APA Corporation (APA) Q4 2018 Earnings Report, Transcript and Summary

Good morning. My name is Rob, and I'll be your conference operator today. At this time, I would like to welcome everyone to the Apache Corporation Fourth Quarter 2018 Results Conference Call. All lines have been place on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer session. [Operator Instructions]. Mr. Gary Clark, Vice President of Investor Relations, you may begin your conference.

Good morning and thank you for joining us on Apache Corporation's fourth quarter and full year 2018 financial and operational results conference call. We will begin the call with an overview by Apache's CEO and President, John Christmann. Tim Sullivan, Executive Vice President of Operations Support, will then provide additional operational color; and Steve Riney, Executive Vice President and CFO will summarize our fourth quarter and full year financial performance. Also available on the call to answer questions are Apache’s Executive Vice Presidents: Mark Meyer, Energy Technology, Data Analytics and Commercial Intelligence; and Dave Pursell, Planning Reserves and Fundamentals. Our prepared remarks will be approximately 30 minutes in length, with the remainder of the hour allotted for Q&A. In conjunction with yesterday's press release, I hope you have had the opportunity to review our fourth quarter Financial and Operational Supplement, which can be found on our Investor Relations website, at investor.apachecorp.com. 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, adjusted production numbers cited in today's call are adjusted to exclude non-controlling interest in Egypt and Egypt's tax barrels. Finally, I would 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. And with that, I will turn the call over to John.

