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

Robert Alan Brackett - Sanford C. Bernstein & Co. LLC Edward Westlake - Credit Suisse Securities (USA) LLC Brian Singer - Goldman Sachs & Co. Scott Hanold - RBC Capital Markets LLC John P. Herrlin - Societe Generale Phillip J.

Jungwirth - BMO Capital Markets (United States) Arun Jayaram - JPMorgan Securities LLC Robert Scott Morris - Citigroup Global Markets, Inc. Charles A. Meade - Johnson Rice & Company L.L.C. David R. Tameron - Wells Fargo Securities LLC.

Welcome to the Apache Corporation First Quarter 2017 Results Earnings Call. I would like to turn the call over to Gary Clark, Vice President-Investor Relations. Sir, the floor is yours..

Good afternoon, and thank you for joining us on Apache Corporation's first quarter 2017 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've had the opportunity to review our first quarter Financial and Operational Supplement, which can be found on our Investor Relations website at investor.apachecorp.com.

Please note that the details of our 2017 production guidance increase can be found on pages 21 through 24 of the supplement. On today's conference call, we may discuss certain non-GAAP financial measures.

A reconciliation of the differences between these non-GAAP financial measures and the most directly comparable GAAP financial measures can be found in the supplemental information provided on our website.

Consistent with previous reporting practices, production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt tax barrels. Finally, I'd like to remind everyone that today's discussions will contain forward-looking estimates and assumptions based on our current views and reasonable expectations.

However, a number of factors could cause results to differ materially from what we discuss today. A full disclaimer is located with the supplemental data on our website. And I will now turn the call over to John..

oil, wet gas and dry gas. And that the depth and temperature at which the source rock is encountered varies across Alpine High and determines the dominant hydrocarbon phase. And lastly, we've established that the Wolfcamp and Bone Springs formations are present oil bearing and perspective and significant portions of Alpine High.

With the knowledge gained from our appraisal work, we are confidently building a comprehensive, long-term, full-field development plan. In parallel, we are constructing a large scale infrastructure system to ensure the ability to process and market the full stream of hydrocarbons and to optimize the value of Alpine High.

We have already begun the transition from the test well program. The majority of our wells going forward will begin an optimization program that will entail longer-laterals, larger fracs with more stage density, vertical and horizontal spacing density, and lateral wellbore placement within highly targeted zones.

This morning, in our Financial and Operational Supplement, we provided results on three new test wells. Two of these wells, the Chinook 101AH and the Blackhawk 5H were drilled to the Woodford and Barnett formations, respectively, in an area where the source rock sequence is quite shallow.

These wells achieved higher 24-hour oil IP and higher oil cuts than any of the wells drilled, completed and disclosed (15:46) to-date. This further validates our geologic and thermal maturity models, which predicted that the source rock would produce more oil and higher BTU gas at shallower depths.

The third well we announced today, the King Hidalgo 3H in the southern portion of Alpine High, was an offset to our previously disclosed 9H well. You may recall from the disclosure in February that we did not believe the 9H well was drilled on an optimal azimuth, as it was drilled before our 3-D was fully processed and interpreted.

In the 3H well, we reoriented the lateral and more than doubled the IP rate of the 9H. Tim Sullivan will provide more detail on all three of these wells. I would just reiterate that these wells are still representative of our testing program.

And while we believe they are economic as drilled, the rates do not represent the capability of optimized Alpine High development wells. You can expect future disclosure to contain well results with more optimized completions. To-date, we've drilled more than 40 wells at Alpine High.

We currently have four wells producing and 22 wells shut-in or curtailed awaiting infrastructure. Additionally, there are a number of wells in flow back, completion or drilling. We look forward to bringing these wells online, optimizing liquids recovery and demonstrating their potential.

I would now like to transition briefly to Alpine High infrastructure. Our midstream facility construction represents a strategically important investment and has proceeded extremely well. Delivery of the initial phase of the buildout was significantly ahead of schedule and under budget.

We first broke ground on our infrastructure at Alpine High in November, and since that time have installed approximately 14 miles of 30-inch trunk line for gas delivery, 11 miles of gathering systems, five centralized processing facilities which are in various stages of completion, one water recycling facility, and 10 central tank batteries in various phases of construction.

Initial gas sales began this week at a rate of around 20 million cubic feet of gas per day. This volume should ramp up to more than 50 million cubic feet of gas per day by the end of June. We're also making good progress on drilling operations at Alpine High as we continue to climb the learning curve.

Tim will have more details on our recent well costs, and how that will change as we transition to more optimized wells in the future. Finally, we recently strengthened our organization on the midstream and marketing side. Last week, we announced the appointment of two highly experienced executives to the team.

