly basis. On a net basis, excluding tax barrels and Sinopec's minority interest, production was approximately 90,000 BOE per day, a 7% decline from the third quarter, as higher realized prices resulted in Apache receiving fewer cost recovery barrels under our production, sharing and contract…

Thank you, Tim. Today, I will highlight the company's fourth quarter and full-year 2016 financial performance. I will also outline our 2017 financial guidance and outlook. 2016 was a very successful year as we continued to progress a very important transformation of Apache Corporation. From a financial perspective, we re-based our capital investment programs to deliver competitive returns in a lower-for-longer price environment. We delivered on our overarching goal of cash flow neutrality, protecting the strength of our balance sheet and our liquidity. We maintained our investment-grade rating, and we delivered an exceptionally smooth transition to the successful efforts method of accounting. Many analysts and investors have noted Apache's conservative and disciplined approach. We remain grounded in the belief that a strong balance sheet, conservative planning and budgeting, and rigorous investment economics based on full-cycle, fully burdened returns deliver the greatest amount of long-term value for our shareholders. We are proud of this approach and it has served us well for the last two years. We have improved our financial position, strengthened our investment programs for the future. And, at the same time, we accessed and advanced a world-class discovery at Alpine High. Let me now review our full-year and fourth quarter 2016 results. As noted in our press release issued this morning, under Generally Accepted Accounting Principles, Apache reported a loss of $182 million or $0.48 per share for the fourth quarter. These results include a number of items outside of our core earnings that are typically excluded by the investment community in published earnings estimates, the most significant of which were asset impairments. Adjusted for these items, the fourth quarter result was a loss of $22 million or $0.06 per share. Note this adjusted loss still includes dry hole costs, which amounted to $27 million or $0.07 per…

And your first question is from John Herrlin of Société Générale. John P. Herrlin - Société Générale: Yes. Thank you. For the Midland wells and the curve improvements that you've demonstrated, can you kind of attribute what you thought the improvements were in terms of landing zones, fracs, well length? Or is it just too hard to generalize?

No, John, I mean, we took time and, really over the last two years, worked on our programs. We focused on targeting there, we did a lot of core work and really zoned in on where do we want to be landing the wells. I can tell you, in general, we went back to higher fluid volumes. They are more stage numbers they're closer together and we actually reduced our sand concentration significantly, so it really is part of the optimization process. We're very excited about the results and since we're flowing back in pads versus one well per section, we're very confident in those results and it's really attributable to the work that the team's done at the detail level in integrating core into the completion optimization process. John P. Herrlin - Société Générale: Okay. Thanks, John. My next one from me is on the Alpine High gas. You mentioned that you've had a lot of interest from industry. Are you looking for index contracts, long-term contracts? I mean, how are you thinking about things?

I mean, I think right now, most of it will be priced off of Waha, is how we're thinking about it. We're very early. The thing I think that we've seen is that on the longer-term view there is a need out there for supply and so I think we'll have some optionality and we're really starting to think about that and think longer-term with larger volumes.

Your next question is from Edward Westlake with Credit Suisse. Edward George Westlake - Credit Suisse Securities (USA) LLC: Yes. Good morning, and thanks for the update last week as well. So, you've further de-risked more of the Alpine High in your statements last week, at multiple landing zones in some of the wet gas. But when we look at the well results outside of the Northwest of the play, where you've had some really good wells, Redwood, Spruce, and Mont Blanc. The market is really just not being impressed by the flow rates. So, maybe just a reiteration of what excites you in the rest of the acreage that the market's not been pleased by?