Good morning and thank you for joining us. On today’s call, I will review Apache's fourth quarter production results, recap our key accomplishments in 2018, update and provide color on the 2019 outlook we issued a few weeks ago and conclude with some high-level direction out to 2021. Our fourth quarter total adjusted production of 421,000 barrels of oil equivalent per day for the quarter was in line with guidance. Strong international volumes offset slightly lower than expected US production. New wells in the North Sea at Callater and Garten drove international outperformance, while production in Egypt was generally in line with our expectations. In the US Permian Oil production continued its trend of strong performance and sequential growth, significantly exceeding our guidance for the quarter. Natural gas and NGL volumes were lower than expected for several reasons, which Tim will outline in a few moments. Our fourth quarter momentum has carried over into the current quarter, prompting an increase in the lower end of our full year 2019 production guidance range, as noted in yesterday's press release. Before moving on to discuss our outlook for this year, I would like to briefly recap some of our key accomplishments in 2018. Each of our regions made great progress last year, and contributed to Apache’s strong growth, returns and financial performance. Operationally, we grew total adjusted production 13% and Permian Oil production 18% over 2017, increased well productivity throughout the Permian basin and reduced drilling and completion costs offsetting much of the inflationary pressures that built in 2018. Formed Altus Midstream Company, an entity capable of independently funding ongoing midstream investments at Alpine High, discovered and commissioned the Garten field, which increased our daily North Sea production to its highest level in two years, received three concession awards in Egypt over the prior 18 months comprising 2.2 million acres adjacent to our existing footprint, made tremendous progress our large-scale high-density 3D seismic acquisition and new prospect identification program in Egypt, and completed a comprehensive petroleum system assessment offshore Suriname and met numerous, large, drill-ready prospects on Block 58. 2018 was also an excellent year financially for Apache, as we increased cash flow from operations 56% year-over-year, delivered an approximate 22% cash return on invested capital, generated robust cash flow from our international operations of $2.4 billion and returned nearly $1 billion or 25% of our cash flow from operations to investors through dividends, share repurchases and debt reduction. Overall, 2018 was a very good year. As we turn to 2019, the lower price environment has prompted us to reduce our capital investment program. We will focus investment on projects that balance near-term cash flow generation with long-term returns and value enhancement. In 2019, we are planning upstream capital investment of approximately $2.4 billion, which represents a 22% reduction year-over-year. Despite this decrease, our production growth will remain resilient. As disclosed in our press release on February 7th, we are projecting fourth quarter 2018 to fourth quarter 2019 production growth of 6% to 10% on a total company adjusted basis, 12% to 16% in the US, and 5% for Permian Oil. Internationally, we are projecting a decline of 2% to 4% over the same time period. This however, is heavily skewed by the strong fourth quarter 2018 volumes we reported in the North Sea, due to the timing of new wells at Callater and Garten. Comparing what we laid out for 2019 a year ago to our current outlook, our capital program has been reduced, our production outlook has moved to the top half of our previous guidance range, and our Permian basin oil production has been and will continue to be significantly higher. Overall, we can deliver attractive and sustainable growth under a reduced activity set due to a high quality diversified portfolio, relatively low base production decline rate, and continuously improving capital investment efficiency. It is important to note, however, the growth at Apache is an outcome of our returns focused investment approach, and not the overarching objective. The changes required to deliver this plan are already being implemented. Following the oil price downturn late last year, we have decreased our operated Permian rig count to 13. This compares to a range of 16 to 18 rigs that we have been running since mid-2017. With this and other activity reductions, we are projecting first quarter upstream capital in the low $600 million range. This is approximately $200 million below our fourth quarter 2018 upstream spend and puts us on a level pace to achieve our full year 2019 target of [$2.4 million]. Let's now look into some of the regional dynamics underpinning 2019. Our US capital program is heavily concentrated in the Permian Basin with a focus on rich gas at Alpine High and oil in the Midland and Other Delaware. We plan to run an average of 12 rigs and 4 frac crews in the Permian this year, with roughly half the activity allocated to Alpine high, and the other half predominantly to the Midland Basin. Maintaining critical mass and proper rig frac crew ratios in these two key areas will enable us to deliver a very efficient capital program given the reduced budget. Apache's US oil production comes primarily from the Permian, including the Midland Basin, the Delaware Basin and Alpine High. This year, we will continue to develop all three, but at an appropriately reduced pace. Our oil drilling will focus primarily in the Wildfire, Powell and Azalea areas which comprise only a small percentage of our total prospective acreage in the Midland Basin. Investment in these areas will continue to leverage the tremendous productivity gains over the last three years, as well as the existing infrastructure. To-date we have drilled fewer than 25% of our known-drilling locations at Wildfire, Powell and Azalea. So there is still a tremendous amount of running room in these areas alone. We have also initiated delineation activities in the nearby Benedum and Hartgrove areas in Upton and Reagan counties. This work enables us to begin planning and installing the facilities to efficiently develop these assets. The strong well results to-date indicate the potential for significant additions to future core growing inventory. In the Delaware Basin and Alpine High we are deferring oil-focused activities, however, substantial future opportunity remains. Apache’s Permian Basin program has improved tremendously over the last three years. We’re now producing at record levels, both in terms of total production and oil volumes. We have accomplished this with far fewer rigs and significantly less capital deployed in our prior production peak in late 2014. Moving on to our rich gas development program in Alpine High, our focus this year will be on multi-well pad development drilling primarily in the Northern Flank of the field. With 600 million cubic feet per day of nameplate cryogenic processing capacity scheduled to come online in the second half of the year, we should realize a significant uplift in cash margins and cash flow generation. We are decreasing our activity this year at Alpine High to five rigs and one frac crew. We’re deemphasizing dry gas drilling which will no longer be needed for blending purposes to meet pipeline specs following cyro processing installation. This will naturally result in lower volume growth than previously projected, but will increase our percentage of NGLs. Apache’s new 2019 Alpine High production volume outlook is 85,000 to 90,000 BOEs per day for the year with the targeted year end exit rate in excess of 100,000 BOEs per day. Our projected year end NGL mix will approach 40% of net Alpine High volumes, up significantly from the previous guidance of 30%, which we provided a year ago. Internationally Egypt, in the North Sea continue to play important roles in our diversified portfolio. Despite the lower commodity price environment, both regions will continue generating significant free cash flow. This year, we will maintain our activity set in the North Sea, which consists of one floating rig and two platform rigs. In the Beryl area we plan to bring our store discovery online in the second half of the year and spud a second well at Garten. In the Forties field we will focus on our waterflood and base decline management program augmented by platform rig activities. In Egypt, we continue to advance our large-scale seismic shoot from which a substantial number of attractive new targets have been identified thus far. We are also drilling exploration and delineation wells in each of our new concession areas, thereby, laying the foundation for potential future growth. Turning to Suriname, we have completed a substantial geologic and geophysical evaluation of Block 58 and have a large number of high quality prospects across multiple different play concepts. We recently contracted a drillship and anticipate spudding our first well around midyear. Block 58 which Apache owns 100% is truly a world-class opportunity. This block is adjacent to the ExxonMobil operated Stabroek Block in neighboring Guyana and is on trend with numerous oil discoveries. To wrap up our view of 2019, I want to emphasize that we are committed to returning to investors at least 50% of any free cash flow, inclusive of asset sale proceeds before increasing planned activity levels. While we have a deep drilling inventory and long list of projects we would like to accelerate, as we have done in the past, Apache will remain disciplined and flex the program subject to available cash flow. Should we encounter a further downturn in commodity prices, we have the flexibility to reduce our capital program. Importantly, with the benefits of a diversified portfolio, Apache is capable of breaking even at WTI oil prices in the mid-$40s, while continuing to fund its dividend. We have included a slide in our supplement, if you would like to review our assumptions behind this metric in further detail. I will conclude my remarks today by outlining our longer term view to 2021. Assuming WTI oil prices in the $50 to $55 per barrel range, we envision an annual upstream capital program of $2.5 billion to $2.8 billion. While the overall capital allocation and activity set will likely be similar to 2019, the specifics of the program will remain fluid as we incorporate learnings. We believe this investment level is capable of generating continued attractive production growth and returns with the US as the primary driver and international flat to slightly down. As in 2019 we will continue to manage for cash flow neutrality, and return 50% or more of any free cash flow to investors. Permian Basin oil and Alpine High rich gas will be the primary drivers of US production growth over this timeframe, with NGLs comprising the fastest growing product stream. In the US our deep inventory of development opportunities will continue to drive production growth, lower F&D costs and increasing returns for the long-term. This will be supplemented by our continuing organic exploration programs in the Lower 48. Our longer-term international production outlook is characterized by a modest decline in the North Sea and flat to potential growth in Egypt. Our new concessions and seismic imaging in Egypt help establish the foundation for an appropriately paced long-term exploration and development program. This is good for the country of Egypt and for Apache as we believe our operations are capable of growing both production and free cash flow. In closing, 2018 was a year of strong execution across the portfolio which translated into our best financial performance in four years. We are off to a good start in 2019 and have a disciplined plan to deliver long-term returns and growth, supported by a deep inventory of development locations and exciting exploration opportunities in the US and internationally. Over the next three years Apache is committed to cash flow neutrality and we will continue to return meaningful capital to our investors. With that, I will turn the call over to Tim Sullivan, who will provide some operational details on the quarter.