Both of these individuals bring a deep understanding of midstream and marketing activities in North America, broad business development experience, and extensive end user relationships to complement our team.

These additions will significantly strengthen our commercial capabilities as we ramp up production at Alpine High and continue to evaluate future alternatives for the midstream business in Apache. To sum up Alpine High, this is a massive hydrocarbon resource and we believe we control the vast majority of it.

A play of this size takes time to properly delineate and optimize, but our progress, since the initial announcement eight months ago, has been exceptional. To-date, we've confirmed a highly economic wet gas play with a minimum of 3,000 locations.

The economics of the wet gas portion of Alpine High are greatly enhanced by its oil content and the high-quality NGLs demonstrated in many of our test wells to-date. As we complete our delineation, we believe the wet gas location count will rise significantly.

And as we test shallower zones and geologic settings, we believe that oil locations will also be added. In closing, we hit the ground running in 2017, and we are delivering on the production, capital spending and LOE targets we established in February.

We're pleased with the early start-up of Alpine High, our under-budget delivery of the midstream side, and the associated increase in production guidance. We look forward to providing further updates in the near future. I will now turn the call over to Tim to provide more operational details..

Good afternoon. In my remarks today, I will highlight operational activity and key wells in our focus areas. I will also provide an update on service and supply costs, along with the actions we're taking to address inflation. Our first quarter results reflect the impact of reduced CapEx and development activity during 2016.

These effects will linger into the second quarter of 2017. Then, we begin our shift to a growth trajectory that you will see in the third quarter and subsequent periods. We began expanding our drilling program in the Midland Basin beginning late in the fourth quarter, increasing from two rigs to the current count of six.

These operations feature pad drilling, which can take longer to see production results than with the single well, but is a more efficient way to produce hydrocarbons and helps us preserve the lower cost structure we achieved last year.

During the first quarter, North America production averaged 252,000 barrels of oil equivalent per day, a 3% decline from the fourth quarter 2016. Most of this decline comes from lower volumes in the Midcontinent, Gulf of Mexico and Canada regions, where we limited investment.

We continue to build momentum in the Permian Basin, where production of 148,000 Boe per day in the first quarter was nearly flat with 149,000 Boe reported for the preceding period. The Midland/Delaware basins contributed approximately 85,000 Boe per day to this total in the first quarter.

The main highlight from the Midland Basin this quarter is the start-up of production from the six-well Connell 48 pad at Powell Field in Upton County. These wells have oil cuts of approximately 80% and have produced at very strong initial 30-day average rates 6x wine-rack spacing in two landing zones in the Wolfcamp B formation.

The Connell 48 pad features mile-long laterals as we're conducting spacing tests on the pad. The flow rates on a per thousand foot basis are impressive. They are outlined in our first quarter Financial and Operational Supplement.

Going forward, in the core of the Midland Basin, we expect two-thirds of our wells to have extended laterals of approximately 1.5 miles or longer. Following Connell 48, the rig moved to the Connell 47, a six-well pad where we'd be testing tighter 8x wine-rack spacing in two Wolfcamp B landing zones.

We are in very early flow back on the Schrock 34 pad in the Azalea area on the border of Midland and Glasscock counties. This includes nine wells drilled with 6x wine-rack spacing in intervals of the Wolfcamp A1, B1 and B3 formations.

Turning to Alpine High, included in our first quarter Financial and Operational Supplement are results from three recent test wells at Alpine High. The Chinook 101AH produced at a peak 24-hour rate of approximately 8.5 million cubic feet of rich 1,300 BTU gas and 620 barrels of oil.

At a depth of 10,100 feet, the Chinook is our shallowest Woodford test to-date. This is an excellent result, particularly when considering that it is an unoptimized test well with a 4,500 foot lateral and a smaller standardized frac. The Blackhawk 5H was completed at a depth of 9,760 feet and is our shallowest Barnett well disclosed to-date.

This well produced at a peak 24-hour rate of 742 barrels of oil and 5.3 million cubic feet of rich 1,300 BTU gas. Like the Chinook, this was an unoptimized test well. Moving to the southern end of Alpine High, we drilled the third well disclosed this morning, King Hidalgo 3H in the Woodford formation.

This was an azimuth test well offset to the previously disclosed King Hidalgo 9H well. The 3H, at a depth of 13,000 feet, recorded a 24-hour peak rate of 7 million cubic feet of 1,200 BTU gas and 72 barrels of oil. The much stronger performance of the 3H proves that azimuth is critical in optimizing flow rates.

