Gary T. Clark - Apache Corp. John J. Christmann - Apache Corp. Timothy J. Sullivan - Apache Corp. Stephen J. Riney - Apache Corp..

John P. Herrlin - Société Générale Edward George Westlake - Credit Suisse Securities (USA) LLC Scott Hanold - RBC Capital Markets LLC Robert Alan Brackett - Sanford C. Bernstein & Co. LLC Brian Singer - Goldman Sachs & Co. Arun Jayaram - JPMorgan Securities LLC David R. Tameron - Wells Fargo Securities LLC Jeffrey L.

Campbell - Tuohy Brothers Investment Research, Inc. Charles A. Meade - Johnson Rice & Co. LLC Paul Sankey - Wolfe Research LLC.

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..

budgeting conservatively and maintaining flexibility to accelerate activity, if warranted; continuing our focus on costs and well optimization to maintain the structural efficiencies achieved over the last two years; increasing capital allocation to the Midland and Delaware Basins, where we have an extensive high quality inventory; initiating an optimized development program at Alpine High; investing to sustain long-term free cash flow generation from Egypt and the North Sea; and, finally, actively managing our portfolio and redeploying capital to higher-value opportunities.

Now I'll turn to the 2017-2018 capital budget. Our capital budget for this year is $3.1 billion, which is up more than 60% from 2016. Our 2017 plan assumes $50 per barrel WTI, $51 per barrel for Brent index crude, $3.15 per Mcf for NYMEX natural gas, and $5.25 per Mcf for UK indexed gas.

At these price levels, our capital program will exceed anticipated operating cash flow. The gap will be covered by proceeds from non-core asset sales, $400 million of which has already occurred, and a realization of prices at the current strip. We have also put in place some oil price hedges to protect against downside price movements.

Steve will cover these in more detail. Our 2017 capital plan allocates nearly two-thirds or $2 billion to the Permian Basin. Of this amount, 90% will be directed to the Midland and Delaware Basins.

This includes approximately $500 million for infrastructure construction at Alpine High, which will fund multiple pipeline connections along with the necessary compression, gathering, centralized processing facilities and tank batteries that will more than accommodate our planned volume ramp.

Internationally, we will invest to sustain long-term free cash flow generation in Egypt and the North Sea. Total international spending represents approximately $900 million or 29% of our 2017 budget, split fairly evenly between Egypt and the North Sea.

We have also included $37 million for an exploration well in Suriname, which we expect to spud next week. Outside of Suriname, our 2017 international opportunity set is primarily focused on development drilling and lower risk step-out exploration, where we have a long-standing track record of success.

We are particularly excited about two exploration concessions that we recently received in the Western Desert of Egypt, our first award there in over 10 years. Should commodity prices further improve during the year and cash flows allow, incremental capital will be allocated primarily to the Midland and Delaware Basins.

Turning briefly to 2018, our preliminary capital outlook is for $3.2 billion in investment. This program is supported by anticipated volume growth and higher plan prices for 2018. Like 2017, our 2018 plan will be heavily weighted toward Permian investment.

Our 2017 and 2018 plan capital program will initiate a significant and prolonged production growth ramp. I would note specifically the magnitude of our anticipated production growth in the Midland and Delaware Basins.

To assist in the production outlook discussion, we have provided a series of slides on pages 22 to 26 in our financial and operational review issued this morning with our earnings results. This includes a production forecast through the end of 2018.

While our capital program has increased to reflect the objective of delivering long-term returns-focused growth, our production response will have a brief lag before transitioning to a strong growth trajectory. We anticipate total production will decline to approximately 372,000 BOEs to 384,000 BOEs per day in the second quarter of 2017.

This will be a result of three primary drivers. In preparation for the start-up of our Callater discovery in the third quarter of 2017, we have accelerated our annual North Sea maintenance turnarounds into the second quarter. These turnarounds would typically occur later in the year.

We have significant gas plant maintenance downtime scheduled in Canada for the second quarter of 2017 and investment in our lowest-margin North American assets was severely curtailed over the last two years and these assets are currently in decline.

Importantly, none of this projected decline is in our higher-margin Midland Basin production, despite very low activity levels last year. In the second half of the year, the North Sea should rebound sharply with the start-up of Callater.

More notably, North America will begin a rapid and relatively consistent quarterly growth ramp, which should continue through the end of 2018 and beyond. This will be driven primarily by the combination of accelerating oil production in the Midland Basin and the start-up of Alpine High in the Delaware Basin.

Our projected oil growth in the Midland Basin is underpinned by the impressive performance we are seeing in our most recent vintage wells. Tim Sullivan will provide more detail on our Midland Basin wells in his remarks. At Alpine High, we anticipate having our first major sales line connection by July.

