APA Corporation (APA) Q3 2017 Earnings Report, Transcript and Summary

Good afternoon. My name is Jennifer and I will be your conference operator today. At this time, I would like to welcome everyone to the Third Quarter 2017 Earnings Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. And I would like to turn the conference over to Mr. Gary Clark. Sir, you may begin.

Good afternoon, and thank you for joining us on Apache Corporation's third 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 have had the opportunity to review our third quarter financial and operational supplement, which can be found on our Investor Relations website at investor.apachecorp.com. 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 actual results to differ materially from what we discuss today. A full disclaimer is located with the supplemental data on our website. I will now turn the call over to John.

Good afternoon and thank you for joining us. On today's call, I will discuss third quarter results and accomplishments, comment on our Midland basin oil production and development program, recap some of the key Alpine High points from last month's webcast and provide an update on our 2018 planning process and current thinking around commodity price assumptions. Beginning with the third quarter, as anticipated, our average daily net production in the US returned to a growth trajectory. We also grew net production in the North Sea and gross production in Egypt. Production was in line with our guidance with notably strong performance in Permian oil volumes. We stated in our webcast update last month that we expect this performance to carry through into the fourth quarter with Midland and Delaware oil production tracking at the high end of the guidance range, established back in February. As we also noted, the delayed start-up of two central processing facilities at Alpine High caused by Hurricane Harvey will defer some natural gas volumes into 2018. So, our updated fourth quarter production guidance is unchanged. In the Midland and Delaware basins, we are benefiting today from the strategic testing, optimization and development planning initiatives that we implemented in 2015 and 2016, while running a very lean capital program. Going forward, we anticipate continued capital efficiency gains in both the Midland and Delaware basins. This is particularly true at Alpine High, as we move further into multi-well pad development, continue to extend average lateral length, utilize more smart completions and further optimize our landing zone targeting and well spacing. The majority of optimization benefits, which have been proven in other unconventional plays are still ahead of us at Alpine High. On the international side, cash flow generation during the third quarter was strong once again, as both Egypt and the North Sea benefited from improving Brent crude prices and production from our Callater startup in the North Sea. Overall, capital investment was in line with expectations and remains on track with our guidance for the full year. We have shifted some capital in the back half of 2017 from our international regions into the US to take advantage of attractive portfolio opportunities in the Permian Basin. Finally, we continue to benefit from our cost structure focus with both LOE per BOE and G&A costs remaining low as a result of the significant rationalization efforts over the last two years. Apache also made some excellent progress this quarter with regard to its portfolio transition. Specifically, the discovery of Alpine High enabled our strategic exit from Canada. In only one short year, we will have completely replaced our Canadian production and we will have done so with an asset that offers significant returns and is only just beginning to show its enormous long term potential. Value creation and returns accretion were challenged in Canada, given this low ratio of cash margins to F&D cost. Alpine High on the other hand will have significantly lower F&D costs, much more attractive cash margins and will transform Apache's long term return on capital employed profile. Organic portfolio transformations like this take time, but are much more accretive to returns than acquiring high priced proved acreage positions. I will now turn to the Midland Basin where activity is primarily focused on multi-well pad drilling to the Wolfcamp and Spraberry formations. Our third quarter oil production was up approximately 5,500 barrels per day over the second quarter, as we are delivering excellent results from recent multi-well pads in our core areas. We will continue to progress our development efforts with two more pads coming online before year end. Our focus in the Midland basin is on multi-well pads and full field development. We believe the proper approach to an unconventional resource has developed each section in a way that optimizes long term value and returns. This requires a full understanding of intra-well dynamics and proper spacing in order to design development patterns that optimize costs and recovery. Additionally, Apache utilizes a fully burdened returns approach, which should give you confidence that the anticipated returns will result in a competitive return on capital employed at the corporate level. Tim will share more details on the impressive progress we have made in our Midland basin development efforts. Next I would like to move to Alpine High and reiterate a few of the key points made in last month's webcast. First, Alpine High consists of three primary plays, a highly economic wet gas play that contains the majority of our currently identified locations, a dry gas play that is smaller, but very economic and an emerging oil play with tremendous future potential. Second, we increased our location count from 3000 to more than 5000, which consists of at least 3500 locations in the wet gas play, at least 1000 locations in the dry gas play and more than 500 locations in the oil play. As we have previously discussed, we believe there is significant upside potential to all of these location counts. Third, 90% of our currently disclosed locations are in the highly predictable and repeatable transgressive source interval, which consists of the Woodford, Barnett and Penn formations. Being a true source interval, there is minimal in situ water that will be produced with the hydrocarbons. Water handling and disposal costs are becoming a significant challenge across the Delaware Basin and this will only get more difficult in the future. We are fortunate to not have this problem in the transgressive source interval. Fourth, returns of Alpine High are driven by the combination of extremely low development costs with attractive cash margins. Recent wells have validated our assumptions on future drilling and completion costs. Cash margins will be attractive due to the high quality liquid content and the low operating costs. Lastly, we are very pleased with the performance of the wells of Alpine High, many of which have been producing now for several months. Cumulative production data is confirming our expectations for this high quality rock, which was predicated on extensive geologic, geophysical and reservoir engineering work. Our investment economics are robust for all three plays at current or lower commodity prices and are consistent with those presented more than a year ago. Next, I'd like to discuss the process we are undertaking as we finalize our 2018 plans. Since the beginning of 2015, we have operated Apache with a fundamental belief that over a typical run of years, it is both possible and appropriate for an E&P company to live within operating cash flows. Within cash flow, a company should be capable of growing production volumes and delivering competitive rates of return above its cost of capital, while also increasing return of capital to shareholders through dividends and/or share buybacks. We have taken a number of transformative steps over the last three years, designed to enable this vision, irrespective of the oil and gas price environment. We streamlined our portfolio and strategically shifted our asset base, reset our overhead and operating cost structure, dramatically reduced our capital investment program from mid-2015 through 2016 to live within cash flow, implemented a rigorous capital allocation process based on fully burdened returns as opposed to fundamentally flawed half cycle economics and reduced debt and preserved our dividend without issuing equity and diluting our shareholders' future ownership. Recently, we have been on the road meeting with shareholders and other long term oriented potential investors. Encouragingly, the market sentiment is becoming more aligned with Apache's philosophy. For most of the last three years, the E&P industry has been engaged in excess spending to drive short term oil growth. Today, we are seeing a return to the fundamentals of capital discipline and focus on long term returns. We welcome this change and believe it is very constructive for the long term health of our industry. So as Apache enters the 2018 planning season, we are experiencing some natural, but very positive short term budget tension. That is, do we continue investing in our attractive Permian upstream opportunities at what we consider to be the optimal pace for delivering the long term returns or do we pare back and manage the program for cash flow neutrality. That is a nice problem to have and as an expected outcome of discovering and bringing into development a large low cost new play. We believe Alpine High is a compelling world-class resource. Once ramped to its production potential, Apache will benefit for decades from high returns and free cash flow from a significant portion of our future capital employed. Given the dynamic nature of our opportunity set and the volatile commodity price environment, our 2018 capital budget is still being rigorously worked. Consistent with previous years, we will issue our 2018 budget and associated guidance in conjunction with our fourth quarter earnings results in February. As we have in each of the past three years, we will base our 2018 plan on benchmark pricing that is slightly on the conservative side of the prevailing strip. Given the recent volatility in oil prices, this means we are preparing for a number of possible scenarios. Fortunately, we have considerable portfolio flexibility. Our focus now is prioritizing next year's activity and identifying areas where the capital program could be pared back. While spending could be lower in 2019, the allocation of capital across the portfolio would likely be very similar to 2017 with Permian Basin investment representing the majority of Apache's capital program. Internationally, we will continue to invest to maintain current levels of free cash flow. At recent oil and gas prices, this spend is in the $700 million to $900 million range. In 2018, we will also continue to fund the Alpine High midstream buildout as this is strategically important to enable an optimized upstream development program. As we have stated previously, we believe this represents a very attractive investment opportunity and are continuing to review its monetization potential. Finally, like in 2017, we have begun a program of hedging for 2018 and '19. This activity is focused on protecting cash flows to support our near term capital program. Steve will talk more about the details in his prepared remarks. To sum up, the third quarter was important for Apache as it marked our strategic exit from Canada, the very early stage acceleration of production at Alpine High and a significant turn in our Permian Basin oil production. We're making excellent progress across the company. As the Permian region grows in relative scale with our portfolio, the quality of its returns and cash flows will improve those of Apache as a whole. Our teams have created a deep inventory of investment opportunities, both domestically and internationally. As we have over the past three years, we will fund these opportunities in a disciplined manner that in no way stresses our balance sheet. We look forward to discussing our plan further in February when we will provide a review of our operating cash flow, capital spending and production outlook for 2018, a higher level preliminary outlook for 2019 and potentially beyond, a longer term view into how the investments we're making today will improve long term corporate level returns and free cash flow and a more detailed view into Alpine High for both the upstream and the midstream. Now, I would like to turn the call over to Tim who will provide some operational highlights.