Because our initial test wells have been quite deep in the Hidalgo area, we didn't expect to encounter a cooler temperature regime. This enabled liquids production and indicates that there will be significant amount of up-hole zone with potential for higher liquid cuts.

For comparison, recall that we encountered dry gas in the Redwood unit at a similar depth in the northern portion of Alpine High. The cost story at Alpine High is also very positive. We recently drilled a pacesetter well with a 4,600 foot lateral in just 13 days, from spud to TD, at a cost of approximately $2 million.

Regardless of the ultimate completion size and technique, all-in costs for this type of a well should fall comfortably in our targeted range of $4 million to $6 million. The result we see in our test wells at Alpine High continue to give us confidence that this will be one of the lowest cost, wet gas plays in North America.

We look forward to demonstrating this later in the year with optimized drilling results. I will turn now to our international assets. Adjusted production in Egypt declined approximately 2% from the fourth quarter 2016 to 88,000 Boe per day. We drilled 18 wells in Egypt during the first quarter with a 72% success rate.

Highlights from this program include development wells at Berenice 6 in the Faghur Basin with a 30-day average IP of nearly 3,760 Boe per day; the Phiops 11, which achieved a peak rate exceeding 3,400 Boe per day in the Shushan Basin; the Ptah 7, which achieved a peak rate of more than 3,330 Boe per day in the Faghur Basin; and the Herunefer 3, which achieved a peak rate of more than 3,100 Boe per day in the Matruh Basin.

In the North Sea, our production declined to 58,000 Boe per day as operations were impacted by a mechanical issue on the Beryl Alpha platform during the quarter. We also experienced some underperformance on a few gas-prone wells in the Beryl area. Oil volumes were generally in line with expectations.

Progress on the Khalda Development continues on schedule for start-up in the third quarter. We have moved up our North Sea facilities' annual turnaround activity to accommodate hookup and commissioning with the new subsea tieback.

While this turnaround and facility work will impact second quarter production, it should help reduce overall planned downtime at Beryl for the year. Please refer to our Financial and Operational Supplement for more details on our first quarter production. I'll move now to service costs.

We continue to see pricing pressure for certain services and supplies, which we planned for in our 2017 capital budget. Cost escalation is most apparent for pressure pumping, premium drilling rigs, and sand in the Permian Basin.

Anticipating this, we implemented a number of strategies to keep our cost structure low and minimize the impact of inflationary pricing. This includes leveraging our size as one of the most active drillers to achieve volume discounts, and we've also unbundled services.

We're working with a wider assortment of vendors who want to work with Apache as we can provide a more continuous, steady program than other operators with smaller footprints. We have also signed agreements for pressure pumping services and sand that index prices to WTI, providing a win-win outcome for us and our vendors as commodity prices improve.

In these agreements, we have seen very little cost increases thus far. On the sand side, we're self-sourcing product by buying almost exclusively native sand, mined close to the operations. Our test indicates that we are achieving effective results with this product, and it significantly reduces our transportation costs.

Vendor competition is good for Apache and healthy for the industry. We found that we can achieve good results safely and economically, sourcing more work to new and different providers. I will conclude by noting that we are pleased to be increasing activity in North America at a measured pace with the focus on generating strong fully burdened returns.

As indicated by our guidance, growth will follow in the second half of 2017. Despite industry cost pressures, we believe our 2017 North America operations will be more productive and capital efficient than in previous years. I will now turn the call over to Steve..

Thank you, Tim, and good afternoon, everyone. On today's call, I will review our financial results for the first quarter, update a few 2017 guidance items, and discuss Alpine High midstream and marketing activities.

Beginning with the first quarter financial results, as noted in our press release, Apache reported net income of $213 million or $0.56 per common share. Our results for the quarter include a number of items outside of our core earnings that are typically excluded by the investment community in published earnings estimates.

These items include a $222 million gain on sale after taxes for the recent non-core asset divestitures John mentioned earlier. When excluding this gain and other smaller items, our adjusted earnings for the quarter were $31 million or $0.08 per share.

Note, this adjusted earnings amount still includes dry hole costs which amounted to $40 million or $0.10 per share after tax, which Apache does not include in its guidance and is not typically modeled by analysts. Cash flow from operations in the first quarter was $455 million.

Before working capital changes, Apache generated $730 million in cash flow. The significant working capital used this quarter is primarily related to the payment of expenses accrued at year-end 2016.

With the proceeds received from non-core asset sales, we increased our cash position to $1.5 billion at quarter-end and reduced net debt to just under $7 billion. Our Oil and Gas capital investment for the quarter was $646 million.