Well connections and facilities commissioning will take place through the end of the year, accompanied by a material ramp in wet gas production. To put some numbers around our two-year growth profile, we expect total company production to increase by approximately 10% annually from the fourth quarter of 2016 to the fourth quarter of 2018.

Our Midland and Delaware Basin assets are projected to grow at a compound annual rate of 50% over the same time and drive the vast majority of Apache's overall production increase. Oil production growth in the Midland and Delaware will also be very strong with an annual growth rate of approximately 18%.

We're very confident that Apache's portfolio can deliver on our production expectations through the end of 2018 and beyond. We are seeing outstanding drilling results in the Midland Basin and Alpine High continues to surprise us to the upside.

With that, I will conclude with a brief update on the Alpine High play and review our next steps as we begin to phase in well optimization and fuel development activities. Since first announcing Alpine High last September, we have made tremendous progress delineating the play. We have confirmed several things thus far.

We have an extensive play fairway, which spans 55 miles and a 5,000 foot vertical column encompassing five geologic formations, each with multiple targets. The hydrocarbon phase of this column ranges from dry gas to wet gas to oil. The entire Alpine High fairway is over-pressured with higher pressure gradients to the north and to the south.

We have a second landing zone in the Woodford formation and most likely a third. We have productivity in the Pennsylvanian formation. And in the southern portion of the play, we have encountered the entire hydrocarbon column, improving productivity in the Woodford.

With these results, we now believe that Alpine High's resource and location count has increased significantly since last September. And we haven't changed our view on well economics. We will provide updates to these numbers in the future.

Importantly, we are beginning to optimize our wells using customized zone targeting, larger fracs and, in some cases, longer laterals. Combined with multi-well pad drilling we are confident this will demonstrate the economic value of the wet gas interval of Alpine High over the coming months.

We continue to refer to Alpine High is a wet gas play, because that is what we have confirmed thus far. As we have previously noted, we are delineating from the bottom-up and this process is not yet complete. This is a prolific wet gas play from which we expect a minimum of 3,000 drillable locations.

A significant enhancement to the economics of the source rock interval at Alpine High is the lack of water in the target formations. Once these wells produce the frac load, water production declined sharply, which results in significantly lower operating costs.

Additionally, the field development program is not constrained by the need for extensive water handling infrastructure. As a result, even in the lower commodity price environment, this play is going to be very economic. Turning to midstream and marketing, our efforts at Alpine High are advancing quickly.

Because the play lies in an area with very little existing infrastructure, it provides the unique opportunity to design a greenfield fit-for-purpose system that optimizes processing and transportation of our production and will service Alpine High for the full life of the field.

For now, we own 100% of the midstream as it allows us to control the pace and scope of the build out. Alpine High is ideally situated with three major transportation lines located within 10 miles to the north and one major line to the south.

The Waha hub which is located roughly 45 miles east of our acreage provides additional options for access to a wide range of domestic markets. Our location places us at the front of the line to deliver gas to Mexico as well as being advantageously positioned with LNG and petrochemical markets on the Texas Gulf Coast.

Contract negotiations are well underway, and we see no near-term takeaway constraints as we prepare for first gas and the follow-on production ramp. On the marketing front, we have been inundated with interest for both our natural gas and NGLs.

Potential customers are looking for certainty of supply, and the thick hydrocarbon bearing zones at Alpine High can provide it. In conclusion, Apache begins 2017 with an excellent opportunity set.

Momentum will start to build around mid-year, with increased contribution from our pad drilling in the Midland Basin and the commencement of first residue gas sales at Alpine High. The Permian Basin will clearly be the driver of strong growth in the second half of 2017 through 2018 and well into the future.

While commodity price volatility may not be completely behind us, we have come through the downturn with a very strong financial position and the ability to fund future growth through cash flow and portfolio high-grade. We continue to have no desire to add leverage or dilute our equity holders.

Over the last two years, Apache demonstrated that we can play very good defense, and we now look forward to showing you our offense. With the plans, we have in place, we believe we will deliver highly competitive returns and top-tier Permian-driven growth. I will now turn the call over to Tim..

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 agreements.

Please refer to our financial operational supplement for more details on our fourth quarter and full-year production. Turning to operations; last year, our focus on operational improvements and strategic testing established a solid foundation for achieving the company's 2017 goals.

As a result, we are now drilling more productive wells more efficiently, and you will begin to see the impact of these improvements this year as we increase development activity primarily in the Delaware and Midland Basins.

Our financial and operation supplement highlights some recent performance results from well optimization we implemented last year in the Midland Basin. This includes the use of improved targeting, drilling longer laterals, and more advanced completion designs.