Well, thanks, Ed. I'd say first and foremost, we've been drilling kind of cookie-cutter wells that are designed to test the rock in the stratigraphy. I think the important piece of information we brought forward was the overpressure to the south. In fact, now, if you look at the pressure gradient across the whole play in the bottom zone, it's all lower pressure. Clearly, as we move to the far northwest, you're deeper and there's even more overpressure. But as we look back, the one well we disclosed, a couple of different wells, but the Hidalgo well actually, we believe, we had to spud that well before we had the 3-D in. And we believe it is drilled. In fact, we now know it's not on the proper azimuth. We've got a couple of wells coming that we're excited about that will be on the proper azimuth. But what was impressive to us was how flat the well has been. It leveled off and hasn't budged and the water is continuing to come down. So, we're very impressed with it. The pressure gradients were higher and the thing that we've been able to see is the entire column as well. So, if you look back, the process we've taken, the very first Woodford wells were all in the middle part of the section. We've now validated there's a stronger upper zone. We believe there's a third landing zone as well on the lower, which would give you three landing zones in the Woodford alone. And if I take you back to the Barclays disclosure in September last year, we really assigned just one landing zone on part of our acreage to the Woodford and the Barnett. So, I know everybody wanted big flow rates. We don't have the processing facilities…

Well, we've got July circled on the calendar and... Edward George Westlake - Credit Suisse Securities (USA) LLC: July 4?

...we're obviously on a path to get there and the way we give guidance and things, I would expect we'd be able to make what we've told you we'd be able to do.

Your next question is from Scott Hanold with RBC Capital Markets.

Thanks, good afternoon. Maybe a little bit on the King Hidalgo well. You obviously saw some area that there was overpressure there. It looks like the well, based on your presentation a week or two ago, indicated that it was flown with ESP. Can you discuss, is that in-line with your expectation? Or would you have expected that to be flowing naturally a little bit longer?

No, Scott, I mean, if you look at the well, still a lot of load coming back. I mean, most of these wells we've moved ESPs in early to get the water off of them. You see a trend on that well that's coming down. As I mentioned, it's not on the optimal azimuth, and we've seen that in some of the wells in the other parts of the play. Getting them on the right azimuth will make a difference as well. But, we're absolutely thrilled with the well and think when you start to look at the curve and realize that really from about day 33 on through we're now over 100 days, the thing has not budged. The oil's been slowly coming down, and it is cutting a little bit of oil with it as well. So, we're very excited about it. I will reiterate, this is only a 3,300 foot lateral and we had a limited number of frac stages in the small frac. And it's not on the optimal azimuth.

Okay. And just to clarify then, then if you would have been on the proper azimuth, then obviously had a more optimal frac, you would have expected that to be flowing naturally a little bit longer? Is that a fair statement?

Well, there are different areas in terms of how the wells flow back. A lot of the wells we've run subs in early they get the water off of them. We've got some instances where they haven't needed them. And I think the different azimuth will relate to a different profile on the water, higher IP, and obviously we think the productivity is going to go up when we optimize the frac. So, I think it will change the shape and the IP capacity of the well and so forth more than anything.

Your next question is from Bob Brackett with Bernstein Research. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Hi, guys. Could you talk about the Suriname prospect; sort of days to drill, when we might get some news, the chance of success, and maybe a risk size, if you're willing to give that?

Bob, at this point, it's a well we're very excited about; Block 53 we own 45% of. We've got two partners in there. The rig is on its way to location now, as we speak. We should be spudding it probably late next week. As Tim said in his prepared remarks, it's probably a 70-days, 10-week type well. I'll say it's an exploration well. It's a well we need to drill. We're excited about it. And that's all we've really disclosed on it. I will also tell you we're working the 3-D on Block 58, which we have 100%, we're really thrilled about as well. So, if I had my druthers, I might be drilling 58 first, but the timing is the opposite. But we're very excited about the Kolibri (46:41) prospect and we'll come back with the results in 70 days, 80 days, roughly. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: And is it a fully strat trap, or is there a structural component?

It is a strat trap. Robert Alan Brackett - Sanford C. Bernstein & Co. LLC: Okay. Thank you.

Thank you.

Your next question is from Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co.: Thank you. Good afternoon.

Hey, Brian. Brian Singer - Goldman Sachs & Co.: My first question is with regards to decline rates outside of Permian Basin and outside of Alpine High. Given the focus on those two areas, can you just refresh us on how we should think about some of those decline rates in a budget that stays relatively flat in 2018 relative to 2017?