This was below our expectations due to capital activity being delivered under budget, as well as movements in the timing of certain spending to later in the year. For reasons outlined by John, our full year capital investment guidance remains unchanged at $3.1 billion.

Turning to costs, lease operating expenses in the first quarter were $7.76 per barrel of oil equivalent, approximately 8% lower than the fourth quarter of 2016. We made tremendous progress on LOE over the last two years, and we are focused on retaining as much of that improvement as possible despite inflationary pressures.

These efforts, combined with increasing low-cost Alpine High volumes, are bringing LOE expectations down. As a result, we are revising our full-year 2017 guidance range for LOE per Boe down to $8.25 to $8.75 per barrel of oil equivalent. Lastly, exploration expense in the first quarter was $92 million.

$67 million of this was attributable to dry hole expense and small amounts of unproved leasehold impairments. For the full-year 2017, we previously guided to $150 million of exploration expense excluding dry holes and unproved impairments. This guidance remains unchanged.

For all other expense items, our first quarter and full year results are generally on track; and thus, our full-year 2017 guidance is unchanged. Please reference the quarterly supplement for a summary of our guidance. Next, let me turn our midstream and marketing activities at Alpine High.

On the midstream side, we are well into a multi-year infrastructure buildout to serve the long-term needs of Alpine High. While there are significant industry infrastructure around the Permian Basin, Alpine High requires extensive in-field processing capacity and transport to market access.

Last year, our early testing demonstrated the enormous resource potential of Alpine High. As plans for full-field development materialized, we made the decision to build the infrastructure ourselves.

It is strategically important to control the scope and pace of the buildout, and we are confident we have the capability to manage a project of this scale. The start-up of gas processing this week ahead of schedule and under budget reinforces that confidence.

Looking ahead at our future infrastructure buildout plans, a high-pressure gas trunk line system, through our acreage, should be mostly complete by the end of 2018. We will have a 30-inch line that connects to three market pipelines to the north, and a 30-inch line that connects to one market pipeline to the south.

To accommodate longer-term volume growth, completion of the third line, running from Alpine High to the Waha Hub, is anticipated during 2019. The size of this line has yet to be determined. Ultimately, Alpine High gas will have access to multiple markets, providing significant optionality for gas flow in the future.

The remaining infrastructure, including gathering lines, separation, treating, compression and processing facilities will be built out over time as the pace of upstream development dictates. In the longer term, we will explore the option of installing cryogenic gas processing to extract more NGLs.

In terms of liquids infrastructure, oil and NGLs are currently being trucked, which will continue for the near term. We anticipate the completion of an NGL pipeline, the size of which has yet to be determined, during 2019. We are evaluating options for the NGL line to extend beyond the Waha Hub to access further market optionality.

Finally, there are many options for oil pipeline access, and we are exploring those for future consideration. As we look further into the future, the need to continue owning the Alpine High infrastructure assets should become less important. We see the possibility of a partial or full monetization and are planning accordingly.

In the near term, we are confident this infrastructure project is a compelling investment, both strategically and financially, as these types of assets are generally monetized at very attractive multiples. On the gas marketing side, we are advancing discussions on many fronts and have begun implementing a contracting strategy.

At this point, we have contractual assurance for the sale of most of our Alpine High gas for 2017, and have begun to contract for 2018. We are developing a portfolio of market solutions for Alpine High gas production.

This will include targeting end users across a wide variety of industrial users, such as petrochemical complexes, utilities, and L&G exporters. It will also include access to gas markets that can deliver higher net backs. Specifically, this will require the ability to move gas away from the Waha Hub to places such as the Texas Gulf Coast and Mexico.

Today, we are receiving a Waha base price for our natural gas. Since Apache announced the Alpine High discovery, more than 10 pipeline projects have been proposed and/or under review to expand takeaway capacity out of the Permian Basin.

We expect at least two of these pipelines will be constructed with estimated in-service dates of mid-2019 to early 2020. While there has been some recent volatility in widening in the Waha base's differentials, additional transportation capacity to the Texas Gulf Coast should help alleviate the situation.

In closing, it was a good first quarter for Apache financially, and we are demonstrating excellent capital cost and operating cost discipline. We've made great progress with our planning and execution on the midstream and marketing side at Alpine High, and I look forward to future updates.

With that, I will turn the call over to the operator for questions and answers..

Our first question is from the line of Bob Brackett with Bernstein..

Alpine High gas takeaway, is that connected to all of the pads or is it focused on some of those pads in the north? How much of those pads can access that market right now?.