Good afternoon. My remarks today will cover operational activity and key wells in our US and international focus areas and their impact as we plan for 2018 and subsequent years. Our third quarter production results reflect the ramp up in drilling activity Apache began at the end of last year. We have shifted to a growth trajectory and are benefiting from the fiscal discipline and returns focused drilling programs that we initiated in 2015. During the third quarter, we maintained activity at a measured pace, averaging 36 operated rigs worldwide with 17 in the Permian, 4 in other North American areas, 12 in Egypt and 3 in the North Sea. In North America, third quarter 2017 adjusted production average 207,000 barrels of oil equivalent per day, up 7% from the second quarter. Please note these volumes exclude Canada, where we completed our country exit during the period. With the success of our Midland basin drilling program and the continued production ramp at Alpine High, third quarter oil production increased 8% quarter to quarter. Our core Midland Basin assets are the primary contributor to these higher oil volumes. At our Wildfire field in Midland County, we completed seven wells with mile and a half laterals at the June tippet-12/13 pad. The pad comprises four completions in the lower Spraberry with twelve by spacing and three completions in the Wolfcamp B on six by spacing. These wells achieved an average 30-day peak initial production rate of 1058 BOE and fifty per day, producing 83% oil. Also in the Wildfire field, on the Lynch A unit, we drilled a six well lower Spraberry pad, also with 12 by spacing. The wells were drilled with a mile and a half long laterals and average a 30-day peak IP rate of 1142 BOE per day, producing 85% oil. At the Powell field in Upton County, we drilled the CC4045, a six well pad with two mile laterals on 12 by spacing staggered in the Wolfcamp B1 and B3 formations. These wells have been online for about four weeks and are trending toward an average 30-day peak IP rate of 1300 BOE per day with 80% oil. We plan to drill three additional wells on this pad in early 2018. These excellent Midland Basin well results are reflective of our integrated approach to determine optimal landing zones, pattern spacing, lateral length and completion design. At Alpine High, net sales to Apache averaged 13300 BOE per day during the third quarter. As we noted in our webcast last month, we began our fourth quarter, producing at a rate of 20,300 BOE per day and assuming this start-up of the Hidalgo CPF by the end of the year, we anticipate achieving production of approximately 25,000 BOE per day. We continue to make good progress on drilling, completion and cost optimization at Alpine High. We recently drilled and completed three wells with an average lateral length of approximately 4500 feet and for an average cost of $5.5 million. We remain very confident that in our development, we will be able to achieve completed well costs in the range of $4 million to $6 million, which is consistent with the economics we put forward when we announced the play last year. I'll turn now to our international assets. Gross production in Egypt increased slightly to 339,000 BOE per day. Adjusted production in Egypt which excludes minority interest and the impact of tax barrels decreased slightly from the second quarter 2017 to 87,000 BOE per day. The decrease in adjusted production reflects the terms of our production sharing contracts in Egypt, which generally provide for fewer cost recovery barrels to the contractor as the price of Brent index crude oil increases. In the North Sea, production increased 9% from the second quarter to 60,000 BOE per day. Net production from the Callater field is currently averaging approximately 14,000 BOE per day from two wells. A third well, the CB1, was recently drilled into a new fault block and found more than 260 foot of net pay. This well is expected to come online later this month. Please see our financial and operational supplement posted today for more information on drilling and production activity during the third quarter in our US and international regions. I'll now turn the call over to Steve.