Well, what I would say, Brian, is overall our North American decline rates probably on average about 20%. It's come down significantly over the last two years as we have not been investing in a lot of those projects and plays. It's about where it would sit now. Some areas are a little heavier, some areas are a little lighter; but in general, that's kind of where that overall base decline rate would be today. As we start to go back to work in some of the other areas, we'll be bringing on some higher decline stuff and it'll start to trend back in the future. Brian Singer - Goldman Sachs & Co.: And what about the areas outside? And where are you at these days in Egypt and North Sea?

With the international, depending like you're seeing, we pulled the third quarter turnaround in the North Sea after the second quarter, so it's going to be lumpy at times. We see relatively flat for our international over the next couple years. The one thing that drives Egypt is the price and the way the production sharing contracts work, so you're seeing our nets come down a little bit as prices started to improve late last year. And that's going to have a little bit of an impact as we look into the out years as depending on price, but pretty stable.

Your next question is from the line of Arun Jayaram with JPMorgan.

Good afternoon. I just quickly want to go back to the press release and you guys commented how your budget of $3.1 billion would exceed your planned cash flow for ops. Guys, is that inclusive of the dividend when you all made that comment?

Arun, it is and it's also at the $50 price deck. So, what we state in there was with the sales that we have already in the house, over $400 million and with where strips would be today, that would cover dividend and everything.

Okay. So that comment was including the dividend as well?

Yes.

Okay. Great. That's helpful. And thanks for the longer-term disclosure and thoughts through 2018. I was wondering as we work on our models, if you could help us think about the oil and gas and the liquids mix, particularly as we get into 2018, just given how Alpine High is going to be more on the wetter gas side of the equation?

Well, what we've done, Arun, we gave you a corporate level numbers. We showed you kind of a North American production outlook and then we really broke down the key driver, which is Midland, Delaware. We showed you an overall number and we've showed you the oil piece. What we did not show you is the liquid yield on the gas and, quite frankly, Alpine is going to be the driver there. And the big thing is by July of this year, we'll have facilities up and running. We'll have more data. We can come back then and start to update the NGL yields and some of those things. I'll also tell you that given the program we have today, which is more wet gas driven with a lot of tests in the oil zone still yet to come, we've got a pretty conservative mix dialed in. So, there's a good chance you get out to 2018 or even later this year where we will be updating those and giving more color. But we didn't want to get into that until we really had the facilities up and running and could really shed some light on the NGLs. And, quite frankly, we've got a lot of well still yet to test that can make things oilier.

Your next question is from the line of David Tameron with Wells Fargo.

Afternoon. John, a lot's been asked on the Permian. Let me get back to the cost. I remember year ago or so you were talking about unbundling the service costs and maybe doing something along those lines. Kind of, where do you see your current, I guess, cost progress and how should we think about it over the next 12 months? And are you having luck on that unbundling, if you will, of service cost?

Well, the answer is absolutely, David. I mean that's kind of the model we've taken. We did see the pumping pressure go up in December. If you look at our overall well costs – and I can have Tim give some more color in just a second to kind of add on to what I'll say here. We have forecasted some inflation in total, probably around 10%. What we don't have dialed in is efficiencies. I think areas like Alpine High where we're still very early we've got a lot of room to move on the efficiency curve as we get in to drill these things. Quite frankly, a few of the laterals that we drilled in the upper zones, we were surprised that the pressure gradients were higher and we had to run some shorter laterals than we had originally planned. So, as we learn those you're going to see things come down, but we've unbundled. Tim pointed out in his comments there that we've done some things, the frac crews, where we've indexed some portions with commodity price. So, we're trying to get creative on how to make it really a win-win as we work through this. But absolutely, still unbundling, very confident in where our cost structure is. We've secured most of our services for the next couple years. So we feel good about what we've got in our numbers. Is there anything you want to add, Tim?