Bob, good afternoon. Right now, the first connections have been to the north. We've got one central processing facility up there that's up and running. So we've got just a handful of wells that we're bringing on initially. We're significantly ahead of schedule. And so, we've started in the north, but it will expand pretty quickly..

So that 50 million cubic feet a day by end of June is coming from a handful of wells?.

It will be a pretty small number. I mean, actually, right now, we're curtailed by what we nominated. We are flowing close to 20 million cubic feet a day and we'll ramp pretty quickly to the 50 million cubic feet..

Okay. Great. Thanks..

Our next question is from the line of Ed Westlake with Credit Suisse..

A question on Alpine High and balance sheet. So, again, congratulations on the work you're doing there. You talk often about stages per well, longer laterals and optimizing liquids recovery. I mean, the longer lateral math is pretty easy to understand in other plays.

But maybe just some color in terms of where you are in terms of current stages and where you think you will get to? And then, what yield uplift you think you might be able to get as you optimize the equipment on the liquids?.

Ed, we've taken, as you know, a very disciplined approach and all of our wells have been specifically designed to kind of mirror each other in terms of the completion. So they've been, what we call, test wells. They've had relatively strong small fracs, very few stages.

And we've done that purposefully, so that with the changes we can see what the rock was telling us, not as you start getting real fancy on your completion. So the nice thing is, we said earlier, this year we were transitioning. And by getting the infrastructure on it, it lets us flow gas early and start to sell some liquids as well.

But more importantly now, we're not going to be limited by flaring and other things. So we've transitioned. As we start to bring some of those wells on and start to disclose some of those rates, we'll start to give some of the comparisons. But we expect a pretty material uptick from what we've been using as our standard completion..

And then, just on the balance sheet. I mean, obviously the whole sector's down, oil is down. Therefore, we don't have a real view on the commodity, but you've still got $1.5 billion of cash.

You've spoken about capital flexibility, but also perhaps disposals, maybe just what is the rainy day plan?.

Well, I mean, if you look at what we did this year, we (41:04) for the back half of the year to protect us at $50, which is our plan. So we feel really good about this year's capital program because we've got a lot more exposure to oil price than we do gas price. We do have $1.5 billion of cash on hand.

We sold $440 million of predominantly non-producing acreage, some things that we weren't going to get to for a long time, probably five, six years, if ever. And so, that's helped us. I think the big thing is, is we've taken a very measured approach.

I mean, we've got a very robust inventory and our guys are chomping it a bit to do more on the capital side, but we've just taken a pretty measured approach. We want to be focused on the cost side, focused on the discipline and ramp up slowly, which is kind of the approach we've taken.

So we feel good about where we sit right now with where commodity prices are. Again, there are some other things we can do as we continue to look at the portfolio, but we feel really good about where the balance sheet is. I don't know, if you want to add anything, Steve? Okay..

Thank you..

Our next question is from the line of Brian Singer with Goldman Sachs..

Thank you. Good afternoon..

Hello..

A couple of questions on Alpine High. The first is, you've talked about that comprehensive development plan.

Can you give us a little bit more color on what that looks like? Specifically, if it includes the Wolfcamp and Bone Springs zones? And then, what the milestones are in those zones to get from today to developing more oilier areas?.

The thing I would say, Brian, is it's a live product for us. As we continue to get more data, it becomes more expansive. The best thing I would say is, look to the guidance. If you go back to the start of the year, we gave you Midland and Delaware and we gave you a look through the fourth quarter of 2018.

And, obviously, we've got a lot of wells that we're drilling. We drilled over 40 wells. With the three we announced today, we've now disclosed I think 19 results. And we're starting to bring some of those on, and we've got a lot of wells that are in the queue.

They're either flowing back now, shut-in and waiting to be produced, being completed, or drilling. So I think it's going to be an exciting next couple quarters for us as we bring forward a lot more information. But we are very optimistic, as we stated, about the parasequences, the Wolfcamp and the Bone Springs.

We've done a lot of integrated work on the geology, the modeling, integrating 3-D seismic; done a lot of work. And I think we've done our homework and we've got some exciting appraisal wells that are in progress..

Thanks.

And then, if we look back on some of the older Alpine High wells, what are you seeing on the decline rate side? And because some of these wells are constrained, would we expect a lower decline rate than the decline rate that we would see in the development plan?.

Brian, most of the wells that – after we've kind of stabilized test rates on them, we shut most of the wells in. So we have not been producing those. I mean, when you're flaring gas without the ability to sell the gas, then you'd be paying royalty that did not make sense. So we shut most of those wells in.

And, obviously, this week we've started to open some wells back up. So we're very anxious to produce. I can tell you, the early responses look really good. A lot of flush liquids and some exciting stuff..