Thank you, Tim and good afternoon, everyone. On today's call, I will begin with a brief review of our third quarter financial results, comment on our infrastructure build out and future midstream plans at Alpine High, provide some additional color on certain Alpine High economic assumptions behind our webcast last month and lastly I will update our hedge positions and the continuing strength of our financial position. Let me begin with third quarter financial results. As noted in our press release, Apache reported net income of $63 million or $0.16 per diluted common share. 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. The after tax values of some of the more material items are a $219 million gain related to recent divestitures, $104 million of unproved acreage impairments and a $54 million unrealized mark-to-market loss on our commodity price derivative positions. Excluding these and other similar items, our adjusted earnings for the quarter was $14 million or $0.04 per share. Cash flow from operations in the quarter was $554 million. Before working capital changes, Apache generated $655 million in operating cash flow. During the third quarter, we completed non-core asset sales in the US and Canada for net cash proceeds of $693 million. Our cash position on September 30, including a small amount of restricted cash, was $1.9 billion, up from $1.7 billion the previous quarter. Lease operating expenses in the third quarter were $8.74 per barrel of oil equivalent, down slightly from the prior quarter. Our year to date LOE was $8.42 per barrel of oil equivalent, which is in line with our guidance for the full year of $8.25 to $8.75 per BOE. Exploration expense in the third quarter was $231 million. $198 million of this was attributable to dry hole expense and unproved leasehold impairments. The primary contributors to dry hole expense this quarter were the previously mentioned well in the barrel area of the North Sea along with some exploration wells in Egypt. Unproved impairment costs were primarily related to acreage in the Anadarko Basin. These were legacy acreage positions, which based on the success of Alpine High will clearly never compete for further exploration funding. Our October 9 webcast included a review of the progress we have made on our Alpine High midstream buildout. As John mentioned, we are investing in a large infrastructure system that will make for an extremely attractive midstream enterprise. Our board recently approved plans to install a first phase of cryogenic processing in Alpine High. This decision was taken for three primary reasons. Most importantly, we believe the incremental cost of cryo processing will be economic in the future. Secondly, having at least some cryo capacity significantly enhances the reliability of processing the extremely rich gas to assure we meet sales pipeline spec and finally cryo processing capacity will enhance the value of the midstream enterprise and product marketing by introducing optionality for the product stream. We will begin by installing 200 million cubic feet per day of cryo capacity, which will come online in 2019. Future increments of additional capacity will be treated as independent decisions and will have to be economically justified based on the then prevailing price outlook for gas and NGLs. To eliminate any potential confusion, let me be clear that this investment is already embedded in our current $500 million Alpine High Midstream capital plans for 2018. Note also that this Midstream spend may be pared back when we finalize our 2018 budget. Next, I would like to discuss some questions that have come up related to the economic assumptions for Alpine High that were set forth in last month's webcast. One of these questions is about how we arrived at our estimated average NGL realization of 60% of WTI. To begin with, I should clarify that this realization is before third-party transportation and fractionation costs. As such, you need to subtract these costs to arrive at a net realization to Apache at the least. Given we are currently trucking NGLs from our processing facilities, these costs are around $10 per barrel. In the future, with full pipe transport, these costs will be closer to $7 per barrel. At current Mont Belvieu pricing and assuming cryo recovery, over 90% of anticipated Alpine High NGL barrels would be priced in a range from 55% to 60% of WTI. Based on some of our future pricing assumptions, average NGL realizations could be as high as 70% of WTI. I would also note that the mechanical refrigeration units we currently use for processing leave most of the ethane in the gas stream. As a result, our NGL barrels today are receiving close to 75% of WTI before transportation and fractionation. Another question we have received is around our long term Waha basis differential assumption of $0.35 per million BTUs. Waha basis has ranged from a $0.37 to $0.53 discount to Henry Hub in the last six months. Prior to that, from 2010 through 2016, that same Waha basis differential range from a $0.69 discount to a $0.42 premium and averaged around $0.15 discount. The forward market view on Waha basis reflects a significant widening of the differential as anticipated production volumes would test takeaway capacity. We see this as a relatively short term risk before additional transport capacity comes online, most likely in 2019. For the long term, we believe Waha basis will trade in a lower range. Moving now to hedging, we have added some crude oil and natural gas hedges through a mix of financial derivative instruments. As a reminder, the primary goal of our hedging activity is to protect the pace of a strategically important capital program at Alpine High against the risks associated with price sensitivity on cash flows. This continues to be the case as we look to 2018. We do not use hedging to speculate on price. For 2018, we have currently hedged an average of 55,000 barrels per day in aggregate of WTI and Brent based oil production volumes through a variety of instruments. On the gas side, we have entered into a series of swap transactions that lock in average 2018 pricing at $3.07 per million BTUs for average volumes of 237 million BTUs per day. We have also entered into hedge positions relative to Waha basis. Most of these hedges are focused on production for the second half of 2018 and the first half of 2019. For this four quarter time period, through a series of swap transactions, we have locked in an average basis differential of a $0.52 discount for 207 million BTUs per day of production. We also have some contractual hedges for Waha basis, which access non Waha based pricing through transportation and sales contracts. A couple of things to note. First, the actual volumes and pricing of product hedged differs from quarter to quarter. What I gave you were averages for the time periods described. Second, our hedge positions represent only a portion of our anticipated production for any given quarter. They should not be construed to give any guidance as to future production volumes. The details on all of our current hedge positions for the remainder of 2017 and the full years 2018 and 2019 can be seen in our financial and operational supplement posted on our website today with the quarterly earnings press release. I would like to conclude by emphasizing Apache's financial strength and quarter end cash position of nearly $1.9 billion. This is a product of our disciplined approach over the last few years. Looking ahead, we are well prepared for continued volatility in commodity prices. Our hedge positions provide cash flow support to assure the deployment of high priority investments without putting the balance sheet at risk. We also have the ability to flex the capital program if that proves to be the best decision for our shareholders. With regard to our capital investment plans, we are carefully weighing the balance between achieving cash flow neutrality and the desire to move forward with investments in 2018 that will optimize long term returns from our asset base. Throughout this effort, we focus on investments that will deliver full cycle economics at current or even lower commodity prices. With that, I will turn the call over to the operator for Q&A.