Good morning. My remarks will briefly cover fourth quarter 2018 production and operations performance and activity in our core regions. I will also provide some details on our planned activity in 2019, and touch on our outlook for US service costs. Operationally, we had another very good quarter, led by the Permian Oil production and the North Sea. We achieved companywide adjusted production of approximately 421,000 barrels of oil equivalent per day, a 5% increase from the third quarter 2018 and up 16% from the fourth quarter 2017. In the US, Permian Oil was our biggest growth driver with an increase of more than 8,000 barrels of oil per day or 9% compared to the third quarter. The Midland Basin, Delaware Basin and Alpine High, all contributed to this sequential Permian Oil increase. Total production for the Permian was up 6% for the third quarter, despite several events across the region that reduced production by approximately 10,000 BOE per day in the fourth quarter. This included excessive downtime due to outages at third-party facilities in the Midland and Delaware basins and weather disruptions. At Alpine High, gas volumes were impacted by a field-wide shut down for several days that pressured on gas sales lines and completions timing. Apache averaged 16 drilling rigs and four frac crews in the Permian Basin during the quarter, drilling and completing 65 net wells up from 44 net wells in the third quarter. In the Midland Basin we placed 26 wells online, all of which were on multi-well pads. Our results are benefiting from a consistent, steady operational cadence across the Midland Basin. In 2018, approximately 75% of our drilling program was focused on development drilling in Azalea, Powell and Wildfire areas, yielding predictable and economically robust drilling results. One example of the type of longer-term results this program is yielding is the nine-well Wolfcamp pad at Powell, which we discussed last quarter. After 245 days online this Wolfcamp pad has cumulative production in excess of 1.5 million barrels of oil and 2 BCF of gas and continues to produce approximately 4,000 barrels of oil per day and 9.5 million cubic feet per day of gas. The remaining 25% of the program in Midland Basin consisted of delineation drilling on other acreage blocks. Most notably, in our Benedum area located in Upton County, this four-well pad was 2 mile laterals targeted four different landing zones and achieved an average 30 day IP of 1,646 BOE per day per well with nearly 80% oil cuts. We’re excited about these results as it sets up a number of locations for future drilling. Shifting to the Delaware Basin we drilled a four-well pad in the Palmillo area of Eddy County, New Mexico, which averaged the 30 day IP of more than 1,700 BOE per day, 79% oil and these were drilled with 1 mile laterals. We plan to drill 20 wells in the area during 2019 and we will still have many years of inventory into play. Please refer to the quarterly supplement for production details on these and other wells highlighted from the quarter. At Alpine High our net production for the quarter averaged approximately 58,000 BOE per day. We exited the fourth quarter producing approximately 70,000 BOE per day on a net basis. We placed 26 wells on production in the field during the fourth quarter, bringing total wells placed on production for the year to 94. Highlights during the quarter include six wells at the Mont Blanc pad in the Northern Flank, which targeted two zones in the Woodford formation and averaged a 30 day IP of 16.1 million cubic feet equivalent per day of rich gas. This pad advances our learnings from the previously disclosed Blackfoot pad and demonstrates improvements in capital and production efficiency, utilizing improved configurations and larger fracs from fewer wells. Also in the Northern Flank, we drilled the Iroquois State 201AH, which targeted the Barnett formation and averaged a 30-day IP of 7.6 million cubic feet of rich gas and 213 barrels of oil per day. These wells are indicative of the drilling program that we have planned for this year and we're looking forward to processing the rich gas to our new cryogenic facilities coming online in the second half of the year. Our lease position at Alpine High is approximately 300,000 net acres as of year-end 2018. Consistent with our October 2017 webcast, we let a portion of our leasehold with known higher geologic risks expire. These areas were never included in our previously disclosed location counts. Turning to service costs, in the Permian we have successfully locked in attractive rates for rigs, frac crews and sand for 2019. We’ve budgeted for slightly lower year-over-year service costs overall at $53 WTI oil price forecast. We continue to monitor the marketplace to secure cost competitive and high-performance services and supplies. Before commenting on our international operations, I would like to address our US production trajectory for 2019. Production in the first half of the year is expected to be relatively flat with Q4 2018 volumes, as we've reduced our operated rig count and implemented a three month frac holiday with one of her two frac crews in the Midland Basin. We then see a fairly significant second half volume ramp resulting from the cryo commissioning at Alpine High, accelerating completions with return of the second frac crew in the Midland Basin and the startup of development in the North Sea. As we stated in our press release a few weeks ago, we expect robust 4Q exit rates in 2019, giving us good momentum into 2020. Internationally, in Egypt, we drilled and completed 24 gross operated wells with a 96% success rate during the fourth quarter, and 110 total wells for the full year. Our 3D seismic acquisition in the Western Desert continues. To-date we have acquired data over 1.25 million acres completing acquisition in our legacy West Kalabsha and Shushan areas. Seismic acquisition in our new Northwest Razzak Concession is in progress for completion later this year. More than 40 new lease have been identified thus far from early data processing and we are currently drilling our first prospect based on the new 3D in our West Kalabsha area. Over the next couple of years, we will continue to build our high-quality inventory in Egypt as a result of the new concessions and acquisition of the new 3D. This will make our drilling program more capital efficient and set the stage for future potential growth in oil production and free cash flow. Moving to the North Sea, production averaged approximately 63,000 BOE per day during the quarter, a 25% increase from the preceding period as turnaround activity was completed in the third quarter, and we realized a full three months of production from the fourth development well at Callater and the startup of the Garten development in November. Garten has already produced over 1 million barrels of oil and 1.3 BCF of gas and is currently producing at 11,500 barrels of oil per day and 12 million cubic feet of gas. We’re planning on second development well for Garten, which we will spud later this year. We’ve also identified two geologic analog prospects, which we are assessing for inclusion in our 2020 drilling program. Operationally, we’re off to a good start and anticipate another strong year in 2019. With that, I'll now turn the call over to Steve.