Great. Thank you..

Our next question is from the line of Scott Hanold with RBC Capital Markets..

Thanks. Good afternoon.

On the Chinook and the Blackhawk wells that had the oil condensate rates, can you give us a little color in terms of the gravity of the oil? Did that fall in line with your expectations or was that a little bit higher than anticipated?.

No. Well, first of all, Scott, it's oil; it's not a condensate. It's very stable. And, yes, it fell in line with our models. So no surprises. The gas BTU content gets heavier as we move up and the oil gravities are getting lower as well, which is a really positive sign. I think one of the keys for us will be getting things into the processing facilities.

When you're catching (45:45) on those, it's hard sometimes and there is room for error within those test samples. But everything really, really fits our maturity model and our geologic models very tightly. So we're very excited about the predictability in the transgressive source intervals..

Okay.

And, outside of the test rate, were you able to flow those wells a little bit or are those shut-in like you mentioned due to the infrastructure constraints?.

No, those wells have been flowing over the last several days. And so, we have been flowing those wells. And, quite frankly, we will be able to move the into facilities pretty early this quarter..

Okay.

Any color on some of the productivity, post the initial test rates?.

No, it looked good. I mean, we're very excited about it. So one of the keys is, we need to get the facilities, get everything tied in and run them through properly, because then we can really start to dial down in what these things are going to do.

But we're very encouraged, and it was predictable to see as we moved up the column with the lower temperature. We knew they were going to get more oily, which is the case. And there's a lot of real estate above us and a lot of other zones to test as well. So, I mean, it's very exciting..

Okay. And if I could just quickly on the gas sales contracts. I think you all said that you had most or all of 2017 locked up and looking at 2018. Who are you signing up the contracts with for 2017? What type of end users, not maybe specifically, but if you can generalize that for us..

Yes. No, we're not at this point disclosing exactly who we're contracting with, but there are lots of player in that area.

So you can count on the fact that we're – as I said in my script, we're looking to have a pretty good size portfolio of various solutions on the contracting side, both in terms of transporting product, as well as marketing it to various forms of users.

And we do have contractual assurance, as I said, for the vast majority of our volume for 2017, as much as we think we can be capable of producing this year. And part of that contract goes into – or part of the contracting that we've done so far goes into 2018 as well..

Okay. Appreciate that. Thank you..

Our next question is from the line of John Herrlin with Soc Gen..

Thank you.

With respect to the cryogenic units at Alpine High, can you give us a sense of how big you're contemplating? Or you're going to do skid units or you're going to do some large centralized units?.

Yes. John, it's early. We've got some time. I mean, it's really an option for us. So as we start to pull the processing facilities, get them all up and running, that's one of the things we've got tabled to make a decision on. Really, we could pull the trigger on it at any time, but we will look at what's optimal.

I mean, the nice thing about this resource play is we've got a wide range from pretty much dry gas in some areas up to the north, to very, very wet gas. So I don't envision it being an all-or-nothing decision on the cryo, and it's just one of the things we've got tabled to do later..

Okay. That's fair.

And then, in terms of monetizing this down the line, I would assume that this is several years out because you want to control your growth right now of the infrastructure in terms of going in a healthy route or whatever?.

I mean, I think if you look at what some of the transactions that have been recently done out there, they're significant value. I mean, I think clearly right now as we're ramping up, now would not be the time. But I think as you get out past a year from now, you could easily be in a window where you could consider doing something.

I don't know, Steve, if you want to add anything further?.

Yes. John, I think ultimately the answer to that is going to be both a strategic answer and a financial answer. I think John is exactly right. By the time we get into – well, into 2018 financially, we'd certainly be capable of monetizing this at a pretty attractive price. And then, it'll come down to the question of strategically is it the right time.

And you're exactly right, there's – as I said in my comments, it's strategically important for us to control this at this point in time and the ability to start it up two months early and the flexibility that we have around constructing. It's a pretty sizable project. It's proven to be pretty important that we had complete control over that.

So we'll continue to monitor that both strategically and financially, and combined, we'll make the decision as to when and if we monetize it..

Okay, great. Thanks, Steve. One last one for me.

Do you have any sense of the notional value of what your hedges are right now for the oil?.

I haven't looked at them today, but they're probably worth more today than they were last week..

Okay. That's fair. Thank you..

Our next question is from the line of Phillip Jungwirth with BMO..

Good afternoon..

Hello..

We're starting to see industry activity, whether it's permits or rigs, into Jeff Davis County. And I know this isn't an area where you guys lease.