[Operator Instructions] And our fresh question comes from the line of Bob Brackett with Bernstein.

A question on the US rig program. It looks like you've got four rigs running outside the Permian. Can you talk about what they're doing and would you expect those rigs to be running next year.

Good afternoon, Bob. No, we've got one section in the scoop, where we've had three rigs running there. There are seven wells we're drilling. They will finish up year end and then they will - that's where they'll stop for now. And then in the Panhandle, we've got some acreage that we got two rigs in quickly that are going to get in and drill some footage before year end, the whole block of acreage there. So they're just purely picking up some acreage retention.

And can you think about next year? I know you don't want to give a specific guidance. Can you just give us some idea of where the levers are? What assets have the most flexibility to dial up CapEx or dial down CapEx?

I mean if you look at the program, we're in really good shape. I mean we've given you the kind of the range. International is going to be pretty similar in the 700 to 900 range. That's where we can sustain our ability to generate good strong free cash flow there. You look at the rest of the rigs predominantly, we're sitting in the Permian with both our Midland basin and Alpine High and we will have the flexibility to flex there either directions. So we've got a lot of flexibility and you'd see it kind of generally across the Permian.

So I guess Alpine High where there are still optionality around retaining acreage might be the least flexible, but everything else has the ability to dial up and down?

Well, even in Alpine High, we've got good flexibility in there. We don't need - we've got six rigs running there today. We would not need all six of those. I mean the nice thing about Alpine High is a lot of that land and we've got some very astute royalty owners with some very large ranches and they recognize that the best way to maximize value for them and us is alignment on how you would handle that. So it's not like we've got a section by section program, where we've got to go out and drill one well across the whole portfolio. So, we've got a lot of flexibility and that count can be scaled up or down pretty easily as well.