We have updated these cumulative curves with additional wells and more days on production since we first showed them in September. The bottom line is that we continue to see wells on our core acreage in the Midland Basin outperforming peers in the area.

Apache concluded 2016 by adding three additional rigs in the Midland Basin, bringing our total rig count in the area up to five. We were at only one rig for most of 2016. These rigs are dedicated to long-term pad development drilling and our core acreage will enable us to place 25 wells on production during the first half of 2017.

This is a significant increase from the nine Midland Basin wells placed on production in the second half of 2016 and will put the Midland Basin on a positive growth path. We are excited about moving forward with a multiyear, multi-rig drilling program that is designed to generate production from some of our best wells and our best rock.

Most recently, our five-well Lynch pad at Wildfire came online last quarter with production from the Middle Spraberry, Lower Spraberry and Wolfcamp B formations. This pad exhibited excellent 24-hour IPs, 30 day IPs and cumulative 60 day oil production.

Our next pad at the Powell field is in early stages of flow back on six wells and began oil production last week. Following that, a nine-well pad at Azalea will go online in April. During 2017, we expect to average 15 rigs in the Permian Basin and drill approximately 250 wells.

Our 2017 Permian Basin rig count comprises five rig lines and two frac crews in the Midland Basin. Three rigs drilling in the Delaware Basin outside of Alpine High, one rig on the Northwest Shelf drilling in the Yeso play and one vertical rig dedicated to improved recovery in the Central Basin Platform.

In addition, we will have a four-rig to six-rig program at Alpine High. To accelerate well completions and data collection, we added a second frac crew at the start of this year. Elsewhere Onshore North America, in Oklahoma, we will run a targeted drilling program in the SCOOP/STACK play.

We have a large inventory of locations in this play and total drilling costs have come down as we've improved our completion techniques. We expect to drill four wells in the MidContinent this year primarily for the purpose of holding acreage. In Canada, we plan to drill a total of 10-wells this year.

In the first half of the year, we will drill out a six well pad in our Kaybob Duvernay play with production from those wells anticipated around mid-year following winter break up. We'll also drill three Montney 10 year wells in our Wapiti area in 2017.

In the North Sea, we will operate an average of three rigs for the year, which includes two platform rigs and two semi-subs on rig sharing agreements. We plan to drill 15 wells to 16 wells this year. We've pulled forward our annual plant turnaround in the North Sea to accommodate first production at Callater.

The net effect of this downtime and new production is that we expect the first half 2017 North Sea production of approximately 55,000 BOE per day and second half production at roughly 70,000 BOE per day. Our gross production in Egypt during 2017 is expected to be down slightly, about 2% from last year.

This is primarily the result of an expected decrease in lower margin gas production as our large cost of field begins to decline. We will run eight rigs to 10 rigs during the year and drill 90 wells to 100 wells.

The two new concessions awarded to Apache in November should be signed during the second quarter, and we plan to commence drilling operations in the fourth quarter. To support development on our existing acreage and the exploration on our new concessions, we will initiate a large continuous 3-D seismic survey program.

This will take place over the coming months and provide newer vintage, high resolution imaging of the substrata across our Western Desert position, allowing us to build and high-grade our drilling inventory.

Offshore Suriname, we are getting ready to spud the Kolibri #1 (27:24), an exploration well and Block 53, where Apache holds a 45% working interest. The rig is currently moving on to location and we expect to begin drilling next week, reaching targeted depth about 10 weeks later.

With the move up in commodity prices and the subsequent increasing demand for drilling rigs, we are seeing an uptick in costs, particularly for certain services in North America Onshore, such as pressure pumping and sand.

Our move to pad drilling operations in the Midland Basin brings efficiencies that will help offset some of these increases and protect some of the cost savings that we have captured over the past two years. We continue to look for ways to optimize our operations and improve our margins.

This includes finding alternative sources and services to mitigate inflation and preserve well economics. We are finalizing contracts to secure fleets in West Texas with terms that include indexing prices to WTI and extending contracts with favorable rates.

Our international operations have not seen the volatility in service costs as compared to North America Onshore. For example, service costs in Egypt remain very competitive and are among the lowest in the world.

I'll conclude by noting that we have structured our capital allocation process and our operations to respond quickly as circumstances warrant. We are pleased to be back at work drilling more wells.

As you can see from the recent data, we believe our 2017 North America development program will be more productive and capital efficient than in previous years. I will now turn the call over to Steve..

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 share after tax. For the full-year 2016, Apache reported a loss of $1.4 billion or $3.71 per share and an adjusted loss of $430 million or $1.13 per share.