But curious as to your view on how the play changes as you move west of your position? And why this wasn't an area that, had you focused on when you initially built this position?.

Well, I mean, what I would say, Phillip is, is obviously since we put the play together grassroots, did a lot of work upfront, went out and leased what we felt like we wanted, shot a massive 3-D over the entire area. I think we like our position. As I said in our comments, we think we've leased the lion's share of the Alpine High.

So, clearly, there's a lot of other targets and a lot of things, and you see a lot of activity picking up around us. But we like where we are and consciously leased what we wanted to lease..

Okay, great. And then, in Suriname, just curious as to your thoughts on farming down some of your 100% interest in Block 58.

And then, given that dry hole costs in this area are relatively inexpensive, how would that factor into your consideration?.

The Kolibrie well was a well we needed to drill. We've learned a lot about the basin from that well and gained some very, very valuable information. Right now, I am also glad that we drilled that well with, what I'll call, 45-cent dollars as we had a 45% interest in it. And our dry hole cost was significantly lower.

It came in around $20 million versus a budgeted number of around $37 million, so relatively much cheaper. What I would say is, is we're working on next steps at Block 53. We've got time on Block 58. We've shot the 3-D, we're processing it, we'll have that done sometime this year.

We're very encouraged by what we see on Block 58, and we'll just leave that for another date..

Great. Thanks..

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

Arun Jayaram from JPM. Challenge....

Hey, Arun..

How are you doing?.

Good..

I was wondering if you could help us think about, on a go-forward basis, what the cost structure is going to look like at Alpine? I am just trying to think, your cash flow per Mcfe kind of margins, as you start getting into 2018 and start to dial the volumes up.

So can you help us think about the cost structure for Alpine High?.

Yes, Arun. This is Steve. I think the best place to go and get that would be in our Barclays pack that we used, the slide deck that we used. Go to that one slide on economics. I think from there you can get the cost per barrel.

It's in the fine print on that slide, but be sure you add $500,000 per well for infrastructure costs, because it's included in the economics that we ran, but not included in the well costs that we published on that day. It does give you the $4 million to $6 million per well on the high-end and low-end.

Add $500,000 to that, you've got estimated EURs and, therefore, you'll have estimated production mix from that. Today, we're selling oil basically at WTI. We are selling NGLs at about – we've been selling it anywhere from 45% to 50% of WTI. And you could probably use Waha Hub as pricing for the gas. So you'll get a mixed price per barrel equivalent.

And I think you can use your typical gas field type of cash costs on the operating side. And I think when you do that, you're going to find a pretty darn attractive ratio of the cost per barrel to cash margin per barrel. That would probably compete with anything you're doing on a more oily basis in the rest of the Permian Basin.

You'll see from that why we're so excited about the economics of this wet gas play..

Okay.

But maybe details on – your thoughts on the LOE versus the GPT on Alpine High?.

No. We're not really sharing any of that right now. But I think you can count on the fact that the LOE per Boe is going to be low, especially for the next several years, as we drill some fresh wells, get some flush production going. And it's going to be, I think, a typical LOE on a robust gas field..

Okay. Fair enough..

One of the pluses, Arun, is you don't have a lot of water in the lower source intervals, which is all we've talked about in the economics. So we're not going to have the water handling challenges that you have in northern parts of the basin. Now, if we start to bring forward some of the parasequences, there may be some more water with some of those.

And so, that's one of the reasons why we'll bring some of that data forward in the future..

Okay. Fair enough.

And just switching gears a little bit, in terms of the new concessions in Egypt, at what point, John, do you think you'll be able to drill some wells on these new concession areas?.

Well, we expect those to be awarded some time pretty quick, this month or next month most likely. I think we could be actively planning to drill this fall, is the plan. So we're very, very excited about those concessions. A big uptick. We have not got two new onshore concessions in the Western Desert since 2006.

And we see a lot of low-hanging fruit and a lot of really neat stuff to go after. So we're chopping it a bit to get our hands on those concessions. We're going to do a lot for our Egypt inventory..

All right. Thanks a lot..

Thank you..

Our next question is from the line of Bob Morris with Citi..

Thanks. John, it wasn't clear on the processing or the handling of the NGLs, when you would have that processing capacity in place to begin moving and selling NGLs.

And if you're initially going to be installing cryogenic plants or just going with cheaper lean oil plants to start with on that?.

We will have refridge in the processing facilities. We've got one up, it's up and running now, that we are working through, kind of lining it out. So we will be selling NGLs. Have been selling some off to some of these skid-mounted units we've had in the field as well.