Thank you, Tim. Today I will review our fourth quarter financial results, briefly touch on Apache’s 2018 highlights and provide some further color on our 2019 financial guidance. As noted in the press release issued last night under Generally Accepted Accounting Principles, Apache reported fourth quarter 2018 net loss of $381 million or $1 per diluted common share. These results include a number of items that are outside of core earnings, which are typically excluded by the investment community and published earnings estimates. The most significant of these items were various impairments taken during the quarter. In the US onshore we took an after-tax impairment of $253 million for oil and gas properties, primarily in the Anadarko Basin. In the offshore we took a $90 million after-tax impairment on a legacy investment in the Gulf of Mexico specific industry consortium. In Egypt, we took an after-tax impairment of $63 million on three concessions that are unlikely to recover certain carry-in costs prior to the end of term due to inadequate remaining revenue potential. And in the North Sea we took an after-tax leasehold impairment of $71 million on a previous discovery, which no longer has certainty of future development. Due to the nature of this property, this impairment is found in exploration expense. Excluding these and other smaller items, adjusted earnings for the quarter were $119 million or $0.31 per share. Other than the production results previously outlined by John, most of the quarter's performance was as expected. Exploration expense was higher than normal, primarily due to the North Sea impairment I just noted and the write-off of other costs associated with the same item. Looking at 2018 as a whole, I would highlight it was a very good year in terms of delivering on guidance and expectations, improving our ability to live within cash flow and improving our return to investors. When compared to our original 2018 guidance provided last February it was a consistently strong performance on production volumes as US production exceeded our original midpoint guidance by 4% and international production delivered as guided. On the cost side nearly all major items were in line with or better than the guidance we provided a year ago. Meaningful exceptions for UK cash taxes, which were higher than guided due to the strength in Brent oil prices and financing costs they were up due to some cost incurred to restructure a portion of the debt portfolio. Capital spending came in higher than original guidance, driven primarily by increased activity in the Permian Basin. This included incremental drilling to optimize completion deficiencies, higher completions intensity, facilities investment and additional testing. In November Apache completed the Altus Midstream transaction. Apache had funded approximately $1.1 billion of midstream investment at Alpine High since announcing the discovery in 2016. In addition, we had acquired valuable equity options in five pipeline projects to transport product from Alpine High to Gulf Coast markets. Altus now provides a separate vehicle to fund both the ongoing midstream buildout, as well as the near term required investment in the joint venture pipeline projects. This significantly improves Apache's forward-looking ability to fund upstream capital spending at an appropriate level commensurate with the price environment. Financially, we delivered materially improved returns for the year, continued to strengthen the balance sheet and increased return of capital to investors. For the year, we paid out $382 million in dividends, repurchased $305 million of Apache common stock and reduced debt by $281 million. I'll now move on to guidance for 2019. I won't go through each component, but I would like to highlight a few key items. We have reduced our 2019 upstream capital to $2.4 billion, of which approximately 75% is allocated to the US and 25% to international, which includes Suriname. Consistent with the past, we expect our growth patterns in the US to continue supported by a slightly declining international production. As Tim outlined, our production growth will come primarily in the back half of 2019. This is driven by a combination of a frac holiday during the first quarter in the Midland Basin, the timing of large pad completions throughout the Permian Basin, and the volume uplift from cryo processing in Alpine High. For the first quarter of 2019, adjusted production is expected to be approximately 425,000 BOEs per day, 287,000 BOEs per day in the US and 138,000 BOEs per day internationally. Upstream capital spending will be around $625 million. We have provided details of both our first quarter and full year guidance in the Financial and Operational Supplement, which can be found on our website. In conclusion, we closed out 2018 well and have great momentum transitioning into 2019. We are executing on our strategy to sustain our international businesses for long-term free cash flow generation and to focus growth investment in the Permian Basin. We also have a tremendous exploration portfolio, which provides great optionality for the future. We are committed to maintaining financial discipline and living within cash flow in a $50 to $55 WTI environment, investing for long-term returns and returning capital to investors. With the current portfolio and a separate Altus Midstream Company, we are well-positioned to deliver on those goals. And with that, I will turn the call over to the operator for Q&A.