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

Two for me. With the Midland drilling, you were doing 6 to 7 well pads, is that going to be kind of the norm going forward and then the next one for me is on hedging. What's the maximum amount that you will set volumetrically Steve?

So on the pads, John, as you know we've been pretty vocal that you need to be developing all your areas on a section basis. So these have been designed and we've got a couple more pads coming on between now and the end of year. They've been doing our adequate spacing and pattern tests. So that's why there are no half sections, we're kind of doing a half section test pad. So that's what you've had going on in the Midland and it's really defined tune exactly the pattern and the spacing between the various landing zones that we say. Hedging, I'll let Steve.

John, the question on hedging was what's the maximum volume we would hedge?

Yeah.

So we don't - we haven't really thought about what the maximum volume at this point in time. We've hedged - we've begun the hedging process. So I think you got to go back to first of all what's the purpose of hedging and why do we do it. We generally like commodity price exposure that's the business that we're in and we prefer to have it. We hedge for purposes of protecting the capital program against say a low price environment. We began hedging oil and gas for 2018 during the quarter. And we put the positions on that you see in the supplement. We feel like that's a good place to be right now. We feel like the oil price movement has been pretty constructive here recently and we'll continue just to monitor that and align any forward hedging program or activity. With that strategy, we want to make sure that we're protecting the balance sheet and cash flows associated with the capital program that we want to deliver.

Your next question comes from the line of Paul Sankey with Wolfe Research.

Can I just follow up on the hedging question while we're on it and you explained that some of the force behind it. But you also have repeatedly made the point that you've been relatively cautious over the down cycle and you're going to remain I think, it sounded, let's say, cautious relative to the strip going forward. Isn't that a bit of a belt and braces guys in terms of planning the company just in terms of being both cautious on how you plan and hedged.

Yeah, maybe so Paul. I don't know, I've never worn belts and braces. I don't think that that's necessarily a bad thing in the price environment that we've come out of over the last couple of years in the volatility associated with it. To be a little bit cautious, a little bit conservative about what we're committing to in the capital program and the liquidity and financial capability of meeting those commitments once we've made them. [indiscernible] maybe a bit on the conservative side on doing that, yes. We've indicated the volumes that we've had for the quarters out in 2018 and Waha basis hedges for '19 as well. We haven't gotten into what is that relative to anticipated production volume. The only thing I would say is that we are below 50% of our anticipated production volume in almost every product, in almost every quarter for 2018 and definitely 2019 obviously, we don't have any commodity hedges other than the Waha basis. So we've still got a significant amount of unhedged volumes going into 2018.

And one thing I want to add to Paul is, we've done some things to protect the upside to because we like the exposure even on the oil where we've done some collars, we've also bought the coal as well. So it's more geared towards protecting some downside and protecting the balance sheet over the short term than it is trying to make a price collar because we like actually the constructive nature, especially on the oil side.

Our next question comes from the line of Jeoffrey Lambujon with Tudor, Pickering, Holt & Co.

If the planned midstream monetization is structured, it comes with a large cash payment up front or if commodity prices are materially higher than what you end up budgeting with for next year. Can you just talk through how you'd rank your options for allocating that extra discretionary funding?

The good news is, is with the price movements has gotten very constructive lately. And we find ourselves and can see a price now where we could actually have some free cash flow next year pretty soon. So I mean that puts you in a position to, you know, we've been a company that's maintained our dividend and actually continued to return something to the shareholders over the last three years. So obviously dividend is an option if you look at in terms of - you could be in a position of accretion. Obviously share buybacks or some acceleration, but clearly we would look to find ways to return that to shareholders.

And then just one last one, looking longer term, starting with the cash balance that you're planning to exit this year with, obviously gives you a lot of flexibility in the near-term to do - to explore some of those options you've mentioned. What does that number look like long terms, is there a steady-state cash balance you have in mind. Thanks.

I think the steady-state cash balances obviously quite a bit lower than $1.9 billion. We don't anticipate carrying 1.9 billion for obviously for the extended period of time into the future. We do that now because we've got for several reasons. The two most important would be, we've got some debt maturities coming up in 2018 and we want to make sure that we've got the liquidity to handle those as they come due 560 million of debt maturing next year. And then also just having that backstop of cash and liquidity in the event of downside price volatility. We are still exposed to that and we want to make sure that we've got the liquidity to protect ourselves in the event that that occurs. I think as we get Alpine High in particular, so we get to a midstream solution in Alpine High and as we get to Alpine High becoming a larger scale producing asset and is more cash flow generative and supports itself and certainly we don't need 1.9 billion of cash I would say that would be - at a sustained level of cash is certainly below $0.5 billion.

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

In the Anadarko Basin, you talked about having a few rigs drilling. Is that HBP, some acreage or are you testing a specific concept. And also with the write-off in that area how does that regionally, how does that write-off compare with some of the stuff you're testing right now.