So, as Steve said, we've kind of been receiving anywhere from 45% to 50% of WTI for those NGLs. And, right now, our plans are for refridge in the field. And with the decision to be made on cryo, as I said, when Mr. Herrlin asked the question, later this year, early next year, sometime in the future on the cryo decision..

Okay. Great. Thank you..

Our next question is from the line of Charles Meade with Johnson Rice..

Good afternoon, John, to you and the rest of your team there. I wanted to ask a question about the Hidalgo pad, the King Hidalgo pad, and the uplift you guys saw on the 3H versus 9H. As I adjust for lateral length there, it looks like there's an uplift of about 60% just from adjusting your azimuth.

And I am curious, is that indicative of the uplift you think is available through most of Alpine High by optimizing your azimuth? Or is there more something visible particularly to this area that made the azimuth more important down here?.

Well, what I would say, Charles, is targeting is always critical in the productivity side, especially when you have rock like this. I mean, we've got a very provable area down there. We knew the azimuth, because we spud that well. We had done some before we had gotten our 3-D processed and really worked through it.

So we knew it was on the wrong azimuth. We disclosed that back in February when we disclosed it, and we knew it would make an impact. So it is one of the key things.

And when we talk about – even mentioned it in the press release today – when we talk about moving into more optimization, that's one of the things we're going to be doing, too, is tweaking the targeting. And it matters a lot.

And getting things on the right azimuth, that's one of the big pluses to having such a blockey acreage position because we can do this the right way, not trying to drill down lease lines and so forth, like you do in a lot of other plays..

Got it.

So is the stress field pretty tricky across the whole play, or is it more just kind of – as you get more structurally complex that it becomes an issue?.

It will change based on the geologic setting and it changes within the setting. So it's one of the things that you have to do a lot of integrative work to fully understand, like anything else. But the 3-D is pretty helpful to understanding that and seeing what some of the substructure is doing, is pretty key to understanding that..

Right, right. And then one last quick one.

The pace of your divestitures, how are you thinking about that? Is that something that we should expect an ongoing kind of steady pace on that? Or is that more opportunistically driven in that case may be attached to oil prices?.

No, I mean, it's more opportunistically driven. We continue to look at our portfolio. As we build out more optionality and more inventory, there are things that we look at today that in the past we might have thought we would've funded that we won't get to. And so, we don't have anything set out there that we're saying here's what's going to be next.

But I'll just say we're actively looking at our portfolio and managing it, and it would be more opportunistically in terms of what we decide to put out there..

That's great detail. Thanks, John..

And our last question comes from line of David Tameron with Wells Fargo. David, your line is open..

Thank you. I was on mute. A couple of questions, John.

North Sea, can you just talk about the production? I think there were some outages, but can you talk about the production quarter-to-quarter and what happened there?.

Yes, David. In January, we had an upset at Beryl Alpha and the whole platform went down. We lost about 18 million cubic feet a day for the month of January. And then, we drilled a couple of non-commercial wells, and then we had a couple of wells that under-performed in the first quarter and that's what's causing our issue.

But keep in mind we've got a calendar coming online start of the third quarter. We're very excited about that. And then, we had really a tremendous quarter in Egypt with a lot of successes not only in our development program, but in our exploration program.

Got 13 wells online there and we've got a number of wells that will be coming online in the second quarter. So as a result of all that, we did not have to do anything with our guidance. We left guidance unchanged for international..

Okay. That's helpful. Thanks. And Alpine High has been (01:03:56). John, so just a comment you made about service contracts, I don't know if that was you or Steve that made the comment, but about linking those to WTI.

What percentage would you say – is it something that you envision going meaningfully higher like structural change and the way prices are set going forward? Or is this just kind of a one-off? Or how should we think about this in the big picture context?.

No, I mean, I think there's an opportunity in some cases to turn it from a win-lose into a win-win.

And we've sat down and had some pretty grownup conversations with some of our bigger service providers that do a lot of different things for us and have tried to find ways where you tie things more to the oil price rise, where both sides are happy than you are directly with demand.

Because, as you know, as we saw in late-2014 and demand can oftentimes outrun the rise in terms of what the commodity price is doing. So I think we're trying to do some things more in a way that's going to create a win-win or we can put some equipment and crews in place and let them work for a long, long time for both companies and be happy with it..

All right. Thanks. That's all I've got..

Thank you..

That is all the time we have for questions today. I'd like to turn the call back over to Mr. Clark for closing remarks..

Well, thanks, everybody, for joining us on a busy earnings day. There were number of analysts left on the queue. So if we didn't get to your question, please feel free to call myself, Patrick or Kian, and we'd be happy to follow up with you. Talk to you all next quarter. Thanks..

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