[Operator Instructions]. Your first question comes from line of Bob Brackett from Bernstein Research. Your line is open.

Yes, I had a question on North Sea operating cost. I noticed a pretty significant step down in that asset. Is that something we should expect on a going forward basis?

Well that’s just going to be predominantly the production coming on at Garten in the Beryl area, so I think it will continue end of -- early part of '19 and the well comes off a little bit before we drill offset, it probably starts to go back up. So that's more driven the BOEs rather than the fixed dollars.

And can you talk about the reserve revisions, is that related to some of the write-downs, or is there something happening there on maybe a five year plan and you’re taking down some puds?

No -- this is Dave Pursell. The revisions were across the board and independent of impairments, a little bit here and there by region. We did have some basis differentials took some puds off but nothing that would be -- we point to as material, it’s more end of year bookkeeping.

Your next question comes from line of Scott Hanold from RBC Capital Markets.

I was wondering if you could give us a little bit of color on Alpine High and it seems like there has been a bit of a shift in some of the focus more NGLs I guess deferring some of the oil drilling and specifically deferring some of the oil opportunities. Can you give us a little bit of color on sort of what drove that decision, was that more of trying to be more disciplined in spending in the near term, or was it more geologic based on what you seeing as you go forward in your plan?

No, Scott, it’s purely a function of the capital program. What you see is as we paired back a little bit internationally, I mean the world has changed from where we were on the last earnings call and we’ve taken CapEx down as you know for 2019 and then the 2020 and ‘21. So it’s really more a function of the program and what we've done is allocate that capital in a way that we can most efficiently invest it to drive the best long-term returns. You'll see continued programs, Egypt and the North Sea where we sustain and then in the US specifically we’ve kind of looked at how spin that Permian capital and we were dropping rig count from a 16 to 18 range to 12 and you're going to see if five-rig program focused on Alpine High mainly on the rich gas today as we can defer some of the other things. And you will also see a very tidy program in the Midland and Delaware where the rigs and frac crews are allocated to kind of maximize our productivity and capital efficiency. So it’s really just the luxury of being able to defer, will push back some timing on some testing and you’re going to see really two focus programs: Rich gas and then an overall oil program.

So would we expect that if oil price are higher than and you do have free cash flow that obviously previously you talked about getting back to shareholders, but as you look at increasing organic activity, would testing some of the old zones be a high priority for you all in Alpine High?

I mean I think as you look at our portfolio today, we’re committed to returning a minimum of 50% of free cash flow to our shareholders and that would be inclusive of any asset sales. But secondly we paired back in Egypt our Permian Midland and Delaware as well as Alpine High. So there's really three areas that we’ve got some pretty strong programs that we would prioritize and think how do we start to put activity sets back but I mean it would be a combination of those areas. And it's a nice thing about having a portfolio with a low decline rates. We can gear down and still grow and generate strong long-term returns.

Your next question comes from line of Gail Nicholson from Stephens. Your line is open.

You guys talked about a slowdown of activity in Alpine and the deemphasizing of drydock developments. Are you still achieving a very healthy exit rate in '19 with more NGLs? But as we look at 2020 with that deemphasize of that dry gas developments, can you just talk about how that any changes to previous 2020 growth outlook and how we should think about composition in 2020 Alpine?

Well what we've done Gail is focused our programs and prior to having cryos coming on we were -- because the gas is so rich we will have to drill some of the dryer gas zones to blend on the pipelines back. So we will no longer have to do that and in 2019, 2020 and 2021. So even I think the key products is, is the program which we lay out a microenvironment it's pretty volatile today on a $50 to $55 world we've kind of laid out CapEx with likely or could be in the 2.5 billion to 2.8 billion ranges 2020 and ‘21, if you look at where we will exit '19, we’re going to exit '19 going into '20 in a much stronger place than we ended '18, coming into '19. So capital probably looks pretty similar as a carry forward and we’re confident that we can deliver mid single-digit to corporate rates at a minimum and there's a lot of factors that could cause that to improve as we start to look at that.

And then look just at the advancements that we've seen kind of in technology as well as seismic processing, has that helped you identified prospects better in Suriname, North Sea in Egypt and does any of those advancements changes your confidence level in success regarding what is your exploration target in those three areas?

Clearly, technology is driving a lot of change and if you look at Egypt where we've added new acreage in order we're shooting the moves state-of-the-art broadband 3D. We've shown pictures in the past in some of our investor deck so what the 2013 seismic look like versus the current seismic. So there's no doubt that we’re seeing a lot shakeout of that look in the Western Desert, I think our West Kalabsha we have identified now over 40 new prospects. So I think it's going to bear a lot of fruit and that's why we're pretty confident with the newer acreage and the new seismic in Egypt. It’s going to give us more inventory to really return Egypt to potentially growth area for Apache. Clearly in Suriname we've got the 3D, we’re excited -- that's a whole other topic about what Suriname can be, but 3D is a big piece there and then we continue to use 3D in our unconventional and onshore as well. It's been very key and was instrumental in the discovery of Alpine High and it remains a key piece as we go forward with the development plans.

Your next question comes from line of John Freeman with Raymond James. Your line is open.

The first question, you all provided the base decline rate for the overall company. Would it be possible to get that broken down for the US versus international?