In the fourth quarter, Apache generated $819 million in net cash from continuing operating activities and $2.5 billion for the full-year. We maintained our strong liquidity position throughout 2016, ending the year with $1.4 billion cash on hand. Our net debt position at year-end 2016 was $7.2 billion, down slightly from year-end 2015.

2016 capital spending was $537 million for the fourth quarter and $1.9 billion for the full-year. Approximately $900 million of our investment during 2016 was directed to the Permian Basin, of which approximately $500 million was directed to Alpine High.

We invested approximately $700 million in our international businesses, consistent with our strategy of investing to sustain the cash flow generating capacity of these assets for the long-term. Lease operating expense for the full-year averaged $7.85 per BOE, a 16% decrease from 2015.

In the fourth quarter, lease operating expense was $8.39 per BOE, down 17% from the fourth quarter of 2015. For 2016, we set a gross overhead cash cost target of $650 million. Actual overhead costs for the year were $639 million. We reported expensed G&A of $410 million or $2.15 per BOE.

During the fourth quarter of 2016, Apache entered into transactions to sell certain non-core assets. These included midstream assets in the North Sea and two mostly non-producing leasehold packages in the Midland and Delaware Basins.

The net production impact from these sales is approximately 1,500 barrels of oil equivalent per day and is reflected in our 2017 production guidance, which John provided earlier. Now I will move on to our 2017 capital program and other financial guidance. As John outlined, we have a clear line of sight to closing the funding gap in our 2017 plan.

While we believe that now is the time to outspend cash flows, we also want to protect our balance sheet. We have worked hard to build a strong financial position and we will not put that at risk to near-term price volatility. As such, we have put in place some protection against further price downside.

Over the past several weeks, we have entered into put option contracts providing a floor of $50 WTI and $51 Brent for most of our second half 2017 oil production. With this protection in place, we will move forward with our Permian Basin capital program knowing that any price weakness will not cause a funding shortfall.

We chose to use put options to mitigate the risk, while maintaining full exposure to upside price potential. In terms of other guidance, we have chosen to expand annual guidance around selected production and financial metrics. This is provided in our quarterly financial and operation supplement.

John has already covered production and CapEx, so I will move directly to financial items. Please note that all guidance is based on our plan assuming $50 WTI and $51 Brent. My comments here will be relatively brief, so please feel free to follow-up with Gary and his team for any questions as you incorporate the data into your models.

In 2017, we will continue to focus on lease operating expense and enhancing our margins. However, given our production declines in the first half of the year and some expected service price inflation, we see lease operating expense rising to somewhere between $8.50 and $9 per BOE.

We estimate gathering and transportation costs will be $200 million to $250 million. Our portion of 2017 cost expense to G&A on the income statement is projected to be around $450 million and our capitalized portion of interest should be around $65 million.

Cash income taxes should be approximately $125 million, which is driven entirely by the profitability of our North Sea operations. Finally, we are forecasting approximately $150 million of exploration expense in 2017. This includes recurring exploration overhead costs and planned exploration expense activities.

This excludes any dry hole expense or unproved property impairments, which are difficult to project in terms of timing and magnitude. In closing, Apache took a prudent approach to capital spending through the downturn. This has put the company on firm ground going into 2017.

We are now very well positioned to fund the capital program that will deliver long-term returns-focused growth, primarily from the Midland and Delaware Basins. We look forward to a successful 2017. And I would now like to turn the call over to the operator for Q&A..

And your first question is from John Herrlin of 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..

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..

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 in place yet to do that.

We are under flaring rules and so drilling longer laterals with bigger fracs right now is just not the optimal use of our dollars. But, we are moving into a phase where we have line of sight now on connection to the gas markets, where we can start to stretch some things out and actually start to demonstrate what we know this rock will do.

So, we're very excited to be shifting gears as we start into the optimization process, but bottom line on it is that there are many, many landing zones, a vast resource, and we're excited about the potential across the whole hydro-column, all the way from the dry gas to the wet gas up into the oil zones, which we're about to get to.

The last thing I'll say, I was at your conference last week, we said we have eight wells that are currently in process that will be targeting shallower zones from 9,500 to 11,000 feet. So, we know the gas gets richer and the liquids content is going to go up and we do anticipate seeing some oil as well. So, we're excited..

And then we're all watching the data, but the other big item obviously is getting this pipe in place, maybe just an update on the progress in terms of getting the infrastructure in place to be able to flow these wells a little bit more optimally?.

Well, we've got July circled on the calendar and....

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..

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..

And is it a fully strat trap, or is there a structural component?.

It is a strat trap..

Okay. Thank you..

Thank you..

Your next question is from Brian Singer with Goldman Sachs..

Thank you. Good afternoon..

Hey, Brian..

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..

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..

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..

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..