Number one, the write-off is really legacy Anadarko Basin; it's not what we call a SCOOP stack area. So it's going to be more in the Texas panhandle, there's some hangover from the Cordillera transaction many, many years ago. So it's really more just legacy Anadarko Basin acreage have some attractive things in the future, but it's not anything we're funding or planning to fund in the near term. So that's where that is. And in the SCOOP stack, actually it's in the SCOOP area. We've got a section there that we needed to drill a well to hold, but rather than going in and drilling one well, we got in there and did seven wells because that's a proper way to do that. So we're drilling those seven wells in the in the SCOOP there to meet some lease obligations on a section that we really like. And it gives us the ability to test some spacing and things in the SCOOP as well. So kind of two birds with one stone.

And just to clarify and I know you guys are still working the capital budget for '18. Are you comfortable spending a little bit in '18 to keep Alpine High up and running or have those thoughts changed at all.

I mean I would say at this point we're looking at '18 hard. We're watching the commodity price view. We said we will come out with a plan that's kind of predicated on something slightly conservative to strip. So we're watching that very carefully. I think the good news is there's flexibility. I mean we don't have to outspend to keep Alpine High up and running so to say is the way you phrased it. But we're also looking at what we think is the right thing to do in the right pace to develop Alpine High. That we're just going to really maximize long-term returns and that's really what we're trying to accomplish.

Your next question comes from the line of Brian Singer with Goldman Sachs.

A little bit of a similar take to Scott's last question, I think you posted the industry history about spending in recent years pretty well in the - this asset is the one worth outspending cash flow for a dilemma that you're facing is likely when many companies have faced over the years. To the degree do you decide to out of free cash neutrality? How do you prioritize between Permian and Alpine High, it seems like based on your comments you might flow the Permian. And is there any flexibility internationally or do those assets run in maintenance levels regardless.

Well, it's a little bit of flexibility on the international side, but we kind of laid out that range where we'd like to stay the $700,000 to $900,000. I think there's flexibility in both places. And I'd also remind you that Alpine High is part of Permian. But there's flexibility in both. I mean you wouldn't see us flex one or the other and we're not talking a massive change from what we've laid out in February of this year anyways. That plan was going to be neutral on the upstream spend at a $55 deck and we're not far from that right now. So we're not talking about a lot that we'd have to pare back and it can be flexed into place. And so we'd look at what we thought made the most sense. And that's some of the exercises and scenarios we're running through right now.

And then on Alpine High, can you talk to a little bit more towards the oil zone opportunities and whether you see a scenario or a likely scenario where you see less volatility and greater predictability of well performance from those zones or should we expect the well may ultimately be perspective and may not necessarily be as consistent.

Well, I mean I think it's just different geology. I mean that's something we've gone to great lengths to explain in terms of a source interval versus a parasequence, which is what the Wolfcamp and the Bone Springs are in the Delaware Basin. So actually if you look at the five wells we've drilled, we're very pleased with the results. Since the disclosure on October 9, we've actually had another one well in there that's cleaned up very, very nicely. So it's actually fairly predictable. We're just talking in terms of the geology. You have to get in and do your rigorous mapping. We have to do the inversion work with the seismic. I mean it's more going to be based on where the organics inside and what's really water wet rock and you have to do the detail work. But once you've done the detail work, it's going to be pretty predictable. It's just not a blanket you're going to lay across a large area. Most of the locations you know we'd came out with 500 was based on a couple of landing zones, we've in truthfulness we've added another one, so those location counts are going to go up even since the October 9 disclosure. So we see it as a very prominent program. I can tell you most of those are in the northern trough. And the good news is, with every well we drill in Alpine High, we're looking at all those sections. So we see it as a very viable and a very material play that we're going to continue to move forward. And you're going to see the number of landing zones and the location counts grow.

Your next question comes from the line of Bob Morris with Citi.

John, you did a nice job last month of laying out the liquids and oil potential an Alpine High. And you sort of touched on this earlier in the Q&A. But you'd been working to try and renegotiate or extend a lot of your leases to be able to accelerate drilling of the shallower zones and still hold those without having to drill to the deeper gassier zones first. How is that progressing? And then, second part of that question is, is there a minimum level of activity or capital spend in 2018 to hold the acreage that you have now that you'd be able to or would want to have to maintain?

There's two things I would say, Bob. Number one, we do have some very sophisticated land owners and we've been making great progress on our discussions with them as well. But it's not a matter of just trying to drill the shallow zones and not drill the deeper zones later. What you really want to do like anything is, you wanted to develop the sections properly and very systematically where we would develop the deeper zones and the shallow zones together where we need to do that. What you don't want to do is come back later and drill deeper after you have develop shallower or you're going to find yourself with some of the challenges that you're seeing in the other parts of the Permian. Where now they happen to run extra casing strings and things to deal with water flows because you've they're going to run extrication strange things to deal with water flows because you've because you've dealt in depletion and that sort of thing. So contrary to that one of the advantages we have at Alpine High, we've done a lot of data analytics and been recently able to eliminate even a string of seven of 58s on our 14,000 foot TVD wells. So you want to do this properly and I think the conversations we're having with the landowners are constructive and that you want to go about this in the right way where we can develop the wet gas and the oil zones and you want to do them where you don't have to go back in later. So it's more or less of you know developing everything and then margin directionally than it is trying to develop bottom up or come in and develop all your shallow and then have to drill through your shallow to get your deep.