No, we haven't broken that out. I think what you've got is we're in the low 20s, and it's going to improve over the next couple of years, and we've got some conventional assets in the Permian that help and we’ve also got some unconventional that have a little higher more characteristic decline. So it's kind of a combination of the asset basis but we haven’t broken that out as of yet by area.

Okay and then I just had a -- my other question is sort of in regards to that, Slide 12 you have, sort of set out for ‘19, kind how you come up with the capital plan and sort of what happens if the oil price does or the commodity price does better than plan and how you kind split up the amount goes to the investor versus increased activity. I’m just trying to think about, make sure I’m on the same page that we’re thinking about. When you go into a year so let’s say in 2020 if we’re sitting here and oil is $70, does the plan get’s at some discount to where the strip is and then if the oil price does better than that’s upside or you all sort of think about it more from what your maintenance capital level is and then the plan is set at something just above that. I’m just trying to think about the way it sort of gets flexed up or down according to the commodity environment?

I mean I think the first is, we’re taking a multiyear look here and then in today’s world we’re $50 to $55 and we think as an industry to improve our competitiveness with other industries we’ve got to prove that we can deliver more capital to shareholders through the cycle. And so what we’ve said we will deliver a minimum of 50% to investors because we think that's a meaningful number. John it could be more and what we’ve said is that we would deliver a minimum of 50% before we increased activity but it’s clearly things we can get after. So I think in general, the point is as we’re damn serious about returning more capital to shareholders before we scale up our activity and our operations.

Yes, John. This is Steve. I would just add to that saying that, that Slide 12 is actually poured from the actual plan we have in place for 2019, so it’s based on the 2.4 billion capital program and it’s based on the pricing environment that we find ourselves in today. And as John said previously in a $50 to $55 world out through ‘20 and ‘21 and we would have the capacity to spend $2.5 billion to $2.8 billion in that price environment still be cash flow neutral. It doesn’t mean that we would spend that much, but we could and still be cash flow neutral. If we woke up and found ourselves in a $70 world in 2020 we have to keep in mind that this maintenance capital would have some sort of an inflationary effect on that. I would imagine, and so this chart holds for the 2019 plan and it holds for a $50 to $55 price environment but when you get into a different price environment we just need to contemplate that kind of stuff.

Your next question comes from John Herrlin from Société Générale. Your line is open.

Regarding Suriname, John, will you be drilling [8 ace] or you’re going to have a partner?

John today we own it a 100%. We’ve got a drillship coming this summer. We will drill a minimum of one wells up to potentially three additional. We are prepared to go a 100%. We also are willing to listen to proposals and things where somebody might talk us into letting somebody else participate with us. So but for now we’re a 100%.

And then regarding the US impairments with Anadarko Basin since that was a prior acquisition, not to your administration. Is that something that will then be put up for sale?

When we look at the portfolio, we historically haven't announced when we were going to monetize assets and if you look at Canada, we usually came back and said we're going to do something after the fact. I think that we’re always looking at the portfolio and assets that we are not funding. If there's an opportunity for somebody to create value by putting those assets into their hands in a way that we think would make sense we would be open to do them and we will probably talk about it after we had done that if that were the case. But we’re always examining everything in our portfolio and looking at, does it belong and is it going to get funding or is it better off in somebody else's hands.

And then with the GoM was it that self-insurance thing?

John, the GoM was the consortium that was put together back in 2011 for companies that were active in the Gulf of Mexico to respond to well incidents.

Okay. Yes, the insurance thing. Okay.

We’re clearly not active in the Gulf of Mexico anymore so…

Your next question comes from the line of Jeoffrey Lambujon from Tudor, Pickering Holding Company.

In the past you mentioned slowing down in the Midland and legacy Delaware to progress learning in the Alpine High, it looks to be showing up an improved performance. So I was hoping if you could just speak to some of those more meaningful learnings as you’ve kind of progressed further on that?

Well I think Jeoff it boils down to, you go back in 2015, 2016, when we really went through a reset, we did a lot of strategic testing both in the Midland and the Delaware. We focused on pad development what is the special relationship between wells both vertically and horizontally. We focused on completions. And what you've seen is the use of technology, the learnings and the implementation of that you are now seeing that paid off in spades in our Midland and Delaware Basin programs. We've also been in the middle of that process at Alpine High, and we were conducting that with some of the key tests that we've talked about, our Blackfoot pad, our Mont Blanc pad. So it's a process that we continue and then I think the important thing is we've always talk, you need to think about things in terms of whole sections, full-scale of development and you have to keep integrating those learnings and you also have to recognize that the geology in each play is a little different and it's going to be in the [Elgin] Reservoir going to be key components in getting the what we call an optimized development program, and it's also why this year we’re going to be running nearly two focused programs when we look at it. There’s going to be a rich gas program at Alpine High, and you are going to see an oil focused program predominantly in the Midland and in Delaware.

And then separately on 2020, I appreciate the thoughts there on spending and how you are planning to exit 2019 with this year's plan. But as we dial-in next year, is there a good production range to think about that's associated with the 2.5 billion to of 2.8 billion that you've highlighted for next year?