The only other thing I might mention, about half of our Permian rigs, a little bit more than half, we do have under longer-term contracts, anywhere from six months to 1.5 year contract. So, we don't see a big push on that. As far as pumping services go, we've seen an increase to-date between 15% and 20%. And on our sand, we've seen an increase to-date about 10%. But, as John mentioned, we do have agreements in place that are tied to WTI. So as we see a 10% increase in WTI, we will only see about a 3% to 5% increase in service costs.

Okay. That's helpful. And then, John, Central Basin Platform, how should we think about? Is there any capital going to that this year?

There is a little bit, David. I mean, it's a cash cow for us. It's why we split it out from the numbers in terms of where the growth investment is. We're excited about – I mean we remain optimistic and excited about the Central Basin Platform. Quite frankly, with more cash flow, there's more projects to do there. But there are things we don't have to do. And so there's a fine line of balancing. One of the things that we should be doing versus what you can be doing. But we've got slight decline there. It's much lower than the North American numbers that I gave, well under 10% on average, and it's a significant source of volume and cash flow for us. After Egypt – Egypt, Central Basin Platform and North Sea are really the three cash drivers – cash flow generators for the corporation right now. So, an important part of our portfolio and the nice thing about it is the longevity.

Okay. Thanks.

Your next question is from Jeffrey Campbell with Tuohy Brothers.

Good afternoon. I just want to make sure I understood the slide 25, when I look at it, the 50% compound average growth rate in Permian. Should I think of most of Alpine High's early potential as built into this forecast? Or can Alpine High represent some upside to the forecast? And if it could, could you discuss the high level variables?

Well, I mean, Jeff, it is built into that forecast right now. We roped it in. Now, I'll tell you, like we always do, we're going to guide in things that we feel like we can deliver. So, it's not our Permian. That's just the Midland and Delaware. So, I think there were a few folks that got that mixed up this morning in their notes and forgot that we've got 72,000 BOEs a day on the Central Basin Platform, but that is just the Midland and Delaware Basin curves. It does have Alpine in it. I think it is a good look, conservative look for us for right now and it's liable to get stronger and liable to get more oily. But I'll leave it. For right now, that's what we put out.

Okay. And the other question I wanted to ask was with regard to slide eight, the Other North America. I was just wondering, if this primarily includes the Montney. Is there something else in there? I'm really asking just because it seems like Apache's continuing to try to simplify the portfolio to the Permian Basin and international assets?

Well, that's going to be predominantly our Canadian assets and what we call our Houston region, which would be our conventional Anadarko and our Eagle Ford assets. So that's heavily influenced by Canada as well as the – I think we've got Guam in there as well, but just a much smaller volume.

Your next question is from Charles Meade with Johnson Rice. Charles A. Meade - Johnson Rice & Co. LLC: Good afternoon, John, and to the rest of your team there. I wondered if you could give us an update perhaps on the two wells that you talked about. In your conference last week, you talked about were flowing back the (57:31). I believe it's the 7H in the Penn and also the Redwood well. I believe it's 4H that was the horizontal in the Wolfcamp. And I'm specifically wondering on the Redwood well. Is that in that same part of the Wolfcamp that gave you the 700 barrels a day from the vertical drills in test back last year?

Well, I mean, at this point, we have not provided updates, Charles, on either of those wells. We are in the area where we were seeing the DST. What I'll also tell you, though, is we had a lot of open hole above us and that's where we, obviously, took a big pressure kick. We let it flow, flowed for about 10 days, was making 700 oil. But we had a lot of column above us. And we showed in the Credit Suisse package that we thought that was probably in a more gassy regime. So we will see. There's a good chance that oil may be coming from some of the up hole zones that also look fantastic as well. But you know, the DST, you had open column but that is where the tool was when we took the kick. So, still to be determined as we delineate and get to that. Charles A. Meade - Johnson Rice & Co. LLC: No. That's helpful color, John. I think it just emphasizes how much there is still left to figure out here. And then second question, if I could switch over to the Midland Basin, Tim, you went through the, some of the big pads you have coming online early in 2017. Once we get to the back half of 2017 and into 2018, are we going to be at or are you going to be more at a steady-state of bringing pads online? Will you have built-up enough momentum at that point? Or should we expect ongoing lumpiness in the Midland Basin program?