That made sense, so that would seem instill a little more activity in drilling these wells. So the second part of my question was, in doing all of that, is there a minimum level of activity or capital spend you need to do in 2018 to be able to hold onto leases?

If you look at '18 and I look at Alpine High and if I just if - even if we were to keep a six rig program, less than half of that would be necessary in terms of near term acreage. So I mean, we're in a really good spot.

Your next question comes from the line of Gail Nicholson with KLR Group.

Looking at the replacement of the Canadian volumes in the year with the Alpine production. That's very impressive especially since now those wells are completed in the optimal manner. When you look at the well count to get to that $50,000 rate by next May, what percentage was optimally completed and what percentage was more science wells?

I mean if you look today, I mean we've been making that shift. And as of the October 9 disclosure we had 34 wells online. And we said we're going to be virtually halfway there year end with I think another eight wells, we're going to bring on 42 by year end. So as we move forward and start to shift into our pattern and spacing tests, you're going to continue to see us start to climb that curve. I'll give you a little bit of a feel for well camps that are necessary to do that.

And then just shifting tack a little bit, I know everyone is trying to talk about cash neutrality and paring back the budget. But looking at the improvement in kind of Brent/LLS pricing that we've seen to-date. Are there any exploratory projects in the portfolio that look more attractive that you might be willing to spend some capital on next year because of the spread there versus WTI?

I think we're continuing looking at the portfolio and clearly we've got projects in Egypt and the North Sea that have, you know, that are Brent-weighted. We've got some brand new acreage that in Egypt that we just received through the award process. We're anxious to get our seismic shot and we'll actually be drilling wells there. So I think it's more a function of the opportunities as we high grading things, there will be things that we will move up in the portfolio for sure.

Your next question comes from the line of Charles Meade with Johnson Rice.

I wondered if I could push a little bit more on this idea that you put out on your prepared remarks about the optimal investment profile being a little - optimal investment for 2018 being over what you'd look at, if you just fund it with cash flow. I think most of us are understanding that to certainly applied to Alpine High, but I'm curious does that also apply to your Midland program or in other words would you, is the optimal development there, would that call for more than cash flow as well.

I think the thing you got to think about is, number one, we're not far off of that optimal from where we sit today anyway. So and kind of what we laid out at the start of this year would have been what we thought was optimal. So we're not, you know, we're pretty darn close to being that zip code as we sit today. The point is, you always want to balance and what's going to maximize our long-term returns and the pace. And I think the beauty of it is, as it has been alluded to we've got some flexibility, we've got some cash on the balance sheet. You're just trying to balance the right approach. And the good news is, we've got the ability to defer. So those are just some of the trade-offs that you have to balance and that's some of that what I'll call good positive tension. As you find things and discover things, your goal is to always bring more things into the portfolio that give you opportunities to high grade and pull things forward. And so it's just a good healthy situation and tells you the quality of our portfolio. And the other piece I'll say to that is. you see we're in multi-well pads, we're not out one well here, one well there. And so I think the testing we've been doing in the Midland Basic, we've been building a lot of momentum there. The patterns and spacing tests and things were also moving toward Alpine High. Those are all building towards understanding and to finding that optimal pace because that's how you're going to maximize your long-term returns versus short-term things you can do to manage short term.

And actually kind of segues to what my next question is, is around what sort of results are we going to see from Midland. If we look at those three pads, where you had those good results, I believe it was [indiscernible] wells on each of those. Is that going to be the bulk of the Midland program in 2018, those big pads or at least moderate sized pads?

Well these are half section type tests. And so, depending on the capital level that we decide to disband, you're going to see us moving more into full section development type mode. And you'll see more similar type things, but that will be hinged on the pace that we want to go. And the beauty of having a lot of inventory that's drill ready and the infrastructure that we put in place puts you in a great position to be able to move forward. But you'll see continued building on pad level type economics because fundamentally we think that's how you're going to create the most value

Your next question comes from the line of Arun Jayaram with J.P. Morgan.

I want to start off, you mentioned in your script how you'd moved some capital from international back to the US. I'm wondering if you could talk about that as well as the prospects for the North Sea and maybe just highlight the results thus far Callater.

I mean, I'd let Tim go into details on Callater, but first two wells that gone on are performing quite well. Any color you want to add Tim to Callater.

The first two wells we brought on, net production was about 19,500 barrels of oil per day. They're currently producing about 13,000 barrels per day right now. We've got another well that will be bringing on shortly. We do have some facility constraints there with our bundle and some surface facilities. But we also have future drilling plans out at Callater as well. So a lot of good things happening there in the North Sea.

And I would say on the capital shift, Arun, it's pretty minor. But it's more geared towards some of the pad testing and things we're doing in the Midland basin.

And just a question, as you guys think about future markets for Alpine High gas. Is obviously the Gulf Coast Express Pipeline, which is the Kinder Pipeline, any thoughts on Apache participating in that long haul pipe?

We're looking at all options. I mean our gas today is flowing into Mexico, but we're certainly not counting on the Mexican market to be the purchaser of all of our gas. We recognize that we've got to be able to move a substantial volume of gas to the Gulf Coast. We're certainly looking at all options associated with that. And for that matter the liquids as well.