Well, I would just say, what I said earlier, we will exit '19 and go into '20 on stronger footing than we've come into this year and in a similar price environment capital allocation likely would look pretty similar. Those things can change, the productivity can change. But we think our floor is going to be mid single-digits at the corporate level. And we think that can improve as we’ve proven in the past with efficiencies, some capital allocation, some other things.

Your next question comes from line of Brian Singer from Goldman Sachs. Your line is now open.

As you flow the dry gas piece of Alpine High a bit, can you just talk about the financing options at the Altus Midstream level? It seems like that’s still in-house there but given the capital needs there and any risk of the need for equity infusion outside from other players like yourselves or others?

There is going to be a call, we want to collect a day on Altus, Brian. So I would just advise you to tune in there for the Altus call.

I guess from an Apache perspective any comment on that or just wait for that call?

Brian I would just say from an Apache perspective, obviously we worked very closely with the Altus team and we don't anticipate any type of capital call on Apache none whatsoever, Altus is actively working their forward-looking capital program and looking at options and they see options for financing as some pretty attractive ones and I think they will be going forward with that. And again referring it to the call this afternoon to get more detail then.

I appreciate that color from the Apache perspective. And then as you slow the dry gas development at Alpine High and the oil delineation to focus more on wet gas and to be capital disciplined, do you ultimately see that oil delineation and dry gas production happening but at a later date and/or when you think about any excess cash flow above the 50% you would return to shareholders, do you see opportunities -- would you consider opportunities to bolster the portfolio broadly through bolt-ons or acquisitions?

Today clearly with what our opportunities set is, is we’re not looking to bolster the portfolio with acquisitions. We've got some very attractive programs that we have deferred. We will eventually resume some of that testing and there is quite a bit of ability to add activity in our Midland non-Alpine High, Delaware, and at Alpine high as well as on the international front in Egypt. So not seeing as we have not over the last four years thought about making to do something on the acquisition side.

Your next question comes from Charles Meade from Johnson Rice. Your line is now open.

I wondered to ask a question about Alpine High. And perhaps we will have to wake at to 1 o'clock for this but you mentioned in your press release that you guys had field wide shut down and some facilities came online a little later than was planned. So wondering if you could just give a narrative on what happened in the quarter, whether those two events are connected, perhaps and if there is anything different that we should expect going forward over the course of 2018 for the built out?

I’ll let Tim jump in, in just a second but Charles the answer you got a one-time offset and we ended up putting a lot of water into the gas lines which required us to have to shut down the entire field for longer period. And then it took longer to get everything cleaned out, so it’s not an event that will occur in the future. And then the other was just purely timing of the way of moving the pad back. So I'll let Tim to give you some more details, but we exited the year kind of where we thought we’d be. It just was a little slower getting a few things on.

Yes, Charles just a little more color on that, on the unplanned field wide shut-in, that was due to, we had a failure on the highway where we put some water down the sales line, so we had to shut the field in for a few days, we had to dig the line and then we’d to re-pressure that line, and then it just took a little longer to get everything up and running and back to full production. So, that was a big portion of it. Then John mentioned the deferrals too and that was really because of the rich gas drilling we had done and the MOUs that we've got, we were running into the BTU spec issues. So we had to delay the development of a number of rich gas wells to put some dry gas wells online to get our BTU spec back in place and that causeed the main issues at Alpine High. There were some minor timing issues just on new facility startups. But the first two were the main issues.

Charles, this is Steve. I'd just add the obvious point and that is when your -- you've got an asset that's growing at the pace of Alpine High and you're bringing large pads on, movements of events in the quarter can actually make a big difference to a quarter. To state the obvious.

Always appreciated.

All these issues have been resolved and we hit accelerate that we anticipated as well…

Got it. And then Tim, maybe this is a question best for you. But I -- on your Midland Basin results in the quarter, one of the things that struck me is, curious or maybe a little countertrend it to what I've seen in the rest of the industry is that you guys have had better Wolfcamp results down in Upton County than you did in your June Tippett pad in Southern Midland. And it seems like for most of rest of the industry that productivity relationship was actually being reversed, the better wells have been up Northern Upton Southern Midland. So wondered if you could talk about what's going on there, and if it has any implications for the way you guys are going to rank your priorities going forward?

Yes, we've had good results from both areas. The Upton County wells in particular the Powell and then the latest test that we did in Hargrove have been outstanding wells. And a little bit is based on some of the testing that we have done. That we’ve gone to development mode and we changed our spacing, most of our wells have been drilled in Upton County to-date, and that's what we've advanced our learnings the most. And I think we've got our spacing completely figured out there and our well completions. And as a result, we've seen it in our results. And I think we're going to see that same evolution up in Wildfire when we start drilling more wells there as well.

Your next question comes from Arun Jayaram from JP Morgan. Your line is open.

I wanted to talk a little bit about Suriname. You guys have completed your seismic on Block 58 and presumably have the geo mapping it has those Exxon Hymera gas county discovery, which is on the Surinam line. What do you think will define the oil leg of what has -- and perhaps you could set the stage for your initial prospect that you will drill midyear?