Yeah, the difference is, as we mentioned, in 2016, we only ran one rig for the majority of the year. And we just added additional rigs toward the back-half of the year, and now we're just now getting some pads online. Now we've got the pad we talked about, we've got one that's flowing back today. Now, we've got a nine-well pad at Azalea that will be coming back on in April, and then we've got another six-well pad back at Powell that will come on mid-May. And then you get into the back-half, again, we will be drilling with pads, but we're going to have continual operations. It will be a bit lumpy because it is pad drilling, but I think you're going to see a much more steady stream of wells coming across in the back-half.

The other thing I would say there is if we've got more cash flow, that's going to be one of the first areas that you can see us pick up some more rigs and activity. I mean, Midland, Delaware are going to be the areas that you'll see, you know, if prices were to move up, we have more cash flow, that's where you'd see us accelerating.

And your last question is from Paul Sankey with Wolfe Research.

Hi, guys. Appreciate the color. Could you just go back to a high-level question? In terms of your infrastructure spend in the Alpine High, what are really your long-term assumptions here? Where do you think this is going in terms of the ultimate volumes over time? How are you going to sell the gas? And what your assumptions are for spending as much money as you are right now? Thanks.

Well, Paul, I mean, I think if you lay out, we spent $200 million last year, we've laid out $500 million the next two years. We're very excited. I mean, the first two phases of this are going to take us several years in. We won't have a decision point to make on staying with re-fridge, which is kind of the base case we have in the field right now, or do we go to cryo? But as I said on the earnings call last August, we're not talking hundreds of millions of cubic feet of gas here a day, we're talking multiple Bcfs, a very rich gas, wet gas, NGLs, and we think there's going to be also a lot of oil to go with it. So, we're very excited about what we have in front of us. I think once we are able to get the processing equipment in the field and things running, you'll start to see some things in terms of lateral lengths, optimized fracs, and we'll start to show you really what this resource is capable of doing. So, we're very excited about it, and I think it's going to be a big underpinning item for Apache and our Permian for a long, long time.

But you don't – can you share – I mean, you must have assumptions on where you're going to here, given the upfront spend. And we're just trying to get to a long-term sort of present value idea of what you guys are basically assuming?

Yeah. And what I'll say, Paul, is just look at what we've given you. We've given you now a look into the end of 2018. I've said, it's likely conservative on what Alpine and what our Permian can do. We gave you some location counts at Barclays. We've come back now and said we've got a minimum of 3,000 confirmed locations in the wet gas window. We will unfold more as it continues to progress, but we remain very optimistic, very excited. But one thing I'll say about this field is it gets bigger. I know there was a little bit of a negative reaction to some of the rates, because everybody's expecting us to be optimizing and scaling-up our fracs and things, but we're very pleased with where we are, and the scope and scale of this field has done nothing but get bigger since our initial disclosure in September of last year.

Got you. Could I ask just one very specific one? Your Midland results have looked good. What percentage of the acreage there do you think will go to longer laterals? And I'll leave it there. Thanks.

Yeah, most of that, we're now got 1.5 mile to two miles dialed in. We did a lot of work over the last two years buttoning down some trades. So most of the wells we're going to be drilling are 1.5 mile to two mile laterals now. So, we're excited about that as well.

This concludes our Q&A portion. I would like to turn the call back over to Mr. Gary Clark for closing remarks.

Well, thank you all for joining us. We have gone past the top of the hour, so we need to cut it off there. If you're still in the queue – and there are some left, please give us a call; feel free to give my team a call and we'll be happy to get your questions answered. Thank you very much.

Ladies and gentlemen, this does conclude today's call. You may now disconnect.