Your next question comes from line of Doug Leggate with Bank of America.

John, just come back to the relative capital allocation for next year, what's the obligation on from an HBP standpoint in Alpine High that might limit your flexibility there. And what I'm really getting at is that you've obviously got a very strong ratable program in the Midland. I'm just wondering would you tend to skew capital away from the Midland in order to meet HBP or would you want to keep the momentum going in the Midland as well. I've got a follow up please.

No, I mean, I think as I've answered, we're in a good place in both. I think we'll be able to move both programs forward. if you look at current rig count today as I mentioned less than half of the capital we'll be spending this year as we kind of roll forward into next year would be required in terms of how we need to meet lease obligations in the Alpine High. So I think we're in a pretty good zone that we can materially move both programs forward, like we need to move them forward.

Is five-rig program is still the right number for avoiding any acreage expiry and so on?

I mean if we look at Alpine High today, I mean, you could see something similar very easily.

My follow actually is really going back to the question about the activity level outside of the Permian. I mean, when you look at the returns that you're talking about in the Alpine High, their obviously, they're going to just be anything else in the portfolio it seem so. When you think about the scaling up of that business going forward, what does it say about the high grading of the bonds? I know you've done a lot, but is there more to be done thinking obviously Oklahoma in particular.

Well, I mean I think the key there is, number one, I mean if you look at the portfolio today, we like the balance that we have across the entire portfolio. We like what we have internationally or like what Egypt and the North Sea bringing to the table with exposure to Brent, we think we've got world class operations there and we differentiate ourselves. And so we like having free cash flow that we can invest. We also like the running room and the exposure we have in those two areas. I think it's a very good compliment. When we look at North America, we're always looking at the portfolio and that's something we will continue to do and continue to do on a daily basis. I like right now we moved up and we've got a nice position in the SCOOP. We could run a couple of rig program up there for several years. And we think it competes fairly nicely. So that's where your rigs are now. But I'll tell you we continue to look at the portfolio, we continue to have those conversations with the board. And I think the nice thing is, with the, you know, those areas there's a lot of upside and there's very little to hold those positions. And so I think they really create options for us in the future because we can see to a point where we're going to be generating a lot of free cash flow coming out of Alpine High.

Your next question comes from the line of Michael Hall with Heikkinen Energy Advisors.

I guess maybe just continuing on the theme around cash flow neutrality and balance. Two questions I guess, number one, longer-dated, how far out do you see it when Alpine High does become self-sustaining including any midstream spend. And then secondarily, when we talk about cash flow neutrality, just to be clear, is that CapEx plus dividend equals cash flow or is it CapEx equals cash flow…

First of all, if we just take a single rig at Alpine High, it's less than two years before its self-funding. So, it really comes down to pace and how we want to scale that up. I mean that's the way you want to think about that. And that's fully burdened with infrastructure and midstream spend. And then secondly, when we do talk about our numbers, we've got our dividends dialed in. So our dividend payment has been dialed into our capital programs.

And then I guess on the midstream side, as we think about monetization pads in 2018, can you maybe just kind of talk about the relative pros and cons you see for the different pads available and how important upfront cash flow is relative to longer-dated value capture.

We're still in early days of looking at that. And looking at the options, we've got a lot to consider. It's not just about the assets that we own, it's about what's going on in the Permian Basin and what's going on between the Permian Basin and the Gulf Coast. So there's a lot of work to do just to get prepared to consider the question that you just asked. We're going to look at it from the perspective of what creates the most value for the shareholders long term and not so much about what creates cash flow in the short term. We'll certainly look at it from the perspective of how does that impact our strategic value for the upstream, making sure that we've still got adequate elements of control if you will to be able to make sure that the midstream serves the purpose of the upstream as opposed to the other way around. But beyond things like that, we're open to quite a few options and exploring what those options ought to look like before we start talking to anybody in earnest in the marketplace.

Your next question comes from the line of Michael McAllister with MUFG.

My question has to do with Alpine High midstream, when you talked about the cryogenic facility being built out in 2019, is that early 2019 or mid-2019, what's the thought on that?

What we're looking at is something that would come available probably in the first half of '19. So it would be - so obviously something that we would start construction on in 2018.

And are there mechanical facilities in the budget for 2018 or we're going to just go with the 330 that are expected at the end of this year?

No, there will be more. There will be more processing in the field during '18.

Do have a number or is it just contingent on the budget I guess activity?

It's something that we haven't shared yet and we'll probably share that when we get to the '18 plan for - that we'll go through in the fourth quarter results in February.

What steps have you been taking for - there's not much NGL takeaway from there, what steps is Apache taking on that front.

By the time we get to a cryo plant, we will obviously need pipe takeaway for liquids as well. So we are looking at that.

And we have no other question in queue at this time. And I would like to turn the call back over to Gary.

Thanks everybody for joining us. We look forward to speaking to you again in February. In the meantime if you have any follow ups please call myself or Kian or Patrick on the IR team and we'd be happy to walk through anything you need. Thanks so much. Bye, bye.

Thank you for your participation. This does conclude today's Apache Corporation third quarter earnings call. You may now disconnect.