Arun, we kind of talked internally, we need to make sure we send them a Christmas card. What it proves is you got hydrocarbons in the system. Clearly in a conventional setting you’re going to expect to see the condensates and the lighter hydrocarbons in the upper sections. I think what I would say is as we look at where they are and I understand they are also continuing to drill deeper themselves in that well, but we would -- so lot of our targets will be deeper where we would anticipate they will be oily as is the case over on the Stabroek block. It’s very, very encouraging. The thing we said in the script though I want to point out is we've got multiple play sites, more than a handful. The thing that’s unique about our block is, is you got shallow and deepwater access and there is both pre-and post unconformity plays. So we’ve mapped many, many high-impact prospects and we’re very excited what this could mean for the country of Suriname and Apache.

And just a follow-up John. We’re reading into your capital allocation in the Permian in 2019 where we didn't note a little bit more activity in your Other Delaware and we’re just trying to think about -- respect the fact that Altus will put their topic later today but they did reduce their overall guidance from 19 to 21 so just trying to read into that what the capital allocation for Alpine High could look like over the next couple of two, three years?

Well as we said we’ve reduced rig count this year, we’re going down from seven or eight rigs at Alpine High to five. I mean we’re reducing our Permian rig count from 16 to 17 down the 12 to 13 and so both programs are going to be reduced as we said. Alpine will get its fair share but you're going to see two very focused programs where we can set up our rigs and frac crews appropriately to deliver optimal value for the capital investment. And we like the pace, we like the programs. We’re both are going to be very focused and pretty similar to what we've been doing fruitfully.

Your next question comes from David Deckelbaum from Cowen. Your line is now open.

Just curious as you look at the -- you give the guidance around mid single-digit growth into 2020 and ‘21 with the $2.5 billion to $2.8 billion budget. I guess this year we saw the double-digit production growth coming out of US onshore. Should we assume that that continues sort of within that high-level model over the next couple years and is there a point in ‘20 and ‘21 program where we would see more growth capital going in Egypt following some of the acreage expansions and seismic activity that you’ve had there?

I mean I think there is no doubt we’re going to have the opportunity to put more capital into Egypt as we get through the 3D and the processing, but we also believe that just through the high grading and the inventory and the quality of the prospects, we can grow that free cash flow and grow that investment in Egypt simultaneously. And if you look back to the last four years and if I take you back to 2014, we are running 28 rigs in Egypt, so we got down to a handful. We've been running about 12, 12 rigs. And really over that time period there's two discoveries Pithom and Berenice, which enabled us to keep Egypt pretty flat at 340,000 BOEs a day on the gross side. So with the new seismic and the new acreage we’re optimistic that there will be several new types of areas like that will let us put more capital in and that efficiency will help us drive more cash flow and help really change the trajectory in Egypt.

But that's not necessarily embedded into that ‘20 and ‘21 capital programs?

Not at this point.

Allocation is more similar, okay.

Not at this point.

And my second question is just, when we go back to some of the conversations you were having around spacing and particularly in Alpine High, and if you guys could revisit some of the results from the Blackfoot pad. I know you talked about it last quarter just the spacing at 660 and developing long and wider spacing with larger fracs. So can you talk to us a bit about your learnings there and what you think it means for how you are going to space the wells in that Northern Flank?

Well, I mean what we've done is we were pretty, we were sticklers on keeping our frac, I'll call it frac jobs similar, so we know what the rock was telling us, and what we learned at the Blackfoot pad is we placed 12 Woodford wells and a half section there were Woodford day 4Bs and 4Cs and we used the same recipe we have been using because we were trying to understand the inter-related most of it. And what we learned there as we would likely can get away with 4As and 4Bs on 660 with those size frac jobs, but we also wanted to test the Mont Blanc, a little wider spacing and a little larger frac jobs, and we will measure those as the flow back over time. I mean what's important everybody gets dialed in on 30 day IPs and you have to look at how wells perform over 3, 6, 9 months, 12 months and I think what you'll see is us probably going a little wider. You're going to see multiple landing zones in the Woodford and larger fracs, some combination in there and that's part of the learning process that we've gone through in the Midland Basin. And as Tim pointed out that's why you're starting to see those same results come through as we continue to very scientifically evaluate every well in our patterns and are doing this in a way designed that’s going to drive improved productivity and capital efficiency.

And this concludes our Q&A session. I'll now turn the call back to John Christmann for closing remarks.

We appreciate all of you for joining us today. And I like to leave you with three key takeaways from the call. First, the world has changed significantly since our last quarterly earnings call. The drop in oil prices necessitates conservative budgeting and capital management. Apache is currently delivering attractive returns and growth rates and can achieve cash flow neutrality and sustain production inclusive of our very strong dividend down to about $45 WTI oil using some fairly conservative assumptions. Second, in 2019, year-over-year, we will sustain relatively flat production internationally and generate approximately 15% growth in the US with our capital heavily concentrated on two programs: oil growth in the Midland and Delaware basins and rich gas development at Alpine High. And lastly, we have entered 2019 with very good momentum and expect to enter 2020 in a even stronger position. As a result, we plan to sustain at least mid single-digit 4Q to 4Q exit rate growth through 2021 at $2.5 billion to $2.8 billion annual spending. Growth will come from a balanced program of Alpine rich gas development in Midland, Delaware oil with significant upside potential from our exploration portfolio including our US onshore unconventional, Egypt and eventually Suriname. Thank you and we look forward to sharing our ongoing progress in the future.

Ladies and gentleman, thank you for your participation. This concludes today's conference call. You may now disconnect.